[Federal Register Volume 66, Number 248 (Thursday, December 27, 2001)]
[Rules and Regulations]
[Pages 66994-67007]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 01-31655]



[[Page 66993]]

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Part III





Department of Transportation





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Research and Special Programs Administration



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49 CFR Part 195



Controlling Corrosion on Hazardous Liquid and Carbon Dioxide Pipelines; 
Final Rule

  Federal Register / Vol. 66, No. 248 / Thursday, December 27, 2001 / 
Rules and Regulations  

[[Page 66994]]


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DEPARTMENT OF TRANSPORTATION

Research and Special Programs Administration

49 CFR Part 195

[Docket No. RSPA-97-2762; Amdt. 195-73]
RIN 2137-AD24


Controlling Corrosion on Hazardous Liquid and Carbon Dioxide 
Pipelines

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

ACTION: Final rule.

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SUMMARY: This Final Rule makes changes in some of the corrosion control 
standards for hazardous liquid and carbon dioxide pipelines. The 
changes are based on our review of the adequacy of the present 
standards compared to similar standards for gas pipelines and 
acceptable safety practices. The changes are intended to improve the 
clarity and effectiveness of the present standards, and reduce the 
potential for pipeline accidents due to corrosion.

DATES: This Final Rule takes effect January 28, 2002. The incorporation 
by reference of the publication listed in the rule is approved by the 
Director of the Federal Register January 28, 2002.
    Compliance dates: Under Sec. 195.563(c), operators of certain 
effectively coated buried piping in breakout tank areas or pump 
stations are not required to cathodically protect that piping until 
December 29, 2003. Under Sec. 195.567(a), operators of cathodically 
protected pipelines or pipeline segments that lack test leads for 
external corrosion control are not required to install test leads until 
December 29, 2004. Under Sec. 195.573(a)(2), operators are not required 
to determine the circumstances in which a close-interval survey or 
comparable technology is practicable and necessary until December 29, 
2003. Under Sec. 195.573(b), operators of unprotected pipe are not 
required to reevaluate the need for corrosion control on the pipe at 
least every 3 years until December 29, 2003.

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

SUPPLEMENTARY INFORMATION:

Background

    Corrosion causes a significant proportion of hazardous liquid 
pipelines accidents. Based on this finding, we reviewed the corrosion 
control standards in 49 CFR part 195 to determine if the standards need 
to be made clearer, more effective, or consistent with acceptable 
safety practices. We believe that improving the standards will have the 
potential to reduce the number of accidents caused by corrosion.
    The review began September 8, 1997, when we held a public meeting 
in Oak Brook, Illinois to discuss how part 195 corrosion control 
standards and the corrosion control standards for gas pipelines in 49 
CFR part 192 might be improved (62 FR 44436; Aug. 21, 1997). We held 
the public meeting in conjunction with meetings of National Association 
of Corrosion Engineers International (NACE), a professional technical 
society dedicated to corrosion control. Participants agreed, 
universally, that part 192 and part 195 corrosion control standards are 
largely sufficient, and although some changes may be needed, the 
standards should remain generally unchanged.
    Based on this conclusion, we began to consider whether the more 
comprehensive part 192 gas standards, possibly with some changes, would 
be appropriate for part 195's hazardous liquid and carbon dioxide 
pipelines. We met then, from time to time, with representatives of 
NACE, the pipeline industry, and state pipeline safety agencies for 
technical input. At these meetings, we also examined whether the part 
192 standards need to be more effective or clearer. The meetings raised 
various concerns about the effectiveness and clarity of some of the 
part 192 corrosion control standards and the suitability of applying 
those standards to hazardous liquid and carbon dioxide pipelines. We 
also took into account that the National Association of Pipeline Safety 
Representatives, the Gas Piping Technology Committee, and the National 
Transportation Safety Board had at various times recommended changes to 
part 192 and part 195 corrosion control standards. So, to gather public 
comment on our concerns and the changes these organizations 
recommended, we held another public meeting on April 28, 1999, in San 
Antonio, Texas, and invited the public to submit written comments. The 
comment period remained open until June 30, 1999 (64 FR 16885; April 7, 
1999).

Notice of Proposed Rulemaking

    Sixty-two persons filed written comments in response to the San 
Antonio meeting notice. We then summarized these comments in a notice 
of proposed rulemaking (NPRM) published last year (65 FR 76968; Dec. 8, 
2000). The NPRM proposed to add to part 195 a new subpart H called 
Corrosion Control. Subpart H would prescribe corrosion control 
standards for all new and existing steel pipelines to which part 195 
applies. At this time, we also decided to address the concerns, 
recommendations, and comments that pertain primarily to the corrosion 
control standards in part 192 in a separate notice of proposed 
rulemaking on gas pipelines.
    Although there was little support in the record for allowing NACE 
Standard RP0169-96, ``Control of External Corrosion on Underground or 
Submerged Metallic Piping Systems,'' to serve as an alternative to 
standards proposed in subpart H, we specifically requested further 
comment on this issue due to NACE's standing in the field of corrosion. 
Unfortunately, no one commenting on the NPRM responded to that request, 
perhaps because of earlier discussions of the issue in Oak Brook and 
San Antonio. While NACE urged us to reference the entire NACE Standard, 
not just section 6 as we proposed, NACE did not assert that the NACE 
Standard could serve as an acceptable alternative to proposed subpart 
H.
    The NPRM discussed each of the standards proposed for inclusion in 
subpart H. Many of these standards are identical to present corrosion 
control requirements in part 195, and many of the standards are 
substantially like the present requirements in part 192. Proposed 
subpart H also includes standards that, while based on present part 192 
requirements, include changes which we think are beneficial 
improvements.

Discussion of Comments

    We received comments from the following entities in response to the 
NPRM: Alberta Energy Company (AEC), City of Dallas Water Utilities, 
Enron Transportation Services Company (Enron), Environmental Defense, 
Equilon Pipeline Company (Equilon), L.A. ``Roy'' Bash, NACE, Phillips 
Pipe Line Company (Phillips), State of Iowa Utilities Board (Iowa), 
State of Washington Utilities and Transportation Commission (WUTC), and 
Tosco Corporation (Tosco). Most commenters supported the rulemaking, 
and all but the City of Dallas recommended changes to some of the 
proposed standards.
    The City of Dallas related its experience with a major pipeline 
spill caused partly by corrosion. Gasoline containing MTBE, a fuel 
oxygenate which effects the taste and odor of water, entered a lake 
resulting in a water supply crisis. The City stated that it is critical 
for DOT to adopt rules to require

[[Page 66995]]

all pipelines, especially those transporting gasoline with MTBE near a 
municipal water resource, to be regularly monitored for corrosion, 
cracks, and leaks; and that any deficiencies found, be timely repaired.
    This rulemaking will accomplish what the City of Dallas is seeking 
with respect to corrosion. In particular, Secs. 195.573, 195.579, and 
195.583 will require operators to monitor pipelines regularly for 
corrosion and correct any deficiencies found in corrosion control. 
Additionally, new Sec. 195.585 specifies corrective action for any 
harmful corrosion found. The timeliness of correcting corrosion control 
deficiencies and harmful corrosion is covered by existing 
Secs. 195.401(b) and 195.452(h).
    The requirement for operators to patrol their pipelines regularly 
for signs of failures is longstanding (Sec. 195.412(a)). However, we 
recently broadened requirements by publishing standards on integrity 
management which will require pipelines in or near high-consequence 
areas, such as drinking water sources, to be internally inspected or 
pressure tested at regular intervals for corrosion, cracks, and other 
defects (65 FR 75377; Dec. 1, 2000). These new standards currently 
apply to operators with 500 or more miles of hazardous liquid 
pipelines, and we have proposed similar standards for the remaining 
hazardous liquid operators subject to part 195 (66 FR 15821; Mar. 21, 
2001).
    The following material, which is organized by sections of final 
subpart H, summarizes comments on the NPRM. In addition, the material 
explains how we treated the comments and other considerations in 
developing final subpart H. If a subsection is not mentioned, no 
significant comments were received on the corresponding proposed rule 
and we are adopting the proposed rule as final.
    Section 195.551. This informational section provides the content of 
subpart H. Subpart H contains minimum requirements for protecting steel 
pipelines against corrosion.
    In commenting on proposed Sec. 195.551, Tosco suggested we replace 
the term ``steel'' with ``metallic'' so subpart H would apply to 
pipelines made of any metal. Indeed, our corrosion control standards 
for gas pipelines apply to any metallic pipeline (49 CFR 192.451(a)). 
However, in contrast to gas pipelines, hazardous liquid and carbon 
dioxide pipelines are almost exclusively made of steel. For this 
reason, many of the existing standards in part 195, including corrosion 
control standards, apply only to steel pipelines. Our review of the 
corrosion control standards did not disclose a need to expand their 
coverage to include pipelines made of metals other than steel. In 
commenting on the NPRM, no one, including Tosco, presented information 
to explain why the coverage should be expanded. Nevertheless, operators 
are required to provide us an opportunity to review the safety of any 
pipeline that is to be constructed with a material other than steel 
(Sec. 195.8). In the case of a metallic pipeline made from a material 
other than steel, such as aluminum, our review would include the 
operator's plan for corrosion control.
    Section 195.553. This new section was not in the NPRM. It provides 
definitions of terms used in subpart H. The definitions of ``active 
corrosion,'' ``electrical survey,'' and ``pipeline environment,'' 
proposed in Sec. 195.569(c), drew no adverse comment. Additionally, 
final Sec. 195.553 establishes definitions of ``buried'' and ``you.'' 
The definition of ``buried'' reflects the common corrosion control 
practice of treating any portion of pipe in contact with the soil as if 
that portion were buried. The term ``you'' has the same meaning as 
``operator.''
    Section 195.555. This section, based on proposed Sec. 195.553, 
keeps in effect the existing qualification standards in Sec. 195.403(c) 
for corrosion control supervisors. Under Sec. 195.403(c), each operator 
must require and verify that its supervisors maintain a thorough 
knowledge of that portion of the corrosion control procedures 
established under Sec. 195.402 for which they are responsible, to 
insure compliance.
    While Tosco and WUTC supported the proposed rule, Phillips objected 
to it. Phillips believed that part 195 should include qualifications 
for supervisors of all operation and maintenance activities, not just 
corrosion control. In the negotiated rulemaking on qualification of 
pipeline personnel (64 FR 46866; Aug. 27, 1999), we removed the 
requirements in Sec. 195.403(c) concerning qualifications of 
supervisors of operations and maintenance activities, effective October 
28, 2002. We did so based on the requirement under subpart G of part 
195, that on this date, individuals performing regulated operation and 
maintenance activities must be fully qualified, thus lessening the need 
to regulate the qualifications of their supervisors. After revising 
Sec. 195.403(c), our more specific review of the corrosion control 
standards called attention to the special role that supervisors play in 
carrying out corrosion control activities. As we explained in the NPRM, 
individuals qualified to do such activities as taking electrical 
readings, usually hand the data collected over to supervisors who make 
critical decisions about corrosion control adequacy and the need for 
corrective action. None of the commenters, including Phillips, argued 
that corrosion control supervisors do not need to have the 
qualifications required by existing Sec. 195.403(c). So given the 
special role of corrosion control supervisors and the apparent 
acceptability of the existing supervisor qualification requirements, we 
continue to believe those requirements should remain in effect after 
October 28, 2002. This decision does not affect the expiration on 
October 28, 2002, of qualification requirements for supervisors of 
other operation and maintenance activities.
    Equilon and NACE believed qualifications for supervisors should be 
no less rigorous than stated in paragraph 1.3 of NACE Standard RP0169-
96. These NACE provisions address the need for corrosion control 
supervisors to have a minimum level of technical competency.\1\ In our 
corrosion control review, we considered this NACE provision as well as 
49 CFR 192.453, which provides that gas pipeline corrosion control 
procedures must be carried out by or under the direction of a person 
qualified in corrosion control methods. Also, in the San Antonio 
meeting notice, we asked if more specific standards are needed for 
individuals who direct corrosion control procedures. Everybody who 
responded opposed changing Sec. 192.453, and most responders also 
opposed establishing specific technical qualifications like those in 
NACE Standard RP0169-96. We expect that individuals who qualify as a 
supervisor under proposed Sec. 195.553, will have appropriate technical 
training or experience in corrosion control. Given that neither our 
review, nor comments on the NPRM disclosed anything in the pipeline 
industry's safety record to demonstrate the need for more specific 
technical qualifications, we did not adopt the Equilon and NACE 
comment.
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    \1\ Paragraph 1.3 reads:
    The provisions of this standard shall be applied under the 
direction of competent persons who, by reason of knowledge of the 
physical sciences and the principles of engineering and mathematics, 
required by education and related practical experience, are 
qualified to engage in the practice of corrosion control on buried 
or submerged metallic piping systems. Such persons may be registered 
professional engineers or persons recognized as corrosion 
specialists or cathodic protection specialists by NACE if their 
professional activities include suitable experience in external 
corrosion control of buried or submerged metallic piping systems.
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    Sections 195.557, 195.559, and 195.561. These three standards on

[[Page 66996]]

external coating are based on proposed Sec. 195.555 and 195.557. 
Collectively, the standards require buried or submerged pipelines to 
have external coating with particular attributes, and require operators 
to inspect pipe coating and repair any damage. As stated in proposed 
Sec. 195.555, the standards are limited to pipelines constructed, 
relocated, replaced, or otherwise changed after certain effective dates 
in Sec. 195.401(c); and limited to certain converted pipelines. In 
final Sec. 195.557, we have clarified that aboveground breakout tank 
bottoms need not be coated. We determined that such a requirement is 
impractical and not a customary corrosion control practice.
    In the NPRM, we proposed in Sec. 195.555 to limit the applicability 
of proposed Secs. 195.557 (external coating), 195.559 (cathodic 
protection), and 195.561 (test leads) to pipelines constructed, 
replaced, relocated, or otherwise changed after the applicable 
effective date. We based proposed Sec. 195.555, for the most part, on 
existing Sec. 195.200, titled Scope, which similarly limits the 
applicability of corresponding existing Secs. 195.238, 195.242, and 
195.244. However, we inadvertently omitted from Sec. 195.555 the pipe 
movement exception included in Sec. 195.200. In this Final Rule, the 
substance of proposed Sec. 195.555 regarding external coating and 
cathodic protection is in Sec. 195.557(a), which does include the 
omitted exception for pipe movement. We addressed the proposed limit on 
test leads differently, as discussed below under the heading, section 
195.567.
    Tosco believes it would be helpful to include in subpart H the past 
effective dates cross-referenced in proposed Sec. 195.555. Tosco 
believes the dates are not widely known. We did not adopt this comment 
because the dates are already stated in Sec. 195.401(c) for purposes of 
indicating the applicability of standards in addition to corrosion 
control standards, and we do not want to create an unnecessary 
redundancy in part 195.
    Final Sec. 195.557 specifies which pipelines must have external 
coating. Rather than cross-referencing Sec. 195.5(b) to indicate which 
converted pipelines must have coating, we transferred to final 
Sec. 195.557 the coating aspect of Sec. 195.5(b). We transferred the 
cathodic protection aspect to final Sec. 195.563(b); and the test lead 
aspect is covered by Sec. 195.567.
    Equilon and NACE suggested we establish an additional standard to 
minimize damage to coating when operators install pipe by boring, 
driving, directional drilling, or any similar method. Final 
Sec. 195.559(d) requires external coating to have enough strength to 
resist damage due to handling and soil stress. We believe this standard 
is broad enough to cover the potential pipe installation problems 
raised by these commenters.
    Phillips advised against requiring the installation of coating on 
older existing bare or ineffectively coated pipelines. We believe 
Phillips may be referencing existing hazardous liquid pipelines 
constructed before the applicable effective dates stated in 
Sec. 195.401(c). These pipelines are not subsequently replaced, 
relocated, or otherwise changed. Final Sec. 195.557 does not require 
these older pipelines to be coated.
    Tosco suggested that Sec. 195.557 should include the dates for 
which pipelines must have external coating. The final rule accomplishes 
this objective by cross-referencing Sec. 195.401(c). Restating the 
dates listed in Sec. 195.401(c) would be unnecessarily redundant since 
the dates are in Sec. 195.401(c) for purposes other than corrosion 
control.
    Section 195.563. Final Sec. 195.563 combines cathodic protection 
requirements proposed in Secs. 195.555, 195.559, and 195.563. It also 
cross-references final Sec. 195.573(b), which requires cathodic 
protection of unprotected pipe found to have active corrosion. As a 
result, all pipelines that must have cathodic protection under subpart 
H are identified in a single section.
    Final Sec. 195.563(a), which is based on proposed Secs. 195.559(a) 
and (b), requires cathodic protection on each pipeline that must have 
an external coating under Sec. 195.557(a). The cross-reference to 
Sec. 195.557(a) limits the cathodic protection requirement to those 
pipelines constructed, relocated, replaced, or otherwise changed after 
certain dates, as proposed under Sec. 195.555. Section 195.563(a) does 
not contain the second sentence of proposed Sec. 195.559(a) which would 
require operators to have a test procedure to determine whether 
adequate cathodic protection was achieved. We now believe this sentence 
is redundant due to the routine monitoring conducted to determine the 
adequacy of cathodic protection, required by final Sec. 195.573(a). 
Also, amended Sec. 195.402(c)(3) requires operators to have procedures 
to carry out Sec. 195.573(a). Although proposed Sec. 195.559(b) only 
referred to completion of construction as the beginning of the period 
during which cathodic protection must be installed, final 
Sec. 195.563(a) reflects the broader applicability indicated by 
proposed Sec. 195.555.
    We proposed in Sec. 195.559(a), which was based on existing 
Sec. 195.242(a), a requirement that operators install cathodic 
protection systems on all buried or submerged pipelines ``to mitigate 
corrosion that might result in structural failure.'' Equilon and NACE 
suggested this proposed rule would be clearer if we replaced 
``structural failure'' with ``structural failure or penetration of pipe 
or tank wall.'' In light of their comment, we believe the phrase, ``to 
mitigate corrosion that might result in structural failure,'' creates 
confusion. It could be interpreted to require protection only against 
severe external corrosion. Moreover, since it is clear that existing 
Sec. 195.242(a) requires cathodic protection against all external 
corrosion, the phrase seems superfluous. Therefore, we did not use it 
in final Sec. 195.563(a).
    Equilon and NACE also commented on the Sec. 195.559(b) proposed 
requirement that a cathodic protection system be installed not later 
than 1 year after completing construction. They believe cathodic 
protection should be in effective operation at the end of 1 year, to 
guard against significant corrosion that could be caused by stray 
currents or galvanic long-line currents. We believe effective operation 
is implicit in the existing and proposed standards on installation of 
cathodic protection. Nevertheless, to avoid confusion on this point, in 
final Sec. 195.563(a) we replaced ``installed'' with ``in operation.'' 
This change is consistent with the comparable standard for gas 
pipelines in Sec. 192.455(a)(2). Under final Sec. 195.571, when the 
cathodic protection system is placed in operation, it would have to 
comply with one or more of the applicable criteria and other 
considerations for cathodic protection contained in paragraphs 6.2 and 
6.3 of NACE Standard RP0169-96. Subsequent electrical tests and other 
steps required by final Sec. 195.573(a) will assure that adequate 
protection is maintained.
    WUTC raised the concern that under proposed Sec. 195.559(b) 
corrosion could go uncontrolled on some facilities for up to 2 years. 
Based on a Washington State administrative rule, WUTC recommended that 
Sec. 195.559(b) require that facilities be cathodically protected 
within 90 days after they are buried or submerged. We did not propose 
to change the currently required time limit (1 year after completing 
construction) because our review of the corrosion control standards and 
the comments from the San Antonio meeting did not indicate any need to 
reduce the installation time limit. After considering

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WUTC's comment, we still believe 1 year after construction is 
acceptable as a generally applicable time limit considering that soil 
conditions may need time to stabilize in order to support cathodic 
protection.
    Final Sec. 195.563(b) requires cathodic protection on certain 
converted pipelines. This requirement does not differ substantively 
from the cathodic protection aspect of the corrosion control 
requirement of Sec. 195.5(b). Therefore, we are modifying Sec. 195.5(b) 
to cross-reference the new subpart H standards.
    Under final Sec. 195.563(c), which is based on proposed 
Sec. 195.563, all buried or submerged pipelines, that have an effective 
external coating must have cathodic protection. This requirement does 
not apply to breakout tanks. This requirement is substantially the same 
as existing Sec. 195.414(a), which requires that all effectively coated 
pipelines must be cathodically protected, except for breakout tank 
areas and buried pumping station piping.
    However, Equilon and NACE each stated it saw no need to except 
buried piping in breakout tank areas and pumping stations from the 
requirement to cathodically protect effectively coated pipelines. We 
agree that the exception seems to lack a sound safety basis. For 
example, NACE Standard RP0169-96 does not have a similar exception from 
cathodic protection. Also, we believe it is now common practice in the 
hazardous liquid pipeline industry to cathodically protect effectively 
coated buried piping in breakout tank areas and pump stations. So, in 
view of the Equilon and NACE comments, and our further consideration, 
we decided to terminate the exception for buried piping in breakout 
tank areas and pumping stations. Therefore, the final rule keeps the 
exception in effect only until December 29, 2003. This period will give 
operators time to install cathodic protection on any effectively coated 
piping in breakout tank areas and pumping stations where it is not 
already installed. Also, since no one commented on application of the 
proposed rule to the bottoms of breakout tanks and there may not be 
many older breakout tanks that have effectively coated bottoms, the 
final rule does not change the present exception for breakout tank 
bottoms.
    Initially, we did not propose regulations similar to 
Secs. 195.414(b) and (c), which require cathodic protection in areas of 
active corrosion found through electrical inspections previously 
required on bare pipelines, breakout tank areas, and buried pumping 
station piping. We reasoned that Secs. 195.414(b) and (c) are no longer 
necessary because the inspection deadlines had expired. However, we now 
recognize that the cathodic protection provisions of Secs. 195.414(b) 
and (c) are continuing requirements, and so we included them in subpart 
H as final Sec. 195.563(d).
    Section 195.565. This section, concerning the installation of 
cathodic protection on breakout tanks, is the same as proposed 
Sec. 195.559(c). There were no comments on proposed Sec. 195.559(c).
    Section 195.567. In this section concerning test leads, paragraphs 
(a) and (b) are based on proposed Sec. 195.561 and existing 
Sec. 195.244. The existing test lead standards in Sec. 195.244 apply to 
onshore pipelines constructed, replaced, relocated, or otherwise 
changed after certain past dates; and to onshore converted pipelines if 
required by Sec. 195.5(b). The NPRM did not propose to vary this 
application. However, upon further consideration of the importance of 
test leads in determining the adequacy of cathodic protection, we are 
applying final Sec. 195.567 to all onshore pipelines that must have 
cathodic protection under subpart H. This increased coverage will 
affect pipelines or segments of pipelines that must have cathodic 
protection under existing Secs. 195.414 and 195.416(d) (i.e., 
effectively coated pipelines and places on bare pipelines, breakout 
tank areas, and pumping station piping where active corrosion is found 
through electrical inspection). The increased coverage will also affect 
converted pipelines that were not substantially in compliance with 
existing Sec. 195.244 when placed in service, as Sec. 195.5(b) now 
permits. To ease the burden of compliance on existing cathodically 
protected pipelines or pipeline segments on which test leads are not 
now required by existing Sec. 195.244 or Sec. 195.5(b), final 
Sec. 195.567(a) allows operators 3 years to identify these pipelines or 
pipeline segments and install test leads as necessary to meet 
Sec. 195.567(b). On existing unprotected pipelines, any newly 
identified segment that must have cathodic protection as a result of an 
electrical survey under final Sec. 195.573(b), must have test leads in 
time to carry out the annual monitoring test under final 
Sec. 195.573(a).
    Final Sec. 195.567 is consistent with acceptable practices. The 
practices recommended for test leads in NACE Standard RP0169-96 and in 
ASME B31.4 are not limited to new, relocated or replaced pipelines. 
Also, our gas pipeline regulations in 49 CFR 192.469 and 192.471 for 
test stations and test leads, apply to all gas pipelines that must be 
cathodically protected under 49 CFR part 192. Moreover, existing 
Sec. 195.416(a) requires annual testing of each cathodically protected 
pipeline to determine the adequacy of cathodic protection; and 
operators normally comply with this requirement by obtaining electrical 
measurements through test leads. So we believe Sec. 195.567 will have 
only a minimal impact on hazardous liquid pipeline companies.
    Based on existing Sec. 195.244(b)(1), we proposed in 
Sec. 195.561(b)(1) that operators install test leads with enough 
looping or slack to prevent the leads from being unduly stressed or 
broken during backfilling. Equilon and NACE suggested that to assure 
test lead wires remain effective, we should add the phrase ``to remain 
mechanically secure and electrically conductive.'' We believe the 
objective of this phrase is within the purpose of the existing rule, 
and therefore, added the phrase to final Sec. 195.567(b)(2) for 
emphasis.
    The long term integrity of test leads is also covered by final 
Sec. 195.567(c). Based on proposed Sec. 195.573, this standard requires 
maintenance of test leads. There were no comments on the proposed rule, 
however we edited the final rule for clarity.
    Equilon and NACE also commented on testing cathodic protection of 
offshore pipelines. They contended that test lead readings at platforms 
or at shore locations may be of little benefit in determining the 
adequacy of cathodic protection of offshore pipelines. As an 
alternative to such readings, they suggested we require operators to 
analyze or inspect each cathodic protection system before the end of 
its design life. In our experience, test leads for offshore pipelines 
normally are installed only on platforms or on shore because of the 
difficulty of accessing leads at underwater locations. For this reason, 
Sec. 195.567 does not apply to buried or submerged portions of offshore 
pipelines. Since pipeline corrosion in an offshore environment 
generally occurs at a uniform rate, we believe readings taken by 
operators at offshore platforms or on shore are used satisfactorily to 
determine the adequacy of protection over the entire pipeline. 
Moreover, this test method is acceptable for offshore gas pipelines 
under paragraph A862.15 of the ASME B31.8 Code. Because there is no 
information to support the need to require the use of an alternative 
testing method, we chose not to take action on the commenters' 
suggestion.
    WUTC commented that because the proposed standard does not 
prescribe the number or precise location of test leads, government 
inspectors may disagree with operators over whether

[[Page 66998]]

test readings are sufficient to determine the adequacy of cathodic 
protection. To ameliorate this situation, WUTC suggested that we 
require operators to conduct close-interval electrical surveys every 5 
years. Although final Sec. 195.567 does not specify the number or 
precise location of test leads, it does provide a performance standard 
for the location of test leads. Under Sec. 195.567(b)(1) test leads 
must be installed at sufficiently frequent intervals to obtain 
electrical measurements indicating the adequacy of cathodic protection. 
Section 4.5 of NACE Standard RP0169-96, which lists many customary test 
lead locations, may be used as a guide to comply with 
Sec. 195.567(b)(1). Additionally, the final rule on monitoring external 
corrosion control, Sec. 195.573, will require operators to use close-
interval surveys in some situations and install additional test leads 
where warranted.
    Section 195.569. This section, which is based on proposed 
Sec. 195.565, provides that whenever an operator learns that any 
portion of a buried pipeline is exposed, the exposed portion must be 
examined for external corrosion if the pipe is bare or has deteriorated 
coating. Further, if external corrosion requiring remedial action is 
found, the operator must investigate pipe in the vicinity of the 
exposed portion (by visual examination, indirect method, or both) to 
determine if there is any additional external corrosion requiring 
remedial action.
    Phillips requested more flexibility in the proposed requirement to 
look for additional corrosion. Phillips commented that the extent of 
further investigation should depend on the type of corrosion found and 
whether the corrosion could be expected to extend beyond the exposed 
segment. We do not believe there is a clear understanding of the 
relationship between the type of corrosion and the likelihood of 
finding similar corrosion in the vicinity of the exposed pipe to 
justify limits on the requirement for additional investigation. Pipe 
and soil conditions are generally too variable to make such predictions 
with accuracy. Therefore, we did not adopt Phillips' comment.
    WUTC believed subpart H should include additional requirements for 
operators to do more to determine the condition of coating than just 
visually examine it whenever pipelines are exposed. WUTC stated that 
the standards should require operators to conduct surveys to identify 
areas with coating defects and take remedial measures such as re-
coating the pipeline. Although the final rules do not specifically 
require pipe coating surveys, operators must conduct electrical tests 
periodically to determine the adequacy of corrosion control on their 
buried pipelines. Low cathodic protection potential readings obtained 
during these tests often are a sign of coating defects. So, in areas 
with low potential readings, many operators supplement cathodic 
protection tests with coating surveys to help them identify places 
where the pipeline must be excavated to look for corrosion cells or to 
determine where additional cathodic protection must be applied. The 
need to mandate the use of coating surveys in addition to electrical 
tests for corrosion, was not evident from our review of the 
regulations.
    Section 195.571. This standard, proposed as Sec. 195.567, 
incorporates by reference the criteria and other considerations in 
section 6 of NACE Standard RP0169-96, as standards for the adequacy of 
cathodic protection.
    Environmental Defense and Iowa argued that because cathodic 
protection criteria are fundamental to safety, the criteria should be 
stated in part 195 rather than incorporated by reference. Iowa believed 
that acquiring and maintaining a separate document is arbitrary and 
unnecessarily burdensome. In considering these comments, we reviewed 
OMB Circular A119 and the National Technology Transfer and Advancement 
Act of 1995. Both documents direct Federal agencies to use consensus 
standards where practical to meet their policy objectives rather than 
develop government-unique standards. We also reviewed the rules of the 
Federal Register on incorporation by reference. In light of these 
Federal policies, we think it is appropriate for us to incorporate the 
NACE criteria and other considerations by reference, as proposed.
    Enron, Environmental Defense, and L. A. (Roy) Bash urged us to 
adopt the criteria in Appendix D of part 192 instead of the NACE 
criteria. Enron commented that many operators are successfully using 
Appendix D for hazardous liquid pipelines; and Environmental Defense 
viewed Appendix D as more specific and therefore more enforceable. Roy 
Bash submitted technical documentation in support of two Appendix D 
criteria, 300 mV shift and E-log-I. In the NPRM we discussed our 
reluctance to propose Appendix D as the new standard for hazardous 
liquid pipelines because the Appendix D 300 mV shift and E-log-I 
criteria are not incorporated in the NACE Standard. Furthermore, we 
explained that under paragraph 6.2.1 of the NACE Standard, operators 
may use any criteria which they can demonstrate achieves corrosion 
control comparable to section 6 criteria. Also, operators may continue 
to use criteria which they have successfully applied to existing 
pipelines, on these pipelines. While this provision may satisfy Enron, 
and should satisfy Roy Bash's concern about the continued use of the 
300 mV shift and E-log-I criteria, the lack of specificity in paragraph 
6.2.1 may be indicative of Environmental Defense's concern. Yet, we do 
not believe the performance wording of paragraph 6.2.1 alone is 
sufficient reason not to reference section 6 of the NACE Standard. On 
the contrary, we generally favor performance standards over 
specification standards because they encourage operators to develop and 
apply better alternatives. If however, an operator chooses to use 
alternative criteria, we will carefully examine the operator's 
rationale for determination that the criteria met the ``comparable to'' 
or ``successfully applied'' tests of paragraph 6.2.1 of the NACE 
Standard.
    WUTC was concerned that the criteria in section 6 of the NACE 
Standard would not be mandatory because paragraph 6.1.1 refers to 
paragraph 1.2, which states that the Standard is a guide; and also 
refers to paragraph 1.4, which allows deviations from the Standard. 
Proposed Sec. 195.567 refers solely to the criteria and other 
consideration provisions of section 6, which are contained in 
paragraphs 6.2 and 6.3 of the NACE Standard. We did not intend to allow 
operators to treat section 6 as a guide or to deviate from the criteria 
and other considerations in section 6. Therefore, the final rule refers 
to paragraphs 6.2 and 6.3, instead of section 6.
    WUTC was also concerned about special conditions, such as elevated 
temperatures, disbonded coatings, thermal insulating coatings, 
shielding, bacterial attack, and unusual contaminants in the 
electrolyte, which may cause cathodic protection to be ineffective. 
WUTC believed the rules on coating and cathodic protection should 
address these special conditions. The theory behind final Sec. 195.571 
is that if all external surfaces of a pipeline are cathodically 
protected according to the criteria and other considerations in 
paragraphs 6.2 and 6.3 of the NACE Standard, external corrosion will be 
controlled successfully. In practice, if an operator learns though in-
line inspection or other means that because of a special condition 
external corrosion is not being controlled successfully, the operator 
must take corrective action. The operator could either remedy the 
condition or adjust the cathodic protection system to assure the 
adequacy of cathodic protection in the

[[Page 66999]]

area of the special condition. We believe this requirement is implicit 
in final Sec. 195.571. Section 195.573(e) also would require corrective 
action if the condition is detected by monitoring under Sec. 195.573.
    In addition, WUTC was concerned that the proposed rules did not 
specify how long the cathodic protection current may be shut off when 
measuring polarization decay under the minimum 100 mV criterion. WUTC 
suggested that the limit be no more than 48 hours, unless a recording 
chart shows continuing significant decay beyond that time. To satisfy 
the100 mV criterion by the decay method, operators must determine that 
a negative polarization voltage shift of at least 100 mV occurs after 
the immediate voltage shift caused by shutting off the cathodic 
protection current. Whether this minimum negative voltage shift occurs 
in minutes or hours after the current is cut off, it is irrelevant to 
satisfying the criterion. We recognize that the longer the current 
remains off, the greater the opportunity for the pipeline to corrode. 
However, in our experience decay tests have not posed a serious problem 
in this regard to warrant establishing a time limit.
    Finally, WUTC opposed use of the net protective current criterion 
on bare or ineffectively coated hazardous liquid pipelines. WUTC was 
concerned about the criterion being applied only at predetermined 
current discharge points identified through leaks, leak history, or 
electrical surveys, preventing the pipeline from having complete 
cathodic protection against corrosion leaks. WUTC suggested that if we 
allow use of the criterion, we limit its use to pipelines constructed 
before part 195 went into effect. According to part 195's terms, the 
net protective current criterion applies only to bare or ineffectively 
coated pipelines. Because all pipelines subject to part 195 
construction standards must be effectively coated, the net protective 
current criterion will mostly be used on older pipelines constructed 
before those standards took effect. The effective dates for different 
groups of pipelines are stated in Sec. 195.401(c).
    WUTC's primary concern seems to be that we did not propose a 
requirement that operators fully cathodically protect bare or 
ineffectively coated pipelines. We did not propose such action for 
several practical reasons. To cathodically protect these pipelines over 
their entire surface area without first coating or recoating them would 
require very high levels of impressed currents. Cathodic protection 
systems producing such high current levels would be costly to install, 
maintain, and operate. Also, to coat all bare or ineffectively coated 
buried pipelines in order to facilitate cathodic protection could be a 
costly endeavor. We also considered the possibility that raising pipe 
sections to coat them would likely create unanticipated stresses and 
disturb pipe foundations, introducing new risk factors not present in 
the existing pipelines.
    Section 195.573. This section is based on proposed Sec. 195.569. It 
requires operators to monitor the performance of cathodic protection 
facilities and monitor unprotected pipe for active corrosion.
    Final Sec. 195.573(a) enhances proposed Sec. 195.569 with regard to 
determinations of the adequacy of cathodic protection. We edited 
Sec. 195.573(a) to clearly state that operators must conduct tests to 
determine whether cathodic protection complies with Sec. 195.571 and 
not whether cathodic protection is adequate, as proposed. In addition, 
we are concerned that proposed Sec. 195.569 does not provide latitude 
in monitoring separately protected short segments of bare or 
ineffectively coated pipelines, as does the corresponding rule for 
monitoring protected gas pipelines (49 CFR 192.465(a)). The gas rule 
allows monitoring of short protected segments over a 10-year period 
where annual monitoring is impractical. We considered adding a similar 
provision to Sec. 195.573(a) but decided that the 10-year period would 
add more latitude than circumstances warrant on bare or ineffectively 
coated hazardous liquid pipelines. Many operators now monitor short 
protected segments of bare or ineffectively coated lines on the same 
cycle as adjoining unprotected segments. So, rather than use the gas 
rule provision, we added a provision that allows monitoring at 3-year 
intervals which is consistent with the monitoring cycle we are adopting 
for unprotected sections (see discussion of Sec. 195.573(b) below).
    We also addressed the problem of how to test pipelines to determine 
the adequacy of cathodic protection. In complying with existing 
Sec. 195.416(a), which was the basis of proposed Sec. 195.569, 
operators generally conducted electrical surveys. This action involves 
measuring potentials at pre-established test stations, to determine the 
adequacy of cathodic protection. In practice, however, this method of 
compliance has not always been sufficient to assure protection of all 
pipeline surfaces. Corrosion problems often arise in areas between test 
stations where there may be interference currents, different 
environmental conditions, damaged coatings, or malfunctioning anodes. 
So, in order to check on cathodic protection adequacy in greater 
detail, many operators augment test station data with periodic close-
interval electrical surveys or use newer technologies. As WUTC pointed 
out in its comments, these more detailed surveys also help operators 
determine if additional test stations are needed to assure the adequacy 
of cathodic protection.
    Paragraph 10.1.1.3 of NACE Standard RP0169-96 recommends that 
operators use close-interval surveys where they are practicable and 
sound engineering judgment indicates they are necessary.\2\ For this 
reason and because we believe the general method of monitoring cathodic 
protection at established test stations may not always be sufficient, 
we have referenced the NACE provision in final Sec. 195.573(a)(2). 
Although the final rule does not prescribe a frequency of close-
interval surveys, operators will have to describe in their maintenance 
procedures the circumstances in which a close-interval survey or 
comparable technology is practicable and necessary to accomplish the 
objectives of paragraph 10.1.1.3 of the NACE Standard, and then follow 
those procedures.
---------------------------------------------------------------------------

    \2\ Paragraph 10.1.1.3 reads: Where practicable and determined 
necessary by sound engineering practice, a detailed (close-interval) 
potential survey should be conducted to (a) assess the effectiveness 
of the cathodic protection system; (b) provide base line operating 
data; (c) locate areas of inadequate protection levels; (d) identify 
locations likely to be adversely affected by construction, stray 
currents, or other unusual environmental conditions; or (e) select 
areas to be monitored periodically.
---------------------------------------------------------------------------

    In order to provide operators with time to prepare for compliance 
with the new close-interval survey requirement, the compliance date for 
existing pipelines will not be mandatory until December 29, 2003.
    Final Sec. 195.573(b), which is based on proposed Sec. 195.569(c), 
requires that operators must reevaluate their unprotected pipe and 
cathodically protect the pipe where active corrosion is found. 
Operators must determine if active corrosion exists by electrical 
survey where practical, or otherwise by a review and analysis of 
certain maintenance records and the pipeline environment. Proposed 
definitions of the terms ``active corrosion,'' ``electrical survey,'' 
and ``pipeline environment'' are combined with other definitions in 
final Sec. 195.553. Also, final Sec. 195.573(b) applies to ``pipe'' 
rather than ``pipelines'' as proposed, because we did not intend for 
the proposed rule to apply to unprotected breakout tank bottoms. 
Integrity inspection of the bottoms of breakout tanks is covered by 
existing Sec. 195.432.

[[Page 67000]]

    Equilon, Environmental Defense, and NACE argued that because 
unprotected pipelines may deteriorate as they age, operators should 
reevaluate these pipelines at intervals of less than 5 years, the 
maximum interval proposed in the NPRM. They suggested that to be 
consistent with part 192 we set the maximum interval at 3 years, not to 
exceed 39 months. Like these commenters, Iowa also saw a need to add 3 
months to the maximum interval, whether it be 5 or 3 years, to provide 
scheduling and operational flexibility.
    In view of the three comments favoring a 3-year inspection interval 
and the Technical Hazardous Liquid Pipeline Safety Standards 
Committee's unanimous recommendation to establish a maximum 3-year 
interval (see the Advisory Committee Consideration heading below), we 
reconsidered whether the appropriate maximum inspection interval should 
be 3 or 5 years. We considered the fact that the relation between 
relevant risk factors on unprotected pipelines and an appropriate 
inspection interval is uncertain. As discussed in the NPRM, we are also 
seeking to make the corrosion control standards for gas and hazardous 
liquid pipelines consistent wherever reasonable. At present part 192 
prescribes a maximum inspection interval of 3 years for unprotected gas 
pipelines; and part 195 prescribes 5 years. Although there is no 
evidence in the record to demonstrate conclusively the advantage of a 
3-year interval over a 5-year interval, taking into consideration the 
risk to the public and environment, we believe the more conservative 3-
year interval is the prudent choice. Furthermore, we believe this 
choice is reasonable based on our enforcement experience, as well as, 
discussions with industry representatives which indicate that many 
hazardous liquid pipeline operators inspect their unprotected pipelines 
every 3 years. Therefore, the final rule is changed from the proposed 
maximum 5-year interval to a maximum 3-year interval.
    In order to provide operators with time to prepare for compliance 
with the new 3-year inspection interval, compliance will not be 
mandatory until December 29, 2003.
    Equilon and NACE suggested that in-line inspection may be a more 
appropriate alternative to electrical survey than analysis of leak 
repairs and other matters as proposed in Sec. 195.569(c). However, the 
proposed rule did not limit an operator's choice of alternatives to an 
analysis of leak repairs. Rather, where electrical surveys are 
impractical, we proposed the use of any alternative means of 
determining whether active corrosion exists, as long as that means 
includes a review and analysis of leak repair and inspection records, 
corrosion monitoring records, exposed pipe inspection records, and the 
pipeline environment. Under the final rule, if operators have in-line 
inspection data and want to use it as an alternative to electrical 
surveys where such surveys are impractical, they may do so provided 
they interpret the data in light of the required review and analysis of 
other pertinent information.
    WUTC suggested we put the following sentence in the final rule: 
``Each operator shall take prompt remedial action to correct any 
deficiencies indicated by the monitoring.'' We discussed in the NPRM 
why we did not propose such a requirement. We stated that it is 
unnecessary to direct such action due to the existing requirements 
under Sec. 195.401(b). This section requires operators to correct 
within a reasonable time any condition that could adversely affect safe 
operation of a pipeline system; and if an immediate hazard exists, to 
cease operating the affected part of the system until the condition is 
corrected. In addition, on pipelines that could affect high consequence 
areas, new Sec. 195.452(h) requires operators to take prompt actions to 
address integrity issues and to repair certain conditions within 
specific time limits. However, in light of WUTC's comment, we 
established Sec. 195.573(e) to draw attention to the remedial action 
required by existing Secs. 195.401(b) and 195.452(h).
    WUTC also was concerned that the discretion built into the proposed 
definition of ``active corrosion'' would allow operators to ignore 
corrosion leaks detrimental to public safety or the environment. WUTC 
suggested we require operators to classify and schedule all corrosion 
leaks for repair. In response, we believe the purpose of proposed 
Sec. 195.569(c) is to require operators to look for and cathodically 
protect certain areas of corrosion before leaks occur. Operator 
response to leaks, whether due to corrosion or other causes, is not 
covered by new subpart H. Leak response is governed by existing 
Sec. 195.401(b) or Sec. 195.452(h), which together require timely 
corrective action for all unsafe conditions on pipelines subject to 
Part 195.
    Section 195.575. This standard requires electrical isolation to 
provide for adequate cathodic protection. The standard is based on 
proposed Sec. 195.571.
    Enron expressed support for the proposed rule; however, Tosco 
believed we should specify the frequency of inspection and electrical 
tests.
    We did not adopt Tosco's comment because the purpose of the 
proposed inspection and electrical tests is to ensure that electrical 
isolation is adequate when it is installed. All post-installation 
inspections and tests of cathodic protection facilities are covered by 
final Sec. 195.573.
    In final paragraph (d), for clarity, we changed the proposed 
wording ``where a combustible atmosphere is anticipated'' to read 
``where a combustible atmosphere is reasonable to foresee.'' Similarly 
in paragraph (e), we changed the proposed ``where fault currents or 
unusual risk of lightning may be anticipated'' to read ``where it is 
reasonable to foresee fault currents or an unusual risk of lightning.''
    Section 195.577. The purpose of this standard, which is based on 
proposed Sec. 195.575, is to minimize the adverse effects of stray 
currents on pipelines and the effects of impressed currents on adjacent 
structures. Expressing support for the proposed rule, Tosco stated that 
the proposed program to identify, test for, and minimize the 
detrimental effects of stray currents may result in operators 
participating in corrosion coordinating groups. We agree that such 
coordination may be necessary for an effective program.
    Section 195.579. This standard, proposed as Sec. 195.577, requires 
operators to investigate the effects of transporting hazardous liquid 
or carbon dioxide which could corrode the pipeline, and take adequate 
steps to mitigate corrosion. Tosco suggested that in the final rule we 
clarify that the investigation may be done by review of operating 
history. A review of relevant operating history may be a satisfactory 
investigation in some situations. However, we did not explicitly 
include this option in final Sec. 195.579. We used the proposed wording 
because we think it is broad enough to permit operators to use any 
method of investigation that will provide a sound basis for deciding 
how to mitigate internal corrosion adequately.
    Under proposed Sec. 195.577(d), if operators discover harmful 
corrosion inside removed pipe, they must investigate further to 
determine if additional harmful corrosion exists in the vicinity of the 
removed pipe. Phillips suggested that the extent of further 
investigation should depend upon the type of corrosion found and 
whether that corrosion could be expected to extend beyond the exposed 
segment. We do not believe there is a clear understanding of the 
relationship between the type of corrosion and the

[[Page 67001]]

likelihood of finding similar corrosion in the vicinity of removed pipe 
to justify limits on a requirement for additional investigation. The 
effect of corrosive liquids on pipe may be too variable to make such 
predictions with accuracy. Therefore, we did not adopt Phillips' 
comment.
    Section 195.581. This section, based on proposed Sec. 195.579, 
modifies an existing requirement (Sec. 195.416(i)) that all pipelines 
exposed to the atmosphere must be protected against atmospheric 
corrosion by a suitable coating. Final Sec. 195.581 gives operators 
flexibility when deciding to coat pipelines where atmospheric corrosion 
will be limited to a light surface oxide, or will not affect the safe 
operation of the pipeline before the next scheduled inspection. Splash 
zones of offshore pipelines and soil-to-air interfaces of onshore 
pipelines are omitted from this exception.
    Iowa opposed allowing pipe with metal loss to remain unprotected or 
unrepaired. Iowa stated that public safety should not depend on an 
operator's judgment of whether a corroding pipe will not fail before 
the next inspection (which could be up to 3 years). Yet under the 
proposed rule, if an operator chose not to coat, it would have to show 
that testing, investigation, or experience supports the decision. In 
other words, safety would not depend solely on an operator's judgment. 
Also, the need for coating would be reviewed again in 3 years. A 3-year 
delay in coating a pipeline judged to be safe should not jeopardize 
public safety, considering that atmospheric corrosion generally 
progresses at a slow rate. Therefore, we did not adopt Iowa's comment. 
Nevertheless, mindful of Iowa's concern, we edited the final wording to 
clarify that any decision not to coat a particular pipeline must be 
supported by testing, investigation, or experience relevant to that 
pipeline.
    Tosco called the proposed rule ``a positive revision.'' However, 
Enron recommended that we add ``active'' as a descriptor of 
``atmospheric corrosion.'' It believed the term ``active atmospheric 
corrosion'' would clarify that the rule does not apply to harmless 
corrosion. We did not adopt Enron's comment because we think the 
proposed exceptions will satisfy Enron's objective. Also, ``active 
atmospheric corrosion'' is a term that may not be in general use in the 
industry.
    Section 195.583. Under this section, proposed as Sec. 195.581, 
operators must periodically inspect exposed pipelines for atmospheric 
corrosion, giving particular attention to areas such as soil-to-air 
interfaces. Onshore pipelines must be inspected every 3 years; and 
offshore pipelines every year. If any inspection reveals atmospheric 
corrosion, the operator must protect the pipeline against atmospheric 
corrosion in accordance with Sec. 195.581.
    Enron, Equilon, Iowa, and NACE advocated adding a 3 months grace 
period to the maximum 3-year inspection interval. We agree that this 
period is useful to allow operators scheduling and operational 
flexibility, and included it in final Sec. 195.583.
    Tosco wanted to make certain that the proposed remedial action 
would not be required for light surface oxide. By the cross reference 
to Sec. 195.581, final Sec. 195.583 allows operators latitude when 
deciding to coat pipelines which exhibit only a light surface oxide.
    AEC urged us to allow operators to use means of assessment other 
than periodic visual inspection. As an example, AEC commented that by 
using in-line inspection and a corrosion growth model, operators could 
predict when a pipeline should be reinspected or repaired. This 
approach, according to AEC, would enable operators to allocate 
resources for maximum benefits instead of periodically scattering them 
across entire systems. AEC's comment indicates two things: first, AEC 
apparently misunderstood the proposed rule to mandate visual 
inspection; and second, AEC would like operators themselves to decide 
appropriate inspection frequencies with the aid of a corrosion growth 
model. As to the first item, the proposed rule would not limit 
operators to using visual means of inspection. They could use any means 
capable of detecting atmospheric corrosion, including in-line 
inspection devices. As to growth models, AEC did not suggest which 
model, if any, can successfully predict the growth of atmospheric 
corrosion on exposed pipelines in changing and varied environments. 
Furthermore, AEC did not suggest how operators would decide when to 
inspect exposed pipe that has no history of corrosion. Since the record 
of this rulemaking proceeding lacks information on these important 
issues, we have adopted the proposed inspection frequencies as final. 
However, we would welcome receiving more complete information that 
could possibly serve as a basis for changing the rule as AEC suggests.
    AEC also suggested we extend the proposed maximum inspection 
interval for onshore pipelines from 3 years to 5 years. It believes 
that extending the time to 5 years is appropriate because atmospheric 
corrosion rates are low, and exposed pipe is typically located outside 
high consequence areas where the maximum interval for reevaluation of 
pipeline integrity is 5 years (see Sec. 195.452(j)(3)). In developing 
the proposed rule, we considered whether 3 or 5 years would be the 
appropriate maximum interval. We proposed 3 years primarily because the 
ASME B31.4 Code, a widely accepted consensus standards code for 
hazardous liquid pipelines, specifies a minimum 3-year inspection 
frequency for atmospheric corrosion onshore. Generally, atmospheric 
corrosion rates are found to be low and therefore, we must assume this 
factor was considered when the 3-year consensus standard was adopted. 
However, a low rate by itself does not seem to justify a longer 
interval. Also, the 5-year interval for integrity reevaluation in high 
consequence areas is based on various factors besides corrosion rate, 
including the time needed to carry out in-line inspections or pressure 
testing on the pipelines involved. Moreover, the 5-year reevaluation 
applies in addition to other monitoring frequencies required by part 
195, such as annual cathodic protection monitoring and biweekly right-
of-way inspections. Yet, we did not intend the 5-year period to serve 
as a yardstick for determining the adequacy of other monitoring 
frequencies.
    Finally, AEC was concerned about the possible adverse consequences 
of visually inspecting soil-to-air interfaces on pipe spans over creeks 
and ravines. AEC suggested that if the interface is on a steep bank, 
the process of visually examining the pipe could accelerate bank 
erosion causing water pollution and overstress of the pipeline. We 
believe the proposed inspection requirement is flexible enough to allow 
operators to take precautions in inspecting soil-to-air interfaces on 
steep banks to avoid or minimize the disturbance AEC foresees. Should a 
disturbance occur that affects the safe operation of the pipeline, the 
operator would have to correct the problem. We did not change the final 
rule as a result of this comment.
    Section 195.585. This section, which is substantively the same as 
proposed Sec. 195.583, requires operators to take certain actions to 
correct corroded pipe. If general corrosion reduces pipe wall thickness 
to less than that required for the maximum operating pressure of the 
pipeline or if localized corrosion pitting exists to a degree that 
leakage might result, the operator must: replace the pipe; repair the 
pipe; or reduce the maximum operating pressure commensurate with the 
strength of the pipe. We edited the final rule to clarify that it is 
the ``maximum operating pressure'' that must be reduced.

[[Page 67002]]

    Environmental Defense believed this section also should require 
operators to account for why corrosion has become so advanced. This 
commenter suggested operators should review their corrosion control 
systems to ensure that further harmful corrosion will not occur. We 
believe the combination of cathodic protection criteria under 
Sec. 195.571 and periodic monitoring under Sec. 195.573 will accomplish 
the objective of this comment. Whenever an operator discovers a 
corrosion control deficiency, it must review its corrosion control 
system and make adjustments as necessary to provide adequate protection 
against corrosion. If adequate protection cannot be achieved, the pipe 
involved may have to be replaced.
    Section 195.587. This section is based on proposed Sec. 195.585. It 
authorizes, but does not require, operators to use the widely accepted 
ASME B31G criteria for determining the remaining strength of corroded 
steel pipe.
    Iowa fully supported the proposed rule. In contrast, WUTC was 
concerned that because ASME B31G allows wall loss of up to 80 percent 
without repair or replacement, it does not provide a reasonable measure 
of strength needed to withstand cyclical stresses, environmental loads, 
and other combined forces.
    Although WUTC is correct, we consider B31G to be a guide to the 
capability of corroded pipe to withstand internal pressure. Final 
Sec. 195.587 advises operators that B31G sets limits on use of the 
criteria. One limitation states that a pipe subject to significant 
secondary stresses should not be kept in service for the purpose of 
satisfying the criteria (paragraph 1.2(d)). To ensure that operators 
consider the effects of secondary stresses, in final 
Sec. 195.585(a)(1), we added the words ``needed for serviceability'' 
immediately following ``strength of the pipe.'' Consequently, as a 
remedy for generally corroded pipe, operators may reduce maximum 
pressure commensurate with the pipe strength needed for serviceability. 
In determining the amount of pressure reduction required, operators may 
use B31G but also must consider any significant secondary stresses that 
may affect pipe serviceability.
    Section 195.589. Under this section, proposed as Sec. 195.587, 
operators must to keep current records or maps of the location of 
cathodically protected pipelines; cathodic protection facilities 
(including anodes) installed after the Final Rule takes effect; and 
structures bonded to cathodic protection systems. Additionally, 
operators must keep records of required maintenance activities 
including inspections, tests, analyses, checks, demonstrations, 
examinations, investigations, reviews, and surveys. These records must 
demonstrate the adequacy of corrosion control measures, or that 
corrosion requiring control measures does not exist. Operators will 
have to keep these records for at least 5 years, except that records 
related to Sec. 195.569 (examination of pipeline when exposed); 
Secs. 195.573(a) and (c) (monitoring external corrosion control); and 
Secs. 195.579(b)(3) and (c) (monitoring internal corrosion control) 
will have to be kept for as long as the pipeline involved is in 
service.
    Commenting on examinations of exposed pipe, Equilon and NACE 
believed that there is no need to keep records of good pipe for as long 
as the pipeline remains in service, and that there is no need to keep 
records of defective pipe after the latest in-line inspection. Equilon 
and NACE also contended that old records of internal corrosion 
monitoring are of little benefit without knowledge of flow rates, 
upstream pipeline operations, fluid properties, and other information. 
None of these records are generally available. We did not adopt either 
comment because the proposed records provide a useful history of 
pipeline condition and are easy to maintain in electronic form. The 
records may be helpful in assessing corrosion control needs, and could 
be used as a comparative base for evaluating in-line inspection data.
    We also considered the Equilon and NACE comment that subpart H 
should not require operators to keep records of maintenance activities 
that occur before subpart H takes effect. Final Sec. 195.589 
specifically states that records must be kept for certain maintenance 
activities ``required by this subpart.'' For example, final 
Sec. 195.589 does not require operators to keep records of corrosion 
control monitoring conducted before subpart H takes effect. However, 
until subpart H takes effect, Sec. 195.404(c)(3) requires records of 
corrosion control inspections and tests required by subpart F of part 
195. Operators must continue to maintain records established under that 
section for the retention period prescribed.
    Tosco believed we should revise Sec. 195.404(c)(3) to indicate that 
corrosion control records are required by subpart H. However, no 
confusion about the application of Sec. 195.404(c)(3) to corrosion 
control should occur because this section applies only to inspections 
and tests ``required by this subpart,'' meaning, required by subpart F. 
After new subpart H goes into effect, Subpart F will no longer require 
corrosion control inspections and tests.
    Phillips argued that the current 2-year retention requirement in 
Sec. 195.404(c)(3) is adequate for auditing compliance, since 2 years 
of records show the current state of corrosion control. However, as we 
explained in the NPRM, 5 years is the minimum retention period that 
will assure the availability of records for our compliance auditing.
    Environmental Defense stated that it would help government 
inspectors determine the adequacy of cathodic protection systems if we 
required operators to keep records of the location of existing cathodic 
protection facilities and not just those facilities installed after 
subpart H takes effect. While this suggestion has merit, we did not 
propose to require records of existing facilities due to the difficulty 
of creating such records, particularly for galvanic anode systems. 
Also, in our experience the lack of such a requirement has not caused a 
significant problem due to the number of operators who keep records of 
the location of existing corrosion control facilities.

Format and Organization

    In accordance with Federal Register guidelines, we drafted final 
subpart H in an easier to read and understand format. Section headings 
are in the form of questions. We minimized passive voice and used the 
word ``you'' as a substitute for ``operator.'' Also, a few proposed 
sections were eliminated, combined with other sections, or separated 
into two or more sections. This Final Rule also changes Secs. 195.5, 
195.402, 195.404 and removes Secs. 195.236, 195.238, 195.242, 195.244, 
195.414, 195.416, 195.418 to account for the new subpart H.

Advisory Committee Consideration

    We presented the NPRM for consideration by the Technical Hazardous 
Liquid Pipeline Safety Standards Committee (THLPSSC) at a meeting in 
Washington, DC on February 7, 2001 (66 FR 132; Jan. 2, 2001). The 
THLPSSC is RSPA's statutory advisory committee for hazardous liquid 
pipeline safety. The committee has 15 members, representing industry, 
government, and the public. Each member is qualified to consider the 
technical feasibility, reasonableness, cost-effectiveness, and 
practicability of proposed pipeline safety standards. The committee 
voted unanimously to approve proposed subpart H but unanimously 
recommended that we require operators of bare or ineffectively coated 
pipe to inspect the pipe for external corrosion every 3 years. Our 
treatment of this

[[Page 67003]]

recommendation is discussed in the Discussion of Comments section under 
section 195.573. A transcript of the February 7, 2001, meeting is 
available in Docket No. RSPA-98-4470.

Regulatory Analyses and Notices

    Executive Order 12866 and DOT Policies and Procedures. RSPA 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 this rulemaking to review. RSPA also does not 
consider this rulemaking to be significant under DOT regulatory 
policies and procedures (44 FR 11034: February 26, 1979).
    We prepared a Final Regulatory Evaluation of the final rules and a 
copy is in the docket. The evaluation states that the rules are, on the 
whole, comparable either to existing safety standards currently in part 
195 for hazardous liquid pipelines or to existing safety standards in 
part 192 for gas pipelines. The evaluation also states that the 
information presented at public meetings and meetings with industry and 
state representatives strongly suggests that imposing gas pipeline 
safety standards for corrosion control on hazardous liquid pipelines 
would not require a significant departure from customary safety 
practices on liquid pipelines.
    An important feature of the final rules not found in part 192 or 
part 195 is the reference to cathodic protection criteria in NACE 
Standard RP0169-96. The evaluation states that these criteria are well 
known and widely followed throughout the industry, as indicated by 
meetings with industry representatives and by the voluntary standards 
in the ASME B31.4 Code. The evaluation further states that operators 
who do not now apply the NACE criteria are likely to apply the criteria 
in appendix D of part 192. The final rules would allow use of appendix 
D criteria under conditions stated in the NACE Standard. The evaluation 
concludes that there should be only minimal additional cost, if any, 
for operators to comply with the final rules.
    Final Sec. 195.563(c) (protecting effectively coated pipelines), 
Sec. 195.567 (test leads), and Sec. 195.573(a)(2) (monitoring cathodic 
protection by close-interval surveys or comparable technology) are 
changed from the proposed rules. However, the changes are consistent 
with industry practices and should not result in more than minimal 
additional costs.
    Regulatory Flexibility Act. The final rules are consistent with 
customary practices for corrosion control in the hazardous liquid and 
carbon dioxide pipeline industry. Therefore, based on the facts 
available about the anticipated impacts of this rulemaking, I certify, 
pursuant to 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. The final rules have been analyzed in 
accordance with the principles and criteria contained in Executive 
Order 13084, ``Consultation and Coordination with Indian Tribal 
Governments.'' Because the rules will not significantly or uniquely 
affect the communities of the Indian tribal governments and will not 
impose substantial direct compliance costs, the funding and 
consultation requirements of Executive Order 13084 do not apply.
    Paperwork Reduction Act. Section 195.589 contains minor additional 
information collection requirements. Operators will be required to 
record the location of certain newly installed protection facilities, 
and keep these records for as long as the pipeline concerned is in 
service. In addition, records of inspections, tests, and other 
maintenance actions will have to be kept for as long as the pipeline is 
in service or for 5 years, depending on the nature of the information 
recorded. The present minimum retention period for records of 
inspections and tests is 2 years or the prescribed interval of test or 
inspection, whichever is longer (up to 5 years in some cases).
    Hazardous liquid pipeline operators are required to keep records 
under Information Collection 2137-0047, Transportation of Hazardous 
Liquids by Pipeline: Record Keeping and Reporting Requirements. 
Operators already maintain records of the location of their protection 
facilities for as long as the pipeline is in service. They do so to 
find the facilities for their own purposes and to carry out existing 
monitoring requirements in part 195. Also, we believe the burden of 
retaining inspection, test, and survey records for the longer period 
will be minimal. These records are largely computerized and maintaining 
these records in a computer file represents very minimal costs. Because 
the additional paperwork burdens of this final rule are likely to be 
minimal, 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 rulemaking will not 
impose unfunded mandates under the Unfunded Mandates Reform Act of 
1995. It will 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 rule.
    National Environmental Policy Act. We have analyzed the final rules 
for purposes of the National Environmental Policy Act (42 U.S.C. 4321 
et seq.). Because the rules parallel present requirements or practices, 
we have determined they will not significantly affect the quality of 
the human environment. An environmental assessment document is 
available for review in the docket. We also made a finding of no 
significant impact.
    Impact on Business Processes and Computer Systems. We do not want 
to impose new requirements that mandate business process changes when 
the resources necessary to implement those requirements could otherwise 
be applied to ``Y2K'' or related computer problems. The final rules do 
not mandate business process changes or require modifications to 
computer systems. Because the rules do not affect the ability of 
organizations to respond to those problems, we have not delayed the 
effectiveness of the requirements.
    Executive Order 13132. The final rules have been analyzed in 
accordance with the principles and criteria contained in Executive 
Order 13132 (``Federalism''). The final rules do not contain any 
regulation that (1) has substantial direct effects on the States, the 
relationship between the national government and the States, or the 
distribution of power and responsibilities among the various levels of 
government; (2) imposes substantial direct compliance costs on State 
and local governments; or (3) preempts state law. Therefore, the 
consultation and funding requirements of Executive Order 13132 do not 
apply. Nevertheless, during our review of the existing corrosion 
control standards, representatives of state pipeline safety agencies 
gave us advice both in private sessions and in the two public meetings 
we held. In addition, our pipeline safety advisory committees, which 
include representatives of state governments, were, on two occasions in 
1999, briefed on the corrosion control review project.
    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

[[Page 67004]]

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 195

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

    In consideration of the foregoing, 49 CFR part 195 is amended as 
follows:

PART 195--[AMENDED]

    1. 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.

    2. Section 195.3 is amended by adding paragraphs (b)(8) and (c)(7) 
to read as follows:


Sec. 195.3  Matter incorporated by reference.

* * * * *
    (b) * * *
    (8) NACE International, 1440 South Creek Drive, Houston, TX 77084.
    (c) * * *
    (7) NACE International (NACE):
    (i) NACE Standard RP0169-96, ``Control of External Corrosion on 
Underground or Submerged Metallic Piping Systems' (1996).
    (ii) [Reserved]
    3. Section 195.5(b) is revised to read as follows:


Sec. 195.5  Conversion to service subject to this part.

* * * * *
    (b) A pipeline that qualifies for use under this section need not 
comply with the corrosion control requirements of subpart H of this 
part until 12 months after it is placed into service, notwithstanding 
any previous deadlines for compliance.
* * * * *
    4. Section 195.402(c)(3) is revised to read as follows:


Sec. 195.402  Procedural manual for operations, maintenance, and 
emergencies.

* * * * *
    (c) * * *
    (3) Operating, maintaining, and repairing the pipeline system in 
accordance with each of the requirements of this subpart and subpart H 
of this part.
* * * * *


Sec. 195.404  [Amended]

    5. In Sec. 195.404, paragraph (a)(1)(v) is removed, and paragraphs 
(a)(1)(vi) through (a)(1)(viii) are redesignated as paragraphs 
(a)(1)(v) through (a)(1)(vii).


Secs. 195.236, 195.238, 195.242, 195.244, 195.414, 195.416, 
195.418  [Removed]

    6. The following sections are removed and reserved: Secs. 195.236, 
195.238, 195.242, 195.244, 195.414, 195.416, and 195.418.
    7. Subpart H is added to read as follows:

Subpart H--Corrosion Control

Sec.
195.551  What do the regulations in this subpart cover?
195.553  What special definitions apply to this subpart?
195.555  What are the qualifications for supervisors?
195.557  Which pipelines must have coating for external corrosion 
control?
195.559  What coating material may I use for external corrosion 
control?
195.561  When must I inspect pipe coating used for external 
corrosion control?
195.563  Which pipelines must have cathodic protection?
195.565  How do I install cathodic protection on breakout tanks?
195.567  Which pipelines must have test leads and how do I install 
and maintain the leads?
195.569  Do I have to examine exposed portions of buried pipelines?
195.571  What criteria must I use to determine the adequacy of 
cathodic protection?
195.573  What must I do to monitor external corrosion control?
195.575  Which facilities must I electrically isolate and what 
inspections, tests, and safeguards are required?
195.577  What must I do to alleviate interference currents?
195.579  What must I do to mitigate internal corrosion?
195.581  Which pipelines must I protect against atmospheric 
corrosion and what coating material may I use?
195.583  What must I do to monitor atmospheric corrosion control?
195.585  What must I do to correct corroded pipe?
195.587  What methods are available to determine the strength of 
corroded pipe?
195.589  What corrosion control information do I have to maintain?

Subpart H--Corrosion Control


Sec. 195.551  What do the regulations in this subpart cover?

    This subpart prescribes minimum requirements for protecting steel 
pipelines against corrosion.


Sec. 195.553  What special definitions apply to this subpart?

    As used in this subpart--
    Active corrosion means continuing corrosion which, unless 
controlled, could result in a condition that is detrimental to public 
safety or the environment.
    Buried means covered or in contact with soil.
    Electrical survey means a series of closely spaced pipe-to-soil 
readings over a pipeline that are subsequently analyzed to identify 
locations where a corrosive current is leaving the pipeline.
    Pipeline environment includes soil resistivity (high or low), soil 
moisture (wet or dry), soil contaminants that may promote corrosive 
activity, and other known conditions that could affect the probability 
of active corrosion.
    You means operator.


Sec. 195.555  What are the qualifications for supervisors?

    You must require and verify that supervisors maintain a thorough 
knowledge of that portion of the corrosion control procedures 
established under Sec. 195.402(c)(3) for which they are responsible for 
insuring compliance.


Sec. 195.557  Which pipelines must have coating for external corrosion 
control?

    Except bottoms of aboveground breakout tanks, each buried or 
submerged pipeline must have an external coating for external corrosion 
control if the pipeline is--
    (a) Constructed, relocated, replaced, or otherwise changed after 
the applicable date in Sec. 195.401(c), not including the movement of 
pipe covered by Sec. 195.424; or
    (b) Converted under Sec. 195.5 and--
    (1) Has an external coating that substantially meets Sec. 195.559 
before the pipeline is placed in service; or
    (2) Is a segment that is relocated, replaced, or substantially 
altered.


Sec. 195.559  What coating material may I use for external corrosion 
control?

    Coating material for external corrosion control under Sec. 195.557 
must--
    (a) Be designed to mitigate corrosion of the buried or submerged 
pipeline;
    (b) Have sufficient adhesion to the metal surface to prevent under 
film migration of moisture;
    (c) Be sufficiently ductile to resist cracking;
    (d) Have enough strength to resist damage due to handling and soil 
stress;
    (e) Support any supplemental cathodic protection; and
    (f) If the coating is an insulating type, have low moisture 
absorption and provide high electrical resistance.


Sec. 195.561  When must I inspect pipe coating used for external 
corrosion control?

    (a) You must inspect all external pipe coating required by 
Sec. 195.557 just prior to lowering the pipe into the ditch or 
submerging the pipe.
    (b) You must repair any coating damage discovered.

[[Page 67005]]

Sec. 195.563  Which pipelines must have cathodic protection?

    (a) Each buried or submerged pipeline that is constructed, 
relocated, replaced, or otherwise changed after the applicable date in 
Sec. 195.401(c) must have cathodic protection. The cathodic protection 
must be in operation not later than 1 year after the pipeline is 
constructed, relocated, replaced, or otherwise changed, as applicable.
    (b) Each buried or submerged pipeline converted under Sec. 195.5 
must have cathodic protection if the pipeline--
    (1) Has cathodic protection that substantially meets Sec. 195.571 
before the pipeline is placed in service; or
    (2) Is a segment that is relocated, replaced, or substantially 
altered.
    (c) All other buried or submerged pipelines that have an effective 
external coating must have cathodic protection.\1\ Except as provided 
by paragraph (d) of this section, this requirement does not apply to 
breakout tanks and does not apply to buried piping in breakout tank 
areas and pumping stations until December 29, 2003.
---------------------------------------------------------------------------

    \1\ A pipeline does not have an effective external coating 
material if the current required to cathodically protect the 
pipeline is substantially the same as if the pipeline were bare.
---------------------------------------------------------------------------

    (d) Bare pipelines, breakout tank areas, and buried pumping station 
piping must have cathodic protection in places where regulations in 
effect before January 28, 2002 required cathodic protection as a result 
of electrical inspections. See previous editions of this part in 49 
CFR, parts 186 to 199.
    (e) Unprotected pipe must have cathodic protection if required by 
Sec. 195.573(b).


Sec. 195.565  How do I install cathodic protection on breakout tanks?

    After October 2, 2000, when you install cathodic protection under 
Sec. 195.563(a) to protect the bottom of an aboveground breakout tank 
of more than 500 barrels (79.5m3) capacity built to API 
Specification 12F, API Standard 620, or API Standard 650 (or its 
predecessor Standard 12C), you must install the system in accordance 
with API Recommended Practice 651. However, installation of the system 
need not comply with API Recommended Practice 651 on any tank for which 
you note in the corrosion control procedures established under 
Sec. 195.402(c)(3) why compliance with all or certain provisions of API 
Recommended Practice 651 is not necessary for the safety of the tank.


Sec. 195.567  Which pipelines must have test leads and what must I do 
to install and maintain the leads?

    (a) General. Except for offshore pipelines, each buried or 
submerged pipeline or segment of pipeline under cathodic protection 
required by this subpart must have electrical test leads for external 
corrosion control. However, this requirement does not apply until 
December 27, 2004 to pipelines or pipeline segments on which test leads 
were not required by regulations in effect before January 28, 2002.
    (b) Installation. You must install test leads as follows:
    (1) Locate the leads at intervals frequent enough to obtain 
electrical measurements indicating the adequacy of cathodic protection.
    (2) Provide enough looping or slack so backfilling will not unduly 
stress or break the lead and the lead will otherwise remain 
mechanically secure and electrically conductive.
    (3) Prevent lead attachments from causing stress concentrations on 
pipe.
    (4) For leads installed in conduits, suitably insulate the lead 
from the conduit.
    (5) At the connection to the pipeline, coat each bared test lead 
wire and bared metallic area with an electrical insulating material 
compatible with the pipe coating and the insulation on the wire.
    (c) Maintenance. You must maintain the test lead wires in a 
condition that enables you to obtain electrical measurements to 
determine whether cathodic protection complies with Sec. 195.571.


Sec. 195.569  Do I have to examine exposed portions of buried 
pipelines?

    Whenever you have knowledge that any portion of a buried pipeline 
is exposed, you must examine the exposed portion for evidence of 
external corrosion if the pipe is bare, or if the coating is 
deteriorated. If you find external corrosion requiring corrective 
action under Sec. 195.585, you must investigate circumferentially and 
longitudinally beyond the exposed portion (by visual examination, 
indirect method, or both) to determine whether additional corrosion 
requiring remedial action exists in the vicinity of the exposed 
portion.


Sec. 195.571  What criteria must I use to determine the adequacy of 
cathodic protection?

    Cathodic protection required by this subpart must comply with one 
or more of the applicable criteria and other considerations for 
cathodic protection contained in paragraphs 6.2 and 6.3 of NACE 
Standard RP0169-96 (incorporated by reference, see Sec. 195.3).


Sec. 195.573  What must I do to monitor external corrosion control?

    (a) Protected pipelines. You must do the following to determine 
whether cathodic protection required by this subpart complies with 
Sec. 195.571:
    (1) Conduct tests on the protected pipeline at least once each 
calendar year, but with intervals not exceeding 15 months. However, if 
tests at those intervals are impractical for separately protected short 
sections of bare or ineffectively coated pipelines, testing may be done 
at least once every 3 calendar years, but with intervals not exceeding 
39 months.
    (2) Identify before December 29, 2003 or not more than 2 years 
after cathodic protection is installed, whichever comes later, the 
circumstances in which a close-interval survey or comparable technology 
is practicable and necessary to accomplish the objectives of paragraph 
10.1.1.3 of NACE Standard RP0169-96 (incorporated by reference, see 
Sec. 195.3).
    (b) Unprotected pipe. You must reevaluate your unprotected buried 
or submerged pipe and cathodically protect the pipe in areas in which 
active corrosion is found, as follows:
    (1) Determine the areas of active corrosion by electrical survey, 
or where an electrical survey is impractical, by other means that 
include review and analysis of leak repair and inspection records, 
corrosion monitoring records, exposed pipe inspection records, and the 
pipeline environment.
    (2) For the period in the first column, the second column 
prescribes the frequency of evaluation.

------------------------------------------------------------------------
                  Period                        Evaluation frequency
------------------------------------------------------------------------
Before December 29, 2003..................  At least once every 5
                                             calendar years, but with
                                             intervals not exceeding 63
                                             months.
Beginning December 29, 2003...............  At least once every 3
                                             calendar years, but with
                                             intervals not exceeding 39
                                             months.
------------------------------------------------------------------------

    (c) Rectifiers and other devices. You must electrically check for 
proper performance each device in the first column at the frequency 
stated in the second column.

[[Page 67006]]



------------------------------------------------------------------------
                  Device                           Check frequency
------------------------------------------------------------------------
Rectifier.................................  At least six times each
                                             calendar year, but with
                                             intervals not exceeding 2\1/
                                             2\ months.
Reverse current switch....................
Diode.....................................
Interference bond whose failure would
 jeopardize structural protection.
Other interference bond...................  At least once each calendar
                                             year, but with intervals
                                             not exceeding 15 months.
------------------------------------------------------------------------

    (d) Breakout tanks. You must inspect each cathodic protection 
system used to control corrosion on the bottom of an aboveground 
breakout tank to ensure that operation and maintenance of the system 
are in accordance with API Recommended Practice 651. However, this 
inspection is not required if you note in the corrosion control 
procedures established under Sec. 195.402(c)(3) why compliance with all 
or certain operation and maintenance provisions of API Recommended 
Practice 651 is not necessary for the safety of the tank.
    (e) Corrective action. You must correct any identified deficiency 
in corrosion control as required by Sec. 195.401(b). However, if the 
deficiency involves a pipeline in an integrity management program under 
Sec. 195.452, you must correct the deficiency as required by 
Sec. 195.452(h).


Sec. 195.575  Which facilities must I electrically isolate and what 
inspections, tests, and safeguards are required?

    (a) You must electrically isolate each buried or submerged pipeline 
from other metallic structures, unless you electrically interconnect 
and cathodically protect the pipeline and the other structures as a 
single unit.
    (b) You must install one or more insulating devices where 
electrical isolation of a portion of a pipeline is necessary to 
facilitate the application of corrosion control.
    (c) You must inspect and electrically test each electrical 
isolation to assure the isolation is adequate.
    (d) If you install an insulating device in an area where a 
combustible atmosphere is reasonable to foresee, you must take 
precautions to prevent arcing.
    (e) If a pipeline is in close proximity to electrical transmission 
tower footings, ground cables, or counterpoise, or in other areas where 
it is reasonable to foresee fault currents or an unusual risk of 
lightning, you must protect the pipeline against damage from fault 
currents or lightning and take protective measures at insulating 
devices.


Sec. 195.577  What must I do to alleviate interference currents?

    (a) For pipelines exposed to stray currents, you must have a 
program to identify, test for, and minimize the detrimental effects of 
such currents.
    (b) You must design and install each impressed current or galvanic 
anode system to minimize any adverse effects on existing adjacent 
metallic structures.


Sec. 195.579  What must I do to mitigate internal corrosion?

    (a) General. If you transport any hazardous liquid or carbon 
dioxide that would corrode the pipeline, you must investigate the 
corrosive effect of the hazardous liquid or carbon dioxide on the 
pipeline and take adequate steps to mitigate internal corrosion.
    (b) Inhibitors. If you use corrosion inhibitors to mitigate 
internal corrosion, you must--
    (1) Use inhibitors in sufficient quantity to protect the entire 
part of the pipeline system that the inhibitors are designed to 
protect;
    (2) Use coupons or other monitoring equipment to determine the 
effectiveness of the inhibitors in mitigating internal corrosion; and
    (3) Examine the coupons or other monitoring equipment at least 
twice each calendar year, but with intervals not exceeding 7\1/2\ 
months.
    (c) Removing pipe. Whenever you remove pipe from a pipeline, you 
must inspect the internal surface of the pipe for evidence of 
corrosion. If you find internal corrosion requiring corrective action 
under Sec. 195.585, you must investigate circumferentially and 
longitudinally beyond the removed pipe (by visual examination, indirect 
method, or both) to determine whether additional corrosion requiring 
remedial action exists in the vicinity of the removed pipe.
    (d) Breakout tanks. After October 2, 2000, when you install a tank 
bottom lining in an aboveground breakout tank built to API 
Specification 12F, API Standard 620, or API Standard 650 (or its 
predecessor Standard 12C), you must install the lining in accordance 
with API Recommended Practice 652. However, installation of the lining 
need not comply with API Recommended Practice 652 on any tank for which 
you note in the corrosion control procedures established under 
Sec. 195.402(c)(3) why compliance with all or certain provisions of API 
Recommended Practice 652 is not necessary for the safety of the tank.


Sec. 195.581  Which pipelines must I protect against atmospheric 
corrosion and what coating material may I use?

    (a) You must clean and coat each pipeline or portion of pipeline 
that is exposed to the atmosphere, except pipelines under paragraph (c) 
of this section.
    (b) Coating material must be suitable for the prevention of 
atmospheric corrosion.
    (c) Except portions of pipelines in offshore splash zones or soil-
to-air interfaces, you need not protect against atmospheric corrosion 
any pipeline for which you demonstrate by test, investigation, or 
experience appropriate to the environment of the pipeline that 
corrosion will--
    (1) Only be a light surface oxide; or
    (2) Not affect the safe operation of the pipeline before the next 
scheduled inspection.


Sec. 195.583  What must I do to monitor atmospheric corrosion control?

    (a) You must inspect each pipeline or portion of pipeline that is 
exposed to the atmosphere for evidence of atmospheric corrosion, as 
follows:

------------------------------------------------------------------------
                                                Then the frequency of
        If the pipeline is located:                inspection is:
------------------------------------------------------------------------
Onshore...................................  At least once every 3
                                             calendar years, but with
                                             intervals not exceeding 39
                                             months.
Offshore..................................  At least once each calendar
                                             year, but with intervals
                                             not exceeding 15 months.
------------------------------------------------------------------------

    (b) During inspections you must give particular attention to pipe 
at soil-to-air interfaces, under thermal insulation, under disbonded 
coatings, at pipe supports, in splash zones, at deck penetrations, and 
in spans over water.
    (c) If you find atmospheric corrosion during an inspection, you 
must provide protection against the corrosion as required by 
Sec. 195.581.


Sec. 195.585  What must I do to correct corroded pipe?

    (a) General corrosion. If you find pipe so generally corroded that 
the remaining wall thickness is less than that required for the maximum 
operating pressure of the pipeline, you must replace the pipe. However, 
you need not replace the pipe if you--
    (1) Reduce the maximum operating pressure commensurate with the 
strength of the pipe needed for serviceability based on actual 
remaining wall thickness; or

[[Page 67007]]

    (2) Repair the pipe by a method that reliable engineering tests and 
analyses show can permanently restore the serviceability of the pipe.
    (b) Localized corrosion pitting. If you find pipe that has 
localized corrosion pitting to a degree that leakage might result, you 
must replace or repair the pipe, unless you reduce the maximum 
operating pressure commensurate with the strength of the pipe based on 
actual remaining wall thickness in the pits.


Sec. 195.587  What methods are available to determine the strength of 
corroded pipe?

    Under Sec. 195.585, you may use the procedure in ASME B31G, 
``Manual for Determining the Remaining Strength of Corroded 
Pipelines,'' or the procedure developed by AGA/Battelle, ``A Modified 
Criterion for Evaluating the Remaining Strength of Corroded Pipe (with 
RSTRENG disk),'' to determine the strength of corroded pipe based on 
actual remaining wall thickness. These procedures apply to corroded 
regions that do not penetrate the pipe wall, subject to the limitations 
set out in the respective procedures.


Sec. 195.589  What corrosion control information do I have to maintain?

    (a) You must maintain current records or maps to show the location 
of--
    (1) Cathodically protected pipelines;
    (2) Cathodic protection facilities, including galvanic anodes, 
installed after January 28, 2002; and
    (3) Neighboring structures bonded to cathodic protection systems.
    (b) 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.
    (c) You must maintain a record of each analysis, check, 
demonstration, examination, inspection, investigation, review, survey, 
and test required by this subpart in sufficient detail to demonstrate 
the adequacy of corrosion control measures or that corrosion requiring 
control measures does not exist. You must retain these records for at 
least 5 years, except that records related to Secs. 195.569, 195.573(a) 
and (b), and 195.579(b)(3) and (c) must be retained for as long as the 
pipeline remains in service.

    Issued in Washington, DC on December 19, 2001.
Ellen G. Engleman,
Administrator.
[FR Doc. 01-31655 Filed 12-26-01; 8:45 am]
BILLING CODE 4910-60-P