[Federal Register Volume 64, Number 66 (Wednesday, April 7, 1999)]
[Proposed Rules]
[Pages 16885-16889]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 99-8628]


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DEPARTMENT OF TRANSPORTATION

Research and Special Programs Administration

49 CFR Parts 192 and 195

[Docket No. RSPA-97-2762; Notice 2]
RIN 2137-AD24


Pipeline Safety: Corrosion Control on Gas and Hazardous Liquid 
Pipelines

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

ACTION: Notice of public meeting and request for comments.

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SUMMARY: We are considering the need to modify our corrosion control 
standards for gas and hazardous liquid pipelines. To start, we are 
reviewing the gas standards to see if any need to be clarified, made 
more effective, or upgraded to be consistent with modern safety 
practices. The review will help us carry out the President's Regulatory 
Reinvention Initiative and determine if rule changes are needed to 
reduce the potential for corrosion-caused incidents. So far, we have 
held a public meeting and met with knowledgeable persons from industry 
and state regulatory agencies on the adequacy of the standards. Now, to 
get feedback on the results of these efforts, interested persons are 
invited to participate in a second public meeting and to submit written 
comments on the matters discussed in this notice. The public meeting 
will be in conjunction with the National Association of Corrosion 
Engineers (NACE) 54th Annual Conference and Exhibition, CORROSION/99, 
in San Antonio, Texas.

DATES: The public meeting will be on April 28, 1999, from 8:00 am to 
12:00 noon at the Marriott Riverwalk Hotel in San Antonio, Texas. If 
you want to make an oral presentation at the meeting, please notify 
Jenny Donohue no later than April 23, 1999, by phone (202-366-4046) or 
by Internet e-mail ([email protected]), and indicate the 
approximate length of your presentation. In addition, no later than 
June 30, 1999, you may submit written comments by mailing or delivering 
an original and two copies to the Dockets Facility, U.S. Department of 
Transportation, Room PL-401, 400 Seventh Street, SW, Washington, DC 
20590-0001. Or you may submit written comments to the docket 
electronically. To do so, log on to the following Internet Web address: 
http://dms.dot.gov. Click on ``Help & Information'' for instructions on 
how to file a document electronically. All

[[Page 16886]]

written comments should identify the docket and notice numbers stated 
in the heading of this notice. Anyone who wants confirmation of mailed 
comments must include a self-addressed stamped postcard. Late filed 
comments will be considered so far as practicable.

ADDRESSES: The Marriott Riverwalk Hotel is located at 101 Bowie Street, 
San Antonio, TX 78205, phone: (210) 223-1000. The Dockets Facility is 
located on the plaza level of the Nassiff Building, Room PL-401, 400 
Seventh Street, SW, Washington, DC. It is open from 10:00 a.m. to 5:00 
p.m., Monday through Friday, except federal holidays when it is closed.

FOR FURTHER INFORMATION CONTACT: Richard Lopez by phone at 713-718-3956 
or by Internet e-mail at [email protected]. You can read 
comments and other material in the docket (RSPA-97-2762) at this 
Internet Web address: http://dms.dot.gov. General information about our 
pipeline safety program is available at this Internet Web address: 
http://ops.dot.gov. Graphs showing the rate of pipeline incidents due 
to corrosion will also be posted at that Web address.

SUPPLEMENTARY INFORMATION:

Background

    Outside-force damage and corrosion are, respectively, the number 
one and number two causes of reported incidents on gas and hazardous 
liquid pipelines. Persons who participated in our Risk Assessment 
Prioritization (RAP) program, which we use to allocate our resources, 
rated the risk of outside-force damage as ``very high'' and the risk of 
corrosion as ``high.'' In an effort to reduce outside-force damage, we 
have established standards for operator programs designed to prevent 
excavation damage and for state programs that oversee one-call 
notification systems. Recently we began working with other concerned 
organizations to inform the public on ways to reduce damage to all 
underground utilities and to study and promote the use of the best 
practices in damage prevention. For the corrosion risk, RAP 
participants identified several risk mitigating activities, the more 
significant of which, such as creating risk-based inspection programs, 
establishing cathodic protection criteria for hazardous liquid 
pipelines, and defining electrical survey alternatives, are among the 
concerns mentioned below.
    Our statistical analyses of the data that operators report under 49 
CFR Parts 191 and 195 show that while corrosion remains the second 
leading cause of reported pipeline incidents, the rate of reportable 
incidents due to corrosion has declined in recent years. Also, as shown 
by the table below for the period 1986 through 1998, the likelihood of 
corrosion-caused incidents harming people or the environment continues 
to be relatively low. Still, we think the record warrants our attention 
and indicates there may be reasons to improve our corrosion control 
standards to reduce the potential for future incidents. We are 
especially interested in evaluating the best long-term corrosion 
control measures to determine if cost-effective means of further 
reducing corrosion can be implemented.

 
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                                                                                                      Percent of
                                                               Percent of   Percent of   Percent of      all
                          Pipeline                                all       all deaths      all        property
                                                               incidents                  injuries     damages
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Gas transmission and gathering..............................         22.7            0          3.7           13
Gas distribution (non-plastic)..............................          4.9          5.6          7.0          3.9
Hazardous liquid............................................         25.7          3.2          0.9           20
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    To evaluate alternative regulatory strategies and in further 
response to the President's Regulatory Reinvention Initiative 
1, on September 8, 1997, we held a public meeting on how the 
corrosion control standards in 49 CFR Parts 192 and 195 might be 
improved (62 FR 44436; Aug. 21, 1997). The meeting was held in Oakbrook 
Illinois in conjunction with NACE's Fall Committee Meetings to attract 
participation by experts in corrosion control. NACE is an international 
organization that provides training and certification programs, 
conferences, standards, and reports on the prevention and control of 
materials corrosion.
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    \1\ On March 4, 1995, President Clinton issued a memorandum to 
heads of departments and agencies calling for a review of all agency 
regulations and elimination or revision of those that are outdated 
or in need of reform.
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    The Oakbrook meeting focused primarily on whether our corrosion 
control standards should incorporate by reference NACE Standard RP0169-
96, ``Control of External Corrosion on Underground or Submerged 
Metallic Piping Systems,'' as a substitute for all or some of the 
requirements, and whether the requirements should be the same for gas 
and hazardous liquid pipelines. Many participants and subsequent 
commenters opposed incorporating the NACE document by reference because 
it is not entirely written in regulatory, or mandatory, style. There 
was also general agreement that although some changes may be needed, 
our corrosion control standards for gas and hazardous liquid pipelines 
should be generally the same.
    After the Oakbrook meeting, we began a detailed review of the 
corrosion control standards in 49 CFR Part 192, Subpart I. We began 
reviewing the gas pipeline standards rather than the standards for 
hazardous liquid pipelines in Part 195 because the gas standards 
provide more detailed criteria. To help in this effort, we have met 
from time to time with representatives from NACE, the pipeline 
industry, and state governments. The meetings have helped us assess 
whether the Subpart I standards are adequate for safety, need 
clarification, or allow the use of new technologies.
    In order to have the same standards for gas and hazardous liquid 
pipelines, we are now considering whether the gas pipeline standards, 
possibly with some changes, would be suitable for hazardous liquid 
pipelines. The advantage of applying the gas standards to hazardous 
liquid pipelines is that the gas standards are less ambiguous than the 
hazardous liquid standards. However, changes besides those that may be 
needed for gas pipelines may be needed to accommodate the different 
operating characteristics of hazardous liquid pipelines, such as 
temperature and commodity corrosiveness.
    To optimize our review process, we have assigned the following 
priorities to different segments of the nation's pipeline 
infrastructure: We are considering hazardous liquid pipelines first, 
because the current Part 195 corrosion control standards are ambiguous 
in many respects and because corrosion-caused failures on these lines 
pose risks to the

[[Page 16887]]

environment as well as public safety. Next in importance are gas 
transmission and non-rural gathering lines because of the continuing 
high percentage of corrosion-caused incidents. Finally comes gas 
distribution lines, because assessing the need to modify standards to 
account for operational differences between gas transmission and 
distribution lines and among gas distribution systems is more 
difficult, requiring more information about systems and possible 
alternatives to present standards. These three stages of review may 
result in publication of one or more notices of proposed rulemaking 
later this year after considering all the comments we receive as a 
result of this notice.

Guiding Principles

    At our latest meetings with industry and state representatives, in 
Houston, Texas on February 16-19, 1999, at the Marriott Westside Hotel, 
and in Washington, DC on March 11, 1999, at our headquarters, the 
following principles were developed to guide our assessment of the need 
to improve or clarify the corrosion control standards:
     Evaluate existing data and use the evaluation to assess 
the need to change standards.
     Continue to improve public safety and environmental 
protection.
     Assess the need for corrosion control standards throughout 
the national pipeline system based on the risk associated with 
different parts of the system.
     Upgrade regulations to allow for future changes in 
pipeline industry technology and operating practices as appropriate.
     Strive for uniform interpretation/enforcement.
     To the extent practicable, involve all interested parties 
in assessing the need to change standards.
     Use the new cost/benefit policy framework being developed 
for RSPA's pipeline safety advisory committees in determining the costs 
and benefits of potential changes to standards.
     Achieve balance between performance and prescriptive 
language.
     Develop performance measures to assess the effectiveness 
of corrosion control programs.
     Focus on managing corrosion to maintain pipeline 
integrity.
     Provide adequate regulatory flexibility to allow operators 
to implement alternative measures that meet the performance 
requirements of the corrosion regulations.

RSPA Concerns

    Besides the guiding principles, the meetings with industry and 
state representatives have helped us evaluate the following concerns we 
have about the adequacy of the gas pipeline corrosion control 
standards. These concerns relate generally to the clarity of the 
standards, whether the standards are effective, whether they are 
consistent with modern practices, and whether they are in the interest 
of safety. The list does not include Sec. 192.459, for which we have 
already proposed changes to deal with the problem of the extent of 
corrosion on exposed pipelines (Docket PS-107; 54 FR 27041; June 27, 
1989). If we were to propose changes to Part 195 based on the corrosion 
control standards in Subpart I of Part 192, we would include in the 
proposal any changes that may be necessary to make Part 195 consistent 
with any changes made to Sec. 192.459 in Docket PS-107.
    The concerns stated below relate to the Subpart I standards in 49 
CFR Part 192, which apply to metallic gas gathering, transmission, and 
distribution lines. As mentioned above, we are considering both the 
need to change these standards in response to the concerns and whether 
to apply the standards, with or without changes, to hazardous liquid 
pipelines subject to 49 CFR Part 195.

Personnel Qualification (Sec. 192.453)

     In view of the proposed rules on qualification of pipeline 
personnel (63 FR 57269; Oct. 27, 1998), are more specific qualification 
standards needed for individuals who direct or carry out corrosion 
control procedures? (The proposed rules apply to personnel doing 
regulated operation and maintenance tasks, including corrosion control, 
on regulated pipeline facilities. However, the proposed rules do not 
apply to management personnel who may oversee but not perform 
corrosion-related tasks on a pipeline.)

External Corrosion: New Pipelines (Sec. 192.455)

     Should a cathodic protection system be installed on 
offshore pipelines in less than 1 year after the pipeline is 
constructed, for example, 60 days, because of the strong corrosiveness 
of salt water?
     Is it in the interest of safety to exempt pipelines in 
particular environments and temporary pipelines from the coating and 
cathodic protection requirements?

External Corrosion: Existing Pipelines (Sec. 192.457)

     Should existing compressor, regulator, and measuring 
station piping continue to be excluded from the requirement to 
cathodically protect effectively coated transmission line pipe?
     Is the present requirement to cathodically protect certain 
older existing pipelines only in areas of ``active corrosion'' adequate 
for public safety? If not, what would be a cost effective alternative 
standard?
     Is the meaning of ``active corrosion'' clear and 
technically sound? If not, how should it be changed?

External Corrosion: Coating (Sec. 192.461)

     Should the implicit requirement to coat field joints and 
repairs be expressly stated? Does coating need to be compatible with 
the anticipated service conditions, including the effects of 
temperature?
     For offshore pipelines, during installation, are special 
measures necessary to protect against damage to coating, including 
field joint coating; and, to avoid mechanical damage, are special 
coatings needed on J-tubes, I-tubes and pipelines installed by the 
bottom tow method?

External Corrosion: Cathodic Protection Criteria (Sec. 192.463)

     Are the cathodic protection system criteria in Appendix D 
of Part 192, 300 mV shift and E-log-I, obsolete, since they are not in 
NACE Standard RP0169-96? If so, should operators be allowed to continue 
to use them on existing pipe, but not new pipe?

External Corrosion: Monitoring (Sec. 192.465)

     Does the sampling basis prescribed for inspecting short 
sections of main or transmission lines not in excess of 100 feet and 
separately protected service lines provide effective corrosion control, 
particularly as it applies to service lines that supply gas to public 
buildings?

External Corrosion: Electrical Isolation (Sec. 192.467)

     What remedial action is needed when an electrical short in 
a casing results in inadequate cathodic protection of the pipeline 
outside the casing?
     Should newly constructed offshore pipelines be 
electrically isolated from bare steel platforms unless both are 
protected as a single unit?
     Is electrical isolation needed where contact with 
aboveground structures would adversely affect cathodic protection?

External Corrosion: Test Leads (Sec. 192.471)

     Are accessible test leads needed on offshore risers that 
are electrically isolated and not accessible for testing?

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     For aluminum pipelines, should all test leads be insulated 
aluminum conductors and installed to avoid harm to the pipe?

External Corrosion: Interference Currents (Sec. 192.473)

     Where light rail systems exist, should operators 
specifically be required to identify and test for stray currents and 
keep records of the test results?

Internal Corrosion (Sec. 192.475)

     Are special requirements needed to deal with the problem 
of internal corrosion in storage field piping, as evidenced by piping 
leaks in West Virginia and several Midwestern states?

Atmospheric Corrosion: General (Sec. 192.479)

     Should new and existing pipelines be subject to the same 
protection requirements?
     Is protection needed where corrosion is a light surface 
oxide or where corrosion will not likely affect the safe operation of 
the pipeline before the next scheduled inspection?
     Is special protection needed in the splash zone of 
offshore pipelines and at soil to air interfaces of onshore pipelines?

Atmospheric Corrosion: Monitoring (Sec. 192.481)

     Should the inspection interval for onshore pipelines be 
extended beyond 3 years in view of the generally low incidence of 
serious problems on protected pipelines?
     For onshore pipelines, are more frequent inspections 
needed at soil to air interfaces, under thermal insulation, at 
disbonded coatings, and at pipe supports?
     For offshore pipelines, are more frequent inspections 
needed under poorly bonded coatings and at splash zones, support 
clamps, and deck penetrations?

Records (Sec. 192.491)

     Should operators keep records of findings of non-corrosive 
conditions if Sec. 192.455 is changed to remove the benefit of such 
findings?
     Is the period for keeping corrosion control monitoring 
records, ``as long as the pipeline remains in service,'' necessary for 
safety or accident investigation? If not, what is an appropriate 
period?

Concerns of Others

National Association of Pipeline Safety Representatives (NAPSR).

    Long before the Oakbrook meeting, NAPSR reported on an extensive 
review of Part 192 that included recommendations to change several of 
the standards for corrosion control. We published the report and 
requested public comment on its various recommended rule changes 
(Docket PS-124, Notice 2; 58 FR 59431, Nov. 9, 1993). We adopted one of 
NAPSR's corrosion standard recommendations (regarding Sec. 192.475) in 
the final rule we published in Docket PS-124 (61 FR 28770; June 6, 
1996). The others are discussed below:
     With regard to Secs. 192.457 and 192.465, NAPSR 
recommended changes to clarify the meaning of ``electrical survey'' and 
where alternatives to electrical surveys may be used. But most 
commenters either opposed or wanted to modify the recommendation, 
feeling it would unreasonably limit an operator's ability to determine 
areas of active corrosion by alternative methods.
     With regard to Sec. 192.459, NAPSR recommended we require 
operators to record the condition of protective coatings whenever they 
inspect exposed portions of buried pipelines, arguing the records would 
provide a useful history of the condition of the pipelines as well as 
evidence that exposed pipe had been inspected as required. Opponents 
argued the recommendation was unnecessary because Sec. 192.491 already 
requires operators to keep records of required inspections.
     With regard to Sec. 192.467(c), NAPSR recommended changes 
to require that operators annually test pipeline casings for electrical 
isolation, and to clarify what ``other measures'' must be taken to 
minimize pipeline corrosion if isolation is not achieved. There was 
strong opposition to this recommendation because studies have not 
correlated shorted casings and corrosion on the carrier pipe, or 
because a longer interval of inspection would be more appropriate.
     With regard to Sec. 192.479(b), NAPSR recommended that 
regardless of the date of installation, all aboveground pipelines or 
portions of a pipeline that are exposed to the atmosphere be cleaned 
and either coated or jacketed with a material suitable for the 
prevention of atmospheric corrosion, unless the pipeline is in a non-
corrosive atmosphere. Commenters who objected to this recommendation 
said the difficulty of proving a non-corrosive atmosphere could cause 
operators to coat older pipelines that have no harmful atmospheric 
corrosion.
     With regard to the provision in Sec. 192.487(a) that 
permits the repair rather than replacement of pipe with a small area of 
general corrosion, NAPSR recommended that the provision refer to 
generally accepted guidelines for determining what corroded areas may 
be repaired. Although most commenters opposed the idea of requiring 
operators to apply the guidelines in every case, there was no objection 
to making the guidelines permissive as Sec. 192.485 does.
     Finally, with regard to Sec. 192.489(b), NAPSR recommended 
that we clarify that internal sealing is not an appropriate method of 
strengthening graphitized pipe. There was no opposition to this 
recommendation.

Gas Piping Technology Committee (GPTC)

    In an April, 1995 rulemaking petition, GPTC requested the 
following:
     Remove from Sec. 192.467 the requirement that pipe be 
electrically isolated from metallic casings. GPTC argued there are no 
safety benefits from clearing shorted casings.
     Amend Secs. 192.465 and 192.481 to allow operators to take 
up to 39 months to carry out inspections of unprotected pipelines that 
must be done at 3-year intervals. GPTC said the extra time would add 
flexibility to the standards with no reduction in safety.

National Transportation Safety Board (NTSB)

    As a result of a recent accident investigation, NTSB recommended 
two changes to the Part 195 corrosion standards:
     Revise Part 195 to require pipeline operators to determine 
the condition of pipeline coating whenever pipe is exposed and, if 
degradation is found, to evaluate the coating condition of the 
pipeline. (P-98-35)
     Revise Part 195 to include performance measures for the 
adequate cathodic protection of liquid pipelines. (P-98-36)
    We will be considering all these recommendations in the present 
proceeding as we decide what changes, if any, to propose for the 
corrosion control standards.

Alternatives

    Changing the current standards to satisfy the concerns discussed 
above may not be the only way to improve protection against corrosion. 
Some industry representatives have expressed a desire to employ new 
technologies or risk management concepts as more advanced solutions to 
corrosion

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problems. So we are considering the following as alternatives to some 
or all of the standards:
     Corrosion Management Plans. Our experience shows that many 
operators get superior results by applying their own pipeline-specific 
plans for controlling corrosion. These plans often contain methods and 
corrosion management techniques not required by the standards. To 
encourage the development and use of these plans, we are considering 
whether to allow operators to comply with corrosion management plans as 
an alternative to the corrosion control standards. While we think such 
plans would have to meet the objectives of the standards if not the 
specifics, this regulatory approach would give operators more 
flexibility to tailor their corrosion control practices to meet varying 
conditions. Such plans would be subject to review by agency inspection 
personnel and possible change if deemed inadequate (49 CFR 190.237).
     NACE Standard RP0169-96. Another alternative to compliance 
with the standards that some persons may favor is incorporation by 
reference of all or part of NACE Standard RP0169-96. Although its 
advisory style affects the suitability of this NACE standard for 
regulatory use, it is, nonetheless, widely accepted as the most 
authoritative source of up-to-date pipeline corrosion control 
practices. In an analogous situation, we have recently proposed to 
incorporate by reference other industry documents that are drafted in 
an advisory style. In the proceeding on the safety of breakout of 
tanks, we proposed to reference four documents published by the 
American Petroleum Institute that are recommended practices: API 
Recommended Practice 651 ``Cathodic Protection of Aboveground Petroleum 
Storage Tanks,'' API Recommended Practice 652 ``Lining of Aboveground 
Petroleum Storage Tanks Bottoms,'' API Recommended Practice 2003 
``Protection Against Ignitions Arising out of Static, Lightning, and 
Stray Currents,'' and API Recommended Practice 2350 ``Overfill 
Protection for Storage Tanks In Petroleum Facilities'' (Docket RSPA-97-
2095; 63 FR 27903; May 21, 1998). Recognizing that API intended these 
documents to be advisory and not imperative, we proposed that operators 
follow the recommended practices unless they note in their procedural 
manuals why compliance with all or certain provisions is not necessary 
for the safety of a particular breakout tank or tanks. Any decisions 
not to follow certain provisions would be subject to review by agency 
inspection personnel and possible change if deemed inadequate (49 CFR 
190.237). We could take a similar approach with respect to advisory 
provisions of NACE Standard RP0169-96 that operators may decide are 
unnecessary for the safety of particular pipelines.

Compliance Manual

    We are also considering developing a Compliance Manual that would 
contain guidelines for federal and state inspectors in evaluating 
operator compliance with the corrosion standards. The manual would be 
available to the public, so operators could learn what inspectors look 
for in checking for compliance. We expect the manual to include 
explanations and illustrations that apply the standards to hypothetical 
pipelines, accounting for variations in operating conditions. For 
example, we plan to include details on how to perform field pipe-to-
soil measurements, including connection of leads to the pipeline, 
voltmeter, and half cell. We also want to show how to apply the 
different cathodic protection criteria, and how to do a close-interval 
survey. We think such a manual would advance an effective and uniform 
understanding, interpretation, and application of the standards. It 
could also provide a basis for training government and operator 
personnel.

Public Participation

    As stated in more detail above, interested persons are invited to 
attend the San Antonio public meeting and present oral or written 
statements about any of the principles, concerns, or alternatives 
discussed in this notice. Written statements not presented at the 
meeting may be submitted to the docket. If necessary, we may limit the 
time for oral presentations so that everyone who requests an 
opportunity to speak may do so. Those who do not request time for 
presentations may have an opportunity to speak as time allows.
    We are particularly interested in receiving comments on the 
following:
    1. Whether any existing standards deter or disallow the use of new 
technologies, and, if so, how.
    2. The costs and benefits of any suggested changes to standards and 
alternatives to standards.
    3. The amount of time operators may need to prepare for compliance 
with any suggested standards or alternatives.
    4. With regard to the Corrosion Management Plan and NACE Standard 
alternatives--
    a. The bases for evaluating the adequacy of corrosion management 
plans.
    b. The best way to facilitate agency review of operator decisions 
under the alternatives (e.g., prior notification, reporting, 
recordkeeping).
    c. Whether NACE Standard RP0169-96 is adequate for pipeline 
corrosion control and, if so, should we incorporate it by reference in 
our corrosion control standards?
    5. For hazardous liquid pipelines--
    a. Whether additional standards are needed to further reduce the 
possibility of damage to environmentally sensitive areas.
    b. If Subpart I standards were applied to hazardous liquid 
pipelines, the changes, if any, that would be needed to account for 
differences between gas and liquid pipelines.
    6. For gas distribution systems--
    a. Root causes of corrosion leaks on coated, uncoated, protected, 
and unprotected metallic lines.
    b. Descriptions of operating/maintenance practices to minimize 
corrosion leaks on cathodically unprotected lines.
    c. Descriptions of risk-based corrosion management programs.
    d. The best approach to monitoring corrosion control in urban wall-
to-wall paved areas.
    7. The amount of buried piping at compressor, regulator, and 
measuring stations that is not cathodically protected.
    8. Explicit examples of adequate compliance with particular 
standards that have had varied interpretations.
    9. To provide an acceptable level of safety on existing pipelines, 
must cathodic protection preserve the pipeline indefinitely or merely 
slow the rate of corrosion until the pipeline has to be rehabilitated 
or replaced?

    Authority: 49 U.S.C. Chapter 601 and 49 CFR 1.53.
Richard B. Felder,
Associate Administrator for Pipeline Safety.
[FR Doc. 99-8628 Filed 4-6-99; 8:45 am]
BILLING CODE 4910-60-P