[Federal Register Volume 67, Number 11 (Wednesday, January 16, 2002)]
[Rules and Regulations]
[Pages 2136-2144]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 02-858]



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DEPARTMENT OF TRANSPORTATION

Research and Special Programs Administration

49 CFR Part 195

[Docket No. RSPA-00-7408; Amdt. No. 195-76]
RIN 2137-AD49


Pipeline Safety: Pipeline Integrity Management in High 
Consequence Areas (Hazardous Liquid Operators With Less Than 500 Miles 
of Pipelines)

AGENCY: Research and Special Programs Administration (RSPA), U.S. 
Department of Transportation (DOT).

ACTION: Final rule.

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SUMMARY: Our regulations for the transportation of hazardous liquids by 
pipeline require operators with 500 or more miles of regulated 
pipelines to establish a program for managing the integrity of 
pipelines that affect high consequence areas. The regulations require 
continual assessment and evaluation of pipeline integrity through 
inspection or testing, data integration and analysis, and follow-up 
remedial, preventive, and mitigative actions. This Final Rule extends 
those regulations to operators with less than 500 miles of regulated 
pipelines. We are taking this action because safety recommendations, 
statutory mandates, and accident analyses indicate that coordinated 
risk control measures are needed for public safety and environmental 
protection in addition to compliance with traditional safety standards. 
Broadening the coverage of the existing regulations will further 
enhance the protection of high consequence areas against the risk of 
pipeline failures.

DATES: This Final Rule takes effect February 15, 2002.

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

    Last year we amended the regulations in 49 CFR part 195 to require 
each operator who owns or operates 500 or more miles of pipelines 
subject to part 195 to establish a program for managing the integrity 
of pipelines that could affect a high consequence area if a leak or 
rupture occurs (Docket No. RSPA-99-6355; 65 FR 75377; Dec. 1, 2000). 
High consequence areas include highly populated areas, areas unusually 
sensitive to environmental damage, and commercially navigable waterways 
(Sec. 195.450). Program standards require continual assessment, 
evaluation, correction, and validation of pipeline integrity 
(Sec. 195.452 and appendix C to part 195). The new standards took 
effect May 29, 2001 (66 FR 9532; Feb. 8, 2001). In addition, in a 
further rulemaking action (Docket No. RSPA-99-6355), we are revising 
the repair provisions of Sec. 195.452(h) and clarifying that 
Sec. 195.452 applies to carbon dioxide pipelines as well as hazardous 
liquid pipelines.
    We did not apply the new program standards to pipelines of 
operators with less than 500 miles of regulated pipelines primarily 
because we needed more information about the potential impact of the 
standards on these operators. We subsequently learned that these 
operators include, to a large extent, companies with ample resources 
and capabilities to carry out the standards.
    A wide range of persons who submitted comments to Docket No. RSPA-
99-6355 supported the need to apply the new program standards to all 
operators of regulated pipelines that could affect high consequence 
areas. Based on these comments and the impact information we had 
collected, we published a Notice of Proposed Rulemaking (NPRM) to 
extend the program standards to pipelines of operators with less than 
500 miles of regulated pipelines (66 FR 15821; March 21, 2001).
    The NPRM did not propose any substantive change to the existing 
program standards. It merely proposed to establish later deadlines for 
developing programs under Sec. 195.452(b)(1), identifying pipelines 
under Sec. 195.452(b)(1)(i), completing baseline assessments under 
Sec. 195.452(d)(1), accepting prior assessments under 
Sec. 195.452(b)(2), and applying certain time limits on reviewing 
assessment results under Sec. 195.452(h)(3). We invited interested 
persons to submit written comments on the proposed rules until May 21, 
2001.
    Although the NPRM proposed no substantive change to the program 
standards, in the earlier proceeding (Docket No. RSPA-99-6355), we 
invited comments until March 31, 2001, on the substance of the standard 
for remedial action (Sec. 195.452(h)). As indicated in the NPRM, if 
Sec. 195.452(h) is changed in that proceeding, the changes will apply 
to all operators of pipelines to which the program standards apply, 
including operators covered by the present Final Rule.

Disposition of Comments

    This section of the preamble summarizes written comments we 
received in response to the NPRM. It also describes how we treated 
those comments in developing the final rules. However, comments related 
to costs and benefits and the impact of the proposed rules on small 
entities are addressed in the ``Regulatory Analyses and Notices'' 
section of this preamble. If a proposed rule is not mentioned, no 
significant comments were received on the proposal, and we are adopting 
the proposed rule as final.
    Eight persons submitted comments: a professional organization, the 
American Society of Safety Engineers (ASSE); a state pipeline safety 
agency, the Washington Utilities and Transportation Commission (WUTC); 
a Washington State advisory committee, the Citizens Advisory Committee 
on Pipeline Safety (CAC); the Small Business Administration (SBA); the 
Department of Energy (DOE); an engineering firm, Wink, Incorporated 
(Wink); and two pipeline operators, the Laclede Pipeline Company 
(Laclede) and the Tosco Corporation (Tosco). ASSE did not comment on 
specific proposals in the NPRM, but strongly supported our goal of 
assuring the integrity of pipeline systems. ASSE also said improving 
pipeline safety would improve the United States' competitive position 
in the world economy. WUTC, CAC, Tosco, and DOE expressed general 
support for the NPRM but, along with Wink, suggested changes. DOE also 
commented on the costs of the proposed rules in their impact on small 
entities. Laclede opposed the integrity assessment proposal and took 
issue with our estimate of compliance costs. SBA's comments were 
limited to the impact of the proposed rules on small entities.
    Under proposed Secs. 195.452(b)(1) and (b)(1)(i), operators with 
less than 500 miles of pipelines would have 9 months after the 
effective date of the final rules to identify all pipeline segments 
that could affect high consequence areas. They would have 1 year after 
the effective date to develop a written integrity management program 
that addresses the risks of those segments. Tosco said the 
identification of pipeline segments should occur after, not before, 
integrity management programs are completed, and suggested we allow 
operators 1 year to complete the identifications. In considering this 
comment, we noted that operators with 500 or more miles of pipelines 
have not indicated they expect any significant difficulties in meeting 
the 9-month identification rule. Tosco's comment

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does not give us reason to believe the 9-month rule might be too 
burdensome for operators with less than 500 miles of pipelines. While 
Tosco is correct that operators will need to have relevant program 
elements in place to guide them in identifying pipeline segments, we 
believe 9 months is enough time to complete those elements and to carry 
out the identifications. The additional 3 months the existing rule 
provides for program development gives operators enough time to 
complete program elements other than those concerning identification. 
We do not think this additional time is also needed to identify 
pipeline segments.
    CAC suggested we require operators to seek input from potentially 
affected communities in identifying high consequence areas. CAC 
believed the input would help operators identify areas of population at 
risk and areas of economic importance. Although we recognize community 
input is valuable in many situations involving pipelines, particularly 
in site selection and emergency response, we do not feel it is 
necessary to mandate that operators seek the input CAC envisioned for 
two reasons. First, the definition of ``high consequence area'' in 
Sec. 195.450 covers CAC's concern about the population-at-risk. That 
definition refers to areas of high or concentrated population that the 
U.S. Census Bureau has defined and delineated. Operators should be able 
to identify these areas quite easily using Census Bureau data. If 
additional information is needed from community records to complete the 
identifications, the proposed rule would implicitly obligate operators 
to seek this information, making an explicit requirement unnecessary. 
Secondly, the NPRM did not propose to require integrity management of 
pipelines that could affect areas of economic significance other than 
commercially navigable waterways. These waterways, which operators also 
can readily identify without community input, arguably are the nation's 
foremost economic resources potentially at risk from pipeline spills. 
Other significant economic resources that may be affected by pipelines 
are less certain, and we feel the present regulations in Part 195 
provide those resources adequate protection against the risk of 
pipeline spills. Similarly, in directing DOT to require additional 
inspection of certain pipelines, Congress did not include pipelines 
that affect economic resources other than commercially navigable 
waterways (49 U.S.C. 60102(f)(2) and 60109). If in the future there is 
a need to apply the integrity management rules to pipelines affecting 
other significant economic resources, we will consider whether 
operators should seek community input in identifying those resources.
    Although we did not adopt CAC's recommendations, it is important to 
note that in a separate proceeding we are considering the need for 
regulations on better communication of pipeline information by 
operators to local officials and the public. We have formed a 
communications work team, consisting of representatives from 
environmental and public safety organizations, pipeline companies, and 
government to aid our own hazardous liquid pipeline safety advisory 
committee in examining communications issues. Notices of meetings of 
the work group are published in the Federal Register, and minutes of 
the meetings are posted on this Web site: http://ops.dot.gov.
    WUTC suggested we require baseline integrity assessments of new 
pipelines as soon after they are constructed as possible, and for 
existing pipelines as soon as practicable after the final rules take 
effect. WUTC stated that early baseline assessment would provide the 
best basis for comparing subsequent assessment results. The NPRM 
proposed, in Sec. 195.452(d), that operators with less than 500 miles 
of pipeline complete baseline assessments within 7 years after the 
effective date of the final rule, with half the line pipe, selected by 
risk, assessed within 42 months after the effective date. 
Alternatively, operators could use as a baseline assessment any 
qualified integrity assessment completed within the 5 years prior to 
the effective date. For newly constructed pipelines, hydrostatic 
testing completed as required by other regulations in Part 195 will 
fulfill the baseline assessment requirement. Since this testing is 
normally part of the construction process, it should meet WUTC's 
objective of early assessment. For existing pipelines, we proposed 7 
years to complete baseline assessments because of the volume of 
assessments, the limited availability of in-line inspection tools, and 
the time needed to schedule pressure testing to minimize service 
disruptions. Although we agree with WUTC that earlier baseline 
assessment would be beneficial, we do not think requiring earlier 
baseline assessments would be reasonable under present circumstances.
    To assure that only qualified persons develop integrity management 
programs and make program decisions, Wink suggested we require 
operators to use registered professional engineers with demonstrated 
technical pipeline expertise and experience. Wink further suggested we 
require operators to submit their integrity management programs for 
review by RSPA certified entities. We did not adopt either suggestion 
because to do so would go beyond the scope of the NPRM. While 
Sec. 195.452(f)(8) requires operators to use persons qualified to 
evaluate assessment results and analyze information, the NPRM did not 
address specific qualifications or program review by certified 
entities. Based on our experience in other areas of pipeline 
regulation, we believe operators will use qualified engineers with 
pipeline experience to assist in developing integrity management 
programs and recommend critical decisions under the programs. Moreover, 
persons carrying out regulated assessment and mitigation activities on 
pipelines are subject to the existing qualification requirements in 
Subpart G of Part 195. To assure that operators carry out their 
programs in accordance with the rules, we will use our own engineers 
and technical specialists to evaluate operators' programs and require 
changes that may be needed for safety. This type of evaluative process 
has been satisfactory for other programs and plans required by Part 
195. We prefer to continue this approach to assure the quality of 
integrity management programs rather than establish additional 
personnel qualifications or a new federal certification program.
    Wink asked to what extent operators would have to consider 
potential terrorist activities in their ongoing assessments of pipeline 
integrity. Under one of the integrity management program requirements 
(Sec. 195.452(e)(1)), operators must schedule integrity assessments 
based on ``all risk factors that reflect the risk conditions on the 
pipeline.'' Therefore, if an operator knows or it is reasonable to 
anticipate that there is a threat to the integrity of the pipeline from 
terrorist activity, the operator must consider that risk in developing 
its integrity program. Since the events of September 11, 2001, we are 
working with DOT, the Department of Energy, the Federal Energy 
Regulatory Commission, and State agencies, to consider the need for 
minimum security standards for critical facilities.
    Wink postulated that construction permit timing could interfere 
with an operator's ability to meet remediation deadlines. Section 
195.452(h) deals with this potential problem. Under this rule, if 
justifiable circumstances preclude an operator from meeting specified 
repair deadlines, the operator may reasonably extend the repair 
schedule if it

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temporarily reduces operating pressure to a safe level or notifies us 
of the delay in making a permanent repair.
    Finally, Wink suggested we establish a program review process in 
which operators would meet with our technical specialists to examine 
whether the program meets applicable requirements. In response to 
Wink's first comment, we mentioned we will use our own engineers and 
technical specialists to evaluate operators' programs and require 
changes that may be needed for safety. We expect this review process 
will involve meeting with operators' representatives.
    Laclede, who operates a 28-mile propane pipeline serving a gas 
distribution system, believed it would be unreasonable to apply the 
proposed integrity assessment requirement (Sec. 195.452(c)) to its 
pipeline. Laclede said the design of 70 percent of its pipeline cannot 
accommodate internal inspection tools, and difficulties in de-watering 
the line after hydrostatic testing would cause control valve and 
instrument freeze-ups during critical cold weather periods. Laclede 
suggested we exempt from internal inspection or hydrostatic testing 
requirements all pipelines directly serving gas distribution systems if 
the pipeline is cathodically protected and inspected according to our 
standards or is equipped with emergency flow restricting or shutdown 
devices. We did not adopt this comment because providing adequate 
cathodic protection and meeting current inspection requirements cannot 
assure a pipeline is free from all potentially harmful defects that 
internal inspection or hydrostatic testing can disclose, such as 
mechanical damage or fatigue cracks. Also, while emergency flow 
restricting or shutdown devices are useful in mitigating the 
consequences of a pipeline rupture, these devices do nothing to prevent 
ruptures, which is the purpose of periodic internal inspection or 
hydrostatic testing. Laclede's comment did not fully explain the 
particular difficulties in de-watering, or drying, its pipeline after 
hydrostatic testing. Drying pipelines is not an uncommon problem in the 
industry and not one we believe makes the proposed testing rule 
unreasonable. Many companies are available to provide expert drying 
services, using techniques that depend on operating conditions. 
However, if an operator's circumstances are so unusual that hydrostatic 
testing would result in unavoidable damage to pipeline facilities and 
internal inspection is not a viable alternative, the operator may apply 
for a waiver of the testing requirement as permitted by 49 U.S.C. 
60118.
    DOE was concerned that construction of new pipelines within the 
next few years to meet the growing demand for fossil fuels could tax 
available technical expertise and equipment needed to meet various 
assessment deadlines in the existing and proposed rules. DOE said 
available resources could be stretched to a point where meeting the 
deadlines would not be possible, or at least not possible without 
significantly increased costs. Therefore, DOE suggested we expand the 
present provisions for extending deadlines (e.g., Sec. 195.452(j)(4)) 
to include situations in which meeting a deadline would result in 
supply disruptions. We agree that by shifting resources away from new 
construction or shutting down vital pipelines for hydrostatic testing 
or repair, supply disruptions could occur. However, at this stage we 
believe the impact of such an eventuality is too speculative to warrant 
changing the rules to add supply disruption as an acceptable reason for 
extending deadlines. Also, over the next few years new technologies 
might become available that would enable acceptable integrity 
assessments with no effect on supply. If in the future a supply problem 
appears more likely, the operator involved may petition us for 
necessary relief or latitude under the rules.
    DOE also commented on our plan to identify high consequence areas 
on it's National Pipeline Mapping System (NPMS) and to make the 
information available to the public via the Internet. DOE recommended 
that before implementing this plan, we fully evaluate issues of 
critical infrastructure protection. Indeed, we designed the NPMS with 
infrastructure protection issues in mind. For example, to avoid 
creating a tool for intentional misuse of information with tragic 
results, critical pipeline components and operating data would not be 
shown on the NPMS. However, the events of September 11, 2001, have 
caused even greater concern about the security of critical 
infrastructure systems. As a result, the NPMS no longer provides open 
access to pipeline-related data. These data are only available to 
pipeline operators and local, state, and federal government officials. 
More information on the availability of data and how operators and 
officials can access it is on the NPMS home page: http://www.npms.rspa.dot.gov.

Editing Changes

    In a further rulemaking action (Docket No. RSPA-99-6355), we are 
revising Sec. 195.452(h)(3) to eliminate the possibility that periods 
specified for reviewing integrity assessment results could cause 
confusion. This change to Sec. 195.452(h)(3) eliminates the need to 
revise that section to cover operators with less than 500 miles of 
regulated pipelines. Therefore, this Final Rule does not include the 
NPRM's proposed change to Sec. 195.452(h)(3).
    Because this Final Rule extends the coverage of existing 
Sec. 195.452 to all operators subject to part 195, there is no need to 
state in final Sec. 195.452 which operators are subject to 
Sec. 195.452. Therefore, we edited Sec. 195.452(a) to describe which 
pipelines are covered by Sec. 195.452 by moving relevant provisions in 
Sec. 195.452(b)(1) to Sec. 195.452(a). Section 195.452(a) now provides 
that Sec. 195.452 applies to hazardous liquid and carbon dioxide 
pipelines that could affect a high consequence area, including 
pipelines located in a high consequence area unless a risk assessment 
effectively shows the pipeline could not affect the area.
    The NPRM proposed certain compliance dates for covered pipelines 
that depend on whether the operator of the pipeline owns or operates 
500 or more miles of regulated pipelines. Although no one commented on 
this approach to determining compliance dates, we now recognize the 
approach could have unintended results. Under the proposed approach, if 
the miles of regulated pipelines an operator owns or operates changes 
during the compliance period (through transfer, construction, or 
abandonment of pipelines), the compliance dates applicable to that 
operator's covered pipelines could also change. For example, if an 
operator currently subject to Sec. 195.452 were to reduce its miles of 
regulated pipelines below 500 during a compliance period for covered 
pipelines, the operator's covered pipelines would then fall under the 
later compliance date applicable to operators with less than 500 miles 
of regulated pipelines. Likewise, covered pipelines of operators who 
increase their miles of regulated pipelines to 500 or more during a 
compliance period would become subject to earlier compliance dates. The 
purpose of the proposed approach to determining compliance dates was 
merely to establish compliance dates for pipelines covered by the NPRM 
that are later than the existing compliance dates in Sec. 195.452. We 
did not intend that the existing or proposed compliance dates change 
with changes in an operator's regulated pipeline mileage. Rather, we 
intended to apply the existing and proposed compliance dates to covered 
pipelines existing on May 29, 2001 (the

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effective date of existing Sec. 195.452), depending on whether, on that 
date, the operator owned or operated 500 or more miles of regulated 
pipelines.
    To clarify the application of compliance dates and to eliminate 
repetitive wording, final Sec. 195.452(a) divides covered pipelines 
into three categories. The first category includes pipelines existing 
on May 29, 2001, that were owned or operated by an operator who owned 
or operated a total of 500 or more miles of pipeline subject to part 
195. This category of pipelines is subject to the existing compliance 
dates in Sec. 195.452, and will remain subject to those dates 
regardless of how many miles of regulated pipelines the present or 
future operator of the pipelines owns or operates after May 29, 2001. 
The second category includes pipelines existing on May 29, 2001, that 
were owned or operated on that date by an operator who owned or 
operated less than 500 miles of pipeline subject to part 195. This 
category of pipelines is subject to the later compliance dates proposed 
in the NPRM for operators with less than 500 miles of regulated 
pipelines. Like the first category, the compliance dates applicable to 
the second category of pipelines do not depend on how many miles of 
regulated pipelines the present or future operator of the pipelines 
owns or operates after May 29, 2001. The third category of covered 
pipelines includes pipelines constructed or converted after May 29, 
2001. Because these pipelines are not subject to the existing or 
proposed compliance dates, we have added appropriate dates to 
Secs. 195.452(b)(1), (b)(2)(i), (d)(1), and (h)(3). The dates in 
paragraphs (b)(1) and (h)(3) provide compliance periods equivalent to 
periods allowed for Category 1 or 2 pipelines. In paragraph (b)(2)(i), 
we set the date as the date the pipeline begins operation, because 
operators should not need any longer time to identify a new or 
converted pipeline as a covered pipeline. The date the pipeline begins 
operation is also the compliance date in paragraph (d)(1), because the 
hydrostatic test part 195 requires on new and converted pipelines 
before operation will serve as the baseline assessment.

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 August 13, 2001 (66 FR 35505; July 5, 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 the rules proposed in the NPRM and the 
associated evaluation of costs and benefits. A transcript of the August 
13 meeting is available in Docket No. RSPA-98-4470.

Regulatory Analyses and Notices

Executive Order 12866 and DOT Regulatory Policies and Procedures

    We consider this Final Rule to be a non-significant regulatory 
action under section 3(f) of Executive Order 12866 (58 FR 51735; 
October 4,1993). Therefore, the Office of Management and Budget (OMB) 
has not received a copy of this rulemaking to review. We do not 
consider this rulemaking to be significant under DOT regulatory 
policies and procedures (44 FR 11034; Feb. 26, 1979).
    This section of the preamble summarizes the findings of the 
Regulatory Evaluation we prepared for this Final Rule. A copy of the 
Regulatory Evaluation is in the docket.
    Pipeline spills can adversely affect human health and the 
environment. However, the magnitude of this impact differs from area to 
area. There are some areas in which the impact of a spill will be more 
significant than it would be in others due to concentrations of people 
who could be affected or to the presence of environmental resources 
that are unusually sensitive to damage. Because of the potential for 
dire consequences of pipeline failures in certain areas, these areas 
merit a higher level of protection. We are promulgating this Final Rule 
to afford the necessary additional protection to these high consequence 
areas.
    Last year we established 49 CFR 195.450 and 195.452, which are new 
requirements for additional protection of populated areas, commercially 
navigable waterways, and areas unusually sensitive to environmental 
damage from pipeline spills (65 FR 75377; Dec.1, 2000). The new 
requirements apply to pipeline operators who own or operate 500 or more 
miles of pipeline. This Final Rule extends the same requirements, with 
modified compliance deadlines, to the remaining operators of regulated 
pipelines--those that own or operate less than 500 miles of regulated 
pipeline.
    RSPA and the National Transportation Safety Board (NTSB) have 
conducted many investigations that have highlighted the importance of 
protecting the public and environmentally sensitive areas from pipeline 
failures. NTSB has made several recommendations to ensure the integrity 
of pipelines near populated and environmentally sensitive areas. These 
recommendations include requiring periodic testing and inspection to 
identify corrosion and other damage, establishing criteria to determine 
appropriate intervals for inspections and tests, determining hazards to 
public safety from electric resistance welded pipe, and requiring 
installation of automatic or remotely-operated mainline valves on high-
pressure lines to provide for rapid shutdown of failed pipelines.
    Congress also directed DOT to undertake additional pipeline safety 
measures in areas of potentially high consequence. These statutory 
requirements call for new regulations on identifying pipelines in high 
density population areas, unusually sensitive environmental areas, and 
commercially navigable waters. They also call for new regulations on 
periodic inspections of pipelines in these areas with internal 
inspection devices, and on emergency flow restricting devices.
    This Final Rule requires operators to systematically manage 
pipeline integrity to reduce the potential for failures that could 
affect high consequence areas (populated areas, unusually sensitive 
areas, and commercially navigable waterways). Operators must develop 
and follow an integrity management program to identify pipeline 
segments that could affect high consequence areas, and continually 
assess, through internal inspection, pressure testing, or equivalent 
alternative technology, the integrity of those segments. The program 
must also evaluate the segments through comprehensive information 
analysis, remediate integrity problems, and provide additional 
protection through preventive and mitigative measures, including the 
use of emergency flow restricting devices.
    Existing Secs. 195.450 and 195.452 cover an estimated 86.7 percent 
of the 157,000 miles of regulated hazardous liquid pipeline in the U.S. 
This Final Rule covers the remaining 13.3 percent. Of this percentage, 
we estimate this Final Rule will impact approximately 5,440 miles of 
pipeline. We estimate the cost to operators to develop the necessary 
programs at approximately $9.94 million, with an additional annual cost 
for program upkeep and reporting of $1.32 million. An operator's 
program begins with a baseline assessment plan and a framework that 
addresses each

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required program element. The framework indicates how decisions will be 
made to implement each element. As decisions are made and operators 
evaluate the effectiveness of the program in protecting high 
consequence areas, the program will be updated and improved, as needed.
    This Final Rule requires a baseline assessment of covered pipeline 
segments through internal inspection, pressure test, or use of other 
technology capable of equivalent performance. The baseline assessment 
must be completed within 7 years after this Final Rule goes into 
effect. After this baseline assessment, the rule further requires that 
operators periodically reassess and evaluate pipeline segments to 
ensure their integrity within a 5-year interval. We estimate the cost 
of periodic reassessment will generally not occur until the sixth year, 
unless the baseline assessment indicates significant defects that would 
require earlier reassessment. Integrating information related to the 
pipeline's integrity is a key element of the integrity management 
program. Costs will be incurred in realigning existing data systems to 
permit integration and in analysis of the integrated data by 
knowledgeable pipeline safety professionals. The total costs for the 
information integration requirements in this Final Rule are $6.6 
million in the first year and $3.3 million annually thereafter.
    This Final Rule requires operators to identify and take preventive 
or mitigative actions that would enhance public safety or environmental 
protection, based on a risk analysis of the pipeline segment. One 
preventive or mitigative action involves installing an emergency flow 
restricting device on the pipeline segment, if determined necessary. We 
could not estimate the total cost of installing emergency flow 
restricting devices because we do not know how many operators will 
install them. Another action involves evaluating leak detection 
capability and modifying that capability, if necessary. We do not know 
how many operators currently have leak detection systems or how many 
systems will be installed or upgraded as a result of this Final Rule. 
Therefore, we are unable to estimate the total costs of the leak 
detection requirements.
    As a result of this Final Rule, we expect operators will assess 
more line pipe than they otherwise would assess. Integrity assessment 
consists of a baseline assessment, to be conducted within 7 years after 
the effective date of the final rule, and subsequent reassessment at 
intervals not to exceed every 5 years. We estimate the cost of 
additional baseline assessments at approximately $377,000 a year, and 
the cost of additional reassessments at approximately $531,000 a year. 
Cost impact will be greater in the sixth and seventh years after the 
effective date of the final rule due to an overlap between baseline 
inspection and the initial subsequent inspection. The additional costs 
in these two years are estimated at $5.26 million.
    We cannot easily quantify the benefits of this Final Rule, but we 
can describe them qualitatively. Issuance of this Final Rule ensures 
that all operators will perform at least to a baseline safety level and 
will contribute to an overall higher level of safety and environmental 
performance nationwide.
    The Final Rule will lead to greater uniformity in how risk is 
evaluated and addressed. It will also provide more clarity in 
discussions by government, industry and the public about safety and 
environmental issues, and how the issues can be resolved.
    Section 195.452 is written using a performance-based approach. This 
approach has several advantages. First, it encourages development and 
use of new technologies. Secondly, it supports operators' development 
of more formal, structured risk-based programs. Thirdly, it supports 
continual evaluation of the programs by RSPA and state inspectors. And 
lastly, it provides greater opportunity for operators to customize 
their long-term maintenance programs.
    Section 195.452 has stimulated the pipeline industry to develop its 
own consensus standard using a risk-based approach to integrity 
management. The rule has further fostered development of industry-wide 
technical standards, such as repair criteria to use following an 
internal inspection.
    The Final Rule encourages a balanced program, addressing the range 
of prevention and mitigation needs and avoiding reliance on any single 
tool or overemphasis on any single cause of failure. A balanced program 
will lead to addressing the most significant risks in populated areas, 
unusually sensitive environmental areas, and commercially navigable 
waterways, thus improving industry performance in these areas.
    The Final Rule requires a verification process that gives RSPA and 
state inspectors an opportunity to influence the methods of assessment 
and the interpretation of results. Government monitoring of the 
adequacy and implementation of this process should expedite the 
operators' rates of remedial action and reduce the public's exposure to 
risk.
    A particularly significant benefit of this Final Rule involves the 
information that operators will gather to support decisions. Two 
essential elements of the integrity management program are the 
continual assessment and evaluation of pipeline integrity using 
inspection and testing technology, and the integration and analysis of 
all available information about the pipeline. The processes of 
planning, assessment, and evaluation will provide operators with better 
data to use in determining a pipeline's condition and the location of 
potential problems that must be addressed. Also, government inspectors 
will be able to focus on potential risks and consequences that require 
greater scrutiny and the need for more intensive preventive and 
mitigation measures.
    The public has expressed concern about the danger pipelines may 
pose to their neighborhoods. The integrity management process leads to 
greater accountability to the public for both operators and DOT. This 
accountability is enhanced through our choice of a map-based approach 
to defining the areas most in need of additional protection--a visual 
depiction of pipelines in relation to populated areas, unusually 
sensitive environmental areas, and commercially navigable waterways. 
The system integrity requirements will assure the public that operators 
are continually inspecting and evaluating the threats to pipelines that 
pass through or close to populated areas.
    We have not estimated quantitative benefits for the continual 
integrity management evaluation required by this Final Rule. We do not 
believe, however, that requiring this comprehensive process, including 
the reassessment of pipelines every 5 years, will be an undue burden on 
operators. We believe the added security this assessment will provide 
and the generally expedited rate of strengthening the pipeline system 
in high consequence areas are benefit enough to promulgate these 
requirements.
    Laclede commented that we grossly underestimated implementation 
costs. Laclede notes that our estimate of the cost for all affected 
operators is $9.64 million, whereas Laclede expects itself to incur 
costs in excess of $1 million to modify its pipeline. Laclede's 
estimated costs are to replace piping that can not now be inspected 
with internal inspection devices. The rule does not require such pipe 
replacement, and costs for such replacement therefore were not included 
in the implementation cost estimate. The rule allows use of hydrostatic 
testing as an alternative to internal inspection. Laclede's replacement 
of piping to allow passage of internal inspection devices, if

[[Page 2141]]

undertaken, would be an operational choice based on the company's 
conclusion that internal inspection would be a better method of 
assessment than hydrostatic testing. Operators are free to make such 
operational choices, but they are not required by the rule, and costs 
associated with pipe replacement are not, therefore, a cost of 
implementing the rule. We fully considered the costs of hydrostatic 
testing in the Regulatory Evaluation.
    DOE expressed concern that costs associated with shutdown time 
during assessment or with obtaining permits to conduct repair 
activities may not have been included in the Regulatory Evaluation. DOE 
also thought per-mile cost estimates may not be appropriate for 
operators with only a few miles of pipe. With respect to the impact on 
small entities, DOE thought the requirements could have an unreasonable 
impact in some cases.
    The values we used to estimate costs for internal inspection and 
hydrostatic testing were based on detailed studies of both methods that 
considered all relevant costs. The outcome of those studies are per-
mile estimates for conducting assessments. We recognize that costs may 
be higher for operators that have only a few miles of pipeline, and for 
whom ``fixed'' costs of assessment would be amortized over just a few 
miles. However, we are unable to estimate how many operators may be so 
affected. Many of the operators subject to this Final Rule are parts of 
larger companies, as described further in response to Small Business 
Administration comments, and should not be so affected. We will work 
with operators who may be unusually impacted, each of whom may request 
a waiver from particular requirements.
    While costs for permitting associated with conducting assessments 
were included, permitting costs associated with repairs were not 
estimated. No repair costs were included in the Regulatory Evaluation. 
This rule does impose time limits on the repair of certain types of 
defects. Generally, however, repair of conditions that could adversely 
affect the safe operation of a pipeline is already required by 49 CFR 
195.401 and so is not a new requirement in this rule.

Regulatory Flexibility Act

    Under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.), we 
must consider whether a rulemaking would have a significant impact on a 
substantial number of small entities. This Final Rule covers only those 
operators that own or operate less than 500 miles of regulated 
pipeline. Because of this limitation, only 132 hazardous liquid 
pipeline operators, covering 13.3 percent of regulated hazardous liquid 
pipelines, are covered by the Final Rule.
    The risks of operating pipelines are similar regardless of the size 
of the operating company. Accordingly, the need to protect against 
those risks is also similar, regardless of operator size. We agree with 
WUTC's comment that ``[t]he integrity of the hazardous liquid 
infrastructure that runs beneath our nation's cities, and crosses our 
public and private lands, should not be treated differently depending 
on the amount of pipeline owned or operated by pipeline companies.''
    We established an artificial cutoff criterion of 500 miles 
specifically so that we could review further the potential impact and 
safety needs of smaller operators to see if different treatment was 
needed. We completed our review and concluded that different treatment 
was not needed. By this Final Rule, we are establishing the same 
integrity management requirements for operators with less than 500 
miles of pipelines as we established previously for operators with more 
pipeline mileage. Extending the existing requirements to the remaining 
operators of regulated pipelines is necessary to ensure the integrity 
of pipelines which could, if damaged or ruptured, cause significant 
injury to public safety and the environment.
    We preliminarily concluded that there is no disproportionate impact 
on small businesses, principally because the risks are the same. We 
examined the companies that operate less than 500 miles of pipelines. A 
few of these operators are ``small businesses'' (less than 1500 
employees, the Small Business Administration's criterion for defining a 
small business in the hazardous liquid pipeline industry.) The 
majority, however, is not. The majority includes larger companies or 
divisions or subsidiaries of very large national and multi-national 
companies.
    We estimate that 132 operators are potentially subject to the 
requirements of this Final Rule, because that is the number of 
operators who paid user fees on less than 500 miles of pipeline in the 
last fiscal year. This number is a conservative upper bound. Some of 
these operators are not, in fact, affected by this rulemaking. As noted 
above, many are divisions or subsidiaries of larger companies. In many 
cases, the parent companies have other divisions or subsidiaries that 
operate pipelines and, when all are considered, own or operate more 
than 500 miles of such pipeline. Those companies, including all their 
divisions and subsidiaries which may, themselves, operate less than 500 
miles of pipeline, are covered by existing Sec. 195.452 and not by this 
Final Rule. In addition, this Final Rule only covers pipeline segments 
that could affect a high consequence area. It is possible that some 
operators, particularly those with only a few miles of pipe, may not 
operate any segments that could affect such areas. If so, those 
operators would not be covered by this Final Rule. Nevertheless, we 
continue to estimate costs on the basis of 132 covered companies, in 
order to provide a conservative estimate.
    SBA thought the NPRM's discussion of the Regulatory Flexibility Act 
was inadequate. The discussion did not include background and basis 
information that was in the previous rulemaking applicable to operators 
with 500 or more miles of regulated pipeline. However, in the present 
document we have improved our discussion of Regulatory Flexibility Act 
issues to describe more clearly the basis for concluding that this 
Final Rule does not disproportionately affect small businesses. SBA's 
comments are also discussed in detail in the final Regulatory 
Evaluation, included in the docket.
    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 Final Rule will 
not have a significant impact on a substantial number of small 
entities.

Paperwork Reduction Act

    This Final Rule contains information collection requirements. As 
required by the Paperwork Reduction Act of 1995 (44 U.S.C. 3507(d)), we 
have submitted a copy of the Paperwork Reduction Act Analysis to the 
OMB for review. The name of the information collection is ``Pipeline 
Integrity Management in High Consequence Areas for Operators with less 
than 500 miles of pipeline.'' The purpose of this information 
collection is designed to require operators of pipelines to develop a 
program to provide direct integrity testing and evaluation of pipelines 
in high consequence areas.
    No comment submitted in response to the NPRM addressed the 
information collection requirements.
    One hundred and thirty-two operators of hazardous liquid pipelines 
will be potentially subject to this Final Rule. We estimate that those 
operators will have to develop integrity management programs taking 
approximately 2,800 hours per program. Each of the operators will also 
have to devote 1,000 hours in the first year to integrate data

[[Page 2142]]

into current management information systems.
    Additionally, under this Final Rule, operators will have to update 
their integrity management programs on a continual basis. We estimate 
updates will take approximately 330 hours per program, annually. An 
additional 500 hours per operator is estimated for the requirement to 
annually integrate data into the operator's current management 
information systems.
    Under the Final Rule, operators may use either hydrostatic testing 
or an internal inspection tool as a method to assess their pipelines. 
However, operators may use another technology if they can demonstrate 
it provides an equivalent understanding of the condition of the line 
pipe as the other two assessment methods. Operators have to provide 
RSPA 90-days notice (by mail or facsimile) before using the other 
technology. We believe that few operators will choose this option. If 
they do choose an alternative technology, notice preparation should 
take approximately 1 hour. Because we believe few if any operators will 
elect to use other technologies, the burden was considered minimal and 
therefore not calculated.
    Additionally, the Final Rule allows operators in particular 
situations to vary from the 5-year continual reassessment interval or 
repair schedule if they can provide the necessary justification and 
supporting documentation. Advance notice would have to be provided to 
RSPA if an operator does so. The advance notification can be in the 
form of letter or fax. We believe the burden of a letter or fax is 
minimal and therefore did not add it to the overall burden hours 
discussed above.
    Organizations and individuals desiring to submit comments on the 
information collection should direct them to: The Office of Management 
and Budget, Office of Information and Regulatory Affairs, ATTN: RSPA 
Desk Officer, 727 Jackson Place, NW, Washington, DC 20503. Please 
provide the docket number of this action. Comments must be sent within 
30 days of the publication of this Final Rule.
    OMB is specifically interested in the following issues concerning 
the information collection:
    1. Evaluating whether the collection is necessary for the proper 
performance of the functions of DOT, including whether the information 
would have a practical use;
    2. Evaluating the accuracy of DOT's estimate of the burden of the 
collection of information, including the validity of assumptions used;
    3. Enhancing the quality, usefulness and clarity of the information 
to be collected; and minimizing the burden of collection of information 
on those who are to respond, including through the use of appropriate 
automated electronic, mechanical, or other technological collection 
techniques or other forms of information technology; e.g., permitting 
electronic submission of responses.
    According to the Paperwork Reduction Act of 1995, no persons are 
required to respond to a collection of information unless a valid OMB 
control number is displayed. The OMB control number for this 
information collection is 2137-0605.

Executive Order 13084

    This Final Rule has been analyzed in accordance with the principles 
and criteria contained in Executive Order 13084 (``Consultation and 
Coordination with Indian Tribal Governments''). Because this proposed 
rule does not significantly or uniquely affect the communities of the 
Indian tribal governments and does not impose substantial direct 
compliance costs, the funding and consultation requirements of 
Executive Order 13084 do not apply.

Executive Order 13132

    This Final Rule has been analyzed in accordance with the principles 
and criteria contained in Executive Order 13132 (``Federalism''). This 
Final Rule does not adopt 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 (64 FR 43255, Aug. 10, 1999) do 
not apply. In a public meeting we held on November 18-19, 1999, we 
invited the National Association of Pipeline Safety Representatives 
(NAPSR), which includes State pipeline safety regulators, to 
participate in a general discussion on pipeline integrity. Again in 
January, and February 2000, we held conference calls with NAPSR, to 
receive its input before proposing an integrity management rule.

Impact on Business Processes and Computer Systems

    We do not want to impose new requirements that would mandate 
business process changes when the resources necessary to implement 
those requirements would otherwise be applied to ``Y2K'' or related 
computer problems. This Final Rule does not mandate business process 
changes or require modifications to computer systems. Because the final 
rules will not affect the ability of organizations to respond to those 
problems, we are not delaying the effectiveness of the requirements.

Unfunded Mandates Reform Act of 1995

    This Final Rule does not impose unfunded mandates under the 
Unfunded Mandates Reform Act of 1995. It does not result in costs of 
$100 million or more to either state, local, or tribal governments, in 
the aggregate, or to the private sector, and is the least burdensome 
alternative that achieves the objective of the NPRM.

National Environmental Policy Act

    We have analyzed the Final Rule in accordance with section 
102(2)(c) of the National Environmental Policy Act (42 U.S.C. 4332), 
the Council on Environmental Quality regulations (40 CFR parts 1500-
1508), and DOT Order 5610.1D. We have determined that this action will 
not significantly affect the quality of the human environment.
    The Environmental Assessment (available in the Docket) determined 
that the combined impacts of the initial baseline assessment (pressure 
testing or internal inspection), the subsequent periodic assessments, 
and additional preventive and mitigative measures that may be 
implemented to protect high consequence areas will result in positive 
environmental impacts. The number of incidents and the environmental 
damage from failures in and near high consequence areas are likely to 
be reduced. However, from a national perspective, the impact is not 
expected to be significant for the pipeline operators covered by the 
Final Rule. The following discussion summarizes the analysis provided 
in the Environmental Assessment.
    Many operators covered by the Final Rule (those operating less than 
500 miles of regulated pipeline) already have internal inspection and 
pressure testing programs that cover most, if not all, of their 
pipeline systems. These operators typically place a high priority on 
the pipeline's proximity to populated areas, commercially navigable 
waterways, and environmental resources when making decisions about 
where and when to inspect and test pipelines. As a result, some high 
consequence areas have already been recently assessed, and a large 
fraction of remaining locations would probably have been assessed in 
the next several years without the Final Rule. The most tangible impact 
will be to ensure

[[Page 2143]]

assessments are performed for those line segments that could affect a 
high consequence area that are not currently being internally inspected 
or pressure tested, and ensuring that integrity is maintained through 
an integrity management program that requires periodic assessments in 
these locations. Because hazardous liquid pipeline failure rates are 
low, and because the total pipeline mileage operated by operators with 
less than 500 miles of pipeline that could affect high consequence 
areas is small, the Final Rule has only a small effect on the 
likelihood of pipeline failure in these locations.
    The Final Rule will result in more frequent integrity assessments 
of line segments that could affect high consequence areas than most 
operators are currently conducting (due to the 5-year interval required 
for periodic assessment). However, if the operator identifies and 
repairs significant problems discovered during the baseline inspection, 
and has in place solid risk controls to prevent corrosion and other 
threats, as they must, the benefits of assessing every 5 years versus 
the longer intervals operators more typically employ are not expected 
to be significant.
    The Final Rule requires operators to conduct an integrated 
evaluation of all potential threats to pipeline integrity, and to 
consider and take preventive or mitigative risk control measures to 
provide enhanced protection. If there is a vulnerability to a 
particular failure cause, like third-party damage, these evaluations 
should identify additional risk controls to address these threats. Some 
operators covered by the Final Rule already perform integrity 
evaluations or formal risk assessments that consider the environmental 
sensitivity and impacts on population. These evaluations have already 
led to additional risk controls beyond existing requirements to improve 
protection for these locations. For these operators, it is expected 
that additional risk controls will be limited and customized to site-
specific conditions that the operator may not have previously 
recognized.
    Finally, an important, although less tangible, benefit of the Final 
Rule will be to establish requirements for operator integrity 
management programs that assure a more comprehensive and integrated 
evaluation of pipeline system integrity in high consequence areas. In 
effect, this will codify and bring an appropriate level of uniformity 
to the integrity management programs some operators are currently 
implementing. It will also require operators who have limited, or no, 
integrity management programs to raise their level of performance.
    We expect this Final Rule to provide a more consistent, and 
overall, a higher level of protection for high consequence areas across 
the nation. Even though there is a benefit, we have concluded that it 
is not significant, and, therefore, have issued a finding of no 
significant impact.

Executive Order 13211

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

List of Subjects in 49 CFR Part 195

    Carbon dioxide, Petroleum, Pipeline safety, Reporting and 
recordkeeping requirements.

    In consideration of the foregoing, we are amending 49 CFR part 195 
as follows:

PART 195--TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE

    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.

Subpart F--Operation and Maintenance

    2. In Sec. 195.452, paragraphs (a), (b), (d) heading, (d)(1), and 
(d)(2) are revised and paragraph (d) introductory text is added to read 
as follows:


Sec. 195.452  Pipeline integrity management in high consequence areas.

    (a) Which pipelines are covered by this section? This section 
applies to each hazardous liquid pipeline and carbon dioxide pipeline 
that could affect a high consequence area, including any pipeline 
located in a high consequence area unless the operator effectively 
demonstrates by risk assessment that the pipeline could not affect the 
area. (Appendix C of this part provides guidance on determining if a 
pipeline could affect a high consequence area.) Covered pipelines are 
categorized as follows:
    (1) Category 1 includes pipelines existing on May 29, 2001, that 
were owned or operated by an operator who owned or operated a total of 
500 or more miles of pipeline subject to this part.
    (2) Category 2 includes pipelines existing on May 29, 2001, that 
were owned or operated by an operator who owned or operated less than 
500 miles of pipeline subject to this part.
    (3) Category 3 includes pipelines constructed or converted after 
May 29, 2001.
    (b) What program and practices must operators use to manage 
pipeline integrity? Each operator of a pipeline covered by this section 
must:
    (1) Develop a written integrity management program that addresses 
the risks on each segment of pipeline in the first column of the 
following table not later than the date in the second column:

------------------------------------------------------------------------
                 Pipeline                               Date
------------------------------------------------------------------------
Category 1................................  March 31, 2002.
Category 2................................  February 18, 2003.
Category 3................................  1 year after the date the
                                             pipeline begins operation.
------------------------------------------------------------------------

    (2) Include in the program an identification of each pipeline or 
pipeline segment in the first column of the following table not later 
than the date in the second column:

------------------------------------------------------------------------
                 Pipeline                               Date
------------------------------------------------------------------------
Category 1................................  December 31, 2001.
Category 2................................  November 18, 2002.
Category 3................................  Date the pipeline begins
                                             operation.
------------------------------------------------------------------------

    (3) Include in the program a plan to carry out baseline assessments 
of line pipe as required by paragraph (c) of this section.
    (4) Include in the program a framework that--
    (i) Addresses each element of the integrity management program 
under paragraph (f) of this section, including continual integrity 
assessment and evaluation under paragraph (j) of this section; and
    (ii) Initially indicates how decisions will be made to implement 
each element.
    (5) Implement and follow the program.
    (6) Follow recognized industry practices in carrying out this 
section, unless--
    (i) This section specifies otherwise; or
    (ii) The operator demonstrates that an alternative practice is 
supported by a reliable engineering evaluation and provides an 
equivalent level of public safety and environmental protection.
* * * * *

[[Page 2144]]

    (d) When must operators complete baseline assessments? Operators 
must complete baseline assessments as follows:
    (1) Time periods. Complete assessments before the following 
deadlines:

------------------------------------------------------------------------
                                     Then complete
                                       baseline          And assess at
                                    assessments not    least 50 percent
                                    later than the     of the line pipe
       If the pipeline is:          following date      on an expedited
                                    according to a     basis, beginning
                                     schedule that     with the highest
                                      prioritizes       risk pipe, not
                                     assessments:         later than:
------------------------------------------------------------------------
Category 1......................  March 31, 2008....  September 30,
                                                       2004.
Category 2......................  February 17, 2009.  August 16, 2005.
Category 3......................  Date the pipeline   Not applicable.
                                   begins operation.
------------------------------------------------------------------------

    (2) Prior assessment. To satisfy the requirements of paragraph 
(c)(1)(i) of this section for pipelines in the first column of the 
following table, operators may use integrity assessments conducted 
after the date in the second column, if the integrity assessment method 
complies with this section. However, if an operator uses this prior 
assessment as its baseline assessment, the operator must reassess the 
line pipe according to paragraph (j)(3) of this section. The table 
follows:

------------------------------------------------------------------------
                 Pipeline                               Date
------------------------------------------------------------------------
Category 1................................  January 1, 1996.
Category 2................................  December 18, 2006.
------------------------------------------------------------------------

* * * * *

    Issued in Washington, DC, on January 8, 2002.
Ellen G. Engleman,
Administrator.
[FR Doc. 02-858 Filed 1-15-02; 8:45 am]
BILLING CODE 4910-60-P