# U.S. DOT/RSPA - Final Regulatory Evaluation

**Citation:** 0900006480e8ae8e  
**Type / status:** rulemaking / current  
**Agency:** Pipeline and Hazardous Materials Safety Administration  
**Effective:** Not stated  
**Published:** Not stated

U.S. Department of Transportation Research and Special Programs Administration Final Regulatory Evaluation Pipeline Integrity Management in High Consequence Areas (Hazardous Liquid Pipeline Operators with less than 500 miles of Pipelines) Docket RSPA-00-7408 3. Requiring pipeline operators to develop integrity management programs providing for inspection and testing based on risk factors and integration of information related to pipeline 1 isk and to add accident mitigative features and improved leak detection based on risk. Pipeline operators are uniquely qualified to...

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U.S. Department of Transportation
Research and Special Programs Administration
Final Regulatory Evaluation
Pipeline Integrity Management in High Consequence Areas (Hazardous Liquid Pipeline
Operators with less than 500 miles of Pipelines)
Docket RSPA-00-7408

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INTRODUCTION
The U.S. Department of Transportation Research and Special Programs Office of Pipeline Safety
(OPS) is changing pipeline safety regulations to require operators of certain hazardous liquid
pipelines to validate the integrity of their pipelines in high consequence areas (HCAs). The rile
would apply to operators with less than 500 aggregate miles of pipeline. (Requirements for
operators with more than 500 miles of hazardous liquid pipeline were established in a previoi is
rulemaking). The objective of the change is to reduce the risk of hazardous liquid pipeline
incidents in these areas. OPS defines a high consequence area as one in which there is a high
population area or densely populated area, a commercially navigable waterway, or an unusua ly
sensitive area. To validate the integrity of their pipelines in high consequence areas under thi :
regulatory change, pipeline operators must implement an integrity management program for : uch
pipelines including periodic inspection and testing and integration of information related to
pipeline integrity. The purpose of this report is to assess the benefits and costs of the regulatc ~ r y
change.
TARGET PROBLEM
Hazardous liquid pipeline spills can have an adverse impact on human health and the
environment. The magnitude of this impact differs. There are some areas in which the impa :t of
a spill will be more significant than it would be in others due to concentrations of people whc I
could be affected or to the presence of environmental resources that are unusually sensitive tc 1
damage. Because of the potential for dire consequences of pipeline failures in certain areas,
these areas merit a higher level of protection. OPS is promulgating this regulation to afford the
necessary additional protection to these “high consequence areas”.
Numerous investigations by OPS and the National Transportation Safety Board (NTSB) havi :
highlighted the importance of protecting the public and environmentally sensitive areas fron L
pipeline failures. NTSB has made several recommendations to ensure the integrity of pipeliries
near populated and environmentally sensitive areas. These recommendations included requi ing
periodic testing and inspection to identify corrosion and other damage, establishing criteria ti 1
determine appropriate intervals for inspections and tests, determining hazards to public safet 1 1
fiom electric resistance welded pipe and requiring installation of automatic or remotely-oper ited
mainline valves on high-pressure lines to provide for rapid shutdown of failed pipelines.
Congress also directed OPS to undertake additional safety measures in areas that are densely
populated or unusually sensitive to environmental damage. These statutory requirements
included having OPS prescribe standards for identifying pipelines in high density population
areas, unusually sensitive environmental areas, and commercially navigable waters; issue
standards requiring periodic inspections using internal inspection devices on pipelines in der lsely-
populated and environmentally sensitive areas; and survey and assess the effectiveness of
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emergency flow restricting devices, and prescribe regulations on circumstances where an
operator must use the devices.
This rulemaking addresses the target problem described above, and is a comprehensive respoi ise
to NTSB’s recommendations and Congressional mandates, as well as pipeline safety and
environmental issues raised over the years.
ALTERNATIVES CONSIDERED
OPS considered several alternatives to provide the necessary increased level of protection to 1 iigh
consequence areas. These alternatives were:
1. No action.
2. Prescriptive requirements for inspection and repair of pipelines in high consequence areas and
for incorporating accident mitigative features and improved leak detection.
3. Requiring pipeline operators to develop integrity management programs providing for
inspection and testing based on risk factors and integration of information related to pipeline iisk
and to add accident mitigative features and improved leak detection based on risk.
4. Requiring pipeline operators to develop integrity management programs providing for
expedited inspection and testing.
INITIAL SCREENING OF ALTERNATIVES
1. No action.
Pipeline operators currently manage their pipeline to avoid accidents, leaks and spills. They
perform inspection and testing on their pipelines to assess their integrity, and make repairs as
they conclude they are needed. These actions would be expected to continue under the “no
action” a1 ternative.
Pipeline leaks, spills, and ruptures occur, despite the existence of these operator programs.
Major pipeline spills have occurred in the last two years, of which two were particularly notallle,
(Bellingham and PEPCO). In both cases, in-line inspection (pigging) of the pipeline had taki :n
place. Operators either failed to recognize the significance of indications from the pig runs or
failed to integrate that information with other information about the pipeline, including the
presence of construction activity in the area. OPS concludes that validation of these prograrr s
through audit and review by outside parties, i.e, the regulator, is necessary to help assure that
appropriate actions are taken.
In addition, continuation of voluntary programs cannot be assured absent some regulatory
requirement. Pipeline operators must be responsive to market conditions, and future change! in
economic conditions could lead to curtailment or elimination of some or all inspection and
testing.
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OPS concludes that assuring continuation of pipeline integrity management programs, assurir g
that their scope encompasses all areas requiring special protection, and verifying their adequa :y
are necessary to assure that the requisite level of protection will be provided. This assurance
cannot be provided without some regulatory requirement addressing the target problem. In
addition, continued reliance on voluntary industry efforts would not be responsive to the
Congressional mandate that OPS promulgate requirements to assure protection of the areas th at
are herein designated as high consequence areas.
For these reasons, the “no action” alternative was not considered further
2. Prescriptive requirements for inspection and repair of pipelines in high consequence areas and
for incorporating accident mitigative features and improved leak detection.
Pipeline circumstances differ, even within high consequence areas. These differences would
make it difficult, at best, to establish prescriptive requirements that would appropriately addri :ss
all possible combinations of pipeline size, type, and configuration or to consider other factor:
that contribute to the risk of failure of a particular pipeline. It is likely that creating detailed
prescriptive requirements would result in a need for a large number of waivers to address the
issues of importance to specific pipelines and high consequence areas. The result would be a
patchwork of specific, but different requirements. It would be an inefficient use of industry 2 nd
government resources to establish requirements in this fashion. Compliance inspection woulij
still require that the requirements applicable to specific pipelines be identified for comparisoi L
with ongoing practices.
Prescriptive requirements also would tend to stifle technological innovation. They do not all iw
for different approaches based on advances in the technology. The technology associated wi. h
in-line inspection of pipelines (i.e., pigging) is advancing at a rapid pace. Establishing
prescriptive requirements could slow this advancement, or could preclude use of new techniciues
that may be developed. In the extreme, prescriptive requirements could stop technological
innovation in this area completely.
Most importantly, however, establishing prescriptive requirements would not assure the
integration of information which experience has shown is vital to preventing pipeline accidei its.
As noted above, two major accidents have occurred in recent years despite the fact that the
pipelines involved had been pigged. It appears that other information was available that, if
correlated to the pig results, could have highlighted the need for action regarding the indicatilms
that ultimately resulted in failure of the pipe. An integrity management program is required o
assure this integration of available information. Outside review of the integrity management
program (Federal and state) by regulators, is necessary to assure that it is complete and propt rly
implemented. This outside review cannot be assured without a requirement for such a progr im.
For these reasons, the option of establishing prescriptive requirements was not evaluated fur her.
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3. Requiring pipeline operators to develop integrity management programs providing for
inspection and testing based on risk factors and integration of information related to pipeline 1 isk
and to add accident mitigative features and improved leak detection based on risk.
Pipeline operators are uniquely qualified to develop integrity management programs and prov ide
for the necessary integration of information. They have the best knowledge of their pipelines and
the factors affecting its risk. Integration of information requires that the management system:, of
the company be aligned and operated to assure that necessary information is shared and that i. is
evaluated in its proper context by knowledgeable personnel. These are actions that are difficii It
to require through prescriptive regulation. Requiring that operators develop such programs is the
best way to assure that they exist. Such a requirement also provides the regulatory basis for (IPS
to audit, review, and assess these programs and their implementation.
The best integrity management plans, when implemented properly, can reduce the risk of pipi :line
accidents. They cannot, however, eliminate that risk. Leaks and ruptures could still occur, fmm
unforseen outside impacts on the pipeline or fkom unanticipated interactions among factors
contributing to pipeline risk. It is therefore important that features and procedures be available to
detect and mitigate the effects of accidents that may occur.
Here again, circumstances differ between pipelines and between regions and local jurisdictioi is.
The differences make it difficult to establish prescriptive requirements that will provide the bl:st
protection for each high consequence area. Requiring that operators explicitly consider the n :ed
for improved leak detection and for mitigative features and provisions and that they impleme it
those found necessary is the most effective means of providing such protection. Such a
requirement also provides the regulatory basis for audit and review by OPS and state regulatclrs.
For these reasons, this option was selected for fbrther development.
4. Requiring pipeline operators to develop integrity management programs providing for
expedited inspection and retesting.
OPS considered the need for requiring integrity management programs that would require
inspection and testing of pipelines to recur over short intervals, a few years. The ability to
require frequent testing is limited by the available resources for testing and inspection.
The companion rule originally proposed for operators with more than 500 miles of pipeline
included requirements for reassessment at ten-year intervals. Based upon consideration of
comments received, that interval was reduced in the final rule to five years, with limited
excpetions. OPS concluded that the spur provided by the regulation would be Iikely to resul. in
an increase in testing capacity over the next five years that will then be able to accommodate
testing at accelerated rates. OPS considers it important to inspect and test pipeline in high
consequence areas at an aggressive rate in order to assure the additional protection desired fclr
these areas. OPS concludes that a similar interval is appropriate for operators with less than 500
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miles of pipeline because the increased testing capacity will also be available to them and
because their historical testing rate is at a similar fiequency.
BASELINE REGULATORY ENVIRONMENT
In order to assess the costs and benefits of the new regulation, it is necessary to first ascertain the
current level of activity in areas addressed by the rule. In this instance, it is necessary to
determine the rate at which pipeline inspections are being performed, the presence of prevent ve
and mitigative features, and the prevalence and nature of integrity management plans similar o
those required by the rule.
Informal discussions with operators with less than 500 miles of pipeline have identified that r iiost
have a regular assessment program. A large majority appear to test all of their pipelines on a
fi-equency of five years or less. OPS assumes that this rate applies to piping in high conseque nce
areas and that this rate would have continued absent a regulatory requirement to increase it.
Much of the testing being conducted by these operators is the initial inspection of pipelines. The
rate at which subsequent inspections would be performed is now unknown. It is likely that s( )me
pipeline would be identified for reinspection frequently (e.g., every five years). It is equally
likely that some pipeline would not be reinspected at all.
OPS also has limited knowledge about the nature and extent of preventive and mitigative fea ures
and procedures that have been implemented by pipeline operators. The mitigative feature fo1
which OPS has the best knowledge is emergency flow restriction devices (EFRDs). EFRDs ,ire
check valves or remotely operated valves, usually block valves, that can reduce the amount o F
product lost in a pipeline leak. It is estimated that 84.1 percent of all valves currently instal ed
on hazardous liquid pipelines are manually operated block valves.’ OPS has no knowledge c f
current plans to convert any of these valves to remote operation.
Integrity plans are a key element of this rule. To better understand and promote more
comprehensive and integrated approaches to safety and environmental protection, OPS creatc :d
the Risk Management Demonstration Program, and the System Integrity Inspection (SII) Pilclt
Program. These programs encourage and evaluate operator-developed safety and environmeiital
management processes that incorporate operator- and pipeline-specific information and data to
identify, assess, and address pipeline risks. These programs, along with the Oil Spill Respor se
Plan Review and Exercise Program, are helping RSPA’s Office of Pipeline Safety (OPS) ref ne
its regulatory oversight processes. These processes help to ensure that pipeline operators ha7 re
effective processes in place to identify the most important risks to the public and the
environment, and to develop and implement cost-effective preventive and mitigative actions to
‘Office of Pipeline Safety, Emergency Flow Restricting Devices Study (A Study Mandated by P.L. 100-561), U S.
DOT, April 1990. The original source of the information was reported to be the American Petroleum Institute.
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manage these risks. Many of these initiatives have validated the importance of focusing
resources and establishing higher levels of protection in areas where a pipeline failure could have
significant consequences.
Through the Risk Management Demonstration Program and the System Integrity Inspection F ilot
Program, OPS has improved its understanding of pipeline operator integrity management syst lems
and activities. This experience has shown that a number of liquid pipeline operators have
formalized management systems to identify and address the most significant integrity threats o
their pipeline systems. In the Risk Management Program, participants perform systematic an1 i
comprehensive risk assessments to identify the specific nature and location of the most
significant risks posed by operation of their pipeline system. An essential feature of these risl
assessments is the integration of information from many diverse sources to fully understand tl le
integrity threats at specific locations on the pipeline. Environmental consequences and the imiDact
on nearby population are explicitly considered in these risk assessments. Through formal, rislc-
based decision making processes, these companies use the risk assessment results to identify
projects and activities that address potential system integrity threats, thereby preventing oil SF ills.
The risk management process also examines the consequences of potential releases and explc res
opportunities to minimize the environmental and public safety and health impacts should a
failure occur. These investigative risk management programs, and the preventive and mitigal ive
risk control activities that evolve from them, supplement the minimum regulatory requiremer Its
established in 49 CFR 195 to protect the public and the environment.
The System Integrity Inspection Program is focused on developing a more integrity-based
approach to OPS inspections. Instead of using a “checklist” approach, OPS is focusing the
inspection process on an operator’s integrity management processes and activities. Through
working with the operator, OPS is able to understand and influence the methods and approac lies
used to assess pipeline integrity, and the approaches to integrating integrity assessment data with
other pipeline specific information to identify the most significant integrity threats to the systlem.
Specifically, OPS has observed how operators examine internal inspection data in conjunctia n
with other surveillance and operating data, expected population growth, land use, constructic n
activity along the pipeline, and other information relevant to assuring the integrity of the pipt line
in high population areas and in environmentally sensitive areas. Through this interaction OP S is
acquiring a broader understanding and a greater confidence that effective programs are in pla :e to
address the most significant risks. Similar to the Risk Management Program, the SI1 Program is
emphasizing how operators evaluate their system condition and its risks, and use this
information to make sound integrity management decisions.
OPS experience in the Risk Management Demonstration Program and the System Integrity
Inspection Program indicates that integrity management programs such as that required by tk is
rule have been developed. They are far from universal, however.
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SCOPE AND PARAMETERS OF ANALYSIS
This analysis of benefits and costs takes the following approach. First, the mileage impacted iy
the regulatory change is identified and estimated. Then the potential benefits of the rule are
discussed. In the next section the potential costs of the rule are examined. Finally, a discussicln
of the costs versus the benefits is examined. It should be noted that, unless otherwise specific d,
all dollar values in this report are given in constant 1998 dollars.2 Furthermore, this analysis 'vi11
arbitrarily consider only the first twenty years after the effective date of the final rule. Includi ng
additional years would not be expected to materially affect the conclusions of this analysis.
ANALYSIS
Impacted Mileage
In this section the total hazardous liquid pipeline mileage impacted by the regulatory change i s
estimated. That mileage is located in or nearby high consequence area's, defined by the chan 1;e
as: (1) high population areas, (2) densely populated areas, (3) commercially navigable
waterways, and (4) unusually sensitive areas.
Total PiDeline Mileage
In total, there is an estimated 157 thousand miles of regulated hazardous liquid pipelines in tlie
U.S.3 This change would not impact all hazardous liquid pipeline operators. Rather, it woulc I
impact only those operators with an aggregate of less than 500 miles of pipeline. The Office of
Pipeline Safety (OPS) estimates that these operators have 13.3 percent of the jurisdictional
hazardous liquid pipeline mileage.4 Thus, the operators covered by the rule are expected to h ave
about 20,900 miles of regulated hazardous liquid pipelines.
Impacted Mileage in High Population And Densely Populated Areas
Because of the similar nature of the two types of areas, the impacted pipeline mileages in higln
population areas and in densely populated areas are considered together. As defined by the
'Dollars are converted from nominal values to real 1998 values using the Producer Price Index (PPI), Intermed ate
Materials, Supplies, and Components. The source of the PPI index numbers is the U.S. Bureau of Statistics Wt b
page.
'Jurisdictional hazardous liquid pipeline mileage for 1999. This mileage was obtained from Office of Pipeline Saf: :ty
User Fee Assessments.
'This percentage estimate was based on information from Office of Pipeline Safety User Fee Assessments. This
estimate may overstate the actual percentage operated by operators with less than 500 miles of pipeline, becaus
some operators may report pipeline segments using multiple names. Therefore, some operators with apparent11 little
pipeline mileage may actually be part of larger operators.
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regulatory change, a high population area is one with 50,000 or more people in total and at lezist
1,000 people per square mile. A densely populated area is defined as any place containing a
concentrated population, such as an incorporated or unincorporated town or village.
The OPS estimates that 16,500 miles of regulated hazardous liquid pipeline are located in higli
population areas and another 5,500 miles are located in densely populated areas. It is likely tl lat
only part of this 22,000 miles is pipeline covered by the rule. Since 13.3 percent of the total
mileage is operated by operators with less than 500 miles of pipeline, it appears reasonable to
assume, in the absence of contrary information, that 13.3 percent of the mileage located in hii1,h
population and densely populated areas, or 2,930 miles of pipeline, is operated by these
operators.
Impacted Mileage Near Commercially Navigable Waterways
The regulated pipeline mileage in or near commercially navigable waterways includes (1) the
mileage crossing those waterways and (2) the mileage lying near enough to the waterways to
adversely impact them, should a leak, spill, or rupture occur.
The OPS estimates that 800 miles of regulated hazardous liquid pipeline are in or near navigilble
waterways. It is likely that only part of this mileage is pipeline within the scope of this
rulemaking. Since 13.3 percent of the total mileage is operated by operators with less than 500
miles of pipeline, it appears reasonable to assume that 13.3 percent of the mileage in or near
navigable waterways, or 1 10 miles of pipeline, is operated by these operators.
Impacted Mileage in Unusually Sensitive Areas
A pilot test relating to unusually sensitive areas (USAs) was recently conducted by the U.S.
Department of Transportation (U.S. DOT) and the American Petroleum Institute (API). This
pilot test covered pipelines in California, Louisiana, and Texas. One product from this pilot t:est
was an estimate of the jurisdictional pipeline mileage in USAs or that could affect a USA. rl he
pilot test results indicate that 14.2 percent of hazardous liquid pipeline mileage in the three s ates
is located in a USA. Some of this pipeline was also located in high- or densely-populated ar :as.
Pilot program results indicate that 2.7 percent of hazardous liquid pipeline mileage in the thr :e
states was in both a USA and a populated area. Thus, 1 1.5 percent of pipeline mileage in thc
pilot states was in a USA but not otherwise encompassed within the definition of a high
consequence area. For purposes of this analysis, OPS has assumed that the same percentage of
hazardous liquid pipeline mileage in other states is located in USAs but not otherwise in a hi gh
consequence area. This percentage multiplied by the total hazardous liquid mileage of opere tors
with less than 500 miles of pipeline, 20,900 miles, results in an estimate of 2,400 miles for t le
pipeline mileage of these operators that is located in USAs.
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Total ImDacted Mileage
Given the estimates derived above for the impacted mileage in or nearby high consequence ar :as,
a total of 5,440 miles of regulated hazardous liquid pipeline is expected to be impacted by the
regulatory change.
Mileage Impacted Per Year
The regulatory change calls for inspection and testing, improving leak detection where
appropriate, and the use of additional prevention or mitigation measures where necessary. Ar
example of such a measure includes the installation of Emergency Flow Restricting Devices
(EFRDs) at selected points. For the purpose of illustration this analysis examines the potentiill
costs of installation of EFRD’s, although EFRD’s are only one alternative among many possi ;)le
preventive and mitigative measures that operators could choose. The mileages impacted per
year will be important inputs in the calculation of the benefits and costs of inspection and tesl ing
and the benefits of the installation of the EFRDs.
Inspection and Testing
The regulatory change requires baseline and subsequent testing of the impacted mileage usin] ; in-
line inspection, pressure testing, or alternative methods. Acceptable in-line inspection includ es
high resolution, low resolution, and ultrasonic pigging. Acceptable pressure testing consists )f
hydrostatic testing. Acceptable alternative methods include any other methods that would
provide a level of safety equivalent to that provided by internal inspection or pressure testing
Baseline Testing
The rule requires that baseline testing be completed within seven years of the effective date clf the
rule. Informal discussions with operators with less than 500 miles of pipeline have identified that
most have a regular assessment program. A large majority appear to test all of their pipeline ; on
a frequency of five years or less. Thus, it would appear that they would need to test no addit onal
mileage beyond that otherwise planned in order to meet the requirements for baseline inspec ion.
OPS recognizes, however, that there are probably some companies not already conducting
assessments at frequencies consistent with the rule, even though the overall amount of inspe1:tion
and assessment in the industry is more than would be required. OPS has conservatively assL med
that as much as 10 percent of impacted mileage, or 544 miles, may require unplanned assessinent
over a seven year period (78 miles per year).
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Once baseline testing has been performed on a segment of pipe, the rule requires that subsequlmt
testing be undertaken on that segment, based on risk factors, at least once every five years (wilh
limited exceptions). The planned rate of re-testing of pipeline by operators with less than 50C
miles of pipeline is unknown. Informal discussions with pipeline operators indicate that muc’i
pipeline mileage would have been re-tested frequently (e.g., every five years), while some
mileage would not have been re-tested at all.
Since most operators with less than 500 miles of pipeline appear to test their pipelines every 1 ive
years or more often, it should only require minor changes in scheduling specific pipe segmenl s
for assessment to assure that all pipe is inspected at least every five years. OPS therefore
concludes that there could be limited additional assessment needed by operators with less tha 1
500 miles of pipeline in order to meet requirements for re-assessment at a five-year fi-equencj .
For the reasons described above, OPS has again estimated for this analysis that 10 percent of
impacted mileage will require unplanned assessment.
Operators with less than 500 miles of pipeline will therefore need to assess an additional two
percent of their impacted mileage annually (1 10 miles) to meet the requirements for subsequt nt
assessment. OPS expects that operators will identify some pipeline in high consequence area s
for which a longer inspection interval can be justified, and that they will seek OPS review to
permit these segments to be tested at a longer interval. OPS has not adjusted this analysis to
account for these longer-interval re-assessments, since the information obtained by informal
discussions with operators indicates limited unplanned assessment should be required and ou r
assumption that 10 percent of impacted mileage will require unplanned assessment should btlund
any additional costs.
Pipeline operators will need to do some subsequent testing at the same time they are doing
baseline testing. This subsequent testing will begin in the sixth year of baseline testing, which is
when mileage “baseline tested” in the first year after the final rule will need to be re-tested.
During the sixth and seventh years of baseline testing, subsequent and baseline testing will
overlap. Assuming that most re-testing would have been deferred until all initial testing was
completed in the absence of a regulatory requirement, all subsequent testing in those two years
will be over and above what would have been done in the absence of the rule. The full 1,09(1
miles undergoing subsequent testing during each of these two years is therefore assumed to be in
excess of what would have been done. This analysis also assumes that 78 miles of additional
pipeline must be inspected in each of these two years to complete baseline inspection (see ab we)
so that the total of additional mileage that will require inspection during these years is 1,168
miles.
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Enhanced Leak Detection
The rule includes criteria for operators to evaluate their leak detection capabilities and upgrad ;
them where necessary. OPS does not know how many operators with less than 500 miles of
pipeline currently have leak detection capabilities nor how many of those existing systems wi 1
require upgrading. Evaluation and upgrading, if necessary, of leak detection capability is
integrally related to the required addition of mitigative features since leak detection would
provide the information necessary to activate those mitigative features or procedures.
Installation of EFRDs
The OPS does not know how many of the manually operated block valves currently installed iin
the 5,440 miles of impacted pipeline will be converted to EFRDs as a consequence of the
regulatory change. (OPS also has no knowledge of other mitigation or prevention actions thal.
might be taken.) It is estimated that 84.1 percent of all valves currently installed on hazardou;;
liquid pipelines are manually operated block valve^.^ The rule specifies factors that operators
must consider in deciding whether to convert these valves to remote operation or to install otl ier
preventive or mitigative features. These factors are:
swiftness of leak detection and pipeline shutdown capabilities
type of commodity camed
rate of potential leakage
volume that can be released
topography or pipeline profile
potential for ignition
proximity to power sources
location of nearest response personnel
specific terrain between the pipeline and the high consequence area
benefits expected by reducing spill size
Operators will only install EFRD’s in pipelines where installation of an EFRD would prove 1 o be
beneficial. That is the cost of the installation and maintenance of the EFRD would be less than
the potential benefit.
BENEFITS
To help reduce hazardous liquid pipeline incidents and their consequences, OPS is requiring that
pipeline integrity management plans be developed and implemented by operators with less tl ian
5
Office of Pipeline Safety, Emergency Flow Restricting Devices Study (A Study Mandated by P.L. 100-561), 1. .S.
DOT, April 1990. The original source of the information was reported to be the American Petroleum Institute.
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500 aggregate miles of pipeline. These plans are to provide for inspection and testing of pipeline
that could affect high consequence areas, which are high-density population areas, navigable
waterways, and unusually sensitive areas. In addition, the rule requires that the plans identify any
sites where Emergency Flow Restricting Devices (EFRDs) would significantly reduce the risk to
a high consequence area from a pipeline spill and that the operators install EFRDs at those sit :s
and that affected operators evaluate leak detection capability and upgrade it if necessary.
The benefits resulting from the regulatory change are discussed in this section. Those benefitis
are expected to result from improvements in pipeline safety performance attributable primaril y
to: ( 1 ) the development of a framework for integrity management that assists operators in
determining and identifying risks to their pipelines in high consequence areas that could bene fit
from periodic testing or other examination, (2) reassurance to the public that pipelines in higl-1
consequence areas receive the necessary levels of attention that ensure their integrity (3)
increases in inspection and testing on pipelines in or near high consequence areas and (4) the
installation of improved leak detection or additional EFRDs on pipelines in or near high
consequence areas.
Pipeline operators also have strong incentives to ensure the integrity of their pipelines. In
addition to the positive safety and environmental benefits, the lost product and unscheduled
downtime for repairs following a major incident can significantly impact the company’s final icial
performance and its ability to satisfy customer commitments. Operators cannot afford to haw e
these critical transportation assets out of service for lengthy periods of time in today’s
competitive business environment. In addition, the damage to the company’s public image aiid
reputation, as well as the legal implications of serious incidents, can pose an even broader a d
longer term negative impact on the company’s business operations. For these and other reasc ns,
many pipeline operators have implemented and are continuing to improve more systematic s ifety
and environmental management processes.
Development of Integrity - Plans And Framework
The single most important part of this rule is the requirement for the integrity plan and
framework. The creation, development and implementation of these documents will provide for
the necessary integration of information regarding pipeline condition. Integration is importa nt to
assure OPS, and the public, that pipeline operators are considering fully the unique risks tha
hazardous liquid pipelines pose to high consequence areas. Plan development will assure ncit
only that they are considering these risks but that they have developed a plan that requires e, tra
scrutiny and precautions in these areas to safeguard the public and the environment. These
safeguards include the use of periodic testing and the installation of EFRD’s where they are
appropriate. The public is apprehensive that “aging” hazardous liquid pipelines pose a dangi :Tous
threat to the safety and environmental health of their community. The development and
implementation of an integrity management plan that requires a periodic testing schedule shimld
provide the public as well as the OPS some level of assurance that pipeline operators have
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provided significantly to the protection of public safety and the environment in these sensitivt 8
areas.
Since integrity management systems are not universal across the industry, OPS believes that i
requirement that such plans be developed is necessary. The rule requires that plans be develo ped
and specifies considerations that must be taken into account in that development. Developmt nt
of the plans will involve consideration of risk factors unique to particular pipelines and high
consequence areas. Operators will be required to establish a periodic assessment program in
which all segments in high consequence areas are pressure tested or internally inspected no le ss
frequently than once every five years, unless an exception is justified, and the entire pipeline s
evaluated, and to determine how experience in other areas should be a factor in HCA’s.
Evaluation is an ongoing process. Operators will be expected to consider the risk factors and
their relative priorities in establishing assessment schedules. This allows operators to develo I an
internal inspection and testing program that is customized to the particular operating
characteristics and risks associated with different portions of their system(s).
Inspection And Testing
The inspection and testing required by the regulatory change will be some combination of in- line
inspection (i.e., high resolution, low resolution, and ultrasonic instrumented pigging), pressui e
testing (i.e., hydrostatic testing), and equivalent alternative testing (Le., testing using other
techniques or tools that provide a level of safety and environmental protection comparable to
pigging and hydrostatic testing).
The change will spur operators with less than 500 miles of pipeline to identify and correct
potential problems in pipelines in high consequence areas that might otherwise be missed. The
main types of potential problems that can be helped by inspection and testing are those relatii lg to
(1) intemal corrosion, (2) external corrosion, and (3) ruptures of previously damaged pipelinl:.
Other types of potential pipeline problems may also be helped, but to a significantly lesser dt g e e
than these.
The expected benefit of increased internal inspection and pressure testing will be a reduction in
incidents and incident consequences. Consequently, the benefits that are expected to result f 1-om
the regulatory change are reduced (1) deaths, (2) major and minor injuries, (3) property damlige,
(4) spilled product, (5) recovered product, (6) environmental damage, and (7) other
consequences.
Benefits of Increased Inspection and Testing
The expected benefit of increased inspection and testing will be a reduction in incidents cau:,ed
by internal corrosion, external corrosion, and ruptures of previously damaged pipeline and irl
their consequences. This benefit will be a function of (1) the additional pipeline mileage tesled
per year, (2) the expected reduction in incidents and consequences that will be attributable tci
13

<<<PAGE 15>>>

inspection and testing, and (3) the expected annual incident and consequence rates on the
relevant mileage.
The Additional Mileage Tested Per Year
Additional mileage inspected and tested during the first five years following the effective datc of
the rule will be 78 miles. During each of the next two years, 1,168 additional miles of pipelir e
will be inspected and tested each year, and 1 10 additional miles of pipeline will be inspected md
tested annually from then on (described above).
With respect to deaths and serious injuries, the following assumptions are made:
A life is valued at $2.7 million
A serious injury is valued at $490 thousand
These valuations are standard assumptions currently used in Office of Pipeline Safety and DC bT
benefit/cost analyses.
Enhanced Leak Detection and EFRDs
In addition to inspection and testing, the regulatory change requires that leak detection be
upgraded where necessary and that other preventive and mitigative actions be considered whl :re
the benefit exceeds the costs. One example of such measures that is used here for purposes c f
illustration is that Emergency Flow Restricting Devices (EFRDs) be installed at locations in I )r
near high consequence areas where they would significantly reduce risk. (Operators could
choose other methods of mitigation and prevention but they are not examined in this analysis .)
Factors that must be considered in deciding whether to install EFRDs are specified in the rull :
and were described above.
The expected impact of the installation of additional EFRDs will be a reduction in the
consequences of incidents attributable to (1) internal corrosion, (2) external corrosion, (3) ru iture
of previously damaged pipe, (4) third party damage, (5) defective pipe, and (6) defective pip4 :
seams.6 The consequences of other types of incidents may also be mitigated by EFRDs, but
probably to a lesser degree than these. It should be noted that incidents will not be reduced tiy
EFRDs, since EFRDs do not help prevent the occurrence of incidents.
Benefit of Enhanced Leak Detection
The benefit of improvements to leak detection will be quicker detection of any leaks or spillrr that
could impact high consequence areas. Quicker detection will allow more rapid use of EFRTls or
60PS, Emergency Restricting Devices Study, April 1990.
14

<<<PAGE 16>>>

other mitigative devices. It will also allow swifter actions in response to leaks or spills that u ill
help to minimize consequences.
Benefit of EFRDs
The benefit of EFRD installation will be a reduction in incident consequences for certain typt s of
incidents. This impact will be a function of (1) the hazardous liquid pipeline mileage protect1 :d
by the EFRDs, (2) the expected reduction in incident consequences that will be attributable tcl
EFRDs, and (3) the expected annual incident and consequence rates on the impacted mileage
COSTS
The rule requires that, within one year of the effective date of the final rule, pipeline operator i:
(1) identify areas that could be affected (2) prepare a written plan for initial (or baseline)
assessment of all pipeline that could affect a high consequence area and (3) prepare a fi-amew ork
addressing each element of an integrity management plan for their pipelines. These documer ts
will detail testing methods to be used, risk factors considered in the selection of the appropri:ite
testing methods for each particular high consequence area, and the schedule of testing and
inspection. Appropriate testing methods include (1) pressure testing, (2) internal inspection, md
(3) equivalent (in terms of level of safety provided) alternatives to pressure testing and intern 11
inspection. The plans will also include a site-specific risk assessment to determine whether I i x k
detection capability needs to be upgraded and to identify sites where mitigation measures SUC h as
Emergency Flow Restricting Devices (EFRDs) would significantly reduce risk. They will al: o
include a schedule for EFRD installation or other mitigation measures, such as enhanced
response procedures or management controls where required. Once the plans have been p r e p e d
they will be used for baseline integrity testing. That testing must be completed within seven ;'ears
of the effective date of the final rule (half of the testing must be completed within three and ( ne-
half years of the effective date). OPS inspections will verify the plans and assure they are
implemented thoroughly.
Pipeline operators will be installing EFRDs at sites or taking other mitigation measures near high
consequence areas where risk assessments indicate that they would significantly reduce risk.
After the baseline testing has been completed, pipeline operators will be expected to periodic ally
reassess the need for additional preventive or mitigative measures. Furthermore, they will bc :
expected to retest their pipeline mileage in or near high consequence areas at least once ever#[
five years depending on risk factors.
Based on the foregoing requirements, the costs that can be expected to result from the regula tory
change will be those associated with the major provisions of this rule, which are:
1. Framework - setting up integrity management program;
2. Baseline assessment - internal inspection or pressure testing;
3. Periodic assessment (inspection) & evaluation;
15

<<<PAGE 17>>>

4. Data integration;
5. Remedial action;
6. Enhanced leak detection; and
6. Mitigative measures (e.g., EFRDs).
The Costs of Plans and Reports
The plans and reports required by the regulatory change are: (1) a written plan for baseline
assessment of all pipelines that could affect high consequence areas, (2) a framework addressing
each element of an integrity management program, and (3) other documents supporting the
decisions made, analyses made, and actions taken in the implementation of the integrity
management program.
Cost of the Written Plan and Framework
Pipeline integrity management plans are relatively new. Experience in developing these plans has
generally been with larger operators. Informal discussions with pipeline industry consultants
indicate that these plans can cost anywhere from $75 thousand to $300 thousand. Well over ialf
their cost would be expected to go toward the preparation of the plan (i.e., analysis and writirlg).
The remainder would go primarily toward data gathering and computer programs needed to
analyze that data.
Integrity management plans that have been prepared voluntarily by some operators are more
extensive than plans that would meet the minimum requirements specified in the rule. OPS I iotes
that the plans required by many operators with less than 500 miles of pipeline will be simplei
than an “average” integrity management plan for a large operator. For the purposes of this
analysis, it is assumed that a written plan and framework prepared by a pipeline operator sol€ ly to
comply with this rule will cost $75,000, the low-point of the estimated range. This estimate IS
considered reasonable for operators with a few hundred miles of pipeline. OPS notes that co Sts
could be considerably lower for operators with only a few miles of pipeline or a limited num )er
of pipehe segments (separate locations that must be considered). OPS has not attempted to
determine how many of the operators with less than 500 miles of pipeline fall into this categc ~ r y
and has, instead, conservatively used the same cost estimate for all operators potentially subj i:ct
to the rule.
Other Supporting Documents
Operators will have to evaluate new information that may affect their integrity programs and
revise those programs as needed. New information could include, for example, new inspecti on
technology, changes to the pipeline system or its operation, and changes to the boundaries oj high
consequence areas. The annual effort required to modify the programs on a continuing basis is
expected to be considerably less than the effort needed to prepare the programs in the first pl ace.
OPS has estimated this annual effort at $8,000 per year.
16

<<<PAGE 18>>>

It is expected that the supporting documents that will be created will be primarily record keep ing
associated with periodic assessment. This record keeping, although important, is expected to
require minimal time and resources. The documents are expected to be prepared by junior stz ff
at the pipeline, under the oversight and management of senior staff. They are expected to tak ; no
longer than two labor weeks to produce. It is estimated that they will have a total cost of $2,C 00.
For the purposes of this analysis, it is assumed that these reports will be produced annually.
Here again, OPS considers these estimates reasonable for operators with a few hundred miles of
pipeline. Costs for operators with only a few miles of pipeline in a limited number of locatio IS
will be lower.
Total Cost of Plans and Reports
There are 132 hazardous liquid pipeline operators who could potentially be subject to the
regulatory change. Some of these companies operate only a few miles of pipeline and may h; we
no pipeline that would affect a high consequence area. Such companies would not be subjecl to
the rule. Some companies included among these 132 are affiliated with other, larger, hazardc pus
liquid pipeline operators and their piping may be addressed in plans developed by those oper; itors
in response to a previously-issued rule. OPS does not yet know whether any operators have I LO
pipe that could affect a high consequence area nor does OPS know how many will be
encompassed in the plans of operators with greater than 500 miles of pipeline, and has
conservatively assumed that all 132 operators with less than 500 miles of pipeline will be
affected. Each of those operators will need to perform annual documentation and updates. 1 he
cost of these activities is conservatively estimated to be $1.32 million per year.
The Office of Pipeline Safety expects that virtually all of the operators with less than 500 mi es
of pipeline will not have existing plans and will need to develop plans in accordance with tht
rule (costing $75 thousand each). The total cost of those plans will be $9.9 million.
This cost will only be incurred once.
Based on the foregoing, the total cost for plans and reports will consist of a one-time cost of ~$9.6
million plus an annual cost of $1.32 million.'
The Costs of Testing
Baseline and periodic testing will be required by the regulatory change. That testing will be
accomplished by an appropriate combination of: (1) pressure testing, (2) internal inspection, and
(3) alternative testing and inspection methods. For the purposes of this analysis, it is assumz d
that all required testing will be accomplished by either (1) hydrostatic testing (pressure testirig) or
'This does not include cost incurred by the Federal government in setting up the review process (including
development of review protocols and training) and in the actual review of the plans and programs.
17

<<<PAGE 19>>>

0
(2) smart pigging (internal inspection). Alternative methods are not yet to the point where the ir
costs for pipeline testing can be reliably estimated. It is assumed that it will be sufficient to
perform either hydrostatic testing or smart pigging, and not both, in order ensure the integrity ‘of
any particular segment of pipeline.
Hydrostatic Testing
The total cost of hydrostatic testing has been previously estimated by the OPS to be $4,656 pc::r
mile in 1990 dollars,’ which equates to $5,777 per mile in 1998 dollars. This estimate includ.:s
the following costs:
0
Cost of performing the actual hydrostatic test
Cost of acquisition, transfer and disposal of test water
Loss of revenue due to the use of storage tanks for holding test water
Loss of pipeline tariff revenue due to pipe being out of service for testing
The estimate does not include the cost of making any repairs to the pipe. The 1990 estimate s
based primarily on information obtained by the OPS from various industry sources.
Smart Piaaing
The total cost of smart pigging has been previously estimated by the OPS to be $2,839 per mile
in 1992 dollars: which equates to $3,043 per mile in 1998 dollars. This estimate does not
include the cost of making a pipeline piggable (i.e., adding pig launchers and receivers or
modifying pipeline that cannot pass instrumented pigs).
Some hazardous liquid pipeline mileage is not currently piggable. Informal discussions with
pipeline operators indicate that 60 to 75 percent of hazardous liquid pipeline mileage of ope1,ators
with less than 500 miles of pipeline is piggable. (Most operators whose lines are not piggab’e
indicated that they rely on routine pressure testing to verify pipe integrity. This accounts for the
conclusion already stated that most pipe of operators with less than 500 miles of pipeline is
currently being tested). For the purposes of this analysis, it is assumed that 70 percent of all
impacted mileage is currently piggable.
’Office of Pipeline Safety, “49 CFR Part 195 Economic Evaluation, NPRM - Hydrostatic Testing of Certain
Hazardous Liquid and Carbon Dioxide Pipelines,” Docket No. PS-121, Notice 1, May 13, 1991.
’Office of Pipeline Safety, Instrumented internal inspection Devices (A Study Mandated by P.L. 100-.561), Re {earth
and Special Programs Administration, November 1992, p. C-2.
18

<<<PAGE 20>>>

The costs of making hazardous liquid pipeline piggable are presented in Exhibit 1. The origir a1
sources of the costs in Exhibit 1 were submissions by liquid pipeline operators to the U.S. DC T’s
Docket No. PS-105; Notice 1 .lo
Exhibit 1. Costs of Making Hazardous Liquid Pipeline Piggable
(1 992 dollars per mile)
Source: OPS, Instrumented Internal Inspection Devices, November 1992, p. 24.
Exhibit 2 presents estimated costs for making hazardous liquid pipeline piggable. These
estimates are the mid-points of the costs presented in Exhibit 1, converted from 1992 to 1998
dollars per mile.
Exhibit 2. Estimated Costs of Making Hazardous Liquid Pipeline Piggable
(1 998 dollars per mile)
Source: The mid-points of the ranges presented in Exhibit 1 in 1998 dollars.
Hydrostatic Testinn vs. Pinging
Informal discussions with pipeline operators suggest that, all other things being equal, piggirig is
much preferred to hydrostatic testing, at least in part because pigging can provide more valu;i.ble
information to operators than hydrostatic testing and because pigging is not destructive, while
hydrostatic testing can be. Consequently, it is assumed that pigging will be the testing methc id
used on all piggable pipeline mileage. Also, it is assumed that pipeline mileage that is not
currently piggable will not be made piggable because of the relatively high costs of doing so (see
Exhibit 2).
‘OOPS, Instrumented Intemal Inspection Devices, November 1992, p. B-2.
19

<<<PAGE 21>>>

Additional Mileage Must Be Tested
It is usually not possible to hydrostatically test or pig pipe in high consequence areas without , tlso
testing some adjacent piping. Hydrostatic testing requires valves that can isolate the pipe
segment being tested. Pigging must be run between available pig launchers and receivers, which
are seldom located immediately adjacent to the boundaries of high consequence areas. For
purposes of this analysis, OPS has estimated that the amount of additional piping that will necsd
to be tested in order to complete the required testing in high consequence areas is 25 percent uf
the amount of piping in the areas. The estimates of required testing above reflect the amount of
pipe that must be tested due to the requirements of the rule. The cost estimates which follow are
based on totals that are 1.25 times that mileage.
Cost of Baseline Testing
To meet the requirements for baseline testing, operators with less than 500 miles of pipeline ,will
need to test annually 78 miles of pipeline beyond that already planned over a seven year pericld
(see earlier discussion). It is expected that 70 percent of this mileage will be pigged, while the
other 30 percent will be hydrostatically tested, and that 25 percent additional piping will neec to
be tested. Operators with less than 500 miles of pipeline will incur an additional cost of
$377,000 annually (in 1998 dollars) to perform baseline testing.
Cost of Subsequent Testing
To meet the requirements for subsequent testing, operators with less than 500 miles of pipeli ie
will need to test annually 1,090 additional miles of pipeline during each of the first two years of
re-testing, and 110 additional miles of pipeline every year thereafter (see earlier discussion).
It is expected that 70 percent of this mileage will be pigged, while the other 30 percent will k e
hydrostatically tested, and that 25 percent additional piping will need to be tested. Operators
with less than 500 miles of pipeline will be expected to incur an additional cost of $5.26 mil ion
(in 1998 dollars) per year during each of the first two years of re-testing and $531,000 (in 19'98
dollars) per year during every year thereafter because of the requirement for subsequent testi ig.
This additional cost will not start being incurred until the sixth year after the effective date of the
final rule, the year in which the mileage baseline tested in the first year will need to be re-tested.
Total Cost of Testing
The total cost of testing will be the sum of the cost of baseline testing, $377 thousand per yeiu for
the first seven years, and the cost of subsequent testing, $5.2 million per year for years six and
seven and $53 1 thousand for years eight and on.
The Costs of Data Integration
20

<<<PAGE 22>>>

As described above, integration of all information relevant to the integrity of the pipeline is a key
element of the integrity management plans required for high consequence areas. Assuring thiis
integration will require that operator’s internal data management systems be aligned and
managed in such a way that relevant information is brought together. It will also require that ,the
importance of this information be assessed by experienced pipeline safety professionals.
Operators with less than 500 miles of pipeline are expected to develop integrity management
plans in response to this rule and will need to implement new actions to assure data integratic n.
These actions will need to include realignment of data management systems that will occur iri the
first year (concurrent with development of the integrity management plan) and continuing coi,ts
for assessment of the integrated data. OPS estimates that first year costs for the impacted
operators will be $50 thousand, and that continuing costs will be $25 thousand annually
thereafter.
As with the estimates for developing integrity management plans, OPS considers these estim ites
to be reasonable for operators with a few hundred miles of pipeline. Again, costs will be less for
operators with only a few miles of pipeline in a limited number of locations. OPS has
conservatively used these estimates in this analysis for all operators potentially subject to the
rule.
Total costs for data integration for the 132 operators that are expected to develop plans will be
$6.6 million in the first year and $3.3 million annually in following years.
The Cost of Remedial Action
Inspection and testing and integration of other relevant data will identify anomalies that mus be
investigated and remediated. OPS has no information on which to base assumptions regardi ig
the number of anomalies that will require action nor on the cost of that action. Costs associated
with remediation are therefore not estimated as part of this analysis.
The Costs of Enhanced Leak Detection
OPS understands that leak detection adequate for the purposes of this rule can be provided
through upgrades of Supervisory Control and Data Acquisition (SCADA) systems. Other
methods of leak detection are also used.
Based on informal discussions with an industry expert in leak detection, OPS estimates that ithe
software required to enhance SCADA systems for leak detection costs approximately $100,000
Approximately six man-months of effort, at a cost of $100,000 would be required to configt re
and test the system. An additional three man-months, or approximately $50,000 will be req iired
to link the SCADA data. Additional flow metering, if required, would cost an additional
$100,000 per location (required every 200 miles). Once installed, annual maintenance costs are
approximately $20,000 to $40,000 per year.
21

<<<PAGE 23>>>

OPS does not know how many operators with less than 500 miles of pipeline currently have
SCADA systems configured for leak detection or have other leak detection systems. OPS is
therefore unable to estimate the total costs for upgrading leak detection systems.
The Cost of EFRDs
EFRDs are pipeline valves specifically installed to help limit the loss of product when there h,as
been a break in a pipeline. Two kinds of EFRDs are considered by the Office of Pipeline Saf .:ty
to be effective: check valves and remotely controlled valves. A check valve is one that allou s
fluid to flow fieely in only one direction. A remotely controlled valve is a block valve that cz n
be opened and closed from a remote location. Generally, that location is the pipeline’s contrd
center. Because remotely controlled valves provide pipeline operators with greater control than
check valves, it is assumed that any EFRDs installed will be remotely controlled valves.
Estimated Costs
In 1994, the OPS issued an advanced notice of mlemaking (ANPRM) concerning EFRDs (se: 59
Federal Register, Jan. 19, 1994). That EFRD ANPRM requested information from the pipeliiie
industry concerning, among other things, the costs of EFRDs, specifically, remotely controllc d
valves. Eight usable responses were received by the docket from hazardous liquid pipeline
operators. Some of these responses provided separate information for multiple segments of
respondents’ pipeline systems. The responses to the EFRD ANPRM relating to cost are
summarized in Exhibits 3,4, and 5. The cost estimates in the exhibits are presumed to be gi1:en
in 1993 nominal dollars.
22

<<<PAGE 24>>>

EXHIBIT 3. COSTS FOR INSTALLING NEW RCVS AS REPORTED BY
RESPONDENTS TO THE EFRD ANPRM
Average
Minimum
Maximum
Valve Diameter (inches)
15
4
45
Cost of RCV
$96,500
$9,500
$231,000
Communication Cost
$7,400
$1,000
$20,000
Other Installation Costs
$9,300
$0
$50,000
Total Installation Cost'
$117,200|
$33,500|
$301,000
Source: Responses by pipeline operators to Question 11 in the EFRD ANPRM.
Notes:
1. The totals represent the values provided by the respondents to the EFRD ANPRM, not the
sums of the relevant cost categories in the table. Some respondents to the ANPRM did not
provide usable information for all cost categories.
•
23

<<<PAGE 25>>>

EXHIBIT 4 COSTS TO CONVERT MANUALLY OPERATED BLOCK VALVES TO
REMOTELY CONTROLLED VALVES AS REPORTED BY RESPONDENTS TO THE
EFRD ANPRM
Average
Minimum
Maximum
Valve Diameter (inches)
NA'
= -
45
Installation Cost
$51,100
$2,000
$89,6010
Communication Svstem Cost
$7.400
$278
$20.000
Other Installation Cost
$2,300
$0
$16,0C0
Total Installation Cost?
$60,600
$5,056
$103,6CQ
Source: Responses by pipeline operators to Question 10 in the EFRD ANPRM.
Notes:
1. An average value for the valve diameter could not be calculated because some respondents did not identify a
not the sums of the relevant cost categories in the table. Some respondents to the ANPRM did not provide usat le
information for all cost categories.
EXHIBIT 5. ANNUAL COSTS ASSOCIATED WITH REMOTELY CONTROLLED
VALVES THAT WERE REPORTED BY RESPONDENTS TO THE EFRD ANPRIV
Average
Minimum
Maximum
Valve Diameter (inches)
NA'
45
Annual Operating Cost
$1,500
$200
$4,000
Annual Maintenance Cost
$1,400
$500
$3,000
Other Annual Costs
$300
$0
$5,000
Total Annual Cost'
$3,400
$2,000
$49,500
Source: Responses by pipeline operators to Question 10 in the EFRD ANPRM. These reprrsent
the estimated annual costs associated with RCVs that were converted manually operated blo:k
valves.
Notes: See Exhibit 4.
24

<<<PAGE 26>>>

Exhibit 6 presents estimates for: (1) the costs of installing a new remotely controlled valve, (2)
the costs of converting a manual block valve into a remotely controlled valve, and (3) the ann la1
operating, maintenance, and other costs associated with a remotely controlled valve. Those
estimates are the totals from bottom of the “Average” columns in Exhibits 3,4, and 5, converted
to 1998 dollars and rounded to the nearest $100.
EXHIBIT 6. ESTIMATED EFRD COSTS
(1998 Constant Dollars)
Cost of Installing a New RCV
$1 24,000
Annual Cost of an RCV $3,500
Number of EFRDs Installed or Converted from Manually berated Block Valves
Valves (including EFRDs) on line pipe used in the transport of hazardous liquids have been
reported to be spaced an average of 13.6 miles apart.” This means that the 5,440 miles of
pipeline impacted by the regulatory change will have approximately 400 valves. About 84.1
percent of those valves are believed to be manually operated block valves.I2 This means that
approximately 336 are manually operated valves. OPS does not know how many EFRD’s w 11 be
installed and seeks comments from the public.
TOTAL COSTS
Costs have been estimated for: (1) plans and reports, (2) testing, (3) data integration, and (4) leak
detection and EFRDs. In Exhibit 7, those costs are totaled and presented by the year that the:y are
incurred after the effective date of the final rule.
“OPS, Emergency Flow Restricting Devices Study, April 1990.
‘‘OPS, Emergency Flow Restricting Devices Study, April 1990.
25

<<<PAGE 27>>>

EXHIBIT 7. THE ESTIMATED COST OF THE
REGULATORYCHANGE
(Costs in thousands of 1998 dollars)
Year
Integrity
Annual
after
Plans'
Reports'
Baseline
Subsequent
Data
EFRD*
Total
Testing
Testing
Integration+
Installation;
Cost
effective
Leak
date of
Detection
final rule
Upgrade
1
1
$9.940
$1.320
$377
$0
$6.600
$13.237
2
$0
$1.320
$377
$0
$3.300
$4.997
3
$0
$1.320
$377
$0
$3,300
$4,997
4
$0
$1,320
$377
$0
$3,300
$4,997
5
$0
$1,320
$377
$0
$3,300
$1,997
6
$0
$1,320
$377
$5,260
$3,300
$110257
7
$0
$1,320
$377
$5,260
$3,300
$10,257
8 - 20
$0
$1,320
$0
$531
$3.300
$5.151
*OPS did not estimate the number of EFRDs that would be installed. However OPS believes operators will only install EF RDs
where cost exceeds benefits. OPS also did not estimate the total cost for upgrading leak detection systems.
the earlier rule.
affiliated with larger operators and are encompassed within activities those companies have already implemented in respon e to
CONCLUSIONS
Issuance of this rule as a national standard will ensure that all operators will perform at least to a
baseline safety level and will contribute to an overall higher level of safety and environment;l
performance nationwide. It will lead to greater uniformity in how risk is evaluated and addrissed
and will provide more clarity in discussion by government, industry and the public about safety
and environmental concerns and how they can be resolved.
The flexibility of a performance-based approach provides several advantages. It encourages
development and use of new technologies. It is an important feature in supporting operators'
26

<<<PAGE 28>>>

development of more formal, structured risk evaluation programs and RSPA’s evaluation of
them. It also provides greater ability for operators to customize their long term maintenance
programs. It has also stimulated the development of a supplemental industry standard which v 4 l
be of assistance in implementation of this rule. A performance-based approach will also
encourage the development and maturing of risk-based approaches to integrity management.
Our emphasis on the integrity management system encourages a balanced program, addressin :;
the range of prevention and mitigation needs and avoiding reliance on any single tool or
overemphasis on any single cause of failure. This orientation will lead to addressing the mosl
significant risks, and is the best opportunity to improve industry performance and assure that he
high consequence areas get the protection they need. It also addresses the interrelationships
among failure causes and benefits. It promotes the coordination of risk control actions, beyorld
what a compliance-based approach would achieve.
The rule provides for a verification process, which gives the regulator a better opportunity to
influence the methods of assessment and the interpretation of results. This is not to say the
regulator would overstep the bounds of oversight, but would provide a beneficial challenge tcl the
adequacy of the operators’ decision process. This leads to greater accountability to the public.
This accountability is enhanced through our choice of a map-based approach to defining the i reas
most in need of additional protection - the visual depiction of the areas in need of protection
brings a focus on the safety and environmental issues in a manner that will be easily
understandable to everyone.
A particularly significant benefit is the quality of information that will be gathered as a result of
this rule to aid operators’ decisions about providing additional protections. Two essential
elements of the integrity management program are that an operator continually assess and
evaluate the pipeline’s integrity, and perform an analysis that integrates all available informal ion
about the pipeline’s integrity. The process of planning, assessment and evaluation will provi le
operators with better data on which to judge a pipeline’s condition and the location of potent a1
problems that must be addressed.
Integrating this data with the environmental and safety concerns associated with high
consequence areas will help prompt operators and the Federal and state governments to focui,,
time and resources on potential risks and consequences that require greater scrutiny and the rleed
for more intensive preventive and mitigation measures. If baseline and periodic assessment 1 lata
is not evaluated in the proper context, it is of little or no value. It is imperative that the
information an operator gathers is assessed in a systematic way as part of the operator’s ongcling
examination of all threats to the pipeline integrity. The rule is intended to accomplish that.
The cost estimates for testing in this evaluation reflect the fact that operators have begun tesi ing
programs and would be expected to continue those programs without this rule. The rule reqr [ires
specifically that piping that can affect high consequence areas be included in these testing
programs and that the rate of testing of such piping be accelerated. Costs for the required
acceleration have been estimated at $377,000 annually during the first five years, and are
27

<<<PAGE 29>>>

considered reasonable. Costs of leak detection upgrades and other preventive or mitigation
measures including EFRD installation and maintenance were not included because OPS did ni It
know how many operators would need to install these devices. However, the rule requires the se
devices only where they would be effective. OPS believes operators would only be required tl)
install EFRDS’s where their benefit is at least equal to the cost.
The costs of this rule increase in the sixth year because of the need to retest the lines. OPS mi’iy
in fact be overestimating the cost of the retest requirement as operators might have voluntarilj,
retested their lines in high consequence areas within the 6 year time-frame. The state of
California already requires hydrostatic testing every 5 years.
While OPS has not performed a quantitative benefit analysis of this rule OPS strongly believes
that this rule is indeed cost-beneficial. The cost for all hazardous liquid pipeline operators wi1.h
less than 500 miles of pipeline to develop plans is a modest $9.9 million with an additional $ .32
for annual updates. Total costs for data integration are estimated at $6.6 million for the first )‘ear,
during which company data systems must be adjusted, and $3.3 million annually thereafter. 1:ach
of these costs is conservatively bounded since OPS has assumed that all 132 pipeline operatoi s
potentially impacted by this rule will actually be affected at an “average” level. In fact, some of
these operators may have no pipeline that could affect high consequence areas and will thus n,ot
be impacted by the rule. Some of these operators may have only a few miles of pipeline and .,vi11
incur significantly less cost. Some of these operators may be encompassed within plans of la.ger
corporate affiliates and will therefore incur no additional costs.
OPS believes that the process of developing an integrity framework and schedule and integra ing
data related to pipeline integrity is an important process for the operator, the government and the
general public. The creation, and development of the plan will alert operators of the potential
risks and consequences unique to high consequence areas. The planning process, including t le
testing schedule, also provides a level of confidence to Federal and state pipeline inspectors that
pipeline operators are considering, examining, testing, and repairing if necessary, hazardous
liquid pipelines that potentially pose severe consequences to public safety and environmental
health. Finally, the public, which has indicated concems that “aging” hazardous liquid pipeli nes
pose to their neighborhoods, will be afforded an additional level of confidence. Additionally,
standardizing the requirements nationally for hazardous liquid pipeline will save operators
having to face potentially different testing and inspection requirements from the various state
pipeline agencies.
Finally, although OPS has not provided quantitative benefits for the retesting provision of th s
rule OPS does not believe that requiring retest of pipelines in high consequence areas on a
minimum schedule of once every five years will be an undue burden on hazardous liquid pipIAine
operators. Industry-wide costs for retesting are estimated to be $53 1 thousand per year ($5.2 6
million in years six and seven due to overlap of baseline testing and initial retesting). Total
damages from the recent PEPCO spill are estimated to range from $50 million to $75 million.
Preventing one such accident every few years would offset the cost of testing. Beyond the
28

<<<PAGE 30>>>

quantitative benefit, though, OPS believes the sense of security that this test gives the general
public is benefit enough to require this test every five years.
RESPONSE TO COMMENTS
Two of the comment letters submitted in response to the Notice of Proposed Rulemaking
addressed the draft Regulatory Evaluation: the Small Business Administration (SBA), and
Laclede Pipeline Company. The response to those comments is provided below.
The SBA objected to the lack of inclusion of equipment and maintenance costs, particularly f i3r
EFSDs and leak detection systems. As described above, and similarly described in the draft
Regulatory Evaluation, OPS did not estimate these costs because we do not know how many
operators will install such equipment. SBA suggested that costs could be estimated by
parametric analyses, varying the number of operators that will install the devices. (SBA mad:
additional comments related to the discussion of Regulatory Flexibility Act compliance. These
comments have been addressed in the Regulatory Flexibility Act discussion in the preamble (:If
the final rule.)
OPS does not believe it is practical to perform the parametric analyses suggested by SBA. A's
noted, we do not know how many operators will install leak detection systems or EFRDs. We
could make certain assumptions regarding the percentage of operators who will need to makc
changes, but that is only one variable. The number of devices that any individual operator might
need is also unknown. The cost to install EFRDs can vary significantly. It depends on the
circumstances of the individual pipeline, including its size, and on the locations in which the
installations must be made. Costs to install valves in areas unusually sensitive to environmei ita1
damage can be very large, and the environmental impact of such installations can, itself,
sometimes be prohibitive. Assumptions would need to be made regarding these variables as
well. In the end, we could produce an analysis that would include quantitative values, but W I :
could not have any confidence that those numbers would be representative of the actual situation
within the pipeline industry. As such, we believe they would obfuscate, rather than inform,
public decisionmaking.
Laclede Pipeline Company commented that the proposed rule was unreasonable, arbitrary, ai id
capricious. Their basis for this comment was threefold: 1) that 70 percent of their 28-mile limpid
propane pipeline cannot be assessed with internal inspection devices, that system design WOI ild
make de-watering after a hydrostatic test difficult, and that freezing of moisture remaining a ter
such a test could cause service interruptions, 2) the company has already installed emergency
shutdown valves at many of its pipeline valve locations that provide protection from rupture,;,
and 3) that implementation costs have been grossly underestimated. Laclede suggested that /.he
rule should exempt pipelines directly serving local distribution systems (natural gas) providtmd
that such pipelines are cathodically protected and satisfy OPS and DOT Safety Inspection
Standards. Laclede also suggested that operators who have installed extensive emergency flow
restricting or emergency shutdown devices should be exempted.
29

<<<PAGE 31>>>

OPS does not agree that blanket exceptions to the rule are appropriate. The particular
circumstances of individual pipelines differ. EFRD’s and ESDs, while valuable, do not prevent
pipeline leaks or ruptures. The specific number and location of EFRDs or ESDs is particularly
important in determining their effectiveness in mitigating potential pipe ruptures. The brief
description provided in Laclede’s comment does not allow OPS to conclude that periodic
assessment of the company’s pipeline to assure integrity is not needed. Laclede, and other
pipeline companies, can apply for a waiver based on particular pipeline design and
circumstances.
With respect to hydrotesting, OPS recognizes that such testing must be done with caution, ani I
that dewatering lines after a test is important. Hydrotesting is not new. The provisions alreacly
included in 49 CFR 5 195.302 require hydrotesting, including when pipe is replaced, relocate:$
or otherwise changed. Laclede’s comments indicate that portions of its pipeline have been
replaced. Hydrotesting would then have been required, and the same dewatering concerns wwld
have had to be addressed. OPS does not agree that requiring periodic assessment that may
require hydrotesting is unreasonable, arbitrary and capricious.
Laclede contends that the NPRM was wrong in that it estimated 50 percent of affected pipelii tes
can be pigged while 70 percent of Laclede’s cannot. This argument is simply not persuasive.
Thirty percent, a non-insignificant portion, of Laclede’s pipeline can be pigged. As Laclede
points out, its pipeline represents only a small portion of the pipeline affected by this rule
nationally.
The principal element of Laclede’s contention that the rule is unreasonable, arbitrary, and
capricious, however, rests with its contention that the costs of implementation have been gro ,;sly
underestimated. In this regard, the company has seriously misrepresented the situation. Lac1 ede
notes that OPS’s estimate of the cost for all affected operators is $9.64 million (revised to $9.94
million in this final regulatory evaluation due to an increase in the number of companies
potentially affected by the rule) whereas Laclede itself expects to incur costs in excess of $1
million to modify its pipeline. Laclede is comparing apples and oranges. Laclede’s estimated
costs are to replace piping that can not now be pigged. 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 hydrotesting which, as noted earlier, is an existing testing
method embodied in the regulations. Laclede’s replacement of piping to allow pigging, if
undertaken, would be an operational choice based on the company’s conclusion that pigging
would be a better method of assessment for their situation than hydrotesting. Companies arc:
certainly free to make such operational choices, but they are not required by the rule and c0sI.s
associated with pipe replacement are not, therefore, a cost for implementing the rule.
The Department of Energy (DOE) also submitted comments pertaining to the draft Regulatory
Evaluation. DOE expressed concern that costs associated with down time during inspections or
with permitting costs for conducting repairs may not have been included, and that per-mile
estimates may not be appropriate for operators with only a few miles of pipe. DOE also
suggested that future developments may make it difficult for operators to comply with the time
30

<<<PAGE 32>>>

requirements for conducting baseline assessments and periodic re-assessments, and having thc :m
reviewed. (DOE acknowledged that the proposed time frames for these activities appear
reasonable today). DOE also expressed concern that the requirements may have an unreason2 ble
impact on some small operators.
The values used to estimate costs for pigging and hydrostatic testing were based on detailed
studies of both methods, which considered all relevant costs. The outcome of those studies
which is used in the Regulatory Evaluation is, indeed, per-mile estimates for conducting thest’
assessments. OPS recognizes that costs may be higher for operators that only have a limited
amount of pipe, and for whom “fixed” costs associated with conducting the assessments musl be
amortized over the small length of pipe. OPS is unable to estimate how many operators may be
so affected. Many of the operators affected by this rule, however, are parts of larger companiizs,
as described further in response to Small Business Administration comments, and should not be
so affected. OPS will work with operators who may be unusually impacted, each of whom n- ay
request waivers as appropriate.
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 safe operation of a pipeline is
already required by 49 CFR 5 195.401. Repair is thus not a new requirement in this rule.
As to potential future problems in meeting the time requirements in the rule, OPS considers I hem
speculative. It is possible that new pipelines and increased demand for the expertise necessa y to
conduct assessments could result in problems, as suggested by DOE. It is equally plausible,
however, that this rule will foster increases in the resources available to operators for that
purpose. OPS concludes that changes to the required time frames are not appropriate at this time.
Problems that may arise in the fbture will be addressed at that time.
The Small Business Administration (SBA) also commented on possible impacts on small
businesses. As described in the discussion of Regulatory Flexibility Act considerations in thl?
preamble to the rule, OPS has considered such impacts. Many of the companies potentially
affected by this rule are affiliated with larger companies. Few meet the SBA criteria for sma I1
businesses (500 employees for hazardous liquid pipeline companies). OPS will work with a,iy
small operators who may experience unusual impacts, any of whom can apply for waivers.
31

<<<PAGE 33>>>

SELECTED BIBLIOGRAPHY
American Petroleum Institute, Analysis of DOT Reportable Incidents for Hazardous Liqulid
Pipelines, 1986 Through 1996, API Publication 1158, Washington, DC, January 7 ,
1999.
Helton, Douglas and Penn, Tony, Putting Response and Natural Damage Costs in Perspective,
1999 International Oil Spill Conference, Paper #114
Office of Management and Budget (OMB), Circular No. A-94, Revised (Transmittal Memo No.
64, October 29,1992), Appendix C (revised January 1999).
Office of Pipeline Safety, “49 CFR Part 195 Economic Evaluation, NPRM - Hydrostatic’
Testing of Certain Hazardous Liquid and Carbon Dioxide Pipelines,” Docket Nc.
PS-121; Notice 1, May 13,1991.
Office of Pipeline Safety, Emergency Flow Restricting Devices Study (A Study Mandated by
P.L. 100-561), OPS, Research and Special Programs Administration, Washingto 11,
DC, April 1990.
Office of Pipeline Safety, Instrumented Internal Inspection Devices (A Study Mandated b i v
P.L. 100-561), OPS, Research and Special Programs Administration, Washington,
DC, November 1992.
Office of Pipeline Safety, Office of Pipeline Safety User Fee Assessments, OPS, Washington,
DC.
32

## Provenance

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