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

- **operation:** document
- **citation:** 0900006480e8a8ce
- **title:** U.S. DOT/RSPA - Draft Final Regulatory Evaluation
- **source type:** rulemaking
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** current
- **official:** true
- **published on:** Not available
- **effective on:** Not available
- **summary:** U.S. Department of Transportation Research and Special Programs Administration Draft Final Regulatory Evaluation Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines) Docket RSPA-00-7666 Prescriptive requirements also would tend to stifle technological innovation. They do not allc w for different approaches based on advances in the technology. The technology associated wit1 i in- line inspection of pipelines (Le., pigging) is advancing at a rapid pace. Establishing prescriptive requirements could slow...
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U.S. Department of Transportation
Research and Special Programs Administration
Draft Final Regulatory Evaluation
Pipeline Integrity Management in High Consequence Areas
(Gas Transmission Pipelines)
Docket RSPA-00-7666

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INTRODUCTION
The U.S. Department of Transportation Research and Special Programs Office of Pipeline Sal ety
(OPS) is proposing to change pipeline safety regulations to require operators of certain pipelir es
to validate the integrity of their pipelines in high consequence areas. The rule would apply to
operators of natural and other gas transmission lines. The objective of the change is to reduce the
risk of pipeline incidents in these areas. The OPS defines a high consequence area as:
All class 3 & 4 locations. These are areas where there are at least 46 buildings intend€ d
for human occupancy or where buildings with four or more stories above ground are
prevalent within 660 feet of the pipeline along any continuous mile of its length. (Are i s
within class 3 & 4 locations but outside of the “potential impact zone”, as defined in tl le
proposed rule, are considered medium consequence areas).
Locations where any hospital, school or other facility having persons who are confineci or
of limited mobility are in a circular impact zone having radius equal to a “threshold
radius” defined based on the diameter and operating pressure of the pipeline.
Locations where 20 or more persons congregate at least 50 days in any 12-month peric d
are in this circular impact zone (pipeline within 100 yards of such locations is conside .ed
class 3 under the current definition in 49 CFR 192.5).
Locations where the radius of the circular impact zone exceeds 660 feet and where an!
circle of 1000 ft. radius (or larger for some large-diameter, high-pressure pipelines)
centered on the pipeline includes 20 or more buildings intended for human occupancy
The 20 building limit within a 1000 ft. radius circle has been established to ensure the
same building density as in Class 3 Locations (see above).
To validate the integrity of their pipelines in high consequence areas under the regulatory chai ige,
pipeline operators must implement an integrity management program for such pipelines incluc ling
periodic inspection and testing and integration of information related to pipeline integrity. Th 2
purpose of this report is to assess the benefits and costs of the proposed regulatory change.
This rule is similar to rules promulgated earlier for hazardous liquid pipeline operators. High
consequence areas were defined differently for hazardous liquid pipelines, because the
environmental consequences of leaks from hazardous liquid pipelines are different than those
from natural gas pipelines. The elements of an integrity management program proposed to be
required by this rule are similar, however, to the elements previously required of hazardous lic pid
pipeline operators. This report considers the costs and benefits of these proposed requirement s in
a manner similar to the analysis of costs and benefits prepared for the earlier rulemakings.
TARGET PROBLEM
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Natural and other gas pipeline breaks can result in explosions and fires that can impact on hur ian
health and safety. The magnitude of this impact differs. There are some areas in which the
impact of a pipe break will be more significant than it would be in others due to concentrations of
people near the pipeline and who thus could be affected. Because of the potential for dire
consequences of pipeline failures in certain areas, these areas merit a higher level of protectioi 1.
The OPS is promulgating this regulation to afford the necessary additional protection to these
“high consequence areas”.
Numerous investigations by the OPS and the National Transportation Safety Board (NTSB) h we
highlighted the importance of protecting the public from pipeline failures. The NTSB has ma le
several recommendations to ensure the integrity of pipelines near populated areas. These
recommendations included requiring periodic testing and inspection to identify corrosion and
other damage, establishing criteria to determine appropriate intervals for inspections and tests and
determining hazards to public safety from electric resistance welded pipe.
Congress also directed the OPS to undertake additional safety measures in areas that are densc.1~
populated. These statutory requirements included having the OPS prescribe standards for
identifying pipelines in high density population areas and issue standards requiring periodic
inspections using internal inspection devices on pipelines in densely-populated areas.
This rulemaking addresses the target problem described above, and is a comprehensive response
to the NTSB’s recommendations and Congressional mandates, as well as pipeline safety and
environmental issues raised over the years.
ALTERNATIVES CONSIDERED
The OPS considered several alternatives to provide the necessary increased level of protectior to
high consequence areas. These alternatives were:
1. No action.
2. Prescriptive requirements for inspection and repair of pipelines in high consequence areas.
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 I isk.
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. They perform inspectic n
and testing on their pipelines to assess their integrity, and make repairs as they conclude they ire
needed. These actions would be expected to continue under the “no action” alternative.
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Pipeline leaks and ruptures occur, despite the existence of these operator programs. Major
pipeline accidents have occurred in recent years, of which two were particularly notable, at Ec ison
Township, NJ and Carlsbad, NM. In the first case, in-line inspection (pigging) of the pipeline had
taken place. The operator either failed to identify, during the pig runs, the areas of damage th, it
eventually caused the rupture or the damage occurred in the years following the inspection. It
addition, the operator failed to integrate information about the pipeline, including the presencc of
significant construction activity in the area, in a continuing assessment of the line’s integrity, In
the latter case, the accident resulted from internal corrosion due to collection of moisture in a ow
spot which could not be inspected by pigging. The operator failed to consider the possibility ,f
such accumulation of moisture and resulting corrosion and thus did not intercede to prevent tl e
pipeline failure. An integrity management program involving integration of all safety-signifil :ant
information about the pipeline could have prevented both of these accidents. The OPS conch des
that validation of operator’s integrity management programs through audit and review by outs ide
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. In the absence of requirements, pipeline operators might choose to curtail or
eliminate some or all inspection and testing.
The OPS concludes that assuring continuation of pipeline integrity management programs,
assuring that their scope encompasses all areas requiring special protection, and verifying thei r
adequacy 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 prob ’ em.
In addition, continued reliance on voluntary industry efforts would not be responsive to the
Congressional mandate that the OPS promulgate requirements to assure protection of the area ;
that 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 ind
for incorporating accident mitigative features.
Pipeline circumstances differ, even within high consequence areas. These differences would
make it difficult, at best, to establish prescriptive requirements that would appropriately addre ss
all possible combinations of pipeline size, type, and configuration or to consider other factors 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 ai id
government resources to establish requirements in this fashion. Compliance inspection woulci
still require that the requirements applicable to specific pipelines be identified for comparison
with ongoing practices.
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Prescriptive requirements also would tend to stifle technological innovation. They do not allc w
for different approaches based on advances in the technology. The technology associated wit1 i in-
line inspection of pipelines (Le., pigging) is advancing at a rapid pace. Establishing prescriptive
requirements could slow this advancement, or could preclude use of new techniques that may be
developed. In the extreme, prescriptive requirements could stop technological innovation in t lis
area completely.
Most importantly, however, establishing prescriptive requirements would not assure the
integration of information which experience has shown is vital to preventing pipeline acciden s.
As noted above, two major accidents have occurred in recent years despite the fact that
information about the causative factors should have, or could have, been known. It appears t k at
information was available that, if correlated to current pig results (in the case of Edison
Township) or other information about the pipeline, could have highlighted the need for action
regarding the problems that ultimately resulted in failure of the pipe. An integrity managemei it
program is required to assure this integration of available information. Outside review of the
integrity management program by regulators (Federal and state), is necessary to assure that it 1 s
complete and properly implemented. This outside review cannot be assured without a
requirement for such a program.
For these reasons, the option of establishing prescriptive requirements was not evaluated furtf er
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.
Pipeline operators are uniquely qualified to develop integrity management programs and prov de
for the necessary integration of information. They have the best knowledge of their pipelines md
the factors affecting its risk. Integration of information requires that the management systems of
the company be aligned and operated to assure that necessary information is shared and that it is
evaluated in its proper context by knowledgeable personnel. These are actions that are difficu It to
require through prescriptive regulation. Requiring that operators develop such programs is th ;
best way to assure that they exist. Such a requirement also provides the regulatory basis for tl e
OPS and states to audit, review, and assess these programs and their implementation.
The best integrity management plans, when implemented properly, can reduce the risk of pipe line
accidents. They cannot, however, eliminate that risk. Leaks and ruptures could still occur, frc im
unforeseen outside impacts on the pipeline or from unanticipated interactions among factors
contributing to pipeline risk. It is therefore important that features and procedures be availablt: to
mitigate the effects of accidents that may occur.
Here again, circumstances differ between pipelines and between regions and local jurisdiction s.
The differences make it difficult to establish prescriptive requirements that will provide the bt st
protection for each high consequence area. Requiring that operators explicitly consider the nc ed
for mitigative features and provisions and that they implement those found necessary is the m 1st
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effective means of providing such protection. Such a requirement also provides the regulator
basis for audit and review by OPS and state regulators.
For these reasons, this option was selected for hrther development.
4. Requiring pipeline operators to develop integrity management programs providing for
expedited inspection and retesting.
The OPS considered the need for requiring integrity management programs that would requirt
inspection and testing of pipelines to recur over short intervals, a few years. The ability to rec uire
frequent testing is limited by the available resources for testing and inspection.
The companion rule covering hazardous liquid pipelines requires reassessments at least every five
years, with limited exceptions. The current capacity to perform pipeline inspections will be
challenged by this required schedule. The OPS concluded that the spur provided by the reguli ltion
would be likely to result in an increase in testing capacity over the next five years that will then be
able to accommodate testing at accelerated rates. The OPS also concluded that protection fro1 n
environmental damage that can be caused by a leak or rupture of a hazardous liquid pipeline
necessitated such frequent inspection. Adding requirements for similarly frequent inspection i f
natural gas pipelines would complicate the existing testing capacity issue and likely make it
difficult for any of the testing requirements to be met.
Existing regulations already provide some additional protection from accidents on gas
transmission pipelines, that could affect high consequence areas. The requirements of 49 CFR
192.61 1 specify that pipelines in class 3 or 4 areas must operate at pressures that produce
significantly lower hoop stresses in the pipe than is allowed in more rural areas. As a practica 1
matter, operators meet this requirement by reducing operating pressure or using heavier-walle 1
pipe in class 3 and 4 areas. Hazardous liquid pipelines do not afford similar protection in higl L
consequence areas. The additional protection already provided by natural gas transmission
pipelines justifies assessment on a more extended interval than for hazardous liquid pipelines,
Additionally, the natural gas pipeline network supplies gas for use in real time. This is not thc
case for hazardous liquid pipelines, which move product in batches and have significant stora ;e
capacity. Assessment of natural gas pipelines can therefore result in interruptions of gas supp y.
This can have a safety impact, in addition to its economic effect, due to the need to restart gas
service in a controlled manner so as to avoid explosions at the point of service. The likelihoo 1 of
service interruptions, with attendant costs and safety concerns, increases as the assessment
interval is shortened, since operators have less flexibility to conduct assessments at times when
demand is lower.
Finally, significant environmental damage is not expected to result from failure of a natural gas
pipeline, unlike hazardous liquid pipelines, since gas is lighter than air and dissipates in the
atmosphere.
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The Pipeline Safety Improvement Act of 2002 requires assessments on no greater than 7-year
intervals. The OPS has established requirements in this proposed rule that would provide for a
more focused assessment on this shorter interval. The OPS evaluated the effect on costs to
operators of requiring full assessments at increased intervals, as described later in this analysi, ;.
Costs would increase significantly without addition of commensurate benefits.
For these reasons, the OPS concluded that assessment of natural gas pipelines need not be
required as frequently as for hazardous liquid pipelines.
BASELINE REGULATORY ENVIRONMENT
In order to assess the costs and benefits of the new regulation, it is necessary first to 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, and the prevalence and
nature of integrity management plans similar to those required by the rule.
The OPS has interacted with gas pipeline operators in recent years as part of development of: n
integrity management standard by the American Society of Mechanical Engineers (ASME). 'I 'he
standard includes many of the elements of the proposed rule, and has been adopted as a conselisus
standard. As a result of these interactions, the OPS understands that many gas pipeline operators
currently have integrity management programs including many aspects that would be required by
this proposed regulation.
These current integrity management programs include inspection of their pipelines by some
operators. The amount of such inspection is relatively low, however. Much of the testing beilig
conducted by these operators is the initial inspection of pipelines. The rate at which subseque nt
inspections would be performed is now unknown. It is likely that some pipeline would be
identified for reinspection routinely (e.g., every ten years). It is equally likely that some pipe1 ne
would not be reinspected at all.
Integrity management plans are a key element of this rule. To better understand and promote
more comprehensive and integrated approaches to safety and environmental protection, the 0 i'S
created the Risk Management Demonstration Program, and the System Integrity Inspection Pi lot
Program. These programs encourage and evaluate operator-developed safety and environmen tal
management processes that incorporate operator- and pipeline-specific information and data tl
identify, assess, and address pipeline risks. These programs are helping RSPA's Office of
Pipeline Safety refine its regulatory oversight processes. These processes help to ensure that
pipeline operators have 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 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 fai lure
could have significant consequences.
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Through the Risk Management Demonstration Program and the System Integrity Inspection Pilot
Program, the OPS has improved its understanding of pipeline operator integrity management
systems and activities. This experience has shown that a number of pipeline operators have
formalized management systems to identify and address the most significant integrity threats 1 o
their pipeline systems. In the Risk Management Program, participants perform systematic an( 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 risk assessmer ts is
the integration of information from many diverse sources to fully understand the integrity t h e ats
at specific locations on the pipeline. The impact on nearby population is explicitly considerer in
these risk assessments. Through formal, risk-based decision making processes, these compan ies
use the risk assessment results to identify projects and activities that address potential system
integrity threats, thereby preventing leaks and accidents. These investigative risk managemen t
programs, and the preventive and mitigative risk control activities that evolve from them,
supplement the minimum regulatory requirements established in 49 CFR 192.
The System Integrity Inspection Program is focused on developing a more integrity-based
approach to OPS inspections. Instead of using a “checklist” approach, the OPS is focusing th :
inspection process on an operator’s integrity management processes and activities. Through
working with the operator, the OPS is able to understand and influence the methods and
approaches used to assess pipeline integrity, and the approaches to integrating integrity assess nent
data with other pipeline specific information to identify the most significant integrity threats t I the
system. Specifically, the OPS has observed how operators examine internal inspection data i t
conjunction with other surveillance and operating data, expected population growth, land use,
construction activity along the pipeline, and other information relevant to assuring the integrity of
the pipeline in high population areas and in environmentally sensitive areas. Through this
interaction the OPS is acquiring a broader understanding and a greater confidence that effectii’e
programs are in place to address the most significant risks. Similar to the Risk Management
Program, the SII Program is emphasizing how operators evaluate their system condition and i s
risks, and use this information to make sound integrity management decisions.
The OPS experience in the Risk Management Demonstration Program and the System Integri y
Inspection Program indicates that integrity management programs such as that required by thi ;
rule have been developed. They are far from universal, however.
REVIEW BY TECHNICAL PIPELINE SAFETY STANDARDS COMMITTEE
The OPS presented a preliminary draft of this regulatory analysis to the Technical Pipeline Sa fety
Standards Committee (TPSSC) at a public meeting on July 18, 2002. TPSSC is a Federal
advisory committee charged with responsibility for advising on the technical feasibility,
reasonableness, cost-effectiveness, and practicability of gas pipeline safety standards. The TF SSC
provided extensive comments on the preliminary draft regulatory analysis, which have been
considered in developing this draft version.
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Of greatest significance were comments indicating that the natural gas pipeline industry intent Is to
implement this proposed rule, if finalized, by a preponderance of in-line inspection. As descr bed
later in this analysis, the OPS presumed that some pipelines that can be modified easily to
accommodate in-line inspection devices would be so modified, but presumed that no pipe tha
would require significant modification costs would be pigged. Industry members of the TPSS C
reported, instead, that much “hard-to-pig” pipe would be modified and that pigging would be Jsed
as the assessment method of choice. This represents an industry conclusion that pigging is thc ;
most cost-effective means of conducting assessments, even if significant up-front capital cost:, are
required to modify existing pipelines. At the same time, the industry members of TPSSC repc n-ted
that reliance on hydrostatic testing would be significantly less than the OPS had estimated in 1 he
preliminary draft analysis. High costs, environmental issues associated with disposing of wat :r
used for hydrostatic tests, and operational difficulties that could result from watedmoisture le t in
pipelines after assessments all contribute to the relative undesirability of this assessment metl- od.
This draft analysis has been revised to reflect these relative industry priorities. With respect tl) the
intent to modify hard-to-pig piping, this is presented herein as an alternative. For reasons
described below, the OPS still has some doubt that significant amounts of hard-to-pig pipe wi 11 be
modified.
The TPSSC also commented that the OPS had underestimated the costs associated with the
proposed rule. In particular, estimates for programmatic costs (i.e., those associated with
developing integrity management programs and implementing related information analysis) v, ere
noted to be low, industry’s estimate of the cost of hydrostatic testing - particularly in urbanizc d
areas where natural gas distribution companies operate - was much higher than that used by tl Le
OPS, and the amount of additional mileage that must be pigged (since pig launchers and receivers
are not generally located on the boundaries of high consequence areas) was noted to be
significantly underestimated.
The OPS has limited data regarding current costs for developing integrity management programs.
The cost ranges used in the preliminary draft analysis were based on a survey conducted sevei a1
years ago. Interactions with hazardous liquid pipeline operators, who are developing integritj
management programs in response to similar rules promulgated earlier, indicate that these ran zes
likely do underestimate actual costs. The OPS had increased the costs assumed for programrr atic
activities, above those used in the analysis of the hazardous liquid rules, but the TPSSC
commented that the increases were not enough. The OPS has further increased the cost estim ites
for these activities in this draft analysis, as described below.
The per-mile cost estimate for hydrostatic testing used in the preliminary draft regulatory analysis,
and in this analysis, is based on a 1990 study. It is possible that costs for such testing have
increased over the last twelve years by more than the rate of inflation. Little hydrostatic testir g
has been performed in recent years, particularly in urbanized areas. The OPS has no more rec mt
data on what the costs of such testing would be, and has not changed the per-mile cost estimai es
used in this analysis. As described above, however, industry’s belief that the costs and diffia lties
associated with hydrostatic testing will be significant has much reduced the relative important e
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expected to be placed on this assessment method. The OPS has revised downward its assumr tion
of how much mileage will be subjected to hydrostatic testing, making any disagreement in thc per-
mile cost relatively less important.
The OPS was persuaded by TPSSC discussion that the amount of mileage that must be piggeci in
order to assess mileage that can affect high consequence areas was underestimated in the
preliminary draft analysis. That analysis estimated an additional 25 percent of pipeline mileal ;e
would be pigged (i.e., the total pigged would be 1.25 times the high consequence area mileagt ).
This is the same additional percentage assumed in the analyses supporting similar rules for
hazardous liquid pipelines and was used for both pigging and hydrostatic testing. Industry
representatives on the TPSSC used a similar assumption for additional mileage for hydrostatic
testing. They reported, however, that launchers and receivers for in-line inspection devices ar 2
spaced much farther apart than valves that will be used for hydrostatic testing. They estimate( I
that the additional mileage that will be pigged will be up to several hundred percent of the mileage
that can affect high consequence areas. The OPS has reflected these comments in this analysi; by
assuming that 200 percent additional mileage will require pigging in order to assess the milea ;e
that can affect high consequence areas and which will be assessed using in-line inspection.
Finally, it is significant to note that the TPSSC supported proceeding with this proposed rule
despite the significant comments made concerning the regulatory analysis. The committee, a~ d
public representatives of the pipeline industry that made presentations at the public meeting,
expressed the belief that the benefit associated with improved public confidence in pipeline s; fety
justifies the costs associated with the proposed rule. The TPSSC unanimously adopted a mot on
finding that the draft cost-benefit analysis supports the concepts for a proposed standard for
integrity management programs for gas transmission pipelines'.
PIPELINE SAFETY IMPROVEMENT ACT OF 2002
The Congress passed the Pipeline Safety Improvement Act of 2002 subsequent to the public
meeting with the TPSSC. The Act requires that natural gas pipeline operators implement inte gity
management plans, and that the Department of Transportation promulgate regulations govem ng
these plans. The Act specifies, however, that assessments of pipelines covered by operator
integrity management plans must occur at no greater than seven (7) year intervals. This
periodicity is greater than considered in the analysis discussed with the TPSSC.
The OPS has revised the proposed rule, and this analysis, to be responsive to the assessment
periodicity requirements in the Act. For reasons described above, under Alternatives Conside red,
and as described in the appendix to this analysis, the OPS concluded that requiring assessmen1.s
using traditional methods at intervals of seven years or less was not necessary. The OPS has,
instead, included in the proposed rule a more-focused application of direct assessment. The
'TPSSC meeting transcript, July 18,2002, RSPA-1998-4470-68
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proposed rule would require that assessments using pressure testing, in-line inspections, direct
assessment, or an equivalent technology be used at intervals of five, ten, or fifteen years
(depending on factors to be described later in this analysis), as considered in the analysis
discussed with the TPSSC. The proposed rule further requires that operators assure that an
assessment, using one of these methods or the more-focused method described in the rule, are
used at least every seven years. This analysis has been revised, from the version discussed wit n
the TPSSC, to reflect this additional method and requirements.
SCOPE AND PARAMETERS OF ANALYSIS
This analysis of benefits and costs takes the following approach. First, the mileage impacted by
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 discussio 1 of
the costs versus the benefits is presented. It should be noted that, unless otherwise specified, i 11
dollar values in this report are given in constant 2001 dollars.* Furthermore, this analysis will
arbitrarily consider only the first twenty years after the effective date of the final rule. Includir Lg
additional years would not be expected to materially affect the conclusions of this analysis.
ANALYSIS
Impacted Mileage
In this section the total pipeline mileage impacted by the regulatory change is estimated. That
mileage is located in or nearby high consequence areas, defined by the change as areas in which
defined numbers of people are expected to be within specified distances of the pipeline. The
distances vary depending on the diameter of the pipe and the pressure at which it operates.
Total Pipeline Mileage
In total, there is an estimated 292 thousand miles of regulated natural gas transmission pipelinzs in
the U.S.3 This rule would not apply to all of this mileage. The proposed rule does not apply tl)
pipelines operated at a hoop stress of less than 20 percent of specified minimum yield strengtk
(SMYS). The OPS has no data on how much transmission pipeline mileage is operated at the ;e
low stresses, but presumes that it is small. The rule also applies to transmission pipelines for
hydrogen, synthetic gas and other products subject to 49 CFR Part 192 that are not included ir the
natural gas transmission pipeline totals. Here, again, the OPS does not have data on the total
transmission mileage for these other gases. This analysis uses the available natural gas
'Dollars are converted from nominal values to real 2001 values using the Producer Price Index (PPI), Intermedi, ite
Materials, Supplies, and Components. The source of the PPI index numbers is the U.S. Bureau of Statistics We11
page.
'Jurisdictional natural gas transmission pipeline mileage (onshore) for 2000. This mileage was obtained from annua I
reports filed by pipeline operators with the Office of Pipeline Safewata available on the OPS web page.
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transmission pipeline total mileage, which is considered to be very close to the total pipeline
mileage potentially affected by the proposed regulation.
Impacted Mileage in High Consequence Areas
The proposed regulatory change does not apply to all of this pipeline. Instead, it applies to thi I t
transmission pipeline that can affect high consequence areas, as described earlier. A principa
element of this definition is pipeline that is in class 3 and 4 areas as defined in 49 CFR 192.5.
Pipeline operators are presently required to maintain data on the population near their pipelint in
order to determine pipeline that is in class 3 or class 4 areas. Historically, this data has not be :n
required to be submitted to the OPS. Reporting of mileage by class was required for the first ime
as part of the 2001 annual reports from gas transmission pipeline operators. At the time this
analysis was prepared, a total of 2 8 3 18 miles had been reported in those reports as class 3 or 4.
Analysis of the 2001 reports was not complete, however. Only approximately 256,000 on-shc Ire
miles of natural gas transmission pipeline had been reported. For purposes of this analysis, th 2
OPS presumes that the total amount of on-shore natural gas transmission mileage did not deci ease
significantly between 2000 and 2001 and that the percentage of class 3 and 4 mileage in the a! -yet
unreported 36,000 miles is the same as that in the 256,000 miles reported. This results in a
conclusion that an additional 4,010 miles of pipeline exists in class 3 and 4 areas, for a total o
32,528 miles.
There are several factors in the definition of high consequence areas which could lead to
additional mileage being included. These include:
e
e
. the requirement to consider the location of buildings that could house populations of
limited mobility,
the requirement to consider areas near pipelines where people congregate, and
the requirement to expand the radius of consideration to 1000 feet (or possibly more) for
pipelines larger than 30 inches in diameter and operating at pressures greater than 101 10
psig or where calculations of potential impact radius indicate a likelihood that areas
beyond 660 feet from the pipeline would be affected by an accident.
The OPS cannot know with certainty how much additional mileage that can affect high
consequence areas will be added by these criteria. The definition of piping that can affect hig I
consequence areas for natural gas transmission pipelines is only now being finalized. Provisic ms
of this proposed rule add additional factors that further refine the definition. Pipeline operato 's
are not required presently to collect data related to these additional factors, and the OPS has n
independent source of such information. For purposes of this analysis, the OPS assumes that
these additional factors would increase the total transmission pipeline mileage affected by the rule
by 30 percent, or 9,758 miles. The OPS seeks comments on the reasonableness of this
assumption.
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The OPS would like operators to apply the definition of high consequence areas and submit
comments indicating how much additional mileage (Le., beyond that in classes 3 and 4) is
identified. The OPS also would like to receive information regarding how this mileage is
distributed. The OPS expects that mileage in urbanized areas, whether classes 3 or 4 or inclul led
as a result of one of the other criterion, will be reasonably concentrated, with a significant por ;ion
of any piggable segment (Le., launcher to receiver) so identified. At the same time, the OPS
expects that piping in rural areas that meets the definition as piping that can affect high
consequence areas (e.g., due to the proximity of areas where people congregate) will be much
more distributed. In rural locations, such areas may constitute only a few miles of a piggable
segment. The distribution of these areas may affect decisions regarding the method of assess1 lent
operators will use, as discussed below.
The total gas transmission pipeline mileage in high consequence areas is thus 42,286 miles, tl e
sum of the amount estimated to be in class 3 and 4 areas and the amount assumed to be added as a
result of other factors in the definition of high consequence areas.
The state of Texas has already promulgated a regulation requiring assessment of intrastate nat xal
gas transmission pipelines within the state. The provisions of the Texas rule require assessmc nt at
intervals that are more frequent than those in this proposed rule. As a result, this proposed ru e
will not impose additional assessment requirements on Texas intrastate natural gas transmissi In
lines, and the total mileage of such pipeline must be subtracted from the national total to
determine the mileage affected by this proposed rule. The Texas Railroad Commission repon s
that there are 37,5 10 miles of intrastate natural gas transmission pipeline within Texas4 The 'IPS
assumes that the percentage of this mileage in high consequence areas is the same as the
percentage of total U.S. transmission pipeline mileage that is affected. The Texas mileage th; t
must be subtracted therefore amounts to 5,432 miles.
The total gas transmission pipeline mileage in high consequence areas that is considered in th s
analysis to be affected by this proposed rule is thus 36,854 miles.
BENEFITS
The benefits resulting from the proposed regulatory change are discussed in this section. Tho ;e
benefits are expected to result from detection of problems that could cause pipeline failures bc :fore
the failure occurs, thereby averting accidents. The inspection and assessment that would be
required by the proposed rule is designed to detect problems related to internal corrosion, extc mal
corrosion, stress corrosion cracking and external damage to the pipeline, all of which can resu It in
pipeline ruptures. Natural gas pipeline accidents usually involve explosions and fire and can
result in death, serious injury, and property damage. Preventing accidents will result in reduced
numbers of deaths and serious injuries and in reduced property damage. These reductions, thc :n,
are principal benefits of the proposed rule. The proposed rule will also provide improved
4Data from Texas Railroad Commission web site, http:/lwww.rrc.state.tx.us/divisions/gslsmiles-html.
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assurance of pipeline safety, will provide a basis for increased public acceptance of the risks f -om
natural gas transmission pipelines, and will provide other, less tangible, benefits. Each of the, ;e
categories of benefits is discussed below.
Pipeline operators also have strong incentives to ensure the integrity of their pipelines. In add ition
to the positive safety and societal benefits, the lost product and unscheduled downtime for rep airs
following a major incident can significantly impact the company’s financial performance and its
ability to satisfy customer commitments. Operators cannot afford to have these critical
transportation assets out of service for lengthy periods of time in today’s competitive busines:
environment. In addition, the damage to the company’s public image and reputation, as well I is
the legal implications of serious incidents, can pose an even broader and longer term negative
impact on the company’s business operations. For these and other reasons, many pipeline
operators have implemented and are continuing to improve more systematic safety and
environmental management processes, many of which already embody the principles in this
proposed rule.
Benefits from reduced death and serious inju$
Accident reports submitted to the OPS during the period 1986 to 2001 (this period was chose] I
because this data is publicly available on the OPS website) identify that there were 1,285
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