# U.S. DOT/RSPA - Draft Final Regulatory Evaluation- Pipeline Integrity Management in High Consequence Areas (Gas Transmission Operators)

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- **citation:** 0900006480e8d47b
- **title:** U.S. DOT/RSPA - Draft Final Regulatory Evaluation- Pipeline Integrity Management in High Consequence Areas (Gas Transmission Operators)
- **source type:** rulemaking
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** current
- **official:** true
- **published on:** Not available
- **effective on:** Not available
- **summary:** DRAFT 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 c for different approaches based on advances in the technology. The technology associated with 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 techniques that may be developed. In the extreme,...
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DRAFT
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
c

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INTRODUCTION
The U.S. Department of Transportation Research and Special Programs Office of Pipeline Safety
(OPS) is proposing to change pipeline safety regulations to require operators of certain pipelines
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:
0 All class 3 & 4 locations. These are areas where there are at least 46 buildings intended
for human occupancy or any buildings with four or more stories above ground within 660
feet of the pipeline along any continuous mile of its length.
0 Locations where any hospital, school or other facility having persons who are confined 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.
0 Locations where 20 or more persons congregate at least 50 days in any 12-month period
are in this circular impact zone
0 Locations where the radius of the circular impact zone exceeds 660 feet and where any
circle of 1000 A. 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 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 change,
pipeline operators must implement an integrity management program for such 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 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 liquid
pipeline operators. This report considers the costs and benefits of these proposed requirements in
a manner similar to the analysis of costs and benefits prepared for the earlier rulemakings.
TARGET PROBLEM
Natural and other gas pipeline breaks can result in explosions and fires that can impact on human
health and safety. The magnitude of this impact differs. There are some areas in which the
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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 protection.
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) have
highlighted the importance of protecting the public from pipeline failures. The NTSB has made
several recommendations to ensure the integrity of pipelines near populated areas. These
recommendations included requiring periodic testing and inspection to identi@ corrosion and
other damage, establishing criteria to determine appropriate intervals for inspections and tests, and
determining hazards to public safety &om electric resistance welded pipe.
Congress also directed the OPS to undertake additional safety measures in areas that are densely
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 protection to
high consequence areas. These altematives were:
-
_ _ __ --------____ppp--___p p~
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 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. 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” alternative.
Pipeline leaks and ruptures occur, despite the existence of these operator programs. Major
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pipeline accidents have occurred in recent years, of which two were particularly notable, at Edison
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 that
eventually caused the rupture or the damage occurred in the years following the inspection. In
addition, the operator failed to integrate information about the pipeline, including the presence of
significant construction activity in the area, in a continuing assessment of the line’s integrity. In
the latter case, the accident resulted fiom internal corrosion due to collection of moisture in a low
spot which could not be inspected by pigging. The operator failed to consider the possibility of
such accumulation of moisture and resulting corrosion and thus did not intercede to prevent the
pipeline failure. An integrity management program involving integration of all safetpsignificant
information about the pipeline could have prevented both of these accidents. The OPS concludes
that validation of operator’s integrity management programs through audit and review by outside
parties, Le, 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 their
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 problem.
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 areas
that are herein designated as high consequence areas.
For these reasons, the “no action” alternative was not considered M e r . ~-
2. Prescriptive requirements for inspection and repair of pipelines in high consequence areas and
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 address
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 and
government resources to establish requirements in this fashion. Compliance inspection would
still require that the requirements applicable to specific pipelines be identified for comparison
with ongoing practices.
Prescriptive requirements also would tend to stifle technological innovation. They do not allow
3
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for different approaches based on advances in the technology. The technology associated with 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 techniques 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 accidents.
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 that
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 management
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 is
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 further.
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 risk.
Pipeline operators are uniquely qualified to develop integrity management programs and provide
for the necessary integration of information. They have the best knowledge of their pipelines and
the factors affecting its risk. Integration of idormation requires that the management systems of
the company be aligned and operated to assure that necessary information is shared and that it is
- __ ---evaluatebin its ~ ~ c ~ ~ ~ - ~ ~ ~ areactionsdmtare difficulta -
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 the
OPS to audit, review, and assess these programs and their implementation.
The best integrity management plans, when implemented properly, can reduce the risk of pipeline
accidents. They cannot, however, eliminate that risk. Leaks and ruptures could still occur, fiom
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 available to
mitigate the effects of accidents that may occur.
Here again, circumstances differ between pipelines and between regions and local jurisdictions.
The differences make it difficult to establish prescriptive requirements that will provide the best
protection for each high consequence area. Requiring that operators explicitly consider the need
for mitigative features and provisions and that they implement those found necessary is the most
effective means of providing such protection. Such a requirement also provides the regulatory
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basis for audit and review by OPS and state regulators.
For these reasons, this option was selected for fiuther 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 require
inspection bnd testing of pipelines to recur over short intervals, a few years. The ability to require
fiequent 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 regulation
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 fiom
environmental damage that can be caused by a leak or rupture of a hazardous liquid pipeline
necessitated such frequent inspection. Adding requirements for similarly hquent inspection of
natural gas pipelines would complicate the existing testing capacity issue and likely make it
difficult for any of the testing requirements to be met.
The natural gas pipeline network supplies gas for use in real time. This is not the case for
hazardous liquid pipelines, which move product in batches and have significant storage capacity.
Assessment of natural gas pipelines can therefore result in inkmptions of gas supply. 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. Another difference fiom
hazardous - liquid pipelines _ _ _ is that _ _ significant environmental _ _ _ _ - damage - is not expected - to - result _ _ fiom -
-- - - -
failure of a n a d gas pipeline, since gas islighter than air and theatmosphere.
The OPS evaluated the effect on costs to operators of requiring assessments at increased intervals,
as described later in this analysis. 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 fust 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.
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The OPS has interacted with gas pipeline operators in recent years as part of development of an
integrity management standard by the American Society of Mechanical Engineers (ASME). The
standard includes many of the elements of the proposed rule, and has been adopted as a consensus
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 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 being
conducted by these operators is the initial inspe'ction of pipelines. The rate at which subsequent
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 pipeline
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 OPS
created the Risk Management Demonstration Program, and the System Integrity Inspection Pilot
Program. These programs encourage and evaluate operator-developed safety and environmental
management processes that incorporate operator- and pipeline-specific idormation and data to
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 Eailure
could have significant consequences.
~~ - - __ ~ s k M m a g e m e n L D e r m " t i o n b g r a a n d - t h e System-IntegritgInspectionPih- -~~ _ _
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 identifL and address the most significant integrity threats to
their pipeline systems. In the Risk Management Program, participants perform systematic and
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 assessments is
the integration of information h m many diverse sources to fully understand the integrity threats
at specific locations on the pipeline. The impact on nearby population is explicitly considered in
these risk assessments. Through formal, risk-based decision making processes, these companies
use the risk assessment results to identify projects and activities that address potential system
integrity threats, thereby preventing leaks and accidents. These investigative risk management
programs, and the preventive and mitigative risk control activities that evolve h m them,
supplement the minimum regulatory requirements established in 49 CFR 192.
The System Integrity Inspection Program is focused on developing a more integrity-based
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approach to OPS inspections. Instead of using a “checklist” approach, the OPS is focusing the
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
assessment data with other pipeline specific information to identify the most significant integrity
threats to the system. Specifically, the OPS has observed how operators examine intemal
inspection data in 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 effective programs are in place 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.
The OPS experience in the Risk Management Demonstration Program and the System Integrity
Inspection Program indicates that integrity management programs such as that required by this
rule have been developed. They are far from universal, however.
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 discussion of
the costs versus the benefits is presented. It should be noted that, unless otherwise specified, all
dollar values in this report are given in constant 2001 dollars.’ Furthermore, this analysis will
arbitrarily consider only the first twenty years afker the effective date of the final rule. IncludiB - ____.__
additional years would not be expected to mate~ally affect the conclusions-of this d y s i s . __ - - ~ - - - - -
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 Pireline Mileage
‘Dollars are converted from nomina1 values to real 200 1 values using the Producer Price Index (PPI), Intermediate
Materials, Supplies, and Components. The source of the PPI index numbers is the U.S. Bureau of Statistics Web
page.
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~
In total, there is an estimated 292 thousand miles of regulated natural gas transmission pipelines
in the US? This rule would not apply to all of this mileage. The proposed rule does not apply to
pipelines operated at a hoop stress of less than 20 percent of specified minimum yield strength
(SMYS). The OPS has no data on how much of transmission pipeline mileage is operated at these
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 in 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
transmission pipeline total mileage, which is considered to be very close to the total pipeline
mileage potentially afhted by the proposed regulation.
Imuacted Mileage in Hi& Conseauence Areas
The proposed regulatory change does not apply to all of this pipeline. Instead, it applies to that
transmission pipeline that can affect high consequence areas, as described earlier. A principal
element of this definition is pipeline that is in class 3 and 4 areas as dehed in 49 CFR 192.5.
Pipeline operators are presently required to maintain data on the population near their pipeline in
--8lrder-to-determine_pip?eline_thati~cl_ass 3 or &s 4 areas. This data_is not required - - to -- be
submitted to the OPS. In a 1992 study of instrumented internal inspection devices, the OPS
concluded that approximately 7 percent of the total transmission pipeline mileage was located in
class 3 or 4 areas3 The definitions of class 3 and class 4 have not changed since that time. While
population growth may have increased the percentage of total transmission pipeline mileage that
is in those class are-=, the OPS does not expect that such growth would have significantly afSected
the overall percentage. The OPS therefore estimates that 7 percent of current natural gas
transmission pipeline mileage, or 20,440 miles, is in class 3 or class 4 areas.
Thexe are several factors in the defhition of high consequence areas which could lead to
additional mileage being included. These include:
e the requirement to consider the location of buildings that could house populations of
limited mobility,
0
the requirement to consider areas near pipelines where people congregate, and
0
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 1000
psig or where calculations of potential impact radius indicate a likelihood that areas
2Jurisdictional natural gas transmission pipeline mileage (onshore) for 2000. This mileage was obtained fi" annual
reports filed by pipeline operators with the OEce of Pipeline Safety. Data available on the OPS web page.
30ffice of Pipeline Safety, Instrumentedhternal Inspection Devices (A Study Mandated by P.L. 100-561),
Research and Special Programs Administration, November 1992, p. C-2.
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beyond 660 feet from the pipeline would be afYected by an accident.
The OPS does not collect data related to these additional factors. The OPS therefore cannot
determine the total amount of additional pipeline mileage (Le., beyond that in class 3 or 4
locations) that would be in high consequence areas. For purposes of this analysis, the OPS
assumes that these additional factors would increase the total transmission pipeline mileage
affected by the rule by 20 percent, or 4,088 miles. The OPS seeks comments on the
reasonableness of this assumption.
The total gas transmission pipeline mileage in high consequence areas, and thus impacted by the
rule is thus 24,528 miles, the 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.
BENEFITS
The benefits resulting h m the proposed regulatory change are discussed in this section. Those
benefits are expected to result fiom detection of problems that could cause pipeline failures before
the failure occurs, thereby averting accidents. The inspection and assessment that would be
re@iEd%yL-hejiGpKiSEIFis dGi@ed5id&tiibleiiE related to inteihii-con6sion;ejikfiiiiI
corrosion, stress corrosion cracking and extemal damage to the pipeline, all of which can result 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, then,
are principal benefits of the proposed rule. The proposed rule will also provide improved
assurance of pipeline safety, will provide a basis for increased public acceptance of the risks fiom
natural gas transmission pipelines, and will provide other, less tangible, benefits. Each of these
categories of benefits is discussed below.
Pipeline operators also have strong incentives to ensure the integrity of their pipelines. In
addition to the positive safety and societal benefits, the lost product and unscheduled downtime
for repairs following a major incident can significantly impact the company’s b c i a l
performance and its ability to satisfjr customer commitments. Operators cannot afford to have
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 and reputation, as
well as 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.
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Benefits from reduced death and serious w1uI.r"
Accident reports submitted to the OPS during the period 1986 to 2001 identifjr that there were
1,285 incidents on natural gas transmission pipelines, resulting in 58 fatalities and 2 17 serious
injuries. The consequences of future pipeline accidents could differ, and are likely to be more
severe, as discussed below. Nevertheless, it is reasonable to use this 1 &year record as an estimate
of consequences that would be likely to occur without changes in the manner in which pipeline
safety is assured. The proposed rule is expected to reduce these consequences, through
identification and remediation of the kinds of anomalies that can cause pipeline accidents before
those accidents occur. Accidents that may be prevented by the proposed rule should include a
high percentage of those that result in death and serious injury, since the rule is focused on
pipelines in areas which have the largest concentrations of people in the vicinity of the pipeline.
It is not possible, however, to estimate precisely how effective the proposed rule will be in
reducing such accidents. The maximum benefit that could be achieved would be elimination of
accidents causing death and serious injury. Based on this historical record, the maximum value
that could be realized fiom reducing deaths and serious injuries is thus $282.5 million over 16
years or $17.65 million per year.
Benefits fiom reduced ~ r o ~ e r t ~ dam ape
~ - - - _ _ _ - - __ _____ -
_ _ _ - _ _ _ _ ~
The same accident data base indicates that $284,829,6 17 in property damage occurred as a resuit
of those 1,285 pipeline incidents. A recent study indicates that this total may be low due to under-
reporting of accident costs?
The study compared accident costs reported to the OPS with other information, including press
reports and costs reported in operator's post-accident financial filings. The study considered 49
accidents, of which only four were natural gas pipeline accidents. (Two of these accidents had not
been reported to OPS). The study found that actual costs for accidents involving hazardous liquid
pipelines were three times the amount reported to the OPS. For the limited set of gas pipeline
accidents considered, costs were under-reported by a factor of 1.62. The OPS believes that a
larger study of gas pipeline accidents would show more under-reporting of costs, similar to the
situation revealed for hazardous liquid pipelines. For purposes of this analysis, the OPS assumes
that costs may have been under-reported for natural gas pipeline accidents by up to a factor of 2.
Thus, the true value of property damage experienced in natural gas transmission pipeline incidents
over the last 16 years is in the range of $285 to approximately $570 million.
4With respect to deaths and serious injuries, the following assumptions are made:
A life is valued at $3 million
A serious injury is valued at $500 thousand
These valuations are standard assumptions currently used in Office of Pipeline Safety and DOT benefidcost
analyses.
'"Report on the Accuracy of Cost Data from Incident ReporW, General Physics Corporation, December
2001, unpublished.
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This range is used in this analysis as representative of the property damages caused by historical
natural gas pipeline accidents. As before, the historical record provides a reasonable estimate of
future accident consequences. Again, the proposed rule is expected to reduce the numbex of
accidents, and thus the amount of property damage that occurs. The extent of such reduction
cannot be estimated. The maximum benefit that could be achieved if the historical damage is at
the upper end of this range and property damage consequences were eliminated by
implementation of the proposed rule is $570 million over 16 years, or $35.6 million per year.
Consequences of Pimline Accidents are Likely to Increase
Urban areas are rapidly expanding in the United States. Housing starts have increased 57% over
the last ten-year period. Increasingly, this brings additional population into the proximity of the
natural gas transmission pipelines that serve our urban areas. Rural areas that pipelines may have
passed through ten years ago are more likely today to be populated, and that likelihood will
further increase over time. Natural gas pipeline accidents that occur in rural areas have limited
consequences, particularly in causing deaths and serious injuries. Accidents in urban areas can be
much more severe.
The March 23,1994, accident in Edison Township, New Jersey is a case in point. This area was
already u r ~ ~ d ~ ~ ~ ~ ~ ~ i a ~ . - R ~ p- - - -
transmission Iine resulted in an explosion and fire that destroyed six apartment buildings.
Property damage exceeded $25 million. Approximately 1,500 residents were evacuated fiom &e
apartments. Immediate evacuation prevented any deaths, although one resident living
approximately one mile h m the scene of the accident suffered a fatal heart attack! Had
circumstances been only a little different, significant loss of life could have occurred.
Increased development makes it likely that the actual consequences of natural gas pipeline
accidents over the next 16 years, assuming no changes in the regulatory environment, would be
more severe than suggested by the historical record. The OPS has not estimated by how much
those consequences might increase, because such an estimate would be highly speculative.
Nevertheless, the trend indicates that use of the historical record to estimate the likely
consequences of fhture accidents is almost certainly conservative.
Conseauential ImDact of Natural Gas Pipeline Accidents
The accident impacts described above are direct effects, i.e., they are caused directly by the
pipeline rupture and resulting explosion and fire. The consequences of natural gas transmission
pipeline accidents often do not stop there. Other impacts include disruption of business activities
in the immediate area of the accident and possibly in aceas near the accident.
Qationai Transportation Safety Board, Pipeline Accident Report: Texas Jkstern Transmission
Corporation Natural Gas Pipeline Explosion and Fire Edison, New Jersey March 23, 1994, January 18, 1995, p. v.
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<<<PAGE 13>>>

Many communities are served by natural gas distribution companies that receive their product via
single lateral pipelines from a natural gas transmission pipeline (so-called “sole-source laterals”).
If an accident occurs on the transmission pipeline that results in interruption of the flow of natural
gas, service to customers in communities served by sole-source laterals may be cut off. The
interruption may be temporary, if gas supply can be restored by valving out the damaged section
of pipe and re-establishing supply from undamaged portions of the line. Even so, there is both an
economic and a safety consequence to such service inten-uptions.
when natural gas service is cut off, pilot valves on gas appliances go out. Service cannot simply
be restored, since gas would enter homes and businesses through the open pilot valves, potentially
build to explosive concentrations, and result in fires, explosions and additional collateral damage.
For this reason, restoration of natural gas service requires that local distribution companies follow
labor-intensive procedures. Representatives of the distribution company must enter each business
or residence to which service was interrupted. They must close valves to pilot lights. Distribution
mains and laterals must be purged to eliminate air that may have become entrained. Only then
can service be restored. Restoration of service again requires that an employee of the distribution
operator must enter the premises, reopen pilot light valves, and re-light the pilot lights. This
process can take several days. A recent service outage involved loss of natural gas service to
approximately 4500 customers. Service was restored in 48 hours, but only by the efforts of 400
P e r s ~ ~ e f ~ e d ~ y - ~ ~ ~ ~ o G ~ ~ s ~ h u t i Q n ~ ~ m ~ ~ ass ist in the emergency
recovery effort. Economic consequences included business interruption for the period of the
outage, overtime for local operator personnel, and the need for the local operator to house and
feed personnel loaned h m other operators to assist.
There is a potential that the impact of consequential damages from Service interruptions could
grow. Natural gas is currently being used to power many new electrical generating facilities. As
more of the nation’s electricity is generated fiom natural gas, the supply of electricity will also
become dependent on reliable, continuous availability of natural gas. It is possible that future
accidents on major interstak natural gas transmission pipelines in certain areas could result in loss
of natural gas supply to multiple electrical generating stations. Electricity generators typically
have a supply margin to account for the unexpected loss of a generating facility. If too many
generators are lost simultaneously, however, the margin can be overwhelmed and electrical
blackouts, with their attendant consequences, could result.
Public Confidence
The most significant benefit of the proposed rule is less tangible. It will provide a basis for
improved public confidence in pipeline safety. Public confidence has been shaken as a result of
several recent accidents with sigdicant consequences. These accidents were widely reported by
national media, becoming known well beyond the communities in which they occurred. These
included the 1994 pipeline rupture, explosion, and fire at Edison Township, NJ (discussed above),
a June 10,1999, rupture of a hazardous liquid pipeline in Bellingham, WA, with subsequent fire,
and an August 19,2000, natural gas pipeline rupture, explosion and fire near Carlsbad, NM.
12

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Three persons were killed in the Bellingham accident. Twelve persons were killed in the Carlsbad
accident. (Hazardous liquid pipelines, such as the one involved in the Bellingham accident,
would not be affected by this proposed rule. They are covered by similar rules for hazardous
liquid pipelines, which have already become effective.)
Improving public confidence is, in itself, important. It will, however, also result in economic
benefits.
One way in which public concern regarding pipeline safety manifests itself is in increased public
opposition to new pipelines. Local governments can impose additional requirements and
restrictions that delay construction and result in significant additional costs. A recent example
involved the conversion of an existing hazardous liquid pipeline in Texas. Community reaction in
the city of Austin resulted in delays and si+cant additional costs. In response to the
community reaction, the operator replaced 12 miles of the existing pipeline with 2 1 miles that
looped to the south of the city, avoiding most populated areas. This significantly increased the
cost of the pipeline project. The average installed cost of natural gas transmission pipelines
approved by the Federal Energy Regulatory Commission (FERC) in Fiscal Year 2001 was $2.7
million per d e . ' A similar re-route for a natural gas transmission pipehe thus would have cost
apprE@mtely $56.7 million, - ~-
- ~ - -~ ~ - - ~ _ ~ _
~ -____
Increased public opposition can also result in delays in implementing pipeline projects. In some
cases, the related costs associated with responding to public concerns, participation in public
hearings, and financing of major construction projects during delays can be as significant as, or
more than, the cost of installing new pipeline. In the eKtrerne, increasing public concern could
make it impossible to site and construct new natural gas transmission pipelines.
The United States needs additional natural gas transmission pipeline capacity to meet current and
future needs. FERC approved 2,449 miles of new transmission pipeline in 2001 .8 If operators are
unable to construct new pipelines, the existing pipeline system would rapidly reach its capacity
limit. New applications of natural gas as a fuel would need to be foregone. The ability to use
~ t ~ r a l gas as an environmentally-preferable fie1 for new electric generating capacity would be
lost. Curtailment of existing natural gas usage would likely be required. For all of these reasons,
it is vitally important that the public have confidence that the national network of natural gas
transmission pipelines a
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