Natural Gas Pipeline Safety
Risk-Based Standards Should Allow Operators to Better Tailor Reassessments to Pipeline Threats Gao ID: GAO-06-945 September 8, 2006The Pipeline Safety Improvement Act of 2002 requires that operators (1) assess gas transmission pipeline segments in about 20,000 miles of highly populated or frequently used areas by 2012 for safety threats, such as incorrect operation and corrosion (called baseline assessments), (2) remedy defects, and (3) reassess these segments at least every 7 years. Under the Pipeline and Hazardous Materials Safety Administration's (PHMSA) regulations, operators must reassess their pipeline segments for corrosion at least every 7 years and for all safety threats at least every 10, 15, or 20 years, based on industry consensus standards--and more frequently if conditions warrant. Operators must also carry out other prevention and mitigation measures. To meet a requirement in the 2002 act, this study addresses how the results of baseline assessments and other information inform us on the need to reassess gas transmission pipelines every 7 years and whether inspection services and tools are likely to be available to do so, among other things. In conducting its work, GAO contacted 52 operators that have carried out about two-thirds of the baseline assessments conducted to date.
Periodic reassessments of gas transmission pipelines are useful because safety threats can change. However, the 7-year requirement appears to be conservative because (1) most operators found few major problems during baseline assessments, and (2) serious pipeline incidents involving corrosion are rare, among other reasons. Through December 2005 (latest data available), 76 percent of the operators (182 of 241) that had begun baseline assessments reported to PHMSA that their pipelines required only minor repairs. These results are encouraging because operators are required to assess their riskiest segments first. Since operators are also required to repair these problems, the overall safety and condition of their pipelines should be enhanced before reassessments begin. In addition, PHMSA data suggest that serious gas transmission pipeline problems due to corrosion are rare. For example, there have been no deaths or injuries as a result of incidents due to corrosion since 2001. Of the 52 operators contacted that have calculated reassessment intervals, the large majority (20 of 23) told GAO that based on conditions identified during baseline assessments, they could safely reassess their pipelines for corrosion, every 10, 15, or 20 years--as industry consensus standards prescribe unless pipeline conditions warrant an earlier assessment. Sufficient resources may be available for operators' reassessment activities, but some uncertainty exists. For the most part, the 52 operators that GAO contacted expect to be able to obtain the services and tools needed through 2012. However, they expressed some concern about whether enough qualified vendors for the confirmatory and direct assessment methods (above-ground inspections followed by excavations) would be available. Industry associations and GAO attempted to determine the degree to which activity would increase from 2010 to 2012, when operators begin reassessing pipelines while completing baseline assessments. An industry effort showed an increase in assessment and reassessment activity, but GAO's showed a decrease. The reasons for the differences are not clear but may be due, in part, to differences in the operators contacted and the methodologies used in collecting this information.
RecommendationsOur recommendations from this work are listed below with a Contact for more information. Status will change from "In process" to "Open," "Closed - implemented," or "Closed - not implemented" based on our follow up work.
Director: Team: Phone:GAO-06-945, Natural Gas Pipeline Safety: Risk-Based Standards Should Allow Operators to Better Tailor Reassessments to Pipeline Threats
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Report to Congressional Committees:
September 2006:
Natural Gas Pipeline Safety:
Risk-Based Standards Should Allow Operators to Better Tailor
Reassessments to Pipeline Threats:
GAO-06-945:
GAO Highlights:
Highlights of GAO-06-945, a report to congressional committees
Why GAO Did This Study:
The Pipeline Safety Improvement Act of 2002 requires that operators (1)
assess gas transmission pipeline segments in about 20,000 miles of
highly populated or frequently used areas by 2012 for safety threats,
such as incorrect operation and corrosion (called baseline
assessments), (2) remedy defects, and (3) reassess these segments at
least every 7 years. Under the Pipeline and Hazardous Materials Safety
Administration‘s (PHMSA) regulations, operators must reassess their
pipeline segments for corrosion at least every 7 years and for all
safety threats at least every 10, 15, or 20 years, based on industry
consensus standards”and more frequently if conditions warrant.
Operators must also carry out other prevention and mitigation measures.
To meet a requirement in the 2002 act, this study addresses how the
results of baseline assessments and other information inform us on the
need to reassess gas transmission pipelines every 7 years and whether
inspection services and tools are likely to be available to do so,
among other things. In conducting its work, GAO contacted 52 operators
that have carried out about two-thirds of the baseline assessments
conducted to date.
What GAO Found:
Periodic reassessments of gas transmission pipelines are useful because
safety threats can change. However, the 7-year requirement appears to
be conservative because (1) most operators found few major problems
during baseline assessments, and (2) serious pipeline incidents
involving corrosion are rare, among other reasons. Through December
2005 (latest data available), 76 percent of the operators (182 of 241)
that had begun baseline assessments reported to PHMSA that their
pipelines required only minor repairs. These results are encouraging
because operators are required to assess their riskiest segments first.
Since operators are also required to repair these problems, the overall
safety and condition of their pipelines should be enhanced before
reassessments begin. In addition, PHMSA data suggest that serious gas
transmission pipeline problems due to corrosion are rare. For example,
there have been no deaths or injuries as a result of incidents due to
corrosion since 2001. Of the 52 operators contacted that have
calculated reassessment intervals, the large majority (20 of 23) told
GAO that based on conditions identified during baseline assessments,
they could safely reassess their pipelines for corrosion, every 10, 15,
or 20 years”as industry consensus standards prescribe unless pipeline
conditions warrant an earlier assessment.
Sufficient resources may be available for operators‘ reassessment
activities, but some uncertainty exists. For the most part, the 52
operators that GAO contacted expect to be able to obtain the services
and tools needed through 2012. However, they expressed some concern
about whether enough qualified vendors for the confirmatory and direct
assessment methods (above-ground inspections followed by excavations)
would be available. Industry associations and GAO attempted to
determine the degree to which activity would increase from 2010 to
2012, when operators begin reassessing pipelines while completing
baseline assessments. An industry effort showed an increase in
assessment and reassessment activity, but GAO‘s showed a decrease. The
reasons for the differences are not clear but may be due, in part, to
differences in the operators contacted and the methodologies used in
collecting this information.
Figure: Framework for Assessing and ReAssessing Pipelines for safety
Threats:
[See PDF for Image]
Source: GAO.
[End of Figure]
What GAO Recommends:
The Congress should consider allowing gas transmission pipeline
operators to reassess their pipelines using risk-based standards. In
commenting on a draft of this report, the Department of Transportation
generally agreed with it and the Department of Energy stated that it
had no comments.
[Hyperlink, http://www.gao.gov/cgi-bin/getrpt?GAO-06-945].
To view the full product, including the scope and methodology, click on
the link above. For more information, contact Katherine Siggerud (202)
512-2834 or siggerudk@gao.gov.
[End of Section]
Contents:
Letter:
Results in Brief:
Background:
The 7-Year Reassessment Requirement Appears to Be Conservative:
Sufficient Resources May Be Available for Pipeline Reassessments:
Conclusions:
Matter for Congressional Consideration:
Agency Comments and Our Evaluation:
Appendixes:
Appendix I: Impact of Periodic Reassessments on Natural Gas Supply May
Be Less than Foreseen:
Appendix II: Scope and Methodology:
Other Aspects of Our Work:
Organizations Contacted:
Appendix III: Contact and Staff Acknowledgments:
Figures:
Figure 1: Most Operators Reported That Their Gas Transmission Pipelines
Are in Good Condition, as of December 2005:
Figure 2: Reassessments Every 7 Years for Corrosion Supplement Broader
Periodic Reassessments:
Figure 3: Operators Contacted Plan to Reassess Nearly All of the
Mileage in Highly Populated or Frequently Used Areas Using In-line
Inspection and Direct Assessment Tools:
Figure 4: Baseline Assessment and Reassessment Activities Are Expected
to Decrease during the Overlap Period, According to Operators We
Contacted:
Figure 5: Baseline and Reassessment Activities Are Expected to Increase
during the Overlap Period, According to INGAA and AGA:
Figure 6: GAO and INGAA/AGA Results Show Different Trends in Assessment
Activity during the Overlap Period:
Figure 7: Parallel Natural Gas Transmission Pipelines Can Help Maintain
Product Supply:
Abbreviations:
AGA: American Gas Association:
INGAA: Interstate Natural Gas Association of America:
PHMSA: Pipeline and Hazardous Materials Safety Administration:
September 8, 2006:
Congressional Committees:
Gas transmission pipelines are one of the nation's safest modes of
freight transportation: nationwide about three people have died and
about eight have been injured annually, on average, over the past
decade because of natural gas pipeline incidents from all
causes.[Footnote 1] To enhance the safety of gas transmission
pipelines, the Pipeline Safety Improvement Act of 2002 requires that
operators of these pipelines develop programs to assess and mitigate
safety threats, such as leaks or ruptures due to incorrect operation or
corrosion, to pipeline segments that are located in highly populated
and frequently used areas, such as parks. Specifically, operators are
required to perform baseline assessments on one-half of the gas
transmission pipeline mileage located in these areas by December 2007
and the remainder by December 2012. Pipeline segments that potentially
face the greatest risks of failure from leaks or ruptures are to be
assessed first.
The 2002 act also requires that operators reassess these pipeline
segments for safety threats at least every 7 years. Under flexibility
provided by the act, the federal regulator--the Pipeline and Hazardous
Materials Safety Administration (PHMSA)--requires that operators
reassess these pipeline segments for corrosion damage at least every 7
years in its implementing regulations, because corrosion is the most
frequent cause of failures that can occur over time.[Footnote 2] It
also incorporated, as mandatory, voluntary industry consensus standards
on maximum reassessment intervals into these regulations for other
types of safety threats. The industry standards require that operators
reassess gas pipelines at least every 10, 15, or 20 years for all
safety risks, depending primarily on the condition of the pipelines and
the pressure under which they operate. If conditions warrant,
reassessments must occur more frequently.
The 2002 act required that we assess the 7-year reassessment
requirement. To do so, we examined (1) the extent to which findings
from baseline assessments and other information inform us about the
need to reassess gas transmission pipelines for safety risks at least
every 7 years and (2) the ability of operators to obtain the services
and tools needed to perform the reassessments. These two topics are the
main focus of this report. We also examined the potential impact of
periodic assessments on the nation's natural gas supply. (See app. I.)
This report deals mostly with natural gas transmission pipelines, which
represent the overwhelming majority of gas pipelines.[Footnote 3]
To understand how the findings from operators' baseline assessments and
other information inform us about the need to reassess gas transmission
pipelines at least every 7 years, we reviewed laws, regulations, and
other PHMSA guidance. We discussed this issue with PHMSA, other federal
agencies, industry associations, companies that perform research in
this area, state safety representatives, and safety advocacy groups. We
also obtained information from 52 gas pipeline operators for which
baseline assessments and reassessments could have the greatest impact,
all else being equal: larger and smaller transmission pipelines and
local distribution companies (pipeline companies that take gas from
transmission pipelines and distribute it to end users) with the highest
proportion of pipeline miles in highly populated and frequently used
areas to total system miles. Overall, these operators have assessed
about 21 percent of the 20,000 miles of gas transmission pipeline that
operators have reported as being within highly populated or frequently
used areas.[Footnote 4] In addition, we analyzed data from PHMSA for
241 operators that reported, in 2004 and 2005, on the number of
immediate repairs conducted after completing their baseline
assessments.[Footnote 5] To determine the extent to which gas
transmission pipeline operators and local distribution companies will
likely have the resources to reassess their pipelines at least every 7
years, we asked operators, inspection tool contractors, and industry
associations about the availability of equipment, equipment operators,
and data analysts to interpret results. We also synthesized the
information from the 52 operators to determine the aggregate level of
actual and planned assessments and reassessments through 2012 and
compared our findings with the results from an Interstate Natural Gas
Association of America and American Gas Association data collection
effort on the same topic. As part of our work, we assessed the internal
controls and the reliability of the data elements needed for this
engagement, and we determined that the data elements were sufficiently
reliable for our purposes. We performed our work between August 2005
and August 2006 in accordance with generally accepted government
auditing standards. (See app. II for additional details on our scope
and methodology.)
Results in Brief:
Periodic reassessments of pipeline threats are beneficial because
threats--such as the corrosive nature of the gas being transported--can
change over time. Baseline assessment findings conducted to date and
the generally safe condition of gas transmission pipelines, suggest
that the 7-year reassessment requirement appears to be conservative.
Through December 2005 (latest data available), 76 percent of the
operators (182 of 241) reporting baseline assessment activity reported
to PHMSA that their gas transmission pipelines were in good condition
and free of major defects, requiring only minor repairs. (See fig. 1.)
Most of the 340 problems reported were concentrated in just seven
pipelines.[Footnote 6] (These assessments reported by the 241 operators
covered about 6,700 miles, or about one-third of the nationwide total
to be assessed by 2012.) Because PHMSA does not require operators to
identify the nature of the problems, we do not know how many, if any,
were corrosion related.
Figure 1: Most Operators Reported That Their Gas Transmission Pipelines
Are in Good Condition, as of December 2005:
[See PDF for image]
Source: GAO presentation of PHMSA data.
Note: Results of 241 operators that reported to PHMSA that they
completed 6,700 miles of baseline assessments. Of those operators that
reported no problems, 82 operate smaller pipeline systems (1 to 49
miles), 41 operate mid-sized systems (50 to 199 miles) and 59 operate
larger systems (200 or more miles).
[End of figure]
These results are encouraging, since operators are required to assess
their riskiest segments first and 54 percent of the operators we
contacted that have begun baseline assessments told us that they had
not conducted risk-based assessments before the onset of the gas
integrity management program. This suggests that, overall, operators
that have thus performed baselines assessments are doing a good job in
managing corrosion. Furthermore, since operators are required to repair
these gas transmission pipelines the overall safety and condition of
the pipeline system should be improved before reassessments begin
toward the end of the decade. In addition, PHMSA data show corrosion
incidents are rare: over the past 5-1/2 years (from January 2001
through early July 2006), there were 26 corrosion-related incidents
over the 295,000-mile transmission system per year, on average--none of
which resulted in death or injury.[Footnote 7]
Of the 52 operators that we contacted, 23 have calculated reassessment
intervals. Based on conditions identified during baseline assessments,
20 of these 23 operators indicated that they would reassess their gas
transmission pipelines at the maximum allowable intervals prescribed by
industry consensus standards--if the 7-year reassessment requirement
were not in place.[Footnote 8] Most operators we contacted (42 of 52 or
81 percent) told us that they prefer following industry consensus
standards that base reassessment intervals on the characteristics and
conditions of pipelines and that were developed using historical
information and research. Although the industry consensus standards
recognize that corrosion does not occur at a rapid rate, they allow for
maximum reassessment intervals for time-dependent threats of 10, 15, or
20 years only if the operator can adequately demonstrate that corrosion
will not become a threat within the chosen time interval. If not, then
the reassessment must occur more frequently, perhaps at 7 or even fewer
years. Federal policy encourages the use of industry consensus
standards, and PHMSA's implementing regulations incorporate three other
industry consensus standards.
PHMSA and state pipeline agencies are conducting inspections that
should serve as a check as to whether operators have identified threats
facing these gas transmission pipeline segments and have determined
appropriate reassessment intervals. Initial results from 137 federal
and state inspections show that operators are doing well on assessing
their pipelines and making repairs. PHMSA and state agencies plan to
inspect all operators' compliance with integrity management, including
reassessment requirements and complete most of them by 2009 to, among
other things, ensure that operators continually and appropriately
assess the conditions of their pipeline segments. Finally, basing
reassessments for corrosion on risk would be consistent with the risk-
based approach to improving pipeline safety (called integrity
management) set out in the 2002 act. We recently reported that PHMSA's
implementation of the gas integrity management program is designed to
enhance public safety.[Footnote 9]
Sufficient resources may be available for operators to reassess their
gas transmission pipelines, but some uncertainty exists. For the most
part, the 52 operators and four inspection contractors we contacted
told us that services and tools needed to conduct assessments have been
readily available for baseline assessments, and they do not anticipate
difficulties obtaining these resources in the future. Operators that
reported both baseline and reassessment schedules told us they plan to
reassess 42 percent of their pipeline miles in highly populated or
frequently used areas using in-line inspection.[Footnote 10] Operators
we contacted said that the in-line inspection industry is well
established and has the capacity to expand readily. Operators plan to
use direct assessment or confirmatory direct assessment methods in
reassessing another 54 percent of their pipeline miles.[Footnote 11]
However, they told us that expertise in direct assessment methods is
limited; therefore, they may not be as readily available to all
operators. Industry associations and we asked operators to estimate the
number of miles of gas transmission pipeline they planned to assess
through 2012 in order to determine whether an increase in overall
assessment activity would occur because of the overlap between
completing baseline assessments and beginning reassessments from 2010
through 2012. The results were conflicting: the industry found an
increase in activity, while we found a decrease. The reasons for these
contrasting findings are unclear but may be due, in part, to the
difference in methods used in collecting this information.
We suggest that the Congress amend the Pipeline Safety Improvement Act
of 2002 to permit pipeline operators to reassess their gas transmission
pipeline segments at intervals based on risk factors, technical data,
and engineering analyses. Such a revision would allow PHMSA to
establish maximum reassessment intervals, and to require shorter
reassessment intervals as conditions warrant.
In commenting on a draft of this report, the Department of
Transportation generally agreed with the report's findings. The
Department of Energy had no comments.
Background:
The United States has about a 295,000-mile network of gas transmission
pipelines that are owned and operated by approximately 900 operators.
These pipelines are important to the nation because they transport
nearly all the natural gas used, which provides about a quarter of the
nation's energy supply. Pipelines do not experience many of the safety
threats faced by other forms of freight transportation because they are
mostly underground; but they are subject to failures that occur over
time--such as leaks and ruptures resulting from corrosion[Footnote 12]
or welding defects--and failures that are independent of time--such as
damage from excavation, land movement, or incorrect operation.
For the most part, two types of pipelines transport gas products: (1)
gas transmission pipelines and (2) local distribution pipelines. Gas
transmission pipelines typically move gas products over long distances
from sources to communities and are primarily interstate. They
typically operate at a higher stress level (higher operating pressure
in relation to wall strength). By contrast, local distribution
pipelines receive gas from transmission pipelines and distribute it to
commercial and residential end users. Local distribution pipelines,
which are primarily intrastate, typically operate under lower-stress
conditions. Local distribution companies may also operate small
portions of transmission pipelines--typically under lower stress--and
are therefore subject to the assessment and reassessment requirements
of the Pipeline Safety Improvement Act of 2002.[Footnote 13]
Before the 2002 act, operators were subject to PHMSA's minimum safety
standards for the design, construction, testing, inspection, operation,
and maintenance of gas transmission pipelines; these standards are
applied to all pipelines. However, this approach does not account for
differences in the kinds of threats and the degrees of risk that
pipelines face. For example, pipelines located in the Pacific Northwest
are more susceptible to damage from geologic hazards, such as land
movement, than pipelines in some other areas of the country; but
PHMSA's safety standards do not take these threats into account in a
systematic way.[Footnote 14] By contrast, the risk-based approach of
the 2002 act--called the integrity management approach--requires
pipeline operators to develop programs to systematically identify
threats and mitigate risks to gas transmission pipeline segments
located in highly populated or frequently used areas.[Footnote 15] In
addition to PHMSA's integrity management program, operators must still
meet the minimum safety standards.
As of December 2005 (latest data available), 447 gas pipeline operators
reported to PHMSA that about 20,000 miles of their pipelines (about 7
percent of all gas transmission pipeline miles) lie in highly populated
or frequently used areas. Individual operators reported that they have
as many as about 1,600 miles and as few as 0.02 miles of transmission
pipeline in these areas.
Under PHMSA's regulations, gas pipeline operators may use any of three
primary approaches to conduct baseline assessments on pipeline segments
lying in highly populated or frequently used areas.
* In-line inspection: In-line inspection involves running a specialized
tool through the pipeline to detect and record anomalies, such as metal
loss and damage. In-line inspection allows operators to determine the
nature of any problems without either shutting down the pipeline for
extended periods or potentially damaging the pipeline, as in
hydrostatic testing (described below). In-line inspection devices can
be run only from facilities established for launching and retrieving
them. These launching and retrieval locations may extend beyond highly
populated or frequently used areas. Operators will typically gather
information along the entire distance between launching and retrieval
locations to gain additional safety information; this is called over-
testing.
* Direct assessment: Direct assessment is a nonintrusive, above-ground
instrument inspection that uses two or more types of diagnostic tools,
such as a close interval survey, at predetermined intervals along the
pipeline.[Footnote 16] Once the data are analyzed, the operator
excavates and inspects segments of the pipeline suspected to have
safety threats.
* Hydrostatic testing: Hydrostatic testing entails sealing off a
portion of the pipeline, removing the gas product, filling it with
water, and increasing the pressure of the water above the rated
strength of the pipeline to test its integrity. If the pipeline leaks
or ruptures, the pipeline is excavated to determine the cause of the
failure. Operators must shut down pipelines to perform hydrostatic
testing. Also, this form of testing can damage the pipeline due to high
pressure testing. Finally, operators must be able to dispose of large
quantities of water in an environmentally responsible manner.
Under PHMSA's regulations, which incorporate voluntary industry
consensus standards for managing the system integrity of gas
pipelines,[Footnote 17] operators must reassess their gas transmission
pipeline segments for safety threats overall at least every 10, 15, or
20 years (consistent with industry consensus standards), depending on
the condition of the pipelines and the stress under which the pipeline
segments are operated. PHMSA's regulations allow operators to limit the
statutorily required 7-year reassessment to corrosion damage. In
performing reassessments to meet the 7-year requirement, operators may
employ a technique called confirmatory direct assessment. This
technique is similar to direct assessment; however, operators are
required to use only one type of assessment tool, rather than at least
two types required under direct assessment. According to PHMSA, it
allowed this more limited assessment because the 7-year reassessment
for corrosion confirms the acceptable integrity of a gas transmission
pipeline, already ensured by assessments and reassessments for safety
threats conducted at 10-, 15-, or 20-year intervals under the industry
consensus standards incorporated in the agency's regulations. (See fig.
2.) About 2010, operators will be expected to begin reassessing some
segments of their pipelines for corrosion under the 7-year reassessment
requirement while they are completing baseline assessments of other
segments--called "the overlap."
Figure 2: Reassessments Every 7 Years for Corrosion Supplement Broader
Periodic Reassessments:
[See PDF for image]
Source: GAO.
Note: Periodic reassessments occur at least every 10, 15, or 20 years.
Both periodic and 7-year reassessments are supposed to occur more
frequently if conditions warrant.
[End of figure]
It is important to note that the reassessment intervals under the
industry consensus standards, the 7-year reassessment requirement for
corrosion, and PHMSA's regulations for time-dependent threats represent
the maximum number of years between reassessments. If pipeline
conditions dictate more frequent reassessments--for example, 5 or fewer
years--then pipeline operators must do so to comply with PHMSA's
regulations.[Footnote 18] In addition, between reassessments, operators
must continually ensure that their gas transmission pipelines are safe.
PHMSA's regulations require all operators--whether or not they are
located in highly populated or frequently used areas to patrol their
pipelines, survey for leakage, maintain valves, ensure that corrosion-
preventing cathodic protection is working properly,[Footnote 19] and
take prevention and mitigation measures to prevent excavation damage.
PHMSA, within the Department of Transportation, attempts to ensure the
safe operation of pipelines through regulation, industry consensus
standards, research, education (e.g., to prevent excavation-related
damage), oversight of the industry through inspections, and
enforcement, when safety problems are found. PHMSA employs about 165
people in its pipeline safety program, about half of whom are pipeline
inspectors who inspect operators' implementation of integrity
management programs for gas and hazardous liquid (e.g., oil, gasoline,
and anhydrous ammonia) pipelines, in addition to other more traditional
compliance programs. PHMSA currently has 22 inspectors trained to
conduct integrity management inspections, of which 9 are devoted
exclusively to the program. In addition, PHMSA expects to be assisted
by about 180 inspectors in 46 states and the District of Columbia in
overseeing intrastate natural gas transmission pipelines.
The 7-Year Reassessment Requirement Appears to Be Conservative:
Periodic reassessments of pipeline threats are beneficial because
threats--such as the corrosive nature of the gas being transported--can
change over time. Baseline assessment findings conducted to date and
the generally safe condition of gas transmission pipelines suggest that
the 7-year requirement appears to be conservative. Most operators of
gas transmission pipelines reported to PHMSA that their baseline
assessments have disclosed 340 problems for which immediate repairs
have been made. This is encouraging because these pipeline segments are
supposed to be the riskiest and few have been systematically assessed
until now. Regarding the industry safety record, the industry is
generally safe and no corrosion-related incidents resulting in deaths
or injuries have occurred in the past 5-1/2 years (from January 2001
through early July 2006) anywhere in the nation, let alone in highly
populated or frequently used areas.[Footnote 20] It is therefore likely
to be safe in most cases to allow longer maximum intervals that
coincide with industry consensus standards. PHMSA and state pipeline
agencies plan to inspect all operators' integrity management
activities, which should serve as a safeguard if longer reassessment
intervals for corrosion are permitted.
Most Operators Have Reported That Their Gas Transmission Pipelines Are
Mostly Free of Serious Problems:
Through December 2005 (latest data available), 76 percent of the
operators (182 of 241) reporting baseline assessment activity to PHMSA
told the agency that their gas transmission pipelines were in good
condition and free of major defects, requiring only minor repairs.
(These assessments covered about 6,700 miles, or about one-third of the
nationwide total to be assessed). The remaining 59 operators reported
340 problems for which immediate repairs have been completed. (See fig.
1.)
Fifty-two operators (21 percent) reported nine or fewer problems for
which immediate repairs have been completed; and seven operators (3
percent) reported 10 or more problems. Most of the problems stem from
the seven operators reporting 10 or more problems and concern only a
small portion of their gas transmission pipelines. Specifically, these
seven operators represent nearly 60 percent of the total problems
requiring immediate repairs, and the problems occurred in only 7
percent of 6,700 miles of baseline assessments conducted.[Footnote 21]
Since PHMSA does not require that operators report to it the nature of
the problems, we do not know how many of the 340 problems, if any, were
due to corrosion.
We contacted 52 operators about the baseline assessments they have
completed and their plans for the rest, and the results were largely
consistent with the overall data reported to PHMSA. Forty-four of these
operators have begun baseline assessments, and 37 of these 44 (84
percent) told us that they found few safety problems that required
reducing pipeline pressure and performing immediate repairs in response
to baseline assessments in highly populated or frequently used areas.
These 44 operators have assessed about 4,100 miles of gas transmission
pipeline, representing about 61 percent of the 6,700 miles of baseline
assessment results reported to PHMSA and about 21 percent of the total
number of pipeline miles in highly populated or frequently used areas
nationwide.
It is encouraging that the majority of operators nationwide reported
few or no problems involving immediate repairs, because (1) operators
are to assess pipeline segments facing the greatest risk of failure
from leaks or ruptures first, as required by the 2002 act, and (2) 54
percent of the operators we contacted (28 of 52) had not conducted risk-
based assessments of their pipeline segments for safety threats prior
to the integrity management program.
Although the PHMSA regulations focus the 7-year reassessment
requirement on corrosion because it is the most frequent cause of time-
dependent pipeline incidents,[Footnote 22] the industry has had a good
safety record prior to and during the initial years of integrity
management. It is not possible to determine which incidents occurred in
highly populated or frequently used areas from summary historical data
published by PHMSA. However, nationwide, these incidents are relatively
rare. Over the past 5½ years (from January 2001 through early July
2006), there were 143 corrosion-related incidents over the 295,000-mile
transmission system (26 per year, on average)--none of which resulted
in death or injury. In addition, according to PHMSA, during the first 2
years of integrity management (2004 and 2005), operators reported that
corrosion caused 49 leaks,[Footnote 23] 16 failures, and two incidents
involving significant property damage, but no fatalities and injuries,
in highly populated or frequently used areas.
Both the positive results found during baseline assessments conducted
to date and the overall good safety industry record suggest that gas
transmission pipeline operators that have thus far performed baseline
assessments overall are doing a good job in managing corrosion.
Further, since operators, are required to identify and repair
significant problems, the overall safety and condition of the gas
transmission pipeline system should be enhanced before reassessments
begin toward the end of the decade.
Operators Support Baseline Assessments and Reassessments but Prefer a
Risk-based Reassessment Requirement Over a Fixed One:
Because many gas transmission pipelines had never been assessed before
integrity management, operators we contacted pointed out that the new
knowledge gained through baseline assessments represents one of the
greatest benefits of the integrity management program. They also
support reassessments, in part because all operators are subject to the
same requirements. However, most support a risk-based reassessment
requirement, consistent with overall integrity management, over the
fixed 7-year requirement prescribed by the 2002 act. Operators also
told us they prefer a risk-based reassessment requirement that is based
on research and historical information. Most operators told us they
prefer reassessing pipelines based on the characteristics and
conditions of the pipeline rather than on the 7-year requirement
prescribed in the 2002 act. About 80 percent of the 52 operators that
we contacted prefer that reassessment intervals be based on the
condition and characteristics of the pipeline segment. About half of
these operators (28) expressed a preference for the industry consensus
standard developed by the American Society of Mechanical Engineers
(ASME B31.8S-2004) for setting reassessment intervals for time-
dependent threats because it incorporates a risk-based approach (for
pipeline failure) and is based on science and engineering knowledge.
This standard sets reassessment intervals at a maximum of 10 years for
high-stress pipeline segments, 15 years for medium-stress segments, and
20 years for low-stress segments. Maximum reassessment intervals, such
as those in the industry consensus standard, incorporate such risk
concepts as built-in safety factors (e.g., wall stress, test pressure,
or predicted failure) and pipeline conditions. The maximum intervals of
10, 15, and 20 years are based on worst-case corrosion growth rates.
The industry consensus standards were developed in 2001 and updated in
2004 based on, among other things, (1) the experience and expertise of
engineers, consultants, operators, local distribution companies, and
pipeline manufacturers; (2) more than 20 technical studies conducted by
the Gas Technology Institute, ranging from pipeline design factors to
natural gas pipeline risk management; and (3) other industry consensus
standards, including the National Association of Corrosion Engineers
standards, on topics such as corrosion. Contributors have been
practicing aspects of risk-based assessments for over 10 years. This
standard serves as a foundation for most sections of PHMSA's integrity
management regulations. The mechanical engineering society's standard
was reviewed by the American National Standards Institute.[Footnote 24]
The institute found that the standard was developed in an environment
of openness, balance, consensus, and due process and therefore approved
it as an American National Standard.
While the mechanical engineering standards are voluntary for the
industry, PHMSA incorporated them as mandatory in its gas transmission
integrity management regulations. The mechanical engineering society's
standard for setting reassessment intervals is not the only industry
consensus standard in PHMSA's integrity management regulations. The
regulations incorporate other industry consensus standards for using
direct assessment for corrosion, calculating pipeline wall strength,
and for determining temporary reductions in operating pressure. In
addition, it is federal policy to encourage the use of industry
consensus standards: the Congress expressed a preference for technical
standards developed by consensus bodies over agency-unique standards in
the National Technology Transfer and Advancement Act of 1995. The
Office of Management and Budget's Circular A-119 provides guidance to
federal agencies on the use of voluntary consensus standards, including
the attributes that define such standards.
Of the 52 operators we contacted, 44 had undertaken baseline
assessments, and 23 of the 44 have calculated their own reassessment
intervals.[Footnote 25] Twenty of these 23 operators indicated that,
based on the conditions they identified during their baseline
assessments, they would reassess their gas transmission pipelines at
maximum intervals of 10, 15, or 20 years--as allowed by industry
consensus standards--if the 7-year reassessment requirement were not in
place. The remaining three operators told us that they would reassess
their pipelines at intervals shorter than the industry consensus
standards but longer than 7 years because of the conditions of their
pipelines. These results add weight to our assessment that the 7-year
requirement may be conservative for most pipelines.
Safeguards Exist if Industry Consensus Standards for Corrosion
Reassessments Are Allowed:
Industry consensus standards allow for maximum reassessment intervals
for time-dependent threats of 10, 15, or 20 years only if the operator
can adequately demonstrate that corrosion will not become a threat
within the chosen time interval. If an operator cannot demonstrate that
corrosion does not pose a threat, (e.g., threats posed by shipping gas
that is more corrosive then was shipped previously), then the
reassessment must occur sooner, perhaps at 7 or even 5 or fewer years.
Furthermore, according to industry consensus standards, it typically
takes longer than the 10, 15, or 20 years specified in the standard for
corrosion problems to result in a leak or rupture.
As a means of ensuring that assessments and reassessments are done
competently, PHMSA regulations and industry consensus standards require
that operators develop and document the steps they take to ensure the
quality of these activities. This includes ensuring that persons
involved are competent and able to carry out the activities. In
addition, operators are encouraged to conduct internal audits of their
quality control approaches and third-party reviews of their entire
integrity management programs.
It is important to note that, in addition to periodic reassessments,
operators must perform prevention and mitigation activities on a
continual basis. PHMSA regulations require that all operators of gas
transmission pipelines, including those outside highly populated or
frequently used areas, patrol their pipelines, survey for leakage,
maintain valves, ensure that corrosion-preventing cathodic protection
is working properly, and take other prevention and mitigation measures.
Finally, PHMSA and the state pipeline agencies are inspecting
operators' integrity management plans that were mandated by the 2002
act to provide their gas transmission pipeline reassessment approaches
and intervals, among other things, to ensure that operators continually
and appropriately assess the conditions of their pipeline segments in
highly populated or frequently used areas. These inspections should
serve as a check on whether operators have identified threats facing
these pipeline segments and determined appropriate reassessment
intervals. PHMSA and states have begun inspections and expect to
complete most of the first round no later than 2009. As of June 2006,
PHMSA had completed 20 of about 100 inspections and, as of January
2006, states had begun or had completed 117 of about 670
inspections.[Footnote 26] Initial results from these inspections show
that operators are doing well in assessing their pipelines and making
repairs, but some need to better document their programs. Based on the
initial inspection results to date, PHMSA and states did not find many
issues that warranted enforcement actions.
Sufficient Resources May Be Available for Pipeline Reassessments:
Although some uncertainty exists, sufficient resources may be available
for operators to reassess their gas transmission pipelines. Operators
and inspection contractors we contacted told us that the services and
tools needed to conduct periodic reassessments will likely be available
to most operators. However, operators expressed their uncertainty about
whether qualified direct assessment and confirmatory direct assessment
contractors will be available. This is important because operators plan
to use these methods to reassess about half of their pipeline mileage.
Contractors told us that they will likely have the capacity to meet
demands, even during periods when baseline assessments and
reassessments may overlap. The severity of this overlap, however,
remains unclear. Although operators that we contacted expect baseline
assessment and reassessment activity to decrease from 2010 through
2012, an Interstate National Gas Association of America (INGAA) and
American Gas Association (AGA) polling of their members suggests that
activity will rise markedly.[Footnote 27]
Operators Report that Services and Tools Are Likely to Be Available for
Reassessments:
Thirty-seven out of 52 operators (71 percent), one in-line inspection
association, and all four inspection contractors that provide direct
assessment or in-line inspection tool services that we contacted told
us that the services and tools needed to conduct periodic reassessments
will likely be available to most operators.[Footnote 28] All but 3 of
the operators reported that they plan to rely on contractors to conduct
all or a portion of their reassessments, and 9 of 52 operators have
signed, or would like to sign, long-term contracts that extend
contractor services through a number of years. However, few have
scheduled reassessments with contractors, as they are several years in
the future and operators are concentrating on baseline assessments.
The 48 operators that reported both baseline and reassessment schedules
told us that they plan to reassess 42 percent of their gas transmission
pipeline miles in highly populated or frequently used areas, using in-
line inspection, and 54 percent of their miles using direct assessment
or confirmatory direct assessment methods.[Footnote 29] (See fig. 3.)
Operators expect to assess only 4 percent of their pipeline miles using
hydrostatic testing for several reasons: (1) this form of testing
requires shutting down their pipelines, (2) other assessment methods
yield more robust information about the condition of their pipelines,
(3) hydrostatic testing can weaken or damage pipelines, and (4) large
quantities of water must be disposed of in an environmentally
responsible manner.
Figure 3: Operators Contacted Plan to Reassess Nearly All of the
Mileage in Highly Populated or Frequently Used Areas Using In-line
Inspection and Direct Assessment Tools:
[See PDF for image]
Source: GAO discussions with 48 operators.
Note: Some operators may use one type of assessment tool on one portion
of their gas transmission pipeline and another type of assessment tool
on another portion.
[End of figure]
The Inline Inspection Association and the two in-line inspection
contractors that we contacted told us that sufficient capacity exists
within the industry to meet current and future operator demands.
However, operators and inspection contractors expressed uncertainty
about whether qualified direct assessment and confirmatory direct
assessment contractors will be available. This is important because
operators plan to use these methods to reassess about half of their gas
transmission pipeline mileage. Unlike the in-line inspection method,
which is an established and less intrusive practice that 27 of 52
operators have used on their pipelines at least once prior to the
integrity management program, two direct assessment contractors told us
that there is limited expertise in this field. One said that newer
contractors coming into the market to meet demand may not be qualified.
The operators planning to use direct assessment for their pipelines are
generally those with smaller-diameter pipelines that cannot accommodate
in-line inspection tools.[Footnote 30] At a recent INGAA integrity
management workshop, in-line inspection and direct assessment
inspection contractors emphasized that, although they currently have
the resources to meet operator demand and continue to train new
inspectors, operators need to plan ahead to ensure resource
availability for future years, when resources may be more constrained.
The workshop also highlighted technological developments for assessment
tools that will make assessments more efficient. Other stakeholders
have told us that there are new tools being developed that will enable
smaller-diameter pipelines to accommodate in-line inspection tools. For
example, the Department of Energy is developing tiny robotic sensors
that can detect flaws in plastic natural gas pipelines without
interrupting the flow of gas.
The Amount of Assessment Activity Occurring in the Overlap Period Is
Uncertain:
An industry concern about the 7-year reassessment requirement is that
operators will be required to conduct reassessments starting no later
than 2010, while they are still in the 10-year period (2003 through
2012) for conducting baseline assessments. Industry is concerned that
this could create a spike in demand for contractor services, and
operators would have to compete for the limited number of contractors
to carry out both. As a result, operators might not be able to meet the
reassessment requirement.[Footnote 31] The information provided by the
operators that we contacted shows a marked overall increase in
assessment and reassessment activity in 2010 (a 16 percent increase
over 2009 activity) and then a gradual decrease of activity through
2012. (See fig. 4.) Operators expect this decrease because they plan to
have completed a large number of baseline assessments between 2005 and
2007 in order to meet the statutory deadline for completing at least
half of their baseline assessments by December 2007 (3 years before the
predicted overlap).
Figure 4: Baseline Assessment and Reassessment Activities Are Expected
to Decrease during the Overlap Period, According to Operators We
Contacted:
[See PDF for image]
Source: GAO discussions with 52 operators.
Note: These results are based on information obtained from 47 of 52
operators we contacted, covering 154,000 miles of gas transmission
pipeline, 12,000 miles of which are in highly populated or frequently
used areas. Five operators did not report their reassessment plans. We
did not ask operators to separate baseline assessments and
reassessments in areas that are not highly populated or frequently
used.
[End of figure]
In contrast, INGAA and AGA, after polling their members in 2006, found
a steady overall increase in total expected baseline assessments and
reassessments during the overlap period. INGAA and AGA found that
baseline assessments and reassessments would start to increase in 2009
and rise steadily through 2012.[Footnote 32] (See fig. 5.) Assessment
activity would increase by 5 percent in 2010 over the 2009 level; in
2011, by 8 percent over the preceding year; and in 2012, by 10 percent
over the 2011 level.
Figure 5: Baseline and Reassessment Activities Are Expected to Increase
during the Overlap Period, According to INGAA and AGA:
[See PDF for image]
Source: GAO analysis of INGAA and AGA results.
Note: These results are based on responses from 56 operators covering
180,000 miles of gas transmission pipeline, 11,000 miles of which are
in frequently used or highly populated areas.
[End of figure]
The difference between our findings and those of INGAA and AGA is not
easy to explain. (See fig. 6.) Both efforts reported on comparable
numbers of operators (47 for us and 56 for INGAA/AGA) and total
transmission pipeline miles (154,000 for us and 180,000 for INGAA/AGA).
To some extent, the difference may be due to the variations in the
pipeline operators that responded to both efforts. About 72 percent of
operators we polled were different from those polled by INGAA and AGA.
However, even where both efforts collected information from the same
operators, the information was sometimes markedly different. Another
reason for the difference may be due to methodology. For example, we
gathered our information through semistructured interviews with a
systematically selected set of pipeline operators based on larger and
smaller transmission pipelines and local distribution companies with
the highest proportion of pipeline miles in highly populated or
frequently used areas to total system miles, among other things. INGAA
and AGA gathered their information by sending out a self-administered
data collection instrument to their members, and reported results based
on those members who responded. In addition, INGAA and AGA asked
operators for data somewhat differently from methods we used, which may
have led to some differences in results.
Figure 6: GAO and INGAA/AGA Results Show Different Trends in Assessment
Activity during the Overlap Period:
[See PDF for image]
Sources: GAO discussions with 52 operators and GAO analysis of
INGAA/AGA results.
Note: See text for possible reasons for the difference in results.
Readers should not interpret these results to suggest that operators
are not planning to complete all required baseline assessment
activities by the end of 2012.
[End of figure]
Conclusions:
Evidence as a result of baseline assessments, the industry's overall
safety record, the existence of accepted risk-based assessment
standards, and PHMSA's actions to inspect how operators are identifying
corrosion threats to their pipelines and setting reassessment intervals
suggests a risk-based approach to reassessing gas transmission pipeline
segments for corrosion can achieve the safety objectives of the 2002
act. Evidence gathered to date suggests that operators that have thus
performed baseline assessments are doing a good job overall managing
corrosion. Since the large majority of pipeline operators that we
contacted had not systematically assessed their transmission pipelines
for corrosion risks before the onset of the gas integrity management
program, if corrosion were a rapidly growing problem, we would have
expected a larger proportion of pipelines to report problems requiring
immediate repairs. But, this was not the case. Furthermore, adopting a
risk-based approach to setting reassessment intervals does not
automatically allow operators to reassess their pipeline segments less
frequently than under the 7-year requirement. Rather, if conditions
warrant, an operator would be required to reassess a pipeline segment
as frequently as needed--perhaps even more frequently than every 7
years. Finally, a risk-based reassessment requirement would be
consistent with the overall approach to integrity management that the
Congress put in place with the 2002 act.
Safeguards are in place to ensure that gas transmission operators
determine reassessment intervals competently. PHMSA regulations and
industry consensus standards require that operators ensure that persons
involved have the experience and expertise to carry out the activities.
Operators are also encouraged to conduct internal audits of their
quality control approaches and third-party reviews of their integrity
management programs. PHMSA and the state pipeline agencies are
inspecting operators' compliance with integrity management reassessment
requirements, among other things, to ensure that operators continually
and appropriately assess the conditions of their gas transmission
pipeline segments in highly populated or frequently used areas.
In summary, the available evidence supports a conclusion that a risk-
based reassessment approach based on technical data, risk factors, and
engineering analyses can achieve the 2002 act's safety objectives. Such
an approach would provide for reassessments to be tailored to the
corrosion threats faced by the pipeline segment and would not result in
reassessments that are either too infrequent or premature. Evidence to
date suggests that gas transmission pipelines are generally in good
shape based on assessments, following up with immediate repairs and
safeguards being in place to ensure operators determine reassessments
appropriately. In our view, it is not necessary to wait until baseline
assessments and a round of reassessments have been completed before
considering whether to retain or modify the 7-year reassessment
requirement.
Matter for Congressional Consideration:
To better align reassessments with safety risks, the Congress should
consider amending section 14 of the Pipeline Safety Improvement Act of
2002 to permit pipeline operators to reassess their gas transmission
pipeline segments at intervals based on technical data, risk factors,
and engineering analyses. Such a revision would allow PHMSA to
establish maximum reassessment intervals, and to require shorter
reassessment intervals as conditions warrant.
Agency Comments and Our Evaluation:
We provided a draft of this report to the Departments of Transportation
and Energy for their review and comment. The Department of
Transportation generally agreed with the report's findings. The
Department of Energy had no comments.
We are sending copies of this report to congressional committees and
subcommittees with responsibility for transportation safety issues; the
Secretary of Transportation; the Secretary of Energy; the
Administrator, PHMSA; the Assistant Administrator and Chief Safety
Officer, PHMSA; the Deputy Secretary for Natural Gas and Petroleum
Technology, Department of Energy; and the Director, Office of
Management and Budget. We will also make copies available to others
upon request. This report will be available at no charge on the GAO Web
site at [Hyperlink, http://www.gao.gov].
If you have any questions about this report, please contact me at (202)
512-2834 or siggerudk@gao.gov. Contact points for our Offices of
Congressional Relations and Public Affairs may be found on the last
page of this report. Staff who made key contributions to this report
are listed in appendix III.
Signed by:
Katherine A. Siggerud:
Director, Physical Infrastructure Issues:
Congressional Committees:
The Honorable Ted Stevens:
Chairman:
The Honorable Daniel K. Inouye:
Co- Chairman:
Committee on Commerce, Science and Transportation:
United States Senate:
The Honorable Don Young:
Chairman:
The Honorable James L. Oberstar:
Ranking Democratic Member:
Committee on Transportation and Infrastructure:
House of Representatives:
The Honorable Joe Barton:
Chairman:
The Honorable John D. Dingell:
Ranking Minority Member:
Committee on Energy and Commerce:
House of Representatives:
[End of section]
Appendix I: Impact of Periodic Reassessments on Natural Gas Supply May
Be Less than Foreseen:
As the Pipeline Safety Improvement Act of 2002 was being considered,
the Interstate Natural Gas Association of America (INGAA) analyzed the
possible impact of requiring assessments and periodic reassessments and
found that significant disruptions in the natural gas supply and
considerable price increases could occur.[Footnote 33] A more moderate
impact was predicted in three subsequent analyses--(1) two reviews of
the INGAA study performed for the Pipeline and Hazardous Materials
Administration (PHMSA) by the John A. Volpe National Transportation
Systems Center and by the Department of Energy during the congressional
debate over the pipeline bill, and (2) a post-act PHMSA evaluation of
its implementing regulations.[Footnote 34] A waiver provision was
included in the 2002 act after INGAA's study was completed; this may
serve as a safety valve if it appears that the natural gas supply may
be disrupted. Finally, our discussions with 50 natural gas pipeline
operators also suggest a more moderate potential impact than INGAA
found.
INGAA Study Expected Significant Supply Disruptions and Price
Increases:
INGAA's study estimated that periodic assessments under integrity
management could lead to a monthly reduction in natural gas supply of
about 1 to 3 percent, along with price increases to customers, among
others, ranging from $382 million to over $1 billion (in 2002 dollars)
from 2002 through 2010, depending on the frequency of
assessments.[Footnote 35] Most of this price increase would be due to
supply disruption and some due to capital expenditures. INGAA
considered the monthly reduction in supply to be significant because it
assumed that gas transmission pipelines would be removed from service
during testing and that some areas of the country would be more
vulnerable to supply disruptions than others.
PHMSA-commissioned Reviews and PHMSA's Regulatory Evaluation Predict
More Moderate Impacts:
Both Volpe's and the Department of Energy's 2002 reviews of the INGAA
study concluded that gas transmission pipelines would not be
significantly affected by periodic assessments. The reviews, however,
did not attempt to quantify overall estimates of gas disruptions or
price impacts. Rather, they examined the major assumptions in the INGAA
study and discussed whether the study's results seemed reasonable.
PHMSA's final regulatory evaluation, which was completed in 2004 to
assess the impact of PHMSA's regulations on implementing the 2002 act,
concluded that transmission pipelines' natural gas supply may be
somewhat disrupted as a result of assessments and that cost increases
may occur. However, PHMSA acknowledged that it could not estimate the
impact of assessments on gas prices. In general, the reviews found that
the INGAA study's estimates of price impacts represent a worst-case
scenario because of several overly pessimistic assumptions. For
example, the INGAA study:
* underestimated the ability of the pipeline network to mitigate
disruptions. INGAA assumed that pipeline assessments would generally
reduce pipeline capacity temporarily, thereby disrupting the supply and
increasing the price of natural gas. Yet, both Volpe's and the
Department of Energy's reviews found that the INGAA study did not
sufficiently account for redundancies in the nation's natural gas
transmission pipeline network. Redundancies enable operators to
mitigate potential disruptions during assessments by rerouting gas
through the network.
Operators we contacted that have higher-stress gas transmission
pipelines[Footnote 36] generally indicated that their pipeline
infrastructure is versatile and includes such redundancies as parallel
pipelines or looping capabilities that allow gas to flow to customers
while portions of the pipeline are assessed or repaired.[Footnote 37]
(See fig. 7.) Operators of lower-stress pipelines[Footnote 38] reported
that they typically use a set of laterals,[Footnote 39] which feed an
interconnected gas distribution system and allow them to plan around
disruptions. In addition, lower-stress operators can use liquid or
compressed natural gas that is located at their facilities or
transported by trucks to specified locations. Forty-four of the 50
natural gas operators (88 percent) that we contacted have some type of
alternative gas supply, such as storage facilities and other gas
suppliers, to meet customers' short-term needs.
Figure 7: Parallel Natural Gas Transmission Pipelines Can Help Maintain
Product Supply:
[See PDF for image]
Source: PHMSA.
[End of figure]
* assumed that a large amount of transmission mileage would require
assessments because of over-testing. The INGAA study concluded that the
number of gas transmission pipeline miles within highly populated or
frequently used areas is only about 5 percent of the total mileage in
the U.S. Nonetheless, the study assumed that over 80 percent of
mainline interstate pipeline miles would require assessing, because the
pipeline miles that are located within the highly populated areas are
scattered throughout the pipeline system, and inspection methods like
in-line testing can only be inserted and retrieved in certain locations
that may lie outside highly populated or frequently used locations. As
a result, the study assumed that operators of these pipelines would
assess over 1,500 percent more miles than are within the highly
populated areas. On the basis of comments from industry groups, PHMSA's
regulatory evaluation assumed that operators would assess about 625
percent more miles when using in-line inspection testing and about 25
percent more miles when using hydrostatic testing, but no over-testing
when using the direct assessment method. Baseline assessment results to
date seem to support the lower over-testing estimate: as of December
31, 2005, on the basis of performance reports submitted to PHMSA,
operators assessed about 650 percent more miles overall than are
located in highly populated or frequently used areas.[Footnote 40]
* assumed that only hydrostatic testing would be used on delivery
laterals. The INGAA study predicted that operators would use only
hydrostatic testing on lateral gas transmission pipelines because it
assumed that very few laterals can accommodate in-line testing. Under
hydrostatic testing, water pressure is used to test the condition of
pipelines; therefore, all of the capacity of a pipeline segment must be
removed for a period of time.
Volpe's review concluded that this particular assumption represents the
worst possible impact of assessments on lateral pipelines because it
does not allow for the use of in-line testing or direct assessment.
Based on discussions with operators and public comments on PHMSA's
draft regulatory analysis, the PHMSA regulatory evaluation also assumed
that few operators would use hydrostatic testing. INGAA's study also
did not address the development of new technologies that could allow in-
line inspection of smaller diameter pipelines. As discussed earlier,
new technology is being developed. Finally, operators we contacted
reported that they do not plan to use hydrostatic testing extensively.
As discussed earlier, only about 4 percent of the mileage will be
reassessed using hydrostatic testing. This testing will typically be
over relatively small lengths of pipeline (from 0.8 to 331 miles).
* did not incorporate the ability of operators to obtain waivers. The
INGAA study did not consider the possible impact of a waiver provision
in the 2002 act on maintaining the natural gas supply. This was
understandable because the waiver provision was added to the bills
under consideration after the INGAA study was completed. The act allows
the PHMSA to waive or modify any requirement for operators to conduct
reassessments when they need to maintain product supply as long as it
is consistent with pipeline safety.[Footnote 41] Twenty-one of the 50
natural gas operators (42 percent) that we contacted said that they
would consider applying for a waiver, if needed, and 23 (46 percent)
told us that they did not plan to apply for a waiver. Three of the
operators were uncertain, and the remaining three operators did not
provide us with a response. Fourteen of the 26 operators that either
did not plan to apply for a waiver or were unsure about doing so said
that it is too early to determine the need for applying for waivers.
They obtained the necessary equipment to conduct assessments or
developed plans for handling potential natural gas supply
disruptions.[Footnote 42]
Operators Contacted Found Assessments Have Had Minimal Impact on
Supply:
Pipeline operators we contacted told us that assessments and repairs of
even their riskiest gas transmission pipelines have not significantly
disrupted the natural gas supplied to customers, such as local
distribution companies and power plants. These 50 natural gas
transmission operators and local distribution companies had assessed
about 4,100 miles of pipeline in highly populated or frequently used
areas, as of December 2005 (latest data available)--or about 21 percent
of the total gas transmission mileage in these areas in the nation and
about 62 percent of the pipeline mileage located in frequently used or
highly populated areas assessed to date. Of the 44 operators that have
begun baseline assessments, 26 (59 percent) indicated that their
assessments and repairs did not require them to shut down their
pipelines or reduce their operating pressure. Sixteen operators (36
percent) reported minor disruptions in their gas supply because they
temporarily shut down pipelines and reduced operating pressure to
conduct assessments or repairs. These operators told us that they used
alternative gas sources, such as liquefied natural gas, to sustain
their customers' gas supply. The remaining two operators (5 percent)
were located in regions that have limited excess gas capacity. Both
operators reported that they could not meet all of the natural gas
needs of their customers when their pipelines were shut down to perform
assessments or repairs. Some customers, especially those with
interruptible contracts,[Footnote 43] did not receive gas from the
pipelines for several days, but they were able to obtain gas from
alternative sources.
Eleven of the 44 operators were located in regions that have limited
excess gas capacity--the Northeast, the Rocky Mountains, and the
Southwest--and reported minor supply disruptions. Five of the 11
operators--all of which operate lower-stress gas transmission
pipelines--reported that none of these disruptions in natural gas
supply were caused by assessments or repairs. Four operators reported
instances in which immediate repairs caused a reduction in operating
pressure; however, they maintained natural gas supply by relying on
alternative gas sources.[Footnote 44] Since PHMSA does not require that
operators report to it the nature of the problems, we do not know how
many immediate repairs, if any, were due to corrosion. And, as
previously mentioned, 2 of the 11 operators reported natural gas supply
disruptions; although they had to shut down their pipelines due to
assessments or repairs, customers were able to obtain natural gas from
other sources.
In early 2006, INGAA and AGA polled their members about their
experiences with and plans for conducting assessments and reassessments
during off-peak and peak months.[Footnote 45] Overall, INGAA and AGA
found that, from 2003 to 2012, members plan to conduct 76 percent of
their baseline assessments and reassessments on their gas transmission
pipelines (as measured in miles) during the off-peak spring and summer
months, 18 percent in the fall, and 6 percent in the winter. According
to an INGAA official, most of the assessment activity that results in
temporary reductions in gas supply due to repairs being made will
likely affect markets regionally. If assessments occur when pipelines
are constrained for capacity, an increase in delivered gas prices will
occur. Overall, assessments will only affect small groups of the
nation's population, but they will have a consumer price impact in
those affected areas.
Our findings from these operators, while not necessarily representative
of all operators, are encouraging. First, these findings do represent a
sizeable proportion (61 percent) of the mileage assessed to date.
Second, the segments that operators assessed were supposed to be the
riskiest segments (those most susceptible to ruptures or leaks) of the
gas transmission pipelines located in highly populated or frequently
used areas. If so, there should be fewer repairs needed for subsequent
baseline assessments of less risky segments, and hence fewer
disruptions in supply.
Post-act Industry Polling Found Members Plan to Modify and Repair
Pipelines, Which May Affect Natural Gas Supply:
The 2006 INGAA and AGA polling of their members did not explicitly ask
for the extent to which their members experienced supply disruptions
because of baseline assessments or repairs. However, INGAA and AGA did
ask members to identify the amount of pipeline modifications and
repairs that would be necessary for conducting baseline assessments and
reassessments, activities that could disrupt supply. Overall, INGAA and
AGA found that about 50,000 of the 180,000 miles of gas transmission
pipelines that were reported by responding operators are scheduled for
or have already undergone (1) modifications to allow in-line inspection
tools to access pipeline segments (2) repairs to eliminate major
defects or (3) monitoring for minor problems.[Footnote 46] According to
a senior INGAA official, assessments and pipeline modifications can
generally follow a prearranged schedule; however, pipeline repairs are
unpredictable. Repairs often require pipelines to be shut down, which
could have an effect on natural gas supply.[Footnote 47] However, PHMSA
officials report that only the worst pipeline problems require
pipelines to be shutdown for repair. From 2003 to 2012, 38,000 of the
50,000 pipeline miles (76 percent) have been scheduled for
modifications or repairs during the off-peak spring and summer months
to mitigate supply disruptions.[Footnote 48]
Department of Energy Expects Little Disruption in the Natural Gas
Supply:
Officials from the Office of Oil and Gas within the Department of
Energy told us that the integrity management program, including the 7-
year reassessment requirement, is not likely to significantly disrupt
the natural gas supply. They told us that operators have, among other
things, sufficient system redundancies, such as parallel lines, to
maintain product supply. The Department of Energy has completed several
regional analyses of the possible effects of the disruptions in the
natural gas supply caused by such events as extreme weather conditions
(e.g., extended cold periods and hurricanes). It is completing other
analyses as well. However, because these are being done at the regional
level, their results are too broad to help inform us about more
localized and subregional potential disruptions.
[End of section]
Appendix II: Scope and Methodology:
To understand how the findings from operators' baseline assessments
inform us about the need to reassess gas transmission pipelines at
least every 7 years, we reviewed the requirements of the Pipeline
Safety Improvement Act of 2002 and PHMSA's implementing regulations. We
also reviewed information about setting reassessment intervals for gas
transmission pipelines, including industry consensus standards for
maximum reassessment intervals developed by the American Society of
Mechanical Engineers, and documents obtained from PHMSA, industry, and
other stakeholders. We discussed this issue with officials from PHMSA,
other federal agencies, industry associations, companies that perform
research in this area, state safety representatives, and safety
advocacy groups. (These organizations are listed at the end of this
appendix.)
We also analyzed data from PHMSA on the number of immediate repairs
reported by operators as a result of baseline assessments conducted
through December 2005 (latest data available) and the number of natural
gas pipeline incidents reported to PHMSA.
We contacted 52 pipeline operators (50 natural gas and 2 hydrogen
operators) from among the 447 operators that reported that they operate
gas transmission pipelines in highly populated or frequently used
areas. Forty-four of these operators have begun baseline assessments.
We selected those operators for which the baseline assessments and
reassessments could be expected to have the greatest impact, all else
being equal: larger and smaller transmission pipelines and local
distribution companies with the highest proportion of pipeline miles in
highly populated or frequently used areas to total system miles. We
also selected operators located in three regions of the country that
several studies and our stakeholders consider to be vulnerable to
energy supply disruptions: the Northeast, the Southwest, and the Rocky
Mountains.
The 52 operators reported that they have assessed about 4,100 of the
6,700 miles (61 percent) of pipeline segments, as of December 2005.
Overall, these operators have assessed about 21 percent of the 20,000
miles of pipeline that operators have reported as being within highly
populated or frequently used areas. Because we used a nonprobability
method of selecting these operators, we cannot project our findings
nationwide.[Footnote 49] Contacting a larger number of operators or
selecting them through a statistical sample would not have been
feasible due to resource and time constraints. Nonetheless, these 52
operators do represent a substantial portion of the miles assessed to
date and of the total number of reported miles of pipeline in highly
populated or frequently used areas.
For these 52 operators, we conducted semistructured interviews to
collect qualitative and quantitative information on the degree to which
they found anomalies during the baseline assessments and, based on
these results, the frequency with which they would reassess these
pipeline segments under American Society for Mechanical Engineers
standards for managing the system integrity of gas pipelines (ASME
B31.8S-2004) if the 7-year reassessment requirement were not in place.
As part of our work, we asked operators to identify the steps that they
take to ensure the quality of their baseline assessments and
reassessments, such as ensuring that competent persons are involved in
determining reassessment intervals and conducting periodic internal or
third-party reviews of their integrity management programs, as
recommended by PHMSA regulations and industry standards. We relied on
the operators' professional judgment in reporting on the conditions
they found during their assessments.
To determine the extent to which gas transmission pipeline operators
and local distribution companies will likely have the resources to
reassess their pipelines, at least every 7 years, we synthesized
testimonial and documentary evidence obtained from our discussions with
(1) 52 operators (as described above) and (2) pipeline assessment tool
contractors, direct assessment vendors, and industry associations on
the prospective availability of equipment, equipment operators, and
data analysts to interpret results. We synthesized the information from
the 52 operators to determine the aggregate level of actual and planned
assessments and reassessments through 2012. We compared our findings
with the results from an INGAA/AGA data collection effort, conducted in
2006, on the same topic. We then discussed our results with INGAA and
analyzed the data obtained from both efforts to try to understand any
differences in results.
To assess the reliability of information provided to us from PHMSA,
INGAA, and AGA, we performed a number of analyses. For the information
provided to us from PHMSA, we compared the number of immediate repairs
operators reported to us to the number of immediate repairs they
reported to PHMSA. To assess the reliability of the data provided to us
from INGAA and AGA, we also compared the reported responses of
operators that were included in INGAA/AGA's and our efforts. In
addition, we checked the accuracy of INGAA/AGA's calculations. We
determined that the data were sufficiently reliable for the types of
analyses we present in this report.
Other Aspects of Our Work:
To determine the potential impact of the 7-year reassessment
requirement on the nation's natural gas supply, we contacted officials
from PHMSA, the Department of Energy, industry associations, and
research firms to discuss how the potential shutdown of gas
transmission pipelines or operation under reduced pressure--as a result
of baseline assessments, reassessments, and repairs--might affect the
continued supply of natural gas. We also obtained information from the
Department of Energy on the results of analyses of the overall
vulnerability of natural gas supplies in several regions of the nation
to extreme conditions, such as extreme cold weather.
Further, we asked the 50 natural gas operators that we contacted about
the vulnerability of their pipelines to supply disruption and the
potential impact on customers. This included 11 operators located in
the three regions of the country that have limited excess supply gas
capacity. We also discussed how their baseline assessments and any
resulting repairs have affected their customers to date. Finally, we
compared operators' experiences in performing assessments,
reassessments, and repairs to the assumptions made in the 2002 INGAA
study of the potential effects of the proposed integrity management
program, two reviews of this study, and PHMSA's final regulatory
evaluation. The reviews were performed by the John A. Volpe National
Transportation Systems Center and the Department of Energy at the
request of PHMSA.[Footnote 50]
Organizations Contacted:
In addition to the 52 pipeline operators and four inspection
contractors that we contacted, we met with or contacted the following
organizations:
Department of Transportation:
Office of Inspector General:
Pipeline and Hazardous Materials Safety Administration:
Other Federal Agencies:
Department of Energy:
Federal Energy Regulatory Commission:
National Institute of Standards and Technology:
National Transportation Safety Board:
Industry Associations:
American Gas Association:
American Public Gas Association:
Inline Inspection Association:
Interstate Natural Gas Association of America:
Midwest Energy Association:
Northeast Gas Association:
State Regulatory Associations:
National Association of Pipeline Safety Representatives:
National Association of Regulatory Utility Commissioners:
New Jersey Public Utility Commission:
Research Firms:
Energy and Environmental Analysis, Inc. Battelle:
Gas Technology Institute:
John A. Volpe National Transportation Systems Center:
Pipeline Research Council International:
Technical Experts:
American Society of Mechanical Engineers:
American Society for Testing and Materials:
Kiefner and Associates, Inc.
National Association of Corrosion Engineers:
Pipeline Safety Advocacy Groups:
Common Ground Alliance:
Cook Inlet Keeper:
Pipeline Safety Trust:
[End of section]
Appendix III: Contact and Staff Acknowledgments:
GAO Contact:
Katherine Siggerud (202) 512-2834 or siggerudk@gao.gov:
Staff Acknowledgments:
In addition to the above, James Ratzenberger, Assistant Director;
Timothy Bober; Anne Dilger; Seth Dykes; Timothy Guinane; Brandon
Haller; Bert Japikse; and Matthew LaTour made key contributions to this
report.
(542069):
FOOTNOTES
[1] Transmission pipelines move products from sources to communities.
An incident, for PHMSA reporting purposes, involves a death, an injury
requiring hospitalization, or property damage (including the value of
any loss of gas) of $50,000 or more.
[2] Other types of failures are independent of time, such as damage
from excavation, land movement, or incorrect operation.
[3] Other types of gas pipelines transport hydrogen and carbon dioxide.
[4] It would have been insightful to be able to assess the effects of
operators' assessment activity in relation to the volume of gas flowing
through their pipelines and the overall capacity of the pipelines.
However, this information was not readily available.
[5] Nationwide, there are about 900 operators, 447 of which have
reported to PHMSA that they operate pipelines in highly populated or
frequently used areas. Of these, 241 have reported to PHMSA that they
have completed some baseline assessments.
[6] Pipeline operators are required to report the number of scheduled
and immediate repairs completed. They may have found other problems but
not have completed the repairs. These repairs are reported only after
they are completed.
[7] In the last 10½ years, PHMSA data show that 236 corrosion-related
incidents occurred, only 2 of which resulted in deaths or injuries. One
of the incidents resulted in 12 deaths and two injuries. The other
incident resulted in one injury. Neither incident occurred in a highly
populated or frequently used area.
[8] The remaining three operators told us that they could reassess
their pipelines at intervals shorter than the industry consensus
standards but longer than 7 years, based on the condition of their
pipelines.
[9] For a discussion on the effect of integrity management on public
safety, see Natural Gas Pipeline Safety: Integrity Management Enhances
Public Safety, but Consistency of Performance Measures Should Be
Improved, GAO-06-946 (Washington, D.C.: Sept. 8, 2006).
[10] In-line inspection involves running a specialized tool through a
pipeline to detect and record anomalies, such as metal loss and damage.
[11] Direct assessment and confirmatory direct assessment involve using
above-ground detection instruments, and then excavating suspected
problem areas.
[12] The Federal Highway Administration estimates the average annual
cost of corrosion to gas and hazardous liquid transmission pipelines at
$7 billion for, among other things, maintenance and failures. See
Federal Highway Administration, Tech Brief: Corrosion Costs and
Preventive Strategies in the United States, study performed by CC
Technologies, March 2002.
[13] Gas transmission pipeline operators and local distribution
companies also operate medium-stress pipelines.
[14] Under its minimum safety standards, PHMSA requires stronger
pipelines in more highly populated areas. In addition, operators are
required to annually evaluate their pipelines for population growth,
which may cause operators to reduce operating pressure or upgrade
pipelines.
[15] The regulatory definition of highly populated or frequently used
area is involved. Some examples of these areas are (1) an area with 20
or more buildings that could be affected by a pipeline incident; (2) a
location where a potential impact of a pipeline rupture contains an
area or open structure that is occupied by 20 or more people on at
least 50 days in a 12-month period (e.g., a camp site); and (3) a
facility occupied by persons that would be difficult to evacuate, such
as a hospital.
[16] A close interval survey is used to assess the coating of covered
pipelines for corrosion damage.
[17] Standards are technical specifications that pertain to products
and processes, such as the size, strength, or technical performance of
a product. National consensus standards are developed by standard-
setting entities on the basis of an industry consensus. For more
details about industry consensus standards, see the National
Association of Corrosion Engineers: Standard Recommended Practice -
Pipeline External Corrosion Direct Assessment (NACE RP002-2002) and the
American Society of Mechanical Engineers: Managing the System Integrity
of Gas Pipelines (ASME B31.8S-2004).
[18] Pipeline conditions and threats change over time. For example,
housing may be built around pipelines, possibly increasing the threat
of excavation damage. Another example is that over time the quality of
the gas being shipped through the pipeline may change and may be more
corrosive.
[19] Cathodic protection involves a small electrical voltage between a
structure and the ground to control corrosion.
[20] As noted earlier, an average of three people have died and eight
have been injured over a 10 1/2-year period, from all causes of natural
gas transmission pipeline incidents.
[21] As noted earlier, product flow and pipeline capacity can be useful
to understand the extent of problems and their effect. However, this
measurement was not practical.
[22] Third-party damage is a significant cause of gas transmission
pipeline incidents. In addition, third-party damage can cause pipeline
dents that may lead to corrosion.
[23] Leaks from gas transmission pipelines can allow methane to escape
into the atmosphere. Methane is a potent greenhouse gas that
contributes to climate change. See U.S. Environmental Protection
Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-
2003, April 2005.
[24] The American National Standards Institute is a private, nonprofit
organization whose mission is to promote and facilitate voluntary
consensus standards and promote their integrity. The Institute does not
approve the technical merits of proposed national standards.
[25] The other 21 operators (1) have not calculated reassessment
intervals; (2) do not intend to, given the prescriptive federal (7
years) or state (5 years in Texas) reassessment requirements; or (3)
did not supply us with information on their reassessment intervals.
[26] See GAO-06-946 for additional information on the results of PHMSA
and state inspections.
[27] INGAA represents the natural gas industry, including transmission
pipeline operators. According to INGAA, it represents virtually all of
the interstate natural gas transmission pipeline companies operating in
the United States. Its members transport over 95 percent of the
nation's natural gas. AGA represents local energy utility companies,
including pipeline companies, which deliver natural gas to homes,
businesses, and industries throughout the United States. According to
AGA, its members account for roughly 83 percent of all natural gas
delivered by the nation's local natural gas distribution companies.
[28] We contacted the Inline Inspection Association, two companies
offering in-line inspection services, and two companies offering direct
assessment services. In our assessment of the public safety effects of
integrity management, we reported that 94 percent of the operators we
contacted had no major concerns about their ability to complete
baseline assessments. (See GAO-06-946.) The difference in these
findings may be due to the fact that operators have 10 years to
complete baseline assessments but must reassess pipeline segments every
7 years or in a shorter period if conditions warrant. The shorter
reassessment period could heighten demand for inspection services and
tools.
[29] Some operators we contacted reported that the cost of using
confirmatory direct assessment as compared with other assessment tools
and the limited time savings before conducting a full assessment as
reasons for not planning to use this method.
[30] According to industry estimates, 35 percent of all local
distribution company pipelines (as measured in miles likely to be
located in highly populated or frequently used areas) cannot
accommodate an in-line inspection tool, compared with only about 4
percent of transmission operators' pipelines.
[31] The 2002 act allows operators to request a waiver from conducting
reassessments when inspection tools are not available. PHMSA
regulations require that operators apply for a waiver when inspection
tools are not available to conduct assessments within the required
reassessment period and that the actions the operator is taking in the
interim ensures the integrity of the pipeline. Environmental
requirements may also affect the scheduling of assessments, repairs and
modifications, and the choice of assessment tools. (See app. I.) Few of
the 52 operators that we contacted mentioned this as a concern.
[32] Although INGAA, AGA, and we collected information differently on
the extent that baseline assessments and reassessments would be
conducted inside and outside highly populated or frequently used areas,
both efforts collected information on overall baseline assessment and
reassessment activity. As a result, the overall results of both efforts
are comparable and are shown in figure 6.
[33] Prepared for The INGAA Foundation, Inc., by Energy and
Environmental Analysis, Inc., Consumer Effects of the Anticipated
Integrity Rule for High Consequence Areas, 2002.
[34] See, Department of Transportation docket, RSPA-00-7666, Energy
Impact Statement for Pipeline Integrity Management in High Consequence
Areas (Gas Transmission Pipelines), March 28, 2002, prepared by John A.
Volpe National Transportation Systems Center and the U.S. Department of
Transportation; Comments from U.S. Department of Energy on INGAA's
Consumer Effects of the Anticipated Integrity Rule for High Consequence
Areas, April 2, 2002; and Research and Special Programs Administration,
Final Regulatory Evaluation, Pipeline Integrity Management in High
Consequence Areas (Gas Transmission Pipelines), March 28, 2002.
[35] The National Petroleum Council also discussed the supply effects
of the integrity management program, including that some pipelines may
be removed from service if it is not economically efficient to repair
them. The council did not estimate the extent that these abandonments
might occur or the resulting price increases, if any. See Balancing
Natural Gas Policy: Fueling the Demands of a Growing Economy Volume V,
Transmission and Distribution Task Group and LNG Subgroup Report,
September 2003.
[36] Higher-stress pipelines operate under pressure at or above 50
percent of the pressure that will cause a pipeline to deform (called
yield strength).
[37] A looping capability involves installing a segment of pipeline
adjacent to an existing pipeline. The segment of pipeline connects to
the existing pipeline at both ends of a loop, which allows more gas to
be moved through the pipeline system.
[38] Lower-stress pipelines operate pressure at or below 30 percent of
a pipeline's yield strength.
[39] A lateral is a segment of a pipeline that branches off of the main
or transmission line to transport the product to a termination point,
such as a tank farm or a metering station.
[40] Over-testing, although not without costs, provides safety benefits
because additional information is collected about the condition of
pipelines. The operators' reports do not indicate which inspection
method was used to conduct the inspections.
[41] Under PHMSA's regulations, an operator must apply for a waiver at
least 180 days before the required reassessment interval, unless
natural gas supply issues make the period impractical. If so, the
operator must apply as soon as the need for the waiver is known.
[42] Eleven operators we contacted did not provide reasons for not
planning to apply for a waiver. One operator reported that it would
wait for regulatory changes for reassessments before applying for a
waiver.
[43] Although interruptible contracts with pipeline operators or local
distribution companies vary in terms and conditions, they generally
allow for service interruptions that are caused by system operating
conditions (e.g., when pipeline pressure is threatened by high rates of
natural gas consumption), among other things.
[44] We did not ask operators about the degree to which they reduced
operating pressure and the reduction in the amount of gas that they
could deliver. Nevertheless, they were able to use alternative sources
to maintain product supply while they made repairs to their pipelines.
[45] According to a Department of Energy official, on-and off-peak
periods vary based on location. For example, in the South, fall and
winter months are often off-peak while the reverse is true in northern
states (e.g., for heating needs).
[46] In its September 2003 report, cited earlier, the National
Petroleum Council estimated that conducting baseline assessments over
10 years, gas transmission pipeline operators will spend about $1.1
billion annually on replacing existing pipeline infrastructure.
[47] In March 2006, PHMSA issued a final rule that requires operators
to use a risk-based approach to determine which onshore gathering
pipelines are subject to PHMSA's gas pipeline safety rules and which of
these rules the lines must meet. The application of these rules may
result in interruption of service to carry out repairs. However, the
rules do not impose requirements for operators to assess their
pipelines in the same manner as the integrity management program.
Therefore, any interruptions caused by the need to carry out repairs
would be the result of normal operation and maintenance activities.
Gathering lines collect natural gas from production facilities and
transport them to transmission or distribution lines. There are about
15,000 miles of onshore gathering lines nationwide.
[48] Complying with environmental laws, such as those dealing with
habitats, may also affect scheduling of modifications and repairs. The
Pipeline Safety Improvement Act of 2002 required the establishment of a
federal interagency committee to develop and ensure implementation of a
coordinated environmental review and permitting process to enable
operators to complete baseline assessments, including pipeline repairs,
with minimal adverse effects to the environment such as harming unique
species or habitat in the specified time periods. The interagency
committee has established a working group to develop a joint regulatory
approach to streamlining. In addition, PHMSA has designed and is
testing a Web-based environmental permit review process to (1) provide
early electronic notification of proposed pipeline repairs to federal
agencies and solicit input from state and local agencies involved in
the review process for pipeline repairs and (2) expedite coordination
and approval of recommended best practices for operators to use to
manage environmental damage when repairing their pipelines in
environmentally important areas.
[49] Results from nonprobability samples cannot be used to make
inferences about a population because, in a nonprobability sample, some
elements of the population being studied have no chance or have an
unknown chance of being selected as part of the sample.
[50] As cited in appendix I.
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