# U.S. DOT/PHMSA - Pipeline Safety: Design and Construction Standards to Reduce Internal Corrosion in Gas Transmission Pipelines - Final Regulatory Evaluation

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- **citation:** 0900006480e93bef
- **title:** U.S. DOT/PHMSA - Pipeline Safety: Design and Construction Standards to Reduce Internal Corrosion in Gas Transmission Pipelines - Final Regulatory Evaluation
- **source type:** rulemaking
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** current
- **official:** true
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- **summary:** F F Fi i in n na a al l l R R Re e eg g gu u ul l la a at t to o or r ry y y E E Ev v va a al l lu u ua a at t ti i io o on n n _______________________________________ Regulatory Assessment with Regulatory Flexibility Analysis Paperwork Reduction Act Analysis Final Regulatory Evaluation Pipeline Safety: Design and Construction Standards to Reduce Internal Corrosion in Gas... F F Fi i in n na a al l l R R Re e eg g gu u ul l la a at t to o or r ry y y E E Ev v va a al l lu u ua a at t ti i io o on n n be designed and constructed with the need to control internal corrosion in mind. This rule addresses the risk of internal corrosion at the earliest stage possible, applying accepted...
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F F Fi i in n na a al l l R R Re e eg g gu u ul l la a at t to o or r ry y y E E Ev v va a al l lu u ua a at t ti i io o on n n
_______________________________________
Regulatory Assessment
with
Regulatory Flexibility Analysis
Paperwork Reduction Act Analysis
Final Regulatory Evaluation
Pipeline Safety: Design and Construction Standards to Reduce Internal
Corrosion in Gas Transmission Pipelines
[Docket No. PHMSA-2005-22642]
March 2007
Prepared by
Economic and Industry Analysis Division
Volpe National Transportation Systems Center
Research and Innovative Technology Administration (RITA)
and
Office of Pipeline Safety
Pipeline and Hazardous Materials Safety Administration (PHMSA)
U.S. Department of Transportation
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F F Fi i in n na a al l l R R Re e eg g gu u ul l la a at t to o or r ry y y E E Ev v va a al l lu u ua a at t ti i io o on n n
Regulatory Analysis
Introduction
The Pipeline and Hazardous Materials Safety Administration (PHMSA) is adopting
regulations on the control of internal corrosion when designing and constructing new and
replaced gas transmission pipelines. The rule requires an operator to consider the
potential for accumulating liquids that could result in internal corrosion and to take steps
in design and construction that would reduce the risk. The rule also requires an operator
to design and construct pipelines to mitigate the impacts of internal corrosion that may
occur. These changes facilitate steps that operators are already required to take in
operating and maintaining their pipelines to prevent or mitigate internal corrosion.
Need for the Action
In 2003, the National Transportation Safety Board (NTSB) recommended the issuance of
Federal design and construction standards for internal corrosion control (see NTSB
recommendation P-03-1). The NTSB recommendation arose out of its investigation of
the August 19, 2000 gas transmission pipeline incident near Carlsbad, New Mexico. The
NTSB concluded that the immediate cause of the Carlsbad incident was a pipeline failure
caused by severe internal corrosion. The NTSB issued a final report, recommending (1)
rulemaking to require that new and replaced gas transmission pipelines be designed and
constructed with features to mitigate internal corrosion; (2) development of requirements
for gas operators to address the role of water in their internal corrosion control programs;
and (3) changes to Federal inspection to ensure adequate assessments of pipeline operator
safety programs. PHMSA has already completed action on the second and third
recommendations. This rule completes action on the first recommendation.
A variety of options exist for the control of internal corrosion. Those options include
controlling the quality of the gas in the pipeline, inspecting the inside of pipe visually,
using ultrasound to ascertain pipe wall thickness, using drips to remove liquids in the gas
stream, using “slam valves” to cut off the flow of gas when high levels of contaminants
are detected, and using alarms to warn when high levels of contaminants are detected.1
To be effective, any drips would need to be drained periodically. A complete internal
control program might use a mix of these options, supplemented and complemented by
other measures, such as cleaning pigs, inhibitors, internal coatings on pipe, and gas
dewatering.2
Currently, pipeline safety regulations found in 49 CFR Part 192 require that operators
establish and implement programs to prevent or mitigate internal corrosion in the
operation and maintenance of gas transmission pipelines. In addition, the recent integrity
management regulations require operators to assess the integrity of their pipelines with
respect to internal corrosion. There are no Federal requirements that require pipelines to
1 NTSB Pipeline Accident Report, NTSB/PAR-03/01, pp. 21, 22.
2 Neil G. Thompson, “Appendix E, Gas and Liquid Transmission Pipelines,” Cost of Corrosion, FHWA
Report FHWA-01-156, April 2005, pp. E-15 to E-16, www.corrosioncost.com/home.html.
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F F Fi i in n na a al l l R R Re e eg g gu u ul l la a at t to o or r ry y y E E Ev v va a al l lu u ua a at t ti i io o on n n
be designed and constructed with the need to control internal corrosion in mind. This
rule addresses the risk of internal corrosion at the earliest stage possible, applying
accepted understandings about the causes and prevention of corrosion. The requirements
of this rule improves the ability of the operator to prevent internal corrosion and
facilitates maintenance activities to control internal corrosion.
Rationale for Regulatory Assessment
All proposed and final Federal regulations must undergo economic analysis. Executive
Order 12866 directs all Federal agencies to develop both preliminary and final regulatory
analyses if their proposed regulations are likely to be “significant regulatory actions” that
may have an annual impact on the economy of $100 million. The Order also requires a
determination as to whether a rule could adversely affect the economy or a section of the
economy in terms of productivity and employment, the environment, public health,
safety, or State, local or tribal governments. In accordance with the regulatory
philosophy and principles provided in Sections 1(a) and (b) and Section 6(a)(3)(C) of
Executive Order 12866, an economic analysis of the regulatory changes must be
conducted. Furthermore, the Regulatory Flexibility Act of 1980, as amended, requires
Federal agencies to conduct a separate analysis of the economic impact of their rules on
small entities.
In accordance with the above directives, PHMSA has performed an evaluation of the
potential compliance costs of the rule and feasible regulatory options and identified those
benefits that can be expressed in monetary terms. To the extent practicable, this is based
on the available data and information from a range of pertinent sources. PHMSA
estimates that the impact of implementing the rule would be less than $100 million
annually, and that the rule would not adversely affect the economy or a section of the
economy in terms of productivity and employment, the environment, public health,
safety, or State, local or tribal governments. The rule is not considered significant under
the Regulatory Policies and Procedures of the Department of Transportation (44 FR
11034, February 26, 1979). PHMSA has also determined, as required by the Regulatory
Flexibility Act, that the rule will not have a significant economic impact on a substantial
number of small entities in the United States.
Alternatives Considered
The goal of this rulemaking is to reduce natural gas transmission system incidents
resulting from internal corrosion. In developing the rulemaking, PHMSA considered the
following two alternatives:
• Do Nothing.
• Amend the pipeline safety regulations to add design and construction standards to
reduce internal corrosion in gas transmission pipelines.
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Given the NTSB’s recommendation P-03-1 concerning adding new regulations requiring
that new or replaced pipelines be designed and constructed in a manner that would
mitigate internal corrosion (see above), and PHMSA’s concurrence with that
recommendation, PHMSA believes that it is necessary and appropriate to pursue a
Federal rulemaking. Therefore, “Do Nothing” is not viewed by PHMSA as a viable
alternative. It is developed no further in this regulatory evaluation.
Economic Analysis
In its rule, Design and Construction Standards to Reduce Internal Corrosion in Gas
Transmission Pipelines, PHMSA is amending 49 CFR Part 192 by adding a new section,
§ 192.476, mandating that operators consider internal corrosion risk when designing and
constructing gas transmission pipelines. The new section will include the following:
• Performance tests for design and construction measures to control internal
corrosion.
• A requirement that an operator consider whether it should install liquid removal
equipment or corrosion monitoring devices on existing pipeline downstream of
new or replaced pipeline.
• A requirement that an operator record the decisions it makes with respect to
internal corrosion control when designing and constructing pipelines.
In the remainder of this section, the impacted industry is identified, and then the
economic impact of the rule will be considered.
Impacted Industries, Including Identification and Characteristics of the Potentially
Affected Industries
The rule will apply to new or replaced pipe and components on all natural gas
transmission pipelines whose safety is regulated under 49 CFR Part 192. In addition, the
requirements will apply to gathering lines. The operators of natural gas transmission
pipelines are generally large firms. The operators of gathering lines are not, however
(i.e., some are small entities).
The following table shows the salient characteristics of the natural gas transmission
pipelines impacted by the rule.
Table 3. Salient Characteristics of Natural Gas Transmission Pipelines and
Gathering Lines
Characteristic Value
Number of operators 1390
Total onshore natural gas transmission and
gathering pipeline mileage
300,755
Estimated onshore annual new and 2,096*
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replacement mileage – transmission
Estimated onshore annual new and
replacement mileage – gathering lines
166*
Total annual new and replacement mileage
expected to be impacted by the rule
2,262*
*Based on mileage information submitted by 1390 pipeline operators in their
2005 annual reports to PHMSA.
Source: PHMSA, 2005 Annual reports for gas transmission and gathering
systems PHMSA 7100.2-1
The rule will not impact the full 300,755 miles of onshore natural gas transmission and
gathering lines estimated to in operation. Rather, only new or replaced pipeline will be
subject to the rule. To estimate the new and replacement mileage information in Table 3,
this analysis used the total mileage of onshore transmission pipes installed during 2000-
2005 from the annual reports and the total mileage of onshore gathering lines during
2000-2005, and assumed that, on average, operators would continue to add or replace
pipes at the same rate in future. Total onshore transmission pipe installed during 2000-
2005 was reported as 12,578 miles, so the average installed each year over the six-year
period from 2000 through 2005 was 2,096 (= 12,578 / 6). Total onshore gathering line
pipe installed during 2000-2005 was reported as 999 miles, so the average installed each
year over the six-year period from 2000 through 2005 was 166 (= 999 / 6). The analysis
assumed that these mileages represent onshore new or replacement pipes for transmission
and gathering systems, respectively. In total, the estimated additional onshore
transmission plus gathering line mileage that would annually become subject to the rule
would be 2,262 miles (= 2,096 miles + 166 miles). It should be noted that, with each
2,262 mile increment, more and more pipeline would become subject to the rule over
time.
Impact of the Rule
PHMSA’s new rule will impact the internal corrosion control activities of gas
transmission and gathering lines. Those activities make pipeline operations safer by
helping to reduce the number of incidents. The rule may result in added costs related to
internal corrosion control that would be borne by pipeline operators and added benefits
that include a reduction in the number of incidents. The rule should also facilitate future
operation and maintenance efforts on the new and replaced lines that have been designed
with corrosion in mind.
Costs
The costs attributable to the rule will be any associated with
• The design and construction of new and replaced pipeline to control internal
corrosion,
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• Operation and maintenance activities required due to designing pipeline to control
internal corrosion,
• Actions taken to modify existing pipeline downstream of and impacted by new or
replaced pipeline, and
• Recordkeeping.
The remainder of this cost section addresses the costs related to pipeline design,
construction, downstream modification, and record keeping.
Design – The costs attributable to designing new or replaced pipeline to meet the
prevention and mitigation requirements of the rule will be nominal. When pipeline
operators add or replace pipeline, they already go through a design process, and the
design teams include individuals with corrosion expertise. There is no evidence to
indicate that mandating the inclusion of internal corrosion prevention and mitigation in
the design of a pipeline will materially impact the cost of this process.
Construction3 – The costs attributable to constructing new or replaced pipeline that meets
the prevention and mitigation requirements of the rule are unknown. They could vary
from $0 on up, depending on such things as the nature of the gas that would be
transported, the terrain, and control and monitoring devices, if any, that would be used.
Most new or replaced pipeline would be constructed exactly as it would have in the
absence of the rule, because terrain and operating conditions are similar to adjoining
pipeline, and internal corrosion is not a high risk threat for that adjoining pipeline. For
pipeline that is constructed differently than it would have been in the absence of the rule,
the changes are expected to be relatively minor (e.g., the addition of drips at strategic
locations). These relatively minor changes are expected to result in equally minor
additions to construction costs. For the purposes of this analysis, the construction costs
attributable to the new rule are assumed to be minimal.
Operation and Maintenance – The operation and maintenance (O&M) costs attributable
to operating new or replaced pipeline that meets the prevention and mitigation
requirements of the rule are unknown. Most new or replaced pipeline would be operated
and maintained exactly as it would have been in the absence of the rule, because terrain
and operating conditions are similar to adjoining pipeline, and internal corrosion is not a
high risk threat for that adjoining pipeline. Changes in O&M due to the rule are expected
to be relatively minor (e.g., if the rule results in the addition of a drip on a new or
replaced line, then an O&M impact would be that the drip would need to be cleaned
periodically). The changes in O&M due to the rule are expected to result in relatively
minor additional costs. For the purposes of this analysis, O&M costs attributable to the
new rule are assumed to be minimal.
Downstream Modification – The costs attributable to modifying existing downstream
pipeline that may be impacted by new or replaced pipeline are unknown. The rule
requires consideration of the impact on downstream pipeline. It is left up to the operator
3 For an overview of the construction process applicable to transmission pipelines, see
primis.phmsa.dot.gov/pipelineInfo/const_overview.htm.
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to decide whether to make any modifications. Presumably, that would be a business-
based decision that would have been the same even in the absence of the rule. For the
purposes of this analysis, the modification costs attributable to the new rule are assumed
to be minimal.
Recordkeeping –Records relating to pipeline design, construction, operation, and
maintenance are already being kept by operators. Prudent business practice requires that
pipeline operators keep pipeline design and construction records. Those records are
created for design and construction purposes, of course, but could satisfy the
requirements of the rule with minimal, if any, additional burden to the industry.
The recordkeeping requirements currently included in 49 CFR Part 192 apply to all
operators transporting natural and other gas by pipeline under PHMSA jurisdiction.
Those requirements cover at least some of the records that would need to be kept under
the proposed regulations. For instance, 49 CFR 192.605(b)(3) requires procedures be
established for “[m]aking construction records…available to appropriate operating
personnel.” To do this, of course, those construction records must be maintained by
operators already. Additionally, 49 CFR 192.491 requires the maintenance of records
“…to demonstrate the adequacy of corrosion control measures or that a corrosive
condition does not exist.” Therefore, existing recordkeeping requirements will also help
minimize the additional burdens, if any, of the rule.
As a consequence of the foregoing, PHMSA expects the costs, if any, associated with the
recordkeeping requirements of the proposed regulations to be nominal.
Overall – Overall, it is assumed that the costs attributable to the rule will be minimal.
The corrosion control requirements embodied in the rule would function primarily as a
reminder of the importance of corrosion control, particularly control of corrosion due to
liquids. It would heighten the awareness of operators to the problem of internal
corrosion. Prudent business practices should already encourage operators to make all
reasonable efforts to control internal corrosion. This would prevent accidents, protect the
operator’s investment, improve reliability of the line, and reduce future maintenance
costs.
Benefits
The benefits of the rule will include a reduction in the direct consequences of internal
corrosion incidents (i.e., a reduction in the deaths, injuries, property damage, and lost
product directly attributable to internal corrosion incidents). It will also include other
savings, such as those related to making future maintenance easier, increasing the
operational life of pipe, and avoiding economic consequences of accident-induced supply
restrictions,4 legal costs,5 and reduced emergency response costs. In this analysis,
however, only the expected reduction in the direct consequences is estimated.
4 Final Regulatory Evaluation, Pipeline Integrity Management in High Consequence Areas (Gas
Transmission Pipelines),” Docket RPSA-00-7666, for instance, estimated that, as a result of the Pipeline
Integrity Management in High Consequence Areas regulations, approximately $1 billion would be saved
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Fuel Regulatory Evaluation
damage are included in the table.
Table 4: Summary of Internal Corrosion Incident Consequences on Natural Gas
Transmission Pipelines, 2000 through 2005
Year
Number of
Property
Injuries
Deaths
incidents
damage
Transmission
2000
5
$1,479,196
0
2001
3
$1,015,850
2002
3
$557,683
2003
3
$6,045,720
2004
2
$149,758
2005
3
$282,034
Gathering
2000
3
$172,000
0
2001
3
$2,000,000
0
2002
1
$45,000
0
2003
1
$127,000
0
2004
1
$600,000
0
2005
2
$718,500
0
0
Compressor Stations
2000
0
2001
0
0
2002
0
0
0
2003
2
$7,363,000
0
0
2004
0
0
2005
0
Total - All Categories
2000
8
$1,651,196
0
0
2001
6
$3,015,850
0
2002
4
$602,683
0
2003
6
$13,535,720
2004
3
$749,758
0
2005
5
$1,000,534
0
0
Source: PHMSA, transmission system incident reports
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The values for 2000, it might be noted, include the internal corrosion incident that
occurred at Carlsbad, New Mexico, on an El Paso Natural Gas pipeline.
the value of a statistical life and the value of an injury requiring hospitalization:
The Department of Transportation currently makes the following assumptions concerning
•
The value of a statistical life is $3,000,000
• Injuries requiring hospitalization are valued at $562,500.°
incident is assumed to be valued at $431 thousand.?
In addition, for the purposes of this analysis, the natural gas lost as a result of a reportable
On average over the six-year period from 2000 through 2005, the direct consequences of
internal corrosion incidents on 300,755 miles of onshore transmission and gathering
pipelines cost $40 per mile per year.®
The proportion of the direct incident consequences that the rule will prevent is unknown.
For the purposes of this analysis, it is assumed that the rule will prevent between 50 and
100 percent of the direct incident consequences. If 50 percent of the direct incident
consequences are avoided, then the benefits of the rule will be $4.0 million over the first
20 years. If 100 percent of the incident consequences are avoided, then the benefits of
the rule will be $8.0 million over the first 20 years.? Thus, it is estimated that the benefits
resulting from the rule will be between $4.0 million and $8.0 million over the first 20
years after the rule is issued. This represents the savings attributable only to reduced
direct incident consequences, it should be noted."°
Comparison of Benefits and Costs
As stated above, the proposed regulatory change is assumed to result in minimal costs.
Benefits are estimated at between $4.0 million and $8.0 million over the first 20 years
' The average injury requiring hospitalization is assumed to be a "Severe injury," as defined by the U.S.
times the cost to society of a lost life.
Department of Transportation. The cost to society of a "Severe injury" is assumed to be equal to 0.1875
' Neil G. Thompson, "Appendix E, Gas and Liquid Transmission Pipelines," estimates that a corrosion
incident results in lost product valued at between $287 thousand and $574 thousand. The $431 thousand
" In deriving this estimate, the property damage reported in Table 4 was deflated using the Producer Price
estimate used here is midway between these two values.
Index, All Commodities, Base=2004. The source of the price index information used here was U.S.
which can be found at www.bls.gov/ro9/9320.pdf.
Department of Labor, Bureau of Labor Statistics, Producer Price Index, All Commodities, 1982=100,
1° It might be noted that, if only transmission and gathering line incidents were to be used in this analysis,
° This is the net present value of avoided direct consequences calculated using a 7 percent discount rate.
then the estimated monetized benefits would be between $3.6 million and $7.2 million. If only
between $2.8 million and $5.5 million. These estimates were calculated for the first 20 years after
transmission incidents were to be used in this analysis, then the estimated monetized benefits would be
implementation of the proposed rule using a 7 percent discount rate.
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following implementation of the rule. These benefits focus exclusively on avoided direct
consequences of incidents (i.e., deaths, injuries, property damage, and lost product), and
do not include other potential benefits, such as avoided economic consequences of
accident-induced supply restrictions, avoided legal costs, reduced emergency response
costs, or increased operational life of pipe.
For the rule not to be cost-beneficial, costs would need to be approximately $753
thousand per year. This would result in total costs in excess of the $8.0 million upper
limit on benefits. They would need to be approximately $377 thousand per year to be in
excess of the $4.0 million lower limit on benefits.11
Conclusion
PHMSA believes that the rule represents the most cost-effective alternative for ensuring
internal corrosion control on gas transmission pipelines. Furthermore, PHMSA expects
that the rule would have a positive net benefit for pipeline operators, public safety, and
the public environment.
11 For this comparison, it is assumed that all costs are incurred in the year in which new or replaced pipeline
is installed. O&M costs, if any, may be incurred in subsequent years, but it is not possible to say what
those recurring O&M costs might be.
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Regulatory Flexibility Analysis
The Regulatory Flexibility Act (5 U.S.C. 601 et seq.) requires an agency to review
regulations to assess their impact on small entities unless the agency determines that a
rule is not expected to have a significant impact on a substantial number of small entities.
The design and construction standards rule would not have a significant impact on a
substantial number of small entities.12
Need for the Final Rule: PHMSA presently has regulations relating to internal corrosion
prevention applicable to natural gas transmission pipeline operators. Those regulations
are found in 49 CFR 192. PHMSA believes that additional regulations enhancing these
existing regulations are necessary to give further guidance to pipeline operators.
Description of Actions: In the Notice of Propose Rulemaking, PHMSA is proposing to
amend the Federal pipeline safety regulations by requiring operators to consider the
control of internal corrosion when designing and constructing new and replaced gas
transmission pipelines.
Identification of potentially affected small entities: For the purposes of the current
analysis, it is assumed that the proposed changes in the regulations would impact an
estimated of 1390 operators. Those operators consist of gas transmission and gathering
systems. Of the gas transmission system operators impacted by the rule, none are small
entities. Some gas gathering system operators may be small entities. The exact number
of gas gathering system operators that are small business according to the Small Business
Administration’s threshold of $6 million in revenue or 1,500 in employee size is
unknown, but it is not substantial.
Compliance, reporting, and recordkeeping requirements: This Notice of Proposed
Rulemaking includes new compliance requirements. Impacted pipeline operators would
be required to consider the potential that accumulating liquids could result in internal
corrosion and to take steps during design and construction that would reduce the risk.
Prevention and mitigation on the new or replaced pipeline, and the impact of the actions
taken on downstream pipeline must all be considered. Operators must document all
design and construction decisions relating to the prevention and mitigation of internal
corrosion. The costs of these actions are expected to be minimal.
Related Federal rules and regulations: Existing rules relating to internal corrosion
prevention on gas transmission pipelines can be found in 49 CFR 192. With respect to
the safety of the transportation of natural gas by pipeline there are no related rules or
regulations issued by other departments or agencies of the Federal Government.
12 As defined by the Small Business Administration, small entities in the pipeline industry, have either
fewer than 500 employees or less than $6 million in revenue, depending on the particular NAICS (North
American Industry Classification System) industry into which the entity falls. For more information, see
www.sba.gov/size/index.html.
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Alternate proposals for small businesses: The Regulatory Flexibility Act directs agencies
to establish exceptions and differing compliance standards for small businesses, where it
is possible to do so and still meet the objectives of applicable regulatory statutes. In the
case of corrosion prevention, no exceptions for small businesses are proposed.
Conclusion: Based on available information, it can be concluded that, this Notice of
Proposed Rulemaking does apply to some small entities (i.e., to some gas gathering
system operators), but it would not result in a significant economic impact on any small
entities.
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