# U.S. DOT/PHMSA - Regulatory Assessment with Regulatory Flexibility Analysis Paperwork Reduction Act Analysis

- **operation:** document
- **citation:** 0900006480e93bf1
- **title:** U.S. DOT/PHMSA - Regulatory Assessment with Regulatory Flexibility Analysis Paperwork Reduction Act Analysis
- **source type:** rulemaking
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** current
- **official:** true
- **published on:** Not available
- **effective on:** Not available
- **summary:** Document scope: Draft Regulatory Evaluation for PHMSA’s proposed amendment to 49 CFR Part 192 (adding § 192.476) requiring operators to consider and document internal corrosion prevention and mitigation when designing and constructing new and replaced gas transmission and gathering pipelines (passages: regulations-gov-attachment-0900006480e93bf1-node-1; node-4; node-5; node-11).
Material conclusions and findings reported in the document: PHMSA estimates the rule’s annual impact would be less than $100 million and that it would not have significant adverse effects on the economy or a substantial number of small entities (passage: node-4; node-11). The analysis assumes costs attributable to the proposed rule would be minimal (passages: node-6; node-7). Estimated benefits from avoided direct incident consequences are between $7.8 million and $15.7 million over the first 20 years (passage: 0
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_______________________________________
Regulatory Assessment
with
Regulatory Flexibility Analysis
Paperwork Reduction Act Analysis
Draft Regulatory Evaluation
Notice of Proposed Rulemaking--Pipeline Safety: Design and Construction
Standards to Reduce Internal Corrosion in Gas Transmission Pipelines
[Docket No. PHMSA-2005-22642]
October 2005
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 (PHMS0A)
U.S. Department of Transportation
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Drait Regulatory Impact Assessment
Regulatory Analysis
Introduction
The Pipeline and Hazardous Materials Safety Administration (PHMSA) is proposing
regulations on the control of internal corrosion when designing and constructing new and
replaced gas transmission pipelines. The proposed rule would require 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 proposed rule
would also require an operator to design and construct pipelines to mitigate the impact
of internal corrosion that may occur. These proposed changes would facilitate steps tha
operators are already required to take in operating and maintaining their pipelines to
prevent or mitigate internal corrosion.
Need for the Action
Internal corrosion has been one of the three leading causes of reportable incidents in gas
transmission pipelines for the past five years, both in terms of percentage of incidents and
their consequences (see Tables 1 and 2). In fact, in 2003 and 2004, internal corrosion
caused more property damage than the other two most frequent causes, third party
excavation damage and external corrosion, combined.
Table 1: Percentage of Total Natural Gas Transmission System Incidents for the
Three Leading Causes
Cause / Year
2000
2001
2002
2003
2004
2005**
(% of Total Incidents)
External corrosion
18
8
9
12
12
10
Internal corrosion
20
19
Excavation damage
25*
43*
18
21
*In 2000 and 2001, number includes all incidents attributable to outside force damage plus
** 2005 data reported as of 10/14/2005.
excavation damage.
Source: PHMSA, Incident Reporting Form 7100.2
Data as of 10/14/2005
Table 2: Amount of Property Damage for Gas Transmission System Incidents for
the Three Leading Causes (in Millions of Dollars)
Cause / Year
2000
2001
2002
2003
2004
2005**
(in Million $)
External corrosion
$3.5
$2.0
$4.1
$8.4
$1.6
$88.7
Internal corrosion
$2.6
$3.3
$4.0
$14.9
$4.9
$4.2
Excavation damage
$3.2*
$14.9*
$1.1
$3.5
$2.4
$1.3
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*In 2000 and 2001, number includes all incidents attributable to outside force damage plus
excavation damage where appropriate.
** 2005 data reported as of 10/14/2005. A single incident in 2005 caused $87.5 million in
property damage.
Source: PHMSA, Incident Reporting Form 7100.2
Data as of 10/14/2005.
.
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
be designed and constructed with the need to control internal corrosion in mind.
Including such requirements would facilitate corrosion control measures in an operating
pipeline. In addition, the National Transportation Safety Board recommended the
issuance of Federal design and construction standards for internal corrosion control.
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 proposed 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 proposed 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 proposed rules
on small entities.
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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In accordance with the above directives, PHMSA has performed a preliminary evaluation
of the potential compliance costs of the proposed 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. This proposed 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 proposed rule would 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.
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 proposed 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 would 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.
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• 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 would be identified, and then the
economic impact of the proposed rule would be considered.
Impacted Industries, Including Identification and Characteristics of the Potentially
Affected Industries
The proposed rule would 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 would 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 proposed rule.
Table 3. Salient Characteristics of Natural Gas Transmission Pipelines and
Gathering Lines
Characteristic Value
Number of operators 903
Total natural gas transmission and gathering
pipeline mileage
322,836*
Estimated onshore annual new and
replacement mileage
2,506*
Estimated offshore annual new and
replacement mileage
325*
Total annual new and replacement mileage
expected to be impacted by the proposed rule
2,831
*Mileage information submitted by 903 operators in 2004 Annual report
submitted in 2005.
Source: PHMSA, 2004 Annual reports for gas transmission and gathering
systems PHMSA 7100.2-1
The proposed rule would not impact the full 322,836 miles of natural gas transmission
and gathering lines. Rather, only new or replaced pipeline would be subject to the
proposed rule. To estimate the new and replacement mileage information in Table 3, this
analysis used the total mileage of onshore and offshore pipes installed during 2000-2004
from the annual reports and assumed that, on average (total mileage divided by 5 years
2000-2004) operators would continue to add or replace pipes at the same rate in future.
For example, total onshore transmission and gathering lines installed during 2000-2004
were reported as 12,530 miles. The analysis assumed that during the period 2000-2004
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this mileage represents the new or replacement pipes. Therefore, on average 12,530/5 or
2,506 per year is the estimated onshore transmission plus gathering miles that would be
subject to the proposed rule. Similarly, 1,624 miles of offshore transmission and
gathering lines were installed during this period (2000-2004), therefore, 1,624/5 or 325
miles per year of offshore transmission and gathering lines would be subject to the
proposed rule. The total annual estimate is the sum of the onshore and offshore annual
estimates of natural gas transmission and gathering miles or (2,506+325) = 2,831 miles of
new or replacement pipes per year.
Impact of the Proposed Regulations
PHMSA’s proposed rule would 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 regulations proposed by PHMSA 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
regulations 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 proposed rule would be any associated with
• The design and construction of new and replaced pipeline to control internal
corrosion,
• 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
• Record keeping.
The remainder of this cost section addresses the potential 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 proposed rule would 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 would 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 proposed rule are unknown. They
could vary from $0 on up, depending on such things as the nature of the gas that would
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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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 proposed 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 proposed 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 proposed rule are unknown. Most new or replaced pipeline would be
operated and maintained exactly as it would have been in the absence of the proposed
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 proposed rule are expected to be relatively minor (e.g., if the proposed 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
proposed 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 proposed
rule requires consideration of the impact on downstream pipeline. It is left up to the
operator 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
proposed rule. For the purposes of this analysis, the modification costs attributable to the
new rule are assumed to be minimal.
Record keeping – The cost of record keeping resulting from the proposed regulation
would be nominal, if any. Records relating to pipeline design, construction, operation,
and maintenance are already being kept by operators. 49 CFR Part 192 recordkeeping
requirements currently apply to all operators transporting natural and other gas by
pipeline under PHMSA jurisdiction. Prudent business practice also requires that pipeline
operators keep pipeline design and construction records. Those records would be created
for design and construction purposes, of course, but could satisfy the requirements of the
NPRM with minimum, if any, additional burden to the industry. Additionally, 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. Furthermore, 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” is required. Therefore
existing recordkeeping requirements would support additional burdens, if any, of this
NPRM.
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Overall – Overall, it is assumed that the costs attributable to the proposed rule would be
minimal. The corrosion control requirements embodied in the proposed 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 proposed rule would 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 would 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.
Table 4 presents a summary of the reported internal corrosion incident consequences on
natural gas transmission pipelines from 2000 through 2004.
Table 4: Summary of Internal Corrosion Incident Consequences on Natural Gas
Transmission Pipelines, 2000 to 2004
Year Number of
Property
Injuries Deaths
incidents
damage
(millions of $)
2000 16 $2.6 2 12
2001 9 $3.3 0 0
2002 15 $4.0 0 0
2003 13 $14.8 0 0
2004 23 $4.9 0 0
Source: PHMSA, ops.dot.gov/stats/stats.htm.
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.
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
over 20 years as a result of reduced economic consequences of accident-induced supply restrictions.
5 Neil G. Thompson, “Appendix E, Gas and Liquid Transmission Pipelines,” estimates that “[l]egal issues
and liabilities” add between $100 million and $200 million per fatality and injury to the costs associated
with pipeline corrosion incidents.
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The Department of Transportation currently makes the following assumptions concerning
the value of a statistical life and the value of an injury requiring hospitalization:
• The value of a statistical life is $3,000,000
• Injuries requiring hospitalization are valued at $562,500.6
In addition, for the purposes of this analysis, the natural gas lost as a result of a reportable
incident is assumed to be valued at $431 thousand.7
On average over the period from 2000 through 2004, the direct consequences of internal
corrosion incidents on gas transmission pipelines cost $0.06 million per thousand miles
per year.8
The proportion of the direct incident consequences that the proposed rule would prevent
is unknown. For the purposes of this analysis, it is assumed that the proposed rule would
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 proposed rule would
be $7.8 million over the first 20 years. If 100 percent of the incident consequences are
avoided, then the benefits of the proposed rule would be $15.7 million over the first 20
years.9 Thus, it is estimated that the benefits resulting from the proposed rule would save
between $7.8 million and $15.7 million over the first 20 years after the proposed rule is
issued. This represents the savings attributable only to reduced direct incident
consequences.
Comparison of Benefits and Costs
As stated above, the proposed regulatory change is assumed to result in minimal costs.
Benefits are estimated at between $7.8 million and $15.7 million over the first 20 years
following implementation of the proposed 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.
6 The average injury requiring hospitalization is assumed to be a “Severe injury,” as defined by the U.S.
Department of Transportation. The cost to society of a “Severe injury” is assumed to be equal to 0.1875
times the cost to society of a lost life.
7 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
estimate used here is midway between these two values.
8 In deriving this estimate, the property damage reported in Table 4 was the Producer Price Index, All
Commodities, Base=2004. The source of the price index information used here was U.S. Department of
Labor, Bureau of Labor Statistics, Producer Price Index, All Commodities, 1982=100, which can be found
at www.bls.gov/ro9/9320.pdf.
9 This is the net present value of avoided direct consequences calculated using a 7 percent discount rate.
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For the proposed rule not to be cost-beneficial, costs would need to be in excess of $1.48
million per year. This would result in total costs in excess of the $15.7 million upper
limit on benefits. They would need to be approximately $736 thousand per year to be in
excess of the $7.8 million lower limit on benefits.10
Conclusion
PHMSA believes that the proposed rule represents the most cost-effective alternative for
ensuring internal corrosion control on gas transmission pipelines. Furthermore, PHMSA
expects that the proposed rule would have a positive net benefit for pipeline operators,
public safety, and the public environment.
10 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.11
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 903 operators. Those operators consist of gas transmission and gathering
systems. Of the gas transmission system operators impacted by the proposed 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.
11 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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