Preliminary Regulatory Impact Analyses

# 

Pipeline Safety: Integrity Management Program for Gas Distribution
Pipelines

**Office of Pipeline Safety**

**Pipeline and Hazardous Materials Safety Administration (PHMSA)**

**U.S. Department of Transportation**

June 17, 2008

TABLE OF CONTENTS

**Executive Summary [2](#executive-summary)**

1\. INTRODUCTION [4](#introduction)

2\. BACKGROUND [5](#background)

3\. REGULATORY ANALYSIS [6](#regulatory-analysis)

4\. IDENTIFICATION OF THE PROBLEM AND THE NEED FOR THE RULE
[6](#identification-of-the-problem-and-the-need-for-the-rule)

5\. IDENTIFICATION OF AVAILABLE ALTERNATIVE APPROACHES
[9](#identification-of-available-alternative-approaches)

6\. INDUSTRY INFORMATION [14](#industry-information)

7\. DEFINITION AND EVALUATION OF THE BENEFITS AND COSTS OF THE PROPOSED
ACTION
[16](#definition-and-evaluation-of-the-benefits-and-costs-of-the-proposed-action)

8\. UNCERTAINTY ANALYSES [57](#uncertainty-analyses)

9\. SUMMARY AND CONCLUSIONS [61](#summary-and-conclusions)

Regulatory Flexibility Analysis [63](#regulatory-flexibility-analysis)

#   {#section-1 .unnumbered}

# Executive Summary

The Pipeline and Hazardous Materials Safety Administration (PHMSA)
proposes to amend the Federal Pipeline Safety Regulations to require
operators of gas distribution pipelines to develop and implement
Integrity Management Programs (IMPs). The purpose of these programs is
to enhance safety by identifying and reducing pipeline integrity risks.
Societal costs associated with hazards and incidents related to gas
distribution systems addressed by the rule are approximately \$1 billion
per year. If these changes are implemented, there will be benefits due
to a reduction in deaths, injuries, and property damages associated with
gas distribution systems.

This rule proposes IMPs similar to those required for gas transmission
pipelines, but tailored to reflect the differences in and among
distribution systems. PHMSA proposes to require operators of gas
distribution pipelines to develop and implement IMPs that will better
assure the integrity of their pipeline systems. Each IMP must contain
the following elements:

-   Improving knowledge of the system's infrastructure

-   Identifying threats (existing and potential)

-   Evaluating and prioritizing risks

-   Identifying and implementing measures to mitigate risks

-   Measuring performance, monitoring results, and evaluating
    effectiveness

-   Periodic re-evaluation and improvement

-   Reporting results

All of the above elements pertain to distribution operators with the
exception of master meter and liquid petroleum gas (LPG) distribution
systems. To minimize regulatory burdens, the proposed rule establishes
simpler requirements for master meter and LPG operators, reflecting the
relatively lower risk posed by these small pipeline systems. This
proposal also addresses statutory mandates and recommendations from the
Department of Transportation's (DOT) Office of the Inspector General
(OIG) and stakeholder groups.

These analyses find that the proposed rule is not expected to adversely
affect the economy or the environment. The analysis finds that, for
those costs and benefits that can be quantified, the present value of
net benefits are expected to be between \$1.5 billion and \$2.8 billion
over a 50-year period after all of the requirements are implemented.
Furthermore, the proposed rule is expected to be cost-effective if it
results in eliminating only approximately 14.5 percent of the societal
costs associated with gas distribution systems. The estimated monetary
cost of the rule is \$155 in the first year and about \$104 million per
year after the first year, while the estimated monetary benefits are
\$214 million per year. Therefore, DOT has classified this rulemaking as
an economically significant regulatory action under Section 3(f)(1) of
Executive Order 12866, and a significant regulatory action under the
DOT's regulatory policies and procedures (44 FR 11034). There is
substantial congressional, industry, and public interest in the rule.
The proposed rule will serve to standardize industry practices, so that
all pipelines operate under the same uniform standard.

Based on this analysis, PHMSA has also determined that the proposed rule
would impose expenditures in excess of \$132 million on State, local, or
tribal governments or the private sector in the first year.

PHMSA has also estimated, as required by the Regulatory Flexibility Act
(RFA), that the proposed rule would have an impact on a substantial
number of small entities in the United States. PHMSA estimates that
1,007 local gas distribution utilities and 8,000 master meter operators
will be impacted by the proposed rule. PHMSA cannot estimate what
percent of revenues the costs of the proposed rule represent, since the
Agency does not have information on operators' revenues. The costs
associated with the proposed rule may be significant for at least some
of the small entities. Therefore, PHMSA assumes that the proposed rule
could result in a significant adverse economic impact for some of the
smallest affected entities. PHMSA invites comments on these assumptions.
We have included a Regulatory Flexibility Analysis which discusses these
issues.

# 1. INTRODUCTION

The Pipeline and Hazardous Materials Safety Administration (PHMSA) has
issued Integrity Management Program (IMP) regulations for operators of
hazardous liquid pipelines (49 CFR 195) and gas transmission pipelines
(49 CFR Part 192, Subpart O). Those regulations require operators to
continually assess, evaluate, repair, and validate through comprehensive
analysis, the integrity of pipeline segments and take actions to address
applicable threats and integrity concerns. Similar regulations do not
currently exist for gas distribution pipelines.

PHMSA proposes to revise the Pipeline Safety Regulations to require
operators of gas distribution pipelines to develop and implement
programs that will better assure the integrity of their pipeline
systems. The proposed regulations require distribution pipeline
operators to implement an IMP similar to those required for gas
transmission pipelines. The proposed regulation requires that the IMPs
contain the following elements:

a)  *Improving knowledge of the system's infrastructure*. An operator's
    integrity management program must demonstrate the operator
    understands its gas distribution system including factors such as:
    location, material composition, piping sizes, construction methods,
    date of installation, soil conditions, pressure (operating and
    design), operating experience, performance data, condition of the
    system, and any other characteristics important to a thorough
    understanding of applicable threats and their contribution to risks.

b)  *Identifying threats (existing and potential).* The operator must
    identify existing and potential threats that apply to its pipeline.
    The operator must consider, at minimum, the following categories of
    threats to each gas distribution pipeline: corrosion, natural
    forces, excavation damage, other outside force damage, material or
    welds, equipment, operations, and any other concerns that may
    threaten the integrity of the pipeline.

c)  *Evaluating and prioritizing risk.* An operator must evaluate the
    risk associated with its distribution pipeline system. This
    evaluation must consider each of the applicable existing and
    potential threats.

d)  *Identifying and implementing measures to mitigate risks.* An
    operator must determine and implement measures designed to reduce
    the risk of each identified threat.

e)  *Measuring performance, monitoring results, and evaluating
    effectiveness.* An operator must develop and monitor performance
    measures, from an established baseline, to evaluate the
    effectiveness of its integrity management program.

f)  *Continual re-evaluation and improvement.* The operator must
    re-evaluate threats and risks periodically.

g)  *Reporting results.* The operator must report annually to PHMSA some
    of the performance measurements resulting from the element:
    *Measuring performance, monitoring results, and evaluating
    effectiveness.*

All of the above elements pertain to distribution operators with the
exception of master meter and liquified petroleum gas (LPG) distribution
systems. For master meter and LPG systems the proposal would have their
programs include all of the elements listed above except (1) evaluating
and prioritizing risks and (2) reporting results.

In addition, the proposed rule requires the installation of excess flow
valves (EFVs) on all new and renewed single family residential services
operating at least 10 pounds per square inch gauge (psig), as long as
certain operating conditions are met. Master meter and LPG systems would
be exempt from this requirement. The proposed mandatory installation
renders the current customer EFV notification requirement (see 49 CFR
192.383) moot. Consequently, the proposed rule would repeal that
requirement.

Incidents and accidents associated with gas distribution pipeline
systems result on average every year in over 10 fatalities, over 40
serious injuries, and tens of millions of dollars of property damages.
Also, each year hundreds of millions of dollars of gas is lost due to
leaks in the system. The purpose of this regulation is to address the
hazards that lead to those incidents as well as reduce gas loss by
including leak management, damage prevention, and excess flow valve
provisions. In this report, the benefits and costs of the proposed
regulatory changes are examined, as required by EO 12866 and the
Unfunded Mandates Reform Act. Additionally, the report includes the
analysis required by the Regulatory Flexibility Act.

[]{.mark}

# 2. BACKGROUND

[]{.mark}

The Nation's existing pipeline infrastructure, much of which is over 50
years old, requires regular safety and environmental reviews to ensure
its reliability and integrity. To improve safety and to address several
statutory mandates and National Transportation Safety Board (NTSB)
recommendations, PHMSA established Integrity Management requirements in
years 2000 and 2002, for operators of hazardous liquid pipelines (49 CFR
195.452).

Subsequently, PHMSA issued IMP regulations for gas transmission
pipelines in December 2003 (49 CFR Part 192, Subpart O). Both the
hazardous liquid and gas transmission pipeline IMP regulations require
operators to analyze risks and focus increased attention on safety,
especially the portions of their pipeline that pose the highest risk.
This increased attention must include physical inspection (assessment)
of the pipe using in-line inspection, pressure testing, or direct
assessment, remediation of anomalous conditions following the
assessment, continual evaluation of the pipeline, application of
additional preventive and mitigative measures, and development of
performance measures.

Current IMP regulations, however, do not apply to gas distribution
pipelines. Gas distribution pipelines deliver gas to residences and
other end users and are different from hazardous liquid and gas
transmission pipelines. Distribution systems are comprised of a grid of
"mains" and "service lines." A main is a pipeline that serves as a
common source of supply for multiple customers, often located under
municipal streets that may be in heavily populated or congested areas.
Service lines transport gas from the mains to the meters or
customer-owned piping of residential, commercial, and industrial
customers. Distribution pipelines can measure as large as 36 inches in
diameter; however, most are much smaller, ranging in size from one-half
inch service lines to 8 inches in diameter for mains. These pipelines
generally operate at lower pressures than the transmission pipelines and
are owned and operated by local distribution companies. Distribution
pipelines are constructed of a variety of materials, both metallic and
non-metallic. Approximately half of the pipe in distribution systems is
plastic. To reach the many end users they serve, distribution pipelines
include extensive branching and interconnection, which is significantly
different from the long, uninterrupted runs of transmission system pipe.
These differences make it impractical to simply apply gas transmission
integrity management requirements to distribution pipelines and instead
necessitate integrity management program requirements tailored to
distribution pipelines.

# 3. REGULATORY ANALYSIS

Executive Order 12866 directs all Federal agencies to consider the costs
and benefits of "significant regulatory actions." Of these, Federal
agencies are directed to develop a formal Regulatory Impact Analysis
consistent with OMB Circular A-4 for all "economically significant"
rules, or those rules estimated to have an impact on the economy of
\$100 million or more in any one year. 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. This requirement applies to rulemakings that rescind or
modify existing rules as well as to those that establish new
requirements. The goal of the analysis is to provide decision makers
with a clear indication of the most efficient alternative---that is, the
alternative that generates the largest net benefits to society (ignoring
distributional effects).

This regulatory analysis:

1)  Identifies the target problem, including a statement of the need for
    the proposed action.

2)  Identifies available alternative approaches.

3)  Defines the baseline.

4)  Defines the scope and parameters of the analysis.

5)  Defines and evaluates the costs and benefits of the proposed action
    and the main alternatives identified by the analysis.

6)  Compares the costs and benefits.

7)  Interprets the cost and benefit results.

# 4. IDENTIFICATION OF THE PROBLEM AND THE NEED FOR THE RULE

There are several reasons why this Federal regulation is being proposed.
The gas distribution system is a diverse industry. The Integrity
Management for Gas Phase I Report written by a multi- stockholder group
(which was created to study integrity management on behalf of the
Agency) noted "It is important to recognize the wide diversity that
exists among distribution pipeline operators. Some operators are very
large, serving more than one million customers."[^1] The industry is
composed of: some very small operators, such as master meter operators,
serving only a few customers; medium sized operators, the majority of
which are municipal agencies, serving from 100 and 10,000 diverse
customers; and large pipeline systems. In areas where gas service has
been available for many years there are thousands of miles of pipeline
of various materials and ages. Newer systems can be more uniform,
consisting of one or a few types of pipe with similar fittings and
connections installed using uniform procedures.

The gas distribution system that serves local markets does not fit a
competitive market model. The pipeline infrastructure is installed so
that the local operator that delivers that product has somewhat of a
natural monopoly. Research on this specific industry has indicated that
there are no robust market signals or incentives to prompt operators to
thoroughly assess the condition of their pipelines or to implement
integrity management programs. For example, the Government Accounting
Office (GAO) has pointed out in a study of gas transmission
operators[^2] that the gas transmission integrity management program
prompted some operators to make assessments of their pipelines for the
first time. We believe the market structure of the distribution industry
has similarly led to distribution system operators spending a less than
socially optimal amount of resources and attention to pipeline
integrity.

Operators may also have inadequate information to assess the risks
associated with gas distribution systems, because they may not have
observed incidents involving death or serious injury in any given year
(or decade, for that matter), and smaller operators are even less likely
to see such incidents. Even though an incident in a particular pipeline
is a low probability event, the risk is still inherent in the system
itself, and consequences of an incident can be severe. In fact, about
half of all reported incidents from distribution operators involve death
or major injury--- at a rate per mile that is roughly comparable to gas
transmission pipeline systems. We believe, therefore, that the aggregate
safety impacts on a national basis justify more significant investment
in risk management systems.

Given this likely market failure, the rest of this analysis seeks to
identify the most efficient particular approach to integrity management.
PHMSA considered other means of dealing with market failure before
proposing new, comprehensive requirements. PHMSA has examined the
feasibility of regulating at the State level. Currently gas pipeline
operators are subject to differing State regulations. PHMSA has
determined that the diversity in State specific regulations dictates the
need for Federal regulatory oversight. This is because many pipelines
entities operate interstate. In these cases, we believe a cohesive
nationwide regulatory policy better serves the public interests and
minimizes the cost of doing business in different States under diverse
guidelines and regulations.

While intrastate gas systems are usually regulated by State pipeline
safety agencies, Congress established a Federal interest in the
regulation of these systems, and the Pipeline and Hazardous Materials
Safety Administration supports these programs through Federal grants to
States. Each State's program must be certified, or subject to an
agreement with PHMSA to act on its behalf, as a condition for Federal
funding.

PHMSA has concluded that a better understanding on the part of operators
of the risks posed by their pipeline systems, and a better focus of
their actions to address the most significant of those risks is the most
effective way to improve the Nation's already-commendable pipeline
safety record. Consequently, PHMSA has been implementing integrity
management requirements on various pipeline types as part of its program
to improve pipeline safety. The historical record shows, however, that
more adverse safety consequences (75 to 80 percent of all pipeline
incidents involving death or major injury) result from accidents on
distribution pipelines than from those on the pipelines already subject
to IMP requirements. It is not possible to produce a significant
improvement in pipeline safety without addressing distribution
pipelines. PHMSA has concluded, therefore, that it is appropriate to
establish IMP requirements that will foster a similar understanding of
and focus on risk among distribution pipeline operators.

[]{.mark}

In 2004, the DOT Inspector General (IG) pointed out recent accident
trends for gas distribution pipelines were unfavorable and suggested the
application of integrity management principles could help improve the
safety of distribution pipelines. The IG acknowledged the reason
distribution pipeline operators were exempt from the regulations was
that distribution pipelines could not use the same inspection methods
used for hazardous and transmission pipelines. Nevertheless, the IG
concluded that there was no reason other elements of IMP could not be
implemented for distribution pipelines.

The IG recommended to Congress[^3] that DOT define an approach for
requiring operators of distribution pipeline systems to implement some
form of integrity management or enhanced safety program with elements
similar to those required in hazardous liquid and transmission pipeline
IMPs. The Appropriations Committee then asked PHMSA "to report to the
House and Senate Committees on Appropriations by May 1, 2005, detailing
the extent to which integrity management program elements may be applied
to the natural gas distribution pipeline industry in order to enhance
distribution system safety."[^4] PHMSA submitted the report "Assuring
the Integrity of Gas Distribution Pipeline Systems" to Congress in June
2005, describing the program used to identify opportunities for
improving the safety of distribution pipeline systems.

PHMSA developed the program in two phases. Phase 1 identified the nature
of requirements that might be imposed and any additional guidance or
consensus standards that might be needed to assist operators in
implementing any integrity management requirements. Phase 2 included
development of appropriate requirements by PHMSA and preparation of
guidance/standards by appropriate bodies. During the development of
Phase 1, PHMSA involved a large number of key stakeholder groups
including State and Federal regulators, representatives from the
spectrum of distribution operators, interested members of the public,
and representatives of the Nation's fire service. The stakeholders
agreed with the DOT IG and Congress' recommendations and concluded that
it would be appropriate to modify the regulations to include a
risk-based integrity management process for gas distribution
pipelines.[^5]

[]{.mark}

# 5. IDENTIFICATION OF AVAILABLE ALTERNATIVE APPROACHES

PHMSA considered several alternatives to assure the necessary protection
from potential incidents caused by gas distribution pipelines, with the
intention of selecting the alternative that is likely to result in the
highest net benefits. PHMSA considered the following approaches:

-   Apply existing gas transmission pipeline IMP regulations to gas
    distribution pipelines.

-   Model State legislation by imposing requirements on excavators and
    others outside the regulatory jurisdiction of pipeline safety
    authorities.

-   Develop guidance documents for adoption by States.

-   Implement prescriptive Federal regulations, specifying in detail,
    actions that must be taken to assure distribution pipeline
    integrity.

    -   Implement risk-based, flexible, performance-oriented Federal
        regulations, establishing high-level elements that must be
        included in integrity management programs.

After considering all the alternatives, PHMSA selected the following
alternative: implementation of risk-based, flexible,
performance-oriented Federal regulations establishing high-level
elements that must be included in integrity management programs.

## [5.Number range CHAPTER1 Baseline: No Action]{.underline}

This was used as the baseline against which PHMSA compared all other
alternatives.

Regulatory analyses typically consider an alternative in which the
agency would not take any action, because it would maintain the status
quo. No new requirements would be levied. No costs would be incurred to
implement new requirements. No new benefits would result.

In response to the mandate concerning IMPs for distribution systems
contained in The Pipeline Inspection, Protection, Enforcement and Safety
Act of 2006 (Public Law No: 109-468, Dec. 29, 2006), also known as the
PIPES Act, PHMSA is initiating this rulemaking. PHMSA is extending its
integrity management approach to the largest segment of the Nation's
pipeline network -- the distribution systems that directly serve homes,
schools, businesses, and other natural gas consumers. Beginning in 2000,
the Agency promulgated regulations requiring operators of hazardous
liquid pipelines (49 CFR 195.452, published at 65 FR 75378 and 67 FR
2136) and gas transmission pipelines (49 CFR 192, Subpart O, published
at 68 FR 69778) to develop and follow individualized integrity
management (IM) programs, in addition to PHMSA's core pipeline safety
regulations. Although some pipeline operators are already implementing
some elements of integrity management into their systems, the IMP
approach was designed to promote continuous improvement in pipeline
safety by requiring all operators to identify and invest in risk control
measures beyond core regulatory requirements existing today.

By not taking action the Agency would be unresponsive to the
congressional mandate in the PIPES Act and there would likely be no
reductions in the numbers of deaths, injuries, or property damages
associated with risks related to the integrity management of
distribution lines. Although this alternative would not lead to
increased compliance costs, there would be no reduction in the societal
costs associated with the deaths, injuries, and property damages
associated with integrity management improvements. This alternative
results in zero net benefits. Thus, this alternative is the baseline for
comparison with other alternatives.

## [5.2 Apply existing gas transmission pipeline IMP regulations to gas distribution pipelines]{.underline}

This alternative was determined by PHMSA to be infeasible.

Gas distribution pipelines are different from hazardous liquid and gas
transmission pipelines. Distribution systems combine main lines with an
almost equal amount of mileage branching from the main lines to connect
services to natural gas users. Lines are generally smaller in diameter,
operate at much lower pressures, and are constructed of a variety of
materials, both metallic and non-metallic. Approximately half of the
pipe in distribution systems is plastic compared to very small amounts
of plastic gas transmission pipeline. To reach the many end users they
serve, distribution pipelines include extensive branching and
interconnection compared to transmission systems that have long
uninterrupted runs of pipe. These differences substantially distinguish
distribution systems from transmission systems and thus it is not
technically feasible to apply gas transmission integrity management
requirements to distribution pipelines. For instance, the low pressures,
small diameters, and complex connections associated with distribution
systems make it infeasible to use smart pigs or hydrotesting, techniques
that are used by transmission lines for integrity management. Since we
have determined this alternative is not technically feasible to
implement, we were unable to estimate impacts. Consequently, no further
consideration was given to this alternative.

## [5.3 Model State legislation, potentially imposing requirements on excavators and others outside the jurisdiction of pipeline safety authorities]{.underline}

This alternative was determined by PHMSA to be infeasible because PHMSA
could not ensure that any or all of the States adopt the model State
legislation.

According to the Integrity Management for Gas Distribution Report of
Phase I Investigations, experience indicates that this option may not be
practical for addressing the broad question of integrity management. The
group references the failure of State legislatures to adopt an available
model from the Common Ground effort to prevent excavation damage.[^6]

In studying the issue, the study group found that model State
legislation may be useful for narrower issues, such as improving
excavation damage prevention through implementation of comprehensive
damage prevention programs, including active enforcement.[^7] The report
concludes, "There are many factors affecting State approaches to
regulation. It would be very unlikely that all States could adopt model
legislation with sufficient consistency that would represent a national
solution to integrity management concerns."

After careful study, this option is not considered any further as a
means of addressing the entire integrity management issue because the
integrity management study group found that the issues surrounding
integrity management are broad and require a holistic approach at the
Federal level. Not being operationally feasible, this alternative was
not considered to be amenable to a comparison of the costs and benefits.

## [5.4 Guidance documents for adoption by States with the intent of States mandating use of the guidance]{.underline}

As with the previous alternative, this alternative was determined by
PHMSA to be infeasible because PHMSA could not ensure that any of the
States would mandate the use of the guidance therefore distribution
safety would not improve.

The Integrity Management for Gas Distribution Report of Phase I
Investigations determined that this option is essentially the same as
option 5.3 above, except it contemplates States adopting the guidance as
mandatory requirements. As with model legislation, the study group
considered that adoption likely would not occur in many States. Although
the Federal government establishes basic safety standards, integrity
management certified States are responsible for intrastate pipelines.
The study group notes that States typically have not uniformly adopt
recommended approaches in the past. Selecting this option would thus
provide only the illusion of a solution. The costs of such an approach
would be relatively low, but if the conclusions of the study group are
correct, there would also be low benefits and perhaps, insignificant net
benefits. For these reasons, this alternative was not considered any
further.

## [5.5 Prescriptive Federal regulation, specifying in detail actions that must be taken to assure distribution pipeline integrity]{.underline}

This alternative was determined by PHMSA to be too inflexible to be
applicable to all relevant situations that distribution system operators
might face.

The Integrity Management for Gas Distribution Report of Phase I
Investigations report reaffirms the need for a flexible Federal rule.
The study group reasoned that a highly detailed prescriptive regulation
would eliminate the flexibility needed to address the unique
circumstances of individual States and operators. The study group
reported, "The issues important to assuring the integrity of these
diverse systems will vary. This diversity makes it difficult for any one
prescriptive requirement to address all possible circumstances. It is
important that any new requirements that are developed allow sufficient
flexibility for the operators of distribution pipeline systems, and the
State regulators who oversee their operations, to customize their
integrity management efforts to address their specific systems, threats,
and issues."[^8]

Although some small operators might prefer a prescriptive regulation,
most large operators want the flexibility of a performance-based
regulation. The wide range in size and nature of distribution pipeline
systems calls for a flexible approach to integrity management rather
than a single detailed set of requirements. Giving operators the
guidance and allowing them to shape it to fit their particular system
will assure integrity management efficiently and effectively. A detailed
prescriptive rule was deemed by PHMSA to be too inflexible to be
applicable to all relevant situations that distribution operators might
face, since there is wide spectrum of distribution operators, from
Master meter (mostly one-man operation) to large utilities covering
thousand of miles of pipelines and over a million customers. Thus a
prescriptive rule would be inappropriate and ineffective, resulting in
many operators being required to perform tasks not appropriate for their
pipeline systems. [^9] These statements of the rule being ineffective
and inappropriate suggest that there would likely be a low level of net
benefits. For these reasons a prescriptive Federal regulation was
evaluated no further.

## [5.6 Risk-based, flexible, performance-oriented Federal regulation, establishing]{.underline}

## [high-level elements that must be included in integrity management programs]{.underline}

This alternative was determined by PHMSA to be practicable and is
compared in this document with the baseline "no action" alternative. As
will be demonstrated, there are significant net benefits associated with
this alternative.

This alternative, that is the subject of the proposal, creates a
high-level, flexible, and performance-based Federal regulation that
requires gas distribution operators to develop and implement an
integrity management program for their distribution pipeline systems.
The proposed regulation requires all operators of a distribution
pipeline system to implement an integrity management program and would
prescribe minimum requirements each operator must meet in doing so. An
integrity management program is intended to manage the risks associated
with an operator's pipeline system.

An integrity management program would include, at a minimum, the
following elements:

-   Improving knowledge of the system's infrastructure

-   Identifying threats (existing and potential)

-   Evaluating and prioritizing risk

-   Identifying and implementing measures to mitigate risks

-   Measuring performance, monitoring results, and evaluating
    effectiveness

-   Periodic re-evaluation and improvement

-   Reporting results

This alternative also embraces the installation of excess flow valves
(EFVs). An operator (excluding LPG and master meter operators) would be
required to install an EFV on newly-installed or replaced service lines
that operate continuously throughout the year at a pressure not less
than 10 psig and serve a single-family residence, unless doing so would
not be practicable. This requirement applies only to new or replaced
service lines. There is no requirement for an operator to install an EFV
retroactively on an existing service. The PIPES Act 2006 mandated this
requirement.

The requirement on EFVs is intended to replace the notification
requirements in 49 CFR 192.383, which requires operators to notify the
customer for new and replaced service lines about the availability and
benefits derived for installing an EFV. PHMSA believes the customer
notification requirement would not be necessary if the proposed rule
goes into effect.

Federal pipeline safety law requires States adopt requirements at least
as stringent as those established by PHMSA to maintain their
certification to exercise regulatory jurisdiction over intrastate
pipeline safety. This alternative establishes basic requirements, while
allowing States the flexibility to accommodate the unique needs of
different geographical areas and different communities of operators.
Furthermore, the alternative does this while assuring that a Federal
rule, which provides for a consistent approach to distribution integrity
management, is implemented. For the reasons stated above, this
alternative was selected.

In order to implement the IMP regulations, PHMSA proposes to add a new
*Subpart P -- Gas Distribution Pipeline Integrity Management* to 49
U.S.C., Part 192 as follows:

-   192.1001 What do the regulations in this subpart cover?

-   192.1003 What definitions apply to this subpart?

-   192.1005 What must an operator do to implement this subpart?

-   192.1007 What are the required program elements?

-   192.1009 When must an Excess Flow Valve (EFV) be installed?

-   192.1011 Where does an operator file a report?

-   192.1013 What records must an operator keep?

Note, under the proposal, master meter or LPG operators of gas
distribution pipelines would comply only with the requirements in
Sections 192.1005 and 192.1007, with some exceptions under 192.1007,
such as prioritizing risks and reporting results. This is due to the
simple nature of their systems.

# 6. INDUSTRY INFORMATION

## [6.1 Impacted Operators and Mileage]{.underline}

The proposed regulatory changes will apply to all operators of gas
distribution systems, including master meter and LPG systems regulated
under 49 CFR Part 192. Master meter and LPG system operators, however,
will only need to meet some of the requirements applicable to other
operators.

For this analysis, gas distribution systems will be divided into three
categories:

(1) Gas distribution systems with over 12,000 services that are operated
    by local gas distribution companies (i.e., local gas utilities).

(2) Gas distribution systems with 12,000 or fewer services that are
    operated by local gas utilities.

(3) Master meter and LPG systems.

Each category will be affected somewhat differently by the proposed
rule. In particular, the costs that each of the operators in each
category will face are expected to be different.

The first category covers the largest local gas utilities impacted by
the proposed rule. Industry sources report that, for management and
operational purposes, local gas utilities begin to break their systems
into districts when they have more than 12,000 services. As of 2004,
there were 201 operators in this category.

The second category covers the smaller local gas utilities impacted by
the proposed rule. This category does not include the master meter and
LPG systems impacted by the proposed rule, since local gas utilities do
not generally operate these systems. As of 2004, there were 1,090
operators in this category.

The third category covers the master meter and LPG systems impacted by
the proposed rule. These are generally very small gas distribution
systems. The number of these systems is unknown, but, for this analysis,
PHMSA estimates that approximately 8,000 of these systems would be
impacted by the proposed rule. This estimate is based on reports to
PHMSA in 2004 from (1) 45 State pipeline safety agencies indicating
that, collectively, 6,972 master meter systems were operating in their
States and (2) 35 State pipeline safety agencies indicating that,
collectively, 926 LPG systems were operating in their States. Because
identifying master meter systems is often difficult and because some
State pipeline safety regulators do not have jurisdiction over all
master meter systems in their States, PHMSA believes that the number of
master meter systems reported by the States actually understates the
number currently subject to Federal pipeline safety regulation.

Table 2 presents the numbers of systems, distribution main mileage, and
services that will be used in this analysis. The numbers for the large
and small local distribution systems are based on the situation in 2004.
The estimated number of master meter and LPG systems is discussed above.
The estimate for master meter and LPG distribution main mileage assumes
that each operator has, on average, one mile of distribution mains. The
estimate for master meter and LPG services assumes that each operator
has, on average, 100 services.[^10]

**TABLE 1. NUMBER OF SYSTEMS, DISTRIBUTION MAIN MILEAGE, AND NUMBER OF
SERVICES IMPACTED BY THE PROPOSED DISTRIBUTION INTEGRITY MANAGAMENT
PROGRAM (DIMP) REQUIREMENTS**

+-----------------------------------------+----------------------------+
| **Characteristic**                      | **Number**                 |
+=========================================+============================+
| ***Large Local Distribution Systems***  |                            |
+-----------------------------------------+----------------------------+
| Number of systems                       | 201                        |
+-----------------------------------------+----------------------------+
| Distribution main mileage               | 1,010,000 miles            |
+-----------------------------------------+----------------------------+
| Number of services                      | 54,900,000                 |
+-----------------------------------------+----------------------------+
| #### Small Local Distribution Systems   |                            |
+-----------------------------------------+----------------------------+
| Number of systems                       | 1,090                      |
+-----------------------------------------+----------------------------+
| Distribution main mileage               | 120,000 miles              |
+-----------------------------------------+----------------------------+
| Number of services                      | 5,270,000                  |
+-----------------------------------------+----------------------------+
| ***Master Meter and LPG Systems***      |                            |
+-----------------------------------------+----------------------------+
| Estimated number of systems             | 8,000                      |
+-----------------------------------------+----------------------------+
| Distribution main mileage               | 8,000 miles                |
+-----------------------------------------+----------------------------+
| Number of services                      | 800,000                    |
+-----------------------------------------+----------------------------+
| ***Total***                             |                            |
+-----------------------------------------+----------------------------+
| Estimated number of systems             | 9,291                      |
+-----------------------------------------+----------------------------+
| Distribution main mileage               | 1,138,000 miles            |
+-----------------------------------------+----------------------------+
| Number of services                      | 60,970,000                 |
+-----------------------------------------+----------------------------+

> [Sources]{.underline}: Large and small local distribution
> systems---2004 data submitted to PHSMA; Master meter and LPG
> systems---PHMSA estimate of number of systems based on information
> from State pipeline safety agencies submitted to PHMSA in 2004. For
> this analysis, PHMSA assumes that every master meter and LPG system
> has, on average, one mile of distribution main and 100 services.

As Table 1 indicates, PHMSA expects the proposed rule to impact 9,291
operators with a combined total of 1,138,000 miles of distribution mains
and 60,970,000 services. Furthermore, assuming that each service is, on
average, 65 feet in length,[^11] the total pipeline mileage impacted by
the proposed rule would be 1,888,578 (= 1,138,000 + (60,970,000 x 65) /
5280 feet per mile).

PHMSA encourages industry comment on the estimates presented in this
section.

# 7. DEFINITION AND EVALUATION OF THE BENEFITS AND COSTS OF THE PROPOSED ACTION

The impact of the proposed regulatory change consists of the benefits
and costs attributable to that change. Table 2 presents a list of the
benefits and costs considered in this analysis.[^12]

**TABLE 2. BENEFITS AND COSTS CONSIDERED IN THIS ANALYSIS**

+-----------------------------------+-----------------------------------+
| **Benefits**                      | **Costs**                         |
+-----------------------------------+-----------------------------------+
| -   Reductions in the             | -   Development of an IMP         |
|     consequences of reportable    |                                   |
|     incidents                     | -   Implementation of the IMP     |
|                                   |     (data acquisition and         |
| -   Reductions in the             |     analysis)                     |
|     consequences of               |                                   |
|     non-reportable incidents      | -   Mitigation of risks           |
|                                   |                                   |
| -   A reduction in the            | -   Reporting to PHMSA and State  |
|     probability of a major        |     Regulators                    |
|     catastrophic incident         |                                   |
|                                   | -   Recordkeeping                 |
| -   Reductions in lost natural    |                                   |
|     gas                           | -   Management of the IMP         |
|                                   |                                   |
| -   Reductions in emergency       |                                   |
|     response costs                |                                   |
|                                   |                                   |
| -   Reductions in evacuations     |                                   |
|                                   |                                   |
| -   Reductions in dig-ins         |                                   |
|     impacting non-gas underground |                                   |
|     facilities                    |                                   |
|                                   |                                   |
| -   The end of the existing EFV   |                                   |
|     notification requirement      |                                   |
+-----------------------------------+-----------------------------------+

## 

## [7.1 Benefits]{.underline}

The proposed rule mandates the design and implementation of integrity
management programs on natural gas distribution systems. Integrity
management programs are designed to proactively address problems related
to corrosion, damage by outside forces, pipeline defects, and pipeline
equipment and operations. The benefits resulting from the proposed rule
are expected to result from the correction of problems that could cause
pipeline failures before those failures occur, thereby averting pipeline
accidents.

Natural gas incidents can have significant impacts. The consequences of
natural gas distribution system accidents include deaths, injuries, and
property damage. Recent examples of distribution pipeline incidents
include the following: On December 13, 2005, at 9:26 a.m., an apartment
building exploded in Bergenfield, New Jersey, after natural gas migrated
into the building from a damaged pipeline. Investigators found a break
in an underground 1 1/4-inch steel natural gas distribution service line
that was operating at 11 1/2 pounds psig. There were three fatalities
and five injuries. Damage was estimated at \$863,300. On August 21,
2004, a natural gas explosion destroyed a residence in DuBois,
Pennsylvania. A leaking butt-fusion joint in a 2-inch-diameter plastic
main line pipe was the cause of the accident. Two residents were killed
in this accident. Damage was estimated at \$800,000.[^13]

To run a safe pipeline, operators must have adequate information, the
ability to anticipate problems, and the means to ensure the pipeline
integrity. Positive benefits are expected from the proposed rule.
Reduced numbers of deaths and injuries and reduced property damage are
expected to be important benefits of the proposed rule.

The proposed rule is expected to reduce the consequences of future
accidents through identification and remediation of problems before
those problems can result in accidents. The proposed rule will not
eliminate all gas distribution system accidents. Estimates will need to
be developed for the proportion eliminated, and where that is not
practicable, assumptions will need to be made. In some cases, it will
not be possible to quantify the benefits. In those cases, a qualitative
discussion of the benefits will be presented.

Each of these benefits is addressed below. Following the discussions of
these benefits, the estimated total benefits for the proposed rule will
be calculated and then used to estimate the present value of the
proposed rule over 50 years.

**7.1.1 [Benefits Resulting from a Reduction in the Consequences of
Reportable Incidents]{.underline}**

From 2001 through 2005, PHMSA received reports on 711 natural gas
distribution system incidents. Those incidents resulted in 58 deaths,
227 injuries requiring hospitalization, and approximately \$594 million
in property damage (in nominal, not constant dollars). The breakdown of
incidents and consequences by year for 2001 through 2005, along with the
estimated pipeline mileage for those years, is presented in Table 3.

**TABLE 3. REPORTED DISTRIBUTION SYSTEM INCIDENTS, 2001-2005**[^14]

+--------+-----------+--------+---------+--------------+--------------+
| #####  | **In      | **De   | **Inj   | **Property   | **Estimated  |
| # Year | cidents** | aths** | uries** | Damage**     | Pipeline     |
|        |           |        |         |              | Miles**      |
|        |           |        |         | **(Nominal   |              |
|        |           |        |         | Dollars)**   | **(Mains     |
|        |           |        |         |              | plus         |
|        |           |        |         |              | Services)**  |
+--------+-----------+--------+---------+--------------+--------------+
| 2001   | 124       | 5      | 46      | \$14,071,486 | 1,837,277    |
+--------+-----------+--------+---------+--------------+--------------+
| 2002   | 102       | 10     | 44      | \$23,804,202 | 1,855,319    |
+--------+-----------+--------+---------+--------------+--------------+
| 2003   | 141       | 11     | 58      | \$21,032,408 | 1,865,679    |
+--------+-----------+--------+---------+--------------+--------------+
| 2004   | 174       | 18     | 41      | \$37,507,950 | 1,918,270    |
+--------+-----------+--------+---------+--------------+--------------+
| 2005   | 170       | 14     | 38      | \            | 1,823,136    |
|        |           |        |         | $497,696,278 |              |
+--------+-----------+--------+---------+--------------+--------------+

Most of the \$498 million (nominal dollars) in property damage for 2005
is attributable to the devastation caused by Hurricane Katrina. It
should be noted that Table 3 does not include information attributable
to incidents on master meter systems, since these operators are not
required to report their incidents to PHMSA.[^15] However, based on a
2002 DOT Report to Congress, from 1995 to 1999, there were two master
meter system incidents, which resulted in two injuries and \$200,000 in
damages. One incident resulted from corrosion and the other from
construction/operation error.[^16]

**Benefits Resulting from Reportable Non-Excavation Incidents**

From 2001 through 2005, PHMSA received reports on 409 non-excavation
incidents occurring on natural gas distribution systems. Those incidents
resulted in 46 deaths, 149 injuries requiring hospitalization, and
approximately \$547 million in property damage (in nominal, not constant
dollars). The breakdown of incidents and consequences by year for 2001
through 2005, along with the estimated pipeline mileage for those years,
is presented in Table 4.

**TABLE 4. REPORTED NON-EXCAVATION INCIDENTS ON GAS DISTRIBUTION
SYSTEMS, 2001-2005**[^17]

+--------+-----------+--------+---------+--------------+--------------+
| **     | **In      | **De   | **Inj   | **Property   | **Estimated  |
| Year** | cidents** | aths** | uries** | Damage**     | Pipeline     |
|        |           |        |         |              | Miles**      |
|        |           |        |         | **(Nominal   |              |
|        |           |        |         | Dollars)**   | **(Mains     |
|        |           |        |         |              | plus         |
|        |           |        |         |              | Services)**  |
+--------+-----------+--------+---------+--------------+--------------+
| 2001   | 59        | 2      | 27      | \$6,922,115  | 1,837,277    |
+--------+-----------+--------+---------+--------------+--------------+
| 2002   | 65        | 8      | 36      | \$14,138,500 | 1,855,319    |
+--------+-----------+--------+---------+--------------+--------------+
| 2003   | 68        | 7      | 21      | \$10,488,683 | 1,865,679    |
+--------+-----------+--------+---------+--------------+--------------+
| 2004   | 113       | 17     | 35      | \$26,543,229 | 1,918,270    |
+--------+-----------+--------+---------+--------------+--------------+
| 2005   | 104       | 12     | 30      | \            | 1,823,136    |
|        |           |        |         | $488,913,297 |              |
+--------+-----------+--------+---------+--------------+--------------+

.

Based on the information in Table 4, from 2001 through 2005, gas
distribution systems experienced the following due to non-excavation
incidents:

-   43.8 incidents per million miles per year,

-   4.9 deaths per million miles per year,

-   15.9 injuries requiring hospitalization per million miles per year,
    and

-   \$61,892,587 (2006 dollars) of property damage per million miles per
    year.

In order to develop an estimate of the expected benefits of this
proposed rule, PHMSA makes two adjustments to the raw expected values of
deaths, injuries, and property damage based on results from 2001-2005.
The first such adjustment is explained here, and serves to lower the
expected value of damages: because of the devastation attributable to
Hurricane Katrina, the property damage in 2005 was at least an order of
magnitude greater than the property damage in any year from 1986 through
2004. As a consequence, PHMSA considers the property damage in 2005 to
be an extreme outlier that is unlikely to reoccur in the near future.
Furthermore, the focus of this analysis is integrity management, and
PHMSA notes that integrity management is unlikely to have much impact on
incidents resulting from extreme hurricane damage.

[]{.mark}

The property damage from 2001 through 2004 would appear to be more
representative of the property damage generally experienced by gas
distribution systems in recent years than the property damage from 2001
through 2005. From 2001 through 2004, PHMSA estimates that gas
distribution systems experienced:

-   \$8,356,808 (2006 dollars) in property damage per million miles per
    year.

For this analysis, PHMSA assumes that incident consequences in the
future will mirror those of the recent past (although due to the short
duration of the consequence measured here, PHMSA makes an adjustment to
this assumption in the section below). Specifically, with the exception
of property damage, PHMSA assumes that the average figures developed
from Table 4 for 2001 through 2005 will be representative of the future
for non-excavation incidents. For property damage, PHMSA assumes that
the average figure developed from Table 4 for 2001 through 2004 will be
representative of the future for those incidents.

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 \$5,800,000.[^18]

-   Injuries requiring hospitalization are valued at \$562,500.[^19]

Multiplying the values for a statistical life and injuries requiring
hospitalization by PHMSA's estimates for deaths and injuries puts those
estimates into monetary terms. Multiplying those results, as well as the
estimate for property damage, by the total mileage for the impacted
pipeline yields estimates of the expected annual cost to society
attributable to the deaths, injuries, and property damage resulting from
non-excavation incidents on gas distribution systems.

Assuming the total impacted pipeline mileage is 1,888,578 miles, the
expected annual cost to society attributable to deaths resulting from
non-excavation incidents on gas distribution systems would be
\$53,998,000 (= 4.9 deaths per million miles per year x 1.9 million
pipeline miles x \$5,800,000), the expected annual cost to society
attributable to injuries requiring hospitalization resulting from gas
distribution system incidents would be \$16,993,125 (=15.9 injuries per
million miles per year x 1.9 million pipeline miles x \$562,500), and
the expected annual costs to society attributable to reported property
damage resulting from gas distribution system incidents would be
\$15,877,935 (= \$8,356,808 per million miles per year x 1.9 million
pipeline miles). In total, the expected annual cost to society
attributable to deaths, serious injuries, and property damage resulting
from non-excavation incidents on gas distribution systems reported to
PHMSA would be \$86,869,060 (= \$53,998,000 + \$16,993,125 +
\$15,877,935).

[]{.mark}

The reported deaths, serious injuries, and property damage that the
proposed rule would prevent is unknown. The integrity management
requirements for liquid pipelines and for gas transmission lines are not
sufficiently similar to the proposed requirements for it to be
reasonably expected that the reductions they experienced would be
similar to those that distribution systems might experience.
Furthermore, the integrity management activities of those pipelines have
not been ongoing for long enough to ensure that the full benefits of
those activities are now being achieved. Finally, it would be difficult
to separate out those benefits from the benefits attributable to other
regulatory actions undertaken by PHMSA.

PHMSA expects the impact of the integrity management activities
contained in the proposed rule to be significant. For this analysis,
PHMSA assumes that the proposed rule would prevent 50% of the reported
deaths, serious injuries, and property damage.

**Benefits Resulting from Reducing Reportable Excavation Incidents**

From 2001 through 2005, PHMSA received reports on 302 excavation
incidents occurring on natural gas distribution systems. Those incidents
resulted in 12 deaths, 78 injuries requiring hospitalization, and
approximately \$47 million in property damage (in nominal, not constant
dollars). The breakdown of incidents and consequences by year for 2001
through 2005, along with the estimated pipeline mileage for those years,
is presented in Table 5.

**TABLE 5. REPORTED EXCAVATION INCIDENTS ON GAS DISTRIBUTION SYSTEMS,
2001-2005**[^20]

+--------+-----------+--------+---------+--------------+--------------+
| **     | **In      | **De   | **Inj   | **Property   | **Estimated  |
| Year** | cidents** | aths** | uries** | Damage**     | Pipeline     |
|        |           |        |         |              | Miles**      |
|        |           |        |         | **(Nominal   |              |
|        |           |        |         | Dollars)**   | **(Mains     |
|        |           |        |         |              | plus         |
|        |           |        |         |              | Services)**  |
+--------+-----------+--------+---------+--------------+--------------+
| 2001   | 65        | 3      | 19      | \$7,149,371  | 1,837,277    |
+--------+-----------+--------+---------+--------------+--------------+
| 2002   | 37        | 2      | 8       | \$9,665,702  | 1,855,319    |
+--------+-----------+--------+---------+--------------+--------------+
| 2003   | 73        | 4      | 37      | \$10,543,725 | 1,865,679    |
+--------+-----------+--------+---------+--------------+--------------+
| 2004   | 61        | 1      | 6       | \$10,964,721 | 1,918,270    |
+--------+-----------+--------+---------+--------------+--------------+
| 2005   | 66        | 2      | 8       | \$8,782,981  | 1,823,136    |
+--------+-----------+--------+---------+--------------+--------------+

Based on the information in Table 5, from 2001 through 2005, gas
distribution systems experienced the following consequences due to
excavation incidents:

-   32.4 incidents per million miles per year,

-   1.3 deaths per million miles per year,

-   8.4 injuries requiring hospitalization per million miles per year,
    and

-   \$5,460,750 (2006 dollars) of property damage per million miles per
    year.

For this analysis, PHMSA assumes that future incident consequences will
mirror those of the recent past. Specifically, PHMSA assumes that the
average figures developed from Table 5 for 2001 through 2005 will be
representative of the future for excavation-related incidents.

Multiplying the values for a statistical life and injuries requiring
hospitalization that were presented earlier by PHMSA's estimates for
deaths and injuries puts those estimates into monetary terms.
Multiplying those results, as well as the estimate for property damage,
by the total mileage for the impacted pipeline yields estimates of the
expected annual cost to society attributable to the deaths, injuries,
and property damage resulting from excavation incidents on gas
distribution systems.

Assuming the total impacted pipeline mileage is 1,888,578 miles, the
expected annual cost to society attributable to deaths resulting from
excavation incidents on gas distribution systems would be \$14,326,000
(= 1.3 deaths per million miles per year x 1.9 million pipeline miles x
\$5,800,000), the expected annual cost to society attributable to
injuries requiring hospitalization resulting from gas distribution
system incidents would be \$8,977,500 (= 8.4 injuries per million miles
per year x 1.9 million pipeline miles x \$562,500), and the expected
annual costs to society attributable to reported property damage
resulting from gas distribution system incidents would be \$10,375,425
(= \$5,460,750 per million miles per year x 1.9 million pipeline miles).
In total, the expected annual cost to society attributable to deaths,
serious injuries, and property damage resulting from excavation
incidents on gas distribution systems reported to PHMSA would be
\$33,678,925 (= \$14,326,000 + \$8,977,500 + \$10,375,425).

[]{.mark}

For this analysis, PHMSA assumes that the actions included in the
proposed rule will prevent 50% of the reported deaths, serious injuries,
and property damage. Consequently, the benefits attributable to that
reduction in consequences for reportable excavation incidents would be
\$16,839,463 (= \$33,678,925 x 0.5) per year.

PHMSA assumes that 50% of the reduction in consequences for reportable
incidents would result from the EFV requirements and 50% of the
reduction would result from the enhanced damage prevention program
requirements. Therefore, the annual benefits attributable to the
enhanced damage prevention program requirements would be \$8,419,731 (=
\$16,839,643 x 0.5) per year. The annual benefits attributable to the
EFV requirements would also be an estimated \$8,419,731.

**Total Benefits Resulting from Reportable Incidents**

The total benefits resulting from reportable incidents attributable to
the proposed rule would be equal \$60,273,993 per year, which is the sum
of the benefits attributable to reportable non-excavation incidents,
\$43,434,530 per year, plus the benefits attributable to enhanced damage
prevention programs, \$8,419,731 per year, plus the benefits
attributable to the EFV requirements, \$8,419,731 per year.

**7.1.2 [Benefits Resulting from a Reduction in the Consequences of
Non-Reportable Incidents]{.underline}**

The proposed rule is expected to impact not only the number of
reportable incidents and their consequences, but also the number of
non-reportable incidents and their consequences, as well. The impact of
the proposed regulatory changes on non-reportable incidents is unknown
and must be estimated. To do this, it is necessary to estimate (1) the
total number of federally non-reportable incidents, (2) the average cost
of those incidents, and (3) the proportion or percentage of the
federally non-reportable incidents that would be impacted by the
proposed rule.

**Estimate for the Total Number of Federally Non-Reportable Incidents**

Section 122.2(d) of the California Public Utility Commission's General
Order 112-E requires that pipeline operators submit quarterly reports to
the Commission, and that those reports include information on:

-   The gas leak incidents for which a telephonic report, a letter of
    explanation, or a DOT Form RSPA 7100.1 or 7100.2 were submitted.

-   The gas leak incidents that involved escaping gas from an operator's
    facilities and property damage, including loss of gas, in excess of
    \$1,000.

-   All gas leak incidents that had property damage of between \$0 and
    \$1,000 involving fires, explosions, or excavation damage.

Table 6 presents the numbers of federally non-reportable gas
distribution system incidents and their costs for 1998 through 2005 that
were reported to the California Public Utility Commission under Section
122.2(d) of General Order 112-E.[^21]

**TABLE 6. NON-REPORTABLE INCIDENTS IN CALIFORNIA, 1998-2005**

+---------------------+-----------------------+-----------------------+
| **Year**            | **Number of           | **Aggregate Cost of   |
|                     | Incidents**           | Incidents -- Loss of  |
|                     |                       | Gas and Property      |
|                     |                       | Damage**              |
|                     |                       |                       |
|                     |                       | **(Nominal dollars)** |
+---------------------+-----------------------+-----------------------+
| 1998                | 6,276                 | \$3,003,388           |
+---------------------+-----------------------+-----------------------+
| 1999                | 16,168                | \$5,314,328           |
+---------------------+-----------------------+-----------------------+
| 2000                | 15,537                | \$6,093,456           |
+---------------------+-----------------------+-----------------------+
| 2001                | 11,672                | \$3,585,534           |
+---------------------+-----------------------+-----------------------+
| 2002                | 9,344                 | \$2,667,416           |
+---------------------+-----------------------+-----------------------+
| 2003                | 7,157                 | \$2,054,593           |
+---------------------+-----------------------+-----------------------+
| 2004                | 9,293                 | \$2,229,366           |
+---------------------+-----------------------+-----------------------+
| 2005                | 7,243                 | \$1,226,032           |
+---------------------+-----------------------+-----------------------+
| **TOTAL**           | **82,690**            | **\$26,174,113**      |
+---------------------+-----------------------+-----------------------+

[Source]{.underline}: Communication from the California Public Utility
Commission, April 4, 2007.

Data related to federally reportable incidents is excluded from the
numbers presented in Table 6.

From 1998 through 2005, California gas distribution systems reported 73
incidents to PHMSA.[^22] This means that, for every incident reported to
PHMSA, approximately 1,133 (= 82,690 / 73) non-reportable incidents
occurred.

Of the 73 California gas distribution system incidents reported to
PHMSA, 43 were caused by excavation damage.[^23] Thus, the proportion of
reportable incidents caused by excavation damage was 43/73. Assuming the
proportion of non-reportable incidents caused by excavation damage is
the same, approximately 668 (= 1,133 x 43/73) of the 1,133 incidents
were caused by excavation damage. Furthermore, approximately 465 (=
1,133 - 668) of the 1,133 non-reportable incidents were not caused by
excavation damage.

Based on the information in Table 3, the average number of reportable
gas distribution system incidents that occurred from 2001 through 2005
was 142 (= ((124 + 102 + 141 + 174 + 170)/5). Multiplying this figure by
those for non-reportable incidents per reportable incident yields
estimates of the numbers of non-reportable incidents that might be
expected annually in the U.S. in the future. Those estimates are (1)
66,030 (= 142 x 465) non-reportable incidents not involving excavation
damage and (2) 94,856 (= 142 x 668) non-reportable incidents involving
excavation damage. In total, there will be an estimated 160,886 (= 142 x
1,133) non-reportable incidents expected annually. These estimates do
not include all non-reportable incidents that might occur, it must be
recognized, but they do include those with the highest costs.

**The Average Cost of Non-Reportable Incidents**

As Table 6 indicates, the 82,690 federally non-reportable incidents
reported to the State of California from 1998 through 2005 by gas
distribution systems had a total cost of \$26,174,113 (nominal). This is
\$317 (nominal) per incident (= \$26,174,113 / 82,690). Converted to
2006 dollars, the cost becomes \$361 per incident.

Based on California's non-reportable information, PHMSA assumes that the
average cost of federally non-reportable incidents is \$350.

**The Proportion of Federally Non-Reportable Incidents Impacted by the
Proposed Rule**

The provisions included in the proposed rule cannot be expected to end
all non-reportable incidents. The proportion that it will end is
unknown. PHMSA assumes the provisions will reduce the consequences of
non-reportable incidents by 50%. This is the same assumption made for
reportable incidents. Additionally, PHMSA assumes that the benefits
arising from incidents involving excavation damage can be split evenly
between the EFV requirements and the enhanced damage prevention program
requirements of the proposed rule. This also is the same assumption made
for reportable incidents.

**Impact of the Proposed Rule on Federally Non-Reportable Incidents**

The proposed rule is expected to result in an annual reduction of
\$11,555,250 (= \$350 x 66,030 x 0.5) in the costs of non-reportable
incidents not involving excavation damage. Additionally, the proposed
rule is expected to result in an annual reduction of \$8,299,900 (=
\$350 x 49,856 x 0.5 x 0.5) in the costs of non-reportable incidents
involving excavation damage due to enhanced damage prevention programs.
The proposed rule is also expected to result in an annual reduction of
\$8,299,900 (= \$350 x 49,856 x 0.5 x 0.5) in the costs of
non-reportable incidents involving excavation damage due to its EFV
provisions. In total, the proposed rule is expected to reduce the annual
costs of non-reportable incidents by \$28,155,050 (= \$11,555,250 +
\$8,299,900 + \$8,299,900).

**7.1.3 [Benefits of Number range CHAPTERAvoiding an Accident with Low
Probability and High Consequences]{.underline}**

As mentioned above, PHMSA made an adjustment to the expected value of
property damage because we believed the raw average 2001-2005 damages
were skewed above expectations by the outlier of Hurricane Katrina,
which posed a risk this proposed rulemaking was not designed to
mitigate. We believe, however, that an additional adjustment to the raw
2001-2005 trends used to estimate consequences is warranted. A principal
objective of pipeline safety regulation is to avoid accidents with
adverse consequences. That this objective has been realized to a large
degree is reflected in the fact that accidents with very severe
consequences occur very rarely. As a consequence, the Agency believes
that the 4-5 year baseline data is not reflective of the expected range
of incidents mitigated by the proposed rule. The Agency believes that a
more accurate expected value of benefits, perhaps reflective of a longer
timeline and taking into account risks and consequences not experienced
from 2001-2005, would show a higher expected benefit of this rule.[^24]
It is possible for high consequence accidents in which a
disproportionately large number of casualties (i.e., deaths and serious
injuries) to occur, since a portion of gas distribution piping is
located in densely populated areas in which population densities are
high and near schools and businesses that could house large number of
people who might be affected by an accident.

For example, the largest accident that has occurred in U.S. distribution
pipeline history occurred on November 21, 1996, in San Juan, Puerto
Rico. A leak from an LPG line resulted in an explosion in a commercial
building that killed 33 people and injured at least 69.[^25] There is
some disagreement as to whether the pipeline leak was a proximate cause
or whether there was a fire first that then ignited the leaking propane.
Nevertheless, this accident demonstrates that high-consequence events
can occur as a result of gas line leaks.

To estimate the benefits derived from avoiding the consequences of
high-consequence events, since that type of event clearly would fall
outside most 4- to 5-year window and was not reflected in the baseline
data, we use international data. The study completed recently by the
Paul Scherer Institute (PSI) in Switzerland can be used as an indicator
of the potential likelihood of a severe consequence of an event in the
U.S.[^26] PSI's study was part of a comprehensive study of the safety of
different energy systems. Although PSI concluded that natural gas has
been demonstrably safer than other forms of energy, considering both
transportation and use, it found that high-consequence accidents have
occurred.

An accident occurred in Corlu, Turkey on August 9, 1992, in which 32
people were killed and 64 injured. The largest number of fatalities
experienced as a result of a natural gas accident was found to have
occurred in a 1995 accident in Taegu, Korea, in which 109 people were
killed. Over the period analyzed (1969-2000), PSI found that 129
accidents occurred worldwide in which 5 or more persons were killed,
resulting in 1,971 fatalities. During this period, 3 accidents involving
more than 50 fatalities occurred within the countries comprising the
Organization for Economic Development and Cooperation (OECD, which
includes the U.S.). Six such accidents occurred in non-OECD countries.

The PSI study considered the frequency of accidents with different
numbers of consequences in order to develop an estimate of the
probability of large-consequence accidents. The data were normalized to
allow comparison of data from different countries. The basis for
normalization was the electric energy equivalent of the amount of gas
consumed, in gigawatts electric per year (GW~e~-yr). The probability
estimate took the form of a curve estimating the probability of an
accident of a given number of fatalities per GW~e~-yr. From this curve,
the probability of an accident in which 45 persons are killed is
estimated to be 0.0001 per GW~e~-yr. PHMSA has used this probability in
its analysis.

The PSI report did not estimate the number of serious injuries that
would occur in addition to the number of fatalities. The limited
experience described above demonstrates that more injuries than
fatalities generally occur in these rare events. This mirrors the
experience for events of lesser consequence. PHMSA has assumed, for
purposes of this analysis, that 90 persons would be seriously injured in
an event in which 45 persons were killed.

Applying this probability estimate to the U.S. for purposes of this
analysis required that the electric equivalent of U.S. gas consumption
be calculated. The Energy Information Administration reports that U.S.
gas consumption in 2006 was 21,860,945 million cubic feet.[^27] This
amount was converted to an energy equivalent using a standard assumption
of 35.6 megajoules per cubic meter (MJ/m^3^). The resulting estimate of
thermal energy used in the U.S. in 2006 in the form of natural gas is
2.2 x 10^13^ MJ. This thermal energy was then converted to electrical
energy equivalent using an assumed efficiency factor of 0.35, the same
factor used in the PSI study. The resulting estimate of electrical
energy equivalent is 244.3 GW~e~-yr.

This equivalent consumption amount was then multiplied by the
probability per GW~e~-yr inferred from the PSI study (1 x 10^-4^). The
resulting estimate of the probability of an accident in the U.S. that
would involve 45 fatalities and 90 serious injuries is 0.0243 per year.
That is, there is approximately a 2.5 percent chance in any given year
that such an event would occur.

The number of such accidents that would be expected to occur in the U.S.
in 50 years is thus 1.215. In twenty years, 0.486 events would be
expected (i.e., there is a 48.6 percent chance of one event occurring in
20 years).

For analysis purposes, it is necessary to determine the monetary
equivalent of the consequences of such an accident. Using the standard
DOT assumptions for the value of a death and serious injury (described
above), the consequences of one accident would be valued at \$311.63
million.[^28] Here, again, it would be unreasonable to assume that the
improvements to be realized as a result of this proposed rule will
eliminate all possibility of a large-consequence accident. PHMSA does
expect, though, that the efficacy of this proposal in avoiding a
large-scale accident will be greater than that for avoiding
smaller-scale incidents.

This is because the key elements of the DIMP programs that would be
required by the proposed rule are for operators to analyze risks and to
focus their risk avoidance activities on those areas where they can be
most effective. Risk includes consideration of the likelihood of an
event, as well as its consequences. Thus, areas where very high
consequences could occur as a result of an accident will receive greater
attention under operator DIMP programs than will portions of their
systems subject to average or lower risk. PHMSA expects that this
improved safety focus of DIMP activities will mean that this proposed
rule will contribute at least 75% to avoiding a large-consequence
accident of this nature. The consequences avoided are thus estimated to
be \$233.72 million per event. In a 50-year analysis horizon, the
avoided consequences would total \$283.97 million. Over a 20-year
analysis, the avoided consequences would be \$113.59 million. Put on an
annual basis, the avoided consequences would be \$5.71 million per year.

**7.1.4 [Benefits Attributable to Reducing Lost Gas]{.underline}**

As a consequence of distribution system leaks, natural gas will be lost.
Reducing the number of leaks through DIMP will reduce the quantity of
natural gas that is lost.

The U.S. Environmental Protection Agency (EPA) estimates natural gas
distribution system emissions of methane in 2005 at 1,303
gigagrams.[^29] According to the EPA, those are "...mainly...fugitive
emissions from gate stations and non-plastic piping (cast iron,
steel)."[^30] Some, of course, will also result from distribution system
leaks in plastic piping. Assuming that (1) there are 0.052 billion cubic
feet of methane per gigagram and (2) natural gas is 80% methane, the
1,303 gigagrams of methane emissions converts to 85 billion cubic feet
(= 1,303 x 0.052 x 1/0.8) of natural gas. Assuming a city gate natural
gas price of \$8.67 per thousand cubic feet,[^31] the total annual value
of the lost gas given in 2005 dollars is approximately \$737 million (=
85 billion cubic feet x \$8.67). This becomes \$759 million when
converted to 2006 dollars.

PHMSA does not know the proportion of gas loss avoided by the
implementation of DIMP, however for the purposes of this analysis is
assumed to be 10 percent, or \$76 million (\$759 million\* .10).

**7.1.5 [Benefits Resulting from Reduced Emergency Response
Costs]{.underline}**

When a gas distribution system incident occurs, local emergency
responders, including fire and police, frequently go to the scene to
ensure public safety. Although communities are already incurring some of
the fixed costs of these services, a gas distribution system incident
adds to the cost of emergency response through the cost of responding to
more incidents, possibly through damaged equipment and emergency
responder injuries or the possible necessity of maintaining a higher
overall response capacity.

The number of studies of addressing the costs of firefighting is very
limited. In a seminal 1991 paper, William Meade developed estimates for
the fully loaded cost of local fire service (i.e., firefighting and
other activities and services provided by local fire departments).[^32]
That paper estimated those costs to be between \$25.8 billion and \$46.4
billion in 1986, with \$39.6 billion the \"Most Likely Estimate\" of the
cost.[^33] These estimates consist of the total annual cost of local
career fire departments, plus an imputed annual cost for the services
provided by volunteer fire departments.[^34]

In 1986, according to the National Fire Protection Association, there
were a total of 11,890,000 fire department calls.[^35] Those included
calls for fires, medical aid, false alarms, mutual aid, hazardous
materials, other hazardous conditions, and other. Based on the best
estimate (i.e., the \"Most Likely Estimate\") of the cost of local fire
service in 1986, and the total number of fire department calls for that
same year, a fire call in 1986 cost, on average, \$3,331.

For this analysis, PHMSA assumes the cost of a fire department call to
be equal to the average cost of a fire department call, \$5,425 (this is
the \$3,331 estimate converted from 1986 to 2006 dollars).

PHMSA assumes that a local fire department will be called for

-   100% of all reportable incidents[^36] and

```{=html}
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```
-   10% of all non-reportable incidents.

Based on information developed previously in this report, PHMSA expects

-   85 reportable non-excavation incidents per year,

-   60 reportable excavation incidents per year,

-   66,030 non-reportable, non-excavation incidents per year, and

-   94,856 non-reportable excavation incidents.

Furthermore, due to the high fixed costs in maintaining a fire
department, PHMSA assumes that only 25% of the costs of those fire
department calls are costs that would not be incurred by local
communities in the absence of gas distribution system incidents.[^37]
PHMSA invites comments on these assumptions.

Thus, PHMSA expects the annual cost savings to local communities and
volunteer firefighters in the absence of gas distribution incidents to
be \$22,017,363 (= (85 + 60 + 6,603 + 9,486) x \$5,425 x 0.25). PHMSA
assumes that the proposed rule, if implemented, would actually result in
50% of those savings, or \$11,008,682 (= \$22,017,363 x 0.5). This
estimate does not include any cost savings associated with non-gas
incidents that might be avoided by the provisions of the proposed rule.

**7.1.6 Cost Savings from Avoided Evacuations**

When gas distribution system incidents occur, people may be evacuated as
a precaution or because of the threat that the incident poses to the
public. Table 7 presents information on evacuations resulting from gas
distribution system incidents for 2004 and 2005, the only years for
which complete evacuation information is available.

**TABLE 7. EVACUATIONS RESULTING FROM REPORTED GAS DISTRIBUTION SYSTEM
INCIDENTS, 2004-2005**[^38]

  ----------- --------------- ------------- ------------ ------------- -----------------
  **Year**    **Number of     **Number of   **Elapsed                  **Estimated
              incidents with  people        time until                 Pipeline Miles
              evacuations**   evacuated**   area was                   (Mains and
                                            made safe**                Services)**

                                            **Hours**    **Minutes**   

  2004        42              4,204         435          13            1,918,270

  2005        51              4,725         321          14            1,823,136

  **Total**   **93**          **8,929**     **756**      **27**        
  ----------- --------------- ------------- ------------ ------------- -----------------

Based on the information in the table, from 2004 through 2005, an
average of 2,392 people per million miles, per year, were evacuated due
to reported gas distribution incidents.

The cost of evacuations is very difficult to estimate since there are
numerous variables. Evacuation costs will include the expense for
temporary lodging and food, lost wages, business disruptions, and
inconvenience to the public. In addition there are costs of agencies
assisting with the evacuation. The U.S. Nuclear Regulatory Commission,
for example, uses a range of \$600 to \$1,800 per person evacuated. The
Federal Railroad Administration (FRA) uses \$1,000 to estimate impacts
from railroad evacuations. [^39] Therefore, PHMSA assumes a cost of
\$1,000 per person for evacuations to be reasonable.[^40] We use this
figure below, also.

**Cost Savings Resulting from Reportable Non-Excavation Incidents**

Table 8 presents information on evacuations resulting from gas
distribution system incidents for 2004 and 2005.

**TABLE 8. EVACUATIONS RESULTING FROM REPORTED NON-EXCAVATION INCIDENTS
ON GAS DISTRIBUTION SYSTEMS, 2004-2005**[^41]

  ----------- --------------- ------------- ----------- ------------- -----------------
  **Year**    **Number of     **Number of   **Elapsed                 **Estimated
              incidents with  people        time until                Pipeline Miles
              evacuations**   evacuated**   area was                  (Mains and
                                            made safe**               Services)**

                                            **Hours**   **Minutes**   

  2004        29              530           207         20            1,918,270

  2005        36              4,341         180         4             1,823,136

  **Total**   **65**          **4,871**     **387**     **24**        
  ----------- --------------- ------------- ----------- ------------- -----------------

# 

Based on the information in the table, from 2004 through 2005, an
average of 1,329 people per million miles, per year were evacuated due
to gas distribution incidents.

For this analysis, PHMSA assumes that incident consequences in the
future will mirror those of the recent past. Specifically, PHMSA assumes
that the 1,329 people per million miles per year evacuated because of
gas distribution incidents will be representative of the future for
non-excavation incidents.

Multiplying the estimate of the cost of evacuation per person, \$1,000 (
see 7.1.6 for the rationale for using this figure), by the number of
people per million miles per year, 1,329, yields an estimate of the
total cost of evacuations resulting from non-excavation incidents,
\$1,329,000 per million miles per year.

PHMSA assumes that, as a result of the proposed rule, 50% of the
\$1,329,000 per million miles per year cost can be avoided. Given that
1.9 million miles of pipeline would be impacted by the proposed rule,
the total annual cost savings resulting from non-excavation incidents is
expected to be \$1,262,550 (= 1,329,000 x 0.5 x 1.9) per year.

**Benefits Resulting from Reportable Excavation Incidents**

Table 9 presents information on evacuations resulting from gas
distribution system incidents for 2004 and 2005.

**TABLE 9. EVACUATIONS RESULTING FROM REPORTED EXCAVATION INCIDENTS ON
GAS DISTRIBUTION SYSTEMS, 2004-2005**[^42]

  ----------- --------------- ------------- ------------ ------------- -----------------
  **Year**    **Number of     **Number of   **Elapsed                  **Estimated
              incidents with  people        time until                 Pipeline Miles
              evacuations**   evacuated**   area was                   (Mains and
                                            made safe**                Services)**

                                            **Hours**    **Minutes**   

  2004        13              3,674         227          53            1,918,270

  2005        15              384           141          10            1,823,136

  **Total**   **28**          **4,058**     **369**      **3**         
  ----------- --------------- ------------- ------------ ------------- -----------------

[Note]{.underline}: In one incident in 2004, 3,000 people were evacuated
as a precaution.

Based on the information in the table, from 2004 through 2005, an
average of 1,063 people per million miles, per year were evacuated due
to reported excavation-related gas distribution incidents.

For this analysis, PHMSA assumes that incident consequences in the
future will mirror those of the recent past. Specifically, PHMSA assumes
that the 1,063 people per million miles per year evacuated because of
gas distribution incidents will be representative of the future for
excavation incidents absent this rulemaking.

Multiplying the estimate of the cost of evacuation per person, \$1,000,
by the number of people per million miles per year, 1,063, yields an
estimate of the total cost of evacuations resulting from excavation
incidents, \$1,063,000 per million miles per year.

PHMSA assumes that, through the actions included in the proposed rule,
50% of the \$1,063,000 per million miles per year cost, or \$531,500 per
million miles per year, can be avoided. PHMSA assumes that 50% of the
reduction in evacuation costs would result from the EFV requirements and
50% of the reduction would result from the enhanced damage prevention
program requirements. Therefore, the benefits attributable to the
enhanced damage prevention program requirements would be \$265,750 (=
\$531,500 x 0.5) per million miles per year. Likewise, the benefits
attributable to the EFV requirements would be \$265,750 (= \$531,500 x
0.5) per million miles per year. Given that 1.9 million miles of
pipeline would be impacted by the proposed rule, the total annual cost
savings associated with the enhanced damage prevention program
requirements is expected to be \$1,009,850 (= \$265,750 x 2 x 1.9) per
year.

**Total Benefit from Reduction in Evacuations**

In total, the annual benefit from the reduction in the number of
evacuations related to reportable incidents would be the sum of the
expected benefits from reportable non-excavation evacuations,
\$1,262,550 annually, and the expected benefits from reportable
excavation evacuations, \$1,009,850 annually, or \$2,272,400 annually.
The annual benefit from a reduction in the number of non-reportable
incidents has not been estimated because the data needed for such
estimation is unavailable. So, for this analysis, PHMSA assumes that the
reduction in non-reportable evacuations, in total, would have a benefit
that is at least equal to that of reportable evacuations, or \$2,272,400
annually. PHMSA invites comments on the reasonableness of this
assumption. Thus, PHMSA estimates that the total benefit from the
reduction in evacuations attributable to the proposed rule would be
\$4,544,800 annually (= \$2,272,400 x 2).

####### 7.1.7 [Benefits Resulting from Reduced Excavation Damage to Non-Gas Distribution System Underground Facilities]{.underline}

As a result of the requirement for operators to implement enhanced
damage prevention programs that is included in the proposed rule, not
only will gas distribution systems experience fewer dig-ins, but so will
other underground facilities. Those other underground facilities include
buried communications, CATV, electric, potable water, and sewer
facilities, and irrigation pipes and pipelines transporting hazardous
liquids or gases.

Currently, comprehensive information on non-gas dig-ins is available
only for Colorado. That State requires the owners and operators of
underground infrastructure to report dig-ins.[^43] The one-call system
in Colorado, UNCC (Utility Notification Center of Colorado), publishes
an annual report summarizing the information. Colorado law mandates that
report.[^44] Table 10 presents the number of reported incidents for
Colorado from 2001 through 2005. It also presents the number of gas
pipeline incidents reported by year and the number of reporting
operators, as well as the total number of underground operators who are
members of UNCC.

**TABLE 10. UNDERGROUND FACILITY INCIDENTS IN COLORADO,**

**2001 -- 2005**

+------------+-------------+------------------+-----------------------+
| **Year**   | **Total     | **Number of Gas  | **Number of Reporting |
|            | Number of   | Facility         | Underground Operators |
|            | Incidents** | Incidents**      | / Total Number of     |
|            |             |                  | Underground           |
|            |             |                  | Operators**           |
+------------+-------------+------------------+-----------------------+
| ####       | 11,092      | 3,191            | 65 / "nearly 1,000"   |
| ##### 2001 |             |                  |                       |
+------------+-------------+------------------+-----------------------+
| 2002       | 12,704      | 3,458            | 71 / NA               |
+------------+-------------+------------------+-----------------------+
| 2003       | 13,540      | 4,489            | 50 / 1,120            |
+------------+-------------+------------------+-----------------------+
| 2004       | 10,573      | 2,627            | 40 / 1,126            |
+------------+-------------+------------------+-----------------------+
| 2005       | 9,371       | 2,435            | NA / NA               |
+------------+-------------+------------------+-----------------------+

> [Notes]{.underline}: NA = Not available.
>
> [Sources]{.underline}: Utility Notification Center of Colorado,
> "Perspectives on Facility Damage -- 2001," "Perspectives on Facility
> Damage -- 2002," "Perspectives on Facility Damage -- 2003,"
> "Perspectives on Facility Damage -- 2004,"and "Perspectives on
> Facility Damage -- 2005."

The gas facilities referenced in the table likely include not only gas
distribution systems in Colorado, but also gas transmission and
gathering systems.

Based on Colorado's experience, PHMSA assumes that for each gas
distribution system excavation incident, there will be approximately 2.5
non-gas distribution system incidents. That is, PHMSA assumes that the
gas pipeline excavation incidents occurring in Colorado were all on
distribution systems. Furthermore, based on California's cost
information for non-reportable gas distribution system incidents, PHSMA
assumes that the average cost of an excavation incident for non-gas
systems is \$350 (see Section 6.2.2). Additionally, PHMSA assumes that
(1) the implementation of enhanced damage prevention programs by gas
distribution systems, as required by DIMP, will reduce the total number
of non-gas incidents by 25%, and (2) the installation of EFVs will have
no impact on excavation incidents affecting non-gas systems.

Enhanced damage prevention programs will have an impact on the number of
dig-ins experienced by other underground facilities. Such programs
should make excavators sensitive to the risks they pose not only to
underground gas distribution services and mains, but also to any and all
underground facilities.

It should be recognized that the installation of EFVs actually would
have some very limited impact on excavation incidents affecting non-gas
systems because gas incidents that include fires or explosions sometimes
adversely impact nearby underground facilities. The frequency that this
occurs, however, is expected to be low.

For Colorado from 2001 through 2005, a total of eight excavation-related
incidents on gas distribution systems were reported to PHMSA (3 in 2001,
2 in 2002, 0 in 2003, 1 in 2004, and 2 in 2005). Thus, for every
reported gas distribution dig-in incident there were 5,135 (= 41,080 /
8) non-gas dig-ins. Assuming that this is the situation nationally, and
using the average annual number of reported gas distribution system
excavation incidents from 2001 through 2005, 60, which can be calculated
using the information in Table 5, a value for the non-gas incidents
avoided annually because of enhanced damage prevention programs can be
estimated. That value is \$26,958,750 (= 60 x 5,135 x 0.25 x \$350).

This estimate may understate the true cost savings to non-gas operators
from the enhanced damage prevention programs that gas distribution
operators will implement under DIMP for several reasons, since, among
other reasons, it does not include avoided dig-ins on gas transmission
and gathering lines. Furthermore, it is not based on the incidents
occurring on all underground facilities in Colorado, as the last column
in Table 10 implies.

####### 7.1.8 [Cost Savings Associated with Ending the Currently Existing EFV Notification Requirement]{.underline}

By mandating the installation of EFVs, with limited exceptions, on all
new and renewed single-family residential services operating at least 10
psig, the proposed rule renders moot the currently existing customer
notification requirement concerning EFVs (see 49 CFR 192.383).
Consequently, PHMSA proposes, as part of the proposed rule, to relieve
distribution system operators of the EFV notification requirement. PHMSA
estimates that 400,000 notifications annually would no longer need to be
made (for the derivation of this estimate, see Section 6.3.4.3 of this
report).

If the EFV notification requirement were to be rescinded, distribution
system operators would experience lower costs because they would no
longer need to (1) mail out EFV notifications or (2) answer the
questions of those receiving the notifications.

With respect to the cost of mailing notifications, PHMSA makes the
following assumptions:[^45]

-   The cost of postage is \$0.41.

-   The cost of the physical copy of the notification is \$0.10.

-   Preparing and mailing each notification takes 5 minutes of staff
    time.

-   Those preparing and mailing the notifications have a fully loaded
    labor cost of \$17.60 per hour.

Based on these assumptions, the total cost savings attributable to not
having to annually mail notifications to 400,000 single family
residential customers with new or renewed services would be \$790,667 (=
400,000 x (\$0.41 + \$0.10 + (5/60 x \$17.60))) per year.

With respect to the cost of answering the questions of those receiving
notifications, PHSMA makes the following assumptions:[^46]

-   10% of all of those receiving EFV notifications will call for more
    information.

-   The calls made will take, on average, five minutes to answer.

-   Those answering the calls have a fully loaded labor cost of \$40 per
    hour.

Based on these assumptions, the total cost savings attributable to not
being required to answer the questions of those receiving notifications
about EFVs on their new or renewed service lines would be \$133,333 (=
400,000 x 0.1 x (5/60) x \$40) per year.

In total, the cost savings attributable to not being required to notify
400,000 customers annually would be \$924,000 (= \$790,667 + \$133,333).
This is PHMSA's estimate of the value of the regulatory relief that the
gas distribution industry would realize annually by eliminating the EFV
notification requirement.

**7.1.9 [Total Benefits]{.underline}**

Table 11 presents a summary of the estimated benefits of the proposed
rule, along with the calculated total for those benefits. In total, the
benefits of the proposed rule are expected to be \$214 million per year.
The \$214 million estimate does not include any estimates for the
benefits associated with (1) reduced GHG emissions, (2) increased public
confidence, or (3) additional costs savings to industry.

**TABLE 11. SUMMARY AND TOTAL FOR THE ESTIMATED BENEFITS OF THE PROPOSED
RULE**

+------------------------------------------+---------------------------+
| **Benefit**                              | **Estimate**              |
|                                          |                           |
|                                          | **(Million dollars per    |
|                                          | year)**                   |
+------------------------------------------+---------------------------+
| Reduced Reportable Incidents             | \$60                      |
+------------------------------------------+---------------------------+
| Reduced Non-reportable Incidents         | \$28                      |
+------------------------------------------+---------------------------+
| Reduced High Consequence Costs           | \$6                       |
+------------------------------------------+---------------------------+
| Reduced Lost Gas                         | \$76                      |
+------------------------------------------+---------------------------+
| Reduced Emergency Response Costs         | \$11                      |
+------------------------------------------+---------------------------+
| Reduced Evacuations                      | \$5                       |
+------------------------------------------+---------------------------+
| Reduced Non-Gas Excavations              | \$27                      |
+------------------------------------------+---------------------------+
| End of Existing EFV Notification         | \$1                       |
| Requirement                              |                           |
+------------------------------------------+---------------------------+
| TOTAL                                    | \$214                     |
+------------------------------------------+---------------------------+

The present value of the estimated \$214 million in expected annual
benefits over 50 years using a 3% discount rate would be approximately
\$5.5 billion. The present value of the annual benefits over 50 years
using a 7% discount rate would be approximately \$3.0 billion.

## [7.2 Costs]{.underline}

The costs associated with the proposed rule will be attributable to the
following activities that will be required of natural gas distribution
systems:

-   Developing an integrity management program

-   Implementing an integrity management program

-   Mitigating risks

-   Managing the integrity management program

-   Reporting to PHMSA and State regulators

-   Recordkeeping

Each of these activities and their associated costs are discussed below,
following a brief overview of the key assumptions used in the
calculation of the costs.

**7.2.1 Assumptions**

Table 12 lists the key assumptions concerning distribution system
characteristics, costs, and other items that are used in the estimation
of the costs of the proposed rule.

**TABLE 12. KEY ASSUMPTIONS IMPACTING COST**

+---------------------------------------------+------------------------+
| **Item**                                    | #                      |
+=============================================+========================+
| #### Distribution System Characteristics\*  |                        |
+---------------------------------------------+------------------------+
| Total miles of steel mains                  | 546,950                |
+---------------------------------------------+------------------------+
| Total miles of plastic mains                | 531,365                |
+---------------------------------------------+------------------------+
| Total miles of cast iron mains              | 34,578                 |
| [\<]{.underline} 8\" in diameter            |                        |
+---------------------------------------------+------------------------+
| Miles of bare steel main to be replaced     | 57,297                 |
| with plastic                                |                        |
+---------------------------------------------+------------------------+
| Miles of bare steel main to be replaced     | 18,682                 |
| with coated steel                           |                        |
+---------------------------------------------+------------------------+
| Miles of PVC + ABS mains                    | 45,000                 |
+---------------------------------------------+------------------------+
| Total number of steel services              | 22,496,190             |
+---------------------------------------------+------------------------+
| Total number of plastic services            | 37,309,715             |
+---------------------------------------------+------------------------+
| Total number of cast iron services          | 128,993                |
+---------------------------------------------+------------------------+
| Total number of copper services             | 1,339,000              |
+---------------------------------------------+------------------------+
| Number of bare steel services               | 4,554,000              |
+---------------------------------------------+------------------------+
| Number of PVC + ABS services                | 1,900,000              |
+---------------------------------------------+------------------------+
| ***Costs\*\* Assumed Value***               |                        |
+---------------------------------------------+------------------------+
| Costs to replace cast iron (high density    | \$90/foot              |
| underground)                                |                        |
+---------------------------------------------+------------------------+
| Costs to replace steel w/ coated steel      | \$77/foot              |
+---------------------------------------------+------------------------+
| Costs to replace steel w/ plastic           | \$25/foot              |
+---------------------------------------------+------------------------+
| Costs to replace steel w/ plastic (high     | \$45/foot              |
| density underground)                        |                        |
+---------------------------------------------+------------------------+
| Cost to replace service -- high density     | \$2,200/service        |
| underground                                 |                        |
+---------------------------------------------+------------------------+
| Cost to replace service -- medium density   | \$1,500/service        |
| underground                                 |                        |
+---------------------------------------------+------------------------+
| Cost to replace service -- low density      | \$1,000/service        |
| underground                                 |                        |
+---------------------------------------------+------------------------+
| Cost of EFV installation on new or          | \$20/service           |
| replacement services for large operators    |                        |
+---------------------------------------------+------------------------+
| Cost of EFV installation on new or          | \$30/service           |
| replacement services for small operators    |                        |
+---------------------------------------------+------------------------+
| Fully loaded cost of pipeline employees --  | \$70/hour              |
| Large and small operators                   |                        |
+---------------------------------------------+------------------------+
| Fully loaded cost of pipeline employees --  | \$50/hour              |
| Master meter and LPG systems                |                        |
+---------------------------------------------+------------------------+
| Cost of leak survey on a main               | \$175/mile             |
+---------------------------------------------+------------------------+
| Cost of leak survey on a service            | \$2.25/service         |
+---------------------------------------------+------------------------+
| ***Other***                                 |                        |
+---------------------------------------------+------------------------+
| Cast iron replacement programs              | 65% of lines covered,  |
|                                             | so 35% of lines not    |
|                                             | covered\*\*\*          |
+---------------------------------------------+------------------------+
| Bare steel replacement programs             | 74% of lines covered,  |
|                                             | so 26% of lines not    |
|                                             | covered\*\*\*          |
+---------------------------------------------+------------------------+
| Vintage plastic replacement activities      | 75% of lines covered,  |
|                                             | so 25% of lines not    |
|                                             | covered\*\*            |
+---------------------------------------------+------------------------+

\*2004 data.

\*\*From industry sources (except for the fully loaded cost of master
meter and LPG system pipeline employees, which is a PHMSA estimate).

\*\*\*From AGF report. Assumed to be valid for all local gas utilities.

**7.2.2 Developing an Integrity Management Program**

The proposed rule requires that each gas distribution system operator
develop a formal integrity management program within 18 months after the
final rule is issued. As stated previously, the integrity management
program is intended to manage the risks associated with the operator's
pipeline system. For distribution operators other than master meter and
LPG gas operators, an integrity management program must, at a minimum,
include the following elements:

-   Demonstrated knowledge of the pipeline system's infrastructure.

-   Identification of existing and potential threats to the system.

-   Risk evaluation and prioritization.

-   Identification and implementation of risk mitigation measures.

-   Performance measures, monitoring of results, and evaluation of
    program effectiveness.

-   Continual evaluation and, if necessary, improvement of the integrity
    management program.

-   Periodic reporting of results.

Since integrity management programs are not currently required for gas
distribution systems, the costs associated with developing such a
program are unknown and must be estimated. Because conditions differ
among the types of operators, the costs associated with developing the
programs will be estimated separately for large operators, small
operators, and master meter and LPG gas systems.

Based on discussions with industry organizations representing the
operators that will be affected by the proposed regulatory changes,
PHMSA has identified the following as the key activities associated with
the development of a formal integrity management program:

-   Preparing a written distribution integrity management program.

-   Documenting the DIMP processes.

-   Identifying threats.

The American Public Gas Association (APGA) Security and Integrity
Foundation (SIF) will develop a model Distribution Integrity Management
Program to assist small operators in developing integrity management
programs meeting the requirements of a final rule. The end product will
be a simple and handy, risk-based integrity management program to help
small operators hold down the cost of developing IMPs.

[]{.mark}

Additionally the proposed rule includes an even more simplified approach
for developing an integrity management program aimed at master meter and
LPG systems. This will help master meter and LPG systems control their
integrity management program development costs.

Table 13 presents PHMSA's estimates of the costs for these activities
listed by operator type. In total, PHMSA estimates that the cost of the
activities will be \$66.7 million dollars in the first year and \$7.5
million in each subsequent year. Of this total, large operators will pay
\$36.1 million in the first year and \$4.1 million in each subsequent
year, small operators will pay \$17.8 million in the first year and
\$1.8 million in each subsequent year, and master meter and LPG systems
will pay \$12.8 million in the first year and \$1.6 million in each
subsequent year.

**TABLE 13. ESTIMATED COSTS OF DEVELOPING AN INTEGRITY MANAGEMENT
PROGRAM**

+-----------+---------+--------+---------+-------------+--------------+
| **Type of | *       | *      | **Labor | **Total     | **Total      |
| Operator  | *Number | *Labor | Rate    | Annual Cost | Annual Cost  |
| and       | of      | Hours  | (Fully  | in Year 1** | in Year 2    |
| A         | Oper    | per    | loaded  |             | and On**     |
| ctivity** | ators** | Oper   | cost    | **(\$       |              |
|           |         | ator** | per     | Million)**  | **(\$        |
|           |         |        | labor   |             | Million)**   |
|           |         |        | hour)** |             |              |
+===========+=========+========+=========+=============+==============+
| ***Large  |         |        |         |             |              |
| Ope       |         |        |         |             |              |
| rators*** |         |        |         |             |              |
+-----------+---------+--------+---------+-------------+--------------+
| DIMP      | 201     | 960    | \$70    | \$13.5      | \-\--        |
| Pr        |         |        |         |             |              |
| eparation |         |        |         |             |              |
+-----------+---------+--------+---------+-------------+--------------+
| Do        | 201     | 800    | \$70    | \$11.3      | \-\--        |
| cumenting |         |        |         |             |              |
| DIMP      |         |        |         |             |              |
| processes |         |        |         |             |              |
+-----------+---------+--------+---------+-------------+--------------+
| Id        | 201     | 800    | \$70    | \$11.3      | \-\--        |
| entifying |         |        |         |             |              |
| threats   |         |        |         |             |              |
+-----------+---------+--------+---------+-------------+--------------+
| Periodic  | 201     | 288    | \$70    | \-\--       | \$4.1        |
| updates   |         |        |         |             |              |
| and       |         |        |         |             |              |
| revisions |         |        |         |             |              |
+-----------+---------+--------+---------+-------------+--------------+
| TOTAL     |         |        |         | \$36.1      | \$4.1        |
+-----------+---------+--------+---------+-------------+--------------+
| ***Small  |         |        |         |             |              |
| Ope       |         |        |         |             |              |
| rators*** |         |        |         |             |              |
+-----------+---------+--------+---------+-------------+--------------+
| DIMP      | 1,090   | Total  |         | \$5.5       | \-\--        |
| Pr        |         | cost   |         |             |              |
| eparation |         | per    |         |             |              |
|           |         | ope    |         |             |              |
|           |         | rator: |         |             |              |
|           |         | \      |         |             |              |
|           |         | $5,000 |         |             |              |
+-----------+---------+--------+---------+-------------+--------------+
| Do        | 1,090   | 40     | \$70    | \$3.1       | \-\--        |
| cumenting |         |        |         |             |              |
| DIMP      |         |        |         |             |              |
| processes |         |        |         |             |              |
+-----------+---------+--------+---------+-------------+--------------+
| Id        | 1,090   | 120    | \$70    | \$9.2       | \-\--        |
| entifying |         |        |         |             |              |
|           |         |        |         |             |              |
| threats   |         |        |         |             |              |
+-----------+---------+--------+---------+-------------+--------------+
| Periodic  | 1,090   | 24     | \$70    | \-\--       | \$1.8        |
| updates   |         |        |         |             |              |
| and       |         |        |         |             |              |
| revisions |         |        |         |             |              |
+-----------+---------+--------+---------+-------------+--------------+
| TOTAL     |         |        |         | \$17.8      | \$1.8        |
+-----------+---------+--------+---------+-------------+--------------+
| ***Master |         |        |         |             |              |
| Meter and |         |        |         |             |              |
| LPG       |         |        |         |             |              |
| S         |         |        |         |             |              |
| ystems*** |         |        |         |             |              |
+-----------+---------+--------+---------+-------------+--------------+
| DIMP      | 8,000   | Total  |         | \$8.0       | \-\--        |
| Pr        |         | cost   |         |             |              |
| eparation |         | per    |         |             |              |
|           |         | ope    |         |             |              |
|           |         | rator: |         |             |              |
|           |         | \      |         |             |              |
|           |         | $1,000 |         |             |              |
+-----------+---------+--------+---------+-------------+--------------+
| Do        | 8,000   | 4      | \$50    | \$1.6       | \-\--        |
| cumenting |         |        |         |             |              |
| DIMP      |         |        |         |             |              |
| processes |         |        |         |             |              |
+-----------+---------+--------+---------+-------------+--------------+
| Id        | 8,000   | 8      | \$50    | \$3.2       | \-\--        |
| entifying |         |        |         |             |              |
| threats   |         |        |         |             |              |
+-----------+---------+--------+---------+-------------+--------------+
| Periodic  | 8,000   | 4      | \$50    | \-\--       | \$1.6        |
| updates   |         |        |         |             |              |
| and       |         |        |         |             |              |
| revisions |         |        |         |             |              |
+-----------+---------+--------+---------+-------------+--------------+
| TOTAL     |         |        |         | \$12.8      | \$1.6        |
+-----------+---------+--------+---------+-------------+--------------+
| ***Grand  |         |        |         |             |              |
| Total***  |         |        |         |             |              |
+-----------+---------+--------+---------+-------------+--------------+
| GRAND     |         |        |         | \$66.7      | \$7.5        |
| TOTAL     |         |        |         |             |              |
+-----------+---------+--------+---------+-------------+--------------+

On a per operator basis, the cost of developing an IMP for large
operators will be approximately \$180 thousand in the first year and
\$20 thousand in each subsequent year, the cost for small operators will
be approximately \$16 thousand in the first year and \$2,000 in each
subsequent year, and the cost for master meter and LPG systems will be
approximately \$2,000 in the first year and less than \$500 in each
subsequent year.

**7.2.3 Implementing an Integrity Management Program**

Distribution system operators will have 18 months after the final rule
is issued to develop and implement their integrity management programs.
The time allowed between the issuing of the final rule and integrity
management program implementation is provided in order to allow
operators to make any modifications their operations and maintenance
procedures may need, as well as any modifications their business
practices may need.

Implementation of integrity management programs includes a variety of
activities, such as assembling and reviewing information about the
infrastructure of an operator's pipeline, evaluating threats and risks,
measuring performance, and deciding on improvements. These activities
will generally need to be undertaken by experienced pipeline safety
professionals.

A key element of integrity management program implementation will be the
active and continual integration of all information relevant to the
integrity of the pipeline covered by that program. This integration is
essential if pipeline operators are to fully consider the unique risks
that each of their individual distributions systems pose. Successful
integrity management requires operators to view their systems as a
whole, and information integration is the general mechanisms that will
allow them do that.

Based on discussions with industry organizations representing operators
that will be affected by the proposed regulatory changes, PHMSA
identified the following as being key activities associated with the
implementation of an integrity management program:

-   Software acquisition (or upgrade)

-   Data acquisition and analysis

-   Database maintenance

Table 14 presents PHMSA's estimates of the cost of integrity management
implementation listed by type of operator. Those estimates were
developed following discussions with industry representatives.

For this analysis, only large operators are assumed to need to acquire
or upgrade risk analysis software. Software acquisition includes not
only the purchase of risk-analysis software, but also the cost of any
training that may be needed. It assumes that the operators have in-house
personnel who can successfully operate the software (with training). In
addition, only large operators are assumed to need significant database
maintenance. The costs of database maintenance for small operators and
master meter and LPG systems are expected to be nominal.

In total, PHMSA estimates that the cost of the data analysis activities
will be \$57.5 million dollars in the first year and \$20.7 million in
each subsequent year. Of this total, large operators will pay \$36.0
million in the first year and \$11.8 million in each subsequent year,
small operators will pay \$18.3 million in the first year and \$7.3
million in each subsequent year, and master meter and LPG systems will
pay \$3.2 million in the first year and \$1.6 million in each subsequent
year.

**TABLE 14. ESTIMATED COSTS OF IMPLEMENTING AN INTEGRITY MANAGEMENT
PROGRAM**

+-----------+---------+--------+---------+-------------+--------------+
| **Type of | *       | *      | **Labor | **Total     | **Total      |
| Operator  | *Number | *Labor | Rate    | Annual Cost | Annual Cost  |
| and       | of      | Hours  | (Fully  | in Year 1** | in Year 2    |
| A         | Oper    | per    | loaded  |             | and On**     |
| ctivity** | ators** | Oper   | cost    | **(\$       |              |
|           |         | ator** | per     | Million)**  | **(\$        |
|           |         |        | labor   |             | Million)**   |
|           |         |        | hour)** |             |              |
+===========+=========+========+=========+=============+==============+
| ***Large  |         |        |         |             |              |
| Ope       |         |        |         |             |              |
| rators*** |         |        |         |             |              |
+-----------+---------+--------+---------+-------------+--------------+
| Software  | 201     | Total  |         | \$5.0       | \-\--        |
|           |         | cost   |         |             |              |
|           |         | per    |         |             |              |
|           |         | ope    |         |             |              |
|           |         | rator: |         |             |              |
|           |         | \$     |         |             |              |
|           |         | 25,000 |         |             |              |
+-----------+---------+--------+---------+-------------+--------------+
| Data      | 201     | 2,200  | \$70    | \$31.0      | \$6.8        |
| ac        |         | in yr. |         |             |              |
| quisition |         | 1;     |         |             |              |
| and       |         |        |         |             |              |
| analysis  |         | 480 in |         |             |              |
|           |         | yrs. 2 |         |             |              |
|           |         | & on   |         |             |              |
+-----------+---------+--------+---------+-------------+--------------+
| Database  | 201     | Total  |         | \-\--       | \$5.0        |
| ma        |         | cost   |         |             |              |
| intenance |         | per    |         |             |              |
|           |         | ope    |         |             |              |
|           |         | rator: |         |             |              |
|           |         | \$     |         |             |              |
|           |         | 25,000 |         |             |              |
+-----------+---------+--------+---------+-------------+--------------+
| TOTAL     |         |        |         | \$36.0      | \$11.8       |
+-----------+---------+--------+---------+-------------+--------------+
| ***Small  |         |        |         |             |              |
| Ope       |         |        |         |             |              |
| rators*** |         |        |         |             |              |
+-----------+---------+--------+---------+-------------+--------------+
| Software  | 1,090   | \-\--  | \-\--   | \-\--       | \-\--        |
+-----------+---------+--------+---------+-------------+--------------+
| Data      | 1,090   | 240 in | \$70    | \$18.3      | \$7.3        |
| ac        |         | yr. 1; |         |             |              |
| quisition |         | 96 in  |         |             |              |
| and       |         | yrs. 2 |         |             |              |
| analysis  |         | & on   |         |             |              |
+-----------+---------+--------+---------+-------------+--------------+
| Database  | 1,090   | \-\--  | \-\--   | \-\--       | \-\--        |
| ma        |         |        |         |             |              |
| intenance |         |        |         |             |              |
+-----------+---------+--------+---------+-------------+--------------+
| TOTAL     |         |        |         | \$18.3      | \$7.3        |
+-----------+---------+--------+---------+-------------+--------------+
| ***Master |         |        |         |             |              |
| Meter and |         |        |         |             |              |
| LPG       |         |        |         |             |              |
| S         |         |        |         |             |              |
| ystems*** |         |        |         |             |              |
+-----------+---------+--------+---------+-------------+--------------+
| Software  | 8,000   | \-\--  | \-\--   | \-\--       | \-\--        |
+-----------+---------+--------+---------+-------------+--------------+
| Data      | 8,000   | 8 in   | \$50    | \$3.2       | \$1.6        |
| ac        |         | yr. 1; |         |             |              |
| quisition |         | 4 in   |         |             |              |
| and       |         | yrs. 2 |         |             |              |
| analysis  |         | & on   |         |             |              |
+-----------+---------+--------+---------+-------------+--------------+
| Database  | 8,000   | \-\--  | \-\--   | \-\--       | \-\--        |
| ma        |         |        |         |             |              |
| intenance |         |        |         |             |              |
+-----------+---------+--------+---------+-------------+--------------+
| TOTAL     |         |        |         | \$3.2       | \$1.6        |
+-----------+---------+--------+---------+-------------+--------------+
| ***Grand  |         |        |         |             |              |
| Total***  |         |        |         |             |              |
+-----------+---------+--------+---------+-------------+--------------+
| GRAND     |         |        |         | \$57.5      | \$20.7       |
| TOTAL     |         |        |         |             |              |
+-----------+---------+--------+---------+-------------+--------------+

On a per operator basis, the cost of implementing an integrity
management program for large operators will be approximately \$179
thousand in the first year and \$59 thousand in each subsequent year.
The cost for small operators will be approximately \$17 thousand in the
first year and \$7 thousand in each subsequent year, and the cost for
master meter and LPG systems will be less than \$500 in the first year
and less than \$500 in each subsequent year.

**7.2.4 Mitigating Risks**

As part of an overall integrity management program, the proposed rule
requires operators to take action to mitigate any known risks and
thereby improve the safety of their systems. The specific actions taken
will vary depending on the applicable threats, their prevalence, and the
current risks posed by the pipelines. In addition to any other risk
reduction programs they may implement, the proposed rule requires all
operators to implement two particular risk reduction programs: (1) an
effective leak reduction program and (2) an enhanced damage prevention
program. Additionally, under the proposed rule, EFV installation is
mandatory, with limited exceptions. Master meter and LPG systems would
be exempt from this requirement.

##### *Leak Management*

In distribution systems one significant element of operator efforts to
manage risks is identifying and fixing severe leaks.  These leaks,
whatever their cause, can lead to gas migration to buildings,
accumulation in these buildings, ignition and fire - potentially causing
injury or death to residents.  All operators are currently required to
periodically survey for leaks.  The DIMP requirements will strengthen
existing leak detection requirements.[^47] The five elements of leak
detection management plan are:

-   Locate the leak.

-   Evaluate its severity.

-   Act to mitigate the hazard.

-   Keep records.

-   Self-assess to determine if additional actions are necessary to keep
    the system safe.

Operators that that do not repair, but monitor, non-hazardous leaks will
need to include criteria in the DIMP plan for evaluating their potential
hazard.

The net effect of leak management requirements in DIMP would be to
reduce leak-caused incidents by redirecting operator resources to higher
risk segments of piping.

Industry sources indicate that operators would increase their leak
surveys as a consequence of the proposed rule and also to increase the
mileage of pipe replaced.  Additional pipe may also be replaced for
reasons other than leak management, of course. The requirement will help
ensure that operators have leak management programs that adequately
protect the public.  Additionally, the requirement should help ensure
that distribution system operators readily adopt any future improvements
in leak management.

**Damage Prevention**

Under 49 CFR 192.614, all natural gas distribution systems must have a
program to prevent damage from excavation activities, including
excavation, blasting, boring, tunneling, backfilling, the removal of
aboveground structures, and other earthmoving operations. Gas pipeline
operators may comply with any of the requirements of the section 192.614
through participation in a public service program, such as a one-call
system. Furthermore, if a qualified one-call system operates in the
area, gas pipeline operators must participate in it. A one-call system
is considered a qualified one-call system if it operates in a State that
has adopted a one-call damage prevention program under 49 CFR 198.37 or
if it is operated in accordance with 49 CFR 198.39.

PHMSA incorporated by reference the guidelines provided in the American
Petroleum Institute (API) Recommended Practice (RP) 1162, ''Public
Awareness Programs for Pipeline Operators.'' (See 49 CFR 192.616.) The
regulations require that an operator follow the general program
recommendations, including baseline and supplemental requirements of API
RP 1162, unless the operator provides justification in its program or
procedural manual as to why compliance with all or certain provisions of
the recommended practice is not practicable and not necessary for
safety.[^48]

In addition to damage prevention programs, public awareness programs can
also help reduce excavation damage to pipelines. As the term implies,
the basic purpose of public awareness programs is to educate the general
public about the presence of, and the potential danger inherent, in
pipelines. An effective public awareness program can increase awareness
of the risks caused by unintentional pipeline releases and their impact
on the public and the environment. Public awareness programs identify
how risks can be prevented or mitigated. Through public awareness, these
programs can help prevent excavation damage, as well as reduce
encroachment on pipeline rights-of-way, improve pipeline safety, and
enhance emergency response.

Currently, natural gas distribution system operators have excavation
damage prevention programs. In addition, all natural gas distribution
system operators have public awareness programs, although PHMSA is
currently in the process of relieving master meter and LPG systems from
the requirement.

PHMSA and its constituents fully endorse maximum, effective damage
prevention. All parties believe these programs are vital to continued
improvements in damage prevention and safe pipeline operations. The
proposed rules would require gas distribution system operators to
develop and implement an enhanced damage prevention program. This would
go beyond what the operators currently have in place. As the PIPES Act
indicates, such a program should, at a minimum, have the following
elements:

[]{.mark}

-   Enhanced communications between pipeline system operators and
    excavators

-   The fostering of support and partnership among all stakeholders

-   The use of performance measures by operators

-   A partnership in employee training

-   A partnership in public education

-   A dispute resolution process

-   The use of technology, where appropriate, to improve processes

-   The analysis of data to periodically evaluate and improve program
    effectiveness.

Natural gas distribution system operators have some requirements of
excavation of the damage prevention and public awareness programs;
however, substantial differences are exist among operators'
programs.[^49] Results of a National Association of Pipeline Safety
Representatives (NASPR) survey (conducted in 2004-2005) indicated States
can and do exercise authority beyond minimum Federal requirements.
Additional requirements are focused in scope, and vary from State to
State, based on local needs and issues. Programs to replace older,
inferior infrastructure are the most widespread practice beyond Federal
requirements. Such programs are in progress in two-thirds of the States,
but some of these programs are of limited scope (i.e., affecting a
single operator). [^50] Still, despite these State efforts, serious
incidents continue to occur on distribution pipeline systems.

For operators with programs that incorporate most (or some) of the
elements required by this rule, the rule will enhance their programs by
building on elements that already exist (e.g., public awareness
programs), or would exist under the proposed rule (e.g., performance
measures). These operators' costs will not increase (or at least not
increase significantly). For operators that do not have many of the
elements of the proposed rule in place, there will be additional costs.
PHMSA does not know to what extent the costs would increase for those
entities. PHMSA invites comment on this.

**Excess Flow Valves**

An excess flow valve (EFV) is a device that can be installed in a
service line to automatically shut off the flow of gas if that service
line is severed or severely damaged downstream of the valve. EFVs can
thus mitigate the consequences of such incidents.

As required by Section 11 of the PIPES Act, the proposed rule requires
gas distribution system operators (with the exception of master meter
and LPG systems) to install EFVs on single family residential service
lines if

-   The service line is installed or entirely replaced after June 1,
    2008

-   The service line operates continuously throughout the year at a
    pressure of not less than 10 psig

-   The service line is not connected to a gas stream with contaminants
    that could interfere with the operation of an excess flow valve.

-   The installation is not likely to cause loss of service to the
    residence or interfere with necessary operation or maintenance
    activities, such as purging liquids from the service line, and

-   An excess flow valve is available that meets the performance
    standards in 49 C.F.R. 192.381.

Operators of natural gas service lines must report annually on the
number of excess flow valves installed on their systems.

After discussions with industry organizations representing operators
that will be affected by the proposed regulatory changes, PHMSA
estimates that an additional 400,000 EFVs would be installed annually as
a direct consequence of the proposed rule.[^51] To derive this estimate,
PHMSA assumes that large and small gas distribution system operators
install approximately 1,250,000 new services annually and completely
replace 500,000 services annually. Of these 1,750,000 services,
approximately 31%, or 542,500 services (= 1,750,000 x 0.31), do not have
the proper operating conditions for an EFV (i.e., they operate at less
than 10 psig, are services off cast iron mains, or are multi-family
services). Of the remaining 1,207,500 services (= 1,750,000 -- 542,500),
PHMSA estimates that 66%, or 796,950 services (= 1,207,500 x 0.66),
would have EFV installed in them even in the absence of the proposed
rule. That leaves 410,550 services (= 1,207,500 -- 796,950). Of those,
approximately 10,550 are estimated to be inappropriate for EFVs because
of line contaminants or other reasons. That leaves 400,000 services (=
410,550 -- 10,550) annually upon which EFVs could be installed.

Of the 400,000 additional EFVs estimated to be installed annually to
meet the proposed requirement, PHMSA estimates that large operators
would install 364,966 additional EFVs (= 400,000 x 54.9/60.17), while
small operators would annually install 35,034 additional EFVs (= 400,000
x 5.27/60.17).[^52] PHMSA expects that the installation of EFVs,
including the cost of those EFVs, would be \$20 for large operators and
\$30 for small operators. Consequently, the additional annual costs for
large operators attributable to EFVs would be \$7,299,320 (= 364,966 x
\$20), while the additional annual costs for small operators
attributable to small operators would be \$1,051,020 (= 35,034 x \$30).
Master meter and LPG systems would not be required to install EFVs under
the proposed rule. In total, the additional annual costs attributable to
EFVs would be \$8,350,340 (= \$7,299,320 + \$1,051,020).

**Mitigating Other Risks**

The proposed rule would require operators to use their measured
performance to determine whether further improvements are needed and, if
so, to make appropriate changes to their integrity management programs,
their infrastructure, and their operations and maintenance activities.
All operators are required to conduct continual program evaluations
(i.e., reviews of their measured performance) at least once every five
years. Consequently, at least once every five years, operators will need
to identify and make any changes needed by their integrity management
programs, as well as to their infrastructure and the operations and
maintenance activities covered by those programs.

The costs associated with this review requirement will be contingent on
(1) the problems and issues revealed by the performance measures, (2)
the frequency of reviews, and (3) the selected solutions to problems and
approaches to handling issues. Because of these uncertainties, the costs
of mitigating other risks are difficult to estimate. For this analysis,
PHMSA estimates that the costs of mitigating other risks will equal 10%
of the sum of the estimates for all other mitigation.

***Estimated Costs of Mitigation***

The costs of mitigation resulting from the proposed rule are unknown and
must be estimated. The field activities that an operator could take to
comply with the proposed rule include :

-   Replacing additional pipe.

-   Performing more leak surveys.

-   Installing additional EFVs.

-   Performing other field activities.

PHMSA recognizes that there are significant differences among operators
regarding risk assessment. Although mitigation of risk is a fundamental
requirement, under the proposed rule, operators retain the flexibility
to choose the mitigative activities they pursue. PHMSA expects that
operators will perform the most cost-effective mitigation activities to
fulfill the requirements.

Table 15 presents the estimated costs of all field activities associated
with the mitigation of risks required by the proposed rule. As mentioned
previously, for this analysis, the costs of performing other activities
are assumed to be equal to 10% of the combined estimated cost of all
other field activities (i.e., 10% of the costs of replacing additional
pipe plus the costs of performing more leak surveys plus the costs of
installing additional EFVs). The estimates in Table 15 were developed
after consultation with industry organizations representing operators
that will be affected by the proposed regulatory changes.

In developing the estimates presented in Table 15, it has been
assumed,[^53] as indicated in Table 12, that 35% of all cast iron lines
are not currently covered by cast iron pipe replacement programs, 26% of
all bare steel lines are not currently covered by bare steel replacement
programs, and 25% of all plastic lines are not currently covered by
vintage plastic replacement activities. Furthermore, for large
operators, it has been assumed that:

-   An additional 3.5% of cast iron mains and services will be replaced
    over a period of 50 years. This is 10% of the 35% of cast iron mains
    and services not currently covered by a replacement program.[^54]

-   An additional 1.3% of bare steel mains and services will be replaced
    over a period of 50 years. This is 5% of the 35% of bare steel mains
    and service not currently covered by a replacement program.[^55]

-   An additional 5% of copper services will be replaced over a period
    of 50 years.

-   An additional 2.5% of plastic mains and services will be replaced
    over a period of 50 years.

Similarly, for small operators, it has been assumed that:

-   An additional 2.6% of bare steel mains and services will be replaced
    over a period of 50 years.

-   An additional 10% of copper services will be replaced over a period
    of 50 years.

-   An additional 5% of plastic mains and services will be replaced over
    a period of 50 years.

Finally, for master meter and LPG systems, it has been assumed that:

-   An additional 35 miles of bare steel mains will be replaced over a
    period of 50 years.

-   An additional 3,604 bare steel services will be replaced over a
    period of 30 years.

-   An additional 49 miles of plastic mains will be replaced over a
    period of 30 years.

-   An additional 3,615 plastic services will to be replaced over a
    period of 30 years.

It should be noted, these actions are over and above replacement that is
currently being undertaken by distribution system operators.

The estimated costs of cast iron and bare steel pipe replacement on
mains used in this analysis (\$475,200 per mile and \$279,145 per mile,
respectively) may be high given that new technology allows plastic
liners to be inserted inside existing pipe. This technology should be
dramatically less costly than digging up and physically replacing the
existing pipe.

The estimates in Table 15 are listed by type of operator. In total,
PHMSA estimates that the cost of the field activities will be \$60.4
million dollars in the second and each subsequent year. Of this total,
large operators will pay \$53.1 million in the second and each
subsequent year, small operators will pay \$5.8 million in the second
and each subsequent year, and master meter and LPG systems will pay
\$1.5 million in the second and each subsequent year.

[]{.mark}

On a per operator basis, the cost of integrity management program field
activities for large operators will be approximately \$264,000 in the
second and each subsequent year, the cost for small operators will be
approximately \$5,000 in the second and each subsequent year, and the
cost for master meter and LPG systems will be less than \$500 in the
second and each subsequent year.

**TABLE 15. ESTIMATED COSTS OF INTEGRITY MANAGEMENT PROGRAM MITIGATION**

+-----------+-----------+-----------------+-------------+-------------+
| **Type of | **Cost**  | **Miles of main | **Total     | **Total     |
| Operator  |           | or number of    | Annual Cost | Annual Cost |
| and       |           | services        | in Year 1** | in Year 2   |
| A         |           | impacted, or    |             | and On**    |
| ctivity** |           | labor hours     | **(\$       |             |
|           |           | required**      | Million)**  | **(\$       |
|           |           |                 |             | Millions)** |
+===========+===========+=================+=============+=============+
| ***Large  |           |                 |             |             |
| Ope       |           |                 |             |             |
| rators*** |           |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| Replacing |           |                 |             |             |
| a         |           |                 |             |             |
| dditional |           |                 |             |             |
| pipe\--   |           |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| -≤8" cast | \$475     | 24.2 miles      | \$0         | \$11.5      |
| iron      | ,200/mile |                 |             |             |
| mains     |           |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| -Cast     | \$2,20    | 90.3 services   | \$0         | \$0.2       |
| iron      | 0/service |                 |             |             |
| services  |           |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| -Bare     | \$279     | 17.5 miles      | \$0         | \$4.9       |
| steel     | ,145/mile |                 |             |             |
| mains     |           |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| -Bare     | \$2,20    | 1,064 services  | \$0         | \$2.3       |
| steel     | 0/service |                 |             |             |
| services  |           |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| -Copper   | \$2,20    | 1,203.1         | \$0         | \$2.6       |
| services  | 0/service | services        |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| -Plastic  | \$132     | 19.9 miles      | \$0         | \$2.6       |
| mains     | ,000/mile |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| -Plastic  | \$2,20    | 854 services    | \$0         | \$1.9       |
| services  | 0/service |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| -SUBTOTAL |           |                 | \$0         | \$26.0      |
+-----------+-----------+-----------------+-------------+-------------+
| P         |           |                 |             |             |
| erforming |           |                 |             |             |
| more leak |           |                 |             |             |
| s         |           |                 |             |             |
| urveys\-- |           |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| -On mains | \         | 50,500 miles    | \$0         | \$8.8       |
|           | $175/mile |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| -On       | \$2.2     | 2,745,000       | \$0         | \$6.2       |
| services  | 5/service | services        |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| -SUBTOTAL |           |                 | \$0         | \$15.0      |
+-----------+-----------+-----------------+-------------+-------------+
| I         | \$2       | 364,966         | \$0         | \$7.3       |
| nstalling | 0/service | services        |             |             |
| a         |           |                 |             |             |
| dditional |           |                 |             |             |
| EFVs on   |           |                 |             |             |
| services  |           |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| P         |           |                 | \$0         | \$4.8       |
| erforming |           |                 |             |             |
| other     |           |                 |             |             |
| a         |           |                 |             |             |
| ctivities |           |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| TOTAL     |           |                 | \$0         | \$53.1      |
+-----------+-----------+-----------------+-------------+-------------+
| ***Small  |           |                 |             |             |
| Ope       |           |                 |             |             |
| rators*** |           |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| Replacing |           |                 |             |             |
| a         |           |                 |             |             |
| dditional |           |                 |             |             |
| pipe\--   |           |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| -Bare     | \$279     | 4.2 miles       | \$0         | \$1.2       |
| steel     | ,145/mile |                 |             |             |
| mains     |           |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| -Bare     | \$1,50    | 204.3 services  | \$0         | \$0.3       |
| steel     | 0/service |                 |             |             |
| services  |           |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| -Copper   | \$1,00    | 232.7 services  | \$0         | \$0.2       |
| services  | 0/service |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| -Plastic  | \$132     | 4.7 miles       | \$0         | \$0.6       |
| (PVC,     | ,000/mile |                 |             |             |
| ABS)      |           |                 |             |             |
| mains     |           |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| -Plastic  | \$1,00    | 163.9 services  | \$0         | \$0.2       |
| (PVC,     | 0/service |                 |             |             |
| ABS)      |           |                 |             |             |
| services  |           |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| -SUBTOTAL |           |                 | \$0         | \$2.5       |
+-----------+-----------+-----------------+-------------+-------------+
| P         |           |                 |             |             |
| erforming |           |                 |             |             |
| more leak |           |                 |             |             |
| s         |           |                 |             |             |
| urveys\-- |           |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| -On mains | \         | 6,000 miles     | \$0         | \$1.1       |
|           | $175/mile |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| -On       | \$2.2     | 263,500         | \$0         | \$0.6       |
| services  | 5/service | services        |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| -SUBTOTAL |           |                 | \$0         | \$1.7       |
+-----------+-----------+-----------------+-------------+-------------+
| I         | \$3       | 35,034 services | \$0         | \$1.1       |
| nstalling | 0/service |                 |             |             |
| a         |           |                 |             |             |
| dditional |           |                 |             |             |
| EFVs on   |           |                 |             |             |
| services  |           |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| P         |           |                 | \$0         | \$0.5       |
| erforming |           |                 |             |             |
| other     |           |                 |             |             |
| a         |           |                 |             |             |
| ctivities |           |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| TOTAL     |           |                 | \$0         | \$5.8       |
+-----------+-----------+-----------------+-------------+-------------+
| ***Master |           |                 |             |             |
| Meter and |           |                 |             |             |
| LPG       |           |                 |             |             |
| S         |           |                 |             |             |
| ystems*** |           |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| Replacing |           |                 |             |             |
| a         |           |                 |             |             |
| dditional |           |                 |             |             |
| pipe\--   |           |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| -Bare     | \$156     | 0.7 miles       | \$0         | \$0.1       |
| steel     | ,667/mile |                 |             |             |
| mains     |           |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| -Bare     | \$1,50    | 72.1 services   | \$0         | \$0.1       |
| steel     | 0/service |                 |             |             |
| services  |           |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| -Copper   | \$1,00    | 679.4 services  | \$0         | \$0.7       |
| services  | 0/service |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| -Plastic  | \$132     | 1.6 miles       | \$0         | \$0.2       |
| (PVC,     | ,000/mile |                 |             |             |
| ABS)      |           |                 |             |             |
| mains     |           |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| -Plastic  | \$1,00    | 120.5 services  | \$0         | \$0.1       |
| (PVC,     | 0/service |                 |             |             |
| ABS)      |           |                 |             |             |
| services  |           |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| -SUBTOTAL |           |                 | \$0         | \$1.2       |
+-----------+-----------+-----------------+-------------+-------------+
| P         |           |                 |             |             |
| erforming |           |                 |             |             |
| more leak |           |                 |             |             |
| s         |           |                 |             |             |
| urveys\-- |           |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| -On mains | \         | 800 miles       | \$0         | \$0.1       |
|           | $175/mile |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| -On       | \$2.2     | 80,000 services | \$0         | \$0.2       |
| services  | 5/service |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| -SUBTOTAL |           |                 | \$0         | \$0.3       |
+-----------+-----------+-----------------+-------------+-------------+
| P         | \-\--     | \-\--           | \$0         | \$0.0       |
| erforming |           |                 |             |             |
| other     |           |                 |             |             |
| a         |           |                 |             |             |
| ctivities |           |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| TOTAL     |           |                 | \$0         | \$1.5       |
+-----------+-----------+-----------------+-------------+-------------+
| ***Grand  |           |                 |             |             |
| Total***  |           |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+
| GRAND     |           |                 | \$0         | \$60.4      |
| TOTAL     |           |                 |             |             |
+-----------+-----------+-----------------+-------------+-------------+

[Notes]{.underline}: (Assumptions based on information from industry
sources, except where specified)

\(1\) Examples of activities that might be undertaken under "Performing
other activities" include

\--Correcting cathodic protection deficiencies to combat external
corrosion

\--Installing pipe liners to combat internal corrosion

\--Improving the accuracy of line locating to combat third party and
operator damage

\--Relocating facilities that are hard to protect to combat vandalism.

\(2\) For large operators:

\--An additional 3.5% of cast iron mains and services are assumed to be
replaced over a period of 50 years. This is 10% of the 35% of cast iron
mains and services not currently covered by a replacement program (see
the American Gas Foundation, "Safety Performance and Integrity of
Natural Gas Infrastructure," January 2005, at
<http://www.gasfoundation.org/ResearchStudies/safety_perf.htm>).

\--An additional 1.3% of bare steel mains and services are assumed to be
replaced over a period of 50 years. This is 5% of the 35% of bare steel
mains and service not currently covered by a replacement program (see
the American Gas Foundation, "Safety Performance and Integrity of
Natural Gas Infrastructure," January 2005, at
<http://www.gasfoundation.org/ResearchStudies/safety_perf.htm>).

\--An additional 5% of copper services are assumed to be replaced over a
period of 50 years.

\--An additional 2.5% of plastic mains and services are assumed to be
replaced over a period of 50 years.

\--EFVs are installed annually on 364,966 services (see Sec. 6.3.3.3).

\(3\) For small operators:

\--Steel and copper replacements are prorated from large operators using
mileage or number of services, as appropriate.

\--An additional 2.6% of bare steel mains and services are assumed to be
replaced over a period of 50 years.

\--An additional 10% of copper services are assumed to be replaced over
a period of 50 years.

\--An additional 5% of plastic mains and services are assumed to be
replaced over a period of 50 years.

\--EFVs are installed annually on 35,034 services (see Sec. 6.3.3.3).

\(4\) For master meter and LPG systems:

\--An additional 35 miles of bare steel mains are assumed to be replaced
over a period of 50 years.

\--An additional 3,604 bare steel services are assumed to be replaced
over a period of 50 years.

\--An additional 20,381 copper services are assumed to be replaced over
a period of 30 years.

\--An additional 49 miles of plastic mains are assumed to be replaced
over a period of 30 years.

\--An additional 3,615 plastic services are assumed to be replaced over
a period of 30 years.

**State Requirements*\
***\
Distribution pipelines are intrastate pipelines. Under the pipeline
safety program, certified States may exercise regulatory oversight over
these operations. A certified State must enforce at least the Federal
regulations, but may also impose additional requirements. States also
foster programs that improve pipeline safety outside their regulatory
structure, for example, via their rate setting process.***\
***\
A 2004-2005 survey by the National Association of Pipeline Safety
Representatives (NAPSR) identified that many States impose additional
safety requirements on gas distribution pipelines.[^56] Many of these
requirements address actions to prevent or detect damage by outside
forces or to conduct additional surveys to detect and repair leaks. In
addition, approximately two-thirds of States have some type of program
to require replacement of certain types of distribution pipeline (e.g.,
cast iron, uncoated steel, copper, and some kinds of plastic pipe) that
are more prone to failures resulting in release of gas and therefore
accident risk.

These additional State requirements help ensure the integrity and safety
of gas distribution pipelines.  The costs associated with these
requirements are assumed to have already been incurred.  PHMSA invites
comment on this.

**Gas Distribution System Operators with DIMP-like Programs**

There are significant differences among operators' risk assessment and
safety programs, some are comprehensive while others are less so. PHMSA
is attempting to standardize industry practices, while providing enough
flexibility to accommodate the diversity. Some gas distribution
operators are expected to already have some programs similar to the one
in the proposed rule. PHMSA expects that such programs cover perhaps as
much as 25% of all distribution system mileage.

Some of the features of the DIMP programs that have been already
implemented by operators are based on the State requirements mentioned
previously. Some operators may have implemented other programs because
they make good business sense. They reduce the overall costs of those
operators. PHMSA assumes some of the costs associated with these
requirements may have already have been incurred by some operators, but
because of the differences among operators' programs and the different
ways they may choose to address the requirements, PHMSA can not estimate
the magnitude of the additional costs. PHMSA invites comments on this.

**7.2.5 Reporting to PHMSA and State Regulators**

The proposed rule would require each impacted operator, except master
meter and LPG systems, to report certain performance measures to PHMSA
and State regulators annually. The report to PHMSA must be made as part
of the annual report required by 49 CFR 191.11. That report must contain
information about the following four performance measures:

-   Number of leaks removed per section 192.793(c) (i.e., because they
    were hazardous), by cause.

-   Number of excavation damages.

-   Number of excavation tickets.

-   Number of EFVs installed.

Other performance measures that might also be included in the required
reports are:

-   Total number of leaks removed, categorized by cause.

-   Number of leaks removed per section 192.793(c) (i.e., because they
    were hazardous), categorized by material.

-   Percentage of each pipe material in operator's system.

-   Progress in refining the operator's understanding of its
    infrastructure.

Distribution operators will incur additional reporting costs
attributable to the proposed rule. PHMSA expects the costs will depend
on the type of operation and experience of the operator with reporting.
PHMSA believes that typically there is a learning curve when operators
are subject to new requirements. Based on past experience with different
rules, PHMSA estimates that the cost to add additional information to
the annual report will be nominal. (The average hourly wage for a
compliance officer is estimated at \$40 per hour, including benefits. If
we assume that the additional time to include these parameters in their
annual reports is 1 hour per operator, the additional cost per operator,
per year would be would be about \$40 (\$40\*1)). This estimate also
assumes that the format of the information provided to PHMSA in the
annual reports will be acceptable to the States and no additional
reports or telephone communication will be needed to comply with the
requirement. PHMSA invites comment on this.

**7.2.6 Recordkeeping**

The proposed rule would require that each operator impacted by that rule
keep certain records. At a minimum, those records must include

-   A written integrity management program

-   Documents supporting threat identification

-   A written procedure of ranking threats

-   Documents supporting any decision, analysis, or process developed
    and used to implement and evaluate each element of the integrity
    management program

-   Records identifying changes made to the integrity management program
    or its elements, including a description of the changes and the
    reasons they were made

Operators must keep the records for the useful life of the pipeline.

Based on previous experience with record keeping requirements, PHMSA
expects the cost of the required recordkeeping to be nominal. Some of
the required records will be kept electronically, while others will be
kept on paper. In the case of those kept electronically, the required
recordkeeping will necessitate a company clerk entering data and in some
cases scanning materials. In the case of those kept on paper, the
required recordkeeping will necessitate a company clerk placing
materials in file folders, placing the file folders in file cabinets,
and retrieving files, when needed. It may also necessitate a system for
signing materials in and out. Finally, in some cases, physical
recordkeeping may necessitate the acquisition of file cabinets and file
folders by some operators. (The average hourly salary -- including
benefits - for a clerk is estimated at \$20. If we assume that the
average time to perform these tasks is one-half hour per month, or 6
hours per year, the total cost per operator, per year would be
approximately \$120 (\$20\*6)). There is no expectation that the
recordkeeping would require operators to hire additional personnel.
Neither is there an expectation that the recordkeeping would require
operators to acquire new computers or peripherals. PHMSA invites
comments on this.

**7.2.7 Managing the Distribution Integrity Management Program**

Each operator will need to manage its distribution integrity management
program. That management will help ensure the proper functioning of each
operator's program, including coordination among and between its various
parts. In addition to providing oversight and guidance, the managers of
each operator's program will serve as points of contact and advocates
for the program within the operator's management structure.

Because the program is new, the costs of managing it are unknown and
consequently must be estimated. Table 16 presents PHMSA's estimates of
the costs of managing the program for large operators, small operators,
and master meter and LPG systems, as well as the total cost to the gas
distribution industry of managing the integrity management program. The
estimates in Table 16 were developed following discussions with gas
distribution industry representatives.

PHMSA's estimates assume that the management requirements will be
significantly greater in the first year, when the programs are being
created, than in subsequent years. For example, PHMSA estimates that
large operators will need to devote one-half of a labor year to
integrity management program management in the first year, but only
one-quarter of a labor year to management in subsequent years.

In total, PHMSA estimates that the cost of DIMP management will be
\$30.9 million dollars in the first year and \$15.5 million in each
subsequent year. Of this total, large operators will pay \$14.0 million
in the first year and \$7.0 million in each subsequent year, small
operators will pay \$7.3 million in the first year and \$3.7 million in
each subsequent year, and master meter and LPG systems will pay \$9.6
million in the first year and \$4.8 million in each subsequent year.

**TABLE 16. ESTIMATED COSTS OF DISTRIBUTION INTEGRITY MANAGEMENT PROGRAM
MANGEMENT**

+-----------+---------+--------+---------+-------------+--------------+
| **Type of | *       | *      | **Labor | **Total     | **Total      |
| O         | *Number | *Labor | Rate    | Annual Cost | Annual Cost  |
| perator** | of      | Hours  | (Fully  | in Year 1** | in Year 2    |
|           | Oper    | per    | loaded  |             | and On**     |
|           | ators** | Oper   | cost    | **(\$       |              |
|           |         | ator** | per     | Million)**  | **(\$        |
|           |         |        | labor   |             | Million)**   |
|           |         |        | hour)** |             |              |
+===========+=========+========+=========+=============+==============+
| Large     | 201     | 996 in | \$70    | \$14.0      | \$7.0        |
| Operators |         | yr. 1; |         |             |              |
|           |         | 498 in |         |             |              |
|           |         | yrs. 2 |         |             |              |
|           |         | & on   |         |             |              |
+-----------+---------+--------+---------+-------------+--------------+
| Small     | 1,090   | 96 in  | \$70    | \$7.3       | \$3.7        |
| Operators |         | yr. 1; |         |             |              |
|           |         | 48 in  |         |             |              |
|           |         | yrs. 2 |         |             |              |
|           |         | & on   |         |             |              |
+-----------+---------+--------+---------+-------------+--------------+
| Master    | 8,000   | 24 in  | \$50    | \$9.6       | \$4.8        |
| Meter and |         | yr. 1; |         |             |              |
| LPG       |         | 12 in  |         |             |              |
| Systems   |         | yrs. 2 |         |             |              |
|           |         | & on   |         |             |              |
+-----------+---------+--------+---------+-------------+--------------+
| TOTAL     |         |        |         | \$30.9      | \$15.5       |
+-----------+---------+--------+---------+-------------+--------------+

On a per operator basis, the cost of managing an integrity management
program for large operators will be approximately \$70,000 in the first
year and \$35,000 in each subsequent year. The cost for small operators
will be approximately \$7,000 in the first year and \$3,000 in each
subsequent year, and the cost for master meter and LPG systems will be
approximately \$1,000 in the first year and \$1,000 in each subsequent
year.

PHMSA's estimates may overstate the net additional cost of management
attributable to the proposed rule. Currently, operators have activities
and programs in place, including leak and damage prevention programs,
which will likely be brought under the DIMP umbrella by those operators
if the proposed rule is implemented. Those activities and programs, as a
consequence, may need less management than they did before. This
potential reduction in the cost of managing currently existing
activities is not included in PHMSA's estimates.

**7.2.8 [Total Cost]{.underline}**

Table 17 summarizes the costs associated with the proposed rule. In
total, PHMSA expects the rule to cost operators \$155.1 million in the
first year and \$104.1 million in the second and subsequent years. Of
this total, large operators will pay \$86.1 million in the first year
and \$76.0 million in every year thereafter, small operators will pay
\$43.4 million in the first year and \$18.6 million in every year
thereafter, and master meter and LPG systems will pay \$25.6 million in
the first year and \$9.5 million in every year thereafter.

**TABLE 17. SUMMARY OF COSTS ASSOCIATED WITH THE DISTRIBUTION INTEGRITY
MANAGEMENT PROGRAM**

+------------------------------+--------------------+-----------------+
| **Type of Operator and Cost  | **Total Annual     | **Total Annual  |
| Category**                   | Cost in Year 1**   | Cost in Year 2  |
|                              |                    | and On**        |
|                              | **(\$ Million)**   |                 |
|                              |                    | **(\$           |
|                              |                    | Millions)**     |
+==============================+====================+=================+
| ***Large Operators***        |                    |                 |
+------------------------------+--------------------+-----------------+
| Developing program           | \$36.1             | \$4.1           |
+------------------------------+--------------------+-----------------+
| Data acquisition and         | \$36.0             | \$11.8          |
| analysis                     |                    |                 |
+------------------------------+--------------------+-----------------+
| Mitigation                   | \-\--              | \$53.1          |
+------------------------------+--------------------+-----------------+
| Reporting                    | Nominal            | Nominal         |
+------------------------------+--------------------+-----------------+
| Recordkeeping                | Nominal            | Nominal         |
+------------------------------+--------------------+-----------------+
| Management                   | \$14.0             | \$7.0           |
+------------------------------+--------------------+-----------------+
| TOTAL                        | \$86.1             | \$76.0          |
+------------------------------+--------------------+-----------------+
| ***Small Operators***        |                    |                 |
+------------------------------+--------------------+-----------------+
| Developing program           | \$17.8             | \$1.8           |
+------------------------------+--------------------+-----------------+
| Data acquisition and         | \$18.3             | \$7.3           |
| analysis                     |                    |                 |
+------------------------------+--------------------+-----------------+
| Mitigation                   | \-\--              | \$5.8           |
+------------------------------+--------------------+-----------------+
| Reporting                    | Nominal            | Nominal         |
+------------------------------+--------------------+-----------------+
| Recordkeeping                | Nominal            | Nominal         |
+------------------------------+--------------------+-----------------+
| Management                   | \$7.3              | \$3.7           |
+------------------------------+--------------------+-----------------+
| TOTAL                        | \$43.4             | \$18.6          |
+------------------------------+--------------------+-----------------+
| ***Master Meter and LPG      |                    |                 |
| Systems***                   |                    |                 |
+------------------------------+--------------------+-----------------+
| Developing program           | \$12.8             | \$1.6           |
+------------------------------+--------------------+-----------------+
| Data acquisition and         | \$3.2              | \$1.6           |
| analysis                     |                    |                 |
+------------------------------+--------------------+-----------------+
| Mitigation                   | \-\--              | \$1.5           |
+------------------------------+--------------------+-----------------+
| Reporting                    | Nominal            | Nominal         |
+------------------------------+--------------------+-----------------+
| Recordkeeping                | Nominal            | Nominal         |
+------------------------------+--------------------+-----------------+
| Management                   | \$9.6              | \$4.8           |
+------------------------------+--------------------+-----------------+
| TOTAL                        | \$25.6             | \$9.5           |
+------------------------------+--------------------+-----------------+
| GRAND TOTAL                  | \$155.1            | \$104.1         |
+------------------------------+--------------------+-----------------+

On a per operator basis, the total cost of an integrity management
program for large operators will be approximately \$428,000 in the first
year and \$378,000 in each subsequent year. The cost for small operators
will be approximately \$40,000 in the first year and \$17,000 in each
subsequent year, and the cost for master meter and LPG systems will be
approximately \$3,000 in the first year and \$1,000 in each subsequent
year.

[]{.mark}

Based on the total cost estimates for the first and subsequent years,
the present value of the costs of the proposed rule calculated over 50
years with a 3% discount rate would be \$2.7 billion, while the present
value of the proposed rule calculated over 50 years with a 7% discount
rate would be \$1,484 million.

PHMSA encourages comment on the cost estimates developed for this
analysis.

## [7.3 Comparison of Benefits and Costs]{.underline}

The benefits resulting from the proposed rule are estimated to be \$214
million per year. The costs of the proposed rule are estimated to be
\$155.1 million in the first year and \$104.1 million in each subsequent
year. Table 18 gives the present values for these estimated benefits and
costs over 50 years at 3% and 7% discount rates.

**TABLE 18. PRESENT VALUES OF BENEFITS, COSTS, and NET BENEFITS OF THE
PROPOSED RULE CALCULATED OVER 50 YEARS**

**(All dollars in millions)**

  --------------- --------------------- ---------------- ----------------
  **Discount      **Benefits**          **Costs**        **Net Benefits**
  Rate**                                                 

  3%              \$5,506               \$2,728          \$2,778

  7%              \$2,953               \$1,484          \$1,469
  --------------- --------------------- ---------------- ----------------

As can be seen from Table 18, the estimated present value of net
benefits of the proposed rule is positive at each discount rate. At the
3 percent discount rate there appears to be about \$2.8 billion in net
benefits over the 50-year period, and at 7 percent about \$1.5 billion
over 50 years.

# 8. UNCERTAINTY ANALYSES

There are many uncertainties associated with this analysis. To deal with
those uncertainties, various assumptions were made. For example, to deal
with the uncertainties associated with incidents in the future, it has
been assumed that the future will resemble the recent past.

Rather than attempt to detail the impact of each assumption
individually, the aggregate impact of the assumptions associated with
each of the benefits and costs derived for this analysis is examined
below. Because assumptions are made for each benefit and for each cost,
looking at their contribution to the total of benefits or costs is one
way of assessing the aggregate impact of the assumptions.

Table 19 presents the contributions that (1) each of the benefits
addressed in this analysis make to the total present value of the
benefits of the proposed rule and (2) each of the costs addressed in
this analysis make to the total present value of the costs of the
proposed rule.

**TABLE 19. IMPACT OF THE EXPECTED BENEFITS ON THE PRESENT VALUE OF
BENEFITS AND THE EXPECTED COSTS ON THE PRESENT VALUE OF COSTS FOR THE
DISTRIBUTION INTEGRITY MANAGEMENT PROGRAM**

+--------------+-------------+-------------+------------+------------+
| **Benefit    | **Present   | **Present   | **Percent  | **Percent  |
| and Cost     | Value with  | Value with  | of Total   | of Total   |
| Categories** | 3% Discount | 7% Discount | When       | When       |
|              | Rate**      | Rate**      | Discount   | Discount   |
|              |             |             | Rate Is    | Rate Is    |
|              | **(\$       | **(\$       | 3%**       | 7%**       |
|              | Million)**  | Million)**  |            |            |
+==============+=============+=============+============+============+
| **           |             |             |            |            |
| *Benefits*** |             |             |            |            |
+--------------+-------------+-------------+------------+------------+
| Reduced      | \$1,544     | \$828       | 28%        | \*         |
| reportable   |             |             |            |            |
| incident     |             |             |            |            |
| consequences |             |             |            |            |
+--------------+-------------+-------------+------------+------------+
| Reduced      | \$720       | \$386       | 13%        | \*         |
| no           |             |             |            |            |
| n-reportable |             |             |            |            |
| incident     |             |             |            |            |
| consequences |             |             |            |            |
+--------------+-------------+-------------+------------+------------+
| Lowered      | \$154       | \$83        | 3%         | \*         |
| chance of a  |             |             |            |            |
| catastrophic |             |             |            |            |
| incident     |             |             |            |            |
+--------------+-------------+-------------+------------+------------+
| Reduced lost | \$1,955     | \$1,049     | 36%        | \*         |
| gas          |             |             |            |            |
+--------------+-------------+-------------+------------+------------+
| Reduced      | \$283       | \$152       | 5%         | \*         |
| emergency    |             |             |            |            |
| response     |             |             |            |            |
| costs        |             |             |            |            |
+--------------+-------------+-------------+------------+------------+
| Reduced      | \$129       | \$69        | 2%         | \*         |
| evacuations  |             |             |            |            |
+--------------+-------------+-------------+------------+------------+
| Reduced      | \$695       | \$373       | 13%        | \*         |
| non-gas      |             |             |            |            |
| dig-ins      |             |             |            |            |
+--------------+-------------+-------------+------------+------------+
| End of       | \$26        | \$14        | \<1%       | \*         |
| existing EFV |             |             |            |            |
| notification |             |             |            |            |
| requirement  |             |             |            |            |
+--------------+-------------+-------------+------------+------------+
| TOTAL        | \$5,506     | 2,954       |            |            |
+--------------+-------------+-------------+------------+------------+
| ***Costs***  |             |             |            |            |
+--------------+-------------+-------------+------------+------------+
| Developing   | \$250       | \$159       | 9%         | 11%        |
| program      |             |             |            |            |
+--------------+-------------+-------------+------------+------------+
| Data         | \$568       | \$320       | 21%        | 22%        |
| acquisition  |             |             |            |            |
| and analysis |             |             |            |            |
+--------------+-------------+-------------+------------+------------+
| Mitigation   | \$1,495     | \$777       | 55%        | 52%        |
+--------------+-------------+-------------+------------+------------+
| Reporting    | \-\--       | \-\--       | \-\--      | \-\--      |
+--------------+-------------+-------------+------------+------------+
| R            | \-\--       | \-\--       | \-\--      | \-\--      |
| ecordkeeping |             |             |            |            |
+--------------+-------------+-------------+------------+------------+
| Management   | \$414       | \$228       | 15%        | 15%        |
+--------------+-------------+-------------+------------+------------+
| TOTAL        | \$2,728     | \$1,484     | 100%       | 100%       |
+--------------+-------------+-------------+------------+------------+

[Note]{.underline}: \* = Same as percentage with 3% discount rate.

Reduced lost gas is the most significant contributor, accounting for 28%
of the total present value of benefits. With respect to costs, the most
significant contributor to the total present value of costs is
mitigation, which accounts for 52%-55% of the total present value of
costs

## [8.1 Analyses Excluding Benefits of Reduced Lost Gas and Reduced Losses From High Consequence Events]{.underline}

Assumptions with respect to the benefits attributed to, for example,
reduced lost gas or reduced costs associated with low probability/high
consequence events, which are uncertain rare events, can be examined for
whether they alter the net benefits of the proposed rule if those
benefits are not realized.

Reduced lost gas benefits were estimated at \$76 million per year. If
those benefits are eliminated from the previously estimated annual
benefits of \$214 million (See Table 18) the present value of expected
benefits (discounted at 3 percent) falls from \$5,506 million to \$3,551
million. This level of benefits is still greater than the 3% present
value discounted costs of \$2,728 billion. If the reduced benefits of
reduced lost gas are discounted at 7 percent, the present value of
benefits falls from \$2,953 to \$1,905 million, which is still greater
than the 7% present value, discounted costs of \$1,484. With these
scenarios there are still positive net benefits without any benefits
from reduced lost gas. See Table 20 below.

##### 

**TABLE 20. PRESENT VALUES OF BENEFITS, COSTS, and NET BENEFITS
EXCLUDING BENEFITS OF REDUCED LOST GAS (\$76 Million)**

**(All dollars in millions)**

  --------------- --------------------- ---------------- ----------------
  **Discount      **Benefits**          **Costs**        **Net Benefits**
  Rate**                                                 

  3%              \$3,551               \$2,728          \$823

  7%              \$1,905               \$1,484          \$421
  --------------- --------------------- ---------------- ----------------

Based on the analysis in the absence of the \$76 million in benefits due
to reduced lost gas, it is obvious that eliminating the \$5.7 million
annual benefits due to reduced losses from high consequence events will
not alter the outcome of the analysis. However, we can also examine the
effect of eliminating benefits from both reduced gas lost and reduced
costs associated with high consequence events. Taking both benefits from
the \$214 million annual benefits reduces the annual benefits to \$132.3
million \[\$214 million -- (\$76 million + \$5.7 million)\]. The
discounted present value over 50 years (at 3 and 7 percent) is \$3,404
million and \$1,826 million respectively, which is still greater than
the present value of the respective costs discounted at 3 and 7 percent.
There are still positive net benefits without benefits of either reduced
lost gas or reduced costs of high consequence events. See Table 21
below.

**TABLE 21. PRESENT VALUES OF BENEFITS, COSTS, and NET BENEFITS
EXCLUDING REDUCED LOST GAS AND REDUCED LOSSES FROM HIGH CONSEQUENCE
EVENTS (\$81.7 Million)**

**(All dollars in millions)**

  --------------- --------------------- ---------------- ----------------
  **Discount      **Benefits**          **Costs**        **Net Benefits**
  Rate**                                                 

  3%              \$3,404               \$2,728          \$676

  7%              \$1,826               \$1,484          \$345
  --------------- --------------------- ---------------- ----------------

## [8.2 Effectiveness Analysis]{.underline}

The benefit-cost analysis in previous sections depended upon making
assumptions about the effectiveness of the proposed rule in reducing
various components of the societal costs associated with gas
distribution systems. For example, the analysis assumes that the rule
will reduce 50 percent of the costs associated with reportable incidents
and 10 percent of the costs associated with lost gas. The predicted
outcome of the analysis in terms of net benefits will vary as the levels
of effectiveness vary.

An alternative evaluation of the proposed rule's assumptions, and the
robustness of the Department's conclusions, is to determine the overall
level of effectiveness in reducing societal costs associated with gas
distribution systems that must be attained to cover the estimated costs
of the rule. From the benefit analysis earlier in this report the annual
societal cost are approximately those illustrated in the table below.

**TABLE 22. CONTRIBUTORS TO SOCIETAL COSTS**

+------------------------------------------+---------------------------+
| **Incidents and other Contributors to    | **Estimate**              |
| Societal Costs Associated with Gas       |                           |
| Distribution**                           | **(Million dollars per    |
|                                          | year)**                   |
+------------------------------------------+---------------------------+
| Reportable Incidents                     | 87                        |
+------------------------------------------+---------------------------+
| Non-reportable Incidents                 | 56                        |
+------------------------------------------+---------------------------+
| High consequence incidents               | 8                         |
+------------------------------------------+---------------------------+
| Lost Gas                                 | 759                       |
+------------------------------------------+---------------------------+
| Emergency Response Costs                 | 44                        |
+------------------------------------------+---------------------------+
| Evacuations                              | 5                         |
+------------------------------------------+---------------------------+
| Non-Gas Excavations                      | 108                       |
+------------------------------------------+---------------------------+
| Existing EFV Notification Requirement    | 1                         |
+------------------------------------------+---------------------------+
|                                          |                           |
+------------------------------------------+---------------------------+
| TOTAL                                    | \$1,068                   |
+------------------------------------------+---------------------------+

The costs of the proposed rule are estimated to be about \$155 million
the first year and about \$104 in each year thereafter. If there are to
be the level of benefits to equal those costs, then the proposed rule
would have to be about 14.5 percent (\$155/1068 \* 100) effective in
reducing overall societal costs the first year, and about 9.7 percent
(104/1068\*100) effective in subsequent years.

# 9. SUMMARY AND CONCLUSIONS

PHMSA proposes to revise the Pipeline Safety Regulations to require
operators of gas distribution pipelines to develop and implement
programs that will better assure the integrity of their pipeline
systems. The proposed regulations require distribution pipeline
operators to implement an IMP similar to those required for gas
transmission pipelines.

The proposed rule is expected to impact 201 local gas utilities with
over 12,000 services, 1,090 local gas utilities with 12,000 or fewer
services, and 8,000 master meter and LPG systems. The larger local gas
utilities are estimated to have over 1 million miles of mains and nearly
55 million services, while the smaller utilities are estimated to have
over 100 thousand miles of mains and approximately 5 million services.
Master meter and LPG systems are estimated to have 8 thousand miles of
mains and 800 thousand services.

The readily monetized benefits resulting from the proposed rule are
estimated to be \$214 million per year. The monetized benefits include:

-   Reductions in the consequences of reportable incidents.

-   Reductions in the consequences of non-reportable incidents.

-   A reduction in the probability of a major catastrophic incident.

-   Reductions in lost natural gas.

-   Reductions in emergency response costs.

-   Reductions in evacuations.

-   Reductions in dig-ins impacting non-gas underground facilities.

-   The end of the existing EFV notification requirement.

The costs of the proposed rule are estimated to be \$155.1 million in
the first year and \$104.1 million in each subsequent year. The costs
include:

-   Development of an IMP.

-   Implementation of the IMP (data acquisition and analysis).

-   Mitigation of risks.

-   Reporting to PHMSA and State regulators.

-   Recordkeeping.

-   Management of the IMP.

[]{.mark}

The present value of the monetized benefits of the proposed rule is
estimated to be about \$5.5 billion calculated over 50 years using a 3%
discount rate and about \$3.0 billion calculated over 50 years using a
7% discount rate. The present value of the estimated costs of the
proposed rule would be expected to be \$2.7 billion over 50 years using
a 3% discount rate and about \$1.5 billion over 50 years using a 7%
discount rate. Based on these calculations, the best estimate of the
present value of expected net benefits is between \$1.5 and \$2.8
billion over a 50-year period.

Another conclusion is that for the proposed rule to be cost-effective,
the societal costs associated with the risks and hazards associated with
gas distribution systems need to be reduced by about 14.5 percent per
year on average over a 50-year period.

This economic evaluation suggests that the proposed rule is in the
public interest because there are expected net benefits and there is
relatively low rate of realized benefits for the proposed rule to be
cost effective.

# Regulatory Flexibility Analysis

**Integrity Management Program for Gas Distribution Pipelines**

[]{.mark}

[]{.mark}

**Introduction**

The Regulatory Flexibility Act of 1980 (Public Law 96-354) requires
agencies to evaluate the potential effects of their proposed and final
rules on small businesses, small organizations, and small governmental
jurisdictions. The Regulatory Flexibility Act requires that Federal
agencies take small entities' concerns into account when developing,
writing, publicizing, promulgating, and enforcing regulations. To this
end, the Act requires that agencies detail how they have met these
concerns, by including a Regulatory Flexibility Analysis (RFA).  An
initial RFA, which accompanies a Notice of Proposed Rulemaking (NPRM),
must include the following five elements:

1)  A description of the reasons why action by the Agency is being
    considered;

2)  A succinct statement of the objectives of, and legal basis for, the
    proposed rule;

3)  A description of and, where feasible, an estimate of the number of
    small entities to which the proposed rule would apply;

4)  A description of the proposed reporting, recordkeeping, and other
    compliance requirements of the proposed rule, including an estimate
    of the classes of small entities that would be subject to the
    requirements and the type of professional skills necessary for
    preparing the report or record; and

5)  Identification, to the extent practicable, of all Federal rules
    which may duplicate, overlap, or conflict with the proposed rule.

A discussion of these requirements follows.

*1. A description of the reasons why action by the Agency is being
considered.*

In 2004, the U.S. Department of Transportation (DOT) Inspector General
(IG) pointed out that recent accident trends for gas distribution
pipelines were unfavorable and suggested that the application of
integrity management principles could help improve the safety of
distribution pipelines.

The IG recommended to Congress[^57] that DOT define an approach for
requiring operators of distribution pipeline systems to implement some
form of integrity management or enhanced safety program with elements
similar to those required in hazardous liquid and transmission pipeline
integrity management programs (IMPs). The Appropriations Committee then
asked PHMSA "to report to the House and Senate Committees on
Appropriations by May 1, 2005, detailing the extent to which integrity
management program elements may be applied to the natural gas
distribution pipeline industry in order to enhance distribution system
safety."[^58] PHMSA submitted the report "Assuring the Integrity of Gas
Distribution Pipeline Systems" to Congress in June 2005, which describes
the program used to identify opportunities for improving the safety of
distribution pipeline systems.

PHMSA proceeded to develop the IMP for gas distribution pipelines in two
phases. Phase 1 identified the nature of requirements that might be
imposed and any additional guidance or consensus standards that might be
needed to assist operators in implementing any integrity management
requirements. Phase 2 included development of appropriate requirements
by PHMSA and preparation of guidance/standards by appropriate bodies.
PHMSA determined that in order to address safety threats to distribution
pipelines and develop a sensible strategy to reduce threats, the Agency
needed to involve a number of key stakeholder groups, including State
and Federal regulators, representatives from the spectrum of
distribution operators, interested members of the public, and
representatives of our Nation's fire service. The stakeholders agreed
with the DOT IG and Congress's recommendations and concluded the current
pipeline safety regulations (49 CFR Part 192) do not include a
risk-based integrity management process for gas distribution pipelines
and that it would be appropriate to modify the regulations to
incorporate such a requirement.[^59] The study group gathered and
analyzed data to help focus the effort and ultimately identify options
for attaining improved safety.

*2. A succinct statement of the objectives of, and legal basis for, the
proposed rule.*

In response to the mandate concerning IMPs for distribution systems
contained in The Pipeline Inspection, Protection, Enforcement and Safety
Act of 2006 (Public Law No: 109-468, Dec. 29, 2006), also known as the
PIPES Act. PHMSA is initiating this rulemaking. PHMSA is extending its
integrity management approach to the largest segment of the Nation's
pipeline network -- the distribution systems that directly serve homes,
schools, businesses, and other natural gas consumers. Beginning in 2000,
the agency promulgated regulations requiring operators of hazardous
liquid pipelines (49 CFR 195.452, published at 65 FR 75378 and 67 FR
2136) and gas transmission pipelines (49 CFR 192, Subpart O, published
at 68 FR 69778) to develop and follow individualized IMPs, in addition
to PHMSA's core pipeline safety regulations.

PHMSA proposes to require operators of gas distribution pipelines to
develop and implement IMPs that will better assure the integrity of
their pipeline systems. Each IMP must contain the following elements:

-   Improving knowledge of the system's infrastructure.

-   Identifying threats (existing and potential).

-   Evaluating and prioritizing risks.

-   Identifying and implementing measures to mitigate risks.

-   Measuring performance, monitoring results, and evaluating
    effectiveness.

-   Periodic re-evaluation and improvement.

-   Reporting results..

All of the above elements pertain to distribution operators with the
exception of master meter and LPG distribution systems. The IMPs of
master meter and LPG systems must include all of the elements listed
above except (1) evaluating and prioritizing risks and (2) reporting
results.

In addition, the proposed rule requires the installation of EFVs, where
practicable, on all new and renewed single-family residential services
operating at at least 10 psig. Master meter and LPG systems would be
exempt from this requirement. The proposed mandatory installation
renders the current customer EFV notification requirement (see 49 CFR
192.383) moot. Consequently, the proposed rule would eliminate that
requirement.

*3. A description of and, where feasible, an estimate of the number of
small entities to which the proposed rule would apply.*

The proposed rule would affect operators of (1) local gas distribution
utilities and (2) master meter and LPG systems. The number of operators
impacted by the proposed rule is unknown and must be estimated.
Furthermore, the size of the operators impacted by the proposed rule is
also unknown and, consequently, must also be estimated.

The impacted operators all belong to North American Industry
Classification System (NAICS) 221210, Natural Gas Distribution. In
accordance with size standards published by the Small Business
Administration, a business with 500 or fewer employees is considered a
small entity in this NAICS.[^60]

PHMSA expects 1,291 local gas distribution utilities and 8,000 master
meter and LPG systems to be impacted by the proposed rule. Based on
information from Dun & Bradstreet (August 2006) on firms in NAICS
221210, PHMSA estimates that 78% of the local gas distribution utilities
have 500 or fewer employees. That is, PHMSA estimates that 1,007 of the
local gas distribution utilities impacted by the proposed rule will have
500 or fewer employees. Furthermore, PHMSA assumes that all 8,000 master
meter and LPG systems will have 500 or fewer employees. Thus, in total,
PHMSA expects that 9,007 small entities will be impacted by the proposed
rule.

The 1291 local gas distribution utilities were divided in the analysis
performed by PHMSA into those with greater than 12,000 services and
those with 12,000 or fewer services. A total of 201 operators fell into
the first category, while 1,090 operators fell into the second. Costs
were separately estimated for each category.

For this analysis, none of those with greater than 12,000 services are
assumed to be small entities as defined by the SBA. That is, the 1,007
local gas distribution utilities that are small entities are all assumed
to have 12,000 or fewer services. PHMSA estimates that the proposed rule
will cost each operator in this category, on average, approximately
\$40,000 in the first year and \$17,000 in each subsequent year.

PHMSA estimates that the proposed rule will cost each of the estimated
8,000 master meter and LPG systems that it impacts, on average,
approximately \$3,000 in the first year and \$1,000 in each subsequent
year. PHMSA does not have information on the operators' revenues and
cannot, therefore, estimate what percent of revenues the cost
represents. PHMSA requests comment on the impact on these operators.

There is currently no case law that identifies the "trigger" levels of
"significant economic impact," or "substantial number of small
entities." However, because the purpose of the analysis is to aid the
decision maker in resolving regulatory issues affecting small entities,
it is SBA's opinion that any rulemaking generating the interest of a
significant number of small entities warrants the application of the
RFA\'s analysis tools.[^61] PHMSA prepared the analysis required by the
Regulatory Flexibility Act.[^62] As a consequence of the foregoing, the
proposed rule is expected by PHMSA to impact a substantial number
(9,007) of small entities. The breakdown of these between those that are
very small operations and those that are small by SBA definitions is
unknown. Few, if any, of the small gas distribution utilities with
12,000 or fewer services are expected to be very small operations.
Almost all of the master meter and LPG systems will be small.. For
example, while a master meter or LPG system serving a small trailer park
might potentially be a very small operation, master meter and LPG
systems operated by public housing authorities or by colleges and
universities will not be. The proposed rule could result in a
significant adverse economic impact for at least some of those small
entities, since for some of the small operators the costs associated
with the proposed rule may be significant.

[Alternate proposals for small businesses]{.underline}: The RFA 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.

For the proposed distribution IMP rule, PHMSA will be taking a number of
steps to meet its safety objectives without unduly burdening small
business. PHMSA's actions include the following:

-   PHMSA will not require master meter and LPG systems to comply with
    all of the requirements of the proposed rule. PHMSA feels that it is
    possible to do this without compromising safety because of the
    nature of the master meter and LPG systems.

-   PHMSA is preparing guidance to help master meter and LPG systems
    implement certain requirements of gas integrity management.

-   PHMSA would be willing to consider extending the limitations on the
    applicability of the integrity management requirements that it
    proposes for master meter and LPG systems to other operators if
    reasonable criteria can be defined to identify operators for which
    such limitation are appropriate. This willingness to extend the
    limitations is explicitly stated in the preamble to the proposed
    rule. Industry is encouraged by PHMSA to comment on this.

-   PHMSA will modify its *Guidance Manual for Operators of Small
    Natural Gas Systems*[^63] to include information that can help small
    entities understand and comply with the distribution integrity
    management program requirements if the proposed rule is adopted. The
    manual has been developed by PHMSA to provide an overview of
    pipeline compliance responsibilities under the federal pipeline
    safety regulations for the non-technically trained person who
    operates a master meter system, a small municipal system, or small
    independent system. Similarly, PHMSA will also modify its *Guidance
    Manual for Operators of Small LP Gas Systems* if the proposed rule
    is adopted.[^64]

In addition to the foregoing, industry is undertaking a number of
initiatives that will help small entities comply with the proposed rule,
including the following:

-   The Gas Pipeline Technology Committee (GPTC) will prepare guidance
    material to assist operators, including small distribution system
    operators, with development of an integrity management program.

The American Public Gas Association (APGA) Security and Integrity
Foundation (SIF) will develop a model Distribution Integrity Management
Program to assist small utilities in developing integrity management
programs meeting the requirements of the proposed rule. The end product
will be a simple and handy risk-based integrity management program.

*4. A description of the proposed reporting, recordkeeping, and other
compliance requirements of the proposed rule, including an estimate of
the classes of small entities that would be subject to the requirements
and the type of professional skills necessary for preparing the report
or record.*

The proposed rule would require that each operator impacted by that rule
keep certain records. At a minimum, those records must include:

-   A written integrity management program.

-   Documents supporting threat identification.

-   A written procedure of ranking threats.

-   Documents supporting any decision, analysis, or process developed
    and used to implement and evaluate each element of the integrity
    management program.

-   Records identifying changes made to the integrity management program
    or its elements, including a description of the changes and the
    reasons they were made.

Operators must keep the records for the useful life of the pipeline.

PHMSA estimates some of the required records will be kept
electronically, while others will be kept on paper. In the case of those
kept electronically, the required recordkeeping will necessitate a
company clerk entering data and in some cases, scanning materials. In
the case of the paper records, the required recordkeeping will
necessitate a company clerk placing materials in file folders, storing
them, and retrieving files, when needed. It may also necessitate a
system for signing materials in-and-out. Finally, in some cases,
physical recordkeeping may necessitate the acquisition of file cabinets
and supplies by some operators. There is no expectation that the
recordkeeping would require operators to hire additional personnel.
Neither is there an expectation that the recordkeeping would require
operators to acquire new computers or peripherals. PHMSA assumes that
the proposed rule does not add significantly to the distribution
operators' current recordkeeping requirements, particularly since the
proposed rule would remove the EFV customer notification requirement.
Currently, on average, the EFV burden is estimated at almost 18 hours
and \$905 dollars per operator.

*5. Identification, to the extent practicable, of all Federal rules
which may duplicate, overlap, or conflict with the proposed rule.*

There are no related rules or regulations issued by other departments or
agencies of the Federal Government.

[^1]: Integrity Management for Gas Distribution. Report of Phase I
    Investigations. December 2005. See
    <http://www.cycla.com/opsiswc/docs/S8/P0068/DIMP_Phase1Report_Final.pdf>,
    p.13.

[^2]: GAO, Gas Pipeline Safety, Preliminary Observations on the
    Integrity Management program and 7-Year Reassessment Requirement,
    GOO-06-474T, Testimony Before the Subcommittee on Highways, Transit
    and Pipelines, Committee on Transportation and Infrastructure, House
    of Representatives.

[^3]: "Progress and Challenges in Improving Pipeline Safety," Statement
    of the Honorable Kenneth M. Mead, Inspector General, Department of
    Transportation, before the Committee on Energy and Commerce,
    Subcommittee on Energy and Air Quality, U.S. House of
    Representatives, July 20, 2004.

[^4]: House of Representatives report 108-792, November 20, 2004.

[^5]: "Integrity Management for Gas Distribution, Report of Phase 1
    Investigations," prepared by Joint Work/Study Groups, December 2005,
    U.S. DOT/PHMSA - Report: DIMP Phase 1, Doc. Number:
    RSPA-2004-19854-70, available at
    http://dmses.dot.gov/docimages/p84/388302.pdf

[^6]: The group was composed of representatives of the natural gas
    distribution industry, state pipeline regulatory authorities and the
    public. See
    <http://www.cycla.com/opsiswc/docs/S8/P0068/DIMP_Phase1Report_Final.pdf>,
    p.71.

[^7]: See
    <http://www.cycla.com/opsiswc/docs/S8/P0068/DIMP_Phase1Report_Final.pdf>,
    p.71.

[^8]: Integrity management for Gas Distribution. Report of Phase I
    Investigations. December 2005. See
    <http://www.cycla.com/opsiswc/docs/S8/P0068/DIMP_Phase1Report_Final.pdf>,
    p.13-14.

[^9]: See
    <http://www.cycla.com/opsiswc/docs/S8/P0068/DIMP_Phase1Report_Final.pdf>,
    p.72

[^10]: Information on the number of services and pipe length for master
    meter systems is limited. According to PHMSA, "Assessment of the
    need for an improved inspection program for Master Meter Systems,"
    January 2002, p. 7, at <http://ops.dot.gov/pubs/Mastermeter.pdf>,
    the average number of customers of master meter systems in Maryland
    was reported to be 284, while 7 of the 8 master meter systems known
    to be operating in Nevada were reported to have from 100 to 275
    customers, and the average length of underground or exterior piping
    at master meter systems in Maryland was reported to be 2,764 feet
    (this includes both mains and services).

[^11]: This is the current estimate used by PHMSA for the length of a
    service.

[^12]: All monetary values, unless otherwise indicated, are in 2008
    constant dollars.

[^13]: NTSB reports. See http://www.ntsb.gov/publictn/2007/PAB0701.htm

[^14]: [Source]{.underline}: <http://ops.dot.gov/stats/stats.htm>.

[^15]: See 49 CFR 191.9.

[^16]: Assessment of the Need for an Improved Inspection Program for
    Master Meter Systems, A Report of the Secretary of Transportation to
    the Congress, prepared pursuant to Section 108 of Public Law
    100-561, p.17

[^17]: [Source]{.underline}: <http://ops.dot.gov/stats/stats.htm>.

[^18]: On February 5, 2008, the Department issued a memorandum on the
    "Treatment of the Economic Value of a Statistical Life in the
    Departmental Analyses" directing DOT analysts to use \$5.8 million
    as the best present estimate of the economic value of preventing
    human fatality. However the Department requested a supplementary
    analysis be conducted using values of \$3.2 million and \$8.4
    million for each life saved.

[^19]: The average injury requiring hospitalization is assumed to be a
    "Severe injury," as defined by DOT. 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.

[^20]: [Source]{.underline}: <http://ops.dot.gov/stats/stats.htm>.

[^21]: General Order 112-E Rule 122.2 d requires utilities to submit
    quarterly reports to the Commission of all gas leaks that involved
    loss of gas or property damage in excess of \$1,000, involving fire,
    explosion, or underground dig-ins.

[^22]: Communication from PHMSA, April 11, 2007.

[^23]: Communication from PHMSA, April 11, 2007.

[^24]: This assumption rests at least partly on a hypothesis that even
    if the short historical time series accurately reflects the expected
    probability of pipeline incidents, and even if that probability were
    expected to be normally distributed, the expected consequences of an
    event may not be normally distributed. In cases such as this, rare
    and extreme events would drive expected damages to a greater degree
    than their historical averages suggest. This addition to the
    analysis is intended to try and capture the influence of a rare,
    extreme event on future expected impacts. The Agency specifically
    requests comment on this addition to the analysis.

[^25]: NTSB Report Number PAR-97/01

[^26]: Peter Burgherr and Stefan Hirschberg, Comparative Assessment of
    Natural Gas Accident Risks, PSI Bericht Nr. 05-01, January 2005,
    available at
    <http://gabe.web.psi.ch/pdfs/PSI_Report/SVGW_PSI-Bericht-05-01.pdf>.

[^27]: EIA data from [www.eia.doe.gov](http://www.eia.doe.gov/)

[^28]: It is obvious that an accident of this magnitude would also
    result in significant consequences in terms of property damage. Such
    damage was not considered in the PSI study. The amount, although
    large, would likely be significantly less than the equivalent value
    of the deaths and injuries. For purposes of this analysis, PHMSA has
    conservatively ignored the contribution from property damage.

[^29]: U.S. EPA, "Inventory of U.S. Greenhouse Gas Emissions and Sinks:
    1990-2005," Public Review Draft, February 20, 2007,
    [epa.gov/climatechange/emissions/downloads07/07Energy.pdf](http://epa.gov/climatechange/emissions/downloads07/07Energy.pdf),
    pp. 3-46 to 3-47. A gigagram is a unit of weight equivalent to 10^9^
    grams.

[^30]: U.S. EPA, "Inventory of U.S. Greenhouse Gas Emissions and Sinks:
    1990-2005," Public Review Draft, February 20, 2007,
    [epa.gov/climatechange/emissions/downloads07/07Energy.pdf](http://epa.gov/climatechange/emissions/downloads07/07Energy.pdf),
    p. 3-46.

[^31]: This was the average city gate price in 2005, according to Energy
    Information Administration, "Natural Gas Annual 2005," Nov. 16,
    2006,
    [www.eia.doe.gov/pub/oil_gas/natural_gas/data_publications/natural_gas_annual/current/pdf/table_022.pdf](http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publications/natural_gas_annual/current/pdf/table_022.pdf),
    p.53.

[^32]: William P. Meade, "A First Pass at Computing the Cost of Fire
    Safety in a Modern Society," *Fire Technology*, November 1991, pp.
    341-345.

[^33]: William P. Meade, "A First Pass at Computing the Cost of Fire
    Safety in a Modern Society," *Fire Technology*, November 1991, pp.
    344-345.

[^34]: ^ ?^ William P. Meade, "A First Pass at Computing the Cost of
    Fire Safety in a Modern Society," *Fire Technology*, November 1991,
    pp. 344.

[^35]: Fax from Nancy Schwartz, National Fire Protection Association, to
    Dianne Sutherland, U.S. DOT, July 8, 1994.

[^36]: Conversations with local fire protection representatives have
    indicated that they want to be present at any incident involving a
    hazardous material.

[^37]: This appears to be a conservative estimate. According to the
    National Volunteer Fire Council Fact Sheet (see
    <http://www.nvfc.org/pdf/2005-fact-sheet.pdf>), (1) 73% of all
    firefighters are volunteers and (2) of the 30,542 fire departments
    in the U.S., 21,671 are staffed entirely by volunteers, while 5,271
    are mostly volunteer, 1,582 are mostly career, and 2,018 are staffed
    entirely by career firefighters.

[^38]: [Source]{.underline}: <http://ops.dot.gov/stats/stats.htm>

[^39]: "Comparative Risks of Hazardous Materials and Non-Hazardous
    Materials Truck Shipment Accidents/Incidents," FMCSA, Washington,
    DC, March 2001, p. 2-14. See
    <http://www.fmcsa.dot.gov/documents/hazmatriskfinalreport.pdf>.

[^40]: Gas pipeline incidents can cause further disruptions to nearby
    businesses and communities, preventing them from carrying on with
    everyday tasks. Customers and supplies may not be able to reach the
    establishments and shipments may not be able to leave the
    establishments even when they are not directly impacted by an
    evacuation.

[^41]: [Source]{.underline}: <http://ops.dot.gov/stats/stats.htm>

[^42]: [Source]{.underline}: <http://ops.dot.gov/stats/stats.htm>.

[^43]: Colorado Revised Statutes (C.R.S.) 9-1.5-103(7)(b).

[^44]: C.R.S. 9-1.5-103(7)(c)(d) and 9-1.5-105.

[^45]: These assumptions are based on, but not necessarily identical to,
    those found in the Final Rule for Excess Flow Valve Notification,
    which was published in the *Federal Register*, Vol. 63, 1998, pp.
    5464-5471.

[^46]: These assumptions are based on but not necessarily identical to
    those found in the Final Rule for Excess Flow Valve Notification,
    which was published in the *Federal Register*, Vol. 63, 1998, pp.
    5464-5471.

[^47]: Some States have leak management requirements or programs
    exceeding Part 192; however, these are often tailored for the local
    conditions (or types of systems) and may not be applicable to all
    operators in a given State or throughout the country. At this time,
    they do not appear appropriate for national requirements, but can be
    considered by operators in developing their individualized risk
    control program.

[^48]: "Integrity Management for Gas Distribution. " Report of Phase I
    Investigations", December 2005. Excavation Damage Group Report,
    p.188. See
    http://www.cycla.com/opsiswc/docs/S8/P0068/DIMP_Phase1Report_Final.pdf.

[^49]: PHMSA is currently in the process of relieving master meter and
    LPG systems from the public awareness requirement.

[^50]: NAPSR's members are the managers of the pipeline safety
    regulatory staff from each state (and the District of Columbia) that
    is certified by, or a designated agent of, DOT for regulatory
    oversight.

[^51]: That is, 400,000 EFVs over and above what operators currently
    install would be installed as a consequence of the proposed rule.

[^52]: From Table 1, large operators have 54,900,000 services and small
    operators have 5,270,000 services. In total, large and small
    operators together have 60,170,000 services.

[^53]: Assumptions are based upon information from industry sources,
    except where specified.

[^54]: See the American Gas Foundation, "Safety Performance and
    Integrity of Natural Gas Infrastructure," January 2005, at
    <http://www.gasfoundation.org/ResearchStudies/safety_perf.htm>.

[^55]: See the American Gas Foundation, "Safety Performance and
    Integrity of Natural Gas Infrastructure," January 2005, at
    <http://www.gasfoundation.org/ResearchStudies/safety_perf.htm>.

[^56]: For a more detailed summary, see the Notice of Proposed
    Rulemaking. For details about the survey, see documents 73 and 74 in
    Docket RSPA-2004-19854.

[^57]: "Progress and Challenges in Improving pipeline Safety," Statement
    of the Honorable Kenneth M.Mead, Inspector General, Department of
    transportation, before the Committee on energy and Commerce,
    Subcommittee on Energy and Air Quality, U.S. House of
    Representatives, July 20, 2004.

[^58]: House of Representatives report 108-792, November 20, 2004.

[^59]: "Integrity Management for Gas Distribution, Report of Phase 1
    Investigations", prepared by Joint Work/Study Groups, December 2005,
    U.S. DOT/PHMSA - Report: DIMP Phase 1, Doc. Number:
    RSPA-2004-19854-70, available at
    http://dmses.dot.gov/docimages/p84/388302.pdf

[^60]: <http://www.sba.gov/size/sizetable2002.pdf>.

[^61]: A Guide for Government Agencies, "How to Comply with the
    Regulatory Flexibility Act." See
    http://www.fws.gov/policy/library/rgSBAGuide.pdf

[^62]: "A Guide for Government Agencies. How to Comply with the
    Regulatory Flexibility Act." Implementing the President's Small
    Business Agenda and Executive Order 13272, May 2003, p.17.

[^63]: The Guidance Manual for Operators of Small Natural Gas Systems
    can be found on the PHMSA website at
    <http://ops.dot.gov/regs/small_ng/SmallNaturalGas.htm>.

[^64]: The Guidance Manual for Operators of Small LP Gas Systems can be
    found on the PHMSA website at
    <http://ops.dot.gov/regs/small_lp/SmallLPGas.htm>.