**TESTIMONY OF**

**TERRY BOSS**

**SENIOR VICE PRESIDENT**

**ENVIRONMENT, SAFETY AND OPERATIONS**

**INTERSTATE NATURAL GAS ASSOCIATION OF AMERICA**

**BEFORE THE**

**COMMITTEE ON COMMERCE, SCIENCE AND TRANSPORTATION**

**UNITED STATES SENATE**

**REGARDING**

**REAUTHORIZATION OF THE PIPELINE SAFETY ACT**

**NOVEMBER 16^TH^, 2006**

Mr. Chairman and Members of the Subcommittee:

Good morning. My name is Terry Boss, and I am Senior Vice President of
Environment, Safety and Operations for the Interstate Natural Gas
Association of America (INGAA). INGAA represents the interstate and
interprovincial natural gas pipeline industry in North America. INGAA's
members transport over 90 percent of the natural gas consumed in the
United States through a network of approximately 212,000 miles of
transmission pipeline. These large capacity pipelines spanning multiple
states or regions are analogous to the interstate highway system.

**INDUSTRY BACKGROUND**

Mr. Chairman, natural gas provides 25 percent of the energy consumed in
the U.S. annually, second only to petroleum and exceeding that of coal
or nuclear. From home heating and cooking, to industrial processes, to
power generation, natural gas is a versatile and strategically important
energy resource.

As a result of the regulatory restructuring of the industry during the
1980s and early 1990s, interstate natural gas pipelines no longer buy or
sell natural gas. Interstate pipelines do not take title to the natural
gas moving through their pipelines. Instead, pipeline companies sell
transportation capacity in much the same way as a railroad, airline or
trucking company.

Because the natural gas pipeline network is essentially a "just-in-time"
delivery system with limited storage capacity, customers large and small
depend on reliable around-the-clock service. That is an important reason
why the safe and reliable operation of our pipeline systems is so
important. The natural gas transmission pipelines operated by INGAA's
members and by others historically have been the safest mode of
transportation in the United States. The interstate pipeline industry,
working cooperatively with the Pipeline and Hazardous Materials Safety
Administration (PHMSA), is taking affirmative steps to make this
valuable infrastructure even safer.

Congressional involvement in pipeline safety dates back almost 40 years
to enactment of the Natural Gas Pipeline Safety Act in 1968. This
legislation borrowed heavily from the engineering standards that had
been developed over the previous decades. The goals of this federal
legislation were to ensure the consistent use of best practices for
pipeline safety across the entire industry, to encourage continual
improvement in safety procedures and to verify compliance. While
subsequent reauthorization bills have improved upon the original, the
core objectives of the federal pipeline safety law have remained a
constant.

**HOW SAFE ARE NATURAL GAS PIPELINES?**

While the safety record of natural gas transmission lines is not
perfect, it compares very well with that of other modes of
transportation. Since natural gas pipelines are buried and isolated from
the public, pipeline accidents involving fatalities and injuries are
unusual.

Pipeline accidents generally are reported to the Department of
Transportation when one of three things occurs: (1) a fatality, (2) an
injury or (3) \$50,000 or more in property damage. Recently, the
Department of Transportation has categorized most "reportable incidents"
either as "significant incidents" or as "serious incidents" and placed
that data on its web site.

"Serious incidents" are defined as incidents that involve fatalities and
injuries. The PHMSA graph below shows the decreasing trend of "serious
incidents" on natural gas transmission pipelines from 1989-2005. For the
last five years, the number of serious incidents that occurred on
natural gas transmission pipelines has averaged five incidents per year.

![](media/image1.jpeg){width="5.992361111111111in" height="3.86875in"}

It is instructive to look at the causes of these serious incidents for
clues on where to devote resources that can prevent serious incidents in
the future. The pie chart below depicts the causes of these serious
incidents. Since 2002, all the fatalities that have occurred during
"serious incidents" on natural gas transmission pipelines have been
excavation-related.

![](media/image2.wmf){width="5.059027777777778in"
height="4.352777777777778in"}

"Significant incidents" include not only the aforementioned "serious
incidents", but also reportable incidents where property damage and gas
lost exceeds \$50,000 in 1984 dollars. Property damage and natural gas
cost are adjusted using the Consumer Price Index for property damage and
the Energy Information Administration data for delivered gas cost. The
PHMSA graph below shows the trend of "significant incidents" on natural
gas transmission pipelines since 1989. It is worth noting that the spike
in "significant incidents" reported in 2005 reflects the pipeline damage
caused by hurricanes Rita and Katrina. Property damage jumped from an
average of \$40 million a year (2005 dollars) to over \$220 million in
2005. It is interesting to note that over 75 percent of these property
damage costs associated with gas transmission pipeline incidents are
either damage to the pipeline operator's facilities or the value of the
natural gas lost (i.e., these are not damages to third-party property).

![](media/image3.jpeg){width="5.997222222222222in"
height="2.2305555555555556in"}

As with the serious incidents, it is informative to understand the
causes of these significant incidents so that technology and management
practices can be focused on preventing future incidents. For example,
periodic inspections using smart pig technology are effective at
discovering "time dependent" defects, such as corrosion, before they
result in significant incidents. Periodic inspections, however, are not
effective in preventing "time independent" incidents such as external
force (i.e. excavation and weather-related damage). The pie chart below
depicts the causes of the reported significant incidents.

![](media/image4.wmf){width="4.930555555555555in" height="4.79375in"}

One note on the reportable incident statistics. From the raw data on
reportable natural gas transmission accidents over the last 10 years, it
could be concluded that the safety of natural gas transmission pipelines
has deteriorated, especially over the last six years. This conclusion
would be misleading, however, because the increase in the commodity
value of natural gas has skewed the number of reportable incidents. As
noted earlier, "reportable incidents" include those in which property
damage exceeds \$50,000 including the value of the natural gas lost in
the incident. Natural gas commodity prices have increased by over 200
percent since 2000, and this has significantly affected the number of
incidents where property damage has exceeded the \$50,000 threshold. In
examining the natural gas transmission integrity management program, the
Government Accountability Office (GAO) noted this anomaly (in report
06-946) and suggested that DOT amend the reporting criteria to eliminate
the linkage to natural gas commodity prices. While the establishment of
the significant and serious incidents categories by PHMSA accurately
depicts incident trends, INGAA agrees that the recommendation by GAO
would provide more accurate and useful accident data.

**THE PIPELINE SAFETY IMPROVEMENT ACT OF 2002 AND INTEGRITY MANAGEMENT**

While the Pipeline Safety Improvement Act of 2002 ("PSIA") focused on a
variety of issues (including operator qualification programs, public
education, and population encroachment on pipeline rights-of-way), the
most significant provision of the 2002 reauthorization law that will
improve long-term pipeline safety was the "Integrity Management Program"
("IMP") for natural gas transmission pipelines.

Section 14 of the PSIA requires operators of natural gas transmission
pipelines to: (1) identify all the segments of their pipelines located
in "high consequence areas" (areas adjacent to significant population);
(2) develop an integrity management program to reduce the risks to the
public in these high consequence areas; (3) undertake baseline integrity
assessments (inspections) at all pipeline segments located in high
consequence areas, to be completed within 10 years of enactment; (4)
develop a process for making repairs to any anomalies found as a result
of these inspections; and (5) reassess these segments of pipeline at
least every 7 years thereafter in order to verify continued pipe
integrity.

The PSIA requires that these integrity inspections be performed by one
of the following methods: (1) an internal inspection device (or a "smart
pig"); (2) hydrostatic pressure testing (filling the pipe with water and
pressurizing it well above operating pressures to verify a safety
margin); (3) direct assessment (digging up and visually inspecting
sections of pipe selected based on various electronic measurements and
other characteristics), or (4) "other alternative methods that the
Secretary of Transportation determines would provide an equal or greater
level of safety." The pipeline operator is required by regulations
implementing the 2002 law to repair all non-innocuous imperfections and
adjust operation and maintenance practices to minimize "reportable
incidents". For natural gas transmission pipelines, internal inspection
devices are the primary means for assessing integrity because, when they
can be used, such devices are more versatile and efficient. The other
assessment methods enumerated in the reauthorization law are useful when
smart pig technology cannot be effectively used. A drawback associated
with such alternatives is that they require a pipeline to cease or
significantly curtail gas delivery operations for a period.

There are some practical issues that must be addressed in order to
utilize "smart pig" inspection devices more fully:

-   First, older pipelines were not engineered to accept such inspection
    devices because these pipelines often were built with tight pipe
    bends, or non-full pipe diameter valves, continuous sections of pipe
    with varying diameters, and side lateral piping. While these
    features do not impede the movement of natural gas through the
    pipeline (because natural gas can be compressed), moving a solid
    object through such pipelines is another matter. These older
    pipeline systems must be modified to allow the use of internal
    inspection devices.

-   Another legacy issue is modifying pipelines to launch and receive
    internal inspection devices. Since a pipeline is buried underground
    for virtually its entire length, the installation of above-ground
    pig launchers and receivers is usually done at or near other
    above-ground locations, such as compressor stations. Occasionally,
    however, new sites must be obtained for these facilities. Compressor
    stations are typically located along the pipeline at a spacing of 75
    to 100 miles apart. Therefore, a set of launchers and receivers must
    be installed for every pipeline segment between compressor stations
    because the inspection device cannot go through a compressor. Once
    installed, these launchers and receivers can usually remain in place
    permanently.

Surveys conducted by our industry about five years ago suggested that
almost one-third of transmission pipeline mileage could immediately
accommodate smart pigs, another one-quarter could accommodate smart pigs
with the addition of permanent or temporary launching and receiving
facilities, and the remainder, about 40-45 percent, would either require
extensive modifications or never be able to accommodate smart pigs due
to the physical or operational characteristics of the pipeline.
Scheduling these extensive modifications to minimize consumer delivery
impacts has been one of the most challenging aspects of the Integrity
Management Program.

The natural gas pipeline industry will use hydrostatic pressure testing
and direct assessment for segments of transmission pipeline that cannot
be modified to accommodate smart pigs, or in other special
circumstances. There are issues worth noting with both hydrostatic
testing and direct assessment. In the case of hydrostatic testing, an
entire section of pipeline must be taken out of service for an extended
period of time, limiting the ability to deliver gas to downstream
customers and potentially causing market disruptions as a result. In
addition, hydrostatic testing -- filling a pipeline up with water at
great pressure to see if the pipe fails -- is a destructive or "go -- no
go" testing method that must take into account pipeline characteristics
so that it does not exacerbate some conditions while resolving others.
Also, because of this "go -- no go" nature, testing must go on
continuously until the segment successfully completes the test,
generally eight hours at pressure, with no leaks or failures.

Direct assessment is generally defined as an inspection method whereby
statistically chosen sections of pipe are excavated and visually
inspected at certain distance intervals along the pipeline right-of-way
based on sophisticated above ground electrical survey measurements that
predict problem areas. The amount of excavation and subsequent
disturbance of landowner's property involved with this technology is
significant and does not decrease with future reassessments. Disturbing
other infrastructure, including roads and other utilities, also creates
a risk and an inconvenience for the public.

Finally, while the pipeline modifications and inspection activity
generally can follow a pre-arranged schedule, repair work is an
unpredictable factor. A pipeline operator does not know ahead of time
how many anomalies an inspection will find, how severe such anomalies
will be, and how quickly they must be repaired. Only the completed
inspection data can provide such information. Repair work often requires
systems to be shut down even if the original inspection work did not
effect system operations. The unpredictable nature of repair work must
be kept in mind, especially during the baseline inspection period, when
it can be expected the number of required repairs to be the greatest.

**INTEGRITY MANAGEMENT PROGRESS TO DATE**

The integrity management program mandated by the PSIA is performing very
well. The program is doing what Congress intended; that is, verifying
the safety of gas transmission pipelines located in populated areas and
identifying and removing potential problems before they occur. Based on
two years of data, the trend is that natural gas transmission pipelines
are safe and becoming safer.

PHMSA immediately initiated a rulemaking to implement the gas integrity
requirements upon enactment of PSIA in December of 2002. The
Administration successfully met the one-year deadline set by the law for
issuing a final IMP rule. Therefore, 2004 was the first full year of
what will end up being a nine-year baseline testing period (the statute
mandates that baseline tests on all pipeline segments in high
consequence areas must be completed by December of 2012). PHMSA's final
rule credits pipeline companies for some integrity assessments completed
before the rule took effect, thereby mitigating the effects of the
shorter baseline period.

PHMSA has summarized the progress achieved through 2005 as follows:

1.  Total Gas Transmission Mileage in the United States -- There are
    295,665 miles of gas transmission pipeline in the U.S. (INGAA's
    members own approximately 200,000 miles of this total, with the
    remainder being owned by *intra*state transmission systems or local
    distribution companies.)

2.  Total High Consequence Area (HCA) Mileage -- There are 20,191 miles
    of pipeline in HCAs (i.e., mileage subject to gas integrity rule).
    This represents about 7 percent of total mileage.

3.  HCA Pipeline Miles Inspected through 2005 --

    -   2004 -- 3,979 miles (incorporated some prior inspections before
        rule took effect).

    -   2005 -- 2,744 miles

    -   Therefore, 6,723 miles of HCA pipeline inspected to date, or 33
        percent of total.

4.  Total Pipeline Miles Inspected (including non-HCA pipeline) --

    -   2004 -- 30,452 miles (7.65 to 1 over-test ratio)

    -   2005 -- 19,884 miles (7.24 to 1 over-test ratio)

    -   Therefore, 50,366 total miles, or approximately 17 percent of
        total transmission pipeline mileage.

The total HCA pipeline mileage inspected to date suggests that the
industry is generally on track to meet the 10-year baseline requirement.
With three years of the baseline period completed at the end of 2005,
about 30 percent of the HCA mileage had been inspected. This translates
into 10 percent being completed annually -- exactly the volume of work
needed in order to meet the baseline requirement.

The 2002 law also required a risk-based prioritization of these HCA
assessments so that higher-ranking HCA pipeline segments would be
scheduled for assessment within five years of enactment. This means that
by December of 2007, the industry must complete at least half of the
total HCA assessments, by mileage; and that work contains the segments
with the highest probability of failure. Again, we appear to be on track
for meeting this requirement.

The mileage counted as being assessed in 2004 is higher than what we
anticipate will be the average annual mileage going forward because the
industry was able to include some HCA segments that had been inspected
in the few years immediately prior to the rule taking effect. As
mentioned, this jump-started the program and compensated some for the
fact that the final IMP rule did not take effect until December of 2003,
thus reducing the *de facto* baseline period to nine years.

The vast majority of the assessments to date have been completed using
smart pig devices. As discussed, these devices can only operate across
large segments of pipeline -- typically between two compressor stations.
A 100-mile segment of pipeline may, for example, only contain 5 miles of
HCA, but in order to assess that 5 miles of HCA, the entire 100-mile
segment between compressor stations must be assessed. This dynamic is
resulting in a large amount of "over-testing" on gas transmission
systems. While it has completed assessments on 6,723 miles of HCA pipe
thus far, the industry actually has inspected over 50,000 miles of pipe
up through 2005 in order to capture the HCA segments. Any problems
identified as a result of inspections, whether in an HCA or not, are
repaired.

In summary, while only about seven percent of total gas transmission
pipeline mileage is located in HCAs, it is anticipated that, due to
over-testing situations, about 55 to 60 percent of total transmission
mileage actually will be inspected during the baseline period.

In addition, PHMSA has made the data available for the first half of the
2006. This shows that an additional 1885 miles of natural gas
transmission line in HCAs were inspected during this period, keeping the
program on track to meet its target.

Now let us look at what the integrity inspections have found through
2005. This data focuses on information from HCA segments since these
segments are the only ones specifically covered under the integrity
management program.

1.  Reportable Incidents in HCAs (in 20,191 miles)

    -   2004 -- 9 (2 time-dependent)

    -   2005 -- 10 (0 time-dependent)

2.  Leaks (too small to be classified as a reportable incident) in HCAs
    (in 20,191 miles)

    -   2004 -- 117 (29 time-dependent)

    -   2005 -- 104 (20 time-dependent)

3.  Immediate Repairs in HCAs Found by Inspections (repair within 5
    days)

    -   2004 -- 101 (3,979 miles inspected)

    -   2005 -- 237 (2,744 miles inspected)

4.  Scheduled Repairs in HCAs Found by Inspections (repair generally
    within 1 year)

    -   2004 -- 595 (3,979 miles inspected)

    -   2005 -- 403 (2,744 miles inspected)

Time-dependent defects are separated out in the data for incidents and
leaks because these types of defects are the prime target of
reassessment under the integrity management program. By time-dependent,
we mean problems with the pipeline that develop and grow over time and,
therefore, can be managed by reinspecting on a periodic basis. The most
prevalent time-dependent defect is corrosion; therefore, the IMP effort
focuses most intently on corrosion identification and mitigation. These
same assessments might also be able to identify other pipeline defects
such as original construction defects or excavation damage. Original
construction defects (stable defects) are usually found and addressed
during post-construction inspections; any construction defects found
with this new, more sensitive inspection technology would be fixed "for
good" so that future assessments looking for these types of anomalies
will be unnecessary. Most reportable incidents caused by excavation
damage (more than 85 percent of the incidents in these HCA areas during
this time period) result in an immediate pipeline failure, so periodic
assessments are unlikely to reduce the number of these types of
time-independent incidents in any significant way. Periodic assessments
on a reasonable schedule are, therefore, most effective for
time-dependent defects.

The number of incidents associated with time-dependent defects in HCA
areas is fairly low, and these reportable incidents (e.g., one
reportable incident per year average) have occurred in HCA areas not yet
assessed under this program. As critical time-dependent defects are
found and repaired, these incident and leak numbers should approach zero
since the gestation period for these defects is significantly longer
than the re-assessment interval.

As for repairs, we have identified the number of "immediate" and
"scheduled" repairs that have been generated by the IMP inspections
through 2005. These are anomalies in pipelines that have not resulted in
a reportable incident or leak but are repaired as a precautionary
measure. "Immediate repairs" and "scheduled repairs" are defined terms
under both PHMSA regulations and engineering standards. As the name
suggests, immediate repairs require immediate action by the operator due
to the higher probability of a reportable incident or leak in the
future. Scheduled repair situations are those that require repair within
a longer time period because of their lower probability of failure.

Even though it is early in the baseline assessment period, the data
suggest a very positive conclusion regarding present state of the gas
transmission pipeline system and the effectiveness of the integrity
management programs. "Immediate repairs" in HCAs removed 50 anomalies
for every 1000 pipeline miles inspected. "Scheduled repairs" removed an
additional 140 anomalies per 1000 miles inspected. By completing these
immediate and scheduled repairs in a timely fashion, the pipeline
industry is reducing the possibility of future reportable incidents or
leaks. Also, data from operators who have completed more than one such
periodic assessment over a number of years strongly suggests there will
be a dramatic decrease in time-dependent defects requiring repairs the
second time around.

For the inspections that have occurred during the first half of 2006,
the trend is continuing with removing 38 "immediate" anomalies and 50
"scheduled" anomalies for every 1000 miles inspected.

Many of the gas pipelines being inspected under this program are 50 to
60 years old. While is it often hard for non-engineers to accept,
well-maintained pipelines can operate safely for many decades.
Policymakers often compare pipelines to vehicles and ask questions such
as: Would you fly in a 50-year-old airplane? From an engineering
standpoint, the comparison to aircraft or automobiles is unsound one.
Natural gas pipelines are built to be robust and are not subject to the
same operational stresses as vehicles. Much of the above inspection data
comes from pipelines that were built in the 1940s and 1950s. And yet,
the number of anomalies found on a per-mile basis is low. Once these
anomalies are repaired, the "clock can be reset" and these pipelines can
operate safely and reliably for many additional decades. One important
benefit of the integrity management program is the verification and
re-establishment of the known safety factors on these older pipeline
systems.

**ISSUES FOR THE 2006 REAUTHORIZATION**

The PSIA authorized the federal pipeline safety program at the
Department of Transportation through fiscal year 2006, and it has,
therefore, expired. INGAA would like the Subcommittee to consider
amendments addressing three issues in the pipeline safety law. Each of
these would achieve an evolutionary change in the current pipeline
safety program: (1) re-consideration of the seven-year reassessment
interval, to one based instead upon a more reasoned, data-driven and
scientific approach; (2) improvements in state excavation damage
prevention programs; and (3) change in the jurisdictional status for
direct sales lateral lines.

**Seven-Year Reassessment Interval**

Under the PSIA, gas transmission pipeline operators have 10 years in
which to conduct baseline integrity assessments on all pipeline segments
located in HCAs. Operators are also required by law to begin reassessing
previously-inspected pipe seven years after the initial baseline and
every seven years thereafter. PHMSA has interpreted these two
requirements to mean that, for those segments baseline-inspected in 2003
through 2005 (including those for which a prior assessment is relied
upon), reassessments must be done in years 2010 through 2012 -- *even
though baseline inspections are still being conducted*.

In 2001 INGAA provided Congress with a proposed industry consensus
standard on reassessment intervals that had been developed by the
American Society of Mechanical Engineers (ASME). The ASME standard used
several criteria to determine a reassessment interval for a particular
segment of pipe, such as the operating pressure of a pipe relative to
its strength and the type of inspection technique used. This standard
relied upon authoritative technical analyses and a "decision matrix"
based on more than 50 years of operational and performance data for gas
pipelines.

For most natural gas transmission pipelines (operating at high
pressures), the ASME standard proposed a conservative 10-year
reassessment interval. The standard suggested longer inspection
intervals for lower pressure lines (a small number of pipelines that are
lower in risk due to their lower operating pressures). The standard also
suggested [shorter]{.underline} intervals for pipeline segments
operating in higher-risk environments, including those where unusually
aggressive corrosion would be more likely to occur. Recent and past
pipeline inspection data confirms that the ASME criteria are
conservative.

There are several reasons for being concerned about whether the
seven-year reassessment interval is appropriate. First, there is the
"overlap" in years 2010 through 2012. The ability to meet the required
volume of inspections is daunting given the limited number of inspection
contractors and equipment available. In addition, this stepped up level
of inspection activity would be difficult to accommodate without
effecting gas system deliverability. This last point is critical. Some
assume that we are focusing on the re-assessment interval only because
of the costs to industry. In fact, our costs will be modest compared to
the potential costs to consumers in the form of higher natural gas
commodity prices if pipeline capacity becomes too constrained. Some
regions of the country can handle more frequent reductions in pipeline
deliverability due to the volume of pipeline capacity serving those
regions. The Chicago region and the Gulf Coast, for example, are better
equipped to handle frequent pipeline capacity interruptions due to the
abundance of pipeline capacity in those regions. Other regions, such as
the Northeast and Southern California, face greater risk that gas
commodity prices will spike if pipeline capacity is reduced too often.
These downstream market effects should be carefully considered,
especially during the baseline inspection period when pipeline
modifications (to accommodate inspection equipment), inspections, and
repair work will all be at peak levels.

Some also suggest that if the pipeline industry is technically capable
of inspecting its lines for corrosion more frequently than engineering
standards suggest, it should do so and not worry about the costs or the
logistics. It is certainly true that large interstate pipelines could,
in fact, be inspected more frequently than every seven years, especially
once systems have been modified to accommodate smart pig devices. But
just because pipelines can be inspected more often does not mean it is
rational to require a one-size-fits-all inspection policy. Most
automobile manufacturers recommend vehicle oil changes every 3000 miles.
Congress could instead mandate that all vehicles have oil changes every
1000 miles, but, of course, there would be little, if any, additional
benefit to the more frequent oil changes, and the costs associated with
the more frequent oil changes would take money away from other, more
beneficial maintenance activities.

The Integrity Management Program requires that the industry identify and
mitigate risks to the public associated with operating our pipelines.
Inspections are but one tool to achieve that end and they do not
accomplish all of the required goals of the program. The inspections
carried out pursuant to the Integrity Management Program focus primarily
on one cause of pipeline accidents -- corrosion. Corrosion causes about
25 percent of the failures on gas transmission lines. What about the
other 75 percent of accidents? What can be done to mitigate the risks of
those? A credible and effective integrity management program prioritizes
risks and develops strategies for addressing all risks. A program that
mandates system-wide inspections too frequently can seriously affect an
operator's ability to perform even more frequent inspections at the very
few locations that may warrant shorter timeframes and may detract from
other important integrity activities such as damage prevention. Focusing
attention and resources on unnecessarily frequent inspections may also
lead to a false sense of security that such inspections are addressing
all significant threats to pipeline safety.

We recognize that some lawmakers may be hesitant to change to the
seven-year reassessment interval given the debate on this issue in 2002.
The authors of the PSIA realized this discussion would be ongoing and
requested that the Government Accountability Office (GAO) review this
issue. GAO has completed its report (Report 06-945) and has concluded
that the fixed re-inspection interval (i.e., seven years) is too
conservative for the majority of the natural gas transmission pipelines
and, therefore, has recommended intervals be based on risk and
engineering analysis. INGAA concurs with the GAO recommendation. The
baseline assessments already underway are yielding valuable information
from which to make reasoned decisions about re-assessment intervals
going forward. INGAA therefore urges the Congress to address the
reassessment issue in [this]{.underline} reauthorization bill. As the
GAO stated in its report, there is no compelling reason to wait and
address this issue at a later time -- the facts already support a
risk-based program of re-assessments.

**Damage Prevention**

In 1998, the Transportation Equity Act for the 21^st^ Century ("TEA21")
highway legislation included a relatively modest program called the
"One-Call Notification Act." The goal of this legislation was to improve
the quality and effectiveness of state one-call (or
"call-before-you-dig") damage prevention programs. By developing federal
minimum standards and then giving grants to those states that adopted
the minimum standards, this law contributed to improving damage
prevention efforts all across the nation. And it did so without
mandating that states adopt the federal minimum standards.

Over the last eight years, there has been a great deal of improvement in
damage prevention. INGAA believes that the time has come to take these
efforts to the next level. Excavation damage prevention has been, and
should remain, a major focus for pipeline safety. On gas transmission
pipelines, accidental damage from excavation equipment is the leading
cause of fatalities and injuries. The majority of incidents that have
raised public and Congressional concern have been due to excavation
damage. These accidents are the most preventable of all, and better
communication between pipeline companies, excavators and the public is
the key to such accident prevention. Despite all the progress that has
been made since 1998, some excavators still do not call before they dig.

Unfortunately, there was a fatal accident involving excavation damage to
one of our member company pipelines just last week in Wyoming. While the
investigation is still in progress, it is not unreasonable to assume
that there was at least some level of misunderstanding between the
excavator and the pipeline operator. With the right level of
communication and understanding, however, these accidents are avoidable.

One state, in particular, has developed an outstanding damage prevention
program based on improved communication, information management, and
performance monitoring and enforcement. That state is Virginia. Not only
does Virginia require broad participation by all utilities and
excavators, but also it has effective public education programs and
effective enforcement of its rules. INGAA believes that effective
enforcement is the most important element to improving state programs
beyond the progress already made, and we believe Virginia offers a model
for other states to adopt. Statistics demonstrate the success of the
Virginia program -- the state has experienced a 50 percent decrease in
the excavation damage since implementing its program.

For 2006, INGAA asks the Congress to emphasize once again the importance
of excavation damage prevention by including a new program of incentives
for state action. A modest amount of focused grant funds could go a long
way to encourage states to improve the content and enforcement of their
damage prevention programs.

**Safety Regulation of Direct Sales Laterals**

One of the goals of the original Pipeline Safety Act enacted in 1968 was
to establish a clear line of demarcation between federal and state
authority to enforce pipeline safety regulations. Prior to 1968, many
states had established their own safety requirements for interstate
natural gas pipelines, and there was no particular consistency in such
regulations across the states. This created compliance problems for
interstate pipeline operators whose facilities crossed multiple states.
The Pipeline Safety Act resolved this conflict by investing the U.S.
Department of Transportation with exclusive jurisdiction over interstate
pipeline safety while delegating to the states authority to regulate
intrastate pipeline systems (generally, pipelines whose facilities are
wholly within a single state).

The statutory definition of an "interstate gas pipeline facility"
subject to federal regulation was clarified further when the Congress
reauthorized the Pipeline Safety Act in 1976 (P.L. 94-477). As part of
this clarification, the Congress stated that "direct sales" lateral
pipelines were not subject to federal jurisdiction. Direct sales
laterals are typically smaller-diameter pipelines that connect a
large-diameter interstate transmission pipeline to a single, large
end-use customer, such as a power plant or a factory. Such direct sales
laterals often are owned and maintained by the interstate transmission
pipeline operator to which they are connected.

This clarification was made necessary by a 1972 U.S. Supreme Court
decision (*Federal Power Commission v. Louisiana Power and Light, 406
U.S. 621*) in which the Court ruled that for purposes of economic
regulation (*i.e.*, rate regulation), direct sales laterals were subject
to preemptive federal jurisdiction. This ruling created uncertainty
regarding the authority to regulate the safety of direct sales laterals
because when the Pipeline Safety Act was enacted in 1968, it was assumed
by the Congress that such pipelines would be subject to both economic
and safety regulation at the state level.

While this exemption from federal jurisdiction may have made sense 30
years ago, it now is an anachronism. As mentioned, many of these direct
sales laterals are owned and operated by interstate pipelines. The
natural gas transported in such lines travels in interstate commerce,
and the lateral lines are extensions of the interstate pipelines to
which they are interconnected.

Additionally, interstate natural gas pipelines are now subject to the
PHMSA's Gas Integrity Management Program and are required to undergo a
specific regimen of Congressionally mandated inspections and safety
verification. State-regulated pipelines are not covered under the
federal program. Instead, states are allowed to create their own safety
programs, which may have different processes/procedures covered than the
federal integrity management program. Given the comprehensive federal
program, there is no particular reason for small segments of the
interstate pipeline system to be subject to differing and potentially
inconsistent regulation at the state level. The inefficiency of this
approach is further compounded by the fact that an interstate pipeline
operator with direct sales laterals in multiple states likely will be
subject to inconsistent regulation across the states. It is therefore
understandable that interstate pipelines wish to have their direct sales
laterals subject to the same federal integrity management requirements
as mainline facilities. This would ensure a consistent and rational
approach to integrity management system-wide, in contrast to being
compelled to exclude parts of the pipeline network on the basis of an
outdated set of definitions.

INGAA supports amending the definitions of "interstate gas pipeline
facilities" and "intrastate gas pipeline facilities" in the Pipeline
Safety Act to eliminate the jurisdictional distinction between direct
sales laterals and other segments of an operator's interstate natural
gas pipeline system. This would make such segments of pipeline subject
to federal safety regulation consistent with the approach taken for the
economic regulation of such pipeline facilities.

Direct sales laterals that are not owned by an interstate pipeline would
still be regulated by states. This amendment also would have the benefit
of permitting the states to concentrate their resources on developing
and enforcing integrity management programs for their natural gas
distribution lines.

**CONCLUSION**

Mr. Chairman, thank you once again for inviting INGAA to participate in
today's hearing. I would like to provide some written comments on S.
3961 for the record. INGAA has made the reauthorization of the Pipeline
Safety Act a top legislative priority, and we want to work with you and
the Committee to move a bill forward as soon as possible. Please let us
know if you have any additional questions, or need additional
information.