- ENSURING THE SAFETY OF OUR NATION'S PIPELINES

[Senate Hearing 111-1014]
[From the U.S. Government Publishing Office]

S. Hrg. 111-1014

ENSURING THE SAFETY
OF OUR NATION'S PIPELINES

=======================================================================

HEARING

before the

SUBCOMMITTEE ON SURFACE TRANSPORTATION
AND MERCHANT MARINE INFRASTRUCTURE,
SAFETY, AND SECURITY

of the

COMMITTEE ON COMMERCE,
SCIENCE, AND TRANSPORTATION
UNITED STATES SENATE

ONE HUNDRED ELEVENTH CONGRESS

SECOND SESSION

__________

JUNE 24, 2010

__________

Printed for the use of the Committee on Commerce, Science, and
Transportation

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0SENATE COMMITTEE ON COMMERCE, SCIENCE, AND TRANSPORTATION

ONE HUNDRED ELEVENTH CONGRESS

SECOND SESSION

JOHN D. ROCKEFELLER IV, West Virginia, Chairman
DANIEL K. INOUYE, Hawaii KAY BAILEY HUTCHISON, Texas,
JOHN F. KERRY, Massachusetts Ranking
BYRON L. DORGAN, North Dakota OLYMPIA J. SNOWE, Maine
BARBARA BOXER, California JOHN ENSIGN, Nevada
BILL NELSON, Florida JIM DeMINT, South Carolina
MARIA CANTWELL, Washington JOHN THUNE, South Dakota
FRANK R. LAUTENBERG, New Jersey ROGER F. WICKER, Mississippi
MARK PRYOR, Arkansas GEORGE S. LeMIEUX, Florida
CLAIRE McCASKILL, Missouri JOHNNY ISAKSON, Georgia
AMY KLOBUCHAR, Minnesota DAVID VITTER, Louisiana
TOM UDALL, New Mexico SAM BROWNBACK, Kansas
MARK WARNER, Virginia MIKE JOHANNS, Nebraska
MARK BEGICH, Alaska
Ellen L. Doneski, Staff Director
James Reid, Deputy Staff Director
Bruce H. Andrews, General Counsel
Ann Begeman, Republican Staff Director
Brian M. Hendricks, Republican General Counsel
Nick Rossi, Republican Chief Counsel
------

SUBCOMMITTEE ON SURFACE TRANSPORTATION AND MERCHANT MARINE
INFRASTRUCTURE, SAFETY, AND SECURITY

FRANK R. LAUTENBERG, New Jersey, JOHN THUNE, South Dakota, Ranking
Chairman Member
DANIEL K. INOUYE, Hawaii OLYMPIA J. SNOWE, Maine
JOHN F. KERRY, Massachusetts JOHN ENSIGN, Nevada
BYRON L. DORGAN, North Dakota JIM DeMINT, South Carolina
BARBARA BOXER, California ROGER F. WICKER, Mississippi
MARIA CANTWELL, Washington JOHNNY ISAKSON, Georgia
MARK PRYOR, Arkansas DAVID VITTER, Louisiana
TOM UDALL, New Mexico SAM BROWNBACK, Kansas
MARK WARNER, Virginia MIKE JOHANNS, Nebraska
MARK BEGICH, Alaska

C O N T E N T S

----------
Page
Hearing held on June 24, 2010.................................... 1
Statement of Senator Lautenberg.................................. 1
Statement of Senator Johanns..................................... 2
Statement of Senator Thune....................................... 20
Statement of Senator Hutchison................................... 21
Prepared statement........................................... 22
Statement of Senator Udall....................................... 76
Prepared statement........................................... 77
Statement of Senator Begich...................................... 78
Statement of Senator Pryor....................................... 81
Statement of Senator Vitter...................................... 82

Witnesses

Hon. Cynthia L. Quarterman, Administrator, Pipeline and Hazardous
Materials Safety Administration, U.S. Department of
Transportation................................................. 3
Prepared statement........................................... 4
Hon. Deborah A.P. Hersman, Chairman, National Transportation
Safety Board................................................... 12
Prepared statement........................................... 13
Rocco D'Alessandro, Executive Vice President of Operations, Nicor
Gas on Behalf of the American Gas Association.................. 34
Prepared statement........................................... 36
Timothy C. Felt, President and CEO, Colonial Pipeline Company on
Behalf of the Association of Oil Pipe Lines (AOPL) and the
American Petroleum Institute (API)............................. 41
Prepared statement........................................... 42
Gary L. Sypolt, CEO, Dominion Energy on Behalf of the Interstate
Natural Gas Association of America............................. 49
Prepared statement........................................... 51
Carl Weimer, Executive Director, Pipeline Safety Trust........... 58
Prepared statement........................................... 60

Appendix

Response to written questions submitted to Hon. Cynthia L.
Quarterman by:
Hon. John D. Rockefeller IV.................................. 87
Hon. Frank R. Lautenberg..................................... 89
Hon. Mark Pryor.............................................. 90
Hon. Mark Begich............................................. 92
Hon. Kay Bailey Hutchison.................................... 93
Hon. John Thune.............................................. 94
Hon. Mike Johanns............................................ 97
Response to written questions submitted to Hon. Deborah A.P.
Hersman by:
Hon. Mark Pryor.............................................. 97
Hon. Kay Bailey Hutchison.................................... 104
Hon. John Thune.............................................. 105
Response to written questions submitted by Hon. Mark Pryor to:
Rocco D'Alessandro........................................... 106
Timothy C. Felt.............................................. 108
Gary L. Sypolt............................................... 109
Response to written questions submitted to Carl Weimer by:
Hon. Mark Pryor.............................................. 110
Hon. John Thune.............................................. 111
Hon. Johanns................................................. 112
Michael Thompson, Chief, Pipeline Safety, Oregon Public Utility
Commission and Chairman, National Association of Pipeline
Safety Representatives (NAPSR), prepared statement............. 113
American Public Gas Association, prepared statement.............. 117

ENSURING THE SAFETY
OF OUR NATION'S PIPELINES

----------

THURSDAY, JUNE 24, 2010

U.S. Senate,
Subcommittee on Surface Transportation and
Merchant Marine Infrastructure Safety, and Security,
Committee on Commerce, Science, and Transportation,
Washington, DC.
The Subcommittee met, pursuant to notice, at 2:31 p.m. in
room SR-253, Russell Senate Office Building, Hon. Frank R.
Lautenberg, Chairman of the Subcommittee, presiding.

OPENING STATEMENT OF HON. FRANK R. LAUTENBERG,
U.S. SENATOR FROM NEW JERSEY

Senator Lautenberg. Good afternoon, everyone. I want to
welcome you, those who are here, to this hearing on pipeline
safety.
Two weeks ago, workers in Weston, Texas, were digging up
clay for a dirt contracting company and a tragedy occurred. The
bulldozer inadvertently ruptured a natural gas pipeline,
causing a fatal blast that left two persons dead and three
others injured. Unfortunately, this was not an isolated
incident. Just 1 day earlier, another worker in Texas was
killed after a construction crew that was digging a hole for a
utility pole accidentally struck a natural gas line.
The fact is that while pipelines are by and large a safe
form of transportation, when there is an accident the
consequences can be deadly. There are nearly 2.5 million miles
of pipelines today moving oil and gas within states and across
the country. We've got to do all that we can to keep these
pipelines safe and to reduce the frequency of accidents.
In 2006, we made significant progress in pipeline safety
when we passed the Pipeline Inspection, Protection,
Enforcement, and Safety Act of 2006, also known as the PIPES
Act. There is no doubt that the PIPES Act has improved pipeline
safety. As we look to reauthorize the law this year, we want to
hear from people who know, our witnesses, how the PIPES Act has
worked and what we can do to improve it.
For instance, a provision that I authored in that law
requires that service lines to single-family homes be fitted
with excess flow valves which can automatically shut off a
pipeline if a sudden change in pressure is detected. I'm
interested in hearing from our witnesses whether or not this
requirement should be expanded to other types of buildings.
The law also addresses the difficult problem of digging and
excavation. Nearly 35 percent of all serious pipeline incidents
during the last 10 years were caused by excavation damage, the
single most common cause of these accidents.
The PIPES Act improved excavation safety by strengthening
the One-Call system, which makes it easier for construction
crews to notify utility companies about digging projects and
therefore dramatically reducing pipeline accidents. Under that
system, construction crews must call one phone number before
digging, giving utility companies time to identify and mark
hidden pipes if they haven't already done so. This system is
now working better because of the PIPES Act, although we've
still got to work to improve and increase awareness of the
program. That's why I authored a resolution, passed by the
Senate, to make April Call Before You Dig Month, to promote
safe digging practices, including 811, the national Call Before
You Dig Number.
So I look forward to hearing from today's witnesses about
their views on the safety of our Nation's pipelines and the
reauthorization of the PIPES Act. I also look forward to
hearing from Administrator Quarterman about what she's doing to
make sure that the Office of Pipeline Safety is vigilant in its
oversight responsibilities.
Before we hear from our panels, I would call on Senator
Johanns.

STATEMENT OF HON. MIKE JOHANNS,
U.S. SENATOR FROM NEBRASKA

Senator Johanns. Thank you very much. I won't give a long
opening statement, but I do want to offer a thought or two just
to maybe kind of queue up in your minds some of my interest in
this hearing today. Somebody laid in front of me these pictures
of damage that obviously occurred at some event, and I look at
them and I wonder to myself not only the impact on human life,
but the impact on the environment. That's especially true these
days as we look to the Gulf and the issues that are out there.
I raise that because today I want to get a better
understanding relative to a project that is going on in
Nebraska, the Keystone pipeline project. All of a sudden my
office is starting to get calls from concerned people. Here's
what's driving that. Our greatest natural resource in our
state, some would argue, is the Ogallala Aquifer. It is
literally an underground lake that stretches for miles and
miles and miles and miles. It's not just in Nebraska; it's in
other states also.
The concern is that this pipeline is going to traverse
that, and so now citizens are worried about safety. So I'm
going to want to know who's responsible, what's the ins and
outs of that, who do we call that can help us address these
concerns, and what the relationship between the various Federal
agencies would be.
This project is even more complicated because it originates
in Canada and it therefore crosses the Canadian border. I
appreciate that there's an international element to what's
going on here, too.
So I didn't want to catch anybody by surprise. I thank the
chairman for giving me an opportunity to raise that in my
opening statement. With that, thank you.
Senator Lautenberg. Thanks very much.
Now I welcome our first panel of witnesses: Ms. Cynthia
Quarterman, Administrator, Pipeline and Hazardous Materials
Safety Administration. Ms. Quarterman, this is your first time
before this subcommittee since your confirmation and we welcome
you and look forward to hearing your testimony. Just to show
that I'm impartial, all statements will be limited to 5
minutes. Thank you.
Please, Ms. Quarterman.

STATEMENT OF HON. CYNTHIA L. QUARTERMAN,

ADMINISTRATOR, PIPELINE AND HAZARDOUS

MATERIALS SAFETY ADMINISTRATION,

U.S. DEPARTMENT OF TRANSPORTATION

Ms. Quarterman. Thank you. Chairman Lautenberg, members of
the Committee: Thank you for the opportunity to appear today.
Your interest in pipeline safety is very much appreciated.
Like Secretary LaHood, safety is my top priority for PHMSA.
The lessons learned from current and past tragedies have
significantly influenced the safety policies underlying the
laws and regulations related to pipeline safety. Thanks to the
Congress and especially to this subcommittee the Department has
made tremendous strides in improving the pipeline safety
program.
I'm pleased to update you on PHMSA's progress in ensuring
the safety of our Nation's pipeline transportation system
through implementing the mandates of the PIPES Act of 2006. The
Act has played a major role in maintaining a safe and reliable
pipeline network. Thanks to your help, PHMSA has developed a
forward-leaning pipeline safety program. A reauthorized program
promises to build on that progress.
PHMSA has worked aggressively to respond to Congressional
interest and implement the PIPES Act. It has made significant
progress in implementing its statutory requirements to build
safer communities. PHMSA has been working with many
governmental partners to promote safety, such as the National
Transportation Safety Board, the Department's Office of
Inspector General, and the Government Accountability Office,
implementing strategic approaches to address their safety
recommendations.
Since its last reauthorization, PHMSA has gone from a high
of 16 open NTSB pipeline recommendations to today's low of 9
open recommendations. Of the remaining nine, none of the
recommendations are classified as unacceptable and several
should close before the year's end. There are no outstanding IG
recommendations for the pipeline program and the two
outstanding GAO recommendations should be closed by year's end
as well.
PHMSA has made great progress in strengthening its industry
oversight program. The PIPES Act reauthorized PHMSA to increase
its inspection and enforcement staffing from 94 in Fiscal Year
2007 to 135 in Fiscal Year 2010. PHMSA has instituted a new,
more aggressive recruiting strategy to promptly fill vacant
inspection and enforcement positions. PHMSA has taken advantage
of higher penalty authority by imposing and collecting larger
penalties where appropriate. PHMSA has set records in its
enforcement processes, proposing $19 million in administrative
civil penalties since 2006, or an average $183,000 per proposed
penalty.
PHMSA has added integrity management requirements to
natural gas distribution networks to address pipelines, where
safety risks have the most impact on citizens. PHMSA has also
worked to improve the internal operations of pipeline
companies' control rooms. This action removes the pipeline
program's control room standards from the NTSB top ten list and
replaces it with NTSB praise.
PHMSA has established valuable state partnerships on
oversight, emergency response, and damage prevention. Funding
to state pipeline safety programs has increased. In 2010 PHMSA
will cover 54 percent of the pipeline safety program costs for
states, compared with 45 percent in 2006.
PHMSA has also maintained strong relationships with
Federal, state, local, and other emergency response agencies to
effectively respond to pipeline incidents and emergencies.
Following incidents, PHMSA staff remain in constant contact
with investigatory and additional oversight agencies to not
only ensure public safety and operator compliance, but to share
information and participate in remediation activities.
PHMSA and its partners have done a good job helping reduce
the number of pipeline incidents related to excavation damage
over the past few years. Since 2006, excavation damage has gone
from 37.5 percent as the cause of serious incidents to 12.7
percent today.
All of us at PHMSA are proud of the accomplishments to date
in implementing the PIPES Act, although we acknowledge there is
still more work to be done. As the Administrator of this
agency, I assure you that all of my staff and all of our
stakeholders know that safety is PHMSA's top priority.
We look forward to working with Congress to reauthorize the
Pipeline Safety Act and I welcome any questions you might have.
[The prepared statement of Ms. Quarterman follows:]

Prepared Statement of Hon. Cynthia L. Quarterman, Administrator,
Pipeline and Hazardous Materials Safety Administration, U.S. Department
of Transportation

Chairman Rockefeller, Ranking Member Hutchison, members of the
Committee, thank you for the opportunity to appear today. Safety is
Secretary LaHood's top priority and it is PHMSA's top priority as well.
PHMSA is also committed to reducing risks in pipeline transportation.
PHMSA employees are encouraged to bring up new and creative ideas and
to challenge each other and their supervisors so that the best safety
solutions are put forward. As our Nation's reliance on the safe and
environmentally sound transportation of hazardous materials is
increasing, the Pipeline and Hazardous Materials Safety
Administration's (PHMSA) safety oversight of the Nation's pipelines
provides critical protection for the American people and our
environment.
PHMSA works with many governmental partners to promote safety. The
National Transportation Safety Board (NTSB), the Department's Office of
Inspector General (OIG), the Government Accountability Office (GAO),
and, of course, the U.S. Congress and the states all have a vested
interest in the safe and reliable operation of the Nation's pipeline
infrastructure. PHMSA is working aggressively to be responsive to all
of these organizations and their recommendations. Since 2006, PHMSA's
accomplishments include: closing the three open OIG recommendations;
making significant progress on the GAO's recommendations on incident
reporting with the last action due out this summer; and making
substantial progress on all of the NTSB recommendations. When the
Pipeline Inspection Protection Enforcement and Safety (PIPES) Act of
2006 passed, NTSB had thirteen open recommendations to PHMSA. Over the
last several years, NTSB has closed nine of those recommendations and
it is currently working to address the remaining four recommendations
as well as a few new recommendations. PHMSA does not currently have any
open unacceptable recommendations.
I am pleased to brief you on the significant progress PHMSA's
Pipeline Safety Program has made since the passage of the PIPES Act in
December, 2006. PHMSA looks forward to working with you to build on
this solid foundation.

I. Implementation of the PIPES Act
PHMSA has made significant progress in fulfilling the statutory
requirements of the PIPES Act, which has resulted in safer communities
today. The number of serious pipeline incidents--those involving death
or injury--has declined by 50 percent over the last twenty years. Yet
over the same period, all the traditional measures of risk exposure
have risen--population, energy consumption, pipeline ton-miles. We aim
to continue the downward long-term trend in pipeline incidents.

A brief description of PHMSA's successful use of the tools provided
by Congress in the PIPES Act to improve the safety record of the Nation
follows.

A. PHMSA Has Increased the Strength of Integrity Management Programs
and
Enforcement Activities
The PIPES Act broadened the scope of the systems-based approach to
assessing and managing safety related risks. The additional initiatives
included: (1) increasing enforcement activity, transparency, and data
quality; (2) implementing an integrity management program for
distribution pipelines, and; (3) requiring a management plan to reduce
risks associated with human factors, including operator fatigue in
pipeline control centers, and implementing NTSB recommendations on the
Supervisory Control and Data Acquisitions (SCADA) systems in pipelines.
We are pleased with the positive results from increasing the systems
risk management approach, which this Committee helped devise.

1. PHMSA Has Increased Enforcement and Improved Transparency and Data
Quality
PHMSA has used its full enforcement authority to give teeth to its
systems-based approach to risk management and increase pipeline company
management accountability for safety. The PIPES Act, and the
appropriations that followed, authorized PHMSA to increase its
inspection and enforcement staffing to 135 in FY 2010 from 94
inspection and enforcement staff in FY 2007. PHMSA is in the process of
an aggressive recruitment effort to fill these positions as soon as
possible.
Also, PHMSA has embraced enforcement transparency by leveraging its
website and data bases to provide on-the-spot information to
stakeholders. Within months after the 2006 PIPES Act was signed into
law, we launched an enforcement transparency website. The website
provides public access to a variety of reports and enforcement program
information that goes beyond what is required by the PIPES Act. This
site provides year-by-year reports on cases initiated and closed, the
status of different types of enforcement cases, and reports on civil
penalty cases showing the amounts proposed, assessed, and collected.
Information and documents on individual cases are also provided. These
documents include the initial notices that allege operator violations
or inadequacies; operator responses to these allegations; and the
orders documenting PHMSA's final determinations. In addition, PHMSA
provides monthly updated enforcement summaries to the public. Use of
the enforcement transparency website has climbed steadily since its
inception in May 2007 and averaged more than 1,500 hits per day in
2009. In 2010, we expanded and improved the information on civil
penalty cases and began displaying enforcement data from state pipeline
safety agencies.
In addition to increased staffing and online function, the PIPES
Act also gave PHMSA a much needed enforcement tool--the Safety Order.
In January 2009, PHMSA published a final rule establishing the process
by which PHMSA conducts Safety Order proceedings to address pipeline
integrity risks to public safety, property, or the environment.
Finally, the PIPES Act now requires that senior executive officers
of pipeline companies certify their pipeline integrity management
program performance on an annual and semi-annual basis. As predicted,
the certification requirement has increased management's accountability
and the accuracy in performance reporting.
PHMSA also undertook a significant effort to improve data
consistency and quality culminating in a new generation of data
reporting that will begin this summer. First, PHMSA published a final
rule in August 2009 to align cause categories across natural gas
transmission and distribution incident reports. Second, PHMSA sought
and received Office of Management and Budget approval for new forms and
additional data collections. Third, PHMSA updated its guidance and
forms regarding incident reporting. Fourth, PHMSA proposed revisions to
the reporting requirements in Part 191 and expects to issue a final
rule. While all seemingly small changes, the process allowed for
coordination and input from state pipeline safety agencies and other
Federal agencies ultimately resulting in raising industry awareness.
This effort specifically addressed Congress' mandates to modify
reporting requirements to ensure that incident data accurately reflects
incident trends over time and collects data on controller fatigue.

2. PHMSA Has Established a Gas Distribution Integrity Management
Program (DIMP)
Pursuant to the authority granted in the 2006 PIPES Act, PHMSA
issued a final rule in December 2009 requiring operators of gas
distribution pipelines to develop and implement integrity management
programs to manage and reduce risks in gas distribution pipeline
systems. These programs are intended to enhance safety by identifying
and reducing pipeline integrity risks. The requirements for the
integrity management programs are similar to those required for gas
transmission pipelines, but tailored to reflect the differences in and
among distribution pipelines. The regulation requires operators to
develop and implement plans for monitoring and improving the condition
of their systems, in addition to complying with current code
requirements. The rule also requires distribution operators to install
excess flow valves in new and replaced service lines for single family
residences where conditions are suitable for their use. The rule
applies to the entire network of distribution pipelines and the
thousands of small and large companies that deliver natural gas over
the 2 million miles of pipelines serving American communities, not just
high consequence areas.
PHMSA made tremendous efforts getting ready for the implementation
of DIMP. We developed consensus standards, guidance, training, IT
systems, and data to increase understanding of the new regulations. We
are especially mindful of the increased oversight requirements
associated with the program. Getting 50 states to implement a
performance standard takes a lot more preparation than preparing a
single Federal entity. Accordingly, we have worked with our state
partners to prepare them by assuring thorough training, education, and
effective enforcement compliance.

3. PHMSA Has Established Control Room Management Requirements
Pursuant to the authority granted in the PIPES Act, PHMSA issued a
final rule on December 4, 2009, to address human factors and other
aspects of control room management for pipelines remotely operated and
controlled by personnel using SCADA systems. Operators must define the
roles and responsibilities of controllers and provide controllers with
the necessary information, training, and processes to fulfill these
responsibilities. Controllers must manage SCADA alarms; assure control
room considerations are taken into account when changing pipeline
equipment or configurations, and review reportable incidents or
accidents to determine whether control room actions contributed to the
event. Operators must also implement methods to prevent controller
fatigue. These regulations will enhance pipeline safety by coupling
strengthened control room management with improved controller training
and fatigue prevention measures.
The regulations apply to all hazardous liquid pipelines, and gas
transmission and distribution pipelines that meet certain risk
criteria. This rule not only responds to the PIPES Act mandate but also
addresses a NTSB safety recommendation regarding controller fatigue
that was on the NTSB's Most Wanted list. A public workshop is planned
for November 2010 to present preliminary guidance materials.
Programmatic inspections will be conducted between September 2011 and
February 2013.

B. PHMSA is Enhancing Pipeline Safety with Increased Assistance to
States,
Damage Prevention Education, Technical Assistance Grants, and
Public Access to Information

1. PHMSA Has Strengthened Its Assistance to States
State pipeline safety agencies oversee the bulk of the 2.5 million
miles of pipeline infrastructure. Specifically, states are responsible
for oversight of virtually all gas distribution pipelines, gas
gathering pipelines and intrastate gas transmission, as well as 88
percent of intrastate hazardous materials liquid pipelines and 20
percent of the interstate gas pipelines. PHMSA maintains primary
responsibility for the remaining pipelines, including all interstate
hazardous liquid pipelines and 80 percent of the interstate gas
pipelines. States employ approximately 63 percent of the inspector
workforce. The expansion of the Federal pipeline safety initiatives,
such as DIMP and integrity management, has increased the resource
demands on both Federal and state pipeline safety agencies.
In recognition, Congress increased PHMSA's ability to provide
grants to state pipeline safety agencies to offset the costs associated
with the statutory requirements for their inspection and enforcement
programs. In addition, Congress gave PHMSA considerable resources to
expand its relationship with state pipeline safety agencies, enabling
increased policy collaboration, training, information sharing, and data
quality and collection. In FY 2010, PHMSA's $40.5 million appropriation
to support state programs will fund 54 percent of state pipeline safety
programs. Additionally, the President's FY 2011 request includes an
increase in funds to support state programs totaling approximately
$44.5 million, which would reflect a 65 percent funding of the state
pipeline safety programs. These States are PHMSA's strongest asset in
assuring the safety of pipelines in American communities.

2. PHMSA Has Strengthened Damage Prevention Efforts
The vast majority of America's pipeline network is underground
making pipelines vulnerable to ``dig-ins'' by third-party excavators.
While excavation damage is 100 percent preventable, it remains a
leading cause of pipeline incidents involving fatalities and injuries.
Three-quarters of all serious consequences from pipeline failures
relate to distribution systems and more than one-third of these
failures are caused by excavation damage. PHMSA's goal is to
significantly reduce excavation damage with strong outreach and public
awareness programs. As evident in the chart below, PHMSA is making
progress.

The PIPES Act authorizes PHMSA to award State Damage Prevention
(SDP) grants to fund improvements in damage prevention programs. Each
state has established laws, regulations, and procedures shaping its
state damage prevention program. Since 2008, PHMSA provided over $4
million in SDP grants to 30 distinct state organizations. Eligible
grantees include: state one-call centers, state pipeline safety
agencies, or any organization created by state law and designated by
the Governor as the authorized recipient of the funding.
SDP grants reinforce nine specific elements that make up the
components of an effective damage prevention program, under the PIPES
Act:

1. Enhances communications between operators and excavators;

2. Fosters support and partnership of all stakeholders;

3. Encourages operator's use of performance measures for
locators;

4. Encourages partnership in employee training;

5. Encourages partnership in public education;

6. Defines roles of enforcement agencies in resolving issues;

7. Encourages fair and consistent enforcement of the law;

8. Encourages use of technology to improve the locating
process; and

9. Encourages use of data analysis to continually improve
program effectiveness.

PHMSA's Technological Development Grants program makes grants to an
organization or entity (not including for-profit entities) to develop
technologies that will facilitate the prevention of pipeline damage
caused by demolition, excavation, tunneling, or construction
activities. A total of $500,000 was appropriated for the program in
2009. Two awards have been made to date.
PHMSA also uses the authority in the PIPES Act to promote public
education awareness with national programs such as, ``811--Call Before
You Dig Program'' through the Common Ground Alliance (CGA). PHMSA
provided over $2.2 million in funding assistance for CGA's 811
advertising campaign since 2002.
PHMSA is proud of its continued and steady leadership in supporting
national and state damage prevention programs. In March 2010, we
participated in the CGA's annual meeting highlighting the importance of
the National ``811--Call Before You Dig Program.'' In April 2010,
Transportation Secretary LaHood acknowledged the importance of calling
before you dig by establishing April as ``National Safe Digging
Month.'' The U.S. Senate and the House of Representatives both
introduced resolutions designating April 2010 as ``National Safe
Digging Month.'' At our urging, forty states, including those
represented by the members of this committee, also followed suit. The
efforts driven and supported by PHMSA, involved the CGA, many states,
and damage prevention stakeholders from around the country, who are
advocates for safe excavation practices.

3. PHMSA Has Launched the Technical Assistance Grant Program
The PIPES Act empowers PHMSA to encourage communities to take part
in efforts to develop technical solutions for environmental and
emergency planning, zoning, and land use management near pipelines, and
to prevent damage to pipelines. Under this authorization, PHMSA created
the Technical Assistance Grant (TAG) program to provide grants to local
communities and organizations for technical assistance related to
pipeline safety issues. Technical assistance is defined as engineering
or other scientific analysis of pipeline safety issues. The funding can
also be used to help promote public participation in official
proceedings.
In 2009, PHMSA selected 21 communities and organizations to receive
funding through the agency's TAG program. Grants, totaling $1 million,
were used to foster open communication between the public and pipeline
operators on pipeline safety and environmental issues, and perform
other important tasks. Examples of such projects include the use of
geographic information systems for enhanced pipeline monitoring and
public awareness campaigns to promote the sharing of information
between pipeline operators and landowners.
Each technical assistance grant recipient must provide a report to
PHMSA within one year of its award demonstrating completion of the work
as outlined in its grant agreement. PHMSA is thoroughly overseeing this
process and will evaluate the expected outcomes of each grant
recipient. PHMSA's Community Assistance and Technical Services Managers
will offer their technical support to communities and organizations as
well to address pipeline safety questions that may arise during the
course of the grant agreement period.

4. PHMSA's Pipelines and Informed Planning Alliance Advances Smart
Growth along Pipelines in Our Communities
In addition to the grants, PHMSA has conducted other activities to
inform the public and engage public interest and participation in all
of its initiatives. We funded publicly accessible, Internet broadcast
viewing of two pipeline events sponsored by the Pipeline Safety Trust,
including a focus on safer land use planning. We have made one grant
and may make others to professional associations of county and city
government officials to represent the public in the Pipelines and
Informed Planning Alliance (PIPA). PIPA is an initiative organized by
PHMSA to encourage the development and use of risk-informed land use
guidelines to protect pipelines and communities.
A companion effort is helping communities understand where
pipelines are located, who owns and operates them, and what other
information is available for community planning. Following the passage
of the PIPES Act, PHMSA worked with the Department of Homeland Security
(DHS)/Transportation Security Administration (TSA) to resolve concerns
about sensitive security sensitive information. Vital information that
communities need for land use, environmental, and emergency planning
around pipelines is now publicly available through PHMSA's National
Pipeline Mapping System (NPMS). We continue to work with states,
industry, and other stakeholders to make the NPMS information more
accurate and useful.

C. PHMSA Has Adopted Additional Regulatory Enhancements and has
Sponsored Congressional Required Studies
In addition to the programmatic authorizations already discussed,
Congress provided PHMSA with the authority to address narrow, but
significant, gaps in its safety regulations. The gaps related to
regulating low stress pipelines, effective response to emergency
disruption of pipeline operations, regulation of direct sale natural
gas pipelines, and the coordination of pipeline security
responsibility. PHMSA has addressed all of these additional regulatory
initiatives in the PIPES Act.
Low Stress Pipelines. Under the direction of the PIPES Act, PHMSA
regulates rural low-stress hazardous liquid pipelines to the same
standards as other hazardous liquid pipelines. Low stress pipelines
operate at or below 20 percent specified minimum yield strength. PHMSA
had already regulated low stress hazardous liquid pipelines that were
in populated areas or that crossed commercially navigable waterways.
The PIPES Act directed PHMSA to regulate all low stress line including
those rural low stress lines that could pose a threat to unusually
sensitive environmental areas. On June 3, 2008, we published a Final
Rule, Low Stress I, as phase one of a two phase process to complete the
regulatory mandate in the PIPES Act. Low Stress I brought under safety
regulation those rural low-stress pipelines that pose the greatest risk
to environmentally sensitive areas, particularly low stress lines that
are 8\5/8\ inches or greater in diameter and located in or within a \1/
2\-mile of an unusually sensitive area. PHMSA issued a notice of
proposed rulemaking for Low Stress II which was published in the
Federal Register on June 22, 2010, to bring the remainder of the
unregulated low stress pipelines under our safety regulation.
Emergency Waiver of Pipeline Safety Requirements. The PIPES Act
authorized PHMSA to waive compliance with certain Federal pipeline
safety requirements without notice and opportunity for a hearing if
needed to address an emergency involving pipeline transportation. In
the wake of Hurricane Katrina, Congress recognized that in an
emergency, it would not be feasible to provide for notice and
opportunity for a hearing, as required for other waivers. PHMSA issued
a final rule on January 16, 2009, to process emergency special permits
when necessary to address an actual or impending emergency caused by a
natural or manmade disaster.
Clarify Regulation of Direct Sale Natural Gas Pipelines. PHMSA
issued an advisory bulletin on May 13, 2008, advising operators that
the PIPES Act eliminated the exception of direct sale natural gas
pipelines from the definition of an interstate gas pipeline facility.
PHMSA is now responsible for regulatory oversight and enforcement of
these lines.
OIG Recommendations Regarding Pipeline Security Annex. PHMSA has
addressed all three recommendations in the OIG report to Congress on
DOT actions to implement the pipeline security annex between DOT and
the DHS. We finalized the action plan for implementing the annex. We
formalized each agency's security roles and responsibilities and helped
develop a Pipeline Security Incident Response Protocols plan for
responding to potential terrorist actions. We coordinate efforts to
minimize duplicative security inspections and we have almost daily
communication with DHS concerning pipeline safety events and security
incidents.
In the PIPES Act, Congress also requested that PHMSA undertake
certain studies to attend to specific concerns brought to light by
certain natural disasters and the aging infrastructure of the pipeline
system. We appreciate the opportunity to show Congress that we are
working diligently with our stakeholders and other governmental
departments to address petroleum capacity, leak detection, and internal
corrosion concerns, as well as to determine appropriate risk assessment
intervals. PHMSA has conducted and reported to Congress on all the
required studies.
Petroleum Capacity Market Study. On June 1, 2008, PHMSA submitted
to Congress a final report on the domestic transport capacity of
petroleum products by pipeline and to reduce the likelihood of
shortages of petroleum products or price disruptions due to shortages
of pipeline capacity.
Leak Detection Systems Study. On June 23, 2009, PHMSA submitted to
Congress a final report describing the capabilities and limitations of
leak detection systems used by hazardous liquid pipeline operators. The
report also discusses ongoing investment by PHMSA and research to
improve the sensitivity of leak detection technology, particularly for
hazardous liquid operators. As we stated in the report, PHMSA has
adequate oversight to evaluate the leak detection capability of
individual operators and has exercised authority as needed to compel
systems upgrades where warranted.
Internal Corrosion Control Regulations Study. In June 2009, PHMSA
submitted to Congress a final report of its thorough review of the
Federal pipeline safety internal corrosion control regulations,
accident history, research findings, and consensus standards to
determine if such regulations are adequate. Although we found that
existing regulations are generally sufficient to achieve safety and
environmental protection goals, we were also considering other near-
and long-term actions to further reduce the risk of internal corrosion.
Seven-Year Risk Assessment Study. In November 2007, PHMSA reported
to Congress on its review of the GAO report on the seven-year
assessment interval.

II. Building on a Solid Foundation
PHMSA is building a solid foundation to advance pipeline safety.
That said, we are committed to completing the two remaining initiatives
authorized by PIPES Act--completing the notice of proposed rulemaking
to regulate low stress pipelines this year, and taking the next step to
implement Federal enforcement of third party excavation damage to
pipelines.
PHMSA has accomplished many goals with its state partners; at the
same time however, it is important that states continue to receive the
resources they need to implement not only damage prevention initiatives
but the distribution integrity management program.
PHMSA also plans to update its enforcement strategy and penalties
to deter future noncompliance and incentivize better performance. We
continue to make full use of the increased administrative civil penalty
authority granted in the Pipeline Safety Improvement Act of 2002. It is
evident from the comparable periods before and after the PIPES Act,
PHMSA has doubled the proposed pipeline safety administrative civil
penalties it issued to operators, and the average per case has more
than tripled. Specifically, between 2004 and 2006, PHMSA proposed $10
million in administrative civil penalties, with an average proposed
civil penalty of $57,000; and, between 2007 and 2009, PHMSA proposed
$19 million in administrative civil penalties and an average proposed
civil penalty of $183,000. Furthermore, the average administrative
civil penalty proposed per individual violation \1\ has increased from
approximately $16,000 in 2002 to an average of approximately $100,000
today. PHMSA issues operators proposed administrative civil penalties
for probable violations identified during inspections or
investigations. Proposed penalties are communicated to operators in
Notices of Probable Violation and operators have the right to respond
to these allegations before a penalty is assessed in a Final Order.
Penalties are an effective tool to ensure operator accountability, but
the current cap on PHMSA's administrative civil penalties of up to
$100,000 per violation, per day and up to $1 million for a related
series of violations may limit PHMSA's enforcement efforts.
---------------------------------------------------------------------------
\1\ Each Notice of Probable Violation case usually contains
multiple individual violations.
---------------------------------------------------------------------------
We look forward to seeing our integrity management programs
continue to mature and yield results. With this in mind we will
continue to look at performance measures and ways we can improve the
data that we collect. Having better data will enable us to make risk
based informed regulatory decisions.
With the anticipated increase in transportation of new products
like ethanol, hydrogen, carbon dioxide, and potentially other bio-
fuels, we are working to ensure a solid regulatory framework to prevent
accidents and ensure safety. We currently regulate pipelines
transporting ethanol blends and to the extent new biofuels are
developed in the future that involve pipeline transportation, PHMSA is
committed to taking whatever steps are necessary to ensure that such
transportation will be conducted safely. We coordinate with other
Federal agencies to forecast the transportation implications from the
inception of marketing new fuels, as part of a systemic oversight
process. We coordinate with other countries to benefit from their
experience. We continue to work with individual operators, identifying
safety concerns that must be satisfied, both with the infrastructure
and with the surrounding community. For example, ethanol poses very
unique emergency response challenges, and PHMSA is responsible for
helping communities prepare. We have also been a part of the
interagency Carbon Capture and Sequestration Task Force in which issues
related to carbon dioxide pipeline transportation are being addressed.
We collaborate with the pipeline industry, the renewable fuels
organizations, and others like emergency responder organizations and
the National Commission on Energy Policy, to investigate and solve
technical challenges.

III. Responding to Current Challenges
While PHMSA is gearing up to deal with the new challenges we expect
to see through an increased use of pipelines to transport renewable
fuels, we are continuing to exert vigilant and visionary leadership to
remain steps ahead of the pipeline safety issues we're faced with
today.

A. PHMSA Coordinates With Federal, State, Local and Private Parties to
Respond to and Investigate Pipeline Accidents and Incidents
PHMSA has established strong relationships with other organizations
involved in responding to pipeline incidents and emergencies. When we
respond to an incident, our primary concern is the public's safety and
to determine an operator's compliance with PHMSA regulations. We are
often times requested to share information and support the
investigations of other agencies, including the National Transportation
Safety Board, the U.S. Chemical Safety and Hazard Investigation Board,
the Occupational Safety and Health Administration and other Federal,
State, and local response agencies. PHMSA staff remains in constant
contact with the Transportation Security Administration to share
information related to pipeline and other transportation failures to
identify each agency's jurisdictional authority, roles, and
responsibilities. In addition, PHMSA has a long history of working
closely with local emergency officials in response to pipeline
emergencies and our staff effectively participates in incidents where
there is an Integrated Command System.

B. PHMSA Provides Routine Training to Staff on Ethics
PHMSA employees must understand that clear lines exist between
being a regulator and the regulated. We want to ensure our employees
are clear on what current Federal policies exist on accepting gifts,
dealing with prohibited sources, responding to bribes, and other ethics
related issues. Employees are trained on Federal ethics guidelines when
initially becoming a new PHMSA employee. PHMSA inspectors and other
staff are also provided annual refresher training on ethics standards,
and on a periodic basis on relevant ethics topics.

C. PHMSA is Reminding Operators of Their Obligations to Have an
Effective Oil Spill Response Plan
The events in the Gulf are a clear reminder of the devastating
impact a serious oil spill can have on the environment and human
activities. PHMSA recently issued an advisory bulletin to operators of
onshore oil pipelines and facilities to remind them of their
responsibilities under the Federal Water Pollution Control Act. In the
advisory, owners and operators of oil transport systems are advised of
their responsibility to have and to periodically review and update
their facility oil spill response plan to reduce the environmental
impact of oil discharges. PHMSA regulations require onshore oil
pipeline operators to prepare, review, and update oil spill response
plans for their facilities periodically, and whenever significant
changes may occur. The advisory requires operators to review their
facility response plans in view of the Gulf incident to ensure they
comply with all applicable requirements. Once an operator reviews its
plan and indicates changes are necessary, they must update and submit
those plans to PHMSA. If no changes are necessary, operators must
notify us that the review has occurred.

D. PHMSA is Preparing an Offshore Pipeline Action Plan
PHMSA is in the process of reviewing its current policies and
procedures related to all offshore pipelines to determine what actions
should be taken to improve its oversight of those pipelines. In
addition, PHMSA is currently in stage one of a three stage process to
conduct an integrated inspection of BP Pipeline North America's U.S.
assets, including the company's 6,800-mile pipeline system. Stage one
of the BP integrated inspection involves assembling and analyzing a
considerable amount of data covering BP's system to understand recent
inspection history, safety performance, and processes and procedures.
After the pre-inspection phase is complete, PHMSA's integrated
inspection team will be better equipped to develop an inspection plan
that is focused on BP's higher risks areas to assure compliance and
improve performance.
In closing, we look forward to working with Congress to address
these issues and to reauthorize the pipeline safety program. PHMSA very
much appreciates the opportunity to report on the status of our
progress with PIPES Act implementation and I am committed to full
compliance. Thank you. I would be pleased to answer any questions you
may have.

Senator Lautenberg. Thank you very much.
Ms. Hersman, we're pleased to hear from you, the Chairman
of the National Transportation Safety Board, and we welcome you
back to the Subcommittee. We look forward to hearing from you.

STATEMENT OF HON. DEBORAH A.P. HERSMAN, CHAIRMAN, NATIONAL
TRANSPORTATION SAFETY BOARD

Ms. Hersman. Thank you, Chairman Lautenberg, Ranking Member
Thune, and Senator Johanns. Thank you for the opportunity to
address the Committee on the important issue of pipeline
safety.
The NTSB is responsible for determining the probable cause
of accidents and issuing recommendations to prevent them from
happening again. Our responsibilities also include evaluating
the effectiveness of safety programs of other agencies,
including PHMSA. PHMSA has made significant improvements in the
last 5 years, in large part because of statutory mandates in
the Pipeline Safety Improvement Act of 2002, as well as the
PIPES Act of 2006. In general, PHMSA has been responsive to
NTSB's pipeline safety recommendations. Between January 1,
2002, and January 1, 2010, the NTSB issued 24 recommendations
to PHMSA. As of today, only eight of those recommendations
remain open and only one issued prior to 2002 remains open.
PHMSA's more notable accomplishments include regulations
addressing integrity management programs for gas transmission,
hazardous liquid, and natural gas distribution lines,
regulations for improved education among emergency response
agencies and the public, and the implementation of the 811 One-
Call system.
Yet, there are some areas of concern that remain. One of
these concerns gained much attention following corrosion
failures on a BP Exploration low-stress pipeline serving the
Trans-Alaska Pipeline in 2006. The leak along this low-stress
pipeline resulted in more stringent PHMSA regulations, but
these regulations overlook most low-stress and on-and offshore
gathering pipelines, leaving thousands of miles of pipelines
unregulated.
However, just this past week, PHMSA outlined safety
requirements for all rural low-stress pipelines not already
covered. The NTSB applauds these efforts, and we look forward
to evaluating their proposal in greater detail.
Another area of concern is risk-based pipeline safety
programs, which provide operators with the responsibility to
develop, implement, and evaluate individual programs and plans.
PHMSA has the responsibility to review these plans for
regulatory compliance and to conduct audits to evaluate their
effectiveness. However, in recent pipeline investigations, the
NTSB has seen indications that PHMSA and operator oversight
have not been adequate.
This photo is from a November 1, 2007, rupture of a propane
pipeline in Carmichael, Mississippi, which resulted in two
fatalities and seven injuries and property damage exceeding $3
million. It is the responsibility of the pipeline operator to
raise public awareness about the pipeline. The operator in this
case hired two contractors to administer its program, but the
mailing list did not include all of the residential addresses
within the mailing area. The mistake was not caught until after
the accident. The NTSB recommended that PHMSA initiate a review
of all public education programs.
Likewise, consideration of pipeline leak history is an
important factor in an operator's integrity management plan.
But in a 2004 Kingman, Kansas, pipeline rupture, we discovered
that the operator left out the leak history. PHMSA did not
identify that history in their oversight, resulting in a
deferred inspection. The pipeline ruptured 2 years before it
was scheduled for an inspection.
In 2009, in Palm City, Florida, an 18-inch diameter gas
transmission pipeline ruptured in the busy Florida Turnpike
right of way. Luckily, there were no fatalities. But, as you
can see from this photograph, the explosion created a crater
over 110 feet long and 17 feet wide. The pipeline operator had
not properly identified this location, and it was not covered
in their integrity management plan. We're still investigating
this accident to determine the cause of this oversight.
As a result of these accidents and other investigations,
the NTSB believes that PHMSA must establish a more aggressive
oversight framework so that risk-based integrity management
programs are not only effectively designed, but effectively
executed as well.
We have a strong working relationship with PHMSA, and we
find PHMSA in most cases to be a responsive partner in
protecting the public wellbeing. However, as I stated today,
there are a few issues that remain of concern to the NTSB,
which we hope to see PHMSA address in the near future.
Thank you, and I look forward to answering your questions.
[The prepared statement of Ms. Hersman follows:]

Prepared Statement of Hon. Deborah A.P. Hersman, Chairman,
National Transportation Safety Board

Introduction/Overview
Chairman Lautenberg, Ranking Member Thune, members of the
Subcommittee, thank you for the opportunity to address you today on the
reauthorization of the U.S. Department of Transportation's (DOT)
Pipeline and Hazardous Materials Safety Administration (PHMSA). PHMSA
has made significant progress over the past 5 years. Much of the credit
for this success is due to the implementation of statutory mandates
included in the Pipeline Safety Improvement Act of 2002, as well as the
Pipeline, Inspection, Protection, Enforcement and Safety (PIPES) Act of
2006.
PHMSA has been responsive to the National Transportation Safety
Board's (NTSB) pipeline safety recommendations. Between January 1,
2002, and June 1, 2010, the NTSB issued twenty-four pipeline
recommendations to PHMSA. As of this date, nine remain open and fifteen
have been closed following a NTSB assessment that PHMSA had taken an
``acceptable action'' or ``acceptable alternate action'' in response to
the recommendation. None were closed with the categorization of
``unacceptable action.'' Additionally, only one recommendation issued
prior to 2002 remains open.
Noteworthy accomplishments by PHMSA include implementing
regulations addressing integrity management programs for gas
transmission pipelines, hazardous liquid pipelines, and natural gas
distribution pipeline systems. Regulations and improved industry
practices also are in place for expanded public awareness and education
programs meant to heighten the awareness of the American public and
regional emergency response agencies. The implementation of the 811
one-call system requires the identification and marking of buried
pipelines before excavation work occurs.
Additionally, partnerships between the industry and PHMSA have led
to a number of joint initiatives, such as development of training
programs for public and municipal officials, enhanced collection and
analysis of accident data, and greater coordination with state agencies
that have been delegated enforcement authority by PHMSA for Federal
pipeline safety standards.
As a result of the NTSB's 2005 Safety Study, Supervisory Control
and Data Acquisition (SCADA)in Liquid Pipelines, the Board issued
Safety Recommendations P-05-1 through -3 which called on PHMSA to: (1)
require hazardous liquid pipeline operators to follow the American
Petroleum Institute's recommended practice for the use of graphics on
SCADA computer screens, (2) require pipeline companies to have a policy
for the review and audit of SCADA alarms, and (3) require training for
pipeline controllers to include simulator or noncomputerized
simulations for controller recognition of abnormal operating
conditions, particularly leak events. These three recommendations were
also incorporated directly into the PIPES Act. PHMSA published a final
rule on December 4, 2009, that included the recommended requirements
and applied them to all pipeline systems.
Despite these notable and varied accomplishments, NTSB has concerns
about certain other aspects of PHMSA's pipeline safety program. Two
such areas specifically addressed in the PIPES Act are the regulation
of low-stress pipeline systems and requirements for the use of excess
flow valves.

Regulation of Low-Stress Pipeline Systems
Corrosion failures on the BP Exploration, Inc.'s, low-stress oil
transit lines from the Prudhoe Bay oil fields to the Trans Alaska
pipeline in 2006 raised concerns among Members of Congress about the
potential pollution of environmentally sensitive areas. As a result,
Congress included provisions in the PIPES Act mandating that PHMSA
issue regulations subjecting low-stress hazardous liquid pipelines near
unusually sensitive environmental areas to the same standards and
regulations as other hazardous liquid pipelines. Low-stress pipelines
are those that are operated at a stress level of 20 percent or less of
their strength ratings.
At the time the PIPES Act was enacted, Federal pipeline safety
regulations only applied to low-stress pipelines that were located in
populated areas, crossed navigable waterways, or carried highly
volatile liquids, such as compressed liquefied propane. In a Notice of
Proposed Rulemaking (NPRM), ``Pipeline Safety: Protecting Unusually
Sensitive Areas from Rural Onshore Hazardous Liquid Gathering Lines and
Low-Stress Lines'', published on September 6, 2006, PHMSA proposed
regulations for rural low-stress pipelines that have a diameter of at
least 8\5/8\ inches and that are within \1/4\ mile of an area defined
as unusually sensitive. (The distance in the final rule is \1/2\ mile.)
The NPRM also proposed regulations for rural gathering lines that
operate at a stress level greater than 20 percent, have a diameter
between 6\5/8\ and 8\5/8\ inches and are within \1/4\ mile of an area
defined as unusually sensitive. A ``gathering line'' is a pipeline with
a diameter of 8\5/8\ inches or less that transports petroleum from a
production facility. Again, at the time the PIPES Act was enacted, only
gathering lines in populated areas were subject to Federal pipeline
regulations.
Exempted from the proposed requirements in the NPRM were gathering
lines in the inlets of the Gulf of Mexico. Certain gathering lines in
inlets of the Gulf of Mexico are subject to burial requirements to
ensure that the lines are not exposed and do not pose a hazard to
navigation. Otherwise, they are not regulated.
In comments submitted by the NTSB on November 21, 2006, we note
that most low-stress pipelines and on- and off-shore gathering
pipelines would remain essentially unregulated. The NTSB also notes
that the NPRM would apply a less stringent patchwork of requirements to
address corrosion and excavation damages to those low-stress pipelines
and gathering pipelines covered by the proposed standards. The NTSB
states its belief that the standards codified in Title 49 Code of
Federal Regulations, Part 195 for hazardous liquid pipelines should
also apply in its entirety to the low-stress pipelines and gathering
lines. PHMSA published the final rule on June 3, 2008, without
significant change to the NPRM. Publication of this final rule
concluded phase one of PHMSA's two phase plan to implement its PIPES
mandate to regulate low-stress pipelines.
On June 22, 2010, PHMSA published a second NPRM regarding the
regulation of all rural onshore hazardous liquid low-stress pipelines.
This second NPRM represents phase two of PHMSA's implementation of its
mandate in the PIPES Act. In this NPRM, PHMSA proposes safety
requirements for all rural low-stress pipelines not included under the
phase one final rule. Specifically, the low-stress pipelines captured
under the new NPRM include: (1) rural low-stress pipelines of a
diameter less than 8\5/8\ inches located in or within one-half mile of
an unusually sensitive area and (2) all other rural low-stress
pipelines that were not included under phase one. PHMSA estimates that
the NPRM will apply to 1,384 miles of low-stress pipelines not covered
by the previous rule. It appears this latest NPRM will apply to onshore
gathering lines that are also low-stress pipelines. However, the NPRM
does not address gathering lines in the inlets of the Gulf of Mexico or
offshore gathering lines. The NTSB has not had the opportunity to
evaluate fully the specific requirements proposed in the NPRM; however,
we will submit comments to PHMSA.
The tragedy in the Gulf of Mexico involving the Deepwater Horizon
drilling platform is a grim reminder of the damage that a major oil
spill can cause. While the magnitude of the Deepwater Horizon spill is
far greater than any known pipeline failure, the events in the Gulf
should remind those involved in the pipeline industry that all
pipelines must be sufficiently safeguarded and regulated in order to
protect the public and the environment.

Integrity Management Programs for Distribution Systems and the Use of
Excess Flow Valves
The PIPES Act also mandates that DOT prescribe minimum standards
for integrity management programs for distribution pipeline systems. On
June 25, 2008, PHMSA published a NPRM, ``Integrity Management Program
for Gas Distribution Pipelines,'' with proposed regulations that would
require operators of gas distribution pipelines to develop and
implement integrity management programs with the same objectives as the
existing integrity management programs for hazardous liquid and gas
transmission pipelines.
Integrity management programs for hazardous liquid and gas
transmission pipelines typically require operators to assess the
condition of their pipelines by using ``in-line'' inspection tools that
travel through the pipeline to determine the nature and extent of any
defects or pressure testing that yields information about the integrity
of the pipeline. Such techniques are not feasible for typical
distribution pipeline systems because of the differences in the design
and operating parameters between distribution pipeline systems and
hazardous liquid and gas transmission pipelines.
Further, the failure of a distribution pipeline is often initially
detected from reports of a gas leak rather than a catastrophic rupture.
As result, development and implementation of an effective leak
management program is an important element of an integrity management
program for a distribution pipeline.
PHMSA acknowledged these differences in the NPRM and properly
emphasized the importance of various leak detection methods as
essential elements of an integrity management program for distribution
pipeline systems.
In its comments on the NPRM, the NTSB emphasized that while an
effective leak detection program is a crucial element of the overall
leak management program, the use of equipment that prevents or
mitigates leaks is equally important. One such device that mitigates a
gas pipeline leak is an ``excess flow valve.'' An excess flow valve is
a device installed on the distribution line, usually serving a user
residence or facility, that detects an abnormally high flow rate, and
when an excess flow is detected, automatically closes a valve, thus
shutting off the flow of gas through the distribution line. The NPRM
did not adequately address this aspect of leak management, other than
incorporating the mandate for PHMSA to require excess flow valves on
new or replacement distribution lines serving single-family residences.
PHMSA complied with this provision of the PIPES Act on December 4,
2009, when it published the final rule on integrity management programs
for distribution pipeline systems.
The NTSB has long advocated the use of excess flow valves in gas
distribution pipeline systems as an effective means of preventing
explosions caused by natural gas leaking from distribution systems. On
July 7, 1998, a natural gas explosion and fire destroyed a newly
constructed residence in South Riding, Virginia, a suburb of
Washington. The accident caused one fatality and one serious injury.
The NTSB determined that the gas service line to the home had failed
and that an uncontrolled release of gas had accumulated in the basement
and subsequently ignited. The NTSB concluded from its investigation
that had an excess flow valve been installed in the service line, the
valve would have closed shortly after the hole in the service line
developed and the explosion likely would not have occurred. The NTSB
recommended that PHMSA require excess flow valves be installed in all
new and renewed gas service lines, regardless of a customer's
classification, when the operating conditions are compatible with
readily available valves. The NTSB believes that apartment buildings,
other multifamily dwellings, and commercial properties are susceptible
to the same risks from leaking gas lines as single-family residences,
and we believe this gap in the law and the regulations should be
eliminated.

Oversight of Integrity Management and Other Risk-Based Pipeline Safety
Programs
Over the past decade or more, PHMSA has adopted a risk-based
assessment approach for regulating the DOT pipeline safety program.
PHMSA has successfully built a partnership with various facets of the
pipeline industry to develop, implement and execute a multi-part
pipeline safety program. All stakeholders, including PHMSA, have, in
the NTSB's view, come to rely heavily upon this approach. The NTSB
believes that a risk-based approach can be an effective method to
develop and execute the pipeline safety program, and there are many
positive elements to PHMSA's approach.
The DOT pipeline safety regulations based on risk assessment
principles provide the structure, content, and scope for many aspects
of the overall pipeline safety program. Within this regulatory
framework, pipeline operators have the flexibility and responsibility
to develop their individual programs and plans, determine the specific
performance standards, implement their plans and programs, and conduct
periodic self-evaluations that best fit their particular pipeline
systems. PHMSA likewise has the responsibility to review pipeline
operators' plans and programs for regulatory compliance and
effectiveness.
The NTSB believes that with the risk-based assessment there should
be increased responsibilities on both the individual pipeline operators
and PHMSA. Operators must diligently and objectively scrutinize the
effectiveness of their programs, identify areas for improvement, and
implement corrective measures. PHMSA, as the regulator, must also do
the same in its audits of the operators' programs and in self-
assessments of its own programs. In short, both operator and regulator
need to verify whether risk-based assessments are being executed as
planned, and more importantly, whether these programs are effective.
In its recent pipeline investigations, the NTSB discovered
indications that PHMSA and operator oversight of risk-based assessment
programs, specifically integrity management programs and public
education programs, has been lacking and has failed to detect flaws and
weaknesses in such programs.
In its investigation of the October 2004, rupture of an anhydrous
ammonia pipeline near Kingman, Kansas, the NTSB identified deficiencies
in PHMSA's auditing procedures when evaluating the operator's integrity
management program. The operator did not include assessments of leak
history when calculating relative risk scores for various segments of
the pipeline. These relative risk scores were used to establish an
initial baseline assessment of the integrity of the pipeline in the
decisionmaking process for prioritizing the inspection schedule. Though
PHMSA did find omissions of other risk factors during its review of the
operator's integrity management program, PHMSA did not identify the
omission of the leak history data during its initial review or during a
subsequent review of the corrected plan. Consequently, the ruptured
pipeline segment was not scheduled for a baseline assessment until
2006, almost 2 years after the October 27, 2004, rupture. The NTSB
recommended that PHMSA require an operator to revise its pipeline risk
assessment plan whenever it has failed to consider one or more risk
factors that can affect pipeline integrity.
The November 1, 2007, rupture of a propane pipeline in Carmichael,
Mississippi, resulted in two fatalities, seven injuries, and property
damage exceeding $3 million. Before the accident, the pipeline operator
relied upon contractors to obtain accurate mailing data and ensure that
mailings to the public were completed. However, the operator did not
perform oversight to ensure that all appropriate recipients were on the
mailing lists and that the mailings met appropriate regulatory
requirements. The operator also had not taken any action to determine
whether recipients who received the mailings understood the guidance
they contained. The NTSB determined that the pipeline operator failed
to properly assess its public awareness and education program by
relying upon contractors without appropriate oversight. The NTSB
recommended that PHMSA initiate a program to evaluate pipeline
operators' public education programs, including the operators' self-
evaluations of the effectiveness of their public education programs.
On May 4, 2009, an 18-inch diameter gas transmission pipeline with
an operating pressure of 850 psi ruptured near Palm City, Florida. The
rupture was located in the Florida Turnpike right-of-way, between I-95
and the Florida Turnpike. The turnpike and interstate were closed for
approximately 3 hours due to the accident. Two gas transmission
pipelines operated by the same pipeline company were also located in
the right-of-way but were reportedly not damaged.
The force of the released gas created a crater approximately 116.5
feet long by 17 feet wide by approximately 2.8 feet deep. Roughly 104
feet of the pipe was ejected from the ruptured pipeline and landed next
to the crater. The closest edge of the crater was approximately 25 feet
from the northbound paved edge of the Florida Turnpike.
There was no ignition of the released gas, and no fatalities were
reported. However, two people were injured when their car reportedly
hit debris, ran off the road, and turned over; a Deputy Sheriff was
hospitalized after walking through a gas cloud; and the accident
resulted in the evacuation of a nearby school and residential
community.
The NTSB's ongoing investigation has determined that at the time of
the accident, the operator had not identified the ruptured segment as
located within a high consequence area, and therefore not covered by
the operator's integrity management plan. However, an independent
evaluation done by PHMSA at the NTSB's request shows the segment in
fact is in a high consequence area. The NTSB is collecting
documentation that will determine the cause of this error.
As a result of these investigations, the NTSB is concerned that the
level of self-evaluation and oversight currently being exercised is not
uniformly applied by some pipeline operators and PHMSA to ensure that
the risk-based safety programs are effective. The NTSB believes that to
ensure effective risk-based integrity management programs are employed
throughout the pipeline industry, PHMSA must establish an aggressive
oversight program that thoroughly examines each operator's
decisionmaking process for each element of its integrity management
program.

Recent Accidents in Texas
The two most recent pipeline accidents in Cleburne, Texas and
Darrouzett, Texas, involved third-party excavation damage resulting in
ruptures, fires, and explosions. Preliminary information from both
investigations indicates that prior to the start of excavation
activities, neither pipeline was marked or identified. Both
investigations will determine the reasons why and how these lapses
occurred.

Cleburne, TX Summary
On June 7, 2010, a natural gas transmission pipeline measuring 36-
inches in diameter near Cleburne, Texas was struck and ruptured by a
contractor for an electrical cooperative that was installing a pole for
a power line. One member of the contractor's crew was drilling a hole
while operating an auger affixed to a truck when the auger struck and
punctured the transmission pipeline. An ignition and explosion of the
escaping gas resulted, and the operator of the auger was killed. Six
other crewmen were hospitalized.
The accident pipeline had a nominal wall thickness of 0.5-inch. The
pipeline was operating at 950 psi at the time of the accident. The
maximum allowable operating pressure is 1,050 psi. The pipeline,
constructed in 1971, is 388 miles long, originating in Coyanosa, Texas
and terminating in Ennis, Texas.
A second pipeline operated by a different pipeline company also
traversed the accident area. Workmen in the area reported that they saw
markers for the second pipeline. A NTSB investigator and Texas Railroad
Commission personnel visiting the site also observed markers for the
second pipeline, but the ruptured pipeline was not marked.
The NTSB is currently investigating this accident with the
assistance of PHMSA and the Texas Railroad Commission (the state
regulatory agency for pipeline safety).

Darrouzett, TX Summary
(The NTSB delegated the on-scene investigation of this accident to
the Texas Railroad Commission, which is the state agency responsible
for regulation of intrastate pipelines.)
On June 8, 2010, a natural gas nonregulated gathering line
measuring 14-inches was struck by a third-party contractor near
Darrouzett, Texas. The maximum allowable operating pressure of the
gathering line was 700 psi; the line was operating at approximately 500
psi. The line begins in Follett, Texas, travels into Oklahoma,
continues west and then returns to Texas near the Hansford/Sherman
County area. The line is fed by many gathering lines in the area and
ends at the plant in Sherman, Texas.
At the time of the incident, six contractor personnel were working
in the area. Two persons were killed, one critically injured, and three
others escaped injury. A bulldozer working in a caliche pit struck the
14-inch natural gas pipeline sometime before 4 p.m. The pipeline
operator's SCADA system picked up a pressure loss and began closing
valves to isolate the ruptured section of the pipeline. The fire was
extinguished by 8 p.m.
Preliminary information from the Texas Railroad Commission
indicates that the excavator had not requested a permit to work in the
area or that there were any pipeline markers at the accident scene. The
accident gathering line is not regulated under DOT pipeline
regulations.
PHMSA accident statistics over the past decade (2000-2009),
identify corrosion as the leading cause of all reported pipeline
accidents. The second leading reported cause is damage from third-party
excavators. Despite the focus on one-call systems, marking of pipelines
prior to excavation, and other measures, the two accidents in Texas are
a reminder that excavation damage remains a serious concern.

Closing
In summary, PHMSA has made great strides in addressing a number of
matters mandated by Congress in the Pipeline Safety Improvement Act of
2002, as well as the Pipeline, Inspection, Protection, Enforcement and
Safety Act of 2006. The NTSB believes more can be done in these areas
and looks forward to a constructive dialogue with PHMSA and DOT as we
advance the interests of pipeline safety, and thus the safety of people
living and working near, and receiving service from, our Nation's
pipelines.
This concludes my testimony and I would be happy to answer any
questions you may have.

Senator Lautenberg. Thank you very much.
We are alerted to the fact that at about 3 o'clock a vote
may occur, so we'll try to stick to our time limitations here.
Ms. Quarterman, despite the moratorium on offshore
drilling, today's New York Times reports that BP is planning to
move forward with a risky drilling project off the coast of
Alaska. This is at a depth of 24,000 feet and several miles of
horizontal pipe to connect to the TransCanada Pipeline. In May
your agency warned BP that it was in probable violation of
Federal standards because of corrosion on the Endicott Pipeline
to which this new project connects.
Given BP's track record of irresponsibility and
carelessness, do you think that this project should be stopped?
Ms. Quarterman. Mr. Chairman, as you're aware, PHMSA is
responsible for pipeline safety regulations. We are not
responsible for the actual project that's at issue here in the
North Slope. I believe that is within the Department of
Interior's jurisdiction.
I can tell you that, as a result of the Deepwater Horizon
incident, we at PHMSA have taken a very strong look at BP, and
within the past couple of weeks I have spoken with, met with,
the President of BP North America Pipelines and explained to
him that we would be looking very closely at their program, we
would be doing an integrated inspection of their entire system,
and that we are going to be very focused over the next year
looking at them.
With respect to the particular pipeline at issue, I believe
that we have issued a warning letter to BP with respect to the
Endicott Pipeline on the North Slope, and they have sent in a
response. We are planning a field inspection this year to
verify whether or not that has been adequately addressed.
Senator Lautenberg. We have to be on constant alert there.
Ms. Quarterman. Absolutely.
Senator Lautenberg. Ms. Hersman, PHMSA is responsible for
overseeing pipeline construction and transportation, while the
Federal Energy Regulatory Commission is responsible for
approving the location of the pipeline. I ask you and I'll ask
Ms. Quarterman, how can communities best determine the real
impact of a proposed pipeline when two agencies with different
regulations are responsible for overseeing pipelines?
Ms. Hersman. Mr. Chairman, the Safety Board has not
investigated any accidents where the siting has been a
particular issue, but we have investigated a number of
accidents where we expressed concern about pipeline issues. A
proposed pipeline between New Jersey and Manhattan, just like
any other pipeline, deserves attention. It's going to be in a
high-consequence area. It's a very populous urban area. There
are potentially going to be three river crossings. There are
many challenges with respect to siting any pipeline in those
kinds of conditions.
We would want to make sure that they have adequate remote
control shutoff valves, that they have corrosion detection, and
that the pipeline is marked. I would defer to Administrator
Quarterman on how they would oversee that construction.
Senator Lautenberg. Yes. The question is one of approving
the location. How can we get that done when two agencies with
different regulations are responsible? Ms. Quarterman?
Ms. Quarterman. As I'm sure you're aware, the FERC is
responsible for siting of natural gas pipeline facilities and
we at PHMSA on the staff level try to work closely with them in
helping their evaluation. We do have state contacts that go out
to their hearings, their public hearings, and answer any
safety-related questions. However, not having jurisdiction over
the siting portion of that, we really cannot speak to the
siting issues. We try to coordinate with FERC as much as
possible. I'm scheduled to meet with the chairman the beginning
of next month.
Senator Lautenberg. Ms. Hersman, in quick form, the NTSB
has long recommended the installation of excess flow valves on
all new and renewed natural gas service lines. In 2006, in the
PIPES Act, I included the requirement that excess flow valves
be installed on gas lines that serve single-family homes. How
can excess flow valves be effectively installed in apartment
buildings or multiple dwellings and commercial buildings?
Ms. Hersman. Mr. Chairman, in quick order, the Safety Board
thinks that excess flow valves should be installed as widely as
possible, including multi-dwelling residences, such as
apartment buildings, and commercial and industrial facilities.
That is the only recommendation prior to 2002 that remains in
an open status to PHMSA, because, even though the PIPES Act
required single-family dwellings to be equipped, we think that
requirement doesn't go far enough and we'd like to see it
universally applied.
Senator Lautenberg. We need your help there.
Senator Johanns.
Senator Johanns. Thank you, Mr. Chairman.
The mission statement of the Office of Pipeline Safety
indicates that environmental safety is within their
jurisdiction. In fact, quoting from that mission statement, it
says: ``OPS is the primary Federal regulatory agency
responsible for ensuring the safe, reliable, and
environmentally sound operation of America's energy
pipelines.''
Mr. Weimer--and I hope I'm pronouncing that correctly--in
his testimony says that he's concerned that PHMSA is not
involved enough in the siting and environmental review process
and expresses that concern. In fact, I think he even uses the
words that it's ``disconnected.''
Now, as I said in my opening statement, there's a pipeline
project coming through Nebraska. Part of it goes over the
Ogallala Aquifer. I'm very familiar with that. I can tell you
that in some areas the water table is high enough where if you
dug a fencepost hole, if you know what I'm talking about, it
would fill with water. So you worry that that pipe literally is
transmitting oil right through the water table right over the
Ogallala Aquifer.
What assurance can you give me--and then I want to add one
other qualifier. I understand that this project involves a
Canadian company, so I think this is managed or oversight is
provided by the Department of State, further complicating
matters. Tell me how PHMSA fits into this and what kind of
oversight you would provide? Do you feel like you've been a
player in this process?
Ms. Quarterman. I believe you're referring to the
TransCanada Keystone XL Project.
Senator Johanns. Right.
Ms. Quarterman. And that is one that originates in Canada
and comes down to the United States through your state. Within
the United States, the FERC does have jurisdiction over siting
of gas pipelines. However, it does not have jurisdiction over
the siting of hazardous liquids pipelines under the Interstate
Commerce Act. So the only authority, other than the states, at
a Federal level who has any oversight into the siting of that
project would be the Department of State. Because it does cross
international lines, they have to provide a Presidential permit
to be able to cross the border, and they are doing any
environmental analysis associated with that.
Again, we would coordinate with them in terms of providing
comments, but we are not a cooperating agency with them on
their environmental impact statement. So our obligations would
be, once the Department of State has approved this Presidential
permit and the siting with the states, to ensure that the
pipeline project, once it starts going into the ground, is safe
in terms of the construction, the operation, the maintenance of
the pipeline.
Senator Johanns. I must admit--and I'm not making any
claims about this being unsafe. Maybe it's the safest pipeline
ever going to be constructed in world history. But having said
that, when I think of the State Department I think of them
doing many great things. I'm not sure environmental assessment
would have come to mind until I learned about this project. I
think you're probably agreeing with me.
How can I assure Nebraska residents that an appropriate
assessment has been done? Because I think of all of the
expertise relative to pipelines in the Federal Government, I
can't imagine it would be at the State Department.
Ms. Quarterman. Well, I think that Nebraska, as a state,
has a role to play in this process, certainly being involved in
any scoping meetings that may go and getting the Nebraska
authorities involved in siting of the project and determining
whether or not the right of way is appropriate. That would be
the only advice I could give at that level.
Senator Johanns. Are you Mr. Chairman?

STATEMENT OF HON. JOHN THUNE,
U.S. SENATOR FROM SOUTH DAKOTA

Senator Thune [presiding]. I guess so.
Senator Johanns. Gosh, that's surprising.
Senator Thune. That's quite a thought.
Senator Johanns. I have run out of time, but let me just
wrap up and say, none of this is very reassuring to me, and you
understand why. This is a big project with significant issues.
We've got a very, very important natural resource, and I just
want to make sure it's properly assessed and protected, so when
I'm asked about it I can say either you have something to worry
about or you have nothing to worry about.
Senator Thune. Senator Hutchison.

STATEMENT OF HON. KAY BAILEY HUTCHISON,
U.S. SENATOR FROM TEXAS

Senator Hutchison. Thank you, Mr. Chairman. I'm sorry I was
late because we had an Appropriations Committee hearing.
But I wanted to just say a couple of things. In the past
few weeks, Texas has had two major fatal pipeline accidents,
both of which were excavation accidents. Any excavation
accident is a preventable one. So I wanted to ask you basically
two questions. One is, do you think that we can improve on the
One-Call system? Are there a number of states that don't
participate in the One-Call system? And should we be doing
something about that, to stop having exemptions from the One-
Call system? That would be number one.
Number two, I'll submit my opening statement for the
record, but the other thing of course, representing a coastal
state, that I worry about is that the Pipeline Hazardous
Materials Safety Administration regulates offshore transmission
lines in state waters, but the Minerals Management Service has
jurisdiction for offshore pipelines in the outer continental
shelf. So I'm concerned that regulations might not be uniform,
that there might be confusion when there is an accident about
who does what. Is that a concern in your opinion, Ms.
Quarterman or Ms. Hersman, and should we be dealing with that
in this authorization?
Ms. Quarterman. Well, first let me speak to the excavation
damage issue. I fully agree with you that those two incidents
were absolutely preventable and, had all the correct steps been
taken both by the people excavating to call and the people
owning the pipeline to mark the line and mark it correctly,
that those incidents would not have occurred.
Since the PIPES Act of 2006, in about 2007, PHMSA worked to
create the National 811 Number and has been providing funding
to the Common Ground Alliance, which deals not only with
pipelines but with other underground utilities, to support
publishing information.
Senator Hutchison. What is the participation level of
states? Is it high or is it low?
Ms. Quarterman. The states are actually very, very much
participating at a high level. Unfortunately, there are some
states that have the exemptions that you refer to, and I have
to say during my speeches to all the organizations that might
be affected by this I repeatedly tell them the exemptions are
not something that we believe are appropriate. For example,
with respect to the State of Maryland, they were very recently
creating a One-Call law and they were going to exempt the
Department of Transportation. We called and talked to them and
were able to help them come to the conclusion that wasn't the
right decision.
We have a lot of work to do on some states. Some states are
doing a fantastic job. But it is a gradual process. I think we
could be doing a lot more if we had more funding on this. We
are providing state damage prevention grants of about $2
million a year to all the states who come and request money to
work on damage prevention. We also have $1 million in One-Call
grants that go to the States as well. So there's a lot being
done, but obviously until 8-1-1 becomes recognized the same as
9-1-1 we would not have done our job completely.
Senator Hutchison. On the coastal issue?
Ms. Quarterman. Yes, on the coastal issue, the jurisdiction
is somewhat confusing. PHMSA has two memoranda of understanding
with the Department of Interior and with the Coast Guard and
also with EPA with respect to, for example, oil spill response.
One memorandum of understanding divides the authority on who
should get oil spill response plans between those different
agencies, and PHMSA gets the plans for onshore pipelines and
MMS gets it for offshore pipelines and other offshore
facilities. I think that maybe there's a piece of legislation
under consideration to change that.
With respect to the jurisdiction over pipelines on the
outer continental shelf, MMS has jurisdiction over those that
are production pipelines, production-related facilities. PHMSA
has those that are on the outer continental shelf that are
transportation-related and the states have those that are in
state water.
Senator Hutchison. Yes, I know. My time is up, so I won't
pursue it further. But any input you can offer on this
reauthorization that would help with those conflicts, I would
appreciate.
Thank you, Mr. Chairman.
[The prepared statement of Senator Hutchison follows:]

Prepared Statement of Hon. Kay Bailey Hutchison, Senator from Texas

Thank you, Senator Lautenberg, and thank you for holding this
afternoon's hearing. It is certainly timely. The ongoing Deepwater
Horizon crisis in the Gulf is an unfortunate wake-up call not only to
oil production safety, but to the safety of the Nation's vast oil and
gas pipeline system. While the safety record for pipelines has
continued to improve, particularly when viewed in terms of exposure, it
is important for our Committee to consider what more needs to be done
as we begin the process of reauthorizing the Pipeline and Hazardous
Materials Safety Administration, whose current authorization expires in
September.
I also want to welcome of all our witnesses today. I will not be
able to stay for the entire hearing, but will likely have follow-up
questions for the witnesses after the hearing.
The oil and gas industry is a foundation of the Texas economy, and
contributes greatly to the quality of life all Americans enjoy. Texas
produces one quarter of the Nation's refined petrochemical products,
and 30 percent of the Nation's natural gas supplies. It is not
surprising, then, that Texas has more miles of pipeline than any other
State--over 220,000 miles, located both on-shore and in the Gulf of
Mexico. My constituents, therefore, have a very direct stake in
pipeline safety.
In just the past few weeks, there have been two deadly gas pipeline
accidents in Texas, both of which resulted from pipeline damage during
excavation work. The accidents highlight the need to focus more
attention on the national ``One-Call'' program. Every accident caused
by excavation is a preventable accident, and I want to ensure to the
extent I can, that the Texas Excavation Safety System (TESS), and the
One-Call systems in other States, are consulted by all developers,
construction companies, and others with a need to dig in the vicinity
of a pipeline. ``Call before you dig'' can mean the difference of life
or death.
Because of the Deepwater oil spill, I--and probably many of my
colleagues--will also want to learn more about the safety regulations
that apply to off-shore pipelines. For example, does it makes sense for
PHMSA (fim-za) to regulate off-shore transmission lines in state
waters, while the Minerals Management Service (MMS) has jurisdiction
for off-shore pipelines in the Outer Continental Shelf? I am concerned
that regulations may not be uniform and that in the event of an
accident, there could be confusion about who is in charge. I would also
like to understand what PHMSA, MMS, and the pipeline companies are
doing to address the unique environment for underwater pipelines,
including corrosion, and threats caused by vessels and hurricanes.
The last two reauthorizations of PHMSA have transformed how
pipelines are regulated in this country, from a system of traditional
enforcement by Federal and State inspectors, to a system built on
``integrity management". Under integrity management, inspectors still
conduct inspections, but the pipeline owners themselves must take
responsibility for inspecting and making repairs to critical portions
of their lines on a scheduled basis. Integrity management appears to be
working well, but I will be interested in learning whether all of our
panelists today agree.
Finally, I am interested the witnesses' recommendations, in
particular those of Ms. Quarterman, for reauthorizing PHMSA. I hope the
Administration will be sending Congress a formal proposal in the very
near term. Thank you, Mr. Chairman.

Senator Thune. Thank you, Senator Hutchison.
Let me, until the Chairman gets back from the vote,
hopefully in the next few minutes, ask a couple of questions,
and then I'm going to have to run and vote, too. But I do want
to thank you for appearing here today.
Pipeline transportation is crucial to our Nation's economy.
Without it, we don't have a way of meeting the energy needs of
American homes and businesses. I think pipelines are going to
play an important role in America's energy future, too. In
South Dakota, as has already been referenced, the first of two
TransCanada Pipelines was recently completed and is now
transporting crude oil from Canada to markets in the Midwest.
The second one, Keystone XL, is currently awaiting approval and
could start construction as early as next summer, and once
completed this pipeline is going to transport crude oil to
markets in Oklahoma and the Gulf. So I want to come back to a
question in just a moment about that.
But another area of interest that I think is important in
terms of America's future energy requirements and our
capability to meet those requirements is the development of
some of these specialized pipelines to transport ethanol and
biofuels. There's a company in South Dakota called POET, which
is the world's largest producer of ethanol, and Magellan
Midstream Partners, who together have proposed the construction
of a 1,700-mile ethanol pipeline from South Dakota to the East
Coast. Moving ethanol by pipeline would be cheaper, more
efficient, and safer than moving the product by truck or rail
as it is done today. I think that this ambitious and innovative
proposal is very encouraging and exciting, particularly as we
try to chart a course toward energy independence.
So a couple of questions on those subjects. One dealing
with Keystone pipeline I would direct to you, Ms. Quarterman,
and that is what requirements did PHMSA impose on Keystone in
approving Keystone's request to operate the pipeline at a
higher than normal pressure?
Ms. Quarterman. Are you referring to Keystone 1?
Senator Thune. Keystone 1. Well, Keystone 1 is the one
that's completed.
Ms. Quarterman. Yes.
Senator Thune. So focus on that, because Keystone 2 is
still in the process.
Ms. Quarterman. We are actually reviewing a request for
Keystone XL to have the same authorities. With respect to
Keystone 1, there were additional requirements on that
pipeline. I don't know them off the top of my head. I will have
to provide you those for the record, but there were additional
requirements.
[The information referred to follows:]

Department of Transportation
Pipeline and Hazardous Materials Safety Administration (PHMSA)
Special Permit

Docket Number: PHMSA-2006-26617

Pipeline Operator: TransCanada Keystone Pipeline, L.P.

Date Requested: November 17, 2006

Code Section(s): 49 CFR 195.106
Grant of Special Permit
Based on the findings set forth below, the Pipeline and Hazardous
Materials Safety Administration (PHMSA) grants this special permit to
TransCanada Keystone Pipeline, L.P. (Keystone). This special permit
allows Keystone to design, construct and operate two new crude oil
pipelines using a design factor and operating stress level of 80
percent of the steel pipe's specified minimum yield strength (SMYS) in
rural areas. The current regulations in 49 CFR 195.106 limit the design
factor and operating stress level for hazardous liquids pipelines to 72
percent of SMYS. This special permit is subject to the conditions set
forth below.
Except for the non-covered portions of the pipelines described
below, this special permit covers two proposed pipelines in the United
States:

The 1,025-mile, 30-inch, Mainline from the Canadian border
at Cavalier County, North Dakota, traversing the States of
South Dakota, Nebraska, Kansas and Missouri, to Wood River,
Illinois; and

The 291-mile, 36-inch, Cushing Extension from Jefferson
County, Nebraska, through Kansas, to Cushing (Marion County),
Oklahoma.

This special permit does not cover certain portions of the Mainline
and Cushing Extension pipelines. These non-covered portions are the
following:

Pipeline segments operating in high consequence areas (HCAs)
described as commercially navigable waterways in 49 CFR
195.450;

Pipeline segments operating in HCAs described as high
population areas in 49 CFR 195.450;

Pipeline segments operating at highway, railroad and road
crossings; and

Piping located within pump stations, mainline valve
assemblies, pigging facilities and measurement facilities.

For the purpose of this special permit, the ``special permit area''
means the area consisting of the entire pipeline right-of-way for those
segments of the pipeline that will operate above 72 percent of SMYS.

Findings
PHMSA finds that granting this special permit to Keystone to
operate two new crude oil pipelines at a pressure corresponding to a
hoop stress of up to 80 percent SMYS is not inconsistent with pipeline
safety. Doing so will provide a level of safety equal to, or greater
than, that which would be provided if the pipelines were operated under
existing regulations. We do so because the special permit analysis
shows the following:

Keystone's special permit application describes actions for
the life cycle of each proposed pipeline addressing pipe and
material quality, construction quality control, pre-in service
strength testing, the Supervisory Control and Data Acquisition
(SCADA) system inclusive of leak detection, operations and
maintenance and integrity management. The aggregate affect of
these actions and PHMSA's conditions provide for more
inspections and oversight than would occur on pipelines
installed under existing regulations; and

The conditions contained in this special permit grant
require Keystone to more closely inspect and monitor the
pipelines over its operational life than similar pipelines
installed without a special permit.

Conditions
The grant of this special permit is subject to the following
conditions:

1. Steel Properties: The skelp/plate must be micro alloyed,
fine grain, fully killed steel with calcium treatment and
continuous casting.

2. Manufacturing Standards: The pipe must be manufactured
according to American Petroleum Institute Specification 5L,
Specification for Line Pipe (API 5L), product specification
level 2 (PSL 2), supplementary requirements (SR) for maximum
operating pressures and minimum operating temperatures. Pipe
carbon equivalents must be at or below 0.23 percent based on
the material chemistry parameter (Pcm) formula.

3. Transportation Standards: The pipe delivered by rail car
must be transported according to the API Recommended Practice
5L1, Recommended Practice for Railroad Transportation of Line
Pipe (API 5L1).

4. Fracture Control: API 5L and other specifications and
standards address the steel pipe toughness properties needed to
resist crack initiation. Keystone must institute an overall
fracture control plan addressing steel pipe properties
necessary to resist crack initiation and propagation. The plan
must include acceptable Charpy Impact and Drop Weight Tear Test
values, which are measures of a steel pipeline's toughness and
resistance to fracture. The fracture control plan, which must
be submitted to PHMSA headquarters, must be in accordance with
API 5L, Appendix F and must include the following tests:

a. SR 5A--Fracture Toughness Testing for Shear Area:
Test results must indicate at least 85 percent minimum
average shear area for all X-70 heats and 80 percent
minimum shear area for all X-80 heats with a minimum
result of 80 percent shear area for any single test.
The test results must also ensure a ductile fracture;

b. SR 5B--Fracture Toughness Testing for Absorbed
Energy; and

c. SR 6--Fracture Toughness Testing by Drop Weight Tear
Test: Test results must be at least 80 percent of the
average shear area for all heats with a minimum result
of 60 percent of the shear area for any single test.
The test results must also ensure a ductile fracture.

The above fracture initiation, propagation and arrest plan must
account for the entire range of pipeline operating
temperatures, pressures and product compositions planned for
the pipeline diameter, grade and operating stress levels,
including maximum pressures and minimum temperatures for
startup and shut down conditions associated with the special
permit area. If the fracture control plan for the pipe in the
special permit area does not meet these specifications,
Keystone must submit to PHMSA headquarters an alternative plan
providing an acceptable method to resist crack initiation,
crack propagation and to arrest ductile fractures in the
special permit area.

5. Steel Plate Quality Control: The steel mill and/or pipe
rolling mill must incorporate a comprehensive plate/coil mill
and pipe mill inspection program to check for defects and
inclusions that could affect the pipe quality. This program
must include a plate or rolled pipe (body and all ends)
ultrasonic testing (UT) inspection program per ASTM A578 to
check for imperfections such as laminations. An inspection
protocol for centerline segregation evaluation using a test
method referred to as slab macro-etching must be employed to
check for inclusions that may form as the steel plate cools
after it has been cast. A minimum of one macro-etch or a
suitable alternative test must be performed from the first or
second heat (manufacturing run) of each sequence (approximately
four heats) and graded on the Mannesmann scale or equivalent.
Test results with a Mannesmann scale rating of one or two out
of a possible five scale are acceptable.

6. Pipe Seam Quality Control: A quality assurance program must
be instituted for pipe weld seams. The pipe weld seam tests
must meet the minimum requirements for tensile strength in API
5L for the appropriate pipe grade properties. A pipe weld seam
hardness test using the Vickers hardness testing of a cross-
section from the weld seam must be performed on one length of
pipe from each heat. The maximum weld seam and heat affected
zone hardness must be a maximum of 280 Vickers hardness (Hv10).
The hardness tests must include a minimum of two readings for
each heat affected zone, two readings in the weld metal and two
readings in each section of pipe base metal for a total of 10
readings. The pipe weld seam must be 100 percent UT inspected
after expansion and hydrostatic testing per APL 5L.

7. Monitoring for Seam Fatigue from Transportation: Keystone
must inspect the double submerged arc welded pipe seams of the
delivered pipe using properly calibrated manual or automatic UT
techniques. For each lay down area, a minimum of one pipe
section from the bottom layer of pipes of the first five rail
car shipments from each pipe mill must be inspected. The entire
longitudinal weld seam must be tested and the results
appropriately documented. For helical seam submerged arc welded
pipe, Keystone must test and document the weld seam in the area
along the transportation bearing surfaces and all other exposed
weld areas during the test. Each pipe section test record must
be traceable to the pipe section tested. PHMSA headquarters
must be notified of any flaws that exceeded specifications and
needed to be removed. Keystone's findings will determine if
PHMSA will require the testing program be expanded to include a
larger sampling population for seam defects originating during
pipeline transportation.

8. Puncture Resistance: Steel pipe must be puncture resistant
to an excavator weighing up to 65 tons with a general purpose
tooth size of 3.54 inches by 0.137 inches. Puncture resistance
will be calculated based on industry established calculations
such as the Pipeline Research Council International's
Reliability Based Prevention of Mechanical Damage to Pipelines
calculation method.

9. Mill Hydrostatic Test: The pipe must be subjected to a mill
hydrostatic test pressure of 95 percent of SMYS or greater for
10 seconds. Any mill hydrostatic test failures must be reported
to PHMSA headquarters with the reason for the test failure.

10. Pipe Coating: The application of a corrosion resistant
coating to the steel pipe must be subject to a coating
application quality control program. The program must address
pipe surface cleanliness standards, blast cleaning, application
temperature control, adhesion, cathodic disbondment, moisture
permeation, bending, minimum coating thickness, coating
imperfections and coating repair.

11. Field Coating: Keystone must implement a field girth weld
joint coating application specification and quality standards
to ensure pipe surface cleanliness, application temperature
control, adhesion quality, cathodic disbondment, moisture
permeation, bending, minimum coating thickness, holiday
detection and repair quality must be implemented in field
conditions. Field joint coatings must be non-shielding to
cathodic protection (CP). Field coating applicators must use
valid coating procedures and be trained to use these
procedures. Keystone will perform follow-up tests on field-
applied coating to confirm adequate adhesion to metal and mill
coating.

12. Coatings for Trenchless Installation: Coatings used for
directional bore, slick bore and other trenchless installation
methods must resist abrasions and other damages that may occur
due to rocks and other obstructions encountered in this
installation technique.

13. Bends Quality: Certification records of factory induction
bends and/or factory weld bends must be obtained and retained.
All bends, flanges and fittings must have carbon equivalents
(CE) equal to or below 0.42 or a pre-heat procedure must be
applied prior to welding for CE above 0.42.

14. Fittings: All pressure rated fittings and components
(including flanges, valves, gaskets, pressure vessels and
pumps) must be rated for a pressure rating commensurate with
the MOP of the pipeline.

15. Design Factor--Pipelines: Pipe installed under this special
permit may use a 0.80 design factor. Pipe installed in pump
stations, road crossings, railroad crossings, launcher/receiver
fabrications, population HCAs and navigable waters must comply
with the design factor in 49 CFR 195.106. If portions of the
pipeline become population HCAs during the operational life of
the pipeline, Keystone will apply to PHMSA headquarters for a
special permit for the affected pipeline sections.

16. Temperature Control: The pipeline operating temperatures
must be less than 150 degrees Fahrenheit.

17. Overpressure Protection Control: Mainline pipeline
overpressure protection must be limited to a maximum of 110
percent MOP consistent with 49 CFR 195.406(b).

18. Construction Plans and Schedule: The construction plans,
schedule and specifications must be submitted to the
appropriate PHMSA regional office for review within 2 months of
the anticipated construction start date. Subsequent plans and
schedule revisions must also be submitted to the PHMSA regional
office.

19. Welding Procedures: The appropriate PHMSA regional office
must be notified within 14 days of the beginning of welding
procedure qualification activities. Automated or manual welding
procedure documentation must be submitted to the same PHMSA
regional office for review. For X-80 pipe, Keystone must
conform to revised procedures contained in the 20th edition of
API Standard 1104, Welding of Pipelines and Related Facilities
(API 1104), Appendix A, or by an alternative procedure approved
by PHMSA headquarters.

20. Depth of Cover: The soil cover must be maintained at a
minimum depth of 48 inches in all areas except consolidated
rock. In areas where conditions prevent the maintenance of 42
inches of cover, Keystone must employ additional protective
measures to alert the public and excavators to the presence of
the pipeline. The additional measures shall include placing
warning tape and additional pipeline markers along the affected
pipeline segment. In areas where the pipeline is susceptible to
threats from chisel plowing or other activities, the top of the
pipeline must be installed at least one foot below the deepest
penetration above the pipeline. If routine patrols indicate the
possible loss of cover over the pipeline, Keystone must perform
a depth of cover study and replace cover as necessary to meet
the minimum depth of cover requirements specified herein. If
the replacement of cover is impractical or not possible,
Keystone must install other protective measures including
warning tape and closely spaced signs.

21. Construction Quality: A construction quality assurance plan
for quality standards and controls must be maintained
throughout the construction phase with respect to: inspection,
pipe hauling and stringing, field bending, welding, non-
destructive examination (NDE) of girth welds, field joint
coating, pipeline coating integrity tests, lowering of the
pipeline in the ditch, padding materials to protect the
pipeline, backfilling, alternating current (AC) interference
mitigation and CP systems. All girth welds must be NDE by
radiography or alternative means. The NDE examiner must have
all current required certifications.

22. Interference Currents Control: Control of induced
alternating current from parallel electric transmission lines
and other interference issues that may affect the pipeline must
be incorporated into the design of the pipeline and addressed
during the construction phase. Issues identified and not
originally addressed in the design phase must be brought to
PHMSA headquarters' attention. An induced AC program to protect
the pipeline from corrosion caused by stray currents must be in
place and functioning within 6 months after placing the
pipeline in service.

23. Test Level: The pre-in service hydrostatic test must be to
a pressure producing a hoop stress of 100 percent SMYS and 1.25
X MOP in areas to operate to 80 percent SMYS. The hydrostatic
test results from each test after completion of each pipeline
must be submitted to PHMSA headquarters.

24. Assessment of Test Failures: Any pipe failure occurring
during the pre-in service hydrostatic test must undergo a root
cause failure analysis to include a metallurgical examination
of the failed pipe. The results of this examination must
preclude a systemic pipeline material issue and the results
must be reported to PHMSA headquarters and the appropriate
PHMSA regional office.

25. Supervisory Control and Data Acquisition (SCADA) System: A
SCADA system to provide remote monitoring and control of the
entire pipeline system must be employed.

26. SCADA System--General:

a. Scan rate shall be fast enough to minimize
overpressure conditions (overpressure control system),
provide very responsive abnormal operation indications
to controllers and detect small leaks within technology
limitations;

b. Must meet the requirements of regulations developed
as a result of the findings of the National
Transportation Safety Board, Supervisory Control and
Data Acquisition (SCADA) in Liquid Pipelines, Safety
Study, NTSB/SS-05/02 specifically including:

-- Operator displays shall adhere to guidance
provided in API Recommended Practice 1165,
Recommended Practice for Pipeline SCADA Display
(API RP 1165)

-- Operators must have a policy for the review/
audit of alarms for false alarm reduction and
near miss or lessons learned criteria

-- SCADA controller training shall include
simulator for controller recognition of
abnormal operating conditions, in particular
leak events

-- See item 27b below on fatigue management

-- Install computer-based leak detection system
on all lines unless an engineering analysis
determines that such a system is not necessary

c. Develop and implement shift change procedures for
controllers;

d. Verify point-to-point display screens and SCADA
system inputs before placing the line in service;

e. Implement individual controller log-in provisions;

f. Establish and maintain a secure operating control
room environment;

g. Establish controls to functionally test the pipeline
in an off-line mode prior to beginning the line fill
and placing the pipeline in service; and

h. Provide SCADA computer process load information
tracking.

27. SCADA--Alarm Management: Alarm Management Policy and
Procedures shall address:

a. Alarm priorities determination;

b. Controllers' authority and responsibility;

c. Clear alarm and event descriptors that are
understood by controllers;

d. Number of alarms;

e. Potential systemic system issues;

f. Unnecessary alarms;

g. Controllers' performance regarding alarm or event
response;

h. Alarm indication of abnormal operating conditions
(ADCs);

i. Combination AOCs or sequential alarms and events;
and

j. Workload concerns.

28. SCADA--Leak Detection System (LDS): The LDS Plan shall
include provisions for:

a. Implementing applicable provisions in API
Recommended Practice 1130, Computational Pipeline
Monitoring for Liquid Pipelines (API RP 1130), as
appropriate;

b. Addressing the following leak detection system
testing and validation issues:

-- Routine testing to ensure degradation has
not affected functionality

-- Validation of the ability of the LDS to
detect small leaks and modification of the LDS
as necessary to enhance its accuracy to detect
small leaks

-- Conduct a risk analysis of pipeline segments
to identify additional actions that would
enhance public safety or environmental
protection

c. Developing data validation plan (ensure input data
to SCADA is valid);

d. Defining leak detection criteria in the following
areas:

-- Minimum size of leak to be detected
regardless of pipeline operating conditions
including slack and transient conditions

-- Leak location accuracy for various pipeline
conditions

-- Response time for various pipeline
conditions

e. Providing redundancy plans for hardware and software
and a periodic test requirement for equipment to be
used live (also applies to SCADA equipment).

29. SCADA--Pipeline Model and Simulator: The Thermal-Hydraulic
Pipeline Model/ Simulator including pressure control system
shall include a Model Validation/Verification Plan.

30. SCADA--Training: The training and qualification plan
(including simulator training) for controllers shall:

a. Emphasize procedures for detecting and mitigating
leaks;

b. Include a fatigue management plan and implementation
of a shift rotation schedule that minimizes possible
fatigue concerns;

c. Define controller maximum hours of service
limitations;

d. Meet the requirements of regulations developed as a
result of the guidance provided in the American Society
of Mechanical Engineers Standard B31Q, Pipeline
Personnel Qualification Standard (ASME B31Q), September
2006 for developing qualification program plans;

e. Include and implement a full training simulator
capable of replaying near miss or lesson learned
scenarios for training purposes;

f. Implement tabletop exercises periodically that allow
controllers to provide feedback to the exercises,
participate in exercise scenario development and
actively participate in the exercise;

g. Include field visits for controllers accompanied by
field personnel who will respond to call-outs for that
specific facility location;

h. Provide facility specifics in regard to the position
certain equipment devices will default to upon power
loss;

i. Include color blind and hearing provisions and
testing if these are required to identify alarm
priority or equipment status;

j. Training components for task specific abnormal
operating conditions and generic abnormal operating
conditions;

k. If controllers are required to respond to ``800''
calls, include a training program conveying proper
procedures for responding to emergency calls,
notification of other pipeline operators in the area
when affecting a common pipeline corridor and education
on the types of communications supplied to emergency
responders and the public using API Recommended
Practice 1162, Public Awareness Programs for Pipeline
Operators (API RP 1162);

l. Implement on-the-job training component intervals
established by performance review to include thorough
documentation of all items covered during oral
communication instruction; and

m. Implement a substantiated qualification program for
re-qualification intervals addressing program
requirements for circumstances resulting in
disqualification, procedure documentation for maximum
controller absences before a period of review,
shadowing, retraining, and addressing interim
performance verification measures between re-
qualification intervals.

31. SCADA--Calibration and Maintenance: The calibration and
maintenance plan for the instrumentation and SCADA system shall
be developed using guidance provided in API 1130.
Instrumentation repairs shall be tracked and documentation
provided regarding prioritization of these repairs. Controller
log notes shall periodically be reviewed for concerns regarding
mechanical problems. This information will be tracked and
prioritized.

32. SCADA--Leak Detection Manual: The Leak Detection Manual
shall be prepared using guidance provided in Canadian Standards
Association, Oil and Gas Pipeline Systems, CSA Z662-03, Annex
E, Section E.5.2, Leak Detection Manual.

33. Mainline Valve Control: Mainline valves located on either
side of a pipeline segment containing an HCA where personnel
response time to the valve exceeds 1 hour must be remotely
controlled by the SCADA system. The SCADA system must be
capable of opening and closing the valve and monitoring the
valve position, upstream pressure and downstream pressure.

34. Pipeline Inspection: The pipeline must be capable of
passing in line inspection (ILI) tools. All headers and other
segments covered under this special permit that do not allow
the passage of an ILI device must have a corrosion mitigation
plan.

35. Internal Corrosion: Keystone shall limit sediment and water
(S&W) to 0.5 percent by volume and report S&W testing results
to PHMSA in the 180-day and annual reports. Keystone shall also
report upset conditions causing S&W level excursions above the
limit. This report shall also contain remedial measures
Keystone has taken to prevent a recurrence of excursions above
the S&W limits. Keystone must run cleaning pigs twice in the
first full year of operation and as necessary in succeeding
years based on the analysis of oil constituents, weight loss
coupons located in areas with the greatest internal corrosion
threat and other internal corrosion threats. Keystone will send
their analyses and further actions, if any, to PHMSA.

36. Cathodic Protection (CP): The initial CP system must be
operational within 6 months of placing a pipeline segment in
service.

37. Interference Current Surveys: Interference surveys must be
performed within 6 months of placing the pipeline in service to
ensure compliance with applicable NACE International Standard
Recommended Practices 0169 and 0177 (NACE RP 0169 and NACE RP
0177) for interference current levels. If interference currents
are found, Keystone will determine if there have been any
adverse affects to the pipeline and mitigate the affects as
necessary. Keystone will report the results of any negative
finding and the associated mitigative efforts to the
appropriate PHMSA regional office.

38. Corrosion Surveys: Corrosion surveys of the affected
pipeline must be completed within 6 months of placing the
respective CP system(s) in operation to ensure adequate
external corrosion protection per NACE RP 0169. The survey will
also address the proper number and location of CP test stations
as well as AC interference mitigation and AC grounding programs
per NACE RP 0177. At least one CP test station must be located
within each HCA with a maximum spacing between test stations of
one-half mile within the HCA. If placement of a test station
within an HCA is impractical, the test station must be placed
at the nearest practical location. If any annual test station
reading fails to meet 49 CFR 195, Subpart H requirements,
remedial actions must occur within 6 months. Remedial actions
must include a close interval survey on each side of the
affected test station and all modifications to the CP system
necessary to ensure adequate external corrosion control.

39. Initial Close Interval Survey (CIS)--Initial: A CIS must be
performed on the pipeline within 2 years of the pipeline in-
service date. The CIS results must be integrated with the
baseline ILI to determine whether further action is needed.

40. Pipeline Markers: Keystone must employ line-of-sight
markings on the pipeline in the special permit area except in
agricultural areas or large water crossings such as lakes where
line of sight markers are impractical. The marking of pipelines
is also subject to Federal Energy Regulatory Commission orders
or environmental permits and local restrictions. Additional
markers must be placed along the pipeline in areas where the
pipeline is buried less than 42 inches.

41. Monitoring of Ground Movement: An effective monitoring/
mitigation plan must be in place to monitor for and mitigate
issues of unstable soil and ground movement.

42. Initial In-Line Inspection (ILI): Keystone must perform a
baseline ILI in association with the construction of the
pipeline using a high-resolution Magnetic Flux Leakage (MFL)
tool to be completed within 3 years of placing a pipeline
segment in service. The high-resolution MFL tool must be
capable of gouge detection. Keystone must perform a baseline
geometry tool run after completion of the hydrostatic strength
test and backfill of the pipeline, but no later than 6 months
after placing the pipeline in service under a special permit.
The ILI data summary sheets and planned digs with associated
ILI tool readings will be sent to the PHMSA regional office.
The PHMSA regional office will be given at least 14 days notice
before confirmation digs are executed onsite. The dimensional
data and other characteristics extracted from these digs will
be shared with the PHMSA regional office. Keystone will also
compare dimensional data and other characteristics extracted
from the digs and compare them with ILI tool data. If there are
large variations between dig data and ILI tool data, Keystone
will submit PHMSA a plan on further actions, inclusive of more
digs, to calibrate their analysis and remediation process.

43. Future ILI: Future ILI inspection must be performed on the
entire pipeline subject to the special permit, on a frequency
consistent with 49 CFR 195.452(j)(3), assessment intervals, or
on a frequency determined by fatigue studies based on actual
operating conditions, inclusive of flaw and corrosion growth
models.

44. Verification of Reassessment Interval: Keystone must submit
a new fatigue analysis to validate the pipeline reassessment
interval annually for the first 5 years after placing the
pipeline subject to this special permit in service. The
analysis must be performed on the segment experiencing the most
severe historical pressure cycling conditions using actual
pipeline pressure data.

45. Two years after the pipeline in-service date, Keystone will
use all data gathered on pipeline section experiencing the most
pressure cycles to determine effect on flaw growth that passed
manufacturing standards and installation specifications. This
study will be performed by an independent party agreed to by
Keystone and PHMSA headquarters. Furthermore, this study will
be shared with PHMSA headquarters as soon as practical after
its completion, preferably before baseline assessment begins.
These findings will determine if an ultrasonic crack detection
tool must be launched in that pipeline section to confirm crack
growth with Keystone's crack growth predictive models.

46. Direct Assessment Plan: Headers, mainline valve bypasses
and other sections covered by this special permit that cannot
accommodate ILI tools must be part of a Direct Assessment (DA)
plan or other acceptable integrity monitoring method using
External and Internal Corrosion Direct Assessment criteria
(ECDA/ICDA).

47. Damage Prevention Program: The Common Ground Alliance (CGA)
damage prevention best practices applicable to pipelines must
be incorporated into the Keystone's damage prevention program.

48. Anomaly Evaluation and Repair: Anomaly evaluations and
repairs in the special permit area must be performed based upon
the following:

a. Immediate Repair Conditions: Follow 195.452(h)(4)(i)
except designate the calculated remaining strength
failure pressure ratio (FPR) = < 1.16;

b. 60-Day Conditions: No changes to 195.452(h)(4)(ii);

c. 180-Day Conditions: Follow 195.452(H)(4)(iii) with
exceptions for the following conditions which must be
scheduled for repair within 180 days:

-- Calculated FPR = < 1.32

-- Areas of general corrosion with predicted
metal loss greater than 40 percent

-- Predicted metal loss is greater than 40
percent of nominal wall that is located at a
crossing of another pipeline

-- Gouge or groove greater than 8 percent of
nominal wall

d. Each anomaly not repaired under the immediate repair
requirements must have a corrosion growth rate and ILI
tool tolerance assigned per the Integrity Management
Program (IMP) to determine the maximum re-inspection
interval.

e. Anomaly Assessment Methods: Keystone must confirm
the remaining strength (RSTRENG) effective area, R-
STRENG--0.85dL and ASME B31G assessment methods are
valid for the pipe diameter, wall thickness, grade,
operating pressure, operating stress level and
operating temperature. Keystone must also use the most
conservative method until confirmation of the proper
method is made to PHMSA headquarters.

f. Flow Stress: Remaining strength calculations for X-
80 pipe must use a flow stress equal to the average of
the ultimate (tensile) strength and the SMYS.

g. Dents: For initial construction and the initial
geometry tool run, any dent with a depth greater than 2
percent of the nominal pipe diameter must be removed
unless the dent is repaired by a method that reliable
engineering tests and analyses show can permanently
restore the serviceability of the pipe. For the
purposes of this condition, a ``dent'' is a depression
that produces a gross disturbance in the curvature of
the pipe wall without reducing the pipe wall thickness.
The depth of the dent is measured as the gap between
the lowest point of the dent and the prolongation of
the original contour of the pipe.

49. Reporting--Immediate: Keystone must notify the appropriate
PHMSA regional office within 24 hours of any non-reportable
leaks originating in the pipe body in the special permit area.

50. Reporting--180 Day: Within 180 days of the pipeline in-
service date under a special permit, Keystone shall report on
its compliance with special permit conditions to PHMSA
headquarters and the appropriate regional office. The report
must also include pipeline operating pressure data, including
all pressures and pressure cycles versus time. The data format
must include both raw data in a tabular format and a graphical
format. Any alternative formats must be approved by PHMSA
headquarters.

51. Annual Reporting: Following approval of the special permit,
Keystone must annually report the following:

a. The results of any ILI or direct assessment results
performed within the special permit area during the
previous year;

b. The results of all internal corrosion management
programs including the results of:

-- S&W analyses

-- Report of processing plant upset conditions
where elevated levels of S&W are introduced
into the pipeline

-- Corrosion inhibitor and biocide injection

-- Internal cleaning program

-- Wall loss coupon tests

c. Any new integrity threats identified within the
special permit area during the previous year;

d. Any encroachment in the special permit area,
including the number of new residences or public
gathering areas;

e. Any HCA changes in the special permit area during
the previous year;

f. Any reportable incidents associated with the special
permit area that occurred during the previous year;

g. Any leaks on the pipeline in the special permit area
that occurred during the previous year;

h. A list of all repairs on the pipeline in the special
permit area during the previous year;

i. On-going damage prevention initiatives on the
pipeline in the special permit area and a discussion of
their success or failure;

j. Any changes in procedures used to assess and/or
monitor the pipeline operating under this special
permit;

k. Any company mergers, acquisitions, transfers of
assets, or other events affecting the regulatory
responsibility of the company operating the pipeline to
which this special permit applies; and

l. A report of pipeline operating pressure data to
include all pressures and pressure cycles versus time.
The data format must include both raw data in a tabular
format and a graphical format. Any alternative formats
must be approved by PHMSA headquarters.

Limitations
Should Keystone fail to comply with any conditions of this special
permit, or should PHMSA determine this special permit is no longer
appropriate or that this special permit is inconsistent with pipeline
safety, PHMSA may revoke this special permit and require Keystone to
comply with the regulatory requirements in 49 CFR 195.106.

Background and Process
The Keystone Pipeline is a 1,845-mile international and interstate
crude oil pipeline project developed by TransCanada Keystone Pipeline
L.P., a wholly-owned subsidiary of TransCanada Pipelines Limited. The
Keystone Pipeline will transport a nominal capacity of 435,000 barrels
per day of crude oil from western Canada's sedimentary basin producing
areas in Alberta to refineries in the United States. Keystone indicates
it has filed an application with the U.S. Department of State for a
Presidential Permit for the Keystone Pipeline since the project
involves construction, operation and maintenance of facilities for the
importation of petroleum from a foreign country. Keystone anticipates
receiving all necessary government approvals by November 2007 and
beginning construction in late 2007. The targeted in-service date is
during the fourth quarter of 2009.
The existing regulations in 49 CFR 195.106 provide the method used
by pipeline operators to establish the MOP of a proposed pipeline by
using the design formula contained in that section. The formula
incorporates a design factor, also called a de-rating factor, which is
fixed at 0.72 for an onshore pipeline. Keystone requests the use of a
0.80 design factor in the formula instead of 0.72 design factor.
PHMSA previously granted waivers to four natural gas pipeline
operators to operate certain pipelines at a hoop stresses up to 80
percent SMYS. The Keystone pipeline project represents the first
request by an operator in the United States for approval to design and
operate a hazardous liquid (crude oil) pipeline beyond the existing
regulatory maximum level. Canadian standards already allow operators to
design and operate hazardous liquids pipelines at 80 percent SMYS.
On January 15, March 27, and April 17, 2006, PHMSA conducted
technical meetings to learn more about the technical merits of
Keystone's proposal to operate at 80 percent SMYS and to answer
questions posed by internal and external subject matter experts. The
meetings resulted in numerous technical information requests and
deliverables, to which Keystone satisfactorily responded.
PHMSA also secured the services of experts in the field of steel
pipeline fracture mechanics, leak detection and SCADA systems to assist
in the review of appropriate areas of Keystone's application. The
experts' reports are included in the public docket.
On February 8, 2007, PHMSA posted a notice of this special permit
request in the Federal Register (FR) (72 FR 6042). In the same FR
notice we informed the public that we have changed the name granting
such a request to a special permit. The request letter, the FR notice,
supplemental information and all other pertinent documents are
available for review under Docket Number PHMSA-2006-26617, in the DOT's
Document Management System.
Two comments were received and posted to the public docket
concerning the Keystone pipeline project request for a special permit.
One commenter listed a number of recommended and relevant conditions
for hazardous liquid pipelines to operate at 80 percent SMYS. The
conditions developed by PHMSA and incorporated into the grant of
special permit include the concerns of the commenter. The second
commenter did not provide substantive comments relevant to the special
permit request.

Authority: 49 U.S.C. 60118(c) and 49 CFR 1.53.

Issued in Washington, D.C. on April 30, 2007.

Jeffrey D. Wiese,
Acting Associate Administrator
for Pipeline Safety.

Senator Thune. If you could, that would be great. It's a
question that we frequently get asked back in South Dakota.
In your written testimony you stated that PHMSA has
increased its assistance to state pipeline safety agencies. I'm
wondering if there are other improvements that can be made in
terms of the coordination between PHMSA and the states.
Ms. Quarterman. Well, there are always improvements that
can be made. One that was discussed is coordinating the damage
prevention laws to make sure that none of the states have
exemptions. But we work very closely with our state partners
and the National Association of State Pipeline Representatives
as well. Perhaps the question is best left to them. I think we
have a good working relationship and we'd like to keep it that
way.
Senator Thune. Tell me what your agency can do to assist in
the development of ethanol and other biofuel pipelines?
Ms. Quarterman. Well, we have been doing--we do have money
for research and we have been using some of that money to
research different products that are being considered, biofuel
products that are being considered for pipeline transportation.
We have also been working with the fire organizations to
deal with issues, especially with respect to ethanol and how do
you respond to an ethanol fire in a pipeline. So we've been
working quite a bit on those issues.
Senator Thune. Mr. Chairman, I'd probably better run over
and vote since there's about 1 minute left, so I'll flip the
gavel back to you. Welcome back.
Senator Lautenberg [presiding]. Well, thank you. I'd like
to give you time to vote. Thank you.
I understand that some of the questions that I had asked
were discussed. So with that, I'll say thank you and, being
mindful of the fact that we keep the record open for some time
and if questions are submitted we ask for your prompt response
not more than a week after you get the questions. We thank each
one of you for making your testimony.
With that, we'll call the second panel. The second panel is
Mr. Rocco D'Alessandro, Tim Felt, Mr. Sypolt, and Mr. Weimer.
[Pause.]
That was the fastest relay I've run for a long time. I got
to the floor and voted and got back within about a 10-minute
cycle. So that was pretty good. I worked off some of the energy
that I might have saved for you folks.
We look forward to your testimony. Mr. D'Alessandro,
Executive Vice President of Operations, Nicor Gas and
representing the American Gas Association; Mr. Felt, President
and CEO of Colonial Pipeline and representing the Association
of Oil Pipelines; Mr. Gary Sypolt, Dominion Energy,
representing the Interstate Natural Gas Association of America;
and Mr. Carl Weimer, Executive Director of the Pipeline Safety
Trust.
Mr. D'Alessandro, I think each of you have heard that we
have a 5-minute time limit and we're going to stick fairly
closely to it so we can give each person a chance to testify.
Mr. D'Alessandro, we look forward to hearing from you now.

STATEMENT OF ROCCO D'ALESSANDRO, EXECUTIVE VICE PRESIDENT OF
OPERATIONS, NICOR GAS ON BEHALF OF THE AMERICAN GAS ASSOCIATION

Mr. D'Alessandro. Good afternoon, Mr. Chairman, members of
the Committee. I'm pleased to appear before you today. Pipeline
safety is a critically important issue and we thank you for
holding this hearing.
I'm testifying today on behalf of American Gas Association.
Founded in 1918, AGA represents 195 local energy companies that
deliver natural gas throughout the United States. There are
more than 70 million natural gas customers in the U.S., of
which 91 percent, or 65 million, receive their gas from AGA
members.
Mr. Chairman, members of the Committee: Our message today
is a simple one. We believe that the current pipeline safety
law is working well and should be reauthorized this year. The
2006 PIPES Act included several significant mandates that the
industry is in the process of implementing. Given this, we do
not believe there's a need for change in the pipeline safety
statute at this time, but rather urge the Committee to
reauthorize the current law.
Safety is our top priority. We spend an estimated $7
billion each year in safety-related activities. A large
percentage of our effort over the last several years has been
focused on working with Federal and state regulators in the
development and implementation of rules specific to the
mandates that were contained in the 2006 PIPES Act.
Specifically, there were four core provisions of the PIPES
Act that are key to enhancing the safety of distribution
pipelines: excavation damage prevention, distribution integrity
management plans, called DIMP, excess flow valves, and control
room management.
Excavation damage represents the single greatest threat to
distribution system safety, reliability, and integrity.
Regulators, natural gas operators, and other stakeholders are
continually working to improve excavation damage prevention
programs. It is having a positive impact, but, as always, more
can be done.
The PIPES Act required DOT to establish an integrity
management program for distribution pipeline operators. DOT
published the final DIMP rule on December 4 of last year. The
effective date was February 12 of this year and operators have
been given until August 2 of 2011 to write and implement the
program. This will impact 1,450 operators, 2.1 million miles of
piping, and 70 million customers.
The final rules allow operators to develop a DIMP plan that
is appropriate for the operating characteristics of their
delivery systems and the customers that they serve. I'm pleased
to report that the operators are working aggressively to
implement the DIMP rule.
The PIPES Act mandated that DOT require distribution gas
utilities install an excess flow valve on new and replacement
service lines for single-family residences if the service line
met specific conditions beginning on June 1, 2008. Operators
have installed an estimated 950,000 excess flow valves since
that date.
I do want to emphasize that Congress was absolutely correct
in limiting the EFV mandate to single-family residence
dwellings. It is inadvisable to attempt a mandatory nationwide
installation of EFVs beyond the single-family resident class to
multiple-family dwellings, commercial and industrial customers,
due to the inherent uncertainties and complexities associated
with the service lines and the significant variations in gas
load. Inadvertent EFV shutdown of a commercial or industrial
facility, like a hospital, chemical plant, could create greater
safety hazards than the release of gas the EFV was attempting
to prevent.
There are two issues that I'd like to bring to the
Committee's attention as we believe there are some additional
regulatory actions that DOT should be encouraged to take to
ensure that the existing statutes continue to be efficiently
implemented. Now that DOT has promulgated the DIMP regulation,
it can modify the assessment requirements for low-stress
transmission pipe operated by distribution gas utilities
covered by TIMP. Since low-stress transmission lines operate
more like distribution lines, we believe the low-stress
pipelines are better covered under the DIMP, which would result
in all low-stress lines being covered under the robust DIMP
regulation.
The other issue I want to bring to attention deals with
high-consequence areas, HCAs. There has been some talk of
perhaps changing the TIMP regulation by eliminating the HCA
definition and requiring operators to perform assessment on all
300,000 miles of natural gas transmission pipeline. Internal
instrument, or smart pigging, inspections are usually not
practical for transmission pipelines operated by distribution
gas utilities, because usually the pipes are not piggable.
As part of its TIMP regulation, DOT has already included
provisions for pipeline operators to have an added layer of
protection on low-stress pipelines outside of HCA areas, known
as Preventive and Mitigation Measures. AGA we strongly
discourage making a change to TIMP HCA criteria.
In summary, many of the mandates within the 2006 PIPES Act
have just become regulations and the government and industry
are working hard to implement these regulations. AGA believes
that Congressional passage of pipeline safety reauthorization
this year will send a positive message that the current law is
working and emphasize the commitment that Congress and all the
industry stakeholders have to securing the safety of the
Nation's pipeline system. We look forward to working with you
to secure reauthorization this year.
[The prepared statement of Mr. D'Alessandro follows:]

Prepared Statement of Rocco D'Alessandro, Executive Vice President of
Operations, Nicor Gas on Behalf of the American Gas Association

Good morning, Mr. Chairman and members of the Committee. I am
pleased to appear before you today. Pipeline safety is a critically
important issue, and I thank you for not only holding this hearing, but
for all the work that you and your colleagues have done over the years
to ensure that America has the safest, most reliable pipeline system in
the world. My name is Rocco D'Alessandro and I am the Executive Vice
President of Operations for Nicor Gas, based in Illinois. Nicor Gas is
the largest natural gas distributor in northern Illinois, serving more
than 2 million customers in 643 communities. Ninety-six percent of
homes in our service territory use natural gas. We serve our customers
utilizing 32,000 miles of gas distribution main and almost 2 million
gas services. There are also 1175 miles of transmission pipelines
integrated into Nicor's distribution system.
I am testifying today on behalf of the American Gas Association
(AGA). Founded in 1918, AGA represents 195 local energy companies that
deliver natural gas throughout the United States. There are more than
70 million residential, commercial and industrial natural gas customers
in the U.S., of which 91 percent--nearly 65 million customers--receive
their gas from AGA members. Today, natural gas meets almost one-fourth
of the United States' energy needs.
Distribution pipelines are operated by natural gas utilities,
sometimes called ``local distribution companies'' or LDCs. The gas
utility's distribution pipes are the last, critical link in the natural
gas delivery chain. Gas distribution utilities bring natural gas
service to customers' front doors. To most customers, their local
utilities are the ``face of the industry.'' Our customers see our name
on their bills, our trucks in the streets and our company sponsorship
of many civic initiatives. We live in the communities we serve and
interact daily with our customers and with the state regulators who
oversee pipeline safety. Consequently, we take very seriously the
responsibility of continuing to deliver natural gas to our communities
safely, reliably and affordably. The distribution pipeline system is an
interconnected network of transmission mains, distribution mains, and
service lines.
Mr. Chairman and members of the Committee, AGA believes that the
current pipeline safety law is working well and that there is no need
to make changes to the pipeline safety statute. I want to assure the
Committee that the natural gas industry has worked vigorously to
implement the significant provisions of the 2002 and 2006 Pipeline
Safety Acts. The industry safety performance has been exceptional and
AGA expects it to improve further after some of the recent pipeline
safety mandates have been fully implemented. For instance, the industry
has already begun marshalling resources to implement the Distribution
Integrity Management Program (DIMP) and Control Room Management
regulations that were promulgated in December 2009.
We strongly urge a straight reauthorization, so as to allow the
full implementation and refinement of each of the various regulations
that have been promulgated since the 2006 Pipeline Safety
reauthorization. We do not believe any new legislative action is
needed.

Regulatory Authority
As part of an agreement with the Federal Government, in most
states, state pipeline safety authorities have primary responsibility
to regulate natural gas utilities as well as intrastate transmission
pipeline companies. State governments are encouraged to adopt as
minimum standards the Federal safety standards promulgated by the
Department of Transportation (DOT). The states may also choose to adopt
standards that are more stringent than the Federal ones, and many have
done so. LDCs are in frequent contact with state pipeline safety
inspectors. As a result of these interactions, distribution operator
facilities are subject to more frequent and closer inspections than
required by the Federal pipeline safety regulations.

Commitment to Safety
Our commitment to safety extends beyond government oversight.
Indeed, safety is our top priority--a source of pride and a matter of
corporate policy for every company. These policies are carried out in
specific and unique ways. Each company employs safety professionals,
provides on-going employee evaluation and safety training, conducts
rigorous system inspections, testing, and maintenance, repair and
replacement programs, distributes public safety information, and
complies with a wide range of Federal and state safety regulations and
requirements. Individual company efforts are supplemented by
collaborative activities in the safety committees of regional and
national trade organizations. Examples of these groups include AGA, the
American Public Gas Association and the Interstate Natural Gas
Association of America.
Natural gas utilities have long made safety their number one
priority. We spend an estimated $7 billion each year in safety-related
activities. Approximately half of this money is spent in complying with
Federal and state regulations. The other half is spent as part of our
companies' voluntary commitment to ensure that our systems are safe and
that the communities we serve are protected. Moreover, we are
continually refining our safety practices.
A large percentage of our effort over the last several years has
been focused on working with Federal and state regulators in the
development and implementation of rules specific to these and other
legislative mandates that were contained in the 2002 and 2006 PIPES
Acts. I want to assure the Committee that the natural gas distribution
industry has worked vigorously to implement those provisions that
related to our sector. From a regulatory perspective, the past 10 years
have easily included far more significant pipeline safety rulemakings
than any other decade since the creation of the Federal pipeline safety
code in 1971. Highlights include:

Approximately 2.1 million miles of distribution system
piping are covered under the recently promulgated Distribution
Integrity Management regulation;

More than 50,000 miles of transmission pipelines operated by
distribution gas utilities are covered by the Transmission
Integrity Management Program;

An estimated 950,000 excess flow valves have been installed
since June 1, 2008;

25,000 natural gas distribution employees are continually
qualified through testing. The average 30 qualification tests
for each employee results in 750,000 documented qualifications;

Locations of all natural gas transmission and hazardous
liquids pipelines have been added to the Federal National
Pipeline Mapping System;

A pipeline awareness program has been developed and
implemented for almost 1,600 natural gas operators; and

Approximately 1,100 controllers are covered under the
recently promulgated Control Room Management regulation, which
includes requirements to address employee fatigue.

Specifically, there were four core provisions of the PIPES Act of
2006 that are key to enhancing the safety of the distribution pipeline
system--Excavation Damage Prevention, DIMP, Excess Flow Valves (EFV),
and Control Room Management.

Excavation Damage Prevention
Excavation damage represents the single greatest threat to
distribution system safety, reliability and integrity. A number of
initiatives have helped to reduce excavation damage and resulting
incidents. These include a new three digit number, ``811'', that
excavators can use to call before they dig, a nationwide education
program promoting 811, ``best practices'' to reduce excavation damage
and regional ``Common Ground Alliances'' that are focused on preventing
excavation damage. Additionally, AGA and other partners established
April as National Safe Digging Month, encouraging individuals to dial
811 before embarking on any digging or excavation project. Since the
Call 811 campaign was launched, there has been approximately a 40
percent reduction in safety-related incidents. A significant cause for
this reduction is the work done by the pipeline industry in promoting
the use of 811. Regulators, natural gas operators, and other
stakeholders are continually working to improve excavation damage
prevention programs. This concerted effort, combined with the effort
that states are undertaking to create robust, and effective, state
damage prevention programs based on the elements contained in the 2006
PIPES Act, is having a positive impact. But as always, more can be
done--and we will continue to remain vigilant in collaborating with
other stakeholders and the public to ensure the safety of our pipeline
systems.

Distribution Integrity Management
The 2006 PIPES Act required the DOT to establish a regulation
prescribing standards for integrity management programs for
distribution pipeline operators. The DOT published the final rule
establishing natural gas DIMP requirements on December 4, 2009. The
effective date of the rule was February 12, 2010. Operators must
develop a written program and begin implementation of DIMP prior to
August 2, 2011.
The DOT's Pipeline and Hazardous Materials Safety Administration
(PHMSA) previously implemented integrity management regulations for
hazardous liquid and gas transmission pipelines. Because there are
significant differences between gas distribution pipeline systems and
the systems of gas transmission or hazardous liquid operators, it would
have been impractical to apply the existing regulations to distribution
pipelines. The DIMP final rule requires operators to develop and
implement individualized integrity management programs, in addition to
PHMSA's core pipeline safety regulations.
The DIMP final rule is a comprehensive regulation that provides an
added layer of protection to the already-strong pipeline safety
programs in use by local distribution companies. It represents the most
significant rulemaking affecting natural gas distribution operators
since the inception of the Federal pipeline safety code in 1971. It
will impact more than 1,400 operators, 2.1 million miles of piping, and
70 million customers. The final rule effectively takes into
consideration the wide differences that exist between natural gas
distribution operators. It also allows operators to develop a DIMP plan
that is appropriate for the operating characteristics of their
distribution delivery system and the customers that they serve.
The final rule requires that all distribution pipeline operators,
regardless of size, implement an integrity management program that
contains seven key elements:

1. Develop and implement a written integrity management plan.

2. Know its infrastructure.

3. Identify threats, both existing and of potential future
importance.

4. Assess and prioritize risks.

5. Identify and implement appropriate measures to mitigate
risks.

6. Measure performance, monitor results, and evaluate the
effectiveness of its programs, making changes where needed.

7. Periodically report performance measures to its regulator.

Operators are aggressively implementing this rule. Workshops have
been conducted throughout the Nation. Webinars and audio conferences
have been held. Software programs have been developed specifically for
distribution integrity management. The Gas Pipeline Technology
Committee (comprised of Federal and state regulators, pipeline
operators, manufacturers, and the public) has developed a guidance
document to support implementation of the DIMP regulation. I am pleased
to inform the Committee that all affected stakeholders are working to
make this an effective regulation.
As discussed previously, low stress transmission pipelines are
integrated into the gas distribution system. Distribution operators and
state regulators will better manage the integrity of the distribution
system when the TIMP and DIMP regulations are harmonized.

Excess Flow Valves
EFVs are installed by natural gas distribution utilities as one
method to reduce the potential consequences when a service line is
significantly damaged due to the impact of outside forces such as
excavation damage. An EFV is usually installed in the pipe where the
service line originates, near the main. EFVs function similar to a fuse
in an electric panel that closes automatically to eliminate the flow of
gas to the home for large leaks that exceed the EFV's closure flow
rate. EFVs are not designed to shut off the flow of gas if a line break
occurs on the customer's side of the gas meter. The device will not
work properly for the low pressure and gas volumes in a customer's
interior or exterior piping system that connects gas appliances. EFVs
also cannot distinguish small gas leaks from changing gas loads.
Instead, they help mitigate the potential consequences for events that
could have a high rate, high volume gas release. These are the types of
events that occur during excavation damage.
Natural gas utilities have been installing EFVs widely on single
family residence service lines since the late 1990s, when operators
were given the option of either installing them voluntarily or
notifying customers of their availability, and then installing them
upon request. The 2006 PIPES Act mandated that DOT require natural gas
distribution utilities install an EFV on new and replacement service
lines for single family residences, if the service line met specific
conditions, beginning on June 1, 2008.
AGA supported the 2006 Congressional mandate for EFVs. Indeed,
operators were voluntarily installing EFVs before the June 2008
Congressional deadline. The DIMP final rule codified the congressional
mandate to install EFVs in services to single-family residences. I do
want to emphasize that Congress was absolutely correct in limiting the
EFV mandate to single-family residential dwellings. Single family
residence dwellings are very uniform and only about 15 percent of the
dwellings have problems with EFV installation (e.g., pressure too low,
dirt, or contaminates in the gas).
Due to the inherent uncertainties and complexities associated with
service lines to multiple-family dwellings, commercial and industrial
customers, however, it is inadvisable to attempt mandatory nation-wide
installation of EFVs beyond the single-family residential class. Multi-
family dwellings, commercial, and industrial customers are subject to
significant variations in gas loads. Since EFVs are designed to shut
down when there is a significant change in gas flow, these variations
could result in the inadvertent closure of an EFV and interruption of
gas service for multiple days. An inadvertent EFV shutoff of commercial
and industrial facilities, like hospitals or chemical plants, could
create greater safety hazards than the release of gas the EFV was
attempting to prevent.

Control Room Management
In December 2009, DOT promulgated the final regulation for Pipeline
Control Room Management, requiring pipeline operators to develop,
implement and submit a human factors management plan designed to reduce
risks associated with human factors for employees working in a pipeline
control room. As a part of their plan, pipeline operators must address
fatigue and establish a maximum limit on the number of hours worked by
pipeline controllers.
AGA commends DOT for putting forth a final rule that enhances
safety and is practical, reasonable, and cost-effective. Similarly to
the DIMP, the rule takes into consideration the inherent differences
that exist between natural gas pipeline operators and hazardous liquids
pipeline operators. There has never been a documented accident that has
been directly caused by the controller of a natural gas pipeline. Yet,
AGA and its members are supportive of the regulation and are active in
working to develop national standards that identify recommended
practices for pipeline operators to consider in developing their plan.
The final rule actually goes beyond the Congressional mandate in the
area of controller fatigue by requiring operators to:

Establish shift lengths and schedule rotations that provide
controllers off-duty time sufficient to achieve 8 hours of
continuous sleep;

Educate controllers and supervisors in fatigue mitigation
strategies and how off-duty activities contribute to fatigue;
and

Train controllers and supervisors to recognize the effects
of fatigue.

The National Transportation Safety Board (NTSB) has expressed its
support of the new regulation by closing its recommendation for
pipeline operators to address fatigue. On February 18, 2010, the NTSB
issued a press release that stated: ``The Board was pleased to report
that the Pipeline and Hazardous Materials Safety Administration has
published a final rule establishing new bases for managing fatigue in
the pipeline industry.'' The Board called the rule ``a significant step
forward for an industry that did not previously have any rules
governing hours of service.'' The Board, therefore, closed the
recommendation ``Acceptable Alternate Action'' and has removed fatigue
in the pipeline industry from its ``Most Wanted'' list.

Public Awareness Programs
Beyond the significant requirements of the 2006 PIPES Act, the
PIPES Act of 2002 directed DOT to put in place standards and criteria
to improve public awareness of pipeline operations. Beginning June 20,
2005, the DOT required all pipeline operators to develop and implement
public awareness programs based on the American Petroleum Institute
(API) Recommended Practice (RP) 1162, ``Public Awareness Programs for
Pipeline Operators.''
AGA applauds the DOT for working with the public, emergency
responders, and industry to improve the public's awareness of
pipelines. AGA's position is that the public awareness initiative has
been successful and has effectively improved the public's awareness of
the pipeline infrastructure and appropriate actions to be taken in the
event of a pipeline emergency. API RP 1162 was developed by a joint
stakeholder task group that included state and Federal safety
regulators, public representatives, emergency responders, and pipeline
operators. Operators adhered to the 12-step guide outlined by the DOT
to develop public awareness programs. Operators are required to assess
their public awareness programs for effectiveness and to identify
opportunities for program improvement. These evaluations are required
on a four-year interval, so operators are currently working to meet the
first evaluation deadline of June 2010. During the second half of 2010,
state and Federal pipeline safety inspectors will review the
effectiveness of operators' public awareness programs. Industry looks
forward to working with the DOT to identify performance metrics that
are critical in assessing program effectiveness.
In response to an NTSB recommendation, industry is working to
ensure that 911 operators are identified as an important stakeholder
audience and receive all needed pipeline awareness information. AGA and
the industry look forward to continuing to work with all regulatory
agencies to improve the methods utilized to educate the public
regarding pipeline safety.

Miscellaneous Issues
Low Stress Gas Pipelines
There are some additional regulatory actions that DOT should be
encouraged to take to ensure that the existing statute continues to be
efficiently implemented. Specifically, now that DOT has promulgated the
DIMP regulation, it can modify the assessment requirements for low
stress transmission pipelines operated by natural gas distribution
utilities. Currently, low stress pipelines are covered under the
Transmission Integrity Management Program (TIMP) regulation, which was
promulgated in December 2003 by DOT. However, since low stress
transmission lines operate more like distribution lines, AGA believes
the low stress pipelines are better covered under DIMP. Making this
change would not have an adverse effect on pipeline safety. Rather, we
believe, it would enhance safety by allowing low stress pipelines to be
covered under DIMP which would result in ALL low stress lines being
covered under the robust DIMP regulation, and not just lines within
high consequence areas.
There are fundamental differences between the high stress pipelines
predominately operated by interstate operators--and the low stress
pipelines, which are predominately operated by gas distribution
utilities. A typical high stress interstate transmission pipeline will
operate between 500 pounds per square inch (psi) and 1,000 psi and have
stress levels up to 80 percent Specified Minimum Yield Strength (SMYS).
Whereas, a typical low stress transmission pipeline will operate
anywhere between 150 psi and 400 psi and have stress levels below 30
percent SMYS. Low stress transmission pipelines are usually embedded in
the distribution network operated by utilities and are often very
similar to higher pressure distribution pipelines. Moreover, many
CANNOT be inspected by in-line inspection tools (``smart pigs'')
because of their, small diameters, valves in the line, layouts that
include sharp turns and angles, relatively low operating pressures. DOT
has already started regulatory initiatives to apply traditional
distribution inspection and corrosion prevention techniques to low
stress pipelines in lieu of the rigid TIMP assessments.
DOT has the regulatory authority to manage low stress transmission
pipelines under DIMP. The issue was discussed during reauthorization of
the 2002 Act. Congress anticipated that the pipelines included in TIMP
might change and 42 U.S.C. 60109(c)1 states that DOT would define the
facilities that will be included in TIMP in chapter 192 of title 49,
Code of Federal Regulations, including any subsequent modifications.
DIMP was finalized in December 2009 and AGA believes safety can be
enhanced if DOT harmonizes the requirements in TIMP and DIMP.

High Consequence Areas
There has been some talk of perhaps changing TIMP, by eliminating
the High Consequence Areas (HCA) definition, and requiring operators to
perform TIMP assessments for all 300,000 miles of natural gas
transmission pipelines.
As previously stated, internal instrument (smart pig) inspections
are usually not practical for transmission pipelines operated by
distribution gas utilities, because the pipelines are usually not
piggable. As part of its regulation on TIMP, DOT has already included
provisions for pipeline operators to have an added layer of protection
on the low-stress pipelines outside of HCAs known as Preventive and
Mitigative (P&M) measures in Subpart O of the Federal Pipeline Safety
Code. These P&M measures consist of enhanced protection against the
threats of external and internal corrosion as well as third party
excavation damage.
Finally, there is a long list of regulatory safety requirements
separate from the integrity management assessments that are used to
manage safety for all pipelines inside and outside of HCAs. These
include leak inspections, corrosion control, surveillance and
patrolling, repair criteria, etc. Pipeline operators have upgraded
their mapping systems and are continually collecting population data
for the sole purpose of identifying HCAs that exist on their system so
that they can use the risk-based principles required by the current
TIMP regulation. AGA would strongly discourage making a change to the
TIMP-HCA criteria.

Summary
Many of the mandates within the 2006 PIPES Act have just become
regulation and government and industry are working to implement these
regulations. AGA believes that Congressional passage of pipeline safety
reauthorization this year will send a positive message that the current
law is working, and emphasize the commitment that Congress and all the
industry stakeholders have to securing the safety of the Nation's
pipeline system. We look forward to working with you to secure
reauthorization this year.

Senator Lautenberg. Thanks very much, Mr. D'Alessandro.
Mr. Felt, you're next, please.

STATEMENT OF TIMOTHY C. FELT, PRESIDENT AND CEO,

COLONIAL PIPELINE COMPANY ON BEHALF OF

THE ASSOCIATION OF OIL PIPE LINES (AOPL)

AND THE AMERICAN PETROLEUM INSTITUTE (API)

Mr. Felt. Thank you, Chairman Lautenberg and members of the
Subcommittee. I am Tim Felt, President and CEO of Colonial
Pipeline, and I appreciate the opportunity to appear on behalf
of AOPL and API. Colonial Pipeline operates a 5,500-mile
pipeline system that begins in Houston, crosses the South and
East before terminating at New York harbor. When measured by
volume transported, Colonial is the largest refined products
pipeline in the world, every day delivering about 100 million
gallons of gasoline, diesel fuel, jet fuel, heating oil, and
fuels for the U.S. military.
Pipelines have the best safety record of any transportation
mode and are the most reliable, economical, and environmentally
favorable way to transport oil to refineries and refined
products to the communities where we live. We are proud of our
improved safety record, but we are not content, as we strive
for zero releases.
Pipelines have every incentive to invest in safety. The
consequences of a failure could include injury to our
neighbors, our employees, our community, our contractors, and
the environment. We could also incur costly repairs, cleanups,
litigation, and fines, and in the event of a problem on a
pipeline we may not be able to meet our commitments to our
customers. That breakdown in reliability can have a longer term
impact on our business. The public expects pipelines to be safe
and reliable and we believe we are meeting that expectation.
Our control room operators are trained to respond to an
event on the pipeline by closing valves and quickly shutting
down pumps. Pipeline operators are required to establish
response plans which are submitted to the Office of Pipeline
Safety within the Department of Transportation. We are required
to plan for worst case discharges and to conduct emergency
response drills on worst case scenarios with local responders
to ensure that emergency preparedness is at a continued state
of readiness.
Over the last decade, Congress and OPS have asked more of
pipelines and the industry has done more. Pipelines have spent
billions of dollars on integrity management, far exceeding
earlier estimates. As a result, liquid pipeline spills along
rights of way have decreased over the past decade in both
volume and the number of releases.
Pipeline operators are required to develop integrity
management plans for segments of pipelines that could affect
high consequence areas, those near population centers,
navigable waterways, drinking water intakes, or sensitive
environmental areas. Liquid pipeline operators conducted
baseline assessments to identify potential hazards to their
pipelines and are implementing plans to address those threats.
This includes in-line inspection by smart pigs. Full
reassessments are under way, must be done within 5 years of the
baseline assessments, and are required into the future.
Pipeline operators take additional steps to maintain
integrity of pipelines, which include cathodic protection to
control corrosion, patrols of rights of way to detect or head
off encroachment or damage, and extensive use of computer
systems to monitor the operations of the pipeline.
I want to thank the Congress and this committee for your
prior work on pipeline safety, including establishment of 811
as the national Call Before You Dig Number. Colonial and other
pipelines are supporters of One-Call centers, which serve as a
clearinghouse for excavation activities mentioned in 811 calls.
I am a board member and past chairman of the Common Ground
Alliance, a place where underground utility operators can
partner with government, excavators, and the public to pursue
best practices on damage prevention.
I also want to thank Chairman Lautenberg and this committee
for its work on Senate Resolution 472, which supported the
designation of April as the National Safe Digging Month.
The pipeline industry asks for additional help protecting
pipelines from excavation damage, a leading cause of
significant pipeline incidents. Many states have been improving
their damage prevention programs, but some state damage
prevention laws are incomplete, inadequate, or inadequately
enforced. 41 states allow some exemptions from the One-Call
system for State agencies, municipalities, or local entities.
These exemptions create a gap in enforcement and safety.
We believe OPS is headed in the right direction with its
proposal of last year for Federal enforcement in States with
inadequate programs. We urge OPS to complete this rulemaking
and even require termination of these exemptions by the States
or risk Federal enforcement or loss of grant funds.
Congress has provided OPS a thorough set of tools to
regulate pipeline safety and they are working. We see no reason
for Congress to greatly expand the pipeline safety program or
impose significant new mandates upon the industry. We do
believe Congress should encourage OPS to complete its rule on
damage prevention, disallowing any exemptions to One-Call
requirements and pushing States to improve and enforce State
damage prevention programs.
We look forward to working with Congress, OPS, and other
stakeholders to improve pipeline safety and reauthorize
pipeline safety laws. Thank you.
[The prepared statement of Mr. Felt follows:]

Prepared Statement of Timothy C. Felt, President and CEO, Colonial
Pipeline Company on Behalf of the Association of Oil Pipe Lines (AOPL)
and the American Petroleum Institute (API)

Introduction
I am Tim Felt, President and CEO of Colonial Pipeline Company. I
appreciate this opportunity to appear before the Subcommittee today on
behalf of AOPL and the American Petroleum Institute (API).
Colonial Pipeline is headquartered in suburban Atlanta, Georgia,
from where we operate a pipeline system consisting of 5,519 miles of
pipeline, beginning in Houston and crossing the South and East before
terminating at the New York harbor. When measuring by volume
transported, Colonial is the largest refined products pipeline in the
world, daily delivering about 100 million gallons of gasoline, diesel
fuel, jet fuel, home heating oil and fuels for the U.S. military.
AOPL is an incorporated trade association representing 51 liquid
pipeline transmission companies. API represents over 400 companies
involved in all aspects of the oil and natural gas industry, including
exploration, production, transportation, refining and marketing.
Together, the two organizations represent the operators of 85 percent
of total U.S. oil pipeline mileage in the United States.
I will discuss the industry's commitment to safety, our improved
safety record, and our view that pipeline safety reauthorization should
remain focused on existing programs, specifically damage prevention.

Liquid Pipelines Overview
Pipelines are the safest, most reliable, economical and
environmentally favorable way to transport oil and petroleum products,
other energy liquids, and chemicals, throughout the U.S.
Liquid pipelines bring crude oil to the Nation's refineries and
petroleum products to our communities, including all grades of
gasoline, diesel, jet fuel, home heating oil, kerosene, and propane.
Some of our members transport renewable fuels via pipeline, as well.
Our members transport carbon dioxide to oil and natural gas fields,
where it is used to enhance production. In addition to providing fuels
for the transportation sector (including cars, trucks, trains, ships
and airplanes), we provide hydrocarbon feedstocks for use by many other
industries, including food, pharmaceuticals, plastics, chemicals, and
road construction. America depends on the network of more than 170,000
miles of hazardous liquid pipelines to safely and efficiently move
energy to fuel our Nation's economic engine.
Hazardous liquid pipelines transport more than 17 percent of
freight moved in America, yet pipelines account for only 2 percent of
the country's freight bill. Approximately 2.5 cents of the cost of a
gallon of gasoline to an end-user can be attributed to pipeline
transportation,\1\ resulting in a low and predictable price for
pipeline customers (referred to as ``shippers''). Liquid pipeline
transportation rates are regulated by the Federal Energy Regulatory
Commission (FERC). Rates are generally stable and predictable, and do
not fluctuate with changes in crude oil and gasoline or other fuel
prices. Typically, pipelines only take custody of the product tendered
for transportation and, as such, are unaffected by changes in the price
of commodities being transported.
---------------------------------------------------------------------------
\1\ ``Liquid Transportation Fuels from Coal and Biomass:
Technological Status, Costs, and Environmental Impacts,'' National
Academy of Sciences, 2009.
---------------------------------------------------------------------------
Pipelines are the preferred mode of transportation for crude and
refined products. The approximate share of domestic shipments, measured
in barrels of product moved per mile, is: \2\
---------------------------------------------------------------------------
\2\ Association of Oil Pipe Lines, Shifts in Petroleum
Transportation, 2009.

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Pipelines--68 percent

Water Carriers--25 percent

Trucks--4 percent

Rail--3 percent

Our industry had a wake-up call after the Bellingham, Washington
fatalities in 1999. Congress and the Office of Pipeline Safety asked
more of pipelines, and industry has done more. As a result of
enhancements to pipeline safety laws, implementing regulations, and
vigorous industry efforts, liquid pipeline spills along rights-of-way
have decreased over the past decade, in terms of both the number of
spills and the volume of product released per 1,000 barrel-miles \3\
transported.
---------------------------------------------------------------------------
\3\ One barrel mile equals one barrel (or 42 gallons) transported
one mile.
---------------------------------------------------------------------------
In addition to its record of fewest releases, pipeline
transportation enjoys the lowest input energy requirement and carbon
footprint as compared to other transportation modes (barge, truck,
rail, and marine). Replacing a medium-sized pipeline that transports
150,000 barrels of gasoline a day would require operating more than 750
trucks or a 225-car train every day. Use of trucks or trains would
increase mobile source greenhouse gas emissions, wear and tear on our
transportation infrastructure, road congestion, and the number and
volume of releases.

Pipeline Operators Insist on Safety
Pipelines have every incentive to invest in safety. Indeed, in our
members' view, there are no incentives to cut corners on pipeline
safety. Most important is the potential for injury or loss of life to
members of the public and our employees and contractors. If a pipeline
experiences a failure or a release, there are numerous consequences for
the operator. We could also incur potentially costly repairs, cleanup,
litigation, and fines. Next, the pipeline may not be able to
accommodate our customers. Finally, the pipeline company's reputation
could be hurt.
Operators of liquid pipelines invest millions of dollars annually
to maintain their pipelines and comply with Federal pipeline safety
laws and regulations. Liquid pipeline assets are inspected regularly
and monitored continuously, using a combination of practices. Pipeline
operators continually seek to reduce the risk of accidental releases by
taking measures to minimize the probability and severity of incidents.
These measures include proper pipeline route selection, design,
construction, operation, and maintenance, as well as comprehensive
public awareness and excavation damage prevention programs.
The frequency of releases from liquid pipelines decreased from 2
incidents per thousand miles in 1999-2001 to 0.7 incidents per thousand
miles in 2006-2008, a decline of 63 percent. Similarly, the number of
barrels released per 1,000 miles decreased from 629 in 1999-2001 to 330
in 2006-2008, a decline of 48 percent. The industry is proud of this
record, but continues to strive for zero releases, zero injuries, zero
fatalities and no operational interruptions.
On many pipelines, operators also seek to minimize the consequences
of a release through the use of automated systems that detect releases
or other abnormal operating conditions and quickly shut off product
flow to isolate the incident. Pipeline operators are required to put
response plans in place, under the 1990 Oil Pollution Act. These plans
are submitted to and reviewed by the Office of Pipeline Safety (OPS)
within the Department of Transportation (DOT). Operators must change
their plans and notify OPS within 30 days if any operational situation
arises that would impact response efforts. Pipeline operators are
required to conduct emergency response drills on worst-case discharges,
and conduct exercises in cooperation with local first responders to
ensure that emergency preparedness and planning is at a continued state
of readiness. These response drills are conducted under the National
Preparedness for Response Plan (PREP) guidelines issued jointly with
OPS, the Environmental Protection Agency (EPA), and the U.S. Coast
Guard. Our operators are trained on all elements of PREP guidelines and
they are required to conduct equipment deployment drills and are
subject to random full drills conducted by OPS.
In 1998, the U.S. oil pipeline industry launched an Environmental
and Safety Initiative (ESI) to make further improvements in spill and
accident prevention. The ESI promotes inter-company learning, improves
pipeline operations and integrity, and provides opportunities for
information sharing. An important part of the ESI is the liquid
pipeline industry's voluntary reporting system, the Pipeline
Performance Tracking System (PPTS), which tracks spills and allows
operators to learn from industry data. Another key element of the ESI
is the Performance Excellence Team (PET), which seeks to promote inter-
company learning to improve pipeline operations and integrity, and
provides methods and opportunities for information sharing.

Pipeline Safety Laws and Regulations
In 1979, Congress enacted comprehensive safety legislation
governing the transportation of liquids by pipeline in the Hazardous
Liquids Pipeline Safety Act of 1979 (HLPSA, 49 U.S.C. 2001). HLPSA
added to previous laws and regulations and expanded the existing
statutory authority for safety regulation. Since then, several new laws
have been passed to govern the liquids pipeline industry, including:
the Pipeline Safety Act (PSA) of 1994, the Pipeline Safety Improvement
Act of 2002 (PSA), and the Pipeline Inspection Protection, Enforcement,
and Safety Act of 2006 (PIPES).
Pipeline safety is closely regulated by the Pipeline and Hazardous
Materials Safety Administration (PHMSA) which includes OPS. PHMSA's OPS
is responsible for establishing and enforcing regulations to assure the
safety of liquid pipelines (Title 49 CFR Parts 190-199). OPS sets
prescriptive performance-based regulations and standards that are
intended to address the dynamic nature of pipeline operations.

Integrity Management
Most pipeline operators are required under Federal regulations
(Title 49 CFR, Part 195.450 and 452) to develop an Integrity Management
Plan (IMP), for pipelines that could affect High Consequence Areas
(HCAs). HCAs for liquid pipelines include any of the following:

Population centers, urbanized areas, or areas with large
population density;

Commercially navigable waters; and

Unusually sensitive areas such as water supplies and
ecological reserves.

Pipeline operators are required in their IMPs to identify segments
that could impact HCAs, conduct periodic integrity assessments on those
segments at intervals not to exceed 5 years, and review assessment
results to make mitigation and repair decisions. A risk-based approach
establishes the appropriate assessment interval within the five-year
period. When identifying segments which could affect HCAs, operators
conduct risk assessments and consider local topographical
characteristics, operational and design characteristics of a pipeline,
and the properties of transported commodities in determining potential
impacts of an incident.
In their IMPs, all operators conduct a baseline assessment that
identifies threats to the pipeline and subsequently apply technologies
to mitigate each threat. These baseline assessments also set a point of
comparison for subsequent assessments so that operators may gauge the
impact of time-dependent threats, like corrosion. Liquid pipeline
baseline assessments for pipelines that could affect HCAs were
completed for existing pipelines by March 2008.
Assessments include in-line inspection by ``smart pigs'', which
detect features in the pipe that need to be addressed, such as
corrosion, pipeline deformation, cracking and others. This technology
includes sensitive internal detection devices, such as magnetic flux
leakage tools (MFL) and ultrasonic testing, to examine pipeline wall
thickness and detect other anomalies. Another assessment method used by
pipeline operators is pressure-testing. Many operators use these same
techniques beyond pipeline segments which could affect HCAs.
Diagram of a Smart Pig

Pipeline companies perform visual inspections along rights-of-way,
including from the air, for signs of damage, leakage, and encroachment.
Pipeline controllers are also trained to identify signs of leaks and
respond quickly to shut off pipeline flow, contact first responders
(company and local government emergency response), and government
officials.
Pipeline automation and supervisory control and data acquisition
(SCADA) systems use various techniques to monitor for pipeline leaks.
Software monitors pipeline pressure instruments and volumetric metering
equipment and uses algorithms to search the data for a signal that may
indicate a leak on the pipeline.
In some cases, an operator will install check valves, which
automatically prevent backflow into a pipeline during a shutdown, or
remote control valves that can be monitored with SCADA systems from a
control room and closed if an accident occurs. These valves must be
installed if an operator determines they are needed to protect an HCA
in the event of a release.\5\ Special attention is given to waterway
crossings. It is common practice to locate block valves on each side of
a waterway.
---------------------------------------------------------------------------
\5\ 49 CFR Part 195.452.
---------------------------------------------------------------------------
There are two ways in which pipe is protected from external
corrosion: through the use of coatings and by impressed current that
makes a pipe act as a cathode. Since corrosion is an electro-chemical
process, this electrical charge inhibits corrosion even if the
protective coating has been damaged. A protective coating is applied to
steel pipe at the pipe mill to help prevent corrosion when placed into
service. During the pipeline construction process, construction crews
apply protective coatings to joints to safeguard the outside surface of
pipeline girth welds from corrosion.

Costs of Integrity Management Programs
Liquid pipelines have implemented comprehensive programs to ensure
compliance with PHMSA's IMP regulations, and have incurred significant
costs associated with these activities. It was estimated by DOT before
implementation that the liquid pipeline industry would spend
approximately $279.5 million from 2001-2007 to comply with the IMP
regulations.\6\ However, industry experience demonstrates that the
actual costs far exceed DOT's early projection.
---------------------------------------------------------------------------
\6\ Five Year Review of Oil Pricing Index, FERC Stats and Regs
(Order), 71 Fed. Reg. 15,329, 15,331 (March 28, 2006).
---------------------------------------------------------------------------
Data from a subset of the industry illustrates the extent of these
integrity-related costs. Lines representing less than 15 percent of the
total DOT-regulated pipeline mileage, including systems that transport
refined products, crude oil, and natural gas liquids, estimate
expenditures in excess of $1 billion on required pipeline integrity
management activities in the years from 2005 through 2009. In other
words, in just the past 5 years these pipelines alone exceeded by
nearly four times DOT's estimated cost for the total industry for the
period 2001-2007. These figures, moreover, do not include integrity
costs associated with DOT-regulated storage tanks, which would add
substantially to the total. With finite resources, pipeline operators
need to be able to rank risk and consequence, and apply resources
accordingly. Pipeline operators should not be required to treat every
mile of pipe with the same level of oversight.
It is important to note that as integrity management tools become
more sophisticated, they are more effective at identifying issues for
pipeline operators to consider. As a result, integrity management
compliance costs have trended upward since implementation of the IMP
regulations, a trend that the industry expects to continue in the
coming years.

Damage Prevention and One-Call
Excavation damage to pipelines is less frequent today, but often
results in extremely high consequences. Incidents from excavation
damage by third parties accounted for only 7 percent of release
incidents from 1999 to 2008. However, 31 percent of all significant
incidents (those that result in spills of 50 barrels or more, fire,
explosion, evacuation, injury or death) come from excavation damage by
third parties. Further, at an even higher frequency, pipelines suffer
damages from third parties that are not severe enough to cause a
release at the time of excavation.
To protect communities, sensitive environmental areas, as well as
the pipeline itself, the pipeline industry and other operators of
underground facilities joined together to create notification centers
that are used by those preparing to conduct excavation close to
underground facilities. These centers--called One-Call Centers--serve
as the clearinghouse for excavation activities that are planned close
to pipelines and other underground utilities. Established by Federal
law in 2007, 811 is the national ``call-before-you-dig'' number which
informs operators, homeowners, and excavators about the location of
underground utilities before they dig to prevent unintentional damage
to underground infrastructure, including pipelines.
When calling 811 from anywhere in the country, a call is routed to
the local One-Call Center. Local One-Call Center operators discern the
location of the proposed excavation and route information about the
proposed excavation to affected infrastructure companies. Under One-
Call regulations, excavators must wait a specified amount of time
before beginning any excavation project, to allow operators of
underground infrastructure time to locate and mark underground
infrastructure to protect it from excavation-related damage.
In addition, pipeline operators, associations, state regulators and
Federal and state agencies take part in the Common Ground Alliance
(CGA), an association that promotes effective damage prevention
practices for all underground utility industry stakeholders to ensure
public safety, environmental protection, public awareness and education
to guard against excavation damage. Membership in CGA spans 1,400
members and sponsors, demonstrating that damage prevention is
everyone's responsibility. Industry has worked closely with CGA to
develop best practices and participates fully in its damage prevention
programs, including the establishment and implementation of 811.

The Need for Improved Damage Prevention Enforcement
We believe more must be done to encourage adherence to state damage
prevention laws and strengthen state and national programs already in
place. We recognize and support the role of the states in preventing
damage to pipelines. However, in some cases, state excavation damage
prevention laws are weak or incomplete, or are not adequately enforced.
On October 29, 2009, OPS issued an Advance Notice of Proposed
Rulemaking (ANPRM) regarding how it will exert its authority to enforce
excavation damage prevention laws in states with inadequate damage
prevention programs. API and AOPL submitted comments that supported OPS
enforcement in states with inadequate excavation damage prevention
programs and reinforced that OPS should not exert its authority in
states with strong programs. OPS is headed in the right direction on
this important issue. While supporting the ANRPM, we suggested some
important changes to the proposed rule. We urge OPS to complete this
rulemaking expeditiously. AOPL and API support more aggressive
enforcement, recognizing it will apply equally to pipeline operators
should they fail to adhere to excavation damage prevention laws.
In many states, state agencies, municipalities and other local
entities are exempted from requirements to use the One-Call system
before they undertake excavation activities. These exemptions create a
gap in enforcement and safety, because the threat of pipeline damage is
the same regardless of who the excavator is or who he works for. This
is of heightened importance now with the expected increase of
infrastructure development, especially road building, resulting from
recent stimulus funding.
Under the proposed rule, OPS would assess a state's damage
prevention program and make the determinations of adequacy or
inadequacy called for by Congress. We believe OPS should promulgate a
final rule that prohibits state programs from being determined
``adequate'' if they allow One-Call exemptions for state agencies,
municipalities, and other commercial excavators.
As AOPL and API commented in the rulemaking,\7\ we recommended that
as a minimum requirement in a state damage prevention program, all
excavators, including state agencies and municipalities:
---------------------------------------------------------------------------
\7\ December 14, 2009 letter to Jeffrey D. Wiese regarding 74 FR
55797 (October 29, 2009).

---------------------------------------------------------------------------
(1) use state One-Call systems prior to excavation;

(2) follow location information or markings established by
pipeline operators;

(3) report all excavation damage to pipeline operators; and

(4) immediately notify emergency responders when excavation
damage results in a release of pipeline products.

Section 2 of the Pipeline Safety Inspection, Protection, and
Enforcement (PIPES) Act of 2006 granted OPS the authority to grant
funds for damage prevention programs to states adhering to the nine
damage prevention principles included in the bill. The Secretary is to
``take into consideration the commitment of each State to ensuring the
effectiveness of its damage prevention program, including legislative
and regulatory actions taken by the state.'' Such grants are limited
and are not enough to incentivize strong state damage prevention
programs. Nevertheless, we believe OPS should withhold damage
prevention grant funds from states whose programs do not meet the
fundamental minimum requirements we suggested.

PIPES Act Implementation
The PIPES Act of 2006 directed both DOT and the liquids pipeline
industry to comply with several new and significant safety mandates.
Below are several noteworthy provisions of the PIPES Act that have been
implemented, or are in the implementation process:

Damage prevention enforcement--Section 2 of the PIPES Act
granted OPS limited authority to enforce damage prevention laws
in states which do not have qualified state damage prevention
programs. It also established civil penalties applicable to
excavators and individuals that fail to use an available One-
Call system, ignore markings, or operate without reasonable
care. As previously mentioned, OPS issued an ANPRM on October
29, 2009, outlining and collecting input on where and how it
might exercise its authority to enforce damage prevention laws
in states. AOPL and API provided comments and recommended that
OPS move forward with a final rule to promote more effective
and streamlined damage prevention rules that will promote
safety and respect for pipelines. Finally, OPS has exercised
its authority to award state damage prevention grants,
promoting stronger state damage prevention programs.

Control room management (CRM)--Section 12 in the PIPES Act
required OPS to promulgate regulations requiring pipeline
operators to develop a control room management plan. A final
rule was published on December 9, 2009, that requires operators
to define the roles and responsibilities of controllers and
provide them with the necessary information, training, and
processes to fulfill their responsibilities. Operators must
include in their plans how they will address controller fatigue
and length of work shifts. It further requires operators to
manage SCADA alarms, assure control room considerations are
taken into account when changing pipeline equipment or
configurations, and review reportable incidents or accidents to
determine whether control room actions contributed to the
event. As a result of this regulation, the National
Transportation Safety Board (NTSB) removed the issue of
pipeline controller fatigue from its Federal Most Wanted List
of Transportation Safety Improvement. The liquid pipeline
industry supports the implementation of the CRM rule, but we
hope to resolve on-going issues with OPS's definition of
``controllers'' and ``control rooms'' in upcoming workshops. If
an overly broad definition is applied, it will cause
significant operational problems for pipeline operators.

Accident reporting requirements--OPS implemented new
accident reporting requirements that address whether control
room personnel are involved in and contribute to an accident.

Regulatory exemption eliminated for low stress pipelines--
Section 4 of the PIPES Act required a new rule to remove
exemptions for rural low-stress lines, which operate at less
than 20 percent of their specified minimum yield strength
(SMYS). On June 3, 2008, OPS issued regulations for rural low-
stress pipelines of 8 5/8'' diameter or more within \1/2\ mile
of an Unusually Sensitive Area. All rural low-stress lines are
required to submit an annual infrastructure report under this
rule, as well. Generally, we believe this was the right
approach. The liquid pipeline industry will review and provide
comments to PHMSA on the recent Notice of Proposed Rulemaking
(NPRM) \8\ that would apply Part 195 requirements to all rural
low-stress lines not included in the phase one rule.
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\8\ 75 Fed. Reg. 35366; June 22, 2010.
---------------------------------------------------------------------------
Pipeline Safety Reauthorization
AOPL and API believe OPS is doing a responsible job with the
authorities granted in the PIPES Act of 2006 and previous statutes. The
results of these programs should be assessed thoroughly before Congress
imposes new mandates. The results of the PIPES Act improvements may not
be fully apparent for several years. Making additional changes before
the programs mandated by the PIPES Act of 2006 have come into full
effect is premature and could dilute the efforts of OPS and the
industry.
If Congress chooses to make changes to the existing pipeline safety
program in pipeline safety reauthorization legislation, AOPL and API
believe any such changes should be focused on addressing existing OPS
programs. We also suggest the reauthorization should be for a longer
period than 4 years, in order to provide more predictability and
stability for the pipeline safety program and the industry that must
implement it. The PIPES Act and previous legislative efforts have given
OPS a thorough set of tools and authorities to effectively regulate
liquid pipelines. There is no reason for Congress to greatly expand the
pipeline safety program or impose significant new mandates upon OPS or
the industry in a new reauthorization bill.
We do believe OPS should move quickly to improve excavation damage
prevention programs in the states, and, most importantly, should remove
exemptions for state and municipal governments from One-Call
requirements. Such exemptions create unnecessary opportunities for
third-party damage to pipelines. AOPL and API believe Congress should
encourage OPS to move forward to issue a final rule on damage
prevention based on the October 2009 ANPRM, disallowing any exemptions
to One-Call requirements.
We look forward to working with Congress, OPS and other
stakeholders to improve pipeline safety and reauthorize the pipeline
safety laws.
I am happy to respond to any questions.

Senator Lautenberg. Thanks very much, Mr. Felt.
Mr. Sypolt, CEO of Dominion Energy and representing the
Interstate Natural Gas Association of America, correct?

STATEMENT OF GARY L. SYPOLT, CEO, DOMINION ENERGY ON BEHALF OF
THE INTERSTATE NATURAL GAS ASSOCIATION OF AMERICA

Mr. Sypolt. Correct.
Senator Lautenberg. Please proceed, Mr. Sypolt.
Mr. Sypolt. Chairman Lautenberg, members of the
Subcommittee: Thank you for inviting me to testify today on the
pipeline of the Nation's energy safety network. I am Gary
Sypolt, CEO of Dominion Energy. Dominion is one of the Nation's
largest producers and transporters of energy, with a portfolio
of more than 27,500 megawatts of power generation, 12,000 miles
of natural gas transmission, gathering, and storage pipeline,
and 6,000 miles of electric transmission lines.
Today I am testifying on behalf of the Interstate Natural
Gas Association of America, or INGAA, which represents the
interstate natural gas pipeline industry in North America.
INGAA's members transport the vast majority of the natural gas
consumed in the U.S. through a network of about 220,000 miles
of large-diameter pipeline. These transmission pipelines are
analagous to the interstate highway system. In other words,
these are high-capacity transportation systems spanning
multiple states or regions.
Natural gas is increasingly being discussed in the context
of the climate change debate as a partner with renewables in
reducing overall emissions from the power and transportation
sectors. Many of you might also have heard about the recent
boom in new domestic natural gas supply development,
particularly from shale deposits. Our industry continues to
expand at impressive levels due to the growth in both natural
gas supply and demand.
As we expand, though, the natural gas pipeline network is
touching more and more people, and these people want to be
assured that this infrastructure is safe and reliable. In other
words, safety is and always will be our industry's main focus.
By all measures, natural gas transmission pipelines are
safe, but our safety record is not perfect. Accidents have
happened and our job is to continuously improve our
technologies and processes so that the number of accidents
continues to decline.
My written testimony highlights some of the statistics with
respect to accidents in the natural gas transmission sector.
The main point I would like to make is that our primary focus
has been on protecting people and as a result the number of
fatalities and injuries associated with our pipelines is low.
We want it to be even lower.
One of the main programs that industry has implemented over
the last decade has been the integrity management program, or
IMP. This program, which was mandated by Congress in 2002,
requires natural gas transmission pipelines to: one, identify
all segments located in populated areas, called high
consequence areas; two, undertake assessments or inspections of
those segments within 10 years; three, remediate any problems
uncovered, including precursors to future problems; and four,
undertake reassessments every 7 years thereafter.
We are far along in this process. In fact, we have already
started to perform reassessments as we are finishing baseline
work. My written testimony includes some data on the results of
the work done thus far.
There are two important take-aways from this work that I
would like to share with the Subcommittee. First, the data
strongly suggests that on reassessments the number of
precursors to corrosion we are finding are significantly lower
than those found in baseline assessments. Since corrosion is a
time-dependent phenomenon that occurs over a fairly predictable
timeframe, these periodic reassessments are able to catch
corrosion precursors before they manifest themselves into
failures.
The other take-away is that the technology for conducting
these assessments, primarily internal inspection devices known
as smart pigs, continues to develop and improve over time. A
new generation of these devices is currently employed and is
giving us a more granular view of the conditions of our
pipeline system.
The last 4 years have also seen several additional
improvements in pipeline safety. My written testimony includes
a discussion of the safety initiatives that have been completed
in recent years.
This leads me to one of my main points. The pipeline safety
program, at least with respect to natural gas transmission
pipelines, is working well to reduce accidents and to protect
the public. PHMSA has the authority it needs to improve
standards over time. INGA believes that, given this level of
performance and in addition the short amount of time remaining
in this Congress, a simple reauthorization of the Pipeline
Safety Act is the logical step for Congress to make. We support
a straightforward reauthorization that leaves the current
programs in place and pledge to work with you in enacting such
a bill.
However, if you choose to pursue a broader bill we offer
the three following suggestions: One, damage prevention is
critical in our industry. State One-Call programs are critical
to avoiding accidents and preventing fatalities and injuries.
I'm pleased to say that our home State of Virginia serves as a
model for this Nation. But despite all the progress, some
improvements still need to be made. Two recent accidents in
Texas caused by third party excavation damage demonstrate the
need to make further improvements to state damage prevention
programs. We'd like to work with you in suggesting some
improvements.
Two, as we implement the IMP program it is becoming clear
that the 7-year reassessment requirement mandated by the 2002
reauthorization bill is not necessary. A more informed, risk-
based approach is more logical for determining the appropriate
reassessment period. Both the GAO and PHMSA have recommended
that Congress update this requirement. We support those
recommendations.
Third, we ask that Congress charge the PHMSA with
identifying and retiring legacy regulations that have become
redundant in the new integrity management era.
Mr. Chairman, we are proud of the pipeline improvements
that have been made in the industry over the last decade. We
hope that you agree much has improved. Thank you again for
graciously inviting me to testify today and I will be happy to
take questions at the appropriate time.
[The prepared statement of Mr. Sypolt follows:]

Prepared Statement of Gary L. Sypolt, CEO, Dominion Energy on Behalf of
the Interstate Natural Gas Association of America

Mr. Chairman and members of the Subcommittee:
Good afternoon. My name is Gary Sypolt, and I am CEO of Dominion
Energy. Dominion Energy is the natural gas-related business unit of
Dominion Resources. Dominion Resources is one of the Nation's largest
producers and transporters of energy, with a portfolio of more than
27,500 megawatts of generation, 12,000 miles of natural gas
transmission, gathering and storage pipeline and 6,000 miles of
electric transmission lines. Dominion operates the Nation's largest
natural gas storage system with 942 billion cubic feet of storage
capacity, and owns and operates the Cove Point liquefied natural gas
facility in Maryland. We also serve retail energy customers in 12
states. Our corporate headquarters are in Richmond, Virginia.
I am testifying today on behalf of 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 the vast majority of the natural gas consumed in the
United States through a network of approximately 220,000 miles of
transmission pipeline. These transmission pipelines are analogous to
the interstate highway system; in other words, these are large capacity
transportation systems spanning multiple states or regions.

Natural Gas
While natural gas has been an important part of the United States
energy supply portfolio for many years, the recent focus on energy
security and controlling emissions of greenhouse gases is making
natural gas even more important to America's energy future. Natural gas
currently provides about 25 percent of the total energy utilized in the
Nation. This includes fueling the generation of about 20 percent of our
electricity and heating the bulk of our homes and businesses. The
clean-burning properties of natural gas make it an attractive resource
for the future as the U.S. looks for ways to reduce carbon and other
emissions. Many experts have advocated natural gas as a logical
``partner'' for renewable power resources, with natural gas providing
reliable electricity when conditions do not permit the operation of
solar and/or wind generation. In addition, natural gas remains a
largely domestic energy resource. The U.S. produces approximately 85
percent of the natural gas consumed domestically; most of the remaining
natural gas supplies are imported from Canada. Only about 2 percent of
our natural gas supply is imported from outside of North America. There
is little doubt that natural gas can fulfill its potential as a long-
term contributor to the U.S. energy future. Natural gas supplies have
grown dramatically in just the last 5 years, and it is estimated that
the U.S. natural gas resource base can supply us for more than 100
years at current consumption levels.

Regulatory Structure of the Interstate Natural Gas Transmission System
Mr. Chairman, I am going to limit my comments to the segment of the
natural gas delivery system represented by INGAA--the interstate
natural gas transmission system. As I mentioned, interstate natural gas
transmission pipelines can be compared to the interstate highway system
and as such, cross state boundaries and have a significant impact on
interstate commerce. Congress recognized the inherently interstate
nature of this commerce by enacting the Natural Gas Act to provide for
Federal economic regulation of interstate pipelines in 1938 and,
shortly thereafter, expanded this Federal role to include siting
authority for such pipelines. This law now is administered by the
Federal Energy Regulatory Commission (FERC).
With regard to pipeline safety, Congress enacted the Natural Gas
Pipeline Safety Act in 1968. This law (as amended) provides for the
exclusive regulation of interstate natural gas and hazardous liquid
pipelines by the Office of Pipeline Safety (OPS) located in the
Pipeline and Hazardous Materials Safety Administration (PHMSA). The
authority to regulate intrastate pipelines is largely delegated to
state pipeline safety agencies.
It is worth noting that with regard to the Nation's interstate
natural gas pipelines, the regulation of economic matters and the
regulation of safety matters have always been handled by two separate
entities. The exclusive safety focus of PHMSA has been an advantage of
the agency. Over the years, some have suggested an expansion of PHMSA's
authority beyond safety matters. Given the importance of the mission,
and the fact that PHMSA has a relatively small staff, we are concerned
about any movement away from safety. INGAA urges Congress and the
Administration to maintain that exclusive safety focus for PHMSA.
Following enactment of the Natural Gas Pipeline Safety Act, OPS
adopted pipeline safety regulations (in 1970) for natural gas
transmission pipelines based on engineering consensus standards
developed by the American Society of Mechanical Engineers. These
engineering consensus standards first were adopted by the industry in
1953 and had been continually updated over the following decades. OPS
established performance measures (e.g., pipeline accident reports,
company activity records and engineering documentation) and initiated a
formal inspection and enforcement program for interstate natural gas
transmission pipeline systems. Conversely, natural gas intrastate or
distribution piping safety guidelines were implemented under similar
pipeline safety regulations and were delegated to the state pipeline
safety agencies. Hazardous liquid pipelines were incorporated into the
OPS regulatory structure in 1984.
The pipeline safety processes of INGAA member companies and the
applicable regulations for natural gas transmission pipelines have
evolved and become more refined over the last 40 years as new
technology has became available, new physical properties have been
identified through engineering and scientific analysis, and societal
expectations have changed. These substantive changes in processes and
regulations have been accomplished through:

Continuing research,

Improved practices and processes,

Revised engineering consensus standards,

New regulatory initiatives,

Focused Congressional actions, and

Improved education and training.

Natural Gas Transmission Pipelines are the Safest Mode of Energy
Transportation
While natural gas transmission pipeline operators will not be
satisfied without continuous safety improvement, the safety record of
our industry compares very well to other modes of transportation and
energy delivery. One way to measure safety performance is to identify
the number of accidents involving a fatality or injury. These are
classified as ``serious'' incidents by OPS. Because natural gas
pipelines are buried and typically are in isolated locations, pipeline
accidents involving fatalities and injuries are very rare.
For example, the chart below (from OPS) sets forth safety
statistics for natural gas transmission pipelines since the last
Pipeline Safety Act reauthorization. This chart first depicts the
categories of fatalities and injuries. It also categorizes property
damage based on whether it is damage to public property or damage to
the pipeline operator's property and the amount of natural gas lost to
the atmosphere during both the accident and the subsequent repair of
the pipeline.

National Gas Transmission Onshore: Consequences Summary Statistics: 2005-2009
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Year Public Industry Public Industry Total Property Damage to Public Damage to Industry Value of Product
------------------------------------------- Fatalities Fatalities Injuries Injuries Damage (C) (D) Property (E) (C) Property (F) (C) Lost (C)
-----------------------------------------------------------------------------------------------------------------------------------------------------
2005 0 0% 0 0% 2 40% 3 60% $214,506,403 $98,072,639 45% $105,375,752 49% $11,058,012 5%
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
2006 1 33% 2 66% 1 33% 2 66% $31,020,029 $2,869,452 9% $20,882,094 67% $7,268,481 23%
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
2007 1 50% 1 50% 1 14% 6 85% $44,562,382 $1,630,991 3% $24,096,641 54% $18,834,750 42%
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
2008 0 0% 0 0% 2 40% 3 60% $111,608,494 $6,643,699 6% $98,424,350 88% $6,540,445 5%
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
2009 0 0% 0 0% 7 63% 4 36% $31,789,417 $2,005,498 6% $25,216,056 79% $4,567,863 14%
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Totals 2 40% 3 60% 13 41% 18 58% $433,486,727 $111,222,281 25% $273,994,894 63% $48,269,552 11%
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

From 2005 to 2009,\1\ there have been two public fatalities due to
natural gas transmission line accidents. One in 2006 involved a
bystander near an incident caused by excavation damage to the pipeline,
and the other in 2007 involved a driver in an automobile near a
pipeline incident caused by corrosion. The three non-public natural gas
transmission pipeline fatalities since 2005 were a third-party
excavator, a pipeline employee and a contractor working for a pipeline
company.
---------------------------------------------------------------------------
\1\ Additional information is available in individual pipeline
incident reports http://www.phmsa.dot.gov/portal/site/PHMSA/
menuitem.ebdc7a8a7e39f2e55cf2031050248a0c/?vgnex
toid=fdd2dfa122a1d110VgnVCM1000009ed07898RCRD&vgnextchannel=3430fb649a2d
c110VgnV
CM1000009ed07898RCRD&vgnextfmt=print.
---------------------------------------------------------------------------
During this same period, 2005 to 2009, there were 13 injuries to
the public. Four of these occurred when citizens were in vehicles that
struck and damaged pipeline facilities. There were also five injuries
to third-party excavators and 13 injuries to either pipeline employees
or contractors working for the pipeline company.
As you can see from the chart, on the average, natural gas
transmission pipeline incidents do not greatly affect public property.
The exception in 2005 primarily was attributable to $85 million of
damage to a power plant adjacent to a pipeline accident. The large
amount of industry property damage in 2005 was related to the Katrina/
Rita hurricane damage in the Gulf Coast region and the large number in
2008 was largely due to a tornado destroying a pipeline compressor
station ($85 million).

Progress Since the Last Reauthorization
Pipeline Integrity Program
Section 14 of the Pipeline Safety Improvement Act of 2002 (PSIA)
mandated an integrity management program for natural gas transmission
pipelines. Specifically, the PSIA requires operators of natural gas
transmission pipelines to: (1) identify all the segments of their
pipelines located in areas where the pipeline is adjacent to
significant population density, known as high consequence areas (HCAs);
(2) develop an integrity management program (IMP) to reduce the risks
to the public in these HCAs; (3) undertake structured baseline
integrity assessments (inspections) of all pipeline segments located in
HCAs, to be completed within 10 years of enactment; (4) develop a
process for repairing any anomalies \2\ found as a result of these
inspections; and (5) reassess these segments of pipeline every 7 years
thereafter in order to verify continued pipe integrity.
---------------------------------------------------------------------------
\2\ An anomaly is defined as a precursor to a possible reportable
incident in the future.
---------------------------------------------------------------------------
The PSIA requires that these integrity inspections be performed
using one of four methods: (1) an inline inspection device,
alternatively called a smart pig; (2) hydrostatic pressure testing
(filling the pipe up 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); or (4) ``other
alternative methods that the Secretary of Transportation determines
would provide an equal or greater level of safety.''
Following such inspections, a pipeline operator is required by the
PHMSA regulations implementing the PSIA to repair all non-innocuous
anomalies and adjust operation and maintenance practices (i.e., apply
additional corrosion protection measures in active corrosion areas to
prevent further corrosion growth) to minimize the probability of
``serious incidents.'' \3\
---------------------------------------------------------------------------
\3\ ``The rule will significantly reduce the likelihood of pipeline
accidents that result in deaths and serious injuries.''; Page 69800,
Federal Register/Vol. 68, No. 240/December 15, 2003.
---------------------------------------------------------------------------
Baseline IMP assessments--the type of work in which our industry
now is engaged--are an effective means of identifying any material or
original construction defects that were not discovered when a pipeline
was built as well as active corrosion problems. Corrosion is an on-
going, time-based phenomenon that is managed and controlled using
integrated technologies and processes (e.g., cathodic protection, pipe
coatings). Internal inspection devices are the predominant means for
performing integrity assessments of natural gas transmission pipelines,
because these are the most versatile and efficient devices for this
inspection process. The other assessment alternatives prescribed by
statute are useful when smart pig technology cannot be effectively
used. A drawback associated with these other alternatives is that they
require a pipeline to cease or significantly curtail natural gas
delivery operations for significant periods of time (e.g., hydrostatic
pressure test) or else require extensive excavation of the pipeline
during every assessment (e.g., direct assessment).
Periodic risk-based reassessments are an effective method for
identifying whether corrosion prevention systems are adequately
preventing this ``time-dependent'' deterioration. While material and
original construction defects are not common, they are for practical
purposes eliminated for the remaining life of the pipeline once they
are identified during a smart pig assessment (or the post-construction
hydrostatic test) and repaired. Recently designed smart pigs can also
effectively identify small dents in the pipeline. These dents may or
may not be precursors for a corrosion failure, depending upon whether
the pipe has been gouged. Sorting through these dents to identify
actual corrosion precursors is a current focus using these updated
smart pig devices.
Based on data from over three quarters of the IMP inspection
baseline period (2002-2009), there is ample basis for concluding that
the integrity of our pipelines is being maintained and that such
pipelines are becoming safer as a result of eliminating the precursors
to possible future accidents. It also is clear that the industry is
dutifully implementing the IMP program prescribed by Congress, since
all INGAA member companies have been subject to in-depth IMP audits by
PHMSA to assure that the programs are comprehensive and implemented
consistently according to Congressional mandates and PHMSA
requirements.
PHMSA has received the reports on IMP progress achieved through the
end of 2009 and the data is presented on the following tables. The
first table depicts the transmission pipelines that have been subject
to an assessment for the first time under the IMP program (baseline).
Let me highlight a particular performance measure. The ``Immediate''
category includes small isolated anomalies (e.g., corrosion, pipe dent
with a gouge) that should be repaired quickly, since these situations
might lead to a leak or pipe rupture within a short period of time. The
``Scheduled'' category addresses individual anomalies (e.g., corrosion)
that should be repaired or reassessed before they grow to the
``Immediate'' category. The bottom row depicts the rate (per mile) of
finding either ``Immediate'' or ``Scheduled'' category anomalies after
decades of operation (e.g., 10-50 years).

----------------------------------------------------------------------------------------------------------------
Number of
Transmission Immediate Number of
Natural Gas Pipeline Miles Total Miles of Category Scheduled
Baseline IMP Data for Gas Onshore Assessed per Number of Pipe Anomalies Category of
Transmission Pipeline Transmission Year Miles of Assessed (failure Anomalies
Integrity Program Miles within Coincidently Pipelines within HCAs precursors) within an
U.S. with the IMP within HCAs per Year within an HCA
program HCA
----------------------------------------------------------------------------------------------------------------
2004 298,207 31,273 21,764 3,997 104 599
----------------------------------------------------------------------------------------------------------------
2005 297,968 19,516 20,561 2,908 261 378
----------------------------------------------------------------------------------------------------------------
2006 293,696 20,250 19,949 3,500 169 342
----------------------------------------------------------------------------------------------------------------
2007 291,898 25,940 19,277 4,661 258 452
----------------------------------------------------------------------------------------------------------------
2008 295,779 20,258 19,568 2,454 146 217
----------------------------------------------------------------------------------------------------------------
2009 (preliminary) 283,975 22,015 18,663 2,269 124 251
----------------------------------------------------------------------------------------------------------------
Cumulative Ba line 139,252 19,789 1,062 2,239
Inspection Results
----------------------------------------------------------------------------------------------------------------
Rate of Anomalies found
(dents & corrosion) in the
Baseline Assessment (per
Mile) .054 .113
----------------------------------------------------------------------------------------------------------------

As these ``Immediate'' and ``Scheduled'' time-dependent precursors
(e.g., anomalies that could possibly grow in size) are remediated and
rendered benign, we expect that the rate of ``Immediate'' and
``Scheduled'' anomalies will decrease with subsequent assessments. This
is because the gestation period of these corrosion anomalies to grow
(if corrosion is active) to failure is significantly longer than either
the present prescriptive seven-year reassessment requirement or the
risk-based reassessment intervals recommended by GAO and consensus
standards organizations (see later discussion).
Since the inception of the IMP program in 2002 through 2009, there
have been no reported significant incidents caused by corrosion to
pipelines within the HCAs that have been assessed.
The next table depicts the results of reassessments that are
occurring concurrently on natural gas transmission pipelines that had
been previously assessed under the IMP baseline program. As with the
baseline assessment, ``Immediate'' and ``Scheduled'' precursors are
identified, assessed to determine if they have changed and then
remediated. As shown in the fourth row, the rate of occurrence of these
corrosion anomalies and dents is significantly reduced from the
baseline assessment.

----------------------------------------------------------------------------------------------------------------
Immediate
Miles of Pipe Re- Categories of Scheduled
Reassessment Data for Gas Transmission Pipeline Assessed within an Anomalies (failure Categories of
Integrity Program HCAs per Year precursors) within Anomalies within
an HCA an HCA
----------------------------------------------------------------------------------------------------------------
2008 348 9 4
----------------------------------------------------------------------------------------------------------------
2009 (preliminary) 903 20 16
----------------------------------------------------------------------------------------------------------------
Cumulative Reasse1,285t Inspection Results29 20
----------------------------------------------------------------------------------------------------------------
Rate of Anomalies (dents & corrosion) found .023 .016
in the Reassessment (per Mile)
----------------------------------------------------------------------------------------------------------------
Rate of Corrosion Anomalies nly) found in .003 .011
the Reassessment (per Mile)
----------------------------------------------------------------------------------------------------------------

In addition, the last row \4\ depicts the low rate of corrosion
anomalies found on the reassessments, the main focus of the IMP
program. It is worth emphasizing that other data obtained from pipeline
operators who have completed multiple integrity assessments over a
number of years, and reviewed by GAO, strongly suggests a dramatic
decrease in the occurrence of time-dependent precursors requiring
repairs in subsequent assessments. This is due to corrective action
being implemented based on prior integrity assessments. Also, technical
analysis \5\ undertaken in 2005 by the Pipeline Research Council
International (PRCI), an international consensus research group,
demonstrated a significant reduction in the number of serious anomalies
found during risk-based reassessments (as compared to baseline
assessments), suggesting that risk-based assessments using smart pig
technology are extremely effective in identifying potential problems
before they manifest themselves into safety problems.
---------------------------------------------------------------------------
\4\ IMP data collected by OPS, enhanced by detailed interviews with
INGAA respondents
\5\ Integrity Management Reinspection Intervals Evaluation,
Pipeline Research Council International, Inc., December 2005.
---------------------------------------------------------------------------
Pipeline Controller Regulation
In 2001, the National Transportation Safety Board (NTSB) issued a
report concerning fatigue among hazardous liquid pipeline controllers.
In response, OPS undertook an effort from 2002 to 2008 to investigate
pipeline control operator fatigue and identify possible solutions.
While the NTSB report did not focus on natural gas transmission
pipeline control room operators, INGAA participated extensively in this
study effort. OPS issued a Notice of Proposed Rulemaking on this matter
in September 2008. During the rulemaking, INGAA proactively worked with
other pipeline trade associations to recommend changes to the proposal
that would reflect the difference of practices and risks between
hazardous liquid, natural gas transmission and natural gas distribution
control operations. Since the rule was finalized in December 2009,
INGAA member companies, working in collaboration with the Southern Gas
Association, have developed an implementation manual for natural gas
transmission and distribution operators. This implementation manual has
been reviewed by OPS and NTSB. In February 2010, the NTSB announced
that it was satisfied that its recommendation on control room personnel
fatigue had been addressed by these actions. As a result, control room
operator fatigue was removed from the NTSB list of ``Most Wanted''
safety improvements.

Improved Incident Data and Transparency
In 2007, INGAA requested that OPS reassess the reporting criteria
for reportable incidents and suggested that incident forms be amended
to facilitate better data analysis of the causes and consequences of
these incidents. For example, the value of natural gas lost from an
incident is included in total property damage numbers. As natural gas
prices increased dramatically over the last 10 years, this metric
caused an increase in reportable incidents since property damage above
a fixed threshold is one trigger for reporting an incident. INGAA
asserted that incident data should not be artificially impacted by
natural gas commodity prices. OPS undertook an effort to modify its
data requirements and the result is an accident reporting form that
more accurately depicts the severity of incidents. We believe this data
will assist the industry, OPS and concerned public assessing the risk
of natural gas transmission pipelines and determining whether modified
practices and procedures are reducing the occurrence of pipeline
accidents.

Allowing Increased Operating Pressure in Specific Transmission
Pipelines
In 2006, several INGAA member companies requested that OPS consider
allowing newer pipelines with improved technologies to operate a higher
operating pressure. The ``safety factors'' for natural gas pipelines
were established in the 1950s and OPS adopted those safety factors in
the original pipeline safety regulations promulgated in the 1970s.
Since then, pipeline technologies and processes have advanced
tremendously (e.g., materials, IMP, smart pigs). The operating pressure
proposed by the pipelines already was part of international engineering
consensus standards, and Canada has utilized these refined criteria
since the 1980s. The United Kingdom adopted these criteria for their
existing pipeline infrastructure in the 1990s after it determined that
this change would result in no effective reduction in the safety. The
U.K. also concluded that these updated criteria would enable more
efficient use of the country's existing infrastructure and thereby
obviate the need to construct additional pipeline capacity (along with
all of the disruption that would cause in such a densely populated
country). Utilizing extensive prior research and international
experience, OPS issued several special permits to allow higher
operating pressures than previously allowed under regulations and to
assess the benefits of additional design, construction, operating and
maintenance requirements imposed as a condition for such permits. This
exploratory work has resulted in a new regulation that will allow
higher operating pressure on new pipelines that meet much stricter
criteria for design, construction, operation and maintenance.

Improved Material and Construction Practices for Natural Gas
Transmission
Pipelines
The natural gas transmission pipeline infrastructure in the U.S.
has expanded significantly in the last decade to meet increased demand
for natural gas and to connect new natural gas supply basins to
consuming markets. This surge in new pipeline construction required
many new material sources, especially steel pipe. At the same time, OPS
adopted more stringent material, construction and inspection regulatory
requirements for projects approved with special permits (allowing
increased operating pressure in specific transmission pipelines) that
exceeded those for comparable pipelines in other nations. The
conjunction of these two events resulted in the unacceptable
performance of a sample of steel pipe in a particular pipeline project
during pre-service integrity testing. INGAA, in cooperation with OPS,
embarked on an unprecedented effort to identify the phenomenon that
caused these pre-service pipe quality issues and to implement processes
and procedures to minimize the occurrence of these events in the
future. All pipelines wishing to operate at higher pressures (under
these new regulatory requirements) have quickly adopted these practices
and procedures. This cooperative process resulted in significantly
faster implementation of solutions than would have occurred under the
traditional engineering consensus standards process or a rulemaking by
the agency.
Concurrently, INGAA has focused on identifying ways to improve the
process for constructing new natural gas transmission pipelines. This
requires a reassessment of the traditional Quality Assurance and
Quality Control (QA/QC) processes and practices in light of changes in
materials, technology, the expectations of industry and regulators. The
same implementation model used in the pipe quality effort is being
utilized to affect change quickly in the construction process.

Incorporation of Safety Culture
INGAA member companies are exploring new avenues for improving
employee and public safety performance. While important, there are
limits on the ability to achieve improvements based solely on
traditional techniques such as training, qualification and increased
inspection. Pipeline workers--whether pipeline employees, contractors
or excavators--must be motivated to make safety a primary focus. There
must be a safety culture. Safety culture has been described as an
inherent attitude toward safety of an individual, whether they are
supervised or not supervised. Our goal is to create and improve this
safety culture.
The U.S. Chemical Safety Board has advocated safety culture as a
constructive means to improve safety performance, and INGAA has
embraced this philosophy. The natural gas transmission pipeline
industry has had an excellent employee safety record over the decades
and we have extended that focus and thought process to encompass work
practices as they impact public safety. We are now in the third year of
implementing this process and have invited our contractor community
(members of the INGAA Foundation, which is affiliated with INGAA) to
adopt the philosophy as well.

Recommendations to Improve the Pipeline Safety Act
The regulatory and process changes referenced in this testimony all
point to a pipeline safety regime that is working well to minimize risk
to the public. INGAA believes that the existing pipeline safety program
has been a success, especially with respect to natural gas transmission
efforts. For this reason, we would endorse a simple reauthorization
bill that reauthorizes the pipeline safety program for 4 years without
any new regulatory programs or mandates. Given the success of the
program over the last 4 years, the expiration of the current
authorization in September, and the short time remaining in this
Congress, a simple reauthorization bill is a logical solution. Still,
should Congress choose to move beyond a simple reauthorization bill, we
would offer the following suggestions, which build on existing efforts
under the law.

Removal of Exclusions from Participating in Excavation Damage
Prevention
Program
The ``serious'' incident data cited earlier in my testimony points
to the importance of damage prevention as an essential means to avoid
fatalities and injuries. The Pipeline Inspection, Protection,
Enforcement, and Safety Act of 2006 (PIPES Act) took an important step
forward by creating incentives for states to adopt improved damage
prevention programs that meet nine critical elements identified in the
Act. This was an important step in raising the performance bar across
the states.
One of the larger issues still existing in some of the State
excavation damage prevention programs is the categorical exclusion of
certain excavators from the notification requirements of state ``one-
call'' systems. These excluded groups often include entities such as
state highway departments (and their contractors), municipal
governments and railroads, who together represent a significant
percentage of excavation activity each year. In order to provide the
public with maximum protection, exemptions from state one-call programs
should be strongly discouraged. We recommend that such one-call
exemptions be a factor that PHMSA must consider when deciding whether
to make annual state pipeline safety grants and one-call grants.
The importance of damage prevention was highlighted in two recent
pipeline accidents in Texas. On June 7, an intrastate natural gas
pipeline near Dallas was struck by utility workers building a power
line, causing one fatality and eight injuries. The next day, another
intrastate natural gas pipeline in the Texas Panhandle was struck by a
bulldozer engaged in construction work, causing two fatalities and one
injury. The Texas Railroad Commission (which regulates these pipelines)
and the National Transportation Safety Board are investigating these
accidents, so the precise causes remain unknown. However, it is clear
that some sort of miscommunication occurred between the excavators and
the pipeline operators. Effective communication is the key, but the
fact that these preventable accidents are still happening means that
more remains to be done. An effective damage prevention effort is about
more than just making the first call; it also means full participation
by all excavators and underground utility operators, accurate and
timely marking of underground utilities when a call is made, and using
due caution when excavating around marked underground utilities. Every
state program should actively be moving toward these goals.

Risk-Based Interval for Reassessments in the Integrity Management
Program
During the last reauthorization, INGAA petitioned Congress to
remove the statutory requirement for mandatory reassessments every 7
years for natural gas transmission pipeline in HCAs. We have previously
provided Congress with the rationale supporting this amendment, along
with detailed technical support and evidence of the concurrence by many
groups including OPS, GAO, international pipeline safety experts and
the American Society of Mechanical Engineers (ASME).
As part of the PIPES Act, Congress directed OPS to present a
recommendation on whether to amend the law governing reassessment
intervals on natural gas transmission pipelines. Deputy Secretary of
Transportation Adm. Thomas Barrett outlined the numerous reasons why
the seven-year requirement should be rescinded in a memo to Congress
dated November 27, 2007. The GAO developed a report \6\ on this issue
as well, stating in 2006:
---------------------------------------------------------------------------
\6\ GAO-06-945, Natural Gas Pipeline Safety: Risk-Based Standards
Should Allow Operators to Better Tailor Reassessments to Pipeline
Threats, September 2006.

To better align reassessments with safety risks, the Congress
should consider amending section 14 of the Pipeline Safety
Improvement Act of 2002 to permit pipeline operators to
reassess their gas transmission pipeline segments at intervals
based on technical data, risk factors, and engineering
analyses. Such a revision would allow PHMSA to establish
maximum reassessment intervals, and to require short
---------------------------------------------------------------------------
reassessment intervals as conditions warrant.

Since then, OPS and the industry have gathered additional
documentation, data and experience that validate the previous request.
We believe a clear statutory mandate from Congress authorizing the
adoption of risk-based intervals would not reduce safety performance,
but would enhance safety through a more efficient and effective
allocation of industry and PHMSA resources.

Review of Legacy PHMSA Regulatory Requirements in Light of New
Technology and Processes
One of the benefits of the IMP was the improvement of pipeline
management practices due to new technology and processes. Much of the
justification of the cost effectiveness of the new IMP regulatory
program was that legacy pipeline safety requirements, such as class
location upgrades, would be superseded by new, more sophisticated
regulations and practices. While the industry has adopted the new, more
sophisticated practices and has documented them in consensus standards,
redundant legacy OPS regulations, such as mandatory class location
upgrades, remain in place. This causes an unnecessary overlap in
procedures to achieve the same safety goals.
INGAA would request that Congress charge PHMSA and consensus
standards organizations such as the ASME with examining whether parts
of the present compendium of pipeline safety regulations have become
redundant in light of changes in technology and processes adopted by
more recent regulations. If the record supports a conclusion that such
legacy requirements are redundant and unnecessary, we ask that such
regulations be rescinded in favor of the new (and more effective)
integrity management requirements.

Conclusion
Mr. Chairman, this subcommittee and the Congress can take pride in
the fact that the pipeline safety efforts embarked upon by you and your
colleagues have improved public safety significantly in the last
decade. An energy delivery system that was, by all measures, already
the safest in the nation, has continued to define new boundaries for
developing a safety culture and reducing risk to the public. Given the
importance of natural gas in America's energy future, the construction
and operation of a safe transportation system for natural gas is
critical. INGAA and its members will not be satisfied without
continuous safety improvement, but we have worked hard in implementing
the Congressional goals articulated in the PIPES Act and in the PSIA.
The safety performance metrics collected by PHMSA from the member
companies of INGAA demonstrate this commitment. This is an effective
safety program, and we hope you agree that any changes should build on
existing programs and successes.
Thank you for holding this hearing and for inviting me to
participate on behalf of INGAA. Please let us know if you have any
additional questions, or need additional information.

Senator Lautenberg. Thank you very much.
Mr. Weimer.

STATEMENT OF CARL WEIMER, EXECUTIVE DIRECTOR, PIPELINE SAFETY
TRUST

Mr. Weimer. Chairman Lautenberg, Ranking Member Thune, and
members of the Subcommittee: Thank you for inviting me to speak
today on the important subject of pipeline safety. My name is
Carl Weimer and I'm the Executive Director of the Pipeline
Safety Trust. The Pipeline Safety Trust is the only nonprofit
organization in the country that strives to provide a voice for
those affected by pipelines. With that in mind, we are here
today to speak for the relatives of the 58 people who have been
killed, the 225 people who have been injured, and for those who
have been burdened by over $900 million in property damage from
pipeline incidents that have occurred since we last spoke to
this committee in November 2006.
We provided many ideas for improvements in our written
testimony, but would like to concentrate on just a few of them
here this afternoon. Our priority for this year's
reauthorization is the expansion of the integrity management
rules to more miles of pipeline. Integrity management has been
one of the most important aspects of both the Pipeline Safety
Improvement Act of 2002 and the PIPES Act of 2006, and it's
what requires that once a pipeline is put in the ground that it
is ever inspected again.
Currently only 44 percent of hazardous liquid pipelines and
only 7 percent of natural gas transmission pipelines fall under
these important integrity management inspection rules. Of all
the deaths caused by these types of pipelines since 2002, over
75 percent of them have occurred on pipelines not required to
meet these rules.
This summer will be the 10-year anniversary of the
Carlsbad, New Mexico, pipeline explosion that killed 12 people.
In response, Congress passed the Pipeline Safety Improvement
Act of 2002, which required integrity management of natural gas
transmission pipelines within certain high consequence areas.
Unfortunately, these areas are still so narrowly defined that
they don't even include the Carlsbad pipeline area where 12
people died. People who live and work near pipelines in more
rural areas interpret this to mean that Congress and PHMSA have
decided their lives are not worth protecting with these same
important integrity management rules.
When integrity management was first conceived, leaders
within Congress and PHMSA stated that in the future these types
of inspection requirements would be expanded. We believe the
future is now and that the industry now has the experience and
the equipment necessary to begin similar inspections on the
over 300,000 miles of pipelines that currently have no such
requirements.
For these reasons, the Trust asks you to direct PHMSA to
initiate a rulemaking to implement a similar integrity
management program on all the pipelines that fall outside of
the current rules.
In the PIPES Act of 2006, Congress made clear its desire
that states move forward with damage prevention programs. We
hope Congress will encourage PHMSA to continue to move forward
with its recent proposed rulemaking regarding damage
prevention. There is also a huge lack of valid data regarding
excavation damage to pipelines that makes it nearly impossible
to implement programs strategically and cost-effectively. We
hope Congress will require PHMSA to ensure there is a valid
mandatory reporting requirement for excavation damage.
After 2 years of work, a multi-stakeholder group of more
than 150 people from around the country, the Pipelines and
Informed Planning Alliance, is about to release a report that
makes recommendations for actions that local government can
take to protect people and pipelines through their land use
regulations when new development is proposed near pipelines.
This effort is a holdover from the 2002 reauthorization and
will implement the recommendations of a Congressionally
mandated Transportation Research Board report.
Such development encroachment near pipelines is a growing
problem nationwide and the Trust asks that this year Congress
authorize $500,000 per year to promote, disseminate, and
provide technical assistance to local governments regarding the
PIPA recommendations so they are actually aware that they
exist.
Finally, there is still a good deal of work to do for PHMSA
to finalize the low-stress pipeline mandates of the PIPES Act
and to institute similar rules for unregulated sections of
natural gas gathering and production pipelines, particularly in
urban areas. Technical assistance grants to communities need to
be authorized and funded so local communities can learn more
about the pipelines in their midst, and industry public
awareness programs need to be upgraded to ensure their
effectiveness, as the NTSB has recently noted in one of their
recommendations.
Congress needs to ensure that PHMSA has the resources
necessary to ensure that the many miles of new pipelines being
constructed are adequately inspected during construction and
that the public and local government is adequately involved in
the review of special permits, spill response plans, and the
designation of high consequence areas.
Thank you again for this opportunity to testify today. We
hope you will consider some of the ideas we have brought
forward, and we'd be glad to answer any questions now or in the
future.
[The prepared statement of Mr. Weimer follows:]

Prepared Statement of Carl Weimer,
Executive Director, Pipeline Safety Trust

Good afternoon, Chairman Lautenberg, Ranking Member Thune and
members of the Subcommittee. Thank you for inviting me to speak today
on the important subject of pipeline safety. My name is Carl Weimer and
I am testifying today as the Executive Director of the Pipeline Safety
Trust. I am also a member of the Pipeline and Hazardous Materials
Safety Administration's (PHMSA) Technical Hazardous Liquid Pipeline
Safety Standard Committee, as well as a member of the steering
committee for PHMSA's Pipelines and Informed Planning Alliance. I also
serve on the Governor-appointed Washington State Citizens Committee on
Pipeline Safety, and bring a local government perspective to these
discussions as an elected member of the Whatcom County Council in
Washington State.
The Pipeline Safety Trust came into being after the 1999 Olympic
Pipe Line tragedy in Bellingham, Washington that left three young
people dead, wiped out every living thing in a beautiful salmon stream,
and caused millions of dollars of economic disruption. After
investigating this tragedy, the U.S. Department of Justice (DOJ)
recognized the need for an independent organization that would provide
informed comment and advice to both pipeline companies and government
regulators, and would provide the public with an independent
clearinghouse of pipeline safety information. The Federal trial court
agreed with the DOJ's recommendation and awarded the Pipeline Safety
Trust $4 million which was used as an initial endowment for the long-
term continuation of the Trust's mission.
The vision of the Pipeline Safety Trust is simple. We believe that
communities should feel safe when pipelines run through them, and trust
that their government is proactively working to prevent pipeline
hazards. We believe that local communities who have the most to lose if
a pipeline fails should be included in discussions of how best to
prevent pipeline failures. And we believe that only when trusted
partnerships between pipeline companies, government, communities, and
safety advocates are formed, will pipelines truly be safer.
We also believe that trust in pipeline safety increases in
proportion to the amount of verifiable scientific information that is
readily available for all concerned to review. For the most part
outside review increases the confidence in pipeline safety as those
with concerns learn that in fact pipelines truly are a safe way to
transport fuels. In those instances when safety has lapsed such review
will help to more quickly correct the situation and create a push for
even greater levels of safety. Consequently, one of the Trust's highest
priorities is to make available as much relevant and accurate
information as possible for independent review.
It is hard to ignore the current disaster in the Gulf of Mexico
when talking about the safety of moving those same fuels by pipeline.
In the past few weeks many people have tried to make a connection
between that disaster and the safety of our onshore pipeline system.
There are certainly many parallel lessons that should be reviewed, but
in many ways PHMSA learned these hard lessons 10 years ago when
pipelines failed in Washington and New Mexico killing 15 people. At
that time PHMSA, then RSPA, was very much like MMS is today--regulation
only when industry approved it, utilizing industry standards even if
they had gaps, very little enforcement, no transparency to the public,
and conflicted in its mission. Fortunately I am happy to report that it
is our opinion that PHMSA learned many of those hard lessons and has
made many significant changes for the better. While there is always
room for improvement, as we will point out today, PHMSA is a very
different agency today than MMS, and people should avoid the temptation
to paint all agencies dealing with oil with the same brush.
The Pipeline Safety Trust is the only non-profit organization in
the country that strives to provide a voice for those affected by
pipelines. With that in mind, we are here today to speak for the
relatives of the 58 people who have been killed by pipeline incidents
since we last spoke to this committee on November 16, 2006. We are
speaking for the 225 people who have been injured, and those who have
been burdened by over $900 million in property damage from pipeline
incidents that have occurred since we were last here 4 years ago.
In my testimony this morning I will cover the following areas that
are still in need of improvement:

Expanding the miles of pipelines that fall under the
Integrity Management rules.

Continuing to push state agencies on damage prevention.

Implementing the Pipelines and Informed Planning Alliance
(PIPA) recommendations.

Correcting the pipeline siting vs. safety disconnect, and
ensuring PHMSA's ability to provide inspections when pipelines
are being constructed.

Continuing implementation and funding of Technical
Assistance Grants to Communities.

Continuing to make more pipeline safety information publicly
available.

Moving forward to address unregulated pipelines and
clarifying regulations of gathering and production pipelines.

Making public awareness programs meaningful and measurable.

Implementing expansion of Excess Flow Valve requirements.

Concerns with industry developed standards being
incorporated into Federal regulations.

Expanding the Miles of Pipelines That Fall under the Integrity
Management Rules
In response to horrific pipeline tragedies, Congress required
integrity management in High Consequence Areas (HCAs) as a way to
protect the people who live, work and play near pipelines, as well to
protect sensitive environmental areas and this Nation's critical energy
infrastructure. Before integrity management, a pipeline company could
install a pipeline transporting huge quantities of often explosive fuel
and leave it uninspected indefinitely--even for 50, 60, or 70 years.
Even today only 7 percent of natural gas transmission pipelines and 44
percent of hazardous liquid pipelines fall under these inspection
programs.
To be blunt, it is not ``safe'' to wait until a pipeline explodes
to learn about its integrity. Consider these examples where people died
when pipelines outside of High Consequence Areas and thereby not
covered by the current integrity management requirements ruptured and
exploded:

An extended family of 12 that was killed when a pipeline
that falls outside of the current integrity management
requirements failed while they were camping at their favorite
fishing hole in New Mexico 10 year ago this summer. Tens years
later this same area is still not protected by the integrity
management program.

Corbin Fawcett who was killed while driving down an
interstate highway north of New Orleans on a beautiful day in
December of 2007 when an natural gas pipeline that falls
outside of the current integrity management requirements
exploded under his car.

Maddie and Naquandra Mitchel, a grandmother and her
granddaughter, who were killed in Mississippi in 2007 trying to
escape from their home when a pipeline that falls outside of
the current integrity management requirements ruptured and
exploded.

The examples are too numerous; in fact, since these rules began to
be implemented in 2001, over 75 percent of all the deaths caused by
these types of pipelines have occurred in areas that fall outside of
the current integrity management requirements. People who live, work or
play near pipelines in a more rural areas interpret this to mean that
Congress and PHMSA have decided their lives are not worth protecting
with these important integrity management rules.
The current concept of requiring integrity management programs only
for pipelines in High Consequence Areas also is not sufficiently
protective of America's economy. Regardless of where a pipeline fails,
there will be a significant economic impact on the downstream markets.
For instance, when the El Paso natural gas pipeline failed in 2000 in a
non-High Consequence Area, the staff of the Federal Energy Regulatory
Commission estimated that the restriction in gas supply cost the people
of California hundreds of millions of dollars. Every time a major
liquid pipeline serving a refinery goes down the price of gasoline in
the region skyrockets until the pipeline can be repaired and supplies
returned to normal. Congress experienced this not too long ago when a
BP pipeline in Alaska failed from corrosion and the American people
paid millions of dollars in higher gas prices. When it comes to
consumer's pocketbooks, and the welfare of the economy, every mile of
pipeline is of high consequence, so every mile should be inspected so
that the American people have reliable and safe pipeline
infrastructure.
The Pipeline Safety Trust believes that limiting integrity
management programs to High Consequence Areas made good sense when
these programs were just starting nearly 10 years ago. At that time
many in the industry had very little experience with these inspection
techniques and knew little about how to categorize and respond to
anomalies found. Furthermore, there was a real shortage of inline
inspection tools and experienced contractors to operate them. Hazardous
liquid pipeline operators have now completed at least one round of
inspections and are well into the second round. Natural gas
transmission operators are approaching completion of their first round
of inspections. It is clear that the industry now has the experience
and infrastructure necessary to move forward with an expansion of
integrity management so that people who live, work and play near all
the pipelines in this country are safe.
Many progressive pipeline operators already apply integrity
management rules to significantly more miles of their pipelines than
required by Federal regulations. These companies do this because they
think it is good business, and we couldn't agree more. Unfortunately
not all companies voluntarily provide these needed safety precautions,
and even those that do are not required to respond to the problems
found as they would be if these areas were covered by the integrity
management rules. It is also important to point out that natural gas
pipeline operators are not even required to report to PHMSA the
problems they find outside of High Consequence Areas. This reporting
needs to be mandated so that PHMSA can have a better understanding of
the safety of this Nation's pipelines.
Since integrity management programs began in 2001, more than 34,000
anomalies found in High Consequence Areas have been repaired based on
integrity management requirements. It is now time to find the thousands
of anomalies on those sections of pipelines that fall outside of these
areas by expanding integrity management to all hazardous liquid and
natural gas transmission pipelines. The American people who live, work,
and play in these uninspected areas deserve these protections.
Implementation of Integrity Management rules have been one of the
most important aspects of both the Pipeline Safety Improvement Act of
2002 and the Pipeline Inspection, Protection, Enforcement and Safety
(PIPES) Act of 2006. The earlier Act focused mainly on transmission
pipelines and the PIPES Act extended Integrity Management to the much
larger realm of distribution pipelines. All of these efforts represent
a significant increase in regulations meant to increase pipeline
safety, and we would like to commend both PHMSA and the industry for
the initial implementation of these programs. It is now time to expand
this important program to all hazardous liquid and natural gas
transmission pipelines.
For these reasons the Trust asks that you direct PHMSA to initiate
a rulemaking by a date certain to implement a similar Integrity
Management program on all the pipelines that fall outside of current
HCAs.

Concerns with Possible Changes to Integrity Management
Since nearly the time integrity management was passed for natural
gas transmission pipelines as part of the Pipeline Safety Improvement
Act of 2002 some within the natural gas industry have lobbied for a
relaxation of the 7-year re-inspection interval that Congress set. The
pipeline Safety Trust opposes any relaxation of this re-inspection
interval for the following reasons:

1. The baseline inspection period has not even been reached
yet, and we believe that it is necessary to go through two or
three re-inspections to determine whether the system is
actually working and if it makes sense to change the re-
inspection interval. Some companies have not even completed one
round of inspections yet. During the first round many anomalies
with the pipelines were identified and repaired. Subsequent
rounds of inspections should tell us how quickly new anomalies
appear and at what rates they are growing. Without that
information from ongoing re-inspections it is too early to
propose changing the re-inspection interval.

2. The industry also argues that Instead of a standard re-
inspection interval that would allow all companies' results to
be compared, each company, based on its own internal findings,
should be allowed to design its own re-inspection program for
each individual segment of its pipelines. This engineered,
risk-based approach may be feasible, but it places much of the
authority to draft the requirements with each company unless
PHMSA has the extensive resources necessary to review each
program to ensure it is no less protective than the current
seven-year re-inspection intervals. We doubt PHMSA has such
resources, and this proposed system also includes no way for
the public to review and comment on the proposed engineered
risk-based re-inspection proposals.

3. There is also increasing mileage of large high pressure
natural gas pipelines in areas with very high density
populations. The consequences if one of these pipelines should
fail in such an area would be catastrophic. Before there is any
consideration to changes in the re-inspection interval for
these types of natural gas pipelines PHMSA should reassess the
safety protocols in place to ensure that it is impossible for a
pipeline to fail in such an area from any cause that is within
the operator's controls (corrosion, materials, operation,
maintenance, inspections, etc.).
For these reasons, we continue to oppose any change to the seven-
year re-inspection interval for natural gas transmission pipelines.
Continuing to Push State Agencies on Damage Prevention
Property owners, contractors, and utility companies digging in the
vicinity of pipelines are still one of the major causes of pipeline
incidents, and for distribution pipelines over the past 5 years
excavation damage is the leading cause of deaths and injuries.
Unfortunately, not all states have implemented needed changes to their
utility damage prevention rules and programs to help counter this
significant threat to pipelines.
In the PIPES Act of 2006 Congress made clear its desire that states
move forward with damage prevention programs by defining the nine
elements that are required to have an effective state damage prevention
program. The Trust is pleased that PHMSA has recently announced its
intent to adopt rules to incorporate these nine elements, and their
intent to evaluate the states progress in complying with them. We also
support PHMSA's plan to exert its own authority to enforce damage
prevention laws in states that won't adopt effective damage prevention
laws. We hope Congress will encourage PHMSA to move forward with this
proposed rulemaking in a timely manner, and make it clear to the states
that Federal money for pipeline safety programs depends upon
significant progress in implementing better damage prevention programs.
It may also be necessary for Congress to clarify important parts of
good damage prevention programs. Many states have exemptions to their
damage prevention ``one-call'' rules for a variety of stakeholders
including municipalities, state transportation departments, railroads,
farmers, and property owners. We believe such exemptions, except in
cases of emergencies, are unwarranted for municipalities, state
transportation departments and the railroads, and urge both Congress
and PHMSA to make it clear that these types of exemptions are not
acceptable in an effective damage prevention program. While we are
skeptical regarding exemptions of any type, limited exemptions for the
farm community and homeowners in specific circumstances may be
necessary to make the programs efficient, affordable and enforceable.
Although PHMSA likes to call itself a data-driven agency, there is
a serious lack of data to determine the extent, causes, or perpetrators
of excavation damage to pipelines. For example, the PHMSA incident
database only includes about 70 total pipeline incidents nationwide in
2008 caused by excavation damage. Yet the Common Ground Alliance's 2008
DIRT database reports well over 60,000 excavation events that affected
the operation of natural gas systems alone.
Why are PHMSA's numbers so low? PHMSA only requires natural gas
pipeline operators to file reports when there is a death,
hospitalization, or over $50,000 of property damage measured in 1984
dollars (about $90,000+ in today's dollars). Industry complaints about
reporting requirements may be part of the reason that reporting
thresholds are so high, but Section 15 of the PIPES Act also required
PHMSA to respond to a GAO report to ensure that ``incident data
gathered accurately reflects incident trends over time,'' which is why
data is normalized to 1984 dollars. While this makes good sense for
tracking property damage, nowhere did GAO or Congress recommend that
thousands of incidents related to excavation damage be left out of the
database thereby creating another data gap making it impossible to
track the larger problem of excavation damage trends over time.
The Common Ground Alliance's database--while more telling--cannot
be relied on for complete and valid data for two reasons: (1) reporting
is voluntary and consequently of a ``hit and miss'' nature; and (2)
reporting is anonymous, making the data not verifiable. Without valid
and complete data it will be impossible to actually measure whether
damage prevention programs are well targeted or effective.
For these reasons, the Trust asks that Congress direct PHMSA to
correct this substantial data gap by ensuring a more accurate reporting
and database for excavation damage to ensure that the effort and money
being spent is well targeted and effective. Because most states have
taken on the responsibility of operating state-based damage prevention
programs it may well be easiest to just have PHMSA require states to
adopt reporting requirements as part of their damage prevention
programs.
One existing example is in Texas where in 2007 Texas adopted
regulations requiring both pipeline operators and excavators to report
excavation damage to pipelines. These reports are submitted directly to
the Texas Railroad Commission's website, and anyone can search the
database for incidents in specific locations, on specific pipelines, by
specific excavators, or for the individual damage report forms. This
system seems to give Texas regulators and involved stakeholders
adequate information to target damage prevention and enforcement
activities, and track improvement over time. More information is
available at: http://www.rrc.state.tx.us/programs/damageprevention/
index.php.
This type of state-based reporting system can go hand-in-hand with
PHMSA's recent Advanced Notice of Proposed Rulemaking about better
defining adequate damage prevention programs. While some consistency
between state reporting requirements may be necessary so state programs
can be adequately evaluated and compared, this ultimately may be an
easier reporting system to institute than either the expansion of
PHMSA's or refining of CGA's.

Implementing the Pipelines and Informed Planning Alliance (PIPA)
Recommendations
Section 11 of the Pipeline Safety Improvement Act of 2002 included
a requirement that PHMSA and FERC provide a study of population
encroachment on and near pipeline rights-of-way. That requirement led
to the Transportation Research Board's (TRB) October 2004 report
Transmission Pipelines and Land Use, which recommended that PHMSA
``develop risk-informed land use guidance for application by
stakeholders.'' PHMSA formed the Pipelines and Informed Planning
Alliance (PIPA) in late 2007 with the intent of drafting a report that
would include specific recommended practices that local governments,
land developers, and others could use to increase safety when
development was to occur near transmission pipelines.
Most large pipelines were placed in rural areas years ago, but as
the populated areas around our cities expand it has led to a growing
encroachment of residential and commercial development near large high-
pressure pipelines. This increases the risk to the pipelines from
related construction activities, as well as to the people who
ultimately live and work nearby if something should go wrong with the
pipeline.
After more than 2 years of work by more than 150 representatives of
a wide range of stakeholders, the draft report and the associated 46
recommendations are finally due to be released sometime this summer.
This will be the first time information of this nature has been made
widely available to local planners, planning commissions, and elected
officials when considering the approval of land uses near transmission
pipelines. We fully agree with the sentiment of Congress in the
Pipeline Safety Improvement Act of 2002 that,

``The Secretary shall encourage Federal agencies and State and
local governments to adopt and implement appropriate practices,
laws, and ordinances, as identified in the report, to address
the risks and hazards associated with encroachment upon
pipeline rights-of-way . . .''

A recent statewide survey of local government planning directors
conducted by the Pipeline Safety Trust showed that to successfully
implement these needed ``practices, laws, and ordinances'' will take a
good deal of well targeted education and promotion by a wide range of
stakeholders outside of the pipeline industry and PHMSA. In order to
make this effort successful, the Trust asks that this year Congress
authorize, just as was authorized in PIPES for the successful promotion
of the 811 ``One-Call'' number, $500,000/year to promote, disseminate,
and provide technical assistance regarding the PIPA recommendations.

Correcting the Pipeline Siting vs. Safety Disconnect, and Ensuring
PHMSA's Ability to Provide Inspections When Pipelines Are Being

Constructed
With thousands of new miles of pipelines in the works, the
disconnect between the agencies that site new pipelines and PHMSA, the
agency that is responsible for the safety of the pipelines once they
are in services, has become quite apparent. While siting agencies go
through supposed comprehensive environmental review processes, these
processes are functionally separate from the special permits or
response plans or high consequence area analyses that are overseen by
PHMSA. Many of the PHMSA determinations go through very limited public
process (special permits), or processes that take place after the
pipeline siting approval is granted (emergency response plans), and
some are totally kept from the public (high consequence areas). How can
local governments and citizens assess the real potential impact of a
pipeline if the environmental review and the safety review processes
are so disconnected?
It also appears that siting agencies such as the Federal Energy
Regulatory Commission, the U.S. State Department, and state agencies
pay little or no attention to the past safety and construction
histories of the companies they are granting permits to. These permits,
which allow the pipeline companies to build new pipelines, also
authorize these companies to condemn people's property.
About a year ago, PHMSA held a special workshop to go over the
numerous problems they found during just 35 inspections of pipelines
under construction. These inspections found significant problems with
the pipe coating, the pipe itself, the welding, the excavation methods,
the testing, etc. PHMSA's findings, and stories we have heard from
people across the country, call into question the current system of
inspections for the construction of new pipelines. This construction
phase is critical for the ongoing safety of these pipelines for years
to come. Since PHMSA has authority over the safety of pipelines once
they are put into service, it makes sense to us that during
construction they also are conducting field inspections and
sufficiently reviewing records to ensure these pipelines are being
constructed properly. Unfortunately, there is a built-in disincentive
for PHMSA to spend the necessary time to ensure proper construction.
Under current rules PHMSA receives no revenue from these companies
until product begins to flow through the pipelines, so any staff time
spent on these pre-operational inspections has to be paid for from
money collected for other purposes from already operational pipelines.
For these reasons, the Pipeline Safety Trust asks that Congress
pass new Cost Recovery fees, similar to those included in Section 17 of
the PIPES act for LNG facility reviews, to allow PHMSA to recoup their
costs related to providing safety information during the review process
for new pipelines and legitimate inspections during the construction
phase without taking resources away from other existing activities.

Continuing the Implementation and Funding of Technical Assistance
Grants to Communities
Over the past year and a half, PHMSA has started the implementation
of the Community Technical Assistance Grant program that was authorized
as part of the Pipeline Safety Improvement Act of 2002 and clarified in
the PIPES Act. Under this program more than a million dollars of grant
money has been awarded to communities across the country that wanted to
hire independent technical advisors so they could learn more about the
pipelines running through and surrounding them, or be valid
participants in various pipeline safety processes.
In the first round of grants, PHMSA funded projects in communities
in seventeen states from California to Florida. Local governments
gained assistance so they could better consider risks when residential
and commercial developments are planned near existing pipelines.
Neighborhood associations gained the ability to hire experts so they
could better understand the ``real'' versus the imagined issues with
pipelines in their neighborhoods. And farm groups learned first-hand
about the impacts of already-built pipelines on other farming
communities so they could be better informed as they participate in the
processes involving the proposed routing of a pipeline through the
lands where they have lived and labored for generations. Overall, we
viewed the implementation of the first round of this new grant program
as a huge success.
Ongoing funding for these grants is not clear, so the Trust asks
that you ensure the reauthorization of these grants to continue to help
involve those most at risk if something goes wrong with a pipeline. We
further ask that you do whatever is necessary to ensure that the
authorized funds are actually appropriated.
One area that should be considered with any new grant program is
the amount of promotion and time it takes to get the word out about new
sources of grant money. The Pipeline Safety Trust worked hard during
the first round to promote this program to ensure that local government
and citizen groups around the country knew about it and applied. Such
targeted promotion, especially for a new grant program, is needed to
ensure that PHMSA receives enough strong grant applications to choose
from. During the application period for the second round of these
grants, promotion was not as well organized and we have since learned
from several groups around the country that they did not apply because
they had no idea the grants were available again. While this will
certainly correct itself as the knowledge of this grant program grows,
we hope that PHMSA continues to provide adequate promotion and that
Congress will take the long-term view of the value of this program
while it grows to maturity.
Finally, we hope that PHMSA will resist the pressure to spend the
money on applications that do not meet the Congressional intent of the
program. While the second round of grants have not yet been announced,
we have heard from some local governments around the country that
municipal gas utilities have tried to apply for these grant funds to
undertake pipeline projects that are clearly part of their existing
pipeline maintenance and operation requirements. Funding municipal
utilities with this community technical assistance grant money is
clearly outside of the intent of what Congress approved this program
for, and will cause a rush by such utilities that will overwhelm this
limited funding. We ask that Congress expressly state--throughout the
reauthorization process and in its final reauthorization legislation--
that this grant program is not to fund the activities of any pipeline
operator, public or private.

Continuing to Make More Pipeline Safety Information Publicly Available
Over the past two reauthorization cycles, PHMSA has done a good job
of providing increased transparency for many aspects of pipeline
safety. In the Trust's opinion, one of the true successes of PIPES has
been the rapid implementation by PHMSA of the enforcement transparency
section of the act. It is now possible for affected communities to log
onto the PHMSA website (http://primis.phmsa.dot.gov/comm/reports/
enforce/Enforcement.html) and review enforcement actions regarding
local pipelines. This transparency should increase the public's trust
that our system of enforcement of pipeline safety regulations is
working adequately or will provide the information necessary for the
public to push for improvements in that system. PHMSA has also
significantly upgraded their incident data availability and accuracy,
and continues to improve their already excellent ``stakeholder
communication'' website.
One area where PHMSA could go even further in transparency would be
a web-based system that would allow public access to basic inspection
information about specific pipelines. An inspection transparency system
would allow the affected public to review when PHMSA and its state
partners inspected particular pipelines, what types of inspections were
performed, what was found, and how any concerns were rectified.
Inspection transparency should increase the public's trust in the
checks and balances in place to make pipelines safe. We have been told
by PHMSA that such a system is in the works. We hope that Congress will
inquire about the design and timeline for implementation of this ``in-
the-works'' system, and if it does not meet the above criteria require
PHMSA to institute an Inspection Transparency system, just as you
required PHMSA to institute the successful Enforcement Transparency in
the PIPES Act of 2006.
There is also a need to make other information more readily
available. This includes information about:

High Consequence Areas (HCAs). These are defined in Federal
regulations and are used to determine what pipelines fall under
more stringent integrity management safety regulations.
Unfortunately, this information is not made available to local
government and citizens so they know if they are included in
such improved safety regimes. Local government and citizens
also would have a much better day-to-day grasp of their local
areas and be able to point out inaccuracies or changes in HCA
designations.

Emergency Spill Response Plans. As has been learned in the
recent Gulf of Mexico tragedy, it is crucial that these types
of spill response plans are well designed, adequately meet
worst-case scenarios, and use the most up-to-date technologies.
While 49 CFR 194 requires onshore oil pipeline operators to
prepare spill response plans, including worst case scenarios,
those plans are difficult for the public to access. To our
knowledge the plans are not public documents, and they
certainly are not easily available documents.

The review and adoption of such response plans is also a process
that does not include the public. In fact PHMSA has argued that
they are not required to follow any public processes, such as
NEPA, for the review of these plans. If the Gulf tragedy has
taught us nothing else it should have taught us that the
industry and agencies could use all the help they can get to
ensure such response plans will work in the case of a real
emergency.

It is always our belief that greater transparency in all aspects of
pipeline safety will lead to increased involvement, review and
ultimately safety. There are many organizations, local and
state government agencies, and academic institutions that have
expertise and an interest in preventing the release of fuels to
the environment. Greater transparency would help involve these
entities and provide ideas from outside of the industry. The
State of Washington has passed rules that when complete spill
plans are submitted for approval the plans are required to be
made publicly available, interested parties are notified, and
there is a 30 day period for interested parties to comment on
the contents of the proposed plan. We urge Congress to require
PHMSA to develop similar requirements for the adoption of spill
response plans across the country, and that such plans for new
pipelines be integrated into the environmental reviews required
as part of the pipeline siting process.

State Agency Partners. States are provided with millions of
dollars of operating funds each year by the Federal Government
to help in the oversight of our Nation's pipelines. While there
is no doubt that such involvement from the states increases
pipeline safety, different states have different authority, and
states put different emphasis in different program areas. Each
year PHMSA audits each participating state program, yet the
results of those program audits are not easily available. We
believe that these yearly audits should be available on PHMSA's
website and that some basic comparable metrics for states
should be developed.

Moving Forward to Address Unregulated Pipelines and Clarifying
Regulations of Gathering and Production Pipelines
After numerous spills from low stress pipelines on Alaska's North
Slope, Congress directed PHMSA to move forward with new rules to better
regulate them. Section 4 of PIPES required PHMSA to ``issue regulations
subjecting low-stress hazardous liquid pipelines to the same standards
and regulations as other hazardous liquid pipelines'' (emphasis added)
with limited exceptions for pipelines regulated by the U.S. Coast Guard
and certain short-length pipelines serving refining, manufacturing, or
truck, rail, or vessel terminal facilities. This section's clear
directive to PHMSA to have these rules adopted by December 31, 2007,
has only been partially followed since PHMSA decided to implement this
directive in a phased approach, and so far PHMSA has only adopted phase
one of those rules and made no announcement about phase two. Congress
needs to require clear answers from PHMSA regarding the initiation and
implementation of the phase 2 rules.
Meanwhile, significant drilling for natural gas has led to a large
expansion of gathering and production pipelines in highly-populated
urban areas. For instance, in Fort Worth Texas there are already 1,000
producing gas wells within the city limits and at least that many more
planned. Development of improved gas drilling methods has led to
thousands of new wells being drilled and proposed in more populated
areas of Texas, Arkansas, Louisiana, Pennsylvania and New York.
Pipelines will connect all these wells, and the regulatory oversight of
these pipelines in these areas is less than clear and in some cases
non-existent. The standards for PHMSA's rules to determine which
pipelines fall under minimum Federal regulations were written by the
American Petroleum Institute and incorporated by reference into the
regulations. If the public wants to review these standards they have to
buy a copy of this part of the Federal regulations from API for $126.
What the API written standards actually require provides much wiggle
room for gas producers to design their systems to avoid regulations.
PHMSA also only regulates a limited amount of these gathering and
production pipelines, and leaves the rest of the regulations up to the
states if they choose to assert any authority. We believe it is time to
ensure that any gathering or production pipeline in a populated area
with similar size and pressure characteristics as other currently
regulated pipelines fall under the same level of minimum Federal
regulations. At a minimum we think Congress should require PHMSA or the
National Transportation Safety Board to produce a study on the onshore
gas production and gathering pipelines that are not covered by current
Federal standards. This study should explain what pipelines are not
covered, what the extent of them is, how many are located in populated
areas, the relative risk, and a proposed regulatory regime for
inclusion of all these pipelines under minimum Federal standards.

Making Public Awareness Programs Meaningful and Measurable
The Pipeline Safety Improvement Act of 2002 required pipeline
operators to provide people living and working near pipelines basic
pipeline safety information, and gave PHMSA the authority to set public
awareness program standards and design program materials. In response
to this Congressional mandate, PHMSA set rules that incorporated by
reference the American Petroleum Institute's (API) recommended practice
(RP) 1162 as the standard for these public awareness programs.
According to RP 1162's Foreword (page iii) of API recommended practice,
the intended audiences were not represented in the development of RP
1162, though they were allowed to provide ``feedback.'' The omission of
representatives from these audiences from the voting committee reduces
the depth of understanding the RP could have had regarding the barriers
and incentives for such programs, and undercuts the credibility of the
recommended actions. The public awareness program regulations--49 CFR
192.616 and 49 CRF 195.440--mandate that operators comply with RP
1162. In essence, this amounts to the drafting of Federal regulations
without the equal participation of the stakeholders the regulations are
meant to involve. With non-technical subject matter, such as this
recommended practice deals with, it is difficult to justify excluding
the intended audiences from the process and allowing the regulated
industries to write their own rules.
This public awareness effort represented a huge and important
undertaking for the pipeline industry, and as such the effectiveness of
it will evolve over time. We were happy that the rules included a
clause that set evaluation requirements that require verifiable
continuous improvements. While we understand that the initial years of
this program have been difficult, we have been disappointed in some of
these efforts as they were clearly farmed out to contractors to meet
the letter of the requirement instead of the intent of the requirement.
Recently, the National Transportation Safety Board cited the failure of
these programs in the investigation report of a deadly pipeline
explosion in Mississippi that killed a girl and her grandmother.
An evaluation of the first 5 years of this program is due this
year, and API has been working on an update of this recommended
practice for some time now. One of the draft proposals from API is to
remove the requirement to measure whether the programs have led to
actual changes in behavior. PHMSA plans to hold a workshop on these
public awareness programs in late June. We hope that Congress will keep
a close eye on the discussions of this issue over the coming months and
be prepared to step in and clarify that the intent of this program is
to change the behavior of the intended audiences to make pipelines
safer, not to count how many innocuous brochures can be mailed.

Implementing Expansion of Excess Flow Valve Requirements
One of the Trust's priorities that was well addressed in the PIPES
Act was to require the use of Excess Flow Valves (EFVs) on distribution
pipelines for most new and replaced service lines in single family
residential housing. While this was a huge step forward, the National
Transportation Safety Board (NTSB) has continued to push for an
expansion of the use of EVFs in multi-family and commercial
applications ``when the operating conditions are compatible with
readily available valves.''
From closely following the deliberations of PHMSA's Large Excess
Flow Valve Team, it is our opinion that there are thousands of
potentially compatible structures being constructed or renewed which
could be afforded greater safety by the installation of Excess Flow
Valves (EFVs). It is clear from the data provided by PHMSA (see figure
1 below) that the services lines serving a majority of these types of
structure fall within the size constraints of commercially available
EFVs. It is also clear from the data (see figure 2) that the vast
majority of these gas services are provided at pressures that avoid the
concerns regarding low pressure lines.
Figure 1 (Source--PHMSA's--Interim Evaluation: Response To NTSB
Recommendation P-01-2)

Figure 2 (Source--PHMSA's--Interim Evaluation: Response To NTSB
Recommendation P-01-2)

The one significant hurdle to overcome is to avoid EFVs to
structures where the demand load varies greatly or could change over
time. There are many multi-family residential, small office, and retail
structures that for all intents and purposes have the same load
profiles as a single family residence. For these types of applications
PHMSA and the industry need to move forward with rules to require
installation of EFVs for new and renewed gas service.
From our perspective, it would be difficult to engineer the
application of EFVs to avoid the problems associated with load
fluctuation for such structures as hospitals, multi-tenant commercial
buildings, and industrial facilities. We agree with the industry's
concerns about the installation of EFVs for these types of
applications, and believe more study is needed both in terms of these
large applications as well as the effectiveness of EFVs on current
applications.
The real difficulty is drafting rules that clearly define which
additional applications are within the needed expansion of the rules
and which applications are not. We are disappointed that some in the
industry--as a way to stop all movement toward improved safety rules--
always point to the types of structures that are difficult or
impossible to serve with EFVs. Instead, they should be searching for a
way to increase the safety of thousands of people who live or work
within buildings that could clearly be served by EFVs. The Pipeline
Safety Trust urges Congress to direct PHMSA to undertake a rulemaking--
as the National Transportation Safety Board has requested--that would
require EFVs be installed on the many types of structures where
``operating conditions are compatible with readily available valves.''

Concerns with Industry Developed Standards Being Incorporated into
Federal Regulations
There has been increasing attention because of the Gulf of Mexico
tragedy to the practice by Federal agencies of incorporating into their
regulations standards that outside organizations developed. Like MMS,
PHMSA has incorporated by reference into its regulations standards
developed by organizations made up in whole or in part of industry
representatives. A review of the Code of Federal Regulations under
which PHMSA operates finds the following numbers of incorporated
standards:

Standards Incorporated by Reference in 49 CFR Parts 192, 193, 195
(As of 6/9/2010)
------------------------------------------------------------------------
CFR Part Topic Standards*
------------------------------------------------------------------------
192 Natural and Other Gas 39
------------------------------------------------------------------------
193 Liquefied Natural Gas 8
------------------------------------------------------------------------
195 Hazardous Liquids 38
------------------------------------------------------------------------
Total 85
------------------------------------------------------------------------
*Note: Some standards may be incorporated by reference in more than one
CFR Part.

Those standards were developed by the following organizations:

American Gas Association (AGA)

American Petroleum Institute (API)

American Society for Testing and Materials (ASTM)

American Society of Civil Engineers (ASCE)

ASME International (ASME)

Gas Technology Institute (GTI)

Manufacturers Standardization Society of the Valve and Fittings
Industry, Inc. (MSS)

NACE International (NACE)

National Fire Protection Association (NFPA)

Pipeline Research Council International, Inc. (PRCI)

Plastics Pipe Institute, Inc. (PPI)

While the Pipeline Safety Trust has not done an extensive review of
these organizations or their standard setting practices, it is of great
concern to us--and we believe it should be to Congress as well--
whenever an organization whose mission is to represent the regulated
industry is--in essence--writing regulations that members of the
organization must follow. A very quick review of the mission statements
of some of these organizations reveals statements like these below that
show, at a minimum, a conflict between the best possible regulations
for the entire public and the economic interests of the industry.

API--``We speak for the oil and natural gas industry to the
public, Congress and the executive branch, state governments
and the media. We negotiate with regulatory agencies, represent
the industry in legal proceedings, participate in coalitions
and work in partnership with other associations to achieve our
members' public policy goals.''

AGA--``Focuses on the advocacy of natural gas issues that are
priorities for the membership and that are achievable in a
cost-effective way.'' ``Delivers measurable value to AGA
members.''

PPI--``PPI members share a common interest in broadening
awareness and creating opportunities that expand market share
and extend the use of plastics pipe in all its many
applications.'' ``The mission of The Plastics Pipe Institute is
to make plastics the material of choice for all piping
applications.''

PRCI--``PRCI is a community of the world's leading pipeline
companies, and the vendors, service providers, equipment
manufacturers, and other organizations supporting our
industry.''

The pipeline industry has considerable knowledge and expertise that
needs to be tapped to draft standards that are technically correct and
that can be implemented efficiently. But we also know the industry's
standard setting practices exclude experts and stakeholders who can
bring a broader ``public good'' view to standard setting. We also know
that when a regulatory agency needs to adopt industry-developed
standards it is a ``red flag'' that the agency lacks the resources and
expertise to develop these standards on its own.
It should be noted that the development of such standards is not an
open process where interested members of the public or experts outside
the industry (such as those in universities and colleges) can review
the material and comment. One of the most ridiculous examples of this
one sided process was the development of the Public Awareness standard
(API RP 1162) which now governs how pipeline companies have to
communicate with the affected public. The process was controlled by
industry, even though industry has no particular expertise in this type
of public awareness or communication. The many possible independent
experts and organizations in the field of communications and education
were not sought and ultimately were not a part of the development of
this standard.
Even once the standards are incorporated by reference into Federal
regulations the standards remain the property of the standard setting
organization and are not provided by PHMSA in their published
regulations. If the public, state regulators, or academic institutions
want to review the standards they have to purchase a copy from the
organization that drafted them. In many cases, this further removes
review of the standards from those outside of the industry. Below are
just a handful of examples of the cost to purchase for review the
standards that are part of the Federal pipeline regulations:

Sample Cost of Pipeline Safety Standards Incorporated by Reference Into Federal Regulations
(As of 6/8/2010)
----------------------------------------------------------------------------------------------------------------
Code of Federal Regulations
Standard Organization (Incorporated by Reference) Cost
----------------------------------------------------------------------------------------------------------------
ANSI/API Spec 5L/ISO 3183 API 49 CFR 192.$245.0092.112,
``Specification for Line Pipe'' 192.113, 195.106
----------------------------------------------------------------------------------------------------------------
ASME B31.4 -2002 ASME 49 CFR 195.$129.00
``Pipeline Transportation Systems
for Liquid Hydrocarbons and
Other Liquids''
----------------------------------------------------------------------------------------------------------------
GRI 02/0057 (2002) ``Internal GTI 49 CFR 192.$295.00
Corrosion Direct Assessment of
Gas Transmission Pipelines
Methodology''
----------------------------------------------------------------------------------------------------------------
NACE Standard RP0NACE2002 49 CFR 192.9$83.00192.925,
``Pipeline External Corrosion 192.931, 192.935,
Direct Assessment Methodology'' 192.939, 195.588
----------------------------------------------------------------------------------------------------------------
A Modified Criterion for PRCI 49 CFR 192.$995.00192.485,
Evaluating the Remaining Strength 195.452
of Corroded Pipe''
----------------------------------------------------------------------------------------------------------------

The Pipeline Safety Trust asks that Congress carefully review the
use of industry developed standards in minimum Federal pipeline safety
regulations, as well as the development of risk-based programs that are
not required to go through any sort of public review.
Summary of Testimony
As stated previously, the Pipeline Safety Improvement Act of 2002
and the Pipeline Inspection, Protection, Enforcement and Safety (PIPES)
Act of 2006, have required many valuable and significant new pipeline
safety efforts, including Integrity Management, increasing damage
prevention efforts, greater transparency, and increasing the number of
inspectors and the amount of fines. The Trust is very pleased with all
of these efforts and does not see the need for any huge new programs
during this reauthorization. Our recommendations build upon the
important foundation that Congress has built during the past 10 years.
What is always needed is constant vigilance so pipeline safety does not
once again return to a system where the regulated control the
regulators, and where what is easy takes precedence over what is safe.
Thank you again for this opportunity to testify today. The Pipeline
Safety Trust hopes that you will closely consider the concerns we have
raised and the requests we have made. If you have any questions now or
at anytime in the future, the Trust would be pleased to answer them.

Senator Lautenberg. Thank you very much, Mr. Weimer.
You mentioned the fact that we've required excess flow
valves. I authored a provision in the 2006 PIPES Act that
required the devices for single-family homes and I think there
is universal approval of this requirement. But they are not
required currently for apartment or commercial buildings. In
the reauthorization of pipeline safety legislation, what can
Congress do to protect the people who live in dwellings other
than single-family homes? I ask you, Mr. Weimer. What do you
think we can do?
Mr. Weimer. Well, NTSB still has a recommendation on the
table that hasn't been fully met to include multi-family
residences and commercial retail types of businesses. I think
the key to that--and PHMSA has had a work group that looked at
this--is when the load demand is similar to what a single-
family residence is, and there are many of those, that they
need to move forward on a rulemaking to include those types of
businesses.
There are thousands of structures that have a load demand
similar to a single-family residence and PHMSA just needs to
come up with a rulemaking to define where that line is, because
we do agree with the industry that there are some situations--
chemical plants, hospitals--where excess flow valves may just
not make sense. But there are lots of buildings they do, and we
need to expand those inclusions.
Senator Lautenberg. Is there technology to do something to
make these valves more effective where the demand for gas is
great? So, even if something happens, that the direct flow to
one user of part of the structure still requires energy?
Mr. Weimer. Right. I think it's obvious from the work group
that PHMSA has conducted that for the vast majority of the size
of pipelines and for the load demands, there are already excess
flow valves available to deal with that. It's just a matter of
clarifying and defining where that line is, where you cross
into different types that have load demands that vary so much
that at this point excess flow valves don't make much sense.
Senator Lautenberg. Mr. D'Alessandro, what do you think?
The industry has voiced concern, and you've expressed it, at
the expanding use of excess flow valves. However, NTSB and
safety advocates across the country have called for them, to be
repetitive, to be required in these structures. Given what
you've said and what you've heard today, can you commit to
working with us, with the Committee, to find a practical
solution on this issue?
Mr. D'Alessandro. We look forward to doing that. Our issue
is the mandatory installation of EFVs on all of the facilities.
We think for some of them they might fit the occasion to do it,
but I think in some of the testimony you've seen the words
``operating conditions justify.'' In my testimony I talked
about the service line and the fluctuation in pressures that
happen within the facilities could kick off EFVs. But we'd love
to work on EFVs and find some type of solution.
Senator Lautenberg. I wonder--this question can be answered
by any one of you--whether or not in those types of buildings
there ought to be something internal, not unlike a fire safety
cannister or something like that--more than a cannister, but a
unit that could be used. There is a significant extra risk in
those buildings where there are multiple dwellings.
Anybody volunteer a response to that? We have to do
something to protect the people who are in those buildings.
Their lives are no less valuable. Their families are no less of
concern. What can we suggest as an alternative to not being
able to provide excess flow valves?
No volunteers?
Mr. D'Alessandro. I'll give it a shot. The excess flow
valve really protects the customer from an external or a hit
before the meter set. That would protect them. If anything
would happen within their own internal piping--and I'm not sure
if that's where you're headed with your question--the excess
flow valve would not protect that. It would not kick itself off
if it's inside the home.
Safety--in the public awareness program that we've got
going on, all of us participate in educating our consumers
about natural gas, about the smell of natural gas, what to do
in case they smell natural gas. Our response record of
responding when there are gas emergencies in the gas
distribution pipeline, we take it very serious and we all
strive to have high standards on that.
Senator Lautenberg. Mr. Felt, a quick question here. BP's
oil spill in the Gulf has shown that the company's response
plan was completely inadequate. How can we be confident that
oil companies operating offshore or onshore pipelines have the
right response plans in place so that they're adequately
prepared for a worst case scenario?
Mr. Felt. Well, sir, I think that if you look at what's
expected today, response plans are developed by the pipeline
companies, by the operators, submitted to the OPS for review
and approval. Our experience, my experience, has been that when
they are submitted we'll get some feedback, either on areas
where they're not adequate or some clarification that's needed.
Just looking from our own personal company's standpoint,
those plans are unique to each facility. They do look at worst
case scenarios. They look at the worst case conditions in those
worst case scenarios. PHMSA I believe is getting ready to come
out--we saw a draft announcement just recently where they're
going to ask for another review in light of what's happened in
the Gulf, just to make sure that there are adequate resources
to respond and if there are any changes please respond within
the next 30 days. I hope I'm not jumping ahead of OPS, but we
did see that announcement coming out.
Senator Lautenberg. Well, certainly this tragedy, this
calamity that has taken place, puts us all on alert and we have
to be much more careful about the exposure that something like
that happens.
Mr. Felt. I agree.
Senator Lautenberg. Senator Thune.
Senator Thune. Thank you, Mr. Chairman.
Gentlemen, thank you for your testimony today. Let me ask
you a question about new technologies. What role do you see new
technologies playing to improve the safety of pipelines?
Mr. Sypolt. Senator, I'll take a shot at that to start
with. Actually, we've seen technology improve over time, that
basically has been used in our integrity management programs,
like in new evolutions or new generations of smart pigs, and
those continue to improve. I think that is a very key thing to
help us in our integrity management programs. So I do think
that continued research is a very valuable tool.
Senator Thune. I think one of the greatest threats to
pipeline safety and integrity--and it has been talked about at
some length today--comes from accidental damage due to digging
and excavation. I commend PHMSA and the states for developing
the One-Call program, which allows excavators to dial 811
anywhere in the country and learn the location of pipelines and
other utilities before digging.
However, recent accidents demonstrate that we may need to
do more in this area, and I'm interested in what
recommendations you might have for improving the One-Call
program to prevent excavation damage. Anybody?
Mr. Sypolt. I'll be happy to start it off for you, Senator.
I do believe that, with regard to One-Call systems, they are
our first line of attack to protect the public. Clearly I
believe there should be no exceptions to One-Call. I think
every party should have to call. No one should be excepted from
safety.
Second, I think that there has to be a very clear
communication between the parties with regard to where the
activity is being done, and then there has to be a thorough
follow up and marking of the pipelines. Fourthly, the group
who's doing the excavation has to work very cautiously around
those facilities.
If all four of those things do not work, I don't believe
there's more regulation that could take care of it. I think
regulation is in place to do those things, except for the part
where certain parties are excepted from One-Call systems.
Mr. Felt. Sir, I'd like to add just one other point to
that, and that's the enforceability. There are cases where
there's no consequence for not following the One-Call rules,
either for the excavator or the person doing the proper
marking. I believe that's something that needs to be addressed
as well.
Mr. Weimer. One other point, if I could, and I certainly
agree with everything that Mr. Sypolt and Mr. Felt said. Back
to our issue of reporting requirements, recently in the two
incidents in Texas, when we looked at those, the PHMSA database
showed that on average there are ten incidents a year from
damage in the State of Texas. The Texas Railroad Commission
shows that there are 18,000 incidents a year from damage. So
there's a big disconnect on whose data you're looking at.
When we looked at the State of Texas, they have an
excellent reporting system that requires both excavators and
operators to report any damage to pipelines. That's why they
know they have 18,000 incidents a year, and it's available to
the public to look at. You can scroll through it and organize
it by excavator, by pipeline company, by city, and look. So you
can come up with A-1 Excavators has hit pipelines in Fort
Worth, Texas, 10 times in the last 6 months and make some
conclusions from those types of things.
I think that's an excellent system that could be adopted in
other states.
Senator Thune. You've noted that state authorities have
primary responsibility over gas distribution pipelines and that
many states have chosen to adopt regulatory standards that are
more stringent than Federal ones. Could you describe some of
the State regulations that are more stringent and how many
states have adopted standards that are more stringent, and then
perhaps, to follow up, are there more stringent state standards
or best practices that PHMSA could or should consider adopting?
I think you just mentioned the State of Texas as an example.
But are there some states that have more stringent standards
and can you give me some examples of those, and are there some
things that perhaps the feds ought to be adopting that states
are already doing?
Mr. Sypolt. I believe that the State of Virginia, Senator,
has probably one of the very best One-Call systems out there. I
think it serves as a model. One, there's high participation in
it, high-profile participation in it. In the event there are
parties who actually cause damage, there's a group that
actually assess penalties on what they think that group should
pay. I think that peer pressure has served very well in the
State of Virginia, and we've been extremely pleased with that
One-Call system.
Senator Thune. You don't have to confine it to One-Call.
It's sort of a broad question about things the states are doing
in terms of regulation.
Mr. Weimer. One of the other things that has been brought
to our attention a lot is the difficulty getting hold of
PHMSA's spill response plans for liquid and oil pipelines.
There are some groups even in the Midwest from your own state,
I believe, that had to use the FOIA to actually get their hands
on a spill response program so they could review it to see if
it adequately protected their area.
In the state I'm from, the State of Washington, Washington
has adopted regulations that once a complete spill response
program is submitted to the State of Washington it opens up a
30-day comment period where the public, universities,
interested local governments, have a chance to review and
comment on that spill response plan. There's nothing within the
Federal regulations that opens up spill response plans for any
public review or comment.
Senator Thune. Thank you.
Thank you, Mr. Chairman.
Senator Lautenberg. I now call on Senator Udall, and
sitting next to him is Senator Begich. These are very
mountainous states, a lot higher than New Jersey's 1,200-foot
highest mountain.
Senator Begich. That's a mountain?
Senator Lautenberg. But I don't know whether the problems
are more difficult. But Senator Udall.

STATEMENT OF HON. TOM UDALL,
U.S. SENATOR FROM NEW MEXICO

Senator Udall. Thank you, Chairman Lautenberg. I'd like to
put my opening statement in the record and proceed from there.
Thank you for doing this hearing. I think the issue of
pipeline safety is a very important one. As you say, we have
mountains, but we also have flat areas and desert areas and a
variety of problems. That's one of the things I wanted to focus
on with the Committee today.
Mr. Weimer emphasized this. We're almost on the 10-year
anniversary of the Carlsbad explosion, where a family of 12 was
camping and through no fault of their own they were wiped out
in an explosion.
I'm wondering, for our first three witnesses, how do you
respond to the recommendation by Mr. Weimer that integrity
management plans be expanded to rural areas, like the area
outside Carlsbad where the accident occurred 10 years ago? What
do you think of that?
Mr. Sypolt. Senator, I believe that--well, let me start
with a few facts here. When you look at the natural gas
transmission system today as it stands, about 49 percent of the
transmission system has been smart pigged, as opposed to the
requirement of only 7 percent in HCA areas. So pipelines are
already doing much more than just the HCA areas.
We expect, based on surveys from particularly the INGAA
membership, that by the end of 2012 we will have pigged 65
percent of those pipelines. That being said, we should make
sure, though, that we do not lose focus on those areas which we
believe have the greatest impact, where there is the most
population and pipelines are closest to those. So I think that
we already are doing much more than just the HCA areas and
pipelines basically treat--when they find something outside of
those HCA areas, they take the same corrective actions as they
do inside the HCA areas. So I believe much more is being done
than the 7 percent required today by PHMSA.
Mr. Felt. Sir, on the liquid side 44 percent are covered
already under the integrity management plan rules, because 44
percent occur within HCAs or affect HCAs. But, like the gas
side, much more is done than just the minimum 44 percent. In
fact, earlier estimates were that the integrity management plan
would require somewhere in the neighborhood of a couple of
hundred million dollars. The industry has spent billions of
dollars, and I think that's a reflection of how much more work
is being done beyond the minimum requirement.
I think the danger with requiring all pipelines or all
miles of pipelines to be treated the same is that you take away
the flexibility or the ability to place your dollars where
there's greater emphasis. It's that flexibility, I think, that
we need. The pipeline companies are already doing more than the
minimum, but to require every mile to be treated the same I
think would not be the most effective way to manage the system.
That's why the rules were developed with emphasis on HCAs.
Mr. D'Alessandro. From a distribution point of view, a lot
of our transmission pipelines that are covered are not
piggable. So we have to do some type of other assessment. Most
of the time it only can be direct assessment because we cannot
pressurize them or hydrotest them because then we put water in
our system and we create another issue of corrosion within our
system.
We believe--in my testimony I talked about the assessment
of low-stress transmission pipelines being moved from TIMP over
to DIMP. That would assist us, that now all pipeline, all
mileage, would be covered underneath the DIMP robust plan and
have a risk-based program looking at that. So that is one
recommendation from a distribution point of view.
Senator Udall. Mr. Weimer, would you like to comment on
those?
Mr. Weimer. We certainly agree that the industry has done
more. There are some companies that almost smart pig 100
percent of their pipelines. We commend those companies. The
main difference we see is what's required versus what's done
voluntarily is who you have to report that to and who knows
that information. For the natural gas transmission industry,
what's found outside of high consequence areas doesn't need to
be reported to PHMSA and what's found--anomalies found in the
pipelines aren't required to be treated the same way they are
if they are under the regulations. So there's a big difference
between whether you're doing it voluntarily or whether it's
under the regulation.
Senator Udall. Thank you, Chairman Lautenberg, and thank
you to the panelists.
[The prepared statement of Senator Udall follows:]

Prepared Statement of Hon. Tom Udall, U.S. Senator from New Mexico

Mr. Chairman, thank you for holding this hearing today on ensuring
the safety and security of our Nation's pipeline infrastructure.
Almost 10 years ago, in August 2000, New Mexico experienced one of
the most tragic pipeline accidents in recent memory.
Twelve members of the same extended family, camping outdoors near
Carlsbad, New Mexico, were killed in a horrific explosion of a natural
gas pipeline early in morning.
The National Transportation Safety Board investigation found the
explosion the result of corrosion, and that both industry and
government attention to pipeline safety needed improvement.
Following that incident, Congress took action, passing the Pipeline
Safety Improvement Act of 2002. Congress reauthorized that Act in 2006
and it is time for us to get to work again on pipeline safety.
Pipelines may be the safest form of transportation, compared to
trucking or railroads, but that fact is no consolation to the family
and friends left behind after fatal pipeline accidents.
That fact also does no cleanup of the environment following
pipeline accidents that leak hazardous liquids like oil and gasoline
into the environment.
As a result, we must remain vigilant. As recent fatal accidents in
Texas have shown, including one earlier this month, our work is not
complete.
I look forward to hearing how the pipeline safety programs Congress
put in place are working and how they can be improved.
In particular, we must ensure that existing regulations are being
enforced and be skeptical of waivers and self-regulation.

Senator Lautenberg. Senator Vitter.
Senator Vitter. Mr. Chairman, I'm going to pass right now.
I really want to hear more discussion from the panelists.
Senator Lautenberg. Senator Begich.

STATEMENT OF HON. MARK BEGICH,
U.S. SENATOR FROM ALASKA

Senator Begich. Thank you, Mr. Chairman.
Let me, if I can, follow up on Senator Thune's questions on
the One-Call. I'm not as familiar with--I understand what they
do on ground, but do they have a similar situation for
offshore? Why I ask that is, as you know, pipelines come
offshore moving product to land facilities, and there is stuff
we're starting to hear about where people might be anchoring,
for example, might be interfering with some of the lines.
Can you help me understand that a little bit better from
your own industry? Is that an issue that's starting to become a
problem? We've heard just a couple indications that as we have
more and more lines coming in offshore onto land-based
facilities and then ships who are then also laying anchor, how
that all connects--or actually, we don't want them to connect.
Tell me, is there a One-Call center for that, where there
are zones that you cannot be anchoring in? And then, if not,
what recommendations might you have on this area? For anyone
who wants to step up on that?
Mr. Sypolt. My understanding, Senator, is for offshore,
obviously it's more difficult than onshore, where pipelines are
mapped very well, GPS coordinates are taken. My understanding
is the State of Texas is actually looking at a system to really
approach those offshore pipelines by having them mapped with
GPS systems and then having ships equipped with those type
systems where they can either look at their system and see the
map of the pipelines or contact the Coast Guard to actually get
some feedback as to whether or not they're looking at laying
anchor somewhere close to a pipeline system.
But offshore is not as far advanced as we are onshore with
One-Call type systems, Senator.
Senator Begich. If I can just interrupt before someone else
answers, based on obviously the larger issue, which is the
blowout and the spill, which is a whole different set of
circumstances, is this something you think we should
accelerate, some more discussion, or is it not that big of a
problem that you've heard within your own associations?
Mr. Felt. Well, sir, I've not heard of it being as much of
a problem. But before I would comment one way or the other, I
think it would be more appropriate to talk to the Office of
Pipeline Safety, because I think there is that transition
period between close to the shoreline versus further offshore.
I think I heard Ms. Quarterman talk about the fact that there
is a transition area, and probably understanding more what
they're regulating would be helpful.
Senator Begich. Any other comments from folks on that one?
[No response.]
Senator Begich. Let me, if I could take another step. As we
talk about pipelines, we have a big one in Alaska and we'll
have, hopefully soon, maybe, a bigger one moving gas. Do you
think PHMSA has the capacity, staffing, and authority to deal
with these large projects in a timely manner, and making sure
that they don't become a bottleneck in the delay of a project
of that magnitude? It's a big project for us as we think of the
gas line, and as we think about this we're thinking of all the
Federal agencies that will be touching this line in some form
of regulatory process. On big projects like this, my instincts
tell me that a lot of agencies are never geared up to deal with
large projects. I may be wrong about that, but I want to get
some feedback from you of how you see that, or their capacity
to deal with large projects.
Mr. Sypolt. Obviously, Senator, the Alaska pipeline is a
huge project. It's outside of the norm. I believe that PHMSA
has looked at other large projects, similar to the Rockies
Express Pipeline that was built across the majority of the
United States. So they have taken on large projects before and
watched over those.
But clearly the Alaska project would be a huge one that
would require several resources that they probably would be
directing in that direction for a period of time.
Senator Begich. Do you think they have the--and again, this
may be an unfair question for you, but do you think they have
the authority to do whatever kind of reimbursable contracting
or anything of that nature to bring those resources to bear as
they need them for a project of that magnitude?
Mr. Sypolt. Senator, I'm not sure that I know that answer.
Senator Begich. That's fine.
Anyone else want to comment on that, on their ability? Yes?
Mr. Weimer. That's one concern that we've had with a lot of
the new pipelines. We've heard some discussion today of the
Keystone pipelines and some of those, and the ones in Alaska
would be even larger. My understanding--and this is something
that it probably would make sense to question PHMSA about a
little more--is there's somewhat of a disincentive built into
their fee structure, because their fee structure is based on
user fees that they don't start to collect until there's
actually product going through those pipelines.
So to inspect pipelines that are not yet working, they're
taking money that's coming from other things and trying to
divert resources. So there has been some discussion about
whether you need actual fees for inspections of proposed new
pipelines so existing pipelines aren't subsidizing the new
operators.
Senator Begich. Let me ask--that's an interesting question.
People hate this when I bring this up at these meetings, but I
used to be a mayor. When we had building inspections, you
always had fees to inspect those buildings in the construction
phase, as well as obviously if you were a commercial building
on your annualized inspections.
Let me ask other people to comment. Do you think there
should be a fee structure for prior to and during construction
of projects, say of that size?
Mr. Weimer. I think I'm coming at it with my same--because
I'm an elected county council member, too.
Senator Begich. Oh, good.
Mr. Weimer. So to a degree we always try to get fees to
cover the fees so other people aren't subsidizing that. So it
makes sense to us and it's a way to make sure that they have
the resources to pay for those things without spreading
themselves too thin. Now, whether that's the case or not, that
would be questions that you'd have to ask PHMSA.
Senator Begich. Anyone else want to comment on that? I know
industry folks don't like to always talk about fee issues, but
this is an opportunity for you.
[Pause.]
Senator Begich. I knew someone would take the bait.
Mr. Felt. I agree that you probably have to ask PHMSA about
the super-large projects. But it hasn't deterred them so far
from inspecting, say, more moderate sized projects. Currently
our company is involved with a relocation project to
accommodate, in the State of New Jersey, where the New Jersey
Turnpike is widening. We're going to spend well over $100
million on construction in that particular project, and we're
just the relocating part of that project. We've already been
notified that PHMSA inspectors will be out there and we're
prepared for that.
So maybe something of a larger nature has to be discussed
separately, but I think for the day-to-day type of work that's
happening it appears to me that PHMSA is----
Senator Begich. Is OK.
Mr. Felt.--is okay. They're there, they're showing up.
The other thing is that the fees that we'll be paying down
the road--if they're inspecting, I think the approach they're
taking, if they're inspecting up front, they probably won't
have as much need to inspect later on. So they'll be collecting
fees, yes, after the fact, but it'll probably more than
reimburse the effort they put in up front. Now, that's not for
maybe the super-large projects, but probably for all other
ones.
Senator Begich. Because we estimate this is probably a 30,
40, 50, depending on what day it is, billion dollar project.
One last comment. I know I've exceeded my time.
Mr. D'Alessandro. The only thing I was going to add was,
when Rocky Express came through Illinois not only was PHMSA
inspecting it, but your state OPS was also out there
inspecting. So there's more pressure, I think, maybe at the
state level because of their funding and their staffing. But
they're also out there inspecting those large projects.
Senator Begich. Very good.
Thank you all very much for your time and answers.
Thank you, Mr. Chairman.
Senator Lautenberg. Senator Vitter, are you still patient?
Senator Vitter. Yes.
Senator Lautenberg. We're joined by Senator Pryor and I
would now ask you to ask any questions that you might have.

STATEMENT OF HON. MARK PRYOR,
U.S. SENATOR FROM ARKANSAS

Senator Pryor. Thank you. Thank you, Mr. Chairman. I do
have just a small number. Thank you for your leadership here,
and I appreciate the panel being here today, too.
Let's see. Mr. Felt, I would like to ask you a question
about the TransCanada Pipeline. In the approval process, as I
understand it, because it's Canada and U.S. there has to be an
approval process through the State Department; is that right?
Mr. Felt. That is correct. You're talking about the gas
line----
Senator Pryor. Yes.
Mr. Felt--coming through? That would probably be more
appropriate for one of the other gentlemen.
Senator Pryor. OK.
Mr. Felt. Oh, the oil line you're talking about? Oh, yes.
I'm sorry. There is a NEPA process for that, for that pipeline,
that's correct.
Senator Pryor. And how is that approval process going? Is
the State Department moving that through or doing the proper
due diligence they need to do?
Mr. Felt. I'm really not familiar with the details. I do
know that it's going through the process. I heard that it is
making progress. But that's really third- or fourth-hand
information.
Senator Pryor. OK. I know as part of the Gulf oil spill
there has been some allegations or concerns about MMS being too
close to the oil industry. I would like to ask about the
relationship with PHMSA and your industry. So I don't know who
this should be best directed to, but if you could tell us about
the relationship between PHMSA and your industry and how hard
they look at things, how difficult the inspections and the
approval process are, etcetera. So who wants to take that?
Mr. Sypolt. I'll be happy to, Senator. I believe that the
PHMSA regulations are based on sound engineering practices, so
the regulations that they enforce make great sense to the
industry. The industry does millions and millions of
inspections. Many of those are based on certain timeframes and
have to be completed within certain timeframes. PHMSA or their
agents come out very regularly and audit our records. The
records are very, very open as far as PHMSA or their agents'
ability to look for any particular violations, such as being 3
days late on an inspection.
When you're doing millions of inspections and you have 1 or
2 of them that are 3 days late and you end up fined for that,
some pipeline operators will believe that to be heavy-handed
regulation. So I think PHMSA is aggressive in their audits and
in their enforcement practices.
Mr. Felt. Sir, I'd like to add a couple points on that. I
would say that we have a respectful relationship with PHMSA. In
addition to just auditing records, it has been my experience
that they'll actually go out into the field, and not just the
field locations, but the remote locations, and look at
corrosion readings out in the middle of a cornfield somewhere.
They'll look at valves just to make sure that they've been
properly maintained.
Interestingly enough, the pipeline records, the safety
record, has been improving over the years, but it seems to me
that the number of inspections have been increasing, the
detailed level of the inspections have been increasing.
Unfortunately, the number of fines have been increasing, both
number and size. To me, that's a reflection of what I believe
is PHMSA raising the bar even while the safety performance is
improving.
So I think that's what the public wants and I'd have to
commend PHMSA for doing it, even though it's at the expense of
the pipeline industry. But I think we all win.
Senator Pryor. Did you want to?
Mr. D'Alessandro. When you look at the PIPES Act and the
impact it had on the distribution companies, PHMSA's been
straightforward and fair with us, but they do enforce what they
have there. From a distribution point of view, they utilize the
state agencies on inspections and enforcements and follow-ups.
But we appreciate PHMSA--they've been straightforward.
They're strict on their rules, but they share them and they're
knowledgeable, so we understand what we're walking into and
what needs to be corrected.
Senator Pryor. One last question on that, and that is that,
again, with some regulators there's not a real clear revolving
door rule or law. Do you know what the rule or law is with
PHMSA in terms of when someone can leave the agency and go to
work for a company that has business before the agency? Do you
know what the rule is on that?
[No response.]
Senator Pryor. Do people in the industry routinely hire ex-
employees of PHMSA?
Mr. Felt. I wouldn't say routinely. I am aware that it's
happened. I think--and it's just anecdotal, but I think it's
just as easily seen where they hire people with experience in
the industry to help them better assess and inspect, and that
has been the experience I've seen. A lot of the people that are
working at the inspector level have got prior first-hand
experience in the industry.
Mr. Sypolt. Senator, I would agree with Mr. Felt. It
typically goes that they hire people from the industry rather
than the industry hires people from PHMSA.
Senator Pryor. Thank you, Mr. Chairman.
Senator Lautenberg. Senator Vitter.

STATEMENT OF HON. DAVID VITTER,
U.S. SENATOR FROM LOUISIANA

Senator Vitter. Thank you, Mr. Chairman.
A couple of questions. For the whole panel: If you look at
serious incidents, particularly those that cause injury or
death, what are the top categories of causes related to those
serious incidents? I assume corrosion is on that short list. I
know that was a factor in an explosion that caused a death in
Louisiana several years ago. Is that on the short list? What
else would be on the short list?
Mr. Sypolt. Outside excavation, Senator, is the largest
impact. Corrosion is on that list, but it's pretty far down,
down the list. But outside excavation would be the greatest
impact.
Senator Vitter. What else would be high on the list?
Anybody?
Mr. Felt. I believe equipment failure is probably high on
the list, too. But I would have to say that the third party or
excavation damage, the reason it's so high on the list is
because you probably--first of all, you're not prepared for it.
That's why it occurs. There's no warning when it happens. And
you've probably got an operating piece of equipment involved.
So it's not so much that you have the release of gas or
gasoline; it's that you have an ignition source right there at
the time. I think that's what contributes to the severity of
the incidents.
Mr. D'Alessandro. The key in excavation damage, it's pretty
broad. The number one issue on excavation damage is people not
using 811 and making that first call. The second thing is, once
the lines are marked, there's proper construction that still
has to be done around the pipes to secure them. That's the
number two issue.
The number third issue on excavation damage is really
mislocating, the locate is not within the 18 inches and it's
mismarked.
Senator Vitter. Then the second question is about offshore
pipelines in particular, which are obviously significant off
Louisiana. What role does PHMSA play in regulating offshore
pipelines, first of all, generally speaking?
Mr. Felt. Sir, I think that PHMSA would be the best people
to ask. I don't have offshore pipelines, but I did hear Ms.
Quarterman talk about the fact that they do have some authority
within--I can't remember how many miles of the shoreline. So
there's probably some transition between OPS or PHMSA and MMS,
and they'd probably be better able to answer that.
Senator Vitter. Maybe I'll go back to them with the
question.
Anyone have any direct perspective on that? Do any of you
have offshore pipelines?
[No response.]
Senator Vitter. Thank you, Mr. Chairman.
Senator Lautenberg. Thank you, Senator Vitter.
You know, I respect so much the fact that safety has been
improved over these years, but nevertheless we have a question
here about the number of accidents since 2006. Not a question,
but there still were 58 deaths since 2006, $900 million in
damages. So the mission is to get that down to an even lower
level, and I'm sure all of you agree with me. I just bring that
to your attention so that we can continue to look at the
possibilities and--this is not intended to be a threat, but at
regulation perhaps, or rules that can make it even safer. I
know that all of you would like that to occur.
The number of inspectors. Mr. Weimer, we've had an increase
from 2007 of about 40 inspectors. With that, do you have
knowledge or an idea as to whether or not we have enough people
out there to look at these things? I hear of going to the
cornfields and other very difficult places to find the
location. Do we have enough people out there to do the job, do
you think?
Mr. Weimer. Probably a good question for PHMSA. From our
perspective, there has been significant progress made because
of the PIPES Act to hire more inspectors. They've had some
problems actually getting those inspectors hired and out in the
field. I was glad to hear Ms. Quarterman talk about their
expedited efforts to get those inspectors actually hired and
fill those positions.
In the State of Washington, after the pipeline explosion in
Bellingham that killed three children, the State of Washington
looked at that and decided that the number of inspectors that
were available from the Western Region of OPS was not adequate
for what they wanted to do in the State of Washington. So they
got the authority to do their own inspections in Washington and
hired I think eight inspectors just for the State of
Washington, which was far more than PHMSA could provide, to
provide better inspections. Other states have made those same
decisions.
Senator Lautenberg. We'll have to look at that, because
again safety being the primary issue of today's hearing. The
fact is we want to make sure that we have the tools on the
government side to do what we have to do to ensure as much
protection as possible.
PHMSA and the Federal Energy Regulatory Commission both
bear responsibility for regulating the development of new
natural gas pipelines. How can this cooperation be improved to
make sure that the public has the necessary information on the
impact of a pipeline to their community and the impact--there
will be those proposing what the economic result might be, but
the fact of the matter is that the safety factor being what it
is--who is principally responsible in your view, and how can
that collaboration be improved--between these two agencies?
Mr. Sypolt. Mr. Chairman, PHMSA does certainly come out on
the construction of new pipelines. How does the public--I
believe that was your question, how do they find out about
these pipelines and the safety of them? FERC actually holds
public awareness meetings or public meetings on projects in
various communities along the pipeline route, where those type
discussions do occur. The pipelines are there present, FERC is
there present, and there's a ton of information given regarding
the construction process, and there are--on INGAA websites
there are many slides that actually explain the construction
process as well.
So people have access to that. But during the construction
process itself, PHMSA comes out for inspection during the
construction, sir.
Senator Lautenberg. So the responsibility lies primarily
there.
One of the things that I've worked on since I've pretty
much been in the Senate, and that is guaranteeing that the
public has a right to know about what's in their area in terms
of chemicals or emissions, etcetera. I wonder how we can
improve the public's awareness of what's in their area and
raise their consciousness to a level so that they an submit
questions if they have any to make sure that they're
appropriately protected.
Mr. Weimer. Well, Mr. Chairman, if I can take a crack at
that one. That's certainly one of our large issues, too, to
make sure as much information is available as possible, because
I think that makes everything safer. Even talking about the
issue you just raised the question about during siting, for gas
pipelines you have FERC and PHMSA working together. With liquid
pipelines, it's even more complicated because you may have the
Department of State or you may have states trying to do it, and
there seems to be a disconnect between the safety issues and
the siting issues, especially when it comes to information
available for people that are trying to decide if a pipeline
through their area is safe, because often PHMSA grants special
waivers or special permits for things to do with pipelines.
They have spill response plan responsibilities. They designate
high consequence areas in places. Lots of those processes are
either somewhat secret from even local governments, like high
consequence areas, or they're done after the fact as the EIS is
moving through for the siting.
So somehow to better coordinate so those processes that
PHMSA is in charge of are actually integrated into the EIS's
that the states or that the Department of State or FERC are
doing would be one way.
There are lots of other things. One of the things that
we're really looking for and we understand that PHMSA is
working on now is inspection transparency, so people in
communities can look to see specific companies, what have they
been inspected for, what was found, what was done. My
understanding is you'll see PHMSA coming out with a website
that will let individuals and communities be able to do that.
We think that would be a great step forward.
Senator Lautenberg. One of the things that happened in my
State of New Jersey, that big accident took place in 1994 and
that raised the recognition. I think that those of you who have
cause to put down new pipelines in the State of New Jersey know
that there's a very interested public in what you're about to
do. So we have an inspection team out there of citizens who are
concerned about themselves, their families, and their
community.
I want to thank you each, all of you who testified here on
this panel, for a degree of consciousness that you bring to the
problem and how you hold safety as a principle factor. Please
continue to do that.
We'll keep the record open for a bit so that any questions
that may not have been asked and want to be asked will be
submitted, and we would ask your prompt response, hopefully
within a week of the time that you get the questions.
Thank you, and this hearing is adjourned.
[Whereupon, at 4:19 p.m., the hearing was adjourned.]

A P P E N D I X

Response to Written Questions Submitted by Hon. John D. Rockefeller IV
to Hon. Cynthia L. Quarterman

Question 1. What has PHMSA found in its evaluations of companies'
oil spill response plans and what additional enforcement mechanisms
does PHMSA need to make sure companies develop adequate plans? Are
companies' response plans available to the public?
Answer. PHMSA ensures that oil response plans meet all applicable
regulatory requirements of 49 CFR Part 194 before it approves them.
After an operator submits a proposed plan, PHMSA reviews it fully. If a
plan does not meet all the applicable regulatory requirements, PHMSA
works with the operator to revise the plan and correct any
deficiencies. PHMSA has reviewed approximately 450 response plans and
has ensured that they all meet regulatory requirements. Response plans
generally include:

Procedures and a list of resources for responding, to the
maximum extent practicable, to a worst case discharge and to a
substantial threat of such a discharge;

Certification that the response plan is consistent with the
National Contingency Plan and specific elements of each
applicable Area Contingency Plan;

A core plan with:

An information summary,

Immediate notification procedures,

Spill detection and mitigation procedures,

Contact information for the oil spill response
organization (OSRO),

Contact information for Federal, State, and local
agencies that the operator expects to have pollution
control responsibilities or support,

Training procedures,

Equipment testing,

A drill plan that satisfies, or is equivalent to
provisions of, the National Preparedness for Response
Exercise Program (PREP), and

Plan review and revision procedures;

An appendix for each response zone included in the plan. If
the plan only covers one response zone, then this section is a
single summary of specific information from the core plan; and

A detailed description of the operator's response management
system that includes a clearly defined chain of command and
identifies sufficient trained personnel to fill each position.

To date, PHMSA has not received reports from response agencies
(e.g., USCG or EPA) indicating that PHMSA-approved plans have been
inadequate during actual pipeline incidents and releases. On June 30,
2010, PHMSA issued an Advisory Bulletin reminding operators of onshore
oil pipeline facilities that they must conduct a review of their oil
spill response plans and submit any updates to their oil spill response
plans as set forth in 194.121 within 30 days.
PHMSA will continue to work with other Federal approving agencies
to strengthen the standards and processes for its response plan review
to ensure that plans adequately address spill risk. PHMSA is planning
an oil spill response plan benchmark study with other Federal agencies.
The study will review how other Federal agencies administer oil spill
planning, preparedness and recovery operations.
PHMSA, through the Secretary of Transportation, needs to have the
authority to enforce Part 194 of the regulations through civil
penalties. PHMSA urges Congress to amend 33 U.S.C. 1321(b)(6)(A) to
provide it with this authority by indicating that agencies who issue
regulations pursuant to 33 U.S.C. 1321 have authority to enforce those
regulations.
Facility oil spill response plans submitted to PHMSA are available
to the public through Freedom of Information Act (FOIA) requests.
Individual operators may also make these plans available on their
websites or as requested by the public.

Question 2. In light of the catastrophic consequences from the
recent oil spill in the Gulf of Mexico, what steps is PHMSA taking to
make sure it is providing sufficient oversight of the offshore
pipelines under its jurisdiction? What additional requirements does
PHMSA apply to offshore pipes than it does for onshore pipes to prevent
such environmental disasters?
Answer. Since the Deepwater Horizon oil spill, PHMSA has reviewed
its inspection records for operators of offshore transportation
pipelines subject to PHMSA's jurisdiction. It has verified that the
facilities of all such operators have been inspected within the past 3
years or are scheduled for inspection this calendar year. PHMSA has
reviewed accident and incident report data to identify risks that may
be unique to offshore pipelines. This review indicates that the
offshore accident rate for offshore liquid pipelines is below the per-
mile average for onshore liquid pipelines. In addition, PHMSA has
identified certain regulatory actions that should be taken, and that it
intends to take, to improve its oversight of offshore facilities.
PHMSA applies the same corrosion control and integrity management
requirements to both onshore and offshore pipelines. Offshore gas
pipelines, however, have a higher rate of corrosion failure than
onshore pipelines. PHMSA regulations include additional inspection and
reburial requirements for pipelines located in shallow waters of the
Gulf of Mexico that could pose a hazard to navigation. Finally, PHMSA
is considering whether additional or different regulatory requirements
should be made for offshore pipelines.

Question 3. Integrity Management Plans are currently only required
for High Consequence Areas, which cover a limited amount of pipeline
mileage. Is this requirement sufficient, or should Integrity Management
Plans be expanded to cover a wider portion of pipelines?
Answer. Integrity Management (IM) programs have significantly
increased safety in High Consequence Areas (HCAs) by ensuring that
operators identify potentially dangerous anomalies and by increasing
operators' knowledge about the condition of their pipelines.
IM programs help focus operator resources on the areas of greatest
risk to the public and the environment. The IM regulations complement
and are in addition to PHMSA's baseline prescriptive safety
requirements. All operators must comply with PHMSA's prescriptive
regulations for any pipelines that fall within PHMSA's jurisdiction. In
addition to these baseline regulations, operators must maintain IM
programs uniquely suited to address the risks confronting the HCAs on
each of their pipelines.
The current IM requirements provide protection that extends beyond
just HCAs. While operators are only required to assess the pipeline
segments that can affect HCAs (approximately 44 percent of the Nation's
pipeline mileage), they have actually ``smart pigged,'' pressure
tested, or otherwise assessed a far greater proportion (approximately
86 percent) of the total hazardous liquid pipeline mileage. This has
increased pipeline safety in locations well beyond the HCAs.
PHMSA intends to review the current rules to determine whether IM
requirements should be applied beyond HCAs and, if so, to what extent.

Question 4. Please describe the process PHMSA uses to inspect the
integrity and safety of pipe used for pipeline construction. Is this
process the same for domestic and imported pipe?
Answer. PHMSA ensures pipe quality through constructionsite
inspections during pipeline installation. Inspections evaluate
installation practices including welding, materials documentation, and
leak and strength tests of the pipe at the conclusion of pipeline
installation. The final documentation of pipe serviceability prior to
placing a pipeline into service is the PHMSA-mandated hydrostatic test,
during which the pipeline is tested at a pressure higher than it will
ever experience during its service life.
PHMSA regulations reference the professional standard for line
pipe, American Petroleum Institute (API) standard 5L. API standard 5L
provides manufacturing standards for pipe used in the oil and natural
gas industry. PHMSA inspections include reviews of pipe testing data
and certifications that document pipe conformity with the manufacturing
standards. Any pipe, whether domestic or imported, used in a pipeline
system under PHMSA's jurisdiction must comply with these provisions.
PHMSA takes a proactive approach when it learns of material quality
issues, including line pipe issues. In late 2008, in the course of
field inspections, PHMSA discovered a potential issue with steel pipe
quality when isolated failures occurred in the field during hydrostatic
testing. PHMSA immediately implemented requirements for determining the
extent of the problem with the operator involved and for removing low
strength pipe from the pipeline system. When PHMSA discovered a second
operator with similar issues, PHMSA issued a safety Advisory Bulletin
to the public in May 2009, alerting all pipeline operators to the
potential issue and recommending practices to ensure that purchased
pipe met PHMSA requirements. PHMSA also later published interim
guidelines providing specific steps operators may take to check for
pipe quality issues. In taking action on the pipe quality issue, PHMSA
acknowledged that although the issue appeared to be isolated to high
grade steels (X70 and X80), action needed to be taken to prevent a
recurrence or a more widespread problem.

Question 5. When a company submits a waiver to construct a pipeline
using pipe that does not meet regulatory requirements, what steps does
PHMSA take to ensure the integrity and safety of the pipe?
Answer. The Federal Pipeline Safety Statute (49 U.S.C. 60118)
permits the Office of Pipeline Safety to waive regulatory requirements
by issuing special permits. PHMSA issues a special permit only after
completing a review that shows that waiver of the regulations will not
compromise public safety. Typically, an operator that requests a
special permit must take measures to mitigate any adverse consequences
of non-compliance with the regulations. Such measures may include but
are not limited to:

Operating pipelines at reduced pressures;

Providing additional cathodic and corrosion protection;

Monitoring pipelines more frequently (e.g., by aerial or
foot patrols);

Installing pipeline instruments that continuously monitor
pipeline pressures;

Installing high and low pressure alarms and automatic
shutdown devices to prevent pipeline failure; and

Carrying out detection and monitoring activities designed to
discover the release of oil.
______

Response to Written Question Submitted by Hon. Frank R. Lautenberg to
Hon. Cynthia L. Quarterman

Question. The BP oil spill in the Gulf of Mexico showed the
disastrous consequences that can occur when a Federal oversight agency
fails to do its job. Are you confident that PHMSA's inspectors are
performing unbiased inspections and that the agency is performing the
necessary level of oversight of our Nation's pipelines?
Answer. PHMSA is confident that its inspections are unbiased and
adequate, and that PHMSA is using all the necessary tools to oversee
the Nation's pipelines. Most PHMSA inspectors are engineers or have
obtained technical college or graduate degrees. All pipeline inspectors
also receive extensive formal and informal training prior to performing
inspections. PHMSA requires all its inspectors to be certified via a
three-year training course. PHMSA inspects pipelines at all phases of
construction and operation. PHMSA inspects new pipeline construction.
These inspections are typically highly resource intensive over a short
time span. PHMSA inspectors examine everything from the design to
construction to initial operation. PHMSA regularly inspects the
operating pipelines under its jurisdiction. PHMSA inspects each
pipeline operator once every 3 years on average. State partners also
assist PHMSA to oversee the Nation's pipelines. PHMSA has a detailed
program to verify that its State partners are performing adequately.
PHMSA conducts targeted inspections to ensure that operators who are
granted special permits are complying with them. PHMSA's enforcement
record demonstrates the success of its inspection program. PHMSA issue
on average 230 enforcement actions per year, and its collection rate on
assessed penalties is 99 percent.
To ensure that PHMSA's inspectors carry out unbiased inspections,
PHMSA requires every inspector to file a financial disclosure report
listing all financial interests and outside activities that could
create a conflict of interest, or the appearance of a conflict of
interest, with the inspector's job responsibilities. This way, PHMSA
ensures that its inspectors are free from any potential conflicts of
interest. In addition, PHMSA provides ethics training to all new hires
as well as annual refresher training for all inspectors. PHMSA also
sends out periodic informational bulletins on relevant topics such as
gift restrictions, avoiding appearances of impropriety, and how to
ensure impartiality and integrity when performing one's job. One such
ethics bulletin specifically addressed the allegations related to the
Federal oversight agency relating to the BP spill.
______

Response to Written Questions Submitted by Hon. Mark Pryor to
Hon. Cynthia L. Quarterman

Question 1. What is the approval process for new trans-national oil
pipeline like the Keystone XL pipeline project from Alberta, Canada to
Houston and Port Arthur?
Answer. Executive Order 13337 authorizes the U.S. Department of
State (DOS) to receive applications and issue Presidential permits for
the construction, connection, operation, or maintenance of certain
facilities (including oil pipelines) at the national borders.
Presidential permit applications require a DOS project assessment
pursuant to the National Environmental Policy Act (NEPA) and Section
106 of the National Historic Preservation Act (NHPA), as well as an
interagency National Interest Determination review. DOS typically
requests relevant Federal agencies, including the Department of
Transportation (DOT), to submit their opinions during this process.
PHMSA has provided assistance to the DOS on technical pipeline matters
with respect to the Keystone XL project. DOS may also coordinate with
affected state and local agencies. Additional applications and
approvals may be needed depending on state and local laws. Approvals
through The National Energy Board (NEB) of Canada are required to
construct and operate the Canadian portion of these lines.
Keystone XL has requested a special permit from PHMSA to deviate
from the design factors in the regulations (49 CFR 195.106). As part
of PHMSA's review of the special permit request, PHMSA is conducting
its own environmental assessment (EA) in accordance with DOT Order
5610.1C; the National Environmental Policy Act (NEPA), 42 U.S.C.
4321-4375; and the Council on Environmental Quality regulations, 40 CFR
1500-1508. The purpose of the EA is to assess whether granting a
special permit would have a significant impact on the environment.
Other agencies with which Keystone XL filed applications include:

The U.S. Bureau of Land Management, for a grant of right-of-
way and temporary use permit allowing construction and
operation of the pipeline project across certain Federal lands;

The Montana Department of Environmental Quality, for a
certificate under the Montana Major Facilities Siting Act; and

The South Dakota Public Utilities Commission, for a permit
under the South Dakota Energy Conversion and Transmission
Facility Act.

Question 2. Do you know the status of the Keystone XL pipeline
project at the Department of State and other relevant agencies?
Answer. The DOS environmental review of the project under NEPA is
ongoing. On April 16, 2010, a draft Environmental Impact Statement
(DEIS) was published for public comment. The comment period for the
DEIS ended July 2. DOS is currently compiling and responding to the
comments, which will inform the Final Environmental Impact Statement
(FEIS). The DOS inter-agency National Interest Determination review is
underway for 90 days beginning June 16. At the end of the formal EIS
and National Interest periods, DOS will decide whether to issue the
permit and will inform the agencies by Executive Secretariat memo of
that decision.
PHMSA's review of the special permit request and related EA is also
ongoing. PHMSA intends to publish draft versions of the special permit
analysis and findings as well as the EA, and to provide a 30-day public
comment period prior to making a final decision.
With respect to other agencies, TransCanada filed its section 52
application with the National Energy Board and received approval on
March 11, 2010 to construct and operate the Canadian portion of the
Keystone XL.
TransCanada filed an application with the U.S. Bureau of Land
Management for a grant of right-of-way and temporary use permit that
would allow construction and operation of the pipeline across certain
Federal lands. The application is currently under review by the agency.
TransCanada filed an application with the Montana Department of
Environmental Quality for a certificate under the Montana Major
Facilities Siting Act. The application is currently under review by the
agency.
TransCanada filed an application for with the South Dakota Public
Utilities Commission for a permit under the South Dakota Energy
Conversion and Transmission Facility Act and received approval on March
11, 2010.

Question 3. What regulatory authority will PHMSA have during its
construction and through the life of its use?
Answer. Once the State Department has approved the siting, PHMSA
will have the statutory authority to regulate the design, construction,
operation, and maintenance of the Keystone XL pipeline to protect
public safety and the environment. PHMSA's regulations cover the full
pipeline life cycle, and PHMSA engineers will conduct inspections to
carry out its responsibilities.
49 CFR Part 195 prescribes safety standards and reporting
requirements for pipeline facilities used in the transportation of
hazardous liquids. 49 CFR Part 195, Subpart C prescribes minimum design
requirements for new pipeline systems constructed with steel pipe. 49
CFR Part 195, Subpart D prescribes minimum requirements for
constructing new pipeline systems with steel pipe.
PHMSA's responsibility in pipeline construction is to ensure that
the pipeline will operate safely once it is placed in service. PHMSA
inspects pipeline construction to ensure compliance with these
requirements. Inspectors review operator-prepared construction
procedures to verify that they conform to regulatory requirements.
Inspectors then observe construction activities in the field to ensure
that they are conducted in accordance with the procedures. Additional
inspections occur once a pipeline is in service and throughout its
lifetime to confirm that it is being operated and maintained in
accordance with 49 CFR Subpart F. Additional Subparts of Part 195 that
subject operators to inspection and enforcement include Subpart B
(Annual, Accident, and Safety Related Condition Reporting), Subpart E
(Pressure Testing), Subpart G (Qualification of Pipeline Personnel),
and Subpart H (Corrosion Control).

Question 4. How would you describe the relationship between PHMSA
and the oil and gas industry? Do you believe there is a revolving door
problem between PHMSA and the oil and gas industry that needs to be
addressed?
Answer. As a safety oversight and enforcement agency, PHMSA
maintains a professional relationship with the oil and gas industry.
PHMSA does not have a revolving door. Some of PHMSA's personnel do have
experience in the oil and gas industry. PHMSA has found that their
experience enables them to identify safety and compliance issues. As
inspectors and accident investigators, PHMSA's personnel see first-hand
the tragic results of safety shortcuts and non-compliance and have
little patience for operators who endanger the public and the
environment.

Question 5. Does PHMSA have adequate resources (inspectors) to
carry out its authorized goals?
Answer. Yes. The additional inspection and enforcement positions
that Congress authorized in Fiscal Years 2009 and 2010 provide PHMSA
with an adequate number of pipeline safety inspectors. These positions
have enabled PHMSA to conduct a wider range of pipeline inspections.

Question 6. Do exemption requirements for one-call systems in
states weaken the effectiveness of these programs?
Answer. Yes. Effective damage prevention programs involve active
participation and accountability for all stakeholders. However, limited
exemptions based on the type of excavation activities, such as
agricultural tilling or gardening to a minimal depth with hand tools,
are often included in state one-call laws, and do not generally
represent a threat to safety. The risks to public safety and the
pipeline infrastructure are greater when groups of stakeholders, such
as municipalities or state DOTs, have blanket exemptions from
participating in the one-call process. PHMSA strongly supports the
elimination of such exemptions and continues to work with the states to
help them strengthen laws and promote fair, balanced, and inclusive
one-call programs.

Question 7. Are existing penalties for safety violations adequate
for pushing industry to focus on safety over revenue?
Answer. Existing penalty levels have largely been effective. That
said, PHMSA has been issuing penalties at the top limit of its
authority. Increased civil penalty levels would be helpful in certain
situations for additional deterrent effect.

Question 8. Should PHMSA have more authority to regulate offshore
pipelines?
Answer. No. PHMSA's authority to regulate offshore transportation
pipelines is complemented by the Bureau of Ocean Energy Management's
authority over production on the Outer Continental Shelf and State
agencies' authority over production in State waters.

Question 9. How is PHMSA prepared to respond to a major pipeline
failure caused by a natural disaster, manmade disaster, or terrorist
attack? (New Madrid)
Answer. When a significant interstate pipeline incident occurs,
PHMSA inspectors are dispatched from their respective Regional Office
to investigate the cause of the failure. They monitor effects of
response operations on pipelines that may be involved or near to the
incident. They determine if there were violations of the Pipeline
Safety Regulations that contributed to the incident. They ensure that
an operator's repair procedures provide an adequate level of safety as
they restore the line to service. In some cases, investigators from
Headquarters or other Regional Offices are deployed to assist if their
specific expertise is necessary. PHMSA has a highly trained and
experienced inspector force of over 100, most of whom are engineers.
When incidents occur in natural gas distribution systems, PHMSA's
State partners usually lead the pipeline safety investigation. PHMSA
will, in some situations, assist in those investigations. PHMSA
supports State-level pipeline safety programs in 48 states and the
District of Columbia through Grants-in-Aid. PHMSA's State partners
generally enforce State laws concerning intrastate natural gas
distribution and master meter systems. In a limited number of cases,
State partner agencies also inspect interstate hazardous liquid
pipeline systems, such as those that transport crude and refined oil
products, as part of their grant agreement. When a pipeline incident
involves a spill of either crude or refined oil, PHMSA works with the
Federal On-Scene Coordinator (usually an official from the U.S.
Environmental Protection Agency or the U.S. Coast Guard) to ensure that
the operator mounts a rapid, efficient spill response operation, even
as PHMSA oversees the operator as it works to repair and restore its
pipeline to service.
When an event involves many Federal, State, and local agencies,
PHMSA provides technical support through Emergency Support Function
(ESF) #1 (Transportation) and ESF #12 (Energy), consistent with the
conduct of operations under the National Response Framework. If the
event or significant consequences of the event are pipeline-related,
PHMSA provides direct assistance to the Incident Commander, as the
Pipeline Operations Branch of the Operations Division. PHMSA's
representatives participate as technical experts concerning pipeline
operations, response options, and consequence management within the
Integrated Command Structure of the incident.
In addition to incidents in which PHMSA directly oversees a
pipeline operator's response to an incident, repair procedures, and
eventual restoration of services, PHMSA has successfully operated in a
wide range of incidents, including those of caused by criminal acts.
PHMSA has routinely participated as a party in incident investigations
under primary NTSB jurisdiction in coordination with the Chemical
Safety and Hazard Analysis Board and others.
PHMSA worked closely with the Transportation Security
Administration for the past 2 years to develop protocols involving the
FBI, TSA and other DHS elements, and the Department of Energy on
coordinating the Federal response to threats to pipelines.

Question 10. What do you believe should be the top priorities for
PHMSA in light of the recent BP disaster?
Answer. One of PHMSA's top priorities is to recruit and retain
America's brightest individuals to help oversee the Nation's pipeline
energy supply systems and help safeguard the public and the
environment. PHMSA must continue to work with all stakeholders to
address the causes of pipeline failure, including excavation damage and
corrosion. PHMSA must continue to support PHMSA's State partners, who
make up a significant portion of the pipeline safety workforce and who
can focus on local needs and concerns. PHMSA must promote research and
development into better ways to assess and assure pipeline safety. In
addition to those priorities, PHMSA will ensure the adequacy of its
oversight of offshore pipelines and oil spill response plans.
______

Response to Written Question Submitted by Hon. Mark Begich to
Hon. Cynthia L. Quarterman

Question. Alaska and Hawaii are the only two states in the Nation
that do not have approved state pipeline safety programs. Pipelines
play a key role in safely transporting the oil and gas produced on
Alaska's North Slope, Cook Inlet, and hopefully soon the National
Petroleum Reserve-Alaska and the Chukchi and Beaufort Seas. The Trans-
Alaska Pipeline system falls under PHMSA jurisdiction as a partner
agency of the Joint Pipeline Office. Although cooperation with Alaska
appears to be improving, the lack of a strong state pipeline program is
still a problem because all these systems connect. It also paces
unusual resource burdens on PHMSA in Alaska. The low stress pipeline
spill on the North Slope in 2006 is one example of the outcomes of
inadequate oversight. It is my understanding that PHMSA assists states
with cost-sharing grants for pipeline safety programs. What steps is
PHMSA taking to encourage the State of Alaska to get an approved
Pipeline Safety program in place?
Answer. PHMSA has a long history of encouraging Alaska to enter the
pipeline safety program and has met repeatedly with various
stakeholders in Alaska to discuss the benefits of a state program.
PHMSA executives, as well as regional personnel, have met with Alaskan
stakeholders to highlight how such a program would help ensure public
and environmental safety and provide for an increased focus on local
issues and concerns.
PHMSA has developed a good working relationship with all of its
State and Federal partners in Alaska and has made a deliberate effort
to consistently share information on pipeline issues with them.
Although the relationship is good, PHMSA seeks a more formal
arrangement for the safety oversight of Alaska's pipelines, especially
the intrastate gas distribution pipelines that directly serve the local
public. Alaska's Governor will have to determine whether to enter into
the Federal pipeline safety program.
PHMSA notes that Alaska does currently regulate some pipelines such
as flowlines, which are also subject to certain regulatory requirements
of the EPA. PHMSA is always willing to assist Alaska with inspector
training and/or technical assistance.
______

Response to Written Questions Submitted by Hon. Kay Bailey Hutchison to
Hon. Cynthia L. Quarterman

Question 1. What recommendations do you have for the Committee with
respect to reauthorizing the pipeline safety program? When can we
expect to see a formal proposal from the Administration?
Answer. The Administration's reauthorization proposal is being
reviewed and will be transmitted in due course.

Question 2. Pipeline operators are working to design and build
pipelines to make transportation of ethanol and ethanol blended fuels
by pipeline feasible. PHMSA has indicated that its research shows that
it is safe to move gasoline blends with ethanol up to 10 percent, but
that at higher blend levels, questions remain because of stress
corrosion cracking. Why does a higher concentration of ethanol cause
more safety problems?
Answer. High concentrations of ethanol threaten the integrity of
storage tanks, line pipe, and valves because ethanol is highly
oxygenated, and oxygen causes corrosion. The use of higher ethanol fuel
mixtures (e.g., 85 percent ethanol (E85) and Fuel Grade Ethanol (95
percent ethanol, or E95)) causes ethanol stress corrosion cracking.
Non-metallic pipeline components such as seals and other elastomers
swell in the presence of ethanol. If there is an ethanol fuel fire,
alcohol resistant foams are needed to suppress the fire. PHMSA has a
comprehensive and collaborative research strategy to address ethanol
pipeline challenges.

Question 3. What more can be done to prevent pipeline damage caused
by hurricane damage? Is any additional Federal authority needed to
allow such damage to be addressed quickly by pipeline operators?
Answer. PHMSA supports H.R. 5629, the Oil Spill Accountability and
Environmental Protection Act of 2010, which would require pipeline
operators to notify the Secretary of Transportation of any changes in
the operational status of their facilities following a hurricane or
other manmade or natural disaster. The proposed bill would also require
operators to submit damage assessments to the Secretary of
Transportation within 30 days after the end of a hurricane or other
manmade or natural disaster. Otherwise, PHMSA believes its regulations
adequately address damage to pipelines caused by hurricanes by ensuring
proper design, materials selection, operations, and regular
maintenance. Facilities designed and operated in accordance with PHMSA
regulations are expected to survive those forces and conditions likely
to be posed by most storms and to be able to resume operations after
conditions return to normal.

Question 4. Under the Oil Pollution Act of 1990, PHMSA has been
delegated authority over onshore oil spill response plans, but does not
have enforcement authority regarding compliance. Instead, PHMSA must
refer non-compliance cases to the Coast Guard for appropriate
enforcement. Does it make sense to you that the Coast Guard, rather
than PHMSA, has enforcement authority over onshore pipelines? Do you
recommend that Congress shift that authority to PHMSA?
Answer. At the time that the Oil Pollution Act was passed, the U.S.
Coast Guard was part of the Department of Transportation, which meant
regulation and enforcement were both delegated to the Secretary of
Transportation. Now that the U.S. Coast Guard is part of the Department
of Homeland Security, enforcement is more difficult to coordinate.
PHMSA, through the Secretary of Transportation, needs to have the
authority to enforce Part 194 of the regulations through civil
penalties. PHMSA urges Congress to amend 33 U.S.C. 1321(b)(6)(A) to
provide it with this authority, as proposed by H.R. 5629, the Oil Spill
Accountability and Environmental Protection Act of 2010.

Question 5. According to PHMSA, Texas is the only state that
regulates off-shore production pipelines. Do you believe other States
should be more pro-active in this area?
Answer. PHMSA has traditionally allowed the states to regulate
offshore production pipelines in state waters. States, including Texas,
California, Alabama, and Mississippi, regulate some pipelines in their
waters. Those regulations vary from jurisdiction to jurisdiction. The
interpretation and application of those regulations are matters of
state and local law. That said, PHMSA reserves the right to regulate
offshore production lines in state waters as a matter of Federal law.
PHMSA is currently reviewing the extent to which states are regulating
pipelines in their waters.

Question 6. What impact does the spill in the Gulf have on PHMSA's
safety priorities? Has it prompted your agency to conduct a review of
the safety of off-shore pipelines?
Answer. Since the Deepwater Horizon oil spill, PHMSA has reviewed
its inspection records for operators of offshore transportation
pipelines subject to PHMSA's jurisdiction. It has verified that the
facilities of all such operators have been inspected within the past 3
years or are scheduled for inspection this calendar year. PHMSA has
reviewed accident and incident report data to identify risks that may
be unique to offshore pipelines. This review indicates that the
offshore accident rate for offshore liquid pipelines is below the per-
mile average for onshore liquid pipelines. In addition, PHMSA has
identified certain regulatory actions that should be taken, and that it
intends to take, to improve its oversight of offshore facilities.
PHMSA has conducted a review of its offshore pipeline safety
inspection program and is considering whether additional or different
regulatory requirements should be made for offshore transportation
pipelines and related facilities. PHMSA has identified the need to
promulgate regulations for design, construction, operation, and
maintenance of transportation regulated platforms and transportation
pipeline risers connected to offshore floating facilities. Consensus
standards are currently under revision to strengthen the design,
construction, and maintenance requirements. PHMSA is participating on
the Committees revising the standard and expects to incorporate the
standard by reference after a thorough internal review is complete. We
anticipate this initiative to update regulations will take 2 years.
PHMSA will be studying the safety oversight of offshore
transportation platforms by working with the Department of the Interior
through the 1996 Memorandum of Understanding. In addition, in the next
year, PHMSA will examine the regulations implemented by State agencies
with regulatory authority for offshore production and transportation
pipelines.

Question 7. How is integrity management applied to off-shore
pipelines? Are there special requirements?
Answer. Offshore hazardous liquid pipelines must be covered by an
integrity management program if the pipelines are in, or could affect,
a commercially navigable waterway or an unusually sensitive area, but
there are no special requirements for offshore pipelines.
Offshore gas transmission pipelines are generally not covered by
integrity management programs.

Question 8. As you know, in 2006 the U.S. Government Accountability
Office (GAO) recommended that Congress consider replacing the 7-year
fixed interval for reassessments of gas transmission pipelines with a
variable schedule based on risk. What is the Administration's position
on GAO's recommendation? When can we expect to have your
recommendation?
Answer. The current law requires a periodic reassessment of
facilities subject to Integrity Management rules. The longest permitted
interval between reassessments is once every 7 years. The
Administration is enforcing the current law.
______

Response to Written Questions Submitted by Hon. John Thune to
Hon. Cynthia L. Quarterman

Question 1. There seem to be different views on the need to
regulate production and gathering lines that connect wells together and
then transport product to a transmission line. I have two questions:
Which of these lines are regulated, and by whom (Federal or State)?
Should all of these lines be subject to safety regulation and, if not,
why not?
Answer. Hazardous Liquid and Gas Production Lines: By statute, the
Federal pipeline safety regulations cannot apply to hazardous liquid
pipelines involved with onshore production, refining, or manufacturing
facilities, and any storage or in-plant piping associated with those
facilities.\1\ These facilities and associated piping are considered
non-transportation-related pursuant to Executive Order 12777 and are
regulated by the Environmental Protection Agency (EPA).\2\
---------------------------------------------------------------------------
\1\ 49 U.S.C. 60101(a)(22).
\2\ See 40 CFR 112.
---------------------------------------------------------------------------
Offshore production pipelines on the OCS are regulated by the
Department of the Interior under the terms of a Memorandum of
Understanding with PHMSA. Offshore hazardous production pipelines in
state waters are reserved for regulation by the states as a matter of
policy.
Hazardous Liquid Gathering Lines: The Federal pipeline safety
regulations apply to all hazardous liquid gathering lines in non-rural
areas and to any pipeline segment, including a hazardous liquid
gathering line of any diameter, which crosses a commercially-navigable
waterway. However, by statute those regulations cannot apply to onshore
crude oil hazardous liquid gathering lines that are: (1) 6 inches or
less in nominal diameter, (2) operated at low pressure, and (3) located
in a rural area which is not unusually sensitive to environmental
damage.\3\
---------------------------------------------------------------------------
\3\ See 49 CFR 195.
---------------------------------------------------------------------------
Consistent with that statutory exclusion, the Federal pipeline
safety regulations only apply to certain ``regulated rural gathering
lines.'' Those lines are onshore gathering lines in rural areas that
(1) have a nominal diameter of between 6\5/8\ inches and 8\5/8\ inches;
(2) are located within \1/4\ mile of an unusually sensitive areas; and
(3) operate at a stress level greater than 20 percent of specified
minimum yield strength (SMYS).
Offshore hazardous liquid gathering lines on the OCS are either
regulated by the Department of the Interior (producer-operated lines)
or PHMSA (transporter-operated lines). Offshore hazardous liquid
gathering lines in state waters are reserved for regulation by the
states as a matter of policy.
Gas Gathering Lines: PHMSA regulates most gas gathering lines.
Congress authorized Federal regulation of gas gathering lines based
largely on the physical and functional characteristics of those lines,
including their location, distance from the wellhead, operating
pressure, throughput, and composition of the transported gas.
Consistent with those requirements, the Federal pipeline safety
regulations do not apply to the onshore gathering of gas: (1) through a
pipeline that operates by gravity, (2) through a pipeline that does not
meet the definition of a ``regulated onshore gathering line,'' and (3)
within the inlets of the Gulf of Mexico, except for certain underwater
inspection and reburial requirements.
There are two categories of ``regulated onshore gathering lines''
for purposes of the Federal pipeline safety regulations. The first are
Type A regulated onshore gathering lines, i.e., metallic lines whose
maximum allowable operating pressure (MAOP) is 20 percent or more of
specified minimum yield strength (SMYS) and nonmetallic lines with an
MAOP of more than 125 psig that are in a Class 2, Class 3, or Class 4
location. The second are Type B gathering lines, i.e., metallic lines
whose MAOP is less than 20 percent of SMYS and nonmetallic lines with
an MAOP of 125 psig or less, which are in a Class 2 location (as
determined under one of three formulas) or in a Class 3 or 4 location.
These two categories of gathering lines are subject to different
requirements as specified further in the pipeline safety regulations.
Onshore gas gathering lines in Class 1 locations are not subject to the
requirements for ``regulated onshore gas gathering lines.''
Offshore gas gathering lines on the OCS are either regulated by the
Department of the Interior (producer-operated) or PHMSA (transporter-
operated).
Offshore gas gathering lines in state waters are reserved for
regulation by the states as a matter of policy.
Further Regulation: PHMSA believes that the production and
gathering of hazardous liquids and gas by pipeline should be subject to
effective safety regulations. The agency has sought to achieve that
objective in a manner consistent with the pipeline safety laws and is
currently reviewing whether additional or more stringent regulation of
these activities is appropriate. However, PHMSA cannot regulate a
pipeline that is excluded from the scope of its authority by statute,
and the agency is willing to work Congress in determining whether any
of these restrictions should be repealed or modified.

Question 2. At the recent pipeline safety hearing before the House
Transportation and Infrastructure Committee, you mentioned that oil
pipelines must have an oil spill response program, but that there is no
similar requirement for natural gas pipelines. What other significant
differences exist between oil and gas pipeline regulations?
Answer. PHMSA is currently completing a comprehensive assessment of
the differences between the regulations for gas and oil pipelines, and
evaluating whether any of these differences suggest significant
opportunities to improve current regulations.
While this study has not been completed, early results suggest that
major differences in the regulations are a result of differences in the
properties of the materials being transported. For example, natural gas
is lighter than air and therefore disperses in the atmosphere following
release from a pipeline, alleviating the need for a ``spill response
plan'' in addition to the required emergency response plan.
Other differences (not all of which are significant) between oil
and gas regulations that PHMSA is examining include:

Numerous differences in integrity management program
regulations. Most derive from differences in the properties of
the materials being transported (e.g., the definition of High
Consequence Area), though some do not (e.g., differences in the
required timeframe for remediation of defects identified by
required assessments). For integrity management inspections,
the maximum time interval allowed between pipeline segment
inspections is 5 years for hazardous liquid pipelines and 7
years for gas pipelines.

Gas pipeline pressure design factors are based on Class
Location, while liquid pipeline design factors are based on
physical location: onshore vs. navigable waterways and offshore
platform.

Differences in corrosion control requirements.

Differences in hydrotest requirements for oil and gas
pipelines.

Gas regulations address threaded fittings, and liquid
regulations do not.

Differences in the regulations for shut-off valves.

For burial of pipeline, the liquid regulations lack backfill
requirements.

Question 3. Can you explain for the Committee where your agency's
jurisdiction begins and where it ends?
Answer. Congress has given PHMSA jurisdiction over hazardous liquid
and gas pipeline systems. That jurisdiction includes authority over gas
and liquid transmission pipelines, certain gas and liquid gathering
lines, gas distribution pipeline systems, and liquefied natural gas
(LNG) facilities. PHMSA does not have jurisdiction over gas or liquid
production pipeline systems or hazardous liquid refining or
manufacturing facilities and any storage or in-plant pipeline
associated with these facilities.
Congress has directed PHMSA to delegate its authority to regulate
certain pipelines to State agencies that are interested and qualified
to assume that responsibility. A part of the delegated responsibility
is to assure state regulations are at least as stringent as Federal
regulations.
PHMSA has jurisdiction over onshore pipeline systems as well as
certain parts of offshore systems. Other jurisdictional agencies
sharing offshore authority include DOI, the Coast Guard, and states
with ocean or gulf borders. PHMSA has developed Memoranda of
Understanding (MOU) with individual agencies to clarify offshore
responsibilities. Under a 1996 MOU with DOI, DOI inspects the
structural integrity of offshore platforms.

Question 4. In addition to safety concerns, we must also ensure the
security of our Nation's pipelines. Please tell the Committee how PHMSA
coordinates with TSA in regards to pipeline security.
Answer. PHMSA and DHS have agreed that TSA is the lead agency in
pipeline security. PHMSA supports TSA by providing technical expertise
and access to existing intergovernmental relationships, such as PHMSA's
State pipeline safety partner agencies. PHMSA communicates frequently
with its counterparts at the TSA Transportation Sector Network
Management's Pipeline Security Division (PSD) concerning pipeline
incidents, threats to pipelines, and suspicious activities at pipeline
and energy facilities. PHMSA Inspectors have participated in TSA
Pipeline Corporate Security Reviews and Critical Facility Inspections
and in DHS' sponsored Security Reviews of Liquefied Natural Gas
facilities. PHMSA and TSA have cooperated on numerous projects
including revision of pipeline security guidelines, and more recently,
development of Security Incident Protocols that extend to the
Department of Justice, Department of the Interior, and Department of
Energy. We meet regularly in accordance with an action plan developed
in 2006 and are actively working on our joint participation in Sector
Coordinating Councils and Government Coordinating Councils in support
of the National Infrastructure Protection Plan.
______

Response to Written Questions Submitted by Hon. Mike Johanns to
Hon. Cynthia L. Quarterman

Question 1. How has your agency been involved with the development
of the Environmental Impact Statement (EIS) applicable to the Keystone
XL pipeline project?
Answer. PHMSA is acting as a cooperating agency during the
development of the EIS. Through that role PHMSA has:

Reviewed and provided comments to the State Department's
pre-draft EIS. Comments from PHMSA were primarily in the area
of pipeline safety, including description of the special permit
request and examples of draft conditions that could be imposed
if the special permit request were granted.

Shared Supplemental Information received from the operator
with the State Department.

Attended State Department Public Meetings following issuance
of the Draft EIS. For those meetings with a Q&A format, PHMSA
helped respond to questions related to pipeline safety.

Provided additional information to the State Department as
needed via e-mail, phone calls, and in-person meetings.

Question 2. Is the State Department required to involve you?
Answer. Yes. Executive Order 13337 of April 30, 2004, requires the
State Department to refer any application for a Presidential permit for
a cross-border oil pipeline to the Secretary of Transportation. The
Executive Order also requires the Secretary of State to send pertinent
information to the Secretary of Transportation and to request the
Secretary's views. Typically such communications are referred to PHMSA.

Question 3. To your knowledge, were state pipeline safety
inspection authorities involved in the Keystone XL EIS? If so, how?
Answer. Under Executive Order 13337, the Secretary of State may
consult with such State, tribal, and local government officials and
foreign governments as she deems appropriate. PHMSA is unaware of
whether state pipeline safety inspection authorities were involved. It
is PHMSA's understanding that the operator was required to file a
separate application with the South Dakota Public Utilities Commission
for a permit under the South Dakota Energy Conversion and Transmission
Facility Act and received approval on March 11, 2010. Two of the States
along the currently proposed route, Oklahoma and Texas, have authority
to regulate, inspect, and enforce liquid pipeline safety requirements
over intrastate liquid pipelines through certification by PHMSA's
Office of Pipeline Safety. In Montana, South Dakota, Nebraska, and
Kansas, PHMSA regulates, inspects, and enforces intrastate liquid
pipeline safety requirements. PHMSA has the authority to inspect,
regulate and enforce interstate liquid pipelines such as Keystone XL in
all states.

Question 4. The State Department's EIS for the Keystone XL project
lists the Department of Transportation's Office of Pipeline Safety as
an ``Assisting Agency,'' and not as a ``Cooperating Agency.'' What does
that distinction mean in terms of how the Department of State completes
its work on the EIS, and what does that distinction mean for your
involvement in the project? What activities did your office undertake,
if any, that would have differed had you been listed as a ``cooperating
agency''?
Answer. PHMSA is actually a cooperating agency on Keystone XL and
has been working with the Department of State to address the project's
pipeline safety issues. The role of a cooperating agency, as
established by the National Environmental Policy Act (NEPA) of 1969, is
to engage its staff, skills, and resources to help the lead agency with
environmental analysis, including any portions of the environmental
impact statement concerning which the cooperating agency has special
expertise. PHMSA has cooperated on those analyses for which it has
jurisdiction or special expertise with respect to the Keystone pipeline
project.
______

Response to Written Questions Submitted by Hon. Mark Pryor to
Hon. Deborah A.P. Hersman

Question 1. What are the most important NTSB recommendations
currently unaddressed?
Answer. Installation of excess flow valves (EFV) in natural gas
distribution pipeline systems has been a recommendation of the Board
for nearly 10 years (P-01-2). EFVs are installed in service lines and
mitigate gas leaks from the service line by detecting an abnormally
high flow rate. When an excess flow is detected, an EFV automatically
closes a valve, thus shutting off the flow of gas from the distribution
line to the service line.
Pipeline Hazardous Material Safety Administration's (PHMSA) current
mandate requires excess flow valves on new or replacement service lines
to single family residences only. The NTSB recommends that PHMSA
require that excess flow valves be installed in all new and renewed gas
service lines, regardless of a customer's classification, when the
operating conditions are compatible with readily available valves.
The NTSB believes that apartment buildings, other multifamily
dwellings, and commercial properties are susceptible to the same risks
from leaking gas lines as single-family residences, and we believe this
gap in the law and the regulations should be eliminated.
While the NTSB has not issued recommendations specifically
addressing either the effective oversight of risk-based assessments in
pipeline safety regulation or the regulation of low-stress pipelines,
these two areas are critical to safeguarding the integrity of our
Nation's pipeline systems.

Effective Oversight
Over the past decade or more, PHMSA has used a risk-based
assessment for regulating the DOT pipeline safety program. PHMSA has
successfully built a partnership with various facets of the pipeline
industry to develop, implement and execute a multi-part pipeline safety
program. In the NTSB's view, all stakeholders, including PHMSA, have
come to rely heavily upon this approach. The NTSB believes a risk-based
approach can work if effective oversight is exercised by PHMSA and the
pipeline operators.
The Safety Board also believes that with the risk-based assessment
come increased responsibilities for both the individual pipeline
operators and PHMSA. Operators must diligently and objectively
scrutinize the effectiveness of their programs, identify areas for
improvement, and implement corrective measures. PHMSA, as the
regulator, must also do the same in its audits of the operators'
programs and in self-assessments of its own programs. In short, both
operator and regulator need to verify whether risk-based assessments
are being executed as planned, and more importantly, whether these
programs are effective. Unfortunately, NTSB has investigated several
accidents in which ineffective oversight contributed to the pipeline
accident.

Question 2. What should Congress do to improve pipeline safety?
Answer. Over the past decade or more, PHMSA has used a risk-based
assessment for regulating pipeline safety. The pipeline safety
regulations provide the structure, content, and scope for many aspects
of the overall pipeline safety program. Within this regulatory
framework, pipeline operators have the flexibility and responsibility
to develop their individual programs and plans, determine the specific
performance standards, implement their plans and programs, and conduct
periodic self-evaluations that best fit their particular pipeline
systems. PHMSA likewise has the responsibility to review pipeline
operators' plans and programs for regulatory compliance and
effectiveness.
The NTSB believes that with the risk-based assessment approach come
important responsibilities for both the individual pipeline operators
and PHMSA. The operator and regulator need to verify whether risk-based
assessments are being executed as planned, and more importantly,
whether these programs are effective. Unfortunately, there have been
some recent pipeline investigations in which the NTSB discovered that
PHMSA and operator oversight of risk-based assessment programs,
specifically integrity management programs and public education
efforts, have been lacking and have failed to detect flaws and
weaknesses in such programs.
NTSB is concerned that the level of self-evaluation and oversight
currently being exercised is not uniformly applied by some pipeline
operators and PHMSA to ensure that the risk-based safety programs are
effective. The NTSB believes that PHMSA must establish an aggressive
oversight program that thoroughly examines each operator's decision-
making process for each element of its integrity management program.
Congress can ensure that PHMSA has the needed funding and resources
to implement an aggressive oversight program, and require that PHMSA
provide periodic analyses of its oversight program.

Question 2a. Should PHMSA have more authority to regulate offshore
pipelines?
Answer. The NTSB believes that PHMSA should have more authority to
regulate all types and categories of offshore pipelines. The regulation
of offshore pipeline systems has not been addressed in recent
legislation or regulatory action. Jurisdiction over offshore pipelines
of all types is complex and currently involves coastal states, PHMSA,
and the Department of the Interior. The jurisdictional responsibilities
are based on the location and function of a pipeline (e.g., production
versus transportation) rather than on the threat to public safety and
the environment from the petroleum and/or natural gas transported.
These jurisdictional complexities can easily lead to gaps in the
regulations and inconsistencies in pipeline safety standards, which
could be minimized if a more seamless approach to regulating offshore
pipelines is taken by giving PHMSA sole jurisdiction over all pipeline
systems located wholly or partially on the Outer Continental Shelf.
Currently, PHMSA has the most expertise at the Federal level on
pipeline safety issues, and would be best suited to work with existing
stakeholders to develop and implement a simplified and more consistent
regulatory program for offshore pipelines. PHMSA would also need the
resources to assume such expanded responsibilities.
The tragedy in the Gulf of Mexico involving the Deepwater Horizon
drilling platform is a grim reminder of the damage that a major oil
spill can cause. While the magnitude of the Deepwater Horizon spill is
far greater than any known pipeline failure, the events in the Gulf
should remind those involved in the pipeline industry that all
pipelines, offshore and onshore, must be sufficiently safeguarded and
regulated in order to protect the public and the environment.

Question 2b. What would be NTSB's role in responding to a major
pipeline failure caused by a natural disaster, manmade disaster, or
terrorist attack?
Answer. Under the NTSB's operating statute (49 U.S.C. 1131), the
NTSB is required to investigate or have investigated a pipeline
accident in which there is a fatality or substantial property damage,
or significant injury to the environment. The NTSB can also investigate
any accident that the Board decides is catastrophic or involves
problems of a recurring nature.
Major catastrophic pipeline failures caused by natural disasters do
not occur often, but can and have been investigated by the NTSB. In
September 1996 the NTSB adopted a Pipeline Special Investigation
Report--Evaluation of Pipeline Failures during Flooding and of Spill
Response Actions, San Jacinto River near Houston, Texas, October 1994,
excerpts of which are attached for your reference. The NTSB report
addressed: (1) the adequacy of Federal and industry standards on
designing pipelines in flood plains, (2) the preparedness of pipeline
operators to respond to threats to their pipelines from flooding and to
minimize the potential for product releases, and (3) the preparedness
of the Nation to minimize the consequences of petroleum releases. More
often, however, acts of nature, such as the washouts of creek and river
beds, floods, frost heaves, or lightning strikes, cause less than
catastrophic incidents. Most NTSB pipeline investigations involve
failures of designs, materials, operations, maintenance, human error
and other factors that could be identified as manmade disasters, or
attributed to some form of human interaction.
NTSB has established multi-tiered evaluation criteria that can be
applied for any pipeline accident in order to determine whether an NTSB
response is needed, and the level of response to be provided. The
criteria are based on the danger to the public (fatalities and
injuries, evacuations, etc.), property damage, and environmental
damage.
According to 49 U.S.C. 1131, the NTSB's investigation has priority
over any other investigation by another department, agency, or
instrumentality of the Federal Government with a key exception. The
NTSB must relinquish its investigative priority to the Federal Bureau
of Investigation if the Attorney General, in consultation with the
Chairman of the NTSB, determines that circumstances indicate that the
accident may have been caused by a criminal act. The NTSB may provide
technical support to the FBI, while continuing its investigation of
safety issues resulting from the accident.
______

Evaluation of Pipeline Failures During Flooding and of Spill Response
Actions, San Jacinto River near Houston, Texas, October 1994

Pipeline Special Investigation Report--Adopted: September 6, 1996--
Notation 6734

National Transportation Safety Board
Washington, DC
Executive Summary
Between October 14 and October 21, 1994, some 15 to 20 inches of
rain fell on the San Jacinto River flood plain near Houston, Texas,
resulting in dangerous flooding that far surpassed past flooding
experience in the region. The floods forced over 14,000 people to
evacuate their homes and resulted in 20 deaths.
Due to the flooding, 8 pipelines ruptured and 29 others were
undermined both at river crossings and new channels created in the
flood plain. More than 35,000 barrels (1.47 million gallons) of
petroleum and petroleum products were released into the river. Ignition
of the released products within flooded residential areas resulted in
547 people receiving (mostly minor) burn and inhalation injuries. The
spill response costs were in excess of $7 million and estimated
property damage losses were about $16 million.
With respect to this accident, the Safety Board undertook a special
investigation that focused on the following safety issues: (1) the
adequacy of Federal and industry standards on designing pipelines in
flood plains, (2) the preparedness of pipeline operators to respond to
threats to their pipelines from flooding and to minimize the potential
for product releases, and (3) the preparedness of the Nation to
minimize the consequences of petroleum releases. The report also
addresses the need for effective operational monitoring of pipelines
and for the use of remote- or automatic-operated valves to allow for
prompt detection of product releases and rapid shutdown of failed pipe
segments.
As a result of its investigation, the Safety Board makes nine
safety recommendations: one to the Research and Special Programs
Administration, five to the National Response Team, and one each to the
American Petroleum Institute, the Association of Oil Pipe Lines, and
the Interstate Natural Gas Association of America.

Introduction
Serious flooding in the San Jacinto River flood plain near Houston,
Texas, in October 1994 caused 8 pipelines to rupture and 29 others to
be undermined both at river crossings and new channels created in the
flood plain.
The high number of pipelines ruptured and damaged during this
incident, and the magnitude of the petroleum releases and spill
response efforts emphasized the threats posed to public safety and the
environment by petroleum transportation by pipeline. Although pipeline
transportation is one of the safest .means for transporting petroleum,
it poses great risk potential to the environment because of the large
volumes of hazardous liquids that can be released when a rupture
occurs.
In a pipeline transport situation, as opposed to other transport
options, there is greater likelihood of releasing petroleum into
environmentally sensitive areas. Concerns about the environmental
consequences of releases from pipelines have been expressed by the
Congress, the States, and local interests.
Because so many pipelines were damaged during this flood and such
large volumes of petroleum and petroleum products were released--
requiring a massive environmental response in terms of personnel and
equipment--the Safety Board undertook this special investigation to
assess the adequacy of Federal and industry standards on designing
pipelines in flood plains, the preparedness of pipeline operators to
respond to threats to their pipelines from flooding and to minimize the
potential for product releases, and the preparedness of the Nation to
minimize the consequences of petroleum releases.
In the course of the investigation, the Safety Board also
discovered evidence reinforcing the need for effective operational
monitoring of pipelines and for the use of remote- or automatic-
operated valves to allow for prompt detection of product releases and
rapid shutdown of failed pipe segments.

Conclusions
1. The design bases of most pipelines undermined or ruptured during
the flood did not include study of the flood plain to identify
potential threats; rather, operators used only general design criteria
applicable at the time the pipelines were installed.
2. Standards for designing pipelines across flood plains are needed
to define the multiple threats posed to pipelines and to address the
research, study, and future considerations that must be used for
designing pipelines and periodically reevaluating the integrity of
their designs during their operating life.
3. Most operators of pipelines crossing the San Jacinto River flood
plain continued operations without evaluating the capability of the
pipeline design to withstand the threats presented by the flood.
4. Few pipeline operators took effective response actions during
the San Jacinto flood to minimize the potential for product releases.
5. Pipeline operators would have been more likely to have
implemented early shutdown and/or purging of products from pipe
segments crossing the San Jacinto flood plain had the Research and
Special Programs Administration required them to develop plans for
responding to substantial threats of a pipeline failure and product
discharge.
6. The response by local, State, and Federal Government agencies to
the flood emergency was well-managed and effective.
7. Failed liquid pipelines continue to release excessive volumes of
petroleum and liquid products into the environment because the Research
and Special Programs Administration has not established requirements
for rapid detection and shutdown of failed pipe segments, and the
liquid pipeline industry has not incorporated means for rapidly
detecting, locating, and shutting down failed pipe segments.
8. Risks to workers and the public were increased significantly
when the unified command conducted an in-situ bum without having in
place appropriate checks and balances to ensure that approved
procedures and requirements were followed explicitly.
9. Spill management personnel responding from other regions of the
country and trained on different incident command procedures created
communications, command, and control difficulties because they were not
familiar with the incident command structure and procedures in use in
the Galveston Bay area.
10. Implementation of the unified incident command structure and
operational principles in the National Response Team's Technical
Assistance Document Incident Command System/Unified Command will
enhance the overall preparedness for responding to petroleum spills.
11. Some lessons on improving the area's spill response
preparedness were not learned primarily because a comprehensive after-
action critique was not conducted.
Recommendations
As a result of its investigation, the National Transportation
Safety Board makes the following recommendations:

--to the Research and Special Programs Administration:

Require operators of liquid pipelines to address, in their Oil
Pollution Act of 1990 spill response plans, identifying and responding
to events that can pose a substantial threat of a worst-case product
release. (Class II, Priority Action) (P-96-21)
--to the National Response Team:

Make your membership aware of the circumstances and nature of the
events in the October 1994 environmental response at Houston, Texas,
specifically in regard to the need for coordinating all planning and
operational activities prior to conducting in-situ burn
countermeasures. (Class II, Priority Action) (I-96-1)
Motivate National Response Team agencies to integrate into their
area contingency plans the command and control principles contained in
Technical Assistance Document Incident Command System/Unified Command
and encourage them to train all personnel assigned management
responsibilities in those principles. (Class II, Priority Action) (I-
96-2)
Include procedures for implementing your Unified Command/Incident
Command System that will ensure that all safety-critical operations are
coordinated with parties at risk. (Class II, Priority Action) (I-96-3)
Establish guidance calling for Federal On-Scene Coordinators to
conduct a comprehensive after-action critique of each spill response to
incorporate the observations of all participating agencies to identify
improvements needed in equipment, communications procedures, guidance,
techniques, and management. (Class II, Priority Action) (I-96-4)
Request that Federal On-Scene Coordinators document and forward to
National Response Team headquarters all ``lessons learned'' developed
from after-action critiques for review and implementation nationwide as
appropriate. (Class II, Priority Action) (I-96-5)
--to the American Petroleum Institute:

Take the lead to develop, in cooperation with the Association of
Oil Pipe Lines and the Interstate Natural Gas Association of America,
design and construction standards adequate for pipelines to safely
cross flood plains and streambeds, including the development of
recommended practices for periodically reassessing crossing designs in
light of changes that have occurred in the flood plain or streambed.
(Class II, Priority Action) (P-96-22)
--to the Association of Oil Pipe Lines:

Develop, in cooperation with the American Petroleum Institute and
the Interstate Natural Gas Association of America, design and
construction standards adequate for pipelines to safely cross flood
plains and streambeds, including the development of recommended
practices for periodically reassessing crossing designs in light of
changes that have occurred in the flood plain or streambed. (Class II,
Priority Action) (P-96-23)
--to the Interstate Natural Gas Association of America:

Develop, in cooperation with the American Petroleum Institute and
the Association of Oil Pipe Lines, design and construction standards
adequate for pipelines to safely cross flood plains and streambeds,
including the development of recommended practices for periodically
reassessing crossing designs in light of changes that have occurred in
the flood plain or streambed. (Class II, Priority Action) (P-96-24)
By the National Transportation Safety Board
James E. Hall,
Chairman.
Robert T. Francis II,
Vice Chairman.
John A. Hammerschmidt,
Member.
John J. Goglia,
Member.
George W. Black, Jr.,
Member.
September 6, 1996
1131. General authority
(a) General.----
(1) The National Transportation Safety Board shall investigate or
have investigated (in detail the Board prescribes) and establish the
facts, circumstances, and cause or probable cause of----

(A) an aircraft accident the Board has authority to investigate
under section 1132 of this title or an aircraft accident
involving a public aircraft as defined by section 40102(a)(37)
of this title other than an aircraft operated by the Armed
Forces or by an intelligence agency of the United States;

(B) a highway accident, including a railroad grade crossing
accident, the Board selects in cooperation with a State;

(D) a pipeline accident in which there is a fatality,
substantial property damage, or significant injury to the
environment;

(E) a major marine casualty (except a casualty involving only
public vessels) occurring on the navigable waters or
territorial sea of the United States, or involving a vessel of
the United States, under regulations prescribed jointly by the
Board and the head of the department in which the Coast Guard
is operating; and

(F) any other accident related to the transportation of
individuals or property when the Board decides----

(i) the accident is catastrophic;

(ii) the accident involves problems of a recurring
character; or

(iii) the investigation of the accident would carry out
this chapter.

(2)(A) Subject to the requirements of this paragraph, an
investigation by the Board under paragraph (1)(A)-(D) or (F) of this
subsection has priority over any investigation by another department,
agency, or instrumentality of the U.S. Government. The Board shall
provide for appropriate participation by other departments, agencies,
or instrumentalities in the investigation. However, those departments,
agencies, or instrumentalities may not participate in the decision of
the Board about the probable cause of the accident.

(B) If the Attorney General, in consultation with the Chairman
of the Board, determines and notifies the Board that
circumstances reasonably indicate that the accident may have
been caused by an intentional criminal act, the Board shall
relinquish investigative priority to the Federal Bureau of
Investigation. The relinquishment of investigative priority by
the Board shall not otherwise affect the authority of the Board
to continue its investigation under this section.

(C) If a Federal law enforcement agency suspects and notifies
the Board that an accident being investigated by the Board
under subparagraph (A), (B), (C), or (D) of paragraph (1) may
have been caused by an intentional criminal act, the Board, in
consultation with the law enforcement agency, shall take
necessary actions to ensure that evidence of the criminal act
is preserved.
(3) This section and sections 1113, 1116(b), 1133, and 1134(a) and
(c)-(e) of this title do not affect the authority of another
department, agency, or instrumentality of the Government to investigate
an accident under applicable law or to obtain information directly from
the parties involved in, and witnesses to, the accident. The Board and
other departments, agencies, and instrumentalities shall ensure that
appropriate information developed about the accident is exchanged in a
timely manner.
(b) Accidents Involving Public Vessels.----
(1) The Board or the head of the department in which the Coast
Guard is operating shall investigate and establish the facts,
circumstances, and cause or probable cause of a marine accident
involving a public vessel and any other vessel. The results of the
investigation shall be made available to the public.
(2) Paragraph (1) of this subsection and subsection (a)(1)(E) of
this section do not affect the responsibility, under another law of the
United States, of the head of the department in which the Coast Guard
is operating.
(e) Accidents Not Involving Government Misfeasance or
Nonfeasance.----
(1) When asked by the Board, the Secretary of Transportation may--
--

(A) investigate an accident described under subsection (a) or
(b) of this section in which misfeasance or nonfeasance by the
Government has not been alleged; and

(B) report the facts and circumstances of the accident to the
Board.

(2) The Board shall use the report in establishing cause or
probable cause of an accident described under subsection (a) or (b) of
this section.
(d) Accidents Involving Public Aircraft.--The Board, in furtherance
of its investigative duties with respect to public aircraft accidents
under subsection (a)(1)(A) of this section, shall have the same duties
and powers as are specified for civil aircraft accidents under sections
1132(a), 1132(b), and 1134(a), (b), (d), and (f) of this title.
______

Response to Written Question Submitted by Hon. Kay Bailey Hutchison to
Hon. Deborah A.P. Hersman

Question. What recommendations do you have for the Committee with
respect to reauthorizing the pipeline safety program?
Answer. NTSB concerns can be grouped into three general areas:
excess flow valves (EFVs), safety oversight, and low-stress pipeline
regulation equality. NTSB has recommended the use of EFVs in gas
distribution pipeline systems for many years. While the NTSB has not
issued recommendations specifically addressing either the effective
oversight of risk-based assessments in pipeline safety regulation or
the regulation of low-stress pipelines, these two areas are critical to
safeguarding the integrity of our Nation's pipeline systems.

Apply Excess Flow Valves (EFVs) Equally
EFVs are installed in natural gas service lines where they connect
to the distribution line. EFVs are designed to mitigate gas leaks from
the service line by detecting an abnormally high flow rate. When an
excess flow is detected, an EFV automatically closes, thus shutting off
the flow of gas from the distribution line to the service line.
The Pipeline and Hazardous Material Safety Administration's (PHMSA)
current mandate under the PIPES Act requires excess flow valves only on
new or replacement service lines to single family residences. The NTS13
recommended nearly 10 years ago (P-01-2) that PHMSA require that excess
flow valves be installed in all new and replacement gas service lines,
regardless of a customer's classification, when the operating
conditions are compatible with readily available valves.
The NTSB believes that apartment buildings, other multifamily
dwellings, and commercial properties are susceptible to the same risks
from leaking gas lines as single-family residences, and we believe this
gap in the law and the regulations should be eliminated.

Effective Safety Oversight
Over the past decade or more, PHMSA has used a risk-based
assessment for regulating the DOT pipeline safety program. PHMSA has
successfully built a partnership with various facets of the pipeline
industry to develop, implement and execute a multi-part pipeline safety
program. In the NTSB's view, all stakeholders, including PHMSA, have
come to rely heavily upon this approach. The NTSB believes a risk-based
approach can work if effective oversight is exercised by PHMSA and the
pipeline operators.
The NTSB also believes that with the risk-based assessment come
increased responsibilities for both the individual pipeline operators
and PHMSA. Operators must diligently and objectively scrutinize the
effectiveness of their programs, identify areas for improvement, and
implement corrective measures. PHMSA, as the regulator, must also do
the same in its audits of the operators' programs and in self-
assessments of its own programs. In short, both operator and regulator
need to verify whether risk-based assessments are being executed as
planned, and more importantly, whether these programs are effective.
Unfortunately, there have been some recent pipeline investigations in
which the NTSB discovered indications that PHMSA and operator oversight
of risk-based assessment programs, specifically integrity management
programs and public education programs, has been lacking and has failed
to detect flaws and weaknesses in such programs.

Low-Stress Pipelines Regulation Equality
At the time the PIPES Act was enacted, Federal pipeline safety
regulations only applied to low-stress pipelines that were located in
populated areas, crossed navigable waterways, or carried highly
volatile liquids, such as compressed liquefied propane. In a final
rulemaking, ``Pipeline Safety: Protecting Unusually Sensitive Areas
from Rural Onshore Hazardous Liquid Gathering Lines and Low-Stress
Lines,'' published on June 3, 2008, PHMSA issued regulations for rural
onshore low-stress pipelines that have a diameter of at least 8\5/8\
inches and that are within \1/2\ mile of an area defined as unusually
sensitive. Low-stress pipelines meeting these criteria will be required
to meet 49 CFR Part 195, for hazardous liquid pipelines in its entirety
by July 2012.
The final rule also included provisions for rural onshore gathering
lines that operate at stress levels greater than 20 percent of the pipe
strength, have a diameter between 6\5/8\ and 8\5/8\ inches and are
within \1/4\ mile of an area defined as unusually sensitive. (A
``gathering line'' is defined as a pipeline with a diameter of 8\5/8\
inches or less that transports petroleum from a production facility.)
Under the final rule, rural onshore gathering lines will be required to
meet Part 195 in part by July 2011. The safety requirements of Part 195
that will eventually apply to the rural onshore gathering lines include
annual and accident reporting requirements, establishment of maximum
operating pressure, installation of line markers, public education
programs, damage prevention programs, corrosion control, and operator
qualification programs.
On June 22, 2010, PHMSA published a follow-up Notice of Proposed
Rulemaking (NPRM) addressing the regulation of all rural onshore
hazardous liquid low-stress pipelines. This NPRM represents phase two
of PHMSA's implementation of its mandate in the PIPES Act.
In this NPRM, PHMSA proposes safety requirements for all rural low-
stress pipelines not included under the phase one final rule. This
latest NPRM does not include any new proposed requirements for onshore
rural gathering lines.
The low-stress pipelines captured under the new NPRM include: (1)
rural low-stress pipelines of a diameter less than 8\5/8\ inches
located in or within one-half mile of an unusually sensitive area and
(2) all other rural low-stress pipelines that were not included under
phase one. PHMSA estimates that the NPRM will apply to 1,384 miles of
low-stress pipelines not covered by the previous rule. However, the
NPRM does not broaden the regulation of rural on-shore gathering lines.
The NTSB believes that the key to the success of these regulations will
be effective oversight exercised by the pipeline operators and PHMSA.
The NTSB believes that PHMSA should have more authority to regulate
all types and categories of offshore pipelines. The regulation of
offshore pipeline systems has not been addressed in recent legislation
or regulatory action. Jurisdiction over offshore pipelines of all types
is complex and currently involves coastal states, PHMSA, and the
Department of the Interior. The jurisdictional responsibilities are
based on the location and function of a pipeline (e.g., production
versus transportation) rather than on the threat to public safety and
the environment from the petroleum and/or natural gas transported.
These jurisdictional complexities can easily lead to gaps in the
regulations and inconsistencies in pipeline safety standards, which
could be minimized if a more seamless approach to regulating offshore
pipelines is taken by giving PHMSA sole jurisdiction over all pipeline
systems located wholly or partially on the Outer Continental Shelf.
Currently, PHMSA has the most expertise at the Federal level on
pipeline safety issues, and would be best suited to work with existing
stakeholders to develop and implement a simplified and more consistent
regulatory program for offshore pipelines. PHMSA would also need the
resources to assume such expanded responsibilities.
The tragedy in the Gulf of Mexico involving the Deepwater Horizon
drilling platform is a grim reminder of the damage that a major oil
spill can cause. While the magnitude of the Deepwater Horizon spill is
far greater than any known pipeline failure, the events in the Gulf
should remind those involved in the pipeline industry that all
pipelines, offshore and onshore, must be sufficiently safeguarded and
regulated in order to protect the public and the environment.
______

Response to Written Questions Submitted by Hon. John Thune to
Hon. Deborah A.P. Hersman

Question 1. Today, ethanol and fuel blended with ethanol usually
move by truck or rail due to technological challenges in moving these
products by pipeline. Yet, the ability to move ethanol and other
biofuels by rail would be safety and less expensive. What
recommendations do you have for encouraging the development of ethanol
pipelines?
Answer. Ethanol or ethyl alcohol is a volatile flammable liquid
with a significant flammability range (concentration in air of 3
percent to 19 percent) and poses a significant fire risk, but ethanol
is not corrosive, particularly toxic, or a severe pollutant. (Pure
ethanol is found in alcoholic beverages.) Today, ethanol is primarily
used as a feedstock for the production of various chemical products and
as an additive in gasoline. Ethanol used for such commercial purposes
is denatured, meaning a substance is added to the ethanol to deter
people from consuming it as an alcoholic beverage.
The commercial demand for ethanol has dramatically risen in recent
years because of its use in gasoline. Automotive gasoline containing
ethanol is commonly transported by hazardous liquid pipelines. Although
the NTSB is not aware of any existing pipelines dedicated to the
transportation of ethanol, the NTSB does not see any properties of
ethanol that would make it uniquely hazardous to transport by pipeline
with existing regulations to safeguard people and the environment
applied to these pipelines.
Biofuels would likewise be flammable. It is conceivable that a
particular biofuel, depending on its source and composition, may
potentially have corrosive or environmentally harmful properties that a
pipeline operator would have to consider in light of current
regulations.

Question 2. You note in your written testimony that partnerships
between the industry and PHMSA have led to a number of joint
initiatives. What lessons can be learned from the cooperative
relationship between PHMSA, the States, and the oil and gas industry
that could be beneficial for other industries?
Answer. Over the past decade or more, PHMSA has used a risk-based
assessment for regulating pipeline safety. Within this regulatory
framework, pipeline operators have the flexibility and responsibility
to develop their individual programs and plans, determine the specific
performance standards, implement their plans and programs, and conduct
periodic self-evaluations that best fit their particular pipeline
systems. PHMSA likewise has the responsibility to review pipeline
operators' plans and programs for regulatory compliance and
effectiveness.
The NTSB believes that with the risk-based assessment approach come
important responsibilities for both the individual pipeline operators
and PHMSA, and these programs can be effective when both parties are
fulfilling their responsibilities. Unfortunately, there have been some
recent pipeline investigations in which the NTSB discovered that PHMSA
and operator oversight of risk-based assessment programs, specifically
integrity management programs and public education efforts, have been
lacking and have failed to detect flaws and weaknesses in such
programs.
Congress can ensure that PHMSA has the needed funding and resources
to implement an aggressive oversight program, and require that PHMSA
provide periodic analyses of its oversight program.
______

Response to Written Questions Submitted by Hon. Mark Pryor to
Rocco D'Alessandro

Question 1. Do you oppose expanding integrity management
inspections?
Answer. AGA opposes expanding the high consequence area (HCA)
definition in the Transmission Integrity Management Program (TIMP).
Some reasons for not expanding the integrity management HCA definition
are: (1) the risk-based integrity management inspection philosophy in
the pipeline safety statute has proven to be effective and is still
being implemented, (2) treating all pipeline segments as if they posed
the same risks is not consistent with the risk-based engineering
principles built into the pipeline safety Federal code of regulations,
49 CFR 192, and the (3) AGA believes there are potential unintended
consequences in eliminating risk prioritization that could stretch
operator safety resources and not allocate them to the most critical
areas.
Congress required DOT to establish criteria for operators to
identify transmission pipelines in densely populated areas, conduct
risk analyses, and adopt and implement integrity management programs.
To accomplish these tasks, the DOT created the HCA concept, which went
beyond densely populated areas and included places where people are
known to congregate on a regular basis. (i.e., churches, playgrounds,
recreational areas, etc.) The intent of establishing HCAs was for the
natural gas industry to devote its resources toward protecting those
areas which represent the greatest risk for the public. Operators were
given 10 years to complete these assessments and begin reassessments.
Baseline assessments will be complete by the December 2012 deadline. It
should be noted that HCAs for hazardous liquid pipelines used a vastly
different technical basis from gas transmission pipelines because of
the properties transported. These HCAs include unusually sensitive
drinking water and ecological resources, high population areas and
other populated areas, and commercially navigable waterways.
Some define risk management as the identification, assessment, and
prioritization of risks followed by coordinated and economical
application of resources to minimize, monitor, and control the
probability and/or impact of unfortunate events. Pipeline safety
regulations have incorporated risk management principles into
regulation for decades. The regulations treat pipeline segments
differently based upon various factors. Since 1970, natural gas
transmission pipelines have used risk-based Class 1, 2, 3 or 4
locations, which are based upon the concentration of buildings near
pipeline corridors, for design, construction, operation and maintenance
requirements. The transmission integrity management program HCA concept
is an enhancement to existing risk-based pipeline safety regulations.
Treating most or all pipeline segments with the assessment
requirements applied in HCAs would dramatically increase the resources
needed for safety without a commensurate improvement in safety. The
expansion could have the unintended consequence of adversely affecting
safety if the focus on higher risk areas is diluted by a one-size-fits-
all approach.

Question 2. How often do most companies conduct internal integrity
assessments?
Answer. The Transmission Integrity Management Program (TIMP)
regulation requires a specific type of integrity assessment every 7
years in HCAs, but operators conduct some type of safety assessment on
all pipeline segments on a continual basis.
The TIMP regulation requires operators to conduct a prescriptive
integrity management assessment every 7 years (49 CFR 192 Subpart O).
The integrity assessment interval recommended by the American Society
of Mechanical Engineers, ASME B31.8S, Managing System Integrity of Gas
Pipelines, consensus standard does not give a fixed interval for an
integrity assessment. Instead it gives a range of years based upon
historical technical national pipeline performance data and current
data on the specific pipeline being analyzed.
There are many safety assessment intervals built into the pipeline
safety code separate from the TIMP assessments. For example, there is
external corrosion control monitoring annually, leakage surveys from
one to four times per year, and patrols from one to four times per
year. Importantly, section 192.613 Continuing Surveillance, requires
operators to have a procedure for continuing surveillance of its
facilities to determine and take appropriate action concerning changes
in class location, failures, leakage history, corrosion, substantial
changes in cathodic protection requirements, and other unusual
operating and maintenance conditions.

Question 3. In light of the recent BP spill and leak events, do you
believe there is more that industry, Congress, or PHMSA should do to
enhance pipeline safety?
Answer. The BP spill and leak event is not related in any way to
pipeline safety. Pipeline incidents are rare because of the extensive
regulatory structure and operator commitment to safety. PHMSA requires
operators to analyzing pipeline accidents and failures, for the purpose
of determining the causes of the failure and minimizing the possibility
of a recurrence.
One area of pipeline safety that could be enhanced is excavation
damage prevention. Although the nine elements in the 2006 PIPES Act
were an important achievement for reducing pipeline damages, the
greatest impact will actually occur when states open up their one-call
laws and revise the language so that it adheres to the nine elements to
create a robust and effective state damage prevention program. This may
take several years due to the unique timing of state legislative
sessions and the existence of special interest groups that have no
desire in overhauling their state damage prevention laws. Still, a
handful of states have recently made positive changes to their one-call
law such as Utah, Indiana and Maryland.
Many state one-call laws are antiquated and fail to effectively
address difficult issues, such as enforcement of excavators who fail to
follow the one-call process or fail to abide by safe digging practices.
Without consistent and effective enforcement from a recognized
authority at the state level, it is impossible to develop an effective
damage prevention program. Most states either have no agency to enforce
the damage prevention laws, or the agency simply does not have the
funding to execute its responsibilities. Many states give enforcement
authority to the attorney general and pipeline safety enforcement is
neglected because of more pressing priorities by state justice
departments. AGA is of the position that consistent and effective
enforcement must be designed so it can hold all entities accountable
for pipeline safety.

Question 4. What do you believe should be the top priorities for
PHMSA in light of the recent BP disaster?
Answer. AGA cannot speak on behalf of PHMSA regarding priorities.
However, over the last 7 months PHMSA has issues two major regulations
that must be implemented--Distribution Integrity Management (DIMP) and
Control Room Management (CRM). These were priorities set forth by
Congress in the Pipeline Improvement, Protection, and Enforcement Act
of 2006. The DIMP program requires operators to develop comprehensive
integrity management plans that will identify risks and implement
corrective actions for all piping an operators' system. The plans will
facilitate better regulatory oversight. The CRM regulation is a
comprehensive control system rule which includes human factors, fatigue
management and emergency response requirements. These are top
priorities for AGA members.

Question 5. Do you believe PHMSA currently provides enough
oversight of our Nation's oil and gas pipelines?
Answer. Most AGA member companies are under the jurisdiction and
oversight of state regulators. AGA believes there is sufficient Federal
and state oversight of pipelines to ensure safety.
______

Response to Written Questions Submitted by Hon. Mark Pryor to
Timothy C. Felt

Question 1. What do you believe should be the top priorities for
PHMSA in light of the recent BP disaster?
Answer. The liquid pipeline industry remains at a continued state
of readiness to properly maintain and operate our systems. We are
certainly aware of the increased focus that the Deepwater Horizon
incident will place on our industry. On June 28, 2010, PHMSA issued an
Advisory Bulletin to all operators of liquid pipeline facilities
required to develop and submit spill response plans under 49 CFR Part
194. The Advisory Bulletin requires all covered operators to review and
update, as necessary, their spill response plans to calculate and
envision worst-case scenario planning. Operators must examine available
resources required to respond to worst-case scenarios, and conduct
their review (including any updates) within 30 days. Operators were
also asked to confirm that drills have been performed at the frequency
specified in their plans and maintain on-going training with first
responders. Pipeline operators already have significant obligations
under current regulation to maintain up-to-date response plans that are
specifically tailored for each site and also include frequent drills
and training. We would request that as the Federal Government continues
its important oversight work, in light of the Deepwater incident, that
it provide clear and consistent compliance guidance to affected
pipeline operators.
We do believe there are some constructive steps PHMSA and the
Office of Pipeline Safety (OPS) could make to remove gaps in pipeline
safety regulation. First, PHMSA should encourage states to enhance
their damage prevention laws or move quickly to improve damage
prevention programs in the states that have weak or ineffective laws.
Most importantly, PHMSA should remove exemptions for state and
municipal governments from One-Call requirements. Such exemptions
create unnecessary opportunities for third-party damage to pipelines.
As I mentioned in my testimony, incidents from excavation damage by
third parties accounted for only 7 percent of release incidents from
1999 to 2008. However, 31 percent of all significant incidents (those
that result in spills of 50 barrels or more, fire, explosion,
evacuation, injury or death) came from excavation damage by third
parties. AOPL and API believe Congress should encourage OPS to move
forward to issue a final rule on damage prevention based on the October
2009 Advanced Notice of Proposed Rulemaking (ANPRM), disallowing any
exemptions to One-Call requirements.

Question 1a. Do you believe PHMSA currently provides enough
oversight of our Nation's oil and gas pipelines?
Answer. The liquids pipeline industry believes that PHMSA is a fair
but tough regulator with several significant oversight tools,
including: random and regular inspections of equipment and facilities,
enforcement authority, and fines. PHMSA has a set of prescriptive
safety regulations and standards that require a diligent focus by our
industry to remain in compliance. Recently, critics of our industry
have unfairly distorted and misconstrued the industry's constructive
working relationship with PHMSA, especially on the issue of setting
consensus standards. Pipeline operators have every interest in
developing best practices that help maintain the integrity of their
systems, which pushes the industry to achieve operational excellence.
It should be recognized that PHMSA can require, as well as reject,
modifications to industry standards before incorporating them by
reference. Further, all consensus industry standards involve public
input under guidelines established by the American National Standards
Institute (ANSI), whose Board of Directors are currently comprised of
individuals from several Federal agencies, including DOE, NIST, CPSC,
EPA, and DoD. In addition, PHMSA's Technical Advisory Committee has
direct representation from those in the advocacy community to
incorporate all points of view in the regulatory process. We take issue
with those that unfairly criticize and malign the reputation of
organizations like the American Society of Mechanical Engineers (ASME)
International and the American Society for Testing and Materials (ASTM)
that were involved in setting consensus standards that have been
adopted by PHMSA. These and other professional organizations provide
real-world technical expertise and important insight to the regulatory
process. The notion that the pipeline industry regulates itself is
false. The role of Federal safety regulator is clearly and strongly
performed by PHMSA.
______

Response to Written Questions Submitted by Hon. Mark Pryor to
Gary L. Sypolt

Question 1. Do you oppose expanding integrity management
inspections?
Answer. We do oppose expanding the High Consequence Area (HCA)
definition in the legislation to include more pipeline mileage.
Currently, these HCAs are defined (for natural gas transmission lines)
as those pipeline segments located within populated areas. If a
pipeline is in an HCA, it is subject to an extra layer of protection
beyond the existing pipeline safety regulations; in other words, it is
subject to the Integrity Management Program (IMP) with its accompanying
procedural and administrative requirements. The existing safety
regulations, which have continually been updated since 1970, govern the
design, materials, construction, operation and maintenance of all
natural gas transmission pipelines and have contributed significantly
to the safety record of natural gas transmission systems both within
HCAs and outside HCAs. The focus of the mandated IMP on reducing risk
in populated areas continues to make sense to us in that it allows the
pipeline operators to focus its resources on those areas of the
pipeline that are more densely populated.
The mandated IMP program specifically allows three types of
inspection technology: hydrostatic pressure testing, direct assessment
and internal inspection using ``smart pigs.'' The legislation does
allow the use of any new technology for inspections, but at this time
no new viable inspection technology has been accepted by PHMSA.
Hydrostatic pressure testing involves isolating a section of
pipeline and filling it with water and pressuring it far beyond the
maximum operating pressure to see if the pipe ruptures or leaks. During
the process, the pipeline segment must be taken out of service for
several weeks. The pipeline operator must collect, handle and dispose
of large volumes of water used in the testing. Finally, residual water
or sediment could present operational problems once the pipeline
segment is returned to service.
Direct assessment involves excavating segments of pipeline and
physically inspecting them (externally) every time it is inspected.
This requires significant excavation work, including tearing up private
property and roads, and potentially damaging the pipeline with
excavation equipment every time the assessment is done.
Within the last two decades, smart pig technology has been the
``solution of choice'' for integrity assessments because the
alternatives--hydrostatic testing and direct assessment--present the
aforementioned problems. Smart pigs can be a useful tool for managing
corrosion where they are practical to use. However, many natural gas
pipelines were constructed in an era before smart pigs were invented.
These pipelines were engineered to transport natural gas--a highly
compressible substance--rather than solid devices such as smart pigs.
This means that pipeline segments with tight bends, telescoping
segments, or valves which do not open completely, limit the passage of
smart pigs and require extensive excavation and modifications to allow
the insertion, passage and retrieval of smart pigs for inspections.
These pipeline modifications are by far the most costly component of
the IMP program.
As I noted in my testimony, however, we have invested heavily and
are already inspecting and repairing pipelines- via smart pigs--in much
more than just the defined HCAs. For natural gas transmission
pipelines, HCAs account for about 7 percent of total mileage, but we
expect to actually perform internal inspections and repairs on about 65
percent of total mileage by the end of the baseline Integrity
Management Program (IMP) assessments which will be completed in
December of 2012.
Based on this level of performance, I do not believe that integrity
management inspections should be expanded by legislative mandate.

Question 2. How often do most companies conduct internal integrity
assessments?
Answer. The Pipeline Safety Improvement Act of 2002 requires that
natural gas transmission pipelines in HCAs undertake an initial
integrity assessment by December 2012, and reassessments every 7 years
thereafter. As mentioned previously, most of this work is being
completed via internal inspections using smart pig devices.
A consensus standard developed by the American Society of
Mechanical Engineers (ASME) about a decade ago suggested a reassessment
interval of 10 years for most high-pressure natural gas transmission
pipelines. We believe the ASME standard is a logically and technically
superior basis for setting reassessment intervals, and we hope Congress
ultimately permits PHMSA to incorporate such a standard into the
regulations, rather than the current seven-year mandate. In a report to
Congress on this question in 2006, the GAO agreed with this position.

Question 3. In light of the recent BP spill and leak events, do you
believe there is more that industry, Congress or PHMSA should do to
enhance pipeline safety?
Answer. First, it should be said that PHMSA and the pipeline safety
program generally are not comparable to MMS and the events that led to
the BP spill. For at least the last decade, the pipeline safety program
at PHMSA has been characterized by action in the development of new
safety standards for a variety of pipeline systems. Congress has added
a number of mandates to PHMSA in terms of directing pipeline safety
efforts. The occurrence of pipeline accidents is low, and serious
accidents are very rare. The main reason is that industry, the
regulator, and the public have worked together to put better safety
programs and technologies in place.
Still, more can be done. My testimony covered several ideas,
including the implementation of a ``safety culture'' across the
pipeline industry, including our contractors. This culture assists in
reducing the workplace accidents which are a significant portion of the
serious pipeline incidents still occurring. It is also an area where
the BP experience is instructive. ``Safety culture'' can be defined as
an environment in which employees engage in best safety practices
whether they are supervised or not. In other words, employees are
empowered to take the safest path, and are rewarded for doing so. This
type of culture creates the best environment for avoiding accidents.
Another area of additional focus, and the largest cause of serious
incidents, is excavation damage prevention. This is also a ``safety
culture'' issue but involves many stakeholders. Much has been done on
this issue in the last 10 years, but more can be done. I would like to
discuss this further in my answer to the next question.
The final area of continuing focus is the ongoing development of
new materials, equipment, and best practices for such items as employee
training or equipment maintenance. All of these things are important to
making continued improvement to safety. In my testimony, I included the
example of improved smart pig technology. Better standards and
technology will ultimately lead to fewer accidents.

Question 4. What do you believe should be the top priorities for
PHMSA in light of the recent BP disaster?
Answer. The top priority for PHMSA, given the BP disaster and the
public response, should be maintaining public credibility and trust by
focusing on those causes of accidents which have the most impact on the
public. INGAA believes more should be done with respect to excavation
damage prevention. Accidental hits to pipelines from, for example,
construction equipment, tend to be the leading cause of deaths and/or
injuries associated with our pipelines. While these state-run damage
prevention programs have improved significantly over the last decade,
more needs to be done. The recent accidents in Texas, profiled in my
testimony, point to this conclusion. Again, a credible damage
prevention effort is about more than just making the first call to a
one-call center. An effective program includes full participation by
all excavators and all underground utility operators, accurate and
timely marking of facilities by utility operators, procedures for due
caution by excavators working around marked facilities, and effective
enforcement of the state regulations.

Question 5. Do you believe PHMSA currently provides enough
oversight of our Nation's oil and gas pipelines?
Answer. Yes. The safety record of the pipeline industry is
testament to this conclusion.
______

Response to Written Questions Submitted by Hon. Mark Pryor to
Carl Weimer

Question 1. What in your view would be the best way to conduct
Integrity Management reviews by industry and PHMSA?
Answer. The Pipeline Safety Trust believes that the basic theory
and implementation of the reviews required by Integrity Management
programs for Hazardous Liquid and Natural Gas Transmission pipelines is
sound, and has led to the detection and correction of thousands of
potential safety problems.
Our concern is not so much in the way that Integrity Management
reviews are conducted, but the limited miles of pipelines that are
required to conduct such valuable safety reviews. Currently only 7
percent of natural gas transmission pipelines and only 44 percent of
hazardous liquid pipelines are required to do these reviews. We believe
that it is time to require that all of these types of pipelines fall
under Integrity Management rules so people living in more rural
neighborhoods have equal safety protection.
If the Integrity Management program is not to be expanded to all of
these types of pipelines then there are a couple of things that would
at least help increase the safety under the existing limited mileage.
These include:

Many operators inspect many more miles of pipeline than is
required, which is a good thing. These operators should be
required to report their findings to PHMSA on the mileage of
pipelines outside of the required areas, and how they responded
to those findings, in the same way they report findings in the
required areas.

The definition for determining High Consequence Areas for
natural gas transmission pipelines in 49 CFR 192.903 should be
changed as follows to significantly increase safety:

High consequence area means an area established by one of the
methods described in paragraphs (1) or (2) as follows:

(1) An area defined as----

(iii) Any area in a Class 1 or Class 2 location where
the potential impact radius is greater than 660 feet
(200 meters), and the area within a potential impact
circle contains 20 or more buildings intended for human
occupancy

It should be made clear that at a minimum during the normal
reinspection intervals operators should reassess their entire
pipelines to determine if there have been any changes in
circumstances (such as increase population near the pipeline)
that would require additional areas to be added to High
Consequence Area status.

Question 2. Should PHMSA have more authority to regulate offshore
pipelines?
Answer. PHMSA already has significant authority in the offshore
areas within the control of the states. While it is clear from the Gulf
of Mexico disaster that a comprehensive review of offshore regulations
and authority needs to be completed, the Pipeline Safety Trust has not
considered this to the degree necessary to make a recommendation about
whether authority needs to shift from MMS to PHMSA.
We would suggest that a study be undertaken to compare both the
regulations and performance under both agencies, and then a good
comparison of what needs to be strengthened where would be relatively
easy.
One further point that should be addressed regardless of which
agency is in charge is the implementation of a mandatory damage
prevention notification system in the offshore waters. Onshore
Congress, PHMSA and the pipeline industry have all spent significant
effort to ensure the implementation of the national 811 ``call before
you dig'' number and associated damage prevention awareness. No similar
system is required in the offshore areas of the Gulf where increasing
activities are occurring putting underwater pipelines at risk. One such
offshore damage prevention system that has been developed that should
be studied for possible mandatory implementation is GulfSafe. More
information about it can be found on their website at: http://
www.gulfsafe.com/.
______

Response to Written Questions Submitted by Hon. John Thune to
Carl Weimer

Question 1. There seems to he some inconsistency in the treatment
of oil pipelines compared to gas pipelines in terms of regulation and
emergency response requirements. What recommendations do you have for
addressing these?
Answer. I am not sure I understand the question, so would need more
information regarding what ``inconsistency'' is being referred to.
The main inconsistency that we are currently concerned about is the
difference in attention being spent addressing production, gathering,
and flow lines. For oil pipelines Congress has asked, and PHMSA is now
working toward a rulemaking, to implement new regulations on these low-
stress oil pipelines. This is important work and we support it! Natural
gas pipelines have similar production lines, many of which are
unregulated, or the point where regulations begin is unclear. With a
huge increase in domestic drilling for natural gas, much of it
occurring in more populated areas in places like Texas, New York, and
Pennsylvania, there is a need to ensure adequate regulation of these
types of natural gas pipelines, especially in populated areas.
We believe that much of our concern about unregulated natural gas
pipeline could be addressed by the following two changes:

Implement a rulemaking to clarify the point where onshore
regulated gas gathering lines begin (49 CFR Part 192.8). That
point should be defined to ensure there are no unregulated gas
pipelines off of well pads in class 2, 3, or 4 areas, or other
``identified sites'' where large groups may gather.

Implement a rulemaking to include all Type A gathering lines
(49 CFR Part 192.9) under the full requirements of the
Integrity Management program (49 CFR Part 192 Subpart O) that
currently only applies to transmission pipelines.

Question 2. Do you consider integrity management a success?
Answer. We do consider Integrity Management of transmission
pipelines a success. For both liquid pipelines and natural gas
pipelines integrity Management was a huge step up in regulations
ensuring that transmission pipelines in more populated areas, and areas
that could affect sensitive environments, were inspected on a regular
basis. These required inspections found nearly 35,000 anomalies in need
of repair on pipelines in the first round of inspections. These are
anomalies that may not have been found and repaired until leaks,
ruptures, or explosions occurred under the previous regulations.
While Integrity Management has been a success it is still limited
to only 7 percent of natural gas pipelines and 44 percent of liquid
pipelines. It is time to expand this successful program to all
transmission pipelines to ensure that those in more rural areas have
these same safety benefits, and that our critical fuel transportation
network remains viable.
______

Response to Written Questions Submitted by Hon. Johanns to
Carl Weimer

Question 1. Your testimony recommends that the pipeline safety
system be changed to correct the ``pipeline siting vs safety
disconnect'' which separates the safety function of PHMSA from the
siting process. In light of this recommendation, what is your view of
how PHMSA has been involved in the permitting process for the Keystone
XL pipeline in Nebraska?
Answer. We have not been actively involved in the Keystone
permitting process, but our understanding is that it has proceeded like
most other new pipeline permitting processes across the country. In all
of those permitting processes, whether being overseen by FERC, the
Department of State or the states, there is a disconnect between
PHMSA's review and approval of pipeline safety issues (special permits,
High Consequence Areas, spill response plans, etc.) and the official
environmental review that is part of the permitting. These two now
separate processes need to be integrated into a single process. That
way things like spill response plans and High Consequence Areas can be
developed and publicly reviewed as part of the permitting--not in the
separate processes that PHMSA now uses many of which are closed to the
public. It makes little sense for the Department of State to do an
environmental review is such critical things as Spill Response plans
(under PHMSA's authority) have not yet been developed or made public.
One way to better integrate these separate processes would be to
require PHMSA to be a cooperating agency for all interstate pipeline
siting processes, and that all parts of a new pipeline's safety review
be a part of that siting review as well.

Question 2. What specific recommendations would you make for the
regulatory process that governs the issuance of a Presidential permit?
Do these recommendations differ as compared to recommendations for the
regulatory process that governs pipeline siting for exclusively
domestic transport of crude oil?
Answer. We don't really see that there should be any real
difference in the permitting process between purely domestic pipelines
and ones that cross an international border. The recommendations we
made above to better integrate permitting and pipeline safety would
apply to both.

Question 3. What comments would you offer, if any, concerning the
role that state authorities play in the regulatory process governing
the issuance of Presidential permits for the international transport of
crude oil?
Answer. Unlike the siting of interstate natural gas pipelines,
which is controlled by FERC, states do have the ability to create
pipeline siting agencies for interstate hazardous liquid pipelines. We
think states should exercise this ability to give them control over the
siting process, but in reality some states do and some states don't. In
the states that do not create such siting agencies the routing and
permitting decisions are left up to the pipeline companies and local
government.
It is unclear to us whether a Presidential Permit granted by the
State Department preempts the normal state siting authority, or whether
those two processes can run in parallel to each other. This should be
clarified, and at a minimum such state agencies should be made
cooperating partners in the review by the State Department.
______

Prepared Statement of Michael Thompson, Chief, Pipeline Safety, Oregon
Public Utility Commission and Chairman, National Association of
Pipeline Safety Representatives (NAPSR)

Introduction
Chairman Lautenberg, Ranking Member Thune, members of the
Committee, thank you for the opportunity to discuss our role in support
of pipeline safety as related to reauthorization of the pipeline safety
law. This law contains necessary protections that our Nation depends on
to maintain safety in its energy pipeline network. I am the Chairman of
the National Association of Pipeline Safety Representatives (NAPSR)
which is a non-profit organization of state pipeline safety personnel
who serve to support, encourage, develop and enhance pipeline safety in
the country. I am pleased to submit this statement for the record on
behalf of NAPSR and in support of our member states' efforts, as well
as in support of the partnership with the Secretary of Transportation
to fulfill the mandates of the Pipeline Safety Act.
I will briefly describe the role of the states in maintaining or
enhancing pipeline safety, where our efforts are currently focused, and
what it takes for State programs to implement the Federal mandates.

The States as Stewards of Pipeline Safety
Since the Pipeline Safety Act was signed into law in 1968, states
have been very active as stewards of pipeline safety in assisting the
U.S. DOT Secretary in carrying out the Nation's pipeline safety
program. States act as certified agents for implementing, ensuring and
enforcing Federal safety regulations, working in partnership with the
Secretary. State pipeline safety program personnel are classified as
state employees providing oversight of state and local safety
regulations which in all cases are either equivalent or stricter than
Federal regulations. This arrangement between the Federal and State
government has mutually benefited both State and Federal regulators,
while ultimately benefiting the local citizens and consumers in
providing a safe, reliable energy supply and distribution
infrastructure. The current arrangement, from a Federal perspective,
has distinct advantages because state employees are generally less
expensive than Federal employees or private contractors, have lower
travel, maintenance and operating costs, and typically yield the
economies of scale that state governments inherently possess. This also
allows for greater safety oversight because it uses knowledge of local
conditions, considerations of local concerns, relationships with local
first responders and the ability to provide direct and immediate
feedback to the public. This is indeed a fiscal ``bargain'' for the
Federal agency but more importantly, provides the prerequisite detailed
knowledge required for thorough scrutinizing of pipeline operations
that the public and this committee demand.
One other distinct advantage that state programs have over
comparable Federal oversight is the ability to incorporate and leverage
state pipeline safety initiatives into a multitude of other existing
state review processes that blend safety, reliability and rate-making
authorities over energy providers, rather than distinct ``silos'' with
separate government agencies.
State pipeline safety personnel represent more than 80 percent of
the state/Federal inspection workforce. State inspectors are the
``first line of defense'' at the community level to promote pipeline
safety, underground utility damage prevention, and public awareness
regarding gaseous and liquid fuel pipelines.
The responsibility for state pipeline safety programs is carried
out by approximately 325 qualified engineers and inspectors in the
lower 48 states, District of Columbia and Puerto Rico. Recent
statistics indicate that states are responsible for pipeline safety
covering over 92 percent of 1.9 million miles of gas distribution
piping in the nation, 29 percent of 300,000 miles of gas transmission
and 32 percent of 166,000 miles of hazardous liquid pipelines. State
personnel in 11 states act as ``interstate agents'' also inspecting
interstate gas and liquids pipelines that would otherwise be inspected
by PHMSA. Based on these percentages, every state inspector is
responsible for overseeing/inspecting, more than 5,500 miles of
pipeline. That's further than twice the distance from Miami to Seattle.

Enhancing Pipeline Safety
Beginning in 1968, when the Pipeline Safety Act was signed into law
and now, since the passage of the PIPES Act in 2006, states have been
working with PHMSA in fulfilling the mandates of the resulting law.
This is being accomplished in a two-pronged approach: (1) on mandates
that are simple to carry out, processes are put in place that can yield
immediate safety benefits (e.g., increased levels of enforcement); and
(2) on multi-faceted mandates (e.g., excavation damage prevention)
states work with the Federal Government, and where appropriate, with
private stakeholders, to concentrate on developing practical, effective
and affordable solutions to implement the various aspects of such
mandates. Although such efforts take more time, the result is a
carefully crafted, sensible approach that is more likely to achieve the
stated goal of the legislative mandate.
Essential to the Federal-state partnership in this area are the
pipeline safety program managers in each of 52 state agencies which are
members of NAPSR. In addition to their intensive inspection oversight
work schedules, many take extra time to address areas of concern in
meeting the existing challenges or with new initiatives and proposals
for recommended improvements to pipeline safety. NAPSR currently has
members on 27 task groups, with representatives from 33 states working
with PHMSA on key safety elements of the pipeline safety program. These
include, but are not limited to, excavation damage prevention, gas
distribution integrity management, gas transmission and hazardous
liquids integrity management, public awareness communications, control
room management, safety performance data collection and analysis,
national consensus standards development, risk-based and integrated
inspections, and planning for pipeline right-of-way encroachment. With
their knowledge and experience about conditions in their states, NAPSR
members provide unique and valuable expertise to these task groups.

Four Key Elements in Ensuring Pipeline Safety
The focus of state efforts is concentrated onto four major
elements:

Comprising the first and basic element in pipeline safety are
on-going state inspection efforts of jurisdictional pipeline
facilities to verify operator compliance with long-standing
Federal standards that cover design, installation, initial
testing, corrosion control and many operating and maintenance
functions. While new sets of regulations have been developed to
address recently identified needs, the on-going enforcement of
the original code requirements is essential to maintaining the
basic levels of safety in our pipeline systems. Oversight of
properly installed new facilities for example, should minimize
future integrity issues.

The second element in pipeline safety is minimizing excavation
damage to pipelines. NAPSR members worked with PHMSA in
developing the necessary implementation steps for the 9
elements specified in the PIPES Act for excavation damage
prevention. Our members are now undertaking projects each year
that help promote One-Call programs and other initiatives to
put into practice the various components of the 9-element
damage prevention program specified in the Act.

The third key element of pipeline safety is pipeline system
integrity resulting from the last two pipeline safety
reauthorizations. Through NAPSR, states worked in the recent
past with a stakeholder group to develop the foundation of the
Distribution Integrity Management Program rule. We are now
working with PHMSA to ensure proper implementation of this rule
which adds formalized integrity management coverage of over 1.8
million miles of distribution pipelines strictly under state
jurisdiction. State programs will be 100 percent responsible
for this, which is about to undergo the test of time to verify
the effectiveness of the corresponding legislative mandate and
its regulatory offspring.

It must be remembered that many states have long had successful
integrity management programs in the form of additional and
accelerated operating and maintenance activities, as well as
planned pipe replacement programs. These programs have been
very effective in addressing the local needs of the individual
distribution systems throughout the country, and are based on
the actual circumstances affecting the individual systems. We
are the source of many of the pipeline safety best practices
developed in this area. New Federal requirements have
significantly increased the states' compliance verification
workload, particularly in the area of written procedures,
implementation processes, on-going data collection and
analysis, and recordkeeping.

Finally, a fourth and critical key element in dealing with
pipeline safety is the practice of fiscal responsibility
through the management of risk. This may include risk-based
approaches to pipeline safety to allow the operators under
state jurisdiction to apply their resources to the areas where
they are most needed, while enhancing or maintaining safety.
Through forums at National Association of Regulatory Utility
Commissioners (NARUC) and the efforts of NAPSR, we work with
our Federal partner, PHMSA, to identify such areas. This
requires ensuring that proper data is collected by our
operators and compiled by our program offices, so that risks
can be properly identified, assessed and mitigated. Here, our
NAPSR members are engaged in an on-going effort with PHMSA to
collect reliable, high quality, relevant data on the
characteristics and safety performance of the Nation's gaseous
and hazardous liquid fuel delivery systems. The associated
costs of all these programs are mostly covered by in-state user
fees and cost-of-service fees, which are augmented by Federal
grant funds derived from Federal user fees--part of which is
also paid by intrastate pipelines. Our regulatory commissions
are directly accountable to the states' ratepayers and are the
fiscal guardians responsible for prudent funding decisions
balanced by the goal of ensuring pipeline safety.

Part of fiscal responsibility also lies with the Federal Government
living up to its original promise from the Pipeline Safety Act of 1968
which provided for up to 50 percent funding of state expenditures for
pipeline-safety. Most recently, the PIPES Act of 2006 authorized a
maximum Federal funding goal of 80 percent of the states' program
costs. Still, it can be shown that in 2009, State gas users have paid
for more than 68 percent of the total pipeline safety program costs.
Final FY 2010 figures are not yet available.
Grant funding of the states through the Federal Pipeline Safety
Program is vital to enabling the states to ensure the safety of
existing pipeline facilities and of new pipeline construction projects
through state inspection activities. These funds form the foundation of
the Federal-state partnership that makes it possible to carry out the
necessary inspection and enforcement work involving pipeline systems of
more than 9,000 gas distribution, transmission and hazardous liquid
companies in the U.S.

The Need to Allow Current Mandates to Work
Amendments in 1996, 2002, and 2006, to Title 49 USC Chapter 601
have set in place additional mandates for pipeline safety in the law.
As a result of those amendments, new regulations, technical standards,
inspection protocols and training requirements have been or are being
adopted. In accordance with Federal certification requirements, each
state must incorporate these changes into their pipeline safety
programs, giving rise to an increasing need for accompanying resources
in maintaining such programs. Furthermore, it takes time for the more
complex mandates of the last three pipeline safety reauthorizations to
achieve maturity. At this point, we do not have conclusive proof that
all these mandates are effective in ensuring safety of pipeline
facilities, but positive effects are becoming noticeable. We feel more
``test time'' is needed, and it seems to us, that added legislative
mandates on the PHMSA pipeline safety program are not warranted during
this period. They may even exacerbate the hardship many state pipeline
programs are currently under, as shown below.
Due to prior insufficient appropriations, states have had to grow
their programs to fulfill the new unfunded mandates and have thus been
forced to cover with state funds a larger share of the program costs
white the Federal share has fallen short of the amount authorized by
Congress.
Despite this shortfall in appropriated Federal funding, states have
continued to improve safety, as is evident from the reduction in
serious pipeline incident data collected by PHMSA over the past 10
years. The record also clearly demonstrates that states in association
with PHMSA have made steady progress in implementing the many mandates
over the past years.
The PHMSA FY 2009 budget request and ensuing appropriation was a
first step directed toward fulfilling the goals established by Congress
in the 2006 Pipes Act (49 U.S.C. Chapter 601) for PHMSA to provide
grants for up to 80 percent of the states' yearly expenditures. FY 2010
appropriations further increased funding toward that goal.
However, Federal grant funds are not just passed along to the
states. There is a means test for eligibility for such grant funds in
the pipeline safety law. Section 60107(b) requires that state spending
(excluding the Federal contribution) on its natural gas and hazardous
liquid safety programs must at least equal the average amount spent in
the previous 3 years. This condition has led to an unintended
consequence. Fortunately, there is a provision by which the Secretary
of Transportation is authorized to waive this requirement.

Unintended Consequence
It has become apparent that in the absence of such a waiver, this
provision could have unanticipated negative impacts on state pipeline
safety programs and the Federal/state partnership. At one point, PHMSA
has even suggested that a legal interpretation of the language
indicates that if a state does not maintain its three-year average
spending level, it could lose eligibility for any grant funds. At the
present time, states are almost universally experiencing severe
economic distress, with reduced revenues and massive budget shortfalls
leading to across-the-board budget cuts, hiring and travel
restrictions, deferred equipment purchases, and other often draconian
measures to control state expenditures. For example, in 18 states
pipeline safety program employees have been furloughed without pay,
some for as many as 21 days. In this environment, it is inevitable that
many states will be forced to reduce expenditures for pipeline safety.
This is not a reflection of the states' commitment to pipeline safety,
but the reality of the current economic crisis.
A survey of state pipeline safety agencies conducted by NAPSR shows
that more than half of the states are experiencing budget cuts with the
remainder taking other measures and expecting possible budget cuts over
the next few years. Not only is growth in state programs during these
times very unlikely, some cutbacks in state expenditures are certain.
Penalizing states under such circumstances undermines state
programs at a time when Federal support for their mission is more
important than ever. The availability of grant funds to reach adequate
funding at the state program level is a very important factor in
protecting state programs from further cutbacks, and even from calls to
discontinue the programs entirely. PHMSA has realized this and after
about 8 months of deliberations, waiver requests by states are being
carefully considered on a state-by-state basis.

How Reauthorization Can Help
The currently contemplated reauthorization process could mitigate
the unintended consequence of Section 60107(b) by specifying that
rather than a rolling average of the previous Fiscal Years, the 3-year
average of state expenditures would be computed on the basis of FY
2004, 2005 and 2006. The rationale for this is that with the passage of
the PIPES Act in 2006, state programs were given a significant number
of added unfunded mandates, that is, mandates whose state funding was
not matched by increased Federal grant appropriations until FY 2009. An
example of such a mandate with a potentially huge impact is the
requirement for gas Distribution Integrity Management Programs.
Ideally, the modification to the existing law would further specify
that the DOT Secretary may grant a waiver of this requirement to a
state in the event of special circumstances, for reasons that may
include a state's inability to collect sufficient revenue to maintain
or increase the state's share of its safety program as required by the
above-named section of the law. The precedent for this approach was set
during passage of the Pipeline Safety improvement Act of 2002 which
included provisions in the law for pipeline facility risk analysis and
integrity management programs. Paragraph 60109(c)(5) of the law states
that ``the Secretary may waive or modify any requirement for
reassessment of a facility under paragraph (3)(B) for reasons that may
include the need to maintain local product supply or the lack of
internal inspection devices if the Secretary determines that such
waiver is not inconsistent with pipeline safety.'' This would allow a
faster process for a decision by the Secretary to grant a waiver to a
state.
It is also important to note that even with waivers in place,
states will continue to be subject to a thorough performance assessment
conducted by PHMSA using certification and evaluation criteria that tie
such performance to the grant amount provided to the states.

Conclusions
Programs mandated by the last three pipeline safety
reauthorizations have required and continue to require extensive
additional state efforts to address safety in areas that include but
are not limited to operator qualification requirements, gas
transmission and liquids pipeline integrity, public awareness
communications, excess flow valve installation, pipeline control room
management, distribution system integrity, and excavation damage
prevention. These mandates still need a number of years to prove their
worth. A hiatus in added legislative mandates would be beneficial by
allowing the regulators to focus on the effectiveness of existing
mandates without detriment to safety.
As state programs have had to grow to administer and enforce the
new requirements, Federal grant monies have not been adequate to fund
even 50 percent of the costs of providing the safety and compliance
activities necessary. The states have gradually had to assume a
gradually larger share of the costs of providing for the majority of
the Nation's pipeline safety programs. This was recognized in the PIPES
Act, which authorized PHMSA to reimburse a State with up to 80 percent
of the cost of the personnel, equipment, and activities for pipeline
safety in that state, provided that the state met the means test of its
funding. This last condition is difficult to satisfy due to the
magnitude of the financial crisis that has befallen most states. A
revision to the language in Section 60107(b) would provide timely
financial relief via easier state access to grant funding.
It is now up to this Congressional committee to adjust the
authorized funding for state pipeline safety grants over the next 4
years and to facilitate state access to such funding, so that states
can continue to carry out the Congressionally-mandated expanded safety
programs even during these times of economic distress. Adequate funding
authorized for state programs will directly lead to more inspectors in
the field, more frequent inspections of pipeline operators, more
thorough inspections and fewer pipeline accidents.
Like you, we understand the importance of our mission to the safety
of our citizens, energy reliability and continued economic growth of
our Nation.
Thank you.
______

Prepared Statement of the American Public Gas Association

Mr. Chairman and members of the Committee, the American Pubic Gas
Association (APGA) appreciates this opportunity to submit testimony on
behalf of public gas systems to the Committee for this important
hearing on pipeline safety. APGA also wants to commend the Committee
for all the work it has done over the years to ensure that America has
the safest, most reliable pipeline system in the world.
APGA is the national association for publicly-owned natural gas
distribution systems. There are currently approximately 1,000 public
gas systems located in 36 states. Publicly-owned gas systems are not-
for-profit, retail distribution entities owned by, and accountable to,
the citizens they serve. They include municipal gas distribution
systems, public utility districts, county districts, and other public
agencies that have natural gas distribution facilities. Public gas
systems range in size from the Philadelphia Gas Works which serves
approximately 500,000 customers to the City of Freedom, Oklahoma which
serves 12 customers.

Overview
Safety is the number one issue for public gas systems. No other
issue rises to the level of safety for the local distribution company
(LDC) that provides natural gas service to its consumers. Gas utilities
are the final step in taking natural gas from the production field to
the homeowner or business. As such, our members' commitment to safety
is second to none and they keep focused on providing safe and reliable
service to their customers.
Our members receive their natural gas from interstate transmission
pipelines. Transmission pipelines usually consist of long and straight
lines of pipe that have a large diameter and are operated at high
volumes and high pressures. By contrast, the distribution pipelines in
LDC's are generally smaller in diameter (as small as \1/2\ inch), and
are constructed of several kinds of materials including cast-iron,
steel and plastic. Distribution pipelines also operate at much lower
pressures and always carry odorized gas that can be readily detected by
smell.
Public gas systems are an important part of their community. Our
members' employees live in the community they serve and are accountable
to local officials (and their friends and neighbors). Public gas
systems are generally regulated by their consumer-owners through
locally elected governing boards or appointed officials. However, when
it comes to pipeline safety, nearly all of our members are regulated by
an individual State's pipeline safety office. All of our members must
comply in the same manner as investor- and privately-owned utilities
with pipeline safety regulations issued by the Pipeline and Hazardous
Materials Safety Administration (PHMSA). This includes belonging to the
State ONE-CALL system, marking the location of gas lines when notified
of an excavation and notifying other utilities in advance of the
utility planning to excavate. Municipal gas utilities are subject to
the same excavation damage prevention requirements as their investor-
and privately-owned utility counterparts.
While the manner of safety regulation may be the same, one major
difference between the average investor-owned utility and the average
public gas system is size: in the number of both customers served and
employees. Approximately half of the 1,000 public gas systems have five
employees or less. As a result, regulations and rules do have a
significantly different impact upon a small public gas system than they
do upon a larger system serving hundreds of thousands or millions of
customers with several hundred or even thousands of employees and an
in-house engineering staff.

Implementation of the PIPES Act
The Pipeline Inspection, Protection, Enforcement and Safety Act of
2006 (PIPES Act) contained several provisions that addressed safety
issues at the LDC level, including excavation damage prevention.
Excavation damage is the leading cause of natural gas distribution
pipeline incidents and APGA strongly supports efforts to reduce
excavation damage. The PIPES Act established an incentive program for
states to adopt stronger damage prevention programs. Specifically, the
Act outlined nine elements of effective damage prevention programs. In
order to obtain damage prevention program grants from the U.S.
Department of Transportation, a state must demonstrate, or have made
substantial progress toward demonstrating, that its damage prevention
program has incorporated these nine elements. This flexible approach
has allowed states to implement the nine elements in a manner that
meets their individual needs.
These elements, along with the 811 national ``Call Before You Dig''
number, which began in May, 2007, have helped address excavation
damage. APGA strongly supports this approach to limiting excavation
damage which recognizes that government has a responsibility to adopt
and enforce effective damage prevention programs. APGA commends
Congress and PHMSA for these efforts toward addressing excavation
damage.

Distribution Integrity Management
Another critical component of the PIPES Act was the requirement
that LDC's establish Distribution Integrity Management Programs (DIMP).
Even before the PIPES Act passed, PHMSA had convened a working group of
Federal and state regulators, industry and the public to advise PHMSA
on how to approach DIMP. The group met over a 12 month period. APGA and
its members actively participated in the group. In December 2009, PHMSA
issued a final regulation on DIMP. APGA would also like to commend
PHMSA for its leadership and work toward the development of a final
rule that will significantly enhance safety.
The final rule requires all distribution pipeline operators,
regardless of size, to implement a risk based integrity management
program that addresses seven key elements:

1. Develop and implement a written integrity management plan.

2. Know the infrastructure performance.

3. Identify threats, both existing and of potential future
importance.

4. Assess and prioritize risks.

5. Identify and implement appropriate measures to mitigate
risks.

6. Measure performance, monitor results, and evaluate the
effectiveness of its programs, making changes where needed.

7. Periodically report performance measures to its regulator.

Basically, a gas distribution system must have a written plan in
place and the plan must demonstrate an understanding of the gas
distribution system, including the characteristics of the system and
the environmental factors that are necessary to assess the applicable
threats and risks to the gas distribution system. The operator must
also identify additional information needed and provide a plan for
gaining that information over time through normal activities. The plan
must consider eight categories of threats to the pipeline system. An
operator must consider incident and leak history, corrosion control
records, continuing surveillance records, patrolling records,
maintenance history and excavation damage experience to identify
existing and potential threats.
A key component of this rule, and one strongly supported by APGA,
is that the rule was designed to be flexible. The rule allows each LDC
to manage its system with the goal of improving safety based on the
system's unique performance characteristics, as opposed to following
prescriptive rules that could divert resources away from the most
significant threats for that particular utility. For example, the
transmission integrity management rules imposed a fixed, interval,
inspection-intensive program aimed primarily at detecting corrosion and
mechanical damage. A review of PHMSA's annual and incident report data
for the 3-year period 2005-2007, found that failures on distribution
systems due to corrosion was the least likely of the eight threats
listed in the DIMP rule to result in fatalities, injuries or
significant property loss. On the other hand, a failure due to
excavation damage is eleven times more likely to result in a reportable
incident than a corrosion-caused failure. Under the DIMP rule, each
operator must still assess the risk of corrosion, but only take
additional actions above and beyond current regulations if indicated by
its risk assessment.
The DIMP rule also requires operators to file annual reports with
PHMSA listing the number of excavation damages that occurred during
each calendar year. PHMSA adopted the Common Ground Alliance's Damage
Information Reporting Tool (DIRT) definition of ``damage'' which
includes ``any impact that results in the need to repair or replace an
underground facility due to a weakening, or the partial or complete
destruction, of the facility, including, but not limited to, the
protective coating, lateral support, cathodic protection or the housing
for the line device or facility.'' In the past, only excavation damage
that resulted in a leak was reported on the annual reports, so PHMSA
will be receiving significantly more damage reports than it collected
in the past. This annual report data is available to the public on
PHMSA's website allowing PHMSA, the industry, state regulators and the
public to evaluate trends in excavation damage.
``SHRIMP''
``SHRIMP,'' short for ``Simple, Handy, Risk-based Integrity
Management Plan,'' is a DIMP plan development tool developed by the
APGA Security and Integrity Foundation (SIF). The SIF is a non-profit
501(c)(3) corporation created by APGA in 2004. The SIF is dedicated to
promoting the security and operational integrity and safety of small
natural gas distribution and utilization facilities. The SIF focuses
its resources on enhancing the abilities of gas utility operators to
prevent, mitigate and repair damage to the Nation's small gas
distribution infrastructure. The SIF delivers programs and services to
the industry through a cooperative agreement with PHMSA while working
closely with the National Association of Pipeline Safety
Representatives (NAPSR) and other state pipeline safety organizations.
SHRIMP is a web-based tool that walks the user through the steps of
developing a Distribution Integrity Management Plan, similar to how tax
preparation software walks users through preparing income tax returns.
It asks questions about the material of construction of the
distribution system; the results of required inspections and tests; the
number and causes of leaks on the system and other information relevant
to assessing the eight threats in the DIMP rule. Where any threat is
elevated, SHRIMP offers suggestions for additional actions the user
could implement to reduce that threat as well as performance measures
to determine whether the additional action chosen is effective at
reducing the threat. The output is a complete, written DIMP plan
customized for the user's system that meets all the requirements of the
regulation. SHRIMP is available to all distribution operators (investor
owned, municipal, master meter, etc) and it is free to the small
systems with fewer than one thousand customers.

Control Room Management
The PIPES ACT also required PHMSA to regulate fatigue and other
human factors in pipeline control rooms. PHMSA issued control room
management rules in December 2009. While these rules may be reasonable
when applied to transmission pipeline controllers, unfortunately
PHMSA's definition of a controller has the unintended consequences of
classifying hundreds of public gas system employees as pipeline
controllers. PHMSA's rule fails to differentiate between Supervisory
Control and Data Acquisition (SCADA) systems and telemetry systems that
simply transmit data to a central office. All SCADA systems include
telemetry, but all telemetry is not SCADA if it provides no means to
control the operation of the pipeline. By PHMSA's definition, however,
anyone who can display telemetered data on a computer is a controller.
Distribution systems typically monitor the pressure and flow at the
gate stations where they receive gas from their transmission pipeline
supplier. They may also record pressures at various points around the
distribution system to ensure there is adequate pressure to deliver gas
to customers at the extreme ends of the system. For years these data
were recorded on paper charts, manually collected each day.
Increasingly utilities are installing telemetry to transmit these data
back to the office where it can be periodically reviewed throughout the
day by utility managers. This allows faster response to low flow/low
pressure situations and frees up the personnel who collected pressure
charts for other inspection and maintenance activities. Some systems
allow telemetry to be viewed remotely via the Internet. This telemetry
is for business purposes, not public safety.
Because distribution systems operate at relatively low pressures
and are an interconnected network rather than a straight line pipeline,
a complete rupture of a distribution line would be unlikely to cause a
flow surge or pressure drop detectable by the telemetry system. Even
were a pressure drop to be detected, all these ``controllers'' can do
is send other personnel to investigate--they have little or no actual
control over the system and no ability to isolate a suspected leak.
For years distribution systems operated safety without the ability
to monitor these data in real time. Even today, many of these ``SCADA
systems'' are left unattended at night and over weekends and holidays.
Yet PHMSA's rules would require utilities to implement a fatigue
management program for individuals and their supervisors who have
access to a SCADA monitor that can safely go unattended over nights and
weekends. This rule adds significant costs to a utility's decision to
automate the transmission of operational data back to offices and thus
stifles the use of telemetry to gas distribution operations.
APGA's concerns could be easily addressed were PHMSA to simply
adhere to the unambiguous language in its controller definition that
states a controller is one who both monitors AND controls via a SCADA
system. Instead, PHMSA stated in the preamble to the rule that it
believes ``control via a SCADA system'' actually means control via
means other than a SCADA system, resulting in the unintended
consequences described above.

Reauthorization
APGA supports reasonable regulations to ensure that individuals who
control the Nation's network of distribution pipelines are provided the
training and tools necessary to safely operate those systems. In this
regard, over the past several years the industry has had numerous
additional requirements placed on it, e.g., DIMP, excess flow valves,
control room management, operator qualification, public awareness and
more. Many of our members are in the process of working to comply with
the administrative burdens of these additional regulations. Given that
our members are non-profit systems in many cases with limited
resources, these additional regulations, while important, do impose an
additional operational burden upon them. For this reason, APGA strongly
supports a clean reauthorization of the Act.
Should the Committee consider revisions to the Act, there are a
number of issues APGA would ask the Committee to consider. We urge the
Committee to give great consideration before imposing any additional
regulatory burdens upon LDC's through this reauthorization effort. In
terms of reauthorization, APGA is specifically concerned about an
expansion in the requirements for excess flow valves and potential
changes in the funding mechanism for PHMSA.

Excess Flow Valves (EFVs)
The PIPES Act included a provision requiring operators to install
excess flow valves on new and replaced single residential service that
operate year around at or above 10 pound-force per square inch gauge.
Exceptions are provided if EFVs are not available, if it is known there
are contaminants in the system that would cause the EFV to fail or if
it is known there are liquids in the system. Prior to this installation
requirement, there was a customer notification rule in place that
required gas systems to make their customers aware of the availability
of EFVs and install an EFV if the customer was willing to pay
installation costs. It was limited to new and renewed services because
EFVs are installed underground where the ``service line'' to a
residence connects to the gas main. If a hole is already open and a new
connection to the main is being installed, adding an EFV at that time
costs just a fraction of what it would cost to install or replace an
EFV when no other work is planned at the main-service connection.
Each EFV has a preset closure flow rate. Once installed on a
service line it will prevent gas from flowing at any flow rate higher
than its preset closure flow rate. There is no way short of replacing
the EFV to change its closure flow rate. This is typically not an issue
with EFVs on residential service lines since the gas demand to a
residence does not typically change drastically. A residence will have
a relatively constant and predictable gas demand over its lifetime so
the EFV can be sized accordingly.
However, APGA is greatly concerned about an expansion of the EFV
requirements to commercial and industrial businesses and multifamily
residences. A commercial building, unlike a residential unit, may see
huge changes in gas demand as tenants in the space move in and out. For
example, a space in a strip mall that today is occupied by a shoe store
could be converted to a restaurant or bakery tomorrow. The gas demand
could double or triple. That could require replacing the meter,
regulator and EFV. Since the first two items are above ground,
replacement is relatively inexpensive. However, the EFV is buried and
replacing it would be very costly, often hundreds of times the initial
cost of the EFV. To address this problem, an operator could install a
grossly oversized EFV with closure flow at or near the free flow limits
of the service line. However, a valve so oversized would probably not
close even if the line were ruptured, defeating the purpose of having
an EFV on the line in the first place.
The same and additional issues apply to installing EFVs on service
lines to industrial customers. The flow rates and operating pressures
to many industrial customers exceed the capacity of commercially
available EFVs.
The potential costs of a false closure of the EFV can be
significantly greater for a commercial or industrial customer than a
residence. Both would suffer business losses in addition to the
inconvenience of no heat or hot water. An evening's loss of business to
a restaurant could run into the thousands of dollars, however some
industries such as microprocessor chip manufacturers could see millions
of dollars of product ruined by the loss of temperature control
required by their processes.
The industry has experience with EFVs designed for typical flow
rates to single-family residences, but has little or no experience with
EFVs designed for larger flows.
PHMSA has established a working group of government, industry and
public experts to study the issues related to installing large volume
EFVs on other than single residential services. We encourage Congress
to allow this stakeholder working group to proceed toward making
specific recommendations on this issue.

Funding of User Fees
Under the current formula, user fees for funding PHMSA are
collected by natural gas transmission operators from their downstream
customers. User fees are mandatory costs a natural gas transmission
operator can pass through to customers in its cost-of-service. This
allowable pass-through treatment is similar to other mandatory safety
program costs. As a result, it is natural gas distribution operators
that pay the user fees to transportation operators in their
transportation rates, and it is the natural gas transmission operators
that, after collecting the user fees from its customers, pass those
fees to PHMSA in the annual pipeline safety user fee assessment.
APGA supports this current formula and we believe it has worked
well over the years. APGA is strongly opposed to any changes in the
current formula that would shift the user fees to the LDC's. The
pipelines currently build these fees into their costs and if they
believe they are not recovering the costs, they have an option provided
to them under Section 4 of the Natural Gas Act to file for a rate
increase with the Federal Energy Regulatory Commission. Since the
Federal Energy Regulatory Commission has never turned down a request to
include pipeline safety user fees in transportation rates charged by
interstate pipelines, the decision whether or not to pass through all
or a portion of the user fees to its customers is completely within the
pipeline's discretion. If for business reasons a natural gas
transmission operator makes a business decision not to pass this safety
cost through to one or more of its customers (e.g., it wishes to
discount rates to certain customers, avoid filing a rate case, etc.),
any consequence arising from that decision should be borne by that
natural gas transmission operator.
Shifting fees to distribution would mean that LDC customers would
pay both the user fees assessed to the LDC and the fees passed on in
transportation rates charged by their pipeline supplier. Gas customers
served directly from a transmission line would pay a lesser amount of
user fees per unit of gas than if the same customer were served through
the LDC. The current user fee system also greatly simplifies fee
collection as there are fewer transmission pipeline operators than
there are LDCs. The current system of user fee collection has worked
well for over 20 years.

Integrity Management of Low Stress Transmission Lines
Currently, low stress transmission lines (a line operating below 30
percent of the specified minimum yield stress) operated by distribution
systems are regulated under the Transmission Integrity Management
Program (TIMP). It is APGA's position that those pipelines should be
regulated under the Distribution Integrity Management Program (DIMP).
The benefit of handling this under DIMP is that TIMP focuses on finding
mainly corrosion problems. The DIMP rule addresses corrosion but also
requires distribution operators to consider other threats to integrity
including excavation, natural forces, incorrect operations and more.
When a high stress line corrodes it can suddenly rupture, whereas a low
stress line would just start leaking, and the leak would get
progressively worse over time. The utility has time to find it through
ongoing leak surveys and patrols and fix it before it threatens public
safety. Since the big issue with distribution is third-party damage,
all the inspections for corrosion are of questionable benefit.

Conclusion
Natural gas is critical to our economy, and millions of consumers
depend on natural gas every day to meet their daily needs. It is
critical that they receive their natural gas through a safe, affordable
and reliable delivery by their LDC. We look forward to working with the
Committee toward reauthorization of the Pipeline Safety Act.