[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.

---------------------------------------------------------------------------
   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.
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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.

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 regulations 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.

    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;

        (C) a railroad accident in which there is a fatality or 
        substantial property damage, or that involves a passenger 
        train;

        (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.

                                  
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