[House Hearing, 108 Congress]
[From the U.S. Government Publishing Office]



                            PIPELINE SAFETY

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

                                HEARING

                               before the

                 SUBCOMMITTEE ON ENERGY AND AIR QUALITY

                                 of the

                    COMMITTEE ON ENERGY AND COMMERCE
                        HOUSE OF REPRESENTATIVES

                      ONE HUNDRED EIGHTH CONGRESS

                             SECOND SESSION

                               __________

                             JULY 20, 2004

                               __________

                           Serial No. 108-111

                               __________

       Printed for the use of the Committee on Energy and Commerce


 Available via the World Wide Web: http://www.access.gpo.gov/congress/
                                 house


                               __________

                    U.S. GOVERNMENT PRINTING OFFICE
95-457                      WASHINGTON : 2004
____________________________________________________________________________
For Sale by the Superintendent of Documents, U.S. Government Printing Office
Internet: bookstore.gpo.gov  Phone: toll free (866) 512-1800; (202) 512ï¿½091800  
Fax: (202) 512ï¿½092250 Mail: Stop SSOP, Washington, DC 20402ï¿½090001

                    COMMITTEE ON ENERGY AND COMMERCE

                      JOE BARTON, Texas, Chairman

W.J. ``BILLY'' TAUZIN, Louisiana     JOHN D. DINGELL, Michigan
RALPH M. HALL, Texas                   Ranking Member
MICHAEL BILIRAKIS, Florida           HENRY A. WAXMAN, California
FRED UPTON, Michigan                 EDWARD J. MARKEY, Massachusetts
CLIFF STEARNS, Florida               RICK BOUCHER, Virginia
PAUL E. GILLMOR, Ohio                EDOLPHUS TOWNS, New York
JAMES C. GREENWOOD, Pennsylvania     FRANK PALLONE, Jr., New Jersey
CHRISTOPHER COX, California          SHERROD BROWN, Ohio
NATHAN DEAL, Georgia                 BART GORDON, Tennessee
RICHARD BURR, North Carolina         PETER DEUTSCH, Florida
ED WHITFIELD, Kentucky               BOBBY L. RUSH, Illinois
CHARLIE NORWOOD, Georgia             ANNA G. ESHOO, California
BARBARA CUBIN, Wyoming               BART STUPAK, Michigan
JOHN SHIMKUS, Illinois               ELIOT L. ENGEL, New York
HEATHER WILSON, New Mexico           ALBERT R. WYNN, Maryland
JOHN B. SHADEGG, Arizona             GENE GREEN, Texas
CHARLES W. ``CHIP'' PICKERING,       KAREN McCARTHY, Missouri
Mississippi, Vice Chairman           TED STRICKLAND, Ohio
VITO FOSSELLA, New York              DIANA DeGETTE, Colorado
STEVE BUYER, Indiana                 LOIS CAPPS, California
GEORGE RADANOVICH, California        MICHAEL F. DOYLE, Pennsylvania
CHARLES F. BASS, New Hampshire       CHRISTOPHER JOHN, Louisiana
JOSEPH R. PITTS, Pennsylvania        TOM ALLEN, Maine
MARY BONO, California                JIM DAVIS, Florida
GREG WALDEN, Oregon                  JANICE D. SCHAKOWSKY, Illinois
LEE TERRY, Nebraska                  HILDA L. SOLIS, California
MIKE FERGUSON, New Jersey            CHARLES A. GONZALEZ, Texas
MIKE ROGERS, Michigan
DARRELL E. ISSA, California
C.L. ``BUTCH'' OTTER, Idaho
JOHN SULLIVAN, Oklahoma

                      Bud Albright, Staff Director

                   James D. Barnette, General Counsel

      Reid P.F. Stuntz, Minority Staff Director and Chief Counsel

                                 ______

                 Subcommittee on Energy and Air Quality

                     RALPH M. HALL, Texas, Chairman

CHRISTOPHER COX, California          RICK BOUCHER, Virginia
RICHARD BURR, North Carolina           (Ranking Member)
ED WHITFIELD, Kentucky               TOM ALLEN, Maine
CHARLIE NORWOOD, Georgia             HENRY A. WAXMAN, California
JOHN SHIMKUS, Illinois               EDWARD J. MARKEY, Massachusetts
  Vice Chairman                      FRANK PALLONE, Jr., New Jersey
HEATHER WILSON, New Mexico           SHERROD BROWN, Ohio
JOHN B. SHADEGG, Arizona             ALBERT R. WYNN, Maryland
CHARLES W. ``CHIP'' PICKERING,       GENE GREEN, Texas
Mississippi                          KAREN McCARTHY, Missouri
VITO FOSSELLA, New York              TED STRICKLAND, Ohio
GEORGE RADANOVICH, California        LOIS CAPPS, California
MARY BONO, California                MIKE DOYLE, Pennsylvania
GREG WALDEN, Oregon                  CHRIS JOHN, Louisiana
MIKE ROGERS, Michigan                JIM DAVIS, Florida
DARRELL E. ISSA, California          JOHN D. DINGELL, Michigan,
C.L. ``BUTCH'' OTTER, Idaho            (Ex Officio)
JOHN SULLIVAN, Oklahoma
JOE BARTON, Texas,
  (Ex Officio)

                                  (ii)




                            C O N T E N T S

                               __________
                                                                   Page

Testimony of:
    Beggs, Breean, Executive Director, Center for Justice, on 
      behalf of Pipeline Safety Trust............................    72
    Bonasso, Samuel G., Deputy Administrator, Research and 
      Special Programs Administration, Department of 
      Transportation; accompanied by Stacey Gerard, Associate 
      Administrator, Office of Pipeline Safety...................     9
    Fischer, Earl, Senior Vice President, Utility Operations, 
      Atmos Energy Corporation...................................    46
    Kipp, Robert, Executive Director, Common Ground Alliance.....    82
    Koonce, Paul D., Chief Executive Officer, Dominion Energy, on 
      behalf of Interstate Natural Gas Association of America....    77
    Mead, Kenneth M., Inspector General, Department of 
      Transportation.............................................    17
    Pearl, Barry, President and CEO, Teppco Partners, L.P., on 
      behalf of Association of Oil Pipe Lines and the American 
      Petroleum Institute........................................    55
    Siggerud, Katherine, Director of Physical Infrastructure 
      Issues, Government Accountability Office...................    15

                                 (iii)

  

 
                            PIPELINE SAFETY

                              ----------                              


                         TUESDAY, JULY 20, 2004

                  House of Representatives,
                  Committee on Energy and Commerce,
                    Subcommittee on Energy and Air Quality,
                                                    Washington, DC.
    The subcommittee met, pursuant to notice, at 11 a.m., in 
room 2123 of the Rayburn House Office Building, Hon. Ralph M. 
Hall (chairman) presiding.
    Members present: Representatives Hall, Norwood, Shimkus, 
Shadegg, Walden, Otter, Barton (ex officio), Boucher, Allen, 
Pallone, Wynn, Green, and McCarthy.
    Staff present: Mark Menezes, majority counsel; William 
Cooper, majority counsel; Peter Kielty, legislative clerk; 
Bruce Harris, minority professional staff member; and Sue 
Sheridan, minority senior counsel.
    Mr. Hall. The subcommittee will come to order. I certainly 
want to thank everyone for coming to today's hearing on 
pipeline safety. Without objection, the committee will proceed 
pursuant to committee rule 4(e). It is so ordered. The Chair 
recognizes himself for an opening statement.
    The life's blood I guess of this Nation depends upon the 
intricate network of pipelines that criss-cross our country. 
Pipelines deliver natural gas, crude oil, gasoline, diesel 
fuel, and a variety of other products to factories, industrial 
sized distribution systems and homes throughout the United 
States.
    Without pipelines, delivering these products would be just 
absolutely prohibitive. Without pipelines, the safety of our 
citizens and the security of our Nation would be jeopardized. 
Indeed, pipelines are the safest mode of transportation for 
fuels that we depend upon every day for our existence and 
quality of life.
    Yet, Federal regulation is needed to ensure that interstate 
pipelines operate as safely as possible. The Office of Pipeline 
Safety is charged with the duty of regulating the pipeline 
industry. Over the past few years, OPS has made a great effort 
to improve its office and even to redefine what it means to be 
a regulator.
    Instead of the old ``Wait until it breaks, then fix it'' 
attitude, OPS has instituted a new mode of enforcement that 
seeks to correct problems before accidents occur; in other 
words, work together to solve pipeline safety issues beforehand 
and not wait until an accident occurs and then point fingers.
    The government spends too much time trying to attach blame 
after the fact and not enough time working on prevention. 
Gladly, OPS has broken out of that mold.
    I'm encouraged by the progress we see. However, I caution 
the Department of Transportation on two fronts. One, if the DOT 
wants to relocate OPS, be cautious. Don't go beyond your 
statutory boundaries, such as has been suggested with local 
distribution companies.
    When my children were younger, I was always telling them to 
color within the lines within their coloring books. Each time 
they saw the wisdom in doing so. We all have boundaries. Let's 
stay in them.
    I look forward to learning from these witnesses here today. 
As you will note during the course of this hearing, members 
will come and go. I want to assure you that your complete 
testimonies will be made available to each member of this 
subcommittee, whether they are here in person or not.
    Your testimony is important in the decisionmaking process 
of this subcommittee and will be duly considered. Actually, we 
base most legislation around intelligent and giving people like 
you that give of your time to prepare for this hearing, give of 
your time to arrive here, give of your time to advise us and to 
sit through this committee hearing and listen to opening 
statements that you may get tired of hearing. I don't know how 
many we will have today, not very many, but I was as quick and 
as least destructive as I could be with mine.
    At this time, I recognize the ranking member, who will 
probably have an outstanding opening statement because he is an 
outstanding member of this committee, the Honorable Rick 
Boucher.
    Mr. Boucher. Well, thank you very much, Mr. Chairman. I 
will try to make my statement as expeditious as was yours. I 
appreciate your convening today's hearing on the topic of 
pipeline safety.
    In 2002, the Pipeline Safety Act, which originated in this 
subcommittee, was signed into law. Prior to 2002, the GAO 
released a report which contained troubling information about 
the enforcement of pipeline safety.
    For example, the General Accounting Office found that the 
Office of Pipeline Safety at the Department of Transportation 
had effectively eliminated the use of fines as an enforcement 
tool and that monetary penalties had declined by more than 90 
percent from the year 1990 until 1998.
    Meanwhile tragic pipeline accidents in Bellingham, 
Washington in 1999 and in Carlsbad, New Mexico in the year 
2000, which claimed a total of 15 lines, underscored the 
consequences of inadequate enforcement of the pipeline safety 
laws.
    Given the problems highlighted by the GAO's report and the 
National concern about the adequacy of pipeline safety law 
enforcement, the Congress made significant reforms to the 
pipeline safety program when we passed the Pipeline Safety Act 
in 2002.
    That law contains several new mandates, including a 
requirement that gas pipeline operators in high-consequence 
areas, implement integrity management programs, mandatory 
baseline inspections of all high-consequence area gas pipelines 
within 10 years and reinspections every 7 years thereafter, 
increased civil penalties for companies found to be operating 
below safety standards, and a variety of community assistance 
programs, including enhanced one-call notification, public 
education, and the authorization of technical assistance 
grants, so that communities could participate in a meaningful 
way in local pipeline proceedings.
    As a part of the act, GAO was required to conduct a study 
of the fine and penalty assessment and collection process. That 
study is scheduled to be released publicly later this week.
    In addition, the Department of Transportation's Inspector 
General has released a report that indicates that significant 
progress has been made with regard to pipeline safety since the 
year 2000. We will hear from our witnesses today, who can 
address findings in each of these reports.
    The final rule establishing an integrity management program 
for natural gas transmission lines was issued by the department 
in December 2003. That rule does not cover distribution lines. 
And I am interested in hearing from our witnesses today about 
the potential for including distribution lines and required 
integrity management plans on a going-forward basis. I 
personally think they should be covered.
    I am concerned about the problems that arise with regard to 
natural gas distribution in municipalities around the Nation. 
It seems to me that IMPs should also be required with respect 
to distribution lines. I will be very interested in what our 
witnesses have to say on that subject this morning.
    These plans work. IMPs for hazardous pipeline liquids have 
uncovered 20,000 pipeline integrity threats, which otherwise 
might have remained undiscovered.
    It's also my understanding that there has been no action 
taken by the Office of Pipeline Safety to date with regard to 
technical assistance grants to communities which were mandated 
under the 2002 law. These grants were intended to provide 
funding to assist communities in obtaining technical analysis 
and other technical assistance so that communities could 
participate in a meaningful way when pipeline safety issues are 
discussed in those localities.
    We need to know when regulations for technical assistance 
grants will be written and when funds will be available under 
these grants to communities across the Nation.
    Today's witnesses will provide a timely update on the 
implementation of the reforms mandated by our 2002 legislation. 
I want to thank the witnesses for taking their time to join us 
this morning. And I very much look forward to their testimony.
    Thank you, Mr. Chairman. I yield back.
    Mr. Hall. Thank you, Mr. Boucher.
    The Chair recognizes the gentleman from Illinois, Mr. 
Shimkus.
    Mr. Shimkus. Mr. Chairman, after your statement and the 
statement of the ranking member, I am well-prepared, and I will 
waive my opening statement.
    Mr. Hall. Mr. Pallone? The Chair recognizes Mr. Pallone.
    Mr. Pallone. Mr. Chairman, thank you for holding this 
hearing today on pipeline safety.
    I wish we could be sitting here today praising the Office 
of Pipeline Safety for dramatic improvements in assuring that 
our communities were safe from pipeline explosions, but, 
unfortunately, that is not the case.
    In 2002, Congress worked together to pass comprehensive 
pipeline safety legislation. And when President Bush signed the 
bill into law that year, I had hoped that we were making waves 
in strengthening and enhancing OPS' ability to conduct its 
duties. Sadly, this has not happened. And people remain 
vulnerable to pipeline hazards.
    Part of the legislation that we passed required the GAO to 
issue a report on the OPS' progress in carrying out the 
required reforms of the 2002 law. From what I understand, this 
report will be released later this week and will reflect that 
minimal improvements have been made. And, moreover, the OPS is 
being criticized for not implementing a mechanism for 
collection of penalties or an overall strategy for improving 
pipeline safety.
    In addition, the 2002 law required the Inspector General of 
the Department of Transportation to conduct a similar study of 
the OPS. This report was released in June. And it called on the 
OPS to complete implementation of congressional mandates, such 
as pipeline security.
    I, along with my colleagues, worked very hard over a number 
of years to create a Nationwide one-call notification program 
in an effort to avoid disastrous pipeline disasters that we 
have seen in the past, including the one in my own district of 
Edison, New Jersey.
    When such legislation was signed into law, we expected 
action. I understand that the FCC is in the midst of the 
rulemaking process with regard to a Nationwide one-call 
program, and I cannot express strongly enough the need for one-
call damage prevention and education programs to be implemented 
in a timely manner and in an accountable manner.
    As an avid proponent of improving pipeline safety, I expect 
compliance of congressional mandates from the OPS. I have seen 
firsthand a terrible pipeline explosion that occurred in 
Edison, in my district, in 1994.
    I know that because of the role that pipelines play in the 
transportation of both natural gas and hazardous liquids we 
need to be sure that pipelines are safe. My constituents also 
understand the need for safe pipelines. A few years ago in my 
district, a section of a new pipeline was rejected, in part 
because the perception by the public is that pipelines are not 
kept safe through proper inspection and oversight.
    Federal regulations to protect the public are woefully 
inadequate. And since pipeline safety laws were strengthened in 
2002, I'm afraid the Office of Pipeline Safety has not yet come 
near the established standards or requirements regarding the 
timing and frequency of pipeline inspections or the use of 
internal inspection devices. And I hope that we will see some 
improvement as a result of this hearing today.
    Thank you, Mr. Chairman.
    Mr. Hall. The Chair recognizes Mr. Norwood, the gentleman 
from Georgia.
    Mr. Norwood. Thank you very much, Mr. Chairman. I will just 
submit my opening statement for the record, even as good as it 
is.
    [The prepared statement of Hon. Charlie Norwood follows:]

    Prepared Statement of Hon. Charlie Norwood, a Representative in 
                   Congress from the State of Georgia

    Thank you, Mr. Chairman. I appreciate you taking the time to hold 
this important hearing today.
    The safety and security of our pipeline system is absolutely vital 
to our country's energy market. The 2.3 million miles of natural gas 
and hazardous liquid pipelines carry almost two-thirds of the energy 
consumed by our country. Liquid pipelines carry over 75% of the crude 
oil and approximately 60% of the refined petroleum products delivered 
in the U.S. The management of these pipelines along with ensuring that 
their infrastructure is sound is vital to our national security and to 
every single energy consumer in this country.
    Transporting hazardous material is an issue we seem to be in 
constant debate over in this Subcommittee. We know that our pipeline 
system is the safest mode for transporting natural gas and hazardous 
liquids. According to DOT statistics, third-party damage was the 
largest contributor to pipeline releases in 2002.
    As we all know the Office of Pipeline Safety is charged with 
securing these vast pipelines. I was pleased to take part in a bi-
partisan effort in the last Congress to improve our system. I was a 
cosponsor and strong supporter of the Pipeline Safety Improvement Act 
of 2002. That legislation included important changes to the federal 
pipeline safety programs as well as providing states with oversight 
responsibility of pipeline operators.
    Today is an excellent opportunity to hear from our two panels of 
expert witnesses on the implementation efforts of the Pipeline Safety 
Improvement Act. Thank you Mr. Chairman, I look forward to the rest of 
today's hearing.

    Mr. Hall. Thank you, Mr. Norwood.
    The Chair recognizes the gentleman from Texas, Mr. Green.
    Mr. Green. Thank you, Mr. Chairman.
    I appreciate your calling the hearing today and examining 
the progress made on pipeline safety. And I want to note that a 
number of witnesses, including the General Accounting Office 
or, as we call it now, I guess, the Government Accounting 
Office and the American Gas Association testified that 
pipelines are the safest means of energy transportation.
    I support the continued efforts for improved pipeline 
safety standards, but we should give credit on the progress 
that has been made. Since their development, pipelines have 
always been the safest form of energy transportation. And they 
are getting safer.
    From 1994 to 2003, accidents have been cut in half. The 
National Transportation Safety Board reports the Office of 
Pipeline Safety and the pipeline industry have implemented 86 
percent of the board's pipeline safety recommendations, the 
second highest of any agency.
    I want to point out that many pipeline accidents are not 
the result of the failure of the pipeline but of digging 
explanation by the parties that damaged the pipeline.
    One of the most important things we can do to improve 
pipeline safety is increase the education and awareness of the 
safe construction procedures to protect our critical pipeline 
infrastructure. It's obviously a benefit for pipelines that 
once constructed they get out of sight, but they must not be 
out of mind for communities and construction crews who have 
shared responsibility for the safety of our underground 
infrastructure.
    I support the efforts of the Federal Commutation Commission 
to implement a three-digit calling number for anyone to call 
before excavating to determine the location and depth of 
pipelines in their area.
    Our pipeline infrastructure is expanding and aging. So to 
provide the levels of safety that the public expects owners of 
natural gas and hazardous materials transmission pipelines are 
implementing integrity management programs for those facilities 
that attack corrosion or other kinds of damage in populated 
areas.
    Press reports reveal that these management programs combine 
with other measures to result in approximately $4 billion in 
costs to the industry. I think it's commendable that the 
industry is stepping up to the plate to improve safety on such 
an already safe transportation system.
    There are two controversial issues that I know the 
witnesses will discuss today. First is the proposed merger of 
the Office of Pipeline Safety with the Federal Railroad 
Administration. This doesn't seem to make sense. Secretary 
Mineta, whom I greatly respect and is a good friend, wants to 
merge the research and development functions of the two agency. 
That's one thing, but they regulate two entirely different 
industries. So it appears to me they should remain distinct.
    My concern is I have a district that is very pipeline-
oriented and energy transportation-oriented. You know, you can 
look at the safety of trucks over the road, train cars, and 
then pipeline safety. And pipeline safety is always safer than 
rail cars or in over-the-road trucks. So I would hope that you 
can't manage two different distinct transportation systems on 
one agency.
    The other controversial question rests on whether natural 
gas transmission pipelines should be regulated differently from 
natural gas distribution lines, the former a large diameter and 
often are interstate and the latter a small diameter and almost 
always intrastate.
    So I look forward to hearing from our witnesses on this 
topic. Mr. Chairman, again thank you for calling this hearing.
    Mr. Hall. Mr. Green, I thank you very much.
    And I would note again to those of you who are in 
attendance here to testify the empty chairs, this is the last 
week for about 6 weeks that the Congress will be in session. We 
all have 3 or 4 committees we are supposed to be with today. 
It's not a lack of interest because I think everyone recognizes 
the same thing Mr. Green was pointing out, the importance of 
your testimony, because I think pipeline safety is right up at 
the top for terrorist threats or economic growth and for 
everything that this country has got going. It is important 
enough for the chairman of the Committee on Energy and Commerce 
to be here with us today.
    At this time, I would like to recognize Chairman Barton for 
anything he has to say. I would make a special request of him, 
though, that he introduce probably the most important person to 
this committee and to this chairman that's in attendance today. 
The Chair recognizes Mr. Barton.
    Chairman Barton. Well, thank you, Mr. Chairman. I 
appreciate that helpful hint.
    Actually, I have two young women I want to introduce to the 
committee and the audience. The first is someone who is working 
for you as an intern, young Ashley Eisenman, who is in the far 
left-hand corner as I look and the far right-hand corner. She 
is the daughter of Donna Eisenman, who is the special services 
lady at American Airlines who has bailed you, me, and others 
out so many times.
    So, Ashley, would you stand up? You're in the far left 
hand. She's right back there.
    Mr. Hall. Regular order.
    Chairman Barton. Now, on my right is a young woman who 
makes my life a joy, my wife of, what is it, 7 weeks, 3 days, 
12 hours, and I don't know how many minutes, Terry Barton from 
Arlington, Texas, who is here to attend a conference for 
American Diabetes Association and is going to go to the 
reception for Cecil and Billy Tauzin this evening.
    Terry, why don't you stand up and let everybody say hi to 
you?
    Mr. Hall. We are honored to welcome the first lady of the 
Energy and Commerce Committee. Thank you.
    Chairman Barton. Mr. Chairman, I want to thank you for 
holding this hearing. I want to emphasize what you said just a 
second ago. Don't be disappointed that there are not lots of 
members here. If there were lots of members here, it would mean 
that you all had done a bad job and there is lots of 
controversy and everybody was ready to get a piece of your 
hide. It is a good thing in a way that we have four members 
here because that shows what a difference 2 years have made.
    We held a hearing in this subcommittee on pipeline safety 
on March 19, 2002. At that hearing, the Office of Pipeline 
Safety was the brunt of a lot of criticism. At that time, the 
Administrator of the Research and Special Programs 
Administration testified about the new direction charted for 
the Office of Pipeline Safety.
    In hindsight, it appears that what she said has turned out 
to be correct. Instead of having a hearing in which the focus 
was all of the things that OPS was not doing as we did 2 years 
ago, today we can focus on all of the things that OPS has been 
doing and is doing to make pipelines safer.
    We are seeing a partnership developing among all of the 
stakeholders in an effort to make the safest mode of fuels 
transportation even safer. Pipeline Safety Improvement Act of 
2002 represents a major legislative accomplishment that will 
further enable OPS, the pipeline industry, and other interested 
stakeholders to reinvent administrative oversight and 
enforcement by encouraging the implementation of safety 
initiatives before a problem arises. I want to emphasize before 
a problem arises.
    The act contained many mandates which were in various 
stages of development. Those mandates range from the integrity 
management rule for natural gas transmission pipelines to 
operator qualification to the three-digit number for the one-
call telephone call.
    Equally important as safety, security issues are also being 
addressed by OPS and the industry. As the Deputy Administrator 
of the Research and Special Programs Administration has stated, 
and I quote, ``Pipeline system integrity and security are 
inextricably linked. Many of the programs and policies 
implemented for the safety of the public provide much needed 
security protection as well.''
    With over 2 million miles of pipelines, from the wellhead 
to people's furnaces, moving such fuels as natural gas, 
gasoline, and diesel fuel are very, very important. The Energy 
and Commerce Committee is committed to fulfilling its role in 
providing the security tools necessary for the government to 
protect the homeland. Therefore, I am encouraged by the news 
coming from OPS over the past 2 years. And I look forward to 
hearing the testimony of the witnesses today.
    Mr. Chairman, thank you for holding this year. I would 
yield back the balance of my time.
    Mr. Hall. Thank you, Mr. Chairman.
    [Additional statements submitted for the record follow:]

   Prepared Statement of Hon. George Radanovich, a Representative in 
                 Congress from the State of California

    Mr. Chairman, I would like to thank you for holding today's hearing 
which will allow us the opportunity to evaluate the progress on the 
Pipeline Safety Improvement Act of 2002.
    There are millions of miles of pipelines that carry nearly two 
thirds of the energy consumed by our nation. It is the Committee's 
responsibility to continue to monitor the important work that is being 
done at the Federal and State level and by the private industry to 
assure the public that pipelines remain the safest mode of 
transportation for natural gas and hazardous products.
    I thank you again Mr. Chairman for holding this important hearing. 
I look forward to hearing the testimony from our witnesses.

    Prepared Statement of Hon. John D. Dingell, a Representative in 
                  Congress from the State of Michigan

    Mr. Chairman, I thank you for holding this important hearing today. 
Our Nation's pipeline system covers some two million miles serving tens 
of millions of Americans by delivering needed energy to heat our homes, 
fuel our automobiles, and power our factories. While it is a necessary 
and beneficial system, it carries with it inherent dangers that can 
wreak havoc if overlooked or neglected.
    Two years ago this Committee led the way to the enactment of the 
Pipeline Safety Improvement Act of 2002, which was a bipartisan effort 
supported by industry, safety advocates, environmental organizations, 
and labor unions. If correctly implemented, this Act will lead to a 
safer, more reliable pipeline system. We are here today to examine the 
progress of the Office of Pipeline Safety (OPS) in implementing the Act 
and to receive testimony from the GAO and the Department of 
Transportation's Inspector General on the strengths and weaknesses of 
OPS.
    I am pleased to note that the Department of Transportation's 
Inspector General finds that OPS has made progress on clearing the 
backlog of National Transportation Safety Board recommendations and 
past Congressional mandates--work that had previously been neglected. I 
also commend the agency for its aggressive implementation of the 
mandates from the 2002 legislation. There is still, however, much work 
to be done and I hope that OPS pays serious attention to the 
recommendations of both the Inspector General and the GAO as it moves 
forward.
    The GAO was charged with studying the methods of OPS for assessing 
and collecting fines as well as the overall effectiveness of its 
enforcement strategy. On this point GAO says that it cannot determine 
overall effectiveness because OPS lacks program goals, a clearly-
defined strategy, and performance measurements. This is a disappointing 
finding given OPS's past record on enforcement and the emphasis placed 
on this issue in the Pipeline Safety Improvement Act of 2002.
    I know that OPS has increased both the number and amount of fines 
issued over the past four years and that the agency has been using some 
of the tools given to it in the legislation we passed in 2002. While 
this is a welcome improvement over OPS's near abandonment of the use of 
fines in the 1990s, there is still work to be done. The goal of an 
enforcement strategy must not be an arbitrary amount of fines, but 
rather the deterrence and prevention of accidents that can cause 
catastrophic damage to human life, property, and the environment. I 
urge OPS to take the GAO's comments with due seriousness.
    Also, are these fines being collected? On February 20, 2004, I 
wrote to Administrator Bonasso regarding OPS's response to the tragic 
accidents that occurred in Bellingham, Washington, and Carlsbad, New 
Mexico. One of my concerns was that the Research and Special Programs 
Administration (RSPA), in previous testimony to this subcommittee, had 
cited a rather large number of $9 million in proposed penalties, 
seemingly as proof of its effectiveness. I specifically asked for a 
detailed list of the fines that comprised that amount; the March 17, 
2004, response did not include such a list. Based on RSPA testimony, 
the $9 million figure would have included a $2.5 million fine in the 
Carlsbad, New Mexico, case. But at this point that fine remains 
uncollected. What about the others?
    Finally, while I commend the GAO for their usual hard work, I am 
concerned with one area they seem to have overlooked. Section 8 of the 
2002 pipeline safety act specifically requires GAO to study ``changes 
in the amounts of fines recommended, assessed by the Secretary, and 
actually collected.'' While the GAO report does include the number of 
times that a recommended fine was reduced, it does not tell us why.
    Statistics without explanation are merely numbers. This is no small 
matter, given that GAO reports that fines were reduced 31 percent 
during the period when their study was conducted. We need to know why 
these fines were reduced and what impact these reductions had on the 
effectiveness of OPS's enforcement efforts.
    Again Mr. Chairman, I thank you for holding this hearing and look 
forward to this Committee's continued oversight over this important 
issue.

    Mr. Hall. We will now turn to our panel. We are honored to 
have the Honorable Samuel G. Bonasso, Deputy Administrator, 
Research and Special Programs Administration, U.S. Department 
of Transportation. Attending with him is one of those CDW-type 
people you can't do without, the associate administrator of the 
Office of Pipeline Safety. We thank you, and we turn to you for 
advice if your boss gets in trouble in any way.
    We have Katherine Siggerud, Director of Physical 
Infrastructures, Government Accountability Office. Happy to 
have you.
    You always need an Inspector General from time to time but 
not much. You shouldn't when you're doing your job like this 
one is. Honorable Kenneth M. Mead, Inspector General, 
Department of Transportation, who is running a good office and 
cared enough to give us some of his time today. We appreciate 
it.
    And we look forward to hearing from you and recognize you, 
Mr. Bonasso, at this time.

     STATEMENTS OF SAMUEL G. BONASSO, DEPUTY ADMINISTRATOR, 
  RESEARCH AND SPECIAL PROGRAMS ADMINISTRATION, DEPARTMENT OF 
    TRANSPORTATION; ACCOMPANIED BY STACEY GERARD, ASSOCIATE 
 ADMINISTRATOR, OFFICE OF PIPELINE SAFETY; KATHERINE SIGGERUD, 
    DIRECTOR OF PHYSICAL INFRASTRUCTURE ISSUES, GOVERNMENT 
ACCOUNTABILITY OFFICE; AND KENNETH M. MEAD, INSPECTOR GENERAL, 
                  DEPARTMENT OF TRANSPORTATION

    Mr. Bonasso. Thank you, Mr. Chairman. Thank you for the 
opportunity to discuss our strategy and our long-term prospects 
for improving the safety and reliability of our Nation's 
pipeline infrastructure.
    My testimony addresses our responses to the mandates in the 
Pipeline Safety Improvement Act of 2002, issues in its 
implementation, and the results of our actions.
    As you all have so aptly stated, our Nation, our economy, 
and our way of life depend on pipeline transportation system. 
Pipelines are the safest, most efficient way to transport the 
enormous quantities of natural gas and hazardous liquids we use 
each day.
    The act challenged RSPA to improve our pipeline safety 
program. We have responded to this challenge with improved 
regulations, improved inspection, and improved enforcement. 
This is a comprehensive and informed plan to identify and 
manage the risks faced by operators and our communities. This 
has helped us implement new regulations and address the 
majority of tasks required by the new law.
    Last year we completed the second step of our hazardous 
liquid and natural gas integrity management regulations. These 
regulations are the most significant safety standards 
improvements for pipelines in the last 30 years. We are moving 
further to incorporate improved consensus standards that 
evaluate the adequacy of a pipeline operators' public education 
program and by the end of the year will finalize standards for 
operators' qualifications.
    We are improving opportunities for communities to 
understand the importance of pipeline safety and take action 
for further pipeline protection. In addition, we have begun a 
crisis communications initiative to improve the process of 
coordination and information sharing following a pipeline 
accident.
    With the Common Ground Alliance, we are spinning off 
regional alliances to help prevent underground accidents. We 
have also petitioned the Federal Communications Commission for 
a National three-digit dialing code to provide a faster, 
simpler, more efficient one-call system. The Transportation 
Research Board of the National Academies recently completed a 
study on pipeline encroachment at our request. That study is 
now public.
    Secretary Mineta recently submitted to Congress our 5-year 
plan for pipeline research and development. In addition, we 
have developed a memorandum of understanding with the 
Department of Energy and the National Institute of Standards 
and Technology for Research Planning. This has provided a clear 
vision for the advancement of technology focusing on improving 
pipeline safety.
    As we continue with rigorous integrity management 
inspections, the pipeline operators, we expect to discover more 
pipeline defects needing speedy repairs. This increased 
inspection, testing, and repair of pipelines could take more 
pipelines temporarily out of service and potentially impact the 
delivery of energy. Recognizing this potential problem, 
Congress required Federal agencies to participate in an 
interagency committee to facilitate the prompt repair of these 
pipelines so as to minimize safety, environment, and energy 
supply consequences.
    We are moving forward on the Council of Environmental 
Quality four-point plan recommended by Chairman James 
Connaughton. Under RSPA safety regulations, we have established 
timeframes for pipeline repairs, depending on defect type and 
severity. Any serious time-sensitive repair should qualify for 
expedited permitting. Once a serious pipeline condition is 
identified, it could potentially impact the safety of our 
citizens and surrounding sensitive environments.
    Reviewing applications for such pipeline repairs should 
move to the front of the line and be dealt with in a new way. 
RSPA and its Office of Pipeline Safety are strongly committed 
to improving safety, reliability, and public confidence in our 
Nation's pipeline infrastructure. We are also working hard to 
educate communities on how they can continue to live safely 
with pipelines.
    Following the leadership of your committee and this 
administration, the legislation passed in recent years takes a 
new, more comprehensive, informed approach to identifying and 
managing the risks pipeline operators face and the risks those 
pipelines pose to our communities. Thanks to this knowledge and 
the cooperation of all of the parties, today everyone involved 
with pipelines is safer. And so is the environment they pass 
through.
    I will be happy to take your questions.
    [The prepared statement of Samuel G. Bonasso follows:]

Prepared Statement of Samuel G. Bonasso, Deputy Administrator, Research 
 and Special Programs Administration, U.S. Department of Transportation

    Mr. Chairman, my name is Samuel Bonasso. I am the Deputy 
Administrator of RSPA, the Research and Special Programs Administration 
of the U.S. Department of Transportation. With me is Stacey Gerard, 
Associate Administrator for the Office of Pipeline Safety (OPS).
    Thank you for this opportunity to discuss our strategy and our long 
term prospects for improved safety and reliability of the Nation's 
pipeline infrastructure. We greatly appreciate this subcommittee's 
attention and support for our work.
    Under Secretary Mineta's leadership, RSPA and OPS have made great 
strides in meeting the mandates set forth in the Pipeline Safety 
Improvement Act (PSIA) of 2002. My testimony today will address our 
responses to these mandates, including specific implementation issues, 
and the results of our actions. Further, I want to make you aware of 
potential short and near term risks of reduced pipeline capacity and 
energy supply due to required pipeline testing and repairs.
    The Nation's pipelines are essential to our way of life. The 2.3 
million miles of natural gas and hazardous liquid pipelines carry 
nearly two-thirds of the energy consumed by our Nation. Pipelines are 
the safest and most efficient way to transport the enormous quantities 
of natural gas and hazardous liquids across land used by our country.
    Recent increased attention to the need for pipeline safety is 
rooted in demographic changes taking place in our country. Suburban 
development in previously rural areas has placed people closer to 
pipelines. This increases the risk that pipeline accidents, although 
infrequent, can have tragic consequences. Expansion and development 
also means more construction activity near pipelines' the leading cause 
of pipeline accidents.
    Pipeline safety is more than inspecting pipelines. It involves 1. 
having better information to understand safety problems, 2. knowing 
where to set the bar in safety standards, 3. advancing technology to 
find and fix those problems, 4. partnering with state and local 
governments to oversee this critical infrastructure, and 5. building 
alliances to prevent damage and educate the public about how to live 
safely with pipelines.
    Pipeline safety is a top priority for the Bush Administration and 
for Secretary Mineta, personally. With their support, RSPA and OPS have 
strengthened each of these five elements in just a few years.
    Expanded enforcement has been an important approach in 
strengthening the pipeline safety program. In the past 10 years, 57 
inspectors have been added to the OPS staff, from 28 inspectors in 1994 
to 85 inspectors today. Our partnerships with the states, such as our 
agreement with the Arizona Corporation Commission, provide several 
hundred more inspectors.

                     I. WE ARE IMPLEMENTING A PLAN

    With the enactment of the PSIA, we embarked on a new, more 
comprehensive and informed plan to identify and manage the risks that 
pipeline operators face and that pipelines pose to our communities. By 
collecting and using better information about pipelines, today we know 
more about pipelines, the world they traverse, and the consequences of 
a pipeline failure.

1. Higher Standards
    We have raised the standards for pipeline safety, through integrity 
management requirements and 17 other regulations, and incorporated 30 
new national consensus safety standards into our regulations.
2. Better Technology
    To improve the technology available to assess and repair pipelines, 
we have secured investment of almost twelve million dollars, for three 
dozen research projects since March 2002, with over half provided by 
the private sector.
3. Stronger Enforcement
    Our inspections are much more rigorous. Today, we spend 240 hours 
on a comprehensive integrity management inspection, in contrast to 32 
hours in 1996 for a standard pipeline safety inspection.
    We have adopted a tough-but-fair approach to improving enforcement, 
making heavier use of fines, while directing pipeline operators to meet 
higher standards. We have initiated steps to ensure that penalties are 
collected promptly.
4. Better States' Partnership
    We have strengthened our partnerships with state pipeline safety 
agencies, such as the Arizona Corporation Commission, through increased 
training, shared inspection data bases, a distributed information 
network to facilitate communications, and policy collaboration.
5. Cleaning Up Our Record
    Our new record as a regulator is important to us. In the past three 
years, the OPS has eliminated most of a 12-year backlog of outstanding 
mandates and recommendations from Congress, the National Transportation 
Safety Board, the DOT Inspector General, and the GAO. Over the past 4 
years, we have responded positively to 41 NTSB safety recommendations 
and are working to close the remaining 10 recommendations.
6. Preparing Partners and Going Local
    Helping communities to know how they can live safely with pipelines 
is a very important goal. We cannot succeed in improving pipeline 
safety without enlisting the help of local officials. We are moving on 
a number of fronts:

 Working with others, we have proposed to incorporate a new national 
        consensus standard for public education in regulations to 
        ensure community officials and citizens have essential safety 
        information they need to make informed decisions;
 The Transportation Research Board of the National Academy of Sciences 
        recently delivered a study we commissioned on the risks of 
        community encroachment on energy pipelines. We are evaluating 
        this study now and the Secretary will shortly report to the 
        Congress on our plans for addressing this issue.
 We have enlisted the help of the Nation's state fire marshals to 
        bring information and guidance to communities to build 
        understanding of pipeline safety and first responder needs, to 
        help identify high consequence areas in communities, and to 
        provide an understanding of LNG operations.
 Similarly, to foster safety and environmental protection on Tribal 
        Lands, we are working toward a partnership with the Council of 
        Energy Resource Tribes.
    responding to the pipeline safety improvement act of 2002 (psia)
    Pipelines are the arteries of our Nation's energy infrastructure 
and critical to the Nation's viability and well being. The Congress 
recognized the critical importance of pipelines when it passed the 
Pipeline Safety Improvement Act of 2002.
    The actions described above are consistent with the PSIA, which 
also has given us new mandates. Under Secretary Mineta's leadership, 
RSPA and OPS are aggressively responding to these new mandates.
1. Integrity Management
    We have completed the most significant improvement in pipeline 
safety standards history by finalizing regulation of integrity 
management programs for hazardous liquid and natural gas transmission 
operators. Going beyond the PSIA requirements, we are also studying, in 
conjunction with the American Gas Association, the potential for an 
integrity management program that would be appropriate for gas 
distribution and municipal operators. We and our state partners have 
completed comprehensive inspections of large hazardous liquid 
operators. During these inspections, we observed that operators had 
completed over 20,000 repairs, 4,400 of which were time sensitive and 
important to find and fix expeditiously.
2. Operator Qualification
    We have completed half of the reviews of interstate operators' 
qualification programs and expect to meet the 2006 statutory deadline. 
States have made similar progress. We plan to incorporate improved 
consensus standards for the qualification of pipeline operators for 
safety critical functions when the standards are completed later this 
year.
3. Public Education and Mapping
    We believe that communication between Federal, State and local 
government, the operator and the public about how to live safely with 
pipelines is an important element in helping to assure the safety of 
our Nation's energy transportation pipeline infrastructure. Actions are 
underway to improve communications with state and local officials about 
actions they can take to protect their citizens and pipelines. We are 
improving opportunities for communities to understand pipeline safety 
and to take local action as required by the PSIA. Finally, with 
Congressional help, we completed the National Pipeline Mapping system. 
The public can use this system now to know who operates pipelines in 
their communities.
    To respond to the need for improved public awareness of pipelines, 
OPS, the National Association of Pipeline Safety Representatives 
(NAPSR), and the pipeline industry have cooperated to develop a 
national consensus standard-- American Petroleum Institute's 
Recommended Practice 1162 (RP 1162) for public education. RP1162 is 
designed to help pipeline operators meet new standards established in 
the PSIA. It requires operators to identify audiences to be contacted, 
effective messages and communications methods, and information for 
evaluating and updating public awareness programs. Lastly we worked 
with pipeline operators to complete, by the December 2003 deadline, 
self assessments of their public education programs against new, higher 
standards and have proposed incorporation of RP 1162 into our 
regulations.
    We are starting a Crisis Communications Initiative to improve 
communications following an accident. We are working hard to develop 
the framework for this initiative, including a pilot program on crisis 
communications and interagency relationships. We expect this initiative 
to meet national objectives and to be complementary to the Homeland 
Security's National Response Plan, FERC's Liquefied Natural Gas 
efforts, and the National Association of Fire Marshal's education 
program.
4. Damage Prevention
    Working with the Common Ground Alliance and the Federal 
Communications Commission, we are delivering a single, national three-
digit number for one call systems, most likely 811. The Federal 
Communications Commission is expected to finalize this action later 
this year. This will allow all Americans to take one action to protect 
all pipelines from excavation damage-- the major cause of pipeline 
damage and high consequence failures. By making it simpler to call one 
number to mark underground lines, we expect more people to use this 
important prevention service.
5. Research and Development
    To provide a vision for the advancement of technology, we developed 
a memorandum of understanding with the Department of Energy and the 
National Institute of Standards and Technology for research planning, 
and the Secretary recently transmitted to Congress our five year plan. 
The plan includes a detailed management strategy that covers oil as 
well as natural gas research solicitation and procurement; technology 
transfer and application of results; coordination and collaboration 
with other agencies, industry and stakeholders; approaches to 
communicate project findings; and methods of optimizing the use of 
resources.
6. Security
    Since 9/11, the Department has devoted considerable attention to 
security across all modes of transportation, including national 
pipeline security. While the PSIA did not speak specifically to 
security, pipeline system integrity and security are inextricably 
linked. We maintain clear expectations for critical pipeline operators' 
security preparedness. With the Department of Homeland Security (DHS), 
we verify industry action by conducting audits of all major pipeline 
operators' security preparedness. OPS expanded its oil spill emergency 
response exercise program to include focus on security and law 
enforcement for maintaining the reliability of energy supply. The 
Department plans to continue working closely with DHS on pipeline 
security issues.
7. Interagency efforts to Implement Section 16 of the PSIA
    Section 16 of the PSIA requires agencies with responsibilities 
relating to pipeline repair projects to develop and implement a 
coordinated process for environmental review and permitting. The 
interagency working group currently has five efforts underway to:

 refine early notification and Federal involvement procedures;
 identify electronic communication methods that would expedite and 
        streamline review;
 establish practices that would reduce or minimize effects to the 
        environment such that reviews would be expedited; and
 refine permitting and review procedures for time-sensitive pipeline 
        repairs consistent with our regulatory and statutory 
        obligations.

             III. KEEPING THE ENERGY INFRASTRUCTURE VIABLE

    The Nation's economic viability and well-being depend on the 
enormous quantities of oil, fuel and natural gas transported safely, 
reliably and at low cost by pipelines each and every day. The energy 
pipeline infrastructure in the United States represents a $31 billion 
investment in over 2 million miles of pipeline infrastructure that is 
critical to American economic interests-- a myriad of goods and 
services as well as millions of jobs are made possible and supported by 
this transportation infrastructure.
    Federal integrity regulations and PSIA have significantly increased 
the requirements on operators to test the integrity of this 
infrastructure, discover any defects and make repairs before ruptures 
or leaks can occur during the implementation of this important safety 
initiative. This initiative could take more pipelines temporarily out 
of service for inspection, assessment and repairs and could impact the 
delivery of energy.
    There are two aspects of this safety initiative which are being 
given special attention by DOT and other Federal agencies.
    First, we, from our safety purview, are the agency that sees the 
results of the testing of multiple pipelines by multiple operators 
across the regions of our Nation. Our experience suggests that many 
repairs will be required under our integrity management regulations-- 
potentially tens of thousands of repairs annually, and perhaps 
clustering in a particular region of the country.
    Second, while a pipeline operator awaits permits for repairs, the 
operating pressure of the pipeline usually needs to be reduced to 
maintain a safety margin. There is a risk that the amount of pressure 
reductions required pending permitting of repairs could measurably 
reduce the energy capacity of pipeline systems in certain regions. 
Depending on where pipelines are located and how energy markets are 
impacted, pressure reductions during peak demand periods could result 
in fuel shortages and price increases.
    The Congress recognized this potential problem and required Federal 
agencies to participate in an Interagency Committee to facilitate the 
prompt repair of our pipelines. Work is ongoing with the other relevant 
Federal agencies to develop guidance to ensure that any necessary 
Federal permits for repairs of pipelines in danger of rupture can be 
coordinated and expedited. We are actively working with the pipeline 
industry to make progress on the implementation of the interagency 
memorandum of understanding, and to develop an expedited and 
coordinated pipeline permit review process. We are focused on 
encouraging early sharing of information and best management practices 
between pipeline operators and Federal agencies, which will allow 
expedited completion of time-sensitive repairs while protecting 
environmental, cultural, and historic resources.
    Some of the specific issues the Interagency Committee is addressing 
include:

 Feasibility of providing Federal permitting agencies with advance 
        information about operator test schedule. Obtaining this 
        information in advance could help agencies anticipate resources 
        needed for permitting repairs and to exchange information about 
        required actions as soon as possible. Pipeline operators, 
        however, are concerned that by providing this information they 
        might be expected to meet the schedule regardless of factors 
        that are beyond their control (weather, availability of 
        appropriate equipment and certified crews, etc.). Operators are 
        also concerned that the testing schedules could become public 
        information that can not be protected as proprietary 
        information, releasing business-sensitive and possibly 
        security-sensitive information.
 Methods to expedite environmental reviews. The Interagency Committee 
        is examining the required consultative processes for permitting 
        repairs in order to determine if actions can be taken that 
        would enable operators to carry out repairs quickly while 
        meeting safety standards.
 Potential energy supply impacts of multiple repairs in a regional 
        area. As we have experienced recently in gasoline markets, a 
        small change in pipeline supplies can have a dramatic impact on 
        fuel price. In a situation with multiple pipelines in a 
        regional area in need of repair, OPS would work with operators 
        to prioritize the order of repairs and maintain safety. A time 
        sensitive repair might qualify for expedited permitting because 
        of the potential energy supply impact. Maintaining pipeline 
        capacity and throughput is essential in supplying fuels to 
        regional markets and vital to the Nation's industries.

                     IV. WE ARE ACHIEVING RESULTS.

    Comparing years 1999 to 2003 to the previous five years, from 1994 
to 1998, hazardous liquid incidents have decreased by 25 percent. By 
2003, the volume of oil spilled had decreased by 15 percent from the 
previous 10-year average.
    Excavation accidents have decreased over the past ten years by 59 
percent. This is largely the result of work with our state partners and 
the more than 900 members of a damage prevention organization we 
initiated--the Common Ground Alliance (CGA). The CGA has formed 22 
regional alliances to foster damage prevention activities and will soon 
announce two additional regional alliances, including a western 
regional common ground alliance, which is the result of a three-state 
effort led by the Arizona Corporation Commission.
    In closing, I want to reassure you, Mr. Chairman, and all of the 
members of this subcommittee, that Secretary Mineta, RSPA and the 
hardworking men and women in the Office of Pipeline Safety share your 
strong commitment to improving safety, reliability, and public 
confidence in our nation's pipeline infrastructure.
    I will be happy to take your questions.

    Mr. Hall. I thank you.
    The Chair recognizes Mrs. Katherine Siggerud.
    Ms. Siggerud. Good morning.
    Mr. Hall. I hope I pronounced that correctly. Did I?
    Ms. Siggerud. That was just fine, yes. Thank you.

                 STATEMENT OF KATHERINE SIGGERUD

    Ms. Siggerud. Good morning, Mr. Chairman. And thank you and 
members of the subcommittee for the invitation to testify at 
this hearing on pipeline safety.
    As you noted, the Pipeline Safety Improvement Act made a 
number of important changes in Federal pipeline safety 
programs, including in enforcement. As several members of the 
subcommittee noted, we did report in 2000 that the Office of 
Pipeline Safety has significantly reduced its use of certain 
enforcement actions, such as the monetary sanctions known as 
civil penalties, in favor of administrative actions. The 2002 
act required that we, in essence, follow up on that report by 
reviewing OPS' enforcement program, including its use of civil 
penalties. The information I will present today is based on 
that ongoing work. We will be issuing a full report later this 
week.
    As you know, pipeline transportation remains the safest 
form of freight transportation. OPS has been taking a number of 
steps toward implementation of the act to make pipelines safer. 
Enforcing pipeline safety standards and taking action against 
violators is an important part of OPS' efforts to prevent 
accidents.
    My testimony today will cover the two topics directed by 
the act: First, the effectiveness of OPS' enforcement strategy; 
and, second, OPS' assessment of civil penalties against 
interstate pipeline operators that violate Federal pipeline 
safety rules.
    Before I address these two topics, let me put OPS' 
enforcement in context. Over the past several years, OPS has 
been developing and implementing its integrity management 
program, a risk-based approach that it believes will 
fundamentally improve pipeline safety. According to OPS, this 
approach has more potential to improve safety than its 
traditional approach, which has focused on compliance but not 
as much on risk.
    During this time, OPS has taken enforcement action but has 
not placed as much effort on developing enforcement policies 
and practices. Therefore, OPS told us that it is planning to 
improve the management of its enforcement program.
    Accordingly, my testimony today focuses on potential 
management improvements that should be useful to OPS as it 
decides how to proceed and to this subcommittee as it continues 
to exercise oversight.
    Turning now to my first topic, the effectiveness of OPS' 
enforcement strategy, we found that definitive information on 
the strategy's effectiveness is not available because OPS is 
not yet using three elements of program management that we view 
as necessary to demonstrate the strategy's relationship to 
industry compliance and ultimately to safety. First, OPS has 
not established goals that specify the intended results of the 
new, more aggressive strategy it has had in place since 2000. 
Second, OPS has not developed a policy that describes the 
enforcement strategy and its contribution to pipeline safety. 
Finally, OPS has not yet put measures in place that would allow 
it to determine and demonstrate the effects of a new strategy 
on the industry's compliance. Without these three elements, OPS 
cannot determine whether recent important changes in its 
enforcement strategy are having or will have the desired 
effects.
    OPS is currently developing an enforcement policy that 
would help to define the strategy and has begun to identify new 
measures of enforcement performance. OPS plans to finalize this 
strategy sometime in 2005 but still has work to do related to 
developing performance measures and linking them to the program 
goals I mentioned earlier.
    Another component of enforcement, OPS' assessment of civil 
penalties is my second topic. Here OPS is taking a more 
aggressive approach, imposing more and larger penalties than it 
did in the late 1990's, when its policy stressed partnering 
with industry. For example, from 2000 to 2003, OPS increased 
its assessment of civil penalties to an average of 22 a year 
compared to an average of 14 penalties a year from 1995 through 
1999.
    The average size of the civil penalties also increased to 
about $29,000 during the more recent years compared with an 
average of about $18,000 during the earlier years.
    We also looked at the extent to which OPS reduced the 
amount of penalties between the time they are originally 
proposed and when they are finally assessed. As you know, 
pipeline operators can bring evidence for OPS to consider. And 
OPS may reduce the amount of the proposed penalty. We found 
that this happened in 31 percent of the cases since 1994, and 
that the total percentage reduction in penalty between the 
proposed and assessed amount was 37 percent.
    We also found that DOT had collected most of the civil 
penalties that OPS assessed over the past 10 years. Data show 
that operators have paid about 94 percent of the assessed civil 
penalties.
    Finally, pipeline safety stakeholders express differing 
views on whether OPS' increased assessment of civil penalties 
will help improve compliance with the agency's pipeline safety 
regulations. Some of those we spoke with, such as pipeline 
industry officials, said that civil penalties of any size or 
other enforcement actions do act as a deterrent, in part 
because they keep the company in the public eye. Others, such 
as pipeline safety advocacy groups, said that OPS' civil 
penalties may be too small in some cases to deter 
noncompliance.
    In light of the issues raised in my statement today, we are 
considering recommendations regarding OPS' management of its 
enforcement program that could enable OPS to demonstrate to the 
Congress that it has an effective enforcement strategy.
    Mr. Chairman, this completes my statement. I am happy to 
answer any questions.
    [The prepared statement of Katherine Siggerud appears at 
the end of the hearing.]
    Mr. Hall. Thank you.
    The Chair recognizes the Honorable Kenneth M. Mead, 
Inspector General.
    Mr. Mead?

                    STATEMENT OF KENNETH MEAD

    Mr. Mead. Thank you, Mr. Chairman.
    When we testified in 2000, we reported that the Office of 
Pipeline Safety was very slow to implement pipeline safety 
initiatives, congressionally mandated or otherwise. Numerous 
mandates from legislation were outstanding, some more than 8 
years past due. Also overdue were National Transportation 
Safety Board recommendations. They remained open, some for more 
than 10 years.
    The lack of responsiveness prompted Congress to again 
mandate basic elements of a pipeline safety program. The 
Pipeline Safety Act of 2002 was a result. It included 
recommendations from our 2000 report. Last month we issued this 
report on where things stand.
    I can report today that OPS has clearly gotten the message 
and has made considerable progress clearing out most, but not 
all, of the 1992 and 1996 congressional mandates and completing 
15 of them to act with the deadlines that have passed.
    It also closed out most of the NTSB recommendations, and 
pipeline safety was removed from NTSB's most wanted list of 
safety improvements. That said, what remains done?
    OPS has issued important rules for improving pipeline 
safety in the past 2 years. The most important ones were those 
requiring integrity management plans. They are for operators of 
hazardous liquid and natural gas transmission pipelines. They 
call them IMPs for short. Safety program operators use these to 
assess their pipelines for risk of a leak or failure, also to 
repair pipelines and mitigate risks.
    It is against that backdrop I would like to highlight four 
basic points: mapping, where these pipelines are located; two, 
the new IMP inspection process; three, closing a gap on natural 
gas distribution pipelines; and, finally, pipeline security.
    Mapping. In 2000, when testified, we did not know where a 
substantial percentage of pipelines in the United States were 
located. A voluntary mapping initiatives that started in 1994 
was clearly not working. Congress mandated it. OPS completed a 
mapping system this past year. This system is now operational 
and maps 100 percent of the hazardous liquid and gas 
transmission pipelines in this country. That's over 480,000 
miles.
    The new IMP inspection process. Operators are in the early 
stages, very early stages, of implementing their IMPs. They are 
not required to have all inspections completed for hazardous 
liquid pipelines until 2009 or for natural gas transmission 
pipelines until 2012. There are early signs that the 
inspections are working quite well. And there was clearly 
unanimously a need for them.
    To date, more than 20,000 integrity threats have been 
identified and, according to OPS, remediated. A key point here 
is that these threats were identified in just 16 percent, about 
25,000 miles, of liquid pipeline that needs to be inspected. Of 
the 20,000 threats, about 1,200 required immediate repairs and 
attention. Seven hundred, sixty required repairs within 60 
days, and 2,400 required repairs within 180 days. The remainder 
were not time-sensitive.
    Now I would like to speak to another issue regarding 
environmental and permitting issues. The process here is not 
just as simple and straightforward as identifying the problem 
and figuring out how to fix it. For some repairs, the 
environmental review and permitting process has delayed 
preventive measures, as was demonstrated by a pipeline rupture 
in California as recently as April of this year.
    The deteriorating condition of this pipeline in California 
was well-documented. It was no secret. The operator knew it. In 
2001, the operator actually initiated action to relocate it. 
But it took nearly 3 years and over 40 permits before approval 
to relocate was obtained. It was too late to prevent that 
spill. But, fortunately, there was no loss of human life.
    Now, when Congress passed the 2002 Pipeline Act, Congress 
recognized the need to expedite the environmental review 
process. An interagency task force was set up to do that.
    A memorandum of understanding was signed in June. If you 
look that over, you will see that it is at a very high level of 
generality. I think it is probably too general to provide clear 
guidance on each agency's responsibilities to speed that 
permitting process up.
    I would like to speak to natural gas distribution 
pipelines. Natural gas distribution pipelines delivered gas to 
end users to make up about 85 percent of the 2.1 million miles 
of natural gas pipelines. They are not required to have an IMP.
    I think the IMP process could readily be applied to the gas 
distribution pipelines. Our concern here is that the number of 
fatalities and injuries from natural gas distribution accidents 
has increased in the past 3 years.
    Now, the American Gas Foundation is sponsoring a study that 
is due out the end of this year that will, among other things, 
identify elements of the IMP that they are currently required 
to do and those that they are not required to do.
    We think it is reasonable that the Office of Pipeline 
Safety report back to the Congress by March 2005 on the steps 
it is going to take to apply the IMP concept to natural gas 
distribution pipelines.
    And, finally, pipeline security. The current directive on 
pipeline security we think is at too high a level of generality 
to provide clear guidance on each agency's responsibilities. 
I'm speaking here of the Department of Transportation, Homeland 
Security, and the Department of Energy.
    The current guidance basically says collaborate. The roles 
and responsibilities of DOT, the DHS, and the Department of 
Energy need to be spelled out so it will be understood who is 
going to be making the rulemaking decisions, who is going to be 
conducting the security inspections, and who will enforce the 
security requirements.
    Thank you, Mr. Chairman.
    [The prepared statement of Kenneth Mead follows:]

    Prepared Statement of Hon. Kenneth M. Mead, Inspector General, 
                      Department of Transportation

    Mr. Chairman, Ranking Member, and Members of the Subcommittee: We 
appreciate the opportunity to testify today on the progress that the 
Office of Pipeline Safety (OPS) has made to improve pipeline safety and 
the actions that still need to be taken.
    OPS is responsible for overseeing the safety of the Nation's 
pipeline system, an elaborate network of more than 2 million miles of 
pipeline moving millions of gallons of hazardous liquids and more than 
55 billion cubic feet of natural gas daily. The pipeline system is 
composed of predominantly three segments--natural gas transmission 
pipelines, natural gas distribution pipelines, and hazardous liquid 
transmission pipelines--and has about 2,200 1 natural gas 
pipeline operators and 220 hazardous liquid pipeline operators.
---------------------------------------------------------------------------
    \1\ Of the 2,200 operators of natural gas pipelines, there are 
approximately 1,300 operators of natural gas distribution pipelines and 
880 operators of natural gas transmission pipelines.
---------------------------------------------------------------------------
    In March 2000, the Office of Inspector General reported 
2 that weaknesses existed in OPS's pipeline safety program 
and made recommendations designed to correct those weaknesses. These 
recommendations were later mandated in the Pipeline Safety Improvement 
Act of 2002 (2002 Act). This Act required us to review OPS's progress 
in implementing our recommendations. Our testimony today is based 
largely on the results of this second review.3
---------------------------------------------------------------------------
    \2\ OIG Report Number RT-2000-069, ``Pipeline Safety Program,'' 
March 13, 2000.
    \3\ OIG Report Number SC-2004-064, ``Actions Taken and Needed for 
Improving Pipeline Safety,'' June 14, 2004.
---------------------------------------------------------------------------
    Historically, OPS was slow to implement critical pipeline safety 
initiatives, congressionally mandated or otherwise, and to improve its 
oversight of the pipeline industry. The lack of responsiveness prompted 
Congress to repeatedly mandate basic elements of a pipeline safety 
program, such as requirements to inspect pipelines periodically and to 
use smart pigs 4 to inspect pipelines.
---------------------------------------------------------------------------
    \4\ A ``smart pig'' is an instrumented internal inspection device 
that traverses a pipeline to detect potentially dangerous defects, such 
as corrosion.
---------------------------------------------------------------------------
    When we testified before the House Subcommittee on Transit, 
Highways and Pipelines on the reauthorization of the pipeline safety 
program in February 2002, our testimony included actions taken and 
actions still needed to implement the recommendations in our March 2000 
report. While much remained to be done at that time, today we can 
report that OPS has shown considerable progress in implementing our 
prior recommendations.
    Before proceeding to the core of our statement, we would like to 
highlight OPS's progress and challenges in closing out congressional 
mandates enacted in 1992, 1996, and 2002. This progress is a direct 
result of attention at the highest levels in DOT management, including 
the Secretary.

 Closing out most, but not all, of the congressional mandates enacted 
        in 1992 and 1996. Of the 31 mandates from legislation enacted 
        in 1992 and 1996, OPS has completed its actions on 26 mandates, 
        18 of which have been completed since our March 2000 report. 
        The most noteworthy of those mandates required integrity 
        management programs 5 (IMP) for operators of 
        hazardous liquid pipelines. The operators use the IMPs to 
        assess their pipelines for risk of a leak or failure, take 
        action to mitigate the risks, and develop program performance 
        measures. In spite of the progress, five mandates from 
        legislation enacted in 1992 and 1996 remain open.
---------------------------------------------------------------------------
    \5\ The Integrity Management Program is a documented set of 
policies, processes, and procedures that includes, at a minimum, the 
following elements: (1) a process for determining which pipeline 
segments could affect a highconsequence area, (2) a baseline assessment 
plan, (3) a process for continual integrity assessment and evaluation, 
(4) an analytical process that integrates all available information 
about pipeline integrity and the consequences of a failure, (5) repair 
criteria to address issues identified by the integrity assessment and 
data analysis, (6) features identified through internal inspection, (7) 
a process to identify and evaluate preventive and mitigative measures 
to protect highconsequence areas, (8) methods to measure the integrity 
management program's effectiveness, and (9) a process for review of 
integrity assessment results and data analysis by a qualified 
individual.
---------------------------------------------------------------------------
 Meeting the deadlines of the congressional mandates enacted in 2002. 
        Of the 23 mandates from legislation enacted in the 2002 Act, 
        OPS has completed its actions, and mostly on time, for 15 of 
        the 17 mandates with deadlines that have expired. OPS expects 
        to complete its actions on two more mandates with expired 
        deadlines by the end of July 2004.
      This progress was the direct result of a high level of management 
        attention and priority in the past few years to implement the 
        mandates. The most noteworthy of those mandates required IMPs 
        for operators of natural gas transmission pipelines and a 
        national pipeline mapping system that maps 100 percent of the 
        hazardous liquid and natural gas transmission pipeline systems 
        operating in the United States.
 Challenges OPS faces in meeting the deadlines of congressional 
        mandates enacted in 2002. For the few mandates whose deadlines 
        were not met, the delays were a result of multiple Federal 
        agencies, including OPS; state and local agencies; and private 
        industry having to coordinate and collaborate to complete the 
        actions necessary to clear out the mandates. For example, the 
        2002 Act required the execution of a Memorandum of 
        Understanding (MOU) by December 17, 2003, (1 year after the 
        enactment of the 2002 Act) to provide for a coordinated and 
        expedited pipeline repair permit process that will enable 
        pipeline operators to commence and complete timesensitive 
        pipeline repairs in environmentally sensitive areas. However, 
        it was only last month (June 14th) that all nine participating 
        Federal agencies signed the MOU.
      Although the MOU has been signed, the question now is will the 
        MOU be effective in expediting the permit process. In our 
        opinion, the provisions in the MOU are too general to provide 
        clear guidance on each agency's responsibility for coordinating 
        and expediting the pipeline repair permit process. Also, there 
        are no deadlines to help foster quicker reviews and decision 
        processes nor are the agencies held accountable for not abiding 
        by the provisions of the MOU.
    OPS has issued important rules for improving pipeline safety in the 
past 2 years. The most important ones were those requiring IMPs for 
hazardous liquids and natural gas transmission pipelines. This is a key 
issue, as the IMP is the backbone of OPS's riskbased approach to 
overseeing pipeline safety.
    It is against this backdrop that I would like to discuss five major 
points regarding pipeline safety: (1) mapping the pipeline system; (2) 
monitoring the evolving nature of IMP implementation; (3) monitoring 
operators' corrective actions for remediating pipeline integrity 
threats; (4) closing the safety gap on natural gas distribution 
pipelines; and (5) developing an approach to overseeing pipeline 
security.

 Mapping the Pipeline System. The first step to an effective oversight 
        program is to locate the assets to be overseen. In the past 
        year, OPS completed the development of its national pipeline 
        mapping system (NPMS). The pipeline industry was reluctant to 
        support this initiative, so Congress mandated it in the 2002 
        Act. The NPMS is now fully operational and has mapped 100 
        percent of the hazardous liquid (approximately 160,000 miles of 
        pipeline) and natural gas transmission (more than 326,000 
        miles) pipeline systems operating in the United States. 
        Congress exempted natural gas distribution pipelines from the 
        mapping mandate, so currently OPS does not have mapping data on 
        the approximately 1.8 million miles of this type of pipeline.
 Monitoring the Evolving Nature of IMP Implementation. The next step 
        is for operators to assess their pipelines for any potential 
        integrity threat and correct any threats that are identified 
        and for OPS to assess whether the implementation of the 
        operators' IMPs were adequate.
    --As mandated by Congress, OPS issued regulations requiring 
            pipeline operators of hazardous liquid and natural gas 
            transmission pipelines to develop and implement IMPs. IMPs 
            are in the early stages of implementation, and operators 
            are not required to have all baseline integrity inspections 
            completed of hazardous liquid pipelines until 2009 and of 
            natural gas transmission pipelines until 2012. OPS required 
            hazardous liquid pipeline operators--the first operators 
            required to implement the IMP--to complete baseline 
            integrity inspections of pipeline miles first in 
            highconsequence areas, such as residential communities and 
            business districts. These pipelines present the highest 
            risk of fatalities, injuries, and property damage should an 
            accident occur.
        About 135,000 miles of hazardous liquid and more than 326,000 
            miles of natural gas transmission pipeline still need 
            baseline integrity inspections. Nevertheless, there are 
            early signs that the baseline integrity inspections of 
            operators of hazardous liquid pipelines are working well. 
            There was clearly a need for such inspections. According to 
            OPS, in the pipelines inspected so far, more than 20,000 
            integrity threats have been identified and remediated. A 
            key point to remember, though, is these threats were 
            identified in less than 16 percent (about 25,000 miles) of 
            hazardous liquid pipeline miles requiring baseline 
            integrity inspections.
    --OPS will be monitoring the implementation of the IMP by more than 
            1,100 hazardous liquid and natural gas transmission 
            pipeline operators. This is in addition to OPS's ongoing 
            oversight activities, such as inspecting new pipeline 
            construction and investigating pipeline accidents. As of 
            April 30, 2004, the 63 largest operators of hazardous 
            liquid pipelines have undergone initial IMP reviews by OPS 
            inspection teams, leaving 157 hazardous liquid and 884 
            natural gas transmission pipeline operators still needing 
            an initial IMP review by an OPS inspection team. Monitoring 
            the implementation of pipeline operators' IMPs will be an 
            ongoing process for years.
 Monitoring Operators' Corrective Actions for Remediating Pipeline 
        Integrity Threats. Once a threat is identified, OPS will need 
        to follow up to ensure that the operators take timely and 
        appropriate corrective action. Of the more than 20,000 threats 
        that have been repaired to date, more than 1,200 required 
        immediate repair, 760 threats required repairs within 60 days, 
        and 2,400 threats required repairs within 180 days. More than 
        16,300 threats fall into the category of ``other repairs,'' for 
        which remediation activities are not considered timesensitive.
      OPS's remediation criteria encompass a broad range of actions, 
        such as mitigative measures (e.g., reducing the pipeline 
        pressure flow) and repairs that an operator can take to resolve 
        an integrity threat. But the process is not as simple as 
        identifying the problem and determining how best to fix it. For 
        some repairs, Federal and state environmental review and 
        permitting processes have delayed preventive measures from 
        occurring, as was demonstrated by the recent pipeline rupture 
        in northern California.
      A hazardous liquid pipeline ruptured and released about 85,000 
        gallons of diesel fuel, affecting 20 to 30 acres of marshland. 
        The deteriorating condition of this pipeline was well 
        documented by the operator, who initiated action to relocate 
        the pipeline in 2001. However, it took nearly 3 years and more 
        than 40 permits before the operator was given approval to 
        relocate the pipeline. It was too late to prevent this spill, 
        but, fortunately, in this case there was no loss of human life.
      An Interagency Task Force was set up to monitor and assist 
        agencies in their efforts to expedite their review of permits. 
        However, the Task Force participating agency members only 
        recently signed the MOU that is expected to expedite the 
        environmental review and permitting processes so that pipeline 
        repairs can be made before a serious consequence occurs.
      Although the MOU has been signed, the question now is will the 
        MOU be effective in expediting the environmental review and 
        permitting processes. In our opinion, the provisions in the MOU 
        are too general to provide clear guidance on each agency's 
        responsibility for coordinating and expediting the 
        environmental review and pipeline repair permitting processes. 
        Also, there are no deadlines to help foster quicker reviews and 
        decision processes nor are the agencies held accountable for 
        not abiding by the provisions of the MOU. If the participating 
        agencies cannot effectively expedite the environmental review 
        and permitting processes, it may be necessary for Congress to 
        take action.
 Closing the Safety Gap on Natural Gas Distribution Pipelines. The 
        natural gas distribution system makes up over 85 percent (1.8 
        million miles) of the 2.1 million miles of natural gas 
        pipelines in the United States. Distribution is the final step 
        in delivering natural gas to end users such as homes and 
        businesses. While hazardous liquid and natural gas transmission 
        pipeline operators are moving forward with IMPs, natural gas 
        distribution pipeline operators 6 are not required 
        to have an IMP. According to industry officials, the initial 
        reason why natural gas distribution pipelines were not required 
        to have an IMP is that the majority of distribution pipelines 
        cannot be inspected using smart pigs.
---------------------------------------------------------------------------
    \6\ There are some operators of natural gas transmission pipelines 
that are also operators of natural gas distribution pipelines. IMP 
requirements do not apply to their distribution pipelines.
---------------------------------------------------------------------------
      The IMP is a risk-management tool designed to improve safety, 
        environmental protection, and reliability of pipeline 
        operations. That natural gas distribution pipelines cannot be 
        internally inspected using smart pigs is not by itself a 
        sufficient reason for not requiring operators of natural gas 
        distribution pipelines to have IMPs. Other elements of the IMP 
        can be readily applied to this segment of the industry, such as 
        a process for continual integrity assessment and evaluation, 
        and for repair.
      Our concern is that the Department's strategic safety goal is to 
        reduce the number of transportationrelated fatalities and 
        injuries, but natural gas distribution pipelines are not 
        achieving this goal. Over the last 10 years, natural gas 
        distribution pipelines have experienced over 4 times the number 
        of fatalities (174 fatalities) and more than 3.5 times the 
        number of injuries (662 injuries) than the combined totals of 
        43 fatalities and 178 injuries for hazardous liquid and natural 
        gas transmission pipelines.
      To address this issue, the American Gas Foundation, with OPS 
        support, is sponsoring a study to assess the Nation's gas 
        distribution infrastructure that will evaluate safety 
        performance, current operating and regulatory practices, and 
        emerging technologies. The study, among other things, will 
        identify those elements of an IMP that are and are not required 
        under existing Federal regulations. The study has been ongoing 
        for about 6 months, with results expected to be reported to OPS 
        in December 2004. With the results of the study in hand, OPS 
        should finalize its approach, by March 31, 2005, for requiring 
        operators of natural gas distribution pipelines to implement 
        some form of integrity management or enhanced safety program 
        with the same or similar integrity management elements as the 
        hazardous liquid and natural gas transmission pipelines.
 Developing an Approach To Overseeing Pipeline Security. It is not 
        only important that we ensure the safety of the Nation's 
        pipeline system, we must also ensure the security of the 
        system. OPS took the lead to help reduce the risk of terrorist 
        activity against the Nation's pipeline infrastructure following 
        the events of September 11, 2001, but OPS now states it plays a 
        secondary or support role to the Department of Homeland 
        Security's (DHS) Transportation Security Administration (TSA).
      The current Presidential Directive 7 that addresses 
        this issue is at too general a level to provide clear guidance 
        on each Agency's (the Department of Transportation [DOT], DHS, 
        and the Department of Energy [DOE]) responsibility in regards 
        to pipeline security. The delineation of roles and 
        responsibilities between DOT, DHS, and DOE needs to be spelled 
        out in an MOU at the operational level so that we can better 
        monitor the security of the Nation's pipelines without impeding 
        the supply of energy.
---------------------------------------------------------------------------
    \7\ Homeland Security Presidential Directive/HSPD-7, ``Critical 
Infrastructure Identification, Prioritization, and Protection,'' issued 
December 2003.
---------------------------------------------------------------------------
                      MAPPING THE PIPELINE SYSTEM

    To provide effective oversight of the Nation's pipeline system, OPS 
must first know where the pipelines are located, the size and material 
type of the pipe, and the types of products being delivered. The 
Nation's pipeline system is an elaborate network of over 2 million 
miles of pipe moving millions of gallons of hazardous liquids and more 
than 55 billion cubic feet of natural gas daily. The pipeline system is 
composed of predominantly three segments--natural gas transmission 
pipelines, natural gas distribution pipelines, and hazardous liquid 
transmission pipelines--run by about 2,200 natural gas distribution and 
transmission pipeline operators and 220 operators of hazardous liquid 
pipelines (as seen in Table 1). Of the 2,200 operators of natural gas 
pipelines, there are approximately 1,300 operators of natural gas 
distribution pipelines and 880 operators of natural gas transmission 
pipelines. There are approximately 90 Federal and 400 state inspectors 
responsible for overseeing the operators' compliance with pipeline 
safety regulations.

             Table 1. Pipeline System Facts and Description
------------------------------------------------------------------------

------------------------------------------------------------------------
System Segment                    Facts               Segment
                                                       Description
------------------------------------------------------------------------
Natural Gas Transmission          326,595 Miles.....  Lines used to
 Pipelines.                                            gather and
                                                       transmit natural
                                                       gas from wellhead
                                                       to distribution
                                                       systems
------------------------------------------------------------------------
Natural Gas Distribution          1.8 Million Miles.  Mostly local lines
 Pipelines.                                            transporting
                                                       natural gas from
                                                       transmission
                                                       lines to
                                                       residential,
                                                       commercial, and
                                                       industrial
                                                       customers
------------------------------------------------------------------------
Hazardous Liquid Transmission     160,000 Miles.....  Lines primarily
 Pipelines.                                            transporting
                                                       products such as
                                                       crude oil, diesel
                                                       fuel, gasoline,
                                                       and jet fuel
------------------------------------------------------------------------
System Operators                  Facts               Operators
                                                       Description
------------------------------------------------------------------------
Natural Gas Transmission          880...............  Large, medium, and
 Operators.                                            small operators
                                                       of natural gas
                                                       transmission
                                                       pipelines
------------------------------------------------------------------------
Natural Gas Distribution          1,300.............  Large, medium, and
 Operators.                                            small operators
                                                       of natural gas
                                                       distribution
                                                       pipelines
------------------------------------------------------------------------
Hazardous Liquid Operators......  220...............  Approximately 70
                                                       large operators
                                                       and 150 small
                                                       operators
------------------------------------------------------------------------

    Originally, industry was reluctant to map the Nation's pipeline 
system, so Congress responded by requiring, in the 2002 Act, the 
mapping of hazardous liquid and natural gas transmission pipelines. In 
the past year, OPS completed the development of the national pipeline 
mapping system (NPMS). The NPMS is now fully operational and has mapped 
100 percent of the hazardous liquid (approximately 160,000 miles of 
pipeline) and natural gas transmission (more than 326,000 miles) 
pipeline systems operating in the United States. Congress excepted 
natural gas distribution pipelines from the mapping mandate, so OPS 
does not have mapping data on these pipelines.
    As a result of mapping efforts by OPS and industry, Government 
agencies and industry have access to reasonably accurate pipeline data 
for hazardous liquid and natural gas transmission pipelines in the 
event of emergency or potentially hazardous situation. The public also 
has access to contact information about pipeline operators within 
specified geographic areas.

          MONITORING THE EVOLVING NATURE OF IMP IMPLEMENTATION

    Hazardous liquid and natural gas transmission pipeline operators 
are in the early stages of implementing their IMPs. Baseline integrity 
inspections are just now being established systemwide--starting with 
hazardous liquid pipelines--so there are no comparable benchmarks and 
not yet enough evidence to evaluate the IMP's effectiveness in 
strengthening pipeline safety. However, early signs show that the 
baseline integrity inspections of hazardous liquid pipelines are 
working well, and there was clearly a need for such inspections.
    OPS is also in the early stages of overseeing the implementation of 
the operators' IMPs, starting with IMP assessments of operators of 
hazardous liquid pipelines. OPS is challenged with monitoring the 
implementation of the IMPs of more than 1,100 hazardous liquid and 
natural gas transmission pipeline operators and assisting in the 
development of technologies to meet the requirements of the IMP for all 
sizes and shapes of pipelines and all types of threats.
Early Stages of Implementing Pipeline Operators' IMPs
    The operators' implementation of their IMPs is a lengthy process. 
Even though the IMP rules have been issued in their final form, they 
will not be fully implemented for up to 8 years. For example, as part 
of the rules requiring IMPs for operators of natural gas transmission 
pipelines, only recently (June 17, 2004) were operators required to 
begin baseline integrity inspections, with inspections to be completed 
no later than December 17, 2012.
    As operators begin implementing their IMPs, there are early signs 
that the baseline integrity inspections are working well for operators 
of hazardous liquid pipelines and that there was clearly a need for 
such inspections. So far, according to OPS, results from the operators' 
baseline integrity inspections in predominantly high-consequence areas 
show that more than 20,000 integrity threats were identified and 
remediated. These threats might not have been discovered during the 
operators' routine inspections. One of the most serious threats 
discovered was a case of corrosion where greater than 80 percent of the 
pipeline wall thickness had been lost. It has since been repaired. A 
lesser threat discovered was minor corrosion along a longitudinal seam.
    A key point to remember about the early baseline integrity 
inspection results for operators of hazardous liquid pipelines is that 
these 20,000 threats were discovered and remediated in less than 16 
percent (about 25,000 miles) of pipeline miles needing inspection. 
About 135,000 miles of hazard liquid pipeline still need baseline 
integrity inspections.
    Although 20,000 threats were discovered in the first 25,000 miles, 
we cannot statistically project the number of threats that could be 
expected in the 135,000 miles of pipeline that still need baseline 
integrity inspections. We also cannot project the number of threats 
that could be expected in the more than 326,000 miles of natural gas 
transmission pipelines that have yet to receive baseline integrity 
inspections. Baseline integrity inspections will not be completed for 
several years and certain threats may be very timesensitive, especially 
those to do with severe internal corrosion.
    OPS required hazardous liquid pipeline operators--the first segment 
of the industry required to implement the IMP--to complete baseline 
integrity inspections of pipeline miles first in high-consequence 
areas, as these areas are populated, unusually sensitive to 
environmental damage, or commercially navigable waterways. These 
pipelines present the highest risk of fatalities, injuries, and 
property damage should an accident occur.
    According to the American Petroleum Institute, nationwide there are 
approximately 160,000 miles of hazardous liquid pipelines, of which 
51,400 miles are located in highconsequence areas. As required by the 
IMP rule, 25,700 of the 51,400 miles (50 percent) should receive 
baseline inspections by September 30, 2004. OPS estimates that of the 
nearly 327,000 miles of natural gas transmission pipelines, 24,970 
miles are located in high-consequence areas. But pipelines in high-
consequence areas represent only about 16 percent of the total miles 
(76,370 of 487,000 total miles) for both hazardous liquid and natural 
gas transmission pipelines,8 and accidents that occur in 
nonhigh-consequence areas can have catastrophic consequences, such as 
the deadly pipeline rupture, explosion, and fire near Carlsbad, New 
Mexico.
---------------------------------------------------------------------------
    \8\ The percentage of total miles in high-consequence areas for 
hazardous liquid and natural gas transmission pipelines are early 
estimates and may change with the beginning of the pipeline operators' 
baseline integrity inspections.
---------------------------------------------------------------------------
    On August 19, 2000, a 30-inch-diameter natural gas transmission 
pipeline ruptured adjacent to the Pecos River near Carlsbad. The 
released gas ignited and burned for 55 minutes. Twelve members of a 
family who were camping under a concrete-decked steel bridge that 
supported the pipeline across the river were killed and their three 
vehicles destroyed. Two nearby steel suspension bridges carrying gas 
pipelines across the river were extensively damaged.
    During the investigation, NTSB investigators found the rupture was 
a result of severe internal corrosion that reduced the pipe wall 
thickness to the point that the remaining metal could no longer contain 
the pressure within the pipe. The significance of this finding cannot 
be overstated, as corrosion is the second leading cause of pipeline 
accidents. Pipeline operators will need to move forward on their 
baseline integrity inspections.
Monitoring the Implementation of Pipeline Operators' IMPs
    OPS must now begin assessing whether the implementation of more 
than 1,100 hazardous liquid and natural gas transmission pipeline 
operators' IMPs were adequate. OPS must also perform ongoing oversight 
activities, such as inspecting new pipeline construction, monitoring 
research and development projects, and investigating pipeline 
accidents. To do so while efficiently and effectively overseeing the 
operators' IMPs, OPS believes it will need to augment its own resources 
with those of the states.
    OPS is actively overseeing IMP implementation through its 
assessments of hazardous liquid pipeline operators' IMP plans. As of 
April 30, 2004, the 63 largest operators of hazardous liquid pipelines 
have undergone the initial IMP assessments. That leaves 157 more 
operators of hazardous liquid pipelines and 884 operators of natural 
gas transmission pipelines who will need initial IMP assessments.
    Monitoring the implementation of pipeline operators' IMPs will be 
an ongoing process. OPS IMP inspection teams, made up of Federal and 
state inspectors, spent approximately 2 weeks at each operator's 
headquarters reviewing results of integrity inspection and actions 
taken to address integrity threats, as well as overall IMP development 
and effectiveness. With over 1,000 pipeline operators who have not yet 
had an initial IMP assessment (at 2 weeks for each assessment), 
compounded by the fact that pipelines operators have up to 8 years to 
complete their baseline integrity inspections, the overall 
effectiveness of operators' IMPs in strengthening pipeline safety will 
not be known for years.

Advancing Threat Detection Technologies Is Fundamental to the Success 
        of Integrity Inspections
    As part of OPS's IMP rule, operators of hazardous liquid and 
natural gas transmission pipelines are required to inspect the 
integrity of their pipelines using smart pigs or an alternate but 
equally effective method such as direct assessment. To date, OPS's 
integrity management assessments indicate that operators of hazardous 
liquids pipelines used smart pigs about 70 percent of the time to 
conduct their baseline integrity inspections and strongly favored the 
use of smart pigs over alternative inspection methods. Although there 
have been significant advances in smart pig technology, the current 
technology still cannot identify all pipeline integrity threats. 
Today's smart pigs can successfully detect and measure corrosion, 
dents, and wrinkles but are less reliable in detecting other types of 
mechanical damage. As a result, certain integrity threats go undetected 
and pipeline accidents may occur.
    For example, on July 30, 2003, an 8inch-diameter hazardous liquid 
pipeline ruptured near a residential area under development in Tucson, 
Arizona, releasing more than 10,000 gallons of gasoline and shutting 
down the supply of gasoline to the greater metropolitan Phoenix area 
for 2 days. Whether this rupture could have been prevented is still not 
known because the cause of the rupture, stress crack 
corrosion,9 rarely causes failure in hazardous liquid 
pipelines. Also, there are currently no tools or mechanisms that can 
identify the threat of stress crack corrosion and are also small enough 
to fit in 8inch-diameter piping.
---------------------------------------------------------------------------
    \9\ Stress crack corrosion (SCC), also known as environmentally 
assisted cracking, is a relatively new phenomenon. Instead of pits, SCC 
manifests itself as cracks that are minute in length and depth. Over 
time, individual cracks coalesce with other cracks and become longer.
---------------------------------------------------------------------------
    OPS's research and development (R&D) program is aimed at enhancing 
the safety and reducing the potential environmental effects of 
transporting natural gas and hazardous liquids through pipelines. 
Specifically, the program seeks to advance the most promising 
technological solutions to problems that imperil pipeline safety, such 
as damage to pipelines from excavation or corrosion. OPS sponsors R&D 
projects that focus on providing near-term solutions that will increase 
the safety, cleanliness, and reliability of the Nation's pipeline 
system.
    OPS's R&D funding has more than tripled, from $2.7 million in FY 
2001 to $8.7 million in FY 2003. Nearly $4 million of the $8.7 million 
is funding projects to improve the technologies used to inspect the 
integrity of pipeline systems for the IMP. OPS currently has 22 active 
projects that explore a variety of ways to improve smart pig 
technologies, develop alternative inspection and detection technologies 
for pipelines that cannot accommodate smart pigs, and improve pipeline 
material performance. For example, OPS has a project underway that will 
improve the capabilities of smart pigs to detect and measure both 
corrosion and mechanical damage. The expected project outcome is a 
smart pig that is more versatile and simpler to build and to use.
    The R&D challenge OPS now faces is seeing these projects through to 
completion, without undue delay and expense, to ensure that viable, 
reliable, costeffective technologies become readily available to meet 
the demands of increased usage required under the IMP.

Monitoring Remediation of Pipeline Integrity Threats
    Much of the Nation's existing pipeline infrastructure is over 50 
years old. When pipeline integrity threats are identified, repairs may 
require Federal and state environmental reviews and permitting before 
the operator can proceed. However, OPS regulations identify repair 
criteria for the types of threats that must be repaired within 
specified time limits. At times, the environmental review and 
permitting processes become an obstacle that can delay the operators' 
remediation efforts.
    When it passed the 2002 Act, Congress recognized that timely repair 
of pipeline integrity threats was essential to the well-being of human 
health, public safety, and the environment. Therefore, Congress 
directed the President to establish an interagency committee to develop 
and ensure the implementation of a coordinated environmental review and 
permitting process. This should allow pipeline operators to commence 
and complete all activities necessary to carry out pipeline repairs 
within any time periods specified under OPS's regulations.

Certain Pipeline Repairs Must Be Completed Within Specified Time Limits
    OPS regulations identify remediation criteria for the types of 
threats that must be repaired within specified time limits, the length 
of which reflects the probability of failure. For hazardous liquid 
pipelines, the three categories of repair are defined as immediate 
repair, 60 days to repair, and 180 days to repair. For example, a top 
dent with any indication of metal loss requires immediate response and 
action, whereas a bottom dent with any indication of metal loss 
requires a response and action within 60 days. Other types of threats 
require remediation activities that are not considered time-sensitive. 
Using the criteria, pipeline operators must characterize the type of 
repair required, evaluate the risk of failure, and make the repair 
within the defined time limit.
    As of April 30, 2004 (the most current OPS data available), of the 
more than 20,000 threats that have been identified and remediated to 
date, more than 1,200 required immediate repair, 760 required repairs 
within 60 days, and 2,400 required repairs within 180 days. More than 
16,300 threats were not considered timesensitive. OPS's remediation 
criteria encompass a broad range of actions, which include mitigative 
measures, such as reducing the pipeline pressure flow, and repairs that 
an operator can make to resolve an integrity threat. For immediate 
repairs, an operator must temporarily reduce operating pressure or shut 
down the pipeline until the operator completes the repair.
    The challenges inspectors face during a review of an operator's 
baseline integrity inspection results are to determine whether OPS's 
repair criteria were properly used to characterize the type of repair 
required for each threat identified and whether the operator's threat 
remediation plans are adequate to repair or mitigate the threat. More 
importantly, however, is that OPS will need to follow up to ensure that 
the operator has properly executed its remediation actions within the 
defined time limit.

Improvements Are Needed in Coordinating Federal and State Environmental 
        Reviews and Permitting Processes
    The transmission of energy through the Nation's pipeline system in 
a safe and environmentally sound manner is essential to the well-being 
of human health, public safety, and the environment. One way to do this 
is to develop and ensure implementation of coordinated Federal and 
state environmental review and permitting processes that will enable 
pipeline operators to complete pipeline repairs quickly. There will be 
mounting pressures to accelerate the environmental review and 
permitting processes, given the high number of threats found during the 
early stages of baseline integrity inspections that must be repaired 
within specified time limits.
    The recent pipeline rupture in northern California demonstrates the 
perils of not being able to promptly repair pipeline threats. In April 
2004, a hazardous liquid pipeline ruptured in the Suisun Marsh south of 
Sacramento, California, releasing about 85,000 gallons of diesel fuel 
into 20 to 30 acres of marshland. Muskrats, beaver, and water fowl were 
harmed by the spill. Fortunately, there were no human fatalities or 
injuries.
    The deteriorating condition of the pipeline that ruptured was well 
documented by the pipeline operator, who had reduced pipeline operating 
pressure to lessen the risk of a rupture but keep the flow of energy to 
users in Sacramento and Chico, California, and Reno, Nevada. The 
pipeline operator wanted to relocate the pipeline away from the Suisun 
Marsh and initiated actions to do so in 2001. However, the 
environmental review and permitting processes took far too long: nearly 
3 years and more than 40 permits in total. There is little doubt that 
the rupture would not have occurred had the permit process been 
quicker.
    The importance of accelerating the permit process, when necessary, 
cannot be overstated. As we have noted, results from the hazardous 
liquid pipeline operators' baseline integrity inspections in high-
consequence areas show that more than 20,000 integrity threats were 
identified for remediation. More than 1,200 threats required immediate 
repairs. As operators continue with their baseline integrity 
inspections, the implications are that the number of integrity threats 
will continue to rise. According to OPS, repairs for other known 
pipeline threats are being delayed because of the environmental review 
and permitting processes. These repairs are best taken care of sooner 
rather than later to prevent another incident like the Suisun March 
rupture.
    When it passed the 2002 Act, Congress recognized the need to 
expedite the environmental review and permitting processes. Section 16 
of the 2002 Act directed the President to establish an interagency 
committee that would develop and ensure implementation of a coordinated 
environmental review and permitting process so that pipeline repairs 
could be made within the time periods specified by IMP regulations.
    The committee was to:

 Evaluate Federal permitting requirements.
 Identify best management practices to be used by industry.
 Enter into a MOU by December 17, 2003, (1 year after the enactment of 
        the 2002 Act) to provide for a coordinated and expedited 
        pipeline repair permitting process that would result in no more 
        than minimal adverse effects on the environment.
    The 2002 Act also requires the committee to consult with state and 
local environmental, pipeline safety, and emergency response officials 
and requires the Secretary of Transportation to designate on ombudsman 
to assist in expediting the permit process and resolving disagreements 
over pipeline repairs between Federal, state, and local permitting 
agencies and the pipeline operator.
    To implement Section 16, the President issued an Executive Order in 
May 2003 establishing the Interagency Task Force and directed it to 
implement the committee initiatives. The Chairman of the Council on 
Environmental Quality chairs the Interagency Task Force, whose 
membership includes representatives from the Departments of 
Agriculture, Commerce, Defense, Energy, the Interior, and 
Transportation; the Environmental Protection Agency; the Federal 
Regulatory Commission; and the Advisory Council on Historic 
Preservation.
    However, the Task Force only recently finalized its MOU that would 
expedite the environmental review and permitting processes. According 
to OPS, the reason for the delay was that not all members of the 
Interagency Task Force had agreed to the provisions of the MOU. Other 
members believe that there are provisions in the Clean Air Act, Clean 
Water Act, and Endangered Species Act that prohibit them from taking 
any action to expedite the environmental review and permitting 
processes.
    Although the MOU has been signed, the question now is will the MOU 
be effective in expediting the environmental review and permitting 
processes. In our opinion, the provisions in the MOU are too general to 
provide clear guidance on each agency's responsibility for coordinating 
and expediting the environmental review and pipeline repair permitting 
processes. Also, there are no deadlines to help foster quicker reviews 
and decision processes, nor are the agencies held accountable for not 
abiding by the provisions of the MOU. If the participating agencies 
cannot effectively expedite the environmental review and permitting 
processes, it may be necessary for Congress to take action.

      CLOSING THE SAFETY GAP ON NATURAL GAS DISTRIBUTION PIPELINES

    The 2002 Act requires that the operators of natural gas pipeline 
facilities implement IMPs. However, the IMP requirement applies only to 
natural gas transmission pipelines and not to natural gas distribution 
pipelines.
    As part of the IMP, operators of hazardous liquid and natural gas 
transmission pipelines are required to inspect the integrity of their 
pipelines using one or more of the following inspection methods: smart 
pigs, pressure testing, or direct assessment.10 According to 
officials of the American Gas Association, the initial reason why IMPs 
were not required for natural gas distribution pipelines is that 
distribution pipelines cannot be inspected using smart pigs. The smart 
pig technologies currently available cannot be used in natural gas 
distribution pipelines because the majority of distribution piping is 
too small in diameter (1 to 6 inches) and has multiple bends and 
material types intersecting over very short distances.
---------------------------------------------------------------------------
    \10\ Operators can choose another technology that demonstrates an 
equivalent understanding of the integrity of the pipeline but only if 
they notify OPS before the inspection begins.
---------------------------------------------------------------------------
    The IMP is a riskmanagement tool designed to improve safety, 
environmental protection, and reliability of pipeline operations. That 
natural gas distribution pipelines cannot be internally inspected using 
smart pigs is not by itself a sufficient reason for not requiring 
operators of natural gas distribution pipelines to have IMPs. Other 
elements of the IMP can be readily applied to this segment of the 
industry, including but not limited to (1) a process for continual 
integrity assessment and evaluation, (2) an analytical process that 
integrates all available information about pipeline integrity and the 
consequences of failure, and (3) repair criteria to address issues 
identified by the integrity assessment and data analysis.
    The American Gas Foundation, with OPS support, is sponsoring a 
study to assess the Nation's gas distribution infrastructure that will 
evaluate safety performance, current operating and regulatory 
practices, and emerging technologies. The study, among other things, 
will identify those elements of an IMP that are and are not required 
under existing Federal regulations. The study has been ongoing for 
about 6 months, with results expected to be reported to OPS in December 
2004.

Natural Gas Distribution Pipeline Safety Concerns
    Our concern is that the Department's strategic safety goal is to 
reduce the number of transportationrelated fatalities and injuries, but 
natural gas distribution pipelines are not achieving this goal. In the 
10year period from 1994 through 2003, OPS's data show accidents in 
natural gas distribution pipelines have caused more than 4 times the 
number of fatalities (174 fatalities) and more than 3.5 times the 
number of injuries (662 injuries) when compared to a combined total of 
43 fatalities and 178 injuries associated with hazardous liquid and gas 
transmission pipeline accidents combined.
    Accidents involving natural gas distribution pipelines can be as 
catastrophic as accidents involving hazardous liquids or natural gas 
transmission pipelines. For example, on December 11, 1998, in downtown 
St. Cloud, Minnesota, a communications crew ruptured an underground 
natural gas distribution pipeline, causing an explosion that killed 4 
people, seriously injured 1, and injured 10 others. Six buildings were 
destroyed. In another example, in July 2002, a gas explosion in a 
multiplefamily dwelling in Hopkinton, Massachusetts, killed 2 children 
and injured 14 others.
    In the past 3 years, the number of fatalities and injuries from 
accidents involving natural gas distribution pipelines has increased 
while the number of fatalities and injuries from accidents involving 
hazardous liquid and natural gas transmission pipelines has held steady 
or declined. OPS's data show that fatalities and injuries from 
accidents involving natural gas distribution pipelines increased from 5 
fatalities and 46 injuries in 2001 to 11 fatalities and 58 injuries in 
2003. For the same period, fatalities and injuries from accidents 
involving hazardous liquid and natural gas transmission pipelines 
decreased from 2 fatalities and 15 injuries in 2001 to 1 fatality and 
13 injuries in 2003.
    Although the American Gas Foundation has moved forward with its 
study to assess the performance and safety of natural gas distribution 
pipelines, OPS needs to ensure that the pace of this effort moves 
quickly enough, given the upward trend in fatalities and injuries 
involving these pipelines and the projected increase in distribution 
pipelines to meet the increasing demand for natural gas. In December 
2004, when industry presents the results of its safety study on natural 
gas distribution pipelines, OPS will have the information to finalize 
its approach, by March 31, 2005, for requiring operators of natural gas 
distribution pipelines to implement some form of integrity management 
or enhanced safety program with the same or similar integrity 
management elements as the hazardous liquid and natural gas 
transmission pipelines. This would be consistent with OPS's riskbased 
approach to overseeing pipeline safety by using IMPs to reduce the risk 
of accidents that may cause injuries or fatalities to people near 
natural gas distribution pipelines, as well as the risk of property 
damage.

         DEVELOPING AN APPROACH TO OVERSEEING PIPELINE SECURITY

    The focus of our recently completed review was pipeline safety. 
However, given the importance of protecting the Nation's infrastructure 
of pipeline systems, we also reviewed OPS's involvement in the security 
of the pipeline systems.

OPS's Security Efforts Following September 11, 2001
    Following the events of September 11, 2001, OPS moved forward on 
several fronts to help reduce the risk of terrorist activity against 
the Nation's pipeline infrastructure, such as opening the lines of 
communication among Federal and state agencies responsible for 
protecting the Nation's critical infrastructure, including pipelines; 
conducting pipeline vulnerability assessments and identifying critical 
pipeline systems; developing security standards and guidance for 
security programs; and working with Government and industry to help 
ensure rapid response and recovery of the pipeline system in the event 
of a terrorist attack.
    To protect the Nation's pipeline infrastructure, OPS issued new 
security guidance to pipeline operators nationwide in September 2002. 
In the guidance, OPS requested that all operators develop security 
plans to prevent unauthorized access to pipelines and identify critical 
facilities that are vulnerable to a terrorist attack. OPS also asked 
operators to submit a certification letter stating that the security 
plan had been implemented and that critical facilities had been 
identified. During 2003, OPS and the DHS's TSA started reviewing 
operator security plans. The plans reviewed have been judged responsive 
to the OPS guidance.
    Unlike its pipeline safety program, OPS's security guidance is not 
mandatory: industry's participation in a security program is strictly 
voluntary and cannot be enforced unless a regulation is issued to 
require industry compliance. In fact, it is still unclear what agency 
or agencies will have responsibility for pipeline security rulemaking, 
oversight, and enforcement. Although OPS took the lead to help reduce 
the risk of terrorist activity against the Nation's pipeline 
infrastructure following September 11, 2001, OPS has stated it now 
plays a secondary, or support, role to TSA, the agency with primary 
responsibility for ensuring the security of the Nation's transportation 
system, including pipelines.

Recent Initiatives Clarifying Security Responsibilities
    Certain steps have been taken to establish what agency or agencies 
would be responsible for ensuring the security of the Nation's critical 
infrastructure, including pipelines. For example, in December 2003, 
Homeland Security Presidential Directive/HSPD-7 (HSPD7):

 Assigned DHS the responsibility for coordinating the overall national 
        effort to enhance the protection of the Nation's critical 
        infrastructure and key resources.
 Assigned DOE the responsibility for ensuring the security of the 
        Nation's energy, including the production, refining, storage, 
        and distribution of oil and gas.
 Directed DOT and DHS to collaborate on all matters relating to 
        transportation security and transportation infrastructure 
        protection and to regulating the transportation of hazardous 
        materials by all modes, including pipelines.
    Although HSPD-7 directs DOT and DHS to collaborate in regulating 
the transportation of hazardous materials by all modes, including 
pipelines, it is not clear from an operational perspective what ``to 
collaborate'' encompasses, and it is also not clear what OPS's 
relationship will be with DOE. The delineation of roles and 
responsibilities between DOT and DHS needs to spelled out by executing 
an MOU or a Memorandum of Agreement. OPS also needs to seek 
clarification on the delineation of roles and responsibilities between 
itself and DOE.
    Mr. Chairman, this concludes my statement. I will be pleased to 
answer any questions that you or other members of the Subcommittee 
might have.

    Mr. Hall. Thank you.
    The Chair notes the presence of Mr. Walden of Oregon, Mr. 
Otter of Idaho, and Mr. Allen of Maine. The time for opening 
statements has passed, but if there is no objection, we can put 
your opening statements in the record, as can any other member 
who comes and goes during this hearing. Without objection, so 
ordered.
    All right. Well, we begin the questions now. I think it 
would be helpful, Mr. Bonasso, if you would--your testimony 
notes that OPS has completed a National pipeline matching 
system. I think that is on page five of your testimony there. 
You state, and I quote, ``The public can use this system now to 
know who operates pipelines in their communities.'' Explain, if 
you would,--this is for anybody who is watching or listening or 
who will read the record--how the public can access this system 
and what information is available that would be helpful, I 
think.
    Mr. Bonasso. All right. Mr. Chairman, the Web site of the 
Office of Pipeline Safety has a feature that allows people to 
insert their Zip Code. So anybody in the United States with a 
Zip Code can enter the Zip Code. And once they enter that Zip 
Code, it will tell them the pipeline companies that are 
operating in their area. It will give them the name of the 
company and the telephone number. They can then call those 
companies and determine whether or not those pipelines are in 
the vicinity of their property and can determine what kind of 
service is involved and so on. So they have ability to identify 
that by Zip Code.
    Mr. Hall. I thank you for that bit of public service.
    Mr. Bonasso. Yes, sir.
    Mr. Hall. Thank you. And that will be helpful.
    Mrs. Siggerud, did I do better that time?
    Ms. Siggerud. That's fine.
    Mr. Hall. In your testimony, you note, and I quote, ``The 
effectiveness of OPS' enforcement strategy cannot be evaluated 
because the agency has not incorporated three key elements of 
effective program management.'' And you listed clear program 
goals, a well-defined strategy for achieving these goals, and, 
logically, measures of performance that are linked to the 
problem goals. I think that is on page three of your testimony.
    You further note that OPS is developing an enforcement 
policy that will help define its enforcement strategy, but will 
not be completed until the year 2005.
    My question is, will that policy address the lack of the 
three key elements you set forth?
    Ms. Siggerud. My understanding is it will address some of 
those key elements. In particular, I mentioned the need for a 
strategy as the first element. I noted in my statement that OPS 
has taken on a new and different approach to imposing 
enforcement actions since about 2000. In addition, it has 
started to take enforcement actions under integrity management.
    What we would hope is that the new enforcement strategy 
that OPS will put into place in 2005 will essentially recognize 
both of those changes and be fairly specific on what it expects 
in terms of the types of enforcement actions that will be 
taken.
    With regard to performance measures, the second element 
that I mentioned, we have spoken with the OPS officials. They 
have a couple of measures that they are considering, 
particularly in the integrity management area, that we think 
will start to be responsive to our concerns.
    What we think is important in terms of performance measures 
is really trying to understand what enforcement is trying to 
accomplish; for example, reducing the number of repeat 
violations, getting speedy remediation of any safety violations 
that are identified, et cetera. What we hope is that OPS will 
consider these types of performance measures in putting 
measures into place.
    Finally, with regard to goals, this is very similar to the 
performance measure issue. What we hope is that OPS will put 
goals into place that specifically identify what its 
enforcement policy is meant to accomplish.
    Mr. Hall. One follow-up to that. What, if anything, has 
been OPS' reaction to your draft report?
    Ms. Siggerud. Yes. Our report is, in fact, in final 
processing. And we do have official comments from the Office of 
Pipeline Safety. And the office agreed with all of the 
recommendations that we made.
    Mr. Hall. I thank you.
    Mr. Inspector General, at one point the Department of 
Transportation intended to propose a reorganization as a part 
of the F.Y. 2005 budget--I think you are aware of that--which 
affected the Office of Pipeline Safety. Do you know what the 
status is of that proposal? Was it carried out? Was it 
initiated? Is it completed?
    Mr. Mead. No. I think my understanding is that the 
department is having discussions with some Members of Congress 
on it. I think Mr. Green raised this issue before.
    Personally I like the idea of bringing together the 
research, different research, organizations into one, but OPS I 
personally would not move them to the Federal Railroad 
Administration. One possible option is to combine them, combine 
the hazmat and the Office of Pipeline Safety, as one other 
office within the Department of Transportation.
    I think you have a pretty good thing going right now with 
the Office of Pipeline Safety. It has taken a while to turn 
them around. And it seems to me that they are going in the 
right direction.
    Mr. Hall. I thank you. Mr. Green probably has follow-up on 
that.
    My time has expired. The Chair recognizes the ranking 
member of this committee. Mr. Boucher?
    Mr. Boucher. Thank you very much, Mr. Chairman.
    Mr. Mead, let me return with you to the question of the 
scope of the requirement with respect to integrity management 
plans. Under the 2002 statute, required that they apply to 
transmission lines. We did not require that they apply to 
natural gas distribution lines.
    Now, I notice in your testimony some comments with respect 
to their application to distribution. I would like for you to 
take just a moment, if you would, to elaborate on the reasons 
why perhaps in your opinion you believe that integrity 
management plans should apply to distribution lines.
    Perhaps in answering that question, you could apprise us as 
to whether or not there have been any significant accidents 
that involve distribution lines or give us other bases for the 
application of these plans to distribution.
    Mr. Mead. Yes, sir. I think this is a fairly 
straightforward matter. You are correct. They are not required 
to have integrity management plans.
    Basically, an integrity management plan sets forth the 
frequency and the criteria for doing inspections; second, what 
you are going to do when you find a problem; and, third, a very 
organized way of communicating among the companies and with the 
government about what the current status of the pipelines are 
and what is going to be done about it. It is a fairly 
straightforward concept.
    I think that they ought to be covered because: one, they 
actually comprise 85 percent of the pipeline mileage in this 
country; second, they are almost always in high-consequence 
areas; that is, densely populated things, like near your home 
and mine. And, third, in terms of the safety record, there has 
been an increase in the last several years in the fatalities 
and accidents and injuries.
    Mr. Boucher. Associated with distribution lines?
    Mr. Mead. Yes, sir. And I can just quickly take that apart 
and stratify it. Actually----
    Mr. Boucher. We are a little bit limited in terms of time. 
If you have some examples of accidents that have occurred, if 
you perhaps could submit those to the committee in written form 
I think that would be helpful.
    Mr. Mead. We would be glad to.
    Mr. Boucher. Let me ask you a couple of additional 
questions about that subject. A comment has been made that with 
their larger diameter, the transmission lines perhaps are 
easier to inspect because automated remote sensing devices can 
be transmitted through these larger lines. With their smaller 
diameter, the distribution lines don't permit that technical 
application.
    So how would an integrity management plan proceed in terms 
of specifying the means for sensing whether or not problems are 
arising with regard to the distribution lines?
    Mr. Mead. What you are referring to is pigging, 
instrumented pigging. And you are correct that the gas 
distribution pipelines generally are too small, have too many 
curves, and so forth, to accommodate them. But there are other 
inspection techniques.
    In the first instance, you can look to the operator to say 
what techniques they would choose to use, but there are other 
techniques other than instrumented pigging.
    Mr. Boucher. There are other techniques?
    Mr. Mead. Yes, there are.
    Mr. Boucher. Such as? Do you have some examples?
    Mr. Mead. Well, one is visual inspection. One is pressure 
inspection. I can submit a full list of these for the record if 
you would like.
    Mr. Boucher. Okay. Well, that would be helpful.
    Mr. Mead. But they are numerous.
    Mr. Boucher. Just add that to the letter you are going to 
send us. I would appreciate that.
    Well, that is helpful testimony. And I appreciate your 
apprising us of your views with regard to the application of 
these plans to distribution.
    In the time I have remaining, I would like to propound a 
question to you, Mr. Bonasso. That relates to the development 
of regulations by the Office of Pipeline Safety with respect to 
the technical assistance grants for communities that were 
required in our 2002 act. These grants are designed to provide 
communities with the technical expertise necessary to let them 
participate in a meaningful way in hearings and other forums 
that are organized to address pipeline safety issues from the 
deployment of pipelines in the first instance and the 
permitting process associated with that to questions that arise 
post-pipeline deployment, such as the adequacy of testing with 
respect to the integrity of these pipelines.
    In the absence of being able to get technical expertise, 
engineering assistance, and the like, communities are obviously 
to a large degree inhibited in their ability to do that. These 
technical assistance grants that we mandated in the 2002 
statute were designed to fill that gap.
    Now, in the regulations issued by the Office of Pipeline 
Safety in December of last year, there was silence on the 
question of these technical assistance grants. We do not have 
rules written with respect to them at the present time.
    So my question to you is, when do you intend to write these 
rules? When will the regulations that specify the procedure for 
accessing the technical assistance grants be put in place in 
final form? When will these funds be available to localities?
    Mr. Bonasso. Congressman, we have approached the 
implementation of the act based on a priority basis. The 
principal approach has been to secure the safety of the 
communities first. And we have spent our time focusing on those 
activities.
    We have also spent a great deal of time considering what 
the issues are that these communities are going to be dealing 
with. What I mentioned, the Transportation Research Board 
research study, deals with the issues of encroachment and how 
significant these problems are.
    The issue of the community technical assistance grant is 
certainly one of the items that we are preparing to work on. We 
expect to have a workshop with the industry and the communities 
tentatively scheduled for December to begin gathering 
information on the implementation of this particular part of 
the act.
    So it is not something that we have forgotten. It is 
something that has been part of our priority approach. And it 
will be acted upon in the near future.
    Mr. Boucher. So within the coming year, you would begin a 
rulemaking?
    Mr. Bonasso. Stacey, what do you think? Within the year?
    Ms. Gerard. We can certainly do that.
    Mr. Bonasso. We can do that, sir.
    Mr. Boucher. Thank you very much. Thank you, Mr. Chairman.
    Mr. Shimkus [presiding]. The gentleman's time has expired. 
And I will recognize myself for 8 minutes. Hopefully I won't 
use that much. And, again, I would like to welcome you all.
    I think I would like to start with Mr. Mead. There is some 
reorganization that is planned in the 2005 budget. Briefly can 
you talk about how you perceive that to be helpful? And then in 
your answer, what I will be looking for, is there congressional 
action that you will be seeking that you think you need? And 
have you coordinated with anyone on the committee here, the 
Energy and Commerce Committee to that effect?
    Mr. Mead. Well, sir, the inspector general, we aren't 
carrying the brief for this reorganization. And I am not 
familiar with exactly who they have spoken to up here in the 
Congress or not.
    I am aware in general of the proposal. I think the idea 
behind it to bring different research components within DOT 
together is a sound one because where there are cross-modal or 
intramodal connections in research, you ought not to have 
everybody going off in their own direction.
    Mr. Shimkus. Well, let me flip to Mr. Bonasso because it is 
probably more in his area.
    Mr. Mead. Yes.
    Mr. Shimkus. Can you answer, in essence, the same line of 
questioning on the reorganization plan by the administration 
and how you perceive that to be helpful with the follow-up 
questions on it? Will you be requesting legislative action in 
support of that?
    Mr. Bonasso. What I can share with you is that the 
department is currently studying the potential of 
reorganization. It does revolve around the research function of 
the department, which is the key component, not only the 
research itself but what is informing the research; that is, 
the BTS activity, the Bureau of Transportation Statistics, the 
need to stop duplicating research to make sure that there is a 
clear oversight of all of the research that is involved.
    Now, I think that is the basic intention. It is not the 
intention of the reorganization plan to impact the operation of 
the Office of Pipeline Safety or the operation of hazardous 
materials at all. It is to make an effort to improve their 
operation, if anything. So I think that there have been a lot 
of rumors and ideas that have been floated out.
    I think that all of the information that has come back from 
those has been helpful. And I think that the Office of the 
Secretary is considering all of that information now. Hopefully 
they will be providing something soon in what they intend.
    Mr. Shimkus. Let me follow up. I mean, this system of pipes 
for the distribution and transmission and all of these goods, I 
think the public as a whole, we just don't have an appreciation 
for how much is being transported. But we do on the fuels 
debate when one gets disrupted, gasoline fuel prices spike 
because of the bulkanization of the fuel markets and the 
boutique fuels and the like.
    The one-call system, the third party intrusion into the 
pipeline system is one of the major reasons why we have these. 
The one-call system is successful when implemented and 
aggressively used. It is usually funded at the Federal level at 
a million dollars. The administration has reduced that to 
$800,000. That is what we are being told. Is that correct, Mr. 
Bonasso?
    Mr. Bonasso. Yes, it is.
    Mr. Shimkus. I guess the argument would be that obviously--
what is the argument for cutting it from $1 million to 
$800,000?
    Mr. Bonasso. It's just that we have limited resources. And 
our goal is to try to maximize the use of those resources and 
to focus on other forms of damage prevention activities. I 
mean, we certainly think that the call before you dig program 
is a very important program. And the speed at which we have 
successfully got FCC to consider the 3-digit dialing is an 
indication of that.
    Mr. Shimkus. Yes. And then I want to follow on the same 
line of questions to Mr. Mead. In the reports, we have the 
issues of fatalities and stuff. Do you have a breakdown as to 
the cause of the fatalities and injuries? And was the bulk due 
to third party damage versus corrosion versus something else?
    Mr. Mead. Yes. That ties into this three-digit call issue 
because half of them are due to third party excavations of some 
sort.
    Also, this is a change I didn't mention in my oral 
statement, but before the last law, they only had a few basic 
categories for reporting the calls. In the past year, they have 
been collecting calls data on 25 different categories. I think 
it is too early to report to you exactly what those results 
are.
    Mr. Shimkus. Thank you.
    Finally, let me ask, Ms. Siggerud, on the issue of 
penalties, reductions in 66 cases, 66 files do not seem to be 
that overwhelming. How many files did you review?
    Ms. Siggerud. I think the issue that you are probably 
getting at is what were the reasons----
    Mr. Shimkus. That's the follow-up question.
    Ms. Siggerud. [continuing] that the penalties were reduced. 
The data bases that were available to us and to OPS do not 
always or, I should say, do not generally include information 
that tell us the reasons why the penalties were reduced between 
the proposed and the assessed phase.
    We looked at several. We did not look at all 66 of those 
cases. We looked at several to try to get a sense of the 
reasons that the penalties are reduced over time. They actually 
can be quite voluminous. And it is not always obvious in 
looking at the file what the major reason was for the 
reduction. Therefore, I am not able to today give you any 
particular information on what the most common reason was.
    Mr. Shimkus. That was the follow-up because you basically 
looked at the data bases.
    Ms. Siggerud. Right.
    Mr. Shimkus. And you're saying you didn't have the time or 
the personnel to go through and actually go through the files 
of the causes. For the layman's point of view, is that----
    Ms. Siggerud. I guess essentially it boils down to that. 
There are a couple of issues to consider here. First of all, as 
I mentioned, in looking at these files, it's not always 
extremely obvious because of the way they are assembled what 
the reason for the reduction was.
    Second, a lot of this information is also contained in the 
field offices. And we have focused our work primarily in 
headquarters but did contact various officials in the regional 
offices to try to get a sense of how they administered the 
program.
    Mr. Shimkus. So obviously I used my entire 8 minutes, but 
to get a further more clarification, would you recall, then, 
for Members of Congress to ask the GAO to do a further 
explanation of why the reductions were in the 66 cases and ask 
for another follow-on report?
    Ms. Siggerud. We would certainly be happy to work with you 
if you would care to request that kind of information.
    Mr. Shimkus. Thank you very much.
    I would now like to recognize Mr. Green for 5 minutes.
    Mr. Green. Thank you, Mr. Chairman.
    Mr. Bonasso, after the Pipeline Safety Act of 2002, DOT 
moved quickly on implementing pipeline safety mandates and 
recommendations. Why did DOT move to require integrated 
management programs for the transmission pipelines but not for 
the distribution pipelines?
    In addition, the AGA's testimony later will explain the 
different pipelines, but it would help to get an understanding 
of the agency's decisionmaking.
    Mr. Bonasso. First, distribution pipelines are all under 
State jurisdiction. That is sort of the nature of the animal. 
There is a great deal of plastic pipe involved in distribution 
pipelines as well.
    The technology for integrity management programs for this 
type of pipe is limited. It involves basically visual 
inspections. There is a certain amount of pressure testing that 
can be done. There is a little bit of other nondestructive 
testing that can be done. So there are limited ways that we can 
implement an integrity management program.
    So the prevention approach, the call before you dig, is 
probably the most significant approach on these distribution 
pipelines. So the reason that we focused on the large gas and 
liquid transmission lines is basically because the technology 
lent itself to doing integrity management programs with them. 
It helped the industry get prepared for what integrity 
management involved and that will allow us to go forward.
    Mr. Green. Okay. Mr. Mead, in your testimony, you talked 
about the California pipeline that deteriorated. I assume that 
was intrastate?
    Mr. Mead. Yes, sir, inter.
    Mr. Green. Interstate?
    Mr. Mead. Yes, sir.
    Mr. Green. Okay. But it took 3 years and 40 permits to 
relocate it safely. What should OPS have done? What was the 
bottleneck? Was it State or Federal regulations? Typically we 
hear that ``Nobody wants a pipeline in our backyard.'' I just 
happen to have lots of them in our area.
    Mr. Mead. Congressman, if I were to redo the list, it would 
take up all of your time.
    Mr. Green. Okay. Submit that to the committee, if you 
would.
    Mr. Mead. I will submit it for the record, but basically 40 
permits from 31 Federal, State, and local agencies. I will 
submit the entire list for the record. Essentially there are 
too many players, all of whom can put up a ``Stop the show'' 
sign. Also, there are no time lines.
    In California, the sad part about that situation was 
everybody knew this was a deteriorating pipeline. They had 
tried all kinds of remediation before. And they knew they had 
to do something. But still the process didn't speed itself 
along.
    Mr. Green. I've had some concern over the years about 
California's infrastructure and regulatory delay in dealing 
with the price jumps. But now we're talking about this would 
impact the safety.
    Let me get to another question that the chairman followed 
up on. Does the DOT have the current authority to combine the 
pipeline R&D functions with other R&D functions, such as the 
Federal Railroad Administration while keeping the regulatory 
agency separate? Can they already under current law combine 
those functions?
    Mr. Mead. Some statutory changes would be required.
    Mr. Green. Since you want to combine or the discussion is 
combining just the R&D, I would hope, for that, why not include 
the R&D also for over-the-road 18-wheeler trucks? Because we're 
talking about transportation of materials. Whether it is in an 
18-wheeler or a tank car on a railroad or a pipeline, it is 
still the same substance. Has there been any discussion to 
expand it to that?
    Mr. Mead. Again, I haven't been privy to other discussions, 
and I am not carrying that brief. I do understand that 
locating, centralizing the research function was intended to 
apply to research functions that were intramodal or had cross-
modal applications and things like where the FAA is just 
focusing on airplanes or the Federal Motor Carrier Safety 
Administration is just focusing on trucks, that that wouldn't 
necessarily be moved over. Maybe Mr. Bonasso can give a further 
exposition on it.
    Mr. Green. Mr. Chairman, I had one other question, but if 
Mr. Bonasso could use the last 9 seconds?
    Mr. Bonasso. Well, just quickly, there is almost a billion 
dollars of research being done in the DOT across the agencies. 
What the secretary is trying to do is get a handle on all of 
that, not just the OPS and railroad research.
    Mr. Green. Oh, I agree with that philosophy because you are 
dealing with the same substances.
    Thank you, Mr. Chairman.
    Mr. Shimkus. The gentleman's time has expired. The Chair 
recognizes the gentleman from Idaho, Mr. Otter, for 5 minutes.
    Mr. Otter. Thank you, Mr. Chairman.
    I appreciate the panel being here today. I can see that, 
even with the best of intentions--I was on the Transportation 
Committee when we passed the new pipeline safety bill. Of 
course, we had a litany of reasons for doing that. And we went 
back for years to relive, once again, many of the horrible 
accidents that we had on pipelines prior to the reauthorization 
or, I should say, I guess, the rehabilitation of the Pipeline 
Act.
    Something that concerned me at the time--and I renew this 
concern today as I hear some of the delays and the pauses and 
the lawsuits and that sort of thing, and I would like to hear 
an expression from the entire panel as to what would be the 
instrument by which we could stop these delays or at least make 
the delays legitimate, rather than an oblique effort to either 
arrest, delay, or perhaps stop completely the rehabilitation of 
a pipeline to make it more safe or perhaps the construction of 
a new one.
    We don't have this problem just in pipelines. In fact, at 
my last recollection in Idaho, we have got about $58 million 
still sitting in the bank from highway construction that we 
haven't been able to get to because somebody found a bug or a 
three-toed frog or something. Nationwide it's $14 billion, 
which would put 400,000 construction workers to work, which 
would also make the highways a lot safer in Idaho. We lose 32 
lives a year on a stretch of road that we have been trying to 
get permission from all of the agencies.
    Anyway, let's get back to my question. My question is, what 
can we put into the system in order to legitimately protect the 
environment, legitimately protect and save lives, and 
legitimately go forward with the mission that you are entrusted 
with?
    Mr. Mead. I think there are three things based on the work 
we did. One is you need a credible way of identifying an 
emergency or exigent circumstance where safety has to be the 
priority. I think that the current memorandum of understanding 
process lends itself to that.
    The second thing you need, though, and the third, which I 
don't believe are in place, one, somebody has to be in charge. 
You can't have the situation where 31 or 40 people all are in 
charge and can all stop the show.
    Finally, with something that is a priority safety matter, 
it seems to me that it is not unreasonable to set a time line 
and say, ``You have all got to decide one way or the other by a 
time certain.'' You can't let this drag out, as we did in the 
case in California, for more than 3 years. The accident 
happened. Now we say, ``Well, we are ready to give you the 
permit.''
    So there are the three suggestions I would have, 
Congressman.
    Mr. Otter. I love those suggestions. Would any of the three 
of you disagree with that? Yes, sir?
    Mr. Bonasso. I would think that there is an additional 
component and one that is being worked on by the CEQ committee. 
That is the opportunity for a categorical exclusion for 
pipelines because they already exist in certain areas. There 
are certain practices that can be clearly identified and can be 
utilized.
    The plan of Chairman Connaughton also involves tandem 
processing of permits and early notification by the operators 
as to when a need for something needs to be done.
    Mr. Otter. Any additional information?
    Ms. Siggerud. Congressman, we haven't done any recent work 
in this area, but all of the suggestions that my fellow panel 
members suggested seem reasonable.
    Mr. Otter. I appreciate your comment about the categorical 
exclusion because the first time I ever heard of it was 
obviously on forest health. Thus far, although we haven't 
really generated all of the horrible consequences that many in 
communities thought was going to happen, we have been able to 
very slowly move forward with--did you have something you 
wanted to add?
    Mr. Bonasso. One other thing that I answered in the 
previous hearing, and that is have the agencies who are 
considering permits for pipeline repairs report to Congress on 
the status of them?
    Mr. Otter. Well, if I could just briefly, one of the things 
that I have found out on categorical exclusions for forest 
health, even when we have a tremendous bug or night shade or 
some kind of a disease or an invasive plant in our forests, 
that being able to move forward on categorical exclusions, 
which I think is a tremendous instrument to overcome some of 
these problems, we still have folks in place that refuse to use 
categorical exclusion.
    And so let me just end this, Mr. Chairman,--I appreciate 
the extra time--by suggesting to you that all of these are 
great suggestions, and I love them. Unless you have people in 
place that will do this, that will follow the law, and use 
their God-given talents to use categorical exclusion, if you 
will, to expedite the system, we have to have some penalty for 
removing those people, just as we would corporate governance 
today. And we have gone through that in the last 2 years. The 
bureaucracy and those who engage in bureaucratic efforts have 
to be just as accountable as we want the private sector to be.
    Thank you, Mr. Chairman.
    Mr. Shimkus. Gentleman's time has expired. The Chair 
recognizes the gentleman from Maine, Mr. Allen, for 5 minutes.
    Mr. Allen. Thank you, Mr. Chairman.
    Mr. Bonasso, I understand the Office of Pipeline Safety is 
responsible for regulating the safety of LNG facilities, which 
have been of great interest in my State recently. Our State is 
trying to find an appropriate community in which to cite such a 
facility, but, as you can imagine, there is great concern up 
and down the coast.
    Could you describe for me the safety record of LNG 
facilities: first, in the United States; and, second, overseas? 
And with respect to the international safety record, if you 
could give us an explanation of the cause of the explosion in 
Algeria a little while ago?
    Mr. Bonasso. In the United States, we have had 33,000 
shipments of LNG to our facilities. And there has not been one 
safety incident.
    Mr. Allen. Over how many years?
    Mr. Bonasso. Since 1971, I think that has been.
    The technology is very well-developed and proven, has 
proven itself. The physics of the LNG itself is that it is not 
explosive, that it doesn't explode. It vaporizes and then 
burns.
    The jury is still out on the Algerian accident as to 
whether or not it was LNG that actually caused the explosion. 
So that is all I can give you, Congressman, on just in a 
nutshell where we are.
    Mr. Allen. Do you have any comment on the international 
record apart from the incident in Algeria?
    Mr. Bonasso. I don't. We don't have any other information 
on international statistics.
    Mr. Allen. Well, I guess, then, can you talk a little bit 
about how LNG terminals compare in terms of safety with oil 
refineries, other ports of entry for petroleum products, and 
pipelines? Is there a way of comparing safety records across 
those different kinds of facilities?
    Mr. Bonasso. Well, the Coast Guard has the responsibility 
for the ship as it comes into the terminal. FERC and Office of 
Pipeline Safety are responsible for the terminal itself and 
then the piping out of the terminal and how it is cited. And so 
basically the operations of these things has been safe.
    Now, we don't have any comparison to refineries and how 
these would compare. There have been basically 60 years of 
experience with LNG. And it has basically been a safe approach 
to delivering natural gas.
    Mr. Allen. Also, staying with you for the moment, the GAO 
notes on page 9 of its testimony that OPS created a new 
enforcement office in 2002 and focuses on enforcement issues. 
We have been talking about that. The GAO says this office is 
not fully staffed and the key positions remain vacant.
    Can you outline for this subcommittee what you envision the 
work of this office to be and when you think it will be fully 
staffed? I don't think that has been answered in the course of 
the previous questions. Correct me if I am wrong.
    Mr. Bonasso. I don't believe it has been answered either. 
It is basically going to be our goal is to get our agency 
staffed by the end of the year. That has been one of the 
overriding goals that I have had this year with OPS.
    This particular office will be a policy-setting office. It 
should be fully operational by next year, when we get these 
activities going. And it will fundamentally audit the 
activities of the enforcement division. These are people in the 
field, people that are monitoring the inspections and so on. So 
that is the kind of function and time line that we have in 
place.
    Mr. Allen. When you said it will be fully staffed next 
year, beginning, end? What is the goal?
    Mr. Bonasso. Early next year.
    Mr. Allen. Early?
    Mr. Bonasso. Yes, sir.
    Mr. Allen. Mr. Bonasso, I thank you. I yield back.
    Mr. Shimkus. Gentleman yields back. The Chair recognizes 
the gentle woman from Missouri, Ms. McCarthy, for 5 minutes.
    Ms. McCarthy. Thank you, Mr. Chairman, for this hearing. 
Thank you to the panelists for the wisdom that you are sharing 
today.
    I would just like to pursue the issue of what more we need 
to do. I know the issues of who is in charge and a time line 
and those kinds of activities were shared. I am very 
appreciative of the continued vigilance, Mr. Mead, that your 
organization is doing in this matter.
    Even as recently as 1990, we had a major incident of 
natural gas pipeline in my district. In fact, we have got a 
major pipeline under our airport, the Continent Airport in 
Kansas City. That would really be long-term economic 
consequences and tragedy if something were to occur.
    I wondered if you could give us a sense of what kind of 
priorities we should put as a Congress working with you with 
regard to the biggest threats that still exist for pipeline 
safety. Is there more the Congress could do?
    You mentioned clarity in who is in charge and putting a 
time line together. Aside from just the continued oversight 
over OPS and pipeline safety in general, what is it that the 
Congress should do and can do to further this, in addition to 
all of the efforts that you are maintaining?
    When I was in the State legislature before coming here, I 
worked on the call dig effort Statewide in Missouri, but what 
is it that we need to be doing to make sure that we reduce the 
incidence of major incidents and make it easier for you to do 
your jobs?
    Mr. Mead. All right. A very quick answer on that, in the 
last 2 months, there have been three oversight hearings in the 
Congress on the subject of pipeline safety: one in the Senate, 
two in the House. This is the third today.
    I would say keep it up. You are at a very critical juncture 
on your so-called IMPs, these inspection maintenance programs 
or integrity management programs, that they are applying to the 
hazardous liquid pipelines and natural gas transmission 
pipelines, very, very recent.
    It's new. And they're finding a fairly substantial number 
of integrity threats that need to be remediated. They are 
focusing initially on inspections in what they call high-
consequence areas. The airport, Lambert Field, for example, 
would be a high-consequence area, I'm sure. So if I were this 
committee, I would have a hearing next spring, for example, to 
say, ``Where are we on the high-consequence areas?''
    No. 2, I am concerned about the environmental permitting 
process. I do not have a high degree of confidence that that 
will clarify itself through the administrative bureaucratic 
process of the agency's signing a memorandum of understanding.
    Third, pipeline security. I think the relationships between 
DHS, DOT, and the Department of Energy need to be spelled out 
with greater clarity. Finally, on natural gas distribution 
pipelines, I believe that that is an area where by March of 
next year, the Office of Pipeline Safety should report back to 
you on what they are going to do about them. They are currently 
not covered as part of the so-called IMP process like it is 
with the hazardous liquid pipelines and natural gas 
transmission pipelines.
    So those are four things that----
    Ms. McCarthy. Excellent things. Thank you very much.
    Would anyone else like to comment? Please?
    Mr. Bonasso. Yes. I would like to add the supporting 
elements in that. Congress could make sure that the three-digit 
dialing for the call before you dig actually takes place. That 
is the single greatest cause of pipeline accidents. And 
anything we can do to create a National campaign to make sure 
people know that would improve the safety greatly.
    The other item is to support the Transportation Research 
Board's report, which helps us with communities and plans to 
help us with communities and local planning relative to 
pipelines. That is what the report is going to recommend.
    So those are areas where local communities can have a 
greater involvement, both of them.
    Ms. McCarthy. Thank you.
    Mr. Bonasso. Yes, ma'am.
    Ms. McCarthy. Any other thoughts? Yes?
    Ms. Siggerud. Yes. Mr. Mead mentioned oversight. And I 
would like to echo that. I think it is very important to 
continue to have oversight of this office and of this program.
    Let me just mention that there are several recommendations 
that GAO has made to OPS and to DOT that I think could bear 
some following up on. Things are in process but not yet 
finished. First, in the report that we are issuing this week, 
we have asked OPS to look at its management process in terms of 
setting goals and performance measures, both for its 
enforcement program. In the past, we have made a similar 
recommendation with regard to its research program.
    Second, we are concerned about workforce planning and 
getting the integrity management program up and running. It is 
very complex. We have made a recommendation. OPS is in process, 
but it is not yet finished with that effort.
    Second to last, we have made some recommendations with 
regard to communicating and making better use of the State 
partners.
    Ms. McCarthy. Yes.
    Ms. Siggerud. Again, there is some action in OPS but more 
left to be done there.
    Finally, we have a recommendation we have made to DOT in 
general and to the Department of Homeland Security with regard 
to security for all modes, including pipelines, so that there 
would be a memorandum of agreement that better states the roles 
of DOT and DHS are in all of these modes in terms of regulation 
oversight.
    Ms. McCarthy. Thank you so much. Those were excellent 
recommendations.
    Mr. Chairman, you have your work cut out for you.
    Mr. Shimkus. Not me, the regular chairman. But I thank my 
colleague and ask the ranking member if he has any additional 
questions.
    We are sort of waiting for another member, who wanted to 
address concerns to you. The door is open. What we'll do, since 
they are on the phone to him, we will adjourn this panel and 
convene the second panel. Thank you for your testimony.
    Mr. Boucher. Mr. Chairman, while the second panel is coming 
forward, I have a unanimous consent request. And that is that 
the statement of the ranking member of the full committee, John 
Dingell of Michigan, be included in the record and along with 
his statement, a copy of correspondence between Mr. Dingell and 
Deputy Administrator Bonasso.
    Mr. Shimkus. Is there objection?
    [No response.]
    Mr. Shimkus. Hearing none, so ordered.
    [The correspondence of Hon. John D. Dingell follow:]

    [GRAPHIC] [TIFF OMITTED] T5457.001
    
    [GRAPHIC] [TIFF OMITTED] T5457.002
    
    [GRAPHIC] [TIFF OMITTED] T5457.003
    
    [GRAPHIC] [TIFF OMITTED] T5457.004
    
    Mr. Shimkus. You all are dismissed.
    We would like to welcome our second panel and move 
expeditiously to gather testimony. Your full statements will be 
submitted for the record. If you could summarize? You have 5 
minutes to do so.
    First, we would like to welcome Mr. Earl Fischer, Senior 
Vice President, Utility Operations for Atmos Energy Corporation 
of Dallas, Texas. Mr. Fischer, welcome, and we await your 
testimony.

   STATEMENTS OF EARL FISCHER, SENIOR VICE PRESIDENT, UTILITY 
 OPERATIONS, ATMOS ENERGY CORPORATION; BARRY PEARL, PRESIDENT 
AND CEO, TEPPCO PARTNERS, L.P., ON BEHALF OF ASSOCIATION OF OIL 
PIPE LINES AND THE AMERICAN PETROLEUM INSTITUTE; BREEAN BEGGS, 
 EXECUTIVE DIRECTOR, CENTER FOR JUSTICE, ON BEHALF OF PIPELINE 
SAFETY TRUST; PAUL D. KOONCE, CHIEF EXECUTIVE OFFICER, DOMINION 
  ENERGY, ON BEHALF OF INTERSTATE NATURAL GAS ASSOCIATION OF 
  AMERICA; AND ROBERT KIPP, EXECUTIVE DIRECTOR, COMMON GROUND 
                            ALLIANCE

    Mr. Fischer. Thank you. Good afternoon, Mr. Chairman and 
members of the committee. My name is Earl Fischer, and I am 
Senior Vice President, Utility Operations of Atmos Energy 
Corporation.
    Atmos Energy is one of the largest pure natural gas 
distributors in the United States delivering natural gas to 
about 1.7 million residential, commercial, industrial, and 
public authority customers. Our regulated utility services are 
provided to more than 1,000 small and medium-sized communities 
across 12 States.
    I am here testifying today on behalf of the American Gas 
Association and the American Public Gas Association. I hope 
that my testimony today will provide for a better understanding 
of how distribution systems work and how the implementation of 
the Pipeline Safety Improvement Act of 2002 affects us.
    Let me begin by commending Congress for passing a fair and 
a balanced pipeline safety bill in 2002. The House Energy and 
Commerce Committee had a very significant role seeing that the 
bill went through. I and both of our trade associations thank 
the committee members for their commitment and their 
leadership.
    Gas distribution utilities like Atmos are the last critical 
link in the natural gas delivery chain. To most customers, 
utilities are the face of the industry. We are the meter at the 
house. We interact daily with our customers and the public in 
the areas that we serve.
    Over the last 17 years, the amount of natural gas traveling 
through distribution pipelines has increased by almost a third 
and more than 650,000 miles of pipeline had been added to the 
system. Yet, the number of reportable incidents on distribution 
pipelines has decreased by 25 percent.
    To properly compare natural gas distribution accident 
statistics to other pipeline accident statistics, the data must 
be reduced to a common basis. One would not compare the number 
of auto traffic accidents with airline accident deaths without 
first reducing this to a statistics per vehicle miles. And it's 
the same with pipelines.
    Over the last 18 years, the number of fatalities and 
injuries associated with distribution pipelines per 100,000 
miles is less than 45 percent of the total of all pipelines.
    Natural gas distribution pipelines are thoroughly 
regulated. As part of an agreement with the Federal Government 
and most States, State pipeline safety authorities have primary 
responsibilities to regulate natural gas utilities and 
intrastate pipeline companies. In return, State governments 
have to adopt as minimum standards the Federal set of standards 
promulgated by the Department of Transportation.
    Distribution systems are constructed in configurations that 
look like a network or a webbing, use followed diameter, 
thicker walled pipe, and operate in high-density population 
areas at much lower volumes and pressures, always using 
odorized natural gas so leaks can be readily smelled and 
detected.
    Under individual authorizations by their States, most 
companies have been already addressing the integrity of 
distribution systems on risk-based prioritization schedules. 
This has been taking place for at least 2 decades and covers 
programs that allow the operator to ensure distribution 
pipelines remain safe and reliable by using customer dollars in 
the most efficient manner.
    So what has occurred since the implementation of the 
Pipeline Safety Improvement Act of 2002? The United States, 
DOT, Office of Pipeline Safety, and industry have diligently 
worked to address much of the scrutiny that arose during the 
debate of the 2002 bill.
    To their credit, OPS has dealt with the vast majority of 
this backlog and is moving expeditiously to address the 
congressional mandates. At least 12 separate new regulatory 
mandates and initiatives to address distribution systems are 
now in progress.
    In view of the span of time allowed us at this hearing on 
pipeline safety, allow me to highlight five points that 
illustrate the progress made with a more complete list being 
contained in the written testimony.
    Point No. 1, the programs required by the Pipeline Safety 
Act are well underway. Many gas pipeline operators have already 
begun implementing the integrity rule. And all operators are 
required to begin assessments by the June deadline just past. 
Approximately 30,000 miles of gas transmission lines operated 
by gas distribution utilities will have to be assessed under 
this rule at the cost of $3 billion in 20 years. At the same 
time, we must maintain an uninterruptable gas supply to our 
customers.
    Point No. 2, we must expedite the environmental permitting 
process. We need a more efficient process that will not allow 
one agency to prohibit a citizen from taking an action required 
by another agency. Our members estimate they must perform about 
110,000 integrity inspections requiring excavation on 
intrastate pipelines over the next 7 years. There are good 
options under existing environmental laws for ensuring 
environmental protection in a way that is less process-
intensive. We have been pleased to see significant progress 
since the Senate hearing in mid June.
    Our point No. 3, as in the past, we urge Congress to focus 
attention on excavation damage prevention for injuries, 
fatalities, property loss, and disruption of services continue 
to occur due to accidental strikes of underground facilities 
during excavation, drilling, and boring.
    Annual gas distribution incident statistics from the DOT 
data base show a clear correlation between the level of 
construction activity and the number of incidents. Year after 
year third party damage by outside excavators cause over 60 
percent of the total ruptures on utilities and the vast 
majority of injuries and fatalities.
    Many third party damage events cannot be prevented by the 
actions of the gas operator alone, no matter how diligent, 
resourceful, or technically well-equipped he is. This is where 
damage prevention organizations like the Common Ground Alliance 
prove to be the most effective.
    Point four, I am pleased to report that the American Gas 
Foundation with AGA and APGA and State and Federal regulator 
involvement----
    Mr. Shimkus. Excuse me, sir. Since you have constituents in 
my district, I will let you rapidly finish. But if you would do 
so, we can get along to our other panelists.
    Mr. Fischer. Thank you, sir.
    Point five is a plea for specific time to measure the 
results. And we are underway with our implementation process. 
We think it would be premature to currently draw conclusions on 
the results of any of these programs, which have also resulted 
in a substantial number of regulatory mandates.
    Public safety is the top priority of natural gas utilities. 
And we are spending about $6.4 billion to comply with Federal 
and State regulations, which also includes a $3.2 billion 
expenditure that is voluntary by the operators alone.
    Thank you for providing the opportunity to present our 
views on this very important matter.
    [The prepared statement of Earl Fischer follows:]

  Prepared Statement of Earl Fischer, Senior Vice President, Utility 
  Operations, Atmos Energy Corporation on Behalf of the American Gas 
           Association and he American Public Gas Association

    Good morning, Mr. Chairman and members of the Committee. I am 
pleased to appear before you today and wish to thank the Committee for 
calling this hearing on the important topic of pipeline safety. My name 
is Earl Fischer. I am Senior Vice President, Utility Operations of 
Atmos Energy Corporation. Atmos Energy is one of the largest pure 
natural gas distributors in the United States, delivering natural gas 
to about 1.7 million residential, commercial, and industrial and 
public-authority customers. Our regulated utility services are provided 
to more than 1,000 small and medium-size communities in 12 states.
    I am here testifying today on behalf of the American Gas 
Association (AGA) and the American Public Gas Association (APGA). The 
American Gas Association represents 192 local energy utility companies 
that deliver natural gas to more than 53 million homes, businesses and 
industries throughout the United States. AGA member companies account 
for roughly 83 percent of all natural gas delivered by--the nation's 
local natural gas distribution companies. AGA is an advocate for local 
natural gas utility companies and provides a broad range of programs 
and services for member natural gas pipelines, marketers, gatherers, 
international gas companies and industry associates.
    The American Public Gas Association is the national, non-profit 
association of publicly owned natural gas distribution systems. APGA 
was formed in 1961, as a non-profit and non-partisan organization, and 
currently has 606 members in 36 states. Overall, there are 949 
municipally owned systems in the U.S. serving nearly five million 
customers. Publicly owned gas systems are not-for-profit retail 
distribution entities that are 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.
    Natural gas meets one-fourth of the United States' energy needs. I 
am pleased to appear here today and hope that my testimony will provide 
you with a better understanding of how distribution systems work and 
how the implementation of the Pipeline Safety Improvement Act of 2002 
affects us.
    AGA, APGA and its members commend Congress for ensuring that the 
safety bill passed in 2002. The legislation that was finally passed in 
the final days of the 104th Congress was a balanced, fair bill and will 
bring yet further safety improvements. This Committee had a significant 
role seeing that the bill went through and I and the industry thank you 
for your commitment and leadership.
    We would also like to commend the U.S. Department of Transportation 
Office of Pipeline Safety (OPS) for diligently working to lay to rest 
numerous criticisms that arose during the debate on the 2002 bill. OPS 
was criticized by Congress, the National Transportation Safety Board, 
DOT's Inspector General and members of the public for failing to 
expeditiously address numerous congressional mandates and safety 
recommendations. To its credit, OPS has dealt with the vast majority of 
this backlog and is moving efficiently and effectively, and often in 
consultation with all affected stakeholders, to address the mandates in 
the Pipeline Safety Improvement Act of 2002.

Gas Distribution Utilities Serve The Customer
    Gas distribution utilities, also known as local distribution 
companies (LDCs) are the last, critical link in the natural gas 
delivery chain. To most customers, 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. 
Consequently, we take very seriously the responsibility of continuing 
to deliver natural gas to our communities safely, reliably and 
affordably.

Natural Gas Utilities Are Committed to Safety
    Safety is a 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.
    Our industry's commitment to safety is borne out each year through 
the National Transportation Safety Board's annual statistics. Delivery 
of energy by pipeline is consistently the safest mode of energy 
transportation. Natural gas utilities are dedicated to seeing this 
continue. Over the last 17 years, the amount of natural gas traveling 
through distribution pipelines has increased by almost a third and more 
than 650,000 miles of pipeline have been added to the system--yet the 
number of reportable incidents on distribution pipelines has decreased 
by 25 percent. This is a remarkable achievement, one that AGA and APGA 
attribute to the industry's overarching commitment to safety.
    To help to put the safety record of different categories of 
pipelines into perspective, it's important in the first place to 
compare the accident data on a common basis. For example, calculations 
of vehicular transportation accidents use vehicle-miles or passenger-
miles traveled to make valid comparisons. For natural gas pipelines, 
calculations should be done using total miles of installed pipeline for 
a given category, such as transmission or distribution lines.
    When measured by total installed miles per pipeline category using 
DOT statistics over the last 10 years (1994-2003), it is clear that gas 
distribution systems have fewer fatalities and injuries per mile than 
all other pipeline categories combined. In fact, natural gas 
distribution lines have 46 deaths and injuries per 100,000 miles for 
distribution compared to 49 deaths and injuries for all the other 
pipeline categories combined.
    Every distribution system operator can attest that natural gas 
distribution pipelines are thoroughly regulated--by state and federal 
safety authorities. State pipeline safety authorities have primary 
responsibility to regulate natural gas utilities and intrastate 
pipeline companies, as part of an agreement with the federal 
government. State governments then must adopt as their minimum 
standards the federal safety standards promulgated by the DOT. In 
exchange, DOT reimburses the state for up to 50 percent of its pipeline 
safety enforcement costs. Clearly, Congress's actions make a strong 
impact on state regulations and our companies.
    In addition, some states choose to impose more stringent 
requirements than the federal code, thus addressing specific concerns 
or conditions in their territory. The role of state commissions in 
setting pipeline safety requirements and verifying an enforcing 
compliance of distribution operators cannot be overemphasized.
    Under individual authorizations by the state, most companies have 
been addressing the integrity of distribution systems on a risk-based 
prioritization schedule. This includes leak management programs and 
repair-replace decisions and processes that allow the operator to 
ensure distribution pipelines remain safe and reliable, while using 
ratepayer funds in the most efficient manner. This has been taking 
place for at least two decades and is further improving as technology 
and materials developments allow more sophisticated decision-making 
processes as well as longer life, stronger materials.
    Maps of all pipelines are already available from the operator upon 
request by the jurisdictional state authority. Gas utilities typically 
provide their maps on request to key constituencies, such as emergency 
responders, city planners, law enforcement officials, one-call centers 
and residents. This is an effective system that works well for all 
concerned. Individual states are best positioned to determine if any 
additional maps or utility records should be publicly provided, but 
certainly a centralized database for hundreds of thousands of 
distribution system maps kept by federal Office of Pipeline Safety 
would do little to improve state oversight of an operator's system.

The Difference in ``Pipelines''
    While many may unintentionally link all ``pipelines'' together, 
there are indeed significant differences between the liquid 
transmission systems, natural gas transmission systems and natural gas 
distribution systems. Each industry faces different challenges, 
operating conditions and consequences of incidents.
    Interstate transmission systems are typically made up of long runs 
of generally straight pipelines occasionally crossing high-density 
population areas. These systems feature large diameter pipe and are 
operated at high volumes and high pressures. Distribution systems, in 
contrast, are constructed in configurations that look like a network or 
web, and use smaller diameter pipe. Because distribution systems are 
usually located in more populated areas, they are required to operate 
at much lower volumes and pressures, often feature thicker-walled pipe 
and always carry odorized gas that can be readily smelled even if a 
small leak occurs. .
    It should be noted that many distribution companies also own and 
operate transmission pipeline segments within their systems.
    Federal regulations recognize the differences between these three 
types of pipelines, and different sets of rules have been created for 
each. 49 CFR Part 192 sets out the regulations for natural gas 
transmission and distribution and the rules discriminate between the 
two, while 49 CFR Part 195 sets out the regulations for liquid 
transmission lines.

Status of Implementing the Pipeline Safety Improvement Act of 2002
    Since the Pipeline Safety Improvement Act of 2002 was signed into 
law on December 17, 2002, many programs have been launched to 
specifically address implementation of the law's mandates and further 
safety enhancements of gas transmission and distribution systems. For 
gas transmission systems, integrity management for gas transmission 
pipelines has been the most notable of the 2002 legislative mandates. 
However, the law has resulted in a substantial number of significant 
regulatory mandates, initiatives and voluntary programs for 
distribution systems.
A. Federal Regulatory Mandates
    The 2002 regulatory mandates affecting distribution systems 
include:

 Direct assessment standards development
 Environmental repair permit streamlining
 One-call 3-digit number rulemaking
 Right-of-way population encroachment study
 Operator qualification standard development
 Public awareness communication effectiveness rulemaking
 Infrastructure R&D grants program
1. Integrity Management Rule for Natural Gas Transmission
    OPS issued the integrity management rule for natural gas 
transmission lines on December 12, 2003. The rule requires natural gas 
transmission pipeline operators to conduct periodic inspections in 
``high consequence areas'', which for natural gas pipelines are 
generally high-density population areas.
    The nature of utility-owned transmission requires that over 50 
percent of the lines under the integrity management rule be inspected 
using direct assessment methods. Direct assessment is an alternative to 
internal inspection (smart pigging) or pressure testing. It comprises a 
variety of screening and examination techniques to locate and identify 
potential problems in the pipeline. The anomalies located by direct 
assessment usually involve corrosion of the pipeline. Corrosion is the 
second leading cause of gas pipeline failures.
    The direct assessment process entails performing two non-invasive 
complementary indirect exams of the section of the pipeline targeted by 
engineering analysis and predictions on that section. Typical indirect 
exams involve different approaches in measuring electrical values, so 
that any variations along the pipeline can give an indication of the 
locations where possible anomalies might be present. They may also 
involve checking for corrosion inside the pipe at preset sampling 
locations. The pipeline is then excavated at the previously identified 
locations, examined and repaired if necessary. The results are compared 
with predictions, becoming part of a learning curve about the condition 
of the pipeline and facilitating future direct assessments of similar 
sections of pipeline.
    Direct assessment is estimated to cost between $7,000 and $15,000 
per mile of pipeline examined, not including any necessary excavations. 
The latter can cost from $2,500 to $250,000 per excavation, depending 
on location.
    Many gas pipeline operators have already begun implementing the 
integrity rule and many more will be ready to begin assessments by the 
deadline on June 17, 2004. Approximately 30,000 miles of gas 
transmission operated by gas distribution utilities will have to be 
assessed under this rule. In the aggregate, for gas distribution 
utilities, estimated costs of compliance with this rule will exceed $3 
billion in 20 years, not including integrity management pass-through 
costs from their gas transmission suppliers upstream, repairs, 
modifications, and changes in operations that may be necessary to 
maintain the reliability of gas supply in the face of large scale 
pipeline inspections and testing.
2. Direct Assessment Standards Development
    The 2002 pipeline safety legislation also required that the DOT 
issue regulations prescribing standards for inspection of a pipeline 
facility by direct assessment. Such standards have been prescribed for 
external corrosion and are now being developed for internal corrosion 
and for stress corrosion cracking. The standards body leading this 
effort is the National Association of Corrosion Engineers (NACE). These 
standards will also be applicable to distribution pipelines.
3. Expedite Permit Streamlining: Timely Repairs vs. Permit Delays
    In the Pipeline Safety Improvement Act of 2002, Congress wisely 
recognized that it would be poor government for one agency to prohibit 
or prevent a citizen from taking an action that is specifically 
required by another agency--and even worse government to then penalize 
that citizen. And yet, this is what could happen if a federal 
environmental agency fails to take timely action on a permit 
application for a pipeline safety repair, so that work cannot begin and 
end by the deadline set by the natural gas IMP rule. Under that rule, 
integrity repairs must be completed either (1) immediately, or (2) 
within one year after the discovery of an anomaly, depending on the 
type of defect involved. If a repair is not completed by the applicable 
deadline, the operator is required to reduce pressure and throughput on 
the affected pipeline by 20% until the repair can be completed. 
Utilities are justifiably concerned that widespread, long-term pressure 
reductions would restrict supply and drive prices up.
    Our members estimate they must perform about 110,000 integrity 
inspections requiring excavation on intra-state pipelines (5 
inspections per mile on average) over the next 7 years. That means 
there will be about 15,000 inspections per year requiring a test hole. 
Although we have made our best estimates, we do not yet know what 
percentage of these will require further excavation to repair the line. 
The vast majority of them will not result in repairs or replacement of 
pipe but most will require permits. The bottom line is that there are 
too many of these projects to use the traditional, time consuming 
process for obtaining individual permits for each and every site. 
Congress wisely recognized the importance of this public safety work 
and therefore directed federal agencies to develop a streamlined 
process to ensure that permits are given in time to allow timely 
repairs.
    We need a more efficient process. Please note that we do not 
advocate changing underlying environmental standards or requirements. 
Our concerns are purely with the process. We only ask that the agencies 
work together in a seamless, efficient and coordinated way so that this 
important public safety work can start and finish on time.
    Interstate natural gas pipelines get their permits through an 
integrated Federal Energy Regulatory Commission (FERC) certification 
process and environmental review under the National Environmental 
Policy Act (NEPA). In December 2002, FERC and other federal agencies 
entered into a Memorandum of Understanding (MOU) to coordinate and 
accelerate the way in which they process permits for the construction 
of new interstate natural gas pipelines. The 2002 MOU also covers 
permits for maintenance and repairs of interstate pipelines, so it has 
been interpreted to help streamline permits for repairs under the IMP 
Rule. Although AGA is pleased because some AGA members operate 
interstate pipelines, the 2002 FERC MOU does not cover integrity 
repairs on intra-state pipelines because they are not certificated by 
FERC.
    The final Pipeline Repair Streamlining MOU specifically addresses 
the need to expedite integrity repairs that must be done 
``immediately'' under the IMP Rule. We are pleased that the MOU sets 
out the general framework for authorizing other repairs to proceed 
without site-specific permits, provided certain conditions are met.
    As I testified last month, we were concerned that the MOU contains 
no details regarding how this will work. Instead, the MOU delegates 
this difficult and essential task to a work group within the White 
House Interagency Taskforce. This group has little time remaining to 
develop a working process to streamline repair permits. Our members are 
on a tight schedule for beginning their integrity testing and first 
phase of repairs, and they will need timely authorization to begin this 
important public safety work.
    We are pleased that in the last three weeks, the interagency work 
group has made significant progress toward streamlining the permit 
process. The group has sought broad input from experts in the field to 
solicit ideas for creative ``outside the box'' solutions. They are 
considering some good options for ensuring environmental protection in 
a way that is less process-intense, acting within the authority the 
agencies have under existing environmental laws.
    The work group now plans to have a workable process in place by 
October 1, 2004 to ensure that timely permits can be obtained for the 
integrity testing and repairs that must be done in the next 18 months. 
AGA applauds this goal and the work group's energy, creativity and 
determination to protect both the environment and public safety.
4. Digit Number for One-Call Systems
    Congress has required the Federal Communications Commission to 
issue a rule that provides a toll-free 3-digit number that excavators 
and the public can use to easily connect to the appropriate one call 
center. One-call centers are designed to have personnel dispatched to 
the excavation site to have underground facilities--natural gas lines, 
petroleum and product lines, fiber optics, telephone, electricity, 
water and sewer lines--to avoid them being damaged. An easily 
remembered, easily advertised 3 digit number will increase the use of 
these vital services and therefore help avoid unnecessary accidents. 
The Federal Communications Commission just issued a proposed rule 
mandating the establishment of the 3-digit number.
    The leading cause of accidents on distribution pipelines comes from 
excavators unintentionally striking our lines. It is known as 
excavation damage, also commonly called ``third-party damage.'' Year 
after year, these strikes cause over 60 percent of the total ruptures 
on utilities and the vast majority of injuries and fatalities.
    Preventing third-party damage is the single greatest safety goal of 
the natural gas distribution industry. For a single cause to be the 
source of almost 60 percent of all incidents is simply unacceptable. As 
we have done numerous times in the past, and continue to do so, we 
strongly urge Congress to focus attention on excavation damage 
prevention.
    A generation ago, gas, water and sewer lines were the primary 
underground facilities in our nation's communities. Today, with the 
addition of telecommunications, electric and other facilities located 
underground, our gas distribution pipelines are more at risk than 
before. Annual distribution incident statistics for the past 10 years 
show a clear and distinct correlation between trends in the level of 
construction activity and the number of incidents. If construction-
related damage incidents are removed from the statistics, leaving only 
non-excavation damage incidents, it's clear that excavation damage 
incidents are on the increase, while the number of other incidents has 
remained relatively stable.
    Integrity programs such as the natural gas transmission pipeline 
integrity rule are better designed to address static and time-dependent 
factors affecting pipelines, rather than to prevent random factors such 
excavation damage. The latter can be due to a number of causes, many of 
which cannot be mitigated by the actions of the gas operator alone no 
matter how diligent, resourceful, or technically well equipped.
    We are continually urging states to require government agencies and 
their contractors to participate in One-Call programs. This would help 
eliminate some exemptions some state agencies currently have in several 
states from participation in One-Call. The Pipeline Safety Improvement 
Act of 2002 helped address this critical problem by clarifying that 
state departments of transportation should participate. However, there 
still is nothing to compel them to do so. Needless accidents continue 
to occur. Injuries, fatalities, property loss and disruption of 
services could be reduced with better use of One-Call centers and 
recommended practices for damage prevention.
    We are also continually urging gas companies to join the Common 
Ground Alliance damage prevention organization, which is working with a 
multitude of stakeholders in developing approaches to preventing and 
mitigating excavation damage.
5. Right-of-Way Encroachment Study
    The 2002 pipeline safety legislation directed DOT to work with the 
Federal Energy Regulatory Commission and other federal and state 
agencies to study the difficult problem of encroachment on pipeline 
rights-of-way and to report to Congress regarding proposed 
recommendations for improvements. DOT contracted with the National 
Academy of Sciences (NAS) Transportation Research Board (TRB) to study 
encroachment and prepare the report to Congress. Encroachment occurs 
where buildings and structures are placed on or very near the ``no 
build zones'' that a pipeline right-of-way represents. This is 
especially a problem where cities and towns expand and ultimately push 
up to a pipeline location that was rural when built.
    Last Monday, July 19, 2004, the NAS published a report concluding 
that OPS should work with a broad based stakeholder organization to 
develop risk-informed land use guidance for activities and construction 
near existing and future transmission pipelines. The report suggests 
using an entity similar to the Common Ground Alliance, which was formed 
to reach broad stakeholder consensus on best practices for preventing 
third party damage to pipelines and supported in part through federal 
appropriations. Of course, this new initiative will also require 
funding and resources through the appropriations process.
    We hope that the Committee will work with OPS and industry to make 
progress in addressing this encroachment problem.
6. Operator Qualification Standards
    In compliance with the 2002 legislative mandate, the OPS is leading 
development of a standard (ASME B31Q) for pipeline operations personnel 
qualification programs. This is another standard that has required 
significant AGA and APGA member involvement in handling both training 
and operational aspects. The standard is still being developed and its 
completion is slated for the end of this year.
7. Public Awareness Communication Effectiveness
    OPS is working with stakeholders from the liquids and gas 
industries to define what would be required to evaluate effectiveness 
of operator communication programs. OPS is also separately working with 
the states to define regulatory requirements that will cover gas 
utilities. AGA and APGA members have been involved via a task group to 
highlight the fact that flexibility is needed to avoid duplication of 
communication efforts already being carried out by gas utilities in 
their respective service territories at the local levels.
8. Infrastructure Research and Development Grants
    Congress significantly increased the authorization for OPS' 
pipeline safety research and development program to $10 million per 
year for four years. As OPS receives its funding primarily through user 
fees assessed on pipelines, these monies will likely be routinely 
provided. The Pipeline Safety Act of 2002 also sought to coordinate the 
efforts of OPS with those of the Department of Energy. Generally OPS 
focuses on those technologies that represent near-term development for 
field applications and the agency also provides matching dollars to the 
recipients.
    With the increase in inspections and repairs and the expanding use 
of natural gas, better ways to do the job need to be found. Industry 
typically cannot provide all that is needed for R&D due to the nature 
of the rate framework. The natural gas surcharge that the FERC allowed 
for many years ends this year on August 1st. FERC is considering an 
alternative proposal. AGA is also pursuing legislation that would 
establish a collaborative research program. AGA and APGA are hopeful 
that either the regulatory or legislative R&D funding proposal will 
become a reality. Either would solidify industry contributions to 
research. However, additional contributions for R&D are needed and AGA 
and APGA would welcome the opportunity to discuss with Committee 
members and staff the gas supply, transmission, distribution and 
utilization research that could be accomplished with increased public 
funding.
B. Additional Federal Regulatory Initiatives
    Current federal regulatory initiatives for distribution systems 
include:

 Operator qualification rule revision
 Public communications standard development
 Better crisis communication
 Excess flow valve installation
 Operator safety performance metrics
1. Operator Qualification Rule Revision
    To comply with NTSB recommendations, OPS expects to revise the 
operator qualification rule to include greater specificity. This has 
required significant AGA and APGA member involvement to ensure our 
members' concerns are taken into account. AGA and APGA believe 
reasonable additional requirements are being developed to adequately 
address the NTSB concerns and will soon become part of the revised 
rule.
2. Public Communications Standard Development
    A public communications standard (API Recommended Practice 1162) 
designed to address a variety of audiences has been completed under the 
American Petroleum Institute (API) banner, with input from industry and 
the regulatory community. It will be referenced by OPS via rulemaking 
on public education and communications.
3. Better Crisis Communication OPS is working with stakeholders to 
        define guidelines for operators to follow in issuing 
        communications in the event of involvement in an accident 
        involving pipelines. The most recent one occurred on a gasoline 
        pipeline in Tucson, AZ and sparked high-profile public 
        hearings. Distribution utilities are engaged in deliberations 
        with the other stakeholders to ensure concerns for gas utility 
        communications are addressed.
4. Excess Flow Valve Installation
    In response to an NTSB recommendation and more recently, public 
testimony, OPS is reconsidering whether to mandate the installation of 
excess flow valves on service lines. Cost-benefit studies performed to 
date by OPS do not adequately justify the nationwide installation of 
these devices on a mandatory basis unless some shaky, easily refutable 
assumptions are made. Mandated installation would pose a potential 
major added burden on AGA and APGA members that elect not to install 
such devices, but instead notify customers and install such devices 
upon request from the customer.
5. Operator Safety Performance Metrics
    OPS continues to look for ways to more clearly demonstrate the 
effectiveness of their safety programs. To this end, the agency is 
seeking to further improve and increase the gathering of safety 
performance data from operators. Federal regulators are contemplating 
further changes in operator reports to DOT that will also cover 
distribution systems. The distribution utilities remain committed to 
develop reasonable safety performance measurements with OPS and other 
stakeholders.
C. Voluntary Industry Programs
    Voluntary industry programs involving distribution utilities 
include:

1. A government-industry group examining existing regulations and 
        practices addressing distribution system integrity in an effort 
        to identify needed enhancements. Along with APGA, many AGA 
        member companies are participating in this study, which is 
        supported by the American Gas Foundation.
2. In response to an NTSB recommendation, numerous gas distribution 
        utilities have been collecting data on the performance of 
        plastic pipe since January 2001. Government and industry 
        stakeholders convene periodically to examine the data for areas 
        of concern.
3. Continued participation in the Common Ground Alliance to promote 
        infrastructure damage prevention through added best practices 
        by all stakeholders, education of excavators, research and 
        damage data collection.
    LDCs comply with a regulatory program that devotes stringent 
attention to design, construction, testing, maintenance, operation, 
replacement, inspection and monitoring practices. We continually refine 
our safety practices. Natural gas utilities spend an estimated $6.4 
billion each year in safety-related activities and this figure will 
significantly increase once the legislative mandates adopted to date 
are implemented fully. Historically, approximately half of this amount 
is spent in compliance 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 and products delivered.
Summary
    In summary, many programs are under way to address implementation 
of the legislative mandates of 2002. They must be given sufficient time 
to allow verification of their effectiveness. We believe it would be 
premature to currently draw conclusions on the results or consequences 
of any of these programs. Furthermore, in view of the growing need for 
energy to support continued economic growth, legislative decisions on 
pipeline safety should support or be consistent with the needed growth 
in the energy delivery infrastructure.
    The natural gas utility industry is proud of its safety record. 
Natural gas has become the recognized fuel of choice by citizens, 
businesses and the federal government.
    Public safety is the top priority of natural gas utilities. We 
invite you to visit our facilities and observe for yourselves our 
employees' dedication to safety. We are committed to continue our 
efforts to operate safe and reliable systems and to strengthen One-Call 
laws and systems in every state.
    Thank you for providing the opportunity to present our views on the 
important matter of pipeline safety. We look forward to working with 
federal, state and local authorities and representatives, as well as 
within our industry, to achieve the highest possible level of public 
and employee safety.

    Mr. Shimkus. Thank you very much.
    Now I would like to recognize Mr. Barry Pearl, President 
and CEO of TEPPCO Partners, Houston, Texas. Welcome, sir. You 
have 5 minutes.

                    STATEMENT OF BARRY PEARL

    Mr. Pearl. Thank you, Mr. Chairman. I am Barry Pearl, 
President and CEO of TEPPCO Partners, L.P. and Chairman of the 
Association of Oil Pipe Lines. I appreciate this opportunity to 
appear before the subcommittee today on behalf of AOPL and the 
pipeline members of the American Petroleum Institute.
    These organizations represent more than 50 pipeline 
companies that transport the vast majority of our Nation's 
liquid petroleum, including crude oil, gasoline, diesel jet 
fuel, propane, and petrochemicals.
    My company, TEPPCO Partners, L.P., owns and operates more 
than 11,600 miles of pipelines in 16 States. Our operations 
include one of the largest common carrier pipelines in the 
United States transporting refined products and liquefied 
petroleum gases from the Gulf Coast to markets in the Midwest 
and Northeast as well as crude oil, petrochemicals, and natural 
gas gathering.
    I have provided my full statement and attachments. And I 
ask that these be included in the record of this hearing. I 
would like to summarize that material for you.
    It has been 1\1/2\ years since the enactment of the 
Pipeline Safety Improvement Act of 2002. On behalf of the 
members of AOPL and APL, I wish to thank the members of this 
subcommittee for passing this very important legislation.
    As the subcommittee reviews the current state of pipeline 
safety, there are a few points I would like to emphasize. 
First, there is a growing recognition that the oil pipeline 
infrastructure is critical to the American economy. We are 
committed to improving pipeline safety while ensuring that 
essential energy supplies can be delivered to that 
infrastructure.
    Second, there has been tremendous progress in pipeline 
safety because of the PSIA.
    Third, many of the initiatives of the PSIA are being 
implemented in a more than satisfactory manner, an honor ahead 
of schedule. However, one important initiative, pipeline repair 
permit streamlining, progress has been disappointing.
    Finally, the Department of Transportation is considering a 
new organizational structure for the pipeline safety program. 
We urge the subcommittee to insist that any changes made to the 
program improve the program and enhance its effectiveness.
    Let me briefly address each of these points in turn. One-
half of total U.S. energy supply comes from petroleum, with 95 
percent of the energy that powers transportation derived from 
petroleum.
    Pipelines are the only reasonable way to supply large 
quantities of petroleum to most of the Nation's consuming 
regions. For example, two-thirds of the ton miles of domestic 
petroleum transportation are provided by pipelines. Pipelines 
do so efficiently and cost-effectively, typically at 2 to 3 
cents per gallon for the pipeline transportation cost charge to 
deliver petroleum to any part of the U.S.
    Oil pipelines are common carriers whose interstate rates 
are controlled by the Federal Energy Regulatory Commission, an 
agency under the jurisdiction of this subcommittee. Pipelines' 
business activities are generally limited to transportation and 
storage services. We don't own or profit from the sale of the 
fuels that we transport.
    The oil pipeline infrastructure is crucial to the American 
energy supply and the stewardship of this critical National 
asset is the joint responsibility of the industry I represent, 
the DOT, and Congress. Oil pipeline operators have been subject 
to the OPS integrity management regulations since March 2001, 
before enactment of the PSIA.
    Our members will complete the required baseline testing of 
the first 50 percent highest risk segments of our systems prior 
to September 30 this year. OPS has inspected each of these 
operators under these regulations at least twice, an initial 
quick hit inspection and a subsequent full inspection, in this 
proceeding with the second round of full inspections.
    I would like to share some of our industry's experience 
with OPS programs. I believe it will be instructive to the 
subcommittee in its review.
    The oil pipeline integrity management program is generating 
safety benefits that significantly exceed anything anticipated 
when the program was designed. Let me explain in a little bit 
more detail.
    In 2002, OPS estimated that approximately 22 percent of the 
pipeline segments in the National oil pipeline network could 
affect a high-consequence area and, therefore, that operators 
in the aggregate would be required to test and protect 22 
percent of the National system.
    When the oil pipeline operators analyzed the high-
consequence areas, we actually identified that we would have 
about twice as many segments. Forty-three percent of the 
pipeline network Nationally could affect an HCA. So the 
anticipated benefits appear to be twice as large as originally 
estimated, but, in fact, the benefits will actually be 
significantly larger than that.
    Because of the way we do internal inspections, it is 
estimated that we are actually going to be inspecting 82 
percent of the oil pipeline infrastructure, a much more 
significant number than 22 percent.
    Another important factor is that repairs being made exceed 
regulatory requirements. Operators are finding and repairing 
many conditions in need of repair and many less serious 
conditions that are found near defects.
    For every condition repaired under the rule, approximately 
six other conditions are excavated and evaluated. Operators are 
fixing what they find, often going beyond requirements of the 
law.
    Industry is stepping up to the significant cost burden 
resulting from these programs. The benefits derived from the 
integrity management rule are much greater than originally 
estimated, but so are the costs. Costs per operator are often 
running at a rate of tens of millions of dollars per year, far 
more than originally anticipated. Operators have, nevertheless, 
moved aggressively to provide the resources needed to implement 
their integrity management programs.
    By the way, flexible economic regulation of liquid 
pipelines by FERC has played an important role in providing the 
resources needed for public safety. And we urge this 
subcommittee in its oversight of FERC to ensure that liquid 
pipeline rate policies continue to allow strong support of 
pipeline safety.
    Our program is not a prescriptive program. It's a mandatory 
program. The operator does have flexible under the program in 
designing and administering the plan for testing and repair 
subject to only periodic inspection reviews by OPS.
    This partnership is proving enormously successful without 
prescriptive regulations, intrusive second-guessing of operator 
decisions, or aggressive enforcement with fines and penalties. 
The integrity management program is successful without 
restoring to the threat of punishment or the need for financial 
incentives because the program aligns the interests of the 
operator and the regulator to adopt the most effective and 
efficient preventive measures to keep the oil in the pipe.
    Put simply, our industry's substantial investment in 
pipeline integrity and leak prevention is a sound one, 
providing long-term benefits to both pipeline operators and the 
public.
    I just want to make a brief point supporting----
    Mr. Shimkus. I hope you are close.
    Mr. Pearl. Yes. I will just say that my written testimony 
pretty much is consistent with some of the points already made 
with respect to repair permit streamlining and the 
reorganization of DOT. And in the interest of time, I will stop 
right here.
    [The prepared statement of Barry Pearl follows:]

Prepared Statement of Barry Pearl, President and CEO, TEPPCO Partners, 
   L.P. on Behalf of the Association Oil Pipe Lines and the American 
                          Petroleum Institute

                              INTRODUCTION

    I am Barry Pearl, President and CEO of TEPPCO Partners, LP and 
Chairman of the Association of Oil Pipe Lines (AOPL). I am here to 
speak on behalf of AOPL and the pipeline members of the American 
Petroleum Institute (API). I appreciate this opportunity to appear 
before the Subcommittee today on behalf of the AOPL and API.
    AOPL is an unincorporated trade association representing 50 
interstate common carrier oil pipeline companies. AOPL members carry 
nearly 85% of the crude oil and refined petroleum products moved by 
pipeline in the United States. API represents over 400 companies 
involved in all aspects of the oil and natural gas industry, including 
exploration, production, transportation, refining and marketing. 
Together, these two organizations represent the vast majority of the 
U.S. pipeline transporters of petroleum products.
    TEPPCO Partners, L.P. is a publicly traded master limited 
partnership, listed on the New York Stock exchange under the symbol 
TPP. TEPPCO owns and operates more than 11,600 miles of pipeline in 
over 16 states. Our operations include one of the largest common 
carrier pipelines of refined petroleum products and liquefied petroleum 
gases in the United States; petrochemical and natural gas liquid 
pipelines; crude oil transportation, storage, gathering and marketing 
activities; and natural gas gathering systems. TEPPCO also owns 50% 
interests in Seaway Crude Pipeline Company, Centennial Pipeline LLC, 
and Mont Belvieu Storage Partners, L.P., and an undivided ownership 
interest in the Basin Pipeline. Texas Eastern Products Pipeline 
Company, LLC, an indirect wholly owned subsidiary of Duke Energy Field 
Services, LLC, is the general partner of TEPPCO Partners, L.P.

                                SUMMARY

    It has been a year and a half since the enactment of the Pipeline 
Safety Improvement Act of 2002 (Public Law 107-355, the ``PSIA''). On 
behalf of the members of AOPL and API, I wish to thank the Members of 
this Subcommittee for their leadership in passing that comprehensive 
and very important legislation.
    As the Subcommittee reviews the current state of pipeline safety 
and the progress that has been made since the PSIA became effective, 
there are a few points that we would like to emphasize.

 First, there is a growing recognition of the importance of the oil 
        pipeline infrastructure to the American economy and the 
        interrelations between pipeline safety, pipeline economic 
        regulation and the essential energy supplies delivered through 
        that infrastructure.
 Second, there has been tremendous progress in pipeline safety because 
        of the PSIA, but there has also been much progress because of 
        actions undertaken by the industry and by the Office of 
        Pipeline Safety, even before the PSIA was signed into law.
 Third, while many of the initiatives of the PSIA are being 
        implemented in a satisfactory manner and on schedule, this is 
        not universally the case. Congress's help is needed in ensuring 
        that pipeline operators can obtain the permits required to 
        carry out the repairs envisioned in the PSIA.
 The Department of Transportation is considering a reorganization that 
        would affect the pipeline safety program. Any new 
        organizational structure for the program should preserve the 
        progress that has been made in elevating the importance of 
        pipeline safety and empowering the federal role in ensuring the 
        operation of an effective pipeline infrastructure.

               THE ROLE OF PIPELINES IN PETROLEUM SUPPLY

    About one-half of total U.S. energy supply comes from petroleum, 
with 95% of the energy that powers transportation derived from 
petroleum. Very few of the elements of the Nation's transportation 
system could operate without petroleum. Fully two-thirds of the ton-
miles of domestic petroleum transportation are provided by pipeline. 
The total amount delivered by both crude oil and refined petroleum 
products pipelines is nearly twice the number of barrels of petroleum 
(14 billion) consumed annually in the United States.
    The major alternatives to pipelines for delivery of petroleum are 
tank ship and barge, which require that the user be located adjacent to 
navigable water, and truck or rail, which are limited in very practical 
ways in the volume they can transport. In fact, pipelines are the only 
reasonable way to supply large quantities of petroleum to most of the 
nation's consuming regions. Pipelines do so efficiently and cost-
effectively--typically at 2-3 cents per gallon for the pipeline 
transportation cost charged to deliver petroleum to any part of the 
United States.
    Oil pipelines are common carriers whose rates are controlled by the 
Federal Energy Regulatory Commission. Pipelines only provide 
transportation. Our owners do not own or profit from the sale of the 
fuels they transport. Oil pipeline rates are not related to the price 
of the products that are transported. Oil pipelines move 17% of 
interstate ton-miles but only receive 2% of the total amount charged 
for interstate freight transportation, a bargain that American 
consumers have enjoyed for decades.
    The oil pipeline infrastructure is crucial to American energy 
supply. The care and stewardship of this critical national asset is an 
appropriate public policy concern and an important joint responsibility 
of the industry I represent, the Department of Transportation and 
Congress.
    I've included a report by Richard A. Rabinow entitled ``The Liquid 
Pipeline Industry in the U.S.--Where It's Been and Where It's Going' 
prepared for AOPL that provides an overview of trends in the oil 
pipeline industry.
        progress report on pipeline safety: integrity management
    Companies represented by AOPL and API operate 85 percent of the 
nation's oil pipeline infrastructure. Since March 2001, these operators 
have been subject to a mandatory federal pipeline safety integrity 
management rule (Title 49, section 95.452) administered by the 
Department of Transportation's Office of Pipeline Safety. The oil 
pipeline industry's experience with pipeline integrity management 
preceded the enactment of the Pipeline Safety Improvement Act of 2002. 
Our operators will complete the required 50 percent of their baseline 
testing of the highest risk segments prior to the September 30, 2004 
midpoint deadline set by the integrity management regulations. OPS has 
inspected the performance of each of these operators under these 
regulations at least twice--an initial ``quick hit' inspection and a 
subsequent full inspection--and is proceeding with the second round of 
full integrity inspections. We have experience with the program that 
will be instructive to the Subcommittee in its review.
    The oil pipeline integrity management program is generating safety 
benefits that significantly exceed anything anticipated when the 
program was designed. To see how this is occurring, it is helpful to 
have a general understanding of how the integrity management program 
operates. The integrity management program requires integrity 
assessment, that is, regular safety testing with an internal inspection 
device (a--smart pig''), hydrostatic pressure or other equivalent 
means, and enhanced protections for those segments of pipe that ``could 
affect' a ``high consequence area.'' A ``high consequence area'' (HCA) 
is a defined term in the regulations that means a commercially 
navigable waterway, a high population area or an area unusually 
sensitive to environmental damage. Such unusually sensitive areas are 
also defined in the regulations. Each operator must have a process to 
determine whether a segment of pipe ``could affect' an HCA. The process 
must consider a range of factors, such as the terrain, the volume and 
type of oil in the pipe and the physical ways oil released from the 
segment of pipe might impact the HCA.
    In 2000, OPS estimated that under the proposed integrity management 
system approximately 22 percent of the pipeline segments in the 
national oil pipeline network could affect an HCA and therefore that 
operators in aggregate would be required to assess and provide enhanced 
protection for 22 percent of the national system. In fact, when oil 
pipeline operators carried out their analyses of how many of their 
segments could affect the high consequence areas that were actually 
identified under the regulations, it turned out that almost twice as 
many segments, 43 percent of the pipeline network nationally, could 
affect an HCA. So the anticipated benefits in theory were nearly twice 
as large as originally estimated.
    But in fact, our experience indicates that the actual benefits 
realized will be significantly larger than that. The predominant method 
of testing oil pipelines utilizes internal inspection devices. The 
ports at which these devices are inserted into and removed from a 
pipeline are fixed in the system. These locations were established 
prior to the advent of integrity management regulations and without 
regard for the location of HCAs. The internal inspection devices 
therefore travel between ports, generating information about all the 
segments between those ports, whether they affect an HCA or not. As a 
result, as shown in OPS inspections of operators' plans, it is 
estimated that integrity testing will cover approximately 82 percent of 
the nations' oil pipeline infrastructure. Thus the actual mileage 
tested is almost four times the original OPS estimate.
    Operators are finding and repairing many conditions in need of 
repair and many less serious conditions that are found near defects. 
For every condition repaired under the rule, approximately six other 
conditions are excavated and evaluated. Operators are fixing what they 
find, often going beyond the requirements of the law. The largest cost 
to the operator is in the scheduling and renting of the internal 
inspection device, obtaining the permits and carrying out the 
excavation, so once the pipeline is uncovered, operators fix many 
conditions that might never have failed in the lifetime of the 
pipeline. This result is a huge additional benefit to pipeline safety 
that will reduce the risk of pipelines to the public far into the 
future.
    Although benefits from the integrity management rule are much 
greater than originally estimated, so is the cost. Costs per operator 
are often running at a rate of tens of millions of dollars per year, 
far more than originally anticipated and a substantial amount by any 
standard. Operators have nevertheless moved aggressively to provide the 
resources needed to implement integrity management.

                    INTEGRITY MANAGEMENT CONCLUSIONS

    What are the lessons of this experience?
    OPS's integrity management program, which relies on the initiative, 
judgment and priorities of individual pipeline operators, is producing 
major benefits for the public and the environment without prescriptive 
regulation. The program is a mandatory one, so operators must 
participate, must carry out regular testing of their pipelines and must 
act promptly to address risks. But the operator has flexibility under 
the program in designing and administering the plan for testing and 
repair subject only to periodic inspection reviews by OPS. This 
partnership is proving enormously successful without resort to 
prescriptive, detailed regulations, intrusive second-guessing of 
operator decisions or aggressive enforcement with fines and penalties. 
It is important to note that operators have been incurring the costs 
required to find the conditions that need repair, to make the repairs 
and to protect the lines for the future without specific assurance that 
these costs will be covered in the rates allowed by the Federal Energy 
Regulatory Commission. The integrity management program has been 
successful without resort to the threat of punishment or the need for 
financial incentives because the program aligns the interests of the 
operator and the regulator--to adopt the most effective and efficient 
preventative measures to keep the oil in the pipe. The recent spill and 
accident record of the pipeline industry (see charts) only underlines 
this success. Put simply, our industry's substantial investment in 
pipeline integrity and leak prevention is a sound one, providing long-
term benefits to both pipeline operators and the public.
 pipeline safety: the pipeline safety improvement act of 2002 and more
    In the Pipeline Safety Improvement Act of 2002 Congress endorsed 
the integrity management approach to pipeline safety that OPS had been 
administering with the oil pipeline industry at the time of enactment 
and extended the integrity management concept to natural gas 
transmission pipelines. In addition, the PSIA contains important 
provisions:

 Coordinating permitting by federal agencies so that pipeline repairs 
        can be carried out in a timely manner
 Strengthening the qualifications of pipeline personnel and 
        contractors;
 Ensuring that pipeline operators are active in promoting public 
        awareness of pipelines along pipeline rights of way
 Increasing OPS outreach to states and state regulators to assist with 
        OPS activities
 Authorizing a promising research and development program to develop 
        better pipeline safety technology
 Establishing a nationwide, toll-free three-digit telephone number to 
        connect excavators to their local call-before-you-dig, one-call 
        notification center
 Supporting a study of pipeline right of way encroachment issues 
        through the Transportation Research Board of the National 
        Academies of Science and Engineering
 Authorizing adequate funding for the operation of the Office of 
        Pipeline Safety
    In our view, the OPS has been very aggressive in seeking to 
implement these PSIA provisions and, with one exception that I will 
mention below, the progress achieved has been excellent. In addition, 
OPS has been responding to and satisfactorily addressing Congressional 
mandates from the time before the PSIA and outstanding National 
Transportation Safety Board, General Accounting Office and DOT 
Inspector General safety recommendations. Here the progress has been 
truly impressive. We anticipate that by the end of 2004 nearly all 
outstanding mandates and recommendations to the agency will have been 
appropriately addressed. Finally, OPS has been playing a very important 
role in assisting the pipeline industry and the Department of Homeland 
Security in developing a security program to protect critical pipeline 
infrastructure.

                  PIPELINE REPAIR PERMIT STREAMLINING

    An important initiative of the PSIA that needs the Subcommittee's 
encouragement and oversight is the implementation of section 16, 
``Coordination of Environmental Reviews', which is concerned with 
expediting the repair of pipeline defects. Some limited progress has 
been made on implementing this section, but the largest portion of the 
work remains to be done, and the deadlines for agency action under the 
provision have passed.
    Under section 16, a federal Interagency Committee on Coordination 
of Environmental Reviews for Pipeline Repair Projects has completed a 
Memorandum of Understanding that lays the foundation for a federal 
pipeline repair permit streamlining process, but this MOU does not 
actually contain the provisions needed to effectuate the streamlining. 
Rather, it establishes a Working Group of federal agency personnel to 
develop a joint regulatory approach to streamlining (which may rely on 
existing regulations of the participating agencies or may recommend 
changes to certain regulations). A successful federal streamlining 
process will help with federal permitting and also provide a model for 
state and local permitting agencies to follow. Congressional hearings 
in June helped highlight the need for pipeline repair permit 
streamlining. I am happy to report that, since those hearings, 
representatives of liquid pipeline operators with experience in 
permitting pipeline repairs have been able to meet with the Working 
Group under the auspices of the White House Task Force on Energy 
Project Streamlining. We welcome the opportunity to provide 
information, observations and suggestions to the Working Group as it 
considers how to implement the goals of the MOU. We urge the 
Subcommittee to monitor the progress of the Working Group to ensure 
that progress continues.
    A central theme of the PSIA is safety through prevention. The 
purpose of section 16 is to accelerate actions that prevent pipeline 
releases. OPS requires pipeline operators to investigate the condition 
of their pipelines on a regular basis and act within a time certain to 
repair any defects discovered that are judged to require repair. The 
more severe the defect, the shorter the timeframe required to make the 
repair. Pipeline repair will typically involve an excavation to uncover 
the buried pipe at the location of the defect on the pipeline right of 
way, and any such excavation in general requires a series of permits, 
some federal, some local, and most designed to protect the environment. 
The purpose of section 16 is to ensure that federal agencies involved 
in permitting for such excavations coordinate so that pipeline 
operators are allowed to make the repairs that are needed in the 
timeframes required by the regulations. The coordination envisioned 
would not affect existing environmental law, but might require some 
adjustments to the existing regulations of some of the environmental 
permitting agencies.
    The goal of section 16 is to see that the priority on pipeline 
safety set by this Subcommittee and, through this Subcommittee, by the 
Congress as a whole is implemented and is not frustrated because, 
although defects are discovered in a timely fashion to prevent 
releases, the permitting delays block carrying out the repairs needed 
to effectuate this prevention. The purpose of section 16 is to ensure 
timely actions required by one federal agency, OPS, in the name of 
pipeline safety are not blocked by one or more other federal agencies 
that do not have pipeline safety as a priority.
    Pipeline repair permitting delays can also have an impact on energy 
supply. When a pipeline defect cannot be repaired within the time 
limits set by OPS, the pipeline operator must reduce pipeline pressure, 
and therefore throughput, by an amount that depends on the suspected 
seriousness of the defect--a greater reduction for defects that are 
more likely to be severe, but the reduction is typically at least 20%. 
Many operators reduce pressure on discovery of a potential defect. Once 
the repair is complete the operator is allowed to return to normal 
throughput capacity.

THE NUMBER OF PIPELINE EXCAVATIONS IS LARGE NOW AND WILL BE MUCH LARGER 
                             IN THE FUTURE

    Under OPS rules for oil pipeline operators, tens of thousands of 
potential defects are being discovered and repaired annually. As of 
December 31, 2003, the largest 47 oil pipeline operators have undergone 
inspection by OPS covering 97% of the mileage operated by these 
companies. These are the operators who eventually plan to include 
approximately 82% of their mileage in the mandatory testing program, 
even though strict requirements of the regulation would only require 
43% of their mileage to be tested. According to OPS data as of the date 
of their respective first full inspections, these operators had carried 
out 4,344 time-sensitive repairs and 16,081 other repairs. Time 
sensitive repairs are those judged potentially serious enough that OPS 
regulations stipulate a repair deadline. These numbers underestimate 
the total volume of repairs prior to December 31, 2003 because they 
only include the repairs completed prior to each operator's particular 
inspection date, all of which occurred before December 31, 2003.
    Completion of over 4,000 time-sensitive repairs is a success story 
of sorts, but it is not without some impact on the capacity of the 
Nation's petroleum delivery system. Many of those repairs required 
pipeline pressure reductions until the repairs were completed. When a 
pipeline system operates at lowered pressure, its capacity is often 
reduced, increasing the likelihood of supply shortages, which generally 
puts upward pressure on petroleum prices. We do not know the extent to 
which the Nation's current oil pipeline capacity has been reduced 
because of pressure reductions occasioned by repairs.
    There is also no assurance that the required federal, state and 
local permits for pipeline repair activity can be obtained in a timely 
way even when federal regulations set a clear deadline for completion 
of the repair. In the absence of full implementation of section 16 
there is currently no organized process to streamline the pipeline 
repair permitting process to ensure that all involved are doing what 
they can to see that the Nation's fuel supply system is not limited by 
capacity restrictions. It seems to us that it would be prudent to put 
such a process in place, as the PSIA wisely requires.
    We have been asked to forecast the magnitude of the permitting 
problems the pipeline industry will face in complying with OPS pipeline 
integrity management rules. We will try to respond. The oil pipeline 
integrity management regulations have been in effect since 2001, so our 
industry has some experience that can be used to try to answer this 
question.
    One thing is clear: the ``where' and ``when' associated with 
complex permitting problems is inherently uncertain. It depends on 
where the apparent defects show up in testing, and that cannot be known 
in advance. While the industry has much experience with pipeline 
repairs that predates the pipeline integrity regulations, the sheer 
number of tests and repairs being executed and the existence of 
mandatory federal time deadlines for completing particular repairs are 
unprecedented in the industry. We are learning as we go along.
    An anecdote: a pipeline operator recently completed an internal 
inspection of a segment of pipe that produced approximately 100 
potential repairs that under OPS rules appear to require completion in 
180 days. The operator estimates that more than half of the required 
excavations for repair can be carried out routinely and another 40 can 
be carried out with the use of an Army Corps of Engineers Nationwide 
Permit. However, there are 3-5 excavations needed in locations that 
that will be difficult to permit in a timely manner, which may result 
in the operator being unable to complete the repairs within the 
required regulatory deadline. So a large number of repairs will be made 
without special permitting concerns and a significant number of 
additional repairs can probably be made because of a pre-existing 
federal permit-streamlining program. However, this entire pipeline 
segment may nevertheless be required to operate at reduced pressure 
because of a few situations for which there is no process in place to 
ensure the operator can obtain the necessary federal permits that will 
meet the federal repair deadline.
    The burden on federal, state and local permitting agencies will 
increase as the OPS program of integrity management for natural gas 
transmission pipelines takes hold and as state integrity management 
programs for intrastate pipelines that mimic the federal program are 
implemented.

         RECOMMENDATIONS ON PIPELINE REPAIR PERMIT STREAMLINING

    The pipeline industry has several recommendations that we believe 
would foster progress towards effective pipeline repair permit 
streamlining:

 Agree to allow representatives of the pipeline industry who are 
        experts in pipeline repair permitting to continue to meet with 
        the Working Group to serve as a resource in providing 
        information about what is likely to be useful in expediting 
        pipeline repairs.
 Work with industry to develop a set of pre-approved pipeline repair 
        site access, use and restoration Best Management Practices such 
        that a commitment by an operator to adhere in good faith to 
        such BMPs would result in expedited permission to access repair 
        sites to carry out the repair from any of the signatory 
        agencies either through use of that agency's emergency 
        procedures or another approach that allows the repair to be 
        completed within the timeframes specified by DOT regulation.
 Commitment to use pre approved BMPs should result in a presumption of 
        compliance by the operator with the requirements of the BMPs 
        and a presumption that actions beyond restoration to pre-
        construction condition will not be required if BMPs are 
        followed.
 BMPs should be habitat-specific rather than species-specific so that 
        multiple species protection can be obtained within a single 
        umbrella BMP.
 Coordinate multi-agency response to requests for permits such that 
        involved agencies operate in parallel or in concert to issue 
        all required permissions (not just that of certain agencies) to 
        the operator in a timely fashion to allow the repair to be 
        completed within the timeframes specified by DOT regulation. To 
        the extent possible the permitting process should be 
        consolidated to limit to one the number of permits required (a 
        consolidated permit). A process is needed to ensure that 
        federal agencies are aware of the relationships in permitting 
        pipeline repairs among federal, state and local requirements 
        and can act accordingly to achieve the goal of section 16.
 With respect to compliance with the Endangered Species Act, establish 
        an agreement between the Department of Transportation and the 
        Department of the Interior under which DOT will voluntarily 
        assume the role of default coordinator, or a ``nexus' by any 
        other name, for pipeline repairs in those cases where no other 
        federal agency is available or able to act as the federal nexus 
        for ESA consultation. This agreement would stipulate that DOT's 
        voluntary participation in a coordination role for pipeline 
        repairs does not mean that ordering or providing for pipeline 
        repairs through regulation is a federal action subject to the 
        ESA or the National Environmental Policy Act.
    The federal government and the pipeline industry should be natural 
partners in seeing that the OPS integrity management program succeeds. 
The pipeline safety goals of the industry and the government are 
entirely aligned in this program. Done properly, pipeline repair permit 
streamlining will help significantly to ensure the success of this 
program, while reducing the burden on federal, state and local 
permitting agencies and allowing these agencies to focus resources on 
much more serious environmental problems. Done properly, pipeline 
repair permit streamlining will ensure the safety and reliability of 
the nation's pipeline infrastructure. Done properly, pipeline repair 
permit streamlining will reduce the risk of higher fuel prices to the 
Nation's consumers.
    The oil pipeline industry stands ready to work with the Interagency 
Committee and the Working Group to provide the information and any 
other assistance needed to carry out the intent of section 16 of the 
PSIA.

                    ORGANIZATION FOR PIPELINE SAFETY

    In December 2003 we were informed that the Department of 
Transportation intended to propose a reorganization as a part of the FY 
2005 budget. As part of this proposal, the Research and Special 
Programs Administration, which houses the Office of Pipeline Safety, 
would be abolished and reinvented as the Research and Technology 
Innovation Administration, an entity built around the Department's 
Volpe Research Center and devoted to transportation research and 
development. As a consequence, the Office of Pipeline Safety (and other 
``special programs' in the former RSPA) would be left without a home in 
the Department. The Secretary's proposed solution for the OPS would be 
to transfer the pipeline safety program to the Federal Railroad 
Administration, an existing DOT administration governing a mode judged 
to be most similar to pipelines.
    The oil pipeline industry and the members of AOPL and API have 
great appreciation for all that has been done to improve the programs 
of the Department of Transportation, including the pipeline safety 
program. However, our members' reaction to the proposal to place the 
pipeline safety program under the Federal Railroad Administration was 
uniformly negative.
    There has been a sea change in pipeline safety in the last several 
years, and the federal pipeline safety program has gained impressive 
and much-needed momentum. The quality and credibility of the program 
administered by the Office of Pipeline Safety has been immeasurably 
strengthened, and this strengthening is both recognized and augmented 
by Congress' unanimous enactment of the PSIA. OPS's successes have been 
accomplished through the hard work and creativity of its employees and 
particularly because of its very effective leadership during this 
period. We feel very strongly that this progress must continue. We have 
come a long way in pipeline safety, but we still have much further to 
go.
    We believe the proposal to place OPS in the FRA, if implemented, 
would inevitably disrupt the momentum OPS has worked so hard to create 
in the past several years. The period required to re-establish this 
momentum can't be known for sure, but we believe it would be measured 
in years, not months. This would be much more than a loss for OPS. It 
would be a loss for Congress, the public and for pipeline safety.

                                HR 4277

    We were very pleased to see the introduction by the Chairman of the 
House Transportation and Infrastructure Committee, Rep. Don Young (R-
AK), of H.R. 4277, the Pipeline Safety Administration Establishment 
Act. This legislation would establish an independent pipeline safety 
administration with the Department of Transportation with minimal 
disruption of OPS activities.
    Our support for the legislation is based first of all on its 
merits. As I have testified, we believe the federal pipeline safety 
program has become much stronger and more effective in recent years and 
the importance of the program and the infrastructure it oversees has 
received greater recognition than in the past. The federal pipeline 
safety program deserves greater organizational recognition in the 
Department that befits its importance to the Nation.
    We also welcome Chairman Young's initiative in introducing H.R. 
4277 because it provides a significant alternative to the proposal to 
place the pipeline safety under the Federal Railroad Administration. 
The five associations that represent the Nations' oil and natural gas 
pipelines recently expressed our views on H.R. 4277 and the proposal in 
a joint letter to Chairman Young. I have provided a copy of that letter 
for the Subcommittee's records. We are encouraged by signs that the DOT 
may be reconsidering its plans for the pipeline safety program under 
any reorganization of the Department. We urge Congress to fully 
participate in deliberations about the future organization for this 
program.
    The tests for any new organizational structure for the federal 
pipeline safety program are whether it strengthens the program, whether 
it helps make the program more effective and credible and whether it 
will further the hard work ahead to continue the progress the program 
has made. We plan to judge any proposal for structuring the pipeline 
safety program based on these tests.
    The oil pipeline industry supports competent, effective, and 
credible federal pipeline safety regulation. The nature of the 
commodities carried in oil pipelines and the level of public confidence 
pipeline operators are able to inspire mean some level of oversight is 
inevitable. Public confidence in the safety of pipelines, and our 
ability to continue to operate pipelines with the public's trust 
depends on the perception and the reality of competent oversight. The 
interstate character of the pipeline business and, indeed, the 
interstate character of the pipeline facilities themselves, require 
that the federal government have the primary responsibility for this 
oversight. We therefore strongly believe that pipeline safety oversight 
should be housed in the U.S. Department of Transportation. If the 
structure governing the pipeline safety program within DOT has to 
change, we would urge Congress to very carefully consider the impact of 
the change on stature of the program and the implications for the 
highly important service pipelines provide to the Nation.
    The PSIA set an ambitious but highly appropriate course for the 
federal pipeline safety program. H.R. 4277 opens the dialogue on the 
proper organizational structure to complement and facilitate the 
success of that program. The pipeline members of AOPL and API look 
forward to working with Congress as this dialogue moves ahead.

                               CONCLUSION

    Thank you for the opportunity to testify before the Subcommittee on 
these important matters. Congress's work product, the PSIA, is in our 
view a significant success, but all those interested in pipeline safety 
have much work ahead of us if we are to fully achieve the purposes of 
this very important legislation. Our industry pledges to seek alignment 
with the OPS to the maximum extent practicable in this important task.
    We need help from Congress to ensure that a key section of the 
legislation, section 16, relating to pipeline repair permit 
streamlining, achieves the full intent of Congress and is effective in 
fostering a safer and more reliable pipeline infrastructure. We also 
ask that the Congress carefully consider the issue of the proper 
organizational structure within the Department of Transportation for 
the federal pipeline safety program, an issue that has been raised by 
the proposed reorganization of the Department and by the legislation 
introduced by Chairman Young.
    Thank you very much.
                                 ______
                                 
                                                       May 20, 2004
The Honorable Don Young
Chairman
Committee on Transportation and Infrastructure
U.S. House of Representatives
Washington, DC 20515
    Dear Chairman Young: On behalf of the natural gas and petroleum 
pipeline industries, we want to thank you for introducing H.R. 4277, 
the ``Pipeline Safety Administration Establishment Act.'' We believe 
this legislation helps ensure the continued improvement and 
effectiveness of the Office of Pipeline Safety (OPS) within the 
Department of Transportation (DOT).
    The members of our associations are united in our concern about the 
ramifications of DOT's draft reorganization plan announced by Secretary 
Mineta in December of 2003. While the announcement focused on the 
benefits of organizing DOT's research and development functions within 
a single administration, the secretary also proposed merging the 
Federal Railroad Administration (FRA) and OPS. We believe this merger 
would be detrimental to the mission and the performance of OPS. 
Therefore, we oppose such a merger.
    The Office of Pipeline Safety has made great strides in improving 
its effectiveness over the last five years. It has successfully 
completed a number of critical rulemakings, including ones regarding 
hazardous liquid and natural gas pipeline integrity. OPS also has made 
outstanding progress both in fulfilling its Congressional mandates and 
in implementing DOT Inspector General and National Transportation 
Safety Board recommendations. OPS is not broken by any measure, and 
that is why we are concerned about the implications of DOT's proposed 
reorganization.
    Your legislation gives OPS the autonomy and accountability it needs 
to fulfill its mandate to protect the public. If DOT attempts to 
proceed with a reorganization plan that includes merging OPS with FRA, 
we strongly encourage your committee to hold a hearing that will allow 
for a full and open discussion among all stakeholders.
    We support your efforts to strengthen the Department of 
Transportation's pipeline safety program and look forward to working 
with you in that regard. Thank you once again for introducing H.R. 
4277. If there is anything further we can do to assist you in your 
efforts, please do not hesitate to contact us.
            Sincerely,
                                                Red Cavaney
                    President and CEO, American Petroleum Institute
                                         Benjamin S. Cooper
                     Executive Director, Association Oil Pipe Lines
                                               Bert Kalisch
                 President and CEO, American Public Gas Association
                                              David Parker,
                        President and CEO, American Gas Association
                                       Donald F. Santa, Jr.
           President, Interstate Natural Gas Association of America
                                 ______
                                 
                 PIPELINE INTEGRITY MANAGEMENT PROGRAM
         CASE STUDY SUPPORTING A STREAMLINED PERMITTING PROCESS

    Project Overview: A crude oil pipeline comes from offshore 
Louisiana through environmentally sensitive areas of Breton Sound into 
a terminal on the Mississippi River. The majority of the line runs off-
shore in Federal and State Waters. The permitting process is completed 
through either the MMS for federal water, or the Louisiana Department 
of Natural Resources--Coastal Management Division (CMD) for State 
waters/land.
    This permitting was fairly straightforward. The Original Corps of 
Engineers permit maintenance clause allowed us to do most of the work 
without having to consult other agencies. For those locations that were 
not covered, the permitting needed to follow the normal process which 
took seven months, much of this was the operators pre-work required for 
offshore repairs. Also, the LDWF required an oyster assessment.
    Permitting Overview: The ``smart pig'' inspection identified 
several locations that needed to be repaired under the PIM rule. 
Pipeline operating pressure was reduced to allow additional time to 
complete the repairs. It is very difficult to do work off-shore 
``immediately'' because of the availability of off shore equipment 
necessary to make repairs Most of the sites used the existing Corps of 
Engineers permit that included a maintenance clause to do the work. The 
Corps of Engineers and CMD recognize the maintenance clause as a valid 
permit. However, one site was in the marsh/land and needed to be fully 
permitted through the CMD. Below is the timeframe that occurred for the
    Coastal Zone permitting:

 1/6/2003--Immediate repair discovery date
 1/8/2002--Reduced pipeline operating pressure
 5/14/2003--Submitted application packages to federal, state and local 
        environmental regulatory agencies. This took time due to the 
        evaluation of offshore repair options, locating the anomalies 
        and the pre-application work that needed to be completed.
 6/11/2003--Oyster Assessment received from assessor
 6/13/2003--Approval received from LDWF for work in oyster seed 
        grounds
 7/2/2003--Final permit letter received. Application sent to 
        Plaquemines Parish for approval
 7/25/2003--Final Parish permit received
    In addition, an oyster assessment was required for the work that 
was done in Breton Sound. Breton Sound is a State protected oyster seed 
ground. Prior to any work being done, the assessment had to be 
completed, and reviewed by Louisiana Department of Wildlife and 
Fisheries (LDWF)

                 PIPELINE INTEGRITY MANAGEMENT PROGRAM
         CASE STUDY SUPPORTING A STREAMLINED PERMITTING PROCESS

    Project Overview: In California, a pipeline company operates a 
refined petroleum products pipeline system that traverses 
environmentally sensitive habitat including freshwater and saltwater 
wetlands, tidally influenced marshland, and habitat supporting several 
federally- and state-listed plant and animal species. The permitting 
process is complicated by various work windows that prevent or limit 
maintenance activities during specific times of the year along the 
pipeline right-of-way (e.g., seasonal flooding conditions, breeding and 
nesting seasons for listed species, etc.).
    This project required a pressure reduction on a branch of the 
pipeline for nine months due to both Federal and State permitting 
requirements. As stated below though, we were fortunate to be able to 
obtain the permits within nine months and to make the repairs within 
the time windows allotted for the refuge and for the nesting periods. 
We have added expensive drag-reducing agent to the pipeline to attempt 
to meet shipping requirements and have had to limit throughputs in the 
summer months due to the lower pressure.
    A major concern is that the main, trunk line of this pipeline is 
due for a smart pig run this month. The majority of this pipeline also 
runs through major Federal and State endangered species areas. A 
pressure reduction on that section of pipeline could cause serious 
consequences to the gasoline supply.
    Permitting Overview: A recent pipeline ``smart pig'' inspection 
survey identified 2 pipe anomalies that required repair within 60-days 
and triggered agency consultation and permitting due to their locations 
in sensitive habitats. Once discovery was declared on August 6th, 2003 
and we realized that this permitting effort needed to be undertaken we 
reduced the pressure in the pipeline. This permitting effort, which 
took approximately nine months to complete, has recently been concluded 
and has thus far included the following federal and state agencies:

 Army Corp of Engineers (ACOE)--San Francisco District;
 California Regional Water Quality Control Board (RWQCB)--San 
        Francisco Bay Region & Central Valley Region;
 U.S. Fish and Wildlife Service (USFWS)--Sacramento Branch;
 California Department of Fish and Game (CDFG); and
 San Francisco Bay Conservation and Development Commission (BCDC).
    As indicated above, consultation with multiple regional branches of 
the same agency has been required for a single project. Applications 
were initially submitted to the Federal agencies in November of 2003 
for the permits. State agencies cannot process permit applications 
until the Federal permits are issued, therefore applications for the 
State Permits were submitted upon receipt of the Federal Permits. We 
were able to expedite the process by asking the Federal agencies to fax 
us the completed permits. We used to the faxed copies to apply to the 
State thereby saving a few days instead of waiting for the mailed 
copies. Following is a comprehensive list of all the permit 
applications submitted:

 2 ACOE Section 404 Pre-construction Notifications under Nationwide 
        Permit 3 and 33;
 2 RWQCB 401 Water Quality Certifications triggered by the 404 
        process;
 2 Endangered Species Act (ESA), Section 7 biological consultations 
        with the USFWS;
 2 CDFG Consistency Determinations for impacts to California Fully 
        Protected Species listed under the California Endangered 
        Species Act (CESA); and
 BCDC permit waiver pursuant to Section 29508 of the Suisan Marsh 
        Preservation Act.
    All agency branches have responded in the standard amount of time 
with the requested permit or waiver. These repairs required a cutout of 
the pipe so to reduce the risk entailed with a pipeline cutout it was 
decided to take on both repairs at the same time.
    One of the repair locations is located within a CDFG State Game 
Refuge. The refuge is on a seasonal schedule of hunting seasons and 
flooding to facilitate waterfowl nesting. The refuge manager has 
provided two construction windows to conduct repairs; a two-week window 
in October and a one-month window in June. The seasons begin with Elk 
hunting from July until September, after which there is about a two-
week repair window, followed by flooding of the entire area to support 
waterfowl hunting. Waterfowl hunting season is followed by waterfowl 
nesting season. After nesting season the ponds are allowed to drain and 
dry. The refuge manager then opens the area up for our repairs again in 
June. Consequently there is a one-month window to complete repairs. All 
permitting agencies explained to us that they could not complete 
permitting in time to meet this 2-week window, therefore a significant 
effort was put into front-end loading to expedite the permit process to 
ensure permitting was completed in time for the second window afforded 
us by the refuge.
    Both repair sites provide habitat for species that are not only 
listed under the ESA, but also under the CESA. For projects that can 
affect species listed under both acts, the USFWS issued BO must be 
submitted to the CDFG for a Consistency Determination. Furthermore, 
some species are listed as fully protected under CESA so no take can be 
authorized by the CDFG. For the two repairs in question, three 
different fully protected species under CESA were involved.
    For the first repair site, surveys for the species of concern, 
California Clapper Rails and Black Rails, yielded no evidence of the 
species. No nests were located and no birds were heard calling during 
the surveys. Therefore, the CDFG concluded that take of these species 
would not occur and consistency was granted.
    However, for the second repair site, CDFG found the BO to be 
inconsistent with CESA. The BO requires that in areas with more than 
50% pickleweed coverage, traps must be set and any Salt Marsh Harvest 
Mouse captured must be relocated. However, the mouse is fully-protected 
under CESA, therefore under California law trapping of the mice is not 
allowed. Through numerous discussions with both agencies and on-site 
inspections a compromise was reached. As long as the repair site did 
not have pickleweed coverage of 50% and we were able to identify an 
access route that avoided areas of 50% pickleweed cover then the repair 
could proceed. Fortunately the repair area was not covered by 50% 
pickleweed, but if the repair been located 300 feet upstream of the 
actual repair we may not have been able to complete the repair as the 
pipeline ROW is completely covered by pickleweed. The pickleweed growth 
prevented us from using the preferred access route as it is the most 
direct route, but we were able to work out an access route allow the 
refuge levees that avoided areas of pickleweed coverage.
    The pipeline repairs have been scheduled and should be completed by 
mid-June, but if the biological surveys of the repair areas had 
indicated presence of the fully protected species we would not have 
been able to complete at least one of the repairs within one year from 
when we dropped pressure. The protected rail's nesting season runs from 
approximately mid-March to mid-August. All BO's are written such that 
if rails are present then work cannot occur until after mid-August. Our 
discovery date was August 6th, so had rails been present we would not 
have been able to conduct the repairs until after the one-year deadline 
passed. In the other case, we are not sure we could have completed the 
repair and still been in compliance with the CESA if the repair site 
had been covered with pickleweed.
    Permitting Timeline for Refuge Repair:

 August 6, 2003--Discovery date and pressure reduction.
 November 30, 2003--Submitted USACE Permit. Permit preparation time 
        included threatened and endangered species identification as 
        well as agency front end loading and consultation.
 December 12, 2003--USACE requested consultation (2 weeks)
 March 2, 2004--Received the USFWS biological opinion (BO) (2-\1/2\ 
        months which is record time). BO gave us authority to trap and 
        move the endangered Salt Marsh Harvest Mouse
 April 21, 2004--Received CA Dept F&G letter disagreeing with USFWS 
        BO. CESA does now allow us to trap and remove the mouse.
 Late May--Received CDFG's ``oral guidance'' for repair due to access 
        and repair site not containing significant amount of mouse 
        habitat.
 June 1, 2004--Mobilized for repair within June 1--July 1 access 
        window.

                 PIPELINE INTEGRITY MANAGEMENT PROGRAM
         CASE STUDY SUPPORTING A STREAMLINED PERMITTING PROCESS

    The Integrity Management Rule requires certain pipeline defects 
repaired within specific timelines. If these timelines cannot be met, a 
20% operating pressure reduction must be taken until the defect is 
repaired or the system is otherwise modified to allow continued safe 
operation. In certain markets, this reduction in operating pressure can 
potentially reduce supply by more than 200,000 barrels per day (nearly 
one million gallons per day) having significant impacts on supply. In 
the fourth quarter of 2003 when distillate demand to the northeast is 
high, a pipeline repair could not be made within the 180-day time frame 
forcing a 20% pressure reduction on the pipeline. Within two weeks it 
became apparent that supplies to New York markets could be jeopardized. 
Numerous reasons attributed to the repair not being completed in the 
180 days. One of which was permitting that eventually took 18 months 
and significant resources to obtain the proper permit for the 
appropriate repair method needed to complete the repair. Acquisition of 
the final permit that provided a practicable repair solution required a 
five month period and involved extensive lobbying of twelve Federal, 
State, and local environmental agencies, the Goverernor's office, and 
other resource stakeholders and interest groups.
    In the meantime, other system changes were made to allow continued 
operation at normal operating pressures. In absence of these solutions, 
shortages in jet fuel to key northeast airports as well as significant 
shortages of heating oil to northeast markets were probable. 
Furthermore, operation of refineries in the Gulf Coast and at least one 
additional pipeline in the northeast would have been impacted.
    Near misses such as the one described above underline the need for 
permit streamlining. Coordination is necessary among pipeline 
operators, federal, state and local permitting agencies and the OPS. 
The Pipeline Safety Improvement Act was meant to protect public safety 
and the environment. Through permit streamlining, the intent of the Act 
and all stakeholders' objectives will be met along with timely repairs 
to pipelines, protection of the environment, and maintaining stability 
in fuel markets.

                 PIPELINE INTEGRITY MANAGEMENT PROGRAM
         CASE STUDY SUPPORTING A STREAMLINED PERMITTING PROCESS

    Early 2002, a deformation with metal loss was identified on a pipe; 
under the IMP rule, this is an immediate condition. The geographical 
location of the pipe is within a large wetland complex and within the 
boundaries of a State Game Area which is managed by the Michigan 
Department of Natural Resources.
    It was determined that this condition met the requirements of a 
Safety Related Condition as stated in 49 CFR 195.55 due to its location 
within an HCA. As such, operating pressure on the system was reduced by 
20% and a SRC Report was filed with OPS five days after discovery.
    Excavation and repair of this condition required a Land and Water 
Management (LWM) Permit which is a joint permitting process between the 
USACE and Michigan DEQ for Clean Water Act Section 404/401 impacts. A 
Special Use Permit was needed from Michigan DNR for working within the 
State Game Area. A Soil and Erosion Control Permit from the Muskegon 
County Department of Public Works was also required.
    The unusual site conditions presented some challenges for accessing 
and dewatering the repair area since it was located in the middle of 
the expansion wetland and under approximately 4 ft. of water. It took 
several days to finalize the repair methodology which was needed prior 
to submitting the permit applications.
    Once repair plans had been finalized, LWM permit applications were 
simultaneously submitted to the USACE and MDEQ 34 days after the 
initial find. Approximately one month (28 days) later, both agencies 
requested additional repair drawings. The drawings were provided to 
both agencies within 10 days of their request. The issuance of LWM 
permit approval was finally received 76 days after the initial 
discovery and 43 days after the application was submitted. 13 days 
after issuance of the LWM, authorization was received from the USACE 
under Nationwide Permit 12.
    An attempt to investigate and repair the condition ensued 110 days 
after discovery, but because of the depth of the water and substrate, 
the work could not be executed in the manner authorized under the above 
reference permits.
    A revised repair methodology was submitted to USACE and MDEQ 4 days 
later, requesting that the previously issued permits be modified to 
allow for the new construction techniques. MDEQ responded to this 
permit amendment request exactly one month later, via letter 
authorization. Similarly, the USACE responded 37 days after the revised 
request was submitted, by authorizing the work under Nationwide Permit 
33. The repairs were finally completed 237 days after the discovery; 
more than six months after permitting efforts were initiated.
    It should be noted that only the USACE and MDEQ permit 
authorizations were difficult to obtain. The Special Use Permit and the 
Soil Erosion Control Permit were both obtained within only days after 
applications for these permits were filed.
    Reducing the pressure on this system has the net effect of removing 
7,600 barrels/day of refined products from the market. Had this 
situation occurred in June, 2000, it would have further exacerbated the 
supply issue that was occurring in the State of Michigan at that time.

                 PIPELINE INTEGRITY MANAGEMENT PROGRAM
         CASE STUDY SUPPORTING A STREAMLINED PERMITTING PROCESS

    A 20 inch diameter products pipeline was scheduled to undergo an 
in-line inspection in accordance with DOT's Integrity Management Rule. 
The inspection on this system was scheduled such that the operator 
would expect to receive the tool data during June 2004.

    A portion of the subject pipeline system traverses the Louisiana 
Coastal Management Zone which is under the jurisdiction of the 
Louisiana Department of Natural Resources, Coastal Management Division 
(CMD). Other agencies with jurisdiction over the pipeline's inspection 
include the US Army Corps of Engineers (USACE) and the Parish Coastal 
Zone Management Committee.
    In anticipation of the upcoming inspection, the operator filed an 
application with the CMD for an ``Area Permit.'' The Area Permit is a 
relatively new permitting process utilized by the CMD (it was 
promulgated in October 2003) and is supposedly a streamlined process 
for allowing more timely pipeline repairs. The intent behind the Area 
Permit is to function as a general permit for the entire pipeline 
system within the Coastal Zone; however, the Area Permit does not 
authorize individual IMP repairs. Individual repairs are not authorized 
until the operator has provided the agency with site specific 
information about each repair location. The CMD suggests that once an 
operator has received Area Permit approval, individual IMP repairs can 
be authorized very quickly once the operator has provided the site 
specific information.
    During early coordination with the CMD, the agency advised that 
they would be coordinating their review and approval of the Area Permit 
application in conjunction with the USACE. In fact, the operator was 
instructed to complete the USACE's standard permit application form 
(Form 4345) as part of the application package. However, during later 
discussions with the USACE, the operator learned that the USACE does 
not recognize the Area Permit as a valid permitting mechanism.
    Despite the efforts in Louisiana to streamline the permitting 
process for IMP repairs, the Area Permit process seems to need further 
refinement in order to be truly valuable to pipeline operators. First, 
the CMD needs to understand that in the event of immediate conditions, 
there is often very little time to prepare the necessary site specific 
information including taking photos of the repair locations, generating 
maps of repair locations, etc. and get this information submitted to 
the CMD prior to initiating any repair activities. The impacts caused 
by IMP repairs, even in environmentally sensitive areas such as the 
Coastal Zone, are general minor and temporary in nature and should not 
warrant such extensive review.
    Secondly, there appears to be a disconnect between the CMD and the 
USACE regarding the validity of the Area Permit process. Better 
coordination between these two agencies could result in the development 
of one permitting process that would address impacts caused by IMP 
repairs to ``waters of the US'' as well as impacts to the Coastal Zone.
    Due to the uncertainty of being able to effect repairs, should the 
circumstance arise, the operator has temporarily postponed an In-line 
Inspection (but will still meet the regulatory deadline) of this system 
in order to get the permits in place. If the permits are not obtained 
by the regulatory deadline, and the operator is forced to shut down the 
system after conducting the In-line Inspection (and unable to effect 
repairs in a timely manner), there could be a potential loss of motor 
fuel supply to the Southeast/East Coast of up to 9,800,000 gallons per 
day. That could equate to (assuming 25 gallons of motor fuel are used 
to fill up an average vehicle) 392,000 vehicles per day that could be 
forced to look elsewhere for fuel, if it were available.

                 PIPELINE INTEGRITY MANAGEMENT PROGRAM
         CASE STUDY SUPPORTING A STREAMLINED PERMITTING PROCESS

    Project Overview: In California, a pipeline company initiated a 
project in 2002 to conduct investigations of anomalies identified 
during a pipeline ``smart pig'' inspection survey run in 2001 that 
identified over 45 anomalies. The pipeline traverses environmentally 
sensitive habitat including freshwater wetlands, tidally influenced 
marshland, and habitat supporting several federally- and state-listed 
plant and animal species. The permitting process is complicated by 
various work windows that prevent or limit maintenance activities 
during specific times of the year along the pipeline right-of-way 
(e.g., seasonal flooding conditions, breeding and nesting seasons for 
listed species, etc.). These anomaly dig locations were similar to digs 
pursued in 2001 from a 1999 ``smart pig'' survey that took 14 months to 
process the permits.
    Overview of Permitting Process: The project took 10 months to 
permit. Permitting involved four different federal and state regulatory 
agencies. The U.S. Army Corps of Engineers (ACOE) was the lead agency 
for permitting. They were involved because the dig locations were 
located within ``waters of the United States.'' The U.S. Fish and 
Wildlife Service (USFWS) were also involved due to the potential 
presence of the federally protected species including endangered vernal 
pool tadpole shrimp, the threatened vernal pool fairy shrimp, the 
threatened giant garter snake, the endangered salt marsh harvest mouse, 
the endangered California clapper rail, the threatened Sacramento 
splittail, and the threatened Delta smelt. California agencies involved 
were the California Regional Water Quality Control Board (RWQCB) and 
the San Francisco Bay Conservation and Development Commission (BCDC).
    Applications for digs indicated by the inspections were submitted 
in August 2002 for the following permits:

 ACOE Section 404 Pre-construction Notifications under Nationwide 
        Permit 3;
 RWQCB 401 Water Quality Certifications triggered by the 404 process;
 Endangered Species Act (ESA), Section 7 biological consultation with 
        the USFWS; and
 BCDC permit waiver pursuant to Section 29508 of the Suisan Marsh 
        Preservation Act.
    After the notification was submitted to the ACOE, the ACOE waited 
until May 2003 to send its letter to the USFWS to initiate the Section 
7 consultation in May 2003. Fortunately, the applicant t had been 
working with USFWS for months preceding the May 2003 letter from ACOE. 
Only because work was initiate and pursued by the operator on parallel 
tracks could final permits be issued in June 2003.
    Approximately 70 permit conditions were included in the four 
permits. Permit conditions addressed the following general areas:

 Protecting soil and water from contamination during repair 
        activities;
 Protection of the federally protected species during construction;
 Restoration of the areas to pre-construction conditions; and
 Mitigation for the impacts to species and habitat.
    Lessons Learned from Case Study: There are a number of ways to 
improve the permitting process. Ten months is too long to permit 
relatively straightforward pipeline repair activity. It is not possible 
to meet the OPS rule repair time limit (e.g. immediate to 6 months) at 
locations where environmental permitting (with its extensive agency 
interactions) is required.
    Ways to streamline the permitting process include:

 Streamlining the ACOE permitting process to expedite pipeline repairs 
        while protecting the environment. Agency pre-review and 
        approval of relatively routine activities prior to their 
        commencement is not necessary. An alternative approach is to 
        develop a set of Best Management Practices (BMPs) to protect 
        the environment during repair activities, possibly similar to a 
        Habitat Conservation plan or a nationwide Permit, that includes 
        all jurisdictional agencies. Repair activities that use these 
        BMPs would no require prior review and approval.
 ACOE permitting in states such as California is sequential, i.e. the 
        ACOE reviews, then request consultation with the USFWS. Each 
        agency approves a permit before they pass the ball to the next 
        regulatory agency. Instead there should be a parallel review 
        process. For projects that do not qualify to use BMPs, OPS 
        could act as a n ombudsman to resolve permitting issues among 
        the various agencies and improve the safety of pipeline.
 Alternatively, for projects that require agency review, a site-
        specific plan for conducting the pipeline repair could be 
        developed and submitted to the appropriate agencies for their 
        review. If agencies did not respond after an appropriate 
        interval consistent with time requirements in the 2001 OPS IMP 
        rule the repair project could proceed under the ``safe harbor'' 
        of the conditions proposed in the applications.

                 PIPELINE INTEGRITY MANAGEMENT PROGRAM
         CASE STUDY SUPPORTING A STREAMLINED PERMITTING PROCESS

    Situation involves replacement of a line with dents. A series of 
dents are located on one piece of pipe in the middle of the pipeline 
crossing of the Delaware River. We ran in-line inspection tools and 
found the dents.
    The situation prohibits repair in place so we will have to drill 
and pull into place a new pipeline segment across the Delaware River, 
from New Jersey to Pennsylvania shores, in the Philadelphia area.
    This requires permits from the Core of Engineers, Fish and Game 
Commission, Commonwealth of Pennsylvania, State of New Jersey, local 
township(s), and the Philadelphia Airport. The permitting process 
(preparation, submittals, administration and technical reviews, 
revisions, final approval, etc.) takes more than one year to complete, 
of which 240 days alone are required for administrative and technical 
reviews.
    In accordance with OPS Integrity Management regulations, we reduced 
the pipeline operating pressure once. Since further remedial action is 
required if we cannot complete repairs within 365 days, we have had to 
reduce the pressure again, while in the process of obtaining all of the 
above mentioned permits and completing the pipeline replacement.

                 PIPELINE INTEGRITY MANAGEMENT PROGRAM
         CASE STUDY SUPPORTING A STREAMLINED PERMITTING PROCESS

    Project Overview: In California, a pipeline company operates a 
crude oil pipeline system that traverses environmentally sensitive 
habitat including freshwater wetlands, waters of the US, and habitat 
supporting several federally- and state-listed plant and animal 
species. The permitting process is complicated by various work windows 
that prevent or limit maintenance activities during specific times of 
the year along the pipeline right-of-way (e.g., seasonal flooding 
conditions, breeding and nesting seasons for listed species, etc.)
    It took nearly one year for us to make the necessary repairs on 
this pipeline, mostly due to Federal ESA permitting issues 
(approximately 6 months to obtain the biological opinion). During this 
timeframe the pressure was reduced on our pipeline. It took three 
months to permit and repair our immediate repair and one year to permit 
and repair the remaining 60 and 180 day repairs. We were fortunate that 
there were not CESA fully protected species on the repair locations. If 
there were, we may not have been able to make those repairs due to the 
inability to ``take'' these species under state law.
    Permitting Overview: A pipeline ``smart pig'' inspection survey 
identified over 15 pipe anomalies that required immediate-, 60- and 
180-day repairs. The locations of the repairs triggered agency 
consultation and permitting due to their locations in sensitive 
habitats. Once it was determined that the repairs needed to be 
conducted in sensitive areas, the operating pressure of the pipeline 
was reduced.
    At the request of the USFWS the project was broken up into two 
permitting repair projects; one for an immediate repair and a 
programmatic approach for the remainder of the repairs. The immediate 
repair permitting effort took approximately three months to complete. 
The programmatic approach progressed for approximately 3 months before 
we were informed by the USFWS that we could not complete the permitting 
before the one-year deadline from discovery. At this point the USFWS 
instructed us to attempt to permit the most critical sites in order to 
meet the one-year deadline. The mini-programmatic permitting effort 
required approximately an additional three months to complete and 
resulted in an 81-page Biological Opinion. The permitting efforts 
included the following federal and state agencies:

 Army Corp of Engineers (ACOE)--Sacramento Valley District;
 California Regional Water Quality Control Board (RWQCB)--San 
        Francisco Bay Region & Central Valley Region;
 U.S. Fish and Wildlife Service (USFWS)--Sacramento Branch; and
 California Department of Fish and Game (CDFG).
    As indicated above, consultation with multiple regional branches of 
the same agency has been required for a single project. The following 
permits were applied for in order to complete the repairs:

 2 ACOE Section 404 Pre-construction Notifications under Nationwide 
        Permit 3;
 2 RWQCB 401 Water Quality Certifications triggered by the 404 
        process;
 2 Endangered Species Act (ESA), Section 7 biological consultations 
        with the USFWS; and
 2 CDFG Consistency Determinations for the USFWS BOs.
    All the repair sites provide habitat for species that are not only 
listed under the ESA, but also under the CESA. For projects that can 
affect species listed under both acts, the USFWS issued BO must be 
submitted to the CDFG for a Consistency Determination. Furthermore, one 
of the species, the blunt-nosed leopard lizard (BNLL) is listed as 
fully protected under CESA so no take can be authorized by the CDFG. 
However, the CDFG concluded that these repairs would not result in take 
of the BNLL, so consistency was granted.

    Mr. Shimkus. Thank you. And I appreciate that.
    Now I would like to recognize Mr. Breean Beggs, Executive 
Director of the Center for Justice. You are recognized for 5 
minutes, sir. Welcome.

                    STATEMENT OF BREEAN BEGGS

    Mr. Beggs. Thank you, Mr. Chairman.
    I am testifying today on behalf of the Pipeline Safety 
Trust. I am a member of the board of directors of that 
organization. You are probably familiar that it was created 
from the families of the victims of the Bellingham pipeline 
accident.
    The goal is simply to prevent any future pipeline failures 
that are caused by failure to inspect, failure to repair, and 
failure to replace pipelines. While there are other causes for 
pipeline explosions, there should never be another one based on 
that.
    If we were going to look at what this committee and the OPS 
could do to improve the chances of that becoming a reality, the 
No. 1 success so far since 2002 and the No. 1 success in the 
future is mandating testing of pipelines and the repair of them 
and, if necessary, the replacement of them.
    So far according to the Department of Transportation report 
that we heard about, they have inspected about 6 percent of the 
liquid fuel pipelines. And they have already come up with 1,200 
direct threats that needed to be repaired immediately, 
including 20,000 that could be repaired over time. That is just 
6 percent. Although it is too soon to tell, the more pipelines 
that are inspected, the safer we are going to be.
    I appreciate Mr. Pearl's testimony that the industry is now 
looking at possibly 82 percent, but the Pipeline Safety Trust 
is, of course, not going to rest until they do 100 percent.
    The second thing about OPS that the Pipeline Safety Trust 
would like to emphasize is a change in enforcement moving to a 
proactive, rather than to fix it after it is broken, method. I 
think the industry is recognizing that these explosions and 
failures are quite expensive. The economic damage alone from 
Bellingham was between $600 and $700 million, not counting the 
pain and suffering in the community and all of that. That could 
have been prevented with just a fraction of spending, and it 
could have been planned.
    The beauty of requiring testing and regulating proactively 
is that the company can build it into the rate structure. And 
the good companies can rest assured that the companies that 
might be willing to cut corners are not going to be able to do 
so, in the overall will cost us far less for energy and the 
disruptions will be less.
    One of the other things that we would really like this 
committee to move forward on in OPS is community right-to-know 
regulations. In the early stages of the Pipeline Safety 
Improvement Act, there were community right-to-know measures. 
Those dropped out at the end of the day, probably because we 
were a little close to September 11. But what the Pipeline 
Safety Trust would ask the industry and OPS and this committee 
is to help us get the information out about what testing has 
been done, what safety measures have been taken, and which 
haven't. We are uniquely set up to be a clearinghouse for that 
information. And we look forward to assisting local communities 
that don't have that expertise in doing that.
    I will touch briefly on the technical assistant grants. We 
stand ready both to apply for those but, more importantly, to 
help smaller communities who haven't yet experienced such a 
crisis apply for those grants so they can make sure that their 
pipelines are as safe as possible.
    We would like OPS to be more proactive in their enforcement 
and collection of civil fines. We think it is important that 
when they identify a substantial deviation from safety 
regulations, that they promptly and fairly enforce that with 
appropriate civil fines so that operators will know that they 
will be punished, not just for causing a horrible explosion but 
also for creating a culture where that might arise.
    The Bellingham explosion fine proposed initially was over 
$3 million. To date, only $250,000 has been collected. And that 
was from Equilon. While there have been some obstacles to 
getting money from Olympic due to a bankruptcy proceeding, that 
has only been going for a year.
    In our communication with OPS and in the correspondence I 
reviewed from members of this committee with OPS, OPS has not 
definitely stated that it is going to try and collect that 
fine. We think, certainly in cases where there is a horrible 
loss of life, they should be collected, but, more importantly, 
operators should know that if they fail to abide by the 
standards, there will be appropriate civil fines.
    My last point is simply this. You would expect that when a 
pipeline explosion happened, that the natural economies would 
cause companies to lose quite a bit of money and pay for the 
damages, but many pipeline operators have taken a legal 
loophole and created separate entities that own the structure 
that insulate their owners, which are often larger companies, 
from any type of liability. And, thus, Olympic Pipeline is a 
good example.
    They are now in bankruptcy. Their owner, which is BP, is 
shielded from liability. And, in fact, there won't be 
sufficient resources to pay all of the bills that are going to 
come due. So we would ask that the committee at least consider 
financial responsibility requirements similar to the liquid 
natural gas facility.
    Thank you for your time. The Pipeline Safety Trust looks 
forward to continuing to work with operators and OPS and this 
committee to make our energy distribution system much safer.
    [The prepared statement of Breean Beggs follows:]

Prepared Statement of Breean Beggs, Board of Directors, Pipeline Safety 
                                 Trust

    Good morning. My name is Breean Beggs and I am a member of the 
Board of Directors for the Pipeline Safety Trust. The Pipeline Safety 
Trust is a non-profit corporation formed by victims of the 1999 
Bellingham Pipeline tragedy to protect communities throughout the 
United States from unsafe pipelines and unsafe management of those 
pipelines.
    Five years ago last month, the Olympic Pipeline burst into a salmon 
stream running through Bellingham's most pristine park and exploded. In 
a flash, three youngsters were killed, a salmon stream that runs 
through the heart of Bellingham was dead, and our community was sent 
into a deep sense of loss and mourning. The horrendous death and damage 
was caused by negligence, poor management, poor agency oversight and 
almost nonexistent regulations. Out of that sadness came a community 
wide awareness of pipeline safety inadequacies, and a commitment to 
improving pipeline safety nationwide. Because of our community's 
commitment local, state, and national pipeline safety laws have been 
passed, and the Office of Pipeline Safety has significantly increased 
their rulemaking efforts.
    The Pipeline Safety Trust came into being a little over a year ago 
because of Bellingham's efforts, and as part of the court settlement 
with Equilon Pipe Line Company over the 1999 Olympic Pipeline 
explosion. After investigating this tragedy the U.S. Justice Department 
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 Justice Department'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 the communities who have the most to lose if a 
pipeline fails should be included in discussions of how better 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.
    In my testimony this morning I will cover:

 The consequences of unsafe pipelines
 The need to address shortcomings of the Pipeline Safety Act of 2002
 Further pipeline safety issues that still need to be addressed.

                    CONSEQUENCES OF UNSAFE PIPELINES

    In Bellingham we learned first hand the worst consequences of not 
properly maintaining, testing and regulating pipelines. Three of our 
young people died. Human death and injury is often the driving force 
behind pipeline safety improvements. This makes sense when you consider 
that according to the Office of Pipeline Safety in the past 20 years 
397 people have died and 1850 people have been injured in pipeline 
accidents nationwide. But death and injury is only one measure of the 
adequacy of our pipeline safety system.
    During the same twenty year period the Office of Pipeline Safety 
(OPS) reports more than $1.5 billion in property loss from pipeline 
accidents, and many believe that this number is significantly under-
reported. OPS also reports nearly 76 million gallons of liquid 
petroleum products were lost into the environment during this same 
period. This figure is also under-reported since spills of less than 
2100 gallons did not even need to be reported until the passage of the 
2002 Pipeline Safety Act. These spills represent potentially 
catastrophic damages to private and public water systems, wetlands and 
other surface and ground waters. The total costs of these damages are 
unknown, but clearly substantial.
    In recent years the economic costs of pipeline distribution 
disruptions have also been recognized. In Washington State, ARCO 
estimated that the cost of alternative transportation for fuel during 
the Olympic Pipe Line shutdown was an additional $500 million. In 
Arizona, California, and Michigan, which have all had recent 
distribution problems due to pipeline failures, the cost of gasoline 
often rose by more than $1/gallon. Multiply these temporary increases 
by the number of drivers forced to pay these higher prices and you find 
another hidden cost of the lack of pipeline safety in the hundreds of 
millions of dollars. After the El Paso Pipeline explosion that killed 
an entire family of twelve near Carlsbad, New Mexico, the Federal 
Energy Regulatory Commission stated that the Carlsbad accident 
``contributed significantly'' to the California energy crisis and OPS 
estimated that impact at $17.5 million a day. Since that pipeline was 
shut down for nearly a year this amounts to an additional $6 billion in 
damages due to the failure of a single pipeline.
    So while death and injury may still be the most powerful reason to 
care about the safety of our nations pipelines, we also need to 
recognize that billions of dollars of economic disruptions and 
increased fuel prices are being passed on to consumers by pipeline 
companies that have failed to ensure the integrity of their pipelines. 
If even a small portion of this money had been spent to test and repair 
these pipelines before they failed, these economic consequences would 
not have occurred, and people would still be alive and uninjured.

            SHORTCOMINGS OF THE PIPELINE SAFETY ACT OF 2002

    The Pipeline Safety Act of 2002 provided many clear enhancements to 
pipeline safety regulations, including increased fines, operator 
training requirements, whistleblower protections, and increased funding 
for the OPS. To build on this progress the following provisions of the 
2002 Act need to be re-examined.
    Integrity Management of Gas Transmission Lines--One of the most 
important rules issued as a result of the 2002 Act, was the natural gas 
transmission pipeline integrity management rule published in December 
of 2003. This rule was a good first step, but in our opinion does not 
go far enough, or fast enough, to ensure the integrity of a majority of 
the gas transmission lines in the system. Because the Act only requires 
integrity assessments in High Density Population Areas, and because 
OPS's definition of such areas only includes an estimated 7% of the 
total mileage of gas transmission lines, only a small percentage of 
pipelines will ever be tested. To illustrate, pipeline inspection will 
not be required under OPS's definition of High Consequence Areas where 
the Carlsbad, New Mexico pipeline ruptured, killed twelve people and 
ultimately cost consumers $17.5 million dollars a day. This lack of 
requirement for assessment amounts to an endorsement of the integrity 
management technique of finding problems by waiting for leaks and 
explosions, and seems to promote a policy choice that ambushes 
consumers and businesses with unexpected costs rather than 
incorporating the cost of inspected, dependable pipelines into the rate 
structure.
    To make matters worse the Act gives companies up to 10 years to 
test only seven percent of their pipelines. We hope that you will take 
a look at this serious flaw in the 2002 Act and move forward in 
requiring testing of all pipelines.
    Another concern in the integrity management section of the 2002 
Pipeline Safety Act was the inclusion of the unproven and undefined 
method of ``direct assessment,'' as an alternative to the well 
documented assessment methods of internal inspection and pressure 
testing, We hope that Congress will continue to provide oversight of 
the development and efficacy of ``direct assessment.''
    Strict liability--The 2002 Act did increase fines for pipeline 
accidents, but those fines were left to the discretion of the Office of 
Pipeline Safety. Often times the fine amounts announced by the OPS are 
never collected or negotiated down significantly. If Congress 
implemented a strict liability formula for penalties based on the 
volume spilled, companies would have a greater incentive to avoid 
spills and neither OPS or the company would have to spend resources 
arguing over the amount of the fine.
    Community Right To Know--Many of the early versions of the 2002 Act 
included sections to help ensure that local communities and citizens 
would have easy access to information to allow them to judge for 
themselves the safety of the pipelines that run through their 
communities. This information would include things like spill and 
accident records, integrity management plans, frequency of testing, 
descriptions of what the testing found, descriptions of what was done 
about problems found, whether operators had been trained, whether 
emergency response plans were in place for local communities, etc. 
Unfortunately, these sections were removed after the 9/11 tragedy for 
fear of providing terrorists information about the country's pipeline 
infrastructure. We hope that Congress will now move forward and include 
such Community Right To Know information into pipeline safety laws, 
since the above information would be of no use to terrorists, but would 
be of significant use to communities trying to assess their own safety 
and shine the light of day on any problems with the overall system of 
pipeline safety.
    Technical Assistance Grants--Section 9 of the 2002 Act provided for 
technical assistance grants to communities for ``engineering and other 
scientific analysis of pipeline safety issues, including the promotion 
of public participation in official proceedings conducted under this 
chapter.'' Unfortunately to date the OPS has not developed the 
competitive procedures required to award these grants, and Congress has 
therefore not provided the appropriations to fund them. We hope that 
Congress will require the OPS to develop the needed procedures to award 
these grants by a date certain, and then provide the funding to allow 
communities around the country to better understand some of the 
pipeline problems in their midst.

     FURTHER PIPELINE SAFETY ISSUES THAT STILL NEED TO BE ADDRESSED

    Integrity Management of Liquid Transmission Lines--Many of the same 
problems already stated above for natural gas transmission lines also 
apply to the rules for liquid pipelines. Only those sections of 
pipelines in High Consequence Areas are required to be assessed, and by 
some estimates this amounts to less than 10% of the total mileage. 
According to testimony by the Inspector General of the Department of 
Transportation given in June, with only 16% of the required mileage 
tested over 1200 ``integrity threats'' requiring immediate repair were 
found. Extrapolating this to the rest of the liquid transmission 
pipeline mileage indicates that there may be more than 7500 ``integrity 
threats'' needing immediate repair. Because of the narrow definition of 
High Consequence Areas, many of them will not be found in a planned 
methodical fashion by inspection and repair. Instead, they will be 
discovered the hard way--by endangering communities with pipeline 
failures and abruptly depriving downstream communities of their energy 
supplies. Congress needs to address why there is no urgent requirement 
to find and remedy these immediate threats as soon as possible.
    Gathering Lines and Shut Off Valves--Congress has previously 
mandated regulations for gathering lines, and shut off valves for oil 
and gas lines, but so far OPS has not developed these rules.
    One Call Systems--Many states provide no penalties for those who do 
not use the one call system to have pipelines located before they dig 
in the area of a pipeline. Horror stories abound of near misses caused 
by contractors and individuals who are willing to take the chance of 
digging near pipelines without formally locating them due to time 
constraints or ignorance. One reason that they take this risk is that 
they know that there is no penalty unless they hit something. We are 
not aware of any studies on this issue, but there is some anecdotal 
evidence that states with penalties for digging before you call for a 
location have fewer near misses and pipeline strikes. A definitive 
study of whether penalties do deter digging without using the one call 
system is needed. If the findings indicate an adequate decrease in 
pipeline damage and near misses in states with such penalties, then OPS 
should encourage or require such penalties nationwide.
    Leak Detection--Many leaks, and even some ruptures, in liquid 
pipelines go undetected for too long. Leak detection performance 
standards for liquid transmission pipelines need to be developed to 
ensure that leaks of a particular size are discovered rapidly.
    State Pre-emption--Current pipeline safety law prevents states from 
regulating and enforcing violations on interstate pipelines even if 
such regulation would improve public safety and/or environmental 
protection and would not affect interstate commerce. There are numerous 
areas of oversight and regulation where states might want to exceed 
federal requirements to enhance pipeline safety, and would not 
compromise a company's ability to operate its pipelines smoothly and 
safely. Congress needs to affirmatively act to allow states to use the 
unique knowledge they have to protect their citizens.
    Financial responsibility requirements for pipeline corporations--
Large corporations can shield themselves from liability for poor safety 
practices through certain strategies, such as holding assets that may 
generate liability (e.g., pipelines) in subsidiaries or as shares of 
separate corporations. As part of this strategy, the parent corporation 
drastically undercapitalizes its subsidiary. In the case of pipelines, 
this is common. It is not unusual for a pipeline company to be 
capitalized by virtually 100% debt, lent by the large corporate 
shareholders. In fact,--a similar strategy was used by the owners of 
Bellingham's Olympic Pipeline. In a major spill like Bellingham, the 
undercapitalized pipeline company is forced into bankruptcy when the 
owners decline to provide further financing. In the usual bankruptcy, 
the shareholders lose the company assets to the debt holders, but in 
this case, those are the same entities. Bankruptcy presents no 
meaningful threat to these shareholders but it does allow pipeline 
companies to avoid financial consequences for inadequate safety 
measures. Congress should impose financial responsibility requirements 
for pipelines as it already does for liquefied natural gas facilities.
    Enforcement--The Pipeline Safety Trust and other members of the 
Bellingham community are very concerned that the OPS has been unwilling 
to date to collect significant fines for violations of OPS regulations 
from the tragedies in Bellingham and Carlsbad. OPS often touts large 
proposed fines, but historically they have collected little if any of 
the money. The public has no evidence that the increased penalties 
contained in Section 8 of the 2002 Act are being used by OPS to send a 
message to pipeline operators that violations are both unacceptable and 
costly.
    The U.S. General Accounting Office (GAO) is expected to release a 
report on OPS' enforcement record. We hope this report will take a look 
at the large difference between fines that the OPS proposes versus the 
actual fines they collect. Preliminary testimony on the GAO report in 
June seemed to emphasize the difference between assessed fines and 
collected fines, which for the most part are nearly the same thing. The 
real mystery lies between the initial proposal of fine amounts and the 
amount actually collected. Why is this difference so great? Is OPS in 
error in their initial proposed fines? Are they negotiating fines down 
because they are understaffed for this task? Are they reducing fines 
because they fear legal fights with pipeline operators? Or, are they 
simply not committed to enforcing the law as enacted by this Committee 
and the Congress. These are the types of questions that we hope the GAO 
report will address. If it does not, we hope that Congress will ask 
them to expand their report to do so. We also believe that proposed 
fines, the company's response to the proposed fines, and information 
describing how the assessed fine was reached needs to be public 
throughout the process. OPS currently does not make such information 
public despite Freedom of Information Act Requests by organizations, 
like the Pipeline Safety Trust, that share the same mission of pipeline 
safety.
    Current OPS enforcement actions appear to be mostly reactive to 
pipeline accidents rather than proactively preventing them. The agency 
needs to adopt a an enforcement strategy that would include fines to 
companies found to be operating pipelines in ways that could result in 
serious spills or explosions regardless of whether or not they occur. 
Only through well publicized and rigorous preventative enforcement will 
some within the industry begin to spend sufficient money on prevention 
instead of relying on insurance and bankruptcy to deal with any 
significant damages caused by a pipeline failure.
    Thank you for this opportunity to testify. Please feel free to 
contact the Pipeline Safety Trust at any time.

    Mr. Shimkus. Thank you.
    Now because of the order of the publication in the hearing 
paper, we are going to go to Mr. Koonce, Chief Executive 
Officer, Dominion Energy, from Richmond. Welcome, sir. You are 
recognized for 5 minutes.

                   STATEMENT OF PAUL D. KOONCE

    Mr. Koonce. Thank you, sir.
    Just a bit about Dominion, Dominion is headquartered in 
Richmond, Virginia. We are the largest fully integrated energy 
company in North America. We operate about 25,000 megawatts of 
electric generation. We produce natural gas and oil from about 
6.4 TCF of crude reserves. And we drilled more wells last year 
in the United States than any E&P company, including the 
majors.
    We serve 5 million regulated retail customers through five 
distribution companies. And through my segment of Dominion, we 
operate over 14,000 miles of electric and natural gas 
transmission facilities. We operate the Nation's largest 
underground natural gas storage complex. And we also operate 
the Nation's most active LNG important terminal at Cove Point, 
Maryland.
    In the interest of time, I am not going to read my prepared 
remarks. Let me just make a couple of observations. One is the 
Office of Pipeline Safety and the Interstate Natural Gas 
Association of America have been very busy. I am here today 
testifying on their behalf.
    INGAA represents members that operate over 180,000 miles of 
interstate natural gas pipeline. We transport 90 percent of the 
natural gas consumed in the United States. And natural gas 
represents 25 percent of the primary energy consumed. Linking 
the producing basins to the markets I think is of interest to 
everyone and doing that safely and reliably.
    Throughout 2003, working with OPS, INGAA members have been 
working to draft a pipeline integrity management rule that we 
think is effective and technically based. This year every 
pipeline company will have to submit an integrity management 
plan, but not only that. They will have to begin direct 
assessments no later than June of this year. So work is already 
underway to directly inspect the high-consequence pipeline 
areas where we operate.
    Much more will be done than just inspect the high-
consequence areas. Because of the most efficient nature of 
performing the inspection, the end-line devices, which we refer 
to as smart pigs, have to be introduced into the pipeline 
system at compressor station locations. Those compressor 
station locations are 75 to 100 miles apart. So while we may 
just have 2 or 3 miles of high-consequence area, we will 
actually inspect 100 miles or more. So many times the miles 
required will actually be inspected and remediated.
    Second, the industry is focused on security, both at the 
pipelines that we operate and the LNG terminals. Plans have 
been developed based on guidelines that have been published by 
DOT as it relates to pipelines and regulations as it relates to 
LNG facilities.
    Field audits are underway. In fact, we are meeting with the 
Department of Transportation and the Homeland Security 
Department to review our security and our counter-threat 
contingencies. DOE is modeling the effect of disruptions to 
energy infrastructure around the Nation. And our industry is 
working with them on how we can mitigate those effects.
    Finally, the third observation and last that we would like 
to make is to comment on the administration's proposal to move 
the Office of Pipeline Safety to the Federal Railroad 
Administration. We as an industry respect the secretary's 
desire to organize his agency as he desires. However, we are 
very concerned about the vital loss of line of sight our 
industry and this Congress has with OPS.
    In fact, INGAA supports the creation of a new pipeline 
safety administration within DOT as proposed by House 
Transportation and Infrastructure Chairman Don Young. We think 
the line of sight that we have with OPS and with this Congress 
is vital.
    Thank you.
    [The prepared statement of Paul D. Koonce follows:]

Prepared Statement of Paul D. Koonce, Chief Executive Officer, Dominion 
 Energy on Behalf of the Interstate Natural Gas Association of America

    Mr. Chairman and Members of the Subcommittee: Good morning. My name 
is Paul Koonce and I am Chief Executive Officer of Dominion Energy. I 
am testifying today on behalf of the Interstate Natural Gas Association 
of America (INGAA). INGAA represents the interstate and interprovencial 
natural gas pipeline industry in North America. INGAA's members 
transport over 90 percent of the natural gas consumed in the U.S., 
through an 180,000-mile pipeline network.
    Dominion, headquartered in Richmond, Virginia, is one of the 
nation's largest producers of energy. Dominion's portfolio consists of 
nearly 24,000 megawatts of electric power transmitted over more than 
6,000 miles of transmission lines, 6.3 trillion cubic feet equivalent 
of natural gas reserves, 7,900 miles of natural gas pipeline and the 
nation's largest natural gas storage system with more than 960 billion 
cubic feet of storage capacity. Dominion also serves 5 million electric 
and natural gas retail customers in nine states.
    The North American pipeline network provides the indispensable link 
between natural gas supply and the local distribution companies that 
serve retail customers. Natural gas represents 25 percent of the 
primary energy consumed annually in the United States, a contribution 
second only to petroleum and exceeding that of coal. Consequently, the 
natural gas pipeline delivery network is a critical part of the 
nation's infrastructure.
    This is why the safe and reliable operation of these pipeline 
systems is so important. Because the natural gas pipeline network is 
essentially a ``just-in-time'' delivery system, with limited storage 
capability, customers large and small depend on reliable around-the-
clock service. And of course, the public wants to know that these 
pipeline systems crisscrossing the nation and serving their communities 
are safe. Mr. Chairman, these pipeline systems are safe--the safest 
mode of transportation in the country--and working together the 
pipeline industry and the Office of Pipeline Safety are making this 
valuable network even more safe and secure.

               PROGRESS AT THE OFFICE OF PIPELINE SAFETY

    Since this Subcommittee last debated the issue of pipeline safety, 
several years ago, a great deal of progress has been made at the 
Department of Transportation's Office of Pipeline Safety (OPS). As 
recently as five years ago, many in Congress and in the public at large 
were saying that the OPS was an agency of sub-standard performance. The 
General Accounting Office cited the backlog of unfinished, 
congressionally mandated rulemakings, the numerous DOT Inspector 
General recommendations that had not been implemented, and the poor 
acceptance rate for National Transportation Safety Board (NTSB) 
recommendations. For years, the OPS had the lowest acceptance rate of 
any modal office at DOT for NTSB safety recommendations, at about 69 
percent. Take a look at what has happened since that time. The OPS now 
has the second-highest acceptance rate for NTSB safety recommendations, 
right behind the Highway Safety Administration, at 86 percent. The 
backlog of unfinished, congressionally mandated rulemakings is 
virtually gone, and by any measure, OPS has made great strides in 
improving its effectiveness.
    Perhaps the most important accomplishment by the OPS since the 
passage of the Pipeline Safety Improvement Act of 2002 is the 
completion of the natural gas pipeline integrity management rule. This 
rule, required by the 2002 Act, took the better part of 2003 to develop 
before its final issuance in December. When the Notice of Proposed 
Rulemaking was released to the public in early 2003, the INGAA 
membership had a great deal of concern about its focus, its 
effectiveness, and workability. However, the OPS took our concerns 
about the proposed rule seriously, and worked with our industry in 
developing a final rule that remains true to the mandate from Congress, 
and does so in a way that is technically-based, practical and 
effective.
    INGAA made a commitment to assist OPS in accomplishing these goals 
in 1999. We have followed through on our commitments to help OPS 
accomplish their goals. INGAA believes that all of this work on the 
part of OPS has made the agency a more effective safety regulator. 
Enforcement has improved. Public education and communications efforts 
have improved. Audit and inspection activity is more focused and 
effective. All this should translate into Congress and the public 
having more faith in the safety and reliability of the natural gas 
pipeline infrastructure.
what the pipeline industry is doing to implement the new integrity rule
    The pipeline industry has been working hard too. As the nation 
increases its demand for natural gas, more pipeline capacity is needed 
to deliver additional supplies to growing markets. Whenever a new 
pipeline is proposed, or an existing pipeline proposes an expansion, 
communities and citizen groups raise the issue of safety. These 
communities and groups often have significant influence in the approval 
process, and therefore their concerns need to be taken seriously. In 
order for our industry to meet its objectives for serving a growing 
natural gas market, we also need to reassure the public that pipelines 
are a safe mode for energy transportation.
    Recent accident statistics are worth examination. For the years 
2002 and 2003, there were no fatalities or injuries associated with 
accidents on interstate natural gas pipelines located in ``high 
consequence areas,'' or the areas with higher population near a 
pipeline. There were four accidents during this period that resulted in 
injuries to one pipeline employee and three pipeline contractors, but 
these occurred on natural gas pipeline segments located in rural areas; 
i.e., not high consequence areas. Three incidents did occur on 
interstate natural gas pipelines in high consequence areas during 2002 
and 2003, but these did not result in either a fatality or an injury, 
and were therefore only reported to OPS because the damage costs 
(including the cost of natural gas lost) exceeded $50,000.
    The new natural gas pipeline integrity rule has been a significant 
area of focus for the industry. Let me assure the Subcommittee that we 
are not resting on our existing safety record. Over a dozen consensus 
standards have been completed, or are near completion, to support this 
rule, and have been supported by multimillion dollar collaborative 
research programs.
    The Pipeline Safety Improvement Act requires each natural gas 
pipeline operator to conduct a risk analysis and develop an integrity 
management plan for pipeline in high consequence areas by December 17th 
of this year. However, the law also required operators to begin 
integrity assessments on their pipelines by June 17th of this year. The 
``highest priority'' fifty percent of an operator's high consequence 
areas (based on the risk analysis) must complete a baseline integrity 
assessment within five years of enactment (December 17th, 2007), with 
the remaining fifty percent to be completed within ten years of 
enactment (December 17th, 2012).
    This integrity assessment work is already well underway. INGAA has 
surveyed its membership to measure the amount of inspection activity 
taking place. One respondent's answers are illustrative of the larger 
group. This pipeline has about 5900 miles of transmission pipeline, of 
which about 200 miles is located in high consequence areas (HCAs). To 
date, about ten miles of these HCAs have completed a baseline 
assessment, but as a function of inspecting these ten miles of HCAs, 
the operator has had to also inspect 250 miles of non-HCA pipe adjacent 
to those sections.
    The reason for these assessments going beyond the HCA requirement 
is simple. The vast majority of our pipelines are going to be inspected 
with internal inspection devices, commonly referred to as ``smart 
pigs.'' Special launcher and receiver facilities have to be constructed 
to both introduce a smart pig into a pipeline, and remove it at some 
point downstream. The most practical place (and often, the only place) 
to construct these launcher/receiver facilities are at compressor 
stations, which are typically located about 75 to 100 miles apart along 
a pipeline. The pipeline segment between compressor stations may have a 
few, discrete miles of HCAs, but in order to inspect the five or six 
miles of HCA pipe, the entire 75 to 100 mile segment between the 
stations will be inspected by the smart pig. INGAA estimates that about 
6 percent of total natural gas transmission pipeline mileage is 
actually located in HCAs, but in order to assess the integrity of this 
6 percent of pipeline mileage, about 60 to 70 percent of total 
interstate pipeline mileage will have to be inspected.
    Mr. Chairman, I would like to provide the Subcommittee with another 
example to illustrate my point. One INGAA member company is in the 
process of modifying a 58-mile section of pipeline so that internal 
inspection devices can be employed for integrity assessments. Since 
this pipeline was originally constructed in the mid-1950s, before the 
advent of smart pigs, it was not engineered to accommodate these 
devices. The pipeline operator has already identified 14 HCAs along 
this 58-mile segment, for a total HCA length of 8.74 miles. In order to 
assess the HCA portions of the pipe, pig launchers and receivers must 
be installed, and several valves will need to be replaced. The 
estimated modification costs for this one segment are $5.1 million, and 
the estimated integrity assessment and repair costs are $640,000. The 
work on this pipeline segment started last month, and is expected to 
last five months.

                         ONE IMPORTANT CONCERN

    The scope of the integrity assessment work to be done over the next 
eight years gives the INGAA membership some pause for concern. This is 
due to the fact that a significant number of pipeline segments will 
have to be removed from service in order to prepare for and perform 
assessments and any resulting repairs. This unprecedented integrity 
program will almost certainly affect natural gas deliverability and 
delivered natural gas commodity prices. The effect could be compounded 
because, coincidentally, the integrity assessments are happening during 
what will likely be a protracted period of tight natural gas supplies.
    In past years, pipelines were able to perform most maintenance and 
repair activities during the warm months of the year, when natural gas 
demand was relatively low. During these periods of low seasonal demand, 
the natural gas pipeline network could more readily handle system 
downtime. Few, if any, customers were impacted in terms of service 
disruptions or higher natural gas commodity prices.
    In today's natural gas market, however, demand not only peaks 
during the cold winter months, but also during hot summer months, due 
to the increased use of natural gas to generate electricity. This means 
that there are fewer weeks of the year when maintenance and repair can 
take place without impacting customers in some manner.
    In 2002, the INGAA Foundation prepared an economic analysis of 
these pipeline capacity reductions, and their effects on consumer 
prices. The report 1 looked at anticipated pipeline 
inspection scenarios under an integrity management program, based in 
large part on how long the industry would be given to perform a 
baseline assessment. For a ten-year baseline period (i.e., the one 
ultimately adopted by Congress), the report estimated increased 
consumer natural gas prices of about $1 billion per year for the first 
ten years. Please note that these costs are not associated with the 
actual cost of inspections and repair activities, even though these 
costs will also be significant. Rather, the study looked only at the 
``costs to consumers due to deliverability constraints'' and their 
effect on the natural gas commodity markets downstream.
---------------------------------------------------------------------------
    \1\ ``Consumer Effects of the Anticipated Integrity Rule for High 
Consequence Areas,'' prepared for the INGAA Foundation by Energy and 
Environmental Analysis, Inc., February, 2002.
---------------------------------------------------------------------------
    One way these unintentional price spikes can be minimized is by 
allowing for the coordination of inspection and repair activities among 
various competing pipeline operators. Unfortunately, the task of 
coordination is a daunting task. Presently the amount of parties 
involved and anti-trust law currently restrict such coordination. In 
the absence of such coordination, however, it is possible and even 
likely that multiple pipelines serving a given market could be down for 
inspection/repair at the same time, causing significant price increases 
and even service disruptions for that market. INGAA urges Congress to 
consider an anti-trust waiver for coordination of pipeline integrity 
assessment and repair activities.
    We also want to join with others in urging the various federal and 
state agencies involved in permitting pipeline inspection and repair 
activities to do so on a coordinated and expedited basis. We anticipate 
that our industry will be required to make significant modifications to 
our pipeline facilities over the next eight years, in order to 
accommodate internal inspection devices. The construction of smart pig 
launchers and receivers, for example, as well as replacing pipeline 
bends, segments and valves that cannot accept internal inspection 
devices may require permits from federal and state authorities. The 
interstate natural gas pipeline members of INGAA are regulated 
economically by the Federal Energy Regulatory Commission (FERC). The 
FERC must approve the construction of any new interstate natural gas 
pipeline, or any major expansion or modification (in excess of a 
certain dollar amount) of an existing interstate natural gas pipeline. 
The FERC has also accepted the primary role for the enforcement of the 
National Environmental Policy Act (NEPA) as it relates to pipeline 
construction and the resulting effects on the environment. In 2002, the 
FERC lead an effort to create and sign a Memorandum of Understanding 
(MOU) between all of the federal agencies associated with any 
permitting activities for pipelines, such as the Corps of Engineers, 
the Environmental Protection Agency, and the U.S. Fish and Wildlife 
Service. This MOU commits the signatory agencies to concurrent review 
of a pipeline construction application, such that agencies can work 
together rather than at cross-purposes, thus saving time and effort. We 
are hopeful that this MOU can also be applied to integrity management-
related activities. It should be noted, however, that this MOU does not 
include participation by state agencies. These state agencies are often 
the most intransigent in terms of approving permits on a timely basis. 
Once again, a signal from Congress as to the importance of approving 
these permits in a timely manner will be critical to the success of the 
Pipeline Safety Improvement Act of 2002.

 THE PROPOSED MERGER OF THE OPS AND THE FEDERAL RAILROAD ADMINISTRATION

    Before concluding, INGAA would like to provide some comments to the 
Subcommittee on the proposed merger of the Office of Pipeline Safety 
and the Federal Railroad Administration (FRA). The Secretary of 
Transportation announced his intent to move forward with this idea as 
part of an overall vision to gather the various research functions at 
DOT and place them under one authority. OPS is currently a part of the 
Research and Special Programs Administration (RSPA), which the 
Secretary envisions would be restructured in order to accept all 
transportation research-related activities from the various modal 
administrations. Since the OPS is a regulatory body, it would not fit 
within the new RSPA, and thus the proposal to move it to FRA.
    INGAA does not have a quarrel with the Secretary regarding his 
vision for transportation research. Our concern is that the OPS would 
lose its focus and effectiveness if it were to be subsumed into the 
much larger FRA. As you have already heard, OPS has made great strides 
in improving its performance over the last five years. Much of that 
success is related to the fact that it has been able to act quickly and 
decisively in improving its programs and enforcement activities. It 
would indeed be a shame if, after having worked so hard to gain back 
its credibility, OPS were to lose it once again by getting lost in a 
large and unfamiliar bureaucracy.
    Rather than merging with the FRA, INGAA supports the creation of a 
new Pipeline Safety Administration at DOT. House Transportation and 
Infrastructure Chairman Don Young introduced legislation (H.R. 4277) 
last month to create a separate pipeline safety entity at DOT, and we 
strongly support his efforts.

                            SECURITY ISSUES

    I also want to briefly mention pipeline security matters. Because 
natural gas pipelines are a part of the nation's critical 
infrastructure, INGAA and its members have been working with numerous 
federal and state agencies in developing heightened security 
procedures. The Department of Homeland Security is now verifying these 
procedures through audits. A key part of this exercise is contingency 
planning for response and recovery should an incident occur. Along with 
the Department of Energy, we are modeling the effect and response to 
possible attacks/outages on key pipeline systems. We also are 
encouraging participation by the operators of other parts of the 
infrastructure so that we can appreciate better the interdependencies 
within our national infrastructure and plan for how best to restore 
service in the event of an emergency.

                               CONCLUSION

    Let me thank you once again, Mr. Chairman, for allowing me to 
testify today. Safety is of paramount importance to our industry, and 
we believe that it is our obligation to work with Congress and the OPS 
to maintain and improve the safe, reliable operation of our pipelines 
in the years ahead. I would be happy to answer any questions you or the 
Subcommittee members might have.

    Mr. Shimkus. Thank you. And now I would like to recognize 
Mr. Robert Kipp, Executive Director of Common Ground Alliance 
from Alexandria, Virginia. Welcome. You are recognized for 5 
minutes.

                    STATEMENT OF ROBERT KIPP

    Mr. Kipp. Mr. Chairman, members of the committee, my name 
is Bob Kipp. I am the Executive Director of the CGA, an 
alliance of 15 stakeholder groups created on September 19, 
2000, Common Ground Alliance, a nonprofit organization 
dedicated to shared responsibility in damage prevention of 
underground facilities.
    In my comments today, I would like to focus on four key 
areas. First is NTSB recommendations to RSPA and the Office of 
Pipeline Safety. The CGA comprises members from 15 stakeholder 
groups. They are gas, oil, road builders, excavators, one-call 
systems, locators, engineers, regulators, insurance, electric, 
telcom, fencing contractors, equipment manufacturers, railroad, 
and public works.
    When the CGA makes a recommendation to the Office of 
Pipeline Safety, or any other government or private body, all 
15 stakeholder groups have unanimously agreed to the wording in 
those recommendations. We believe this to be a very powerful 
statement.
    Our recommendations are not those of any one industry but 
those of a group of industries with the belief that damage to 
our infrastructure is a shared responsibility.
    In the past 3 years, we have undertaken the review of nine 
NTSB recommendations to RSPA and OPS, six dating back to 1997. 
We have resolved eight of these nine to the complete 
satisfaction of RSPA and the NTSB, and expect to close the last 
recommendation in the next year or so.
    Our more than 1,100 members, of whom some 300 are currently 
working on 6 committees and numerous subcommittees, volunteer 
their time and their traveling expenses to work through the 
issues and recommendations.
    The second issue is regional CGAs. Like many other 
programs, much of the success and payoff is derived from the 
buy-in at local levels. Since last meeting with you in 2002, we 
succeeded in partnering with 22 regional CGAs covering most or 
all of 19 different States. Representatives from these 22 
regional CGAs meet 3 times a year to discuss issues, problems, 
initiatives, and solutions to problems.
    The third item is damaging information reporting tool, 
known as DIRT. CGA has worked with the Utility Notification 
Center of Colorado to develop a data-gathering system to 
provide statistical analysis of damages and the root cause of 
damage to our underground infrastructure. As a result of State 
law, the UNCC has been gathering data on all damages to the 
infrastructure in the State of Colorado since 2001 and 
publishing these results on an annual basis.
    Our data committee has worked with the UNCC to enhance the 
system and make it easy to use. And the committee is now in the 
process of trialing the system with over 30 CGA corporate 
members from the State of Connecticut. We would like to thank 
Linda Kelly, the Utilities Commissioner of Connecticut, for 
providing Connecticut's State damage information to our system.
    The National Association of State Fire Marshals is working 
with us to encourage States to collect damage data and have 
this damage data uploaded to the DIRT system. Did you know that 
in 2002, there were 12,000 damages to underground facilities in 
Colorado; 39 percent of the damages were caused by people who 
did not call before digging; nearly 60 percent of these damages 
were to communications facilities, and 27 percent to gas lines; 
in those instances where people did call before digging, 
incorrect locating accounted for more than 20 percent of the 
damages, and that excavation damage where locates were correct 
accounted for more than 50 percent of the damages; in 15 
percent of all damages, landscaping was a primary function 
being performed at the time the damage occurred? Colorado's 
tremendous statistics do enable them to address problem areas.
    The point here is not to point fingers at any one group. 
The stakeholders in Colorado have damage data to enable them to 
address their issues. Most other States aren't as fortunate and 
don't have the data to enable them to identify problem areas.
    A number of State regulators are currently considering 
damage data within their jurisdictions. We hope that those 
States consider adopting some of the practices in Colorado, 
Connecticut, and other States and consider utilizing the CGA 
system in order to have one uniform actionable National data 
base. The CGA is hopeful that the system will be used by all 
stakeholders on a Nationwide basis in order to help enable all 
of us to develop plans to reduce the approximately 400,000 
damages Nationwide.
    Last point, three-digit dialing. Your committee is amazing. 
I met with you March 19, 2002 and asked that you consider the 
implementation of a 3-digit number for access to our Nation's 
62 one-call centers. Some 9 months later, on December 17, 2002, 
President George Bush signed into law the Pipeline Safety 
Improvement Act.
    Included in this act were the words, ``Within 1 year after 
the date of enactment of this act, the Secretary of 
Transportation shall, in conjunction with the Federal 
Communications Commission, facility operators, excavators, and 
one-call notification system operators, provide for the 
establishment of a three-digit Nationwide toll-free number 
system to be used by State one-call notification systems.''
    We support the implementation of any three-digit number 
deemed appropriate by the FCC. We also support the continued 
use of #344 in the wireless community. We cannot support the 
use of a shared dual-use three-digit number.
    The CGA estimates that the 62 one-call center currently 
receives 15 million calls annually. We also estimate that 40 
percent of the damages to bird facilities were caused by those 
who did not call before digging. The potential incoming call 
volume to one-call centers over the next few years could well 
exceed 20 million. Adding an additional interface to callers 
could discourage the use of the service and reduce the 
effectiveness and purpose of the 62 centers.
    On the last point, on the 10-digit number being proposed by 
some people who opposed the 3-digit number, it just simply 
won't work. Our call centers have 10-digit numbers today and 
see no advantage to changing from one 10-digit number to 
another one.
    Having been in the telecom industry, I know the advantage 
of an easy-to-remember three-digit number. That is why telecom 
uses 411 for directory assistance and 611 for repair. It is the 
CGA's hope that a one-call center three-digit number will 
reduce the need for people to call 611 by assisting in reducing 
the estimated annual 200,000-plus damages to communications 
facilities in the country.
    Our letter to the FCC goes on to say the stakeholder groups 
represented by the CGA believe that the rapid implementation of 
this new three-digit number will help reduce facilities and 
injuries to Americans who excavate and also help reduce the 
estimated 400,000 damages to our infrastructure each year.
    Last, damage prevention is truly a shared responsibility. 
No one industry should be singled out in general discussion of 
incidences. The CGA believes that stakeholders working together 
at both the National and regional levels will make a 
difference.
    Thank you for the opportunity to testify today.
    [The prepared statement of Robert Kipp follows:]

 Prepared Statement of Robert Kipp, Executive Director, Common Ground 
                                Alliance

    Good afternoon, Mr. Chairman and members of the Committee. My name 
is Robert Kipp and I am the Executive Director of the Common Ground 
Alliance (CGA). I am pleased to appear before you today to represent 
the CGA.
    Background: The Common Ground Alliance is a nonprofit organization 
dedicated to shared responsibility in the damage prevention of 
underground facilities. The Common Ground Alliance was created just 
over three years ago at the completion of the ``Common Ground Study of 
One-Call Systems and Damage Prevention Best Practices.'' This landmark 
study, sponsored by the U.S. Department of Transportation Office of 
Pipeline Safety, was completed in 1999 by 161 experts from the damage 
prevention stakeholder community.
    The ``Common Ground Study'' began with a public meeting in 
Arlington, VA in August 1998. The study was prepared in accordance 
with, and at the direction and authorization of the Transport Equity 
Act for the 21st Century signed into law June 9, 1998 that authorized 
the Department of Transportation to undertake a study of damage 
prevention practices associated with existing one-call notification 
systems. Participants in the study represented the following 
stakeholder groups: oil; gas; telecommunications; railroads; utilities; 
cable TV; one-call systems and centers; excavation; locators; equipment 
manufacturers; design engineers; regulators; federal, state, and local 
government. The Common Ground Study concluded on June 30, 1999 with the 
publication of the ``Common Ground Study of One-Call Systems and Damage 
Prevention Best Practices.''
    At the conclusion of the study, the Damage Prevention Path Forward 
initiative led to the development of the nonprofit organization now 
recognized as the Common Ground Alliance (CGA). The CGA's first Board 
of Directors' meeting was held September 19, 2000. Building on the 
spirit of shared responsibility resulting from the Common Ground Study, 
the purpose of the CGA is to ensure public safety, environmental 
protection, and the integrity of services by promoting effective damage 
prevention practices. The CGA works to prevent damage to the 
underground infrastructure by:

 fostering a sense of shared responsibility for the protection of 
        underground facilities;
 supporting research;
 developing and conducting public awareness and education programs;
 identifying and disseminating the stakeholder best practices such as 
        those embodied in the Common Ground Study; and
 serving as a clearinghouse for damage data collection, analysis and 
        dissemination.
    The CGA now counts more than 1,150 individuals representing 15 
stakeholder groups and over 130 member organizations. Each of the 15 
stakeholder groups has one seat on the CGA Board of Directors, 
regardless of membership representation or financial participation. CGA 
members populate the organization's six working committees: Best 
Practices, Research & Development, Educational Programs, Data Reporting 
& Evaluation, Marketing, Membership, & Communications and the One Call 
Center Education Committee.
    In addition to increasing our membership by some 60% since last 
meeting with you, we have added a board seat to represent the American 
Fence Association and its members. The association estimates that 
fencing contractors dig some 120,000,000 holes per year and are excited 
to be represented within the CGA to ensure they too can help contribute 
to the damage prevention initiatives of the CGA.
    In December of 2003, the CGA welcomed the One Call Systems 
International group and their members to the CGA in the capacity of an 
education committee. The One Call Center organization was instrumental 
in the development of our Best Practices, active throughout the 
association, and the front line in damage prevention initiatives. The 
inclusion of this group in the CGA was an inevitable and a welcome 
addition to our association.

                           WORKING COMMITTEES

    The CGA working committee guidelines include:

 All stakeholders are welcomed and encouraged to participate in the 
        Committees' work efforts.
 Committee members represent the knowledge, concerns and interests of 
        their constituents.
 A ``primary'' member is identified within each Committee for each 
        particular stakeholder group as the spokesperson for consensus 
        decisions.
A. Best Practices Committee
    To promote damage prevention, it is important that all stakeholders 
implement the damage prevention Best Practices currently identified in 
the Common Ground Study Report, as applicable to each stakeholder 
group. The Best Practices Committee focuses on identifying those Best 
Practices that are appropriate for each stakeholder group, gauging 
current levels of implementation and use of those Best Practices, and 
encouraging and promoting increased implementation of the Best 
Practices.
B. Research and Development Committee
    The Research & Development Committee's primary role is to promote 
damage prevention research and development and serve as a clearing 
house for gathering and disseminating information on new damage 
prevention technologies and practices. The Research and Development 
Committee seeks to identify new technologies and existing technologies 
that can be adapted to damage prevention.
C. Educational Programs Committee
    The Educational Programs Committee develops and communicates public 
stakeholder awareness and educational programs. These programs and 
products focus on the best practices and the theme of damage 
prevention. The Committee looks at existing damage prevention education 
programs to identify opportunities where the CGA can have significant 
impact in furthering the reach and effectiveness of those programs, and 
the Committee develops new educational messages and items.
D. Data Reporting and Evaluation Committee
    The Data Reporting & Evaluation Committee looks at currently 
available damage data, the gaps where additional data reporting and 
evaluation is needed, and how such data for various underground 
infrastructure components can best be gathered and published. Reporting 
and evaluation of damage data is important to: measure effectiveness of 
damage prevention groups; develop programs and actions that can 
effectively address root causes of damages; assess the risks and 
benefits of different damage prevention practices being implemented by 
various stakeholders; and assess the need for and benefits of education 
and training programs.
E. Marketing, Membership, & Communication Committee
    The CGA Marketing, Membership, & Communications Committee (MM&C) 
pursues opportunities where it can best promote the organization to 
increase sponsorship and membership. The Committee is also dedicated to 
the adoption of the Best Practices and promotion of damage prevention 
at the local level, and the committee has developed the CGA's Regional 
Partner Program to further this effort.
F. One Call Center Education Committee
    The purpose of One-Call Systems International (OCSI) is to promote 
facility damage prevention and infrastructure protection through 
education, guidance and assistance to one call centers internationally.

                               ACTIVITIES

                        A. NTSB RECOMMENDATIONS

    In July of 2001, the Office of Pipeline safety requested CGA's 
assistance in resolving and responding to a number of outstanding 
National Transportation Safety Board recommendations. In the past 3 
years the CGA contributed to the closing of 8 of 9 NTSB 
recommendations. The ninth recommendation was directed to the CGA in 
2003 and is currently in committee. The 8 recommendations deemed 
``Closed--Acceptable'' by the NTSB are as follows;
NTSB Recommendation P-00-01
 Resulting from the NTSB report, ``Natural Gas Pipeline Rupture and 
        Subsequent Explosion, St. Cloud, Minnesota, December 11, 
        1998''--a review of safety recommendations regarding the use of 
        E-911 when excavation damage occurs for inclusion to CGA Best 
        Practices. As a result of this report, the Office of Pipeline 
        Safety requested that the CGA review the existing Best Practice 
        and determine if the NTSB recommendation P-00-1 should be 
        included as a ``New Best Practice.''
 The recommendation from the NTSB report read: ``To advise excavators 
        to call ``911'' if the damage to the pipeline results in a 
        release of gas or other hazardous substance or potentially 
        endangers life, health or property.''
 Prior to the Recommendation the Best Practice on this issue left it 
        to the excavator to determine if the release of gas or 
        hazardous substance posed a danger, and if so, to determine if 
        911 should be called.
      The CGA Best Practices Committee reviewed the recommendation and 
        unanimously approved a change to the Best Practice to reflect 
        the following:
        Practice Statement (Best Practices Committee Approved by 
        Consensus 11/27/01)
        ``If the damage results in the escape of any flammable, toxic, 
        or corrosive gas or liquid or endangers life, health, or 
        property, the excavator responsible immediately notifies 911 
        and the facility owner/operator.''
 Following additional language approved by Board on September 27, 2002 
        (TR 2001--2B):
        ``The excavator takes reasonable measures to protect themselves 
        and those in immediate danger, general public, property, and 
        the environment until the facility owner/operator or emergency 
        responders have arrived and completed their assessment.''
NTSB Recommendation P-01-01
    Following a natural gas explosion in South Riding, Virginia 
(Loudoun County), which resulted in one death, a number of injuries, 
and damage to a number of homes, the NTSB recommended that a Best 
Practice be developed regarding minimum separation of electric and 
plastic gas pipes in common trenches.

 Following wording approved as a CGA Best Practice by Board on 
        September 25, 2003:
        ``When installing new direct buried supply facilities in a 
        common trench, a minimum of 12 inch radial separation should be 
        maintained between supply facilities such as steam lines, 
        plastic gas lines, other fuel lines, and direct buried 
        electrical supply lines. If 12 inches separation cannot be 
        feasibly attained at the time of installation, then mitigating 
        measures should be taken to protect lines against damage that 
        might result from proximity to other structures. Examples may 
        include the use of insulators, casing, shields or spacers. If 
        there is a conflict among any of the applicable regulations or 
        standards regarding minimum separation, the most stringent 
        should be applied.''
NTSB Recommendation P-97-16,17 & 18
 P-97-16: Sponsor independent testing of locator equipment performance 
        under a variety of field conditions.
 P-97-17: Develop uniform certification criteria for locator 
        equipment.
 P-97-18: Review State requirements for location accuracy and hand dig 
        tolerance zones and applicability.
    The Research and Development Committee of the CGA addressed the 
above recommendations in 2 reports filed with the Office of Pipeline 
Safety in 2003. These reports were subsequently forwarded to the NTSB. 
The 3 recommendations were closed-acceptable by the NTSB.
NTSB Recommendation P-97-22, 23 & 24
 P-97-22: In conjunction with the American Public Works Association 
        (APWA), develop a plan for collecting excavation damage 
        exposure data.
 P-97-23: Work with the one-call systems to implement the plan 
        outlined in P-97-22 to ensure that excavation damage data are 
        being consistently collected.
 P-97-24: Use the excavation damage exposure data outlined in P-97-22 
        in the periodic assessments of the effectiveness of State 
        excavation damage prevention programs described in 
        Recommendation P-97-15.
    The CGA has worked with the Utility Notification Center of Colorado 
to develop a Data gathering system to provide statistical analysis of 
damages and the root causes of damage to our underground 
infrastructure.
    As a result of State Law, the UNCC has been gathering data on all 
damages to the underground infrastructure in the State of Colorado 
since 2001, and publishing these results on an annual basis. Our Data 
committee has worked with the UNCC to enhance the system and make it 
easy to use, and the committee is now in the process of trialing the 
system with over 30 CGA corporate members.
NTSB Recommendation P-98-25
 P-98-25: Require pipeline system operators to precisely locate and 
        place permanent markers at sites where their gas and hazardous 
        liquid pipelines cross navigable waterways.
    The recommendation, received by the CGA in 2003 is in committee and 
resolution is expected within the year.

                           B. BEST PRACTICES

    During the past two years the Best Practices Committee has reviewed 
over thirty practice proposals, developed and approved three new 
practices, and finalized an updated publication of the best practices.

 The committee receives new practice proposals from CGA members and 
        industry representatives throughout the year. The committee is 
        dedicated to following a process for review and approval of 
        these practices that meet the ``consensus'' standards set by 
        the CGA to ensure agreement by all stakeholder groups.
 The committee approved a practice in 2004 relating to the separation 
        of gas and electric utilities that assisted with the closure of 
        NTSB recommendation P-01-01. The closure of P-01-01 followed 
        the committee's assistance with the 2001 closure of P-00-01. 
        The committee also approved a practice relating to quality 
        assurance programs for locating and marking of facilities.
 The latest version of the practices, Best Practices Version 1.0, was 
        published in December 2003 and has been distributed at over 100 
        industry events and has reached well over 10,000 stakeholders.
New Practices (Reference):
Approved by CGA Board--March 26, 2004
 Practice Statement: Underground facility owners/operators have a 
        Quality Assurance program in place for monitoring the locating 
        and marking of facilities.
 Practice Description: The process of conducting audits for locates is 
        a critical component to the protection of underground 
        facilities. The recommended components included in the 
        description were assembled from multiple sources and are meant 
        to provide general guidelines for auditing the work of 
        locators.
Approved by CGA Board--September 26, 2004
 Practice Statement: When installing new direct buried supply 
        facilities in a common trench, a minimum of 12 inch radial 
        separation should be maintained between supply facilities such 
        as steam lines, plastic gas lines, other fuel lines, and direct 
        buried electrical supply lines. If 12 inches separation cannot 
        be feasibly attained at the time of installation, then 
        mitigating measures should be taken to protect lines against 
        damage that might result from proximity to other structures. 
        Examples may include the use of insulators, casing, shields or 
        spacers. If there is a conflict among any of the applicable 
        regulations or standards regarding minimum separation, the most 
        stringent should be applied.

                        C. EDUCATIONAL PROGRAMS

    The Educational Programs Committee develops and communicates public 
stakeholder awareness and educational programs. These programs and 
products focus on the best practices and the theme of damage 
prevention. The Committee looks at existing damage prevention education 
programs to identify opportunities where the CGA can have significant 
impact in furthering the reach and effectiveness of those programs, and 
the Committee develops new educational messages and items.
    The CGA directed an OPS sponsored survey, which determined 
awareness levels of various population segments with respect to 
underground facilities. With the findings in hand, the CGA embarked on 
an educational campaign targeting the agricultural community. With 
funding from OPS in the form of a cooperative agreement, the CGA 
developed a radio and print campaign targeted to this community. 
Materials developed for this campaign, (radio public service 
announcements and print media), have been made available to our members 
and are being utilized by some of these members in their educational 
campaigns.
    Our Educational Programs Committee has developed the outline of the 
substantial awareness campaign in anticipation of the announcement of a 
3-Digit number for One Call Centers. The CGA has also published ``Best 
Practices Version 1.0'' for distribution to all CGA members and 
regional partners in 2003. As of July 14, 2004, more than 10,000 copies 
have been distributed. Version 2.0 which will include best practices 
developed in 2004 is scheduled for print and distribution later this 
year.

                  D. DAMAGE INFORMATION REPORTING TOOL

    Though addressed earlier in the CGA has worked with the Utility 
Notification Center of Colorado to develop a Data gathering system to 
provide statistical analysis of damages and the root causes of damage 
to our underground infrastructure. As a result of State Law, the UNCC 
have been gathering data on all damages to the underground 
infrastructure in the State of Colorado since 2001, and publishing 
these results on an annual basis. Our Data committee has worked with 
the UNCC to enhance the system, make it easy to use, and is now in the 
process of trialing the system with some 30 CGA corporate members.
    The CGA is hopeful that this system will be used by all 
stakeholders on a nationwide basis, in order to help the industry 
gather the statistical data that will enable us to develop plans to 
help us reduce the approximately 400,000 damages nationwide.
    Many companies are reluctant to utilize the system or upload their 
data into the CGA Damage Information Reporting Tool (D.I.R.T.). Some of 
the concerns expressed by those who would utilize this system revolve 
around the information being used in litigation against those who 
provide the data, being used by competitors should the security of the 
data be compromised.
    A number of state regulators are currently considering gathering 
damage data within their jurisdictions. We hope that those states 
considering adopting some of the practices in Colorado, Connecticut and 
other states, consider utilizing the CGA system in order to have one 
uniform, actionable national database.

                          E. REGIONAL PARTNERS

    In 2002, it was proposed that the CGA accept petitions from 
regional groups as ``partners'' to the CGA. With assistance from OPS, 
the CGA Regional Partner Program was implemented in 2002 and has since 
grown to 22 partners. The first annual Regional Partner meeting was 
held December 3, 2003, bringing representatives of all CGA regional 
partner programs together to develop a program roadmap.
    The Regional CGA's include: Alberta Utility Coordinating Council; 
Blue Stakes of Utah; Central Texas DPC; Denver Metropolitan; El Paso 
County (Colorado); Georgia Utilities Coordinating Council; Greater 
Columbus DPC; Greater Toledo DPC; Greater Youngstown DPC; Miami Valley 
DPC (Ohio); Michigan Damage Prevention Board; Minnesota Utility 
Alliance; Missouri Common Ground; Northeast Illinois DPC; Northwest 
Region CGA; Oklahoma CGA; Ontario Region CGA; Quebec Regional CGA; 
Tennessee DPC; Utilities Council of Northern Ohio; Western Region CGA; 
and Wisconsin Underground Contractors Association.

                           F. 3-DIGIT-DIALING

    On December 17, 2002, President George W. Bush signed into law the 
``Pipeline Safety Improvement act of 2002.'' Included in this Act was 
the following provision:
    ``Within 1 year after the date of the enactment of this Act, the 
Secretary of Transportation shall, in conjunction with the Federal 
Communications Commission, facility operators, excavators, and one-call 
notification system operators, provide for the establishment of a 3-
digit nationwide toll-free telephone number system to be used by State 
one-call notification systems.''
    Subsequent to the Act, the F.C.C. began looking into the logistics 
of implementing this provision. Following a number of technical 
meetings of telecom personnel, public hearings, and no doubt, internal 
meetings on the matter, the F.C.C. addressed this issue at a public 
meeting on May 13, 2004. A Notice of Proposed Rulemaking followed 
shortly thereafter, with publication in the June 8, 2004 Federal 
Register. On all matters related to this issue, the F.C.C. requested 
responses by July 8, 2004, and replies to these by July 23, 2004. I am 
certain that the F.C.C. will move expeditiously to determine which 3 
digit number to implement, and determine an aggressive timeline for its 
implementation.
    Following is the text contained in the CGA response to the F.C.C.
          We would like to congratulate the Commission on their 
        willingness and desire to move expeditiously towards assigning 
        and implementing a nationwide 3 digit number for access to our 
        nation's 62 One Call centers.
          In addition to being in the best interest of our nation, 
        implementing a nationwide 3 digit telephone number is required 
        by the Public Law 107-355, the Pipeline Safety Improvement Act 
        of 2002. This act was signed into law by President Bush on 
        December 17, 2002.
          As previously stated in our letter dated November 4, 2003, 
        the Common Ground Alliance (CGA) and the 15 stakeholder groups 
        represented by the CGA will support the implementation of any 3 
        digit number deemed appropriate by the FCC.
          We also support the continued use of ``#344'' in the wireless 
        community, in addition to the 3 digit number chosen by the FCC. 
        We believe this number should be available as an alternative to 
        the new 3 digit number for as long as the wireless community 
        chooses to support this number. The wireless community deserves 
        to be recognized and congratulated for their leadership in the 
        movement to provide abbreviated dialing to their users in order 
        to reduce damages to underground infrastructure, personal 
        injuries, and deaths.
          We can not support the use of a shared (dual use), 3 digit 
        number. The CGA estimates that the 62 One Call centers 
        currently receive 15,000,000 calls annually. We also estimate 
        that some 40% of damages to buried utilities were caused by 
        those who did not call before digging. The potential incoming 
        call volume to One Call centers over the next few years could 
        well exceed 20 million. Adding an additional interface to 
        callers could discourage the use of the service and reduce the 
        effectiveness and purpose of the 62 centers.
          We also can not support the use of a 10 digit number. One 
        Call centers currently have 10 digit numbers. Converting to a 
        new number would not benefit the country and would be rejected 
        by most, if not all of the centers. Public Law (PL) 107-355 
        clearly mandated a 3 digit number be implemented.
          Paragraph 16 of the Federal Register states in part that 
        ``When a caller dials the abbreviated dialing code, the 
        carriers would translate the abbreviated dialing code into the 
        appropriate toll-free or local number.'' This is an important 
        aspect of the process. In locations such as Arizona, the One 
        Call center (Arizona Blue Stake) receives nearly 50% of its 
        calls through the local 7 digit number. To translate all of the 
        3 digit calls to a toll free 10 digit number would add an 
        unnecessary cost burden to this center.
          We congratulate and thank the Honorable Chris John for 
        introducing and sponsoring 3digit dialing as a provision to the 
        ``Pipeline Safety Improvement Act of 2002.'' We congratulate 
        the commissioners on their unanimous support of this endeavor. 
        In his statement Commissioner Michael J. Copps states:
          ``The very first sentence of the Communications Act states 
        that the Act was written to make ``available . . . a rapid, 
        efficient, Nation-wide and world-wide telecommunications 
        service . . . for the purpose of promoting safety of life and 
        property through the use of wire and radio communication.'' So 
        our charge and authority are clear. Now the need is to move 
        ahead expeditiously--to ensure that excavators everywhere can 
        dig safely and avoid disrupting the nation's essential 
        services.''
          The 15 stakeholder groups represented by the CGA believe that 
        the rapid implementation of this new 3 digit number will help 
        reduce fatalities and injuries to Americans who excavate and 
        also help reduce the estimated 400,000 damages to our 
        infrastructure each year.

                                CLOSING

    When preparing for this testimony, I reviewed the Closing remarks 
in the March 19, 2002 testimony. Other than changing one name the 
comments remain the same. The Common Ground Alliance is a true member-
driven organization. Members from the 15 stakeholder groups work 
together to determine direction and problem-solve, making the CGA a 
truly unique forum. We would not exist without the immense dedication 
and effort of our members as well as the financial and logistical 
support of Mr. Sam Bonasso (RSPA) and Ms. Stacey Gerard (OPS).
    Our greatest strengths can be summarized as follows:
          When the CGA proposes a policy, solution or response to a 
        government or corporate body, the wording of such a proposal 
        has been agreed to by primary members representing every 
        stakeholder group within the CGA. The receiving body of a CGA 
        proposal knows that no one industry has a vested interest, and 
        that all stakeholder groups agree with the content and wording 
        of such a proposal.
          In addition, the CGA has brought together industry leaders on 
        a National basis to work together and help fund the Alliance in 
        its effort to reduce damage to our nation's underground 
        infrastructure.
          Lastly, in addition to all of the wonderful accomplishments 
        in education, best practice development, data gathering, and 
        research and development, the CGA is now reaching for and 
        succeeding in bringing together stakeholders at a local level. 
        We believe it to be successful, and we must continue to 
        encourage and promote communication, problem resolution, and 
        the adoption of the Best Practices within local communities as 
        well as on a national level.

    Mr. Hall. Thank you.
    I guess the questioning period will start now. How much 
time am I allowed? I will take 5 minutes. I will recognize 
myself for 5 minutes.
    Mr. Fischer, where is home for you?
    Mr. Fischer. Dallas, Texas.
    Mr. Hall. Not from up in Cook County and that area?
    Mr. Fischer. No. I've lived in Dallas about 5 years now.
    Mr. Hall. Your testimony states, ``When measured by total 
installed miles per pipeline category using DOT statistics over 
the last 10 years, it is clear that gas distribution systems 
have fewer fatalities and injuries per mile than all of the 
other pipeline categories combined.''
    The inspector general's testimony states, ``Over the last 
10 years, natural gas distribution pipelines have experienced 
over 4 times the number of fatalities and more than 3 and a 
half times the number of injuries than the combined total of 43 
fatalities and 178 injuries for hazardous liquid and natural 
gas transportation pipelines.''
    How do you reconcile the two statements?
    Mr. Fischer. Having not had access to the latter, I am 
going on the statistics gathered by the American Gas 
Association on distribution systems, sir.
    Mr. Hall. You don't know what they relied on in their 
testimony?
    Mr. Fischer. No, I don't, but I would be glad to submit 
that.
    Mr. Hall. Okay. If you can, that would be fine. Let me ask 
you further. Your testimony notes that over 60 percent of the 
total ruptures on pipelines is caused by third party damage.
    Mr. Fischer. Yes, sir.
    Mr. Hall. Who causes the other 40 percent?
    Mr. Fischer. I guess it is a multi combination of things, 
Mr. Chairman. Again, we have relied heavily on the third call 
party system to get this number of accidents down, but they are 
probably mostly corrosion, I would have to think. External 
corrosion-type leaks that have been undetected would make up a 
majority of that.
    Mr. Hall. I thank you.
    Mr. Pearl, in your testimony when discussing the pipeline 
repair permit streamlining, you stated, and I quote, ``The 
purpose of section 16 is to ensure timely actions required by 
one Federal agency, OPS, in the name of pipeline safety are not 
blocked by one or more other Federal agencies that do not have 
pipeline safety as a priority.'' But the purpose of that was to 
ensure timely action in the name of pipeline safety, that 
they're not blocked by one or more.
    Do you know why the other agencies would either block or 
delay actions on permits necessary for pipeline repairs?
    Mr. Pearl. Well, I don't think various agencies or 
stakeholders are blocking permits to cause more accidents. It's 
just they get hung up in their own parochial areas. The net 
effect is for delays.
    Mr. Hall. And as such, they block or delay action on 
permits?
    Mr. Pearl. Yes. And that's the end result of that. I think 
we provided in our testimony several cases where companies were 
not able to comply with the time lines required by OPS because 
of permitting delays.
    Mr. Hall. I might have missed that. Are you aware of any 
specific examples? I thought you said you noted some in your 
testimony. I don't remember seeing that, but it could surely be 
in there.
    Mr. Pearl. These weren't spills. These were permit or 
repair delays caused by the inability to get permits. 
Fortunately, there hasn't been a major incident where a spill 
has directly been related to delayed permitting.
    However, I think the oft noted Kinder Morgan incident in 
San Francisco, there they were doing more than just repairing 
the pipeline. They were rerouting it. But the 3-year delay, had 
there been more timely permitting, that spill clearly would not 
have occurred because you had new pipe in in a less sensitive 
area.
    Mr. Hall. Can you give me specific examples of where timely 
actions were required by a Federal agency and they were blocked 
by other Federal agencies?
    Mr. Pearl. Yes. As I mentioned, we filed eight of those in 
my written testimony. I can refer to those if you would like.
    Mr. Hall. No. Just tell me where they are, and I will look 
for them.
    Mr. Pearl. Well, I am aware of at least one in California.
    Mr. Hall. No. I mean in your testimony, what pages?
    Mr. Pearl. I think it is filed as a supplement.
    Mr. Hall. Okay. Well, that is the reason.
    Mr. Pearl. Yes. There are several. There is one in the 
Delaware River. There is one in California. There are eight in 
total that we filed.
    Mr. Hall. Do you know of any examples in which a pipeline 
repair was held up waiting for permits and a release occurred?
    Mr. Pearl. No. I would say the one that would be the most 
related to that would be the Kinder Morgan case, where it was 
more than just permitting they were doing.
    Mr. Hall. All right. I thank you. My time has expired. I 
recognize Mr. Boucher, the gentleman from Virginia.
    Mr. Boucher. Well, thank you very much, Mr. Chairman. And I 
want to join with you in thanking each of these witnesses for 
sharing their views with us on what I think is a very timely 
subject.
    Mr. Fischer, I would like to pose a question to you. You 
might pull that microphone over in front of you. We can hear 
you better when you do that. Thank you.
    You heard the Inspector General Mr. Mead testify on the 
previous panel that in his view, the integrity management plans 
that now apply to transmission lines should also apply to 
natural gas distribution lines. And I know that the foundation 
associated with the American Gas Association is examining that 
question.
    Mr. Fischer. Right, sir.
    Mr. Boucher. My understanding is the foundation will 
release a report on its conclusions sometime later this year.
    Mr. Fischer. That's correct, sir.
    Mr. Boucher. Would you care to preview some of the 
considerations the foundation has undertaken and perhaps give 
us a sense of what its conclusions may be on that subject?
    Mr. Fischer. I really don't have a sense of conclusion 
because I think the debate is going on, even among the 
organizations that are participating, to arrive at a good 
consensus on that.
    I did think the Inspector General was certainly correct in 
saying that yes, we need to turn now and look at distribution 
lines certainly, but to impose the same system on--and I'm 
trying to capture some of the consensus of the debate that is 
going on--to impose those regulations on distribution lines 
when it is an entirely different type of system, not long 
cross-country lines, a network, a web, a tie-in, something that 
smart pigging cannot go in is almost an impossible situation in 
our end of the business.
    However, we do not want to give out any sense of an image 
of not wanting good integrity on our pipelines. We are very 
much engaged, if you will, through State jurisdictions now, 
routine inspections, priority grading systems, mandated 
inspections from State regulators. And what we would like to 
see is a collaborative process among all of these organizations 
to find out what does work in distribution systems.
    I would very much encourage some of the things that you 
named while you were addressing the first panel that really 
would be probably instrumental in bringing some of these 
accident situations down. That is supporting a one-call system 
to continue our operator qualification requirements that come 
under pipeline integrity management but to look now at the next 
phase of education of those operators.
    So there are many things we can do. It's just to 
superimpose one upon the other probably would not be the 
solution.
    Mr. Boucher. Well, let me make a suggestion. I appreciate 
that answer. And I understand your reluctance today to prejudge 
what your foundation's report is going to say, but let me make 
a recommendation.
    I think it would be in your industry's interest to come 
forward with an affirmative recommendation for the application 
of integrity management plans to distribution lines bearing in 
mind that a different kind of integrity management plan would 
be required for distribution lines than are required for 
transmission lines.
    Mr. Fischer. Yes, sir.
    Mr. Boucher. Your diameters are thinner. There are more 
curves, I am sure, than distribution lines than there are in 
transmission lines. The physical characteristics of these lines 
would necessitate a different set of integrity management plans 
and perhaps the use of different technologies in order to do 
sensing of the line itself.
    I tried to ask Mr. Mead if he had some suggestions for what 
the elements of integrity management plans might be for 
distribution lines, as distinct from transmission lines, and he 
offered a few, including pressure sensing and other kinds of 
observation.
    I think in order to move the subject forward, it would be 
extremely helpful if your foundation's report when it is issued 
later this year lists some of the things that it would be 
appropriate to include in integrity management plans as applied 
to distribution lines. And I very much look forward to seeing 
that report.
    I know Mr. Mead has recommended that the Office of Pipeline 
Safety provide a formal response to the Congress by March of 
next year. I hope the office will do that. Perhaps, Mr. 
Chairman, at the appropriate time next year, we could have 
another hearing that addresses the recommendations of your 
foundation, the response of the Office of Pipeline Safety, and 
the views of other witnesses concerning that matter. And I want 
to thank you Mr. Fischer for your answer.
    In the couple of seconds that I have--did you want to say 
something?
    Mr. Fischer. No, no. Just I think that is right on target. 
And I hope we do get the invitation to come back as we wrap 
that up. And we can add specificity to it. Thank you.
    Mr. Boucher. Thank you.
    In the brief time I have remaining, which is now 1 second, 
I would like to ask Mr. Koonce if Dominion is planning to build 
on the success that your company has enjoyed in operating your 
Cove Point liquified natural gas importation facility by 
examining the possibility of building additional LNG facilities 
in other locations.
    Mr. Koonce. We are looking at the opportunity of additional 
LNG import facilities throughout the Eastern seaboard, where we 
operate. But, really, our first mission has been to bring the 
facility, which was mothballed for in excess of 30 years, back 
to commercial operation. We did that last August.
    We recently announced an expansion of the Cove Point 
facility doubling in size, our partner in that being the State 
Oil Company in Norway. So we are most right now immediately 
focused on doing the environmental work, the pre-site work to 
bring that additional supply into the region in a timely 
fashion.
    Now, looking at other opportunities up and down the Eastern 
seaboard, we believe there are a couple of other opportunities 
where expansion may go forward. Whether there is Dominion 
directly participating in that expansion or other members of 
the industry I think the business case will vet that out.
    Mr. Boucher. Thank you very much, Mr. Koonce. Thank you, 
Mr. Chairman.
    Mr. Hall. Thank you, Mr. Boucher.
    The Chair recognizes the gentleman from Illinois, Mr. 
Shimkus.
    Mr. Shimkus. Thank you, Mr. Chairman.
    This is a good hearing. I always like to wrap it around the 
whole energy debate and comprehensive energy plan because when 
we piecemeal things, we see the trees and we are not seeing the 
forest.
    The reality is, as we said in the refinery discussions of 
last week, I mentioned that a company was just ecstatic that 
they wanted to pipe Western heavy Canadian crude from western 
Canada all the way down to the Gulf Coast, to crack it there 
because of our inability to build refineries in this country 
shows the importance of pipelines.
    Another company talked to me about in the debate on the LNG 
they're excited about building an LNG facility I think in the 
Bahamas in which they will because of the inability to cite LNG 
facilities in the United States. And then they will pipe the 
natural gas to Florida. Again highlighting the importance of 
pipelines today and pipelines in the future, if we don't build 
refineries, if we don't place LNG facilities, pipelines are 
only going to take an ever-increasing role. So this is 
important to discuss.
    My father-in-law was a microwave technician to help build 
the Alaskan pipeline. So he was in the telecommunications era. 
That is really past its operational design--I wouldn't want to 
say past its use, but they projected 25 or 30 years. I don't 
have its stats before me, but now it's fulfilled its longevity, 
and it is still operating, as are numerous things that we build 
and operate in this country, which brings the debate on how 
long things that we build withstand and last and how do you 
maintain them and how do you inspect them and the like, 60 
percent being third party intrusions, 40 percent being probably 
corrosion and natural aging. So it's a debate as to how do we 
check them.
    Now, what I have learned in the hearing is about the famous 
pig and its ability being placed in the compressing stations of 
75 to 100 miles apart, probably mostly not in the transmission 
system primarily because of the size and the distribution 
system, as the ranking member said, having additional 
challenges because of the curves and the like.
    I think the public wants to do all we can to ensure that we 
have safety, not just fear of the loss of life, which is a 
major concern, but, as I said in the opening statement, the 
disruption. I mean, if we are relying on imported oil or 
imported refined product or natural gas, any disruption of a 
pipeline facility will cause major economic challenges to this 
country.
    The one question I have in Mr. Beggs' statement that 
``Large corporations can shield themselves from liability for 
poor safety practices through certain strategies, such as 
holding assets that may generate liability,'' Mr. Pearl, do you 
agree with that statement? And how many of the companies of 
your association practice that type of management?
    Mr. Pearl. Well, I think it would be best if I first speak 
from personal experience. And I can talk a little broadly.
    Mr. Shimkus. That's always great to do that.
    Mr. Pearl. Yes. I have had the privilege of having 
leadership roles in three different pipelines companies. That 
whole notion just is not realistic from my vantage point. If my 
company has a spill, we are responsible. We clean it up. We pay 
whatever fines. We suffer the loss of business. We suffer the 
customer dissatisfaction.
    So I think that though there may be some complications in a 
given case, the bottom line is pipeline companies are 
responsible for what they do. And they pay the bills associated 
with that. So we take this burden very seriously.
    Mr. Shimkus. Thank you.
    Mr. Beggs, what was the cause of the disruption? That was 
before my time. I don't really know the story.
    Mr. Beggs. Sure. Bellingham, there were several causes. 
They had smart pigged the Olympic pipeline. They knew there was 
a problem. There was some debate about whether it was caused by 
a bulldozer or not a few years earlier. They knew there was a 
problem. They were told they should fix it. They didn't fix it. 
They had a valve misfunction, shut down the pipeline, the 
increasing pressure blew out at that one point into a park and 
then exploded.
    I would like to mention Olympic Pipeline is owned by BP, 
which has lots of money. Olympic's main asset is the pipeline. 
They don't have enough money to pay for the damage. And they 
are in bankruptcy.
    Mr. Shimkus. Well, let me just follow up. Who has not been 
paid?
    Mr. Beggs. One, I don't think they have paid the fines that 
the government imposed on them. Two----
    Mr. Shimkus. You don't think or you know? It is my 
impression that the victims were paid, the fines and penalties 
were paid. In fact, the Federal Government has settled. And 
that is the basis for your organization at the tune of $4 
million.
    Maybe you could help us. If there are any outstanding 
persons caused harm that have not been reconciled through this 
accident to get that for us because it is our understanding 
that everyone has been settled.
    Mr. Beggs. I think one way to clarify that is that there 
was both Equilon, which was helping the management, and 
Olympic. Equilon paid the majority of those fines. I'm 90 
percent sure that Olympic itself has not paid its fines yet 
because they are in bankruptcy.
    The biggest outstanding damage that hasn't been paid is 
actually another oil company, ARCO, who had to pay about $500 
million extra in alternative transportation. They have sued 
Olympic. Olympic went into bankruptcy to avoid having to pay 
ARCO.
    There are other people with claims out there, but I would 
say the three families that lost their children, they have been 
paid. The park land has been retroed. I believe Equilon and 
Olympic have now settled up with each other. I am not sure of 
the details. But there is still a $500 million bill out there 
that hasn't been paid, and they are in bankruptcy.
    Mr. Shimkus. Mr. Chairman, I know we are short for time, 
but I think Mr. Koonce wanted to respond to this line of 
questioning.
    Mr. Hall. You went over your time sitting here as chairman. 
So I will grant you another 3 minutes.
    Mr. Shimkus. Thank you. Just enough for Mr. Koonce to 
follow up. Thank you, Mr. Chairman.
    Mr. Koonce. Yes, sir. Thank you for the opportunity. Just 
to comment about the Bellingham accident, three officers have 
gone to jail as a result of the accident that occurred due to 
negligence.
    So, in addition to there being tremendous financial 
deterrence, as he has described the bankruptcy, which is the 
ultimate financial deterrence, there is also criminal liability 
associated with failure to operate natural gas or oil pipelines 
in a safe manner. And I think that serves as the ultimate 
deterrent to responsible operation of these facilities.
    Mr. Shimkus. I am not trying to get into a finger-pointing. 
The reality is we need these systems. They need to be safe. And 
people who are negligent need to be held accountable. And I 
think if that is our basis, I think we can move forward with 
any type of reforms.
    Thank you, Mr. Chairman. I yield back.
    Mr. Hall. Thank you.
    The Chair recognizes the gentleman from Arizona, Mr. 
Shadegg.
    Mr. Shadegg. Thank you, Mr. Chairman.
    I want to begin, Mr. Pearl, with you and follow up on a 
line of questioning that the chairman had with regard to one 
agency trying to get a pipeline either repaired or perhaps 
installed and other Federal agencies delaying that process. 
There is reference to that in your testimony.
    In other legislation; in fact, in the energy bill, which 
this committee cleared some time ago and which is languishing 
in the Senate, I was able to insert language making the DOE the 
lead agency for citing transmission lines. And if other Federal 
agencies had statutory authority to become involved in that 
process, DOE could then essentially set deadlines by which 
those other Federal agencies had to meet their responsibilities 
so that the agency in charge of that area--in this case, DOE, 
it was electricity we were talking about--would be able to 
essentially compel other Federal agencies or block other 
Federal agencies from delaying the process.
    Is that something which you think needs to occur in this 
area or is that something which you think the law already 
provides in this area but it isn't working?
    Mr. Pearl. Well, not being a lawyer, I won't comment on 
what the law provides. I would just from a practical 
standpoint. Although under previous questioning, really, 
fortunately, other than the Kinder Morgan situation that is 
certainly related to permitting where a spill could have been 
prevented in hindsight, we haven't had a major issue yet with 
respect to complying with the OPS rules. I believe we have had 
a number of we will call them market near misses, where had we 
not had good cooperation with permitting, we would have had 
delays that you weren't going to compromise pipeline safety, 
but there would have been other issues involved.
    In some of my prepared remarks, which I wasn't able to get 
through because of time, we had a situation last year where we 
found some anomalies in a pipe that serves 40 percent of New 
York's and Pennsylvania's propane supply.
    Fortunately, we had good cooperation. We had a major repair 
situation under a reservoir. We got the permits quickly and 
were able to avoid a serious supply issue. That supply issue is 
not just economic. It would force product into less safe, less 
efficient modes of transportation.
    So the issue of pipeline permit streamlining is one where 
to do the work required by DOT--and we are totally supportive 
of that as an industry. We just need to be able to make sure 
that we can get timely permits to get the job done, not only to 
make the pipes safe because that is obviously the first 
priority. You are not going to operate because of all of the 
other ramifications without it being safe but also to serve the 
overall----
    Mr. Shadegg. I would like to work with you and the 
industry. If similar legislation is needed here so that there 
is a lead agency that can, I would be happy to work with you.
    Mr. Pearl. Certainly everybody would like to have one 
person, one agency that is responsible, that is accountable for 
getting the permits done.
    Mr. Shadegg. I am glad you mentioned Kinder Morgan.
    I wanted to question the other panel. Unfortunately, I had 
to speak on the floor because Kinder Morgan has been deeply 
involved in the Arizona issue, where we had a gas pipeline a 
year ago go bad on us. And the price of gasoline in my 
community went to over $3 a gallon and caused a lot of 
disruption. We had an inadequate variety of supply coming into 
Arizona, putting us in a dismal spot.
    Mr. Koonce, I want to ask you. In his testimony, Mr. Beggs 
says that only 7 percent of the total mileage of gas 
transmission lines will ever be tested under the integrity 
management rule. He cites OPS for that point.
    Your testimony, however, says that effectively 60 or 70 
percent will have to be tested. I would like to give you an 
opportunity to explain that difference.
    Mr. Koonce. Yes. I appreciate the opportunity to clarify. 
The way the integrity management plan is drafted, 100 percent 
of the high-consequence areas of a pipeline must be inspected. 
What I was alluding to as to what the industry will get is much 
more than that.
    While that is the technical reading of the integrity 
management plan, by use of the smart pig device and the way 
that that is introduced into the system, we will, in essence, 
be inspecting hundreds of miles of pipe to get at the three or 
four miles of pipe that are within the high-consequence area.
    As an example, my company, we have got about 3,500 miles of 
high-pressure long-line transmission system. But of that, about 
300 miles are high-consequence areas. In order to get to the 
high-consequence areas, we will have to inspect essentially 100 
percent of the 3,000 miles.
    Mr. Shadegg. Mr. Beggs, do you acknowledge that point?
    Mr. Beggs. Yes. Our point was simply the way the 
regulations only require 7 percent if the industry goes beyond 
the----
    Mr. Shadegg. I think that helps the committee understand 
the two different positions.
    Mr. Beggs. Yes.
    Mr. Shadegg. Mr. Koonce, I want to ask one more question of 
you. In your testimony, you talked about OPS and about not 
moving OPS. And you used the phrase ``line of sight,'' 
``Congress' line of sight ability to be involved in this 
area.'' I am not sure I understand that reference, and I would 
appreciate an explanation.
    Mr. Koonce. Sure. This hearing as an example, to call this 
specific area of DOT before Congress to ask the hard questions 
about how are we doing on pipeline safety, we think is a good 
oversight. And I think keeping it where it is gives it that 
visibility and gives all of us the confidence that the Office 
of Pipeline Safety is doing the work that they need to do.
    Mr. Shadegg. And your concern is that if it were moved as 
proposed, we would lose that?
    Mr. Koonce. If we move it into a much larger agency, I will 
pose the question, will we lose that level of accountability 
that we have today?
    Mr. Shadegg. Fair enough. Thank you very much. Thank you, 
gentlemen, for your testimony.
    Mr. Hall. Gentleman, we thank you very much for good 
testimony, good presentation, for your time. And because of the 
absence of some of the members of their necessity to be other 
places, we will leave open for them to write questions to you, 
if we might, and expect you to give us an answer within a 
couple of weeks. With unanimous consent, we will put that in 
the record.
    And for Mr. Pearl's documents and materials, I ask 
unanimous consent that they be placed into the record. Is there 
objection?
    [No response.]
    Mr. Hall. Hearing none, so ordered.
    We are adjourned.
    [Whereupon, at 1:30 p.m., the foregoing matter was 
adjourned.]

[GRAPHIC] [TIFF OMITTED] T5457.005

[GRAPHIC] [TIFF OMITTED] T5457.006

[GRAPHIC] [TIFF OMITTED] T5457.007

[GRAPHIC] [TIFF OMITTED] T5457.008

[GRAPHIC] [TIFF OMITTED] T5457.009

[GRAPHIC] [TIFF OMITTED] T5457.010

[GRAPHIC] [TIFF OMITTED] T5457.011

[GRAPHIC] [TIFF OMITTED] T5457.012

[GRAPHIC] [TIFF OMITTED] T5457.013

[GRAPHIC] [TIFF OMITTED] T5457.014

[GRAPHIC] [TIFF OMITTED] T5457.015

[GRAPHIC] [TIFF OMITTED] T5457.016

[GRAPHIC] [TIFF OMITTED] T5457.017

[GRAPHIC] [TIFF OMITTED] T5457.018

[GRAPHIC] [TIFF OMITTED] T5457.019

[GRAPHIC] [TIFF OMITTED] T5457.020

[GRAPHIC] [TIFF OMITTED] T5457.021

[GRAPHIC] [TIFF OMITTED] T5457.022

[GRAPHIC] [TIFF OMITTED] T5457.023

                                 
