[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) 512�091800
Fax: (202) 512�092250 Mail: Stop SSOP, Washington, DC 20402�090001
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