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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

COMMITTEE ON ENERGY AND COMMERCE

JOE BARTON, Texas, Chairman

W.J. ‘‘BILLY’’ TAUZIN, Louisiana

RALPH M. HALL, Texas

MICHAEL BILIRAKIS, Florida

FRED UPTON, Michigan

CLIFF STEARNS, Florida

PAUL E. GILLMOR, Ohio

JAMES C. GREENWOOD, Pennsylvania

CHRISTOPHER COX, California

NATHAN DEAL, Georgia

RICHARD BURR, North Carolina

ED WHITFIELD, Kentucky

CHARLIE NORWOOD, Georgia

BARBARA CUBIN, Wyoming

JOHN SHIMKUS, Illinois

HEATHER WILSON, New Mexico

JOHN B. SHADEGG, Arizona

CHARLES W. ‘‘CHIP’’ PICKERING,

Mississippi, Vice Chairman

VITO FOSSELLA, New York

STEVE BUYER, Indiana

GEORGE RADANOVICH, California

CHARLES F. BASS, New Hampshire

JOSEPH R. PITTS, Pennsylvania

MARY BONO, California

GREG WALDEN, Oregon

LEE TERRY, Nebraska

MIKE FERGUSON, New Jersey

MIKE ROGERS, Michigan

DARRELL E. ISSA, California

C.L. ‘‘BUTCH’’ OTTER, Idaho

JOHN SULLIVAN, Oklahoma

JOHN D. DINGELL, Michigan

Ranking Member

HENRY A. WAXMAN, California

EDWARD J. MARKEY, Massachusetts

RICK BOUCHER, Virginia

EDOLPHUS TOWNS, New York

FRANK PALLONE, Jr., New Jersey

SHERROD BROWN, Ohio

BART GORDON, Tennessee

PETER DEUTSCH, Florida

BOBBY L. RUSH, Illinois

ANNA G. ESHOO, California

BART STUPAK, Michigan

ELIOT L. ENGEL, New York

ALBERT R. WYNN, Maryland

GENE GREEN, Texas

KAREN MCCARTHY, Missouri

TED STRICKLAND, Ohio

DIANA DEGETTE, Colorado

LOIS CAPPS, California

MICHAEL F. DOYLE, Pennsylvania

CHRISTOPHER JOHN, Louisiana

TOM ALLEN, Maine

JIM DAVIS, Florida

JANICE D. SCHAKOWSKY, Illinois

HILDA L. SOLIS, California

CHARLES A. GONZALEZ, Texas

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

RICHARD BURR, North Carolina

ED WHITFIELD, Kentucky

CHARLIE NORWOOD, Georgia

JOHN SHIMKUS, Illinois

Vice Chairman

HEATHER WILSON, New Mexico

JOHN B. SHADEGG, Arizona

CHARLES W. ‘‘CHIP’’ PICKERING,

Mississippi

VITO FOSSELLA, New York

GEORGE RADANOVICH, California

MARY BONO, California

GREG WALDEN, Oregon

MIKE ROGERS, Michigan

DARRELL E. ISSA, California

C.L. ‘‘BUTCH’’ OTTER, Idaho

JOHN SULLIVAN, Oklahoma

JOE BARTON, Texas,

(Ex Officio)

RICK BOUCHER, Virginia

(Ranking Member)

TOM ALLEN, Maine

HENRY A. WAXMAN, California

EDWARD J. MARKEY, Massachusetts

FRANK PALLONE, Jr., New Jersey

SHERROD BROWN, Ohio

ALBERT R. WYNN, Maryland

GENE GREEN, Texas

KAREN MCCARTHY, Missouri

TED STRICKLAND, Ohio

LOIS CAPPS, California

MIKE DOYLE, Pennsylvania

CHRIS JOHN, Louisiana

JIM DAVIS, Florida

JOHN D. DINGELL, Michigan,

(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)

(1)

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.

2

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 onecall notification, public education, and the authorization of techVerDate 11-MAY-2000 12:43 Oct 27, 2004 Jkt 000000 PO 00000 Frm 00006 Fmt 6633 Sfmt 6633 95457.TXT HCOM1 PsN: HCOM1
3

nical 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

4

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.

5

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.

6

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 lefthand 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.

7

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.

8

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

9

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

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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:]

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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.

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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.

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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

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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 westVerDate 11-MAY-2000 12:43 Oct 27, 2004 Jkt 000000 PO 00000 Frm 00018 Fmt 6633 Sfmt 6621 95457.TXT HCOM1 PsN: HCOM1
15

ern 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

16

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.

17

[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

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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:]

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1Of 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. 2OIG Report Number RT-2000-069, ‘‘Pipeline Safety Program,’’ March 13, 2000.

3OIG Report Number SC-2004-064, ‘‘Actions Taken and Needed for Improving Pipeline Safety,’’ June 14, 2004. 4 A ‘‘smart pig’’ is an instrumented internal inspection device that traverses a pipeline to detect potentially dangerous defects, such as corrosion. 5The 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.

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.

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

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.

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. • 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 transVerDate 11-MAY-2000 12:43 Oct 27, 2004 Jkt 000000 PO 00000 Frm 00023 Fmt 6633 Sfmt 6621 95457.TXT HCOM1 PsN: HCOM1
20

mission 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

21

6There 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.

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.

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,

22

7 Homeland Security Presidential Directive/HSPD-7, ‘‘Critical Infrastructure Identification,

Prioritization, and Protection,’’ issued December 2003.

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.

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 Pipelines ... 326,595 Miles .... Lines used to gather and transmit natural gas from wellhead

to distribution systems

Natural Gas Distribution Pipelines ..... 1.8 Million Miles Mostly local lines transporting natural gas from transmission

lines to residential, commercial, and industrial customers

Hazardous Liquid Transmission Pipelines.160,000 Miles .... Lines primarily transporting products such as crude oil, diesel

fuel, gasoline, and jet fuel

System Operators Facts Operators Description

Natural Gas Transmission Operators .. 880 ..................... Large, medium, and small operators of natural gas transmission pipelines

Natural Gas Distribution Operators .... 1,300 .................. Large, medium, and 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 developVerDate 11-MAY-2000 12:43 Oct 27, 2004 Jkt 000000 PO 00000 Frm 00026 Fmt 6633 Sfmt 6621 95457.TXT HCOM1 PsN: HCOM1
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ment 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

8The 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. 9Stress 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.

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.

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

25

no tools or mechanisms that can identify the threat of stress crack corrosion and

are also small enough to fit in 8inch-diameter piping.

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.

26

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 opinVerDate 11-MAY-2000 12:43 Oct 27, 2004 Jkt 000000 PO 00000 Frm 00030 Fmt 6633 Sfmt 6621 95457.TXT HCOM1 PsN: HCOM1
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10Operators 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.

ion, 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.

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.

28

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.

29

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

30

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 inVerDate 11-MAY-2000 12:43 Oct 27, 2004 Jkt 000000 PO 00000 Frm 00034 Fmt 6633 Sfmt 6602 95457.TXT HCOM1 PsN: HCOM1
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volve 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.

32

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

33

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 onecall 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

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tainly 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?

35

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.

36

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

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thing. 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.

38

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 enforceVerDate 11-MAY-2000 12:43 Oct 27, 2004 Jkt 000000 PO 00000 Frm 00042 Fmt 6633 Sfmt 6602 95457.TXT HCOM1 PsN: HCOM1
39

ment 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

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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 socalled 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

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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:]

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43

44

45

46

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.

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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 acciVerDate 11-MAY-2000 12:43 Oct 27, 2004 Jkt 000000 PO 00000 Frm 00051 Fmt 6633 Sfmt 6602 95457.TXT HCOM1 PsN: HCOM1
48

dental 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

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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 vehiclemiles 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.

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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 presVerDate 11-MAY-2000 12:43 Oct 27, 2004 Jkt 000000 PO 00000 Frm 00054 Fmt 6633 Sfmt 6621 95457.TXT HCOM1 PsN: HCOM1
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sure 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,

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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

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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.

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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.

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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 11⁄2 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.

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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

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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.

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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 twothirds 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 costeffectively—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.

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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

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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 longterm 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

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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 sysVerDate 11-MAY-2000 12:43 Oct 27, 2004 Jkt 000000 PO 00000 Frm 00065 Fmt 6633 Sfmt 6621 95457.TXT HCOM1 PsN: HCOM1
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tem. 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

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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

64

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 continVerDate 11-MAY-2000 12:43 Oct 27, 2004 Jkt 000000 PO 00000 Frm 00068 Fmt 6633 Sfmt 6621 95457.TXT HCOM1 PsN: HCOM1
65

ued 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

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• 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.

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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 twoweek 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.

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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

69

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.

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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 interVerDate 11-MAY-2000 12:43 Oct 27, 2004 Jkt 000000 PO 00000 Frm 00074 Fmt 6633 Sfmt 6621 95457.TXT HCOM1 PsN: HCOM1
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val 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 oneyear 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;

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• 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.

73

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:]

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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 milVerDate 11-MAY-2000 12:43 Oct 27, 2004 Jkt 000000 PO 00000 Frm 00078 Fmt 6633 Sfmt 6621 95457.TXT HCOM1 PsN: HCOM1
75

lion 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

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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 penVerDate 11-MAY-2000 12:43 Oct 27, 2004 Jkt 000000 PO 00000 Frm 00080 Fmt 6633 Sfmt 6621 95457.TXT HCOM1 PsN: HCOM1
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alties 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

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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.

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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.

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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 mid1950s, 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.

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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.

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.

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

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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.

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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,

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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 tollfree 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,

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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

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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.

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• 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.

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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.

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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

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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?

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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.

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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

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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.

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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 natVerDate 11-MAY-2000 12:43 Oct 27, 2004 Jkt 000000 PO 00000 Frm 00098 Fmt 6633 Sfmt 6602 95457.TXT HCOM1 PsN: HCOM1
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ural 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

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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

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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.

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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.]

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