PIPELINE SAFETY: A PROGRESS 

REPORT SINCE THE ENACTMENT 

OF THE PIPELINE SAFETY 

IMPROVEMENT ACT OF 2002 

HEARING 

BEFORE THE 

SUBCOMMITTEE ON ENERGY AND AIR QUALITY 

OF THE 

COMMITTEE ON ENERGY AND 

COMMERCE 

HOUSE OF REPRESENTATIVES 

ONE HUNDRED NINTH CONGRESS 

SECOND SESSION 

APRIL 27, 2006 

Serial No. 109-84 

Printed for the use of the Committee on Energy and Commerce 

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

U.S. GOVERNMENT PRINTING OFFICE 

WASHINGTON : 2006 

For sale by the Superintendent of Documents, U.S. Government Printing Office 

Internet: bookstore.gpo.gov Phone: toll free (866) 512-1800; DC area (202) 512-1800 

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28-513PDF 
COMMITTEE ON ENERGY AND COMMERCE 

JOE BARTON, Texas, Chairman 

RALPH M. HALL, Texas 

MICHAEL BILIRAKIS, Florida 

 Vice Chairman 

FRED UPTON, Michigan 

CLIFF STEARNS, Florida 

PAUL E. GILLMOR, Ohio 

NATHAN DEAL, Georgia 

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 

ROY BLUNT, Missouri

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 

C.L. “BUTCH” OTTER, Idaho 

SUE MYRICK, North Carolina 

JOHN SULLIVAN, Oklahoma 

TIM MURPHY, Pennsylvania 

MICHAEL C. BURGESS, Texas 

MARSHA BLACKBURN, Tennessee 

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 

BOBBY L. RUSH, Illinois 

ANNA G. ESHOO, California 

BART STUPAK, Michigan 

ELIOT L. ENGEL, New York 

ALBERT R. WYNN, Maryland 

GENE GREEN, Texas 

TED STRICKLAND, Ohio 

DIANA DEGETTE, Colorado 

LOIS CAPPS, California 

MIKE DOYLE, Pennsylvania 

TOM ALLEN, Maine 

JIM DAVIS, Florida 

JAN SCHAKOWSKY, Illinois 

HILDA L. SOLIS, California 

CHARLES A. GONZALEZ, Texas 

JAY INSLEE, Washington 

TAMMY BALDWIN, Wisconsin 

MIKE ROSS, Arkansas 

BUD ALBRIGHT, Staff Director 

DAVID CAVICKE, General Counsel

REID P. F. STUNTZ, Minority Staff Director and Chief Counsel

SUBCOMMITTEE ON ENERGY AND AIR QUALITY 

RALPH M. HALL, Texas, Chairman 

MICHAEL BILIRAKIS, Florida 

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 

VITO FOSSELLA, New York 

GEORGE RADANOVICH, California 

MARY BONO, California 

GREG WALDEN, Oregon 

MIKE ROGERS, Michigan 

C.L. “BUTCH” OTTER, Idaho 

JOHN SULLIVAN, Oklahoma 

TIM MURPHY, Pennsylvania 

MICHAEL C. BURGESS, Texas 

JOE BARTON, Texas 

(EX OFFICIO) 

RICK BOUCHER, Virginia 

 Ranking Member 

MIKE ROSS, Arkansas 

HENRY A. WAXMAN, California 

EDWARD J. MARKEY, Massachusetts 

ELIOT L. ENGEL, New York 

ALBERT R. WYNN, Maryland 

GENE GREEN, Texas 

TED STRICKLAND, Ohio 

LOIS CAPPS, California 

MIKE DOYLE, Pennsylvania 

TOM ALLEN, Maine 

JIM DAVIS, Florida 

HILDA L. SOLIS, California 

CHARLES A. GONZALEZ, Texas 

JOHN D. DINGELL, Michigan 

 (EX OFFICIO)

(II)
CONTENTS 

Page 

Testimony of: 

Gerard, Stacey L., Acting Administrator/Chief Safety Officer, Pipeline and Hazardous 

Materials Administration, U.S. Department of Transportation.................................... 12 

Alves, Theodore, Principal Assistant Inspector General for Audit and Evaluation, 

Office of Inspector General, U.S. Department of Transportation ................................. 20 

Chipkevich, Robert, Director, Office of Railroad, Pipeline, and Hazardous Materials 

Investigations, National Transportation Safety Board................................................... 32 

Siggerud, Katherine, Director, Physical Infrastructure Issues, U.S. Government 

Accountability Office..................................................................................................... 37 

Tahamtani, Massoud, Director, Division of Utility and Railroad Safety, Virginia State 

Corporation Commission, on behalf of National Association of Pipeline Safety 

Representatives............................................................................................................... 83 

Hon., Mason, Donald L., Commissioner, Public Utilities Commission of Ohio, on 

behalf of National Association of Regulatory Utilities Commissioners ....................... 92 

Bender, Jr., Edmund F., Vice President, Gas Distribution and New Business Division, 

Baltimore Gas and Electric Company, on behalf of American Gas Association.......... 110 

Mohn, Jeryl L., Senior Vice President, Operations and Engineering, Panhandle 

Energy, on behalf of Interstate Natural Gas Association of America ........................... 123 

Felt, Timothy C., President and CEO, Explorer Pipeline Company, on behalf of 

Association of Oil Pipe Lines ........................................................................................ 137 

Epstein, Lois N., Senior Engineer, Oil and Gas Industry Specialist, Cook Inlet Keeper, 

on behalf of Pipeline Safety Trust ................................................................................. 156 

Kipp, Bob, President, Common Ground Alliance .............................................................. 170 

(III) 

(1) 

PIPELINE SAFETY: A PROGRESS 

REPORT SINCE THE ENACTMENT OF 

THE PIPELINE SAFETY IMPROVEMENT 

ACT OF 2002 

THURSDAY, APRIL 27, 2006 

HOUSE OF REPRESENTATIVES, 

COMMITTEE ON ENERGY AND COMMERCE, 

SUBCOMMITTEE ON ENERGY AND AIR QUALITY, 

Washington, DC. 

 The subcommittee met, pursuant to notice, at 10:08 a.m., in Room 

2322 of the Rayburn House Office Building, Hon. Ralph M. Hall 

(chairman) presiding. 

 Members present: Representatives Wilson, Otter, Murphy, Burgess, 

Barton (ex officio), Boucher, Markey, Green, Gonzalez, and Hall. 

 Staff present: Maryam Sabbaghian, Counsel; Elizabeth Stack, Policy 

Coordinator; David McCarthy, Chief Counsel for Energy and 

Environment; Tom Hassenboehler, Counsel; Peter Kielty, Legislative 

Clerk; and Bruce Harris, Minority Professional Staff Member. 

MR. HALL. Okay. I thank you for your patience, and I thank you for 

the time that you have given, are giving, and will give. And I want to 

begin by just discussing a little bit of what we expect and what we hope 

for here. 

 Protecting the safety of our pipeline system requires a lot of 

comprehensive and coordinated efforts of several Federal and State 

agencies and industry and pipeline safety advocacy groups. 

 To this end, the hearing is going to consist of three panels of 

witnesses, and the first panel will consist of representatives from the 

Department of Transportation, Pipeline and Hazardous Materials 

Administration and the Office of Inspector General, the National 

Transportation Safety Board, and the Government Accountability Office. 

 The second panel is going to consist of representatives from the 

National Association of Regulatory Utility Commissioners and the 

National Association of Pipeline Safety Representatives. 

 And the third panel will include representatives from the pipeline 

industry and pipeline safety advocacy groups. We are appreciative and 

grateful for all of your views on the topic of pipeline safety. 

Congress, as you know, passed the Pipeline Safety Improvement Act 

of 2002 to improve pipeline safety and security practices, and to provide 
2

Federal oversight of pipeline operator security programs. That is due for 

reauthorization at the end of this year, and the purpose of this hearing 

really is to see how successful or how unsuccessful the implementation 

of that Act has been with an eye toward legislation reauthorizing the Act. 

 And again, I look forward to hearing from all of you on the progress 

you have made and are helping us to make, and your recommendations 

as the committee goes forward. I really appreciate your time. 

 [The prepared statement of Hon. Ralph M. Hall follows:] 

PREPARED STATEMENT OF THE HON. RALPH M. HALL, CHAIRMAN, SUBCOMMITTEE ON 

ENERGY AND AIR QUALITY

I want to begin by thanking our many witnesses for testifying before the 

Subcommittee today. Protecting the safety of our pipeline system requires the 

comprehensive and coordinated effort of several federal and state agencies, industry and 

pipeline safety advocacy groups. 

To this end, the hearing will consist of three panels of witnesses. The first panel will 

consist of representatives from the Department of Transportation’s Pipeline and 

Hazardous Materials Administration and Office of Inspector General, the National 

Transportation Safety Board and the Government Accountability Office. The second 

panel will consist of representatives from the National Association of Regulatory Utility 

Commissioners and the National Association of Pipeline Safety Representatives. The 

third panel will include representatives from the pipeline industry and pipeline safety 

advocacy groups. We are appreciative and grateful for your all of your views on the 

topic of pipeline safety. 

In the 107th Congress passed Pipeline Safety Improvement Act of 2002 to improve 

pipeline safety and security practices and to provide federal oversight of pipeline operator 

security programs. That Act is due for reauthorization at the end of this year. The 

purpose of this hearing is to see how successful or unsuccessful implementation of that 

Act has been with an eye towards legislation reauthorizing the Act. 

Again, I also look forward to hearing from you all on the progresses you’ve made 

and your recommendations as the Committee goes forward legislatively. 

 MR. HALL. At this time, we will recognize Mr. Boucher. 

 MR. BOUCHER. Thank you very much, Mr. Chairman. 

 I want to commend you for convening today’s hearing on the timely 

question of pipeline safety. 

 In 2002, this Committee enacted, on a bipartisan basis, the Pipeline 

Safety Improvement Act. And now, as we near the time for 

reauthorization of that measure, it is appropriate that we hear from 

interested parties concerning their views about the appropriateness and 

effectiveness of the 2002 legislation and receive suggestions for 

improvements that can be made to the Nation’s pipeline safety laws. 

 The witnesses that we have before us today offer a broad range of 

expertise, and I look forward to hearing from them. I am particularly 

pleased that we have a witness from my home State of Virginia who will 

provide testimony on Virginia’s highly successful program to prevent 

excavation damage to natural gas pipelines. Since implementation of 
3

Virginia’s program, our State has experienced a dramatic reduction in 

excavation damage. I look forward to hearing from the witnesses about 

the manner in which this program operates, perhaps some operational 

detail would be helpful for us, and also their view of the program 

successes, and perhaps most importantly, their recommendations as to 

whether or not the Virginia experience could serve as a model for what 

other States might do in order to address their own problems with 

excavation damage to natural gas pipelines. 

 In addition, I hope that our witnesses will address a number of 

matters that are of further interest. I was pleased that the 2002 Act 

included a section authorizing technical assistance grants for local 

communities. However, it is my understanding that no grants have been 

awarded under this program since its inception. I am continually of the 

view that providing assistance to local communities for technical 

assistance on pipeline issues is important, and I have been disappointed 

that the program has not functioned as we intended it to function. 

Perhaps our witnesses can comment on the reasons that technical 

assistance grants to communities have not been awarded to date and 

make suggestions to us for ways that we can structure this program more 

appropriately to assure that its objectives are met. 

 During the hearing before this subcommittee two years ago, a 

Department of Transportation official testified that the Department 

planned to develop an integrity management plan for natural gas 

distribution lines. The distribution lines comprise approximately 85 

percent of all of the natural gas pipelines in the country. But at that time, 

the idea of a comprehensive integrity management plan for distribution 

lines was merely a recommendation. Now the Office of Pipeline Safety 

is moving ahead with the establishment of an integrity management plan 

for these distribution lines. It is my understanding that a report on 

integrity management for gas distribution has been produced through a 

consultative process involving a wide range of stakeholders, including 

the Federal and local officials directly affected, industry experts, and 

safety advocates, and that the Office of Pipeline Safety expects to publish 

a distribution integrity management early in 2007. That is good news, 

indeed. And this effort marks the first comprehensive and consensusbased attempt to develop an integrity management plan for natural gas 

distribution lines. And I commend the effort and look forward to 

learning more about the progress of the development of this plan. 

 There are many areas that our witnesses could usefully address. For 

example, a recent failure on a subsequent crude oil leak from a lowpressure transmission line in Alaska highlights, I think, the need for a 

regulation of low-pressure pipelines. And I understand that OPS is now 
4

developing regulations in order to cover those lines. I applaud that 

approach. 

 I expect that some of our witnesses will address the requirement for 

periodic inspection of the 10-year baseline and the 7-year inspections 

that are performed on a re-inspection basis that were mandated in the 

2002 legislation. The Act also requires GAO to complete a study with 

regard to the appropriateness of these particular timelines, the 10-year 

baseline and the 7-year periodic inspections. While that report will not 

be completed until the fall, we would welcome today, or at any time 

between now and then, any preliminary findings from the report that 

witnesses would care to present to us. 

 Having said that, I would caution that I think we need to allow time 

for the GAO to complete its work and make final recommendations 

before reaching any judgments about possible changes to the timing of 

these inspections. 

 Finally, I would like to hear the general opinions of our witnesses on 

the successes, generally speaking, and the problems that have been 

presented through implementation of the 2002 Act. It is my perception 

that the consensus Act we passed in 2002 has produced positive results 

with an increased emphasis on safety and accident prevention both by the 

agencies of enforcement and by the industry. 

 The views of our witnesses on all of these matters would be most 

welcome, and I look forward to their presentations. 

 And I thank you, Mr. Chairman, for your indulgence during this 

somewhat lengthy opening statement. 

 MR. HALL. I thank the gentleman. The Chair recognizes, for 3 

minutes, the gentleman from Pennsylvania, Mr. Murphy. 

 MR. MURPHY. Thank you, Mr. Chairman, for holding this important 

hearing. And I share the views expressed of using this as an opportunity 

to see what we can do to assure pipeline safety as we look at what is 

involved in this Act. 

 But I want to draw attention to one particular issue here that occurred 

in my district, the 18th District in Pennsylvania. 

 On March 16, 2005, two teenagers in my district, while coming 

home from school, walked past utility workers who had ruptured a 

natural gas pipeline. Apparently, the gas had been seeping for some 

time, and they followed the local rules to notify the community via fax to 

an office that was not manned at the time. As the gas continued to seep 

into their home, and let me show you a picture of their house before. 

 [Slide.] 

 As the gas continued to seep into their home, this house the children 

walked into with the smell of natural gas in the air. 

 [Slide.] 
5

 While one child was up in the upper left part of the house watching 

TV, another child was downstairs, could you show the next picture, the 

house, in seconds, was reduced to this. 

 Now unfortunately, many States do not have uniform standards in 

terms of how to notify local officials when there is a rupture in a 

pipeline, and this is not an interstate transmission line, this is a 

neighborhood line. However, there is a hodgepodge of rules, and my 

question is if we need to have uniform nationwide standards or, at the 

very least, require each State to have a workable notification system, 

such as calling 911, or some other number, where there is a person there 

to do something to secure the neighborhood, notify the gas company, and 

clear the area all at once. 

 We, unfortunately, do not have unified rules such as that, and one of 

the things I am hoping to hear from people testifying today is what we 

can do to prevent these. Now we also recognize that there are problems 

with regard to even making sure we follow the rules notifying before 

someone digs, making sure we have qualified people doing the digging 

where there are gas pipelines around. And we also should have some 

rules with regard to increased penalties when people do not follow those 

notification procedures. But those are the two ends: the preparation and 

the fine at the end. 

 What I am concerned about is what happens in the middle. Much 

like healthcare, we may be able to prevent illnesses, and at the end, if 

someone has an error, we may be able to find them or have some other 

lawsuits to deal with that. But in the middle process, we do have a 

confusing array of laws around this Nation and within States. And one 

of the things that I am hoping to get out of this hearing is a sense from 

the experts involved in these fields of pipeline safety of what we can do 

to make sure that young children like Mark and Chelsea, who, 

unfortunately, were severely burned in this incident, do not happen 

again. 

 For all of these reasons, I have introduced H.R. 2958, which would 

establish some notification standards for any excavator, construction 

worker, and anyone else who calls or becomes aware of damage to a 

pipeline. And I am hoping that that is one of the issues that we can 

resolve so that situations like this, dangerous situations, do not occur 

again. And luckily, Mark and Chelsea are better now with some scars. 

Their family is traumatized from this, and they are moving on to a new 

home. But when you look at that situation, I hope it helps motivate 

Members of Congress to understand the hundreds of people who have 

died in pipeline accidents, and the thousands of incidents that occur. It is 

time we work on finding ways to prevent this from happening again. 

 Thank you, Mr. Chairman. 
6

MR. HALL. I thank you for a good opening statement. 

 I recognize the gentleman from Texas, Mr. Green, for three minutes. 

 MR. GREEN. Thank you, Mr. Chairman and Ranking Member 

Boucher for putting together such a very solid group of witnesses for 

today’s hearing on a very important issue. Obviously to Pennsylvania, 

but also to Texas and the district I represent, pipeline safety. I would like 

to note that pipelines are the safest and most efficient form of 

transportation, any way you measure it, especially for energy products 

like natural gas, crude oil, fuel, or propane. It is much better for those 

things to be in a quality steel pipe in the ground and not on trucks on the 

roads, and I think we should promote pipelines when they can be safe 

and efficient. 

 To do that, we must ensure pipelines remain the safest form of 

transportation with continuing inspections and better technology. Every 

pipeline in a high-consequence population area must be inspected, and 

many other less populated areas will also be inspected by 2012, 10 years 

after the Act. But if a pipeline runs in your neighborhood, like they do in 

many parts of our district, it should be inspected and re-inspected. Our 

legislation 5 years ago made some major changes and improvements 

which are in the process of making the ten-year baseline safety goals set 

up by that Act. I am interested to hear the testimony from our panels 

about how the ten-year baseline assessment we set four years ago is 

going and what plans are going on for the ongoing reassessment phase. 

 And again, thank you, Mr. Chairman and Ranking Member, and I 

yield back my time. 

 MR. HALL. I thank the gentleman. 

 The Chair recognizes Mrs. Wilson, the gentlelady from New 

Mexico, for 3 minutes. 

 MRS. WILSON. Thank you, Mr. Chairman, and thank you for this 

hearing. 

 In August of 2000, an explosion in an El Paso Natural Gas Company 

pipeline near Carlsbad killed 12 people, 2 extended families, including a 

6-month-old infant. The explosion of a 30-inch, 50-year-old natural gas 

pipeline left a crater that was 86 feet long, 36 feet wide, and 20 feet deep. 

It was the natural gas pipeline explosion that was the most serious one in 

terms of fatalities in the past 25 years. 

 In New Mexico, in addition to our interstate pipelines, we have 

13,000 miles of intrastate natural gas pipelines. In fact, 10 percent of the 

natural gas consumed in the Nation today comes from the State of New 

Mexico. A third of California’s natural gas comes from the State of New 

Mexico, most of it from the Four Corners Region. Thirteen thousand 

miles of natural gas pipelines crisscrossing our State to supply the Nation 
7

with natural gas. That is enough to go from Albuquerque, New Mexico 

to Bombay, India. 

 Since 2003, we have had one fatality and four injuries because of 

pipeline safety incidents. While we have made progress, that is one 

fatality and four injuries too many. Pipelines are near people. They run 

through neighborhoods, near schools, and hospitals. And for those of us 

who live in States that produce the natural gas that the Nation needs, 

these are major issues. 

 We have to keep these pipelines safe. And I continue to believe that 

our pipeline industry continues to use old technology with respect to 

making sure pipelines are as safe as they can be, and we need to make 

significant improvements in the research and development to bring 

pipeline safety into the 21st century. 

 Mr. Chairman, thank you very much for holding this hearing. 

 MR. HALL. I thank the gentlelady. 

 I recognize Mr. Otter, the gentleman from Idaho, for 3 minutes. 

 MR. OTTER. Mr. Chairman, I want to defer so we can get on with 

the witnesses’ testimony. 

 MR. HALL. That is very kind and generous of you. 

 We will go to the witnesses at this time. 

 [Additional statements submitted for the record follow:] 

PREPARED STATEMENT OF THE HON. JOE BARTON, CHAIRMAN, COMMITTEE ON ENERGY 

AND COMMERCE

Chairman Hall, thank you for holding this hearing today. I want to also thank our 

many witnesses for testifying before the Subcommittee today. We are appreciative and 

grateful for your analysis and views on the topic of pipeline safety. 

Nearly half a million miles of crude oil, petroleum product and natural gas 

transmission pipeline crisscross the United States. These pipelines are integral to U.S. 

energy supply and have vital links to other critical infrastructure, such as power plants, 

airports, and military bases. 

The best and most effective way to bring down fuel prices is to increase supply, and 

more oil will require more pipelines. While we have ships, trucks and railroads, pipelines 

are the arteries of the nation. They are just the most effective way to transport oil, natural 

gas and gasoline. 

Last fall, the House passed the GAS Act to address concerns about high gasoline 

prices by easing siting and permitting restrictions for refineries and pipelines. I intend to 

make pipeline projects a reality. The critics want to build problems instead of pipelines, 

but that’s not an energy policy. It’s a policy to raise gasoline prices on working people. 

Of course, protecting the safety of our existing pipeline system is the most important 

thing we can do to secure our existing supply and to safeguard our citizens. This requires 

the comprehensive and coordinated effort of several federal and state agencies, industry 

and pipeline safety advocacy groups. However, when it is operating at its very best, you 

don’t know even it’s there. 

There has been recent attention in the press on pipeline safety following the BP 

pipeline leak in Alaska. I know there have been Department of Transportation 

investigations since the Department issued its Corrective Action Order. I recognize that 
8

the investigation is ongoing and look forward to a better understanding of the causes of 

this leak as the investigation continues. 

The 107th Congress passed the bipartisan Pipeline Safety Improvement Act of 2002 

to improve pipeline safety and security practices and to provide federal oversight of 

pipeline operator security programs. A centerpiece to the Act is the requirement it places 

on oil and natural gas pipeline operators to prepare and implement an integrity 

management program. I also look forward to hearing from you all on the progress and 

results of this program. 

 Later, this Subcommittee will turn to a possible reauthorization of pipeline safety 

laws. Chairman Hall and I are ready to work with Congressman Dingell and Boucher 

and all other Members of the Subcommittee on a successful bill. 

PREPARED STATEMENT OF THE HON. MICHAEL BURGESS, A REPRESENTATIVE IN CONGRESS 

FROM THE STATE OF TEXAS

Thank you, Mr. Chairman for holding this important hearing. 

When our constituents think of the movement of products and goods across the 

country -- most of them think about large trucks on the highway carrying everything from 

ice cream to new cars. 

Some think of the railroads and others think about the barges that traverse the 

Mississippi. But few think of the interstate transmission pipelines that transport huge 

volumes of crude oil, refined products including gasoline and natural gas; until something 

goes wrong. 

In 2000, three people died in a natural gas distribution pipeline explosion in 

Garland, Texas, which is just east of my congressional district. 

Although this particular pipeline does not fall under federal jurisdiction, it shows 

just how high the stakes can be and why it is so critical that we have a robust federal 

pipeline safety program. 

Fortunately, these types of accidents do not occur frequently. Oil pipelines reported 

an average of 1.4 deaths per year from 2000 to 2004; gas pipelines reported an average of 

17.0 deaths per year during the same period. 

Congress last updated the federal pipeline safety law in 2002. Among other things, 

the bill required operators of regulated gas pipelines in densely populated areas to 

conduct risk analysis and periodic inspections, and to strengthen public education 

regarding pipeline safety. 

One of the best ways that we can reduce the risk of harm to the general public is 

through education. The Danielle Dawn Smalley Foundation, in Chairman Hall's district, 

is a non-profit organization that conducts these types of education programs for the 

general public as well as for first responders, including the City of Fort Worth Fire 

Department which will participate in the program later this year. 

In conclusion, Mr. Chairman, while the risk of harm from a pipeline accident is far 

less than driving on I-35 West, we should always strive to do better. 

I am looking forward to hearing from our witnesses today about how they view the 

changes made in 2002 as well as their suggestions for us as we move forward with 

reauthorization during the 109th Congress. 

PREPARED STATEMENT OF THE HON. JOHN D. DINGELL, A REPRESENTATIVE IN CONGRESS 

FROM THE STATE OF MICHIGAN

Mr. Chairman, I commend both you and Chairman Barton for holding this very 

important hearing and for working with us cooperatively to assemble the panels before us 

today. 
9

Pipeline safety is an immensely important but little-followed energy issue. We are 

all aware of the catastrophic damage that can occur to life, property, and the environment 

when a line fails. We all remember the horrible tragedies of Bellingham, Washington, 

and Carlsbad, New Mexico, that resulted in the loss of life. We learned last summer after 

Hurricane Katrina the supply problems that can occur when pipeline integrity is 

compromised. This concern arose again, albeit on a smaller scale, with the breach of the 

Plantation pipeline outside of Richmond, Virginia, which resulted in the spill of over 

27,000 gallons of jet fuel – a precious commodity to the struggling airline industry. 

The good news is that in recent years the Federal Government’s approach to pipeline 

safety seems to be improving. The Pipeline Safety Improvement Act of 2002 deserves a 

good portion of the credit for those improvements. Through baseline assessments, 

operators of natural gas transmission lines have been able to identify and repair 

anomalies before they result in catastrophic accidents; the Office of Pipeline Safety has 

made tremendous progress in meeting mandates of the Act and responding to 

recommendations of the National Transportation Safety Board (NTSB) and the 

Department of Transportation Inspector General; one-call notification programs to 

prevent excavation damage have been strengthened and are continuing to improve around 

the country. 

The basic structure of the 2002 Act is a sound one that we should amend only in 

those few areas that it can be improved upon. With this in mind I hope that our witnesses 

can inform us on a number of issues including means to further strengthen the 

enforcement approach of the Office of Pipeline Safety, the need to take more action to 

prevent excavation damage, and the merits of an integrity management program for 

America’s local distribution gas companies. 

Challenges remain, however. I must note that events have a way of focusing 

Congressional attention and I hope that we will explore the issues surrounding the recent 

spill of over 200,000 gallons of crude oil on Alaska’s North Slope. Unfortunately the 

line that failed was exempt, by regulation, from Office of Pipeline Safety oversight. It 

seems that because the line was operating at low pressure it was assumed that the risk 

was also low. That assumption has been turned on its head. We need to find out how 

many of these lines exist and how they may be regulated. Whether you are a defender of 

the Alaskan environment, a proponent of hydrocarbon production in Alaska, or both, this 

spill was bad news for everyone. I hope the Subcommittee will seriously examine this 

issue. I have attached correspondence to my statement that details some of the 

information that our investigative efforts have uncovered thus far and I ask that it be 

included in the record. 

Finally, Mr. Chairman, I want to reiterate that the Pipeline Safety Improvement Act 

of 2002 was a good piece of legislation of which we may all be proud. It was the result 

of much hard work and enjoyed the support of industry, safety advocates, 

environmentalists, and the States. It was the result of a bipartisan process. I hope that as 

we begin to look at its reauthorization we keep its origins in mind and attempt to follow a 

similar path. I thank you and look forward to hearing from our witnesses. 

PREPARED STATEMENT OF THE HON. CHARLES A. GONZALEZ, A REPRESENTATIVE IN 

CONGRESS FROM THE STATE OF TEXAS

Mr. Chairman, 

I would like to thank you for convening this important hearing on pipeline safety 

today. As the supply and demand cycle for energy in America continues to tighten, 

maintaining the safe and efficient transmission of natural gas is vitally important to our 

nation’s economic and domestic security. I look forward to receiving an update from the 

witnesses before us today on the progress of implementing the Pipeline Safety 

Improvement Act of 2002, and whether or not changes need to be made as we consider 
10

reauthorizing this important legislation. I appreciate the special challenges presented by 

ensuring the integrity and safety of the nation’s pipeline systems, while still preserving 

the uninterrupted delivery of energy to markets in a supply tight environment. I welcome 

the witnesses to address whether we have built enough flexibility into the process to 

allow for needed inspections to take place concurrently with meeting the delivery 

requirements of our citizens and industries. 

I am especially interested in hearing the thoughts of the panel regarding the progress 

of the initial inspections of all high consequence pipeline as required by the 2002 Act. 

Completing these baseline inspections in a timely manner is crucial to ensuring reliable 

transmission of natural gas, and meeting the safety mandate set forth by Congress. In 

addition, I am eager to hear from the witnesses on the issue of the re-inspection of 

pipeline and the interval at which these re-inspections should occur. I would like to hear 

the panel address whether the current seven year re-inspection mandate is reasonable. In 

particular I would like to know their views as to whether we should transition to a 

standard that prioritizes resources on the highest stress pipelines. In other words, would 

an approach that emphasized inspecting higher consequence pipe more often and lower 

consequence pipe less often be more or less effective at identifying and correcting safety 

risks. Finally, I would also like to hear whether the panels feels that requiring reinspections to begin after seven years, which is before the baseline inspections have been 

completed, will result in extra segments of pipeline being removed from service and what 

impact that might have on the supply chain in certain regions of the country. 

Again, I thank the Chairman for calling attention to these issues with vast national 

and economic security implications. I look forward to receiving today’s testimony. 

 MR. HALL. We have Ms. Stacey Gerard, Acting Administrator and 

Chief Safety Officer, Pipeline Hazardous Materials Administration. I 

recognize you. Just summarize for 5 minutes or thereabouts, or as close 

as you can. 

 And thank you. We will recognize you at this time. 

STATEMENTS OF STACEY L. GERARD, ACTING 

ADMINISTRATOR/CHIEF SAFETY OFFICER, PIPELINE 

AND HAZARDOUS MATERIALS ADMINISTRATION, U.S. 

DEPARTMENT OF TRANSPORTATION; THEODORE 

ALVES, PRINCIPAL ASSISTANT INSPECTOR GENERAL 

FOR AUDIT AND EVALUATION, OFFICE OF GENERAL 

INSPECTOR, U.S. DEPARTMENT OF TRANSPORTATION; 

ROBERT CHIPKEVICH, DIRECTOR, OFFICE OF 

RAILROAD, PIPELINE, AND HAZARDOUS MATERIALS 

INVESTIGATION, NATIONAL TRANSPORTATION 

SAFETY BOARD; AND KATHERINE SIGGERUD, 

DIRECTOR, PHYSICAL INFRASTRUCTURE ISSUES, U.S. 

GOVERNMENT ACCOUNTABILITY OFFICE 

MS. GERARD. Thank you, Mr. Chairman, distinguished members of 

the subcommittee. I appreciate the opportunity to appear today to 

discuss U.S. DOT’s Pipeline and Hazardous Material Safety 

Administration’s efforts to improve the safety of America’s pipelines. 
11

Our Acting Administrator, Brigham McCown, regrets that he can’t be 

here today, because he is on previously-scheduled military duty as a 

reserve officer in the U.S. Navy. 

 We understand the subcommittee’s concern surrounding the safety of 

your constituents and all Americans who live, work, and conduct their 

daily routines near pipelines. Our agency has taken actions to achieve 

results, including reducing the number of pipeline incidences of severe 

consequences to people. 

 Under Secretary Mineta’s leadership, PHMSA has succeeded in 

addressing every mandate of the Pipeline Safety Act of 2002. We have 

eliminated most of the 12-year backlog of past mandates of 

recommendations from the Congress, the MTSB, the DOT Inspector 

General, and the General Accountability Office. Just last month, we 

published the final rule to define and regulate natural gas gathering lines. 

 Now we are working on our last outstanding mandate, protecting 

unusually sensitive areas from risks posed by rural liquid gathering lines 

and low-stress transmission lines. We will be holding a public workshop 

in June to review our concepts to improve protection, how to seek a 

consensus among stakeholders so we can expedite this rule. The June 

workshop will address the need for a maintenance, testing, leak 

detection, operator qualification, marking, buffer zones, and other topics. 

This rule is relevant to the low-stress transmission pipeline that failed 

recently on the north slope of Alaska. We issued a corrective action 

order to protect the people and the environment of Alaska. We are 

working hard to make operations safer and are working closely with 

Alaskan State agencies. 

 We have taken advantage of higher penalty authority by imposing, 

and collecting, larger penalties. Compared to 2003, the first year when 

higher penalty authority was available, we doubled the civil penalties 

proposed in 2004 and tripled them in 2005. For calendar year 2005, the 

proposed penalties amounted to over $4 million. 

 Additionally, from 2003 to 2005, we closed 56 percent of the penalty 

cases and collect 94 percent of the total penalties proposed. We have 

reinforced our partnerships with State pipeline safety agencies through a 

policy collaboration, better training, shared data, and more frequent 

communication. Pipeline safety depends on States overseeing roughly 

90 percent of the infrastructure. Since appearing last before this 

committee in 2004, we are now enforcing regulation of the integrity 

management programs for both hazardous liquid and natural gas 

transmission operators. The interstate partners have conducted 

comprehensive inspectors. Liquid operators are assessing and repairing 

nearly 80 percent of the Nation’s hazardous liquid pipelines and gas 
12

operators are replacing nearly 60 percent of their transmission pipelines. 

About 82 percent of the most sensitive areas have already been assessed. 

 In June of 2005, the Bush Administration sent the Congress our plan 

to strengthen the safety of distribution pipelines through use of integrity 

management principles, and a rulemaking is well along the way. 

 We are also raising the quality of education operators provide. First, 

we oversaw operator self assessments required by the law and 

determined considerable improvement was needed. We called for a new 

consensus standard for public education, and stakeholders responded by 

creating one that significantly raised the bar. We adopted it in 

regulation. PHMSA has invested over $5 million since the passage of 

the Pipeline Safety Act to bringing meaningful information to the public 

regarding pipeline operator performance. 

 Working with the Common Ground Alliance, we have led many 

stakeholders to share responsibility for our number one priority, damage 

prevention. We thank the CGA and its volunteers for their partnership 

and leadership and helping us fight the war on damaged underground 

facilities. They are doing a great job on that and to implement 811. It 

provides one action all Americans can take to improve safety. 

 We have been building a new, more comprehensive, and improved 

approach to pipeline safety. We are improving pipeline performance by 

managing risk, sharing responsibility, and providing effective 

stewardship. This plan is consistent with the Pipeline Safety Act and 

leaves no stone unturned in identifying and addressing pipeline risk. 

 We recognize there is always room for improvement and believe 

there is more work to be done. We look forward to continuing to work 

with all of you. 

 Thanks very much. 

 [The prepared statement of Stacey L. Gerard follows:] 

PREPARED STATEMENT OF STACEY L. GERARD, ACTING ADMINISTRATOR/CHIEF SAFETY 

OFFICER, PIPELINE AND HAZARDOUS MATERIALS ADMINISTRATION, U.S. DEPARTMENT OF 

TRANSPORTATION

Good morning, Mr. Chairman. Thank you for inviting the Department to testify 

today before your Subcommittee to provide you and the other members an update on the 

successes of the Department’s pipeline safety program. Our Acting Administrator 

Brigham McCown regrets he cannot be here today as he is on previously scheduled 

annual military duty as a reserve officer in the U.S. Navy. I am Stacey Gerard. I 

currently serve in dual roles as the Pipeline and Hazardous Materials Safety 

Administration’s (PHMSA) Acting Assistant Administrator/Chief Safety Officer as well 

as the agency’s Associate Administrator for Pipeline Safety. 

This opportunity to discuss our progress in improving the safety and reliability of 

the Nation’s pipeline infrastructure is welcome. The 2.3 million miles of natural gas and 

hazardous liquid pipelines carry nearly two-thirds of the energy consumed by our Nation 

and as such, it is easy to see why our pipelines are in fact, our energy highways. It is also 
13

important for me to stress that as a mode of transportation, our pipelines remain the safest 

and most efficient way to transport the enormous quantities of natural gas and hazardous 

liquids America uses each day. 

We greatly appreciate this Subcommittee’s attention to our efforts in advancing 

pipeline safety. We are achieving results – pipeline accidents with severe consequences 

to people are trending steadily downward. There has been an increase in the total of all 

reported accidents in the recent past. Although we are watching these numbers closely, I 

can report that we believe this data reflects normal variations in year-to-year reporting, 

and also reflects damage caused by last year’s hurricanes. Higher fuel prices also mean 

that smaller spills now qualify for reporting under the property damage criteria. 

Under Secretary Mineta’s leadership, PHMSA has succeeded in achieving every 

mandate set forth in the Pipeline Safety Improvement Act (PSIA) of 2002, and the 

agency has done so in a timely manner. This testimony today will provide an update on 

the progress report given 18 months ago. 

Demographic changes taking place in our country require us to be increasingly 

vigilant. Urbanization of previously rural areas is placing people closer to pipelines. 

Expansion and development also means more construction activity near pipelines. It 

should come as no surprise therefore that third party excavation damage is a leading 

cause of pipeline accidents. 

Encroachment on areas containing pipelines increases the potential for pipeline 

accidents, which although infrequent, can have tragic consequences. We have stepped up 

our efforts to address third party damage because of greater congestion in our 

underground infrastructure and the potential to save lives. Managing the risk to pipelines 

is more difficult because the underground is increasingly crowded with the installation of 

new fiber optics and telecommunications infrastructure central to our way of life. 

Our record as a regulator and overseer of public safety is important to us. Safety is, 

and remains the Administration’s top priority when it comes to regulating the pipeline 

industry. In addition to addressing the many mandates of the PSIA, PHMSA has 

eliminated most of a 12-year backlog of outstanding mandates and recommendations 

from the Congress, the National Transportation Safety Board (NTSB), the Department of 

Transportation (DOT) Inspector General, and the Government Accountability Office 

(GAO). Over the past five years, the agency has responded positively to 46 NTSB safety 

recommendations and is working to close the three recommendations remaining from the 

pre-2002 environment. The GAO recently closed eight pipeline safety 

recommendations─ six in enforcement, and two in research and development. 

Just last month, we published the final rule to define and regulate natural gas 

gathering lines. 

Through rulemaking we are actively addressing our last outstanding mandate, 

protecting unusually sensitive areas from risks posed by rural liquid gathering lines and 

low stress transmission pipelines. This rule is relevant to the low stress transmission 

pipeline that failed recently on the North Slope of Alaska. We issued a corrective action 

order soon after to ensure safety and environmental protection of that and two similar 

lines nearby. We are making good progress with the remediation of the failed line and 

are working closely with Alaska State agencies. We will be holding a public workshop in 

June to review our concepts to improve protections and address other important issues. 

The June workshop will focus on low stress lines and how they can be improved through 

leak detection, operator qualification, maintenance, defining applicability criteria, and 

buffer zones. 

Stronger oversight has been an important strategy in strengthening pipeline safety. 

In the past 12 years, the agency has added 60 additional inspectors to PHMSA’s pipeline 

safety staff, up from 28 inspectors in 1994. PHMSA’s state agency partners employ over 

400 additional inspectors who oversee 90 percent of the infrastructure and contribute 50 
14

percent of the total costs. This Federal-State partnership is crucial to the agency’s 

success. 

PHMSA is fulfilling its plan to improve the safety, reliability, and environmental 

performance of the Nation’s energy transportation pipeline network. Our plan includes a 

multi-phase strategy which leaves no stone unturned in identifying and addressing 

pipeline risks. To manage the risks inherent in pipeline transportation, PHMSA has been 

building a new, more comprehensive and informed approach to pipeline safety consistent 

with the PSIA. 

This plan, discussed 18 months ago, is based on improving pipeline performance by: 

(1) managing risk; (2) sharing responsibility; and (3) providing effective stewardship. 

I. We Are Implementing A Plan To Manage Risk 

We have raised the bar on safety. 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. 

By strengthening our ability to better collect and analyze data, we can better 

characterize safety issues and highlight pipeline operators with performance concerns. 

We have also strengthened our regulations and oversight to respond to problems. 

1. Higher Standards 

We have raised the standards for pipeline safety across the board through 

requirements for integrity management, operator qualification, public education and 19 

other regulations, and incorporated 68 new national consensus safety standards. 

 

2. Better States’ Partnership 

We have strengthened our partnerships with State pipeline safety agencies through 

increased policy collaboration, better training, shared databases, and a distributed 

information network to facilitate communication. In partnership with our State 

inspectors, we are working hard to deliver better oversight in accordance with higher 

standards. 

3. Stronger Enforcement 

We have taken advantage of higher penalty authority and have institutionalized a 

tough-but-fair approach to enforcement. We are imposing and collecting larger penalties, 

while guiding pipeline operators to enhance higher performance. We also coordinated 

much more effectively with other Federal agencies, including the Department of Justice 

and the Environmental Protection Agency. We have identified several performance 

measures to track the impact of our enforcement efforts, such as the severity of inspection 

findings. Compared to 2003, the first year when higher penalty authority was available, 

we doubled the civil penalties proposed in 2004 and tripled them in 2005. For calendar 

year 2005, the proposed penalties amounted to over $4,000,000. For the period from 

calendar year 2003 to 2005, PHMSA has closed 56 percent of the penalty cases and 

collected 94 percent of penalties we proposed. 

4. Better Technology 

To improve the technology available to assess and repair pipelines, we have invested 

over $22 million in technology research and development since 2002 and leveraged an 

additional $26 million in investments from the private sector. These investments have 

jump-started more than 80 projects across the country and have already generated eight 

new patent applications. 
15

5. Greater Resources

DOT has requested, and the Congress has appropriated, 24.5 percent more resources 

since 2002 to help implement the plan to improve pipeline safety. 

II. Sharing Responsibility ─ Preparing Partners 

Advancing pipeline safety in the face of growing construction in our communities is 

a big task and we need help to succeed. 

We have identified clear roles for others at the Federal, State, and local levels of 

government and citizens to help us and they are responding. These roles range from 

environmental and emergency planning to better zoning and management of land use 

near pipelines, to helping prevent damage and permitting repairs to pipelines, to citizens 

taking safety actions to protect themselves. 

Our pipeline safety communications program provides crucial knowledge about the 

pipeline system to our various stakeholders, including our citizens, which enables them to 

share responsibility for continuously improving safety. PHMSA has invested over $5 

million since the passage of the PSIA to bring meaningful information to the public 

regarding pipeline operator performance. We recognize that by “going local,” we are 

better able to affect pipeline safety where it matters most─ in the neighborhoods where 

our Nation’s citizens work, play and live. 

III. Effective Stewardship 

Our role has evolved in response to a dynamic environment. The energy pipeline 

infrastructure in the United States represents a $31 billion investment. These energy 

highways also transport the essential fuels needed to produce a myriad of goods and 

services in our economy and make millions of jobs possible. 

The agency’s relationship with the industry it regulates has proved vital in the timely 

understanding of operational problems caused by natural disasters and our ability to 

rapidly respond. During Hurricanes Katrina and Rita, PHMSA moved quickly to assess 

interruptions in energy product transportation and facilitated rapid restoration of supply. 

By working with our sister agencies and pipeline operators, DOT was responsible for 

returning our pipeline infrastructure to full operating capability within days of each 

storm’s passing. 

From our vantage point as safety regulators over the entire industry, we have a 

unique knowledge of this infrastructure. By what we know, we can inform other 

agencies to help with energy capacity planning as well as economic and security 

considerations. 

IV. Responding to the Pipeline Safety Improvement Act of 2002 

The Congress recognized the critical importance of pipelines to our Nation’s vitality 

when it passed the Pipeline Safety Improvement Act of 2002. Under Secretary Mineta’s 

leadership, PHMSA has aggressively responded to these new mandates. 

1. Integrity Management 

Since last appearing before this Committee in June 2004, PHMSA is now enforcing 

regulation of integrity management programs for both hazardous liquid and natural gas 

transmission operators. PHMSA and its State partners have completed comprehensive 

inspections of large hazardous liquid operators who are assessing and repairing nearly 80 

percent of the Nation’s hazardous liquid pipelines, resulting in the elimination of over 

20,000 time sensitive pipeline defects. Our hazardous liquid integrity inspections 

address, among other safety issues, the adequacy of placement of emergency flow 

restricting devices and the adequacy of the leak detection systems. We worked with 46 

percent of operators inspected to improve their preventive and mitigation measures. 
16

PHMSA has now completed 13 percent of gas transmission integrity management 

inspections, providing supplemental protections for approximately two-thirds of 

American communities living along natural gas pipelines. We expect eventually that 

nearly 60 percent of the natural gas transmission pipeline mileage will be similarly 

assessed and repaired. 

In June 2005, the Administration submitted our plan to Congress to strengthen the 

safety of gas distribution pipeline systems through use of integrity management 

principles. We work closely with the State Utility Commissions who have jurisdiction 

over distribution systems and the ultimate authority to decide what additional protections 

to require and what costs to pass on to consumers. We are following the guidance 

provided in the February 16, 2005 National Association of Regulatory Utility 

Commissioners’ “Resolution on Distribution Integrity Management” in implementing 

this safety plan which urges a performance based approach that leaves states flexibility. 

PHMSA began work with the Gas Piping Technology Committee to develop consensus 

guidance to accompany the agency rulemaking that is underway. 

2. Operator Qualification 

Our regulations require operators of gas and hazardous liquid pipelines to conduct 

programs to qualify individuals who perform certain safety-related tasks on pipelines. In 

early 2003, we developed a standard to evaluate the adequacy of operators’ programs, as 

required by the PSIA. We also issued a Direct Final Rule that codifies the new mandated 

requirements concerning personnel training, notice of program changes, government 

review and verification of programs, and use of on-the-job performance as a qualification 

method. 

 We completed all reviews of interstate operators’ qualification programs and met the 

2005 statutory deadline. States have made similar progress. Our report to the Congress 

is due December 2006. We held two public meetings to seek more comprehensive 

information from states, the public and the pipeline industry to produce an informative 

final product. 

We are considering some additional improvements in our regulations. We plan to 

incorporate in our enforcement approach improved consensus standards for the 

qualification of pipeline operators for safety critical functions. 

 As required by the PSIA, we conducted a controller certification pilot program to 

evaluate how best to further assure pipeline controllers have and maintain adequate 

qualification for their required job tasks. We reviewed information on training and 

qualification programs from a variety of resources, including programs of other 

industries, the NTSB, operators, trade associations, public interest groups, system 

vendors, and simulator specialists. We have completed our assessment and will hold a 

public workshop in June to share our findings. This workshop will focus on alarms, shift 

change procedures, roles controllers play, fatigue, recognition of abnormal events, and 

validation of adequacy of control processes. 

3. Public Education and Mapping 

Working with others, we are raising the quality of public education operators 

provide, as well as what we provide. First we oversaw operators’ self assessments 

required in the PSIA and determined considerable improvement was needed. We called 

for a new consensus standard for public education and stakeholders responded by 

creating one that significantly raised the bar. The NTSB acted to close all its 

recommendations on public education. We conducted four nationwide, webcast public 

meetings on this standard to build effective public awareness programs. Currently, we 

are developing a clearinghouse to review and evaluate the adequacy and effectiveness of 

more than 2,200 public safety and education programs established locally by the pipeline 

industry. 
17

We have enlisted State fire marshals to help bring information and guidance to 

communities across America and build an understanding of pipeline safety and first 

responder needs. In less than 15 months, we made great strides in advancing our fire 

service training curriculum. We have provided training to approximately 5,000 trainers 

in 31 States and distributed over 13,000 textbooks, 5,000 instructor guides and 6,000 

training videos. The first-of-its-kind pipeline accident response training and public 

education program for first responders will help pipeline operators to identify high 

consequence areas in communities and provide an understanding of liquefied natural gas 

operations. 

We are improving our efforts to reach the public by preparing local officials to be 

public education resources within communities and providing additional resources for 

citizens to learn how they can protect themselves and pipelines. Our community 

assistance and technical services staff provide information to citizens and advise local 

officials to guide their decisions about local land use. We also utilize the efficiency of 

the World Wide Web to give citizens and other stakeholders instant access to community 

specific pipeline information with our newly established stakeholder communications 

website. 

We completed the base structure of the National Pipeline Mapping System in 2003, 

and keep it up to date with improvements. We recently made the system available for 

public web searches on contact information of pipeline companies and made other web 

improvements to help the public access general information on pipelines and operator 

performance. We provide more sensitive mapping information to Federal, State and local 

governments through a password-protected application. This information is restricted by 

jurisdiction and cannot be released outside of the requesting agency. 

Working with the pipeline industry and State agencies, we annually hold about 15 

public meetings per year to acquaint citizens and public officials with essential safety 

information to make informed decisions about living safely with and minimizing damage 

to pipelines. 

4. Damage Prevention 

Helping communities know how they can live safely with pipelines by preventing 

damage to pipelines is a very important goal. We cannot succeed without enlisting the 

help of State and local officials and the full range of public safety stakeholders who share 

an interest in protecting all underground infrastructure. 

We work with the Common Ground Alliance (CGA) on all damage prevention 

efforts, leading many stakeholders to share responsibility for damage prevention. We are 

now planning to implement the most important new tool in our assault on third-party 

damage to pipelines, three-digit dialing, required in the PSIA. The Federal 

Communications Commission responded favorably to our request for a single three-digit 

number usable for “one call” anywhere in the U.S. Three-digit dialing of “811” provides 

a single uniform action that all Americans can take to improve safety. Since 2002, our 

partnership with the CGA has helped us address nine NTSB recommendations in 

preventing damage to pipelines. 

We also worked with CGA to create 44 new regional CGAs to help communities 

implement damage prevention best practices across all underground facilities. These 

alliances provide synergy in the “underground” among other utilities, railroads, insurance 

companies, public works and other municipal organizations, to implement best safety 

actions. The CGA highlights best practices of leading States such as Minnesota, 

Virginia, Connecticut, Georgia, and Massachusetts in identifying and enforcing the 

elements of an effective damage prevention program for other States to follow. These 

States’ enforcement against all who violate their laws led to a 50 percent decrease in 

damages in just a few years. Strengthening enforcement is one of many important best 
18

practices we promote through the CGA and with our state partners and we believe all 

states can achieve similar results. 

5. Research and Development 

Over the past three years, PHMSA has built a research and development (R&D) 

program that has funded 80 projects at a cumulative expense of nearly $50 million to 

address better diagnostic tools, testing of unpiggable pipes, stronger materials, improved 

pipeline locating and mapping, prevention of outside force damage, and leak detection. 

We are focused on near-term technology development needs. We support 

technology demonstrations such as remote sensing of gas leaks and internal inspection of 

unpiggable pipes. 

We are maximizing the return on our R&D investment by coordinating activities 

within and with other Federal agencies such as the Department of Commerce, National 

Institutes of Standards and Technology and the Department of Interior. 

6. Interagency Efforts to Implement Section 16 of the PSIA 

Since our last testimony, we have designed and are testing a web-based 

environmental permit review process to: (a) provide early electronic notification of 

proposed pipeline repairs to Federal agencies, and solicit State and local agencies 

involved in the review process for pipeline repairs and (b) expedite coordination and 

approval of recommended best practices for operators to use to manage environmental 

damage when repairing their pipelines in environmentally important areas. This process 

meets the requirements of the PSIA by ensuring all environmental laws are addressed in 

the most efficient manner. A remaining issue is timely, consistent participation by all 

permitting agencies. 

IV. We are Achieving Results 

When we compare the years 2001-2005 to the previous five-year period of 1996-

2000, the rate of hazardous liquid pipeline accidents has declined by 18 percent. In 

addition, by 2005 the volume of significant oil spills decreased by 34 percent from the 

previous 10 year average, and the 10-year average volume of net spills for the same 

period decreased 36 percent. 

Pipeline excavation related accidents decreased over the past ten years by 59 

percent. This outcome is largely due to the result of working with our State partners and 

the more than 900 volunteer members of the Common Ground Alliance who strive to 

foster damage prevention activities. 

In the face of ten years of increased new construction, other accident types remain 

relatively stable. Accidents of most severe consequence, involving deaths and injuries 

are trending steadily downward. 

In closing, I want to reassure the members of this Subcommittee, that the 

Administration, Secretary Mineta, and the hardworking men and women of PHMSA 

share your strong commitment to improving safety, reliability, and public confidence in 

our Nation’s pipeline infrastructure. 

I would be pleased to answer your questions. 

 MR. HALL. And I thank you very much. 

 Mr. Theodore Alves, Principal Assistant Inspector General for Audit 

and Evaluation, Office of Inspector General, we will recognize you, sir. 

MR. ALVES. Thank you. 
19

 Mr. Chairman, Ranking Member, and members of the subcommittee, 

I appreciate the opportunity to testify today about progress that has been 

made in strengthening pipeline safety. 

 We have seen considerable progress since we first testified on this 

issue over 6 years ago. That progress is the direct result of the attention 

from this subcommittee, Secretary Mineta, and the Office of Pipeline 

Safety, as well as the States, industry, and other groups, such as the 

Common Ground Alliance. 

 The Office of Pipeline Safety has completed action on 18 of the 23 

mandates from the 2002 Act. One outstanding mandate from 1992 

establishing safety regulations for hazardous liquid gathering lines and 

low-stress transmission lines is scheduled to be completed by the end of 

this year. 

 This focus on implementing congressional mandates has 

significantly improved pipeline safety, but we are not yet at an end state 

because operators are in the early stages of implementing integrity 

management programs. 

 Today, I would like to make six points. 

 First, operators are identifying integrity threats and making timely 

repairs. Although operators have not yet fully implemented their 

integrity management programs, they are making good progress 

completing baseline assessments, and they are on track to complete the 

assessments. Preliminary indications are that the program is identifying 

and the operators are repairing a significant number of integrity threats. 

Our auditors visited seven hazardous liquid pipeline operators and found 

that they had repaired all 409 integrity threats we had examined. About 

98 percent of the repairs were also completed within established 

timeframes. 

 Second, reports from six of the seven hazardous liquid operators we 

visited contained errors. The errors were due to several factors, such as 

using preliminary data or data outside the reporting period. Accurate 

reports are important to the Office of Pipeline Safety’s risk-based 

oversight approach, and the Office is working with operators to improve 

their reporting. 

 Third, the Office of Pipeline Safety inspection program is helping 

operators improve safety. As of December of 2005, the Office of 

Pipeline Safety and its State partners had conducted inspections at over 

86 percent of the 249 hazardous liquid operators. At one operator we 

visited, inspectors found threats that had not been repaired in a timely 

manner. The operator has since made the repairs. 

 Fourth, the Office of Pipeline Safety and a broad range of 

stakeholders now agree that natural gas distribution operators should 

implement integrity management programs. This is important because 
20

nearly all distribution pipelines are in high-consequence areas where a 

rupture could have severe consequences. And while actual numbers 

remain low, injuries and fatalities involving distribution pipelines have 

gone up over the last 5 years. The Pipeline Safety Office is drafting a 

rule calling for operators to develop integrity management plans during 

2008, and to begin implementing those plans in 2009. 

 Fifth, security responsibilities still need to be clarified. DOT and 

DHS have signed a Memorandum of Understanding to improve their 

security coordination. Even though Congress told DOT and DHS in 

October of 2004 to come up with an annex to their MOU clarifying roles 

and responsibilities for pipeline security, this has not been done. The 

lack of clearly defined roles could lead to duplicative or conflicting 

efforts and the potential for an uncoordinated response to a terrorist 

attack. 

 Finally, Congress may wish to consider strengthening the Secretary’s 

authority to waive safety regulations during a disaster. By law, the 

Secretary may waive the pipeline safety regulation, but only after public 

notice and an opportunity for a hearing. With an emergency like Katrina, 

this requirement may not always be practical. In fact, during Katrina, 

loss of electrical power to pumping stations forced three major operators 

to shut down, cutting off most sources of fuel to the eastern seaboard. 

The Pipeline Safety Office sent inspectors to oversee manual operations 

and remote pumping stations. That direct oversight avoided any question 

about whether a waiver was required to operate the system safely, but in 

a future emergency, a waiver might be the only way to respond in a 

timely manner. 

 Mr. Chairman, this concludes my statement. I will be pleased to 

answer any questions that you or other members may have. 

 [The prepared statement of Theodore Alves follows:] 

PREPARED STATEMENT OF THEODORE ALVES, PRINCIPAL ASSISTANT INSPECTOR GENERAL 

FOR AUDIT AND EVALUATION, OFFICE OF INSPECTOR GENERAL, U.S. DEPARTMENT OF 

TRANSPORTATION

Summary 

The Office of Pipeline Safety (OPS) is making good progress in implementing 

congressional mandates and improving pipeline safety. I would like to briefly summarize 

my major points. 

Operators are identifying integrity threats and making timely repairs. Although 

operators have not yet fully implemented their Integrity Management Programs (IMP), 

preliminary indications show that the baseline integrity assessments of hazardous liquid 

and natural gas transmission pipelines are working well. In our current review of 

integrity threats to hazardous liquid pipelines, we found that operators had repaired all 

409 threats we examined, with approximately 98 percent of the repairs having been 

completed on time. 
21

However, pipeline operator reports contain errors and OPS needs to work with 

operators to improve their reporting. Six of the seven hazardous liquid pipeline 

operators we visited had errors in their annual reports. OPS is taking steps to improve the 

accuracy of operator annual reports but needs to verify the accuracy of reported threat 

data during integrity management inspections. Inaccurate reports degrade OPS’s ability 

to analyze integrity threats, identify important trends, and focus limited inspection 

resources. 

OPS’s integrity management inspection program is helping operators comply 

with the IMP requirements. As of December 2005, OPS and its state partners had 

conducted one or more integrity management inspections for over 86 percent of the 249 

hazardous liquid pipeline operators. We also have seen evidence that OPS’s enforcement 

program is helping to improve pipeline safety. 

Initiatives are underway to establish IMPs for natural gas distribution 

pipelines. OPS, its state partners, and a broad range of stakeholders agree that all gas 

distribution pipeline operators should implement IMPs. OPS is drafting a rule requiring 

IMPs for all gas distribution operators and plans to have the final rule issued in mid-2007. 

It expects operators of natural gas distribution pipeline systems to develop integrity 

management plans during 2008 and begin implementing those plans in 2009. 

OPS and TSA need to establish their respective pipeline security roles and 

responsibilities. In September 2004, the Departments of Transportation and Homeland 

Security signed a Memorandum of Understanding (MOU) to improve their cooperation 

and coordination. Now OPS and the Transportation Security Administration (TSA) need 

to spell out their roles and responsibilities at the operational level in an annex to the 

MOU. A lack of clearly defined roles among OPS and TSA at the working level could 

lead to duplicating or conflicting efforts, less than effective intergovernmental 

relationships, and—most importantly—the potential for an uncoordinated response to a 

terrorist attack. 

The Secretary’s waiver authority for responding to disasters may need to be 

strengthened. OPS took an active role in responding to and recovering from Hurricane 

Katrina disruptions to the pipeline system. By law, the Secretary of Transportation is 

authorized to grant waivers of pipeline safety requirements only after public notice and 

an opportunity for a hearing. It may not always be possible for OPS and pipeline 

operators to work around waiver requirements. Thus, Congress should consider whether 

the Secretary’s waiver authority for responding to a disaster involving pipeline 

transportation needs to be strengthened. 

Mr. Chairman, Ranking Member, and Members of the Subcommittee: 

We appreciate the opportunity to testify today on the progress and remaining 

challenges in strengthening pipeline safety. We have done a great deal of work over the 

years evaluating the Department of Transportation’s (DOT) efforts to improve pipeline 

safety and have issued a number of reports and testified several times before this 

Subcommittee and other congressional subcommittees about progress and challenges the 

Department and industry have faced. 

The pipeline infrastructure consists of 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—hazardous liquid transmission pipelines, natural gas 

transmission pipelines, and natural gas distribution pipelines—and has about 2,2001

natural gas pipeline operators and 250 hazardous liquid pipeline operators. 

 

1

 Of the 2,200 operators of natural gas pipelines, there are approximately 1,300 operators of natural 

gas distribution pipelines and 880 operators of natural gas transmission pipelines. 
22

Within the DOT’s Pipeline and Hazardous Materials Safety Administration 

(PHMSA), the Office of Pipeline Safety (OPS) is responsible for overseeing the safety of 

the Nation’s pipeline system. This oversight is important because pipelines, while 

fundamentally a safe way to transport these inherently dangerous resources, are subject to 

forces of nature, human actions, and material defects that can cause potentially 

catastrophic events. OPS sets safety standards that pipeline operators must meet when 

designing, constructing, inspecting, testing, operating, and maintaining their pipelines. In 

general, OPS is responsible for enforcing regulations over interstate pipelines and 

certifies programs the states implement to ensure the safety of intrastate pipelines. 

Today, I would like to discuss three major points regarding pipeline safety: 

• Progress made in implementing integrity management program (IMP) 

requirements and the challenges that remain. 

• Initiatives underway to strengthen the safety of natural gas distribution pipeline 

systems. 

• Need for clearer lines of authority to address pipeline security and disaster 

response. 

Before I discuss these points, I would like to briefly summarize the considerable 

progress we have seen since we first testified on pipeline safety over 6 years ago. This 

progress is the direct result of congressional attention, including that of this 

Subcommittee; high-level management attention under the leadership of Secretary 

Mineta; and OPS’s priority to improve its pipeline safety program. This progress started 

under what was then the Research and Special Programs Administration and continues 

today under PHMSA, which was created under the Norman Y. Mineta Research and 

Special Programs Improvement Act. Even during this reorganization, OPS was able to 

sustain its progress in improving pipeline safety. 

As an indication that we were seeing clear signs of improvement, we removed 

pipeline safety from our DOT top management challenge report in 2002. As we testified 

before the House Subcommittee on Highways, Transit, and Pipelines on the 

reauthorization of the pipeline safety program in February 2002, OPS was making 

progress in implementing prior congressional mandates and our recommendations. 

However, with 8 mandates open from 1992 and 1996, plus an additional 23 mandates 

enacted in the Pipeline Safety Improvement Act of 2002, a lot of work remained. 

Our June 2004 report,2

 “Actions Taken and Needed To Improve Pipeline Safety,” 

recognized OPS’s continued progress in clearing out most, but not all, of the 

congressional mandates enacted in 1992 and 1996. This included completing the 

development of the national pipeline mapping system and issuing regulations requiring 

IMPs for operators of hazardous liquid and natural gas transmission pipelines. These 

results were included in our last testimony before this Subcommittee in July 2004. 

In our October 2005 report,3

 we again recognized that OPS’s progress in closing out 

the long-overdue mandates and National Transportation Safety Board safety 

recommendations. Currently, there is only one open mandate from 1992, and OPS 

expects to close it by the end of 2006 through a rulemaking establishing safety 

regulations for hazardous liquid gathering lines and low stress transmission pipelines. 

The importance of completing and finalizing this rule cannot be overstated as it is 

pertinent to the low stress transmission pipeline that failed just last month on the North 

Slope of Alaska. As a result of the failure, an estimated 200,000 gallons of crude oil 

spilled, impacting the Arctic tundra and covering approximately 2 acres of permafrost. 

 

2

 OIG Report No. SC-2004-064, “Actions Taken and Needed for Improving Pipeline Safety,” June 

14, 2004. 3

 OIG Report No. SC-2006-003, “Actions Taken and Needed in Implementing Mandates and 

Recommendations Regarding Pipeline and Hazardous Materials,” October 20, 2005. See OIG 

reports on this website: www.oig.dot.gov. 
23

All of the mandates from 1996 are closed, and OPS has completed actions on 18 of 

the 23 mandates from the 2002 Act. Three of these open mandates are not yet late, since 

the congressional deadlines for completing them have not come due. 

Clearly, OPS is making good progress in implementing congressional mandates and 

improving pipeline safety, but it is not at an end state because operators are in the early 

stages of implementing IMPs. I would now like to turn to my three points on pipeline 

safety. 

Progress Made in Implementing Integrity Management Program Requirements 

and the Challenges That Remain. The most important congressional mandates required 

IMPs for operators of hazardous liquid and natural gas transmission pipelines. Operators 

are required to identify their pipelines in or potentially affecting high-consequence areas 

(HCA)4

 and assess their pipelines for risk of a leak or failure using smart pigs5 or 

equivalent inspection methods. Hazardous liquid pipeline operators were first to come 

under the new IMP requirements, starting in 2001. Natural gas transmission pipeline 

operators followed 3 years later. Operators were also required to categorize and repair 

integrity threats within specified timeframes and to report these threats to OPS. 

Although operators have not yet fully implemented their IMPs, preliminary 

indications show that the baseline integrity assessments of hazardous liquid and natural 

gas transmission pipelines are working well, and there was clearly a need for such 

assessments because the assessments led operators to identify and correct a significant 

number of integrity threats. This is a key outcome as the IMP is the backbone of OPS’s 

risk-based approach to overseeing pipeline safety. 

According to data provided by OPS, hazardous liquid and natural gas transmission 

pipeline operators have identified all of their HCAs and are well on their way toward 

completing their baseline assessments on time. As of December 31, 2004 (the latest data 

reported), hazardous liquid operators had completed baseline assessments of 

approximately 95 percent of their pipeline systems in or potentially affecting HCAs, even 

though they have until 2009 to do so. In comparison, at the end of 2005, natural gas 

transmission pipeline operators had completed around 33 percent of their baseline 

assessments of pipelines in or potentially affecting HCA pipeline systems, but they have 

until 2012 to complete the assessments. 

Operator baseline assessments have been instrumental in helping identify and repair 

a significant number of integrity threats. In our current review of integrity threats to 

hazardous liquid pipelines, we found that operators had repaired all 409 threats we 

examined, with approximately 98 percent of the repairs completed within established 

IMP timeframes or OPS-approved extensions. OPS has also made noticeable progress in 

overseeing IMP implementation through its integrity management inspection program, 

and we have seen examples of OPS directing operators to take corrective actions when 

violations were found. As of December 2005, OPS and its state partners had conducted 

one or more integrity management inspections of 86 percent (215 of 249) of hazardous 

liquid pipeline operators. 

However, we have concerns with the reports submitted to OPS on integrity threats. 

Specifically, six of the seven hazardous liquid pipeline operators we visited had errors in 

their reports. Reporting errors were due to a variety of factors, such as the submission of 

preliminary numbers, of data outside the reporting period, or of threats involving nonHCA pipeline segments. OPS is taking steps to improve the accuracy of operator annual 

reports and to help operators better understand the reporting requirement. But OPS needs 

to review integrity threat data and related documentation as part of its integrity 

 

4

 HCAs include unusually sensitive areas (defined as drinking water or ecological resource areas), 

urbanized and other populated places, and commercially navigable waterways. 5

 A “smart pig” is an in-line inspection device that traverses a pipeline to detect potentially 

dangerous defects, such as corrosion. 
24

management inspection program. Our primary concern is that OPS’s risk-based approach 

to safety relies on accurate reporting from operators. Inaccurate reports degrade OPS’s 

ability to analyze integrity threats, identify important trends, and focus limited inspection 

resources on areas of greatest concern. 

Initiatives Underway To Strengthen the Safety of Natural Gas Distribution 

Pipeline Systems. In our June 2004 report, we recommended that OPS require operators 

of natural gas distribution pipelines to implement some form of pipeline integrity 

management or enhanced safety program with the same or similar integrity management 

elements as the hazardous liquid and natural gas transmission pipelines. 

Since 2004, there has been a sea change in the industry toward integrity 

management for natural gas distribution pipeline systems. OPS, in partnership with the 

industry stakeholders, is developing a plan to strengthen the safety of natural gas 

distribution pipeline systems using integrity management principles. So far, the process 

for developing a natural gas distribution IMP has worked well, and indications are that 

progress will continue. 

Although much has been accomplished, much more remains to be done before 

distribution IMPs can be implemented. OPS, its state partners, and a broad range of 

stakeholders have decided that all distribution pipeline operators, regardless of size, 

should implement an IMP. OPS is drafting a rule requiring integrity management for all 

gas distribution operators and plans to have the final rule issued in mid-2007. It expects 

operators of natural gas distribution pipeline systems to develop integrity management 

plans during 2008 and begin implementing those plans in 2009. 

Need for Clearer Lines of Authority To Address Pipeline Security and Disaster 

Response. Not only is it important that we ensure the safety of the Nation’s pipeline 

system, but we must also ensure the security and recovery of the system in the event of a 

terrorist attack or natural disaster. 

Since we last testified before this Subcommittee on the issue of pipeline security in 

July 2004, DOT and the Department of Homeland Security (DHS) signed a 

Memorandum of Understanding (MOU) to improve their cooperation and coordination in 

promoting the safe, secure, and efficient movement of people and goods throughout the 

U.S. transportation system. Finalizing the MOU was the first critical step in what is a 

very dynamic process. However, OPS and the Transportation Security Administration 

(TSA) still need to spell out their roles and responsibilities at the operational level in an 

annex to the MOU. A lack of clearly defined roles among OPS and TSA at the working 

level could lead to duplicating or conflicting efforts, less than effective intergovernmental 

relationships, and—most importantly—the potential for an uncoordinated response to a 

terrorist attack. 

With respect to natural disasters, OPS took an active role in responding to and 

recovering from Hurricane Katrina disruptions in the pipeline system. What we learned 

from this disaster is that, by law, the Secretary of Transportation is authorized to grant 

waivers of pipeline safety requirements only after public notice and an opportunity for a 

hearing. However, with an emergency like Katrina, this would not have been practical. 

Katrina disruptions to the pipeline system caused the pipeline operators to switch their 

operations from automated to manual. When responding to Katrina, OPS had to send its 

inspectors out to remote pumping stations immediately following the storm to personally 

ensure that the pipeline operator personnel were technically qualified to operate the 

pipeline systems manually and keep the fuel flowing. 

It may not always be possible for OPS and pipeline operators to work around waiver 

requirements, as occurred in this case. Therefore, Congress should consider whether the 

Secretary’s waiver authority for responding to a terrorist attack or disaster involving 

pipeline transportation needs to be strengthened. 
25

Specific Observations 

I. Progress Made in Implementing Integrity Management Program Requirements 

and the Challenges That Remain 

Operators Are Making Significant Progress in Fulfilling IMP Requirements. 

According to data provided by OPS, hazardous liquid and natural gas transmission 

pipeline operators have made significant progress in recent years in implementing key 

elements of their IMPs. For example, according to OPS, both pipeline segments have 

identified all of their HCAs. Operators are also well on their way toward completing 

their baseline assessments of pipeline systems in or affecting HCAs. As Table 1 

indicates, 

operators 

have 

complete

d 

baseline 

assessme

nts on 

approxim

ately 

77 percen

t of their 

pipeline 

systems as of December 31, 2004, with hazardous liquid and natural gas transmission 

segments completing approximately 95 percent and 18 percent, respectively. This latter 

figure jumps to 33 percent when 2005 assessment numbers are added.6

 

Although hazardous liquid and natural gas transmission pipeline operators are only 

required to assess pipelines in or potentially affecting HCAs, some operators—on their 

own initiative—have extended their baseline assessments to some of their non-HCA 

pipeline segments. For example, hazardous liquid pipeline operators have conducted 

baseline assessments on over a quarter of their non-HCA pipelines as of December 31, 

2004. 

Large Numbers of Integrity Threats Are Being Identified and Repaired on 

Time, Although Operator Annual Reports Need Improvement. According to OPS, 

tens of thousands of hazardous liquid pipeline integrity threats have been discovered and 

repaired as of the end of 2004. Approximately one quarter of these threats fell into timesensitive repair categories of immediate, 60-day, or 180-day. The majority of threats 

were categorized as “other,” which are not considered time-sensitive. In our current 

review of integrity threats to hazardous liquid pipelines, we found that operators had 

repaired all 409 threats7

 we examined, with approximately 98 percent of the repairs 

completed within established IMP timeframes or OPS-approved extensions. 

While recognizing IMP success in identifying and repairing integrity threats, we 

have concerns with the reports submitted to OPS on integrity threats. OPS uses the data 

in these reports, much of which is available to the public, in a variety of ways, including 

identifying important trends, prioritizing integrity management inspections, and 

monitoring industry performance and regulatory compliance. Yet, our current review 

 

6

 We do not have 2005 data for hazardous liquid pipeline operators since their annual reports are 

not due to OPS until June 15, 2006. In comparison, natural gas pipeline operators were required 

to submit their 2005 data by 

February 28, 2006. 7

 Our sample of 409 threats was pulled from operator data bases, not from information reported to 

OPS. 

Table 1. Completed Baseline Assessments 

(As of December 31, 2004) 

Operator HCAs* 

Baseline 

Assessments* 

% 

Completed 

Hazardous 

Liquid 71,903 67,982 95% 

Natural Gas 

Transmission 21,727 3,947 18% 

 Total 93,630 71,929 77% 

* Measured in pipeline miles 
26

found reporting errors in the integrity threat data submitted by six of the seven operators 

we visited. We asked each of the seven operators to re-examine the 2004 threat data that 

they reported to OPS. Six of the seven operators acknowledged having made errors in 

their annual reports, in some cases significant errors. For example, one operator’s 

numbers of immediate, 60-day, and 180-day threats reported to OPS had to be increased 

by 49 percent (i.e., from 53 to 79). In a second example, the operator had to decrease his 

numbers by 41 percent (i.e., from 186 to 110). 

These reporting errors were due to a variety of factors. For example, one operator 

mistakenly reported preliminary pig data instead of actual numbers obtained from 

subsequent excavation and repair work. A second operator reported integrity threat data 

involving non-HCA pipeline segments. Other types of errors included reporting data 

outside the 2004 reporting period and entering numbers relating to pipeline mileage 

rather than integrity threats. Our primary concern is that OPS’s risk-based approach to 

safety needs accurate reporting from operators. Inaccurate reports hamper OPS’s ability 

to analyze threat data, identify important trends, and focus limited inspection resources 

on areas of greatest concern. 

OPS officials are taking steps to improve the accuracy of operator reports and to 

help operators better understand new reporting requirements. OPS plans on issuing new 

reporting guidelines by mid-2006, including clearer definitions of each threat category. 

Starting in January 2006, OPS began posting operator annual integrity threat reports to its 

public website as a means of providing transparency and encouraging greater accuracy. 

While these efforts to improve the accuracy of operator IMP reports should help, OPS 

needs to have operators verify the accuracy of threat data contained in their earlier annual 

reports and submit revised data if errors are found. OPS also needs to verify the accuracy 

of the integrity threat data as part of its integrity management inspection program. 

OPS Inspection and Enforcement Programs Are Helping Achieve Operator 

Compliance With IMP Requirements. OPS has made progress in overseeing IMP 

implementation through its inspection and enforcement programs. During inspections for 

both hazardous liquid and natural gas transmission pipeline operators, OPS and state 

inspectors look at whether operators: (1) perform a thorough and effective review of pig 

results, (2) identify all integrity threats in a timely manner, (3) remediate integrity threats 

in a timely manner, and (4) use the appropriate repair or remediation methods. As of 

December 2005, OPS and its state partners had conducted one or more integrity 

management inspections of 86 percent (215 of 249) of hazardous liquid pipeline 

operators. Even more important, those operators inspected were responsible for 

approximately 98 percent of all pipeline miles in or potentially affecting HCAs. With 

respect to natural gas transmission pipeline operators, which OPS only recently began 

inspecting, OPS had completed inspections on 10 percent (11 of 110) of the operators for 

which it is responsible as of March 2006. 

During our current review of integrity threats, we found evidence of how the OPS 

enforcement program is helping to improve pipeline safety. At one of the seven 

operators we reviewed, OPS inspectors found that the operator had failed to discover 

integrity threats (approximately 160) due to an error in analyzing pig data. Although the 

operator had identified the error and had asked the pig vendor to recalculate the data, 

subsequent repairs were not completed before an integrity management inspection 

2 months later. OPS directed the operator to make necessary corrections and warned the 

operator that OPS would take enforcement action should the operator not address the 

problem. The operator has since made the necessary repairs. 

OPS also took action against Kinder Morgan Energy Partners. On August 24, 2005, 

OPS issued a Corrective Action Order to Kinder Morgan in response to numerous 

accidents in its Pacific Operations unit and designated the entire unit as a “hazardous 
27

facility.”8 The Corrective Action Order requires a thorough analysis of recent incidents, 

a third-party independent review of operations and procedural practices, and a 

restructuring of Kinder Morgan’s internal inspection program. On April 10, 2006, OPS 

and Kinder Morgan entered into a consent agreement that met all of the elements of the 

Order. 

II. Initiatives Underway To Strengthen the Safety of Natural Gas Distribution 

Pipeline Systems 

OPS has implemented IMP requirements for hazardous liquid and natural gas 

transmission pipelines. No similar requirements presently exist for natural gas 

distribution pipelines, and we have recommended that some form of pipeline integrity 

management or enhanced safety program be required. Since 2004, there has been a sea 

change in the industry toward integrity management for natural gas distribution pipeline 

systems. 

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. Nearly all of the 

natural gas distribution pipelines are located in highly populated areas, such as business 

districts and residential communities, where a rupture could have the most significant 

consequences. 

When we testified in July 2004, our concern then was, as it is today, that the 

Department’s strategic safety goal of reducing the number of transportation-related 

fatalities and injuries was not being achieved by natural gas distribution pipelines. In the 

10-year period from 1996 through 2005, OPS’s data show accidents in natural gas 

distribution pipelines have caused more than 3.5 times the number of fatalities (173 

fatalities) and nearly 4.0 times the number of injuries (616 injuries) as the combined total 

of 48 fatalities and 156 injuries for hazardous liquid and gas transmission pipeline 

accidents. In the past 5 years, the number of fatalities and injuries from accidents 

involving natural gas distribution pipelines has increased from 5 fatalities and 46 injuries 

in 2001 to 17 fatalities and 48 injuries in 2005. Given that most pipeline fatalities and 

injuries involve natural gas distribution pipelines, OPS needs to ensure that it moves 

quickly to enhance the safety of these pipelines. 

Initiatives Leading up to the Development of a Natural Gas Distribution 

Integrity Management Program. To close the safety gap on natural gas distribution 

pipelines, we recommended in our June 2004 report on pipeline safety that OPS require 

operators of natural gas distribution pipelines to implement some form of pipeline 

integrity management or enhanced safety program with the same or similar integrity 

management elements as those for hazardous liquid and natural gas transmission 

pipelines. 

In its fiscal year 2005 report, the Conference Committee on Appropriations 

recognized the need for enhancements in the safety of natural gas distribution pipelines 

and agreed with the findings of our June 2004 report that certain IMP elements can 

readily be applied to this segment of the industry, such as developing timeframes on how 

often inspections should take place and when repairs should be made. The Committee 

directed OPS to submit a report detailing the extent to which integrity management plan 

elements may be applied to natural gas distribution pipeline systems to enhance safety. 

The report was submitted in May 2005 with detailed specific milestones and activities, 

including the development of requirements, guidance, and standards. 

 

8

 Normally OPS will designate pipeline segments immediately adjacent to a rupture a “hazardous 

facility.” This Corrective Action Order designated the entire Pacific Operations unit a “hazardous 

facility” because of OPS’s conclusion that the unit had systemic problems with its IMP. 
28

As part of the initiatives in collecting data to prepare the report for the Committee, 

in December 2004, OPS held a public meeting on enhancing integrity management of 

natural gas distribution pipelines. OPS invited our office to participate in the meeting 

and present our views. At the meeting, we outlined three areas that in our view were 

fundamental to integrity management: understanding the infrastructure, identifying and 

characterizing the threats, and determining how best to manage the known risks (i.e., 

prevention, detection, and mitigation). These three areas are essentially the same as those 

underlying the natural gas transmission IMP and would become the foundation for 

building a natural gas distribution IMP. 

Identifying the Need for and Developing a Distribution IMP. In its report to 

Congress in May 2005, OPS outlined the extent to which integrity management plan 

elements could be applied to natural gas distribution pipeline systems to enhance safety. 

A December 2005 report prepared by OPS, its state partners, and a broad range of 

stakeholders concluded that all distribution pipeline operators, regardless of size, should 

implement an IMP that includes seven key elements, three of which are fundamental to 

integrity management: know the infrastructure, identify the threats, and assess and 

prioritize risks. OPS is currently drafting a rule to implement IMP requirements for 

operators of natural gas distribution pipelines. 

With respect to identifying and characterizing threats, the December 2005 report 

points out that “excavation damage poses by far the single greatest threat to distribution 

systems safety, reliability, and integrity: therefore excavation damage prevention presents 

the most significant opportunity for distribution pipeline safety improvements.” 

The source of excavation damage to distribution pipelines can be from anyone who 

has a reason to dig underground, such as homeowners, landscapers, local water and sewer 

departments or their contractors, cable companies, electric companies, and owners and 

operators of distribution pipeline systems or their contractors. 

The December 2005 report also points out that what is needed to prevent excavation 

damage to distribution pipelines in the first place is a comprehensive damage prevention 

program that includes nine important elements, such as enhanced communication 

between operators and excavators, partnership in employee training, partnership in public 

education, and fair and consistent enforcement of the law. 

An important factor in preventing excavation damage is a well-established one-call 

system that excavators must use by law before they dig in an area of a pipeline. A onecall notification system is already in place and provides a telephonic link between 

excavators and operators of underground pipeline and facilities. The heart of the system 

is an operational center whose main function is to transfer information from excavators 

about their intended excavation activities to the operators of underground pipelines and 

facilities participating in the system. 

To further enhance this service, the Federal Communication Commission 

established a three-digit number—811—for one-call systems that excavators and the 

public can use to easily connect to the appropriate one-call center. It is anticipated that 

the 811 number will increase the use of the one-call system service and help avoid 

excavation damage. Under the Federal Communication Commission rule, the 811 

number must be used as the dialing code for one-call centers by April 13, 2007. 

Currently, implementation lies at the state level, with at least one center already accepting 

calls directed to 811. 

We believe a comprehensive damage prevention program is needed as outlined in 

the December 2005 report9

 and that Congress may want to consider legislation to support 

the development and implementation of the damage prevention program with special 

emphasis on effective enforcement. 

 

9

 The December 2005 report, “Integrity Management for Gas Distribution,” was prepared by OPS, 

its state partners, and a broad range of stakeholders. 
29

III. Need for Clearer Lines of Authority To Address Pipeline Security and Disaster 

Response 

The attacks of September 11, 2001, and the devastation and destruction of Hurricane 

Katrina, which hit on August 29, 2005, demonstrated the vulnerabilities of the Nation’s 

critical transportation and energy infrastructure to catastrophic events. What has become 

clear as a result of these events is the continuing need for a well-defined, 

well-coordinated interagency approach for preparing for, responding to, and recovering 

from such events. 

DOT has the responsibility of working with other agencies to secure the U.S. 

transportation system and protect its users from criminal and terrorist acts. In our report 

“DOT’s Top Management Challenges” for FY 2005 and 2006, we discussed the growing 

interdependency among Federal agencies in this area. The imperative for DOT is to 

effectively integrate new security measures into its existing safety regimen and to do so 

in a way that promotes stronger security without degrading transportation safety and 

efficiency. 

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 7: 

• Assigned DHS the responsibility for coordinating the overall national effort to 

enhance the protection of the Nation’s critical infrastructure and key resources. 

• Assigned the Department of Energy 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 the regulation of the 

transportation of hazardous materials by all modes, including pipelines. 

Although the Presidential Directive 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 OPS’s relationship will be with TSA. 

Identifying the Need for Clarifying Security Roles and Responsibilities. In our 

July 2004 testimony, we reported that it was unclear which agency or agencies will have 

responsibility for pipeline security rulemaking, oversight, and enforcement and 

recommended that the delineation of roles and responsibilities between DOT and DHS be 

spelled out by executing an MOU or Memorandum of Agreement. 

Since then, DOT and DHS signed a MOU in September 2004 to improve their 

cooperation and coordination in promoting the safe, secure, and efficient movement of 

people and goods throughout the U.S. transportation system. Finalizing the MOU was 

the first critical step, but much more remains to be sorted out between the two 

departments. For example, the delineation of roles and responsibilities between OPS and 

TSA needs to be spelled out by executing a security annex to the MOU specifically 

relating to pipelines. 

In the October 2004 House Report10 accompanying the Norman Y. Mineta Research 

and Special Programs Improvement Act (Public Law 108-426), which created PHMSA, 

the Committee strongly urged DOT and DHS to execute an agreement clarifying the 

roles, responsibilities, and resources of the departments in addressing pipeline and 

hazardous materials transportation security matters upon establishment of the new 

agency. Today, this has still not been done. 

Resolving pipeline security roles and responsibilities between OPS and TSA is 

necessary to avoid, at the working level, duplicating or conflicting efforts, less than 

 

10 House Report No. 108-749, dated October 6, 2004.
30

effective intergovernmental relationships, and—most importantly—the potential for 

problems in responding to terrorism. OPS already has a set of well-established security 

requirements pre-dating September 11th that it oversees and enforces for operators of 

liquid petroleum gas facilities. What is not clear in this situation is whether oversight and 

enforcement remains with OPS or whether it will be transferred to TSA. 

The pipeline industry clearly supports the need for a security regimen but has 

pointed out to us that it does not need two separate agencies overseeing two separate sets 

of rules and that the issue of security roles and responsibilities needs to be clarified and 

formalized. 

We agree that the roles and responsibilities of OPS and TSA for pipeline 

security-related subjects need to be clarified. These subjects include security grant 

activities, emergency communication, rulemaking and adjudications, and the oversight 

and enforcement jurisdiction of TSA and OPS inspectors. 

Identifying the Need for Waiver Authority When Responding to Disasters. In 

addition to security issues, the growing interdependency among Federal agencies can be 

found in their response to catastrophic natural or man-made disasters. The National 

Response Plan, adopted in December 2004, requires extensive coordination, 

collaboration, and information sharing between Federal, state, local, and tribal 

governments to prevent, prepare for, respond to, and recover from any type of national 

incident, such as Hurricane Katrina. 

We would like to recognize OPS’s efforts in preparing for, responding to, and 

recovering from Hurricane Katrina disruptions on the pipeline system. Loss of electrical 

power to their pumping stations forced three major pipeline operators to shut down. This 

eliminated most sources of fuel to the entire Eastern seaboard and led to a wide array of 

economic disruptions, including hoarding and severe price spikes. OPS’s efforts 

immediately following Hurricane Katrina included, among other things, deploying teams 

to move generators to pipeline pumping stations so that the flow of petroleum products to 

the Southeastern and Mid-Atlantic regions was restored. 

When OPS was preparing for Katrina, a question was raised about whether the 

Secretary had the authority to waive compliance with pipeline safety regulations. By 

law, the Secretary may waive regulations but only after public notice and an opportunity 

for a hearing. However, with an emergency like Katrina, this would not have been 

practical. Katrina disruptions to the pipeline system caused the pipeline operators to 

switch their operations from automated to manual. When responding to Katrina, OPS 

had to send its inspectors out to remote pumping stations immediately following the 

storm to personally ensure that the pipeline operator personnel were technically qualified 

to operate the pipeline systems manually and keep the fuel flowing. It may not always be 

possible for OPS and pipeline operators to work around waiver requirements, as occurred 

in this case. 

The economic disruptions from Katrina were felt immediately and notifying the 

public and holding a hearing would have significantly delayed restoring the flow of 

energy, causing severe economic consequences. Given the lessons learned from 

Hurricane Katrina, Congress should consider whether the Secretary’s waiver authority for 

responding to a terrorist attack or disaster involving pipeline transportation needs to be 

strengthened. 

Mr. Chairman, this concludes my statement. I will be pleased to answer any 

questions that you or the other members might have. 

 MR. HALL. And thank you very much, sir. 

 Mr. Robert Chipkevich, Director, Office of Railroad, Pipeline and 

Hazardous Materials Investigations, the National Transportation Safety 

Board, we recognize you, sir. 
31

MR. CHIPKEVICH. Thank you, sir. 

 Good morning, Chairman Hall, Ranking Member Boucher, and 

members of the subcommittee. 

 Since I last testified before this committee in March of 2002, the 

Pipeline and Hazardous Materials Safety Administration has continued to 

make progress to improve pipeline safety. I would like to briefly 

highlight a few of the safety issues. 

 After a series of pipeline accidents, the Safety Board had 

recommended that PHMSA assess industry public education programs 

and to require pipeline operators to periodically evaluate the 

effectiveness of those programs. In December of 2003, the American 

Petroleum Institute published Recommended Practice 1162 and 

addressed these issues in that. And then in May of 2005, PHMSA 

incorporated the recommended practices into its safety requirements. 

 Progress has also been made in the area of mandatory pipeline 

integrity assessments. The Safety Board had recommended periodic 

inspections of pipelines to identify corrosion, mechanical damage, and 

other time-dependent defects that could be detrimental to the safe 

operation of pipelines. Other rules were published that required both 

liquid and gas transmission line operators to conduct these integrity 

assessment programs. The safety board supported that rulemaking and 

then closed the recommendation that was made in 1987. 

 PHMSA must now ensure that the pipeline operators implement 

effective integrity management programs. Quantifying inputs into 

various risk managed models can be difficult and subjective. And 

PHMSA has shared its inspection protocols with the Safety Board, and as 

we investigate accidents that could involve integrity issues, we will 

examine its process for evaluating those integrity management programs. 

 In 2001, after investigating an accident that had involved the 

explosion of a new home in South Riding, Virginia, the Safety Board 

again recommended that PHMSA require gas pipeline operators to install 

excess flow valves in all new and renewed gas service lines when 

operating conditions are compatible with readily available valves, only 

about one-half of the operators currently install these valves at their cost. 

Excess flow valves should be a stand-alone requirement and not the 

result of a decision based on risk analysis. Risk factors may change over 

time due to community growth or other events, and the cost of 

excavating existing service to homes to install excess flow valves would 

be another factor to then overcome. The excess flow valves are 

inexpensive, and they are safety devices that we believe can save lives. 

 PHMSA’s final rule on operator qualification training and testing 

standards was issued in 2001 that focused on qualifying individuals for 

pertaining certain tasks. However, at that time, it did not require training 
32

or specify maximum intervals for re-qualifying personnel. Last year, 

PHMSA published a rule that now requires operators to provide training 

and held public hearings to explore ways to further strengthen the 

operator qualifications rules. These developments are positive and the 

Safety Board continues to urge PHMSA to move forward on this 

important issue. The Board does believe that operator qualification 

requirements must include training, testing to determine if the training 

was effective, and the re-qualification of personnel on a timely basis. 

 Finally, the Safety Board recently completed a study on a series of 

accidents that involved delayed reaction by pipeline controllers. The 

study found that an effective alarm audit review system by operators 

would increase the likelihood of controllers responding appropriately to 

alarms associated with pipeline leaks and recommended that PHMSA 

required such type reviews by operators. 

 The Safety Board will continue to review activities involving 

pipeline safety, and we do believe, overall, in the past 5 years, there has 

been progress in this area. 

 Mr. Chairman, that completes my statement. I would be happy to 

answer your questions when you are ready. 

 [The prepared statement of Robert Chipkevich follows:] 

PREPARED STATEMENT OF ROBERT CHIPKEVICH, DIRECTOR, OFFICE OF RAILROAD,

PIPELINE, AND HAZARDOUS MATERIALS INVESTIGATIONS, NATIONAL TRANSPORTATION 

SAFETY BOARD

Good morning Chairman Hall, Ranking Member Boucher, and Members of the 

Subcommittee. My name is Bob Chipkevich. I am the Director of the National 

Transportation Safety Board’s Office of Railroad, Pipeline and Hazardous Materials 

Investigations. The Safety Board’s Acting Chairman, Mark Rosenker, asked me to 

represent the Board today to discuss pipeline safety. 

The Safety Board is currently investigating pipeline accidents in Dubois, 

Pennsylvania, involving a leaking butt fusion joint in a 2-inch diameter plastic gas main; 

Kingman, Kansas involving the failure of an 8-inch diameter hazardous liquid pipeline 

carrying anhydrous ammonia; and, Bergenfield, New Jersey where an apartment building 

was destroyed. Excavation activities were being conducted adjacent to a natural gas 

service line located near the apartment building. 

Since I last testified before this Subcommittee in March 2002, the Pipeline and 

Hazardous Materials Safety Administration (PHMSA) has continued to make progress to 

improve pipeline safety. 

After a series of natural gas pipeline accidents in Kansas in 1988 and 1989 and a 

liquid butane pipeline failure near Lively, Texas, in 1996, the Safety Board recommended 

that PHMSA assess industry programs for public education on the dangers of pipeline 

leaks and require pipeline operators to periodically evaluate the effectiveness of those 

programs. 

In December 2003, the American Petroleum Institute published its Recommended 

Practice 1162, Public Awareness Programs for Pipeline Operators, that addressed these 

issues. And in May of 2005, PHMSA incorporated this Recommended Practice into its 

pipeline safety requirements. 
33

PHMSA also has made progress in the area of mandatory pipeline integrity 

assessments. The failure of pipelines with discoverable integrity problems has been a 

safety issue identified in pipeline accidents investigated by the Safety Board for many 

years, and related safety recommendations date back to 1987. The Board recommended 

that PHMSA require periodic inspections or tests of pipelines to identify corrosion, 

mechanical damage, and other time dependent defects that could be detrimental to the 

safe operation of pipelines. 

PHMSA published final rules in 2000 and 2002 requiring liquid pipeline operators 

to conduct integrity assessments in high-consequence areas. And in 2003, PHMSA issued 

similar requirements for natural gas transmission pipelines in high-consequence areas. 

Operators must now assess the integrity of these pipelines using in-line inspection tools, 

pressure tests, direct assessment, or other technologies capable of equivalent 

performance. PHMSA’s rulemaking met the intent of the Safety Board’s 

recommendations and we closed the safety recommendations as “acceptable action. “ 

As the Safety Board has previously noted, PHMSA will have to ensure that pipeline 

operators implement effective integrity management programs. Risk management 

principles, if properly applied, can be powerful tools to identify the risks to pipeline 

integrity and should lead operators to take action to mitigate those risks. Quantifying 

inputs into various risk management models, however, can be difficult and subjective. To 

ensure that the new rules for risk-based integrity management programs are effectively 

employed throughout the pipeline industry, it is important that PHMSA establish an 

effective evaluation program. PHMSA has shared its inspection protocols with the 

Safety Board, and when we investigate pipeline accidents that involve integrity issues we 

will examine the effectiveness of PHMSA’s process for evaluating pipeline operators’ 

integrity management programs. 

In 2001, after investigating an accident that involved the explosion of a new home in 

South Riding, Virginia, the Safety Board again recommended that PHMSA require gas 

pipeline operators to install excess flow valves in all new and renewed gas service lines 

when operating conditions are compatible with readily available valves. PHMSA 

currently requires gas distribution operators, for new or renewed services, to either install 

the valves at their cost or notify customers of their option to have them installed at the 

customer’s cost. Only about one-half of the operators currently install these valves at 

their cost. 

We understand that PHMSA plans to incorporate a decision-making process for the 

installation of excess flow valves into its upcoming gas distribution integrity management 

rules. This would require each operator to employ a risk-based approach to consider the 

mitigation value of installing excess flow valves. PHMSA has asked the Gas Piping 

Technology Committee to develop guidance to address risk factors that would be 

appropriate for this determination. 

The Safety Board believes that its recommendation to install excess flow valves 

should be a stand-alone requirement and not be the result of a decision based solely on 

risk analysis. A decision to install excess flow valves needs to be made when gas lines 

are newly installed or renewed. Once a service is installed, it normally has a very long 

life-- several decades-- before it must be renewed. Risk factors may change over time 

due to community growth or other future events, and the cost of excavating existing 

service to install excess flow valves would be another factor to overcome. Excess flow 

valves are inexpensive safety devices that can save lives. They should be installed 

whenever operating conditions are compatible with readily available valves. 

In 1987, after investigating accidents in Kentucky and Minnesota, the Safety Board 

recommended that PHMSA require operators to develop training and testing programs to 

qualify employees. And following a 1996 accident in San Juan, Puerto Rico, the Board 

recommended that PHMSA complete its rulemaking on operator qualification, training, 

and testing standards. 
34

PHMSA’s final rule, issued in 2001, focused on qualifying individuals for 

performing certain tasks. The Safety Board noted that the final rule did not include 

requirements for training, nor did it specify maximum intervals for re-qualifying 

personnel. The safety recommendation was closed as “unacceptable action.” 

On March 3, 2005, PHMSA published a direct final rule that amended the pipeline 

personnel qualification regulations to conform to the Pipeline Safety Improvement Act of 

2002. Among other changes, this rule required operators to provide training. And on 

December 15, 2005, PHMSA held a public meeting to explore several issues and 

potential ways to strengthen the operator qualification rule. The Safety Board believes 

that operator qualification requirements must include training, testing to determine if the 

training was effective, and the re-qualification of personnel on a timely basis. 

Over the years, the Safety Board has investigated numerous accidents involving 

excavation damage to pipeline systems, and excavation damage continues to be a leading 

cause of pipeline accidents. Therefore, the recent effort of PHMSA and the Common 

Ground Alliance to establish a national one-call number -- 811 -- is especially 

noteworthy. Soon, contractors and homeowners across the country will have an easy-toremember, easy-to-use means for getting underground utilities marked and identified 

before excavation activities begin. We hope that all States will move quickly to ensure 

that this number is incorporated into all telephone exchange systems. 

Last year, the Safety Board completed a study of a series of liquid pipeline accidents 

that involved delayed reaction by pipeline controllers and made several safety 

recommendations to PHMSA. The study found that most controllers indicated that 

alarms represent the most important safety feature of Supervisory Control and Data 

Acquisition (SCADA) systems. However, two controllers reported receiving up to 100 

alarms an hour and one manager noted a reduction from 5,000 alarms a day in the control 

center to 1,000 by working with controllers to develop guidelines for more realistic alarm 

set points. The study found that an effective alarm review/audit system by operators 

would increase the likelihood of controllers responding appropriately to alarms associated 

with pipeline leaks. The Board recommended that PHMSA require pipeline companies 

to have a policy for the review/audit of alarms and that controller training include 

simulator or non-computerized simulations for controller recognition of leaks. The study 

also found that most control center employees worked 12-hour shifts, but the shifts could 

be extended and the cycle of shifts changed. The Board believes that requiring operators 

to report information about controllers’ schedules on accident reports could help PHMSA 

determine the contribution of fatigue to pipeline accidents and recommended that 

PHMSA require operators to provide related data. 

Other safety issues with open recommendations include the need for determining the 

susceptibility of some plastic pipe to premature brittle-like cracking problems; ensuring 

that pipelines submerged beneath navigable waterways are adequately protected from 

damage by vessels; and requiring that new pipelines be designed and constructed with 

features to mitigate internal corrosion. Actions on these safety recommendations are 

classified as “acceptable response” by the Board. 

The Safety Board will continue to review activities involving pipeline safety, but 

clearly progress has been made in the past 5 years. 

Mr. Chairman, that completes my statement, and I will be happy to respond to any 

questions you may have. 

 MR. HALL. I thank you. And we will have questions a little bit later. 

 The Chair recognizes Ms. Siggerud, Director, Physical Infrastructure 

Issues, U.S. Government Accountability Offices for 5 minutes, ma'am. 

Thank you. 
35

MS. SIGGERUD. Thank you, Mr. Chairman, Ranking Member 

Boucher, and members of the subcommittee. I appreciate the 

opportunity to participate in this hearing today on the Pipeline Safety 

Improvement Act. My testimony today is based on the preliminary 

results of our work on the effects of safety stemming from, first, 

PHMSA’s integrity management program for natural gas transmission 

pipelines, and second, the requirement that pipeline operators reassess 

these pipelines for corrosion at least every 7 years. We will be reporting 

in more detail on both of those issues this fall. 

 I would also like to touch on how PHMSA has acted to strengthen its 

enforcement programs since I testified before this subcommittee almost 

two years ago. My statement is based on our review of laws, regulations, 

and discussions with a broad range of stakeholders. This includes 41 

operators representing about 60 percent of the miles of pipeline assessed 

to date. We also surveyed 47 States involved in the program. 

 Early indications are that the integrity management program has 

enhanced public safety by requiring that operators identify and address 

the greatest risks to their pipelines in highly populated areas known as 

HCAs. We found broad support for the program among both operators 

and stakeholders concerned with safety and the environment. Benefits of 

the program include better knowledge of their pipeline systems and 

improved communications within their companies. 

 Pipeline operators are making good progress in assessing their 

pipelines. Since 2004, operators have assessed about 6,700 miles of their 

20,000 miles of pipelines in HCAs and completed 338 repairs that, by 

definition, needed to be made immediately. While it is not possible to 

know how many of these repairs would have been identified without 

integrity management, it is clear that assessing pipelines identifies 

problems that would otherwise go undetected. 

 PHMSA has performed 12 inspections of operators and found that 

they are doing well in conducting their assessments and making 

identified repairs. However, some are having difficulty in the 

documentation of their management processes. Operators we contacted 

also expressed some confusion about how they can tell whether their 

documentation will be sufficient. 

 PHMSA has also been working to improve communication with 

States about their role in overseeing the integrity management program. 

States do play a significant part in integrity management, and most State 

pipeline officials reported that they have started, or will start, inspections 

of intrastate operators this year. However, most also said they are facing 

challenges in the areas of staffing and training. 

 Turning now to the 7-year reassessment requirement, we considered 

operators’ experiences in relation to the industry consensus standards 
36

that basically call for reassessments at 5, 10- 15, or 20-year intervals. 

We have also considered whether the operators expect to be able to 

obtain the resources necessary to implement the requirement. Most of 

the operators that we contacted told us that, if the 7-year requirement 

were not in place, the conditions that they identified would lead them to 

reassess their pipelines at 10, 15, or 20 years following the industry 

consensus standards. 

 For pipelines operating under higher stress, the 7-year reassessment 

requirement represents an approximately midpoint between the 5 and 10-

year industry reassessment requirements for these pipelines. However, 

while the standard requires a five-year interval if all repairs are not made, 

PHMSA’s regulations require that these repairs be made, making the 5-

year interval less relevant. 

 Operators pointed out that reassessing their pipelines in 7 rather than 

10 years creates additional costs without equivalent improvements in 

safety, and that these costs will eventually be passed on to customers. 

Most operators told us the 7-year requirement is also conservative for 

pipelines that operate under lower stress. This is especially true for local 

distribution companies. Most we spoke with reported finding conditions 

that would necessitate another assessment in 15 to 20 years in the 

absence of the 7-year requirement. 

 Operators view the assessment as valuable for public safety. 

However, those operators prefer a risk-based requirement based on 

engineering standards. This approach would be consistent with the 

overall thrust of the integrity management program. Many noted that 

reassessing pipeline segments with no defects every 7 years, in addition 

to not enhancing of safety, takes resources away from other riskier 

segments that require attention. 

 Operators and inspection contractors we contacted told us that the 

services and tools needed to conduct reassessments will likely be 

available to most operators, including during the overlap period from 

2010 through 2012, where some baseline assessment activity and 

reassessments will happen during the same time. Some operators told us 

that they had already signed long-term contracts to lock in the services 

that they need. 

 Another issue is whether natural gas supplies could be interrupted 

and affects the energy market during years when a large number of 

assessments and reassessments occur if operators have to reduce pressure 

in their pipelines to conduct assessments and make repairs. 

 Finally, we reported in 2004 that PHMSA did not have a clear and 

comprehensive enforcement strategy. In response, PHMSA adopted a 

strategy last year that is focused on using risk-based enforcement, 

increasing knowledge and accountability, and improving its own 
37

enforcement activities. Our preliminary review is that this strategy is 

responsive to the concerns we raised. 

 Mr. Chairman, this concludes my statement. I would be happy to 

answer any questions. 

 [The prepared statement of Katherine Siggerud follows:] 

PREPARED STATEMENT OF KATHERINE SIGGERUD, DIRECTOR, PHYSICAL INFRASTRUCTURE 

ISSUES, U.S. GOVERNMENT ACCOUNTABILITY OFFICE
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MR. HALL. All right. I thank you very much. 

 And at this time, the gentleman from Texas, Mr. Gonzalez, do you 

wish to make your opening statement or have it put in the record, sir? 

 MR. GONZALEZ. Put it in the record, thank you very much, Mr. 

Chairman. 

 MR. HALL. Without objection, we will do so. 

 MR. HALL. And we will begin some inquiries here. I guess, Ms. 

Gerard, I will probably start with you. 
66

 Talk to us about how the coordination between your agencies and 

others have been, including TSA, EPA, and Interior, since the enactment 

of the Pipeline Safety Improvement Act of 2002. Where do you see any 

remaining issues, such as response to terrorist threats, emergency waiver 

authority, and spill response, issues like that, if you would? And gosh, 

you have 5 minutes to do that in. 

 MS. GERARD. Coordination with the other Federal agencies has been 

much improved, especially with agencies responsible for permitting 

repairs, environmental permits, especially the Department of Interior 

agencies, EPA, and cooperation is much improved. Also, we work 

closely with the Federal Energy Regulation Commission on L&G issues, 

as well as the Coast Guard, which is now a part of DHS. We have a 

concerted integrated approach, which I believe is more effective. 

 As to security issues, we work closely with the Department of 

Homeland Security on, basically, a daily basis. We are supportive of 

their efforts. They clearly have a lead role in security, and we provide 

our operational expertise on various aspects of planning when requested. 

 You asked about oil spill planning, and I think oil spill planning 

relationships have been fairly constant since the early 1990s and remain 

good. 

 MR. HALL. I have other questions, but I think I will recognize Mr. 

Boucher for his. I believe that we have Members, obviously, that have 

some personal questions and very descriptive testimony to make 

inquiries from, and we will get to them. 

 Mr. Boucher, we will recognize you for 5 minutes or more. 

 MR. BOUCHER. Well, thank you very much, Mr. Chairman. I 

particularly appreciate the “more.” 

 Mrs. Gerard, thank you for your testimony this morning. 

 In my opening statement, I referenced information that I have that, to 

date, the grants that we had required to be made in the 2002 legislation to 

assist communities with technical assistance to address a range of 

pipeline issues have not been made. Is that information correct? And if 

it is correct, why have the grants not been made, as we required four 

years ago? 

 MS. GERARD. Yes, sir, it is correct; we have not made those grants. 

We have not been successful in requesting funding for the grants. We do 

realize the importance of the intent and did step out to meet the intent of 

the law in every way that we could, including improving public 

education standards, making considerable changes to our website to 

provide much more specific and localized information in a form that 

communities could use. We have also hired new staff who are engineers 

who are focused on solely reaching out to communities and State 

government and addressing questions that they have personally. We 
67

have also made changes to the national pipeline mapping system, which, 

although we took it off the website after 9/11, we made modifications so 

that a citizen in a neighborhood could put in a zip code and get 

information on a 24-hour contact with an operator who they could begin 

a dialogue with. 

 MR. BOUCHER. Well, all of those steps sound positive to me, and I 

would applaud you having taken those steps. And I would assume that 

you were able to find funding within your general budget in order to 

finance those particular steps. I would simply encourage you to go back 

and look within your general budget and try to find money for the rather 

modest grants that we expected to be made to local governments. Have 

you gotten any applications from localities for these grants to date? 

 MS. GERARD. We have not gotten applications. We did hold a 

public meeting on the subject a year ago December, and we did discuss 

in public we were specifically seeking advice from stakeholders on what 

type of criteria that we should use to make those grants. And they 

looked to the State of Washington, that has a lot of experience in 

working with stakeholder groups. So I think we have taken steps to 

prepare to make those grants, but haven’t made them due to funding 

issues. 

 MR. BOUCHER. Well, all right. I hear the answer. I don’t think we 

anticipated that an appropriation specifically line-itemed for technical 

assistance grants directed to you would be required for this. It was 

anticipated that your general budget would be sufficient for that purpose. 

 Let me move to another subject. 

 I mentioned, also, in my opening statement the fact that Virginia has 

had a very successful experience with its excavation damage prevention 

program. That program is a creature of State law in Virginia, and it is 

enthusiastically supported by the pipeline industry and also by utilities. 

It derived from a consensus-based process in which all of the 

stakeholders shared views and have their concerns acknowledged, and a 

very successful program arose from that collaborative effort. What 

model from that successful Virginia experience could we derive for 

national application, and would it be helpful for us, in the reauthorization 

of the Pipeline Safety Act, to include some kind of provision? I am not 

suggesting a complete program outlined in the statute, but some kind of 

provision that might lead to similar success stories nationwide. Do you 

have any recommendations for us? 

 MS. GERARD. We completely agree with you that the Virginia 

experience is the most perfect model we have seen anywhere in the 

United States. We have spent a great deal of staff time working with the 

Common Ground Alliance and other States to highlight the performance 

that has resulted from the Virginia experience. We do think it would be 
68

helpful for the committee, as a focus in reauthorization, to look at the 

safety improvements and damage reductions that have been achieved in 

Virginia. And our approach is generally to incentivize States and 

highlight what opportunities there are and give States the opportunity to 

make this choice themselves. 

 MR. BOUCHER. Well, I am not sure there is a whole lot we could do, 

beyond just having this hearing, to inform States of what Virginia has 

done. I was thinking more about some kind of statutory provision that 

might focus attention a little more directly on it. 

 Let me just suggest this. If you have something in mind, or if you 

have a suggestion for us over the next month or two, why don’t you 

share that with us, and we will take a look at what you present? 

 Let me turn to some other questions. I am concerned about what 

happened in Alaska. And briefly let me ask you about the crude oil spill 

that resulted in the loss of approximately 250,000 gallons of crude oil 

from a so-called low-stress transmission line in Alaska. 

 Your agency, I think, has the primary regulatory responsibility for 

these lines, does it not? 

 MS. GERARD. We have the statutory authority to exercise regulation. 

We had not exercised regulation at the time of this bill. That is a 

rulemaking that is underway. And yes, we should have primary 

jurisdiction over it. 

 MR. BOUCHER. Well, I mean, the statute is very clear. It says that 

you may not exempt regulation of a low-stress transmission line simply 

because it has no internal pressure. 

 MS. GERARD. Right. 

 MR. BOUCHER. So I think the intent of Congress was clear that you 

are supposed to regulate these lines. I take it from what you have just 

said that you have not done so so far, and rather than belabor why you 

haven’t done so so far, let me look toward the future. You have got a 

regulation on the books, as I understand it, that basically says that there 

are three bases for exemption for such a line. One would be that it 

doesn’t carry a high volatile liquid. I would assume that that is propane 

or butane. And these are independent bases for exemptions. The second 

would be that it is located in a rural area. And the third is that it is 

outside a navigable waterway. 

 Now it seems to me that these exemptions are so broad that one of 

them could probably be found for the vast majority of most pipelines in 

the country, not those in the city that cross a navigable waterway, maybe, 

but, you know, there is a very small window of opportunity for you to 

regulate these lines at all given the incredible breadth of this set of 

exemptions. I personally think these are exemptions that go well beyond 

the intent of our very clear statute. And they, I think, subvert the intent 
69

of the statute. And I would say to you that either you should change 

these or we need to, in the reauthorization of this Act, clearly direct you 

to regulate these lines in a way that is, perhaps, more precise than what 

we have done so far. 

 Any comment? 

 MS. GERARD. We completely agree that the regulations should be in 

place. We began it in 2004 and slowed down to finalize regulations 

where there was more evidence of human life at risk. But having 

completed those, we are rushing to finish this one. We put a notice in the 

Federal Register posting yesterday that laid out the areas that we intend 

to talk about publicly and give everybody else an opportunity to weigh 

in. It is the third week in June. We hope to have a consensus that day so 

that we can quickly finalize the regulation very shortly after that meeting. 

We wish we had the regulation in place today, and we completely agree 

that these lines should be regulated. We do regulate the low stress lines 

where people are and where there are navigable waterways, and this is 

the last piece of regulation to complete. 

 MR. BOUCHER. All right. Well, that is certainly a schedule that is a 

lot faster than the pace at which we will move, and so I wish you well 

with the exercise, and we will watch with interest the results of your 

rulemaking. 

 Mr. Chairman, with your indulgence, I just had one other question, 

but it is important, I think, that we ask this of the witness. Could I ask 

unanimous consent for another 90 seconds? 

 MR. HALL. Without objection, it is granted. 

 MR. BOUCHER. Thank you very much, Mr. Chairman. 

 We have heard from the Interstate Natural Gas Association an 

expression of concern about the timetables that are contained in the 2002 

law for the initial baseline inspections, and that has to happen on a 10-

year schedule, and then the periodic re-inspections following that 

baseline, which happen on a 7-year schedule. And as I understand the 

concerns the Association has expressed, they are worried that there will 

be some overlap between the 10-year baseline and the 7-year reinspection and that this overlap might cause supply disruption for natural 

gas and that we might wind up in a situation where there are not enough 

inspectors, because they are doing, in essence, both inspections at once. 

And this is too much to expect for a limited supply of inspectors. So, 

you know, they are saying there may be disruptions. That may not be a 

perfect explanation of their concerns, but I think it is close. 

 I know the GAO is in the process of preparing a report. And I 

understand that leading up to that report there has been a suggestion to 

you that operators do not expect the overlap to cause problems and 

finding inspection contractors in order to conduct these reassessments. Is 
70

that an accurate statement of what you have heard so far? And if so, how 

do you square that with what we are hearing from the Interstate Natural 

Gas Association? 

 MS. SIGGERUD. Thank you. 

 It is a very important question, and it is right at the heart of what our 

work is looking at. Let me, first of all, tell you the timetable of our work. 

We will be looking at the 7-year reassessment interval from a couple of 

points of view. First of all, whether it is reasonable from a risk-based 

point of view, and I talked a little bit about that in my statement. We will 

also be looking at the ability of the regulated industry to comply and the 

possible impact on energy supplies. Our hope is to get a report to this 

and the other committees of jurisdiction in early October and to be able 

to brief your staff on our recommendations specifically on this issue a 

month or two before that, probably in late summer. 

 The Act does establish an overlap period. This happens between 

2010 and 2012 when some of the assessments that occurred early in this 

time period will have reached their 7-year interval and will begin to need 

to be reassessed between 2010 to 2012. That is the same period under 

which these operators need to be finishing up the final 50 percent of 

baseline assessments that they are required to complete by 2012. 

 There are two major tools that we are hearing the operators are using 

to conduct their assessments and plan to use for their reassessments. One 

is in-line inspection. The majority are using this approach. The others 

are using direct assessment. 

 In our discussions with in-line assessment contractors and/or the 

operators themselves, they do anticipate having the ability to get access 

to those contractor resources. However, for direct assessment, this is a 

new technique that was established under the law, and there are a number 

of operators just coming into this field to try to perform this concept. 

Therefore, there is a low level of concern there. 

 We don’t have a complete answer on the energy issue at this time, 

but we do find operators are making plans and intend to deliver on the 

schedules that are required under the law. I also want to point out that 

there is a waiver authority that is available during that time period that 

should an operator anticipate an important or a difficult effect on local 

gas supplies, it may request a waiver from PHMSA. Most of the 

operators we talked with were aware of that opportunity. 

 I would like to point out, however, that there are no rules or guidance 

out on this yet in terms of what process should be used or what the 

criteria might be for approving such a waiver, if necessary. 

 MR. BOUCHER. And I suppose the waiver applications would be 

directed to Ms. Gerard, is that correct? 

 MS. SIGGERUD. That is right. 
71

 MR. BOUCHER. All right. And you are aware that you have that 

authority, Ms. Gerard? 

 MS. GERARD. Yes, sir. 

 MR. BOUCHER. All right. Have we had any applications? I guess 

not yet. 

 MS. GERARD. Not yet, but we could prepare quickly to receive 

them. 

 MR. BOUCHER. Okay. Well, that is comforting to know. 

 Mr. Chairman, you have been very generous with permitting me this 

amount of time. Thank you. 

 MR. HALL. The Chair recognizes Mr. Murphy, in the ability of the 

Chairman, for as long as he takes, I suppose, but I hope he limits it to 5 

minutes. 

 MR. MURPHY. Thank you. I would ask unanimous consent to 

change it. 

 MR. HALL. Give yourself unanimous consent. 

 MR. MURPHY. [Presiding] Thank you, Mr. Chairman. 

 I just have 2 hours worth of questions for you all, and unanimous 

consent to agree to that. Thank you. 

 Yes, I would like to start off with a question for the panel, and this is 

probably more to Mr. Chipkevich. To begin with, can you tell the 

subcommittee more about the current investigations with regard to 

Pennsylvania, Kansas, and New Jersey recommendations that have come 

through to prevent future accidents, such as those that have occurred in 

those States? 

 MR. CHIPKEVICH. Sir, those are ongoing investigations at this point. 

But I can factually let you know that the staff has completed the 

investigation work for the DuBois, Pennsylvania accident and has 

forwarded that report to the Board for its consideration, who will review 

the entire report and any recommendations. That particular accident 

involved a gas distribution system with plastic mains and plastic service 

lines. There was a home that did explode following a gas leak, and there 

were fatalities involved in that. During the investigation, we did find a 

failure at a butt fusion joint in the main, so we had it examined 

extensively, in our laboratory, the mechanism of the failure and looking 

at the procedures that were followed, the procedures that are available 

nationwide. 

 MR. MURPHY. You recall the picture I put there. I am going to put 

that again, because one of the things that I understand is being pushed is 

a mixture of 811 systems being followed. And I understand as this bill is 

being drafted, the Department is working closely to make sure that 

prevention procedures are followed. 

 Well, let me run through the details. 
72

 What happened is a subcontractor was there and apparently ruptured 

a line that was clearly marked with blue paint. They had notified 

authorities before. And I think the breach occurred at 11:30 in the 

morning, and the gas company was finally notified at 2 o’clock in the 

afternoon and then arrived when the children came home from school. 

They were allowed to go into the house. No one stopped them. 

 In a situation like this, I am wondering, if the emphasis is going to be 

on notification using 811 or some other procedure, how do we prevent 

instances such as this once there is a breach that has occurred? 

 MR. CHIPKEVICH. The NTSB investigated an accident, and I believe 

it was about 1998 in St. Cloud, Minnesota. There was excavation 

damage to a distribution system and recognized as a leak that was 

ongoing, and what we found was that there was a delay in notifying local 

authorities and the local emergency response personnel. And in fact, 

rather, the excavator went through a process of notifying his home office 

first and then went through a process before local authorities were 

notified. 

 MR. MURPHY. What State was that in? 

 MR. CHIPKEVICH. That was in Minnesota. 

 As a result, another person then later notified the local fire 

department about the event, and they arrived on the scene, and there was 

an explosion before there were any evacuations that resulted in fatalities. 

As a result of that accident, NTSB had recommended that whenever 

there is a gas leak or somebody strikes a pipeline where there is a leak, 

whether it is a gas leak or a hazardous liquid leak, that a call be made to 

911 so that local authorities get immediate notification, and made this 

recommendation both to PHMSA, the Pipeline and Hazardous Material 

Safety Administration, as well as to OSHA, because the Pipeline Safety 

Administration does not have authority over contractors, but we went 

also to OSHA to recommend in their standards that if a contractor does 

work and hits a pipeline to call 911. 

 This information went through a process through the Common 

Ground Alliance and has been incorporated as a best practice by the 

pipeline operators in their best practices for the Common Ground 

Alliance. However, there is still the issue of all of the contractors having 

the information out there. We have had positive feedback from OSHA, 

the Department of Labor, on this particular recommendation. 

 MR. MURPHY. Can I ask, then, you describe that what happened in 

Minnesota, in other words, is that they notified their home office and 

went through their procedures. Has Minnesota changed its laws to 

require 911 notification? 

 MR. CHIPKEVICH. To the best that I recall, I think they did after that 

accident. 
73

 MR. MURPHY. How about other States? Do we know if there is 

uniformity between States in terms of notifying 911 when there is a leak? 

 MR. CHIPKEVICH. I do not believe so. The process that we went to 

was to try to go to PHMSA as well as the industry on a national basis, 

but I do not think it is consistent across the country, the individual States. 

 MR. MURPHY. Okay. And I know in Pennsylvania and some other 

States, it is they have other notifications and not necessarily notifying 

911. It may be notifying the local municipality. And in the case of this 

community, in their township, it was one that they would notify an 

office, which, essentially, was unmanned, because the maintenance 

people for the community are out during the day, so they didn’t get a fax 

until someone came back in. Is that an adequate law just to notify if 

there is no one in the office? 

 MR. CHIPKEVICH. We certainly have found, from our investigation, 

that it is important to have an immediate notification to the local 

emergency response authorities. 

 MR. MURPHY. Why is the Department resisting notification of 911 

as a law? 

 MR. CHIPKEVICH. Are you talking about the Office of Pipeline 

Safety? 

 MR. MURPHY. Yes, the Office of Pipeline Safety, Department of 

Transportation. Why is there resistance to use 911, putting that into law? 

 MS. GERARD. We don’t have resistance. We support it. 

 MR. MURPHY. Then why does the Gas Association resist that? 

 MS. GERARD. Well, you probably need to ask them, but we 

definitely think that there is opportunity for the Congress to take some 

action that could motivate States to adopt this, and there are a variety of 

ways of doing that, but we think we certainly can support what you are 

wanting to do. 

 MR. MURPHY. Well, and I understand sometimes there is variability, 

assuming a rural community and they have a different need than a city or 

urban area. One possibility might be that Congress might say that States 

shall have some uniform rule in place to notify emergency authorities, 

whatever that might be, and leave it to the State to determine that. 

Would that fit and so allow some flexibility for States to determine their 

own needs? 

 MS. GERARD. I think if you can put the responsibility on the State to 

choose and adopt something and have some variation on that thing that it 

would work very well. 

 MR. MURPHY. Would you be willing to help the committee, 

obviously, go to the Chairman to help us understand some of the 

variability between State rules and laws? I would assume this gets in the 

way of a number of public safety issues, and it has got to be confusing 
74

for the gas companies that have the utilities, as they are drilling, if there 

are rules that change, not only between States, but between 

municipalities. It has to be very difficult for them, I would assume, and 

that would be helpful if you could assist us in understanding some of this 

variability between States and variability between municipalities. 

 MS. GERARD. We certainly will look forward to working with you 

on that. 

 MR. MURPHY. Thank you. 

 I see that the Chairman of the committee has arrived, and given that I 

believe my time has expired, I should defer to the Chairman. 

 Mr. Chairman, welcome. 

 CHAIRMAN BARTON. Thank you, Mr. Chairman. 

 It is good to be here. I have got another hearing going on and several 

other things, so I apologize for not being here for the entire hearing. 

 It is our intent, later this summer, to do basically a straight 

reauthorization of the existing Act. Do any of you folks have a problem 

with that? And if you do, you need to let us know what specific changes 

you would like to see us incorporate into the reauthorization. 

 Just go right down the line. 

 MS. GERARD. We think that there are opportunities to improve 

safety by putting additional focus on damage prevention, incentivizing 

States to adopt some of the practices that we have been discussing this 

morning. There has been testimony about some other opportunities that 

the Inspector General has mentioned today, and we will have, I believe, 

an Administration proposal to get up to you very soon with some other 

ideas. 

 CHAIRMAN BARTON. Excuse me, ma’am. Is this going to be a 

legislative proposal or just a statement of principles? 

 MS. GERARD. The Administration’s legislative proposal we hope to 

have to you very soon. 

 CHAIRMAN BARTON. Great. 

 MR. ALVES. We support reauthorization and think that there are 

some things that could be strengthened. It is not entirely clear to us 

whether they need to be strengthened in reauthorization or whether they 

can be done administratively. In particular, we are concerned about 

making sure that there be a security annex to the Memorandum of 

Understanding between DOT and DHS over pipeline security issues. We 

think that can be done administratively. 

 The second issue that we have is a waiver authority in emergencies 

for the Secretary to be able to waive safety requirements. It was an issue 

in Katrina. He has the authority, excuse me, but only after public notice 

and an opportunity for a hearing. In an emergency situation like Katrina, 
75

that is probably not very useful, because actions need to be taken in a 

timely way. 

 Those are the two primary issues that we have at this point. 

 MR. CHIPKEVICH. Bob Chipkevich. We certainly believe that there 

has been significant improvement in pipeline safety since the 2002 Act 

and a lot of positive activity. We don’t have any specific 

recommendations for legislation at this time, but we would certainly be 

glad to look into anything for you and provide any comments. 

 CHAIRMAN BARTON. Thank you. 

 MS. SIGGERUD. The GAO is required to do two studies and report 

out before the end of this year. We will be, in fact, reporting out this fall 

in both areas. The first asks us to look at the implementation of the 

integrity management program for natural gas transmission pipelines. 

We are generally going to give you a further review of the 

implementation and the safety effectiveness of that aspect of the Pipeline 

Act. We also are required to report specifically on the 7-year 

reassessment interval. We are going to be looking at it from several 

aspects, including the extent to which it is risk based and the extent to 

which it is having an effect on operators and the energy markets. We 

will have some recommendations for you in October in that area. 

 CHAIRMAN BARTON. Thank you. 

 This is a little off the point of the hearing, but we have got a lot of 

bright people here today, so I am going to ask you, Ms. Gerard. 

 In last year’s energy bill, I led an effort unsuccessfully to do a 

limited safe water reliability for the Fuel Act of MTBE and set up a trust 

fund to clean up contaminated water supplies that had MTBE 

contamination. The Senate was not real receptive to the trust fund idea 

and the liability protection, so we dropped it from the bill. We didn’t ban 

MTBE, but because of potential liability concerns, some of the major 

pipelines that were carrying gasoline that had MTBE in it, and these 

were privately owned pipelines, decided not to carry the MTBE gasoline. 

If you can’t transport it, you can’t distribute it, so consequently, even 

without a Federal ban on MTBE, there is basically no way to distribute 

it, so there is no market, so it is about to be gone. And in areas that were 

using it, like the area that I live in, the Dallas/Fort Worth area, we have 

had gasoline stations in the last month who didn’t even have gasoline. 

And Texas, which is the largest producer of oil in the country, has got 

some of the highest gasoline prices in the country. 

 Is there any record that there has been a contamination problem 

caused by the transportation of MTBE and gasoline through the pipeline 

system? 

 MS. GERARD. I am not aware of any, sir. It is a little outside my 

area of expertise. 
76

 CHAIRMAN BARTON. Well, it is not the focus of the hearing, but, 

you know, gasoline prices are at all-time highs, and the Speaker and the 

President and their staffs almost every day are calling my office asking 

what I am going to do about it. And we will even be doing a number of 

hearings at the Full Committee level in the next month to do a 

comprehensive review of the energy sector. One of the things that I 

think might make some sense is to put some sort of a limited liability 

protection for the MTBE in place on a temporary basis so that those 

areas that were receiving MTBE gasoline could get the pipelines once 

again to carry it, and at least for the next year or two in those areas, you 

would probably see gasoline prices go down 20 or 30 cents a gallon 

because of that. So I just wanted to know on the record if you were 

aware of any contamination problems at the pipeline level caused by 

MTBE being added to the gasoline in the pipeline, and your answer is 

you are not aware? 

 MS. GERARD. I am not aware. 

 CHAIRMAN BARTON. Could you check officially with your agency 

and reply in writing on that question, please? 

 MS. GERARD. Yes, sir, I will. 

 CHAIRMAN BARTON. Thank you. 

 Thank you, Mr. Chairman. 

 MR. MURPHY. Thank you, Mr. Chairman. 

 The gentleman from Massachusetts arrived. Mr. Markey, you have 5 

minutes. 

 MR. MARKEY. Thank you, Mr. Chairman, very much. 

 Mrs. Gerard, on March 2, 2006, BP officials discovered a leak in one 

of the transmission lines, which resulted in nearly 300,000 gallons of 

crude oil spilling into the sensitive arctic environment. Prior to the spill, 

had these arctic pipelines been subject to oversight and regulation by 

your Department? 

 MS. GERARD. No, sir. 

 MR. MARKEY. Now I understand that following the BP spill, your 

office issued a March 15 corrective action order to BP. Don’t you think 

it would be better if you could regulate these pipelines before an accident 

occurs rather than only having the power to come in after there has been 

a spill? 

 MS. GERARD. Well, that is a very important item. We began the 

rulemaking on this particular initiative about 2 years ago, but put it aside 

for some higher priority life safety initiatives. Now that they are 

completed, it is our top regulatory priority, and we have scheduled a 

public meeting in June, in which we hope to have a consensus to report. 

 MR. MARKEY. Is it your view that you should be able to get in 

before, not after? 
77

 MS. GERARD. Of course we would prefer to have prevented it. 

 MR. MARKEY. Okay. Now I am told that the trans-Alaska pipeline 

system that DOT does have ongoing regulatory authority over is scraped, 

using a device known as a “scraper pig” every 14 days in order to keep 

them clean of the sludge that might block the line or contribute to 

corrosion. In contrast, I have been told that the BP feeder line that 

leaked in March had not been scraped in 8 years. So Ms. Gerard, doesn’t 

that suggest the pipelines subject to ongoing oversight by your office are 

better maintained than those that are not? 

 MS. GERARD. That certainly seems to be the case here. 

 MR. MARKEY. Ms. Gerard, today’s Financial Times reports that BP 

will be unable to comply with the corrective action order issued by your 

office because the pipelines that have been up on the North Slope have 

been so poorly maintained. Is this true? And if so, how much of an 

extension have they asked for? And why do they need it? 

 MS. GERARD. At the time that we wrote the order, we did not realize 

that there was a large amount of deposits that had been built up inside the 

walls of these pipelines, which needs to be removed prior to the testing 

with a “smart pig.” We have been alerted by Alyeska Pipeline to the risk 

that moving a large amount of these deposits through their lines could 

cause, and so we are working with both companies to get a good picture 

on the amount, composition, and density of this material so that we can 

know how much there is and how long it is going to take to gradually 

remove it. 

 MR. MARKEY. Have they made a request for a specific time 

extension? 

 MS. GERARD. They have made more than one request. 

 MR. MARKEY. What is that? The most recent time extension 

request. 

 MS. GERARD. I believe the most recent request is for about a 4-to-6-

week extension to be able to complete their diagnostics on this sludge 

material. 

 MR. MARKEY. Now it has also been reported that BP believes that 

there could be up to 2,500 cubic yards of oil sludge in key pipelines and 

that sending a scraper pig through those lines could, therefore, shut them 

down. Is that true? 

 MS. GERARD. It is possible that they could need to be shut down. 

 MR. MARKEY. If the BP lines up in Prudoe Bay were to be shut 

down due to the sludge, how many barrels per day of oil would be 

removed from the world’s oil markets? 

 MS. GERARD. I would have to get back to you on the record for that 

number. 
78

 MR. MARKEY. Ms. Gerard, how do you think BP could have 

allowed their pipelines up on the North Slope to deteriorate to this point? 

 MS. GERARD. Well, BP has employed a great number of different 

corrosion prevention methodologies. They apparently did not use this 

basic technique of running scraper pigs to remove the sludge, which is a 

hazard to the pipeline and-- 

 MR. MARKEY. So what you are saying is it is just basic 

incompetence on their part? 

 MS. GERARD. We don’t have any-- 

 MR. MARKEY. Not using state-of-the-art technology? 

 MS. GERARD. We have no single logical reason why they did not 

use the scraper pigs. 

 MR. MARKEY. So how much would you attribute to incompetence 

on the part of BP, and how much of it to the fact that there was no 

regulatory oversight by the Federal government? How would you divide 

that responsibility? 

 MS. GERARD. It was our expectation that they would have been 

running those scraper pigs and that most companies do run the scraper 

pigs on a weekly to biweekly basis. There is a general standard of care 

that most operators exercise that are exercised without our regulating 

them. Obviously, we wish we had regulations in place sooner. 

 MR. MARKEY. Okay. It can’t be, bogusly, that BP doesn’t have 

enough money. Or is it just another cost-saving measure, regardless of 

what the consequences are? 

 MS. GERARD. I can’t speak to how much money BP has, but it 

certainly seems like they should have been running scraper pigs on a 

weekly basis so that this problem didn’t build up and occur. 

 MR. MARKEY. And what is their explanation to you for their failure 

to run the pigs? Is it the same one I gave to my mother for not cleaning 

my room? I mean, what is the answer? 

 MS. GERARD. I think there is a question about how much of the 

deposits there are and questions about how to remove them. We don’t 

have a good explanation as to why they didn’t start sooner, but obviously 

having not started sooner, the problem is more difficult today and is 

going to be hard to address, but we-- 

 MR. MARKEY. But what is their explanation for not doing their job? 

 MS. GERARD. We don’t have an explanation for why they did not 

run scraper pigs. 

 MR. MARKEY. No acceptable answer to you or no answer at all from 

them? 

 MS. GERARD. No acceptable answer. 

 MR. MARKEY. No acceptable answer. 

 Thank you. 
79

 Thank you, Mr. Chairman. 

 MR. MURPHY. Thank you. 

 Mrs. Wilson is here from New Mexico, yes. You are recognized for 

5 minutes. 

 MRS. WILSON. Thank you, Mr. Chairman. I appreciate your 

patience. 

 I wanted to ask, and none of you touched on this in your testimony, 

although you do talk about significant progress being made in examining 

pipelines and so forth, what research and development is underway to 

better identify and prevent pipeline problems and take technologies to the 

next step, either sponsored by the Federal government or on their way in 

industry? 

 MS. GERARD. Since the Pipeline Safety Improvement Act of 2002, 

we began a research program, really, for the first time that focuses on a 

range of integrity issues, from prevention to detection to repair 

techniques and so on. We have funded about 30 projects to look at 

bringing short-term technologies to market, and there are 8 patents 

pending from this work. We are very optimistic about the ability to use 

technology to be able to direct sooner and to be able to do detection in 

areas where pipelines, for example, cannot be inspected with a pig type 

device, for example. 

 MRS. WILSON. Thirty projects, eight patents pending, what is the 

total amount of money that you all have put into R&D from the Federal 

budget? 

 MS. GERARD. It is now 38 projects, and it is about $30 million 

maybe on the Federal side with more than that matched on the privatesector side, so about a $50 to $60 million investment. 

 MRS. WILSON. What do we spend using old technology annually in 

private industry to inspect these pipelines? How expensive is it to do this 

job? 

 MS. GERARD. This is just a rough guess, but I would expect that an 

average pipeline company will spend at least $100 million using 

detection prevention technologies. 

 MRS. WILSON. Anybody else have a better answer? 

 Well, it continues to concern me that when we look at remote 

detection technologies and sensing technologies in other industry areas, 

we are making such tremendous advances, whether you look at 

telecommunications. France has spent a lot of working time in 

intelligence. And pipeline safety R&D for remote detection and sensing 

is moving so slowly, and it is stuck somewhere in the 20th Century, and I 

just don’t understand why we are not leveraging other investments. 
80

 MS. GERARD. We have a number of investments dealing with use of 

remote sensing technologies and would be happy to provide you with a 

description for the record. 

 MRS. WILSON. I would very much appreciate that information. And 

Mr. Chairman, I think this is an area where there is substantial work to be 

done and substantial other Federal investment that can be leveraged in 

this area that will reduce operating costs for those who operate pipelines 

and improve safety. 

 Thank you, Mr. Chairman. 

 MR. HALL. Thank you. 

 I think that concludes your presentation. We thank you very much 

for it. 

 We will now prepare for the second panel. 

 We appreciate the time that you took to prepare research, to travel 

here, and to give us your expertise. It is people like you that help write 

the laws that we all live under, and I thank you for your appearance here. 

 MR. ALVES. Thank you, Mr. Chairman. 

 MR. HALL. We have the Honorable Donald Mason, the 

Commissioner of Public Utilities Commission of Ohio. He is running a 

little bit late, but he will be here in a little bit. And Mr. Massoud 

Tahamtani, did I say it right? 

 MR. TAHAMTANI. Yes, sir. 

 MR. HALL. Pretty close? 

 MR. TAHAMTANI. Yes, sir. 

 MR. HALL. The Director, Division of Utility and Railroad Safety, 

Virginia State Corporation Commission, and we will recognize you first, 

since you are the only one here. I ask you to use about 5 minutes, if you 

can. If you have to go over a little, we understand that. We recognize 

you at this time. Thank you. 

STATEMENTS OF MASSOUD TAHAMTANI, DIRECTOR, 

DIVISION OF UTILITY AND RAILROAD SAFETY, 

VIRGINIA STATE CORPORATION COMMISSION, ON 

BEHALF OF NATIONAL ASSOCIATION OF PIPELINE 

SAFETY REPRESENTATIVES; AND HON. DONALD L. 

MASON, COMMISSIONER, PUBLIC UTILITIES 

COMMISSION OF OHIO, ON BEHALF OF NATIONAL 

ASSOCIATION OF REGULATORY UTILITY 

COMMISSIONERS 

MR. TAHAMTANI. Thank you, Mr. Chairman, Congressman 

Boucher, members of the subcommittee. 
81

 Good morning. My name is Massoud Tahamtani, and I am the 

Director of the Division of Utility and Railroad Safety for the State 

Corporation Commission of Virginia. Our division assists our 

commissioners in administrating safety programs involving pipeline 

facilities, railroads, and underground utility damage prevention. 

 Thank you for inviting me to participate in this important hearing. 

 I have been asked to comment on Virginia’s underground utility 

damage prevention program as it relates to pipeline facilities. The 

specifics of this program are detailed in my written testimony, which was 

submitted earlier. 

 I could talk about this for hours, but I will talk for about a few 

minutes. 

 Mr. Chairman, this program is about 15 years old, and I have been 

talking about it for the last 10 years, at least. But I will leave my 

comments to a brief summary of how the program started and what 

makes it work. 

 The Virginia damage prevention efforts began in 1992, not because 

of an accident, but because we noticed excavation damage to our 

pipelines was increasing at an alarming rate. In order to address this 

serious threat, our commission appointed tasks for the key stakeholders 

to conduct a comprehensive review of our damage prevention law and 

make recommendations that would help significantly reduce excavation 

damage to all underground facilities. 

 To ensure the success of this task force, the commission created an 

environment where, for the first time, all stakeholders were put on equal 

footing. As I am sure you know, contractors always think that they are 

the small guys and utilities are the big boys and they never have a voice 

in the process. We corrected that, beginning in 1992, and continue to 

practice that today. 

 The task force’s recommendations, with minor changes, became the 

Virginia law that Congressman Boucher noted. The new law contained a 

number of key provisions, which can be grouped into three categories: 

improved communication, effective enforcement, and effective public 

education. 

 With the new law on January 1, 1995, we began our enforcement 

program with voluntary reporting of gas damages by gas companies. By 

the end of 1995, only 30 out of 2,500 damages had been reported to us 

for investigation. That is only 1.2 percent. Obviously, an effective and 

meaningful enforcement program could not be carried out by taking 

action on a select few damages. As a result, beginning with the 1996 

calendar year, we required all gas operators to report all damages and 

violations of our law for investigation and possible enforcement actions. 
82

 Along with our enforcement, we strongly encouraged the broad 

participation of all stakeholders to help improve Virginia’s damage 

prevention program. In 1999, soon after the U.S. DOT’s study of 

damage prevention best practices was released, we compared our law, 

rules, and practices to the best practice contained in that study. With full 

participation of key stakeholders, we began a rulemaking and, in 2001, 

adopted commission rules to improve the program even further. Twenty 

issues that were best practices were not really addressed by our law or 

rules. The commission again invited stakeholders to serve on a task 

force to study these issues and recommend a resolution. The 

recommendations made by this task force again were adopted into our 

law. 

 The commission rules and the 2002 amendments to the law 

addressed additional but very important damage prevention requirements 

for excavators, operators, locators, and the notification center. In order 

to effectively communicate all safety and these additional requirements, 

the commission formed another committee of stakeholders to guide 

Virginia’s public education program. Every year, this committee 

recommends and the commission adapts the statewide education and 

public outreach program. Our law requires that all the penalties collected 

from these fines be spent on public education. 

 Now a few words about our results. 

 In 1996, when we began to report gas damages, Virginia’s gas 

distribution system, since 1996, has grown by 30 percent. So 30 percent 

more facilities are protected. Sixty percent more excavation is 

happening at least around Virginia. With those two, we have reduced 

damages to gas pipelines by 50 percent. So as you can see, this is a very 

impressive result, and that is why you keep hearing the name of Virginia 

here. 

 Over the last 10 years, more gas facilities have been put in the 

ground and need protection from more excavation, and we have managed 

to reduce these damages to our pipelines. The success of our program 

clearly can be attributed to nine factors that you have seen and will hear 

about again: enhanced communication between operators and 

excavators; partnership in public education; partnership in training the 

contractors, locators, and on-call center employees; commission role as a 

partner and facilitator; efficient, fair, and consistent enforcement; user 

performance measures for persons performing locating and also 

constructing utility facilities, and these are the individuals who work 

around the existing facilities more often; using available technologies to 

improve the process; and then finally, continual review to help evaluate 

and improve the program. 
83

 As I indicated, the details behind each of these elements are in my 

written testimony, and I will not get into it here, but I will be happy to 

answer any questions. 

 Finally, Mr. Chairman, on behalf of the National Association of 

Pipeline Safety Representatives, these are my colleagues from other 

States, I want to encourage Congress to provide additional grants to 

States to assist them with their increased pipeline safety responsibilities, 

including having an effective damage prevention program. We 

specifically request that the 50-percent pipeline safety grants in the Act 

be raised to 80 percent. This is consistent with other DOT grants to 

States, and we have a $1 million damage prevention grant that I helped to 

hopefully give to the States. We need that to be increased to $2.5 million 

to better help the States carry out their current damage prevention 

programs. 

 Thank you, Mr. Chairman. 

 [The prepared statement of Massoud Tahamtani follows:] 

PREPARED STATEMENT OF MASSOUD TAHAMTANI, DIRECTOR, DIVISION OF UTILITY AND 

RAILROAD SAFETY, VIRGINIA STATE CORPORATION COMMISSION, ON BEHALF OF NATIONAL 

ASSOCIATION OF PIPELINE SAFETY REPRESENTATIVES

Summary of Testimony 

 Virginia State Corporation Commission appreciates the opportunity to discuss our 

Underground Utility Damage Prevention Program. Over the last 10 years, we have 

managed to reduce excavation damage to our pipeline facilities by more than 50 percent. 

This is especially significant in light of the fact that our gas system has grown by more 

than 30 percent and the notices of excavation have increased by more than 60 percent 

over the same period. Our results are due to our comprehensive damage prevention 

program which includes the following elements: 

• Enhanced communication between operators and excavators; 

• Partnership in public education; 

• Partnership in training of excavators, locators and one-call center employees; 

• Commission’s role as a partner and facilitator; 

• Efficient, fair and consistent enforcement; 

• Use of performance measures for persons performing locating of facilities and 

constructing new utility facilities; 

• Use of available technology to improve the process; and 

• Continual review of data to help evaluate and improve the program. 

 We encourage Congress to provide additional grants to states to assist them in better 

carrying out their increased pipeline safety responsibilities including the implementation 

of effective damage prevention programs. Specifically, we support increasing the current 

50 percent pipeline safety grants to states to 80 percent and increasing the current $1 

million damage prevention grant to $2.5 million to assist states with current damage 

prevention efforts. 

Mr. Chairman and Members of the Subcommittee, 

Good morning. My name is Massoud Tahamtani and I am the Director of the 

Division of Utility and Railroad Safety for the State Corporation Commission in the 

Commonwealth of Virginia. Our Division assists our Commissioners in administering 
84

safety programs involving pipeline facilities, railroads and underground utility damage 

prevention. Thank you for inviting me to participate in this important hearing. 

This morning, I have been asked to focus on Virginia’s underground utility damage 

prevention program as it relates to pipeline facilities. Over the next few minutes, I hope 

to share with you how our program has evolved to where it is today and the steps we are 

taking to ensure its continued effectiveness. 

Background 

As we all know, in the late 1980’s and early 1990’s, excavation damage to pipelines 

across our country increased at an alarming rate. Several of these damages resulted in 

serious accidents involving deaths, injuries and millions of dollars in damage to 

properties and the environment. 

 In order to address this serious threat to Virginia’s pipeline system, in 1992 our 

Commission appointed a task force of stakeholders to conduct a comprehensive review of 

our damage prevention law and recommend changes that would help significantly reduce 

excavation damage to our underground facilities. This task force included representatives 

from operators, excavators, underground facility locators, local and state government as 

well as the notification centers. 

To ensure the success of this task force, the Commission created an environment 

where, for the first time, all stakeholders were placed on an equal footing so that 

individual issues would not override our ultimate goal of significantly reducing damages 

to all underground facilities in Virginia. 

In early 1993, the Virginia General Assembly recognized the work of the task 

force and requested the Commission to submit a report and any recommendations to the 

Assembly’s 1994 Session. The task force’s recommendations with minor changes were 

adopted into law effective January 1, 1995. 

Virginia’s New Damage Prevention Law 

 The new law contained a number of key provisions, which can be grouped into the 

following three categories: Improved communication, Effective enforcement and 

Effective public education. 

Improved Communication

The stakeholders believed that first and foremost, the exchange of timely information 

between the excavators and operators needed to improve. This was accomplished by 

having the law require: 

• The notification centers operating in Virginia to design and implement a 

“Positive Response System” to enable operators to efficiently communicate the 

marking status of their facilities to excavators; 

• Excavators to provide an additional notice to the operator(s), through the 

notification center, when they observed clear evidence of unmarked facilities 

and wait an additional three hours for operators to mark their facilities; 

• The notification centers to re-notify the operators who had failed to respond to 

the “Positive Response System” 48 hours after the notice of excavation. 

These three requirements assisted the stakeholders in Virginia to eliminate the 

gaps that occurred in their communication and to strengthen the partnership which is 

critical to a successful damage prevention program. 

Effective Enforcement

 Just as our founding fathers believed that self government was more effective than 

any government from afar, the law created a way for the enforcement to come from the 

stakeholders themselves. Thus, included in our new law was a directive to the 

Commission to appoint a Damage Prevention Advisory Committee (“Committee”) 
85

comprised of expert representatives from operators, excavators, facility locators, 

notification centers, local government, Virginia DOT, the Virginia Board for Contractors 

and the Commission Staff. This Committee was charged with assisting the Commission 

in furthering Virginia’s damage prevention program by reviewing reports of damages and 

violations and by making enforcement recommendations to the Commission. It was 

believed that this administrative process would result in a fair and consistent enforcement 

program without costly legal proceedings. 

Effective Public Education

Effective education and training is critical to changing behaviors and impacting 

results. To better accomplish this, the law required all penalties collected from the 

enforcement program be kept in a “Special Fund” account to be used for training, 

education and enforcement. In addition, the law required all operators to assist in the 

education of the public relative to safe digging practices. 

With a new law, on January 1, 1995, we began our enforcement program with 

voluntary reporting of damages by gas operators. By the end of 1995, only 30 of more 

than 2,500 damages to pipelines, or 1.2 percent, were reported to the Commission for 

investigation. Obviously, an effective and meaningful enforcement program could not be 

carried out by taking actions on only the select few damages which were being reported. 

As a result, beginning with the 1996 calendar year, we required all our gas operators to 

report all damages and violations involving their facilities for investigation and possible 

enforcement actions. 

Along with our enforcement program we strongly encouraged broad participation of 

all stakeholders to help improve Virginia’s damage prevention program. The 

combination of these efforts resulted in a 26.5 percent reduction in gas pipeline damages 

by 1998. Meanwhile, several serious pipeline accidents across the nation prompted 

Congress to take action. 

As you know, in 1998, the Transportation Equity Act for the 21st Century (TEA21) 

was signed into law. Section 6105 of this Act authorized the USDOT to undertake a 

study to determine which existing practices were most effective in reducing excavation 

damage to pipelines and other underground facilities. Soon after USDOT’s study was 

released in 1999, we compared our law, rules and practices to all the “Best Practices” 

contained in that study. 

As a result, we began a rule making and in 2001, adopted specific rules to further 

improve Virginia’s damage prevention program. Our comparison also identified 20 

issues that could not be addressed through rule making. The Commission again invited 

stakeholders to serve on a task force to study these issues and recommend resolutions. 

The recommendations made by this task force resulted in further improvements to our 

law in 2002. The Commission’s Rules and the 2002 amendments to the law addressed a 

number of very important damage prevention requirements that can be grouped as 

follows: 

Excavators are required to: 

• Take reasonable steps to avoid damage during routine and emergency 

excavations; 

• Take nine specific steps when conducting trenchless excavation; 

• Conduct pre-excavation site inspections and preserve markings during 

excavation; and 

• Take reasonable care when hand-digging around utility facilities. 

Operators are required to: 

• Update the notification center’s data base any time they place new facilities in 

operation; 
86

• Maintain accurate records of their active facilities as well as facilities 

abandoned after July 1, 2002; 

• Provide underground utility information to project designers; 

• Make all new non-metallic underground lines locatable; and 

• Place underground utility lines at specific depths. 

Notification Centers are required to: 

• Include non-operators on the center’s board; and 

• Meet certain performance standards. 

Locators are required to: 

• Follow certain standards for marking underground utility lines; and 

• Be trained based on their industry standards. 

In order to effectively communicate these additional requirements to the 

stakeholders, the Commission formed a statewide education and training committee again 

comprised of representatives of key stakeholders. Every year, this committee 

recommends and the Commission adopts a statewide education and public outreach 

program. I will review the details of this program later in this testimony. 

Results 

 Since 1996, when we began our mandatory reporting of all gas damages, Virginia’s 

gas distribution system has grown by more than 30 percent. 

During this same period excavation notices also known as “tickets” has increased by 

more than 60 percent. 

Year 

Gas Distribution System Growth in Virginia

10000

11000

12000

13000

14000

15000

16000

17000

18000

19000

20000

1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Miles of Main

500000

600000

700000

800000

900000

1000000

1100000

Number of Services

Number of Services (33.5% Increase)

Miles of Main (30% Increase)
87

Statewide Gas Facility Damage Trend 

Gas Damages per 1000 Gas Tickets

4.49

3.45 3.36

2.65 2.55

2.83

2.30

2.10 2.25 2.28

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

4.00

4.50

5.00

1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Year 

816,902

1,040,077 1,032,127 1,055,889

1,216,232

1,162,335

1,125,627

1,139,652

928,845

759,825

0

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Year

Tickets 

Incoming Excavation Ticket Requests 1996 – 2005

Incoming Ticket Volume (60.06% Increase)

Finally, the index that is often used to measure the success of a damage prevention 

program, damages/1,000 tickets, for our gas system, has decreased from 4.49 in 1996 to 

2.28 in 2005. This is a 50 percent reduction in excavation damage to gas pipelines in 

Virginia. 

 

A review of the previous three charts shows that although over the last 10 years, 

more gas facilities were constructed and needed protection from increased excavation 

activities, Virginia has managed to realize a significant reduction in gas damages. The 

success of this program can clearly be attributed to our comprehensive damage 

prevention program which has been based on the following: 
88

• Enhanced communication between operators and excavators. The 

exchange of accurate and timely information between the excavators and 

operators of underground facilities is at the heart of any effective damage 

prevention process. The easier and the more efficient this communication, the 

more effectively the two main stakeholders (excavators and operators) can 

communicate throughout the excavation activity. Virginia was the first state to 

implement the Positive Response System and require excavators to learn the 

status of their tickets by contacting this system before commencing excavation. 

Our “three hour notice” is another opportunity for excavators and operators to 

ensure they are “talking” when unmarked facilities are noted in the field. The 

requirement for the center to re-notify operators when they have failed to 

respond to the system is yet another way to ensure additional communication 

when a request for marking seems to have not been acted upon. Finally, the 

requirement for locators to add company specific letter designations and facility 

information when they mark the facilities is another way to better provide the 

excavators with information relative to a facility they need to protect from 

damage. 

• Partnership in public education. As noted earlier, a committee of 

stakeholders currently guide Virginia’s public outreach program. Annually, 

this committee reviews a significant amount of data to determine the 

effectiveness of our education and outreach program and recommends to the 

Commission the specific elements of a new program for the upcoming year. 

Through this process, outreach campaigns of at least one million dollars per 

year have been implemented since 2001. To assist in training of stakeholders, 

the Commission has three full time trainers on staff who conduct face to face 

training for more than 3,500 individuals every year. Our utilities provide 

significant assistance in increasing the overall value of our educational 

campaign. For example, this year’s campaign is valued at more than $3.2 

million with approximately $1.2 million dollars of free PSA’s being provided 

by our cable and telecommunications companies. The gas operators have 

completed several unique initiatives such as having our safe digging message 

on a 2.5 million gallon LNG tank, on a building front, on gas meters, on gas 

pipeline markers, on company vehicles and bills, just to name a few. The 

annual campaign and the efforts of our partners keep our safe digging message 

in front of the public eye at all times. 

• Partnership in training of excavators, locators and one-call center 

employees. Effective training of those individuals involved in excavation, 

locating and marking of facilities and the notification center operation is also 

critical in reducing damage to underground facilities. In Virginia, most of our 

training is done by teams representing the stakeholders. Additionally, we have 

developed a “Train the Trainer” program to certify individuals to conduct 

training for their own employees or assist in training others. We also have an 

education credit program that encourages companies and individuals to get 

involved with educating their own employees or other companies’ employees 

and receive credit to reduce possible future penalties. 

• Commission’s role as a partner and facilitator. As a result of our active 

damage prevention program, we have been presented with many different 

issues, the proper resolutions of which have been critical to the overall success 

of the program. When issues have required the involvement of all stakeholders, 

we have formed task forces, committees, etc. to quickly address these issues. 

Our Damage Prevention Advisory Committee, which meets monthly, has 

become the first place where issues or concerns are discussed. These 

discussions have resulted in recommending revisions to the law, rules, 
89

procedures and policies. In all of these processes we have worked hard to 

ensure fairness to all stakeholders. 

• Efficient, fair and consistent enforcement. As noted earlier, the results of 

investigations of damages and violations are reviewed by an Advisory 

Committee appointed by the Commission. The make up of this Committee is 

as follows: 

 Representing No. of Members

 Excavators 3 

 Operators 2 

 Utility Locators 2 

 Notification Center 1 

 Local Government 2 

 VA DOT 1 

 Virginia Board for Contractors 1 

 Commission Staff 1 

After a review of the facts surrounding each incident, the Committee makes 

enforcement recommendations which may include: civil penalty, civil penalty with 

training, warning letter, letter of concern, or dismissal. Every recommendation is made 

by considering factors such as circumstances that led to the incident, culpability, gravity, 

history of the violator and other factors that may be justified. When civil penalties are 

necessary, a fairly complicated set of matrices guide the investigators and the Committee 

in recommending the appropriate level of civil penalties for settlement purposes while 

maintaining consistency. If applicable, a performance improvement credit is applied to 

reduce the penalty and therefore recognize a stakeholder’s overall performance. There 

are several opportunities for the involved parties to present their information and 

positions to the Committee outside a formal hearing. The Committee operates based on 

approved bylaws and strict policies to ensure the consistency and credibility of its 

process. 

• Use of performance measures for persons performing locating of facilities 

and constructing new utility facilities. Quality assurance programs must be 

in place to monitor and ensure that locators perform their duties properly when 

they locate facilities. Also, contractors working for utilities must be monitored 

to ensure their full compliance as they mostly work around existing facilities. 

In Virginia, we have encouraged our operators to have incentives (penalties) 

tied to the performance of locators and utility contractors to further improve the 

operators’ damage prevention programs.

• Use of available technology to improve the process. When a recent analysis 

of our data showed that damages caused by hand digging were on the rise, we 

encouraged our excavators to take advantage of air-knife technology and 

trenchless excavation using water to reduce these damages. When an operator 

had more than 30,000 unlocatable gas service lines, we encouraged that 

operator to use existing technologies to make their facilities locatable. Finally, 

our notification center has employed a number of technologies to improve its 

performance in providing timely service to excavators and operators. In three 

months, the center will implement new mapping technologies to better serve its 

customers. 

• Continual review of data to help evaluate and improve the program. Over 

the last 10 years, we have investigated more than 25,000 damages to our gas 

facilities. The cause of every single damage has been identified by our 

Committee of experts. For every incident, important information is gathered 

and maintained in a single database at the Commission. In addition, the 
90

notification center is required to capture and maintain data relative to every 

notice of excavation and every utility response to these notifications. The 

combination of these two data bases has allowed Virginia stakeholders to 

review the trends and to take appropriate and focused actions to improve the 

program. For example, data is used to effectively plan and implement the 

statewide education outreach program. Data is also used to share trends with 

our gas operators and devise plans to address problem areas. 

Virginia Damage Prevention Pilot Project 

Due to Virginia’s mature and successful program, our state has been 

selected as a pilot state by a number of organizations, including the Common Ground 

Alliance (“CGA”), the Pipeline Research Council International, Inc. (“PRCI”), the Office 

of Pipeline Safety, and the various operators having facilities in Virginia. The purpose of 

this pilot project is to research and implement new and existing technologies such as GPS 

technology to further improve the communication of accurate information among 

excavators, one-call centers and operators. The results of this pilot will benefit every 

states’ damage prevention program. 

Distribution Integrity Management 

As you know, a recent study on integrity management for gas distribution systems 

was completed in December, 2005. This study was conducted by four joint 

government/industry groups. The Excavation Damage Prevention Group (“EDPG”), 

which I chaired, found excavation damage by far poses the single greatest threat to 

distribution system integrity. EDPG further found that comprehensive damage 

prevention programs were needed to significantly reduce accidents caused by excavation 

damage to pipelines. Further, the group found that federal legislation is needed to 

support the development and implementation of damage prevention programs that 

include effective enforcement as part of a state’s pipeline safety program. States should 

be encouraged to incorporate pipeline damage prevention responsibilities with their 

pipeline safety programs. The costs associated with carrying out effective damage 

prevention programs along with resources needed to fund the current pipeline safety 

program, as well as implementing the recent safety mandates justifies increasing the 50 

percent grant ceiling contained in the law to 80 percent. This funding level is consistent 

with other non-pipeline safety grants to states administered by USDOT. Any effort to 

significantly reduce excavation damage threats, which are the most preventable of all, is 

very much consistent with Congress’s overall pipeline safety objectives. For any federal 

legislation to be effective, it must include provisions for additional grants to support the 

states’ damage prevention and pipeline safety programs. We also support increasing the 

current $1 million Damage Prevention Grant to $2.5 million dollars to assist all states 

with their existing damage prevention efforts. As I serve on the federal/state committee 

that helps to review the applications for the $1 million, I know that a number of states’ 

entire damage prevention program depend on this grant which has been very effective in 

supporting limited yet effective activities by these states. 

Mr. Chairman, this concludes my testimony. Once again, thank you for the 

opportunity to participate in today’s hearing. 

 MR. HALL. I thank you. 

 And we note the presence of Mr. Mason. Welcome. I understand 

traffic problems and time pressures. And thank you for being here. 

 We will recognize you at this time to receive your testimony for 

about 5 minutes or more to accommodate your full presentation to us, 

and then we will have questions for both of you. 
91

 Thank you, and we recognize you, Mr. Mason. 

MR. MASON. Good afternoon and thank you, Mr. Chairman. I guess 

we are still in the morning. Good morning, Mr. Chairman and members 

of the subcommittee. 

 As indicated earlier, my name is Don Mason, Commissioner of the 

Public Utility Commission of Ohio. I also serve as Chairman of the Gas 

Committee of the National Association of Regulatory Utility 

Commissioners. I am speaking on behalf of NARUC and the PUCO 

with regard to my prepared testimony. 

 As indicated earlier, NARUC members actually regulate the retail 

rates and services of gas, electricity, and water. My testimony represents 

that of the technical individuals as well as the policy individuals who 

determine how to allocate the rates across the States. 

 My first point gets into grant funding. We feel it must increase to 

meet our resource requirements of the State pipeline safety programs. 

Consumers ultimately pay the Pipeline Hazardous Materials Safety 

Administration pipeline users’ fees that are passed on by natural gas and 

hazardous liquid transmission companies. Again, all of the rates and fees 

get passed on to the consumers in the end. State pipeline safety program 

funding is heavily dependent on PHMSA’s proper sharing of these user 

fees and the State pipeline safety programs represent approximately 80 

percent of the Federal/State workforce that oversees the pipeline 

nationwide. So without the adequate funding, States would not be able 

to conduct the required inspections of the existing pipelines. 

 The Pipeline Safety Act provides for States to receive a Federal grant 

up to 50 percent of the actual expenses for their safety programs, and in 

2005, the State estimated cost of the portion was actually around $36 

million, but due to the 50-percent funding, we did not receive the entire 

funding. It looked like the Federal government funded about $15.9 

million. So roughly, there is a disproportionate sharing where the States 

are bearing a little more of the load, and I might point out that States are 

responsible for about 2.14 million miles of the total 2.41 million miles of 

pipeline. So in other words, we are responsible, really, for about 89 

percent of the pipelines in the United States of America. So our burden 

is fairly heavy, and we hope that Congress will recognize the need for 

additional support of the State inspection resources. 

 And may I also say that Congress, we feel, should increase the 

current $1 million damage prevention grant to about $2.5 million. For 

several years now, Congress has funded a $1 million grant to assist all 

States with their existing excavation damage prevention programs. 

PHMSA receives about $2.2 million in requests, so as you can see, our 

requests exceed the budgeted amount. And many States that cope with 

the enforcement would be restricted without the funding that is set aside 
92

in this grant, as it is now. Much of the data collected to evaluate damage 

prevention program effectiveness and its needs is made possible by onecall grants. Incentives such as equipment and training supported by grant 

funding have been effective in bringing small operators of limited 

financial means into compliance with our State damage prevention laws. 

 On the good news side, in March of 2005, your States, basically 

through the help of the FCC, of course, the Pipeline Safety Act of 2002 

authorized the one call, which starting about a year ago, we have all been 

working on a one-call system. That is the 811. We hope it will really 

reduce the amount of damage to pipelines and other facilities. I can’t 

emphasize enough how we need to continue to promote the public 

awareness of 811 so that more people will call before they dig, because 

again, third-party cut-ins still represent over 50 percent of the damage to 

pipelines. 

 And I will just summarize in closing, and then I will bounce to a 

couple of points that we have been working on. 

 We have been working really hard with PHMSA, not just the States 

in the program, a lot of shareholders, in trying to allocate just the right 

amount of flexibility and the right amount of responsibility on inspecting 

the distribution and integrity management system. Right now, we have 

sort of a Federal flexibility plan in place that we support. But part of that 

also includes looking at something called excess flow valves that became 

an issue at one point where there was concerned that EFVs, as they are 

called, would be mandated across 100 percent of the country. We have 

concern that you have to have the right pressure to make these systems 

operate, the right constituents in the gas to make sure they operate. For 

example, in parts of Ohio, and other production areas, I am sure in 

Texas, there are gas constituents that could actually gum up the works, 

distribution systems operating too close to a production area, as so many 

do. 

 With that, I will just close my remarks, and I am ready to help 

answer questions with my partner here. 

 Thank you, Mr. Chairman. 

 [The prepared statement of Donald L. Mason follows:] 

PREPARED STATEMENT OF THE HON. DONALD L. MASON, COMMISSIONER, PUBLIC 

UTILITIES COMMISSION OF OHIO, ON BEHALF OF NATIONAL ASSOCIATION OF REGULATORY 

UTILITY COMMISSIONERS

• Grant funding must increase to meet resource requirements of State pipeline safety 

programs. 

• Congress should increase the current $1 million damage prevention grant to States 

to $2.5 million. 

• Distribution Integrity Management programs should provide additional safety 

improvement. 
93

• NARUC supports 80% grant funding for all pipeline safety programs that enforce 

excavation damage prevention distribution integrity inspections and other mandated 

programs. 

• Federally mandated installation of excess flow valves (EFVs) on service lines to 

customers is not necessary. 

Good Afternoon Mr. Chairman and Members of the Subcommittee. 

I am Donald L. Mason, a commissioner at the Public Utilities Commission of Ohio 

(PUCO). I have served in that capacity since 1998. I also serve as the Chair of the 

Committee on Gas for the National Association of Regulatory Utility Commissioners 

(NARUC). As Chairman of the NARUC Committee that focuses on some of the issues 

that are the subject of today’s hearing, I am testifying today on behalf of that 

organization. In addition, my testimony reflects my own views and those of the PUCO as 

well as the comments of the National Association of Pipeline Safety Representatives 

(NAPSR) reflected in items 1, 2, 3 & 5. On behalf of NARUC, NAPSR and the PUCO, I 

very much appreciate the opportunity to appear before you this morning. 

NARUC is a quasi-governmental, non-profit organization founded in 1889. Its 

membership includes the State public utility commissions serving all States and 

territories. NARUC’s mission is to serve the public interest by improving the quality and 

effectiveness of public utility regulation. NARUC’s members regulate the retail rates and 

services of electric, gas, water, and telephone utilities. We are obligated under the laws 

of our respective States to ensure the establishment and maintenance of such utility 

services as may be required by the public convenience and necessity and to ensure that 

such services are provided under rates and subject to terms and conditions of service that 

are just, reasonable, and non-discriminatory. NAPSR is a non-profit organization of state 

pipeline safety directors, mangers, inspectors and technical personnel who serve to 

support, encourage, develop and enhance pipeline safety. 

This morning I will focus on what NARUC believes are the five main issues facing 

the States with regard to the pipeline safety program. 

1. Grant Funding Must Increase To Meet Resource Requirements Of State 

Pipeline Safety Programs. 

State pipeline safety agencies are closely connected to the ultimate consumers of 

natural gas and liquid hydrocarbons through the oversight of facilities that distribute 

products near or at the end of the transportation supply chain. These consumers 

ultimately pay the Pipeline Hazardous Material Safety Administration (PHMSA) pipeline 

safety user fees that are passed on by natural gas and hazardous liquid transmission 

companies. State pipeline safety program funding is heavily dependent upon PHMSA’s 

proper sharing of these user fees. State pipeline safety programs represent approximately 

80 percent of the federal/State inspector work force that oversees pipelines nationwide. 

Without adequate funding, States will not be able to conduct the required inspections of 

the existing pipeline facilities or new pipeline construction projects, and encourage 

compliance with new and existing safety regulations. Grant funds are an effective way to 

leverage resources and increase total inspection capability since States match or exceed 

federal funding provided for pipeline safety. 

However, federal base grants to States who administer the gas and liquid pipeline 

safety program are not keeping up with their actual expenditures. The Pipeline Safety Act 

provides for States to receive a federal grant up to 50 percent of actual expenses for their 

safety programs. For example, in 2005 the States estimated that the total cost of their 

portion of the program to be approximately $36.2 million. Due to the 50 percent limit 

imposed in the Pipeline Safety Act, the most the States can be granted to cover their costs 

was $18.1 million. However, the actual base funding grant level that was given to the 

States was $15.9 million. 
94

State pipeline safety programs have jurisdiction over 222,000 miles of natural gas & 

liquid transmission and gathering lines, 1.15 million miles of natural gas distribution 

pipelines and 764,000 miles of service lines. Therefore, States are responsible for over 

2.14 million of the total 2.41 million miles of pipe (PHMSA oversees 272,000 miles), 

which represents 89 percent of the total pipelines in the United States. However, while 

the States are responsible for 89 percent of the pipelines, in FY 2005 they only received 

28% of the total dollars appropriated by Congress for pipeline safety. Unless Congress 

recognizes the need for additional State inspection resources this funding shortfall will 

continue to widen in the future, jeopardizing the States’ working relationship and 

partnership agreement with PHMSA creating a potential public safety concern. 

The responsibility for State pipeline safety programs is carried out by approximately 

325 qualified engineers and inspectors who represent more than 80 percent of the 

State/federal inspection workforce that are currently inspecting natural gas and liquid 

pipeline operators on a daily basis. 

State inspectors are the “first line of defense” at the community level to promote 

pipeline safety, underground utility damage prevention, public education and awareness 

regarding pipelines, interface with emergency management agencies on security and 

reliable energy issues. Daily activities include inspection of existing facilities, renewal or 

new pipeline construction projects, review of safety maintenance and operations records, 

drug and alcohol records, compliance and enforcement actions, training and education 

programs for operator and public, and accident investigation of reportable incidents. 

State inspectors are required to attend nine mandatory training and computer based 

training (CBT) courses provided by PHMSA’s Transportation Safety Institute within 

three years of employment with a State agency and refresher training required within 7 

years of their attendance to the course. These one week courses already impact State 

expenditures and resources for the program, however, PHMSA has recently added two 

additional courses that gas safety engineers must attend in order to act as their agent and 

participate in integrity management audits. We believe all the courses are positive. It 

seems, however, the federal government is providing additional mandates while not 

funding the program at a level commensurate with the existing responsibilities, let alone 

any additional requirements. 

2. Congress Should Increase The Current $1 Million Damage Prevention Grant 

To States To $2.5 Million. 

For several years now, Congress has funded a $1 million grant to assist all States 

with their existing excavation damage prevention programs. Every year, PHMSA 

receives more than $2.2 million in requests from States to support and continue their 

existing prevention efforts. NARUC is respectfully requesting that Congress increase this 

very important grant to at least $2.5 million to better support existing damage prevention 

efforts. 

One-Call grants have enhanced state damage prevention efforts by funding a wide 

range of enforcement, incentive, and awareness activities. In many states the scope of 

enforcement would be restricted without this funding. Much of the data collection to 

evaluate damage prevention program effectiveness and needs is made possible by the 

One-Call grants. Incentives such as equipment and training, supported by grant funding, 

have been effective in bringing small operators of limited financial means into 

compliance with state damage prevention laws. Grant-assisted training for excavators 

has improved their knowledge of State One-Call laws and safe excavation practices, but 

must be on-going to remain effective. The One-Call grants support changes in State 

damage prevention law to meet federal guidelines. And the grants have greatly assisted 

State actions to educate local officials, excavators, utilities and the public on One-Call 

awareness and the importance of preventing damage to all underground facilities. 
95

In March 2005, with NARUC’s strong support, the Federal Communications 

Commission designated the 811 number as the national abbreviated dialing code for OneCall systems to comply with the Pipeline Safety Act of 2002. The three-digit number 811 

will be easy to remember and use by excavators to help reduce damages to all 

underground facilities. States are approving applications submitted to their agencies by 

the local One-Call organization for the assignment of the 811 number. The States will 

need funds to help promote the awareness of this service. 

State programs requested $2.2 million in One-Call grant funds during the last 

application period. This would undoubtedly have been higher if caps were not placed on 

the amount a state could request, and does not reflect the additional need to promote 811. 

Grant funding of $2.5 million would adequately fund existing and new needs. 

3. Distribution Integrity Management Program Should Provide Additional Safety 

Improvement. 

NARUC is of the opinion that implementing gas distribution integrity management 

consistent with the findings and conclusions contained in the “Integrity Management for 

Gas Distribution” report released in December of 2005 and prepared by representatives 

from NARUC, other government agencies, industry, and public joint work/study groups 

should provide additional safety improvement. Specifically, this study found that the 

most useful option for implementing distribution integrity management requirements is a 

high-level flexible federal regulation in conjunction with implementation guidance 

developed by the government and industry. 

The report finds that a high-level flexible rule requiring distribution operators to 

formally develop and implement integrity management plans that address the key 

elements outlined by Department of Transportation Inspector General; understand the 

infrastructure, identify and characterize the threats, and determine how best to manage 

the known risks, should be sufficient to address distribution safety enhancements. 

NARUC members participated in each of the four task teams in the development of the 

report and on going development of guidance material to assist operators, small and 

large, in compliance with the proposed rule. 

This report was too lengthy to be included in my testimony, however it can be found 

at: http://www.cycla.com/opsiswc/docs/S8/P0068/DIMP_Phase1Report_Final.pdf 

4. NARUC Supports 80% Grant Funding For All Pipeline Safety Programs That 

Enforce Excavation Damage Prevention Distribution Integrity Inspections and 

Other Mandated Programs. 

NARUC recommends that the present 50 percent reimbursement ceiling contained 

in federal statute be changed to 80 percent. A State pipeline safety program’s cost to 

enforce damage prevention laws is not presently considered to be allowable costs for the 

Base Grant. As noted in the Integrity Management for Gas Distribution Report to 

PHMSA, excavation damage to pipelines was considerably less in States where State 

pipeline safety programs enforced damage prevention laws. States should be encouraged 

to place pipeline damage prevention responsibilities within State pipeline safety 

programs. The cost associated with implementing effective damage prevention programs 

along with additional resources needed to carry out the core pipeline safety programs 

justifies the 80 percent funding. This funding level is consistent with other non-pipeline 

safety grants to States administered by DOT. Providing cost reimbursement of 80 percent 

to State pipeline programs will allow States to accomplish their pipeline safety 

responsibilities and provide an important incentive for States to implement effective 

damage prevention programs, distribution integrity inspections and other mandated 

programs thus improving the safety of the nation’s gas distribution infrastructure. 

In the Integrity Management for Gas Distribution Report, the Excavation Damage 

Prevention Task Group found excavation damage by far poses the single greatest threat to 
96

distribution system integrity and is thus the most significant opportunity for distribution 

pipeline safety improvements. Reducing the threat of excavation damage requires 

affecting the behavior of persons not subject to the jurisdiction of pipeline safety 

authorities (i.e. excavators). Federal legislation is needed to support the development and 

implementation of effective comprehensive State damage prevention programs. Data 

from the Task Group report over the last 5 years has demonstrated that States with 

comprehensive damage prevention programs that include effective enforcement 

experience results in substantially lower rates of excavation damage to pipeline facilities 

than programs that do not. The lower rate directly translates to a substantially lower risk 

of serious incidents, accidents, and consequences resulting from excavation damage to 

pipelines. PHMSA’s reaction to the report recommendations has been positive, including 

the view that the agency should consider providing seed funding to States as an incentive 

to develop stronger damage prevention programs. The program would be a separate grant 

fund, apart from funding already being provided under the matching grants or One-Call 

programs and may be entitled, Excavation Damage Prevention Grant. Once the State 

takes steps to implement the program, which would be similar to the damage prevention 

enforcement programs in Virginia and four other States, it would be granted additional 

funds via the matching grants program. Obviously, the new programs will need funding 

up to 80% at the beginning for staffing levels to respond to calls and investigations of 

damages by outside parties. Such funding may be reduced as outside damages are 

lowered by enforcement. The funds should be provided to State agencies having 

experience and knowledge in underground utility damage prevention for pipeline safety. 

The Task Group reviewed several approaches to provide incentives for this program and 

developed proposed legislation which I have included in this testimony as an attachment. 

5. Federally Mandated Installation Of Excess Flow Valves (EFVs) On Service 

Lines To Customers Is Not Necessary.

A survey performed at the request of NARUC by the National Regulatory Research 

Institute in July of 2005 supports the majority of State regulatory agencies which are 

satisfied that operators are installing them where they can be effective. NARUC passed 

resolutions encouraging federal agencies and legislators to recognize that State officials 

are well positioned to have knowledge of the operational conditions and circumstances 

for the installation of these devices and understand that a decision whether or not to 

install the devices is best determined by the affected State regulatory body. 

Distribution Integrity Management Program steering committee members submitted 

formal comments to PHSMA consistent with other organizations on the installation of 

these valves. Operational experience verifies that of the thousands of EFVs installed in 

the past, very few have had false activations. When properly specified and installed, 

EFVs can reliably interrupt the gas flow under certain conditions when there is an excess 

flow in the service line. These valves are primarily installed in new and replaced service 

lines on single family residences where operating pressure is greater than 10 psig. 

Addressing safety requires an overall approach that allows consideration of all tools and 

technologies for the various threats to distribution pipelines. EFVs can be used to 

address the threat of excavation damage for single family residential lines. There may be 

other tools that can equally or more effectively address this same threat. Therefore, rather 

than a blanket mandate for installation of EFVs, a provision of Distribution Integrity 

Management should state that each operator consider the use of EFVs on its own 

operating system. 

Mr. Chairman and members of the Subcommittee, this concludes my remarks. 

Thank you again for the opportunity to appear before you today and share these views on 

a most important issue. I will be happy to address any question you may have. 
97

ATTACHMENT 

Draft Federal Legislation 

§ 60105. State pipeline safety program certifications 

Subsection (b) of section 60105 is amended by revising paragraph (b)(4) to read as 

follows: 

“(4) has or will adopt, within 36 months of [the date of enactment of this 

amendment], a program designed to prevent damage by excavation, demolition, 

tunneling, or construction activity to the pipeline facilities to which the certification 

applies that meets the requirements of section 601XX.” 

(i) If a state fails to develop and implement an excavation damage 

prevention program in accordance with item (4), above, the Secretary 

shall take any action deemed appropriate to ensure an effective damage 

prevention program within that state. 

(ii) Annually, if a state can demonstrate to the Secretary that it has taken all 

reasonable actions to implement such a program without success, 

funding for the remainder of its pipeline safety program shall not be 

affected. 

§ 601XX. State damage prevention programs 

(a) Minimum standards. In order to qualify for a grant under this section, each State 

authority (including a municipality if the agreement applies to intrastate gas pipeline 

transportation) having an annual certification in accordance with section 60105 or an 

agreement in accordance with section 60106 shall have an effective damage prevention 

program that, at a minimum, includes the following elements: 

(1) Effective communication between operators and excavators- Each state 

program shall provide for appropriate participation by operators, excavators, 

and other stakeholders in the development and implementation of methods for 

establishing and maintaining effective communications between stakeholders 

from receipt of an excavation notification until successful completion of the 

excavation, as appropriate. 

(2) Fostering support and partnership of stakeholders- Each state program shall 

include a process for fostering and ensuring the support and partnership of 

stakeholders including excavators, operators, locators, designers, and local 

government in all phases of the program. 

(3) Operator’s use of performance measures – Each state program shall include a 

process for reviewing the adequacy of a pipeline operator’s internal 

performance measures regarding persons performing locating services and 

quality assurance programs. 

(4) Partnership in employee training – Each state program shall provide for 

appropriate participation by operators, excavators, and other stakeholders in the 

development and implementation of effective employee training programs to 

ensure that operators, the one-call center, the enforcing agency and the 

excavators have partnered to design and implement training for operators,’ 

excavators’ and locators’ employees. 

(5) Partnership in public education – Each state program shall include a process for 

fostering and ensuring active participation by all stakeholders in public 

education for damage prevention activities. 

(6) Dispute resolution process – Each state program shall include a process for 

resolving disputes that defines the state authority’s role as a partner and 

facilitator to resolve issues. 
98

(7) Fair and consistent enforcement of the law- Each state program shall provide 

for the enforcement of its damage prevention laws and regulations for all 

aspects of the excavation process including public education. The enforcement 

program must include the use of civil penalties for violations assessable by the 

appropriate state authority. 

(8) Use of technology to improve all parts of the process – Each state program 

shall include a process for fostering and promoting the use, by all appropriate 

stakeholders, of improving technologies that may enhance communications, 

locate capability, and performance tracking. 

(9) Analysis of data to continually evaluate/improve program effectiveness – Each 

state program shall include a process for review and analysis of the 

effectiveness of each program element and include a process for implementing 

improvements identified by such program reviews. 

(b) Application. If a State authority files an application for a grant under this section not 

later than September 30 of a calendar year, the Secretary of Transportation shall review 

that State’s damage prevention program to determine its effectiveness. For programs 

determined to be effective, the Secretary shall pay 80 percent of the cost of the personnel, 

equipment, and activities the authority reasonably requires during the next calendar year 

to carry out an effective damage prevention enforcement program as defined in (a) of this 

section. 

(c) Authorization of Appropriations. There is authorized to be appropriated to the 

Secretary for carrying out this section [the dollar amount equal to the 80% referenced in 

(b) above] for each of the fiscal years 2006 through 2010. Such funds shall remain 

available until expended. Any funds appropriated to carry out this section shall be 

derived from general revenues and shall not be derived from user fees collected under 

section 60301. 

 MR. HALL. I think it is pretty obvious that the gentleman from 

Virginia is satisfied with the positive response system that he has offered 

and probably would suggest that as a Federal model, would you?

 MR. TAHAMTANI. Mr. Chairman, in a recent study that was 

completed in December of 2005 on distribution management, I chaired 

the Excavation Damage Prevention Group within that group that 

conducted the study. That group came up with the nine elements that I 

mentioned that have worked for Virginia, so I would believe that any 

program put together with those nine elements would hopefully produce 

the results that we have produced in Virginia. 

 MR. HALL. Do any other States have a similar program? 

 MR. TAHAMTANI. There are at least three or four other States that 

have seen a dramatic decrease in their damages as a result of a very 

active enforcement program, but not all of these States have the nine 

elements that I mentioned that we have in Virginia. 

 MR. HALL. You both were interested, in your testimony, in 

increasing the grant funding for all pipeline safety programs that enforce 

excavation damage prevention programs from 50 percent, as it is now, to 

80 percent. Give us some sense of actual dollar numbers that you are 

talking about for each State, and how that funding could be applied to 

enforce excavation damage prevention at the State level. Not in 
99

percentages, but in money, in dollars and cents. And how would that 

money be spent? 

 MR. TAHAMTANI. I will go ahead, Commissioner Mason, and just 

talk about Virginia very briefly. 

 Our damage prevention program, again, is funded by the penalties 

we collect. So none of that money comes from either the State or the 

Federal government, and maybe that is very unique in that it keeps it 

moving along. Now some people don’t like that because they think that, 

well, the more you fine, the more money you have and the more things 

you can do. That has not been the issue. I started with five investigators 

in 1996. Today I am down to two, because the damage has gone down. 

Now we didn’t fire the other three. They are full-time trainers. They 

train about 4,000 contractors a year. We have 41,000 licensed 

contractors in the State of Virginia, and all of those are not licensed that 

come in from D.C., Maryland, and other States. So you can see that that 

program has sort of funded itself, and that is why I believe we have the 

success we have. 

 As far as pipeline safety, we help OPS do inspections of the 

interstate pipelines on the liquid, the oil pipelines. Our program costs 

about $2 million a year. Forty-one percent of that comes from the grant 

from the Federal government. This is why we need more grants to assist. 

In Virginia, that money has never been a problem. Our commissioners 

support our program. There are a lot of States that match the grant that 

the Federal government provides, so if you give them $50,000, they only 

match it by $50,000. They need your help, and this is why we are 

recommending that the funding be increased from 50 to 80 percent. 

 MR. HALL. Commissioner Mason? 

 MR. MASON. Mr. Chairman, that is a great question, and going to 

the point of perhaps even using the grant money to create seed money, 

sir, that the program can be up and running. Then as you have 

excavation damage and subsequent fines that can continue to refund 

almost on a rotary or a revolving basis, but you really need, initially, at 

least, for the seed money to be there so that a State can get a program up 

and running. It is almost like running any business. It costs money to 

get in business before you can open the door. 

 MR. HALL. All right. I recognize the gentleman from Virginia, Mr. 

Boucher. 

 MR. BOUCHER. Well, thank you very much, Mr. Chairman. 

 And Mr. Tahamtani, did I get that correct? 

 MR. TAHAMTANI. Yes, sir. 

 MR. BOUCHER. Yes, that is good. 

 Let me thank you for taking part in our hearing today and 

congratulate you on the success that you are having in Virginia. You are 
100

getting accolades all of the way around. I think you heard on the first 

panel a general consensus that Virginia’s program leads the Nation in 

preventing damage from excavation. And we are all in agreement that it 

is a model that would usefully be replicated elsewhere. I think the key 

question that we have is what we might be able to do, perhaps in our 

reauthorization of the 2002 statute, that could encourage other States to 

adopt Virginia’s program, or at least the essential elements of it. 

 And so I would ask both of you if you have any suggestions for us 

that we could incorporate in the statutory revision that we intend to make 

that would have the effect of having every State celebrate their 

experience to the level that Virginia is. 

 Mr. Mason, do you have any suggestions? 

 MR. MASON. I don’t know specifically what I can recommend to 

Congress. I know what we do, as States, is try to put on sessions. Three 

times a year our association meets. We try to take best practices and sort 

of inform and educate other commissioners as to what is going well. 

And Virginia does have a great program. I know our staff and others 

have worked with them to understand it. But yes, it takes funding to get 

to that next level so that we can make a good program, you know, the 

best available technology, so to speak, go statewide. As we mentioned 

earlier in our testimony, it really does take Federal funding proportionate 

and equal to what State funding you have there, so I really believe that if 

Congress appropriates the amount we recommend, then we can take it to 

the next level and work across the State jurisdictional and 

commonwealth jurisdictional lines. 

 MR. BOUCHER. Let me ask you why funding is essential to this. 

Virginia developed its program based on resources then available. Why 

can’t other States do the same? Why does money have to flow from the 

Federal Government in order to make that happen? 

 MR. MASON. Well, that is somewhat of a loaded question, because 

that would mean I would have to identify States that are destitute or not 

as well off as Virginia, but in fact, not every State has a growing 

population and those kinds of things, such as Virginia. Many States are 

in economic decline. And when the State General Assembly is trying to 

allocate their funds in everything from education to medical issues, 

social and medical issues, and so without grant money to match State 

money, this has received the lower priority. 

 MR. BOUCHER. Okay. Well, that is a point very well taken. 

 So let me ask you, Mr. Tahamtani, do you have any statutory 

recommendations for us, I mean, changes in the law that might be helpful 

in this respect? 

 MR. TAHAMTANI. Mr. Boucher, as I indicated, I participated in this 

very lengthy study last year that has been submitted to the Office of 
101

Pipeline Safety, its gas distribution integrity management. We all know 

that excavation damage is the leading cause of pipeline accidents and 

failures, so our group spent a lot of time coming up with ways to help all 

States improve their damage prevention program. And we also put some 

language together to give the Secretary the authority to encourage the 

States with some seed money first and some after to ensure that they are 

moving forward with State laws. It is going to take good State laws to 

make this happen at the State level. 

 The fact that Virginia, I guess, from the very beginning used their 

funds to go back to the public, that has helped. They don’t think of this 

as a way to balance the State budget. This money goes back into the 

program, and that has helped our program. 

 MR. BOUCHER. Okay. Well, that answer doesn’t quite get at the 

question. I guess at one extreme, we could simply suggest that maybe 

we ought to have a Federal statute that says here are nine elements that 

every State should adopt in order to prevent excavation damage. We 

would probably be legislating that with greater certainty than we 

generally have when we embark upon a statutory exercise because we 

have the Virginia program that is a model, based on those nine elements, 

that, in the opinion of virtually everyone, has succeeded extraordinarily 

well, better than any other State in the country. 

 So I think I can anticipate your answer, but why should we not 

simply do that? 

 MR. TAHAMTANI. What I mean here is that our group proposed that 

you do exactly that. 

 MR. BOUCHER. Oh, that we do that? 

 MR. TAHAMTANI. Yes. 

 MR. BOUCHER. So in other words, we have a Federal statute that 

says every State shall have a program that adopts the following nine 

elements. Period. And then we provide some grant funds to help States 

with implementation. 

 MR. TAHAMTANI. Exactly. 

 MR. BOUCHER. So that is your proposal? 

 MR. TAHAMTANI. Yes. 

 MR. BOUCHER. Mr. Mason, do you agree with that? 

 MR. MASON. Mr. Boucher, I guess, just because I represent an 

organization, so I will answer that based on my viewpoint. Having a 

flexible Federal recommendation is very good. It still gets down to the 

bottom line of whether there will be sufficient funding at the State level. 

I think we include in our testimony, for example, a survey of States on 

what kind of funding they will use for their programs. And really, only a 

couple actually use GRF. Almost every one of them use some sort of a 

formula based on some sort of a fee. So the bottom line is, if there is a 
102

flexible Federal requirement encouraging those nine points or other 

points, or you know, somewhere around that guideline, that would help 

in a long way to where State GPS programs could then work through 

their system to try to get, again, match money for Federal match money, 

because I think your State legislature is going to know that they are 

partnering with the Federal government. In other words, if the flexible 

requirements are coming from the Federal side, it needs to have money 

to match the State money, because there only two that I can find that use 

GRF. 

 MR. BOUCHER. Okay. Well, your answer sort of comes back to 

money again. I gather your recommendation to us falls somewhat short 

of Mr. Tahamtani’s in terms of the statutory requirement that the Federal 

government would make. You are not prepared to endorse, at this point, 

a Federal statute that would simply say each State must adopt a program 

that relies upon these nine principles? You are not willing to go that far, 

is that correct? 

 MR. MASON. And the reason I am not willing to go that far is my 

experience at NARUC is a lot of States are willing to do something, but 

truly they like to have it as a State decision and not Federal mandates. 

And I have run into this on other issues and I am dealing with our 

pipeline taxation issue right now. It is just a lot of people like seeing the 

light; they just don’t like being drawn with a noose around their neck to 

it. 

 MR. BOUCHER. All right. Well, Mr. Mason, do you think NARUC 

would be willing to work with us over the coming month or so on an 

appropriate Federal statutory provision that your organization, perhaps, 

could then endorse? 

 MR. MASON. I could go so far as to say we could put workshops on 

sponsor resolution and try to inform and educate the membership. 

 MR. BOUCHER. Right, but the question I am asking you, will you 

work with this committee-- 

 MR. MASON. Oh, absolutely. 

 MR. BOUCHER. --in order to help us derive an appropriate statutory 

provision for whatever changes we decide to make in the 2002 law that 

addresses this concern? 

 MR. MASON. I would be happy to work with the committee, and we 

have had a great working relationship with DOT, with PHMSA, and its 

predecessor, so absolutely. 

 MR. BOUCHER. All right. Very good. Thank you very much. 

 Thank you, Mr. Chairman. 

 MR. MURPHY. [Presiding] Thank you. 

 The Chairman will recognize himself for 5 minutes here. 
103

 A question to Mr. Tahamtani. With regard to the Virginia model you 

had mentioned that it reduced incidents by 50 percent. How did it do in 

terms of preventing injuries from breaches of pipeline? Do you know 

what that rate was? 

 MR. TAHAMTANI. Since 1996, again, when we began the mandatory 

reporting, we had one death. A woman had called, so the public 

education was working, and the marking was supposed to happen by 

Wednesday. The locator called and requested an extension to Friday. 

They marked it on Friday. They mismarked the gas line. On Saturday 

morning, when he started his saw in the basement, he had a house 

looking like this, and he died three weeks later. 

 That particular case, we took it to the commission and went through 

our process, and they did a very, very good case. As a result of that, that 

locator company is now out of business. So we have had one death since 

1996, so-- 

 MR. MURPHY. But in terms of reduction of injuries, though? 

 MR. TAHAMTANI. We have not had any injuries. 

 MR. MURPHY. In this now, you have heard earlier, we were talking 

about Minnesota had a change to require notification to 911 when there 

is a breach. Does Virginia have any equipment law with regard to 

notifying anybody when there is a-- 

 MR. TAHAMTANI. I knew you would ask that question, so here is my 

law. If the damage, this location, or disturbance in the underground 

utility facility creates an emergency, and this is defined in our law 

something that impacts life, property, and so on and so forth, the person 

responsible for the excavation and demolition shall, in addition to 

complying with subsection D, which means calling the gas company, in 

this case, take immediate steps to reasonably safeguard life, health, and 

property. Now that is enforceable by our commission, so when we see 

that they have not done that, obviously penalties are used to encourage 

that. We haven’t had any problems. 

 MR. MURPHY. That seems broadly defined, I mean, with regard to 

taking steps to secure life and property. Is that interpreted to mean they 

notify the police or the fire department? And what mechanism do they 

have to go through to do that? 

 MR. TAHAMTANI. We have got a county, Fairfax County, not far 

from here, that they monitor all of the 911 or all of the damages and they 

appear because of the way they want to run their emergency response in 

the county, that under that provision I believe that it is flexible enough. 

The other piece of this is that we are out there educating excavators. 

This is what you do when you have got a damage. If you have got a nick 

to the pipeline and no gas releases, this is what you do. If the gas is 
104

released, this is what you do. So excavators have actually evacuated the 

area before even calling 911. 

 MR. MURPHY. Mr. Mason, would you know what some of those are 

with regard to how States are managing this when there is an actual 

release when a pipeline is breached? 

 MR. MASON. The language, of course, varies from jurisdiction to 

jurisdiction. I don’t know of any that actually have language that says 

the magic numbers 911. It goes back to the issue of notifying proper 

authorities and company personnel. That seems to be the-- 

 MR. MURPHY. You were not here earlier, you were caught up in 

traffic, when I was showing a picture of this home where the rule in 

Pennsylvania was similar. You notify someone and they notify the local 

municipality, but no one was in the local municipality, and so it came via 

fax to an empty room. And I understand there is a variation between 

States and how they notify. And my concern is that if it simply says they 

take reasonable steps and the local reasonable step is you send a fax, that 

is not going to save lives. And so part of the question I asked the 

previous panel, and hope it is something you can help me with, too, by 

giving the two areas that each of you have expertise and jurisdiction in to 

help us understand and know what different States do and what would be 

an effective model. The Virginia model sounds like it is working pretty 

well with reducing and preventing the breach in the first place. But once 

it does occur, my question is how can we require the States to have some 

reasonable rules, which also are sensitive to the vast differences in, for 

example, rural areas versus urban areas and the size of the pipe and the 

type of the leak, et cetera. So that is something I wouldn’t expect you all 

to have full knowledge of now, but if your associations could help get 

information back to the Chairman on this, I would be very grateful for 

that. 

 MR. MASON. Mr. Chairman, it is difficult to talk about, you know, 

cases in specific, and especially those ones that are in litigation. One of 

the biggest issues we have, though, is when there has been possible 

damage, and a lot of times you don’t know of the leak at the time, and 

then a subsequent slow leak that eventually causes the fire or, you know, 

something along that line. So you have that whole range of things 

happening right now with a flash or with a leak you can hear to 

something that creates a slow enough leak that you may not know that it, 

you know, runs along the pipe into a home. 

 MR. MURPHY. Along those lines, when someone is doing excavating 

as a subcontractor or someone else is drilling, in this case they were 

doing horizontal drilling, and I guess they not only punctured a gas line, 

but they punctured the drain line to the house, in situations like this, is it 
105

required that the excavators have with them equipment to monitor for gas 

leaks? 

 MR. MASON. I am not aware that it is, Mr. Chairman. 

 MR. MURPHY. So how would they know, when you say it is a slow 

leak or a medium leak? Basically, would they only know if they smell 

it? I mean, I am assuming when someone is going through a 

neighborhood to detect any kind of gas leaks, then you would be 

searching for leaks that perhaps are so small they would not be sensitive 

to the human nose to pick that up. And if we don’t require them to have 

any kind of monitoring equipment, and yet they are drilling or excavating 

in an area that has pipelines and concerned enough to call 811- or some 

other system, how would we even know if they broke a line? 

 MR. TAHAMTANI. Well, again, the gas is odorized, so the first thing 

is the sense of smell and, as I mentioned, the odor had been stripped off 

of the gas, because it migrated through soil to the basement of the house, 

of course, hearing, and the actual damage. But no law that I know of 

requires excavators to carry gas-detecting equipment to monitor the gas 

leaks. If something is nicked and it is covered up and the gas migrates, 

then we all hope that everything goes right and people smell the gas and 

respond properly to make sure nothing happens. 

 MR. MURPHY. But you just said that that odor may be stripped off as 

it migrates through the soil. 

 MR. TAHAMTANI. It can get stripped, yes. 

 MR. MURPHY. Can that still be detected if someone has the 

monitoring equipment, such as what gas companies go through 

neighborhoods with? 

 MR. TAHAMTANI. Right. 

 MR. MURPHY. You said, as far as you know, however, no one is 

required to have that equipment with them? 

 MR. TAHAMTANI. For excavators. 

 MR. MURPHY. For excavators. All right. I see my time is expired. 

 And Mr. Burgess here from Texas is recognized for 5 minutes. 

Thank you. 

 MR. BURGESS. Thank you, Mr. Chairman. 

 I apologize for missing most of the hearing. There was another 

hearing going on downstairs. 

 Just for a point of reference, I live in this green spot here in Texas. It 

is called the Barnett Shale. And I really don’t have a lot of questions, 

because, again, I did miss most of this, but I do want to ask you, Mr. 

Mason. You made reference to the fact that if the point of distribution 

was too close to the production facility, that that could gum up the 

works. I think that is the technical term that you used. 
106

 MR. MASON. Very technical, Mr. Congressman. I work with Mary 

McDaniel. Well, I believe she was the director of the Gas Pipeline 

Safety Program at the Texas Railroad Commission. We were trying to 

scope when an EFV should be used and when it, perhaps, wouldn’t be 

prudent. Basically, now the EFVs work well, about 10 pounds per 

square inch. One of the caveats, though, is there is concern if the natural 

gas has constituent qualities, and I would hear people use the term 

“contamination.” I don’t like using that word, because that implies, to 

me, something from outside. And for 9 years, by the way, I was the 

Chief of the Division of Oil and Gas. I oversaw oil and gas production in 

the State of Ohio Environmental Enforcement. So when I hear the word 

“contamination,” that, to me, is something that is not indigenous to the 

natural gas itself. But in production areas, through the Appalachians, 

obviously Texas, and other places, you do have some of the heavier 

gases that, as the gas moves and cools, could, in fact, drop out. Perhaps 

there is a better term than “gum up,” but in fact, what we are talking 

about is interfering with the normal operation of the EFV itself. Again, 

those are the concerns we have on what would be called a mandatory 

mandate. We want to make sure anything that was put in place operated 

well, regardless of the constituents, as well as above 10 p.s.i. As far as 

the p.s.i. goes, you know, 5 years from now, a year from now, it could be 

five p.s.i. That is based on the development of technology on the EFVs. 

 MR. BURGESS. Well, is the concern there because of the relationship 

between volume, temperature, and pressure, or is it because of the 

presence of other substances in the gas as it recently comes out of the 

well? 

 MR. MASON. It is my understanding, as you know, and this is the 

way it has been in Ohio, but with a little experience in the Southwest, but 

a lot of times, the heavier gases were stripped out for sale, and that is fine 

when you are moving natural gas from Oklahoma or Texas into Ohio or 

into the Northeast, and that does happen. But frankly, gas systems are 

located close enough to the well fields that you are really getting gas 

fairly directly from the well fields, and so it has been explained to me 

from my counterparts in Texas that one of the concerns they have is they 

want to make sure if, for example, there was a requirement for an EFV 

that it would actually operate well in all conditions of natural gas, again 

in the Northeast as well as in the Southwest. 

 MR. BURGESS. So we do have, because of the geologic peculiarities 

of the Barnett Shale, that gas is harvested by hydraulic fracturing, and so 

we have ended up poking a lot of holes in that geologic formation to 

recover the gas. 

 Another issue with the Barnett Shale is that it is sited underneath 

what is largely, in some instances, a very developed and populated area. 
107

Of course, with lateral drilling, they are able to recover more of a gas, 

but are there special considerations that need to be taken with this type of 

geologic formation that is under an area that is relatively populated? 

 MR. MASON. I am not aware of any. And of course, we have had, 

you know, a lot of drilling within urban areas for a lot of years, and the 

biggest safety issues always get down to set back from tank batteries and 

things of that nature, anywhere you might have vapors. But that has 

nothing to do with the distribution system, per se. That is the production 

side, and of course, Texas has the Texas Railroad Commission and I 

think their own DEQ or DNR, and I think there are three agencies 

involved in Texas that do a good job. 

 MR. BURGESS. Thank you, Mr. Chairman. I will yield back. 

 MR. MURPHY. Thank you very much. 

 If there are no more questions, we will dismiss this panel. 

 And we invite the third panel forward. 

 We are just going to hold for one second. We are trying to locate the 

Chairman and ask him a quick question. Thank you. Just relax. Here he 

comes now. 

 MR. HALL. We use the two-platoon system here. Thank you for 

chairing, Tim. 

 Okay. We thank this third group for taking position. Mr. Bender, 

who is Vice President of Gas Distribution and New Business Division, 

Baltimore Gas and Electric Company, we recognize you for 5 minutes or 

less to go over your testimony and then subject yourself to some 

questions. Thank you. 

STATEMENTS OF EDMUND F BENDER, JR., VICE 

PRESIDENT, GAS DISTRIBUTION AND NEW BUSINESS 

DIVISION, BALTIMORE GAS AND ELECTRIC COMPANY, 

ON BEHALF OF AMERICAN GAS ASSOCIATION; JERYL 

L. MOHN, SENIOR VICE PRESIDENT, OPERATIONS AND 

ENGINEERING, PANHANDLE ENERGY, ON BEHALF OF 

INTERSTATE NATURAL GAS ASSOCIATION OF 

AMERICA; TIMOTHY C. FELT, PRESIDENT AND CEO, 

EXPLORER PIPELINE COMPANY, ON BEHALF OF 

ASSOCIATION OF OIL PIPELINES; LOIS N. EPSTEIN, P.E., 

SENIOR ENGINEER, OIL AND GAS INDUSTRY 

SPECIALIST, COOK INLET KEEPER, ON BEHALF OF 

PIPELINE SAFETY TRUST; AND BOB KIPP, PRESIDENT, 

COMMON GROUND ALLIANCE 

MR. BENDER. Thank you, Mr. Chairman. Good morning. 
108

 I would like to thank the committee for convening this hearing on the 

important topic of pipeline safety. 

 My name is Frank Bender. I am Vice President of Gas Distribution 

and New Business of Baltimore Gas and Electric Company. We are a 

subsidiary of Constellation Energy. BGE delivers natural gas to 634,000 

customers in Maryland. 

 I am testifying today on behalf of the American Gas Association and 

the American Public Gas Association. Together, AGA and APGA 

represent more than 850 local natural gas utilities serving almost 56 

million customers nationwide. 

 The Pipeline Hazardous Material Safety Administration and the 

industry have made significant progress on the initiatives mandated by 

the 2002 Pipeline Safety Act. 

 In our opinion, only minor adjustments should be considered at this 

point. Our companies have identified only one major area we believe 

requires considerable improvement, and that is excavation damage 

prevention. 

 Congressional attention to more effective State excavation damage 

programs can, and will, result in real, measurable decreases in the 

number of incidents occurring on natural gas distribution pipelines each 

year. Excavation damage is the single cause of a majority of the natural 

gas distribution pipeline incidents. 

 Understandably, most of our customers think that all pipelines are 

alike. There are, however, significant differences between liquid 

transmission systems, natural gas transmission systems, and natural gas 

distribution systems, which are operated by local gas utilities. 

 Gas distribution utilities bring the natural gas service to our 

customers’ front doors. Each type of pipeline system faces different 

challenges, operating conditions, and consequences from incidents. 

 Federal regulations recognize the differences between distribution 

pipes and other types of pipelines, and different sets of rules have been 

created for each. At the same time, State regulators, who have direct 

oversight over distribution operators, are regularly inspecting or 

reviewing our operations. 

 Our industry commitment to safety extends beyond government 

oversight. We continually refine our safety practices. Natural gas 

utilities spend an estimated $6.4 billion each year in safety-related 

activities. Our industry’s commitment to safety is borne out each year 

through the Federal Bureau of Transportation Statistics’ annual figures. 

 Now there are two kinds of incidents involving natural gas 

distribution systems, and if you can look at the chart on my left: first, 

those caused by factors the pipeline operator, to some extent, can control, 

such as improper welds, material defects, incorrect operation, corrosion, 
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or excavation damage by our own contractors. And secondly, those 

caused by factors the pipeline has little or limited ability to control, such 

as excavation damage by a third party, earth movement, structure fires, 

floods, vandalism, and lightning. 

 The record shows that between 2001 and 2005, 82 percent of all 

reported incidents were the result of excavation damage by third party or 

other factors the utility company had little or no control over. In many 

cases, the typical little-or-no-control incident involves a party outside the 

jurisdiction of authorities overseeing pipeline safety. 

 You have heard several times today that excavation damage 

represents the single greatest threat to distribution system safety, 

reliability, and integrity. The nationwide education program on the 

three-digit, one-call dialing to prevent excavation damage is a step in the 

right direction, but more is needed. Data from the last 5 years 

demonstrates that States that have stringent enforcement programs 

experienced a much lower rate of excavation damage to pipeline 

facilities than States that do not have these stringent enforcement powers. 

And again, if you look at the chart, that demonstrates that point with 

Virginia and Minnesota actually leading the way much better than States 

without enforcement programs. 

 A comprehensive damage prevention program includes not only 

education, but also effective enforcement. Currently, the U.S. 

Department of Justice is responsible for enforcing Federal infrastructure 

damage prevention statutes with regard to parties conducting 

excavations. Most unfortunately, the Department has rarely exercised 

such authority. 

 Programs such as Virginia’s and Minnesota’s show that nine key 

elements must be present and functional for the damage prevention 

program to be effective. And this chart shows specifically those nine 

elements. 

 AGA and APGA recommend that Congress modify existing law to 

insert a new section outlining these nine elements and providing for 

additional funding for implementation of the program. Such funding 

should be allocated directly to each State agency having oversight over 

pipeline safety. AGA and APGA also support providing continued 

funding authority for grants to States to support one-call programs and 

for partial funding of the Common Ground Alliance damage prevention 

organization. 

 The statistics are clear: excavation damage prevention represents the 

single greatest opportunity for distribution safety enhancements, and we 

urge Congress to take decisive action on this front. 

 Turning now to distribution system integrity, we have been 

participating in a team with all members of a joint Federal, State, 
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industry, and public stakeholder group to work towards completion of 

the distribution integrity management rule by PHMSA. Thus, industry 

and government stakeholders are working collaboratively on their own 

initiative to improve the safety of the Nation’s distribution lines. We 

believe that this process is moving forward successfully and should be 

continued without further legislative imperatives. 

 This distribution integrity management stakeholder group also found 

that federally-mandated installation of excess flow valves on service 

lines to customers is not appropriate. It did, however, suggest that 

operators be required to perform a risk assessment and outline risk 

criteria for installation of the excess flow valves. 

 It is our hope that in evaluating the appropriateness of the 7-year 

reinspection requirement, the U.S. Government Accountability Office 

will uncover all of the pertinent facts and that, based on those findings, 

Congress will consider options for allowing a change to the interval that 

would be consistent with those findings. This will allow operators to 

continue to deliver natural gas safely and affordably. 

 In summary, AGA and APGA believe that Congressional passage of 

pipeline safety reauthorization this year will result in timely and 

significant distribution system safety improvements. The members of 

AGA and APGA emphatically support the recommendation that 

Congress enact legislation that gives States an incentive to adopt stronger 

damage prevention programs. 

 Thank you for the opportunity to appear here today. 

 [The prepared statement of Edmund F. Bender, Jr. follows:] 

PREPARED STATEMENT OF EDMUND F. BENDER, JR., VICE PRESIDENT, GAS DISTRIBUTION 

AND NEW BUSINESS DIVISION, BALTIMORE GAS AND ELECTRIC COMPANY, ON BEHALF OF 

AMERICAN GAS ASSOCIATION

Summary

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 continuing our efforts to operate safe and reliable systems and to 

strengthening One-Call laws and systems in every state. 

AGA and APGA believe that Congressional passage of pipeline safety 

reauthorization this year will result in timely and significant distribution system safety 

improvements. Further, because of the wide variety of distribution systems across the 

U.S, promulgation of a distribution integrity regulation by PHMSA may yield effective 

enhancements in distribution safety if PHMSA allows gas utilities risk-based options to 

address threats to pipeline integrity in their specific systems and situations. 

Despite the fact that our members, when undertaking excavation themselves, would 

have to also abide by the provisions of an enhanced state damage prevention program, the 

members of AGA and APGA emphatically endorse the recommendation that Congress 
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enact legislation that incentivizes states to adopt stronger damage prevention programs. 

By doing so, all states could realize a significant, marked reduction in incidents on 

distribution lines. 

Thank you for providing the opportunity to present our views on the important 

matter of pipeline safety. To reiterate, since the passage of the 2002 Pipeline Safety Act, 

PHMSA and the industry have made significant progress – and now we urge you to go a 

step further in that positive direction by addressing excavation damage. We feel 

confident overall in reporting today that, other than this issue, the pipeline safety program 

is going well. 

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 Frank Bender. I am vice president of Gas 

Distribution and the New Business Division of Baltimore Gas and Electric Company, a 

subsidiary of Constellation Energy. BG&E delivers natural gas to 634,000 customers in 

an 800 square mile area in Baltimore and surrounding areas in Central Maryland. Our 

company is proud of its heritage as the first gas utility in the United States, tracing its 

history back to 1816. 

I am here testifying today on behalf of the American Gas Association (AGA) and 

the American Public Gas Association (APGA). AGA represents 197 local energy utility 

companies that deliver natural gas to more than 56 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. 

 APGA 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 655 members in 36 states. Overall, there are 

approximately 950 municipally owned systems in the U.S. serving nearly five million 

customers. Publicly owned gas systems are not-for-profit retail distribution entities that 

are owned by, and accountable to, the citizens they serve. They include municipal gas 

distribution systems, public utility districts, county districts, and other public agencies 

that have natural gas distribution facilities. 

 I hope that my testimony will provide you with a better understanding of natural gas 

distribution systems, their regulatory setting, what is being done to further enhance their 

safety and how together we can build upon the excellent record of safety natural gas 

utilities have established. 

The last reauthorization of pipeline safety resulted in several significant mandates 

and initiatives aimed at enhancing safety. Since the passage of that bill in 2002, the 

Pipelines and Hazardous Materials Safety Administration (PHMSA) and the industry 

have made significant progress on each of those initiatives, and the record shows that 

things are proceeding very well, with only a few minor adjustments to be considered. In 

fact, our companies have identified only one major area we believe requires considerable 

improvement: excavation damage prevention. Our companies believe your attention to 

more effective state excavation damage programs can, and will, result in real, measurable 

decreases in the number of incidents occurring on natural gas distribution pipelines each 

year. Although I will speak today on a number of issues the industry has considered in 

terms of further enhancing the safety record of natural gas pipelines, I will spend the 

majority of my time addressing excavation damage, which is the cause behind the 

majority of natural gas distribution pipeline incidents, and the need for Congress to 

provide an incentive for states to adopt stronger damage prevention programs. 

 
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Gas Distribution Utilities Serve The Customer

 In order to understand how distribution safety can be enhanced, it is first important 

to understand the function and structure of distribution pipelines. 

Distribution pipelines are operated by natural gas utilities, sometimes called “local 

distribution companies” or LDCs. The gas utility’s distribution pipes are the last, critical 

link in the natural gas delivery chain. To most customers, their local utilities are the “face 

of the industry”. Our customers see our name on their bills, our trucks in the streets and 

our company sponsorship of many civic initiatives. We live in the communities we 

serve and interact daily with our customers and with the state regulators who oversee 

pipeline safety. Consequently, we take very seriously the responsibility of continuing to 

deliver natural gas to our communities safely, reliably and affordably. 

 

The Difference in “Pipelines”

 Understandably, most customers lump all “pipelines” together, however, there are 

indeed significant differences between liquid transmission systems, natural gas 

transmission systems and natural gas distribution systems operated by local gas utilities. 

Each type of pipeline system faces different challenges, operating conditions and 

consequences of incidents. 

 Interstate transmission systems are generally long, straight runs of large diameter 

steel pipelines, operated at high volumes and high pressures. These larger transmission 

lines feed natural gas to the gas distribution utility systems. 

Gas distribution utility systems, in contrast, are configured like spider webs, operate 

at much lower volumes and pressures and always carry gas that has been odorized for 

easy leak detection. Distribution pipeline systems exist in populated areas, which are 

predominantly urban or suburban. 

Distribution pipelines are generally smaller in diameter (as small as 1/2 inch), 

operate at pressures ranging upward from under one pound per square inch, and are 

constructed of several kinds of materials including a large amount (over 40 percent) of 

non-corroding plastic pipe. Distribution pipelines also have frequent branch connections, 

since most customers require individual service lines. Most distribution systems are 

located under streets, roads, and sidewalks and, when working on them, care must be 

taken not to disrupt the flow of traffic and of commerce unnecessarily. Because 

distribution pipelines provide a direct feed to customers, the use of in-pipe inspection 

tools usually requires natural gas service to customers to be interrupted for a period of 

time. 

Utility system customers play a unique role in identifying and reporting gas odors. 

At BG&E, our 610,000 customers serve as early alert systems, by monitoring for odors 

that may indicate an unsafe condition and promptly calling our call center. For these 

reasons, gas distribution utility systems are quite different from transmission systems. 

Federal regulations recognize the differences between these 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 pipelines and the rules 

distinguish between the two, while 49 CFR Part 195 sets out the regulations for liquid 

transmission lines. 

Regulatory Authority

As part of an agreement with the federal government, most state pipeline safety 

authorities have primary responsibility for natural gas utilities as well as intrastate 

pipeline companies. However, state governments have to adopt as minimum standards 

the federal safety standards promulgated by the U.S. Department of Transportation 

(DOT.) In exchange, DOT reimburses the state for up to 50% of its pipeline safety 

enforcement costs. Therefore, the actions of Congress affect state regulations and our 

companies. The states may also choose to adopt standards that are more stringent than 
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the federal ones, and many have done so. BG&E and many other distribution system 

operators are in close contact with state pipeline safety inspectors. As a result of these 

interactions, distribution facilities are subject to more frequent and closer inspections than 

what is required by the pipeline safety regulations. 

Natural Gas Utilities Are Committed to Safety

 Our commitment to safety extends beyond government oversight. Indeed, safety is 

our top priority -- a source of pride and a matter of corporate policy for every company. 

These policies are carried out in specific and unique ways. Each company employs 

safety professionals, provides on-going employee evaluation and safety training, 

conducts rigorous system inspections, testing, and maintenance, repair and replacement 

programs, distributes public safety information, and complies with a wide range of 

federal and state safety regulations and requirements. Individual company efforts are 

supplemented by collaborative activities in the safety committees of regional and national 

trade organizations, such as the American Gas Association, the American Public Gas 

Association and the Interstate Natural Gas Association of America.

 We continually refine our safety practices. Natural gas utilities spend an estimated 

$6.4 billion each year on safety-related activities. Approximately half of this money is 

spent in complying with federal and state regulations. The other half is spent for our 

companies’ voluntary commitment to ensure that our systems are safe and that the 

communities we serve are protected. 

Our industry’s commitment to safety is borne out each year through the federal 

Bureau of Transportation Statistics’ annual figures. Delivery of energy by pipeline is 

consistently the safest mode of energy transportation. Natural gas utilities are dedicated 

to continuing to improve on this record of safe and reliable delivery of natural gas to our 

customers. 

What Are The Facts About Gas Distribution Safety Incidents? 

As part of our commitment to safety, through the DOT pipeline statistic database gas 

utility trade associations monitor the number and causes of all reportable incidents on the 

nearly 2-million mile natural gas distribution system. An examination of DOT’s statistics 

tells a tale of two trends. 

A comparison of reportable incidents along the natural gas distribution system 

between 2001 and 2005 is depicted in the chart labeled Exhibit 1. The chart highlights 

the existence of two different types of incidents: those caused by factors the pipeline 

operator can directly control (such as improper welds, material defects, incorrect 

operation, corrosion or excavation damage by a utility contractor); and those caused by 

factors the pipeline has little or limited ability to control (such as excavation damage by a 

third party, earth movement, structure fires, floods, vandalism and lightning). 

The record shows that between 2001 and 2005, 82 percent of all reported incidents 

were the result of excavation damage by a third party or other factors the utility company 

had little or no control over. The number of incidents operators could possibly control 

remained a small portion of overall incidents. In addition, statistics show that it is 

incidents caused by factors beyond the control of pipeline operators that are on the 

increase, with more reported incidents every year except 2002. (The dip in 2002 is 

attributed to a slowdown in construction-related activities associated with the post-9/11 

downturn in the economy.) 

In many cases, the typical “little or no control” incident involves a local excavator 

who has decided to expedite an excavation project at the calculated risk of hitting a line. 

The excavator’s actions, while irresponsible and risky, generally lie outside the 

jurisdiction of PHMSA. Given that willful negligence is generally difficult to prove and 

despite efforts by PHMSA, pipeline operators and others to educate excavators about the 

need for safe digging practices, third party excavation damage remains the single largest 
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cause of incidents along the natural gas distribution system, accounting for almost half 

(48 percent) of incidents beyond the utility’s ability to control. Pipeline operators 

recognize the need to change this risky behavior in order to protect their lines and have 

used educational efforts to help raise awareness about the need for safe practices, but 

with a limited effect. 

As the data demonstrates, the most effective way to minimize safety incidents on our 

distribution lines is to make incidents caused by excavation damage an endangered 

species. Congress has long recognized that excavation damage to gas and hazardous 

liquid pipelines is a major safety concern. This was the major reason for passage of 

damage prevention legislation passed in 1999 with the Transportation Equity Act of the 

21st Century and in 2002 with the Pipeline Safety Improvement Act. These measures 

have made a substantial contribution toward decreasing the number of incidents; but 

more can be done, with your continued support.

How Can the Distribution Integrity Process Affect Pipeline Safety Reauthorization?

Since the passage of the 2002 Pipeline Safety Improvement Act, AGA and APGA 

member companies that also operate natural gas transmission pipelines have been 

resolutely implementing the requirements of the gas transmission integrity rule. It is a 

learning process for both operators and inspectors as together they proceed through the 

various steps of the implementation process. When PHMSA decided to promulgate the 

transmission rule, AGA and APGA stated that our members supported taking a 

responsible course of action in seeking to enhance transmission pipeline integrity. Our 

members continue to believe that such a course of action will yield safety benefits, as a 

result of the transmission integrity regulation. 

Last year, PHMSA embarked on a new initiative to develop a regulation governing 

distribution integrity management programs (DIMP). Again, AGA and APGA member 

companies have fully supported taking a responsible course of action in seeking to 

enhance distribution pipeline integrity. As a starting point for distribution system 

regulation, PHMSA has followed the directives of the DOT Inspector General and the 

findings of a joint federal, state, industry and public stakeholder group that met for one 

year. Those findings are presented in the report Integrity Management for Gas 

Distribution, Report of Phase 1 Investigations released in December of 2005. The DIMP 

stakeholder group found that to achieve distribution safety enhancements while ensuring 

continued reliable delivery of gas at an affordable cost to customers, a high-level flexible 

rule should be promulgated by PHMSA requiring each operator of a gas distribution 

system to develop and implement a formal integrity management plan that addresses key 

elements outlined by the DOT Inspector General. The group also found that this rule 

should be implemented in conjunction with a nationwide education program on 3-digit 

One-Call dialing, plus continuing R & D. 

First and foremost, the stakeholder group determined that the wide differences 

between gas distribution pipeline systems operated across the U.S. make it impractical 

simply to apply the integrity management requirements for gas transmission pipelines to 

distribution. The diversity among gas distribution pipeline operators also makes it 

impractical to establish prescriptive requirements that would be appropriate for all 

circumstances. Over half the distribution operators that will be affected by this rule are 

small entities – city owned utilities that serve fewer than one thousand customers and 

have revenues less than one million dollars per year. Thus, it is important that any rule 

not impose a one-size-fits-all approach. The DIMP stakeholder group found that it would 

be most appropriate to require that all distribution pipeline operators, regardless of size, 

implement an integrity management program that would contain seven key elements: 

 

1. Develop and implement a written integrity management plan. 

2. Know its infrastructure. 
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3. Identify threats, both existing and of potential future importance. 

4. Assess and prioritize risks. 

5. Identify and implement appropriate measures to mitigate risks. 

6. Measure performance, monitor results, and evaluate the effectiveness of its 

programs, making changes where needed. 

7. Periodically report performance measures to its regulator. 

These seven elements will be clarified by way of guidance being developed by a 

nationally recognized standards body to provide a basis for operator compliance and for 

regulator enforcement. The DIMP stakeholder group found that this guidance should 

also focus on ways of verifying the effectiveness of an operator’s leak management 

program as an essential element of a risk-based distribution integrity management 

approach. 

AGA and APGA are committed to working with all stakeholders with a goal of 

completing the distribution integrity management rule by PHMSA early next year. 

The DIMP stakeholder group also found that federally mandated installation of 

excess flow valves on service lines to customers is not appropriate under the distribution 

integrity regulation. State, industry and public members of the DIMP stakeholder group 

submitted formal comments to PHMSA recommending that operators who choose not to 

voluntarily install excess flow valves in all circumstances should instead develop a 

process whereby the installation of these valves for specific service lines is based on 

defined risk criteria. The members of this stakeholder group outlined decision criteria for 

installation of the valves, also concluding that, depending on the situation, there may be 

more effective methods for controlling the risk to a service line. 

AGA does not support federally mandated installation of excess flow valves; nor 

does such a mandate have the support of the majority of state safety regulatory agencies, 

many of which are satisfied that operators are installing them where they can prove to be 

effective. Indeed, the National Association of Utility Regulatory Commissioners 

(NARUC) and the National Association of Pipeline Safety Representatives (NAPSR) 

have passed resolutions to that effect. Many utilities already install these valves 

voluntarily, and the number is expected to grow. 

At the same time, over the past several years, AGA has facilitated forums with 

industry and regulators to ensure dissemination of the most up-to-date operational 

information about excess flow valves. We believe that operators now have the 

information needed to determine if these valves would be effective for their systems. 

Combined with the proposed risk-based criteria, the operator’s decision on whether to 

install the valves would have a sound technical basis to provide such protection where it 

is most appropriate. 

Excavation Damage – The Big Threat to Distribution Pipelines

With that, we turn again to excavation damage on natural gas distribution lines. As 

the distribution safety statistics have repeatedly shown, excavation damage represents the 

single greatest threat to distribution system safety, reliability and integrity. Although the 

nationwide education program on the three-digit One-Call dialing to prevent excavation 

damage, together with the DIMP rule, is a step in the right direction, the DIMP 

stakeholder group found that more is needed. 

Gas pipeline facility operators are required to have damage prevention programs 

under current DOT regulations. However, preventing excavation damage to gas pipelines 

is not completely under the control of such operators. Reducing this threat requires 

affecting the behavior of persons not subject to the jurisdiction of pipeline safety 

authorities (e.g. excavators working for entities other than pipeline facility 

owners/operators). Pipeline facility operators currently approach this through educational 

efforts. 
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Data from the last five years has demonstrated that states, such as Minnesota, 

Virginia, Georgia, Connecticut and Massachusetts have experienced a substantially lower 

rate of excavation damage to pipeline facilities than states that do not have stringent 

enforcement powers and/or programs. I have brought along a chart that compares the 

measurable results of effective programs in Virginia and Minnesota against the results in 

a state where the absence of some key processes precludes an effective program 

(Attachment 2). The lower rate of excavation damage translates directly to a 

substantially lower risk of serious incidents on gas and hazardous liquid pipelines and 

avoided consequences resulting from excavation damage to pipelines. 

The DIMP stakeholder group explored a variety of approaches to enhancing damage 

prevention programs. The group found that a comprehensive damage prevention 

program includes not only education but also effective enforcement. Currently, the U.S. 

Department of Justice is responsible for enforcing federal infrastructure damage 

prevention statutes on parties conducting excavations. However, and most unfortunately, 

the Department has rarely exercised such authority. 

Programs such as Virginia’s show that nine key elements must be present and 

functioning for the damage prevention program to be effective. The DIMP group 

concluded that federal legislation would be necessary to encourage such programs in all 

states. This should include providing additional funding for the states, apart from 

funding already being provided under the matching grants or One-Call programs. 

As quoted from the above-mentioned DIMP report, the nine elements a state 

program should have are as follows: 

(1) Effective communication between operators and excavators -- Provide for 

appropriate participation by operators, excavators, and other stakeholders in the 

development and implementation of methods for establishing and maintaining 

effective communications between stakeholders from receipt of an excavation 

notification until successful completion of the excavation, as appropriate. 

(2) Fostering support and partnership of stakeholders -- Have a process for 

fostering and ensuring the support and partnership of stakeholders including 

excavators, operators, locators, designers, and local government in all phases of 

the program. 

(3) Operator’s use of performance measures – Include a process for reviewing the 

adequacy of a pipeline operator’s internal performance measures regarding 

persons performing locating services and quality assurance programs. 

(4) Partnership in employee training – Provide for appropriate participation by 

operators, excavators, and other stakeholders in the development and 

implementation of effective employee training programs. This would ensure that 

operators, the one-call center, the enforcing agency and the excavators have 

partnered to design and implement training for employees of operators, 

excavators and locators. 

(5) Partnership in public education – Have a process for fostering and ensuring 

active participation by all stakeholders in public education for damage 

prevention activities. 

(6) Dispute resolution process – Feature a process for resolving disputes that 

defines the state authority’s role as a partner and facilitator to resolve issues. 

(7) Fair and consistent enforcement of the law -- Provide for the enforcement of its 

damage prevention laws and regulations for all aspects of the excavation process 

including public education. The enforcement program must include the use of 

civil penalties for violations found by the appropriate state authority. 

(8) Use of technology to improve all parts of the process – Include a process for 

fostering and promoting the use, by all appropriate stakeholders, of improving 

technologies that may enhance communications, locate capability, and 

performance tracking. 
117

(9) Analysis of data to continually evaluate/improve program effectiveness – 

Contain a process for review and analysis of the effectiveness of each program 

element, and for implementing improvements identified by such program 

reviews. 

AGA and APGA recommend that Congress enact legislation that modifies Title 49 

USC Subtitle VIII, Chapter 601, § 60105 - State pipeline safety program certifications, to 

insert a new section outlining the nine elements and providing for additional funding for 

implementation of the program. Such funding should be allocated directly to the State 

agency having oversight over pipeline safety. In addition to our own members as 

excavators, a variety of stakeholders will be affected by the proposed legislation, 

including in most states, entities presently not under the jurisdiction of state pipeline 

safety authorities. Accordingly, funding authority for the program should be sought from 

general revenues. 

Past experience has shown that, without legislation, PHMSA’s activities under its 

existing authority have had a limited effect, principally because many of the entities 

causing excavation damage were outside the agency’s jurisdiction. Moreover, without 

associated funding, a legislative mandate for an enhanced program -- be it at the federal 

level or at the state level -- would be equivalent to an unfunded mandate and have 

minimal effect on existing state programs. 

Finally, AGA and APGA support providing continued funding authority for grants to 

states to support One-Call programs and for partial funding of the Common Ground 

Alliance (CGA) damage prevention organization. The CGA has been instrumental in 

bringing to the forefront the need for excavation damage prevention as a shared 

responsibility among all locators, One-Call system operators, excavators and owners or 

operators of buried infrastructure facilities. Development and adoption of consensusbased best practices, education, and damage data collection are significant and 

worthwhile efforts under CGA sponsorship and should be continued. 

The statistics are clear. Excavation damage prevention presents the single greatest 

opportunity for distribution safety enhancements. 

Gas Transmission Integrity Reassessment Time Interval

The Interstate Natural Gas Association of America testimony today addresses the 7-

year reassessment interval required by the gas transmission integrity rule. In particular, 

gas company planning personnel view the overlap between the baseline assessments and 

the reassessments that must take place for a pipeline segment in year 7 after the baseline 

assessment as representing an unwarranted increase in workload and demand for services, 

with possible gas supply interruptions. This will affect interstate as well as intrastate 

transmission systems. AGA and APGA believe that a pipeline segment’s reassessment 

interval should be based on technical arguments. It is our hope that in evaluating the 

appropriateness of the 7-year requirement, the U.S. Government Accountability Office 

(GAO) will seek to uncover all of the facts and that, based on the GAO report, Congress 

would then consider options for allowing a change to the interval that would be consistent 

with GAO findings. This will allow operators to continue to deliver natural gas safely and 

affordably. 

Attachments: 

1) Comparison of Incidents 

2) States With Strong Prevention Programs 

3) The Nine Elements of an Effective Excavation Damage Program 

4) Path To Success 
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119
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MR. HALL. I thank you. 

 The Chair recognizes the Senior Vice President of Operations and 

Engineering for the Panhandle Energy, Mr. Mohn. And try to keep your 

remarks within about 5 minutes, if you can. Thank you. 

MR. MOHN. I will do it, Mr. Chairman. 

 Good afternoon. My name is Jeryl Mohn. I am testifying today on 

behalf of the Interstate Natural Gas Association of America, or INGAA. 

Our trade association represents virtually all of the major gas pipelines in 
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North America. My testimony today will highlight some successes in the 

safety of gas pipelines and also suggest further improvements. 

 When Congress passed the Pipeline Safety Improvement Act in 

2002, you set in motion one of the most significant regulatory 

improvement processes for pipeline safety since the original safety act of 

1968, namely integrity management that you have heard a lot about 

today. 

 In short, the 2002 Act requires that we assess and remediate defects 

in high-consequence areas. The act requires the 10-year baseline 

inspection, as noted previously, and requires a 7-year reassessment of all 

pipelines in high-consequence areas. PHMSA formalized their final 

regulations in 2003, and we have made considerable progress in 

implementing integrity management. Through 2005, we completed 

assessment on about 30 percent of our HCAs, and we are on track to 

complete all of the baseline by 2012, including the highest priority 50 

percent by the end of 2007. We are identifying defects and removing 

those from our pipelines before they become incidents. PHMSA began 

their audits last year, they are continuing this year, and we think they will 

validate the results that I have just commented on. 

 Next, I would like to give you a couple of thoughts on the matter 

before you, namely reauthorization. 

 We believe the existing law is effective and that only minor changes 

would further enhance pipeline safety. We do believe that it is in the 

best interest of all parties to complete the authorization in 2006 for 

something in the range of a 5-year period. 

 There are a couple of issues, however, I would like to mention, for 

your consideration. All of these are described further in my written 

testimony. 

 The first is something that you have heard quite a bit about before, 

namely the baseline overlap period. As we have heard before, the law 

requires that we establish a baseline condition of our pipelines within 10 

years, something that we will complete by 2012, assessing about 10 

percent of our pipelines a year. And then the law requires that once we 

have established that baseline, we begin to reassess on a 7-year 

frequency. The result, as you have heard, is that we will be required to 

double our efforts in the years 2010, 2011, and 2012. 

 While this interpretation of the law is understandable, we are not 

certain that that was the intent of Congress in 2002. We are further 

concerned that this doubling of the reassessment will have an impact on 

inspection resources. For inspection companies to suggest that they 

would ramp up for 3 years and double the amount of inspection services 

available and then go back down to that level in subsequent years is 

aggressive, from my perspective. Secondly, as you heard from your 
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GAO witness earlier, we are concerned that we may disrupt supply to our 

customers by doubling the inspection efforts during that 3-year period, 

and we urge you to consider fixing that overlap issue. 

 The second point is about the 7-year reassessment interval that I 

would like to make is really quite simple. As we know, GAO is 

examining the pluses and minuses, and I respect the need to await those 

results before you would make a firm judgment as to any change in that. 

I would offer you, though, just one observation, and that is this: 

reinspection is not new to our industry. At least two of our members 

began major assessments of their pipeline systems in the 1980s. One of 

those operators, who has over 8,100 miles of pipeline, has reassessed at 

least 80 percent of its pipeline twice during that period of time. Some of 

it they have reassessed at a more frequent basis, and others they have 

assessed on a less frequent basis, but on average, they are about 12 to 14 

years between the reassessment. Again, I appreciate and we respect the 

need to await GAO’s results, and we have tried to provide and will 

continue to work with GAO so that they have the benefit of that 

experience. 

 My last, and very important, recommendation is one that you have 

heard a lot about today, but it is an important element for high-pressure 

natural gas pipelines, and that is prevention of third-party damage. It is 

our leading cause of recent fatalities on our system, and we have, as an 

industry, been making continuous improvement for the last several years, 

as you have heard, and we would urge Congress to take a major step to 

help us crush those incidents going forward. You have just heard from 

my colleague from AGA as to the proposal that they would have, and we 

would urge you to consider those seriously. 

 To summarize quickly, from our perspective, the law is working, and 

we urge reauthorization in 2006 with only minor enhancements. 

 Thank you. 

 [The prepared statement of Jeryl L. Mohn follows:] 

PREPARED STATEMENT OF JERYL L. MOHN, SENIOR VICE PRESIDENT, OPERATIONS AND 

ENGINEERING, PANHANDLE ENERGY, ON BEHALF OF INTERSTATE NATURAL GAS 

ASSOCIATION OF AMERICA

Summary of Testimony 

INGAA appreciates the opportunity to testify on reauthorization of the Pipeline 

Safety Act. We want to provide the Subcommittee with some background on the natural 

gas pipeline industry and discuss the progress being made with the Integrity Management 

Program that was a part of the 2002 reauthorization. In general, INGAA believes the 

Integrity Management Program is working well in meeting the intent of Congress to 

reduce risks to the public. Our recommendations for legislation to reauthorize the Act in 

2006 include: 
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• Five-year reauthorization. 

• Re-examination of the seven-year reassessment interval that was part of the gas 

integrity management requirement in the 2002 legislation. We recommend a 

reassessment interval based on scientific and/or engineering criteria. At a 

minimum, the baseline assessment/reassessment overlap in years 2010 through 

2012 should be eliminated. 

• Incentives to further improve state damage prevention programs nationwide. 

• Amend the definition of “direct sales lateral” pipelines in the Pipeline Safety 

Act to make those owned by interstate pipelines jurisdictional to federal, rather 

than state, oversight. 

Mr. Chairman and Members of the Subcommittee: 

Good morning. My name is Jeryl Mohn, and I am Senior Vice President of 

Operations and Engineering for Panhandle 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 United States 

through a network of approximately 200,000 miles of transmission pipeline. These 

transmission pipelines are analogous to the interstate highway system – in other words, 

large capacity systems spanning multiple states or regions. 

Panhandle Energy, headquartered in Houston, Texas, is a subsidiary of the Southern 

Union Company and owns or holds a major ownership interest in five interstate pipelines 

and a liquefied natural gas import terminal. Our pipelines serve a significant share of the 

markets in the Midwest, the Southwest including California, and Florida. In addition, our 

Trunkline LNG terminal in Lake Charles, Louisiana is one of the nation’s largest LNG 

import facilities. 

INDUSTRY BACKGROUND 

Mr. Chairman, natural gas provides 25 percent of the energy consumed in the U.S. 

annually, second only to petroleum and exceeding that of coal or nuclear. From home 

heating and cooking, to industrial processes, to power generation, natural gas is a 

versatile and strategically important energy resource. 

As a result of the regulatory restructuring of the industry during the 1980s and early 

1990s, interstate natural gas pipelines no longer buy or sell natural gas. Interstate 

pipelines do not take title to the natural gas moving through our pipelines. Instead, 

pipeline companies sell transportation capacity in much the same way as a railroad, 

airline or trucking company. 

Because the natural gas pipeline network is essentially a “just-in-time” delivery 

system, with limited storage capacity, customers large and small depend on reliable 

around-the-clock service. That is an important reason why the safe and reliable operation 

of our pipeline systems is so important. The natural gas transmission pipelines operated 

by INGAA’s members and by others historically have been the safest mode of 

transportation in the United States. The interstate pipeline industry, working 

cooperatively with the Pipeline and Hazardous Materials Safety Administration 

(PHMSA), is taking affirmative steps to make this valuable infrastructure even safer. 

Congressional involvement in pipeline safety dates back almost 40 years to 

enactment of the Natural Gas Pipeline Safety Act in 1968. This legislation borrowed 

heavily from the engineering standards that had been developed over the previous 

decades. The goals of this federal legislation were to ensure the consistent use of best 

practices for pipeline safety practices across the entire industry, to encourage continual 

improvement in safety procedures and to verify compliance. While subsequent 

reauthorization bills have improved upon the original, the core objectives of the federal 

pipeline safety law have remained a constant. 
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HOW SAFE ARE NATURAL GAS PIPELINES

While the safety record of natural gas transmission lines is not perfect, it nonetheless 

compares very well to other modes of transportation. Since natural gas pipelines are 

buried and isolated from the public, pipeline accidents involving fatalities and injuries are 

unusual. 

In 2005 there were no fatalities and 5 injuries associated with our pipelines. During 

the period 2002 -2005, there were a total of two fatalities and 21 injuries. Both fatalities 

and nine of the injuries were attributable to excavation damage or vehicular crashes with 

pipeline facilities. The remainder of the injuries involved pipeline company 

repair/maintenance personnel. 

There are rare exceptions to the exceptional safety record of natural gas transmission 

pipelines. The accident that occurred near Carlsbad, New Mexico in 2000 resulted in the 

deaths of 12 family members who were camping on a remote pipeline right-of-way. That 

accident was the result of internal corrosion on a section of pipe that could not be 

inspected by internal inspection devices due to engineering constraints (more on that 

issue below). This has been the only gas transmission corrosion incident with fatalities 

since 1985, when PHMSA improved its record keeping system. 

Since 1984, the Department of Transportation has defined a “reportable incident” as 

one that results in a fatality, an injury, or property damage exceeding $50,000. Included 

in the determination of property damage, however, is damage to the pipeline itself and the 

monetary value of the natural gas lost. As most of you know, natural gas commodity 

prices have increased more than 300 percent in the last six years. This linkage of 

“reportable incidents” to natural gas commodity prices has resulted in heavily skewed 

data over the last several years. 

Internally, PHMSA has discussed a new “serious accident” incident category, which 

includes incidents with fatalities, injuries and fires. This category would rely less on the 

amount of natural gas lost to the air and would be, therefore, a more effective measure of 

safety performance. Another alternative would be a volumetric threshold for natural gas 

lost based on 2002 natural gas prices. If the 2005 incident data was normalized to 2002 

gas prices, for example, 60 fewer onshore incidents would have been reported. Either 

approach would provide more consistency in the reportable incident data and help focus 

industry and PHMSA efforts on the more serious issues of human safety. 

In terms of the causes of accidents on gas transmission pipelines, the table below 

shows that corrosion (internal and external) accounts for about one quarter of all 

incidents. This statistic is important, because the periodic inspection aspects of the 

Integrity Management Program discussed later are principally designed to reduce the risk 

of corrosion-related failures in highly populated areas. “Natural forces” was the second 

leading cause of damage, with the Gulf Hurricanes Ivan, Katrina and Rita accounting for 

most of these incidents. “Excavation damage,” which tends to be the leading cause of 

fatalities associated with natural gas transmission lines, is the third leading cause of 

incidents. The new PHMSA accident statistics separate excavation damage from “other 

outside force damage” – most of the incidents associated with this new category are the 

result of vehicular crashes with pipeline facilities. 
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Natural Gas Transmission Failure Causes 2002-2005 

THE PIPELINE SAFETY IMPROVEMENT ACT OF 2002 AND INTEGRITY 

MANAGEMENT

The most recent reauthorization bill – the Pipeline Safety Improvement Act of 2002 

(“PSIA”) – focused on a variety of issues, including operator qualification programs, 

public education, and population encroachment on pipeline rights-of-way. But the most 

significant provision of the 2002 law that will improve long-term pipeline safety dealt 

with the “Integrity Management Program” (“IMP”) for natural gas transmission 

pipelines. 

Section 14 of the PSIA requires operators of natural gas transmission pipelines to: 1) 

identify all the segments of their pipelines located in “high consequence areas” (areas 

adjacent to significant population); 2) develop an integrity management program to 

reduce the risks to the public in these high consequence areas; 3) undertake baseline 

integrity assessments (inspections) at all pipeline segments located in high consequence 

areas, to be completed within 10 years of enactment; 4) develop a process for making 

repairs to any anomalies found as a result of these inspections; and 5) reassess these 

segments of pipeline every 7 years thereafter, in order to verify continued pipe integrity. 

The PSIA requires that these integrity inspections be performed by one of the 

following methods: 1) an internal inspection device (or a “smart pig”); 2) hydrostatic 

pressure testing (filling the pipe up with water and pressurizing it well above operating 

pressures to verify a safety margin); 3) direct assessment (digging up and visually 

inspecting sections of pipe), or 4) “other alternative methods that the Secretary of 

Transportation determines would provide an equal or greater level of safety.” The 

pipeline operator is then required by regulations implementing the 2002 law to repair all 

non-innocuous imperfections and adjust operation and maintenance practices to minimize 

“reportable incidents”. For natural gas transmission pipelines, internal inspection devices 

are the primary means of integrity assessments, due to the fact that, when they can be 

used, they are more versatile and efficient. Other assessment alternatives listed in the 

legislation are useful in cases where smart pig technology cannot be effectively used. A 

drawback associated with such alternatives is that they require a pipeline to cease or 

significantly curtail gas delivery operations for periods of time. 

In-line internal inspection “smart pig” devices were invented by the natural gas 

pipeline industry several decades ago, and over the years their capabilities and 

effectiveness as analytical tools have increased. Still, the pipeline industry must address 

some practical issues our industry must deal with in order to utilize these devices more 

fully. 

First, our older pipelines were not engineered to accept such inspection devices. 

This means that older pipelines were often built with tight pipe bends, non-full pipe 
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diameter valves, continuous sections of pipe with varying diameters, and side lateral 

piping. In all of these circumstances, the movement of natural gas is not impeded 

because of its relative compressibility. Moving a solid object through such pipelines is 

another matter, however. These older pipeline systems must be modified to allow the use 

of internal inspection devices. 

The other legacy issue is the modification of pipelines to launch and receive internal 

inspection devices. Since a pipeline is buried underground for virtually its entire length, 

the installation of aboveground pig launchers and receivers is usually done at or near 

other above ground locations such as compressor stations. Occasionally, however, new 

sites must be obtained for these facilities. Compressor stations are typically located along 

the pipeline at a spacing of 75 to 100 miles apart. Therefore, for every segment, another 

set of launchers and receivers needs to be installed. Once installed, these launchers and 

receivers can usually remain in place permanently. 

Surveys conducted by our industry about five years ago suggested that almost onethird of transmission pipeline mileage could immediately accommodate smart pigs, 

another one-quarter could accommodate smart pigs with the addition of permanent or 

temporary launching and receiving facilities, and the remainder, about 40-45 percent, 

would either require extensive modifications or never be able to accommodate smart pigs 

due to the physical or operational characteristics of the pipeline. Scheduling these 

extensive modifications to minimize consumer delivery impacts has been one of the most 

challenging aspects of the Integrity Management Program. 

The natural gas pipeline industry will use hydrostatic pressure testing and direct 

assessment for segments of transmission pipeline that cannot be modified to 

accommodate smart pigs, or in other special circumstances. There are issues worth 

noting with both hydrostatic testing and direct assessment. In the case of hydrostatic 

testing, an entire section of pipeline must be taken out of service for an extended period 

of time, limiting the ability to deliver gas to downstream customers and potentially 

causing market disruptions as a result. In addition, hydrostatic testing – filling a pipeline 

up with water at great pressure to see if the pipe fails – is a destructive or “go – no go” 

testing method that must take into account pipeline characteristics so that it does not 

exacerbate some conditions while resolving others. Also, because of this “go – no go” 

nature, testing must continue until the segment successfully completes the test, generally 

8 hours at pressure, with no leaks or failures. 

Direct assessment is generally defined as an inspection method whereby statistically 

chosen sections of pipe are excavated and visually inspected at certain distance intervals 

along the pipeline right-of-way based on sophisticated above ground electrical survey 

measurements that predict problem areas. The amount of excavation and subsequent 

disturbance of landowner’s property involved with this technology is significant and does 

not decrease with future reassessments. Disturbing other infrastructures, including roads 

and other utilities, is also a significant risk and inconvenience for the public. 

One final note. While the pipeline modifications and inspection activity can 

generally follow a pre-arranged schedule, repair work is an unpredictable factor. A 

pipeline operator does not know, ahead of time, how many anomalies an inspection will 

find, how severe such anomalies will be, and how quickly they will need to be repaired. 

Only the completed inspection data can provide that information. Repair work often 

requires systems to be shut down, even if the original inspection work did not affect 

system operations. The unpredictable nature of repair work must be kept in mind, 

especially during the baseline inspection period, when we can expect the number of 

required repairs to be the greatest. 

INTEGRITY MANAGEMENT PROGRESS TO DATE

The integrity management program mandated by the PSIA is performing very well. 

The program is doing what Congress intended; that is, verifying the safety of gas 
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transmission pipelines located in populated areas and identifying and removing potential 

problems before they occur. Based on two years of data, the trend is that our pipelines 

are safe and are becoming safer. 

PHMSA immediately initiated a rulemaking to implement the gas integrity 

requirements upon enactment of PSIA in December of 2002. The Administration 

successfully met the one-year deadline set by the law for issuing a final IMP rule. 

Therefore, 2004 was the first full year of what will end up being a nine-year baseline 

testing period (the statute mandates that baseline tests on all pipeline segments in high 

consequence areas must be completed by December of 2012). PHMSA’s final rule 

credits pipeline companies for some integrity assessments completed before the rule took 

effect, thereby mitigating the effects of the shorter baseline period. 

PHMSA has reported on progress achieved thus far: 

1. Total Gas Transmission Mileage in the United States – There are 295,665 miles 

of gas transmission pipeline in the U.S. INGAA’s members own 

approximately 200,000 miles of this total, with the remainder being owned by 

intrastate transmission systems or local distribution companies. 

2. Total High Consequence Area (HCA) Mileage – There are 20,191 miles of 

pipeline in HCAs (i.e., mileage subject to gas integrity rule). This represents 

about 7 percent of total mileage. 

3. HCA Pipeline Miles Inspected to Date – 

• 2004 – 3,979 miles (incorporated some prior inspections before rule took 

effect). 

• 2005 – 2,744 miles 

• Therefore, 6,723 miles of HCA pipeline inspected to date, or 33 percent of 

total. 

4. Total Pipeline Miles Inspected (including non-HCA pipeline) – 

• 2004 – 30,452 miles (7.65 to 1 over-test ratio) 

• 2005 – 19,884 miles (7.24 to 1 over-test ratio) 

• Therefore, 50,366 total miles, or approximately 17 percent of total 

transmission pipeline mileage. 

The total HCA pipeline mileage inspected to date suggests that the industry is 

generally on track with respect to meeting the 10-year baseline requirement. With three 

years of the baseline period completed at the end of 2005, about 30 percent of the HCA 

mileage had been inspected. This translates into 10 percent being completed annually – 

exactly the volume of work needed in order to meet the baseline requirement. 

The 2002 law also required a risk-based prioritization of these HCA assessments, so 

that the higher-ranking HCA pipeline segments would be scheduled for assessment 

within five years of enactment. This means that by December of 2007 we must have 

completed at least half of the total HCA assessments, by mileage, and that work contains 

the segments with the highest probability of failure. Again, we appear to be on track for 

meeting this requirement. 

The mileage counted as being assessed in 2004 is higher than what we anticipate 

will be the average annual mileage going forward, because we were able to include some 

HCA segments that had been inspected in the few years immediately prior to the rule 

taking effect. As mentioned, this helped to jump-start the program and make up for the 

fact that the final IMP rule did not take effect until December of 2003, thus reducing the 

de facto baseline period to nine years. 

The vast majority of the assessments to date have been completed using smart pig 

devices. As discussed, these devices can only operate across large segments of pipeline – 

typically between two compressor stations. A 100 mile segment of pipeline may, for 

example, only contain 5 miles of HCA, but in order to assess that 5 miles of HCA, the 
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entire 100 mile segment between compressor stations must be assessed. This dynamic is 

resulting in a large amount of “over-testing” on our systems. While we have completed 

assessments on 6,723 miles of HCA pipe thus far, the industry has actually inspected 

about 50,366 miles of pipe in order to capture the HCA segments. Any problems that are 

identified as a result of inspections, whether in an HCA or not, are repaired. 

As you can see from the data, only about 7 percent of total gas transmission pipeline 

mileage is located in HCAs. Yet, due to the over-testing situation, we anticipate that 

about 55 to 60 percent of total transmission mileage will actually be inspected during the 

baseline period. 

Now let us look at what the integrity inspections have found to date. For this data, 

we focus on information from HCA segments, since these segments are the only ones 

specifically covered under the integrity management program. 

1. Reportable Incidents in HCAs (in 20,191 miles) 

• 2004 – 9 (2 time-dependent) 

• 2005 – 10 (0 time-dependent) 

2. Leaks (too small to be classified as a reportable incident) in HCAs (in 20,191 

miles) 

• 2004 – 117 (29 time-dependent) 

• 2005 – 104 (20 time-dependent) 

3. Immediate Repairs in HCAs Found by Inspections (repair within 5 days) 

• 2004 – 101 (3,979 miles inspected) 

• 2005 – 237 (2,744 miles inspected) 

4. Scheduled Repairs in HCAs Found by Inspections (repair generally within 1 

year) 

• 2004 – 595 (3,979 miles inspected) 

• 2005 – 403 (2,744 miles inspected) 

In the data for incidents and leaks, we separate out the time-dependent defects, since 

these are the types of defects that are the prime target of reassessment under the integrity 

management program. By time-dependent, we mean problems with the pipeline that 

develop and grow over time, and, therefore, should be examined on a periodic time basis. 

The most prevalent time-dependent defect is corrosion; therefore, the IMP effort is 

focused most intently on corrosion identification and mitigation. These same 

assessments might also be able to identify other pipeline defects such as original 

construction defects or excavation damage. Original construction defects are usually 

found and addressed during post-construction inspections; any construction defects found 

with this new, more sensitive inspection technology would be fixed “for good” so that 

future assessments looking for these types of anomalies will be unnecessary. Most 

reportable incidents caused by excavation damage (more than 85 percent) result in an 

immediate pipeline failure, so periodic assessments are not likely to reduce the number of 

these types of accidents in any significant way. Periodic assessments on a fixed schedule 

are, therefore, most effective for time-dependent defects. 

You can see that the number of incidents associated with time-dependent defects in 

HCA areas is fairly low and that these reportable incidents (e.g. 1 reportable incident per 

year average) have occurred in HCA areas not yet assessed under this program. As 

critical time dependent defects are found and repaired, we expect these incident and leak 

numbers to approach zero, since the gestation period for these defects is significantly 

longer than the re-assessment interval. 

As for repairs, we have identified the number of “immediate” and “scheduled” 

repairs that have been generated by the IMP inspections thus far. These are anomalies in 

pipelines that have not resulted in a reportable incident or leak, but are repaired as a 
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precautionary measure. “Immediate repairs” and “scheduled repairs” are defined terms 

under both PHMSA regulations and engineering standards. As the name suggests, 

immediate repairs require immediate action by the operator, due to the higher probability 

of a reportable incident or leak in the future. Scheduled repair situations are those that 

require repair within a longer time period because of their lower probability of failure. 

Even though we are early in the baseline assessment period, the data suggests a very 

positive conclusion regarding present state of the gas transmission pipeline system and 

the effectiveness of integrity management programs. “Immediate repairs” in HCAs 

removed 50 anomalies for every 1000 pipeline miles inspected. The number of 

“scheduled repairs” removed an additional 140 anomalies per 1000 miles inspected. By 

completing these immediate and scheduled repairs in a timely fashion, we are reducing 

the possibility of future reportable incidents or leaks. Also, data from operators who have 

completed more than one such periodic assessment over a number of years strongly 

suggests a dramatic decrease in the occurrence of time-dependent defects requiring 

repairs the second time around. 

Many of the gas pipelines being inspected under this program are 50 to 60 years old. 

While is it often hard for non-engineers to accept, well-maintained pipelines can operate 

safely for many decades. Policymakers often compare pipelines to vehicles and ask 

questions such as: “Would you fly in a 50-year-old airplane?” The comparison to aircraft 

or automobiles is an unsound one, though, from an engineering standpoint. Natural gas 

pipelines are built to be robust and are not subject to the same operational stresses as 

vehicles. Much of the above inspection data comes from pipelines that were built in the 

1940s and 1950s. And yet, the number of anomalies found on a per-mile basis is low. 

Once these anomalies are repaired, the “clock can be reset,” and these pipelines can 

operate safely and reliably for many additional decades. One important benefit of the 

integrity management program is the verification and re-certification of the safety on 

these older pipeline systems. 

ISSUES FOR THE 2006 REAUTHORIZATION 

The 2002 Act authorized the federal pipeline safety program at the Department of 

Transportation through fiscal year 2006. Although the Congressional schedule for the 

rest of 2006 is short, the current program is working very effectively and therefore needs 

only modest changes. We therefore see no reason why Congress cannot reach consensus 

and complete a reauthorization bill this year. INGAA also urges the Congress to pass a 

five-year reauthorization bill that would take the next reauthorization outside the short 

legislative calendar that occurs in an election year. 

INGAA would like the Subcommittee to consider amendments addressing three 

issues in the pipeline safety law. Each of these would achieve an evolutionary change in 

the current pipeline safety program: 1) re-consideration of the seven-year reassessment 

interval, to one based instead upon a more reasoned approach; 2) improvements in state 

excavation damage prevention programs; and 3) change in the jurisdictional status for 

direct sales lateral lines. 

Seven-Year Reassessment Interval 

Under the PSIA, gas transmission pipeline operators have 10 years in which to 

conduct baseline integrity assessments on all pipeline segments located in high 

consequence areas (HCAs). Operators are also required by law to begin reassessing 

previously-inspected pipe seven years after the initial baseline and every seven years 

thereafter. PHMSA has interpreted these two requirements to mean that, for those 

segments baseline-inspected in 2003 through 2005 (including those for which a prior 

assessment is relied upon), reassessments must be done in years 2010 through 2012 – 

even though baseline inspections are still being conducted. 
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In 2001 INGAA provided Congress with a proposed industry consensus standard on 

reassessment intervals that had been developed by the American Society of Mechanical 

Engineers (ASME). The ASME standard used several criteria to determine a 

reassessment interval for a particular segment of pipe, such as the operating pressure of a 

pipe relative to its strength and the type of inspection technique used. This standard 

relied upon authoritative technical analyses and a “decision matrix” based on more than 

50 years of operational and performance data for gas pipelines. 

For most natural gas transmission pipelines (operating at high pressures), the ASME 

standard proposed a conservative ten-year reassessment interval. The standard suggested 

longer inspection intervals for lower pressure lines, a small number of pipelines that are 

lower in risk due to their lower operating pressures. The standard also suggested shorter

intervals for pipeline segments operating in higher-risk environments, including those 

where unusually aggressive corrosion would be more likely to occur. Recent and past 

pipeline inspection data confirms that the ASME criteria are conservative. 

Why are we so concerned about the seven-year reassessment interval? First, there is 

the “overlap” in years 2010 through 2012. The ability to meet the required volume of 

inspections is daunting given the limited number of inspection contractors and equipment 

available. In addition, this stepped up level of inspection activity would be difficult to 

accommodate without affecting gas system deliverability. This last point is critical. 

Some assume that we are focusing on the re-assessment interval only because of the costs 

to industry. In fact, our costs will be modest compared to the potential costs to 

consumers in the form of higher natural gas commodity prices if pipeline capacity 

becomes too constrained. Some regions of the country can handle more frequent 

reductions in pipeline deliverability, due to the volume of pipeline capacity serving those 

regions. The Chicago region and the Gulf Coast, for example, are equipped to handle 

frequent pipeline capacity interruptions due to the abundance of pipeline capacity in those 

regions. Other regions, such as the Northeast and Southern California, face greater risk 

that gas commodity prices will spike if pipeline capacity is reduced too often. These 

downstream market effects should be carefully considered, especially during the baseline 

inspection period when pipeline modifications (to accommodate inspection equipment), 

inspections, and repair work will all be at peak levels. 

Some also suggest that if the pipeline industry is technically capable of inspecting its 

lines for corrosion more frequently than engineering standards suggest, then it should do 

so and not worry about the costs or the logistics. It is certainly true that large interstate 

pipelines could, in fact, be inspected more frequently than every seven years, especially 

once systems have been modified to accommodate smart pig devices. But just because 

pipelines can be inspected more often does not mean it is rational to require a one-sizefits-all inspection policy. Most automobile manufacturers recommend vehicle oil 

changes every 3000 miles. Congress could instead mandate that all vehicles have oil 

changes every 1000 miles, but, of course, there would be little, if any, additional benefit 

to the more frequent oil changes, and the costs associated with the more frequent oil 

changes would take money away from other, more beneficial maintenance activities. 

The Integrity Management Program asks us to identify and mitigate risks to the 

public associated with operating our pipelines. Inspections are but one tool to achieve 

that end, and they do not accomplish all of the required goals of the program. The 

inspections carried out pursuant to the Integrity Management Program focus primarily on 

one cause of pipeline accidents – corrosion. Corrosion causes about 25 percent of the 

failures on gas transmission lines. What about the other 75 percent of accidents? What 

can be done to mitigate the risks of those? A credible and effective integrity management 

program prioritizes risks and develops strategies for addressing all risks. A program that 

mandates system-wide inspections too frequently can seriously affect an operator’s 

ability to perform even more frequent inspections at the very few locations that may 
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warrant shorter timeframes and may detract from other important integrity activities such 

as damage prevention. 

We recognize that some lawmakers may be hesitant to change to the seven-year 

reassessment interval given the heated debate on this issue in 2002. This is especially 

true given that the Integrity Management Program is relatively new and that GAO has not 

finalized its final report. We still urge the Congress to address the reassessment issue in 

this reauthorization bill, particularly the inspection overlap. The inspection overlap issue 

will manifest itself within the next four years; in other words, during the next 

reauthorization period. Our industry has worked in good faith to make the IMP program 

work and to improve pipeline safety overall. We want this safety initiative to work, but 

we also want to continue doing our collective job to deliver natural gas supplies reliably 

across the country when those supplies are needed. INGAA has provided the GAO with 

data that clearly shows there would be no compromise of safety either by lengthening the 

seven-year interval or by eliminating the baseline-reassessment overlap. 

Damage Prevention 

In 1998, the TEA21 highway legislation included a relatively modest program called 

the “One-Call Notification Act.” The goal of this legislation was to improve the quality 

and effectiveness of state one-call (or “call-before-you-dig”) damage prevention 

programs. By developing federal minimum standards and then giving grants to those 

states that adopted the minimum standards, this law contributed to improving damage 

prevention efforts all across the nation. And it did so without mandating that states adopt 

the federal minimum standards. 

Over the last eight years, there has been a great deal of improvement in damage 

prevention. INGAA believes that the time has come to take these efforts to the next 

level. Excavation damage prevention has been, and should remain, a major focus for 

pipeline safety. On our gas transmission pipelines, accidental damage from excavation 

equipment is the leading cause of fatalities and injuries. The majority of incidents that 

have raised public and Congressional concern have been due to excavation damage. 

These accidents are the most preventable of all, and better communication between 

pipeline companies and excavators is the key to such accident prevention. Despite all the 

progress that has been made since 1998, some excavators still do not call before they dig. 

One state, in particular, has developed an outstanding damage prevention program 

based on improved communication, information management, and performance 

monitoring. That state is Virginia. Not only does Virginia require broad participation by 

all utilities and excavators, but also it has effective public education programs and 

effective enforcement of its rules. We believe that enforcement is the most important 

element to improving state programs beyond the progress already made, and we believe 

Virginia offers a model for other states to adopt. Statistics demonstrate the success of the 

Virginia program – the state has experienced a 50 percent decrease in the excavation 

damage since implementing its program. 

For 2006 we ask the Congress to emphasize once again the importance of 

excavation damage prevention by including a new program of incentives for state action. 

A modest amount of grant funds could go a long way in reducing accidents. INGAA 

would like to work with the American Gas Association and the Common Ground 

Alliance in proposing legislative language on this issue in the next few weeks. 

Safety Regulation of Direct Sales Laterals 

One of the goals of the original Pipeline Safety Act enacted in 1968 was to establish 

a clear line of demarcation between federal and state authority to enforce pipeline safety 

regulations. Prior to 1968, many states had established their own safety requirements for 

interstate natural gas pipelines, and there was no particular consistency in such 

regulations across the states. This created compliance problems for interstate pipeline 
133

operators whose facilities crossed multiple states. The Pipeline Safety Act resolved this 

conflict by investing the U.S. Department of Transportation with exclusive jurisdiction 

over interstate pipeline safety while delegating to the states authority to regulate intrastate 

pipeline systems (generally, pipelines whose facilities are wholly within a single state). 

The statutory definition of an “interstate gas pipeline facility” subject to federal 

regulation was clarified further when the Congress reauthorized the Pipeline Safety Act 

in 1976 (P.L. 94-477). As part of this clarification, the Congress stated that “direct sales” 

lateral pipelines were not subject to federal jurisdiction. Direct sales laterals are typically 

smaller-diameter pipelines that connect a large-diameter interstate transmission pipeline 

to a single, large end-use customer, such as a power plant or a factory. Such direct sales 

laterals often are owned and maintained by the interstate transmission pipeline operator to 

which they are connected. 

This clarification was made necessary by a 1972 U.S. Supreme Court decision 

(Federal Power Commission v. Louisiana Power and Light, 406 U.S. 621) in which the 

Court ruled that for purposes of economic regulation (i.e., rate regulation), direct sales 

laterals were subject to preemptive federal jurisdiction. This ruling created uncertainty 

regarding the authority to regulate the safety of direct sales laterals because when the 

Pipeline Safety Act was enacted in 1968, it was assumed by the Congress that such 

pipelines would be subject to both economic and safety regulation at the state level. 

While this exemption from federal jurisdiction may have made sense 30 years ago, it 

now is an anachronism. As mentioned, many of these direct sales laterals are owned and 

operated by interstate pipelines. The natural gas transported in such lines travels in 

interstate commerce, and the lateral lines are extensions of the interstate pipelines to 

which they are interconnected. 

In addition, interstate natural gas pipelines are now subject to the PHMSA’s Gas 

Integrity Management Program and are required to undergo a specific regimen of 

Congressionally mandated inspections and safety verification. State-regulated pipelines 

are not covered under the federal program. Instead, states are allowed to create their own 

safety programs, which may have different processes/procedures covered than the federal 

integrity management program. Given the comprehensive federal program, there is no 

particular reason for small segments of the interstate pipeline system to be subject to 

differing and potentially inconsistent regulation at the state level. The inefficiency of this 

approach is further compounded by the fact that an interstate pipeline operator with direct 

sales laterals in multiple states likely will be subject to inconsistent regulation across the 

states. It is therefore understandable that interstate pipelines wish to have their direct 

sales laterals subject to the same federal integrity management requirements as mainline 

facilities. This would ensure a consistent and rational approach to integrity management 

system-wide, in contrast to being compelled to exclude parts of the pipeline network on 

the basis of an outdated set of definitions. 

INGAA supports amending the definitions of “interstate gas pipeline facilities” and 

“intrastate gas pipeline facilities” in the Pipeline Safety Act to eliminate the jurisdictional 

distinction between direct sales laterals and other segments of an operator’s interstate 

natural gas pipeline system. This would make such segments of pipeline subject to 

federal safety regulation consistent with the approach taken for the economic regulation 

of such pipeline facilities. 

Direct sales laterals that are not owned by an interstate pipeline would still be 

regulated by states. This amendment also would have the benefit of permitting the states 

to concentrate their resources on developing and enforcing integrity management 

programs for their natural gas distribution lines. 

CONCLUSION 

Mr. Chairman, thank you once again for inviting me to participate in today’s 

hearing. INGAA has made the reauthorization of the Pipeline Safety Act a top legislative 
134

priority for 2006, and we want to work with you and the Subcommittee to move a bill 

forward as soon as possible. Please let us know if you have any additional questions, or 

need additional information. 

 MR. HALL. Thank you. That is exactly 5 minutes. Good. 

 Next the President and CEO of Explorer Pipeline Company, Mr. 

Felt, we recognize you for 5 minutes. 

MR. FELT. Thank you, Mr. Chairman. 

 MR. HALL. And let me say this before you start. Don’t be dismayed 

by the empty chairs here. It is an unusual day, and they have just called 

an emergency meeting of most of the Republicans for some upcoming 

legislation. That is where they are, but your testimony is being taken 

down. It will go to every member of this committee and every Member 

of Congress, and it will be read by everybody. So you are not testifying 

just to two guys here. You have the main ones with me, the legislative 

aides that are in attendance here. So thank you. And your time is 

valuable, and you are very valuable people, and we look to you to give us 

guidance on how to write the legislation that you need and the things that 

you need and that the country needs. And I thank you again for your 

time, but I am a little embarrassed that you don’t have more people to 

talk to, but you are really talking to the Congress. 

 MR. FELT. Thank you, sir. 

 Mr. Chairman and members of the subcommittee, my name is Tim 

Felt. I am President and CEO of Explorer Pipeline Company 

headquartered in Tulsa, Oklahoma. We operate 1,400 miles of 

petroleum products pipeline serving 16 States extending from the Gulf 

Coast throughout the midwestern United States. 

 I am part of the leadership of the pipeline segment of the API, a 

member of the Association of Oil Pipelines, and the oil pipeline 

industry’s board member on the Common Ground Alliance. 

 I appreciate the opportunity to appear today on behalf of API and 

AOPL. Together, API and AOPL represent the vast majority of U.S. oil 

pipeline transportation companies. 

 Mr. Chairman, I will summarize my written testimony, which has 

been submitted for the record. 

 It has been over 3 years since the enactment of the Pipeline Safety 

Improvement Act of 2002. On behalf of our members, I wish to thank 

you for your leadership in passing a comprehensive and very important 

legislation. 

 As the subcommittee reviews the current state of pipeline safety and 

the progress that has been made since the 2002 Act, these are the main 

points I would like to emphasize. 

 The Pipeline Safety Improvement Act of 2002 is a success. Industry 

and DOT have cooperated to achieve significant improvement in pipeline 
135

safety, and this improvement is demonstrated by our industry’s record. 

This record is reflected on the charts that accompany my testimony. The 

oil pipeline industry is making the investments that are required to fully 

comply with the law, and in many cases, to exceed its requirements. In 

the liquid industry, plants invest over $1 billion in pipeline safety 

improvements over the next 5 years. 

 Finally, it is very important that Congress reauthorize the DOT 

pipeline safety program in 2006 to send a clear signal that these 

investments are appropriate and the DOT is on the right track to 

implementing the 2002 Act. A 5-year reauthorization would provide that 

needed certainty. 

 About 40 percent of the total U.S. energy supply comes from 

petroleum, but the transportation sector depends on petroleum for 96 

percent of its energy. Two-thirds of domestic crude oil and refined 

products transportation is provided by pipeline. Pipelines do this safely 

and efficiently. The cost to transport a gallon of petroleum by pipeline is 

very low, typically 2 to 3 cents per gallon. 

 Oil pipelines are common carriers whose rates are controlled by the 

Federal Energy Regulatory Commission. Oil pipeline income is driven 

only by the volume transported and does not depend on the price of the 

products transported. In fact, high oil prices have a negative impact on 

the oil pipeline income by raising power costs and reducing demand for 

petroleum. 

 Oil pipeline operators have been subject to DOT’s pipeline integrity 

management regulations since March 2001, before enactment of the 2002 

Act. Initially, DOT estimated approximately 22 percent of the pipeline 

segments in the national oil pipeline network would be assessed and 

provided enhanced protection. However, DOT’s inspections of 

operators’ plans show that integrity testing will eventually cover 

approximately 82 percent of the Nation’s oil pipeline infrastructure, 

almost four times the original estimate. 

 Large oil pipeline operators, those with over 500 miles of pipeline, 

completed the required 50 percent of their baseline testing of the highestrisk segments prior to the September 30, 2004, deadline set by the 

regulations. 

 DOT has audited each of these operators under these regulations at 

least two times, an initial quick-hit audit and one subsequent full audit. 

Although operating under a different deadline, the same program has 

been followed by the smaller operators. 

 Operators are repairing conditions in need of repair and less serious 

conditions that are found in the course of investigating defects. 

Operators are fixing what they find, often going beyond the requirement 

of the law. 
136

 As a result of this program, the oil pipeline spill record has improved 

dramatically in the last 5 years, as the exhibits show. The data for these 

exhibits come from a voluntary industry program that, since 1999, has 

collected data on oil pipeline performance. These figures represent 

pipeline releases, which are those that occur outside a pipeline 

company’s facilities and are the releases most likely to impact the public. 

For each cause category, the trend is down. The number of total releases 

has dropped 51 percent. Releases due to corrosion have dropped 67 

percent. Releases due to operator error have dropped by 63 percent. 

Finally, releases from third-party damage from excavation have dropped 

37 percent. 

 The safety improvement has been dramatic even though the data 

only covers half of the 7-year baseline assessment period for oil 

pipelines. We expect this trend to continue as we complete the full cycle 

and begin reassessment intervals. This provides a clear indication that 

the program is working, and we can make this good program even better. 

Releases caused by excavation damage are the largest, most traumatic, 

and the most likely to threaten the public and the environment. 

 We believe new legislation is appropriate to strengthen the 

underground damage prevention. Recently DOT has discussed 

strengthening Federal enforcement authority when excavating is 

undertaken without using the available one-call system. DOT has also 

discussed raising the ceiling on Federal funding for States whose damage 

prevention programs meet certain standards set forth in statute. We 

would support these changes in law to foster more effective underground 

damage prevention. Regulation of oil pipelines operating at low stress 

has received attention in the aftermath of a recent leak from a low-stress 

line on the north slope of Alaska. 

 While the pipeline industry is developing a proposal for low-stress 

pipelines that we will submit to DOT, we will support risk-based 

regulation of these low-stress pipelines that pose a significant threat to 

high-consequence areas. DOT can put such a program in place using 

existing elements in its successful integrity management regulations. 

Existing legislative authority is adequate to accomplish this. 

 Finally, you should be aware of the fine job that PHMSA did in 

assisting pipeline operators in the aftermath of the hurricanes in 2005. 

They are familiar with their operations and readily served as a resource 

in answering questions, securing permits, and advising us of important 

contacts and interim requirements. They also helped us locate temporary 

power-generating equipment, and served as a voice to others in the 

Government. This helped us restore service and therefore product was 

supplied to areas served by Gulf Coast refineries. 
137

 In summary, current pipeline safety law is working and working very 

well. Improvements can be made, particularly in strengthening 

underground damage prevention, but fundamental changes are not 

needed. Rather, consistency and predictability are important as oil 

pipeline operators claim continued investments for safety and reliability. 

We need Congress to act now to reaffirm the course set in 2002 by 

reauthorizing the program for 5 more years. 

 This concludes my remarks. I would be happy to answer questions. 

 [The prepared statement of Timothy C. Felt follows:] 

PREPARED STATEMENT OF TIMOTHY C. FELT, PRESIDENT AND CEO, EXPLORER PIPELINE 

COMPANY, ON BEHALF OF ASSOCIATION OF OIL PIPE LINES

The objectives of this testimony are: 

• The Pipe Line Safety Improvement Act of 2002 is a success. Industry and DO have 

cooperated to achieve significant improvement in pipeline safety, and this 

improvement is demonstrated by our industry’s record. 

• The oil pipeline industry is making the investments that are required to produce this 

improved performance. We are on track to spend over $1 billion on pipeline safety 

over the next five years. 

• It is very important that Congress reauthorize the DOT pipeline safety program in 

2006 to send a clear signal that these investments are appropriate and DOT is on the 

right track in implementing the 2002 Act. 

• Improvements in DOT’s authority to promote underground damage prevention are 

appropriate, but there is no urgent need for fundamental changes in the pipeline 

safety statures at this time. What is needed is vigorous implementation of the 2002 

Act, and that is happening. 

Improved Spill Record – Oil pipeline operators have been subject to the DOT’s pipeline 

integrity management regulations since March 2001. As a result of this program, the oil 

pipeline spill record has improved dramatically in the last five yeas. The number of total 

releases has dropped 51 percent and each cause category is down. (See attached charts). 

We expect this trend to continue as we complete the remaining 50% of the required 

baseline inspections. This provides clear evidence the program is working. 

Damage Prevention – Releases caused by excavation damage tend to be more traumatic, 

larger and more likely to threaten the public and the environment in comparison to other 

causes. We believe new legislation may be appropriate to strengthen underground 

damage prevention. We would support changes in law to encourage states to adopt more 

effective underground damage prevention programs like the ones in Virginia and 

Minnesota. 

Low Stress Pipelines – Regulation of oil pipelines operating at low stress levels has 

received attention in the aftermath of BP’s recent leak on the Alaska North Slope. The 

oil pipeline industry expects to make proposal to DOT to use existing law to bring low 

stress oil pipelines that could affect high consequence area into a proactive spill 

prevention program using elements of DOT’s successful integrity management 

regulations. Existing legislative authority is adequate to accomplish this. 
138

Introduction

I am Tim Felt, President and CEO of Explorer Pipeline. I am here to speak on 

behalf of AOPL and the pipeline members of API. I appreciate this opportunity to 

appear before the Subcommittee today on behalf of the AOPL and API. 

AOPL is an unincorporated trade association representing 48 interstate common 

carrier oil pipeline companies. Our membership is predominately domestic, but we also 

represent oil pipeline companies affiliated with Canadian 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. 

Explorer Pipeline operates a 1,400-mile pipeline system that transports gasoline, 

diesel fuel and jet fuel from the Gulf Coast to the Midwest. Explorer is based in Tulsa, 

Okla., and also serves Houston, Dallas, Fort Worth, St. Louis and Chicago. Through 

connections with other products pipelines, Explorer serves more than 70 major 

population centers in 16 states. Explorer currently transports refined products with more 

than 72 different product specifications for over 60 different shippers. The company does 

not buy or sell petroleum products; it only provides transportation services. Explorer is 

owned by subsidiaries of Chevron, Citgo, Conoco Phillips, Marathon, Sun, Texaco, and 

Shell. 

Summary

It has been over three years 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 Committee reviews the current state of pipeline safety and the progress that 

has been made since the PSIA 2002 became effective, there are a few points that we 

would like to emphasize. 

• The PSIA, actions by DOT’s Pipeline and Hazardous Materials Safety 

Administration (PHMSA) and initiatives taken by industry on its own have 

combined to produce significant improvement in pipeline safety, and this 

improvement is demonstrated by the record. 

• Substantial changes at DOT and in the industry are under way as a result of 

greater safety oversight and strengthening in safety requirements. Under the 

PSIA, industry and its regulators are driving towards even stronger safety 

programs that will result in further improvements in performance in the future. 

• The oil pipeline industry is making the investments that are required to produce 

this improved performance. We are on track to spend over $ 1 billion on 

pipeline safety over the next five years. 

• Since the hurricanes in 2005, a new awareness of the vital importance of a 

robust, reliable and secure pipeline system has developed in government, 

industry and the public. 

• Improvements in DOT’s authority to promote underground damage prevention 

are appropriate, but there is no urgent need for fundamental changes in the 

pipeline safety statutes at this time. What is needed is vigorous implementation 

of the 2002 Act, and that is happening. 

• It is important that Congress send a signal before adjournment in 2006 

affirming the general direction of the PSIA by reauthorizing the pipeline safety 

program for at least 5 more years with increases in funding levels to match 

projected inflation. 
139

The Role of Pipelines in Petroleum Supply

About 40 percent of total U.S. energy supply comes from petroleum, but 

transportation in the U.S. depends on petroleum for 96 percent of its energy. The 

nation’s transportation system could not operate without petroleum. Fully two-thirds of 

the ton-miles of domestic petroleum transportation are provided by pipeline. The total 

amount delivered by both crude oil and refined petroleum products pipelines (13.4 billion 

barrels in 2004) is nearly twice the number of barrels of petroleum consumed annually in 

the United States. 

The major alternatives to pipelines for delivery of petroleum are tank ship and barge, 

which require that the source and user be located adjacent to navigable water. Trucks and 

rail also carry petroleum, but are limited in very practical ways in the volume they can 

transport. In fact, pipelines are the only reasonable way to supply large quantities of 

petroleum to most of the nation’s consuming regions. Pipelines do so efficiently and 

cost-effectively – typically at 2-3 cents per gallon for the pipeline transportation cost 

charged to deliver petroleum to any part of the United States. 

Oil pipelines are common carriers whose rates are controlled by the Federal Energy 

Regulatory Commission. Pipelines only provide transportation, and our owners do not 

profit from the sale of the fuels they transport. 

Oil pipeline income is not related to the price of the products that are transported. In 

fact, high oil prices can have negative impacts on oil pipelines by raising power costs and 

reducing the demand for petroleum. 

Oil pipelines move 17% of interstate ton-miles at only 2% of the cost of interstate 

freight transportation, a bargain that American consumers have enjoyed for decades. 

The oil pipeline infrastructure is crucial to American energy supply. The care and 

stewardship of this critical national asset is an appropriate public policy concern and an 

important joint responsibility of the industry I represent, the Department of 

Transportation and Congress. 

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 (for large operators) and February 2002 (for 

small operators), oil pipelines have been subject to a mandatory federal pipeline safety 

integrity management rule (Title 49, section 195.452) administered by the DOT’s 

Pipeline and Hazardous Material Safety Administration (PHMSA). The oil pipeline 

industry’s experience with pipeline integrity management preceded the enactment of the 

PSIA. Our members who are large operators completed 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. PHMSA 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. Regular inspections are a 

permanent part of our future. Oil pipelines have experience with the PHMSA integrity 

management program that will be instructive to the Subcommittee in its review. 

Improvement in spill record

The oil pipeline spill record has improved dramatically in the last five years as 

exhibit 1 and 2 show. The data for these exhibits comes from a voluntary industry 

program that since 1999 has collected data on oil pipeline performance. This program is 

the Pipeline Performance Tracking System sponsored by the American Petroleum 

Institute and the Association of Oil Pipe Lines. (For more on PPTS, see 

http://www.api.org/ppts). The PPTS spill database is more detailed than any other 

similar database in existence, including data maintained by PHMSA. Exhibit 1 shows 

PPTS data for line pipe releases for the 1999-2004 period. Line pipe releases are those 

that occur outside the company’s facilities. They are the releases that have the most 
140

direct potential effect on the public and the environment. For each cause category, the 

trend is down. The number of total releases dropped 51 percent between 1999 and 2004. 

Releases due to corrosion dropped 67 percent. Releases due to third party damage 

dropped 37 percent. Releases due to operator error dropped 63 percent. During this 

period, the volume released in incidents on line pipe dropped 40 percent. 

Pipeline inspection and repair

In 2000, OPS estimated that under its proposed pipeline integrity management 

program approximately 22 percent of the pipeline segments in the national oil pipeline 

network would be assessed and provided enhanced protection. In fact, when oil pipeline 

operators carried out their analyses of how many of their segments could affect high 

consequence areas under the terms of the regulation, it turned out that almost twice as 

many segments, 43 percent of the pipeline network nationally, were covered. But in fact, 

the actual benefits realized have been even larger. 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 in most instances fixed in the system. As 

the internal inspection devices travel between ports they generate information about all 

the pipeline segments between those ports, which can be 35 to 50 miles apart. 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 pipeline mileage protected by the program as implemented will be almost 

four times the original OPS estimate. 

Operators are finding and repairing conditions in need of repair and less serious 

conditions that are found in the course of investigating defects. 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 

required permits to excavate the line 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. 

Cost

Although benefits from the integrity management rule are much greater than 

originally estimated, so is the cost. Costs per operator are often in the low tens of 

millions of dollars per year, far more than originally anticipated. We estimate that the 

cost of inspection and repair for the industry has averaged nearly $8,000 per mile. 

Operators have nevertheless moved aggressively to provide the resources needed to 

implement integrity management. 

The pipeline cost benchmarking survey conducted by the oil pipeline industry 

provides a snapshot for 2004 of the cost of integrity management activities of 19 oil 

pipeline companies. These companies operated 71,000 miles of pipeline (approximately 

42% of the U.S. total of 167,000 miles of oil pipelines under DOT jurisdiction), about 

half of which was identified as segments that could affect a high consequence area. The 

total cost of the integrity management programs of these 19 companies in 2004 was $215 

million. These operators inspected some 27,500 miles of pipeline in 2004 using inline 

inspection or hydrostatic pressure testing (some segments are tested with more than one 

technique), at a total cost of $7,820 per mile. 

PHMSA’s performance

The members of AOPL and API supported the establishment of DOT’s Pipeline and 

Hazardous Materials Safety Administration. Our members have seen positive results 

from elevating pipeline safety to the modal level within the DOT. In our view, PHMSA 

has been very aggressive in seeking to implement the provisions of the PSIA, has shown 

enhanced ability to work effectively with other federal agencies whose activities impact 
141

pipeline safety and has joined with the pipeline industry and interested stakeholders to 

achieve important results for pipeline safety and reliability. 

Security

In addition, PHMSA has been playing a very important and positive role in assisting 

the pipeline industry and the Department of Homeland Security in developing a security 

program to protect critical pipeline infrastructure that complements the risk-based 

integrity management program that PHMSA administers under the Pipeline Safety Act. 

PHMSA’s September 5, 2002 Pipeline Security Information Circular remains the 

principal federal guidance for pipeline industry security programs. The DHS’s 

Transportation Security Administration has joined PHMSA in conducting inspections of 

pipeline facilities based on the provisions of this circular. 

PHMSA currently has the mission of regulating security with respect to non-pipeline 

hazardous materials transportation in coordination with DHS. We believe Congress 

should consider assigning PHMSA a parallel role in the security of pipeline 

transportation. PHMSA has an experienced inspection force and by far the greatest 

expertise in pipeline operations of any of the federal agencies. Therefore, it makes sense 

to leverage those resources and expertise in developing an effective federal pipeline 

security program. PHMSA is familiar with the use of risk management and cost benefit 

techniques that are critical to developing security measures that work in the real world of 

limited resources. 

Oil pipeline operators will continue to cooperate with PHMSA, TSA and DHS to 

meet the government’s pipeline security expectations pending clarification by Congress 

of the federal agency oversight responsibilities for pipeline security. 

Pipeline Personnel Qualification

The PSIA required pipeline operators to develop programs to qualify pipeline 

personnel for tasks performed on the pipeline. These programs must require training 

where appropriate and periodic reevaluation of the qualifications of all pipeline 

personnel. Pipeline operators have responded with comprehensive programs that provide 

added assurance that only qualified personnel work on our pipelines. An important 

recent development is a joint pipeline industry association letter to PHMSA 

recommending a modification to PHMSA’s pipeline personnel qualification rules to 

indicate specifically when training of personnel may be appropriate and to provide for 

intervals for the periodic re-evaluation of the qualifications of individual personnel. Our 

letter is attached. Ensuring the ability of PHMSA to enforce appropriate training and 

evaluation requirements has been a long-standing interest of the National Transportation 

Safety Board. It is our understanding that PHMSA is considering modifications to its 

rules that will fully address the NTSB interest. The purpose of our letter is to indicate the 

joint industry’s support for such a modification. 

Areas for improvement in the federal pipeline safety program

The pipeline industry ‘s first priority is a clear Congressional reaffirmation -- before 

the 2006 adjournment -- of the direction charted by Congress for DOT and the industry in 

the Pipeline Safety Improvement Act of 2002. Accordingly, we urge that the 

Subcommittee at a minimum pass a bill in this Congressional Session that extends 

PHMSA funding authority for at least 5 years. If in addition Congress decides that 

improvements to the pipeline safety statutes are appropriate and can be enacted in this 

Session, we would be prepared to participate and put forward our own recommendations 

consistent with the thrust of the 2002 Act. If the opportunity to include substantive 

legislation arises, we would recommend consensus legislative provisions addressing 

excavation damage prevention, streamlining transmission pipeline integrity management 

and enhancing the efficiency and effectiveness of PHMSA. Below we discuss several 
142

areas where improvement in the federal pipeline safety program is warranted, although in 

many cases this improvement may be able to be achieved without new legislation. 

Damage prevention

An area where new legislation may be appropriate is underground damage 

prevention. Damage to buried pipelines during excavation is a persistent, preventable 

and significant cause of pipeline releases. Releases caused by excavation damage tend to 

be more traumatic, larger and more likely to threaten the public and the environment in 

comparison to releases from other causes. Damage prevention programs are almost 

totally controlled by the laws of the several states, and the federal interest in promoting 

damage prevention must be expressed in partnership with the states in most instances. 

Enforcement of damage prevention laws varies among the states across the entire 

spectrum of effectiveness. The affected interests in damage prevention are typically 

beyond the reach of any single regulatory authority, so often the most feasible approach 

is a cooperative one that brings affected interests together in a voluntary commitment to 

improvement. I am a board member of the Common Ground Alliance, an organization 

that Congress helped start that brings the key interests in damage prevention together to 

work cooperatively to improve safety. We understand that a promising approach to 

improving state damage prevention programs has recently been developed under the 

auspices of CGA and the Distribution Integrity Management Team. We would urge the 

Subcommittee to take this approach seriously and, if appropriate for purposes of 

reauthorization in 2006, include the necessary legislative provisions in your 

reauthorization bill. 

Public Information, including the National Pipeline Mapping System

Prior to the terrorist attacks of September 11, 2001 PHMSA developed the National 

Pipeline Mapping System (NPMS). Pipeline maps and basic information about the 

pipeline were made available to public through the internet. After 9/11 access to 

information on the NPMS was restricted. The public could only obtain pipeline operator 

contact information within a specified geographic location and could no longer view the 

maps. PHMSA then developed the Pipeline Integrity Management Mapping Application 

(PIMMA) for use by pipeline operators and federal, state, and local government officials. 

The application contains sensitive pipeline critical infrastructure information. PIMMA is 

intended to be used solely by the person who is given access by PHMSA and is not 

available to the public. 

PHMSA also requires pipeline operators to prepare annual reports of their 

operations, and these annual reports are available to the public upon request. Many 

pipeline companies also provide general information about their pipelines on their 

websites and as part of their public awareness programs. Much of the information in 

NPMS and other locations in PHMSA would help better inform the public and could be 

made available at some level that would not pose an undue security risk. 

We believe it is time that PHMSA and the Transportation Security Administration 

re-establish public access to the NPMS and determine what non-sensitive information 

already submitted by pipeline operators to PHMSA may be made available to the public. 

Pipeline Repair Permit Streamlining

An important initiative of the PSIA is section 16, “Coordination of Environmental 

Reviews”, which is concerned with expediting the repair of pipeline defects. While 

progress has been made on implementing this section, more work remains to be done, and 

the deadlines for agency action under the provision have passed. Since passage of the 

PSIA, the Council on Environmental Quality has played an important leadership role in 

implementing section 16. In June 2004, CEQ Chairman James Connaughton testified on 

before the Senate Committee on Commerce, Science and Transportation. He described 
143

an ambitious plan to coordinate pipeline repair information and decision-making among 

the federal agencies. We were very pleased at the time to hear Chairman Connaughton’s 

plan for implementing section 16. It is unfortunate that that plan has not been carried out, 

despite its obvious merit under the terms of the PSIA. On December 15, 2005, the joint 

industry associations wrote to CEQ seeking action on an important provision of the 

Connaughton/CEQ plan: a pilot test for a set of pre-approved Best Management Practices 

(BMPs) for pipeline repair site access, use and restoration. A copy of the letter is 

attached. To date, our letter has not been answered. 

Under the Connaughton/CEQ plan, a commitment by an operator to adhere in good 

faith to the BMPs would result in expedited permission to access repair sites to carry out 

the repair in order to allow repairs to be completed within the timeframes specified by 

DOT regulation. A multi-agency website would be used to coordinate response to 

requests for permits such that involved agencies operate in parallel or in concert to issue 

all required permissions to the operator in a timely fashion. To the extent possible the 

permitting process would be consolidated to limit to one the number of permits required 

(a consolidated permit) for each project. The process would also 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. 

We may need assistance from the Subcommittee to achieve the goals of section 16 

while complying with the Endangered Species Act. One way to accomplish this would 

be through an agreement between the Department of Transportation and the Department 

of the Interior under which DOT would voluntarily assume the role of default coordinator 

(or nexus) for pipeline repairs in those cases where no other federal agency is available or 

able to act as the federal nexus for ESA consultation. If legislation is judged to be 

necessary to facilitate such an agreement and role for DOT, we recommend that the 

Subcommittee seriously consider it. 

Our industry is eager to help carry out the vision Chairman Connaughton has 

articulated. We urge the CEQ to assign appropriate staff resources to accelerate progress 

with the plan. Section 16 is Congress’s direction to the executive branch agencies under 

CEQ’s leadership to facilitate full compliance with applicable environmental laws in the 

conduct of pipeline repairs while at the same time meeting the time periods for 

completion of repairs specified in DOT regulations. We have no intention other than full 

compliance with the applicable environmental laws, and are eager to assist in any way 

possible to devise a process that will harmonize objectives of the pipeline safety statutes 

with compliance with those laws. 

Encroachment

Section 11 of the PSIA required DOT to study land use practices, zoning ordinances 

and preservation of environmental resources in pipeline rights-of-way to determine 

effective practices to limit encroachment on these rights-of-way. DOT complied with 

section 11 by contracting with the Transportation Research Board of the National 

Academies to carry out the study. “Transmission Pipelines and Land Use, a RiskInformed Approach”, is available from the TRB website at 

http://www.nap.edu/catalog/11046.html. 

The TRB study recommended that DOT convene a multi stakeholder process to 

develop practices to limit encroachment that could be recommended to state and local 

government, developers and landowners along pipelines. The TRB favorably noted 

experience with the Common Ground Alliance in addressing excavation damage issues as 

a possible model for addressing encroachment issues. The oil pipeline industry is ready 

to participate enthusiastically, and encouragement of the process from the Subcommittee 

would be welcomed. 
144

Oil Pipelines Operated at Low Stress

Regulation of oil pipelines operating at low stress has received attention in the 

aftermath a recent leak from a low stress line on the North Slope of Alaska. The oil 

pipeline industry is developing a proposal for low stress pipelines that we will submit to 

DOT. We will support DOT in the regulation of those low stress pipelines that pose a 

significant threat to high consequence areas. We will recommend a risk-based program 

of proactive spill prevention for such lines that DOT can put in place using elements of 

the DOT’s successful integrity management regulations. Existing legislative authority is 

adequate to accomplish this. 

Conclusion 

The PSIA 2002 continues to provide valuable guidance that has resulted in 

significant improvement in the safe operation of hazardous liquid and natural gas 

pipelines. AOPL and API urge this Subcommittee and Congress to pass legislation in 

2006 that will provide DOT and the industry certainty in the years ahead by reaffirming 

the overall direction provided by the PSIA 2002 and extending its provisions for at least 

an additional 5 years. 

Thank you for the opportunity to testify before the Subcommittee on these important 

matters. 
145
146
147
148
149

 
150

Attachment 1 – Proposed Rule Modifications 

Proposal: 

We believe that these modifications to the rule will meet the needs of NTSB, allow 

companies to manage resources more effectively and will enhance the OQ rule. Below is 

a summary of our recommendations: 

1. Provided language to address “Evaluation Interval” (192.805 and 195.505) 

2. Provided language to address “Training” (192.805 & 195.505) 

Recommended new language: 

We are providing the following suggestions in revising the regulatory language to make 

these improvements (changes from the text of the current language are in italic and 

underlined): 

49 CFR 192 Subpart N

§192.805 Qualification program

Each operator shall have and follow a written qualification program. The program shall 

include provisions to: 

(a) Identify covered tasks; 

(b) Ensure through evaluation that individuals performing covered tasks are qualified; 

(c) Allow individuals that are not qualified pursuant to this subpart to perform a covered 

task if directed and observed by an individual that is qualified; 

(d) Evaluate an individual if the operator has reason to believe that the individual's 

performance of a covered task contributed to an incident as defined in Part 191; 

(e) Evaluate an individual if the operator has reason to believe that the individual is no 

longer qualified to perform a covered task; 

(f) Communicate changes that affect covered tasks to individuals performing those 

covered tasks; 

(g) Identify those covered tasks and the intervals at which evaluation of the individual's 

qualifications is needed. The evaluation interval for each covered task may not exceed 5 

years;

(h) After December 16, 2004, provides training, as appropriate, to ensure that individuals 

performing covered tasks have the necessary knowledge and skills to perform the tasks in 

a manner that ensures the safe operation of pipeline facilities. The operator’s plan must 

identify circumstances in which training is required and should include situations where 

the individual:

1) Is seeking qualification for a covered task not previously performed;

2) Is seeking qualification for a covered task outside their knowledge and 

skills;

3) Has had a qualification suspended or revoked;

4) Fails an evaluation for qualification;

5) Requires new or different knowledge or skills to perform a covered task;

6) Will utilize new equipment or procedures to perform a covered task; or

7) Has completed an evaluation and requires additional knowledge or skills 

to implement specific requirements that are outside the scope of the 

evaluation.; and
151

(i) After December 16, 2004, notify the Administrator or a state agency participating 

under 49 U.S.C. Chapter 601 if the operator significantly modifies the program after the 

Administrator or state agency has verified that it complies with this section. 

49 CFR 195 Subpart G

§195.505 Qualification program

(a) Identify covered tasks; 

(b) Ensure through evaluation that individuals performing covered tasks are qualified; 

(c) Allow individuals that are not qualified pursuant to this subpart to perform a covered 

task if directed and observed by an individual that is qualified; 

(d) Evaluate an individual if the operator has reason to believe that the individual's 

performance of a covered task contributed to an incident as defined in Part 191; 

(e) Evaluate an individual if the operator has reason to believe that the individual is no 

longer qualified to perform a covered task; 

(f) Communicate changes that affect covered tasks to individuals performing those 

covered tasks; 

(g) Identify those covered tasks and the intervals at which evaluation of the individual's 

qualifications is needed. The evaluation interval for each covered task may not exceed 5 

years; 

 (h) After December 16, 2004, provides training, as appropriate, to ensure that individuals 

performing covered tasks have the necessary knowledge and skills to perform the tasks in 

a manner that ensures the safe operation of pipeline facilities. The operators plan must 

identify circumstances in which training is required and should include situations where 

the individual:

1) Is seeking qualification for a covered task not previously performed;

2) Is seeking qualification for a covered task outside their knowledge and 

skills;

3) Has had a qualification suspended or revoked;

4) Fails an evaluation for qualification;

5) Requires new or different knowledge or skills to perform a covered task;

6) Will utilize new equipment or procedures to perform a covered task; or

7) Has completed an evaluation and requires additional knowledge or skills 

to implement specific requirements that are outside the scope of the 

evaluation; and

(i) After December 16, 2004, notify the Administrator or a state agency participating 

under 49 U.S.C. Chapter 601 if the operator significantly modifies the program after the 

Administrator or state agency has verified that it complies with this section.
152
153

MR. HALL. Thank you, sir. 

 The Chair recognizes Ms. Epstein, Senior Engineer, Oil and Gas 

Industry Specialist, Cook Inlet Keeper, for 5 minutes to summerize your 

testimony please. Thank you. 
154

MS. EPSTEIN. All right. Good afternoon. Thank you, Mr. 

Chairman, Mr. Boucher, members of the subcommittee and the full 

committee, and thanks to our legislative aides who are here, as Chairman 

Hall acknowledged. 

 Cook Inlet Keeper is a non-profit conservation and safety 

organization and part of the Water Keeper Alliance of 130-plus groups 

headed by Bobby Kennedy, Jr. My background includes serving on the 

U.S. Department of Transportation Advisory Committee for oil pipelines 

since 1995 and testifying before Congress four times on pipeline safety. 

 I also am testifying today on behalf of the Pipeline Safety Trust, an 

organization that came into being after the Olympic pipeline tragedy in 

Bellingham, Washington in 1999, which left three young people dead, 

destroyed a salmon stream, and cost millions of dollars in economic 

disruption. 

 Today, I will discuss the oversight and legislative improvements 

needed to guide PHMSA and State pipeline agency actions until the next 

reauthorization. 

 Before I begin, however, I would like to commend the progress 

PHMSA has made under its current leadership and that of the many 

pipeline companies who are maintaining their pipelines in ways that go 

beyond the minimum Federal requirements. Everyone should celebrate 

this progress while acknowledging that continuous evaluation 

improvement can make pipelines safer yet, which will, in turn, increase 

the public’s trust. We do support prompt reauthorization and also 

believe the current statute is working well. 

 One of our highest priorities is to ensure that local governments and 

the public have accurate information which allows them to independently 

evaluate, sometimes with technical assistance, the safety of nearby 

pipelines. PHMSA has made progress in this area, but some of the most 

important public information pieces still are missing. Congress needs to 

make available: one, pipeline maps for emergency responders, planners, 

zoning officials, and residents while still respecting security needs; two, 

increase public information on pipeline inspections and enforcement 

actions; and three, operator reports of all over-pressurization incidents, 

which are among the best measures of whether pipeline companies have 

good control over their systems. 

 Along with this additional information, Congress needs to ensure 

that Section 9 of the 2002 law is carried out. This section states that 

pipeline safety information grants up to $50,000 will be available to use, 

for example, by statewide pipeline stakeholder organizations such as 

those that exist now in Washington and Kentucky, by organizations 

needing technical assistance to comment on, or participate in, rule or 

industry standard development, and by community groups seeking to 
155

understand technical and regulatory issues following pipeline accidents. 

As time goes on, there have been numerous missed opportunities for 

effective public involvement as a result of the lack of grants to date, and 

I appreciate Mr. Boucher’s and Ms. Gerard’s comments on that topic 

today. 

 As you know, on March 2nd of this year, the largest oil spill to date, 

on Alaska’s North Slope, of 200,000 gallons or more was discovered out 

of Caribou Crossing located in a PHMSA-recognized high-consequence 

area. This spill came from a BP transmission pipeline that was exempt 

from PHMSA regulations. According to BP in the Anchorage Daily 

News, the pipeline “had known interior and exterior corrosion damage. 

Because of this, BP had downgraded the maximum pressure allowed 

within the line,” making it a low-stress line. Ironically, lower pressure 

takes the line out of the Federal regulatory system. Figure C, which 

everyone can view in my written testimony, shows the extensive cleanup at the site. 

 It is clear from figure C that low-stress hazardous liquid transmission 

pipelines can result in significant damage and cost when there are 

releases. PHMSA needs to remove the low-stress hazardous liquid 

pipeline exemption from the regulations, and I am pleased with Ms. 

Gerard’s answers to questions on this topic. 

 While low-stress lines may release hazardous liquids at a rate less 

than other transmission lines, this winter’s spill shows that they pose 

comparable environmental hazards and should be regulated similarly. 

And that is an important point. 

 On enforcement, it is not enough for PHMSA to pursue consent 

agreements and enforcement actions against individual violators if these 

actions do not convey to the industry as a whole that all operators are at 

risk of serious penalties for non-compliance and/or incidents. PHMSA 

needs to increase its use of judicial enforcement and allow qualified State 

pipeline safety officials to pursue enforcement actions against any State 

pipeline operators. 

 Our written testimony provides much-needed evidence of the 

deficiencies in PHMSA’s current enforcement program. As one 

example, the subcommittee should note that the lowest of the 

Environmental Protection Agency’s pipeline operator penalties is nearly 

12-times larger than the largest PHMSA-collected penalty from March 7, 

2002 through March 31, 2006. 

 Those portions of transmission pipelines that could affect highconsequence areas, or HCAs, are subject to the greatest regulatory 

oversight by PHMSA to date. Due to resource limitations, certain HCA 

areas were overlooked by PHMSA to date, namely parks and refuges and 

fishable and swimable waters for hazardous liquid pipelines. 
156

Additionally, Congress needs to add new language in the statute to 

include culturally and historically significant resources as HCAs. 

 For liquid pipelines, these expansions should not involve assessing 

many more sections of pipelines than are tested now. The majority of 

deaths and injuries from pipelines occur from incidents on the 

distribution pipeline systems that bring gas to towns, businesses, and 

homes. From 2001 through 2005, 61 people died along these pipelines, 

and 236 were injured. Congress needs to adopt a deadline for regulations 

to be completed on distribution pipeline integrity management and 

should mandate an excess flow valve requirement for new and 

replacement distribution pipelines as recommended by the NTSB, the 

International Association of Firefighters, and the International 

Association of Fire Chiefs, and this will be at a cost of $5 to $15 per 

EFV, or excess flow valve. 

 Thank you very much for your interest in pipeline safety and for 

inviting me to present here today. Please feel free to contact me at any 

time with your questions. 

 [The prepared statement of Lois N. Epstein, P.E. follows:] 

PREPARED STATEMENT OF LOIS N. EPSTEIN, P.E., SENIOR ENGINEER, OIL AND GAS 

INDUSTRY SPECIALIST, COOK INLET KEEPER, ON BEHALF OF PIPELINE SAFETY TRUST

Congress should pursue the following oversight and reauthorization items: 

1. Public information – direct PHMSA to: 

a) Reinstate public access to the National Pipeline Mapping System, 

b) Create a web-based enforcement document docket, 

c) Remove regulatory exemptions from over-pressurization reporting 

2. Ensure that PHMSA develops oil pipeline shut-off valve location and 

performance standards 

3. Ensure that PHMSA issues leak detection system performance standards for oil 

pipelines in High Consequence Areas 

4. Reauthorize and ensure that Congress appropriates money for Pipeline Safety 

Information Grants 

5. Remove the “low-stress” oil pipeline exemption 

6. Require PHMSA to provide web-based data on federal and state pipeline 

inspection and enforcement activities and an annual report to Congress on civil 

and criminal enforcement including penalty issuance and collection, and allow 

state regulators to pursue enforcement on interstate pipelines 

7. Direct PHMSA to expand High Consequence Areas so they include cultural 

and historic sites, parks and refuges, and fishable and swimmable waters 

8. Mandate a deadline for distribution pipeline integrity management regulations 

to be in place 

9. Maintain the current natural gas transmission pipeline integrity management 

reassessment interval 

Good morning. My name is Lois Epstein and I am a licensed engineer and an oil 

and gas industry specialist with Cook Inlet Keeper in Anchorage, Alaska. Cook Inlet 

Keeper is a nonprofit, membership organization dedicated to protecting Alaska’s 47,000 
157

square mile Cook Inlet watershed, and a member of the Waterkeeper Alliance of 130+ 

organizations headed by Bobby Kennedy, Jr. My background in pipeline safety includes 

membership since 1995 on the U.S. Department of Transportation’s Technical Hazardous 

Liquid Pipeline Safety Standards Committee which oversees the Pipeline and Hazardous 

Materials Safety Administration’s (PHMSA’s) oil pipeline activities and rule 

development, testifying before Congress in 1999, 2002, 2004, and last month on pipeline 

safety, and researching and analyzing the performance of Cook Inlet’s 1000+ miles of 

pipeline infrastructure by pipeline operator and type.1 I have worked on environmental 

and safety issues for over 20 years for two private consultants, the U.S. Environmental 

Protection Agency, Environmental Defense, and Cook Inlet Keeper. 

My work on pipelines in Alaska allows me to see how well the policies developed in 

DC operate in the “real world.” The Cook Inlet watershed, which includes Anchorage 

and encompasses an area larger than Virginia, is where oil and gas first was developed 

commercially in Alaska beginning in the late 1950s. Cook Inlet is an extraordinarily 

scenic and fisheries- and wildlife-rich, region, so ensuring that fisheries and the 

environment remain in a near-pristine condition is an important Alaskan value. 

I also am a part-time consultant for the Pipeline Safety Trust, located in Bellingham, 

Washington, and my testimony today reflects both Cook Inlet Keeper and the Pipeline 

Safety Trust’s views. Carl Weimer, the Executive Director of the Pipeline Safety Trust, 

is in Texas this week speaking at the annual American Petroleum Institute pipeline 

conference, so he could not be with us today. The Pipeline Safety Trust came into being 

after the 1999 Olympic Pipe Line tragedy in Bellingham, Washington which left three 

young people dead, wiped out every living thing in a beautiful salmon stream, and caused 

millions of dollars of economic disruption to the region. After investigating this tragedy, 

the U.S. Department of Justice (DOJ) recognized the need for an independent 

organization which 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 DOJ's 

recommendation and awarded the Pipeline Safety Trust $4 million that was used as an 

initial endowment for the long-term continuation of the Trust's mission. 

Background 

The Pipeline Safety Improvement Act of 2002 became law on December 17, 2002 

following two particularly tragic pipeline accidents: in Bellingham, Washington in June 

1999 and near Carlsbad, New Mexico in August 2000. The 2002 law contains some 

needed improvements but, like many acts of Congress, it represents a compromise among 

competing interests. As a result, safety will be improved, but not necessarily by as much 

or as fast as the public would like. 

 To put my presentation into context, the graphs below display the performance of 

the pipeline industry over time based on reported incidents and incidents/mile (the latter 

multiplied by appropriate factors for graphical display purposes). As you can see from 

the hazardous liquid pipeline data displayed in Figure 1, reported hazardous liquid 

pipeline incidents began dropping after 1994. 1994 is two years after Congress imposed 

mandatory requirements on the Office of Pipeline Safety (OPS) – now part of PHMSA – 

to prevent releases that impacted the environment, as opposed to releases which solely 

affect safety. From Figure 1, it appears that natural gas distribution pipeline incidents are 

trending slightly upward, while natural gas transmission pipeline incidents clearly are 

increasing. These upward trends may in part be an artifact of the recent increases in the 

price of natural gas which, in turn, increases the number of incidents above reporting 

thresholds (due to the cost of lost gas).

 

1

 See Lurking Below: Oil and Gas Pipeline Problems in the Cook Inlet Watershed, 28 pp. plus 

appendices, 2002, and follow-up reports in 2003 and 2005. www.inletkeeper.org/pipelines.htm 
158

Figure 1 

Number of Reported Incidents by Pipeline Type

0

50

100

150

200

250

300

1990

1992

1994

1996

1998

2000

2002

2004

Year

# of Incidents

Natural gas

transmission

Nat. gas distribution

Hazardous liquid

Figure 2 shows incidents divided by, or normalized by, pipeline mileage, which is a 

better way of measuring performance than the number of incidents alone since it accounts 

for changes in the number of incidents based on increased or decreased pipeline mileage. 

What is important to notice in Figure 2 is not the number of incidents per mile, but the 

trends this graph shows. The graph reinforces the improving performance of hazardous 

liquid pipelines, with a clear downward trend. Natural gas distribution pipelines do not 

show an upward or a downward trend in performance. Natural gas transmission 

pipelines, however, show a clear increase in the number of incidents per mile (again, at 

least some of this increase may be an artifact of the recent increase in natural gas prices). 

As I stated in my June 15, 2004 testimony before the Senate Commerce Committee, 

however: 

The most important rule issued as a result of the 2002 law, the natural gas 

transmission pipeline integrity management rule published on December 15, 

2003...will not reduce incidents on those lines for several years and it’s unclear 

how much of a reduction we can expect. This is true for several reasons. First, the 

law requires baseline integrity assessments to occur within 10 years, with 50% of 

the assessments occurring within 5 years of the law’s enactment; this long 

timeframe will delay the benefits. Second, because the rule only applies to an 

estimated 7% of transmission pipelines,2

 by 2007 (i.e., five years after the law’s 

enactment) we may 

expect only a 3.5% reduction in incidents, though the incidents that do occur should 

take place in areas of lesser consequences. Third, since the rule allows the use of 

 

2

 OPS states in the preamble to the rule “that about 22,000 miles of gas transmission pipelines are 

located in the [High Consequence Areas] in a network of 300,000 miles of gas transmission 

pipeline.” (68 Federal Register 69815, December 15, 2003) 
159

not-fully-proven methodologies (i.e., “direct assessment” and “confirmatory direct 

assessment”), we need to wait several years to see whether OPS’ approach to this 

rule will result in a meaningful reduction in incidents. 

Figure 2 

Incidents Normalized by Mileage

 (x 100,000 for nat. gas, x 10,000 for haz. liquid)

0.00

5.00

10.00

15.00

20.00

25.00

30.00

35.00

40.00

1990

1992

1994

1996

19982000

2002

2004

Year

Incidents/Mile (x 100,000 for nat. 

gas, x 10,000 for haz. liquid)

Natural gas

transmission

Nat. gas distribution

Hazardous liquid

Taking into account the different multipliers used, Figure 2 also shows that hazardous 

liquid transmission pipelines have a reported higher incident/mile rate than either type of 

natural gas pipeline, however the reporting thresholds for the different types of pipelines 

also differ. 

Issues to Address During Oversight and Reauthorization

 Based on the data shown in Figures 1 and 2, PHMSA’s reported performance to 

overseers including its federal advisory committees, the U.S. Government Accountability 

Office, and members of Congress, and a key recent incident on the North Slope of 

Alaska, I will discuss the oversight and legislative improvements needed to guide 

PHMSA and state pipeline agency actions until the next reauthorization. 

 Before I begin with recommended changes, I would like to commend the progress 

OPS/PHMSA has made under its current leadership. For the first time, hazardous liquid 

(i.e., oil) and natural gas transmission pipelines must be internally inspected, and 

rulemaking is proceeding to include integrity management requirements for gas 

distribution pipelines, where the majority of deaths and injuries occur. Pipeline operators 

now have clear requirements for communicating to the public and local governments, and 

PHMSA has unveiled valuable new additions to its own website and communication 

programs. Perhaps just as significant, many forward-thinking pipeline companies have 

taken pipeline safety seriously enough that they are now leading by example and 

operating and maintaining their pipelines in ways that go beyond the minimum federal 

standards. Everyone should celebrate this progress, while acknowledging that continuous 
160

evaluation and improvement can make pipelines considerably safer yet and thereby 

restore the public’s trust in pipelines. 

With respect to PHMSA oversight, I will discuss: 

• Public information access – pipeline maps, inspection and enforcement 

activities, and over-pressurization reporting, 

• Oil pipeline shut-off valve location and performance standards, and 

• Leak detection system performance standard(s). 

With respect to reauthorization needs, I will cover the following: 

• Pipeline Safety Information Grants, 

• Removal of the “low-stress” oil pipeline exemption, 

• Enforcement, 

• High Consequence Areas, 

• Distribution pipeline integrity management, and 

• Natural gas transmission pipeline integrity management reassessments. 

 

Public information. One of the public interest community’s highest priorities is to ensure 

that there is accurate information easily available to local governments and the public to 

allow them to independently evaluate – sometimes with technical assistance – the safety 

of nearby pipelines. PHMSA has made good progress in this area, but some of the most 

important information pieces still are missing. 

Pipeline Maps – Maps that allow local government emergency responders, planners, and 

zoning officials to know where pipelines are in relation to housing developments and 

other infrastructure are critical to prevent pipeline damage and increase safety. Maps that 

allow the public to see the locations of nearby pipelines also are the best way to capture 

the public’s attention regarding pipeline safety, increase their awareness of pipeline 

damage, and enlist them to be the eyes that help prevent damage. Maps also allow homebuyers and businesses to decide their own comfort level with living near pipelines. 

The Pipeline Safety Improvement Act of 2002 required pipeline companies to 

provide PHMSA with data for the web-based National Pipeline Mapping System 

(NPMS) so maps could be available for the above purposes. Unfortunately after the 

September 11th, 2001 terrorist attacks, the NPMS became a password-protected system 

that required users to agree not to share the NPMS information with anyone else. The 

NPMS thus is not available to the public, and the system is largely useless for local 

governments because pipeline location information cannot be added to local Global 

Positioning Systems or planning maps due to the non-disclosure requirement. 

The removal of NPMS maps from the web out of fear that terrorists may use them to 

find targets flies in the face of common sense. Major malls and stadiums, which are 

tempting targets, have no such non-disclosure requirement. Additionally, the locations of 

pipelines are no secret – in fact 49 CFR 195.410 requires that “Markers must be located 

at each public road crossing, at each railroad crossing, and in sufficient number along the 

remainder of each buried line so that [a pipeline’s] location is accurately known.” All 

that has been accomplished by removing maps from the web is to increase the problems 

of encroachment near pipelines, unintentional damage to pipelines, and public skepticism 

about pipeline safety. 

The removal of the NPMS from the web also has caused some states, such as 

Washington and Texas, to spend limited state dollars to duplicate PHMSA’s mapping 

system so that local governments and the public can have access to this valuable 

information. 
161

For these reasons, Congress should direct PHMSA to reinstate access to the NPMS 

so local governments can plan and the public can be aware of the pipelines that run 

through its midst. 

Information on Inspection and Enforcement Activities – One of the most important 

functions that PHMSA provides is its ongoing independent inspection of pipeline 

companies’ operations, maintenance, and training programs. Unfortunately, no portion of 

PHMSA’s inspection findings are available for local government or the public to review, 

leaving everyone outside of PHMSA and operators guessing the condition of pipelines 

and even if inspections are taking place. 

The pipeline industry itself complains about this lack of transparency. Individual 

companies know when they have been inspected, but often have to wait months or years 

to learn the outcome of inspections and, if there are no problems, they may hear 

absolutely nothing. This lengthy and frequently non-existent feedback system for 

operators is unfair, and does not improve safety the way a timely feedback system would. 

There should be a coversheet for each inspection that includes basic information 

such as pipeline segment inspected, inspection date, concerns noted, and corrections 

required. If this basic information, along with associated correspondence between 

PHMSA and operators were provided on a web-based docket system that could be 

searched by state or operator name, it would go a long way toward increasing trust in 

pipeline safety. 

For non-compliance-related enforcement actions, PHMSA should create a webbased enforcement document docket where the public could view enforcement as it 

progresses. The docket would include PHMSA’s Notices of Probable Violation, 

operators’ responses, transcripts of hearings, and final decisions. This would provide the 

public with a transparent enforcement system that would either instill confidence in 

PHMSA’s efforts, or provide the documentation needed to improve the system. 

Over-Pressurization Reporting – One of the clearest measurements of whether a pipeline 

operator has good control over its pipeline system is the frequency that it allows the 

system to exceed the maximum allowable operating pressure plus a permitted 

accumulation pressure for natural gas pipelines, or 110% of the maximum operating 

pressure for liquid pipelines. Unfortunately, the vast majority of these events are not 

required to be reported to PHMSA, so neither the federal government nor the public can 

use this information to determine whether pipeline operators are causing unwarranted 

stress on their lines and therefore need greater scrutiny. For these reasons, the 

exemptions from reporting these events contained in 49 CFR 191.23(b) and 49 CFR 

195.55(b) should be removed. 

Oil pipeline shut-off valve location and performance standards. In 1992, 1996, and 

2002, Congress required OPS to “survey and assess the effectiveness of emergency flow 

restricting devices...to detect and locate hazardous liquid pipeline ruptures and minimize 

product releases.”3

 Following this analysis, Congress required OPS to “prescribe 

regulations on the circumstances under which an operator of a hazardous liquid pipeline 

facility must use an emergency flow restricting device (emphasis added).”4

OPS/PHMSA never issued a formal analysis on emergency flow restricting device 

(EFRD) effectiveness. Instead, in its hazardous liquid pipeline integrity management 

rule,5

 OPS rejected the comments of the National Transportation Safety Board, the U.S. 

 

3

 49 USC 60102(j)(1). 

4

 49 USC 60102(j)(2). 

5

 49 CFR 195.452(i)(4). 

 
162

Environmental Protection Agency, the Lower Colorado River Authority, the City of 

Austin, and Environmental Defense and chose to leave EFRD decisions up to pipeline 

operators (after listing in the rule various criteria for operators to consider). It is unlikely 

such an approach to EFRD use meets Congressional intent, partly because the approach is 

virtually unenforceable and not protective of important environmental assets such as 

rivers and lakes. At this time, Congress needs to reiterate its previous mandates to 

PHMSA on EFRD use. 

Leak detection system performance standard(s). In its hazardous liquid transmission 

pipeline integrity management rule, PHMSA requires that operators have a means to 

detect leaks, but there are no performance standards for such a system. Similar to the 

situation for EFRD use, PHMSA listed in the rule various criteria for operators to 

consider when selecting such a device.6

 Again, such an approach is virtually 

unenforceable and not protective of important environmental assets such as rivers and 

lakes. Thus, Congress needs to direct PHMSA to issue a performance standard(s) for 

leak detection systems used by hazardous liquid pipeline operators to prevent damage to 

High Consequence Areas. 

Pipeline Safety Information Grants. Section 9 of the 2002 law states that: 

The Secretary of Transportation may make grants for technical assistance to local 

communities and groups of individuals (not including for-profit entities) relating to 

the safety of pipeline facilities in local communities...The amount of any grant 

under this section may not exceed $50,000 for a single grant recipient. The 

Secretary shall establish appropriate procedures to ensure the proper use of funds 

provided under this section. (§ 60130(a)(1)) 

To date, PHMSA has not established any such procedures, nor has it had any 

success obtaining appropriated funds for this purpose. As time goes on, there are missed 

opportunities for use of these funds, e.g., such funds might have helped community 

organizations understand the technical and regulatory issues associated with the Tucson 

gasoline pipeline accident in July 2003, as well as the Kentucky-based state-wide 

organization working on the substantial Kentucky and Ohio River crude oil pipeline spill 

of January 2005. Likewise, such grants are needed to assist public interest groups in 

commenting on technical regulations and to participate in technical standards 

development. 

Cook Inlet Keeper, the Pipeline Safety Trust, and other public interest organizations 

urge Congress to make certain that this section of the 2002 law is carried out as intended. 

Congress needs to ensure that authorization of this program continues and money to fund 

the grants is appropriated. 

Removal of the “low-stress” oil pipeline exemption. Last month on March 2, 2006 the 

largest oil spill to date on the North Slope of Alaska of 200,000 gallons or more was 

discovered at a caribou crossing located in a PHMSA-recognized High Consequence 

Area. This spill came from a BP crude oil transmission pipeline that was exempt from 

PHMSA regulations because it was a “low-stress” hazardous liquid pipeline that met the 

following criteria: it did not transport a highly volatile liquid (HVL), it was located in a 

rural area, and it was outside a waterway currently used for commercial navigation.7

 

According to BP, the pipeline “had known interior and exterior corrosion damage. 

 

6

 49 CFR 195.452(i)(3). 

7

 49 CFR 195.1(a)(3). 
163

Because of this, BP had downgraded the maximum pressure allowed within the line...”8 

Figure 3 shows the extensive cleanup operation which occurred (and is still ongoing) at 

this site. 

Figure 3 

Oil recovery efforts, March 13, 2006, Unified Command photo. 

 

It’s clear from Figure 3 that “low-stress” hazardous liquid transmission pipelines can 

cause significant damage when there is a release. Congress recognized this fact and 

included the following provision in the pipeline safety law: 

Prohibition against low internal stress exception. The Secretary may not provide 

an exception to this chapter for a hazardous liquid pipeline facility only because the 

facility operates at low internal stress.9

To provide necessary protection of the environment, Congress now needs to direct 

PHMSA to remove the “low-stress” hazardous liquid pipeline exemption from the 

regulations, perhaps retaining only the “low-stress” exemption for HVL lines. While 

low-stress lines may release hazardous liquids at a rate that is less than other transmission 

lines, this winter’s spill on the North Slope shows that they pose comparable 

environmental hazards and should be regulated similarly. 

 

8

 “Workers respond to Prudhoe spill: Leak may be one of largest in 29 years of production,” Wesley 

Loy, Anchorage Daily News, March 4, 2006. 

9

 49 USC 60102(k). 
164

Enforcement. The public and, presumably, pipeline operators have very little evidence 

that the increased penalties contained in Section 8 of the 2002 pipeline safety law are 

being consistently used and collected by PHMSA to send a message to pipeline operators 

that violations are both unacceptable and costly. This reality, along with PHMSA’s 

relative lack of judicial enforcement actions and the current inability of qualified states to 

pursue pipeline safety enforcement actions, leads to a still- problematic enforcement 

environment for pipelines. It is not enough for PHMSA to pursue consent agreements 

and enforcement actions against individual violators (e.g., Kinder Morgan following 

multiple releases10) if these actions do not convey to the industry as a whole that all 

operators are at risk of serious penalties for non-compliance and/or incidents. 

Cook Inlet Keeper and the Pipeline Safety Trust propose two modest and one 

substantive and significant legislative changes at the end of this section in order to ensure 

improved enforcement accountability, visibility, and effectiveness. 

 As evidence of current problems with pipeline safety enforcement, consider that: 

• In my response to follow-up questions from Senator Breaux after the June 15, 

2004 Senate Commerce Committee hearing, I stated that PHMSA needs to 

pursue several, high-profile preventive enforcement actions related to pipeline 

safety requirements in instances where there have not been releases. These 

include violations of corrosion prevention requirements, improper performance 

of direct assessment (a less-proven means of integrity assessment than smart 

pigging which PHMSA allows natural gas transmission pipelines to use), 

exposed pipelines, poorly performed repairs, etc. While PHMSA occasionally 

pursues enforcement actions related to these types of violations, practically no 

one except the violator knows that it has done so because penalties are low, 

media attention is limited or non-existent, it is hidden on the PHMSA website if 

it is visible at all, etc. 

• PHMSA can pursue enforcement actions for interstate pipeline violations but 

qualified state regulators cannot, though the large number of state regulators 

can assist in inspection and analysis of violations. In fiscal year 2003, PHMSA 

employed approximately 75 inspectors11 who were responsible for oversight of 

roughly 6,000 miles of interstate transmission pipeline each, a very large 

number of miles per inspector. Additionally, federal inspectors may not be as 

aware of certain technical, geographic, and even management issues associated 

with interstate pipelines as state regulators because of state officials’ proximity 

to the lines. 

• The Bellingham, WA proposed penalty in 2000 was $3.02 million, which was 

negotiated down to $250,000 nearly five years later. The Carlsbad, NM 

proposed penalty in 2001 was $2.52 million however, to date, no penalty has 

been collected. 

• In contrast to PHMSA, the U.S. Environmental Protection Agency (EPA) has 

issued and collected several recent, multi-million dollar penalties from 

hazardous liquid pipeline companies for their releases (EPA cannot use its 

capabilities to enforce against natural gas pipeline releases). These EPA 

penalties are shown in the following table. Note that the lowest of the EPA 

pipeline penalties is still nearly 12 times larger than the largest PHMSAcollected penalty from March 7, 2002 – March 31, 2006.

12

 

10 Pipeline and Hazardous Materials Safety Administration, CPF No. 5-2005-502H. 11 GAO, op. cit., p. 12. 

12 Response letter from Brigham A. McCown, PHMSA Acting Administrator, to Congressmen John 

D. Dingell and Rick Boucher, April 18, 2006. 
165

Company Date Penalty Summary of Violations 

Mobil E & P 8/04 $5.5 mill. Oil and produced water releases, 

inadequate prevention and control, 

failure to notify EPA of releases 

Olympic 

Pipeline/Shell 

1/03 >$5 mill. - 

Olympic 

>$10 mill. – 

Shell 

> 230,000 gal. of gasoline released, 3 

human deaths, over 100,000 fish killed 

Colonial 

Pipeline 

4/03 $34 mill. 1.45 mill. gal. of oil released in 5 states 

from 7 spills (from corrosion, 

mechanical damage, and operator error) 

ExxonMobil 9/02 $4.7 mill. Approx. 75,000 gal. of crude oil 

released, fouling a river and nearby 

areas 

Koch 

Industries, 

Inc. 

1/00 >$35 mill. Approx. 3 mill. gal. of oil released in 6 

states (from corrosion of pipelines in 

rural areas) 

 As a result of these ongoing problems with PHMSA enforcement, Cook Inlet 

Keeper and the Pipeline Safety Trust recommend that the federal pipeline safety statute 

be amended to: 

1. require PHMSA to provide web-based data on federal and state pipeline 

inspection and enforcement activities, including basic information such as 

pipeline segment inspected, inspection date, concerns noted, and corrections 

required as discussed above; 

2. require PHMSA to submit an annual report to Congress on civil and criminal 

pipeline safety enforcement, including penalty issuance, collection, and reasons 

for significant penalty reductions; and, 

3. allow qualified state pipeline safety officials to pursue enforcement actions 

against interstate pipeline operators. This recommendation, while significant, is 

necessary to maximize use of state and federal regulatory resources in the 

service of pipeline safety. 

High Consequence Areas. Those portions of transmission pipelines that could affect 

High Consequence Areas (HCAs) are subject to the greatest regulatory oversight, i.e., the 

hazardous liquid and natural gas transmission pipeline integrity management rules. 

Currently, HCAs for hazardous liquid transmission pipelines cover commercially 

navigable waterways, high population areas, and drinking water and ecological resources. 

HCAs for natural gas transmission pipelines cover high-density and other frequentlypopulated areas. According to industry-submitted data, approximately 40% of hazardous 

liquid transmission lines could affect HCAs, but over 80% of hazardous liquid 

transmission pipelines likely will be smart-pigged or pressure-tested for pipeline 

integrity.13 If, in fact, over 80% of the hazardous liquid transmission lines meet the 

standards of the integrity management rule (including post-pigging repairs), that is an 

excellent step toward improved pipeline safety. 

 There are portions of hazardous liquid transmission pipelines that do not fall within 

the 40% of the lines that could affect HCAs which nevertheless should have the 

protection afforded by the integrity management rule. Congress needs to direct PHMSA 

to expand the definition of HCAs to include the following areas – parks and refuges, and 

 

13 PHMSA Pipeline Integrity Workshop, Houston, Texas, May 17-18, 2005. 
166

fishable and swimmable waters.14 For reasons that are obvious to most anyone, parks and 

refuges and fishable and swimmable waters are areas of unusually high environmental 

sensitivity. At the time of HCA rule development, OPS took a narrow view of HCAs, 

partly for resource reasons and partly because of the need to issue the rule in a timely 

fashion. At this point in time, PHMSA is better able to expand the HCA rule to cover 

parks and refuges and fishable and swimmable waters. 

 Additionally, in mandating identification of HCAs in the 1992 statute, Congress did 

not include language about HCAs covering culturally and historically significant 

resources. This is a clear gap in the current statute, which Congress now needs to 

address. 

Distribution pipeline integrity management. The majority of deaths and injuries from 

pipelines occur from incidents on the distribution pipeline systems that bring gas to our 

towns, businesses, and homes. From 2001-2005, 61 people died along these pipelines and 

236 were injured. PHMSA, states, industry, and private organizations have undertaken 

an aggressive work plan to come up with an integrity management program for 

distribution pipelines. The Phase 1 report on this plan was released in December 2005,15

and all involved deserve thanks for their efforts. It is imperative that this plan now 

moves to the adoption of rules as soon as possible. Congress should adopt a deadline for 

regulations to be completed on this important issue. 

The proposed distribution pipeline integrity management program poses one area of 

concern: the lack of a mandatory excess flow valve (EFV) requirement. Congress asked 

PHMSA to set standards for the circumstances in which excess flow valves should be 

required,16 and the National Transportation Safety Board (NTSB) recommended that 

excess flow valve installation be mandatory in new construction and when existing 

service pipelines are replaced or upgraded.17 The International Association of Fire 

Fighters and the International Association of Fire Chiefs supports this mandatory 

installation position. 18 The Pipeline Safety Trust commissioned an independent review 

of the literature and science on excess flow valves, and that review came to the same 

conclusion.19 

The current Phase 1 report does not ask for mandatory EFV installation, but instead 

states that “It is not appropriate to mandate excess flow valves (EFV) as part of a highlevel, flexible regulatory requirement. An EFV is one of many potential mitigation 

options.”20 Congress should ask PHMSA and the pipeline industry how they plan to 

explain to the families of those killed in the future because of the lack of a $5-15 excess 

flow valve how a “flexible regulatory requirement” protected their loved ones. 

Natural gas transmission pipeline integrity management reassessments. The 2002 

reauthorization of the pipeline safety statute included some prescriptive language 

 

14 The federal Clean Water Act goals are fishable, swimmable, and drinkable waters. HCAs 

currently ensure only drinkable waters. 

15 Integrity Management for Gas Distribution: Report of Phase 1 Investigations, December 2005 

(http://www.cycla.com/opsiswc/docs/S8/P0068/DIMP_Phase1Report_Final.pdf). 16 49 USC 60110. 

17 National Transportation Safety Board Safety Recommendation P-01-1, 2. June 22, 2001 

(http://www.ntsb.gov/recs/letters/2001/p01_1_2.pdf). 18 Letter from the International Association of Fire Fighters and the International Association of Fire 

Chiefs to U.S. Department of Transportation Secretary Mineta, January 20, 2004, DOT Docket 

Management System #RSPA-2003-14455-49. 

19 A Simple Perspective on Excess Flow Valve Effectiveness in Gas Distribution System Service 

Lines, Richard B. Kuprewicz for the Pipeline Safety Trust, July 2005 (see 

http://www.pstrust.org/library/pdf/issuedEFV_Report.pdf). 20 Integrity Management for Gas Distribution: Report of Phase 1 Investigations, op. cit., p. 14. 
167

covering natural gas transmission pipeline integrity management timeframes. This was 

needed because – even though the hazardous liquid pipeline integrity management 

program was developed through rulemaking – it was clear to those involved that the 

timeframes for baseline and reassessment integrity assessments for natural gas 

transmission pipelines were highly contentious and needed to be resolved by Congress 

for a rulemaking to move forward. Since it is now only 2 1⁄2 years after the integrity 

management rule for natural gas transmission pipelines was issued and there have not 

been enough completed baseline assessments or any seven-year reassessments to know 

with any certainty the appropriate reassessment interval, it is not a sound technical 

decision to move forward with any changes to the Congressionally-mandated 

reassessment interval at this time. Additionally, the U.S. Government Accountability 

Office stated in its March 16, 2006 testimony that it would not complete its report on the 

reassessment interval until fall 2006, 21 further arguing against any change to the 

reassessment interval at this time. 

Summary 

In conclusion, Congress should pursue the following oversight and reauthorization 

items: 

10. Public information – direct PHMSA to: 

a) Reinstate public access to the National Pipeline Mapping System, 

b) Create a web-based enforcement document docket, 

c) Remove regulatory exemptions from over-pressurization reporting 

11. Ensure that PHMSA develops oil pipeline shut-off valve location and 

performance standards 

12. Ensure that PHMSA issues leak detection system performance standards for oil 

pipelines in High Consequence Areas 

13. Reauthorize and ensure that Congress appropriates money for Pipeline Safety 

Information Grants 

14. Remove the “low-stress” oil pipeline exemption 

15. Require PHMSA to provide web-based data on federal and state pipeline 

inspection and enforcement activities and an annual report to Congress on civil 

and criminal enforcement including penalty issuance and collection, and allow 

state regulators to pursue enforcement on interstate pipelines 

16. Direct PHMSA to expand High Consequence Areas so they include cultural 

and historic sites, parks and refuges, and fishable and swimmable waters 

17. Mandate a deadline for distribution pipeline integrity management regulations 

to be in place 

18. Maintain the current natural gas transmission pipeline integrity management 

reassessment interval. 

Thank you very much for your interest in pipeline safety. Please feel free to contact me 

at any time with your questions or comments. 

 MR. HALL. Thank you for a good presentation. 

 

21 Gas Pipeline Safety: Preliminary Observations on the Integrity Management Program and 7-Year 

Reassessment Interval, Testimony by Katherine Siggerud, U.S. Government Accountability Office, 

March 16, 2006, Highlights. 
168

 Mr. Kipp, we recognize you, as President of Common Ground 

Alliance, for 5 minutes. Thank you, sir. 

MR. KIPP. Thank you. Good afternoon, Mr. Chairman and members 

of the subcommittee. 

 I am pleased to appear before you today to represent the CGA. In 

reduced time, I would like to focus on three issues. 

 The first, damage information reporting tool. Late last year, the 

CGA published its first report on damage data. This report can be found 

on our website. We are now in a position to draw some conclusions and 

provide trends and analysis on damage to our infrastructure. For 

example, our 2004 analysis indicates that the estimate of damages to our 

underground infrastructure ranges between 600,000 and 750,000 

damages per year. Of the damage reports available for analysis, more 

than 40 percent of the damages were associated with work where a call 

to the one-call center had not occurred. The number one work activity 

being performed at the time of the damage was landscaping. More 

statistics and charts are available on our website. We encourage all 

companies to input their confidential data to this free system in order that 

these companies and the industry as a whole can determine what our 

problems are and what we may do to fix these problems. 

 Secondly, best practices on compliance and enforcement in the 

distribution integrity management report. In August 1999, the 161 

experts who developed the best practices unanimously agreed that an 

effective compliance and enforcement program at the State level was 

required to reduce the incidences of damage to the infrastructure. 

 There are a number of States with effective enforcement programs, 

including Minnesota, Virginia, New Hampshire, Maine, Connecticut, 

New Jersey, Georgia, Arizona, Massachusetts, and others. That idea 

holds true today. When examining gas distribution damage data 

available to the distribution integrity management program, the 

committee responsible for this analysis, at the rate of damages per 

thousand tickets, in Virginia and Minnesota, two States with effective 

enforcement programs, was lower than two comparable States with no 

enforcement programs. Virginia had 2.25 gas distribution damages per 

thousand tickets in 2005. Minnesota had 2.98 damages per thousand 

tickets, a 60-percent decrease in their past 10 years. The DIMP results 

team analyzed and provided statistics on two similar States without 

enforcement programs. One State has averaged approximately 6.7 

damages per thousand tickets over the past 5 years, while the other State, 

at 6.9 damages per thousand tickets also for the past 5 years. 

 Though operationally different, the Virginia program and Minnesota 

program are similar in that every gas or liquid damage is investigated 

and, when appropriate, the company responsible for the damage is fined. 
169

 Earlier I stated that more than 40 percent of damages in the country, 

no call was made to the one-call center. In Virginia, that number is 

between 13 and 18 percent only. They are virtually all homeowners. 

Few are professional excavators. They call the center. Additionally, 99 

percent of locates are done on time both in Minnesota and Virginia. The 

industry has responded positively to the enforcement program. 

Compliance and enforcement has resulted in a trusting, professional 

industry where all stakeholders know their roles and complete their tasks 

accordingly. 

 The third item, three-digit dialing. The Pipeline Safety Improvement 

Act of 2002 included a provision for the establishment of a three-digit 

nationwide toll-free telephone number system to be used by State onecall notification systems. We congratulate and thank this committee and 

former Congressman Chris John for introducing and sponsoring threedigit dialing as a provision of the Pipeline Safety Improvement Act. The 

one-call centers across the country have been working with the various 

telecoms to coordinate implementation of 811 in order to completely roll 

out the system in early 2007. We expect an increase in the more than 20 

million annual calls received by the Nation’s 62 one-call centers. We 

believe that a coordinated public awareness campaign should help reduce 

the 40 percent of damages where no call was made to the one-call center. 

 While our one-call center committee has been working with 

technical aspects of the conversion, our education team has been tasked 

with coordinating the development of a logo and tagline as well as 

selecting a firm to develop a public awareness campaign. This logo and 

tagline was released last month, and there it is up there. I am sure that 

you can identify that the CGA is very proud of this logo, and we expect 

you are going to see this logo on a regular basis beginning early in 2007. 

 Requests. The CGA requests the committee consider the following 

in their deliberations. One, extending the annual cooperative grant to the 

CGA for the duration of the reauthorization. This money is targeted to 

specific programs. We continue to require technology enhancements in 

our efforts to expand the use of and effectiveness of the DIRT tool as 

well as other software/hardware upgrades. We would also request that 

the committee consider providing an additional $1 million in 2007 to 

enable the CGA to extend its nationwide public awareness of 811 as it 

cuts over early next year. Secondly, as with the DIMP ommittee report 

to the CGA, we would request that this committee develop a method to 

assist the State governments in implementing a compliance and 

enforcement program consistent with their one-call laws. The CGA 

believes that effective compliance and enforcement of State laws and the 

implementation of 811 and an industry-wide volunteer participation in 
170

submitting data to our DIRT tool will help reduce injuries, fatalities, and 

damages to our industry. 

 The Common Ground Alliance is a true member-driven organization, 

and the 300 committee members from the 15 stakeholder groups work 

together to determine direction and problem solve, making the CGA a 

really unique forum. Their efforts and the financial support of their 

companies are what make the CGA a success. The CGA is extremely 

grateful for the support of Ms. Stacey Gerard of PHMSA and her great 

staff, who can never do enough for the CGA. 

 Thank you. 

 [The prepared statement of Bob Kipp follows:] 

PREPARED STATEMENT OF BOB KIPP, PRESIDENT, COMMON GROUND ALLIANCE

SUMMARY

The Common Ground Alliance is a nonprofit organization dedicated to shared 

responsibility in the damage prevention of underground facilities. 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. 

Since meeting with this committee in July 2004, the CGA has grown to more than 1200 

individuals representing 15 stakeholder groups and 130 member organizations. In 

addition, there are some 1000 or so members involved in our 43 regional partner groups. 

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 & Marketing, Membership, & Communications Committee, Data 

Reporting & Evaluation, , and the One Call Center Education Committee. 

Key initiatives described in the following testimony include: 

A. Resolution of 9 NTSB recommendations forwarded to the CGA for resolution by the 

Office of Pipeline Safety; 

B. Rollout of 43 regional CGA’s throughout the country; 

C. Identification of the “Virginia Pilot Project for Locating Technology”; 

D. Implementation of the CGA Damage Information Reporting Tool (DIRT); 

E. Review of CGA Best Practices and their relation to PHMSA’s Distribution Integrity 

Management Program; 

F. Review of D.I.M.P. results, the Virginia and Minnesota Enforcement Programs and 

the use of the CGA D.I.R.T. tool in support of these programs; 

G. Rollout of “811”, the 3 digit number to access one call centers across the country 
171

Testimony of Robert Kipp, Executive Director of the Common Ground Alliance, to 

the Subcommittee on Energy and Air Quality

Good afternoon, Mr. Chairman and members of the Committee. My name is Robert 

Kipp and I am the President 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 on September 19, 2000, at the completion of the “Common Ground 

Study of One-Call Systems and Damage Prevention Best Practices.” This landmark 

study, sponsored by the U.S. Department of Transportation Office of Pipeline Safety, was 

completed in 1999 by 161 experts from the damage prevention stakeholder community. 

The “Common Ground Study” began with a public meeting in Arlington, VA in 

August 1998. The study was prepared in accordance with, and at the direction and 

authorization of the Transport Equity Act for the 21st Century signed into law June 9, 

1998 that authorized the Department of Transportation to undertake a study of damage 

prevention practices associated with existing one-call notification systems. Participants 

in the study represented the following stakeholder groups: oil; gas; telecommunications; 

railroads; utilities; cable TV; one-call systems and centers; excavation; locators; 

equipment manufacturers; design engineers; regulators; federal, state, and local 

government. The Common Ground Study concluded on June 30, 1999 with the 

publication of the “Common Ground Study of One-Call Systems and Damage Prevention 

Best Practices.” 

At the conclusion of the study, the Damage Prevention Path Forward initiative led to 

the development of the nonprofit organization now recognized as the Common Ground 

Alliance (CGA). The CGA’s first board of directors’ meeting was held September 19, 

2000. Building on the spirit of shared responsibility resulting from the Common Ground 

Study, the purpose of the CGA is to ensure public safety, environmental protection, and 

the integrity of services by promoting effective damage prevention practices. 

The CGA now counts more than 1,200 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 Marketing, Membership, & 

Communications, Data Reporting & Evaluation, the One Call Center Education 

Committee, and the Regional Partners Committee. 

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. 

The Common Ground Alliance is managed by the association's Board of Directors. 

Currently, each director on the Board represents one of the fifteen CGA stakeholder 

categories. The Directors are elected by the CGA members within their respective 

stakeholder group, and represent the stakeholder group at approximately 5 meetings and 
172

to 3 – 6 teleconferences per year. Following are the names of the directors and the 

stakeholder group they represent. 

Excavator..................................Fred Cripps, Distribution Construction Company 

State Regulator.................................... Glynn Blanton, Tennessee Reg. Authority 

Insurance.......................................Raymond Pyrcz, Aegis Insurance Service, Inc. 

Railroad...............................Bob VanderClute, Association of American Railroads 

Oil (vice chair).....................................Timothy Felt, Explorer Pipeline Company 

Locators............................................................Jamal Masumi, Utiliquest LLC 

Public Works.......................................................Mark Macy, City of Nashville 

One Call..............................JD Maniscalco, Utility Notification Center of Colorado 

Equipment Mfg...............................................Scott Pollman, Subsite Electronics 

Gas.(chair).....................................................Paul Preketes, Consumers Energy 

Engineering............................................................Bill Johns, SPEC Services 

Road Builder...(treasurer)........................................Vic Weston, Tri-State Boring 

Electric............................................................Alan Yonkman, Detroit Edison 

Telecomm......................................................................John Thomas, Sprint 

Emergency Services...................Jim Narva, Dep. of Fire Protection/Electrical Safety, 

State of Wyoming 

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 and Marketing, Membership, & Communication 

Committee

The 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 Committee 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. 

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 
173

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. 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. They are also responsible for coordination 

of the nationwide rollout of “811”. 

F. Regional Partner Committee

The CGA recognizes that existing regional damage prevention groups have 

invaluable knowledge and experience, and these groups continue to make great strides in 

preventing excavation damage to America’s infrastructure. The CGA also recognizes 

that some areas of the country currently have no regional damage prevention programs. 

Through the CGA Regional Partner Program, the CGA partners with existing local, 

regional, and state damage prevention programs that have an objective of promoting 

communication among all stakeholders about damage prevention Best Practices. 

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 5 years the CGA contributed to the closing of 9 

NTSB recommendations. A tenth recommendation was directed to the CGA in 2005 and 

is currently in committee. The first nine recommendations were deemed “Closed – 

Acceptable” by the NTSB.

B. REGIONAL PARTNER PROGRAM

Since beginning this program, some 43 regional partners have been accepted into the 

CGA. These partners cover groups operating across most of the United States and parts 

of Canada. Their membership totals more than 1000 individuals involved in our industry 

across this country. The Regional Partners are: 

Alberta Utility Coordination Council Nevada Regional CGA Partnership 

Allegheny/Kiski Valley Coord. Committee New Jersey Common Ground Alliance 

Blue Stakes of Utah Utility Notification Center New Mexico Regional CGA 

British Columbia Common Ground Alliance North Carolina Regional CGA 

California Regional Common Ground Alliance Northeast Illinois Damage Prevention Council 

Central Texas Damage Prevention Council Northwest Region Common Ground Alliance 

Delaware Valley Damage Prevention Council Oklahoma One-Call System 

Denver Metropolitan DPC Ontario Region Common Ground Alliance 

Dig Safely New York Regional DPC Pittsburgh Public Service Committee 

El Paso County Damage Prevention Council Public Service Committee Indiana County 

Georgia Utilities Coordinating Council Quebec Regional CGA 

Greater Columbus Damage Prevention Council SE North Dakota – Utility Partnership 

Greater Toledo Underground DPC Southwest Ohio Utility Safety Council 

Greater Youngstown Underground DPC Tennessee Damage Prevention Committee 

Indiana Underground Plant Protection Service Texas Common Ground Committee 

Johnstown Area Public Service Committee Utilities Council of Northern Ohio 
174

Miami Valley Utility Damage Prevention Council Utility Service Protection Center, Delmarva 

Michigan Damage Prevention Board Virginia Utility Protection Service, Inc. 

Minnesota Utility Alliance Western Region Common Ground Alliance 

Miss Utility of West Virginia Wisconsin Underground Contractors Assoc. 

Mississippi One-Call System, Inc. Wyoming Regional CGA Partnership 

Missouri Common Ground 

C. VIRGINIA’S PILOT PROGRAM FOR ONE – CALL LOCATION 

TECHNOLOGY

In 2005 a number of representatives from various industry groups, government, and 

associations met to put together a framework to develop a trial program in Virginia. The 

purpose of this pilot project will be to research and implement new and existing 

technologies that appear to have great potential to significantly enhance the 

communication of accurate information among excavators, one-call centers, underground 

facility operators and facility locators. 

In ensuing meetings the participants list has grown, the business case developed, 

timelines developed, and processes set to begin the trial in the next few months. It is 

expected that the results will be known in a year. As can be seen from the list of 

participants that follows, the industry is poised to make this trial the high water mark for 

the industry in terms of technology use and benefits of same. 

Participants List

Participant Organization

Johnnie Barr NUCA (Ward & Stancil, Inc.) 

Terry Boss INGAA 

Scott Brown Washington Gas 

Carl Brumfield Utiliquest 

Corey Bufi GE 

Rodney Cope GE 

Kris Countryman Verizon 

Kim Cranmer Verizon 

David Doyle ProMark 

Quintin Frazier Plantation/Kinder Morgan 

Catherine Graichen GE 

Harvey Haines PRCI 

Wayne Hamilton Plantation/Kinder Morgan 

Roger Haycraft Texas Gas Transmission/PRCI 

Christina Head Colonial Pipeline 

Sandra Holmes AZ Blue Stake/CGA R&D Committee 

Blaine Keener PHMSA 

Bob Kipp CGA (conference line) 

Joe Kucera Angler Construction Co. / HCCA 

Cedric Kline Colonial Pipeline 

Jamal Masumi Utiliquest 

Stu Megaw AGC 

Dan Paterson Williams 
175

Rick Pevarski Virginia UPS 

Dave Price Virginia UPS 

Massoud Tahamtani Virginia SCC 

George Tenley PRCI 

Dwayne Teschendorf Duke 

Scott Thetford GE 

Scott Tolliver Verizon 

Isaac Weathers Georgia Utilities Protection Center 

John West VUPS Board 

Jeff Wiese PHMSA 

Herb Wilhite Cycla Corp. 

D. DAMAGE INFORMATION REPORTING TOOL

The primary purpose in collecting underground facility damage data is to analyze 

data, to learn Why events occur, and how actions by industry can prevent them in the 

future; thereby, ensuring the safety and protection of people and the infrastructure. Data 

collection will allow the CGA to identify root causes, perform trend analysis, and help 

educate all stakeholders so that damages can be reduced through effective practices and 

procedures. 

The CGA’s purpose is to reduce underground facility damage, which threatens the 

public’s safety and costs billions of dollars each year. In order to better understand where, 

how and why these damages are occurring, we require accurate and comprehensive data 

from all stakeholders. Late last year the CGA published its first report on damage data. 

A sample of the charts and graphs included in this report follows. 

Type of Work-Performed - 2004

Top 14 of 33 Categories (>= 1.0%) 

Unknown/Other, 

15.9%

Sewer, 9.1%

Fencing, 4.4%

Roadwork, 4.7%

Water, 6.0%

Electric, 6.9%

Construction, 

3.0%

Telecom, 2.7%

Petro-Pipeline, Irrigation, 2.4%

2.0%

CATV, 1.3%

Storm Drain, 

1.0%

Data Not 

Collected, 27.5%

Landscaping, 

9.5%
176

Type of Excavation Equipment - 2004

Backhoe, 7643, 

35.2%

Grader/Scraper, 

704, 3.2%

Auger, 664, 3.1%

Explosive, 2, 

0.0%

Probe, 118, 0.5% Bore, 341, 1.6%

Directional Drill, 

112, 0.5%

Vacuum, 50, 

0.2%

Drill, 6, 0.0% Trencher, 1501, 

6.9%

Hand tools, 1660, 

7.7%

Data Not 

Collected, 6076, 

28.0%

Unknown/Other, 

2811, 13.0%

Description of Root Cause - 2004

No Notification 

Made

48.0%

Insufficient 

Excavation 

Practices

23.8%

Insufficient Marking 

Practices

6.9%

Data Not Collected

5.6%

Unknown/Other 

Cause

10.2% Previous Damage

0.0%

Wrong Information 

Provided

0.1%

Call Center Error

0.1%

Facility Not 

Located

3.6%

Insufficient Call 

Practices

1.0%

Bad Map 

Information

0.4%

Facility Not Found

0.1%

Abandoned Facility

0.2%

It should be noted that the estimate of damages to our underground infrastructure 

ranges between 600, 000 and 750,000 damages per year. Of the damage reports available 
177

for analysis, more than 40% of the damages were associated with work where a call to 

the 1 call center had NOT occurred. 

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. 

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. 

The CGA believes that a strong state compliance and enforcement program combined 

with strong damage data analysis will assist in reducing damages. 

E. BEST PRACTICES – COMPLIANCE AND ENFORCEMENT

In August 1999, the 161 experts who developed the Best Practices unanimously 

agreed that an effective Compliance and Enforcement program at state level was required 

to reduce the incidences of damage to the infrastructure. 

These practices are contained in the Common Ground Alliance’s Best Practices Version 

3.0 

There are a number of states with effective enforcement programs including 

Minnesota, Virginia, New Hampshire, Maine, Connecticut, New Jersey, Arizona, 

Massachusetts, Virginia, and others. 

That idea holds true today. When examining gas distribution damage data available 

to the D.I.M.P. committee responsible for analysis, the rate of damages in Virginia and 

Minnesota, 2 states with effective enforcement programs, the rate of damages per 1000 

tickets was far superior to 2 comparable states with no enforcement programs. This can 

be seen in the following charts: 

Minnesota

(Effective Enforcement Program)

7.64

5.86 5.69

4.51 4.46

3.73 3.96

3.47

2.98

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

9.00

1996 1997 1998 1999 2000 2001 2002 2003 2004

Gas Distribution Excavation Damages per 1000 Tickets
178

VIRGINIA --Total Statewide Gas Facility

Damages 

Gas Damages per 1000 Gas Tickets

4.49

3.45 3.36

2.65 2.55

2.83

2.30

2.10 2.25 2.28

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

4.00

4.50

5.00

1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Gas Damages Per 1000 Tickets

State Without Effective Enforcement

Gas Distribution Leaks Repaired per 1000 Tickets

Third Party (2000-2003) and Excavation (2004)

9.78

8.35 8.98 8.64

6.96

0.00

2.00

4.00

6.00

8.00

10.00

12.00

2000 2001 2002 2003 2004
179

State Without Effective Enforcement

Gas Distribution Leaks Repaired per 1000 Tickets

Third Party (2000-2003) and Excavation (2004)

6.79 7.10 6.78

6.26

6.60

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

2000 2001 2002 2003 2004

These slides are from the Distribution Integrity Management Program Report 

available on PHMSA’s website.

F. D.I.M.P. RESULTS

MINNESOTA AND VIRGINIA ENFORCEMENT PROGRAM

Though operationally different the Virginia Program under Massoud Tahamtani and 

the Minnesota Program under Charles Kenow and Mike McGrath are similar in that 

every gas or liquid damage is investigated, and when appropriate, the company 

responsible for the damage is fined. 

Their damage rates are very low when compared to most states without enforcement 

programs. 

Earlier, I stated that in more than 40% of damages in the country, no call was made 

to the 1 call center. In Virginia, the number is between 13% and 18%. They are virtually 

all homeowners. Additionally, 99.0% of locates are done on time in both Minnesota and 

Virginia. The industry has responded positively to the enforcement program. 

The professional excavator knows that when he calls, the locate will be done on 

time. The owner/operator hires sufficient well-trained locators to do the job on an 

accurate and timely basis. Marks are adhered to, injuries are reduced, standown time is 

reduced, damages are reduced and both the public and industry benefit from a 

professional work process. 

One of the key findings in the D.I.M.P. report is that the Federal Government finds 

the means to encourage State Governments to develop and implement a Compliance and 

Enforcement Program. The CGA has worked closely with Stacey Gerard and her staff in 

many of the initiatives described in this paper and has found PHMSA to be very 

supportive of all stakeholders involved in this industry and the CGA’s consensus process. 
180

In many ways the D.I.M.P. report to PHMSA under the chairmanship of Glynn 

Blanton of Tennessee mirrors many of the findings of the original best practices report of 

1999. 

The CGA supports this concept and has promoted a State Compliance and 

Enforcement Program since the publication of the Best Practices in 1999. 

G. 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.” 

We congratulate and thank this committee and former congressman Chris John for 

introducing and sponsoring 3digit dialing as a provision to the “Pipeline Safety 

Improvement Act of 2002.” We congratulate the FCC commissioners on their unanimous 

support of this endeavor. The One Call Centers across the country have been working 

with the various telecoms to coordinate implementation of “811” in order to completely 

rollout the system in early 2007. We expect an increase in the more than 20 million 

annual calls received by the nation’s 62 one call centers. We believe that a coordinated 

public awareness campaign should help reduce the 40% of damages where no call was 

made to the 1 call center. 

Bill Kiger and Sandy Holmes our One Call co-chairs have worked with the telecoms 

the past few months to ensure a seamless transition to “811”. We congratulate Verizon 

Wireless and the numerous rural and community telephone companies who have 

completed the translation work in their switches at no cost to the one call centers. Bill 

Kiger is currently negotiating what we hope will be a similar arrangement with Cingular. 

At this time we are not aware of any issues which will prevent a complete transition to 

the “811” number early next year. 

While our One Call Center Committee have been working with the technical aspects 

of the conversion Tom Shimon and Dan Meiners CGA’s 811 task team co-chairs have 

successfully contracted to Celeritas and Krysanne Kerr the task of coordinating the 

development of a logo and tagline as well as as selecting a firm to develop a public 

awareness campaign. Below is the logo and tagline developed by RBMM of Dallas. 
181

Common Ground Alliance Common Ground Alliance 

811 Status 811 Status

The CGA is proud of the new 811 logo and tagline and looks forward to nationwide 

use of this mark to announce 811 implementation. 

CLOSING

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. The 300 or so committee members check egos at 

the door and work together to develop consensus decisions. Their efforts and the financial 

support of their companies are what make the CGA the success it has become. 

The CGA would not exist without the financial and logistical support of Ms. Stacey 

Gerard of PHMSA and her great staff led by Jeff Wiese who can never do enough for the 

CGA. The CATS folks of PHMSA led by Blaine Keener have been a wonderful addition 

to the damage prevention efforts. 

Lastly our sponsors; it is the 31 companies that sponsor the CGA that make a 

difference. There are many other companies in this country reaping substantial benefits 

from the CGA activities without contributing to its success. To those companies, it’s time 

to get on board. 

Thank you for the opportunity to provide you with this testimony. 

 MR. HALL. Thank you. 

 We will ask some questions, but I will ask unanimous consent that 

you be allowed to respond to questions that members submit to you in 

writing. In their absence here, they are entitled to that. And if you 

could, be as timely as you can with giving us a return on it, so we can get 

it into the record for everybody else to read. 

 I am going to start out and ask a question. 
182

 Most of you expressed some concerns regarding the 7-year 

requirement for reassessments. And as I understand the way the law is 

currently written, the 7-year interval only applies to those segments of 

pipes that required repair based on information gained from the baseline 

assessment. Is that your understanding? And if this is true, what is the 

overlap concern? 

 MR. MOHN. With all due respect, Mr. Chairman, the 7-year 

reassessment applies to all of our pipelines that are in high-consequence 

areas. So let me try to describe it this way. By the end of 2012, we will 

have done our baseline assessment on all of the HCAs. Then we are 

required to reassess all of those HCAs, each one of them within a 7-year 

period. Our concern is that the way the law is written, it requires that we 

start the reassessment period in 2010, prior to completion of 

establishment of the baseline. And that would mean that we have to 

inspect not just the 10 percent a year that we need to do to get the 

baseline, but we also have to assess about 14 percent a year, or 100 

divided by 7, in order to hit the reassessment period, which gives us a 

total annual workload of somewhere in the range of 25 percent. 

 MR. HALL. Anyone else want to comment on that? 

 Yes, Ms. Epstein? 

 MS. EPSTEIN. That is an accurate characterization of what the law 

requires. What the public interest community believes is that potentially 

that would be an appropriate workload, because some of the tests would 

have been done, in fact, quite a long time before, and so reassessment 

may be appropriate. We recognize there is a waiver provision in the 

pipeline safety statute at this time that if there is a problem, if there is 

some reason why a particular company or a particular geographic 

location cannot meet that timeframe, then PHMSA would be able to 

grant a waiver. 

 So you know, we are, as everyone else is, anxious to hear what the 

Government Accountability Office has to say on this matter, but we do 

think, you know, we are not way off where we need to be right now, and 

potentially-- 

 MR. HALL. Do you want to change it or lessen it or extend it? 

 MS. EPSTEIN. At this point, I think we should wait. We should 

maintain the current statutory requirements, unless there is compelling 

evidence from the GAO or from the industry in a few years that things 

need to be changed. 

 MR. HALL. Mr. Kipp, do you have any comment on that? 

 MR. KIPP. No comment on that. 

 MR. HALL. Anyone else? 

 The Chair recognizes the gentleman from Virginia. 
183

 MR. BOUCHER. Well, thank you, Mr. Chairman, and I want to 

express appreciation to our witnesses for taking part in our hearing today, 

also. 

 Mr. Bender, let me begin with you. I appreciate you preparing that 

demonstration of the nine points that have resulted in success in 

preventing excavation damage and the places where those nine principles 

are in operation. I think Virginia first and then perhaps rapidly followed 

by Minnesota are the key examples around the country. 

 I asked a question on the previous panel about whether there is 

something we could do at the Federal level to encourage more States to 

adopt similar principles. And I gather that among the principles, 

enforcement is fundamentally important. And there has to be an 

enforcement program for the excavation damage to be prevented. But 

what do you think, and what would you recommend, that we do? We are 

going to be reauthorizing the 2002 statute. It creates the legislative 

opportunity to make a variety of changes. And within that opportunity, 

what would you suggest that we do in order to encourage more States to 

do what Virginia and Minnesota have done so successfully? And the 

range of opportunities might be from simply requiring the nine-point 

program in each of those States to some less regulatory and more 

incentive-based approach. So what is your association’s suggestion to 

us? 

 MR. BENDER. Thank you, Congressman. 

 The main thing, I think, that can be done and should be done is to 

introduce legislation with these nine tenets of damage prevention. 

Within these tenets is the capability to improve communication and to 

improve enforcement. Currently, a lot of enforcement is done by the 

State attorney or city attorney, and they are more involved with criminal 

activity. So consequently, many times enforcement is just lacking. The 

people who really should be enforcing this are the people who are 

responsible for enforcement of the regulation: the State safety people, the 

State engineering people associated with the regulatory responsibility. 

Money is important. I know nobody likes to hear that Federal dollars are 

needed, but they are, because without those dollars, there are people that 

exist today to do the functions within the State organizations that need to 

be done. This approach advocates a carrot and a stick approach. The 

carrot is training. And that also involves, if I may, what do you do when 

you strike gas and there is throwing gas and there is a danger. People, 

excavators, need to know and need to be trained as to who they call and 

when they call and what they explicitly do. That is important. That is 

part of this program. That training costs money. 

 Recognition is important. Recognition of people who are doing very 

well through various means. But again, that requires money, and this 
184

group of stakeholders that got together, that PHMSA, to their credit, 

assembled and said, “Let us collaboratively come up with some 

solutions.” You know, basically, they are saying if there is one thing we 

want to do, if there is one thing you want to spend your money on to 

improve public safety, it is this. 

 MR. BOUCHER. Do you know how much money we should 

appropriate on an annual basis to the States in order to carry this program 

forward effectively? 

 MR. BENDER. Unfortunately, at this point, I do not, but I am sure 

that we, along with the other stakeholders, would be happy to work with 

the committee to determine that. 

 MR. BOUCHER. Oh, well, that is helpful. Thank you, Mr. Bender. I 

have another question of you, but before I come to that, let me ask Mr. 

Mohn if he is in general agreement with what Mr. Bender has just said in 

terms of what Congress ought to do to promote excavation prevention. 

 MR. MOHN. We are. In all likelihood, the funds to support the 

States’ enhancement of their programs will come from user fees, and 

while we support the necessity for some funding or a reallocation of 

funding within States, we would certainly urge an examination of the 

current dollars that are flowing to States to ensure that there aren’t 

dollars in those, based upon the experience of Virginia, where they found 

a way to fund the program without incremental dollars. The idea of 

incentivizing States, either by an additional grant or perhaps not as much 

funding as they would otherwise have gained for introducing a program 

that would incorporate these nine points, both work for us, and as in Mr. 

Bender’s case, we would love to work with the committee and your staff 

to find a way to make this a reality. 

 MR. BOUCHER. Well, thank you. We will accept that offer. 

 Mr. Kipp, would you care to comment on this question? 

 MR. KIPP. Yes, if I could, if this mic works. Great. 

 I think it is important for the committee to also understand that all 

stakeholders support this. It is not just a gas initiative, an oil initiative, or 

a PHMSA initiative. And part of the DIMP committee included 

representatives from the National Utility Contractors Association, from 

the Association of General Contractors. Our best practices include 

members from those two groups. In the audience here today, there are 

members from the AGC and NUCA, and they are here to listen to the 

goings-on. They are active participants in everything we do, and they 

want to be part of the solution. 

 At the end of the day, it is typically the people in those two industries 

that get hurt. Those trench accidents and explosions, if it is not 

homeowners, it is typically people working on equipment, and it is often 
185

the excavators. So there is a lot for them at stake here, and they support 

this 100 percent. 

 MR. BOUCHER. All right. Thank you. 

 Ms. Epstein, I saw you reaching for the microphone a moment ago. 

No? All right. That is fine. 

 Mr. Bender, a second question for you. You have heard Ms. Gerard 

testify that she is moving forward with a final distribution integrity rule. 

Are you satisfied with the progress that is being made on that? Would 

you recommend to us that we insert some kind of statutory deadline by 

which that rule has to be published? Or do you think the progress being 

made currently is satisfactory? 

 MR. BENDER. I certainly think the progress in developing the 

regulation is moving satisfactorily. We would support a deadline that 

you described. We have been working with a group of stakeholders, 

including PHMSA, to develop a recommended schedule, if you will, that 

will meet the requirements and provide a great program in an expeditious 

manner. 

 So our short answer is yes. 

 MR. BOUCHER. Okay. 

 Mr. Mohn, one question for you. I know that you heard our earlier 

discussion today with respect to the waiver authority that Ms. Gerard has 

with regard to the 7-year required re-inspections. And if problems arise, 

she is there to consider possible relief. So I suppose my question to you 

is I know your association has been recommending that we have a 

statutory change with regard to the 7-year re-inspections to address the 

potential that there might be some supply disruption involving this 

overlap between the 10-year inspection and the 7-year inspection in order 

to guard against the possibility that there might be a shortage of 

inspectors, because you have got a lot of inspections taking place at once. 

But that is precisely what the waiver authority is designed to address. So 

why is your association not comforted by the presence of the waiver 

authority? Why are you, instead, asking for a statutory relief? 

 MR. MOHN. That is a good question. 

 I would sum it this way. PHMSA and its predecessor, OPS, have 

had waiver authority from the time that I have been in the industry; I 

would expect maybe since the statute was originally passed. And we 

have rarely requested waivers or rarely put that process into place, 

because generally the regulations are things that we should follow. 

 Our concern is the uncertainty associated with the granting of 

waivers and the potential need on an operator-by-operator basis to 

request waivers that might even be regionally specific would not yield 

the certainty that we would like to have as to the way we are going to 

manage resources in that 3-year period. 
186

 I think your testimony from GAO earlier today summed the issue up 

very, very succinctly. We are looking to have to increase not just people, 

but smart pig resources by over twice for a 3-year period, and to suggest 

that somehow these companies who are in the business to make money 

are going to ramp up for 3 years without a commitment or an expectation 

that the equipment will be needed in subsequent years is a stretch. 

 Her comment also about direct assessment being a new technology 

that is only ramping up now as opposed to the more mature smart pig 

technology, I think, is quite relevant. 

 So in summary, we would like the certainty of the way we are going 

to plan and manage our resources within that 3-year period as opposed to 

the uncertainty of this path related to waivers, again recognizing that we 

could literally have tens if not hundreds of waivers hitting PHMSA. 

 MR. BOUCHER. Well, thank you, Mr. Mohn. You have expressed 

your association’s position very clearly, and we appreciate you sharing 

that with us. 

 Mr. Chairman, I have completed my questions. I have a unanimous 

consent request, and that is that we insert in the record some 

correspondence that Ranking Member Dingell has had on several of the 

issues that we have been discussing here this morning. 

 MR. HALL. I have been advised that our staff has looked at it and it 

is acceptable. Without objection, I hear none, it will be inserted. 

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MR. BOUCHER. Thank you, sir. 

 MR. HALL. I will ask just this last question. 

 Ms. Epstein, you stated in your testimony that high-consequence 

areas, or HCAs, as you all call them, are currently afforded the greatest 

regulatory oversight, a lot more attention. These areas are defined as 

hazardous transmission pipelines over commercially navigable 

waterways, high-population areas, in drinking water and ecological 

resources, and for natural gas transmission pipelines that cover highdensity and other frequently-populated areas. However, I think you 

stated that this isn’t enough, and you would like to see the definition of 

an HCA also include parks and refuges and fishable and swimable 

waters. I guess my question is if we change this definition, what areas 

are not considered HCAs? What would you leave out? And how would 

you propose the government prioritize its regulatory oversight if we 

defined every area as a high-consequence area? 

 MS. EPSTEIN. Yes. 

 MR. HALL. Lawyers say some kind of answer. The thing will speak 

for itself that all HCAs--go ahead. 

 MS. EPSTEIN. With due respect, Mr. Chairman, I don’t believe that 

ever offended the NHCA, but it is important to remember that right now 

the industry is testing about 80 percent of its pipelines, so this would add 

some areas associated with public lands. Fishable and swimable waters 

are the clean water definition areas that do need to be protected, so we 

felt that it was important to bring that up. 
250

 That doesn’t require, I believe, and I am not a lawyer, I am an 

engineer, a statutory change. If culturally and historic areas were 

included, that seems to be something that is not in the statute at this 

point. And I was a member of the Federal Advisory Committee when 

this was discussed and how broad should the regulatory definition be, 

and these issues were raised at that time. And in the interest of getting 

the rule out quickly, we focused--and some of us were in the minority 

who disagreed with the limited scope--but we did focus on the drinking 

water areas and the ecologically-relevant areas and the populated areas. 

And we said that is okay, but I think that it might make sense for 

PHMSA to go back and look at the transcript from those meetings where 

there was a promise made that there would be another look at some of 

these additional areas in the future. 

 MR. HALL. I think that concludes my questions. 

 Thank you all for your teaching, and thank you for your very good 

presentations and for your answers. And we will have some submissions 

to you, and I thank you for that. 

 MR. BOUCHER. Thank you. 

 MR. HALL. Well, we are adjourned. 

 [Whereupon, at 1:01 p.m., the subcommittee was adjourned.] 

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