[House Hearing, 109 Congress]
[From the U.S. Government Publishing Office]



 
                   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


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                      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)

                                CONTENTS


Testimony of:                                                    Page

Gerard, Stacey L., Acting Administrator/Chief Safety Officer, 
Pipeline and Hazardous-------------------------------------------- 12 
Materials Administration, U.S. Department of Transportation 
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 Ohio, on ----------------------------------------------- 92 
behalf of National Association of Regulatory Utilities Commissioners 
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 



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 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 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 consensus-based 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 low-pressure transmission line in Alaska highlights, I 
think, the need for a regulation of low-pressure pipelines.  And I 
understand that OPS is now 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.] 
	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. 
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 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 o 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 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.  

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 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 re-inspections 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 ISSUE, 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. 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 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 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 
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. 


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. 
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. 

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 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. 
	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 
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. 
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 2,200  natural gas pipeline operators and 250 hazardous 
liquid pipeline operators. 
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,  "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,  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. 

Implementing Mandates and Recommendations Regarding Pipleline and
Hazardous Materials,'' October 20, 2005.  See OIG reports on this 
website: www.oig.dot.gov. 

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)  and assess their pipelines for risk 
of a leak or failure using smart pigs  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 non-HCA 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 
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. 

                       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 completed baseline assessments on 
approximately 77 percent 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.   
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 time- 
sensitive 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 threats  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 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 facility."  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. 

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 one-call 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 report  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. 



Page 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 Report  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 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. 
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 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. 
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. 
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-to-remember, 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.
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 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 
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 

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. 
	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 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 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 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 
re-inspection 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 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. 
	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.
	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. 
	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 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, 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. 
	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? 
	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. 
	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. 
	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 private-sector 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. 
	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. 
	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. 
	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. 
	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 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") 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; 
      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. 
 

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: 
        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, 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 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. 
	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 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 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 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. 
      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. 
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.  


In March 2005, with NARUC's strong support, the Federal Communications 
Commission designated the 811 number as the national abbreviated 
dialing code for One-Call 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 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. 


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. 
(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 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 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 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 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. 
	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 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 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.  
	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.  
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.
	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, 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, 
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 
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.  
 
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 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 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.
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.  
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. 
(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, ï¿½ 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 consensus-based 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






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 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 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: 

	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. 
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. 


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 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 one-third 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 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 ipeline 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 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 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.  
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-size-fits-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 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 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 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 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 highest-risk 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. 
	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. 
	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. 


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. 

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 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 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 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 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 Risk-Informed 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. 



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.  



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

ï¿½192.805  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 (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. 



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. 
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 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 clean-up 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 
high-consequence 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.  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 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.   
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). 

Figure 1 



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,  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 
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 



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 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 home-buyers 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. 
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 web-based 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."   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)." 
OPS/PHMSA never issued a formal analysis on emergency flow 
restricting device (EFRD) effectiveness.   Instead, in its hazardous 
liquid pipeline integrity management rule,  OPS rejected the 
comments of the National Transportation Safety Board, the U.S. 
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.   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. (ï¿½ 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.   
According to BP, the pipeline "had known interior and exterior 
corrosion damage.  
Because of this, BP had downgraded the maximum pressure allowed 
within the line."   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. 

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. 

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 
releases ) 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 
inspectors  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 PHMSA-collected 
penalty from March 7, 2002 - March 31, 2006. 


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 frequently-populated 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.   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 fishable and swimmable waters.  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,  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,  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.   The International Association of Fire Fighters and 
the International Association of Fire Chiefs supports this mandatory 
installation position.    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.   
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 high-level, flexible 
regulatory requirement. An EFV is one of many potential mitigation 
options."   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 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 ï¿½ 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,    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.
	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. 
	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 one-call notification systems.  We congratulate and 
thank this committee and former Congressman Chris John for 
introducing and sponsoring three-digit 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 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 

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 
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 
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 
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
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 stakehoders 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. 

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 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: 

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. 
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. 



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. 
	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. 
	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 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 t
his 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 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. 
	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. 
	[The information follows:] 

        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 high-density 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. 
	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.] 

  	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. 
  	OIG Report No. SC-2004-064, "Actions Taken and Needed for 
Improving Pipeline Safety," June 14, 2004. 
  	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. 
DCAs include unusually sensitive areas (defined as drinking water 
or ecological resource areas), urbanized and other populated places, 
and commercially navigable waterways.  
  	A "smart pig" is an in-line inspection device that traverses 
a pipeline to detect potentially dangerous defects, such as 
corrosion. 
	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. 
  	Our sample of 409 threats was pulled from operator data 
bases, not from information reported to OPS. 
  	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. 
 	The December 2005 report, "Integrity Management for Gas 
Distribution," was prepared by OPS, its state partners, and a broad 
range of stakeholders. 
 	House Report No. 108-749, dated October 6, 2004. 
  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 
  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) 
  49 USC 60102(j)(1). 
  49 USC 60102(j)(2). 
  49 CFR 195.452(i)(4). 
 
  49 CFR 195.452(i)(3). 
  49 CFR 195.1(a)(3). 

  "Workers respond to Prudhoe spill: Leak may be one of largest in 
29 years of production," Wesley Loy, Anchorage Daily News, 
March 4, 2006. 
  49 USC 60102(k). 

  Pipeline and Hazardous Materials Safety Administration, CPF No. 
5-2005-502H.  GAO, op. cit., p. 12.
  Response letter from Brigham A. McCown, PHMSA Acting Administrator, 
to Congressmen John D. Dingell and Rick Boucher, April 18, 2006. 
  PHMSA Pipeline Integrity Workshop, Houston, Texas, May 17-18, 2005. 

  The federal Clean Water Act goals are fishable, swimmable, and 
drinkable waters.  HCAs currently ensure only drinkable waters. 
  Integrity Management for Gas Distribution: Report of Phase 1 
Investigations, December 2005 
(http://www.cycla.com/opsiswc/docs/S8/P0068/DIMP_Phase1Report_Final.pdf).
  49 USC 60110. 
  National Transportation Safety Board Safety Recommendation P-01-1, 
2. June 22, 2001 
(http://www.ntsb.gov/recs/letters/2001/p01_1_2.pdf). 
  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. 
  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). 
  Integrity Management for Gas Distribution: Report of Phase 1 
Investigations, op. cit., p. 14. 

  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. 








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