[Senate Hearing 113-043]
[From the U.S. Government Publishing Office]



                                                        S. Hrg. 113-043
 
   PIPELINE SAFETY: AN ON-THE-GROUND LOOK AT SAFEGUARDING THE PUBLIC

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


                             FIELD HEARING

                               before the

                         COMMITTEE ON COMMERCE,

                      SCIENCE, AND TRANSPORTATION

                          UNITED STATES SENATE

                    ONE HUNDRED THIRTEENTH CONGRESS

                             FIRST SESSION

                               __________

                            JANUARY 28, 2013

                               __________

    Printed for the use of the Committee on Commerce, Science, and 
                             Transportation





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       SENATE COMMITTEE ON COMMERCE, SCIENCE, AND TRANSPORTATION

                    ONE HUNDRED THIRTEENTH CONGRESS

                             FIRST SESSION

            JOHN D. ROCKEFELLER IV, West Virginia, Chairman
JOHN F. KERRY, Massachusetts         JOHN THUNE, South Dakota, Ranking
BARBARA BOXER, California            ROGER F. WICKER, Mississippi
BILL NELSON, Florida                 ROY BLUNT, Missouri
MARIA CANTWELL, Washington           MARCO RUBIO, Florida
FRANK R. LAUTENBERG, New Jersey      KELLY AYOTTE, New Hampshire
MARK PRYOR, Arkansas                 DEAN HELLER, Nevada
CLAIRE McCASKILL, Missouri           DAN COATS, Indiana
AMY KLOBUCHAR, Minnesota             TIM SCOTT, South Carolina
MARK WARNER, Virginia                TED CRUZ, Texas
MARK BEGICH, Alaska                  DEB FISCHER, Nebraska
RICHARD BLUMENTHAL, Connecticut      RON JOHNSON, Wisconsin
BRIAN SCHATZ, Hawaii
                    Ellen L. Doneski, Staff Director
                   James Reid, Deputy Staff Director
                     John Williams, General Counsel
              David Schwietert, Republican Staff Director
              Nick Rossi, Republican Deputy Staff Director
   Rebecca Seidel, Republican General Counsel and Chief Investigator


                            C O N T E N T S

                              ----------                              
                                                                   Page
Hearing held January 28, 2013....................................     1
Statement of Senator Rockefeller.................................     1

                               Witnesses

Hon. Joseph Manchin, U.S. Senator from West Virginia.............     4
Sue Bonham, Resident of Sissonville, West Virginia...............     5
    Prepared statement...........................................     8
Hon. Deborah A.P. Hersman, Chairman, National Transportation 
  Safety Board...................................................     9
    Prepared statement...........................................    10
Cynthia L. Quarterman, Administrator, Pipeline and Hazardous 
  Materials Safety Administration................................    18
    Prepared statement...........................................    21
Susan A. Fleming, Director, Physical Infrastructure Issues, U.S. 
  Government Accountability Office...............................    30
    Prepared statement...........................................    31
Jimmy D. Staton, Executive Vice President and Group CEO, NiSource 
  Gas Transmission & Storage.....................................    52
    Prepared statement...........................................    54
Rick Kessler, President, Pipeline Safety Trust...................    72
    Prepared statement...........................................    74

                                Appendix

Response to written questions submitted by Hon. Barbara Boxer to:
    Pipeline and Hazardous Materials Safety Administration.......    91
    Jimmy D. Staton..............................................    93
Tim Gooch, Fire Chief, Sissonville Volunteer Fire Department, 
  West Virginia, prepared statement..............................    94


   PIPELINE SAFETY: AN ON-THE-GROUND LOOK AT SAFEGUARDING THE PUBLIC

                              ----------                              


                        MONDAY, JANUARY 28, 2013

                                       U.S. Senate,
        Committee on Commerce, Science, and Transportation,
                                                    Charleston, WV.
    The Committee met, pursuant to notice, at 12:36 p.m., in 
the Ceremonial Courtroom, Seventh Floor of the Robert C. Byrd 
Courthouse, Hon. John D. Rockefeller IV, Chairman of the 
Committee, presiding.

       OPENING STATEMENT OF HON. JOHN D. ROCKEFELLER IV, 
                U.S. SENATOR FROM WEST VIRGINIA

    The Chairman. Welcome everybody. This hearing will come to 
order. This is a full and regular meeting of the Commerce 
Committee. We did this about a year ago on the same subject up 
north. Now we have new motivation because of what's happened 
here in the last several days.
    Let me just make a statement and then Senator Manchin, who 
joins us here today will make his statement, and I'm very happy 
about that.
    These pipes, pipelines, crisscross underneath our cities 
and our countryside. They're everywhere, 2.5 million miles, 
maybe more. Yet most of the time we're not even aware that they 
are there or have been there for 30, 40, 50, 60, 70 years or 
more recently. They deliver the critical fuel that powers our 
homes, our factories, and offices. And they also transport the 
oil and gas that keep our cars, trucks, and planes operating. 
They are the critical conduit between the shale gas development 
boom in our region and the rest of the country.
    And most days the network of pipelines operates across the 
country without a hitch. Let me be clear in saying that. 
Compared to other forms of transportation, pipelines are a 
relatively safe, clean, and efficient way of transporting the 
goods that they carry. Unfortunately, this is not always the 
case.
    Everyone in this room knows all too well what can happen 
when something does go wrong. Sue Bonham will be our first 
testifier, and she certainly knows. Wes, who has worked with me 
for 28 years, lives very close to there.
    So last month's incident in Sissonville was a startling 
reminder of the destruction that can occur when a pipeline does 
in fact rupture, explode. Houses were destroyed and portions of 
the nearby interstate were literally dismantled, disintegrated 
by the overwhelming heat of the flames from the ruptured 
pipeline.
    We can only thank our lucky stars that nobody was killed 
and that nobody was badly injured. I think there's a lot of 
pretty shaken up people out there, but there were no serious 
injuries. As we have seen in other accidents in the last few 
years, we're not always so lucky.
    After the explosion in Sissonville, we must sustain our 
focus on making sure the pipeline industry and all industries 
operate as safely as possible. That's my duty. That's what I 
swore an oath to.
    While we do not yet know the exact cause of the Sissonville 
incident, today's hearing provides the opportunity to examine 
where we stand in regard to the safety of our nation's pipeline 
system, which is vast. And --and just you know in your mind, 
feel the surge of that industry as it diverges and grows 
everywhere. People can't go fast enough.
    And in the building of that, some of the platforms you have 
trucks that carry water that can be up to 80,000 pounds going 
over West Virginia roads, which are built for far less than 
that, sometimes going right through people's front yard because 
they can't make the turn. So there's a lot of hurt that goes on 
just in the construction of these matters.
    When I took over as Chairman of the Commerce Committee, I 
made consumer protection and public safety my key priorities, 
and I really did. It was a good committee. It was a nice 
committee. It did its work. But accordingly, with the changes 
that I made, the Committee has been very active on the safety 
front. We actually established an idea that I got from Henry 
Waxman in the investigations unit which is made up--we made it 
up with very, very bright people, all lawyers with sharp teeth 
looking for bad people and doing something about it.
    These efforts have resulted in safety improvements across 
several industries from aviation to trucking to automobiles and 
on. As for pipeline safety, the Committee has held multiple 
hearings and successfully worked with our colleagues in the 
House to pass a Pipeline Safety Bill into law last year. It was 
not all that I had wanted, and it was compromised a good deal 
in the House, which is something that you get a bit familiar 
with in the Congress.
    This law which is called the Pipeline Safety Regulatory 
Certainty and Job Creation Act of 2011, welcome to Washington 
speak, was largely based on legislation that we in fact had 
developed in the Commerce Committee over a period of years and 
then passed out of the Commerce Committee and then through the 
Senate and then on to conference. And then both Houses then 
voting for it and the President signed it.
    This legislation included a number of new requirements that 
will move the ball forward in pipeline safety. For example, we 
laid the foundation to require the use of remote controlled and 
automatic shutoff valves on new pipelines. That's something I 
know that we're going to discuss today.
    We removed exemptions from requirements to call and get 
underground lines marked before you excavate. Year after year, 
excavation damage is the leading cause of pipeline accidents, 
and it certainly is time to pay attention to that. Removing 
exemptions from who has to ``call before you dig'' is now 
history, and it will help reduce the problem.
    We required operators to verify records and to reestablish 
lines, maximum operating pressure, PSI. How much can it take? I 
believe Ms. Hersman said the maximum pressure was 1,000 was 
what it was out there, maximum. And it was up to 970, 997 or 
something like that. It was a very, very close margin. So 
pressure within the pipelines becomes an enormously important 
effort. Should you have to set a reasonable pressure standard? 
I think the answer is yes.
    Lack of records predictively is a huge problem about older 
pipelines and just in general and contributed to the 
catastrophic pipeline explosion in California that killed eight 
people and injured many more, dozens more, I think.
    We require that critical pipeline location and inspection 
and information be provided to the public to build greater 
awareness of the lines that exist in and around our 
communities. That's something that is important now that people 
now are just living in a website world. And if you put 
information about pipelines and where they're located and make 
it available to the public, that's what government ought to be 
doing. That's what we ought to be doing.
    Does everybody immediately go to a website? Does everybody 
necessarily use the technology to get to a website? No. But 
it's going to keep going and increase each and every year.
    Finally, we increased penalties on operators who ensure the 
safety regulations. This will help deter bad actors from 
avoiding their safety obligations. And there's a lot that was 
pointed out this morning in the stop at Sissonville that had it 
been another series of companies that it could have been things 
might have been a whole lot worse.
    So while I'm pleased with the progress that we made in last 
year's law, I pushed for stronger requirements to move pipeline 
safety even further ahead. The Senate-passed bill, while not 
perfect, included a number of more stringent requirements for 
operators but House negotiators demanded watered down 
provisions for an agreement to move forward. And, of course, if 
you don't get their votes in conference you can't have a bill, 
so we went with the best we could possibly do.
    On the bright side, I'm confident that we will see strong 
but fair and sensible safety regulations out of our 
legislation. That's one of the things I want to discuss today 
with our Federal panel of witnesses. The questioning will be 
somewhat technical, and please forgive me for that. It was a 
tough fight to get pipeline safety legislation signed into law. 
However, it's important that we continue to provide a rigorous 
oversight into the industry to determine whether serious gaps 
still exist in our safety requirements.
    So today is a perfect opportunity to take stock in where we 
are and consider what steps might be necessary moving forward. 
One word too. One of our main jobs on the committees that 
Senator Manchin and I sit is something called oversight. And it 
is much maligned by many but not by us and not by me.
    Everybody has to be accountable to somebody else within a 
free society and a free enterprise society. There have to be 
limits. There have to be rules. In a country with over 300 
million people and so many different kinds of industries, that 
just is something that has to happen. It's something that only 
the Congress can do and then hopefully turn some of that into 
law.
    Anyway, I'm very excited about the witnesses we will hear 
from today, and particularly right now, Sue Bonham, a resident 
of Sissonville, whose house, fence, former house, former fence 
I saw this morning because it was right across from where we 
were in that 17-foot hole. And she's going to tell her great 
personal story about her experiences the day of the Sissonville 
explosion.
    Ms. Bonham provides a unique and important perspective as 
someone who was directly affected, and it's vital that we hear 
her point of view and that we keep it in our minds. As we 
consider what steps are necessary moving forward, we must 
remember there are crucial decisions and policies that have 
real impact on people's lives.
    And, Ms. Bonham, if you'll excuse me, I'm very happy that 
Senator Manchin is here and if he has some comments, hopefully 
shorter than mine, you're welcome to make them, sir. And I'm 
very happy you took the time to come.

               STATEMENT OF HON. JOSEPH MANCHIN, 
                U.S. SENATOR FROM WEST VIRGINIA

    Senator Manchin. Thank you, Senator, and to all of you here 
today, I appreciate so much your attendance. To all of the 
citizens of Sissonville who are affected directly or 
indirectly, I'm so pleased that nobody was injured but I'm 
sorry for the losses you've had and I hope all that will be 
restored fully.
    And, Sue, we'll be anxious to hear from you also.
    I want to thank Senator Rockefeller for his leadership as 
Chairman of the Senate Committee on Commerce, Science, and 
Transportation to make sure that our pipelines are constructed, 
maintained, and operated safely. I also want to thank the 
Senator for organizing the field hearing to make sure horrific 
explosions like the one in Sissonville never happen again.
    This is the fourth pipeline safety hearing held by Senator 
Rockefeller and the Commerce Committee in the last three years, 
which reflects the importance of the issue to the people of 
West Virginia, to Senator Rockefeller, and to myself. Of course 
we're not the only state interested in pipeline safety. In the 
last couple of years, there have been fatal pipeline ruptures 
in Pennsylvania and California. In any given year, there are 
between 32 to 61 pipeline incidents involving a fatality or 
hospitalization.
    We are so fortunate that no one was seriously injured last 
December when the gas pipeline ruptured in Sissonville. And I'm 
so thankful that all of you--and, Sue, I know that you were 
trapped in your home for quite some time, and survived that 
ordeal. And we'll be anxious to hear from you.
    We're all fortunate, indeed, that we had no West Virginians 
injured. We can't count on being that lucky the next time. The 
best thing that we can do is to make sure there is no next time 
ultimately. That's why we're all here today.
    I was exchanging a few comments with the families. I 
remember, it had to be about 20 years ago in Farmington, we had 
a horrific explosion, the same type. And the first time in my 
life I had ever seen anything like it. And I was visiting my 
father and mother in Farmington. And this had to be 20 or more 
years ago. And that's back when most of the cars were 
carbureted.
    So my dad and I jumped in the car and went up to the scene 
immediately, and horrific noise, just like a blowtorch but 
magnified many, many times. And my first thought is, is why 
doesn't somebody just shut the gas off? That was my first 
reaction. Why would they continue to let this happen? And the 
next of all, I saw all these cars lined up on U.S. Route 250 
and they all come to a standstill. And I thought, oh, my 
goodness, Senator, the worst possible. These people had all 
gotten killed in their cars. So I'm running through the cars 
very quickly and looking in and didn't see. A couple of the 
houses, the paint was melting. And I found out later that when 
the line exploded it sucked all the oxygen out and the cars 
stopped dead in their tracks. And it was just horrific. So I 
have witnessed that myself.
    So today I look forward to hearing how the Pipeline and 
Hazardous Material Safety Administration, with the help of the 
National Transportation Safety Board and the Government 
Accountability Office, plans to work with natural gas companies 
to develop and to enforce regulations that ensure pipelines are 
being operated safely and maintained properly and inspected 
regularly. We need common sense guidelines to prevent these 
incidents like the recent rupture in Sissonville.
    And, again, I want to thank Senator Rockefeller for holding 
this hearing and for also his many years of service which are 
going to be greatly missed. I can tell you he's been a great 
mentor, and he's been very helpful to me. And his staff has 
been absolutely unbelievable during my transition into the 
Senate. We're going to miss him, but we still have him for a 
while and we're going to work him hard while we still have him.
    The Chairman. And I've upgraded my clothing.
    Senator Manchin. He has done that. He sometimes----
    The Chairman. I'm an embarrassment to Senator Manchin on 
the Senate floor. I don't dress well enough for him, so I'm 
trying to improve my act. Now this is not a time for frivolous 
things.
    Senator Manchin. You can imagine he comes to consult with 
me on proper clothing.
    With that being said, I just want to thank him again. It's 
a pleasure to serve with him and an honor. But also the care 
and the concern we have for all the citizens of West Virginia--
we hope together we can figure out ways this won't happen and 
we can continue to improve the quality of safety and the 
quality of lives. Thank you, Senator.
    The Chairman. Thank you, Senator Manchin.
    Sue Bonham, please take your time.

STATEMENT OF SUE BONHAM, RESIDENT OF SISSONVILLE, WEST VIRGINIA

    Ms. Bonham. Thank you, Senator Rockefeller and Senator 
Manchin, for your gracious invitation to share my experience 
during the gas pipeline explosion in Sissonville on Tuesday, 
December 11, 2012.
    Not only am I honored by your invitation, I am truly 
blessed to have survived my 40 to 45 minute ordeal and to be 
able to share that story with you today.
    The front of my home faced Sissonville Drive where the 
explosion occurred. On the backside to the left there's a 
flower garden and an in-ground pool, both of which are 
surrounded by a large privacy fence with a gate access to the 
front of the home. Toward the right backside are the driveway 
and garage areas where my vehicle and another vehicle were 
parked. But the corner of the flower garden is where I sought 
shelter that afternoon.
    I was ready to walk out the door to run errands when I 
received a phone call from a lady named Trudy to schedule an 
appliance repair. Within seconds, Trudy and her coworkers 
became my only lifeline. I believe that call kept me from 
exiting my driveway onto Sissonville Drive when and where the 
blast occurred and where I believe I would have been killed 
instantly during the explosion.
    Instead, I stood in the center of my home where it was 
trembling, shifting, shaking, grinding all around me, the 
ground rumbling beneath me thinking the earth would open up at 
any moment and swallow me. The noise was so loud I had to 
scream for Trudy to please stay on the line, because I believed 
there was an earthquake or possibly a plane had crashed.
    Projectiles began falling like missiles through the ceiling 
into my home and I felt an immediate intense heat that took my 
breath away. As everything around me became more intense, I 
became more frightened. I dove underneath my dining room table 
and I looked out the bottom of the sliding glass doors only to 
see everything sizzling, blistering, or melting. The vehicles 
on the ground were literally rocking, moving in ways, and hot 
steam was filtering up out of the ground like hot springs.
    I crawled from my shelter to peek out a front window only 
to see a huge wall of fire roaring as far as I could see. At 
that moment I realized a gas line may have exploded and that I 
was in extreme danger. I ran out the back doors toward my 
flower garden thinking that if necessary I could jump into the 
pool to protect myself from the fire. My first attempt failed 
because the heat was so intense that I was driven back inside 
my home.
    I returned to my spot under the table becoming even more 
frightened realizing the house must be on fire and if it was a 
gas line explosion both my home and I could explode at any 
moment. Frightened, but thinking I had no other choice, I made 
another attempt to escape to the flower garden where I hid in 
the corner behind a withering vine and the privacy fence.
    I continued to scream into the phone hoping Trudy could 
hear me because I could no longer hear her over the roar of the 
explosion which was so deafening that I felt my eardrums would 
explode. The heat became more intense, suffocating, and the 
only area I could breathe was in that corner of the garden.
    I attempted once to run for the pool but the heat and lack 
of air drove me back to my corner. I failed at several attempts 
of stacking landscaping stones around me hoping that they might 
protect me from the overwhelming heat. I feared the landscaping 
mulch surrounding me might burst into flame at any moment.
    I rolled onto the ground to absorb some coolness believing 
I would soon be burned alive if I couldn't stay damp. At one 
point I threw my purse over the fence to mark my location for 
any rescue attempts. My only exits were to the front gate where 
the explosion was or to the driveway area where the blast and 
huge fireball were also located. I was trapped.
    I witnessed the earth being scorched, my home burning and 
melting. Everything was blistering or exploding. My 
stepdaughter's home imploding into ashes and hearing the 
continuing roar of the explosion. I looked into the sky and 
wondered if maybe this was simply the end of the world.
    I portrayed to Trudy that it was important to me that my 
family knew I fought hard to survive and that my last thoughts 
were of them because I became defeated. Suddenly two great 
firemen, Scott Holmes and Eddie Elmore, came into sight. Word 
had been received I was trapped. They wrapped their arms around 
me and escorted me to safety where I was loaded into an 
ambulance, treated for smoke inhalation, and then transported 
to a triage location where my family was awaiting. The relief I 
felt when I saw my daughter's beautiful face will remain in my 
heart forever.
    As the shock somewhat wore off, I began to understand the 
enormity of my experience. Overwhelmed by the odds that I had 
defied, I learned that I most likely would have been scalded 
alive had I jumped into the pool. And mostly certainly I would 
have died from lack of oxygen and smoke inhalation had I 
remained inside my home.
    Perhaps over the years, I've picked up some survival skills 
from surviving breast cancer, losing our home to a fire 5 years 
ago in that same location or listening to my youngest son's 
survival experiences with 130th Air Guard and for putting up 
with war stories from my husband Paul, a retired Charleston 
firefighter.
    All I know for sure is that I'm truly blessed by God to be 
here today. And, again, I thank you for this opportunity to 
share my survival experience of the Sissonville gas line 
pipeline explosion on December, 11, 2012.
    The Chairman. Ms. Bonham, thank you very, very much. In 
reading one of the stories, something that just stuck in my 
mind was that you, early on in the process, put up some rocks 
to hide behind.
    Ms. Bonham. Yes, I did.
    The Chairman. And then so that people would know that there 
was somebody behind there you sort of put your purse over on 
the other side.
    Ms. Bonham. I did.
    The Chairman. And what that says to me is the fullness of 
desperation, the fullness of the instinct for survival. And 
that was before you had to run because you didn't want to run 
because you didn't know that you'd make it to get under that 
bush.
    But we're so glad that you did. You, yourself, and your 
testimony and just the example that you've set already around 
the state now is important for every one of us, and I thank you 
very, very much for your testimony.
    Ms. Bonham. Thank you for the opportunity.
    [The prepared statement of Ms. Bonham follows:]

    Prepared Statement of Sue Bonham, Resident of Sissonville, West 
                                Virginia
    Thank you Senator Rockefeller for your gracious invitation to share 
my experience during the gas pipeline explosion in Sissonville on 
Tuesday, December 11, 2012. Not only am I honored by your invitation, I 
am truly blessed to have survived my 40-45 minute ordeal and to be able 
to share that story with you today.
    The front of my home faced Sissonville Drive where the explosion 
occurred. On the backside to the left, there is a flower garden and an 
in-ground pool, both of which are surrounded by a large privacy fence 
with a gate access to the front of the house. Towards the right 
backside are the driveway and garage areas, where my vehicle and 
another vehicle were parked. But, the corner of the flower garden is 
where I sought shelter that afternoon.
    I was ready to walk out the door to run errands when I received a 
phone call from a lady named Trudy to schedule an appliance repair. 
Within seconds, Trudy and her co-workers became my only lifeline. I 
believe that call kept me from exiting my driveway onto Sissonville 
Drive, when and where the blast occurred, and where I believe I would 
have been killed instantly during the explosion.
    Instead, I stood in the center of my home where it was trembling, 
shifting, shaking, grinding all around me; the ground rumbling beneath 
me, thinking the earth would open up at any moment and swallow me. The 
noise was so loud I had to scream for Trudy to please stay on the 
line--that I believed there was an earthquake or possibly a plane had 
crashed.
    Projectiles began falling like missiles through the ceiling into my 
home, and I felt an immediate intense heat that took my breath away.
    As everything around me became more intense, I became more 
frightened. I dove underneath my dining room table, looked out the 
bottom of the sliding glass doors, only to see everything sizzling, 
blistering or melting. The vehicles and the ground were literally 
rocking, moving in waves. Hot steam was filtering up out of the ground, 
like hot springs.
    I crawled from my shelter to peek out a front window only to see a 
huge wall of fire roaring as far as I could see. At that moment, I 
seemed to realize a gas line may have exploded, and that I was in 
extreme danger.
    I ran out the back doors towards my flower garden, thinking that, 
if necessary, I could jump into the pool to protect myself from the 
fire. My first attempt failed because the heat was so intense that I 
was driven back inside my home. I returned to my spot under the table, 
becoming even more frightened, realizing the house must be on fire, and 
if it was a gas line explosion, both my home and I could explode at any 
moment.
    Frightened, but thinking I had no other choice, I made another 
attempt to escape to the flower garden where I hid in the corner behind 
a withering vine and the privacy fence. I continued to scream into my 
phone--hoping Trudy could hear me because I could no longer hear her 
over the roar of the explosion which was so deafening that I felt my 
eardrums would explode.
    The heat became more intense, suffocating, and the only area I 
could breathe was in that corner of the garden. I attempted once to run 
for the pool, but the heat and lack of air drove me back to my corner. 
I failed at several attempts of stacking landscaping stones around me, 
hoping they might protect me from the overwhelming heat. I feared the 
landscaping mulch surrounding me would burst into flame at any moment.
    I rolled onto the ground to absorb some coolness, believing I would 
soon be burned alive if I couldn't keep damp. At one point I threw my 
purse over the fence to mark my location for any rescue attempts.
    My only exits were to a front gate where the explosion was, or to 
the driveway area where the blast and huge fireball were also located. 
I was trapped.
    I witnessed the Earth being scorched, my home burning and melting, 
everything was blistering or exploding, my step-daughter's home 
imploding into ashes, and hearing the continuing roar of the explosion. 
I looked into the sky and wondered if maybe this was simply the end of 
the world.
    I portrayed to Trudy that it was important to me that my family 
knew I fought hard to survive and that my last thoughts were of them. I 
became defeated.
    Suddenly, two brave firemen (Scott Holmes and Eddie Elmore) came 
into sight. Word had been received I was trapped. They wrapped their 
arms around me and escorted me to safety, where I was loaded into an 
ambulance, treated for smoke inhalation, and then transported to a 
triage location where my family was waiting.
    The relief I felt when I saw my daughter's beautiful face will 
remain in my heart forever. As the shock somewhat wore off, I began to 
understand the enormity of my experience, overwhelmed by the odds that 
I had defied. I learned that, most likely, I would have been scalded 
alive had I jumped into the pool. And, most certainly, I would have 
died from lack of oxygen and smoke inhalation had I remained inside my 
home.
    Perhaps over the years I've picked up some survival skills from 
surviving breast cancer, losing our home to a fire five years ago in 
that same location, or listening to my youngest son's survival 
experiences with the 130th Air Guard, and from putting up with ``war 
stories'' from my husband, Paul, a retired Charleston firefighter. All 
I know for sure is that I'm truly blessed by God to be here today.
    Again, thank you for this opportunity to share my survival 
experience of the Sissonville gas pipeline explosion on December 11, 
2012.

    The Chairman. And you may want to go back and join your 
family.
    All right. Our second panel will be the Honorable Cynthia 
Quarterman, who is the Administrator of the Pipeline and 
Hazardous Materials Safety Administration and the Honorable 
Deborah Hersman, Chairman, National Transportation Safety 
Board. They go to all kinds of tragedies and they are 
constantly being worked. And Ms. Susan Fleming, Director of 
Political Infrastructure issues of the United States Government 
Accountability Office.
    A lot of people may not know what the Government 
Accountability Office does, but it's one of those groups in the 
government in Washington that you can really trust when you ask 
them for their ideas or their report, the reflections on 
something which has happened and people believe them.
    Not that they don't believe you, Debbie, or you, Cynthia.
    And, Debbie, I think I should say NTSB, National 
Transportation Safety Board, should be the first witness. We 
welcome you and we thank you for coming down today and going 
out their and spending time and being here.

  STATEMENT OF HON. DEBORAH A.P. HERSMAN, CHAIRMAN, NATIONAL 
                  TRANSPORTATION SAFETY BOARD

    Ms. Hersman. Thank you very much, Senator Rockefeller. 
Thank you for your chairmanship of the Committee and for your 
leadership on pipeline safety issues as well as all 
transportation safety issues.
    Senator Manchin, thank you for having me here today.
    And, Sue, thank you for your story of personal survival. 
It's very important for all of us to hear your story because it 
is why we are here today.
    On December 11, the NTSB sent a full go team to Sissonville 
to investigate the Columbia Gas pipeline rupture that destroyed 
three homes, damaged several more, and burned through I-77 
about 15 miles from where we are today. The NTSB's 
investigation is still ongoing, but today I will review the 
sequence of events that we have developed so far.
    Line SM-80 is a 20-inch diameter gas transmission line 
running west to east from Lanham to Broad Run near Clendenin. 
It is interconnected with two other Columbia Gas pipelines that 
are operating nearby as you can see in the diagram.
    At approximately 12:41 p.m. the line was operating at 929 
PSI. It ruptured at a point about 112 feet west of I-77 and 
ejected a 20-foot section of the pipe 40 feet from where it 
originated. Almost immediately the 911 call center received the 
first call from a nearby retirement home.
    After hearing the explosion and seeing the fire, a Cabot 
Oil & Gas field technician, who was driving nearby, called the 
Cabot control center. At 12:43 p.m. the Columbia Gas operations 
center in Charleston received the first three pressure drop 
alerts from the Lanham compressor station. Over the next 10 
minutes, 13 more alerts were received in the control center in 
Charleston.
    Each alert was acknowledged by the controller but it was 
not until 12:53 PM when Columbia Gas received a call from Cabot 
did the Columbia Gas controller begin to understand that one of 
its pipelines had likely ruptured. By that time the pressure on 
all three interconnected transmission lines had dropped by 100 
pounds per square inch (PSI). The four valves at Rocky Hollow 
downstream of the rupture were closed manually by 1:19 p.m. 
However, additional time elapsed before the six valves at the 
upstream Lanham compressor station were closed.
    While the compressor at Lanham was shut down in the 
compressor station by 12:59, the valves required personnel to 
be physically present to close them. Technicians started 
closing the valves at 1:15 and notified the operations manager 
at 1:40 that the valves were fully closed, nearly one hour 
after the rupture.
    While on scene, NTSB investigators found the ruptured 
pipeline wall thickness had deteriorated by 70 percent from its 
original thickness at installation, and the external corrosion 
covered an area of about 12 square feet. The 20-foot segment 
that was ejected is now at the NTSB's lab near Washington, D.C.
    Issues of particular interest to our investigation are 
integrity management and inspections, control center 
operations, and automatic or remote shutoff valves.
    More than 2.5 million miles of pipelines operate in the 
United States. Thousands of those miles run near or close to 
our streets, our interstates, our churches, businesses, homes, 
and schools. They are a largely unseen part of the U.S. 
transportation system.
    Most people do not notice pipeline markers, like these 
pictured here, that identify where a pipeline is located in 
their neighborhood. But as you saw in Sissonville, when things 
go wrong the results can be catastrophic.
    Fortunately there were no fatalities in this accident, but 
sadly that is not always the case.
    Pipeline safety is on the NTSB's most wanted list of 
transportation safety improvements because we are focused on 
improving safety and the oversight of their operations in order 
to prevent future accidents like the one that occurred in 
Sissonville.
    Thank you very much for inviting me to West Virginia to 
participate in the hearing today. I'll be ready to answer your 
questions.
    [The prepared statement of Ms. Hersman follows:]

      Prepared Statement of Hon. Deborah A.P. Hersman, Chairman, 
                  National Transportation Safety Board
    Chairman Rockefeller, Members of the Committee, and Senator 
Manchin, thank you for the opportunity to address you today concerning 
the National Transportation Safety Board's (NTSB) ongoing investigation 
of the pipeline rupture and fire in Sissonville, West Virginia, 7 weeks 
ago.
    Mr. Chairman, as you have indicated, this is the fourth Senate 
Commerce Committee hearing on the issue of pipeline safety during your 
tenure as chairman. This hearing is also the NTSB's fourth Senate 
Commerce Committee hearing on this issue since I became Chairman. It is 
regrettable that major pipeline safety accidents continue to be a 
significant transportation and public safety concern. It is also 
regrettable that in the area of pipeline safety, philosopher George 
Santayana's aphorism that those who do not learn from history are 
doomed to repeat it, is certainly true. Indicative of the safety risks 
posed by pipelines, just four weeks prior to the Sissonville accident, 
the NTSB added pipeline safety to its Most Wanted List of the top 10 
transportation safety challenges for 2013--the first time this general 
subject has appeared on our annual List.
    Today, I will discuss the safety risks posed by the transportation 
of oil and natural gas by pipeline, the rupture and fire that occurred 
in Sissonville on December 11, 2012, the NTSB's response to the 
accident and the status of its investigation, and key NTSB findings and 
recommendations as the result of its past investigations of major 
pipeline accidents.
    As described in our Most Wanted List, today, in the United States 
there are some 2.5 million miles of pipelines transporting natural gas, 
oil, and other hazardous liquids, with a significant amount of new 
pipeline design and construction activity underway. The pipeline 
network in this country includes 300,000 miles of gas transmission 
pipelines. Because pipelines are usually underground, most people don't 
even know they exist, much less where they are located. Therefore, it 
is incumbent on pipeline operators and regulators to ensure that the 
Nation's pipelines are safe. Sufficient resources should be available 
to regulators to carry out critical oversight and enforcement efforts. 
These pipelines power thousands of homes and deliver important 
resources, such as oil and gasoline, to consumers. While one of the 
safest and most efficient means of transporting these commodities, 
there is an inherent risk that can lead to tragic consequences, 
especially when safety standards are not observed or implemented.
    As was evident in Sissonville last December 11, pipeline ruptures 
can cause significant damage. Last July, the NTSB issued its accident 
report for the July 2010 hazardous liquid pipeline rupture in Marshall, 
Michigan--a rupture that was not discovered for over 17 hours. As a 
result, almost 850,000 gallons of crude oil spilled into the 
surrounding wetlands and flowed into local waterways, costing nearly a 
billion dollars to date for clean-up and recovery--by far the most 
expensive environmental clean-up for an onshore oil spill. Also, in 
September 2010, one of the worst gas pipeline ruptures occurred in San 
Bruno, California, when a natural gas transmission pipeline ruptured 
and ignited, killing 8 persons. In addition, 58 persons were injured, 
38 homes were destroyed and 70 more were damaged as a result of this 
horrific and tragic accident.
The Sissonville Accident
    On December 11, 2012, at about 12:41 pm eastern standard time, a 
buried 20-inch diameter natural gas transmission pipeline (Line SM-80), 
running west to east, perpendicular to Interstate 77, and owned and 
operated by Columbia Gas Transmission Corporation, ruptured about 112 
feet west of Interstate 77 in Sissonville, Kanawha County, West 
Virginia, near Route 21 and Derricks Creek. The pipeline maximum 
allowable operating pressure (MAOP) was 1,000 pounds per square inch 
gauge (psig), and the operating pressure at the time of the rupture was 
about 929 psig. After the escaping high-pressure natural gas ignited, 
fire damage extended nearly 1,100 feet along the pipeline and about 820 
feet wide. About 20 feet of pipe was ejected from the underground 
pipeline and landed more than 40 feet from its original location.
    The rupture occurred in a pipe that was a part of a pipeline 
segment installed in 1967 with a nominal wall thickness of 0.281 
inches. The 20-foot ejected section of the pipe was found to have a 
fracture along the entire longitudinal direction at the bottom of the 
pipe. The outside surface of the pipe was heavily corroded near the 
midpoint and along the longitudinal fracture. The thinned area was 
approximately 6 feet in the longitudinal direction and 2 feet in the 
circumferential direction. The wall thickness had degraded so 
significantly that it measured only 0.078 inches at the point along the 
fracture--about 70 percent thinner than the uncorroded pipe.
    The force of the released gas created a crater about 75 feet long 
by 35 feet wide and up to14 feet deep. Escaping high-pressure natural 
gas from the ruptured pipeline ignited. The intense fire destroyed 
three near-by homes, caused damage to several others, and heavily 
damaged both the northbound and southbound lanes of I-77, closing both 
lanes for about 14-19 hours until the roadway surfaces were repaired.
    The first call to 911 about the pipeline rupture and fire was made 
by a person at a nearby retirement home at 12:41 p.m. At 12:43 p.m. the 
Columbia Gas controller on duty at the gas control center in 
Charleston, West Virginia, began receiving alerts on the Supervisory 
Control and Data Acquisition (SCADA) system from instrumentation at the 
Lanham Compressor Station, located 4.7 miles upstream from the rupture 
location. Over the next ten minutes, 16 SCADA alerts indicated that the 
discharge pressure was dropping on Line SM-80 and two other pipelines 
in the SM-80 system (Line SM-86 and Line SM-86 Loop). The first 
notification to the Columbia Gas control center in Charleston, West 
Virginia, was provided by a controller from Cabot Oil and Gas Company 
at about 12:53 p.m., who had received a report of a ``huge boom and 
flames shooting over the interstate'' from a field technician who was 
near the accident location. Columbia Gas SCADA data indicate that the 
discharge pressures on the three pipelines leaving Lanham had dropped 
about 100 psig.
    At about the same time that the control center was notified of the 
rupture, a Columbia Gas Operations Manager was called by a separate 
Columbia Gas field operator and told about the release and fire. The 
Operations Manager sent a crew to the Rocky Hollow valves approximately 
3.2 miles downstream of the rupture, where two technicians, closer to 
the accident site, had already self-dispatched. Columbia Gas field 
technicians closed the downstream isolation valves at about 1:19 p.m., 
preventing the backflow of gas. The Operations Manager also notified 
personnel at the Lanham compressor station to shut the upstream valves. 
The 6 valves at the Lanham compressor station required a technician for 
closure. Technicians started closing the valves at 1:15 p.m., and 
notified the Operations Manager at 1:40 p.m. that the valves were fully 
closed, stopping gas flow to the rupture nearly one hour after the 
rupture occurred.
The NTSB's Investigation
    After learning of the accident, a 10-person team from the NTSB, led 
by Board Member Robert Sumwalt, launched to Sissonville. According to 
our team's surveys conducted at the accident site, the rupture occurred 
in a nearly 38-foot long pipe joint that was a part of the pipeline 
segment installed in 1967. According to Columbia Gas documents, the 
ruptured segment of Line SM-80 was pressure tested twice in 1967: first 
at about 1,800 psig and then at about 1,750 psig. According to Columbia 
Gas records, the nominal wall thickness of the 20-inch ruptured pipe 
segment was 0.281 inches, had a longitudinal electric resistance weld 
seam, and was manufactured according to American Petroleum Institute 
specifications.
    Parties to the Investigation are: Pipeline and Hazardous Materials 
Safety Administration, (PHMSA), Public Service Commission of West 
Virginia, Columbia Gas Transmission Corporation, Kanawha County 
Sheriff's Office, and West Virginia State Police South Charleston 
Detachment.
    The NTSB issued a preliminary report on the Sissonville accident on 
January 16. Our investigative work, including metallurgical analysis of 
sections of the ruptured pipe at our laboratory in Washington, DC, is 
ongoing. Additional reports, analysis and a finding of probable cause 
will come later in the investigation.
Recurring Pipeline Safety Issues
    Although it is premature for the NTSB to determine the cause of the 
Sissonville accident, issue findings, or draw conclusions, there are a 
number of recurring safety issues we have identified in previous 
pipeline accidents we have investigated that merit highlighting today. 
In particular, these safety issues include:

   Automatic and/or remote control shut-off valve installation

   Use of in-line inspection tools

   Integrity management program

   SCADA training
Automatic and/or remote control shut-off valves
    The NTSB has long been concerned about the lack of standards for 
rapid shutdown and the lack of requirements for automatic shutoff 
valves (ASV) or remote control valves (RCV) in high consequence areas 
(HCA) and class 3 and 4 areas. As far back as 1971, the NTSB 
recommended the development of standards for rapid shutdown of failed 
natural gas pipelines. In 1995, the NTSB recommended that the Research 
and Special Programs Administration--the predecessor agency of PHMSA--
expedite requirements for installing automatic-or remote control valves 
on high-pressure pipelines in urban and environmentally sensitive areas 
to provide for rapid shutdown of failed pipeline segments. The current 
PHMSA integrity management regulation, which was promulgated in 2003, 
leaves the decision whether to install ASVs or RCVs in HCAs to the gas 
transmission operator.
    In Sissonville, it took the operator approximately 58 minutes after 
the pipeline rupture and explosion to stop the gas flow by closing 
manual shutoff valves. Although the operator did not identify an HCA 
associated with the site of the Line SM-80 rupture, as the NTSB has 
pointed out in previous accidents involving pipelines located in an 
HCA, the availability of ASVs or RCVs is an important tool in 
containing the safety risks after a pipeline rupture.
Use of in-line inspection tools
    One of the 13 recommendations the NTSB made to PHMSA as a result of 
the San Bruno pipeline rupture and fire is to require all natural gas 
transmission pipelines be configured to accommodate in-line inspection 
(also known as internal inspection) tools with priority given to older 
pipelines. This recommendation was predicated on the NTSB's concern 
that in-line inspection is not possible in many of the Nation's 
pipelines, which--because of the date of their installation--have been 
subjected to less scrutiny than more recently installed pipelines. As 
indicated earlier, the Sissonville rupture occurred in a pipeline 
segment installed in 1967. Due to construction limitations such as 
sharp bends and the presence of plug valves, many older natural gas 
transmission pipelines, including the ruptured segment in Sissonville, 
cannot accommodate modern in-line inspection tools without 
modifications.
    In-line inspection tools travel through the pipeline to determine 
the nature and extent of any anomalies in the pipe. Another option for 
this type of testing is hydrostatic pressure testing that yields 
information about the integrity of the pipeline.
    In the NTSB's judgment, the use of specialized in-line inspection 
tools that identify and evaluate damage caused by corrosion, dents, 
gouges, and circumferential and longitudinal cracks is a uniquely 
promising option. Unlike other assessment techniques, only in-line 
inspection can provide visualization of the pipeline integrity 
throughout the entire pipeline segment and, when performed 
periodically, can provide useful information about corrosion and crack 
growth. Although in-line inspection technology has detection 
limitations (generally a 90 percent probability that certain type of 
anomalies will be detected), the probability of detecting a crack may 
be improved with multiple runs, and it is nonetheless a more effective 
method for detecting unacceptable internal and external pipeline 
anomalies before a leak or rupture occurs.
Integrity management system assessments
    The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 
2011, enacted a little more than one year ago, includes a provision 
requiring the Secretary of Transportation to evaluate whether integrity 
management system requirements first set forth in the Pipeline 
Inspection, Protection, Enforcement, and Safety Act of 2006 (the PIPES 
Act), should be expanded beyond HCAs and report the analysis findings 
to this Committee and the Committee on Transportation and 
Infrastructure, U.S. House of Representatives, by early next January. 
If the Secretary determines that integrity management system 
requirements should be expanded beyond HCAs, the Secretary must issue 
regulations to implement these requirements after a Congressional 
review period has elapsed.
    Although the NTSB certainly welcomes the statutorily-required 
evaluation and recognizes that Columbia Gas and other operators of 
natural gas transmission pipeline facilities in non-HCAs are not 
required to establish integrity management programs that meet minimum 
performance standards established in PHMSA regulations, the NTSB views 
these programs as important business practices that these operators 
should consider for implementation. In our San Bruno, California and 
Marshall, Michigan, investigations, we determined the Pacific Gas and 
Electric Company and Enbridge Incorporated, respectively--both of whom 
must comply with PHMSA's integrity management program requirements--
nonetheless had ineffective programs. Deficiencies identified by the 
NTSB included use of inappropriate inspection methods and tools and 
failures to detect pipeline defects.
    The NTSB does, however, recognize that achieving a robust and 
effective integrity management program--whether mandated or voluntary--
requires dedication, sustained effort, and resources.
SCADA training
    As indicated above, the Columbia Gas controller on duty received 16 
``pressure-drop'' alerts--but did not receive any ``critical'' alarms--
on the SCADA system, before receiving notification from another 
pipeline operator. These alerts showed the discharge pressure dropping 
on Line SM-80 and the two other pipelines in the SM-80 system.
    The NTSB has addressed SCADA training in a number of instances. In 
2005, the NTSB conducted a study of SCADA in liquid pipelines. The 
study examined the role of SCADA systems in 13 hazardous liquid line 
accidents investigated between 1992 and 2004. In ten of the accidents 
cited by the study, there was a delay in recognizing the leak by the 
control center operators. As a result of one of the NTSB safety 
recommendations resulting from this study and requirements enacted in 
the PIPES Act, in December 2009, PHMSA promulgated its control room 
management rule for pipeline facilities in Title 49, Code of Federal 
Regulations, section 192.631.
    In the Marshall, Michigan pipeline rupture, the NTSB determined 
that inadequate training of control center personnel allowed the 
rupture to remain undetected for 17 hours, including two startups of 
the pipeline. In the San Bruno, California accident, the NTSB found 
``that it was evident from the communications between the SCADA center 
staff, the dispatch center, and various other PG&E employees that the 
roles and responsibilities for dealing with such emergencies were 
poorly defined.''
    As part of its investigation in Sissonville, the NTSB is looking 
into the operator's control room operations, its SCADA system, and the 
capabilities and training of its control room staff.
Closing
    Although the rupture and fire did not result in any fatalities or 
serious injuries, the Sissonville accident could easily have caused 
significant injuries and fatalities. Pipeline accidents that have 
occurred in San Bruno, California; Marshall, Michigan; Sissonville; and 
elsewhere are devastating to the affected communities. Particularly 
regrettable are the recurring frequency of these accidents and the 
resource constraints that hamper regulators' pipeline safety oversight.
    This concludes my testimony and I would be happy to answer any 
questions you may have.


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    The Chairman. Thank you, Ms. Hersman.
    And now the Honorable Deborah--I'm sorry. The Honorable 
Cynthia Quarterman, Administrator of the Pipeline and Hazardous 
Materials Safety Administration, PHMSA. The nickname is PHMSA.

       STATEMENT OF CYNTHIA L. QUARTERMAN, ADMINISTRATOR,

     PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION

    Ms. Quarterman. Thank you, Mr. Chairman. Thank you, Senator 
Manchin, and thank you, Senator Rockefeller, for all your 
leadership over the past few years associated with pipeline 
safety. We really appreciate the emphasis that you have put on 
that and look forward to working with you further as we 
implement the provisions of the Pipeline Safety Act 2011.
    Thank you also, Chairman Rockefeller, for your leadership 
in helping with the passage of that act and for your efforts to 
advance pipeline safety. The act has given us important tools 
and authority that we need to help us achieve our mission.
    While pipeline safety is improving, high profile incidents 
like the one that occurred in Sissonville underscore how 
important it is to be ever vigilant in preventing pipeline 
failures. Safety is the top priority for Secretary Lahood and 
for myself and for all of the employees of PHMSA, and we are 
working hard to protect the American people and the environment 
from the risks that are inherent in the transportation of 
hazardous materials by pipeline.
    There are 2.6 million miles of pipeline that crisscross our 
nation. PHMSA works hand in hand with a variety of partners, 
including state officials, to share the enormous responsibility 
of keeping our community safe while ensuring the nation's 
energy supply is moved efficiently.
    Thanks to the provisions of the act we are currently able 
to cover 77 percent of the program costs that our state 
partners incur. This funding covers personnel and equipment 
needs, public outreach programs, and other activities that 
allow states to inspect and regulate intrastate pipelines.
    West Virginia, as a full partner of ours, is responsible 
for inspecting their gas and liquid intrastate lines as well as 
serving as our interstate agent on gas transmission lines. This 
partnership has proven an important and strong partnership for 
the pipelines in West Virginia.
    The explosion in Sissonville, as Chairman Rockefeller has 
said, was terrible, serious, and dangerous. We are especially 
concerned for those families like the Bonham family who lost 
their homes in this incident. Fortunately no one was killed and 
it was not a greater tragedy.
    We're working closely with the NTSB and the Public Service 
Commission of West Virginia on the investigation of that 
incident. NTSB recently issued a preliminary report but there's 
still a lot of work to do before final conclusions can be made 
about that incident.
    PHMSA issued a corrective action order to immediately 
implement precautionary measures and assure safety elsewhere on 
that line. The pipeline will not be placed back into service 
until we are absolutely satisfied with the restart plan from 
Columbia Gas Transmission.
    When the pipeline is placed back into service it must 
operate at a 20 percent pressure reduction until a series of 
tests and evaluations have been completed and have been 
reviewed by our engineers. That will not be the end of our 
involvement.
    In addition to our assistance to NTSB and West Virginia and 
to the incident investigation, we will also perform our own 
compliance investigation to determine whether any regulations 
were violated with respect to the pipeline at issue.
    We will also take aggressive steps to apply any lessons 
that we learn here into our broader oversight mission with 
respect to pipeline safety. Lessons we learn here will help us 
prevent future accidents in other communities and will help us 
to continue to fulfill the goals and the purpose of the Act.
    The leadership of Chairman Rockefeller and the bipartisan 
effort associated with creating and passing the Pipeline Safety 
Act shows that there is some common agreement about the 
importance and of the safe and reliable pipeline system.
    PHMSA takes that responsibility very, very seriously and 
we've been taking a deliberate approach to implementing the 
provisions of that act. We are a small agency but with a big 
mission. We worked very hard with what we have, and I'm proud 
of what we've been able to accomplish in the first year since 
the act was passed.
    We were not only able to complete all the mandates that 
were required by January 3, 2013. We also completed additional 
mandates and performed more work than was required. In total, 
of the 42 mandates the act gave us, we have already 
successfully implemented 16 or 38 percent of them in just 1 
year.
    Reports on important issues like leak detection, automatic 
and remote control shutoff valves, depth of cover over buried 
pipelines at river crossings, and inventory of cast iron 
pipeline infrastructure have been completed.
    Furthermore, we have planned or initiated rulemakings on 
eight additional mandates, including access flow valves, and 
work is continuing and progressing on schedule for the 
remaining 18 mandates. We are confident that we will complete 
all the 42 mandates as specified and on time even without the 
additional--any additional resources.
    Additionally, we want to continue to look for ways to 
improve our existing regulations. We currently have a blend of 
performance based and prescriptive safety regulations. This 
year we're going to hold a public meeting to begin to talk 
about the Integrity Management Program which has been in place 
for more than a decade.
    We're also working to continuously improve our oversight. 
As an example, we significantly accelerated the implementation 
of a control room management regulation which relates to the 
supervisory control and data acquisition systems in pipeline 
system control rooms. We're going to use all that information 
and the information that we get from the recently released 
general accountability offices study on pipelines as we move 
forward.
    Despite the fact that the traditional risks of pipelines, 
including population, development, energy consumption have 
steadily increased over the years, over the past 20 years the 
number of serious incidents has gone down by 50 percent. 
Fortunately 2012 marked the fewest number of pipeline incidents 
in a decade. Despite those successes we continue to face large 
challenges in fulfilling our mission.
    Much like the members of the Committee, the President has 
recognized that the need for a more aggressive approach to 
safety on the Nation's pipeline systems from the discovery of 
vast energy shale deposits which will require more pipelines to 
the maintenance and rehabilitation to the aging pipelines 
already in place, the nation's infrastructure needs are growing 
and changing. The President's aggressive and historic budget 
requests for Fiscal Year 2013 for our agency reflects this 
need.
    The Act and the outreach and oversight is working. We have 
a long way to go to reach our goal of no deaths, no injuries, 
no environmental harm, and no property damage. But we have a 
solid foundation on which to build as we continue to advance 
pipeline safety.
    In closing, we look forward to working with this committee 
and with Congress in continuing to address pipeline safety 
issues. Everyone at PHMSA is dedicated and committed to 
fulfilling the remaining mandates and accomplishing our 
pipeline safety mission. It's an honor to serve the American 
people and to work with the dedicated career employees at the 
Pipeline and Hazardous Materials Safety Administration.
    Thank you again for the opportunity to speak here today.
    [The prepared statement of Ms. Quarterman follows:]

 Prepared Statement of Cynthia L. Quarterman, Administrator, Pipeline 
             and Hazardous Materials Safety Administration
    Chairman Rockefeller and members of the Committee, thank you for 
the opportunity to appear today to discuss the progress the Pipeline 
and Hazardous Materials Safety Administration (PHMSA) has made to 
implement the mandates of the Pipeline Safety, Regulatory Certainty, 
and Job Creation Act of 2011 (Pipeline Safety Act).
    Thank you for your leadership in helping to secure passage of the 
Pipeline Safety Act and for your efforts to advance pipeline safety. 
The Act has given us important tools and authority that we need to help 
us achieve our mission. While pipeline safety is improving, high-
profile incidents like the one that occurred at Sissonville underscore 
how important it is to be ever-vigilant in preventing pipeline 
failures.
    Safety is the top priority for Secretary of Transportation Ray 
LaHood and myself, and everyone at PHMSA is working hard to protect the 
American people and environment from the risks that are inherent in the 
transportation of hazardous materials by pipeline. PHMSA works to 
achieve its safety mission through prevention, rigorous enforcement, 
strong partnerships, and continuing education.
    This testimony will focus on several issues such as to the 
implementation of the Pipeline Safety Act mandates; our response to the 
Sissionville, WV pipeline incident and the Government Accountability 
Office (GAO) study on the ability of transmission pipeline facility 
operators to respond to a hazardous liquid or gas release.
    First, I will give an overview of PHMSA's pipeline safety program, 
including the role that the States take in ensuring the safety of 
pipelines. Second, I will provide an overview of the mandates we have 
completed and the efforts we have taken to improve pipeline safety. 
Third, I will discuss how, incidents like the one at Sissonville show 
us that we have a long way to go to succeed in our mission and that 
there is still a lot of work to be done in preventing pipeline 
incidents. Finally, I will reiterate the importance of a robust 
pipeline safety program, and the importance of reviewing the findings 
of the GAO study especially with regard to the Nation's changing and 
growing infrastructure needs.
I. Overview of Phmsa Pipeline Safety Program
    There are 2.6 million miles of pipelines that crisscross our 
Nation; those pipelines offer the safest and most cost-efficient way to 
transport hazardous materials. To ensure that this vast network is 
operating safely and reliably and that communities and families are 
protected, PHMSA works together with a variety of partners, including 
other Federal agencies, State and local officials, emergency 
responders, environmental groups, and the public.
    Federal oversight agencies like the National Transportation Safety 
Board (NTSB), the Office of Inspector General (OIG), and the Government 
Accountability Office (GAO) also have a vested interest in the safe and 
reliable operation of the Nation's pipeline infrastructure. For years, 
we have worked aggressively to respond to their recommendations. In 
addition to the mandates of the Act, we are currently working on 26 
open NTSB recommendations, 9 recommendations from the OIG, and 4 
recommendations from the GAO. Some of these recommendations are similar 
to the requirements of the Pipeline Safety Act, which suggests that 
there is a shared understanding of some of the challenges for the 
Nation's pipeline system.
    We have taken each and every mandate and recommendation that has 
been issued to us very seriously, and we have many completed and 
ongoing initiatives to provide protection to the American people and 
environment.
    Overall, the pipeline safety record is good. PHMSA's regulatory 
oversight program has led to many successes. Despite the fact that the 
traditional measures of risk--population, energy consumption, pipeline 
ton-miles--have steadily increased over the past two decades, the risk 
of pipeline incidents with death or major injury have decreased by 
about 10 percent every 3 years. The risks of hazardous liquid pipeline 
spills that have environmental consequences have decreased by an 
average of 5 percent per year. Nonetheless, there is more work to be 
done.
    In 2012, the number of pipeline-related fatalities was at a level 
not seen since 2008, and the number of pipeline-related injuries was at 
the lowest level since 2007. Furthermore, 2012 had the fewest total 
pipeline incidents in a decade. However, PHMSA, as an organization, 
cannot accept death or injury as an inevitable consequence of 
transporting hazardous materials. We are working continuously to find 
new ways to reduce risk to operators and the public, and we aim to 
sustain and improve upon these long-term trends.
II. Implementation of the Pipeline Safety Act
    On January 3, 2012, President Obama signed the Pipeline Safety, 
Regulatory Certainty, and Job Creation Act of 2011. The Act is designed 
to examine and improve the state of pipeline safety regulations and 
authorizes funding, through Fiscal Year 2015, for provisions of the 
pipeline statute in the U.S. Code related to gas and hazardous liquids. 
Ultimately, the Act gives enhanced safety authority to PHMSA and will 
improve pipeline transportation, by strengthening the enforcement 
capabilities of current laws.
    The leadership of Chairman Rockefeller and this committee, as well 
as the bipartisan effort that led to the creation and passage of the 
Pipeline Safety Act shows there is a common agreement about the 
importance of a safe and reliable pipeline system for the welfare of 
the Nation. PHMSA takes this responsibility very seriously. As the 
committee is aware, we have struggled to hire pipeline inspectors over 
the last several years, but by the end of FY 2012, we achieved and 
successfully filled our targeted 135 pipeline inspector billets. We now 
look forward to working with this committee to continue to strengthen 
our pipeline inspector program and further implement PHMSA's Pipeline 
Safety Reform effort.
    PHMSA not only completed all of the mandates that were due by 
January 3, 2013, it also completed additional mandates and performed 
more work than required. PHMSA has already successfully completed 16 of 
the 42 requirements in the Pipeline Safety Act. PHMSA has reported on 
cover over buried pipelines at river crossings, leak detection, remote 
controlled and automatic shut-off valve (RCV/ASV) use, increasing civil 
penalties authority, improved the quantity, quality, and transparency 
of our data, and inventoried the status of cast iron pipeline 
infrastructure. Information gathered from these reports will be used to 
inform us as we determine how best to move forward with updated 
requirements to address these topics.
    The following is a brief description of PHMSA's work the Pipeline 
Safety Act requirements:
Section 2--Civil Penalties
    The Act authorized PHMSA to increase the maximum civil penalty for 
pipeline safety violations from $100,000 to $200,000 per violation per 
day. In addition, the agency will be able to collect a maximum of 
$2,000,000 for a related series of violations, up from $1,000,000.
    PHMSA is currently addressing this activity through a rulemaking to 
update Part 190 of the Code of Federal Regulations. A Notice of 
Proposed Rulemaking (NPRM) entitled ``Administrative Procedures; 
Updates and Technical Corrections'' was published on August 13, 2012.
Section 3--Pipeline Damage Prevention
    The Act required PHMSA to incorporate new standards for state one-
call programs into the State Damage Prevention (SDP) grant program 
criteria, including no state and local exemptions.
    Some state excavation damage prevention laws include exemptions 
from one-call system participation that detract from the goals of the 
system. The following are examples of two typical types of exemption:

        Facility Owners--some state laws exempt owners of specific 
        types of underground facilities (e.g., municipalities, State 
        departments of transportation, and small water and sewer 
        companies from participation in the one-call system). 
        Excavators--some excavators (e.g., homeowners and State 
        departments of transportation) are exempted from calling for 
        underground facilities to be located and marked before they 
        begin digging. PHMSA has discussed these exemptions with the 
        National Association of Pipeline Safety Representatives (NAPSR) 
        and One Call Systems International (OCSI). A public meeting 
        regarding these issues is scheduled for March 2013. These new 
        requirements were included in the SDP grant program criteria.

    The Act also requires for PHMSA to conduct a study on the impact of 
excavation damage on pipeline safety, including exemptions, frequency, 
severity, and type of damage, and report these results to Congress.
    PHMSA met with the United States Infrastructure Corporation (USIC) 
to discuss performing a data analysis regarding damage prevention. As 
mentioned above, PHMSA is planning a public meeting in March 2013 to 
discuss damage prevention issues with industry stakeholders. PHMSA is 
considering using data from the Common Ground Alliance's (CGA's) Damage 
Information Reporting Tool (DIRT) to help with this study it will reach 
out to states to discuss the use of this data in the analysis.
Section 4--Automatic and Remote-Controlled Shut-Off Valve Use
    The Act requires PHMSA to issue regulations requiring the use of 
automatic or remote-control shut-off valves on transmission pipelines 
constructed or entirely replaced after the date of the rule, if 
appropriate.
    PHMSA began to collect information on the use of automatic shut-off 
valves (ASVs) and remote-controlled shut-off valves (RCVs) on hazardous 
liquid and gas transmission pipelines prior to the enactment of the 
Pipeline Safety Act, through issuance of two Advanced Notice of 
Proposed Rulemakings (ANPRM) entitled ``Safety of On-Shore Hazardous 
Liquid Pipelines'' and ``Safety of Gas Transmission Pipelines''. For 
hazardous liquid transmission pipelines, an ANPRM issued on October 18, 
2010, requested public comments on the use of RCVs. For gas 
transmission pipelines, an ANPRM issued on October 25, 2011, requested 
public comments on requiring the use of ASV and RCV installation.
    To gather sufficient input on ASV/RCV feasibility, PHMSA sponsored 
a public workshop on March 28, 2012 with the National Association of 
Pipeline Safety Representatives, entitled ``Understanding the 
Application of Automatic Control & Remote Control Valves.'' PHMSA then 
commissioned an independent study on the feasibility and effectiveness 
of ASVs and RCVs on hazardous liquid and natural gas transmission 
pipelines. Public comments and workshop input were used to develop the 
commissioned study entitled, ``Studies for the Requirements of 
Automatic and Remotely Controlled Shutoff Valves on Hazardous Liquid 
and Natural Gas Pipelines with Respect to Public and Environmental 
Safety'' (ASV-RCV study), including the original scope of work.
    The ASV-RCV study performed by the Oak Ridge National Laboratory, 
while not mandated by the Act, will help to determine the effectiveness 
of block valve closure swiftness in mitigating the consequences of 
natural gas and hazardous liquid pipeline releases on the safety of the 
public and the environment. Additionally, a related NTSB 
recommendation, NTSB P-11-11, was incorporated into the parameters of 
the study. The recommendation suggested ASVs and RCVs be required in 
high-consequence areas (HCAs). A public web-based seminar (webinar) and 
public comment period was also held for input on the draft study. The 
ASV-RCV study addressed the submitted comments and incorporated 
substantive technical recommendations. The ASV-RCV study, which is 344 
pages, was transmitted to Congress on December 27, 2012.
    The information from this study will assist in providing additional 
guidance for potential rulemaking. PHMSA also anticipates progressing 
with a rulemaking related to ASV and RCV installation and use on 
hazardous liquid and gas transmission pipelines in 2013.
    In addition, PHMSA is soliciting a research project specific to 
technology used in ASVs that will provide important insight on their 
ability to provide reliability and flow assurance to pipelines. 
Automatic shut-off valves are often recommended to minimize valve shut-
off times after a leak is detected. However, they may lead to 
unintended valve closures because of an inaccurate leak determination. 
The project aims to study and identify technologies and systems to 
minimize inaccurate leak alarms and unintended valve closures on ASV 
systems. .
Section 5--Integrity Management
    The Act required PHMSA to conduct an evaluation on whether 
integrity management programs (IMPs) should be expanded beyond high-
consequence areas (HCAs) and whether gas IMPs should replace the class 
location system. This section also asks, PHMSA to consider issuing 
regulations expanding IMP requirements and/or replacing class 
locations.
    As mentioned above, PHMSA initiated an ANPRM, entitled ``Safety of 
On-Shore Hazardous Liquid Pipelines'' and ``Safety of Gas Transmission 
Pipelines'' for both gas and liquid pipeline safety that addresses 
these issues. PHMSA is also holding an integrity management program 
(IMP) 2.0 workshop in 2013.
    This section of the statute also suggests that PHMSA may extend a 
gas pipeline operator's 7-year reassessment interval by 6 months if the 
operator submits written notice with sufficient justification of the 
need for an extension, and that PHMSA should publish guidance on what 
constitutes sufficient justification. PHMSA is currently considering 
this issue in the context of a gas transmission NPRM, which is a follow 
on from the ANPRM entitled ``Safety of Gas Transmission Pipelines'' 
mentioned above. PHMSA anticipates this NPRM to be published by August 
2013.
Section 6--Public Education and Awareness
    There were several mandates in this section of the Act. One mandate 
requires that PHMSA maintain a map of all gas HCAs as a part of the 
National Pipeline Mapping System (NPMS). PHMSA has already begun 
implementing this with the information we have currently available, and 
we are continuing to work on expanding the information available. PHMSA 
was also requested to update the NPMS map biennially.
    In addition, PHMSA was required to implement a program for 
promoting greater awareness of the NPMS to state and local emergency 
responders and other parties. To address this issue, PHMSA hosted a 
meeting of Public Safety and Emergency Response officials to discuss 
pipeline emergency preparedness and response on December 9, 2011. 
Additionally, PHMSA made contact with various emergency responder 
groups through its Emergency Responder (ER) Outreach program and the 
Community Assistance and Technical Services (CATS) program. PHMSA has 
also begun publishing articles regarding its public resources, 
including the NPMS, in ER publications. A brochure, designed for 
widespread distribution in the ER community, was also created that 
described available resources.
    PHMSA was also required to issue guidance to operators to provide 
system-specific information about their pipelines to emergency 
responders after consulting with those responders. This mandate fell 
closely in line with an NTSB recommendation (P-11-8), which recommended 
pipe diameter, operating pressure, product transported, and potential 
impact radius, among other information, is shared.
    PHMSA, in partnership with the Pipeline Emergency Response Working 
Group (PERWG), met with emergency responders at a pipeline emergency 
response focus group during the HOTZONE conference in Houston on 
October 19, 2012. The PERWG had its follow up meeting last week. On 
October 11, 2012, PHMSA published (Advisory Bulletin ADB-12-09) about 
Communication During Emergency Situations that reminds operators of 
gas, hazardous liquid, and liquefied natural gas pipeline facilities 
that operators should immediately and directly notify the Public Safety 
Access Point that serves the communities and jurisdictions in which 
those pipelines are located when there are indications of a pipeline 
facility emergency. We also met with the Associate of Public 
Communication Offices to discuss how to increase awareness and develop 
training for 911 center personnel.
    Additionally, PHMSA is funding a Transportation Research Board 
study that will produce a guide for communication between pipeline 
operators and emergency responders.
    PHMSA recognizes and agrees that the emergency response to an 
incident or a leak is critical. In addition to strengthening the 
capabilities of local emergency responders with increased coordination, 
targeted planning, and training grants. PHMSA has also worked to 
increase the visibility of prevention and response efforts to better 
prepare the public.
    The final mandate from this section required PHMSA to maintain the 
most recent oil facility response plans (FRPs), which are currently 
collected from operators and provide copies of those FRPs to any 
requester through the FOIA process. The copies can exclude sensitive 
information. PHMSA has implemented this mandate and continues to 
improve the FRP program.
Section 7--Cast Iron Gas Pipelines
    The Act required PHMSA to follow-up on the industry's progress in 
replacing cast iron gas pipelines. PHMSA has collected updates and has 
published the responses on its website which can be found at http://
opsweb.phmsa.dot.gov/pipelineforum/. This inventory was developed and 
posted before the December 31, 2012 due date.
Section 8--Leak Detection
    The Act requires PHMSA to submit a report to Congress on leak 
detection systems used by operators of hazardous liquid pipeline 
facilities and transportation related flow lines. The Act requires the 
following be included in the report:

   an analysis of the technical limitations of current leak 
        detection systems, including the ability of the systems to 
        detect ruptures and small leaks that are ongoing or 
        intermittent, and what can be done to foster development of 
        better technologies; and

   an analysis of the practicability of establishing 
        technically, operationally, and economically feasible standards 
        for the capability of such systems to detect leaks, and the 
        safety benefits and adverse consequences of requiring operators 
        to use leak detection systems.

    PHMSA began working on leak detection for a number of years before 
the Act. As mentioned above, on October 18, 2010, an ANPRM for the 
Safety of On-Shore Hazardous Liquid Pipelines was published. Among the 
issues discussed in the ANPRM was whether to establish and/or adopt 
standards and procedures for minimum leak detection requirements for 
all pipelines.
    In addition, PHMSA sponsored a public workshop in March 2012 with 
the National Association of Pipeline Safety Representatives entitled 
``Improving Pipeline Leak Detection System Effectiveness.'' It also 
held a Pipeline Research and Development (R&D) Forum in July 2012 that 
included a working group discussion focused specifically on leak 
detection and mitigation. As a result, PHMSA has issued a research 
announcement and solicitation for proposals for research and 
development on a number of topics, including leak detection. As part of 
its research and development activities, PHMSA has been active in 
studying and improving other leak detection technologies, including 
automated monitoring systems, sensors for small leak detection, aerial 
surveillance, satellite imaging, and improvements in the cost and 
effectiveness of current leak detection systems.
    As with valves, PHMSA also commissioned an independent study on 
leak detection. In conjunction with satisfying the requirements of the 
Act, PHMSA is also addressing a leak detection related recommendation 
for natural gas transmission and distribution pipelines from the NTSB 
(NTSB recommendation P-11-10, which involves Supervisory Control and 
Data Acquisition (SCADA) enhancements to Identify and Locate Leaks). 
PHMSA's leak detection work included systems used in gas transmission 
and distribution pipelines as well as hazardous liquid pipelines. While 
the different types of pipeline systems have various and distinct 
characteristics and considerations for leak detection, PHMSA brought 
all pipeline industry stakeholders together to more efficiently 
communicate the issues affecting the respective sectors and to share 
lessons learned.
    The review of leak detection systems was not limited to the 
technology but also extended to pipeline facilities and infrastructure. 
Effective leak detection relies heavily on how well any technology is 
implemented through people, procedures, and the environment in which it 
is installed and operated.
    The leak detection study performed was based on input received 
through the workshops and a public comment period for the original 
scope of work. A public web-based seminar (webinar) and public comment 
period was also held for input on the draft report of the study. 
Additionally, some operators were interviewed as part of the work. The 
final leak detection study, which is almost 300 pages, has been posted 
electronically for review and has been transmitted to Congress.
    PHMSA will use all of the input gathered from the above initiatives 
as well as other data when considering any future rulemakings. A 
rulemaking is under consideration for this item.
    PHMSA is also creating a Leak Detection webpage on the PHMSA 
website to provide background information about leak detection issues.
Section 9--Accident and Investigation Notification
    PHMSA was required by the Act to revise regulations to require 
telephonic reporting of incidents or accidents not later than 1 hour 
following a ``confirmed discovery'' and to require revising the initial 
telephonic report after 48 hours if practicable. An NPRM entitled 
``Miscellaneous Rule II'' regarding these revisions is expected to be 
issued in late 2013.
    The Act also requires PHMSA to review and revise, as necessary, 
procedures for operators and the National Response Center (NRC) to 
notify emergency responders, including local public safety answering 
points or 911 centers. PHMSA is continuing to develop a means to 
address this issue.
Section 10--Transportation-Related Onshore Facility Response Plan 
        Compliance
Administrative Enforcement and Civil Penalties
    While there was no specific mandate with this item, the section did 
suggest that PHMSA should update Part 190 to be consistent with the new 
authority to enforce Part 194 regulations. A rulemaking entitled 
``Administrative Procedures; Updates and Technical Corrections'' is 
under consideration for this item.
Section 11--Pipeline Infrastructure Data Collection
    PHMSA is considering collecting other geospatial and technical data 
for the NPMS. Although there was no specific mandate for this action, 
as mentioned in Section 11 above, a rulemaking is under consideration 
for this item.
Section 12--Transportation-Related Oil Flow Lines
    There is no mandate related to this section, but PHMSA is 
considering collecting geospatial and other data on transportation-
related oil flow lines, as mentioned in Section 11 above, as defined in 
the Act.
Section 13--Cost Recovery for Design Reviews
    PHMSA was required to prescribe a fee structure and procedures for 
assessment and collection in order to implement authority to recover 
design review costs for projects that cost over $2.5 billion or that 
involve ``new technologies.'' PHMSA is currently developing guidance on 
this issue.
    This section also mandates that PHMSA issue guidance on the meaning 
of the term ``new technologies.'' This guidance was completed and was 
posted on the external PHMSA website prior to the January 3, 2013 
deadline.
Section 15--Carbon Dioxide Pipelines
    The Act requires that PHMSA issue regulations for transporting 
carbon dioxide by pipeline in a gaseous state. PHMSA is currently 
exploring rulemaking options with this item.
Section 16--Study of Transportation of Diluted Bitumen
    PHMSA was required to review and report to Congress on whether 
current regulations are sufficient to regulate pipelines transporting 
diluted bitumen. A study has been contracted to perform this analysis 
to the National Academy of Sciences (NAS), which is meeting on the 
issue on January 31 and February 1, 2013, and it is on track for timely 
completion. Once the study is completed, a report to Congress will 
follow.
Section 17--Study of Nonpetroleum Hazardous Liquids Transported by 
        Pipeline
    This section allows PHMSA to analyze the extent to which pipelines 
transporting non-petroleum hazardous liquids, such as chlorine, are 
unregulated, and whether being unregulated presents risks to the 
public. The results of any analysis must be made available to Congress 
as directed by the Act. PHMSA is currently reviewing this issue.
Section 19--Maintenance of Effort
    PHMSA was required to grant waivers of the maintenance of effort 
clause in FY12 and FY13 to States that demonstrate an inability to 
maintain funding to their pipeline safety program due to economic 
hardship. This action has been completed for FY12, and we are 
addressing this issue as it pertains to future years.
Section 20--Administrative Enforcement Process
    This section requires PHMSA to issue regulations for enforcement 
hearings that require a presiding official, implement a separation of 
functions, prohibit ex parte communications and provide other due 
process provisions. This issue is currently being addressed in the Part 
190 Rule referred to in Section 20 above. The NPRM entitled 
``Administrative Procedures; Updates and Technical Corrections'' was 
published on August 13, 2012.
Section 21--Gas and Hazardous Liquid Gathering Lines
    The Act requires PHMSA to review and report to Congress on existing 
Federal and State regulations for all gathering lines, existing 
exemptions, and the application of existing regulations to lines not 
presently regulated. PHMSA has contracted Oak Ridge National to assist 
in the research of this issue and a report is under development.
    PHMSA must also consider issuing regulations that would subject 
offshore liquid gathering lines to the same standards as other liquid 
gathering lines. PHMSA will determine whether these regulations are 
necessary based on the results of the research and report.
Section 22--Excess Flow Valves
    The Act requires PHMSA to consider issuing regulations requiring 
the use of excess flow valves on new or entirely replaced distribution 
branch services, multi-family facilities, and small commercial 
facilities. PHMSA issued an ANPRM entitled ``Expanding the Use of 
Excess Flow Valves in Gas Distribution Systems to Applications Other 
Than Single-Family Residences '' on November 25, 2011 and is currently 
analyzing public comments.
Section 23--Maximum Allowable Operating Pressure (MAOP)
    PHMSA was required to issue an Advisory Bulletin regarding the 
existing requirements to verify records confirming MAOP in Classes 3 
and 4 and in HCAs. An Advisory Bulletin on ``Verification of Records'' 
was issued for this item on May 7, 2012.
    PHMSA was also required to issue regulations requiring operators to 
report by July 3, 2013, any pipelines without sufficient records to 
confirm MAOP. As part of meeting the mandate, PHMSA determined they had 
the authority under existing regulations to collect this additional 
data. Therefore, PHMSA revised its gas transmission annual reporting 
form to collect this information which we will receive for the first 
time on June 15, 2013. The information collected will be used to 
address the mandate in the Act.
    This section also required PHMSA to issue regulations that require 
operators to report any exceedance of MAOP within 5 days, and to ensure 
the safety of pipelines without records to confirm MAOP. PHMSA 
published an advisory bulletin in the Federal Register on December 21, 
2012 on Reporting the Exceedances of Maximum Allowable Operating 
Pressure (ADB-2012-11). A rulemaking is under consideration for this 
item.
    PHMSA was also required to issue regulations requiring tests to 
confirm the material strength of previously untested gas transmission 
pipelines in HCAs. As part of meeting the mandate, PHMSA determined 
they had the authority under existing regulations to collect this 
additional data. PHMSA will use its revised gas transmission annual 
report to collect this relevant data by June 15, 2013. This information 
will be used to meet the mandate in the Act.
Section 24--Limitation of Incorporation of Documents by Reference
    This section requires PHMSA, starting in one year, to stop 
incorporating by reference into its regulations or guidance materials 
any industry standard unless it is publicly available free of charge on 
the internet. PHMSA is continuing to work with organizations that 
develop standards in order to make Incorporation-By-Reference (IBR) 
material available for free on the Internet. We are pleased that many 
standards setting organizations have agreed and are assisting PHMSA in 
complying with this item.
Section 28--Cover Over Buried Pipelines
    PHMSA was required to conduct a study and report to Congress on 
hazardous liquid pipeline accidents at water crossings to determine if 
depth of cover was a factor. This study was completed and was 
transmitted to Congress before the January 3, 2013, deadline.
    If the study shows depth of cover was a factor, PHMSA must review 
the sufficiency of existing depth of cover regulations and consider 
possible regulatory changes and/or legislative recommendations. The 
Administration is still determining whether legislative changes should 
be recommended.
Section 29--Seismicity
    There was no specific mandate within this section, but it was 
suggested that PHMSA should issue regulations to be consistent with the 
requirement in statute that operators consider seismicity in 
identifying and evaluating all potential threats to each pipeline 
pursuant to Parts 192 and 195. PHMSA has conducted research on this 
issue, which is currently under review.
Section 30--Tribal Consultation for Pipeline Projects
    The Act requires PHMSA to develop and implement a protocol for 
consulting with Indian tribes to provide technical assistance for the 
regulation of pipelines that are under the jurisdiction of Indian 
tribes. This protocol was posted on the PHMSA website prior to the 
January 3, 2013, deadline.
Section 31--Pipeline Inspection and Enforcement Needs
    PHMSA was required to report to Congress on the total number of 
full-time equivalents (FTEs) for pipeline inspection and enforcement, 
the number of such FTEs that are not presently filled and the reasons 
they are not filled, the actions being taken to fill the FTEs, and any 
additional resources needed. This action has been completed by PHMSA, 
and a report was submitted to Congress on December 20, 2012.
Section 32--Authorization of Appropriations
    This section of the act required PHMSA to ensure at least 30 
percent of the costs of program-wide Research and Development (R&D) 
activities are carried out using non-Federal sources. These efforts are 
currently ongoing and are on-track.
    This section additionally mandates that PHMSA transmit a report to 
Congress on the status and results-to-date of implementation of the R&D 
program every 2 years. The R&D program is designed to identify gaps in 
needed pipeline technology and map a path forward to assure there is no 
duplicative research and that resources are leveraged appropriately. 
PHMSA is finalizing a draft of this report.
III. Sissonville and the Challenges We Face
    Despite our successes, we continue to face challenges in fulfilling 
our mission, and this is obvious when taking a look at what happened in 
Sissonville, WV. The explosion at Sissonville, as Chairman Rockefeller 
has said, was terrible, serious, and dangerous. Although several homes 
were destroyed or damaged, and portions of a major interstate highway 
were severely damaged, it is fortunate that no one was killed and there 
were only minor injuries. It could have been a much larger tragedy. We 
are working closely with the National Transportation Safety Board 
(NTSB) and the Public Service Commission of West Virginia in the 
investigation, and we are also undertaking our own compliance 
investigation. In addition we are taking immediate action to determine 
what additional steps need to be taken to prevent accidents like this 
from occurring in the future.
    We have issued a Corrective Action Order (CAO) based on our 
preliminary findings. The pipeline will not be placed back into service 
until we are completely satisfied with the restart plan that Columbia 
Gas is required to submit. When the pipeline is eventually placed back 
into service, it will operate at a 20 percent pressure reduction from 
the maximum allowable pressure, while our engineers oversee a series of 
tests and evaluations and review the results. It is only after PHMSA is 
fully satisfied that the pipeline is safe for full operation that the 
pipeline can return to regular operating pressure.
    One of the greatest challenges that we as an organization face is 
assisting our State partners to succeed in the inspection, regulation, 
and enforcement of the pipelines for which they are responsible. With 
the exception of Alaska and Hawaii, State pipeline safety agencies are 
the first line of defense in protecting the American public, and they 
have always been a critical component of PHMSA's success.
    Thanks to provisions in the Act, we are currently able to cover 77 
percent, or approximately $43.5 million, of the program costs that 
States incur. This funding covers personnel and equipment needs, public 
outreach programs, and other activities that allow the States to 
inspect and regulate intrastate pipelines. Currently, we partner with 
52 state pipeline safety programs through certification and agreements 
for the inspection of the Nation's intrastate gas and hazardous liquid 
pipelines. PHMSA also has interstate agent agreements with 10 states to 
perform interstate pipeline inspections. We are pleased to report that 
the State of West Virginia participates as an interstate pipeline agent 
for gas transmission lines. This partnership has proven to be a great 
asset in helping to strengthen the safety of pipelines in West 
Virginian communities.
    The day this incident happened, several of my top staff members and 
I were visiting the Marcellus Shale area. We received a call that 
alerted us to the incident, and we were able to launch our response 
from the meeting we were conducting in Pennsylvania. Tim Butters, my 
Deputy Administrator, was in contact with emergency response officials 
from Sissonville shortly after the explosion occurred. It is because of 
the great relationship PHMSA and our State partners have with the 
pipeline industry and emergency responder community that we were 
contacted directly for support. PHMSA exists for the safety of the 
public, and we have been involved from the onset of this incident up 
through this point in time. We continue to support our fellow partners 
on the ground at the incident. As well as work with the emergency 
response community in order to share best practices and lessons 
learned.
    In fact, we recently returned to Sissonville to meet with the local 
emergency responders and emergency management officials of Sissonville 
and Kanawha County to discuss the response to this incident, and what 
prior interaction they had with the operator.
    We were very encouraged to learn that there was a good working 
relationship with the utility operator and the local public safety 
community. These established relationships, coupled with the fact that 
the local responders were well-trained, made it possible for the 
successful and effective management of this incident. The fact that 
there were only minor civilian injuries and no injuries to emergency 
responders is a testament to the capability of the local emergency 
response system and the importance of cooperation with the pipeline 
industry, and Federal and state regulators.
    However, we also learned there is still much work to do. Both the 
pipeline operators and local officials recognize that additional 
training and exercises are needed. As the statute now requires, 
operators will be providing more detailed information about their 
pipeline systems, including location, size of pipe, and other critical 
elements. A rulemaking is under consideration that will allow PHMSA to 
collect additional information as part of its emergency responder 
outreach program. While Columbia Gas had been engaged with the local 
community, we were informed that cooperation and coordination between 
the local community and other pipeline operators could be improved. We 
will do what is necessary to ensure that this is corrected as quickly 
as possible.
    We always make an aggressive effort to apply the information from 
specific pipeline incidents to the broader, national context of 
pipeline safety. We accelerated the implementation of control room 
management regulations based upon lessons learned about supervisory 
control and data acquisition (SCADA) system challenges. This year we 
will hold a public workshop to evaluate lessons learned during the last 
ten years of performance based integrity management regulations.
    Lessons we learn from the Sissonville incident will also be used to 
help prevent accidents in other communities and will help us continue 
to fulfill the safety goals and purpose of the Act. Once our 
investigations into this incident are complete, we will release our 
findings and information to the larger emergency responder community 
and operator network.
IV. Changing Infrastructure and the Importance of Oversight
    Much like the members of this Committee, this Administration has 
recognized the need for an aggressive approach to the safety of the 
Nation's pipeline system and the Fiscal Year 2013 Budget includes a 
funding request to implement an aggressive Pipeline Safety Reform 
initiative, which seeks to significantly increase both Federal and 
State resources supporting pipeline safety, as well as furthering 
research and development, and enhancing information technology 
capabilities to address the safety of the national pipeline system. We 
just recently received the final GAO study on the ability of 
transmission pipeline facility operators to respond to a hazardous 
liquid or gas release. We are currently reviewing the findings and will 
be happy to discuss with your staff on how we plan to move forward.
    From the discovery of vast energy shale deposits, which will 
require the creation of additional infrastructure, to the maintenance 
and rehabilitation of the infrastructure already in place, the Nation's 
infrastructure needs are growing and changing.
    I have been to the Bakken and Marcellus Shales, and I have seen 
these changes and the evolution of the energy industry firsthand. And I 
can tell you that we must prepare for these new and shifting demands 
right now. We must make sure that people and the land are protected at 
the beginning of the process even before the pipe goes in the ground. 
Effective standards and regulations are one of the best ways to keep 
America's people and environment safe while providing for the reliable 
transportation of the Nation's energy supplies, and the oversight 
provided by PHMSA and our partners will become even more critically 
important in the future.
    With that being said, I believe that the Pipeline Safety Act, and 
our outreach and oversight, is working. We have a long way to go to 
reach our goal of no deaths, injuries, environmental and property 
damage, or transportation disruptions, but we have a solid foundation 
to build on as we continue to advance pipeline safety.
    In closing, we look forward to continuing to work with Congress to 
address pipeline safety issues and to improve pipeline safety programs. 
Together, we will keep America's people and environment safe while 
providing for the reliable transportation of the Nation's energy 
supplies. Everyone at PHMSA is dedicated and committed to fulfilling 
the remaining mandates and accomplishing our pipeline safety mission. 
It is an honor to serve the American people and to work with the 
dedicated public servants at PHMSA. Thank you again for the opportunity 
to speak with you today. I would be pleased to answer any questions you 
may have.

    The Chairman. Thank you very much, Ms. Quarterman.
    And now we will go to Ms. Susan Fleming, who is Director of 
the Physical Infrastructure Issues at the United States 
Government Accountability Office.

       STATEMENT OF SUSAN A. FLEMING, DIRECTOR, PHYSICAL

  INFRASTRUCTURE ISSUES, U.S. GOVERNMENT ACCOUNTABILITY OFFICE

    Ms. Fleming. Mr. Chairman, I'd also like to add my 
appreciation for your leadership on pipeline safety and all the 
range of transportation issues this committee covers and for 
your kind words on GAO. I appreciate that.
    I very much appreciate the opportunity to be here in West 
Virginia to discuss pipeline safety and incident response. As 
the recent transmission pipeline incident in Sissonville 
demonstrates, while pipelines are considered the safest means 
of transporting natural gas and hazardous liquids, pipeline 
incidents can and do occur.
    The speed of a pipeline operator's response is critical to 
reduce the consequences of an incident. My statement is based 
on a recent report to the Committee covering variables that 
affect pipeline operator's ability to respond quickly to a 
response and opportunities we identified to measure and improve 
these operator's incident response times.
    First, a number of variables, only some of which are within 
an operator's control can influence operator response time. For 
example, weather conditions and time of day are variables 
beyond an operator's control. Factors within an operator's 
control include the operator's leak detection capabilities, 
proximity of operator response personnel, the type of valve 
installed, automated or manual, and relationships with local 
first responders.
    These factors affect incident response time to varying 
degrees depending on the specific incident. Given the 
Committee's interest in the topic of automated valves I'd like 
to take a moment to discuss that factor. PHMSA, which oversees 
pipeline safety, does not mandate the installation of automated 
valves but does require that such valves be considered as part 
of an operator's risk assessment for pipeline segments in 
highly populated or environmentally sensitive areas.
    The primary potential advantage of installing these valves, 
whether automatic shutoff or remote controlled, is the speed 
they provide in isolating a pipeline segment. However, one 
potential downside of these valves is the risk of accidental 
valve closure which could lead to loss of service to customers.
    The potential advantages and disadvantages of installing 
automated valves can vary based on the unique attributes of the 
valve's location. Therefore we concluded that the decision of 
whether to install automated valves should be made on a case-
by-case basis. For example, if a valve is located at an 
operator's facility that is staffed 24 hours a day, a manual 
valve might be sufficient.
    We found that most operators are currently making these 
decisions on a case-by-case basis and are using a variety of 
risk-based frameworks including decision tree and spill 
modeling software to aid in their decisionmaking.
    Moving on to my second point, we identified potential 
opportunities for PHMSA to improve incident response time in 
two areas, performance-based requirements and information 
sharing. We and others have recommended that the Federal 
government move toward a more performance-based regulatory 
approach to allow those being regulated to determine the most 
appropriate way to achieve desired measurable outcomes.
    PHMSA does not currently have a specific measurable 
response time requirement and told us that creating such a 
requirement would be difficult due to the often unique nature 
of incidents. However, some organizations in the pipeline 
industry have recently developed such a framework for incident 
response times. Therefore, we believe that the PHMSA should 
consider moving toward a more quantifiable performance-based 
goal in this area.
    To do so PHMSA would first need to collect reliable data on 
incident response times. This data would allow PHMSA to measure 
incident response time and assist the agency in considering 
development of a performance-based approach for improvements.
    In addition to reliable data, a performance-based approach 
would require strong oversight from PHMSA. PHMSA can further 
support improvements and response time by helping operators 
make more informed decisions on the use of automated valves 
through enhanced guidance and broader sharing of decision 
analysis methods used by operators.
    In closing, improvements to incident response time can be 
achieved in a variety of ways. One solution may not be 
appropriate for all situations and locations. A performance-
based framework, along with better data collection and 
communication could help both PHMSA and pipeline operators make 
evidence-based decisions on how and where to best apply 
resources to improve incident response time.
    Mr. Chairman, this concludes my statement, and I would be 
pleased to answer questions you or Senator Manchin might have.
    [The prepared statement of Ms. Fleming follows:]

      Prepared Statement of Susan A. Fleming, Director, Physical 
      Infrastructure Issues, U.S. Government Accountability Office
    Chairman Rockefeller and Members of the Committee:

    Thank you for the opportunity to participate in this hearing on 
pipeline safety. As you know, pipelines are a relatively safe means of 
transporting natural gas and hazardous liquids; however, catastrophic 
incidents can and do occur.\1\ We are here today because such an 
incident occurred on December 11, 2012, near Sissonville, West 
Virginia, when a rupture of a natural gas transmission pipeline 
destroyed or damaged 9 homes and badly damaged a section of Interstate 
77. Large-diameter transmission pipelines such as these that carry 
products over long distances from processing facilities to communities 
and large-volume users make up more than 400,000 miles of the 2.5 
million mile natural gas and hazardous liquid pipeline network in the 
United States.\2\ The Department of Transportation's (DOT) Pipeline and 
Hazardous Materials Safety Administration (PHMSA), working in 
conjunction with state pipeline safety offices, oversees this network, 
which transports about 65 percent of the energy we consume.
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    \1\ In its regulations, PHMSA refers to the release of natural gas 
from a pipeline as an ``incident'' (49 C.F.R. Sec. 191.3) and a spill 
from a hazardous liquid pipeline as an ``accident.'' (49 C.F.R. 
Sec. 195.50). For simplicity, this statement refers to both as 
``incidents.''
    \2\ This statement uses the term ``transmission pipeline'' to refer 
to both onshore hazardous liquid and natural gas pipelines carrying 
product over long distances to users.
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    The best way to ensure the safety of pipelines, and their 
surrounding communities, is to minimize the possibility of an incident 
occurring. PHMSA's regulations require pipeline operators to take 
appropriate preventive measures such as corrosion control and periodic 
assessments of pipeline integrity. To mitigate the consequences if an 
incident occurs, operators are also required to develop leak detection 
and emergency response plans. One mitigation measure operators can take 
is to install automated valves that, in the event of an incident, close 
automatically or can be closed remotely by operators in a control 
room.\3\ Such valves have been the topic of several National 
Transportation Safety Board (NTSB) recommendations since 1971 and a 
PHMSA report issued in October 2012.\4\
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    \3\ For the purposes of this statement, the term ``install an 
automated valve'' refers to any actions that allow the operator to 
remotely or automatically close a valve. Such actions do not 
necessarily mean an operator is installing a completely new valve. For 
example, operators may install an actuator and communications at an 
existing valve location.
    \4\ Oak Ridge National Laboratory, Studies for the Requirements of 
Automatic and Remotely Controlled Shutoff Valves on Hazardous Liquids 
and Natural Gas Pipelines with Respect to Public and Environmental 
Safety, ORNL/TM-2012/411 (Oct. 31, 2012). The study was conducted 
pursuant to the Pipeline Safety, Regulatory Certainty, and Job Creation 
Act of 2011, which directed the Secretary of Transportation to consider 
additional regulations requiring the use of automated valves where 
economically, technically, and operationally feasible on new 
transmission facilities. Pub. L. No. 112-90, Sec. 4, 125 Stat. 1904, 
1906 (2012).
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    As mandated in the Pipeline Safety, Regulatory Certainty, and Job 
Creation Act of 2011, we issued a January 2013 report on the ability of 
transmission pipeline operators to respond to a hazardous liquid or 
natural gas release from an existing pipeline segment.\5\ My statement 
today is based on this report and addresses (1) variables that 
influence the ability of transmission pipeline operators to respond to 
incidents and (2) opportunities to improve these operators' responses 
to incidents. My statement also provides information from two other 
recent GAO reports on pipeline safety (see app. I). For our January 
2013 report, we examined incident data, conducted a literature review, 
and interviewed selected operators, industry stakeholders, state 
pipeline safety offices, and PHMSA officials. Our work on each pipeline 
safety report was conducted in accordance with generally accepted 
government auditing standards. Those standards require that we plan and 
perform the audit to obtain sufficient, appropriate evidence to provide 
a reasonable basis for our findings and conclusions based on our audit 
objectives. We believe that the evidence obtained provides a reasonable 
basis for our findings and conclusions based on our audit objectives.
---------------------------------------------------------------------------
    \5\ GAO, Pipeline Safety: Better Data and Guidance Needed to 
Improve Pipeline Operator Incident Response, GAO-13-168 (Washington, 
D.C.: Jan. 23, 2013).
---------------------------------------------------------------------------
Summary
    Numerous variables--some of which are under operators' control--
influence the ability of transmission pipeline operators to respond to 
incidents. For example, the location of response personnel and the use 
of manual or automated valves can affect the amount of time it takes 
for operators to respond to incidents. However, because the advantages 
and disadvantages of installing an automated valve are closely related 
to the specifics of the valve's location, it is appropriate that 
operators decide whether to install automated valves on a case-by-case 
basis. Several operators we spoke with have developed approaches to 
evaluate the advantages and disadvantages of installing automated 
valves, such as using spill-modeling software to estimate the potential 
amount of product released and extent of damage that would occur in the 
event of an incident.
    One method PHMSA could use to improve operator response to 
incidents is to develop a performance-based approach for incident 
response times. While defining performance measures and targets for 
incident response can be challenging, PHMSA could move toward a 
performance-based approach by evaluating nationwide data to determine 
response times for different types of pipeline (based on location, 
operating pressure, and pipeline diameter, among other factors). First, 
though, PHMSA must improve the data it collects on incident response 
times. These data are not reliable because operators are not required 
to fill out certain time-related fields in the reporting form and 
because operators told us they interpret these data fields in different 
ways. Furthermore, while PHMSA conducts a variety of information-
sharing activities, the agency does not formally collect or share 
evaluation approaches used by operators to decide whether to install 
automated valves, and not all operators we spoke with were aware of 
existing PHMSA guidance designed to assist operators in making these 
decisions. We recommended that PHMSA should: (1) improve incident 
response data and use those data to explore the feasibility of 
developing a performance-based approach for improving operators' 
responses to pipeline incidents and (2) assist operators in deciding 
whether to install automated valves by formally collecting and sharing 
evaluation approaches and ensuring operators are aware of existing 
guidance. PHMSA agreed to consider these recommendations.
Background
    Three main types of pipelines--gathering, transmission, and 
distribution--carry hazardous liquid and natural gas from producing 
wells to end users (residences and businesses) and are managed by about 
3,000 operators. Transmission pipelines carry these products, sometimes 
over hundreds of miles, to communities and large-volume users, such as 
factories. Transmission pipelines tend to have the largest diameters 
and operate at the highest pressures of any type of pipeline. PHMSA has 
estimated there are more than 400,000 miles of hazardous liquid and 
natural gas transmission pipelines across the United States.
    PHMSA administers two general sets of pipeline safety requirements 
and works with state pipeline safety offices to inspect pipelines and 
enforce the requirements. The first set of requirements is minimum 
safety standards that cover specifications for the design, 
construction, testing, inspection, operation, and maintenance of 
pipelines. The second set is part of a supplemental risk-based 
regulatory program termed ``integrity management.'' Under transmission 
pipeline integrity management programs, operators are required to 
systematically identify and mitigate risks to pipeline segments that 
are located in highly populated or environmentally sensitive areas 
(called ``high-consequence areas'').\6\
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    \6\ ``High-consequence areas'' are defined differently for 
hazardous liquid and natural gas. For natural gas, such areas typically 
include highly populated or frequented areas, such as parks. For 
hazardous liquid, high-consequence areas include highly populated 
areas, other populated areas, navigable waterways, and areas unusually 
sensitive to environmental damage.
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    According to PHMSA, industry, and state officials, responding to 
either a hazardous liquid or natural gas pipeline incident typically 
includes detecting that an incident has occurred, coordinating with 
emergency responders, and shutting down the affected pipeline segment. 
Under PHMSA's minimum safety standards, operators are required to have 
a plan that covers these steps for all of their pipeline segments and 
to follow that plan during an incident. Officials from PHMSA and state 
pipeline safety offices perform relatively minor roles during an 
incident, as they rely on operators and emergency responders to take 
actions to mitigate the consequences of such events. Operators must 
report incidents that meet certain thresholds--including incidents that 
involve a fatality or injury, excessive property damage or product 
release, or an emergency shutdown--to the Federal National Response 
Center.\7\ Operators must also conduct an investigation to identify the 
root cause and lessons learned, and report to PHMSA. Federal and state 
authorities may use their discretion to investigate some incidents, 
which can involve working with operators to determine the cause of the 
incident.\8\
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    \7\ The National Response Center, managed by the United States 
Coast Guard, is the sole Federal point of contact for reporting oil and 
chemical spills.
    \8\ PHMSA may conduct an incident investigation in instances when 
an NTSB investigation is also under way. In such cases, PHMSA does not 
determine the cause of the incident; rather its review is to determine 
regulatory compliance.
---------------------------------------------------------------------------
    While prior research shows that most of the fatalities and damage 
from an incident occur in the first few minutes following a pipeline 
rupture, operators can reduce some of the consequences by taking 
actions that include closing valves that are spaced along the pipeline 
to isolate segments. The amount of time it takes to close a valve 
depends upon the equipment installed on the pipeline. For example, 
valves with manual controls (referred to as ``manual valves'') require 
a person to arrive on site and either turn a wheel crank or activate a 
push-button actuator. Valves that can be closed without a person at the 
valve's location (referred to as ``automated valves'') include remote-
control valves, which can be closed via a command from a control room, 
and automatic-shutoff valves, which can close without human 
intervention based on sensor readings.\9\ Automated valves generally 
take less time to close than manual valves. PHMSA's minimum safety 
standards dictate the spacing of all valves, regardless of type of 
equipment installed to close them,\10\ while integrity management 
regulations require that transmission pipeline operators conduct a risk 
assessment for pipelines in high-consequence areas that includes the 
consideration of automated valves.
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    \9\ Hazardous liquid regulations refer to emergency flow 
restriction devices, which include remote-control valves and ``check'' 
valves that automatically prevent product from flowing in a specific 
direction. See 49 C.F.R. Sec. 195.452(i)(4). We refer to all of these 
valves as automated valves.
    \10\ 49 C.F.R. Sec. Sec. 192.179, 195.260.
---------------------------------------------------------------------------
Incident Response Time Depends on Multiple Variables, Including the Use 
        of Automated Valves
    Multiple variables--some controllable by transmission pipeline 
operators--can influence the ability of operators to respond quickly to 
an incident, according to PHMSA officials, pipeline safety officials, 
and industry stakeholders and operators. Ensuring a quick response is 
important because according to pipeline operators and industry 
stakeholders, reducing the amount of time it takes to respond to an 
incident can reduce the amount of property and environmental damage 
stemming from an incident and, in some cases, the number of fatalities 
and injuries. For example, several natural gas pipeline operators noted 
that a faster incident response time could reduce the amount of 
property damage from secondary fires (after an initial pipeline 
rupture) by allowing fire departments to extinguish the fires sooner. 
In addition, hazardous liquid pipeline operators told us that a faster 
incident response time could result in lower costs for environmental 
remediation efforts and less product lost. We identified five variables 
that can influence incident response time and are within an operator's 
control, and four other variables that influence a pipeline operator's 
ability to respond to an incident but are beyond an operator's control. 
The effect a given variable has on a particular incident response will 
vary according to the specifics of the situation. The five variables 
within an operator's control are:

   leak detection capabilities,

   location of qualified operator response personnel,

   type of valve,

   control room management, and

   relationships with local first responders.

    The four factors beyond an operator's control are:

   type of release,

   time of day,

   weather conditions, and

   other operators' pipelines in the same area.

    (See table 1 for further detail.) Appendix II provides several 
examples of response time in past incidents; response time varied from 
several minutes to days depending on the presence and interaction of 
the variables just mentioned.



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   Table 1.--Variables Influencing Pipeline Operator Incident Response
                                  Times
------------------------------------------------------------------------
   Variables within an operator's       Variables beyond an operator's
              control                              control
------------------------------------------------------------------------
 Leak detection               Type of release (leak vs.
 capabilities. Pipeline operators     rupture). Leaks are generally a
 perform a variety of leak            slow release of product over a
 detection activities to monitor      small area, which can go
 their systems and identify leaks,    undetected for long periods. Once
 including periodic external          a leak is detected, it can take
 monitoring, such as aerial patrols   additional time to confirm the
 of the pipeline, as well as          exact location. Ruptures, which
 continuous internal monitoring,      usually produce more significant
 such as measuring the intake and     changes in the external or
 outtake volumes or pressure flows    internal conditions of the
 in the pipeline.                     pipeline, are typically easier to
 Location of qualified        detect and locate.
 operator response personnel.         Time of day. The
 Response personnel who have a        operator's response personnel may
 greater distance to travel to the    be delayed in reaching facilities
 facility or valve site can take      in urban or suburban areas during
 longer to establish an incident      peak traffic times. Conversely, if
 command center or to close manual    an incident occurs during the
 valves.                              evening or on a weekend, the
 Type of valves. Automated    operator's response personnel
 valves, which can be closed          could be able to reach the
 automatically or remotely, can       facility more quickly, because of
 shorten incident response time       lighter traffic.
 compared to manual valves, which     Weather conditions.
 require that personnel travel to     Weather-such as storms, winter
 the valve site and turn a wheel      conditions, and wind-can affect
 crank or activate a push-button      how quickly an operator can detect
 actuator to close the valve.         and respond to pipeline incidents.
 Control room management.     Other operators' pipelines
 Clear operating policies and         in the same area. If two or more
 shutdown protocols for control       operators own pipeline in a shared
 room personnel can influence         right of way determining whose
 response time to incidents. For      system is affected can increase
 example, incident response time      incident response time.
 might be reduced if control room
 personnel have the authority to
 shut down a pipeline or facility
 if a leak is suspected, and are
 encouraged to do so.
 Relationships with local
 first responders. Operators that
 have already established effective
 communications with local first
 responders-such as fire and police
 departments-may respond more
 quickly during emergencies.
------------------------------------------------------------------------
Source: GAO analysis of information from PHMSA officials, pipeline
  safety officials, and industry stakeholders and operators.

    As noted, one variable that influences operators' response times to 
incidents is the type of valve installed on the pipeline. Research and 
industry stakeholders indicate that the primary advantage of installing 
automated valves--as opposed to other safety measures--is related to 
the time it takes to respond to an incident. Although automated valves 
cannot mitigate the fatalities, injuries, and damage that occur in an 
initial blast, quickly isolating the pipeline segment through automated 
valves can reduce subsequent damage by reducing the amount of hazardous 
liquid and natural gas released.
    Research and industry stakeholders also identified two 
disadvantages operators should consider when determining whether to 
install automated valves related to potential accidental closures and 
the monetary costs of purchasing and installing the equipment. 
Specifically, automated valves can lead to accidental closures, which 
can have severe, unintended consequences, including loss of service to 
residences and businesses. In addition, according to operators, vendors 
and contractors, the monetary costs of installing automated valves can 
range from tens of thousands to a million dollars per valve,\11\ which 
may be significant expenditures for some pipeline operators. According 
to operators and other industry stakeholders, considering monetary 
costs is important when making decisions to install automated valves 
because resources spent for this purpose can take away from other 
pipeline safety efforts. Specifically, operators and industry 
stakeholders told us they often would rather focus their resources on 
incident prevention to minimize the risk of an incident instead of 
focusing resources on incident response. PHMSA officials stated that 
they generally support the idea that pipeline operators be given some 
flexibility to target spending where the operator believes it will have 
the most safety benefit.
---------------------------------------------------------------------------
    \11\ The cost of installing an automated valve ranges depending on 
the location and size of the pipeline and the type of equipment being 
installed, among other things.
---------------------------------------------------------------------------
    Research and industry stakeholders also indicate the importance of 
determining whether to install valves on a case-by-case basis because 
the advantages and disadvantages can vary considerably based on factors 
specific to a unique valve location. These sources indicated that the 
location of the valve, existing shutdown capabilities, proximity of 
personnel to the valve's location, the likelihood of an ignition, type 
of product being transported, operating pressure, topography, and 
pipeline diameter, among other factors, all play a role in determining 
the extent to which an automated valve would be advantageous.
    Operators we met with are using a variety of methods for 
determining whether to install automated valves that consider--on a 
case-by-case basis--whether these valves will improve response time, 
the potential for accidental closure, and monetary costs. For example, 
two natural gas pipeline operators told us that they applied a decision 
tree analysis to all pipeline segments in highly populated and 
frequented areas. They used the decision tree to guide a variety of 
yes-or-no questions on whether installing an automated valve would 
improve response time to less than an hour and provide advantages for 
locations where people might have difficulty evacuating quickly in the 
event of a pipeline incident. Other hazardous liquid pipeline operators 
said they used computer-based spill modeling to determine whether the 
amount of product release would be significantly reduced by installing 
an automated valve.
Performance-Based Approach Offers Opportunity to Measure and Improve 
        Incident Response, but Better Data and Guidance Are Needed
    In our report, we note that PHMSA has not developed a performance-
based framework for incident response times, although some 
organizations in the pipeline industry have done so.\12\ We and others 
have recommended that the Federal government move toward performance-
based regulatory approaches to allow those being regulated to determine 
the most appropriate way to achieve desired, measurable outcomes.\13\ 
According to our past work, such a framework should include: (1) 
national goals, (2) performance measures that are linked to those 
national goals, and (3) appropriate performance targets that promote 
accountability and allow organizations to track their progress toward 
goals. While PHMSA has established a national goal for incident 
response times, it has not linked performance measures or targets to 
this goal. Specifically, PHMSA directs operators to respond to certain 
incidents--emergencies that require an immediate response \14\--in a 
``prompt and effective'' manner, but neither PHMSA's regulations nor 
its guidance describe ways to measure progress toward meeting this 
goal. Without a performance measure and target for a prompt and 
effective incident response, PHMSA cannot quantitatively determine 
whether an operator meets this goal and track their performance over 
time. PHMSA officials told us that because pipeline incidents often 
have unique characteristics, developing a performance measure and 
associated target for incident response time would be difficult. In 
particular, it would be challenging to establish a performance measure 
using incident response time in a way that would always lead to the 
desired outcome of a prompt and effective response. In addition, 
officials stated it would be difficult to identify a single response 
time target for all incidents, as pipeline operators likely should 
respond to some incidents more quickly than others.
---------------------------------------------------------------------------
    \12\ For example, according to the National Association of Pipeline 
Safety Representatives, several state pipeline safety offices have 
initiatives that require natural gas pipeline operators to respond 
within a specified time frame to reports of pipeline leaks. In 
addition, members of the Interstate Natural Gas Association of America 
have committed to achieving a 1-hour incident response time for large 
diameter (greater than 12 inches) natural gas pipelines in highly 
populated areas. To meet this goal, operators are planning changes to 
their systems, such as relocating response personnel and automating 
over 1,800 valves throughout the United States.
    \13\ In addition, NTSB has recommended that the Department of 
Transportation conduct an audit to assess the effectiveness of PHMSA's 
oversight of performance-based safety programs. See NTSB, Pipeline 
Accident Report: Pacific Gas and Electric Company Natural Gas 
Transmission Pipeline Rupture and Fire, San Bruno, California, 
September 9, 2010, NTSB/PAR-11/01 (Washington, D.C: Aug. 30, 2011). In 
response to the NTSB recommendation, the Department of Transportation 
is currently conducting an audit, which it expects to issue in early 
2013, that will evaluate the effectiveness of PHMSA's inspection and 
oversight of pipeline operators' integrity management programs, 
including expanding the use of meaningful metrics and setting goals for 
pipeline operators and tracking performance against those goals.
    \14\ Emergencies include natural gas detected inside or near a 
building, accidental release of hazardous liquid or carbon dioxide from 
a pipeline facility, fire or explosion occurring near or directly 
involving a pipeline facility, operational failure causing a hazardous 
condition, or natural disaster affecting pipeline facilities.
---------------------------------------------------------------------------
    Defining performance measures and targets for incident response can 
be challenging, but one possible way for PHMSA to move toward a more 
quantifiable, performance-based approach would be to develop strategies 
to improve incident response based on nationwide data. For example, 
performing an analysis of nationwide incident data--similar to PHMSA's 
current analyses of fatality and injury data--could help PHMSA 
determine response times for different types of pipelines (based on 
characteristics such as location, operating pressure, and diameter); 
identify trends; and develop strategies to improve incident response. 
However, we found that PHMSA does not have the reliable nationwide data 
on incident response time data it would need to conduct such analyses. 
Specifically, the response time data PHMSA currently collects are 
unreliable for two reasons: (1) operators are not required to fill out 
certain time-related fields in the PHMSA incident-reporting form and 
(2) when operators do provide these data, they are interpreting the 
intended content of the data fields in different ways. Our report 
recommended that PHMSA improve incident response data and use these 
data to evaluate whether to implement a performance-based framework for 
incident response times. PHMSA agreed to consider this recommendation.
    We also found that PHMSA needs to do a better job of sharing 
information on ways operators can make decisions to install automated 
valves. For example, many of the operators we spoke with were unaware 
of existing PHMSA enforcement and inspection guidance that could be 
useful for operators in determining whether to install automated valves 
on transmission pipelines. In addition, while PHMSA inspectors see 
examples of how operators make decisions to install automated valves 
during integrity management inspections, they do not formally collect 
this information or share it with other operators. Given the variety of 
risk-based methods for making decisions about automated valves across 
the operators we spoke with, we believe that both operators and 
inspectors would benefit from exposure to some of the methods used by 
other operators to make decisions on whether to install automated 
valves. Our report recommended that PHMSA share guidance and 
information on operators' decision-making approaches to assist 
operators with these determinations. PHMSA also agreed to consider this 
recommendation.
    Chairman Rockefeller this concludes my prepared remarks. I am happy 
to respond to any questions that you or other Members of the Committee 
may have at this time.
 Appendix I: Summary of Recent GAO Reports on Gathering Pipelines and 
                   Low-stress Transmission Pipelines
    GAO recently issued two reports related to the safety of certain 
types of pipelines. The first, GAO-12-388, reported on the safety of 
gathering pipelines, which currently are largely unregulated by the 
Federal government. The second, GAO-12-389R, reported on the potential 
safety effects of applying less prescriptive requirements, currently 
levied on distribution pipelines, to low-stress natural gas 
transmission pipelines. Further detail on each report is provided 
below. For the full report text, go to www.gao.gov.
GAO-12-388: Collecting Data and Sharing Information on Federally 
        Unregulated Gathering Pipelines Could Help Enhance Safety
    Included in the Nation's pipeline network are an estimated 200,000 
or more miles of onshore gathering pipelines, which transport products 
to processing facilities and larger pipelines. Many of these pipelines 
have not been subject to Federal regulation because they are considered 
less risky due to their generally rural location and low operating 
pressures. For example, out of the more than 200,000 estimated miles of 
natural gas gathering pipelines, the Pipeline and Hazardous Materials 
Safety Administration (PHMSA) regulates roughly 20,000 miles. 
Similarly, of the 30,000 to 40,000 estimated miles of hazardous liquid 
gathering pipelines, PHMSA regulates about 4,000 miles.\1\
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    \1\ According to PHMSA officials, Alaska, California, Louisiana, 
and Oklahoma have the majority of federally unregulated gathering 
pipeline mileage in the United States.
---------------------------------------------------------------------------
    While the safety risks of onshore gathering pipelines that are not 
regulated by PHMSA are generally considered to be lower than for other 
types of pipelines, PHMSA does not collect comprehensive data to 
identify the safety risks of unregulated gathering pipelines. Without 
data on potential risk factors--such as information on construction 
quality, maintenance practices, location, and pipeline integrity--
pipeline safety officials are unable to assess and manage safety risks 
associated with gathering pipelines. Further, some types of changes in 
pipeline operational environments could also increase safety risks for 
federally unregulated gathering pipelines. Specifically, land-use 
changes are resulting in development encroaching on existing pipelines, 
and the increased extraction of oil and natural gas from shale deposits 
is resulting in the construction of new gathering pipelines, some of 
which are larger in diameter and operate at higher pressure than older 
pipelines. As a result, PHMSA is considering collecting data on 
federally unregulated gathering pipelines. However, the agency's plans 
are preliminary, and the extent to which PHMSA will collect data 
sufficient to evaluate the potential safety risks associated with these 
pipelines is uncertain.
    In addition, we found that the amount of sharing of information to 
ensure the safety of federally unregulated pipelines among state and 
Federal pipeline safety agencies appeared limited. For example, some 
state and PHMSA officials we interviewed had limited awareness of 
safety practices used by other states. Increased communication and 
information sharing about pipeline safety practices could boost the use 
of such practices for unregulated pipelines.
    We recommended that PHMSA should collect data on federally 
unregulated onshore hazardous liquid and gas gathering pipelines, 
subsequent to an analysis of the benefits and industry burdens 
associated with such data collection. Data collected should be 
comparable to what PHMSA collects annually from operators of regulated 
gathering pipelines (e.g., fatalities, injuries, property damage, 
location, mileage, size, operating pressure, maintenance history, and 
the causes of incidents and consequences). Also, we recommended that 
PHMSA establish an online clearinghouse or other resource for states to 
share information on practices that can help ensure the safety of 
federally unregulated onshore hazardous liquid and gas gathering 
pipelines. This resource could include updates on related PHMSA and 
industry initiatives, guidance, related PHMSA rulemakings, and other 
information collected or shared by states. PHMSA concurred with our 
recommendations and is taking steps to implement them.
GAO-12-389R: Safety Effects of Less Prescriptive Requirements for Low-
        Stress Natural Gas Transmission Pipelines Are Uncertain
    Gas transmission pipelines typically move natural gas across state 
lines and over long distances, from sources to communities. 
Transmission pipelines can generally operate at pressures up to 72 
percent of specified minimum yield strength (SMYS).\2\ By contrast, 
local distribution pipelines generally operate within state boundaries 
to receive gas from transmission pipelines and distribute it to 
commercial and residential end users. Distribution pipelines typically 
operate well below 20 percent of SMYS. Connecting the long-distance 
transmission pipelines to the local distribution pipelines are lower 
stress transmission pipelines that may transport natural gas for 
several miles at pressures between 20 and 30 percent of SMYS.
---------------------------------------------------------------------------
    \2\ Pipelines will begin to deform at a certain level of operating 
pressure. As a result, pipelines operate at a percentage of the level 
of pressure that will cause the pipeline to deform, known as SMYS. The 
SMYS depends on the type of metal and is an indicator of when the metal 
in the pipe starts to yield, deforming in a way that does not return to 
its original shape. By definition, transmission pipelines operate at or 
above 20 percent of SMYS (49 CFR Sec. 192.3). Some transmission 
pipelines operate under special permits that allow different maximum 
operating pressure that could exceed 72 percent of SMYS.
---------------------------------------------------------------------------
    Applying PHMSA's distribution integrity management requirements to 
low-stress transmission pipelines would result in less prescriptive 
safety requirements for these pipelines. Overall, requirements for 
distribution pipelines are less prescriptive than requirements for 
transmission pipelines in part because the former operate at lower 
pressure and pose lower risks in general than the latter. For example, 
the integrity management regulations for transmission pipelines allow 
three types of in-depth physical inspection. In contrast, distribution 
pipeline operators can customize their integrity management programs to 
the complexity of their systems, including using a broader range of 
methods for physical inspection. While PHMSA officials stated that 
``less prescriptive'' does not necessarily mean less safe, they also 
stated that distribution integrity management requirements for 
distribution pipelines can be more difficult to enforce than integrity 
management requirements for transmission pipelines.
    In general, the effect of changing PHMSA's requirement for low-
stress transmission pipelines for pipeline safety is unclear. While the 
consequences of a low-stress transmission pipeline failure are 
generally not severe because these pipelines are more likely to leak 
than rupture, the point at which a gas pipeline fails by rupture is 
uncertain and depends on a number of factors in addition to pressure, 
such as the size or type of defect and the materials used to conduct 
the pipeline. In addition, the mileage and location of pipelines that 
would be affected by such a regulatory change are currently unknown, 
although PHMSA recently changed its reporting requirements to collect 
such information. The concern is that because distribution pipelines 
are located in highly populated areas, the low-stress transmission 
pipelines that are connected to them could also be located in highly 
populated areas. As a result, we considered the current regulatory 
approach of applying more prescriptive transmission pipeline 
requirements reasonable.
       Appendix II: Examples of Pipeline Incident Response Times
    Operators we spoke with stated that the amount of time it takes to 
respond to an incident can vary depending on a number of variables (see 
table 2).



------------------------------------------------------------------------



 Table 2.-- Examples of Response Times in Select Pipeline Incidents from
                              2009 to 2011
------------------------------------------------------------------------
 Incident  response
        time                             Description
------------------------------------------------------------------------
1 minute             A rupture on a natural-gas transmission pipeline
                      located underground in a sparsely populated area
                      was caused when a construction company worker
                      accidentally struck the pipeline, which then
                      ignited and exploded. When the line broke,
                      automatic-shutoff valves on either side of the
                      rupture closed within one minute. Despite the fast
                      valve closure, the explosion caused one fatality-
                      the worker who struck the pipeline-and injured
                      seven others. The affected pipeline segment was 20
                      miles long. Though the valves were closed, there
                      was enough gas remaining in the pipeline to fuel
                      the fire for several hours. In addition to causing
                      a fatality and injuries, the incident cost the
                      operator an estimated $1 million, due primarily to
                      the value of the lost product ($740,000), as well
                      as damage to the pipeline ($288,000).
------------------------------------------------------------------------
3 minutes            A rupture on a hazardous liquid transmission
                      pipeline, located underground near a creek in a
                      sparsely populated area, was caused when heavy
                      rains shifted the land which broke the pipeline,
                      releasing over 1,700 barrels of propane. The line
                      break was immediately picked up by the operator's
                      computer-based leak detection system, and operator
                      personnel on site closed manual valves to isolate
                      the segment within 3 minutes. Because propane is a
                      highly volatile liquid, which turns to gas when
                      released into the atmosphere, there was no soil or
                      water contamination or environmental cleanup
                      costs. The incident cost the operator an estimated
                      $128,000, due primarily to the cost of repairs
                      ($73,000) and value of lost product ($55,000).
------------------------------------------------------------------------
8 minutes            During the night, unknown individuals operating
                      construction equipment punctured a hazardous
                      liquid transmission pipeline located underground
                      in an environmentally sensitive area, causing 56
                      barrels of crude oil to leak into the soil. The
                      puncture caused a drop in pressure that the
                      control room operator detected in 2 minutes. Six
                      minutes later, the control room operator shut down
                      the pipeline and isolated the affected segment
                      with remotely controlled valves. About 2 hours
                      later, the operator's response personnel arrived
                      on site. The incident cost the operator an
                      estimated $1.3 million, due primarily to its
                      environmental remediation efforts ($1 million) and
                      emergency response ($250,000).
------------------------------------------------------------------------
2 hours              A crack on an above-ground portion of a hazardous
                      liquid pipeline, located in a populated area,
                      caused 120 barrels of crude oil to spray into the
                      air. About 15 minutes after the incident started,
                      a local resident reported to the fire department
                      that crude oil was spraying into the air at a
                      pipeline station. The fire department went to the
                      incident site and, about 30 minutes after the
                      initial call, notified the pipeline operator of a
                      broken oil pipeline. About 20 minutes after
                      receiving the fire department's call, the control
                      room began shutting down the pipeline system and
                      isolating the affected segment by ordering the
                      closure of the upstream valve. Approximately 50
                      minutes later-about 2 hours after the incident
                      started-response personnel arrived on site and
                      manually closed the valve, which stopped the leak.
                      The incident cost the operator an estimated
                      $183,000, due primarily to its emergency response
                      ($118,000) and environmental remediation efforts
                      ($61,000).
------------------------------------------------------------------------
7 days               A natural gas transmission pipeline, located
                      underground in a sparsely populated area,
                      developed a small leak as the result of a
                      construction defect. The operator did not discover
                      the leak on the pipeline for almost a week
                      following initial reports due to the size of the
                      leak in combination with wind gusts in the area
                      that dissipated the escaping natural gas, reducing
                      the common signs of a gas leak, such as the smell
                      and damage to vegetation. Once the operator
                      detected the leak during routine, periodic
                      external monitoring of the pipeline, it took over
                      a day to identify its exact location. The incident
                      cost the operator an estimated $128,000 in repairs
                      ($106,000) and lost product ($22,000).
------------------------------------------------------------------------
Source: GAO presentation of information obtained during interviews with
  pipeline operators.


    The Chairman. Thank you very much. I have to do an 
immediate apology because as I praised GAO it occurred to me 
that I wasn't praising the agencies seated to your right. And 
there's a reason for that. They have specific tasks used to 
cover the world. In other words, I could write you a letter 
saying what do you think the future of whales are or coral 
reefs, and I would get an answer.
    Ms. Fleming. Right.
    The Chairman. A very academic reason to answer. So I just 
make that separation for my own protection from these two very 
nice people whose agencies I desperately need.
    Ms. Quarterman, I thank all of you for your statements. And 
any time we have a pipeline incident we hear about the amount 
of time that it took the operator to respond to that incident 
and therefore shut down the flow of gas or oil through the 
affected pipeline.
    The aftermath of the Sissonville incident is no different. 
While the cause of the event is still under investigation, 
there has been a lot of discussion about how quickly the 
operator did or did not respond, and I want to delve into this 
a bit.
    Ms. Quarterman, what is an acceptable amount of time that 
an operator should take to respond to a rupture? And I 
understand there are a lot of variables that can impact how it 
takes an operator to respond, nature and lots of things. But 
there are metrics that you can put in place to measure how well 
operators are performing; is that not right?
    Ms. Quarterman. That is correct. We require that an 
operator respond promptly. After the incident that occurred in 
San Bruno we came forward and----
    The Chairman. That's California?
    Ms. Quarterman. California, yes. I'm sorry. In August 2011 
we put out an advanced Notice of Proposed Rulemaking where we 
asked a series of questions about gas transmission and 
pipelines in particular. And ways that our regulations could be 
improved included among the questions that were asked related 
to remote and automatic shutoff valves and whether or not that 
is an option that should be considered moving forward.
    When the Pipeline Safety Act passed there was a provision 
in that Act as well that required us to study it with respect 
to existing pipelines and report back, which is one of the 
reports that we finished at the end of this year, and ask GAO 
to study it with respect to existing pipelines. And the report 
that came out today is associated with that.
    Another thing that we are looking at, and I think I 
mentioned during our testimony, is that later on this year 
we're planning to have a workshop with respect to the integrity 
management program and begin to ask some of these questions 
about how we might expand upon what is right now a performance-
based system to ensure that operators are really assessing the 
risks and responding on a timely basis.
    The Chairman. Can you explain to me more specifically what 
you mean by the way in which they choose to respond or not 
respond? What is it that they go through? I'm going to also ask 
this to another witness later on. What is it they go through in 
order to decide--first they have to know about it. Then they 
have to make a decision based upon several factors.
    Now, Ms. Hersman was referring to 16 fluctuations that took 
place before this Sissonville pipe blew. What's the way that 
they planned in how they're going to respond? What goes through 
their head?
    Ms. Quarterman. I think perhaps Columbia Gas would answer 
this better. But what I hope goes through their head is when 
they have an alarm or alert at a control room, as was the case 
here, they should take that very seriously because it indicates 
that something severe may have happened and they should alert 
the authorities. They should talk among themselves within the 
control room and immediately move toward shutting a pipeline in 
if there's an indication that there is a loss of pressure in 
that pipeline. Because that's an indication that there is a 
leak.
    One of the other studies that we also completed recently 
was an independent study on leak detection because of concerns 
we had about the fact that in many instances a leak is not 
found until someone in the public calls and says something has 
exploded or there's oil all over the place, another provision 
also of the act that we're looking at closely.
    So, in part, it's detecting a problem, and the second is 
stopping the problem. If you have an automatic or remote 
control shutoff valve you can do that instantaneously.
    The Chairman. And you can do that from the response----
    Ms. Quarterman. From the control room.
    The Chairman. Yes.
    Ms. Quarterman. It should be right there. And ideally, if 
you have a good safety culture, you should have given every one 
in that control room the authority to shut down the pipeline if 
they're concerned. So it's not a question of, you know, calling 
the boss who might not be there and saying there's a problem, 
but immediate authority to shut the pipeline in. And also 
notifying the public officials that there is a problem so that 
they know, if there is an incident that's out there, they know 
the cause of it and they can immediately start communicating 
and responding to it.
    They should also notify the National Response Center, 
notify so that we in the public sector know that there has been 
an incident. And that gets communicated all around government 
so everyone knows immediately that there is a problem.
    The Chairman. All right. I thank you.
    For Ms. Fleming, you note a lack of data that the 
Department of Transportation had about incident response times. 
Can you identify specific data that would be helpful for the 
department in order to make timely collections? What type of 
metrics would work best to measure operator's performance on 
how quickly they respond given the number of variables such as 
weather, traffic, rupture location? Can you provide examples 
from other industries? Large question, but interesting.
    Ms. Fleming. Yes. All right. So I think your first question 
was regarding data that would help measure incident response. 
So there are a couple of key areas, four to be exact, that we 
feel would really help PHMSA try to get a sense of incident 
response time.
    The first is the amount of time it takes an operator to 
identify and confirm an incident. The second would be when an 
operator or emergency response folks arrive at a scene. Third 
would be how much time it takes an operator to close a valve 
and isolate a pipeline segment. And then last would be the 
amount of time it takes for the operator or emergency response 
folks to assess the incident and declare it safe again.
    Currently PHMSA does not collect information in all of 
these areas. They only require the date and time the incident 
occurs. And we feel that all of these areas are important in 
order to be able to move toward a performance-based framework. 
So currently the data is unreliable because it's not complete. 
It doesn't encompass all of those areas. And when operators do 
try to provide information they're providing, it's kind of 
spotty because they're interpreting the data fields differently 
amongst the operators.
    So if PHMSA was able to collect this information they would 
be able to then take a step back and analyze to look for 
average incident response times and also look for trends 
amongst the different types of incidents and also amongst the 
pipeline operators.
    Your second question, I think, gets to the metrics. So in 
our work we've identified several characteristics of 
performance measures that really help organizations to 
identify, target, and track safety efforts.
    The first would be to really develop specific measurable 
goals that make clear the results you're trying to achieve. An 
example of that would be the Federal Motor Carrier Safety 
Administration has a range of measurable goals that they use to 
assess progress in how their enforcement programs are working 
and also in terms of the compliance with safety regulations and 
in reducing crashes, fatalities, and injuries.
    The second characteristic that we think is important for 
metrics would be that the goals should really be targeted 
toward your key dimension in terms of your performance 
measures. So an example of that would be the Federal Railroad 
Administration's annual budget submission has very specific 
numeric targets in terms of trying to reduce average train 
accident rates.
    And another example would be other emergency response 
organizations really have response requirements. For instance, 
the National Fire Protection Association requires that fire 
departments, the first fire engine must arrive within 4 minutes 
of an incident and all subsequent fire engines must arrive 
within 8 minutes. So these types of performance measures allow 
different entities to kind of take a step back and to gauge and 
see what adjustments need to be made in order to really improve 
your response time.
    The Chairman. So it is possible even though conditions 
vary, terrain varies, geology varies, all kinds of things vary, 
it is possible to set out a general metric with specific 
timelines which can be aimed for or met?
    Ms. Fleming. Absolutely, Mr. Chairman. I think the first 
step is to get a handle on the data and see what the data is 
telling you so that you can look across and say, OK, for this 
type of gas operator here's what the trend is telling us or 
this type of liquid operator with this type of dimension and 
pressure, here's the incident, here's what's happening in the 
last, you know, couple of years. Here's what the trends are 
showing.
    And then you really definitely could start setting some 
performance time related requirements and--and metrics and--and 
see and make adjustments and work to improve response time and 
safety.
    The Chairman. Just to close my point, the general thought 
that some might have, well, you know, just too much depends on 
what the circumstance is, and you yield some veracity to that 
point. But you say that in general where you were collecting 
relevant data, data is data, no matter what it's used for.
    Ms. Fleming. Yes.
    The Chairman. If it's collected honestly and interpreted 
honestly, it leads to a point of decision when you can do 
something if you are going to do that.
    Ms. Fleming. Absolutely. Absolutely.
    The Chairman. Thank you.
    Senator Manchin, do you want to ask any questions--I've got 
so many questions here.
    Senator Manchin. I've got a few, if I may.
    The Chairman. Yes, please.
    Senator Manchin. To Ms. Hersman, we have pipelines still in 
operation that are as old if not older than the line that 
ruptured. And I'm sure that you have to be concerned about the 
age and conditions of some of these lines.
    And finding out that the line that ruptured, where it 
ruptured, was one-third of the thickness it had originally 
been, I think, was start out----
    Ms. Hersman. Reduced by 70 percent. That's right.
    Senator Manchin. OK. How could that happen? And if that's 
the case and we have all these lines out there and we're much 
more dependent now, and I think we're going to be sometime in 
the future on natural gas, how vulnerable are we as a society?
    Ms. Hersman. About 50 percent. I mentioned 2.5 million 
miles of pipeline exist in our country. And about 50 percent of 
those lines were installed prior to 1970. So we indeed do have 
an aging pipeline infrastructure system like we do in all of 
our modes of transportation where we do see aging.
    One of the things that's really important is if a pipeline 
is adequately maintained and it's inspected properly its age is 
not the critical factor. The condition of the pipe is a 
critical factor. And so in this situation what we saw is a pipe 
that did not have any inline inspections and so there was not a 
recognition that this external corrosion was occurring reducing 
the thickness of the pipe.
    And so we are very concerned. We've made recommendations 
about inspections, that those have to be done regularly. And I 
think it's like anything else that we have, you've got to 
maintain it, you've got to invest in it, you've got to inspect 
it. Things can last a long time but it is important to 
understand the condition of them. And that's not what we're 
seeing in many of our investigations. We've investigated three 
major accidents in the last three years, and those pipelines 
were laid in the 1950s. There was a manufacturing defect in 
that one. In the 1960s in Michigan--the first one is 
California, San Bruno that people have referred to.
    The second one was in Michigan, and that was cracking and 
corrosion. And here now again we're seeing a 1960s era pipe 
where we're seeing significant corrosion. We have to do better.
    Senator Manchin. Ms. Quarterman, as I'm understanding in 
the vicinity there was three lines, SM-86, which is a 26-inch. 
And then the one that blew was an SM-80, was a 20-inch. And I'm 
understanding that the smart pig, so-called smart pig, and you 
probably want to explain that. I just understand that the 
inspection device creates a squealing noise and that's how it 
got its name the smart pig.
    Ms. Quarterman. That's one rumor I've heard, yes.
    Senator Manchin. OK. You might have other ones you might 
not want to talk about in here. Anyway, I'm understanding 
that's the only one that was not able to be or was not fitted 
with a smart pig to be inspected. Why would that be? That's 
still a big line, 20-inch.
    Ms. Quarterman. It is a big line. And the three pipelines 
that are at issue, one was, as you mentioned, 26. I believe the 
other one is 30-inch. There was the SM-86 loop, which was 26-
inch. The SM-86 loop was 30 inches. These three pipelines were 
essentially parallel in the same area.
    Senator Manchin. Right.
    Ms. Quarterman. Under the integrity management rules that 
were issued in 2003, a pipeline that is in a high consequence 
area as determined by the rule must have assessments of it, 
one--one version of--one assessment method, a very popular one, 
is an inline inspection tool or a pig.
    With respect to the two larger pipelines, because of the 
size of the line, the diameter, as well as the pressure of the 
line, there was a calculation made that is called the PIR, the 
potential impact radius. So depending upon how big the pipe--
how much pressure it is, the diameter of the pipeline, the 
bigger radius upon which the explosion would have an effect.
    With respect to the two larger pipelines, the explosion 
radius was bigger. The way it works is it's sort of a bubble 
that travels up and down the pipeline. If there are 20 
residences within a bubble it is considered a high consequence 
area.
    Senator Manchin. Is your thought process changing on that 
now? And I'm sure the industry might have other thoughts. But 
I'm sure everybody wants to be as safe as they can, and they 
don't want these things to happen either. Are you--would your 
recommendation be now that these are all treat--they should be 
inspected by the pig, smart pig?
    Ms. Quarterman. I mentioned earlier the rulemaking that we 
came out with in August 2011. One of the questions on that was, 
number one, should we redefine the high consequence area, 
expanding the scope. Or, number two, should we require more 
pipelines to be inspected or assessed. That is still the 
rulemaking process, so I can't comment on where we're going 
with that. But that's something that we are very, very, very 
seriously considering amending.
    Senator Manchin. And one real quickly, Ms. Fleming, if I 
may ask, the automated valves, my experience was I kept 
thinking why don't they just shut this thing off? Why is it 
still burning? And I understand the location, demographics and 
all that.
    And I'm understanding also that some of the valves may 
cause a problem as much as they might prevent a problem. Does 
that advance to the position to where you all have taken the 
position that there should be automated valves? And at what 
increments do you believe this should happen?
    Ms. Fleming. We leave the increments to PHMSA.
    Senator Manchin. OK.
    Ms. Fleming. You know, there are a number of means to try 
to improve response time. And it may make sense for an operator 
to install them every single location. It really is on a case-
by-case. There are other factors----
    Senator Manchin. What do you mean by every single location? 
Because some of these lines are quite, quite long.
    Ms. Fleming. Right. Right. Absolutely. We spoke to eight 
operators.
    Senator Manchin. Between compressing stations and things of 
that sort.
    Ms. Fleming. Yes. We spoke to eight operators. And one 
operator, a gas operator, said that, you know, they just made a 
decision that they are going to replace them and put automated 
valves regardless of risk. Because in their view they wanted to 
remove any judgment that control room staff would have in terms 
of whether or not to shut down the operation. So they just 
didn't want that to come into play during an incident.
    And there are other factors that are very critical too to a 
response. And really upgrading your leak detection 
capabilities, making sure your response personnel are close to 
the valve. Again, the control room procedures are very 
important to make sure that folks have adequate training and 
the authority to shut down the system.
    So we just feel that operators should take all of these 
factors into consideration knowing their characteristics of the 
pipeline location, and really do what they feel in working with 
PHMSA to come up with the optimal solution. Because as we know, 
automated valves absolutely improve safety but only in 
conjunction with a rapid well coordinated response.
    Senator Manchin. Thank you, Senator.
    The Chairman. Thank you, Senator Manchin.
    Just a quick one. Are you aware of any pipeline companies 
where when the control room lights up that the people that run 
the control room feel that they need to call a higher up to get 
permission to shut off the flow of gas?
    Ms. Fleming. We talked to eight operators. And a couple of 
folks told us that the old way of doing things was that, you 
know, kind of keep it running at all costs, right. And they 
said that they were very pleased that things were changing in 
that environment, that at least for their company safety was 
becoming the most important thing. But, again, we only spoke to 
eight operators and I think there's over 600 in the country 
with pipeline in highly populated and environmentally sensitive 
areas.
    So I think control room protocols, procedures are critical. 
And I think folks need to have adequate training and have the 
proper authority to shut down a system to make sure that 
there's no rupture or leaks.
    The Chairman. Yes, that was brought to my attention first 
through that movie the China Syndrome.
    Ms. Fleming. Right.
    The Chairman. I mean, that was the whole--that was the 
whole ball game.
    Ms. Fleming. That was the premise, right?
    The Chairman. Yes. All right.
    For Ms. Quarterman, last year's Pipeline Safety Bill 
required that automatic or remote controlled shutoff valves be 
installed on new and/or reconstructed pipelines where feasible. 
Now, the phrase ``where feasible'' perplexes me. I know you've 
started working on this requirement. What kind of process--
progress are you making in terms of this requirement? When can 
you expect to finalize this requirement?
    And I won't ask you whether OMB is being difficult. I 
didn't ask you that. I was just talking to myself. If you could 
answer the first part of the question, please.
    Ms. Quarterman. With respect to the automatic and remote 
controlled shutoff valves, I believe the requirement is that we 
perform a study and then determine whether to regulate. 
Fortunately we had already started the regulations before the 
law passed so we are well along the way in terms of looking at 
that.
    As I mentioned, there was a study released at the end of 
2012 that was performed by an independent expert on those 
valves. And the next act will be ours in terms of proposing a 
regulation going forward. I think the new pipelines are the 
easy part of this. It is the existing pipelines that will be 
much more difficult for us.
    The Chairman. But the general feeling is that the words 
``where feasible'' is not one which I should worry about?
    Ms. Quarterman. I think candidly that not only we but the 
entire industry is now committed to making sure that this 
happens going forward, that the valves are in place going 
forward for new pipelines.
    The Chairman. And you have the power through rule making, 
et cetera, to make sure?
    Ms. Quarterman. Absolutely.
    The Chairman. Thank you.
    This is a question is for Ms. Hersman and Ms. Fleming. The 
NTSB has advocated for requiring automatic or remote controlled 
shutoff valves on existing pipelines.
    Ms. Fleming, GAO has ultimately said that requiring these 
valves across the board may not be appropriate as a way 
forward. If these valves increase safety levels, why shouldn't 
we push for them to be installed as much as possible and why 
this conflicting approach?
    Ms. Hersman. The NTSB is charged with investigating 
accidents and making recommendations to prevent their 
reoccurrence or the loss of life or injury. We have seen in 
multiple investigations like San Bruno, CA where we had loss of 
life in a natural gas accident; Marshall, Michigan where they 
had a catastrophic release of crude oil, and here in 
Sissonville, WV.
    What we see is, one, a lack of recognition that the 
pipeline has leaked. In two of these events, an outside source 
called in and reported the rupture.
    The Chairman. Somebody else calling in?
    Ms. Hersman. Somebody else calling in and saying there's a 
problem. That is because the systems that have been set up to 
operate these pipelines are really operational systems. They 
are not leak detection systems. They monitor and control the 
distribution of gas and oil to customers in the most efficient 
manner.
    These systems are not sophisticated. In fact, here in 
Sissonville, there were three parallel lines and they all 
interconnected at various points. When Columbia needed to 
isolate and identify the ruptured line, the technology they had 
would not provide the appropriate information to them. They 
didn't----
    The Chairman. Would or would not?
    Ms. Hersman. Would not because they could not identify 
which of the three lines had ruptured and they had to shut down 
all three lines. The Control Centers do not have that level of 
sophistication.
    In Marshall, MI, it took Enbridge, the operator, 17 hours 
to identify the leak on a hazardous liquid line. They restarted 
the line twice, and they were about to do it for a third time. 
During the 17 hours, there were three shifts of employees who 
did not recognize that there was leaking petroleum. It was the 
worst onshore oil spill we have had in the United States, 
almost $1 billion worth of damages.
    The control systems are not recognizing ruptures. These 
automatic systems--and, again, Ms. Fleming mentioned it--takes 
the decisionmaking process out in some instances. If you have a 
huge outflow of gas on a single line, you know you need to shut 
that line down. In Sissonville, the rupture occurred on the 
smallest line where this rupture occurred of the three 
interconnected pipelines. The interconnection of the lines 
massed the drop in pressure because it was pulling gas from all 
three of those lines so the controller only saw a 100 PSI drop.
    If the controller had known on those cross flows where the 
gas was going, that it wasn't going this direction, that it was 
escaping, it would have helped. The future is really to improve 
the technology. To understand what is going on, to provide the 
controllers better information, and to have automatic valves, 
because we know that people have problems shutting these valves 
down. In San Bruno, an urban area, it took them almost 90 
minutes to close the valves. That was not because they were far 
away. It was because of traffic congestion. They physically 
could not get to the valves.
    In an area like West Virginia the situation could have been 
very different if it had been in the middle of the night, or 
during rush hour with more people on I-77. At the time of the 
rupture, there were four people in the compressor station at 
Lanham because it was during the work day. They actually could 
shut those valves down. It took them an hour to do it, but they 
could close the valves. They did not have to come from 
somewhere else to shut them down.
    Technology will help improve all of this. That being said, 
the NTSB makes recommendations for safety. That's our focus. We 
don't have to do the cost benefit analysis that Administrator 
Quarterman does to decide how much this costs versus how much 
the gain is. We look at what is in the best interest of the 
public when it comes to safety. We have a different mission.
    The Chairman. And the new technology, which I assume is in 
use in many places, is not mind bogglingly complex and 
expensive.
    Ms. Hersman. Well, I would say expensive is probably a 
relative term. It depends on who is paying for it.
    The Chairman. That's what I want you to say.
    Ms. Hersman. That this is technology that is certainly 
available. And as I mentioned to Senator Manchin earlier, the 
problem with these systems that are based on infrastructure 
that's 50 years old, is like the difference between having a 
paper map versus an electronic map with location technology 
when you're on the highway and understanding that you're in 
between two cities.
    With a paper map, maybe you know the closest mile marker, 
but you don't know exactly where you are. With a smartphone 
with GPS technology, however, you know exactly where you are. 
You can probably see weather and traffic on it too. The paper 
map is where we are with these pipeline systems. But, we need 
better technology to provide better information to people in 
the control rooms to identify, isolate, and shut down ruptured 
pipelines more efficiently and effectively.
    The Chairman. OK. Ms. Fleming, did you have----
    Ms. Fleming. I absolutely agree. I mean, I think 
automated--our work has shown that automated valves is a very 
effective means for improving response time and addressing an 
incident. But it is one--it's just one of the means. We also 
think it's very important to update leak detection 
technologies, to really take a look at your control room 
procedures, and then to really--each operator has to make an 
assessment in order to come up--and maybe it's a combination or 
maybe it really is installing valves everywhere. But each one 
of them really needs to take a step back and figure out the 
optimum solution to their particular situation.
    We spoke to one pipeline operator, it was interesting, and 
one location would have taken them--they decided to automate 
this valve because they figured out that it would really take 
them about two and a half to 3 hours to get there. Once there 
it would take at least 30 minutes to shut down the valve. So by 
automating this particular valve they were able to reduce their 
incident response time to less than an hour.
    And so I think each entity has to go through this exercise, 
look at where the valves are, look at the characteristics of 
their system, look at the control room procedures, take a look 
at their leak detection capabilities, location of their 
response personnel really in order to come up with an optimal 
solution.
    The Chairman. Thank you.
    I want to ask a question to the panel, that in the absence 
of these valves that we've been discussing, are there feasible 
alternatives to help shut off ruptured lines more quickly? I'm 
just asking for a yes or a no. I would think it would be pretty 
much a standard.
    Ms. Hersman. Yes.
    The Chairman. Yes, there are?
    Ms. Hersman. You're asking about technologies to shut the 
lines down quicker?
    The Chairman. Yes.
    Ms. Hersman. Yes. I think that's some of the technology 
improvements that we have been talking about today. For 
example, what I saw actually this morning out at the Lanham 
Compressor Station are three types of valves. There are 
hydraulic valves that will actuate on their own once they are 
activated.
    There are electric valves that will close the pipelines 
that are slower. And there are manual valves. Some of the 
valves have to be physically operated. They require human 
beings to turn a hand crank hundreds and hundreds of times with 
significant force to close the valves.
    That is the reason why it took so long to close some of 
those valves at Lanham. People may imagine that somebody 
presses a button and the valves are closed, but every situation 
is different depending on the infrastructure. Some valves 
require a person to be physically present if they are not 
automatic or remote control valves.
    The Chairman. Understood.
    Ms. Fleming. And I think what we're highlighting today is 
first you have to know that you have a problem. And so that's 
the idea of really having the leak detection capabilities. But 
in some cases it's also a robust public awareness program.
    You know, I think there are many incidents where it's not 
necessarily the operator that's the first one to make that 
call. And then once you have a problem then you have to have 
the best technology, whether it's an automated valve, in order 
to shut down and isolate a segment. So it's really taking a 
look at all of these different things to make sure that the 
public is aware of how to identify, how to report a problem. 
And then you have the capability to address a particular 
incident.
    The Chairman. I would think, Ms. Quarterman, before you 
answer, that particularly those people who live near gathering 
pipelines who recognize that there's a major amount of activity 
taking place under their feet and in their area would be pretty 
quick to get familiar with a website with the right kind of 
information. Please?
    Ms. Quarterman. One would hope so. But we understand that 
that is not always the case. From a technological perspective 
I'm not aware of any other technology beyond the ones you were 
talking about here today. But the public awareness point, I 
think, is an excellent one. We do require operators to put in 
place a public awareness plan so that individuals living near 
these facilities are aware of what's there. They should be 
aware of what to look for if there's a problem and how to 
respond to it.
    I understand from some of the conversations we've had here 
that Columbia Gas had done a reasonable job with that, the 
public awareness piece of it. We should also point to the 
prevention piece as well. I want to say a very great thanks for 
the state, for the Public Safety Commission, for the 
firefighters who were involved with this incident. I understood 
it went extremely smoothly given what had happened. I think 
they were aware that the pipeline was there, which has not 
always been the case in some of these incidents.
    And we're trying to make sure that that doesn't happen 
again by reaching out to emergency responders so they know in 
advance where the pipelines are in their area, who the 
operators are, who to call if there is a problem. That's a big 
part of what we could be doing here as well.
    The Chairman. Senator Manchin has a question. I just wanted 
to put in when I was out there this morning talking with a fire 
chief who I knew from D-block and other subjects. There seemed 
to be a sense that they knew what they were meant to do. In 
other words, you go out there, you see this huge hole, vast 
amounts of straw covering land.
    And, you know, Sue Bonham's, the remainder for their house, 
et cetera, that there would be a sense of, my heavens, we've 
never had this before. But to the contrary, the folks that live 
there and work there and have responsibilities there seem to be 
rather calm about what their duties were and they proceeded to 
do them. That was my impression. So that's not really a 
question.
    Ms. Quarterman. I agree with that. I would also just like 
to add that when this incident occurred we happened to have 
been in Pennsylvania looking at some of the new development 
there. And my deputy is a former fire chief, Mr. Butters, got a 
call from the West Virginia folks and so we were talking to 
them immediately about this incident. And they have been 
fantastic throughout this period. Mr. Butters has been here and 
visited with those folks and we are really impressed with what 
they were able to do. And we are going to make sure that they 
are even better prepared in the future.
    The Chairman. OK. Senator Manchin?
    Senator Manchin. Very quickly. The Senator had mentioned 
about having apparatuses today that could automatically shut 
down and prevent, let's say, these type of disasters to the 
extent that they are.
    The thing that comes to mind is the BP oil spill, and I 
think to all of our amazement how that thing could have blown 
for so long and spewed out for so long and we didn't have the 
right equipment, if you would. And trying to design something 
in real time that would take care of the problem is difficult. 
And I'm sure that we've moved further ahead so that hopefully 
never happens again.
    I think the same thing is happening here. You're saying 
that it should be strategically located when you have 
personnel, that you know you're going to have personnel at some 
of these substations, that's one thing. Knowing in a remote 
area is another thing. And are these rules and regulations or 
do you need codification from the legislation or--to move 
forward, where--where are you at on these things?
    Ms. Quarterman. We don't need codification. We have the 
authority to move forward in rulemakings on these things. I 
think some of the things that were being recommended by GAO are 
beyond rulemaking, putting in place some performance measures.
    We had a workshop earlier this year on the subject of data, 
something that I think we have not nearly enough of and need 
more of. And we actually have a rulemaking in progress to 
request more data from operators on a geospatial basis so that 
you can click on any point in a pipeline and know a lot about 
it.
    Senator Manchin. Yes. Are you all working with the 
company's operators, people responsible for the lines so that 
we all come up with a conclusion on what's the best method to 
take?
    Ms. Quarterman. Absolutely.
    Senator Manchin. And they've been cooperative working with 
you?
    Ms. Quarterman. They have been cooperative, yes.
    Senator Manchin. So you're not having a problem there? It's 
just making sure you get the right equipment in the right 
place?
    Ms. Quarterman. Actually, we did a pilot program very 
recently because we were trying to get more geospatial base 
information. And NiSource was one of the volunteers for that to 
see if we could actually get the kind of data we wanted to get.
    Senator Manchin. My final question, very quickly, is if 
that line had deteriorated to one-third of the actual size it 
should have been to carry safely the pressures it was carrying, 
it led me to believe that maybe there was other parts of that 
line that might blow. Are you sure that there's a safety on 
that, which is the SM-80 line, the 20-inch line? Since the 
other ones have been inspected I assume that this line is not 
inspected anywhere? Or have you started inspections on it?
    Ms. Quarterman. It will be before it returns to operations.
    Senator Manchin. Got you.
    Ms. Quarterman. One of the requirements in our corrective 
action order was that before they could begin operating again 
they would change the valves at the ends of the pipeline so 
that they can actually accept an inline inspection tool and run 
a corrosion test within that pipeline.
    And we have required that before they begin, you know, 
complete operations they will do that and they will then repair 
the line as though it was in a high consequence area even 
though under the official regs it is not.
    Senator Manchin. Thank you.
    The Chairman. There's a final question before we go to the 
third panel and before I thank you all.
    The fire chief, who I said is a good friend, told me that 
there is in fact a length, he didn't describe it, but a semi 
lengthy amount of plastic pipe sitting on the ground out in 
Sissonville carrying gas. And I'm trying to think how could 
that possibly be?
    Ms. Quarterman. I am guessing, and I don't know anything 
about that particular situation. I haven't talked to him about 
that. I'm guessing it is a gas gathering line. This is another 
area that when the President put forward a request for 
reauthorization we requested the authority to be able to 
oversee gas gathering that had not traditionally been 
regulated.
    And when I mentioned my trip to Pennsylvania to see some of 
the shale plays, one of our concerns is that a great deal of 
gas gathering lines are going into place, some of them 20 
inches or larger, high pressure lines that are currently not 
within our regulatory authority because they are in a rural 
area. We are extremely concerned that we get ahead of that 
problem by beginning to know what is out there, where pipelines 
are, and begin to regulate those lines in some way or fashion.
    The Chairman. In a rural area and therefore not within your 
jurisdiction?
    Ms. Quarterman. Right.
    The Chairman. That strikes me as odd. I want to thank all 
three of you, and I don't want you to move. I want you to stay 
right where you are because coming down on the plane with you, 
you all had briefing books that were like 10 inches thick in 
sort of biblically small handwriting and you've all read all of 
it. And I was just very impressed.
    And I was also concerned, Ms. Quarterman, with respect to 
your situation, because you indicate you do not have a large 
agency. And therefore the number of people as this burgeoning 
industry merges further, it will be important for you to be 
able to monitor it. And you have been there through a situation 
where you had 75 people. Then you were taken down to 39 people 
and now you're over 100 people or whatever it is. That doesn't 
sound like a very healthy way of doing business. You need 
stability, don't you? You need enough people and you need 
stability.
    Ms. Quarterman. Absolutely. We have a very small agency. 
Despite overseeing 2.6 million miles of pipeline, we have 200 
people, 135 of which are inspection enforcement personnel.
    The President was very generous in his request in Fiscal 
Year 2013, which would add another 120 inspectors. We 
desperately need those people because those people not only do 
the day-to-day meat and potatoes inspection, when you have a 
boom as you're having now with gas and oil production in this 
country, what happens next to the pipelines going to there.
    So they want to be there to see the construction as it 
happens. In addition to that, with all these incidents we also 
have to take people away from the day-to-day bread and butter 
inspections to do that. And the infrastructure is not getting 
any younger. So it is a huge challenge for us.
    The Chairman. I thank you all a lot.
    And I now call upon the third panel to sit over there. And 
that's Mr. Jimmy Staton, who is Executive Vice President and 
Group CEO of the NiSource Gas Transmission & Storage. And 
second, Mr. Rick Kessler, President of the Board of the 
Pipeline Safety Trust. If you gentlemen could have a seat.
    And, Mr. Staton, if you could start with your statement, I 
would appreciate it.

          STATEMENT OF JIMMY D. STATON, EXECUTIVE VICE

       PRESIDENT AND GROUP CEO, NiSource GAS TRANSMISSION

                           & STORAGE

    Mr. Staton. Good afternoon, Chairman Rockefeller and 
Senator Manchin.
    The Chairman. Could you pull that a little closer?
    Mr. Staton. Certainly. My name is Jimmy Staton, and I live 
in Clarksburg, West Virginia. And I'm the CEO of Columbia Gas 
Transmission, whose operational headquarters are located here 
in Charleston. And I appreciate the opportunity to be with you 
today.
    Columbia Gas is a proud member of the West Virginia 
community. And while we clearly recognize that the incident 
along our SM-80 pipeline near Sissonville was unacceptable, I 
want to assure you that we operate with a daily commitment to 
safety. We have been and will continue to work with all of our 
focus and our energy to make things right and to learn from 
this incident.
    In the wake of this incident we moved quickly to address 
the needs of the local residents and agencies. We partnered 
with the Red Cross to ensure that no necessity was overlooked 
as we took steps to address longer term issues like home repair 
and relocations. We are providing full reimbursements to local 
and state agencies for their emergency response costs and have 
made charitable contributions to other local entities who 
pitched in to help following the incident.
    We are also working with the NTSB and Administrator 
Quarterman and her team at PHMSA to identify the cause of the 
event and apply the findings to our operations systemwide.
    The NTSB has noted that line SM-80 had experienced external 
corrosion. They also confirmed in a preliminary report that 
Columbia's SCADA system detected a drop in pressure on the 
pipeline as it was designed to do. SCADA system alerts are a 
critical first step toward the initiation of our emergency 
response programs.
    We will continue to work cooperatively with these agencies 
as the NTSB completes its final analysis and will apply lessons 
learned to our processes, procedures, and all of our pipeline 
assets.
    We are also working with PHMSA to implement an integrity 
assurance plan that will ensure the long-term safety of the SM-
80 pipeline. Our plan is designed to safely return the line to 
limited service, to facilitate a comprehensive integrity 
assessment, including an internal or smart pig, as we've talked 
about today, inspection before we return to full service. A 
copy of our plan is attached to my written testimony.
    In addition to the steps we are taking to address the 
incident, we are undertaking a systemwide modernization of our 
pipeline infrastructure. This modernization program is designed 
to replace and rebuild our pipeline and compression facilities 
in order to improve the safety, reliability, and efficiency of 
our system.
    Our modernization program includes the replacement of 
nearly 1,000 miles of older pipelines, provides for pipeline 
upgrades to expand the use of smart pigs, and the replacement 
of compression equipment to improve efficiency and 
environmental performance.
    Our modernization program is aligned with the U.S. 
Transportation Secretary Ray Lahood's call to action as well as 
key provisions of the recent Pipeline Safety Act that you led 
reauthorization of a year ago.
    We developed our modernization program with the input and 
assistance of our customers and other stakeholders, and I am 
pleased to report that the Federal Energy Regulatory Commission 
recently endorsed our plan by issuing an affirmative order that 
clears the way for our modernization efforts to continue and 
more importantly to accelerate.
    And some of our most critical modernization projects will 
occur right here in West Virginia. We will invest close to 
three-quarters of a billion dollars in West Virginia in the 
first 5 years of our program alone on projects that will expand 
our ability to use smart pigs, replace older pipelines and 
upgrade compressors to improve efficiency and significantly 
reduce emissions. These infrastructure investments will not 
only improve safety but will also create jobs and generate new 
tax revenue for the state and localities.
    In closing, we recognize the importance of pipeline safety 
and are committed to applying the lessons learned from the 
Sissonville incident. In addition, the pipeline safety 
legislation you helped enact sought to drive investment in 
newer and more advanced pipeline systems all in the name of 
safety. Columbia's modernization program helps accomplish this 
crucially important goal.
    Mr. Chairman, Senator, I was in Sissonville the evening of 
the event, and I saw the impact on the community. And I also 
looked at the faces of my employees who work and live in the 
Sissonville area. And I vowed to them at that time that we 
would do right and we would make it right for the people of 
Sissonville and that we would make the right investments, 
continue to make the right investments to ensure that our 
system does not incur another incident like this. And I make 
that same commitment to you all today.
    I thank you. That concludes my testimony, and I look 
forward to your questions.
    [The prepared statement of Mr. Staton follows:]

  Prepared Statement of Jimmy D. Staton, Executive Vice President and 
             Group CEO, NiSource Gas Transmission & Storage
Introduction
    Mr. Chairman and Members of the Committee:

    My name is Jimmy Staton. I live in Clarksburg, West Virginia, and I 
am CEO of NiSource Gas Transmission & Storage, parent company of 
Columbia Gas Transmission whose operational headquarters are located in 
Charleston.
    Columbia Gas Transmission owns and operates approximately 12,000 
miles of natural gas pipelines, including roughly 2,500 miles of 
pipeline in West Virginia. Our pipeline system is integrated with one 
of the largest underground storage systems in North America and we 
deliver domestically produced natural gas to businesses and communities 
across the Midwest, Mid-Atlantic and Northeast regions of the United 
States. Through our predecessor companies, NiSource and Columbia Gas 
have been a safe pipeline operator, an employer of choice and a 
community partner of West Virginia and surrounding states for more than 
a century.
    Personally, I have worked in the natural gas and energy industry 
for nearly 30 years--serving in a variety of roles ranging from rates 
and regulatory to operations and engineering. At no other time during 
my career has there been such a promising outlook for America's 
domestic energy potential--and the economic and national security 
related benefits that comes with it--but that energy potential must be 
grounded in a daily commitment to operating safely.
    At Columbia Gas we take our commitment to safety very seriously. I 
appreciate the opportunity to share with you the various initiatives we 
are undertaking to ensure we continue to provide safe and reliable 
pipeline service.
Sissonville Incident
    Mr. Chairman, let me take a moment to provide you with an update on 
our efforts to respond to the incident that occurred on December 11, 
2012, on our Line SM-80 pipeline near Sissonville.
    This was a terrible incident--one in which I hope we never see the 
likes of again. Thankfully, no one was seriously injured. Please be 
assured that we are fully committed to making this right and taking any 
steps necessary to ensure the safety of our company's pipeline system.
    In working with local emergency responders, we were able to isolate 
the incident, secure the site, and focus on the following three key 
areas:

  (1)  Making the area safe and immediately addressing the needs of any 
        local residents and community agencies impacted by the pipeline 
        incident;

  (2)  Collaborating with the National Transportation Safety Board 
        (NTSB) and other federal, state and local authorities to 
        identify the root cause of the event and apply ``lessons 
        learned'' to our operations systemwide; and,

  (3)  Working proactively with Federal and state officials to design 
        and implement an Integrity Assurance plan that will ensure a 
        safe return to service and the long-term integrity of Line SM-
        80.
Attending to Community Needs
    Immediately following the incident, a team of local Columbia 
employees identified and made contact with each impacted resident to 
ensure that basic essentials, including temporary housing, food, and 
transportation were provided. Our team remained in constant contact 
with residents to ensure that no necessity was overlooked. In addition, 
we partnered with the regional office of the Red Cross--to tap into 
their special expertise, provide additional support for those in need, 
and facilitate Columbia employees and others in the community looking 
to help their neighbors through charitable giving. Our team has worked 
closely with all of the impacted residents to resolve the issues 
associated with the Line SM-80 incident.
    We know this incident impacted the lives of several families living 
in the area, and we will continue to work to make things right.
    We have also been working with various local and state agencies 
that assisted our efforts to safely secure the incident site. As a 
longtime West Virginia resident, I know first-hand that during 
challenging times, we come together to help each other--and that has 
certainly been the case here. We are grateful for the dedication and 
commitment of the first responders, the Department of Highways, and 
other local agencies that provided support and recovery efforts that 
day. We also have moved quickly to ensure that the operating budgets 
for these public agencies were not adversely impacted by this incident, 
and are providing full reimbursements for costs associated with the 
emergency response services rendered by these groups.
    We've also provided contributions to the Aldersgate United 
Methodist Church and Sissonville High School in recognition of the 
important role they played in the hours and days following the 
incident.
    We recognize this was a difficult time for Sissonville and Kanawha 
County. It has been and will continue to be our priority to work 
proactively with those who were impacted, as well as those who lent a 
helping hand. We've enjoyed a positive working relationship with a 
number of local agencies in Kanawha County over our many years of 
providing service in West Virginia, and we look forward to continuing 
this cooperative partnership in the future.
Cooperating with the NTSB
    As I mentioned earlier, we have been working in close collaboration 
with the NTSB to determine the cause of the incident and to implement 
lessons learned across our policies, procedures and pipeline assets. 
The NTSB has noted, both in press briefings and a recently issued 
Preliminary Report, that the ruptured line had experienced significant 
external corrosion.
    The NTSB has also confirmed that Columbia's SCADA system detected a 
drop in pressure in the SM-80 line, as well as the nearby SM-86 and SM-
86 Loop pipelines, as designed. Alerts issued by our SCADA system are 
the first critical step toward the initiation of our Emergency Response 
plan and the dispatching of personnel to a pipeline rupture site. 
Columbia's SCADA system is staffed 24-hours a day, seven days a week by 
trained operations employees to provide a real-time monitoring of the 
flow of gas through our pipeline system. The proper functioning of our 
SCADA system and the procedures followed by our Control Room personnel 
were a crucial component to our response to the Sissonville incident. 
We will continue to work closely with the NTSB as it produces its final 
report and are committed to applying lessons learned to our Control 
Room procedures.
A Safe Return to Service
    As NTSB's investigation proceeds, our engineering team has been 
hard at work developing a comprehensive Integrity Assurance plan \1\ to 
ensure the safe return to limited service for Line SM-80. This line is 
an important part of a pipeline system that plays a vital role in 
supplying natural gas to West Virginia and other critical eastern 
markets.
---------------------------------------------------------------------------
    \1\ A copy of the Executive Summary of the Columbia Gas 
Transmission Integrity Assurance Plan as submitted to PHMSA is included 
in Appendix A. Supporting materials are available upon request.
---------------------------------------------------------------------------
    Our Integrity Assurance plan is designed to help facilitate an 
advanced internal inspection of the SM-80 pipeline. It addresses a 
comprehensive Corrective Action Order (CAO) recently issued by the U.S. 
Department of Transportation's Pipelines and Hazardous Materials Safety 
Administration (PHMSA). The CAO requires the implementation of a number 
of measures prior to restarting Line SM-80 to restricted service. We 
will address each requirement and, in fact, have elected to supplement 
the order in several important ways in order to provide an even greater 
level of assurance that we are fully committed to operating safely.
    Under the Integrity Assurance plan, Columbia's engineering team 
will identify and complete the repair work needed to ensure the 
integrity of the pipeline for operation at a reduced pressure, and 
ready the line for further evaluation using ``smart pig'' in-line 
inspection tools. The work will include: the replacement of mainline 
valves along a 30-mile stretch of Line SM-80 from the Lanham Compressor 
Station to Columbia's Broad Run Valve Setting; the installation of 
launcher and receiver facilities at points along the line to enable 
passage of in-line inspection tools; a verification that the cathodic 
protection system is operating properly on all three of Columbia's 
pipelines in the vicinity of the incident origin; and the installation 
and adjustment of pressure regulation and overpressure protection 
equipment to support operation of the pipeline at a safe temporary 
maximum allowable pressure. These steps will allow us to return the 
pipeline to a restricted level of service so that additional integrity 
assessment can be performed. Columbia will then implement the 
appropriate preventive and mitigative measures based on this assessment 
to provide for the safe return of Line SM-80 to full commercial service 
and to ensure the long-term integrity of the pipeline.
    We will only return Line SM-80 to service once we have received 
approval from PHMSA and the West Virginia Public Service Commission, as 
well as communicated with our neighbors in Sissonville. We have also 
elected to hire an independent monitor experienced in pipeline safety 
and integrity related issues to provide a third party review of the 
plan and actions taken by Columbia in the course of carrying it out. 
The independent monitor will review pipeline integrity plans and 
inspections and provide feedback to both Columbia and PHMSA on the 
effectiveness of our work.
Modernization
    In addition to our response to the SM-80 incident, Columbia is 
taking significant steps forward to assure the continued safe operation 
of our entire pipeline system for generations to come.
    Aligning our efforts with the ``Call to Action'' by U.S. Department 
of Transportation Secretary Ray LaHood, we developed a comprehensive 
modernization plan that ensures pipeline and system upgrades; improves 
public safety, customer reliability and service; and provides economic 
benefits. This modernization effort will strategically and 
systematically replace, revamp or rebuild key pipeline and compression 
facilities across our entire system.
    Our Modernization program, which is the first of its kind in the 
industry, is the culmination of a multi-year effort to evaluate our 
system and identify areas in need of investment. The program's system 
improvements include:

   Replacing Aging Infrastructure--replacing approximately 
        1,000 miles of existing interstate transmission pipelines, 
        primarily bare steel (400 miles in the first five years);

   Expanding In-Line Inspection Capabilities--facilitating 
        Columbia's ability to perform state-of-the-art maintenance and 
        inspections without interrupting service;

   Increasing Pipeline System Reliability--uprating pressures 
        and looping systems where needed to ensure gas is reliably 
        delivered to critical markets; and,

   Upgrading Natural Gas Compression Systems--replacing and 
        modernizing more than 50 critical compressor units along the 
        pipeline system that will enhance system efficiency and improve 
        environmental performance.

    We anticipate investing more than $2 billion in this program over 
the next five years--dollars that will be directly focused on 
increasing pipeline safety and service reliability.
    The Columbia Modernization program is aligned with key provisions 
of the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 
2011 that you and this Committee led the enactment of one year ago. 
Recently, Secretary LaHood publicly pledged to support and assist our 
efforts to navigate the Federal and state permitting process under the 
auspices of an Executive Order issued by President Obama in March of 
2012 aimed at encouraging investment in vital and economically 
significant national infrastructure.\2\
---------------------------------------------------------------------------
    \2\ The Department of Transportation press release is attached in 
Appendix B.
---------------------------------------------------------------------------
    We developed this initiative with the input and assistance of our 
customers, and filed a broadly supported settlement agreement with the 
Federal Energy Regulatory Commission (FERC) in September of last year. 
Just recently, on January 24, the FERC endorsed our plan by issuing an 
affirmative order \3\ that clears the way for our modernization efforts 
to continue and accelerate.
---------------------------------------------------------------------------
    \3\ Columbia Gas Transmission, LLC, 142 FERC Paragraph 61,062 
(2013), included in Appendix C.
---------------------------------------------------------------------------
    A number of our most critical Modernization projects will be 
occurring in West Virginia. One of the largest of those projects will 
be the $38 million WB Pipeline project, which will upgrade a number of 
older pipelines to accommodate in-line inspection equipment, or so-
called ``smart pigs.'' Our WB pipeline system runs across central West 
Virginia and delivers natural gas to the state and other eastern 
markets. Upgrading this system to accommodate today's latest safety 
technology will not only allow for enhanced integrity assessment, but 
it will also greatly improve the efficiency and reliability of the 
pipeline.
    Our plan also calls for over $100 million in critical compression 
facility upgrades in West Virginia. Three compressor stations have been 
identified for enhancement at Seneca, Frametown, and Lost River. These 
investments will provide increased reliability, system flexibility and 
efficiency. Work at the stations will improve compressor horsepower, 
dramatically improve emissions performance, and result in a significant 
reduction in fuel consumption.
    In total, over the first six years of our Modernization program, 
Columbia will invest close to three-quarters of a billion dollars in 
safety and reliability related improvement projects in West Virginia 
alone. A recent economic analysis of our program estimates that 
Modernization will result in more than $1.1 billion in economic output 
in the state, including the creation or support of approximately 1,700 
total jobs at the peak of our program in 2016 ranging from engineering 
to construction services. In addition to private economic activity, our 
Modernization investment is anticipated to generate approximately $80 
million in new revenue for the State of West Virginia and its units of 
local government. Most importantly, our work in the state will make our 
systems safer and more reliable.
Closing
    Mr. Chairman, Columbia's Modernization program is good news for 
pipeline safety and good news for job creation. At its core, the 
legislation you spearheaded in the 112th Congress sought to drive 
investment in newer and more advanced pipeline systems and facilities--
all in the name of safely and reliably transporting this important 
resource. Columbia's Modernization program helps accomplish this 
important goal and will keep us on a solid footing to safely and 
reliably deliver natural gas to the next generation of natural gas 
consumers.
    As a constituent, I cannot close without thanking you for your 
public service of nearly 50 years and your tireless dedication to the 
residents of West Virginia and this Nation.
    Thank you for the invitation to appear before the committee today. 
I am pleased to answer any questions you may have.
                               Appendix A
          Columbia Gas Transmission--Integrity Assurance Plan 
                  (Executive Summary)--January 8, 2013

            Columbia Gas Transmission, LLC--January 8, 2013

   Line SM-80--Lanham to Broad Run--Integrity Assurance Plan--Phase 1

                           Table of Contents
        Executive Summary
        Background
        Safety
        Independent Review and Monitoring
        Preliminary Cause Determination
        Repairs to Incident Origin
        Verification of Cathodic Protection
        Preparation of Line SM-80 for In-Line Inspection
        Safe Return to Temporary Maximum Allowable Pressure
        Preliminary Phase I Schedule
        Summary and Overview of Integrity Assurance Plan--Phase 2
        Criteria--Assessment, Repair, Documentation, Request for 
        Approval and Restoration of Full Service--Phase 3
        Conclusion Criteria--Periodic and Summary Reporting and 
        Documentation--Phase 4
                 Columbia Gas Transmission--Line SM-80
                 Lanham Compressor Station to Broad Run
                   Integrity Assurance Plan--Phase 1
Executive Summary
    On December 11, 2012, at approximately 12:41 p.m., a natural gas 
pipeline incident involving an ignition and fire occurred in northern 
Kanawha County, WV, along the 20 inch diameter Columbia Gas 
Transmission (Columbia Gas) Line SM-80. Line SM-80 is approximately 30 
miles long and runs from the Lanham Compressor Station to the Broad Run 
Valve Setting. In response to the incident, a pipeline segment 
approximately 8 miles long, from the Lanham Compressor Station to the 
Rocky Hollow Valve setting, was isolated, blown down and has remained 
out of service since the time of the rupture. In addition, a section 
approximately 22 miles long, from Rocky Hollow to the Broad Run valve 
setting, has been isolated and remains out of service, with a static 
pressure of less than 300 psig. The maximum allowable operating 
pressure (MAOP) of Line SM-80 is 1,000 psig, and the discharge pressure 
at Lanham was approximately 929 psig at the time of the incident.
    This integrity assurance plan details the first phase in a four-
phase approach designed to implement corrective measures to prevent 
recurrence, and ensure the safe return to service of Line SM-80. Phase 
1 of the plan focuses on making repairs and ensuring the near term 
safety and integrity of Line SM-80, while preparing the line for Phase 
2. Phase 2 focuses on performing a comprehensive integrity assessment 
of Line SM-80. Based on the integrity assessment, Columbia Gas will 
implement appropriate preventive and mitigative measures to provide for 
the safe return of Line SM-B0 to full service and ensure the long-term 
integrity of the pipeline. Phase 3 includes completion of necessary 
repairs, summarizing the work completed, requesting regulatory approval 
to return Line SM-80 to service, and upon approval, restoring normal 
service to the pipeline. Phase 4 focuses on steps that Columbia Gas 
will take to document and communicate the work conducted, including 
keeping regulators informed of progress, maintaining records, and 
tracking expenditures associated with implementation of this plan.
Phase 1 Key Elements
    Phase 1 includes the steps that Columbia Gas will take to repair 
the damaged sections of the pipeline, ensure the integrity of the 
pipeline for operation at a reduced/restricted pressure, and ready the 
pipeline for further evaluation using in-line inspection tools. Key 
elements of Phase 1 are:

  (1)  Verification of the integrity of the pipeline in the vicinity of 
        the incident origin

  (2)  Complete repairs to Line SM-80 at the incident origin

  (3)  Verification that the cathodic protection (CP) system is 
        operating properly on all three pipelines in the vicinity of 
        the incident origin

  (4)  Replacement of mainline valves along Line SM-80 from Lanham to 
        Broad

  (5)  Installation of a temporary launcher at Lanham Station and a 
        temporary receiver at Broad Run to enable the passage of in-
        line inspection tools (a permanent launcher and receiver will 
        be installed in Phase 2)

  (6)  Verification of the discharge pressure at Lanham Station 
        immediately prior to the incident to establish a safe temporary 
        maximum allowable pressure

  (7)  Installation and adjustment of pressure regulation and 
        overpressure protection to support operation of the pipeline at 
        the safe temporary maximum allowable pressure.

  (8)  Return of Line SM-80 to service at or below the safe temporary 
        maximum allowable pressure on a temporary basis for purposes of 
        conducting an in-line inspection. The pressure will be restored 
        through a stepped approach that includes instrumented leak 
        surveys.
Background
    The NTSB conducted a field investigation following the incident. 
The NTSB reported that a 20 foot section of pipe was ejected during the 
event. The NTSB further reported that the ruptured pipeline was found 
to have areas consistent with external corrosion. According to the 
NTSB, visual examination of the ruptured pipe revealed a six foot area 
that ran along the bottom of the pipe where the pipe thickness was 
measured to be less than 1/10 inch thick in some places (approximately 
.078 inch thick). On December 20, 2012, the Pipeline and Hazardous 
Materials Safety Administration (PHMSA) issued a Corrective Action 
Order (CAO) that requires the implementation of certain measures prior 
to restarting the pipeline to restricted service.
    The purpose of this plan is to detail the work that will be 
completed both in the vicinity of the incident origin as well as along 
Line SM-80 from Lanham Compressor Station to the Broad Run valve 
setting to safely return the pipeline to restricted service so that 
additional integrity assessment can be completed. This plan also 
details the other actions Columbia Gas will take to comply with the 
requirements set out in the CAO issued by PHMSA. As further detailed in 
this Plan, Phase 1 includes:
Preliminary Cause Determination
   Continue to support the NTSB in the ongoing investigation of 
        the incident and incorporate findings, as appropriate, into the 
        Integrity Assurance Plan.
Repairs to Incident Origin
   Verification of the integrity of the pipeline in the 
        vicinity of the incident origin.

   Repairs to Line SM-80 at the incident origin.
Verification of Cathodic Protection
   Verification that the cathodic protection (CP) system is 
        operating properly on SM-80 and the two adjacent pipelines, SM-
        86 and SM-86 Loop, within three miles upstream and three miles 
        downstream of the incident origin.
Preparation of Line SM-80 for In-Line Inspection
   Replacement of mainline valves along Line SM-80 from Lanham 
        to Broad Run with new, full bore valves to enable passage of 
        in-line inspection tools.

   Investigation and, where necessary, replacement of other 
        potential restrictions to the passage of in-line inspection 
        tools.

   Installation of a temporary launcher at Lanham Station and a 
        temporary receiver at Broad Run to enable the passage of in-
        line inspection tools. A permanent launcher and receiver will 
        be installed in Phase 2 (see Element 9 of ``Summary and 
        Overview of Integrity Assurance Plan--Phase 2,'' below).
Safe Return to Temporary Maximum Allowable Pressure
   Verification of the discharge pressure at Lanham Station 
        immediately prior to the incident for establishing a safe 
        temporary maximum allowable pressure.

   Inspection and full operation of all critical valves that 
        might be required during an emergency to ensure they can be 
        completely closed.

   Installation and adjustment of pressure regulation and 
        overpressure protection to support operation of the pipeline at 
        a restricted pressure.

   Return of Line SM-80 to service at or below the safe 
        temporary maximum allowable pressure on a temporary basis for 
        purposes of conducting an in-line inspection. The pressure will 
        be restored through a stepped approach that includes 
        instrumented leak surveys.

    In the course of completing the Phase 1 work, detailed 
documentation of measurements, pipe characteristics, pipe condition, 
pipe coating characteristics, environmental and other conditions will 
be collected. This information will be used, where appropriate, to 
support Phase 2 of the Integrity Assurance Plan. The results of the 
work outlined in this Integrity Assurance Plan will be shared with 
PHMSA, as well as the National Transportation Safety Board (NTSB) and 
the West Virginia Public Service Commission (WVPSC).
Safety
    Employee and public safety will be the highest priority in the 
course of conducting the work outlined in this plan. All work will be 
conducted in a safe manner and will comply with all Columbia Gas safety 
plans and procedures. Daily safety meetings will be held that will 
include employees, contractors and authorized visitors at the beginning 
of each work day. All company and state required one-calls shall be 
completed and the site cleared before any excavation activities occur. 
In addition, all persons performing tasks covered by 49 CFR Part 192, 
Subpart N shall be qualified according to the Columbia Gas Operator 
Qualification Plan.
Independent Review and Monitoring
    Columbia Gas will hire a qualified outside contractor 
(``independent monitor'') experienced in pipeline safety and pipeline 
integrity related issues to provide independent third party review and 
monitoring of the Integrity Assurance Plan prepared for Line SM-80 and 
the actions taken by Columbia Gas in the course of carrying out the 
work specified in the Plan. The independent monitor will (1) review and 
provide feedback to Columbia and PHMSA concerning the prudence and 
effectiveness of plans for verification of the integrity of Line SM-80, 
(2) review the results of inspections, tests and analysis completed for 
Line SM-80 during the course of this plan, (3) review the actions taken 
pursuant to the plan to ensure that they are reasonable and prudent, 
and (4) provide PHMSA with a quarterly report of progress towards 
compliance with the CAO and the Columbia Gas Integrity Assurance Plan.
Preliminary Cause Determination
    Following the Line SM-80 pipeline incident, an investigation into 
the cause of the incident was initiated by the National Transportation 
Safety Board (NTSB). As stated, the NTSB has reported that the ruptured 
pipeline was found to have areas consistent with external corrosion and 
that visual examination of the ruptured pipe revealed a six foot area 
that ran along the bottom of the pipe where the pipe thickness was 
measured to be less than 1/10 inch thick in some places (approximately 
.078 inch thick). The NTSB, however, has not released a preliminary 
cause determination, and the investigation is ongoing.
    Columbia Gas has been fully cooperating with the NTSB investigation 
and is committed to supporting the ongoing investigation of the 
incident. Columbia Gas has provided and will continue to provide 
requested information and support to the NTSB and will incorporate, as 
appropriate, the findings of the investigation into the Integrity 
Assurance Plan.
Repairs to Incident Origin
    The removed sections of pipe near the rupture origin will be 
replaced with new, coated pipe. Repair and testing of the pipe will 
follow the Pipe Repair, Modification and Hydrostatic Testing Plan 
provided in Attachment A. Up to approximately four joints (160 feet) of 
new 20 inch diameter, 0.375 wall thickness, API-5L X65 pipe will be 
installed at the location, The pipe will be hydrostatically tested for 
not less than eight hours at a minimum test pressure of 2,438 psig (100 
percent SMYS). The minimum test pressure of 2,438 psig is equivalent to 
244 percent of the pipeline MAOP of 1,000 psig.
    All girth welds will be non-destructively tested in accordance with 
the Columbia Gas Welding Manual and will be coated with a 100 percent 
solids two-part epoxy in accordance with Procedure 70.001.026 External 
Coating--Underground Facilities--New Construction or Maintenance 
Application (See Attachment B). In addition, the pipe will be supported 
with sand bags, covered in rock shield, and soft fill will be installed 
below and around the pipe to ensure the pipe is protected from damage. 
Prior to backfilling the pipe, an instrumented inspection of the 
coating will be performed in accordance with Procedure 70.001,013--
Inspect Pipe Coating with Holiday Detector (See Attachment C).
Verification of Cathodic Protection
    Columbia Gas will inspect and verify the proper operation of all CP 
rectifiers, test stations and other CP equipment on Lines SM-80, SM-86 
and SM-86 Loop within three miles upstream and three miles downstream 
of the incident origin. CP inspections will be completed after the pipe 
replacements described in the previous section. Inspections will 
include test station and rectifier readings that will be performed in 
accordance with Procedures 70.002.008--P/S Reading--Test Stations, 
70.002.001-Readings--Casing and 70.002.003--Reading--Rectifier (See 
Attachment D) and will be documented in the company Work Management 
System. Any deficiencies will be documented and remediated prior to 
continuing the Phase 1 Plan.
Preparation of Line SM-80 for In-Line Inspection
    Line SM-80 from Lanham Compressor Station to the Broad Run valve 
setting is currently not equipped to allow the passage of in-line 
inspection tools. Pipe replacements, equipment replacements and 
facility enhancements, as follows, will be performed to prepare the 
pipeline for the passage of in-line inspection tools:

   The existing mainline plug valves on Line SM-80 at Rocky 
        Hollow and Patterson Fork Valve Settings will be removed and 
        replaced with new ball valves that will support the passage of 
        ILI tools. The replacement and testing of the pipe at these 
        locations will follow the Pipe Repair and Hydrostatic Testing 
        Plan shown in Attachment A. Pipe exposed during the course of 
        the valve replacement work will be inspected following the 
        Columbia Gas pipe inspection protocols (see Attachment E).

   A review of pipe materials and mapping will be completed to 
        identify any other restrictions that would inhibit the passage 
        of in-line inspection tools. Where such restrictions are 
        identified they will be investigated and, if necessary, 
        replaced to ensure the passage of in-line inspection tools. The 
        replacement and testing of the pipe at these locations will 
        follow the Pipe Repair and Hydrostatic Testing Plan shown in 
        Attachment A. Pipe exposed during the course of investigation 
        or replacement work will be inspected following the Columbia 
        Gas pipe inspection protocols (see Attachment E).

   Temporary launchers and receivers sized and compatible with 
        high resolution in-line inspection tools will be installed. A 
        temporary launcher will be installed at Lanham Compressor 
        Station and a temporary receiver will be installed at the Broad 
        Run Valve setting. Due to the long lead time associated with 
        permanent launchers and receivers, temporary facilities will be 
        used to allow for in-line inspection in the near term. However, 
        permanent facilities will be fabricated and installed in Phase 
        2, and will be installed prior to the return of Line SM-80 to 
        full service. See section titled ``Summary and Overview of 
        Integrity Assurance Plan--Phase 2''.

   All girth welds will be non-destructively tested in 
        accordance with the Columbia Gas Welding Manual and will be 
        coated with a 100 percent solids two-part epoxy in accordance 
        with Procedure 70.001.026 External Coating--Underground 
        Facilities (See Attachment B). In addition, the pipe will be 
        supported with sand bags, covered in rock shield, and soft fill 
        will be installed below and around the pipe to ensure the pipe 
        is protected from damage. An instrumented inspection of the 
        coating will be performed prior to backfilling the pipe in 
        accordance Procedure 70.001.013 Inspect Pipe Coating with 
        Holiday Detector (See Attachment C).

    A drawing showing the areas along SM-80 where work is planned to 
prepare the line for the passage of in-line inspection tools is 
included in Attachment F.
Safe Return to Temporary Maximum Allowable Pressure
    The following measures will be taken to ensure the integrity of 
Line SM-80 before it is returned to restricted service.

   Repairs--Any actionable anomalous conditions discovered on 
        the SM-80 pipeline during the course of completing Phase 1 of 
        the Integrity Assurance Plan will be repaired following 
        Operations and Maintenance Plan 220.02.01 Pipeline Repair (see 
        Attachment G).

   Critical Valves--All critical valves along the SM-80 
        pipeline system from Lanham to Broad Run that may be required 
        during an emergency will be inspected and fully operated to 
        ensure that they can be completely closed. Valve inspections 
        will follow Plan 220.03.02 Valve Inspection and Operation and 
        Procedure 220.002.001 inspection & Operation--Valve (see 
        Attachment H) except that each valve will be fully operated. A 
        schematic depicting all critical valves that will be inspected 
        and operated is provided in Attachment I.

   Discharge Pressure Review and Validation--A report 
        validating the SM-80 discharge pressure at Lanham Compressor 
        Station at the time of the incident is included in Attachment 
        J. Columbia Gas has reviewed SCADA pressure data and has 
        validated that the discharge pressure at Lanham Compressor 
        Station on Line SM-80 at the time of failure was greater 
        than,929 psig, which Supports a temporary MAOP of 741 psig (80 
        percent of 929 psig). However, due to favorable market 
        conditions, Columbia Gas has determined that additional safety 
        measures can be taken and will further restrict the temporary 
        MAOP to 600 psig for the duration of the Integrity Assurance 
        Plan.

   Return to Service under Temporary Maximum Allowable 
        Operating Pressure--Once the pipeline repair work is completed, 
        the measures prescribed in this plan have been satisfactorily 
        completed, and approval is received from the Director of the 
        PHMSA Eastern Region, Columbia Gas will follow the Return to 
        Service plan provided in Attachment K, to safely return Line 
        SM-80 to restricted operation for purposes of conducting an in-
        line inspection. Columbia Gas plans to return the pipeline 
        pressure to no more than is necessary to efficiently and 
        effectively conduct an in-line inspection on Line SM-80 between 
        Lanham and Broad Run (not to exceed 600 psig). After successful 
        completion of the necessary in-line inspections, Columbia Gas 
        will isolate Line SM-80 from other sources of natural gas 
        supply and reduce the pressure of the pipeline to below 300 
        psig until completing the remaining requirements of this 
        Integrity Assurance Plan and PHMSA has granted the necessary 
        approvals to restore full service to the pipeline.

   The Return to Restricted Service Plan (Attachment K) 
        requires step increases in pressure in quarter increments up to 
        the temporary MAOP of 600 psig. Each quarter step will be 
        followed by a 30 minute idle period. Following each 30 minute 
        idle period, an instrumented leak survey will be conducted over 
        the entire pipeline using instrumented aerial patrol. In 
        addition, an on-ground instrumented leakage patrol will be 
        conducted for 300 feet upstream and downstream from the 
        incident location. Any leaks discovered will be investigated 
        and resolved before continuing the quarter step process. 24 
        hours after the fourth pressure increment is completed, another 
        set of aerial and ground leak surveys will be conducted. Any 
        leaks discovered will be investigated and resolved as soon as 
        practical, but within 24 hours.

   The Return to Restricted Service Plan will be initiated only 
        during weather conditions conducive to ensure successful aerial 
        leakage patrol of the pipeline (not during periods of high 
        winds or severe weather). Should conditions change during 
        implementation of the Return to Restricted Service Plan and 
        aerial patrol can no longer be effectively conducted, the 
        pressure on the pipeline will be lowered to the previous step 
        up in pressure until effective aerial patrol can be completed.

   All pressure control and overpressure protection devices 
        will be set to ensure that the temporary MAOP of 600 psig will 
        not be exceeded. Line SM-80 will continue to be isolated from 
        Line SM-86 and SM-86 Loop while the temporary maximum allowable 
        operating pressure is in effect. Overpressure protection 
        devices at Lanham Compressor Station will be used to limit the 
        operating pressure at or below the pressure necessary to 
        effectively and efficiently run the in-line inspection tools, 
        and in no case above 600 psig.
Preliminary Phase I Schedule
    The schedule for completion of tasks outlined in this Phase 1 plan 
is dependent upon many factors including receipt of environmental and 
other clearances, weather, availability of materials and other factors. 
A Gantt chart containing a preliminary schedule for the completion of 
each major item outlined in this plan is included in Attachment L. This 
schedule is based upon information known at this time and is subject to 
change as actions under this plan are carried out.
Summary and Overview of Integrity Assurance Plan--Phase 2
    Upon completion of Phase 1 of the Integrity Assurance Plan, Line 
SM-80 will have been repaired at the rupture site and verified safe for 
a return to service at a temporary maximum allowable pressure not to 
exceed 600 psig for purpose of performing additional integrity 
assessment. Line SM-80 will have been made capable of passage of in-
line inspection tools and additional work will have been completed to 
aid in the comprehensive integrity assessment of Line SM-80.
    Following the successful completion of Phase 1, Columbia Gas will 
seek approval from the Director of PHMSA Eastern Region for initiation 
of a Phase 2 plan. The Phase 2 plan will be documented and submitted 
for approval prior to initiation. Key elements of the Phase 2 plan will 
include:

   1.  Continued support of the ongoing NTSB investigation and 
        incorporation, as appropriate, of findings of the investigation 
        into the Integrity Assurance Plan.

   2.  Verification of Line SM-80 pipe properties and data to ascertain 
        if records reflect actual pipe specifications, including 
        representative sampling with bell-hole excavation, inspection 
        and validation.

   3.  Verification of MAOP records for Line SM-80 and implementation 
        of corrective measures if records do not substantiate current 
        MAOP.

   4.  The SM-80 pipeline from Lanham to near Broad Run will be 
        prepared for the passage of instrumented in-line inspection 
        tools by running cleaning pig(s) and a pig equipped with a 
        gauge plate to further ensure that there are not restrictions 
        for the in-line inspection tools. Columbia plans to conduct an 
        in-line inspection using Baker Hughes 20 inch high resolution 
        magnetic flux leakage (MFL) and high resolution caliper ILI 
        tools coupled with an inertial mapping unit along Line SM-80, 
        from Lanham to Broad Run.

   5.  After successful completion of the necessary in-line 
        Inspections, Columbia will isolate Line SM-80 from other 
        sources of natural gas supply and reduce the pressure of the 
        pipeline to below 300 psig until such time as Columbia has 
        completed the necessary steps under this Integrity Assurance 
        plan and PHMSA has granted the necessary approvals to restore 
        full pressure service to the pipeline.

   6.  Investigation of anomalies and repairs (as necessary), based on 
        ILI results

   7.  Performance of a close interval survey from Lanham to Broad Run 
        of Lines SM-80, SM-86 and SM-86 Loop.

   8.  Performance of a coating integrity survey and correction of any 
        deficiencies in areas where the survey indicates potentially 
        inadequate cathodic protection (i.e., where readings fail to 
        meet the criteria of 49 CFR Part 192, Subpart I).

   9.  Installation of a permanent launcher at the Lanham Compressor 
        Station and permanent receiver at Broad Run on Line SM-80, to 
        enable the passage of in-line inspection tools in the future.

  10.  Establishment of a long term integrity assurance and 
        reassessment plan for Line SM-80 for incorporation into the 
        Columbia Gas Integrity Management Plan.

  11.  Columbia Gas will contract with a qualified contractor to 
        provide a geotechnical survey of Line SM-80 between Lanham 
        Compressor Station and Broad Run to identify any areas of 
        significant earth movement within the pipeline right of way 
        that could adversely impact the pipeline. Any such areas 
        identified will be investigated and remediated, as necessary.
Criteria--Assessment, Repair, Documentation, Request for Approval and 
        Restoration of Full Service--Phase 3
    The following elements will be completed under Phase 3:

  1.  Columbia Gas will complete the assessment in Phase 2 and perform 
        any necessary repairs by December 20, 2013.

  2.  Columbia Gas will maintain records of all work performed as part 
        of the Integrity Assurance Plan and will prepare a complete 
        package of information for presentation to the PHMSA Eastern 
        Region, once the steps under Phase II have been completed. 
        Based on successful completion of the Integrity Assurance 
        measures, Columbia Gas will present this information and seek 
        PHMSA Eastern Region approval to return Line 5M-80 to full and 
        normal service.

  3.  Line SM-80 will only be returned to normal service after all work 
        has been successfully completed and approval has been granted 
        by the Director of the PHMSA Eastern Region.
Conclusion Criteria--Periodic and Summary Reporting and Documentation
        --Phase 4
    Columbia Gas will take steps to ensure that PHMSA is kept informed 
of progress during each phase of implementation of this plan, will 
provide summary reports and will maintain documentation and report 
certain expenditures associated with implementation of this plan as 
further detailed below:

  1.  Monthly reports for Phase 1--Columbia Gas will submit monthly 
        reports to the Director of the PHMSA Eastern Region that: (1) 
        include all available data and results of the testing and 
        evaluations required by the CAO; and (2) describe the progress 
        of the repairs or other corrective and/or remedial actions 
        undertaken. The first monthly report is due by the third of 
        each month until Phase 1 has been completed. The Director may 
        adjust the reporting period upon written request of Columbia 
        Gas.

  2.  Quarterly Reports for Phase 2 Columbia Gas will submit quarterly 
        reports to the Director of PHMSA Eastern Region that: (1) 
        include all available data and results of the testing and 
        evaluations required by the CAO; and (2) describe the progress 
        of the repairs or other corrective and/or remedial actions 
        being undertaken. The first calendar quarterly report is due 
        once Phase I has been completed, as determined by the Director 
        of the Eastern Region. There should be four quarterly report 
        submissions while this order is still in effect.

  3.  Summary Report for Phase II--Once Phase 2 has been completed, a 
        composite summary of all work performed will be assembled and 
        presented to the Director of the PHMSA Eastern Region. The 
        Director will review the summary as part of the consideration 
        for approval to return Line 5M-80 to normal service.

  4.  Documentation--Columbia Gas will maintain documentation of the 
        costs associated with the implementation of the CAO and will 
        include in each monthly report submitted the to-date costs 
        associated with: (1) preparation and revision of procedures, 
        studies and analysis; (2) physical changes to the pipeline 
        infrastructure, including repairs, replacements and other 
        modifications; and (3) environmental remediation, if 
        applicable.
                               Appendix B

    U.S. Department of Transportation Press Release--April 20, 2012

         Secretary LaHood Pledges Support to Expedite Pipeline 
                         Modernization Project

     Increased Safety, More Energy Capacity & Thousands of New Jobs

    PITTSBURGH, Pa.--U.S. Department of Transportation Secretary Ray 
LaHood today announced that the agency will lead the effort to help 
expedite Federal permitting for a 1,000 mile pipeline modernization 
project by NiSource, Inc. that will produce thousands of jobs, enhance 
safety and increase energy capacity.
    ``A year ago, I asked pipeline operators to take a hard look at 
their infrastructure and identify those sections of pipeline that need 
to be repaired, rehabilitated or replaced to ensure safer and more 
reliable delivery of energy resources,'' said Secretary LaHood. ``And 
we are happy to help NiSource speed up construction and replace some of 
the oldest pipelines in the nation, ensuring good jobs and increased 
safety for people in Pittsburgh, as well as throughout Pennsylvania and 
the other states that will benefit from this project.''
    Secretary LaHood and PHMSA Administrator Cynthia Quarterman met 
with Pittsburgh Mayor Luke Ravenstahl and representatives from NiSource 
in Pittsburgh today to pledge their support in expediting the 
construction. NiSource, Inc. has announced it will modernize its 
Columbia Gas Transmission, LLC gas transmission and storage system by 
replacing aging infrastructure that serves communities in six states, 
including the Marcellus shale gas production region, where the majority 
of the pipeline infrastructure is more than 40 years old and running on 
inefficient platforms.
    Project Spans Six States
    This massive modernization project will take place in Kentucky, 
Maryland, Ohio, Pennsylvania, Virginia and West Virginia, and it will 
promote the safe and reliable delivery of energy resources across the 
Midwest, Mid-Atlantic and Northeastern regions of the United States. 
NiSource projects that the modernization project will:

   Invest $4 billion over 10 to 15 years, beginning in 2012;

   Produce an estimated 7,000 to 8,000 direct jobs by replacing 
        aging infrastructure with safer and more reliable pipelines; 
        and

   Replace approximately 1,000 miles of large diameter pipeline 
        using domestic-made steel.

    ``A modern pipeline infrastructure is crucial for the efficient and 
safe delivery of our nation's resources, and this is exactly the kind 
of project that government should help facilitate,'' said PHMSA 
Administrator Cynthia Quarterman. ``We will help them work through the 
process, and make sure the project is constructed safely.''
    A year ago, Secretary LaHood issued a Call to Action to the 
nation's pipeline operators, asking them to take a hard look at their 
infrastructure and identify pipelines that need to be repaired, 
requalifed or replaced to ensure safer and more reliable delivery of 
energy resources. This project is also in accordance with the 
President's Executive Order to Improve Performance of Federal 
Permitting and Review of Infrastructure Projects.
    ``I commend Pennsylvania for making pipeline safety a priority by 
passing the Gas and Hazardous Liquids Pipeline Act,'' said Secretary 
LaHood. ``This is personal for all of us--none of us ever want to see 
another tragedy like the one that happened in Allentown.''
    DOT will coordinate with other government entities to identify 
opportunities to remove overlaps and expedite the regulatory and 
approval processes without sacrificing safety or lowering industry 
standards.
    About PHMSA
    There are more than 2.5 million miles of pipelines that deliver oil 
and gas to communities and businesses throughout the United States. 
PHMSA provides information and resources to the public to help them 
stay safe around pipelines through its Pipeline Safety Awareness 
website, State Pipeline Profiles and pipeline safety workshops for 
operators and emergency responders. PHMSA also urges the public to 
learn more about 811, a toll-free number that everyone should call 
before beginning any excavation project.
    The Pipeline and Hazardous Materials Safety Administration develops 
and enforces regulations for the safe, reliable, and environmentally 
sound operation of the Nation's 2.5 million mile pipeline 
transportation system and the nearly 1 million daily shipments of 
hazardous materials by land, sea, and air. Please visit http://
phmsa.dot.gov for more information.

                               Appendix C

                         142 FERC para. 61,062

                        UNITED STATES OF AMERICA

                  FEDERAL ENERGY REGULATORY COMMISSION




Before Commissioners:         Jon Wellinghoff, Chairman;
                              Philip D. Moeller, John R. Norris,
                             Cheryl A. LaFleur, and Tony T. Clark.


Columbia Gas Transmission, LLC                Docket No. RP12-1021-000
                  ORDER APPROVING CONTESTED SETTLEMENT
                       (Issued January 24, 2013)
    1. On September 4, 2012, Columbia Gas Transmission, LLC (Columbia) 
filed with the Commission a Stipulation and Agreement of Settlement 
(Settlement) that represents a settlement of Columbia's base rate 
levels and other issues related to the repair and maintenance of 
Columbia's aging pipeline system. According to Columbia, the Settlement 
represents a collaborative resolution between Columbia and the vast 
majority of its shippers to address complex issues arising from recent 
and anticipated changes in pipeline safety requirements and the aging 
nature of Columbia's system. As discussed below, we approve the 
contested Settlement on the basis that it provides an overall just and 
reasonable result.
Background
    2. Columbia states that the Settlement arose from Columbia's 
comprehensive evaluation of its interstate pipeline transmission 
facilities, which identified areas for rehabilitation or replacement in 
order to modernize its system, improve system integrity, and enhance 
service reliability and flexibility. According to Columbia, 
approximately 73 percent of the 12,000 miles of its system subject to 
the United States Department of Transportation's (DOT) regulation was 
constructed before the enactment of Federal pipeline safety standards 
in 1970. In addition, Columbia states that its system contains 
approximately 1,272 miles of bare steel pipeline, which is at higher 
risk for corrosion and failure. According to Columbia, this is 
significantly more bare steel pipeline than any other interstate 
pipeline subject to DOT regulation. Columbia states that the majority 
of its system cannot accommodate in-line inspection and cleaning tools.
    3. Columbia also states that approximately 55 percent of its more 
than 300 compressor units were installed before 1970. Columbia states 
that it has 18 compressor facilities, with 57 compressor units, which 
must be available 100 percent of the time during the November to March 
winter period in order to ensure that Columbia can make all of its firm 
deliveries.
    4. Columbia states that its evaluation of its interstate facilities 
identified a number of specific rehabilitation and modernization 
projects that comprise its Modernization Program. Columbia states that 
pursuant to its Modernization Program, the pipeline will make 
significant capital expenditures over the next 10 to 15 years to 
modernize its interstate pipeline system infrastructure, and to enhance 
the system's reliability, safety and regulatory compliance. These 
projects focus on replacing high pressure bare steel pipelines and 
pipelines with a history of failure in locations where there is the 
greatest risk that a pipeline failure would cause a disruption of 
service or threaten public safety. These projects also focus on 
modernizing compressor units along constrained mainlines serving a 
broad customer base.
    5. Columbia avers that the Settlement represents a fair and 
balanced resolution of numerous issues relating to Columbia's base rate 
levels, the Modernization Program, and the recovery of revenue 
requirements associated with the Program.
The Settlement
    6. Columbia's September 4, 2012 Settlement generally provides for 
the following:

   An annual $35 million rate reduction (retroactive to January 
        1, 2012), and an additional base rate reduction of $25 million 
        each year beginning January 1, 2014, both reductions to end on 
        the effective date of Columbia's next Natural Gas Act (NGA) 
        section 4 general rate case, or a subsequent NGA section 5 rate 
        adjustment.

   Initial refunds to firm shippers of $50 million in two equal 
        installments.

   A rate moratorium through January 31, 2018 and an NGA 
        section 4 general rate filing obligation no later than February 
        1, 2019.

   A capital cost recovery mechanism (CCRM), through which 
        Columbia would recover the revenue requirements associated with 
        the Modernization Program.

   A revenue sharing mechanism under which Columbia will refund 
        to its customers 75 percent of any base rate revenues it 
        collects over $750 million in any year after January 1, 2012.

   The standard of review for future changes to the Settlement 
        is the just and reasonable standard.

    7. Pursuant to the Settlement, the CCRM would recover the costs (up 
to $300 million annually, subject to a 15 percent tolerance) associated 
with ``Eligible Facilities'' that have been placed in service and 
remain in service. The Settlement includes an initial five-year term 
for the CCRM (January 1, 2014 -January 1, 2019) to recover costs 
Columbia incurs during the 2013-2017 period as part of the 
Modernization Project. Appendix E to the Settlement identifies the 
specific eligible replacement and upgrade projects that Columbia 
intends to undertake each year between 2013 and 2017, and the estimated 
costs of each project. Appendix E sets forth the location of each 
pipeline replacement and looping project and the number of miles of 
pipeline to be replaced or constructed in each project. Appendix E also 
identifies the location of each compressor unit to be replaced, the 
horse power of the replacement compressor unit, and which existing 
units will be converted to standby service.
    8. Section 7.2 of the Settlement requires Columbia to obtain the 
consensus of 75 percent of the shippers paying the CCRM rate 
(determined by billing determinants) to add, remove or substitute 
Eligible Facility projects, or to modify an Eligible Facility. Columbia 
retains the discretion to unilaterally perform projects that it 
reasonably believes could lead to imminent unsafe conditions, including 
replacing bare steel pipeline, subject to the cost and scope 
limitations otherwise applicable to projects eligible for CCRM 
recovery. Columbia also agrees to a $100 million annual capital 
maintenance expenditure for transportation and storage projects that 
will not be recouped through the CCRM recovery mechanism, and to use 
any amounts less than $100 million spent in a given year as a reduction 
to plant investment. Storage and gathering projects are also 
specifically excluded from recovery as Eligible Facilities.
    9. The Settlement provides for Columbia to earn a return on the 
capital costs included in the CCRM through a total net rate base 
multiplier of 14 percent, made up of a pre-tax rate of return of 12 
percent, and Taxes Other Than Income of 2 percent. Columbia will 
recalculate the CCRM on an annual basis. Further, Columbia states that, 
in order to provide rate stability and safeguard shippers against 
losses in billing determinants, the Settlement requires Columbia to 
calculate the annual per unit CCRM rate based on the greater of (1) 
actual annual billing determinants for all non-incremental rate 
customers adjusted for discounting \1\ or (2) an agreed-upon minimum 
level of billing determinants (billing determinant floor). The 
Settlement provides that in each annual CCRM filing, Columbia will true 
up any over or under-recovery of its CCRM revenue requirement during 
the preceding year.\2\ However, if Columbia's discounted rate 
transactions reduce Columbia's CCRM revenue below the level that would 
result from the billing determinant floor, Columbia must impute the 
revenue it would achieve by charging the maximum rate for service at 
the level of billing determinant floor. Columbia must also assume that 
all negotiated rate transactions are at the maximum rate. Absent 
agreement of the parties and approval of the Commission, the CCRM will 
not be used to recover Modernization Program costs incurred after 2017.
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    \1\ The Settlement treats the CCRM as an add on to Columbia's base 
rate and provides that Columbia will attribute any discounts to the 
total base rate, including the CCRM add-on, proportionately between the 
CCRM and the remainder of the applicable base rate.
    \2\ Section 7.7 of the Settlement provides that each CCRM Rate 
calculation will include an annual true-up so that any over-or under-
recovery of revenue requirements from the previous year shall be 
recovered in the next succeeding CCRM Rate filing, calculated each year 
(subject to the annual and overall CCRM caps) by comparing the actual 
revenue requirements to the revenues received during the recovery 
period. The Settlement provides that each subsequent annual CCRM filing 
shall include revenue requirements related to Eligible Facilities 
placed in service during the prior November 1 through October 31 
period, except that if the CCRM remains in place for the full five year 
Initial Term, the final year of the CCRM shall include revenue 
requirements related to the Eligible Facilities placed in service 
during November and December of 2017.
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    10. Columbia states that the CCRM will avoid ``pancaking'' NGA 
section 4 rate cases. Columbia also claims the CCRM will make the rate 
review process more efficient by limiting the scope of an annual review 
to whether Columbia's actual capital expenses in the past year meet its 
Eligible Facilities Plan. The Settlement also provides that Columbia 
will remove its existing daily scheduling penalty provision from its 
tariff.
    11. The Settlement provides that Columbia will not propose any new 
cost tracking mechanism during the term of the Settlement.
    12. The Settlement states that Columbia will not propose market 
based rates for new storage projects during the term of the Settlement.
    13. The Settlement provides that it is not precedential and is 
being agreed to only in light of existing circumstances on Columbia's 
system, particularly that approximately 50 percent of Columbia's system 
was constructed prior to 1960 and approximately 55 percent of 
Columbia's compressor units were installed prior to 1970. In addition, 
Columbia's system contains approximately 1,272 miles of bare steel 
pipeline subject to DOT regulation, and the majority of the system 
cannot accommodate in-line inspection and cleaning tools.
    14. The Settlement also provides for the severance of the direct 
interests of Contesting Parties, and an option for Columbia to withdraw 
the settlement offer if there are contesting parties that represent 10 
percent or more of total peak day transportation entitlements on the 
system.
Comments on Settlement
    15. Numerous customers from all sectors of the industry filed in 
support of the Settlement.\3\ Those customers filing in support all 
note that given the unique circumstances of Columbia's system, the 
Settlement represents a fair and balanced resolution that allows 
Columbia to make critical necessary modernization upgrades to its 
system while providing its customers with real and meaningful benefits 
in terms of both improved services and flexibility through the 
modernization efforts, and rate relief and predictability. The 
supporting customers note that Columbia's system serves customers in 
eleven states and the District of Columbia and provides significant 
take away capacity for gas producers in the expanding Marcellus and 
Utica shale plays.\4\ The customers state that they will benefit from 
increased operational flexibility and reliability, as well increases in 
public safety, as a result of the Modernization Program. Those 
customers also specifically identify the Settlement's significant base 
rate reduction, the retroactive decrease in base rates, the $50 million 
in refunds, the revenue sharing provision and the rate predictability 
resulting from the moratorium as key rate components underlying their 
support of the Settlement. Exelon, NiSource, the Virginia Cities, and 
others also note that by allowing Columbia to recover the costs 
associated with the necessary system upgrades through the CCRM, it can 
avoid successive rate case filings and the inherent financial costs and 
distractions of resources associated with protracted litigation. 
Chesapeake notes that customers also benefit through Columbia's 
agreement to spend $100 million annually on maintenance, and the fact 
that the CCRM recovery mechanism is capped on both an annual and full 
program basis. It also approves of the fact that the CCRM proposal 
specifically identifies projects and provides shippers with the right 
to monitor and challenge Columbia's expenditures. In sum, Columbia's 
shippers support the Settlement because they find the CCRM to be a fair 
mechanism for Columbia to complete and recover the costs of needed 
system modernizations that will enable Columbia to maintain the 
integrity and reliability of its system and protect the public's 
safety, while also providing the customers with immediate and concrete 
benefits in the form of rate reductions and predictability.
---------------------------------------------------------------------------
    \3\ Those filing comments in support of the Settlement include 
Cabot Oil and Gas Corporation (Cabot), Exelon Corporation (Exelon), the 
NiSource Delivery Companies (including Columbia Gas of Maryland), New 
Jersey Natural Gas Company and NJR Energy Services Company (NJR), 
Waterville Gas and Oil Company, The Cities of Charlottesville and 
Richmond, Virginia (Virginia Cities), Interstate Gas Supply, Indicated 
Shippers, Duke Energy of Ohio and Duke Energy of Kentucky, Antero 
Resources Appalachian Corporation, and Chesapeake Energy Marketing, 
Inc. (Chesapeake).
    \4\ See, e.g., Comments of Cabot.
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    16. Only the Maryland Public Service Commission (Maryland PSC) 
opposes the Settlement. It asserts that the surcharge mechanism 
proposed to recover the costs of the Modernization Program is an 
inappropriate method to recover capital costs, and generally challenged 
the 14 percent rate base multiplier to be used to determine a pre-tax 
rate of return and taxes other than income taxes to be recovered 
through the CCRM. According to the Maryland PSC, it and the Commission 
have repeatedly considered trackers such as the CCRM to be 
inappropriate for core infrastructure spending because they reduce the 
pipeline's incentive to maximize revenues and minimize costs. The 
Maryland PSC also asserts that the CCRM would shift the burden of 
investment costs from Columbia to its customers, and its approval could 
start the slide down a slippery slope toward such mechanisms replacing 
rate cases as the primary method for recovering major investment costs. 
The Maryland PSC also argues that the Commission has consistently 
disallowed such mechanisms, including recently rejecting a similar 
surcharge to recover safety charges,\5\ because recovering such costs 
in a surcharge is contrary to the requirement in the Commission's 
regulations \6\ to design rates based on estimated units of service.
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    \5\ Maryland PSC Protest at 2 (citing Granite State Gas 
Transmission, Inc., 132 FERC para. 61,089 (2010) (Granite State)).
    \6\ 18 C.F.R. Sec. 284.10(c)(2) (2012).
---------------------------------------------------------------------------
    17. In its reply to the Maryland PSC's protest, Columbia asserts 
that the Settlement represents a comprehensive package that enjoys the 
unanimous support of Columbia's shippers, and that the CCRM and rate 
base multiplier challenged in the protest are two integral components 
of the indivisible Settlement. Columbia asserts that the Settlement 
includes numerous protections insisted on by its shippers to ensure 
that Columbia has the incentive to perform the modernization work 
efficiently and effectively, including specifically defining the 
Eligible Facilities for which costs may be recouped by the CCRM, and 
placing caps on the recoverable amounts so that Columbia is at risk for 
costs that fall outside the scope of the defined projects and for any 
costs that exceed the caps. Columbia further asserts that the 
Settlement contemplates significant shipper oversight through a 
requirement for annual meetings to review projects and costs for the 
past period and for the upcoming year. Columbia also states that the 
Settlement limits each annual rate filing to recovery of revenues 
related to Eligible Facilities that are placed in service between 
November 1 and October 31 of the prior year. Columbia also claims that 
the Settlement is consistent with, and supported by, the Commission's 
policy strongly supporting negotiated settlements as a means of 
providing regulatory certainty and administrative efficiencies for the 
Commission and the parties, by avoiding lengthy and costly rate 
proceedings. Finally, Columbia argues that the Commission should not 
allow the Maryland PSC's protest to prevent Columbia's shippers from 
realizing the substantial benefits afforded by the Settlement.
Discussion
    18. In order to approve Columbia's proposed Settlement over the 
objections of the Maryland PSC, the Commission must find that the 
settlement is just and reasonable.\7\ In determining whether to approve 
a contested settlement under that standard, section 385.602(h)(1)(i) 
\8\ of the settlement rules permits the Commission to decide the merits 
of the contested issues, if the record contains substantial evidence on 
which to base a reasoned decision, or if the Commission determines 
there is no genuine issue of material fact. In addition, as the 
Commission held in Trailblazer, even if some individual aspects of a 
settlement may be problematic, the Commission still may approve a 
contested settlement as a package if the overall result of the 
settlement is just and reasonable.\9\
---------------------------------------------------------------------------
    \7\ Trailblazer Pipeline Co., 85 FERC para. 61,345, at 62,339 
(1998), reh'g, 87 FERC para. 61,110 (1999), reh'g, 88 FERC para. 61,168 
(1999) (Trailblazer) (citing Mobil Oil Corp. v. FERC, 417 U.S. 283, 314 
(1974)).
    \8\ 18 C.F.R. Sec. 385.602(h)(1)(i) (2012).
    \9\ Trailblazer, 85 FERC para. 61,345 at 62,342-3, explaining what 
that order described as the second of three approaches the Commission 
has used to approve contested settlements, without severing the 
contesting parties.
---------------------------------------------------------------------------
    19. As discussed more fully below, after considering the Maryland 
PSC's comments opposing the Settlement, the Commission finds that those 
comments do not raise any genuine issue of material fact. The 
Commission also finds that the overall result of the settlement is just 
and reasonable. Therefore, the Commission approves the Settlement for 
all parties, including the Maryland PSC and the local distribution 
companies subject to regulation by the Maryland PSC.
    20. Maryland PSC's primary objection to the Settlement raises a 
policy issue, rather than any issue of fact: namely that the CCRM is 
contrary to the Commission's policy that capital costs incurred to 
comply with the requirements of the pipeline safety legislation should 
not be included in a cost-of-service tracking mechanism which 
guarantees the pipeline's recovery of those costs.\10\ As Maryland PSC 
points out, the Commission has stated that pipelines commonly incur 
capital costs in response to regulatory requirements intended to 
benefit the public interest, and recovering those costs in a tracking 
mechanism is contrary to the requirement, in section 284.10(c)(2) of 
our regulations to design rates based on estimated units of 
service.\11\ This requirement means that the pipeline is at risk for 
under-recovery of its costs between rate cases, but may retain any 
over-recovery. As the Commission explained in Order No. 436, this gives 
the pipeline an incentive both to (1) ``minimize costs in order to 
provide services at the lowest reasonable costs consistent with 
reliable long-term service'' \12\ and (2) ``provide the maximum amount 
of service to the public.'' \13\ Cost-trackers undercut these 
incentives by guaranteeing the pipeline a set revenue recovery. Thus, 
in accordance with this policy, in Florida Gas and Granite State, the 
Commission rejected proposals for safety cost trackers, with true-up 
mechanisms, made in NGA section 4 filings. The Commission has, however, 
permitted such a regulatory surcharge for pipeline safety costs in 
uncontested settlements.\14\
---------------------------------------------------------------------------
    \10\ Florida Gas Transmission Co., 105 FERC para. 61,171, at PP 47-
48 (2003) (Florida Gas), distinguishing such capital costs from 
security-related costs which may be included in a surcharge mechanism 
under the policy set forth in Extraordinary Expenditures Necessary to 
Safeguard National Energy Supplies, 96 FERC para. 61,299 (2001); 
Granite State, 132 FERC para. 61,089 at P 11.
    \11\ Florida Gas, 105 FERC para. 61,171 at P 47.
    \12\ Regulation of Natural Gas Pipelines After Partial Wellhead 
Decontrol, Order No. 436, FERC Stats. & Regs., Regulations Preambles 
1982-1985 para. 30,665, at 31,534 (1985).
    \13\ Id. at 31,537.
    \14\ See, e.g., Florida Gas Transmission Co., 109 FERC para. 61,320 
(2004); Granite State Gas Transmission, Inc., 136 FERC para. 61,153 
(2011).
---------------------------------------------------------------------------
    21. The Commission recently followed this policy when it rejected a 
protested proposal by CenterPoint Energy--Mississippi River 
Transmission, LLC (MRT), in an NGA general section 4 rate case filing, 
to recover regulatory safety costs through a tracker with a true-up 
mechanism.\15\ The order in that proceeding noted, however, that while 
the Commission was rejecting MRT's proposed safety tracker consistent 
with existing policy, that decision was based in part on the fact that 
the DOT's Pipeline and Hazardous Materials Safety Administration 
(PHMSA) is in the early stages of developing regulations to implement 
the 2011 Act. The Commission stated that it is open to considering the 
need for additional action as the PHMSA process moves forward and 
pipelines face increased regulatory requirements.
---------------------------------------------------------------------------
    \15\ CenterPoint Energy--Mississippi River Transmission, LLC, 140 
FERC para. 61,253 (2012) (MRT).
---------------------------------------------------------------------------
    22. In this case, the Commission finds that the Settlement and the 
CCRM provide a reasonable means for Columbia to recover the substantial 
costs of addressing urgent public safety and reliability concerns, 
without undercutting Columbia's incentives to operate efficiently and 
to maximize service to the extent that previously proposed and rejected 
surcharges would have done. As stated by Columbia, approximately half 
of its pipeline infrastructure regulated by the DOT is over fifty years 
old, approximately 55 percent of its compressors were installed before 
1970 and there is limited horsepower back-up at many critical 
locations. In addition, the system contains approximately 1,272 miles 
of potentially dangerous bare steel pipeline, many of its control 
systems run on an obsolete platform and because the older part of the 
system was not designed to accommodate in-line inspection, Columbia 
will only be able to inspect approximately thirty-five percent of the 
DOT regulated portion of its system using modern in-line inspection 
tools. Our approval of the Settlement and the CCRM will facilitate 
Columbia's ability to make the substantial capital investments 
necessary to correct these very significant problems and thus provide 
more reliable service while minimizing public safety concerns.
    23. We find that the CCRM surcharge proposed by Columbia includes 
numerous positive characteristics that distinguish the surcharge from 
those we have rejected previously, and that work to maintain the 
pipeline's incentives for innovation and efficiency. First, the 
development of the CCRM began with Columbia and its shippers engaging 
in a collaborative effort to review Columbia's current base rates, 
leading to Columbia's agreement to reduce its base rates by $35 million 
retroactive to January 1, 2012, by another $25 million effective 
January 1, 2014, and to provide refunds to firm shippers of $50 
million. Maryland PSC does not contest this aspect of the Settlement, 
which provides the shippers rate relief which could otherwise only be 
obtained pursuant to NGA section 5 and could not take effect in the 
retroactive manner provided by the Settlement. The Commission finds 
that these provisions of the Settlement assure that the base rates, to 
which the CCRM surcharge will be added, have been updated in a just and 
reasonable manner to reflect current circumstances on Columbia's 
system.
    24. Second, the Settlement identifies, by pipeline segment and 
compressor station, the specific Eligible Facilities for which costs 
may be recovered through the CCRM, and the Settlement delineates and 
limits the amount of capital costs and expenses for each such 
project.\16\ The Settlement also limits Columbia's ability to add or 
change projects. In addition, it is significant that Columbia agrees to 
continue making annual capital maintenance expenditures of $100 million 
for transportation and storage projects, which it will not seek to 
recover through the CCRM recovery mechanism. These provisions of the 
Settlement should assure that the projects whose costs are recovered 
through the CCRM go beyond the regular capital maintenance expenditures 
which Columbia would perform in the ordinary course of business and 
that the projects are critical to assuring safe and reliable operation 
of Columbia's existing system. In addition, these provisions should 
minimize disputes in Columbia's annual CCRM filings concerning the need 
for particular projects.
---------------------------------------------------------------------------
    \16\ By contrast, the surcharge mechanisms proposed in Florida Gas 
and MRT contained only general definitions of what type of costs would 
be eligible for recovery, leaving the pipeline considerable discretion 
as to what projects it would subsequently propose to include in the 
surcharge and creating the potential for significant disputes 
concerning the eligibility of particular projects.
---------------------------------------------------------------------------
    25. Third, and critically important to our approval of the CCRM, is 
Columbia's agreement to (1) establish a billing determinant floor for 
calculating the CCRM and (2) impute the revenue it would achieve by 
charging the maximum rate for service at the level of billing 
determinant floor before it trues up any cost under-recoveries.\17\ 
Also, any such true-up is limited to the $300 million annual cap and 
other related cost caps. These provisions, along with the required base 
rate reductions and the provision for Columbia to continue substantial 
capital maintenance investments that will not be recovered in the CCRM 
surcharge, subject Columbia to a continuing risk of cost under-
recovery. These aspects of the Settlement thus alleviate the 
Commission's historic concern that surcharges which guarantee cost 
recovery are not appropriate for recovering capital costs, because they 
diminish a pipeline's incentive to be efficient and to maximize service 
provided to the public. These provisions of the Settlement also protect 
Columbia's shippers from significant cost shifts if Columbia loses 
shippers or must provide increased discounts to retain business.
---------------------------------------------------------------------------
    \17\ By contrast, the surcharge mechanisms proposed in Florida Gas, 
Granite State, and MRT did not include a comparable billing determinant 
floor.
---------------------------------------------------------------------------
    26. Fourth, the CCRM would not be a permanent part of Columbia's 
rates. The Settlement provides that the CCRM will terminate on January 
1, 2019, unless the parties agree to extend it and the Commission 
approves the extension. Thus, subject to extension requiring the 
consent of all parties, the CCRM is meant to recover a set amount of 
costs over defined period, and will not become a permanent part of 
Columbia's rates.
    27. Finally, the surcharge is broadly supported, or at least not 
opposed, by all Columbia's customers. Based on all these factors, the 
Commission finds that Maryland PSC's policy objections to the CCRM 
mechanism do not justify rejection of the Settlement.
    28. Maryland PSC's only other contention in opposing the Settlement 
is its statement that an NGA general section 4 rate case in this 
instance would provide the opportunity to determine whether the 14 
percent rate base multiplier, inclusive of a 12 percent pre-tax rate of 
return and taxes other than income taxes of 2 percent for eligible 
facilities is just and reasonable. Rule 602(f)(4) of the Commission's 
regulations requires that, ``any comment that contests a settlement by 
alleging a dispute as to a genuine issue of material fact must include 
an affidavit detailing any issue of material fact by specific 
reference.'' Maryland PSC did not file any affidavit with its comments 
demonstrating an issue of fact concerning whether the rate base 
multiplier provides an unreasonable return. Thus, we cannot find that 
its protest raised a genuine issue of fact with respect to the return 
to be included in the CCRM surcharge.\18\
---------------------------------------------------------------------------
    \18\ See, e.g., San Diego Gas & Electric Company v. Sellers of 
Energy and Ancillary Services into Markets Operated by the California 
Independent System Operator Corporation and the California Power 
Exchange Corporation, et al., 128 FERC para. 61,004, at P 16 (2009); 
Duke Energy Trading and Marketing, L.L.C., et al., 125 FERC para. 
61,345, at P 31 (2008).
---------------------------------------------------------------------------
    29. The Commission also finds that all of Columbia's customers are 
likely to be in better position with the Settlement than without it. To 
the extent the Commission was to sever the Maryland PSC and local 
distribution companies it regulates,\19\ those LDCs and Maryland 
consumers could not receive the immediate benefits of the Settlement, 
including the retroactive rate reduction and refunds. Moreover, while 
the severed parties would not be subject to the CCRM when it takes 
effect next year, Columbia would be free to file section 4 rate cases 
to increase the severed parties' rates at such time as the CCRM 
resulted in Columbia's overall rates exceeding its current rates.
---------------------------------------------------------------------------
    \19\ See Trailbazer, 85 FERC para. 61,345 at 62,345, explaining 
that, if the Commission severs a public service Commission from a 
settlement, it must also sever the local distribution companies 
regulated by the public service Commission.
---------------------------------------------------------------------------
    30. The Settlement also includes numerous other significant 
benefits for Columbia's shippers which would not be available absent 
the Settlement. Aside from the significant retroactive rate reduction 
and refund payments already discussed, these include (1) the revenue 
sharing mechanism under which Columbia will refund to its customers 75 
percent of any base rate revenues it collects over $750 million in any 
year after January 1, 2012, (2) a rate moratorium that will provide 
rate certainty until 2018, (3) a requirement for the pipeline to file 
an NGA section 4 general rate case by February 2019, (4) the removal of 
Columbia's existing daily scheduling penalty, thus providing shippers 
greater flexibility to modify their daily takes to respond to 
unexpected changes in their need for gas without incurring additional 
costs, and (5) Columbia's agreement not to propose market-based rates 
for new storage projects during the term of the Settlement or to 
propose any additional cost tracking mechanisms.
    31. The Commission finds that the very substantial benefits that 
will inure to Columbia's shippers through the Settlement outweigh the 
inclusion of an otherwise disfavored surcharge, particularly given the 
customer protections inherent in the CCRM. The Settlement is crafted to 
address undisputed circumstances on Columbia's system, namely that the 
system is aging and that Columbia needs to make significant upgrades 
and repairs to modernize the system and to ensure that it will be able 
to continue to provide reliable firm transportation service, consistent 
with public safety. The Commission concludes that the benefits of the 
Settlement render the overall Settlement package just and reasonable.
    32. As we have stated repeatedly, the Commission favors 
collaborative efforts and settlements between pipelines and their 
shippers regarding rate and other contested issues, as such negotiated 
agreements conserve the Commission's time and resources. The instant 
Settlement is the result of an extensive and comprehensive effort on 
behalf of Columbia and its customers to review the pipeline's existing 
rates, to evaluate imminent issues with regard to the aging system, and 
to develop a plan to address and pay for the costs of modernizing that 
system. The Commission notes that the procedures undertaken by the 
pipeline and its customers are precisely the kind of pro-active 
discussions and communications between customers and the pipelines that 
the Commission has repeatedly encouraged, and we commend the parties 
for their efforts in reaching this agreement.
    The Commission orders:

    The Settlement is hereby approved as discussed in the body of this 
order.
    By the Commission. Chairman Wellinghoff is concurring with a 
separate statement attached.
    (S E A L)
                                          Kimberly D. Bose,
                                                         Secretary.
                       UNITED STATES OF AMERICA 
                  FEDERAL ENERGY REGULATORY COMMISSION
Columbia Gas Transmission Corporation              Docket No. RP12-
1021-000
                       (Issued January 24, 2013)
WELLINGHOFF, Chairman, concurring:

    I share the concerns about cost tracking mechanisms expressed in 
this proceeding by the Public Service Commission of Maryland. Cost 
tracking mechanisms reduce a pipeline's incentive for innovation, 
efficiency and cost minimization, and shift the risk embedded in the 
return on equity from the pipeline to the shippers.
    I am voting to approve the instant settlement because Columbia's 
shippers have negotiated significant limits to this cost tracking 
mechanism that mitigate my concerns. In particular, the cost tracking 
mechanism is limited to specifically identified projects, establishes a 
billing determinant floor at maximum tariff rates, and is not permanent 
part of Colwnbia's rates. Further, Columbia agrees that it will not 
propose any new cost tracking mechanism nor market based rates during 
the term of the settlement. In addition, there are other significant 
consumer benefits to approving the settlement. The settlement provides 
for $50 million in refunds, an annual $35 million rate reduction 
(retroactive to January 1, 2012), and an additional base rate reduction 
of $25 million each year beginning January 1, 2014.
    For these reasons, I am voting to approve the settlement. However, 
I encourage shippers of pipelines seeking to implement a cost tracking 
mechanism to consider additional limits to protect consumers. For 
example, I believe that it also would be appropriate for a pipeline to 
credit shippers all revenues from services provided over the facilities 
at issue that were not included in the rate design billing determinants 
and to explore a reduction in the return on equity that applies to 
those facilities.

                                           Jon Wellinghoff,
                                                          Chairman.

    The Chairman. Thank you. You answered my first one.
    Mr. Kessler?

             STATEMENT OF RICK KESSLER, PRESIDENT, 
                     PIPELINE SAFETY TRUST

    Mr. Kessler. Thank you, Mr. Chairman and Senator Manchin. 
Good afternoon to the members of the Committee and the public. 
I want to thank you for inviting me back to testify before the 
Committee again. My name is Rick Kessler, and I am here in my 
wholly voluntary and uncompensated role as the president of the 
Pipeline Safety Trust.
    And for years after each new tragedy we've been invited to 
testify about what's needed to prevent the next tragedy. 
Unfortunately, we're back again after the recent failure of the 
pipeline and the incident in Sissonville. The failure comes all 
too soon after a spate of incidents in California, Michigan, 
Pennsylvania, Montana, and Utah among many other places. Many 
of these failures had common threads and common solutions that 
could have prevented or at least minimized their impacts.
    The Trust and I were very happy to work with you, Mr. 
Chairman, your colleague Senator Boxer and my former bosses, 
Senator Lautenberg and Congressman Dingell, to enact the 2011 
Pipeline Safety Act. And that began to move regulators and 
industry in the right direction on some of these issues. But 
the speed of review, rulemaking, and implementation of the 
needed changes was and continues to be painfully slow and 
certainly not fast enough to have avoided the tragedy in 
Sissonville.
    Now, we've provided a great deal of testimony in the past 
on how we think we could improve pipeline safety in this 
country. I'm going to try and highlight some of the more 
pertinent issues to the re--things that are pertinent to the 
recent Sissonville failure and explosion.
    But since a lot of this information is still coming forward 
I don't want to judge too much because that would be unfair and 
premature. But I will say one of the critical issues related to 
any type of pipeline rupture is how quickly the pipeline 
operator, as you've pointed out, can identify the rupture has 
occurred and act to shut it down to minimize any further 
effects of the pipeline failure.
    In a perfect world built-in leak detection systems would 
alert a pipeline controller to the drop in pressure and allow 
for the quickest response to shut down the pipeline. 
Unfortunately as the recent PHMSA leak detection report shows 
less than 50 percent of major failures such as in Sissonville 
are initially identified by current leak detection 
technologies. We really need to do better. I think you know 
that, and I think everyone here knows that.
    Now once a failure is identified the pipeline operator 
still needs to be able to shut down the valves on either side 
of the failure site so that the natural gas boring into the 
community and subsequent fire is minimized. In the case of 
where natural gas ignites, such as in Sissonville, the closure 
of these valves is what we call a blowtorch effect on the 
neighborhood and allow emergency responders to get in there and 
take care of the people.
    Now, the final report on remote control and on automated 
valves that PHMSA recently provided this committee concludes 
that a cost effective strategy for reducing the consequences of 
natural gas pipeline failures is automated valves that can be 
closed within 10 minutes of failure.
    Now, I got to tell you, I've been working on this 
particular matter for upwards of 17 years as a staffer handling 
the authorization of Federal law after a very similar incident 
in Edison, New Jersey back in 1994, which you may remember. 
Same thing. Fortunately no one was killed, but a huge fireball 
and it took about 3 hours to shut down the line mainly because 
it was manual and just the mere act of turning the wheel took 
about an hour or more.
    Now, we agree with NTSB that such valves should require the 
automatic or remote shutoff valves, and there is a difference. 
Yet the Pipeline Safety Bill that we all worked on fell short 
of this requirement on existing pipelines in Sissonville and 
San Bruno.
    No doubt, Mr. Chairman, you opened your car this morning 
using a remote control. We use remote controls to turn off and 
on our TVs, to do all sorts of things, our garage doors, for 
instance. Yet somehow we find it acceptable that an industry 
can use 1960s technology in 2013 to close its valves. For 
industry, unfortunately we've seen far more stall than install 
of these technologies.
    It's unclear to us whether Sissonville failure was in an 
area where the company would have been required to do an 
integrity management plan. Only a small fraction of areas fall 
under these requirements. As we've testified before, these 
integrity management requirements must be expanded to cover all 
pipelines. And yet while we support integrity management, these 
programs are often fairly weak and need to be more much 
effective and easier to evaluate.
    Some of the issues that must be addressed include creating 
a clear way for regulators to establish whether a company is 
basing the risk assessments on valid records, minimizing direct 
assessment as an inspection tool, and ensuring that when direct 
assessment is used as opposed to, say, inline inspection, the 
techniques are adequate and being used correctly.
    We also must determine whether repair criteria within these 
programs undermine safety factors based on faulty assumptions 
and therefore are not addressing or perhaps exacerbating the 
problem.
    To summarize, the state of West Virginia, like surrounding 
states, has seen a dramatic increase in the development of 
natural gas resources and relating pipe--related pump lines. 
Speaking for myself alone, I actually think this is a good 
thing for our economy, for the nation, for energy security. But 
this boom in drilling has also led to the construction of more 
and more pipelines and facilities across the area and more and 
more particularly gathering lines, which you mentioned earlier 
which can be, as you said and the Administrator said, the same 
size as transmission pipelines, the same pressure as 
transmission pipelines. Unfortunately these lines are 
completely unregulated by the Federal Government. We agree with 
the Administrator that the Federal Government should have 
authority to regulate these lines.
    Finally, we believe that PHMSA is critical of the pipeline 
safety but not as effective a regulator as it should be. 
Certainly PHMSA can and must do more to regulate better 
regardless of budget. There is no excuse for continuing 
decades. It's not necessarily on this administration or the 
last, but it's been decades of neglect of this agency. However, 
we agree that PHMSA also suffers from a very serious lack of 
financial and personnel resources. This is particularly 
dangerous and shortsighted at a time when shale resources are 
feeding the rapid growth of pipeline mileage across the 
country.
    For that reason we support PHMSA's 2013 budget request 
which would provide significant and additional funding to 
support critical increases in inspectors and program 
development. It's good for the industry, the consumer, and the 
Nation because we need the public to have confidence in the 
safety of the system to ensure smooth growth and access to gas 
and oil from shale plays around the Nation.
    Thank you again for the opportunity to testify today. And I 
stand ready to answer any questions and continue to work with 
you, and you, Senator Manchin, and the rest of the Congress to 
move safety forward. Thank you.
    [The prepared statement of Mr. Kessler follows:]

  Prepared Statement of Eric Kessler, President, Pipeline Safety Trust
    Good morning, Chairman Rockefeller and members of the Committee. 
Thank you for inviting me to speak today on the important subject of 
pipeline safety. My name is Rick Kessler and I am testifying today in 
my purely voluntary, uncompensated role as the President of the 
Pipeline Safety Trust. My involvement and experience with pipeline 
safety stems from my years as one of the primary staff members on such 
issues in the House of Representatives and my subsequent work with the 
Pipeline Safety Trust.
    The Pipeline Safety Trust came into being after a pipeline disaster 
over thirteen years ago--the 1999 Olympic Pipeline tragedy in 
Bellingham, Washington that left three young people dead, wiped out 
every living thing in a beautiful salmon stream, and caused millions of 
dollars of economic disruption. While prosecuting that incident the 
U.S. Justice Department was so aghast at the way the pipeline company 
had operated and maintained its pipeline, and equally aghast at the 
lack of oversight from Federal regulators, that the Department asked 
the Federal courts to set aside money from the settlement of that case 
to create the Pipeline Safety Trust as an independent national watchdog 
organization over both the industry and the regulators. We have worked 
hard to fulfill that vision ever since, but with continuing major 
failures of pipelines, such as the one in Sissonville, West Virginia 
that brings us here today, we question whether our message is being 
heard.
    Born from a tragedy in Bellingham, but also riding on the facts and 
emotion of other tragedies in places like Edison, New Jersey; Carlsbad, 
New Mexico; Walnut Creek, California and Carmichael, Mississippi, we 
have testified to Congress for years about the improvements needed in 
Federal regulations to help prevent more such tragedies. For years we 
have talked about the need for more miles of pipelines to be inspected 
by smart pigs. We have pleaded for clear standards for leak detection, 
requirements for the placement of automated shut off valves, closing 
the loopholes that allow a growing mileage of pipelines to remain 
unregulated, and for better information to be available so innocent 
people will know if they live near a large pipeline and whether that 
pipeline is maintained and inspected in a way to ensure their safety.
    So here we are again after the very recent failure of a pipeline in 
Sissonville which completely destroyed three homes, damaged other 
homes, caused extensive damage to an interstate highway, and once again 
terrorized a community. This recent failure falls too soon after a 
spate of significant failures over the past few years in Michigan, 
California, Pennsylvania, Montana, and Utah. Many of these failures had 
common themes and common solutions that could have prevented or at 
least minimized their impacts. We have been asking for action on these 
issues in previous hearings following previous tragedies for years now. 
Last year, Congress passed the Pipeline Safety, Regulatory Certainty, 
and Job Creation Act of 2011, which began to move the regulators and 
the pipeline industry in the right direction on some of these issues, 
but the speed of review, rule making, implementation and enforcement of 
the needed changes was not sufficient to prevent the tragedy in 
Sissonville. It is our sincere desire not to be back in front of this 
committee again in the future saying the same things after yet another 
tragedy.
    The vision of the Pipeline Safety Trust is simple. We believe that 
communities should feel safe when pipelines run through them, and trust 
that their government is proactively working to prevent pipeline 
hazards. We believe that local communities who have the most to lose if 
a pipeline fails should be included in discussions of how best to 
prevent pipeline failures. And we believe that only when trusted 
partnerships between pipeline companies, government, communities, and 
safety advocates are formed, will pipelines truly be safer.
    Clearly trust in pipeline safety has now been lost in the community 
around Sissonville, so add those people to people in Michigan, 
California, Pennsylvania, Montana, Utah and elsewhere, where people now 
question whether the industry, regulators and legislators are really 
doing all they can to keep people and the environment safe.
    In my testimony today I will focus on areas that are pertinent to 
natural gas transmission pipelines like the one that failed in 
Sissonville. Since much of the pertinent information about the 
Sissonville failure, such as whether or not it had been previously 
inspected, what type of inspection was used, whether the failure site 
was within a high consequence designation, and the type of valves 
upstream and downstream of the rupture site, has not yet been released, 
specific conclusions related to this failure would be premature. I will 
also review areas addressed by the Pipeline Safety, Regulatory 
Certainty, and Job Creation Act of 2011, and needed safety areas that 
bill failed to address. These are the issues I would like to speak to 
today:

   Response times to pipeline ruptures

   Expanding and clarifying integrity management requirements

   Inadequate Federal and state resources

   Non-regulated and under-regulated Gathering Lines

   Poor facility response planning (hazardous liquids)

   Lack of clear jurisdiction for new pipeline approval and 
        routing decisions

   Pipe replacement programs (cast iron, bare steel, faulty 
        plastics)

   Quantifying natural gas leak significance

   Depth of cover at river crossings

   Diluted bitumen study constraints

    Response times to pipeline ruptures--One of the critical issues 
related to any type of pipeline rupture is how quickly the pipeline 
operator can identify that a rupture has occurred and then act to shut 
the pipeline down to minimize any further effects of the pipeline 
failure. In a perfect world, built in leak/rupture detection systems 
would alert a pipeline controller of a rupture immediately and allow 
for the quickest response to shut down the pipeline. Unfortunately, as 
the final report--Leak Detection Study--DTPH56-11-D-000001, which was 
recently provided to this Committee by PHMSA shows, for all leaks on 
natural gas transmission pipelines less than 16 percent are initially 
identified by the current leak detection systems. Even for the larger 
major releases that should be more easily identified with such systems 
less than 50 percent of these failures are initially identified by 
current leak detection systems. What this means is that someone other 
than the pipeline controller, such as local residents or emergency 
response personnel, or field employees with the pipeline company are 
the ones that initially identify the pipeline failure, and precious 
time is then lost as this failure identification is then relayed to the 
control room.
    Once a failure has been identified, the pipeline operator still 
needs to be able to shut down the valves on either side of the failure 
site so the natural gas roaring into the local community is minimized 
as much as possible. In the case where the natural gas ignites, such as 
in Sissonville, the closure of these valves is what can halt the 
blowtorch effect on the neighborhood and allow emergency responders to 
access the area to do their jobs. The types of valves in these critical 
locations, and how far apart they are spaced, play an important role in 
how quickly the fuel will stop flowing into the community. The final 
report on automated valves--Studies for the Requirements of Automatic 
and Remotely Controlled Shutoff Valves on Hazardous Liquids and Natural 
Gas Pipelines with Respect to Public and Environmental Safety--that 
PHMSA recently provided this Committee provides the following cost 
effective strategy for reducing the consequences of natural gas 
pipeline failures such as occurred in Sissonville.

        ``For natural gas pipelines, adding automatic closure 
        capability to block valves in newly constructed or fully 
        replaced pipeline facilities may be a cost effective strategy 
        for mitigating potential fire consequences resulting from a 
        release and subsequent ignition provided . . .

                The leak is detected and the appropriate ASVs and RCVs 
                close completely so that the damaged pipeline segment 
                is isolated within 10 minutes or less after the break, 
                and fire fighting activities within the area of 
                potentially severe damage can begin soon after the fire 
                fighters arrive on the scene.''

    Unfortunately, as was seen in the recent Sissonville failure, and 
even more dramatically in the 2010 San Bruno tragedy, the leak 
detection systems combined with the associated valves were not capable 
of meeting the timeline in this cost effective consequence mitigation 
strategy. While these leak detection and valve issues have been talked 
about for years, current Federal regulations do not require such 
automated valves, and it appears adequate leak detection systems for 
natural gas pipelines are many years off and will only be developed if 
adequate funding is provided for ongoing research and development. We 
join with the NTSB in calling for new regulations to require these 
automated valves at a minimum in all High Consequence Areas.\1\ The 
Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 
fell well short of these requirements by only requiring such valves for 
new or fully replaced pipelines. This shortcoming of the 2011 Act 
should be corrected to ensure that people living along existing natural 
gas transmission pipelines, such as in San Bruno and Sissonville, are 
afforded this additional protection also.
---------------------------------------------------------------------------
    \1\ NTSB recommendation P-11-011, 9/26/2011.
---------------------------------------------------------------------------
    One other issue that Congress should keep a careful eye on relates 
to the development of a performance-based response time for companies 
to respond to and shut down pipelines in significant events such as 
Sissonville. The recent GAO report alludes to such a standard in its 
recommendations, which in part state:

        ``evaluate whether to implement a performance-based framework 
        for incident response times.''

    We certainly agree with GAO that the first step is to improve the 
incident response data available so such decisions can be made based on 
clear facts. In submittals to PHMSA on this issue, and at numerous 
public meetings, the Interstate Natural Gas Association of America 
(INGAA) has tried to create a starting point for such a standard 
response time discussion by repeating its findings and commitment of:

        ``In populated areas, INGAA members have committed to having 
        personnel on scene within one hour to coordinate with first 
        responders and isolate failures.'' \2\
---------------------------------------------------------------------------
    \2\ Interstate Natural Gas Association of America, 11/2/11, 
comments on ANPRM for Safety of Gas Transmission Pipelines, Docket# 
PHMSA-2011-0023.

    As the recent valve study provided to you by PHMSA, and mentioned 
previously states, to effectively mitigate potential fire consequences 
from natural gas pipeline ruptures the failed pipeline segment needs to 
be isolated within 10 minutes. While it is true that a good deal of the 
damage from such pipeline failures occurs in the first minutes after 
failure, there is also clear evidence from places such as San Bruno and 
Edison that faster isolation of failed lines can reduce fire 
consequences and reduce the terror that citizens within the area 
experience. This often needlessly prolonged terror is rarely figured 
into the equations for such response times to shut down pipelines, but 
talk to anyone that lives through one of these events and you will 
realize that the terror has ongoing personal effects for years. Getting 
operators on site to isolate the ruptured site within an hour means 
that it will frequently be well over an hour before firefighters can 
safely enter the area. For firefighters waiting to get access to a 
potentially growing fire scene, and for those who live and work in the 
areas at risk, particularly hard to evacuate populations, that hour 
would be interminable. We do not believe one hour is a fast enough 
response time, and we urge Congress to keep a careful eye on this 
response time discussion.
    Expanding and clarifying integrity management requirements--The 
Pipeline Safety Trust has testified at numerous Congressional hearings 
on the need to expand integrity management processes for hazardous 
liquid and gas transmission pipelines beyond the current limited 
requirements of High Consequence Areas. Integrity management programs 
have shown value by being responsible for the identification and repair 
of thousands of flaws in pipelines over the past decade. Unfortunately 
these programs are only required on around 44 percent of hazardous 
liquid pipelines and 7 percent of natural gas transmission pipelines. 
This leaves thousands of people in more rural areas without the clear 
safety benefits that integrity management programs provide.
    We are thankful that in the Pipeline Safety, Regulatory Certainty, 
and Job Creation Act of 2011 Congress asked PHMSA to study the 
expansion of integrity management beyond High Consequence Areas, and we 
are also encouraged that PHMSA has already undertaken two significant 
Advanced Notices of Proposed Rulemakings to get this process started. 
Many progressive companies recognizing the value of integrity 
management programs have already moved to include all of their pipeline 
mileage under these programs, and the Interstate Natural Gas 
Association of America has publicly supported the expansion of 
integrity management to all miles of gas transmission pipelines.
    While the Pipeline Safety Trust has been very supportive of the 
integrity management programs and would like to see them expanded, it 
is also clear that the program needs to be reevaluated to ensure that 
it is working as originally planned. There are a few areas within the 
integrity management programs that we believe need to be reassessed to 
ensure they are moving safety forward as intended. We understand that 
PHMSA is already preparing for a review and update of the integrity 
management program for transmission pipelines, and NTSB has also 
questioned whether regulators have clear evaluation metrics to 
effectively inspect and enforce such performance-based regulations. The 
most well publicized example of an issue that undermines proper 
integrity management related to the San Bruno tragedy where a lack of 
proper records led to incorrect assumptions about the type and quality 
of pipe in the ground. While much effort has been put into this record 
verification issue, there are other concerns with the integrity 
management program that still need to be addressed.
    For example, also in the San Bruno tragedy, and perhaps in the 
recent Sissonville failure also, the use of Direct Assessment as a tool 
to inspect these large transmission pipelines has come into question. 
From the record of the development of the original integrity management 
program for natural gas transmission pipelines, it is clear that direct 
assessment was included as a way to appease the industry and help them 
avoid the large cost of retrofitting their pipelines so they could use 
the most up-to-date and effective internal inspection devices. 
Engineers from within regulatory agencies have shared concerns with us 
that the use of Direct Assessment is often done incorrectly, and is 
rarely as effective as the other approved integrity management 
inspection methods. We hope that a complete and thorough review of the 
use of Direct Assessment is undertaken soon, and that clearer criteria 
are developed for when and how it can be used. We support the NTSB 
recommendations that address this point by calling for hydrostatic 
pressure tests for all older pipe, and that all pipe be configured to 
accommodate inline inspection devices.\3\
---------------------------------------------------------------------------
    \3\ NTSB recommendations P-11-014 & P-11-017, 9/26/2011.
---------------------------------------------------------------------------
    One further piece of the integrity management program that we think 
needs to be reviewed is the repair criteria. Pipelines that do not fall 
under the integrity management rules have a fairly conservative safety 
factor built into the design and operation, to account for the fact 
that once put in the ground there are no current requirements that they 
be inspected using the best inspection technologies. The repair 
criteria under the integrity management program reduce this safety 
factor because it was assumed that companies would be regularly 
inspecting their pipelines and would catch any problems before they 
reach a critical state. As seen in many failures in recent years this 
is a dangerous assumption, so we believe the repair criteria within the 
integrity management programs need to be reviewed and probably 
tightened to ensure a sufficient safety factor is maintained, since to 
date integrity management assumptions have not always been accurate.
    We are concerned that PHMSA has not issued proposed rules on the 
Advanced Notices of Proposed Rulemakings (ANPRMs) to update both 
natural gas and hazardous liquid pipeline safety requirements. The 
Trust, industry, and other stakeholders spent many hours developing 
comments to respond to the ANPRMs on pipeline safety needs, especially 
in the area of integrity management. We hope Congress ensures that 
PHMSA acts in a timely manner on these important regulatory issues 
concerning integrity management.
    Inadequate Federal and state resources--For years the Pipeline 
Safety Trust has served on one of PHMSA's technical advisory 
committees, has helped with PHMSA workgroups on specific pipeline 
initiatives, and has had a great deal of interaction with PHMSA staff 
at all levels of the organization. All these interactions have 
confirmed our belief that this small agency is critical to pipeline 
safety, but is not as effective as it could be because of a lack of 
financial and personnel resources. The same issues also apply to state 
regulators who actually have more inspectors on the ground. For these 
reasons we support PHMSA's 2013 budget request,\4\ which would provide 
additional funding to support the needed increase in inspectors and 
analysts, an Accident Investigation Team, an increase in state funding, 
greater research and development, and the development of the much 
needed National Pipeline Information Exchange to help ensure adequate 
and accurate information is being collected to make good safety 
decisions. We hope this Committee, as the Senate committee that has the 
clear understanding of pipeline safety needs, will work with your 
colleagues to obtain this critical funding.
---------------------------------------------------------------------------
    \4\ U.S. Department of Transportation, Budget Estimates, Fiscal 
Year 2013 http://phmsa
.dot.gov/staticfiles/PHMSA/DownloadableFiles/
FY%202013%20PHMSA%20BUDGET.pdf.
---------------------------------------------------------------------------
    Non-regulated and under-regulated Gathering Lines--With the huge 
increase in natural gas production in states such as West Virginia and 
Pennsylvania, thousands of miles of under-regulated or completely 
unregulated gathering lines have recently been installed and more are 
on the way. No one really knows how many miles of gathering lines are 
out there or where they are located or how many have releases because 
up until recently no one ever tracked them. For example, the March 2012 
GAO report \5\ on unregulated gathering pipelines stated ``out of the 
more than 200,000 estimated miles of natural gas gathering pipelines, 
PHMSA regulates roughly 20,000 miles.'' While in years past these 
gathering lines were smaller and lower pressure, many of the new 
gathering lines now being used in formations such as the Marcellus 
Shale are the same size and even higher pressure than the pipeline that 
failed in Sissonville. Yet unlike the Sissonville transmission 
pipeline, the majority of these gathering lines in rural areas, which 
may have riskier safety profiles than the Sissonville pipeline, are 
completely unregulated by the Federal Government.
---------------------------------------------------------------------------
    \5\ GAO, Collecting Data and Sharing Information on Federally 
Unregulated Gathering Pipelines Could Help Enhance Safety, Report #GAO-
12-388, March 2012.
---------------------------------------------------------------------------
    For the most part the 20,000 miles of gathering lines that do fall 
under PHMSA regulations are the gathering lines that lie within more 
populated areas. Again many of these ``regulated'' gathering lines in 
these populated areas are the same size and pressure as the 
transmission pipelines that failed in San Bruno and Sissonville, yet 
are not afforded equal level of pipeline safety protection. For example 
a transmission pipeline running through a town would be required to 
undertake the important integrity management inspections to help ensure 
its safety, yet a gathering line that has the exact same risk profile 
running through that same town is currently not required to ever 
undertake any form of the important integrity management inspection and 
risk analysis.
    While the development of various natural gas shale plays around the 
Nation has arguably been a boon to our energy supplies and economy, 
because of this serious loophole in the pipeline regulations it has 
also increased the risk to thousands of people in these same areas. 
This is a loophole that needs to be closed as soon as possible before 
we have to gather for another hearing after a tragedy along one of 
these under-regulated or completely unregulated gathering pipelines.
    Similarly, there are numerous unregulated hazardous liquid 
gathering lines with characteristics similar to regulated hazardous 
liquid lines. PHMSA needs to adequately regulate these gathering lines. 
Congress should consider elimination of the term ``gathering'' line for 
hazardous liquids. Doing so would ensure that all oil gathering lines 
are regulated, as the State of Alaska has done for its oil pipelines.
    Poor facility response planning (hazardous liquids)--The NTSB in 
its report on the Marshall, Michigan spill of nearly a million gallons 
of oil into the Kalamazoo River made numerous recommendations targeted 
at improving facility response planning for hazardous liquid 
pipelines.\6\ We support all of the NTSB recommendations and hope they 
will be acted upon as quickly as possible. As we have testified to this 
committee previously, the review and adoption of such response plans is 
a process that does not include the public. In fact PHMSA has argued 
that it is not required to follow any public processes, such as those 
under the National Environmental Policy Act, for the review of these 
plans. If the Enbridge pipeline spill in Marshall, Michigan and the BP 
Gulf tragedy have taught us nothing else it should have taught us that 
the industry and agencies could use all the help they can get to ensure 
such response plans will work in the case of a real emergency.
---------------------------------------------------------------------------
    \6\ NTSB recommendations P-12-001, P-12-002, P-12-009, P-12-010, 7/
25/2012.
---------------------------------------------------------------------------
    It is always our belief that greater transparency in all aspects of 
pipeline safety will lead to increased involvement, review and 
ultimately safety. There are many organizations, local and state 
government agencies, and academic institutions that have expertise and 
an interest in preventing the release of fuels to the environment. 
Greater transparency would help involve these entities and provide 
ideas from outside of the industry. The State of Washington has passed 
rules that when spill plans are submitted for approval the plans are 
required to be made publicly available, interested parties are 
notified, and there is a 30 day period for interested parties to 
comment on the contents of the proposed plan.\7\ We urge Congress to 
require PHMSA to develop similar requirements for review and approval 
of spill response plans across the country, and that PHMSA's review and 
approval of facility response plans for new pipelines be an integral 
part of any environmental reviews required as part of the pipeline 
siting process.
---------------------------------------------------------------------------
    \7\ Washington Administrative Code 173-182-640.
---------------------------------------------------------------------------
    To encourage greater public education and awareness regarding these 
response plans, Section 6 of the Pipeline Safety, Regulatory Certainty, 
and Job Creation Act of 2011 required PHMSA to ``provide upon written 
request to a person a copy of the plan.'' In April of 2012, three 
months after the 2011 Act became law, the Pipeline Safety Trust 
requested a few of these facility response plans from PHMSA. We 
received an acknowledgement of our request within 2 weeks, but nine 
months later we are still waiting to receive the plans requested. In 
the State of Washington if we request such a facility response plan it 
is normally delivered to us on a CD within the week. While we certainly 
understand that PHMSA is understaffed, such long delays in filling 
information requests does little to accomplish the Congressional intent 
for public education and awareness, and makes us wonder how long others 
are waiting for information also.
    Lack of clear jurisdiction for new pipeline approval and routing 
decisions--Nearly everyone agrees that the people living along the 
rights-of-way of the pipelines in this country can serve a very 
valuable function as the eyes and ears for pipeline safety along those 
routes. Unfortunately, too often the lack of any clear routing process 
and overly aggressive tactics by right-of-way agents sour the 
relationship before it even gets started, leaving too many property 
owners disgruntled and no longer willing to cooperate on safety issues.
    For interstate natural gas transmission pipelines FERC provides a 
predictable siting process that provides communities potentially 
impacted by proposed pipelines valuable information about the proposal 
and ways to have their concerns heard and hopefully addressed. For all 
hazardous liquid pipelines, and for intrastate natural gas pipelines 
there is no such predictable process or information source. Some states 
have developed their own processes, while others have not, allowing 
smaller and smaller pieces of the decisions to fall on cities, counties 
and townships that often lack much knowledge regarding the issues 
associated with pipelines. This mish mash of routing authority often 
leads to a high degree of frustration from property owners and local 
governments who will be impacted by these decisions, and we suspect 
does not lead to the best routing decisions. Throw into the mix the 
often early threat of eminent domain and it is easy to see why these 
routing decisions too often become news stories about gymnasiums full 
of angry people that ultimately undermine trust in pipeline safety.
    While the problem is clear and being repeated more frequently 
because of our new sources of gas and oil, we hope that Congress will 
use its investigative powers to commission a comprehensive study on 
this important issue to help find a solution. The study should at a 
minimum look at the shortfalls of the current system, compare the 
outcomes from the FERC process to the outcomes that fall outside of 
FERC authority, and consider which Federal or state agencies are best 
equipped to help make these routing decisions for the various different 
types of pipelines. The study should also discuss any added benefits 
such cohesive route planning may produce in the form of lessening 
impacts by encouraging pipeline companies to better share 
infrastructure and rights-of-way, and in comprehensive environmental 
analysis allowing public review of potential alternatives.
    Pipe replacement programs (cast iron, bare steel, faulty 
plastics)--Section 7 of the Pipeline Safety, Regulatory Certainty, and 
Job Creation Act of 2011 required the Secretary to conduct a survey 
every two years ``to measure the progress that owners and operators of 
pipeline facilities have made in adopting and implementing their plans 
for the safe management and replacement of cast iron gas pipelines.'' 
After years of knowledge of the problems associated with this old cast 
iron pipe, and continued failures causing death and community 
destruction, this survey, which PHMSA has posted on their website, 
serves as a good way of shining a light on the operators who have taken 
this problem seriously and those who may not have. This was a great 
first step but could be expanded to be even more effective.
    Cast iron pipe is not the only type of pipe in the ground that has 
clearly known deficiencies. There are some types of plastic pipe that 
also have been identified as in need of replacement, and older bare 
steel pipe that lacks the important protective coating of more modern 
pipe also poses a threat. These types of pipe should also be added to 
the survey to provide a measurable metric of how well pipeline 
companies are doing to address these potential problems.
    While the Pipeline Safety Trust's main concern is the replacement 
of these types of problematic pipes for safety reasons, we also realize 
that paying for these replacement programs is a complicated equation. 
Many of the companies that have these pipes operate as regulated 
monopolies with a guaranteed rate of return, so the success of 
replacement programs often also lies with how state utility commissions 
approve rates for these replacement programs. We certainly support 
companies getting a fair return on safety investments, but the 
mechanisms to provide that return have to be carefully crafted to 
ensure the ratepayers are not paying for more than their fair share or 
for replacing things just to increase the rate of return with no real 
safety benefit.
    Quantifying natural gas leak significance--With recent failures and 
deaths from leaking natural gas distribution systems the public has 
come to question the safety of the very common small leaks, which both 
regulators and industry acknowledge. New technology has also been 
developed that allows a person to drive through a neighborhood and see 
these small leaks all around. Recent information estimates that between 
1.4 percent to 3.6 percent of all natural gas could be lost during 
transport, storage and distribution.\8\ A 2009 article in the Pipeline 
& Gas Journal \9\ regarding just the cast iron pipe portion of the 
pipeline network stated:
---------------------------------------------------------------------------
    \8\ Robert W. Howarth · Renee Santoro ·Anthony 
Ingraffea, 2011, Methane and the greenhouse-gas footprint of natural 
gas from shale formations--http://www.psehealthy
energy.org/data/Howarth_Climatic_Change_Shale_Methane1.pdf.
    \9\ Pipeline & Gas Journal, New Measurement Data Has Implications 
For Quantifying Natural Gas Losses From Cast Iron Distribution Mains, 
September 2009 Vol. 236 No. 9, Carey Bylin, Luigi Cassab, Adilson 
Cazarini, Danilo Ori, Don Robinson and Doug Sechler.

        A significant source of natural gas losses from distribution 
        systems is cast iron distribution pipes. U.S. cast iron 
        distribution mains are estimated to have leaked 9 billion cubic 
        feet (Bcf) of natural gas in 2007. This equates to $150 million 
        worth of gas, assuming the average U.S. distribution price in 
        2007, or $50 to $115 million if gas were valued between $3 and 
---------------------------------------------------------------------------
        $7 per thousand cubic feet (Mcf).

    We are surprised that more information has not been developed to 
clarify the quantity and significance of such leaks. Often such small 
leaks do not represent a safety hazard, but it only makes common sense 
that the loss of such a potentially large amount of gas is a 
significant waste of a non-renewable natural resource. Furthermore, 
methane (the main constituent of natural gas) has a far more potent 
negative effect on climate change than carbon dioxide, so the real 
quantity of natural gas leaking from these pipelines is important to 
understand along with what efforts to correct these leaks may be cost 
effective. We hope that Congress will ask for a study to better 
quantify these leaks, and discuss the impacts they have to safety, user 
rates, resource conservation, and climate change. Following such a 
study, Congress should consider requiring PHMSA to monitor and address 
significant natural gas leak problems from pipelines, compressor 
stations and storage.
    Depth of cover at river crossings--Section 28 of the Pipeline 
Safety, Regulatory Certainty, and Job Creation Act of 2011 requires the 
Secretary to ``conduct a study of hazardous liquid pipeline incidents 
at crossings of inland bodies of water with a width of at least 100 
feet from high water mark to high water mark to determine if the depth 
of cover over the buried pipeline was a factor in any accidental 
release of hazardous liquids.'' That study has been provided to this 
Committee, and concluded that depth of cover at river crossings was a 
factor in at least 16 incidents since 1991. A recent Wall Street 
Journal article \10\ provides a good overview of this problem along 
just one section of one river:
---------------------------------------------------------------------------
    \10\ Wall Street Journal, Floods Put Pipelines At Risk, Jack Nicas, 
December 2, 2012.

        ``The U.S. Geological Survey found severe scour last year at 27 
        sites surveyed along the Missouri River from Kansas City to St. 
        Louis, with the riverbed deepened in places by nine to 41 feet. 
        Other unpublished USGS research found more severe scouring 
---------------------------------------------------------------------------
        upstream.

        Of the 55 oil and gas pipelines that cross the Missouri--which 
        runs 2,300 miles from Montana to St. Louis--at least 24 have 
        sections that lie 10 feet or less beneath the riverbed, within 
        the range of scour observed on the river, according to Federal 
        records obtained via a Freedom of Information Act request. 
        During recent inspections, operators discovered at least two of 
        those pipes, in Platte County, Mo. and near Boonville, Mo., 
        were exposed but didn't break.

        Federal law requires operators to bury pipelines a minimum of 
        four feet beneath waterways. Many river engineers say that 
        standard is grossly inadequate. A congressional research report 
        this year said the 4-foot minimum ``appears to be insufficient 
        to prevent riverbed pipeline exposure.''

    PHMSA already has a rulemaking in progress where they could address 
these findings. It is our hope that PHMSA in its rulemaking will 
develop clear standards that required companies, when geologically 
feasible, to use horizontal directional drilling (HDD) to place these 
pipelines at a depth under such river crossings to avoid future 
failures.
    Depth of cover is not only an issue at such river crossings. Every 
year pipelines are struck and damaged, often leading to serious 
consequences, because of a lack of sufficient cover. Federal 
regulations require that hazardous liquid and gas transmission lines 
``must be installed with a minimum cover,'' but the regulations do not 
require that that level of cover be maintained. In some parts of the 
country normal erosion has led some pipelines to be at very shallow 
depth or even exposed, making them an easy target for plowing and 
various forms of excavation. While certainly excavators have a 
responsibility to call before they dig near such pipelines, the current 
depth of cover regulations need to be analyzed to determine if a change 
is warranted. An additional benefit of extending integrity management 
principles to more rural areas is that the assessment of foreseeable 
risks of third party damage to pipelines in agricultural areas from 
lack of cover will be made a necessary component of an adequate risk 
assessment by the operators, requiring them to undertake mitigative and 
preventative actions.
    Diluted bitumen study constraints--Section 28 of the Pipeline 
Safety, Regulatory Certainty, and Job Creation Act of 2011 requires the 
Secretary to ``complete a comprehensive review of hazardous liquid 
pipeline facility regulations to determine whether the regulations are 
sufficient to regulate pipeline facilities used for the transportation 
of diluted bitumen.'' PHMSA has contracted with the National Academy of 
Sciences for that review, which is due out next summer. Because of the 
high profile nature of the Keystone Pipeline proposed to carry this 
diluted bitumen, many people are already voicing concerns about the 
industry membership in the NAS review committee, as well as the fact 
that it appears the committee will not be doing any new research, just 
relying on existing information, a majority of which comes from 
industry.
    The 2010 Enbridge spill of diluted bitumen into the Kalamazoo River 
in Michigan made clear that when diluted bitumen gets out of a pipeline 
it presents a difficult challenge to clean up because so much of it is 
prone to sinking. We had hoped that the diluted bitumen study that 
Congress required would be broad enough to also answer questions about 
the need for greater cleanup preparedness and technologies along 
pipelines that carry this unique material, but PHMSA's contract with 
NAS does not cover these problems. For these reasons we hope that 
Congress will pay careful attention when the report is released next 
summer, and ensure follow up of any questions left unanswered.
    Thank you again for this opportunity to testify today. The Pipeline 
Safety Trust hopes you will closely consider the ideas and concerns we 
have raised today. If you have any questions about our testimony, the 
Trust would be pleased to answer them and, of course, we stand ready to 
work with you and your colleagues on improving this country's pipeline 
safety laws that are so important to ensuring the well-being of 
millions of Americans and the healthy environment that is their 
birthright.

    The Chairman. Thank you, sir, very much.
    Mr. Staton, I'm going to put you through a little exercise 
for my education, for all of our education. I want to hit on a 
few topics similar to what we discussed in the first panel. 
Whenever there is a pipeline incident, discussion of the 
affected operator's response surely follows, was it timely, was 
it not?
    So let me just ask you this: How is your control room made 
aware when an incident occurs, one? Can you walk me through 
your company's process for responding to an incident? Does your 
company have performance metrics for response times to 
incidents? And how could industry improve response time?
    Mr. Staton. The initiation of an event within our control 
center is indicated to one of the control room operators who 
are very well trained at understanding the implications on our 
system in what we call--we refer to as an alert.
    Specifically on the SM-80 pipeline, we have three pipelines 
there that operate effectively as a common system, and those 
have been referred to earlier today. So we received--when we 
received it--when we saw pressure drop on all three of those 
pipelines, we immediately saw three alerts, one for each 
pipeline.
    Two minutes later, which is not--by the way, it's not an 
absolutely uncommon occurrence on a pipeline. There are 
fluctuations in pressure from time to time. And so that initial 
alert indicated that there had been a pressure drop. We then 
subsequently received three additional alerts, one on each of 
those three pipelines 2 minutes later indicating that pressure 
was declining again.
    That happened one more time and then our team in the 
control center began to react. At about that time, a few 
minutes after that, we received a call from the folks at Cabot 
that one of their technicians had identified a specific 
location. So now we had confirmation in the control center that 
indeed what we were seeing in our control system had--something 
had happened and there had been an incident. And we began to 
deploy our resources with the folks calling out to the field 
and alerting emergency responders, ultimately also alerting the 
National Response Center.
    And so we deployed our folks. Our folks went to the 
locations in order to close the valves at the two locations. 
Those locations were about seven miles apart. One was at 
Lanham. One was downstream of Lanham. And then our operators 
began the process of closing and isolating that pipeline 
system.
    The Chairman. Had you not received a phone call from Cabot, 
what would have been the result?
    Mr. Staton. Had we not received that immediate phone call 
from Cabot there were also calls being made to local 911 folks 
because of the incident. We would have been able --and we would 
have deployed our folks on both ends of the system toward the 
particular incident.
    The Chairman. All right. Now, I asked you for a bit more. 
The process by which you make decisions, you've described to me 
the first part, the company's process for responding. Does your 
company have performance metrics for response, et cetera?
    Mr. Staton. We--I'm sorry. Our intent, we have over the 
last several years been continuing to improve our processes 
across the industry and here at Columbia. We have redeployed 
people on our--in our organization. Well, let me take a step 
back.
    First, we have deployed in areas where we are comfortable 
the operations can utilize automated shutoff valves. We have 
deployed those. Along our system where, particularly in 
Appalachian, where our system is very integrated. It's an 
integrated set of network pipelines with a lot of inputs coming 
into a system and a lot outputs that create--that can create 
some additional pressure implications.
    We have deployed people closer to the valve settings so 
that we can assure that we can close off valves and reduce the 
time-frame of an incident down to 1 hour.
    The Chairman. Any--that would be it? Do you have the 
appropriate--it was mentioned there were four people in the 
response station. Does that--is that fairly regular or does 
that depend upon the time of day or whatever?
    Mr. Staton. At different locations on the system it varies. 
At our Lanham station we have folks onsite. We do have some 
unmanned locations. And we ensure that we have the appropriate 
response personnel close enough to be able to respond in the 
event that those valves need to be actuated.
    The Chairman. OK. If there's any comments from any of the 
second panel, I'd welcome them.
    Mr. Staton, as you know, we included a requirement for 
remote controlled automatic shutoff valves on new or 
reconstructed pipelines in last year's law. So that's law. As 
we all know, the line that ruptured in Sissonville was equipped 
with a manual shutoff valve that required onsite attention, as 
you indicated was probably hard to do, physically hard to do. 
Although this requirement has not yet been made final, do you 
plan to install one of these valves on the Sissonville line 
once it is reconstructed?
    Mr. Staton. Our first priority in any circumstance is to 
prevent an incident like this from happening, and that our 
primary----
    The Chairman. I missed that. I'm sorry.
    Mr. Staton. Is to prevent an event, an incident like this 
from ever happening on our system, and that is to--to learn 
more, continue to learn more about our system and to install 
the right technologies at the right times. With regard to ASVs 
in new areas, obviously we're going to comply with whatever the 
requirements are.
    As we look at our SM-80 line, it is one of those integrated 
lines that I was talking about. And we are--it's a challenge 
for companies like ours to install automated shutoff valves on 
those types of systems because they can create inadvertent 
affects. And we want--we obviously want to avoid that.
    Having said that, it is our plan as we learn more and 
finalize our analysis of bringing SM--the line SM-80 back into 
service along with support from PHMSA. We will consider putting 
automatic or remote controlled valves in place on line SM-80.
    I would also indicate that our current modernization 
program that we are undertaking, it's about a $5 billion 
program to modernize our pipeline system across all of our 
pipeline system. Our intent is to expand the use of automated 
and remote control valves.
    The Chairman. Let me ask one which is not strictly in our 
arena today but which is much on my mind. In a hearing we had a 
year ago in Clarksburg, there was talk that you're building a 
platform you need to have a lot of water and sometimes you get 
80,000 pound trucks. 80,000 pound trucks and the average rural 
bridges that I have crossed in Pocahontas County and every 
other county in the state don't necessarily love each other. 
There's bound to be a problem, especially when they're one-way 
bridges.
    But there was also talk of the fact that those who drove 
those trucks, and this haunts me, since they know they're going 
on to another job as soon as this platform is built, that they 
don't appear to respect neighbors, and this testimony came from 
the sheriff, and granted he wasn't running for office again so 
maybe he felt more free speak, but therefore I think he was 
saying what he really felt. Now that was a cynical comment, 
wasn't it?
    That they tend to just go on a rampage. They just get to 
where they have to go as fast as they can get there and turn 
around and get back and there's sort of no real response or 
interest in the people whose land they're traversing. Do you 
have any comment?
    Mr. Staton. Specifically on--I mean, we obviously did not 
feel that way about the folks that we serve, and we value the 
property. We value, more importantly, the life of everyone 
along our pipeline system. And that's why we're making and 
continuing to make the types of investments to ensure that we 
don't have instances like this and that we can create one of 
the strongest infrastructures in this industry. And so I 
don't--I don't think that I see anything like that.
    The Chairman. I'm not talking about you.
    Mr. Staton. With regard to our industry, is that--is 
there--maybe there will be instances where folks are moving on 
too quickly to other activities. I would imagine there are 
opportunities where you can be distracted by the next job or 
the next responsibility. And--but I think, again, we have to 
make the appropriate investments in our infrastructure, period, 
whether it be roads, pipeline systems, bridges across the 
entirety of the country.
    The Chairman. Understood. As Senator Manchin and I 
discovered after the Sago mine disaster, there are large mines 
and there are small mines. There are large pipeline companies. 
There are small pipeline companies. And it would appear to me 
that there needs to be a certain level of largeness in order to 
afford to do business safely. And I'm not sure where that is or 
how that question can be answered, but could you reflect on 
that? And does INGAA discuss this?
    Mr. Staton. There are organizations that are focused on 
bringing together parts of the--parts of this industry that are 
relatively small that in and of themselves may not be able to 
address all of the issues that larger pipelines like ours would 
be able to address. And I think those organizations enable the 
coming together of that portion of the industry to address 
infrastructure types of issues.
    I think we've seen a fair amount of consolidation across 
this industry. And I believe that the capital and the 
capability to make the investments to operate safely, 
effectively, efficiently, those capabilities are there to 
operate effectively. And we intend to make those investments to 
be one of those--one of the safest pipeline operators in the 
country.
    The Chairman. So there's actually an argument for 
consolidations in certain circumstances so as to be able to 
afford the equipment and the precision materials that you have 
to have.
    Mr. Staton. I think across many levels of infrastructure 
there is a significant amount of investment that needs to be 
made. And in bringing the appropriate financial wherewith all 
to the table to accomplish that, I think, is a very important 
part of the overall process. And I do think that's why we've 
seen some consolidation and probably will see additional 
consolidation going forward.
    The Chairman. OK, good.
    Mr. Kessler, should there be a blanket requirement for 
these types of valves to be installed on all existing gas 
transmission that would be automatic?
    Mr. Kessler. Well, I don't know if I want to say it should 
be blanket. It should certainly be reason. But there should be 
a requirement for installation on existing lines. I continue to 
hear, and I've heard this since 1994 when I started, the 
concerns about the technology on remote valves.
    And it's really starting to ring a bit hollow after these 
many years particularly when, say, the U.S. Government entrusts 
some of its most sensitive military operations to remotely 
controlled drones yet somehow we can't have the technology to 
safely operate a shutoff valve by remote control. I think it's 
time to really take a comprehensive look, and this is something 
your staff, you, our organization all discussed in the last go 
round of pipeline safety authorization, even just requiring 
companies to assess their own lines, existing lines, come 
forward with their own plans for where these things should be 
installed, where they shouldn't be, and file those and make 
them public.
    That was rejected as being too much. Not a requirement that 
they actually install them, but to do the assessment much like 
we require pollution prevention assessments or security 
assessments. That was rejected.
    So I don't want to sound like we want all remote all the 
time everywhere, but certainly a comprehensive look at where we 
should be putting these things and then actually installing 
them. Look, I think this is the time to do it when gas prices 
are going down, demand is growing. There's plenty of money to 
be made. Why not use some of the money being made to 
reinvigorate the system, not just with valves but also better 
replacing old segments of lines and things like that and better 
inspections.
    Which I agree with Mr. Staton, that's where it starts is 
prevention. And better and more frequent inspections of more 
lines is really the beginning. But, yes, more valves, more 
remote valves.
    The Chairman. The answer is yes?
    Mr. Kessler. I think so. Thank you, Mr. Chairman.
    The Chairman. Panel two agrees?
    Ms. Quarterman. Yes.
    The Chairman. I'm about finished, but not quite.
    Mr. Kessler, because of their shape with or other reasons 
some transmission pipelines are unable to accommodate inline 
inspections to determine if any defects of risks exist. In lieu 
of inline inspections, operators often rely on direct 
assessment inspections which rely on walking the line or aerial 
surveys. I mean, this thing of helicopters flying over it----
    Mr. Kessler. Drones.
    The Chairman.--with long ropes and an orange thing at the 
bottom.
    Mr. Kessler. Right.
    The Chairman. And I'm not sure how that works. But it's 
trying just to assess how things are going. Do you include any 
kind of internal evaluation of a pipeline's condition?
    Mr. Kessler. I'm not sure I understand the last part of 
that question, Mr. Chairman.
    The Chairman. Well, the first part indicated that sometimes 
the situations----
    Mr. Kessler. It's not possible.
    The Chairman.--make it more difficult. And if you're trying 
to make sure that things like here don't happen again you don't 
want to really guess at what's inside.
    Mr. Kessler. Right.
    The Chairman. And therefore the orange things at the end of 
ropes attached to a helicopter may be a good idea but may not 
really tell you that much.
    Mr. Kessler. So when into--when congress, you and others 
enacted the 2002 Pipeline Safety Act there was--and we 
formalized in law integrity management, there was an--part of 
the legislative record included a preference--well, not a 
preference. A statement that direct assessment should be the 
least preferred form of inspection in these situations.
    It appears that that has been kind of flipped on its head. 
It's certainly the most cost effective but the least effective 
means of actually getting data. Certainly there are times when 
these lines cannot be inspected by inline inspection devices. 
But that is narrowing more and more as the devices themselves 
become smaller, more able to move in different directions. The 
lines become more capable. We certainly need--and the law was 
weakened in 1996 in terms of PHMSA's authority.
    But really we should be requiring more and more 
circumstances where lines should be replaced to accommodate 
these smart pigs. And we should be doing better on technology. 
And there should be even more than just inline inspection at 
this point. So, yes, more--less direct assessment.
    And by the way, Mr. Chairman, we're not always sure, just 
like you were saying, what that direct assessment is. Is it 
walking? Is it flying? Is it looking out the window and saying, 
hey, this looks pretty good to me. I think GAO has pointed that 
out. I think NTSB at times has talked about this. We really 
need good strict easily understandable for the industry's sake 
very clear standards on what direct assessment means, when you 
use it, and most importantly when you shouldn't.
    The Chairman. All right. Thank you. I'll just make a 
comment and then Senator Manchin may have a closing statement 
to make, and I may or may not.
    But let me just say that the very first question I said 
that you already answered is a really, really important one, 
and that is that you're committed to doing absolutely 
everything that it takes. Now, granted this is something one 
could say at almost any time. But the fact is even though 
transmission by pipeline is generally much safer than most 
other ways of transmitting things and we all recognize that, we 
have had an accident here and it's not been a good experience.
    So the statement that you're going to do everything 
possible, everything necessary to bind the wounds, to help 
people understand, to stay with people, to be close to them is 
extremely important. And that's more difficult for you because 
you're head of a very large company. But it just seems to me 
that your presence is--it's amazing what that will do, what 
statement that will make. And so I was very encouraged to hear 
that.
    And then I wanted to just say as a matter of what I've 
heard is that by and large you seem to be doing a very good 
job.
    Mr. Staton. Thank you.
    The Chairman. And I know of a couple people that are upset 
about this and that, which always happens and necessarily 
happens, but that you seem to be trying, people seem to feel 
that. I feel that at least. And so I wanted to make that 
statement.
    Mr. Staton. Thank you. Thank you very much.
    The Chairman. Senator Manchin?
    Senator Manchin. Thank you, Senator.
    Mr. Kessler, you mentioned quite a few things. Is there one 
thing you think we're not doing that we should be doing 
immediately that would be helping us to have a safer 
distribution system? Just one.
    Mr. Kessler. One thing would be better inspections, more 
often, with greater oversight. Prevention.
    Senator Manchin. That's----
    Mr. Kessler. Even a good company, and that's why I've been 
declining to comment on this incident, because even a good 
company doing all the right things can still have an incident.
    Senator Manchin. Sure.
    Mr. Kessler. But that said, as President Reagan said, 
``Trust, but verify,'' and I don't think we're doing quite 
enough verifying and doing it in the way we should be. So that 
would be my answer. Better and more inspections.
    Senator Manchin. OK.
    Mr. Staton, knowing what happened on this particular line 
when there are three lines parallel in the same area. This is 
the only one that didn't have that inspection. We've been told 
now, I think, that there will be valves so that you can do the 
inspections. Knowing that, do you have other lines in your 
system that you will take this same precautionary before, 
hopefully it will never happen again, are you doing that now 
systemwide?
    Mr. Staton. Absolutely we are. We identified on this 
pipeline because of the size of the pipeline, as Administrator 
Quarterman indicated, that it was not in a high consequence 
area. Part of what our modernization program is all about is 
essentially making all of our system capable so that we can 
always find issues before they become incidents.
    Senator Manchin. Is that part of the upgrade FERC if it's 
granted for you?
    Mr. Staton. It is. That's part of the FERC upgrade and it 
is our intention as part of our corrective action order working 
with PHMSA to make this line pigable, to run a pig throughout 
the entirety of this line. And then most importantly, to your 
point, to take the learnings of similarly situated pipelines 
where we have crossings, tie-ins with different vintage 
pipelines, rocky soil, and apply that learning across anywhere 
else on our system.
    Senator Manchin. Right. From an industry standard, from you 
all speaking upon the industry, knowing that we can't have all 
the people that we need and all the money that's going to be 
needed to do what we should for the safety of the public, do 
you recommend that all these companies, I'm sure you're pretty 
much in tune with all the distribution companies around the 
country, that this should be a rule that the Federal Government 
should take in order for this to happen?
    Mr. Staton. I fully think--I fully believe that the 
industry is responding. We are responding beyond, above and 
beyond----
    Senator Manchin. Sure.
    Mr. Staton.--the requirements in HCAs. I know other 
pipelines are also responding above and beyond.
    Senator Manchin. So you all will not have a problem if that 
rule was adopted by the agencies?
    Mr. Staton. We're going to continue--we're going to 
continue to do the good things we're doing irrespective of--of 
what happens from a regulatory and legislative perspective.
    Senator Manchin. And just final, one question, on all the 
parties that have been involved, I know you all have been 
making great strides, have you settled--or are you in the 
process of settling with all of the affected parties in 
Sissonville and making every effort you can to make sure that 
settlement is done as quickly as possible?
    Mr. Staton. Absolutely we are. I've--my--I believe strongly 
that my team has worked in a collaborative, thoughtful 
consideration, taking consideration for what has happened here. 
And we continue to work to resolve issues. We have resolved a 
number of them already. But as you would expect----
    Senator Manchin. Sure.
    Mr. Staton.--there's--there are a lot of them.
    Senator Manchin. You're working to fully reimburse or what 
we call make whole?
    Mr. Staton. Yes. And we have--we've certainly made the 
state whole for the just amazing work they did on I-77. We made 
Kanawha County whole for the wonderful work that the emergency 
responders undertook, and they really did do just a tremendous 
job. And we are in the process with every affected property 
owner addressing anything that we can address.
    Senator Manchin. Let me just say on my behalf in closing, I 
want to thank Senator Rockefeller for inviting me to be part of 
this hearing today, and it's truly informative. But encouraging 
also to see that everyone is trying to move in the most 
appropriate manner and taking the public safety first and 
foremost and high standard that we should be trying to achieve 
those levels of protection for. So from our agencies and also 
from the private sector we appreciate so much that, and thank 
you so much for your testimony and your appearances today.
    Senator, thank you.
    The Chairman. And I would agree with all of that, and point 
out that I'm sorry that I kept you, but I'm not because if 
something had been amiss you would have been pushed to correct 
it. That the whole concept of oversight, you know, it's very 
controversial right now in America. People don't like 
government. People don't like government agencies. People don't 
like us.
    Senator Manchin. We've seen that.
    The Chairman. But you cannot compromise on the business of 
oversight because the Congress is elected. The President is 
elected and appoints these good people. But there's something 
about an oversight, having a commerce committee which has, you 
know, aviation, oceans, weather, all kinds of things and 
pipelines in its jurisdiction.
    I think the concept of oversight is very important. Not 
that it always causes the world to change vastly for the better 
but that it's there, that it's asking questions, and that it's 
frankly part of what democracy needs to be about.
    Mr. Kessler. Mr. Chairman?
    The Chairman. Yes?
    Mr. Kessler. Let me say one thing. I could not agree more. 
Last Congress you and your Ranking Member, Senator Hutchinson, 
Chairman Upton, and Member Waxman came out with very good 
bills. And House--in the House they got watered down once out 
of those committees into other committees.
    The one thing that can keep things moving along, I've 
learned, in all these years is a commitment to oversight. And 
the very things that you're talking about mean so much to my 
organization and I think the public who have all been affected 
by this. And I think it is good in the long run for this 
industry and the country. That will help make everyone feel 
safe and confident in this industry.
    So thank you for that statement.
    The Chairman. Good. Thank you all very much. This hearing 
is adjourned.
    [Whereupon, at 2:48 p.m., the hearing was adjourned.]
                            A P P E N D I X

   Response to Written Questions Submitted by Hon. Barbara Boxer to 
         Pipeline and Hazardous Materials Safety Administration
    Question 1. Similar to the tragic 2010 accident in San Bruno, 
California that killed 8 people and injured 52, the preliminary results 
of the NTSB's investigation on the Sissonville accident suggest that 
Columbia's failure to detect serious flaws in its transmission pipeline 
may have been a contributing factor to the accident. What is the status 
of PHMSA's rulemakings to improve oversight and communication to 
pipeline safety operators regarding proper recordkeeping and inspection 
protocols?
    Answer. PHMSA issued an advance notice of proposed rulemaking 
(ANPRM), entitled ``Safety of Gas Transmission Pipelines'', RIN 2137-
AE72 regarding natural gas transmission pipelines on August 25, 2011. 
That ANPRM requested public comments on issues raised by the San Bruno 
incident, including integrity management principles for gas 
transmission pipelines and gas gathering. PHMSA intends to issue a 
notice of proposed rulemaking related to those issues later this year. 
In order to support the required regulatory analysis for that 
rulemaking PHMSA took several actions last year. On January 10, 2011, 
PHMSA issued an Advisory Bulletin (AB) (76 FR 1504) to remind operators 
of gas and hazardous liquid pipeline facilities of their 
responsibilities, under Federal integrity management (IM) regulations, 
to perform detailed threat and risk analyses that integrate accurate 
data and information, especially when calculating Maximum Allowable 
Operating Pressure (MAOP) or Maximum Operating Pressure (MOP). On May 
7, 2012, PHMSA issued an AB (77 FR 26822) to remind operators of gas 
and hazardous liquid pipeline facilities to verify their records 
relating to operating specifications for MAOP and MOP required by 49 
CFR 192.517 and 49 CFR 195.310, respectively. On December 21, 2012, 
PHMSA issued an AB (77 FR 75699) to inform owners and operators of gas 
transmission pipelines that if the pipeline pressure exceeds MAOP plus 
the build-up allowed for operation of pressure-limiting or control 
devices, the owner or operator must report the exceedance to PHMSA (and 
States with regulatory authority) on or before the 5th day following 
the date on which the exceedance occurs. On December 5, 2012, the 
Office of Management and Budget (OMB) approved revisions to the gas 
transmission and gathering annual reporting requirement (PHMSA F-
7100.2-1). On January 28, 2013, PHMSA issued a Federal Register notice 
(78 FR 5866) to owners and operators of gas transmission and gathering 
lines regarding significant changes to the annual reporting 
requirements. Those new annual reporting requirements require owners 
and operators to validate their Operator Identification Number data, 
and requests supplemental reports to correct gas transmission and 
liquefied natural gas annual report data issues when filing their next 
annual reports on June 15, 2013. This data will be used to support 
regulations required by the Pipeline Safety, Regulatory Certainty, and 
Job Creation Act of 2011, which requires operators to conduct tests to 
confirm the material strength of previously untested natural gas 
transmission pipelines that operate at a pressure greater than 30 
percent of specified minimum yield strength and are located in high-
consequence areas. The pipeline in Sissonville was not such a pipeline, 
however, we are doing further analysis.

    Question 2. Also similar to the San Bruno incident, the time it 
took to shut off the gas in the Sissonville incident may have been a 
factor contributing to the extent of the damage. It took several 
minutes for the Columbia Gas controller to even learn of the explosion, 
despite numerous pressure drop alerts beforehand. It then took company 
officials over an hour to isolate the section of pipeline where the 
explosion occurred. Could requiring automatic or remotely-controlled 
shutoff valves wherever technically and economically feasible help 
minimize damages in future transmission pipeline explosions?
    Answer. In the ANPRM mentioned above, PHMSA also discussed the 
subject of automatic and remote controlled shutoff valves. PHMSA held a 
workshop on this subject on March 27, 2012. PHMSA also commissioned an 
independent study performed by Keiffner and Associates on this topic 
and held a workshop on the draft of the study and accepted comments on 
the draft. A copy of that study was submitted to Congress on December 
27, 2012. Based on the study, PHMSA is considering a rulemaking action 
on the benefits and costs of both automatic shutoff valves as well as 
remote control valves.

    Question 3. Why did PHMSA wait until January 31, 2013, to issue its 
Advisory Bulletin to pipeline owners and operators recommending that 
they contact the National Response Center within one hour of discovery 
of a pipeline incident?
    Answer. PHMSA had issued a series of Advisory Bulletins' regarding 
the importance of operators promptly reporting incidents to the NRC. 
PHMSA's predecessor--Research and Special Programs Administration--
issued AB's regarding these issues during the 1980s, and more recently 
on September 6, 2002 (67 FR 57060) to advise owners and operators of 
gas distribution, gas transmission, hazardous liquid pipeline systems, 
and liquefied natural gas (LNG) facilities to ensure that telephonic 
reports of incidents to the NRC are prompt (within 1 to 2 hours). In 
addition, on October 11, 2012, PHMSA issued an AB (77 FR 61826) to 
remind operators of gas, hazardous liquid, and liquefied natural gas 
pipeline facilities to immediately and directly notify the Public 
Safety Access Point (PSAP) that serves the communities and 
jurisdictions in which those pipelines are located when there are 
indications of a pipeline facility emergency. Furthermore, the AB 
stated operators should have the ability to immediately contact PSAP(s) 
along their pipeline routes if there is an indication of a pipeline 
facility emergency to determine if the PSAP has information which may 
help the operator confirm an emergency or to provide assistance and 
information to public safety personnel who may be responding to the 
event.

    Question 4. In 2003, 2005, and 2010, PHMSA hosted public workshops 
on pipeline operator public awareness programs. Why has PHMSA not 
conducted any additional public workshops in 2\1/2\ years?
    Answer. Since late 2010, PHMSA has been conducting inspections on 
the effectiveness of pipeline operators public awareness programs. 
Those inspections were completed at the end of December 2012 and we are 
currently analyzing the results. Once those results have been analyzed, 
PHMSA is planning to conduct a Public Awareness workshop in June 2013 
to bring public awareness stakeholders together to share the inspection 
results and discuss ways to strengthen and expand public awareness for 
the public, emergency response officials, public officials, and 
excavators. The workshop will be webcast live to allow for broad public 
participation.

    Question 5. PHMSA's current Strategic Plan calls for 
``increase[ing] the visibility of our prevention and response efforts 
to better prepare the public.'' Please describe the three major actions 
PHMSA plans to take to address this objective and its approach to 
evaluating the effectiveness of these actions?
    Answer. PHMSA has already taken significant actions to increase the 
visibility of our prevention and response efforts and has much more 
planned. PHMSA is evaluating a number of major actions to increase the 
visibility of our prevention and response efforts to better prepare the 
public, including:

   PHMSA has pursued a strategy of institutionalizing pipeline 
        awareness in the emergency response community over the past 18 
        months. The strategy commenced with a public, webcast Pipeline 
        Emergency Response Forum on December 11, 2011. Since the forum, 
        PHMSA has undertaken a variety of initiatives to better prepare 
        emergency responders to safely and effectively respond to 
        pipeline emergencies. PHMSA convened a Pipeline Emergency 
        Response Working Group of emergency responders, pipeline 
        operators, and government officials. PHMSA has also partnered 
        with the National Association of State Fire Marshals, the U.S. 
        Fire Administration, and Transportation Community Awareness and 
        Emergency Response (TRANSCAER). PHMSA has led a pilot project 
        in Virginia to incorporate pipelines into the statewide 
        emergency response plan and has led a pilot project in Georgia 
        to ensure adequate pipeline training for emergency responders. 
        PHMSA has also been represented annually at five major 
        firefighter/emergency response conferences across the country. 
        PHMSA has written several articles for major firefighter 
        magazines and developed a brochure that highlights pipeline 
        safety resources that PHMSA makes available to emergency 
        responders. PHMSA is also funding a research project that will 
        produce a guide for effective communication practices between 
        pipeline operators and emergency responders. Additionally, the 
        National Fire Protection Association (NFPA) is making a variety 
        of changes to their standards that will elevate the importance 
        of pipelines in the training competencies of firefighters.

   PHMSA also produced and distributed an 811 television and 
        radio Public Service Announcement, expanded its efforts in 
        supporting National Safe Digging Month and National 811 Day, 
        and incorporated social media messages into the 811 campaign. 
        An annual survey is conducted to measure 811 awareness. PHMSA 
        is also planning to conduct a public awareness workshop in June 
        2013 to bring public awareness stakeholders together to discuss 
        recent public awareness inspections and to discuss ways to 
        strengthen and expand public awareness.

   PHMSA is executing damage prevention initiatives and will, 
        in the coming months, issue a Final Rule entitled ``Pipeline 
        Safety: Pipeline Damage Prevention Programs, RIN 2137-AE 43. 
        The rule will focus on the enforcement of One Call laws; 
        address exemptions in One Call laws through a study; grants to 
        States for the purpose of strengthening damage prevention 
        programs; and work with State stakeholders who seek to improve 
        their One Call laws and programs through meetings, data 
        analysis, and letters of support. Incidents caused by 
        excavation damage have decreased by 30 percent since 2008.
                                 ______
                                 
   Response to Written Questions Submitted by Hon. Barbara Boxer to 
                            Jimmy D. Staton
    Question 1. Why did Columbia have to rely on another company's 
employee to notify Columbia of the explosion?
    Answer. Columbia Gas relied on several pieces of information to 
determine that the Sissonville rupture had occurred. The primary source 
of information was the Supervisory Control and Data Acquisition System 
(SCADA) network. The SCADA system collects near-real-time electronic 
data from sensors strategically located throughout the pipeline system. 
Pipeline pressures, equipment status, station alarms and other 
information is relayed through the SCADA system to our Gas Control 
Center where the data is used by our Gas Control Team to monitor and 
safely control natural gas flow throughout the pipeline system.
    Within approximately two minutes of the rupture occurring, 
Columbia's Gas Control personnel received and acknowledged SCADA alerts 
indicating a drop in operating pressure. The deviation alert was 
generated from pressure sensors located at Lanham Compressor Station, 
located approximately 4.7 miles west and upstream of the rupture 
location. Since pressure drops are not unusual and can have both normal 
and abnormal causes, our Gas Control personnel acknowledged receipt of 
the alerts and began to investigate potential causes of the pressure 
drop, such as compression changes, market (demand) changes, a leak, 
etc., to see whether any further action was needed.
    After receipt of the SCADA alerts, Columbia's Gas Control Center 
received a call from a gas controller at Cabot Oil & Gas and were told 
that one of Cabot's field technicians happened to be driving near 
Sissonville and heard a loud noise and then a roaring sound, which he 
believed could have been caused by the rupture of a major gas pipeline. 
Since Cabot did not have any indications of a leak in their system, and 
the employee knew Columbia Gas had transmission lines in the 
Sissonville area, the Cabot gas controller conveyed this information to 
Columbia Gas Control.
    In short, Columbia Gas did not rely on another company's employee 
to notify it of the Sissonville rupture. Among the several pieces of 
information Columbia Gas Control collected to analyze the situation was 
an eye witness report from a Cabot field technician who happened to be 
in the Sissonville area and witnessed the immediate aftermath of the 
rupture.

    Question 2. What notifications to the community was Columbia 
required to make about the event, and did the company comply with these 
requirements?
    Answer. Columbia Gas complied with all applicable reporting 
requirements. Columbia Gas is required to contact the National Response 
Center (NRC) following any event that meets the definition of an 
incident, in accordance with current pipeline safety regulations (49 
CFR 191). Columbia personnel did in fact contact the NRC to report the 
Sissonville rupture immediately after the accident. After reporting the 
incident to the NRC, Columbia also contacted the Director of the West 
Virginia Public Service Commission and the Pipeline and Hazardous 
Materials Safety Administration's Eastern Regional Office to inform 
them of the incident.
    In addition, Columbia's Operations personnel coordinated with the 
responding fire, police and emergency management services to isolate 
the rupture location and secure the site to ensure the safety of the 
public.
                                 ______
                                 
Prepared Statement of Tim Gooch, Fire Chief, Sissonville Volunteer Fire 
                       Department, West Virginia
    Thank you Senator Rockefeller and other esteemed members of the 
Committee for allowing me the opportunity to testify on the matter of 
Pipeline Safety: An on-the-ground look at safeguarding the public. My 
name is Tim Gooch and I am the Fire Chief of the Sissonville Volunteer 
Fire Department. I have served with the fire department for almost 
forty (40) years. I am proud of our department and of our community.
    Our fire department protects a 125 square mile fire district in 
northern Kanawha County, West Virginia. We serve a population of just 
over 8,700 homes and over 150 businesses. In 2012 we answered over 600 
fire and rescue calls and were dispatched to another 1,000 emergency 
medical calls. All of these calls were answered by volunteers--men and 
women who don't get paid to respond to events like this explosion. I 
would put our department's training up against any other volunteer fire 
department in the country--we take training very seriously.
    One of the largest employers in the Kanawha Valley, the NGK 
Corporation, calls our community ``home''. We have four (4) public 
schools, a library, and almost twenty (20) miles of Interstate 77 that 
run through our area. Part of what we protect is over fifty (50) miles 
of natural gas transmission pipelines along with four (4) natural gas 
compressor stations and numerous production wells. While coal is often 
the first thing one thinks of when you hear West Virginia, we know 
about the other resource--natural gas--that is so critical to our 
Nation's energy future.
    Our fire district is made up of a resilient population that have 
gone through four (4) natural disasters in the past fifteen (15) 
years--three (3) National Disaster floods and one (1) ``Derecho''. We 
have seen our fair share of destruction but we have also been blessed 
to see how a community can pull together with neighbor helping 
neighbor. Sissonville is not the ``Buckwild'' seen on TV--it is 
families and people, churches, civic groups and businesses--that pull 
together in tough times and rebuild. It is a fire department that 
nearly lost everything to fire in 2010 but rose like the Phoenix from 
the ashes to be even better than before. That is my view of 
Sissonville. I wouldn't have spent the last forty (40) years in the 
fire service if I didn't believe in the good in this community.
Tuesday, December 11, 2012
    On Tuesday, December 11, 2012 I was looking forward to an afternoon 
off my paying job to do things to get ready for the holidays. At 12:41 
p.m. our department--Station 26--dispatched to an explosion in the area 
of 2001 Teresa Lane--an apartment complex--in our area. The initial 
dispatch was that it may have been a gas well explosion. Within a brief 
period there was radio traffic about multiple structures on fire--
possibly a nursing home--possibly a meth lab explosion. I started to 
respond to the station to get a truck immediately after the initial 
dispatch. Our department operates three (3) stations and the station 
that I was heading to is located in the southern part of our fire 
district. Once at the station, because of the radio traffic I was able 
to receive, I marked enroute with one (1) of our tankers and headed 
towards the scene. I could tell by the radio traffic that others were 
enroute as well but still had not received a clear size-up of what was 
the real situation.
    I was fortunate that I was able to proceed to the scene by using 
Route 21 (Sissonville Drive) without encountering all of the traffic 
congestion that units who responded after the initial alarm had to deal 
with. As I got into the area of Sissonville High School (the 6100 Block 
of Sissonville Drive) I saw a large column of smoke and knew we had a 
large body of fire--there was a large thermal column of dark smoke--
typical of what one would see with a structure fire. Keep in mind that 
this was approximately two (2) miles south of the fire scene and on the 
other side of Archibald Hill--a large hill that is between the high 
school and where the incident was actually located.
    As I came up and over Archibald Hill I knew that the incident was 
not in the area of 2001 Teresa Lane as initially dispatched but was 
north of that location in the bottom of the valley near the 
intersection of Derrick's Creek and Route 21 (Sissonville Drive). As I 
reached the top of Archibald Hill it was quite clear that we had a 
large body of fire with an approximate size of 200 feet across and 100 
to 150 feet high burning. When I marked on scene and got out of the 
truck there was a lot of noise from the gas venting from the breach. As 
I walked towards the other members of my department that had arrived 
before me I could also see, based on the smoke, that at least a couple 
of structures were involved. The nature and scope of the fire coupled 
with the radiant heat made doing a 360 walk-around impossible. My 
Lieutenant, Eddie Elmore, who had arrived before me in Engine 261 told 
me that he had requested mutual aid from other departments including 
trying to get units on the north end of the fire which was inaccessible 
from our location. I assumed command and began trying to formulate an 
Incident Action Plan.
    You have to understand the nature of a volunteer fire department. 
During the day we often operate short on manpower because our 
firefighters have to work. I had four (4) firefighters on scene, 
multiple structures on fire, and an obvious natural gas based fire. I 
knew I had help coming but didn't know the time frame for when it would 
get there. My primary consideration was for the safety of my 
firefighters and then to get any victims out as safely as possible. 
Denying entry into the scene really wasn't an issue as nobody in their 
right mind would go near the incident with the volume of fire and the 
radiant heat being given off.
    I saw that the Interstate was compromised but, again, couldn't get 
over to it and had to rely on common sense to prevail and that people 
would avoid the fire. I could see vehicle stopped so I assumed the road 
was blocked. Please understand that I am giving you ``snapshots''--as a 
Fire Chief or an Incident Commander you have to look at the situation 
you have, what you have to work with, what needs to be done, in what 
order it needs to occur and how all this can be done safely. We 
received information that a woman was trapped behind a house and we 
formulated a plan for a ``GO RESCUE'' of her. A team went in and got 
her and safely removed her from harm's way.
    As additional resources arrived we were able to do a more thorough 
recon of the area. An Incident priority was to get the gas shut off and 
that plan was implemented in what I thought was a short timeline. With 
the interstate and Sissonville Drive being closed because of the 
incident there were some issues getting additional resources to the 
scene but it is what it is and we had to deal with it. We responded to 
at least five (5) other related calls while handling the main incident 
and were able to arrange for emergency services coverage for the rest 
of our area during the event. I felt that the interagency cooperation 
was tremendous and contributed to the successful incident outcomes that 
we achieved--no loss of life, no life threatening injuries, and no 
First Responder injuries or deaths. As we needed resources, they were 
assigned and effectively managed. We returned units to service as 
quickly as practical.
    Once the pipeline involved was identified, we received excellent 
cooperation from them. School children were sheltered in place at their 
schools until safe arrangements could be made to get them home. A 
church in our community quickly set up a shelter for those impacted--
either displaced or those who couldn't get home because of the roads 
blocked. We worked with the media to help ensure that accurate 
information was getting out in a timely fashion. It was a true team 
effort. I am very proud of the efforts made by all of the First 
Responders who helped out in this event. As the Fire Chief it is good 
to know that our training and preparation paid off. We contained the 
event, made several rescues, and, although many were inconvenienced, no 
one died or was hurt other than those initially impacted by the blast.
    Lastly, I am proud to continue to serve my community. This incident 
is now part of our history and will be used by my department to prepare 
for the future. We will learn and grow from what occurred. We will 
never stop trying to be better than we are.
    Thank you all for your time today and for your concern about the 
countless Sissonville's of our nation. May God bless our community and 
our country.

                                  

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