[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
COMMITTEE ON COMMERCE,
SCIENCE, AND TRANSPORTATION
UNITED STATES SENATE
ONE HUNDRED THIRTEENTH CONGRESS
JANUARY 28, 2013
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SENATE COMMITTEE ON COMMERCE, SCIENCE, AND TRANSPORTATION
ONE HUNDRED THIRTEENTH CONGRESS
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
Hearing held January 28, 2013.................................... 1
Statement of Senator Rockefeller................................. 1
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
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
Committee on Commerce, Science, and Transportation,
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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,
The Chairman. And you may want to go back and join your
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
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
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.
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
Thank you very much for inviting me to West Virginia to
participate in the hearing today. I'll be ready to answer your
[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
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
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
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
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
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
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
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
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.
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
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.
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.
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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 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
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
Section 17--Study of Nonpetroleum Hazardous Liquids Transported by
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
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
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
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
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
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
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
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.
\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
\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.
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\
\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,
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).
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.
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\
\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.
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
\7\ The National Response Center, managed by the United States
Coast Guard, is the sole Federal point of contact for reporting oil and
\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
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.
\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.
Table 1.--Variables Influencing Pipeline Operator Incident Response
Variables within an operator's Variables beyond an operator's
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
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\
\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
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.-- Examples of Response Times in Select Pipeline Incidents from
2009 to 2011
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
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
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
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
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
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
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
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
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
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
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
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
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
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
Senator Manchin. Between compressing stations and things of
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
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
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
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
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
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
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
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
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
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
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
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
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
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
Ms. Quarterman. Absolutely.
Senator Manchin. And they've been cooperative working with
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
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
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
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
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
Mr. Staton. Good afternoon, Chairman Rockefeller and
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
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
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
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
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 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
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
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
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
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
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
(1) Making the area safe and immediately addressing the needs of any
local residents and community agencies impacted by the pipeline
(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-
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
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
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
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
\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.
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
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
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
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
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.
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
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.
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
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
Columbia Gas Transmission--Line SM-80
Lanham Compressor Station to Broad Run
Integrity Assurance Plan--Phase 1
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
(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
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
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
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).
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
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
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
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
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
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
3. Verification of MAOP records for Line SM-80 and implementation
of corrective measures if records do not substantiate current
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
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
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
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
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
U.S. Department of Transportation Press Release--April 20, 2012
Secretary LaHood Pledges Support to Expedite Pipeline
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
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;
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
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.
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
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
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.
6. Columbia's September 4, 2012 Settlement generally provides for
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
Initial refunds to firm shippers of $50 million in two equal
A rate moratorium through January 31, 2018 and an NGA
section 4 general rate filing obligation no later than February
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.
\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.
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
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
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,
\4\ See, e.g., Comments of Cabot.
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.
\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.
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
\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
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
\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
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
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
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
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
By the Commission. Chairman Wellinghoff is concurring with a
separate statement attached.
(S E A L)
Kimberly D. Bose,
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
Columbia Gas Transmission Corporation Docket No. RP12-
(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
The Chairman. Thank you. You answered my first one.
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
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
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
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
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
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
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
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
Pipe replacement programs (cast iron, bare steel, faulty
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
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#
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
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
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/
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
\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
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
\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
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
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
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
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
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
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
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
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
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
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
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
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
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,
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
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
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
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
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
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
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
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
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
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
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
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
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
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
[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
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
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
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
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
Question 2. What notifications to the community was Columbia
required to make about the event, and did the company comply with these
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
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