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81–794 PDF 2013

S. HRG. 113–043 

PIPELINE SAFETY: AN ON-THE-GROUND LOOK AT 

SAFEGUARDING THE PUBLIC 

FIELD HEARING 

BEFORE THE

COMMITTEE ON COMMERCE, 

SCIENCE, AND TRANSPORTATION 

UNITED STATES SENATE 

ONE HUNDRED THIRTEENTH CONGRESS 

FIRST SESSION 

JANUARY 28, 2013 

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

( 

(II) 

SENATE COMMITTEE ON COMMERCE, SCIENCE, AND TRANSPORTATION 

ONE HUNDRED THIRTEENTH CONGRESS 

FIRST SESSION 

JOHN D. ROCKEFELLER IV, West Virginia, Chairman 

JOHN F. KERRY, Massachusetts 

BARBARA BOXER, California 

BILL NELSON, Florida 

MARIA CANTWELL, Washington 

FRANK R. LAUTENBERG, New Jersey 

MARK PRYOR, Arkansas 

CLAIRE MCCASKILL, Missouri 

AMY KLOBUCHAR, Minnesota 

MARK WARNER, Virginia 

MARK BEGICH, Alaska 

RICHARD BLUMENTHAL, Connecticut 

BRIAN SCHATZ, Hawaii 

JOHN THUNE, South Dakota, Ranking 

ROGER F. WICKER, Mississippi 

ROY BLUNT, Missouri 

MARCO RUBIO, Florida 

KELLY AYOTTE, New Hampshire 

DEAN HELLER, Nevada 

DAN COATS, Indiana 

TIM SCOTT, South Carolina 

TED CRUZ, Texas 

DEB FISCHER, Nebraska 

RON JOHNSON, Wisconsin 

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 

(III) 

C O N T E N T S 

Page 

Hearing held January 28, 2013 .............................................................................. 1 

Statement of Senator Rockefeller ........................................................................... 1 

WITNESSES

Hon. Joseph Manchin, U.S. Senator from West Virginia ..................................... 4 

Sue Bonham, Resident of Sissonville, West Virginia ............................................ 5 

Prepared statement .......................................................................................... 8 

Hon. Deborah A.P. Hersman, Chairman, National Transportation Safety 

Board ..................................................................................................................... 9 

Prepared statement .......................................................................................... 10 

Cynthia L. Quarterman, Administrator, Pipeline and Hazardous Materials 

Safety Administration .......................................................................................... 18 

Prepared statement .......................................................................................... 21 

Susan A. Fleming, Director, Physical Infrastructure Issues, U.S. Government 

Accountability Office ............................................................................................ 30 

Prepared statement .......................................................................................... 31 

Jimmy D. Staton, Executive Vice President and Group CEO, NiSource Gas 

Transmission & Storage ...................................................................................... 52 

Prepared statement .......................................................................................... 54 

Rick Kessler, President, Pipeline Safety Trust ..................................................... 72 

Prepared statement .......................................................................................... 74 

APPENDIX

Response to written questions submitted by Hon. Barbara Boxer to: 

Pipeline and Hazardous Materials Safety Administration ........................... 91 

Jimmy D. Staton ............................................................................................... 93 

Tim Gooch, Fire Chief, Sissonville Volunteer Fire Department, West Virginia, 

prepared statement .............................................................................................. 94 

(1) 

PIPELINE SAFETY: AN ON-THE-GROUND LOOK 

AT SAFEGUARDING THE PUBLIC 

MONDAY, JANUARY 28, 2013 

U.S. SENATE, COMMITTEE ON COMMERCE, SCIENCE, AND TRANSPORTATION, Charleston, WV. 

The Committee met, pursuant to notice, at 12:36 p.m., in the 

Ceremonial Courtroom, Seventh Floor of the Robert C. Byrd Courthouse, Hon. John D. Rockefeller IV, Chairman of the Committee, 

presiding. 

OPENING STATEMENT OF HON. JOHN D. ROCKEFELLER IV, 

U.S. SENATOR FROM WEST VIRGINIA 

The CHAIRMAN. Welcome everybody. This hearing will come to 

order. This is a full and regular meeting of the Commerce Committee. We did this about a year ago on the same subject up north. 

Now we have new motivation because of what’s happened here in 

the last several days. 

Let me just make a statement and then Senator Manchin, who 

joins us here today will make his statement, and I’m very happy 

about that. 

These pipes, pipelines, crisscross underneath our cities and our 

countryside. They’re everywhere, 2.5 million miles, maybe more. 

Yet most of the time we’re not even aware that they are there or 

have been there for 30, 40, 50, 60, 70 years or more recently. They 

deliver the critical fuel that powers our homes, our factories, and 

offices. And they also transport the oil and gas that keep our cars, 

trucks, and planes operating. They are the critical conduit between 

the shale gas development boom in our region and the rest of the 

country. 

And most days the network of pipelines operates across the country without a hitch. Let me be clear in saying that. Compared to 

other forms of transportation, pipelines are a relatively safe, clean, 

and efficient way of transporting the goods that they carry. Unfortunately, this is not always the case. 

Everyone in this room knows all too well what can happen when 

something does go wrong. Sue Bonham will be our first testifier, 

and she certainly knows. Wes, who has worked with me for 28 

years, lives very close to there. 

So last month’s incident in Sissonville was a startling reminder 

of the destruction that can occur when a pipeline does in fact rupture, explode. Houses were destroyed and portions of the nearby 

interstate were literally dismantled, disintegrated by the overwhelming heat of the flames from the ruptured pipeline. 

2 

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. 

3 

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 

4 

to happen. It’s something that only the Congress can do and then 

hopefully turn some of that into law. 

Anyway, I’m very excited about the witnesses we will hear from 

today, and particularly right now, Sue Bonham, a resident of 

Sissonville, whose house, fence, former house, former fence I saw 

this morning because it was right across from where we were in 

that 17-foot hole. And she’s going to tell her great personal story 

about her experiences the day of the Sissonville explosion. 

Ms. Bonham provides a unique and important perspective as 

someone who was directly affected, and it’s vital that we hear her 

point of view and that we keep it in our minds. As we consider 

what steps are necessary moving forward, we must remember there 

are crucial decisions and policies that have real impact on people’s 

lives. 

And, Ms. Bonham, if you’ll excuse me, I’m very happy that Senator Manchin is here and if he has some comments, hopefully 

shorter than mine, you’re welcome to make them, sir. And I’m very 

happy you took the time to come. 

STATEMENT OF HON. JOSEPH MANCHIN, 

U.S. SENATOR FROM WEST VIRGINIA 

Senator MANCHIN. Thank you, Senator, and to all of you here 

today, I appreciate so much your attendance. To all of the citizens 

of Sissonville who are affected directly or indirectly, I’m so pleased 

that nobody was injured but I’m sorry for the losses you’ve had and 

I hope all that will be restored fully. 

And, Sue, we’ll be anxious to hear from you also. 

I want to thank Senator Rockefeller for his leadership as Chairman of the Senate Committee on Commerce, Science, and Transportation to make sure that our pipelines are constructed, maintained, and operated safely. I also want to thank the Senator for 

organizing the field hearing to make sure horrific explosions like 

the one in Sissonville never happen again. 

This is the fourth pipeline safety hearing held by Senator Rockefeller and the Commerce Committee in the last three years, which 

reflects the importance of the issue to the people of West Virginia, 

to Senator Rockefeller, and to myself. Of course we’re not the only 

state interested in pipeline safety. In the last couple of years, there 

have been fatal pipeline ruptures in Pennsylvania and California. 

In any given year, there are between 32 to 61 pipeline incidents involving a fatality or hospitalization. 

We are so fortunate that no one was seriously injured last December when the gas pipeline ruptured in Sissonville. And I’m so 

thankful that all of you—and, Sue, I know that you were trapped 

in your home for quite some time, and survived that ordeal. And 

we’ll be anxious to hear from you. 

We’re all fortunate, indeed, that we had no West Virginians injured. We can’t count on being that lucky the next time. The best 

thing that we can do is to make sure there is no next time ultimately. That’s why we’re all here today. 

I was exchanging a few comments with the families. I remember, 

it had to be about 20 years ago in Farmington, we had a horrific 

explosion, the same type. And the first time in my life I had ever 

seen anything like it. And I was visiting my father and mother in 

5 

Farmington. And this had to be 20 or more years ago. And that’s 

back when most of the cars were carbureted. 

So my dad and I jumped in the car and went up to the scene immediately, and horrific noise, just like a blowtorch but magnified 

many, many times. And my first thought is, is why doesn’t somebody just shut the gas off? That was my first reaction. Why would 

they continue to let this happen? And the next of all, I saw all 

these cars lined up on U.S. Route 250 and they all come to a standstill. And I thought, oh, my goodness, Senator, the worst possible. 

These people had all gotten killed in their cars. So I’m running 

through the cars very quickly and looking in and didn’t see. A couple of the houses, the paint was melting. And I found out later that 

when the line exploded it sucked all the oxygen out and the cars 

stopped dead in their tracks. And it was just horrific. So I have 

witnessed that myself. 

So today I look forward to hearing how the Pipeline and Hazardous Material Safety Administration, with the help of the National Transportation Safety Board and the Government Accountability Office, plans to work with natural gas companies to develop 

and to enforce regulations that ensure pipelines are being operated 

safely and maintained properly and inspected regularly. We need 

common sense guidelines to prevent these incidents like the recent 

rupture in Sissonville. 

And, again, I want to thank Senator Rockefeller for holding this 

hearing and for also his many years of service which are going to 

be greatly missed. I can tell you he’s been a great mentor, and he’s 

been very helpful to me. And his staff has been absolutely unbelievable during my transition into the Senate. We’re going to miss 

him, but we still have him for a while and we’re going to work him 

hard while we still have him. 

The CHAIRMAN. And I’ve upgraded my clothing. 

Senator MANCHIN. He has done that. He sometimes—— 

The CHAIRMAN. I’m an embarrassment to Senator Manchin on 

the Senate floor. I don’t dress well enough for him, so I’m trying 

to improve my act. Now this is not a time for frivolous things. 

Senator MANCHIN. You can imagine he comes to consult with me 

on proper clothing. 

With that being said, I just want to thank him again. It’s a 

pleasure to serve with him and an honor. But also the care and the 

concern we have for all the citizens of West Virginia—we hope together we can figure out ways this won’t happen and we can continue to improve the quality of safety and the quality of lives. 

Thank you, Senator. 

The CHAIRMAN. Thank you, Senator Manchin. 

Sue Bonham, please take your time. 

STATEMENT OF SUE BONHAM, RESIDENT OF SISSONVILLE, 

WEST VIRGINIA 

Ms. BONHAM. Thank you, Senator Rockefeller and Senator 

Manchin, for your gracious invitation to share my experience during the gas pipeline explosion in Sissonville on Tuesday, 

December 11, 2012. 

6 

Not only am I honored by your invitation, I am truly blessed to 

have survived my 40 to 45 minute ordeal and to be able to share 

that story with you today. 

The front of my home faced Sissonville Drive where the explosion 

occurred. On the backside to the left there’s a flower garden and 

an in-ground pool, both of which are surrounded by a large privacy 

fence with a gate access to the front of the home. Toward the right 

backside are the driveway and garage areas where my vehicle and 

another vehicle were parked. But the corner of the flower garden 

is where I sought shelter that afternoon. 

I was ready to walk out the door to run errands when I received 

a phone call from a lady named Trudy to schedule an appliance repair. Within seconds, Trudy and her coworkers became my only 

lifeline. I believe that call kept me from exiting my driveway onto 

Sissonville Drive when and where the blast occurred and where I 

believe I would have been killed instantly during the explosion. 

Instead, I stood in the center of my home where it was trembling, shifting, shaking, grinding all around me, the ground rumbling beneath me thinking the earth would open up at any moment 

and swallow me. The noise was so loud I had to scream for Trudy 

to please stay on the line, because I believed there was an earthquake or possibly a plane had crashed. 

Projectiles began falling like missiles through the ceiling into my 

home and I felt an immediate intense heat that took my breath 

away. As everything around me became more intense, I became 

more frightened. I dove underneath my dining room table and I 

looked out the bottom of the sliding glass doors only to see everything sizzling, blistering, or melting. The vehicles on the ground 

were literally rocking, moving in ways, and hot steam was filtering 

up out of the ground like hot springs. 

I crawled from my shelter to peek out a front window only to see 

a huge wall of fire roaring as far as I could see. At that moment 

I realized a gas line may have exploded and that I was in extreme 

danger. I ran out the back doors toward my flower garden thinking 

that if necessary I could jump into the pool to protect myself from 

the fire. My first attempt failed because the heat was so intense 

that I was driven back inside my home. 

I returned to my spot under the table becoming even more frightened realizing the house must be on fire and if it was a gas line 

explosion both my home and I could explode at any moment. 

Frightened, but thinking I had no other choice, I made another attempt to escape to the flower garden where I hid in the corner behind a withering vine and the privacy fence. 

I continued to scream into the phone hoping Trudy could hear 

me because I could no longer hear her over the roar of the explosion which was so deafening that I felt my eardrums would explode. The heat became more intense, suffocating, and the only 

area I could breathe was in that corner of the garden. 

I attempted once to run for the pool but the heat and lack of air 

drove me back to my corner. I failed at several attempts of stacking 

landscaping stones around me hoping that they might protect me 

from the overwhelming heat. I feared the landscaping mulch surrounding me might burst into flame at any moment. 

7 

I rolled onto the ground to absorb some coolness believing I 

would soon be burned alive if I couldn’t stay damp. At one point 

I threw my purse over the fence to mark my location for any rescue 

attempts. My only exits were to the front gate where the explosion 

was or to the driveway area where the blast and huge fireball were 

also located. I was trapped. 

I witnessed the earth being scorched, my home burning and 

melting. Everything was blistering or exploding. My stepdaughter’s 

home imploding into ashes and hearing the continuing roar of the 

explosion. I looked into the sky and wondered if maybe this was 

simply the end of the world. 

I portrayed to Trudy that it was important to me that my family 

knew I fought hard to survive and that my last thoughts were of 

them because I became defeated. Suddenly two great firemen, Scott 

Holmes and Eddie Elmore, came into sight. Word had been received I was trapped. They wrapped their arms around me and escorted me to safety where I was loaded into an ambulance, treated 

for smoke inhalation, and then transported to a triage location 

where my family was awaiting. The relief I felt when I saw my 

daughter’s beautiful face will remain in my heart forever. 

As the shock somewhat wore off, I began to understand the enormity of my experience. Overwhelmed by the odds that I had defied, 

I learned that I most likely would have been scalded alive had I 

jumped into the pool. And mostly certainly I would have died from 

lack of oxygen and smoke inhalation had I remained inside my 

home. 

Perhaps over the years, I’ve picked up some survival skills from 

surviving breast cancer, losing our home to a fire 5 years ago in 

that same location or listening to my youngest son’s survival experiences with 130th Air Guard and for putting up with war stories 

from my husband Paul, a retired Charleston firefighter. 

All I know for sure is that I’m truly blessed by God to be here 

today. And, again, I thank you for this opportunity to share my 

survival experience of the Sissonville gas line pipeline explosion on 

December, 11, 2012. 

The CHAIRMAN. Ms. Bonham, thank you very, very much. In 

reading one of the stories, something that just stuck in my mind 

was that you, early on in the process, put up some rocks to hide 

behind. 

Ms. BONHAM. Yes, I did. 

The CHAIRMAN. And then so that people would know that there 

was somebody behind there you sort of put your purse over on the 

other side. 

Ms. BONHAM. I did. 

The CHAIRMAN. And what that says to me is the fullness of desperation, the fullness of the instinct for survival. And that was before you had to run because you didn’t want to run because you 

didn’t know that you’d make it to get under that bush. 

But we’re so glad that you did. You, yourself, and your testimony 

and just the example that you’ve set already around the state now 

is important for every one of us, and I thank you very, very much 

for your testimony. 

Ms. BONHAM. Thank you for the opportunity. 

[The prepared statement of Ms. Bonham follows:] 

8 

PREPARED STATEMENT OF SUE BONHAM, RESIDENT OF SISSONVILLE, WEST VIRGINIA

Thank you Senator Rockefeller for your gracious invitation to share my experience 

during the gas pipeline explosion in Sissonville on Tuesday, December 11, 2012. Not 

only am I honored by your invitation, I am truly blessed to have survived my 40– 

45 minute ordeal and to be able to share that story with you today. 

The front of my home faced Sissonville Drive where the explosion occurred. On 

the backside to the left, there is a flower garden and an in-ground pool, both of 

which are surrounded by a large privacy fence with a gate access to the front of 

the house. Towards the right backside are the driveway and garage areas, where 

my vehicle and another vehicle were parked. But, the corner of the flower garden 

is where I sought shelter that afternoon. 

I was ready to walk out the door to run errands when I received a phone call from 

a lady named Trudy to schedule an appliance repair. Within seconds, Trudy and her 

co-workers became my only lifeline. I believe that call kept me from exiting my 

driveway onto Sissonville Drive, when and where the blast occurred, and where I 

believe I would have been killed instantly during the explosion. 

Instead, I stood in the center of my home where it was trembling, shifting, shaking, grinding all around me; the ground rumbling beneath me, thinking the earth 

would open up at any moment and swallow me. The noise was so loud I had to 

scream for Trudy to please stay on the line—that I believed there was an earthquake or possibly a plane had crashed. 

Projectiles began falling like missiles through the ceiling into my home, and I felt 

an immediate intense heat that took my breath away. 

As everything around me became more intense, I became more frightened. I dove 

underneath my dining room table, looked out the bottom of the sliding glass doors, 

only to see everything sizzling, blistering or melting. The vehicles and the ground 

were literally rocking, moving in waves. Hot steam was filtering up out of the 

ground, like hot springs. 

I crawled from my shelter to peek out a front window only to see a huge wall of 

fire roaring as far as I could see. At that moment, I seemed to realize a gas line 

may have exploded, and that I was in extreme danger. 

I ran out the back doors towards my flower garden, thinking that, if necessary, 

I could jump into the pool to protect myself from the fire. My first attempt failed 

because the heat was so intense that I was driven back inside my home. I returned 

to my spot under the table, becoming even more frightened, realizing the house 

must be on fire, and if it was a gas line explosion, both my home and I could explode 

at any moment. 

Frightened, but thinking I had no other choice, I made another attempt to escape 

to the flower garden where I hid in the corner behind a withering vine and the privacy fence. I continued to scream into my phone—hoping Trudy could hear me because I could no longer hear her over the roar of the explosion which was so deafening that I felt my eardrums would explode. 

The heat became more intense, suffocating, and the only area I could breathe was 

in that corner of the garden. I attempted once to run for the pool, but the heat and 

lack of air drove me back to my corner. I failed at several attempts of stacking landscaping stones around me, hoping they might protect me from the overwhelming 

heat. I feared the landscaping mulch surrounding me would burst into flame at any 

moment. 

I rolled onto the ground to absorb some coolness, believing I would soon be burned 

alive if I couldn’t keep damp. At one point I threw my purse over the fence to mark 

my location for any rescue attempts. 

My only exits were to a front gate where the explosion was, or to the driveway 

area where the blast and huge fireball were also located. I was trapped. 

I witnessed the Earth being scorched, my home burning and melting, everything 

was blistering or exploding, my step-daughter’s home imploding into ashes, and 

hearing the continuing roar of the explosion. I looked into the sky and wondered 

if maybe this was simply the end of the world. 

I portrayed to Trudy that it was important to me that my family knew I fought 

hard to survive and that my last thoughts were of them. I became defeated. 

Suddenly, two brave firemen (Scott Holmes and Eddie Elmore) came into sight. 

Word had been received I was trapped. They wrapped their arms around me and 

escorted me to safety, where I was loaded into an ambulance, treated for smoke inhalation, and then transported to a triage location where my family was waiting. 

The relief I felt when I saw my daughter’s beautiful face will remain in my heart 

forever. As the shock somewhat wore off, I began to understand the enormity of my 

experience, overwhelmed by the odds that I had defied. I learned that, most likely, 

I would have been scalded alive had I jumped into the pool. And, most certainly, 

9 

I would have died from lack of oxygen and smoke inhalation had I remained inside 

my home. 

Perhaps over the years I’ve picked up some survival skills from surviving breast 

cancer, losing our home to a fire five years ago in that same location, or listening 

to my youngest son’s survival experiences with the 130th Air Guard, and from putting up with ‘‘war stories’’ from my husband, Paul, a retired Charleston firefighter. 

All I know for sure is that I’m truly blessed by God to be here today. 

Again, thank you for this opportunity to share my survival experience of the 

Sissonville gas pipeline explosion on December 11, 2012. 

The CHAIRMAN. And you may want to go back and join your family. 

All right. Our second panel will be the Honorable Cynthia 

Quarterman, who is the Administrator of the Pipeline and Hazardous Materials Safety Administration and the Honorable Deborah Hersman, Chairman, National Transportation Safety Board. 

They go to all kinds of tragedies and they are constantly being 

worked. And Ms. Susan Fleming, Director of Political Infrastructure issues of the United States Government Accountability Office. 

A lot of people may not know what the Government Accountability Office does, but it’s one of those groups in the government 

in Washington that you can really trust when you ask them for 

their ideas or their report, the reflections on something which has 

happened and people believe them. 

Not that they don’t believe you, Debbie, or you, Cynthia. 

And, Debbie, I think I should say NTSB, National Transportation 

Safety Board, should be the first witness. We welcome you and we 

thank you for coming down today and going out their and spending 

time and being here. 

STATEMENT OF HON. DEBORAH A.P. HERSMAN, CHAIRMAN, 

NATIONAL TRANSPORTATION SAFETY BOARD 

Ms. HERSMAN. Thank you very much, Senator Rockefeller. Thank 

you for your chairmanship of the Committee and for your leadership on pipeline safety issues as well as all transportation safety 

issues. 

Senator Manchin, thank you for having me here today. 

And, Sue, thank you for your story of personal survival. It’s very 

important for all of us to hear your story because it is why we are 

here today. 

On December 11, the NTSB sent a full go team to Sissonville to 

investigate the Columbia Gas pipeline rupture that destroyed three 

homes, damaged several more, and burned through I–77 about 15 

miles from where we are today. The NTSB’s investigation is still 

ongoing, but today I will review the sequence of events that we 

have developed so far. 

Line SM–80 is a 20-inch diameter gas transmission line running 

west to east from Lanham to Broad Run near Clendenin. It is 

interconnected with two other Columbia Gas pipelines that are operating nearby as you can see in the diagram. 

At approximately 12:41 p.m. the line was operating at 929 PSI. 

It ruptured at a point about 112 feet west of I–77 and ejected a 20- 

foot section of the pipe 40 feet from where it originated. Almost immediately the 911 call center received the first call from a nearby 

retirement home. 

10 

After hearing the explosion and seeing the fire, a Cabot Oil & 

Gas field technician, who was driving nearby, called the Cabot control center. At 12:43 p.m. the Columbia Gas operations center in 

Charleston received the first three pressure drop alerts from the 

Lanham compressor station. Over the next 10 minutes, 13 more 

alerts were received in the control center in Charleston. 

Each alert was acknowledged by the controller but it was not 

until 12:53 PM when Columbia Gas received a call from Cabot did 

the Columbia Gas controller begin to understand that one of its 

pipelines had likely ruptured. By that time the pressure on all 

three interconnected transmission lines had dropped by 100 pounds 

per square inch (PSI). The four valves at Rocky Hollow downstream of the rupture were closed manually by 1:19 p.m. However, 

additional time elapsed before the six valves at the upstream 

Lanham compressor station were closed. 

While the compressor at Lanham was shut down in the compressor station by 12:59, the valves required personnel to be physically present to close them. Technicians started closing the valves 

at 1:15 and notified the operations manager at 1:40 that the valves 

were fully closed, nearly one hour after the rupture. 

While on scene, NTSB investigators found the ruptured pipeline 

wall thickness had deteriorated by 70 percent from its original 

thickness at installation, and the external corrosion covered an 

area of about 12 square feet. The 20-foot segment that was ejected 

is now at the NTSB’s lab near Washington, D.C. 

Issues of particular interest to our investigation are integrity 

management and inspections, control center operations, and automatic or remote shutoff valves. 

More than 2.5 million miles of pipelines operate in the United 

States. Thousands of those miles run near or close to our streets, 

our interstates, our churches, businesses, homes, and schools. They 

are a largely unseen part of the U.S. transportation system. 

Most people do not notice pipeline markers, like these pictured 

here, that identify where a pipeline is located in their neighborhood. But as you saw in Sissonville, when things go wrong the results can be catastrophic. 

Fortunately there were no fatalities in this accident, but sadly 

that is not always the case. 

Pipeline safety is on the NTSB’s most wanted list of transportation safety improvements because we are focused on improving 

safety and the oversight of their operations in order to prevent future accidents like the one that occurred in Sissonville. 

Thank you very much for inviting me to West Virginia to participate in the hearing today. I’ll be ready to answer your questions. 

[The prepared statement of Ms. Hersman follows:] 

PREPARED STATEMENT OF HON. DEBORAH A.P. HERSMAN, CHAIRMAN, 

NATIONAL TRANSPORTATION SAFETY BOARD

Chairman Rockefeller, Members of the Committee, and Senator Manchin, thank 

you for the opportunity to address you today concerning the National Transportation 

Safety Board’s (NTSB) ongoing investigation of the pipeline rupture and fire in 

Sissonville, West Virginia, 7 weeks ago. 

Mr. Chairman, as you have indicated, this is the fourth Senate Commerce Committee hearing on the issue of pipeline safety during your tenure as chairman. This 

hearing is also the NTSB’s fourth Senate Commerce Committee hearing on this 

11 

issue since I became Chairman. It is regrettable that major pipeline safety accidents 

continue to be a significant transportation and public safety concern. It is also regrettable that in the area of pipeline safety, philosopher George Santayana’s aphorism that those who do not learn from history are doomed to repeat it, is certainly 

true. Indicative of the safety risks posed by pipelines, just four weeks prior to the 

Sissonville accident, the NTSB added pipeline safety to its Most Wanted List of the 

top 10 transportation safety challenges for 2013—the first time this general subject 

has appeared on our annual List. 

Today, I will discuss the safety risks posed by the transportation of oil and natural gas by pipeline, the rupture and fire that occurred in Sissonville on December 

11, 2012, the NTSB’s response to the accident and the status of its investigation, 

and key NTSB findings and recommendations as the result of its past investigations 

of major pipeline accidents. 

As described in our Most Wanted List, today, in the United States there are some 

2.5 million miles of pipelines transporting natural gas, oil, and other hazardous liquids, with a significant amount of new pipeline design and construction activity underway. The pipeline network in this country includes 300,000 miles of gas transmission pipelines. Because pipelines are usually underground, most people don’t 

even know they exist, much less where they are located. Therefore, it is incumbent 

on pipeline operators and regulators to ensure that the Nation’s pipelines are safe. 

Sufficient resources should be available to regulators to carry out critical oversight 

and enforcement efforts. These pipelines power thousands of homes and deliver important resources, such as oil and gasoline, to consumers. While one of the safest 

and most efficient means of transporting these commodities, there is an inherent 

risk that can lead to tragic consequences, especially when safety standards are not 

observed or implemented. 

As was evident in Sissonville last December 11, pipeline ruptures can cause significant damage. Last July, the NTSB issued its accident report for the July 2010 

hazardous liquid pipeline rupture in Marshall, Michigan—a rupture that was not 

discovered for over 17 hours. As a result, almost 850,000 gallons of crude oil spilled 

into the surrounding wetlands and flowed into local waterways, costing nearly a billion dollars to date for clean-up and recovery—by far the most expensive environmental clean-up for an onshore oil spill. Also, in September 2010, one of the worst 

gas pipeline ruptures occurred in San Bruno, California, when a natural gas transmission pipeline ruptured and ignited, killing 8 persons. In addition, 58 persons 

were injured, 38 homes were destroyed and 70 more were damaged as a result of 

this horrific and tragic accident. 

The Sissonville Accident 

On December 11, 2012, at about 12:41 pm eastern standard time, a buried 20- 

inch diameter natural gas transmission pipeline (Line SM–80), running west to east, 

perpendicular to Interstate 77, and owned and operated by Columbia Gas Transmission Corporation, ruptured about 112 feet west of Interstate 77 in Sissonville, 

Kanawha County, West Virginia, near Route 21 and Derricks Creek. The pipeline 

maximum allowable operating pressure (MAOP) was 1,000 pounds per square inch 

gauge (psig), and the operating pressure at the time of the rupture was about 929 

psig. After the escaping high-pressure natural gas ignited, fire damage extended 

nearly 1,100 feet along the pipeline and about 820 feet wide. About 20 feet of pipe 

was ejected from the underground pipeline and landed more than 40 feet from its 

original location. 

The rupture occurred in a pipe that was a part of a pipeline segment installed 

in 1967 with a nominal wall thickness of 0.281 inches. The 20-foot ejected section 

of the pipe was found to have a fracture along the entire longitudinal direction at 

the bottom of the pipe. The outside surface of the pipe was heavily corroded near 

the midpoint and along the longitudinal fracture. The thinned area was approximately 6 feet in the longitudinal direction and 2 feet in the circumferential direction. The wall thickness had degraded so significantly that it measured only 0.078 

inches at the point along the fracture—about 70 percent thinner than the 

uncorroded pipe. 

The force of the released gas created a crater about 75 feet long by 35 feet wide 

and up to14 feet deep. Escaping high-pressure natural gas from the ruptured pipeline ignited. The intense fire destroyed three near-by homes, caused damage to several others, and heavily damaged both the northbound and southbound lanes of I– 

77, closing both lanes for about 14–19 hours until the roadway surfaces were repaired. 

The first call to 911 about the pipeline rupture and fire was made by a person 

at a nearby retirement home at 12:41 p.m. At 12:43 p.m. the Columbia Gas controller on duty at the gas control center in Charleston, West Virginia, began receivVerDate Nov 24 2008 10:32 Jul 19, 2013 Jkt 075679 PO 00000 Frm 00015 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\81794.TXT JACKIE
12 

ing alerts on the Supervisory Control and Data Acquisition (SCADA) system from 

instrumentation at the Lanham Compressor Station, located 4.7 miles upstream 

from the rupture location. Over the next ten minutes, 16 SCADA alerts indicated 

that the discharge pressure was dropping on Line SM–80 and two other pipelines 

in the SM–80 system (Line SM–86 and Line SM–86 Loop). The first notification to 

the Columbia Gas control center in Charleston, West Virginia, was provided by a 

controller from Cabot Oil and Gas Company at about 12:53 p.m., who had received 

a report of a ‘‘huge boom and flames shooting over the interstate’’ from a field technician who was near the accident location. Columbia Gas SCADA data indicate that 

the discharge pressures on the three pipelines leaving Lanham had dropped about 

100 psig. 

At about the same time that the control center was notified of the rupture, a Columbia Gas Operations Manager was called by a separate Columbia Gas field operator and told about the release and fire. The Operations Manager sent a crew to 

the Rocky Hollow valves approximately 3.2 miles downstream of the rupture, where 

two technicians, closer to the accident site, had already self-dispatched. Columbia 

Gas field technicians closed the downstream isolation valves at about 1:19 p.m., preventing the backflow of gas. The Operations Manager also notified personnel at the 

Lanham compressor station to shut the upstream valves. The 6 valves at the 

Lanham compressor station required a technician for closure. Technicians started 

closing the valves at 1:15 p.m., and notified the Operations Manager at 1:40 p.m. 

that the valves were fully closed, stopping gas flow to the rupture nearly one hour 

after the rupture occurred. 

The NTSB’s Investigation 

After learning of the accident, a 10-person team from the NTSB, led by Board 

Member Robert Sumwalt, launched to Sissonville. According to our team’s surveys 

conducted at the accident site, the rupture occurred in a nearly 38-foot long pipe 

joint that was a part of the pipeline segment installed in 1967. According to Columbia Gas documents, the ruptured segment of Line SM–80 was pressure tested twice 

in 1967: first at about 1,800 psig and then at about 1,750 psig. According to Columbia Gas records, the nominal wall thickness of the 20-inch ruptured pipe segment 

was 0.281 inches, had a longitudinal electric resistance weld seam, and was manufactured according to American Petroleum Institute specifications. 

Parties to the Investigation are: Pipeline and Hazardous Materials Safety Administration, (PHMSA), Public Service Commission of West Virginia, Columbia Gas 

Transmission Corporation, Kanawha County Sheriff’s Office, and West Virginia 

State Police South Charleston Detachment. 

The NTSB issued a preliminary report on the Sissonville accident on January 16. 

Our investigative work, including metallurgical analysis of sections of the ruptured 

pipe at our laboratory in Washington, DC, is ongoing. Additional reports, analysis 

and a finding of probable cause will come later in the investigation. 

Recurring Pipeline Safety Issues 

Although it is premature for the NTSB to determine the cause of the Sissonville 

accident, issue findings, or draw conclusions, there are a number of recurring safety 

issues we have identified in previous pipeline accidents we have investigated that 

merit highlighting today. In particular, these safety issues include: 

• Automatic and/or remote control shut-off valve installation 

• Use of in-line inspection tools 

• Integrity management program 

• SCADA training 

Automatic and/or remote control shut-off valves 

The NTSB has long been concerned about the lack of standards for rapid shutdown and the lack of requirements for automatic shutoff valves (ASV) or remote 

control valves (RCV) in high consequence areas (HCA) and class 3 and 4 areas. As 

far back as 1971, the NTSB recommended the development of standards for rapid 

shutdown of failed natural gas pipelines. In 1995, the NTSB recommended that the 

Research and Special Programs Administration—the predecessor agency of 

PHMSA—expedite requirements for installing automatic-or remote control valves on 

high-pressure pipelines in urban and environmentally sensitive areas to provide for 

rapid shutdown of failed pipeline segments. The current PHMSA integrity management regulation, which was promulgated in 2003, leaves the decision whether to install ASVs or RCVs in HCAs to the gas transmission operator. 

In Sissonville, it took the operator approximately 58 minutes after the pipeline 

rupture and explosion to stop the gas flow by closing manual shutoff valves. AlVerDate Nov 24 2008 10:32 Jul 19, 2013 Jkt 075679 PO 00000 Frm 00016 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\81794.TXT JACKIE
13 

though the operator did not identify an HCA associated with the site of the Line 

SM–80 rupture, as the NTSB has pointed out in previous accidents involving pipelines located in an HCA, the availability of ASVs or RCVs is an important tool in 

containing the safety risks after a pipeline rupture. 

Use of in-line inspection tools 

One of the 13 recommendations the NTSB made to PHMSA as a result of the San 

Bruno pipeline rupture and fire is to require all natural gas transmission pipelines 

be configured to accommodate in-line inspection (also known as internal inspection) 

tools with priority given to older pipelines. This recommendation was predicated on 

the NTSB’s concern that in-line inspection is not possible in many of the Nation’s 

pipelines, which—because of the date of their installation—have been subjected to 

less scrutiny than more recently installed pipelines. As indicated earlier, the 

Sissonville rupture occurred in a pipeline segment installed in 1967. Due to construction limitations such as sharp bends and the presence of plug valves, many 

older natural gas transmission pipelines, including the ruptured segment in 

Sissonville, cannot accommodate modern in-line inspection tools without modifications. 

In-line inspection tools travel through the pipeline to determine the nature and 

extent of any anomalies in the pipe. Another option for this type of testing is hydrostatic pressure testing that yields information about the integrity of the pipeline. 

In the NTSB’s judgment, the use of specialized in-line inspection tools that identify and evaluate damage caused by corrosion, dents, gouges, and circumferential 

and longitudinal cracks is a uniquely promising option. Unlike other assessment 

techniques, only in-line inspection can provide visualization of the pipeline integrity 

throughout the entire pipeline segment and, when performed periodically, can provide useful information about corrosion and crack growth. Although in-line inspection technology has detection limitations (generally a 90 percent probability that 

certain type of anomalies will be detected), the probability of detecting a crack may 

be improved with multiple runs, and it is nonetheless a more effective method for 

detecting unacceptable internal and external pipeline anomalies before a leak or 

rupture occurs. 

Integrity management system assessments 

The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, enacted 

a little more than one year ago, includes a provision requiring the Secretary of 

Transportation to evaluate whether integrity management system requirements 

first set forth in the Pipeline Inspection, Protection, Enforcement, and Safety Act 

of 2006 (the PIPES Act), should be expanded beyond HCAs and report the analysis 

findings to this Committee and the Committee on Transportation and Infrastructure, U.S. House of Representatives, by early next January. If the Secretary determines that integrity management system requirements should be expanded beyond 

HCAs, the Secretary must issue regulations to implement these requirements after 

a Congressional review period has elapsed. 

Although the NTSB certainly welcomes the statutorily-required evaluation and 

recognizes that Columbia Gas and other operators of natural gas transmission pipeline facilities in non-HCAs are not required to establish integrity management programs that meet minimum performance standards established in PHMSA regulations, the NTSB views these programs as important business practices that these 

operators should consider for implementation. In our San Bruno, California and 

Marshall, Michigan, investigations, we determined the Pacific Gas and Electric 

Company and Enbridge Incorporated, respectively—both of whom must comply with 

PHMSA’s integrity management program requirements—nonetheless had ineffective 

programs. Deficiencies identified by the NTSB included use of inappropriate inspection methods and tools and failures to detect pipeline defects. 

The NTSB does, however, recognize that achieving a robust and effective integrity 

management program—whether mandated or voluntary—requires dedication, sustained effort, and resources. 

SCADA training 

As indicated above, the Columbia Gas controller on duty received 16 ‘‘pressuredrop’’ 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 recogVerDate Nov 24 2008 10:32 Jul 19, 2013 Jkt 075679 PO 00000 Frm 00017 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\81794.TXT JACKIE
14 

nizing the leak by the control center operators. As a result of one of the NTSB safety recommendations resulting from this study and requirements enacted in the 

PIPES Act, in December 2009, PHMSA promulgated its control room management 

rule for pipeline facilities in Title 49, Code of Federal Regulations, section 192.631. 

In the Marshall, Michigan pipeline rupture, the NTSB determined that inadequate training of control center personnel allowed the rupture to remain undetected for 17 hours, including two startups of the pipeline. In the San Bruno, California accident, the NTSB found ‘‘that it was evident from the communications between the SCADA center staff, the dispatch center, and various other PG&E employees that the roles and responsibilities for dealing with such emergencies were 

poorly defined.’’ 

As part of its investigation in Sissonville, the NTSB is looking into the operator’s 

control room operations, its SCADA system, and the capabilities and training of its 

control room staff. 

Closing 

Although the rupture and fire did not result in any fatalities or serious injuries, 

the Sissonville accident could easily have caused significant injuries and fatalities. 

Pipeline accidents that have occurred in San Bruno, California; Marshall, Michigan; 

Sissonville; and elsewhere are devastating to the affected communities. Particularly 

regrettable are the recurring frequency of these accidents and the resource constraints that hamper regulators’ pipeline safety oversight. 

This concludes my testimony and I would be happy to answer any questions you 

may have. 

15 


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The CHAIRMAN. Thank you, Ms. Hersman. 

And now the Honorable Deborah—I’m sorry. The Honorable Cynthia Quarterman, Administrator of the Pipeline and Hazardous 

Materials Safety Administration, PHMSA. The nickname is 

PHMSA. 

STATEMENT OF CYNTHIA L. QUARTERMAN, ADMINISTRATOR, 

PIPELINE AND HAZARDOUS MATERIALS SAFETY 

ADMINISTRATION 

Ms. QUARTERMAN. Thank you, Mr. Chairman. Thank you, Senator Manchin, and thank you, Senator Rockefeller, for all your 

leadership over the past few years associated with pipeline safety. 

We really appreciate the emphasis that you have put on that and 

look forward to working with you further as we implement the provisions of the Pipeline Safety Act 2011. 

Thank you also, Chairman Rockefeller, for your leadership in 

helping with the passage of that act and for your efforts to advance 


128NTSB6.eps
19 

pipeline safety. The act has given us important tools and authority 

that we need to help us achieve our mission. 

While pipeline safety is improving, high profile incidents like the 

one that occurred in Sissonville underscore how important it is to 

be ever vigilant in preventing pipeline failures. Safety is the top 

priority for Secretary Lahood and for myself and for all of the employees of PHMSA, and we are working hard to protect the American people and the environment from the risks that are inherent 

in the transportation of hazardous materials by pipeline. 

There are 2.6 million miles of pipeline that crisscross our nation. 

PHMSA works hand in hand with a variety of partners, including 

state officials, to share the enormous responsibility of keeping our 

community safe while ensuring the nation’s energy supply is moved 

efficiently. 

Thanks to the provisions of the act we are currently able to cover 

77 percent of the program costs that our state partners incur. This 

funding covers personnel and equipment needs, public outreach 

programs, and other activities that allow states to inspect and regulate intrastate pipelines. 

West Virginia, as a full partner of ours, is responsible for inspecting their gas and liquid intrastate lines as well as serving as our 

interstate agent on gas transmission lines. This partnership has 

proven an important and strong partnership for the pipelines in 

West Virginia. 

The explosion in Sissonville, as Chairman Rockefeller has said, 

was terrible, serious, and dangerous. We are especially concerned 

for those families like the Bonham family who lost their homes in 

this incident. Fortunately no one was killed and it was not a greater tragedy. 

We’re working closely with the NTSB and the Public Service 

Commission of West Virginia on the investigation of that incident. 

NTSB recently issued a preliminary report but there’s still a lot of 

work to do before final conclusions can be made about that incident. 

PHMSA issued a corrective action order to immediately implement precautionary measures and assure safety elsewhere on that 

line. The pipeline will not be placed back into service until we are 

absolutely satisfied with the restart plan from Columbia Gas 

Transmission. 

When the pipeline is placed back into service it must operate at 

a 20 percent pressure reduction until a series of tests and evaluations have been completed and have been reviewed by our engineers. That will not be the end of our involvement. 

In addition to our assistance to NTSB and West Virginia and to 

the incident investigation, we will also perform our own compliance 

investigation to determine whether any regulations were violated 

with respect to the pipeline at issue. 

We will also take aggressive steps to apply any lessons that we 

learn here into our broader oversight mission with respect to pipeline safety. Lessons we learn here will help us prevent future accidents in other communities and will help us to continue to fulfill 

the goals and the purpose of the Act. 

The leadership of Chairman Rockefeller and the bipartisan effort 

associated with creating and passing the Pipeline Safety Act shows 

20 

that there is some common agreement about the importance and of 

the safe and reliable pipeline system. 

PHMSA takes that responsibility very, very seriously and we’ve 

been taking a deliberate approach to implementing the provisions 

of that act. We are a small agency but with a big mission. We 

worked very hard with what we have, and I’m proud of what we’ve 

been able to accomplish in the first year since the act was passed. 

We were not only able to complete all the mandates that were 

required by January 3, 2013. We also completed additional mandates and performed more work than was required. In total, of the 

42 mandates the act gave us, we have already successfully implemented 16 or 38 percent of them in just 1 year. 

Reports on important issues like leak detection, automatic and 

remote control shutoff valves, depth of cover over buried pipelines 

at river crossings, and inventory of cast iron pipeline infrastructure 

have been completed. 

Furthermore, we have planned or initiated rulemakings on eight 

additional mandates, including access flow valves, and work is continuing and progressing on schedule for the remaining 18 mandates. We are confident that we will complete all the 42 mandates 

as specified and on time even without the additional—any additional resources. 

Additionally, we want to continue to look for ways to improve our 

existing regulations. We currently have a blend of performance 

based and prescriptive safety regulations. This year we’re going to 

hold a public meeting to begin to talk about the Integrity Management Program which has been in place for more than a decade. 

We’re also working to continuously improve our oversight. As an 

example, we significantly accelerated the implementation of a control room management regulation which relates to the supervisory 

control and data acquisition systems in pipeline system control 

rooms. We’re going to use all that information and the information 

that we get from the recently released general accountability offices 

study on pipelines as we move forward. 

Despite the fact that the traditional risks of pipelines, including 

population, development, energy consumption have steadily increased over the years, over the past 20 years the number of serious incidents has gone down by 50 percent. Fortunately 2012 

marked the fewest number of pipeline incidents in a decade. Despite those successes we continue to face large challenges in fulfilling our mission. 

Much like the members of the Committee, the President has recognized that the need for a more aggressive approach to safety on 

the Nation’s pipeline systems from the discovery of vast energy 

shale deposits which will require more pipelines to the maintenance and rehabilitation to the aging pipelines already in place, 

the nation’s infrastructure needs are growing and changing. The 

President’s aggressive and historic budget requests for Fiscal Year 

2013 for our agency reflects this need. 

The Act and the outreach and oversight is working. We have a 

long way to go to reach our goal of no deaths, no injuries, no environmental harm, and no property damage. But we have a solid 

foundation on which to build as we continue to advance pipeline 

safety. 

21 

In closing, we look forward to working with this committee and 

with Congress in continuing to address pipeline safety issues. Everyone at PHMSA is dedicated and committed to fulfilling the remaining mandates and accomplishing our pipeline safety mission. 

It’s an honor to serve the American people and to work with the 

dedicated career employees at the Pipeline and Hazardous Materials Safety Administration. 

Thank you again for the opportunity to speak here today. 

[The prepared statement of Ms. Quarterman follows:] 

PREPARED STATEMENT OF CYNTHIA L. QUARTERMAN, ADMINISTRATOR, PIPELINE AND

HAZARDOUS MATERIALS SAFETY ADMINISTRATION

Chairman Rockefeller and members of the Committee, thank you for the opportunity to appear today to discuss the progress the Pipeline and Hazardous Materials 

Safety Administration (PHMSA) has made to implement the mandates of the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (Pipeline Safety 

Act). 

Thank you for your leadership in helping to secure passage of the Pipeline Safety 

Act and for your efforts to advance pipeline safety. The Act has given us important 

tools and authority that we need to help us achieve our mission. While pipeline safety is improving, high-profile incidents like the one that occurred at Sissonville underscore how important it is to be ever-vigilant in preventing pipeline failures. 

Safety is the top priority for Secretary of Transportation Ray LaHood and myself, 

and everyone at PHMSA is working hard to protect the American people and environment from the risks that are inherent in the transportation of hazardous materials by pipeline. PHMSA works to achieve its safety mission through prevention, 

rigorous enforcement, strong partnerships, and continuing education. 

This testimony will focus on several issues such as to the implementation of the 

Pipeline Safety Act mandates; our response to the Sissionville, WV pipeline incident 

and the Government Accountability Office (GAO) study on the ability of transmission pipeline facility operators to respond to a hazardous liquid or gas release. 

First, I will give an overview of PHMSA’s pipeline safety program, including the 

role that the States take in ensuring the safety of pipelines. Second, I will provide 

an overview of the mandates we have completed and the efforts we have taken to 

improve pipeline safety. Third, I will discuss how, incidents like the one at 

Sissonville show us that we have a long way to go to succeed in our mission and 

that there is still a lot of work to be done in preventing pipeline incidents. Finally, 

I will reiterate the importance of a robust pipeline safety program, and the importance of reviewing the findings of the GAO study especially with regard to the Nation’s changing and growing infrastructure needs. 

I. Overview of Phmsa Pipeline Safety Program 

There are 2.6 million miles of pipelines that crisscross our Nation; those pipelines 

offer the safest and most cost-efficient way to transport hazardous materials. To ensure that this vast network is operating safely and reliably and that communities 

and families are protected, PHMSA works together with a variety of partners, including other Federal agencies, State and local officials, emergency responders, environmental groups, and the public. 

Federal oversight agencies like the National Transportation Safety Board (NTSB), 

the Office of Inspector General (OIG), and the Government Accountability Office 

(GAO) also have a vested interest in the safe and reliable operation of the Nation’s 

pipeline infrastructure. For years, we have worked aggressively to respond to their 

recommendations. In addition to the mandates of the Act, we are currently working 

on 26 open NTSB recommendations, 9 recommendations from the OIG, and 4 recommendations from the GAO. Some of these recommendations are similar to the requirements of the Pipeline Safety Act, which suggests that there is a shared understanding of some of the challenges for the Nation’s pipeline system. 

We have taken each and every mandate and recommendation that has been 

issued to us very seriously, and we have many completed and ongoing initiatives 

to provide protection to the American people and environment. 

Overall, the pipeline safety record is good. PHMSA’s regulatory oversight program 

has led to many successes. Despite the fact that the traditional measures of risk— 

population, energy consumption, pipeline ton-miles—have steadily increased over 

the past two decades, the risk of pipeline incidents with death or major injury have 

decreased by about 10 percent every 3 years. The risks of hazardous liquid pipeline 

22 

spills that have environmental consequences have decreased by an average of 5 percent per year. Nonetheless, there is more work to be done. 

In 2012, the number of pipeline-related fatalities was at a level not seen since 

2008, and the number of pipeline-related injuries was at the lowest level since 2007. 

Furthermore, 2012 had the fewest total pipeline incidents in a decade. However, 

PHMSA, as an organization, cannot accept death or injury as an inevitable consequence of transporting hazardous materials. We are working continuously to find 

new ways to reduce risk to operators and the public, and we aim to sustain and 

improve upon these long-term trends. 

II. Implementation of the Pipeline Safety Act 

On January 3, 2012, President Obama signed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. The Act is designed to examine and improve 

the state of pipeline safety regulations and authorizes funding, through Fiscal Year 

2015, for provisions of the pipeline statute in the U.S. Code related to gas and hazardous liquids. Ultimately, the Act gives enhanced safety authority to PHMSA and 

will improve pipeline transportation, by strengthening the enforcement capabilities 

of current laws. 

The leadership of Chairman Rockefeller and this committee, as well as the bipartisan effort that led to the creation and passage of the Pipeline Safety Act shows 

there is a common agreement about the importance of a safe and reliable pipeline 

system for the welfare of the Nation. PHMSA takes this responsibility very seriously. As the committee is aware, we have struggled to hire pipeline inspectors over 

the last several years, but by the end of FY 2012, we achieved and successfully filled 

our targeted 135 pipeline inspector billets. We now look forward to working with 

this committee to continue to strengthen our pipeline inspector program and further 

implement PHMSA’s Pipeline Safety Reform effort. 

PHMSA not only completed all of the mandates that were due by January 3, 

2013, it also completed additional mandates and performed more work than required. PHMSA has already successfully completed 16 of the 42 requirements in the 

Pipeline Safety Act. PHMSA has reported on cover over buried pipelines at river 

crossings, leak detection, remote controlled and automatic shut-off valve (RCV/ASV) 

use, increasing civil penalties authority, improved the quantity, quality, and transparency of our data, and inventoried the status of cast iron pipeline infrastructure. 

Information gathered from these reports will be used to inform us as we determine 

how best to move forward with updated requirements to address these topics. 

The following is a brief description of PHMSA’s work the Pipeline Safety Act requirements: 

Section 2—Civil Penalties 

The Act authorized PHMSA to increase the maximum civil penalty for pipeline 

safety violations from $100,000 to $200,000 per violation per day. In addition, the 

agency will be able to collect a maximum of $2,000,000 for a related series of violations, up from $1,000,000. 

PHMSA is currently addressing this activity through a rulemaking to update Part 

190 of the Code of Federal Regulations. A Notice of Proposed Rulemaking (NPRM) 

entitled ‘‘Administrative Procedures; Updates and Technical Corrections’’ was published on August 13, 2012. 

Section 3—Pipeline Damage Prevention 

The Act required PHMSA to incorporate new standards for state one-call programs into the State Damage Prevention (SDP) grant program criteria, including no 

state and local exemptions. 

Some state excavation damage prevention laws include exemptions from one-call 

system participation that detract from the goals of the system. The following are 

examples of two typical types of exemption: 

Facility Owners—some state laws exempt owners of specific types of underground facilities (e.g., municipalities, State departments of transportation, and 

small water and sewer companies from participation in the one-call system). Excavators—some excavators (e.g., homeowners and State departments of transportation) are exempted from calling for underground facilities to be located and 

marked before they begin digging. PHMSA has discussed these exemptions with 

the National Association of Pipeline Safety Representatives (NAPSR) and One 

Call Systems International (OCSI). A public meeting regarding these issues is 

scheduled for March 2013. These new requirements were included in the SDP 

grant program criteria. 

23 

The Act also requires for PHMSA to conduct a study on the impact of excavation 

damage on pipeline safety, including exemptions, frequency, severity, and type of 

damage, and report these results to Congress. 

PHMSA met with the United States Infrastructure Corporation (USIC) to discuss 

performing a data analysis regarding damage prevention. As mentioned above, 

PHMSA is planning a public meeting in March 2013 to discuss damage prevention 

issues with industry stakeholders. PHMSA is considering using data from the Common Ground Alliance’s (CGA’s) Damage Information Reporting Tool (DIRT) to help 

with this study it will reach out to states to discuss the use of this data in the analysis. 

Section 4—Automatic and Remote-Controlled Shut-Off Valve Use 

The Act requires PHMSA to issue regulations requiring the use of automatic or 

remote-control shut-off valves on transmission pipelines constructed or entirely replaced after the date of the rule, if appropriate. 

PHMSA began to collect information on the use of automatic shut-off valves 

(ASVs) and remote-controlled shut-off valves (RCVs) on hazardous liquid and gas 

transmission pipelines prior to the enactment of the Pipeline Safety Act, through 

issuance of two Advanced Notice of Proposed Rulemakings (ANPRM) entitled ‘‘Safety of On-Shore Hazardous Liquid Pipelines’’ and ‘‘Safety of Gas Transmission Pipelines’’. For hazardous liquid transmission pipelines, an ANPRM issued on October 

18, 2010, requested public comments on the use of RCVs. For gas transmission pipelines, an ANPRM issued on October 25, 2011, requested public comments on requiring the use of ASV and RCV installation. 

To gather sufficient input on ASV/RCV feasibility, PHMSA sponsored a public 

workshop on March 28, 2012 with the National Association of Pipeline Safety Representatives, entitled ‘‘Understanding the Application of Automatic Control & Remote Control Valves.’’ PHMSA then commissioned an independent study on the feasibility and effectiveness of ASVs and RCVs on hazardous liquid and natural gas 

transmission pipelines. Public comments and workshop input were used to develop 

the commissioned study entitled, ‘‘Studies for the Requirements of Automatic and 

Remotely Controlled Shutoff Valves on Hazardous Liquid and Natural Gas Pipelines 

with Respect to Public and Environmental Safety’’ (ASV–RCV study), including the 

original scope of work. 

The ASV–RCV study performed by the Oak Ridge National Laboratory, while not 

mandated by the Act, will help to determine the effectiveness of block valve closure 

swiftness in mitigating the consequences of natural gas and hazardous liquid pipeline releases on the safety of the public and the environment. Additionally, a related 

NTSB recommendation, NTSB P–11–11, was incorporated into the parameters of 

the study. The recommendation suggested ASVs and RCVs be required in high-consequence areas (HCAs). A public web-based seminar (webinar) and public comment 

period was also held for input on the draft study. The ASV–RCV study addressed 

the submitted comments and incorporated substantive technical recommendations. 

The ASV–RCV study, which is 344 pages, was transmitted to Congress on December 

27, 2012. 

The information from this study will assist in providing additional guidance for 

potential rulemaking. PHMSA also anticipates progressing with a rulemaking related to ASV and RCV installation and use on hazardous liquid and gas transmission pipelines in 2013. 

In addition, PHMSA is soliciting a research project specific to technology used in 

ASVs that will provide important insight on their ability to provide reliability and 

flow assurance to pipelines. Automatic shut-off valves are often recommended to 

minimize valve shut-off times after a leak is detected. However, they may lead to 

unintended valve closures because of an inaccurate leak determination. The project 

aims to study and identify technologies and systems to minimize inaccurate leak 

alarms and unintended valve closures on ASV systems. . 

Section 5—Integrity Management 

The Act required PHMSA to conduct an evaluation on whether integrity management programs (IMPs) should be expanded beyond high-consequence areas (HCAs) 

and whether gas IMPs should replace the class location system. This section also 

asks, PHMSA to consider issuing regulations expanding IMP requirements and/or 

replacing class locations. 

As mentioned above, PHMSA initiated an ANPRM, entitled ‘‘Safety of On-Shore 

Hazardous Liquid Pipelines’’ and ‘‘Safety of Gas Transmission Pipelines’’ for both 

gas and liquid pipeline safety that addresses these issues. PHMSA is also holding 

an integrity management program (IMP) 2.0 workshop in 2013. 

24 

This section of the statute also suggests that PHMSA may extend a gas pipeline 

operator’s 7-year reassessment interval by 6 months if the operator submits written 

notice with sufficient justification of the need for an extension, and that PHMSA 

should publish guidance on what constitutes sufficient justification. PHMSA is currently considering this issue in the context of a gas transmission NPRM, which is 

a follow on from the ANPRM entitled ‘‘Safety of Gas Transmission Pipelines’’ mentioned above. PHMSA anticipates this NPRM to be published by August 2013. 

Section 6—Public Education and Awareness 

There were several mandates in this section of the Act. One mandate requires 

that PHMSA maintain a map of all gas HCAs as a part of the National Pipeline 

Mapping System (NPMS). PHMSA has already begun implementing this with the 

information we have currently available, and we are continuing to work on expanding the information available. PHMSA was also requested to update the NPMS map 

biennially. 

In addition, PHMSA was required to implement a program for promoting greater 

awareness of the NPMS to state and local emergency responders and other parties. 

To address this issue, PHMSA hosted a meeting of Public Safety and Emergency 

Response officials to discuss pipeline emergency preparedness and response on December 9, 2011. Additionally, PHMSA made contact with various emergency responder groups through its Emergency Responder (ER) Outreach program and the 

Community Assistance and Technical Services (CATS) program. PHMSA has also 

begun publishing articles regarding its public resources, including the NPMS, in ER 

publications. A brochure, designed for widespread distribution in the ER community, was also created that described available resources. 

PHMSA was also required to issue guidance to operators to provide system-specific information about their pipelines to emergency responders after consulting with 

those responders. This mandate fell closely in line with an NTSB recommendation 

(P–11–8), which recommended pipe diameter, operating pressure, product transported, and potential impact radius, among other information, is shared. 

PHMSA, in partnership with the Pipeline Emergency Response Working Group 

(PERWG), met with emergency responders at a pipeline emergency response focus 

group during the HOTZONE conference in Houston on October 19, 2012. The 

PERWG had its follow up meeting last week. On October 11, 2012, PHMSA published (Advisory Bulletin ADB–12–09) about Communication During Emergency Situations that reminds operators of gas, hazardous liquid, and liquefied natural gas 

pipeline facilities that operators should immediately and directly notify the Public 

Safety Access Point that serves the communities and jurisdictions in which those 

pipelines are located when there are indications of a pipeline facility emergency. We 

also met with the Associate of Public Communication Offices to discuss how to increase awareness and develop training for 911 center personnel. 

Additionally, PHMSA is funding a Transportation Research Board study that will 

produce a guide for communication between pipeline operators and emergency responders. 

PHMSA recognizes and agrees that the emergency response to an incident or a 

leak is critical. In addition to strengthening the capabilities of local emergency responders with increased coordination, targeted planning, and training grants. 

PHMSA has also worked to increase the visibility of prevention and response efforts 

to better prepare the public. 

The final mandate from this section required PHMSA to maintain the most recent 

oil facility response plans (FRPs), which are currently collected from operators and 

provide copies of those FRPs to any requester through the FOIA process. The copies 

can exclude sensitive information. PHMSA has implemented this mandate and continues to improve the FRP program. 

Section 7—Cast Iron Gas Pipelines 

The Act required PHMSA to follow-up on the industry’s progress in replacing cast 

iron gas pipelines. PHMSA has collected updates and has published the responses 

on its website which can be found at http://opsweb.phmsa.dot.gov/pipelineforum/. 

This inventory was developed and posted before the December 31, 2012 due date. 

Section 8—Leak Detection 

The Act requires PHMSA to submit a report to Congress on leak detection systems used by operators of hazardous liquid pipeline facilities and transportation related flow lines. The Act requires the following be included in the report: 

• an analysis of the technical limitations of current leak detection systems, including the ability of the systems to detect ruptures and small leaks that are 

25 

ongoing or intermittent, and what can be done to foster development of better 

technologies; and 

• an analysis of the practicability of establishing technically, operationally, and 

economically feasible standards for the capability of such systems to detect 

leaks, and the safety benefits and adverse consequences of requiring operators 

to use leak detection systems. 

PHMSA began working on leak detection for a number of years before the Act. 

As mentioned above, on October 18, 2010, an ANPRM for the Safety of On-Shore 

Hazardous Liquid Pipelines was published. Among the issues discussed in the 

ANPRM was whether to establish and/or adopt standards and procedures for minimum leak detection requirements for all pipelines. 

In addition, PHMSA sponsored a public workshop in March 2012 with the National Association of Pipeline Safety Representatives entitled ‘‘Improving Pipeline 

Leak Detection System Effectiveness.’’ It also held a Pipeline Research and Development (R&D) Forum in July 2012 that included a working group discussion focused 

specifically on leak detection and mitigation. As a result, PHMSA has issued a research announcement and solicitation for proposals for research and development on 

a number of topics, including leak detection. As part of its research and development activities, PHMSA has been active in studying and improving other leak detection technologies, including automated monitoring systems, sensors for small leak 

detection, aerial surveillance, satellite imaging, and improvements in the cost and 

effectiveness of current leak detection systems. 

As with valves, PHMSA also commissioned an independent study on leak detection. In conjunction with satisfying the requirements of the Act, PHMSA is also addressing a leak detection related recommendation for natural gas transmission and 

distribution pipelines from the NTSB (NTSB recommendation P–11–10, which involves Supervisory Control and Data Acquisition (SCADA) enhancements to Identify 

and Locate Leaks). PHMSA’s leak detection work included systems used in gas 

transmission and distribution pipelines as well as hazardous liquid pipelines. While 

the different types of pipeline systems have various and distinct characteristics and 

considerations for leak detection, PHMSA brought all pipeline industry stakeholders 

together to more efficiently communicate the issues affecting the respective sectors 

and to share lessons learned. 

The review of leak detection systems was not limited to the technology but also 

extended to pipeline facilities and infrastructure. Effective leak detection relies 

heavily on how well any technology is implemented through people, procedures, and 

the environment in which it is installed and operated. 

The leak detection study performed was based on input received through the 

workshops and a public comment period for the original scope of work. A public 

web-based seminar (webinar) and public comment period was also held for input on 

the draft report of the study. Additionally, some operators were interviewed as part 

of the work. The final leak detection study, which is almost 300 pages, has been 

posted electronically for review and has been transmitted to Congress. 

PHMSA will use all of the input gathered from the above initiatives as well as 

other data when considering any future rulemakings. A rulemaking is under consideration for this item. 

PHMSA is also creating a Leak Detection webpage on the PHMSA website to provide background information about leak detection issues. 

Section 9—Accident and Investigation Notification 

PHMSA was required by the Act to revise regulations to require telephonic reporting of incidents or accidents not later than 1 hour following a ‘‘confirmed discovery’’ 

and to require revising the initial telephonic report after 48 hours if practicable. An 

NPRM entitled ‘‘Miscellaneous Rule II’’ regarding these revisions is expected to be 

issued in late 2013. 

The Act also requires PHMSA to review and revise, as necessary, procedures for 

operators and the National Response Center (NRC) to notify emergency responders, 

including local public safety answering points or 911 centers. PHMSA is continuing 

to develop a means to address this issue. 

Section 10—Transportation-Related Onshore Facility Response Plan Compliance 

Administrative Enforcement and Civil Penalties 

While there was no specific mandate with this item, the section did suggest that 

PHMSA should update Part 190 to be consistent with the new authority to enforce 

Part 194 regulations. A rulemaking entitled ‘‘Administrative Procedures; Updates 

and Technical Corrections’’ is under consideration for this item. 

26 

Section 11—Pipeline Infrastructure Data Collection 

PHMSA is considering collecting other geospatial and technical data for the 

NPMS. Although there was no specific mandate for this action, as mentioned in Section 11 above, a rulemaking is under consideration for this item. 

Section 12—Transportation-Related Oil Flow Lines 

There is no mandate related to this section, but PHMSA is considering collecting 

geospatial and other data on transportation-related oil flow lines, as mentioned in 

Section 11 above, as defined in the Act. 

Section 13—Cost Recovery for Design Reviews 

PHMSA was required to prescribe a fee structure and procedures for assessment 

and collection in order to implement authority to recover design review costs for 

projects that cost over $2.5 billion or that involve ‘‘new technologies.’’ PHMSA is 

currently developing guidance on this issue. 

This section also mandates that PHMSA issue guidance on the meaning of the 

term ‘‘new technologies.’’ This guidance was completed and was posted on the external PHMSA website prior to the January 3, 2013 deadline. 

Section 15—Carbon Dioxide Pipelines 

The Act requires that PHMSA issue regulations for transporting carbon dioxide 

by pipeline in a gaseous state. PHMSA is currently exploring rulemaking options 

with this item. 

Section 16—Study of Transportation of Diluted Bitumen 

PHMSA was required to review and report to Congress on whether current regulations are sufficient to regulate pipelines transporting diluted bitumen. A study has 

been contracted to perform this analysis to the National Academy of Sciences (NAS), 

which is meeting on the issue on January 31 and February 1, 2013, and it is on 

track for timely completion. Once the study is completed, a report to Congress will 

follow. 

Section 17—Study of Nonpetroleum Hazardous Liquids Transported by Pipeline 

This section allows PHMSA to analyze the extent to which pipelines transporting 

non-petroleum hazardous liquids, such as chlorine, are unregulated, and whether 

being unregulated presents risks to the public. The results of any analysis must be 

made available to Congress as directed by the Act. PHMSA is currently reviewing 

this issue. 

Section 19—Maintenance of Effort 

PHMSA was required to grant waivers of the maintenance of effort clause in 

FY12 and FY13 to States that demonstrate an inability to maintain funding to their 

pipeline safety program due to economic hardship. This action has been completed 

for FY12, and we are addressing this issue as it pertains to future years. 

Section 20—Administrative Enforcement Process 

This section requires PHMSA to issue regulations for enforcement hearings that 

require a presiding official, implement a separation of functions, prohibit ex parte 

communications and provide other due process provisions. This issue is currently 

being addressed in the Part 190 Rule referred to in Section 20 above. The NPRM 

entitled ‘‘Administrative Procedures; Updates and Technical Corrections’’ was published on August 13, 2012. 

Section 21—Gas and Hazardous Liquid Gathering Lines 

The Act requires PHMSA to review and report to Congress on existing Federal 

and State regulations for all gathering lines, existing exemptions, and the application of existing regulations to lines not presently regulated. PHMSA has contracted 

Oak Ridge National to assist in the research of this issue and a report is under development. 

PHMSA must also consider issuing regulations that would subject offshore liquid 

gathering lines to the same standards as other liquid gathering lines. PHMSA will 

determine whether these regulations are necessary based on the results of the research and report. 

Section 22—Excess Flow Valves 

The Act requires PHMSA to consider issuing regulations requiring the use of excess flow valves on new or entirely replaced distribution branch services, multi-family facilities, and small commercial facilities. PHMSA issued an ANPRM entitled 

‘‘Expanding the Use of Excess Flow Valves in Gas Distribution Systems to ApplicaVerDate Nov 24 2008 10:32 Jul 19, 2013 Jkt 075679 PO 00000 Frm 00030 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\81794.TXT JACKIE
27 

tions Other Than Single-Family Residences ’’ on November 25, 2011 and is currently 

analyzing public comments. 

Section 23—Maximum Allowable Operating Pressure (MAOP) 

PHMSA was required to issue an Advisory Bulletin regarding the existing requirements to verify records confirming MAOP in Classes 3 and 4 and in HCAs. An 

Advisory Bulletin on ‘‘Verification of Records’’ was issued for this item on May 7, 

2012. 

PHMSA was also required to issue regulations requiring operators to report by 

July 3, 2013, any pipelines without sufficient records to confirm MAOP. As part of 

meeting the mandate, PHMSA determined they had the authority under existing 

regulations to collect this additional data. Therefore, PHMSA revised its gas transmission annual reporting form to collect this information which we will receive for 

the first time on June 15, 2013. The information collected will be used to address 

the mandate in the Act. 

This section also required PHMSA to issue regulations that require operators to 

report any exceedance of MAOP within 5 days, and to ensure the safety of pipelines 

without records to confirm MAOP. PHMSA published an advisory bulletin in the 

Federal Register on December 21, 2012 on Reporting the Exceedances of Maximum 

Allowable Operating Pressure (ADB–2012–11). A rulemaking is under consideration 

for this item. 

PHMSA was also required to issue regulations requiring tests to confirm the material strength of previously untested gas transmission pipelines in HCAs. As part 

of meeting the mandate, PHMSA determined they had the authority under existing 

regulations to collect this additional data. PHMSA will use its revised gas transmission annual report to collect this relevant data by June 15, 2013. This information will be used to meet the mandate in the Act. 

Section 24—Limitation of Incorporation of Documents by Reference 

This section requires PHMSA, starting in one year, to stop incorporating by reference into its regulations or guidance materials any industry standard unless it is 

publicly available free of charge on the internet. PHMSA is continuing to work with 

organizations that develop standards in order to make Incorporation-By-Reference 

(IBR) material available for free on the Internet. We are pleased that many standards setting organizations have agreed and are assisting PHMSA in complying with 

this item. 

Section 28—Cover Over Buried Pipelines 

PHMSA was required to conduct a study and report to Congress on hazardous liquid pipeline accidents at water crossings to determine if depth of cover was a factor. 

This study was completed and was transmitted to Congress before the January 3, 

2013, deadline. 

If the study shows depth of cover was a factor, PHMSA must review the sufficiency of existing depth of cover regulations and consider possible regulatory 

changes and/or legislative recommendations. The Administration is still determining 

whether legislative changes should be recommended. 

Section 29—Seismicity 

There was no specific mandate within this section, but it was suggested that 

PHMSA should issue regulations to be consistent with the requirement in statute 

that operators consider seismicity in identifying and evaluating all potential threats 

to each pipeline pursuant to Parts 192 and 195. PHMSA has conducted research on 

this issue, which is currently under review. 

Section 30—Tribal Consultation for Pipeline Projects 

The Act requires PHMSA to develop and implement a protocol for consulting with 

Indian tribes to provide technical assistance for the regulation of pipelines that are 

under the jurisdiction of Indian tribes. This protocol was posted on the PHMSA 

website prior to the January 3, 2013, deadline. 

Section 31—Pipeline Inspection and Enforcement Needs 

PHMSA was required to report to Congress on the total number of full-time 

equivalents (FTEs) for pipeline inspection and enforcement, the number of such 

FTEs that are not presently filled and the reasons they are not filled, the actions 

being taken to fill the FTEs, and any additional resources needed. This action has 

been completed by PHMSA, and a report was submitted to Congress on December 

20, 2012. 

28 

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 ap- proximately $43.5 million, of the program costs that States incur. This funding covers personnel and equipment needs, public outreach programs, and other activities 

that allow the States to inspect and regulate intrastate pipelines. Currently, we 

partner with 52 state pipeline safety programs through certification and agreements 

for the inspection of the Nation’s intrastate gas and hazardous liquid pipelines. 

PHMSA also has interstate agent agreements with 10 states to perform interstate 

pipeline inspections. We are pleased to report that the State of West Virginia participates as an interstate pipeline agent for gas transmission lines. This partnership 

has proven to be a great asset in helping to strengthen the safety of pipelines in 

West Virginian communities. 

The day this incident happened, several of my top staff members and I were visiting the Marcellus Shale area. We received a call that alerted us to the incident, 

and we were able to launch our response from the meeting we were conducting in 

Pennsylvania. Tim Butters, my Deputy Administrator, was in contact with emergency response officials from Sissonville shortly after the explosion occurred. It is 

because of the great relationship PHMSA and our State partners have with the 

pipeline industry and emergency responder community that we were contacted directly for support. PHMSA exists for the safety of the public, and we have been involved from the onset of this incident up through this point in time. We continue 

to support our fellow partners on the ground at the incident. As well as work with 

the emergency response community in order to share best practices and lessons 

learned. 

In fact, we recently returned to Sissonville to meet with the local emergency responders and emergency management officials of Sissonville and Kanawha County 

to discuss the response to this incident, and what prior interaction they had with 

the operator. 

We were very encouraged to learn that there was a good working relationship 

with the utility operator and the local public safety community. These established 

relationships, coupled with the fact that the local responders were well-trained, 

made it possible for the successful and effective management of this incident. The 

fact that there were only minor civilian injuries and no injuries to emergency responders is a testament to the capability of the local emergency response system 

29 

and the importance of cooperation with the pipeline industry, and Federal and state 

regulators. 

However, we also learned there is still much work to do. Both the pipeline operators and local officials recognize that additional training and exercises are needed. 

As the statute now requires, operators will be providing more detailed information 

about their pipeline systems, including location, size of pipe, and other critical elements. A rulemaking is under consideration that will allow PHMSA to collect additional information as part of its emergency responder outreach program. While Columbia Gas had been engaged with the local community, we were informed that cooperation and coordination between the local community and other pipeline operators could be improved. We will do what is necessary to ensure that this is corrected 

as quickly as possible. 

We always make an aggressive effort to apply the information from specific pipeline incidents to the broader, national context of pipeline safety. We accelerated the 

implementation of control room management regulations based upon lessons learned 

about supervisory control and data acquisition (SCADA) system challenges. This 

year we will hold a public workshop to evaluate lessons learned during the last ten 

years of performance based integrity management regulations. 

Lessons we learn from the Sissonville incident will also be used to help prevent 

accidents in other communities and will help us continue to fulfill the safety goals 

and purpose of the Act. Once our investigations into this incident are complete, we 

will release our findings and information to the larger emergency responder community and operator network. 

IV. Changing Infrastructure and the Importance of Oversight 

Much like the members of this Committee, this Administration has recognized the 

need for an aggressive approach to the safety of the Nation’s pipeline system and 

the Fiscal Year 2013 Budget includes a funding request to implement an aggressive 

Pipeline Safety Reform initiative, which seeks to significantly increase both Federal 

and State resources supporting pipeline safety, as well as furthering research and 

development, and enhancing information technology capabilities to address the safety of the national pipeline system. We just recently received the final GAO study 

on the ability of transmission pipeline facility operators to respond to a hazardous 

liquid or gas release. We are currently reviewing the findings and will be happy to 

discuss with your staff on how we plan to move forward. 

From the discovery of vast energy shale deposits, which will require the creation 

of additional infrastructure, to the maintenance and rehabilitation of the infrastructure already in place, the Nation’s infrastructure needs are growing and changing. 

I have been to the Bakken and Marcellus Shales, and I have seen these changes 

and the evolution of the energy industry firsthand. And I can tell you that we must 

prepare for these new and shifting demands right now. We must make sure that 

people and the land are protected at the beginning of the process even before the 

pipe goes in the ground. Effective standards and regulations are one of the best 

ways to keep America’s people and environment safe while providing for the reliable 

transportation of the Nation’s energy supplies, and the oversight provided by 

PHMSA and our partners will become even more critically important in the future. 

With that being said, I believe that the Pipeline Safety Act, and our outreach and 

oversight, is working. We have a long way to go to reach our goal of no deaths, injuries, environmental and property damage, or transportation disruptions, but we 

have a solid foundation to build on as we continue to advance pipeline safety. 

In closing, we look forward to continuing to work with Congress to address pipeline safety issues and to improve pipeline safety programs. Together, we will keep 

America’s people and environment safe while providing for the reliable transportation of the Nation’s energy supplies. Everyone at PHMSA is dedicated and committed to fulfilling the remaining mandates and accomplishing our pipeline safety 

mission. It is an honor to serve the American people and to work with the dedicated 

public servants at PHMSA. Thank you again for the opportunity to speak with you 

today. I would be pleased to answer any questions you may have. 

The CHAIRMAN. Thank you very much, Ms. Quarterman. 

And now we will go to Ms. Susan Fleming, who is Director of the 

Physical Infrastructure Issues at the United States Government 

Accountability Office. 

30 

STATEMENT OF SUSAN A. FLEMING, DIRECTOR, PHYSICAL 

INFRASTRUCTURE ISSUES, U.S. GOVERNMENT 

ACCOUNTABILITY OFFICE 

Ms. FLEMING. Mr. Chairman, I’d also like to add my appreciation 

for your leadership on pipeline safety and all the range of transportation issues this committee covers and for your kind words on 

GAO. I appreciate that. 

I very much appreciate the opportunity to be here in West Virginia to discuss pipeline safety and incident response. As the recent 

transmission pipeline incident in Sissonville demonstrates, while 

pipelines are considered the safest means of transporting natural 

gas and hazardous liquids, pipeline incidents can and do occur. 

The speed of a pipeline operator’s response is critical to reduce 

the consequences of an incident. My statement is based on a recent 

report to the Committee covering variables that affect pipeline operator’s ability to respond quickly to a response and opportunities 

we identified to measure and improve these operator’s incident response times. 

First, a number of variables, only some of which are within an 

operator’s control can influence operator response time. For example, weather conditions and time of day are variables beyond an operator’s control. Factors within an operator’s control include the operator’s leak detection capabilities, proximity of operator response 

personnel, the type of valve installed, automated or manual, and 

relationships with local first responders. 

These factors affect incident response time to varying degrees depending on the specific incident. Given the Committee’s interest in 

the topic of automated valves I’d like to take a moment to discuss 

that factor. PHMSA, which oversees pipeline safety, does not mandate the installation of automated valves but does require that 

such valves be considered as part of an operator’s risk assessment 

for pipeline segments in highly populated or environmentally sensitive areas. 

The primary potential advantage of installing these valves, 

whether automatic shutoff or remote controlled, is the speed they 

provide in isolating a pipeline segment. However, one potential 

downside of these valves is the risk of accidental valve closure 

which could lead to loss of service to customers. 

The potential advantages and disadvantages of installing automated valves can vary based on the unique attributes of the valve’s 

location. Therefore we concluded that the decision of whether to install automated valves should be made on a case-by-case basis. For 

example, if a valve is located at an operator’s facility that is staffed 

24 hours a day, a manual valve might be sufficient. 

We found that most operators are currently making these decisions on a case-by-case basis and are using a variety of risk-based 

frameworks including decision tree and spill modeling software to 

aid in their decisionmaking. 

Moving on to my second point, we identified potential opportunities for PHMSA to improve incident response time in two areas, 

performance-based requirements and information sharing. We and 

others have recommended that the Federal government move toward a more performance-based regulatory approach to allow those 

31 

1 In its regulations, PHMSA refers to the release of natural gas from a pipeline as an ‘‘incident’’ (49 C.F.R. § 191.3) and a spill from a hazardous liquid pipeline as an ‘‘accident.’’ (49 C.F.R. 

§ 195.50). For simplicity, this statement refers to both as ‘‘incidents.’’ 2This statement uses the term ‘‘transmission pipeline’’ to refer to both onshore hazardous liquid and natural gas pipelines carrying product over long distances to users. 

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. 

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 

32 

3For 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. 4Oak 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, § 4, 125 Stat. 1904, 1906 (2012). 5GAO, Pipeline Safety: Better Data and Guidance Needed to Improve Pipeline Operator Incident Response, GAO–13–168 (Washington, D.C.: Jan. 23, 2013). 

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

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. 

Summary 

Numerous variables—some of which are under operators’ control—influence the 

ability of transmission pipeline operators to respond to incidents. For example, the 

location of response personnel and the use of manual or automated valves can affect 

the amount of time it takes for operators to respond to incidents. However, because 

the advantages and disadvantages of installing an automated valve are closely related to the specifics of the valve’s location, it is appropriate that operators decide 

whether to install automated valves on a case-by-case basis. Several operators we 

spoke with have developed approaches to evaluate the advantages and disadvantages of installing automated valves, such as using spill-modeling software to estimate the potential amount of product released and extent of damage that would 

occur in the event of an incident. 

One method PHMSA could use to improve operator response to incidents is to develop a performance-based approach for incident response times. While defining performance measures and targets for incident response can be challenging, PHMSA 

could move toward a performance-based approach by evaluating nationwide data to 

determine response times for different types of pipeline (based on location, operating 

pressure, and pipeline diameter, among other factors). First, though, PHMSA must 

improve the data it collects on incident response times. These data are not reliable 

because operators are not required to fill out certain time-related fields in the reporting form and because operators told us they interpret these data fields in different ways. Furthermore, while PHMSA conducts a variety of information-sharing 

activities, the agency does not formally collect or share evaluation approaches used 

by operators to decide whether to install automated valves, and not all operators 

we spoke with were aware of existing PHMSA guidance designed to assist operators 

in making these decisions. We recommended that PHMSA should: (1) improve incident response data and use those data to explore the feasibility of developing a performance-based approach for improving operators’ responses to pipeline incidents 

and (2) assist operators in deciding whether to install automated valves by formally 

collecting and sharing evaluation approaches and ensuring operators are aware of 

existing guidance. PHMSA agreed to consider these recommendations. 

Background 

Three main types of pipelines—gathering, transmission, and distribution—carry 

hazardous liquid and natural gas from producing wells to end users (residences and 

businesses) and are managed by about 3,000 operators. Transmission pipelines 

33 

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. 7The National Response Center, managed by the United States Coast Guard, is the sole Federal point of contact for reporting oil and chemical spills. 8PHMSA may conduct an incident investigation in instances when an NTSB investigation is 

also under way. In such cases, PHMSA does not determine the cause of the incident; rather its 

review is to determine regulatory compliance. 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. § 195.452(i)(4). We refer to all of these valves as automated valves. 10 49 C.F.R. §§ 192.179, 195.260. 

carry these products, sometimes over hundreds of miles, to communities and largevolume 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

According to PHMSA, industry, and state officials, responding to either a hazardous liquid or natural gas pipeline incident typically includes detecting that an 

incident has occurred, coordinating with emergency responders, and shutting down 

the affected pipeline segment. Under PHMSA’s minimum safety standards, operators are required to have a plan that covers these steps for all of their pipeline segments and to follow that plan during an incident. Officials from PHMSA and state 

pipeline safety offices perform relatively minor roles during an incident, as they rely 

on operators and emergency responders to take actions to mitigate the consequences 

of such events. Operators must report incidents that meet certain thresholds—including incidents that involve a fatality or injury, excessive property damage or 

product release, or an emergency shutdown—to the Federal National Response Center.7 Operators must also conduct an investigation to identify the root cause and lessons learned, and report to PHMSA. Federal and state authorities may use their 

discretion to investigate some incidents, which can involve working with operators 

to determine the cause of the incident.8

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. 

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, 

34 

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 Times 

Variables within an operator’s control Variables beyond an operator’s control 

• Leak detection capabilities. Pipeline operators perform a variety of leak detection activities to monitor 

their systems and identify leaks, including periodic 

external monitoring, such as aerial patrols of the 

pipeline, as well as continuous internal monitoring, 

such as measuring the intake and outtake volumes 

or pressure flows in the pipeline. 

• Location of qualified operator response personnel. Response personnel who have a greater distance to 

travel to the facility or valve site can take longer to 

establish an incident command center or to close 

manual valves. 

• Type of valves. Automated valves, which can be 

closed automatically or remotely, can shorten incident response time compared to manual valves, 

which require that personnel travel to the valve site 

and turn a wheel crank or activate a push-button actuator to close the valve. 

• Control room management. Clear operating policies 

and shutdown protocols for control room personnel 

can influence response time to incidents. For example, 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. 

• Type of release (leak vs. rupture). Leaks are generally a slow release of product over a small area, 

which can go undetected for long periods. Once a 

leak is detected, it can take additional time to confirm the exact location. Ruptures, which usually 

produce more significant changes in the external or 

internal conditions of the pipeline, are typically easier to detect and locate. 

• Time of day. The operator’s response personnel may 

be delayed in reaching facilities in urban or suburban areas during peak traffic times. Conversely, if 

an incident occurs during the evening or on a weekend, the operator’s response personnel could be able 

to reach the facility more quickly, because of lighter 

traffic. 

• Weather conditions. Weather-such as storms, winter 

conditions, and wind-can affect how quickly an operator can detect and respond to pipeline incidents. 

• Other operators’ pipelines in the same area. If two or 

more operators own pipeline in a shared right of 

way determining whose system is affected can increase incident response time. 

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. 

35 

11The 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. 12For 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. 

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. 

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— 

36 

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. 

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. 

Defining performance measures and targets for incident response can be challenging, but one possible way for PHMSA to move toward a more quantifiable, performance-based approach would be to develop strategies to improve incident response based on nationwide data. For example, performing an analysis of nationwide incident data—similar to PHMSA’s current analyses of fatality and injury 

data—could help PHMSA determine response times for different types of pipelines 

(based on characteristics such as location, operating pressure, and diameter); identify trends; and develop strategies to improve incident response. However, we found 

that PHMSA does not have the reliable nationwide data on incident response time 

data it would need to conduct such analyses. Specifically, the response time data 

PHMSA currently collects are unreliable for two reasons: (1) operators are not required to fill out certain time-related fields in the PHMSA incident-reporting form 

and (2) when operators do provide these data, they are interpreting the intended 

content of the data fields in different ways. Our report recommended that PHMSA 

improve incident response data and use these data to evaluate whether to implement a performance-based framework for incident response times. PHMSA agreed 

to consider this recommendation. 

We also found that PHMSA needs to do a better job of sharing information on 

ways operators can make decisions to install automated valves. For example, many 

of the operators we spoke with were unaware of existing PHMSA enforcement and 

inspection guidance that could be useful for operators in determining whether to install automated valves on transmission pipelines. In addition, while PHMSA inspectors see examples of how operators make decisions to install automated valves during integrity management inspections, they do not formally collect this information 

or share it with other operators. Given the variety of risk-based methods for making 

decisions about automated valves across the operators we spoke with, we believe 

that both operators and inspectors would benefit from exposure to some of the methods used by other operators to make decisions on whether to install automated 

valves. Our report recommended that PHMSA share guidance and information on 

operators’ decision-making approaches to assist operators with these determinations. PHMSA also agreed to consider this recommendation. 

Chairman Rockefeller this concludes my prepared remarks. I am happy to respond 

to any questions that you or other Members of the Committee may have at this 

time. 

37 

1 According to PHMSA officials, Alaska, California, Louisiana, and Oklahoma have the majority of federally unregulated gathering pipeline mileage in the United States. 

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

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. 

38 

2Pipelines 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 § 192.3). Some 

transmission pipelines operate under special permits that allow different maximum operating 

pressure that could exceed 72 percent of SMYS. 

GAO–12–389R: Safety Effects of Less Prescriptive Requirements for LowStress 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. 

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 indepth 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 lowstress transmission pipeline failure are generally not severe because these pipelines 

are more likely to leak than rupture, the point at which a gas pipeline fails by rupture is uncertain and depends on a number of factors in addition to pressure, such 

as the size or type of defect and the materials used to conduct the pipeline. In addition, the mileage and location of pipelines that would be affected by such a regulatory change are currently unknown, although PHMSA recently changed its reporting requirements to collect such information. The concern is that because distribution pipelines are located in highly populated areas, the low-stress transmission 

pipelines that are connected to them could also be located in highly populated areas. 

As a result, we considered the current regulatory approach of applying more prescriptive transmission pipeline requirements reasonable. 

39 

APPENDIX II: EXAMPLES OF PIPELINE INCIDENT RESPONSE TIMES

Operators we spoke with stated that the amount of time it takes to respond to 

an incident can vary depending on a number of variables (see table 2). 

Table 2.— Examples of Response Times in Select Pipeline Incidents from 2009 to 2011 

Incident 

response time Description 

1 minute A rupture on a natural-gas transmission pipeline located underground in a sparsely populated area was caused when a construction company worker accidentally struck the pipeline, which then ignited and exploded. When the line broke, automatic-shutoff valves on either side of the rupture closed within one minute. Despite the fast valve closure, the explosion caused one fatality-the worker who struck the pipeline-and injured seven others. The 

affected pipeline segment was 20 miles long. Though the valves were closed, there was 

enough gas remaining in the pipeline to fuel the fire for several hours. In addition to causing a fatality and injuries, the incident cost the operator an estimated $1 million, due primarily to the value of the lost product ($740,000), as well as damage to the pipeline 

($288,000). 

3 minutes A rupture on a hazardous liquid transmission pipeline, located underground near a creek 

in a sparsely populated area, was caused when heavy rains shifted the land which broke 

the pipeline, releasing over 1,700 barrels of propane. The line break was immediately 

picked up by the operator’s computer-based leak detection system, and operator personnel 

on site closed manual valves to isolate the segment within 3 minutes. Because propane is a 

highly volatile liquid, which turns to gas when released into the atmosphere, there was no 

soil or water contamination or environmental cleanup costs. The incident cost the operator 

an estimated $128,000, due primarily to the cost of repairs ($73,000) and value of lost 

product ($55,000). 

8 minutes During the night, unknown individuals operating construction equipment punctured a hazardous liquid transmission pipeline located underground in an environmentally sensitive 

area, causing 56 barrels of crude oil to leak into the soil. The puncture caused a drop in 

pressure that the control room operator detected in 2 minutes. Six minutes later, the control room operator shut down the pipeline and isolated the affected segment with remotely 

controlled valves. About 2 hours later, the operator’s response personnel arrived on site. 

The incident cost the operator an estimated $1.3 million, due primarily to its environmental remediation efforts ($1 million) and emergency response ($250,000). 

2 hours A crack on an above-ground portion of a hazardous liquid pipeline, located in a populated 

area, caused 120 barrels of crude oil to spray into the air. About 15 minutes after the incident started, a local resident reported to the fire department that crude oil was spraying 

into the air at a pipeline station. The fire department went to the incident site and, about 

30 minutes after the initial call, notified the pipeline operator of a broken oil pipeline. 

About 20 minutes after receiving the fire department’s call, the control room began shutting down the pipeline system and isolating the affected segment by ordering the closure of 

the upstream valve. Approximately 50 minutes later-about 2 hours after the incident started-response personnel arrived on site and manually closed the valve, which stopped the 

leak. The incident cost the operator an estimated $183,000, due primarily to its emergency 

response ($118,000) and environmental remediation efforts ($61,000). 

7 days A natural gas transmission pipeline, located underground in a sparsely populated area, developed a small leak as the result of a construction defect. The operator did not discover 

the leak on the pipeline for almost a week following initial reports due to the size of the 

leak in combination with wind gusts in the area that dissipated the escaping natural gas, 

reducing the common signs of a gas leak, such as the smell and damage to vegetation. 

Once the operator detected the leak during routine, periodic external monitoring of the 

pipeline, it took over a day to identify its exact location. The incident cost the operator an 

estimated $128,000 in repairs ($106,000) and lost product ($22,000). 

Source: GAO presentation of information obtained during interviews with pipeline operators. 

The CHAIRMAN. Thank you very much. I have to do an immediate 

apology because as I praised GAO it occurred to me that I wasn’t 

praising the agencies seated to your right. And there’s a reason for 

that. They have specific tasks used to cover the world. In other 

words, I could write you a letter saying what do you think the future of whales are or coral reefs, and I would get an answer. 

Ms. FLEMING. Right. 

40 

The CHAIRMAN. A very academic reason to answer. So I just 

make that separation for my own protection from these two very 

nice people whose agencies I desperately need. 

Ms. Quarterman, I thank all of you for your statements. And any 

time we have a pipeline incident we hear about the amount of time 

that it took the operator to respond to that incident and therefore 

shut down the flow of gas or oil through the affected pipeline. 

The aftermath of the Sissonville incident is no different. While 

the cause of the event is still under investigation, there has been 

a lot of discussion about how quickly the operator did or did not 

respond, and I want to delve into this a bit. 

Ms. Quarterman, what is an acceptable amount of time that an 

operator should take to respond to a rupture? And I understand 

there are a lot of variables that can impact how it takes an operator to respond, nature and lots of things. But there are metrics 

that you can put in place to measure how well operators are performing; is that not right? 

Ms. QUARTERMAN. That is correct. We require that an operator 

respond promptly. After the incident that occurred in San Bruno 

we came forward and—— 

The CHAIRMAN. That’s California? 

Ms. QUARTERMAN. California, yes. I’m sorry. In August 2011 we 

put out an advanced Notice of Proposed Rulemaking where we 

asked a series of questions about gas transmission and pipelines in 

particular. And ways that our regulations could be improved included among the questions that were asked related to remote and 

automatic shutoff valves and whether or not that is an option that 

should be considered moving forward. 

When the Pipeline Safety Act passed there was a provision in 

that Act as well that required us to study it with respect to existing pipelines and report back, which is one of the reports that we 

finished at the end of this year, and ask GAO to study it with respect to existing pipelines. And the report that came out today is 

associated with that. 

Another thing that we are looking at, and I think I mentioned 

during our testimony, is that later on this year we’re planning to 

have a workshop with respect to the integrity management program and begin to ask some of these questions about how we might 

expand upon what is right now a performance-based system to ensure that operators are really assessing the risks and responding 

on a timely basis. 

The CHAIRMAN. Can you explain to me more specifically what 

you mean by the way in which they choose to respond or not respond? What is it that they go through? I’m going to also ask this 

to another witness later on. What is it they go through in order to 

decide—first they have to know about it. Then they have to make 

a decision based upon several factors. 

Now, Ms. Hersman was referring to 16 fluctuations that took 

place before this Sissonville pipe blew. What’s the way that they 

planned in how they’re going to respond? What goes through their 

head? 

Ms. QUARTERMAN. I think perhaps Columbia Gas would answer 

this better. But what I hope goes through their head is when they 

have an alarm or alert at a control room, as was the case here, 

41 

they should take that very seriously because it indicates that something severe may have happened and they should alert the authorities. They should talk among themselves within the control room 

and immediately move toward shutting a pipeline in if there’s an 

indication that there is a loss of pressure in that pipeline. Because 

that’s an indication that there is a leak. 

One of the other studies that we also completed recently was an 

independent study on leak detection because of concerns we had 

about the fact that in many instances a leak is not found until 

someone in the public calls and says something has exploded or 

there’s oil all over the place, another provision also of the act that 

we’re looking at closely. 

So, in part, it’s detecting a problem, and the second is stopping 

the problem. If you have an automatic or remote control shutoff 

valve you can do that instantaneously. 

The CHAIRMAN. And you can do that from the response—— 

Ms. QUARTERMAN. From the control room. 

The CHAIRMAN. Yes. 

Ms. QUARTERMAN. It should be right there. And ideally, if you 

have a good safety culture, you should have given every one in that 

control room the authority to shut down the pipeline if they’re concerned. So it’s not a question of, you know, calling the boss who 

might not be there and saying there’s a problem, but immediate 

authority to shut the pipeline in. And also notifying the public officials that there is a problem so that they know, if there is an incident that’s out there, they know the cause of it and they can immediately start communicating and responding to it. 

They should also notify the National Response Center, notify so 

that we in the public sector know that there has been an incident. 

And that gets communicated all around government so everyone 

knows immediately that there is a problem. 

The CHAIRMAN. All right. I thank you. 

For Ms. Fleming, you note a lack of data that the Department 

of Transportation had about incident response times. Can you identify specific data that would be helpful for the department in order 

to make timely collections? What type of metrics would work best 

to measure operator’s performance on how quickly they respond 

given the number of variables such as weather, traffic, rupture location? Can you provide examples from other industries? Large 

question, but interesting. 

Ms. FLEMING. Yes. All right. So I think your first question was 

regarding data that would help measure incident response. So 

there are a couple of key areas, four to be exact, that we feel would 

really help PHMSA try to get a sense of incident response time. 

The first is the amount of time it takes an operator to identify 

and confirm an incident. The second would be when an operator or 

emergency response folks arrive at a scene. Third would be how 

much time it takes an operator to close a valve and isolate a pipeline segment. And then last would be the amount of time it takes 

for the operator or emergency response folks to assess the incident 

and declare it safe again. 

Currently PHMSA does not collect information in all of these 

areas. They only require the date and time the incident occurs. And 

we feel that all of these areas are important in order to be able to 

42 

move toward a performance-based framework. So currently the 

data is unreliable because it’s not complete. It doesn’t encompass 

all of those areas. And when operators do try to provide information they’re providing, it’s kind of spotty because they’re interpreting the data fields differently amongst the operators. 

So if PHMSA was able to collect this information they would be 

able to then take a step back and analyze to look for average incident response times and also look for trends amongst the different 

types of incidents and also amongst the pipeline operators. 

Your second question, I think, gets to the metrics. So in our work 

we’ve identified several characteristics of performance measures 

that really help organizations to identify, target, and track safety 

efforts. 

The first would be to really develop specific measurable goals 

that make clear the results you’re trying to achieve. An example 

of that would be the Federal Motor Carrier Safety Administration 

has a range of measurable goals that they use to assess progress 

in how their enforcement programs are working and also in terms 

of the compliance with safety regulations and in reducing crashes, 

fatalities, and injuries. 

The second characteristic that we think is important for metrics 

would be that the goals should really be targeted toward your key 

dimension in terms of your performance measures. So an example 

of that would be the Federal Railroad Administration’s annual 

budget submission has very specific numeric targets in terms of 

trying to reduce average train accident rates. 

And another example would be other emergency response organizations really have response requirements. For instance, the National Fire Protection Association requires that fire departments, 

the first fire engine must arrive within 4 minutes of an incident 

and all subsequent fire engines must arrive within 8 minutes. So 

these types of performance measures allow different entities to 

kind of take a step back and to gauge and see what adjustments 

need to be made in order to really improve your response time. 

The CHAIRMAN. So it is possible even though conditions vary, terrain varies, geology varies, all kinds of things vary, it is possible 

to set out a general metric with specific timelines which can be 

aimed for or met? 

Ms. FLEMING. Absolutely, Mr. Chairman. I think the first step is 

to get a handle on the data and see what the data is telling you 

so that you can look across and say, OK, for this type of gas operator here’s what the trend is telling us or this type of liquid operator with this type of dimension and pressure, here’s the incident, 

here’s what’s happening in the last, you know, couple of years. 

Here’s what the trends are showing. 

And then you really definitely could start setting some performance time related requirements and—and metrics and—and see 

and make adjustments and work to improve response time and 

safety. 

The CHAIRMAN. Just to close my point, the general thought that 

some might have, well, you know, just too much depends on what 

the circumstance is, and you yield some veracity to that point. But 

you say that in general where you were collecting relevant data, 

data is data, no matter what it’s used for. 

43 

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. 

44 

Senator MANCHIN. OK. You might have other ones you might not 

want to talk about in here. Anyway, I’m understanding that’s the 

only one that was not able to be or was not fitted with a smart pig 

to be inspected. Why would that be? That’s still a big line, 20-inch. 

Ms. QUARTERMAN. It is a big line. And the three pipelines that 

are at issue, one was, as you mentioned, 26. I believe the other one 

is 30-inch. There was the SM–86 loop, which was 26-inch. The SM– 

86 loop was 30 inches. These three pipelines were essentially parallel in the same area. 

Senator MANCHIN. Right. 

Ms. QUARTERMAN. Under the integrity management rules that 

were issued in 2003, a pipeline that is in a high consequence area 

as determined by the rule must have assessments of it, one—one 

version of—one assessment method, a very popular one, is an inline 

inspection tool or a pig. 

With respect to the two larger pipelines, because of the size of 

the line, the diameter, as well as the pressure of the line, there was 

a calculation made that is called the PIR, the potential impact radius. So depending upon how big the pipe—how much pressure it 

is, the diameter of the pipeline, the bigger radius upon which the 

explosion would have an effect. 

With respect to the two larger pipelines, the explosion radius was 

bigger. The way it works is it’s sort of a bubble that travels up and 

down the pipeline. If there are 20 residences within a bubble it is 

considered a high consequence area. 

Senator MANCHIN. Is your thought process changing on that 

now? And I’m sure the industry might have other thoughts. But 

I’m sure everybody wants to be as safe as they can, and they don’t 

want these things to happen either. Are you—would your recommendation be now that these are all treat—they should be inspected by the pig, smart pig? 

Ms. QUARTERMAN. I mentioned earlier the rulemaking that we 

came out with in August 2011. One of the questions on that was, 

number one, should we redefine the high consequence area, expanding the scope. Or, number two, should we require more pipelines to be inspected or assessed. That is still the rulemaking process, so I can’t comment on where we’re going with that. But that’s 

something that we are very, very, very seriously considering 

amending. 

Senator MANCHIN. And one real quickly, Ms. Fleming, if I may 

ask, the automated valves, my experience was I kept thinking why 

don’t they just shut this thing off? Why is it still burning? And I 

understand the location, demographics and all that. 

And I’m understanding also that some of the valves may cause 

a problem as much as they might prevent a problem. Does that advance to the position to where you all have taken the position that 

there should be automated valves? And at what increments do you 

believe this should happen? 

Ms. FLEMING. We leave the increments to PHMSA. 

Senator MANCHIN. OK. 

Ms. FLEMING. You know, there are a number of means to try to 

improve response time. And it may make sense for an operator to 

install them every single location. It really is on a case-by-case. 

There are other factors—— 

45 

Senator MANCHIN. What do you mean by every single location? 

Because some of these lines are quite, quite long. 

Ms. FLEMING. Right. Right. Absolutely. We spoke to eight operators. 

Senator MANCHIN. Between compressing stations and things of 

that sort. 

Ms. FLEMING. Yes. We spoke to eight operators. And one operator, a gas operator, said that, you know, they just made a decision 

that they are going to replace them and put automated valves regardless of risk. Because in their view they wanted to remove any 

judgment that control room staff would have in terms of whether 

or not to shut down the operation. So they just didn’t want that 

to come into play during an incident. 

And there are other factors that are very critical too to a response. And really upgrading your leak detection capabilities, making sure your response personnel are close to the valve. Again, the 

control room procedures are very important to make sure that folks 

have adequate training and the authority to shut down the system. 

So we just feel that operators should take all of these factors into 

consideration knowing their characteristics of the pipeline location, 

and really do what they feel in working with PHMSA to come up 

with the optimal solution. Because as we know, automated valves 

absolutely improve safety but only in conjunction with a rapid well 

coordinated response. 

Senator MANCHIN. Thank you, Senator. 

The CHAIRMAN. Thank you, Senator Manchin. 

Just a quick one. Are you aware of any pipeline companies where 

when the control room lights up that the people that run the control room feel that they need to call a higher up to get permission 

to shut off the flow of gas? 

Ms. FLEMING. We talked to eight operators. And a couple of folks 

told us that the old way of doing things was that, you know, kind 

of keep it running at all costs, right. And they said that they were 

very pleased that things were changing in that environment, that 

at least for their company safety was becoming the most important 

thing. But, again, we only spoke to eight operators and I think 

there’s over 600 in the country with pipeline in highly populated 

and environmentally sensitive areas. 

So I think control room protocols, procedures are critical. And I 

think folks need to have adequate training and have the proper authority to shut down a system to make sure that there’s no rupture 

or leaks. 

The CHAIRMAN. Yes, that was brought to my attention first 

through that movie the China Syndrome. 

Ms. FLEMING. Right. 

The CHAIRMAN. I mean, that was the whole—that was the whole 

ball game. 

Ms. FLEMING. That was the premise, right? 

The CHAIRMAN. Yes. All right. 

For Ms. Quarterman, last year’s Pipeline Safety Bill required 

that automatic or remote controlled shutoff valves be installed on 

new and/or reconstructed pipelines where feasible. Now, the phrase 

‘‘where feasible’’ perplexes me. I know you’ve started working on 

this requirement. What kind of process—progress are you making 

46 

in terms of this requirement? When can you expect to finalize this 

requirement? 

And I won’t ask you whether OMB is being difficult. I didn’t ask 

you that. I was just talking to myself. If you could answer the first 

part of the question, please. 

Ms. QUARTERMAN. With respect to the automatic and remote controlled shutoff valves, I believe the requirement is that we perform 

a study and then determine whether to regulate. Fortunately we 

had already started the regulations before the law passed so we are 

well along the way in terms of looking at that. 

As I mentioned, there was a study released at the end of 2012 

that was performed by an independent expert on those valves. And 

the next act will be ours in terms of proposing a regulation going 

forward. I think the new pipelines are the easy part of this. It is 

the existing pipelines that will be much more difficult for us. 

The CHAIRMAN. But the general feeling is that the words ‘‘where 

feasible’’ is not one which I should worry about? 

Ms. QUARTERMAN. I think candidly that not only we but the entire industry is now committed to making sure that this happens 

going forward, that the valves are in place going forward for new 

pipelines. 

The CHAIRMAN. And you have the power through rule making, et 

cetera, to make sure? 

Ms. QUARTERMAN. Absolutely. 

The CHAIRMAN. Thank you. 

This is a question is for Ms. Hersman and Ms. Fleming. The 

NTSB has advocated for requiring automatic or remote controlled 

shutoff valves on existing pipelines. 

Ms. Fleming, GAO has ultimately said that requiring these 

valves across the board may not be appropriate as a way forward. 

If these valves increase safety levels, why shouldn’t we push for 

them to be installed as much as possible and why this conflicting 

approach? 

Ms. HERSMAN. The NTSB is charged with investigating accidents 

and making recommendations to prevent their reoccurrence or the 

loss of life or injury. We have seen in multiple investigations like 

San Bruno, CA where we had loss of life in a natural gas accident; 

Marshall, Michigan where they had a catastrophic release of crude 

oil, and here in Sissonville, WV. 

What we see is, one, a lack of recognition that the pipeline has 

leaked. In two of these events, an outside source called in and reported the rupture. 

The CHAIRMAN. Somebody else calling in? 

Ms. HERSMAN. Somebody else calling in and saying there’s a 

problem. That is because the systems that have been set up to operate these pipelines are really operational systems. They are not 

leak detection systems. They monitor and control the distribution 

of gas and oil to customers in the most efficient manner. 

These systems are not sophisticated. In fact, here in Sissonville, 

there were three parallel lines and they all interconnected at various points. When Columbia needed to isolate and identify the ruptured line, the technology they had would not provide the appropriate information to them. They didn’t—— 

The CHAIRMAN. Would or would not? 

47 

Ms. HERSMAN. Would not because they could not identify which 

of the three lines had ruptured and they had to shut down all three 

lines. The Control Centers do not have that level of sophistication. 

In Marshall, MI, it took Enbridge, the operator, 17 hours to identify the leak on a hazardous liquid line. They restarted the line 

twice, and they were about to do it for a third time. During the 17 

hours, there were three shifts of employees who did not recognize 

that there was leaking petroleum. It was the worst onshore oil spill 

we have had in the United States, almost $1 billion worth of damages. 

The control systems are not recognizing ruptures. These automatic systems—and, again, Ms. Fleming mentioned it—takes the 

decisionmaking process out in some instances. If you have a huge 

outflow of gas on a single line, you know you need to shut that line 

down. In Sissonville, the rupture occurred on the smallest line 

where this rupture occurred of the three interconnected pipelines. 

The interconnection of the lines massed the drop in pressure because it was pulling gas from all three of those lines so the controller only saw a 100 PSI drop. 

If the controller had known on those cross flows where the gas 

was going, that it wasn’t going this direction, that it was escaping, 

it would have helped. The future is really to improve the technology. To understand what is going on, to provide the controllers 

better information, and to have automatic valves, because we know 

that people have problems shutting these valves down. In San 

Bruno, an urban area, it took them almost 90 minutes to close the 

valves. That was not because they were far away. It was because 

of traffic congestion. They physically could not get to the valves. 

In an area like West Virginia the situation could have been very 

different if it had been in the middle of the night, or during rush 

hour with more people on I–77. At the time of the rupture, there 

were four people in the compressor station at Lanham because it 

was during the work day. They actually could shut those valves 

down. It took them an hour to do it, but they could close the valves. 

They did not have to come from somewhere else to shut them 

down. 

Technology will help improve all of this. That being said, the 

NTSB makes recommendations for safety. That’s our focus. We 

don’t have to do the cost benefit analysis that Administrator 

Quarterman does to decide how much this costs versus how much 

the gain is. We look at what is in the best interest of the public 

when it comes to safety. We have a different mission. 

The CHAIRMAN. And the new technology, which I assume is in 

use in many places, is not mind bogglingly complex and expensive. 

Ms. HERSMAN. Well, I would say expensive is probably a relative 

term. It depends on who is paying for it. 

The CHAIRMAN. That’s what I want you to say. 

Ms. HERSMAN. That this is technology that is certainly available. 

And as I mentioned to Senator Manchin earlier, the problem with 

these systems that are based on infrastructure that’s 50 years old, 

is like the difference between having a paper map versus an electronic map with location technology when you’re on the highway 

and understanding that you’re in between two cities. 

48 

With a paper map, maybe you know the closest mile marker, but 

you don’t know exactly where you are. With a smartphone with 

GPS technology, however, you know exactly where you are. You 

can probably see weather and traffic on it too. The paper map is 

where we are with these pipeline systems. But, we need better 

technology to provide better information to people in the control 

rooms to identify, isolate, and shut down ruptured pipelines more 

efficiently and effectively. 

The CHAIRMAN. OK. Ms. Fleming, did you have—— 

Ms. FLEMING. I absolutely agree. I mean, I think automated—our 

work has shown that automated valves is a very effective means 

for improving response time and addressing an incident. But it is 

one—it’s just one of the means. We also think it’s very important 

to update leak detection technologies, to really take a look at your 

control room procedures, and then to really—each operator has to 

make an assessment in order to come up—and maybe it’s a combination or maybe it really is installing valves everywhere. But 

each one of them really needs to take a step back and figure out 

the optimum solution to their particular situation. 

We spoke to one pipeline operator, it was interesting, and one location would have taken them—they decided to automate this 

valve because they figured out that it would really take them about 

two and a half to 3 hours to get there. Once there it would take 

at least 30 minutes to shut down the valve. So by automating this 

particular valve they were able to reduce their incident response 

time to less than an hour. 

And so I think each entity has to go through this exercise, look 

at where the valves are, look at the characteristics of their system, 

look at the control room procedures, take a look at their leak detection capabilities, location of their response personnel really in order 

to come up with an optimal solution. 

The CHAIRMAN. Thank you. 

I want to ask a question to the panel, that in the absence of 

these valves that we’ve been discussing, are there feasible alternatives to help shut off ruptured lines more quickly? I’m just asking for a yes or a no. I would think it would be pretty much a 

standard. 

Ms. HERSMAN. Yes. 

The CHAIRMAN. Yes, there are? 

Ms. HERSMAN. You’re asking about technologies to shut the lines 

down quicker? 

The CHAIRMAN. Yes. 

Ms. HERSMAN. Yes. I think that’s some of the technology improvements that we have been talking about today. For example, 

what I saw actually this morning out at the Lanham Compressor 

Station are three types of valves. There are hydraulic valves that 

will actuate on their own once they are activated. 

There are electric valves that will close the pipelines that are 

slower. And there are manual valves. Some of the valves have to 

be physically operated. They require human beings to turn a hand 

crank hundreds and hundreds of times with significant force to 

close the valves. 

That is the reason why it took so long to close some of those 

valves at Lanham. People may imagine that somebody presses a 

49 

button and the valves are closed, but every situation is different 

depending on the infrastructure. Some valves require a person to 

be physically present if they are not automatic or remote control 

valves. 

The CHAIRMAN. Understood. 

Ms. FLEMING. And I think what we’re highlighting today is first 

you have to know that you have a problem. And so that’s the idea 

of really having the leak detection capabilities. But in some cases 

it’s also a robust public awareness program. 

You know, I think there are many incidents where it’s not necessarily the operator that’s the first one to make that call. And 

then once you have a problem then you have to have the best technology, whether it’s an automated valve, in order to shut down and 

isolate a segment. So it’s really taking a look at all of these different things to make sure that the public is aware of how to identify, how to report a problem. And then you have the capability to 

address a particular incident. 

The CHAIRMAN. I would think, Ms. Quarterman, before you answer, that particularly those people who live near gathering pipelines who recognize that there’s a major amount of activity taking 

place under their feet and in their area would be pretty quick to 

get familiar with a website with the right kind of information. 

Please? 

Ms. QUARTERMAN. One would hope so. But we understand that 

that is not always the case. From a technological perspective I’m 

not aware of any other technology beyond the ones you were talking about here today. But the public awareness point, I think, is 

an excellent one. We do require operators to put in place a public 

awareness plan so that individuals living near these facilities are 

aware of what’s there. They should be aware of what to look for 

if there’s a problem and how to respond to it. 

I understand from some of the conversations we’ve had here that 

Columbia Gas had done a reasonable job with that, the public 

awareness piece of it. We should also point to the prevention piece 

as well. I want to say a very great thanks for the state, for the 

Public Safety Commission, for the firefighters who were involved 

with this incident. I understood it went extremely smoothly given 

what had happened. I think they were aware that the pipeline was 

there, which has not always been the case in some of these incidents. 

And we’re trying to make sure that that doesn’t happen again by 

reaching out to emergency responders so they know in advance 

where the pipelines are in their area, who the operators are, who 

to call if there is a problem. That’s a big part of what we could be 

doing here as well. 

The CHAIRMAN. Senator Manchin has a question. I just wanted 

to put in when I was out there this morning talking with a fire 

chief who I knew from D-block and other subjects. There seemed 

to be a sense that they knew what they were meant to do. In other 

words, you go out there, you see this huge hole, vast amounts of 

straw covering land. 

And, you know, Sue Bonham’s, the remainder for their house, et 

cetera, that there would be a sense of, my heavens, we’ve never 

had this before. But to the contrary, the folks that live there and 

50 

work there and have responsibilities there seem to be rather calm 

about what their duties were and they proceeded to do them. That 

was my impression. So that’s not really a question. 

Ms. QUARTERMAN. I agree with that. I would also just like to add 

that when this incident occurred we happened to have been in 

Pennsylvania looking at some of the new development there. And 

my deputy is a former fire chief, Mr. Butters, got a call from the 

West Virginia folks and so we were talking to them immediately 

about this incident. And they have been fantastic throughout this 

period. Mr. Butters has been here and visited with those folks and 

we are really impressed with what they were able to do. And we 

are going to make sure that they are even better prepared in the 

future. 

The CHAIRMAN. OK. Senator Manchin? 

Senator MANCHIN. Very quickly. The Senator had mentioned 

about having apparatuses today that could automatically shut 

down and prevent, let’s say, these type of disasters to the extent 

that they are. 

The thing that comes to mind is the BP oil spill, and I think to 

all of our amazement how that thing could have blown for so long 

and spewed out for so long and we didn’t have the right equipment, 

if you would. And trying to design something in real time that 

would take care of the problem is difficult. And I’m sure that we’ve 

moved further ahead so that hopefully never happens again. 

I think the same thing is happening here. You’re saying that it 

should be strategically located when you have personnel, that you 

know you’re going to have personnel at some of these substations, 

that’s one thing. Knowing in a remote area is another thing. And 

are these rules and regulations or do you need codification from the 

legislation or—to move forward, where—where are you at on these 

things? 

Ms. QUARTERMAN. We don’t need codification. We have the authority to move forward in rulemakings on these things. I think 

some of the things that were being recommended by GAO are beyond rulemaking, putting in place some performance measures. 

We had a workshop earlier this year on the subject of data, 

something that I think we have not nearly enough of and need 

more of. And we actually have a rulemaking in progress to request 

more data from operators on a geospatial basis so that you can 

click on any point in a pipeline and know a lot about it. 

Senator MANCHIN. Yes. Are you all working with the company’s 

operators, people responsible for the lines so that we all come up 

with a conclusion on what’s the best method to take? 

Ms. QUARTERMAN. Absolutely. 

Senator MANCHIN. And they’ve been cooperative working with 

you? 

Ms. QUARTERMAN. They have been cooperative, yes. 

Senator MANCHIN. So you’re not having a problem there? It’s just 

making sure you get the right equipment in the right place? 

Ms. QUARTERMAN. Actually, we did a pilot program very recently 

because we were trying to get more geospatial base information. 

And NiSource was one of the volunteers for that to see if we could 

actually get the kind of data we wanted to get. 

51 

Senator MANCHIN. My final question, very quickly, is if that line 

had deteriorated to one-third of the actual size it should have been 

to carry safely the pressures it was carrying, it led me to believe 

that maybe there was other parts of that line that might blow. Are 

you sure that there’s a safety on that, which is the SM–80 line, the 

20-inch line? Since the other ones have been inspected I assume 

that this line is not inspected anywhere? Or have you started inspections on it? 

Ms. QUARTERMAN. It will be before it returns to operations. 

Senator MANCHIN. Got you. 

Ms. QUARTERMAN. One of the requirements in our corrective action order was that before they could begin operating again they 

would change the valves at the ends of the pipeline so that they 

can actually accept an inline inspection tool and run a corrosion 

test within that pipeline. 

And we have required that before they begin, you know, complete 

operations they will do that and they will then repair the line as 

though it was in a high consequence area even though under the 

official regs it is not. 

Senator MANCHIN. Thank you. 

The CHAIRMAN. There’s a final question before we go to the third 

panel and before I thank you all. 

The fire chief, who I said is a good friend, told me that there is 

in fact a length, he didn’t describe it, but a semi lengthy amount 

of plastic pipe sitting on the ground out in Sissonville carrying gas. 

And I’m trying to think how could that possibly be? 

Ms. QUARTERMAN. I am guessing, and I don’t know anything 

about that particular situation. I haven’t talked to him about that. 

I’m guessing it is a gas gathering line. This is another area that 

when the President put forward a request for reauthorization we 

requested the authority to be able to oversee gas gathering that 

had not traditionally been regulated. 

And when I mentioned my trip to Pennsylvania to see some of 

the shale plays, one of our concerns is that a great deal of gas gathering lines are going into place, some of them 20 inches or larger, 

high pressure lines that are currently not within our regulatory authority because they are in a rural area. We are extremely concerned that we get ahead of that problem by beginning to know 

what is out there, where pipelines are, and begin to regulate those 

lines in some way or fashion. 

The CHAIRMAN. In a rural area and therefore not within your jurisdiction? 

Ms. QUARTERMAN. Right. 

The CHAIRMAN. That strikes me as odd. I want to thank all three 

of you, and I don’t want you to move. I want you to stay right 

where you are because coming down on the plane with you, you all 

had briefing books that were like 10 inches thick in sort of biblically small handwriting and you’ve all read all of it. And I was 

just very impressed. 

And I was also concerned, Ms. Quarterman, with respect to your 

situation, because you indicate you do not have a large agency. And 

therefore the number of people as this burgeoning industry merges 

further, it will be important for you to be able to monitor it. And 

you have been there through a situation where you had 75 people. 

52 

Then you were taken down to 39 people and now you’re over 100 

people or whatever it is. That doesn’t sound like a very healthy 

way of doing business. You need stability, don’t you? You need 

enough people and you need stability. 

Ms. QUARTERMAN. Absolutely. We have a very small agency. Despite overseeing 2.6 million miles of pipeline, we have 200 people, 

135 of which are inspection enforcement personnel. 

The President was very generous in his request in Fiscal Year 

2013, which would add another 120 inspectors. We desperately 

need those people because those people not only do the day-to-day 

meat and potatoes inspection, when you have a boom as you’re having now with gas and oil production in this country, what happens 

next to the pipelines going to there. 

So they want to be there to see the construction as it happens. 

In addition to that, with all these incidents we also have to take 

people away from the day-to-day bread and butter inspections to do 

that. And the infrastructure is not getting any younger. So it is a 

huge challenge for us. 

The CHAIRMAN. I thank you all a lot. 

And I now call upon the third panel to sit over there. And that’s 

Mr. Jimmy Staton, who is Executive Vice President and Group 

CEO of the NiSource Gas Transmission & Storage. And second, Mr. 

Rick Kessler, President of the Board of the Pipeline Safety Trust. 

If you gentlemen could have a seat. 

And, Mr. Staton, if you could start with your statement, I would 

appreciate it. 

STATEMENT OF JIMMY D. STATON, EXECUTIVE VICE 

PRESIDENT AND GROUP CEO, NISOURCE GAS TRANSMISSION 

& STORAGE 

Mr. STATON. Good afternoon, Chairman Rockefeller and Senator 

Manchin. 

The CHAIRMAN. Could you pull that a little closer? 

Mr. STATON. Certainly. My name is Jimmy Staton, and I live in 

Clarksburg, West Virginia. And I’m the CEO of Columbia Gas 

Transmission, whose operational headquarters are located here in 

Charleston. And I appreciate the opportunity to be with you today. 

Columbia Gas is a proud member of the West Virginia community. And while we clearly recognize that the incident along our 

SM–80 pipeline near Sissonville was unacceptable, I want to assure 

you that we operate with a daily commitment to safety. We have 

been and will continue to work with all of our focus and our energy 

to make things right and to learn from this incident. 

In the wake of this incident we moved quickly to address the 

needs of the local residents and agencies. We partnered with the 

Red Cross to ensure that no necessity was overlooked as we took 

steps to address longer term issues like home repair and relocations. We are providing full reimbursements to local and state 

agencies for their emergency response costs and have made charitable contributions to other local entities who pitched in to help following the incident. 

We are also working with the NTSB and Administrator 

Quarterman and her team at PHMSA to identify the cause of the 

event and apply the findings to our operations systemwide. 

53 

The NTSB has noted that line SM–80 had experienced external 

corrosion. They also confirmed in a preliminary report that Columbia’s SCADA system detected a drop in pressure on the pipeline as 

it was designed to do. SCADA system alerts are a critical first step 

toward the initiation of our emergency response programs. 

We will continue to work cooperatively with these agencies as the 

NTSB completes its final analysis and will apply lessons learned to 

our processes, procedures, and all of our pipeline assets. 

We are also working with PHMSA to implement an integrity assurance plan that will ensure the long-term safety of the SM–80 

pipeline. Our plan is designed to safely return the line to limited 

service, to facilitate a comprehensive integrity assessment, including an internal or smart pig, as we’ve talked about today, inspection before we return to full service. A copy of our plan is attached 

to my written testimony. 

In addition to the steps we are taking to address the incident, 

we are undertaking a systemwide modernization of our pipeline infrastructure. This modernization program is designed to replace 

and rebuild our pipeline and compression facilities in order to improve the safety, reliability, and efficiency of our system. 

Our modernization program includes the replacement of nearly 

1,000 miles of older pipelines, provides for pipeline upgrades to expand the use of smart pigs, and the replacement of compression 

equipment to improve efficiency and environmental performance. 

Our modernization program is aligned with the U.S. Transportation Secretary Ray Lahood’s call to action as well as key provisions of the recent Pipeline Safety Act that you led reauthorization 

of a year ago. 

We developed our modernization program with the input and assistance of our customers and other stakeholders, and I am pleased 

to report that the Federal Energy Regulatory Commission recently 

endorsed our plan by issuing an affirmative order that clears the 

way for our modernization efforts to continue and more importantly 

to accelerate. 

And some of our most critical modernization projects will occur 

right here in West Virginia. We will invest close to three-quarters 

of a billion dollars in West Virginia in the first 5 years of our program alone on projects that will expand our ability to use smart 

pigs, replace older pipelines and upgrade compressors to improve 

efficiency and significantly reduce emissions. These infrastructure 

investments will not only improve safety but will also create jobs 

and generate new tax revenue for the state and localities. 

In closing, we recognize the importance of pipeline safety and are 

committed to applying the lessons learned from the Sissonville incident. In addition, the pipeline safety legislation you helped enact 

sought to drive investment in newer and more advanced pipeline 

systems all in the name of safety. Columbia’s modernization program helps accomplish this crucially important goal. 

Mr. Chairman, Senator, I was in Sissonville the evening of the 

event, and I saw the impact on the community. And I also looked 

at the faces of my employees who work and live in the Sissonville 

area. And I vowed to them at that time that we would do right and 

we would make it right for the people of Sissonville and that we 

would make the right investments, continue to make the right inVerDate Nov 24 2008 10:32 Jul 19, 2013 Jkt 075679 PO 00000 Frm 00057 Fmt 6633 Sfmt 6601 S:\GPO\DOCS\81794.TXT JACKIE
54 

vestments to ensure that our system does not incur another incident like this. And I make that same commitment to you all today. 

I thank you. That concludes my testimony, and I look forward to 

your questions. 

[The prepared statement of Mr. Staton follows:] 

PREPARED STATEMENT OF JIMMY D. STATON, EXECUTIVE VICE PRESIDENT AND GROUP

CEO, NISOURCE GAS TRANSMISSION & STORAGE

Introduction 

Mr. Chairman and Members of the Committee: 

My name is Jimmy Staton. I live in Clarksburg, West Virginia, and I am CEO 

of NiSource Gas Transmission & Storage, parent company of Columbia Gas Transmission whose operational headquarters are located in Charleston. 

Columbia Gas Transmission owns and operates approximately 12,000 miles of 

natural gas pipelines, including roughly 2,500 miles of pipeline in West Virginia. 

Our pipeline system is integrated with one of the largest underground storage systems in North America and we deliver domestically produced natural gas to businesses and communities across the Midwest, Mid-Atlantic and Northeast regions of 

the United States. Through our predecessor companies, NiSource and Columbia Gas 

have been a safe pipeline operator, an employer of choice and a community partner 

of West Virginia and surrounding states for more than a century. 

Personally, I have worked in the natural gas and energy industry for nearly 30 

years—serving in a variety of roles ranging from rates and regulatory to operations 

and engineering. At no other time during my career has there been such a promising outlook for America’s domestic energy potential—and the economic and national security related benefits that comes with it—but that energy potential must 

be grounded in a daily commitment to operating safely. 

At Columbia Gas we take our commitment to safety very seriously. I appreciate 

the opportunity to share with you the various initiatives we are undertaking to ensure we continue to provide safe and reliable pipeline service. 

Sissonville Incident 

Mr. Chairman, let me take a moment to provide you with an update on our efforts 

to respond to the incident that occurred on December 11, 2012, on our Line SM– 

80 pipeline near Sissonville. 

This was a terrible incident—one in which I hope we never see the likes of again. 

Thankfully, no one was seriously injured. Please be assured that we are fully committed to making this right and taking any steps necessary to ensure the safety of 

our company’s pipeline system. 

In working with local emergency responders, we were able to isolate the incident, 

secure the site, and focus on the following three key areas: 

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

(2) Collaborating with the National Transportation Safety Board (NTSB) and 

other federal, state and local authorities to identify the root cause of the event 

and apply ‘‘lessons learned’’ to our operations systemwide; and, 

(3) Working proactively with Federal and state officials to design and implement 

an Integrity Assurance plan that will ensure a safe return to service and the 

long-term integrity of Line SM–80. 

Attending to Community Needs 

Immediately following the incident, a team of local Columbia employees identified 

and made contact with each impacted resident to ensure that basic essentials, including temporary housing, food, and transportation were provided. Our team remained in constant contact with residents to ensure that no necessity was overlooked. In addition, we partnered with the regional office of the Red Cross—to tap 

into their special expertise, provide additional support for those in need, and facilitate Columbia employees and others in the community looking to help their neighbors through charitable giving. Our team has worked closely with all of the impacted residents to resolve the issues associated with the Line SM–80 incident. 

We know this incident impacted the lives of several families living in the area, 

and we will continue to work to make things right. 

We have also been working with various local and state agencies that assisted our 

efforts to safely secure the incident site. As a longtime West Virginia resident, I 

55 

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. 

know first-hand that during challenging times, we come together to help each 

other—and that has certainly been the case here. We are grateful for the dedication 

and commitment of the first responders, the Department of Highways, and other 

local agencies that provided support and recovery efforts that day. We also have 

moved quickly to ensure that the operating budgets for these public agencies were 

not adversely impacted by this incident, and are providing full reimbursements for 

costs associated with the emergency response services rendered by these groups. 

We’ve also provided contributions to the Aldersgate United Methodist Church and 

Sissonville High School in recognition of the important role they played in the hours 

and days following the incident. 

We recognize this was a difficult time for Sissonville and Kanawha County. It has 

been and will continue to be our priority to work proactively with those who were 

impacted, as well as those who lent a helping hand. We’ve enjoyed a positive working relationship with a number of local agencies in Kanawha County over our many 

years of providing service in West Virginia, and we look forward to continuing this 

cooperative partnership in the future. 

Cooperating with the NTSB 

As I mentioned earlier, we have been working in close collaboration with the 

NTSB to determine the cause of the incident and to implement lessons learned 

across our policies, procedures and pipeline assets. The NTSB has noted, both in 

press briefings and a recently issued Preliminary Report, that the ruptured line had 

experienced significant external corrosion. 

The NTSB has also confirmed that Columbia’s SCADA system detected a drop in 

pressure in the SM–80 line, as well as the nearby SM–86 and SM–86 Loop pipelines, as designed. Alerts issued by our SCADA system are the first critical step toward the initiation of our Emergency Response plan and the dispatching of personnel to a pipeline rupture site. Columbia’s SCADA system is staffed 24-hours a 

day, seven days a week by trained operations employees to provide a real-time monitoring of the flow of gas through our pipeline system. The proper functioning of our 

SCADA system and the procedures followed by our Control Room personnel were 

a crucial component to our response to the Sissonville incident. We will continue to 

work closely with the NTSB as it produces its final report and are committed to applying lessons learned to our Control Room procedures. 

A Safe Return to Service 

As NTSB’s investigation proceeds, our engineering team has been hard at work 

developing a comprehensive Integrity Assurance plan 1 to ensure the safe return to 

limited service for Line SM–80. This line is an important part of a pipeline system 

that plays a vital role in supplying natural gas to West Virginia and other critical 

eastern markets. 

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 

56 

2The Department of Transportation press release is attached in Appendix B. 

3 Columbia Gas Transmission, LLC, 142 FERC Paragraph 61,062 (2013), included in 

Appendix C. 

for the safe return of Line SM–80 to full commercial service and to ensure the longterm integrity of the pipeline. 

We will only return Line SM–80 to service once we have received approval from 

PHMSA and the West Virginia Public Service Commission, as well as communicated 

with our neighbors in Sissonville. We have also elected to hire an independent monitor experienced in pipeline safety and integrity related issues to provide a third 

party review of the plan and actions taken by Columbia in the course of carrying 

it out. The independent monitor will review pipeline integrity plans and inspections 

and provide feedback to both Columbia and PHMSA on the effectiveness of our 

work. 

Modernization 

In addition to our response to the SM–80 incident, Columbia is taking significant 

steps forward to assure the continued safe operation of our entire pipeline system 

for generations to come. 

Aligning our efforts with the ‘‘Call to Action’’ by U.S. Department of Transportation Secretary Ray LaHood, we developed a comprehensive modernization plan 

that ensures pipeline and system upgrades; improves public safety, customer reliability and service; and provides economic benefits. This modernization effort will 

strategically and systematically replace, revamp or rebuild key pipeline and compression facilities across our entire system. 

Our Modernization program, which is the first of its kind in the industry, is the 

culmination of a multi-year effort to evaluate our system and identify areas in need 

of investment. The program’s system improvements include: 

• Replacing Aging Infrastructure—replacing approximately 1,000 miles of existing 

interstate transmission pipelines, primarily bare steel (400 miles in the first 

five years); 

• Expanding In-Line Inspection Capabilities—facilitating Columbia’s ability to 

perform state-of-the-art maintenance and inspections without interrupting service; 

• Increasing Pipeline System Reliability—uprating pressures and looping systems 

where needed to ensure gas is reliably delivered to critical markets; and, 

• Upgrading Natural Gas Compression Systems—replacing and modernizing 

more than 50 critical compressor units along the pipeline system that will enhance system efficiency and improve environmental performance. 

We anticipate investing more than $2 billion in this program over the next five 

years—dollars that will be directly focused on increasing pipeline safety and service 

reliability. 

The Columbia Modernization program is aligned with key provisions of the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 that you and this 

Committee led the enactment of one year ago. Recently, Secretary LaHood publicly 

pledged to support and assist our efforts to navigate the Federal and state permitting process under the auspices of an Executive Order issued by President Obama 

in March of 2012 aimed at encouraging investment in vital and economically significant national infrastructure.2

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. 

A number of our most critical Modernization projects will be occurring in West 

Virginia. One of the largest of those projects will be the $38 million WB Pipeline 

project, which will upgrade a number of older pipelines to accommodate in-line inspection equipment, or so-called ‘‘smart pigs.’’ Our WB pipeline system runs across 

central West Virginia and delivers natural gas to the state and other eastern markets. Upgrading this system to accommodate today’s latest safety technology will not 

only allow for enhanced integrity assessment, but it will also greatly improve the 

efficiency and reliability of the pipeline. 

Our plan also calls for over $100 million in critical compression facility upgrades 

in West Virginia. Three compressor stations have been identified for enhancement 

at Seneca, Frametown, and Lost River. These investments will provide increased reliability, system flexibility and efficiency. Work at the stations will improve comVerDate Nov 24 2008 10:32 Jul 19, 2013 Jkt 075679 PO 00000 Frm 00060 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\81794.TXT JACKIE
57 

pressor horsepower, dramatically improve emissions performance, and result in a 

significant reduction in fuel consumption. 

In total, over the first six years of our Modernization program, Columbia will invest close to three-quarters of a billion dollars in safety and reliability related improvement projects in West Virginia alone. A recent economic analysis of our program estimates that Modernization will result in more than $1.1 billion in economic 

output in the state, including the creation or support of approximately 1,700 total 

jobs at the peak of our program in 2016 ranging from engineering to construction 

services. In addition to private economic activity, our Modernization investment is 

anticipated to generate approximately $80 million in new revenue for the State of 

West Virginia and its units of local government. Most importantly, our work in the 

state will make our systems safer and more reliable. 

Closing 

Mr. Chairman, Columbia’s Modernization program is good news for pipeline safety 

and good news for job creation. At its core, the legislation you spearheaded in the 

112th Congress sought to drive investment in newer and more advanced pipeline 

systems and facilities—all in the name of safely and reliably transporting this important resource. Columbia’s Modernization program helps accomplish this important goal and will keep us on a solid footing to safely and reliably deliver natural 

gas to the next generation of natural gas consumers. 

As a constituent, I cannot close without thanking you for your public service of 

nearly 50 years and your tireless dedication to the residents of West Virginia and 

this Nation. 

Thank you for the invitation to appear before the committee today. I am pleased 

to answer any questions you may have. 

APPENDIX A 

COLUMBIA GAS TRANSMISSION—INTEGRITY ASSURANCE PLAN

(EXECUTIVE SUMMARY)—JANUARY 8, 2013 

Columbia Gas Transmission, LLC—January 8, 2013 

LINE SM–80—LANHAM TO BROAD RUN—INTEGRITY ASSURANCE PLAN—PHASE 1 

TABLE OF CONTENTS

Executive Summary 

Background 

Safety 

Independent Review and Monitoring 

Preliminary Cause Determination 

Repairs to Incident Origin 

Verification of Cathodic Protection 

Preparation of Line SM–80 for In-Line Inspection 

Safe Return to Temporary Maximum Allowable Pressure 

Preliminary Phase I Schedule 

Summary and Overview of Integrity Assurance Plan—Phase 2 

Criteria—Assessment, Repair, Documentation, Request for Approval and Restoration of Full Service—Phase 3 

Conclusion Criteria—Periodic and Summary Reporting and Documentation— 

Phase 4 

COLUMBIA GAS TRANSMISSION—LINE SM–80 

LANHAM COMPRESSOR STATION TO BROAD RUN

INTEGRITY ASSURANCE PLAN—PHASE 1 

Executive Summary 

On December 11, 2012, at approximately 12:41 p.m., a natural gas pipeline incident involving an ignition and fire occurred in northern Kanawha County, WV, 

along the 20 inch diameter Columbia Gas Transmission (Columbia Gas) Line SM– 

80. Line SM–80 is approximately 30 miles long and runs from the Lanham Compressor Station to the Broad Run Valve Setting. In response to the incident, a pipeline segment approximately 8 miles long, from the Lanham Compressor Station to 

the Rocky Hollow Valve setting, was isolated, blown down and has remained out 

of service since the time of the rupture. In addition, a section approximately 22 

58 

miles long, from Rocky Hollow to the Broad Run valve setting, has been isolated 

and remains out of service, with a static pressure of less than 300 psig. The maximum allowable operating pressure (MAOP) of Line SM–80 is 1,000 psig, and the 

discharge pressure at Lanham was approximately 929 psig at the time of the incident. 

This integrity assurance plan details the first phase in a four-phase approach designed to implement corrective measures to prevent recurrence, and ensure the safe 

return to service of Line SM–80. Phase 1 of the plan focuses on making repairs and 

ensuring the near term safety and integrity of Line SM–80, while preparing the line 

for Phase 2. Phase 2 focuses on performing a comprehensive integrity assessment 

of Line SM–80. Based on the integrity assessment, Columbia Gas will implement 

appropriate preventive and mitigative measures to provide for the safe return of 

Line SM–B0 to full service and ensure the long-term integrity of the pipeline. Phase 

3 includes completion of necessary repairs, summarizing the work completed, requesting regulatory approval to return Line SM–80 to service, and upon approval, 

restoring normal service to the pipeline. Phase 4 focuses on steps that Columbia Gas 

will take to document and communicate the work conducted, including keeping regulators informed of progress, maintaining records, and tracking expenditures associated with implementation of this plan. 

Phase 1 Key Elements 

Phase 1 includes the steps that Columbia Gas will take to repair the damaged 

sections of the pipeline, ensure the integrity of the pipeline for operation at a reduced/restricted pressure, and ready the pipeline for further evaluation using in-line 

inspection tools. Key elements of Phase 1 are: 

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

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

(3) Verification that the cathodic protection (CP) system is operating properly on 

all three pipelines in the vicinity of the incident origin 

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

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

(6) Verification of the discharge pressure at Lanham Station immediately prior to 

the incident to establish a safe temporary maximum allowable pressure 

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

(8) Return of Line SM–80 to service at or below the safe temporary maximum allowable pressure on a temporary basis for purposes of conducting an in-line 

inspection. The pressure will be restored through a stepped approach that includes instrumented leak surveys. 

Background 

The NTSB conducted a field investigation following the incident. The NTSB reported that a 20 foot section of pipe was ejected during the event. The NTSB further 

reported that the ruptured pipeline was found to have areas consistent with external corrosion. According to the NTSB, visual examination of the ruptured pipe revealed a six foot area that ran along the bottom of the pipe where the pipe thickness 

was measured to be less than 1/10 inch thick in some places (approximately .078 

inch thick). On December 20, 2012, the Pipeline and Hazardous Materials Safety 

Administration (PHMSA) issued a Corrective Action Order (CAO) that requires the 

implementation of certain measures prior to restarting the pipeline to restricted 

service. 

The purpose of this plan is to detail the work that will be completed both in the 

vicinity of the incident origin as well as along Line SM–80 from Lanham Compressor Station to the Broad Run valve setting to safely return the pipeline to restricted service so that additional integrity assessment can be completed. This plan 

also details the other actions Columbia Gas will take to comply with the requirements set out in the CAO issued by PHMSA. As further detailed in this Plan, Phase 

1 includes: 

Preliminary Cause Determination 

• Continue to support the NTSB in the ongoing investigation of the incident and 

incorporate findings, as appropriate, into the Integrity Assurance Plan. 

59 

Repairs to Incident Origin 

• Verification of the integrity of the pipeline in the vicinity of the incident origin. 

• Repairs to Line SM–80 at the incident origin. 

Verification of Cathodic Protection 

• Verification that the cathodic protection (CP) system is operating properly on 

SM–80 and the two adjacent pipelines, SM–86 and SM–86 Loop, within three 

miles upstream and three miles downstream of the incident origin. 

Preparation of Line SM–80 for In-Line Inspection 

• Replacement of mainline valves along Line SM–80 from Lanham to Broad Run 

with new, full bore valves to enable passage of in-line inspection tools. 

• Investigation and, where necessary, replacement of other potential restrictions 

to the passage of in-line inspection tools. 

• Installation of a temporary launcher at Lanham Station and a temporary receiver at Broad Run to enable the passage of in-line inspection tools. A permanent launcher and receiver will be installed in Phase 2 (see Element 9 of ‘‘Summary and Overview of Integrity Assurance Plan—Phase 2,’’ below). 

Safe Return to Temporary Maximum Allowable Pressure 

• Verification of the discharge pressure at Lanham Station immediately prior to 

the incident for establishing a safe temporary maximum allowable pressure. 

• Inspection and full operation of all critical valves that might be required during 

an emergency to ensure they can be completely closed. 

• Installation and adjustment of pressure regulation and overpressure protection 

to support operation of the pipeline at a restricted pressure. 

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

In the course of completing the Phase 1 work, detailed documentation of measurements, pipe characteristics, pipe condition, pipe coating characteristics, environmental and other conditions will be collected. This information will be used, where 

appropriate, to support Phase 2 of the Integrity Assurance Plan. The results of the 

work outlined in this Integrity Assurance Plan will be shared with PHMSA, as well 

as the National Transportation Safety Board (NTSB) and the West Virginia Public 

Service Commission (WVPSC). 

Safety 

Employee and public safety will be the highest priority in the course of conducting 

the work outlined in this plan. All work will be conducted in a safe manner and 

will comply with all Columbia Gas safety plans and procedures. Daily safety meetings will be held that will include employees, contractors and authorized visitors at 

the beginning of each work day. All company and state required one-calls shall be 

completed and the site cleared before any excavation activities occur. In addition, 

all persons performing tasks covered by 49 CFR Part 192, Subpart N shall be qualified according to the Columbia Gas Operator Qualification Plan. 

Independent Review and Monitoring 

Columbia Gas will hire a qualified outside contractor (‘‘independent monitor’’) experienced in pipeline safety and pipeline integrity related issues to provide independent third party review and monitoring of the Integrity Assurance Plan prepared 

for Line SM–80 and the actions taken by Columbia Gas in the course of carrying 

out the work specified in the Plan. The independent monitor will (1) review and provide feedback to Columbia and PHMSA concerning the prudence and effectiveness 

of plans for verification of the integrity of Line SM–80, (2) review the results of inspections, tests and analysis completed for Line SM–80 during the course of this 

plan, (3) review the actions taken pursuant to the plan to ensure that they are reasonable and prudent, and (4) provide PHMSA with a quarterly report of progress 

towards compliance with the CAO and the Columbia Gas Integrity Assurance Plan. 

Preliminary Cause Determination 

Following the Line SM–80 pipeline incident, an investigation into the cause of the 

incident was initiated by the National Transportation Safety Board (NTSB). As stated, the NTSB has reported that the ruptured pipeline was found to have areas consistent with external corrosion and that visual examination of the ruptured pipe revealed a six foot area that ran along the bottom of the pipe where the pipe thickness 

60 

was measured to be less than 1/10 inch thick in some places (approximately .078 

inch thick). The NTSB, however, has not released a preliminary cause determination, and the investigation is ongoing. 

Columbia Gas has been fully cooperating with the NTSB investigation and is committed to supporting the ongoing investigation of the incident. Columbia Gas has 

provided and will continue to provide requested information and support to the 

NTSB and will incorporate, as appropriate, the findings of the investigation into the 

Integrity Assurance Plan. 

Repairs to Incident Origin 

The removed sections of pipe near the rupture origin will be replaced with new, 

coated pipe. Repair and testing of the pipe will follow the Pipe Repair, Modification 

and Hydrostatic Testing Plan provided in Attachment A. Up to approximately four 

joints (160 feet) of new 20 inch diameter, 0.375 wall thickness, API–5L X65 pipe 

will be installed at the location, The pipe will be hydrostatically tested for not less 

than eight hours at a minimum test pressure of 2,438 psig (100 percent SMYS). The 

minimum test pressure of 2,438 psig is equivalent to 244 percent of the pipeline 

MAOP of 1,000 psig. 

All girth welds will be non-destructively tested in accordance with the Columbia 

Gas Welding Manual and will be coated with a 100 percent solids two-part epoxy 

in accordance with Procedure 70.001.026 External Coating—Underground Facilities—New Construction or Maintenance Application (See Attachment B). In addition, the pipe will be supported with sand bags, covered in rock shield, and soft fill 

will be installed below and around the pipe to ensure the pipe is protected from 

damage. Prior to backfilling the pipe, an instrumented inspection of the coating will 

be performed in accordance with Procedure 70.001,013—Inspect Pipe Coating with 

Holiday Detector (See Attachment C). 

Verification of Cathodic Protection 

Columbia Gas will inspect and verify the proper operation of all CP rectifiers, test 

stations and other CP equipment on Lines SM–80, SM–86 and SM–86 Loop within 

three miles upstream and three miles downstream of the incident origin. CP inspections will be completed after the pipe replacements described in the previous section. Inspections will include test station and rectifier readings that will be performed in accordance with Procedures 70.002.008—P/S Reading—Test Stations, 

70.002.001-Readings—Casing and 70.002.003—Reading—Rectifier (See Attachment 

D) and will be documented in the company Work Management System. Any deficiencies will be documented and remediated prior to continuing the Phase 1 Plan. 

Preparation of Line SM–80 for In-Line Inspection 

Line SM–80 from Lanham Compressor Station to the Broad Run valve setting is 

currently not equipped to allow the passage of in-line inspection tools. Pipe replacements, equipment replacements and facility enhancements, as follows, will be performed to prepare the pipeline for the passage of in-line inspection tools: 

• The existing mainline plug valves on Line SM–80 at Rocky Hollow and Patterson Fork Valve Settings will be removed and replaced with new ball valves that 

will support the passage of ILI tools. The replacement and testing of the pipe 

at these locations will follow the Pipe Repair and Hydrostatic Testing Plan 

shown in Attachment A. Pipe exposed during the course of the valve replacement work will be inspected following the Columbia Gas pipe inspection protocols (see Attachment E). 

• A review of pipe materials and mapping will be completed to identify any other 

restrictions that would inhibit the passage of in-line inspection tools. Where 

such restrictions are identified they will be investigated and, if necessary, replaced to ensure the passage of in-line inspection tools. The replacement and 

testing of the pipe at these locations will follow the Pipe Repair and Hydrostatic 

Testing Plan shown in Attachment A. Pipe exposed during the course of investigation or replacement work will be inspected following the Columbia Gas pipe 

inspection protocols (see Attachment E). 

• Temporary launchers and receivers sized and compatible with high resolution 

in-line inspection tools will be installed. A temporary launcher will be installed 

at Lanham Compressor Station and a temporary receiver will be installed at 

the Broad Run Valve setting. Due to the long lead time associated with permanent launchers and receivers, temporary facilities will be used to allow for inline 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’’. 

61 

• All girth welds will be non-destructively tested in accordance with the Columbia 

Gas Welding Manual and will be coated with a 100 percent solids two-part 

epoxy in accordance with Procedure 70.001.026 External Coating—Underground 

Facilities (See Attachment B). In addition, the pipe will be supported with sand 

bags, covered in rock shield, and soft fill will be installed below and around the 

pipe to ensure the pipe is protected from damage. An instrumented inspection 

of the coating will be performed prior to backfilling the pipe in accordance Procedure 70.001.013 Inspect Pipe Coating with Holiday Detector (See Attachment 

C). 

A drawing showing the areas along SM–80 where work is planned to prepare the 

line for the passage of in-line inspection tools is included in Attachment F. 

Safe Return to Temporary Maximum Allowable Pressure 

The following measures will be taken to ensure the integrity of Line SM–80 before 

it is returned to restricted service. 

• Repairs—Any actionable anomalous conditions discovered on the SM–80 pipeline during the course of completing Phase 1 of the Integrity Assurance Plan 

will be repaired following Operations and Maintenance Plan 220.02.01 Pipeline 

Repair (see Attachment G). 

• Critical Valves—All critical valves along the SM–80 pipeline system from 

Lanham to Broad Run that may be required during an emergency will be inspected and fully operated to ensure that they can be completely closed. Valve 

inspections will follow Plan 220.03.02 Valve Inspection and Operation and Procedure 220.002.001 inspection & Operation—Valve (see Attachment H) except 

that each valve will be fully operated. A schematic depicting all critical valves 

that will be inspected and operated is provided in Attachment I. 

• Discharge Pressure Review and Validation—A report validating the SM–80 discharge pressure at Lanham Compressor Station at the time of the incident is 

included in Attachment J. Columbia Gas has reviewed SCADA pressure data 

and has validated that the discharge pressure at Lanham Compressor Station 

on Line SM–80 at the time of failure was greater than,929 psig, which Supports 

a temporary MAOP of 741 psig (80 percent of 929 psig). However, due to favorable market conditions, Columbia Gas has determined that additional safety 

measures can be taken and will further restrict the temporary MAOP to 600 

psig for the duration of the Integrity Assurance Plan. 

• Return to Service under Temporary Maximum Allowable Operating Pressure— 

Once the pipeline repair work is completed, the measures prescribed in this 

plan have been satisfactorily completed, and approval is received from the Director of the PHMSA Eastern Region, Columbia Gas will follow the Return to 

Service plan provided in Attachment K, to safely return Line SM–80 to restricted operation for purposes of conducting an in-line inspection. Columbia 

Gas plans to return the pipeline pressure to no more than is necessary to efficiently and effectively conduct an in-line inspection on Line SM–80 between 

Lanham and Broad Run (not to exceed 600 psig). After successful completion 

of the necessary in-line inspections, Columbia Gas will isolate Line SM–80 from 

other sources of natural gas supply and reduce the pressure of the pipeline to 

below 300 psig until completing the remaining requirements of this Integrity 

Assurance Plan and PHMSA has granted the necessary approvals to restore full 

service to the pipeline. 

• The Return to Restricted Service Plan (Attachment K) requires step increases 

in pressure in quarter increments up to the temporary MAOP of 600 psig. Each 

quarter step will be followed by a 30 minute idle period. Following each 30 

minute idle period, an instrumented leak survey will be conducted over the entire pipeline using instrumented aerial patrol. In addition, an on-ground instrumented leakage patrol will be conducted for 300 feet upstream and downstream 

from the incident location. Any leaks discovered will be investigated and resolved before continuing the quarter step process. 24 hours after the fourth 

pressure increment is completed, another set of aerial and ground leak surveys 

will be conducted. Any leaks discovered will be investigated and resolved as 

soon as practical, but within 24 hours. 

• The Return to Restricted Service Plan will be initiated only during weather conditions conducive to ensure successful aerial leakage patrol of the pipeline (not 

during periods of high winds or severe weather). Should conditions change during implementation of the Return to Restricted Service Plan and aerial patrol 

can no longer be effectively conducted, the pressure on the pipeline will be lowVerDate Nov 24 2008 10:32 Jul 19, 2013 Jkt 075679 PO 00000 Frm 00065 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\81794.TXT JACKIE
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ered 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 inline inspection tools, and in no case above 600 psig. 

Preliminary Phase I Schedule 

The schedule for completion of tasks outlined in this Phase 1 plan is dependent 

upon many factors including receipt of environmental and other clearances, weather, availability of materials and other factors. A Gantt chart containing a preliminary schedule for the completion of each major item outlined in this plan is included 

in Attachment L. This schedule is based upon information known at this time and 

is subject to change as actions under this plan are carried out. 

Summary and Overview of Integrity Assurance Plan—Phase 2 

Upon completion of Phase 1 of the Integrity Assurance Plan, Line SM–80 will 

have been repaired at the rupture site and verified safe for a return to service at 

a temporary maximum allowable pressure not to exceed 600 psig for purpose of performing additional integrity assessment. Line SM–80 will have been made capable 

of passage of in-line inspection tools and additional work will have been completed 

to aid in the comprehensive integrity assessment of Line SM–80. 

Following the successful completion of Phase 1, Columbia Gas will seek approval 

from the Director of PHMSA Eastern Region for initiation of a Phase 2 plan. The 

Phase 2 plan will be documented and submitted for approval prior to initiation. Key 

elements of the Phase 2 plan will include: 

1. Continued support of the ongoing NTSB investigation and incorporation, as 

appropriate, of findings of the investigation into the Integrity Assurance Plan. 

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

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

4. The SM–80 pipeline from Lanham to near Broad Run will be prepared for the 

passage of instrumented in-line inspection tools by running cleaning pig(s) 

and a pig equipped with a gauge plate to further ensure that there are not 

restrictions for the in-line inspection tools. Columbia plans to conduct an inline inspection using Baker Hughes 20 inch high resolution magnetic flux 

leakage (MFL) and high resolution caliper ILI tools coupled with an inertial 

mapping unit along Line SM–80, from Lanham to Broad Run. 

5. After successful completion of the necessary in-line Inspections, Columbia will 

isolate Line SM–80 from other sources of natural gas supply and reduce the 

pressure of the pipeline to below 300 psig until such time as Columbia has 

completed the necessary steps under this Integrity Assurance plan and 

PHMSA has granted the necessary approvals to restore full pressure service 

to the pipeline. 

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

7. Performance of a close interval survey from Lanham to Broad Run of Lines 

SM–80, SM–86 and SM–86 Loop. 

8. Performance of a coating integrity survey and correction of any deficiencies 

in areas where the survey indicates potentially inadequate cathodic protection 

(i.e., where readings fail to meet the criteria of 49 CFR Part 192, Subpart I). 

9. Installation of a permanent launcher at the Lanham Compressor Station and 

permanent receiver at Broad Run on Line SM–80, to enable the passage of 

in-line inspection tools in the future. 

10. Establishment of a long term integrity assurance and reassessment plan for 

Line SM–80 for incorporation into the Columbia Gas Integrity Management 

Plan. 

11. Columbia Gas will contract with a qualified contractor to provide a 

geotechnical survey of Line SM–80 between Lanham Compressor Station and 

Broad Run to identify any areas of significant earth movement within the 

63 

pipeline right of way that could adversely impact the pipeline. Any such areas 

identified will be investigated and remediated, as necessary. 

Criteria—Assessment, Repair, Documentation, Request for Approval and 

Restoration of Full Service—Phase 3 

The following elements will be completed under Phase 3: 

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

2. Columbia Gas will maintain records of all work performed as part of the Integrity Assurance Plan and will prepare a complete package of information for 

presentation to the PHMSA Eastern Region, once the steps under Phase II 

have been completed. Based on successful completion of the Integrity Assurance measures, Columbia Gas will present this information and seek PHMSA 

Eastern Region approval to return Line 5M–80 to full and normal service. 

3. Line SM–80 will only be returned to normal service after all work has been 

successfully completed and approval has been granted by the Director of the 

PHMSA Eastern Region. 

Conclusion Criteria—Periodic and Summary Reporting and Documentation 

—Phase 4 

Columbia Gas will take steps to ensure that PHMSA is kept informed of progress 

during each phase of implementation of this plan, will provide summary reports and 

will maintain documentation and report certain expenditures associated with implementation of this plan as further detailed below: 

1. Monthly reports for Phase 1—Columbia Gas will submit monthly reports to the 

Director of the PHMSA Eastern Region that: (1) include all available data and 

results of the testing and evaluations required by the CAO; and (2) describe 

the progress of the repairs or other corrective and/or remedial actions undertaken. The first monthly report is due by the third of each month until Phase 

1 has been completed. The Director may adjust the reporting period upon written request of Columbia Gas. 

2. Quarterly Reports for Phase 2 Columbia Gas will submit quarterly reports to 

the Director of PHMSA Eastern Region that: (1) include all available data and 

results of the testing and evaluations required by the CAO; and (2) describe 

the progress of the repairs or other corrective and/or remedial actions being undertaken. The first calendar quarterly report is due once Phase I has been completed, as determined by the Director of the Eastern Region. There should be 

four quarterly report submissions while this order is still in effect. 

3. Summary Report for Phase II—Once Phase 2 has been completed, a composite 

summary of all work performed will be assembled and presented to the Director of the PHMSA Eastern Region. The Director will review the summary as 

part of the consideration for approval to return Line 5M–80 to normal service. 

4. Documentation—Columbia Gas will maintain documentation of the costs associated with the implementation of the CAO and will include in each monthly 

report submitted the to-date costs associated with: (1) preparation and revision 

of procedures, studies and analysis; (2) physical changes to the pipeline infrastructure, including repairs, replacements and other modifications; and (3) environmental remediation, if applicable. 

APPENDIX B 

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

SECRETARY LAHOOD PLEDGES SUPPORT TO EXPEDITE PIPELINE

MODERNIZATION PROJECT

Increased Safety, More Energy Capacity & Thousands of New Jobs 

PITTSBURGH, Pa.—U.S. Department of Transportation Secretary Ray LaHood 

today announced that the agency will lead the effort to help expedite Federal permitting for a 1,000 mile pipeline modernization project by NiSource, Inc. that will 

produce thousands of jobs, enhance safety and increase energy capacity. 

‘‘A year ago, I asked pipeline operators to take a hard look at their infrastructure 

and identify those sections of pipeline that need to be repaired, rehabilitated or replaced to ensure safer and more reliable delivery of energy resources,’’ said Secretary LaHood. ‘‘And we are happy to help NiSource speed up construction and reVerDate Nov 24 2008 10:32 Jul 19, 2013 Jkt 075679 PO 00000 Frm 00067 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\81794.TXT JACKIE
64 

place some of the oldest pipelines in the nation, ensuring good jobs and increased 

safety for people in Pittsburgh, as well as throughout Pennsylvania and the other 

states that will benefit from this project.’’ 

Secretary LaHood and PHMSA Administrator Cynthia Quarterman met with 

Pittsburgh Mayor Luke Ravenstahl and representatives from NiSource in Pittsburgh today to pledge their support in expediting the construction. NiSource, Inc. 

has announced it will modernize its Columbia Gas Transmission, LLC gas transmission and storage system by replacing aging infrastructure that serves communities in six states, including the Marcellus shale gas production region, where the 

majority of the pipeline infrastructure is more than 40 years old and running on 

inefficient platforms. 

Project Spans Six States 

This massive modernization project will take place in Kentucky, Maryland, Ohio, 

Pennsylvania, Virginia and West Virginia, and it will promote the safe and reliable 

delivery of energy resources across the Midwest, Mid-Atlantic and Northeastern regions of the United States. NiSource projects that the modernization project will: 

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

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

• Replace approximately 1,000 miles of large diameter pipeline using domesticmade steel. 

‘‘A modern pipeline infrastructure is crucial for the efficient and safe delivery of 

our nation’s resources, and this is exactly the kind of project that government 

should help facilitate,’’ said PHMSA Administrator Cynthia Quarterman. ‘‘We will 

help them work through the process, and make sure the project is constructed safely.’’ 

A year ago, Secretary LaHood issued a Call to Action to the nation’s pipeline operators, asking them to take a hard look at their infrastructure and identify pipelines 

that need to be repaired, requalifed or replaced to ensure safer and more reliable 

delivery of energy resources. This project is also in accordance with the President’s 

Executive Order to Improve Performance of Federal Permitting and Review of Infrastructure Projects. 

‘‘I commend Pennsylvania for making pipeline safety a priority by passing the Gas 

and Hazardous Liquids Pipeline Act,’’ said Secretary LaHood. ‘‘This is personal for 

all of us—none of us ever want to see another tragedy like the one that happened 

in Allentown.’’ 

DOT will coordinate with other government entities to identify opportunities to 

remove overlaps and expedite the regulatory and approval processes without sacrificing safety or lowering industry standards. 

About PHMSA 

There are more than 2.5 million miles of pipelines that deliver oil and gas to communities and businesses throughout the United States. PHMSA provides information and resources to the public to help them stay safe around pipelines through 

its Pipeline Safety Awareness website, State Pipeline Profiles and pipeline safety 

workshops for operators and emergency responders. PHMSA also urges the public 

to learn more about 811, a toll-free number that everyone should call before beginning any excavation project. 

The Pipeline and Hazardous Materials Safety Administration develops and enforces regulations for the safe, reliable, and environmentally sound operation of the 

Nation’s 2.5 million mile pipeline transportation system and the nearly 1 million 

daily shipments of hazardous materials by land, sea, and air. Please visit http:// 

phmsa.dot.gov for more information. 

65 

APPENDIX C 

142 FERC ¶ 61,062 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Before Commissioners: Jon Wellinghoff, Chairman; 

Philip D. Moeller, John R. Norris, 

Cheryl A. LaFleur, and Tony T. Clark. 

Columbia Gas Transmission, LLC Docket No. RP12–1021–000 

ORDER APPROVING CONTESTED SETTLEMENT 

(Issued January 24, 2013) 

1. On September 4, 2012, Columbia Gas Transmission, LLC (Columbia) filed with 

the Commission a Stipulation and Agreement of Settlement (Settlement) that represents a settlement of Columbia’s base rate levels and other issues related to the 

repair and maintenance of Columbia’s aging pipeline system. According to Columbia, the Settlement represents a collaborative resolution between Columbia and the 

vast majority of its shippers to address complex issues arising from recent and anticipated changes in pipeline safety requirements and the aging nature of Columbia’s system. As discussed below, we approve the contested Settlement on the basis 

that it provides an overall just and reasonable result. 

Background 

2. Columbia states that the Settlement arose from Columbia’s comprehensive 

evaluation of its interstate pipeline transmission facilities, which identified areas for 

rehabilitation or replacement in order to modernize its system, improve system integrity, and enhance service reliability and flexibility. According to Columbia, approximately 73 percent of the 12,000 miles of its system subject to the United States 

Department of Transportation’s (DOT) regulation was constructed before the enactment of Federal pipeline safety standards in 1970. In addition, Columbia states that 

its system contains approximately 1,272 miles of bare steel pipeline, which is at 

higher risk for corrosion and failure. According to Columbia, this is significantly 

more bare steel pipeline than any other interstate pipeline subject to DOT regulation. Columbia states that the majority of its system cannot accommodate in-line inspection and cleaning tools. 

3. Columbia also states that approximately 55 percent of its more than 300 compressor units were installed before 1970. Columbia states that it has 18 compressor 

facilities, with 57 compressor units, which must be available 100 percent of the time 

during the November to March winter period in order to ensure that Columbia can 

make all of its firm deliveries. 

4. Columbia states that its evaluation of its interstate facilities identified a number of specific rehabilitation and modernization projects that comprise its Modernization Program. Columbia states that pursuant to its Modernization Program, 

the pipeline will make significant capital expenditures over the next 10 to 15 years 

to modernize its interstate pipeline system infrastructure, and to enhance the system’s reliability, safety and regulatory compliance. These projects focus on replacing 

high pressure bare steel pipelines and pipelines with a history of failure in locations 

where there is the greatest risk that a pipeline failure would cause a disruption of 

service or threaten public safety. These projects also focus on modernizing compressor units along constrained mainlines serving a broad customer base. 

5. Columbia avers that the Settlement represents a fair and balanced resolution 

of numerous issues relating to Columbia’s base rate levels, the Modernization Program, and the recovery of revenue requirements associated with the Program. 

The Settlement 

6. Columbia’s September 4, 2012 Settlement generally provides for the following: 

• An annual $35 million rate reduction (retroactive to January 1, 2012), and an 

additional base rate reduction of $25 million each year beginning January 1, 

2014, both reductions to end on the effective date of Columbia’s next Natural 

Gas Act (NGA) section 4 general rate case, or a subsequent NGA section 5 rate 

adjustment. 

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

66 

1The 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. 2Section 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. 

• A rate moratorium through January 31, 2018 and an NGA section 4 general 

rate filing obligation no later than February 1, 2019. 

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

• A revenue sharing mechanism under which Columbia will refund to its customers 75 percent of any base rate revenues it collects over $750 million in any 

year after January 1, 2012. 

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

7. Pursuant to the Settlement, the CCRM would recover the costs (up to $300 million annually, subject to a 15 percent tolerance) associated with ‘‘Eligible Facilities’’ 

that have been placed in service and remain in service. The Settlement includes an 

initial five-year term for the CCRM (January 1, 2014 –January 1, 2019) to recover 

costs Columbia incurs during the 2013–2017 period as part of the Modernization 

Project. Appendix E to the Settlement identifies the specific eligible replacement 

and upgrade projects that Columbia intends to undertake each year between 2013 

and 2017, and the estimated costs of each project. Appendix E sets forth the location 

of each pipeline replacement and looping project and the number of miles of pipeline 

to be replaced or constructed in each project. Appendix E also identifies the location 

of each compressor unit to be replaced, the horse power of the replacement compressor unit, and which existing units will be converted to standby service. 

8. Section 7.2 of the Settlement requires Columbia to obtain the consensus of 75 

percent of the shippers paying the CCRM rate (determined by billing determinants) 

to add, remove or substitute Eligible Facility projects, or to modify an Eligible Facility. Columbia retains the discretion to unilaterally perform projects that it reasonably believes could lead to imminent unsafe conditions, including replacing bare 

steel pipeline, subject to the cost and scope limitations otherwise applicable to 

projects eligible for CCRM recovery. Columbia also agrees to a $100 million annual 

capital maintenance expenditure for transportation and storage projects that will 

not be recouped through the CCRM recovery mechanism, and to use any amounts 

less than $100 million spent in a given year as a reduction to plant investment. 

Storage and gathering projects are also specifically excluded from recovery as Eligible Facilities. 

9. The Settlement provides for Columbia to earn a return on the capital costs included in the CCRM through a total net rate base multiplier of 14 percent, made 

up of a pre-tax rate of return of 12 percent, and Taxes Other Than Income of 2 percent. Columbia will recalculate the CCRM on an annual basis. Further, Columbia 

states that, in order to provide rate stability and safeguard shippers against losses 

in billing determinants, the Settlement requires Columbia to calculate the annual 

per unit CCRM rate based on the greater of (1) actual annual billing determinants 

for all non-incremental rate customers adjusted for discounting 1 or (2) an agreedupon 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. 

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 

67 

3Those filing comments in support of the Settlement include Cabot Oil and Gas Corporation 

(Cabot), Exelon Corporation (Exelon), the NiSource Delivery Companies (including Columbia 

Gas of Maryland), New Jersey Natural Gas Company and NJR Energy Services Company 

(NJR), Waterville Gas and Oil Company, The Cities of Charlottesville and Richmond, Virginia 

(Virginia Cities), Interstate Gas Supply, Indicated Shippers, Duke Energy of Ohio and Duke Energy of Kentucky, Antero Resources Appalachian Corporation, and Chesapeake Energy Marketing, Inc. (Chesapeake). 4See, e.g., Comments of Cabot. 

expenses in the past year meet its Eligible Facilities Plan. The Settlement also provides that Columbia will remove its existing daily scheduling penalty provision from 

its tariff. 

11. The Settlement provides that Columbia will not propose any new cost tracking 

mechanism during the term of the Settlement. 

12. The Settlement states that Columbia will not propose market based rates for 

new storage projects during the term of the Settlement. 

13. The Settlement provides that it is not precedential and is being agreed to only 

in light of existing circumstances on Columbia’s system, particularly that approximately 50 percent of Columbia’s system was constructed prior to 1960 and approximately 55 percent of Columbia’s compressor units were installed prior to 1970. In 

addition, Columbia’s system contains approximately 1,272 miles of bare steel pipeline subject to DOT regulation, and the majority of the system cannot accommodate 

in-line inspection and cleaning tools. 

14. The Settlement also provides for the severance of the direct interests of Contesting Parties, and an option for Columbia to withdraw the settlement offer if there 

are contesting parties that represent 10 percent or more of total peak day transportation entitlements on the system. 

Comments on Settlement 

15. Numerous customers from all sectors of the industry filed in support of the 

Settlement.3 Those customers filing in support all note that given the unique circumstances of Columbia’s system, the Settlement represents a fair and balanced 

resolution that allows Columbia to make critical necessary modernization upgrades 

to its system while providing its customers with real and meaningful benefits in 

terms of both improved services and flexibility through the modernization efforts, 

and rate relief and predictability. The supporting customers note that Columbia’s 

system serves customers in eleven states and the District of Columbia and provides 

significant take away capacity for gas producers in the expanding Marcellus and 

Utica shale plays.4 The customers state that they will benefit from increased operational flexibility and reliability, as well increases in public safety, as a result of 

the Modernization Program. Those customers also specifically identify the Settlement’s significant base rate reduction, the retroactive decrease in base rates, the 

$50 million in refunds, the revenue sharing provision and the rate predictability resulting from the moratorium as key rate components underlying their support of the 

Settlement. Exelon, NiSource, the Virginia Cities, and others also note that by allowing Columbia to recover the costs associated with the necessary system upgrades 

through the CCRM, it can avoid successive rate case filings and the inherent financial costs and distractions of resources associated with protracted litigation. Chesapeake notes that customers also benefit through Columbia’s agreement to spend 

$100 million annually on maintenance, and the fact that the CCRM recovery mechanism is capped on both an annual and full program basis. It also approves of the 

fact that the CCRM proposal specifically identifies projects and provides shippers 

with the right to monitor and challenge Columbia’s expenditures. In sum, Columbia’s shippers support the Settlement because they find the CCRM to be a fair 

mechanism for Columbia to complete and recover the costs of needed system modernizations that will enable Columbia to maintain the integrity and reliability of its 

system and protect the public’s safety, while also providing the customers with immediate and concrete benefits in the form of rate reductions and predictability. 

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 

68 

5Maryland PSC Protest at 2 (citing Granite State Gas Transmission, Inc., 132 FERC ¶ 61,089 

(2010) (Granite State)). 6 18 C.F.R. § 284.10(c)(2) (2012). 

7Trailblazer Pipeline Co., 85 FERC ¶ 61,345, at 62,339 (1998), reh’g, 87 FERC ¶ 61,110 (1999), 

reh’g, 88 FERC ¶ 61,168 (1999) (Trailblazer) (citing Mobil Oil Corp. v. FERC, 417 U.S. 283, 314 

(1974)). 8 18 C.F.R. § 385.602(h)(1)(i) (2012). 

9Trailblazer, 85 FERC ¶ 61,345 at 62,342–3, explaining what that order described as the second of three approaches the Commission has used to approve contested settlements, without 

severing the contesting parties. 10Florida Gas Transmission Co., 105 FERC ¶ 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 ¶ 61,299 (2001); Granite State, 132 FERC ¶ 61,089 at P 11. 11Florida Gas, 105 FERC ¶ 61,171 at P 47. 

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. 

17. In its reply to the Maryland PSC’s protest, Columbia asserts that the Settlement represents a comprehensive package that enjoys the unanimous support of Columbia’s shippers, and that the CCRM and rate base multiplier challenged in the 

protest are two integral components of the indivisible Settlement. Columbia asserts 

that the Settlement includes numerous protections insisted on by its shippers to ensure that Columbia has the incentive to perform the modernization work efficiently 

and effectively, including specifically defining the Eligible Facilities for which costs 

may be recouped by the CCRM, and placing caps on the recoverable amounts so that 

Columbia is at risk for costs that fall outside the scope of the defined projects and 

for any costs that exceed the caps. Columbia further asserts that the Settlement 

contemplates significant shipper oversight through a requirement for annual meetings to review projects and costs for the past period and for the upcoming year. Columbia also states that the Settlement limits each annual rate filing to recovery of 

revenues related to Eligible Facilities that are placed in service between November 

1 and October 31 of the prior year. Columbia also claims that the Settlement is consistent with, and supported by, the Commission’s policy strongly supporting negotiated settlements as a means of providing regulatory certainty and administrative 

efficiencies for the Commission and the parties, by avoiding lengthy and costly rate 

proceedings. Finally, Columbia argues that the Commission should not allow the 

Maryland PSC’s protest to prevent Columbia’s shippers from realizing the substantial benefits afforded by the Settlement. 

Discussion 

18. In order to approve Columbia’s proposed Settlement over the objections of the 

Maryland PSC, the Commission must find that the settlement is just and reasonable.7 In determining whether to approve a contested settlement under that standard, section 385.602(h)(1)(i) 8 of the settlement rules permits the Commission to decide the merits of the contested issues, if the record contains substantial evidence 

on which to base a reasoned decision, or if the Commission determines there is no 

genuine issue of material fact. In addition, as the Commission held in Trailblazer, 

even if some individual aspects of a settlement may be problematic, the Commission 

still may approve a contested settlement as a package if the overall result of the 

settlement is just and reasonable.9

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 

69 

12 Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol, Order No. 436, FERC 

Stats. & Regs., Regulations Preambles 1982–1985 ¶ 30,665, at 31,534 (1985). 13 Id. at 31,537. 14See, e.g., Florida Gas Transmission Co., 109 FERC ¶ 61,320 (2004); Granite State Gas 

Transmission, Inc., 136 FERC ¶ 61,153 (2011). 15 CenterPoint Energy—Mississippi River Transmission, LLC, 140 FERC ¶ 61,253 (2012) 

(MRT). 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. 

between rate cases, but may retain any over-recovery. As the Commission explained 

in Order No. 436, this gives the pipeline an incentive both to (1) ‘‘minimize costs 

in order to provide services at the lowest reasonable costs consistent with reliable 

long-term service’’ 12 and (2) ‘‘provide the maximum amount of service to the public.’’ 13 Cost-trackers undercut these incentives by guaranteeing the pipeline a set 

revenue recovery. Thus, in accordance with this policy, in Florida Gas and Granite 

State, the Commission rejected proposals for safety cost trackers, with true-up 

mechanisms, made in NGA section 4 filings. The Commission has, however, permitted such a regulatory surcharge for pipeline safety costs in uncontested settlements.14

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. 

22. In this case, the Commission finds that the Settlement and the CCRM provide 

a reasonable means for Columbia to recover the substantial costs of addressing urgent public safety and reliability concerns, without undercutting Columbia’s incentives to operate efficiently and to maximize service to the extent that previously proposed and rejected surcharges would have done. As stated by Columbia, approximately half of its pipeline infrastructure regulated by the DOT is over fifty years 

old, approximately 55 percent of its compressors were installed before 1970 and 

there is limited horsepower back-up at many critical locations. In addition, the system contains approximately 1,272 miles of potentially dangerous bare steel pipeline, 

many of its control systems run on an obsolete platform and because the older part 

of the system was not designed to accommodate in-line inspection, Columbia will 

only be able to inspect approximately thirty-five percent of the DOT regulated portion of its system using modern in-line inspection tools. Our approval of the Settlement and the CCRM will facilitate Columbia’s ability to make the substantial capital investments necessary to correct these very significant problems and thus provide more reliable service while minimizing public safety concerns. 

23. We find that the CCRM surcharge proposed by Columbia includes numerous 

positive characteristics that distinguish the surcharge from those we have rejected 

previously, and that work to maintain the pipeline’s incentives for innovation and 

efficiency. First, the development of the CCRM began with Columbia and its shippers engaging in a collaborative effort to review Columbia’s current base rates, leading to Columbia’s agreement to reduce its base rates by $35 million retroactive to 

January 1, 2012, by another $25 million effective January 1, 2014, and to provide 

refunds to firm shippers of $50 million. Maryland PSC does not contest this aspect 

of the Settlement, which provides the shippers rate relief which could otherwise only 

be obtained pursuant to NGA section 5 and could not take effect in the retroactive 

manner provided by the Settlement. The Commission finds that these provisions of 

the Settlement assure that the base rates, to which the CCRM surcharge will be 

added, have been updated in a just and reasonable manner to reflect current circumstances on Columbia’s system. 

24. Second, the Settlement identifies, by pipeline segment and compressor station, 

the specific Eligible Facilities for which costs may be recovered through the CCRM, 

and the Settlement delineates and limits the amount of capital costs and expenses 

for each such project.16 The Settlement also limits Columbia’s ability to add or 

change projects. In addition, it is significant that Columbia agrees to continue making annual capital maintenance expenditures of $100 million for transportation and 

70 

17 By contrast, the surcharge mechanisms proposed in Florida Gas, Granite State, and MRT 

did not include a comparable billing determinant floor. 18See, 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 ¶ 61,004, at P 16 (2009); Duke Energy 

Trading and Marketing, L.L.C., et al., 125 FERC ¶ 61,345, at P 31 (2008). 19See Trailbazer, 85 FERC ¶ 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. 

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. 

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. 

26. Fourth, the CCRM would not be a permanent part of Columbia’s rates. The 

Settlement provides that the CCRM will terminate on January 1, 2019, unless the 

parties agree to extend it and the Commission approves the extension. Thus, subject 

to extension requiring the consent of all parties, the CCRM is meant to recover a 

set amount of costs over defined period, and will not become a permanent part of 

Columbia’s rates. 

27. Finally, the surcharge is broadly supported, or at least not opposed, by all Columbia’s customers. Based on all these factors, the Commission finds that Maryland 

PSC’s policy objections to the CCRM mechanism do not justify rejection of the Settlement. 

28. Maryland PSC’s only other contention in opposing the Settlement is its statement that an NGA general section 4 rate case in this instance would provide the 

opportunity to determine whether the 14 percent rate base multiplier, inclusive of 

a 12 percent pre-tax rate of return and taxes other than income taxes of 2 percent 

for eligible facilities is just and reasonable. Rule 602(f)(4) of the Commission’s regulations requires that, ‘‘any comment that contests a settlement by alleging a dispute 

as to a genuine issue of material fact must include an affidavit detailing any issue 

of material fact by specific reference.’’ Maryland PSC did not file any affidavit with 

its comments demonstrating an issue of fact concerning whether the rate base multiplier provides an unreasonable return. Thus, we cannot find that its protest raised 

a genuine issue of fact with respect to the return to be included in the CCRM surcharge.18

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. 

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 

71 

case by February 2019, (4) the removal of Columbia’s existing daily scheduling penalty, thus providing shippers greater flexibility to modify their daily takes to respond to unexpected changes in their need for gas without incurring additional 

costs, and (5) Columbia’s agreement not to propose market-based rates for new storage projects during the term of the Settlement or to propose any additional cost 

tracking mechanisms. 

31. The Commission finds that the very substantial benefits that will inure to Columbia’s shippers through the Settlement outweigh the inclusion of an otherwise 

disfavored surcharge, particularly given the customer protections inherent in the 

CCRM. The Settlement is crafted to address undisputed circumstances on Columbia’s system, namely that the system is aging and that Columbia needs to make significant upgrades and repairs to modernize the system and to ensure that it will 

be able to continue to provide reliable firm transportation service, consistent with 

public safety. The Commission concludes that the benefits of the Settlement render 

the overall Settlement package just and reasonable. 

32. As we have stated repeatedly, the Commission favors collaborative efforts and 

settlements between pipelines and their shippers regarding rate and other contested 

issues, as such negotiated agreements conserve the Commission’s time and resources. The instant Settlement is the result of an extensive and comprehensive effort on behalf of Columbia and its customers to review the pipeline’s existing rates, 

to evaluate imminent issues with regard to the aging system, and to develop a plan 

to address and pay for the costs of modernizing that system. The Commission notes 

that the procedures undertaken by the pipeline and its customers are precisely the 

kind of pro-active discussions and communications between customers and the pipelines that the Commission has repeatedly encouraged, and we commend the parties 

for their efforts in reaching this agreement. 

The Commission orders: 

The Settlement is hereby approved as discussed in the body of this order. 

By the Commission. Chairman Wellinghoff is concurring with a separate statement attached. 

(S E A L) 

KIMBERLY D. BOSE, 

Secretary. 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Columbia Gas Transmission Corporation Docket No. RP12–1021–000 

(Issued January 24, 2013) 

WELLINGHOFF, Chairman, concurring: 

I share the concerns about cost tracking mechanisms expressed in this proceeding 

by the Public Service Commission of Maryland. Cost tracking mechanisms reduce 

a pipeline’s incentive for innovation, efficiency and cost minimization, and shift the 

risk embedded in the return on equity from the pipeline to the shippers. 

I am voting to approve the instant settlement because Columbia’s shippers have 

negotiated significant limits to this cost tracking mechanism that mitigate my concerns. In particular, the cost tracking mechanism is limited to specifically identified 

projects, establishes a billing determinant floor at maximum tariff rates, and is not 

permanent part of Colwnbia’s rates. Further, Columbia agrees that it will not propose any new cost tracking mechanism nor market based rates during the term of 

the settlement. In addition, there are other significant consumer benefits to approving the settlement. The settlement provides for $50 million in refunds, an annual 

$35 million rate reduction (retroactive to January 1, 2012), and an additional base 

rate reduction of $25 million each year beginning January 1, 2014. 

For these reasons, I am voting to approve the settlement. However, I encourage 

shippers of pipelines seeking to implement a cost tracking mechanism to consider 

additional limits to protect consumers. For example, I believe that it also would be 

appropriate for a pipeline to credit shippers all revenues from services provided over 

the facilities at issue that were not included in the rate design billing determinants 

and to explore a reduction in the return on equity that applies to those facilities. 

JON WELLINGHOFF, 

Chairman. 

The CHAIRMAN. Thank you. You answered my first one. 

72 

Mr. Kessler? 

STATEMENT OF RICK KESSLER, PRESIDENT, 

PIPELINE SAFETY TRUST 

Mr. KESSLER. Thank you, Mr. Chairman and Senator Manchin. 

Good afternoon to the members of the Committee and the public. 

I want to thank you for inviting me back to testify before the Committee again. My name is Rick Kessler, and I am here in my wholly voluntary and uncompensated role as the president of the Pipeline Safety Trust. 

And for years after each new tragedy we’ve been invited to testify about what’s needed to prevent the next tragedy. Unfortunately, we’re back again after the recent failure of the pipeline and 

the incident in Sissonville. The failure comes all too soon after a 

spate of incidents in California, Michigan, Pennsylvania, Montana, 

and Utah among many other places. Many of these failures had 

common threads and common solutions that could have prevented 

or at least minimized their impacts. 

The Trust and I were very happy to work with you, Mr. Chairman, your colleague Senator Boxer and my former bosses, Senator 

Lautenberg and Congressman Dingell, to enact the 2011 Pipeline 

Safety Act. And that began to move regulators and industry in the 

right direction on some of these issues. But the speed of review, 

rulemaking, and implementation of the needed changes was and 

continues to be painfully slow and certainly not fast enough to have 

avoided the tragedy in Sissonville. 

Now, we’ve provided a great deal of testimony in the past on how 

we think we could improve pipeline safety in this country. I’m 

going to try and highlight some of the more pertinent issues to the 

re—things that are pertinent to the recent Sissonville failure and 

explosion. 

But since a lot of this information is still coming forward I don’t 

want to judge too much because that would be unfair and premature. But I will say one of the critical issues related to any type 

of pipeline rupture is how quickly the pipeline operator, as you’ve 

pointed out, can identify the rupture has occurred and act to shut 

it down to minimize any further effects of the pipeline failure. 

In a perfect world built-in leak detection systems would alert a 

pipeline controller to the drop in pressure and allow for the 

quickest response to shut down the pipeline. Unfortunately as the 

recent PHMSA leak detection report shows less than 50 percent of 

major failures such as in Sissonville are initially identified by current leak detection technologies. We really need to do better. I 

think you know that, and I think everyone here knows that. 

Now once a failure is identified the pipeline operator still needs 

to be able to shut down the valves on either side of the failure site 

so that the natural gas boring into the community and subsequent 

fire is minimized. In the case of where natural gas ignites, such as 

in Sissonville, the closure of these valves is what we call a blowtorch effect on the neighborhood and allow emergency responders 

to get in there and take care of the people. 

Now, the final report on remote control and on automated valves 

that PHMSA recently provided this committee concludes that a 

cost effective strategy for reducing the consequences of natural gas 

73 

pipeline failures is automated valves that can be closed within 10 

minutes of failure. 

Now, I got to tell you, I’ve been working on this particular matter 

for upwards of 17 years as a staffer handling the authorization of 

Federal law after a very similar incident in Edison, New Jersey 

back in 1994, which you may remember. Same thing. Fortunately 

no one was killed, but a huge fireball and it took about 3 hours to 

shut down the line mainly because it was manual and just the 

mere act of turning the wheel took about an hour or more. 

Now, we agree with NTSB that such valves should require the 

automatic or remote shutoff valves, and there is a difference. Yet 

the Pipeline Safety Bill that we all worked on fell short of this requirement on existing pipelines in Sissonville and San Bruno. 

No doubt, Mr. Chairman, you opened your car this morning 

using a remote control. We use remote controls to turn off and on 

our TVs, to do all sorts of things, our garage doors, for instance. 

Yet somehow we find it acceptable that an industry can use 1960s 

technology in 2013 to close its valves. For industry, unfortunately 

we’ve seen far more stall than install of these technologies. 

It’s unclear to us whether Sissonville failure was in an area 

where the company would have been required to do an integrity 

management plan. Only a small fraction of areas fall under these 

requirements. As we’ve testified before, these integrity management requirements must be expanded to cover all pipelines. And 

yet while we support integrity management, these programs are 

often fairly weak and need to be more much effective and easier 

to evaluate. 

Some of the issues that must be addressed include creating a 

clear way for regulators to establish whether a company is basing 

the risk assessments on valid records, minimizing direct assessment as an inspection tool, and ensuring that when direct assessment is used as opposed to, say, inline inspection, the techniques 

are adequate and being used correctly. 

We also must determine whether repair criteria within these programs undermine safety factors based on faulty assumptions and 

therefore are not addressing or perhaps exacerbating the problem. 

To summarize, the state of West Virginia, like surrounding 

states, has seen a dramatic increase in the development of natural 

gas resources and relating pipe—related pump lines. Speaking for 

myself alone, I actually think this is a good thing for our economy, 

for the nation, for energy security. But this boom in drilling has 

also led to the construction of more and more pipelines and facilities across the area and more and more particularly gathering 

lines, which you mentioned earlier which can be, as you said and 

the Administrator said, the same size as transmission pipelines, 

the same pressure as transmission pipelines. Unfortunately these 

lines are completely unregulated by the Federal Government. We 

agree with the Administrator that the Federal Government should 

have authority to regulate these lines. 

Finally, we believe that PHMSA is critical of the pipeline safety 

but not as effective a regulator as it should be. Certainly PHMSA 

can and must do more to regulate better regardless of budget. 

There is no excuse for continuing decades. It’s not necessarily on 

this administration or the last, but it’s been decades of neglect of 

74 

this agency. However, we agree that PHMSA also suffers from a 

very serious lack of financial and personnel resources. This is particularly dangerous and shortsighted at a time when shale resources are feeding the rapid growth of pipeline mileage across the 

country. 

For that reason we support PHMSA’s 2013 budget request which 

would provide significant and additional funding to support critical 

increases in inspectors and program development. It’s good for the 

industry, the consumer, and the Nation because we need the public 

to have confidence in the safety of the system to ensure smooth 

growth and access to gas and oil from shale plays around the Nation. 

Thank you again for the opportunity to testify today. And I stand 

ready to answer any questions and continue to work with you, and 

you, Senator Manchin, and the rest of the Congress to move safety 

forward. Thank you. 

[The prepared statement of Mr. Kessler follows:] 

PREPARED STATEMENT OF ERIC KESSLER, PRESIDENT, PIPELINE SAFETY TRUST

Good morning, Chairman Rockefeller and members of the Committee. Thank you 

for inviting me to speak today on the important subject of pipeline safety. My name 

is Rick Kessler and I am testifying today in my purely voluntary, uncompensated 

role as the President of the Pipeline Safety Trust. My involvement and experience 

with pipeline safety stems from my years as one of the primary staff members on 

such issues in the House of Representatives and my subsequent work with the Pipeline Safety Trust. 

The Pipeline Safety Trust came into being after a pipeline disaster over thirteen 

years ago—the 1999 Olympic Pipeline tragedy in Bellingham, Washington that left 

three young people dead, wiped out every living thing in a beautiful salmon stream, 

and caused millions of dollars of economic disruption. While prosecuting that incident the U.S. Justice Department was so aghast at the way the pipeline company 

had operated and maintained its pipeline, and equally aghast at the lack of oversight from Federal regulators, that the Department asked the Federal courts to set 

aside money from the settlement of that case to create the Pipeline Safety Trust 

as an independent national watchdog organization over both the industry and the 

regulators. We have worked hard to fulfill that vision ever since, but with continuing major failures of pipelines, such as the one in Sissonville, West Virginia that 

brings us here today, we question whether our message is being heard. 

Born from a tragedy in Bellingham, but also riding on the facts and emotion of 

other tragedies in places like Edison, New Jersey; Carlsbad, New Mexico; Walnut 

Creek, California and Carmichael, Mississippi, we have testified to Congress for 

years about the improvements needed in Federal regulations to help prevent more 

such tragedies. For years we have talked about the need for more miles of pipelines 

to be inspected by smart pigs. We have pleaded for clear standards for leak detection, requirements for the placement of automated shut off valves, closing the loopholes that allow a growing mileage of pipelines to remain unregulated, and for better information to be available so innocent people will know if they live near a large 

pipeline and whether that pipeline is maintained and inspected in a way to ensure 

their safety. 

So here we are again after the very recent failure of a pipeline in Sissonville 

which completely destroyed three homes, damaged other homes, caused extensive 

damage to an interstate highway, and once again terrorized a community. This recent failure falls too soon after a spate of significant failures over the past few years 

in Michigan, California, Pennsylvania, Montana, and Utah. Many of these failures 

had common themes and common solutions that could have prevented or at least 

minimized their impacts. We have been asking for action on these issues in previous 

hearings following previous tragedies for years now. Last year, Congress passed the 

Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, which began 

to move the regulators and the pipeline industry in the right direction on some of 

these issues, but the speed of review, rule making, implementation and enforcement 

of the needed changes was not sufficient to prevent the tragedy in Sissonville. It 

75 

is our sincere desire not to be back in front of this committee again in the future 

saying the same things after yet another tragedy. 

The vision of the Pipeline Safety Trust is simple. We believe that communities 

should feel safe when pipelines run through them, and trust that their government 

is proactively working to prevent pipeline hazards. We believe that local communities who have the most to lose if a pipeline fails should be included in discussions 

of how best to prevent pipeline failures. And we believe that only when trusted partnerships between pipeline companies, government, communities, and safety advocates are formed, will pipelines truly be safer. 

Clearly trust in pipeline safety has now been lost in the community around 

Sissonville, so add those people to people in Michigan, California, Pennsylvania, 

Montana, Utah and elsewhere, where people now question whether the industry, 

regulators and legislators are really doing all they can to keep people and the environment safe. 

In my testimony today I will focus on areas that are pertinent to natural gas 

transmission pipelines like the one that failed in Sissonville. Since much of the pertinent information about the Sissonville failure, such as whether or not it had been 

previously inspected, what type of inspection was used, whether the failure site was 

within a high consequence designation, and the type of valves upstream and downstream of the rupture site, has not yet been released, specific conclusions related 

to this failure would be premature. I will also review areas addressed by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, and needed safety 

areas that bill failed to address. These are the issues I would like to speak to today: 

• Response times to pipeline ruptures 

• Expanding and clarifying integrity management requirements 

• Inadequate Federal and state resources 

• Non-regulated and under-regulated Gathering Lines 

• Poor facility response planning (hazardous liquids) 

• Lack of clear jurisdiction for new pipeline approval and routing decisions 

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

• Quantifying natural gas leak significance 

• Depth of cover at river crossings 

• Diluted bitumen study constraints 

Response times to pipeline ruptures—One of the critical issues related to any type 

of pipeline rupture is how quickly the pipeline operator can identify that a rupture 

has occurred and then act to shut the pipeline down to minimize any further effects 

of the pipeline failure. In a perfect world, built in leak/rupture detection systems 

would alert a pipeline controller of a rupture immediately and allow for the quickest 

response to shut down the pipeline. Unfortunately, as the final report—Leak Detection Study—DTPH56–11–D–000001, which was recently provided to this Committee 

by PHMSA shows, for all leaks on natural gas transmission pipelines less than 16 

percent are initially identified by the current leak detection systems. Even for the 

larger major releases that should be more easily identified with such systems less 

than 50 percent of these failures are initially identified by current leak detection 

systems. What this means is that someone other than the pipeline controller, such 

as local residents or emergency response personnel, or field employees with the 

pipeline company are the ones that initially identify the pipeline failure, and precious time is then lost as this failure identification is then relayed to the control 

room. 

Once a failure has been identified, the pipeline operator still needs to be able to 

shut down the valves on either side of the failure site so the natural gas roaring 

into the local community is minimized as much as possible. In the case where the 

natural gas ignites, such as in Sissonville, the closure of these valves is what can 

halt the blowtorch effect on the neighborhood and allow emergency responders to 

access the area to do their jobs. The types of valves in these critical locations, and 

how far apart they are spaced, play an important role in how quickly the fuel will 

stop flowing into the community. The final report on automated valves—Studies for 

the Requirements of Automatic and Remotely Controlled Shutoff Valves on Hazardous Liquids and Natural Gas Pipelines with Respect to Public and Environmental Safety—that PHMSA recently provided this Committee provides the following cost effective strategy for reducing the consequences of natural gas pipeline 

failures such as occurred in Sissonville. 

‘‘For natural gas pipelines, adding automatic closure capability to block valves 

in newly constructed or fully replaced pipeline facilities may be a cost effective 

76 

1 NTSB recommendation P–11–011, 9/26/2011. 

2 Interstate Natural Gas Association of America, 11/2/11, comments on ANPRM for Safety of 

Gas Transmission Pipelines, Docket# PHMSA–2011–0023. 

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. 

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

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. 

77 

3 NTSB recommendations P–11–014 & P–11–017, 9/26/2011. 

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

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 

78 

4 U.S. Department of Transportation, Budget Estimates, Fiscal Year 2013 http://phmsa 

.dot.gov/staticfiles/PHMSA/DownloadableFiles/FY%202013%20PHMSA%20BUDGET.pdf. 5GAO, Collecting Data and Sharing Information on Federally Unregulated Gathering Pipelines Could Help Enhance Safety, Report #GAO–12–388, March 2012. 6 NTSB recommendations P–12–001, P–12–002, P–12–009, P–12–010, 7/25/2012. 

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. 

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. 

For the most part the 20,000 miles of gathering lines that do fall under PHMSA 

regulations are the gathering lines that lie within more populated areas. Again 

many of these ‘‘regulated’’ gathering lines in these populated areas are the same 

size and pressure as the transmission pipelines that failed in San Bruno and 

Sissonville, yet are not afforded equal level of pipeline safety protection. For example a transmission pipeline running through a town would be required to undertake 

the important integrity management inspections to help ensure its safety, yet a 

gathering line that has the exact same risk profile running through that same town 

is currently not required to ever undertake any form of the important integrity management inspection and risk analysis. 

While the development of various natural gas shale plays around the Nation has 

arguably been a boon to our energy supplies and economy, because of this serious 

loophole in the pipeline regulations it has also increased the risk to thousands of 

people in these same areas. This is a loophole that needs to be closed as soon as 

possible before we have to gather for another hearing after a tragedy along one of 

these under-regulated or completely unregulated gathering pipelines. 

Similarly, there are numerous unregulated hazardous liquid gathering lines with 

characteristics similar to regulated hazardous liquid lines. PHMSA needs to adequately regulate these gathering lines. Congress should consider elimination of the 

term ‘‘gathering’’ line for hazardous liquids. Doing so would ensure that all oil gathering lines are regulated, as the State of Alaska has done for its oil pipelines. 

Poor facility response planning (hazardous liquids)—The NTSB in its report on 

the Marshall, Michigan spill of nearly a million gallons of oil into the Kalamazoo 

River made numerous recommendations targeted at improving facility response 

planning for hazardous liquid pipelines.6 We support all of the NTSB recommendations and hope they will be acted upon as quickly as possible. As we have testified 

to this committee previously, the review and adoption of such response plans is a 

process that does not include the public. In fact PHMSA has argued that it is not 

required to follow any public processes, such as those under the National Environmental Policy Act, for the review of these plans. If the Enbridge pipeline spill in 

Marshall, Michigan and the BP Gulf tragedy have taught us nothing else it should 

have taught us that the industry and agencies could use all the help they can get 

to ensure such response plans will work in the case of a real emergency. 

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 

79 

7Washington Administrative Code 173–182–640. 

are submitted for approval the plans are required to be made publicly available, interested parties are notified, and there is a 30 day period for interested parties to 

comment on the contents of the proposed plan.7 We urge Congress to require 

PHMSA to develop similar requirements for review and approval of spill response 

plans across the country, and that PHMSA’s review and approval of facility response plans for new pipelines be an integral part of any environmental reviews required as part of the pipeline siting process. 

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 

80 

8 Robert W. Howarth · Renee Santoro ·Anthony Ingraffea, 2011, Methane and 

the greenhouse-gas footprint of natural gas from shale formations—http://www.psehealthy 

energy.org/data/HowarthlClimaticlChangelShalelMethane1.pdf. 9Pipeline & 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. 10Wall Street Journal, Floods Put Pipelines At Risk, Jack Nicas, December 2, 2012. 

be added to the survey to provide a measurable metric of how well pipeline companies are doing to address these potential problems. 

While the Pipeline Safety Trust’s main concern is the replacement of these types 

of problematic pipes for safety reasons, we also realize that paying for these replacement programs is a complicated equation. Many of the companies that have these 

pipes operate as regulated monopolies with a guaranteed rate of return, so the success of replacement programs often also lies with how state utility commissions approve rates for these replacement programs. We certainly support companies getting 

a fair return on safety investments, but the mechanisms to provide that return have 

to be carefully crafted to ensure the ratepayers are not paying for more than their 

fair share or for replacing things just to increase the rate of return with no real 

safety benefit. 

Quantifying natural gas leak significance—With recent failures and deaths from 

leaking natural gas distribution systems the public has come to question the safety 

of the very common small leaks, which both regulators and industry acknowledge. 

New technology has also been developed that allows a person to drive through a 

neighborhood and see these small leaks all around. Recent information estimates 

that between 1.4 percent to 3.6 percent of all natural gas could be lost during transport, storage and distribution.8 A 2009 article in the Pipeline & Gas Journal 9 regarding just the cast iron pipe portion of the pipeline network stated: 

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: 

‘‘The U.S. Geological Survey found severe scour last year at 27 sites surveyed 

along the Missouri River from Kansas City to St. Louis, with the riverbed deepened in places by nine to 41 feet. Other unpublished USGS research found more 

severe scouring upstream. 

Of the 55 oil and gas pipelines that cross the Missouri—which runs 2,300 miles 

from Montana to St. Louis—at least 24 have sections that lie 10 feet or less 

beneath the riverbed, within the range of scour observed on the river, according 

to Federal records obtained via a Freedom of Information Act request. During 

recent inspections, operators discovered at least two of those pipes, in Platte 

County, Mo. and near Boonville, Mo., were exposed but didn’t break. 

81 

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

PHMSA already has a rulemaking in progress where they could address these 

findings. It is our hope that PHMSA in its rulemaking will develop clear standards 

that required companies, when geologically feasible, to use horizontal directional 

drilling (HDD) to place these pipelines at a depth under such river crossings to 

avoid future failures. 

Depth of cover is not only an issue at such river crossings. Every year pipelines 

are struck and damaged, often leading to serious consequences, because of a lack 

of sufficient cover. Federal regulations require that hazardous liquid and gas transmission lines ‘‘must be installed with a minimum cover,’’ but the regulations do not 

require that that level of cover be maintained. In some parts of the country normal 

erosion has led some pipelines to be at very shallow depth or even exposed, making 

them an easy target for plowing and various forms of excavation. While certainly 

excavators have a responsibility to call before they dig near such pipelines, the current depth of cover regulations need to be analyzed to determine if a change is warranted. An additional benefit of extending integrity management principles to more 

rural areas is that the assessment of foreseeable risks of third party damage to 

pipelines in agricultural areas from lack of cover will be made a necessary component of an adequate risk assessment by the operators, requiring them to undertake 

mitigative and preventative actions. 

Diluted bitumen study constraints—Section 28 of the Pipeline Safety, Regulatory 

Certainty, and Job Creation Act of 2011 requires the Secretary to ‘‘complete a comprehensive review of hazardous liquid pipeline facility regulations to determine 

whether the regulations are sufficient to regulate pipeline facilities used for the 

transportation of diluted bitumen.’’ PHMSA has contracted with the National Academy of Sciences for that review, which is due out next summer. Because of the high 

profile nature of the Keystone Pipeline proposed to carry this diluted bitumen, many 

people are already voicing concerns about the industry membership in the NAS review committee, as well as the fact that it appears the committee will not be doing 

any new research, just relying on existing information, a majority of which comes 

from industry. 

The 2010 Enbridge spill of diluted bitumen into the Kalamazoo River in Michigan 

made clear that when diluted bitumen gets out of a pipeline it presents a difficult 

challenge to clean up because so much of it is prone to sinking. We had hoped that 

the diluted bitumen study that Congress required would be broad enough to also 

answer questions about the need for greater cleanup preparedness and technologies 

along pipelines that carry this unique material, but PHMSA’s contract with NAS 

does not cover these problems. For these reasons we hope that Congress will pay 

careful attention when the report is released next summer, and ensure follow up 

of any questions left unanswered. 

Thank you again for this opportunity to testify today. The Pipeline Safety Trust 

hopes you will closely consider the ideas and concerns we have raised today. If you 

have any questions about our testimony, the Trust would be pleased to answer them 

and, of course, we stand ready to work with you and your colleagues on improving 

this country’s pipeline safety laws that are so important to ensuring the well-being 

of millions of Americans and the healthy environment that is their birthright. 

The CHAIRMAN. Thank you, sir, very much. 

Mr. Staton, I’m going to put you through a little exercise for my 

education, for all of our education. I want to hit on a few topics 

similar to what we discussed in the first panel. Whenever there is 

a pipeline incident, discussion of the affected operator’s response 

surely follows, was it timely, was it not? 

So let me just ask you this: How is your control room made 

aware when an incident occurs, one? Can you walk me through 

your company’s process for responding to an incident? Does your 

company have performance metrics for response times to incidents? 

And how could industry improve response time? 

Mr. STATON. The initiation of an event within our control center 

is indicated to one of the control room operators who are very well 

82 

trained at understanding the implications on our system in what 

we call—we refer to as an alert. 

Specifically on the SM–80 pipeline, we have three pipelines there 

that operate effectively as a common system, and those have been 

referred to earlier today. So we received—when we received it— 

when we saw pressure drop on all three of those pipelines, we immediately saw three alerts, one for each pipeline. 

Two minutes later, which is not—by the way, it’s not an absolutely uncommon occurrence on a pipeline. There are fluctuations 

in pressure from time to time. And so that initial alert indicated 

that there had been a pressure drop. We then subsequently received three additional alerts, one on each of those three pipelines 

2 minutes later indicating that pressure was declining again. 

That happened one more time and then our team in the control 

center began to react. At about that time, a few minutes after that, 

we received a call from the folks at Cabot that one of their technicians had identified a specific location. So now we had confirmation 

in the control center that indeed what we were seeing in our control system had—something had happened and there had been an 

incident. And we began to deploy our resources with the folks calling out to the field and alerting emergency responders, ultimately 

also alerting the National Response Center. 

And so we deployed our folks. Our folks went to the locations in 

order to close the valves at the two locations. Those locations were 

about seven miles apart. One was at Lanham. One was downstream of Lanham. And then our operators began the process of 

closing and isolating that pipeline system. 

The CHAIRMAN. Had you not received a phone call from Cabot, 

what would have been the result? 

Mr. STATON. Had we not received that immediate phone call 

from Cabot there were also calls being made to local 911 folks because of the incident. We would have been able —and we would 

have deployed our folks on both ends of the system toward the particular incident. 

The CHAIRMAN. All right. Now, I asked you for a bit more. The 

process by which you make decisions, you’ve described to me the 

first part, the company’s process for responding. Does your company have performance metrics for response, et cetera? 

Mr. STATON. We—I’m sorry. Our intent, we have over the last 

several years been continuing to improve our processes across the 

industry and here at Columbia. We have redeployed people on 

our—in our organization. Well, let me take a step back. 

First, we have deployed in areas where we are comfortable the 

operations can utilize automated shutoff valves. We have deployed 

those. Along our system where, particularly in Appalachian, where 

our system is very integrated. It’s an integrated set of network 

pipelines with a lot of inputs coming into a system and a lot outputs that create—that can create some additional pressure implications. 

We have deployed people closer to the valve settings so that we 

can assure that we can close off valves and reduce the time-frame 

of an incident down to 1 hour. 

The CHAIRMAN. Any—that would be it? Do you have the appropriate—it was mentioned there were four people in the response 

83 

station. Does that—is that fairly regular or does that depend upon 

the time of day or whatever? 

Mr. STATON. At different locations on the system it varies. At our 

Lanham station we have folks onsite. We do have some unmanned 

locations. And we ensure that we have the appropriate response 

personnel close enough to be able to respond in the event that 

those valves need to be actuated. 

The CHAIRMAN. OK. If there’s any comments from any of the second panel, I’d welcome them. 

Mr. Staton, as you know, we included a requirement for remote 

controlled automatic shutoff valves on new or reconstructed pipelines in last year’s law. So that’s law. As we all know, the line that 

ruptured in Sissonville was equipped with a manual shutoff valve 

that required onsite attention, as you indicated was probably hard 

to do, physically hard to do. Although this requirement has not yet 

been made final, do you plan to install one of these valves on the 

Sissonville line once it is reconstructed? 

Mr. STATON. Our first priority in any circumstance is to prevent 

an incident like this from happening, and that our primary—— 

The CHAIRMAN. I missed that. I’m sorry. 

Mr. STATON. Is to prevent an event, an incident like this from 

ever happening on our system, and that is to—to learn more, continue to learn more about our system and to install the right technologies at the right times. With regard to ASVs in new areas, obviously we’re going to comply with whatever the requirements are. 

As we look at our SM–80 line, it is one of those integrated lines 

that I was talking about. And we are—it’s a challenge for companies like ours to install automated shutoff valves on those types of 

systems because they can create inadvertent affects. And we 

want—we obviously want to avoid that. 

Having said that, it is our plan as we learn more and finalize our 

analysis of bringing SM—the line SM–80 back into service along 

with support from PHMSA. We will consider putting automatic or 

remote controlled valves in place on line SM–80. 

I would also indicate that our current modernization program 

that we are undertaking, it’s about a $5 billion program to modernize our pipeline system across all of our pipeline system. Our intent is to expand the use of automated and remote control valves. 

The CHAIRMAN. Let me ask one which is not strictly in our arena 

today but which is much on my mind. In a hearing we had a year 

ago in Clarksburg, there was talk that you’re building a platform 

you need to have a lot of water and sometimes you get 80,000 

pound trucks. 80,000 pound trucks and the average rural bridges 

that I have crossed in Pocahontas County and every other county 

in the state don’t necessarily love each other. There’s bound to be 

a problem, especially when they’re one-way bridges. 

But there was also talk of the fact that those who drove those 

trucks, and this haunts me, since they know they’re going on to another job as soon as this platform is built, that they don’t appear 

to respect neighbors, and this testimony came from the sheriff, and 

granted he wasn’t running for office again so maybe he felt more 

free speak, but therefore I think he was saying what he really felt. 

Now that was a cynical comment, wasn’t it? 

84 

That they tend to just go on a rampage. They just get to where 

they have to go as fast as they can get there and turn around and 

get back and there’s sort of no real response or interest in the people whose land they’re traversing. Do you have any comment? 

Mr. STATON. Specifically on—I mean, we obviously did not feel 

that way about the folks that we serve, and we value the property. 

We value, more importantly, the life of everyone along our pipeline 

system. And that’s why we’re making and continuing to make the 

types of investments to ensure that we don’t have instances like 

this and that we can create one of the strongest infrastructures in 

this industry. And so I don’t—I don’t think that I see anything like 

that. 

The CHAIRMAN. I’m not talking about you. 

Mr. STATON. With regard to our industry, is that—is there— 

maybe there will be instances where folks are moving on too quickly to other activities. I would imagine there are opportunities 

where you can be distracted by the next job or the next responsibility. And—but I think, again, we have to make the appropriate 

investments in our infrastructure, period, whether it be roads, 

pipeline systems, bridges across the entirety of the country. 

The CHAIRMAN. Understood. As Senator Manchin and I discovered after the Sago mine disaster, there are large mines and there 

are small mines. There are large pipeline companies. There are 

small pipeline companies. And it would appear to me that there 

needs to be a certain level of largeness in order to afford to do business safely. And I’m not sure where that is or how that question 

can be answered, but could you reflect on that? And does INGAA 

discuss this? 

Mr. STATON. There are organizations that are focused on bringing together parts of the—parts of this industry that are relatively 

small that in and of themselves may not be able to address all of 

the issues that larger pipelines like ours would be able to address. 

And I think those organizations enable the coming together of that 

portion of the industry to address infrastructure types of issues. 

I think we’ve seen a fair amount of consolidation across this industry. And I believe that the capital and the capability to make 

the investments to operate safely, effectively, efficiently, those capabilities are there to operate effectively. And we intend to make 

those investments to be one of those—one of the safest pipeline operators in the country. 

The CHAIRMAN. So there’s actually an argument for consolidations in certain circumstances so as to be able to afford the equipment and the precision materials that you have to have. 

Mr. STATON. I think across many levels of infrastructure there is 

a significant amount of investment that needs to be made. And in 

bringing the appropriate financial wherewith all to the table to accomplish that, I think, is a very important part of the overall process. And I do think that’s why we’ve seen some consolidation and 

probably will see additional consolidation going forward. 

The CHAIRMAN. OK, good. 

Mr. Kessler, should there be a blanket requirement for these 

types of valves to be installed on all existing gas transmission that 

would be automatic? 

85 

Mr. KESSLER. Well, I don’t know if I want to say it should be 

blanket. It should certainly be reason. But there should be a requirement for installation on existing lines. I continue to hear, and 

I’ve heard this since 1994 when I started, the concerns about the 

technology on remote valves. 

And it’s really starting to ring a bit hollow after these many 

years particularly when, say, the U.S. Government entrusts some 

of its most sensitive military operations to remotely controlled 

drones yet somehow we can’t have the technology to safely operate 

a shutoff valve by remote control. I think it’s time to really take 

a comprehensive look, and this is something your staff, you, our organization all discussed in the last go round of pipeline safety authorization, even just requiring companies to assess their own 

lines, existing lines, come forward with their own plans for where 

these things should be installed, where they shouldn’t be, and file 

those and make them public. 

That was rejected as being too much. Not a requirement that 

they actually install them, but to do the assessment much like we 

require pollution prevention assessments or security assessments. 

That was rejected. 

So I don’t want to sound like we want all remote all the time everywhere, but certainly a comprehensive look at where we should 

be putting these things and then actually installing them. Look, I 

think this is the time to do it when gas prices are going down, demand is growing. There’s plenty of money to be made. Why not use 

some of the money being made to reinvigorate the system, not just 

with valves but also better replacing old segments of lines and 

things like that and better inspections. 

Which I agree with Mr. Staton, that’s where it starts is prevention. And better and more frequent inspections of more lines is 

really the beginning. But, yes, more valves, more remote valves. 

The CHAIRMAN. The answer is yes? 

Mr. KESSLER. I think so. Thank you, Mr. Chairman. 

The CHAIRMAN. Panel two agrees? 

Ms. QUARTERMAN. Yes. 

The CHAIRMAN. I’m about finished, but not quite. 

Mr. Kessler, because of their shape with or other reasons some 

transmission pipelines are unable to accommodate inline inspections to determine if any defects of risks exist. In lieu of inline inspections, operators often rely on direct assessment inspections 

which rely on walking the line or aerial surveys. I mean, this thing 

of helicopters flying over it—— 

Mr. KESSLER. Drones. 

The CHAIRMAN.—with long ropes and an orange thing at the bottom. 

Mr. KESSLER. Right. 

The CHAIRMAN. And I’m not sure how that works. But it’s trying 

just to assess how things are going. Do you include any kind of internal evaluation of a pipeline’s condition? 

Mr. KESSLER. I’m not sure I understand the last part of that 

question, Mr. Chairman. 

The CHAIRMAN. Well, the first part indicated that sometimes the 

situations—— 

Mr. KESSLER. It’s not possible. 

86 

The CHAIRMAN.—make it more difficult. And if you’re trying to 

make sure that things like here don’t happen again you don’t want 

to really guess at what’s inside. 

Mr. KESSLER. Right. 

The CHAIRMAN. And therefore the orange things at the end of 

ropes attached to a helicopter may be a good idea but may not really tell you that much. 

Mr. KESSLER. So when into—when congress, you and others enacted the 2002 Pipeline Safety Act there was—and we formalized 

in law integrity management, there was an—part of the legislative 

record included a preference—well, not a preference. A statement 

that direct assessment should be the least preferred form of inspection in these situations. 

It appears that that has been kind of flipped on its head. It’s certainly the most cost effective but the least effective means of actually getting data. Certainly there are times when these lines cannot be inspected by inline inspection devices. But that is narrowing 

more and more as the devices themselves become smaller, more 

able to move in different directions. The lines become more capable. 

We certainly need—and the law was weakened in 1996 in terms of 

PHMSA’s authority. 

But really we should be requiring more and more circumstances 

where lines should be replaced to accommodate these smart pigs. 

And we should be doing better on technology. And there should be 

even more than just inline inspection at this point. So, yes, more— 

less direct assessment. 

And by the way, Mr. Chairman, we’re not always sure, just like 

you were saying, what that direct assessment is. Is it walking? Is 

it flying? Is it looking out the window and saying, hey, this looks 

pretty good to me. I think GAO has pointed that out. I think NTSB 

at times has talked about this. We really need good strict easily 

understandable for the industry’s sake very clear standards on 

what direct assessment means, when you use it, and most importantly when you shouldn’t. 

The CHAIRMAN. All right. Thank you. I’ll just make a comment 

and then Senator Manchin may have a closing statement to make, 

and I may or may not. 

But let me just say that the very first question I said that you 

already answered is a really, really important one, and that is that 

you’re committed to doing absolutely everything that it takes. Now, 

granted this is something one could say at almost any time. But 

the fact is even though transmission by pipeline is generally much 

safer than most other ways of transmitting things and we all recognize that, we have had an accident here and it’s not been a good 

experience. 

So the statement that you’re going to do everything possible, everything necessary to bind the wounds, to help people understand, 

to stay with people, to be close to them is extremely important. 

And that’s more difficult for you because you’re head of a very large 

company. But it just seems to me that your presence is—it’s amazing what that will do, what statement that will make. And so I was 

very encouraged to hear that. 

And then I wanted to just say as a matter of what I’ve heard is 

that by and large you seem to be doing a very good job. 

87 

Mr. STATON. Thank you. 

The CHAIRMAN. And I know of a couple people that are upset 

about this and that, which always happens and necessarily happens, but that you seem to be trying, people seem to feel that. I 

feel that at least. And so I wanted to make that statement. 

Mr. STATON. Thank you. Thank you very much. 

The CHAIRMAN. Senator Manchin? 

Senator MANCHIN. Thank you, Senator. 

Mr. Kessler, you mentioned quite a few things. Is there one thing 

you think we’re not doing that we should be doing immediately 

that would be helping us to have a safer distribution system? Just 

one. 

Mr. KESSLER. One thing would be better inspections, more often, 

with greater oversight. Prevention. 

Senator MANCHIN. That’s—— 

Mr. KESSLER. Even a good company, and that’s why I’ve been declining to comment on this incident, because even a good company 

doing all the right things can still have an incident. 

Senator MANCHIN. Sure. 

Mr. KESSLER. But that said, as President Reagan said, ‘‘Trust, 

but verify,’’ and I don’t think we’re doing quite enough verifying 

and doing it in the way we should be. So that would be my answer. 

Better and more inspections. 

Senator MANCHIN. OK. 

Mr. Staton, knowing what happened on this particular line when 

there are three lines parallel in the same area. This is the only one 

that didn’t have that inspection. We’ve been told now, I think, that 

there will be valves so that you can do the inspections. Knowing 

that, do you have other lines in your system that you will take this 

same precautionary before, hopefully it will never happen again, 

are you doing that now systemwide? 

Mr. STATON. Absolutely we are. We identified on this pipeline because of the size of the pipeline, as Administrator Quarterman indicated, that it was not in a high consequence area. Part of what 

our modernization program is all about is essentially making all of 

our system capable so that we can always find issues before they 

become incidents. 

Senator MANCHIN. Is that part of the upgrade FERC if it’s granted for you? 

Mr. STATON. It is. That’s part of the FERC upgrade and it is our 

intention as part of our corrective action order working with 

PHMSA to make this line pigable, to run a pig throughout the entirety of this line. And then most importantly, to your point, to take 

the learnings of similarly situated pipelines where we have crossings, tie-ins with different vintage pipelines, rocky soil, and apply 

that learning across anywhere else on our system. 

Senator MANCHIN. Right. From an industry standard, from you 

all speaking upon the industry, knowing that we can’t have all the 

people that we need and all the money that’s going to be needed 

to do what we should for the safety of the public, do you recommend that all these companies, I’m sure you’re pretty much in 

tune with all the distribution companies around the country, that 

this should be a rule that the Federal Government should take in 

order for this to happen? 

88 

Mr. STATON. I fully think—I fully believe that the industry is responding. We are responding beyond, above and beyond—— 

Senator MANCHIN. Sure. 

Mr. STATON.—the requirements in HCAs. I know other pipelines 

are also responding above and beyond. 

Senator MANCHIN. So you all will not have a problem if that rule 

was adopted by the agencies? 

Mr. STATON. We’re going to continue—we’re going to continue to 

do the good things we’re doing irrespective of—of what happens 

from a regulatory and legislative perspective. 

Senator MANCHIN. And just final, one question, on all the parties 

that have been involved, I know you all have been making great 

strides, have you settled—or are you in the process of settling with 

all of the affected parties in Sissonville and making every effort 

you can to make sure that settlement is done as quickly as possible? 

Mr. STATON. Absolutely we are. I’ve—my—I believe strongly that 

my team has worked in a collaborative, thoughtful consideration, 

taking consideration for what has happened here. And we continue 

to work to resolve issues. We have resolved a number of them already. But as you would expect—— 

Senator MANCHIN. Sure. 

Mr. STATON.—there’s—there are a lot of them. 

Senator MANCHIN. You’re working to fully reimburse or what we 

call make whole? 

Mr. STATON. Yes. And we have—we’ve certainly made the state 

whole for the just amazing work they did on I–77. We made 

Kanawha County whole for the wonderful work that the emergency 

responders undertook, and they really did do just a tremendous job. 

And we are in the process with every affected property owner addressing anything that we can address. 

Senator MANCHIN. Let me just say on my behalf in closing, I 

want to thank Senator Rockefeller for inviting me to be part of this 

hearing today, and it’s truly informative. But encouraging also to 

see that everyone is trying to move in the most appropriate manner 

and taking the public safety first and foremost and high standard 

that we should be trying to achieve those levels of protection for. 

So from our agencies and also from the private sector we appreciate so much that, and thank you so much for your testimony and 

your appearances today. 

Senator, thank you. 

The CHAIRMAN. And I would agree with all of that, and point out 

that I’m sorry that I kept you, but I’m not because if something 

had been amiss you would have been pushed to correct it. That the 

whole concept of oversight, you know, it’s very controversial right 

now in America. People don’t like government. People don’t like 

government agencies. People don’t like us. 

Senator MANCHIN. We’ve seen that. 

The CHAIRMAN. But you cannot compromise on the business of 

oversight because the Congress is elected. The President is elected 

and appoints these good people. But there’s something about an 

oversight, having a commerce committee which has, you know, 

aviation, oceans, weather, all kinds of things and pipelines in its 

jurisdiction. 

89 

I think the concept of oversight is very important. Not that it always causes the world to change vastly for the better but that it’s 

there, that it’s asking questions, and that it’s frankly part of what 

democracy needs to be about. 

Mr. KESSLER. Mr. Chairman? 

The CHAIRMAN. Yes? 

Mr. KESSLER. Let me say one thing. I could not agree more. Last 

Congress you and your Ranking Member, Senator Hutchinson, 

Chairman Upton, and Member Waxman came out with very good 

bills. And House—in the House they got watered down once out of 

those committees into other committees. 

The one thing that can keep things moving along, I’ve learned, 

in all these years is a commitment to oversight. And the very 

things that you’re talking about mean so much to my organization 

and I think the public who have all been affected by this. And I 

think it is good in the long run for this industry and the country. 

That will help make everyone feel safe and confident in this industry. 

So thank you for that statement. 

The CHAIRMAN. Good. Thank you all very much. This hearing is 

adjourned. 

[Whereupon, at 2:48 p.m., the hearing was adjourned.] 

(91) 

A P P E N D I X 

RESPONSE TO WRITTEN QUESTIONS SUBMITTED BY HON. BARBARA BOXER TO

PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION

Question 1. Similar to the tragic 2010 accident in San Bruno, California that 

killed 8 people and injured 52, the preliminary results of the NTSB’s investigation 

on the Sissonville accident suggest that Columbia’s failure to detect serious flaws 

in its transmission pipeline may have been a contributing factor to the accident. 

What is the status of PHMSA’s rulemakings to improve oversight and communication to pipeline safety operators regarding proper recordkeeping and inspection protocols? 

Answer. PHMSA issued an advance notice of proposed rulemaking (ANPRM), entitled ‘‘Safety of Gas Transmission Pipelines’’, RIN 2137–AE72 regarding natural 

gas transmission pipelines on August 25, 2011. That ANPRM requested public comments on issues raised by the San Bruno incident, including integrity management 

principles for gas transmission pipelines and gas gathering. PHMSA intends to 

issue a notice of proposed rulemaking related to those issues later this year. In 

order to support the required regulatory analysis for that rulemaking PHMSA took 

several actions last year. On January 10, 2011, PHMSA issued an Advisory Bulletin 

(AB) (76 FR 1504) to remind operators of gas and hazardous liquid pipeline facilities 

of their responsibilities, under Federal integrity management (IM) regulations, to 

perform detailed threat and risk analyses that integrate accurate data and information, especially when calculating Maximum Allowable Operating Pressure (MAOP) 

or Maximum Operating Pressure (MOP). On May 7, 2012, PHMSA issued an AB 

(77 FR 26822) to remind operators of gas and hazardous liquid pipeline facilities to 

verify their records relating to operating specifications for MAOP and MOP required 

by 49 CFR 192.517 and 49 CFR 195.310, respectively. On December 21, 2012, 

PHMSA issued an AB (77 FR 75699) to inform owners and operators of gas transmission pipelines that if the pipeline pressure exceeds MAOP plus the build-up allowed for operation of pressure-limiting or control devices, the owner or operator 

must report the exceedance to PHMSA (and States with regulatory authority) on or 

before the 5th day following the date on which the exceedance occurs. On December 

5, 2012, the Office of Management and Budget (OMB) approved revisions to the gas 

transmission and gathering annual reporting requirement (PHMSA F–7100.2–1). On 

January 28, 2013, PHMSA issued a Federal Register notice (78 FR 5866) to owners 

and operators of gas transmission and gathering lines regarding significant changes 

to the annual reporting requirements. Those new annual reporting requirements require owners and operators to validate their Operator Identification Number data, 

and requests supplemental reports to correct gas transmission and liquefied natural 

gas annual report data issues when filing their next annual reports on June 15, 

2013. This data will be used to support regulations required by the Pipeline Safety, 

Regulatory Certainty, and Job Creation Act of 2011, which requires operators to 

conduct tests to confirm the material strength of previously untested natural gas 

transmission pipelines that operate at a pressure greater than 30 percent of specified minimum yield strength and are located in high-consequence areas. The pipeline in Sissonville was not such a pipeline, however, we are doing further analysis. 

Question 2. Also similar to the San Bruno incident, the time it took to shut off 

the gas in the Sissonville incident may have been a factor contributing to the extent 

of the damage. It took several minutes for the Columbia Gas controller to even learn 

of the explosion, despite numerous pressure drop alerts beforehand. It then took 

company officials over an hour to isolate the section of pipeline where the explosion 

occurred. Could requiring automatic or remotely-controlled shutoff valves wherever 

technically and economically feasible help minimize damages in future transmission 

pipeline explosions? 

Answer. In the ANPRM mentioned above, PHMSA also discussed the subject of 

automatic and remote controlled shutoff valves. PHMSA held a workshop on this 

subject on March 27, 2012. PHMSA also commissioned an independent study perVerDate Nov 24 2008 10:32 Jul 19, 2013 Jkt 075679 PO 00000 Frm 00095 Fmt 6601 Sfmt 6621 S:\GPO\DOCS\81794.TXT JACKIE
92 

formed by Keiffner and Associates on this topic and held a workshop on the draft 

of the study and accepted comments on the draft. A copy of that study was submitted to Congress on December 27, 2012. Based on the study, PHMSA is considering a rulemaking action on the benefits and costs of both automatic shutoff valves 

as well as remote control valves. 

Question 3. Why did PHMSA wait until January 31, 2013, to issue its Advisory 

Bulletin to pipeline owners and operators recommending that they contact the National Response Center within one hour of discovery of a pipeline incident? 

Answer. PHMSA had issued a series of Advisory Bulletins’ regarding the importance of operators promptly reporting incidents to the NRC. PHMSA’s predecessor— 

Research and Special Programs Administration—issued AB’s regarding these issues 

during the 1980s, and more recently on September 6, 2002 (67 FR 57060) to advise 

owners and operators of gas distribution, gas transmission, hazardous liquid pipeline systems, and liquefied natural gas (LNG) facilities to ensure that telephonic reports of incidents to the NRC are prompt (within 1 to 2 hours). In addition, on October 11, 2012, PHMSA issued an AB (77 FR 61826) to remind operators of gas, hazardous liquid, and liquefied natural gas pipeline facilities to immediately and directly notify the Public Safety Access Point (PSAP) that serves the communities and 

jurisdictions in which those pipelines are located when there are indications of a 

pipeline facility emergency. Furthermore, the AB stated operators should have the 

ability to immediately contact PSAP(s) along their pipeline routes if there is an indication of a pipeline facility emergency to determine if the PSAP has information 

which may help the operator confirm an emergency or to provide assistance and information to public safety personnel who may be responding to the event. 

Question 4. In 2003, 2005, and 2010, PHMSA hosted public workshops on pipeline 

operator public awareness programs. Why has PHMSA not conducted any additional 

public workshops in 21⁄2 years? 

Answer. Since late 2010, PHMSA has been conducting inspections on the effectiveness of pipeline operators public awareness programs. Those inspections were 

completed at the end of December 2012 and we are currently analyzing the results. 

Once those results have been analyzed, PHMSA is planning to conduct a Public 

Awareness workshop in June 2013 to bring public awareness stakeholders together 

to share the inspection results and discuss ways to strengthen and expand public 

awareness for the public, emergency response officials, public officials, and excavators. The workshop will be webcast live to allow for broad public participation. 

Question 5. PHMSA’s current Strategic Plan calls for ‘‘increase[ing] the visibility 

of our prevention and response efforts to better prepare the public.’’ Please describe 

the three major actions PHMSA plans to take to address this objective and its approach to evaluating the effectiveness of these actions? 

Answer. PHMSA has already taken significant actions to increase the visibility of 

our prevention and response efforts and has much more planned. PHMSA is evaluating a number of major actions to increase the visibility of our prevention and response efforts to better prepare the public, including: 

• PHMSA has pursued a strategy of institutionalizing pipeline awareness in the 

emergency response community over the past 18 months. The strategy commenced with a public, webcast Pipeline Emergency Response Forum on December 11, 2011. Since the forum, PHMSA has undertaken a variety of initiatives 

to better prepare emergency responders to safely and effectively respond to 

pipeline emergencies. PHMSA convened a Pipeline Emergency Response Working Group of emergency responders, pipeline operators, and government officials. PHMSA has also partnered with the National Association of State Fire 

Marshals, the U.S. Fire Administration, and Transportation Community Awareness and Emergency Response (TRANSCAER®). PHMSA has led a pilot project 

in Virginia to incorporate pipelines into the statewide emergency response plan 

and has led a pilot project in Georgia to ensure adequate pipeline training for 

emergency responders. PHMSA has also been represented annually at five 

major firefighter/emergency response conferences across the country. PHMSA 

has written several articles for major firefighter magazines and developed a brochure that highlights pipeline safety resources that PHMSA makes available to 

emergency responders. PHMSA is also funding a research project that will 

produce a guide for effective communication practices between pipeline operators and emergency responders. Additionally, the National Fire Protection Association (NFPA) is making a variety of changes to their standards that will elevate the importance of pipelines in the training competencies of firefighters. 

• PHMSA also produced and distributed an 811 television and radio Public Service Announcement, expanded its efforts in supporting National Safe Digging 

93 

Month and National 811 Day, and incorporated social media messages into the 

811 campaign. An annual survey is conducted to measure 811 awareness. 

PHMSA is also planning to conduct a public awareness workshop in June 2013 

to bring public awareness stakeholders together to discuss recent public awareness inspections and to discuss ways to strengthen and expand public awareness. 

• PHMSA is executing damage prevention initiatives and will, in the coming 

months, issue a Final Rule entitled ‘‘Pipeline Safety: Pipeline Damage Prevention Programs, RIN 2137–AE 43. The rule will focus on the enforcement of One 

Call laws; address exemptions in One Call laws through a study; grants to 

States for the purpose of strengthening damage prevention programs; and work 

with State stakeholders who seek to improve their One Call laws and programs 

through meetings, data analysis, and letters of support. Incidents caused by excavation damage have decreased by 30 percent since 2008. 

RESPONSE TO WRITTEN QUESTIONS SUBMITTED BY HON. BARBARA BOXER TO

JIMMY D. STATON

Question 1. Why did Columbia have to rely on another company’s employee to notify Columbia of the explosion? 

Answer. Columbia Gas relied on several pieces of information to determine that 

the Sissonville rupture had occurred. The primary source of information was the Supervisory Control and Data Acquisition System (SCADA) network. The SCADA system collects near-real-time electronic data from sensors strategically located 

throughout the pipeline system. Pipeline pressures, equipment status, station 

alarms and other information is relayed through the SCADA system to our Gas 

Control Center where the data is used by our Gas Control Team to monitor and 

safely control natural gas flow throughout the pipeline system. 

Within approximately two minutes of the rupture occurring, Columbia’s Gas Control personnel received and acknowledged SCADA alerts indicating a drop in operating pressure. The deviation alert was generated from pressure sensors located at 

Lanham Compressor Station, located approximately 4.7 miles west and upstream of 

the rupture location. Since pressure drops are not unusual and can have both normal and abnormal causes, our Gas Control personnel acknowledged receipt of the 

alerts and began to investigate potential causes of the pressure drop, such as compression changes, market (demand) changes, a leak, etc., to see whether any further 

action was needed. 

After receipt of the SCADA alerts, Columbia’s Gas Control Center received a call 

from a gas controller at Cabot Oil & Gas and were told that one of Cabot’s field 

technicians happened to be driving near Sissonville and heard a loud noise and then 

a roaring sound, which he believed could have been caused by the rupture of a 

major gas pipeline. Since Cabot did not have any indications of a leak in their system, and the employee knew Columbia Gas had transmission lines in the Sissonville 

area, the Cabot gas controller conveyed this information to Columbia Gas Control. 

In short, Columbia Gas did not rely on another company’s employee to notify it 

of the Sissonville rupture. Among the several pieces of information Columbia Gas 

Control collected to analyze the situation was an eye witness report from a Cabot 

field technician who happened to be in the Sissonville area and witnessed the immediate aftermath of the rupture. 

Question 2. What notifications to the community was Columbia required to make 

about the event, and did the company comply with these requirements? 

Answer. Columbia Gas complied with all applicable reporting requirements. Columbia Gas is required to contact the National Response Center (NRC) following 

any event that meets the definition of an incident, in accordance with current pipeline safety regulations (49 CFR 191). Columbia personnel did in fact contact the 

NRC to report the Sissonville rupture immediately after the accident. After reporting the incident to the NRC, Columbia also contacted the Director of the West Virginia Public Service Commission and the Pipeline and Hazardous Materials Safety 

Administration’s Eastern Regional Office to inform them of the incident. 

In addition, Columbia’s Operations personnel coordinated with the responding 

fire, police and emergency management services to isolate the rupture location and 

secure the site to ensure the safety of the public. 

94 

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-theground 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 

95 

to get units on the north end of the fire which was inaccessible from our location. 

I assumed command and began trying to formulate an Incident Action Plan. 

You have to understand the nature of a volunteer fire department. During the day 

we often operate short on manpower because our firefighters have to work. I had 

four (4) firefighters on scene, multiple structures on fire, and an obvious natural gas 

based fire. I knew I had help coming but didn’t know the time frame for when it 

would get there. My primary consideration was for the safety of my firefighters and 

then to get any victims out as safely as possible. Denying entry into the scene really 

wasn’t an issue as nobody in their right mind would go near the incident with the 

volume of fire and the radiant heat being given off. 

I saw that the Interstate was compromised but, again, couldn’t get over to it and 

had to rely on common sense to prevail and that people would avoid the fire. I could 

see vehicle stopped so I assumed the road was blocked. Please understand that I 

am giving you ‘‘snapshots’’—as a Fire Chief or an Incident Commander you have 

to look at the situation you have, what you have to work with, what needs to be 

done, in what order it needs to occur and how all this can be done safely. We received information that a woman was trapped behind a house and we formulated 

a plan for a ‘‘GO RESCUE’’ of her. A team went in and got her and safely removed 

her from harm’s way. 

As additional resources arrived we were able to do a more thorough recon of the 

area. An Incident priority was to get the gas shut off and that plan was implemented in what I thought was a short timeline. With the interstate and Sissonville 

Drive being closed because of the incident there were some issues getting additional 

resources to the scene but it is what it is and we had to deal with it. We responded 

to at least five (5) other related calls while handling the main incident and were 

able to arrange for emergency services coverage for the rest of our area during the 

event. I felt that the interagency cooperation was tremendous and contributed to the 

successful incident outcomes that we achieved—no loss of life, no life threatening 

injuries, and no First Responder injuries or deaths. As we needed resources, they 

were assigned and effectively managed. We returned units to service as quickly as 

practical. 

Once the pipeline involved was identified, we received excellent cooperation from 

them. School children were sheltered in place at their schools until safe arrangements could be made to get them home. A church in our community quickly set up 

a shelter for those impacted—either displaced or those who couldn’t get home because of the roads blocked. We worked with the media to help ensure that accurate 

information was getting out in a timely fashion. It was a true team effort. I am very 

proud of the efforts made by all of the First Responders who helped out in this 

event. As the Fire Chief it is good to know that our training and preparation paid 

off. We contained the event, made several rescues, and, although many were inconvenienced, no one died or was hurt other than those initially impacted by the blast. 

Lastly, I am proud to continue to serve my community. This incident is now part 

of our history and will be used by my department to prepare for the future. We will 

learn and grow from what occurred. We will never stop trying to be better than we 

are. 

Thank you all for your time today and for your concern about the countless 

Sissonville’s of our nation. May God bless our community and our country. 

Æ