[Senate Hearing 112-470]
[From the U.S. Government Publishing Office]
S. Hrg. 112-470
PIPELINE SAFETY SINCE SAN BRUNO
AND OTHER INCIDENTS
=======================================================================
HEARING
before the
SUBCOMMITTEE ON SURFACE TRANSPORTATION
AND MERCHANT MARINE INFRASTRUCTURE,
SAFETY, AND SECURITY
of the
COMMITTEE ON COMMERCE,
SCIENCE, AND TRANSPORTATION
UNITED STATES SENATE
ONE HUNDRED TWELFTH CONGRESS
FIRST SESSION
__________
OCTOBER 18, 2011
__________
Printed for the use of the Committee on Commerce, Science, and
Transportation
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SENATE COMMITTEE ON COMMERCE, SCIENCE, AND TRANSPORTATION
ONE HUNDRED TWELFTH CONGRESS
FIRST SESSION
JOHN D. ROCKEFELLER IV, West Virginia, Chairman
DANIEL K. INOUYE, Hawaii KAY BAILEY HUTCHISON, Texas,
JOHN F. KERRY, Massachusetts Ranking
BARBARA BOXER, California OLYMPIA J. SNOWE, Maine
BILL NELSON, Florida JIM DeMINT, South Carolina
MARIA CANTWELL, Washington JOHN THUNE, South Dakota
FRANK R. LAUTENBERG, New Jersey ROGER F. WICKER, Mississippi
MARK PRYOR, Arkansas JOHNNY ISAKSON, Georgia
CLAIRE McCASKILL, Missouri ROY BLUNT, Missouri
AMY KLOBUCHAR, Minnesota JOHN BOOZMAN, Arkansas
TOM UDALL, New Mexico PATRICK J. TOOMEY, Pennsylvania
MARK WARNER, Virginia MARCO RUBIO, Florida
MARK BEGICH, Alaska KELLY AYOTTE, New Hampshire
DEAN HELLER, Nevada
Ellen L. Doneski, Staff Director
James Reid, Deputy Staff Director
Bruce H. Andrews, General Counsel
Todd Bertoson, Republican Staff Director
Jarrod Thompson, Republican Deputy Staff Director
Rebecca Seidel, Republican General Counsel and Chief Investigator
------
SUBCOMMITTEE ON SURFACE TRANSPORTATION AND MERCHANT MARINE
INFRASTRUCTURE, SAFETY, AND SECURITY
FRANK R. LAUTENBERG, New Jersey, ROGER F. WICKER, Mississippi,
Chairman Ranking Member
DANIEL K. INOUYE, Hawaii JIM DeMINT, South Carolina
JOHN F. KERRY, Massachusetts JOHN THUNE, South Dakota
BARBARA BOXER, California JOHNNY ISAKSON, Georgia
MARIA CANTWELL, Washington ROY BLUNT, Missouri
MARK PRYOR, Arkansas JOHN BOOZMAN, Arkansas
CLAIRE McCASKILL, Missouri PATRICK J. TOOMEY, Pennsylvania
AMY KLOBUCHAR, Minnesota MARCO RUBIO, Florida
TOM UDALL, New Mexico KELLY AYOTTE, New Hampshire
MARK WARNER, Virginia DEAN HELLER, Nevada
MARK BEGICH, Alaska
C O N T E N T S
----------
Page
Hearing held on October 18, 2011................................. 1
Statement of Senator Lautenberg.................................. 1
Statement of Senator Wicker...................................... 2
Statement of Senator Boxer....................................... 3
Article from News10 dated September 28, 2011 entitled,
``Roseville gas leak spouts flames on road''............... 5
Article from The Fresno Bee dated September 15, 2011
entitled, ``6 Sanger homes evacuated when gas line
ruptures''................................................. 5
Article from The Mercury News dated September 2, 2011
entitled, ``Blast rocks Cupertino home; PG&E crews find
seven pipe leaks``......................................... 5
Article from ABC News dated February 10, 2011 entitled,
``Allentown, Pa., Explosion Leaves Five Dead``............. 6
Article from trib.com dated July 22, 2011 entitled, ``Natural
as pipeline explores near Gillette``....................... 7
Article from FOX8.com dated February 11, 2011 entitled, ``Gas
Explosion Lights Up Sky in Columbiana County''............. 8
Article from Lex18.com dated September 21, 2011 entitled,
``Clark Co. Gas Line Rupture Heard Several Counties Away``. 8
Witnesses
Hon. Dianne Feinstein, U.S. Senator from California.............. 9
Prepared statement........................................... 11
Hon. Cynthia L. Quarterman, Administrator, Pipeline And Hazardous
Materials Safety Administration, U.S. Department of
Transportation................................................. 14
Prepared statement........................................... 16
Hon. Deborah A.P. Hersman, Chairman, National Transportation
Safety Board................................................... 19
Prepared statement........................................... 20
Nick Stavropoulos, Executive Vice President, Gas Operations,
Pacific Gas and Electric Company............................... 24
Prepared statement........................................... 25
Rick Kessler, Vice President, Pipeline Safety Trust.............. 32
Prepared statement........................................... 34
Donald F. Santa, Jr., President and CEO, Interstate Natural Gas
Association of America......................................... 42
Prepared statement........................................... 44
Christina Sames, Vice President, Operations and Engineering,
American Gas Association....................................... 48
Prepared statement........................................... 49
Appendix
Response to written questions submitted to Hon. Cynthia L.
Quarterman by:
Hon. Barbara Boxer........................................... 83
Hon. Roger F. Wicker......................................... 87
Response to written questions submitted to Hon. Deborah A.P.
Hersman by:
Hon. Frank R. Lautenberg..................................... 87
Hon. Barbara Boxer........................................... 87
Response to written questions submitted by Hon. Frank R.
Lautenberg to Nick Stavropoulos................................ 93
Response to written questions submitted by Hon. Barbara Boxer to:
Donald F. Santa, Jr.......................................... 100
Christina Sames.............................................. 101
PIPELINE SAFETY SINCE SAN BRUNO
AND OTHER INCIDENTS
----------
TUESDAY, OCTOBER 18, 2011
U.S. Senate,
Subcommittee on Surface Transportation and
Merchant Marine Infrastructure, Safety, and Security,
Committee on Commerce, Science, and Transportation,
Washington, DC.
The Subcommittee met, pursuant to notice, at 2:32 p.m. in
room SR-253, Russell Senate Office Building, Hon. Frank R.
Lautenberg, Chairman of the Subcommittee, presiding.
OPENING STATEMENT OF HON. FRANK R. LAUTENBERG,
U.S. SENATOR FROM NEW JERSEY
Senator Lautenberg. I call the hearing to order. We have
the excellent opportunity to hear from our distinguished
colleague from California.
I welcome everybody to today's hearing, which will address
pipeline safety since last year's explosion in San Bruno,
California, as well as broader concerns about the safety of
America's 2.3 million miles of pipeline.
Now, these pipelines, which move oil and gas within states
and across the country, are one of the safest forms of
transportation. But when an accident occurs, the consequences
can be deadly.
We witnessed this last year: a natural gas pipeline
ruptured below the ground in San Bruno, igniting a blaze that
killed eight people and destroyed dozens of homes.
Now other recent oil pipeline accidents in Michigan and
along the Yellowstone River spilled thousands of barrels of oil
into sensitive waterways, causing severe damage in both areas.
These tragedies remind us that we have a responsibility to keep
our country's pipelines safe and reduce the frequency of
accidents.
And that's why I'm proud that last night that the Senate
passed my Pipeline Transportation Safety Improvement Act, which
will help us implement critical safety improvements to our
Nation's pipeline networks.
The bill requires companies to keep better records
detailing the maximum pressure levels that their pipelines can
safely handle.
It also requires apartment buildings and commercial
facilities to add excess flow valves, which can automatically
shut off a pipeline if a major spike in pressure is detected.
Now, these valves will help us reduce the likelihood of
tragedies like the one we experienced in my home state of New
Jersey--in Edison, New Jersey--in 1994 when a natural gas
pipeline exploded and destroyed 14 apartment buildings.
Additionally, the bill will boost the amount of information
available to the public on pipeline inspections, stiffen
penalties for companies that fail to follow the rules, and put
more pipeline inspectors on the job.
The bill is funded through a combination of fees and other
assessments paid for by the industry, which supports this bill
and its approach to funding pipeline safety improvement.
Safety advocates have also rallied behind this bill, which
enjoys broad bipartisan support. The bottom line is the
Pipeline Transportation Safety Improvement Act makes the
sensible, cost-effective safety improvements that our country
needs.
And now that it's passed the Senate, it should be passed by
the House without further delay.
And I know that this issue is particularly important to
Senator Feinstein and Senator Boxer. I thank Senator Boxer for
her efforts and I will continue working with her and our
colleagues to make our country's pipelines safer.
I also look forward to hearing from today's witnesses.
But first we're going to turn to other members for their
opening statements.
And I ask Senator Wicker, the Ranking Member, to give his
statement now.
STATEMENT OF HON. ROGER F. WICKER,
U.S. SENATOR FROM MISSISSIPPI
Senator Wicker. Thank you very much, Senator Lautenberg.
And I'm sure all of my colleagues on the Committee are
delighted to have our colleague from California, Senator
Feinstein, with us as our first witness today.
As the Chair mentioned yesterday, by unanimous consent the
Senate passed a pipeline safety bill that will be of great
benefit to the safety of our pipeline infrastructure in the
United States.
I'd like to thank Senator Lautenberg for his leadership on
this issue, and for working closely with the minority to craft
a bill that will make needed improvements while ensuring that
pipeline operators will continue to provide a high level of
service.
Because they are rarely seen, it's easy to forget about the
importance of pipelines. They're important to the national
economy, and to our daily lives. Pipelines are the circulatory
system for the Nation's energy needs, moving natural gas,
petroleum, and other vital fuels from the point of production
to people's doorstep. They provide the transportation for the
fuel that does everything from warming our homes, to fueling
our factories, to generating electricity.
Of course, as with any transportation of hazardous
materials, we must do our best to ensure the safety of our
pipeline system. And pipelines do present some unique
challenges.
With millions of miles of pipeline in the United States, it
is a particularly difficult task to identify the lines that are
most likely to fail and to mitigate the risks.
The Office of Pipeline Safety, within the Pipelines and
Hazardous Materials Safety Administration, is charged with
overseeing the safety of the Nation's pipeline system. And the
office's effectiveness is demonstrated by the improving safety
performance of the Nation's pipelines.
Since OPS is funded through user fees paid by industry, it
operates at minimal cost to the government. I'm interested to
hear from the PHMSA administrator about the recent initiatives
in the office. NTSB has also done an admirable job in
investigating recent pipeline accidents, and I look forward to
hearing what we can do at the congressional level to make the
system even safer.
Senator Wicker. Thank you, sir.
Senator Lautenberg. Thank you, very much. We'll go on to
Senator Boxer for her statement.
STATEMENT OF HON. BARBARA BOXER,
U.S. SENATOR FROM CALIFORNIA
Senator Boxer. Thank you, Senator Lautenberg. Senator
Feinstein and I will never forget what hit our state, and I'm
going to go through this with some photos so, my colleagues,
you can see this.
At 6:11 p.m. on September 9, 2010, a PG&E transmission
pipeline exploded beneath a densely populated neighborhood in
San Bruno, California, and eight people lost their lives and
another 52 were injured. And of course our hearts go out to all
the victims.
The inferno destroyed 38 homes and damaged 70 homes. And
you can see the destroyed homes are in red--38, damaged homes,
70, in the yellow.
And I'll show you some pictures of the devastation, because
I walked that neighborhood and it's just--when you know this
was such a thriving community, this is what you saw--only a few
chimneys, charred vehicles, and debris were left behind.
So this is what you saw--the chimneys standing--and here
you can see the charred vehicles that were standing afterwards.
Most disturbing of all, this accident and this tragic loss
were entirely preventable. Because we know it--because the
NTSB's investigation reveals that there were numerous points at
which this accident could have been prevented.
First, PG&E installed a faulty, poorly welded pipeline back
in 1956 that would not have met industry standards at the time,
even. Its flaws would have been visible to the naked eye.
Proper quality control procedures could have prevented the
installation of the pipeline, or in-line inspection could have
detected its flaws later.
Second, PG&E's poor recordkeeping led them to believe they
had a seamless pipe in this location, which didn't even exist
in 1956. So it couldn't have been a seamless pipe. A proper
integrity management program or pressure testing would have
uncovered this error, or, at the very least, required a 30
percent reduction in the maximum allowable operating pressure
for the pipeline.
Third, prior excavations of this pipeline found various
data errors, leaks, and other problems, but PG&E didn't address
this and didn't even update its records to include these
discoveries. Again, a proper integrity management program would
have raised red flags about the pipeline and warranted further
testing
Fourth, poorly planned electrical work at the Milpitas
terminal triggered the pressure surge that led to the rupture
of the faulty pipeline.
You can see that the pipe split open along the seam. Proper
work clearance procedures and contingency planning would have
allowed PG&E's control center to anticipate this potential
complication and reduce the pressure in the pipeline before it
was too late.
Finally, once the accident occurred it took PG&E an hour
and a half to shut off the gas. Look at what was happening on
the ground here. An hour and a half to shut off the gas, while
the fire continued to burn like a blowtorch, increasing the
amount of the damage.
So, proper emergency response protocols and the use of
automatic or remote controlled shutoff valves would have
reduced this time significantly, saving homes and maybe even
lives.
This litany of failures was not just attributable to PG&E,
but also to serious failures by state and Federal regulators.
Again, according to the NTSB's report, the CPUC, the California
Public Utilities Commission, audited PG&E in 2005 and again
only 4 months before the explosion. Yet, and I quote from the
NTSB, ``failed to detect the inadequacies in PG&E's integrity
management program,'' even though they went on to say, ``many
of them should have been easy to detect.''
Meanwhile, PHMSA repeatedly gave CPUC an A plus for its
oversight. And NTSB says this raises strong doubts about the
quality and effectiveness of enforcement at both the Federal
and the state levels.
Unfortunately, although San Bruno was particularly severe,
the accident was not at all unusual. And I ask unanimous
consent to place in the record the recent pipeline explosions
throughout the country that we have flagged in my opening
statement.
An average of 42 serious gas pipeline incidents per year
over the past decade, resulting in an average of 14 deaths, 16
injuries, and over $32 million in property damages each year.
So, Roseville, Sanger--I'm just quoting--in Pennsylvania,
Allentown, in Wyoming near Gillette, in Ohio, in Kentucky.
So Senator Feinstein and I introduced legislation to
strengthen pipeline safety. I joined her--she took the lead.
I'm so proud that similar legislation passed the Senate last
night.
But even after this legislation is signed into law, there's
more work to be done. So I look forward today to hearing about
what PHMSA's doing to strengthen its regulation enforcement and
what PG&E and the pipeline industry are doing to strengthen
their own safety programs.
And we don't want to see anything like this again, this
out-of-control horror that hit a beautiful, middle-class,
strong community in our state. We want to spare that to
everyone, and so we hope that this hearing will lead us in that
direction.
Senator Boxer. Senator Lautenberg, Senator Wicker, thank
you so much for your help in getting this out here today.
Thank you.
[The information referred to follows:]
Roseville News--Wednesday, September 28, 2011
Roseville gas leak spouts flames on road
Submitted by Maneeza Iqbal
ROSEVILLE, CA--Pacific Gas and Electric crews are trying to seal of
a broken section of a 4-inch gas distribution line that developed a
leak and then caused a fire at 6:50 p.m. Tuesday.
UPDATE: As of 5:22 a.m. Wednesday, the fire was extinguished and
most lanes of Riverside Ave. and Cirby Way were open to traffic. Only
the westbound lanes of Cirby Way between Orlando Avenue and Riverside
Avenue remained closed to through traffic. Through traffic was being
diverted onto Orlando
The fire burned in middle of the intersection of Cirby Way and
Riverside Avenue, Roseville Assistant Chief Jeff Carman said.
Carman said the flames were six feet above the ground and that
there is some concern the gas could build up and cause an explosion.
``We're worried about the buildup possibly accumulating in sewer
pipes and storm drain pipes,'' Carman said. ``So, our hazmat team's on
scene and they're taking readings every few minutes to make sure we're
not getting that buildup.''
Most nearby businesses were closed by the time the fire started,
but the seven that were still open had to be closed and the employees
evacuated.
A few homes and apartment units are nearby, but they do not need to
be evacuated, according to Carman.
The intersection was closed off to traffic.
City of Roseville spokeswoman Dee Dee Gunther said Riverside Avenue
was closed off between the Interstate 80 exchange and Kenroy Lane.
Cirby Way has been closed between Melody Lane and Orlando Avenue.
PG&E crews are on scene and will work through the night.
Drivers are being urged to avoid the area during the morning rush
hour and possibly even later into the day.
The intersection was the scene of another gas leak about a year
ago. A PG&E spokesperson said that leak was caused by a crack in a
section of plastic pipe, but would not speculate on why this latest
leak happened so close by just one year later.
Dave Marquis [email protected] contributed to this story.
______
The Fresno Bee--Thursday, Sep. 15, 2011
6 Sanger homes evacuated when gas line ruptures
A construction crew working in northeast Sanger on Thursday
afternoon ruptured a natural gas line, forcing the evacuation of six
homes, said Greg Tarascou, the city's interim fire chief.
The gas leak happened about 2:30 p.m. near Church and Harrison
avenues, Tarascou said. Pacific Gas & Electric Co. workers capped the
line about 7:30 p.m.
No illnesses or injuries were reported and the residents who were
evacuated were allowed back into their homes shortly after the line was
capped, Tarascou said.
______
The Mercury News--Posted: 09/02/2011 12.02.04 PM PDT--Updated: 09/02/
2011 12:30.52 PM PDT
Blast rocks Cupertino home; PG&E crews find seven pipe leaks
By Mike Rosenberg
A day after federal investigators chastised PG&E for a ``litany of
failures'' in last year's San Bruno blast, a loud explosion blew away a
Cupertino home's garage door, and several underground gas pipes in the
area were found leaking, authorities said Thursday.
Pacific Gas & Electric crews found seven leaks in the 2-inch pipes
that distribute gas to homes in the area near the explosion. But
investigators are still unsure exactly what caused Wednesday's blast.
PG&E has more than 42,000 miles of the distribution pipes running
beneath properties in the Bay Area and beyond--and a similar explosion
killed a man inside his Sacramento-area horn three years ago.
The resident of the Cupertino townhome near the Homestead Square
Shopping Center had left the home 15 minutes before the explosion,
which badly damaged the residence. No injuries were reported, and
firefighters said they saved a pet dog hiding under a bed inside.
State regulators are investigating the blast. In addition, PG&E
President Chris Johns and the utility's head of gas operations are
taking part in the probe.
``We got a lot of people looking into this to find out exactly what
happened.'' PG&E spokesman Dave Eisenhauer said.
A day after the fire, investigators were still piecing everything
together.
About 12:25 p.m., people from Cupertino to Sunnyvale flooded 911
call centers to report a boom, said Deputy Chief Don Jarvis of the
Santa Clara County Fire Department.
``The people who were calling didn't know exactly where it was;
they just heard it:'' Jarvis said.
The explosion partially engulfed the townhome in flames at 20299
Northwest Square, Jarvis said. When firefighters from Sunnyvale and
Cupertino arrived, they found the garage door lying m the driveway and
the side door of the garage off its hinges, lying in the bushes.
The firefighters quickly extinguished the blaze, which began in the
garage and advanced into the second story and the underside of the
roof. They moved to evacuate the two adjacent four-plex townhouse units
as a precaution--although no one was home there, either.
Firefighters noticed gas was leaking near the damaged home--
overhead TV cameras caught footage of flaming pipes--and PG&E crews
responded by shutting off the gas flow.
On Thursday, Eisenhauer said, the utility's investigators who were
working all night found six more gas leaks in the area and repaired
them.
Both PG&E and fire crews said it could take a while to determine
the cause of the blast, a complicated process Both the California
Public Utilities Commission and the National Transportation Safety
Board have been notified about the fire. Investigators were also trying
to find out whether anyone reported smelling gas before the blast.
The smaller distribution pipes that were leaking receive gas from
the larger transmission lines, like the one that blew up in San Bruno,
killing eight people and destroying 38 homes.
Since the tragedy, oversight groups and consumers have focused on
the big pipes, which carry much more gas. But PG&E also has 42.141
miles of the smaller distribution pipes, about seven times the length
of its bigger transmission lines. And the smaller pipes explode on
occasion, too.
______
ABC News--Feb. 10, 2011
Allentown, Pa., Explosion Leaves Five Dead--
By Lyneka Little and Alan Farnham
Five people are dead after a powerful gas line explosion ripped
through downtown Allentown, Pennsylvania.
Authorities say the five victims are a couple in their 70s, a 4-
month-old boy, a 16-year-old girl and one of the children's parents.
The victims are from two families who lived in the two townhouses that
were destroyed by the blast.
The explosion rocked the neighborhood at 10:45 p.m. on Wednesday,
touching off fires that blazed into the early-morning hours as
firefighters combed through snow and ice to stop an underground
pipeline from feeding the flames.
Authorities said at least six homes will not be salvageable and two
homes were entirely leveled. Forty-seven homes and ten businesses were
damaged by the explosion, fire or ice.
Utility workers inspected the area the day before the explosion and
detected no leaks. The pipe that fed the explosion was installed in
1928 and Ed Pawlowski, the mayor of Allentown, said old and dangerous
pipes run under many cities.
``Lines built over 150 years ago are still servicing a lot of these
building today,'' Pawlowski said. ``When you have constant thawing and
freezing you're going to have problems . . . and lead to disasters like
this.''
Utility workers were called in to assist and get the gas lines shut
off after the explosion on the 500 block of North 13th Street. Snow
piles and ice hampered firefighters as they attempted to put out the
flames. UGI Corporation, the local gas utility, was unable to shut off
the gas until 3:45 a.m.
The magnitude of the explosion and flames forced the evacuation of
hundreds of residents. The cause of the explosion is being
investigated.
``I think we are going under the assumption that it is a gas
explosion, but it has not been confirmed to be the case,'' Joseph
Swope, a UGI spokesman told the Morning Call.
He said the 12-inch low pressure main involved in the incident
hadn't had any history of leaks.
The powerful blast sent a computer monitor crashing into the home
of one person in the neighborhood, according to The Associated Press.
``I thought we were under attack,'' Antonio Arroyo told the AP.
``What I saw, I couldn't believe.'' Arroyo and his wife sought refuge
in a shelter after the explosion destroyed their home. The couple
expects to return to their home to see what can be salvaged but every
keepsake they own may be lost.
``This is a real tragedy,'' Mayor Ed Pawlowski told the Morning
Call. ``Our thoughts and prayers are with the families.''
The tragedy follows another explosion that rocked the West Coast
last year.
The explosion that leveled a San Bruno, California, neighborhood in
September sent flames 300 feet into the air after a ruptured natural
gas pipeline-- in that case, one belonging to the Pacific Gas &
Electric Company.
San Bruno's fire and explosion destroyed 53 homes and damaged 120
more. It killed seven and injured more than 50. ``The central ball of
fire,'' said a reporter for the San Francisco Chronicle, ``raged past
nightfall before abating. By then, houses on several blocks and thick
stands of trees were engulfed in flames."
The death toll wasn't the worst in pipeline history. An incident 10
years ago in Carlsbad, New Mexico, killed 12. Pipeline blasts in the
past five years have killed 60 and injured 230.
Though roughly half these incidents were the fault of parties other
than utilities (builders or cable companies that accidentally dug into
underground pipes), pipeline operators dug into their own pipes in at
least two dozen cases. Other incidents for which they were responsible
involved corrosion, faulty equipment and operator error.
The San Bruno incident was caused by a pipe that ruptured because
of regular changes in gas pressure, according to federal investigators.
The age of a pipeline matters less than inspection and maintenance,
said Carl Weier, head of the Pipeline Safety Trust, a government-
financed watchdog group. ``Most of the pipelines in this country are 40
to 50 years old. If properly maintained, they don't present a danger.''
But even a new pipeline, he said, will fail if not well-inspected
and maintained. Corrosion caused the Carlsbad event, according to
inspectors who examined the wreckage. Weier said the danger of future
explosions could be defused by better and more frequent inspection,
especially in rural areas, where pipelines get a thorough going-over
only once every seven years.
The Associated Press contributed to this story.
______
trib.com--Posted: Friday, July 22,2011 3:00 am
Natural gas pipeline explodes near Gillette
By Jeremy Fugleberg--Star-Tribune energy reporter
A natural gas pipeline west of Gillette exploded Wednesday night.
It shook nearby homes and echoed at least 30 miles away but didn't
cause any injuries or property damage, officials and a resident said.
The blast ripped open a 60-foot section of the Bison Pipeline and
shot several pieces of 30-inch-diameter pipe around thebluffs on land
about 20 miles west of Gillette at about 7:30 p.m.
The explosion's shock wave slammed Dan and Candy Mooney's home,
about a mile from the rupture, as well as his brother's house not far
away.
The earth-shaking rattling and boom were followed by what Dan
Mooney described as a ``terrible roar'' as natural gas underhigh
pressure burst from the broken pipe.
``If you've ever heard a jet fighter going off, like an F-16 or
something like that, it sounded like many of them going off at thesame
time,'' he said. ``It roared, it just screamed.''
Mooney said a fiend from Recluse, about 30 miles north of Gillette,
called in to say the explosion could be heard that far away. Several
residents in and near Gillette dialed emergency dispatchers to report
``sounds of rockets going off, whooshing sounds and some explosions,''
said David King, Campbell County Emergency Management Agency
coordinator.
The roaring stopped as the pipeline system detected the drop in
pressure from the rupture and closed off the flow of gaswithin 15
minutes of the breach, according to Terry Cunha, spokesman for
TransCanada Corp., which owns the pipeline.
King as well as other county emergency responders traveled to the
site, but waited for a TransCanada team to check the areafor natural
gas pockets before anyone got close to the explosion site--a crater in
the ground and pipeline pieces blown wellclear of the pipe trench.
A 40-foot piece of the pipe, split along its length and spread open
with jagged ends, lay almost 70 feet away from the pipeline path said
Rod Warne, Campbell County Fire Department assistant chief, who visited
the site. In the gathering dark,he saw at least one other piece of pipe
blown nearby.
``I've never been to one that had that big of a pipe, that big of a
chunk blown out that far,'' he said.
All officials and Mooney said the explosion didn't cause any
injuries or property damage other than to the pipeline.
It's not yet clear what caused the pipeline to explode, and there's
no clear timeline for when the company will rebuild theline and get it
back into use, said Cunha, the TransCanada spokesman.
``Unfortunately this incident happened, but we'll do a thorough
review and work with regulatory agencies to investigate thecause of
this and ensure we prevent it from happening again,'' he said.
It's not yet clear how much natural gas was vented, but the
pipeline was transporting natural gas on Wednesday at a rate of365
million cubic feet a day, Cunha said.
The 303-mile line was designed to transport up to 477 million cubic
feet a day of natural gas from the Powder River Basin northeast through
Montana to the Northern Border Pipeline in North Dakota for transport
to customers in the Midwest. The pipeline went on line in January and
is owned by TransCanada Corp. through its interest in TC PipeLines.
TransCanada was able to provide 50 percent of the pipeline's volume
to customers on Thursday, but the pipeline will beshut down starting
today as the investigation continues, Cunha said.
While the closure of the pipeline might cause some problems for a
day or two, other pipelines will quickly pickup the slack, said Brian
Jeffries, executive director of the Wyoming Pipeline Authority.
The state's natural gas production is about what it was before the
Bison Pipeline came on line, so the state's pipeline systemhas other
ways of moving the gas, he said.
``I expect any impact on production and flow to be relatively
short-lived,'' he said.
______
Fox8.com--10:44 AM EST, February 11,2011--Hanoverton, Ohio
Gas Explosion Lights Up Sky in Columbiana County
A gas pipeline explosion rocked Columbiana County, creating a
fireball so huge that people saw it for many miles, Fox 8's Stacey Frey
reports.
A county official says people many miles away from a natural gas
pipeline explosion saw a glow in the sky and reported hearing a sound
similar to a blowtorch.
Columbiana County Commissioner Jim Hoppel said Friday he could see
the sky ``all lit up'' from the county seat in Lisbon, about 20 miles
from Thursday night's explosion and fire near Hanoverton. He says from
about the same distance, others heard a crackling that reminded them of
a blowtorch.
Officials say they had no reports of injuries. El Paso Corp., which
operates Tennessee Gas Pipeline, says one house was damaged.
Company spokesman Richard Wheatley says the explosion involved the
``failure'' of a 36-inch, buried transmission line that carries natural
gas through the region.
______
LEX 18--Posted: Sep 21, 2011 5:25 AM--Updated: Sep 21, 2011 7:26 AM
Clark Co. Gas Line Rupture Heard Several Counties Away
People across several counties heard the rumbling sound early
Wednesday morning. It shook the ground and rattled windows.
A gas line ruptured just after midnight in Clark County, near the
Powell County line. People as far away as Lee County heard the noise,
and the LEX 18 newsroom was flooded with calls.
Herman Cole lives nearby.
``All I heard was a big pop sound and a big roar sound. I thought
it was a motorcycle outside my door. So it was pretty loud,'' he said.
``It was really roaring and it got louder and louder. No major
explosion or anything,'' he said.
The rupture occurred in a commercial transmission line near Irvine
Road. It took crews several hours to find the break and shut off the
flow of gas. But officials say there was never an actual explosion.
There were no injuries or evacuations, and since the line does not
serve the public, there was no interruption of service.
Crews from the Tennessee Gas Company continue working to inspect
and repair the line. Officials with the company have not given a
timetable for repairs.
Fire officials say this wasn't the first incident involving these
particular gas lines. There was a rupture four years ago and a deadly
incident 50 years back.
Senator Lautenberg. Thank you very much, Senator Boxer. And
we welcome our colleague, Senator Dianne Feinstein.
Senator Feinstein's a strong advocate for improving
pipeline safety, and she's committed to ensuring that we do
everything that we can to avoid tragedies like what we
witnessed in San Bruno in the pictures that we just witnessed
saw here that tell us about the horror of these things.
Again, fortunately in the big New Jersey explosion, we
didn't have the fatality consequences that you had in
California.
But there are terrible consequences when this happens, and
we look forward to hearing your views, Senator Feinstein.
STATEMENT OF HON. DIANNE FEINSTEIN,
U.S. SENATOR FROM CALIFORNIA
Senator Feinstein. Thank you very much, Mr. Chairman,
Senator Wicker, my friend and colleague, Senator Boxer.
I think Senator Boxer's statement really expressed it very
well.
I happened to be at home around the evening news time,
turned on the news, and saw this explosion. And I watched it,
and I watched it for 10 minutes, 15 minutes, a half-hour, 45
minutes, an hour, an hour and 39 minutes.
What was interesting is the explosion didn't abate. And
there was a lot of discussion--did a plane, taking off from San
Francisco International, crash there? What happened? And no one
really knew.
Well, I went to the scene on the Sunday after the explosion
with then-CEO and Chairman of PG&E, and looked at the scene,
and it was one of--as Senator Boxer's chart showed--absolute
devastation, with people who were shocked and shattered and
couldn't believe that this huge transmission line was running
right under the streets of a residential subdivision.
We actually saw the part of the line, and so you could see
the outside weld. One of the problems was the weld was only on
one side, and it went both circularly as well as
longitudinally.
So there were a number of questions. First: how did a
pipeline, owned and operated by a 106-year-old utility, and
regulated by the California Public Utilities Commission, in
compliance with Federal safety standards, blow up without
warning? And second: why did the fire rage so long?
The National Transportation Safety Board--that's an agency
that continues to impress me. They're straightforward, there is
no guile, they say it like it is, and they're really to be
commended.
Well, they've completed an investigation of the explosion,
and the report concludes that the pipeline failed along a
faulty and incomplete seam weld, when pressure spiked to
unusually high levels.
The NTSB found this accident could have been prevented. And
I think that's what is important to us. And the report reaches
a simple conclusion: no one knew whether the pipeline under San
Bruno was safe--not the utility, not the state regulators, and
not the Federal regulators.
The first problem was that PG&E's records of the pipeline
under San Bruno were wrong. They showed a seamless pipe, when
in fact the pipe had a seam. Because no seam was recorded, the
strength of that seam was never inspected.
Second, because the pipe was installed before 1970, when
pressure testing for new pipes was established, the pipeline
had never undergone a strength test, a pressure test.
Like 61 percent of all pipelines in the United States, the
pipeline had been grandfathered. Sixty-one percent of all
pipelines have been grandfathered, meaning regulators and the
industry assumed it was safe to continue operating the pipeline
at pressures used in the past.
No safety buffer was established, as would have been
established during a normal pressure test that pushes the pipe
to 125 percent of the approved maximum allowable operating
pressure.
In fact though, the San Bruno pipe failed when pressure
spiked just above the historic operating levels, and far less
than 125 percent above historic operating levels.
The third problem was that the pipeline had never undergone
an inline inspection with a smart pig. A smart pig may have
found both the existence of the unreported seams as well as
their faults.
Like many older pipelines, this pipe had too many twists
and turns to be inspected, and had never been upgraded to allow
for such an inspection.
Fourth, the pipeline had inaccessible manual shutoff
valves. First responders didn't know how to cut off the gas,
and utility employees were stuck in traffic as the inferno
raged, devastating a once idyllic neighborhood.
So, let me be clear. The problems that led to tragedy in
San Bruno are not unique to that neighborhood, or that
pipeline. They are widespread throughout the United States.
Many older pipelines in urban areas have inaccurate and
incomplete records, have never been pressure tested, or
inspected by smart pigs, and lack automatic or remote control
shutoff valves capable of limiting damage following a rupture.
At the NTSB's recommendation, California law--Governor
Brown has just signed it--requires now that utilities
throughout the state establish a traceable, verifiable, and
complete set of pipeline records.
Thus far, utilities throughout the state have found
incomplete records for as much as 30 percent of the system. So
almost a third of the system, with 38 million people in it,
have no records.
I really thank the Committee for including in its pipeline
safety bill a nationwide review, which Senator Boxer and I
proposed in our bill. I think this will go a long way, and I
want to thank you for it.
The NTSB also found that 61 percent of all transmission
pipelines in America were grandfathered from current pipeline
strength tests, such as hydrostatic pressure tests under DOT
regulations. So, 61 percent is grandfathered.
I'm pleased that the Committee has accepted the amendment
worked out with Senator Paul requiring that all pipelines that
have never undergone a pressure test undergo a viable and
effective strength test.
These tests would verify the safety of current maximum
allowable operating pressures, and establish pressure safety
buffers on older pipes for the very first time.
The Department of Transportation should also consider
ordering untested pipelines to lower their pressures to
establish a safety buffer, as the California Public Utilities
Commission has chosen to do.
The bill would also require deployment of automatic shutoff
valves on new and replacement pipes. I believe we should
require these valves on all pipelines, as California has done
now. But requiring them on new pipes is at least a step in the
right direction.
Bottom line: the San Bruno tragedy may have been prevented
had the seams been properly recorded and inspected, or had the
pipeline strength ever been established with a pressure test.
And, as you know, and I had the pleasure of talking with
the new CEO this morning, Mr. Early, and there's another
problem, and it's plastic pipe. And there's 1,200 miles of
PG&E's plastic pipe that the company is now going to pull.
I believe there have been some 11 accidents with this pipe,
that, as Mr. Early described to me this morning, under
pressure--underground for some period of time--that pipe
becomes brittle, and therefore a rock, a change in the ground,
can rupture it and then you have a gas leak.
And so there have been, I think, 11 accidents in California
from that pipe. So I would just like to say to this committee,
first of all, I think your first step has at least been
partially accomplished--the bill was hot lined, it has passed
the Senate. I think that's very good news.
But I would really encourage you to look further. This is
expensive for the companies, and I know it's expensive for
them, but we're earthquake country, with 38 million people.
These pipes are all underground. They're in dense places--you
know, all throughout San Francisco, a relatively old city when
it comes to cities in California.
So there are a lot of reasons to worry about this, and I
think there are a lot of reasons to continue to do
extraordinary due diligence on this particular issue.
So, Senators, the three of you have made a major step
forward and I, for one, am very grateful and I thank you.
[The prepared statement of Senator Feinstein follows:]
Prepared Statement of Hon. Dianne Feinstein,
U.S. Senator from California
I happened to be at home around the evening news time, turned on
the news and saw this explosion. And I watched it. And I watched it for
10 minutes, 15 minutes, a half hour, 45 minutes, an hour, an hour and
39 minutes.
What's interesting is the explosion didn't abate. There was a lot
of discussion: Did a plane taking off from San Francisco International
crash there? What happened? And no one really knew.
Well, I went to the scene on the Sunday after the explosion with
the then-CEO and Chairman of PG&E, and looked at the scene and it was
one of--as Senator Boxer's chart showed--absolute devastation, with
people who were shocked and shattered and couldn't believe that this
huge transmission line was running right under the streets of a
residential subdivision.
We actually saw the part of the line and you could see the outside
weld. One of the problems was the weld was only on one side and it went
both circularly as well as longitudinally.
So there are a number of questions.
First, how did a pipeline owned and operated by a 106-year-old
utility and regulated by the California Public Utilities Commission--in
compliance with Federal safety standards--blow up without warning?
And second, why did the fire rage so long?
The National Transportation Safety Board--and that's an agency that
continues to impress me, they're straightforward, there's no guile,
they say it like it is, and they're really to be commended--well,
they've completed an investigation of the explosion. And the report
concludes that the pipeline failed along a faulty and incomplete seam-
weld when pressure spiked to unusually high levels.
The NTSB found this accident could have been prevented, and I think
that's what is important to us.
And the report reaches a simple conclusion: No one knew whether the
pipeline under San Bruno was safe. Not the utility, not the state
regulators and not the Federal regulators.
The first problem was that PG&E's records of the pipeline under San
Bruno were wrong. They showed a seamless pipe when in fact the pipe had
a seam. Because no seam was recorded, the strength of that seam was
never inspected.
Second, because the pipe was installed before 1970--when pressure
testing for new pipes was established--the pipeline had never undergone
a strength test, a pressure test.
Like 61 percent of all pipelines in the United States, the pipeline
had been grandfathered. Sixty-one percent of all pipelines have been
grandfathered, meaning regulators and the industry assumed it was safe
to continue operating the pipeline at pressures used in the past.
No safety buffer was established, as would have been established
during a normal pressure test that pushes the pipe to 125 percent of
the approved Maximum Allowable Operating Pressure.
In fact though, the San Bruno pipe failed when pressure spiked just
above the historic operating levels, and far less than 125 percent
above historic operating levels.
The third problem was that the pipeline had never undergone an
inline inspection with a smart pig. A smart pig may have found both the
existence of the unreported seams as well as their faults. Like many
older pipelines, this pipe had too many twists and turns to be
inspected and had never been upgraded to allow for such an inspection.
Fourth, the pipeline had inaccessible manual shutoff valves. First
responders didn't know how to cut off the gas and utility employees
were stuck in traffic as the inferno raged, devastating a once-idyllic
neighborhood.
So let me be clear: The problems that led to tragedy in San Bruno
are not unique to that neighborhood or that pipeline. They are
widespread throughout the United States.
Many older pipelines in urban areas have inaccurate and incomplete
records, have never been pressure tested or inspected by smart pigs,
and lack automatic or remote-controlled shutoff valves capable of
limiting damage following a rupture.
At the NTSB's recommendation, California law--and Governor Brown
has just signed it--requires now that utilities throughout the state
establish a traceable, verifiable and complete set of pipeline records.
Thus far, utilities throughout the state have found incomplete records
for as much as 30 percent of the system. So almost a third of the
system with 38 million people in it have no records.
I really thank the Committee for including in its pipeline safety
bill a nationwide review, which Senator Boxer and I proposed in our
bill. I think this will go a long way and I want to thank you for it.
The NTSB also found that 61 percent of all transmission pipelines
in America were grandfathered from current pipeline strength tests,
such as hydrostatic pressure tests, under DOT regulations. So, 61
percent is grandfathered.
I am pleased that the Committee has accepted the amendment worked
out with Senator Paul requiring that all pipelines that have never
undergone a pressure test undergo a viable and effective strength test.
These tests would verify the safety of current maximum allowable
operating pressures and establish pressure safety buffers on older
pipes for the very first time.
The Department of Transportation should also consider ordering
untested pipelines to lower their pressures to establish a safety
buffer, as the California Public Utilities Commission has chosen to do.
The bill would also require deployment of automatic shutoff valves
on new and replacement pipes. I believe we should require these valves
on all pipelines, as California has done now, but requiring them on new
pipes is at least a step in the right direction.
Bottom line: the San Bruno tragedy may have been prevented had the
seams been properly recorded and inspected, or had the pipeline
strength ever been established with a pressure test.
And as you know, and I had the pleasure of talking with the new CEO
this morning, Mr. Early, and there is another problem, and it is
plastic pipe. There are 1,200 miles of PG&E's plastic pipe that the
company is now going to pull. I believe there have been some 11
accidents with this pipe that, as Mr. Early described to me this
morning, under pressure, underground for some period of time, that pipe
becomes brittle. And therefore a rot, a change in the ground can
rupture it and then you have a gas leak. And so there have been I think
11 accidents in California from that pipe.
So I would just like to say to this committee, first of all, I
think your first step has been at least been partially accomplished.
The bill was hotlined, it has passed the Senate, I think that is very
good news.
But I would really encourage you to look further. This is expensive
for the companies, and I know it's expensive for them. But, we're
earthquake country. We have 38 million people. These pipes are all
underground, they're in dense places. All throughout San Francisco, a
relatively old city when it comes to cities in California.
So there are a lot of reasons to worry about this and I think there
are a lot of reasons to really to continue to do extraordinary due
diligence on this particular issue.
So senators, the three of you have made a major step forward. And
I, for one, am very grateful, and I thank you.
Senator Lautenberg. Senator Feinstein, my little state
doesn't compare in population numbers, but in population
density we win the prize. And thusly, if something happens in
New Jersey, it invariably affects a lot of people.
And this explosion we had, I mentioned, 14 buildings were
destroyed. Luckily, we had a fatality that resulted from a
health condition the person was having, but this is too heavy
of a hazard to just be lying there ready to pop open when the
pressure, as you indicated, gets high enough.
So, thank you very much, and we'll certainly excuse you and
continue to work together with our colleagues here to make sure
that we get as much of a bill as we possibly can here.
I think we've got a good start, and having crossed the
Capitol is a giant step. But our work is not over by a long
shot.
Senator Feinstein. Thank you.
Senator Boxer. Can I say one thing before Senator leaves?
Senator Lautenberg. Please.
Senator Boxer. I just wanted to say one thing to my friend
and colleague. I remember right after this explosion we had a
hearing here, and we were so bound and determined to do
something. And I just wanted to add my voice of thanks to
Senators Lautenberg and Wicker, and the rest of the Committee,
and Chairman Rockefeller'--though he's not here.
I mean, they really moved heaven and earth. We know how
hard it is for a bill to become a law--it's not as easy as it
sounds in the textbooks. It takes a lot of perseverance and a
lot of people have to help us.
So I wanted to join you in thanking this committee for its
work. And I know if we keep this bipartisanship going, we'll do
a lot more in this arena. And I thought that your testimony was
absolutely right on the mark. Thank you.
It was a ``ten'' as you would say.
[Laughter.]
Senator Lautenberg. And I point out that it was unanimously
passed, and I credit that thusly to Senator Wicker for being
forthcoming and silent at the right time.
[Laughter.]
Senator Feinstein. Thank you, Senators. Thank you very
much.
Senator Lautenberg. And now we are calling the witnesses to
the table. Each one brings significant experience and expertise
to the issue of pipeline safety.
Cynthia Quarterman, Administrator of the Pipeline Hazardous
Materials Safety Administration--she's going to be discussing
her agency's work to improve pipeline safety in the United
States.
Deborah Hersman, Chairman of the National Transportation
Safety Board, will update us on her agency's review of recent
pipeline accidents.
Mr. Nick Stavropoulos is Executive Vice President of
Pacific Gas and Electric. And he's going to discuss his
company's response to the San Bruno explosion.
And Rick Kessler, Vice President of the Pipeline Safety
Trust organization.
Donald Santa Jr., President and CEO of Interstate National
Gas Association of America.
Christina Sames is Vice President of Operations and
Engineering for the American Gas Association.
And I thank all of you for coming today and we're going to
try to adhere to the 5-minute rule. So, please let us hear from
you, and I will not put the brakes on too fast, but I will put
them on.
We look forward to hearing testimony and we would first ask
Ms. Quarterman to give us her views.
STATEMENT OF HON. CYNTHIA L. QUARTERMAN,
ADMINISTRATOR, PIPELINE AND HAZARDOUS
MATERIALS SAFETY ADMINISTRATION,
U.S. DEPARTMENT OF TRANSPORTATION
Ms. Quarterman. Chairman Lautenberg, Ranking Member Wicker,
and members of the Subcommittee, thank you for providing me
with the opportunity to discuss our Nation's pipeline safety
program.
I would also like to congratulate the Senate for
unanimously passing Senate Bill 275 regarding pipeline safety
last night. This bill will strengthen our oversight and
regulatory enforcement authority.
As you know, just over a year ago, a tragic pipeline
incident occurred in San Bruno, California, resulting in
serious consequences. This incident, and other recent pipeline
incidents, demonstrate that, while our Nation's pipeline
infrastructure is an efficient means of transporting energy, we
need to be more vigilant in preventing pipeline failures and
minimizing the severity of failures that do occur.
My testimony today focuses on several issues relevant to
the San Bruno accident, the Department's plan to address the
safety issues raised by that incident, and legislation that
will help them address these issues.
PHMSA has preemptive regulatory authority over interstate
pipeline facilities under the pipeline safety laws, but states
are permitted to regulate the safety standards and practices
for intrastate pipeline facilities.
The California Public Utility Commission serves as the
principal regulator of intrastate gas pipelines in California.
PHMSA provides funding to the CPUC, and conducts annual audits
to review the use of those funds. PHMSA also conducts field
audits and annual performance reviews of the CPUC's gas
pipeline safety program. PHMSA accepts full responsibility for
administering the state pipeline certification program.
In light of recent incidents, including the San Bruno
pipeline failure, we will be conducting a full and
comprehensive review of our state program, including the CPUC's
oversight.
PHMSA, CPUC, and the National Transportation Safety Board
acted quickly after the explosion to organize a coordinated
response and launch an investigation. In the months since the
incident, PHMSA has provided subject matter expertise, advice,
and counsel in support of both the NTSB and the CPUC.
As a result of the San Bruno pipeline failure, PHMSA has
conducted a thorough review of its regulations, policies,
programs, and procedures.
Even though this incident and failure investigation fall
within the purview of the state of California, it has prompted
PHMSA to take a fresh look at ways to strengthen Federal
regulations that must be adopted by our state partners, and to
reexamine our role in auditing and funding state pipeline
programs.
This review has led to a number of new initiatives. For
example, in November of 2010, PHMSA issued an advisory bulletin
to remind operators of gas and hazardous liquid pipeline
facilities, that they must make their pipeline emergency
response plans available to local emergency responders.
This April, Secretary LaHood issued a Call to Action to
pipeline safety stakeholders asking pipeline owners and
operators to conduct a comprehensive review of their oil and
gas pipelines to accelerate the repair, rehabilitation, or
replacement of the highest-risk pipelines.
In July, PHMSA held workshops on managing challenges with
seam failures and improving pipeline risk assessment and record
keeping.
And in August, PHMSA issued an advanced notice of proposed
rulemaking on improving the safety of onshore gas transmission
lines, which encompasses many of the NTSB's recommendations.
During my time as administrator, PHMSA has also conducted
an internal and independent audit of its state certification
program.
The NTSB recently issued its pipeline accident report for
the San Bruno pipeline failure. In addition to the actions
already planned, my written testimony identifies several other
planned actions.
While PHMSA is confident that it already has the authority
to fully respond to the San Bruno pipeline failure, and address
NTSB's recent recommendations, the pipeline safety bill passed
by the Senate yesterday will help us to address some other
issues.
In particular, the bill includes provisions to increase the
maximum administrative civil penalty, to increase the number of
pipeline safety inspectors, and to address gaps in current
statutory authority. The incentives in this bill are very
similar to the legislation that the administration transmitted
to Congress last fall and earlier this year.
And PHMSA is pleased to see bipartisan support for such an
important issue. Mr. Chairman, members of the Subcommittee, I
assure you that PHMSA, through appropriate regulation and
oversight, will issue--will use its full enforcement authority
to ensure that operators meet pipeline safety standards.
In the meantime, I thank you for moving forward on your
pipeline safety reauthorization bill. Thank you.
[The prepared statement of Ms. Quarterman follows:]
Prepared Statement of Hon. Cynthia L. Quarterman, Administrator,
Pipeline and Hazardous Materials Safety Administration, U.S. Department
of Transportation
Chairman Lautenberg, Ranking Member Wicker, and members of the
Subcommittee, thank you for providing me with the opportunity to
discuss our Nation's pipeline safety program.
As you know, thirteen months ago a tragic pipeline accident
occurred in San Bruno, California, resulting in eight deaths, numerous
injuries, and the destruction of 38 homes. This accident and other
recent pipeline failures demonstrate that while our Nation's pipeline
infrastructure is an efficient means of transporting energy, we need to
be ever vigilant in seeking to prevent pipeline failures and to
minimize the number and severity of failures that do occur.
My testimony today will focus on several issues relevant to the San
Bruno accident and the Department's plan for addressing the safety
issues raised by that accident. First, I will provide an overview of
the pipeline safety program, including the role of States in ensuring
the safety of intrastate gas pipelines. Second, I will discuss the
actions that PHMSA has already taken to address some of the factors
that caused or contributed to the San Bruno accident. Third, I will
provide our preliminary responses to the National Transportation Safety
Board (NTSB) Accident Report. Last, I will briefly discuss some of the
critical provisions in the pending pipeline safety reauthorization bill
that will further enhance our statutory authority to prevent pipeline
accidents. I thank you for moving forward with that legislation and
look forward to its presentation to the full Senate.
Pipeline Safety Program
Congress has authorized Federal regulation of the safety of gas and
hazardous liquid pipelines and liquefied natural gas (LNG) facilities
in the pipeline safety laws (49 U.S.C. Sec. Sec. 60101 et seq.), a
series of statutes that are administered by the U.S. Department of
Transportation (Department), Pipeline and Hazardous Materials Safety
Administration (PHMSA). PHMSA has used that authority to prescribe the
pipeline safety regulations, a set of minimum Federal safety standards
for the design, construction, testing, operation, and maintenance of
such facilities (49 C.F.R. Parts 190-199).
PHMSA has preemptive regulatory authority over interstate pipeline
facilities under the pipeline safety laws, but the States (including
Puerto Rico and the District of Columbia) are permitted to regulate the
safety standards and practices for intrastate pipeline facilities. The
States must submit an annual certification to PHMSA to exercise that
authority. The States can also receive authorization from PHMSA to
serve as an agent for inspecting interstate pipeline facilities. PHMSA
can reject a certification or terminate an agreement if a State is not
taking satisfactory action to ensure pipeline safety.
Most State pipeline safety programs are administered by public
utility commissions. As noted above, these State authorities are
required to adopt the Federal pipeline safety regulations as part of
the certification process, but can establish more stringent safety
standards for intrastate pipeline facilities. PHMSA is prohibited by
statute from regulating the safety standards or practices for an
intrastate pipeline facility if and to the extent that a State has a
current certification to regulate such facilities (49 U.S.C.
Sec. 60105(a)).
The California Public Utilities Commission (CPUC) serves as the
principal regulator of intrastate gas pipelines in California, having
obtained that authority by submitting an annual certification to PHMSA.
As a certified State authority, CPUC has complied with its obligation
to adopt the minimum Federal gas pipeline safety standards and drug and
alcohol testing requirements. CPUC has also exercised its discretion to
establish supplementary state pipeline safety standards, including
additional reporting requirements for the construction of new and
reconditioning of existing pipelines and for proposed increases in the
maximum allowable operating pressure (MAOP) of higher stress pipelines;
and additional leak survey and valve maintenance requirements for gas
distribution systems. Following the San Bruno accident, CPUC adopted
additional pressure testing requirements for verifying the MAOP of
older intrastate gas transmission lines and determining whether those
pipelines need to be replaced.
PHMSA provides funding to the CPUC through the grant allocation
formulas listed in 49 C.F.R. Part 198 and conducts frequent audits to
review the use of these funds. PHMSA also conducts field audits and
annual performance reviews of the CPUC's gas pipeline safety program.
With the exception of Alaska and Hawaii, state pipeline safety
agencies are the first line of defense in assuring the safety of
intrastate gas pipelines in American communities. States have always
been the cornerstone of the pipeline safety program on intrastate gas
pipelines. States are responsible for oversight of virtually all gas
distribution pipelines, gas gathering pipelines and intrastate gas
transmission, as well as serving as our agents for 20 percent of the
interstate gas pipelines. PHMSA maintains primary responsibility for
the remaining gas pipelines. States employ approximately 63 percent of
the total pipeline inspector workforce.
PHMSA accepts full responsibility for administering the state
pipeline certification program. In light of recent accidents, including
the San Bruno pipeline failure, we will be conducting a full and
comprehensive review of our state program.
San Bruno Pipeline Failure
The San Bruno pipeline accident, which occurred on September 9,
2010, involved the rupture of Line 132, a 30-inch natural gas
intrastate transmission line operated by the Pacific Gas and Electric
Company and regulated by CPUC.
PHMSA, CPUC, and the National Transportation Safety Board (NTSB)
acted quickly after the explosion to organize a coordinated response
and launch an investigation. The first PHMSA investigator arrived on
the scene on September 10, and a second PHMSA investigator arrived
three days later. Shortly thereafter, I personally visited the accident
site, where I witnessed the devastating consequences of the accident
firsthand and met with counterparts from NTSB, the CPUC, and other
State regulatory agencies.
In the months since the accident, PHMSA has provided subject matter
expertise, advice, and counsel in support of NTSB and CPUC, including
the dedication of staff and resources from our offices in Ontario,
California; Denver, Colorado; Kansas City, Missouri; and Washington,
D.C.
PHMSA Initiatives and Actions
PHMSA has conducted a thorough review of its regulations, policies,
programs, and procedures as a result of the San Bruno pipeline failure.
Even though this accident and failure investigation fall within the
purview of the State of California, it has prompted PHMSA to take a
fresh look at ways to strengthen Federal regulations that must be
adopted by our state partners and to reexamine our role in auditing and
funding state pipeline programs.
This review has led to a number of new initiatives, including:
November 2010 HMSA issued an Advisory Bulletin to remind
operators of gas and hazardous liquid pipeline
facilities that they must make their pipeline
emergency response plans available to local
emergency response officials. PHMSA recommended
that operators provide their emergency response
plans to officials through their required public
awareness liaisons and activities. PHMSA also
stated that it will be evaluating the extent to
which operators have provided their emergency
plans to local emergency officials during
upcoming public awareness inspections scheduled
through December 31, 2012.
January 2011 PHMSA issued an Advisory Bulletin to remind
operators of gas and hazardous liquid pipeline
facilities of their responsibilities under the
Federal integrity management (IM) regulations to
perform detailed threat and risk analyses that
integrate accurate data and information from
their entire pipeline system, especially when
calculating Maximum Allowable Operating Pressure
(MAOP) or Maximum Operating Pressure (MOP). PHMSA
also reiterated that operators must utilize these
risk analyses in the identification of
appropriate IM assessment methods, and
preventative and mitigative measures.
April 2011 Following several fatal pipeline accidents,
including one that killed five people in
Allentown, PA, Secretary LaHood issued a Call to
Action on Pipeline Safety asking pipeline owners
and operators to conduct a comprehensive review
of their oil and gas pipelines to identify areas
of high risk and accelerate critical repair and
replacement work. Secretary LaHood also called on
Congress to pass Federal legislation aimed at
strengthening oversight on pipeline safety and
holding operators accountable for pipeline
violations. Secretary LaHood also launched a new
webpage to provide the public--as well as
community planners, builders and utility
companies--with clear and easy to understand
information about their local pipeline networks.
April 2011 PHMSA assisted CPUC in performing a review of the
Risk Assessment and Threat Identification portion
of its Gas Integrity Management Audit of PG&E.
July 2011 PHMSA and the National Association of Pipeline
Safety Representatives (NAPSR) held a workshop,
entitled ``Improving Pipeline Risks Assessments
and Recordkeeping,'' to exchange information on
identifying threats and improving risk
assessments and record keeping for onshore
pipelines. More than 560 representatives from
U.S. and Canadian pipeline safety regulatory
agencies, state agencies, standards developing
organizations, technology vendors, service
providers, pipeline operators, trade
organizations, steel pipeline manufacturers,
independent contractors and the general public
attended in person and via webcast. The panelists
discussed the critical need for an accurate
pipeline-specific risk assessment illustrating
that good data supports effective integrity
programs and that recent pipeline incidents are
raising concern over operator risk assessments.
The panelists also highlighted some of the major
aspects of risk assessment that continue to need
improvement, including addressing interactive
threats, vintage/legacy pipe, recordkeeping, and
data integration.
July 2011 PHMSA and NAPSR held a workshop, entitled
``Managing Challenges with Pipeline Seam Welds,''
to exchange information as part of a multi-year
research effort on the integrity of pipeline seam
welds. More than 250 representatives from U.S.
and Canadian pipeline safety regulatory agencies
and State/Provincial agencies, standards
developing organizations, technology vendors,
service providers, pipeline operators, trade
organizations, steel pipeline manufacturers,
independent contractors and the general public
attended in person and via webcast. The forum
facilitated discussion on how anomalies in seam
welds are identified and managed. Panelists
agreed that hydrotesting was the preferred method
to find threats in seam welds for most operators,
but recent improvements with in-line inspection
technology were noted as well. Actions taken by
regulators and standards developing organizations
have also kept a focus on mitigating threats
associated with seam weld defects.
August 2011 PHMSA issued an Advance Notice of Proposed
Rulemaking (ANPRM) on improving the safety of
onshore gas transmission lines. PHMSA is seeking
public comment on the following potential
regulatory changes: repealing the regulatory
exemption from the hydrostatic pressure testing
requirements for pipelines installed prior to
1970; revising the definition of a high-
consequence area (HCA); imposing additional
restrictions on the use of certain pipeline
assessment methods; revising the requirements for
mainline valves, including valve spacing and
installation of remotely operated or
automatically operated valves; modifying the
corrosion control requirements for steel
pipelines; revising the requirements for
collecting, validating, and integrating pipeline
data; and adopting new requirements for
management of change and quality control.
During my time as Administrator, PHMSA has also initiated two
separate audits of its state certification program. The results of
these audits will be considered in making future improvements to this
program.
National Transportation Safety Board Pipeline Accident Report
The National Transportation Safety Board (NTSB) recently issued its
Pipeline Accident Report for the San Bruno pipeline failure. NTSB found
that the probable cause of the accident was (1) inadequate quality
assurance and quality control by PG&E during its relocation of Line 132
in 1956, which allowed the installation of a substandard and poorly-
welded pipe section with a visible seam weld flaw to grow to a critical
size and cause the pipeline to rupture 54 years later during a pressure
increase stemming from poorly-planned electrical work at the Milpitas
Terminal; and (2) an inadequate pipeline integrity management program,
which failed to detect and repair or remove the defective pipe section.
NTSB further found that CPUC and DOT contributed to the accident by
failing to require hydrostatic pressure testing of ``grandfathered''
gas pipelines and to detect the inadequacies in PG&E's pipeline
integrity management program. NTSB also found that the lack of either
automatic shutoff valves or remote control valves on Line 132, and
PG&E's flawed emergency response procedures and delay in isolating the
rupture to stop the flow of gas, contributed to the severity of the
accident.
NTSB issued new safety recommendations for the Secretary and PHMSA.
The Secretary will respond by:
Conducting an independent audit to evaluate the
effectiveness of PHMSA's oversight of its performance-based
safety standards, enforcement policies and procedures, and
annual state certification programs.
Ensuring that PHMSA takes appropriate action to address the
results of these audits.
In addition to the actions already taken, PHMSA will respond by:
Proceeding with the August 2011 ANPRM and issuing a notice
of proposed rulemaking with appropriate amendments to the gas
pipeline safety regulations.
Ensuring adequate implementation of PHMSA's new control room
and distribution integrity management requirements.
Reviewing PHMSA's drug and alcohol testing requirements and
proposing a clarifying amendment, if necessary.
Revising PHMSA's integrity management inspection protocols.
Issuing Advisory Bulletins on the development of pipeline
emergency response plans and performance of post-accident drug
and alcohol testing.
Holding additional forums on pipeline emergency response and
use of automatic shutoff valves and remotely controlled valves.
Assisting CPUC in conducting a comprehensive audit of its
state gas pipeline safety program and in performing an upcoming
evaluation of PG&E's Public Awareness Program.
Improving CPUC's understanding and enforcement of the
Integrity Management Requirements.
Consulting with NAPSR and the National Association of
Regulatory Utility Commissioners (NARUC) on ways to improve
State oversight of intrastate pipeline operators.
Legislation
While PHMSA is confident that it already has the authority to fully
respond to the San Bruno pipeline failure and address NTSB's recent
recommendations, we note that the Committee has passed legislation,
S.275, sponsored by Senators Rockefeller and Lautenberg, which will
assist the agency in these efforts. In particular, the bill includes
provisions to increase the maximum administrative civil penalties for
the most serious types of violations from $100,000 per day not to
exceed $1 million for a related series of violations to $250,000 per
day not to exceed $2.5 million for a related series of violations; on
the use of automatic shutoff valves and remotely-controlled valves,
increased public awareness of PHMSA inspection activities and
operator's emergency response plans, improved incident and accident
notification requirements for state and local officials and first
responders, State implementation of their pipeline safety programs, and
verification of pipeline records and confirmation of the MAOP of gas
pipelines. It would also provide authorization for the hiring of 39
additional employees. The initiatives in this bill are very similar to
the legislation the Administration transmitted to Congress last fall
and earlier this year.
Conclusion
Mr. Chairman, Members of the Subcommittee, I assure you that PHMSA,
through appropriate regulation and oversight, will use its full
enforcement authority to ensure that operators meet pipeline safety
standards. In the meantime, I thank you for moving forward on the
reauthorization bill and we look forward to the presentation of the
legislation to the full Senate.
Senator Lautenberg. Thank you very much.
Ms. Hersman, I call on you, please.
STATEMENT OF HON. DEBORAH A.P. HERSMAN, CHAIRMAN, NATIONAL
TRANSPORTATION SAFETY BOARD
Ms. Hersman. Good afternoon Chairman Lautenberg, Senator
Boxer, and committee staff. I'm joined today by NTSB staff who
produced the report, as well as members Sumwalt and Rosekind,
who are in the audience.
On October 30, the NTSB held its board meeting on the
pipeline rupture that occurred on September 9, 2010, in San
Bruno, California. As you've heard today, that accident killed
eight people, injured dozens more, and destroyed 38 homes.
The NTSB findings include flawed pipeline, flawed
operations, and flawed oversight. In total, the board issued
nearly 40 recommendations associated with this accident
investigation, including recommendations to improve
recordkeeping, eliminate the grandfathering of older pipelines,
install automatic or remote control shutoff valves, require in-
line inspections of pipelines, and improve risk-management
programs and their oversight.
I'd like to show a brief video that tells the story of this
accident investigation.
[The prepared statement of Ms. Hersman follows:]
Prepared Statement of Hon. Deborah A.P. Hersman, Chairman,
National Transportation Safety Board
Chairman Lautenberg, Ranking Member Wicker, members of the
Subcommittee, thank you for the opportunity to address you today
concerning the National Transportation Safety Board's (NTSB)
investigation and recently issued accident report on the pipeline
rupture and fire in San Bruno, California, 13 months ago. This tragic
accident was particularly devastating to the City of San Bruno and its
41,000 residents. It resulted in the deaths of eight people, 58
injuries, destroyed 38 homes, damaged 70 more homes, caused the
evacuation of many more residents from their homes.
Today, I will discuss the results of the NTSB's investigation and
its findings, probable cause determination, and series of far reaching
safety recommendations. Mr. Chairman, the troubling lessons learned
from the San Bruno pipeline rupture compel that all necessary steps be
taken to minimize the safety risks that underground pipelines present.
We also need to understand that the oil and gas pipeline network in
the United States is pervasive-consisting of 2.5 million miles--with a
significant amount of new pipeline design and construction activity
underway. The unacceptable safety risks present at San Bruno certainly
apply to aging pipelines but some of the NTSB's finding also extend to
newer pipelines, particularly in light of lax Federal and state
pipeline safety oversight and operators' ability to exploit regulatory
and enforcement deficiencies.
The Accident
On September 9, 2010, about 6:11 p.m. Pacific Daylight Time, a 30-
inch-diameter segment of an intrastate natural gas transmission
pipeline known as Line 132, owned and operated by the Pacific Gas and
Electric Company (PG&E), ruptured in the Crestmoor neighborhood in San
Bruno, California. The rupture occurred at mile point 39.28 of Line
132, at the intersection of Earl Avenue and Glenview Drive. The rupture
produced a crater about 72 feet long by 26 feet wide. The section of
pipe that ruptured, which was about 28 feet long and weighed about
3,000 pounds, was found 100 feet away from the crater. PG&E estimated
that the rupture released 47.6 million standard cubic feet of natural
gas-enough to serve 1,200 residential homes for 1 year--which ignited
and resulted in the intense and deadly fire.
More than 900 emergency responders from the City of San Bruno and
surrounding jurisdictions executed a coordinated emergency response.
Once the flow of natural gas was interrupted, this response included
defensive operations, search and evacuation, medical operations, and
firefighting operations that continued for 2 days. Overall, the
emergency response was well coordinated and effectively managed by
local responders.
However, PG&E took over 90 minutes to stop the flow of gas and to
isolate the rupture site--a response time that was excessively long and
contributed to the extent and severity of property damage and increased
the life-threatening risks to the residents and emergency responders.
The NTSB found that PG&E lacked a detailed and comprehensive procedure
for responding to large-scale emergencies such as a transmission
pipeline break, including a defined command structure that clearly
assigns a single point of leadership and allocates specific duties to
supervisory control and data acquisition (SCADA) staff and other
involved employees. PG&E's SCADA system limitations caused delays in
pinpointing the location of the break. The use of either automatic
shutoff valves or remote control valves would have reduced the amount
of time taken to stop the flow of gas.
The NTSB's Investigation
The NTSB determined that the probable cause of the accident was
PG&E's (1) inadequate quality assurance and quality control in 1956
during its Line 132 relocation project, which allowed the installation
of the substandard and poorly welded pipe section with a visible scam
weld flaw that, over time grew to a critical size, causing the pipeline
to rupture during a pressure increase stemming from poorly planned
electrical work at PG&E's Milpitas Terminal where Line 132 originates--
approximately 39 miles south of where the rupture occurred; and (2) an
inadequate pipeline integrity management program, which failed to
detect and repair or remove the defective pipe section.
Contributing to the accident were the actions taken decades ago by
the pipeline safety regulator within the state of California, the
California Public Utilities Commission (CPUC), and the U.S. Department
of Transportation (DOT) to grandfather pre-1961 and pre-1970 pipelines,
respectively, from the regulatory requirement for pressure testing,
which likely would have detected the installation defects. Also
contributing to the accident was the CPUC's failure to detect the
inadequacies of PG&E's pipeline integrity management program.
Additionally contributing to the severity of the accident were the lack
of either automatic shutoff valves or remote control, valves on the
line and PG&E's flawed emergency response procedures that delayed the
isolation of the rupture to stop the flow of gas.
The NTSB's investigation found that the rupture of Line 132 was
caused by a fracture that originated in the partially welded
longitudinal seam of one of six short pipe sections, which are known as
``pups.'' The fabrication of five of the pups in 1956 during the
relocation of Line 132 would not have met generally accepted industry
quality control and welding standards today or at the time of
installation, indicating that those standards were either overlooked or
ignored. The weld defect in the failed pup would have been visible when
it was installed. The investigation also determined that a sewer line
installation in 2008 near the rupture did not damage the defective
pipe.
Even prior to completion of the San Bruno investigation, in early
January of this year, the NTSB issued six safety recommendations to
PG&E and CPUC--five of which were designated as ``Urgent.'' One
``Urgent'' safety recommendation was also issued to the Pipeline and
Hazardous Materials Safety Administration (PHMSA). These safety
recommendations pointed out the need for PG&E to address inaccuracies
in its records for the accident pipe, including the need to search
aggressively and diligently for records concerning the pipeline system
components for PG&E natural gas transmission pipelines in high
consequence areas that had not had a maximum allowable operating
pressure established through hydrostatic pressure testing. Also, after
the NTSB's investigative hearing on the accident, it issued two
additional recommendations to PHMSA regarding issuing guidance to
pipeline operators on the importance of sharing system-specific
information with emergency response agencies and one recommendation to
PG&E to require its SCADA operators to notify immediately the
appropriate 9-1-1 emergency call center when there is a possible
pipeline rupture.
Unfortunately, the NTSB had seen these problems at PG&E before.
Several deficiencies revealed by the NTSB investigation, such as PG&E's
poor quality control during the pipe installation and inadequate
emergency response, were also factors in the 2008 explosion of a PG&E
gas pipeline in Rancho Cordova, California and a 1981 PG&E gas pipeline
leak in San Francisco that were also investigated by the NTSB. In
Rancho Cordova, PG&E installed the wrong pipe, and its emergency
response was inadequate with PG&E dispatching untrained personnel. In
the San Francisco accident, PG&E's inaccurate record-keeping, dispatch
of personnel who were not trained or equipped to close valves, and
unacceptable delays in shutting down the pipeline led to the flow of
natural gas from a ruptured pipeline lasting for over 10 hours.
More importantly, the NTSB's accident report, adopted on August 30,
depicts PG&E's longstanding multiple deficiencies in its operational
procedures and management controls and failure.to recognize and correct
them as key factors leading to the persistence and growth of hazardous
circumstances over time until an accident occurs--in this case, a
rupture of a 30-inch pipeline. These higher-order, or organizational
accident factors, which the NTSB views as a systemic problem, must be
addressed to improve PG&E's safety management practices. In general,
organizational accidents have multiple contributing causes, involve
people at numerous levels within a company, and are characterized by a
pervasive lack of proactive measures to ensure adoption and compliance
with a safety culture. Moreover, organizational accidents are
catastrophic events with substantial loss of life, property, and
environment; they also require complex organizational changes in order
to avoid them in the future.
Performance-Based Pipeline Safety Programs
In 2003, PHMSA promulgated gas pipeline safety regulations that
implemented various statutory requirements enacted the previous year.
PHMSA, with the support and assistance of the pipeline industry, added
to its prescriptive regulatory scheme a performance-based regulatory
scheme with broad performance goals as the basis for its pipeline
safety program, most notably with respect to integrity management
programs, and to a lesser extent, to public awareness programs. This
new regulatory scheme applies to gas transmission and distribution
systems and to hazardous liquid pipeline systems. Under performance-
based regulations, the fundamental premise is that an individual
pipeline operator knows its system best, and thereby is best able to
develop, implement, execute, evaluate, and adjust safety priorities and
measures. Within this regulatory framework, pipeline operators have a
great deal of flexibility and responsibility to develop their
individual programs and plans, determine the specific performance
standards, implement their plans and programs, and conduct periodic
self-evaluations that best fit their particular pipeline systems.
Integrity management programs for hazardous liquid and gas
transmission pipelines typically require operators to assess the
condition of their pipelines. Use of ``in-line'' inspection tools that
travel through the pipeline and pressure testing are two effective
methods to detect and identify internal defects, including the type of
weld defects that caused Line 132 to rupture. Prior to the accident, no
in-line inspections had been performed on Line 132. PG&E's pipeline
integrity management program, which should have ensured the safety of
the system, was deficient and ineffective because
it was based on incomplete and inaccurate pipeline
information;
did not consider the design and materials contribution to
the risk of a pipeline failure;
failed to consider the presence of previously identified
welded seam cracks in Line 132 as part of its risk assessment;
resulted in the selection of an examination method that
could not detect welded seam defects; and
used internal assessments of the program that were
superficial and resulted in no improvements.
The effectiveness of performance-based pipeline safety programs is
dependent on the diligence and accountability of both the operator and
the regulator--the operator for development and execution of its plan,
and the regulator for oversight of the operators. However, as is
evident in this investigation, the PG&E integrity management and public
awareness programs failed to achieve their stated goals because
performance measures were neither well defined nor evaluated with
respect to meeting performance goals. By overlooking the existence of,
and the risk from, manufacturing and fabrication defects under its
integrity management program, PG&E took no actions to assess risk and
ultimately was unaware of the internal defects that caused the rupture
of Line 132.
The NTSB's investigation also determined that CPUC failed to detect
the inadequacies in PG&E's integrity management program and that
PHMSA's integrity management inspection protocols need improvement.
Because PHMSA has not incorporated the use of effective and meaningful
metrics as part of its guidance for performance-based management
pipeline safety programs, its oversight of state public utility
commissions regulating gas transmission and hazardous liquid pipelines
could be improved. Without effective and meaningful metrics in
performance-based pipeline safety management programs, neither PG&E nor
CPUC was able to properly evaluate or assess PG&E's pipeline system.
NTSB'S Recommendations
In addition to the already discussed recommendations issued before
the final report was completed, the NTSB made 29 new safety
recommendations in its report, for an unusually high total of 39
recommendations stemming from this accident. Recommendation recipients
include the Secretary of Transportation, PHMSA, PG&E, CPUC, the
Governor of the State of California, the American Gas Association, and
the Interstate Natural Gas Association of America.
Four of the recommendations call on the Secretary of Transportation
to conduct audits of the effectiveness of PHMSA's oversight of
performance-based pipeline safety programs, its enforcement policies
and procedures, and its state pipeline safety certification and grant
programs. We addressed thirteen of our new recommendations to PHMSA.
These included:
requiring operators of natural gas transmission and
distribution pipelines and hazardous liquid pipelines to
provide more system-specific information to emergency
responders and communities where the pipelines are located and
to ensure their SCADA centers are equipped with tools to
immediately pinpoint the location of leaks and control room
operators immediately notify 9-1-1 emergency call centers when
a possible pipeline rupture is indicated.
amending the Pipeline Safety Regulations to require that
automatic shutoff valves or remote control valves be installed
in areas with the highest potential for risk; remove the
provision that exempts gas transmission pipelines constructed
before 1970 from hydrostatic testing to determine the line's
maximum allowable operating pressure; and require post-
construction hydrostatic pressure tests of at least 1.25 the
maximum allowable operating pressure in order for
manufacturing- and construction-related defects to be
considered stable.
requiring that all natural gas transmission pipelines be
configured so as to accommodate in-line inspection tools, with
priority given to older pipelines.
developing and implementing standards for integrity
management and other performance-based safety programs that
require operators of all types of pipeline systems to regularly
assess the effectiveness of their programs.
working with state public utility commissioners to implement
pipeline oversight programs that employ meaningful metrics
available in a centralized database and to identify and correct
deficiencies in these oversight programs.
The NTSB directed eight recommendations to PG&E that included:
establishing comprehensive emergency response procedures.
identifying the likelihood and consequence of failures
associated with planned work activities and developing
contingency plans.
expediting installation of automatic shutoff valves and
remote control valves in high consequence areas.
assessing every aspect of its integrity management program
and implementing a revised program that, at a minimum,
addresses issues including consideration of all defect and leak
data for the life of each pipeline, including its construction,
a revised risk analysis methodology, and an improved self-
assessment process.
The NTSB addressed two recommendations to the CPUC:
conduct a comprehensive audit of all PG&E's operations, with
assistance from PHMSA.
require PG&E to correct all deficiencies identified as a
result of the NTSB's San Bruno accident investigation, as well
as additional deficiencies identified as a result of the
recommended CPUC comprehensive audit, and verify that all
corrective actions are completed.
The NTSB also recommended that the Governor of the State of
California evaluate the authority and ability of CPUC's pipeline safety
division to enforce effectively state pipeline safety regulations and
that the American Gas Association and the Interstate Natural Gas
Association of America report to the NTSB on their progress in
developing and introducing advanced in-line inspection platforms for
use in gas transmission pipelines not currently accessible to existing
in-line inspection platforms.
Closing
The accident in San Bruno was a horrific and tragic event.
Particularly regrettable is the history of Federal and state
ineffectiveness in overseeing pipeline safety, identifying systemic
safety problems, and the lack of meaningful enforcement. Equally
troubling is the failure of the regulators to identify PG&E's safety
and emergency response deficiencies and carefully audit and inspect
pipeline operations even after past deficiencies had been identified
and documented. I believe if the NTSB recommendations are implemented,
the safety of pipelines and surrounding communities across the country
will be vastly improved so tl1at we are not investigating a similar
accident in the future.
This concludes my testimony, and I would be happy to answer any
questions you may have.
Senator Lautenberg. Mr. Stavropoulos, we'll call on you.
STATEMENT OF NICK STAVROPOULOS,
EXECUTIVE VICE PRESIDENT, GAS OPERATIONS,
PACIFIC GAS AND ELECTRIC COMPANY
Ms. Stavropoulos. Thank you, Mr. Chairman.
Good afternoon. My name is Nick Stavropoulos, Executive
Vice President of Gas Operations for PG&E. Thank you for this
opportunity, and thank you for your focus on this critical
issue.
As someone who has spent over 32 years in the natural gas
business, it's my view that it's never been more important to
reevaluate, reinforce, and reaffirm our collective focus on
pipeline safety.
The Pipeline Transportation Safety Act of 2011, approved by
this committee last night--approved by this committee and last
night by the full Senate--represents a major step in that
direction, and we at PG&E strongly support it. And we applaud
and thank the Committee for its leadership in advancing this
legislation.
Several serious accidents around the country have recently
underscored why this renewed attention on safety is so
important. And none of these--none of these--was more tragic
than the explosion and fire on our pipeline in San Bruno,
California: eight lives lost, many people badly burned and
injured, dozens of homes destroyed in a community that's been
changed forever.
No one can convey in words the full tragedy of September 9,
2010. What I hope to convey is our tremendous sorrow and our
profound sympathy to the families whose lives will never be the
same.
What we can also do is stand by our promise to help San
Bruno recover, and we can stand by our pledge to do everything
necessary to prevent another accident like this from ever
happening again.
That's our goal; that's our commitment. It's the charge
that I accepted when I joined PG&E in June of this year to run
the gas business. And I want to briefly outline some of the
steps we are now taking.
Many of those, of course, go directly to the important
recommendations that Chairman Hersman and the NTSB recently
issued, as well as priorities raised by Senator Boxer, Senator
Feinstein, and the leadership of this committee.
Chairman Hersman, I want to thank you for the meticulous
work by your team on the San Bruno investigation, and for the
recommendations in your final report, all of which PG&E fully
embraces.
I also want to share with the Committee that PG&E today is
announcing that former NTSB Chairman Jim Hall has agreed to be
an outside advisor to PG&E. He's going to help assure that the
steps we are taking are as responsive to the NTSB's
recommendations, and as effective as they can possibly be.
Chairman Hall will also be available to provide the
California Public Utilities Commission with independent reports
on our progress.
Broadly speaking, PG&E's efforts fall into several areas,
including verifying our records and conducting extensive
pressure testing to validate that our lines are running at safe
pressures, installing new equipment and technology to provide
better monitoring, and emergency shutoff capabilities such as
automated valves, retrofitting certain pipelines so they can be
inspected from inside using smart pigs, increasing our
information sharing with local communities including residents,
fire departments, and other local public safety officials, and
also adopting more rigorous work safety procedures to match and
surpass the best in the industry.
In all of these areas we're moving forward. We've
undertaken an unprecedented program to pressure test or replace
any pipe that doesn't have complete pressure test records, and
validate the safe pressures for all the pipelines through a
rigorous records-based analysis.
We've validated safe pressures on hundreds of miles of
lines throughout this documentation, and we're on track to
complete hydrotesting on as much as 160 miles of line this
year. And so far, all of our lines have fully passed our
hydrotests. We're also on track to install 29 automated shutoff
valves in key locations by the end of this year.
However, we know that we're on the front end of what must
be a longer-term effort to modernize our system, and really set
new standards for operational and public safety. That's why
we're working with the California regulators in an effort that
will make California pipeline safety requirements the toughest
and most comprehensive of any state in the country.
We recently presented our long-term pipeline safety
enhancement plan to the CPUC. The first phase is targeting
pipelines in highly populated areas that have vintage seam
wells that don't meet modern standards and that were
grandfathered under previous regulations and have not been
strength tested.
By the end of this first phase, PG&E plans to replace 186
miles of pipe, strength test more than 780 miles, retrofit
about 200 miles to permit inline inspections, and to install
228 automated valves.
We look forward to the California Commission's decision on
this plan. We believe that these measures are the right thing
to do, and it's the right time to do it. In the meantime, we
continue to move forward with the actions I mentioned earlier,
and we continue to do whatever is necessary to protect the
public safety.
Thanks again for this opportunity, and I'm pleased to be
available for questions.
[The prepared statement of Mr. Stavropoulos follows:]
Prepared Statement of Nick Stavropoulos, Executive Vice President,
Gas Operations, Pacific Gas and Electric Company
Good afternoon Chairman Lautenberg, Ranking Member Wicker, Senator
Boxer and other members of the Subcommittee. My name is Nick
Stavropoulos and I am executive vice president of Gas Operations for
Pacific Gas and Electric Company or PG&E. PG&E is one of the largest
combined natural gas and electric utilities in the United States.
Headquartered in San Francisco with nearly 20,000 employees, the
company delivers electricity and natural gas to approximately 15
million people in Northern and Central California. PG&E's extensive
natural gas system integrates more than 42,000 miles of natural gas
distribution lines and more than 5,700 miles of natural gas
transportation (or transmission) pipelines.
I want to thank you for providing me with the opportunity to be
here today to participate in this hearing on the current state of
pipeline safety following the San Bruno accident and other recent
pipeline incidents in other parts of the country.
The Committee's focus on this issue is critically important; the
events of the evening of September 9, 2010 are a stark reminder of
that. On that evening, PG&E's natural gas transmission line running
through the Crestmoor neighborhood of San Bruno, California ruptured
and the results were devastating. As has been widely reported, eight
people lost their lives and dozens of people were taken to local
hospitals and treated for serious burns and injuries. Thirty-eight
homes were destroyed and many more were damaged. In total, more than
375 households were forced to evacuate.
The 13 months since that accident have been an ordeal for the
Crestmoor community; most of us cannot truly comprehend what they
experienced that night and continue to go through today.
My heart goes out to all the families and people affected by this
tragedy. We know that it has been a long road to recovery and that it
is not over. We want to reiterate PG&E's commitment to stand by the
people and community of San Bruno. We have tried to do what's right to
help rebuild the community--and to help people rebuild their lives--and
we will continue to do so. We are also moving forward aggressively to
make the necessary changes and upgrades in our natural gas system to
make sure this does not happen again.
For these reasons, I want to thank this Committee's leadership on
the issue of pipeline safety. PG&E strongly supports the Pipeline
Transportation Safety Improvement Act of 2011, which was approved
unanimously by the Committee, and now awaits action by the full Senate.
It includes provisions that are critically important to enhancing the
safety of the Nation's pipeline system, including those related to the
validation of the maximum allowable operating pressure (MAOP) for pre-
1970 pipelines, the installation of remote control or automated valves,
and excess flow valves. These are important policies that will help
enhance the safety of anyone who lives or works around natural gas
pipelines and facilities. We hope this legislation can soon be passed
by Congress and signed into law.
NTSB Recommendations and PG&E Actions
The National Transportation Safety Board (NTSB) recently completed
a meticulous review of the San Bruno accident. I want to thank the NTSB
for providing PG&E with a thorough set of recommendations and findings.
We fully share the NTSB's commitment to ensuring that such a horrific
accident never happens again.
Toward that end, PG&E' embraces all of the NTSB recommendations and
those of other major investigations of this accident, such as the
Report of the Independent Review Panel, which was ordered by the
California Public Utilities Commission (CPUC). In the year since the
tragedy, we have taken numerous actions including many recommended by
the NTSB and others.
The balance of my testimony will be devoted to reviewing the steps
we have taken to build a safer and more reliable natural gas system.
Attached to my testimony is a document (Attachment A) that summarizes
actions taken in direct response to the NTSB recommendations.
In order to successfully implement the NTSB's recommendations, our
number one priority and overarching focus is building a ``safety
first'' culture at PG&E--both public and employee safety. Public and
employee safety must describe not only what we say we believe in, it
must be reflected in our actions, values and priorities. Every employee
must understand how their actions contribute to the safe operations of
our system, and they must never doubt the imperative need to report and
act upon any concerns they may have.
A first step we took to build a ``safety first'' culture at PG&E
was to benchmark against industry leaders to see how we compare and
determine what we need to do to become a leading utility. We also
separated PG&E's gas and electric operations and associated functions
to ensure clear roles and responsibilities. Now the organizational
structure within PG&E's gas function mirrors the work and precisely
defines roles and accountabilities. We are in the process of putting
new standards and practices in place that support employee and public
safety.
In addition to making organizational and structural changes, we
have taken numerous other actions, several of which were recommended by
the NTSB, including the following:
Validating and Modernizing Our Records. PG&E must understand
its assets inside and out. Having accurate asset knowledge and
a robust integrity management process are fundamental to
operating a safe and reliable natural gas transmission and
distribution system. Specifically, we have:
Retrieved and scanned more than 2.1 million paper
documents dating back to the 1920s to validate the maximum
allowable operating pressure (MAOP) of all pipelines in
Class 3 and Class 4 locations, and Class 1 and Class 2 high
consequence areas (HCAs);
Verified strength test documentation for more than 1,150
miles of HCA pipeline;
Validated the MAOP for more than 750 miles of high
priority pipelines in HCAs without prior strength tests;
and
Video inspected pipe in various locations throughout the
transmission system.
Strength Testing Our Pipes. PG&E has embraced the idea of
eliminating the ``grandfathering'' of older pipelines and is in
the process of an extensive strength testing and reviewing of
our pipeline system. Starting with pipes that have similar
qualities to the pipe that ruptured in San Bruno, we have
successfully completed pressure tests or identified strength
test records for approximately 97 miles of pipeline and are on
track to complete testing between 144 and 160 miles this year.
As of September 30, more than 85 transmission pipeline miles
have been hydrostatically tested or replaced. As part of our
Pipeline Safety Enhancement Plan (PSEP) that we filed with the
CPUC, we propose pressure testing approximately 783 miles of
pipe over the next five years.
Automating Our System. PG&E recognizes the importance of
modernizing our system and using technology to help us identify
potential issues and address them quickly. As part of our
efforts, we are installing automated shut-off valves (ASVs). We
are on track to install 29 automated valves in 2011, targeting
areas of high seismicity on the Peninsula, and have proposed to
install a total of 228 ASVs as part of our PSEP.
PG&E applauds Senator Boxer, Senator Feinstein and Representative
Speier for calling attention to the important role that ASVs
can play in promoting pipeline safety, and for making
provisions related to ASVs a legislative priority.
We are also enhancing our Supervisory Control and Data Acquisition
(SCADA) information system by including information related to
pipeline pressures, valve position and gas flow.
In-Line (ILI) Inspection. Through 2011, PG&E will have
retrofit close to 1,000 miles of pipe to accommodate ILI tools.
By the end of 2014, PG&E expects to have a total of
approximately 1,480 miles (24 percent) of the gas transmission
pipe retrofitted to accommodate ILI tools.
Sharing Information and Improving Our Emergency Response
Procedures. PG&E recognizes that it is our responsibility to
ensure that first responders have the information they need to
do their jobs and that, as a company, we have clearly
established processes and procedures for first responder
engagement. Since September 2010, PG&E has:
Required gas control room operators to notify 911
emergency call centers of affected communities immediately
and directly when a possible rupture of any pipeline is
indicated;
Updated emergency response plans to reflect current best
practices and is training employees on the plan;
Conducted emergency planning exercises with public
officials and first responders to simulate gas curtailment
scenarios and prepare for potential events;
Launched a secure website for first responders detailing
the location of PG&E's gas transmission pipelines and
mainline valves;
Mailed more than two million letters to individuals who
live within 2,000 feet of a natural gas transmission line
and providing them with information regarding natural gas
safety.
PG&E is in the process of updating the SCADA system to provide
operators in PG&E's Gas Control Center with the tools and
training to identify and improve response time in the event of
a pipeline rupture.
Improving Work Clearance Procedures. The investigation of
the events leading up to the San Bruno accident revealed that
changes need to be made to PG&E's work clearance procedures.
PG&E has taken steps to:
Develop and implement a comprehensive controls framework
based on industry best practices. This framework will focus
on proactive practices to assess, prevent, detect and
respond to potential threats (e.g., physical, logical and
personnel) to PG&E's system. We have sought subject matter
experts to advise us on these issues and have incorporated
their expertise;
Establish standardized procedures to effectively deal with
abnormal and emergency operating situations;
Improve the quality of information available to operators
by providing increased pipeline pressure and flow
information; and
Upgrade alarm management software systems.
The initiatives outlined above are in addition to steps we took
immediately following the accident, which included reducing the
operating pressure on a significant number of our gas transmission
lines, increasing leak surveys and patrols for segments of transmission
pipeline, and conducting weekly ground patrols on the local San
Francisco Peninsula transmission system.
PG&E's Pipeline Safety Enhancement Plan
While we have taken many actions to date to improve the overall
safety of our system, we know that there is much more to do. The state
of California is working toward codifying the most aggressive pipeline
safety standards of any state, and we are wholly supportive of those
efforts. As part of its pipeline safety efforts, the CPUC directed the
state's investor-owned utilities to submit plans to enhance and improve
the safety and operations of their natural gas systems. On August 26,
2011, PG&E submitted the Pipeline Safety Enhancement Plan, which
represents a clear break from the way California and its utilities
approached pipeline safety in the past, and the way it will be
approached in the future. The result of this effort will be tougher
standards for pipeline safety that will better serve the public and
PG&E customers.
The gas pipeline infrastructure in California and across the United
States contains a wide range of pipeline types and vintages. Like other
parts of our country's infrastructure, natural gas transmission
pipelines were generally built with the best design tools, technology,
materials and techniques available at the time they were constructed
and installed. Over time, as those methods and materials improved, the
regulations and codes governing the construction of the pipelines have
also evolved to require more effective inspection control techniques,
resulting in better quality and confidence in pipeline integrity. One
of those changes, adopted by Federal regulators in 1970, required all
new gas transmission lines to have their MAOP established through
pressure testing and records validation.
Following the San Bruno accident, the CPUC has rightly insisted on
a more rigorous standard for older pipelines, consistent with the NTSB
recommendations. PG&E fully supports this new policy direction. As
previously indicated, we have undertaken a massive and unprecedented
program to pressure test or replace every pipeline that does not have
complete pressure test records, and validate the MAOP of older
pipelines through a rigorous, records-based analysis.
The actions and investments outlined in the PSEP are the roadmap
for taking PG&E's pipeline safety to this new level. They are
consistent with and encompass many of the NTSB's recommendations and
include four main components:
Pipeline Modernization
Valve Automation
Pipeline Records Integration
Interim Safety Enhancement Measures
The PSEP has two phases. Phase 1, which has already begun, will
carry through 2014. It targets pipeline segments that are in highly
populated urban areas, have vintage seam welds that do not meet modern
manufacturing, fabrication, or construction standards or were
''grandfathered'' under previous regulations, and have not been
strength tested. During this phase, PG&E plans to replace 186 miles of
transmission pipelines, strength test more than 780 miles, retrofit
about 200 miles to permit in-line inspections, and in-line inspect over
200 miles. In addition, 228 valves will be replaced with automated
valves. In Phase 2, PG&E will expand the program to cover the remainder
of our gas transmission system.
The PSEP is currently pending before the CPUC, where stakeholders
have the opportunity to comment on what we have proposed. We are
hopeful that the CPUC will issue a final decision in the first quarter
of next year. In the meantime, we continue to move forward with actions
to enhance the safety of our system and to take steps to prevent
another accident like San Bruno from occurring.
I would like to thank the Committee for providing me with the
opportunity to appear and provide testimony at this very important
hearing. I would be pleased to answer any questions that members of the
Committee may have.
______
Attachment A
PG&E Actions Relating to NSTB Safety Recommendations
I. Records, Maximum Allowable Operation Pressure (MAOP) Validation, and
Strength Testing (NTSB P-10-2, P-10-3, and P-10-4)
Summary of Safety Recommendation: (1) Diligently search for
traceable, verifiable and complete records for transmission pipelines
in class 3 and 4, and class 1 and 2 high-consequence area (HCA)
locations for which the MAOP has not been established by a pressure
test; (2) calculate valid MAOP for such transmission pipelines based on
those traceable, verifiable and complete records; and (3) establish a
valid MAOP by hydrostatic pressure test for any transmission pipelines
for which the MAOP cannot be validated by steps (1) and (2).
PG&E Actions Related to Safety Recommendations:
MAOP Validation Project: Validated the MAOP for more than
750 miles of high priority pipelines in HCAs without prior
strength tests. MAOP validation work will continue on all
remaining HCA pipelines in 2011 and the first part of 2012 with
work commencing on all non-HCA pipelines thereafter.
Strength Tests: Strength testing between 144 and 160 miles
of pipeline in 2011. As of September 30, more than 85
transmission pipeline miles have been hydrostatically tested or
replaced.
Video Inspections: Video inspected approximately six miles
of pipe in various locations throughout the transmission
system.
Specialized In-Line Inspection (ILI) Tools: PG&E will have
retrofit nearly 1,000 miles of pipe to accommodate ILI tools
through 2011. By the end of 2014, PG&E expects to have a total
of approximately 1,480 miles of the gas transmission pipe
retrofitted to accommodate ILI tools.
Pipeline Safety Enhancement Plan: Ultimately PG&E will
pressure test all transmission lines not previously tested,
including strength testing on 783 miles of pipe in Phase 1 of
the program and replacing 186 miles of pre-1970 pipe (single-
submerged arc welded (``SSAW''), low frequency electric
resistance welded (``LF-ERW), joint efficiency (``JE'') < 1.0)
in High Consequence Areas in Phase 1 of the program.
Interim Safety Measures: Reducing pressure in some pipelines
to ensure an adequate margin of safety until MAOP is validated
through on-going and future corrective action, such as records
validation, pressure tests or pipe replacement. Currently,
pressure has been reduced on 29 primary pipelines totaling
approximately 1,600 miles.
II. 911 Notification by Gas Control (NTSB P-11-3)
Summary of Safety Recommendation: Requires gas control room
operators to notify immediately and directly 911 emergency call
center(s) for affected communities when a possible rupture of any
pipeline is indicated.
PG&E Actions Related to Safety Recommendations:
Gas Control Room: As addressed in PG&E's August 26, 2011
response to Safety Recommendation P-11-3, PG&E has established
and implemented a Gas Control Room Process (911 Notification
Process) in response to this NTSB recommendation. The new 911
notification process provides guidance to Gas Control and
requires that the responsible 911 Emergency Response Center(s)
be notified during any emergency incident that may affect the
safety of the public, property or the environment.
Related and continuing actions include:
Gas System Operators: Gas System Operators to take the
lead to further assess best practices for emergency
response and 911 contacts in connection with pipeline
events.
Outreach and Partnering: Outreach to and partner with 911
agencies to determine best practices to give and receive
information to establish situational awareness so that all
first responders, utility and agencies are in unified
command; ultimate goal to reduce response time and thereby
improve opportunity to safeguard the public.
Gas Dispatch and Gas Control: Evaluate possible co-
location of Gas Dispatch and Gas Control to facilitate
information sharing; consider establishing collaborative
process whereby Gas Control determines need to call 911 and
Dispatch initiates communications at Gas Control's
direction.
GPS Locators: Evaluate GPS locators on every PG&E first
responder vehicle with real-time visibility to Dispatch and
Gas Control.
Distribution Gas Control and Transmission Gas Control:
Establish a Distribution Gas Control center separate from
Transmission Gas Control.
III. Work Clearance Procedures and Supervisory Control (NTSB: P-11-24,
P-11-26)
Summary of Safety Recommendations: (1) Include requirements for
identifying the likelihood and consequence of failure associated with
the planned work and for developing contingency plans; (2) Equip
supervisory control and data acquisition (SCADA) system with tools to
assist in recognizing and pinpointing the location of leaks, including
line breaks; such tools could include a real-time leak detection system
and appropriately spaced flow and pressure transmitters along covered
transmission lines.
PG&E Actions Related to Safety Recommendations:
Comprehensive Controls Framework: Developing and
implementing a comprehensive controls framework consisting of
industry best practices. This framework will focus on proactive
practices to assess, prevent, detect and respond to potential
threats (e.g., physical, logical, and personnel) to PG&E's
system. Areas of focus include access control for both the
Industrial Control Systems (ICS) and underlying infrastructure;
training of operators on proper use of controls and reporting;
enhanced monitoring of controls and system configuration;
independent assessments; and business continuity and disaster
recovery capabilities.
Subject Matter Experts: Identified subject matter
experts knowledgeable in ICS, Geographic Information System
(GIS), Information Technology (IT), and related security
controls and incorporated their expertise
Standardized Procedures: Establishing standardized
procedures to effectively deal with abnormal and emergency
operating situations. Examples include: station start-up,
operational protocols, electrical maintenance, controls
construction, and the retention and accessibility of critical
station documentation.
Quality and Accessibility of Information: Improving the
quality of information available to operators by providing
increased pipeline pressure and flow information.
Alarm Management Systems: Upgrading alarm management
software systems to improve alarm analysis.
IV. Emergency Response (NTSB: P-11-25)
Summary of Safety Recommendation: Establish a comprehensive
emergency response procedure for responding to large-scale emergencies
on transmission lines.
PG&E Actions Related to Safety Recommendations:
Increased SCADA Capability: Updating and expanding SCADA
system by installing more pressure and flow monitoring points;
deploying real-time and situational SCADA viewing tools to
improve gas control monitoring and response abilities;
developing new shut-down protocols for emergency response.
Benchmarking: Incorporating information gained from
benchmarking with 25 other utilities and first responders to
identify best practices and industry standards.
Enhanced Emergency Response Capability: Organizational
changes to support emergency planning and response and
implementation of mobile command centers.
Training and Outreach:
Developed contact list for all local first responders
to facilitate future communications and notifications
Launched PG&E first responder password-protected
website
Provided maps, GIS data and other information to first
responders
PG&E completed in-house Incident Command System
training and regionally-based training for fire departments
and other agencies in coordination with PG&E employees
PG&E is conducting Gas Controller training regarding
the use of automated isolation valves in emergency response
PG&E also plans to improve processes for dispatching
first responders to the scene of a natural gas emergency
(See actions taken in response to NTSB P-11-3 above)
V. Installation of Automated Valves (NTSB: P-11-27)
Summary of Safety Recommendation: Expedite the installation of
automatic shutoff valves and remote control valves on gas transmission
lines in HCAs, and in class 3 and 4 locations, and space them at
intervals that consider the factors listed in Title 49 Code of Federal
Regulations 192.935(c).
PG&E Actions Related to Safety Recommendations:
Isolate or Shutdown Pipe Segments: Install automated and
remotely operated pipeline safety valves to enable PG&E's to
isolate or shutdown pipeline segments in an emergency.
Automated Valves and SCADA: Installed automated valves and
SCADA capability at Line 132/109 cross-ties.
Automating 29 valves in 2011 on the San Francisco
Peninsula.
Planning to install a total of 228 automated valves
over the next three years as part of PG&E's proposed
Pipeline Safety Enhancement Plan.
VI. Post Accident Toxicological Testing (NTSB: P-11-28)
Summary of Safety Recommendation: Revise PG&E's post accident
toxicological testing program to ensure that testing is timely and
complete.
PG&E Actions Related to Safety Recommendations:
Post-Accident Training: Conducted Department of
Transportation (DOT) Gas Post-Accident training to all PG&E'S
Gas Maintenance & Construction management team and first-line
supervisors.
Procedures, Controls and Training: Clarified procedures,
established controls and ongoing training of the on-call
procedure binder, procedural checklist and DOT contact;
conducted DOT training on July 18, 2011 for all supervisors and
on-call engineers.
VII. Integrity Management Program (NTSB: P-11-29, P-11-30, P-11-31)
Summary of Safety Recommendations: (1) Assess every aspect of
Integrity Management program and implement a revised program; (2)
conduct assessments using revised risk analysis methodology
incorporated in (1) and report results to the CPUC; (3) develop and
incorporate into public awareness program written performance
measurements and guidelines for evaluating the plan and for continuous
program improvement.
PG&E Actions Related to Safety Recommendations:
Review and Modify Integrity Management Program:
Conducting a comprehensive review of Gas Transmission
Integrity Management Program.
Benchmarking Integrity Management Program against
industry leaders.
Updating prioritization methods to incorporate
structured risk assessment across facilities and functions.
Improving Integrity Management Program Through Records
Management: Establishing a technology infrastructure to ensure
data reliability, improve risk and integrity management,
strengthen record and data analysis, and aid in decision-
making.
Training: Providing additional training to ensure employees
can execute and meet highest standards related to PG&E's
Integrity Management Program.
Quality Assurance: Established clear audit and review
procedures to ensure work is:
Performed according to established standards
Improvement actions identified through audits are
effectively implemented and tracked
Senator Lautenberg. Thank you very much. Rick Kessler, the
familiarity here is justified. Rick was on my team for some
time before he joined this organization. With all of the
informality, Rick, come up.
STATEMENT OF RICK KESSLER, VICE PRESIDENT,
PIPELINE SAFETY TRUST
Mr. Kessler. Thank you, Mr. Chairman, and thank you,
Ranking Member Wicker, Senator Boxer, and the members of the
Subcommittee.
I want to thank you for inviting the Pipeline Safety Trust
back again to speak on the important subject of pipeline
safety, focusing on the pending legislation--or, no longer
pending legislation over here--and the recent NTSB
recommendations.
I want to congratulate the Committee and to commend the
Senate, and particularly Senators Rockefeller, Hutchison, you,
Mr. Chairman, you, Senator Boxer, Senator Wicker, Senator
Thune, and Senator Udall, for coming together and passing S.
275 by unanimous consent.
It's good legislation. We support it; we hope it will be
enacted. We also hope that the House will follow the Senate's
lead and move quickly to pass that, or H.R. 2937, legislation
based upon and substantially similar to your bill.
That legislation was crafted on a bipartisan basis by
Chairman Upton and former Chairman Dingell, and it was approved
by an overwhelming, bipartisan vote of 51-nothing that included
conservative Republican Tea Party caucus members and liberal,
progressive caucus members on the Democratic side.
Now, while neither bill incorporates all the improvement we
believe are necessary to reform the Federal pipeline safety
program, both have the support of all stakeholders, including
industry and public safety advocates and provide a clear path
forward to quickly make meaningful and immediate improvements
to our Nation's pipeline safety program.
Now according to PHMSA's own statistics for the past 10
years, pipeline accidents kill or hospitalize at least one
person in the U.S. every 8.7 days, and cause more than $407
million in property damage per year.
And given the tragedies in Montana, Michigan, Pennsylvania,
and California, people now question whether the industry and
Federal and state regulators are really doing all they can to
keep people, property, and the environment safe. They're right
to do so, especially in light of the rapid aging and apparent
deterioration of our pipeline system.
As you review the state of pipeline safety since the San
Bruno explosion, the horrific Allentown disaster and other
pipeline tragedies, perhaps the best place to start is the
recent NTSB report on San Bruno, and particularly its numerous
critical findings and safety recommendations, which we join
PG&E in fully supporting.
The NTSB report certainly provides us all another
significant opportunity to review the DOT pipeline safety
program and pending legislation, and augment them to resolve
some of the shortcomings identified by the board.
Now I think a lot of people have already gone over the
specifics of what the NTSB found, so let me skip ahead to say
that blame for San Bruno clearly falls squarely on the
shoulders of PG&E. However, I would note that they have taken
at least some actions that appear to be very serious first
steps to address management and safety program failings. While
PG&E's activities should continue to be closely scrutinized,
the utility was clearly not the only entity implicated in this
deadly failure.
NTSB found that the California Public Utilities Commission
failed to detect inadequacies in PG&E's integrity program, and
our characterization of CPUC's role in this is less charitable
because it appears there was little to no oversight or
regulation prior to San Bruno.
At a minimum we've learned that we can't assume anything
about state oversight of pipeline safety. We don't know what we
don't know, and what we don't know can be deadly.
Of course, one of the reasons we don't know what a bad job
CPUC was doing was because PHMSA appears to have handed off
responsibility to the state while never appearing to have
possibly never done meaningful oversight. I am very grateful
for Administrator Quarterman's comments today, and her
commitment to review and reform that program.
Now, I want to get to some of the specific requirements in
my few seconds left. We strongly support NTSB's recommendation
to delete the grandfather clause that allows all gas
transmission pipelines constructed before 1970 to be operated
without being subjected to a hydrostatic pressure test that
incorporates a spike test.
We also agree that pipeline safety regulations should be
revised so that manufacturing and construction related defects
can only be considered stable if a gas pipeline has been
subjected to a post-construction test.
With regard to NTSB's remote and automatic shutoff valves
recommendations, I'm just left wondering why it is that we shut
off our televisions, we close our garage doors, and lock our
cars by remote control, yet somehow we still find it acceptable
to have someone drive an hour in traffic in a car, get out of
the car, and turn a valve that's huge to shut off a raging
inferno.
Seventeen years ago we were debating this, Mr. Chairman, on
your legislation that would have required these valves. It's
just time to stop the analysis and the regulatory paralysis and
act on this recommendation.
We feel similarly about smart pigs, and the need to make
existing pipelines able to be pigged or otherwise inspected.
Too many aren't.
Let me just close by thanking you again for the opportunity
to testify. At the end of the day, we note that many of the
most important changes to the Federal pipeline safety program
we have requested could be instituted by the Department of
Transportation without further congressional action.
Many of these changes have been recommended time and time
again. What we need is a President, a Secretary, and an agency
that has the will to get the job done. The Pipeline Safety
Trust hopes that Congress and the administration will seriously
consider the concerns we have raised today and the requests we
have made, including those in our written testimony. I thank
you for your time and stand ready to answer any questions.
[The prepared statement of Mr. Kessler follows:]
Prepared Statement of Rick Kessler, Vice President, Pipeline Safety
Trust
Good afternoon, Chairman Lautenberg, Ranking Member Wicker, Senator
Boxer and members of the Subcommittee. My name is Rick Kessler and I am
testifying today in my purely voluntary role as the Vice President of
the Board of Directors 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.
Thank you for inviting the Pipeline Safety Trust back again to
speak on the important subject of pipeline safety, focusing on pending
legislation and the recent NTSB recommendations following the PG&E
transmission line explosion in San Bruno, California. The Pipeline
Safety Trust came into being after the 1999 Olympic Pipe Line 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.
According to PHMSA's own statistics for the past 10 years, pipeline
accidents kill or hospitalize at least one person in the U.S. every 8.7
days on average and cause more than $407 million in property damage per
year. Given the tragedies in Montana, Michigan, Pennsylvania, and
California, people now question whether the industry and Federal and
state governments are really doing all they can to keep people,
property and the environment safe. They are right to do so, especially
in light of the rapid aging and apparent deterioration of our pipeline
system, particularly when even industry sources refer to transmission
pipelines over 20 years old as ``middle aged'' stating that ``even the
best designed and maintained pipeline will become defective as it
progresses through its design life.'' However, moving forward a strong
bill to address the tragedies of the past year, and close gaps in
pipeline safety that have been identified--particularly in the National
Transportation Safety Board's (NTSB) recent report on the San Bruno
tragedy--will help reduce the potential for more tragedies restore the
public's trust.
Pipeline Safety Program Reauthorization and Reform
Since I last testified before the Committee, you have unanimously
reported legislation to reauthorize and improve the Federal pipeline
safety program. That legislation has stalled due to objections raised
by Senator Paul of Kentucky that the bill fails to address some of the
key NTSB recommendations arising out of the San Bruno tragedy including
requiring retrofitting of existing pipeline segments with remote
shutoff valves and to accommodate internal inspection devices, as well
as deleting the grandfather clause and require that all gas
transmission pipelines constructed before 1970 be subjected to a
hydrostatic pressure test that incorporates a spike test. We agree with
Senator Paul that this Congress should include such provisions in any
legislation sent to the President for signature and stand ready to work
with Senator Paul, this Committee and industry to craft language that
would accomplish those goals in a manner that maximizes safety while
minimizing costs to consumers and shareholders.
Now, while S. 275, as reported, does not incorporate all the
improvements we believe are necessary to truly reform the program, we
continue to support the bill and thank Chairman Lautenberg, Senator
Thune, Senator Boxer and others for crafting balanced legislation that
is worthy of enactment. We hope that as the process moves forward,
there will be an opportunity incorporate the key NTSB recommendations
into S. 275 as well as perfect some of the bill's language to ensure
adequate oversight of grants to states and extensions of statutory re-
inspection periods.
Likewise, we strongly support H.R. 2937, legislation based upon and
substantially similar to S.275 crafted by House Energy and Commerce
Chairman Upton and former Chairman Dingell. Their legislation includes
significant refinements and additions to the language of S. 275 to
provide enhanced benefits for public safety and industry, such as a
revised provision on CO2 gas pipelines requested by industry
and consensus language addressing problems identified in the wake of
the Exxon pipeline spill into the Yellowstone River in Montana similar
to that included in legislation introduced by Senators Tester and
Baucus. Not surprisingly, H.R. 2937 was recently reported by an
overwhelming full committee vote of 51-0 that included some of the most
conservative Republican members of the Tea Party Caucus and some of the
most liberal Democratic members of the Progressive Caucus. Like S. 275,
the Upton-Dingell legislation enjoys the support of all the major
industry stakeholders, environmental groups, the PipelinemSafety Trust
and other public safety advocates.
Unfortunately, a third bill that was reported by the House
Transportation and Infrastructure Committee, H.R. 2845, diverges
sharply from the successful legislative recipe created by this
Committee and adopted by the Energy and Commerce Committee. That bill
fails to address in any meaningful way any of the issues raised by any
of the all too numerous pipeline disasters of the past 18 months. We
strongly oppose H.R. 2845 in its current form, and hope that Chairman
Mica and Ranking Member Rahall will give serious consideration to
adopting the formula that has proved so successful in both the Senate
and House Commerce Committees.
NTSB's Report on the San Bruno Disaster
As you review the state of pipeline safety since the San Bruno
explosion, the horrific Allentown disaster and other pipeline
tragedies, perhaps the best place to start is the recent NTSB report on
San Bruno and, particularly, its numerous, critical findings and safety
recommendations. The NTSB report certainly provides us all another
significant opportunity to review the DOT pipeline safety program and
pending legislation and augment them to resolve some of the
shortcomings identified by the Board.
As you know, the NTSB found that the leak that caused the San Bruno
explosion resulted from ``a fracture that originated in the partially
welded longitudinal seam of one of six short pipe sections'' installed
in 1956. The welding, oversight and installation were done so poorly
that they wouldn't have even met 1956 standards--which NTSB stated were
probably ``either overlooked or ignored.'' According to NTSB, PG&E took
more than 1.5 hours to stop gas from flowing to the rupture and this
unacceptably slow response time ``contributed to the extent and
severity of property damage and increased the life-threatening risks to
the residents and emergency responders.'' The use of either automatic
shutoff valves or remote control valves would have reduced the amount
of time taken to stop the flow of gas. The Board also found that PG&E
didn't have a detailed, comprehensive response plan for large-scale
emergencies and labeled ``deficient and ineffective'' PG&E's pipeline
integrity management program.
While blame for the San Bruno disaster falls squarely on the
shoulders of PG&E, the utility was certainly not the only entity
implicated in this deadly failure. NTSB also found that the California
Public Utilities Commission (CPUC) ``failed to detect the inadequacies
in PG&E's integrity management program.'' Our characterization of the
CPUC's role in this catastrophe is less charitable: it appears that
there was little to no oversight or regulation of pipeline safety by
the CPUC for at least a decade before the San Bruno explosion. At a
minimum, we've learned that we can't assume anything about state
oversight of pipeline safety: we don't know what we don't know and what
we don't know could be deadly.
Of course, one of the reasons we didn't know how bad a job the CPUC
was doing of running its program is because PHMSA appears to have
handed off responsibility to the state, while possibly never having
done any meaningful oversight of California or PG&E's program. NTSB's
report is particularly critical of PHMSA's integrity management
inspection protocols and cites the agency for ``not having incorporated
the use of effective and meaningful metrics as part of its guidance for
performance-based management pipeline safety programs.'' In the case of
PG&E's program NTSB determined that the program:
Was based on incomplete and inaccurate pipeline information
Did not consider the design and materials contribution to
the risk of a pipeline failure
Failed to consider the presence of previously identified
welded seam cracks as part of its risk assessment
Resulted in the selection of an examination method that
could not detect welded seam defects
Led to internal assessments of the program that were
superficial and resulted in no improvements
This begs the question as to why these shortcomings had to be
uncovered by NTSB after an explosion, rather than by the agency that is
supposed to overseeing industry integrity management programs before
the terrible loss of life and destruction of property occurred. While
this sounds bad on its own, this criticism is particularly
disheartening in light of the fact that the integrity management
program represents the best of what PHMSA has to offer in terms of
managing pipeline safety.
Expanding the miles of pipelines that fall under the Integrity
Management rules and improving PHMSA's oversight
The Pipeline Safety Trust agrees with NTSB's criticisms of PHMSA's
integrity management program and its recommendation that the Secretary
of Transportation carry out an audit assessing the effectiveness of
PHMSA's oversight of performance based safety programs, including the
integrity management programs. Such an audit could be carried out
simultaneously with PHMSA's study of mechanisms to expand the
application of the integrity management programs, assuring that PHMSA's
future oversight of the expanded performance based programs is
effective and based on meaningful metrics backed up by complete and
accurate data. If the Secretary is unwilling to take up this
recommendation on his own, then we urge Congress to add language
directing the Secretary or other another appropriate, objective entity
to immediately undertake such an audit and make public its findings.
Despite the foregoing criticism, we do, however, continue to
support expansion of integrity management to cover more areas. Congress
required integrity management in High Consequence Areas (HCAs) as a way
to protect the people who live, work and play near pipelines, as well
to protect sensitive environmental areas and this Nation's critical
energy infrastructure. Since these rules began to be implemented, over
75 percent of all the deaths caused by these types of pipelines have
occurred in areas that fall outside of the current integrity management
requirements, and more than 34,000 anomalies found in High Consequence
Areas have been repaired based on integrity management requirements.
Yet these requirements do not apply to the vast majority of
pipelines and today only about 7 percent of natural gas transmission
pipelines and 44 percent of hazardous liquid pipelines fall under these
important inspection programs. What this means is that outside of
HCA's, a pipeline company can install a pipeline transporting huge
quantities of often explosive fuel and leave it uninspected
indefinitely--even for 50, 60, or 70 years.
It's important to note, too, that regardless of where a pipeline
fails there will be a significant economic impact on the downstream
markets--adversely affecting both our economic and energy security. For
instance, when the El Paso natural gas pipeline failed in 2000 in a
non-High Consequence Area, the staff of the Federal Energy Regulatory
Commission estimated that the restriction in gas supply cost the people
of California hundreds of millions of dollars. Every time a major
liquid pipeline serving a refinery goes down the price of gasoline in
the region skyrockets until the pipeline can be repaired and supplies
returned to normal. When it comes to consumer's pocketbooks, and the
welfare of the economy, every mile of pipeline is of high consequence,
so every mile should be inspected so that the American people have
reliable and safe pipeline infrastructure.
Many progressive pipeline operators already apply integrity
management rules to significantly more miles of their pipelines than
required by Federal regulations. These companies do this because they
think it is good business, and we couldn't agree more. Unfortunately
not all companies voluntarily provide these needed safety precautions,
and even those that do are not required to respond to the problems
found, as they would be if these areas were covered by the integrity
management rules.
Elimination of the Exemption of pre-1970 Pipelines from Hydrostatic
Pressure Tests
As previously stated, we strongly support NTSB's recommendation to
delete the grandfather clause and require that all gas transmission
pipelines constructed before 1970 be subjected to a hydrostatic
pressure test that incorporates a spike test. As Senator Paul noted,
the lack of language addressing this recommendation is a serious
shortcoming shared by both House and Senate Commerce Committee bills.
Further, we agree that pipeline safety regulations should be revised so
that manufacturing-and construction-related defects can only be
considered stable if a gas pipeline has been subjected to a post-
construction hydrostatic pressure test of at least 1.25 times the
maximum allowable operating pressure.
Requiring automated shut off valves for gas and liquid transmission
pipelines
Seventeen years ago, Congress was debating a requirement for remote
or automatic shutoff valves on natural gas pipelines in the wake of the
Edison, NJ accident and the two and a half hours it took to shut off
the flow of gas that fed the fireball due to the lack of a remotely
controlled shut off valve. In fact, Chairman Lautenberg's own
legislation introduced in 1994 would have required the installation of
automatic or remote shutoff valves on existing natural gas pipelines
where technically and economically feasible and yet here we sit
discussing it again. It is both puzzling and sad that we still have to
debate the benefits of requiring remote or automatic shut off valves
after another tragedy, this time in San Bruno, California.
How is it that we shut off our televisions, close our garage doors,
and lock our cars by remote control, but somehow we still find it
acceptable to shut off a large pipeline spewing fire into a populated
neighborhood by finding someone with a key to a locked valve and have
that person drive to the valve to shut it off manually? In good weather
in San Bruno that method took an hour and a half to shut off the flow
of fuel. How long would that method take after an earthquake?
Existing language in S. 275and H.R. 2937 directs PHMSA to develop
rules for the installation of valves on new lines in certain
circumstances. Language in HR 2937, which we support, goes further in
that it calls for a review to determine the viability of replacing
valves on existing pipelines. The NTSB recommendation to PHMSA is that
automatic or remote controlled valves be required by rule in all HCAs
and Class 3 and 4 areas. Again, Senator Paul has rightly highlighted
the lack of such a requirement as an important deficiency in pending
reauthorization legislation and, again, we agree. The Secretary of
Transportation should be directed to immediately begin a study to
determine the type, placement, feasibility and phase-in period for
installation of automatic or remote controlled valves on existing and
new lines, and proceed expeditiously with a rule-making requiring such
installation.
It's important to note, that for liquid pipelines in 1992, 1996,
2002, and 2006, Congress required OPS to ``survey and assess the
effectiveness of emergency flow restricting devices. . .to detect and
locate hazardous liquid pipeline ruptures and minimize product
releases'' with the first such requirement having a deadline in 1994
(17 years ago!). Following this analysis, Congress required OPS to
``prescribe regulations on the circumstances under which an operator of
a hazardous liquid pipeline facility must use an emergency flow
restricting device.''
OPS/PHMSA never issued a formal analysis on emergency flow
restricting device (EFRD) effectiveness. Instead, in its hazardous
liquid pipeline integrity management rule, OPS rejected the comments of
the NTSB, the U.S. Environmental Protection Agency, the Lower Colorado
River Authority, the City of Austin, and the Environmental Defense Fund
and chose to leave EFRD decisions up to pipeline operators after
listing in the rule various criteria for operators to consider. Such an
approach to EFRD use does not appear to meet Congressional intent,
partly because the approach is essentially unenforceable and not
protective of important environmental assets such as rivers and lakes
including those not considered High Consequence Areas.
Congress needs to reiterate its previous mandates to PHMSA on EFRD
use on liquid pipelines and ensure they are followed to mitigate the
extent of future pipeline releases.
Require Natural Gas Transmission Pipelines Be Able To Accommodate Smart
Pigs
Again, we support NTSB's recommendation that pipelines be
configured so as to accommodate in-line inspection tools--known as
``smart pigs``--with priority given to older pipelines. While age is a
risk factor in pipelines, just as it is in humans, proper inspection
and maintenance can go a long way to lowering that risk. Yet, unless a
pipeline is designed to accommodate an internal inspection device,
corrosion and other threats that develop with age can't really be
detected and evaluated. It is time to end the two decades of hand
wringing by PHMSA over the need to replace pipeline segments to ensure
the ability to inspect with smart pigs. Congress should include
language ensuring implementation of NTSB's recommendation in any bill
sent to the President's desk.
Developing and Implementing Enhanced Standards and Requirements for
Leak Detection on Hazardous Liquid and Gas Transmission Lines
In its hazardous liquid transmission pipeline integrity management
rule, PHMSA requires that operators have a means to detect leaks, but
there are no performance standards for such a system. This is in
contrast to the State of Alaska, for example, which requires that all
crude oil transmission pipelines have a leak detection system capable
of promptly detecting a leak of no more than 1 percent of daily
throughput. PHMSA listed in the integrity management rule various
criteria for operators to consider when selecting such a device. Again,
such an approach is virtually unenforceable and not protective of
important environmental assets such as rivers and lakes including those
not considered High Consequence Areas.
Last year's Enbridge spill in Michigan and the Chevron pipeline
release near Salt Lake City are examples of what can go wrong when a
pipeline with a leak detection system has no performance standards for
operations. In both those incidents the pipelines had leak detection
systems as required by regulations, but neither system was capable of
detecting and halting significant spills. We ask that Congress direct
PHMSA to issue performance standards for leak detection systems used by
hazardous liquid pipeline operators by a date certain to prevent damage
from future pipeline releases.
Existing language in both S. 275 and H.R. 2937 directs the
Secretary to study leak detection for one year, and implement the
findings of the study within another year. Again, H.R. 2937 language
goes slightly farther, and includes a requirement for a study and
report on leak detection technologies available for gas transmission
lines. The language from H.R. 2937 could easily be amended to include
language that meets the recommendations of the NTSB with regard to leak
detection by providing that the study on leak detection technologies
for gas lines be followed by a rulemaking requiring the SCADA systems
of gas transmission operators to be equipped with tools to recognize
and locate leaks.
Regulating Gas Gathering Pipelines
Significant drilling for natural gas has led to a large expansion
of gathering and production pipelines in highly populated urban areas.
For instance, in Fort Worth, Texas there are already 1,000 producing
gas wells within the city limits and at least that many more planned.
Development of advanced shale gas drilling methods has led to thousands
of new wells being drilled and proposed in more populated areas of
Texas, Arkansas, Louisiana, Pennsylvania and New York. Pipelines will
connect to all of these wells, and the regulatory oversight of these
pipelines is less than clear and in some cases non-existent. According
to a recent briefing paper from PHMSA they only regulate 20,150 miles
of onshore gathering lines, but they estimate that there are 230,000
miles of such lines. Many of these lines are the same size and pressure
as transmission pipelines, but they are regulated far less, if at all.
To make matters worse, the standard (API RP 80) for determining
what is and isn't a gathering line was written by the American
Petroleum Institute and adopted into Federal regulations. The API
standard provides too much wiggle room for gas producers to design
their systems to avoid regulations. PHMSA's recent briefing paper also
recognizes this problem saying ``enforcement of the current regulations
has been hampered by the uncertainties that exist in applying API RP
80.''
We believe it is time to ensure that any gathering or production
pipeline with similar size and pressure characteristics to transmission
pipelines fall under the same level of minimum Federal regulations,
including the integrity management requirements for those in high
consequence areas. The current language in S. 275 and H.R. 2937
requires PHMSA to produce a study on the regulatory issues with onshore
gas production and gathering pipelines, and institute a rule making
based on the findings. This is language we support and hope to see
enacted.
Regulating Unregulated Liquid Pipelines
Onshore oil wells and their associated pipelines have a troubling
spill record and a highly inadequate oversight framework, which needs
to be addressed by Congress and the Obama Administration. Recently, the
Administration and BP agreed to a proposed civil settlement for 2006
pipeline spills on the North Slope of $25 million plus a set of
required safety measures on BP's federally unregulated North Slope
pipelines. Under the requirements of the settlement, BP's federally-
unregulated oil field pipelines, i.e., three-phase flowlines (gas,
crude, produced water mixture), produced water lines, and well lines,
now will be subject to integrity management requirements largely
similar to those that must be met by transmission pipelines in 49 CFR
195. While this settlement certainly is a welcome step for BP's lines
and an important precedent, Congress in its pipeline safety act
reauthorization and PHMSA need to move forward expeditiously on
requiring such measures for lines operated by other companies in Alaska
and the Lower 48.
BP's March 2006 spill of over 200,000 gallons was the largest crude
oil spill to occur in the North Slope oil fields and it brought
national attention to the chronic problem of such spills. Another
pipeline spill in August 2006 resulted in shutdown of BP's production
in Prudhoe Bay and brought to light major concerns about systemic
neglect of key infrastructure. Lack of adequate preventive maintenance
was not a new issue, however, as corrosion problems in Prudhoe Bay's
and other oil field pipelines have been raised previously by regulators
and others, including as early as 1999 by the Alaska Department of
Environmental Conservation.
As additional evidence of the problems with upstream
infrastructure, the State of Alaska completed a report in November
2010, which reviewed a set of over 6,000 North Slope spills from 1995-
2009. This report showed that there were 44 loss-of-integrity spills/
year with 4.8 spills greater than 1,000 gallons/year. Of the 640 spills
included in the report, a significant proportion, 39 percent, were from
federally unregulated pipelines.
We ask that Congress close the loopholes on these federally
unregulated pipelines and direct PHMSA to move forward as fast as is
practicable to put in place regulations similar to what was recently
agreed to by BP on their unregulated North Slope pipelines.
Correcting the Pipeline Siting vs. Safety Disconnect, and Ensuring
PHMSA's Ability to Provide Inspections When Pipelines Are Being
Constructed
With thousands of new miles of pipelines in the works, the
disconnect between the agencies that site new pipelines and PHMSA, the
agency that is responsible for the safety of the pipelines once they
are in service, has become quite apparent. While siting agencies go
through supposedly comprehensive environmental review processes, these
processes are functionally separate from the special permits or
response plans or high consequence area analyses that are overseen by
PHMSA. Many of the PHMSA determinations go through very limited public
process (special permits), or processes that take place after the
pipeline siting approval is granted (emergency response plans), and
some are totally kept from the public (high consequence areas). How can
local governments, citizens, or even other Federal agencies assess the
real potential impact of a pipeline if the environmental review and the
safety review processes are so disconnected?
A perfect example of this disconnect is currently taking place
regarding the Presidential Permit that the U.S. State Department is
considering for the Keystone XL pipeline. For months now national
organizations have been asking specific pipeline safety questions
related to the corrosiveness and abrasiveness of the product the
Keystone XL will transport. The U.S. EPA questioned the State
Department's SDEIS because not enough information was included
regarding the proposed products to allow for an analysis of the effects
if a spill should occur. While the State Department is in charge of
granting the permit to allow the pipeline to be sited, PHMSA is the
agency in charge of both pipeline safety and spill planning for the
pipeline, yet it has been silent on these issues. As Senator Johanns
from Nebraska said during a pipeline safety hearing last year ``Of all
the expertise relative to pipelines in the Federal government I can't
imagine it would be at the State Department.'' Unfortunately the State
Department seems to be getting precious little help from the agency in
charge of pipeline safety -PHMSA. This disconnect between siting and
safety needs to be corrected.
Two years ago, PHMSA held a special workshop to go over the
numerous problems they found during just 35 inspections of pipelines
under construction. These inspections found significant problems with
the pipe coating, the pipe itself, the welding, the excavation methods,
the testing, etc. PHMSA's findings, and stories we have heard from
people across the country, call into question the current system--or
lack of one--of inspections for the construction of new pipelines. This
construction phase is critical for the ongoing safety of these
pipelines for years to come. Since PHMSA has authority over the safety
of pipelines once they are put into service, it makes sense to us that
during construction they also are conducting field inspections and
sufficiently reviewing records to ensure these pipelines are being
constructed properly. Unfortunately, there is a built-in disincentive
for PHMSA to spend the necessary time to ensure proper construction.
Under current rules PHMSA receives no revenue from these companies
until product begins to flow through the pipelines, so any staff time
spent on these pre-operational inspections has to be paid for from
money collected for other purposes from already operational pipelines.
For these reasons, the Pipeline Safety Trust asks that Congress
pass new Cost Recovery fees, similar to those included in Section 17 of
the PIPES act for LNG facility reviews, to allow PHMSA to recoup their
costs related to providing safety information during the review process
for all new pipelines and legitimate inspections during the
construction phase without taking resources away from other existing
activities. Hopefully this additional revenue will help PHMSA ensure
that pipeline siting agencies adequately assess pipeline safety issues.
The existing language in both House bills and the Senate dramatically
limit cost recovery to review of new pipelines with costs exceeding $1
or 3.4 billion dollars. We ask that the language from the
Administration's bill be substituted into the Senate bill, allowing
cost recovery for review of all lines, regardless of cost or technology
used.
Continuing to Push State Agencies on Damage Prevention
Property owners, contractors, and utility companies digging in the
vicinity of pipelines are still one of the major causes of pipeline
incidents, and for distribution pipelines over the past five years
excavation damage is the leading cause of deaths and injuries.
Unfortunately, not all states have implemented needed changes to their
utility damage prevention rules and programs to help counter this
significant threat to pipelines.
In the PIPES Act of 2006 Congress made clear its desire that states
move forward with damage prevention programs by defining the nine
elements that are required to have an effective state damage prevention
program. The Trust is pleased that PHMSA has recently announced its
intent to adopt rules to incorporate these nine elements, and its
intent to evaluate the states progress in complying with them. We also
support PHMSA's plan to exert its own authority to enforce damage
prevention laws in states that won't adopt effective damage prevention
laws. We hope Congress will encourage PHMSA to move forward with this
proposed rulemaking in a timely manner, and make it clear to the states
that Federal money for pipeline safety programs depends upon
significant progress in implementing better damage prevention programs.
It may also be necessary for Congress to clarify important parts of
good damage prevention programs. Many states have exemptions to their
damage prevention ``one call'' rules for a variety of stakeholders
including municipalities, state transportation departments, railroads,
farmers, and property owners. We believe such exemptions, except in
cases of emergencies, are unwarranted for municipalities, state
transportations departments and the railroads, and urge both Congress
and PHMSA to make it clear that these types of exemptions are not
acceptable in an effective damage prevention program. While we are
skeptical regarding exemptions of any type, limited exemptions for the
farm community and homeowners in specific circumstances may be
necessary to make the programs efficient, affordable and enforceable.
Although PHMSA likes to call itself a data-driven agency, there is
a serious lack of data to determine the extent, causes, or perpetrators
of excavation damage to pipelines. For example, because of the limited
reporting requirements, the PHMSA incident database only includes about
70 total pipeline incidents nationwide in 2008 caused by excavation
damage. Yet the Common Ground Alliance's 2008 DIRT database reports
well over 60,000 excavation events that affected the operation of
natural gas systems alone.
For these reasons, the Trust asks that Congress direct PHMSA to
correct this substantial data gap by ensuring more accurate reporting
and a database for excavation damage to ensure that the effort and
money being spent is well targeted and effective. Because most states
have taken on the responsibility of operating state-based damage
prevention programs it may well be easiest to just have PHMSA require
states to adopt reporting requirements as part of their damage
prevention programs.
Continuing The implementation and Funding of Technical Assistance
Grants to Communities
Over the past two and a half years, PHMSA has started the
implementation of the Community Technical Assistance Grant program that
was authorized as part of the Pipeline Safety Improvement Act of 2002
and clarified in the PIPES Act. Under this program more than a million
dollars of grant money has been awarded to communities across the
country that wanted to hire independent technical advisors so they
could learn more about the pipelines running through and surrounding
them, or be valid participants in various pipeline safety processes.
In the first two rounds of grants, PHMSA funded 46 projects in 22
states from California to Florida. Local governments gained assistance
so they could better consider risks when residential and commercial
developments are planned near existing pipelines. Neighborhood
associations gained the ability to hire experts so they could better
understand the ``real'' versus the imagined issues with pipelines in
their neighborhoods. And farm groups learned first-hand about the
impacts of already-built pipelines on other farming communities so they
could be better informed as they participate in the processes involving
the proposed routing of a pipeline through the lands where they have
lived and labored for generations. Overall, we viewed the
implementation of this new grant program as a huge success.
The Trust appreciates your efforts to ensure the reauthorization of
these grants, as provided for in S. 275 to continue to help involve
those most at risk if something goes wrong with a pipeline. We further
ask that you accept language from H.R. 2937 to allow the use of user
fees in funding these grants.
Continuing to Make More Pipeline Safety Information Publicly Available
Over the past two reauthorization cycles, PHMSA has done a good job
of providing increased transparency for many aspects of pipeline
safety. In the Trust's opinion, one of the true successes of PIPES has
been the rapid implementation by PHMSA of the enforcement transparency
section of the act. It is now possible for affected communities to log
onto the PHMSA website and review specific enforcement and inspection
actions regarding local transmission pipelines. This transparency for
the most part should increase the public's trust that our system of
enforcement and inspection of pipelines is working adequately or in
some instances may provide the information necessary for the public to
push for improvements from specific companies.
PHMSA has also significantly upgraded their incident data
availability and accuracy, and continues to improve their already
excellent ``stakeholder communication'' website.
There is also a need to make other information more readily
available. This includes information about:
High Consequence Areas (HCAs). These are defined in Federal
regulations and are used to determine which pipelines fall
under more stringent integrity management safety regulations.
Unfortunately, this information is not made available to local
government and citizens so they know if they are included in
such improved safety regimes. Local government and citizens
also would have a much better day-to-day grasp of their local
areas and be able to point out inaccuracies or changes in HCA
designations if this information were publicly available.
Emergency Spill Response Plans. As has been learned in the
Gulf of Mexico tragedy, it is crucial that spill response plans
are well designed, adequately meet worst-case scenarios, and
use the most up-to-date technologies. While 49 CFR Sec. 194
requires onshore oil pipeline operators to prepare spill
response plans, including worst case scenarios, those plans are
difficult for the public to access. To our knowledge the plans
are not public documents, and they certainly are not easily
available documents.
The review and adoption of such response plans is also a process
that does not include the public. In fact PHMSA has argued that
they are not required to follow any public processes, such as
NEPA, for the review of these plans. If the Gulf tragedy has
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 complete spill
plans are submitted for approval the plans are required to be
made publicly available, interested parties are notified, and
there is a 30 day period for interested parties to comment on
the contents of the proposed plan. We urge Congress to require
PHMSA to develop similar requirements for the adoption of spill
response plans across the country, and that such plans for new
pipelines be integrated into the environmental reviews required
as part of the pipeline siting process.
State Agency Partners. States are provided with millions of
dollars of operating funds each year by the Federal government
to help in the oversight of our Nation's pipelines. While there
is no doubt that such involvement from the states increases
pipeline safety, different states have different authority, and
states put different emphasis in different program areas. After
the San Bruno tragedy an independent review panel was formed to
review problems with the pipeline safety system in California.
One of their recent conclusions regarding the California Public
Utility Commission was that ``it would be difficult for the gas
safety staff to offer assurances on the quality of prevailing
integrity management efforts they audit.'' Why was it that such
stunning conclusions about one of the largest pipeline safety
programs in the Nation were not understood before eight people
were killed? Each year PHMSA audits each participating state
program, yet the results of those program audits are not easily
available. We believe that these yearly audits should be
available on PHMSA's website and that some basic comparable
metrics for states should be developed. It is not only the
performance of pipeline companies that needs to be inspected.
Implementing Expansion of Excess Flow Valve Requirements
One of the Trust's priorities that was well-addressed in the PIPES
Act was to require the use of Excess Flow Valves (EFVs) on distribution
pipelines for most new and replaced service lines in single family
residential housing. While this was a huge step forward, the National
Transportation Safety Board (NTSB) has continued to push for an
expansion of the use of EVFs in multi-family and commercial
applications ``when the operating conditions are compatible with
readily available valves.''
From closely following the deliberations of PHMSA's Large Excess
Flow Valve Team, it is our opinion that there are thousands of
potentially compatible structures being constructed or renewed which
could be afforded greater safety by the installation of Excess Flow
Valves (EFVs). It is clear from the data provided by PHMSA that the
service lines serving a majority of these types of structure fall
within the size constraints of commercially available EFVs. It is also
clear from the data that the vast majority of these gas services are
provided at pressures that avoid the concerns regarding low pressure
lines.
There are many multi-family residential, small office, and retail
structures that for all intents and purposes have the same load
profiles as a single family residence. For these types of applications
PHMSA and the industry need to move forward with rules to require
installation of EFVs for new and renewed gas service.
For these reasons the Pipeline Safety Trust urges Congress to
direct PHMSA to undertake a rulemaking--as the National Transportation
Safety Board has requested--that would require EFVs be installed on the
many types of structures where ``operating conditions are compatible
with readily available valves.''
Conclusion
Thank you again for this opportunity to testify today. At the end
of the day, we note that many of the most important changes to the
Federal pipeline safety program we have requested could be instituted
without legislation and have been recommended by safety experts over
and again throughout the past decade or more. All we need is a
President, a Secretary and an agency that has the will to get the job
done. The Pipeline Safety Trust hopes that both that Congress and the
Administration will seriously consider the concerns we have raised and
the requests we have made. If you have any questions now or at any time
in the future, the Trust would be pleased to answer them.
Senator Lautenberg. Thank you.
Mr. Santa?
STATEMENT OF DONALD F. SANTA, JR., PRESIDENT AND CEO,
INTERSTATE NATURAL GAS ASSOCIATION OF AMERICA
Mr. Santa. Good afternoon, Mr. Chairman, Ranking Member
Wicker, and Senator Boxer.
I am Donald Santa, President and CEO of the Interstate
Natural Gas Association of America. Our members operate
approximately 200,000 miles of natural gas transmission
pipelines. It appreciates the work of the National
Transportation Safety Board to develop pipeline safety
recommendations as part of its San Bruno accident
investigation.
On behalf of INGAA, I also offer our congratulations to the
Chairman and his colleagues on the passage of S. 275 last
evening.
The NTSB recommendations are aggressive and aspirational.
Still, much work will need to be done to transform these
recommendations into a concrete, practicable, and achievable
plan for realizing the pipeline safety goals that all of us
share.
INGAA advocates a multi-tiered approach that would build on
the well-founded existing approach of reducing risks to the
greatest number of people in the most effective way.
We believe that S. 275 would accomplish these objectives.
Pipeline transportation remains the safest method of moving
energy supplies within the United States. Still, in the wake of
the San Bruno accident last year, we recognized more must be
done to improve safety and to regain public confidence in the
safety of our pipeline infrastructure.
Last December, INGAA established a board-level task force
to pursue these objectives. This task force produced a set of
aggressive guiding principles anchored by the goal of zero
pipeline incidents.
This summer, INGAA committed publicly to a nine-point
action plan to improve pipeline safety. For purposes of the
discussion today, I wanted to focus on two of the items
addressed in our action plan: first, expanding integrity
management, and second, fitness for service of pre-regulation
pipelines.
Mr. Chairman, you and many members of the Subcommittee may
be familiar with the integrity management program, which was
the cornerstone of the Pipeline Safety Improvement Act of 2002.
The IMP requires operators to identify pipeline segments in
populated areas, known as high consequence areas, perform
baseline assessments on all such segments by December 2012, and
reassess those segments every 7 years thereafter. The baseline
assessments are close to completion, and many segments already
have been reassessed.
INGAA's members already have committed to go further, and,
over time, to expand integrity management principles beyond
HCAs. INGAA has proposed that integrity management principles
be extended to cover 70 percent of the people who live or work
in close proximity to pipelines by 2020, and 100 percent of
this population by 2030.
A phased approach to covering additional pipeline segments
beyond HCAs is important, because it will be necessary both to
undertake significant pipeline modification, and to develop and
deploy improved inline inspection technologies that do not
exist today.
Next, fitness for service of pre-regulation pipelines. The
first Federal pipeline safety regulations provided operators
with two options for confirming the maximum allowable operating
pressure of pre-regulation pipelines: first, pressure testing
in the same manner required of pipelines constructed after
1970, and second, using verifiable records demonstrating past
operating history to confirm the basis of the then current
MAOP.
Many pre-regulation--pre-1970 pipelines elected the second
option, which has come to be known as the grandfather clause.
About 60 percent of the U.S. natural gas transmission pipeline
mileage was installed prior to 1970. Most of these pipelines
are performing well, and have records that the pipe has been
pressure tested.
Engineering and operational history shows that older
pipelines are perfectly capable of safely remaining in service
for many decades to come. Age should not be the sole
determinative factor in determining whether to replace a
natural gas transmission pipeline. Fitness for service is the
correct focus. If a pipeline is unfit for service, then it must
be repaired or replaced, regardless of age.
INGAA supports a process for confirming the fitness for
service of pre-regulation pipelines located in HCAs. INGAA
believes there must be a workable time-frame to complete the
retesting, in order to avoid significant adverse consumer
energy price impacts due to testing-related pipeline capacity
constraints and service disruptions. INGAA suggests that such
work be completed by 2020. S. 275 is consistent with this
approach, and we believe it represents an effective legislative
response to the San Bruno accident.
Mr. Chairman, thank you for providing INGAA with the
opportunity to testify today. Our key messages are these:
first, reducing risk to people must remain the primary focus of
the Federal pipeline safety program. Second, S. 275 provides a
constructive framework for enhancing the pipeline safety
program in a way that maintains this important focus. And
third, given that we are at such a critical moment in the
evolution of our pipeline safety program, it is important for
Congress to act this year to enact the reauthorization bill.
Thank you very much.
[The prepared statement of Mr. Santa follows:]
Prepared Statement of Donald F. Santa, Jr., President and CEO,
Interstate Natural Gas Association of America
Mr. Chairman and Members of the Subcommittee:
I am Donald F. Santa, President and CEO of the Interstate Natural
Gas Association of America, or INGAA. Our members operate approximately
200,000 miles of natural gas transmission pipelines, representing two-
thirds of the Nation's total natural gas transmission mileage and about
90 percent of the total interstate natural gas transmission mileage in
the United States. The pipeline systems operated by INGAA's members are
analogous to the interstate highway system, transporting natural gas
across state and regional boundaries.
Let me state at the outset that INGAA appreciates the work of the
National Transportation Safety Board (NTSB) to develop pipeline safety
recommendations as part of its San Bruno accident investigation.
Furthermore, our association agrees with the goals served by those
recommendations: to reduce pipeline accidents and restore the public
confidence of the safety of the natural gas infrastructure.
Some of NTSB's key recommendations include confirming the safe
maximum allowable operating pressure (MAOP) for pre-1970 pipes,
expanding and/or modifying integrity management principles beyond the
current focus on populated areas, improving accident response times
using both personnel and automation (such as valves), and the need for
improved inspection technologies.
The NTSB recommendations are aggressive and aspirational. Still,
there is much work needed to transform these recommendations into a
concrete, practicable and achievable plan for realizing the pipeline
safety goals that we share. INGAA advocates a phased approach that
would build on the well-founded, existing approach of reducing risks to
the greatest number of people in the most effective way. We believe
that S. 275 accomplishes these objectives. S. 275 and a similar bill
emerging in the House provide a well-considered framework for achieving
groundbreaking improvements to the Federal pipeline safety program.
Therefore, Congress should enact this legislation this year.
INGAA Commitments
Pipeline safety has improved consistently over the decades through
the application and continuous refinement of consensus standards,
technology, law and regulation. Because of this work, pipeline
transportation remains the safest method of moving energy supplies
within the United States. Still, in the wake of the San Bruno accident
last year, we recognized more needed to be done to improve the safety
of natural gas transmission pipelines and to regain public confidence
in the safety of our pipeline infrastructure. Last December, INGAA's
board of directors established a board-level task force to pursue these
objectives. This task force produced a set of aggressive guiding
principles, anchored by the goal of zero pipeline incidents, which
subsequently were adopted by our board of directors. The guiding
principles are as follows:
1. Our goal is zero incidents--a perfect record of safety and
reliability for the national pipeline system. We will work
every day toward this goal.
2. We are committed to safety culture as a critical dimension
to continuously improve our industry performance.
3. We will be relentless in our pursuit of improving by
learning from the past and anticipating the future.
4. We are committed to applying integrity management principles
on a system-wide basis.
5. We will engage our stakeholders--from the local community to
the national level--so they understand and can participate in
reducing risk.
At first blush, the goal of zero incidents may sound daunting.
Still, we were inspired by the substantial results achieved by other
industries that set similar goals. Commercial aviation stands out as an
example. A quote from Vince Lombardi captures the idea well:
``Perfection is not attainable. But if we chase perfection, we may
capture excellence.''
Developing and adopting these guiding principles was an important
first step, but we knew that the real test of INGAA's commitment to
pipeline safety would be the specific actions we as an industry were
prepared to take in response to this challenge. As part of its response
to the ``call to action'' issued by Secretary of Transportation Ray
LaHood, INGAA committed publicly to a nine-point action plan to improve
pipeline safety. The INGAA action plan includes commitments to do the
following:
1. Apply risk management beyond High Consequence Areas (HCAs,
or populated areas).
2. Raise the standards for corrosion anomaly management.
3. Demonstrate ``fitness for service'' on pre-regulation (or
pre-1970) pipelines.
4. Shorten pipeline isolation and response time to one hour.
5. Improve integrity management communication and data.
6. Implement the Pipelines and Informed Planning Alliance
guidance.
7. Evaluate, refine and improve threat assessment and
mitigation.
8. Implement management systems across INGAA members.
9. Provide forums for stakeholder engagement and emergency
officials.
We will be working with the Pipeline and Hazardous Materials
Administration (PHMSA) and other pipeline safety stakeholders to
implement these action items, either through regulation or on our own
accord. (The complete plan of action can be downloaded from INGAA's
website.) For purposes of the discussion today on S. 275 and the recent
NTSB recommendations, I want to focus on three of the nine items
addressed in our action plan.
Expansion of Integrity Management
Mr. Chairman, you and many members of the Subcommittee may be
familiar with Integrity Management Program, or IMP. The integrity
management program is the cornerstone of the pipeline safety
enhancements included in the Pipeline Safety Improvement Act of 2002.
Briefly, the IMP requires operators to identify pipeline segments in
populated areas (known as High Consequence Areas, or HCAs), perform
baseline assessments of all such segments by December 2012, and
reassess those segments every seven years thereafter. The baseline
assessments are close to completion, and many segments already have
been reassessed.
There are approximately 300,000 miles of natural gas transmission
pipelines in the United States. Of this, about 18,000 miles, or six
percent, is located in an HCA. Because in-line inspection devices,
commonly known as ``smart pigs,'' are used most often for these
assessments and because of practical considerations affecting how these
devices are inserted and retrieved from pipelines, pipeline operators
ultimately will assess about 65 percent of the total natural gas
transmission pipeline mileage by the end of next year. Completing the
baseline assessments will be an important milestone. It is an opportune
time to begin contemplating the next steps for natural gas transmission
pipeline integrity management.
INGAA's members already have committed to go further, and over time
plan to extend integrity management principles beyond HCAs. Our plan is
based upon a phased approach, looking specifically at assessing those
pipelines located in close proximity to where people live and work.
Using the integrity management principles contained in the American
Society of Mechanical Engineers (ASME) standard B31.8S, INGAA has
proposed that integrity management principles be extended to cover 70
percent of the people who live or work in close proximity to pipelines
by 2020, and 100 percent of the people who live or work in close
proximity to pipelines by 2030.
As is common with such efforts, the final increments of this
integrity work will be the most difficult and most expensive to
complete. As noted, the majority of this work is being performed with
smart pig devices, which increasingly are able to perform more accurate
and comprehensive testing. Still, some natural gas transmission
pipeline segments cannot readily accommodate such devices, since these
pipelines were constructed before the technology was invented and were
not engineered to accommodate smart pig devices. In addition, some low-
pressure, low flow, small-diameter pipelines cannot accommodate smart
pigs--at least based upon current technology.
A phased approach to covering additional pipeline segments beyond
HCAs is important because it will be necessary both to undertake
significant pipe modification and to develop and deploy improved in-
line inspection technologies that do not exist today. Our commitment to
cover 100 percent of the population living or working near pipelines is
based on the assumption that new technology will provide the answer. It
could not be achieved fully today given the configuration of the
pipeline system and the state of current technology. Still, it is the
aspirational goal that the industry should be setting for itself.
Section 7 of S. 275 would require the Secretary of Transportation
to evaluate an extension of integrity management beyond HCAs, and then
proceed with a rulemaking within one year. The bill also would direct
the Secretary to re-evaluate the class location regulations for natural
gas transmission pipelines. These regulations pre-date new technology
advancements and the application of integrity management and now
largely are redundant because class location and IMP address the same
issue--reducing risk in populated areas. The need for these legacy
regulations will be even less compelling as integrity management is
broadened. Section 7 of S. 275 is consistent with our goals for
expanding integrity management.
Fitness for Service of Pre-Regulation Pipelines
The Natural Gas Pipeline Safety Act was enacted in 1968, and
regulations implementing the new law took effect in 1970. Prior to
this, pipeline operators utilized the ASME B31.8 standard to determine
a pipeline's ``fitness for service.'' (This standard did not require
consistent record keeping.) The new regulations provided operators of
pre-regulation pipelines with several options for confirming the
Maximum Allowable Operating Pressure (MAOP) of the pipeline. Pre-
regulation pipelines could determine MAOP through pressure testing, in
the same manner required of pipelines constructed after 1970, or they
could demonstrate, using verifiable records, past operating history to
confirm the basis for the then-current MAOP. Many pre-1970 pipelines
elected this second option, which has come to be known as the
``grandfather clause.''
Engineering and operational history supports the assertion that
older pipelines are perfectly capable of safely remaining in service
for many decades to come. Just as with an older home, pipelines that
are well maintained can continue to provide reliable service. INGAA
does not agree with the notion that older pipelines should be replaced
simply due to their age. Age should not be the sole determinative
factor in deciding whether to replace a natural gas transmission
pipeline. Fitness for service is the correct focus. If a pipeline is
unfit for service, then it must be repaired or replaced--regardless of
age.
About 60 percent of U.S. natural gas transmission pipeline mileage
was installed before 1970. Most of these pipelines are performing well
and have records that the pipe had been pressure tested. INGAA supports
a process for confirming the ``fitness for service'' of pre-regulation
(or pre-1970) pipelines located in HCAs. This directly addresses the
fact pattern in the San Bruno accident. INGAA believes that for all
natural gas transmission pipelines operating in HCAs, an operator must
either produce adequate records verifying a pipeline's fitness for
service or reconfirm the fitness of that pipeline by pressure testing
or utilizing an equivalent new technology. INGAA believes there must be
a workable time-frame for completing this retesting to avoid
significant adverse consumer energy price impacts due to testing-
related pipeline capacity constraints and service disruptions. INGAA
suggests that such work be completed by 2020.
Section 27 of S. 275 is consistent with the approach we support,
and we believe it represents an effective legislative response to the
San Bruno accident. INGAA's recommendation to reconfirm the MAOP in
HCAs with testing or new technology, within a reasonable timeframe, is
focused, rational, and demonstrability improves safety. Conversely, if
the NTSB recommendation were implemented verbatim into regulation, all
pre-1970 pipes would be required to undergo a specific type of
hydrostatic pressure test, presenting a very problematic mandate. It is
important to recognize that a pipeline must be completely removed from
service, perhaps for up to several weeks, in order to be pressure
tested hydrostatically. Moving beyond HCAs to cover all pre-1970
pipeline mileage would increase greatly the likelihood and magnitude of
transportation service disruptions and increase consumer energy prices
due to pipeline capacity constraints. Furthermore, with hydrostatic
testing costs of approximately $250,000 to $500,000 per mile and with
approximately 179,000 miles of pre-1970 natural gas transmission
pipelines in the United States, the direct cost of such testing alone
could have a significant impact on consumer energy costs when included
in natural gas pipeline rates. This clearly is an area that should be
subject to a rigorous cost-benefit analysis and where the availability
of less costly and less disruptive alternatives to achieve the same
safety goals should be considered.
The INGAA action plan closely mirrors S. 275 on this issue. We
believe pre-1970 pipe segments, located in HCAs, that do not have
pressure test records should meet certain fitness-for-service
requirements by 2020. The lessons learned from this effort, which would
be focused on decreasing the risk to people, could then be applied to
broader pipeline segments beyond 2020. A key ``enabler'' for expanding
such testing will be the development and commercialization of smart pig
technology that could substitute for a hydrostatic test, and thereby
dramatically decrease testing costs and service disruptions, while at
the same time provide better data to operators. We believe that smart
pig research and development ultimately will be critical to meeting the
goals of the NTSB recommendation on pre-regulation pipelines.
Pipeline Isolation and Response Time
Incident response time is another part of the INGAA action plan.
Based on our meetings with emergency responders, the key issues for
improving incident response and mitigation are, first, rapid
recognition and, second, certainty of response. INGAA's members have
committed to have personnel on-site to coordinate with emergency
responders, and within an HCA, to isolate a damaged pipe section,
within one hour. In areas where an operator cannot get workers to an
incident scene promptly, automation (such as automatic or remotely-
controlled valves) is an option. Still, automation will not provide
that prompt face-to-face interface preferred by emergency responders.
Incident response should focus on performance, not specific
technology. Automatic and remotely controlled valves may be part of
improving response time, but they are not the only solution and alone
are not a complete solution. Valves cannot prevent an incident, nor are
they likely to reduce the number injuries or fatalities in the unlikely
event of a natural gas pipeline rupture and fire. Even with an
automatic or remote controlled valve, a high-pressure natural gas
pipeline can take significant time to depressurize following a rupture.
Most of the human impacts from a rupture occur in the first few
seconds, well before any valve technology could reduce the flow of
natural gas. It is important for policymakers to understand that the
primary benefit of isolating a damaged pipe segment--either through
personnel or through automation--is to mitigate property damage from
fire and allow emergency responders access to the impacted area.
INGAA supports section 5 of S. 275, which directs PHMSA to develop
a regulation for the installation of automatic and remotely controlled
valves on all new pipelines (including pipe replacements). We would
suggest, however, that such a requirement be focused on pipe segments
located in HCAs. Additionally, INGAA supports the provision in H.R.
2937 that would require the Secretary to review and report incident
response time for existing pipe segments located in HCAs.
NTSB's recommendations for valve automation and spacing, taken
literally, are very prescriptive and would result in the dedication of
significant resources to an issue that does not prevent accidents from
happening.
Pipeline Technology Research and Development
A common theme in this testimony has been the role that new
technologies can play in making it possible to chart a practicable and
achievable course for reaching the pipeline safety goals that all of us
share. The further development of smart pig technologies is absolutely
critical to achieving these goals. It will be important for industry,
government and other pipeline stakeholders to work together closely to
develop a research and development road map for the pipeline safety
technologies needed, an efficient and effective work plan for
developing and deploying these technologies, and a means to fund this
important R&D work.
Conclusion
Mr. Chairman, thank you once again for providing INGAA with the
opportunity to testify today. Our key messages are these: first,
reducing risk to people must remain the primary focus of the Federal
pipeline safety program; second, S. 275 would provide a constructive
framework for enhancing the pipeline safety program in a way that
maintains this important focus; and, third, given that we are at such a
critical moment in the evolution of our pipeline safety program, it is
important for Congress to act this year to enact the reauthorization
bill.
Senator Lautenberg. Thanks very much for your testimony,
Mr. Santa.
And Ms. Sames, Vice President of Operations and Engineering
for the American Gas Association, we look forward to hearing
your testimony.
Please, Ms. Sames, give us your testimony.
STATEMENT OF CHRISTINA SAMES, VICE PRESIDENT,
OPERATIONS AND ENGINEERING,
AMERICAN GAS ASSOCIATION
Ms. Sames. Thank you, and good afternoon. I appreciate the
opportunity to appear in front of the Subcommittee.
Pipeline safety is a critically important issue, and I
commend the Senate for passing a bipartisan bill, something a
little unusual in this day and age. I applaud you for that.
That bill will help to ensure that America continues to have
one of the safest, most reliable pipeline systems in the world.
I'm here today testifying on behalf of AGA, whose members
transport approximately one-fourth of the energy consumed in
the United States.
Natural gas is delivered to customers through a safe, 2.4
million mile underground pipeline system. This does include 2.1
million miles of distribution pipe, the local utility pipe, and
another 300,000 miles of natural gas transmission pipe. These
pipelines stretch across the country, covering and providing
service to more than 175 million Americans.
The industry has demonstrated that it can increase delivery
of natural gas while continuously making improvements in
safety. DOT data shows a continued downward trend in pipeline
incidents of approximately 10 percent every 3 years. While this
is a great record, clearly more has to be done. The tragic
incident in San Bruno reminds us that one accident is just
really one too many.
The leadership of AGA believes that the commitment must
start at the top, and our actions as leaders clearly
demonstrate that we are committed to achieving the goal of
pipeline safety.
AGA's already addressing a number of NTSB recommendations,
proposed legislation, and PHMSA's advanced notice of proposed
rulemaking on gas transmission integrity management.
We are also moving forward with other initiatives that we
believe will improve safety. Most notably, during today's
hearing, the AGA board of directors met and just approved a
number of significant actions that distribution and intrastate
transmission operators can take to enhance pipeline safety.
This commitment to enhancing safety addresses key
recommendations of the NTSB, of Congress, of PHMSA, and of the
states. AGA members also commit to continuing proactive
initiatives that we truly believe are enhancing safety. This
includes engaging CEOs and executive leaders in safety
improvement.
Back in 2007, AGA created a board-level safety committee
that meets regularly to focus on pipeline, customer, employee,
contractor, and vehicular safety. The AGA board has adopted a
safety culture statement that states that all employees, as
well as the contractors and suppliers providing services to AGA
members, are expected to place the highest priority on safety.
We have an evergreen safety action plan, and hold an annual
executive leadership safety summit. Our next summit will
actually be November 7th and 8th; it will be our fifth one, and
I invite the members of the Subcommittee to join my leaders at
that summit.
AGA's taken a number of voluntary steps to promote safety
in direct response to Secretary LaHood and the NTSB's calls to
action on safety. This includes creating a technical task force
focused on pipeline fitness for service, records, maximum
allowable operating pressure, automatically and remotely
controlled shutoff valves, and emergency response.
We are working with other pipeline trade associations in
the U.S. and Canada on a comprehensive study to explore
initiatives currently utilized by other sectors, as well as the
pipeline industry, in order to share information more wisely.
We're committed to continuing our work on excavation
damage, one of the leading causes of pipeline incidents. AGA's
actually a cofounder of the Common Ground Alliance, and
supports a number of initiatives to address excavation damage.
We believe that more industry research is needed in order
to improve inline inspections, direct assessment,
nondestructive testing, and leak detection. Many companies are
members of research consortiums and contribute toward research.
On October 4, AGA actually hosted a meeting of the research
consortiums and the national pipeline trade associations in
order to begin our work on NTSB recommendation P-11-32, and
create a path forward for near and long-term research.
Finally, AGA members are committed to finding new and
innovative ways to inform and engage stakeholders. This
includes emergency responders, public officials, excavators,
and members of the public living in the vicinity of pipelines.
On September 25, AGA and INGAA sponsored an emergency
response workshop presented by the National Association of
State Fire Marshalls. We're working on an emergency responder
checklist to assist communications, and we'll participate in
PHMSA's emergency response workshop later this year.
In conclusion, the natural gas utility industry has a
strong safety record. Recognizing the critical role that
natural gas can and should play in meeting the Nation's energy
needs, we're committed to working with all stakeholders to
improve. To that end, we applaud this committee's focus on the
common goal to enhance the safe delivery of a vital energy
resource.
Thank you.
[The prepared statement of Ms. Sames follows:]
Prepared Statement of Christina Sames, Vice President, Operations and
Engineering, American Gas Association
Good morning, Mr. Chairman and members of the Committee. Pipeline
safety is a critically important issue, and I commend you for the
bipartisan support that members of Congress have provided over the
years to ensure that America has one of the safest, most reliable
pipeline system in the world.
I am here testifying today on behalf of the American Gas
Association (AGA), which was founded in 1918, and represents over 200
local energy companies that deliver clean natural gas throughout the
United States. There are more than 70 million residential, commercial
and industrial natural gas customers in the U.S., of which 91 percent--
more than 65 million customers--receive their gas from AGA members. AGA
is an advocate for natural gas utility companies and their customers
and provides a broad range of programs and services for member natural
gas companies, pipelines, marketers, gatherers, international natural
gas companies and industry associates.
Natural gas pipelines, which transport approximately one-fourth of
the energy consumed in the United States, are an essential part of the
Nation's infrastructure. Natural gas is delivered to customers through
a safe, 2.4-million mile underground pipeline system. This includes 2.1
million miles of local utility distribution pipelines and 300,000 miles
of transmission pipelines that stretch across the country, providing
service to more than 175 million Americans. The recent development of
natural gas shale resources has resulted in abundant supplies of
domestic natural gas, which has meant affordable and stable natural gas
prices for our customers. America needs clean and abundant energy and
America's natural gas provides just that. This has made the safe,
reliable and cost-effective operation of the natural gas pipeline
infrastructure even more critically important, as it is our job to
deliver the natural gas to the customer.
Critical Pipeline Infrastructure
AGA believes that the domestic abundance of natural gas and the
resulting price stability, when combined with the other advantages of
natural gas--including its environmental attributes and efficiency of
use--presents us with an unprecedented opportunity. There is direct use
of natural gas in core residential and commercial markets, expanding
use for gas-fired electric generation, and the transportation market
where natural gas vehicles can displace some traditional diesel-and
gasoline-based vehicles. These actions will save consumers billions of
dollars in related energy costs, reduce greenhouse gas emissions and
enhance America's energy security by reducing our reliance on imported
oil. Our industry can help meet America's need for clean and abundant
energy by delivering more of America's fuel--natural gas--not just in
2011, but also well into the future. Indeed, natural gas should now be
considered a foundation fuel for the country.
Shale production grew from about 1 billion cubic feet (Bcf) per day
in 2000 to about 15 Bcf per day by year-end 2010, thus forming nearly
twenty-five percent of all domestic dry natural gas production. U.S.
shale gas production is now spread between Appalachian states, the mid-
continent, Texas, Louisiana, Arkansas and even the Michigan basin. The
pipeline infrastructure is being expanded to accommodate large shale
gas resources in the Northeast and other parts of the Nation. As shale
production and the natural gas infrastructure grow to take advantage of
this abundant resource, it must be done with a focus on safety. The AGA
Board of Directors recently adopted principles for Responsible Natural
Resource Development. These principles address a foundation for the
sustainable and responsible development of all natural gas resources in
our country and underscore the commitment of local natural gas
utilities to the communities they serve. Not only will this significant
production help to ensure a stable supply of natural gas, it will also
provide new jobs. Estimates are that in 2011, the Marcellus Shale
region alone will directly or indirectly create 122,000 new jobs. All
told, 2.8 million people are directly or indirectly employed by the
natural gas industry.
Industry's Demonstrated Commitment to Safety
The industry has demonstrated that it can increase the delivery of
natural gas while continuously making improvements in safety. The data
from the Department of Transportation's Pipeline & Hazardous Materials
Safety Administration (PHMSA) shows a continual downward trend in
pipeline incidents of approximately 10 percent every three years. AGA
has analyzed data from the PHMSA database and leaks, serious incidents,
and significant incidents are continually being reduced.
Over the last twenty years, we have seen improvements in leak
reduction (49 percent), as well as significant incidents (29 percent)
and serious incidents (49 percent). But clearly more needs to be done.
The tragic incident in San Bruno, California reminds us that one
accident is one too many. The leadership of AGA believes that
commitment must start at the top in any organization or business. Our
actions as leaders in reducing incidents and leaks clearly demonstrate
that we are fully committed to achieving the goal of improving pipeline
safety.
AGA'S Review of the NTSB Report, Legislation and Regulations
AGA commends the Committee for developing a solid bipartisan bill
for pipeline safety. Everyone has the common goal of continuing to have
a safe, reliable and efficient national pipeline infrastructure.
Congressmen, public utility commissioners, regulators, gas utility
leaders, and utility hourly employees all agree that safety is the top
priority.
It is important to highlight that the NTSB investigative process,
pipeline safety reauthorization, and rulemaking by PHMSA are separate
and distinct processes. AGA has provided support for each of these
processes. AGA and its Operations Section chairman, Charles Dippo, Vice
President of Engineering Services and System Integrity for South Jersey
Gas, testified at the NTSB San Bruno hearing in March 2011 on
activities that operators and the association are doing to promote
pipeline safety. Mr. Dippo also testified at several House and Senate
hearings. AGA technical committees have engineers from its operating
companies reviewing the NTSB report, legislation and PHMSA proposed
rulemaking.
The investigative process of this tragic accident is complete and
there are important lessons to learn. Industry must be prudent in
moving forward to enhance its safety practices. On the positive side,
the facts associated with this accident appear to be unique and not
part of a systemic problem. The NTSB investigation showed that there
were good engineering practices in place as early as the 1940s that
required gas transmission pipe to use high grade steel, to be pressure
tested at the mill, to be properly field inspected, and to operate at a
maximum allowable operating pressure (MAOP) with a margin of safety.
All of the 42 miles of the Line 132 that failed were constructed to
industry standard and in good condition, except six approximately four
foot sections that were installed when 1,825 feet of the line was
relocated in 1956. The NTSB stated that the proximate cause of the San
Bruno incident was,
``the Pacific Gas and Electric Company's (PG&E) (1) inadequate
quality assurance and quality control in 1956 during its Line
132 relocation project, which allowed the installation of a
substandard and poorly welded pipe section with a visible seam
weld flaw that, over time grew to a critical size, causing the
pipeline to rupture during a pressure increase stemming from
poorly planned electrical work at the Milpitas Terminal; and
(2) inadequate pipeline integrity management program, which
failed to detect and repair or remove the defective pipe
section.''
AGA has circulated the full NTSB report to its members companies
and they are analyzing the facts and the recommendations for
consideration in their operations. AGA believes that the NTSB staff did
an excellent job investing this unique incident and now it is time to
address their findings through the regulatory process.
There was one NTSB safety recommendation to AGA. The recommendation
states,
``Report to the National Transportation Safety Board on your
progress to develop and introduce advanced in-line inspection
platforms for use in gas transmission pipelines not currently
accessible to existing in-line inspection platforms, including
a timeline for implementation of these advanced platforms. (P-
11-32).''
On October 4, AGA hosted a meeting that was attended by all of the
national pipeline trade associations and the following research
organizations; Gas Technology Institute, NYSEARCH, Operations
Technology Development, and the Pipeline Research Council International
(PRCI). The meeting was designed to develop answers to NTSB Safety
Recommendation P-11-32 and created a path forward for near and long-
term R&D for the pipeline industry.
AGA commends the Subcommittee on Surface Transportation and
Merchant Marine Infrastructure, Safety, and Security for developing a
comprehensive pipeline safety bill for reauthorization. AGA believes
the bill provides a balance of prescriptive mandates from Congress that
leaves technical details to be implemented by the Secretary of
Transportation through regulation. AGA sent a letter to Congress urging
the immediate passage of the bill. There has already been thorough
discussion on every aspect of the bill and we urge Congress to pass the
bill by unanimous consent so that regulators and industry can begin
immediate implementation of the safety improvement ordered by Congress.
Finally, PHMSA has already begun the regulatory process to address
many of the integrity management issues related to the NTSB San Bruno
investigation and contained within Senate bill 275. PHMSA issued an
advance notice of proposed rulemaking on August 25 that contained 191
questions, many with subparts. AGA and its member companies have a
number of technical committees reviewing the questions and developing
responses that are due December 2. The notice includes all aspects of
integrity management including in-line inspection, pressures testing,
expanding high consequence areas (HCAs), installation of automatic or
remotely controlled valves, and managing pipe that has not had a post
construction hydrotest, but has a long history of stable operation
below established MAOPs.
Raising the Bar for Safety
Along with addressing the findings in the NTSB investigation, new
legislation and the PHMSA proposed rulemaking, industry must keep its
focus on key safety initiatives that are already underway and are
showing success. AGA has been, and continues to be, actively engaged in
all aspects of pipeline safety. This includes the following:
Engaging CEOs and executive leadership in safety
improvement--In 2007, AGA created a board-level safety
committee that focuses on pipeline safety, customer safety in
the home, employee safety, contractor safety and vehicular
safety. The committee meets regularly to share lessons learned,
review safety statistics, and identify ways to further improve
safety. This committee has developed a Safety Information
Resource Center that includes safety alerts, safety messages,
safety statistics, information on motor vehicular safety and
case studies. In addition, AGA and our executive leadership
hold an annual Safety Summit that brings together key safety
personnel and leaders in safety from government and a variety
of industries to share lessons learned.
Sharing Safety Information--AGA has 14 technical committees
and an operations managing committee focusing on a wide range
of operations and safety issues. The technical committees
develop and share information, including those issues raised by
Secretary LaHood, PHMSA and the National Transportation Safety
Board. In addition, AGA has three Best Practices Programs
(distribution, transmission and supplemental gas) focused on
identifying superior performing companies and innovative work
practices that can be shared with others to improve operations.
AGA is also the Secretariat for the National Fuel Gas codes and
the Gas Piping Technology Committee.
State Safety and Rate Mechanisms--Gas utilities operate
under the safety and rate making jurisdiction of state utility
commissions. AGA serves as a clearinghouse to document the
effective cost-recovery mechanisms that various states have
used to fund infrastructure maintenance and replacement
projects. AGA provides technical and regulatory information at
regional and national meetings of state utility commissioners
and pipeline safety regulators.
Publications--AGA has developed a number of publications
dedicated to improving safety and operations. This includes
publications on corrosion control, gas control, integrity
management, odorization, plastic piping, purging principles and
practices, repair and replacement, worker safety practices,
contractor safety, natural gas pipelines and unmarked sewer
lines, alarm management, directional drilling and emergency
shutdown.
Actions Supporting the NTSB and DOT Secretary Calls to Action
AGA has taken a number of voluntary steps to promote safety in
direct response to the NTSB recommendations and Secretary LaHood's call
to action on pipeline safety. This includes creating technical task
forces focused on addressing a pipeline's fitness for service, records,
maximum allowable operating pressure, automatic and remotely controlled
shutoff valves, and emergency response. We have held a number of
workshops, teleconferences and other events to share information, and
have initiated a Safety Information Safety Study with other pipeline
trade associations, including our Canadian counterparts. In addition,
the AGA Board of Directors has finalized and adopted a Safety Culture
Statement to show its commitment to promoting positive safety cultures
and, today, the Board will adopt AGA's Commitment to Enhancing Safety,
a list of commitments that AGA and its members are willing to take to
improve safety. Additional details are listed below:
Pipe Fitness for Service--AGA brought together two task
forces to develop guidance on how to determine a distribution
or transmission pipeline's fitness for service, including the
critical records needed for this determination, and the maximum
allowable operating pressure on a transmission pipeline.
Distribution and transmission piping serve different purposes
and have very different characteristics for examining fitness
for service. The initial documents were submitted for the DOT
Report to the Nation. Also under development are more
comprehensive documents focused on the fitness for service
considerations, the level of accuracy needed for critical
records, how to address gaps in records, and how to obtain new
information to address record gaps and update records. These
documents are expected to be finalized in Fall 2011.
Transmission Records Verification Process--AGA developed a
technical paper to provide guidance on determining the maximum
allowable operating pressure of a transmission pipeline. This
technical paper was finalized in April and distributed to
operators and Federal and state regulators. Additional work is
being conducted by the task forces listed above and a companion
document to the April technical paper will be issued in the
Fall of 2011.
Safety Information Sharing Study--In order to share safety
information amongst all operators, AGA is working with the
Interstate Natural Gas Association of America (INGAA), the
American Petroleum Institute (API), the Association for Oil
Pipelines (AOPL) and our Canadian counterparts, the Canadian
Gas Association and the Canadian Energy Pipeline Association,
on a comprehensive study to explore safety sharing initiatives
currently utilized by other sectors in the economy, as well as
the pipeline industry. It is our hope that by learning from
others, the energy pipeline industry can identify and implement
a model that will measurably improve pipeline system safety.
The safety management study is expected to be completed as
early as February of 2012.
Gas Utility Emergency Response--The safety performance of
the natural gas pipeline industry is largely attributed to a
well designed and maintained infrastructure. Operators must
also be prepared to respond quickly to address potentially
dangerous situations. Consistent with PHMSA advisories, an AGA
task group is developing a checklist that will enable operators
to enhance their emergency response communications and
education programs. This emergency check list will be completed
in the fall of 2011.
Automatic and Remotely Controlled Valves--AGA has developed
a technical paper on Automatic and Remotely Controlled Valves.
The technical paper presents the benefits and disadvantages of
their installation on new, fully replaced and existing
transmission pipelines, especially as it relates to the gas
transmission pipelines embedded into distribution systems. The
initial technical document was completed in March 2011 and AGA
is developing a more comprehensive technical paper that is
expected to be completed by December of 2011.
Safety Culture Statement--In February of 2011 the AGA Board
of Directors adopted a Safety Culture Statement to show its
commitment to promoting positive safety cultures among
employees throughout the natural gas distribution industry. All
employees, as well as contractors and suppliers providing
services to AGA members, are expected to place the highest
priority on employee, customer, public and pipeline safety. The
Safety Culture Statement addresses the commitment by management
to promoting open and honest communications across all levels
of an organization, identifying hazards, managing risks,
planning the work and working the plan, and promoting a
learning environment and personal accountability.
Infrastructure Replacement Rate Mechanisms--AGA, INGAA and
API have developed a document to explain to the public the
ratemaking mechanisms used for the pipeline infrastructure. A
well designed rate reflects the input of all stakeholders and
the importance of factors such as expanded safety programs,
infrastructure repair and replacement. Such a rate design also
recognizes the changing methods of cost recovery and other
factors.
Technical Workshops, Teleconferences and Other Events to
Share Information--Information sharing is critical to improving
safety. AGA has held a number of workshops, teleconferences and
other events to promote the sharing of pipeline safety
information. This includes numerous technical committee
meetings; workshops on emergency response, transmission
integrity management, vintage pipelines and utility contractor
management; regional operations executives' roundtables; and
roundtables on external corrosion, damage prevention and
marking and locating. In addition, the AGA Operations
Conference and Exhibition, which was held in May of 2011 and
included technical sessions on the management of vintage pipe,
distribution and transmission integrity management, emergency
management, pipe replacement, welding repair qualification
procedures, leak detection, corrosion assessment, MAOP,
qualification of personnel, control room management, sewer
cross bores, compression fittings, worker safety, weld failure
mechanisms, safety culture, contractor management, improving
communications, and new construction. AGA also participated in
the workshops that PHMSA held on weld seams and integrity
assessments and its revised annual and incident reporting
forms.
The Safety Path Forward
AGA has developed additional actions that distribution and
intrastate transmission pipeline operators can take to enhance pipeline
safety. This plan will be voted on by the AGA Board of Directors at its
October 2011 meeting.
In addition to the actions identified above, AGA believes
additional safety actions need to continue in order to improve pipeline
safety consistent with the intent of Congress. AGA supports timely
reauthorization of the pipeline safety law and in July sent a letter to
the Senate requesting passage of the Senate bill 275. This is a
constructive vehicle to meet our common objective for a safer system
that also can effectively meet our Nation's energy needs. AGA members
are already engaged to take action on the following:
Damage Prevention--AGA is a founder of the Common Ground
Alliance and supports programs that address excavation damage,
which is one of the leading causes of pipeline safety
incidents. Based upon 2008 data collected by the Common Ground
Alliance, excavation damages for all underground facilities
have decreased by approximately 50 percent compared to 2004
data. AGA believes a significant cause of this reduction is the
work done by the pipeline industry in promoting the use of 811,
the national number for people to call before they dig. AGA
members are working at the state level to promote participation
in One-Call programs by all underground operators and all
excavators. They also want state legislation with flexible and
effective enforcement that prohibits municipalities, state
agencies or their contractors from being exempt from One-Call
notification requirements.
Transmission Integrity Management Enhancements--AGA's
distribution company members operate approximately 45,000 miles
of natural gas transmission pipeline in the United States.
These pipelines generally have different operating
characteristics from interstate natural gas pipelines.
Transmission pipelines operated by distribution companies are
often embedded within the distribution network that serves
residential, commercial and industrial customers, and they
operate at lower stress levels.
AGA members are committed to immediately engaging in public
discussions to evaluate whether gas transmission integrity
management should be expanded beyond HCAs, and the benefits and
disadvantages of applying the integrity management principles
to additional areas. Many AGA members are required to manage
Distribution Integrity Management Programs (DIMP) and
Transmission Integrity Management Programs (TIMP) programs, so
the effectiveness, inefficiencies and duplication of multiple
integrity management programs must also be explored. AGA
members are committed to evaluating how various low-stress
pipelines operating below 30 percent SMYS would benefit by
using elements from either or both programs.
Data Collection and Sharing--Collecting accurate data and data
analysis are integral to determine areas for pipeline safety
improvement. AGA is committed to working with PHMSA, state
regulators and the public to create a data quality team made up
of representatives from government, industry and the public,
similar to the PHMSA technical advisory committees. The team
could analyze the data that PHMSA collects and determine
opportunities to improve pipeline safety based on the data
analysis. The team could also identify gaps in the data that
are collected by PHMSA and others, identify ways to improve the
collected data, and communicate consistent messages about
pipeline incident data.
Research & Development--More industry research is necessary to
improve in-line inspection tool quality, operator use of tool
data, direct assessment tools, non-destructive testing and leak
detection. Many pipeline companies have direct memberships in
research consortiums and contribute towards research. These
research consortiums include Pipeline Research Council
International (PRCI), NYSEARCH and Operations Technology
Development (OTD), Utilization Technology Development (UTD) and
Sustaining Membership Program (SMP). In the last five years,
hazardous liquid and gas pipeline operators have contributed
more than $115 million to research and development. However,
R&D cannot be successful without cooperative planning between
industry and government. As noted above, AGA is committed to
improving the transparent collaborative relationship with PHMSA
that has historically enhanced pipeline safety R&D.
Emergency Response--AGA members are committed to finding new
and innovative ways to inform and engage stakeholders,
including emergency responders, public officials, excavators,
consumers and safety advocates and members of the public living
in the vicinity of pipelines. AGA and INGAA sponsored a
workshop on September 26 that was presented by the National
Association of State Fire Marshals. The workshop had
approximately 60 emergency responders, PHMSA staff and 40
operator personnel in attendance.
AGA, PHMSA, NTSB, and the public have the common goal of continuing
to keep the pipeline infrastructure the most safe and efficient mode of
energy transportation in America. AGA is confident that the commitments
to safety listed above will indeed achieve that goal.
Summary
In conclusion, the natural gas utility industry has a strong safety
record. Recognizing the critical role that natural gas can and should
play in meeting our Nation's energy needs, we are committed to working
with all stakeholders to improve. To that end, we applaud this
committee's focus on the common goal: to enhance the safe delivery of
this vital energy resource.
Senator Lautenberg. Ms. Quarterman, the NTSB made more than
a dozen recommendations to PHMSA, and its report on the San
Bruno accident. Now, how quickly can PHMSA move forward on
addressing these recommendations?
Ms. Quarterman. Mr. Chairman, we started to address these
recommendations before the report came out. As I mentioned in
my written testimony, we issued a couple of safety advisories
earlier in the year, one before the incident in response to
actually the Michigan incident with respect to emergency
response. We have a couple of recommendations associated with
that from NTSB that will require some tweaking of those
advisory bulletins.
We also issued an advisory bulletin with respect to
recordkeeping and risk assessment, and we've held workshops on
those issues. We have also issued an advanced notice of
proposed rulemaking that addresses many of the provisions
related to maximum allowable operating pressure, grandfathering
of pipe, the automatic and remote control shutoff valves. So we
are well on the way to, we hope, getting rid of these current
recommendations that NTSB has made and closing them.
Senator Lautenberg. So, how long more might it take to
install the remainder of the recommendations that you've made?
Ms. Quarterman. We're subject to the vagaries of the
rulemaking process, which take years. I mean, we're not talking
about this happening overnight. We're talking about a few years
to get these rules in a position where they become final.
Senator Lautenberg. Ms. Hersman, and also Mr. Kessler, the
NTSB's investigation into the San Bruno explosion found that
PG&E knew very little about the 50-year-old pipe that ruptured.
How could this explosion have been prevented, if the company
didn't know? Would better recordkeeping have made the
difference here? More information? What might have been done?
And it sounds like this could have been--I don't want to
trifle with this, but easily fixed. And it just didn't happen.
What do you think the principle reason for this was? Was it
poor recordkeeping? What was it?
Ms. Hersman. Poor recordkeeping is a symptom, certainly, of
the problems with this system. But really that installation of
the flawed pipe was what set all of this into motion. The pipe
they installed were substandard quality. We know that there
were welds that were substandard quality. This was an accident
that was waiting to happen.
Since the pipe was installed, the line was not tested
hydrostatically and no inline inspections were performed; it
lay there for over 50 years before this accident occurred.
During all that time, they had the potential to identify
problems, but the fact that their records were bad resulted in
faulty risk assessment and they continued to overlook this
pipe.
Senator Lautenberg. How much time might have been needed to
fix this, if discovered?
Ms. Hersman. I would defer to Mr. Stavropoulos to respond.
Certainly, if they had discovered this section of pipe, I think
it would have raised their interest in this area of pipe and
probably would have led them to test it, inspect it, and remove
it.
Senator Lautenberg. Mr. Stavropoulos, the investigation
identified deficiencies of PG&E's recordkeeping, emergency
response procedures, and the management of its system.
Now, PG&E has been aware of some of these deficiencies
since incidents that occurred as far back as 1981. What's PG&E
done to remedy the deficiencies that the NTSB has identified as
a systemic problem?
Mr. Stavropoulos. Well, Mr. Chairman, one of the first
things that PG&E has done is to reorganize its gas business.
And, really, the problems identified by NTSB is the primary
reason why they asked me to join the company and bring my 30
years of experience of dealing with old infrastructure in the
United States, to see what we can do to quickly remedy the
situation regarding recordkeeping, regarding the integrity
management flaws that had been identified, our procedures
around clearances to do work on the pipeline, our emergency
response procedures.
We've reorganized--I've been with the company almost 4
months. We've completely reorganized our gas management team. I
brought in other senior leaders from across the country. I've
traveled to--not only using my experience, but that of others,
to address the problem.
Senator Lautenberg. Now, I'm going to turn to Senator
Wicker and--but I have continuing questions for some of you.
Thank you.
Senator Wicker. Thank you very much, Mr. Chairman. Ms.
Sames, how do you pronounce your name?
Ms. Sames. Sames.
Senator Wicker. Sames, just like it's spelled. Here we are.
[Laughter.]
Ms. Sames. I get mispronunciation a lot.
Senator Wicker. Well, I won't mispronounce it again since
it's so easy.
Thank you for acknowledging that one accident is too many.
And particularly such a horrific incident as we had in San
Bruno is just unthinkable, and horrific.
But you do talk about the improvement in safety statistics
over time. A 49 percent improvement in leak reduction, 29
percent in significant incidents, and 49 percent improvement in
serious incidents. Now those are not your data, are they?
Ms. Sames. They are not. This is data collected by the
Department of Transportation, by PHMSA. We rely on their data
for these statistics.
Senator Wicker. OK. Do they, to your knowledge, have data
as to injuries and fatalities?
Ms. Sames. They do. PHMSA collects data on all incidents
that result in a death, an injury, or significant property
damage.
Senator Wicker. And has there also been a steady
improvement in the record with regard to fatalities and
injuries?
Ms. Sames. I would need to look at PHMSA's data. I don't
know that off the top of my head. But I do know that the number
of incidents have been decreasing over time, and I find that to
be a good sign.
Senator Wicker. Well, absolutely.
Ms. Sames. But more needs to be done--completely recognize
that.
Senator Wicker. Ms. Quarterman, is the term ``serious
incident'' a term of art--is the term ``significant incident''
a term of art that we use in PHMSA.
Ms. Quarterman. They are terms of art, and to answer the
question you just asked about the number of fatalities--we have
seen an increase in the number of fatalities over the past 3
years. We do not like to see that.
We have to always be cognizant of the fact that despite the
good record in terms of the number of incidents, we need to
continually improve the program.
Senator Wicker. Well, that--that is interesting. You know,
if serious incidents have decreased and significant incidents
have decreased, and fatalities have increased, it seems that we
might need to change the definition within the office, just
within the agency just so we can be clear there.
Let me move, though, Ms. Quarterman, to Mr. Kessler's
observation that is backed up by recommendations, that the
state agency did a bad job. And one of the main reasons for
that is that PHMSA appeared to have handed off responsibility
while never doing any meaningful oversight.
Now, apparently that's going to be improved under your
watch. Was insufficient resources an issue in this lack of
oversight leading up to San Bruno?
Ms. Quarterman. Well, I think resources are always a
challenge. We--the Pipeline Safety Program is only 200
employees, of which about five or six oversee the 52 programs
that are run by the states.
I would say that I think that when the pipeline safety law
was first put in place, which was late 1960s, early 1970s,
you've heard a majority of this pipeline was already in the
ground. And in fact, many of the states were already regulating
these programs, the intrastate gas programs, and so the
legislation was very strong in that it wanted the states to be
in charge of many of these programs. They don't want to
completely upset the apple cart, and therefore there's a strong
certification program for the states, and the states have, in
fact, been certified.
I think this is a huge challenge for the Pipeline Safety
Program in terms of being able to have a consistent regulatory
practice across all the states, when you have to oversee so
many states with so few people in the oversight position.
That's something that we would like to see improved going
forward.
We have talked with our partners in the states about how we
would like to make their data more transparent. For example, we
right now have all of our data available to anybody in the
United States. The individual state records are not available
to them or to us. So we want to be more consistent in our
implementation.
Senator Wicker. Mr. Kessler, is it a good idea for 30-inch
natural gas pipes to be running through residential areas like
this?
Mr. Kessler. I don't know that it's a good or bad idea,
Senator. I think it certainly can be done.
Senator Wicker. How prevalent is that?
Mr. Kessler. Sorry?
Senator Wicker. How prevalent is that in these little
residential communities like San Bruno?
Mr. Kessler. I'm not sure off the top of my head.
Senator Wicker. Anyone answer that?
Mr. Kessler. The Administrator may have a better idea. But
I do know that this----
Senator Wicker. Is this happening frequently? I understand
this pipe was defective.
Mr. Kessler. Right. We do----
Senator Wicker. But is there the likelihood that thousands
of people watching this today have 30-inch natural gas
pipelines running through their subdivisions without their
knowledge?
Mr. Kessler. There are large, significant transmission
lines are running through people's neighborhoods without their
knowledge. Not wholly the fault of the industry, because many
of these communities popped up on top of the pipelines.
But, yes, we have a real problem in that local governments
don't know what's below, that local residents don't know what's
below, and I think that it can be safe but without the
knowledge, without the inspections, it may not be.
Senator Wicker. Thank you.
Senator Lautenberg. I'm going to call on Senator Boxer and
ask her please to take the chairmanship, if she will, as she
asks her questions.
And please excuse me. Thank you all for what you've done.
Senator Boxer [presiding]. Thank you. Senator Lautenberg,
thank you so much for your leadership here.
I have a lot of questions, so I may have a couple of
rounds. If Senator Wicker wants some more rounds, that's great
with me. We'll just go as long as we can.
I want to start with PHMSA because PHMSA got a pretty bad
rap from the NTSB, and I want to discuss this. They say
specifically on page 121, the NTSB concludes that the PHMSA
integrity management inspection protocols are inadequate, and
they go through a whole host of things you should do:
incorporate a review of meaningful metrics, require auditors to
verify the operator has a procedure in place for ensuring the
completeness and accuracy of underlying information, three,
require auditors to review all integrity management performance
measures reported to PHMSA, and compare the leak failure and
incident measures to the operator's risk model, and four,
require setting performance goals for pipeline operators at
each audit and follow up on those goals at subsequent audits.
Have you begun the process of changing your protocols?
Ms. Quarterman. We have not begun the process of changing
our protocols. And I actually had a conversation with
Chairwoman Hersman yesterday to talk about those particular
provisions, to ask that we might meet with them to understand
more what it is they have in mind when they made those
recommendations.
Senator Boxer. Well, it's not that complicated, is it? It
says, ``Incorporate a review of meaningful metrics, require
auditors to verify the operator has a procedure in place for
ensuring the completeness and accuracy''--this is plain
English. You have not started to change your protocols? After
this?
And I want to put up this picture again. This happened, and
you have not started to change your protocols? I don't get it.
Ms. Quarterman. We believe that we do have protocols in
place, that's why we'd like----
Senator Boxer. So you don't agree with the NTSB after they
made that exhaustive investigation?
Ms. Quarterman. I'm not saying I don't agree with them, I'm
saying that I don't necessarily understand what their
recommendations mean beyond what we have in place.
Senator Boxer. OK. Well, I would suggest you look at page
121. It's the clearest English. I mean, I understand it and I
know compared to what you know, this much. But it's not so
difficult--you gave the CPUC very high grades, didn't you?
Ms. Quarterman. Grades with respect to its program?
Senator Boxer. Yes.
Ms. Quarterman. I believe that it was rated--perhaps there
were two others with lower scores than they. So they weren't
the highest rated, obviously they were near the bottom.
Senator Boxer. Well, weren't they in the 90s? They had a
rating of 99 percent to 100 percent, and then you say ``our
partners in the states?'' I'm all for you cooperating with your
partners, but you have an obligation to ride herd on them.
And I'm very concerned. This started the first time we
spoke, and I thought maybe today you'd have some better
answers. Now you also said in your questioning from Senator
Lautenberg, this is going to take several years to change
rules. Look at this. You think the people are going to stand
for that, if--God forbid it's anything even close to this.
Ms. Quarterman. I would love to have rules in place sooner
than that.
Senator Boxer. Good.
Ms. Quarterman. Unfortunately, I can't control the process.
Senator Boxer. Well, yes, I understand that you have the
ability to act in emergency orders. You have that don't you in
this case? Don't you think this requires emergency orders, to
immediately test and immediately talk to your partners in the
state to see if there's even a remote chance that this could
happen again?
Let me just say my opinion, from watching you and your
testimony. You are a well-meaning woman, but so far you haven't
understood what the NTSB did. You should watch this video. You
don't understand what they said, or your people don't
understand what they said. You're going to have a meeting. When
are you going to meet with them to understand what they said?
When are you going to have a meeting with them?
Ms. Quarterman. As I mentioned in my written and oral
testimony, we have been out front in terms of trying to respond
to this incident, issuing several safety advisories and going
forward with rulemaking. We would love to meet with the NTSB as
soon as they're available. We discussed this yesterday. We
don't expect----
Senator Boxer. Good. Ms. Hersman, are you available to meet
with Ms. Quarterman ASAP?
Ms. Hersman. Yes, ma'am.
Senator Boxer. I would like to have a report about that
meeting, if I could, as soon as you meet. I'd like to know that
you met and I'd like to know how it went, and if it's
appropriate, I would love to send someone there just to be
present. But if you don't think that's appropriate we don't
have to.
But I don't sense this feeling of emergency in your voice,
Ms. Quarterman. And I walked this area. People are dead because
of this. You know what they were doing? They were sitting in
their house having a cup of coffee. That's what they were
doing. This could happen anywhere in America.
And your agency gave 100 percent rating to the CPUC. Your
partner. Listen, that is not being an oversight agency. And
what regulations are you writing now? Can you share that
information with us? You said several regulations. What do they
include?
Ms. Quarterman. Our regulations relate to matters beyond
this particular incident, but they also relate to the remote
control shutoff valves, the measurement of the MAOP.
Senator Boxer. What's MAOP?
Ms. Quarterman. The maximum allowable operating pressure
for the pipeline.
Senator Boxer. Well, that is related. Both of those things
are related to this incident.
Ms. Quarterman. Well, I know they are related.
[The information referred to follows:]
U.S. Department of Transportation,
Washington, DC, December 14, 2011
Hon. Deborah A.P. Hersman,
Chairman,
National Transportation Safety Board,
Washington, DC.
Dear Chairman Hersman:
I am sending you this letter in response to the National
Transportation Safety Board's (NTSB) safety recommendations P-11-8
through -20 and P-11-1 and P-11-2 (Reclassification) issued to the
Pipeline and Hazardous Materials Safety Administration (PHMSA) on
September 26, 2011. The NTSB made these recommendations following its
investigation of the tragic September 9, 2010 natural gas pipeline
rupture in the city of San Bruno, California. We were pleased to
provide substantial support to the NTSB during this investigation, and
I want to assure you that we are acting expeditiously to address the
significant risks our investigation revealed in this incident. As you
know, PHMSA began addressing these risks through both regulatory and
non- regulatory means even before the investigation was officially
concluded.
PHMSA takes all recommendations from the NTSB seriously and I want
to assure you and the rest of the Board that we are focused on
addressing all pipeline safety recommendations as expeditiously as
possible.
The following text will identify the San Bruno NTSB recommendations
by number, and PHMSA's response to each:
NTSB Safety Recommendation P-11-8:
Require operators of natural gas transmission and distribution
pipelines and hazardous liquid pipelines to provide system-
specific information about their pipeline systems to the
emergency response agencies of the communities and
jurisdictions in which those pipelines are located. This
information should include pipe diameter, operating pressure,
product transported, and potential impact radius. This
recommendation supersedes Safety Recommendation P-11-1.
PHMSA Actions:
On November 3, 2010, PHMSA issued Advisory Bulletin PHMSA-2010-0307
regarding Pipeline Safety: Emergency Preparedness Communications. PHMSA
expanded on that effort through an Emergency Responder Forum, which was
held on December 9, 2011 at the U.S. Department of Transportation's
Headquarters in Washington, D.C. The NTSB was invited to attend. This
Forum convened leaders from the emergency responder community, Federal
and State Government, the public, and the pipeline industry to begin
development of a strategy and action plan for improving emergency
responders' ability to prepare for and respond to pipeline emergencies.
Our Forum evaluated available resources and current regulatory
requirements, and drew lessons from several recent pipeline accidents,
and sought to reveal potential gaps in information firefighters and
other emergency responders need to prepare for and respond to natural
gas and hazardous liquid pipeline emergencies adequately.
PHMSA will create a plan to address this recommendation now that
the Forum is completed.
NTSB Recommendation P-11-9:
Require operators of natural gas transmission and distribution
pipelines and hazardous liquid pipelines to ensure that their
control room operators immediately and directly notify the 911
emergency call center(s) for the communities and jurisdictions
in which those pipelines are located when a possible rupture of
any pipeline is indicated. (P-11-9) This recommendation
supersedes Safety Recommendation P-11-2.
PHMSA Actions:
PHMSA will soon publish an advisory bulletin to all pipeline
operators reiterating the importance of immediate dialogue between the
operator and emergency responders when any indication of a pipeline
rupture or other emergency condition that may have an adverse impact on
people or the environment arises.
NTSB Recommendation P-11-10:
Require that all operators of natural gas transmission and
distribution pipelines equip their supervisory control and data
acquisition systems with tools to assist in recognizing and
pinpointing the location of leaks, including line breaks; such
tools could include a real-time leak detection system and
appropriately spaced flow and pressure transmitters along
covered transmission lines.
PHMSA Actions:
PHMSA has already accelerated our new Control Room Management
rule's effective date from February 1, 2013 to October 1, 2011. That
new rule addresses human factors and other aspects of control room
management for pipelines where pipelines use supervisory control and
data acquisition (SCADA) systems. Under this rule, affected pipeline
operators must define the roles and responsibilities of controllers and
provide controllers with the necessary information, training and
processes to fulfill these responsibilities. Operators must also
implement methods to prevent controller fatigue. The rule further
requires operators to manage SCADA alarms, assure control room
considerations are taken into account when changing pipeline equipment
or configurations and review reportable incidents or accidents to
determine whether control room actions contributed to the event.
In addition, on August 25, 2011, PHMSA published an Advance Notice
of Proposed Rulemaking (ANPRM), which requests comments regarding leak
detection systems on natural gas pipelines. As part of a larger study
on pipeline leak detection technology, PHMSA will conduct a public
workshop in early 2012. This study will, among other things, examine
how enhancements to SCADA systems can improve recognition of pipeline
leak locations. Additionally, in early 2012 PHMSA plans to hold a
pipeline research forum to identify technological gaps, potentially
including the advancement of leak detection methodologies. We
anticipate advancing rulemaking to address this recommendation
following these actions.
NTSB Recommendation P-11-11:
Amend Title 49 Code of Federal Regulations Section 192.935(c)
to directly require that automatic shutoff valves (ASV) or
remote control valves (RCV) in high consequence areas and in
class 3 and 4 locations be installed and spaced at intervals
that consider the population factors listed in the regulations.
PHMSA Actions:
PHMSA published an ANPRM on August 25, 2011 and invited comments on
the need for revised mainline valve regulations for new pipeline
construction or existing pipelines. The ANPRM discusses the issue of
valve spacing and automatic shutoff valves (ASV) or remote control
valves (RCV) in high consequence areas.
PHMSA will hold a public workshop in the first quarter of 2012 on
pipeline valve issues--including the need for additional valve
installation on both natural gas and hazardous liquid transmission
pipelines. We will also include this topic in our 2012 Pipeline
Research Forum. We anticipate advancing rulemaking to address this
recommendation following these actions.
NTSB Recommendation P-11-12:
Amend 49 CFR 199.105 and 49 CFR 199.225 to eliminate operator
discretion with regard to testing of covered employees. The
revised language should require drug and alcohol testing of
each employee whose performance either contributed to the
accident or cannot be completely discounted as a contributing
factor to the accident.
PHMSA Actions:
PHMSA is consulting within the U.S. DOT, as its broader authority
and policy is relevant in this matter, and will seek to clarify the
regulatory language identified in Sec. 199.105(b) and .225(a)(1), as
appropriate, following those discussions.
NTSB Recommendation P-11-13:
Issue immediate guidance clarifying the need to conduct post
accident drug and alcohol testing of all potentially involved
personnel despite uncertainty about the circumstances of the
accident.
PHMSA Actions:
PHMSA will soon publish an Advisory Bulletin reminding operators of
the requirement for post-accident testing and clarify that testing must
occur unless an operator can unequivocally determine that personnel did
not contribute to the accident.
NTSB Recommendation P-11-14:
Amend Title 49 Code of Federal Regulations 192.619 to delete
the grandfather clause and require that all gas transmission
pipelines constructed before 1970 be subjected to a hydrostatic
pressure test that incorporates a spike test.
PHMSA Actions:
In our August 2011 gas transmission ANPRM referenced earlier, PHMSA
began rulemaking on this and other issues relating to the San Bruno
failure. We intend to advance rulemaking to address this topic during
CY 2012. Removing the grandfather clause for all gas transmission
pipelines will involve significant technical and economic challenges
and is likely to require time to implement. Notwithstanding, PHMSA will
evaluate several options for implementing this recommendation. To
commence these actions PHMSA is initiating an OMB-approved information
collection effort to gather key data needed to characterize the
quantity and locations of pre-1970 gas transmission pipelines operating
under the grandfather clause accurately.
NTSB Recommendation P-11-15:
Amend Title 49 Code of Federal Regulations Part 192 of the
Federal pipeline safety regulations so that manufacturing- and
construction-related defects can only be considered stable if a
gas pipeline has been subjected to a post-construction
hydrostatic pressure test of at least 1.25 times the maximum
allowable operating pressure.
PHMSA Actions:
PHMSA's August 2011 rulemaking also began the regulatory process
needed to implement rulemaking to strengthen the Integrity Management
requirements relating to manufacturing and construction defects. We
plan to advance this rulemaking during 2012.
NTSB Recommendation P-11-16:
Assist the California Public Utilities Commission in conducting
the comprehensive audit recommended in Safety Recommendation P-
11-22.
PHMSA Actions:
PHMSA has already been assisting the California Public Utilities
Commission (CPUC) in conducting its oversight responsibilities for
which PHMSA provides substantial funding. In April of 2011, PHMSA sent
a team of five engineers to help CPUC review the Risk Assessment and
Threat Identification portion of their Gas Integrity Management audit
of Pacific Gas and Electric (PG&E). In October 2011, PHMSA sent
additional staff to assist the CPUC in its audit of PG&E's public
awareness program. PHMSA will continue to provide support to the CPUC
with regard to the application of the integrity management and other
pipeline safety regulations. I have spoken with the CPUC leadership
offering them all the help they need to carry out their
responsibilities.
NTSB Recommendation P-11-17:
Require that all natural gas transmission pipelines be
configured so as to accommodate in-line inspection tools, with
priority given to older pipelines.
PHMSA Actions:
PHMSA regulations were changed in 2004 to require that most new gas
transmission pipelines be piggable. In March 2010, Secretary LaHood
issued a call to action to accelerate the repair, replacement or
rehabilitation of the highest risk pipe. PHMSA is hopeful that natural
gas transmission pipeline operators will respond to that call to action
by ensuring the integrity of older pipelines. PHMSA has already
initiated an Advanced Notice of Proposed Rulemaking to consider whether
the IMP rule should be expanded to include more pipelines for integrity
assessment and to address assessment methods (including application of
inline inspections).
Since significant portions of the Nation's natural gas transmission
pipelines are not now piggable, requiring that all natural gas
transmission pipelines be made piggable will entail a major rulemaking
that must analyze the costs that it would entail. To ensure their
piggability many may need to be replaced or the in line inspection
technology must be improved. As mentioned earlier, PHMSA is requesting
OMB approval for an information collection that will help us more
precisely understand the implications of such a requirement.
PHMSA also intends to continue to invest significant research and
development attention on this problem. Our prior investments have
yielded very promising new robotic technology that has effectively made
portions of this infrastructure previously considered unpiggable
accessible to new types of pigs. We are optimistic that a combination
of information, research, and rulemaking will help us drive attainment
of this laudable, but ambitious goal.
NTSB Recommendation P-11-18:
Revise your integrity management inspection protocol to (1)
incorporate a review of meaningful metrics; (2) require
auditors to verify that the operator has a procedure in place
for ensuring the completeness and accuracy of underlying
information; (3) require auditors to review all integrity
management performance measures reported to the Pipeline and
Hazardous Materials Safety Administration and compare the leak,
failure, and incident measures to the operator's risk model;
and (4) require setting performance goals for pipeline
operators at each audit and follow up on those goals at
subsequent audits.
PHMSA Actions:
PHMSA agrees that clear, meaningful metrics are important. PHMSA
has been collecting and reviewing integrity management performance
metrics from pipeline operators since 2004. PHMSA inspectors compare
the operator reported data to the records maintained by the operator
for consistency. In January 2011, PHMSA issued an Advisory Bulletin on
record keeping and risk, two critical components to an effective
integrity management program. PHMSA intends to revise the inspection
format to encourage inspectors to focus on verification of performance
measures, record adequacy, data integration, and risk analysis.
PHMSA has always maintained a bias for continual improvement in
pipeline safety, which at times, has included in-person performance
reviews with company executives. These meetings have occurred to remedy
unanswered deficiencies found in inspections, and establish clear
expectations these companies need to follow for compliance. We intend
to maintain our continual improvement approach with pipeline operators
and will continue dialogue on this subject with NTSB to ensure needed
actions are taken to address concerns.
NTSB Recommendation P-11-19:
(1)Develop and implement standards for integrity management and
other performance-based safety programs that require operators
of all types of pipeline systems to regularly assess the
effectiveness of their programs using clear and meaningful
metrics, and to identify and then correct deficiencies; and (2)
make those metrics available in a centralized database.
PHMSA Actions:
PHMSA agrees that clear, meaningful, and readily available metrics
are important. PHMSA's integrity management program has many metrics in
place. However, PHMSA will continue to meet with representatives of the
NTSB and States to evaluate ways to improve those metrics to ensure
that operators regularly assess the effectiveness of their programs and
correct identified deficiencies. As mentioned above, PHMSA will also
advance the goals of this recommendation in a Spring 2012 pipeline
safety data workshop.
NTSB Recommendation P-11-20:
Work with state public utility commissions to (1) implement
oversight programs that employ meaningful metrics to assess the
effectiveness of their oversight programs and make those
metrics available in a centralized database, and (2) identify
and then correct deficiencies in those programs.
PHMSA Actions:
PHMSA agrees that clear, meaningful, and readily available metrics
are important. PHMSA will work with State Pipeline Safety programs to
evaluate ways to improve the oversight of the State programs and
correct identified deficiencies. We have begun dialog on this and other
topics relating to the performance of State programs with the National
Association of Regulatory Utility Commissioners who, as a general rule,
direct the actions of our State pipeline safety program managers. We
have also begun parallel discussions with the National Association of
Pipeline Safety Representatives.
PHMSA has for some years now been committed to increasing the
transparency of its own data, and has over the past few years been
pushing for greater transparency of State pipeline safety program data.
We are engaged with the many States now, and will be using State
generated data in the next year to increase the amount of performance
data available to the public.
Please let me reiterate PHMSA's commitment to address each of the
NTSB recommendations arising from the tragic San Bruno accident. We
will do all we can to help prevent similar failures. If you have
questions, concerns, or comments regarding this or any other pipeline
safety matter, please feel free to contact me directly at 202-366-4433.
Regards,
Cynthia L. Quarterman
______
National Transportation Safety Board,
Washington, DC, April 24, 2012
Hon. Cynthia L. Quarterman,
Administrator,
Pipeline and Hazardous Materials Safety Administration,
Washington, DC.
Dear Administrator Quarterman:
Thank you for your letter, dated December 14, 2011, which the
National Transportation Safety Board (NTSB) received on February 24,
2012, updating the status of actions to address Safety Recommendations
P-11-8 through -20, stated below. We issued these recommendations to
the Pipeline and Hazardous Materials Safety Administration (PHMSA) on
September 26, 2011, as a result of our investigation of the September
9, 2010, natural gas pipeline rupture that occurred in a residential
area in the City of San Bruno, California.
P-11-8
Require operators of natural gas transmission and distribution
pipelines and hazardous liquid pipelines to provide system-
specific information about their pipeline systems to the
emergency response agencies of the communities and
jurisdictions in which those pipelines are located. This
information should include pipe diameter, operating pressure,
product transported, and potential impact radius.
The NTSB is aware that PHMSA issued Advisory Bulletin (ADB) PHMSA-
2010-0307, Pipeline Safety: Emergency Preparedness Communications. We
note that, in December 2011, PHMSA held an emergency responder forum
that brought together leaders of the emergency responder community from
the Federal and state governments, the public, and the pipeline
industry to begin development of a strategy and action plan for
improving emergency responders' ability to prepare for, and respond to,
pipeline emergencies. The forum evaluated available resources and
current regulatory requirements, drew lessons from recent pipeline
accidents, and looked for potential gaps in information that emergency
responders need to adequately prepare for, and respond to, natural gas
and hazardous liquid pipeline emergencies. PHMSA plans to use this
information to address Safety Recommendation P-11-8; accordingly, the
recommendation is classified ``Open-Acceptable Response.''
P-11-9
Require operators of natural gas transmission and distribution
pipelines and hazardous liquid pipelines to ensure that their
control room operators immediately and directly notify the 911
emergency call center(s) for the communities and jurisdictions
in which those pipelines are located when a possible rupture of
any pipeline is indicated.
The NTSB notes that PHMSA plans to issue an ADB to all pipeline
operators, reiterating the importance of immediately notifying
emergency responders when a pipeline ruptures or other emergency
condition exists. However, the pending ADB, which does not constitute a
regulation, will not require operators to directly notify emergency
responders, as recommended. Accordingly, we ask that PHMSA reconsider
its planned action to address Safety Recommendation P-11-9. Pending
receipt of further information from PHMSA regarding our request, Safety
Recommendation P-11-9 is classified ``Open-Acceptable Response.''
P-11-10
Require that all operators of natural gas transmission and
distribution pipelines equip their supervisory control and data
acquisition systems [SCADA] with tools to assist in recognizing
and pinpointing the location of leaks, including line breaks;
such tools could include a real-time leak detection system and
appropriately spaced flow and pressure transmitters along
covered transmission lines.
The NTSB notes that, in late 2011, PHMSA issued an Advanced Notice
of Proposed Rulemaking (ANPRM), and in 2012, as part of a study to
examine how enhancements to SCADA systems can improve recognition of
pipeline leak locations, will hold a public workshop as well as a
public forum on leak detection. Because PHMSA intends to initiate
rulemaking once these actions are complete, Safety Recommendation P-11-
10 is classified ``Open-Acceptable Response.''
P-11-11
Amend Title 49 Code of Federal Regulations [CFR] 192.935(c) to
directly require that automatic shutoff valves or remote
control valves in high consequence areas and in class 3 and 4
locations be installed and spaced at intervals that consider
the factors listed in that regulation.
P-11-14
Amend Title 49 Code of Federal Regulations 192.619 to delete
the grandfather clause and require that all gas transmission
pipelines constructed before 1970 be subjected to a hydrostatic
pressure test that incorporates a spike test.
P-11-15
Amend Title 49 Code of Federal Regulations Part 192 of the
Federal pipeline safety regulations so that manufacturing-and
construction-related defects can only be considered stable if a
gas pipeline has been subjected to a post-construction
hydrostatic pressure test of at least 1.25 times the maximum
allowable operating pressure.
Because PHMSA initiated regulatory action to address these issues,
with the August 2011 issuance of an ANPRM, Pipeline Safety: Safety of
Gas Transmission Pipelines, Safety Recommendations P-11-11, -14, and -
15 are classified ``Open-Acceptable Response,'' pending publication of
the recommended final rule.
P-11-12
Amend Title 49 Code of Federal Regulations 199.105 and 49 Code
of Federal Regulations 199.225 to eliminate operator discretion
with regard to testing of covered employees. The revised
language should require drug and alcohol testing of each
employee whose performance either contributed to the accident
or cannot be completely discounted as a contributing factor to
the accident.
The NTSB understands that PHMSA is reviewing its legal authority
and policy with the U.S. Department of Transportation (DOT) to clarify
the regulatory language identified in Title 49 CFR 199.105(b) and
.225(a)(l), and that, following those discussions, PHMSA will clarify
the regulations as needed. Accordingly, pending completion of this
review and receipt of further information about PHMSA's intended course
of action, Safety Recommendation P-11-12 is classified ``Open-
Acceptable Response.''
P-11-13
Issue immediate guidance clarifying the need to conduct post-
accident drug and alcohol testing of all potentially involved
personnel despite uncertainty about the circumstances of the
accident.
PHMSA issued ADB-2012-02, Pipeline Safety: Post Accident Drug and
Alcohol Testing, on February 23, 2012, satisfying the recommendation.
Accordingly, Safety Recommendation P-11-13 is classified ``Closed-
Acceptable Action.''
P-11-16
Assist the California Public Utilities Commission [CPUC] in
conducting the comprehensive audit recommended in Safety
Recommendation P-11-22.
Because PHMSA is assisting the CPUC as requested, Safety
Recommendation P-11-16 is classified ``Open-Acceptable Response,''
pending completion of the CPUC's audit.
P-11-17
Require that all natural gas transmission pipelines be
configured so as to accommodate in-line inspection tools, with
priority given to older pipelines.
The NTSB is encouraged that the U.S. Secretary of Transportation is
committed to this issue and that PHMSA initiated regulatory action with
its August 25, 2011, issuance of an ANPRM, Pipeline Safety: Safety of
Gas Transmission Pipelines, which includes action regarding Integrity
Management Programs (IMP). Accordingly, pending publication of a final
rule that satisfies the recommendation, Safety Recommendation P-11-17
is classified ``Open-Acceptable Response.''
P-11-18
Revise your integrity management inspection protocol to (1)
incorporate a review of meaningful metrics; (2) require
auditors to verify that the operator has a procedure in place
for ensuring the completeness and accuracy of underlying
information; (3) require auditors to review all integrity
management performance measures reported to the Pipeline and
Hazardous Materials Safety Administration and compare the leak,
failure, and incident measures to the operator's risk model;
and (4) require setting performance goals for pipeline
operators at each audit and follow up on those goals at
subsequent audits.
PHMSA has initiated action to revise its IMP inspection protocol
and amend its audit requirements as requested. Accordingly, pending
completion of these efforts, Safety Recommendation P-11-18 is
classified ``Open-Acceptable Response.''
P-11-19
(1) Develop and implement standards for integrity management
and other performance-based safety programs that require
operators of all types of pipeline systems to regularly assess
the effectiveness of their programs using clear and meaningful
metrics, and to identify and then correct deficiencies; and (2)
make those metrics available in a centralized database.
The NTSB understands that PHMSA's IMP contains some of the
recommended metrics, and we are encouraged that PHMSA plans to continue
working with applicable stakeholders to improve those metrics and to
ensure that operators regularly assess the effectiveness of their
programs and correct identified deficiencies. We are also encouraged
that PHMSA plans to advance the goals of this recommendation in a
spring 2012 pipeline safety data workshop. Pending completion of
PHMSA's efforts to satisfy this recommendation, Safety Recommendation
P-11-19 is classified ``Open-Acceptable Response.''
P-11-20
Work with state public utility commissions to (1) implement
oversight programs that employ meaningful metrics to assess the
effectiveness of their oversight programs and make those
metrics available in a centralized database, and (2) identify
and then correct deficiencies in those programs.
The NTSB is encouraged that PHMSA plans to work, or already has
begun to work, (1) with state pipeline safety programs, (2) with the
National Association of Regulatory Utility Commissioners, and (3) with
the National Association of Pipeline Safety Representatives to address
this recommendation. We are further encouraged that your agency is
working to improve the transparency of its data and of state pipeline
safety program data. Pending completion of these efforts to implement
Safety Recommendation P-11-20, this recommendation is classified
``Open-Acceptable Response.''
We would appreciate receiving periodic updates on these initiatives
as progress continues to address Safety Recommendations P-11-8 through
-12 and 14 through -20. We encourage you to submit updates
electronically at the following e-mail address:
[email protected]. If a response includes attachments that exceed
5 megabytes, please e-mail us at the same address for instructions. To
avoid confusion, please do not submit both an electronic copy and a
hard copy of the same response.
Sincerely,
Deborah A.P. Hersman,
Chairman.
cc: Ms. Linda Lawson, Director
Office of Safety, Energy, and Enviromnent
Office of Transportation Policy
Senator Boxer. Because we didn't have--you said it goes
beyond it. So those two are important. And when do you think
you'll have those regulations out for the public to respond to?
Ms. Quarterman. As I told you, we are actually in the
middle of the comment period right now. So the details of those
regulations are not something that we are supposed to be
discussing publicly.
Senator Boxer. OK. But you're asking for comment, for
public comment. You're soliciting input from the public, but
have you printed these regulations yet? These proposed
regulations anywhere so we can see what they are exactly?
Ms. Quarterman. It's an advanced notice of proposed rules.
Senator Boxer. So you have that out?
Ms. Quarterman. Yes.
Senator Boxer. Excellent. And those are two. And what else
do you have?
Ms. Quarterman. You said those--?
Senator Boxer. You said--you described to me two
provisions, the maximum pressure, the shutoff valves.
Ms. Quarterman. Oh, there are--there are many, many
different provisions in there. I don't remember them all. I'd
be happy to get----
Senator Boxer. How many regulations are you considering
writing?
Ms. Quarterman. I don't know the number. I think we have
tens of things, 40 plus.
Senator Boxer. Forty plus regs. Would you send me the
proposed regs that you have that are related to this incident?
Ms. Quarterman. Absolutely.
Senator Boxer. Thank you. That'd be very, very helpful. But
I would urge you to look at these protocols. They're, you know,
very, very clear. They require setting performance goals for
pipeline operators at each audit and followup--I mean, this is
not rocket science. This is written in a way by the NTSB that
those of us who don't have a degree in engineering can really
readily understand. So I hope you'll take a look at that.
I wanted to talk to PG&E. First of all, I'm glad that you
were hired there.
Mr. Stavropoulos. Thank you.
Senator Boxer. Sounds like they need you, badly. They
needed you long before.
So, let me say this. I don't know if you're aware, but in
2008 there was an explosion in a PG&E gas pipeline in Rancho
Cordova. One person died, and there were five injuries. And as
we look at this, if you look at the causes and the deficiencies
there, they were really very similar to the deficiencies here.
Do you have an answer to this question why was it that
corrections were not taken, these deficiencies--why were these
deficiencies not corrected prior to these explosions since they
were so similar?
Mr. Stavropoulos. Senator, I wasn't here to be part of
those activities.
Senator Boxer. Well, maybe that's why they sent you to this
hearing.
Mr. Stavropoulos. Between Rancho Cordova and San Bruno,
Rancho Cordova happened on the gas distribution lines of our
system----
Senator Boxer. So you don't know why they didn't make any
corrections. Could you get an answer for the record for me,
please?
Mr. Stavropoulos. Certainly.
[The informationr referred to follows:]
American Gas Association
AGA Actions Supporting the Secretary's Call to Action and NTSB
Recommendations
Pipe Fitness for Service--Developed guidance on how to determine a
distribution or transmission pipeline's fitness for service, including
criticalrecords needed for this determination. The initial documents
were submitted for consideration in the DOT Report to the Nation. More
comprehensive documents are under development focused on fitness for
service considerations, level of accuracy needed for critical records,
and how to address record gaps and update records. These documents are
expected to be finalized fall2011.
Transmission MAOP Records Verification--Developed guidance on
determining a transmission pipeline's MAOP. Technical paper finalized
in April and distributed to operators and Federal and state regulators.
A more detailed document on records review for transmission pipeline
MAOPs was completed in October 2011.
Safety Information Sharing Study--Working with INGAA, API, AOPL,
Canadian Gas Association and Canadian Energy Pipeline Association on a
comprehensive study to explore safety sharing initiatives currently
utilized by other sectors, as well as the pipeline industry. The
results of the study may help to identify and implement a model that
will measurably improve the sharing of pipeline safety information. The
study is expected to be completed in February of 2012.
Gas Utility Emergency Response--Developing a checklist that will
enable operators to enhance emergency response communications and
education programs. Checklist will be completed fall 2011.
Automatic Shutoff and Remotely Controlled Shutoff Valves (ASV/
RCV)--Developed ASV/RCV technical paper that presents the benefits and
disadvantages of their installation on new, fully replaced and existing
transmission pipelines, especially as it relates to gas transmission
pipelines embedded in distribution systems. The initial technical
document was completed March 2011 and a more comprehensive technical
paper is expected to be completed by December 2011.
Safety Culture Statement--In February 2011, the AGA Board of
Directors adopted a Safety Culture Statement. All employees, as well as
contractors and suppliers providing services to AGA members, are
expected to place the highest priority on employee, customer, public
and pipeline safety. The Safety Culture Statement addresses the
commitment by management to promoting open and honest communications
across all levels of an organization, identifying hazards. managing
risks, planning the work and working the plan, and promoting a learning
environment and personal accountability.
Infrastructure Replacement Rate Mechanisms--AGA, INGAA and API
developed a document to explain to the public the ratemaking mechanisms
used for the pipeline infrastructure. A well designed rate reflects the
input of all stakeholders and the importance of factors such as
expanded safety programs, infrastructure repair and replacement. Such a
rate design also recognizes the changing methods of cost recovery and
other factors.
Events to Share Information--In the past year, AGA has held a
number of events to share information, including workshops on emergency
response, transmission integrity management, utility contractor
management and vintage pipe; regional operations executives'
roundtables, roundtables on external corrosion, damage prevention and
marking and locating, and technical committee meetings and sessions on
the management of vintage pipe, distribution and transmission integrity
management, emergency management, pipe replacement, welding repair
qualification procedures, leak detection, corrosion assessment, MAOP,
qualification of personnel, control room management, sewer cross bores,
mechanical fittings, worker safety, weld failure mechanisms, safety
culture, and new construction. AGA also participated in PHMSA workshops
on transmission pipeline weld seams, transmission integrity management
risk assessments and its revised annual and incident reporting forms.
AGA's Commitment to Enhancing Safety--Developed AGA's Commitment to
Enhancing Safety which identifies additional actions that distribution
and intrastate transmission pipeline operators are committed to take to
improve pipeline safety. Approved by the AGA Board October 2011.
The Safety Path Forward
AGA supports timely reauthorization of the pipeline safety
law.
Actions under AGA's Commitment to Enhancing Safety. This
includes actions that will help ensure pipelines are built for
safety, existing pipelines operate safety, and work to enhance
pipeline safety.
Damage Prevention--AGA is a founder of the Common Ground Alliance
and supports programs that address excavation damage, historically the
leading cause of significant pipeline incidents. A number of
initiatives have reduced excavation damage by 50 percent over the last
6 years and that work must continue if we are to further reduce
excavation damages. This includes promoting 811, the national number
for people to call before they dig; working at the state level to
promote participation in One-Call programs by all underground operators
and excavators; and strengthening state damage prevention legislation.
Transmission Integrity Management Enhancements--AGA members are
committed to engaging in public discussions to evaluate whether
transmission integrity management should be expanded beyond high
consequence areas (HCAs), and the benefits and disadvantages of
applying integrity management principles to additional areas. Many AGA
members are required to manage Distribution Integrity Management
Programs (DIMP) and Transmission Integrity Management Programs (TIMP)
programs, so the effectiveness, inefficiencies and duplication of
multiple integrity management programs must also be explored. AGA
members are committed to evaluating how various low-stress pipelines
(those with MAOPs below 30 percent SMYS) would benefit by using
elements from either or both programs.
Data Collection and Sharing--AGA is committed to working with
PHMSA, state regulators and the public to create a data quality team
made up of representatives from government, industry and the public,
similar to the PHMSA technical advisory committees. The team could
analyze the data PHMSA collects and determine opportunities to improve
pipeline safety based on conclusions reached by data analysis. The team
could also identify gaps in the data that are collected by PHMSA and
others, identify ways to improve the collected data, and communicate
consistent messages about pipeline incident data.
Research & Development--Continue funding and collaboration on
research, development and deployment of technologies to improve safety,
including in-line inspection tool capabilities, operator use of tool
data, direct assessment tools, non-destructive testing and leak
detection.
Emergency Response--AGA members are committed to finding new and
innovative ways to inform and engage stakeholders, including emergency
responders, public officials, excavators, consumers and safety
advocates and members of the public living in the vicinity of
pipelines.
Executive Leadership Engagement In Safety Improvement--Continue the
work of the Board of Directors Safety Committee that focuses on
pipeline, customer, employee, contractor and vehicular safety. This
includes holding an annual Executive Leadership Safety Summit, sharing
lessons learned, reviewing safety statistics, identifying ways to
further improve safety, and furthering the Safety Information Resource
Center that includes safety alerts, safety messages, statistics,
information on motor vehicular safety and case studies.
Sharing Safety Information--Continue sharing safety information
through AGA technical committees, the operations managing committee,
and the AGA Best Practices Programs. The Best Practices Programs focus
on identifying superior performing companies and innovative work
practices that can be shared with others to improve operations.
State Safety and Rate Mechanisms--Continue to promote effective
cost-recovery mechanisms that states can use to fund infrastructure
maintenance and replacement projects. Continue to serve as a
clearinghouse of state rate mechanisms.
Publications--Continue to develop publications dedicated to
improving safety and operations.
______
AGA's Commitment to Enhancing Safety
AGA and its members are dedicated to the continued enhancement of
pipeline safety. As such, we are committed to proactively collaborating
with public officials, emergency responders, excavators, consumers,
safety advocates and members of the public to continue to improve the
industry's longstanding record of providing natural gas service safely
and effectively to more than 175 million Americans. AGA and its members
support the development of reasonable regulations to implement new
Federal legislation as well as the National Transportation Safety Board
safety recommendations. Below are actions that are being, or will be,
implemented by AGA or individual operators to help ensure the safe and
reliable operation of the Nation's 2.4 million miles of pipeline which
span all 50 states representing diverse regions and operating
conditions. In implementing these actions, the AGA and its individual
operators recognize the significant role that their state regulators or
governing body will play in supporting and funding these actions.
Building Pipelines for Safety
Construction
Expand requirements of the Operator Qualification (OQ) rule to
include new construction of distribution and transmission
pipelines.
AGA Members Action. Task Forces suggested operators take
this action by June 1, 2013
Review established Quality Assurance/Quality Control (QA/QC)
procedures associated with pipeline construction to ensure adequacy
of oversight and confirm that operator construction practices and
procedures are followed.
AGA Members Action. Task Forces suggested that operators
establish QA/QC procedures that help ensure effective
compliance with procedures of company and contract construction
personnel by June 1, 2013.
Emergency Shutoff Valves
Support the use of automatic shutoff and/or remote control
valves where economically, technically and operationally feasible
on transmission lines that are being newly constructed or entirely
replaced. Develop guidelines for consideration of automatic shutoff
and remote control valves on transmission lines that are already in
service. We commit to work collaboratively with appropriate
regulatory agencies and policy makers to develop these criteria.
AGA Action--Guidelines. AGA has developed a technical
paper on ASVs and RCVs. The technical paper presents the
benefits and disadvantages of their installation on new, fully
replaced and existing transmission pipelines, especially as it
relates to the gas transmission pipelines embedded into the
distribution system. The initial technical document was
completed in March 2011 and AGA is developing a more
comprehensive technical paper that is expected to be completed
by December 2011. AGA will hold a roundtable focused on
operator experience and lessons learned during the 2012
Operations Conference.
AGA Members Action--Task Forces suggested that, for
newly constructed or entirely replaced transmission pipelines,
AGA members commit to installing the necessary ASVs or RCVs or
equivalent technology for those pipelines designed after
December 31, 2012.
Expand the use of excess flow valves to new and fully replaced
distribution branch services, small multi-family facilities, and
small commercial facilities where economically, technically and
operationally feasible.
AGA Members Action--Installation of EFVs on new or fully
replaced service lines to branched single family residential
services, duplexes, triplexes, quad-plexes and small commercial
customers up to 1,000 standard cubic feet/hour (SCFH) connected
load where the operator determines it to be economically,
technically and operationally feasible starting in June 1,
2013. Note: PHMSA issued ANPRM on EFVs beyond SFHs 11/24/11.
Appears they are considering requiring EFVs beyond 1000 SCFH
Operating Pipelines Safely
Integrity Management
Continue to advance integrity management programs and
principles to mitigate system specific risks. This includes
operational activities as well as the repair, replacement or
rehabilitation of pipelines and associated facilities where it will
most improve safety and reliability.
Develop industry guidelines for data management to advance
data quality and knowledge related to pipeline integrity.
AGA Actions for the above bullets--
Develop guidance on how to determine a distribution or
transmission pipeline's fitness for service. The initial
documents were submitted for the DOT Report to the Nation.
More comprehensive documents are under development and are
expected to be finalized fall/winter 2011
Develop guidance on critical records needed to determine a
pipeline's fitness for service and the records needed to
determine maximum allowable operating pressure (MAOP) on a
transmission pipeline. The initial documents were submitted
for the DOT Report to the Nation. More comprehensive
documents focused on the level of accuracy needed for
critical records, how to address gaps in records, and how
to obtain new information to address record gaps and update
records are under development and were finalized in October
2011
AGA developed a technical paper to provide guidance on
determining a transmission pipeline's MAOP. This technical
paper was finalized in April and distributed to operators
and Federal and state regulators.
Continue to serve as a clearinghouse to document the
effective cost-recovery mechanisms that various states have
used to fund infrastructure repair, replacement and
rehabilitation projects. AGA will continue to provide
technical and regulatory information at regional and
national meetings of state utility commissioners and
pipeline safety regulators. AGA, INGAA and API developed a
document to explain to the public the ratemaking mechanisms
used for the pipeline infrastructure.
Engage in public discussions on whether gas transmission
integrity management should be expanded beyond HCAs, and
the benefits and disadvantages of applying the integrity
management principles to additional areas.
AGA has highlighted in DOT workshops, NAPSR
meetings, and in discussions with the Government
Accountability Office that--
Many AGA members are required to
manage Distribution Integrity Management
Programs (DIMP) and Transmission Integrity
Management Programs (TIMP) and the
effectiveness, inefficiencies and duplication
of multiple integrity management programs must
be explored.
Low-stress pipelines operating below
30 percent SMYS would benefit by using elements
from either or both programs.
AGA Member Actions for the above bullets--
Distribution: Task force suggested operators conduct an
evaluation of all distribution pipelines for fitness for
service as an element of an operator's DIMP program by
December 31, 2012.
Transmission: Task force suggested that operators--
Complete a systematic validation of records
relative to MAOP for their pre-1970 installed
transmission pipelines by December 31, 2013.
Evaluate a transmission pipeline's fitness for
service by integrating readily available information by
December 31, 2014.
Use a risk based approach to extend integrity
management principles outside of currently defined high
consequence areas, incorporating all transmission lines
in class 3 and class 4 locations by December 31, 2022
and all transmission lines in class 1 and class 2
locations by December 31, 2032
Support development of processes and guidelines that enable
the tracking and traceability of new pipeline components.
AGA Actions--Work with other stakeholders to develop
potential technological solutions that will allow for the
tracking and traceability of new pipeline components (including
pipe, valves, fittings and other appurtenances attached to the
pipe).
Excavation Damage Prevention
Support strong enforcement of the 811--Call Before You Dig
program through state damage prevention laws.
AGA Actions--
Support legislation the strengthens enforcement of damage
prevention programs and 811
Support the Common Ground Alliance, the use of 811 and
other programs that address excavation damage
AGA Member Actions--Work at the state level to:
Encourage participation in One-Call programs by all
underground operators and excavators.
Modify state legislation, if needed, to strengthen
enforcement of damage prevention programs and 811
Improve the level of engagement between the operator and
excavators working in the immediate vicinity of the operator's
pipelines.
AGA Actions--Develop a process that provides for an
improved level of engagement between the company and excavators
when they are identified as excavating in the immediate
vicinity of a company's high priority gas facilities. The
results of that work to be reported by December 31, 2013
Enhancing Pipeline Safety
Safety Knowledge Sharing
Review programs currently utilized for the sharing of safety
information. Identify and implement models that will enhance safety
knowledge exchange among operators, contractors, government and the
public.
AGA Actions -
AGA is working with INGAA, API, AOPL, the Canadian Gas
Association and the Canadian Energy Pipeline Association on
a comprehensive study to explore initiatives currently
utilized by other sectors, as well as the pipeline
industry. The safety management study is expected to be
completed February/March 2012
Based on the results of the safety management study,
identify and implement initiatives that will enhance the
appropriate sharing of safety information. AGA to begin
this work spring 2012
Continue the work of the AGA Best Practices Programs to
identify superior performing companies and innovative work
practices that can be shared with others to improve
operations and safety.
Work with other stakeholders to improve pipeline safety
data collection and analysis, converting data into
meaningful information and communicating it to other
stakeholders. This includes working with PHMSA, state
regulators and the public to create a data quality team
made up of representatives from government, industry and
the public to analyze the data that PHMSA collects,
determine opportunities to improve pipeline safety based on
the data analysis, identify gaps in the data collected by
PHMSA and others, and communicate consistent messages about
pipeline incident data. This also includes continuing the
work of the Plastic Pipe Database Committee to collect and
analyze plastic material failures.
Conduct workshops, teleconferences and other events to
share information:
By December 2012, hold workshops,
teleconferences or other events on pipeline safety
reauthorization, distribution and transmission
integrity management, fitness for service, records,
corrosion, in-line inspection, emergency response,
damage prevention, plastic material issues,
environmental issues and other key safety initiatives
Hold regional operations executives'
roundtables summer 2012
AGA Operations Conference and Exhibition. This
year's conference included technical sessions on the
management of vintage pipe, distribution and
transmission integrity management, emergency
management, pipe replacement, welding repair
qualification procedures, leak detection, corrosion
assessment, MAOP, qualification of personnel, control
room management, sewer cross bores, worker safety, weld
failure mechanisms, safety culture, contractor
management, improving communications, and new
construction.
Technical committee meetings
Support PHMSA and NAPSR workshops and other
events
Continue roundtable discussions within AGA
committees
Stakeholder Engagement and Emergency Response
Evaluate methods to more effectively communicate with public
officials, excavators, consumers, safety advocates and members of
the public about the presence of pipelines. Implement tested and
proven communication methods to enhance those communications.
AGA Actions--Search for new and innovative ways to
inform, engage and provide appropriate information to
stakeholders, including emergency responders, public officials,
excavators, consumers and safety advocates and members of the
public living in the vicinity of pipelines
AGA Member Actions--Continue to meet RP 1162, implement
lessons learned, and explore new and innovative ways to inform,
engage and provide appropriate information to stakeholders,
including emergency responders, public officials, excavators,
consumers and safety advocates and members of the public living
in the vicinity of pipelines.
Partner with emergency responders to share information and
improve emergency response coordination.
AGA Actions--
In September, AGA sponsored a workshop of the National
Association of State Fire Marshals on emergency response
planning. The workshop included approximately 60 emergency
responders and 40 operators. AGA is currently analyzing the
workshop results to determine potential next steps.
Develop a checklist that will enable operators to enhance
their emergency response communications and education
programs. This emergency check list will be completed by
December 2011
Work with PHMSA to establish time limits for telephonic or
electronic notification of reportable incidents to the
National Response Center after confirmation by the operator
that an incident meets the PHMSA incident reporting
requirements
Search for new and innovative ways to inform, engage and
provide appropriate information to emergency responders
AGA Member Actions--
Utilize the emergency response checklist that AGA is
developing
Participate in local emergency response training exercises
Continue outreach to emergency responders to share
information and improve emergency response
Pipeline Planning Engagement
Work with a coalition of Pipelines and Informed Planning
Alliance (PIPA) Guidance stakeholders to increase awareness of risk
based land use options and adopt existing PIPA recommended best
practices.
AGA Actions--Continue to build an active coalition of
AGA member representatives to work with PHMSA and other
stakeholders to implement PIPA recommended practices pertaining
to encroachment around existing transmission pipelines.
AGA Member Actions--For operators with transmission
pipelines, collaborate with PIPA stakeholders near existing
transmission lines to increase awareness and adoption of PIPA
recommended best practices.
Advancing Technology Development
Increase investment, continue participation, and support
research, development and deployment of technologies to improve
safety. Evaluate and appropriately implement new technological
advances.
AGA Actions--
Continue to promote to state commissioners the inclusion
of research funding in rate cases in an effort to increase
overall funding for research and development
Work with PHMSA and other stakeholders on opportunities to
increase R&D funding and deployment of technologies
Continue to encourage (or advocate) PHMSA and state
acceptance of technologies that can improve safety
AGA Member Actions--Evaluate and implement where
appropriate new advances in technologies for the assessment of
potential threats to distribution and transmission pipelines.
Other Actions to Enhance Safety
Engaging CEOs and executive leadership in safety improvement--
Continue the work of the Board of Directors' Safety Committee to
improve pipeline safety, customer safety in the home, employee
safety, contractor safety and vehicular safety. This includes
Sharing lessons learned, reviewing safety statistics,
and identifying ways to further improve safety.
Further enhancement of the Safety Information Resource
Center to include additional safety alerts, safety messages,
safety statistics, information on motor vehicular safety and
case studies.
Hold an annual executive leadership safety summit to
bring together key safety personnel and leaders in safety from
government and a variety of industries to share lessons
learned.
Publications--AGA will continue to develop publications
dedicated to improving safety and operations. Publications
developed to date include guidance on corrosion control, gas
control, integrity management, odorization, plastic piping, purging
principles and practices, repair and replacement, worker safety
practices, contractor safety, natural gas pipelines and unmarked
sewer lines, alarm management, directional drilling and emergency
shutdown.
Safety Culture Statement--Continue to promote the AGA Safety
Culture Statement and positive safety cultures among employees
throughout the natural gas distribution industry. All employees, as
well as contractors and suppliers providing services to AGA
members, are expected to place the highest priority on employee,
customer, public and pipeline safety. The Safety Culture Statement
addresses the commitment by management to promoting open and honest
communications across all levels of an organization, identifying
hazards, managing risks, planning the work and working the plan,
and promoting a learning environment and personal accountability.
Senator Boxer. From PG&E, someone who does know? Because
something happened very similar 2 years before. Very similar
deficiencies, and they were not taken care of.
Let's see. I want to ask Mr. Kessler a couple questions. Do
you believe the problems in PG&E's pipeline safety programs are
unique to PG&E, or are they pervasive throughout the pipeline
industry?
Mr. Kessler. Well, certainly, Madame Chair, there are
companies that go above and beyond the Federal minimums because
they understand it's in their business interests to do so.
Senator Boxer. Yes. I would agree.
Mr. Kessler. Unfortunately, I think the problems at PG&E
are pervasive, how widespread we don't know because we're not
looking. And I think that's a big part of the problem. Senator
Lautenberg asked earlier about age and whether we need to
inspect. And clearly anyone over 40 knows you kind of can't
keep up, or at least I can't the way I used to before then, but
if you maintain yourself you've got to put more and more work
in and you can do a good job. It's not just age.
Senator Boxer. So some are doing very well at this, and
some are not. Is that your point?
Mr. Kessler. Right. Well, and we don't really know for sure
because we haven't really looked exhaustively.
Senator Boxer. And so you would support testing these lines
and all the things NTSB now says ought to be done? And our
legislation moves in that direction.
Mr. Kessler. Just like going for a check-up, Senator. You
know, we all have to do it and we find things and we fix them.
Senator Boxer. Absolutely. I think that's a very good
analogy, frankly. Especially at my age--we have to worry about
different things just not functioning.
Mr. Kessler. Then you know how successful it can be if
you've ever tried to keep up with Senator Lautenberg.
Senator Boxer. Oh, boy, I wish I could when I'm there.
So I want to ask the NTSB this question. Have any of your
prior investigations found similar contributing factors to the
accident as those identified in your investigation of the San
Bruno explosion?
Ms. Hersman. Yes, we have identified two previous
investigations involving PG&E. One was a large release that
occurred in San Francisco that required evacuation. It took
them almost 10 hours to shut down the line. We again saw a
delay in shutting down the line here. We expected after our
previous recommendations that this issue would have been
addressed or remedied.
Also you mentioned Rancho Cordova----
Senator Boxer. Before you get there--what about in the rest
of the country, any of the other explosions? Were they similar
things where you had a pipe that wasn't welded properly, or was
too old, or inadequate, no inspections? Did you come across
anything in the rest of the country other than in PG&E's domain
or California?
Ms. Hersman. Yes. We've seen poor welds in earlier accident
investigations. We've also seen problems with the integrity
management program, which really is at the heart of the
oversight regime now. We've seen operations in which companies
didn't identify the pipeline correctly, elevate the risk
appropriately, or consider past leak history, and so we've
investigated accidents in Florida and Kansas where we've seen
problems with integrity management.
Senator Boxer. The reason I'm asking this, and I asked Mr.
Kessler a similar question--you know, this shouldn't have
happened. Because my understanding is you have investigated 118
pipeline accidents, natural gas or otherwise, since NTSB was
formed in 1967. And how many of those were over the last
decade? Oh, I think it's 118 over the last decade. Is that
right, or is----
Ms. Hersman. We have conducted 115 pipeline investigations
since 1970, and we've issued roughly 17 reports in the last
decade.
Senator Boxer. Seventeen in the last decade. Now, in each
of these did you make recommendations to PHMSA? Prior to Ms.
Quarterman's taking over.
Ms. Hersman. Yes, many of these investigations have
resulted in recommendations to PHMSA. I would like to note that
80 percent of our recommendations on average are accepted and
adopted in a favorable way, and that PHMSA has a higher rate of
91 percent.
While we issued quite a few recommendations to PHMSA with
this accident investigation, in the past they have been
responsive to us and going forward, Administrator Quarterman
has committed to me that they're working to address our----
Senator Boxer. Good. So PHMSA has taken 86 percent, has
adopted 91 percent of your recommendations.
Ms. Hersman. Yes, since PHMSA was created in 2004.
Senator Boxer. Over the history--well, that's very
important. I think they should do 100 percent. But 91 percent
is a lot better than FAA does after the safety board tells them
what to do, so I'll say fine.
But these protocols, that's an example of your
recommendation, so that's good to know for your meeting
tomorrow. Because I think if you accept these protocols we're
on our way to a better situation.
Look, what we're doing here is trying, all of us together,
to make sure this never happens again, or anything close to
this. Now, can we be assured that nothing bad goes wrong? Of
course not, we're dealing with reality here. But there are so
many levels of failure here, and so many obvious levels of
failure, I think we can make huge strides. If we don't, then
we're not acting in the memory of these decent people who
perished on that day.
Now, I would ask Ms. Quarterman, PG&E reported 67 leaks,
failures, and incidents to PHMSA over the 6-year period 2004 to
2010, an average of 10 a year. How does PG&E's records of
leaks, failures, and incidents compare to other natural gas
operators? Is it exceptionally high, or within the range of
operators?
Ms. Quarterman. I would have to get back to you on that.
[The information referred to follows:]
Question. Now, I would ask Ms. Quarterman, PG&E reported 67 leaks,
failures, and incidents to PHMSA over the six year period '04 to 2010,
an average of 10 a year. How does PG&E's records of leaks, failures,
and incidents compare to other natural gas operators? Is it
exceptionally high, or within the range of operators?
Answer. Based on the Incident reports submitted to PHMSA over the
six period 2004 to 2010, PG&E's record of incidents is not
exceptionally high, and within the range, compared to the similar size
gas transmission operators.
Among the group of 11 similar size operators, PG&E ranked 3rd based
on 7-year average incident rate per 10,000 miles of onshore
transmission miles operated. PG&E has an average of 4.58 per 10,000
miles of onshore transmission it operates in the period 2004-2010.
Senator Boxer. OK.
Let me just say, on your website, Ms. Quarterman, there
were 387 serious gas pipeline incidents, 54 in transmission,
329 on distribution, four in gathering pipelines from 2001 to
2010--the last 10 years--resulting in 126 fatalities, 542
injuries, and nearly $300 million in property damage. Does this
indicate to you that our minimum Federal pipeline safety
standards are too low?
Ms. Quarterman. That's why we're in the midst of looking at
those minimum standards. We have out for comment and are in the
middle of drafting a proposed rule with respect to hazardous
liquid pipelines, and as I mentioned, we are in the midst of a
rulemaking with respect to gas transmission pipelines.
We recently enacted a piece of regulation in December of
2009 with respect to distribution, gas pipelines, that is just
at the beginning of being implemented.
So I do believe that there are changes to be made,
absolutely.
Senator Boxer. Good. And what I'm saying, just as a senator
from the state in which this happened, the easiest thing for
you to do is make the changes that can be done via regulation,
through your protocols. We're going to help you with
legislation. I understand your staff was helpful in helping
Senator Lautenberg put that together. I think that's been
strengthened now in the Senate.
And then there are the new regulations, which I don't want
to see them take 3 years, so maybe there are ways we can use
your emergency capabilities to move that forward. Because, you
know, somebody said--I think you did, Ms. Hersman, that this
was an accident waiting to happen. It just was sitting there
waiting to happen. Of course, as we sit here our thoughts go
to, ``Is there something else out there that we don't know
about waiting to happen?''
And just as a human being and knowing that none of us is
perfect--there's something out there, and if we can figure out
a way to catch it before by an inspection and making sure we
test these old lines. You know, we'll never get a pat on the
back for what doesn't happen. But you know what? We'll know.
We'll know we did the right thing when we see these accidents
going down. So I guess that would leave me to Mr. Kessler.
You know, we have an aging infrastructure. And so the
question I have is does an aging infrastructure inevitably lead
to accidents, or can we do a better job testing and maintaining
that infrastructure?
Mr. Kessler. We can certainly do a better job. Again, age
alone, even materials alone, aren't insurmountable. You know,
what I find really interesting about this, and from dealing in
other areas of environmental law and whatnot, is what we're
actually talking about--we're arguing about--is inspecting, not
fixing other parts of this. We're having this long-running,
kind of silly discussion over how often to inspect.
You know, it was only less than 10 years ago that Congress
put in place, with the help of this committee and others, a
mandatory minimum backstop of 7-year reinspection period. We
had nothing before that.
And it's--you know, the whole program is centered around
industry. It's kind of a trust but verify sort of program, and
we're doing a lot of trusting but not a lot of verifying. And
if you don't inspect, you don't know and so where does that
leave you? I think with all the fears----
Senator Boxer. It leaves us at the mercy of something like
this.
Mr. Kessler. That's right.
Senator Boxer. And everyone comes and says, ``Oh my God,
how awful,'' and then we have to make the most of the moment.
And that's important.
Let me ask Mr. Santa and Ms. Sames, because I think they
represent the industry. So, the same question to you, because
what we know is 61 percent of our present-day gas transmission
pipelines were constructed prior to 1970--61 percent.
And when you say, Ms. Sames, we have the safest record in
the world and so on, I guess one way to look at it is if you
look at Europe, you look at other places, they have very old
infrastructure, older than ours in some cases. And we want to
make sure that we don't have the same problems, or worse
problems, going forward.
So I guess I have the same question. Does an aging
infrastructure inevitably lead to accidents, or can we do a
better job--can you do a better job--of testing and maintaining
that infrastructure, Mr. Santa?
Mr. Santa. I--yes, Senator, I believe that we can. As a
matter of fact, I think that's reflected in the nine
commitments that INGAA has made--our voluntary commitments on
pipeline safety, and we are very committed to this.
I think that age alone is not the determinative factor.
We're committed to a goal of zero incidents, and I think that
we will do that which we can to improve.
We've got a good record, but it is not perfect. We'll
concede that. And we are committed to that improvement.
Senator Boxer. To me what's really important is go after
those high-risk areas first.
So in other words, if there's a pipeline that's very old,
and if that pipe is big, and if there was no development there
before and suddenly there's housing there--I mean, my goodness,
a bell has to go up. And if there's a lot of, you know,
roadwork there, all these things are, it seems to me, clues
that you need to move faster in certain areas and because we
know there's miles and miles and miles and miles.
So what we want to do is get after the high-risk pipelines
first. Would you agree with that, Ms. Sames?
Ms. Sames. I would, and I would also like to agree with Mr.
Kessler and Mr. Santa that age or material are not the only
factors to consider.
Pipelines are very unique. You have a multitude of ages,
multitude of materials, and multitude of environments. And an
operator really needs to take into account a variety of factors
to determine the health of that pipeline.
And you can do that in a number of ways. I know you've read
through the NTSB report as I have. What you see in the NTSB
report is there really isn't a silver bullet, but there's a
multitude of tools that could be used to assess the integrity
of the line.
I think what we in the industry firmly believe is that all
tools should be utilized to take a closer look, specific to a
particular pipeline.
Senator Boxer. OK. I'm going to ask a yes or no, and go
down. We'll start from you, Ms. Sames, and just say yes or no,
or don't know.
Do you support eliminating the grandfather clause that
exempts pre-1970 pipelines from pressure tests? Do you now
support eliminating that grandfather clause, so we can give
pressure tests to those pipelines pre-1970?
Ms. Sames. I know you asked for a yes/no.
Senator Boxer. Yes, no, or don't know.
Ms. Sames. I'd say yes, with caveats.
Senator Boxer. Yes with caveats.
Mr. Santa?
Mr. Santa. We support eliminating it in high-consequence
areas as is done in S. 275.
Senator Boxer. OK. So you support it in high-consequence
areas but not all the pre-1970 pipelines.
Mr. Kessler?
Mr. Kessler. Look, we absolutely support removing it,
period. But we're not sure S. 275 actually goes all the way to
doing that, so.
Senator Boxer. Right. It doesn't, sir, Mr. Santa. We don't.
We say you have to give us records, but it doesn't force the
tests. So it's not as strong as you've shown it to be. We wish
it was. We're trying.
Mr. Kessler. I agree with you, Madame Chair.
Mr. Santa. I'd be happy to discuss that with you at some
point, Senator, but I think that between the records
requirement and, if you do not pass the records requirement,
the requirement to test, I do believe that effectively
eliminates the grandfather clause for pipe within HCAs.
Senator Boxer. OK. We don't believe it is for all pre-1970
lines.
Yes, do you support that testing?
Mr. Stavropoulos. Yes.
Senator Boxer. Yes. No caveats. Let the record show PG&E
said yes without a caveat.
Ms. Hersman. Yes.
Ms. Quarterman. Absolutely.
Senator Boxer. OK, that's good. That's good.
I had a lot of questions for PG&E, but you can't answer
them because you're so new. So I'll have to send it to them in
the record. And the record will stay open. How many days can we
keep the record open? Two weeks, so that we can get back from
you your comments.
Mr. Santa, pipeline safety legislation introduced by
Senator Feinstein and myself would have required automatic or
remote controlled shutoff valves, wherever technically and
economically feasible. And I think Mr. Kessler--I think you're
the one who made a very, I thought, compelling case for that.
The compromised legislation that passed this committee only
required these valves on new pipelines. Is that correct?
Did INGAA oppose requiring automatic or remote controlled
shutoff valves on preexisting pipelines?
Mr. Santa. We support what's in S. 275, Senator, and I'd
also note for you that the House Energy and Commerce bill
includes a directive to the secretary to review and report back
on the question of whether or not retrofits should be required.
And we're comfortable with that assessment.
Senator Boxer. I know you're comfortable with it. I'm not
so comfortable. I think we ought to require this. And you have
caveats. And I think that is critical.
Let me just say this: it took so long, and I thought that
the most stunning thing on your video presentation was that it
was volunteer PG&E people that came over there and were able to
shut this off. This makes no sense. It's just a dereliction of
responsibility. If you had these automatic shutoff valves, it
would make all the difference in the world.
So I hope you'll take another look at this. Because,
frankly, I think maybe Mr. Kessler said something--that the
good operators are the ones who are going to win over the
pubic, who are going to have the good relations. And if ever
there was a case for automatic shutoff valves--you had a
situation here where people didn't show up, and the ones that
showed up risked everything to go there. It shows the amazing
sense of responsibility they had.
So, I'll ask this again to INGAA. Does INGAA support
requiring automatic or remote controlled shutoff valves on
preexisting pipelines, either through legislation or rulemaking
by PHMSA?
Mr. Santa. Were it to be required in rulemaking by PHMSA,
we would comply with the requirements, yes, Senator.
Senator Boxer. I know you'd comply. Because if you don't
comply you're breaking the law; you'd never do that.
So you'd comply, but you're not saying that you support it.
Am I right? I mean, let's just be candid here. You're not
supporting it here today but you're saying if PHMSA required
it, you would of course comply.
Mr. Santa. Of course we would, yes. Our members comply with
the regulations----
Senator Boxer. Right, but you don't support it. You're not
asking PHMSA to do this.
Mr. Santa.--and in many instances go beyond the
regulations.
Senator Boxer. But you're not asking PHMSA to do this
today.
Mr. Santa. No, we are not, Senator.
Senator Boxer. Fine. I just wanted--and I assume, Ms.
Sames, you're the same.
Ms. Sames. We've actually taken a very hard look at--we
support it on new and fully replaced lines. We support that in
the bill.
We've also looked at existing lines. We have a technical
committee that has submitted a document to the NTSB during the
hearing process on this particular issue. We have extended that
work, of the technical committee, to really dive into all of
the pros, cons, considerations that need to be taken into
account when installing these lines on an existing system. We
expect that to be finished around the end of the year.
Senator Boxer. All right. I'm going to close now; I'm sure
you're all breathing a sigh of relief that I'm about to close
this hearing.
But I want to leave you with this picture in mind, but also
this picture in mind. This is what happened because there was
no automatic shutoff valve. If we had that, it would've sensed
the leak and we would've not seen this happen. And 38 more
people would not have died, more than likely. It would have
been immediately stopped.
So what I want you to think about is this. We all serve the
public--utilities serve the public, regulators serve the
public, PG&E serves the public. Mr. Kessler is chosen to be a
consumer advocate; he speaks for the public. You look like
you're absolutely dying to say something, Mr. Kessler.
Mr. Kessler. I just wanted to say--Madame Chair, thank you.
You know, I agree with everything you said and I want to
point out that should PHMSA actually promulgate a role, the law
requires that that rule go through a very rigorous cost/benefit
analysis that is peer reviewed by committees that are
substantially populated by industry folks. And it would have to
have benefits that outweigh the costs.
And we have supported the idea that retrofit should be done
in technically, economically, feasible locations where lives
would be saved. And I would go so far--and we've made this
offer--that we'd be happy to see the industry required--
companies be required to come up with plans, that they'd be
required to assess their own system and submit plans
themselves, and file those plans.
Not a hard mandate. I mean, if that gets us closer to our
goal, much like the Pollution Protection Act, just the mere
assessment and filing of a plan is often enough. We'd be
supporting of that. We are not out to--natural gas has a clean,
good feel. It's American. We're not out to bankrupt the
industry.
Senator Boxer. Nobody is. And part of it being acceptable
to the public is to minimize this. So I'm going to correct what
I said before. If we test for leaks, then we would stop an
explosion. If we put in an automatic shutoff valve, that's the
second line of defense. You would still have the explosion and
I don't know that we could say nobody would be devastated, but
we can definitely say it would minimize the damage after the
initial explosion.
So it seems to me these two things are doable. There's no
crisis in technology. It's out there for you. It's out there
for you, I say to the utilities and to the people who represent
them. And, you know, the greatest thing in my life would be--
and I can speak for Senator Feinstein, and I can speak for my
colleagues, and I think I can speak for the regulators--is if
you do this, you step out front and do the right thing--now, I
think PG&E, from your testimony today, it sounds to me like
you're moving in the right direction.
But nothing will speak to me better than actually testing,
first the most vulnerable areas, areas that we describe like
this, where you have the old pipe. It's too large for a
residential community, and the recordkeeping was no good then,
and we need massive inspections of this pipe. Because I don't
want to be here again, being aggravated with you, and having a
new person hired by some other utility to come here and say,
``I can't answer for what happened back then.''
And we're in a position to make this better. We really are,
on multiple levels. I do want to say to NTSB, I can't tell you
how impressed you are--I know that Senator Feinstein said that.
I agree with her. You were out there immediately. I was talking
to NTSB practically every day for weeks, and they were on the
case--smart people, fair people, you know, but calling it the
way it was.
And, I mean, that's something we don't often say around
here, and so I wanted to say that. So here's my wrap-up. There
were multiple opportunities to prevent this accident. Due to
failures by the pipeline industry, the state and Federal
regulators, everybody bears the burden of not doing what they
should've.
The same safety problems persisted year after year. I told
you about the 2008 incident. You're not familiar with it? Same
problems. Very similar. This happened 2 years later. Not enough
was done.
I'm pleased that the Senate passed S. 275, and I thank Ms.
Quarterman for her help and her agency's help in helping us put
that together. And it was strengthened last night.
But I am concerned--as you can note from my questions to
you, Ms. Quarterman, that PHMSA has not even begun making
changes to its integrity management program protocols.
I believe this to be an emergency. I think you should go
back there; you should work through the weekend; you should
take what you learn from a one-on-one with the NTSB. Your
agency has a good record, I was pleased to hear that, of
accepting their ideas. Eighty-seven percent, let's make it 95
percent.
These protocols have to be changed. There is no way anyone
could say that CPUC deserved 100 percent. Come on. That either
just shows a reflexive, you know, buddy-to-buddy partner
mentality, or somebody seriously didn't do their job and look
at what was happening.
So, I was glad that Secretary LaHood said, ``I agree that
the tragedy''--he wrote me a letter on October 5--``I agree
that the tragedy in San Bruno requires action, and I'm
committed to ensuring that the pipeline and hazardous materials
safety administration--that's your agency, Ms. Quarterman--
responds to NTSB's recommendations in a timely and effective
manner.''
On September 26, we formally received the accident report
and recommendations. So, it's true, you got them recently, but
now I hope that this hearing, if it does anything else--I hope
it does a few things. I hope it gets this meeting going between
you two, dedicated public servants, and we get going on the
protocols and anything I can do to help move the rulemaking. I
hope that the industry will think again about the images here.
You know, we live in a world where we have short spans of
attention because our world is so full of images every day, and
not all of them are good. And we sometimes forget, which is why
I have this photo here. I think if the industry--if the
regulators do what they have to do, be fair--don't drag it out,
don't be bureaucratic, you do that, we have the
recommendations, that would be tremendous.
We have the industry and, in this case, PG&E, not waiting.
You don't have to wait for protocols. You can just come out and
announce. I would be so excited to hear you have a press
conference: ``We have decided to move now. We're going to do
leak detection, we're going to do automatic shutoff valves on
our oldest pipelines that are near these residential
communities.'' I'm telling you, this would give confidence.
The American people are frustrated about a lot of things.
You've a chance to restore some confidence in something that
they can't live without.
And, Mr. Kessler, I think that again, as usual, you came
forward here with the right attitude. You're not pointing
fingers of blame. You want to work with people but you are
speaking for the consumer, I think in an intelligent way.
I again want to thank Senators Lautenberg and Wicker. I
want to thank Senators Rockefeller and Hutchison, the Chair and
Ranking Member.
I want to thank my dear colleague Senator Feinstein for her
eloquence today, and, you know, I feel in my heart that we can
make a difference here, and I'm ready to work with everybody,
all the parties that I can.
And with that, we stand adjourned. Thank you very much.
[Whereupon, at 4:30 p.m. the hearing was adjourned.]
A P P E N D I X
Response to Written Questions Submitted by Hon. Barbara Boxer to
Hon. Cynthia L. Quarterman
Question 1. At the hearing, I asked how PG&E's record of leaks,
failures, and incidents compare to other natural gas operators. You
responded that you would need to take a further look into the matter,
and I would appreciate your response.
Answer. The incident reports submitted to PHMSA by pipeline
operators for the six-year period of 2004 to 2010 of gas transmission
systems of similar size as PG&E is in the attached chart.
Among the group of 11 similar sized operators, PG&E ranked 3rd
highest number of incidents based on a 7-year average incident rate per
10,000 miles of onshore transmission miles operated. PG&E has an annual
average of 4.58 incidents per 10,000 miles of the onshore transmission
pipelines it operated in the period of 2004-2010.
PHMSA's analysis did not incorporate data for the number of
failures and leaks, as the agency did not require separate reporting of
this information by pipeline operators prior to 2010. Newly revised
operator annual report forms, effective January 1, 2011, allowed PHMSA
to begin to collect and analyze data concerning the number of leaks,
failures, and incidents experienced by pipeline operators as separate
categories.
Question 2. The San Francisco Chronicle reported that recent gas
leaks in Cupertino and Roseville, California involved a type of plastic
pipe called Aldyl-A. Almost three decades ago, Dupont, who is the
manufacturer of Aldyl-A, warned that pipes constructed before 1973 were
prone to cracking and failure. In 1998, after a series of problems, the
NTSB urged operators to assess and replace these problematic pipelines.
Question 2a. If the manufacturer of the pipe and the NTSB both
identified problems with Aldyl-A, why didn't PHMSA require utility
companies to replace the faulty plastic pipelines?
Answer. In April, the Secretary of Transportation issued a Call to
Action urging all stakeholders to do their part to assure the
replacement of high-risk infrastructure, including Aldyl-A, cast iron
and other pipe materials of concern. PHMSA regulations
(Sec. 192.613(b)) require pipeline operators to either (1) recondition
or phase out segments of pipe determined to be in unsatisfactory
condition but not posing immediate hazard, or (2) lower the maximum
allowable operating pressure. PHMSA has issued multiple safety
advisories to pipeline operators reminding them of their responsibility
to take remedial action, including replacement, to mitigate any risks
to public safety posed by pipe whose integrity cannot be verified.
Further, PHMSA has repeatedly advised state pipeline safety programs,
who oversee the vast majority of this type of plastic pipe to institute
repair, rehabilitation, replacement, or requalification programs within
their respective states. PHMSA cannot order large scale replacement of
pipeline infrastructure unless it can support a finding that such pipe
poses an immediate hazard to persons or property.
Question 2b. Are pipeline operators required to report information
about specific types of plastic or other materials that are exhibiting
problems, so that PHMSA can track materials that are prone to failure?
Answer. Yes, pipeline operators are required to submit incident
reports as well as safety related condition reports for events
occurring on their pipelines. These reports include information about
the material qualities of the pipe and allow PHMSA to identify
materials that may be prone to failure.
In addition, PHMSA in cooperation with NTSB and industry
associations, has access to an industry operated reporting system, akin
to a near miss reporting system, in which pipeline operators
voluntarily report issues that do not rise to the level of an incident
or safety related condition. The benefit of the system is that
operators report more information on a greater number of ``non-
incident'' events because of the system's confidentiality. The
increased data allows for more trending and identifying emerging
plastic pipe-related threats.
Question 3. Much of our Nation's original gas pipeline
infrastructure was constructed between the 1950s and 1970s, and much of
it has never been replaced.
Question 3a. What percentage of our present-day gas transmission
pipelines were constructed prior to 1970?
Answer. 59 percent of gas transmission pipelines were constructed
prior to 1970.
Question 3b. What percentage of the leaks, failures, and incidents
that have been reported by gas operators involved pipelines from those
two decades? Is there a correlation between the age of the pipeline and
the likelihood of an accident?
Answer. About 45 percent of ``significant'' gas transmission
incidents between 2005 and 2009, occurred on pipelines installed prior
to 1970. Approximately 55 percent of the significant incidents occurred
on pipelines installed after 1970, representing roughly 41 percent of
the total gas transmission mileage. There does not appear to be a
direct correlation between age of the pipe and the incidents using
2005-2009 data.
Question 4. The California State Legislature recently passed a
series of five bills strengthening the state's pipeline safety
regulations, which for years have already been more stringent than
Federal standards. Are you aware of any states, other than California,
that have more stringent requirements for pipeline safety beyond what
is federally required? If so, which states and how exactly do they
exceed current Federal regulations? Please provide a table listing
those states who exceed Federal regulations, including state statutory
and regulatory citations.
Answer. Yes, as the Federal pipeline safety laws contemplate, some
states have more stringent requirements than those in the Federal
regulations based on the needs within their states. The National
Association of Pipeline Safety Representatives (NAPSR) recently
compiled a listing of state requirements exceeding the minimum Federal
requirements. PHMSA has made this document publicly available at:
http://opsweb.phmsa.dot.gov/pipelineforum/library/index.html.
Attached is a table excerpt from the full document listing which
States exceed Federal regulations.
Question 5. As you know, the Pipeline Safety Improvement Act of
2002 sets December 17, 2008 as the deadline for all pipelines in High
Consequence Areas (HCAs) to be inspected and for remediation plans to
be put in place. The deadline for non-HCAs is 2012. To date, what
percentage of each of these types of pipelines (i.e., in HCAs and in
non-HCAs) have not yet been inspected? Of those that have been
inspected, what percentage do not yet have remediation plans?
Answer. The PSIA of 2002, and subsequent Federal regulations,
require that 50 percent of all gas pipeline segments in High
Consequence Areas (HCAs) be assessed by December 17, 2007. The
regulations further require that 100 percent of pipeline segments in
HCAs be assessed by December 17, 2012. All pipeline segments in HCAs
must have a plan to address any anomalies within the timeframes
identified in the regulations, i.e., immediate, one year, monitored,
and other activities depending on the severity of the anomalies found.
Out of the 302,000 onshore gas transmission miles, about 7 percent
or 21,000 miles of onshore gas transmission lines are in HCAs. The
total mileage assessed is about 187,000 miles since the start of the
IMP Program. This includes mileage inside and outside of HCAs.
Based on reports submitted to date, roughly 95 percent of HCA miles
on gas transmission systems have been assessed in accordance with
PHMSA's Integrity Management regulations, leaving approximately 1,000
miles yet to be assessed prior to the 2012 deadline. The remaining HCA
miles yet to be assessed are lower-risk segments.
Question 6. In March, Senator Feinstein and I sent you a letter
expressing concern about a regulatory loophole that allows pipeline
operators to avoid reporting instances when they exceed the Maximum
Allowable Operating Pressure (MAOP) on a pipeline, as PG&E did twice in
San Bruno before last year's explosion. PHMSA does not require
operators to report these high pressures unless they persist for more
than five days.
Federal law requires that the Secretary of Transportation ``shall
prescribe regulations requiring each operator of a pipeline facility. .
.to submit to the Secretary a written report on any (A) condition that
is a hazard to life, property or the environment. . . .'' Yet, PHMSA's
regulations limit this reporting requirement to a narrow suite of
conditions.
Question 6a. What was the Department of Transportation's basis for
so severely limiting the types of safety-related conditions that
pipeline operators are required to report, particularly in the face of
a clear Congressional directive?
Answer. PHMSA believes the safety related condition regulations,
which were reviewed by OMB and legal staff prior to adoption, are
aligned with the original Congressional directive and intent. The
pipeline safety regulations require operators to report certain safety
related conditions that, if allowed to continue without prompt
mitigation, could result in a safety risk. The safety-related condition
reporting requirements were specifically designed to assure that PHMSA
is notified of conditions that require prompt and timely action so that
regulators can monitor the operator's mitigative action.
Question 6b. Unless operators report on all safety and
environmental hazards (including all instances when the MAOP is
exceeded), how will PHMSA know what hazards are recurring frequently?
Answer, PHMSA reviews records of any abnormal operating conditions
during routine and specialized onsite inspections. Inspectors examine
operator records and facilities to assure that the cause of an abnormal
operation is investigated and addressed. Further, as part of their
safety evaluation duties, inspectors consider the potential engineering
impact of recurring abnormal conditions and whether the operator has
adequately addressed the situation. Moreover, following its
inspections, PHMSA both may bring enforcement actions and will publish
final orders against operators, which applies a broader audience to
view the types and character of identified safety and environmental
hazards.
Question 6c. Given that the current regulation so clearly fails to
meet the Congressional directive does PHMSA intend to draft new rules
that will comport with the law? If so, when will those rules be
proposed?
Answer. PHMSA does not anticipate changes to the current regulatory
requirements for safety related condition reporting. However, on August
25, 2011, PHMSA proposed an Advanced Notice of Proposed Rulemaking
(ANPRM) for the Safety of Gas Transmission Pipelines. This ANPRM poses
a number of questions to stakeholders regarding the adequacy and
stringency of current regulations. The public comment period on the
ANPRM expires on January 20, 2012. Based on public comment, PHMSA may
consider changes to this portion of the regulations.
Comparison per 7 year totals and averages; based on Gas Transmission & Gathering systems Incident and Annual Reports
--------------------------------------------------------------------------------------------------------------------------------------------------------
Data as of 11/02/2011 Gas Transmission line mileage in TRANSMISSION LINES (Gathering lines excluded)
-------------------------------------- 2004-2010; OPID 15700 and similar -----------------------------------------------------------------------------
size operators
-------------------------------------
7 years average
of incidents Number of
Operator OPID Average of which occurred on Count of Number of Property Occurred Serious
Transmission transmission line Incidents(*) fatalities injuries Damage in HCA Incidents
Onshore Miles per 10,000
in 2004-2010 transmission line
mileage
--------------------------------------------------------------------------------------------------------------------------------------------------------
CENTERPOINT ENERGY GAS 602 6,215 10.57 46 0 1 $9,992,420 9 1
TRANSMISSION
--------------------------------------------------------------------------------------------------------------------------------------------------------
GULF SOUTH PIPELINE 31,728 6,687 7.48 35 1 2 $12,217,613 8 3
COMPANY, LP
--------------------------------------------------------------------------------------------------------------------------------------------------------
PACIFIC GAS & ELECTRIC CO 15,007 5,620 4.58 18 8 51 $223,981,666 6 1
--------------------------------------------------------------------------------------------------------------------------------------------------------
SOUTHERN STAR CENTRAL GAS 31,711 5,894 4.36 18 1 1 $11,634,701 4 2
PIPELINE, INC
--------------------------------------------------------------------------------------------------------------------------------------------------------
ATMOS PIPELINE--TEXAS 31,978 6,069 3.77 16 0 0 $2,389,601 3 0
--------------------------------------------------------------------------------------------------------------------------------------------------------
TEXAS GAS TRANSMISSION LLC 19,270 5,772 2.97 12 0 2 $2,444,130 1 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
PANHANDLE EASTERN PIPELINE 15,105 6,042 2.84 12 0 0 $6,069,669 0 0
CO
--------------------------------------------------------------------------------------------------------------------------------------------------------
FLORIDA GAS TRANSMISSION CO 5,304 4,908 2.62 9 0 3 $1,626,878 3 1
--------------------------------------------------------------------------------------------------------------------------------------------------------
COLORADO INTERSTATE GAS CO 2,564 5,208 2.19 8 1 0 $6,076,828 0 1
--------------------------------------------------------------------------------------------------------------------------------------------------------
ENTERPRISE PRODUCTS 31,618 5,303 2.15 8 1 7 $2,195,449 1 1
OPERATING LLC
--------------------------------------------------------------------------------------------------------------------------------------------------------
KM INTERSTATE GAS 1,007 4,643 1.85 6 0 0 $469,705 0 0
TRANSMISSION CO
--------------------------------------------------------------------------------------------------------------------------------------------------------
(*) includes incidents where pipeline function not reported; incident form changed in 2010.
______
Response to Written Questions Submitted by Hon. Roger F. Wicker to
Hon. Cynthia L. Quarterman
Question 1. The investigation of the San Bruno accident found that
the pipe involved was defective, yet went undetected for over 50 years.
Is there a way to detect if there are other, similar pipes currently in
use?
Answer. There are two ways of determining if other, similar, pipe
is currently in use elsewhere in the country: Records evaluation and
physical examination of the pipe itself.
The pipe involved in the San Bruno incident was installed prior to
implementation of Federal pipeline safety regulations (1968-1970).
Therefore, the company was not required to maintain records of the type
of pipe installed until pipeline safety regulations went into effect.
Pursuant to the existing industry standards, companies installing pipe
prior to the regulations should have maintained records of the pipe in
their systems. The specific PG&E case involves the installation of pipe
that did not meet existing industry standards and incorrect or
incomplete records about the type of pipe installed. On January 10,
2011, PHMSA issued an Advisory Bulletin to all operators reminding them
of the need to check their records for accuracy and adequacy.
Physical examination of the pipe involves either excavation to
inspect the pipe visually or the use of internal inspection devices
(smart pigs) that can detect problems inside the pipe. Since excavation
of all pipelines that might be similar would probably be impracticable,
assessment tools such as in line inspection technologies or hydrostatic
testing could be used to determine the integrity of the pipelines.
While use of internal inspection tools is the preferred method to
inspect pipelines, many older pipelines cannot accommodate the tools
because of sharp turns, T-intersections, and other obstructions and
hydrostatic testing might be necessary and the only available option
for internal testing.
Question 2. The accident at San Bruno had catastrophic results, at
least partly due to the large volume of natural gas located so close to
a residential area. How many similarly large natural gas distribution
pipelines are located in populated areas?
Answer. Almost all of the two million miles of distribution system
pipelines are located in high population areas because they supply
natural gas to homes and businesses in our communities for heating and
cooking. Distribution pipelines directly supply natural gas into
residential, public and commercial buildings, and manufacturing
facilities. However, the PG&E pipeline that failed in San Bruno was an
intrastate transmission pipeline that supplied gas to lower pressure
distribution pipelines. There are approximately 35,000 miles of gas
transmission pipelines located in populated areas.
______
Response to Written Question Submitted by Hon. Frank R. Lautenberg to
Hon. Deborah A.P. Hersman
Question Several state and local government agencies are currently
exempt from using the one-call system before digging. With excavation
damage being the leading cause of pipeline accidents year after year,
should anyone be exempt from this safety requirement?
Answer. The NTSB believes that pipeline safety rules, like marking
lines, should be followed by all entities working around pipelines. No
one should be exempt from the one-call rules.
______
Response to Written Questions Submitted by Hon. Barbara Boxer to
Hon. Deborah A.P. Hersman
Question 1. What does the San Bruno incident indicate about the
need for improvements in quality control, integrity management
programs, release prevention, and emergency response protocols
throughout the industry?
Answer. Although the NTSB's investigation and accident report were
focused on San Bruno, the NTSB considered the likelihood that similar
conditions exist with other pipeline operators and state pipeline
regulators. The NTSB believes that safety improvements are needed
throughout the pipeline industry.
The three critical elements of Quality Control, Integrity
Management Programs, and Release Prevention stated in the question go
hand-in-hand. As was shown in the San Bruno accident, an inadequate
Quality Assurance and Quality Control Program in the 1950s allowed the
installation of a substandard and poorly welded pipe section with a
visible seam weld flaw that grew to a critical size. Since the 1950s,
the pipeline industry and regulators have established quality control
measures that far exceed those in place sixty years ago. Current
Federal safety regulations for gas pipelines have incorporated the
standards and recommended practices of highly regarded technical
organizations such as the Pipeline Research Council International, the
American Petroleum Institute, the American Society for Testing and
Materials, the American Society of Mechanical Engineers International,
and the National Association of Corrosion Engineers. These standards
and recommended practices supplement Federal requirements for the
design of pipe and pipeline components, welding standards,
qualification of welders, general construction standards, corrosion
control and maintenance. These technical standards typically include
testing and quality control measures to ensure the standards are being
met.
The bigger concern in the NTSB's view is that more than half of the
Nation's natural gas transmission pipelines were constructed prior to
1970 and predate today's comprehensive technical standards and quality
controls. It is therefore imperative that operators and regulators are
both accountable to continuously and aggressively monitor and maintain
the structural integrity of these pipelines. To that end, PHMSA should
(1) modify its oversight protocols to better verify that operators have
employed and are executing integrity management and other performance-
based safety programs based on accurate risk assessments and the use of
meaningful metrics; (2) ensure that pipeline operators maintain
accurate system data on pipeline construction, maintenance, and leak
and repair histories; and (3) assess whether operators are establishing
and meeting performance goals.
In addition, PHMSA should (1) require all operators of natural gas
transmission and distribution pipelines to equip their supervisory
control and data acquisition (SCADA) systems with tools to assist in
recognizing and pinpointing the location of leaks, including line
breaks, and to isolate lines breaks in a timely manner; such tools
could include a real-time leak detection system and appropriately
spaced flow and pressure transmitters along covered transmission lines;
(2) require automatic shutoff valves or remote control valves in high
consequence areas, and (3) require all gas transmission pipelines
constructed before 1970 be subjected to a hydrostatic pressure test
that incorporates a spike test to eliminate defects from reaching a
critical size and causing a pipeline failure.
Regarding Emergency Response, the operators of natural gas
transmission and distribution pipelines and hazardous liquid pipelines
should be required (1) to provide system-specific information about
their pipeline systems to the emergency response agencies of the
communities and jurisdictions in which those pipelines are located;
this information should include pipe diameter, operating pressure,
product transported, and potential impact radius; and (2) to ensure
that their control room operators immediately and directly notify the
911 emergency call center(s) for the communities and jurisdictions in
which those pipelines are located when a possible rupture of any
pipeline is indicated.
Question 2. At the hearing, you mentioned that 91 percent of NTSB's
recommendations have been accepted by PHMSA over the years. Which
recommendations have been implemented? What recommendations have not
been implemented?
Answer. The ``acceptable'' rate of our recommendations is a
constantly changing number given action or inaction on the part of the
recipient. At this time, the acceptance rate of NTSB's pipeline
recommendations issued to PHMSA, since it was created in 2004, is 100
percent. In other words, all pipeline recommendations issued to PHMSA,
since its creation in 2004, are either closed in an acceptable manner
or they have acted favorably on open pipeline recommendations.
Since the creation of PHMSA in 2004, the following 24 pipeline
recommendations have been closed with acceptable action or superseded
by a new NTSB recommendation:
1. Closed Acceptable Action (CAA) 04/28/10. Require operators
of hazardous liquid pipelines to follow the American Petroleum
Institute's Recommended Practice 1165 for the use of graphics
on the SCADA screens. (P-05-001)
2. CAA 04/28/10. Require pipeline companies to have a policy
for the review/audit of alarms. (P-05-002)
3. CAA 04/28/10. Require controller training to include
simulator or non-computerized simulations for controller
recognition of abnormal operating conditions, in particular,
leak events. (P-05-003)
4. CAA 04/06/10. Change the liquid accident reporting form
(PHMSA F 7000-1) and require operators to provide data related
to controller fatigue. (P-05-004)
5. Closed Acceptable Alternative Action (CAAA) 05/06/10.
Require operators to install computer-based leak detection
systems on all lines unless engineering analysis determines
that such a system is not necessary. (P-05-005)
6. CAA 03/17/08. Provide a summary of the lessons learned from
the Bergenfield, New Jersey accident to recipients of emergency
planning and response grants. (P-07-001)
7. CAA 02/14/11. Require in 49 Code of Federal Regulations
195.52 that a pipeline operator must have a procedure to
calculate and provide a reasonable initial estimate of released
product in the telephonic report to the National Response
Center. (P-07-007)
8. CAA 02/14/11. Require in 49 Code of Federal Regulations
195.52 that a pipeline operator must provide an additional
telephonic report to the National Response Center if
significant new information becomes available during the
emergency response. (P-07-008)
9. CAA 09/18/09. Require an operator to revise its pipeline
risk assessment plan whenever it has failed to consider one or
more risk factors that can affect pipeline integrity. (P-07-
009)
10. CAA 02/14/11. Through appropriate and expeditious means
such as advisory bulletins and posting on your website,
immediately inform the pipeline industry of the circumstances
leading up to and the consequences of the September 9, 2010,
pipeline rupture in San Bruno, California, and the National
Transportation Safety Board's urgent safety recommendations to
Pacific Gas and Electric Company so that pipeline operators can
proactively implement corrective measures as appropriate for
their pipeline systems. (P-10-001, Urgent)
11. Closed Superseded (CS) 09/26/11. Issue guidance to
operators of natural gas transmission and distribution
pipelines and hazardous liquid pipelines regarding the
importance of sharing system-specific information, including
pipe diameter, operating pressure, product transported, and
potential impact radius, about their pipeline systems with the
emergency response agencies of the communities and
jurisdictions in which those pipelines are located. (P-11-001)
12. CS 09/26/11. Issue guidance to operators of natural gas
transmission and distribution pipelines and hazardous liquid
pipelines regarding the importance of control room operators
immediately and directly notifying the 911 emergency call
center(s) for the communities and jurisdictions in which those
pipelines are located when a possible rupture of any pipeline
is indicated. (P-11-002)
13. CAA 07/01/08. Develop and implement, with the assistance of
the Minerals Management Service, the U.S. Coast Guard, and the
U.S. Army Corps of Engineers, effective methods and
requirements to bury, protect, inspect the burial depth of, and
maintain all submerged pipelines in areas subject to damage by
surface vessels and their operations. (P-90-029)
14. CAA 04/28/10. Determine the extent of the susceptibility to
premature brittle-like cracking of older plastic piping (beyond
that piping marketed by Century Utility Products, Inc.) that
remains in use for gas service nationwide. Inform gas system
operators of the findings and require them to closely monitor
the performance of the older plastic piping and identify and
replace, in a timely manner, any of the piping that indicates
poor performance based on such evaluational factors as
installation, operating and environmental conditions, piping
failure characteristics, and leak history. (P-98-002)
15. CAAA 05/03/06. Require pipeline system operators to
precisely locate and place permanent markers at sites where
their gas and hazardous liquid pipelines cross navigable
waterways. (P-98-025)
16. CAA 05/03/06. Assess the potential safety risks associated
with rotating pipeline controller shifts and establish industry
guidelines for the development and implementation of pipeline
controller work schedules that reduce the likelihood of
accidents and attributable to controller fatigue. (P-98-030)
17. CAAA 02/18/10. Establish within 2 years scientifically
based hours-of-service regulations that set limits on hours of
service, provide predictable work and rest schedules, and
consider circadian rhythms and human sleep and rest
requirements. (P-99-012)
18. CAA 11/28/06. Establish quantitative criteria, based on
engineering evaluations, for determining whether a wrinkle may
be allowed to remain in a pipeline. (P-02-001)
19. CAA 05/03/06. Develop and issue guidance to pipeline
operators on specific testing procedures than can (1) be used
to approximate actual operations during the commissioning of a
new pumping station or the installation of a new relief valve,
and (2) be used to determine, during annual tests, whether a
relief valve is functioning properly. (P-02-004)
20. CAA 09/20/07. Revise 49 Code of Federal Regulations Part
192 to require that new or replaced pipelines be designed and
constructed with features to mitigate internal corrosion. At a
minimum, such pipelines should (1) be configured to reduce the
opportunity for liquids to accumulate, (2) be equipped with
effective liquid removal features, and (3) be able to
accommodate corrosion monitoring devices at location with the
greatest potential for internal corrosion. (P-03-001)
21. CAA 08/21/05. Evaluate the Office of Pipeline Safety's
pipeline operator inspection program to identify deficiencies
that resulted in the failure of inspectors, before the
Carlsbad, New Mexico, accident, to identify the inadequacies in
El Paso Natural Gas Company's internal corrosion control
program. Implement the changes necessary to ensure adequate
assessments of pipeline operator safety programs. (P-03-003)
22. CAA 01/10/11. Amend 49 Code of Federal Regulations to
require that natural gas pipeline operators (Part 192) and
hazardous liquid pipeline operators (Part 195) follow the
American Petroleum Institute's recommended practice RP 5LW for
transportation of pipe on marine vessels. (P-04-002)
23. CAAA 05/03/06. Revise the emergency response planning
requirements in the pipeline safety regulations to include
coordination with electric and other utilities that may need to
respond to a pipeline emergency. (P-04-007)
24. CAA 05/18/2005. Issue an advisory bulletin to liquid
pipeline operators to validate the accuracy of their tank
strapping tables. (P-04-008)
As of this date, the following 19 pipeline recommendations to PHMSA
remain open. For six of the 19 recommendations, the NTSB has determined
that PHMSA is acting on them in a manner consistent with the intent of
the recommendation. The NTSB is awaiting a response from PHMSA
concerning its actions in regard to the other 13 open recommendations:
1. Open Acceptable Response (OAA). Require that excess flow
valves be installed in all new and renewed gas service lines,
regardless of a customer's classification, when the operating
conditions are compatible with readily available valves. (P-01-
002)
2. OAA. Remove the exemption in 49 Code of Federal Regulations
192.65 (b) that permits pipe to be placed in natural gas
service after pressure testing when the pipe cannot be verified
to have been transported in accordance with the American
Petroleum Institute's recommended practice RP 5L1. (P-04-001)
3. OAA. Evaluate the need for a truck transportation standard
to prevent damage to pipe, and, if needed, develop the standard
and incorporate it in 49 Code of Federal Regulations Parts 192
and 195 for both natural gas and hazardous liquid line pipe.
(P-04-003)
4. OAA. Conduct a comprehensive study to identify actions that
can be implemented by pipeline operators to eliminate
catastrophic longitudinal seam failures in electric resistance
welded pipe; at a minimum, the study should include assessments
of the effectiveness and effects of in-line inspection tools,
hydrostatic pressure tests, and spike pressure tests; pipe
material strength characteristics and failure mechanisms; the
effects of aging on electric resistance welded pipelines;
operational factors; and data collection and predictive
analysis. (P-09-001)
5. OAA. Based on the results of the study requested in
recommendation (P-09-1), implement the actions needed. (P-09-
002)
6. OAA. Initiate a program to evaluate pipeline operators'
public education programs, including pipeline operators' self-
evaluations of the effectiveness of their public education
programs. Provide the National Transportation Safety Board with
a timeline for implementation and completion of this
evaluation. (P-09-003)
7. Open Await Response (OAR). Require operators of natural gas
transmission and distribution pipelines and hazardous liquid
pipelines to provide system-specific information about their
pipeline systems to the emergency response agencies of the
communities and jurisdictions in which those pipelines are
located. This information should include pipe diameter,
operating pressure, product transported, and potential impact
radius. [Supersedes Recommendation P-11-1] (P-11-008)
8. OAR. Require operators of natural gas transmission and
distribution pipelines and hazardous liquid pipelines to ensure
that their control room operators immediately and directly
notify the 911 emergency call center(s) for the communities and
jurisdictions in which those pipelines are located when a
possible rupture of any pipeline is indicated. [Supersedes
Recommendation P-11-2] (P-11-009)
9. OAR. Require that all operators of natural gas transmission
and distribution pipelines equip their supervisory control and
data acquisition systems with tools to assist in recognizing
and pinpointing the location of leaks, including line breaks;
such tools could include a real-time leak detection system and
appropriately spaced flow and pressure transmitters along
covered transmission lines. (P-11-010)
10. OAR. Amend Title 49 Code of Federal Regulations 192.935(c)
to directly require that automatic shutoff valves or remote
control valves in high consequence areas and in class 3 and 4
locations be installed and spaced at intervals that consider
the factors listed in that regulation. (P-11-011)
11. OAR. Amend 49 CFR 199.105 and 49 CFR 199.225 to eliminate
operator discretion with regard to testing of covered
employees. The revised language should require drug and alcohol
testing of each employee whose performance either contributed
to the accident or cannot be completely discounted as a
contributing factor to the accident. (P-11-012)
12. OAR. Issue immediate guidance clarifying the need to
conduct post-accident drug and alcohol testing of all
potentially involved personnel despite uncertainty about the
circumstances of the accident. (P-11-013)
13. OAR. Amend Title 49 Code of Federal Regulations 192.619 to
delete the grandfather clause and require that all gas
transmission pipelines constructed before 1970 be subjected to
a hydrostatic pressure test that incorporates a spike test. (P-
11-014)
14. OAR. Amend Title 49 Code of Federal Regulations Part 192 of
the Federal pipeline safety regulations so that manufacturing-
and construction-related defects can only be considered stable
if a gas pipeline has been subjected to a post-construction
hydrostatic pressure test of at least 1.25 times the maximum
allowable operating pressure. (P-11-015)
15. OAR. Assist the California Public Utilities Commission in
conducting the comprehensive audit recommended in Safety
Recommendation P-11-22. (P-11-016)
16. OAR. Require that all natural gas transmission pipelines be
configured so as to accommodate in-line inspection tools, with
priority given to older pipelines. (P-11-017)
17. OAR. Revise your integrity management inspection protocol
to (1) incorporate a review of meaningful metrics; (2) require
auditors to verify that the operator has a procedure in place
for ensuring the completeness and accuracy of underlying
information; (3) require auditors to review all integrity
management performance measures reported to the Pipeline and
Hazardous Materials Safety Administration and compare the leak,
failure, and incident measures to the operator's risk model;
and (4) require setting performance goals for pipeline
operators at each audit and follow up on those goals at
subsequent audits. (P-11-018)
18. OAR. (1) Develop and implement standards for integrity
management and other performance-based safety programs that
require operators of all types of pipeline systems to regularly
assess the effectiveness of their programs using clear and
meaningful metrics, and to identify and then correct
deficiencies; and (2) make those metrics available in a
centralized database. (P-11-019)
19. OAR. Work with state public utility commissions to (1)
implement oversight programs that employ meaningful metrics to
assess the effectiveness of their oversight programs and make
those metrics available in a centralized database, and (2)
identify and then correct deficiencies in those programs. (P-
11-020)
Thirteen of the nineteen open safety recommendations to PHMSA were
issued as a result of the San Bruno investigation.
Question 3. What are NTSB's top pipeline safety priorities that
have not been addressed by Federal pipeline safety regulations?
Answer. In the San Bruno accident report, the NTSB addressed
several safety issues that need to be addressed by Federal pipeline
safety regulations. The NTSB considers the following safety issues to
be of critical importance for restoring and improving the safety of
natural gas transmission pipelines:
Integrity Management
Establishment of an Maximum Allowable Operating Pressure
(MAOP)
Oversight of Performance-based Programs
Supervisory Control And Data Acquisition (SCADA) System
Operations
Use of Automatic Shut-Off Valves (ASVs) or Remote Control
Valves (RCVs)
Emergency and Risk Management Procedures
Public Awareness Programs
Another long-standing safety issue that needs to be address is the
broader use of excess flow valves (EFVs). The NTSB's safety
recommendation P-01-02 called upon PHMSA to require that excess flow
valves be installed in all new and renewed gas service lines,
regardless of a customer's classification, when the operating
conditions are compatible with readily available EFVs. The existing
regulations only require the installation of EFVs on newly constructed
single-family homes.
Question 4. The NTSB report cites the CPUC's ``failure to detect
the inadequacies of PG&E's pipeline integrity management program'' as a
contributing factor in the San Bruno Accident. Could you describe in
more detail the deficiencies in the CPUC's oversight and inspection of
natural gas operators, and what this indicates in turn about PHMSA's
oversight of state regulators?
Answer. The NTSB determined that the CPUC missed opportunities over
many years through its audits and inspections to uncover the pervasive
and long-standing problems within PG&E. These problems were found with
its integrity management program, which is a performance-based program
intended to ensure the safe operation of a pipeline system. Despite
conducting two audits and using a procedure developed by PHMSA for use
nationwide, the CPUC failed to uncover these problems. The NTSB
believes that had the CPUC detected and acted on PG&E's problems with
implementation and execution of its integrity management program, the
defective pipe section that ruptured in San Bruno could have been
detected and removed before it ruptured. Of great concern to the NTSB
is that CPUC and PHMSA (1) failed to identify and correct deficiencies
within PG&E, and (2) failed to recognize through objective self-
assessments the need for improvements of their respective oversight
programs.
Question 5. Based on past natural gas pipeline incidents
investigated by NTSB, what is the average length of time for gas
operators to shut off the gas flow following an accident? Have there
been other incidents where it has taken an equally long time as it took
for PG&E to shut off the gas during the San Bruno incident (95
minutes).
Answer. In the San Bruno accident, the ruptured section of the gas
transmission pipeline was not isolated for 95 minutes, which the NTSB
determined to be excessive for the densely populated residential area.
There is no one length of time to shut off the flow of gas that is
appropriate for all systems and situations. In any event, it is
critical to stop the flow of gas in the pipeline to prevent or minimize
the danger to the public and the environment. To stop the flow, the
breach in the pipeline has to be isolated by closing shutoff valves on
either side of the breach.
Factors such as population density, potential impact upon the
environment, the size and operating pressure of the pipeline, and the
hazards of the product in the pipeline, are critical considerations of
any pipeline operator when determining the types, placements, and
spacing of shutoff valves to attain a timely shutdown in an emergency
situation.
In 1982, the NTSB issued a safety recommendation regarding
emergency shutdown to PG&E following a gas distribution pipeline
investigation. On August 25, 1981, a PG&E excavation contractor
punctured a 16-inch natural gas main in San Francisco, California. The
PG&E personnel who first arrived on scene were neither trained nor
equipped to close the valves. The flow of gas was not stopped until 9
hours, 10 minutes after the puncture. As a result of this 1981
investigation, NTSB issued the following safety recommendation to PG&E:
Train and equip company personnel who respond to emergency
conditions in the operation of emergency shutdown valves. (P-
82-1)
On June 21, 1982, PG&E responded that special attention was being
directed to training personnel about the location and the operation of
emergency shutdown valves, and that additional valve keys were being
provided to crews who could be called in an emergency. Safety
Recommendation P-82-1 was subsequently classified ``Closed--Acceptable
Action.''
More recently, since 2000, the NTSB has investigated two other
natural gas transmission pipeline accidents: (1) the rupture of an El
Paso Natural Gas Company pipeline on August 19, 2000, near Carlsbad,
New Mexico, and (2) the rupture of a Florida Gas Transmission Company
pipeline in Palm City, Florida, on May 4, 2009. The gas flow in the El
Paso pipeline in Carlsbad was stopped in 55 minutes, and the gas flow
in the Florida Gas pipeline in Palm City was stopped in 2 hours.
Question 6. Is the delay in length of time for shutting off the gas
following a leak or explosion a pervasive problem throughout the
industry? If so, how would the presence of automatic or remote-
controlled shutoff valves minimize ensuing damage?
Answer. The NTSB believes that the delay in the shutoff of the gas
flow following the failure of natural gas transmission pipeline is a
pervasive problem. In the San Bruno public hearing, it was stated that
the use of automatic shut-off valves (ASVs) or remote control valves
(RCVs) would have reduced the shutdown time by approximately 1 hour,
thus reducing the time the fire burned and the severity of the
accident.
For 40 years, the NTSB has advocated for rapid shutdown of natural
gas pipelines during an accident. In 1971, the NTSB issued safety
recommendation (P-71-1) for the development of standards for the rapid
shutdown of failed natural gas pipelines. In 1991, the NTSB recommended
that the Research and Special Programs Administration (RSPA, the
predecessor to PHMSA) expedite requirements for installing ASVs or RSVs
on high pressure pipelines in urban and environmentally sensitive
areas.
In 1995, the NTSB recommended that RSPA expedite requirements for
the installation of ASVs or RCVs to help prevent the severity of
accidents. In San Bruno, the NTSB believes that ASVs or RCVs on Line
132 would have mitigated the severity of the ensuing fire and property
destruction. It also would have allowed first responders the
opportunity to access to scene sooner to begin their search and
recovery efforts.
Title 49 Code of Federal Regulations (CFR) 192.179 prescribes the
spacing of valves on a transmission line based on its class location.
The regulations, however, do not require a response time to isolate a
ruptured gas line, nor do they require the use of ASVs or RCVs. The
regulations give the operator discretion to decide whether ASVs or RCVs
are needed in HCAs as long as they consider the factors listed in 49
CFR 192.935. There is little incentive for an operator to perform an
objective risk analysis as to usage of ASVs or RCVs.
______
Response to Written Questions Submitted by Hon. Frank R. Lautenberg to
Nick Stavropoulos
Question 1. Several of the deficiencies revealed by the recent
National Transportation Safety Board report were also factors in a
previous explosion of a PG&E gas pipeline that occurred in 2008 in
Rancho Cordova, California. Like San Bruno, the Rancho Cordova accident
also involved a pipeline that did not meet specifications at the time
of installation, inaccurate record-keeping that failed to detect the
deficiencies in the pipeline, and an inadequate emergency response that
caused an unnecessary delay in stopping the flow of gas. Correcting
some of these deficiencies back in 2008, particularly the poor record-
keeping, could have prevented the San Bruno explosion and saved 8
lives, numerous injuries, and many homes.
At the hearing, I asked why deficiencies from the 2008 explosion in
Rancho Cordova were not corrected prior to the 2010 San Bruno
explosion. You responded that you would need to take a further look
into that situation. Your response would be appreciated.
Answer. The deficiencies identified in connection with Rancho
Cordova were corrected prior to the San Bruno explosion. They were,
however, unrelated to the causes of the San Bruno rupture, and
unfortunately did not prevent the San Bruno tragedy.
I will briefly cover the three main deficiencies that led to the
2008 Rancho Cordova explosion.
Use of Packing Pipe
The problem in Rancho Cordova occurred when an employee, in
violation of PG&E's written policies and procedures, used a short piece
of plastic packing pipe (i.e., pieces of pipe used to hold the package
in place) instead of approved gas pipe. PG&E's procedures require that
employees only use approved pipe (distribution as well as
transmission), and, to ensure compliance, that employees document
information from the print line on the pipe, such as the manufacturing
code and date.
In the case of Rancho Cordova, the unapproved pipe had no
manufacturer print line. Had the installer followed PG&E's procedures,
he would have discovered his mistake and would not have installed the
packing pipe. To prevent a recurrence of this type of error, PG&E
issued a bulletin to all gas construction employees and followed this
with company-wide presentations reinforcing the importance of following
PG&E's procedures. PG&E also investigated how pipe not intended for gas
service got on the employee's truck. PG&E determined that it was pipe
used as packing material by the manufacturer and that 16 of PG&E's 17
divisions had a practice of destroying all such packing pipe, but one
division kept it and used it to mark the location of gas lines. PG&E
implemented a company-wide policy of destroying packing pipe to ensure
that no employee mistakenly used it again.
For the one division that had not discarded the packing pipe, PG&E
identified all repairs using pipe of the same diameter during a six-
year period and excavated those sites to ensure that no packing pipe
had been installed. PG&E confirmed that the Rancho Cordova repair was
the only repair in which packing pipe had mistakenly been used.
As an extra precaution, PG&E also identified all repairs during
that period in which the same diameter pipe had been used throughout
PG&E's service territory and leak surveyed the repair locations. PG&E
excavated each site where a leak was found. PG&E again found no repairs
in which the packing pipe had been used.
Transmission lines are not made of plastic and were never shipped
using similar pipe as packing material. The use of unmarked plastic
pipe is unrelated to the events that led to the San Bruno tragedy.
Record Keeping
The issue in Rancho Cordova was not inaccurate record-keeping that
failed to detect deficiencies, but false information on a record.
PG&E's policies and procedures require pipe to be used to distribute
gas be pressure tested at 100 psi or more for at least five minutes.
The employee who performed the faulty repair did not document that he
performed the required pressure test. When his supervisor reviewed the
form, rather than require the employee to go back to the site and
perform the proper pressure test, the supervisor altered the form. PG&E
conducted a thorough investigation of the incident and terminated the
employment of that supervisor. PG&E also made a company-wide
presentation reinforcing the importance of following PG&E's procedures,
including record-keeping procedures. However, the underlying causes and
the corrective measures PG&E took in response to the Rancho Cordova
accident had no relation to the causes of the San Bruno tragedy.
Emergency Response
The issue in Rancho Cordova was not the time it took to shut off
the gas, but rather the time it took for a crew to arrive on site to
repair the leak after it had been located by a PG&E Gas Service
Representative. Two PG&E supervisors failed to adhere to PG&E's
procedures and allowed an unreasonable delay in PG&E's response to the
leak. This was exacerbated by an over-turned big-rig that created a
major traffic jam, as well as a mechanical problem on a PG&E vehicle.
PG&E took three measures in response. First, PG&E thoroughly
investigated the incident and terminated the employment of the two
supervisors. Second, PG&E made a company-wide presentation on Rancho
Cordova that reinforced the importance of following PG&E's procedures.
Third, PG&E implemented new dispatch and crew tracking procedures to
better track the location of crews to ensure prompt responses to leaks.
In the case of the San Bruno explosion, there was no report of a
gas leak or odor prior to the explosion. The corrective measures PG&E
took in response to the Rancho Cordova accident thus had no ability to
prevent the San Bruno tragedy.
Question 2. Did PG&E use any kind of quality control measures when
the pipe was installed at segment 180 of line 132--the segment that
caused the San Bruno explosion?
Answer. The relocation work in 1956 on Line 132 for what would
become segment 180 was designed and constructed to meet ASA B31.8, the
operative industry standard in 1956. The welders on the project would
have been qualified before being allowed to work on the project.
Question 2a. If so, how is PG&E reforming its practices to ensure
that newly installed pipelines are subjected to more rigorous quality
control, and that records are verified for existing pipelines?
Answer. PG&E is making changes to the way it does business so that
all field work conducted for both the electric and gas operations is
consistent with PG&E standards and meets or exceeds regulatory
requirements. The Company will also ensure that appropriate corrective
action mechanisms are in place and that there is transparency for all
findings.
Under 49 CFR Part 192, newly installed pipelines are subject to
rigorous design, construction, inspection and testing requirements,
particularly when compared to industry standards in place in 1956.
Subpart E of Part 192 establishes enhanced requirements for inspections
of welds, far more rigorous than the industry standard in 1956. In
addition, PG&E is performing an exhaustive review of its pipeline
records to confirm the maximum allowable operating pressure (MAOP).
PG&E has retrieved and scanned more than 2.3 million paper documents
going back more than 50 years to validate the MAOP of all pipelines in
Class 3 and Class 4 locations and Class 1 and Class 2 High Consequence
Areas. This involves a structured process employing qualified
engineering companies and multiple stages of Quality Control and
Quality Assurance performed by an independent third party vendor.
As of November 2011, PG&E has validated the MAOP for more than
1,500 miles of Class 3 and Class 4 locations and Class 1 and Class 2
High Consequence Area pipelines, including more than 750 miles of high-
priority pipelines without records of prior pressure tests. After
completing this validation effort for those areas, PG&E will undertake
a similar review of its records for the remainder of the transmission
system.
PG&E is also enhancing the safety of its new and existing
transmission pipelines through an aggressive program to pressure test
or replace all transmission pipelines for which PG&E does not have a
record of a prior pressure test. This year we have completed over 150
miles of hydrostatic pressure tests. This will help ensure that the
pipelines can safely operate at their approved MAOP.
Question 3. How many miles of PG&E's pipelines have inadequate
records? What percentage of these particular pipelines or segments fall
under High Consequence Areas?
Answer. We have confirmed pressure test records for approximately
95 percent or more of transmission pipeline segments installed since
July 1970 in Class 3 and Class 4 locations and Class 1 and Class 2 High
Consequence Areas (collectively referred to as HCAs for purposes of
this answer). We have also confirmed that we have pressure test records
for approximately 73 percent of all HCA pipeline segments. While we
have not completed our ongoing records review, but preliminary
estimates indicate that approximately 60 percent of non-HCA pipelines
have been pressure tested. These percentages will be confirmed by our
records review, which will be completed by January 31, 2012 for HCA
pipeline segments and by early 2013 for non-HCA pipeline segments.
To the extent you are asking whether we have adequate records to
confirm the MAOP for HCA or non-HCA pipeline segments, PG&E is in the
midst of a review of its relevant records to confirm the MAOP for all
transmission lines. Consistent with the recommendation of the National
Transportation Safety Board, the first phase of our effort has been to
focus on HCA segments for which PG&E has been unable to locate pressure
test records. PG&E has confirmed the MAOP for those HCA pipeline
segments that did not previously undergo a pressure test. We anticipate
completing this MAOP review for the remaining HCA areas (i.e., the
pipeline segments for which PG&E has pressure test records) by January
31, 2012.
We have not yet completed our review of the non-HCA Class 1 and
Class 2 areas, so we are unable to provide a percentage of those
segments for which we may be missing key records. That effort has
begun, and will be completed by early 2013.
For any segments where we are unable to find necessary records to
support the MAOP, PG&E has and will continue to perform excavations to
verify the critical pipeline system information, reduce pressure,
perform a hydrostatic test, or take other appropriate action, such as
replacing the pipeline segment in question.
Question 4. What efforts are being undertaken to assemble missing
or inadequate information and when do you anticipate that work will be
completed?
Answer. PG&E is in the midst of a comprehensive review of existing
records. We have over three hundred employees or contractors dedicated
to this effort. To date, we have completed the following work:
Retrieved and scanned more than 2.3 million paper documents
going back more than 50 years to validate the MAOP of all
pipelines in Class 3 and Class 4 locations and Class 1 and
Class 2 High Consequence Areas (HCAs)
Verified pressure test documentation for more than 1,150
miles of HCA pipeline.
Validated the MAOP for more than 1,500 miles of HCA
pipelines, including more than 750 miles of high-priority
pipelines without prior pressure tests.
We are also in the process of completing the following efforts:
Collecting and verifying pipeline pressure tests, as-built
construction drawings and relevant documents to validate the
MAOP of remaining non-HCA pipelines and respective components.
PG&E anticipates completing this validation effort for over
6,700 miles of pipelines (both transmission and distribution)
operating above 60 psig by early 2013.
Continuing to excavate and inspect pipe segments within the
transmission system to verify pipe specifications and confirm
pipeline integrity as part of the MAOP validation effort. This
work will be completed by early 2013, as it supports the
records validation discussed above.
Question 4a. When does PG&E expect to complete a comprehensive
review and revision of its integrity management program, including its
risk assessment protocols?
Answer. Integrity management is a critical part of a public
utility's responsibility, and PG&E is committed to a complete review
and upgrade of its Integrity Management Program to ensure the integrity
of our gas pipeline network. To that end, the Company is undertaking
several initiatives to improve its integrity management program and
supporting systems. We expect a comprehensive review to be complete in
the first quarter of 2012, and the initiatives are presently planned to
be completed in 2012 as well.
Some of our initiatives to improve integrity management are:
Using outside experts to conduct a complete review of the
entire Gas Transmission Integrity Management Program (TIMP) and
procedures.
Benchmarking current TIMP against industry leaders.
Once the benchmarking is complete, PG&E will develop an
implementation plan for the future state of PG&E's TIMP,
including a scope and schedule for the selected industry best
practices and enhancement initiatives.
Question 5. As it took PG&E 95 minutes to stop the flow of gas and
isolate the rupture site following the accident in San Bruno, what is
PG&E doing to reform its emergency response protocols to prevent such
delays in responding to a future pipeline leak or rupture?
Answer. PG&E is updating emergency response plans to reflect
recommendations and current best practices. We are also proposing to
expand PG&E's use of automated gas transmission pipeline system
isolation valves through our Valve Automation Program included as part
of our Pipeline Safety Enhancement Plan filed with the California
Public Utilities Commission in August. This plan proposes installing
over 220 additional automated valves on large-diameter, high-pressure
pipelines in heavily populated areas.
I have separated the actions the Company is taking into three
categories: (a) Emergency Response, (b) Emergency Training and
Outreach, and (c) Gas Operations and Gas Control.
Emergency Response: With respect to emergency response protocols,
upon completion of the initiatives described below, the Company will
have a comprehensive and up-to-date emergency response plan that will
integrate and standardize emergency response across the Company.
Completed
Benchmarking--Contacted approximately 25 other utilities and
first responders to identify best practices and industry
standards.
Incorporated results into gas emergency response plan
updates and improvements.
Organized into three areas: (1) Prevention (2)
Preparedness (3) Recovery.
Clearly defined roles and responsibilities.
Defined emergency scenarios with three incident-severity
levels and developed appropriate response plans.
In Process
Implementing new, fully functioning mobile command centers
to be used in emergencies. Four of six centers have been
completed; an additional two will be completed by 2012.
An assessment is underway to establish a distribution
control center that will be co-located with the transmission
gas control center and gas dispatch, which will improve data
and information sharing for assessing potential pipeline
incidents and improving emergency response.
Planned (Implementation Has Not Begun)
Restructure all division, regional and Company emergency
plans to incorporate industry best practices.
Emergency Training and Outreach: PG&E is working with external
partners such as first responders and public safety officials to
enhance training for emergency preparedness and response. Enhanced
emergency prevention, preparedness and response programs consist of
education programs for first responders, contractors, infrastructure
departments, community members, school children, and other
stakeholders.
Completed
Launched PG&E first responder website portal.
Provided maps, GIS data, and other information to first
responders.
Providing free, regionally-based training to fire
departments and agencies located within PG&E's service area.
Developed an improved process for incoming emergency calls
to efficiently dispatch Gas Maintenance and Construction
personnel, Gas Service Representatives and other first
responders to the scene of a natural gas emergency.
Gas Operations and Gas Control: The San Bruno tragedy also
underscored the need for a comprehensive review of the Gas Operations
and Gas Control business areas. PG&E has launched a number of
initiatives designed to improve the operations of its gas pipeline
network by focusing on infrastructure, operations, and processes. The
objective is to bring best practices of the industry to PG&E's Gas
Operations and Gas Control.
In Process
Conducting condition assessments on 24 gas transmission
stations this year.
Identifying improvements within each station to bring each
station up to a new level of instrumentation, automation,
and control.
Engineering in progress for major improvements to at least
four stations.
Establishing detailed procedures for system-wide operations.
Retained outside consultants and experts in operational
assessment, human factor analysis, alarm management, and
operator training to make recommendations for SCADA and
control room procedure improvements.
Developing and implementing gas control operator practices
and updated clearances processes and training.
Working to build a state-of-the-art Distribution Control
System utilizing advanced technology and protections.
Developing and implementing a comprehensive unified
controls framework with best accepted practices in the
industry.
Updating SCADA procedures to ensure that manually-input
information is accurate and that clear instructions on pipeline
segment shutdowns are available during emergencies.
Conducting training for alarm management, emergency response
and SCADA change management.
Upgrading alarm management software systems.
Question 6. Although there were no Federal regulations requiring
hydrostatic pressure testing of new pipelines until 1970, a voluntary
national consensus standard was established by ASME in 1955 calling for
hydrostatic pressure testing of newly constructed pipelines. Why did
PG&E not follow the ASME standard for hydrostatic pressure testing when
it installed this pipeline?
Answer. The relocation work in 1956 on Line 132 for what would
become segment 180 was designed and constructed to meet ASA B31.8 (the
predecessor to ASME B31.8). PG&E has pressure test reports for lines
constructed in 1956 both before and after Segment 180, with forms that
specifically refer to ASA B31.1.1.8 hydro test procedures, but PG&E has
been unable to locate records that show whether Segment 180 was
pressure tested.
Question 6a. In light of the NTSB's recommendations, is PG&E now
performing pressure tests on its pre-1970 pipelines?
Answer. Yes. PG&E has pressure tested approximately 150 miles of
pre-1970 transmission pipelines in 2011. Our Pipeline Safety
Enhancement Plan filed with the CPUC in August 2011 proposes pressure
testing all transmission pipelines that have not previously been
pressure tested.
Question 6b. When PG&E completes the pressure tests it is planning
to conduct through 2014, what percentage of PG&E's pre-1970 pipelines
will have been tested?
Answer. PG&E operates 5,786 miles (2010 PHMSA 7100 Report) of gas
transmission and gas gathering pipeline, 3,862 miles (67 percent) of
which was installed prior to 1970. (References elsewhere in these
answers to approximately 6,700 miles of pipelines are discussions of
all pipelines operating above 60 psig, regardless of whether it is
transmission or distribution pipe.)
By the end of 2014, PG&E currently forecasts a minimum of 1,068
miles (27 percent) of the pre-1970 transmission pipelines will have had
prior pressure tests or been pressure tested to 49 CFR 192, Subpart J
testing requirements as part of the Pipeline Safety Enhancement Plan.
In addition, PG&E is currently proposing to replace 176 miles of pre-
1970 pipeline by 2014 as part of our Pipeline Safety Enhancement Plan.
Question 7. Although automatic or remote controlled shutoff valves
are not mandated, existing Federal pipeline integrity management
regulations require that, ``If an operator determines, based on a risk
analysis, that an automatic or remote-controlled shutoff valve would be
an efficient means of adding protection to a high consequence area in
the event of a gas release, an operator must install the ASV or RCV.''
Did PG&E ever perform a risk analysis for line 132?
Answer. Yes
Question 7a. If so, did the risk analysis indicate that adding an
automatic or remote-controlled shutoff valve would be an efficient
means of adding protection to this high consequence area? If not, why
not?
Answer. The analysis concluded that adding automatic or remote
shut-off valves was not recommended. The explanation was as follows:
``There are 9 Mainline Valves at [specific locations that] can
be used to isolate the pipeline sections in between in case of
emergency. The valve spacings are in compliance with class
location requirements.
Note: A review of the environment that the line operates in
reveals that there are no unique conditions or characteristics
which may lead one to believe that the length of time necessary
to respond to a rupture will increase the likelihood of harm to
population around the pipeline (such as due to large structures
weakened by exposure to heat) or increase the likelihood of a
failure due to areas of unique geologic features which may
increase the likelihood of failure. In addition, because:
Most of the damage to property and risk to human safety
occurs immediately or shortly thereafter,
The immediate energy release has little or nothing to do
with the location of vales,
The rate of release from a rupture decreases exponentially,
A lead or rupture may not immediately trigger a ASV,
The leak will continue for a long period of time regardless
of the valve location.
Additional ASV's and RCV's are not recommended. . . .''
Question 8. Is PG&E currently working to retrofit pre-1994
pipelines for in-line inspection? When that is complete, what
percentage of PG&E's pipelines will be able to accommodate in-line
inspection?
Answer. Yes. PG&E has been retrofitting gas transmission pipelines
to accommodate ILl inspection tools since 2000. As of December 2010,
PG&E had retrofitted 988 miles of pipeline to accommodate ILI tools,
which represents 17 percent of our gas transmission pipelines.
PG&E is planning to retrofit all pipelines operating above 30
percent SMYS, and many below 30 percent SMYS, to accommodate
inspections using current intelligent ``pigging'' technologies. PG&E
forecasts the total pipeline miles retrofitted for ILI to be
approximately 1,483 miles (about 26 percent) by the end of 2014. Where
ILI is not feasible in pipelines operating below 30 percent SMYS, PG&E
will continue pressure testing, pipe replacement, or other actions to
assure the margin of safety is not compromised.
Question 9. On October 25, 2011, the San Francisco Chronicle
reported that a PG&E transmission line (which was laid in the 1950s)
ruptured during a pressure test, creating a crater in an alfalfa field
near Weedpatch, CA. If a pressure test had not been performed, is there
a risk this pipeline could have ruptured in the future, such as when
the pressure in the pipeline were increased to meet winter demand?
Answer. It is highly unlikely Line 300B would have ruptured at the
location of the failed pressure test under normal operating conditions.
Line 300B has an MAOP of 757 psig. The pipeline would not be operated
above this pressure. The section of Line 300B failed during the
pressure test at 998 psig, or 241 psig above the MAOP. The pipeline was
at 95 percent of Specified Minimum Yield Strength at the point of
rupture. There was no evidence that the anomaly responsible for the
hydrostatic test failure was growing while it was in service, so it is
likely that this anomaly could have lasted indefinitely in the pipe at
pressures up to the MAOP of 757 psig.
Question 9a. In the same article, you said regarding the test
failure: ``This is the first one--but that's what these tests are
intended to do, identify areas of weakness.'' Has PG&E identified other
areas where pipelines are expected to be weak or contain flaws?
Answer. PG&E has focused its initial pressure testing on 152 miles
of pipeline that had not been tested previously and had characteristics
similar to the segment that failed in San Bruno. The purpose of the
pressure testing program is to identify and remediate pipeline flaws
found during the testing. PG&E's record search has not identified any
areas where the pipeline is expected to be weak or contain flaws.
PG&E also notes it is in the final stages of a multi-year plan to
In-Line Inspect (ILI) the portion of L300B in Bakersfield which
experienced the recent hydrostatic test rupture. Over the past few
years, this portion of Line 300B and the parallel pipeline Line 300A
have been physically upgraded to accommodate ILI tools and the ILI
inspections are scheduled to occur in 2012.
Question 9b. Was this rupture located in a ``High Consequence
Area?''
Answer. No, the rupture was not in a High Consequence Area.
Question 9c. How many miles of your pipelines that lie outside of
High Consequence Areas have not been subjected to pressure tests? What
is your schedule for testing these pipelines?
Answer. PG&E has 1,027 miles of HCA pipelines (using Method 2, 49
CFR Part 192 Subpart 0) and operates 4,727 miles of gas transmission
and gas gathering pipelines outside of HCA (2010 PHMSA 7100 Report).
Preliminary estimates indicate that approximately 60 percent of these
non-HCA pipelines have already been pressure tested. This information
is in the process of being validated as part of our MAOP validation
project.
PG&E has not completed its plan for pressure testing all untested
HCA and non HCA pipelines. PG&E estimates that approximately 2,200
miles will not have previously been pressure tested and will require
testing. As part of our Pipeline Safety Enhancement Plan, we propose to
pressure test approximately 780 miles of pipe between 2011 and 2014.
Question 10. On November 2, 2011, the San Francisco Chronicle
reported that the aforementioned Bakersfield pipeline was discovered to
have a seam flaw in 1974, the same kind of defect that caused the San
Bruno explosion. However, the article reported that PG&E vouched for
the pipeline's safety by using an inspection method used mainly for
finding corrosion problems. Was the flaw found in 1974 ever repaired
before the failed test conducted last week?
Answer. In 1974 PG&E had a rupture during a hydrostatic test of a
long seam weld on a 34 inch diameter section of Line 300B near Harris
Ranch, about 90 miles north of the section that ruptured in
Bakersfield. The section ruptured at approximately 1040 psig. This was
200 psig above its maximum allowable operating pressure, and 84 percent
of the Specified Minimum Yield Strength. The failed section of pipe
from the 1974 test was replaced, and the pipeline was successfully
retested with an 8 hour hydrostatic test at over 1100 psig. Our records
indicate that subsequent examination revealed that the cause of the
rupture was inadequate penetration on the long seam weld at that spot.
Question 10a. If a seam flaw was found, what is the justification
for confirming the pipeline's safety through use of a corrosion test
and not a test for bad welding?
Answer. The determination of an assessment method for a particular
HCA segment is based upon the threats identified with respect to that
particular segment. In cases where a pipeline is hundreds of miles
long, such as Lines 300A and 300B, different segments of the pipeline
are built at different times, sometimes in different years, using
different manufacturing methods and will operate at different pressures
and under different conditions.
As discussed above, the flaw discovered in 1974 was the rupture of
a longitudinal weld during a hydrostatic test. By the nature of the
test, the section was subjected to pressures that far exceeded its
expected operating pressure in order to identify potential defects
caused during the manufacturing or construction that could adversely
affect the pipeline. In this instance, the 1974 hydrostatic test worked
as intended and identified a defect that was removed from the pipeline.
The section of Line 300B was then re-tested and passed.
A single incident at one location does not necessarily have
implications for the entire pipeline and does not require an assessment
method designed to identify suspect welds. PHMSA Frequently Asked
Question 219 provides in part that ``any manufacturing and construction
defects that survive the Subpart J pressure test are considered to be
stable and not subject to failure, unless other threats adversely
affect the stability of the residual manufacturing and construction
defects.'' Here, the segment where the pipeline ruptured was not in a
``High Consequence Area'' and was not required to be assessed. 49 CFR
192.917 (e)(4) sets forth special consideration for the identification
of threats on low frequency ERW pipe, but the longitudinal seam that
ruptured on Line 300B was manufactured using Double Submerged Arc
Welded (DSAW) method. In contrast to ERW pipe, DSAW was, and still is,
considered one of if not the most reliable seam manufacturing
technologies.
Question 10b. Have any other pipelines been designated as safe
through a corrosion test where previous seam flaws were detected? If
so, how many, and where are these pipelines located?
Answer. PG&E is in the midst of several major initiatives to
enhance the safety of our transmission system, including major efforts
to improve our records, to validate the maximum allowable operating
pressure of all of our transmission lines and to pressure test all of
our transmission pipelines that have not already been pressure tested.
If PG&E finds a seam defect on an HCA segment that can no longer be
considered stable we will take steps to confirm the integrity of the
longitudinal seam.
______
Response to Written Questions Submitted by Hon. Barbara Boxer to
Donald F. Santa, Jr.
Question 1. At the hearing, I asked you whether INGAA supported a
repeal of the ``grandfather clause,'' which exempts pre-1970 pipelines
from hydrostatic pressure testing to determine maximum allowable
operating pressure. You replied that INGAA would support doing away
with the grandfather clause in high consequence areas.
However, on October 25, the San Francisco Chronicle reported that a
PG&E transmission line (which was laid in the 1950s) ruptured during a
pressure test, creating a crater in an alfalfa field near Weedpatch,
CA. Commenting on repairing the damage, PG&E's Executive Vice President
for Gas Operations, Nick Stavropoulos, said, ``It's typically not an
extensive process. Here, access should not be an issue, so it shouldn't
take very long.''
Question 1a. With this in mind, can you elaborate on why INGAA does
not support greater regulations that would enhance the safety for all
people, regardless of whether they live within or outside of a high
consequence area?
Answer. INGAA believes that the focus of all pipeline regulations,
including those regarding verification of pipe material strength,
should be on protecting people first and foremost. Thus the focus on
populated areas, or high consequence areas. We think that at least
initially, regulations regarding re-verification of maximum allowable
operating pressure (MAOP) for pipelines constructed before 1970 should
be focused on these high consequence areas. As Senator Boxer stated in
the hearing on October 18th, ``to me what's really important is go
after those high-risk areas first.'' We agree. Given the technical
difficulties of undertaking this effort, an initial focus on high-risk
pipe segments located in populated areas makes the most sense and
provides the best improvement in safety over the next few years.
Question 1b. In light of Mr. Stavropoulos' comments, isn't it true
that it would not be much of an added burden to perform pressure tests
in non-high consequence areas in addition to high-consequence areas?
Answer. We do not think Mr. Stavropoulos intended for his remarks
to suggest that MAOP re-verification of all pipelines in the United
States constructed before 1970 is ``easy'' or ``shouldn't take very
long.'' Our united opinion is that such an effort, extrapolated across
all gas transmission mileage rather than focusing initially on pre-1970
high consequence areas, would be a massively disruptive effort that
would not be logical or manageable.
______
Response to Written Questions Submitted by Hon. Barbara Boxer to
Christina Sames
Question 1. At the hearing, I asked you whether AGA supported a
repeal of the ``grandfather clause,'' which exempts pre-1970 pipelines
from hydrostatic pressure testing to determine maximum allowable
operating pressure. You replied that AGA would support doing away with
the grandfather clause, with certain caveats. What are these caveats?
Why does AGA not support regulations that would enhance the safety of
all people, regardless of where they live?
Answer. AGA and its member companies are committed to safety. The
largest portion of AGA's resources is dedicated to supporting
operations, safety and engineering. AGA maintains 14 technical
committees, a Board level safety committee, a Safety Implementation
Task Force, three Best Practices programs, is secretariat for the
national and the international Fuel Gas Codes and forms task groups
whenever additional support is needed. The responses contained herein
are supported by widely accepted technical standards and practices
regarding how pipelines and other industries effectively manage risks.
All risks are relative and resources have to be thoughtfully applied to
eliminate or manage the risks.
AGA supports eliminating the grandfather clause as it is currently
written in 49 CFR 192.619(c) for transmission pipelines that represent
the largest risk as defined by S.275, the Pipeline Transportation
Safety Improvement Act of 2011. AGA supports amending regulations to
require additional integrity management requirements for pipelines that
operate in a high consequence area (HCA) above 30 percent SMYS (stress
levels) and do not have a post construction pressure test, in-line
inspection or acceptable alternative inspections.
Since its inception in 1970, Federal pipeline safety regulations
have implemented a tiered risk based design and operational philosophy
that is based upon population density. AGA believes this risk-based
approach, founded upon sound engineering, is consistent with safety for
all people. And AGA will continue its efforts to enhance safety for all
people. AGA has petitioned PHMSA to adopt the latest standards for
installing natural gas plastic pipe in distribution systems, supported
the expedited implementation of the control room management regulation,
and seeks improvement to transmission integrity management. I have
included in our response a copy of ``AGA Commitment to Enhance Safety''
that was approved by the AGA Board of Directors. I have also included
the document ``AGA Actions Supporting the Secretary's Call to Action
and NTSB Recommendations'' that identifies actions AGA and its members
have taken in response to Secretary LaHood's Call to Action on Pipeline
Safety.
Question 2. On October 25, the San Francisco Chronicle reported
that a PG&E transmission line (which was laid in the 1950s) ruptured
during a pressure test, creating a crater in an alfalfa field near
Weedpatch, CA. Commenting on repairing the damage, PG&E's Executive
Vice President for Gas Operations, Nick Stavropoulos, said, ``It's
typically not an extensive process. Here, access should not be an
issue, so it shouldn't take very long.'' In light of Mr. Stavropoulos'
comments, isn't it true that it would not be much of an added burden to
perform pressure tests in non-high consequence areas in addition to
high-consequence areas?
Answer. AGA does not know the full context of the statement by Mr.
Stavropoulos, therefore our answer is not a direct reflection on his
statement. Most pipelines do not rupture during a pressure test and it
is relatively easy to effect repairs if there is a failure. However,
the preparation to pressure test transmission pipeline operated by
local distribution companies can be very complicated.
Many rural transmission pipelines traverse long distances, and are
constructed in parallel (looped) configurations that allow supply to be
diverted from one line to another. Many of the intrastate transmission
pipelines operated by local distribution companies, on the other hand,
typically cover shorter distances, are primarily located in more
densely populated areas, are constructed of smaller diameter pipe that
operates at lower pressures and stress levels, are seldom constructed
in parallel (looped) configurations and are often the single source of
supply to a city, town or industrial facility.
Local distribution companies operate pipelines that will have to be
taken out of service to be pressure tested. A significant portion of
this mileage is pipe that is the single source of supply (single source
feed) that is relied upon exclusively to serve cities, villages and
large industrial customers. Without the benefit of an alternate supply
source, utilities will need to serve customers with temporary gas
supplies, such as portable compressed natural gas trailers or temporary
liquid natural gas. In some cases, temporary supplies will not be
adequate and new pipelines will have to be built before the existing
pipeline can be tested.
AGA appreciated the opportunity to testify on the important issue
of pipeline safety. If you need more information please feel free to
contact me.