```

[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

                  U.S. GOVERNMENT PRINTING OFFICE
74-986                    WASHINGTON : 2012
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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'')  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.

                                  
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