[Senate Hearing 108-1034]
[From the U.S. Government Publishing Office]


                                                      S. Hrg. 108-1034

                            PIPELINE SAFETY

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

                                 HEARING

                               BEFORE THE

                         COMMITTEE ON COMMERCE,
                      SCIENCE, AND TRANSPORTATION
                          UNITED STATES SENATE

                      ONE HUNDRED EIGHTH CONGRESS

                             SECOND SESSION

                               __________

                             JUNE 15, 2004

                               __________

    Printed for the use of the Committee on Commerce, Science, and 
                             Transportation
                             
                             
[GRAPHIC NOT AVAILABLE IN TIFF FORMAT]   



                      U.S. GOVERNMENT PUBLISHING OFFICE                    
27-960 PDF                     WASHINGTON : 2018                     
          
----------------------------------------------------------------------------------------
For sale by the Superintendent of Documents, U.S. Government Publishing Office, 
http://bookstore.gpo.gov. For more information, contact the GPO Customer Contact Center, 
U.S. Government Publishing Office. Phone 202-512-1800, or 866-512-1800 (toll-free). 
E-mail, [email protected]. 




       SENATE COMMITTEE ON COMMERCE, SCIENCE, AND TRANSPORTATION

                      ONE HUNDRED EIGHTH CONGRESS

                             SECOND SESSION

                     JOHN McCAIN, Arizona, Chairman
TED STEVENS, Alaska                  ERNEST F. HOLLINGS, South 
CONRAD BURNS, Montana                    Carolina, Ranking
TRENT LOTT, Mississippi              DANIEL K. INOUYE, Hawaii
KAY BAILEY HUTCHISON, Texas          JOHN D. ROCKEFELLER IV, West 
OLYMPIA J. SNOWE, Maine                  Virginia
SAM BROWNBACK, Kansas                JOHN F. KERRY, Massachusetts
GORDON H. SMITH, Oregon              JOHN B. BREAUX, Louisiana
PETER G. FITZGERALD, Illinois        BYRON L. DORGAN, North Dakota
JOHN ENSIGN, Nevada                  RON WYDEN, Oregon
GEORGE ALLEN, Virginia               BARBARA BOXER, California
JOHN E. SUNUNU, New Hampshire        BILL NELSON, Florida
                                     MARIA CANTWELL, Washington
                                     FRANK R. LAUTENBERG, New Jersey
      Jeanne Bumpus, Republican Staff Director and General Counsel
             Robert W. Chamberlin, Republican Chief Counsel
      Kevin D. Kayes, Democratic Staff Director and Chief Counsel
                Gregg Elias, Democratic General Counsel
                            
                            
                            C O N T E N T S

                              ----------                              
                                                                   Page
Hearing held on June 15, 2004....................................     1
Statement of Senator Cantwell....................................    50
    Prepared statement...........................................    53
Statement of Senator Lautenberg..................................     2
Statement of Senator McCain......................................     1
    Prepared statement...........................................     2

                               Witnesses

Bonasso, Hon. Samuel G., Deputy Administrator, Research and 
  Special Programs Administration, U.S. Department of 
  Transportation; accompanied by Ms. Stacey Gerard, Associate 
  Administrator for Pipeline Safety..............................     4
    Prepared statement...........................................     5
Connaughton, Hon. James L., Chairman, Council on Environmental 
  Quality........................................................    11
    Prepared statement...........................................    13
Mead, Hon. Kenneth M., Inspector General, U.S. Department of 
  Transportation.................................................    14
    Prepared statement...........................................    18
Siggerud, Katherine, Director, Physical Infrastructure Issues, 
  U.S. General Accounting Office.................................    28
    Prepared statement...........................................    31
Spitzer, Hon. Marc, Chairman, Arizona Corporation Commission.....    40
    Prepared statement...........................................    43
Epstein, P.E., Lois N., Senior Engineer, Oil and Gas Industry 
  Specialist, Cook Inlet Keeper..................................    55
    Prepared statement...........................................    57
Murray, Hon. Patty, U.S. Senator from Washington.................    62
    Prepared statement...........................................    64
Pearl, Barry, President and CEO, TEPPCO Partners, L.P., on behalf 
  of the Association of Oil Pipelines and the American Petroleum 
  Institute......................................................    65
    Prepared statement...........................................    68
    Report dated April 2004 entitled ``The Liquid Pipeline 
      Industry in the United States: Where It's Been Where It's 
      Going'' by Richard A. Rabinow..............................    81
    Letter dated May 20, 2004 to Hon. Don Young, Chairman, 
      Committee on Transportation and Instructure, U.S. House of 
      Representatives from Red Cavaney, President and CEO, 
      American Petroleum Institute; Benjamin S. Cooper, Executive 
      Director, Association Oil Pipe Lines; Bert Kalisch, 
      President and CEO, American Public Gas Association; David 
      Parker, President and CEO, American Gas Association and 
      Donald F. Santa, Jr., President, Interstate Natural Gas 
      Association of America.....................................   140
Fischer, Earl, Senior Vice President, Utility Operations, Atmos 
  Energy Corporation, on behalf of the American Gas Association 
  and the American Public Gas Association........................   141
    Prepared statement...........................................   143
Howard, Robert T., Vice President and General Manager, Pipeline 
  Operations, Gas Transmission Northwest Corporation, on behalf 
  of the Interstate Natural Gas Association of America...........   149
    Prepared statement...........................................   151

                                Appendix

Letter dated August 2, 2004 to Hon. John Breaux from Marc 
  Spitzer, Chairman, Arizona Corporation Commission..............   159
Response to written questions submitted by Hon. John Breaux to:
    Samuel G. Bonasso............................................   159
    Hon. Kenneth M. Mead.........................................   161
    Katherine Siggerud...........................................   162
    Hon. Marc Spitzer............................................   163
    Lois N. Epstein..............................................   165
Response to written questions submitted to Barry Pearl by:
    Hon. John McCain.............................................   168
    Hon. John Breaux.............................................   171
Response to written questions submitted to Earl Fischer by:
    Hon. John McCain.............................................   172
    Hon. John Breaux.............................................   176
Response to written questions submitted to Robert T. Howard by:
    Hon. John McCain.............................................   179
    Hon. John Breaux.............................................   180

 
                            PIPELINE SAFETY

                              ----------                              


                         TUESDAY, JUNE 15, 2004

                                       U.S. Senate,
        Committee on Commerce, Science, and Transportation,
                                                    Washington, DC.
    The Committee met, pursuant to notice, at 9:31 a.m. in room 
SR-253, Russell Senate Office Building, Hon. John McCain, 
Chairman of the Committee, presiding.

            OPENING STATEMENT OF HON. JOHN McCAIN, 
                   U.S. SENATOR FROM ARIZONA

    The Chairman. Good morning. It has been 18 months since the 
Pipeline Safety Improvement Act of 2002 became law. That 
legislation, which was spearheaded by the Senate Commerce 
Committee, enacted a number of improvements to pipeline safety, 
including the establishment of an Integrity Management Program 
for gas pipelines, the establishment of qualifications 
standards for pipeline operators, the establishment of a three-
digit/one-call number to reduce digging accidents, and the 
establishment of an interagency working group to streamline the 
issuance of Federal permits needed to perform pipeline repairs.
    The purpose of today's hearing is to understand how the Act 
is working, whether the Office of Pipeline Safety is on 
schedule to meet the Act's implementation requirements, and to 
learn whether Congress needs to do more in this area. Pipelines 
carry most of the natural gas and oil transported in the United 
States and are one of the safest modes of transportation, 
representing less than two/one-hundredths of 1 percent of the 
total number of transportation fatalities on an annual basis, 
yet pipeline accidents, when they do occur, can result in 
significant fatalities, injuries, and damage to the 
environment, as was demonstrated by the accidents in 
Bellingham, Washington, in 1999, and Carlsbad, New Mexico, in 
the year 2000.
    Pipeline ruptures can also affect energy supply. When a 
gasoline pipeline operated by Kinder-Morgan Energy Partners 
ruptured in Tucson last summer and remained out of service for 
approximately 2 weeks, fuel supplies dwindled, and there were 
reports of local price gouging. The Tucson action also 
highlighted the growing problem of encroachment on pipeline 
rights of way. The Tucson ruptured occurred in the vicinity of 
a new housing developing, and several new and, thankfully, 
unoccupied homes were sprayed with gasoline and had to be torn 
down.
    More recently, another Kinder Morgan pipeline ruptured, 
this time in an environmentally sensitive area in California. 
Kinder Morgan has been trying to perform needed repairs on the 
pipeline and relocate it away from the marsh for 3 years, but 
had been unable to obtain necessary environmental permits.
    I hope our witnesses today will discuss the circumstances 
surrounding the accident and whether the work of the 
interagency task force formed under the 2002 Pipeline Act will 
be able to prevent such an accident from happening again.
    By all accounts, the Office of Pipeline Safety has made 
great strides in the past several years in improving its 
performance overseeing pipeline safety. The agency has closed 
over 40 recommendations of the National Transportation Safety 
Board, and implemented most, although not all, of the 
congressional mandates enacted in 1992, 1996, and 2002. I 
commend OPS for the progress that has been made, and look 
forward to your comments about the agency's future challenges.
    [The prepared statement of Senator McCain follows:]

   Prepared Statement of Hon. John McCain, U.S. Senator from Arizona
    Good morning. It has been 18 months since the Pipeline Safety 
Improvement Act of 2002 became law. That legislation, which was 
spearheaded by the Senate Commerce Committee, enacted a number of 
improvements to pipeline safety, including the establishment of an 
integrity management program for gas pipelines; the establishment of 
qualification standards for pipeline operators; the establishment of a 
3-digit ``one-call'' number to reduce digging accidents; and the 
establishment of an interagency working group to streamline the 
issuance of Federal permits needed to perform pipeline repairs.
    The purpose of today's hearing is to understand how the Act is 
working, whether the Office of Pipeline Safety (OPS) is on schedule to 
meet the Act's implementation requirements, and to learn whether 
Congress needs to do more in this area. Pipelines carry most of the 
natural gas and oil transported in the United States, and are one of 
the safest modes of transportation, representing less than 2 one-
hundredths of one percent of the total number of transportation 
fatalities on an annual basis. Yet pipeline accidents, when they do 
occur, can result in significant fatalities, injuries, and damage to 
the environment, as demonstrated by the accidents in Bellingham, 
Washington in 1999 and Carlsbad, New Mexico in the year 2000.
    Pipeline ruptures can also affect energy supply. When a gasoline 
pipeline operated by Kinder Morgan Energy Partners ruptured in Tucson 
last summer and remained out of service for approximately two weeks, 
fuel supplies dwindled and there were reports of local price gouging. 
The Tucson accident also highlighted the growing problem of 
encroachment on pipeline rights-of-way. The Tucson rupture occurred in 
the vicinity of a new housing development and several new--and 
thankfully unoccupied--homes were sprayed with gasoline and had to be 
tom down.
    More recently, another Kinder Morgan pipeline ruptured, this time 
in an environmentally sensitive area in California. Kinder Morgan had 
been trying to perform needed repairs on the pipeline and relocate it 
away from the marsh for 3 years, but had been unable to obtain 
necessary environmental permits. I hope our witnesses today will 
discuss the circumstances surrounding the accident and whether the work 
of the interagency task force formed under the 2002 Pipeline Act will 
be able to prevent such an accident from happening again.
    By all accounts, the Office of Pipeline Safety (OPS) has made great 
strides in the past several years in improving its performance 
overseeing pipeline safety. The agency has closed over 40 
recommendations of the National Transportation Safety Board, and 
implemented most, although not all, of the congressional mandates 
enacted in 1992, 1996, and 2002. I commend O-P-S for the progress that 
has been made and look forward to your comments about the agency's 
future challenges.

    The Chairman. Senator Lautenberg?

            STATEMENT OF HON. FRANK R. LAUTENBERG, 
                  U.S. SENATOR FROM NEW JERSEY

    Senator Lautenberg. Thanks, Mr. Chairman.
    This is an important safety issue, and it seems to get 
little attention unless there's a major accident. Additionally, 
we now have a different consideration than that which we had 
when--in New Jersey, we had a terrible explosion in 1994. We've 
got to pay much more attention to the possibility of a 
terrorist attack on our extensive network of pipeline, which 
cover over two million miles.
    In New Jersey, we experienced a major accident on March 23, 
1994. It was when a 36-inch natural-gas pipeline exploded at a 
factory in Edison, New Jersey, sending gas hundreds of feet 
into the air. Now, fortunately, nobody was killed in that 
accident as a direct result, but almost a hundred people were 
hospitalized, and over 1,500 people had to be evacuated from 
their homes. The fire that ensued ignited roofs over nearby 
apartment buildings, and, once again, we were lucky that no one 
was killed. Now, I do mention the fact that firefighters found 
the soles of their shoes melting from the extreme heat and the 
possibility of this catastrophe were awesome to contemplate.
    Now, following that accident, I introduced a bill called 
the Pipeline Safety Improvement Act of 1994. Mr. Chairman, you 
know that it--around here, it sometimes takes some time to get 
into active structure, but it wasn't until 2002 when Congress 
passed the Comprehensive Pipeline Safety Improvement 
legislation. It took a sustained effort by the Chairman and the 
Ranking Member of this Committee to see it through.
    Now, because of the leadership of Senator McCain and 
Senator Hollings, Congress finally passed the Pipeline Safety 
Improvement Act of 2002. Pipelines play a critical role in the 
intra- and interstate movements of commodities, especially oil 
and gas. Pipelines transport 63 percent of the energy consumed 
in this country and 21 percent of the total annual freight 
tonnage. Now, if our highways and roads are the Nation's 
arteries, then pipelines could be called the capillaries. The 
operation of these privately owned pipelines must be safety-
centered to protect both employees and the public, who may not 
even know when they're at risk. This is especially true when 
pipelines are transporting hazardous or flammable substances.
    Now, states normally have the oversight responsibility. And 
they--as a matter of fact, it's 90 percent of the pipeline 
mileage in this country. But clearly there is an important 
Federal role in maintaining pipeline safety, especially now 
with the threat of terrorism.
    So I look forward to hearing from our witnesses today on 
how the Federal Government can boost pipeline safety and 
security.
    Thanks, Mr. Chairman.
    The Chairman. Thank you very much, Senator Lautenberg.
    Our first panel is the Honorable Samuel Bonasso, who is the 
Acting Administrator of Research and Special Programs at the 
United States Department of Transportation; the Honorable James 
L. Connaughton, who is the Chairman of the Council on 
Environmental Quality; the Honorable Kenneth Mead, Inspector 
General, Department of Transportation; Ms. Kate Siggerud, 
Director of Physical Infrastructure Issues at the General 
Accounting Office; and the Honorable Marc Spitzer, Chairman of 
the Arizona Corporation Commission.
    Mr. Bonasso, we will begin with you, and thank you for 
coming today.

            STATEMENT OF HON. SAMUEL BONASSO, DEPUTY

          ADMINISTRATOR, RESEARCH AND SPECIAL PROGRAMS

       ADMINISTRATION, U.S. DEPARTMENT OF TRANSPORTATION;

               ACCOMPANIED BY MS. STACEY GERARD,

          ASSOCIATE ADMINISTRATOR FOR PIPELINE SAFETY

    Mr. Bonasso. Thank you, Mr. Chairman.
    With me is Stacey Gerard, the Associate Administrator of 
Research and Special Programs, Office of Pipeline Safety.
    Thank you for this opportunity to discuss our strategy and 
our long-term prospects for improving the safety and 
reliability of our Nation's pipeline infrastructure. My 
testimony addresses our responses to mandates in the Pipeline 
Safety Improvement Act of 2002, issues in its implementation, 
and the results of our actions. Our nation, our economy, and 
our way of life depend on the pipeline transportation system.
    Pipelines are the safest, most-efficient way to transport 
the enormous quantities of natural gas and hazardous liquids we 
use each day. The Pipeline Safety Improvement Act of 2002 
challenged RSPA to improve our pipeline safety----
    The Chairman. Could I interrupt you a minute?
    Mr. Bonasso. Yes, sir.
    The Chairman. As opposed to what other methods? In other 
words, you say it's the safest, what are the other methods?
    Mr. Bonasso. Transporting by barge and by rail for this--
rail and truck for this type of commodity. So we have those 
other options.
    The Chairman. Thank you. I wanted that for the record. 
Thank you.
    Mr. Bonasso. All right.
    As I said, we were challenged by the Safety Improvement Act 
to improve our safety program in pipelines. We have responded 
to this challenge with improved regulations, improved 
inspections, and improved enforcement. This is a comprehensive 
and informed plan to identify and manage the risks faced by 
operators in our communities. It has helped us implement new 
regulations, and addresses the majority of tasks required by 
the new law.
    Last year, we completed the second step of our hazardous 
liquid and natural-gas integrity management regulations. These 
regulations are the most significant safety standards 
improvements for pipelines in the last 30 years. We are moving 
further to incorporate improved consensus standards that 
evaluate the adequacy of a pipeline operator's public education 
program and, by the end of the year, will finalize standards 
for operator qualifications. We are improving opportunities for 
communities to understand the importance of pipeline safety and 
to take local action for further pipeline protection. In 
addition, we are beginning a crisis communications initiative 
to improve the process of coordination and information-sharing 
following a pipeline accident.
    With the Common Ground Alliance, we are spinning off 
regional alliances similar to the one in Arizona recently 
championed by the Arizona Corporation Commission. We have also 
petitioned the Federal Communications Commission for a national 
three-digit dialing code to provide a faster, simpler, and more 
efficient one-call system.
    We have a five-year plan for pipeline research and 
development, and a memorandum of understanding with the 
Department of Energy and the National Institute of Standards 
and Technology for Research Planning. This has provided a clear 
vision for the advancement of technology focusing on improving 
pipeline safety.
    As we continue with rigorous integrity management 
inspections of pipeline operators, we expect to discover more 
pipeline defects needing speedy repairs. This increased 
inspection, testing, and repair of pipelines could take more 
pipelines temporarily out of service and potentially impact the 
delivery of energy. Recognizing this potential problem, 
Congress required Federal agencies to participate in an 
interagency committee to facilitate the prompt repair of these 
pipelines so as to minimize safety, environment, and energy 
supply consequences. Under RSPA safety regulations, we have 
established timeframes for pipeline repairs depending on defect 
type and severity. Any serious time-sensitive repairs should 
qualify for expedited permitting. Once a serious pipeline 
condition is identified, it could potentially impact the safety 
of citizens and surrounding sensitive environments. Reviewing 
applications for such a pipeline repair should move to the 
front of the line and be dealt with in a new way. RSPA and its 
Office of Pipeline Safety are strongly committed to improving 
safety, reliability, and public confidence in our pipeline 
infrastructure.
    We are also working hard to educate communities on how they 
can continue to live safely with pipelines. Following the 
leadership of your Committee and this Administration, the 
legislation passed in recent years takes a new, more 
comprehensive and informed approach to identifying and managing 
the risks pipeline operators face and the risks posed to our 
communities. Thanks to this knowledge and the cooperation of 
all the parties, today everyone involved with pipelines is 
safer, and so is the environment they pass through.
    Thank you, sir. I'd be happy to take your questions.
    [The prepared statement of Mr. Bonasso follows:]

 Prepared Statement of Samuel G. Bonasso, P.E., Deputy Administrator, 
   Research and Special Programs Administration, U.S. Department of 
                             Transportation
    Mr. Chairman, my name is Samuel Bonasso. I am the Deputy 
Administrator of RSPA, the Research and Special Programs Administration 
of the U.S. Department of Transportation. With me is Stacey Gerard, 
Associate Administrator for the Office of Pipeline Safety (OPS).
    Thank you for this opportunity to discuss our strategy and our long 
term prospects for improved safety and reliability of the Nation's 
pipeline infrastructure. We greatly appreciate this committee's 
attention and support for our work.
    Under Secretary Mineta's leadership, RSPA and OPS have made great 
strides in meeting the mandates set forth in the Pipeline Safety 
Improvement Act (PSIA) of 2002. My testimony today will address our 
responses to these mandates, including specific implementation issues, 
and the results of our actions. Further, I want to make you aware of 
potential short and near term risks of reduced pipeline capacity and 
energy supply due to required pipeline testing and repairs.
    The Nation's pipelines are essential to our way of life. The 2.3 
million miles of natural gas and hazardous liquid pipelines carry 
nearly two-thirds of the energy consumed by our Nation. Pipelines are 
the safest and most efficient way to transport the enormous quantities 
of natural gas and hazardous liquids across land used by our country.
    Recent increased attention to the need for pipeline safety is 
rooted in demographic changes taking place in our country. Suburban 
development in previously rural areas has placed people closer to 
pipelines. This increases the risk that pipeline accidents, although 
infrequent, can have tragic consequences. Expansion and development 
also means more construction activity near pipelines--the leading cause 
of pipeline accidents.
    Pipeline safety is more than inspecting pipelines. It involves (1) 
having better information to understand safety problems, (2) knowing 
where to set the bar in safety standards, (3) advancing technology to 
find and fix those problems, (4) partnering with state and local 
governments to oversee this critical infrastructure, and (5) building 
alliances to prevent damage and educate the public about how to live 
safely with pipelines.
    Pipeline safety is a top priority for the Bush Administration and 
for Secretary Mineta, personally. With their support, RSPA and OPS have 
strengthened each of these five elements in just a few years.
    Expanded enforcement has been an important approach in 
strengthening the pipeline safety program. In the past 10 years, 57 
inspectors have been added to the OPS staff, from 28 inspectors in 1994 
to 85 inspectors today. Our partnerships with the states, such as our 
agreement with the Arizona Corporation Commission, provide several 
hundred more inspectors.
I. We Are Implementing A Plan
    With the enactment of the PSIA, we embarked on a new, more 
comprehensive and informed plan to identify and manage the risks that 
pipeline operators face and that pipelines pose to our communities. By 
collecting and using better information about pipelines, today we know 
more about pipelines, the world they traverse, and the consequences of 
a pipeline failure.
1. Higher Standards
    We have raised the standards for pipeline safety, through integrity 
management requirements and 17 other regulations, and incorporated 30 
new national consensus safety standards into our regulations.
2. Better Technology
    To improve the technology available to assess and repair pipelines, 
we have awarded almost eight million dollars, for three dozen research 
projects since March 2002.
3. Stronger Enforcement
    Our inspections are much more rigorous. Today, we spend 240 hours 
on a comprehensive integrity management inspection, in contrast to 32 
hours in 1996 for a standard pipeline safety inspection.
    We have adopted a tough-but-fair approach to improving enforcement, 
making heavier use of large fines, while guiding pipeline operators to 
meet higher standards. We have initiated steps to ensure that penalties 
are collected and acknowledged promptly.
4. Better States' Partnership
    We have strengthened our partnerships with state pipeline safety 
agencies, such as the Arizona Corporation Commission, through increased 
training, shared inspection data bases, a distributed information 
network to facilitate communications, and policy collaboration.
5. Cleaning Up Our Record
    Our new record as a regulator is important to us. In the past three 
years, the OPS has eliminated most of a 12-year backlog of outstanding 
mandates and recommendations from Congress, the National Transportation 
Safety Board, the DOT Inspector General, and the GAO. Over the past 4 
years, we have responded positively to 41 NTSB safety recommendations 
and are working to close the remaining 10 recommendations.
6. Preparing Partners and Going Local
    Helping communities to know how they can live safely with pipelines 
is a very important goal. We cannot succeed in improving pipeline 
safety without enlisting the help of local officials. We are moving on 
a number of fronts:

   Working with others, we have proposed to incorporate a new 
        standard for public education in regulations to ensure 
        community officials and citizens have essential safety 
        information they need to make informed decisions;

   We have commissioned a study by the Transportation Research 
        Board of the National Academy of Sciences on issues of 
        encroachment and maintenance on pipeline rights-of-way which 
        will report results in July.

   We have enlisted the help of the local fire marshals to 
        bring information and guidance to communities to build 
        understanding of pipeline safety and first responder needs, to 
        help identify high consequence areas in communities, and to 
        provide an understanding of LNG operations.

   Similarly, to foster safety and environmental protection on 
        Tribal Lands, we are working toward a partnership with the 
        Council of Energy Resource Tribes.
II. Responding to the Pipeline Safety Improvement Act of 2002 (PSIA)
    Pipelines are the arteries of our Nation's energy infrastructure 
and critical to the Nation's viability and well being. The Congress 
recognized the critical importance of pipelines when it passed the 
Pipeline Safety Improvement Act of 2002.
    The actions described above are consistent with the PSIA, which 
also has given us new mandates. Under Secretary Mineta's leadership, 
RSPA and OPS are aggressively responding to these new mandates.
1. Integrity Management
    We have completed the most significant improvement in pipeline 
safety standards by finalizing regulation of integrity management 
programs for hazardous liquid and natural gas transmission operators. 
Going beyond the PSIA requirements, we are studying, in conjunction 
with the American Gas Association, the potential for an integrity 
management program that would be appropriate for gas distribution and 
municipal operators. We and our state partners have completed 
comprehensive inspections of large hazardous liquid operators. During 
these inspections, we observed that operators had completed over 20,000 
repairs, 4,400 of which were time sensitive and important to find and 
fix expeditiously.
2. Operator Qualification
    We have completed half of the reviews of interstate operators' 
qualification programs and expect to meet the 2006 statutory deadline. 
States have made similar progress. We plan to incorporate improved 
consensus standards for the qualification of pipeline operators for 
safety critical functions when the standards are completed later this 
year.
3. Public Education and Mapping
    We believe that communication between Federal, State and local 
government, the operator and the public about how to live safely with 
pipelines is an important element in helping to assure the safety of 
our Nation's energy transportation pipeline infrastructure. Actions are 
underway to improve communications with state and local officials about 
actions they can take to protect their citizens and pipelines. We are 
improving opportunities for communities to understand pipeline safety 
and to take local action as required by the PSIA. We completed the 
National Pipeline Mapping system and we worked with pipeline operators 
to complete, by the December 2003 deadline, self assessments of their 
public education programs against new, higher standards.
    To respond to the need for improved public awareness of pipelines, 
OPS, the National Association of Pipeline Safety Representatives 
(NAPSR), and the pipeline industry have cooperated to develop a 
national consensus standard--American Petroleum Institute's Recommended 
Practice 1162 (RP 1162) for public education. RP1162 is designed to 
help pipeline operators meet new standards established in the PSIA. It 
requires operators to identify audiences to be contacted, effective 
messages and communications methods, and information for evaluating and 
updating public awareness programs. We have proposed incorporation of 
RP 1162 into our regulations.
    We are starting a Crisis Communications Initiative to improve 
communications following an accident. In July, we will host a workshop 
to develop the framework for this initiative, including a pilot program 
on crisis communications and interagency relationships. We expect this 
initiative to meet national objectives and to be complementary to the 
Homeland Security's National Response Plan, FERC's Liquefied Natural 
Gas efforts, and the National Association of Fire Marshal's education 
program.
4. Damage Prevention
    Working with the Common Ground Alliance and the Federal 
Communications Commission, we have provided for a single, national 
three-digit number for one call systems, most likely 811. The Federal 
Communications Commission is expected to finalize this action later 
this year. This will allow all Americans to take one action to protect 
all pipelines from excavation damage--the major cause of pipeline 
damage and failure. By making it simpler to call one number to mark 
underground lines, we expect more people to use this important 
prevention service.
5. Research and Development
    To provide a vision for the advancement of technology, we developed 
a memorandum of understanding with the Department of Energy and the 
National Institute of Standards and Technology for research planning, 
and have completed a five year plan. The plan includes a detailed 
management strategy for research solicitation and procurement; 
technology transfer and application of results; coordination and 
collaboration with other agencies, industry and stakeholders; 
approaches to communicate project findings; and methods of optimizing 
the use of resources.
6. Security
    Since 9/11, the Department has devoted considerable attention to 
security across all modes of transportation, including national 
pipeline security. While the PSIA did not speak specifically to 
security, pipeline system integrity and security are inextricably 
linked. We maintain clear expectations for critical pipeline operators' 
security preparedness. With the Department of Homeland Security (DHS), 
we verify industry action by conducting audits of all major pipeline 
operators' security preparedness. OPS expanded its oil spill emergency 
response exercise program to include focus on security and law 
enforcement for maintaining the reliability of energy supply. The 
Department plans to continue working closely with DHS on pipeline 
security issues.
7. Interagency efforts to Implement Section 16 of the PSIA
    Section 16 of the PSIA requires agencies with responsibilities 
relating to pipeline repair projects to develop and implement a 
coordinated process for environmental review and permitting. The 
interagency working group currently has five efforts underway to:

   refine early notification and Federal involvement 
        procedures;

   identify electronic communication methods that would 
        expedite and streamline review;

   establish practices that would reduce or minimize effects to 
        the environment such that reviews would be expedited; and

   refine permitting and review procedures for time-sensitive 
        pipeline repairs consistent with our regulatory and statutory 
        obligations.
III. Keeping the Energy Infrastructure Viable
    The Nation's economic viability and well-being depend on the 
enormous quantities of oil, fuel and natural gas transported safely, 
efficiently and at low cost by pipelines each and every day. The energy 
pipeline infrastructure in the United States represents a $31 billion 
investment in over 2 million miles of pipeline technology that is 
essential to American economic interests--a myriad of goods and 
services as well as millions of jobs are made possible and supported by 
this transportation infrastructure.
    Federal integrity regulations and PSIA have significantly increased 
the requirements on operators to test the integrity of this 
infrastructure, discover any defects and make repairs before ruptures 
or leaks can occur during the implementation of this important safety 
initiative. This initiative could take more pipelines temporarily out 
of service for inspection, assessment and repairs and could impact the 
delivery of energy.
    There are two aspects of this safety initiative which are being 
given special attention by DOT and other Federal agencies.
    First, we, from our safety purview, are the agency that sees the 
results of the testing of multiple pipelines by multiple operators 
across the regions of our Nation. Our experience suggests that many 
repairs will be required under our integrity management regulations--
potentially tens of thousands of repairs annually, and perhaps 
clustering in a particular region of the country.
    Second, while a pipeline operator awaits permits for repairs, the 
operating pressure of the pipeline usually needs to be reduced to 
maintain a safety margin. There is a risk that the amount of pressure 
reductions required pending permitting of repairs could measurably 
reduce the energy capacity of pipeline systems in certain regions. 
Depending on where pipelines are located and how energy markets are 
impacted, pressure reductions during peak demand periods could result 
in fuel shortages and price increases.
    The Congress recognized this potential problem and required Federal 
agencies to participate in an Interagency Committee to facilitate the 
prompt repair of our pipelines. Work is ongoing with the other relevant 
Federal agencies to develop guidance to ensure that any necessary 
Federal permits for repairs of pipelines in danger of rupture can be 
coordinated and expedited.
    Some of the specific issues the Interagency Committee is addressing 
include:

   Feasibility of providing Federal permitting agencies with 
        advance information about operator test schedule. Obtaining 
        this information in advance could help agencies anticipate 
        resources needed for permitting repairs and to exchange 
        information about required actions as soon as possible. 
        Pipeline operators, however, are concerned that by providing 
        this information they might be expected to meet the schedule 
        regardless of factors that are beyond their control (weather, 
        availability of appropriate equipment and certified crews, 
        etc.). Operators are also concerned that the testing schedules 
        could become public information that can not be protected as 
        proprietary information, releasing business-sensitive and 
        possibly security-sensitive information.

   Methods to expedite environmental reviews. The Interagency 
        Committee is examining the required consultative processes for 
        permitting repairs in order to determine if actions can be 
        taken that would enable operators to carry out repairs quickly 
        while meeting safety standards.

   Potential energy supply impacts of multiple repairs in a 
        regional area. As we have experienced recently in gasoline 
        markets, a small change in pipeline supplies can have a 
        dramatic impact on fuel price. In a situation with multiple 
        pipelines in a regional area in need of repair, OPS would work 
        with operators to prioritize the order of repairs and maintain 
        safety. A time sensitive repair might qualify for expedited 
        permitting because of the potential energy supply impact. 
        Maintaining pipeline capacity and throughput is essential in 
        supplying fuels to regional markets and vital to the Nation's 
        industries.
IV. We are achieving results.
    Comparing years 1999 to 2003 to the previous five years, from 1994 
to 1998, hazardous liquid incidents have decreased by 25 percent. By 
2003, the volume of oil spilled had decreased by 15 percent from the 
previous 10-year average.
    Excavation accidents have decreased over the past ten years by 59 
percent. This is largely the result of work with our state partners and 
the more than 900 members of a damage prevention organization we 
initiated--the Common Ground Alliance (CGA). The CGA has formed 22 
regional alliances to foster damage prevention activities and will soon 
announce two additional regional alliances, including a western 
regional common ground alliance, which is the result of a three-state 
effort led by the Arizona Corporation Commission.
    In closing, I want to reassure you, Mr. Chairman, and all of the 
members of this committee, that Secretary Mineta, RSPA and the 
hardworking men and women in the Office of Pipeline Safety share your 
strong commitment to improving safety, reliability, and public 
confidence in our Nation's pipeline infrastructure.
    I will be happy to take your questions.
    [GRAPHICS NOT AVAILABLE IN TIFF FORMAT]
    

    The Chairman. Thank you very much.
    Mr. Connaughton?

 STATEMENT OF HON. JAMES L. CONNAUGHTON, CHAIRMAN, COUNCIL ON 
                     ENVIRONMENTAL QUALITY

    Mr. Connaughton. Thank you, Mr. Chairman. Good morning, 
Senator Lautenberg.
    First of all, I want to thank you, Mr. Chairman, for your 
leadership in getting this legislation and these authorities to 
us, and actually, Senator Lautenberg, for your foresight a 
decade ago.
    I am the--the President was pleased to sign this 
legislation, and actually we moved very aggressively to put in 
place and get the processes moving to fulfill its mandates.
    I am in charge of the--the Chair of the Interagency Task 
Force that oversees the energy projects streamlining to which 
this was assigned. Our goal has been to develop an efficient 
process for pipeline testing and more timely repair in a way 
that still ensures appropriate environmental stewardship and 
compliance.
    We've already mentioned that our pipeline infrastructure is 
over 50 years old, and requires regular testing and inspection 
to ensure its reliability, protect human life, property, and 
natural resources, as well as to ensure sufficient supply of 
natural gas and liquid fuels, such as gasoline or diesel. At 
the same time, many of the pipelines that are subject to this 
new testing regime run through what are called high consequence 
areas. These are areas that are highly populated, they're 
sensitive to environmental damage, or they're located near 
waterways. Effecting timely repairs of these pipelines while 
enabling environmental protection is a critical challenge, as 
Congress recognized in the Pipeline Safety Act.
    I'm pleased to report to you today that we have completed 
work on the memorandum of understanding that was called for by 
Section 16 of the Act, and the text of the MOU is attached to 
my written testimony. The process envisioned under the 
memorandum of understanding would expedite the ability of 
operators to obtain the necessary permits or authorizations 
prior to making repairs in a high consequence area when a time-
sensitive repair is indicated by testing. And that is when the 
pipeline's physical condition is such that repair is mandated 
within a certain period of time by DOT's implementing 
regulations.
    This process requires enhanced coordination among Federal 
agencies, and recognizes that early planning, notice, and 
consultation among pipeline operators and Federal agencies can 
result in timely decisions that enable these critical repair 
actions to go forward within the context of resource 
protection.
    The MOU also supports the development of a comprehensive 
one-stop information system to improve information sharing 
between pipeline operators and the agencies to help identify 
potential issues and provide recommendations on best management 
practices that will avoid, reduce, or mitigate any impacts to 
resources of concern.
    Even as the MOU was being developed by these participating 
agencies, we have been working to implement the process that is 
formalized in the MOU, and I'll outline just a few key points 
from that.
    First, we are encouraging early notification by operators 
of their testing schedules, which would allow earlier 
consultations on issues that arise, as well as coordination of 
testing activities so that energy supply and price impacts can 
be minimized.
    Second, we're working to consolidate the existing 
permitting process, which is sequential, into a more single, 
concurrent permitting process that is triggered by the operator 
upon finding that a time-sensitive repair is needed.
    Third, we are considering the appropriate use of what are 
called categorical exclusions under the National Environmental 
Policy Act for instances where repairs can occur entirely 
within an existing right-of-way or where minimal additional 
access is required, so long as consensus best-management 
practices are used to avoid or minimize any impacts.
    Now, this issuance of a categorical exclusion would be 
based on a determination that the specific category of 
actions--so these are repeated actions that you see again and 
again--described would not individually or cumulatively have a 
significant effect on the human environment, and, therefore, 
would not require further action-specific environmental 
assessment or an environmental impact statement. So that is, 
there's an environmental review as to the category of actions. 
Once that's done, those kinds of actions can proceed without 
having a one-by-one-by-one review.
    Finally, we are working with operators to identify those 
instances where specific issues or additional authorizations, 
such as under the Endangered Species Act or the Clean Water 
Act, may have, in the past, prevented repairs in a timely 
manner. Specific procedures can then be developed to help avoid 
these issues in the future, and allow for more timely 
completion of repairs in each case, while still allowing the 
Federal agencies to carry out their resource-protection 
responsibilities.
    Given the state of our Nation's aging pipeline 
infrastructure, we're working hard to ensure that these timely 
repairs can be made, that accidents can be avoided, and human 
life, property, and natural resources are protected. At the 
same time, we're working to minimize any negative impacts on 
natural resources from this work, as well as any impacts on our 
Nation's energy supply.
    And I'm happy to take your questions, as well.
    [The prepared statement of Mr. Connaughton follows:]

         Prepared Statement of James L. Connaughton, Chairman, 
                    Council on Environmental Quality
    Good morning Chairman McCain, Ranking Member Hollings, and Members 
of the Committee.
    I am pleased to appear before you today to describe our efforts to 
implement the provisions of the Pipeline Safety Act of 2002 by 
developing an efficient process for expedited pipeline testing and 
repair while ensuring environmental stewardship.
    The Nation's existing pipeline infrastructure, much of which is 
over 50 years old, requires regular safety and environmental reviews to 
ensure its reliability.
    Timely testing and repair of both natural gas and hazardous liquid 
pipelines is essential to protect human life and property, and to 
facilitate the sufficient availability and use of natural gas and 
liquid fuels for our energy needs.
    At the same time, many natural gas and hazardous liquid pipelines 
run through ``High Consequence Areas'': areas that are highly 
populated, are unusually sensitive to environmental damage, or are 
located along or near commercially navigable waterways.
    Effecting timely repairs of these pipelines, while enabling 
effective environmental protection, is a critical challenge we are 
tackling as directed by Congress in Section 16 of the Pipeline Safety 
Act of 2002.
    Our work is ongoing, and I am pleased to report to you today on our 
results thus far.
Implementation of the Pipeline Safety Act of 2002
    Through Executive Order 13212, issued on May 18, 2001, President 
Bush directed Federal agencies to expedite reviews of authorizations 
for energy-related projects and to take other actions necessary to 
accelerate the completion of projects that will increase the 
production, transmission, or conservation of energy, while maintaining 
safety, public health and environmental protections.
    The Executive Order also created a Task Force, chaired by CEQ, to 
monitor and assist Federal agencies in carrying out this directive.
    Following pipeline ruptures in Bellingham, Washington in June 1999 
and Carlsbad, New Mexico in August 2000 which caused loss of life and 
significant property damage, Congress enacted the Pipeline Safety 
Improvement Act of 2002 (PSIA), which was signed into law by President 
Bush on December 17, 2002.
    Section 16 of the PSIA directed the President to establish an 
Interagency Committee to implement a coordinated environmental review 
and permitting process enabling pipeline repairs within the time 
periods specified by DOT regulations called for in other sections of 
the PSIA.
    To implement Section 16 of the PSIA, the President issued Executive 
Order 13302 on May 15, 2003, adding these pipeline safety functions to 
the charge given the Task Force authorized under Executive Order 13212. 
Therefore, CEQ has coordination responsibility for efforts to implement 
Section 16 of the PSIA, and that is why I appear before you today.
MOU Development
    During the summer and fall of 2003, a working group of the Task 
Force evaluated Federal permitting requirements, identified best 
management practices (BMPs), and developed a memorandum of 
understanding (MOU) to provide for a coordinated and expedited pipeline 
permit review process. The text of the MOU is attached to my written 
testimony.
    The process envisioned under the MOU would expedite the ability of 
pipeline operators to obtain the necessary permits or authorizations 
prior to making repairs in a High Consequence Area when a ``time-
sensitive'' repair is indicated by testing: that is, when the 
pipeline's physical condition is such that repair is mandated within a 
certain period of time as directed by the PSIA and DOT's implementing 
regulations.
    The MOU enhances coordination of the processes through which 
agencies with environmental and historic preservation review 
responsibilities under various statutes--such as the Clean Water Act, 
or the Endangered Species Act--meet those responsibilities in 
connection with the authorizations required to repair natural gas and 
hazardous liquid pipelines that have been identified by pipeline 
operators as in need of repair on a timely basis to protect life, 
health or physical property.
    The MOU recognizes that early planning, notice, and consultation 
among pipeline operators and Federal agencies can result in a 
structured process that facilitates timely decisions and enables 
critical repair actions to go forward, within the context of resource 
conservation.
    The MOU supports the development of a comprehensive, ``one-stop'' 
information system to allow pipeline operators and agencies alike 
access to the best available information on pipeline testing and repair 
schedules, agency official contact information, natural resource 
conservation needs, and recommendations on management practices for 
testing and repair.
    Further, the MOU recognizes that the identification and use of best 
management practices (BMPs) to avoid, reduce, or mitigate impacts to 
resources of concern can be one means of implementing specific measures 
to protect affected resources and encourage increased environmental 
stewardship.
Further Actions
    The Task Force working group continues to consult on specific steps 
and agency actions to implement the process envisioned in the MOU.
    First, we are working with industry to encourage early notification 
by operators of their testing schedules, so as to enable early 
consultation on issues that arise, and coordinate pipeline testing so 
that energy supply and price impacts are minimized.
    Second, interagency discussions are well along in attempting to 
consolidate existing sequential permitting processes into a single, 
concurrent permitting process for general repairs that is triggered by 
the operator upon finding of a time-sensitive repair need.
    Third, we are considering the potential for proposing categorical 
exclusions under the National Environmental Policy Act for instances 
where repairs can occur entirely within an existing right-of-way, or 
where minimal additional access is required, so long as consensus Best 
Management Practices are used to minimize impacts. Issuance of a 
categorical exclusion would mean that the specific category of actions 
described in the categorical exclusion do not individually or 
cumulatively have a significant effect on the human environment, and 
therefore, neither an environmental assessment nor an environmental 
impact statement would be required.
    Finally, we are working with pipeline operators to identify those 
instances where specific issues and additional authorizations may have 
in the past prevented repairs in a timely manner (e.g., threatened or 
endangered species, navigable waterways, private lands, etc.). Once 
these instances are identified, we will work to develop specific 
procedures that will avoid these issues in the future and allow for 
timely completion of time-sensitive repairs in each case while allowing 
Federal agencies to carry out their resource protection 
responsibilities.
Conclusion
    Given the state of our Nation's aging pipeline infrastructure, we 
are working to ensure that timely repairs can be made, accidents can be 
avoided, and human life and property is protected. At the same time, we 
are working to minimize negative impacts on the surrounding 
environment, and on our Nation's energy supply.
    I will be glad to take any questions you may have. Thank you.

    The Chairman. Thank you very much.
    Mr. Mead, welcome back.

         STATEMENT OF HON. KENNETH M. MEAD, INSPECTOR 
           GENERAL, U.S. DEPARTMENT OF TRANSPORTATION

    Mr. Mead. Thank you, Mr. Chairman.
    The Chairman. Mr. Mead, by your calculations, how many 
appearances have you made before this Committee, besides too 
many?
    [Laughter.]
    Mr. Mead. It would probably be in the neighborhood of 50 or 
60.
    The Chairman. Thank you. Welcome back.
    Mr. Mead. Yes, sir.
    We're issuing a report today. You'll be receiving it under 
a formal transmittal. I'll speak to the highlights of that.
    You referred to the Bellingham, Washington, accident. That 
was, in fact, the impetus behind a 2000 audit that we did of 
this program. That was followed by a request from the U.S. 
Attorney there that we, along with the EPA, help to determine 
whether there were violations of Federal law associated with 
that accident.
    Ultimately, in the largest criminal and civil settlement 
ever obtained in a pipeline case, two companies were ordered to 
pay $36 million to resolve criminal and civil penalties, an 
additional $77 million to ensure the safety of their pipelines.
    Now, when we last testified before this Committee, in 2000, 
we reported that OPS was very slow. And I think that's probably 
a generous characterization. They are very slow to implement--I 
find--safety initiatives. It didn't matter whether they were 
congressionally mandated, came from NTSB, or some other place. 
Some mandates, some legislation remained outstanding, some more 
than 8 years past due. Also, overdue NTSB safety 
recommendations remained open, some for more than a decade. 
That lack of responsiveness prompted Congress to, again, 
mandate basic elements of a pipeline safety program. That 
culminated in the Pipeline Safety Improvement Act of 2002. That 
law actually incorporated recommendations from our audit report 
that had been initially requested by Senator Murray.
    Well, I can report today that OPS has gotten the message, 
they've made considerable progress, cleared out most, but not 
all, the 1992, 1996 Congressional mandates, also closed out 
most of the NTSB recommendations. They were also removed from 
NTSB's most wanted safety list. Well, that said, much remains 
to be done.
    OPS has issued--and I think they will tell you this--many 
important rules over the last couple of years. The most 
important ones, thought, you've alluded to in your opening 
remarks, what's called the Integrity Management Program for the 
hazardous liquid and natural gas transmission pipelines. That 
is the safety program the operators use to assess their 
pipelines for risk of a leak or a failure, take action to 
repair pipelines, and mitigate the risks.
    So against that backdrop, I'd like to highlight four 
points. First, mapping where the pipelines are located. Two, 
the new IMP inspection process, and oversight of it. Third, 
closing a gap we see on natural gas distribution pipelines. 
And, four, pipeline security responsibilities.
    Mapping where pipelines are located. When we testified 
before this Committee in 2000, we did not know where a 
substantial percentage of pipelines were located. I'm talking--
by substantial, I mean over 50 percent of them. A voluntary 
mapping initiative that started in 1994 was not working, so 
Congress mandated that one--mandated it in 2002. OPS completed 
its mapping system this year. We now have 100 percent of the 
hazardous liquid pipeline and natural gas transmission 
pipelines mapped.
    The new IMP inspection process. Operators are in the early 
stages of implementing their IMPs. Now, they are not required 
to have all these inspections completed for hazardous liquid 
pipelines until 2009, and natural gas transmission pipelines 
until 2012, but about 25,000 miles of hazardous liquid 
pipelines have received inspections, and most of those have 
been in what they call high-consequence areas. They're areas of 
dense population----
    The Chairman. Twenty-five thousand out of how many?
    Mr. Mead. Twenty-five thousand out of about 435,000. Well, 
that leaves about 135,000 of the hazardous liquid pipeline, and 
about, I think, 325,000 of natural gas transmission pipelines 
to go. Gas operators must begin inspections actually later this 
week. I believe it's on June 17.
    Well, what are these inspections showing? There are early 
signs that the inspections are working well, and there was 
clearly a need for them. To date, more than 20,000 integrity 
threats have been identified and, according to OPS, remediated. 
That means fixed. A key point here is that these threats were 
identified in less than 16 percent of hazardous liquid 
pipeline. So we have a lot to go.
    Once a threat's identified, OPS needs to follow up to 
ensure that the operators take corrective action. Of the 20,000 
threats, here's how they broke down. About 1200 of them 
required immediate repairs, 760 required repairs within 60 
days, and 2,400 required repairs within 180 days. The remainder 
weren't time-sensitive.
    Now, the process here is not as simple as just identifying 
the problem and figuring out how to fix it. For some repairers, 
the environmental review and permitting process delayed 
preventive measures, as was demonstrated by a pipeline rupture 
in California as recently as April of this year. The 
deteriorating condition of this pipeline, Mr. Chairman, was 
well documented, it was well known. In fact, in 2001, the 
operator initiated the action to relocate the pipeline, but it 
took nearly 3 years and over 40 permits before approval to 
relocate was obtained. That was too late to prevent this spill. 
Fortunately, in this one, there was no loss at least of human 
life.
    Congress recognized the need to expedite the environmental 
process when it passed the 2002 Pipeline Act, and an 
interagency task force was set up to do it. Well, a Memorandum 
of Understanding has been drafted. The Department of 
Transportation----
    The Chairman. The 3 years and 40 permits, how much of that 
was Federal requirements versus state requirements?
    Mr. Mead. I don't have that breakdown. I can get it for 
you.
    The Chairman. Do you know, Mr. Connaughton?
    Mr. Connaughton. Yes, there are--of the main programs, of 
which there are about two dozen, three of them were Federal 
permitting programs--Fish and Wildlife Service, Army Corps of 
Engineers--and then three was the initial review done by the 
Integrity Management timeline issue. So it's largely Federal--
it's largely state and local, but the Federal one, especially 
the endangered species one, is the one that took nearly the 
entire 3 years. So it's a smaller piece of the total number, 
but it has accounted for a larger----
    The Chairman. It had a major impact on the 3-year delay. 
Thank you.
    I'm sorry, Mr. Mead.
    Mr. Mead. That's OK.
    Well, I want to say a word about this Memorandum of 
Understanding. The Department of Transportation signed it 
yesterday, and it's not clear to us what process changes this 
Memorandum of Understanding is actually going to require. I 
hope that it will become clear as it's implemented. I don't 
want to wait for a serious accident to occur. We don't need a 
repeat of that situation in California.
    Now, the oversight of these IMPs. The IMP is actually--the 
inspections there are actually done by the operator, and the 
Office of Pipeline Safety oversees them. That means they have 
to monitor the implementation of more than 1100 pipeline 
operator IMPs, and they've done about 70 of those to date. 
Also, 10 years ago OPS had 28 inspectors to oversee pipeline 
safety. That has tripled, and it's augmented by about 400 state 
inspectors. Also, when we testified, in May 2000, OPS did not 
even train its inspectors on the use of ``smart pig'' 
technologies. That's an instrumented inspection device you 
stick in the pipelines. Well, they do so today.
    I'm not going into detail on this, but I think that OPS is 
headed in the right direction on research and development, too. 
There, in 2000--or 1999, I think they had one research project. 
Today, they have 22. The funding for it has moved from $2.7 
million to almost $9 million. And that's important, because 
these ``smart pigs,'' they may be very smart, but they're not 
smart enough to detect all the problems that you find with 
pipelines.
    Now, I think there's a safety gap on the actual gas 
distribution pipelines that I'd like to touch on. These 
pipelines, they deliver natural gas to the end users, and they 
make up, actually, over 85 percent--that's 1.8 million miles--
of the 2.1 million miles of natural gas pipelines in this 
country. These natural gas distribution pipeline operators are 
not required to have an IMP, which is unlike the hazardous 
liquid operators and unlike the natural gas transmission 
pipeline operators. And according to industry officials, the 
reason for that, or the primary reason for it, is that their 
pipelines can't be inspected using ``smart pigs.'' Well, in our 
opinion, that's not a sufficient reason for not requiring some 
form of an IMP. There are other IMP elements that can readily 
be applied to this segment of the industry, like developing 
timeframes on how often pipelines should be inspected, how--and 
when repairs should be made.
    Our concern, Mr. Chairman, is that over the last 10 years, 
natural gas distribution pipelines experienced four times the 
numbers of fatalities and more than three times the number of 
injuries than the combined totals for hazardous liquid and 
natural gas transmission pipelines. I think that's a pretty 
good case for applying the IMPs.
    Finally, security. The Office of Pipeline Safety took the 
lead to help reduce the risk of terrorist activity against the 
pipeline infrastructure following 9/11. But the guidance to the 
operators is currently voluntary, and OPS now states it plays a 
secondary or support role to the Transportation Security 
Administration, which is, of course, in DHS. The current 
Presidential directive addressing security is at too high a 
level of generality to provide clear guidance on each agency's 
responsibilities, the three agencies--DOT, DOE, and DHS. And 
the current guidance is basically, ``Go collaborate and 
coordinate.'' And I think the delineation of the roles and 
responsibilities between those three agencies needs to be 
spelled out in a memorandum of understanding so that it's 
clearly understood who's going to be making rulemaking policy 
decisions, who will conduct the security inspections, and who's 
going to enforce the security requirements. Presently, that is 
unsettled. Thank you, Mr. Chairman.
    [The prepared statement of Mr. Mead follows:]

    Prepared Statement of Hon. Kenneth M. Mead, Inspector General, 
                   U.S. Department of Transportation
    Mr. Chairman, Mr. Vice Chairman, and Members of the Committee:
    We appreciate the opportunity to testify today on the actions the 
Office of Pipeline Safety (OPS) has taken to improve pipeline safety 
and the actions that still need to be done.
    OPS is responsible for overseeing the safety of the Nation's 
pipeline system, an elaborate network of more than 2 million miles of 
pipeline moving millions of gallons of hazardous liquids and more than 
55 billion cubic feet of natural gas daily. The pipeline system is 
composed of predominantly three segments--natural gas transmission 
pipelines, natural gas distribution pipelines, and hazardous liquid 
pipelines--and has about 2,200 \1\ natural gas pipeline operators and 
220 hazardous liquid pipeline operators. Pipelines are a relatively 
safe way to transport energy resources and other products, but they are 
subject to forces of nature, human action, and material defects that 
can cause potentially catastrophic accidents.
---------------------------------------------------------------------------
    \1\ Of the 2,200 operators of natural gas pipelines, there are 
approximately 1,300 operators of natural gas distribution pipelines and 
880 operators of natural gas transmission pipelines.
---------------------------------------------------------------------------
    Following the deadly pipeline explosion and fire in Bellingham, 
Washington, in June 1999, Senator Patty Murray requested the Office of 
Inspector General to review the activities of OPS. Also, a few months 
following the Bellingham accident, the United States Attorney's Office, 
Western District of Washington, requested that we, in a joint effort 
with the Environmental Protection Agency's Criminal Investigation 
Division, assist in an investigation to determine whether violations of 
Federal law occurred in connection with the accident.
    In the largest criminal and civil settlement ever obtained in a 
pipeline rupture case, two pipeline companies were ordered to pay $21 
million in criminal penalties and $15 million in civil penalties. In 
addition, the companies were ordered to implement pipeline integrity/
spill mitigation programs valued in the aggregate at $77 million. The 
charges, the first ever brought under the Hazardous Liquid Pipeline 
Safety Act of 1979, as amended, included three criminal counts for 
violating this act, which sets minimum safety standards for training 
employees who operate interstate pipelines that carry hazardous 
liquids.
    In response to Senator Murray's request, we reported in March 2000 
\2\ that weaknesses existed in OPS's pipeline safety program and made 
recommendations designed to correct these weaknesses. These 
recommendations were later mandated in the Pipeline Safety Improvement 
Act of 2002 (2002 Act). This Act required us to review OPS's progress 
in implementing our recommendations. Our testimony today is based 
largely on the results of this second review.\3\
---------------------------------------------------------------------------
    \2\ OIG Report Number RT-2000-069, ``Pipeline Safety Program,'' 
March 13, 2000.
    \3\ OIG Report Number SC-2004-064, ``Actions Taken and Needed for 
Improving Pipeline Safety,'' June 14, 2004.
---------------------------------------------------------------------------
    Historically, OPS was slow to implement critical pipeline safety 
initiatives, congressionally mandated or otherwise, and to improve its 
oversight of the pipeline industry. The lack of responsiveness prompted 
Congress to repeatedly mandate basic elements of a pipeline safety 
program, such as requirements to inspect pipelines periodically and to 
use smart pigs \4\ to inspect pipelines.
---------------------------------------------------------------------------
    \4\ A ``smart pig'' is an instrumented internal inspection device 
that traverses a pipeline to detect potentially dangerous defects, such 
as corrosion.
---------------------------------------------------------------------------
    OPS is making considerable progress in implementing the 
recommendations in our March 2000 report by clearing out most, but not 
all, of the congressional mandates enacted in 1992 and 1996. It has 
also closed out nearly all the long-overdue National Transportation 
Safety Board (NTSB) safety recommendations we identified. In addition, 
OPS was removed from NTSB's most-wanted list of safety improvements in 
2002. Even though OPS has issued many important rules for improving 
pipeline safety, the most important rules, relating to Integrity 
Management Programs (IMP)\5\ will not be fully implemented for up to 8 
years. This is a key issue as the IMP is the backbone of OPS's risk-
based approach to overseeing pipeline safety.
---------------------------------------------------------------------------
    \5\ The Integrity Management Program is a documented set of 
policies, processes, and procedures that includes, at a minimum, the 
following elements: (1) a process for determining which pipeline 
segments could affect a high-consequence area, (2) a baseline 
assessment plan, (3) a process for continual integrity assessment and 
evaluation, (4) an analytical process that integrates all available 
information about pipeline integrity and the consequences of a failure, 
(5) repair criteria to address issues identified by the integrity 
assessment and data analysis, (6) features identified through internal 
inspection, (7) a process to identify and evaluate preventive and 
mitigative measures to protect high-consequence areas, (8) methods to 
measure the integrity management program's effectiveness, and (9) a 
process for review of integrity assessment results and data analysis by 
a qualified individual.
---------------------------------------------------------------------------
    It is against this backdrop that I would like to discuss five major 
points regarding pipeline safety: (1) mapping the pipeline system; (2) 
monitoring the evolving nature of IMP implementation; (3) monitoring 
operators' corrective actions for remediating pipeline integrity 
threats; (4) closing the safety gap on natural gas distribution 
pipelines; and (5) developing an approach to overseeing pipeline 
security.

   Mapping the Pipeline System--The first step to an effective 
        oversight program is to identify where the assets to be 
        overseen are located. In the past year, OPS completed the 
        development of its national pipeline mapping system (NPMS), an 
        initiative the pipeline industry was reluctant to support, so 
        Congress mandated it in the 2002 Act. The NPMS is now fully 
        operational and has mapped 100 percent of the hazardous liquid 
        (approximately 160,000 miles of pipeline) and natural gas 
        transmission (more than 326,000 miles) pipeline systems 
        operating in the United States. Congress exempted natural gas 
        distribution pipelines from the mapping mandate, so currently 
        OPS does not have mapping data on the approximately 1.8 million 
        miles of this type of pipeline.

   Monitoring the Evolving Nature of IMP Implementation--The 
        next step is threefold: (1) operators assessing their pipelines 
        for any potential integrity threat and correcting any threats 
        that are identified, (2) OPS assessing whether the 
        implementation of the operators' IMPs were adequate, and (3) 
        OPS continuing to support research and development projects to 
        improve pipeline inspection technology.

  --  As mandated by Congress, OPS issued regulations requiring 
            pipeline operators of hazardous liquid and natural gas 
            transmission pipelines to develop and implement IMPs. IMPs 
            are in the early stages of implementation, and operators 
            are not required to have all baseline integrity inspections 
            completed of hazardous liquid pipelines until 2009 and of 
            natural gas transmission pipelines until 2012. OPS required 
            hazardous liquid pipeline operators--the first segment of 
            the industry required to implement the IMP--to first 
            complete baseline integrity inspections of pipeline miles 
            in high-consequence areas, such as residential communities 
            and business districts. These pipelines present the highest 
            risk of fatalities, injuries, and property damage should an 
            accident occur.

      About 135,000 miles of hazardous liquid and more than 326,000 
            miles of natural gas transmission pipeline still need 
            baseline integrity inspections. Nevertheless, there are 
            early signs that the baseline integrity inspections are 
            working well for operators of hazardous liquid pipelines, 
            and there was clearly a need for such inspections. 
            According to OPS, in the pipelines inspected so far, more 
            than 20,000 integrity threats have been identified and 
            remediated. A key point to remember, though, is these 
            threats were identified in less than 16 percent (about 
            25,000 miles) of hazardous liquid pipeline miles requiring 
            baseline integrity inspections.

  --  OPS will be monitoring the implementation of the IMP by more than 
            1,100 hazardous liquid and natural gas transmission 
            pipeline operators. This is in addition to OPS's ongoing 
            oversight activities, such as inspecting new pipeline 
            construction and investigating pipeline accidents. As of 
            April 30, 2004, the 63 largest operators of hazardous 
            liquid pipelines have undergone initial IMP reviews by OPS 
            inspection teams, leaving 157 hazardous liquid and 884 
            natural gas transmission pipeline operators still needing 
            an initial IMP review by an OPS inspection team. Monitoring 
            the implementation of pipeline operators' IMPs will be an 
            ongoing process for years.

  --  In addition, OPS must continue to support research and 
            development projects to improve pipeline assessment 
            technology. The majority of operators are using smart pigs 
            to assess pipelines under their IMPs, but smart pigs are 
            not a silver bullet that can identify all pipeline 
            integrity threats. Smart pigs currently in use can 
            successfully detect and measure corrosion, dents, and 
            wrinkles but are less reliable in detecting other types of 
            mechanical damage. As a result, certain integrity threats 
            still go undetected after a baseline integrity inspection, 
            and pipeline accidents may occur. Also, the smart pig 
            technologies currently available cannot be used in natural 
            gas distribution pipelines because the majority of 
            distribution piping is too small in diameter (1 to 6 
            inches) and has multiple bends and material types 
            intersecting over very short distances.

   Monitoring Operators' Corrective Actions for Remediating 
        Pipeline Integrity Threats--Once a threat is identified, OPS 
        will need to follow up to ensure that the operators take timely 
        and appropriate corrective action. Of the more than 20,000 
        threats have been repaired to date, more than 1,200 required 
        immediate repair, 760 threats required repairs within 60 days, 
        and 2,400 threats required repairs within 180 days. More than 
        16,300 threats fall into the category of ``other repairs,'' for 
        which remediation activities are not considered time-sensitive.

    In understanding the operators' actions to remediate many of these 
        threats, IMP inspectors need a working knowledge of the 
        operators' pigging operations and of the interpretation of 
        inspections' results. At the time we issued our March 2000 
        report, OPS did not train its inspectors on the use of smart 
        pig technologies and the interpretation of the result of the 
        inspections. Since that time, OPS now provides a course to IMP 
        inspectors where they gain the knowledge and skills required to 
        conduct meaningful safety evaluations of operator pigging 
        program inspections and of pigging data for hazardous liquid 
        and natural gas transmission pipelines.

    OPS's remediation criteria encompass a broad range of actions, 
        which include mitigative measures (such as reducing the 
        pipeline pressure flow), as well as repairs that an operator 
        can take to resolve an integrity threat. But the process is not 
        as simple as identifying the problem and determining how best 
        to fix it. For some repairs, Federal and state environmental 
        review and permitting processes have delayed preventive 
        measures from occurring, as was demonstrated by the recent 
        pipeline rupture in northern California. A hazardous liquid 
        pipeline ruptured and released about 85,000 gallons of diesel 
        fuel, affecting 20 to 30 acres of marshland.

    The deteriorating condition of this pipeline was well documented by 
        the operator, who initiated action to relocate the pipeline in 
        2001. However, it took nearly 3 years and more than 40 permits 
        before the operator was given approval to relocate the 
        pipeline. It was too late to prevent this spill, but 
        fortunately in this case there was no loss of human life.

    An Interagency Task Force was set up to monitor and assist agencies 
        in their efforts to expedite their review of permits. However, 
        the Task Force has yet to implement its Memorandum of 
        Understanding (MOU) that would expedite the environmental 
        review and permitting processes so that pipeline repairs can be 
        made before a serious consequence occurs. If there are any 
        further delays in implementing the MOU, then it may be 
        necessary for Congress to take action.

   Closing the Safety Gap on Natural Gas Distribution 
        Pipelines--The natural gas distribution system makes up over 85 
        percent (1.8 million miles) of the 2.1 million miles of natural 
        gas pipelines in the United States. Distribution is the final 
        step in delivering natural gas to end users such as homes and 
        businesses. While hazardous liquid and natural gas transmission 
        pipeline operators are moving forward with IMPs, natural gas 
        distribution pipeline operators \6\ are not required to have an 
        IMP. According to industry officials, the initial reason why 
        natural gas distribution pipelines were not required to have an 
        IMP is that the majority of distribution pipelines cannot be 
        inspected using smart pigs.
---------------------------------------------------------------------------
    \6\ There are some operators of natural gas transmission pipelines 
that are also operators of natural gas distribution pipelines. IMP 
requirements do not apply to their distribution pipelines.

    The IMP is a risk-management tool designed to improve safety, 
        environmental protection, and reliability of pipeline 
        operations. That natural gas distribution pipelines cannot be 
        internally inspected using smart pigs is not by itself a 
        sufficient reason for not requiring operators of natural gas 
        distribution pipelines to have IMPs. Other elements of the IMP 
        can be readily applied to this segment of the industry, 
        including but not limited to (1) a process for continual 
        integrity assessment and evaluation, and (2) repair criteria to 
        address issues identified by the integrity assessment and data 
---------------------------------------------------------------------------
        analysis.

    Our concern is that the Department's strategic safety goal is to 
        reduce the number of transportation-related fatalities and 
        injuries, but natural gas distribution pipelines are not 
        achieving this goal. Over the last 10 years, natural gas 
        distribution pipelines have experienced over 4 times the number 
        of fatalities (174 fatalities) and more than 3.5 times the 
        number of injuries (662 injuries) than the combined totals of 
        43 fatalities and 178 injuries for hazardous liquid and natural 
        gas transmission pipelines.

    To address this issue, the American Gas Foundation, with OPS 
        support, is sponsoring a study to assess the Nation's gas 
        distribution infrastructure that will evaluate safety 
        performance, current operating and regulatory practices, and 
        emerging technologies.

   Developing an Approach To Overseeing Pipeline Security--It 
        is not only important that we ensure the safety of the Nation's 
        pipeline system, we must also ensure the security of the 
        system. OPS took the lead to help reduce the risk of terrorist 
        activity against the Nation's pipeline infrastructure following 
        the events of September 11, 2001, but OPS now states it plays a 
        secondary or support role to the Department of Homeland 
        Security's (DHS) Transportation Security Administration (TSA).

    The current Presidential Directive \7\ that addresses this issue is 
        at too high a level of generality to provide clear guidance on 
        each Agency's [DOT, DHS, and the Department of Energy (DOE)] 
        responsibility in regards to pipeline security. The delineation 
        of roles and responsibilities between DOT, DHS, and DOE needs 
        to be spelled out in an MOU at the operational level so that we 
        can better monitor the security of the Nation's pipelines 
        without impeding the supply of energy.
---------------------------------------------------------------------------
    \7\ Homeland Security Presidential Directive/HSPD-7, ``Critical 
Infrastructure Identification, Prioritization, and Protection,'' issued 
December 2003.
---------------------------------------------------------------------------
Mapping the Pipeline System
    To provide effective oversight of the Nation's pipeline system, OPS 
must first know where the pipelines are located, the size and material 
type of the pipe, and the types of products being delivered. The 
Nation's pipeline system is an elaborate network of over 2 million 
miles of pipe moving millions of gallons of hazardous liquids and more 
than 55 billion cubic feet of natural gas daily. The pipeline system is 
composed of predominantly three segments--natural gas transmission 
pipelines, natural gas distribution pipelines, and hazardous liquid 
transmission pipelines--run by about 2,200 natural gas distribution and 
transmission pipeline operators and 220 operators of hazardous liquid 
pipelines (as seen in Table 1). Of the 2,200 operators of natural gas 
pipelines, there are approximately 1,300 operators of natural gas 
distribution pipelines and 880 operators of natural gas transmission 
pipelines. There are approximately 90 Federal and 400 state inspectors 
responsible for overseeing the operators' compliance with pipeline 
safety regulations.

                                 Table 1.--Pipeline System Facts and Description
----------------------------------------------------------------------------------------------------------------
 
----------------------------------------------------------------------------------------------------------------
System Segment                                Facts                  Segment Description
----------------------------------------------------------------------------------------------------------------
Natural Gas Transmission Pipelines            326,595 Miles          Lines used to gather and transmit natural
                                                                      gas from wellhead to distribution systems
----------------------------------------------------------------------------------------------------------------
Natural Gas Distribution Pipelines            1.8 Million Miles      Mostly local distribution lines
                                                                      transporting natural gas from transmission
                                                                      lines to residential, commercial, and
                                                                      industrial customers
----------------------------------------------------------------------------------------------------------------
Hazardous Liquid Transmission Pipelines       160,000 Miles          Lines primarily transporting products such
                                                                      as crude oil, diesel fuel, gasoline, and
                                                                      jet fuel
----------------------------------------------------------------------------------------------------------------
System Operators                              Facts                  Operators Description
----------------------------------------------------------------------------------------------------------------
Natural Gas Transmission Operators            880                    Large, medium, and small operators of
                                                                      natural gas transmission pipelines
----------------------------------------------------------------------------------------------------------------
Natural Gas Distribution Operators            1,300                  Large, medium, and small operators of
                                                                      natural gas distribution pipelines
----------------------------------------------------------------------------------------------------------------
Hazardous Liquid Operators                    220                    Approximately 70 large operators and 150
                                                                      small operators
----------------------------------------------------------------------------------------------------------------

    Originally, industry was reluctant to map the Nation's pipeline 
system, so Congress responded by requiring, in the 2002 Act, the 
mapping of hazardous liquid and natural gas transmission pipelines. In 
the past year, OPS completed the development of the national pipeline 
mapping system (NPMS). The NPMS is now fully operational and has mapped 
100 percent of the hazardous liquid (approximately 160,000 miles of 
pipeline) and natural gas transmission (more than 326,000 miles) 
pipeline systems operating in the United States. Congress excepted 
natural gas distribution pipelines from the mapping mandate, so OPS 
does not have mapping data on these pipelines.
    As a result of OPS and industry's mapping efforts, Government 
agencies and industry have access to reasonably accurate pipeline data 
for hazardous liquid and natural gas transmission pipelines in the 
event of emergency or potentially hazardous situation. The public also 
has access to contact information about pipeline operators within 
specified geographic areas.
Monitoring the Evolving Nature of IMP Implementation
    Hazardous liquid and natural gas transmission pipeline operators 
are in the early stages of implementing their IMPs. Safety baseline 
integrity inspections are just now being established systemwide--
starting with hazardous liquid pipelines--so there are no comparable 
benchmarks. Nevertheless, as they begin implementing their IMPs, there 
is not yet enough evidence available to evaluate the IMP's 
effectiveness in strengthening pipeline safety. However, there are 
early signs that the baseline integrity inspections are working well 
for operators of hazardous liquid pipelines, and there was clearly a 
need for such inspections.
    OPS is also in the early stages of overseeing the implementation of 
the operators' IMPs, starting with IMP assessments of operators of 
hazardous liquid pipelines. In doing so, OPS is challenged with 
monitoring the implementation of the IMPs of more than 1,100 hazardous 
liquid and natural gas transmission pipeline operators and assisting in 
the development of technologies to meet the requirements of the IMP for 
all sizes and shapes of pipelines and different threat detections.
Early Stages of Implementing Pipeline Operators' IMPs
    The operators' implementation of their IMPs is a lengthy process. 
Even though the IMP rules have been issued in their final form, they 
will not be fully implemented for up to 8 years. For example, as part 
of the rules requiring IMPs for operators of natural gas transmission 
pipelines, operators are required to begin baseline integrity 
inspections no later than June 17, 2004, with inspections completed no 
later than December 17, 2012.
    As operators begin implementing their IMPs, there are early signs 
that the baseline integrity inspections are working well for operators 
of hazardous liquid pipelines and that there was clearly a need for 
such inspections. So far, according to OPS, results from the operators' 
baseline integrity inspections in predominantly high-consequence areas 
show that more than 20,000 integrity threats were identified and 
remediated. These threats may not have been discovered during the 
operators' routine inspections. One of the most serious threats 
discovered was a case of corrosion where greater than 80 percent of the 
pipeline wall thickness had been lost. It has since been repaired. A 
lesser threat discovered was minor corrosion along a longitudinal seam.
    A key point to remember about the early baseline integrity 
inspection results for operators of hazardous liquid pipelines is that 
these 20,000 threats were discovered and remediated in less than 16 
percent (about 25,000 miles) of pipeline miles needing inspection. 
About 135,000 miles of hazard liquid pipeline still needs baseline 
integrity inspections.
    Although 20,000 threats were discovered in the first 25,000 miles, 
we cannot statistically project the number of threats that could be 
expected in the remaining 135,000 miles that still need baseline 
integrity inspections. We also cannot project the number of threats 
that could be expected in the more than 326,000 miles of natural gas 
transmission pipelines that have yet to receive baseline integrity 
inspections. Also, baseline integrity inspections will not be completed 
for several years and certain threats may be very time-sensitive, 
especially those to do with severe internal corrosion.
    OPS required hazardous liquid pipeline operators--the first segment 
of the industry required to implement the IMP--to first complete 
baseline integrity inspections of pipeline miles in high-consequence 
areas, as these areas are populated, unusually sensitive to 
environmental damage, or commercially navigable waterways. These 
pipelines present the highest risk of fatalities, injuries, and 
property damage should an accident occur.
    According to the American Petroleum Institute, nationwide there are 
approximately 160,000 miles of hazardous liquid pipelines, of which 
51,400 miles are located in high-consequence areas. As required by the 
IMP rule, 25,700 of the 51,400 miles (50 percent) should receive 
baseline inspections by September 30, 2004. OPS estimates, of the 
nearly 327,000 miles of natural gas transmission pipelines, 24,970 
miles are located in high consequence areas. But pipelines in high-
consequence areas represent only about 16 percent of the total miles 
(76,370 of 487,000 total miles) for both hazardous liquid and natural 
gas transmission pipelines \8\ and accidents that occur in non-high-
consequence areas can have catastrophic consequences, such as the 
deadly pipeline rupture, explosion, and fire near Carlsbad, New Mexico.
---------------------------------------------------------------------------
    \8\ The percentage of total miles in high consequence areas for 
hazardous liquid and natural gas transmission pipelines are early 
estimates and may change with the beginning of the pipeline operators' 
baseline integrity inspections.
---------------------------------------------------------------------------
    On August 19, 2000, a 30-inch-diameter natural gas transmission 
pipeline ruptured adjacent to the Pecos River near Carlsbad. The 
released gas ignited and burned for 55 minutes. Twelve members of a 
family who were camping under a concrete-decked steel bridge that 
supported the pipeline across the river were killed and their three 
vehicles destroyed. Two nearby steel suspension bridges for gas 
pipelines crossing the river were extensively damaged.
    During the investigation, NTSB investigators found the rupture was 
a result of severe internal corrosion that caused a reduction in pipe 
wall thickness to the point that the remaining metal could no longer 
contain the pressure within the pipe. The significance of this finding 
cannot be overstated, as corrosion is the second leading cause of 
pipeline accidents, and pipeline operators will need to forge ahead on 
their baseline integrity inspections.
Monitoring the Implementation of Pipeline Operators' IMPs
    OPS must now begin assessing whether the implementation of more 
than 1,100 hazardous liquid and natural gas transmission pipeline 
operators' IMPs were adequate. OPS must also perform ongoing oversight 
activities, such as inspecting new pipeline construction, monitoring 
research and development projects, and investigating pipeline 
accidents. To do so, OPS believes it will need to augment its own 
resources with those of the states to efficiently and effectively 
oversee the operators' IMPs.
    OPS is actively overseeing IMP implementation through its 
assessments of hazardous liquid pipeline operators' IMP plans. As of 
April 30, 2004, the 63 largest operators of hazardous liquid pipelines 
have undergone the initial IMP assessments. That leaves 157 more 
operators of hazardous liquid pipelines and 884 operators of natural 
gas transmission pipelines who will need initial IMP assessments.
    Monitoring the implementation of pipeline operators' IMPs will be 
an ongoing process. OPS IMP inspection teams, made up of Federal and 
state inspectors, spent approximately 2 weeks at each operator's 
headquarters reviewing results of integrity inspection and actions 
taken to address integrity threats, as well as overall IMP development 
and effectiveness. With about 1,041 pipeline operators who have not yet 
had an initial IMP assessment (at 2 weeks for each assessment), 
compounded by the fact that pipelines operators have up to 8 years to 
complete their baseline integrity inspections, the overall 
effectiveness of operators' IMPs in strengthening pipeline safety will 
not be known for years.
Advancing Threat Detection Technologies Is Fundamental to the Success 
        of Integrity Inspections
    As part of OPS's IMP rule, operators of hazardous liquid and 
natural gas transmission pipelines are required to inspect the 
integrity of their pipelines using smart pigs or an alternate equally 
effective method such as direct assessment. To date, OPS's integrity 
management assessments indicate that operators of hazardous liquids 
pipelines used smart pigs about 70 percent of the time to conduct their 
baseline integrity inspections and strongly favored the use of smart 
pigs over alternative inspection methods available under the IMP. 
Although there have been significant advances in smart pig technology, 
the current technology still cannot identify all pipeline integrity 
threats. Smart pigs currently in use can successfully detect and 
measure corrosion, dents, and wrinkles but are less reliable in 
detecting other types of mechanical damage. As a result, certain 
integrity threats go undetected and pipeline accidents may occur.
    For example, on July 30, 2003, an 8-inch diameter hazardous liquid 
pipeline ruptured near a residential area under development in Tucson, 
Arizona, releasing more than 10,000 gallons of gasoline and shutting 
down the supply of gasoline to the greater metropolitan Phoenix area 
for 2 days. Whether this rupture could have been prevented is still not 
known because the cause of the rupture, stress crack corrosion,\9\ 
rarely causes failure in hazardous liquid pipelines. Also, currently 
there are no tools or mechanisms small enough to fit in 8-inch diameter 
piping in order to identify the threat of stress crack corrosion.
---------------------------------------------------------------------------
    \9\ Stress crack corrosion (SCC), also known as environmentally 
assisted cracking, is a relatively new phenomenon. Instead of pits, SCC 
manifests itself as cracks that are minute in length and depth. Over 
time, individual cracks coalesce with other cracks and become longer.
---------------------------------------------------------------------------
    OPS's research and development (R&D) program is aimed at enhancing 
the safety and reducing the potential environmental effects of 
transporting natural gas and hazardous liquids through pipelines. 
Specifically, the program seeks to advance the most promising 
technological solutions to problems that imperil pipeline safety, such 
as damage to pipelines from excavation or corrosion. OPS sponsors R&D 
projects that focus on providing near-term solutions that will increase 
the safety, cleanliness, and reliability of the Nation's pipeline 
system.
    OPS's R&D funding has more than tripled, from $2.7 million in FY 
2001 to $8.7 million in FY 2003. Nearly $4 million of the $8.7 million 
is funding projects to improve the technologies used to inspect the 
integrity of pipeline systems in support of the IMP. OPS currently has 
22 active projects that explore a variety of ways to improve smart pig 
technologies, develop alternative inspection and detection technologies 
for pipelines that cannot accommodate smart pigs, and improve pipeline 
material performance. For example, OPS has a project underway that will 
improve the capabilities of smart pigs to better detect and measure 
both corrosion and mechanical damage. The expected project outcome is a 
smart pig that is simpler to build and use.
    The R&D challenge OPS now faces is seeing these projects through to 
completion, without undue delay and expense, to ensure that viable, 
reliable, cost-effective technologies become readily available to meet 
the demands of increased usage required under the IMP.
Monitoring Remediation of Pipeline Integrity Threats
    Much of the Nation's existing pipeline infrastructure is over 50 
years old. When pipeline integrity threats are identified, repairs may 
require Federal and state environmental reviews and permitting before 
the operator can proceed. However, OPS regulations identify repair 
criteria for the types of threats that must be repaired within 
specified time limits. At times, the environmental review and 
permitting processes become an obstacle that can delay the operators' 
remediation efforts.
    When it passed the Pipeline Safety Improvement Act of 2002, 
Congress recognized that timely repair of pipeline integrity threats 
was essential to the well-being of human health, public safety, and the 
environment. Therefore, Congress directed the President to establish an 
interagency committee to develop and ensure the implementation of a 
coordinated environmental review and permitting process. This process 
should allow pipeline operators to commence and complete all activities 
necessary to carry out pipeline repairs within any time periods 
specified under OPS's regulations.
Certain Pipeline Repairs Must Be Completed Within Specified Time Limits
    OPS regulations identify remediation criteria for the types of 
threats that must be repaired within specified time limits, the length 
of which reflects the probability of failure. For hazardous liquid 
pipelines, the three categories of repair are defined as immediate 
repair, 60 days to repair, and 180 days to repair. For example, a top 
dent with any indication of metal loss requires immediate response and 
action, whereas a bottom dent with any indication of metal loss 
requires a response and action within 60 days. Other types of threats 
include remediation activities that are not considered time-sensitive. 
Using the criteria, pipeline operators must characterize the type of 
repair required, evaluate the risk of failure, and make the repair 
within the defined time limit.
    Of the more than 20,000 threats that have been identified and 
remediated to date, more than 1,200 required immediate repair, 760 
required repairs within 60 days, and 2,400 required repairs within 180 
days. More than 16,300 threats fall into the category of other 
remediation activities that are not considered time-sensitive. OPS's 
remediation criteria encompass a broad range of actions, which include 
mitigative measures (such as reducing the pipeline pressure flow), as 
well as repairs that an operator can make to resolve an integrity 
threat. For immediate repairs, an operator must temporarily reduce 
operating pressure or shut down the pipeline until the operator 
completes the repair of the threat.
    The challenges inspectors face during a review of an operator's 
baseline integrity inspection results are to determine whether OPS's 
repair criteria were properly used to characterize the type of repair 
required for each threat identified and whether the operator's threat 
remediation plans are adequate to repair or mitigate the threat. More 
importantly, however, is that OPS will need to follow up to ensure that 
the operator has properly executed its remediation actions within the 
defined time limit.
Improvements Are Needed in Coordinating Federal and State Environmental 
        Reviews and Permitting Processes
    The transmission of energy through the Nation's pipeline system in 
a safe and environmentally sound manner is essential to the well-being 
of human health, public safety, and the environment. One way to do this 
is to develop and ensure implementation of a coordinated Federal and 
state environmental review and permitting process that will enable 
pipeline operators to complete pipeline repairs quickly. There will be 
mounting pressures to accelerate the environmental review and 
permitting processes, given the high number of threats found during the 
early stages of pipeline operators' baseline integrity inspections that 
must be repaired within specified time limits.
    The recent pipeline rupture in northern California demonstrates the 
perils of not being able to promptly repair pipeline threats. In April 
2004, a hazardous liquid pipeline ruptured in the Suisun Marsh south of 
Sacramento, California, releasing about 85,000 gallons of diesel fuel 
into 20 to 30 acres of marshland. Muskrats, beaver, and water fowl were 
affected by the spill. Fortunately, there were no human fatalities or 
injuries as a result of the rupture.
    The deteriorating condition of the pipeline that ruptured was well 
documented by the pipeline operator, who had reduced pipeline operating 
pressure to lessen the risk of a rupture and keep the flow of energy to 
users in Sacramento and Chico, California, and Reno, Nevada. The 
pipeline operator wanted to relocate the pipeline away from the Suisun 
Marsh and initiated actions to do so in 2001. However, the 
environmental review and permitting processes took far too long: nearly 
3 years and more than 40 permits in total. There is little doubt that 
the rupture would not have occurred had the permit process been 
quicker.
    The importance of accelerating the permit process, when necessary, 
cannot be overstated. As we have noted, results from the hazardous 
liquid pipeline operators' baseline integrity inspections in high-
consequence areas show that more than 20,000 integrity threats were 
identified for remediation. More than 1,200 threats required immediate 
repairs, 760 threats required repairs within 60 days, and 2,400 threats 
required repairs within 180 days. As operators continue with their 
baseline integrity inspections, the implications are that the number of 
integrity threats will continue to rise. According to OPS, repairs for 
other known pipeline threats are being delayed because of the 
environmental review and permitting processes, and they are best taken 
care of sooner rather than later, so as to prevent another incident 
like the Suisun March rupture.
    When it passed the 2002 Act, Congress recognized the need to 
expedite the environmental review and permitting process. Section 16 of 
the 2002 Act directed the President to establish an interagency 
committee that would implement a coordinated environmental review and 
permitting process so that pipeline repairs could be made within the 
time periods specified by IMP regulations.
    Committee activities were to include:

   An evaluation of Federal permitting requirements.

   Identification of best management practices to be used by 
        industry.

   The development of an MOU by December 17, 2003, (1 year 
        after the enactment of the 2002 Act) to provide for a 
        coordinated and expedited pipeline permit process that would 
        result in no more than minimal adverse effects on the 
        environment.

    The 2002 Act also requires the committee to consult with state and 
local environmental, pipeline safety, and emergency response officials, 
and requires the Secretary of Transportation to designate on ombudsman 
to assist in expediting the pipeline process and resolving 
disagreements over pipeline repairs between Federal, state, and local 
permitting agencies and the pipeline operator.
    To implement Section 16, the President issued an Executive Order in 
May 2003, establishing the Interagency Task Force and directed it to 
implement the committee activities. The Chairman of the Council on 
Environmental Quality chairs the Interagency Task Force, whose 
membership includes representatives from the Departments of 
Agriculture, Commerce, Defense, Energy, the Interior, and 
Transportation; the Environmental Protection Agency; the Federal 
Regulatory Commission; and the Advisory Council on Historic 
Preservation.
    Although an MOU has been drafted, it has not been finalized as of 
June 11, 2004. According to OPS, not all members of the Interagency 
Task Force have agreed to the provisions of the MOU, while other 
members believe that there are provisions in the Clean Air Act, Clean 
Water Act, the Endangered Species Act that prohibit them from taking 
any action to expedite the permitting process. Until the MOU is 
finalized, an evaluation of Federal permitting requirements and 
identification of best management practices to be used by industry will 
be further delayed.
    These issues need to be resolved by the Interagency Task Force. 
While the problem may not be easily resolved, Federal agencies must 
work together to accelerate the environmental review and permitting 
process to avoid failures like the Suisun Marsh rupture or even worse. 
If the Interagency Task Force set up to monitor and assist agencies in 
their efforts to expedite their review of permits cannot develop a 
method for expediting the environmental review and permit process so 
that pipeline repairs can be made before a serious consequence occurs, 
then it may be necessary for Congress to take action.
Closing the Safety Gap on Natural Gas Distribution Pipelines
    The 2002 Act requires that the operators of natural gas pipeline 
facilities implement IMPs. However, the IMP requirement applies only to 
natural gas transmission pipelines and not to natural gas distribution 
pipelines.
    As part of the IMP, operators of hazardous liquid and natural gas 
transmission pipelines are required to inspect the integrity of their 
pipelines using one or more of the following inspection methods: smart 
pigs, pressure testing, or direct assessment.\10\ According to 
officials of the American Gas Association, the initial reason why IMPs 
were not required for natural gas distribution pipelines is that 
distribution pipelines cannot be inspected using smart pigs. The smart 
pig technologies currently available cannot be used in natural gas 
distribution pipelines because the majority of distribution piping is 
too small in diameter (1 to 6 inches) and has multiple bends and 
material types intersecting over very short distances.
---------------------------------------------------------------------------
    \10\ Operators can choose another technology that demonstrates an 
equivalent understanding of the integrity of the pipeline but only 
after notifying OPS before the inspection begins.
---------------------------------------------------------------------------
    The IMP is a risk-management tool designed to improve safety, 
environmental protection, and reliability of pipeline operations. That 
natural gas distribution pipelines cannot be internally inspected using 
smart pigs is not by itself a sufficient reason for not requiring 
operators of natural gas distribution pipelines to have IMPs. Other 
elements of the IMP can be readily applied to this segment of the 
industry, including but not limited to (1) a process for continual 
integrity assessment and evaluation, (2) an analytical process that 
integrates all available information about pipeline integrity and the 
consequences of failure, and (3) repair criteria to address issues 
identified by the integrity assessment and data analysis.
Natural Gas Distribution Pipeline Safety Concerns
    Our concern is that the Department's strategic safety goal is to 
reduce the number of transportation-related fatalities and injuries, 
but natural gas distribution pipelines are not achieving this goal. In 
the 10-year period from 1994 through 2003, OPS's data show accidents in 
natural gas distribution pipelines have caused more than 4 times the 
number of fatalities (174 fatalities) and more than 3.5 times the 
number of injuries (662 injuries) when compared to a combined total of 
43 fatalities and 178 injuries associated with hazardous liquid and gas 
transmission pipeline accidents combined.
    Accidents involving natural gas distribution pipelines can be as 
catastrophic as accidents involving hazardous liquids or natural gas 
transmission pipelines. For example, on December 11, 1998, in downtown 
St. Cloud, Minnesota, a communications crew ruptured an underground 
natural gas distribution pipeline, causing an explosion that killed 4 
people, seriously injured 1, and injured 10 others. Six buildings were 
destroyed. In another example, in July 2002, a gas explosion in a 
multiple-family dwelling in Hopkinton, Massachusetts, killed 2 children 
and injured 14 others.
    In the past 3 years, the number of fatalities and injuries from 
accidents involving natural gas distribution pipelines has increased 
while the number of fatalities and injuries from accidents involving 
hazardous liquid and natural gas transmission pipelines has held steady 
or declined. OPS's data show that fatalities and injuries from 
accidents involving natural gas distribution pipelines increased from 5 
fatalities and 46 injuries in 2001 to 11 fatalities and 58 injuries in 
2003. For the same period, fatalities and injuries from accidents 
involving hazardous liquid and natural gas transmission pipelines 
decreased from 2 fatalities and 15 injuries in 2001 to 1 fatality and 
13 injuries in 2003.
    Although OPS has moved forward with initiatives \11\ to enhance the 
safety of natural gas distribution pipelines, OPS needs to ensure that 
the pace of its efforts moves quickly enough, given the upward trend in 
fatalities and injuries involving these pipelines and the projected 
increase in distribution pipelines to meet the increasing demand for 
natural gas.
---------------------------------------------------------------------------
    \11\ With OPS support, the American Gas Foundation is sponsoring a 
study to assess the Nation's gas distribution infrastructure that will 
evaluate safety performance, current operating and regulatory 
practices, and emerging technologies.
---------------------------------------------------------------------------
    OPS should require operators of natural gas distribution pipelines 
to implement some form of pipeline integrity management or enhanced 
safety program with the same or similar integrity management elements, 
except pigging, as the hazardous liquid and natural gas transmission 
pipelines. This would be consistent with OPS's risk-based approach to 
overseeing pipeline safety by using IMPs to reduce the risk of 
accidents that may cause injuries or fatalities to people living or 
working near natural gas distribution pipelines, as well as to reduce 
property damage.
Developing an Approach To Overseeing Pipeline Security
    The focus of our recently completed review was pipeline safety. 
However, given the importance of protecting the Nation's infrastructure 
of pipeline systems, we also reviewed OPS's involvement in the security 
of the pipeline systems.
OPS's Security Efforts Following September 11, 2001
    Following the events of September 11, 2001, OPS moved forward on 
several fronts to help reduce the risk of terrorist activity against 
the Nation's pipeline infrastructure, such as opening the lines of 
communication among Federal and state agencies responsible for 
protecting the Nation's critical infrastructure, including pipelines; 
conducting pipeline vulnerability assessments and identifying critical 
pipeline systems; developing security standards and guidance for 
security programs; and working with Government and industry to help 
ensure rapid response and recovery of the pipeline system in the event 
of a terrorist attack.
    To protect the Nation's pipeline infrastructure, OPS issued new 
security guidance to pipeline operators nationwide in September 2002. 
In the guidance, OPS requested that all operators develop security 
plans to prevent unauthorized access to pipelines and identify critical 
facilities that are vulnerable to a terrorist attack. OPS also asked 
operators to submit a certification letter stating that the security 
plan had been implemented and that critical facilities had been 
identified. During 2003, OPS in conjunction with the DHS's TSA started 
reviewing operator security plans. The plans reviewed have been judged 
responsive to the OPS guidance.
    Unlike its pipeline safety program, OPS's security guidance is not 
mandatory: industry's participation in a security program is strictly 
voluntary and cannot be enforced unless a regulation is issued to 
require industry compliance. In fact, it is still unclear what agency 
or agencies will have responsibility for pipeline security rulemaking, 
oversight, and enforcement. Although OPS took the lead to help reduce 
the risk of terrorist activity against the Nation's pipeline 
infrastructure following the events of September 11, 2001, OPS has 
stated it now plays a secondary, or support, role to TSA, the agency 
with primary responsibility for ensuring the security of the Nation's 
transportation system, including pipelines.
Recent Initiatives Clarifying Security Responsibilities
    Certain steps have been taken to establish what agency or agencies 
would be responsible for ensuring the security of the Nation's critical 
infrastructure, including pipelines. For example, in December 2003, 
Homeland Security Presidential Directive/HSPD-7 (HSPD-7):

   Assigned the DHS the responsibility for coordinating the 
        overall national effort to enhance the protection of the 
        Nation's critical infrastructure and key resources.

   Assigned DOE the responsibility for ensuring the security of 
        the Nation's energy, including the production, refining, 
        storage, and distribution of oil and gas.

   Directed DOT and DHS to collaborate on all matters relating 
        to transportation security and transportation infrastructure 
        protection and to regulating the transportation of hazardous 
        materials by all modes, including pipelines.

    Although HSPD-7 directs DOT and DHS to collaborate in regulating 
the transportation of hazardous materials by all modes, including 
pipelines, it is not clear from an operational perspective what ``to 
collaborate'' encompasses, and it is also not clear what OPS's 
relationship will be with DOE. The delineation of roles and 
responsibilities between DOT and DHS needs to spelled out by executing 
an MOU or a Memorandum of Agreement. OPS also needs to seek 
clarification on the delineation of roles and responsibilities between 
itself and DOE.
    Mr. Chairman, this concludes my statement. I will be pleased to 
answer any questions that you might have.

    The Chairman. Thank you very much.
    Ms. Siggerud, welcome.

           STATEMENT OF KATHERINE SIGGERUD, DIRECTOR,

                PHYSICAL INFRASTRUCTURE ISSUES,

                 U.S. GENERAL ACCOUNTING OFFICE

    Ms. Siggerud. Thank you, Mr. Chairman and Members of the 
Committee, for the invitation to testify at this hearing on 
oversight of the Office of Pipeline Safety.
    The information I will present today is based on our 
ongoing work looking at OPS's enforcement policy and practices. 
As you know, this work was required by the Pipeline Safety 
Improvement Act of 2002, and we will be issuing a full report 
on our work next month.
    Pipeline transportation remains the safest form of freight 
transportation, and OPS has been taking a number of steps, 
including a more aggressive enforcement posture, to make 
pipelines safer. Enforcing pipeline safety standards and taking 
action against violators is an important part of OPS's efforts 
to prevent accidents. Therefore, my testimony today will cover 
two topics. First, the effectiveness of OPS's enforcement 
strategy, and, second, OPS's assessment of monetary sanctions, 
often called civil penalties, against interstate pipeline 
operators that violate Federal pipeline safety rules.
    But before I address these two topics, let me put OPS's 
enforcement program in context. Over the past several years, 
OPS has been developing and implementing the risk- based 
approach that it believes will fundamentally improve pipeline 
safety. This approach, which my fellow witnesses have 
mentioned, is called integrity management. It requires 
interstate pipeline operators to identify and address safety-
related threats to their pipelines in areas where an accident 
could have the greatest consequences. According to OPS, this 
approach has more potential to improve safety than its 
traditional approach, which focused on compliance, but not so 
much on threats. OPS emphasizes that integrity management 
coupled with other initiatives can change the safety culture of 
the industry and drive down the number of accidents.
    Now that these initiatives are substantially underway, OPS 
is planning to improve the management of its enforcement 
program. Accordingly, my testimony today focuses on potential 
management improvements that should be useful to OPS as it 
decides how to proceed, and to this Committee as it continues 
to exercise oversight over this program.
    Let me turn now to my first topic, the effectiveness of 
OPS's enforcement strategy. We've found that definitive 
information on the strategy's effectiveness is not available 
because OPS has not yet incorporated three key elements of 
effective program management. First, OPS has not established 
goals that specify the intended results of the new, more 
aggressive strategy it has had in place since 2000. Second, OPS 
has not developed a policy that describes the strategy and the 
strategy's contribution to pipeline safety. Finally, OPS has 
not put measures in place that would allow it to determine and 
demonstrate the effects of this new strategy on the industry's 
compliance. Without these three key elements, OPS cannot 
determine whether recent and planned changes in its enforcement 
strategy are having, or will have, the desired effects.
    OPS is developing an enforcement policy that will help 
define the strategy. It has also begun to identify new measures 
of enforcement performance. OPS plans to finalize this policy 
sometime in 2005. However, it still needs to link its 
performance measures to program goals, a key element of 
effective program management.
    One component of enforcement, OPS's assessment of civil 
penalties, is my second topic for today. Here, OPS is taking a 
more aggressive approach, imposing more and larger penalties 
than it did in the late 1990s. At that time, its policy was to 
partner with industry, and we and others expressed concern 
about a significant decrease in OPS's use of civil penalties. 
We found that, from 2000 through 2003, OPS increased its 
assessment of civil penalties to an average of 22 penalties a 
year, with an average of 14 penalties a year from 1995 through 
1999. The average size of civil penalties also increased to 
about $29,000 during the more recent years, compared with an 
average of around $18,000 during the earlier years.
    Pipeline safety stakeholders express differing views on 
whether OPS's increased use of civil penalties will help deter 
noncompliance with the pipeline safety regulations. Some of 
those we spoke with, such as pipeline industry officials, said 
that civil penalties of any size, or any other kind of 
enforcement action, act as a deterrent in part because they 
keep the companies in the public eye. Others, such as some of 
the pipeline safety advocacy groups, said that civil penalties 
may be too small to deter noncompliance.
    Finally, we found that DOT had, in fact, collected most of 
the civil penalties that OPS assessed over the past 10 years. 
Data show that operators have paid 94 percent of the assessed 
civil penalties. However, we found some gaps in communication 
between OPS and its collection agent about which penalties 
should be collected and which already had been collected. In 
light of the issues raised in my statement today, we are 
considering recommendations that could, first, enable OPS to 
demonstrate to the Congress that it has an effective 
enforcement strategy, and, second, remedy the problems we 
identified in OPS's collection of civil penalties.
    Mr. Chairman, this concludes my statement, and I am happy 
to answer any questions.
    [The prepared statement of Ms. Siggerud follows:]

                             GAO Highlights
Why GAO Did This Study
    Interstate pipelines carrying natural gas and hazardous liquids 
(such as petroleum products) are safer to the public than other modes 
of freight transportation. The Office of Pipeline Safety (OPS), the 
Federal agency that administers the national regulatory program to 
ensure safe pipeline transportation, has been undertaking a broad range 
of activities to make pipeline transportation safer. However, the 
number of serious accidents--those involving deaths, injuries,and 
property damage of $50,000 or more--has not fallen. Among other things, 
OPS takes enforcement action against pipeline operators when safety 
problems are found. OPS has several enforcement tools to require the 
correction of safety violations. It can also assess monetary sanctions 
(civil penalties).
    This testimony is based on ongoing work for the Senate Committee on 
Commerce, Science and Transportation and for other committees, as 
required by the Pipeline Safety Improvement Act of 2002. The testimony 
provides preliminary results on (1) the effectiveness of OPS's 
enforcement strategy and (2) OPS's assessment of civil penalties.
What GAO Recommends
    GAO expects to issue a report in July 2004 that will address these 
and other topics and anticipates making recommendations.
                            Pipeline Safety
Preliminary Information on the Office of Pipeline Safety's Enforcement 
        Activities
What GAO Found
    The effectiveness of OPS's enforcement strategy cannot be 
determined because the agency has not incorporated three key elements 
of effective program management--clear program goals, a well-defined 
strategy for achieving goals, and performance measures that are linked 
to program goals. (See below.) Without these key elements, the agency 
cannot determine whether recent and planned changes in its strategy 
will have the desired effects on pipeline safety. Over the past several 
years, OPS has focused on other efforts--such as developing a new risk-
based regulatory approach--that it believes will change the safety 
culture of the industry. While OPS has become more aggressive in 
enforcing its regulations, it now intends to further strengthen the 
management of its enforcement program. In particular, OPS is developing 
an enforcement policy that will help define its enforcement strategy 
and has taken initial steps toward identifying new performance 
measures. However, OPS does not plan to finalize the policy until 2005 
and has not adopted key practices for achieving successful performance 
measurement systems, such as linking measures to goals.


    OPS increased both the number and the size of the civil penalties 
it assessed against pipeline operators over the last 4 years (2000-
2003) following its decision to be ``tough but fair'' in assessing 
penalties. OPS assessed an average of 22 penalties per year during this 
period, compared with an average of 14 per year for the previous 5 
years (1995-1999), a period of more lenient ``partnering'' with 
industry. In addition, the average penalty increased from $18,000 to 
$29,000 over the two periods. About 94 percent of the 216 penalties 
levied from 1994 through 2003 have been paid. The civil penalty is one 
of several actions OPS can take when it finds a violation, and these 
penalties represent about 14 percent of all enforcement actions over 
the past 10 years. While OPS has increased the number and size of civil 
penalties, stakeholders--including industry, state, and insurance 
company officials and public advocacy groups--expressed differing views 
on whether these penalties deter noncompliance with safety regulations. 
Some, such as pipeline operators, thought that any penalty was a 
deterrent if it kept the pipeline operator in the public eye, while 
others, such as safety advocates, told us that the penalties were too 
small to be effective sanctions.
                                 ______
                                 
     Prepared Statement of Katherine Siggerud, Director, Physical 
     Infrastructure Issues, United States General Accounting Office
    Mr. Chairman and Members of the Committee:

    We appreciate the opportunity to participate in this hearing on the 
oversight of the Office of Pipeline Safety (OPS). As you know, pipeline 
transportation for hazardous liquids and natural gas is the safest form 
of freight transportation, and OPS has taken many steps to make it 
safer.\1\ However, the number of serious hazardous liquid accidents has 
stayed about the same while the number of serious natural gas accidents 
has increased.\2\ (See fig. 1.) Finally, the serious accident rate--
which considers the amount of product and distance shipped--for 
hazardous liquids has decreased. None of these statistics show a 
constant pattern. In part, the lack of significant change over time and 
the fluctuation over time may be due to the relatively small number of 
serious accidents--an average of about 150 per year for both types 
combined.
---------------------------------------------------------------------------
    \1\ Hazardous liquid pipelines carry products such as crude oil, 
diesel fuel, gasoline, jet fuel, anhydrous ammonia, and carbon dioxide.
    \2\ Serious accidents are those resulting in a death, injury, or 
$50,000 or more in property damage.


    Notes: This figure does not include the injuries that occurred 
during one series of accidents caused by severe flooding near Houston, 
Texas, in October 1994.
    The accident rate is the number of serious accidents per billion 
ton-miles shipped. (A ton-mile is 1 ton of a product shipped 1 mile.)
    The accident rates are based on the volume of petroleum products 
shipped. Federal agencies and industry associations we contacted could 
not provide data on other hazardous liquids shipped. Aggregated 
industry data on the amounts of products shipped through hazardous 
liquid pipelines for 2002 and 2003 are not available so we do not 
present accident rate information for those years. We are inquiring 
into the availability of data on natural gas shipped through interstate 
pipelines; these data are needed to calculate the accident rates for 
this type of pipeline.

    A cornerstone to OPS's efforts over the past several years has been 
the agency's development and implementation of a risk-based approach 
that it believes will fundamentally improve the safety of pipeline 
transportation. This approach, called integrity management, requires 
interstate pipeline operators to identify and fix safety-related 
threats to their pipelines in areas where an accident could have the 
greatest consequences. OPS believes that this approach has more 
potential to improve safety than its traditional approach, which 
focused on enforcing compliance with safety standards regardless of the 
threat to pipeline safety. Officials have emphasized that integrity 
management, coupled with other initiatives, such as oversight of 
operators' programs to qualify employees to operate their pipelines, 
represents a systematic approach to overseeing and improving pipeline 
safety that will change the safety culture of the industry and drive 
down the number of accidents.
    Now that its integrity management approach and other initiatives 
are substantially under way, OPS recognizes that it needs to turn its 
attention to the management of its enforcement program. Accordingly, my 
testimony today focuses on opportunities for improving certain aspects 
of OPS's enforcement program that should be useful to OPS as it decides 
how to proceed and to this committee as it continues to exercise 
oversight.
    My statement is based on the preliminary results of our ongoing 
work for this committee and others. As directed by the Pipeline Safety 
Improvement Act of 2002, we have been (1) evaluating the effectiveness 
of OPS's enforcement strategy and (2) examining OPS's assessment of 
monetary sanctions (called civil penalties) against interstate pipeline 
operators that violate Federal pipeline safety rules. We expect to 
report on the results of our work on these and other issues next month.
    Our work is based on our review of laws, regulations, program 
guidance, and discussions with OPS officials and a broad range of 
stakeholders.\3\ To evaluate the effectiveness of OPS's enforcement 
strategy, we determined the extent to which the agency's strategy 
incorporates three key elements of effective program management: clear 
program goals, a well-defined strategy for achieving goals, and 
measures of performance that are linked to program goals. We also 
examined how OPS assessed civil penalties from 1994 through 2003 and 
the extent to which pipeline operators have paid them. Finally, we 
interviewed stakeholders on whether OPS's civil penalties help deter 
safety violations. As part of our work, we assessed internal controls 
and the reliability of the data elements needed for this engagement, 
and we determined that the data elements, with one exception, were 
sufficiently reliable for our purposes.\4\ We performed our work in 
accordance with generally accepted government auditing standards.
---------------------------------------------------------------------------
    \3\ These stakeholders represent industry trade associations, 
pipeline companies, Federal enforcement agencies, state pipeline 
enforcement agencies and associations, pipeline safety advocacy groups, 
and pipeline insurers.
    \4\ The data elements needed to determine when civil penalties were 
paid were, in our opinion, too unreliable to use to report on 
timeliness of payments. This limitation did not create a major 
impediment to our reporting on OPS's use of civil penalties overall.
---------------------------------------------------------------------------
    In summary:

   The effectiveness of OPS's enforcement strategy cannot be 
        evaluated because the agency has not incorporated three key 
        elements of effective program management--clear program goals, 
        a well-defined strategy for achieving those goals, and measures 
        of performance that are linked to the program goals. Without 
        these three key elements, OPS cannot determine whether recent 
        and planned changes in its enforcement strategy are having or 
        will have the desired effects on pipeline safety. Under a more 
        aggressive enforcement strategy (termed ``tough but fair'') 
        that OPS initiated in 2000, the agency is using the full range 
        of its enforcement tools, rather than relying primarily as it 
        did before on more lenient administrative actions, such as 
        warning letters. However, OPS has not established goals that 
        specify the intended results of this new strategy, developed a 
        policy that describes the strategy and the strategy's 
        contribution to pipeline safety, or put measures in place that 
        would allow OPS to determine and demonstrate the effects of 
        this strategy on pipeline safety. OPS is developing an 
        enforcement policy that will help define its enforcement 
        strategy and has taken some initial steps toward identifying 
        new measures of enforcement performance. However, it does not 
        anticipate finalizing this policy until sometime in 2005 and 
        has not adopted key practices for achieving successful 
        performance measurement systems, such as linking measures to 
        program goals.

   OPS increased both the number and the size of the civil 
        penalties it assessed in response to criticism that its 
        enforcement activities were weak and ineffective. For example, 
        from 2000 through 2003, following its decision to be tough but 
        fair in assessing civil penalties, OPS assessed an average 22 
        penalties per year, compared with an average of 14 penalties 
        per year from 1995 through 1999, when OPS's policy was to 
        ``partner'' with industry, rather than primarily to enforce 
        compliance. In addition, from 2000 through 2003, OPS assessed 
        an average civil penalty of about $29,000, compared with an 
        average of $18,000 from 1995 through 1999. Departmental data 
        show that operators have paid 94 percent (202 of 216) of the 
        civil penalties issued over the past 10 years. Civil penalties 
        are one of several enforcement actions that OPS can take to 
        increase compliance and represent about 14 percent of all 
        enforcement actions taken over the past 10 years. Although OPS 
        has increased both the number and the size of its civil 
        penalties, it is not clear whether this action will help deter 
        noncompliance with the agency's safety regulations. The 
        pipeline safety stakeholders we spoke with expressed differing 
        views on whether OPS's civil penalties deter noncompliance with 
        the pipeline safety regulations. Some--such as pipeline 
        industry officials--said that civil penalties of any size act 
        as a deterrent, in part because they keep companies in the 
        public eye. Others--such as pipeline safety advocacy groups--
        said that OPS's civil penalties are too small to deter 
        noncompliance.
Background
    OPS, within the Department of Transportation's Research and Special 
Programs Administration (RSPA), administers the national regulatory 
program to ensure the safe transportation of natural gas and hazardous 
liquids by pipeline.\5\ The office attempts to ensure the safe 
operation of pipelines through regulation, national consensus 
standards, research, education (e.g., to prevent excavation-related 
damage), oversight of the industry through inspections, and enforcement 
when safety problems are found.\6\
---------------------------------------------------------------------------
    \5\ In general, OPS retains full responsibility for inspecting 
interstate pipelines and enforcing regulations applicable to them. OPS 
certifies states to perform these functions for intrastate pipelines. 
OPS has agreements with 11 state pipeline enforcement agencies, known 
as interstate agents, to help it inspect segments of interstate 
pipelines within these states' boundaries. However, OPS undertakes any 
enforcement actions identified through inspections conducted by 
interstate agents. 6Standards are technical specifications that pertain 
to products and processes, such as the size, strength, or technical 
performance of a product. National consensus standards are developed by 
standard-setting entities, such as the American Society for Testing and 
Materials, on the basis of an industry consensus.
    \6\ Standards are technical specifications that pertain to products 
and processes, such as the size, strength, or technical performance of 
a product. National consensus standards are developed by standard-
setting entities, such as the American Society for Testing and 
Materials, on the basis of an industry consensus.
---------------------------------------------------------------------------
    In general, OPS retains full responsibility for inspecting 
interstate pipelines and enforcing regulations applicable to them. OPS 
certifies states to perform these functions for intrastate pipelines. 
OPS has agreements with 11 state pipeline enforcement agencies, known 
as interstate agents, to help it inspect segments of interstate 
pipelines within these states' boundaries. However, OPS undertakes any 
enforcement actions identified through inspections conducted by 
interstate agents.
    The office uses a variety of enforcement tools, such as compliance 
orders and corrective action orders that require pipeline operators to 
correct safety violations, notices of amendment to remedy deficiencies 
in operators' procedures, administrative actions to address minor 
safety problems, and civil penalties. OPS is a small Federal agency. In 
Fiscal Year 2003, OPS employed about 150 people, about half of whom 
were pipeline inspectors.
    Before imposing a civil penalty on a pipeline operator, OPS issues 
a notice of probable violation that documents the alleged violation and 
a notice of proposed penalty that identifies the proposed civil penalty 
amount. Failure by an operator to inspect the pipeline for leaks or 
unsafe conditions is an example of a violation that may lead to a civil 
penalty. OPS then allows the operator to present evidence either in 
writing or at an informal hearing. Attorneys from RSPA's Office of 
Chief Counsel preside over these hearings. Following the operator's 
presentation, the civil penalty may be reaffirmed, reduced, or 
withdrawn. If the hearing officer determines that a violation did 
occur, the Office of Chief Counsel issues a final order that requires 
the operator to correct the safety violation (if a correction is 
needed) and pay the penalty (called the ``assessed penalty''). The 
operator has 20 days after the final order is issued to pay the 
penalty. The Federal Aviation Administration (FAA) collects civil 
penalties for OPS.\7\
---------------------------------------------------------------------------
    \7\ To consolidate its accounting functions, in September 1993 RSPA 
began contracting with FAA to collect its accounts receivable, 
including civil penalties for OPS.
---------------------------------------------------------------------------
    From 1992 through 2002, Federal law allowed OPS to assess up to 
$25,000 for each day a violation continued, not to exceed $500,000 for 
any related series of violations. In December 2002, the Pipeline Safety 
Improvement Act increased these amounts to $100,000 and $1 million, 
respectively.
Key Management Elements Are Needed to Determine the Effectiveness of 
        OPS's Enforcement Strategy
    The effectiveness of OPS's enforcement strategy cannot be 
determined because OPS has not incorporated three key elements of 
effective program management--clear performance goals for the 
enforcement program, a fully defined strategy for achieving these 
goals, and performance measures linked to goals that would allow an 
assessment of the enforcement strategy's impact on pipeline safety.
OPS's Enforcement Strategy Has Been Evolving
    OPS's enforcement strategy has undergone significant changes in the 
last 5 years. Before 2000, the agency emphasized partnering with the 
pipeline industry to improve pipeline safety rather than punishing 
noncompliance. In 2000, in response to concerns that its enforcement 
was weak and ineffective, the agency decided to institute a ``tough but 
fair'' enforcement approach and to make greater use of all its 
enforcement tools, including larger and more frequent civil 
penalties.\8\ In 2001, to further strengthen its enforcement, OPS began 
issuing more corrective action orders requiring operators to address 
safety problems that led or could lead to pipeline accidents. In 2002, 
OPS created a new Enforcement Office to focus more on enforcement and 
help ensure consistency in enforcement decisions. However, this new 
office is not yet fully staffed, and key positions remain vacant.
---------------------------------------------------------------------------
    \8\ For example, in May 2000, we reported that OPS had dramatically 
reduced its use of civil penalties and increased its use of 
administrative actions over the years without assessing the effects of 
these actions. See Pipeline Safety: Office of Pipeline Safety Is 
Changing How It Oversees the Pipeline Industry, GAO/RCED-00-128 
(Washington, D.C.: May 15, 2000).
---------------------------------------------------------------------------
    In 2002, OPS began to enforce its new integrity management and 
operator qualification standards in addition to its minimum safety 
standards. Initially, while operators were gaining experience with the 
new, complex integrity management standards, OPS primarily used notices 
of amendment, which require improvements in procedures, rather than 
stronger enforcement actions. Now that operators have this experience, 
OPS has begun to make greater use of civil penalties in enforcing these 
standards.
    OPS has also recently begun to reengineer its enforcement program. 
Efforts are under way to develop a new enforcement policy and 
guidelines, develop a streamlined process for handling enforcement 
cases, modernize and integrate the agency's inspection and enforcement 
databases, and hire additional enforcement staff. However, as I will 
now discuss, OPS has not put in place key elements of effective 
management that would allow it to determine the impact of its evolving 
enforcement program on pipeline safety.
OPS Needs Goals for its Enforcement Program
    Although OPS has overall performance goals, it has not established 
specific goals for its enforcement program. According to OPS officials, 
the agency's enforcement program is designed to help achieve the 
agency's overall performance goals of (1) reducing the number of 
pipeline accidents by 5 percent annually and (2) reducing the amount of 
hazardous liquid spills by 6 percent annually.\9\ Other agency 
efforts--including the development of a risk-based approach to finding 
and addressing significant threats to pipeline safety and of education 
to prevent excavation-related damage to pipelines--are also designed to 
help achieve these goals.
---------------------------------------------------------------------------
    \9\ OPS refers to the release of natural gas from a pipeline as an 
``incident'' and a spill from a hazardous liquid pipeline as an 
``accident.'' For simplicity, this testimony refers to both as 
``accidents.''
---------------------------------------------------------------------------
    OPS's overall performance goals are useful because they identify 
the end outcomes, or ultimate results, that OPS seeks to achieve 
through all its efforts. However, OPS has not established performance 
goals that identify the intermediate outcomes, or direct results, that 
OPS seeks to achieve through its enforcement program. Intermediate 
outcomes show progress toward achieving end outcomes. For example, 
enforcement actions can result in improvements in pipeline operators' 
safety performance--an intermediate outcome that can then result in the 
end outcome of fewer pipeline accidents and spills. OPS is considering 
establishing a goal to reduce the time it takes the agency to issue 
final enforcement actions. While such a goal could help OPS improve the 
management of the enforcement program, it does not reflect the various 
intermediate outcomes the agency hopes to achieve through enforcement. 
Without clear goals for the enforcement program that specify intended 
intermediate outcomes, agency staff and external stakeholders may not 
be aware of what direct results OPS is seeking to achieve or how 
enforcement efforts contribute to pipeline safety.
OPS Needs to Fully Define Its Enforcement Strategy
    OPS has not fully defined its strategy for using enforcement to 
achieve its overall performance goals. According to OPS officials, the 
agency's increased use of civil penalties and corrective action orders 
reflects a major change in its enforcement strategy. However, although 
OPS began to implement these changes in 2000, it has not yet developed 
a policy that defines this new, more aggressive enforcement strategy or 
describes how it will contribute to the achievement of its performance 
goals. In addition, OPS does not have up-to-date, detailed internal 
guidelines on the use of its enforcement tools that reflect its current 
strategy. Furthermore, although OPS began enforcing its integrity 
management standards in 2002 and received greater enforcement authority 
under the 2002 pipeline safety act, it does not yet have guidelines in 
place for enforcing these standards or implementing the new authority 
provided by the act.\10\
---------------------------------------------------------------------------
    \10\ We have reported on challenges that OPS faces in enforcing its 
complex integrity management requirements consistently and effectively. 
See our August 2002 report, Pipeline Safety and Security: Improved 
Workforce Planning and Communication Needed, GAO-02-785 (Washington, 
D.C.: Aug. 26, 2002).
---------------------------------------------------------------------------
    According to agency officials, OPS management communicates 
enforcement priorities and ensures consistency in enforcement decisions 
through frequent internal meetings and detailed inspection protocols 
and guidance. Agency officials recognize the need to develop an 
enforcement policy and up-to-date detailed enforcement guidelines and 
have been working to do so. To date, the agency has completed an 
initial set of enforcement guidelines for its operator qualification 
standards and has developed other draft guidelines. However, because of 
the complexity of the task, agency officials do not expect that the new 
enforcement policy and remaining guidelines will be finalized until 
sometime in 2005.
    The development of an enforcement policy and guidelines should help 
define OPS's enforcement strategy; however, it is not clear whether 
this effort will link OPS's enforcement strategy with intermediate 
outcomes, since agency officials have not established performance goals 
specifically for their enforcement efforts. We have reported that such 
a link is important.\11\
---------------------------------------------------------------------------
    \11\ See U.S. General Accounting Office, Managing for Results: 
Strengthening Regulatory Agencies' Performance Management Practices, 
GAO/GGD-00-10 (Washington, D.C.: Oct. 28, 1999); Agency Performance 
Plans: Examples of Practices That Can Improve Usefulness to 
Decisionmakers, GAO/GGD/AIMD-99-69 (Washington, D.C.: Feb. 26, 1999); 
and The Results Act: An Evaluator's Guide to Assessing Agency Annual 
Performance Plans, GAO/GGD-10.1.20 (Washington, D.C., Apr. 1998).
---------------------------------------------------------------------------
OPS Needs Adequate Measures of the Effectiveness of Its Enforcement 
        Strategy
    According to OPS officials, the agency currently uses three 
performance measures and is considering three additional measures to 
determine the effectiveness of its enforcement activities and other 
oversight efforts. (See table 1.) The three current measures provide 
useful information about the agency's overall efforts to improve 
pipeline safety, but do not clearly indicate the effectiveness of OPS's 
enforcement strategy because they do not measure the intermediate 
outcomes of enforcement actions that can contribute to pipeline safety, 
such as improved compliance. The three measures that OPS is considering 
could provide more information on the intermediate outcomes of the 
agency's enforcement strategy, such as the frequency of repeat 
violations and the number of repairs made in response to corrective 
action orders, as well as other aspects of program performance, such as 
the timeliness of enforcement actions.\12\
---------------------------------------------------------------------------
    \12\ In addition, measures of pipeline operator integrity 
management performance and of the results of integrity management and 
operator qualification inspections could provide information on the 
intermediate outcomes of these regulatory approaches.

  Table 1: Enforcement Program Performance Measures That OPS Currently
                   Uses and Is Considering Developing
------------------------------------------------------------------------
         Measure                             Examples
------------------------------------------------------------------------
                       Measures OPS currently uses
------------------------------------------------------------------------
Achievement of agency     Annual numbers of natural gas and hazardous
 performance goals         liquid pipeline accidents and tons of
                           hazardous liquid materials spilled per
                           million ton-miles shipped.
------------------------------------------------------------------------
Inspection and            Number of inspections completed; hours per
 enforcement activity      inspection; accident investigations;
                           enforcement actions taken, by type; and
                           average proposed civil penalty amounts.
------------------------------------------------------------------------
Integrity management      Annual numbers of accidents in areas covered
 performance               by integrity management standards and of
                           actions by pipeline operators in response to
                           these standards, such as repairs completed
                           and miles of pipeline assessed.a
------------------------------------------------------------------------
                 Measures OPS is considering developing
------------------------------------------------------------------------
Management of             The time taken to issue final enforcement
 enforcement actions       actions, the extent to which penalty amounts
                           are reduced, and the extent to which
                           operators commit repeat violations.
------------------------------------------------------------------------
Safety improvements       Actions by pipeline operators in response to
 ordered by OPS            corrective action orders, including miles of
                           pipeline assessed, defects discovered,
                           repairs made, and selected costs incurred.
------------------------------------------------------------------------
Results of integrity      The percentage of pipeline operators that did
 management and operator   not meet certain requirements and the
 qualification             reduction in the number of operators with a
 inspections               particular deficiency.
------------------------------------------------------------------------
Source: GAO analysis of OPS information.
a OPS started collecting some of these data in 2002 but does not
  anticipate obtaining all of it on an annual basis until 2005.

    We have found that agencies that are successful in measuring 
performance strive to establish measures that demonstrate results, 
address important aspects of program performance, and provide useful 
information for decision-making.\13\ While OPS's new measures may 
produce better information on the performance of its enforcement 
program than is currently available, OPS has not adopted key practices 
for achieving these characteristics of successful performance 
measurement systems:
---------------------------------------------------------------------------
    \13\ See, for example, GAO/GGD/AIMD-99-69; Executive Guide: 
Effectively Implementing the Government Performance and Results Act, 
GAO/GGD-96-118 (Washington, D.C.: June 1996); and Tax Administration: 
IRS Needs to Further Refine Its Tax Filing Season Performance Measures, 
GAO-03-143 (Washington, D.C.: Nov. 22, 2002).

   Measures should demonstrate results (outcomes) that are 
        directly linked to program goals. Measures of program results 
        can be used to hold agencies accountable for the performance of 
        their programs and can facilitate congressional oversight. If 
        OPS does not set clear goals that identify the desired results 
        (intermediate outcomes) of enforcement, it may not choose the 
        most appropriate performance measures. OPS officials 
        acknowledge the importance of developing such goals and related 
        measures but emphasize that the diversity of pipeline 
        operations and the complexity of OPS's regulations make this a 
        challenging task.\14\
---------------------------------------------------------------------------
    \14\ We have reported on the challenges faced by agencies in 
developing measures of program results and on their approaches for 
overcoming such challenges. See, in particular, GAO/GGD-00-10, Managing 
for Results: Measuring Program Results That Are Under Limited Federal 
Control, GAO/GGD-99-16 (Washington, D.C.: Dec. 11, 1998), and Managing 
for Results: Regulatory Agencies Identified Significant Barriers to 
Focusing on Results, GAO/GGD-97-83 (Washington, D.C.: June 24, 1997).

   Measures should address important aspects of program 
        performance and take priorities into account. An agency 
        official told us that a key factor in choosing final measures 
        would be the availability of supporting data. However, the most 
        essential measures may require the development of new data. For 
        example, OPS has developed databases that will track the status 
        of safety issues identified in integrity management and 
        operator qualification inspections, but it cannot centrally 
        track the status of safety issues identified in enforcing its 
        minimum safety standards. Agency officials told us that they 
        are considering how to add this capability as part of an effort 
        to modernize and integrate their inspection and enforcement 
---------------------------------------------------------------------------
        databases.

   Measures should provide useful information for decision-
        making, including adjusting policies and priorities.\15\ OPS 
        uses its current measures of enforcement performance in a 
        number of ways, including monitoring pipeline operators' safety 
        performance and planning inspections. While these uses are 
        important,they are of limited help to OPS in making decisions 
        about its enforcement strategy. OPS has acknowledged that it 
        has not used performance measurement information in making 
        decisions about its enforcement strategy. OPS has made progress 
        in this area by identifying possible new measures of 
        enforcement results (outcomes) and other aspects of program 
        performance, such as indicators of the timeliness of 
        enforcement actions, that may prove more useful for managing 
        the enforcement program.
---------------------------------------------------------------------------
    \15\ See, for example, GAO/GGD-96-118 and U.S. General Accounting 
Office, Results-Oriented Government: GPRA Has Established a Solid 
Foundation for Achieving Greater Results, GAO-04-38 (Washington, D.C.: 
Mar. 10, 2004).
---------------------------------------------------------------------------
OPS Has Increased Its Use of Civil Penalties; the Effect on Deterrence 
        is Unclear
    In 2000, in response to criticism that its enforcement activities 
were weak and ineffective, OPS increased both the number and the size 
of the civil monetary penalties it assessed.\16\ Pipeline safety 
stakeholders expressed differing opinions about whether OPS's civil 
penalties are effective in deterring noncompliance with pipeline safety 
regulations.
---------------------------------------------------------------------------
    \16\ The civil penalty results we present largely reflect OPS's 
enforcement of its minimum safety standards because integrity 
management enforcement did not begin until 2002.
    Our results may differ from the results that OPS reports because 
our data are organized differently. OPS reports an action in the year 
in which it occurred. For example, OPS may propose a penalty in one 
year and assess it in another year. The data for this action would show 
up in different years. To better track the disposition of civil 
penalties, we associated assessed penalties and penalty amounts with 
the year in which they were proposed--even if the assessment occurred 
in a later year.
---------------------------------------------------------------------------
OPS Now Assesses More and Larger Civil Penalties
    OPS assessed more civil penalties during the past 4 years under its 
current ``tough but fair'' enforcement approach than it did in the 
previous 5 years, when it took a more lenient enforcement approach. 
(See fig. 2.) From 2000 through 2003, OPS assessed 88 civil penalties 
(22 per year on average) compared with 70 civil penalties from 1995 
through 1999 (about 14 per year on average). For the first 5 months of 
2004, OPS proposed 38 civil penalties. While the recent increase in the 
number and the size of civil penalties may reflect OPS's new ``tough 
but fair'' enforcement approach, other factors, such as more severe 
violations, may be contributing to the increase as well.


    Note: The amounts in this figure may not be comparable to the 
amounts that OPS reports. See footnote 16.

    Overall, OPS does not use civil penalties extensively. Civil 
penalties represent about 14 percent (216 out of 1,530) of all 
enforcement actions taken over the past 10 years. OPS makes more 
extensive use of other types of enforcement actions that require 
pipeline operators to fix unsafe conditions and improve inadequate 
procedures, among other things. In contrast, civil penalties represent 
monetary sanctions for violating safety regulations but do not require 
safety improvements. OPS may increase its use of civil penalties as it 
begins to use them to a greater degree for violations of its integrity 
management standards.
    The average size of the civil penalties has increased. For example, 
from 1995 through 1999, the average assessed civil penalty was about 
$18,000.\17\ From 2000 through 2003, the average assessed civil penalty 
increased by 62 percent to about $29,000.\18\ Assessed penalty amounts 
ranged from $500 to $400,000.
---------------------------------------------------------------------------
    \17\ All amounts are in current year dollars. Inflation was low 
during the 1995-2003 period. If the effects of inflation were 
considered, the average assessed penalty amount for 1995 through 1999 
would be $21,000 and the average amount for 2000 through 2003 would be 
$30,000 (in 2003 dollars).
    \18\ The median civil penalty size for the 1995-1999 period was 
about $5,800 and the median size for the 2000-2003 period was $12,700.
---------------------------------------------------------------------------
    In some instances, OPS reduces proposed civil penalties when it 
issues its final order. We found that penalties were reduced 31 percent 
of the time during the 10-year period covered by our work (66 of 216 
instances). These penalties were reduced by about 37 percent (from a 
total of $2.8 million to $1.7 million). The dollar difference between 
the proposed and the assessed penalties would be over three times as 
large had our analysis included the extraordinarily large penalty for 
the Bellingham, Washington, incident. For this case, OPS proposed a 
$3.05 million penalty and had assessed $250,000 as of May 2004.\19\ If 
we include this penalty, then over this period OPS reduced total 
proposed penalties by about two-thirds, from about $5.8 million to 
about $2 million.
---------------------------------------------------------------------------
    \19\ OPS proposed a $3.05 million penalty against Equilon Pipeline 
Company, LLC (Olympic Pipeline Company) for the Bellingham incident and 
later assessed Shell Pipeline Company (formerly Equilon) $250,000, 
which it collected. According to RSPA's Office of Chief Counsel, the 
penalty against Olympic Pipeline is still open, waiting for the company 
to come out of bankruptcy court.
---------------------------------------------------------------------------
    OPS's database does not provide summary information on why 
penalties are reduced. According to an OPS official, the agency reduces 
penalties when an operator presents evidence that the OPS inspector's 
finding is weak or wrong or when the pipeline's ownership changes 
during the period between the proposed and assessed penalty. It was not 
practical for us to gather information on a large number of penalties 
that were reduced, but we did review several to determine the reasons 
for the reductions. OPS reduced one of the civil penalties we reviewed 
because the operator provided evidence that OPS inspectors had 
miscounted the number of pipeline valves that OPS said the operator had 
not inspected. Since the violation was not as severe as OPS had stated, 
OPS reduced the proposed penalty from $177,000 to $67,000.
Operators Paid Full Amounts of Most Civil Penalties
    Of the 216 penalties that OPS assessed from 1994 through 2003, 
pipeline operators paid the full amount 93 percent of the time (200 
instances) and reduced amounts 1 percent of the time (2 instances). 
(See fig. 3.) Fourteen penalties (6 percent) remain unpaid, totaling 
about $837,000 (or 18 percent of penalty amounts).


    In two instances, operators paid reduced amounts. We followed up on 
one of these assessed penalties. In this case, the operator requested 
that OPS reconsider the assessed civil penalty and OPS reduced it from 
$5,000 to $3,000 because the operator had a history of cooperation and 
OPS wanted to encourage future cooperation.
    For the 14 unpaid penalties, neither FAA's nor OPS's data show why 
the penalties have not been collected. We expect to present a fuller 
discussion of the reasons for these unpaid penalties and OPS's and 
FAA's management controls over the collection of penalties when we 
report to this and other committees next month.
The Effect of OPS's Larger Civil Penalties on Deterring Noncompliance 
        Is Unclear
    Although OPS has increased both the number and the size of the 
civil penalties it has imposed, the effect of this change on deterring 
noncompliance with safety regulations, if any, is not clear. The 
stakeholders we spoke with expressed differing views on whether the 
civil penalties deter noncompliance. The pipeline industry officials we 
contacted believed that, to a certain extent, OPS's civil penalties 
encourage pipeline operators to comply with pipeline safety regulations 
because they view all of OPS's enforcement actions as deterrents to 
noncompliance. However, some industry officials said that OPS's 
enforcement actions are not their primary motivation for safety. 
Instead, they said that pipeline operators are motivated to operate 
safely because they need to avoid any type of accident, incident, or 
OPS enforcement action that impedes the flow of products through the 
pipeline and hinders their ability to provide good service to their 
customers. Pipeline industry officials also said that they want to 
operate safely and avoid pipeline accidents because accidents generate 
negative publicity and may result in costly private litigation against 
the operator.
    Most of the interstate agents, representatives of their 
associations, and insurance company officials expressed views similar 
to those of the pipeline industry officials, saying that they believe 
civil penalties deter operators' noncompliance with regulations to a 
certain extent. However, a few disagreed with this point of view. For 
example, the state agency representatives and a local government 
official said that OPS's civil penalties are too small to be 
deterrents. Pipeline safety advocacy groups that we talked to also said 
that the civil penalty amounts OPS imposes are too small to have any 
deterrent effect on pipeline operators. As discussed earlier, for 2000 
through 2003, the average assessed penalty was about $29,000.
    According to economic literature on deterrence, pipeline operators 
may be deterred if they expect a sanction, such as a civil penalty, to 
exceed any benefits of noncompliance.\20\ Such benefits could, in some 
cases, be lower operating costs. The literature also recognizes that 
the negative consequences of noncompliance--such as those stemming from 
lawsuits, bad publicity, and the value of the product lost from 
accidents--can deter noncompliance along with regulatory agency 
oversight. Thus, for example, the expected costs of a legal settlement 
could overshadow the lower operating costs expected from noncompliance, 
and noncompliance might be deterred.
---------------------------------------------------------------------------
    \20\ Expected sanctions are the product of the sanction amount and 
the likelihood of being detected and sanctioned by that amount.
---------------------------------------------------------------------------
    Mr. Chairman, this concludes my prepared statement. We expect to 
report more fully on these and other issues when we complete our work 
next month. We also anticipate making recommendations to improve OPS's 
ability to demonstrate the effectiveness of its enforcement strategy 
and to improve OPS's and FAA's management controls over the collection 
of civil penalties. I would be pleased to respond to any questions that 
you or Members of the Committee might have.

    The Chairman. Thank you very much.
    Welcome, Commissioner Spitzer.

           STATEMENT OF HON. MARC SPITZER, CHAIRMAN, 
                 ARIZONA CORPORATION COMMISSION

    Mr. Spitzer. Good morning, Mr. Chairman and Senator 
Lautenberg. My name is Marc Spitzer.
    The Chairman. And Senator Cantwell.
    Mr. Spitzer. Beg your pardon?
    The Chairman. Go ahead.
    Mr. Spitzer. Oh, I'm sorry. Senator, my apologies.
    My name is Marc Spitzer, Chairman of the Arizona 
Corporation Commission, and I am honored to address the 
Committee this morning.
    Today, I will update this Committee on the aftermath of the 
pipeline rupture in Arizona in July 2003 and the strides made 
by the United States Department of Transportation, Office of 
Pipeline Safety, OPS, and the Arizona Commission not only to 
strengthen the integrity of the pipelines in Arizona, but also 
the ongoing relationship between those two agencies. I will 
also propose solutions for your consideration, rather than cast 
blame, as many have already done, and with marginal benefit. 
These solutions address the need for some changes regarding the 
way agencies inspect and investigate the pipeline system. I 
will also discuss the relationship between our interstate 
pipeline system and an adequate supply of energy at reasonable 
prices.
    On July 30, 2003, Kinder Morgan's eight-inch gasoline 
pipeline from Tucson to Phoenix burst, spewing gasoline on 
Tucson homes and disrupting the main supply line of gas to 
Phoenix. This resulting shortage, combined with the difficulty 
in obtaining other sources of the correct formula of fuel to be 
used in our region, created a situation that led to long gas 
lines, filling stations running out of gas, Arizonans unable to 
get to work, motorists stranded in 100-degree heat, and grave 
concern for the health, safety, and welfare of our community.
    The pipeline rupture that occurred in Arizona in July 2003 
is indicative of the aging infrastructure in the United States, 
and is the reason Federal and state governments need to conduct 
coordinated, aggressive inspections to reduce the risk of 
another pipeline rupture and the attendant environmental and 
economic damage.
    In October 2003, Mr. Chairman, you held a hearing in 
Phoenix during which I made suggestions for improvement. 
Although more remains to be done, Mr. Chairman, your efforts, 
those of OPS, and my colleagues on the Arizona Commission have 
been successful.
    Let me briefly highlight the cooperation the Arizona 
Commission has enjoyed with OPS since the Kinder Morgan 
rupture.
    OPS timely released interstate pipeline safety records 
requested by the commission on behalf of other Arizona state 
and local officials. OPS personnel visited the commission and 
committed to develop rules governing the release of interstate 
pipeline records by state agents, consistent with the Patriot 
Act. OPS participated with our commission in numerous public 
forums, including a special task force to explain to the people 
of Arizona the Federal and state roles in pipeline safety 
regulation. We particularly appreciate OPS's support for a 
second metallurgical analysis of the Kinder Morgan pipe that 
failed last summer, enhanced inspection schedules for the 50-
year-old segments of the pipeline, and efforts to expedite 
replacement of that line. This spirit of cooperation should 
continue.
    While improving the communications between agencies is a 
step in the right direction, I believe more can be done. 
Current law allows a pipeline operator to contract with a lab 
for a postmortem on a piece of ruptured pipe. In Arizona, we 
have adopted rules requiring independent testing for intrastate 
pipeline access. Independent testing in serious cases should be 
Federal law, as well.
    Arizona must be allowed to continue its participation with 
OPS in the oversight and inspection of pipelines, particularly 
in the integrity-management program. For obvious reasons, no 
homes should be built within 200 feet of a high-pressure eight- 
or twelve-inch gasoline pipeline. OPS should work with the 
states to develop clear guidance for counties and cities on the 
dangers and locations of pipelines to prevent residential 
zoning within 200 feet.
    The gravest threat to pipeline safety is excavation. In an 
effort to prevent hazards arising from excavation, I would 
point out the participation of OPS and the Arizona Commission 
and the Common Ground Alliance. The CGA provides necessary 
information and education to the community about the dangers of 
unwary excavation.
    At the Arizona Commission, we are making structural changes 
in our organization to increase the information flow from the 
Arizona Commission to OPS in order to better assist OPS and its 
sizable workload. Sharing is a two-way street. OPS should 
timely notify the states when requests for opinions concerning 
pipelines within their boundaries are received. States must be 
allowed to submit their comments on those requests before OPS 
renders its opinion.
    Finally, OPS funding must be sufficient to achieve the 
safety Americans expect in the transportation of hazardous 
liquids.
    Now, in the area of energy solutions, which I think are 
relevant to this issue of pipeline safety, better, more 
coordinated pipeline inspections are only part of the 
solutions. This Committee should also evaluate the positive 
impacts on pipeline safety associated with increasing the 
supply of energy available to the market. No gasoline refinery 
has been built in the Southwest United States since 1969. 
Limited refinery capacity imposes obvious stress on gasoline 
supply and relentless upward pressure on price. A new refinery 
in Arizona would reduce dependence on aging pipelines, the 
risks associated with high pressure on those lines, and allow 
more dependable petroleum distribution. The resulting reduction 
in required miles of pipeline transport will ease the burden on 
our commission's inspectors and OPS. The benefits of a refinery 
clearly serve the public health, safety, and welfare.
    Government must address the connection between the myriad 
boutique fuels and stress on the pipeline system. As majority 
leader in the Arizona Senate, I negotiated Arizona's state 
implementation program with the EPA regional administrator. I 
understand the importance of clean air and the need for clean-
burning gasoline to combat ozone, particulates, and carbon 
monoxide in the non-attainment areas in our state and 
throughout the country. However, the status quo hodgepodge of 
fuel blends with no Federal effort to standardize is highly 
inefficient for refineries, pipeline operators, and service 
stations, and needlessly expensive for motorists.
    Natural gas supply is now critically low. Arizona has no 
production, zero storage, and constrained and costly pipeline 
transport. Federal and state agencies must unleash private 
operators willing to invest in natural gas production, new 
storage facilities, LNG terminals, and gas pipelines. A number 
of these projects are tied up in court. The Chair will be 
pleased to know that it is not just the telecom companies that 
endlessly litigate. But as with telecommunications, the public 
is ill-served by essential utilities mired in a perpetual legal 
morass.
    Our Commission is committed to renewable energy to clean 
the environment and reduce dependence on volatile and expensive 
fossil fuels. Federal tax benefits for renewables recently 
passed by the Senate level the playing field, vis-a-vis heavily 
subsidized oil, gas, nuclear, and stability and tax treatment 
of clean energy technologies is an imperative.
    In this extraordinary era of unstable crude oil supply, the 
Congress should reconsider CAFE standards. With premium gas at 
$3 per gallon, Detroit may be happy to adapt.
    The Arizona Commission has adopted demand-side management 
and energy-efficiency programs. We would welcome Federal 
teamwork with state agencies and the private sector to reduce 
demand.
    Finally, Michael Gent and the North American Reliability 
Council have, for almost a year, been seeking legislation to 
make present electricity transmission rules legally 
enforceable. I am aware of a temptation to attach special- 
interest measures to a must-go bill, but it is a time for 
gamesmanship to end. It should not take another blackout to 
coerce the Congress to enact mandatory reliability standards 
proposed by the NERC.
    I thank the Chairman and the Committee for your effort and 
the opportunity today. I ask you to continue your consideration 
of the critical importance of our Nation's pipelines and its 
energy supply. And, Mr. Chairman, I might have been a little 
blunt in my remarks, but I had a very good mentor over the 
years, and I thank you.
    [Laughter.]
    [The prepared statement of Mr. Spitzer follows:]

          Prepared Statement of Hon. Marc Spitzer, Chairman, 
                     Arizona Corporation Commission
I. Introduction
    My name is Marc Spitzer, Chairman of the Arizona Corporation 
Commission (the ``Arizona Corporation Commission'' or ``ACC''), and I 
am honored to address the Committee this mornmg.
    Today, I will update this Committee on the pipeline rupture in 
Arizona in July 2003, and the strides made by United States Department 
of Transportation Office of Pipeline Safety (``OPS'') and the ACC to 
not only strengthen the integrity of the pipelines in Arizona, but also 
the ongoing relationship between those two agencies. I will also 
propose for your consideration solutions addressing the need for some 
changes regarding the way agencies inspect and investigate the pipeline 
system. Finally, I suggest proposals to assure an adequate supply of 
energy.
II. Kinder Morgan Rupture, An Infrastructure Example
    On July 30, 2003, Kinder Morgan's 8-inch gasoline pipeline from 
Tucson to Phoenix burst, spewing gasoline on Tucson homes and 
disrupting the main supply line of gas to Phoenix. The resulting 
shortage combined with the difficulty in obtaining other sources of the 
correct ``formula'' of fuel to be used in the region led to long gas 
lines, filling stations running out of gas, motorists stranded in 100-
degree heat and grave concern for the health, safety and welfare of our 
community. The pipeline rupture that occurred in Arizona in July 2003 
is indicative of the aging U.S. infrastructure and is the reason 
Federal and state governments need to conduct coordinated, aggressive 
inspections to reduce the risk of another pipeline rupture and the 
attendant environmental and economic damage.
    In October 2003, the Chairman of this Committee held a hearing in 
Phoenix in which I made suggestions for improvement to the OPS. Mr. 
Chairman, although more remains to be done, your efforts and those of 
OPS and my colleagues on the Arizona Commission have been successful.
    Let me briefly highlight the cooperation the Arizona Commission has 
enjoyed with OPS since the rupture. OPS timely released interstate 
pipeline safety records requested by the Commission on behalf of other 
Arizona state and local officials. OPS personnel visited the Commission 
and committed to develop rules governing the release of interstate 
pipeline records by state agents, consistent with the Patriot Act. OPS 
participated with our Commission in numerous public forums, including a 
special Task Force, to explain to the people of Arizona the Federal and 
state roles in pipeline safety regulation.
    We particularly appreciate OPS' support for a second metallurgical 
analysis of the Kinder Morgan pipe that failed last summer, enhanced 
inspection schedules for the fifty year-old segments of the pipeline 
and efforts to expedite replacement of that line. This spirit of 
cooperation should continue.
III. Pipeline Inspection Solutions
    In light of today's gasoline prices, Arizona cannot afford another 
situation like the one in July 2003, economically, environmentally or 
to protect public health. While improving the communications between 
agencies is a step in the right direction, I believe more can be done. 
I think the following areas need to be addressed:

  a.  Arizona must be allowed to continue its participation with OPS in 
        the oversight and inspection of pipelines, particularly in the 
        Integrity Management Program (``IMP''). I should point out that 
        in Arizona, OPS has graciously consented to state 
        participation, which I understand is in accordance with the 
        national model. This participation is important as each State 
        has a cadre of trained experts at the ready, prepared to assist 
        and support OPS in its task of ensuring interstate pipeline 
        safety.

  b.  Independent Exams should be required by law. The current system 
        allows an entity that owns a pipeline to contract with a lab to 
        do a ``post mortem'' on a piece of pipe that ruptured as the 
        sole analysis as to why the problem occurred in the first 
        place. This system of trust should be augmented with a system 
        to independently verify those results. In Arizona, we have 
        adopted rules requiring independent testing for intrastate 
        pipeline accidents. Independent testing in serious cases should 
        be Federal law as well.

  c.  Sharing is a two way street. At the ACC, we are currently making 
        structural changes to our organization to increase the 
        information flow from the ACC to OPS in order to better assist 
        OPS and its sizable workload.

  d.  Residential or commercial construction should not take place 
        within 200 feet of a high pressure 8 or 12-inch gasoline 
        pipeline. In Tucson, residential buildings were 37 feet from 
        the pipeline. Within minutes over 6,000 gallons of gasoline had 
        soaked several homes. We can only thank God they were 
        unoccupied-but we must recognize the danger. Real estate 
        development involves the use of heavy machinery and 
        excavation--to continue to allow that to occur within 37 feet 
        of a fifty-year old gasoline pipeline is insane. The Federal 
        and state governments are obligated to impose restrictions 
        where counties and cities fail to act. The OPS should work with 
        states to develop clear guidance for counties and cities on the 
        dangers and locations of pipelines to prevent residential 
        zoning within 200 feet.

  e.  The gravest threat to pipeline safety is excavation. In an effort 
        to prevent hazards due to excavations, I would point out the 
        participation of OPS and the ACC in the Common Ground Alliance 
        (``CGA''). The CGA is a group of government and industry stake 
        holders that try to work toward a ``common ground'' in the 
        excavation community. It focuses on the areas of best 
        practices, education and research and development, to name a 
        few. The CGA provides necessary information and education to 
        the community about the dangers of unwary excavation.

  f.  OPS funding must be sufficient to achieve the safety Americans 
        expect in the transportation of hazardous liquids.
IV. Energy Solutions
    Better, more coordinated pipeline inspections are only a part of 
the solution. This Committee should also evaluate the positive impacts 
on pipeline safety associated with increasing the supply of energy 
available to the market.
    No gasoline refinery has been built in the southwest United States 
since 1969. Limited refinery capacity imposes obvious stress on 
gasoline supply and relentless upward pressure on price. A new refinery 
in Arizona would reduce dependence on aging pipelines, the risks 
associated with high pressure in those lines, afford more dependable 
distribution and the ultimate reduction in required miles of pipeline 
will ease the burden on our Commission's inspectors and OPS. The 
benefits of a refinery clearly serve the public health, safety and 
welfare.
    Government must address the connection between myriad boutique 
fuels and stress on the pipeline system. There are at least thirteen 
and as many as thirty formulations of gasoline. Fewer fuel formulations 
would simplify gasoline distribution, and make refineries more 
efficient, thereby reducing the price volatility associated with a 
local supply disruption. As Majority Leader in the Arizona Senate I 
negotiated Arizona's State Implementation Program with the EPA Regional 
Administrator. I understand the importance of clean air and the need 
for clean burning gasoline to combat ozone, particulates and carbon 
monoxide in non attainments areas in our State. However, the status quo 
hodgepodge of fuel blends, with no Federal effort to standardize, is 
highly inefficient for refineries, pipeline operators and service 
stations and needlessly expensive for motorists.
    As I note below, natural gas supply is now critically low. Arizona 
has no production, zero storage and constrained and costly pipeline 
transport. The lack of storage capacity is a key determinate of natural 
gas price volatility. Storage capacity provides the system with a 
buffer to supply and demand shocks, allowing it to smooth the natural, 
cyclical swings in prices. Natural gas volatility and the means to 
flatten the cost curve are especially important when we are faced with 
declining domestic gas reserves. Ninety percent of new power plants 
under construction in the U.S. are gas fired and eighteen new natural 
gas fired plants are proposed in Arizona alone.
    Federal and state agencies must unleash private operators willing 
to invest in natural gas production, new storage facilities, Liquefied 
Natural Gas (``LNG'') terminals and gas pipelines. A number of these 
projects are tied up in court. The Chair will be pleased to know it is 
not just the telecom companies that endlessly litigate, but as with 
telecommunications the public is ill-served by essential utilities 
mired in a perpetual legal morass. Congressional action may be 
necessary to sever this Gordian knot of parochial interests and 
Nimbyism.
    Our Commission is committed to renewable energy to clean the 
environment and reduce dependence on volatile and expense fossil fuels. 
Federal tax benefits for renewables, passed recently by the Senate, 
level the playing field viz a vis heavily subsidized oil, gas and 
nuclear, and stability in tax treatment of clean energy technologies is 
an imperative.
    In this extraordinary era of unstable crude oil supply and 
increasing global demand, the Congress should reconsider the CAFE 
standards. With premium gas at $3 per gallon, Detroit may be happy to 
adapt.
    The Arizona Commission has adopted demand-side management and 
energy efficiency programs. The goal is to avoid construction of costly 
and polluting power plants. We would welcome Federal teamwork with 
state agencies and the private sector to reduce demand.
    Finally, Michael Gent and the North American Reliability Council 
have for almost a year been seeking legislation to make the present 
electricity transmission rules legally enforceable. I am acutely aware 
of the temptation to attach special interest measures to a ``must go'.' 
bill. But it is time for the gamesmanship to end. It should not take 
another blackout to coerce the Congress to enact the mandatory 
reliability standards proposed by NERC.
V. Difficulties in Assuring Adequate Supplies of Energy at Reasonable 
        Prices
    Since my tenure on the Arizona Commission our ratepayers have 
endured the consequences of disruptions to energy supply, price spikes 
and the attendant economic and personal damage and dislocation. This is 
of course true throughout the country. In the 21st Century economy, 
dependent upon increasing amounts of energy to sustain high American 
productivity, the Government has fallen short.
    In January 2001, the California electricity market was unraveling, 
causing turmoil throughout the Western interconnection. There were many 
causes and culprits-lack of generation capacity, inadequate 
transmission, flawed regulation, absence of long-term contracts, 
misconduct of market participants culminating in old-fashioned panic. 
Enron's collapse and California aftershocks helped crater the merchant 
power sector. Huge market capitalization was wiped out. Wall Street 
spurns the energy sector depriving an industry of necessary capital 
investment for infrastructure. Moreover, human capital is growing 
scarce as college classes in electrical engineering are only one-third 
filled.
    In natural gas, all evidence indicates the rosy scenario for North 
American gas production is a myth. The 2003 National Petroleum Council 
report indicates a structural deficit in natural gas production, 
something State utility regulators and customers already knew from the 
quintupling of commodity prices in 2001. Across the country, in the 
winter of 2003-2004 thousands of ratepayers could not afford to pay 
their gas heating bills and in then the shutoff notices came like the 
spring rains. Our Commission held a packed-house hearing at the Opera 
House in Prescott, Arizona to deal with customer complaints over high 
natural gas bills, and the villain was not even in the house. The gas 
LDC earned nothing on the high commodity costs passed through to our 
customers. Incantation of the term ``market forces'' was not accepted 
by those who knew the market was dysfunctional.
    In the meantime, hundreds of thousands of American jobs in the 
fertilizer, ammonia and other industries have been lost to high natural 
gas prices. Brand new, clean-burning gas-fired electricity plants stand 
idle while filthy, polluting coal plants run flat out-all due to 
commodity fuel prices. And press reports suggest opposition to LNG 
terminals has cancelled all five pending LNG applications. While 
Americans bear a great burden from inadequate supplies of natural gas, 
gas pipeline and storage contracts remain inadequate to deal with 
bottlenecks and shortages.
    The bottom line is America's energy consumption has grown and will 
continue to grow, however, supplies are dwindling or remain untapped, 
our infrastructure is collapsing and the economic growth in other 
countries has resulted in increased competition for energy supplies in 
the global market. These pressing issues need immediate attention.
    I thank the Chairman and the Committee for the opportunity today, 
and I ask you to continue your consideration of the critical importance 
of our Nation's pipelines and its energy supply.

    The Chairman. Thank you very much. Thank you very much, 
Commissioner Spitzer, and we're glad you're here.
    Mr. Mead and Ms. Siggerud, from the tenor of your 
statements, you would give OPS and Department of Transportation 
fairly high marks for actions they've taken since the bill was 
passed in 2002. Is that a correct assessment of your remarks, 
with some certain caveats?
    Mr. Mead. Yes.
    Ms. Siggerud. Yes, I would say so. We are particularly 
pleased with the progress on the Integrity Management Program. 
GAO has always been a supporter of a risk-based approach to 
regulation.
    The Chairman. Well, then I'd like to thank Mr. Bonasso and 
Mr. Connaughton and Ms. Gerard for the good work. A lot of 
times we don't have that kind of report from the GAO and the 
Inspector General, and we thank you for your good work. I hope 
you'll take seriously the additional recommendations that have 
been made.
    Now, one of the problems that we've identified time after 
time in light of the Bellingham, Washington, situation, the 
California situation, Arizona pipeline ruptures, this whole 
issue of Federal/state coordination. So, Commissioner Spitzer, 
you would say, generally speaking, that coordination between 
the Arizona Corporation Commission and the Office of Pipeline 
Safety has been good? Or what kind of comments would you make 
about that?
    Mr. Spitzer. Mr. Chairman, thank you. We've had some rocky 
times in the past, particularly prior to my tenure on the 
Commission. But I must say that since the Kinder Morgan episode 
in July 2003, and in the wake of the Committee hearing in 
Phoenix in October, OPS has worked very capably with us, and 
the information is coming downstream, and the IMP coordination 
has markedly improved, so we're extremely pleased with the 
relationship, and we'd hope it would not only continue in 
Arizona, but be applied nationally.
    The Chairman. Mr. Mead, Ms. Siggerud, Mr. Connaughton and 
Mr. Bonasso, the one element of testimony here that's extremely 
disturbing, or should be a red flag, is the number of 
pipelines--and inspections have revealed a number of serious 
failings, or possible failings, of pipelines in the relatively 
small number that have been inspected. I guess we'll begin with 
you, Mr. Bonasso. Are you--does that concern you?
    Mr. Bonasso. Well, yes, it does, but I'd like to put it 
just in a little bit more perspective. There were roughly 
41,000 miles of high-consequence areas, and the integrity 
threats that were defined came in 25,000 of those miles. So 
we've done roughly half of the high-consequence areas. And what 
I think this shows is that the technology is showing that there 
are significant repairs needed in this.
    The Chairman. More than had been originally estimated.
    Mr. Bonasso. Perhaps. And that's the idea of integrity 
management--replace for cause, rather than failure. I----
    The Chairman. Mr. Connaughton? Go ahead.
    Ms. Bonasso.--I would ask to ask Ms. Gerard if she----
    The Chairman. Ms. Gerard, would you like to add to that?
    Ms. Gerard. I think that's a fair assessment. But the 
raising the standards is working for the intended effect, so I 
think that's a good thing. And I would say----
    The Chairman. The good news is, it's working; the bad news 
is, we're finding out we've got more problems than we thought 
we had.
    Ms. Gerard. But, fortunately, the technology is advancing 
to help us diagnose better.
    Mr. Mead. And I just--may I interject something here?
    The Chairman. Sure.
    Mr. Mead. We've referred to this high--the 25,000 miles 
that have been inspected within these high-consequence areas, 
of which there are about 50,000 miles, I think, in the country 
for hazardous liquid. Well, that represents about 16 percent of 
the total. And you recall that Carlsbad, New Mexico, pipeline 
rupture some years ago. That was in a fairly rural area. It 
took out a couple of bridges and, I think, an entire family. 
And you can have some very serious consequences even though you 
may not be in a highly populated--in a densely populated area.
    The Chairman. Mr. Connaughton?
    Mr. Connaughton. Yes, the other point I would just add into 
this, it is important--and we've got this new information--it's 
important--the priority process that the legislation calls for, 
and that we put in place, is critical because there's a lot of 
work to be done. I would note, however, I think we have about 
20,000 repairs that have been made, 4,400 of which have been 
time sensitive. And most of those have gone forward without 
significant delay. There has been a subset of those that are 
subject to some of these much more intensive permitting 
exercises, and that actually, from a resource perspective, 
gives me some cause for----
    The Chairman. Yes, I was going to get to----
    Mr. Connaughton.--optimism, which is, we can focus on a 
much smaller piece that requires the more intensive and 
integrated review. My bigger concern had been that this was 
going to be something even bigger than we thought we'd be able 
to tackle. And so I feel fairly good. But I do want to 
underscore, in that smaller set, we are just at the beginning 
of the integrated process, so we have a good process in place. 
And I appreciate Mr. Mead's remarks. But I do underscore, we 
have to implement it now in an effective way.
    The Chairman. Ms. Siggerud?
    Ms. Siggerud. Senator McCain, the issue that you raise was 
not a central focus of our review. However, I would note that 
the fact that we even have the information that you were able 
to provide is a great step forward, in my view, in terms of 
being able to, again, get at that issue about the effectiveness 
of the inspection and enforcement programs.
    As you know, the Pipeline Safety Integrity Act of 2002 
requires us to report quite extensively on the Integrity 
Management Program in 2006, and I hope to look at the issue you 
raised, along with other implementation issues, when we do so.
    The Chairman. Mr. Spitzer, you talk about the fact that we 
don't have a refinery in Arizona. I think all of us are aware 
of that. Do you know of any community in Arizona that would 
welcome a refinery?
    Mr. Spitzer. Well, actually, the Yuma County Board of 
Supervisors, I believe, has expressed some interest out----
    The Chairman. My point is, at least from my experience, the 
reason why we don't have a refinery is because nobody wants 
one, and the process of starting one and getting in operation 
is viewed by many as an insurmountable task. We'll have 
witnesses here who will say exactly that. It's very alarming 
when--especially in a state like ours, where you have this 
tremendously high growth, and yet apparently houses are being 
built right next to pipelines, which, as you say, no homes 
should be built within 200 feet, yet it continues as we speak. 
That's a bit disturbing.
    Mr. Spitzer. Well, Senator, you allude to a very important 
global issue, and that's infrastructure, and it's complex. We 
are encouraging companies to build infrastructures in Arizona, 
and we've cited a number of power plants, high-voltage 
transmission lines. There is always the neighborhood outcry. 
But over time, we've managed to build the power plants that we 
need, and the transmission lines, through the corporation 
commission's process. Refineries are outside of our authority, 
as are the natural gas pipelines and gasoline pipelines.
    I think, with the California fiasco in 2000-2001 that 
affected the entire western interconnection, and then the East 
Coast blackout of last year, I sense, Senator, a growing 
understanding that the electricity doesn't just come out of a 
socket, and the same with gasoline, and the same with natural 
gas, and we're able to overcome the NIMBYism. But we have a 
almost historic implosion within the energy industry, which 
means even if companies are willing to consider entering the 
hazards of the siting process at the FERC, Wall Street is not 
willing to finance a number of projects that need to be built. 
So it's a--it almost becomes a vicious circle.
    The Chairman. And I don't take the side of Wall Street or 
Kinder Morgan, who I castigated severely after--in the past, 
who I think, according to most people, have improved their way 
of doing business rather dramatically. But Wall Street probably 
does not want to invest in something where compliance with the 
Endangered Species Act takes 2 or 3 years in order to move a 
pipeline, much less locate and build a major facility. So it's 
hard for me to blame an investor if the first time that a 
return on the investment is an unknown situation. I think it's 
very disturbing. I'd be glad to--I've run out of my time--Mr. 
Connaughton's assessment of the reason why the Kinder Morgan 
pipeline was not moved in California was because of 
bureaucratic delays which--everybody knew there was a problem 
there, but they couldn't relocate their pipeline because of 
compliance with a thicket of rules and regulations. And yet I 
doubt if I or anyone else would agree to significant 
modification of the Endangered Species Act.
    Mr. Connaughton? This is a conundrum that is, I think, 
going to be with us for a long time.
    Mr. Connaughton. Let me address two aspects of that. First, 
it is a given that a new refinery, on balance, will be safer 
and environmentally better than our old ones. And bringing on 
new capacity with new technology under the stringent laws we 
have that reduce air pollution, you know, how they manage 
waste, we're just in a new place today. So any new, major piece 
of capital infrastructure built in America is a net 
environmental benefit for America. Right now, it happens that 
we have increasing refining offshore that does not operate 
under those kinds of standards, and that doesn't help either 
because then we rely on our old infrastructure to get it to our 
consumers. So that's--from just a strict environmental 
perspective, we're not actually achieving our objectives.
    And then I do share your concern, because I talk to the 
folks on Wall Street, and I talk to the people who would 
otherwise invest in what are billion-dollar projects, when it 
takes 3 to 7 years to get a project built and you're looking at 
a return-on-investment, you want your return-on-investment 
coming fast, not long. And so it is a challenge that's with us.
    I think some of these innovations on integrated permitting 
are going to help. I think the effort here, because we'll have 
a much better shared database on environmental conditions 
surrounding our mapped pipeline areas, is going to help, 
because if we have all that information up front, we can begin 
to collectively design projects better and get a higher level 
of assurance that they're not creating significant 
environmental impact. However, as long as we have eight to 
forty different review processes, those are eight to forty 
opportunities for the NIMBY effect to take place, and that is a 
architectural issue that we have to collectively resolve, I 
think, if we want brand-new, gleaming, safe, environmentally 
sound capital infrastructure in America.
    The Chairman. I thank you for your good work, Commissioner 
Spitzer, and I hope that every zoning authority in America--I 
mean, in Arizona--is well aware of the zoning restrictions 
which should apply concerning construction of homes near an 
existing pipeline.
    Senator Lautenberg?
    Senator Lautenberg. Thanks, Mr. Chairman.
    Based on the time remaining, I have time for only one 
question. I'll ask that the record be kept open. I submit 
others to writing.
    I first commend the witnesses for their forthright 
statements. I think they were very good. What I hear is a 
fairly high grade, in response to the Chairman's question, for 
the effort--Mr. Mead and Ms. Siggerud. But I then am forced to 
ask this question. If it's working fairly well--and we all know 
that there's a lot of work to be done--more inspectors, more 
mapping, et cetera, et cetera, better technology--why move 
this, OPS, to the Federal Railroad Administration if it's 
fairly well covered under Transportation?
    Hello?
    [Laughter.]
    Ms. Siggerud. Well, I'll take a crack at that, and then Mr. 
Mead.
    From what I understand of the proposal, the goal of the 
proposal is to try to get RSPA to focus more specifically on 
its research mission. We have other work on RSPA that would 
certainly view that as a positive step. We believe that RSPA 
could, in fact, focus more specifically there, but there are 
issues with regard to moving OPS to FRA. I have not seen a lot 
of details of the proposal, but I would think that there are a 
couple of questions that one could ask about it. One is, in 
moving OPS elsewhere in DOT, are there similarities between the 
kinds of regulation, oversight, and inspections that OPS does 
in comparison with FRA or any----
    Senator Lautenberg. And the activities.
    Ms. Siggerud.--and the activities of the industry itself.
    Senator Lautenberg. Sure.
    Ms. Siggerud. So these, I think, are issues that DOT needs 
to be concerned about. Also, OPS is a relatively small 
organization in DOT. FRA, I believe, has in excess of about 800 
employees. OPS is at about 150. So we need to think about the 
role of OPS in a larger organization like that and whether it 
will get swallowed up or whether it could continue to pursue 
its mission effectively.
    Senator Lautenberg. Ken Mead?
    Mr. Mead. Yes, sir. I think it's probably a good idea to 
combine the different research arms of DOT, including the 
Bureau of Transportation Statistics. They need to have a focus 
that's a critical mass.
    I would be very careful, though, in what--in moving this 
organization, as well as to have this material function, which 
is another separate function inside of RSPA, that you make sure 
that they don't get too close to industry.
    You'll recall, several years ago--and, Senator McCain, I 
think you'll recall this, too--with the Federal Motor Carrier 
Safety Administration, they were in the Federal Highway 
Administration, and we had a number of problems with their 
closeness. We have made a lot of progress in the last several 
years. I don't think you want to lose that. So if you move 
them, make sure that they're not going to go to a place where 
they'll end up being too close to industry.
    Senator Lautenberg. Thank you.
    The Chairman. Senator Cantwell?

               STATEMENT OF HON. MARIA CANTWELL, 
                  U.S. SENATOR FROM WASHINGTON

    Senator Cantwell. Thank you, Mr. Chairman. And if I could 
submit a longer statement for the record?
    The Chairman. Without objection.
    Senator Cantwell. Thank you, Mr. Chairman. And thank you 
for your attention to this issue, starting with the hearing and 
focus on the Olympic pipeline explosion in 1999 and the passage 
of the Pipeline Safety Act in 2002 that you and Senator Murray 
and many others worked on. Very much appreciate your continued 
attention to this issue.
    I have a question. We recently, in Seattle, just last week, 
we had a pipeline leak thousands of gallons in Renton, 
Washington, and caused a shutdown of jet-fuel crisis at Sea-Tac 
Airport. I'm wondering, is that in the half-percent or half of 
the congested area that you've already looked at? Would Puget 
Sound and the Puget Sound region qualify as that?
    Ms. Gerard. Your question is whether or not that pipeline 
has been tested by the operator?
    Senator Cantwell. You, in your testimony, were saying, 
Here's where we are in testing, in general. And you were saying 
that you have half of what you would call high-consequence 
areas. I'm assuming those are population areas.
    Ms. Gerard. Those are tests by the operators.
    Senator Cantwell. What's a high-consequence area?
    Ms. Gerard. For a liquid pipeline, it's an area that we've 
defined as unusually environmentally sensitive, or it's a 
populated area defined by the census as a highly populated area 
or--not just a highly populated area, but a town or a township, 
and commercially navigable waterways. And in the definition of 
unusually environmentally sensitive, that includes drinking-
water sources, for example.
    Senator Cantwell. So do you think the near suburbs of 
Seattle would qualify as such?
    Ms. Gerard. Oh, it would definitely qualify. I thought your 
question was, Had the pipeline operator already completed their 
integrity baseline assessment?
    Senator Cantwell. That's my--yes, that's my question.
    Ms. Gerard. I don't know. I'd have to get you that for the 
record.
    Senator Cantwell. OK. And when are you planning on 
completing the second half of those areas?
    Ms. Gerard. The operator would be required--if they haven't 
already done it, and they may have, they would be required to 
complete that by 2009.
    Senator Cantwell. And what conclusions would we draw if 
they already have completed it?
    Ms. Gerard. We can give you a report on what our inspection 
of their integrity plan is, for the record. We have completed 
our inspections as the Federal Government of all of the 
operators' integrity plans. We have inspected, as the Federal 
Government, to see whether or not they're complying with the 
requirements. I don't know whether the operator has completed 
their baseline testing. They have 7 years to do it, and for 
that particular operator, I don't know. I think that this 
particular failure was not a transmission line. It was a 
sampling line. And so I believe that they would include that as 
part of their integrity program to look at, if it failed, why 
did it fail, and then to make a correction in their integrity 
program.
    Senator Cantwell. What number of incidents have happened in 
this area of high consequence that you have tested already? Of 
the areas that you've tested so far, of the high-consequence 
areas, have you had any incidents of leakage or explosion since 
the testing has been completed?
    Ms. Gerard. We'll have to get you that statistic for the 
record.
    Senator Cantwell. Don't you think that would be an 
interesting assessment of how well the testing----
    Ms. Gerard. Right. We have----
    Senator Cantwell.--is going?
    Ms. Gerard.--we have modified our inspection reports in the 
past few years to specifically zero in on that number so we can 
compare the results in high-consequence areas compared to the 
rest of the pipelines. So we'll have to----
    Senator Cantwell. Well, but in the areas that you've 
already tested, how many now have you found that you go back 
and you find that the testing didn't necessarily detect a 
potential problem. I think that's important data to track. One 
of the reasons I'm bringing this up is not just the situation 
that just happened recently in Puget Sound or the great number 
of issues that we have in the region, is that one of the 
debates in the 2002 bill was, How often should you do testing? 
The legislature--the Congress ended up settling on 10 years. I 
was more of an advocate of 5 years. Now, I'm assuming that, in 
some of these areas, you're using these hydro-statistic ``smart 
pig'' technology or something that is something that can be 
monitored on a more frequent basis. Is that correct?
    Ms. Gerard. Yes, that's correct.
    Senator Cantwell. What percentage are you using technology 
versus----
    Ms. Gerard. The vast majority of the pipelines for 
hazardous liquid are using internal inspection devices.
    Senator Cantwell. And so what kind of notification would 
you suggest Congress get if, on those incidents of areas that 
have already been tested, and then you still have leakage--what 
would be the notification process?
    Ms. Gerard. We have a regulation in place that will require 
the operator to report on that question annually, the extent to 
which there have been failures in high-consequence areas.
    Senator Cantwell. And you would----
    Ms. Gerard. That is a----
    Senator Cantwell.--that report would be----
    Ms. Gerard.--new requirement. That is a new----
    Senator Cantwell.--and that report----
    Ms. Gerard.--requirement.
    Senator Cantwell.--would be available to Congress once a 
year?
    Ms. Gerard. Yes, for liquid pipelines. For gas pipelines, 
twice a year. Natural gas transmission, twice a year.
    Senator Cantwell. But you would get us this information now 
on this first half that you've already tested? I'm just curious 
about this incident in the Puget Sound area, or anything 
related to that, where we've already--this is our first 
assessment of testing. Right? The Act has been in place. Now 
we've gone out, we're patting ourselves on the back, we've got 
half the high-consequence areas done. The first and most 
important question I think we would ask is, since we've tested, 
have we had any incidences in those areas? The fact that we 
can't answer that question this morning may be good news 
because there have been no incidents, or it may be that----
    Ms. Gerard. There may----
    Senator Cantwell.--or it may be that----
    Ms. Gerard.--there may have been no incidents.
    Senator Cantwell.--we aren't doubling back on how good our 
testing is--you know, on how good our testing model is. So I'd 
appreciate that information.
    And, Mr. Bonasso, if you could--part of the Olympic 
pipeline explosion outcome was a pipeline safety trust that the 
families coordinated to get a clearinghouse of information for 
pipeline safety nationwide. Do you work with that organization?
    Mr. Bonasso. Yes. The Office of Pipeline Safety does work 
with that organization, and I'm not personally familiar with 
the specifics, and I'd like to ask Ms. Gerard to comment on it.
    Ms. Gerard. We're working with the trust in at least two 
ways relatively formally. A representative of the trust is part 
of the peer-review process we use to do our research and 
development planning, and the trust participates in our program 
with the National Association of State Fire Marshals to advise 
us on community education efforts, to help us have public 
involvement in identifying the high-consequence areas, and to 
help us with developing an education program to acquaint 
communities with the science of protection of LNG facilities. 
So the trust is working with us on at least two projects, and 
then we invite them to participate when we have a public 
meeting on a topic that they would be interested in.
    Senator Cantwell. Thank you. I know my colleague is here, 
my time has run out----
    The Chairman. Go ahead.
    Senator Cantwell. Well, thank you. I just wanted to thank 
Mr. Spitzer for mentioning the reliability standard 
legislation, very important legislation that I hope we get 
passed this year. If we don't get anything else done on energy, 
that would be very satisfactory.
    I had a question as it relates--because we got into this 
discussion with the Chairman on investments in infrastructure, 
in energy infrastructure, and one of the issues is whether we 
have the proper focus on rate of return or on market-based 
rates. And I don't know if you, Mr. Spitzer, had any comments 
as to FERC's oversight on market-based rates and whether there 
is enough certainty in that market, given everything we've just 
seen in the West as it relates to electricity, or whether we 
need to make some adjustments.
    Mr. Spitzer. The pendulum swings back and forth, Senator, 
and I've had these discussion with Ms. Showalter, the Chairman 
of your Commission in Washington State. In 1998, Wall Street 
loved Enron, at 90. They said buy. And the merchant model was 
the model. The pendulum swung all the way over. We've had two 
powerplants, in Arizona, who were in the merchant sector, go 
back to the bank. And so the merchant sector is now despised, 
and the vertically integrated monopoly is the prevailing model.
    My personal opinion, since you asked it, is, the truth, I 
think, lies somewhere in between, and I believe that there's a 
role for both, depending upon the state. And being a state 
commissioner, we're certainly jealous of the state's rights and 
state's prerogatives, given that when retail prices go out of 
whack, when service stops, we're the ones who get the phone 
calls. Ms. Showalter gets the phone calls.
    But I do think a balance is appropriate, and I'm hopeful 
that the pendulum will swing a little bit back to the merchant 
model, because it does yield price benefits for ratepayers as 
well as--it's difficult for me to justify, Mr. Chairman, 
Senator, the running a plant like the one in Laughlin, one of 
the dirtiest plants in the United States, coal, in a non-
attainment area where the wind from the west blows over the 
Grand Canyon, when you have brand-new, clean-burning gas plants 
not being used only because they're in the merchant sector as 
opposed to part of the vertically integrated monopolies. So I'd 
like to see a balance between the two models.
    Senator Cantwell. And how important is transparency in 
these models, as it relates to the sector and their----
    Mr. Spitzer. Obviously, we'd like to see the FERC at the 
wholesale--which we, at the state commissions, do not 
regulate--pursue liquid transparent pricing at the wholesale 
level.
    Senator Cantwell. Thank you.
    Thank you, Mr. Chairman.
    [The prepared statement of Senator Cantwell follows:]

Prepared Statement of Hon. Maria Cantwell, U.S. Senator from Washington
    Thank you Mr. Chairman, I want to thank you for holding this 
hearing and for your personal leadership on the importance of pipeline 
safety.
    Nearly half a million miles of oil and gas transmission pipelines 
crisscross the United States.
    In my state alone, the Olympic pipeline system moves 12 million 
gallons of gasoline, diesel fuel and jet fuel through western 
Washington every day--from refineries at Cherry Point, north of 
Bellingham, and March Point, near Anacortes, to as far south as 
Portland, Ore.
    Also, Washington depends on the Williams Northwest Pipeline, which 
supplies 80 percent of Washington's gas, primarily from Canada and the 
Rocky Mountains.
    These pipelines and others like them comprise a crucial energy 
backbone of our country--providing the fuel and energy necessary for 
major production plants and factories, military installations and 
airports, and power generation facilities that keep our country moving.
    When there is a disruption, there are serious consequences for our 
infrastructure.
    Just last month, for example, the Olympic Pipeline leaked thousands 
of gallons of fuel and caused an intense fire in Renton Washington--
shooting flames twenty feet in the air.
    The Pipeline was shut for three days and created a jet-fuel crisis 
at Sea-Tac International Airport, which relies on the Olympic Pipeline 
as its sole supplier--in fact, the airport was just days away from 
having to close.
    More important, however, these pipelines run through many of our 
state's urban areas--through, under and near parks, schools and major 
population centers--and accidents can be extremely hazardous and even 
deadly.
    My state knows first-hand the tragedy of pipeline accidents.
    Just last week, we recognized the tragic fifth anniversary of the 
Olympic Pipeline explosion near Bellingham.
    This disastrous rupture spilled 237,000 gallons of gasoline and 
exploded into a fireball that killed two ten-year-olds, Stephen 
Tsiorvas [SEE-OR-VUS] and Wade King, and Liam Wood, an 18-year-old who 
was out fishing.
    These kids were simply playing in a park and fishing in a river--
when a threat that few people in the city even knew existed killed 
them.
    I want to re-state that fact: few people in the city even knew that 
this pipeline ran through their city.
    In fact, these pipelines run through our cities and neighborhoods 
and often they are buried underground without any knowledge of those 
living above them.
    Ensuring the safety of these lines must be a principal priority, 
which is why I supported the Pipeline Safety Improvement Act of 2002 as 
a good step towards increased pipeline safety.
    This legislation that was introduced under our chairman's 
leadership gives the Secretary of Transportation greater authority to 
take swift action in ensuring the safety of our pipeline system.
    Specifically, the legislation included increased inspections, an 
expanded public right to know about pipeline hazards, environmental 
reviews intended to enable more timely pipeline repairs, and increased 
state oversight of safety activities.
    I was particularly pleased that the legislation added a mandatory 
inspection requirement.
    However, I must say that I remain disappointed that the final 
conference report did not include the Senate's requirement for testing 
every five years that was included as a Murray-Cantwell amendment in 
the Senate bill.
    Instead, the law requires pipeline inspections over all lines once 
in the next ten years and every seven years thereafter. Physical 
testing is really the only way that we know the vulnerabilities of 
these systems and I think that testing only once in ten years is 
insufficient.
    The final ten-year requirement must--I repeat must--be the absolute 
minimum standard.
    We need to make sure that consistent physical testing of our 
pipelines is a principal priority, and I strongly encourage more 
testing beyond the statutory requirements.
    It is important to recognize, that the OPS has made significant 
steps to increase safety--while last year there were 126 liquid 
pipeline accidents; this is almost a 50 percent decrease from a decade 
earlier.
    Yet, 126 accidents are still too many. We need to do more.
    I am pleased that the Administration's FY 2005 budget includes 
funding for 168 full-time inspectors--this is an increase from 111 when 
the Pipeline Safety bill was passed.
    In addition to increased inspectors, I think we need to focus on 
providing states and communities the resources that they need to 
develop security, safety and response plans to ensure that we will not 
have another tragic pipeline anniversary to mourn.
    I look forward to hearing from you today specifically about the 
ongoing testing of our Nation's pipelines and also the steps that are 
being taken to ensure transparency in the pipeline system to ensure 
that our cities, municipalities and citizens are given the information 
that they need to make decisions regarding public safety around the 
pipeline routes.

    The Chairman. Thank you.
    I thank the witnesses, and I appreciate the opportunity to 
revisit this issue, and I thank you for the good work.
    Next panel will be Ms. Lois Epstein, the Senior Engineer of 
Cook Inlet Keeper; Mr. Barry Pearl, President and CEO of TEPPCO 
Partners; Mr. Earl Fischer, Senior Vice President of Utility 
Operations at Atmos Energy Corporation, on behalf of the 
American Gas Association and the American Public Gas 
Association; and Mr. Robert Howard, Vice President and General 
Manager, Pipeline Operations, Gas Transmission Northwest 
Corporation, on behalf of the Interstate Natural Gas 
Association of America.
    [Pause.]
    The Chairman. Ms. Epstein, we'll begin with you. Welcome.

 STATEMENT OF LOIS N. EPSTEIN, P.E., SENIOR ENGINEER, OIL AND 
           GAS INDUSTRY SPECIALIST, COOK INLET KEEPER

    Ms. Epstein. Thank you very much, Mr. Chairman.
    Good morning. My name is Lois Epstein, and I am a licensed 
engineer and an oil and gas industry specialist with Cook Inlet 
Keeper, in Anchorage, Alaska.
    Cook Inlet Keeper is a member of the Waterkeeper Alliance, 
an alliance of approximately 100 organizations headed by Bobby 
Kennedy, Jr., and dedicated to water protection. Cook Inlet 
watershed is 47,000 square miles in size, and is where oil and 
gas first was developed commercially in Alaska, beginning in 
the late 1950s.
    The Pipeline Safety Improvement Act of 2002 followed 
several tragic pipeline events, one of which, the Bellingham 
rupture that killed three youths, occurred 5 years ago last 
week.
    The graph in my testimony shows that reported hazardous 
liquid pipeline incidents have been dropping yearly since 1994. 
It's also apparent from the graph that there has been a 
discernable upward--there has not been a discernable upward or 
downward trend in natural gas transmission or distribution 
incidents, by year. And I apologize for those of you who don't 
have a copy of the testimony. But I think it's important to put 
the trend in incidents in perspective and use that information 
in our discussion.
    The natural gas transmission pipeline integrity management 
rule will not reduce incidents on those lines for several 
years, and it's unclear how much of a reduction we can expect, 
so it's very early right now to be evaluating that rule. This 
is true for several reasons. First, the long time-frame for 
implementation will delay the benefits. Second, because the 
rule only applies to an estimated 7 percent of transmission 
pipelines, by 2007, we may expect only a 3.5 percent reduction 
in incidents. Third, since the rule allows the use of not-fully 
proven methodologies--i.e., direct assessment and confirmatory 
direct assessment--we need to wait several years to see whether 
OPS's approach will result in a meaningful reduction in 
incidents.
    Public-interest organizations are particularly concerned 
about the large portions of pipelines that currently are not 
covered by pipeline integrity management rules. For example, 
it's unclear whether the existing natural gas integrity rule 
covers the location near Carlsbad, New Mexico, where the August 
2000 pipeline tragedy occurred.
    The public also is very concerned that OPS has been unable, 
to date, to collect significant fines for violations of 
regulations from the tragedies in Bellingham and Carlsbad. OPS 
has touted the improvements it has required in those pipeline 
systems as a result of the accidents; however, that is like 
requiring brake upgrades in cars with brakes that failed and 
caused injuries and deaths. The public has no evidence that the 
increased penalties contained in Section 8 of the 2002 law are 
being used by OPS to send a message to pipeline operators that 
violations are both unacceptable and costly.
    OPS has a particularly poor enforcement record, compared to 
EPA, which, as I understand it, GAO did not look at. And EPA 
also issues fines for oil pipeline spills, sometimes totaling 
tens of millions of dollars. So I think that kind of comparison 
is relevant. While the amount of fines has gone up, it's still 
starting from a very low baseline compared to EPA and 
potentially other agencies.
    Additionally, without a preventive approach to enforcement, 
it's practically pointless to have preventive requirements in 
place, so it's important to do the enforcement before the 
accidents, as well as after.
    Section 9 of the 2002 law states that the Secretary of 
Transportation may make grants for technical assistance to 
local communities and groups of individuals, not including for-
profit entities, relating to the safety of pipeline facilities 
in local communities. OPS has not had any success obtaining 
appropriated funds for this purpose. Public-interest groups 
request that both Senator McCain and Senator Stevens, on the 
Appropriations Committee, as well as on this Committee, help 
ensure that this section of the law is carried out as intended.
    As for regulatory gaps that OPS needs to address, these are 
discussed in my written testimony. One such gap that 
particularly affects Alaska and other oil-producing states is 
the lack of regulation of rural gathering and flow lines. These 
types of lines have serious environmental impacts, and this 
Committee needs to ensure that OPS collects spill data from 
these unregulated pipelines, and develops regulations to 
prevent releases from these lines.
    Pipeline safety needs include modifications in Section 
60104(c) of the law, which covers state preemption. There are 
numerous areas of oversight and regulation--for example, 
earthquake zone provisions, enforcement, the definition of 
high-consequence areas--where states might want to exceed 
Federal requirements to enhance pipeline safety and where their 
actions would not compromise a company's ability to operate its 
pipelines safely and smoothly, nor would those actions affect 
interstate commerce.
    In summary, the Committee should pursue the following key 
items and others noted in my written testimony. Consider 
requiring OPS to make changes in the 2002 law if the natural 
gas transmission pipeline incident rate does not decline 
significantly over time. Ensure that OPS diligently enforces 
violations of its regulations, both prior to and following 
accidents. Ensure that OPS distributes pipeline safety 
information grants. Ensure that OPS continues to fill 
regulatory gaps and amend the pipeline safety law to collect 
spill data from currently unregulated gathering and flow lines. 
Amend the preemption provision of the pipeline safety law so it 
provides needed flexibility to states that wish to strengthen 
pipeline safety without impacting interstate commerce. And I 
haven't spoken about these last two items, but they are worth 
mentioning in the summary. Ensure that OPS, with its increased 
LNG responsibilities as new plants are being sited, has the 
resources it needs to ensure safety at LNG and pipeline 
facilities. And, finally, consider passage of a bill similar to 
H.R. 4277 to create a pipeline safety administration at DOT.
    Due to my time limitations, I think I'm covering a lot of 
different topics, and I hope and encourage you to look at my 
written testimony for more details. But I thank you very much 
for your interest in this important topic. And thank you, 
Senator Murray, for joining us today and for your good work on 
this issue. I look forward to your questions.
    [The prepared statement of Ms. Epstein follows:]

 Prepared Statement of Lois N. Epstein, P.E., Senior Engineer and Oil 
             and Gas Industry Specialist, Cook Inlet Keeper
    Good morning. My name is Lois Epstein and I am a licensed engineer 
and an oil arid gas industry specialist with Cook Inlet Keeper in 
Anchorage, Alaska. Thank you very much, Senator McCain, for holding 
this oversight hearing on pipeline safety and for your ongoing 
attention to this issue (even if some of that attention results from an 
unfortunate pipeline accident which took place in Tucson last July).
    Cook Inlet Keeper is a nonprofit, membership organization dedicated 
to protecting Alaska's Cook Inlet watershed and the life it sustains. 
My background in pipeline safety includes membership since 1995 on the 
U.S. Department of Transportation's (DOT's) Technical Hazardous Liquid 
Pipeline Safety Standards Committee which oversees the Office of 
Pipeline Safety's (OPS') oil pipeline activities and rule development, 
testifying before Congress in 1999 and 2002 on pipeline law 
reauthorization, and researching and analyzing the performance of Cook 
Inlet's pipeline infrastructure by pipeline operator and type.\1\ I 
have worked on safety and environmental issues for 20 years for two 
private consultants, the U.S. Environmental Protection Agency, 
Environmental Defense, and Cook Inlet Keeper.
---------------------------------------------------------------------------
    \1\ See Lurking Below: Oil and Gas Pipeline Problems in the Cook 
Inlet Watershed, 28 pp. plus appendices, September 2002. 
www.inletkeeper.org/pipelines.htm
---------------------------------------------------------------------------
    My work in Alaska is entirely focused on the Cook Inlet watershed's 
oil and gas operations. From this vantage point, I can see how well the 
policies developed in DC work in the real-world. The Cook Inlet 
watershed; which includes Anchorage and drains an area approximately 
the size of Virginia, is where oil and gas first was developed 
commercially in Alaska, beginning in the late 1950s. Cook Inlet is an 
extraordinarily scenic and fisheries-and wildlife-rich, region.
    In this testimony I will discuss:

   Implementation of the Pipeline Safety Improvement Act of 
        2002, including safety, regulatory, and policy progress, and 
        enforcement concerns;

   Ongoing pipeline safety needs, namely increased public 
        information and modifying the state preemption provision in the 
        law;

   The role of OPS in Liquified Natural Gas facility oversight; 
        and,

   The DOT reorganization and how that might impact OPS.
Implementation of the Pipeline Safety Improvement Act of 2002
    The Pipeline Safety Improvement Act of2002 (the 2002law) was passed 
by Congress on November 15, 2002 following several tragic pipeline 
events, one of which the June 10, 1999 Bellingham rupture that killed 
three youths--occurred 5 years ago last week. Since this 1999 event and 
the August 19, 2000 natural gas pipeline rupture which killed 12 people 
including 5 children, there has been increased scrutiny of the pipeline 
industry, its performance, and of deficiencies in Federal and state 
oversight. The 2002 law contains some needed improvements but, like 
many acts of Congress, it represents a compromise among competing 
interests. As a result, safety will be improved, but not necessarily by 
as much or as fast as the public would like.
    To put my presentation in context, the graph below displays the 
performance of the industry over time based on reported incidents. As 
you can see from the top line, reported hazardous liquid pipeline 
incidents dropped after 1994, two years after Congress imposed 
mandatory requirements on OPS to prevent releases that impacted the 
environment (as opposed to releases which solely affected safety). It's 
also apparent that there has not beep a discernable upward or downward 
trend in natural gas transmission or distribution incidents in recent 
years.


    It is critical for this committee and its House counterparts to 
hold periodic oversight hearings to see if the law and its resulting 
regulations are, in fact, having an impact in reducing pipeline 
accidents. Keeping the time lag for pipeline performance improvements 
in mind, I n9W will discuss regulatory progress, regulatory gaps, 
important enforcement concerns, and Pipeline Safety Information Grants 
to Communities (Section 9 of the 2002 law).
    Regulatory Progress: The most important rule issued as a result of 
the 2002law, the natural gas transmission pipeline integrity management 
rule published on December 15, 2003 which went into effect this past 
January, will not reduce incidents on those lines for several years and 
it's unclear how much of a reduction we can expect. This is true for 
several reasons. First, the law requires baseline integrity assessments 
to occur within 10 years, with 50 percent of the assessments occurring 
within 5 years of the law's enactment; this long time-frame will delay 
the benefits. Second, because the rule only applies to an estimated 7 
percent of transmission pipelines,\2\ by 2007 (i.e., five years after 
the law's enactment) we may expect only a 3.5 percent reduction in 
incidents, though the incidents that do occur should take place in 
areas of lesser consequences. Third, since the rule allows the use of 
not-fully-proven methodologies (i.e., ``direct assessment'' and 
``confirmatory direct assessment''), we need to wait several years to 
see whether OPS' approach to this rule will result in a meaningful 
reduction in incidents.
---------------------------------------------------------------------------
    \2\ OPS states in the preamble to the rule ``that about 22,000 
miles of gas transmission pipelines are located in the [High 
Consequence Areas] in a network of 300,000 miles of gas transmission 
pipeline.'' (68 Federal Register 69815, December 15, 2003)
---------------------------------------------------------------------------
    Public interest organizations are particularly concerned about the 
large portions of pipelines that currently are not covered by the oil 
and natural gas pipeline integrity rules. For example, it's unclear 
whether the existing natural gas integrity management rule covers the 
location near Carlsbad where the August 2000 pipeline tragedy occurred. 
Some of the uncovered portions of pipelines eventually might be covered 
as High Consequence Areas that are culturally or historically 
significant, a designation that has not yet been developed by OPS but 
which it committed to develop in meetings with the Technical Hazardous 
Liquid Pipeline Safety Standards Committee.
    In summary, this committee needs to pay attention over the next few 
years as to whether the natural gas integrity management rule makes a 
noticeable difference in pipeline incidents and their severity.
    Regulatory Gaps: The 2002 law required OPS to develop integrity 
management standards for natural gas distribution pipelines as well as 
for natural gas transmission pipelines, but OPS has not yet proposed an 
integrity management rulemaking to address distribution lines. This is 
not the only gap in OPS regulations, however. Also needed are 
regulations that cover gathering lines and related flowlines \3\ (as 
Congress mandated in 1992 and which OPS has made some progress on, 
holding public hearings in Austin and Anchorage 11 years later in 
2003); specific requirements for shut-off valves for oil and natural 
gas lines (as Congress mandated in 1992 and 1996); leak detection 
performance standards for oil transmission pipelines to ensure that 
leaks of a particular size are rapidly discovered, as is the case for 
crude oil transmission lines in Alaska;\4\ enhanced regulation of low-
stress oil lines given their potential for serious environmental 
impacts; requirements ensuring that operators submit revised accident 
reports which they are not required to do now (as the DOT Inspector 
General recommended \5\; and failsafe requirements to prevent over-
pressurization.
---------------------------------------------------------------------------
    \3\ These pipelines represented approximately 40 percent of 
reported releases from Cook Inlet watershed pipelines from 1997-2001. 
See Lurking Below, op. cit., p. 10.
    \4\ See 18 AAC 75.055.
    \5\  Pipeline Safety Program, Research and Special Programs 
Administration, Report No. RT-2000-069, Office of Inspector General, 
Audit Report, March 13, 2000, p. 22.
---------------------------------------------------------------------------
    Enforcement: It's clear the public is very concerned that OPS has 
been unable to date to collect significant fines for violations of OPS 
regulations from the tragedies in Bellingham and Carlsbad. OPS touts 
the improvements it has required in those pipeline systems as a result 
of the accidents,\6\ however that is like requiring brake upgrades in 
cars with brakes that failed and caused injuries and deaths. The public 
has no evidence that the increased penalties contained in Section 8 of 
the 2002 law are being used by OPS to send a message to pipeline 
operators that violations are both unacceptable and costly.
---------------------------------------------------------------------------
    \6\ Letter from DOT Secretary Norm Mineta to Congressman Rick 
Larsen, March 10, 2004.
---------------------------------------------------------------------------
    The U.S. General Accounting Office (GAO) soon will issue a report 
on OPS' enforcement record. I urge both GAO and this committee to 
compare OPS' enforcement program statistics with those of EPA, i.e., 
examining the highest penalties issued for similar types of releases 
including pipeline-related oil pollution fines levied by EPA. To 
improve its enforcement program, OPS also needs to consider initiating 
a public comment period on significant pipeline penalties, as EPA does. 
I look forward to seeing GAO's updated statistics on the rate of OPS 
fines--in 1998, GAO found that OPS proposed a fine in only 1 of every 
25 enforcement actions (a reduction from 1 in 2 in 1990),\7\ far too 
low a ratio if the government wants operators to follow regulations at 
least in part to avoid penalties.
---------------------------------------------------------------------------
    \7\ U.S. GAO, op. cit., p. 26.
---------------------------------------------------------------------------
    Additionally, as I stated in my 2002 testimony,\8\ OPS needs to 
initiate several high profile, preventive enforcement actions to deter 
potential violators. Currently, OPS only pursues high-profile 
enforcement actions following pipeline accidents. Preventive 
enforcement, in contrast, would require OPS to penalize pipeline 
companies whose operations might result in serious releases prior to a 
release occurring. Major civil enforcement actions identifying 
violations of standards prior to accidents should be publicized and 
readily available on OPS' website. Without a preventive approach to 
enforcement, it's practically pointless to have preventive requirements 
in place.
---------------------------------------------------------------------------
    \8\ Before the U.S. House of Representatives Committee on 
Transportation and Infrastructure, the Subcommittee on Highways and 
Transit, February 13, 2002.
---------------------------------------------------------------------------
    Thus, the committee needs to ensure that OPS commits to enforce 
violations of its regulations, both prior to and following accidents.
    Pipeline Safety Information Grants: Section 9 of the 2002 law 
states that:

        The Secretary of Transportation may make grants for technical 
        assistance to local communities and groups of individuals (not 
        including for-profit entities) relating to the safety of 
        pipeline facilities in local communities . . . The amount of 
        any grant under this section may not exceed $50,000 for a 
        single grant recipient. The Secretary shall establish 
        appropriate procedures to ensure the proper use of funds 
        provided under this section. (Sec. 60130(a)(1))

    To date, OPS has not established any such procedures, nor has it 
had any success obtaining appropriated funds for this purpose. As time 
goes on, there are missed opportunities for use of these funds, e.g., 
such funds might have helped community organizations understand the 
technical and regulatory issues associated with the Tucson pipeline 
accident and/or assisted public interest groups in commenting on 
ongoing regulations and standards development. Public interest groups 
request that both Senator McCain and Senator Stevens on the 
Appropriations Committee help ensure that this section of the 2002 law 
is carried out as intended.
Pipeline Safety Needs
    Increased Public Information: Pipelines do not require periodic 
renewals of operating permits so the public has almost no knowledge of 
the adequacy of pipeline operations following siting approvals. This 
means the public cannot help regulators identify High Consequence 
Areas, nor can it weigh in on the integrity measures utilized by 
particular pipeline operators. OPS and the industry have unreasonably 
resisted providing more information to the public on pipeline 
operations even though the types of additional information requested--
such as the primary threats to pipelines, the integrity assessment 
tools utilized, the leak detection strategies used would have no 
security--related value. As stated in the preamble to the natural gas 
transmission pipeline integrity management rulemaking:

        RSPA/OPS does not consider it appropriate to collect additional 
        information relevant to integrity management for public 
        dissemination. RSPA/OPS will implement an inspection program to 
        evaluate operator implementation of this rule . . . Regulators 
        will take enforcement action when appropriate, and records of 
        such enforcement will be available to the public as they are 
        now. (68 Federal Register 69800, December 15, 2003)

    From this statement, it's clear that OPS does not appreciate the 
value of the public participating in integrity management rule 
implementation and enforcement. The statement implies that the public 
has nothing to add in terms of technical analyses of trends and 
patterns and/or on-the-ground knowledge, and that OPS has foolproof 
inspection and enforcement mechanisms. Given that OPS has been 
frequently criticized for its poor enforcement record, the latter is a 
particularly implausible claim.
    Because public participation and public dissemination of 
operational data are likely to strengthen pipeline safety (the latter 
through a powerful, non-regulatory means of demonstrating progress), 
the committee should encourage OPS to provide more information on 
pipeline operations to the public.
    State Preemption: Current pipeline safety law prevents states from 
regulating and enforcing violations on interstate pipelines \9\ even if 
such regulation would improve safety and/or environmental protection 
and would not affect interstate commerce. This is an unnecessary 
intrusion on states' rights with serious adverse consequences since 
national regulations might not protect states sufficiently from 
pipeline hazards, e.g., from earthquakes, difficult cleanup terrain, 
etc. There are numerous areas of oversight and regulation (e.g., 
testing requirements, right-of-way management, landslide and earthquake 
zone provisions, enforcement, defining high consequence areas) where 
states might want to exceed Federal requirements to enhance pipeline 
safety, and where their actions would not compromise a company's 
ability to operate its pipelines smoothly and safely.
---------------------------------------------------------------------------
    \9\ 49 U.S.C. Sec. 60104(c).
---------------------------------------------------------------------------
    Interestingly, Sec. 3(a) of the 2002 law also finds the existing 
state preemption provision too broad. This provision contains a 
limitation on preemption for enforcement of state ``one-call'' 
notification programs. As this example shows, a well-designed provision 
that limits the preemption language currently in the law could 
strengthen pipeline safety.
OPS and Liquified Natural Gas Oversight
    The 2002 law contains language dating from 1968 and 1979 that 
describes OPS' role in regulating liquified natural gas (LNG) 
facilities.\10\ While much recent attention has been focused on the 
Federal Energy Regulatory Commission's role in siting LNG import-
regassification facilities, little attention has been paid to OPS' role 
in developing, implementing, and enforcing LNG siting, operating, and 
contingency plan rules.\11\
---------------------------------------------------------------------------
    \10\ 49 U.S.C. Sec. 60103.
    \11\ These rules are contained in 49 CFR 193.
---------------------------------------------------------------------------
    The reason this issue is important to the committee is that the 
committee is aware of OPS' currently constrained inspection and 
enforcement resources. Given these resource constraints and the 
likelihood that OPS will need to initiate some new LNG-related 
rulemaking, policy, and enforcement work with the expected expansion of 
new LNG facilities in the U.S., OPS soon might face severe resource 
challenges. Without additional OPS resources, safety concerns for LNG 
and/or pipeline facilities nationwide might result.
Potential DOT Reorganization
    On December 8, 2003, DOT Secretary Mineta proposed removing OPS 
from the Research and Special Programs Administration and combining it 
with the Federal Railroad Administration to form the Federal Railroad 
and Pipeline Administration. At least partly in response to this 
proposal, Congressman Young introduced H.R. 4277, a bill that would 
establish the Pipeline Safety Administration at DOT.
    In general, public interest organizations believe that pipeline 
safety should be elevated within DOT, so we are supportive of 
Congressman Young's bill. Pipelines have enormous impacts both locally 
and nationwide and for too long have been relegated to a small, obscure 
office at DOT.
Summary
    In conclusion, the committee should pursue the following items 
further in its oversight work:

   Periodically review the annual natural gas transmission line 
        incident rate to see whether the integrity management rule is 
        making a noticeable difference in the rate of incidents and 
        incident severity;

   Ensure that OPS continues to fill regulatory gaps;

   Ensure that OPS diligently enforces violations of its 
        regulations, both prior to and following accidents;

   Ensure that OPS distributes Pipeline Safety Information 
        Grants;

   Strongly encourage OPS to provide information on pipeline 
        operations with no security related value to the public;

   Research how best to amend the preemption provision of the 
        pipeline safety law so it provides needed flexibility to states 
        that wish to strengthen pipeline safety without impacting 
        interstate commerce;

   Ensure that OPS' increased LNG responsibilities do not 
        comprise safety at LNG or pipeline facilities; and,

   Consider passage of a bill similar to H.R. 4277 to create a 
        Pipeline Safety Administration at DOT.

    Thank you very much for your interest in this important topic. Feel 
free to contact me at any time with your questions or comments.
                                 ______
                                 
                                          Cook Inlet Keeper
                                        Anchorage, AK, July 2, 2004

Senator John McCain,
Chairman,
Committee on Commerce, Science, and Transportation,
U.S. Senate,
Washington, DC.

Dear Chairman McCain:

    Thank you very much for holding the full committee oversight 
hearing on pipeline safety on June 15, 2004 where I appeared as a 
witness.
    The statement on page 3 of my written testimony that there is a 
need for ``requirements ensuring that operators submit revised accident 
reports which they are not required to do now (as the DOT Inspector 
General recommended)'' requires clarification and revision. These 
requirements do exist in the pipeline safety code at:

        49 CFR 191.9(b)--for distribution pipelines

        49 CFR 191.15(b)--for gas gathering and transmission pipelines

        49 CFR 195.54(b)--for hazardous liquid pipelines

    According to the Inspector General, however, ``even when OPS knows 
the information in the original accident report is inaccurate, under 
current regulations, it cannot correct the database without an 
operator's written revision.'' \1\ The Inspector General recommended 
that OPS ``establish an enforcement mechanism to ensure [that] 
operators submit revised accident reports'' \2\ [emphasis added]. There 
still is a need for OPS to develop an enforcement mechanism, perhaps 
employing spot-checks of operator accident submittals, to ensure that 
all operators submit accurate, revised accident reports. My written 
testimony should have clearly stated such a recommendation.
---------------------------------------------------------------------------
    \1\ Pipeline Safety Program, Research and Special Programs 
Administration, Report No. RT-2000-069, Office of Inspector General, 
Audit Report, March 13, 2000, p. 5.
    \2\ Ibid., p. 22.
---------------------------------------------------------------------------
    Please include this letter in the hearing record.
            Sincerely,
                                     Lois N. Epstein, P.E.,
                                                   Senior Engineer,
                                   Oil and Gas Industry Specialist.

    The Chairman. Thank you. Your written statement, along with 
the others, will be made part of the record.
    Senator Murray, would you like to make a comment?

                STATEMENT OF HON. PATTY MURRAY, 
                  U.S. SENATOR FROM WASHINGTON

    Senator Murray. Thank you, Mr. Chairman. I appreciate the 
accommodation this morning, and I appreciate your holding this 
oversight hearing. Without your commitment and your hard work, 
along with Senator Hollings, we would never have enacted such a 
strong pipeline safety bill back in December 2002, and I 
appreciate all the work you've done on this.
    Five days ago, I was in Bellingham, Washington, at a 
ceremony marking the fifth anniversary of the Bellingham 
pipeline explosion. That explosion killed three young boys and 
left a scar in my state that still has not healed. My sister is 
a public school teacher in Bellingham, and every year she asks 
her eighth-grade students to write about the most important 
even in their life, and she told me that this year an amazing 
number of them wrote about the Bellingham pipeline explosion. 
So I hope as we examine our progress today, we don't lose sight 
of the real people whose lives have been torn apart by pipeline 
tragedies.
    I am pleased to say that we have made progress in the past 
few years because of the law we passed, the funding we secured, 
and Congressional oversight. I want to commend RSPA and OPS for 
the dramatic improvements they've made, but we know our work is 
not done.
    Before the Bellingham tragedy, like many people, I had 
never thought about the safety of our pipelines. I assumed 
someone was taking care of it. But after the accident, I 
discovered inadequate laws, insufficient oversight, too few 
inspections, and a lack of awareness about pipeline dangers. I 
learned that one of the most important public safety offices in 
our government was underfunded and neglected. So I asked 
Inspector General Ken Mead to investigate the Office of 
Pipeline Safety and give me recommendations for how to make the 
system work better.
    Through my research and discussion, I learned that we 
needed to improve many areas. Safety standards, enforcement, 
penalties, technology, public education, state participation, 
and citizen involvement. So we began to work on legislation to 
address all those areas, and worked to get hearings on the 
subject. Chairman McCain and former Senator Gorton were real 
champions on that effort. In the Senate, we passed a pipeline 
bill three times--in September 2000, in February 2001, and 
again in March 2002. Finally, the House passed a bill in July 
2002, and our Act was signed into law in December 2002. A lot 
of Members worked together to pass that law, including Senators 
McCain, Hollings, Hutchinson, Inouye, Brownback, Breaux, 
Domenici, Bingaman, Wyden, Lautenberg, Corzine, Gorton, and 
Cantwell, and Representatives Metcalf and Larson, of Washington 
State.
    Working together, we passed one of the strongest pipeline 
safety bills in American history. We then worked to fund it, 
and that has been a personal mission of mine, as the Ranking 
Member and past Chairman of the Transportation Appropriations 
Subcommittee.
    So what has happened since we passed that law? Well, let me 
give you ten facts.
    First, we are inspecting pipelines as never before, and our 
inspections are ten times more rigorous than before. Before 
this bill became law, a pipeline inspection was one person 
spending 20 hours. Today, it is a team of six people spending 
240 hours. And today all large liquid pipeline operators have 
been inspected twice.
    Second, we are finding and fixing pipeline problems at 
double the rate before the law.
    Third, we've boosted the Office of Pipeline Safety by 20 
percent, from 135 people up to 160 people now, and most of them 
are inspectors.
    Fourth, we are making real gains in new technology. I have 
secured $10 million in each of the past 2 years so we can 
develop the next generation of equipment for pipeline 
inspection, detection, repair, and monitoring.
    Fifth, we have completed a national pipeline mapping 
system.
    And, sixth, we've beefed up enforcement. In fact, in the 
past 3 years, the Office of Pipeline Safety has issued 
corrective action orders at three times the rate they did 5 
years ago.
    Seventh, we've more than doubled the size of the average 
civil penalty for violations.
    Eighth, we've given local groups expertise and a real role 
in the process.
    Ninth, we've increased our coordination with states and 
utilities so people are talking to each other before they dig.
    And, finally, number ten, we boosted public education 
through a new standard that went into effect in December of 
last year.
    And the statistics show pipeline safety has improved. 
Nationally, over the past 10 years, there was an average of 
25.2 incidents per million miles of pipeline. Over the past 3 
years, that average has declined to 21.7 incidents per million 
miles.
    As I look at all these improvements, two things stand out. 
First, we turned a slow, reactive government agency into one 
that is active and aggressively enforcing those higher safety 
standards. Today, the Pipeline Office has closed 40 of 50 
recommendations from the NTSB, and has made considerable 
progress on implementing IG recommendations. It has issued new 
rules in record time, and it has reached out to work with 
states and citizens groups as never before. And, second, we've 
empowered local citizen groups to be strong watchdogs for 
public safety. We've made progress, but our work is not yet 
done. The recent incidents in Auburn, Washington, in Arizona, 
and elsewhere show that we still have a long way to go. The IG 
and GAO have come up with recommendations on how Congress and 
OPS can further improve pipeline safety. Those recommendations 
focus on maintaining and increasing OPS monitoring of the 
Integrity Management Program and ensuring that they follow up 
with corrective action orders and penalties. It is critical 
that OPS continue to push industry to live up to their 
obligations, and to punish them when they do not.
    I want to highlight one set of recommendations the IG makes 
involving natural gas distribution lines. These distribution 
lines were not required to have integrity management plans. 
New, non-evasive technologies are being developed to test these 
pipelines for corrosion and defects, and I believe these lines 
should be required to have integrity management plans.
    Five years after the Bellingham tragedy, we've made 
progress, but we cannot slip back and assume that someone else 
is protecting us. I'm committed to work with all of you to make 
sure that we keep our eye on the ball with strong enforcement, 
oversight, coordination, and funding. And I applaud you, Mr. 
Chairman and Members of the Committee, for this commitment. And 
I know that by staying vigilant and working together, we can 
keep our communities safe.
    Thank you very much.
    [The prepared statement of Senator Murray follows:]

 Prepared Statement of Hon. Patty Murray, U.S. Senator from Washington
    Thank you, Mr. Chairman, for holding this oversight hearing. 
Without your commitment and hard work, along with Senator Hollings, we 
would have never enacted such a strong pipeline safety bill in December 
2002.
    Five days ago, I was in Bellingham, Washington at a ceremony 
marking the fifth anniversary of the Bellingham pipeline explosion. 
That explosion killed three young boys and left a scar in my state that 
still has not healed. My sister is a public school teacher in 
Bellingham. Every year, she asks her eighth grade students to write 
about the most important events in their lives. She told me that this 
year, an amazing number of them wrote about the Bellingham pipeline 
explosion. So as we examine our progress today we can't lose sight of 
the real people whose lives have been tom apart by pipeline tragedies.
    I am pleased to say that we have made progress in the past few 
years because of the law we passed, the funding we secured, and 
Congressional oversight. I want to commend RSPA and OPS for the 
dramatic improvements they have made, but we know our work is not done.
    Before the Bellingham tragedy, like many people, I'd never thought 
about the safety of our pipelines. I assumed that someone was taking 
care of it. But after the accident, I discovered inadequate laws, 
insufficient oversight, too few inspections, and a lack of awareness 
about pipeline dangers. I learned that one of the most important public 
safety offices in our government was under-funded and neglected. So, I 
asked Inspector General Ken Mead to investigate the Office of Pipeline 
Safety and give me recommendations for how to make the system work 
better.
    Through my research and discussion, I learned that we needed to 
improve many areas like safety standards, enforcement, penalties, 
technology, public education, state participation and citizen 
involvement. So we began to work on legislation to address all of those 
areas and then worked to get hearings on the subject. Chairman McCain 
and former Senator Gorton were real champions in that effort.
    In the Senate, we passed a pipeline bill three times-in September 
2000, in February 2001, and again in March 2002. Finally, the House 
passed a bill in July 2002, and our Act was signed into law in December 
2002.
    A lot of Members worked together to pass that law, including 
Senators McCain, Hollings, Hutchison, Inouye, Brownback, Breaux, 
Domenici, Bingaman, Wyden, Lautenberg, Corzine, Gorton, and Cantwell, 
and Representatives Metcalf and Larsen, both of Washington state.
    Working together, we passed one of the strongest pipeline safety 
bills in American history. We then worked to fund it, and that has been 
a personal mission of mine as the Ranking Member and past Chairman of 
the Transportation Appropriations Subcommittee.
    So what has happened since we passed the law? Let me give you 10 
facts.
    First, we are inspecting pipelines as never before, and our 
inspections are 10 times more rigorous than before. Before the bill 
became law, a pipeline inspection was one person spending 20 hours. 
Today, it's a team of six people spending 240 hours. Today, all large 
liquid pipeline operators have been inspected twice.
    Second, we are finding and fixing pipeline problems at double the 
rate before the law.
    Third, we've boosted the Office of Pipeline Safety by 20 percent 
from 135 people before up to 162 people now and most of them are 
inspectors.
    Fourth, we are making real gains in new technology. I've secured 
$10 million in each of the past two years so that we can develop the 
next generation of equipment for pipeline inspection, detection, repair 
and monitoring.
    Fifth, we have completed a national pipeline mapping system.
    Sixth, we've beefed up enforcement. In the past three years, the 
Office of Pipeline Safety has issued corrective action orders at three 
times the rate they did five years ago.
    Seventh, we've more than doubled the size of the average civil 
penalty for violations.
    Eighth, we've given local groups expertise and a real role in the 
process.
    Ninth, we've increased our coordination with states and utilities 
so people are talking to each other before they dig.
    And finally, number 10, we've boosted public education through a 
new standard that went into effect in December of last year.
    And the statistics show pipeline safety has improved. Nationally, 
over the past 10 years, there was an average of 25.2 incidents per 
million miles of pipeline. Over the past three years, that average has 
declined to 21.7 incidents per million miles.
    As I look at all of those improvements, two things really stand 
out. First, we turned a slow, reactive government agency into one that 
is active and that's aggressively enforcing these higher safety 
standards. Today, the pipeline office has closed 40 out of 50 
recommendations from the NTSB, and has made considerable progress on 
implementing IG recommendations. It has issued new rules in record 
time, and it's reached out to work with states and citizen groups as 
never before. And we've also empowered local citizen groups to be 
strong watchdogs for public safety.
    We have made progress, but our work is not done. The recent 
incidents in Auburn, WA, Arizona, and elsewhere show that we still have 
a long way to go. The IG and GAO have come up with recommendations on 
how Congress and OPS can further improve pipeline safety. Those 
recommendations focus on maintaining and increasing OPS monitoring of 
the integrity management program, and ensuring that they follow up with 
corrective action orders and penalties. It is critical that OPS 
continue to push industry to live up to their obligations and to punish 
them when they do not.
    I want to highlight one set of recommendations that the IG makes 
involving natural gas distribution lines. These distribution lines were 
not required to have integrity management plans. New, non-evasive 
technologies are being developed to test these pipelines for corrosion 
and defects. I believe these lines should be required to have integrity 
management plans.
    Five years after the Bellingham tragedy, we have made progress, but 
we can't slip back and assume that someone else is protecting us. I am 
committed to making sure that we keep our eye on the ball with strong 
enforcement, oversight, coordination and funding. I applaud the 
Chairman and other members of this Committee for their commitment, and 
I know that by staying vigilant and working together, we can keep our 
communities safe.

    The Chairman. Thank you very much.
    Mr. Pearl?

 STATEMENT OF BARRY PEARL, PRESIDENT AND CEO, TEPPCO PARTNERS, 
 L.P., ON BEHALF OF THE ASSOCIATION OF OIL PIPE LINES AND THE 
                  AMERICAN PETROLEUM INSTITUTE

    Mr. Pearl. Thank you, Mr. Chairman.
    I'm Barry Pearl, President and CEO of TEPPCO Partners, 
L.P., and Chairman of the Association of Oil Pipe Lines. I 
appreciate this opportunity to appear before the Committee 
today on behalf of AOPL and the pipeline members of the 
American Petroleum Institute. These organizations represent 
more than 50 pipeline companies that transport the vast 
majority of our Nation's liquid petroleum.
    My company, TEPPCO Partners, LP, owns and operates more 
than 11,600 miles of pipelines in 16 states. Our operations 
include one of the largest common carrier pipelines in the 
U.S., transporting refined petroleum products and liquefied 
petroleum gases from the Gulf Coast to markets in the Midwest 
and the Northeast.
    I've provided my full statement and several attachments. I 
ask that those be included in the record of this hearing. I'd 
now like to summarize that material for you.
    It has been a year and a half since the enactment of the 
Pipeline Safety Improvement Act of 2002. On behalf of the 
members of AOPL and API, I wish to thank the Members of this 
Committee for passing this very important legislation.
    As the Committee reviews the current state of pipeline 
safety, there are a few points that I'd like to emphasize.
    First, there's a growing recognition that the oil pipeline 
infrastructure is critical to the American economy. We are 
committed to improving pipeline safety while ensuring the 
delivery of essential energy supplies.
    Second, there has been tremendous progress in pipeline 
safety because of the PSIA, and also because of actions 
undertaken by the industry and by the Office of Pipeline Safety 
before the Act became law. My testimony includes two charts 
that show the improvement in the safety record of the oil 
pipeline industry. They are displayed on the easels behind me.
    Third, many of the initiatives of the Pipeline Safety Act 
are being implemented in a more than satisfactory manner, and 
on or ahead of schedule. However, for one important initiative, 
pipeline-repair permit streamlining, progress has been 
disappointing. We think that with your help we can get this 
initiative back on track.
    And, finally, we fear that much of the progress that has 
been made in pipeline safety could be diminished if not lost 
because of a reorganization plan that would transfer the 
pipeline safety program to the Federal Railroad Administration.
    Let me briefly address each of these points in turn.
    First, the role of oil pipelines. One half of total U.S. 
energy supply comes from petroleum, with 95 percent of the 
energy that powers transportation derived from petroleum 
products. Pipelines provide the only reasonable mode of 
transportation to supply large quantities of petroleum to most 
of the Nation's consuming regions. For example, two thirds of 
the ton miles of domestic petroleum transportation are provided 
by pipeline. There's no doubt that the oil pipeline 
infrastructure is crucial to American energy supply. The 
stewardship of this critical national asset is the joint 
responsibility of the industry I represent, the Department of 
Transportation, and Congress, through this Committee.
    Now, turning to pipeline safety, oil pipeline operators 
have been subject to the Office of Pipeline Safety's integrity 
management regulations since March 2001, before enactment of 
the PSIA. Our members will complete the required baseline 
testing of the first 50 percent highest-risk segments of our 
systems prior to September 30 of this year. OPS has inspected 
each of these operators under these regulations at least twice.
    The Oil Pipeline Integrity Management Program is generating 
safety benefits that significantly exceed anything anticipated 
when the program was designed. In the end, the oil pipeline 
mileage being tested under the OPS program will amount to four 
times the original estimate, and will exceed four fifths of the 
total system.
    Operators are finding and repairing many conditions in need 
of repair and many less serious conditions that are found near 
defects. For every condition repaired under the rule, 
approximately six other conditions are excavated and evaluated. 
Operators are fixing what they find, often going beyond the 
requirements of the law.
    While the benefits derived from the integrity management 
rule are much greater than originally estimated, so are the 
costs. Costs-per-operator are often running at a rate of tens 
of millions of dollars per year, far more than originally 
anticipated. Operators have, nevertheless, moved aggressively 
to provide the resources needed to implement their Integrity 
Management Programs.
    We believe that our industry's substantial investment in 
pipeline integrity and leak prevention is a sound one, 
providing long-term benefits to both pipeline operators and the 
public.
    Turning to pipeline-repair permit streamlining, an 
important initiative of the PSIA that needs the Committee's 
encouragement is the implementation of Section 16, which is 
concerned with expediting the repair of pipeline defects. Some 
limited progress has been made on implementing this section, 
but the largest portion of the work remains to be done, and the 
deadlines for energy action under the provision have passed.
    Let me discuss my own company's recent experience in 
permitting. Last year, we discovered some anomalies in a key 
part of our pipeline system that transports propane to New York 
and Pennsylvania. One segment of pipe that needed replacement 
happened to be under a reservoir in Ohio. We were very 
concerned about this project, as it had to be completed prior 
to the high seasonal demand for propane, starting around 
October. Our permitting people estimated that it could take as 
long as 6 months to permit our work, which would have been a 
problem for us and the people in the Northeast, as we transport 
40 percent of New York and Pennsylvania's propane demand and 
provide propane supply for several New England states.
    Fortunately, we were able to quickly obtain an emergency 
permit from the Corps of Engineers in just a few weeks. We had 
great cooperation from the local authorities, and completed the 
repairs in time. However, had we not been so fortunate, we 
could have had a serious supply crisis on our hands impacting 
several important populous states.
    Our point here is that we need an effective Federal permit-
streamlining initiative to ensure that all pipelines have the 
experience that we had last fall and that critical petroleum 
supplies reach the markets that our customers and your 
constituents need.
    Attached to my testimony are recent examples of operators 
who have not been as fortunate in obtaining permits required by 
Federal, state, and local agencies. These problems occur 
because these agencies do not consistently accord the priority 
to pipeline safety that this Committee and OPS expects.
    My prepared testimony includes several suggestions that we 
hope to discuss with the pipeline repair permit streamlining 
workgroup led by the Council on Environmental Quality. Our 
principal suggestion is that our industry experts be allowed to 
fully participate in the process, as we can provide valuable 
information and insight about what will work.
    My last topic relates to the proposed transfer of OPS to 
the Federal Railroad Administration. We are concerned about the 
proposal to move the OPS to the Federal Railroad 
Administration. We fear that this proposal would inevitably 
disrupt the momentum for pipeline safety that OPS and the 
industry have worked so hard to create in the past several 
years. A loss of this momentum would be much more than a loss 
for OPS. It would be a loss for Congress, the public, and for 
pipeline safety.
    We were very pleased to see the introduction of H.R. 4277, 
the Pipeline Safety Administration Establishment Act by 
Representative Don Young, Chairman of the House Transportation 
and Infrastructure Committee. This legislation would establish 
an independent pipeline safety administration within the 
Department of Transportation, with minimal disruption of OPS 
activities.
    Our support for this legislation is based, first of all, on 
its merits, which are expressed in a joint Oil and Gas 
Association letter that I have provided for the Committee's 
record.
    We urge the Committee to insist that any proposal for 
restructuring the Pipeline Safety Program not be merely 
neutral, but that it significantly enhances the program. The 
program deserves greater organizational recognition and 
authority within the Department.
    In closing, we believe that the Pipeline Safety Improvement 
Act has been a significant success, but we have much work ahead 
of us if we are to fully achieve the purposes of this very 
important legislation. Our industry pledges to work with the 
OPS in this important task.
    We need help from this Committee to ensure that a key 
section of the legislation, Section 16, related to pipeline 
repair permit streamlining, achieves the full intent of 
Congress and is effective in fostering a safer and more 
reliable pipeline infrastructure.
    We also ask that the Committee carefully consider the issue 
of the proper organizational structure within the Department of 
Transportation for the Federal Pipeline Safety Program.
    I thank you for providing me the opportunity to testify 
before the Committee on these important matters.
    [The prepared statement of Mr. Pearl follows:]

Prepared Statement of Barry Pearl, President and CEO, TEPPCO Partners, 
  L.P., On Behalf of the Association Oil Pipe Lines and the American 
                          Petroleum Institute
Introduction
    I am Barry Pearl, President and CEO of TEPPCO Partners, LP and 
Chairman of the Association of Oil Pipe Lines (AOPL). I am here to 
speak on behalf of AOPL and the pipeline members of the American 
Petroleum Institute (API). I appreciate this opportunity to appear 
before the Committee today on behalf of the AOPL and API.
    AOPL is an unincorporated trade association representing 50 
interstate common carrier oil pipeline companies. AOPL members carry 
nearly 85 percent of the crude oil and refined petroleum products moved 
by pipeline in the United States. API represents over 400 companies 
involved in all aspects of the oil and natural gas industry, including 
exploration, production, transportation, refining and marketing. 
Together, these two organizations represent the vast majority of the 
U.S. pipeline transporters of petroleum products.
    TEPPCO Partners, L.P. is a publicly traded master limited 
partnership, listed on the New York Stock exchange under the symbol 
TPP. TEPPCO owns and operates more than 11,600 miles of pipeline in 
over 16 states. Our operations include one of the largest common 
carrier pipelines of refined petroleum products and liquefied petroleum 
gases in the United States; petrochemical and natural gas liquid 
pipelines; crude oil transportation, storage, gathering and marketing 
activities; and natural gas gathering systems. TEPPCO also owns 50 
percent interests in Seaway Crude Pipeline Company, Centennial Pipeline 
LLC, and Mont Belvieu Storage Partners, L.P., and an undivided 
ownership interest in the Basin Pipeline. Texas Eastern Products 
Pipeline Company, LLC, an indirect wholly owned subsidiary of Duke 
Energy Field Services, LLC, is the general partner of TEPPCO Partners, 
L.P.
Summary
    It has been a year and a half since the enactment of the Pipeline 
Safety Improvement Act of 2002 (Public Law 107-355, the ``PSIA''). On 
behalf of the members of AOPL and API, I wish to thank the Members of 
this Committee for their leadership in passing that comprehensive and 
very important legislation.
    As the Committee reviews the current state of pipeline safety and 
the progress that has been made since the PSIA became effective, there 
are a few points that we would like to emphasize.

   First, there is a growing recognition of the importance of 
        the oil pipeline infrastructure to the American economy and the 
        interrelations between pipeline safety, pipeline economic 
        regulation and the essential energy supplies delivered through 
        that infrastructure;

   Second, there has been tremendous progress in pipeline 
        safety because of the PSIA, but there has also been much 
        progress because of actions undertaken by the industry and by 
        the Office of Pipeline Safety, even before the PSIA was signed 
        into law;

   Third, while many of the initiatives of the PSIA are being 
        implemented in a satisfactory manner and on schedule, this is 
        not universally the case, and I will cite an important example 
        at the intersection between pipeline safety and fuel supply 
        where the Committee's help is needed; and

   Finally, a warning. We strongly believe that much of the 
        progress that has been made in elevating the importance of 
        pipeline safety and empowering the Federal role in ensuring the 
        operation of an effective pipeline infrastructure is threatened 
        by a reorganization plan that we understand is pending that 
        would uproot the pipeline safety program and move it to the 
        Federal Railroad Administration.
The Role of Pipelines in Petroleum Supply
    About one-half of total U.S. energy supply comes from petroleum, 
with 95 percent of the energy that powers transportation derived from 
petroleum. Very few of the elements of the Nation's transportation 
system--the core of this Committee's jurisdiction--could operate 
without petroleum. Fully two-thirds of the ton-miles of domestic 
petroleum transportation is provided by pipeline. The total amount 
delivered by both crude oil and refined petroleum products pipelines is 
nearly twice the number of barrels of petroleum (14 billion) consumed 
annually in the United States.
    The major alternatives to pipelines for delivery of petroleum are 
tank ship and barge, which require that the user be located adjacent to 
navigable water, and truck or rail, which are limited in very practical 
ways in the volume they can transport. In fact, pipelines are the only 
reasonable way to supply large quantities of petroleum to most of the 
Nation's consuming regions. Pipelines do so efficiently and cost-
effectively--typically at 2-3 cents per gallon for the pipeline 
transportation cost charged to deliver petroleum to any part of the 
United States.
    Oil pipelines are common carriers whose rates are controlled by the 
Federal Energy Regulatory Commission. Pipelines only provide 
transportation. Oil pipeline operators do not own or profit from the 
sale of the fuels they transport. Oil pipeline rates are not related to 
the price of the products oil pipeline operators transport. Oil 
pipelines move 17 percent of interstate ton-miles but only receive 2 
percent of the total amount charged for interstate freight 
transportation, a bargain for the Nation's economy that has been 
delivering needed fuel for American consumers quietly and effectively 
for decades.
    The oil pipeline infrastructure is crucial to American energy 
supply. The care and stewardship of this critical national asset is an 
appropriate public policy concern and an important joint responsibility 
of the industry I represent, the Department of Transportation and 
Congress through this Committee.
    I've included a report by Richard A. Rabinow entitled ``The Liquid 
Pipeline Industry in the U.S.--Where It's Been and Where It's Going'' 
prepared for AOPL that provides an overview of trends in the oil 
pipeline industry.
Progress Report on Pipeline Safety: Integrity Management
    Companies represented by AOPL and API operate 85 percent of the 
Nation's oil pipeline infrastructure. Since March 2001, these operators 
have been subject to a mandatory Federal pipeline safety integrity 
management rule (Title 49, section 95.452) administered by the 
Department of Transportation's Office of Pipeline Safety. The oil 
pipeline industry's experience with pipeline integrity management 
preceded the enactment of the Pipeline Safety Improvement Act of 2002. 
Our operators will complete the required 50 percent of their baseline 
testing of the highest risk segments prior to the September 30, 2004 
midpoint deadline set by the integrity management regulations. OPS has 
inspected the performance of each of these operators under these 
regulations at least twice--an initial ``quick hit'' inspection and a 
subsequent full inspection--and is proceeding with the second round of 
full integrity inspections. We have experience with the program that 
will be instructive to the Committee in its review.
    The oil pipeline integrity management program is generating safety 
benefits that significantly exceed anything anticipated when the 
program was designed. To see how this is occurring, it is helpful to 
have a general understanding of how the integrity management program 
operates. The integrity management program requires integrity 
assessment, that is, regular safety testing with an internal inspection 
device (a ``pig''), hydrostatic pressure or other equivalent means, and 
enhanced protections for those segments of pipe that ``could affect'' a 
``high consequence area''. A ``high consequence area (HCA)'' is a 
defined term in the regulations that means a commercially navigable 
waterway, a high population area or an area unusually sensitive to 
environmental damage. Such unusually sensitive areas are also defined 
in the regulations. Each operator must have a process to determine 
whether a segment of pipe ``could affect'' an HCA. The process must 
consider a range of factors, such as the terrain, the volume and type 
of oil in the pipe and the physical ways oil released from the segment 
of pipe might impact the HCA.
    In 2000, OPS estimated that under the proposed integrity management 
system approximately 22 percent of the pipeline segments in the 
national oil pipeline network would affect an HCA and therefore that 
operators in aggregate would be required to assess and provide enhanced 
protection for 22 percent of the national system. In fact, when oil 
pipeline operators carried out their analyses of how many of their 
segments could affect the high consequence areas that were actually 
identified under the regulations, it turned out that almost twice as 
many segments, 43 percent of the pipeline network nationally, could 
affect an HCA. So the benefits in theory are nearly twice as large as 
originally estimated.
    But in fact, the benefits are even larger than that. The 
predominant method of testing oil pipelines utilizes internal 
inspection devices. The ports at which these devices are inserted into 
and removed from a pipeline are fixed in the system. These locations 
were established prior to the advent of integrity management 
regulations and without regard for the location of HCAs. The internal 
inspection devices therefore travel between ports, generating 
information about all the segments between those ports, whether they 
affect an HCA or not. As a result, as shown in OPS inspections of 
operators' plans, it is estimated that integrity testing will cover 
approximately 82 percent of the nations' oil pipeline infrastructure. 
Thus the actual mileage tested is almost four times the original OPS 
estimate.
    Operators are finding and repairing many conditions in need of 
repair and many less serious conditions that are found near defects. 
For every condition repaired under the rule, approximately six other 
conditions are excavated and evaluated. Operators are fixing what they 
find, often going beyond the requirements of the law. The largest cost 
to the operator is in the scheduling and renting of the internal 
inspection device, obtaining the permits and carrying out the 
excavation, so once the pipeline is uncovered, operators fix many 
conditions that might never have failed in the lifetime of the 
pipeline. This result is a huge additional benefit to pipeline safety 
that will reduce the risk of pipelines to the public far into the 
future.
    The benefit of the integrity management rule is much greater than 
originally estimated, so is the cost. Costs per operator that were 
estimated in the hundreds of thousands of dollars are actually turning 
out to be in the tens of millions of dollars. Operators have 
nevertheless moved aggressively to provide the resources needed to 
implement integrity management.
Integrity Management Conclusions
What are the lessons of this experience?
    OPS's integrity management program, which relies on the initiative, 
judgment and priorities of individual pipeline operators, is producing 
major benefits for the public and the environment without prescriptive 
regulation. The program is a mandatory one, so operators must 
participate, must carry out regular testing of their pipelines and must 
act promptly to address risks. But the operator has flexibility under 
the program in designing and administering the plan for testing and 
repair subject only to periodic inspection reviews by OPS. This 
partnership is proving enormously successful without resort to 
prescriptive, detailed regulations, intrusive second-guessing of 
operator decisions or aggressive enforcement with fines and penalties. 
Operators have been incurring the costs required to find the conditions 
that need repair, to make the repairs and to protect the lines for the 
future without specific assurance that these costs will be covered in 
the rates allowed by the Federal Energy Regulatory Commission. The 
integrity management program has been successful without resort to the 
threat of punishment or the need for financial incentives because the 
program aligns the interests of the operator and the regulator--to 
adopt the most effective and efficient preventative measures to keep 
the oil in the pipe. The recent spill and accident record of the 
pipeline industry (see charts) only underlines this success. It turns 
out to be true that the best investment for the operator and for the 
public is leak prevention.
Pipeline Safety: The Pipeline Safety Improvement Act of 2002 and More
    In the Pipeline Safety Improvement Act of 2002 Congress endorsed 
the integrity management approach to pipeline safety that OPS had been 
administering with the oil pipeline industry at the time of enactment 
and extended the integrity management concept to natural gas 
transmission pipelines. In addition, the PSIA contains important 
provisions:

   Coordinating permitting by Federal agencies so that pipeline 
        repairs can be carried out in a timely manner;

   Strengthening the qualifications of pipeline personnel and 
        contractors;

   Ensuring that pipeline operators are active in promoting 
        public awareness of pipelines along pipeline rights of way;

   Increasing OPS outreach to states and state regulators to 
        assist with OPS activities;

   Authorizing a promising research and development program to 
        develop better pipeline safety technology;

   Establishing a nationwide, toll-free three-digit telephone 
        number to connect excavators to their local call-before-you-
        dig, one-call notification center;

   Supporting a study of pipeline right of way encroachment 
        issues through the Transportation Research Board of the 
        National Academies of Science and Engineering; and

   Authorizing adequate funding for the operation of the Office 
        of Pipeline Safety;

    In our view, the OPS has been very aggressive in seeking to 
implement these PSIA provisions and, with one exception that I will 
mention below, the progress achieved has been excellent. In addition, 
OPS has been responding to and satisfactorily addressing Congressional 
mandates from the time before the PSIA and outstanding National 
Transportation Safety Board, General Accounting Office and DOT 
Inspector General safety recommendations. Here the progress has been 
truly impressive. We anticipate that by the end of 2004 nearly all 
outstanding mandates and recommendations to the agency will have been 
appropriately addressed. Finally, OPS has been playing a very important 
role in assisting the pipeline industry and the Department of Homeland 
Security in developing a security program to protect critical pipeline 
infrastructure.
Pipeline Repair Permit Streamlining
    An important initiative of the PSIA that needs the Committee's 
encouragement is the implementation of section 16, ``Coordination of 
Environmental Reviews'', which is concerned with expediting the repair 
of pipeline defects. Some limited progress has been made on 
implementing this section, but the largest portion of the work remains 
to be done, and the deadlines for agency action under the provision 
have passed.
    Under section 16 a Federal Interagency Committee on Coordination of 
Environmental Reviews for Pipeline Repair Projects has completed a 
Memorandum of Understanding that lays the foundation for a Federal 
pipeline repair permit streamlining process, but this MOU does not 
actually contain the provisions needed to effectuate the streamlining. 
Rather, it establishes a Working Group of Federal agency personnel to 
develop a joint regulatory approach to streamlining (which may rely on 
existing regulations of the participating agencies or may recommend 
changes to certain regulations). A successful Federal streamlining 
process will help with Federal permitting and also provide a model for 
state and local permitting agencies to follow. However, to our 
understanding the draft MOU of March 4, 2004 has not yet been signed by 
all the participating agencies and so is not effective. Nevertheless, 
the Working Group has held several meetings since the draft MOU became 
available, although to date the pipeline industry permitting experts 
have not been allowed to brief the Working Group or review its plans to 
see if any of the Working Group's proposals will actually facilitate 
pipeline repair permit streamlining.
    A central theme of the PSIA is safety through prevention. The 
purpose of section 16 is to accelerate actions that prevent pipeline 
releases. OPS requires pipeline operators to investigate the condition 
of their pipelines on a regular basis and act within a time certain to 
repair any defects discovered that are judged to require repair. The 
more severe the defect, the shorter the time-frame required to make the 
repair. Pipeline repair will typically involve an excavation to uncover 
the buried pipe at the location of the defect on the pipeline right of 
way, and any such excavation in general requires a series of permits, 
some federal, some local, and most designed to protect the environment. 
The purpose of section 16 is to ensure that Federal agencies involved 
in permitting for such excavations coordinate so that pipeline 
operators are allowed to make the repairs that are needed in the 
timeframes required by the regulations. The coordination envisioned 
would not affect existing environmental law, but might require some 
adjustments to the existing regulations of some of the environmental 
permitting agencies.
    The goal of section 16 is to see that the priority on pipeline 
safety set by this Committee and, through this Committee, by the 
Congress as a whole is implemented and is not frustrated because, 
although defects are discovered in a timely fashion to prevent 
releases, the permitting delays block carrying out the repairs needed 
to effectuate this prevention. The purpose of section 16 is to ensure 
timely actions required by one Federal agency--OPS--in the name of 
pipeline safety are not blocked by one or more other Federal agencies 
that do not have pipeline safety as a priority.
    Pipeline repair permitting delays can also have an impact on energy 
supply. When a pipeline defect cannot be repaired within the time 
limits set by OPS, the pipeline operator must reduce pipeline pressure, 
and therefore throughput, by an amount that depends on the suspected 
seriousness of the defect--a greater reduction for defects that are 
more likely to be severe, but the reduction is typically at least 20 
percent. Many operators reduce pressure on discovery of a potential 
defect. Once the repair is complete the operator is allowed to return 
to normal throughput.
The Number of Pipeline Excavations is Large Now and Will be Much 
        Larger in the Future
    Under OPS rules for oil pipeline operators, tens of thousands of 
potential defects are being discovered and repaired annually. As of 
December 31, 2003, the largest 47 oil pipeline operators have undergone 
inspection by OPS covering 97 percent of the mileage operated by these 
companies. These are the operators who eventually plan to include 
approximately 82 percent of their mileage in the mandatory testing 
program, even though strict requirements of the regulation would only 
require 43 percent of their mileage to be tested. According to OPS data 
as of the date of their respective first full inspections, these 
operators had carried out 4,344 time-sensitive repairs and 16,081 other 
repairs. Time sensitive repairs are those judged potentially serious 
enough that OPS regulations stipulate a repair deadline. These numbers 
underestimate the total volume of repairs prior to December 31, 2003 
because they only include the repairs completed prior to each 
operator's particular inspection date, all of which occurred before 
December 31, 2003.
    Completion of over 4,000 time-sensitive repairs is a success story 
of sorts, but it is not without some impact on the capacity of the 
Nation's petroleum delivery system. Many of those repairs involved 
pipeline pressure reductions. When a pipeline system operates at 
lowered pressure, its capacity is often reduced, increasing the 
likelihood of supply shortages, which generally puts upward pressure on 
petroleum prices. We do not know the extent to which the Nation's 
current oil pipeline capacity has been reduced because of pressure 
reductions occasioned by repairs.
    There is also no assurance that the required federal, state and 
local permits for pipeline repair activity can be obtained in a timely 
way even when Federal regulations set a clear deadline for completion 
of the repair. In the absence of full implementation of section 16 
there is currently no organized process to streamline the pipeline 
repair permitting process to ensure that all involved are doing what 
they can to see that the Nation's fuel supply system is not limited by 
capacity restrictions. It seems to us that it would be prudent to put 
such a process in place, as the PSIA wisely requires.
    We have been asked to forecast the magnitude of the permitting 
problems the pipeline industry will face in complying with OPS pipeline 
integrity management rules. We will try to respond. The oil pipeline 
integrity management regulations have been in effect since 2001, so our 
industry has some experience that can be used to try to answer this 
question.
    One thing is clear: the ``where'' and ``when'' associated with 
complex permitting problems is inherently uncertain. It depends on 
where the apparent defects show up in testing, and that cannot be known 
in advance. While the industry has much experience with pipeline 
repairs that predates the pipeline integrity regulations, the sheer 
number of tests and repairs being executed and the existence of 
mandatory Federal time deadlines for completing particular repairs are 
unprecedented in the industry. We are learning as we go along.
    An anecdote: a pipeline operator recently completed an internal 
inspection of a segment of pipe that produced approximately 100 
potential repairs that under OPS rules appear to require completion in 
180 days. The operator estimates that more than half of the required 
excavations for repair can be carried out routinely and another 40 can 
be carried out with the use of an Army Corps of Engineers Nationwide 
Permit. However, there are 3-5 excavations needed in locations that, at 
this time, the operator is not sure that permits can be obtained in 
time to complete the repair. So a large number of repairs will be made 
without special permitting concerns and a significant number of 
additional repairs can probably be made because of a pre-existing 
Federal permit-streamlining program. However, this pipe segment may 
nevertheless reduce pressure because of a few instances where there is 
no process in place to ensure the operator can obtain the necessary 
Federal permits that will allow them to meet the Federal repair 
deadline.
    The burden on federal, state and local permitting agencies will 
increase as the OPS program of integrity management for natural gas 
transmission pipelines takes hold and as state integrity management 
programs for intrastate pipelines that mimic the Federal program are 
implemented.
    Attached to my testimony are a number of recent examples that 
illustrate the very practical difficulties that arise for operators 
seeking in approval of the various repair site access permits required 
by federal, state and local agencies that have not been encouraged and 
are not organized to accord the same priority to pipeline safety that 
this Committee and OPS expects.
Recommendations on Pipeline Repair Permit Streamlining
    The pipeline industry has several recommendations that we believe 
would foster progress towards effective pipeline repair permit 
streamlining:

   Agree to allow representatives of the pipeline industry who 
        are experts in pipeline repair permitting to meet with the 
        Working Group to serve as a resource in providing information 
        about what is likely to be useful in expediting pipeline 
        repairs.

   Work with industry to develop a set of pre-approved pipeline 
        repair site access, use and restoration Best Management 
        Practices such that a commitment by an operator to adhere in 
        good faith to such BMPs would result in expedited permission to 
        access repair sites to carry out the repair from any of the 
        signatory agencies either through use of that agency's 
        emergency procedures or another approach that allows the repair 
        to be completed within the timeframes specified by DOT 
        regulation.

   Commitment to use pre approved BMPs should result in a 
        presumption of compliance by the operator with the requirements 
        of the BMPs and a presumption that actions beyond restoration 
        to pre-construction condition will not be required if BMPs are 
        followed.

   BMPs should be habitat-specific rather than species-specific 
        so that multiple species protection can be obtained within a 
        single umbrella BMP.

   Coordinate multi-agency response to requests for permits 
        such that involved agencies operate in parallel or in concert 
        to issue all required permissions (not just that of certain 
        agencies) to the operator in a timely fashion to allow the 
        repair to be completed within the timeframes specified by DOT 
        regulation. To the extent possible the permitting process 
        should be consolidated to limit to one the number of permits 
        required (a consolidated permit). A process is needed to ensure 
        that Federal agencies are aware of the relationships in 
        permitting pipeline repairs among federal, state and local 
        requirements and can act accordingly to achieve the goal of 
        section 16.

   With respect to compliance with the Endangered Species Act, 
        establish an agreement between the Department of Transportation 
        and the Department of the Interior under which DOT will 
        voluntarily assume the role of default coordinator, or a 
        ``nexus'' by any other name, for pipeline repairs in those 
        cases where no other Federal agency is available or able to act 
        as the Federal nexus for ESA consultation. This agreement would 
        stipulate that DOT's voluntary participation in a coordination 
        role for pipeline repairs does not mean that ordering or 
        providing for pipeline repairs through regulation is a Federal 
        action subject to the ESA or the National Environmental Policy 
        Act.

    The Federal government and the pipeline industry should be natural 
partners in seeing that the OPS integrity management program succeeds. 
The pipeline safety goals of the industry and the government are 
entirely aligned in this program. Done properly, pipeline repair permit 
streamlining will help significantly to ensure the success of this 
program, while reducing the burden on federal, state and local 
permitting agencies and allowing these agencies to focus resources on 
much more serious environmental problems. Done properly, pipeline 
repair permit streamlining will ensure the safety and reliability of 
the Nation's pipeline infrastructure. Done properly, pipeline repair 
permit streamlining will reduce the risk of higher fuel prices to the 
Nation's consumers.
    The oil pipeline industry stands ready to work with the Interagency 
Committee and the Working Group to provide the information and any 
other assistance needed to carry out the intent of section 16 of the 
PSIA.
Proposed Transfer of OPS to the Federal Railroad Administration
    Let me turn to a troublesome subject.
    In December 2003 we were informed that Secretary of Transportation 
Norman Y. Mineta intended to propose a reorganization of the Department 
of Transportation as a part of the FY 2005 budget. As part of this 
proposal, the Research and Special Programs Administration, which 
houses the Office of Pipeline Safety, would be abolished and reinvented 
as the Research and Technology Innovation Administration, an entity 
built around the Department's Volpe research center and devoted to 
transportation research and development. As a consequence, the Office 
of Pipeline Safety (and other ``special programs'' in the former RSPA) 
would be left without a home in the Department. The Secretary's 
proposed solution for the OPS would be to transfer the pipeline safety 
program to the Federal Railroad Administration, an existing DOT 
administration governing a mode judged to be most similar to pipelines.
    The oil pipeline industry and the members of AOPL and API have 
great appreciation for Secretary Mineta and all he has done to improve 
the programs of the Department of Transportation, including the 
pipeline safety program. However, our members' reaction to the proposal 
to sever the pipeline safety program from its existing location and 
place it under the Federal Railroad Administration was uniformly 
negative.
    There has been a sea change in pipeline safety in the last several 
years, and the Federal pipeline safety program has gained impressive 
and much-needed momentum. The quality and credibility of the program 
administered by the Office of Pipeline Safety has been immeasurably 
strengthened, and this strengthening is both recognized and augmented 
by Congress' unanimous enactment of the PSIA. OPS's successes have been 
accomplished through the hard work and creativity of its employees and 
particularly because of its very effective leadership during this 
period. We feel very strongly that this progress must continue. We have 
come a long way in pipeline safety, but we still have much further to 
go.
    We believe the Secretary's proposal, if implemented, would 
inevitably disrupt the momentum the agency has worked to hard to create 
in the past several years. The period required to re-establish this 
momentum can't be known for sure, but we believe it would be measured 
in years, not months. This would be much more than a loss for OPS. It 
would be a loss for Congress, the public and for pipeline safety.
    There are several reasons for our grave reservations about the 
Secretary's proposal.
   As indicated above, the proposal is not likely to be neutral 
        in terms of performance. Pipeline operator experience with 
        mergers in the private sector teaches that merged activities 
        are very susceptible to a loss in momentum, particularly for 
        the lesser of the merger partners, and often for both. The 
        pipeline safety program has made very considerable progress in 
        gathering strength and credibility in the last five years and 
        is currently heavily engaged in the implementation of PSIA 
        initiatives. Loss of this momentum through a transfer to a 
        subordinate position in a substantially different program such 
        as that of FRA would be a very serious concern for the pipeline 
        industry.

   The proposal is not likely to be neutral in terms of 
        flexibility and responsiveness. The Office of Pipeline Safety, 
        operating within RSPA, has been very creative in finding 
        solutions to problems. OPS has established a successful and 
        very well-regarded pipeline safety research and development 
        program that has attracted substantial private sector interest 
        while requiring peer review and at least 50 percent private 
        matching funds. OPS has been an active partner in creating the 
        Common Ground Alliance, a non-profit organization focusing 
        resources on preventing damage to pipelines and other 
        underground facilities. OPS is leveraging the work of the 
        National Association of State Fire Marshals to improve the 
        understanding of pipeline issues in local fire departments and 
        to provide more informed public participants in pipeline safety 
        at the local level. OPS has been successfully addressing 
        pipeline safety concerns of the National Transportation Safety 
        Board, effectively closing almost every recommendation of the 
        Board. OPS has continually worked to improve its relationship 
        with the states that have active intrastate programs and states 
        that don't. We believe it is critical to the credibility of OPS 
        that these initiatives maintain or accelerate momentum under a 
        reorganized DOT.

   The proposal does not recognize competition between 
        railroads and pipelines. Liquid pipelines and railroads each 
        transport petroleum. In certain markets there is therefore 
        business competition between railroads and pipelines. All 
        pipelines contest vigorously with railroads over the terms and 
        conditions of railroad right of way crossings. The merged 
        pipeline-railroad entity could influence this competition in 
        favor of one side over the other, most likely to the detriment 
        of the lesser merger partner.

   The proposal is not likely to be neutral in terms of budget. 
        Most Federal umbrella organizations like RSPA provide generic 
        services to the programs they house. OPS uses generic services 
        provided by RSPA. These include information technology (OPS 
        uses IT heavily); training; regional office support; advisory 
        committees (two); budget development; procurement and 
        contracting; legal and policy support; and state programs. 
        Currently, FRA capabilities and expertise do not match RSPA's 
        in the services used by OPS. Replicating these services within 
        FRA would increase the cost of the merger by an estimated 5-10 
        percent, while likely failing, at least initially, to provide 
        services fully replacing those that had been received from 
        RSPA.

   Separation of budgets would be required. OPS is fully funded 
        by the transmission pipeline industry through user fees and the 
        Oil Spill Liability Trust Fund; FRA is taxpayer funded. Equity 
        would require careful separation of budgets in the merged 
        organization so that pipeline operators do not subsidize 
        railroad operations.

   The Federal Railroad Administration's budget is volatile. 
        FRA's budget includes Amtrak funding at several hundred million 
        dollars ($1,218 million in 2004 enacted, $900 million in 2005 
        as proposed, with Amtrak recently estimating that $1,800 
        million is actually required in 2005). Routine fluctuation in 
        FRA's budget annually significantly exceeds the amount of the 
        entire OPS budget. Within the merged railroad-pipeline entity, 
        there may be significant uncertainty or actual fluctuation in 
        the budget amounts available to the pipeline program relative 
        to the experience in RSPA.
HR 4277
    We were very pleased to see the introduction by the Chairman of the 
House Transportation and Infrastructure Committee, Rep. Don Young (R-
AK), of H.R. 4277, the Pipeline Safety Administration Establishment 
Act. This legislation would establish an independent pipeline safety 
administration with the Department of Transportation with minimal 
disruption of OPS activities.
    Our support for the legislation is based first of all on its 
merits. As I have testified, we believe the Federal pipeline safety 
program has become much stronger and more effective in recent years and 
the importance of the program and the infrastructure it oversees has 
received greater recognition than in the past. The Federal pipeline 
safety program deserves greater organizational recognition in the 
Department that befits its importance to the Nation.
    We also welcome Chairman Young's initiative in introducing H.R. 
4277 because it provides a significant alternative to the Secretary's 
proposal to place the pipeline safety under the Federal Railroad 
Administration and changes the nature of the conversation about the 
appropriate organizational structure for the program. The five 
associations that represent the Nations' oil and natural gas pipelines 
recently expressed our views on H.R. 4277 and the Secretary's proposal 
in a joint letter to Chairman Young. I have provided a copy of that 
letter for the Committee's records.
    The tests for any new organizational structure for the Federal 
pipeline safety program are whether it strengthens the program, whether 
it helps make the program more effective and credible and whether it 
will further the hard work ahead to continue the progress the program 
has made. We plan to judge any proposal for structuring the pipeline 
safety program based on these tests.
    The oil pipeline industry supports competent, effective, and 
credible Federal pipeline safety regulation. The nature of the 
commodities carried in oil pipelines and the level of public confidence 
pipeline operators are able to inspire mean some level of oversight is 
inevitable. Public confidence in the safety of pipelines, and our 
ability to continue to operate pipelines with the public's trust 
depends on the perception and the reality of competent oversight. The 
interstate character of the business and, indeed, the interstate 
character of the physical facilities themselves, require that the 
Federal government have the primary responsibility for this oversight. 
We therefore strongly believe that pipeline safety oversight should be 
housed in the U.S. Department of Transportation. If the structure 
governing the pipeline safety program within DOT has to change, we 
would urge the Committee to very carefully consider the impact of the 
change on stature of the program and the implications for the highly 
important service pipelines provide to the Nation.
    The PSIA set an ambitious but highly appropriate course for the 
Federal pipeline safety program. H.R. 4277 opens the dialogue on the 
proper organizational structure to complement and facilitate the 
success of that program. The pipeline members of AOPL and API look 
forward to working with the Committee as this dialogue moves ahead.
Conclusion
    Thank you for the opportunity to testify before the Committee on 
these important matters. The Committee's work product, the PSIA, is in 
our view a significant success, but all those interested in pipeline 
safety have much work ahead of us if we are to fully achieve the 
purposes of this very important legislation. Our industry pledges to 
seek alignment with the OPS to the maximum extent practicable in this 
important task.
    We need help from this Committee to ensure that a key section of 
the legislation, section 16, relating to pipeline repair permit 
streamlining, achieves the full intent of Congress and is effective in 
fostering a safer and more reliable pipeline infrastructure. We also 
ask that the Committee carefully consider the issue of the proper 
organizational structure within the Department of Transportation for 
the Federal pipeline safety program, an issue that has been raised by 
the Secretary in his proposed reorganization of the Department and by 
the legislation introduced by Chairman Young.
    Thank you very much.
                                 ______
                                 
    Pipeline Integrity Management Program--Case Study Supporting a 
              Streamlined Permitting Process--Case Study 1
    Situation involves replacement of a line with dents. A series of 
dents are located on one piece of pipe in the middle of the pipeline 
crossing of the Delaware River. We ran in-line inspection tools and 
found the dents.
    The situation prohibits repair in place so we will have to drill 
and pull into place a new pipeline segment across the Delaware River, 
from New Jersey to Pennsylvania shores, in the Philadelphia area.
    This requires permits from the Core of Engineers, Fish and Game 
Commission, Commonwealth of Pennsylvania, State of New Jersey, local 
township(s), and the Philadelphia Airport. The permitting process 
(preparation, submittals, administration and technical reviews, 
revisions, final approval, etc.) takes more than one year to complete, 
of which 240 days alone are required for administrative and technical 
reviews.
    In accordance with OPS Integrity Management regulations, we reduced 
the pipeline operating pressure once. Since further remedial action is 
required if we cannot complete repairs within 365 days, we have had to 
reduce the pressure again, while in the process of obtaining all of the 
above mentioned permits and completing the pipeline replacement.
                                 ______
                                 
    Pipeline Integrity Management Program--Case Study Supporting a 
              Streamlined Permitting Process--Case Study 2
    Project Overview: In California, a pipeline company initiated a 
project in 2002 to conduct investigations of anomalies identified 
during a pipeline ``smart pig'' inspection survey run in 2001 that 
identified over 45 anomalies. The pipeline traverses environmentally 
sensitive habitat including freshwater wetlands, tidally influenced 
marshland, and habitat supporting several federally-and state-listed 
plant and animal species. The permitting process is complicated by 
various work windows that prevent or limit maintenance activities 
during specific times of the year along the pipeline right-of-way 
(e.g., seasonal flooding conditions, breeding and nesting seasons for 
listed species, etc.). These anomaly dig locations were similar to digs 
pursued in 2001 from a 1999 ``smart pig'' survey that took 14 months to 
process the permits.
    Overview of Permitting Process: The project took 10 months to 
permit. Permitting involved four different Federal and state regulatory 
agencies. The U.S. Army Corps of Engineers (ACOE) was the lead agency 
for permitting. They were involved because the dig locations were 
located within `''waters of the United States''. The U.S. Fish and 
Wildlife Service (USFWS) were also involved due to the potential 
presence of the federally protected species including endangered vernal 
pool tadpole shrimp, the threatened vernal pool fairy shrimp, the 
threatened giant garter snake, the endangered salt marsh harvest mouse, 
the endangered California clapper rail, the threatened Sacramento 
splittail, and the threatened Delta smelt. California agencies involved 
were the California Regional Water Quality Control Board (RWQCB) and 
the San Francisco Bay Conservation and Development Commission (BCDC).
    Applications for digs indicated by the inspections were submitted 
in August 2002 for the following permits:

   ACOE Section 404 Pre-construction Notifications under 
        Nationwide Permit 3;

   RWQCB 401 Water Quality Certifications triggered by the 404 
        process;

   Endangered Species Act (ESA), Section 7 biological 
        consultation with the USFWS; and

   BCDC permit waiver pursuant to Section 29508 of the Suisan 
        Marsh Preservation Act.

    After the notification was submitted to the ACOE, the ACOE waited 
until May 2003 to send its letter to the USFWS to initiate the Section 
7 consultation in May 2003. Fortunately, the applicant t had been 
working with USFWS for months preceding the May 2003 letter from ACOE. 
Only because work was initiate and pursued by the operator on parallel 
tracks could final permits be issued in June 2003.
    Approximately 70 permit conditions were included in the four 
permits. Permit conditions addressed the following general areas:

   Protecting soil and water from contamination during repair 
        activities;

   Protection of the federally protected species during 
        construction;

   Restoration of the areas to pre-construction conditions; and

   Mitigation for the impacts to species and habitat.

    Lessons Learned from Case Study: There are a number of ways to 
improve the permitting process. Ten months is too long to permit 
relatively straightforward pipeline repair activity. It is not possible 
to meet the OPS rule repair time limit (e.g., immediate to 6 months) at 
locations where environmental permitting (with its extensive agency 
interactions) is required.
    Ways to streamline the permitting process include:

   Streamlining the ACOE permitting process to expedite 
        pipeline repairs while protecting the environment. Agency pre-
        review and approval of relatively routine activities prior to 
        their commencement is not necessary. An alternative approach is 
        to develop a set of Best Management Practices (BMPs) to protect 
        the environment during repair activities, possibly similar to a 
        Habitat Conservation plan or a nationwide Permit, that includes 
        all jurisdictional agencies. Repair activities that use these 
        BMPs would no require prior review and approval.

   ACOE permitting in states such as California is sequential, 
        i.e., the ACOE reviews, then request consultation with the 
        USFWS. Each agency approves a permit before they pass the ball 
        to the next regulatory agency. Instead there should be a 
        parallel review process. For projects that do not qualify to 
        use BMPs, OPS could act as a n ombudsman to resolve permitting 
        issues among the various agencies and improve the safety of 
        pipeline.

   Alternatively, for projects that require agency review, a 
        site-specific plan for conducting the pipeline repair could be 
        developed and submitted to the appropriate agencies for their 
        review. If agencies did not respond after an appropriate 
        interval consistent with time requirements in the 2001 OPS IMP 
        rule the repair project could proceed under the `safe harbor' 
        of the conditions proposed in the applications.
                                 ______
                                 
    Pipeline Integrity Management Program--Case Study Supporting a 
              Streamlined Permitting Process--Case Study 3
    A 20'' diameter products pipeline was scheduled to undergo an in-
line inspection in accordance with DOT's Integrity Management Rule. The 
inspection on this system was scheduled such that the operator would 
expect to receive the tool data during June 2004.
    A portion of the subject pipeline system traverses the Louisiana 
Coastal Management Zone which is under the jurisdiction of the 
Louisiana Department of Natural Resources, Coastal Management Division 
(CMD). Other agencies with jurisdiction over the pipeline's inspection 
include the U.S. Army Corps of Engineers (USACE) and the Parish Coastal 
Zone Management Committee.
    In anticipation of the upcoming inspection, the operator filed an 
application with the CMD for an ``Area Permit''. The Area Permit is a 
relatively new permitting process utilized by the CMD (it was 
promulgated in October 2003) and is supposedly a streamlined process 
for allowing more timely pipeline repairs. The intent behind the Area 
Permit is to function as a general permit for the entire pipeline 
system within the Coastal Zone; however, the Area Permit does not 
authorize individual IMP repairs. Individual repairs are not authorized 
until the operator has provided the agency with site specific 
information about each repair location. The CMD suggests that once an 
operator has received Area Permit approval, individual IMP repairs can 
be authorized very quickly once the operator has provided the site 
specific information.
    During early coordination with the CMD, the agency advised that 
they would be coordinating their review and approval of the Area Permit 
application in conjunction with the USACE. In fact, the operator was 
instructed to complete the USACE's standard permit application form 
(Form 4345) as part of the application package. However, during later 
discussions with the USACE, the operator learned that the USACE does 
not recognize the Area Permit as a valid permitting mechanism.
    Despite the efforts in Louisiana to streamline the permitting 
process for IMP repairs, the Area Permit process seems to need further 
refinement in order to be truly valuable to pipeline operators. First, 
the CMD needs to understand that in the event of immediate conditions, 
there is often very little time to prepare the necessary site specific 
information including taking photos of the repair locations, generating 
maps of repair locations, etc. and get this information submitted to 
the CMD prior to initiating any repair activities. The impacts caused 
by IMP repairs, even in environmentally sensitive areas such as the 
Coastal Zone, are general minor and temporary in nature and should not 
warrant such extensive review.
    Secondly, there appears to be a disconnect between the CMD and the 
USACE regarding the validity of the Area Permit process. Better 
coordination between these two agencies could result in the development 
of one permitting process that would address impacts caused by IMP 
repairs to ``waters of the US'' as well as impacts to the Coastal Zone.
    Due to the uncertainty of being able to effect repairs, should the 
circumstance arise, the operator has temporarily postponed an In-line 
Inspection (but will still meet the regulatory deadline) of this system 
in order to get the permits in place. If the permits are not obtained 
by the regulatory deadline, and the operator is forced to shut down the 
system after conducting the In-line Inspection (and unable to effect 
repairs in a timely manner), there could be a potential loss of motor 
fuel supply to the Southeast/East Coast of up to 9,800,000 gallons per 
day. That could equate to (assuming 25 gallons of motor fuel are used 
to fill up an average vehicle) 392,000 vehicles per day that could be 
forced to look elsewhere for fuel, if it were available.
                                 ______
                                 
    Pipeline Integrity Management Program--Case Study Supporting a 
                     Streamlined Permitting Process
    Early 2002, a deformation with metal loss was identified on a pipe; 
under the IMP rule, this is an immediate condition. The geographical 
location of the pipe is within a large wetland complex and within the 
boundaries of a State Game Area which is managed by the Michigan 
Department of Natural Resources.
    It was determined that this condition met the requirements of a 
Safety Related Condition as stated in 49 CFR 195.55 due to its location 
within an HCA. As such, operating pressure on the system was reduced by 
20 percent and a SRC Report was filed with OPS five days after 
discovery.
    Excavation and repair of this condition required a Land and Water 
Management (LWM) Permit which is a joint permitting process between the 
USACE and Michigan DEQ for Clean Water Act Section 404/401 impacts. A 
Special Use Permit was needed from Michigan DNR for working within the 
State Game Area. A Soil and Erosion Control Permit from the Muskegon 
County Department of Public Works was also required.
    The unusual site conditions presented some challenges for accessing 
and dewatering the repair area since it was located in the middle of 
the expansion wetland and under approximately 4 ft. of water. It took 
several days to finalize the repair methodology which was needed prior 
to submitting the permit applications.
    Once repair plans had been finalized, LWM permit applications were 
simultaneously submitted to the USACE and MDEQ 34 days after the 
initial find. Approximately one month (28 days) later, both agencies 
requested additional repair drawings. The drawings were provided to 
both agencies within 10 days of their request. The issuance of LWM 
permit approval was finally received 76 days after the initial 
discovery and 43 days after the application was submitted. 13 days 
after issuance of the LWM, authorization was received from the USACE 
under Nationwide Permit 12.
    An attempt to investigate and repair the condition ensued 110 days 
after discovery, but because of the depth of the water and substrate, 
the work could not be executed in the manner authorized under the above 
reference permits.
    A revised repair methodology was submitted to USACE and MDEQ 4 days 
later, requesting that the previously issued permits be modified to 
allow for the new construction techniques. MDEQ responded to this 
permit amendment request exactly one month later, via letter 
authorization. Similarly, the USACE responded 37 days after the revised 
request was submitted, by authorizing the work under Nationwide Permit 
33. The repairs were finally completed 237 days after the discovery; 
more than six months after permitting efforts were initiated.
    It should be noted that only the USACE and MDEQ permit 
authorizations were difficult to obtain. The Special Use Permit and the 
Soil Erosion Control Permit were both obtained within only days after 
applications for these permits were filed.
    Reducing the pressure on this system has the net effect of removing 
7,600 barrels/day of refined products from the market. Had this 
situation occurred in June, 2000, it would have further exacerbated the 
supply issue that was occurring in the State of Michigan at that time.
                                 ______
                                 
    Pipeline Integrity Management Program--Case Study Supporting a 
              Streamlined Permitting Process--Case Study 5
    The Integrity Management Rule requires certain pipeline defects 
repaired within specific timelines. If these timelines cannot be met, a 
20 percent operating pressure reduction must be taken until the defect 
is repaired or the system is otherwise modified to allow continued safe 
operation. In certain markets, this reduction in operating pressure can 
potentially reduce supply by more than 200,000 barrels per day (nearly 
one million gallons per day) having significant impacts on supply. In 
the fourth quarter of 2003 when distillate demand to the northeast is 
high, a pipeline repair could not be made within the 180-day time frame 
forcing a 20 percent pressure reduction on the pipeline. Within two 
weeks it became apparent that supplies to New York markets could be 
jeopardized. Numerous reasons attributed to the repair not being 
completed in the 180 days. One of which was permitting that eventually 
took 18 months and significant resources to obtain the proper permit 
for the appropriate repair method needed to complete the repair. 
Acquisition of the final permit that provided a practicable repair 
solution required a five month period and involved extensive lobbying 
of twelve Federal, State, and local environmental agencies, the 
Goverernor's office, and other resource stakeholders and interest 
groups.
    In the meantime, other system changes were made to allow continued 
operation at normal operating pressures. In absence of these solutions, 
shortages in jet fuel to key northeast airports as well as significant 
shortages of heating oil to northeast markets were probable. 
Furthermore, operation of refineries in the Gulf Coast and at least one 
additional pipeline in the northeast would have been impacted.
    Near misses such as the one described above underline the need for 
permit streamlining. Coordination is necessary among pipeline 
operators, federal, state and local permitting agencies and the OPS. 
The Pipeline Safety Improvement Act was meant to protect public safety 
and the environment. Through permit streamlining, the intent of the Act 
and all stakeholders' objectives will be met along with timely repairs 
to pipelines, protection of the environment, and maintaining stability 
in fuel markets.
[GRAPHICS NOT AVAILABLE IN TIFF FORMAT]
                                 
                                 ______
                                 
                                                       May 20, 2004
Hon. Don Young,
Chairman,
Committee on Transportation and Infrastructure,
U.S. House of Representatives,
Washington, DC.

Dear Chairman Young:

    On behalf of the natural gas and petroleum pipeline industries, we 
want to thank you for introducing H.R. 4277, the ``Pipeline Safety 
Administration Establishment Act.'' We believe this legislation helps 
ensure the continued improvement and effectiveness of the Office of 
Pipeline Safety (OPS) within the Department of Transportation (DOT).
    The members of our associations are united in our concern about the 
ramifications of DOT's draft reorganization plan announced by Secretary 
Mineta in December of 2003. While the announcement focused on the 
benefits of organizing DOT's research and development functions within 
a single administration, the secretary also proposed merging the 
Federal Railroad Administration (FRA) and OPS. We believe this merger 
would be detrimental to the mission and the performance of OPS. 
Therefore, we oppose such a merger.
    The Office of Pipeline Safety has made great strides in improving 
its effectiveness over the last five years. It has successfully 
completed a number of critical rulemakings, including ones regarding 
hazardous liquid and natural gas pipeline integrity. OPS also has made 
outstanding progress both in fulfilling its Congressional mandates and 
in implementing DOT Inspector General and National Transportation 
Safety Board recommendations. OPS is not broken by any measure, and 
that is why we are concerned about the implications of DOT's proposed 
reorganization.
    Your legislation gives OPS the autonomy and accountability it needs 
to fulfill its mandate to protect the public. If DOT attempts to 
proceed with a reorganization plan that includes merging OPS with FRA, 
we strongly encourage your committee to hold a hearing that will allow 
for a full and open discussion among all stakeholders.
    We support your efforts to strengthen the Department of 
Transportation's pipeline safety program and look forward to working 
with you in that regard. Thank you once again for introducing H.R. 
4277. If there is anything further we can do to assist you in your 
efforts, please do not hesitate to contact us.
            Sincerely,

Red Cavaney
President and CEO
American Petroleum Institute

Bert Kalisch
President and CEO
American Public Gas Association

Donald F. Santa, Jr.
President Interstate
Natural Gas Association of America

Benjamin S. Cooper
Executive Director
Association Oil Pipe Lines

David Parker
President and CEO
American Gas Association

  
  

    The Chairman. Thank you very much.
    Mr. Fischer, welcome.

   STATEMENT OF EARL FISCHER, SENIOR VICE PRESIDENT, UTILITY 
OPERATIONS, ATMOS ENERGY CORPORATION, ON BEHALF OF THE AMERICAN 
    GAS ASSOCIATION AND THE AMERICAN PUBLIC GAS ASSOCIATION

    Mr. Fischer. Thank you, sir.
    Good morning, Mr. Chairman and Members of the Committee. 
I'm pleased to appear before you today.
    My name is Earl Fischer, and I'm the Senior Vice President, 
Utility Operations of Atmos Energy Corporation. Atmos Energy is 
one of the largest pure natural gas distributors in the United 
States, delivering natural gas to about 1.7 million 
residential, commercial, industrial, and public authority 
customers. Our regulated utility services are provided to more 
than 1,000 small- and medium-size communities in 12 states.
    I am here testifying today on behalf of the American Gas 
Association, AGA, and the American Public Gas Association, 
APGA. I hope that my testimony today will provide for a better 
understanding of how distribution systems work and how the 
implementation of the Pipeline Safety Improvement Act of 2002 
affects us.
    Let me begin by commending Congress for passing a fair and 
balanced pipeline safety bill in 2002. This Committee, and 
Chairman McCain in particular, had a very significant role in 
seeing that the bill went through, and I and both of our trade 
associations thank you for your commitment and your leadership. 
I join Senator Murray in her comments, as well.
    Gas distribution utilities like Atmos are the last critical 
link in the natural gas delivery chain. To most customers, 
utilities are the face of the industry. We are the meter at the 
house. We interact daily with our customers and the public in 
the areas that we serve. Over the last 17 years, the amount of 
natural gas traveling through distribution pipelines has 
increased by almost a third, and more than 650,000 miles of 
pipeline have been added to the system during that period of 
time, yet the number of reportable incidents on distribution 
pipelines has decreased by 25 percent. This is a remarkable 
achievement, one that AGA and APGA attribute to the industry's 
overarching commitment to safety. At the same time, our 
commitment drives us to continually look for effective ways to 
improve our record.
    Natural gas distribution pipelines are thoroughly 
regulated. As part of an agreement with the Federal Government 
in most states, state pipeline safety authorities have primary 
responsibility to regulate natural gas utilities and intrastate 
pipeline companies. In return, state governments have to adapt, 
as minimum standards, the Federal set of standards promulgated 
by the Department of Transportation. DOT, then, reimburses the 
state for up to 50 percent of their pipeline safety enforcement 
costs.
    Distribution systems are constructed in configurations that 
look like a network or a web, use smaller-diameter pipe, and 
operate in high-density population areas at much lower volumes 
and at much lower pressures.
    So what has occurred since implementation of the Pipeline 
Safety Improvement Act of 2002? The United States Department of 
Transportation Office of Pipeline Safety and Industry has 
diligently worked to address much of the scrutiny that arose 
during the debate of the 2002 bill. To their credit, OPS has 
dealt with the vast majority of this backlog, and is moving 
expeditiously to address the congressional mandates.
    Given this tremendous progress, we are concerned over the 
proposed reorganization of DOT that would include moving OPS 
into the Federal Railroad Administration. Indeed, we cannot 
understand the rationale for wanting to make any move that 
could jeopardize this positive momentum that Mr. Pearl spoke 
about, as well.
    In the most effective use of the span of time allowed us at 
this oversight hearing on pipeline safety, allow me to 
highlight six points that illustrate the progress made, with a 
more complete list being contained in my written testimony.
    Point number one. The programs required by the Pipeline 
Safety Act are well underway. Many gas pipeline operators have 
already begun implementing the integrity rule, and many more 
will be ready to begin assessments by the deadline on June 17, 
2004, only 2 days away. Approximately 30,000 miles of gas 
transmission lines operated by gas distribution utilities will 
have to be assessed under this rule, at a cost of $3 billion in 
20 years. At the same time, we must maintain an interruptible 
gas supply to our customers.
    Point number two. We must expedite the environmental 
permitting process, as others have testified here today. Our 
members estimate that they must perform about 110,000 integrity 
inspections requiring excavation on intrastate pipelines over 
the next 7 years, and that is five or more per mile on the 
average. We need a more efficient process that will not allow 
one agency to prohibit a citizen from taking action required by 
another agency. There are good options under existing 
environmental laws for ensuring environmental protection in a 
way that is less process-intense.
    Point three. Injuries, fatalities, property loss, and the 
disruption of services could be reduced with the better use of 
the three-digit/one-call centers and systems. The Pipeline 
Safety Act also helped improve the systems by clarifying that 
State Departments of Transportation should participate; 
however, there is still nothing that will compel them to do so.
    Point four. There has been significant progress on several 
other initiatives, including a right-of-way encroachment study, 
operator-qualification standard development, and public-
awareness communications rulemaking.
    Point five. I am pleased to report that the American Gas 
Foundation, with AGA, APGA, state and Federal regulator 
involvements, is proactively exploring existing regulations and 
practices addressing distribution system integrity in an effort 
to identify any needed enhancements. You should note that we 
have already identified a dozen currently mandated inspection 
requirements for distribution systems.
    Point six is a plea for specific time to measure the 
results. In summary, we are underway with our implementation 
process. We think it would be premature to currently draw 
conclusions on the results of any of these programs, which have 
also resulted in a substantial number of regulatory mandates. 
We humbly request to be given sufficient time for effectiveness 
verification.
    Public safety is the top priority of natural gas utilities. 
Historically, approximately one half of the current $6.4 
billion is spent by utilities in compliance with Federal and 
state regulators. At the same time, the other half is spent to 
ensure that our systems and communities are safe and that our 
gas is always reliably there.
    Thank you for providing the opportunity to present our 
views on this very important matter of pipeline safety.
    Thank you.
    [The prepared statement of Mr. Fischer follows:]

  Prepared Statement of Earl Fischer, Senior Vice President, Utility 
  Operations, Atmos Energy Corporation, On Behalf of the American Gas 
          Association and the American Public Gas Association
    Good morning, Mr. Chairman and members of the Committee. I am 
pleased to appear before you today and wish to thank the Committee for 
calling this hearing on the important topic of pipeline safety. My name 
is Earl Fischer. I am Senior Vice President, Utility Operations of 
Atmos Energy Corporation. Atmos Energy is one of the largest pure 
natural gas distributors in the United States, delivering natural gas 
to about 1.7 million residential, commercial, and industrial and 
public-authority customers. Our regulated utility services are provided 
to more than 1,000 small and medium-size communities in 12 states.
    I am here testifying today on behalf of the American Gas 
Association (AGA) and the American Public Gas Association (APGA). The 
American Gas Association represents 192 local energy utility companies 
that deliver natural gas to more than 53 million homes, businesses and 
industries throughout the United States. AGA member companies account 
for roughly 83 percent of all natural gas delivered by the Nation's 
local natural gas distribution companies. AGA is an advocate for local 
natural gas utility companies and provides a broad range of programs 
and services for member natural gas pipelines, marketers, gatherers, 
international gas companies and industry associates.
    The American Public Gas Association is the national, non-profit 
association of publicly owned natural gas distribution systems. APGA 
was formed in 1961, as a non-profit and non-partisan organization, and 
currently has 606 members in 36 states. Overall, there are 949 
municipally owned systems in the U.S. serving nearly five million 
customers. Publicly owned gas systems are not-for-profit retail 
distribution entities that are owned by, and accountable to, the 
citizens they serve. They include municipal gas distribution systems, 
public utility districts, county districts, and other public agencies 
that have natural gas distribution facilities.
    Natural gas meets one-fourth of the United States' energy needs. I 
am pleased to appear here today and hope that my testimony will provide 
you with a better understanding of how distribution systems work and 
how the implementation of the Pipeline Safety Improvement act of 2002 
affects us.
    AGA, APGA and its members commend Congress for ensuring that the 
safety bill passed in 2002. The legislation that was finally passed in 
the final days of the 104th Congress was a balanced, fair bill and will 
bring yet further safety improvements. This Committee and Chairman 
McCain in particular, had a very significant role seeing that the bill 
went through and I and the industry thank you for your commitment and 
leadership.
    We would also like to commend the U.S. Department of Transportation 
Office of Pipeline Safety (OPS) for diligently working to address much 
of the disapproval that arose during the debate on the 2002 bill. OPS 
was criticized by Congress, the National Transportation Safety Board, 
DOT's Inspector General, and members of the public for not addressing 
numerous congressional mandates and safety recommendations. To their 
credit, OPS has dealt with the vast majority of this backlog and is 
moving expeditiously, and often in consultation with all affected 
stakeholders, to address the mandates in the Pipeline Safety 
Improvement Act of 2002. Given this tremendous progress, we are 
concerned over the proposed reorganization of DOT that would include 
moving OPS into the Federal Railroad Administration. Indeed, we cannot 
understand the rationale for wanting to make any move that could 
jeopardize this positive momentum.
Gas Distribution Utilities Serve The Customer
    Gas distribution utilities or Local Distribution Companies (LDCs) 
are the last, critical link in the natural gas delivery chain. To most 
customers, utilities are the ``face of the industry''. Our customers 
see our name on their bills, our trucks in the streets and our company 
sponsor ship of many civic initiatives. We live in the communities we 
serve and interact daily with our customers. Consequently, we take very 
seriously the responsibility of continuing to deliver natural gas to 
our communities safely, reliably and affordably.
Natural Gas Utilities Are Committed to Safety
    Safety is a top priority, a source of pride and a matter of 
corporate policy for every company. These policies are carried out in 
specific and unique ways. Each company employs safety professionals, 
provides on-going employee evaluation and safety training, conducts 
rigorous system inspections, testing, and maintenance, repair and 
replacement programs, distributes public safety information, and 
complies with a wide range of Federal and state safety regulations and 
requirements. Individual company efforts are supplemented by 
collaborative activities in the safety committees of regional and 
national trade organizations.
    Our industry's commitment to safety is borne out each year through 
the National Transportation Safety Board's annual statistics. Delivery 
of energy by pipeline is consistently the safest mode of energy 
transportation. Natural gas utilities are dedicated to seeing this 
continue. Over the last 17 years, the amount of natural gas traveling 
through distribution pipelines has increased by almost a third and more 
than 650,000 miles of pipeline have been added to the system--yet the 
number of reportable incidents on distribution pipelines has decreased 
by 25 percent. This is a remarkable achievement, one that AGA and APGA 
attribute to the industry's overarching commitment to safety.
    Natural gas distribution pipelines are thoroughly regulated. As 
part of an agreement with the Federal Government, in most states, State 
pipeline safety authorities have primary responsibility to regulate 
natural gas utilities as well as intrastate pipeline companies. 
However, state governments have to adopt as minimum standards the 
Federal safety standards promulgated by the DOT. In exchange, DOT 
reimburses the State for up to 50 percent of their pipeline safety 
enforcement costs. Therefore, what Congress does affects state 
regulations and our companies. The states may also choose to adopt 
standards that are more stringent than the Federal ones.
The Difference in ``Pipelines''
    While many may unintentionally link all ``pipelines'' together, 
there are indeed significant differences between the liquid 
transmission systems, natural gas transmission systems and natural gas 
distribution systems. Each industry faces different challenges, 
operating conditions and consequences of incidents.
    Interstate transmission systems are generally made up of long runs 
of generally straight pipelines, having large diameter, and operated at 
high volumes and high pressures. Distribution systems, in contrast, are 
constructed in configurations that look like a network or web, use 
smaller diameter pipe, and operate at much lower volumes and pressures. 
However, many distribution companies also own and operate transmission 
pipeline segments within their systems.
    Federal regulations recognize the differences between these three 
types of pipelines, and different sets of rules have been created for 
each. 49 CFR Part 192 sets out the regulations for natural gas 
transmission and distribution and the rules discriminate between the 
two, while 49 CFR Part 195 sets out the regulations for liquid 
transmission lines.
Status of Implementing the Pipeline Safety Improvement Act of 2002
    Since the Pipeline Safety Improvement Act of 2002 was signed into 
law on December 17, 2002, many programs are under way to specifically 
address implementation of the law's mandates and further safety 
enhancements of gas transmission and distribution systems. For gas 
transmission systems, most notable among many of the 2002 legislative 
mandates was integrity management for gas transmission pipelines. The 
law's provisions have also resulted in a substantial number of 
regulatory mandates, initiatives and voluntary programs for 
distribution systems.
Federal Regulatory Mandates
    The 2002 regulatory mandates affecting distribution systems 
include:

   Direct assessment standards development

   Environmental repair permit streamlining

   One-call 3-digit number rulemaking

   Right-of-way population encroachment study

   Operator qualification standard development

   Public awareness communication effectiveness rulemaking

   Infrastructure R&D grants program
Integrity Management Rule for Natural Gas Transmission
    OPS issued the integrity management rule for natural gas 
transmission lines on December 12, 2003. The rule requires natural gas 
transmission pipeline operators to conduct periodic inspections in 
``high consequence areas'', which for natural gas pipelines are 
generally high-density population areas.
    The nature of utility-owned transmission requires that over 50 
percent of the lines under the integrity management rule be inspected 
using direct assessment methods. Direct assessment is an alternative to 
internal inspection (smart pigging) or pressure testing. It comprises a 
variety of screening and examination techniques to locate and identify 
potential problems in the pipeline. The anomalies located by direct 
assessment usually involve corrosion of the pipeline. Corrosion is the 
second leading cause of gas pipeline failures.
    The direct assessment process entails performing two non-invasive 
complementary indirect exams of the section of the pipeline targeted by 
engineering analysis and predictions on that section. Typical indirect 
exams involve different approaches in measuring electrical values, so 
that any variations along the pipeline can give an indication of the 
locations where possible anomalies might be present. They may also 
involve checking for corrosion inside the pipe at preset sampling 
locations. The pipeline is then excavated at the previously identified 
locations, examined and repaired if necessary. The results are compared 
with predictions, becoming part of a learning curve about the condition 
of the pipeline and facilitating future direct assessments of similar 
sections of pipeline.
    Direct assessment is estimated to cost between $7,000 and $15,000 
per mile of pipeline examined, not including any necessary excavations. 
The latter can cost from $2,500 to $250,000 per excavation, depending 
on location.
    Many gas pipeline operators have already begun implementing the 
integrity rule and many more will be ready to begin assessments by the 
deadline on June 17, 2004. Approximately 30,000 miles of gas 
transmission operated by gas distribution utilities will have to be 
assessed under this rule. In the aggregate, for gas distribution 
utilities, estimated costs of compliance with this rule will exceed $3 
billion in 20 years, not including integrity management pass-through 
costs from their gas transmission suppliers upstream, repairs, 
modifications, and changes in operations that may be necessary to 
maintain the reliability of gas supply in the face of large scale 
pipeline inspections and testing.
Direct Assessment Standards Development
    The 2002 pipeline safety legislation also required that the DOT 
issue regulations prescribing standards for inspection of a pipeline 
facility by direct assessment. Such standards have been prescribed for 
external corrosion and are now being developed for internal corrosion 
and for stress corrosion cracking. The standards body leading this 
effort is the National Association of Corrosion Engineers (NACE). These 
standards will also be applicable to distribution pipelines.
Expedite Permit Streamlining: Timely Repairs vs. Permit Delays
    Integrity management applied to distribution utility transmission 
lines will result in at least 100,000 excavation locations and possibly 
many more over the next 7 years. The vast majority of them will not 
result in repairs or replacement of pipe but ALL will require permits.
    In the Pipeline Safety Improvement Act of 2002, Congress wisely 
recognized that it would be bad government and very inequitable to 
allow one agency to prohibit or prevent a citizen from taking an action 
required by another agency, and then penalize the citizen. This is what 
could happen if a Federal environmental agency fails to take timely 
action on a permit application for a pipeline safety repair, so that 
work cannot begin and end by the deadline set by the natural gas IMP 
rule. Under that rule, integrity repairs must be completed either (1) 
immediately, or (2) within one year after the discovery of an anomaly, 
depending on the type of defect involved. If a repair is not completed 
by the applicable deadline, the operator is required to reduce pressure 
and throughput on the affected pipeline by 20 percent until the repair 
can be completed. We are concerned that widespread, long-term pressure 
reductions would restrict supply and drive prices up.
    Our members estimate they must perform about 110,000 integrity 
inspections requiring excavation on intra-state pipelines (5 
inspections per mile on average) over the next 7 years. That means 
there will be about 15,000 inspections per year requiring a test hole. 
Although we have made our best estimates, we do not yet know what 
percentage of these will require further excavation to repair the line. 
The bottom line is that there are too many of these projects to use the 
traditional, time consuming process for obtaining individual permits 
for each and every site. Congress wisely recognized this should not be 
allowed to happen and therefore directed Federal agencies to develop a 
streamlined process to ensure that permits are given in time to allow 
timely repairs.
    We need a more efficient process. Please note that we do not 
advocate changing underlying environmental standards or requirements. 
Our concerns are purely with the process. We only ask that the agencies 
work together in a seamless, efficient and coordinated way so that this 
important public safety work can start and finish on time.
    Federal agencies have made some progress in streamlining their 
permit process. Interstate natural gas pipelines get their permits 
through an integrated FERC certification process and environmental 
review under the National Environmental Policy Act (NEPA). In December 
2002, FERC and other Federal agencies entered into a Memorandum of 
Understanding (MOU) to coordinate and accelerate the way in which they 
process permits for the construction of new interstate natural gas 
pipelines. The 2002 MOU also covers permits for maintenance and repairs 
of interstate pipelines, so it has been interpreted to help streamline 
permits for repairs under the IMP Rule. Although AGA is pleased because 
some AGA members operate interstate pipelines, the 2002 FERC MOU does 
not cover integrity repairs on intra-state pipelines because they are 
not certificated by FERC.
    The final Pipeline Repair Streamlining MOU specifically addresses 
the need to expedite integrity repairs that must be done 
``immediately'' under the IMP Rule. We are pleased that the MOU sets 
out the general framework for authorizing other repairs to proceed 
without site-specific permits, provided certain conditions are met.
    However, we are very concerned that there are no details in the MOU 
regarding how this will work. Instead, the MOU delegates this difficult 
and essential task to a new interagency working group. This group has 
little time remaining to develop a working process to streamline repair 
permits. Our members are on a tight schedule for beginning their 
integrity testing and first phase of repairs, and they will need timely 
authorization to begin this important public safety work.
    AGA has been urging the agencies to seek broad input from experts 
in the field and to solicit creative ``outside the box'' solutions. 
There are good options for ensuring environmental protection in a way 
that is less process-intense. This can be done within the authority 
agencies have under existing environmental laws.
3 Digit Number for One-Call Systems
    Congress has required the Federal Communications Commission to 
issue a rule that provides a toll-free 3-digit number that excavators 
and the public can use to easily connect to the appropriate one call 
center. One-call centers are designed to have personnel dispatched to 
the excavation site to have underground facilities--natural gas lines, 
petroleum and product lines, fiber optics, telephone, electricity, 
water and sewer lines--to avoid them being damaged. An easily 
remembered, easily advertised 3 digit number will increase the use of 
these vital services and therefore help avoid unnecessary accidents. 
The Federal Communications Commission just issued a proposed rule 
mandating the establishment of the 3-digit number.
    The leading cause of accidents on distribution pipelines comes from 
excavators unintentionally striking our lines. It is known as 
excavation damage, also commonly called third-party damage. Year after 
year, these strikes cause over 60 percent of the total ruptures on 
utilities and the vast majority of injuries and fatalities.
    We are continually urging states to require government agencies and 
their contractors to participate in One-Call programs. This would help 
eliminate some exemptions some state agencies currently have in several 
states from participation in One-Call. The Pipeline Safety Improvement 
Act of 2002 did help address this critical problem by clarifying that 
State departments of transportation should participate. However, there 
still is nothing to compel them to do so. Needless accidents continue 
to occur. Injuries, fatalities, property loss and disruption of 
services could be reduced with better use of One-Call centers and 
recommended practices for damage prevention.
Right-of-Way Encroachment Study
    The 2002 pipeline safety legislation directed DOT to work with the 
Federal Energy Regulatory Commission and other Federal and state 
agencies to study the difficult problem of encroachment on pipeline 
rights-of-way and to make recommendations for improvements. We 
understand that this study is under way under the direction of a 
steering group. Encroachment is where buildings and structures are 
placed on or very near the ``no build zones'' that a pipeline right-of-
way represents. This is especially a problem where cities and towns 
expand to ultimately push up to a pipeline location that was rural when 
built.
    We hope that the Committee will work with us to make progress on 
addressing this problem once the study's recommendations are made 
public.
Operator Qualification Standards
    In compliance with the 2002 legislative mandate, the OPS is leading 
development of a standard (ASME B31Q) for pipeline operations personnel 
qualification programs. This is another standard that has required 
significant member AGA and APGA member involvement in handling both 
training and operational aspects. The standard is still being developed 
and its completion is slated for the end of this year.
Public Awareness Communication Effectiveness
    OPS is working with stakeholders from the liquids and gas 
industries to define what would be required to evaluate effectiveness 
of operator communication programs. With input from industry, OPS is 
separately working with the states to define regulatory requirements 
that will cover gas utilities. AGA and APGA members have been involved 
via a task group to highlight the fact that flexibility is needed to 
avoid duplication of communication efforts already being carried out by 
gas utilities in their respective service territories at the local 
levels.
Infrastructure Research and Development Grants
    Congress significantly increased the authorization for OPS' 
pipeline safety research and development program to $10 million per 
year for four years. As OPS receives their funding primarily through 
user fees assessed on pipelines, these monies will likely be routinely 
provided. The pipeline safety act of 2002 also sought to coordinate the 
efforts of OPS with those of the Department of Energy. Generally OPS' 
focus on those technologies that represent near-term development for 
field applications and provides matching dollars to the recipients.
    With the increase in inspections and repairs and the expanding use 
of natural gas, better ways to do the job need to be found. Industry 
typically cannot provide directly all that is needed for R&D due to the 
nature of their rate framework. The natural gas surcharge that the 
Federal Energy Regulatory Commission (FERC) allowed for many years ends 
this year on August 1. FERC is considering an alternative proposal. AGA 
is also pursuing legislation that would establish a collaborative 
research program. AGA and APGA are hopeful that either the regulatory 
or legislative R&D funding proposal will become a reality. Either would 
solidify industry contributions to research. However, additional 
contributions for R&D are needed and AGA and APGA would welcome the 
opportunity to discuss with Committee members and staff the gas supply, 
transmission, distribution and utilization research that could be 
accomplished with increased public funding.
Additional Federal Regulatory Initiatives
    Current Federal regulatory initiatives for distribution systems 
include:

   Operator qualification rule revision

   Public communications standard development

   Better crisis communication

   Excess flow valve installation

   Operator safety performance metrics
Operator qualification rule revision
    To comply with NTSB recommendations, OPS expects to revise the 
operator qualification rule to include greater specificity. This has 
required significant AGA and APGA member involvement to ensure our 
members' concerns are taken into account. AGA and APGA believe 
reasonable additional requirements are being developed to adequately 
address the NTSB concerns and will soon become part of the revised 
rule.
Public Communications Standard Development
    A public communications standard (API Recommended Practice 1162) 
designed to address a variety of audiences has been completed under the 
American Petroleum Institute (API) banner, with input from industry and 
the regulatory community. It will be adopted by OPS via rulemaking on 
public education and communications.
Better Crisis Communication
    OPS is working with stakeholders to define guidelines for operators 
to follow in issuing communications in the event of involvement in an 
accident involving pipelines. The most recent one occurred on a 
gasoline pipeline in Tucson, AZ and sparked high-profile public 
hearings. Distribution utilities are engaged in deliberations with the 
other stakeholders to ensure concerns for gas utility communications 
are addressed.
Excess Flow Valve Installation
    In response to an NTSB recommendation and more recently, public 
testimony, OPS is reconsidering whether to mandate the installation of 
excess flow valves on service lines. Mandated installation would pose a 
potential major added burden on AGA and APGA members that elect not to 
install such devices, but instead notify customers and install such 
devices upon request from the customer. Cost-benefit studies performed 
to date by OPS do not adequately justify the nationwide installation of 
these devices on a mandatory basis unless some shaky, easily refutable 
assumptions are made.
Operator safety performance metrics
    OPS continues to look for ways to more clearly demonstrate the 
effectiveness of their safety programs. To this end, the agency is 
seeking to further improve and increase the gathering of safety 
performance data from operators. Federal regulators are contemplating 
further changes in operator reports to DOT that will also cover 
distribution systems. The distribution utilities remain committed to 
develop reasonable safety performance measurements with OPS and other 
stakeholders.
Voluntary Industry Programs
    Voluntary industry programs involving distribution utilities 
include:

   A government-industry group examining existing regulations 
        and practices addressing distribution system integrity in an 
        effort to identify needed enhancements. Along with APGA, many 
        AGA member companies are participating in this study, which is 
        supported by the American Gas Foundation.

   In response to an NTSB recommendation, numerous gas 
        distribution utilities have been collecting data on the 
        performance of plastic pipe since January 2001. Government and 
        industry stakeholders convene periodically to examine the data 
        for areas of concern.

   Continued participation in the Common Ground Alliance to 
        promote infrastructure damage prevention

    LDCs comply with a regulatory program that devotes stringent 
attention to design, construction, testing, maintenance, operation, 
replacement, inspection and monitoring practices. We continually refine 
our safety practices. Natural gas utilities spend an estimated $6.4 
billion each year in safety-related activities and this figure will 
significantly increase once the legislative mandates adopted to date 
are implemented fully. Historically, approximately half of the current 
$6.4 billion is spent in compliance with Federal and state regulations. 
The other half is spent, as part of our companies' voluntary commitment 
to ensure that our systems are safe and that the communities we serve 
are protected and products delivered.
Summary
    In summary, many programs are under way to address implementation 
of the legislative mandates of 2002. They must be given sufficient time 
to allow verification of their effectiveness. We believe it would be 
premature to currently draw conclusions on the results or consequences 
of any of these programs. Furthermore, in view of the growing need for 
energy to support continued economic growth, legislative decisions on 
pipeline safety should support or be consistent with the needed growth 
in the energy delivery infrastructure.
    The natural gas utility industry is proud of its safety record. 
Natural gas has become the recognized fuel of choice by citizens, 
businesses and the Federal Government.
    Public safety is the top priority of natural gas utilities. We 
invite you to visit our facilities and observe for yourselves our 
employees' dedication to safety. We are committed to continue our 
efforts to operate safe and reliable systems and to strengthen One-Call 
laws and systems in every state.
    Thank you for providing the opportunity to present our views on the 
important matter of pipeline safety. We look forward to working with 
federal, state and local authorities and representatives, as well as 
within our industry, to achieve the highest possible level of public 
and employee safety.

    The Chairman. Thank you very much.
    Mr. Howard?

         STATEMENT OF ROBERT T. HOWARD, VICE PRESIDENT

         AND GENERAL MANAGER, PIPELINE OPERATIONS, GAS

        TRANSMISSION NORTHWEST CORPORATION, ON BEHALF OF

       THE INTERSTATE NATURAL GAS ASSOCIATION OF AMERICA

    Mr. Howard. Thank you, Mr. McCain. It's a pleasure to be 
here.
    My name is Bob Howard, and I am testifying here on behalf 
of the Interstate Natural Gas Association of America. INGAA 
represents the interstate natural gas pipeline industry in 
North America--that's the U.S. and Canada--whose members 
transport over 90 percent of the natural gas consumed through 
180,000-mile pipeline network. GTN is headquartered in 
Portland, Oregon, and has 1,350 miles of interstate natural gas 
pipelines operating in five states, including Arizona, and 
delivers about three billion cubic feet of natural gas per day, 
supplying almost a third of the West Coast's natural gas 
everyday needs.
    As an aside, if I might, the proposed refinery would 
actually use natural gas off of a project that we're 
potentially developing that could be sourced from LNG 
development in Baja, Mexico.
    Natural gas represents 25 percent of the primary energy 
consumed annually in the United States, proving the natural gas 
pipeline delivery network to be a critical part of the Nation's 
infrastructure.
    Since this Committee debated the issue of pipeline safety, 
we're also saying that a great deal of progress has been made 
at the Office of Pipeline Safety. The backlog of unfinished 
Congressionally-mandated rulemakings are virtually gone, and 
certainly we've been involved in helping them clear those 
mandates and cooperate with them. And they've also made great 
strides in improving their public outreach.
    Perhaps the most important accomplishment since 2002 is the 
completion of the natural gas pipeline industry integrity 
management rule that was completed this year, and they've 
worked very hard with our industry and the public in developing 
a final rule that remains true to the mandate from Congress 
that is technically based, practical, and effective.
    I am personally involved, also, in their improved public 
education and communications effort, including work that I am 
associated with, the National Association of State Fire 
Marshals. Together, OPS and the National Association of State 
Fire Marshals are developing better training materials for our 
first-responders in strengthening the skills of first-
responders nationwide, not just the career officers in big 
cities, but the volunteer fire departments throughout the 
country are going to have access to excellent training 
materials.
    At GTN, communication with first-responders is a top 
priority, with over 300 face-to-face visits each year with the 
various first-responders and the agencies that support them. 
This should translate into increased faith in the safety and 
reliability of natural gas pipelines.
    The Pipeline Safety Improvement Act requires each natural 
gas pipeline operator to conduct a risk analysis and develop an 
integrity management plan by December 17 of this year. The law 
also requires operators to begin integrity assessments by June 
17, two days from now. You've heard it, and it's true in the 
natural gas pipeline industry, much of that work is well 
underway, and it began before the rule was finalized, in order 
to make the necessary capital improvements to accommodate 
internal inspection tools.
    At GTN, our total investment in integrity management will 
be between 40 million and 45 million, and we've spent already 
about 12 million of that.
    I want to say, as part of that, there are, in the natural 
gas pipeline transmission industry, about 5,000 miles of HCA. 
We know, from surveys of our own members, that almost half of 
that has already been surveyed prior to the implementation of 
the rule. Not that it will be counted in the baseline 
assessments, but it has already been done. And so as we begin 
our baseline assessments, we have that data to compare with, 
with new and better technologies that we'll be using.
    We've started our baseline programs at GTN through several 
sections of our system, and we have done most of our internal--
our HCAs prior to the integrity management rule, as well, so we 
have that data ourselves. In addition, this year's work at GTN 
employed more than a hundred people over our existing work 
force. I hope you see that our industry is committed to 
fulfilling and surpassing the rule's requirements in providing 
that data.
    The scope of the integrity assessment work to be done over 
the next 8 years, however, is enormous, and gives us some 
concern. Because all pipelines must comply simultaneously--
we're all in the same boat--it will, most certainly, affect 
natural gas deliverability and delivered natural gas commodity 
prices.
    In 2002, the INGAA foundation prepared an economic analysis 
of these pipeline capacity reductions and their effects on 
consumer prices. For a 10-year baseline period, the report 
estimated increased consumer natural gas prices of about one 
billion per year for the first 10 years.
    One way to mitigate these unintentional price spikes can be 
by allowing for the coordination of inspection and repair 
activities among various competing pipelines which antitrust 
law currently restricts. We would urge Congress to consider an 
antitrust waiver for the coordination of those integrity 
assessments and repair activities.
    Before concluding, we would also like to comment on the 
proposed merger of OPS and the Federal Railroad Administration. 
Our concern is that OPS would lose its focus and regulatory 
effectiveness--I heard them talk about it being a research 
agency, but it is also a regulatory agency--if it were to be 
subsumed into the much larger FRA. Much of OPS's recent success 
is due to the fact that it has actively improved public access 
to its agency and been able to act quickly and decisively in 
improving its programs and enforcement activities. We believe 
these activities could be diluted.
    House Transportation and Infrastructure Chairman Don Young 
introduced legislation, H.R. 4277, last month to create a 
separate pipeline safety entity at DOT, and, given the concern 
of this country about pipeline safety, we strongly support his 
efforts.
    Let me thank you, again, Mr. Chairman, for allowing me to 
testify today. Safety is of paramount importance to our 
industry, and we believe it is our obligation to work with 
Congress and the OPS to maintain and improve the safe, reliable 
operation of our pipelines in the years ahead. And I'd be happy 
to answer any questions.
    [The prepared statement of Mr. Howard follows:]

  Prepared Statement of Robert T. Howard, Vice President and General 
Manager, Pipeline Operations Gas Transmission Northwest Corporation, On 
      Behalf of the Interstate Natural Gas Association of America
    Mr. Chairman and Members of the Committee:

    Good morning. My name is Bob Howard and I am Vice President and 
General Manager of Pipeline Operations for Gas Transmission Northwest 
Corporation (GTN). I am testifying today on behalf of the Interstate 
Natural Gas Association of America (INGAA). INGAA represents the 
interstate and interprovencial natural gas pipeline industry in North 
America. INGAA's members transport over 90 percent of the natural gas 
consumed in the U.S., through an 180,000-mile pipeline network.
    Gas Transmission Northwest is an interstate natural gas pipeline 
headquartered in Portland, Oregon. With 1,350 miles of transmission 
pipeline in three states, GTN delivers about 2.9 billion cubic feet of 
natural gas per day, supplying almost a third of the West Coast's total 
natural gas needs every day.
    The North American pipeline network provides the indispensable link 
between natural gas supply and the local distribution companies that 
serve retail customers. Natural gas represents 25 percent of the 
primary energy consumed annually in the United States, a contribution 
second only to petroleum and exceeding that of coal. Consequently, the 
natural gas pipeline delivery network is a critical part of the 
Nation's infrastructure.
    This is why the safe and reliable operation of these pipeline 
systems is so important. Because the natural gas pipeline network is 
essentially a ``just-in-time'' delivery system, with limited storage 
capability, customers large and small depend on reliable around-the 
clock service. And of course, the public wants to know that these 
pipeline systems crisscrossing the Nation and serving their communities 
are safe. Mr. Chairman, these pipeline systems are safe--the safest 
mode of transportation in the country--and working together the 
pipeline industry and the Office of Pipeline Safety are making this 
valuable network even more safe and secure.
Progress at the Office of Pipeline Safety
    Since this Committee last debated the issue of pipeline safety, 
several years ago, a great deal of progress has been made at the 
Department of Transportation's Office of Pipeline Safety (OPS). As 
recently as five years ago, many in Congress and in the public at large 
were saying that the OPS was an agency of sub-standard performance. The 
General Accounting Office cited the backlog of unfinished, 
congressionally mandated rulemakings, the numerous DOT Inspector 
General recommendations that had not been implemented, and the poor 
acceptance rate for National Transportation Safety Board (NTSB) 
recommendations. For years, the OPS had the lowest acceptance rate of 
any modal office at DOT for NTSB safety recommendations, at about 69 
percent. Take a look at what has happened since that time. The OPS now 
has the second-highest acceptance rate for NTSB safety recommendations, 
right behind the Highway Safety Administration, at 86 percent. The 
backlog of unfinished, congressionally mandated rulemakings is 
virtually gone, and by any measure, OPS has made great strides in 
improving its effectiveness.
    Perhaps the most important accomplishment by the OPS since the 
passage of the Pipeline Safety Improvement Act of 2002 is the 
completion of the natural gas pipeline integrity management rule. This 
rule, required by the 2002 Act, took the better part of 2003 to develop 
before its final issuance in December. When the Notice of Proposed 
Rulemaking was released to the public in early 2003, the INGAA 
membership had a great deal of concern about its focus, its 
effectiveness, and workability. However, the OPS took our concerns 
about the proposed rule seriously, and worked with our industry in 
developing a final rule that remains true to the mandate from Congress, 
and does so in a way that is technically-based, practical and 
effective.
    INGAA believes that all of this work on the part of OPS has made 
the agency a more effective safety regulator. Enforcement has improved. 
Public education and communications efforts have improved. Audit and 
inspection activity is more focused and effective. All this should 
translate into Congress and the public having more faith in the safety 
and reliability of the natural gas pipeline infrastructure.
What the Pipeline Industry is Doing to Implement the New Integrity Rule
    The pipeline industry has been working hard too. As the Nation 
increases its demand for natural gas, more pipeline capacity is needed 
to deliver additional supplies to growing markets. Whenever a new 
pipeline is proposed, or an existing pipeline proposes an expansion, 
communities and citizen groups raise the issue of safety. These 
communities and groups often have significant influence in the approval 
process, and therefore their concerns need to be taken seriously. In 
order for our industry to meet its objectives for serving a growing 
natural gas market, we also need to reassure the public that pipelines 
are a safe mode for energy transportation.
    Recent accident statistics are worth examination. For the years 
2002 and 2003, there were no fatalities or injuries associated with 
accidents on interstate natural gas pipelines located in ``high 
consequence areas,'' or the areas with higher population near a 
pipeline. There were four accidents during this period that resulted in 
injuries to one pipeline employee and three pipeline contractors, but 
these occurred on natural gas pipeline segments located in rural areas; 
i.e., not high consequence areas. Three accidents did occur on 
interstate natural gas pipelines in high consequence areas during 2002 
and 2003, but these did not result in either a fatality or an injury, 
and were therefore only reported to OPS because the damage costs 
(including the cost of natural gas lost) exceeded $50,000.
    The new natural gas pipeline integrity rule has been a significant 
area of focus for the industry. Let me assure the Committee that we are 
not resting on our existing safety record. Over a dozen consensus 
standards have been completed, or are near completion, to support this 
rule, and have been supported by multimillion dollar collaborative 
research programs.
    The Pipeline Safety Improvement Act requires each natural gas 
pipeline operator to conduct a risk analysis and develop an integrity 
management plan for pipeline in high consequence areas by December 17 
of this year. However, the law also required operators to begin 
integrity assessments on their pipelines by June 17, two days from now. 
The ``highest priority'' fifty percent of an operator's high 
consequence areas (based on the risk analysis) must complete a baseline 
integrity assessment within five years of enactment (December 17, 
2007), with the remaining fifty percent to be completed within ten 
years of enactment (December 17, 2012).
    This integrity assessment work is already well underway. INGAA has 
surveyed its membership to measure the amount of inspection activity 
taking place. One respondent's answers are illustrative of the larger 
group. This pipeline has about 5900 miles of transmission pipelineof 
which about 200 miles is located in high consequence areas (HCAs). To 
date, about ten miles of these HCAs have completed a baseline 
assessment, but as a function of inspecting these ten miles of HCAs, 
the operator has had to also inspect 250 miles of non-HCA pipe.
    The reason for these assessments going beyond the HCA requirement 
is simple. The vast majority of our pipelines are going to be inspected 
with internal inspection devices, commonly referred to as ``smart 
pigs.'' Special launcher and receiver facilities have to be constructed 
to both introduce a smart pig into a pipeline, and remove it at some 
point downstream. The most practical place (and often, the only place) 
to construct these launcher/receiver facilities are at compressor 
stations, which are typically located about 75 to 100 miles apart along 
a pipeline. The pipeline segment between compressor stations may have a 
few, discrete miles of HCAs, but in order to inspect the five or six 
miles of HCA pipe, the entire 75 to 100 mile segment between the 
stations will be inspected by the smart pig. INGAA estimates that about 
6 percent of total natural gas transmission pipeline mileage is 
actually located in HCAs, but in order to assess the integrity of this 
6 percent of pipeline mileage, about 60 to 70 percent of total 
interstate pipeline mileage will have to be inspected.
    Mr. Chairman, I would like to provide the Committee with another 
example to illustrate my point. One INGAA member company is in the 
process of modifying a 58-mile section of pipeline so that internal 
inspection devices can be employed for integrity assessments. Since 
this pipeline was originally constructed in the mid-1950s, before the 
advent of smart pigs, it was not engineered to accommodate these 
devices. The pipeline operator has already identified 14 HCAs along 
this 58-mile segment, for a total HCA length of 8.74 miles. In order to 
assess the HCA portions of the pipe, pig launchers and receivers must 
be installed, and several valves will need to be replaced. The 
estimated modification costs for this one segment are $5.1 million, and 
the estimated integrity assessment and repair costs are $640,000. The 
work on this pipeline segment started last month, and is expected to 
last five months. During this five-month period, some part of the 
pipeline segment will either be completely shut down, or operating at 
reduced pressure.
    At Gas Transmission Northwest, we are well underway with the 
installation of internal inspection infrastructure and our baseline 
assessments. We recently ran a ``smart pig'' through a section of our 
system and are in the process of examining the results. I am proud of 
the work we have done so far and we are committed to fulfilling and 
surpassing the rule requirements.
One Important Concern
    The scope of the integrity assessment work to be done over the next 
eight years gives the INGAA membership some pause for concern. This is 
due to the fact that a significant number of pipeline segments will 
have to be removed from service in order to prepare for and perform 
assessments and any resulting repairs. This unprecedented integrity 
program will almost certainly affect natural gas deliverability and 
delivered natural gas commodity prices. The effect could be compounded 
because, coincidentally, the integrity assessments are happening during 
what will likely be a protracted period of tight natural gas supplies.
    In past years, pipelines were able to perform most maintenance and 
repair activities during the warm months of the year, when natural gas 
demand was relatively low. During these periods of ]ow seasonal demand, 
the natural gas pipeline network could more readily handle system 
downtime. Few, if any, customers were impacted in terms of service 
disruptions or higher natural gas commodity prices.
    In today's natural gas market, however, demand not only peaks 
during the cold winter months, but also during hot summer months, due 
to the increased use of natural gas to generate electricity. This means 
that there are fewer weeks of the year when maintenance and repair can 
take place without impacting customers in some manner.
    In 2002, the INGAA Foundation prepared an economic analysis of 
these pipeline capacity reductions, and their effects on consumer 
prices. The report \1\ looked at anticipated pipeline inspection 
scenarios under an integrity management program, based in large part on 
how long the industry would be given to perform a baseline assessment. 
For a ten-year baseline period (i.e., the one ultimately adopted by 
Congress), the report estimated increased consumer natural gas prices 
of about $1 billion per year for the first ten years. Please note that 
these costs are not associated with the actual cost of inspections and 
repair activities, even though these costs will also be significant. 
Rather, the study looked only at the ``costs to consumers due to 
deliverability constraints'' and their effect on the natural gas 
commodity markets downstream.
---------------------------------------------------------------------------
    \1\ ``Consumer Effects of the Anticipated Integrity Rule for High 
Consequence Areas,'' prepared for the INGAA Foundation by Energy and 
Environmental Analysis, Inc., February, 2002.
---------------------------------------------------------------------------
    One way these unintentional price spikes can be minimized is by 
allowing for the coordination of inspection and repair activities among 
various competing pipeline operators. Anti-trust law currently 
restricts such coordination. In the absence of such coordination, 
however, it is possible and even likely that multiple pipelines serving 
a given market could be down for inspection/repair at the same time, 
causing significant price increases and even service disruptions for 
that market. INGAA urges Congress to consider an anti-trust waiver for 
coordination of pipeline integrity assessment and repair activities.
    We also want to join with others in urging the various Federal and 
state agencies involved in permitting pipeline inspection and repair 
activities to do so on a coordinated and expedited basis. We anticipate 
that our industry will be required to make significant modifications to 
our pipeline facilities over the next eight years, in order to 
accommodate internal inspection devices. The construction of smart pig 
launchers and receivers, for example, as well as replacing pipeline 
bends, segments and valves that cannot accept internal inspection 
devices may require permits from Federal and state authorities. The 
interstate natural gas pipeline members of INGAA are regulated 
economically by the Federal Energy Regulatory Commission (FERC). The 
FERC must approve the construction of any new interstate natural gas 
pipeline, or any major expansion or modification (in excess of a 
certain dollar amount) of an existing interstate natural gas pipeline. 
The FERC has also accepted the primary role for the enforcement of the 
National Environmental Policy Act (NEPA) as it relates to pipeline 
construction and the resulting effects on the environment. In 2002, the 
FERC lead an effort to create and sign a Memorandum of Understanding 
(MOU) between all of the federal agencies associated with any 
permitting activities for pipelines, such as the Corps of Engineers, 
the Environmental Protection Agency, and the U.S. Fish and Wildlife 
Service. This MOU commits the signatory agencies to concurrent review 
of a pipeline construction application, such that agencies can work 
together rather than at cross-purposes, thus saving time and effort. We 
are hopeful that this MOU can also be applied to integrity management-
related activities. It should be noted, however, that this MOU does not 
include participation by state agencies. These state agencies are often 
the most intransigent in terms of approving permits on a timely basis. 
Once again, a signal from Congress as to the importance of approving 
these permits in a timely manner will be critical to the success of the 
Pipeline Safety Improvement Act of 2002.
The Proposed Merger of the OPS and the Federal Railroad Administration
    Before concluding, INGAA would like to provide some comments to the 
Committee on the proposed merger of the Office of Pipeline Safety and 
the Federal Railroad Administration (FRA). The Secretary of 
Transportation announced his intent to move forward with this idea as 
part of an overall vision to gather the various research functions at 
DOT and place them under one authority. OPS is currently a part of the 
Research and Special Programs Administration (RSPA), which the 
Secretary envisions would be restructured in order to accept all 
transportation research-related activities from the various modal 
administrations. Since the OPS is a regulatory body, it would not fit 
within the new RSPA, and thus the proposal to move it to FRA.
    INGAA does not have a quarrel with the Secretary regarding his 
vision for transportation research. Our concern is that the OPS would 
lose its focus and effectiveness if it were to be subsumed into the 
much larger FRA. As you have already heard, OPS has made great strides 
in improving its performance over the last five years. Much of that 
success is related to the fact that it has been able to act quickly and 
decisively in improving its programs and enforcement activities. It 
would indeed be a shame if, after having worked so hard to gain back 
its credibility, OPS were to lose it once again by getting lost in a 
large and unfamiliar bureaucracy.
    Rather than merging with the FRA, INGAA supports the creation of a 
new Pipeline Safety Administration at DOT. House Transportation and 
Infrastructure Chairman Don Young introduced legislation (H.R. 4277) 
last month to create a separate pipeline safety entity at DOT, and we 
strongly support his efforts. We hope that a Senate companion bill will 
be introduced soon, and that it will have this Committee's support.
Conclusion
    Let me thank you once again, Mr. Chairman, for allowing me to 
testify today. Safety is of paramount importance to our industry, and 
we believe that it is our obligation to work with Congress and the OPS 
to maintain and improve the safe, reliable operation of our pipelines 
in the years ahead. I would be happy to answer any questions you or the 
Committee members might have.

    The Chairman. Thank you very much.
    Ms. Epstein, do you share the other witnesses' opposition 
to shifting the RSPA over to the Office of--the Office of 
Pipeline Safety over to the Federal Railroad Administration?
    Ms. Epstein. Yes, I do.
    The Chairman. I wonder who came up with that idea.
    [Laughter.]
    The Chairman. Ms. Epstein, what grade would you give the 
Office of Pipeline Safety today? And what grade would you have 
given it 5 years ago?
    Ms. Epstein. Five years ago, I would have given the Office 
of Pipeline Safety a very poor grade, probably a C-minus or a 
D. And today, I would give them an excellent grade on progress, 
but, in terms of where we want them to be, I would only give 
them about a B.
    The Chairman. Everybody knows that there's going to be an 
increased demand for natural gas, as well as oil. Most 
witnesses agree we don't have the refining capacity or the 
pipeline capacity to meet these increased demands. What's your 
solution?
    Ms. Epstein. Well, as you know, Senator, it's a very 
complicated problem, and there are nuances, such as existing 
refineries have expanded at the same time that new refineries 
haven't been built. Certainly, I would hope we'd be moving more 
toward a decentralized renewable energy infrastructure, and I 
think there are ways that we can move faster than we have to 
date.
    In terms of expanding pipelines, I agree with my fellow 
witnesses that we need to make the public more confident about 
pipeline safety, and that is going to help siting of new 
pipelines. I think we are moving in that direction. But, in 
terms of what I said today, I know I've been somewhat more 
negative than others, but I feel that my role is to point out 
the deficiencies, and I knew others would point out the good 
things that have been done.
    I think it's critical that we recognize that there have 
been some enforcement issues, and they're ongoing. And the 
public takes those very seriously. When you don't--when you 
issue high penalties and don't collect those, that is going to 
have an impact on whether people think you are doing all you 
can to ensure that those who aren't performing properly are 
going to improve.
    And, at the same time, I would hope those in industry who 
have an excellent record and perform well and are investing to 
prevent problems recognize that a strong enforcement program 
will level the playing field, and those who are not doing as 
much as they are will be penalized for that.
    The Chairman. Thank you. You strayed from my question, but 
it's very informative. Thank you.
    [Laughter.]
    The Chairman. Mr. Pearl and Mr. Fischer and Mr. Howard, 
were you surprised at the number of problems that have been--in 
the pipelines--that have been discovered under this new 
inspection regime? According to Mr. Mead, approximately 15 
percent of the pipelines have been inspected, and the problem 
rate has been much higher than expected. And if you are 
surprised, what do you think needs to be done?
    We'll be begin with you, Mr. Pearl.
    Mr. Pearl. Yes, I think, certainly from our company's 
vantage point, and most of my colleagues in the liquids 
pipeline industry, the current run of ``smart pigs,'' inline 
inspection devices, has detected more anomalies than we 
certainly anticipated. Over the mid- to long-term, that's a 
good thing, because, as I mentioned in my testimony, we're not 
just looking in repairing those that are required by law. You 
know, most operators are taking a prudent view and 
anticipating. And if you see an anomaly now that perhaps 
doesn't meet the regulatory criteria, you'd still go ahead and 
repair it so you'd prevent a leak down the road.
    I think, all in all, the experience, you know, has been 
good. I believe--there's a little difference in numbers here. 
From our numbers, 43 percent of the infrastructure will have 
been tested by the September 30 deadline. And, as I mentioned 
in my testimony, we've gone well beyond the mileage required 
under the Act. It's turned out that, because of the way you 
inspect pipelines, by large segments, we cover far more than 
the mileage required under the HCA regulations. I believe we're 
going to be around 85 percent.
    So the bad news, I guess, from a cost standpoint is, we're 
seeing more. That's due to much better technology. These 
``smart pigs'' are seeing a lot--things that we couldn't see 
just 2 or 3 or 4 years ago. And I think when we get through 
this first wave, we're hopeful, as an industry, that we'll have 
far fewer anomalies second time around.
    The Chairman. Mr. Fischer?
    Mr. Fischer. I would certainly agree with Mr. Pearl. Yes, I 
do get surprised when I see statistics like that appear, but 
not surprised from the standpoint that we don't fully expect 
that to happen with today's technology. The technology out 
there today is tremendous, and 5 years from now will be even 
more so. So, yes, today's technology is uncovering a lot of 
things.
    However, what should we do about it as we move forward? I 
really think there are a lot of things in this new Pipeline 
Safety Act that will keep us very much on track. We look at 
these pipelines over a period of 10 years, and 50 percent of 
them are to have been inspected and fully documented and 
repaired in 5 years. We begin the process every 7 years from 
the date of the first year that we completed that segment. So 
there's a constant revolving inspection process now put in 
place that we didn't have before you sponsored this 
legislation. So I do think things are--we must judge it as we 
go along. Is that enough? Is that--you know, what are we doing? 
However, there is a lot in place that is just really starting 
to read out right now, Senator.
    The Chairman. Mr. Howard?
    Mr. Howard. I'm, frankly, surprised. I just don't have 
enough information to know why--I mean, and what those results 
might be. It does raise in me a natural curiosity to try and 
dig into the numbers and understand them better so that we've 
got the benefit of having the information.
    The Chairman. Well, I intend to write a letter today in 
opposition of this movement of the Office of Pipeline Safety, 
and we'll see if that works. If not, maybe we'll have to act 
legislatively. I'm not sure that when a system is working, with 
all the caveats that have been presented by the witnesses, 
including your important testimony, Ms. Epstein, why we would 
want to shift. And if there is a problem in America, it 
certainly is with our railroads. So maybe misery loves company. 
I'm not sure----
    [Laughter.]
    The Chairman.--if that's the rationale behind it, but that 
can be the only rationale that I can see.
    I don't mean to branch out into other areas, because this 
issue is to--this hearing is to review the Act and see what 
needs to be done and how they're doing, and recognizing that we 
have to continue the vigorous oversight and vigorous pursuit of 
pipeline safety so we never have to have a series of hearings 
again that I know were as uncomfortable for you as were for me 
when we had the tragic loss of life. And despite the fact that 
one of the other witnesses mentioned that it's--they have less 
accidents and less fatalities when something happens like 
happened in Bellingham, Washington, it gets--it grips all of 
us.
    But I would argue, particularly, these four witnesses, 
everyone agrees that we're going to have an energy crisis in 
this country, if we're not in one now. There's a huge backlash 
about the role of some companies. These recent tapes of Enron 
have disgusted and angered all of us. And then motivates many 
Americans to say, ``These people need to be re-regulated.'' 
I'm, by nature, a deregulator.
    So my request from you is, you start--your various 
organizations start looking at the challenges that we face 
ahead, as far as an adequate energy supply for the American 
people is concerned. I agree with you, Ms. Epstein, that 
alternate energy is a great--renewable energy sources are a 
great way to begin. I'm not sure that that solves the whole 
problem in the short term.
    So I don't know if that crisis comes next year or 10 years 
from now. It's not a matter of--it's a matter of when, not 
whether. And so I hope you'll start focusing your attention, 
because these issues involve things such as a 3-year delay in 
moving a pipeline from one place to another. I'm particularly 
interested in that when--I'm in a high-growth state, and we 
have pipelines out in the desert now that are turning into 
communities, and it's a little disturbing to me that many of 
the local authorities who do the zoning don't know that these 
rules exist. Ranging from that to what's going to happen in the 
Middle East as we see continued unrest and disturbances in 
Saudi Arabia, a major source of oil. So we'd better start 
thinking about this from a global standpoint. Otherwise, we 
will be blamed for not being prepared for something that 
clearly lies ahead of us.
    And that's the end of my sermon and tirade for today.
    [Laughter.]
    The Chairman. And I thank you all for being here, and I 
appreciate you participating in this hearing.
    This hearing is adjourned.
    [Whereupon, at 11:29 a.m., the hearing was adjourned.]

                            A P P E N D I X

                             Arizona Corporation Commission
                                                     August 2, 2004
Hon. John Breaux,
Senate Committee on Commerce, Science, and Transportation,
Washington, DC.

RE: Post Hearing Questions for the Pipeline Safety Oversight Hearing on 
            6/15/04

Dear Senator Breaux:

    This is in response to your questions posted.
I Independent Exams
    We believe that where a major incident occurs, there should be an 
independent exam to ensure (1) Proper analysis of the cause of the 
rupture and (2) That appropriate remediation is undertaken for the 
integrity of the line. In 2003 Arizona broke new ground in that U.S. 
DOT/OPS agreed to a second independent test. OPS has authority to 
conduct the independent test, and OPS paid for the test. However, there 
is no statute or regulation compelling the operator to reimburse this 
taxpayer expense. Again, in compelling cases, such reimbursement by the 
operator for independent testing should be mandatory.
II Adequacy of Funding
    The Arizona workplans for inspection of interstate pipelines in 
Arizona have been aggressive, but we believe appropriate, consistent 
with public safety and reasonable given the potential economic and 
human costs of inadequate inspection schedules. OPS responds to our 
workplans that funds are limited and that one state should not absorb 
disproportionate funding. This has the quixotic result of discouraging 
necessary inspections and ``penalizing'' states that zealously guard 
public safety, in Arizona pursuant to statutory mandate. If Arizona 
believes an inspection is necessary for a certain segment of pipeline, 
the adequacy of funding should not cause OPS to deny the request.
    Please contact me if you have further questions.
            Very truly yours,
                                              Marc Spitzer,
                                                          Chairman.
                                 ______
                                 
    Response to Written Questions Submitted by Hon. John Breaux to 
                           Samuel G. Bonasso
    Question 1. Your testimony states that OPS has completed 
assessments of the integrity management plans of the 63 largest 
operators of hazardous liquid pipelines, with each assessment taking 
about 2 weeks to complete. Is OPS on track to complete the remaining 
157 assessments for hazardous liquid pipelines and the 884 assessments 
of natural gas transmission pipelines in compliance with current 
deadlines?
    Answer. OPS set a very aggressive 2-year schedule for completing 
its IMP assessments of the 63 largest operators of hazardous liquid 
pipelines. According to OPS, IMP assessments are on track for the 
remaining 157 hazardous liquid pipeline operators, who are mostly small 
operators. OPS anticipates completing its initial IMP assessments of 
the remaining hazardous liquid pipeline operators by the end of Fiscal 
Year 2005.
    According to OPS, it needs to hire additional inspectors before it 
can begin its IMP assessments of operators of natural gas transmission 
pipelines. For Fiscal Year 2005, OPS has requested an additional 12 
inspector positions. OPS also needs to provide the necessary IMP 
training to both Federal and state inspectors. According to OPS, there 
are many more inspectors at the state level to train for IMP 
assessments of operators of natural gas transmission pipelines than 
were trained for IMP assessments of operators of hazardous liquid 
pipelines. Training will have to be completed before the assessments 
can begin.
    OPS estimates beginning its initial IMP assessments of operators of 
natural gas transmission pipelines in the fall of 2005, with an 
estimated completion date in the spring of 2007. However, OPS will be 
in a better position to finalize its plans for completing IMP 
assessments of operators of natural gas transmission pipelines once the 
FY 2005 budget is passed.

    Question 2. Do you believe OPS has sufficient resources to meet the 
mandates of the 2002 Pipeline Safety Improvement Act on schedule?
    Answer. OIG has not assessed OPS's resource strengths to determine 
whether they are sufficient to meet the mandates and deadlines of the 
Pipeline Safety Improvement Act of 2002 (2002 Act).

    Question 3. Your testimony notes that gas distribution lines are 
responsible for 4 times the number of fatalities and more than 3.5 
times the number of injuries than hazardous liquid and gas transmission 
pipelines combined. Yet gas distribution pipelines are not included in 
the current integrity management initiatives. What specifically should 
Congress do to address this gap in the safety program?
    Answer. In our final report,\1\ we recommended that OPS require 
operators of natural gas distribution pipelines to either implement 
some form of pipeline integrity management or enhance safety programs 
with the same or similar integrity management elements as the hazardous 
liquid and natural gas transmission pipelines.
---------------------------------------------------------------------------
    \1\ OIG Report Number SC-2004-064, ``Actions Taken and Needed for 
Improving Pipeline Safety,'' June 14, 2004.
---------------------------------------------------------------------------
    In its response to our recommendation, OPS stated that industry, 
state, and Federal regulators are now working to develop natural gas 
distribution IMPs and that a public workshop to discuss IMP concepts is 
planned for December 2004. However, other than stating that it is 
working with states and industry to develop an IMP for operators of 
natural gas distribution pipelines, OPS did not indicate when they 
expect to require an IMP for natural gas distribution pipelines. In our 
opinion, OPS should issue a rule no later than March 31, 2005, 
requiring operators of natural gas distribution pipelines to implement 
IMPs.
    We would suggest that Congress get a commitment from OPS as to when 
it expects to require an IMP for operators of natural gas distribution 
pipelines, including realistic milestones and performance measures on 
the actions necessary to carry out its IMP initiative. OPS should also 
report to the committee on its progress periodically. If OPS and 
industry do not meet the milestones, Congress should proceed to close 
this safety gap by enacting legislation requiring an IMP for operators 
of natural gas distribution pipelines.

    Question 4. What mandates from the 1992 and 1996 Acts has OPS still 
not implemented?
    Answer. OPS has completed its action on all mandates from the 1996 
Act. However, five mandates from legislation enacted in 1992 remain 
outstanding. All are over 10 years past due. The table below identifies 
those mandates OPS has yet to implement since our March 2000 report.

          Status of Outstanding Mandates from 1992 Legislation
------------------------------------------------------------------------
  Pipeline Act &
      Section                Mandate                     Status
------------------------------------------------------------------------
1992                Require periodic           NPRM published and
Sec. 108             inspection of all          awaiting public comment,
                     offshore and navigable     final rule expected
                     waterway natural gas       August 2004
                     pipeline facilities
------------------------------------------------------------------------
1992                Require periodic           NPRM published and
Sec. 207             inspection of all          awaiting public comment,
                     offshore and navigable     final rule expected
                     waterway hazardous         August 2004
                     liquid pipeline
                     facilities
------------------------------------------------------------------------
1992                Prepare a report to        Report is in the
Sec. 307(b)          Congress on a study        clearance process,
                     concerning how to          report expected July
                     abandon underwater         2004
                     pipelines
------------------------------------------------------------------------
1992                Define and regulate        NPRM comments under
Sec. 109(b)          natural gas gathering      discussion, supplemental
                     lines                      notice expected December
                                                2004
------------------------------------------------------------------------
1992                Define and regulate        OPS is coordinating with
Sec. 208(b)          hazardous liquid           the states and industry
                     gathering lines            to develop a definition,
                                                NPRM expected December
                                                2004
------------------------------------------------------------------------
NPRM: Notice of Proposed Rule Makmg

    Question 5. You note in your testimony that ``Much of the Nation's 
existing pipeline infrastructure is over 50 years old.'' How much a 
correlation is there between the age of a pipeline and the likelihood 
of a leak or rupture?
    Answer. The age of a pipeline can certainly be a contributing 
factor in pipeline failures, as was demonstrated in the pipelines that 
ruptured or leaked in Bellingham, Washington; Carlsbad, New Mexico; 
Tucson, Arizona; and · the Suisun Marsh in northern California. 
In each incident, the pipelines where the rupture or leak occurred were 
more than 35 years old. According to OPS, in the Bellingham and 
Carlsbad accidents, the ineffectiveness of the operators' maintenance 
programs, compounded by the age of the pipeline, resulted in the 
pipeline failures.
    OPS, through its research and development efforts, is looking into 
integrity threats (i.e., external corrosion, internal corrosion, stress 
corrosion cracking, manufacturing defects, fabrication and construction 
defects, and third-party or mechanical damage) associated with aged 
pipelines. One current project underway will (1) evaluate the extent to 
which aging leads to loss of the pipelines capabilities, (2) identify 
material and construction anomalies common to vintage pipeline, and (3) 
develop a process to evaluate potential threats posed by such 
anomalies.

    Question 6. In your opmwn, should age be a factor in where 
pipelines are inspected, in addition to whether the pipeline is located 
in a ``high-consequence area''?
    Answer. Yes, as does OPS. In its guidance for implementation of an 
IMP, OPS lists 18 risk factors, including age of pipe, that pipeline 
operators should consider when establishing the frequency of IMP 
assessments in high-consequence areas. Generally, older pipe shows more 
corrosion and may be uncoated or have an ineffective coating for 
preventing corrosion. OPS rates pipe 25 or more years old as high risk 
and pipe less than 25 years old to be low risk, but factors such as the 
pipeline's coating and corrosion conditions can affect the true risk 
level. Other risk factors that operators should consider when 
establishing an integrity assessment schedule include, among others, 
results from previous inspections, leak history, known corrosion or 
condition of the pipeline, type and quality of the protective coating, 
and operating stress levels in the pipeline.
                                 ______
                                 
    Response to Written Questions Submitted by Hon. John Breaux to 
                          Hon. Kenneth M. Mead
    Question 1. You point out that permitting for time sensitive 
pipeline repairs is a significant issue and mention the recent 
California accident. Do you know how many time-sensitive pipeline 
repairs have been delayed, past their required completion date, due to 
permitting problems?
    Answer. According to OPS, information is not available on the 
actual number of time-sensitive pipeline repairs that have been 
delayed, past their required completion date, due to permitting 
problems. However, information obtained from OPS, California's Office 
of the State Fire Marshal and pipeline operators, disclosed that not 
only have there been several time-sensitive pipeline repairs that were 
delayed due to permitting problems, pipeline relocations were also 
delayed due to the permitting process.
    For example, in early 2002, a pipeline operator in Michigan 
discovered an integrity threat in pipe that was located within a large 
wetland complex managed by the Michigan Department of Natural 
Resources. Federal, state and local permits were required before the 
operator could take action to repair the pipe. The repairs were finally 
completed more than 6 months after permitting efforts were initiated.
    According to officials in California's Office of the State Fire 
Marshal, a 1,400-foot pipeline relocation in the San Francisco Bay area 
took 29 months to obtain permits and a 3-mile pipeline relocation in 
rural Contra Costa County, California took 3 years to obtain permits.

    Question 2. In the California accident, I understand that the 
pipeline operator was trying to relocate the pipeline out of the marsh 
area. Does this require more permitting and a longer process than just 
a simple repair to an existing pipeline?
    Answer. Yes, in this case, a significantly longer and larger 
environmental review and permitting process was required in order to 
relocate the pipeline away from the Suisun Marsh area. The pipeline 
operator was replacing approximately 70 miles of existing pipe with new 
pipe that would be re-routed away from the Suisun Marsh. Re-routing 70 
miles of new pipe effected many more state and local environmental 
review and permitting jurisdictions that otherwise would not have been 
involved in the environmental review and permitting processes for a 
one-time repair to an existing pipeline. For example, only one city and 
county would have been involved in the permitting process had the 
operator chosen to repair the existing pipeline. By choosing to 
relocate the new pipe, the operator had to obtain environmental reviews 
and permits from an additional six cities and two counties, not 
including local water, irrigation and sewage districts. As we 
testified, thirty-one separate Federal, state, and local agencies and 
railroads were involved in the environmental review and permitting 
processes for relocating the hazardous liquid pipeline away from the 
marsh area (see attachment).

    Question 3. According to your testimony, there is still some 
clarification needed between DHS and DOT regarding pipeline security. 
What do you feel needs to be done to clearly define OPS's role for 
pipeline security?
    Answer. Although Homeland Security Presidential Directive-7 directs 
DOT and DHS to collaborate in regulating the transportation of 
hazardous materials by all modes, including pipelines, it is not clear 
from an operational perspective what ``to collaborate'' encompasses. 
The delineation of roles and responsibilities between DOT and DHS needs 
to be spelled out by executing a Memorandum of Understanding or a 
Memorandum of Agreement. At a minimum, the Memorandum should state 
clearly what agency will have the primary responsibility for issuing 
pipeline security rules, orders and directives; and responsibility for 
overseeing and enforcing operators' compliance with security 
requirements.

    Question 4. Are the approximately 90 Federal and 400 state 
inspectors responsible for pipeline safety adequate given the tasks 
ahead?
    Answer. OPS is faced with a very aggressive and ambitious task in 
overseeing and enforcing the pipeline operators' execution of their 
integrity management programs (IMP) and, at the same time, performing 
other oversight activities such as inspecting new pipeline 
construction, monitoring research and development projects, and 
investigating pipeline accidents.
    In our testimony, we stated that OPS had completed its IMP 
assessments of the 63 largest operators of hazardous liquid pipelines. 
Most of the heavy lifting lies ahead with 157 hazardous liquid and 884 
natural gas transmission pipeline operators still needing an initial 
IMP review by an OPS inspection team.
    Given the magnitude of this effort, with more than 1,000 pipeline 
operators who have not yet had an initial IMP assessment (at 
approximately 2 weeks for each assessment), OPS should be able to 
schedule out for the Committee a timetable for completing its initial 
IMP assessments in an effective and timely manner. In doing so, OPS 
should factor in its (1) staffing needs, both Federal and state 
inspectors, to conduct IMP assessments; and (2) training needs, both 
Federal and state, knowing that there are many more inspectors at the 
state level to train for IMP assessments of operators of natural gas 
transmission pipelines than were trained for IMP assessments of 
operators of hazardous liquid pipelines. As of June 30, 2004, 110 
Federal and state inspectors have received the advanced IMP training, 
with an additional 58 Federal and state inspectors scheduled to take 
the advanced training in 2004.
                                 ______
                                 
    Response to Written Questions Submitted by Hon. John Breaux to 
                           Katherine Siggerud
    Question 1. If OPS does not have clear goals for its enforcement 
strategy, on what basis is the agency making decisions about whether to 
impose a civil penalty, versus issuing a compliance order or taking 
some other enforcement action?
    Answer. When OPS fmds a violation, it relies on regional directors 
to determine the most appropriate enforcement action for the situation. 
OPS has an enforcement manual that provides general guidance on the 
various types of enforcement actions and how they should be used. 
However, this guidance is out of date, because it reflects the agency's 
earlier more lenient enforcement approach of partnerlng approach with 
industry. Therefore, OPS management has communicated current 
enforcement priorities to staff and relies on frequent contact among 
regional directors to assure consistency. OPS intends to devote more 
attention to strengthening the management of the agency's enforcement 
program. OPS expects to fmalize its new enforcement policy and 
guidelines sometime in 2005.

    Question 2. If OPS does not have clear goals for its enforcement 
strategy, on what basis does the agency impose a civil penalties and 
how does it determine the amount of the penalty?
    Answer. When imposing civil penalties, OPS must by law consider 
seven factors: (1) the nature, circumstances, and gravity of the 
violation; (2) the degree of the operator's culpability; (3) the 
operator's history of prior offenses; (4) the operator's ability to 
pay; (5) any good faith shown by the operator in attempting to achieve 
compliance; (6) the effect on the operator's ability to continue doing 
business; and (7) other matters as justice may require. OPS relies on 
frequent contact among regional directors to assure consistency. OPS is 
developing guidance that should help assure that it is making 
consistent decisions concerning civil penalties for all types of 
violations, but has told us that it does not anticipate finalizing this 
guidance until 2005.

    Question 3. How well is OPS communicating with its state partners?
    Answer. We believe that OPS has improved its communication with its 
state partners since we last reported on this issue 2000. Most ofOPS's 
interstate agents we contacted (7 of 11) told us that their 
communications with OPS have improved since 2000, when we recommended 
that OPS do a better job of involving them in Federal pipeline safety 
efforts. However, most (7 of 11) also raised concerns that OPS was too 
slow in informing them of actions the agency took on their notices of 
operator noncompliance. OPS told us that effective November, 2003, it 
would provide states with written responses to their notices within 60 
days of receiving them.
    In addition, we recommended in 2002 that OPS develop a strategy for 
communicating with the states what role they will play in oversight 
activities. In response, OPS told us that it was pursuing various 
initiatives to improve communication with the states, such as 
additional meetings with state officials and providing states with 
access to agency information systems.

    Question 4. How long does it take OPS to collect the civil 
penalties it assesses?
    Answer. We could not determine whether operators paid penalties in 
a timely manner because we determined OPS's and FAA's data were not 
sufficiently reliable for this purpose.

    Question 5. What effect does this delay have on the effectiveness 
of civil penalties in deterring safety violations?
    Answer. According to economic literature, the longer it takes to 
collect a given dollar penalty--whose amount was set after considering 
the circumstances of the infraction and the damage caused by it--the 
lower its expected deterrent effect.

    Question 6. How well has OPS fulfilled other GAO recommendations?
    Answer. In response to two recommendations we made in 2000, OPS has 
worked more closely with state officials in overseeing pipeline safety 
and adopted a more aggressive enforcement posture. As a result, we 
believe that OPS has implemented these two recommendations. For the 
third recommendation, that OPS determine whether the reduced use of 
civil penalties has affected operators' compliance with pipeline 
regulations, OPS told us that it did not have sufficient data to do so. 
However, to better assure that it could address safety concerns, OPS 
changed its enforcement policy to make fuller use of its range of 
enforcement tools, including increasing the number and size of civil 
penalties. We believe that this action implemented the intent of this 
recommendation.
    Five of our recommendations to OPS, made from 2001 to 2003, remain 
open. These include recommendations that OPS

   develop a workforce plan to ensure that it has the resources 
        and expertise it needs to carry out all of its 
        responsibilities,

   develop a strategy for communicating to the states what role 
        they will play in pipeline safety oversight, and

   develop a systematic process for evaluating the outcomes of 
        its R&D program.

    We are aware that OPS is working on these open recommendations and 
will continue to monitor their progress.
                                 ______
                                 
    Response to Written Questions Submitted by Hon. John Breaux to 
                           Hon. Marc Spitzer
    Question 1. What specific actions have been taken since the 
pipelines accident last summer in Tucson to improve your relationship 
between OPS and the ACC?
    Answer. After a review of the situation, I concluded that a lack of 
communication was the primary culprit that damaged our relationship. In 
an effort to address this issue from our end, the ACC is in the process 
of hiring a supervisor in our pipeline division that will act as a 
liaison to FOPS. I believe that this action will result in obtaining 
the desired level of communication between the ACC and FOPS.
    I would also highlight the following:
    In January, 2004, the Arizona Corporation Commission held a series 
of forums on pipeline safety around the state. Federal pipeline safety 
personnel participated in the forums. I believe their participation in 
the forums has helped to improve communication between the agencies.
    In May, 2004, Stacey Gerard, Jim Wiggins and Patricia Klinger of 
FOPS and the USDOT met individually with each Commissioner at the ACC. 
During our meeting, those three individuals and I agreed that 
communication was the issue and implemented a plan to communicate more 
directly with each other.
    Currently, Kinder Morgan has been keeping us informed on the 
activity taking place on the 6-inch Phoenix to Tucson line. This 
activity is part of a corrective action order FOPS issued to Kinder 
Morgan. Prior to that order Kinder Morgan did not appropriately 
communicate with the ACC. This communication has helped us to keep FOPS 
better informed.
    Overall, I believe through the efforts of all parties involved, 
communication has and will continue to improve.

    Question 2. Are you satisfied with this year's work plan for 
pipeline inspections, including the time authorized by OPS to inspect 
the Kinder Morgan pipeline?
    Answer. Yes, Staff and I are satisfied with this year's work plan.
    After consultation with the Staff, it is our understanding that 
FOPS granted our request to amend the current year work plan by adding 
an additional 15 days to inspect the remainder of Kinder Morgan 
pipeline facilities in Arizona. The only restriction is that we have to 
get all the other work noted in the work plan completed before we can 
pursue the additional inspection work we requested.
    FOPS has expressed to me a willingness to grant such a request. The 
ACC expects to complete its required inspections in October of 2004. 
Therefore, there is no indication that the ACC will be restricted from 
conducting additional inspections outside the current work plan.

    Question 3. The recent exchange of letters between Commissioner 
Mayes and OPS suggests that there may be a different interpretation of 
the work plan and how much flexibility it gives the state in performing 
inspections. What is your view?
    Answer. As I stated above, Staff, FOPS and I are satisfied with the 
present form of the work plan. As to the comments of another 
Commissioner, in Arizona each Commissioner is an elected official. A 
majority of three Commissioners is required for a formal Commission 
position. I cannot comment on the reasons for a difference of opinion 
among the Commissioners on the relationship with FOPS.

    Question 4. Your written testimony states that residential or 
commercial construction should not take place within 200 feet of a high 
pressure 8 or 12-inch gasoline pipeline. While you advocate for Federal 
and state standards, zoning is primarily a local issue, is it not? What 
progress is being made by cities in Arizona to prevent encroachment on 
pipeline rights-of-way?
    Answer. I recognize that the law of land use has historically been 
promulgated and adjudicated by local governmental units. The 1911 
Supreme Court decision of Town of Euclid ushered in a tradition of 
respect for the land use decisions (in that case zoning) of local 
government.
    In the case of the Kinder Morgan rupture of 2003, an unfortunate 
pattern of urban development clearly emerged. Particularly in 
``growth'' communities, real estate becomes dear. Residential, 
commercial and industrial real estate development places a premium on 
efficient use of raw land to maximize the rate of return to developer 
and land-owner (often these roles are combined).
    My experience as an Arizona attorney is that local government 
generally accommodates real estate development. That is not necessarily 
a bad thing, but it is a fact. And in case where residential or 
commercial development draws opposition, it arises from the pre 
existing residents.
    Where development is proposed in the vicinity of a natural gas or 
hazardous liquid interstate pipeline, there is no natural constituency 
as a check on the desire of the developer to maximize the value of the 
land, in fact the very nature of a remote development precludes 
neighborhood opposition. In the case of the Kinder Morgan rupture, 
development occurred only 37 feet from the pipeline.
    Federal law limits developments near nuclear reactors, and to a 
lesser extent military installations and airports. That analogy should 
obtain in connection with proposed development adjacent to interstate 
pipelines.
    I suggest a Federal rulemaking process be invoked by the U.S. DOT 
to fashion rules that adequately balance private property rights, local 
zoning authority and public health and safety. I believe expert 
testimony should be obtained to address an appropriate setback 
distance, recognizing that most pipeline ruptures are due to 
excavation.
    Thank you once again for this opportunity to supplement my 
testimony on these very important issues.
                                 ______
                                 
    Response to Written Questions Submitted by Hon. John Breaux to 
                            Lois N. Epstein
    Question 1. In your testimony, you discuss the need for 
``preventive enforcement actions to deter potential violators''. Could 
you please provide us with a few examples of how this might work? What 
type of violations would be appropriate to address with preventive 
enforcement actions? Do other regulatory agencies regularly use 
preventive enforcement?
    Answer. There are several sections of the pipeline safety 
regulations that Office of Pipeline Safety (OPS) enforcement personnel 
should pay particular attention to in order to prevent releases. 
Enforcement of these ``preventive'' regulations would supplement OPS' 
non-preventive enforcement actions, which are enforcement actions that 
take place after releases have occurred.
    In addition to OPS' current enforcement emphasis on proper 
implementation of its integrity management programs for both hazardous 
liquid and natural gas transmission pipelines, OPS preventive 
enforcement actions should address the following specific regulatory 
violations:

   Inadequate external and internal corrosion prevention (49 
        CFR 192, Subpart I; 49 CFR 195, Subpart H). Corrosion caused 
        24.5 percent of the natural gas transmission pipeline releases 
        and 24.4 percent of the hazardous liquid transmission pipeline 
        releases in 2003.

   Inadequate internal inspection testing and/or analysis of 
        test results.

   Improper performance of direct assessment. Because direct 
        assessment allows great operator flexibility and is a lower-
        cost and less-proven alternative to smart-pigging, OPS must 
        ensure that operators perform direct assessments properly for 
        them to have value in preventing releases.

   Exposed pipelines (49 CFR 192.327 and 49 CFR 195.248).

   Poorly-done repairs.

    My point is not that OPS never pursues enforcement actions related 
to these types of violations--it does on occasion, but practically no 
one except the violator knows that it has done so. OPS needs to pursue 
several enforcement actions in each of these regulatory categories, 
imposing relatively high penalties for non-compliance and with high 
media exposure. By doing so, all pipeline operators would realize they 
are at risk of receiving similar high penalties for similar violations.
    As an example of another agency pursuing preventive enforcement for 
oil releases, I refer the reader to the U.S. Environmental Protection 
Agency's (EPA's) Underground Storage Tank 1998 Deadline Enforcement 
Strategy at http://www.epa.gov/Compliance/resources/policies/civil/
rcra/storagetank-mem.pdf (Attachment A). Underground storage tank (UST) 
system releases derive from both tanks and their associated piping, so 
there is a strong correspondence with OPS' pipeline regulations. The 
UST enforcement strategy states that ``sub-standard UST systems should 
not operate after December 22, 1998. Those who delay [compliance] can 
be subject to monetary penalties of up to $11,000 per day for each 
violation throughout their period of non-compliance'' (p. 1). The 
strategy also states that ``In pursuit of its goal, EPA will use all 
the enforcement tools available for dealing with UST violations, 
including administrative and judicial enforcement actions. Judicial 
enforcement actions are particularly appropriate in situations 
involving recalcitrant parties'' (p. 3). A clearly articulated 
preventive enforcement strategy--available to both pipeline operators 
and the public on OPS' website--like the UST enforcement strategy, 
would be very beneficial to prevent pipeline releases.

    Question 2. Can you discuss the difference between OPS's 
enforcement approach and the EPA's, which I believe you are familiar 
with? Do you believe that OPS's enforcement strategy is less effective 
than EPA's in influencing industry's behavior?
    Answer. There are two major differences between EPA's enforcement 
strategies and OPS' enforcement strategies: (1) EPA pursues costly (to 
the operator), publicly-visible, and more-certain enforcement actions 
against the regulated community, which OPS does not do, and (2) EPA 
delegates enforcement to states if states are qualified to run their 
own enforcement programs, which OPS does not do for interstate 
pipelines because of an existing statutory prohibition.\1\ For both 
these reasons, OPS' enforcement strategy is less effective than EPA's 
in improving industry's performance. These items are discussed below.
---------------------------------------------------------------------------
    \1\ 49 USC Sec. 60104(c).
---------------------------------------------------------------------------
    1. Costly, visible, and certain enforcement--The U.S. Government 
Accountability Office (GAO) recently issued a report on OPS' 
enforcement program that analyzed the size of the civil penalties 
levied by OPS. According to GAO, ``the average civil penalty that OPS 
assessed from 2000 through 2003 was about $29,000'' \2\ Such penalties 
are far less than Congress envisioned when it raised the limits for OPS 
penalties in the Pipeline Safety Improvement Act of 2002 from $25,000 
per daily violation with a $500,000 maximum to $100,000 per daily 
violation with a $1,000,000 maximum.
---------------------------------------------------------------------------
    \2\ Pipeline Safety: Management of the Office of Pipeline Safety's 
Enforcement Program Needs Further Strengthening, U.S. Government 
Accountability Office, GAO-04-801, July 2004, p. 4.
---------------------------------------------------------------------------
    While I do not have data on the average civil penalty from EPA--and 
I encourage Congress or OPS to pursue that information--I can provide 
examples of pipeline releases that resulted in far higher (more than 
100 times higher) penalties from EPA than from OPS for similar pipeline 
problems. These examples are shown in the following table, with more 
details provided in Attachment B:

      Recent EPA Civil Penalties/Settlements for Pipeline Releases
------------------------------------------------------------------------
   Company       Date        Penalty           Summary of Violations
------------------------------------------------------------------------
Mobil E & P   8/04       $5.5 mill.       Oil and produced water
                                           releases, inadequate
                                           prevention and control,
                                           failure to notify EPA of
                                           releases
------------------------------------------------------------------------
Olympic       1/03       >$5 mill.--      > 230,000 gal. of gasoline
 Pipeline/                Olympic/>$10     released, 3 human deaths,
 Shell                    mill.--Shell     over 100,000 fish killed
------------------------------------------------------------------------
Colonial      4/03       $34 mill.        1.45 mill. gal. of oil
 Pipeline                                  released in 5 states from 7
                                           spills (from corrosion,
                                           mechanical damage, and
                                           operator error)
------------------------------------------------------------------------
ExxonMobil    9/02       $4.7 mill.       Approx. 75,000 gal. of crude
                                           oil released, fouling a river
                                           and nearby areas
------------------------------------------------------------------------
Koch          1/00       >$35 mill.       Approx. 3 mill. gal. of oil
 Industries,                               released in 6 states (from
 Inc.                                      corrosion of pipelines in
                                           rural areas)
------------------------------------------------------------------------

    EPA penalties also are far more visible to the public, which make 
them more effective. First, EPA distributes press releases for its 
large penalties, which OPS has begun to do, and second, any EPA 
penalties greater than $100,000 must be reported to the Securities and 
Exchange Commission under 17 CFR 229.103. The latter requirement means 
that company investors are aware of the violations and the penalty, 
which can provide a strong deterrent effect against additional 
violations.\3\
---------------------------------------------------------------------------
    \3\ Note that GAO did not consider this deterrent effect in its 
analysis of the effectiveness of OPS penalties.
---------------------------------------------------------------------------
    Last, EPA's numerous civil penalty policies posted on the Internet 
at http://cfpub.epa.gov/compliance/resources/policies/civil/penalty/ 
help ensure uniform and thus more certain enforcement against 
violators.
    2. Federal vs. state enforcement--A simple description of EPA-based 
environmental enforcement is that qualified states are delegated 
primary enforcement responsibilities for environmental laws even as EPA 
retains the right to pursue enforcement actions. In contrast, OPS alone 
can pursue enforcement actions for interstate pipeline violations, 
although certain states assist in inspection and analysis of 
violations. While the EPA system is not perfect and is similar to OPS' 
relationship with states with delegated responsibilities to oversee and 
enforce violations for intrastate pipelines, it is far superior to the 
current federal/state division of responsibilities for interstate 
pipelines.
    According to the new GAO report, the states have approximately 400 
pipeline safety inspectors and OPS has approximately 75 inspectors.\4\ 
Natural gas and hazardous liquid transmission pipelines (327,000 miles 
and 161,000 miles, respectively) primarily are interstate. As a result, 
the typical Federal inspector is responsible for oversight of 
approximately 6,500 miles of transmission pipeline. Additionally, 
Federal inspectors frequently are not as aware of certain technical, 
geographic, and even management issues associated with interstate 
pipelines as state pipeline safety officials are because of their 
proximity to the lines. As a result of limited Federal oversight 
resources and the Federal lack of familiarity with certain interstate 
pipeline concerns, it would be beneficial to change current law and 
allow qualified state pipeline safety officials to pursue enforcement 
actions against interstate pipeline operators.
---------------------------------------------------------------------------
    \4\ GAO, op. cit., p. 12.
---------------------------------------------------------------------------
    A final problem with the current federal/state interstate pipeline 
enforcement relationship is that the states' inability to pursue 
enforcement actions against interstate pipeline operators leads to 
frustrated state pipeline safety and elected officials. GAO spoke with 
one state pipeline safety official who stated that after his agency 
``alerted OPS to noncompliant activity at one company, it found the 
same violation 2 years later during the next scheduled inspection 
cycle.'' \5\
---------------------------------------------------------------------------
    \5\ Ibid., p.53.

    Question 3. Can you discuss the need for oversight of flow and 
gathering lines? Do you think OPS and the states are doing enough to 
ensure the safety of these types of pipelines?
    Answer. During my past three years of work in Alaska, I have become 
very familiar with the environmental and safety issues associated with 
oil and gas production fields from releases of crude oil, natural gas, 
and produced water.\6\ The rural nature of these lines has meant that, 
until recently, few have paid attention to their hazards. There 
currently is a pressing need for strengthened regulation of these 
lines.
---------------------------------------------------------------------------
    \6\ ``Produced water'' is any water that comes to the surface 
during oil and gas production, including water containing oil from the 
geologic formation, injection water, and drilling additives. Produced 
water, which generally is briny, typically contains pollutants such as 
oil and grease, acids, ammonia, benzene, naphthalene, metals (e.g., 
chromium, copper, lead, zinc), and sometimes radionuclides, following 
separation from crude oil and natural gas.
---------------------------------------------------------------------------
    Because Alaska has a very low threshold for reporting releases,\7\ 
I was able to ascertain what proportion of the oil pipeline releases in 
the Cook Inlet watershed came from flow and gathering lines. Of the 311 
miles of oil pipelines in the watershed, 60 miles (19 percent) are flow 
and gathering lines. From 1997-2001, 41 percent of the reported oil 
pipeline releases in the watershed came from flow and gathering lines, 
including 7 of the 8 largest releases (ranging from 1,134 to 228,648 
gallons). For the year following, 50 percent of the reported oil 
pipeline releases in the watershed came from these lines.
---------------------------------------------------------------------------
    \7\ Releases from ``unregulated'' pipelines need not be reported to 
OPS.
---------------------------------------------------------------------------
    Given the clear environmental and safety problems flow and 
gathering lines pose in the Cook Inlet watershed and the apparent 
problem they cause in other areas in the country (see Cook Inlet 
Keeper's comments to the OPS docket which are included as Attachment C 
and the August 3, 2004 Mobil example in Attachment B), I recommend that 
OPS:

  1.  Research the frequency and extent of releases from these 
        pipelines on the North Slope of Alaska and in other oil and gas 
        production states with appropriately low reporting thresholds; 
        and,

  2.  Expeditiously begin a rulemaking on this issue.

    Should OPS fail to address the environmental and safety issues 
associated with flow and gathering lines, Congress should ensure that 
it does so through appropriate oversight and/or legislation.

    Question 4. You mention that the current Federal preemption policy 
that prevents states from regulating and enforcing violations on 
interstate pipelines is overly restrictive. How would you change this 
to allow a greater state role? What type of activities could states 
engage in that would increase pipeline safety, yet not unduly impact 
interstate commerce?
    Answer. Given that states have particular pipeline safety concerns 
which OPS might not be sufficiently familiar with and thus might not 
address (e.g., earthquakes, subsidence, uniquely aggressive corrosion), 
and the fact that many if not all state-specific issues can be 
addressed without adversely impacting interstate commerce, I recommend 
that OPS and/or Congress:

  1.  Query state pipeline safety officials on how states have exceeded 
        Federal requirements for intrastate pipelines and on which of 
        these requirements they think are needed for interstate 
        pipelines; and,

  2.  Develop legislative language for the next pipeline safety law 
        reauthorization that allows states to exceed Federal 
        requirements to address state-specific conditions or needs in a 
        manner which does not unduly impact interstate commerce.

    As I stated in my testimony, 49 USC Sec. 60104(c) presents ``an 
unnecessary intrusion on states' rights with serious adverse 
consequences since national regulations might not protect states 
sufficiently from pipeline hazards, e.g., from earthquakes, difficult 
cleanup terrain, etc.'' \8\ Other areas where states might want to 
exceed Federal requirements include internal assessment requirements, 
right-of-way management, and definitions of high consequence areas. 
Simply put, requirements that are appropriate in one part of the 
country may not be adequate in another part of the country; if 
implementing such requirements would not unduly impact interstate 
commerce, states should be allowed to do so.
---------------------------------------------------------------------------
    \8\ Testimony of Lois N. Epstein, P.E., before the U.S. Senate 
Committee on Commerce, Science and Transportation, Oversight Hearing on 
Pipeline Safety, June 15, 2004.
---------------------------------------------------------------------------
                                 ______
                                 
    Response to Written Questions Submitted by Hon. John McCain to 
                              Barry Pearl
    Question 1. The Office of Pipeline Safety reports that the 
integrity management program for hazardous liquid pipelines has already 
resulted in 20,000 repairs. What kinds of problems have the inspections 
uncovered and how does the number of repairs under the integrity 
management program compare to the number completed annually before the 
program started?
    Answer. The principal conditions being repaired are those that are 
required to be repaired by the OPS regulations at 49 CFR 195.452 (h) 
(5).
    --Paragraph (h)(5)(i) describes immediate repair conditions, which 
include metal loss greater than 80 percent, predicted burst pressure 
less than the maximum operating pressure at the location of the 
anomaly, and dents at the top of the pipe (above the 4 and 8 o'clock 
position) with any metal loss, cracking, stress riser, or greater than 
six percent of nominal pipe diameter.
    --Paragraph (h)(S)(ii) describes 60-day conditions, which include 
dents located on top of the pipeline with a depth greater than three 
percent of the pipeline diameter or dents on the bottom of the pipeline 
that have any indication of metal loss, cracking, or stress riser.
    --Paragraph (h)(5)(iii) describes 180-day conditions, which 
includes dents with depth greater than two percent of the pipeline's 
diameter that affect pipe curvature at a girth weld or a longitudinal 
seam weld, dents located on the top of the pipeline with a depth 
greater than two percent of the pipeline's diameter, dents located on 
the bottom of the pipeline with a depth greater than six percent of the 
pipeline's diameter, anomalies with a calculated remaining strength of 
the pipe that shows an operating pressure that is less than the current 
established maximum operating pressure at the location of the anomaly, 
an area of general corrosion with a predicted metal loss of greater 
than 50 percent, a potential crack indication that is determined to be 
a crack when excavated, corrosion of or along a longitudinal seam weld, 
or a gouge or groove greater than 12.5 percent of nominal wall 
thickness.
    --Paragraph (h)(5)(iv) describes conditions for which an operator 
must schedule for evaluation and remediation, which include a change 
since a prior assessment, any mechanical damage to the top of the pipe, 
anomalies that are abrupt in nature, anomalies that are longitudinal in 
nature or extend over a large area, and anomalies located in or near 
cased crossings, crossings of another pipeline and areas with suspect 
cathodic protection.
    In addition to required repairs, other repairs are being made as 
well. The 20,000 repairs to which you refer in your question is a 
number taken from a database assembled by OPS from its inspections/
audits of thirty-six large and eleven small liquid pipeline operators 
conducted before December 31, 2003. OPS found these operators in total 
completed 1,191 immediate repairs, 756 60-day repairs and 2,397 180-day 
repairs. In addition, these operators undertook an additional 16,081 
repairs that were not subject to regulatory time deadlines. Many 
repairs in this last category were paragraph (h)(5)(iv) repairs, but 
others were not required by the IMP, but were made anyway because the 
excavation has exposed a condition. Obtaining permits for excavation 
and excavation itself are significant expenses, so, once the pipe is 
exposed, operators have a strong incentive to take a conservative 
approach and repair anything they find that may possibly be a cause of 
concern, including many conditions that likely would never fail in the 
lifetime of the pipe. These discretionary actions enlarge the total 
number of reported repairs, but represent a significant benefit to 
pipeline safety that will reduce pipeline risk far into the future.
    Although there is no comprehensive database to describe integrity 
inspections conducted by operators in the oil pipeline industry prior 
to the IMP, we know that such inspections were widespread. Based on my 
own experience, I would expect that the discovery of conditions and 
repair activity prior to the advent of the IMP for many ofthe stronger 
operators was similar to what they are experiencing now. For others the 
rate of assessment and the rate of repair have increased significantly 
as a result of IMP. The main differences under the IMP are the 
mandatory schedule for integrity assessments to which all operators 
must adhere and the mandatory time deadlines for completing the repairs 
for specific categories of conditions discovered. The IMP establishes a 
level expectation for the performance of all operators in the 
deployment of integrity assessment tools. The time deadlines for 
completion of repairs put pressure on operators to complete repairs 
sooner when conditions are discovered by these tools. There is no doubt 
that these deadlines accelerate the rate of repair. These time 
deadlines for repairs lend urgency to achieving prompt and successful 
implementation by federal, state and local agencies of section 16 of 
the PSIA addressing the ability of operators to get permits needed to 
complete repairs within these time limits. In enacting the PSIA 
Congress was raising the expectation of performance for pipeline 
operators to enhance pipeline safety. In enacting section 16 of the 
PSIA, Congress was also raising the expectation of performance for 
government permitting agencies to do their part to achieve the safety 
goals of the PSIA.
    By the way, there have actually been more than 20,000 repairs under 
the OPS integrity management program (IMP) for liquid pipelines since 
the program went into effect, and this is good news, not a concern. 
These repairs are reducing pipeline risks to the public by preventing 
leaks that will never have to be cleaned up and preventing 
environmental damage that will never need to be restored.
    The 20,000 number in your question comes from a database assembled 
by OPS before December 31, 2003. OPS teams spent approximately one to 
two weeks at each operator's headquarters to review the results of the 
operator's integrity assessments and actions taken to address integrity 
issues. The schedule under the rule calls for fifty percent of the 
highest risk segments of each operator to be assessed by September 30, 
2004, and operators are on track to meet that deadline. The data to 
which you refer provides a snapshot of the program in its early stages. 
Assessments and repairs are ongoing and will be ongoing for the 
foreseeable future. The data from your question covers conditions that 
an individual operator discovered through integrity assessment, 
evaluated and repaired in the period beginning with the effective date 
of the IMP and the date of OPS inspection for that operator. Since the 
OPS operator inspection visits did not all occur at the same time, and 
integrity assessments by operators continue after the OPS inspection, 
we can infer that the number of repairs is larger than the sum of the 
repairs reported at each operator's particular inspection date, all of 
which occurred before December 31, 2003. So the number of repairs 
completed by the industry as of December 31, 2003 is actually larger 
than 20,000.

    Question 2. Given the number of repairs that have had to be 
performed, should the schedule for implementing integrity management be 
accelerated?
    Answer. No. For hazardous liquid pipelines, the baseline 
inspections will reach the 50 percent point in 2004 and be completed in 
early 2008. Any further acceleration would be likely to disrupt those 
plans. Stability in the integrity management rules is very important at 
this point in their implementation. Operators are already undertaking 
the assessments required by the integrity management rules at a rapid 
pace, and most are ahead of the program's schedule. The expenditures 
for a company's integrity program are significant and budgets for 
future expenditures under the program are in place. Further 
acceleration of the program could lead to shortages of internal 
inspection devices (smart pigs) and personnel qualified to interpret 
the output of these devices. Correct interpretation is necessary to 
find the important conditions and limit unnecessary excavations. 
Moreover, immediate repairs are less than 6 percent of repairs in the 
data set you refer to in your first question, so the number of 
conditions requiring immediate action is relatively small.
    The best way Congress can support the speedy repair of the nations' 
oil pipeline infrastructure is to push the Council on Environmental 
Quality and the Federal permitting agencies to promptly and fully 
implement section 16 ofthe PSIA to provide permit streamlining for 
repairs under the current schedule.

    Question 3. How do these repairs correlate to the age of the 
pipelines involved?
    Answer. Pipeline age as a risk factor is usually misunderstood. The 
issue isn't how long the pipeline has been in service, but how it was 
initially manufactured, how it was installed and how it has been 
maintained. Cathodic protection, for instance, keeps an underground 
pipeline from corroding. If a pipeline has been protected from third 
party damage and inspected and maintained over its life, you won't see 
any difference in the pipe's condition whether its age is 50 years, 30 
years, or 10 years. The study by Kiefner and Trench, ``Oil Pipeline 
Characteristics and Risk Factors: Illustrations from the Decade of 
Construction'', which is available at http://committees.api.org/
pipeline/ppts/docs/decadefinal.pdf, reviews the performance of oil 
pipelines as a function of age. The study found that prevention 
programs, monitoring, testing and renovation can effectively keep 
pipelines of any vintage fit for service. However, the era of 
construction matters, because manufacturing, construction and 
prevention techniques have evolved over time to produce better pipe and 
pipe that is better protected from the causes of leaks. Knowledge of a 
particular pipeline segment's history is taken into account in 
designing prevention programs. Pre-1930s pipelines (about 2 percent of 
the Nation's mileage) were constructed before modem manufacturing 
techniques were developed and accordingly require more careful 
evaluation and may require mitigation measures. By the late 1940s 
cathodic protection began to be used to significantly reduce corrosion 
of steel pipe. By the late 1960s newer alloy and carbon steels greatly 
reduced manufacturing defects, and testing methods enabled addressing 
the defects that were present prior to placing the pipe in service. The 
1980s and 1990s saw development of in-line inspection tools (smart 
pigs) that allow operators to evaluate pipelines without having to stop 
flow and take the pipeline out of service, permitting sophisticated 
assessment of pipe in the ground to determine where repairs are needed. 
Pipeline operators' integrity management programs integrate the full 
range of information available about the history of a pipeline segment 
to tailor assessment and maintenance practices to mitigate risk.

    Question 4. The rate of incidents for hazardous liquid pipelines, 
while declining, is significantly higher than that of gas distribution 
and transmission pipelines. To what do you attribute this?
    Answer. The incident reporting criteria are different for hazardous 
liquid and natural gas pipelines, which results in the appearance that 
there are more hazardous liquid pipeline incidents. Hazardous liquid 
pipeline operators must report releases from pipelines (historically at 
a threshold of 50 barrels and more recently at threshold of 5 gallons) 
even when there is no additional safety impact (fire, explosion, 
fatality or injury) or damage exceeding $50,000.
    The net effect is that essentially all hazardous liquid pipeline 
releases are reported to OPS as accidents. This reporting requirement 
reflects the potential for environmental harm from such releases. In 
contrast, releases from natural gas operators are not reportable unless 
there is additional impact such as a fatality, injury or damage 
exceeding $50,000. In fact the vast majority of natural gas releases 
are not reported as accidents to OPS. Such releases are reported on a 
yearly basis through a natural gas annual report provided by each 
natural gas operator; such releases (without fatalities, injuries or 
substantial property damage) number in the thousands each year. The 
impacts from these, mostly small, releases are minimal Because of the 
potential environmental impact of any hazardous liquid pipeline 
release, liquid pipeline releases are reportable even when there is no 
other safety impact, such as a fire, explosion, injury, fatality or 
substantial property damage. Please note that the testimony of the 
General Accounting Office, including the chart in the GAO testimony, 
does not accurately describe or compare the safety performance and 
accident rates of hazardous liquid and natural gas pipelines. We will 
be communicating with GAO about this issue and will provide the 
Committee with a copy of our letter.

    Question 5. Why is it that the construction of new gas pipelines is 
regulated by the Federal Government (through PERC), but the 
construction of new oil pipelines is not?
    Answer. Historically, government granted natural gas pipeline 
companies exclusive franchise territories, but oil pipeline operators 
have always served an unregulated end-use market. The Natural Gas Act 
(NGA) established a certificate of public convenience and necessity for 
natural gas pipeline construction that is granted to an approved 
natural gas pipeline operator by the Federal Energy Regulatory 
Commission. Such a certificate currently governs the construction of 
all new interstate natural gas pipelines. On the other hand, oil 
pipeline construction is not subject to prior Federal authorization, 
and no federal certificate authority is available to oil pipelines. The 
NGA certificate is issued to jurisdictional natural gas pipelines and 
provides that if FERC determines it in the public interest, it may 
order a natural gas pipeline company to extend or improve its 
facilities; in turn, abandonment of all or any part of its facilities 
by a natural gas pipeline company cannot be accomplished without the 
permission and approval of the Commission. In return for this 
obligation to serve, natural gas pipeline companies are granted a 
federal right of eminent domain through the certificate process. While 
the NGA was significantly amended (1942, 1958 and 1978), these aspects 
of the regulatory framework have not changed.
    Federal pipeline construction certification has not been extended 
to oil pipeline companies, due in part to critical differences in 
regulatory history, marketplace and product characteristics and service 
functions between the two industries. For example, the Interstate 
Commerce Act, which provides the Federal authority for economic 
regulation of oil pipelines, is designed to encourage the growth of 
competing transportation modes and to allow commercial practices to 
govern most construction decisions. Federal eminent domain is not 
available to oil pipeline companies under the ICA. The ICA regulates 
oil pipelines as non-discriminatory common carriers. As common 
carriers, oil pipelines may benefit from a state's eminent domain law, 
depending on the statutes and precedents of that state. If an oil 
pipeline company seeks government assistance in constructing a 
pipeline, it applies to the state in which the construction would 
occur, not the Federal Government, for authority to acquire the 
necessary right-of way.

    Question 6. With demand for petroleum expected to increase 1.6 
percent annually through 2025, according to the Department of Energy's 
Energy Information Administration, do you foresee a need for Federal 
help to get new pipelines permitted?
    Answer. We do not seek Federal help in permitting new oil 
pipelines. The adequacy of oil pipeline capacity will become an issue 
in the future if rate treatment, now the province of the Federal Energy 
Regulatory Commission's implementation of the Interstate Commerce Act, 
fails to allow oil pipeline operators to attract the capital needed for 
expansion. With adequate ability to attract capital, oil pipeline 
operators have, with some important recent exceptions, been able to add 
capacity as needed. The industry has not found it appropriate to seek 
Federal intervention to ensure that permits for rights of way are 
provided in a timely fashion.

    Question 7. The Interstate Natural Gas Association of America 
(INGAA) recommends that the natural gas industry be granted antitrust 
immunity to exchange information about pipeline testing to ensure that 
local gas supplies are not jeopardized by integrity management 
inspections. Has this been a problem for operators of hazardous liquid 
pipelines?
    Answer. This has not been a problem for oil pipelines. Crude oil 
and petroleum product can reach most markets by many different modes 
and from many sources. Petroleum markets in general are highly 
competitive, and considerable flexibility is available to address 
supply issues. While pipelines are the safest and most efficient way to 
move these products, if pipeline transportation is not available, or if 
a particular pipeline is out of service, even in the short-term, 
alternative transportation or alternative supply is usually readily 
available, albeit sometimes at a higher cost. Unlike natural gas 
pipelines, hazardous liquid pipelines do not need to coordinate service 
among providers to avoid a market disruption.
                                 ______
                                 
    Response to Written Questions Submitted by Hon. John Breaux to 
                              Barry Pearl
    Question 1. You mention in your testimony that while the extent of 
product shortages and market impacts caused by pipeline pressure 
reductions are largely unknown, that it is a very real potential 
problem. Do you have an estimate, or a sense, of how pipeline pressure 
reductions may be impacting gasoline pricing? Of the pipelines 
operating at reduced pressures, how many of these are because of 
permitting issues?
    Answer. As you know, many factors affect gasoline prices, and it is 
very difficult to isolate the impact of any one of these factors. 
Experience tells us that a sudden loss in pipeline capacity has the 
potential to cause gasoline prices to spike, but the market generally 
reacts very quickly to increase supply. In any case, pipeline pressure 
reductions, which effectively reduce capacity, can't be helpful to the 
price situation faced by consumers. That is why we suggest that it 
would be prudent for government to expedite, to the extent possible, 
pipeline repair permitting, so pressure reductions are held to the 
absolute minimum necessary.
    As you know, we filed with our testimony a number of case studies 
of the actual experience of liquid pipeline operators with permitting 
issues. However, we are not aware of any comprehensive industry-wide 
data to answer your question about the interaction of permit delays and 
pressure reductions. My own guess is that a significant portion, but by 
no means all, of the pipelines operating under reduced pressure do so 
out of an abundance of caution. A significant portion also operate at 
reduced pressure because operators have not gotten permits in a timely 
fashion. Our case studies indicate this. Some operators reduce pressure 
upon discovery of a time sensitive condition even though this is not a 
required action. Others reduce pressure only after the time deadline 
has passed and the reduction is required by OPS regulations. In these 
latter cases engineering analysis establishes that the original 
operating line pressure is below what the line can handle and the extra 
safety margin in place can absorb the risk presented by the condition.

    Question 2. You point out that permitting for time sensitive 
pipeline repairs is a significant issue. How many time sensitive 
interstate liquid transmission pipeline repairs have been held up, past 
their required completion date, due to permitting problems?
    Answer. As indicated above, we do not believe a database exists to 
permit answering this question in a quantitative way. Our case studies 
indicate that, as you put it, ``sensitive interstate liquid 
transmission pipeline repairs have been held up, past their required 
completion date, due to permitting problems'', but we do not know the 
number or the percentage of completed repairs that experience this 
problem. We do know that delayed permitting is a problem, and one that 
would seem to be preventable.
    Because of the risk posed by the anti-trust statutes, trade 
associations (or our members) must be careful not to provide data to 
one another or to the public that impacts competitive relationships or 
prices. Assembling information about what markets are likely to have 
tight supply because of pressure reductions could be considered 
problematic behavior on our part by some of our regulators or 
customers.

    Question 3. Can you elaborate further on AOPL's idea for using Best 
Management Practices (BMP's) to expedite repairs to pipelines? Under 
your proposal, operators are assumed to be in compliance with 
permitting requirements if they employ BMP's in making repairs. Who 
would ensure that operators are following the BMP's in the field and 
that the work was completed without adversely impacting the 
environment?
    Answer. We intend to identify or develop best management practices 
(BMPs) or activities that are acceptable to the relevant regulatory 
agencies, with the intent that operators could undertake these 
activities without prior agency approval, similar to the way in which 
activities are pre-approved under the Corps of Engineers' Nationwide 
Permit process. Any agency with oversight responsibility would always 
be free to review the performance of an operator to ensure that BMPs or 
activities are being properly carried out in practice. An operator who 
does not perform as required under pre-approved BMPs or activities 
would be subject to fines or enforcement. What we are recommending is a 
presumption of compliance so that the operator can promptly take the 
actions needed to complete the repair. We are not seeking permission to 
adversely affect the environment without sanctions.
                                 ______
                                 
    Response to Written Questions Submitted by Hon. John McCain to 
                              Earl Fischer
    Question 1. According to statistics published by the Office of 
Pipeline Safety, gas distribution pipelines have experienced over 4 
times the number of fatalities and more than 3.5 times the number of 
injuries that hazardous liquid and natural gas transmission pipelines 
combined. Shouldn 't distribution pipelines, as suggested by Mr. Mead, 
be required to implement some form of integrity management program even 
if lines can't be pigged?
    Answer. Gas distribution systems have significantly fewer deaths 
and fatalities per mile than do the gas and liquid transmission lines 
put together.
    The safety record of natural gas distribution pipelines is truly 
extraordinarily positive. Unfortunately, the statistical data contained 
in the DOT Inspector General 's report did not fairly or accurately 
represent this fact because of the way in which it was presented. In 
order to fully understand the safety record of the natural gas 
distribution sector, it is necessary to have a clear picture of the 
holistic nature ofthe natural gas system.
    Over the last 10 years, the amount of natural gas traveling through 
natural gas distribution pipelines has increased by almost 6 percent, 
and 380,000 miles of pipeline have been added to the system. Based on 
2003 data, there are now almost 1.9 million miles of natural gas 
distribution pipeline today serving over 60 million homes and 
businesses in the United States.* In contrast, there are 
only about 300,000 miles of gas transmission pipe and 160,000 miles of 
liquid transmission pipe. In order to compare statistics from one 
sector to another, the accident data must be put on a common basis. For 
example, calculations of vehicular transportation accidents use 
vehicle-miles or passenger-miles traveled to make valid comparisons. 
For gas pipelines, this should be done by using total miles of 
installed pipeline for a given category such as transmission or 
distribution.
---------------------------------------------------------------------------
    \*}\Based on DOT Office of Pipeline Safety website data 
extrapolated for 2003.
---------------------------------------------------------------------------
    When measured in this way, it is clear that gas distribution 
systems have significantly fewer deaths and fatalities per mile than do 
the gas and liquid transmission lines put together. (See table in 
Attachment 1.)
    Nearly SO percent of all incidents on natural gas distribution 
pipelines are caused by an excavator hitting a pipeline (third-party 
damage), often because the excavator failed to call ahead to have the 
location of the line marked. Preventing third-party damage is the 
single greatest safety goal of the natural gas distribution industry. 
For a single cause to be the source of almost 50 percent of all 
incidents is simply unacceptable. As we have done numerous times in the 
past, and continue to do so, we strongly urge Congress to focus 
attention on excavation damage prevention. A generation ago, gas, water 
and sewer lines were the primary underground facilities in our nation's 
communities. Today, with the addition of telecommunications, electric 
and other facilities located underground, our gas distribution 
pipelines are more at risk than before. As shown by the chart in 
Attachment 2, annual distribution incident statistics show a clear and 
distinct correlation between the level of construction activity and the 
number of incidents. If excavation damage (also called ``third party 
damage'') incidents are removed from the picture, a different trend 
appears, as shown by the green line with the short dashes in the chart. 
This more closely reflects the efforts of gas distribution operators in 
ensuring the safety of their systems.
    Integrity programs like the one for natural gas transmission 
pipelines are not necessarily the best approach to preventing events 
such as excavation damage. Such events can be due to a number of 
causes, many of which cannot be mitigated by the actions of the gas 
operator alone no matter how diligent, resourceful, or technically well 
equipped.
    We urge Congress to continue to enforce tough laws that focus on 
preventing and reducing excavation damage incidents, such as the one-
call provision that was enacted in 1998 as part of TEA-21 and the 
excavation damage measures contained in the Pipeline Safety Improvement 
Act of 2002.
    As discussed during the question and answer phase of the hearing, 
the inability of natural gas distribution lines to accommodate internal 
instrumented inspection devices called ``smart pigs'' was not why 
Congress excluded natural gas distribution pipelines from the integrity 
inspection requirement of the Pipeline Safety Act of 2002. But rather, 
Congress acknowledged that there are already a variety of integrity 
management requirements for distribution systems. Distribution systems 
were exempted from the rigorous gas integrity legislation of 2002 
because these lines are located in high-density population areas and as 
such, already feature integrity safeguards that are incorporated in the 
current Code of Federal Regulation. Examples ofthese safeguards include 
extra-thick pipe walls, lower operating pressure and stress levels in 
the pipe, and a requirement that natural gas be odorized so people 
readily detect even small leaks by smelling the gas.
    Maps of all pipelines are already available from the operator upon 
request by the jurisdictional state authority. Unlike interstate 
pipelines, most states regulate the utilities serving customers in the 
state. Thus, each state is in the best position to determine what makes 
sense as to maps and other utility records to be kept, as well as what 
is most effective in the oversight of distribution system integrity. A 
centralized database for distribution system maps kept by Federal 
Office of Pipeline Safety would do little to improve state oversight of 
an operator's system.
    In addition, the current pipeline safety code contains 12 distinct 
requirements dictating the inspection of distribution pipeline 
facilities. The inspection frequencies depend on the location of the 
pipelines in relation to population and business activities.
    Under individual authorizations by the state, most companies have 
been addressing the integrity of distribution systems on a risk-based 
prioritization schedule. This includes leak management programs and 
repair-replace decisions and processes that allow the operator to 
ensure distribution pipelines remain safe and reliable, while using 
ratepayer funds in the most efficient manner. This has been taking 
place for at least two decades and is expected to improve as technology 
and materials developments allow more sophisticated decision-making 
processes as well as longer life, stronger materials. In addition, some 
states chose to impose more stringent requirements than the Federal 
code, thus addressing specific concerns or conditions in their 
territory. The role of state commissions in setting pipeline safety 
requirements and verifying an enforcing compliance of distribution 
operators cannot be overemphasized.
    Moreover, the gas utility members of the American Gas Association 
and the American Public Gas Association are conducting a study through 
the American Gas Foundation of enhancements to distribution system 
infrastructure integrity. Safety representatives from members of the 
National Association of Pipeline Safety Representatives and the 
National Association of Regulatory Utility Commissioners are also 
providing input to this study, to be completed by the end of 2004. In 
the meantime, critical experience is being accumulated with 
implementation of the transmission integrity rule.
    To meet our Nation's present and future energy needs, any policy 
related to the assessment of almost 1.9 million miles of distribution 
piping must take into account the potential impact on safe, reliable 
and affordable delivery of natural gas, as well as minimize disruption 
to consumers, the public and the environment.

    Question 2. What is the status of research efforts to develop smart 
pigs for smaller-diameter pipelines?
    Answer. Several manufacturers and research organizations are 
working to develop new and improved internal inspection devices, also 
known as ``smart pigs''.
[GRAPHIC NOT AVAILABLE IN TIFF FORMAT]

    However, as the Inspector General testified, ``smart pigs are not a 
silver bullet that can identify all pipeline integrity threats''. Even 
if smaller devices are developed, the majority of the distribution 
system infrastructure will not be amenable to internal inspection using 
such devices, as distribution pipelines are vastly different from 
transmission lines. Distribution pipeline systems are built in a 
network configuration; distribution pipes have numerous (many more than 
transmission) turns, valves, joints, branches and connections 
intersecting over very short distances that present obstacles to 
internal inspection devices. Normally, there is also insufficient 
pressure in the pipeline to drive the device through a line that has 
been rated for the low pressures typical of distribution systems. There 
must be sufficient space to insert and to remove the instrument from 
the pipe to be inspected; space is usually at a premium in urban 
streets and roadways where most of the distribution pipes are located.
    The effectiveness of the smart pigging method is further reduced in 
view of the fact that 40 to 50 percent of the distribution piping in 
the U.S. today is made from plastic. Less than 5 percent of the 
distribution incidents are due to corrosion in metal pipe. As described 
above, smart pigs are designed to detect defects through magnetization. 
Plastic does not magnetize. Since plastic pipe typically does not dent 
on impact, caliper pigs are also useless.
    In view of the above, other research and development initiatives 
are being implemented to ensure improved methods and equipment for 
distribution pipeline inspection. Examples of such are improved pipe 
locating tools that can pinpoint the depth of pipe, non-intrusive 
inspection methods and tools, and acoustic leak detection equipment.

    Question 3. The Energy Information Administration (EIA) projects 
that demand for natural gas will rise an average of 1.4 percent 
annually from 2002 through 2025. What impact will this growth have on 
distribution pipelines?
    Answer. Natural gas utility companies will continue improving the 
safety and reliability of their systems as demand for natural gas 
continues to grow. For example, utilities will implement methodical 
updates to systems, in some cases replacing thousands of miles of aging 
steel and cast iron pipe while installing new distribution pipe (most 
of which is durable plastic pipe) to meet the growing energy needs of 
homes, schools, businesses and other customers.
    One of the biggest challenges that gas utilities will face in this 
endeavor is financial--not operational. Massive amounts of capital will 
be required to support utility expansion of natural gas distribution 
lines, as noted in the next response.

    Question 4. Has the industry estimated how much additional pipeline 
capacity will be needed to accommodate the growth in demand?
    Answer. Yes. Nearly $70 billion (or a stunning $5.3 billion per 
year) will be required for natural gas distribution facilities by 2025 
(twice the rate for interstate pipelines and storage, which will cost 
$35 billion), according to the September 2003 National Petroleum 
Council report, Balancing Natural Gas Policy, Volume II. Successful 
development of this distribution infrastructure will depend on key 
factors such as obtaining inter-agency coordination and regulatory 
certainty in all permitting processes, maintaining the historical 
levels of reliability and flexibility of natural gas services as gas 
demand grows and load patterns change, and developing mechanisms to 
foster research and development, the NPC said.
    When it comes to gas distribution systems, the Federal 
environmental streamlining process is just the tip of the iceberg. 
Distribution operators must also contend with permits at the state and 
local levels, such as for state highways, railroad crossings, local 
pavement breakup, street barricading, traffic control, and depending on 
location, with local environmental permits, as well as pavement breakup 
prohibitions and pavement restoration fees. The above-named National 
Petroleum Council report also states (and we agree) that obtaining 
permits and construction of new or replacement facilities is becoming 
more difficult and more expensive as a consequence of various growth 
management, building code and environmental policies. This area cannot 
be ignored when dealing with policies on distribution system integrity.
    Hundreds of operators of gas transmission systems will soon be 
required to inspect their pipelines on a preset schedule. Many such 
pipelines will have to be shut down for inspections and the associated 
repairs. If gas outages occur, gas prices and reliability of delivery 
will come under intense pressure. Now, imagine the effects of a similar 
approach to distribution system integrity with over 6 times the 
mileage. This presents a potential for disrupting the everyday lives of 
gas customers and the public, if the approach to distribution integrity 
is not well thought out and adaptable to local circumstances and 
conditions. Obviously, even the Inspector General agrees that the 
approach to transmission integrity cannot be directly translated to 
distribution. If reliability of gas delivery is to be maintained, other 
approaches must be explored for distribution integrity. That is why the 
American Gas Foundation distribution study is so important.
    Mechanisms to foster research and development when implemented 
could, for example, help speed development of technology enhancements 
that more effectively address excavation damage detection and 
prevention, and to better pinpoint and prevent gas leaks from 
escalating into a bigger hazard. As previously mentioned, advances in 
materials and equipment may further help enhance safety while 
maintaining operating efficiency.
    The American Gas Association's three top priorities for research 
and development related to gas distribution are (1) improved gas system 
security; (2) enhanced reliability and integrity; and (3) improved 
efficiency for energy delivery. We fully concur with the Inspector 
General that the research projects the Office of Pipeline Safety is co-
sponsoring with industry are key to safety improvements in the gas 
delivery infrastructure and must continue.
    Attachments
    [GRAPHICS NOT AVAILABLE IN TIFF FORMAT]
    
                                 ______
                                 
    Response to Written Questions Submitted by Hon. John Breaux to 
                              Earl Fischer
    Question 1. Can you describe the ongoing AGA efforts with OPS to 
look at options for an integrity management program for distribution 
lines? How are the issues different than for those facing transmission 
lines?
    Answer. AGA, OPS, NARUC and other stakeholders are constantly 
working in a collaborative effort to ensure the safe and reliable 
delivery of natural gas. Together, we are seeking to make improvements 
that will enhance our systems. Indeed, while the integrity management 
requirements contained in the Pipeline Safety Act of 2002 appropriately 
focused on transmission lines within high consequence areas, AGA and 
its members nevertheless immediately went to work to assess the 
effectiveness of the current distribution regulations to maintain 
system integrity. This assessment will be completed by the end of the 
year and should serve as the foundation for discussions on how to 
further improve distribution safety during the next reauthorization 
process.
    Distribution pipelines are vastly different from transmission 
pipelines, and thus have a separate regulatory regime governing their 
safety. This regulatory regime is extensive, requiring no less than 24 
separate types of safety activities to be conducted on each 
distribution system, and has contributed to superior distribution 
pipeline safety.
    When compared with gas transmission and liquids incidents over the 
past 10 years, distribution systems show more incidents because there 
is 4 times more distribution pipe in service than transmission and 
liquids combined. Per 100,000 miles of pipe, however, the distribution 
incident count is less than transmission and liquids combined (46 
versus 49 total over 10 years, respectively). Comparing statistics 
between different categories of pipelines is only meaningful if done in 
this way because the miles of pipeline and the yearly growth in mileage 
must be taken into account.
    Interstate transmission systems are generally made up of long runs 
of generally straight pipelines occasionally crossing high-density 
population areas in our cities and towns. They feature large diameter 
pipe, and are operated at high volumes and high pressures. Distribution 
systems, in contrast, are constructed in configurations that look like 
a network or web, and run under practically every street in 
neighborhoods and business districts where there are gas consumers. 
These systems use smaller diameter pipe. By being located in high-
density population areas to begin with, they are required to operate at 
much lower volumes and pressures, often feature thicker-walled pipe and 
always carry odorized gas that can be readily smelled even if a small 
leak occurs.
    Transmission pipelines are almost exclusively made of steel. To 
maximize the volume of natural gas transported, interstate pipelines 
operate at stress levels from 20 percent to 80 percent of the maximum 
stress allowed for the type of steel material being used. Distribution 
pipelines use steel, plastic, cast iron or other materials of 
construction. When steel is used, distribution regulations require that 
stress levels be below 20 percent of the maximum allowed stress. 
Currently plastic pipe makes up 52 percent of the Nation's distribution 
system, steel comes in second at 43 percent, with the other materials 
making up the remaining 5 percent. Use of these materials is not 
uniform throughout the country, with newer areas for example, using 
predominantly plastic pipe.
    State pipeline safety authorities have primary responsibility to 
regulate natural gas utilities and intrastate pipeline companies, as 
part of an agreement with the Federal government. State governments 
then must adopt as their minimum standards the Federal safety standards 
promulgated by the DOT. In exchange, DOT reimburses the state for up to 
50 percent of its pipeline safety enforcement costs. Clearly, 
Congress's actions make a strong impact on state regulations and our 
companies.
    In addition, some states choose to impose more stringent 
requirements than the Federal code, thus addressing specific concerns 
or conditions in their territory. The role of state commissions in 
setting pipeline safety requirements and verifying an enforcing 
compliance of distribution operators cannot be overemphasized.
    Finally, under individual authorizations by the state, many 
distribution operators have risk-based integrity management programs 
already in place as part of a ``repair or replace'' decision-making 
process. This allows these companies to actively manage system safety 
by prioritizing inspections, maintenance, repair or replacement of the 
various portions of their distribution system. In fact, 49 CFR Section 
192.613 Continuing Surveillance, requires that operators consider a 
whole host of pipeline data to determine whether a segment should be 
reconditioned, phased out or undergo a reduction in operating pressure.

        Section 192.613 states the following:
        ``(a) Each operator shall have a procedure for continuing 
        surveillance of its facilities to determine and take 
        appropriate action concerning changes in class location, 
        failures, leakage history, corrosion, substantial changes in 
        cathodic protection requirements, and other unusual operating 
        and maintenance conditions.
        (b) If a segment of pipeline is determined to be in 
        unsatisfactory condition but no immediate hazard exists, the 
        operator shall initiate a program to recondition or phase out 
        the segment involved, or, if the segment cannot be 
        reconditioned or phased out, reduce the maximum allowable 
        operating pressure in accordance with Sec. 192.619(a) and 
        (b).''

    In short, to ensure reliable gas delivery, various approaches must 
be explored for distribution integrity and these may not end up 
following the transmission integrity model.
    To address such approaches, gas utility members of the American Gas 
Association and the American Public Gas Association are conducting a 
study through the American Gas Foundation of the distribution system 
infrastructure integrity in an effort to identify needed enhancements. 
State safety regulators of the National Association of Pipeline Safety 
Representatives and the National Association of Regulatory Utility 
Commissioners are also providing input to this study, to be completed 
by the first quarter of 2005. While OPS does not have direct 
jurisdiction over most distribution systems, the agency is also 
providing input.
    State regulators are using their experience to help identify 
distribution pipeline issues that have contributed to incidents, impact 
safety and could be reasonably implemented without unnecessary 
increases to the consumers' gas utility bill. The American Gas 
Foundation study will present findings that may help the above 
government-industry group formulate recommendations for enhancing the 
pipeline infrastructure, ensuring pipeline integrity, and tracking 
progress in improving safety.

    Question 2. What options exist to institute integrity management 
for distribution lines, given the limitations on using smart pigs?
    Answer. The options are currently being studied and expected to be 
quite diverse, as distribution systems are designed and built to 
optimally fit the conditions found in the respective utility's specific 
service territory.
    As briefly exemplified in our reply to the first question, the gas 
transmission, liquids, and distribution pipeline industries deal with 
differing challenges, operating conditions and consequences of 
incidents. Federal regulations recognize the differences between these 
three types of pipelines, and different sets of rules have been created 
for each. 49 CFR Part 192 sets out the regulations for natural gas 
transmission and distribution and the rules discriminate between the 
two, while 49 CFR Part 195 sets out the regulations for liquid 
transmission lines. It should be noted also that many distribution 
companies also own and operate transmission pipeline segments within 
their systems.
    The integrity management options for interstate transmission and 
liquid pipelines focused on methods to detect and repair points on the 
pipeline where anomalies are detected, to prevent stress at that point 
from causing a pipeline rupture. OPS issued the integrity management 
program or ``IMP'' rule for natural gas transmission lines on December 
12, 2003. The rule requires natural gas transmission pipeline operators 
to conduct periodic inspections in ``high consequence areas'', which 
for natural gas pipelines are generally high-density population areas.
    For gas distribution systems, the repair of gas leaks is allowed to 
follow a gas industry standard \1\ whereby the repair is prioritized 
according to how critical the leak is. The typically low pressures and 
volumes of gas in the pipe, in combination with the ever-present odor, 
provide an opportunity to react before the leak hazard escalates. Thus, 
for distribution systems and its widely different varieties, it is 
obvious that options for integrity management will have to be tailored 
to the conditions prevalent in the given service area.
---------------------------------------------------------------------------
    \1\ See Gas Piping Technology Committee (GPTC) Guide. This is the 
work of an accredited consensus standards committee with members from 
industry, government and academia.
---------------------------------------------------------------------------
    Hundreds of operators of gas transmission systems will soon be 
required to inspect their pipelines on a preset schedule. Many such 
pipelines would have to be shut down for inspections and the associated 
repairs. If gas outages occur, gas prices and reliability of delivery 
will come under intense pressure. Now, imagine the effects on a 
distribution system with over 6 times the mileage of gas transmission, 
if utilities are required to follow the integrity management script of 
a transmission IMP model. This presents an unwarranted potential for 
greatly disrupting the everyday lives of gas customers and the public 
on a continuing basis, if the approach to distribution integrity is not 
well thought out and made adaptable to local circumstances and 
conditions.
    Obviously, the approach to transmission integrity cannot be 
directly translated to distribution. Instead, it is critical that any 
process incorporate the regulations that are currently in-place, 
provide an approach that focuses only on where there may be areas of 
concern, and fully recognize the risk-based compliance approaches being 
utilized by state regulators with their operators.

    Question 3. Can you discuss the excess flow valve installation? You 
suggest that there are problems with the cost benefits analysis used by 
OPS relating to the nationwide installation of these valves?
    Answer. The existing regulation allows a natural gas utility to 
either notify customers of the availability and function of excess flow 
valves (EFVs), or to voluntarily install the valves on services which 
meet certain operating conditions. Therefore, under current rules, any 
customer that wants an EFV can get one when their service line is 
installed or replaced. As you may know, the valve is primarily intended 
to shut off gas flow when a service line rupture occurs resulting in 
escaping gas at a rate that is within 50 percent more than the normal 
flow to the customer's premises. This means that not all leaks in the 
gas line will trip the valve to shut-off.
    There were three major concerns about the draft cost benefit 
analysis conducted by OPS in its study published on March 7, 2003:

  1.  OPS made several inaccurate or shaky assumptions in regard to 
        incident prevention, EFV activation rate, and the ratio of 
        reportable to non-reportable incidents. Specifically, OPS did 
        not use its own incident data to estimate how many service line 
        incidents could be prevented by EFVs. As a result the OPS draft 
        analysis estimated that EFVs could prevent 10 times more 
        service line incidents than have actually occurred over the 
        past 20 years. In addition, OPS overestimated the number of 
        minor, non-reportable incidents that EFVs might prevent \2\. 
        The assumptions led to overstating of the benefits and 
        understating of the costs associated with mandatory EFV 
        installation. These assumptions were necessary because there is 
        a lack of EFV field operating performance data on the devices.
---------------------------------------------------------------------------
    \2\ Incidents are reportable to DOT if they result in death, injury 
requiring hospitalization and/or greater than $50,000 property loss.

  2.  The estimate for the costs attributed to false activations for 
        EFVs is not backed by adequate data. The study estimates the 
        cost to rectify a false activation at $552. In some cases, this 
        figure does not even cover the cost of pavement restoration and 
        permit fees since the EFV is quite often located in the public 
---------------------------------------------------------------------------
        road right-of-way.

  3.  The study lumped commercial services together with residential 
        services in its analyses. The functionality and use of EFVs for 
        residential services is far different than that for commercial 
        services. This is largely due to the higher variation in gas 
        consumption for commercial customers. An excess flow valve 
        typically comes in different sizes to match different ranges of 
        flows. A valve that is improperly matched to the flow can fail 
        to close when needed or close unnecessarily.

    On July 20, 2004, OPS placed a revised EFV cost/benefit analysis in 
the docket that corrects these discrepancies and now concludes that the 
cost of EFV installation exceeds potential benefits by nearly 4 to 1.
    The natural gas utilities continue to support utility choice of 
either voluntary installation or customer notification for excess flow 
valves as provided in the current pipeline safety regulations. All of 
our members, even those that voluntarily install the valves believe 
mandated installation of the devices would take away the utilities' 
flexibility to install the valves when and where they do the most good.
                                 ______
                                 
    Response to Written Questions Submitted by Hon. John McCain to 
                            Robert T. Howard
    Question 1. You have suggested that there may be a need to provide 
an antitrust exemption to permit companies to coordinate their 
inspection and repair activities to avoid disruption of energy supply. 
Wouldn't such an exemption allow companies to be privy to information 
that could be used against their competitors?
    Answer. Interstate natural gas pipelines are required by the 
Federal Energy Regulatory Commission (FERC) to be open-access, and 
place information about capacity availability, scheduling, planned and 
actual service outages or disruptions in service capacity, etc. on 
their respective websites on a real-time basis. See 18 C.P.R. 
284.13(c)(5)(d). The maximum rate a pipeline can charge for service is 
set by the PERC under Section 4 of the Natural Gas Act, and set out in 
the pipeline's public tariff. Pipelines are required to post pricing 
information related to any discounts offered to shippers on their 
Internet websites (18 C.P.R. 358.5(d)), and make discounts equally 
available to all similarly situated shippers. This ensures that 
pipelines are transparent, and that all customers and competitors have 
equal access to important information about pipeline capacity 
availability and pricing. Our industry is therefore accustomed to 
providing operational and pricing data to the public in an open forum 
setting.
    When a pipeline has planned maintenance or pigging that will 
disrupt service, the pipeline notifies its customers on the location of 
the maintenance or pigging, the anticipated duration of the maintenance 
or service disruption, and what services would be effected by the 
pipeline's activities. Pipelines want to give their customers as much 
advance notice as practical under the circumstances. This gives 
customers some time to adjust their natural gas supply needs and find 
alternative transportation if necessary. With unplanned service 
disruptions, the pipelines also post the relevant information but, 
because they must react immediately to circumstances beyond their 
control, they do not have the ability to provide their customers with 
as much advance notice.
    The interstate pipeline transportation industry is a competitive 
market. Often, more than one pipeline serves a major market area. 
Pipelines could best serve their customers by coordinating their 
maintenance schedules to ensure that multiple pipelines serving a 
single market do not all choose to engage in maintenance at the same 
time. However, pipelines are concerned that if they coordinate with 
other pipelines on when to conduct safety inspections and related 
repairs, the pipelines could face antitrust lawsuits from customers and 
consumers that allege that the pipelines improperly have acted in 
concert to create shortages and increase either gas commodity or 
transportation prices.
    If a pipeline must repair segments of pipeline as a result of 
inspecting its system, the pipeline may have to either reduce 
transportation throughput or perhaps take transportation lines out of 
service during the repair process. Customers may not be able to 
transport as much gas supply through these sections of the pipeline. 
The value of gas in certain areas may increase if the customer can get 
its gas to market; the value of gas that cannot leave the supply basin 
will fall.
    INGAA is concerned that should pipelines coordinate repairs with 
other pipelines to minimize the likelihood that its disruptions do not 
occur at the same time as a competitor or an interconnected pipeline, 
parties that may have been economically harmed by increased gas 
commodity or transportation prices could allege, albeit without merit, 
that the pipelines worked together to knowingly create these shortages 
and cause increased prices. While INGAA does not believe that these 
allegations would be supported in a court of law, it would still be 
time consuming and expensive to litigate each case. Accordingly, if the 
pipelines had explicit antitrust protection that permitted them to 
coordinate safety inspection and repair activities pursuant to the 
Pipeline Safety Improvement Act, pipelines would be able to work with 
other pipelines, including those that are part of the delivery chain 
from the production area to the market area, to ensure that as little 
service disruption occurs as possible.

    Question 2. Shouldn't the Department of Energy and the Office of 
Pipeline Safety, which have access to the industry's inspection and 
repair schedules, be able to manage scheduling to avoid disruptions?
    Answer. Natural gas pipelines are required under the new 
regulations to inform the Office of Pipeline Safety (OPS) as to the 
location of the High Consequence Areas (HCA) on their pipelines and as 
to whether a baseline inspection will be conducted in the first or last 
five years of the program. While there are performance reports 
required, there are no plans to notify OPS on the detailed scheduling 
of the baseline preparations, assessment and remediation. The 
complexity of scheduling these tasks in a centralized coordinated 
fashion is daunting at best. There are so many variables and competing 
priorities that successful centralized planning is a remote 
possibility. Not only are there many variables, but the rate of change 
of these variables is overwhelming. In planning maintenance, a pipeline 
needs to consider the particular demand curve of its customers, changes 
in weather, hydropower forecasts, nuclear plant outages in the 
pipeline's service area, and many other factors. For example, consider 
a pipeline that plans to perform maintenance during a month where the 
pipeline historically has seen low throughput due to mild temperatures. 
If a nuclear plant serving the same market must be taken down for 
repairs, or the weather changes dramatically, the pipeline must be 
ready to react and shift its maintenance schedule to ensure it can meet 
market needs. This need to react to market conditions makes a fixed 
central plan infeasible. It also highlights the need, as discussed in 
response to Question 1, for pipelines to be able to interact with each 
other on a real time basis without fear that their actions could 
trigger antitrust concerns.

    Question 3. The Energy Information Administration (EIA) projects 
that demand for natural gas will rise an average of 1.4 percent 
annually from 2002 through 2025. What impact will this growth have on 
transmission pipelines?
    Answer. This anticipated growth will translate into the need for 
additional pipeline capacity. Additional capacity will be needed in 
emerging production areas such as the Rocky Mountain region and Alaska, 
and in market areas such as the Northeast and Southwest where delivery 
capacity is becoming constrained.

    Question 4. Has the industry estimated how much additional pipeline 
capacity will be needed to accommodate the growth in demand?
    Answer. Yes. The INGAA Foundation will be releasing a report in 
July that outlines the natural gas pipeline and storage infrastructure 
expansions that will be required, out to 2020. In sum, if the U.S. 
market is to satisfy demand in an efficient manner by 2020, 
approximately $61 billion (in constant 2003 dollars) in infrastructure 
investment must be made in both the U.S. and Canada. Approximately $19 
billion of investment will be needed for replacement of current pipe 
simply to maintain existing pipeline capacity. Nearly $42 billion will 
be needed for new pipeline and storage projects. Of that, $18 billion 
will be associated with the Alaska natural gas pipeline and a similar 
pipeline from the Canadian MacKenzie Delta.
                                 ______
                                 
    Response to Written Questions Submitted by Hon. John Breaux to 
                            Robert T. Howard
    Question 1. You point out that permitting for time-sensitive 
pipeline repairs is a significant issue. How many time-sensitive 
interstate natural gas transmission pipeline repairs have been delayed, 
past their required completion date, due to permitting problems, and 
what impact has this had on safety?
    Answer. Natural gas pipelines have not yet been impacted by 
permitting for time sensitive-pipeline repairs. Based on the experience 
of hazardous liquid pipelines, we are concerned that this issue be 
addressed. First, let me differentiate between our segment of the 
industry, interstate natural gas transmission pipelines, and hazardous 
liquid pipelines.
    The integrity regulation for hazardous liquid pipelines has been 
effect for several years and the record of inspection and repair delays 
being discussed is primarily based on those experiences. The 
Association of Oil Pipe Lines has documented several cases and has 
reported the instances to the Office of Pipeline Safety. Based on the 
particular consequences of hazardous liquid pipeline incidents, the 
preponderance of the high consequence areas (HCA) where these repairs 
are occurring are at locations in environmental sensitive areas which 
have more permitting requirements. As a comparison, the HCA areas on 
interstate natural gas pipelines are predominantly in high-density 
population areas that that have less environmental issues due to 
previous human disturbances. Also, the design of the hazardous liquid 
regulations place a more rigorous timeline on repairing defects as 
compared to the natural gas integrity rule which used an improved 
technical basis to determine the repair response time.
    The new integrity regulations for natural gas transmission 
pipelines just became effective on December 15, 2003, with individual 
integrity plans due in December of 2004; therefore, the amount of 
experience in our segment has not emerged. However, interstate natural 
gas pipelines have complied with the National Environment Policy Act 
(NEPA) for many years, since the Federal Energy Regulatory Commission 
(FERC) must approve the construction of any new interstate natural gas 
pipeline pursuant to the Natural Gas Act of 1938 (and therefore, a FERC 
construction certificate is a ``major Federal action'' under NEPA). 
While burdensome, this process does centralize the disparate permitting 
processes of various Federal agencies and we expect will be helpful if 
permitting for time-sensitive repairs becomes an issue on natural gas 
pipelines. In some respects NEPA provides an integrated review of 
environmental issues and provides programmatic approval of certain 
practices. However, intrastate natural gas pipelines and hazardous 
liquid pipelines do not employ this NEPA process. Only recently has the 
need for expedited inspection/repair activities brought this to the 
forefront for these pipeline sectors.
    The amount of permits needed by the interstate natural gas pipeline 
sector due to integrity management activities remains difficult to 
predict at this stage. While it is true the U.S. has more natural gas 
transmission pipeline mileage than hazardous liquid pipeline mileage, 
hazardous liquid pipelines have a greater percentage of lines located 
in HCAs. This is because ``environmentally sensitive areas'' are 
included in the definition of HCAs for hazardous liquid pipelines, 
while HCAs for natural gas transmission lines are limited to areas near 
population. The natural gas sector will be seeking permits for 
activities such as the installation of smart pig launchers and 
receivers, and the replacement of pipeline segments/equipment that are 
not compatible with these inspection devices. And of course, we don't 
yet know how much repair activity will take place as a result of the 
integrity assessments.
    We think it is important for Congress to remain aware of these 
permitting issues, and we support efforts to improve permitting 
processes for time-sensitive repairs in other pipeline segments as the 
integrity program moves forward. Congress created strict timeframes for 
baseline assessments when it enacted the Pipeline Safety Improvement 
Act and it is critical that Federal and state permitting agencies have 
the same concern about whether these requirements actually get 
completed within the prescribed time.

    Question 2. OPS plays an important role in the regulation of 
liquefied natural gas (LNG) facilities. Given the growing usage of LNG 
and the many new LNG facilities being planned, do you think OPS has 
sufficient resources to focus the necessary attention on LNG facilities 
without compromising their ongoing pipeline safety efforts?
    Answer. Yes, for the time being at least. OPS draws upon the 
expertise of a number of other organizations to fulfill its LNG 
regulatory responsibilities, including the Federal Energy Regulatory 
Commission (which must approve any new LNG terminal) and the National 
Fire Protection Association (NFPA). The NFPA, for example, develops 
(and periodically updates) fire-prevention standards (NFPA 59A) for the 
design, construction and operation of LNG facilities that have been 
subsequently adopted by OPS. FERC plays a major role in the approval of 
a design for a new terminal, and seeks input from the OPS as part of 
that process. The U.S. Coast Guard plays a significant role in the 
safety and security of both LNG terminals and the vessels delivering 
LNG to these terminals. So, while the OPS staff is relatively small, it 
can leverage the resources of these much larger organizations.

    Question 3. You mention that the coordination of inspection and 
repair activities among various pipeline operators could help avoid 
market disruptions and price spikes, by ensuring that all of the 
pipelines serving a market are not off-line at one time due to repairs. 
INGAA has proposed authorizing an antitrust waiver for this activity. 
Why couldn't OPS serve to coordinate this activity instead, since they 
already must be notified of the repairs?
    Answer. Natural gas pipelines are required under the new 
regulations to inform the Office of Pipeline Safety (OPS) as to the 
location of the High Consequence Areas (HCA) on their pipelines and as 
to whether a baseline inspection will be conducted in the first or last 
five years of the program. While there are performance reports 
required, there are no plans to notify OPS on the detailed scheduling 
of the baseline preparations, assessment and remediation.
    It's really not a question of notifying OPS of the repairs; the 
issue is coordination and sharing of outage schedules between pipelines 
so that the effort of one company's plans on upstream or downstream 
capacity can be understood. This sharing of capacity information may be 
viewed as anticompetitive, when the intended outcome instead is to 
avoid unnecessary outages. OPS does not currently perform this function 
and would require a significant expansion in staffing at OPS which is 
well beyond their current function. We believe that a waiver would be a 
much easier approach that would assure that sharing such information 
would not be deemed anticompetitive.

    Question 4. What were INGAA's concerns with the initial proposed 
rulemaking of natural gas pipeline integrity management? How were these 
addressed in the final rule?
    Answer. While there are a number of issues that concerned INGAA 
with the proposed rule, the central one dealt with the definition of a 
High Consequence Area (HCA). The proposed definition was imprecise and 
based on outdated modeling. Working with OPS last year, INGAA advocated 
a more precise definition, based upon ``potential impact circles.'' 
Since natural gas is lighter than air, the release from a pipeline 
rupture goes straight up into the atmosphere (unlike hazardous liquid 
pipelines, where product can flow some distance away from the 
pipeline). These potential impact circles model the effects of a 
rupture and subsequent ignition, with the center of the circle being 
the rupture itself. Using mathematical formulas that take into 
consideration the maximum allowable operating pressure for the pipeline 
in question, the zone that would effected by fire radiation can be 
accurately determined. Then an operator can survey the number of 
buildings within these circles to see if there are a sufficient number 
to classify a pipeline segment as being within an HCA. OPS decided to 
allow for the use of these potential impact circles in defining an 
operator's High Consequence Areas.

    Question 5. In your testimony, you note that the law requires 
natural gas transmission pipeline operators to begin integrity 
assessments on their pipelines on June 17. Will all of your members be 
able to meet this deadline, without jeopardizing service to the public?
    Answer. Our members are complying with the deadline to begin 
integrity assessments, and in fact a great deal of this work started 
months ago. The summer is generally a good time to perform maintenance 
activities, since there is less demand for natural gas during these 
months. The recent increase in gas-fired power generation has somewhat 
changed that dynamic, however, especially during abnormally hot days 
when the maximum amount of power is needed to meet demand.
    Most of the work initiated to complete this deadline has been 
completed and was done without jeopardizing service. INGAA members will 
continue to do their utmost to prevent major service disruptions as a 
result of the integrity management activities. Some elements of the 
work, such as scheduling of inspection work and the extent to which 
repairs will be required, are difficult to predict right now. As we get 
further into the process, we hope to learn from experience and continue 
to minimize service impacts.

                                  [all]

                  This page intentionally left blank.
                  This page intentionally left blank.
                  This page intentionally left blank.
                  This page intentionally left blank.
                  This page intentionally left blank.