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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 

( 

(II) 

SENATE COMMITTEE ON COMMERCE, SCIENCE, AND TRANSPORTATION 

ONE HUNDRED EIGHTH CONGRESS 

SECOND SESSION 

JOHN MCCAIN, Arizona, Chairman 

TED STEVENS, Alaska 

CONRAD BURNS, Montana 

TRENT LOTT, Mississippi 

KAY BAILEY HUTCHISON, Texas 

OLYMPIA J. SNOWE, Maine 

SAM BROWNBACK, Kansas 

GORDON H. SMITH, Oregon 

PETER G. FITZGERALD, Illinois 

JOHN ENSIGN, Nevada 

GEORGE ALLEN, Virginia 

JOHN E. SUNUNU, New Hampshire 

ERNEST F. HOLLINGS, South Carolina, 

Ranking 

DANIEL K. INOUYE, Hawaii 

JOHN D. ROCKEFELLER IV, West Virginia 

JOHN F. KERRY, Massachusetts 

JOHN B. BREAUX, Louisiana 

BYRON L. DORGAN, North Dakota 

RON WYDEN, Oregon 

BARBARA BOXER, California 

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 

(III) 

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 

Page

IV 

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 

(1) 

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 

2 

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. 

3 

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. 

4 

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 informationsharing 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 FedVerDate Nov 24 2008 13:13 Jan 03, 2018 Jkt 075679 PO 00000 Frm 00008 Fmt 6633 Sfmt 6601 S:\GPO\DOCS\27960.TXT JACKIE
5 

eral 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 transVerDate Nov 24 2008 13:13 Jan 03, 2018 Jkt 075679 PO 00000 Frm 00009 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\27960.TXT JACKIE
6 

port 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: 

7 

• 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. 

8 

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 reVerDate Nov 24 2008 13:13 Jan 03, 2018 Jkt 075679 PO 00000 Frm 00012 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\27960.TXT JACKIE
9 

pairs 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. 

10 


615BONAS1.eps 615BONAS2.eps

Open Recommendations and Mandates: 

Cleaning Up the Pipeline Safety Record 

2001 -2004* 

70 .. 

c: 60 .2 

c; .. 50 .., "' c:- "' e.., "' 40 E ; o::::E 30 ~~ 

a: "' 20 c: 

"' Q. 

0 10 

0 

2001 2002 2003 2004 

Year 

*Does not include new recommendations 

or mandates 

RSPA Enforcement Trends 

Original Alternative Approach 

Type of Action Enforcement to Enforcement 

Polley (1995-1999) 

(1990-1994) 

Inspector Hours per 20 32 

Inspection 

Average Number of 

Inspections Conducted per 534 924 Year 

Average Number of Civil 63 19 

Penalties Proposed per Year 

Average Proposed $16,500 $19,000 

Civil Penalty 

Number of 11 9 

Corrective Action Orders 

•GAO 

O OIG 

D Congress 

DNTSB 

Current Polley 

(2000-2003) 

240 

821 

42 

$45,000t 

34 

t This average increases to $91,000 if proposed penalties for the Olympic and El Paso 

cases are included 
11 

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. 


615BONAS3.eps
12 

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 onestop 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 

13 

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 withVerDate Nov 24 2008 13:13 Jan 03, 2018 Jkt 075679 PO 00000 Frm 00017 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\27960.TXT JACKIE
14 

in 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. 

15 

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 ob- tained 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 

16 

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. 

17 

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 reVerDate Nov 24 2008 13:13 Jan 03, 2018 Jkt 075679 PO 00000 Frm 00021 Fmt 6633 Sfmt 6601 S:\GPO\DOCS\27960.TXT JACKIE
18 

1Of 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. 2OIG Report Number RT–2000–069, ‘‘Pipeline Safety Program,’’ March 13, 2000. 

3OIG Report Number SC–2004–064, ‘‘Actions Taken and Needed for Improving Pipeline Safety,’’ June 14, 2004. 4 A ‘‘smart pig’’ is an instrumented internal inspection device that traverses a pipeline to detect potentially dangerous defects, such as corrosion. 

sponsibilities 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. 

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

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. 

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 ProVerDate Nov 24 2008 13:13 Jan 03, 2018 Jkt 075679 PO 00000 Frm 00022 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\27960.TXT JACKIE
19 

5The 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. 

grams (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. 

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 

20 

6There 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. 

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. 

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. 

21 

7 Homeland Security Presidential Directive/HSPD–7, ‘‘Critical Infrastructure Identification, 

Prioritization, and Protection,’’ issued December 2003. 

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. 

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. 

22 

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 

23 

8The 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. 

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. 

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 

24 

9Stress 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. 

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. 

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 procVerDate Nov 24 2008 13:13 Jan 03, 2018 Jkt 075679 PO 00000 Frm 00028 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\27960.TXT JACKIE
25 

ess 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. 

26 

10Operators can choose another technology that demonstrates an equivalent understanding of 

the integrity of the pipeline but only after notifying OPS before the inspection begins. 

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. 

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. 

27 

11With 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. 

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 multiplefamily 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. 

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 

28 

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 manVerDate Nov 24 2008 13:13 Jan 03, 2018 Jkt 075679 PO 00000 Frm 00032 Fmt 6633 Sfmt 6601 S:\GPO\DOCS\27960.TXT JACKIE
29 

agement. 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. 

30 

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. 

31 

1 Hazardous liquid pipelines carry products such as crude oil, diesel fuel, gasoline, jet fuel, 

anhydrous ammonia, and carbon dioxide. 2Serious accidents are those resulting in a death, injury, or $50,000 or more in property damage. 

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. 


615SIGGE1.eps
32 

3These stakeholders represent industry trade associations, pipeline companies, Federal enforcement agencies, state pipeline enforcement agencies and associations, pipeline safety advocacy groups, and pipeline insurers. 

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 safetyrelated 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: 


615SIGGE2.eps
33 

4The 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. 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 

Continued 

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. 

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 atVerDate Nov 24 2008 13:13 Jan 03, 2018 Jkt 075679 PO 00000 Frm 00037 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\27960.TXT JACKIE
34 

are developed by standard-setting entities, such as the American Society for Testing and Materials, on the basis of an industry consensus. 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. 7To consolidate its accounting functions, in September 1993 RSPA began contracting with 

FAA to collect its accounts receivable, including civil penalties for OPS. 8For 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). 

tempts 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

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

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. 

In 2002, OPS began to enforce its new integrity management and operator qualification standards in addition to its minimum safety standards. Initially, while operVerDate Nov 24 2008 13:13 Jan 03, 2018 Jkt 075679 PO 00000 Frm 00038 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\27960.TXT JACKIE
35 

9OPS 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.’’ 10We 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). 

ators 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. 

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

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. 

36 

11See 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). 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. 13See, 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 Meas- ures, GAO–03–143 (Washington, D.C.: Nov. 22, 2002). 

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

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

Table 1: Enforcement Program Performance Measures That OPS Currently Uses and Is Considering Developing 

Measure Examples 

Measures OPS currently uses 

Achievement of agency 

performance goals 

Annual numbers of natural gas and hazardous liquid pipeline accidents and tons of 

hazardous liquid materials spilled per million ton-miles shipped. 

Inspection and 

enforcement activity 

Number of inspections completed; hours per inspection; accident investigations; enforcement actions taken, by type; and average proposed civil penalty amounts. 

Integrity management 

performance 

Annual numbers of accidents in areas covered 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 

enforcement actions 

The time taken to issue final enforcement actions, the extent to which penalty 

amounts are reduced, and the extent to which operators commit repeat violations. 

Safety improvements 

ordered by OPS 

Actions by pipeline operators in response to corrective action orders, including miles 

of pipeline assessed, defects discovered, repairs made, and selected costs incurred. 

Results of integrity 

management and 

operator qualification 

inspections 

The percentage of pipeline operators that did not meet certain requirements and the 

reduction in the number of operators with a particular deficiency. 

Source: GAO analysis of OPS information. 

aOPS 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: 

• Measures should demonstrate results (outcomes) that are directly linked to program goals. Measures of program results can be used to hold agencies accountVerDate Nov 24 2008 13:13 Jan 03, 2018 Jkt 075679 PO 00000 Frm 00040 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\27960.TXT JACKIE
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14We 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). 15See, 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). 16The 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. 

able 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

• 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. 

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. 

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. 

38 

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). 18The 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. 19OPS 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. 

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. 

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. 

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 


615SIGGE3.eps
39 

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 regulaVerDate Nov 24 2008 13:13 Jan 03, 2018 Jkt 075679 PO 00000 Frm 00043 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\27960.TXT JACKIE

615SIGGE4.eps
40 

20 Expected sanctions are the product of the sanction amount and the likelihood of being detected and sanctioned by that amount. 

tions 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. 

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. 

41 

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 twelveinch 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. 

42 

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 

43 

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 sysVerDate Nov 24 2008 13:13 Jan 03, 2018 Jkt 075679 PO 00000 Frm 00047 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\27960.TXT JACKIE
44 

tem 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 unoccupiedbut 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 reVerDate Nov 24 2008 13:13 Jan 03, 2018 Jkt 075679 PO 00000 Frm 00048 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\27960.TXT JACKIE
45 

newables, 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 culpritslack 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. 

46 

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. 

47 

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 

48 

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 

49 

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 

50 

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. 

51 

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. 

52 

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 peerreview 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. 

53 

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. 

54 

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 transVerDate Nov 24 2008 13:13 Jan 03, 2018 Jkt 075679 PO 00000 Frm 00058 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\27960.TXT JACKIE
55 

parency 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 

56 

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 conVerDate Nov 24 2008 13:13 Jan 03, 2018 Jkt 075679 PO 00000 Frm 00060 Fmt 6633 Sfmt 6601 S:\GPO\DOCS\27960.TXT JACKIE
57 

1See Lurking Below: Oil and Gas Pipeline Problems in the Cook Inlet Watershed, 28 pp. plus 

appendices, September 2002. www.inletkeeper.org/pipelines.htm 

tinues 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. 

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 

58 

2OPS 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) 

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 notfully-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. 

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, 


615COOK1.eps
59 

3These pipelines represented approximately 40 percent of reported releases from Cook Inlet 

watershed pipelines from 1997–2001. See Lurking Below, op. cit., p. 10. 4See 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. 6Letter from DOT Secretary Norm Mineta to Congressman Rick Larsen, March 10, 2004. 

7 U.S. GAO, op. cit., p. 26. 

8 Before the U.S. House of Representatives Committee on Transportation and Infrastructure, 

the Subcommittee on Highways and Transit, February 13, 2002. 

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. 

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. 

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. 

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. 

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. (§ 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 opVerDate Nov 24 2008 13:13 Jan 03, 2018 Jkt 075679 PO 00000 Frm 00063 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\27960.TXT JACKIE
60 

9 49 U.S.C. § 60104(c). 

10 49 U.S.C. § 60103. 11These rules are contained in 49 CFR 193. 

portunities 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. 

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

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 exVerDate Nov 24 2008 13:13 Jan 03, 2018 Jkt 075679 PO 00000 Frm 00064 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\27960.TXT JACKIE
61 

1Pipeline Safety Program, Research and Special Programs Administration, Report No. RT– 

2000–069, Office of Inspector General, Audit Report, March 13, 2000, p. 5. 

pansion 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 

62 

2 Ibid., p. 22. 

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 spotchecks of operator accident submittals, to ensure that all operators submit accurate, 

revised accident reports. My written testimony should have clearly stated such a 

recommendation. 

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 SepVerDate Nov 24 2008 13:13 Jan 03, 2018 Jkt 075679 PO 00000 Frm 00066 Fmt 6633 Sfmt 6601 S:\GPO\DOCS\27960.TXT JACKIE
63 

tember 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 se- cured $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 

64 

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 

65 

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 

66 

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 

67 

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. Costsper-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 permitstreamlining 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 

68 

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. 

69 

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 costeffectively—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 NaVerDate Nov 24 2008 13:13 Jan 03, 2018 Jkt 075679 PO 00000 Frm 00073 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\27960.TXT JACKIE
70 

tion’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 

71 

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 

72 

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 

73 

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 preexisting 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 

74 

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 

75 

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 wellregarded 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. 

76 

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 

77 

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 

78 

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. 

79 

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 

80 

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. 


615PPT1.eps 615PPT2.eps
81 


615RABIN1.eps

The Liquid Pipeline Industry 

in the United States: 

Where It's Been 

Where It's Going 

A Report prepared for the 

Associatio11 of Oil Pipe Li11es 

by 

Richard A Rabinow 

April, 2004 

© Ricl11ml A. Rabi11ow 2004 
82 


615RABIN2.eps

Table of Contents 

OveJView: The Liquid l'ipeline Industry 

Themes 

The Liquid Pipeline Industry is Extremely Diverse 

Decisions are Driven by Economic Analysis 6 

The Liquid Pipeline Industry is Increasingly l'roactive Regarding 

Environmental. Safety and other Matters of Public Interest 1 

Right-of: Way Maners have become Major Challenges 8 

Economic Regulation is Costly 9 

TrCJtds 11 

The Need for Liquid Pipelines 11 

Historical Overview I l 

The Customers 14 

The Commodities 15 

Regional Considerations 21 

Competition witlt Other Transponation Modes 27 

Ownership Stmcture of the Liquid Pipeline Industry 28 

Operarional Factors 32 

Operations Integrity 32 

Security 34 

Rights-of-Way 35 

Capacity Management 36 

Maintaini11g Product Quality 37 

Field Opcrat ions 39 

Work Force 41 

Community Involvement 42 

Costs 43 

Legislative and Regulatory Impacts 45 

Economic Oversight 46 

Environmental Protection 48 

Safety Oversight 49 
83 


615RABIN3.eps

Impact of Technology 

Constructing. Operating and Maintaining Pipelines 

Reducing Risk 

rv1anaging Costs 

Summary --· The Outlook 

49 

49 

51 

52 

53 
84 


615RABIN4.eps

List of Exhibits 

I. Fact Sheet - US Liquid Pipeline Industry 

2. l'etroleum Overview 1950 to 2025 II 

Selected Crude Oil Trunk line Systems 12 

4. Major Refined Product Pipelines 13 

s. Crude Oil Production and Oil Well Productivity 19SO to 2025 16 

6. Petroleum hnpo11s and E.' pons 1950 to 2025 16 

7. Refineries; Input & Output and Number 1950 10 2025 18 

8. l'etroleum Products Supplied by Type 1950 to 2025 19 

9 Pelroleum Administration for Defe.nse Dis11'ic1s 21 

10. Daily Supply & Disposition of Crude Oil and Petroleum 22 

Products, 200 I 

II. Operational Parameters by PAD District, 2001 22 

12. Oil Spill History; An Improving Record, 1%8 to 2001 33 

13 Typical Sequence of Petroleum Products Flow Through 39 

a Pipeline 

14. Average Pipeline Cost Distribution 1990 to 1998 44 

Ill 
85 


615RABIN5.eps

Acknowledgements 

The author acknowledges the support and assistance of Ben Cooper and Michele Joy, the 

Executive Director and General Counsel. respectively, ofthe Association of Oil Pipe 

Lines (AOPL) The websitcs of AOPL (www.AOPL.org] and of the American 

Petroleum Institute (API) [wMv.API.org] provide a great deal of useful infomtation 

ahC'Mtl liqttid peline.~ rh~tyl Trent:h, Pre<idenl nr Allegro Energy C"..n tlring. whn a~ 

prepared a number of important studies of the liquid pipeline industoy while serving as a 

consultant to AOPL and API, has been extremely helpful. The souroe of virtually all of 

the energy data contained in this report was the website of the Energy lnfonnation 

Administration [www.eia.doe.gov]. EIA reports of particular help were the Annual 

Energy Review 2001 , the Petroleum Supply Annual2001, Volume I and the Energy 

Outlook 2003, released Januaoy 9. 2003. 

About the Author 

Richard A Rabinow retired from ExxonMobil Pipeline Company on April I, 2002 after 

almost 34 years of service with ExxonMobil and its predecessors. Early in his career Mr. 

Rabinow held various assignments in the refining and supply functions, including the 

pos«ion of Manager of dte Baytown Refineoy during the mid-1980s. Thereafter he 

served as the Manager of the OOicc of Corporate Affairs and Manager of Environment 

and Safety for Exxon C001pany. USA 

Mr. Rabinow's association with pipelines began in 1993 when he served on the steering 

committee for an operational assessment of the Trans Alaska Pipeline System. A 

subsequent loan assignment as Senior Vice President of the Alyeska Pipeline Service 

Company was followed by his transfer t.o the Exxon Pipeline Company (EPC) and in 

early 1996 he was elected President. During his seven years as president ofEPC and 

E.xsonMobil Pi peline Company Mr. Rabinow also served on the TAPS Owners 

Committee, including a two-year temt as Chaimtan, and on the Boards of Plantation Pipe 

tine Company and Yellowstone Pipeline C<>mpany, He also was active in AOPL 31\d 

API acthrities and served a tem1 as Chainnan of AOPL. 

Mr Rabinow was educated at Lehigh University where he earned a Bachelor's Degree in 

Engineering Mechanics and at the Massachusens Institute of Technology where he 

received Master's Degroes in Mechanical Engineering and in Management. 

IV 
86 


615RABIN6.eps

Overview: The Liquid Pipeline Industry 

Cntit:<tl 

hifrastmcture: 

Stability. 

Diversity, tmd 

S<ifetyjor 

erica:~ 

Energy Supply 

The US liquid pipeline industry is large, diverse and vital to the economy. 

Comprised of approximately 200,000 miles of pipe in all of the fifty states, 

liquid pipelines carried more than 40 million barrels per day, or 4 trillion 

barre~ miles, of crude oil and refined products during 2001. That 

represents about 17% of all freight transponed in the US. yet the cost of 

doing so was only 2% of the nation's freight bill. Approximately 66% of 

domestic petroleum moves by pipeline, with marine movements 

accounting for 28% and rail and truck 1he balance. An illustration of the 

low cost of pipeline transportation is the J¢ per gallon cost to move a 

barrel of gasoline from Houston. Texas to New York !·I arbor. a small 

fraction of the cost of gasoline co the consumer. 

Pipelines may be small or large, up to 48" in diameter. but with only 

minor exceptions all ofthe pipe is buried. Some lines are a,s shon as a 

mile. while others may extend I 000 miles or more. Some are Vel)' simple, 

connecting a single source to a single destination, while others are very 

comple.x. having many sources. destinations and inter·connections. Most 

pipelines cross one or more state boundaries (interstate) while some are 

located within a single state (imrastare). and still others operate on the 

Outer Continental Shelf and may or may not extend into one 0 1· more 

states. US pipelines arc located in coaStal plains, desens, arctic tundra, 

moumains and more than a mile beneath the surface of the Gulf of 

Mexico. 

11te materials canied in liquid pipelines embrace a wide range of liquids. 

Crude syStems gather production from on-shore and off· shore fields, while 

transmission lines transport crude to temtinals, inter·connection points and 

refineries. The crude oil may be of domestic origin or imponed. Relined 

petroleum products, including motor gasoline, aviation fuels, kerosene, 

diesel fuel. heating oil and various fuel oils. whether produced in domestk 

refineries or imponed to coastal terminals. are sizable poniO<lS of the 

pipelines business. Other materials include petrochemical feed stocks and 

products and natural gas liquids (NGLs). including propane. which are 

often referred to as highly volatile liquids (HVLs) because they are gases 

at atmospheric temperature and pressure. but liquids under the higher 

pressures in pipelines. Still other pipelined materials include carbO<> 

dioxide and anhydrous ammonia and some liquid pipeline companies 

operate lines canying nitrogen. oxygen, and occasionally small amounts 

of natural gas. However. no~>li< uid pipelines handle almost all natural 

gas transmission and distribution. 

Pipeline companies are structured and owned in many ways. Pipelines 

may be organized as stock corporations. pannerships., master limited 
87 


615RABIN7.eps

A1cetiug the future: 

iucreasetl safety and 

security through 

''olumary initiath•es 

anti regularmy 

overs;ght, with (t 

new foc:us on 

community 

im•ob:emem. 

partnerships (MLPs}. limited liability companies (LLCs} and sometimes 

combinations of those fom1s. Many lines have a single owner who might 

be an independe-nt company. an integrated energy company. a large 

company with interests in businesses other than energy, a nofloaffiliated 

liquids shipper or an individual investor. In addition, there a.re numerous 

pipelines that are joindy owned by some combination of the entities that 

own pipelines by tl1emselves. 

With few exceptions tiq,•ids pipclinct; a.re commo11 carriers and the .. ates 

charged and the tcnns and conditions of the services are regulated by the 

Federal Energy Regulatory Commission (FERC} lOr interstate lines and 

similar state agencies for intrastate lines. The Office of Pipeline Safety 

(OPS) in the Depanmem of Transportation provides most operational 

oversight, although other federal agencies, such as the EPA and d1e 

Minerals Management Service, play imponant roles. State agencies 

regulate intrastate lines and local jurisdictions become involved with a 

variety ofmauers. including siting and emergency ,·esponse in the event of 

an incident 

111e liquid pipeline industry has made significant progress over time in 

reducing the number of safety incidents and oil spills and the volume of 

oil spilled. although d1e long term objective of no incidents and no spillage 

remains elusive. The years 2000 and 2001 each represented record 

performance. The year 2002. while not another record. sustained the 

lower level of incidents and volume spilled. A number of voluntary 

initiatives and regulatory pressures are helping to meet ever increasing 

industry and public e.'pectations. 

111e outlook during the first 25 years of the 21" Century is for US 

petroleum product demand to increase 9.5 million barrels per day (48%} 

with 2/3 of the growth being for transportation fuels. During that lime 

inland crude production is cxpe<:ted to de<:line 900 thousand barrels per 

day. mostly in Texas. LO<oisiana. Oklahoma and the Rocky Mounu.in 

states. while Gulf of Mexico production likely will increase by 500 

thousand barrels per day. And the forecast shows refining capacity 

growing 3.3 million barrels per day, mostly in Texas and Louisiana. That 

outlook would necessitate impons growing substantially. with cn,de up 4 

million barrels per day and refined products up 6.3 million barrels per day. 

During the same period significant grow1h is e.xpected in the 

petrochemical industry. 

'111e implications of the outJook are significant for the liquid pipeline 

industry With regard to cn1de transponation. it will be necessary to add 

large, expensive lines in the Gulf of Mexico. to add numerous large. shon 

lines between marine temtinals and coastal refi neries and to add cmde 

transmission infrastructure in the Midwest. to handle increased Canadian 

2 
88 


615RABIN8.eps

Forecast: Markt•l 

growth, 

infrastructure 

CXJXlnsion. 

rea/igumenl. and 

IIU} I't!IIL'lll 

Jedmologies 

imports, and along tl1e Texas/Louisiana Gulf Coast. Disinvestment in 

inland crude gathering systems and associated crude transmission systems 

will occur. as will redeployment and re-investment in many areas of the 

counuy. 

For refined product transportation the implications include c.xpansions. 

some significant. to move imported produc1 from coastal tenninals to 

inland consumption points and major expansions of product transmission 

~apacity from Te;,.as/Louisiaala Gulf Coast relining centers to the 

Southeast and the Midwest and to a lesser extent to Ari zona, CaJifomia 

and the Rocky Moumain region. The situmion is likely to be complicated 

by a continuing proliferation in the number of grades of product. And the 

network of pipelines providing feedstock and carrying petrochemical 

products, especially along the Texas/Louisiana Gulf Coast will expand 

rapidly. 

The rO\\~ng reliance of atar nation on petroleum products has other 

implications for the liquid pipeline industry. To accommodate substantial 

pipeline growth the availability of suitable rights-of-way, despite 

increasing urbanization. will be necessary. And. it is imperative that the 

existing infrasmscture continue 10 be well mai111ained and the aging 

network of pipelines be selectively upgraded and replaced. Technology 

and effective management systems will be keys to accomplishing that. 

while assuring safe, environmentally sound and reliable operations. 

There are several key points to keep in mind: 

• The liquid pipeline industl)' will grow significantly during the next 25 years, 

although not so much as the natural gas pipeline system 

• The induStl)' is extremely diverse and is becoming mon: so, especially with the 

rapid gro\\1h of Master l imited Pannerships (MLPs) and the decreasing role of 

major integrated energy companies 

• The pipeline industry is extremely competitive, and becoming more so, and there is 

a decreasing need for traditiornl economic regulation 

• Technology will play an essential role in continuing 10 improve the safe. 

environmentally sound and reliable operation of liquid pipelines and to effectively 

deal with the challenges o f an aging infrastnacture 

• Land use issues will be a major factor in acquiring rights-of-way that will be 

essemial to expanding and reorienting 1he pipeline network to meet the natjon's 

needs in the years ahead 

3 
89 


615RABIN9.eps

Exhibil I Fac1 Shec~ US Liquid Pi peline lndusuy 

M~ Cn.de l'nl tmnl. Itt~ (UII\lh s• 1D U", I.IJ) to 48•) S.S.((()nnks 

:t01o40,000mlle.4 

9'S.(O)nn~ 

1\J)Ilro' 200.(K){) Olll~ 

(CHlo(ppduli: 

..... ., .... .,., 

Propon10n or us ,.,.,. 

Mod< of 

-(l01)1) 

Oil~illagc: 

Cndc ... IJ.,-u. (~MIIID"Id. 11)0!11\ TXJ\lK/I..NWY) 

~trok\IJ" pro<l\ ... 1$ 

1oUtl hl.ltud J)lpclull.'t 

ll'\S~1 7nuk:ol 

RcH.,t~ae S6 26 U1lhon 

UO.(XX)+m•ks 

TOUII od ttlnsj.'Of1A."d u• p1p:lu"-'!1 (2001) ~ 1mlhon bnm:l<~ p.'tda~ 

.S7So- bdln'lll wn-nulo:J 

4 tnlhon bl•rnkmk"ll 

E_V11nplc.IIOU$llWI. TatdloNc~ Yotl.Ua~ Appro,$12$~--rbwn:l 

1\rfli'O.'\ ) t JI'.T tllllon 

0..1 shrpmcntf.., r.,.,.. or total fr..""' '" Cos.asrr:~.·t~C~C~oiiOQJ llrilti!ONII fA.-..Mc:.o!K 2'\ 

Wlklc.nmctw,:o•-.Lcn .,.,.,._ ) -

~ 

Trutls ~ 

Roo! l"to 

U..U: llO.OOO lwn:- pope~.,. 

T...U :!OOiwTdtC-s«<I.,._Ieo<. 7lO .. d,>padol 

4 

,.,.,~C'\Cf)2 ... 

.,_19l0o N 

'''"' ,.. ·- ''"' 19l0s l2'o 

19«11 ll ... 1911~ ,,.. 

19l!Oo ,.. 

I'M< 1% 

1000+ lett lhall 1% 

~tam-hne p1pc: A~"t'ln>' lau.J fl'=l. nl!IIIOI\ 

l~lnd-rmk:J 

I m thnn 11~ p:t lho~K:Md 

h..,l'l•fl\llc1 
90 


615RABIN10.eps

Themes 

1. The Liquid Pipel ine lnduslry is Extr emely Oi\rerse 

Although the concept of a liquid pipeline is simple and straight forward, the reality is that the liquid pipdi1lC illdusuy ill the Uojted States is extremely divc.-sc. 

in just about any way that one might attempt to measure the industry. For 

example: 

Size: PPeline diameter can be as small as a few inches or as large as 4 

fee~ length can range from less than a mile to more than I 000 miles and the line 

can be a pipe of unifom1 dimension or comprised of sections of multiple 

diameters or even parallel, interconnected pipes 

Geographv: Pipelines can be situated solely in one state. can cross many 

Slates. can operate emi1·eJy in federal waters outside any state or involve some 

combination of federal waters and one or more states. Pipelines operate in urban 

as well as remote areas, in arctic tundra. in desens. in coastal plains. in mountains 

and deep under the surface of coastal waters. 

Commoditie< carried: Pipelines can be dedicated to tmnsponing single 

commodities, such as crude oil. 1notor gasoline. jet lhel and propane. or can cany 

a range of difltrent commodities or of distinct grades of a single commodity; a 

typical large product pipeline carries 30 to 50 products regularly 

Complexity: Some pipelines carry material from a single source to a single 

destination while others have many sources. destinations and connections to other 

pipelines 

Shippers: Some pipelines have a single shipper while others have dozens 

of shippers: some shippers have an affiliation with 1he pipeline wi1ile others have 

none 

Tyoe< of services: While the basic service provided by a pipeline is 

transportation from one point to another, other services can be provided such as 

treatjng. blending and storing materials and operating and maintaining pipe.line 

facilities for others 

Coroorate structure: Pipelines may be organized as stock corporations., 

pannerships. Master Limited Partnerships and Limited Liability Companies 

Ownership: Some pipelines are wholly owned by a single emity, 

sometimes by an integrated energy company and also by other entities in and out 
91 


615RABIN11.eps

of the energy business: other pipelines have multiple ownership where the owners 

might be other pipeline companies, other energy companies. various other 

corporate entities. investor groups or individual investors 

Given the wide range of situations. from a small pipe-line with a single owner. 

carrying a single ma1crial for a single customer, 10 large companies owning and 

opera1ing thousands of miles of pipe in many states and in federal waters and 

canying a long list of commodities for one hundred or more shippers, i1 is diffic~.1 h lO establish a11d admi1ljsccr policy i11 \vays that arc fajr ftJld equi1ablc 10 

1he wide range of industry participams. Inasmuch as !here cxis1 subjecls for 

which regulation is essentially nor~discretio nary. it is importam that the 

industry's diversity be recognized and understood so that whatever regulation is 

imposed will be as effective as possible in meeting its objectives. 

2. Decisions are Dri,·en by Economic Analyses 

Today, every pipeline emily. whe1her a s•11all, indepclldenl opera1or or a part of a 

large. integrated oil company. makes decisions that are driven by similar business 

and econo•nic analyses. Simply put, vinually evel)' pipeJine emity uses a similar 

process 10 make decisions, al1hough 1hc dc1ails of1he analysis, 1he sophis1ica~ion 

of1he 1ools employed and 1he judgmems and assump1ions vary. ne common 

elcmeniS of the analylical process are: 

ne ~ 10 cons1ruc1 opcra1e and maimain 1he pipeline or segment in 

question 

The revenues. considering volumes, 1ariffs. seasonality and other 

variability over time that can be e..xpected to be associated \\~th the pipeline or 

segment being studied 

l11e competition. as it exists and as it may change in response to the 

projec1 under s1udy and 10 01her factors 

The business risks associated \vitl1 the venture. which include the cost and 

schedule for executing a project, changes to the cost and revenue projections, 

legislative and regula!OI)' changes, and !he consequences of any operational 

inciderns 

'111e inclusion of a profit component that provides a return to the investor. 

be il an individual or a large corporation, and is rcOec1ive of the cos1 of capi~al 10 

the investor. the perceived risks involved and the alternative invcsuncnrs available 

Every pipeline opcra1or considers 1hose fac1ors wt1en deciding whe1her 10 go 

forward with a project or whetl1er to retain a panicular business segment. Some 

may be more optimis1ic than others regarding cost, revenues and 1he longer term 

outlook. some may require a higher or lower return component and there may be 
92 


615RABIN12.eps

differences of opinion regarding me level of risk, but everyone considers the same 

factors. Contrary to \Vhat some may believe. even the pipeline companies that are 

a part of large, integraced oil companies must consider those factors and their 

decisions mus1 be economically sound. The time is past; if in fact it ever e.xisted. 

that the pipeline segment in an imegrated company will make an unsound 

business decision because it is panly or wholly owned by a company that has 

other interests as a potential shipper. 

3. The Liqt•id Pipdioe lodustt·y is hH ea~iogly P••oacch't: Rega•·diug En"i•·ou•)ltocal, Safety 

and other Matters of Public Interest 

For a number of years the leadership of the liquid pipeline industry has been 

acutely aware of the imponance of meeting or exceeding the public's e.'Cpectations 

regarding environmental and safety performance. While the industry would argue 

tl1at it always has striven for excellent operations, ttere were factors in the past. 

such as the state of technology, the level of perfom1ance standards, the then 

exisling best practices and the p•·iorities of the business. that did not provide the 

emphasis that operational e.'<cellence has achieved during recent years. 

During llle 1980s. there were a number of major incidents (including the chemical 

release in Bhopal, India and the propane explosion in Mexico City which together 

killed thousands of people and tl1e Valdez, Alaska oil spill) that had a profound 

impact on the petroleum and petrochemical industries. There also have been 

widely reported incidents im•olving liquid and natural gas pipelines (including 

Brenham. Texas, Edison, NJ. Colonial Pipeline spills and the Bellingham, 

Washington explosion and fire) that brought home a recognition that pipelines. 

too. needed to respond and to improve operatiOilS. l11e overall response has been 

to alter priorities and to systematically re·,examine operations with an eye to 

fundamentally improving the way pipelines are constructed, maintained and 

operated. 

The general approach has been to develop and implement a set of management 

systems that cover all aspects of operations and virtually everything associated 

with tJ1enl, Thus it stans with the leadership role of management, includes the 

selection, training and qualification of employees and contractors. the building, 

maintaining and operating of pipelines, risk assessment, the application of 

enhanced technology and incident prevention and response and ends wi1h system 

eva luation and continuous improvement. As with most such broad initiatives, 

some companies became involved earlier than others.. but \\~lh 1he passage of ren 

or more years \~nuall y everyone is actively engaged. And the results show it, 

although everyone would be quick to acknowledge that the level of pc1fcction 

expected by the public is not yet being met regularly. 

During llle mid·l990s alignment was built across tl1e leadership of the liquid 

pipeline indtlStl)' and a variety of initiatives were begun to funher improve the 

industry's performance. Until then the pace of improvement had been slower 
93 


615RABIN13.eps

than desired: and there was a need for a step change improvement. Perhaps the 

most significant ac1ion thai was taken was the establishment of a voluntary 

industry program, the Pipeline Perfom1ance Tracking System (PPTS). to record 

virtually every spill incident in keeping with a belief that something must be 

measured for it to be mana_ged. Thai voluntary efT on has been in place for several 

years, significant improvement is being seen and the federal safety regulatory 

agency recently adopted a reponing program similar to what the indusuy 

instituted. PPTS was not the only initiative. Others relate to berter training for employees., beltcf infomtaticm for usc by pipeline companies. regulators a1ld 

emergency responders, research seeking to identifY boner tools and techniques 

and encouraging Congress and the regulators to adopt enhanced legislation to 

ensure unifom1 compliance. 

4. Right-of-Way Mlmers have become Major Challenges 

During most of the early history of the liquid pipeline industry the acquisition of 

rights of way for pipelines was relati,,ely easy, rcnecting routes that were mostly 

in sparsely populated, rural areas and the generally understood need to mo\e 

crude oil from producing areas to refineries and products from refineries to 

consumers. In recent decades the situation has changed considerably, as the 

United States has become increasingly urbanized and the interests of the land 

owner and the oil indLOtry have deviated. Today, the acquisition of rights of way 

can take extended periods, often much longer than the time required 10 construct a 

pipeline, involves difficult and time-consuming negotiations. is increasingly 

costly and oflen ends in litigation that can drag on for years and sometimes a 

decade or more. The outlook is for the situation to become even more difficult, 

time-consuming. cosily and litigious. And 1his is true everywhere. even in areas 

such as Texas that are commonly thought 10 have close affinities to the petroleum 

industry 

111ere appear to be two basic factors that are driving the changes. one being 

financial interests and the other being safety concerns. Few land owners today 

have any vested interest in the petrolamt irtdustry: rather chey desire to maximize 

the return from their land. So, if a pipe-line crosses the-ir propeny or if a new line 

is routed across it, their desire is to gain as large a payment as possible for 

granting access and most land owners are prepared to cake whatever steps are 

available to bolster their case. Thus, dueling appraisals. 1he retention of 

specialized. sophisticated attorneys, protests before regulatory bodies and legal 

chaJienges are all pan of the efforts to e.xtract higher value for providing an 

easement co a pipeline. Others are concerned ab-out the potential for safely 

incidents that could arise from a pipeline in close proximity to their hon>es, the 

schools their children attend, their places of business and so forth, 111ey also 

express concern that the value of their propeny will be diminished by the 

presence of a pipeline easement. Despite the improving safety and environmental 

perfom1ance of pipelines. the relatively few significant incidents receive wide-
94 


615RABIN14.eps

spread and graphic coverage and foster the NIMBY (Not in My Back Yard) 

philosophy that many industrial and public facilities face. 

Another aspect of the rig:ltt·of.way challenge is the effective management of 

existing easements. Despite the existence of safery concerns. land owners 

typically seek to limit the width of easements and to ligl>t constraints on ~>cir use 

of the land immediately over the buried pipeline. A large body of historical data 

demonstrates that the single larges1 cause of pipeline safety incidents and spills is damasc co pipcliiH:s by third-parties whe•l they e.xca"ate, faml Of co•lduct other 

activities in the rights of way. As a result there is a major enon underway by the 

pipeline industry and other interested parties (such as excavation contractors, 

regulatory bodies, telecommunications companies and utilities) to develop better 

ways to build and mark pipelines (and other underground utilities), to infonn 

contractors and the public about the need for caution when worldng on or near 

easements, to enhance the nation-wide one-call system, to eliminate physical 

encroachments onto easements and to implement land use planning standard< to 

reduce the risk of incidentS from intrusions onto the rights-of-way. 

11le economic (i.e. rate) regulation of liquid pipelines is costly and it is 

questionable e~ er the regulatory structure that has evolved over a long peried 

is still needed or justified. For the last decade pipeline rates have been set under 

four approved methodologies. The most common method has been tO adjust rates 

according to a FERC-set index that uses an inflation factor to establish a ceiling 

for any rate. Alternatively, pipelines (I) may negotiate rates if all shippers using 

the service concur. (2) may use the market-clearing price provided that FERC has 

found ~>e pipeline lacks market power in the etrected origin and destination 

markets; or (3) may apply for traditional cost-of-service treatment. Shippers may 

also request a cost-of-service review of rates. Under the rules of common 

carriage applicable to all pipelines. the same rate must be charged to all similarly 

situated shippers. Of the various available methods, the least used, since the 

inception of inde.'\:ation. has been cost-of-service. However, as pipeline assets 

change hands more rates are being challenged, which leads to more os ~ofservice reviews being conducted and moves liquid pipelines closer to utility.. type 

regulation than ever before. 

Any analysis of the cost of regulation should stan with tl>c direct costs, which are 

significant, including employees of1he pipeline companies. the regulatory staffs 

and the fees for lawyers retained by shippers and carrie . Such costs are 

measured in the tens of millions of dollars annually, but are n01 the most 

substantial costs associated with economic regulation. It is the indirect costs that 

are most significam. One is the opponunity cos1 of 1he management time that 

could be employed for higher economic vaJue in many ways. such as improving 

operating perfom>ance and better serving the needs of shippers. And probably 

even more imponantly. the economic regulation has a chilling efl"cc1 on 

9 
95 


615RABIN15.eps

invesuncnts in new infrastructure. The cost of any large pipeline project is 

measured in the millions, if not tens of millions. of dollars and uncenainty. which 

can result from economic regulation. is a major factor in delaying and even 

avoiding investment. The uncenainty arises because economic regulation is being 

used to delay projec1s and to drive dow·n revenues to levels that may not provide 

adequate returns to the investors. 

Once, there might have been an argument that despite the cost. economic rcgulatiOtl \vas needed ror other reasons. suc:h as pfotec:lillS shippei'S. Howeve r, 

the pipeline industry has changed over time. Today il is a \ery diverse, 

competitive industry. with a large number of companies, an increasing number of 

large. independent entities (such as MLPs that can tolerate a lower return level 

because of tax advantages to their investors) and a much diminished panicipation 

by integrated majors. furthennore, the situations of the pipeline companies 

O\Y!led by the majors have changed. Today. each must stand on its own and be 

judged by iiS financial and operating perfomtanee and vinually no credit is given 

for service to an afll liatc. It is strictly business and an affiliated pipeline company 

must compete just like its unaftlliated brethren and show results. These changes. 

\Vhich have been undel'\vay for years.. are accelerating. 

A solution to cha11ging economic times would be to limit economic regulation to 

cases of undue discrimination and otherwise let the marketplace set the 

appropriate level of pipeline rates. Maintaining some requirement for pipelines. 

such as to publish tariffs and to provide access under reasonable tenns and 

conditions. should provide acceptable safeg11ards for all concerned. 

1U 
96 


615RABIN16.eps

Trends 

The Need for Liquid Pipelines 

Historical Overview 

1950 

1%0 

1970 

1980 

1990 

2000 

2010 

2025 

11lc hislory of liquid pipelines in 1hc Unilcd Slales can be !raced 10 lhe lale 1800s 

in Ohio, J>enn syl ani:,~: 3nd New Jersey. T he primary driver for the use of 

pipelines has always been economic. When oil was discovered and produc1ion 

commenced. crude oil volumes were small and a distributed transponation 

gys1em. such as horse-drawn wagons, trucks, and railroads. was the most cfficicn1 

means of transporting the oil to refineries where it would be convened into 

producls desired by oil consumers As 1he level of produc1ion increased i1 became 

ccooomical to invest in pipelines, especially for the transmission lines that would 

carry lhe crude 10 1he refineries Depending upon 1he level of produc1ion in a 

panicular field and the proximity of the wells one to an01her, producers might 

cominue 10 use wagons and •rucks or decide 10 inves1 in pipes 10 ga1her 1he crude. 

Exhibit 2. Petroleum Overview 1950 to 2025 

ThousuOO Bam::ls J"-""T Da, 

Ptti"''. Total 

Crude To1al Rtnne.,, Produt't M()t(tr Petrolc·um 

Cnule OU Oil Nee Rtfinery 0151. I Ga.wline Product 

Production lmporb Input Ca pal'it\' lntporb uppli~d uppli~d 

5.407 392 6.020 (,220 t53 2,616 6.458 

7,035 1,007 8.580 9,840 606 3,969 9,797 

9.637 t,310 tl.750 12,020 1,850 5.185 t4,697 

8.597 4,976 14,020 17,990 I,JSS 6,579 17,05<5 

7,355 5.785 t4.S90 15,570 t,375 7.235 6.98~ 

S.S22 9,021 t6.300 t6.510 t,399 ~.an t9,70t 

5,630 11,510 NA 18,700 2,250 10,690 22,990 

5,330 13,1)(;0 NA 19.800 6,730 t3.770 29,170 

cr~· Information Admimstration/Annuul Encl'tt)' ~C\'1 w 2001 

En<:l' •y lnfonntuion AdL~u ni:d.taltOti!An u.u l 12~' Oudool: 2003 

As the decades passed and exploration and production activities covered much of 

the US. the need to gather ever larger quantities of~ and then to transport 

1ha1 oil1o refineries necessila1ed 1he cons1ruC1ion of a large ne1work of c"ode oil 

pipel ines. bo1h iorficld ga1hcring sys1cms and large 1ransmission lines. Thai trend 

con1inued 1hrough much of1he 1wentie1h oen1ury. peaking in 1970 al 9.4 million 

barrels of production per day in the Lower 48 states. Thereafter the trend 

reversed as lhe produc1ion in most inland domes1ic fields declined and by 2002 

Lower 48 produo1ion had decreased 10 4.8 million barrels per day As a resuh, 1he 

1hroughpu1s in galhering sys1ems and 1ransmission lines declined. soone1imes 10 

the point where volumes would no longer support operations. and lines were shut 

down. aba11doned or converted 10 o1her uses. Despi1e the decline in inland 

11 
97 


615RABIN17.eps

production, the demand for cn•de oil to feed US refineries and ultimately for the 

consumption of refined petroleum products continued to grow. Those needs. 

along with improved technology, enCO\araged production in new areas. A primary 

growth area has been in ever-deeper waters in the Gulf of Mexico, with offshore 

production reaching 1.9 million barrels per day in 2001. In addition, the amoum 

of foreign crude imponed into the US has continued to grow. reaching 9.1 million 

barrels per day in 2002. In the decade altead it can be expected that inland 

production. both in the lower-48 and in Alaska. will continue to decline. to approxi.natcly I million barrels pef day in 2025. 8Jld that the dcep-watef Gull' of 

Me.xico and foreign sources will provide increasing volumes of crude oil, 2.2 

million barrels per day and 13.0 million barrels per day. respectively. Canadian 

crude impons are expected to grow modestly from 2000 to 2025 (i.e. 300 

thousand barrels per day) while Persian Gulf and Me.xicanNenezuelan impons 

are expected to increase 2 million barrels per day and 1.6 million barrels per day, 

respectively. 

Exhibit 3. Selected Crude Oil Trunkline Systems 

...,01 C1rwtdlan Crude 

•. -Of OtiWf lmportt 

.._,om • Oom.ltlc Origin 

$1;111t ....... ..._, ""--AciiOiinStnW!I 

torOrft""CM1"'blfA.OOe.t 

12 
98 


615RABIN18.eps

11tcconsumption of petroleum products has always been " tidely disseminated and 

refineries tended to be widely distributed and sized to mee.t regional needs. For 

most of the first half of the t\ventieth celliUIY the vast majority of products were 

transponed from refineries in discrete parcels. by trucks, rail cars. barges and 

tankers. During Wo~d War lithe fi rst large transmission pipelines for petroleum 

products were constructed, primarily from the Gulf Coast to the Mid-Atlantic 

States. driven by the vulnerability of coastal tankers to Gemtan lJ..boars.. Since 

the war. the network of product pipelines has continued to grow. The outlook is fOf produvt dcma•ld, which wa~ about 20 million barrels pcf day in 2002. to 

continue to incre-ase. albeit at ditlCrent rates in diOCrent pans of the country, 

reaching almost 30 million barrels per day in 2025. The trend for domestic 

refining capacity is to become more concentrated in regional centers and for 

impons of petroleum products to grow, reaching 6.7 million barrels per day in 

202S versus 1.4 million barrels per day in 2002. Those factors, including declines 

in inland crude production and the number of small inland refiners, will o\~ de 

the ilnpetus for expanding the network of product pipelines. 

Exhibit 4, Major Refined Product Pipelines 

~ rom .. l-low J>ipelincs Mnke lhc Oil Markel Worl...'" Alkgro Energy Oroup.IA."CC.'mber 2(1()1 

13 
99 


615RABIN19.eps

111e CIISIQJIICI'J' and 

lite commO<Iitif!S in 

the pipeliue indus11y 

/l(u:e t:h<mgcd ow!r 

time. 

71u! pipeline 

business tu.k1pts to 

the products and 

desfinatious that are 

in demand. 

Commerdal (IIN.I 

militmy goals are 

occommodtlletl in 

this dh-erse se,·tor. 

The Customers 

11te circumstances of the petrochemical industry are similar to the refining 

industry. As planes increased in size it bccal'ne more attractive co invest in 

pipelines to transport raw materials to the planrs and in other pipelines to transpon 

the products. especially intcnnediate products (i.e. those needing additional 

processing into consumer products), to other plants for further processing. 

Since the inception of the domestic petroleum industry in the late ~ cenl\,11')' 

crude oil producers and refiners have been the primary customers of the liquid 

pipeline industry. Along the way the marketers of refined petroleum products 

also became a larger factor. Then. the rapid gro"'h oftl>c petrochemical industry 

during the second half of the twentieth century created a significant demand for 

pipelines to transpol1 feed stocks to chemical plants and products from those 

plants to other plams for further processing. Jn recent decades other panies have 

become shippers on the pipelines, including the military. many of the airlines, 

crude and product imponers and traders of crude and petroleum products. 

For much of the history of pipelines it was not unusual that some son of 

affiliation existed between a pipeline and its shippers. The pipeline might have 

been organized as a separate entity. but its owner was often a parent that also had 

interests in the production, rcJin.i ng and ma1·keting segments or by a railroad 

(Buckeye and Santa Fe Pacific). Under those circumstances it was common for a 

pipeline to work closely with its atTaliated producer. refiner and marketer to 

develop pipeline infrastructure to move crude oil to a market, possibly an 

affiliated refinery; to trnnsport crude, whether or not produced by an affiliate, to a 

refinery~ and to move products to a market that might or might not be affiliated, 

A similar situation, but to a lesser extent, existed with petrochemicals inasmuch as 

the degree of integration of chemicals with petroleum has been considerably less 

than the integration of petroleum segments alone. 

During the past few decades the extent of integrntion of pipelines with other 

segments of the petroleum indusuy has diminished consilerably. Increasingly. 

and now to a large extent, the integrated companies demand tl13t each segment, 

including pipeline trnns-ponation. stand on its own economically. That has caused 

the production. refining and marketing arms of integrated companies to look to 

non-afliliated transponation opponuniries and for the aOiliated pipeline 

companies to increasingly look to third pa11y, nor>afliliated business. An 

increasing numbe-r of joint ventures, with venture panners including a ,v;de 

variety of participants, have diminished tlte situations where it is either practical 

orccono1nical for a pipeline to deal solely with an affiliate. In addition. there arc 

now many more independent participants in every segment of the petroleum 

indusny and competition in all areas has forced every pan of the indusuy. carrier 

and shipper alike, to seck the most economical transportation system. Still 

anocher factor in diminishing inter-affiliate business is 1he number of mergers in 

recent years, which resulted in restructurings that included tl>edisposal ofpipeli11e 

14 
100 


615RABIN20.eps

Mm~tJ ials 'vrrkd 

"ia pipeline are 

uumerous (md 

''llrietl. Operations 

l~tn•e become more 

sc>phisticmed due 

tolhetn'er· 

increasing 1111mher 

of commodities 

lrlliM7HJrled 

"'i!l)'day. 

assets co chird-pa11ies for regulatory and financial reasons. There is every 

indication that the trend of diminished affiliated business will continue and may 

well accelerate. 

The Commodities 

The list of materials cranspo11ed by liquids pipelines is long. h sca11s with crude 

oil of many different grades and types. covers many refined petroleum products. including motor gasoline., aviation fuels, kerosene. diesel and heating oil a•1d a 

variety ofruel oils. 3Jld a multiplicity ofintemlcdiate refinery screams. The lise 

also includes narural gas liquids (NGls), with propane being an example, and 

pcltOChemical feedstocks and produces. The NGLs and pecrochemicalmacerials 

are cypically referred to as highly volatile liquids (HVLs) since they are gases at 

atmospheric temperature and pressure. but liquids at the pressures in a pipeline. 

Other materials transported by liquids pipelines include carbon dioxide. coal 

slurry and anhydrous ammonia and some lines operated by liquid pipeline 

companies carry still Olher materials such as nitrogen. oxygen and hydrogen. In a 

few instances a liquids company may transport small quantities of natural gas, but 

narural gas pipeline companies handle virtually all transmission a1td dislribution 

of natural gas. l11e number of discrete commodities is increased many-fold by 

gradations in the base commodity. for example. 1here are numerous grades of 

crude oil as a result of the differing prope11ies such as sulfur and density and 

many grades of motor gasoline reflecting a wide variety of specifications. As an 

example. one Midwest pipeline operator reports carrying 34 grades of gasoline 

during a typical 10 day pipeline cycle. Large product pipelines have 30 co 50 

products moving regularly and as many as 100 to 120 grades that move 

occasionally. 

Cmde oil may be produced domestically. ei1he-r on-shore or in coastal waters. or 

may be imponed from a foreign source. For the most pan, until the second half of 

the twentieth century. the crude oil processed in US refineries was produced and 

gathered at inland fields in the US. The early production was predominantly in 

Pennsylvania and Ohio, bu1 over time there were large finds in East 1"exas, West 

Texas, Oklahoma. louisiana, California, Alaska and the Rocky Mountains and 

smaller discoveries elsewhere, lt became economical to invest in pipeline 

infrastn1cture to gather t11e crude and chen transport it to refineries as the 

production in any region increased. 

As demand for petroleum produces grew during World War II, and especially in 

tlle decades thereafier, tripling between 1950 and 2000, e consumption of crude 

grew from 6.0 million barrels per day in 1950 co 16 2 million barrels per day in 

2002. During the decades of the 1940s, 1950s and I %0s domestic production 

increased co meet chose needs, helped by controls on crude oil impo11s because 

economics favored foreign crude. By the early 1970s crude production was 

essentially at capac,ity at about 9 million barrels per day and controls were 

eliminated. During that pose-war period, liquid pipelines rapidly increased their 

1!> 
101 


615RABIN21.eps

1950 

1960 

1970 

1980 

1990 

2000 

2010 

2025 

capacity to transport crude to the growing refining centers. particularly on the 

Texas/Louisiana Gulf Coast. 

Exhibit 5. 

Crude Oil Production and Oil Well Productivity 1950 to 2025 

Thouli:flnd lliUTels per OU\' 

GEOGRAPHIC Produdn A'rng LOCATION SIT£ T OTAL \V('Ib Pr·v \JutliVt 

J8SIItf('S Aht~kit On.!. O~ Ofr ~ IT00us3nds (B31Tcl~: 

19SO 5.~07 0 NA NA 5,4(), NA NA 

(9(,0 7,0)4 2 6,716 319 7,03 591 II 

1970 9,408 229 8.060 t.S77 9,63 531 18.1 

t980 6,980 1,617 7,562 t,034 8,59 54, IS 

1990 5,582 1,773 6,273 1,082 7.35. 00: 12. 

2000 4.851 910 4,049 1,773 5,82 SJ 10. 

2010 4.980 <HO J,ISO 2.470 S.63t NA NA 

2025 4,160 1.170 ),ISO 2.180 5.33( NA NA 

; I'IC'l)' lnfonnulion Admini&1to,lJOZ"Annunl Encr@:y ~e.,.icw 2001 

•nci'JlY lnf(lnnation Adminislnttion!AruiU&I Enco1y Outlook 2003 

ExhibitS. Petroleum Imports and Exports 1950 to 2025 

Th()U!C3nd ll11rrc ~ per 0.'1}1 

CRUDE PETROLEUM PRODUCTS l'OTAL 

lm )()rl5 ElJ.OrlS N•• lmroru Exporh Ntl lmporu Ex )(IriS N<l 

~87 9S 392 363 2t0 153 8SO :l<>S S4S 

1.015 8 1.007 799 193 606 1,815 202 1.61) 

t,324 14 1.310 2.095 245 1.850 3,419 259 3,161 

5.263 287 4.976 I.<H6 258 1.388 6.999 544 6.365 

5.894 109 5.785 2.l23 748 1.375 8.018 857 7,161 

9,07 1 so 9,021 3~9 990 t,399 11,'159 1,().10 10,419 

11,580 60 11.510 3,250 1,000 2,250 14,830 1,060 13,760 

13.110 so 13.060 7.830 1.100 6.730 20.940 I. ISO 19.790 

Encrs> lnfon ioo Admini..Cru1ioniAMual Enc TS) .. ' Rc,iew 2001 

EnC'tll~ lnfornltltion Admi nistrahonJAn ut~ l Enci'Q'Y Outlook 2003 

111e logistics of crude supply began to change in the 1970s and the trends that 

emerged have continued until now. Inland production has been essentially 

maximized and most inland fields are in significant decline if not depleted. 

Domestic exploration efforts have moved to more remote locations. ~th notable 

success on dtc North Slope or Alaska in the late I %0s and early 1970s and into 

ever deeper water in the Gulf of Mexico, with recert activity in 5,000 feet to 

I 0,000 feet or water. There were other successes. such as heavy crude oil 

expansion in California, along the California coast and in the Rockies, but none 

matched Alaska or the Gulf or Mexico. The result or an increasing total demand 

ror crude and a decreasing ability to supply that need domestically has caused 

16 
102 


615RABIN22.eps

Growlhin 

Canlulian 

'·rude imporls 

77re 7itms 

Alaskan 

Pipellne 

System 

(rAPS) is 800 

milesloug.. 

cntde impons to grow very significantly, reaching more than 9 million barrels per 

day, and accounting for some 60% of all crude oil refined in the US. 

111e impact on pipelines of the changes in crude supply has been significant. 

Gathering activities have diminished in vinually all inland areas.. with systems 

being s.hut-down and abandoned, trucking replacing the usc of pipelines, the 

remaining gathering systems be:ing co1'60iidated and ownership changing with the 

integrated and mher larger companies being replaced with smaller, more spcc.ialimd 8Jld onc:n llCW <:om panics. At the $81llC time Ill MY of the crude 

transmission lines from the inland fields are no longer needed and are being taken 

out of service. to be converted to other uses or abandoned. Often. those that 

remain are operating at considerably less than capacity. 

While those changes were occurring in inland areas, other developments were 

taking place. Cntde impons, largely to Gulf Coast, Atlantic Coast and upper Mid 

West refineries, grew rapidly. Marine terminals grew and relatively high-capacity 

but short pipelines were put in place to handle the coastal impons, while new and 

expanded transmission lines were buih to move approximately J.8 million barrels 

per day of Canadian cn•de to the US, especially to the upper Midwest. The 

pressure to move Canadian crude further south in the US triggered several of the 

largest pipeline expansions (i.e. Express, Enbridge. etc.) of the late t990s and 

early 2000s. 

During the 1970s a large transponation system. involving the 800 mile, 48" 

diameter Trans Alaska Pi pelitte System (TAPS) and a fleet of oceat>going 

tankers, was established to move North Slope crude to market. mostly on the 

West Coas~ but forthe 1980s and much of the 1990s to Gulf and Atlantic coast 

refineries as well. With the decline in Alaska production (fAPS throughput is 

currently at about t million barrels per day versus a peak in e.xcess of2 MB/D in 

1988) the West Coast is onoe again seeing an increase in crude importS (750 

thousand barrels per day). 

111e other major crude logistics development that is underway and is likely to 

continue throughom the next decade is the gathering and transponation of deep. 

water Gulf ofMCJ<ico production. For example, a !53-mile line of 18" and 20" 

pipe in the Western Gulf was completed in 2000 that transports crude gathered in 

5000 feet of water. Even larger systems in the Cemral Gulf, such as Caesar and 

Proteus, are under development currently in even deeper water. The demands for 

capital and technology enhancements are significant and government policy is 

encouraging the St0"1h in a safe and e<:onomic way. 

1/ 
103 


615RABIN23.eps

Exhibit 7. Refineries: Input & Output and Number, 1950 to 2025 

Million Oarrcls per O:t'. 

L>;Ptrr OITrPtrr REf iNERIES 

Crut.le Motor Oblillate Utilit11111ion 

Oil Tolal Cl!Uolinc Fud Oil Tot11l NumhC'r CltUIC:it:r (% 

1950 5 74 G.O 2.7J I.CJ9 6.01 320 6.22 92.5 

1960 8.07 8.5! 4. 13 1..82 8.73 30') 9.84 85.1( 

1970 10 .87 11 7~ >.70 2.4> 12. 11 216 12.02 92.6< 

1980 13.48 14.0 6.49 2.66 IJ.6 319 17.99 75.4 

1990 IHI 14 ;S 696 292 15.27 205 1557 S7.1C 

2000 IS.Q7 163 7.95 3.58 17.24 158 16.51 92.6C 

2010 17.14 NA NA NA NA NA 18.70 93.2( 

2025 18 39 NA NA NA NA N1\ 19.80 946( 

En<.-rg_y lnfOftllation Admmislmtion/Annual EDL·1-gy Rc\•ic" 2001 

Ent'f2\' ln fotm~llbl'l Admm1strluion/Annunl En<:rll't' Ou1look 2003 

11troughout the early decades ofrhe petroleum indusuy. refined products were 

manufaclured at small to medium sized refineries located relatively close 10 the 

product markets. In 1ha1 environmen1 there was a heavy reliance on rail, barge, 

small coastal tankers and some limited scope pipeline systems to move the 

products from refineries to distribution tem1inals and then to use trucks to move 

the produc1 1he final step to service s1a1ions or to 1he cus1omer direedy. Duri11g 

World War II !he combination of growing demand and submarine warfare led 10 

!he developmenl oflarge pipelines to move produc1s 10 the Eas1 Coas1 from d1c 

refining cen1crs 1ha1 were situalcd ncar the large supply of domestic crude along 

the Texas/Louisiana Gulf CoasL After the war, as the economy grew rapidly and 

the demand for producrs, especially motor gasoline. increased there were many 

expansions and additions 1.0 the network of product transmission pipelines. For 

example, the volume of oil moved by pipeline increased 420/o betwee-n 1970 and 

2002. folowever. the need remains fOr truck. and sometimes for rail. transportation 

10 gel produc1s 10 1he consumer. The seemingly ever-increasing demand for 

petroleum products comjnues to provide a need for more capacity in the 

Jransportation system and thai is likely 10 be 1he case imo 1he foreseeable future. 

111e transponation of pearoleum productS also has become more comple:(, 111e 

prolifera1ion of product grades during recenl decades, especially for gasoline. has 

been a complicating factor that required expanding the number of segregations in 

lhc mawial being shipped. There are capacily, cos1and product quali1y 

implications of the multiplicity of grades. When there is sufllcient volume. the 

simplest and least expensive pipeline operation would be a dedicated line, but 

rarely is e produC1 volume large enough. Thus opera1ors reson 10 ba1ching ---

shipping a sequence of discrete producls (or balches). Care musl be taken 10 

maintain isolation between batches and any interface betwee.n successive batches 

mus1 be down-graded (say premium gasoline in10 regular) or reprocessed. 

Sometimes the size of batches can be increased. lowering the transponation cost. 

Hl 
104 


615RABIN24.eps

if more than one shipper is a~oreeablc 10 meeting a common specification (i.e. a 

fungible product). 

ExhibitS. Petroleum Products Supplied by Type 1950 to 2025 

Thous:and BarTds ')Cf' l>ii\' 

Motor m \"tUiatc Rf'!lldullll A.~ lt & Other 

a-~llne Jel Fue-l Fuel Oil Fuel Oil Ro11dOII Products TOtlll 

1950 2,616 NA 1,062 1.517 ISC 1.063 6,4 5~ 

1%0 3.969 371 1.872 1,529 30, 1.754 9.191 

1970 5,185 967 2,540 2,2().1 447 3,721 14,691 

1980 6.579 1.06! 2,86<} 2,508 39<' 3.639 17.0;< 

1990 7,235 1.52l 3.021 1,229 4~3 5,020 16,98, 

2000 &.472 1.72: 3,122 909 52: 4,348 19,701 

2010 10.690 1.90C 4.610 600 Ni\ 5.190 22,99( 

2025 13.770 2,74( 5.870 640 Ni\ 6, 150 29.17( 

Ent.'f1!-Y lnj'onn:tllon Admini:itmlionlAnmwl Encrll)' Review 2001 

Encr !Y lnfonn:tlton AdmmtSirallQn/Annual l~r r Outlook 2003 

Motor gtl.mline 

1i·tviS· 

tJOJ'Iation 

fueL< 

Mo1or gasoline accoun1s for aboul half of • volume of U.S. petroleum products 

consumption (8.8 million barrels per day out of 19.8 million barrels per day total 

in 2002). Once there were typically two or three grades of gasoline differentiated 

by their oc1ane levels and in some pans of the country, panicularly the nonhem 

areas. there were seasonal variations summer versus winter. Today there is a 

multiplicity of grades (as many as 30 to 40 accordi ng 10 a recent survey by the 

American Petroleum I nstirute), some specific to a panicular region, state. counry 

or even locality. Those changes have made pipeline operations more dinicull. 

reduced the effective capaci1y of the existing transportation system. necessirated 

capital invcstmcm and generally raised costs. There seems 10 be no change in this 

trend and, if anything, the proliferation is likely 10 continue. For instance, a 

number of states are prohibiting gasoline containing MBTE and are requiri ng 

cenain specific ethanol blends. 

Other s.ignificant transponation fuels include jet and diesel fuels, accounting for 

more than 25% of 101al product demand in 2002. Whereas aviation gasoline was 

once the predominant aviation fuel and later naphtha·based jet fuel was the 

primary mili tary aviation fuel. they have been s.opereeded by kerosene based jet 

fuel, much of which is transponcd by pipeline for at least pan of its journey to the 

consumer As with gasoline. there are a growing number of grades of these fuels. 

with the advent of a very low sulfur diesel fuel in the near future posing many 

issues and concerns for the pipeline industry. 

11te remainder of the product barrel is eompoised of other fuels, such as kerosene, 

heating oil, and a variety of heavier, higher-sulfur fuels. The lighter fuels (i.e. 

kerosene a11d heating oil) are often transported in batches '"~ th gasoline and other 

transportation fuels. whereas the heavier. dirty fuels. such a.s asphalt and heavy 

fuel oil, are much less compatible with 1he lighter fuels and are usually 

19 
105 


615RABIN25.eps

10./ay:< 

Markeiplace 

demtmds safe 

11'011~7)()1'/0iiQn 

ft>r "cleanfuds. ·· 

agricultural and 

indu.writ1/ sob>ents. 

and mcmy other 

liquids. F.ach 

C011m1od11Y 

requires .skillful 

handlinf(alld 

modern 

equipment. 

transponed in separate pipeline systems. which tend to be of limited scale in tenns 

of size and distance covered. The higher viscosity materials also require special 

handling.. Historically the lighter fuels were called 1'clean fuels". but in recent 

year.; the tenn "clean fuels" has been applied to fuels that have been funhcr 

refined 10 remove impurities, such as sulfur, that will enable them to be ''clean 

burning. 

11te narural gas liquids (NOLs) cover a range of materials. including ethane. propaate. butalle and xturc~ of lhcm. that are gases at atmospheric tempenuvrc 

and pressure, but liquids at the operating pressures in pipelines. P-ropane (or 

liquefied petroleum gas-·· LPG) is a fuel widely used for agrietohural purposes 

and for heating in ruraJ areas and is pipelined when sufficient volumes make it 

economic The other NOLs typically represent by-products from the production 

of crude and natural gas, petrochemical feedstocks and products and intem1ediate 

materia.ls among gas plants associated with natural gas production. refineries and 

chemical plants. In low volumes NOLs are transponed by truck and rail, but a 

pipeline network has developed in the larger production areas, such as East Texas 

and West Texas, along the Texas/louisiana Gulf Coast with its concentration of 

gas plants, refineries and chemical plants and from Canada into Michigan The 

demand for and availability of NGLs. associated with growth in Gulf of Mexico 

cnade and natural gas production and growth in the petrochemical indusuy. provides an outlook for expanded NGL pipeline systems in the year.; ahead. 

The situation with petrochemical feedstocks and products is similar to that of 

NOLs. although there are many materials moved by pipeline that do n04 fall under 

the umbrella ofNGLs. For example. pipelines. particularly along the 

Texas/Lo<oisiana Gulf Coast. transpon ethylene. propylene (both in dilute and 

concentrated forms). butylenes, hexane, benzene, toluene, xylene, butadiene and 

many others, smaller streams. The petrochemical industry has grown rapidly 

during the last several decades and the outlook is for continued expansion as the 

overall economy grows. The need for liquid pipeline additions and expansions 

will grow concurrently. 

There are ()(her, miscellaneous materials carried by liquid pipeline companies. 

such as carbon dioxide (C02) and anhydrous ammonia, and non-liquid mate.rials 

that are transponed. such as nitrogen, oxygen. hydrogen and coal slurry. 

However, the circumstances that create the need for pipeline transponation are 

usually specific. Such situations will undoubtedly continue in the future and 

needs and opportUnities will arise from time to time. but in the aggregate they 

represent a very small activity by the liquid pipeline industry. 
106 


615RABIN26.eps

Regional Considerations 

Another dimension to an understanding of the needs for liquid pipelines is to take 

into account regional factors. Inasmuch as the government established a standard 

nomenclature for regional energy measurement and analysis during World Wa.r n that is still in use. it '"ill be used here. Five Petroleum Administration for 

Defense Districts (or PA DDs) were established. with PADD I covering the 

Arl:.ntit: Scahn::~rd. PADO II ent:nmpl'l.!:.~ ng h~ Mid-\Ves1. PAOO 111 heing Alnng 

the Gulf Coast, PADD LV covering the Rocky Mountains and I' ADD V being 

along the West Coas~ Alaska and Hawaii. Some PADDs are further subdivided, 

such as a nonh and south Atlantic. to better recognize regional differences. 

Exhibit 9. Petroleum Administration for Defense Districts 

PADO S: 

West Coast 

AK, HI 

Petroleum Administration 

for Defense Districts 

PADD4: 

Rockle.s ~f PADOZ: 

MidWest 

ncr~' lnfonnatton Admim:;tmtton.f-()il Mnrkctll~t:Sics ... 

:.!1 
107 


615RABIN27.eps

Exhibit 10. Daily Supply and Disposition of Crude Oil and Petroleum 

Products, 2001 

Crut.lc production 

Crude tmport..;. n1.1 

Crude, net I"CQCiots 

RdinoC'ly mput · crude 

• 10131 

Finashcd pctrolcwn product 

Refinery produclton 

hnt)()ns,nct 

Rcocipts, ncl 

)rodut1~ SlJJ'I>IiOO 

,.housnnd ~UTC s per Dll\' 

PADD I PADD II PADD Ill PADD IV 

~ 

1,47< 

1,49' 

1,87 

1,92· 

1.061 

2,76 

5.721 

45 3.27 28; 

8Sl 

1,99> 

3,30. 

338< 

J,4JC 

89 

4.52 

5,92 

·1,90 

7,27 

7.79 

7. 1 

-~ 

·3.81. 

3.75 

27 

·9· 

5()( 

53 

54 

( 

5. 

59 · 

nc..~y ln(onnation Administratiun1P'"1roleum Suwty Annual 200 1. Volwne I 

PADDV 

1.7& 

74( 

( 

2,5J 

2,79! 

l ,lll!l 

·I Of 

10. 

2,88: 

Exhibit 11. Operational Parameters by PAD District, 2001 

Thousand Jl.t~rn.:l$ ot.T \ 

TOTAL 

5.801 

9,3 1( 

( 

15. 121 

16.381 

16.(;81 

66 

( 

17 481 

PADO I PADD II PADDIII PAOD tV PAOOV 

Produ<'lion ~L 12 OK 188 rx 1,162 WY 157 AK 963 

PA 4 KS 93 LA 287 co 45 CA 714 

wv 3 1\'D ffl 1\'}.ol 186 MO ~ F<"<l 85 otrshoa'¢ Olbe:r I Other 90 Fod 1,536 UT 42 Ober 2 Offsllbl\: 

Other 100 

Tocul 20 458 3.271 2&; 1.764 

t.nn~rie.s 

Numhc:r 16 27 56 16 38 

Cupacitr 1.715 3,591 7.780 572 3.128 

nn r~· Crude" R.tt't'i 1$ 

DonleStic 29 1.689 2. 144 296 1.901 

fOfCI@Ji 1.472 1.613 5.1().1 205 744 

Pspdinc 68 3.287 3,016 -168 1,022 

Ttmker 1.201 0 3,930 0 I,S$4 

llnrg..: 217 I 253 0 )() 

Tt~n e~rs 8 0 3 0 10 

rruck...; 7 14 47 33 23 

Tot'l 1,501 3,302 7,249 SOl 2,64S 

Fncrgy nfom ~Stio" Admitli-;lrnlifln/P<..1r\tlemn SUPI)h Anr1ual 2001. Volume 1 

:a 

TOT AL 

5.801 

153 

16.785 

6.058 

9.139 

7.860 

6.686 

507 

20 

124 

15.197 
108 


615RABIN28.eps

PADIJ!is 

/cx:aied 

along the 

At Iamie 

seaboanl 

PADDII 

t!IIC0!11f){J.S$1!S 

1hc Micl-Wesl. 

While PAOO I was the home of the early American crude production industry. its 

fields are largely depleted. For many years there has been virtually no indigenous 

production (20 thousand barrels per day in 2001) and there is liule likelihood of 

developing any meaningful amount. As a result, its refining industry (16 

refineries with 10% of US capacity), which is concentrated along the coast in 

Virginia. Pennsylvania and New Jersey, relied on domestic cmde transponed by ta•lk~rlarsc y rrom Texas a•ld LouisiMa pon.s \ulti l US crude produccio•l reached 

capacity in 1970. Since then the refineries have lived on an increasingly larger 

diet of foreign cn•de (98% in 2001). directly imported from the North Sea. South 

America, Africa and the Middle East. 

With its large population, !he demand for petroleum products in I' ADD I (5.7 

million barrels per day) exceeds its indigenous refi nery production so products 

must be imported (4.2 million barrels per day). both from I' ADD Ill (Te.'"s and 

Louisiana) and increasingly from foreign sources. From time to time, the 

possibility of adding a major increment of refining capaciry has been studied, but 

the economics were never favorable. Among the faetors were higher East Coast 

construcaion costs, higher landed crude costs (because the Jack of a deep water 

pon led to the use of smaller. more expensive tankers) and the lack of 

downstream infrastructure to deliver product from a central refining bcation. 

The situation in the South Atlantic sub-region differs slightly in that its demand is 

rising faster than in the North and it relies to a greater extent on pipeline imports 

of products from PADD Ill The outlook. especially in the Sou~ east, is lOr 

incrcasill.S product imports from both domestic and foreign sources as the region's 

population grows. The major pipeline systems carrying product from I' ADD Il l 

into PAOD I are Colonial and PJamation for mocor gnsoline, diesel,je1 and 

heating oil and Dixie for propane. A number of older, smaller pipeline systems 

intemal1o PAOD l are used to cany produc1s from coastal refi neries and 

tenninals to interior areas. Systems originating in Providence, Rhode Island; 

Northern New Jersey; and the Philadelphia/Paulsboro, NJ area are examples. 

I' ADD II is comprised of a populous, highly industrialized eastern se<:tion and a 

mo1'e rural. agricultural western section. for a long time indigenous cn1de 

production. supplemented with domestic crude from the northern Rockies and 

from Texas and Oklahoma was sufficient to supply local refineries. Refined 

product demand was met through a combination of output from lhe local 

rclineries and product impOrts. primarily from the south, some by barges up the 

Mississippi River and other by pipeline. In recent decades local crude production 

has diminished considerably (dropping to 600 thousand barrels per day in 2001) 

and West Texas and Oklahoma cnode production is preferentially sent to PADD 

ll. lmponed crude has increased ro feed increased refining capaciry and to offse.t 

declines from other sources. During 2001 1.3 million barrels per day of domestic 
109 


615RABIN29.eps

PADD Ill 

/{)C{Jted along the 

GulfCoa.w. is the 

US refining 

cemer. 

crude and 1.6 million barrels per day of foreign crude entered PADD ll. A 

considerable ponion ofrhe imports originates in Western Canada, but lines such 

as Capline. whiclt connects LOOP (Louisiana Offshore Oil Pon) with the mid· 

west are an important source of crude. Depending upon shon teml supply and 

cost fac1ors.. the mix of impons swings between Canadian sources and cnade that 

was tankered to the Gulf Coast. Inasmuch as refining capacity has remained 

relatively nat with expansions ofT-seuing shut-downs. the need to import 

domestic products has increased to meet growing demand, reaching 900 1hous.and 

ban·els per day in 2001 . 

11te liquid pipeline indusuy has responded to PADD ll's needs by adding crude 

tmnsmission capacity from Western Canada and from PADD Il l and product 

transmission capacity from PADD Ill, The overall crude carrying capacity 

exceeds PADD u·s needs. and in recent years there have been periods when the 

systems from Canada and fTonl the Sooth have had significant spare capacily. 

11te outlook is for a continuation of uncenainty in the mix of crude impons. As 

for products. a number of projects have been completed recently to move more 

products into PADD II from PADD rll. The pace of those expansions and 

additions will depend upon the rate of product growth and whether there is any 

significant funher curtailment of refining capacity within the region (27 refineries 

and 3.6 million barrels per day of capacity in 2001) 

During most oflhe twentieth cemury PADD rn had sufficiem crude production to 

meet the needs of the growing refining centers along the Texas/Louisiana Gulf 

Coast. After inland production reached maxin\\unlevels in the early 1970s, 

funher growth in crude demand was supplied from foreign impons. With the 

decline of inland production and the shift to foreign crude it made sense to 

transpon much of the remaining inland production to PADD 11. mosdy througlt 

Cushing, Oklahoma. and to increase foreign impons for 1he coastal refineries 

rather than to incur the cost of hauling that crude to the Mid-West. Another factor 

in the level ofimpons has been the amount of production in the Gulf of Mexico. 

Industry moved into coastal waters after World War II, but fomterly sizable, nearshore volumes had declined significantly by the 1980s as fields were depleted. 

With advances in technology, exploration and production in deeper waters 

accelerated during the 1980s and 1990s and that substantial production ( 1.5 

million barrels per day in 2001) has slowed the growth in crude impons. Because 

the product output ofPADD Ill's refineries exceeds region demands there are 

essentially no product impons to the region and substantial product movements 

out of the region (3.8 million barrels per day in 200l), largely by pipeline. to the 

EaSt Coast (PADD I) and the Mid-West (PADD II). 

In view of the very large inland crude production in PADD Ill through much of 

the 20tb century (3.3 million barrels per day in 2001)~ a cnade pipeline system was 

established to transpon that crude to the large coastal refining centers in Texas 

and Louisiana and to 1ranspon 1he excess 10 PADD ll. As produc1ion declined 

and much of what remained went to the Mid-West. the need for the capacity 

:.14 
110 


615RABIN30.eps

J>ADD/Vis 

/oca~edailile 

Rocky 

Moumaius. 

decreased, forcing e abandonment of lines and encouraging auemplS to conven 

the remaining capacity to other uses. 111ere was a short· lived blip in the 1980s 

when some of the under-utilized capacity was used to move excess Alaska and 

California crudes east from PADD V. For instance. All American Pipeline was 

built for that purpose. However, \\ lh the decline of production in Alaska that 

movement ceased during the 1990s. The process of reducing the crude pipeline 

infrastructure in PAOO Ill is continuing and is the source of many issues and 

uncenainties. These include questions about asset rationalization through s.ale:s to Slllall. i1ldCJ)C1ldCnt operatOI"S, the ag,e or the li 1lCS, the impacts (C1WirOtllllCilt81 8Jld 

other) of using the pipe for other purposes and the growing urbanization of many 

pans of the region. The situation regarding product pipelines is difl'e,·em, in that 

the demand for product movements into PADDs I and 11 continues to increase and 

thus it is a matter of continuing to add capacity in logical, cost~ effective 

increments. The outlook is for that trend to continue 

PADD IV. the Rocky Mountains, is a sparsely populatod and not highly 

industrializod region. As such the local crude production (288 thousand barrels 

per day in 200 I) has tendod to be sufficient to feed the typically small refineries 

( 16 refineries with less ~tan 600 thousand barrels per day capacity) that are 

located to satisfy the widely distributod population In recent years the decline in 

Wyoming crude and the demand growth, panicularly in Billings, Montana-area 

refi neries seiVing the Nonhem area, has been met by modest increases in the 

availabili ty of Canadian crude. Growth in Colorado has largely been met by 

small l1\Cteases in local refini11g capacity and increased movement of refined 

products from the South (PADD lU). 

Given the scope of crude and product movements within PAOD IV the pipelines 

are of modest size and the systems have been changing less than in the other 

PADDs, although there have been a number of recent 0\\11ership changes. An 

exception has been the addition and expansion of crude transmission pipelines 

passing through the nonhero pan of PADD IV that carry crude from Western 

Canada to the Mid-West. While thecltanges taking place in PAOO IV are modest 

in relation to those in other regions. the incre.asing availability of Canadian crude 

and the specter of product impons from the South is a major concern to local 

industry panicipants, especially in ~1e Salt Lake City and Casper. Wyoming areas. 

One 1nanifestation of the competitive situation is the relatively large number of 

cases brought to the FERC involving PADO IV pipeline transponation. 
111 


615RABIN31.eps

PAD!) Vis 

/ocaied along I he 

lfle.<JCoa.<J. 

Alaskacmd 

Hawaii. 

111e rapid and large population increases. the dependence on the automobile and 

the advent of stringent environmental regulations have had a major impact on 

PAOD V, panicularly in California. PADD V has long been home to crude 

production in and around Los Angeles, in State waters towards Santa Barbara and 

to production of heavy crude from large fields in the San Joaquin Valley between 

Los Angeles and San Francisco. In the late 1960s there were substantial finds of 

heavy. high sulf\lf ~n. de i1l federal waters oO'Salltft Bart>ara Md of the giant 

Prudhoe Bay field on the Nonh Slope of Alaska. Through the first half of the 

centul)' local production had been sufficient to meet refining needs. but as 

demand for products outstripped domestic crude availability foreign crude 

impons increased to fill e:<panding refining capaciry. With the advent of 

production in Alaska and the Outer Continemal Shclf(OCS) impons were largely 

eliminated and refining capacity was added in the Pacific Nonhwest That 

capacity was supplied with Alaska cntde and the excess I' ADD V cnrle was 

transponed to PADDs Il l and I via a logistics system oombining marine and 

pipeline segments. By e year 2000 Alaska production had declined to one 

million barrels per day (versus a peak of2. 1 million barrels per day in 1988) and 

OCS production had declined substantially as well (8S thousand barrels per day in 

2001). Thus. the movements to J'AODs Ill and I ceased and foreign impons 

resumed. The high intensity refineries on the West Coast (38 refineries with 3.1 

million barrels per day capacity in 2001) and some product impons have largely 

met the demands for refined productS (2.9 million barrels per day in 2001), which 

are weighted much mo•·e heavily to motor gasc:Mi11e 1han elsewhere in che US. 

From time to time there have also been marine movemertsofproduct w PADD 

V. usually from PADD lll Those 1110\'emcnts, which transh the Panama Canal in 

purpose-built ships, are only ecooomic during periods of price disruption 

Since early in the 20" centul)' there has been a network or crude pipelines in place 

in California. For the most pan. they have been private, proprietal)' lines, unlike 

the common carrier systems in the rest of the US. As refineries expanded and 

new ones were added and as producrion grew the pipeline network expa11ded co 

meet the growing transponation requirements. A relativeJy recent example was 

the construction of the common carrier imra-state Pacific Pipeline to move 

increased San Joaquin Valley (Bakersfield) production to Los Angeles area 

refineries. 

111e discovel)' of oil at Prudhoe Bay in I %9 necessitated creation of a large. 

expensive and rather unique transponation system comprised of the 800 mile, 48" 

diameter pipeline from Alaska's Nonh Slope to a marine tenninal at Valdez, 

Alaska. From Lhere large tankers transpon the crude to refineries, primarily in 

areas near Seattle. San Francisco and los Angeles. During the years when the 

supply exceeded PADD V demand, the excess crude was transponed to PADDs 

Ill and I. Initially the excess moved by lanker around South America, later a 

pipeline was constructed across Panama enabling tanker-pipeline-tanker 
112 


615RABIN32.eps

movements and sti ll later a pipeline was built !'rom tltc San Joaquin Valley to 

West Texas where it connected 10 the e.xisting pipeline infrastrucrure enabling 

Alaska and OCS cnlde to reach the Houston area. 

11te refined products market in I' ADD V has historically operated independently 

ol'the markets elsewhere in the US. Distance and terrain were certainly factors, 

but generally adequate refining capacity. a proportionally greater demand for 

motor fuels and mandates for special grades of gasoJine during recent decades have co.nbincd to djscourage pipeline itlte con ~tiOtlS behV'een PAODs ill Md 

IV and PADD V. Nomtally, the network or pipelines that has developed to move 

refined producrs 10 distribt•tion terminals for dissemination to the ultimate 

consumer is adequate to mee1 West Coast needs. However. the supply/demand 

balance is fairly tight and 1he infrastructure provides only limited flexibiliry to 

accommodate shorHem1 issues. Thus, if a few refineries encounter operating 

p10blems, il'there is a problem in the distribution system (pipeline or other) or if 

prevailing prices jump, there is no quick mechanism for the energy industry to 

respond. The events in Phoenix during the summerof2003 (i.e. price rurrup and 

service station lines as a result of a pipeline outage) illustrate the impact of an 

infrastn•cture problem on supply and price. A few anempts have been made to 

add infrastructure, such as the Longhorn proposal (conversion/reversal of a 

former crude oil trunk line to refined piOducts service) that could move Gull' 

Coast product to Califomia in conjunction with Kinder Morgan's SFPP system, 

but economics., competitors and various local interests have stymied a solution. 

Competition with other Transportation Modes 

While liquids pipelines are the primary workhorse for transponing crude oil and 

refined petrOleum products, tankers, barges. railroads and trucks arc an important 

and. in some instances. an essential element of the transponation system. In 

almost all cases the selection of a transp011ation mode is an economic choice. but 

there are factors that swing the economics to favor one or another alternative. 

The most obvious examples are that imports of crude and prodt.etS. other than 

overland from Canada and Mc.xico. must move by tanker. whereas many locations 

cannot be reached by either tankers or barges. Probably the most significant 

factors in detennining the optimum transponation mode relate to the number and 

location of the sources and des6na1ions of 1he crude and products to be moved 

and the volumes (both average and extremes) among the sources and desti•l3tions. 

At one end of tl1e range. pipelines. because they are capita) intensive and not very 

Oexible, are best suited for high volumes moving from a limited number of 

sources to a limited number of destinations. At the other end of the spectrum. 

trucks are extremely flexible and can extend the range of less fle.xible 

transponation modes. Trucks do n01 impose a large capital requirement. al least 

for low volume movements. but are expensive to operate. Railroads. barges and 

coastal tankers fall between the two extremes. 

'LI 
113 


615RABIN33.eps

Ur>lil the rapid increase in crude imports in the 1970s, tanker transportatioo had 

been utilized to move PADD Il l crude to PADD I, to haul mod"51 amounts of 

specialized foreign ertrde impons (such as Venezuelan asphalt crude) and for the 

coastal movement of petroleum products. Since then tankers have played a key 

role in the system for moving Alaska crude 10 lower-48 refineries and for 

importing foreign cnrde, while the previous uses have diminished or ceased. 

,tere is a modest utilization of bames 10 move crude and a much larger utjliz.atiOtl 10 mo,.rc products i11 ooastaJ ser..-ice and 011 the major river systems. 

During recent years the role of barges, particularly on the river systems, although 

still sig.nificam. has been declining in response 10 environmental and safety 

concerns and co other operating ssues~ such as winter icing, low water limitations, 

flood situations and the e.xpansion of other transponation alternatives. However, 

some areas. such as New England and southern Florida. remain dependent on 

coastal tankers and barges to transpon products. 

Short hauls and sonall-volume point-to-point movements clearly favor the use of 

truck~ especially when many sources or many destinations are involved. Thus. 

the movements of produCts to the conStamers from distribution terminals are 

almost exclusively handled by trucks. h is a common sight to see trucks 

delivering motor gasoline to service stations. heating oil and propane to 

residential and commercial customers and aviation fuels to fixed base operators. 

Also. trucks are a strong competilor of pipelines for gathering crude, especlally as 

fields are depleted and producrion declines. as well as for occasional. low-volume 

movements of miscellaneous crude and petroleum prod"tacts. 

Rail roods tend to serve niche opportunities for moving crude and products. For 

example. there is a unit train operation in California moving heavy San Joaquin 

Valley crude to a refinery in the Los Angeles area and there is a unit train 

operating as part of the Yellowstone product system in Mootana. In addition 

there are numerous movements among gas plants, refineries and petrochemical 

plants or feed stocks and intennediate products as a resull of low and variable 

(sometimes seas01lal) volumes. 

Ownership Structure of the Pipeline Industry 

11le needs for liquid pipelines are diverse and so are the ways in which the 

industry is structured to meet those needs. Pipelines may be independent enlities 

or may be owned, in whole or pa~ by integrated energy companies, by other 

companies in or out of the energy industl)' and by investors. In many instances 

they are owned jointly by a combination of entities. A particular pipeline may be 

organized as a stock corporation, a pannership, a particular fom1 of partnership 

known as a Master Limited Pannership (MLP) or as a Limited liability Contpany 

(LLC). Funhenmore. the owner may not be the operator or a pipeline. While it is 

most common. for an owner or one of the owners, in the case of a joint venture, to 

act as the operator, there are instances when an independent. third pany operates 
114 


615RABIN34.eps

11w role of 

lllleJ:,'l'ated 

Cmnpanics 

the line on behalf of the owner(s). The way in which a pipeline is owned and 

structured is a function of many factors, including the purpose of the pipeline. the 

complexity of dte cask, historical considerations, legislative and regulatory 

constraints. the abil ity to raise capital and a necessity to manage a wide variety of 

risks 

11te way a pipeline company is structured must consider the pu1·pose of the 

system. In its simplest form a pipeline may move a single materia) from one source lO one destinatio•l over a distaJlce as sho11 as a rnilc or less, Of as lOllS as a 

thousand or more miles, and it might operate in a single state or cross numerous 

state boundaries. or it might be located in federal waters and not in any state. 

Examples include lines carrying crude oil from one production platform to 

another in the Gulf of Mexico. crude oil from one marine terminal to one refinery, 

jet fuel from one refinery or tenninal to one airpon., fuel oil from one terminal to 

one power plant or petrochemicals from one plant to another, Beyond those 

simplest fomts the complexity ean become considerable. There can be many 

sources and a single destination (such as crude gathering), a single source and 

many destination (such as a products line serving a single refinery and a number 

of end markets) and networi<s that i11c1ude many sources and ma•1y destinations. 

And whatever the physical layout of the pipeline, it may carry a single product or 

many discre1e products/grades and it may carry nlateria1 for 011e or for many 

shippers. 

In the early years of the petroleum industry most pipe.lines were part of integrated 

companies, whether established by a crude p1·oducer needing to transpOit its crude 

to a market or by a refiner needing a reliable supply of feedstock for its refinery. 

But as the energy industry has grown and diversified. as new entrants have been 

established and as special situations have arisen the extent of integrated 

ownership has diminished to the point that only about one-third of liquid pipelines 

are part of integrated enterprises today_ Along the way independent companies 

have been established whose sole business is pipe.line ua.nsponation and related 

services. Also, Other interes1s such as pension funds, private investors 

(individually or collectively in funds) and corporations in other businesses, such 

as electric utilities needing fuel for their power plants. have assumed ownership of 

pipelines. The effect of integrated ownership has also diminished greatly during 

the last ten 10 twenty years as financial and other pressures have caused the 

remaining integrated enel'g:y companies to demand that eve.y segment of1heir 

company stand on its own. Thus, the pipelines owned by integrated companies 

look co third pany business as essemial to their well· being and 1he integrated 

owner ships on whatever pipeline will provide the best service at the bcs1 price. 

Joim ownership of pipelines is increasingly common as a means co manage 

business risks. 10 achieve economies of scale, to obtain sutliciem capital for large. 

risky projects and to enhance t11e abiliry to establish new pipelines in the face of 

increasing difficulties in obcaining pennies and ocher approvals. The way in 
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615RABIN35.eps

.Jomt Vemure 

Umll,·id1.ul 

Joim 

lntere.ws 

Stock 

Corpora/ion 

PtutueJ·s.hips, 

Limited 

PllrJJu.:r~hips 

l.imited Liahilily 

Companies 

Mli.Wer Limited 

Parmer.•ihips 

which joint owner$ hip is implemented takes many fonns. boch as 10 the SU\ICture 

of the venture and as to its management. 

A joint venture (JV) may look similar to a non-JV (i.e. a corporation, parmership, 

MLP or LLC), bUl have multiple owners and be managed as though it were a 

single entity. Alternatively. it could be organized as an Undividod Joint Interest 

.Q.U!} in which the owners act mgether to build, operate and maintain the pipeline, 

but each owner retains responsibility for its share of the common facility, 

petiorming acti..,itics &uch as pos•ing separalc 1arifis, hatldli•lS its ow1l tev-enuc 

accounting and so forth. A UJI has been dcscribod as muhiplcstraws, each 

ownod by a diiTerem pany, within a single, larger s1raw A well known e.'ample 

of a UJI is TAPS (the Trans Alaska Pipeline System). ln that case five owners ·· 

BP, ConocoPhillips, ExxonMobil, Unocal and Koch •• own varying shares. post 

their own tariffs and compete for shippers. but together have a contract with 

Alyeska Pipeline Service Company to operate the line for their mutual benefit. 

By agreement there is an Owners Comminee to resolve any conflicts in operating 

instn•ctions to the contract operator. JVs also can be managod directly by 

employees of the venture (as is case for Colonial and Explorer) or by one owner 

serving as the operator under contract to the JV (examples of which include 

Plantation. Yellowstone, West Shore and Wolverine). In the Iauer situation it is 

usual that d1e ownership agreement provide a mechanism for the operator 10 

resign and for the owners to replace an operator. 

During much of the twentieth century the most common form of structuring a 

pipeline. venture, whether singly or multiply owned. was a stock corporation. 

Such entities are straight fonvard with the owner(s) holding the stock of the 

vemure, but the entity raises capital itself to build facilities.. receives revenues for 

its services. incurs costs to operate. pays taxes and provides dividends to its 

owners to the extent it is profitable. 

Along 1he way pannerships began 10 be utilized as a means to minimize tax 

liability, but they canied the risk that every panner assumed the business 

liabilities of the pipeline. As states allowed the crealion of limited pannerships, 

that fonn came into use as a means of shielding the limited panners from the 

business liabilities and concemrating those risks with a managing general panner 

who typically ownod only a small lraction (say I%) of the venture. During the 

las! ten years or so, states have allowed the creation of Limitod Liability 

Companies (LLCs) 10 allow ta.xation benefits and liability protections in an entity 

that resembles a corporation. Although only recently available the LLC fonn is 

gaining wide usage. 

Master limited Partnerships (MLPs) are a variation of the partnership form ~>at 

IVaS creatod by the 1986 Ta.x Refonn Act and are limited to the development, 

production and transportation of natural resources. ln addition to the tax and 

liability benefits of lirnitod pannerships. MLJ>s have great utility for raising 

capital because units (e.g. the analog of corporate shares) trade on stock 
116 


615RABIN36.eps

;\Jergers. Acquisitions, 

and 

dNe.~stmems 

are chtmglng 

the ownt!rship 

struc111re of the 

pif~CiiiiC 

industry. 

exchanges and are generally available to public investors, large and small. The 

use of MLPs has increased rapidly during the past 15 years and can be expected to 

increase funher. Even large,. diversified energy companies such as Sun and 

Williams reorganized their pipelines into MLPs. Other examples ofMLPs are 

Buckeye, Kaneb. TEPPCO. Kinder Morgan. Plains All American and Enterprise. 

11te owner and the operator of a pipeline need not be the same entity although it is 

most common for an owner to serve as tl1e operator. That is especially true when thefe is a si•l.Sic ow·ncr. but less so for a joint venture. The ope.-ating ernity has 

the day.ro--day responsibility to control, monitor and maintain the pipeline. In 

addition there are many responsibilities of the operator ,·elating to reporting. 

regulatory comp~ance, community interfaces and emergency response. l11ere are 

several reasons for an owner to contract with a third pany to operate its pipeline. 

l11e most common ones involve joint ventures where no owner wishes to accept 

total liabiliry given their panial ownership or where the owners do not want one 

owner to serve as operator and thereby receive any perceived advantages. Other 

reasons for using a contract operator include insufficient operating capability 

within the owner organization and attempts to achieve economies of scale by 

utilizing an entity wich other operations. 

11te strucnore of the US pipeline industry has been changins signilicantly in recent 

years as mergers. acquisitions, divestments and other transactions have occurred. 

'111e reasons for the changes go beyond evolving corporate forms and changes in 

the transponation needs of the industry's customers. Rather the drivers have been 

the need to manage costs. the des-ire to achieve economies of scale and to reduce a wide variety of business risks, the necessity of complying with regulatol)' 

requirements and the hope of realizing new business opportunities. Several 

examples arc cited in tlte following paragraphs. 

As throughputs have declined in inland crude gathering systems and in certain 

crude transmission pipelines. the owners of those systems and lines have 

auempted to find new customers to replace the declining business. When that has 

not been successful they have merged with competing systems tO establish a 

viable successor. have sold to an e;~is ting player or to a new entrant. have sold or 

mmsferred the asset to a new entity to be used for some other purpose or. as a last 

resort. have shut down and abandoned the facilities. 

11tc approval of many large corporate mergers has been conditioned by the FTC 

and the states on divestiture ofo'Arnership in one or more pipelines. such as 

Mobil's interests in Colonial and TAPS and Shell's interest in Plamation. 

'111e advent ofMLPs has provided the capital1o acquire existing assets with a goal 

of improving profir.ability and providing an attractive return to a wide ownership 

population. As a result, ~1LP • share of pipeline assets has grown significantly. 

1hrough acquisition and by reorganizing pipelines into M-LPs. Shifts in the 

transp011ation business. combined with needs to reallocale capital among 

:$1 
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615RABIN37.eps

Operational 

imegrily: 

afocu,\·o, 

sofety, 

(!/H'irOIIIUeJI((J/ 

proteL'Iitm aud 

reliable 

lhrnup}umt, 

competing uses and changing assessmeniS of the risks associated with pipeline 

transportation have led companies to divest assets that are no longer viewed as 

core co their business and vvhere it is assessed that the asset may be wonh more to 

someone else than to the e.xisting owner. 

The changes in the pipeline industry arc increasing the lc,•cl of competition and 

spurring efficiency improvements. Those changes are encouraging and likely 10 

continue. but there are issues that flow from them. For the most pan they relate to a dimi•lishin,g I'()IC fof the well established. w-ell financed and largcf ofganiutions 

that have been the back bone of the industry for a century. In their place are new 

entrants that need to establish ~1eir positions and build the organizations and 

capabilities. 

Operational Factors 

Operational Integrity 

Safe, environmentally sound and reliable operations. variously called Operations 

Integrity or Operatio11al Excelle11ce, is absolutely critical to the liquid pipeli11e 

industry. Throughout its history the industry has worked at making its operations 

safer for iiS employees and its neighbors and more environmentally friendly. And 

the long tcnn trends show progress and demonstrate that pipelines arc the safest 

means of moving petroleum. Despite that progress. there have been safety and 

environmC$1181 incidents and the industry's stake.holders have not been satisfied 

with the rate ofimprovemen1. In ··ccognition that operations can and must be 

improved more rapidly the leadership of the pipeline industry has put in place 

volumary initiatives to accelerate the pace The objective is to strive to elimi•late 

all incidents. That will be extremely challenging, and may never be fully realized, 

but industry-wide data covering the past few years demonstrate a step-cha•tge in 

the rate of progress. 

·ne key to achieving fundamental. long.temt. sustainable improvements in 

operations integrity is to employ so.md management systems that span the full 

spectrum of the desi~ construction, operation and maintenance of pipelines. It 

is essential that those systems be clear, understandable and practicable so that 

everyone having a role in their implementation knows the objectives of the 

system. what resources are available. who is responsible for perfomting the 

various activities. how performance will be measured to assure the objectives are 

being met and how the process can be improved as time passes. lessons are 

learned and technology improves. The coverage must be broad. including 

employees and cornractors alike, extending from the most junior employee to the 

most senior manager and covering the processes that directly relate to operations 

and maintenance. the supponing ones, such as procuremem. record keeping and 

human resources. as well as those associated with planning, risk assessment and 

risk mirigation. During the past dozen years or so. a number of management 

systems have been developed to achieve operations integrity. The systems go by 
118 


615RABIN38.eps

Pipeline 

PerJarmm1ce 

1i·t,cking System 

many names and have minor variations. but they contain the same fundamentals. 

Many companies voluntarily have adopred one or another system and even those 

that have not done so are employing many of the features of the approach since an 

increasing number of regulatory requirements mandate such systems. at least in 

some areas of operations and maintenance. 

Measureme111 is an essemial element of management systems. For a long time 

most pipeline companies have measured various operationaJ parameters and the federal and Slate regulatory bodjes with jufisdictjon over the i•ldust•Y have 

mandated certain reponing requirements. Historically, there were gaps and 

inconsistencies in what was measured a11d rep011ed and the thresholds for 

reporting were sometimes high relative to the perfonnance that the industry and 

rhe public ex peered. For example, unrilrhe beginning of2002 rhe Office of 

Pipeline Safery (OPS) had an incident reporting threshold of 50 barrels spilled 

unless damage exceeded 550,000 or there was an injury, faraliry. fire or e.'plosion. 

The liquid pipeline industry initiated a voluntary program efl'ective January I. 

1999 to gather data on spills of any amount to water and other spills greater than 5 

gallons. There were concerns as to what the daut would show· aro hO\V it might 

be misused to the disadvantage of the industry. Nonetheless, two·t1ti rds of the 

industry panicipated. As with any new initiative it took a few data gathering 

cycles 10 clarify definitions, 10 standardize forms and lo ger lhc process working 

smoothly. Although rhe data are nor publicly available, OPS has kepi abreast of 

developments and used rhe industry experience ro enhance irs repOning systems 

eiTccrive in early 2002. 

Ex hibit 12 

Oil Spill f/istory: All lmprovi11g Record, /968-200/ 

First five years, Annl Avg: 377 spills; 366,000 barrels Last five years, Annl Avg: 154 spills; 144 .• 000 barrels 

~O T--------------------------------- ~ 

.~ ~-

~- ~t lm ~~ ~~ m~ 

.!1 100 100 .!1 

0 

-Spill Volume ('000 bbl) -o- Number of Splits - S·Year Avg Spill VOlume 

Source· RSPA 7000-1 
119 


615RABIN39.eps

Post-September II 

security concerns 

m·e <tlop priori1y. 

Since 1%8, the year that data collection began, the spill record of the liquid 

pipeline industry has improved substantially, with the amount of oil spilled 

decreasing about 600/o. During the five years 1968 to 1972 the industry averaged 

377 incidents reponable to OI'S per year and an annual spill volume of366 

Otousand barrels. During the most recent five year period ( 1997 to 200 I), the 

nUinber of reponable average annual incidents dropped to 154 and the spill 

volume decJined to 144 thousand barrels annually. The improvement continues as 2000 was a r~ord IO\\' ycaf and 2001 5\ll)>aSSed dun (128 i•lcidems.. 97thousalld 

barrels). The available data show that pipelines have a be11er safety record than 

other modes of transponatioot and that outside force damage was the most 

important cause of large spills. lmernaJ and extemaJ corrosion were a major 

cause of smaller spills, often on pipeline company propeny. All spill causes are 

being vigorously pursued to fUrther improve perfoml8nce. 

Security 

The 1ragic e\rents of September I I. 200 l uiggered a re-examination of the 

security of the oil pipeline network. which is the core of the US petroleum 

transJ)Of"tation system. As Stich. ia is a val'-•able national assetlhat must be 

protected. Fonunately pipelines are physically robust with the vast majority of 

the system underground and less vulnerable than aboveground facilities. And 

pipeline operators have been managing the integrity. safety and security oftheir 

systems for many years. The historical efforts have been enhanced ( I) by ready 

cooperation with the federal government to identify, for preparedness purposes, 

those pipeline lacilities that are critical to the nation; (2) by cooperatively 

developing security guidance ("Guidelines for Developing and Implementing 

Se<:urity Plans for Petroleum Pipelines" ... APL July 2002): and (3) by 

responding 10 the federal government's guidance for security contingency 

planning. 

By April I, 2003 operators of95% of the oil pipeline infrastructure had certified 

to the US Depanment ofTransponation their compliance \\~th the contingency 

planning guidelines. Shonly thereafter the Office of Pipeline Safety began to 

conduct verification checks to validate the cenifications. In addition, pipeline 

operators are conduCting and will continue to conduct vulnerability assessments 

of critical pipeline facilities as the federal government and the industry develop a 

be11er understanding of the terrorist threats and capabilities. Operators have taken 

numerous steps. in many forms to enhance security and will continue to work 

closely with tb.l Office of Pipeline Safety and the Depanment of Homeland 

Security to take prudent and practical actions. including monitoring threat 

information, analyzing pipeline vuJnerabilitles and implementing practicaJ and 

reasonable protective measures. 
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615RABIN40.eps

Right:.- of-Way 

are a crilictt! 

feature of 

pltmuiog. 

OJJCI'<IIing and 

maimaininJ!the 

PlfJCilnes. 

Acquiring (t /Ught 

of Way 

Rights-of-Way 

Pipelines physically reside in Rights of Way, which are sometimes owned by the 

pipeline owner, but more often are used under the terms of an agreement with a 

private landowner or a permit from a public landholder. During the early years of 

the indusuy, obtaining rights of way was relatively straightforward and the 

agreements tended to be simple documents. As the industry has matured the 

issues associated with rights of way have multiplied and there are many examples of contentious. emotional and protracted battles stemming from anempts to 

acquire new rights of way or to utilize existing ones. The outlook is for 1he 

situation to grow ever more difficult, given che increas.ing urbanization of the US. 

heightening concerns about environmental and sa~ y matters, an increasing goal 

of e.xtracaing monerary value for use of1he land and a growing unwillingness to 

site industrial type facilities in many areas. 

Today. a well·written pipeline ag_reemenl or permit will address many terms, 

starring wi1h a description of the physicaJ easement. including i1s width. Other 

items include duration. renewal. f~ rights oflhe pipeline company to access the 

easemem and rights of the landov/ner, restrictions on use of the easemen1 by both 

parties. the number and size of lines, materials that may be transported. rights for 

expansion (number of lines, size of lines), communications among parr.ies, 

abandonment (delinitiCM> and responsibilities), and more. Older agreements ofien 

did not contemplate many of the issues and, as one or another situation has arisen. 

have resulted in expensive, time~consuming arguments and frequently in 

litigation. Modem agreements that deal with the range oftenns and COI1ditiOI1S 

and more clearly spell out the restrictions on dte parties tend to raise the right of 

way cost 

A liquid pipeline desiring to invest in a new line has a number of options for 

acquiring a right of way. Whichever appo·oach is pumoed, an analysis of the 

alternative routes and the issues associated with each is the starting point Once a 

lead route has been selected the pipeline has the option of buying the right of way 

in fee, in which case the company would become the landowner and maintain fUll 

control. That could be expensive and often impossible. Alternatively the pipeline 

can approach the landowners along the proposed right of way and negotiate 

voluntary agreements for easements. lfthat fails, and the proposed pipeline "ill 

be a common carrier. the pipeline company may be able to resort to using its right 

of eminent domain that is spelled out in the statutes of ahe pa11.iCt1lar state. 

Increasingly. using rights of eminent domain leads to time consuming and 

expensive litigation, but often the project may move forward before all of the cost 

issues are resolved. In view of the difficuhy and e.xpense of acquiring rights of 

way there are examples in highly developed ~.as, such as Houston, of pipeline 

corridors being established and set aside for future construction of lines. 11te 

initiative may originate with a pipeline company or it may be promoced by a local 

jurisdiction. 
121 


615RABIN41.eps

11lis discussion has focused on private landowners, but the pennitting process for 

the use of public lands has many similar features. Under certain circumstances. 

both public and private, it may be necessary to conduct an environmental impact 

review, assessment or study as spelled out under NEPA (National Environmental 

Policy Act of t969) which adds comple.,ity, time and cost to the process. 

Both for existing a•ld new rights of way there are cominuing responsibilities to 

maintain dte rights of way and to comply with the provisions of the agreements. Operaticms and .najntc•lancc n~quifc kecpi•lS lhc casement clear (periodic 

mowing. side trimming of trees. etc.) inspecting it with some frequency 

(surveillance flights.. traversing the route, etc.), inspecting and n1aimaining the 

line and any associated facilities. such as cathodic protection. valves and meters, 

and dealing with any encroachments that may occur. When restrictjons in the 

agreements on usc of the easement by the landowner have not been rigorously 

enforced it may become necessary to remove structures (i.e. buildings. sheds., 

fences, ete.). 11lat ean create considerable animosity between the pipeline and the 

landowner. 

As the pipeline indusuy sarives to reduce operational incidents, increasing 

atlention has been focused on rights of way. Historical analyses show that the 

leadi•tg cause of the more severe incidems have been impac1s sustained by the 

pipe. whether caused by the landowner or by someone, such as a utility company 

or contractor. operating on behalf of the landowner. Thus. ever more stringent 

processes. such as emphasis on a "call before you dig" process and increased 

surveillance. are being employed. furthermore, in the event of an incident. •lO 

matter t11e cause. the safety of neighbors increases the fiuthe.r from the pipeline 

lhey are located. Thus, some initiatives associated with land use restrictions are 

beginning to establish minimum setbacks from pipelines. In a more urbanized 

environment these may be needed. but they raise issues of contlicring la11d use 

and can be contentious. 

Capacity Management 

Historically there has been sufficient pipeline capacity in the US to meet shippers' 

needs. whether lbr mo,~ng crude oil to market, providing feedsrock to refineries 

and petrochemical plants or transponing products from those refineries and plants 

to consumers. However. from time to time. situations arise. such as 1he s1an·up of 

new facilities (e.g. a new production lield or a new refinery), !lJ'0\\1h in aggregate 

demand, and shon·tenn penurbations or emergencies (e.g. weather, pipeline 

outages, other supply disntptions) tltat call for steps 10 increase capaci1y. These 

are becoming more frequent, especially in son1e geographic areas such as the 

Mid· West and West Coast. 

In many cases tltere are steps tltat can be taken to squeeze more capacity out of an 

existing sys1em. Examples include raising the ope.ra1ing pressure on a line when 

it is safe to do so by adding or modifying the cx.isting pumps, by adjusting the 
122 


615RABIN42.eps

Prorationmg and 

C{IJXtCily 

en/I(IIICI!IIU.!JII 

schedule for moving multiple products on a panicular line to take advantage of 

the specific confi!,.ruration of1he line and its related facilities, by reducing down .. 

time through improvements in operations and maintenance practices and by 

employing relatively new technology, such as Drag Reducing Agent (ORA) that 

reduces friction in the pipe, thereby allowing a higher rate of flow. If such steps 

arc insufficicnt, presumably the.re arc business opportunities for one or another 

company to expand existing capacity or to add new capacily. It is always possible 

to build a new, large pipeline~ but sometimes there are less costly opportunities. s.uch as utili ~:.i lS a line that had previously bcc•l in some other service &1ld 

convening it to meet the new need, or swapping two lines to better match the 

physical capacity of the pipes with the needs of the respective shippers or 

removing locaJ bottlenecks if most of t11e route would have sufficient capacity to 

meet the new situation. 

During periods \\ilen there is insufticient ca1>aciry to meet the transportation 

needs of all shippers, established pipelines rely on provisions in their tariffs to 

prorate the available capacity among their shippers. Typically the existing 

capacity is shared in a way that renects the historical pa«em of shipments by the 

ditTerem shippers as well as their current needs and provides some cor1sideration 

for new shippers nol having an his10rical base. Usually a pipeline company will 

do everything possible to maximize the capacity available in the short tenn to 

avoid having to prorate capacity and to minimize the length of time prorationing 

is in eft"ect. Available steps include deferring scheduled maintenance if the risks 

of doing so are reasonable, temporarily running spare equipment or running it 

harder. and increasing temporary staOi ng to expedite other short-term 

opportunities. Such steps apply in many situations, but depending upon the 

specifics there may be otl>cr opportunities that apply during supply disn1ptions. 

For example, if the problem is associated \\~th a pipeline outage there are usua.lly 

steps thai can be taken to e.~pedite the repair and rhe reaum of the facility to 

service. Needless to say, in any of these situations. good communications. 

coordination and COOI>eration among all of the interested panies and no~ 

discriminatory solutions are essential. 

Maintaining Product Quality 

In the early years of the liquid pipeline industry the product quality emphasis was 

on avoiding any gross contamination of the materiaJ being transported. By the 

middle part of the twentieth century advances in the internal combustion engines 

for automobiles and the increasing use of airplanes raised the importance of 

maintaining product quality, especially in some of the grades being shipped. 

Higher-octane gasoline. a,;ation gasoline and later kerosene-type jet fuel required 

considerable care to avoid contamination. Then. in th.e years after \:Vorld Warn, 

the proliferation of special fuels. driven primarily by efTons to improve the 

environment, and the need to segregate some refinery and petrochemical plant 

feedstocks and intermediate products increased the challenge of maintaining 

product quality. 

'J/ 
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615RABIN43.eps

(i·ude Oils (md 

qualify b(mks 

Feeds1ock 10 NGI. 

{l'ltclionators and 

pelrochemlcal 

pltml~ 

PrcxhtCis and 

hatching 

segregctliou 

In the ear1y part of the 201,. Century there was little distinction among 1he varioo:s 

crude oils. As the se<~rces of crude diven;ified. so did the characteristics of the 

oil. Early on some crude oils were good sources of lubricants and others were 

light and sweet (i.e. low sulfur) and used 10 make a variety of fuel products. As 

production expanded westward, crude oils were produced that had large variations 

in sulfur. metals content and density (called gravity) and occasionally in some 

other characteristic. Since higher sulti..1r, heavier crude oils generally had a lower 

value. COOl mingling dHicrcnt pcs of crude oils i1l a pip¢1i nc carried a11 CGO•lomic 

penalty to some shippers. One solution to preserve the relative value of the crude 

oils being rransponed is 10 maintain segregations by crude oil type .. butrharrakes 

more facilities and pipeline capacity. raises t11e transportation cost and is not 

always practical. Another approach is 10 impose a quality bank, whereby the 

shipper of the poorer quality crude pays some money into the quality bank and tl1e 

shipper of the higher quality crude receives a payment to compensate for the 

degradation of its crude. Typically the pipeline establishes the quality bank in its 

tariO: handles the accounting and uses some simple measure. such as sulfur level 

or gravity level alone or in combination. as the basis for the payments and 

\Vithdrawals. In these s.i1Ualions the pipeline operator is merely the banker or 

escrow agent for the shippers of the dinering crude qualities. 

Although the quantities involved are considerably smaller, feedstock 10 NGL 

fractionators and petrochemical plants face analogous issues and solmjons to 

those faced by crude oil. Because there will be tunher processing after 

transpo11ing the raw materials there is a costly option of segregati11g the feeds or 

of commingling feeds whose quality varies and imposing a quality bank to 

compensate the shippers for the quality gained and lost during shipment. 

Producas. whether from refineries or perrochemical plantS, must have their 

charac1eristics maintained and cannot be commingled as is frequently done with 

crude oil. An exception is that a transmission pipeline may establish 

specifications for a fungible material, say regular gasoline, and batches from more 

than one shipper may be consolidated into a single fungible batch 10 be moved so 

long as the tendered material meets the minimum specifications. Commingling of 

fungible product thereby Iowen; the cost of rransponation. In a few cases the 

volumes being transponed are large enough, the distances are shon enough or the 

specifications are so rigorous that dedi cared lines can or must be used. usually ar a 

significant cost. Fortunately. in most ins-tances it is possible to batch the products, 

that is to say. carry multiple products in series in a single pipeline. Doing so 

requires additi:>nal fc1cilities. which may i1ltludc ta11ks) pumps) meters a11d 

analyzen;, at tl1e origin, destination and possibly at intermediate points. Close 

auention to scheduling the batches and good communications among the carrier 

and the shippers are essential. Good pipeline operations will minimize the mixing 

between successive batches. Depending upon the spec.ifications of adjacent 

barches it may be possible to downgrade rhe interface between two batches into a 

succeeding lower quality material (such as premitlnl g_a soline intO TCgt1lar 
124 


615RABIN44.eps

gasoline), btl! in other cases it will tx; necessary to segregate ~>e interface, called 

transmix, and to arrange for it to be reprocessed. 

Maintaining tl>e integrity of the quality of product being shipped, whetl>er it 

moves in batches or in dedicated systems.. can be influenced by many operational 

factors. Facilities must be maintained to avoid leaks across closed valves where 

different materials are in dte lines on either side of the valve. Care must be 1aken 

in operations to establish the proper interconnections (i.e. lineups) within tank farms a11d tennillals w·hen •noviog prodl•Cts in aald out or taHkase. to be sure that 

other or off· spec materials, such as water and transmix. do not enter a batch of 

good material. Quality is maintained by proper sampling and analysis (in a 

product quality laboratory or via an ifloo line analyzer) at various points in the 

transpona1ion system. In some cases the product quality requirements are so 

stringent that the only way to assure their integrity is to isolate the system from all 

other materials. 

Exhibit 13 

Typical Sequence of Petroleum Products 

Flow through a Pipeline 

I Compatible Interfaces 

Field Operations 

n Transmix (Interface Material Which u Must Be Reprocessed) 

Good field operations, which are critical to the safe, environlllentally sound and 

reliable operation of a pipeline system and which may have significant impacls on 

maintaining product quality and operating cost. CQver a wide range of activities. 

For reasons of brevity the discussion will be limited to a few areas. including 

gauging and calibration., equipment and facility maintenance. inspection and 

survcillance and emergency preparation. 
125 


615RABIN45.eps

Me(L';uremelll 

;\tl(lilllen<mce 

Sur\.V!illmJCe 

PreparatioiiS 

[or 

emergencies 

Meas.,remcnt of the material in the custody of a pipeline company, whether in the 

process of being transponed or in a rank awaiting further acrion. is important to 

the carTier and to its shippers. both for commercial and operational reasons., such 

as remote and automatic leak detection. Installing. maintajning and calibrating 

appropriate flow me1ers and tank gauges are essential and require regular 

activities. Usually tanks ean be gauged remotely. but it is customal)' for field 

personnel to manually gauge tanks at least Ollce a moEtth. In-line flow meters can 

often be read remotely, bu1 it is common 10 require that me1ers be read manually as one,l as daily and sometimes for individual ba!chcs -w·hich may require multiple 

readings a day. Calibrating (or proving) meters can sometimes be done 

automatically for high volume situations, but more olien there is a schedule based 

on throughput and tlte necessity to make temporal)' connections of a portable 

prover. 

Equipment and facility maintenance involves routinely inspecting and checking 

equipment, conducting scheduled activities to prevent failures and unplanned 

shutdowns and making repairs after inspections and breakdowns. Activities 

include using scraper pigs to remove the buildup of paraffin on the inside of crude 

pipelines, lubricating pumps. val ves and other equipment: periodically running 

equipment that would otherwise be idle; and using cathodic protection. paint 

systems and other coatings to proH!CI facilities.. Normally there is a large amouru 

of electrical gear associated with pipeline operations that must be routinely 

inspected and majntained and an increasing utilization of electronics that requires 

routine maintenance. upgrading and trouble-shOOting. 

Field surveillance of a pipeline covers a range of activities, conducted with 

diiTerent frequencies. to assure the integrity of the operation and to identify steps 

to prevent future failures. A common type of suiVeillance, aerial patrols every 

few days or weeks. is designed to spot leaks, encroachments on the right of way 

or activities off the right of way that have potential to impactrhe pipeline. 

Normally the pilot has a means to communicate with ground personnel so prompt 

action may be taken if the situation requires a <tuick response. Other types of 

surveillance. typically conducted less frequently. include personnel walking or 

riding along tl1e right of way to gain an up·close view of conditions on the ground 

and the equipment, close inteiVal suiVeys to ascertain the effectiveness ofche 

cathodic protection system and inspections of waterway crossings. whether the 

crossing is by a pipeline bridge or a pipe laying on the bonom of the waterway or 

buried beneath the bon om or the water. 

Preparation for emergencies includes maintaining and testing equipment used to 

recognize and deal with unexpected and undesirable sicuations and conducting 

drills to familiarize field personnel with response plans and their roles in promptly 

and effectively dealing wi1h emergency situations. Equipment for monitoring 1he 

pipeline and ancillary facilities include sensors to spot high temperatures and 

pressures, flames. releases of hydrocarbon vapors, high levels in tanks and 

imbalances between the volume of material entering a line and that leaving the 

4U 
126 


615RABIN46.eps

Dutiestmd 

structure Wlr)' 

Plpeliues hm·'f! 

moved from 

manua/10 

J'L•mott• 

operations 

Maintenance 

line. Other equipment is in place 10 shutdown and isolate sections of the pipeline. 

tenninals or rank fa rms. under local or remote control or automatically. Drills are 

organized to rehearse steps that would be taken in response to oil spills or to other 

emergency siruations. They frequently involve representatives from federal, state 

and local response organizations. and may be cable-top exercises remote from the 

pipeline or field exercises 1ha1 include the deployment of people and equipment. 

Work For ce 

As with any business. pipeline companies are organized to provide specific 

services to tl1eir customers and to provide the range of activities needed to support 

their mission. Mis.slon-specHic tasks include designing and constructing 

facilities. handling rigln-of-way matters. operating and maintaining the pipelines 

and ancillary equipment. interfacing with the pertinent regulatory bodies and 

conducting commerciaJ activities, such as establishing tariffs and interacting with 

shippers. The support activities cover a wide range of tasks, including technical, 

accouming and legal suppon., planning analysis and reponjng, human resources 

and general management Depending on the size, complexity and philosophy of 

the company, the ways in which che organization is structured and staffed vary 

widely. Some organizations are centralized and others distributed. some rely 

heavily on employees while others out·source many activities, using a high 

proponion of contractors, and some arc leaner than others in I he level of in1emal 

staffing. 

11te way in which pipelines are operated and main1ained has evolved considerably 

over time. In the early years of the induSII)I operations were largely manual and 

there was a need for local oversight and control. so the operations work force was 

distributed lhmughoul lhc pipeline network. Typical field organizations were 

structured along crafl lines.. such as with guagers and operators in operations and 

with gangs, mechanics, elearicians. instnnnem technicians and such in 

ma.intenance. \Vith advarr.es in technology, especially telecommunications.. 

computing and remote sensing and comrol, it is possible 10 "operate" (i.e 

"controt>') most pipe.line networks.. even chose covering facilities across the 

United Stales, from a single control center that can be located vinually anywhere. 

11tose controllers are usually located in rooms tilled with sophisticated consoles 

containing computer screens, TV monitors, and the latest in communications 

technology and employing s1a1e of the art SCAD A (Supervisal)' Control and Data 

Acquisition) systems thai enable the computers and the controllers 10 monitor and 

remotely control facilities (i.e. s1an and stop pumps. open and close valves and 

check operating conditions) regardless of the location of those facilities. 

In some ways the maintenance activities have not changed so much as operations, 

but increased mechani7..ation has somewhat diminished the traditionally manual 

activities, while the equipment and instrumentation (i.e. pumps. motors. valves. 

analyzers. sensors a~tt locaJ controllers) have become much more sophisticated 

and hence require a higher skill se110 maintain. Recognition of the technological 

41 
127 


615RABIN47.eps

Comractor 

use 

Fufllre work 

{orceissue.o; 

advances in operations and maintenance, together with lhe advent and emphasis 

on integrity management systems, caused many pipeline companies to take steps 

to enhance work force training and development. 10 raise perfom1ance standards 

and to periodically assess the quaJitications of the relevant workers. Those 

initiatives recently became industi)'-Wide and mandatory with the adop1ion by the 

Office of Pipeline Safety of !he Operation Qualification (OQ) rule that is being 

impleme,ned natio~wide. 

111c utilizatio•l of contractors to design a.11d build new pipcli1lCS typically itwolvcs 

a high level of contractor utilization, but the role of contractors in operations, 

maintenance and suppon activicies varies \\ dcly among pipeline companies. 

Factors that often support the use of contractors include work that is seasonal or 

highly variable as to the level of eflbrt, tasks !hat are relatively unskilled and with 

a high manual labor content and tasks that require an unusual skill set making it 

hard for a company to develop and maintain an in-house competency. Other 

factors inllueneing the mix of employoos and contractors include the availability 

of suitable contractors locally, the cost of contract personnel, including overhead 

and benefits. whether or not the task is viewed as a core competency that should 

be maimained ~house and any over arching management view on out-sourcing. 

Regardless of the reason for using comractors, the expectations regarding 

competency must remain comparable to those for employees and the OQ rule 

holds the operator responsible for the competency qualifications whether the task 

is be,ing handled by COlli ractors or employees. 

There are a number of worl< force iSStles facing the pipeline industl)', many of 

which are being faced by other industries. As an example, the demographics of 

c employee population are such that a high proponion of the worl< force will 

retire during the next decade and replacing the attrition will be challenging with a 

smaller pool of candidates at the same time that employment standards are rising, 

A somewhat related issue is !he shift from organizing the field work force along 

traditional cratl lines to a more flexible. multi-skill approach. The fom1er tends to 

be less ellicient and more costly, whereas the latter can be more efficient and 

provide more opportunities for individual growth, but needs higher skilled 

individuals and more training. 11te role of unions. particularly intemational 

unions such as I' ACE (Paper, Allied-Industrial, Chemical and Energy Workers 

International Union). in the mix of represented and non-represented employees is 

another issue being faced by the industl)'. And various issues related to employee 

benefits, such as health care and pensions, arc vel)' much on ~~• minds of 

employees and management 

Commu nity Involvement 

'111ere may have been a short period in the early days of the pipeline industl)' 

when the interfaces "ith the public were li mited. but for most of !he history of the 

industry there has been an ever-increasing level of interaction. Today, separate 

from all the reguJatory interactions, there are relations with the owners of1he 

42 
128 


615RABIN48.eps

CmummiicatiQIIS 

property traversed by the pipelines. with neighbors, near and far, with e 

responders (police, fire and others) for drills or if an emergency were to occur and 

with the direct and indirect consumers of the transponation services provided by 

the pipelines. Pipelines increasingly recognize how imponant it is to expend the 

time and eflOn to establish and maintain sound. open communications with the 

various interested publics. Wi th few exceptions there are only minor differences 

in 1he objectives of the industry arld the public. bm the increasing urbanization. 

growing awareness of pipelines and the influence of1he media contribute to an ever heig.1HcllillS of sooiety•s expcecatio•lS of all i•ldustry, not the least of which 

are pipelines. 

l11e leadership of the liquid pipeline indusuy has rerognized the trend and e 

need, noc only to respond, bu1 also to get out in front with communications.. To 

that end the indusuy has initiated and supported various programs to more 

effectively communicate with the public, educating them with regard to pipelines, 

creating forums for dialogs on issues of mutual interest and responding to the 

interests and expectations of the public. The communications methods employed 

vaay v.~dely. including the preparation of written materials that are distributed 

proactively (to right of way owners and neighbors. for example) Ot in response to 

inquiries, the creation of web sites for any interested party to learn more about an 

individual company or the industry (e.g. www.pipeline iOI.co1n) and visits and 

presenlations to many subsets of the public. Depending on the audience the 

efforts mee1 with va.l)'ing degrees of success. In some cases. the public seems 

disinterested in the communications overtures. In other instances, there can be a 

lot of emotion associated wi1h pipeline isst1es and it is not always possible to 

come 10 a readily satisfying resolution or compromise among the various views. 

Nonetheless. the communication and outreach effort is recognized to be essential 

and must be continued. 

Costs 

The financial performance of pipeline companies is driven by revenue, which is 

closely tied to the volumes being transpo1ted for their shippers, and the costs to 

operate, maintain and upgrade existing lines and to build new ones. And what is 

revenue to a pipeline is an addi1ional cost to the producer to get its crude to 

mall<ct. to the refiner to get feedstock to its refinery and to the marketer to get its 

refined products to the consumer. Consequently, in today·s competitive 

transportation market, shippers (even in integrated energy companies) apply 

considerable pressure on the pipeline companies to keep 1heir tariffs low and the 

shippers back up tlteir demands through commercial (i.e. by using other 

transportation options) and regulatOI)' (i.e. by challenging tariO"s} means. The 

result is that pipeline companies are driven to manage their costs in order to 

attrac1 business and to improve 1heir bottom line. Another factor increasingly 

impac1ing the industry's cost oudook is the need for invesunent and reinvestment 

to meet a variety of needs., some arising from shippers. some from legislative and 

regulatory requirements and some from public demands. 

43 
129 


615RABIN49.eps

Capital 

lmY!slilu?lll 

For many years 

the single largest 

cost to operate 

and maintai1la 

pipclinc was tbr 

the fuel and 

Eshibill-l. A\crajtt Pi H.' lint Co~ I Dblribullon 1.990 1(1 1.998 

OPERATING EXPENSES CAPITAL EXPENSES 

Ou1sidc set\ i«S 

fuel and power 

~lan<:$ and W3~S 

power needed to SuJ)phcs and expenses 

pump the crud¢ All olhcr 

and products. 

During the last 

decade or so. 

o/, 

24 Pipe oon.!ll"Xtio-n 

21 nep-~pc 

I Olhcr stm1on C(jlnpmcm 

Oillnnk.'l 

J.l PumpinJ equipmc.-nt 

Lute pipe li ng.~ 

All 01hcr 

! ()( 

pipeline Soun:c. t\s.'"()('iation o( Oil Pipe l.incs companies have 

OJ1·sourced 

% 

3 

2( 

I 

many of the services previously handled it>-house as a means 10 become 

more efficient and reduce their total costs. As a result, Outside Services 

was the single largest cost during the 1990s (22%), followed closely by 

Fuel and Power (21%). The cost of employees (Sala,·ies and Wages at 

14%) was ncx~ followed by Supplies and Expenses at9%. The FERC 

definition of"Supplies and Expenses" involves supplies consumed and 

expended in operations and includes expenses of aircraft and vehicle 

operations, traveJ and other emplo)ee e.\:penses and related miscellaneous 

costs. The 01her 34% of operating and maintenance expenses arc 

comprised of a wide range of n1iscellaneous costs. 

11te distribution of expenses associa~ed wi1h capital projects is largely innueneed 

by !he cost of !he pipe and equipment and the cost of constructing the facilities. 

During the 1990s the single largest capital cost eategoty was l'ipe Construction 

(35%). followed by the cost of Line Pipe (20"/o). Other Station Equipment ( 12%). 

Oil Tanks (5%), Pumping Equipment (4%) and Line Pipe Fittings (3%). The 

catcgO<y "All Other" accounted for the remaining 21% and was comprised of a 

large number of smaller categories. 

Unlike the post-war period of the 1950s through the 1970s during which some 

62% of !he presently existing pipeline intrastructure was put in place, !he 1980s 

and 1990s saw relatively small additions. <)0/o and 7%, respectively. 111e reasons 

included the decline of inland crude production which made considerable pipeline 

mileage available for other purposes. 1he ability to debonleneck existing capacity 

and the limited growth of refining capacity. Today there are emerging factors that 

may alter the situation and increase the industry's need to invest. TI1cse include a 

shifting. growing population especially in some areas of the countty. the limited 

remaining ability to achieve incremental capacity growth by redeploying existing 

infrastructure and the extremely capital intensive development of large crude 

reserves in vety deep water (5000' to 10,000') in I he Gulf of Mexico. 01her 

reasons include the issues surroc.mding, the maintenance of older pipelines and the 

44 
130 


615RABIN50.eps

Aurae/in~ 

Sl!tficie/11 Cllpltlll Jo 

mee1 hwestmenl and n.dnw!.o;lnu.ml 

needs 

need to replace some portion or those systems, as well as the need to respond to 

the heightened public expectation.s of the industl)' that are renected in legislative 

and regulatory requirements, inc.luding the development and implementation of 

expensive, cutting--edge technology. 

The ability of the pipeline industry to aurnct suflicient capital to meet its 

invesunent and reinvestment needs will be strongly influenced by the bahlllCe of 

risk and reward perceived by pocemial investors. \\'hereas in 1he decades after 

World War U the latgc. oficn i•nesratcd. co•llpa•lies stepp<Xll•P to meet obvious 

needs, such as investing S8 Billion to build the Trans Alaska Pipeline System, 

teday many things are different l11e integrated companies are much less of a 

factor in the pipeline industry and even for those that remain, the ability of a 

pipeline aftiliate to obtain capital is more challenging. as every project needs 10 

stand on its own and compete with expensive, high return exploration and 

production inve$tments. Concurrently. the sources of capiral have become much 

more diverse. E.xamples include eon1panies not in the energy industry, public and 

private funds and small, individual investors who buy units in Master Limited 

Pannerships. The ability co tap those sot1rces requires a clear understanding of 1he 

rewards (i.e. the returns) and the risks. 

111e rewards include a steady, long term cash flow and an acceptable retlJ'n, 

especially for those entities with a lower cost of capital. And. although there are 

segments of the industry that have been comractjng and restructuring. the ootlook 

is for substantial growth in order to meet the rising energy needs of the country. 

On 1he other side of the balance the changing nature of the risks facing the 

industry "ill make it more diflicuh to attract capital. Some business risks have 

existed since the inception of the indusuy and will continue. Examples relate to 

the cost and schedule for e.•ecuting projects, the impact of operational upsets and 

the effects or competition on volumes and revenues. Risks that may prove to be 

more impon.anr factors in the future involve the difficohies of obtaining pem1its 

and rights-of-way, operations in more difficult envirooments (such as deep water 

Gulf of Mexico). the extreme design and operating requirements that may be 

imposed on operators and the difticuhy of specifying and applying new 

technologies. 1'here are other risks that also influence the ability to raise capital. 

Perhaps ~1c most important for a pi peline (including its owners, oflioers and 

employees) is the ever-increasing liability that flows from any sort of opcratillg 

problem having a safety or environmental impact. In our titig,ious society the 

implications of an incident are enormous and will color investment decisions. 

legislative and Regulatory Impacts 

Since 1906 when Congress passed the Hepburn Act, oil pipelines have been 

declared to be common carriers and have been Stbjcct to the provisions ofthc 

Interstate Commerce Act of 1887, which had applied previously only to railroads. 

Congress' action responded to the publi c outrage resulting from John D. 

4!> 
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615RABIN51.eps

Rockefeller's Standard Oil gaining control of9QO/o of the refining industry and 

800/o oft he oil transportation business and employing a variety of anr}.competitive 

practices. The Interstate Commerce Commission (ICC) was responsible for 

regulating the oil pipelines. including rates and charges. terms of service, the fonn 

and coment ofrarifTs. accounting, reponing and limits on the disclosure of shipper 

information. bu1 not the eonstntction and abandonment of pipelines. sales and 

leases of pipeline assets- non-transponation services and securities tra•tsactions. 

With the exception of some pipeline cases in 19 14, the ICC was relatively 

i•lact.ive with reg.atd to oil pipelines until the 1940s. t\JllOilS the more sign.iticaJll 

regulatol)' actions thereafter were the Atlantic Refining Consent Decree in 194 1 

(which limited the dividends that a pipeline s.•bsidiary CO<Jid lawfully pay 10 its 

parent, thereby etl"ectively limiting pipeline rates ofreiUm), the ICC Valuation 

Methodology during the 1940s (which detem1ined aSS<!t values for recovery 

throogh rates) and d1e Williams Pipe Line and TAPS proceedings of the 1970s 

(both of which challenged existing rate methodologies). 

Economic Oversight 

In 1977, the Depanment of Energy Act created the Federal Energy Regulatory 

Commission (FERC) a.nd transferred responsibility for oil pipelines to I'ERC from 

d1e ICC. The DOE Act specified that the interstate rransponation of oil by 

common carrier pipeline was 10 be regulated by the FERC, there.by excluding 

anhydrous ammonia, C0 2. water and a variety of other materials which are 

regulated economically by otrer agencies or are not regulated as to rates. During 

the early years ofFERC's oversight, its regulatory effons were quite limited. 

Then in 1985 FERC issued Opinion No. I 54· B. which set a new cost-based 

mechanism and in 1988, in a case involving Buckeye, FERC introduced the 

ahema1ive of marke1 based nues for sit\lations ln which a pipeline could 

demonstrate a lack of market power and thus be pem1ined to charge markel·based 

rates. 8ucthe time and cost of proceedings under each of these me1hodologies 

was significant 

Congress, by enacting the Energy Policy Act of 1992, altered the regulatory 

landscape by mandating that the FERC create a simplified and generally 

applicable rate methodology. The Act deemed most existing and unchallenged 

rates just and reasonable. which is known as 1he "grandfathering·· provision. Late 

in 1993 FERC responded by proposing an inde.xing approach thot was adopted in 

1994, h utilized an index that was the Producers Price Index for Finished Goods 

less one percent (i.e. PPI ·I%). The chosen index methodology was effective 

initially for five years and was subsequcnlly extended for a second five year 

period. 111at extension was challenged. largely because the cumulative index 

(3.5% from 1/ 1/95 to 7/ 1/02) lagged actual cost increases. The U.S. C0t1n of 

Appeals for the DC Circuit vacated d1e e.xtension and on February 20, 2003 FERC 

announced that rates would be indexed using the new PPI index (without the 

minus one percent) for the five year period 2001 to 2005. The index allows 

46 
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615RABIN52.eps

Commou 

carriage 

pipelines to increase rates up to the index eeilins, largely without risk of 

challenge. 

111e notion of a common carrier flows from common law and subjects to 

regulation pri vate propeny chat is .. afl'ected with the public imerest". A common 

canier has cenain obligations: to provide prompt and safe services. to be strictly 

liable for injuries. to avoid undue discriminatio•l or preferences among shippe.rs 

and to charge reasonable (i.e. not excessive) rates. The public also has 

obligatiOfiS: to provide a fair rctunl to the eaffier and to ann the carrier with the 

right of eminent domain. And there are limits on the canier•s obligations, 

including: no requirement 10 continue in service and no requirement to expand. 

although a pipeline must treat shippers fairly if capacity is constrained. 

While the indexing methodology has been the primary rate making mechanism 

since the mid· J 990s. there are alternatives. The 154·B cost of service approach 

dating from 1985, market based rates and negotiated rates are all being utilized 

currently. The underlying requirement is that the rates must be just and 

reasonable, but there are many details and fine points that apply to each of the 

methodologies. ·n1ese include the requirement that the service mus1 strictly 

confonn to provisions of the tariff (i.e. prorationing of capacity. demurrage, 

odoriuuion. storage. handling, loading/unloading. blending. etc.) While undue 

discrimination is prohibited, some forms of discrimination. especially Lhose aimed 

at responding to competitive pressures are allowed. so long as they are not 

"undue". These include prOpOnional rate discounts. volume incentive discounts 

and favo•·able treaunent for signatories of throughput and deficiency agreements. 

Through or joint rates also are allowed. 

This discussion has centered on interstate rate making, which applies to about 

SO% of US oil pipeline mileage and volumes transponed. The other, intrastate 

movements may be regulated by the respecti,•e states (often by a public utility 

commission. but some1imes with a different name. such as the Railroad 

Commission in Texas and • Regulatory Commission of Alaska) and most state 

stau.ues provide for generally similar approaches to economic regulation. A11 

issue that sometimes arises involves decisions as to when a pipeline is in interstate 

versus lntrastate service. Often the disci net ion is cJear, but not always. 

In addirion to the more global interstate and intrastate issues, there can be sorne 

local economic regulato.y issues, an example of which is franchise fees. In most 

cities utilities that have easements under the streets to distribute water. 

telecommunications. electricity and natural gas to consumers pay franchise fees to 

the city for the right to usc those easentents. Nonnally the fees are paid annually 

and can be substantial. perhaps a percentage of the value of the service being 

distributed. With few exceptions liquid pipelines do not use city streets as rights 

of way. ahhough tl1ere may be numerous crossings of streets, especially as urban 

sprawl increases. ln most places liquid pipelines pay a fee that bears some 

relationship to the costs incurred by the city to grant an initial permit and then to 

4 / 
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615RABIN53.eps

administer it thereafter. However, in recent years, as t1tc revenue needs of cities 

have increased. many have tried to impose franchise fees. Litigation has ensued 

and for che most part the liquid pipelines have prevailed. The situa1ion in 

California is difl'"erent in that a system of franchise fees imposed on oil pipelines 

has been in place for many years. 

Envir onmental Pr otection 

11te pipeline industry must comply with a wide variety of enviro1tmental 

regulations, so1ne of which direcLiy affeet new and existing facilities, while others 

represent an indirect impact because the regulations relate to the materials being 

transported. The Environmemal Prote<:tion Agency (EPA) has the largest role in 

such regulation, but many other federal. state and local agencies are involved. 

some of which establish standards while others are charged with enforce,nent 

1l1e list of federal agencies includes, in addition to EPA, the Office of Pipeline 

Safety, the Bureau of Land Managemen~ the Army Corps of Engineers, the 

Minerals Managemem Service, the US Fish and Wildlife, 1he US Coast Guard and 

the US Forest!)• Service. 111e number of state agencies is similarly wide-ranging. 

Aside from the challenges of dealing will> a large number of agencies, 1here are 

conflicts and inconsistencies among the requiremems imposed An e..'<ample of an 

area of conflicting jurisdiction is terrninals, which may serve more than one 

function. Most pipeline tetmina1s are under the pucview ofOPS, but most 

marketing tenninals are under the jurisdiction of EPA. Another example is that 

otTshore pipelines come under MMS rather than OPS jurisdiction. Furthem•ore. 

aH too often state and local agencies are not consistent with thejr fcderaJ 

counterpans and there arc state-to--state variations, 

Most direct environmemal regulation deals with releases to the vironment~ 

whether occurring during nom1aJ operations and maintenance accivities, during 

constn1ction or as the result of unplanned incidents. The regulations cover 

releases to air (tank emissions: fugitive emissions from pumps. valves and other 

cc:1uipment; releases occurring when equipment is opened fOr operations and 

maintenance; "spills" of highly volaLile liquids; ere.) and to warer (discharges 

from treating facilities, normal nu>-off from a sire. run-off during construction and 

spills). handling of 1oxic substances and disposal ofhazardOU$ materials. The 

regulatory coverage includes spe<:ifying limits on discharges and mandating 

procedures for obtaining approvals for new and modified facilities and tbr 

establishing and testing plans for handling operational contingencies. With the 

passage of time the regulations are becoming more demanding. tightening 

emissions limits. imposing additional requirements for 01e contingency plans and 

raising 1he e:ICpectations and standards for the operation of pipelines. such as the 

training and qualification of operating and maintenance personnel. 

1l1e indirect environll\ental impaccs relate to Ute increasingly stringe111 

specifications for refined produc1s., such as reducing the perntissible level of 

S<llfur or other compO<Jnds in some fuels (such as low sulfur diesel fuel) and 

4!l 
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615RABIN54.eps

defining 1hc compOsilion of other fuels (e.g. banning MBTE. requiring elhanol 

addilion, limiling RVP, elc.), particularly wilh respec110 moror gasoline, in order 

to meet attainmen1 standards in cenain geographic areas. One impact of these 

new fuel requiremems is simply the challenge of maintaining the integrity of a 

productt recognizing that only a slight amou111 of contamination will render the 

produc1 useless and a candida1e for reprocessing. An01her ou1come is the 

prolifera1ion of grades of a fi•el d1a1 require special care and handling which 

manifests itself in higher operational and maintenance costs and reduced capacity. 

Safety Oversight 

111e gt0\\1h in regulations rela1ed 10 the safely of pipeline operations and 10 1hc 

protection of employees, including contractors., and 10 the neighbors of pipelines 

is quite similar to the 1rend in the environmental area. Once again there are a 

multitude of federal. state and local agencies with an interest and a role and often 

some over·lap with the environmental regulations. With regard ro worker safety 

1he Occupa1ional Safely and Heahh Administralion plays 1he lead role, bu1 o1hers, 

particularly state OSHA organizations are involved Safety of operations is 

primarily 1he responsibili1y of1he Office of Pipeline Safely, bull here arc o1her 

agencies with an active irne•·cst. such as the Minerals Managc•nem Service for 

off..shore pipelines and state agencies such as the Railroad Commission in Texas 

1ha1 peJfonn func1ions analogous 10 1hose of1he OPS. Local en1i1ies. do'"' 10 lhe level of cities and towns become deeply involved in contingency plans and drills 

for all sorts of emergency situations. As in the environmental area there are not 

always consistent standards and approaches among age•lcies and across state 

boundaries. 

Impact of Technology 

11>rougl>oul iiS 100-plus year hislo•y 1he pipeline industry has employed advances 

in 1echnology, implemenling new lechnology developed specifically for pipelines 

as wen as taking advantage of developments in other areas and industries. Since 

the first pipeline was conslnacted. there has been a steady stream of advances 

rclating to construction, operation and maintenance. Along the way there bas 

been an increasing emphasis on new and improved techniques 10 reduce risk and 

there have been applications of1cchnology aimed a1 managing cos1s. 

Constructing a nd Maintaining Pipelines 

Since 1he la1e 1800s, s1eel has been the ma~eria l of choice for vinuaiiX all 

pipelines and tanks. 11le steel induslry evolved rapidly in the late 19 h centUI)' and 

as the steelmaking process improved, so did the quality of the steel. \a.~th 

stronger. tougher materials having fewer impurities and better welding properties 

becoming available. That progress continues with standards for the newest, 

strongcs1 steel ycl developed being adopled in 2002. ll>e mc1hods of convening 

49 
135 


615RABIN55.eps

/mprOl-i:d steel 

am/coatings 

Construction 

steel plate into pipe have also changed a great deal. In the early days furnace bull 

welding and furnace lap welding were used to form the longitudinal weld on a 

section of pipe. There have been a number of improvements and today double 

submerged arc welded pipe is used and has a longitudinaJ weld as strong as the 

pipe itself. In parallel with improved materials and pipe fabrication there has 

been progress in coatings that protect the steel from the environment and enable 

an almost unlimited service life Early coatings of mastic and tar have given way 

to Cusiol')obonded epoxies that provide a tough, corrosion resistant coating. 

Similar advan<:<:s are employed in scorage tanks coli mic corrosion or lhe bouom 

and walls. 

11te methods of constructing pipelines have changed considerably from the early 

years when screwed joints. bolted flanges and other mechanical methOOs were 

used. In 1911 oxy-acetylene girth welds were first employed, but since the 1930s 

electric arc ginh welding has been used. When pipelines are built the welds are 

checked by X-rnys or ullrasonie probes to identify weld defec1s and corrections 

are made before completing the line. Then. before operation, the line is subjected 

to a hydrostatic test at pressures at least 25% higher than the maximum operating 

pressure to identify weak spots. Also, i~ ine electronic sensors may be used to 

identify construction defects. Analogous progress has been made in constructing 

storage tanks and other facilities associated with pipeline operntions. 

11te evolmion of the technology for constructing pipelines can be illustrated best 

by examples or pipelines that have been built in very diflicult locations. A 

particular feat \\QS COitstn•ction of the To-ans Alaska Pipeline System. the 800· 

mile, 48" pipeline from the North Slope of Alaska to the marine terminal at 

Valdez on Prince William Sound that was built during Ote 1970s. Half of the line 

had to be built above· ground as it traverses tundra that remains frozen all year~ the 

right-of-way crosses three mountain ranges and numerous eanhquake fauhs and 

the remote location of much of the line presented cnonnous and unprecedented 

construction challenges. Current examples are the lines being constructed to 

transport crude oil in the deep waters of the Gulf of Mexico, often in excess of 

5,000 feet Since it is impossible for humans to work at S<•ch depths the pipeline 

must be constructed on the surface, lowered to the bonom and then monitored and 

maintai1ted re.motely. Special materials, coatings. equipme.nt and techniques have 

been developed and employed and the quest for new and better approaches 

continues. 

During the past thirty years or so. the technology for inspecting liquid pipelines 

while in-service has advanced considerably. "Sman pigs.'· or internal inspection 

devices, have become more sophisticated with progress in electronics. 

miniaturization and sensor technology. Today there are a variety of devices 

available to identify imperfections in the steel fonning the pipe wall. such as 

surface defects created during fabrication or by corrosion since installation, or the 

existence of cracks that if nor repaired have a potemial 10 lead to failure. Besides 

the internal devices, there arc a large number of ocher tools, applying all so11s of 
136 


615RABIN56.eps

Moniton'ng aud 

comtolliug 

pipelines 

llep<liri11g 

pipelines 

technology. to test and evaluate pipe, tanks, and equipment. Examples include 

ultrasonic and infra. red probes and vibration and gas detection sensors. 

In recent years the technology for monitoring and controlling pipelines, tanks and 

ancillary equipment has evolved rapidly. taking advantage of developments in 

telecommunications and computer technology. Operating conditions, such as now rate, 1emperature and pressure.. as well as the condition of equipment. are 

detennined by sensors that can be read locally and remotely. And control of cquipmem • .such as valves, pumps Md compressofs, call be exercised llHulually, 

locally via programmable logic computers (PLCs) or remotely from sophisticated 

control centers. Most pipeline systems are now moniwred and controlled from 

centrnlized control centers that employ state· of-the-an SCAD A (System Control 

and Data Acquisition) systems. The operators sit at consoles wi1h multiple 

computer screens and a variety of communications capabilities at their finger tips. 

controlling remote facilities and operations, conversing with employees in tJ1e 

field, viewing the status of operations and being assisted by computer programs 

that periodically check operating conditions and alarm when a significant 

deviation is noted. 

Reducing Risk 

The methods for repairing pipelines. tanks and other equipment have advanced. 

taking advantage of technological developments in materials, techniques and 

verification. The results are better quality, longer lasting repairs. 

The o~going development and application of new technology is vitaJ to n.--dueing 

the risks associated with pipeline OJ>erations. The industry is dedicated 10 

systematically eliminating risks and a major contributor is application of results 

from the industry's research and development programs. Virtually all of the 

advances associated with constnacting. operating a1ld maintaining pipelines also 

play a role in managing and reducing risk. It is obvious that bener materials, 

fabrication, inspec io •~ monitoring and control are essential. 

There are other areas that also contribute to reducing risk. For e.xample. research 

into enhanced SUIVeillance techniques continues in hopes of being able to spot 

weak links so as to avoid leaks, as well as to detect spills quickly. before they 

grow and have a large impact on the environment Some ofche leads being 

pursued include beuer computer leak detection algorithms, improved sensors for 

airborne application and satellite imagery. Another are.a of emphasis involves a 

mull~ industry cooperative elTon to reduce incidems caused by excavators 

damaging or puncturing underground lines and other infrastructure such as fiber 

optic cables. Better mapping techniques.., more precise methods for locating lines., 

enhanced ways of marking lines, bener information systems, and even tougher 

pipe are all pans of the solution. 

!>1 
137 


615RABIN57.eps

DRA impi'O\'l'S 

{Jif)eline 

capacity 

Puwt~r 

managc.•nu?ut 

;\t/ailllentmce 

management 

A number of research initiatives arc underway to identify and develop new and 

better approaches. The liquid pipeline industry is leading and funding some of the 

etTons directly, some are jointly funded with the natural gas pipeline industry and 

the government is funding still others. panicularly the Office of Pipeline Safety 

and the Oepanmem of Energy. Several major universities also conduct relevant 

research programs. 

Managing Costs 

Improvements in constructing. operating and maintaining pipelines have a 

positive impact on managing the costs of operating and maimaining pipelines. 

However, there are other initiatives that can also contribute, e.xamples of which 

include cost-effectively increasing capacity. reducing energy consumption and 

finding more economical ways to maintain facilities. 

Seeking low.cost ways of squeezing more capacity out of existing lines has 

always been an objective Systematically removing bottlenecks. raising operating 

pressure by modifying, adding and improving pumps and by looping some line 

sections are examples. However, a different approach represented a large breakthrough in the 1970s when the controlled addition of a small amount of a longchained molecule was found to reduce the friction in a pipe, thus increasing the 

capac.ity in most cases. The additive, known as ORA (Drag Reduc.ing Agent) has 

been employed in many cn1de a1ld produ.:t pipelines and continuing research is 

aimed at finding even more effective ORA compounds, requiring less additive 

and more benefit. 

Power, representing a large cost for pipeline opera1ors. is a major area of 

emphasis. One thrust has been to employ equipment that uses less electricity, 

such as more efficient motors. variable speed motors and other equipment that 

requires less power. A second approach is aimed at managing the consumption of 

power by using sophisticated, computerized monitoring and man~mem systems 

to reduce peak demands and to utilize interruptible supplies. 

Opportunities to lower costs by enhancing maintenance activities cover a wide 

range of e.<amples. from simple to quite sophisticated. At one end of the 

spectrum there are complex, eompu r~based maintenance management systems 

thai 1rack equipmen1 perfonnance and main1enancc history and enable the 

application of preventive maintenance, thereby largely eliminating the costly 

repairs necessitated by breakdowns. An example at the other end of the spectru1n 

relates to the need to maintain pipeline rights.of·way throogh use of improved 

herbicides to manage the growth of vegetation and the use of helicopter mounted 

s:ide .. cuuing tools to trim trees aJong rights-of .. way. Between those examples is a 

long list of other approaches that employ new technology. 
138 


615RABIN58.eps

Summary --- The Outlook 

During the first quarter of1he 2 1" Century tlte demand for refined products will 

grow considerably, crude production will decline overall, ahhough deep-water 

production will increase, and relining ca.paei1y will become more concentrated in 

major coastal retining centers and only grow modestly. And petrochemicals will 

continue to grow rapidly with the economy. 

A short summary of the Energy lnfom18tion Administration's Energy Outlook 

2003. comparing 2025 ";'h 2000 helps 10 put the outlook for liquid pipelines in 

perspective. During that period, refined product demand in the US is expected to 

increase 9.5 million barrels per day (48%), with more than 213 of the increase 

being for transportation fuels (motor gasoline, jet fuel and diesel). Domestic 

crude production is forecast to decline 0.5 million barrels per day (8%). with 

inland production forecast to decrease 900 thousand barrels per day (22"/o) and 

oiTshore production up 400 thousand barrels per day. However, during the period 

offshore production will be up as much as I million barrels per day. Refining 

capacity is expected 10 increase 3 J million barrels per day (20%) despite the 

shutdown of additional smaller, inland refineries that EIA has not specified. The 

combined forecasts ofproduc1 demand. crude production and refining capaciay 

imply crude imports will increase 4.0 million barrels per day (45%) and refined 

product imports will increase 6.3 million barrels per day (380%). 

The overall changes during the first25 years of the 21 " Century will impact the 

regions differently. Most of the decline in inland crude production will take place 

in PADD Il l, ";th some in PADDs II (Oklahoma) and IV. and the growth in 

oA'shore production will be in coastal waters off Texas and Louisiana (PADD Il l). 

Most refining capacity gr0\\1h will be in 1he major coasral refining centers in 

PADD Ill, driven by the decline in inland crude production, the location of the 

demand groW1h and economies of scale favori ng expansions. Thus there will be 

modest increases of Canadian c.rude imports into PADDs II and IV and of other 

cnode into PADO V, but much of the increase in cnode imports will be into I' ADD 

ITL The increase in product impons will be predominantly into the East Coas~ 

especially the mid-Atlantic and New England, and the West Coast. 

l11e implicatiollS for cnode transpoctation are the addition of large, expensive 

pipelines in the Gulf of Mexico, considerable additions of large, short lines 

between marine terminals and coastal refineries to handle crude impon:s: and some 

additions of crude transmission infrastructure along the Texas/Louisiana Gulf 

Coast. Disinvestment in inland gathering and associated crude transmission 

systems and modest asset redeployment and re·invesunent associated with 

transporting domestic and foreign crude in PADDs II , Ill and IV can be 

anticipated. for refined product pipelines, the implications are expansions., in 

some cases significant, to move imponed product from coasral rerminals to inland 

consumption points and expansions of product 1ransmission capacity from the 
139 


615RABIN59.eps

Texas/Louisiana Gulf Coast refining centers to tlte Soutlteast and the Mid- es~ 

perhaps an interconnection to the southern ponion of PADD V (Ari zona and 

southem California) and some movements into the Rocky Mountain region. And 

the refined product situation is likely to be complicated by further changes to tlte 

number and quality of products being transported in response to health and 

environmental requirements_ The network of pipelines providing feedstock and 

canying petrochemical products. especially along the Texas/L0<1isiana Gulf 

Coast, will continue to expand rapidly. The investment in inland pipeline ~apacity. primarily for prodliCl S<:&'Vicc. will replace some existing capacity. bu1 

much of the existing pipeline ne1work will remain in service. Thus. the existing 

infrastructure will continue to age, althO<•glt enhanced inspe<:tion and repair 

techniques. selective upgrades and replacements and more sophisticated 

operational control systems will enable those pipelines to be operated safely. 

11te ability to expand the liquid pipeline network and to update the aging 

infrastructure will be ever more difficult. Increasing urbanization. ever higher 

environmental expectations. and a decreasing tolerance for siting industrial 

facilities will make the acquisition of pipeline rights·of .. way even more 

challenging. Implications will include more e.'pensive projects that take longer to 

develop and that involve a great deal of litigation. 

In conclusion. the O<Jtlook for the liquid pipeline industl)' in the US is for ever 

improving environmental and safety performance, albeit at the same time that tlte 

public's expectations continue to rise rnpidly. with little tolerance for operational 

incidents. An already diverse industry is likely co become even more so, 

especially as it relates 10 the number of product grades, the number of shippers. 

c entl)' of many new caniers, the gro"1h of MLPs and the diminishing role of 

the major, integrated carriers who will continue 10 shift their emphasis toward 

major cransmission lines and compte:<. capital intensive deep-water Gulf of 

Me.xico projects. and away from inland cmde gathering and older. smaller 

systems. Increased compe.tition and a need for cos1 control \\~ II increase the 

imponancc for industry panicipants 10 rely on objcc1ive, impartial decision 

making and will diminish further the need tor ecO<tomic regulation, althO<•gh the 

need for open access and the posting of taritl$ will remain. Issues relating to 

rights of way will become even more co111entious and expensive. 
140 

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 

141 

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. 

142 

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, operatorqualification 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 subVerDate Nov 24 2008 13:13 Jan 03, 2018 Jkt 075679 PO 00000 Frm 00146 Fmt 6633 Sfmt 6601 S:\GPO\DOCS\27960.TXT JACKIE
143 

stantial 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. 

144 

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 

145 

• 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 requirVerDate Nov 24 2008 13:13 Jan 03, 2018 Jkt 075679 PO 00000 Frm 00149 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\27960.TXT JACKIE
146 

ing 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 

147 

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 

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148 

lines. 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? 

149 

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 Congressionallymandated 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 firstresponders 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 

150 

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. 

151 

[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. 

152 

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 mid1950s, 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. 

153 

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 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. 

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. 

154 

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 

155 

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 midto 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 hapVerDate Nov 24 2008 13:13 Jan 03, 2018 Jkt 075679 PO 00000 Frm 00159 Fmt 6633 Sfmt 6601 S:\GPO\DOCS\27960.TXT JACKIE
156 

pen 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—reVerDate Nov 24 2008 13:13 Jan 03, 2018 Jkt 075679 PO 00000 Frm 00160 Fmt 6633 Sfmt 6601 S:\GPO\DOCS\27960.TXT JACKIE
157 

newable 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.] 

(159) 

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 assessVerDate Nov 24 2008 13:13 Jan 03, 2018 Jkt 075679 PO 00000 Frm 00163 Fmt 6601 Sfmt 6621 S:\GPO\DOCS\27960.TXT JACKIE
160 

1OIG Report Number SC–2004–064, ‘‘Actions Taken and Needed for Improving Pipeline Safety,’’ June 14, 2004. 

ments 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. 

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 

Sec. 108 

Require periodic inspection of all offshore and 

navigable waterway natural gas pipeline facilities 

NPRM published and awaiting public comment, final rule expected August 2004 

1992 

Sec. 207 

Require periodic inspection of all offshore and 

navigable waterway hazardous liquid pipeline 

facilities 

NPRM published and awaiting public comment, final rule expected August 2004 

1992 

Sec. 307(b) 

Prepare a report to Congress on a study concerning how to abandon underwater pipelines Report is in the clearance process, report expected July 2004 

1992 

Sec. 109(b) 

Define and regulate natural gas gathering 

lines 

NPRM comments under discussion, supplemental notice expected December 2004 

1992 

Sec. 208(b) 

Define and regulate hazardous liquid gathering lines OPS is coordinating with the states and industry to develop a definition, NPRM expected 

December 2004 

NPRM: Notice of Proposed Rule Makmg 

161 

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 

162 

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 direcVerDate Nov 24 2008 13:13 Jan 03, 2018 Jkt 075679 PO 00000 Frm 00166 Fmt 6601 Sfmt 6621 S:\GPO\DOCS\27960.TXT JACKIE
163 

tors 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, 

164 

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. 

165 

1 49 USC § 60104(c). 

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), publiclyvisible, 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. 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 

166 

2Pipeline 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. 3 Note that GAO did not consider this deterrent effect in its analysis of the effectiveness of 

OPS penalties. 4GAO, op. cit., p. 12. 

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. 

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 

Pipeline/Shell 

1/03 >$5 mill.—Olympic/ 

>$10 mill.—Shell 

> 230,000 gal. of gasoline released, 3 human deaths, over 

100,000 fish killed 

Colonial 

Pipeline 

4/03 $34 mill. 1.45 mill. gal. of oil 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 

Industries, Inc. 

1/00 >$35 mill. Approx. 3 mill. gal. of oil released in 6 states (from 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

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. 

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 

167 

5 Ibid., p.53. 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. 7 Releases from ‘‘unregulated’’ pipelines need not be reported to OPS. 

8Testimony 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. 

‘‘alerted OPS to noncompliant activity at one company, it found the same violation 

2 years later during the next scheduled inspection cycle.’’ 5

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. 

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. 

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 § 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 

168 

country; if implementing such requirements would not unduly impact interstate 

commerce, states should be allowed to do so. 

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 

169 

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 

170 

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 

171 

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 

172 

* Based on DOT Office of Pipeline Safety website data extrapolated for 2003. 

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. 

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 

173 

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? 

174 

Answer. Several manufacturers and research organizations are working to develop 

new and improved internal inspection devices, also known as ‘‘smart pigs’’. 

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 crossVerDate Nov 24 2008 13:13 Jan 03, 2018 Jkt 075679 PO 00000 Frm 00178 Fmt 6601 Sfmt 6621 S:\GPO\DOCS\27960.TXT JACKIE

615EFISQ3.eps
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ings, 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 


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176 

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 neighborVerDate Nov 24 2008 13:13 Jan 03, 2018 Jkt 075679 PO 00000 Frm 00180 Fmt 6601 Sfmt 6621 S:\GPO\DOCS\27960.TXT JACKIE

615EFISQ2.eps
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hoods 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 § 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 

178 

1See Gas Piping Technology Committee (GPTC) Guide. This is the work of an accredited consensus standards committee with members from industry, government and academia. 2 Incidents are reportable to DOT if they result in death, injury requiring hospitalization and/ 

or greater than $50,000 property loss. 

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. 

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. 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 

179 

$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 

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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. 

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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 

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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. 

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