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S. HRG. 111–1014 

ENSURING THE SAFETY 

OF OUR NATION’S PIPELINES 

HEARING 

BEFORE THE

SUBCOMMITTEE ON SURFACE TRANSPORTATION 

AND MERCHANT MARINE INFRASTRUCTURE, 

SAFETY, AND SECURITY 

OF THE

COMMITTEE ON COMMERCE, 

SCIENCE, AND TRANSPORTATION 

UNITED STATES SENATE 

ONE HUNDRED ELEVENTH CONGRESS 

SECOND SESSION 

JUNE 24, 2010 

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

( 

(II) 

SENATE COMMITTEE ON COMMERCE, SCIENCE, AND TRANSPORTATION 

ONE HUNDRED ELEVENTH CONGRESS 

SECOND SESSION 

JOHN D. ROCKEFELLER IV, West Virginia, Chairman 

DANIEL K. INOUYE, Hawaii 

JOHN F. KERRY, Massachusetts 

BYRON L. DORGAN, North Dakota 

BARBARA BOXER, California 

BILL NELSON, Florida 

MARIA CANTWELL, Washington 

FRANK R. LAUTENBERG, New Jersey 

MARK PRYOR, Arkansas 

CLAIRE MCCASKILL, Missouri 

AMY KLOBUCHAR, Minnesota 

TOM UDALL, New Mexico 

MARK WARNER, Virginia 

MARK BEGICH, Alaska 

KAY BAILEY HUTCHISON, Texas, Ranking 

OLYMPIA J. SNOWE, Maine 

JOHN ENSIGN, Nevada 

JIM DEMINT, South Carolina 

JOHN THUNE, South Dakota 

ROGER F. WICKER, Mississippi 

GEORGE S. LEMIEUX, Florida 

JOHNNY ISAKSON, Georgia 

DAVID VITTER, Louisiana 

SAM BROWNBACK, Kansas 

MIKE JOHANNS, Nebraska 

ELLEN L. DONESKI, Staff Director 

JAMES REID, Deputy Staff Director 

BRUCE H. ANDREWS, General Counsel 

ANN BEGEMAN, Republican Staff Director 

BRIAN M. HENDRICKS, Republican General Counsel 

NICK ROSSI, Republican Chief Counsel 

SUBCOMMITTEE ON SURFACE TRANSPORTATION AND MERCHANT 

MARINE INFRASTRUCTURE, SAFETY, AND SECURITY 

FRANK R. LAUTENBERG, New Jersey, 

Chairman 

DANIEL K. INOUYE, Hawaii 

JOHN F. KERRY, Massachusetts 

BYRON L. DORGAN, North Dakota 

BARBARA BOXER, California 

MARIA CANTWELL, Washington 

MARK PRYOR, Arkansas 

TOM UDALL, New Mexico 

MARK WARNER, Virginia 

MARK BEGICH, Alaska 

JOHN THUNE, South Dakota, Ranking 

Member 

OLYMPIA J. SNOWE, Maine 

JOHN ENSIGN, Nevada 

JIM DEMINT, South Carolina 

ROGER F. WICKER, Mississippi 

JOHNNY ISAKSON, Georgia 

DAVID VITTER, Louisiana 

SAM BROWNBACK, Kansas 

MIKE JOHANNS, Nebraska 

(III) 

C O N T E N T S 

Page 

Hearing held on June 24, 2010 ............................................................................... 1 

Statement of Senator Lautenberg .......................................................................... 1 

Statement of Senator Johanns ............................................................................... 2 

Statement of Senator Thune ................................................................................... 20 

Statement of Senator Hutchison ............................................................................ 21 

Prepared statement .......................................................................................... 22 

Statement of Senator Udall .................................................................................... 76 

Prepared statement .......................................................................................... 77 

Statement of Senator Begich .................................................................................. 78 

Statement of Senator Pryor .................................................................................... 81 

Statement of Senator Vitter .................................................................................... 82 

WITNESSES

Hon. Cynthia L. Quarterman, Administrator, Pipeline and Hazardous Materials Safety Administration, U.S. Department of Transportation ................... 3 

Prepared statement .......................................................................................... 4 

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

Board ..................................................................................................................... 12 

Prepared statement .......................................................................................... 13 

Rocco D’Alessandro, Executive Vice President of Operations, Nicor Gas on 

Behalf of the American Gas Association ............................................................ 34 

Prepared statement .......................................................................................... 36 

Timothy C. Felt, President and CEO, Colonial Pipeline Company on Behalf 

of the Association of Oil Pipe Lines (AOPL) and the American Petroleum 

Institute (API) ...................................................................................................... 41 

Prepared statement .......................................................................................... 42 

Gary L. Sypolt, CEO, Dominion Energy on Behalf of the Interstate Natural 

Gas Association of America ................................................................................. 49 

Prepared statement .......................................................................................... 51 

Carl Weimer, Executive Director, Pipeline Safety Trust ..................................... 58 

Prepared statement .......................................................................................... 60 

APPENDIX

Response to written questions submitted to Hon. Cynthia L. Quarterman by: 

Hon. John D. Rockefeller IV ............................................................................ 87 

Hon. Frank R. Lautenberg ............................................................................... 89 

Hon. Mark Pryor ............................................................................................... 90 

Hon. Mark Begich ............................................................................................. 92 

Hon. Kay Bailey Hutchison ............................................................................. 93 

Hon. John Thune .............................................................................................. 94 

Hon. Mike Johanns .......................................................................................... 97 

Response to written questions submitted to Hon. Deborah A.P. Hersman by: 

Hon. Mark Pryor ............................................................................................... 97 

Hon. Kay Bailey Hutchison ............................................................................. 104 

Hon. John Thune .............................................................................................. 105 

Response to written questions submitted by Hon. Mark Pryor to: 

Rocco D’Alessandro ........................................................................................... 106 

Timothy C. Felt ................................................................................................. 108 

Gary L. Sypolt ................................................................................................... 109 

Page

IV 

Response to written questions submitted to Carl Weimer by: 

Hon. Mark Pryor ............................................................................................... 110 

Hon. John Thune .............................................................................................. 111 

Hon. Johanns .................................................................................................... 112 

Michael Thompson, Chief, Pipeline Safety, Oregon Public Utility Commission 

and Chairman, National Association of Pipeline Safety Representatives 

(NAPSR), prepared statement ............................................................................. 113 

American Public Gas Association, prepared statement ........................................ 117 

(1) 

ENSURING THE SAFETY 

OF OUR NATION’S PIPELINES 

THURSDAY, JUNE 24, 2010 

U.S. SENATE, SUBCOMMITTEE ON SURFACE TRANSPORTATION AND

MERCHANT MARINE INFRASTRUCTURE SAFETY, AND SECURITY,

COMMITTEE ON COMMERCE, SCIENCE, AND TRANSPORTATION, 

Washington, DC. 

The Subcommittee met, pursuant to notice, at 2:31 p.m. in room 

SR–253, Russell Senate Office Building, Hon. Frank R. Lautenberg, 

Chairman of the Subcommittee, presiding. 

OPENING STATEMENT OF HON. FRANK R. LAUTENBERG, 

U.S. SENATOR FROM NEW JERSEY 

Senator LAUTENBERG. Good afternoon, everyone. I want to welcome you, those who are here, to this hearing on pipeline safety. 

Two weeks ago, workers in Weston, Texas, were digging up clay 

for a dirt contracting company and a tragedy occurred. The bulldozer inadvertently ruptured a natural gas pipeline, causing a fatal 

blast that left two persons dead and three others injured. Unfortunately, this was not an isolated incident. Just 1 day earlier, another worker in Texas was killed after a construction crew that was 

digging a hole for a utility pole accidentally struck a natural gas 

line. 

The fact is that while pipelines are by and large a safe form of 

transportation, when there is an accident the consequences can be 

deadly. There are nearly 2.5 million miles of pipelines today moving oil and gas within states and across the country. We’ve got to 

do all that we can to keep these pipelines safe and to reduce the 

frequency of accidents. 

In 2006, we made significant progress in pipeline safety when we 

passed the Pipeline Inspection, Protection, Enforcement, and Safety 

Act of 2006, also known as the PIPES Act. There is no doubt that 

the PIPES Act has improved pipeline safety. As we look to reauthorize the law this year, we want to hear from people who know, 

our witnesses, how the PIPES Act has worked and what we can do 

to improve it. 

For instance, a provision that I authored in that law requires 

that service lines to single-family homes be fitted with excess flow 

valves which can automatically shut off a pipeline if a sudden 

change in pressure is detected. I’m interested in hearing from our 

witnesses whether or not this requirement should be expanded to 

other types of buildings. 

2 

The law also addresses the difficult problem of digging and excavation. Nearly 35 percent of all serious pipeline incidents during 

the last 10 years were caused by excavation damage, the single 

most common cause of these accidents. 

The PIPES Act improved excavation safety by strengthening the 

One-Call system, which makes it easier for construction crews to 

notify utility companies about digging projects and therefore dramatically reducing pipeline accidents. Under that system, construction crews must call one phone number before digging, giving utility companies time to identify and mark hidden pipes if they 

haven’t already done so. This system is now working better because 

of the PIPES Act, although we’ve still got to work to improve and 

increase awareness of the program. That’s why I authored a resolution, passed by the Senate, to make April Call Before You Dig 

Month, to promote safe digging practices, including 811, the national Call Before You Dig Number. 

So I look forward to hearing from today’s witnesses about their 

views on the safety of our Nation’s pipelines and the reauthorization of the PIPES Act. I also look forward to hearing from Administrator Quarterman about what she’s doing to make sure that the 

Office of Pipeline Safety is vigilant in its oversight responsibilities. 

Before we hear from our panels, I would call on Senator Johanns. 

STATEMENT OF HON. MIKE JOHANNS, 

U.S. SENATOR FROM NEBRASKA 

Senator JOHANNS. Thank you very much. I won’t give a long 

opening statement, but I do want to offer a thought or two just to 

maybe kind of queue up in your minds some of my interest in this 

hearing today. Somebody laid in front of me these pictures of damage that obviously occurred at some event, and I look at them and 

I wonder to myself not only the impact on human life, but the impact on the environment. That’s especially true these days as we 

look to the Gulf and the issues that are out there. 

I raise that because today I want to get a better understanding 

relative to a project that is going on in Nebraska, the Keystone 

pipeline project. All of a sudden my office is starting to get calls 

from concerned people. Here’s what’s driving that. Our greatest 

natural resource in our state, some would argue, is the Ogallala 

Aquifer. It is literally an underground lake that stretches for miles 

and miles and miles and miles. It’s not just in Nebraska; it’s in 

other states also. 

The concern is that this pipeline is going to traverse that, and 

so now citizens are worried about safety. So I’m going to want to 

know who’s responsible, what’s the ins and outs of that, who do we 

call that can help us address these concerns, and what the relationship between the various Federal agencies would be. 

This project is even more complicated because it originates in 

Canada and it therefore crosses the Canadian border. I appreciate 

that there’s an international element to what’s going on here, too. 

So I didn’t want to catch anybody by surprise. I thank the chairman for giving me an opportunity to raise that in my opening 

statement. With that, thank you. 

Senator LAUTENBERG. Thanks very much. 

3 

Now I welcome our first panel of witnesses: Ms. Cynthia 

Quarterman, Administrator, Pipeline and Hazardous Materials 

Safety Administration. Ms. Quarterman, this is your first time before this subcommittee since your confirmation and we welcome 

you and look forward to hearing your testimony. Just to show that 

I’m impartial, all statements will be limited to 5 minutes. Thank 

you. 

Please, Ms. Quarterman. 

STATEMENT OF HON. CYNTHIA L. QUARTERMAN, 

ADMINISTRATOR, PIPELINE AND HAZARDOUS 

MATERIALS SAFETY ADMINISTRATION, 

U.S. DEPARTMENT OF TRANSPORTATION 

Ms. QUARTERMAN. Thank you. Chairman Lautenberg, members 

of the Committee: Thank you for the opportunity to appear today. 

Your interest in pipeline safety is very much appreciated. 

Like Secretary LaHood, safety is my top priority for PHMSA. 

The lessons learned from current and past tragedies have significantly influenced the safety policies underlying the laws and regulations related to pipeline safety. Thanks to the Congress and especially to this subcommittee the Department has made tremendous 

strides in improving the pipeline safety program. 

I’m pleased to update you on PHMSA’s progress in ensuring the 

safety of our Nation’s pipeline transportation system through implementing the mandates of the PIPES Act of 2006. The Act has 

played a major role in maintaining a safe and reliable pipeline network. Thanks to your help, PHMSA has developed a forward-leaning pipeline safety program. A reauthorized program promises to 

build on that progress. 

PHMSA has worked aggressively to respond to Congressional interest and implement the PIPES Act. It has made significant 

progress in implementing its statutory requirements to build safer 

communities. PHMSA has been working with many governmental 

partners to promote safety, such as the National Transportation 

Safety Board, the Department’s Office of Inspector General, and 

the Government Accountability Office, implementing strategic approaches to address their safety recommendations. 

Since its last reauthorization, PHMSA has gone from a high of 

16 open NTSB pipeline recommendations to today’s low of 9 open 

recommendations. Of the remaining nine, none of the recommendations are classified as unacceptable and several should close before 

the year’s end. There are no outstanding IG recommendations for 

the pipeline program and the two outstanding GAO recommendations should be closed by year’s end as well. 

PHMSA has made great progress in strengthening its industry 

oversight program. The PIPES Act reauthorized PHMSA to increase its inspection and enforcement staffing from 94 in Fiscal 

Year 2007 to 135 in Fiscal Year 2010. PHMSA has instituted a 

new, more aggressive recruiting strategy to promptly fill vacant inspection and enforcement positions. PHMSA has taken advantage 

of higher penalty authority by imposing and collecting larger penalties where appropriate. PHMSA has set records in its enforcement processes, proposing $19 million in administrative civil penalties since 2006, or an average $183,000 per proposed penalty. 

4 

PHMSA has added integrity management requirements to natural gas distribution networks to address pipelines, where safety 

risks have the most impact on citizens. PHMSA has also worked 

to improve the internal operations of pipeline companies’ control 

rooms. This action removes the pipeline program’s control room 

standards from the NTSB top ten list and replaces it with NTSB 

praise. 

PHMSA has established valuable state partnerships on oversight, emergency response, and damage prevention. Funding to 

state pipeline safety programs has increased. In 2010 PHMSA will 

cover 54 percent of the pipeline safety program costs for states, 

compared with 45 percent in 2006. 

PHMSA has also maintained strong relationships with Federal, 

state, local, and other emergency response agencies to effectively 

respond to pipeline incidents and emergencies. Following incidents, 

PHMSA staff remain in constant contact with investigatory and additional oversight agencies to not only ensure public safety and operator compliance, but to share information and participate in remediation activities. 

PHMSA and its partners have done a good job helping reduce the 

number of pipeline incidents related to excavation damage over the 

past few years. Since 2006, excavation damage has gone from 37.5 

percent as the cause of serious incidents to 12.7 percent today. 

All of us at PHMSA are proud of the accomplishments to date 

in implementing the PIPES Act, although we acknowledge there is 

still more work to be done. As the Administrator of this agency, I 

assure you that all of my staff and all of our stakeholders know 

that safety is PHMSA’s top priority. 

We look forward to working with Congress to reauthorize the 

Pipeline Safety Act and I welcome any questions you might have. 

[The prepared statement of Ms. Quarterman follows:] 

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

AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION, U.S. DEPARTMENT OF

TRANSPORTATION

Chairman Rockefeller, Ranking Member Hutchison, members of the Committee, 

thank you for the opportunity to appear today. Safety is Secretary LaHood’s top priority and it is PHMSA’s top priority as well. PHMSA is also committed to reducing 

risks in pipeline transportation. PHMSA employees are encouraged to bring up new 

and creative ideas and to challenge each other and their supervisors so that the best 

safety solutions are put forward. As our Nation’s reliance on the safe and environmentally sound transportation of hazardous materials is increasing, the Pipeline 

and Hazardous Materials Safety Administration’s (PHMSA) safety oversight of the 

Nation’s pipelines provides critical protection for the American people and our environment. 

PHMSA works with many governmental partners to promote safety. The National 

Transportation Safety Board (NTSB), the Department’s Office of Inspector General 

(OIG), the Government Accountability Office (GAO), and, of course, the U.S. Congress and the states all have a vested interest in the safe and reliable operation 

of the Nation’s pipeline infrastructure. PHMSA is working aggressively to be responsive to all of these organizations and their recommendations. Since 2006, 

PHMSA’s accomplishments include: closing the three open OIG recommendations; 

making significant progress on the GAO’s recommendations on incident reporting 

with the last action due out this summer; and making substantial progress on all 

of the NTSB recommendations. When the Pipeline Inspection Protection Enforcement and Safety (PIPES) Act of 2006 passed, NTSB had thirteen open recommendations to PHMSA. Over the last several years, NTSB has closed nine of those recommendations and it is currently working to address the remaining four recVerDate Nov 24 2008 07:17 Jul 12, 2011 Jkt 067270 PO 00000 Frm 00008 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\67270.TXT SCOM1 PsN: JACKIE
5 

ommendations as well as a few new recommendations. PHMSA does not currently 

have any open unacceptable recommendations. 

I am pleased to brief you on the significant progress PHMSA’s Pipeline Safety 

Program has made since the passage of the PIPES Act in December, 2006. PHMSA 

looks forward to working with you to build on this solid foundation. 

I. Implementation of the PIPES Act 

PHMSA has made significant progress in fulfilling the statutory requirements of 

the PIPES Act, which has resulted in safer communities today. The number of serious pipeline incidents—those involving death or injury—has declined by 50 percent 

over the last twenty years. Yet over the same period, all the traditional measures 

of risk exposure have risen—population, energy consumption, pipeline ton-miles. We 

aim to continue the downward long-term trend in pipeline incidents. 

A brief description of PHMSA’s successful use of the tools provided by Congress 

in the PIPES Act to improve the safety record of the Nation follows. 

A. PHMSA Has Increased the Strength of Integrity Management Programs and 

Enforcement Activities 

The PIPES Act broadened the scope of the systems-based approach to assessing 

and managing safety related risks. The additional initiatives included: (1) increasing 

enforcement activity, transparency, and data quality; (2) implementing an integrity 

management program for distribution pipelines, and; (3) requiring a management 

plan to reduce risks associated with human factors, including operator fatigue in 

pipeline control centers, and implementing NTSB recommendations on the Supervisory Control and Data Acquisitions (SCADA) systems in pipelines. We are pleased 

with the positive results from increasing the systems risk management approach, 

which this Committee helped devise. 

1. PHMSA Has Increased Enforcement and Improved Transparency and Data 

Quality 

PHMSA has used its full enforcement authority to give teeth to its systems-based 

approach to risk management and increase pipeline company management accountability for safety. The PIPES Act, and the appropriations that followed, authorized 

PHMSA to increase its inspection and enforcement staffing to 135 in FY 2010 from 

94 inspection and enforcement staff in FY 2007. PHMSA is in the process of an aggressive recruitment effort to fill these positions as soon as possible. 

Also, PHMSA has embraced enforcement transparency by leveraging its website 

and data bases to provide on-the-spot information to stakeholders. Within months 

after the 2006 PIPES Act was signed into law, we launched an enforcement transparency website. The website provides public access to a variety of reports and enforcement program information that goes beyond what is required by the PIPES 

Act. This site provides year-by-year reports on cases initiated and closed, the status 

of different types of enforcement cases, and reports on civil penalty cases showing 

the amounts proposed, assessed, and collected. Information and documents on indiVerDate Nov 24 2008 07:17 Jul 12, 2011 Jkt 067270 PO 00000 Frm 00009 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\67270.TXT SCOM1 PsN: JACKIE

624QUART1.eps
6 

vidual cases are also provided. These documents include the initial notices that allege operator violations or inadequacies; operator responses to these allegations; and 

the orders documenting PHMSA’s final determinations. In addition, PHMSA provides monthly updated enforcement summaries to the public. Use of the enforcement transparency website has climbed steadily since its inception in May 2007 and 

averaged more than 1,500 hits per day in 2009. In 2010, we expanded and improved 

the information on civil penalty cases and began displaying enforcement data from 

state pipeline safety agencies. 

In addition to increased staffing and online function, the PIPES Act also gave 

PHMSA a much needed enforcement tool—the Safety Order. In January 2009, 

PHMSA published a final rule establishing the process by which PHMSA conducts 

Safety Order proceedings to address pipeline integrity risks to public safety, property, or the environment. 

Finally, the PIPES Act now requires that senior executive officers of pipeline companies certify their pipeline integrity management program performance on an annual and semi-annual basis. As predicted, the certification requirement has increased management’s accountability and the accuracy in performance reporting. 

PHMSA also undertook a significant effort to improve data consistency and quality culminating in a new generation of data reporting that will begin this summer. 

First, PHMSA published a final rule in August 2009 to align cause categories across 

natural gas transmission and distribution incident reports. Second, PHMSA sought 

and received Office of Management and Budget approval for new forms and additional data collections. Third, PHMSA updated its guidance and forms regarding incident reporting. Fourth, PHMSA proposed revisions to the reporting requirements 

in Part 191 and expects to issue a final rule. While all seemingly small changes, 

the process allowed for coordination and input from state pipeline safety agencies 

and other Federal agencies ultimately resulting in raising industry awareness. This 

effort specifically addressed Congress’ mandates to modify reporting requirements 

to ensure that incident data accurately reflects incident trends over time and collects data on controller fatigue. 

2. PHMSA Has Established a Gas Distribution Integrity Management Program 

(DIMP) 

Pursuant to the authority granted in the 2006 PIPES Act, PHMSA issued a final 

rule in December 2009 requiring operators of gas distribution pipelines to develop 

and implement integrity management programs to manage and reduce risks in gas 

distribution pipeline systems. These programs are intended to enhance safety by 

identifying and reducing pipeline integrity risks. The requirements for the integrity 

management programs are similar to those required for gas transmission pipelines, 

but tailored to reflect the differences in and among distribution pipelines. The regulation requires operators to develop and implement plans for monitoring and improving the condition of their systems, in addition to complying with current code 

requirements. The rule also requires distribution operators to install excess flow 

valves in new and replaced service lines for single family residences where conditions are suitable for their use. The rule applies to the entire network of distribution 

pipelines and the thousands of small and large companies that deliver natural gas 

over the 2 million miles of pipelines serving American communities, not just high 

consequence areas. 

PHMSA made tremendous efforts getting ready for the implementation of DIMP. 

We developed consensus standards, guidance, training, IT systems, and data to increase understanding of the new regulations. We are especially mindful of the increased oversight requirements associated with the program. Getting 50 states to 

implement a performance standard takes a lot more preparation than preparing a 

single Federal entity. Accordingly, we have worked with our state partners to prepare them by assuring thorough training, education, and effective enforcement compliance. 

3. PHMSA Has Established Control Room Management Requirements 

Pursuant to the authority granted in the PIPES Act, PHMSA issued a final rule 

on December 4, 2009, to address human factors and other aspects of control room 

management for pipelines remotely operated and controlled by personnel using 

SCADA systems. Operators must define the roles and responsibilities of controllers 

and provide controllers with the necessary information, training, and processes to 

fulfill these responsibilities. Controllers must manage SCADA alarms; assure control room considerations are taken into account when changing pipeline equipment 

or configurations, and review reportable incidents or accidents to determine whether 

control room actions contributed to the event. Operators must also implement methods to prevent controller fatigue. These regulations will enhance pipeline safety by 

7 

coupling strengthened control room management with improved controller training 

and fatigue prevention measures. 

The regulations apply to all hazardous liquid pipelines, and gas transmission and 

distribution pipelines that meet certain risk criteria. This rule not only responds to 

the PIPES Act mandate but also addresses a NTSB safety recommendation regarding controller fatigue that was on the NTSB’s Most Wanted list. A public workshop 

is planned for November 2010 to present preliminary guidance materials. Programmatic inspections will be conducted between September 2011 and February 

2013. 

B. PHMSA is Enhancing Pipeline Safety with Increased Assistance to States, 

Damage Prevention Education, Technical Assistance Grants, and Public Access 

to Information 

1. PHMSA Has Strengthened Its Assistance to States 

State pipeline safety agencies oversee the bulk of the 2.5 million miles of pipeline 

infrastructure. Specifically, states are responsible for oversight of virtually all gas 

distribution pipelines, gas gathering pipelines and intrastate gas transmission, as 

well as 88 percent of intrastate hazardous materials liquid pipelines and 20 percent 

of the interstate gas pipelines. PHMSA maintains primary responsibility for the remaining pipelines, including all interstate hazardous liquid pipelines and 80 percent 

of the interstate gas pipelines. States employ approximately 63 percent of the inspector workforce. The expansion of the Federal pipeline safety initiatives, such as 

DIMP and integrity management, has increased the resource demands on both Federal and state pipeline safety agencies. 

In recognition, Congress increased PHMSA’s ability to provide grants to state 

pipeline safety agencies to offset the costs associated with the statutory requirements for their inspection and enforcement programs. In addition, Congress gave 

PHMSA considerable resources to expand its relationship with state pipeline safety 

agencies, enabling increased policy collaboration, training, information sharing, and 

data quality and collection. In FY 2010, PHMSA’s $40.5 million appropriation to 

support state programs will fund 54 percent of state pipeline safety programs. Additionally, the President’s FY 2011 request includes an increase in funds to support 

state programs totaling approximately $44.5 million, which would reflect a 65 percent funding of the state pipeline safety programs. These States are PHMSA’s 

strongest asset in assuring the safety of pipelines in American communities. 

2. PHMSA Has Strengthened Damage Prevention Efforts 

The vast majority of America’s pipeline network is underground making pipelines 

vulnerable to ‘‘dig-ins’’ by third-party excavators. While excavation damage is 100 

percent preventable, it remains a leading cause of pipeline incidents involving fatalities and injuries. Three-quarters of all serious consequences from pipeline failures 

relate to distribution systems and more than one-third of these failures are caused 

by excavation damage. PHMSA’s goal is to significantly reduce excavation damage 

with strong outreach and public awareness programs. As evident in the chart below, 

PHMSA is making progress. 

The PIPES Act authorizes PHMSA to award State Damage Prevention (SDP) 

grants to fund improvements in damage prevention programs. Each state has established laws, regulations, and procedures shaping its state damage prevention proVerDate Nov 24 2008 07:17 Jul 12, 2011 Jkt 067270 PO 00000 Frm 00011 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\67270.TXT SCOM1 PsN: JACKIE

624QUART2.eps
8 

gram. Since 2008, PHMSA provided over $4 million in SDP grants to 30 distinct 

state organizations. Eligible grantees include: state one-call centers, state pipeline 

safety agencies, or any organization created by state law and designated by the Governor as the authorized recipient of the funding. 

SDP grants reinforce nine specific elements that make up the components of an 

effective damage prevention program, under the PIPES Act: 

1. Enhances communications between operators and excavators; 

2. Fosters support and partnership of all stakeholders; 

3. Encourages operator’s use of performance measures for locators; 

4. Encourages partnership in employee training; 

5. Encourages partnership in public education; 

6. Defines roles of enforcement agencies in resolving issues; 

7. Encourages fair and consistent enforcement of the law; 

8. Encourages use of technology to improve the locating process; and 

9. Encourages use of data analysis to continually improve program effectiveness. 

PHMSA’s Technological Development Grants program makes grants to an organization or entity (not including for-profit entities) to develop technologies that will 

facilitate the prevention of pipeline damage caused by demolition, excavation, tunneling, or construction activities. A total of $500,000 was appropriated for the program in 2009. Two awards have been made to date. 

PHMSA also uses the authority in the PIPES Act to promote public education 

awareness with national programs such as, ‘‘811—Call Before You Dig Program’’ 

through the Common Ground Alliance (CGA). PHMSA provided over $2.2 million in 

funding assistance for CGA’s 811 advertising campaign since 2002. 

PHMSA is proud of its continued and steady leadership in supporting national 

and state damage prevention programs. In March 2010, we participated in the 

CGA’s annual meeting highlighting the importance of the National ‘‘811—Call Before You Dig Program.’’ In April 2010, Transportation Secretary LaHood acknowledged the importance of calling before you dig by establishing April as ‘‘National 

Safe Digging Month.’’ The U.S. Senate and the House of Representatives both introduced resolutions designating April 2010 as ‘‘National Safe Digging Month.’’ At our 

urging, forty states, including those represented by the members of this committee, 

also followed suit. The efforts driven and supported by PHMSA, involved the CGA, 

many states, and damage prevention stakeholders from around the country, who are 

advocates for safe excavation practices. 

3. PHMSA Has Launched the Technical Assistance Grant Program 

The PIPES Act empowers PHMSA to encourage communities to take part in efforts to develop technical solutions for environmental and emergency planning, zoning, and land use management near pipelines, and to prevent damage to pipelines. 

Under this authorization, PHMSA created the Technical Assistance Grant (TAG) 

program to provide grants to local communities and organizations for technical assistance related to pipeline safety issues. Technical assistance is defined as engineering or other scientific analysis of pipeline safety issues. The funding can also 

be used to help promote public participation in official proceedings. 

In 2009, PHMSA selected 21 communities and organizations to receive funding 

through the agency’s TAG program. Grants, totaling $1 million, were used to foster 

open communication between the public and pipeline operators on pipeline safety 

and environmental issues, and perform other important tasks. Examples of such 

projects include the use of geographic information systems for enhanced pipeline 

monitoring and public awareness campaigns to promote the sharing of information 

between pipeline operators and landowners. 

Each technical assistance grant recipient must provide a report to PHMSA within 

one year of its award demonstrating completion of the work as outlined in its grant 

agreement. PHMSA is thoroughly overseeing this process and will evaluate the expected outcomes of each grant recipient. PHMSA’s Community Assistance and Technical Services Managers will offer their technical support to communities and organizations as well to address pipeline safety questions that may arise during the 

course of the grant agreement period. 

4. PHMSA’s Pipelines and Informed Planning Alliance Advances Smart Growth 

along Pipelines in Our Communities 

In addition to the grants, PHMSA has conducted other activities to inform the 

public and engage public interest and participation in all of its initiatives. We fundVerDate Nov 24 2008 07:17 Jul 12, 2011 Jkt 067270 PO 00000 Frm 00012 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\67270.TXT SCOM1 PsN: JACKIE
9 

ed publicly accessible, Internet broadcast viewing of two pipeline events sponsored 

by the Pipeline Safety Trust, including a focus on safer land use planning. We have 

made one grant and may make others to professional associations of county and city 

government officials to represent the public in the Pipelines and Informed Planning 

Alliance (PIPA). PIPA is an initiative organized by PHMSA to encourage the development and use of risk-informed land use guidelines to protect pipelines and communities. 

A companion effort is helping communities understand where pipelines are located, who owns and operates them, and what other information is available for 

community planning. Following the passage of the PIPES Act, PHMSA worked with 

the Department of Homeland Security (DHS)/Transportation Security Administration (TSA) to resolve concerns about sensitive security sensitive information. Vital 

information that communities need for land use, environmental, and emergency 

planning around pipelines is now publicly available through PHMSA’s National 

Pipeline Mapping System (NPMS). We continue to work with states, industry, and 

other stakeholders to make the NPMS information more accurate and useful. 

C. PHMSA Has Adopted Additional Regulatory Enhancements and has Sponsored 

Congressional Required Studies 

In addition to the programmatic authorizations already discussed, Congress provided PHMSA with the authority to address narrow, but significant, gaps in its safety regulations. The gaps related to regulating low stress pipelines, effective response 

to emergency disruption of pipeline operations, regulation of direct sale natural gas 

pipelines, and the coordination of pipeline security responsibility. PHMSA has addressed all of these additional regulatory initiatives in the PIPES Act. 

Low Stress Pipelines. Under the direction of the PIPES Act, PHMSA regulates 

rural low-stress hazardous liquid pipelines to the same standards as other hazardous liquid pipelines. Low stress pipelines operate at or below 20 percent specified 

minimum yield strength. PHMSA had already regulated low stress hazardous liquid 

pipelines that were in populated areas or that crossed commercially navigable waterways. The PIPES Act directed PHMSA to regulate all low stress line including 

those rural low stress lines that could pose a threat to unusually sensitive environmental areas. On June 3, 2008, we published a Final Rule, Low Stress I, as phase 

one of a two phase process to complete the regulatory mandate in the PIPES Act. 

Low Stress I brought under safety regulation those rural low-stress pipelines that 

pose the greatest risk to environmentally sensitive areas, particularly low stress 

lines that are 85⁄8 inches or greater in diameter and located in or within a 1⁄2-mile 

of an unusually sensitive area. PHMSA issued a notice of proposed rulemaking for 

Low Stress II which was published in the Federal Register on June 22, 2010, to 

bring the remainder of the unregulated low stress pipelines under our safety regulation. 

Emergency Waiver of Pipeline Safety Requirements. The PIPES Act authorized 

PHMSA to waive compliance with certain Federal pipeline safety requirements 

without notice and opportunity for a hearing if needed to address an emergency involving pipeline transportation. In the wake of Hurricane Katrina, Congress recognized that in an emergency, it would not be feasible to provide for notice and opportunity for a hearing, as required for other waivers. PHMSA issued a final rule on 

January 16, 2009, to process emergency special permits when necessary to address 

an actual or impending emergency caused by a natural or manmade disaster. 

Clarify Regulation of Direct Sale Natural Gas Pipelines. PHMSA issued an advisory bulletin on May 13, 2008, advising operators that the PIPES Act eliminated 

the exception of direct sale natural gas pipelines from the definition of an interstate 

gas pipeline facility. PHMSA is now responsible for regulatory oversight and enforcement of these lines. 

OIG Recommendations Regarding Pipeline Security Annex. PHMSA has addressed 

all three recommendations in the OIG report to Congress on DOT actions to implement the pipeline security annex between DOT and the DHS. We finalized the action plan for implementing the annex. We formalized each agency’s security roles 

and responsibilities and helped develop a Pipeline Security Incident Response Protocols plan for responding to potential terrorist actions. We coordinate efforts to minimize duplicative security inspections and we have almost daily communication with 

DHS concerning pipeline safety events and security incidents. 

In the PIPES Act, Congress also requested that PHMSA undertake certain studies to attend to specific concerns brought to light by certain natural disasters and 

the aging infrastructure of the pipeline system. We appreciate the opportunity to 

show Congress that we are working diligently with our stakeholders and other governmental departments to address petroleum capacity, leak detection, and internal 

10 

1 Each Notice of Probable Violation case usually contains multiple individual violations. 

corrosion concerns, as well as to determine appropriate risk assessment intervals. 

PHMSA has conducted and reported to Congress on all the required studies. 

Petroleum Capacity Market Study. On June 1, 2008, PHMSA submitted to Congress a final report on the domestic transport capacity of petroleum products by 

pipeline and to reduce the likelihood of shortages of petroleum products or price disruptions due to shortages of pipeline capacity. 

Leak Detection Systems Study. On June 23, 2009, PHMSA submitted to Congress 

a final report describing the capabilities and limitations of leak detection systems 

used by hazardous liquid pipeline operators. The report also discusses ongoing investment by PHMSA and research to improve the sensitivity of leak detection technology, particularly for hazardous liquid operators. As we stated in the report, 

PHMSA has adequate oversight to evaluate the leak detection capability of individual operators and has exercised authority as needed to compel systems upgrades 

where warranted. 

Internal Corrosion Control Regulations Study. In June 2009, PHMSA submitted 

to Congress a final report of its thorough review of the Federal pipeline safety internal corrosion control regulations, accident history, research findings, and consensus 

standards to determine if such regulations are adequate. Although we found that 

existing regulations are generally sufficient to achieve safety and environmental 

protection goals, we were also considering other near- and long-term actions to further reduce the risk of internal corrosion. 

Seven-Year Risk Assessment Study. In November 2007, PHMSA reported to Congress on its review of the GAO report on the seven-year assessment interval. 

II. Building on a Solid Foundation 

PHMSA is building a solid foundation to advance pipeline safety. That said, we 

are committed to completing the two remaining initiatives authorized by PIPES 

Act—completing the notice of proposed rulemaking to regulate low stress pipelines 

this year, and taking the next step to implement Federal enforcement of third party 

excavation damage to pipelines. 

PHMSA has accomplished many goals with its state partners; at the same time 

however, it is important that states continue to receive the resources they need to 

implement not only damage prevention initiatives but the distribution integrity 

management program. 

PHMSA also plans to update its enforcement strategy and penalties to deter future noncompliance and incentivize better performance. We continue to make full 

use of the increased administrative civil penalty authority granted in the Pipeline 

Safety Improvement Act of 2002. It is evident from the comparable periods before 

and after the PIPES Act, PHMSA has doubled the proposed pipeline safety administrative civil penalties it issued to operators, and the average per case has more than 

tripled. Specifically, between 2004 and 2006, PHMSA proposed $10 million in administrative civil penalties, with an average proposed civil penalty of $57,000; and, 

between 2007 and 2009, PHMSA proposed $19 million in administrative civil penalties and an average proposed civil penalty of $183,000. Furthermore, the average 

administrative civil penalty proposed per individual violation 1 has increased from 

approximately $16,000 in 2002 to an average of approximately $100,000 today. 

PHMSA issues operators proposed administrative civil penalties for probable violations identified during inspections or investigations. Proposed penalties are communicated to operators in Notices of Probable Violation and operators have the right 

to respond to these allegations before a penalty is assessed in a Final Order. Penalties are an effective tool to ensure operator accountability, but the current cap on 

PHMSA’s administrative civil penalties of up to $100,000 per violation, per day and 

up to $1 million for a related series of violations may limit PHMSA’s enforcement 

efforts. 

We look forward to seeing our integrity management programs continue to mature 

and yield results. With this in mind we will continue to look at performance measures and ways we can improve the data that we collect. Having better data will enable us to make risk based informed regulatory decisions. 

With the anticipated increase in transportation of new products like ethanol, hydrogen, carbon dioxide, and potentially other bio-fuels, we are working to ensure a 

solid regulatory framework to prevent accidents and ensure safety. We currently 

regulate pipelines transporting ethanol blends and to the extent new biofuels are 

developed in the future that involve pipeline transportation, PHMSA is committed 

to taking whatever steps are necessary to ensure that such transportation will be 

conducted safely. We coordinate with other Federal agencies to forecast the transportation implications from the inception of marketing new fuels, as part of a sysVerDate Nov 24 2008 07:17 Jul 12, 2011 Jkt 067270 PO 00000 Frm 00014 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\67270.TXT SCOM1 PsN: JACKIE
11 

temic oversight process. We coordinate with other countries to benefit from their experience. We continue to work with individual operators, identifying safety concerns 

that must be satisfied, both with the infrastructure and with the surrounding community. For example, ethanol poses very unique emergency response challenges, 

and PHMSA is responsible for helping communities prepare. We have also been a 

part of the interagency Carbon Capture and Sequestration Task Force in which 

issues related to carbon dioxide pipeline transportation are being addressed. We collaborate with the pipeline industry, the renewable fuels organizations, and others 

like emergency responder organizations and the National Commission on Energy 

Policy, to investigate and solve technical challenges. 

III. Responding to Current Challenges 

While PHMSA is gearing up to deal with the new challenges we expect to see 

through an increased use of pipelines to transport renewable fuels, we are continuing to exert vigilant and visionary leadership to remain steps ahead of the pipeline safety issues we’re faced with today. 

A. PHMSA Coordinates With Federal, State, Local and Private Parties to Respond 

to and Investigate Pipeline Accidents and Incidents 

PHMSA has established strong relationships with other organizations involved in 

responding to pipeline incidents and emergencies. When we respond to an incident, 

our primary concern is the public’s safety and to determine an operator’s compliance 

with PHMSA regulations. We are often times requested to share information and 

support the investigations of other agencies, including the National Transportation 

Safety Board, the U.S. Chemical Safety and Hazard Investigation Board, the Occupational Safety and Health Administration and other Federal, State, and local response agencies. PHMSA staff remains in constant contact with the Transportation 

Security Administration to share information related to pipeline and other transportation failures to identify each agency’s jurisdictional authority, roles, and responsibilities. In addition, PHMSA has a long history of working closely with local emergency officials in response to pipeline emergencies and our staff effectively participates in incidents where there is an Integrated Command System. 

B. PHMSA Provides Routine Training to Staff on Ethics 

PHMSA employees must understand that clear lines exist between being a regulator and the regulated. We want to ensure our employees are clear on what current 

Federal policies exist on accepting gifts, dealing with prohibited sources, responding 

to bribes, and other ethics related issues. Employees are trained on Federal ethics 

guidelines when initially becoming a new PHMSA employee. PHMSA inspectors and 

other staff are also provided annual refresher training on ethics standards, and on 

a periodic basis on relevant ethics topics. 

C. PHMSA is Reminding Operators of Their Obligations to Have an Effective Oil 

Spill Response Plan 

The events in the Gulf are a clear reminder of the devastating impact a serious 

oil spill can have on the environment and human activities. PHMSA recently issued 

an advisory bulletin to operators of onshore oil pipelines and facilities to remind 

them of their responsibilities under the Federal Water Pollution Control Act. In the 

advisory, owners and operators of oil transport systems are advised of their responsibility to have and to periodically review and update their facility oil spill response 

plan to reduce the environmental impact of oil discharges. PHMSA regulations require onshore oil pipeline operators to prepare, review, and update oil spill response 

plans for their facilities periodically, and whenever significant changes may occur. 

The advisory requires operators to review their facility response plans in view of the 

Gulf incident to ensure they comply with all applicable requirements. Once an operator reviews its plan and indicates changes are necessary, they must update and 

submit those plans to PHMSA. If no changes are necessary, operators must notify 

us that the review has occurred. 

D. PHMSA is Preparing an Offshore Pipeline Action Plan 

PHMSA is in the process of reviewing its current policies and procedures related 

to all offshore pipelines to determine what actions should be taken to improve its 

oversight of those pipelines. In addition, PHMSA is currently in stage one of a three 

stage process to conduct an integrated inspection of BP Pipeline North America’s 

U.S. assets, including the company’s 6,800-mile pipeline system. Stage one of the 

BP integrated inspection involves assembling and analyzing a considerable amount 

of data covering BP’s system to understand recent inspection history, safety performance, and processes and procedures. After the pre-inspection phase is complete, 

PHMSA’s integrated inspection team will be better equipped to develop an inspecVerDate Nov 24 2008 07:17 Jul 12, 2011 Jkt 067270 PO 00000 Frm 00015 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\67270.TXT SCOM1 PsN: JACKIE
12 

tion plan that is focused on BP’s higher risks areas to assure compliance and improve performance. 

In closing, we look forward to working with Congress to address these issues and 

to reauthorize the pipeline safety program. PHMSA very much appreciates the opportunity to report on the status of our progress with PIPES Act implementation 

and I am committed to full compliance. Thank you. I would be pleased to answer 

any questions you may have. 

Senator LAUTENBERG. Thank you very much. 

Ms. Hersman, we’re pleased to hear from you, the Chairman of 

the National Transportation Safety Board, and we welcome you 

back to the Subcommittee. We look forward to hearing from you. 

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

NATIONAL TRANSPORTATION SAFETY BOARD 

Ms. HERSMAN. Thank you, Chairman Lautenberg, Ranking Member Thune, and Senator Johanns. Thank you for the opportunity to 

address the Committee on the important issue of pipeline safety. 

The NTSB is responsible for determining the probable cause of 

accidents and issuing recommendations to prevent them from happening again. Our responsibilities also include evaluating the effectiveness of safety programs of other agencies, including PHMSA. 

PHMSA has made significant improvements in the last 5 years, in 

large part because of statutory mandates in the Pipeline Safety Improvement Act of 2002, as well as the PIPES Act of 2006. In general, PHMSA has been responsive to NTSB’s pipeline safety recommendations. Between January 1, 2002, and January 1, 2010, the 

NTSB issued 24 recommendations to PHMSA. As of today, only 

eight of those recommendations remain open and only one issued 

prior to 2002 remains open. 

PHMSA’s more notable accomplishments include regulations addressing integrity management programs for gas transmission, 

hazardous liquid, and natural gas distribution lines, regulations for 

improved education among emergency response agencies and the 

public, and the implementation of the 811 One-Call system. 

Yet, there are some areas of concern that remain. One of these 

concerns gained much attention following corrosion failures on a 

BP Exploration low-stress pipeline serving the Trans-Alaska Pipeline in 2006. The leak along this low-stress pipeline resulted in 

more stringent PHMSA regulations, but these regulations overlook 

most low-stress and on-and offshore gathering pipelines, leaving 

thousands of miles of pipelines unregulated. 

However, just this past week, PHMSA outlined safety requirements for all rural low-stress pipelines not already covered. The 

NTSB applauds these efforts, and we look forward to evaluating 

their proposal in greater detail. 

Another area of concern is risk-based pipeline safety programs, 

which provide operators with the responsibility to develop, implement, and evaluate individual programs and plans. PHMSA has 

the responsibility to review these plans for regulatory compliance 

and to conduct audits to evaluate their effectiveness. However, in 

recent pipeline investigations, the NTSB has seen indications that 

PHMSA and operator oversight have not been adequate. 

This photo is from a November 1, 2007, rupture of a propane 

pipeline in Carmichael, Mississippi, which resulted in two fatalities 

and seven injuries and property damage exceeding $3 million. It is 

13 

the responsibility of the pipeline operator to raise public awareness 

about the pipeline. The operator in this case hired two contractors 

to administer its program, but the mailing list did not include all 

of the residential addresses within the mailing area. The mistake 

was not caught until after the accident. The NTSB recommended 

that PHMSA initiate a review of all public education programs. 

Likewise, consideration of pipeline leak history is an important 

factor in an operator’s integrity management plan. But in a 2004 

Kingman, Kansas, pipeline rupture, we discovered that the operator left out the leak history. PHMSA did not identify that history 

in their oversight, resulting in a deferred inspection. The pipeline 

ruptured 2 years before it was scheduled for an inspection. 

In 2009, in Palm City, Florida, an 18-inch diameter gas transmission pipeline ruptured in the busy Florida Turnpike right of 

way. Luckily, there were no fatalities. But, as you can see from this 

photograph, the explosion created a crater over 110 feet long and 

17 feet wide. The pipeline operator had not properly identified this 

location, and it was not covered in their integrity management 

plan. We’re still investigating this accident to determine the cause 

of this oversight. 

As a result of these accidents and other investigations, the NTSB 

believes that PHMSA must establish a more aggressive oversight 

framework so that risk-based integrity management programs are 

not only effectively designed, but effectively executed as well. 

We have a strong working relationship with PHMSA, and we 

find PHMSA in most cases to be a responsive partner in protecting 

the public wellbeing. However, as I stated today, there are a few 

issues that remain of concern to the NTSB, which we hope to see 

PHMSA address in the near future. 

Thank you, and I look forward to answering your questions. 

[The prepared statement of Ms. Hersman follows:] 

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

NATIONAL TRANSPORTATION SAFETY BOARD

Introduction/Overview 

Chairman Lautenberg, Ranking Member Thune, members of the Subcommittee, 

thank you for the opportunity to address you today on the reauthorization of the 

U.S. Department of Transportation’s (DOT) Pipeline and Hazardous Materials Safety Administration (PHMSA). PHMSA has made significant progress over the past 

5 years. Much of the credit for this success is due to the implementation of statutory 

mandates included in the Pipeline Safety Improvement Act of 2002, as well as the 

Pipeline, Inspection, Protection, Enforcement and Safety (PIPES) Act of 2006. 

PHMSA has been responsive to the National Transportation Safety Board’s 

(NTSB) pipeline safety recommendations. Between January 1, 2002, and June 1, 

2010, the NTSB issued twenty-four pipeline recommendations to PHMSA. As of this 

date, nine remain open and fifteen have been closed following a NTSB assessment 

that PHMSA had taken an ‘‘acceptable action’’ or ‘‘acceptable alternate action’’ in 

response to the recommendation. None were closed with the categorization of ‘‘unacceptable action.’’ Additionally, only one recommendation issued prior to 2002 remains open. 

Noteworthy accomplishments by PHMSA include implementing regulations addressing integrity management programs for gas transmission pipelines, hazardous 

liquid pipelines, and natural gas distribution pipeline systems. Regulations and improved industry practices also are in place for expanded public awareness and education programs meant to heighten the awareness of the American public and regional emergency response agencies. The implementation of the 811 one-call system 

requires the identification and marking of buried pipelines before excavation work 

occurs. 

14 

Additionally, partnerships between the industry and PHMSA have led to a number of joint initiatives, such as development of training programs for public and municipal officials, enhanced collection and analysis of accident data, and greater coordination with state agencies that have been delegated enforcement authority by 

PHMSA for Federal pipeline safety standards. 

As a result of the NTSB’s 2005 Safety Study, Supervisory Control and Data Acquisition (SCADA)in Liquid Pipelines, the Board issued Safety Recommendations P– 

05–1 through –3 which called on PHMSA to: (1) require hazardous liquid pipeline 

operators to follow the American Petroleum Institute’s recommended practice for the 

use of graphics on SCADA computer screens, (2) require pipeline companies to have 

a policy for the review and audit of SCADA alarms, and (3) require training for 

pipeline controllers to include simulator or noncomputerized simulations for controller recognition of abnormal operating conditions, particularly leak events. These 

three recommendations were also incorporated directly into the PIPES Act. PHMSA 

published a final rule on December 4, 2009, that included the recommended requirements and applied them to all pipeline systems. 

Despite these notable and varied accomplishments, NTSB has concerns about certain other aspects of PHMSA’s pipeline safety program. Two such areas specifically 

addressed in the PIPES Act are the regulation of low-stress pipeline systems and 

requirements for the use of excess flow valves. 

Regulation of Low-Stress Pipeline Systems 

Corrosion failures on the BP Exploration, Inc.’s, low-stress oil transit lines from 

the Prudhoe Bay oil fields to the Trans Alaska pipeline in 2006 raised concerns 

among Members of Congress about the potential pollution of environmentally sensitive areas. As a result, Congress included provisions in the PIPES Act mandating 

that PHMSA issue regulations subjecting low-stress hazardous liquid pipelines near 

unusually sensitive environmental areas to the same standards and regulations as 

other hazardous liquid pipelines. Low-stress pipelines are those that are operated 

at a stress level of 20 percent or less of their strength ratings. 

At the time the PIPES Act was enacted, Federal pipeline safety regulations only 

applied to low-stress pipelines that were located in populated areas, crossed navigable waterways, or carried highly volatile liquids, such as compressed liquefied propane. In a Notice of Proposed Rulemaking (NPRM), ‘‘Pipeline Safety: Protecting Unusually Sensitive Areas from Rural Onshore Hazardous Liquid Gathering Lines and 

Low-Stress Lines’’, published on September 6, 2006, PHMSA proposed regulations 

for rural low-stress pipelines that have a diameter of at least 85⁄8 inches and that 

are within 1⁄4 mile of an area defined as unusually sensitive. (The distance in the 

final rule is 1⁄2 mile.) 

The NPRM also proposed regulations for rural gathering lines that operate at a 

stress level greater than 20 percent, have a diameter between 65⁄8 and 85⁄8 inches 

and are within 1⁄4 mile of an area defined as unusually sensitive. A ‘‘gathering line’’ 

is a pipeline with a diameter of 85⁄8 inches or less that transports petroleum from 

a production facility. Again, at the time the PIPES Act was enacted, only gathering 

lines in populated areas were subject to Federal pipeline regulations. 

Exempted from the proposed requirements in the NPRM were gathering lines in 

the inlets of the Gulf of Mexico. Certain gathering lines in inlets of the Gulf of Mexico are subject to burial requirements to ensure that the lines are not exposed and 

do not pose a hazard to navigation. Otherwise, they are not regulated. 

In comments submitted by the NTSB on November 21, 2006, we note that most 

low-stress pipelines and on- and off-shore gathering pipelines would remain essentially unregulated. The NTSB also notes that the NPRM would apply a less stringent patchwork of requirements to address corrosion and excavation damages to 

those low-stress pipelines and gathering pipelines covered by the proposed standards. The NTSB states its belief that the standards codified in Title 49 Code of Federal Regulations, Part 195 for hazardous liquid pipelines should also apply in its entirety to the low-stress pipelines and gathering lines. PHMSA published the final 

rule on June 3, 2008, without significant change to the NPRM. Publication of this 

final rule concluded phase one of PHMSA’s two phase plan to implement its PIPES 

mandate to regulate low-stress pipelines. 

On June 22, 2010, PHMSA published a second NPRM regarding the regulation 

of all rural onshore hazardous liquid low-stress pipelines. This second NPRM represents phase two of PHMSA’s implementation of its mandate in the PIPES Act. In 

this NPRM, PHMSA proposes safety requirements for all rural low-stress pipelines 

not included under the phase one final rule. Specifically, the low-stress pipelines 

captured under the new NPRM include: (1) rural low-stress pipelines of a diameter 

less than 85⁄8 inches located in or within one-half mile of an unusually sensitive 

area and (2) all other rural low-stress pipelines that were not included under phase 

15 

one. PHMSA estimates that the NPRM will apply to 1,384 miles of low-stress pipelines not covered by the previous rule. It appears this latest NPRM will apply to 

onshore gathering lines that are also low-stress pipelines. However, the NPRM does 

not address gathering lines in the inlets of the Gulf of Mexico or offshore gathering 

lines. The NTSB has not had the opportunity to evaluate fully the specific requirements proposed in the NPRM; however, we will submit comments to PHMSA. 

The tragedy in the Gulf of Mexico involving the Deepwater Horizon drilling platform is a grim reminder of the damage that a major oil spill can cause. While the 

magnitude of the Deepwater Horizon spill is far greater than any known pipeline 

failure, the events in the Gulf should remind those involved in the pipeline industry 

that all pipelines must be sufficiently safeguarded and regulated in order to protect 

the public and the environment. 

Integrity Management Programs for Distribution Systems and the Use of 

Excess Flow Valves 

The PIPES Act also mandates that DOT prescribe minimum standards for integrity management programs for distribution pipeline systems. On June 25, 2008, 

PHMSA published a NPRM, ‘‘Integrity Management Program for Gas Distribution 

Pipelines,’’ with proposed regulations that would require operators of gas distribution pipelines to develop and implement integrity management programs with the 

same objectives as the existing integrity management programs for hazardous liquid 

and gas transmission pipelines. 

Integrity management programs for hazardous liquid and gas transmission pipelines typically require operators to assess the condition of their pipelines by using 

‘‘in-line’’ inspection tools that travel through the pipeline to determine the nature 

and extent of any defects or pressure testing that yields information about the integrity of the pipeline. Such techniques are not feasible for typical distribution pipeline 

systems because of the differences in the design and operating parameters between 

distribution pipeline systems and hazardous liquid and gas transmission pipelines. 

Further, the failure of a distribution pipeline is often initially detected from reports of a gas leak rather than a catastrophic rupture. As result, development and 

implementation of an effective leak management program is an important element 

of an integrity management program for a distribution pipeline. 

PHMSA acknowledged these differences in the NPRM and properly emphasized 

the importance of various leak detection methods as essential elements of an integrity management program for distribution pipeline systems. 

In its comments on the NPRM, the NTSB emphasized that while an effective leak 

detection program is a crucial element of the overall leak management program, the 

use of equipment that prevents or mitigates leaks is equally important. One such 

device that mitigates a gas pipeline leak is an ‘‘excess flow valve.’’ An excess flow 

valve is a device installed on the distribution line, usually serving a user residence 

or facility, that detects an abnormally high flow rate, and when an excess flow is 

detected, automatically closes a valve, thus shutting off the flow of gas through the 

distribution line. The NPRM did not adequately address this aspect of leak management, other than incorporating the mandate for PHMSA to require excess flow 

valves on new or replacement distribution lines serving single-family residences. 

PHMSA complied with this provision of the PIPES Act on December 4, 2009, when 

it published the final rule on integrity management programs for distribution pipeline systems. 

The NTSB has long advocated the use of excess flow valves in gas distribution 

pipeline systems as an effective means of preventing explosions caused by natural 

gas leaking from distribution systems. On July 7, 1998, a natural gas explosion and 

fire destroyed a newly constructed residence in South Riding, Virginia, a suburb of 

Washington. The accident caused one fatality and one serious injury. The NTSB determined that the gas service line to the home had failed and that an uncontrolled 

release of gas had accumulated in the basement and subsequently ignited. The 

NTSB concluded from its investigation that had an excess flow valve been installed 

in the service line, the valve would have closed shortly after the hole in the service 

line developed and the explosion likely would not have occurred. The NTSB recommended that PHMSA require excess flow valves be installed in all new and renewed gas service lines, regardless of a customer’s classification, when the operating 

conditions are compatible with readily available valves. The NTSB believes that 

apartment buildings, other multifamily dwellings, and commercial properties are 

susceptible to the same risks from leaking gas lines as single-family residences, and 

we believe this gap in the law and the regulations should be eliminated. 

16 

Oversight of Integrity Management and Other Risk-Based Pipeline Safety 

Programs 

Over the past decade or more, PHMSA has adopted a risk-based assessment approach for regulating the DOT pipeline safety program. PHMSA has successfully 

built a partnership with various facets of the pipeline industry to develop, implement and execute a multi-part pipeline safety program. All stakeholders, including 

PHMSA, have, in the NTSB’s view, come to rely heavily upon this approach. The 

NTSB believes that a risk-based approach can be an effective method to develop and 

execute the pipeline safety program, and there are many positive elements to 

PHMSA’s approach. 

The DOT pipeline safety regulations based on risk assessment principles provide 

the structure, content, and scope for many aspects of the overall pipeline safety program. Within this regulatory framework, pipeline operators have the flexibility and 

responsibility to develop their individual programs and plans, determine the specific 

performance standards, implement their plans and programs, and conduct periodic 

self-evaluations that best fit their particular pipeline systems. PHMSA likewise has 

the responsibility to review pipeline operators’ plans and programs for regulatory 

compliance and effectiveness. 

The NTSB believes that with the risk-based assessment there should be increased 

responsibilities on both the individual pipeline operators and PHMSA. Operators 

must diligently and objectively scrutinize the effectiveness of their programs, identify areas for improvement, and implement corrective measures. PHMSA, as the 

regulator, must also do the same in its audits of the operators’ programs and in selfassessments of its own programs. In short, both operator and regulator need to 

verify whether risk-based assessments are being executed as planned, and more importantly, whether these programs are effective. 

In its recent pipeline investigations, the NTSB discovered indications that 

PHMSA and operator oversight of risk-based assessment programs, specifically integrity management programs and public education programs, has been lacking and 

has failed to detect flaws and weaknesses in such programs. 

In its investigation of the October 2004, rupture of an anhydrous ammonia pipeline near Kingman, Kansas, the NTSB identified deficiencies in PHMSA’s auditing 

procedures when evaluating the operator’s integrity management program. The operator did not include assessments of leak history when calculating relative risk 

scores for various segments of the pipeline. These relative risk scores were used to 

establish an initial baseline assessment of the integrity of the pipeline in the decisionmaking process for prioritizing the inspection schedule. Though PHMSA did find 

omissions of other risk factors during its review of the operator’s integrity management program, PHMSA did not identify the omission of the leak history data during 

its initial review or during a subsequent review of the corrected plan. Consequently, 

the ruptured pipeline segment was not scheduled for a baseline assessment until 

2006, almost 2 years after the October 27, 2004, rupture. The NTSB recommended 

that PHMSA require an operator to revise its pipeline risk assessment plan whenever it has failed to consider one or more risk factors that can affect pipeline integrity. 

The November 1, 2007, rupture of a propane pipeline in Carmichael, Mississippi, 

resulted in two fatalities, seven injuries, and property damage exceeding $3 million. 

Before the accident, the pipeline operator relied upon contractors to obtain accurate 

mailing data and ensure that mailings to the public were completed. However, the 

operator did not perform oversight to ensure that all appropriate recipients were on 

the mailing lists and that the mailings met appropriate regulatory requirements. 

The operator also had not taken any action to determine whether recipients who received the mailings understood the guidance they contained. The NTSB determined 

that the pipeline operator failed to properly assess its public awareness and education program by relying upon contractors without appropriate oversight. The 

NTSB recommended that PHMSA initiate a program to evaluate pipeline operators’ 

public education programs, including the operators’ self-evaluations of the effectiveness of their public education programs. 

On May 4, 2009, an 18-inch diameter gas transmission pipeline with an operating 

pressure of 850 psi ruptured near Palm City, Florida. The rupture was located in 

the Florida Turnpike right-of-way, between I–95 and the Florida Turnpike. The 

turnpike and interstate were closed for approximately 3 hours due to the accident. 

Two gas transmission pipelines operated by the same pipeline company were also 

located in the right-of-way but were reportedly not damaged. 

The force of the released gas created a crater approximately 116.5 feet long by 

17 feet wide by approximately 2.8 feet deep. Roughly 104 feet of the pipe was ejected from the ruptured pipeline and landed next to the crater. The closest edge of the 

17 

crater was approximately 25 feet from the northbound paved edge of the Florida 

Turnpike. 

There was no ignition of the released gas, and no fatalities were reported. However, two people were injured when their car reportedly hit debris, ran off the road, 

and turned over; a Deputy Sheriff was hospitalized after walking through a gas 

cloud; and the accident resulted in the evacuation of a nearby school and residential 

community. 

The NTSB’s ongoing investigation has determined that at the time of the accident, 

the operator had not identified the ruptured segment as located within a high consequence area, and therefore not covered by the operator’s integrity management 

plan. However, an independent evaluation done by PHMSA at the NTSB’s request 

shows the segment in fact is in a high consequence area. The NTSB is collecting 

documentation that will determine the cause of this error. 

As a result of these investigations, the NTSB is concerned that the level of selfevaluation and oversight currently being exercised is not uniformly applied by some 

pipeline operators and PHMSA to ensure that the risk-based safety programs are 

effective. The NTSB believes that to ensure effective risk-based integrity management programs are employed throughout the pipeline industry, PHMSA must establish an aggressive oversight program that thoroughly examines each operator’s decisionmaking process for each element of its integrity management program. 

Recent Accidents in Texas 

The two most recent pipeline accidents in Cleburne, Texas and Darrouzett, Texas, 

involved third-party excavation damage resulting in ruptures, fires, and explosions. 

Preliminary information from both investigations indicates that prior to the start of 

excavation activities, neither pipeline was marked or identified. Both investigations 

will determine the reasons why and how these lapses occurred. 

Cleburne, TX Summary 

On June 7, 2010, a natural gas transmission pipeline measuring 36-inches in diameter near Cleburne, Texas was struck and ruptured by a contractor for an electrical cooperative that was installing a pole for a power line. One member of the 

contractor’s crew was drilling a hole while operating an auger affixed to a truck 

when the auger struck and punctured the transmission pipeline. An ignition and explosion of the escaping gas resulted, and the operator of the auger was killed. Six 

other crewmen were hospitalized. 

The accident pipeline had a nominal wall thickness of 0.5-inch. The pipeline was 

operating at 950 psi at the time of the accident. The maximum allowable operating 

pressure is 1,050 psi. The pipeline, constructed in 1971, is 388 miles long, originating in Coyanosa, Texas and terminating in Ennis, Texas. 

A second pipeline operated by a different pipeline company also traversed the accident area. Workmen in the area reported that they saw markers for the second 

pipeline. A NTSB investigator and Texas Railroad Commission personnel visiting 

the site also observed markers for the second pipeline, but the ruptured pipeline 

was not marked. 

The NTSB is currently investigating this accident with the assistance of PHMSA 

and the Texas Railroad Commission (the state regulatory agency for pipeline safety). 

Darrouzett, TX Summary 

(The NTSB delegated the on-scene investigation of this accident to the Texas Railroad Commission, which is the state agency responsible for regulation of intrastate 

pipelines.) 

On June 8, 2010, a natural gas nonregulated gathering line measuring 14-inches 

was struck by a third-party contractor near Darrouzett, Texas. The maximum allowable operating pressure of the gathering line was 700 psi; the line was operating 

at approximately 500 psi. The line begins in Follett, Texas, travels into Oklahoma, 

continues west and then returns to Texas near the Hansford/Sherman County area. 

The line is fed by many gathering lines in the area and ends at the plant in Sherman, Texas. 

At the time of the incident, six contractor personnel were working in the area. 

Two persons were killed, one critically injured, and three others escaped injury. A 

bulldozer working in a caliche pit struck the 14-inch natural gas pipeline sometime 

before 4 p.m. The pipeline operator’s SCADA system picked up a pressure loss and 

began closing valves to isolate the ruptured section of the pipeline. The fire was extinguished by 8 p.m. 

Preliminary information from the Texas Railroad Commission indicates that the 

excavator had not requested a permit to work in the area or that there were any 

pipeline markers at the accident scene. The accident gathering line is not regulated 

under DOT pipeline regulations. 

18 

PHMSA accident statistics over the past decade (2000–2009), identify corrosion as 

the leading cause of all reported pipeline accidents. The second leading reported 

cause is damage from third-party excavators. Despite the focus on one-call systems, 

marking of pipelines prior to excavation, and other measures, the two accidents in 

Texas are a reminder that excavation damage remains a serious concern. 

Closing 

In summary, PHMSA has made great strides in addressing a number of matters 

mandated by Congress in the Pipeline Safety Improvement Act of 2002, as well as 

the Pipeline, Inspection, Protection, Enforcement and Safety Act of 2006. The NTSB 

believes more can be done in these areas and looks forward to a constructive dialogue with PHMSA and DOT as we advance the interests of pipeline safety, and 

thus the safety of people living and working near, and receiving service from, our 

Nation’s pipelines. 

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

may have. 

Senator LAUTENBERG. Thank you very much. 

We are alerted to the fact that at about 3 o’clock a vote may 

occur, so we’ll try to stick to our time limitations here. 

Ms. Quarterman, despite the moratorium on offshore drilling, today’s New York Times reports that BP is planning to move forward 

with a risky drilling project off the coast of Alaska. This is at a 

depth of 24,000 feet and several miles of horizontal pipe to connect 

to the TransCanada Pipeline. In May your agency warned BP that 

it was in probable violation of Federal standards because of corrosion on the Endicott Pipeline to which this new project connects. 

Given BP’s track record of irresponsibility and carelessness, do 

you think that this project should be stopped? 

Ms. QUARTERMAN. Mr. Chairman, as you’re aware, PHMSA is responsible for pipeline safety regulations. We are not responsible for 

the actual project that’s at issue here in the North Slope. I believe 

that is within the Department of Interior’s jurisdiction. 

I can tell you that, as a result of the Deepwater Horizon incident, 

we at PHMSA have taken a very strong look at BP, and within the 

past couple of weeks I have spoken with, met with, the President 

of BP North America Pipelines and explained to him that we would 

be looking very closely at their program, we would be doing an integrated inspection of their entire system, and that we are going 

to be very focused over the next year looking at them. 

With respect to the particular pipeline at issue, I believe that we 

have issued a warning letter to BP with respect to the Endicott 

Pipeline on the North Slope, and they have sent in a response. We 

are planning a field inspection this year to verify whether or not 

that has been adequately addressed. 

Senator LAUTENBERG. We have to be on constant alert there. 

Ms. QUARTERMAN. Absolutely. 

Senator LAUTENBERG. Ms. Hersman, PHMSA is responsible for 

overseeing pipeline construction and transportation, while the Federal Energy Regulatory Commission is responsible for approving 

the location of the pipeline. I ask you and I’ll ask Ms. Quarterman, 

how can communities best determine the real impact of a proposed 

pipeline when two agencies with different regulations are responsible for overseeing pipelines? 

Ms. HERSMAN. Mr. Chairman, the Safety Board has not investigated any accidents where the siting has been a particular issue, 

but we have investigated a number of accidents where we expressed concern about pipeline issues. A proposed pipeline between 

19 

New Jersey and Manhattan, just like any other pipeline, deserves 

attention. It’s going to be in a high-consequence area. It’s a very 

populous urban area. There are potentially going to be three river 

crossings. There are many challenges with respect to siting any 

pipeline in those kinds of conditions. 

We would want to make sure that they have adequate remote 

control shutoff valves, that they have corrosion detection, and that 

the pipeline is marked. I would defer to Administrator Quarterman 

on how they would oversee that construction. 

Senator LAUTENBERG. Yes. The question is one of approving the 

location. How can we get that done when two agencies with different regulations are responsible? Ms. Quarterman? 

Ms. QUARTERMAN. As I’m sure you’re aware, the FERC is responsible for siting of natural gas pipeline facilities and we at PHMSA 

on the staff level try to work closely with them in helping their 

evaluation. We do have state contacts that go out to their hearings, 

their public hearings, and answer any safety-related questions. 

However, not having jurisdiction over the siting portion of that, we 

really cannot speak to the siting issues. We try to coordinate with 

FERC as much as possible. I’m scheduled to meet with the chairman the beginning of next month. 

Senator LAUTENBERG. Ms. Hersman, in quick form, the NTSB 

has long recommended the installation of excess flow valves on all 

new and renewed natural gas service lines. In 2006, in the PIPES 

Act, I included the requirement that excess flow valves be installed 

on gas lines that serve single-family homes. How can excess flow 

valves be effectively installed in apartment buildings or multiple 

dwellings and commercial buildings? 

Ms. HERSMAN. Mr. Chairman, in quick order, the Safety Board 

thinks that excess flow valves should be installed as widely as possible, including multi-dwelling residences, such as apartment buildings, and commercial and industrial facilities. That is the only recommendation prior to 2002 that remains in an open status to 

PHMSA, because, even though the PIPES Act required single-family dwellings to be equipped, we think that requirement doesn’t go 

far enough and we’d like to see it universally applied. 

Senator LAUTENBERG. We need your help there. 

Senator Johanns. 

Senator JOHANNS. Thank you, Mr. Chairman. 

The mission statement of the Office of Pipeline Safety indicates 

that environmental safety is within their jurisdiction. In fact, 

quoting from that mission statement, it says: ‘‘OPS is the primary 

Federal regulatory agency responsible for ensuring the safe, reliable, and environmentally sound operation of America’s energy 

pipelines.’’ 

Mr. Weimer—and I hope I’m pronouncing that correctly—in his 

testimony says that he’s concerned that PHMSA is not involved 

enough in the siting and environmental review process and expresses that concern. In fact, I think he even uses the words that 

it’s ‘‘disconnected.’’ 

Now, as I said in my opening statement, there’s a pipeline 

project coming through Nebraska. Part of it goes over the Ogallala 

Aquifer. I’m very familiar with that. I can tell you that in some 

areas the water table is high enough where if you dug a fencepost 

20 

hole, if you know what I’m talking about, it would fill with water. 

So you worry that that pipe literally is transmitting oil right 

through the water table right over the Ogallala Aquifer. 

What assurance can you give me—and then I want to add one 

other qualifier. I understand that this project involves a Canadian 

company, so I think this is managed or oversight is provided by the 

Department of State, further complicating matters. Tell me how 

PHMSA fits into this and what kind of oversight you would provide? Do you feel like you’ve been a player in this process? 

Ms. QUARTERMAN. I believe you’re referring to the TransCanada 

Keystone XL Project. 

Senator JOHANNS. Right. 

Ms. QUARTERMAN. And that is one that originates in Canada and 

comes down to the United States through your state. Within the 

United States, the FERC does have jurisdiction over siting of gas 

pipelines. However, it does not have jurisdiction over the siting of 

hazardous liquids pipelines under the Interstate Commerce Act. So 

the only authority, other than the states, at a Federal level who 

has any oversight into the siting of that project would be the Department of State. Because it does cross international lines, they 

have to provide a Presidential permit to be able to cross the border, 

and they are doing any environmental analysis associated with 

that. 

Again, we would coordinate with them in terms of providing comments, but we are not a cooperating agency with them on their environmental impact statement. So our obligations would be, once 

the Department of State has approved this Presidential permit and 

the siting with the states, to ensure that the pipeline project, once 

it starts going into the ground, is safe in terms of the construction, 

the operation, the maintenance of the pipeline. 

Senator JOHANNS. I must admit—and I’m not making any claims 

about this being unsafe. Maybe it’s the safest pipeline ever going 

to be constructed in world history. But having said that, when I 

think of the State Department I think of them doing many great 

things. I’m not sure environmental assessment would have come to 

mind until I learned about this project. I think you’re probably 

agreeing with me. 

How can I assure Nebraska residents that an appropriate assessment has been done? Because I think of all of the expertise relative 

to pipelines in the Federal Government, I can’t imagine it would 

be at the State Department. 

Ms. QUARTERMAN. Well, I think that Nebraska, as a state, has 

a role to play in this process, certainly being involved in any 

scoping meetings that may go and getting the Nebraska authorities 

involved in siting of the project and determining whether or not the 

right of way is appropriate. That would be the only advice I could 

give at that level. 

Senator JOHANNS. Are you Mr. Chairman? 

STATEMENT OF HON. JOHN THUNE, 

U.S. SENATOR FROM SOUTH DAKOTA 

Senator THUNE [presiding]. I guess so. 

Senator JOHANNS. Gosh, that’s surprising. 

Senator THUNE. That’s quite a thought. 

21 

Senator JOHANNS. I have run out of time, but let me just wrap 

up and say, none of this is very reassuring to me, and you understand why. This is a big project with significant issues. We’ve got 

a very, very important natural resource, and I just want to make 

sure it’s properly assessed and protected, so when I’m asked about 

it I can say either you have something to worry about or you have 

nothing to worry about. 

Senator THUNE. Senator Hutchison. 

STATEMENT OF HON. KAY BAILEY HUTCHISON, 

U.S. SENATOR FROM TEXAS 

Senator HUTCHISON. Thank you, Mr. Chairman. I’m sorry I was 

late because we had an Appropriations Committee hearing. 

But I wanted to just say a couple of things. In the past few 

weeks, Texas has had two major fatal pipeline accidents, both of 

which were excavation accidents. Any excavation accident is a preventable one. So I wanted to ask you basically two questions. One 

is, do you think that we can improve on the One-Call system? Are 

there a number of states that don’t participate in the One-Call system? And should we be doing something about that, to stop having 

exemptions from the One-Call system? That would be number one. 

Number two, I’ll submit my opening statement for the record, but 

the other thing of course, representing a coastal state, that I worry 

about is that the Pipeline Hazardous Materials Safety Administration regulates offshore transmission lines in state waters, but the 

Minerals Management Service has jurisdiction for offshore pipelines in the outer continental shelf. So I’m concerned that regulations might not be uniform, that there might be confusion when 

there is an accident about who does what. Is that a concern in your 

opinion, Ms. Quarterman or Ms. Hersman, and should we be dealing with that in this authorization? 

Ms. QUARTERMAN. Well, first let me speak to the excavation 

damage issue. I fully agree with you that those two incidents were 

absolutely preventable and, had all the correct steps been taken 

both by the people excavating to call and the people owning the 

pipeline to mark the line and mark it correctly, that those incidents 

would not have occurred. 

Since the PIPES Act of 2006, in about 2007, PHMSA worked to 

create the National 811 Number and has been providing funding 

to the Common Ground Alliance, which deals not only with pipelines but with other underground utilities, to support publishing information. 

Senator HUTCHISON. What is the participation level of states? Is 

it high or is it low? 

Ms. QUARTERMAN. The states are actually very, very much participating at a high level. Unfortunately, there are some states that 

have the exemptions that you refer to, and I have to say during my 

speeches to all the organizations that might be affected by this I 

repeatedly tell them the exemptions are not something that we believe are appropriate. For example, with respect to the State of 

Maryland, they were very recently creating a One-Call law and 

they were going to exempt the Department of Transportation. We 

called and talked to them and were able to help them come to the 

conclusion that wasn’t the right decision. 

22 

We have a lot of work to do on some states. Some states are 

doing a fantastic job. But it is a gradual process. I think we could 

be doing a lot more if we had more funding on this. We are providing state damage prevention grants of about $2 million a year 

to all the states who come and request money to work on damage 

prevention. We also have $1 million in One-Call grants that go to 

the States as well. So there’s a lot being done, but obviously until 

8-1-1 becomes recognized the same as 9-1-1 we would not have 

done our job completely. 

Senator HUTCHISON. On the coastal issue? 

Ms. QUARTERMAN. Yes, on the coastal issue, the jurisdiction is 

somewhat confusing. PHMSA has two memoranda of understanding with the Department of Interior and with the Coast 

Guard and also with EPA with respect to, for example, oil spill response. One memorandum of understanding divides the authority 

on who should get oil spill response plans between those different 

agencies, and PHMSA gets the plans for onshore pipelines and 

MMS gets it for offshore pipelines and other offshore facilities. I 

think that maybe there’s a piece of legislation under consideration 

to change that. 

With respect to the jurisdiction over pipelines on the outer continental shelf, MMS has jurisdiction over those that are production 

pipelines, production-related facilities. PHMSA has those that are 

on the outer continental shelf that are transportation-related and 

the states have those that are in state water. 

Senator HUTCHISON. Yes, I know. My time is up, so I won’t pursue it further. But any input you can offer on this reauthorization 

that would help with those conflicts, I would appreciate. 

Thank you, Mr. Chairman. 

[The prepared statement of Senator Hutchison follows:] 

PREPARED STATEMENT OF HON. KAY BAILEY HUTCHISON, SENATOR FROM TEXAS

Thank you, Senator Lautenberg, and thank you for holding this afternoon’s hearing. It is certainly timely. The ongoing Deepwater Horizon crisis in the Gulf is an 

unfortunate wake-up call not only to oil production safety, but to the safety of the 

Nation’s vast oil and gas pipeline system. While the safety record for pipelines has 

continued to improve, particularly when viewed in terms of exposure, it is important 

for our Committee to consider what more needs to be done as we begin the process 

of reauthorizing the Pipeline and Hazardous Materials Safety Administration, 

whose current authorization expires in September. 

I also want to welcome of all our witnesses today. I will not be able to stay for 

the entire hearing, but will likely have follow-up questions for the witnesses after 

the hearing. 

The oil and gas industry is a foundation of the Texas economy, and contributes 

greatly to the quality of life all Americans enjoy. Texas produces one quarter of the 

Nation’s refined petrochemical products, and 30 percent of the Nation’s natural gas 

supplies. It is not surprising, then, that Texas has more miles of pipeline than any 

other State—over 220,000 miles, located both on-shore and in the Gulf of Mexico. 

My constituents, therefore, have a very direct stake in pipeline safety. 

In just the past few weeks, there have been two deadly gas pipeline accidents in 

Texas, both of which resulted from pipeline damage during excavation work. The 

accidents highlight the need to focus more attention on the national ‘‘One-Call’’ program. Every accident caused by excavation is a preventable accident, and I want 

to ensure to the extent I can, that the Texas Excavation Safety System (TESS), and 

the One-Call systems in other States, are consulted by all developers, construction 

companies, and others with a need to dig in the vicinity of a pipeline. ‘‘Call before 

you dig’’ can mean the difference of life or death. 

Because of the Deepwater oil spill, I—and probably many of my colleagues—will 

also want to learn more about the safety regulations that apply to off-shore pipeVerDate Nov 24 2008 07:17 Jul 12, 2011 Jkt 067270 PO 00000 Frm 00026 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\67270.TXT SCOM1 PsN: JACKIE
23 

lines. For example, does it makes sense for PHMSA (fim-za) to regulate off-shore 

transmission lines in state waters, while the Minerals Management Service (MMS) 

has jurisdiction for off-shore pipelines in the Outer Continental Shelf? I am concerned that regulations may not be uniform and that in the event of an accident, 

there could be confusion about who is in charge. I would also like to understand 

what PHMSA, MMS, and the pipeline companies are doing to address the unique 

environment for underwater pipelines, including corrosion, and threats caused by 

vessels and hurricanes. 

The last two reauthorizations of PHMSA have transformed how pipelines are regulated in this country, from a system of traditional enforcement by Federal and 

State inspectors, to a system built on ‘‘integrity management′′. Under integrity management, inspectors still conduct inspections, but the pipeline owners themselves 

must take responsibility for inspecting and making repairs to critical portions of 

their lines on a scheduled basis. Integrity management appears to be working well, 

but I will be interested in learning whether all of our panelists today agree. 

Finally, I am interested the witnesses’ recommendations, in particular those of 

Ms. Quarterman, for reauthorizing PHMSA. I hope the Administration will be sending Congress a formal proposal in the very near term. Thank you, Mr. Chairman. 

Senator THUNE. Thank you, Senator Hutchison. 

Let me, until the Chairman gets back from the vote, hopefully 

in the next few minutes, ask a couple of questions, and then I’m 

going to have to run and vote, too. But I do want to thank you for 

appearing here today. 

Pipeline transportation is crucial to our Nation’s economy. Without it, we don’t have a way of meeting the energy needs of American homes and businesses. I think pipelines are going to play an 

important role in America’s energy future, too. In South Dakota, as 

has already been referenced, the first of two TransCanada Pipelines was recently completed and is now transporting crude oil 

from Canada to markets in the Midwest. The second one, Keystone 

XL, is currently awaiting approval and could start construction as 

early as next summer, and once completed this pipeline is going to 

transport crude oil to markets in Oklahoma and the Gulf. So I 

want to come back to a question in just a moment about that. 

But another area of interest that I think is important in terms 

of America’s future energy requirements and our capability to meet 

those requirements is the development of some of these specialized 

pipelines to transport ethanol and biofuels. There’s a company in 

South Dakota called POET, which is the world’s largest producer 

of ethanol, and Magellan Midstream Partners, who together have 

proposed the construction of a 1,700-mile ethanol pipeline from 

South Dakota to the East Coast. Moving ethanol by pipeline would 

be cheaper, more efficient, and safer than moving the product by 

truck or rail as it is done today. I think that this ambitious and 

innovative proposal is very encouraging and exciting, particularly 

as we try to chart a course toward energy independence. 

So a couple of questions on those subjects. One dealing with Keystone pipeline I would direct to you, Ms. Quarterman, and that is 

what requirements did PHMSA impose on Keystone in approving 

Keystone’s request to operate the pipeline at a higher than normal 

pressure? 

Ms. QUARTERMAN. Are you referring to Keystone 1? 

Senator THUNE. Keystone 1. Well, Keystone 1 is the one that’s 

completed. 

Ms. QUARTERMAN. Yes. 

Senator THUNE. So focus on that, because Keystone 2 is still in 

the process. 

24 

Ms. QUARTERMAN. We are actually reviewing a request for Keystone XL to have the same authorities. With respect to Keystone 

1, there were additional requirements on that pipeline. I don’t 

know them off the top of my head. I will have to provide you those 

for the record, but there were additional requirements. 

[The information referred to follows:] 

DEPARTMENT OF TRANSPORTATION

PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION (PHMSA) 

Special Permit 

Docket Number: PHMSA–2006–26617 

Pipeline Operator: TransCanada Keystone Pipeline, L.P. 

Date Requested: November 17, 2006 

Code Section(s): 49 CFR 195.106 

Grant of Special Permit 

Based on the findings set forth below, the Pipeline and Hazardous Materials Safety Administration (PHMSA) grants this special permit to TransCanada Keystone 

Pipeline, L.P. (Keystone). This special permit allows Keystone to design, construct 

and operate two new crude oil pipelines using a design factor and operating stress 

level of 80 percent of the steel pipe’s specified minimum yield strength (SMYS) in 

rural areas. The current regulations in 49 CFR 195.106 limit the design factor and 

operating stress level for hazardous liquids pipelines to 72 percent of SMYS. This 

special permit is subject to the conditions set forth below. 

Except for the non-covered portions of the pipelines described below, this special 

permit covers two proposed pipelines in the United States: 

• The 1,025-mile, 30-inch, Mainline from the Canadian border at Cavalier County, North Dakota, traversing the States of South Dakota, Nebraska, Kansas and 

Missouri, to Wood River, Illinois; and 

• The 291-mile, 36-inch, Cushing Extension from Jefferson County, Nebraska, 

through Kansas, to Cushing (Marion County), Oklahoma. 

This special permit does not cover certain portions of the Mainline and Cushing 

Extension pipelines. These non-covered portions are the following: 

• Pipeline segments operating in high consequence areas (HCAs) described as 

commercially navigable waterways in 49 CFR 195.450; 

• Pipeline segments operating in HCAs described as high population areas in 49 

CFR 195.450; 

• Pipeline segments operating at highway, railroad and road crossings; and 

• Piping located within pump stations, mainline valve assemblies, pigging facilities and measurement facilities. 

For the purpose of this special permit, the ‘‘special permit area’’ means the area 

consisting of the entire pipeline right-of-way for those segments of the pipeline that 

will operate above 72 percent of SMYS. 

Findings 

PHMSA finds that granting this special permit to Keystone to operate two new 

crude oil pipelines at a pressure corresponding to a hoop stress of up to 80 percent 

SMYS is not inconsistent with pipeline safety. Doing so will provide a level of safety 

equal to, or greater than, that which would be provided if the pipelines were operated under existing regulations. We do so because the special permit analysis shows 

the following: 

• Keystone’s special permit application describes actions for the life cycle of each 

proposed pipeline addressing pipe and material quality, construction quality 

control, pre-in service strength testing, the Supervisory Control and Data Acquisition (SCADA) system inclusive of leak detection, operations and maintenance 

and integrity management. The aggregate affect of these actions and PHMSA’s 

conditions provide for more inspections and oversight than would occur on pipelines installed under existing regulations; and 

25 

• The conditions contained in this special permit grant require Keystone to more 

closely inspect and monitor the pipelines over its operational life than similar 

pipelines installed without a special permit. 

Conditions 

The grant of this special permit is subject to the following conditions: 

1. Steel Properties: The skelp/plate must be micro alloyed, fine grain, fully 

killed steel with calcium treatment and continuous casting. 

2. Manufacturing Standards: The pipe must be manufactured according to 

American Petroleum Institute Specification 5L, Specification for Line Pipe (API 

5L), product specification level 2 (PSL 2), supplementary requirements (SR) for 

maximum operating pressures and minimum operating temperatures. Pipe carbon equivalents must be at or below 0.23 percent based on the material chemistry parameter (Pcm) formula. 

3. Transportation Standards: The pipe delivered by rail car must be transported 

according to the API Recommended Practice 5L1, Recommended Practice for 

Railroad Transportation of Line Pipe (API 5L1). 

4. Fracture Control: API 5L and other specifications and standards address the 

steel pipe toughness properties needed to resist crack initiation. Keystone must 

institute an overall fracture control plan addressing steel pipe properties necessary to resist crack initiation and propagation. The plan must include acceptable Charpy Impact and Drop Weight Tear Test values, which are measures of 

a steel pipeline’s toughness and resistance to fracture. The fracture control plan, 

which must be submitted to PHMSA headquarters, must be in accordance with 

API 5L, Appendix F and must include the following tests: 

a. SR 5A—Fracture Toughness Testing for Shear Area: Test results must 

indicate at least 85 percent minimum average shear area for all X–70 heats 

and 80 percent minimum shear area for all X–80 heats with a minimum 

result of 80 percent shear area for any single test. The test results must 

also ensure a ductile fracture; 

b. SR 5B—Fracture Toughness Testing for Absorbed Energy; and 

c. SR 6—Fracture Toughness Testing by Drop Weight Tear Test: Test results must be at least 80 percent of the average shear area for all heats 

with a minimum result of 60 percent of the shear area for any single test. 

The test results must also ensure a ductile fracture. 

The above fracture initiation, propagation and arrest plan must account for the 

entire range of pipeline operating temperatures, pressures and product compositions planned for the pipeline diameter, grade and operating stress levels, including maximum pressures and minimum temperatures for startup and shut 

down conditions associated with the special permit area. If the fracture control 

plan for the pipe in the special permit area does not meet these specifications, 

Keystone must submit to PHMSA headquarters an alternative plan providing 

an acceptable method to resist crack initiation, crack propagation and to arrest 

ductile fractures in the special permit area. 

5. Steel Plate Quality Control: The steel mill and/or pipe rolling mill must incorporate a comprehensive plate/coil mill and pipe mill inspection program to check 

for defects and inclusions that could affect the pipe quality. This program must 

include a plate or rolled pipe (body and all ends) ultrasonic testing (UT) inspection program per ASTM A578 to check for imperfections such as laminations. 

An inspection protocol for centerline segregation evaluation using a test method 

referred to as slab macro-etching must be employed to check for inclusions that 

may form as the steel plate cools after it has been cast. A minimum of one 

macro-etch or a suitable alternative test must be performed from the first or 

second heat (manufacturing run) of each sequence (approximately four heats) 

and graded on the Mannesmann scale or equivalent. Test results with a 

Mannesmann scale rating of one or two out of a possible five scale are acceptable. 

6. Pipe Seam Quality Control: A quality assurance program must be instituted 

for pipe weld seams. The pipe weld seam tests must meet the minimum requirements for tensile strength in API 5L for the appropriate pipe grade properties. 

A pipe weld seam hardness test using the Vickers hardness testing of a crosssection from the weld seam must be performed on one length of pipe from each 

heat. The maximum weld seam and heat affected zone hardness must be a maximum of 280 Vickers hardness (Hv10). The hardness tests must include a minimum of two readings for each heat affected zone, two readings in the weld 

26 

metal and two readings in each section of pipe base metal for a total of 10 readings. The pipe weld seam must be 100 percent UT inspected after expansion 

and hydrostatic testing per APL 5L. 

7. Monitoring for Seam Fatigue from Transportation: Keystone must inspect the 

double submerged arc welded pipe seams of the delivered pipe using properly 

calibrated manual or automatic UT techniques. For each lay down area, a minimum of one pipe section from the bottom layer of pipes of the first five rail 

car shipments from each pipe mill must be inspected. The entire longitudinal 

weld seam must be tested and the results appropriately documented. For helical 

seam submerged arc welded pipe, Keystone must test and document the weld 

seam in the area along the transportation bearing surfaces and all other exposed weld areas during the test. Each pipe section test record must be traceable to the pipe section tested. PHMSA headquarters must be notified of any 

flaws that exceeded specifications and needed to be removed. Keystone’s findings will determine if PHMSA will require the testing program be expanded to 

include a larger sampling population for seam defects originating during pipeline transportation. 

8. Puncture Resistance: Steel pipe must be puncture resistant to an excavator 

weighing up to 65 tons with a general purpose tooth size of 3.54 inches by 0.137 

inches. Puncture resistance will be calculated based on industry established calculations such as the Pipeline Research Council International’s Reliability 

Based Prevention of Mechanical Damage to Pipelines calculation method. 

9. Mill Hydrostatic Test: The pipe must be subjected to a mill hydrostatic test 

pressure of 95 percent of SMYS or greater for 10 seconds. Any mill hydrostatic 

test failures must be reported to PHMSA headquarters with the reason for the 

test failure. 

10. Pipe Coating: The application of a corrosion resistant coating to the steel 

pipe must be subject to a coating application quality control program. The program must address pipe surface cleanliness standards, blast cleaning, application temperature control, adhesion, cathodic disbondment, moisture permeation, 

bending, minimum coating thickness, coating imperfections and coating repair. 

11. Field Coating: Keystone must implement a field girth weld joint coating application specification and quality standards to ensure pipe surface cleanliness, 

application temperature control, adhesion quality, cathodic disbondment, moisture permeation, bending, minimum coating thickness, holiday detection and repair quality must be implemented in field conditions. Field joint coatings must 

be non-shielding to cathodic protection (CP). Field coating applicators must use 

valid coating procedures and be trained to use these procedures. Keystone will 

perform follow-up tests on field-applied coating to confirm adequate adhesion to 

metal and mill coating. 

12. Coatings for Trenchless Installation: Coatings used for directional bore, slick 

bore and other trenchless installation methods must resist abrasions and other 

damages that may occur due to rocks and other obstructions encountered in this 

installation technique. 

13. Bends Quality: Certification records of factory induction bends and/or factory weld bends must be obtained and retained. All bends, flanges and fittings 

must have carbon equivalents (CE) equal to or below 0.42 or a pre-heat procedure must be applied prior to welding for CE above 0.42. 

14. Fittings: All pressure rated fittings and components (including flanges, 

valves, gaskets, pressure vessels and pumps) must be rated for a pressure rating commensurate with the MOP of the pipeline. 

15. Design Factor—Pipelines: Pipe installed under this special permit may use 

a 0.80 design factor. Pipe installed in pump stations, road crossings, railroad 

crossings, launcher/receiver fabrications, population HCAs and navigable waters 

must comply with the design factor in 49 CFR 195.106. If portions of the pipeline become population HCAs during the operational life of the pipeline, Keystone will apply to PHMSA headquarters for a special permit for the affected 

pipeline sections. 

16. Temperature Control: The pipeline operating temperatures must be less 

than 150 degrees Fahrenheit. 

17. Overpressure Protection Control: Mainline pipeline overpressure protection 

must be limited to a maximum of 110 percent MOP consistent with 49 CFR 

195.406(b). 

18. Construction Plans and Schedule: The construction plans, schedule and 

specifications must be submitted to the appropriate PHMSA regional office for 

27 

review within 2 months of the anticipated construction start date. Subsequent 

plans and schedule revisions must also be submitted to the PHMSA regional 

office. 

19. Welding Procedures: The appropriate PHMSA regional office must be notified within 14 days of the beginning of welding procedure qualification activities. Automated or manual welding procedure documentation must be submitted 

to the same PHMSA regional office for review. For X–80 pipe, Keystone must 

conform to revised procedures contained in the 20th edition of API Standard 

1104, Welding of Pipelines and Related Facilities (API 1104), Appendix A, or by 

an alternative procedure approved by PHMSA headquarters. 

20. Depth of Cover: The soil cover must be maintained at a minimum depth of 

48 inches in all areas except consolidated rock. In areas where conditions prevent the maintenance of 42 inches of cover, Keystone must employ additional 

protective measures to alert the public and excavators to the presence of the 

pipeline. The additional measures shall include placing warning tape and additional pipeline markers along the affected pipeline segment. In areas where the 

pipeline is susceptible to threats from chisel plowing or other activities, the top 

of the pipeline must be installed at least one foot below the deepest penetration 

above the pipeline. If routine patrols indicate the possible loss of cover over the 

pipeline, Keystone must perform a depth of cover study and replace cover as 

necessary to meet the minimum depth of cover requirements specified herein. 

If the replacement of cover is impractical or not possible, Keystone must install 

other protective measures including warning tape and closely spaced signs. 

21. Construction Quality: A construction quality assurance plan for quality 

standards and controls must be maintained throughout the construction phase 

with respect to: inspection, pipe hauling and stringing, field bending, welding, 

non-destructive examination (NDE) of girth welds, field joint coating, pipeline 

coating integrity tests, lowering of the pipeline in the ditch, padding materials 

to protect the pipeline, backfilling, alternating current (AC) interference mitigation and CP systems. All girth welds must be NDE by radiography or alternative means. The NDE examiner must have all current required certifications. 

22. Interference Currents Control: Control of induced alternating current from 

parallel electric transmission lines and other interference issues that may affect 

the pipeline must be incorporated into the design of the pipeline and addressed 

during the construction phase. Issues identified and not originally addressed in 

the design phase must be brought to PHMSA headquarters’ attention. An induced AC program to protect the pipeline from corrosion caused by stray currents must be in place and functioning within 6 months after placing the pipeline in service. 

23. Test Level: The pre-in service hydrostatic test must be to a pressure producing a hoop stress of 100 percent SMYS and 1.25 X MOP in areas to operate 

to 80 percent SMYS. The hydrostatic test results from each test after completion of each pipeline must be submitted to PHMSA headquarters. 

24. Assessment of Test Failures: Any pipe failure occurring during the pre-in 

service hydrostatic test must undergo a root cause failure analysis to include 

a metallurgical examination of the failed pipe. The results of this examination 

must preclude a systemic pipeline material issue and the results must be reported to PHMSA headquarters and the appropriate PHMSA regional office. 

25. Supervisory Control and Data Acquisition (SCADA) System: A SCADA system to provide remote monitoring and control of the entire pipeline system must 

be employed. 

26. SCADA System—General: 

a. Scan rate shall be fast enough to minimize overpressure conditions (overpressure control system), provide very responsive abnormal operation indications to controllers and detect small leaks within technology limitations; 

b. Must meet the requirements of regulations developed as a result of the 

findings of the National Transportation Safety Board, Supervisory Control 

and Data Acquisition (SCADA) in Liquid Pipelines, Safety Study, NTSB/ 

SS–05/02 specifically including: 

— Operator displays shall adhere to guidance provided in API Recommended Practice 1165, Recommended Practice for Pipeline SCADA 

Display (API RP 1165) 

— Operators must have a policy for the review/audit of alarms for false 

alarm reduction and near miss or lessons learned criteria 

28 

— SCADA controller training shall include simulator for controller recognition of abnormal operating conditions, in particular leak events 

— See item 27b below on fatigue management 

— Install computer-based leak detection system on all lines unless an 

engineering analysis determines that such a system is not necessary 

c. Develop and implement shift change procedures for controllers; 

d. Verify point-to-point display screens and SCADA system inputs before 

placing the line in service; 

e. Implement individual controller log-in provisions; 

f. Establish and maintain a secure operating control room environment; 

g. Establish controls to functionally test the pipeline in an off-line mode 

prior to beginning the line fill and placing the pipeline in service; and 

h. Provide SCADA computer process load information tracking. 

27. SCADA—Alarm Management: Alarm Management Policy and Procedures 

shall address: 

a. Alarm priorities determination; 

b. Controllers’ authority and responsibility; 

c. Clear alarm and event descriptors that are understood by controllers; 

d. Number of alarms; 

e. Potential systemic system issues; 

f. Unnecessary alarms; 

g. Controllers’ performance regarding alarm or event response; 

h. Alarm indication of abnormal operating conditions (ADCs); 

i. Combination AOCs or sequential alarms and events; and 

j. Workload concerns. 

28. SCADA—Leak Detection System (LDS): The LDS Plan shall include provisions for: 

a. Implementing applicable provisions in API Recommended Practice 1130, 

Computational Pipeline Monitoring for Liquid Pipelines (API RP 1130), as 

appropriate; 

b. Addressing the following leak detection system testing and validation 

issues: 

— Routine testing to ensure degradation has not affected functionality 

— Validation of the ability of the LDS to detect small leaks and modification of the LDS as necessary to enhance its accuracy to detect small 

leaks 

— Conduct a risk analysis of pipeline segments to identify additional 

actions that would enhance public safety or environmental protection 

c. Developing data validation plan (ensure input data to SCADA is valid); 

d. Defining leak detection criteria in the following areas: 

— Minimum size of leak to be detected regardless of pipeline operating 

conditions including slack and transient conditions 

— Leak location accuracy for various pipeline conditions 

— Response time for various pipeline conditions 

e. Providing redundancy plans for hardware and software and a periodic 

test requirement for equipment to be used live (also applies to SCADA 

equipment). 

29. SCADA—Pipeline Model and Simulator: The Thermal-Hydraulic Pipeline 

Model/ Simulator including pressure control system shall include a Model Validation/Verification Plan. 

30. SCADA—Training: The training and qualification plan (including simulator 

training) for controllers shall: 

a. Emphasize procedures for detecting and mitigating leaks; 

b. Include a fatigue management plan and implementation of a shift rotation schedule that minimizes possible fatigue concerns; 

c. Define controller maximum hours of service limitations; 

29 

d. Meet the requirements of regulations developed as a result of the guidance provided in the American Society of Mechanical Engineers Standard 

B31Q, Pipeline Personnel Qualification Standard (ASME B31Q), September 

2006 for developing qualification program plans; 

e. Include and implement a full training simulator capable of replaying 

near miss or lesson learned scenarios for training purposes; 

f. Implement tabletop exercises periodically that allow controllers to provide 

feedback to the exercises, participate in exercise scenario development and 

actively participate in the exercise; 

g. Include field visits for controllers accompanied by field personnel who 

will respond to call-outs for that specific facility location; 

h. Provide facility specifics in regard to the position certain equipment devices will default to upon power loss; 

i. Include color blind and hearing provisions and testing if these are required to identify alarm priority or equipment status; 

j. Training components for task specific abnormal operating conditions and 

generic abnormal operating conditions; 

k. If controllers are required to respond to ‘‘800’’ calls, include a training 

program conveying proper procedures for responding to emergency calls, notification of other pipeline operators in the area when affecting a common 

pipeline corridor and education on the types of communications supplied to 

emergency responders and the public using API Recommended Practice 

1162, Public Awareness Programs for Pipeline Operators (API RP 1162); 

l. Implement on-the-job training component intervals established by performance review to include thorough documentation of all items covered 

during oral communication instruction; and 

m. Implement a substantiated qualification program for re-qualification intervals addressing program requirements for circumstances resulting in disqualification, procedure documentation for maximum controller absences 

before a period of review, shadowing, retraining, and addressing interim 

performance verification measures between re-qualification intervals. 

31. SCADA—Calibration and Maintenance: The calibration and maintenance 

plan for the instrumentation and SCADA system shall be developed using guidance provided in API 1130. Instrumentation repairs shall be tracked and documentation provided regarding prioritization of these repairs. Controller log 

notes shall periodically be reviewed for concerns regarding mechanical problems. This information will be tracked and prioritized. 

32. SCADA—Leak Detection Manual: The Leak Detection Manual shall be prepared using guidance provided in Canadian Standards Association, Oil and Gas 

Pipeline Systems, CSA Z662–03, Annex E, Section E.5.2, Leak Detection Manual. 

33. Mainline Valve Control: Mainline valves located on either side of a pipeline 

segment containing an HCA where personnel response time to the valve exceeds 

1 hour must be remotely controlled by the SCADA system. The SCADA system 

must be capable of opening and closing the valve and monitoring the valve position, upstream pressure and downstream pressure. 

34. Pipeline Inspection: The pipeline must be capable of passing in line inspection (ILI) tools. All headers and other segments covered under this special permit that do not allow the passage of an ILI device must have a corrosion mitigation plan. 

35. Internal Corrosion: Keystone shall limit sediment and water (S&W) to 0.5 

percent by volume and report S&W testing results to PHMSA in the 180-day 

and annual reports. Keystone shall also report upset conditions causing S&W 

level excursions above the limit. This report shall also contain remedial measures Keystone has taken to prevent a recurrence of excursions above the S&W 

limits. Keystone must run cleaning pigs twice in the first full year of operation 

and as necessary in succeeding years based on the analysis of oil constituents, 

weight loss coupons located in areas with the greatest internal corrosion threat 

and other internal corrosion threats. Keystone will send their analyses and further actions, if any, to PHMSA. 

36. Cathodic Protection (CP): The initial CP system must be operational within 

6 months of placing a pipeline segment in service. 

37. Interference Current Surveys: Interference surveys must be performed within 6 months of placing the pipeline in service to ensure compliance with applicaVerDate Nov 24 2008 07:17 Jul 12, 2011 Jkt 067270 PO 00000 Frm 00033 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\67270.TXT SCOM1 PsN: JACKIE
30 

ble NACE International Standard Recommended Practices 0169 and 0177 

(NACE RP 0169 and NACE RP 0177) for interference current levels. If interference currents are found, Keystone will determine if there have been any adverse affects to the pipeline and mitigate the affects as necessary. Keystone will 

report the results of any negative finding and the associated mitigative efforts 

to the appropriate PHMSA regional office. 

38. Corrosion Surveys: Corrosion surveys of the affected pipeline must be completed within 6 months of placing the respective CP system(s) in operation to 

ensure adequate external corrosion protection per NACE RP 0169. The survey 

will also address the proper number and location of CP test stations as well as 

AC interference mitigation and AC grounding programs per NACE RP 0177. At 

least one CP test station must be located within each HCA with a maximum 

spacing between test stations of one-half mile within the HCA. If placement of 

a test station within an HCA is impractical, the test station must be placed at 

the nearest practical location. If any annual test station reading fails to meet 

49 CFR 195, Subpart H requirements, remedial actions must occur within 6 

months. Remedial actions must include a close interval survey on each side of 

the affected test station and all modifications to the CP system necessary to ensure adequate external corrosion control. 

39. Initial Close Interval Survey (CIS)—Initial: A CIS must be performed on the 

pipeline within 2 years of the pipeline in-service date. The CIS results must be 

integrated with the baseline ILI to determine whether further action is needed. 

40. Pipeline Markers: Keystone must employ line-of-sight markings on the pipeline in the special permit area except in agricultural areas or large water crossings such as lakes where line of sight markers are impractical. The marking 

of pipelines is also subject to Federal Energy Regulatory Commission orders or 

environmental permits and local restrictions. Additional markers must be 

placed along the pipeline in areas where the pipeline is buried less than 42 

inches. 

41. Monitoring of Ground Movement: An effective monitoring/mitigation plan 

must be in place to monitor for and mitigate issues of unstable soil and ground 

movement. 

42. Initial In-Line Inspection (ILI): Keystone must perform a baseline ILI in association with the construction of the pipeline using a high-resolution Magnetic 

Flux Leakage (MFL) tool to be completed within 3 years of placing a pipeline 

segment in service. The high-resolution MFL tool must be capable of gouge detection. Keystone must perform a baseline geometry tool run after completion 

of the hydrostatic strength test and backfill of the pipeline, but no later than 

6 months after placing the pipeline in service under a special permit. The ILI 

data summary sheets and planned digs with associated ILI tool readings will 

be sent to the PHMSA regional office. The PHMSA regional office will be given 

at least 14 days notice before confirmation digs are executed onsite. The dimensional data and other characteristics extracted from these digs will be shared 

with the PHMSA regional office. Keystone will also compare dimensional data 

and other characteristics extracted from the digs and compare them with ILI 

tool data. If there are large variations between dig data and ILI tool data, Keystone will submit PHMSA a plan on further actions, inclusive of more digs, to 

calibrate their analysis and remediation process. 

43. Future ILI: Future ILI inspection must be performed on the entire pipeline 

subject to the special permit, on a frequency consistent with 49 CFR 

195.452(j)(3), assessment intervals, or on a frequency determined by fatigue 

studies based on actual operating conditions, inclusive of flaw and corrosion 

growth models. 

44. Verification of Reassessment Interval: Keystone must submit a new fatigue 

analysis to validate the pipeline reassessment interval annually for the first 5 

years after placing the pipeline subject to this special permit in service. The 

analysis must be performed on the segment experiencing the most severe historical pressure cycling conditions using actual pipeline pressure data. 

45. Two years after the pipeline in-service date, Keystone will use all data gathered on pipeline section experiencing the most pressure cycles to determine effect on flaw growth that passed manufacturing standards and installation specifications. This study will be performed by an independent party agreed to by 

Keystone and PHMSA headquarters. Furthermore, this study will be shared 

with PHMSA headquarters as soon as practical after its completion, preferably 

before baseline assessment begins. These findings will determine if an ultraVerDate Nov 24 2008 07:17 Jul 12, 2011 Jkt 067270 PO 00000 Frm 00034 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\67270.TXT SCOM1 PsN: JACKIE
31 

sonic crack detection tool must be launched in that pipeline section to confirm 

crack growth with Keystone’s crack growth predictive models. 

46. Direct Assessment Plan: Headers, mainline valve bypasses and other sections covered by this special permit that cannot accommodate ILI tools must be 

part of a Direct Assessment (DA) plan or other acceptable integrity monitoring 

method using External and Internal Corrosion Direct Assessment criteria 

(ECDA/ICDA). 

47. Damage Prevention Program: The Common Ground Alliance (CGA) damage 

prevention best practices applicable to pipelines must be incorporated into the 

Keystone’s damage prevention program. 

48. Anomaly Evaluation and Repair: Anomaly evaluations and repairs in the 

special permit area must be performed based upon the following: 

a. Immediate Repair Conditions: Follow 195.452(h)(4)(i) except designate 

the calculated remaining strength failure pressure ratio (FPR) = < 1.16; 

b. 60-Day Conditions: No changes to 195.452(h)(4)(ii); 

c. 180-Day Conditions: Follow 195.452(H)(4)(iii) with exceptions for the following conditions which must be scheduled for repair within 180 days: 

— Calculated FPR = < 1.32 

— Areas of general corrosion with predicted metal loss greater than 40 

percent 

— Predicted metal loss is greater than 40 percent of nominal wall that 

is located at a crossing of another pipeline 

— Gouge or groove greater than 8 percent of nominal wall 

d. Each anomaly not repaired under the immediate repair requirements 

must have a corrosion growth rate and ILI tool tolerance assigned per the 

Integrity Management Program (IMP) to determine the maximum re-inspection interval. 

e. Anomaly Assessment Methods: Keystone must confirm the remaining 

strength (RSTRENG) effective area, R–STRENG—0.85dL and ASME B31G 

assessment methods are valid for the pipe diameter, wall thickness, grade, 

operating pressure, operating stress level and operating temperature. Keystone must also use the most conservative method until confirmation of the 

proper method is made to PHMSA headquarters. 

f. Flow Stress: Remaining strength calculations for X–80 pipe must use a 

flow stress equal to the average of the ultimate (tensile) strength and the 

SMYS. 

g. Dents: For initial construction and the initial geometry tool run, any dent 

with a depth greater than 2 percent of the nominal pipe diameter must be 

removed unless the dent is repaired by a method that reliable engineering 

tests and analyses show can permanently restore the serviceability of the 

pipe. For the purposes of this condition, a ‘‘dent’’ is a depression that produces a gross disturbance in the curvature of the pipe wall without reducing the pipe wall thickness. The depth of the dent is measured as the gap 

between the lowest point of the dent and the prolongation of the original 

contour of the pipe. 

49. Reporting—Immediate: Keystone must notify the appropriate PHMSA regional office within 24 hours of any non-reportable leaks originating in the pipe 

body in the special permit area. 

50. Reporting—180 Day: Within 180 days of the pipeline in-service date under 

a special permit, Keystone shall report on its compliance with special permit 

conditions to PHMSA headquarters and the appropriate regional office. The report must also include pipeline operating pressure data, including all pressures 

and pressure cycles versus time. The data format must include both raw data 

in a tabular format and a graphical format. Any alternative formats must be 

approved by PHMSA headquarters. 

51. Annual Reporting: Following approval of the special permit, Keystone must 

annually report the following: 

a. The results of any ILI or direct assessment results performed within the 

special permit area during the previous year; 

b. The results of all internal corrosion management programs including the 

results of: 

32 

— S&W analyses 

— Report of processing plant upset conditions where elevated levels of 

S&W are introduced into the pipeline 

— Corrosion inhibitor and biocide injection 

— Internal cleaning program 

— Wall loss coupon tests 

c. Any new integrity threats identified within the special permit area during the previous year; 

d. Any encroachment in the special permit area, including the number of 

new residences or public gathering areas; 

e. Any HCA changes in the special permit area during the previous year; 

f. Any reportable incidents associated with the special permit area that occurred during the previous year; 

g. Any leaks on the pipeline in the special permit area that occurred during 

the previous year; 

h. A list of all repairs on the pipeline in the special permit area during the 

previous year; 

i. On-going damage prevention initiatives on the pipeline in the special permit area and a discussion of their success or failure; 

j. Any changes in procedures used to assess and/or monitor the pipeline operating under this special permit; 

k. Any company mergers, acquisitions, transfers of assets, or other events 

affecting the regulatory responsibility of the company operating the pipeline 

to which this special permit applies; and 

l. A report of pipeline operating pressure data to include all pressures and 

pressure cycles versus time. The data format must include both raw data 

in a tabular format and a graphical format. Any alternative formats must 

be approved by PHMSA headquarters. 

Limitations 

Should Keystone fail to comply with any conditions of this special permit, or 

should PHMSA determine this special permit is no longer appropriate or that this 

special permit is inconsistent with pipeline safety, PHMSA may revoke this special 

permit and require Keystone to comply with the regulatory requirements in 49 CFR 

195.106. 

Background and Process 

The Keystone Pipeline is a 1,845-mile international and interstate crude oil pipeline project developed by TransCanada Keystone Pipeline L.P., a wholly-owned subsidiary of TransCanada Pipelines Limited. The Keystone Pipeline will transport a 

nominal capacity of 435,000 barrels per day of crude oil from western Canada’s sedimentary basin producing areas in Alberta to refineries in the United States. Keystone indicates it has filed an application with the U.S. Department of State for a 

Presidential Permit for the Keystone Pipeline since the project involves construction, 

operation and maintenance of facilities for the importation of petroleum from a foreign country. Keystone anticipates receiving all necessary government approvals by 

November 2007 and beginning construction in late 2007. The targeted in-service 

date is during the fourth quarter of 2009. 

The existing regulations in 49 CFR 195.106 provide the method used by pipeline 

operators to establish the MOP of a proposed pipeline by using the design formula 

contained in that section. The formula incorporates a design factor, also called a derating factor, which is fixed at 0.72 for an onshore pipeline. Keystone requests the 

use of a 0.80 design factor in the formula instead of 0.72 design factor. 

PHMSA previously granted waivers to four natural gas pipeline operators to operate certain pipelines at a hoop stresses up to 80 percent SMYS. The Keystone pipeline project represents the first request by an operator in the United States for approval to design and operate a hazardous liquid (crude oil) pipeline beyond the existing regulatory maximum level. Canadian standards already allow operators to design and operate hazardous liquids pipelines at 80 percent SMYS. 

On January 15, March 27, and April 17, 2006, PHMSA conducted technical meetings to learn more about the technical merits of Keystone’s proposal to operate at 

80 percent SMYS and to answer questions posed by internal and external subject 

matter experts. The meetings resulted in numerous technical information requests 

and deliverables, to which Keystone satisfactorily responded. 

33 

PHMSA also secured the services of experts in the field of steel pipeline fracture 

mechanics, leak detection and SCADA systems to assist in the review of appropriate 

areas of Keystone’s application. The experts’ reports are included in the public docket. 

On February 8, 2007, PHMSA posted a notice of this special permit request in 

the Federal Register (FR) (72 FR 6042). In the same FR notice we informed the public that we have changed the name granting such a request to a special permit. The 

request letter, the FR notice, supplemental information and all other pertinent documents are available for review under Docket Number PHMSA–2006–26617, in the 

DOT’s Document Management System. 

Two comments were received and posted to the public docket concerning the Keystone pipeline project request for a special permit. One commenter listed a number 

of recommended and relevant conditions for hazardous liquid pipelines to operate 

at 80 percent SMYS. The conditions developed by PHMSA and incorporated into the 

grant of special permit include the concerns of the commenter. The second commenter did not provide substantive comments relevant to the special permit request. 

Authority: 49 U.S.C. 60118(c) and 49 CFR 1.53. 

Issued in Washington, D.C. on April 30, 2007. 

JEFFREY D. WIESE, 

Acting Associate Administrator 

for Pipeline Safety. 

Senator THUNE. If you could, that would be great. It’s a question 

that we frequently get asked back in South Dakota. 

In your written testimony you stated that PHMSA has increased 

its assistance to state pipeline safety agencies. I’m wondering if 

there are other improvements that can be made in terms of the coordination between PHMSA and the states. 

Ms. QUARTERMAN. Well, there are always improvements that can 

be made. One that was discussed is coordinating the damage prevention laws to make sure that none of the states have exemptions. 

But we work very closely with our state partners and the National 

Association of State Pipeline Representatives as well. Perhaps the 

question is best left to them. I think we have a good working relationship and we’d like to keep it that way. 

Senator THUNE. Tell me what your agency can do to assist in the 

development of ethanol and other biofuel pipelines? 

Ms. QUARTERMAN. Well, we have been doing—we do have money 

for research and we have been using some of that money to research different products that are being considered, biofuel products that are being considered for pipeline transportation. 

We have also been working with the fire organizations to deal 

with issues, especially with respect to ethanol and how do you respond to an ethanol fire in a pipeline. So we’ve been working quite 

a bit on those issues. 

Senator THUNE. Mr. Chairman, I’d probably better run over and 

vote since there’s about 1 minute left, so I’ll flip the gavel back to 

you. Welcome back. 

Senator LAUTENBERG [presiding]. Well, thank you. I’d like to give 

you time to vote. Thank you. 

I understand that some of the questions that I had asked were 

discussed. So with that, I’ll say thank you and, being mindful of 

the fact that we keep the record open for some time and if questions are submitted we ask for your prompt response not more than 

a week after you get the questions. We thank each one of you for 

making your testimony. 

With that, we’ll call the second panel. The second panel is Mr. 

Rocco D’Alessandro, Tim Felt, Mr. Sypolt, and Mr. Weimer. 

34 

[Pause.] 

That was the fastest relay I’ve run for a long time. I got to the 

floor and voted and got back within about a 10-minute cycle. So 

that was pretty good. I worked off some of the energy that I might 

have saved for you folks. 

We look forward to your testimony. Mr. D’Alessandro, Executive 

Vice President of Operations, Nicor Gas and representing the 

American Gas Association; Mr. Felt, President and CEO of Colonial 

Pipeline and representing the Association of Oil Pipelines; Mr. 

Gary Sypolt, Dominion Energy, representing the Interstate Natural 

Gas Association of America; and Mr. Carl Weimer, Executive Director of the Pipeline Safety Trust. 

Mr. D’Alessandro, I think each of you have heard that we have 

a 5-minute time limit and we’re going to stick fairly closely to it 

so we can give each person a chance to testify. Mr. D’Alessandro, 

we look forward to hearing from you now. 

STATEMENT OF ROCCO D’ALESSANDRO, EXECUTIVE VICE 

PRESIDENT OF OPERATIONS, NICOR GAS ON BEHALF OF 

THE AMERICAN GAS ASSOCIATION 

Mr. D’ALESSANDRO. Good afternoon, Mr. Chairman, members of 

the Committee. I’m pleased to appear before you today. Pipeline 

safety is a critically important issue and we thank you for holding 

this hearing. 

I’m testifying today on behalf of American Gas Association. 

Founded in 1918, AGA represents 195 local energy companies that 

deliver natural gas throughout the United States. There are more 

than 70 million natural gas customers in the U.S., of which 91 percent, or 65 million, receive their gas from AGA members. 

Mr. Chairman, members of the Committee: Our message today 

is a simple one. We believe that the current pipeline safety law is 

working well and should be reauthorized this year. The 2006 

PIPES Act included several significant mandates that the industry 

is in the process of implementing. Given this, we do not believe 

there’s a need for change in the pipeline safety statute at this time, 

but rather urge the Committee to reauthorize the current law. 

Safety is our top priority. We spend an estimated $7 billion each 

year in safety-related activities. A large percentage of our effort 

over the last several years has been focused on working with Federal and state regulators in the development and implementation 

of rules specific to the mandates that were contained in the 2006 

PIPES Act. 

Specifically, there were four core provisions of the PIPES Act 

that are key to enhancing the safety of distribution pipelines: excavation damage prevention, distribution integrity management 

plans, called DIMP, excess flow valves, and control room management. 

Excavation damage represents the single greatest threat to distribution system safety, reliability, and integrity. Regulators, natural gas operators, and other stakeholders are continually working 

to improve excavation damage prevention programs. It is having a 

positive impact, but, as always, more can be done. 

The PIPES Act required DOT to establish an integrity management program for distribution pipeline operators. DOT published 

35 

the final DIMP rule on December 4 of last year. The effective date 

was February 12 of this year and operators have been given until 

August 2 of 2011 to write and implement the program. This will 

impact 1,450 operators, 2.1 million miles of piping, and 70 million 

customers. 

The final rules allow operators to develop a DIMP plan that is 

appropriate for the operating characteristics of their delivery systems and the customers that they serve. I’m pleased to report that 

the operators are working aggressively to implement the DIMP 

rule. 

The PIPES Act mandated that DOT require distribution gas utilities install an excess flow valve on new and replacement service 

lines for single-family residences if the service line met specific conditions beginning on June 1, 2008. Operators have installed an estimated 950,000 excess flow valves since that date. 

I do want to emphasize that Congress was absolutely correct in 

limiting the EFV mandate to single-family residence dwellings. It 

is inadvisable to attempt a mandatory nationwide installation of 

EFVs beyond the single-family resident class to multiple-family 

dwellings, commercial and industrial customers, due to the inherent uncertainties and complexities associated with the service lines 

and the significant variations in gas load. Inadvertent EFV shutdown of a commercial or industrial facility, like a hospital, chemical plant, could create greater safety hazards than the release of 

gas the EFV was attempting to prevent. 

There are two issues that I’d like to bring to the Committee’s attention as we believe there are some additional regulatory actions 

that DOT should be encouraged to take to ensure that the existing 

statutes continue to be efficiently implemented. Now that DOT has 

promulgated the DIMP regulation, it can modify the assessment requirements for low-stress transmission pipe operated by distribution gas utilities covered by TIMP. Since low-stress transmission 

lines operate more like distribution lines, we believe the low-stress 

pipelines are better covered under the DIMP, which would result 

in all low-stress lines being covered under the robust DIMP regulation. 

The other issue I want to bring to attention deals with high-consequence areas, HCAs. There has been some talk of perhaps changing the TIMP regulation by eliminating the HCA definition and requiring operators to perform assessment on all 300,000 miles of 

natural gas transmission pipeline. Internal instrument, or smart 

pigging, inspections are usually not practical for transmission pipelines operated by distribution gas utilities, because usually the 

pipes are not piggable. 

As part of its TIMP regulation, DOT has already included provisions for pipeline operators to have an added layer of protection on 

low-stress pipelines outside of HCA areas, known as Preventive 

and Mitigation Measures. AGA we strongly discourage making a 

change to TIMP HCA criteria. 

In summary, many of the mandates within the 2006 PIPES Act 

have just become regulations and the government and industry are 

working hard to implement these regulations. AGA believes that 

Congressional passage of pipeline safety reauthorization this year 

will send a positive message that the current law is working and 

36 

emphasize the commitment that Congress and all the industry 

stakeholders have to securing the safety of the Nation’s pipeline 

system. We look forward to working with you to secure reauthorization this year. 

[The prepared statement of Mr. D’Alessandro follows:] 

PREPARED STATEMENT OF ROCCO D’ALESSANDRO, EXECUTIVE VICE PRESIDENT OF

OPERATIONS, NICOR GAS ON BEHALF OF THE AMERICAN GAS ASSOCIATION

Good morning, Mr. Chairman and members of the Committee. I am pleased to appear before you today. Pipeline safety is a critically important issue, and I thank 

you for not only holding this hearing, but for all the work that you and your colleagues have done over the years to ensure that America has the safest, most reliable pipeline system in the world. My name is Rocco D’Alessandro and I am the 

Executive Vice President of Operations for Nicor Gas, based in Illinois. Nicor Gas 

is the largest natural gas distributor in northern Illinois, serving more than 2 million customers in 643 communities. Ninety-six percent of homes in our service territory use natural gas. We serve our customers utilizing 32,000 miles of gas distribution main and almost 2 million gas services. There are also 1175 miles of transmission pipelines integrated into Nicor’s distribution system. 

I am testifying today on behalf of the American Gas Association (AGA). Founded 

in 1918, AGA represents 195 local energy companies that deliver natural gas 

throughout the United States. There are more than 70 million residential, commercial and industrial natural gas customers in the U.S., of which 91 percent—nearly 

65 million customers—receive their gas from AGA members. Today, natural gas 

meets almost one-fourth of the United States’ energy needs. 

Distribution pipelines are operated by natural gas utilities, sometimes called 

‘‘local distribution companies’’ or LDCs. The gas utility’s distribution pipes are the 

last, critical link in the natural gas delivery chain. Gas distribution utilities bring 

natural gas service to customers’ front doors. To most customers, their local utilities 

are the ‘‘face of the industry.’’ Our customers see our name on their bills, our trucks 

in the streets and our company sponsorship of many civic initiatives. We live in the 

communities we serve and interact daily with our customers and with the state regulators who oversee pipeline safety. Consequently, we take very seriously the responsibility of continuing to deliver natural gas to our communities safely, reliably 

and affordably. The distribution pipeline system is an interconnected network of 

transmission mains, distribution mains, and service lines. 

Mr. Chairman and members of the Committee, AGA believes that the current 

pipeline safety law is working well and that there is no need to make changes to the 

pipeline safety statute. I want to assure the Committee that the natural gas industry 

has worked vigorously to implement the significant provisions of the 2002 and 2006 

Pipeline Safety Acts. The industry safety performance has been exceptional and 

AGA expects it to improve further after some of the recent pipeline safety mandates 

have been fully implemented. For instance, the industry has already begun marshalling resources to implement the Distribution Integrity Management Program 

(DIMP) and Control Room Management regulations that were promulgated in December 2009. 

We strongly urge a straight reauthorization, so as to allow the full implementation and refinement of each of the various regulations that have been promulgated 

since the 2006 Pipeline Safety reauthorization. We do not believe any new legislative action is needed. 

Regulatory Authority 

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 transmission pipeline companies. State governments are encouraged to adopt as minimum standards the Federal safety standards promulgated 

by the Department of Transportation (DOT). The states may also choose to adopt 

standards that are more stringent than the Federal ones, and many have done so. 

LDCs are in frequent contact with state pipeline safety inspectors. As a result of 

these interactions, distribution operator facilities are subject to more frequent and 

closer inspections than required by the Federal pipeline safety regulations. 

Commitment to Safety 

Our commitment to safety extends beyond government oversight. Indeed, safety 

is our 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 emVerDate Nov 24 2008 07:17 Jul 12, 2011 Jkt 067270 PO 00000 Frm 00040 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\67270.TXT SCOM1 PsN: JACKIE
37 

ploys 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. Examples of these groups include AGA, the 

American Public Gas Association and the Interstate Natural Gas Association of 

America. 

Natural gas utilities have long made safety their number one priority. We spend an estimated $7 billion each year in safety-related activities. Approximately half of 

this money is spent in complying 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. Moreover, we are continually refining our safety practices. 

A large percentage of our effort over the last several years has been focused on 

working with Federal and state regulators in the development and implementation 

of rules specific to these and other legislative mandates that were contained in the 

2002 and 2006 PIPES Acts. I want to assure the Committee that the natural gas 

distribution industry has worked vigorously to implement those provisions that related to our sector. From a regulatory perspective, the past 10 years have easily included far more significant pipeline safety rulemakings than any other decade since 

the creation of the Federal pipeline safety code in 1971. Highlights include: 

• Approximately 2.1 million miles of distribution system piping are covered under 

the recently promulgated Distribution Integrity Management regulation; 

• More than 50,000 miles of transmission pipelines operated by distribution gas 

utilities are covered by the Transmission Integrity Management Program; 

• An estimated 950,000 excess flow valves have been installed since June 1, 2008; 

• 25,000 natural gas distribution employees are continually qualified through 

testing. The average 30 qualification tests for each employee results in 750,000 

documented qualifications; 

• Locations of all natural gas transmission and hazardous liquids pipelines have 

been added to the Federal National Pipeline Mapping System; 

• A pipeline awareness program has been developed and implemented for almost 

1,600 natural gas operators; and 

• Approximately 1,100 controllers are covered under the recently promulgated 

Control Room Management regulation, which includes requirements to address 

employee fatigue. 

Specifically, there were four core provisions of the PIPES Act of 2006 that are key 

to enhancing the safety of the distribution pipeline system—Excavation Damage Prevention, DIMP, Excess Flow Valves (EFV), and Control Room Management. 

Excavation Damage Prevention 

Excavation damage represents the single greatest threat to distribution system 

safety, reliability and integrity. A number of initiatives have helped to reduce excavation damage and resulting incidents. These include a new three digit number, 

‘‘811’’, that excavators can use to call before they dig, a nationwide education program promoting 811, ‘‘best practices’’ to reduce excavation damage and regional 

‘‘Common Ground Alliances’’ that are focused on preventing excavation damage. Additionally, AGA and other partners established April as National Safe Digging 

Month, encouraging individuals to dial 811 before embarking on any digging or excavation project. Since the Call 811 campaign was launched, there has been approximately a 40 percent reduction in safety-related incidents. A significant cause for this 

reduction is the work done by the pipeline industry in promoting the use of 811. 

Regulators, natural gas operators, and other stakeholders are continually working 

to improve excavation damage prevention programs. This concerted effort, combined 

with the effort that states are undertaking to create robust, and effective, state 

damage prevention programs based on the elements contained in the 2006 PIPES 

Act, is having a positive impact. But as always, more can be done—and we will continue to remain vigilant in collaborating with other stakeholders and the public to 

ensure the safety of our pipeline systems. 

Distribution Integrity Management 

The 2006 PIPES Act required the DOT to establish a regulation prescribing 

standards for integrity management programs for distribution pipeline operators. 

The DOT published the final rule establishing natural gas DIMP requirements on 

December 4, 2009. The effective date of the rule was February 12, 2010. Operators 

38 

must develop a written program and begin implementation of DIMP prior to August 

2, 2011. 

The DOT’s Pipeline and Hazardous Materials Safety Administration (PHMSA) 

previously implemented integrity management regulations for hazardous liquid and 

gas transmission pipelines. Because there are significant differences between gas 

distribution pipeline systems and the systems of gas transmission or hazardous liquid operators, it would have been impractical to apply the existing regulations to 

distribution pipelines. The DIMP final rule requires operators to develop and implement individualized integrity management programs, in addition to PHMSA’s core 

pipeline safety regulations. 

The DIMP final rule is a comprehensive regulation that provides an added layer 

of protection to the already-strong pipeline safety programs in use by local distribution companies. It represents the most significant rulemaking affecting natural gas 

distribution operators since the inception of the Federal pipeline safety code in 1971. 

It will impact more than 1,400 operators, 2.1 million miles of piping, and 70 million 

customers. The final rule effectively takes into consideration the wide differences 

that exist between natural gas distribution operators. It also allows operators to develop a DIMP plan that is appropriate for the operating characteristics of their distribution delivery system and the customers that they serve. 

The final rule requires that all distribution pipeline operators, regardless of size, 

implement an integrity management program that contains seven key elements: 

1. Develop and implement a written integrity management plan. 

2. Know its infrastructure. 

3. Identify threats, both existing and of potential future importance. 

4. Assess and prioritize risks. 

5. Identify and implement appropriate measures to mitigate risks. 

6. Measure performance, monitor results, and evaluate the effectiveness of its 

programs, making changes where needed. 

7. Periodically report performance measures to its regulator. 

Operators are aggressively implementing this rule. Workshops have been conducted throughout the Nation. Webinars and audio conferences have been held. 

Software programs have been developed specifically for distribution integrity management. The Gas Pipeline Technology Committee (comprised of Federal and state 

regulators, pipeline operators, manufacturers, and the public) has developed a guidance document to support implementation of the DIMP regulation. I am pleased to 

inform the Committee that all affected stakeholders are working to make this an 

effective regulation. 

As discussed previously, low stress transmission pipelines are integrated into the 

gas distribution system. Distribution operators and state regulators will better manage the integrity of the distribution system when the TIMP and DIMP regulations 

are harmonized. 

Excess Flow Valves 

EFVs are installed by natural gas distribution utilities as one method to reduce 

the potential consequences when a service line is significantly damaged due to the 

impact of outside forces such as excavation damage. An EFV is usually installed in 

the pipe where the service line originates, near the main. EFVs function similar to 

a fuse in an electric panel that closes automatically to eliminate the flow of gas to 

the home for large leaks that exceed the EFV’s closure flow rate. EFVs are not designed to shut off the flow of gas if a line break occurs on the customer’s side of 

the gas meter. The device will not work properly for the low pressure and gas volumes in a customer’s interior or exterior piping system that connects gas appliances. 

EFVs also cannot distinguish small gas leaks from changing gas loads. Instead, they 

help mitigate the potential consequences for events that could have a high rate, 

high volume gas release. These are the types of events that occur during excavation 

damage. 

Natural gas utilities have been installing EFVs widely on single family residence 

service lines since the late 1990s, when operators were given the option of either 

installing them voluntarily or notifying customers of their availability, and then installing them upon request. The 2006 PIPES Act mandated that DOT require natural gas distribution utilities install an EFV on new and replacement service lines 

for single family residences, if the service line met specific conditions, beginning on 

June 1, 2008. 

AGA supported the 2006 Congressional mandate for EFVs. Indeed, operators were 

voluntarily installing EFVs before the June 2008 Congressional deadline. The DIMP 

39 

final rule codified the congressional mandate to install EFVs in services to singlefamily residences. I do want to emphasize that Congress was absolutely correct in 

limiting the EFV mandate to single-family residential dwellings. Single family residence dwellings are very uniform and only about 15 percent of the dwellings have 

problems with EFV installation (e.g., pressure too low, dirt, or contaminates in the 

gas). 

Due to the inherent uncertainties and complexities associated with service lines 

to multiple-family dwellings, commercial and industrial customers, however, it is inadvisable to attempt mandatory nation-wide installation of EFVs beyond the singlefamily residential class. Multi-family dwellings, commercial, and industrial customers are subject to significant variations in gas loads. Since EFVs are designed 

to shut down when there is a significant change in gas flow, these variations could 

result in the inadvertent closure of an EFV and interruption of gas service for multiple days. An inadvertent EFV shutoff of commercial and industrial facilities, like 

hospitals or chemical plants, could create greater safety hazards than the release 

of gas the EFV was attempting to prevent. 

Control Room Management 

In December 2009, DOT promulgated the final regulation for Pipeline Control 

Room Management, requiring pipeline operators to develop, implement and submit 

a human factors management plan designed to reduce risks associated with human 

factors for employees working in a pipeline control room. As a part of their plan, 

pipeline operators must address fatigue and establish a maximum limit on the number of hours worked by pipeline controllers. 

AGA commends DOT for putting forth a final rule that enhances safety and is 

practical, reasonable, and cost-effective. Similarly to the DIMP, the rule takes into 

consideration the inherent differences that exist between natural gas pipeline operators and hazardous liquids pipeline operators. There has never been a documented 

accident that has been directly caused by the controller of a natural gas pipeline. 

Yet, AGA and its members are supportive of the regulation and are active in working to develop national standards that identify recommended practices for pipeline 

operators to consider in developing their plan. The final rule actually goes beyond 

the Congressional mandate in the area of controller fatigue by requiring operators 

to: 

• Establish shift lengths and schedule rotations that provide controllers off-duty 

time sufficient to achieve 8 hours of continuous sleep; 

• Educate controllers and supervisors in fatigue mitigation strategies and how offduty activities contribute to fatigue; and 

• Train controllers and supervisors to recognize the effects of fatigue. 

The National Transportation Safety Board (NTSB) has expressed its support of 

the new regulation by closing its recommendation for pipeline operators to address 

fatigue. On February 18, 2010, the NTSB issued a press release that stated: ‘‘The 

Board was pleased to report that the Pipeline and Hazardous Materials Safety Administration has published a final rule establishing new bases for managing fatigue 

in the pipeline industry.’’ The Board called the rule ‘‘a significant step forward for 

an industry that did not previously have any rules governing hours of service.’’ The 

Board, therefore, closed the recommendation ‘‘Acceptable Alternate Action’’ and has 

removed fatigue in the pipeline industry from its ‘‘Most Wanted’’ list. 

Public Awareness Programs 

Beyond the significant requirements of the 2006 PIPES Act, the PIPES Act of 

2002 directed DOT to put in place standards and criteria to improve public awareness of pipeline operations. Beginning June 20, 2005, the DOT required all pipeline 

operators to develop and implement public awareness programs based on the American Petroleum Institute (API) Recommended Practice (RP) 1162, ‘‘Public Awareness 

Programs for Pipeline Operators.’’ 

AGA applauds the DOT for working with the public, emergency responders, and 

industry to improve the public’s awareness of pipelines. AGA’s position is that the 

public awareness initiative has been successful and has effectively improved the 

public’s awareness of the pipeline infrastructure and appropriate actions to be taken 

in the event of a pipeline emergency. API RP 1162 was developed by a joint stakeholder task group that included state and Federal safety regulators, public representatives, emergency responders, and pipeline operators. Operators adhered to 

the 12-step guide outlined by the DOT to develop public awareness programs. Operators are required to assess their public awareness programs for effectiveness and 

to identify opportunities for program improvement. These evaluations are required 

on a four-year interval, so operators are currently working to meet the first evaluaVerDate Nov 24 2008 07:17 Jul 12, 2011 Jkt 067270 PO 00000 Frm 00043 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\67270.TXT SCOM1 PsN: JACKIE
40 

tion deadline of June 2010. During the second half of 2010, state and Federal pipeline safety inspectors will review the effectiveness of operators’ public awareness 

programs. Industry looks forward to working with the DOT to identify performance 

metrics that are critical in assessing program effectiveness. 

In response to an NTSB recommendation, industry is working to ensure that 911 

operators are identified as an important stakeholder audience and receive all needed 

pipeline awareness information. AGA and the industry look forward to continuing 

to work with all regulatory agencies to improve the methods utilized to educate the 

public regarding pipeline safety. 

Miscellaneous Issues 

Low Stress Gas Pipelines 

There are some additional regulatory actions that DOT should be encouraged to 

take to ensure that the existing statute continues to be efficiently implemented. 

Specifically, now that DOT has promulgated the DIMP regulation, it can modify the 

assessment requirements for low stress transmission pipelines operated by natural 

gas distribution utilities. Currently, low stress pipelines are covered under the 

Transmission Integrity Management Program (TIMP) regulation, which was promulgated in December 2003 by DOT. However, since low stress transmission lines 

operate more like distribution lines, AGA believes the low stress pipelines are better 

covered under DIMP. Making this change would not have an adverse effect on pipeline safety. Rather, we believe, it would enhance safety by allowing low stress pipelines to be covered under DIMP which would result in ALL low stress lines being 

covered under the robust DIMP regulation, and not just lines within high consequence areas. 

There are fundamental differences between the high stress pipelines predominately operated by interstate operators—and the low stress pipelines, which are predominately operated by gas distribution utilities. A typical high stress interstate 

transmission pipeline will operate between 500 pounds per square inch (psi) and 

1,000 psi and have stress levels up to 80 percent Specified Minimum Yield Strength 

(SMYS). Whereas, a typical low stress transmission pipeline will operate anywhere 

between 150 psi and 400 psi and have stress levels below 30 percent SMYS. Low 

stress transmission pipelines are usually embedded in the distribution network operated by utilities and are often very similar to higher pressure distribution pipelines. Moreover, many CANNOT be inspected by in-line inspection tools (‘‘smart 

pigs’’) because of their, small diameters, valves in the line, layouts that include 

sharp turns and angles, relatively low operating pressures. DOT has already started 

regulatory initiatives to apply traditional distribution inspection and corrosion prevention techniques to low stress pipelines in lieu of the rigid TIMP assessments. 

DOT has the regulatory authority to manage low stress transmission pipelines 

under DIMP. The issue was discussed during reauthorization of the 2002 Act. Congress anticipated that the pipelines included in TIMP might change and 42 U.S.C. 

60109(c)1 states that DOT would define the facilities that will be included in TIMP 

in chapter 192 of title 49, Code of Federal Regulations, including any subsequent 

modifications. DIMP was finalized in December 2009 and AGA believes safety can 

be enhanced if DOT harmonizes the requirements in TIMP and DIMP. 

High Consequence Areas 

There has been some talk of perhaps changing TIMP, by eliminating the High 

Consequence Areas (HCA) definition, and requiring operators to perform TIMP assessments for all 300,000 miles of natural gas transmission pipelines. 

As previously stated, internal instrument (smart pig) inspections are usually not 

practical for transmission pipelines operated by distribution gas utilities, because 

the pipelines are usually not piggable. As part of its regulation on TIMP, DOT has 

already included provisions for pipeline operators to have an added layer of protection on the low-stress pipelines outside of HCAs known as Preventive and Mitigative (P&M) measures in Subpart O of the Federal Pipeline Safety Code. These P&M 

measures consist of enhanced protection against the threats of external and internal 

corrosion as well as third party excavation damage. 

Finally, there is a long list of regulatory safety requirements separate from the 

integrity management assessments that are used to manage safety for all pipelines 

inside and outside of HCAs. These include leak inspections, corrosion control, surveillance and patrolling, repair criteria, etc. Pipeline operators have upgraded their 

mapping systems and are continually collecting population data for the sole purpose 

of identifying HCAs that exist on their system so that they can use the risk-based 

principles required by the current TIMP regulation. AGA would strongly discourage 

making a change to the TIMP–HCA criteria. 

41 

Summary 

Many of the mandates within the 2006 PIPES Act have just become regulation 

and government and industry are working to implement these regulations. AGA believes that Congressional passage of pipeline safety reauthorization this year will 

send a positive message that the current law is working, and emphasize the commitment that Congress and all the industry stakeholders have to securing the safety 

of the Nation’s pipeline system. We look forward to working with you to secure reauthorization this year. 

Senator LAUTENBERG. Thanks very much, Mr. D’Alessandro. 

Mr. Felt, you’re next, please. 

STATEMENT OF TIMOTHY C. FELT, PRESIDENT AND CEO, 

COLONIAL PIPELINE COMPANY ON BEHALF OF 

THE ASSOCIATION OF OIL PIPE LINES (AOPL) 

AND THE AMERICAN PETROLEUM INSTITUTE (API) 

Mr. FELT. Thank you, Chairman Lautenberg and members of the 

Subcommittee. I am Tim Felt, President and CEO of Colonial Pipeline, and I appreciate the opportunity to appear on behalf of AOPL 

and API. Colonial Pipeline operates a 5,500-mile pipeline system 

that begins in Houston, crosses the South and East before terminating at New York harbor. When measured by volume transported, Colonial is the largest refined products pipeline in the 

world, every day delivering about 100 million gallons of gasoline, 

diesel fuel, jet fuel, heating oil, and fuels for the U.S. military. 

Pipelines have the best safety record of any transportation mode 

and are the most reliable, economical, and environmentally favorable way to transport oil to refineries and refined products to the 

communities where we live. We are proud of our improved safety 

record, but we are not content, as we strive for zero releases. 

Pipelines have every incentive to invest in safety. The consequences of a failure could include injury to our neighbors, our 

employees, our community, our contractors, and the environment. 

We could also incur costly repairs, cleanups, litigation, and fines, 

and in the event of a problem on a pipeline we may not be able 

to meet our commitments to our customers. That breakdown in reliability can have a longer term impact on our business. The public 

expects pipelines to be safe and reliable and we believe we are 

meeting that expectation. 

Our control room operators are trained to respond to an event on 

the pipeline by closing valves and quickly shutting down pumps. 

Pipeline operators are required to establish response plans which 

are submitted to the Office of Pipeline Safety within the Department of Transportation. We are required to plan for worst case discharges and to conduct emergency response drills on worst case 

scenarios with local responders to ensure that emergency preparedness is at a continued state of readiness. 

Over the last decade, Congress and OPS have asked more of 

pipelines and the industry has done more. Pipelines have spent billions of dollars on integrity management, far exceeding earlier estimates. As a result, liquid pipeline spills along rights of way have 

decreased over the past decade in both volume and the number of 

releases. 

Pipeline operators are required to develop integrity management 

plans for segments of pipelines that could affect high consequence 

areas, those near population centers, navigable waterways, drinkVerDate Nov 24 2008 07:17 Jul 12, 2011 Jkt 067270 PO 00000 Frm 00045 Fmt 6633 Sfmt 6601 S:\GPO\DOCS\67270.TXT SCOM1 PsN: JACKIE
42 

ing water intakes, or sensitive environmental areas. Liquid pipeline operators conducted baseline assessments to identify potential 

hazards to their pipelines and are implementing plans to address 

those threats. This includes in-line inspection by smart pigs. Full 

reassessments are under way, must be done within 5 years of the 

baseline assessments, and are required into the future. 

Pipeline operators take additional steps to maintain integrity of 

pipelines, which include cathodic protection to control corrosion, patrols of rights of way to detect or head off encroachment or damage, 

and extensive use of computer systems to monitor the operations 

of the pipeline. 

I want to thank the Congress and this committee for your prior 

work on pipeline safety, including establishment of 811 as the national Call Before You Dig Number. Colonial and other pipelines 

are supporters of One-Call centers, which serve as a clearinghouse 

for excavation activities mentioned in 811 calls. I am a board member and past chairman of the Common Ground Alliance, a place 

where underground utility operators can partner with government, 

excavators, and the public to pursue best practices on damage prevention. 

I also want to thank Chairman Lautenberg and this committee 

for its work on Senate Resolution 472, which supported the designation of April as the National Safe Digging Month. 

The pipeline industry asks for additional help protecting pipelines from excavation damage, a leading cause of significant pipeline incidents. Many states have been improving their damage prevention programs, but some state damage prevention laws are incomplete, inadequate, or inadequately enforced. 41 states allow 

some exemptions from the One-Call system for State agencies, municipalities, or local entities. These exemptions create a gap in enforcement and safety. 

We believe OPS is headed in the right direction with its proposal 

of last year for Federal enforcement in States with inadequate programs. We urge OPS to complete this rulemaking and even require 

termination of these exemptions by the States or risk Federal enforcement or loss of grant funds. 

Congress has provided OPS a thorough set of tools to regulate 

pipeline safety and they are working. We see no reason for Congress to greatly expand the pipeline safety program or impose significant new mandates upon the industry. We do believe Congress 

should encourage OPS to complete its rule on damage prevention, 

disallowing any exemptions to One-Call requirements and pushing 

States to improve and enforce State damage prevention programs. 

We look forward to working with Congress, OPS, and other 

stakeholders to improve pipeline safety and reauthorize pipeline 

safety laws. Thank you. 

[The prepared statement of Mr. Felt follows:] 

PREPARED STATEMENT OF TIMOTHY C. FELT, PRESIDENT AND CEO, COLONIAL

PIPELINE COMPANY ON BEHALF OF THE ASSOCIATION OF OIL PIPE LINES (AOPL) 

AND THE AMERICAN PETROLEUM INSTITUTE (API) 

Introduction 

I am Tim Felt, President and CEO of Colonial Pipeline Company. I appreciate this 

opportunity to appear before the Subcommittee today on behalf of AOPL and the 

American Petroleum Institute (API). 

43 

1 ‘‘Liquid Transportation Fuels from Coal and Biomass: Technological Status, Costs, and Environmental Impacts,’’ National Academy of Sciences, 2009. 2 Association of Oil Pipe Lines, Shifts in Petroleum Transportation, 2009. 3One barrel mile equals one barrel (or 42 gallons) transported one mile. 

Colonial Pipeline is headquartered in suburban Atlanta, Georgia, from where we 

operate a pipeline system consisting of 5,519 miles of pipeline, beginning in Houston 

and crossing the South and East before terminating at the New York harbor. When 

measuring by volume transported, Colonial is the largest refined products pipeline 

in the world, daily delivering about 100 million gallons of gasoline, diesel fuel, jet 

fuel, home heating oil and fuels for the U.S. military. 

AOPL is an incorporated trade association representing 51 liquid pipeline transmission companies. API represents over 400 companies involved in all aspects of the 

oil and natural gas industry, including exploration, production, transportation, refining and marketing. Together, the two organizations represent the operators of 85 

percent of total U.S. oil pipeline mileage in the United States. 

I will discuss the industry’s commitment to safety, our improved safety record, 

and our view that pipeline safety reauthorization should remain focused on existing 

programs, specifically damage prevention. 

Liquid Pipelines Overview 

Pipelines are the safest, most reliable, economical and environmentally favorable 

way to transport oil and petroleum products, other energy liquids, and chemicals, 

throughout the U.S. 

Liquid pipelines bring crude oil to the Nation’s refineries and petroleum products 

to our communities, including all grades of gasoline, diesel, jet fuel, home heating 

oil, kerosene, and propane. Some of our members transport renewable fuels via pipeline, as well. Our members transport carbon dioxide to oil and natural gas fields, 

where it is used to enhance production. In addition to providing fuels for the transportation sector (including cars, trucks, trains, ships and airplanes), we provide hydrocarbon feedstocks for use by many other industries, including food, pharmaceuticals, plastics, chemicals, and road construction. America depends on the network of more than 170,000 miles of hazardous liquid pipelines to safely and efficiently move energy to fuel our Nation’s economic engine. 

Hazardous liquid pipelines transport more than 17 percent of freight moved in 

America, yet pipelines account for only 2 percent of the country’s freight bill. Approximately 2.5 cents of the cost of a gallon of gasoline to an end-user can be attributed to pipeline transportation,1 resulting in a low and predictable price for pipeline 

customers (referred to as ‘‘shippers’’). Liquid pipeline transportation rates are regulated by the Federal Energy Regulatory Commission (FERC). Rates are generally 

stable and predictable, and do not fluctuate with changes in crude oil and gasoline 

or other fuel prices. Typically, pipelines only take custody of the product tendered 

for transportation and, as such, are unaffected by changes in the price of commodities being transported. 

Pipelines are the preferred mode of transportation for crude and refined products. 

The approximate share of domestic shipments, measured in barrels of product 

moved per mile, is: 2

• Pipelines—68 percent 

• Water Carriers—25 percent 

• Trucks—4 percent 

• Rail—3 percent 

Our industry had a wake-up call after the Bellingham, Washington fatalities in 

1999. Congress and the Office of Pipeline Safety asked more of pipelines, and industry has done more. As a result of enhancements to pipeline safety laws, implementing regulations, and vigorous industry efforts, liquid pipeline spills along 

rights-of-way have decreased over the past decade, in terms of both the number of 

spills and the volume of product released per 1,000 barrel-miles 3 transported. 

In addition to its record of fewest releases, pipeline transportation enjoys the lowest input energy requirement and carbon footprint as compared to other transportation modes (barge, truck, rail, and marine). Replacing a medium-sized pipeline 

that transports 150,000 barrels of gasoline a day would require operating more than 

750 trucks or a 225-car train every day. Use of trucks or trains would increase mobile source greenhouse gas emissions, wear and tear on our transportation infrastructure, road congestion, and the number and volume of releases. 

44 

Pipeline Operators Insist on Safety 

Pipelines have every incentive to invest in safety. Indeed, in our members’ view, 

there are no incentives to cut corners on pipeline safety. Most important is the potential for injury or loss of life to members of the public and our employees and contractors. If a pipeline experiences a failure or a release, there are numerous consequences for the operator. We could also incur potentially costly repairs, cleanup, 

litigation, and fines. Next, the pipeline may not be able to accommodate our customers. Finally, the pipeline company’s reputation could be hurt. 

Operators of liquid pipelines invest millions of dollars annually to maintain their 

pipelines and comply with Federal pipeline safety laws and regulations. Liquid pipeline assets are inspected regularly and monitored continuously, using a combination 

of practices. Pipeline operators continually seek to reduce the risk of accidental releases by taking measures to minimize the probability and severity of incidents. 

These measures include proper pipeline route selection, design, construction, operation, and maintenance, as well as comprehensive public awareness and excavation 

damage prevention programs. 

The frequency of releases from liquid pipelines decreased from 2 incidents per 

thousand miles in 1999–2001 to 0.7 incidents per thousand miles in 2006–2008, a 

decline of 63 percent. Similarly, the number of barrels released per 1,000 miles decreased from 629 in 1999–2001 to 330 in 2006–2008, a decline of 48 percent. The 

industry is proud of this record, but continues to strive for zero releases, zero injuries, zero fatalities and no operational interruptions. 

On many pipelines, operators also seek to minimize the consequences of a release 

through the use of automated systems that detect releases or other abnormal operating conditions and quickly shut off product flow to isolate the incident. Pipeline 

operators are required to put response plans in place, under the 1990 Oil Pollution 

Act. These plans are submitted to and reviewed by the Office of Pipeline Safety 

(OPS) within the Department of Transportation (DOT). Operators must change their 

plans and notify OPS within 30 days if any operational situation arises that would 

impact response efforts. Pipeline operators are required to conduct emergency response drills on worst-case discharges, and conduct exercises in cooperation with 

local first responders to ensure that emergency preparedness and planning is at a 

continued state of readiness. These response drills are conducted under the National 

Preparedness for Response Plan (PREP) guidelines issued jointly with OPS, the Environmental Protection Agency (EPA), and the U.S. Coast Guard. Our operators are 

trained on all elements of PREP guidelines and they are required to conduct equipment deployment drills and are subject to random full drills conducted by OPS. 

In 1998, the U.S. oil pipeline industry launched an Environmental and Safety Initiative (ESI) to make further improvements in spill and accident prevention. The 

ESI promotes inter-company learning, improves pipeline operations and integrity, 

and provides opportunities for information sharing. An important part of the ESI 

is the liquid pipeline industry’s voluntary reporting system, the Pipeline Performance Tracking System (PPTS), which tracks spills and allows operators to learn 

from industry data. Another key element of the ESI is the Performance Excellence 

Team (PET), which seeks to promote inter-company learning to improve pipeline operations and integrity, and provides methods and opportunities for information 

sharing. 

Pipeline Safety Laws and Regulations 

In 1979, Congress enacted comprehensive safety legislation governing the transportation of liquids by pipeline in the Hazardous Liquids Pipeline Safety Act of 1979 

(HLPSA, 49 U.S.C. 2001). HLPSA added to previous laws and regulations and expanded the existing statutory authority for safety regulation. Since then, several 

new laws have been passed to govern the liquids pipeline industry, including: the 

Pipeline Safety Act (PSA) of 1994, the Pipeline Safety Improvement Act of 2002 

(PSA), and the Pipeline Inspection Protection, Enforcement, and Safety Act of 2006 

(PIPES). 

Pipeline safety is closely regulated by the Pipeline and Hazardous Materials Safety Administration (PHMSA) which includes OPS. PHMSA’s OPS is responsible for 

establishing and enforcing regulations to assure the safety of liquid pipelines (Title 

49 CFR Parts 190–199). OPS sets prescriptive performance-based regulations and 

standards that are intended to address the dynamic nature of pipeline operations. 

Integrity Management 

Most pipeline operators are required under Federal regulations (Title 49 CFR, 

Part 195.450 and 452) to develop an Integrity Management Plan (IMP), for pipelines 

that could affect High Consequence Areas (HCAs). HCAs for liquid pipelines include 

any of the following: 

45 

• Population centers, urbanized areas, or areas with large population density; 

• Commercially navigable waters; and 

• Unusually sensitive areas such as water supplies and ecological reserves. 

Pipeline operators are required in their IMPs to identify segments that could impact HCAs, conduct periodic integrity assessments on those segments at intervals 

not to exceed 5 years, and review assessment results to make mitigation and repair 

decisions. A risk-based approach establishes the appropriate assessment interval 

within the five-year period. When identifying segments which could affect HCAs, operators conduct risk assessments and consider local topographical characteristics, 

operational and design characteristics of a pipeline, and the properties of transported commodities in determining potential impacts of an incident. 

In their IMPs, all operators conduct a baseline assessment that identifies threats 

to the pipeline and subsequently apply technologies to mitigate each threat. These 

baseline assessments also set a point of comparison for subsequent assessments so 

that operators may gauge the impact of time-dependent threats, like corrosion. Liquid pipeline baseline assessments for pipelines that could affect HCAs were completed for existing pipelines by March 2008. 

Assessments include in-line inspection by ‘‘smart pigs’’, which detect features in 

the pipe that need to be addressed, such as corrosion, pipeline deformation, cracking 

and others. This technology includes sensitive internal detection devices, such as 

magnetic flux leakage tools (MFL) and ultrasonic testing, to examine pipeline wall 

thickness and detect other anomalies. Another assessment method used by pipeline 

operators is pressure-testing. Many operators use these same techniques beyond 

pipeline segments which could affect HCAs. 

Diagram of a Smart Pig 

Pipeline companies perform visual inspections along rights-of-way, including from 

the air, for signs of damage, leakage, and encroachment. Pipeline controllers are 

also trained to identify signs of leaks and respond quickly to shut off pipeline flow, 

contact first responders (company and local government emergency response), and 

government officials. 

Pipeline automation and supervisory control and data acquisition (SCADA) systems use various techniques to monitor for pipeline leaks. Software monitors pipeline pressure instruments and volumetric metering equipment and uses algorithms 

to search the data for a signal that may indicate a leak on the pipeline. 


624FELT1.eps
46 

5 49 CFR Part 195.452. 

6Five Year Review of Oil Pricing Index, FERC Stats and Regs (Order), 71 Fed. Reg. 15,329, 

15,331 (March 28, 2006). 

In some cases, an operator will install check valves, which automatically prevent 

backflow into a pipeline during a shutdown, or remote control valves that can be 

monitored with SCADA systems from a control room and closed if an accident occurs. These valves must be installed if an operator determines they are needed to 

protect an HCA in the event of a release.5 Special attention is given to waterway 

crossings. It is common practice to locate block valves on each side of a waterway. 

There are two ways in which pipe is protected from external corrosion: through 

the use of coatings and by impressed current that makes a pipe act as a cathode. 

Since corrosion is an electro-chemical process, this electrical charge inhibits corrosion even if the protective coating has been damaged. A protective coating is applied 

to steel pipe at the pipe mill to help prevent corrosion when placed into service. 

During the pipeline construction process, construction crews apply protective coatings to joints to safeguard the outside surface of pipeline girth welds from corrosion. 

Costs of Integrity Management Programs 

Liquid pipelines have implemented comprehensive programs to ensure compliance 

with PHMSA’s IMP regulations, and have incurred significant costs associated with 

these activities. It was estimated by DOT before implementation that the liquid 

pipeline industry would spend approximately $279.5 million from 2001–2007 to comply with the IMP regulations.6 However, industry experience demonstrates that the 

actual costs far exceed DOT’s early projection. 

Data from a subset of the industry illustrates the extent of these integrity-related 

costs. Lines representing less than 15 percent of the total DOT-regulated pipeline 

mileage, including systems that transport refined products, crude oil, and natural 

gas liquids, estimate expenditures in excess of $1 billion on required pipeline integrity management activities in the years from 2005 through 2009. In other words, 

in just the past 5 years these pipelines alone exceeded by nearly four times DOT’s 

estimated cost for the total industry for the period 2001–2007. These figures, moreover, do not include integrity costs associated with DOT-regulated storage tanks, 

which would add substantially to the total. With finite resources, pipeline operators 

need to be able to rank risk and consequence, and apply resources accordingly. Pipeline operators should not be required to treat every mile of pipe with the same level 

of oversight. 

It is important to note that as integrity management tools become more sophisticated, they are more effective at identifying issues for pipeline operators to consider. 

As a result, integrity management compliance costs have trended upward since implementation of the IMP regulations, a trend that the industry expects to continue 

in the coming years. 

Damage Prevention and One-Call 

Excavation damage to pipelines is less frequent today, but often results in extremely high consequences. Incidents from excavation damage by third parties accounted for only 7 percent of release incidents from 1999 to 2008. However, 31 percent of all significant incidents (those that result in spills of 50 barrels or more, fire, 

explosion, evacuation, injury or death) come from excavation damage by third parties. Further, at an even higher frequency, pipelines suffer damages from third parties that are not severe enough to cause a release at the time of excavation. 

To protect communities, sensitive environmental areas, as well as the pipeline 

itself, the pipeline industry and other operators of underground facilities joined together to create notification centers that are used by those preparing to conduct excavation close to underground facilities. These centers—called One-Call Centers— 

serve as the clearinghouse for excavation activities that are planned close to pipelines and other underground utilities. Established by Federal law in 2007, 811 is 

the national ‘‘call-before-you-dig’’ number which informs operators, homeowners, and 

excavators about the location of underground utilities before they dig to prevent unintentional damage to underground infrastructure, including pipelines. 

When calling 811 from anywhere in the country, a call is routed to the local OneCall Center. Local One-Call Center operators discern the location of the proposed 

excavation and route information about the proposed excavation to affected infrastructure companies. Under One-Call regulations, excavators must wait a specified 

amount of time before beginning any excavation project, to allow operators of underground infrastructure time to locate and mark underground infrastructure to protect 

it from excavation-related damage. 

47 

7December 14, 2009 letter to Jeffrey D. Wiese regarding 74 FR 55797 (October 29, 2009). 

In addition, pipeline operators, associations, state regulators and Federal and 

state agencies take part in the Common Ground Alliance (CGA), an association that 

promotes effective damage prevention practices for all underground utility industry 

stakeholders to ensure public safety, environmental protection, public awareness 

and education to guard against excavation damage. Membership in CGA spans 

1,400 members and sponsors, demonstrating that damage prevention is everyone’s 

responsibility. Industry has worked closely with CGA to develop best practices and 

participates fully in its damage prevention programs, including the establishment 

and implementation of 811. 

The Need for Improved Damage Prevention Enforcement 

We believe more must be done to encourage adherence to state damage prevention 

laws and strengthen state and national programs already in place. We recognize 

and support the role of the states in preventing damage to pipelines. However, in 

some cases, state excavation damage prevention laws are weak or incomplete, or are 

not adequately enforced. 

On October 29, 2009, OPS issued an Advance Notice of Proposed Rulemaking 

(ANPRM) regarding how it will exert its authority to enforce excavation damage 

prevention laws in states with inadequate damage prevention programs. API and 

AOPL submitted comments that supported OPS enforcement in states with inadequate excavation damage prevention programs and reinforced that OPS should not 

exert its authority in states with strong programs. OPS is headed in the right direction on this important issue. While supporting the ANRPM, we suggested some important changes to the proposed rule. We urge OPS to complete this rulemaking expeditiously. AOPL and API support more aggressive enforcement, recognizing it will 

apply equally to pipeline operators should they fail to adhere to excavation damage 

prevention laws. 

In many states, state agencies, municipalities and other local entities are exempted from requirements to use the One-Call system before they undertake excavation 

activities. These exemptions create a gap in enforcement and safety, because the 

threat of pipeline damage is the same regardless of who the excavator is or who he 

works for. This is of heightened importance now with the expected increase of infrastructure development, especially road building, resulting from recent stimulus 

funding. 

Under the proposed rule, OPS would assess a state’s damage prevention program 

and make the determinations of adequacy or inadequacy called for by Congress. We 

believe OPS should promulgate a final rule that prohibits state programs from being 

determined ‘‘adequate’’ if they allow One-Call exemptions for state agencies, municipalities, and other commercial excavators. 

As AOPL and API commented in the rulemaking,7 we recommended that as a 

minimum requirement in a state damage prevention program, all excavators, including state agencies and municipalities: 

(1) use state One-Call systems prior to excavation; 

(2) follow location information or markings established by pipeline operators; 

(3) report all excavation damage to pipeline operators; and 

(4) immediately notify emergency responders when excavation damage results 

in a release of pipeline products. 

Section 2 of the Pipeline Safety Inspection, Protection, and Enforcement (PIPES) 

Act of 2006 granted OPS the authority to grant funds for damage prevention programs to states adhering to the nine damage prevention principles included in the 

bill. The Secretary is to ‘‘take into consideration the commitment of each State to 

ensuring the effectiveness of its damage prevention program, including legislative 

and regulatory actions taken by the state.’’ Such grants are limited and are not 

enough to incentivize strong state damage prevention programs. Nevertheless, we 

believe OPS should withhold damage prevention grant funds from states whose programs do not meet the fundamental minimum requirements we suggested. 

PIPES Act Implementation 

The PIPES Act of 2006 directed both DOT and the liquids pipeline industry to 

comply with several new and significant safety mandates. Below are several noteworthy provisions of the PIPES Act that have been implemented, or are in the implementation process: 

• Damage prevention enforcement—Section 2 of the PIPES Act granted OPS limited authority to enforce damage prevention laws in states which do not have 

48 

8 75 Fed. Reg. 35366; June 22, 2010. 

qualified state damage prevention programs. It also established civil penalties 

applicable to excavators and individuals that fail to use an available One-Call 

system, ignore markings, or operate without reasonable care. As previously 

mentioned, OPS issued an ANPRM on October 29, 2009, outlining and collecting input on where and how it might exercise its authority to enforce damage prevention laws in states. AOPL and API provided comments and recommended that OPS move forward with a final rule to promote more effective 

and streamlined damage prevention rules that will promote safety and respect 

for pipelines. Finally, OPS has exercised its authority to award state damage 

prevention grants, promoting stronger state damage prevention programs. 

• Control room management (CRM)—Section 12 in the PIPES Act required OPS 

to promulgate regulations requiring pipeline operators to develop a control room 

management plan. A final rule was published on December 9, 2009, that requires operators to define the roles and responsibilities of controllers and provide them with the necessary information, training, and processes to fulfill their 

responsibilities. Operators must include in their plans how they will address 

controller fatigue and length of work shifts. It further requires operators to 

manage SCADA alarms, assure control room considerations are taken into account when changing pipeline equipment or configurations, and review reportable incidents or accidents to determine whether control room actions contributed to the event. As a result of this regulation, the National Transportation 

Safety Board (NTSB) removed the issue of pipeline controller fatigue from its 

Federal Most Wanted List of Transportation Safety Improvement. The liquid 

pipeline industry supports the implementation of the CRM rule, but we hope 

to resolve on-going issues with OPS’s definition of ‘‘controllers’’ and ‘‘control 

rooms’’ in upcoming workshops. If an overly broad definition is applied, it will 

cause significant operational problems for pipeline operators. 

• Accident reporting requirements—OPS implemented new accident reporting requirements that address whether control room personnel are involved in and 

contribute to an accident. 

• Regulatory exemption eliminated for low stress pipelines—Section 4 of the 

PIPES Act required a new rule to remove exemptions for rural low-stress lines, 

which operate at less than 20 percent of their specified minimum yield strength 

(SMYS). On June 3, 2008, OPS issued regulations for rural low-stress pipelines 

of 8 5/8’’ diameter or more within 1⁄2 mile of an Unusually Sensitive Area. All 

rural low-stress lines are required to submit an annual infrastructure report 

under this rule, as well. Generally, we believe this was the right approach. The 

liquid pipeline industry will review and provide comments to PHMSA on the recent Notice of Proposed Rulemaking (NPRM) 8 that would apply Part 195 requirements to all rural low-stress lines not included in the phase one rule. 

Pipeline Safety Reauthorization 

AOPL and API believe OPS is doing a responsible job with the authorities granted 

in the PIPES Act of 2006 and previous statutes. The results of these programs 

should be assessed thoroughly before Congress imposes new mandates. The results 

of the PIPES Act improvements may not be fully apparent for several years. Making 

additional changes before the programs mandated by the PIPES Act of 2006 have 

come into full effect is premature and could dilute the efforts of OPS and the industry. 

If Congress chooses to make changes to the existing pipeline safety program in 

pipeline safety reauthorization legislation, AOPL and API believe any such changes 

should be focused on addressing existing OPS programs. We also suggest the reauthorization should be for a longer period than 4 years, in order to provide more predictability and stability for the pipeline safety program and the industry that must 

implement it. The PIPES Act and previous legislative efforts have given OPS a thorough set of tools and authorities to effectively regulate liquid pipelines. There is no 

reason for Congress to greatly expand the pipeline safety program or impose significant new mandates upon OPS or the industry in a new reauthorization bill. 

We do believe OPS should move quickly to improve excavation damage prevention 

programs in the states, and, most importantly, should remove exemptions for state 

and municipal governments from One-Call requirements. Such exemptions create 

unnecessary opportunities for third-party damage to pipelines. AOPL and API believe Congress should encourage OPS to move forward to issue a final rule on damage prevention based on the October 2009 ANPRM, disallowing any exemptions to 

One-Call requirements. 

49 

We look forward to working with Congress, OPS and other stakeholders to improve pipeline safety and reauthorize the pipeline safety laws. 

I am happy to respond to any questions. 

Senator LAUTENBERG. Thanks very much, Mr. Felt. 

Mr. Sypolt, CEO of Dominion Energy and representing the Interstate Natural Gas Association of America, correct? 

STATEMENT OF GARY L. SYPOLT, CEO, DOMINION ENERGY ON 

BEHALF OF THE INTERSTATE NATURAL GAS ASSOCIATION 

OF AMERICA 

Mr. SYPOLT. Correct. 

Senator LAUTENBERG. Please proceed, Mr. Sypolt. 

Mr. SYPOLT. Chairman Lautenberg, members of the Subcommittee: Thank you for inviting me to testify today on the pipeline of the Nation’s energy safety network. I am Gary Sypolt, CEO 

of Dominion Energy. Dominion is one of the Nation’s largest producers and transporters of energy, with a portfolio of more than 

27,500 megawatts of power generation, 12,000 miles of natural gas 

transmission, gathering, and storage pipeline, and 6,000 miles of 

electric transmission lines. 

Today I am testifying on behalf of the Interstate Natural Gas Association of America, or INGAA, which represents the interstate 

natural gas pipeline industry in North America. INGAA’s members 

transport the vast majority of the natural gas consumed in the U.S. 

through a network of about 220,000 miles of large-diameter pipeline. These transmission pipelines are analagous to the interstate 

highway system. In other words, these are high-capacity transportation systems spanning multiple states or regions. 

Natural gas is increasingly being discussed in the context of the 

climate change debate as a partner with renewables in reducing 

overall emissions from the power and transportation sectors. Many 

of you might also have heard about the recent boom in new domestic natural gas supply development, particularly from shale deposits. Our industry continues to expand at impressive levels due to 

the growth in both natural gas supply and demand. 

As we expand, though, the natural gas pipeline network is touching more and more people, and these people want to be assured 

that this infrastructure is safe and reliable. In other words, safety 

is and always will be our industry’s main focus. 

By all measures, natural gas transmission pipelines are safe, but 

our safety record is not perfect. Accidents have happened and our 

job is to continuously improve our technologies and processes so 

that the number of accidents continues to decline. 

My written testimony highlights some of the statistics with respect to accidents in the natural gas transmission sector. The main 

point I would like to make is that our primary focus has been on 

protecting people and as a result the number of fatalities and injuries associated with our pipelines is low. We want it to be even 

lower. 

One of the main programs that industry has implemented over 

the last decade has been the integrity management program, or 

IMP. This program, which was mandated by Congress in 2002, requires natural gas transmission pipelines to: one, identify all segments located in populated areas, called high consequence areas; 

50 

two, undertake assessments or inspections of those segments within 10 years; three, remediate any problems uncovered, including 

precursors to future problems; and four, undertake reassessments 

every 7 years thereafter. 

We are far along in this process. In fact, we have already started 

to perform reassessments as we are finishing baseline work. My 

written testimony includes some data on the results of the work 

done thus far. 

There are two important take-aways from this work that I would 

like to share with the Subcommittee. First, the data strongly suggests that on reassessments the number of precursors to corrosion 

we are finding are significantly lower than those found in baseline 

assessments. Since corrosion is a time-dependent phenomenon that 

occurs over a fairly predictable timeframe, these periodic reassessments are able to catch corrosion precursors before they manifest 

themselves into failures. 

The other take-away is that the technology for conducting these 

assessments, primarily internal inspection devices known as smart 

pigs, continues to develop and improve over time. A new generation 

of these devices is currently employed and is giving us a more 

granular view of the conditions of our pipeline system. 

The last 4 years have also seen several additional improvements 

in pipeline safety. My written testimony includes a discussion of 

the safety initiatives that have been completed in recent years. 

This leads me to one of my main points. The pipeline safety program, at least with respect to natural gas transmission pipelines, 

is working well to reduce accidents and to protect the public. 

PHMSA has the authority it needs to improve standards over time. 

INGA believes that, given this level of performance and in addition 

the short amount of time remaining in this Congress, a simple reauthorization of the Pipeline Safety Act is the logical step for Congress to make. We support a straightforward reauthorization that 

leaves the current programs in place and pledge to work with you 

in enacting such a bill. 

However, if you choose to pursue a broader bill we offer the three 

following suggestions: One, damage prevention is critical in our industry. State One-Call programs are critical to avoiding accidents 

and preventing fatalities and injuries. I’m pleased to say that our 

home State of Virginia serves as a model for this Nation. But despite all the progress, some improvements still need to be made. 

Two recent accidents in Texas caused by third party excavation 

damage demonstrate the need to make further improvements to 

state damage prevention programs. We’d like to work with you in 

suggesting some improvements. 

Two, as we implement the IMP program it is becoming clear that 

the 7-year reassessment requirement mandated by the 2002 reauthorization bill is not necessary. A more informed, risk-based approach is more logical for determining the appropriate reassessment period. Both the GAO and PHMSA have recommended that 

Congress update this requirement. We support those recommendations. 

Third, we ask that Congress charge the PHMSA with identifying 

and retiring legacy regulations that have become redundant in the 

new integrity management era. 

51 

Mr. Chairman, we are proud of the pipeline improvements that 

have been made in the industry over the last decade. We hope that 

you agree much has improved. Thank you again for graciously inviting me to testify today and I will be happy to take questions at 

the appropriate time. 

[The prepared statement of Mr. Sypolt follows:] 

PREPARED STATEMENT OF GARY L. SYPOLT, CEO, DOMINION ENERGY ON BEHALF OF

THE INTERSTATE NATURAL GAS ASSOCIATION OF AMERICA

Mr. Chairman and members of the Subcommittee: 

Good afternoon. My name is Gary Sypolt, and I am CEO of Dominion Energy. Dominion Energy is the natural gas-related business unit of Dominion Resources. Dominion Resources is one of the Nation’s largest producers and transporters of energy, with a portfolio of more than 27,500 megawatts of generation, 12,000 miles 

of natural gas transmission, gathering and storage pipeline and 6,000 miles of electric transmission lines. Dominion operates the Nation’s largest natural gas storage 

system with 942 billion cubic feet of storage capacity, and owns and operates the 

Cove Point liquefied natural gas facility in Maryland. We also serve retail energy 

customers in 12 states. Our corporate headquarters are in Richmond, Virginia. 

I am testifying today on behalf of the Interstate Natural Gas Association of America (INGAA). INGAA represents the interstate and interprovincial natural gas pipeline industry in North America. INGAA’s members transport the vast majority of 

the natural gas consumed in the United States through a network of approximately 

220,000 miles of transmission pipeline. These transmission pipelines are analogous 

to the interstate highway system; in other words, these are large capacity transportation systems spanning multiple states or regions. 

Natural Gas 

While natural gas has been an important part of the United States energy supply 

portfolio for many years, the recent focus on energy security and controlling emissions of greenhouse gases is making natural gas even more important to America’s 

energy future. Natural gas currently provides about 25 percent of the total energy 

utilized in the Nation. This includes fueling the generation of about 20 percent of 

our electricity and heating the bulk of our homes and businesses. The clean-burning 

properties of natural gas make it an attractive resource for the future as the U.S. 

looks for ways to reduce carbon and other emissions. Many experts have advocated 

natural gas as a logical ‘‘partner’’ for renewable power resources, with natural gas 

providing reliable electricity when conditions do not permit the operation of solar 

and/or wind generation. In addition, natural gas remains a largely domestic energy 

resource. The U.S. produces approximately 85 percent of the natural gas consumed 

domestically; most of the remaining natural gas supplies are imported from Canada. 

Only about 2 percent of our natural gas supply is imported from outside of North 

America. There is little doubt that natural gas can fulfill its potential as a long-term 

contributor to the U.S. energy future. Natural gas supplies have grown dramatically 

in just the last 5 years, and it is estimated that the U.S. natural gas resource base 

can supply us for more than 100 years at current consumption levels. 

Regulatory Structure of the Interstate Natural Gas Transmission System 

Mr. Chairman, I am going to limit my comments to the segment of the natural 

gas delivery system represented by INGAA—the interstate natural gas transmission 

system. As I mentioned, interstate natural gas transmission pipelines can be compared to the interstate highway system and as such, cross state boundaries and 

have a significant impact on interstate commerce. Congress recognized the inherently interstate nature of this commerce by enacting the Natural Gas Act to provide 

for Federal economic regulation of interstate pipelines in 1938 and, shortly thereafter, expanded this Federal role to include siting authority for such pipelines. This 

law now is administered by the Federal Energy Regulatory Commission (FERC). 

With regard to pipeline safety, Congress enacted the Natural Gas Pipeline Safety 

Act in 1968. This law (as amended) provides for the exclusive regulation of interstate natural gas and hazardous liquid pipelines by the Office of Pipeline Safety 

(OPS) located in the Pipeline and Hazardous Materials Safety Administration 

(PHMSA). The authority to regulate intrastate pipelines is largely delegated to state 

pipeline safety agencies. 

It is worth noting that with regard to the Nation’s interstate natural gas pipelines, the regulation of economic matters and the regulation of safety matters have 

always been handled by two separate entities. The exclusive safety focus of PHMSA 

52 

1 Additional information is available in individual pipeline incident reports http:// 

www.phmsa.dot.gov/portal/site/PHMSA/menuitem.ebdc7a8a7e39f2e55cf2031050248a0c/?vgnex 

toid=fdd2dfa122a1d110VgnVCM1000009ed07898RCRD&vgnextchannel=3430fb649a2dc110VgnV 

CM1000009ed07898RCRD&vgnextfmt=print. 

has been an advantage of the agency. Over the years, some have suggested an expansion of PHMSA’s authority beyond safety matters. Given the importance of the 

mission, and the fact that PHMSA has a relatively small staff, we are concerned 

about any movement away from safety. INGAA urges Congress and the Administration to maintain that exclusive safety focus for PHMSA. 

Following enactment of the Natural Gas Pipeline Safety Act, OPS adopted pipeline safety regulations (in 1970) for natural gas transmission pipelines based on engineering consensus standards developed by the American Society of Mechanical Engineers. These engineering consensus standards first were adopted by the industry 

in 1953 and had been continually updated over the following decades. OPS established performance measures (e.g., pipeline accident reports, company activity 

records and engineering documentation) and initiated a formal inspection and enforcement program for interstate natural gas transmission pipeline systems. Conversely, natural gas intrastate or distribution piping safety guidelines were implemented under similar pipeline safety regulations and were delegated to the state 

pipeline safety agencies. Hazardous liquid pipelines were incorporated into the OPS 

regulatory structure in 1984. 

The pipeline safety processes of INGAA member companies and the applicable 

regulations for natural gas transmission pipelines have evolved and become more 

refined over the last 40 years as new technology has became available, new physical 

properties have been identified through engineering and scientific analysis, and societal expectations have changed. These substantive changes in processes and regulations have been accomplished through: 

• Continuing research, 

• Improved practices and processes, 

• Revised engineering consensus standards, 

• New regulatory initiatives, 

• Focused Congressional actions, and 

• Improved education and training. 

Natural Gas Transmission Pipelines are the Safest Mode of Energy 

Transportation 

While natural gas transmission pipeline operators will not be satisfied without 

continuous safety improvement, the safety record of our industry compares very well 

to other modes of transportation and energy delivery. One way to measure safety 

performance is to identify the number of accidents involving a fatality or injury. 

These are classified as ‘‘serious’’ incidents by OPS. Because natural gas pipelines 

are buried and typically are in isolated locations, pipeline accidents involving fatalities and injuries are very rare. 

For example, the chart below (from OPS) sets forth safety statistics for natural 

gas transmission pipelines since the last Pipeline Safety Act reauthorization. This 

chart first depicts the categories of fatalities and injuries. It also categorizes property damage based on whether it is damage to public property or damage to the 

pipeline operator’s property and the amount of natural gas lost to the atmosphere 

during both the accident and the subsequent repair of the pipeline. 

National Gas Transmission Onshore: Consequences Summary Statistics: 2005–2009 

Year 

Public 

Fatalities 

Industry 

Fatalities 

Public 

Injuries 

Industry 

Injuries 

Total 

Property 

Damage 

(C) (D) 

Damage to 

Public Property 

(E) (C) 

Damage to 

Industry Property 

(F) (C) 

Value of Product 

Lost 

(C) 

2005 0 0% 0 0% 2 40% 3 60% $214,506,403 $98,072,639 45% $105,375,752 49% $11,058,012 5% 

2006 1 33% 2 66% 1 33% 2 66% $31,020,029 $2,869,452 9% $20,882,094 67% $7,268,481 23% 

2007 1 50% 1 50% 1 14% 6 85% $44,562,382 $1,630,991 3% $24,096,641 54% $18,834,750 42% 

2008 0 0% 0 0% 2 40% 3 60% $111,608,494 $6,643,699 6% $98,424,350 88% $6,540,445 5% 

2009 0 0% 0 0% 7 63% 4 36% $31,789,417 $2,005,498 6% $25,216,056 79% $4,567,863 14% 

Totals 2 40% 3 60% 13 41% 18 58% $433,486,727 $111,222,281 25% $273,994,894 63% $48,269,552 11% 

From 2005 to 2009,1 there have been two public fatalities due to natural gas 

transmission line accidents. One in 2006 involved a bystander near an incident 

caused by excavation damage to the pipeline, and the other in 2007 involved a driver in an automobile near a pipeline incident caused by corrosion. The three non-pubVerDate Nov 24 2008 07:17 Jul 12, 2011 Jkt 067270 PO 00000 Frm 00056 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\67270.TXT SCOM1 PsN: JACKIE
53 

2 An anomaly is defined as a precursor to a possible reportable incident in the future. 

3 ‘‘The rule will significantly reduce the likelihood of pipeline accidents that result in deaths 

and serious injuries.’’; Page 69800, Federal Register/Vol. 68, No. 240/December 15, 2003. 

lic natural gas transmission pipeline fatalities since 2005 were a third-party excavator, a pipeline employee and a contractor working for a pipeline company. 

During this same period, 2005 to 2009, there were 13 injuries to the public. Four 

of these occurred when citizens were in vehicles that struck and damaged pipeline 

facilities. There were also five injuries to third-party excavators and 13 injuries to 

either pipeline employees or contractors working for the pipeline company. 

As you can see from the chart, on the average, natural gas transmission pipeline 

incidents do not greatly affect public property. The exception in 2005 primarily was 

attributable to $85 million of damage to a power plant adjacent to a pipeline accident. The large amount of industry property damage in 2005 was related to the 

Katrina/Rita hurricane damage in the Gulf Coast region and the large number in 

2008 was largely due to a tornado destroying a pipeline compressor station ($85 million). 

Progress Since the Last Reauthorization 

Pipeline Integrity Program 

Section 14 of the Pipeline Safety Improvement Act of 2002 (PSIA) mandated an 

integrity management program for natural gas transmission pipelines. Specifically, 

the PSIA requires operators of natural gas transmission pipelines to: (1) identify all 

the segments of their pipelines located in areas where the pipeline is adjacent to 

significant population density, known as high consequence areas (HCAs); (2) develop 

an integrity management program (IMP) to reduce the risks to the public in these 

HCAs; (3) undertake structured baseline integrity assessments (inspections) of all 

pipeline segments located in HCAs, to be completed within 10 years of enactment; 

(4) develop a process for repairing any anomalies 2 found as a result of these inspections; and (5) reassess these segments of pipeline every 7 years thereafter in order 

to verify continued pipe integrity. 

The PSIA requires that these integrity inspections be performed using one of four 

methods: (1) an inline inspection device, alternatively called a smart pig; (2) hydrostatic pressure testing (filling the pipe up with water and pressurizing it well above 

operating pressures to verify a safety margin); (3) direct assessment (digging up and 

visually inspecting sections of pipe); or (4) ‘‘other alternative methods that the Secretary of Transportation determines would provide an equal or greater level of safety.’’ 

Following such inspections, a pipeline operator is required by the PHMSA regulations implementing the PSIA to repair all non-innocuous anomalies and adjust operation and maintenance practices (i.e., apply additional corrosion protection measures 

in active corrosion areas to prevent further corrosion growth) to minimize the probability of ‘‘serious incidents.’’ 3

Baseline IMP assessments—the type of work in which our industry now is engaged—are an effective means of identifying any material or original construction 

defects that were not discovered when a pipeline was built as well as active corrosion problems. Corrosion is an on-going, time-based phenomenon that is managed 

and controlled using integrated technologies and processes (e.g., cathodic protection, 

pipe coatings). Internal inspection devices are the predominant means for performing integrity assessments of natural gas transmission pipelines, because these 

are the most versatile and efficient devices for this inspection process. The other assessment alternatives prescribed by statute are useful when smart pig technology 

cannot be effectively used. A drawback associated with these other alternatives is 

that they require a pipeline to cease or significantly curtail natural gas delivery operations for significant periods of time (e.g., hydrostatic pressure test) or else require 

extensive excavation of the pipeline during every assessment (e.g., direct assessment). 

Periodic risk-based reassessments are an effective method for identifying whether 

corrosion prevention systems are adequately preventing this ‘‘time-dependent’’ deterioration. While material and original construction defects are not common, they are 

for practical purposes eliminated for the remaining life of the pipeline once they are 

identified during a smart pig assessment (or the post-construction hydrostatic test) 

and repaired. Recently designed smart pigs can also effectively identify small dents 

in the pipeline. These dents may or may not be precursors for a corrosion failure, 

depending upon whether the pipe has been gouged. Sorting through these dents to 

identify actual corrosion precursors is a current focus using these updated smart pig 

devices. 

54 

Based on data from over three quarters of the IMP inspection baseline period 

(2002–2009), there is ample basis for concluding that the integrity of our pipelines 

is being maintained and that such pipelines are becoming safer as a result of eliminating the precursors to possible future accidents. It also is clear that the industry 

is dutifully implementing the IMP program prescribed by Congress, since all INGAA 

member companies have been subject to in-depth IMP audits by PHMSA to assure 

that the programs are comprehensive and implemented consistently according to 

Congressional mandates and PHMSA requirements. 

PHMSA has received the reports on IMP progress achieved through the end of 

2009 and the data is presented on the following tables. The first table depicts the 

transmission pipelines that have been subject to an assessment for the first time 

under the IMP program (baseline). Let me highlight a particular performance measure. The ‘‘Immediate’’ category includes small isolated anomalies (e.g., corrosion, 

pipe dent with a gouge) that should be repaired quickly, since these situations 

might lead to a leak or pipe rupture within a short period of time. The ‘‘Scheduled’’ 

category addresses individual anomalies (e.g., corrosion) that should be repaired or 

reassessed before they grow to the ‘‘Immediate’’ category. The bottom row depicts 

the rate (per mile) of finding either ‘‘Immediate’’ or ‘‘Scheduled’’ category anomalies 

after decades of operation (e.g., 10–50 years). 

Baseline IMP Data for Gas Transmission Pipeline 

Integrity Program 

Natural Gas 

Onshore Transmission 

Miles within U.S. 

Transmission Pipeline 

Miles 

Assessed 

per Year 

Coincidently 

with the IMP program 

Total Number of 

Miles of 

Pipelines 

within 

HCAs 

Miles of Pipe 

Assessed 

within HCAs per Year 

Number of 

Immediate 

Category 

Anomalies 

(failure 

precursors) 

within an HCA 

Number of 

Scheduled 

Category of 

Anomalies 

within an HCA 

2004 298,207 31,273 21,764 3,997 104 599 

2005 297,968 19,516 20,561 2,908 261 378 

2006 293,696 20,250 19,949 3,500 169 342 

2007 291,898 25,940 19,277 4,661 258 452 

2008 295,779 20,258 19,568 2,454 146 217 

2009 (preliminary) 283,975 22,015 18,663 2,269 124 251 

Cumulative Baseline 

Inspection Results 

139,252 19,789 1,062 2,239 

Rate of Anomalies found 

(dents & corrosion) in the 

Baseline Assessment (per 

Mile) .054 .113 

As these ‘‘Immediate’’ and ‘‘Scheduled’’ time-dependent precursors (e.g., anomalies 

that could possibly grow in size) are remediated and rendered benign, we expect 

that the rate of ‘‘Immediate’’ and ‘‘Scheduled’’ anomalies will decrease with subsequent assessments. This is because the gestation period of these corrosion anomalies 

to grow (if corrosion is active) to failure is significantly longer than either the 

present prescriptive seven-year reassessment requirement or the risk-based reassessment intervals recommended by GAO and consensus standards organizations 

(see later discussion). 

Since the inception of the IMP program in 2002 through 2009, there have been 

no reported significant incidents caused by corrosion to pipelines within the HCAs 

that have been assessed. 

The next table depicts the results of reassessments that are occurring concurrently on natural gas transmission pipelines that had been previously assessed 

under the IMP baseline program. As with the baseline assessment, ‘‘Immediate’’ and 

‘‘Scheduled’’ precursors are identified, assessed to determine if they have changed 

and then remediated. As shown in the fourth row, the rate of occurrence of these 

corrosion anomalies and dents is significantly reduced from the baseline assessment. 

55 

4 IMP data collected by OPS, enhanced by detailed interviews with INGAA respondents 

5 Integrity Management Reinspection Intervals Evaluation, Pipeline Research Council International, Inc., December 2005. 

Reassessment Data for Gas Transmission 

Pipeline Integrity Program 

Miles of Pipe 

Re-Assessed within 

an HCAs per Year 

Immediate 

Categories of 

Anomalies 

(failure precursors) 

within an HCA 

Scheduled 

Categories of 

Anomalies within 

an HCA 

2008 348 9 4 

2009 (preliminary) 903 20 16 

Cumulative Reassessment Inspection Results 1,285 29 20 

Rate of Anomalies (dents & corrosion) found 

in the Reassessment (per Mile) 

.023 .016 

Rate of Corrosion Anomalies (only) found in 

the Reassessment (per Mile) 

.003 .011 

In addition, the last row 4 depicts the low rate of corrosion anomalies found on 

the reassessments, the main focus of the IMP program. It is worth emphasizing that 

other data obtained from pipeline operators who have completed multiple integrity 

assessments over a number of years, and reviewed by GAO, strongly suggests a dramatic decrease in the occurrence of time-dependent precursors requiring repairs in 

subsequent assessments. This is due to corrective action being implemented based 

on prior integrity assessments. Also, technical analysis 5 undertaken in 2005 by the 

Pipeline Research Council International (PRCI), an international consensus research group, demonstrated a significant reduction in the number of serious anomalies found during risk-based reassessments (as compared to baseline assessments), 

suggesting that risk-based assessments using smart pig technology are extremely effective in identifying potential problems before they manifest themselves into safety 

problems. 

Pipeline Controller Regulation 

In 2001, the National Transportation Safety Board (NTSB) issued a report concerning fatigue among hazardous liquid pipeline controllers. In response, OPS undertook an effort from 2002 to 2008 to investigate pipeline control operator fatigue 

and identify possible solutions. While the NTSB report did not focus on natural gas 

transmission pipeline control room operators, INGAA participated extensively in 

this study effort. OPS issued a Notice of Proposed Rulemaking on this matter in 

September 2008. During the rulemaking, INGAA proactively worked with other 

pipeline trade associations to recommend changes to the proposal that would reflect 

the difference of practices and risks between hazardous liquid, natural gas transmission and natural gas distribution control operations. Since the rule was finalized 

in December 2009, INGAA member companies, working in collaboration with the 

Southern Gas Association, have developed an implementation manual for natural 

gas transmission and distribution operators. This implementation manual has been 

reviewed by OPS and NTSB. In February 2010, the NTSB announced that it was 

satisfied that its recommendation on control room personnel fatigue had been addressed by these actions. As a result, control room operator fatigue was removed 

from the NTSB list of ‘‘Most Wanted’’ safety improvements. 

Improved Incident Data and Transparency 

In 2007, INGAA requested that OPS reassess the reporting criteria for reportable 

incidents and suggested that incident forms be amended to facilitate better data 

analysis of the causes and consequences of these incidents. For example, the value 

of natural gas lost from an incident is included in total property damage numbers. 

As natural gas prices increased dramatically over the last 10 years, this metric 

caused an increase in reportable incidents since property damage above a fixed 

threshold is one trigger for reporting an incident. INGAA asserted that incident 

data should not be artificially impacted by natural gas commodity prices. OPS undertook an effort to modify its data requirements and the result is an accident reporting form that more accurately depicts the severity of incidents. We believe this 

data will assist the industry, OPS and concerned public assessing the risk of natural 

gas transmission pipelines and determining whether modified practices and procedures are reducing the occurrence of pipeline accidents. 

Allowing Increased Operating Pressure in Specific Transmission Pipelines 

In 2006, several INGAA member companies requested that OPS consider allowing 

newer pipelines with improved technologies to operate a higher operating pressure. 

The ‘‘safety factors’’ for natural gas pipelines were established in the 1950s and OPS 

56 

adopted those safety factors in the original pipeline safety regulations promulgated 

in the 1970s. Since then, pipeline technologies and processes have advanced tremendously (e.g., materials, IMP, smart pigs). The operating pressure proposed by the 

pipelines already was part of international engineering consensus standards, and 

Canada has utilized these refined criteria since the 1980s. The United Kingdom 

adopted these criteria for their existing pipeline infrastructure in the 1990s after 

it determined that this change would result in no effective reduction in the safety. 

The U.K. also concluded that these updated criteria would enable more efficient use 

of the country’s existing infrastructure and thereby obviate the need to construct additional pipeline capacity (along with all of the disruption that would cause in such 

a densely populated country). Utilizing extensive prior research and international 

experience, OPS issued several special permits to allow higher operating pressures 

than previously allowed under regulations and to assess the benefits of additional 

design, construction, operating and maintenance requirements imposed as a condition for such permits. This exploratory work has resulted in a new regulation that 

will allow higher operating pressure on new pipelines that meet much stricter criteria for design, construction, operation and maintenance. 

Improved Material and Construction Practices for Natural Gas Transmission 

Pipelines 

The natural gas transmission pipeline infrastructure in the U.S. has expanded 

significantly in the last decade to meet increased demand for natural gas and to 

connect new natural gas supply basins to consuming markets. This surge in new 

pipeline construction required many new material sources, especially steel pipe. At 

the same time, OPS adopted more stringent material, construction and inspection 

regulatory requirements for projects approved with special permits (allowing increased operating pressure in specific transmission pipelines) that exceeded those 

for comparable pipelines in other nations. The conjunction of these two events resulted in the unacceptable performance of a sample of steel pipe in a particular 

pipeline project during pre-service integrity testing. INGAA, in cooperation with 

OPS, embarked on an unprecedented effort to identify the phenomenon that caused 

these pre-service pipe quality issues and to implement processes and procedures to 

minimize the occurrence of these events in the future. All pipelines wishing to operate at higher pressures (under these new regulatory requirements) have quickly 

adopted these practices and procedures. This cooperative process resulted in significantly faster implementation of solutions than would have occurred under the traditional engineering consensus standards process or a rulemaking by the agency. 

Concurrently, INGAA has focused on identifying ways to improve the process for 

constructing new natural gas transmission pipelines. This requires a reassessment 

of the traditional Quality Assurance and Quality Control (QA/QC) processes and 

practices in light of changes in materials, technology, the expectations of industry 

and regulators. The same implementation model used in the pipe quality effort is 

being utilized to affect change quickly in the construction process. 

Incorporation of Safety Culture 

INGAA member companies are exploring new avenues for improving employee 

and public safety performance. While important, there are limits on the ability to 

achieve improvements based solely on traditional techniques such as training, qualification and increased inspection. Pipeline workers—whether pipeline employees, 

contractors or excavators—must be motivated to make safety a primary focus. There 

must be a safety culture. Safety culture has been described as an inherent attitude 

toward safety of an individual, whether they are supervised or not supervised. Our 

goal is to create and improve this safety culture. 

The U.S. Chemical Safety Board has advocated safety culture as a constructive 

means to improve safety performance, and INGAA has embraced this philosophy. 

The natural gas transmission pipeline industry has had an excellent employee safety record over the decades and we have extended that focus and thought process 

to encompass work practices as they impact public safety. We are now in the third 

year of implementing this process and have invited our contractor community (members of the INGAA Foundation, which is affiliated with INGAA) to adopt the philosophy as well. 

Recommendations to Improve the Pipeline Safety Act 

The regulatory and process changes referenced in this testimony all point to a 

pipeline safety regime that is working well to minimize risk to the public. INGAA 

believes that the existing pipeline safety program has been a success, especially 

with respect to natural gas transmission efforts. For this reason, we would endorse 

a simple reauthorization bill that reauthorizes the pipeline safety program for 4 

years without any new regulatory programs or mandates. Given the success of the 

57 

6GAO–06–945, Natural Gas Pipeline Safety: Risk-Based Standards Should Allow Operators 

to Better Tailor Reassessments to Pipeline Threats, September 2006. 

program over the last 4 years, the expiration of the current authorization in September, and the short time remaining in this Congress, a simple reauthorization bill 

is a logical solution. Still, should Congress choose to move beyond a simple reauthorization bill, we would offer the following suggestions, which build on existing efforts 

under the law. 

Removal of Exclusions from Participating in Excavation Damage Prevention 

Program 

The ‘‘serious’’ incident data cited earlier in my testimony points to the importance 

of damage prevention as an essential means to avoid fatalities and injuries. The 

Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 (PIPES Act) 

took an important step forward by creating incentives for states to adopt improved 

damage prevention programs that meet nine critical elements identified in the Act. 

This was an important step in raising the performance bar across the states. 

One of the larger issues still existing in some of the State excavation damage prevention programs is the categorical exclusion of certain excavators from the notification requirements of state ‘‘one-call’’ systems. These excluded groups often include 

entities such as state highway departments (and their contractors), municipal governments and railroads, who together represent a significant percentage of excavation activity each year. In order to provide the public with maximum protection, 

exemptions from state one-call programs should be strongly discouraged. We recommend that such one-call exemptions be a factor that PHMSA must consider when 

deciding whether to make annual state pipeline safety grants and one-call grants. 

The importance of damage prevention was highlighted in two recent pipeline accidents in Texas. On June 7, an intrastate natural gas pipeline near Dallas was 

struck by utility workers building a power line, causing one fatality and eight injuries. The next day, another intrastate natural gas pipeline in the Texas Panhandle 

was struck by a bulldozer engaged in construction work, causing two fatalities and 

one injury. The Texas Railroad Commission (which regulates these pipelines) and 

the National Transportation Safety Board are investigating these accidents, so the 

precise causes remain unknown. However, it is clear that some sort of 

miscommunication occurred between the excavators and the pipeline operators. Effective communication is the key, but the fact that these preventable accidents are 

still happening means that more remains to be done. An effective damage prevention effort is about more than just making the first call; it also means full participation by all excavators and underground utility operators, accurate and timely marking of underground utilities when a call is made, and using due caution when excavating around marked underground utilities. Every state program should actively 

be moving toward these goals. 

Risk-Based Interval for Reassessments in the Integrity Management Program 

During the last reauthorization, INGAA petitioned Congress to remove the statutory requirement for mandatory reassessments every 7 years for natural gas transmission pipeline in HCAs. We have previously provided Congress with the rationale 

supporting this amendment, along with detailed technical support and evidence of 

the concurrence by many groups including OPS, GAO, international pipeline safety 

experts and the American Society of Mechanical Engineers (ASME). 

As part of the PIPES Act, Congress directed OPS to present a recommendation 

on whether to amend the law governing reassessment intervals on natural gas 

transmission pipelines. Deputy Secretary of Transportation Adm. Thomas Barrett 

outlined the numerous reasons why the seven-year requirement should be rescinded 

in a memo to Congress dated November 27, 2007. The GAO developed a report 6 on 

this issue as well, stating in 2006: 

To better align reassessments with safety risks, the Congress should consider 

amending section 14 of the Pipeline Safety Improvement Act of 2002 to permit 

pipeline operators to reassess their gas transmission pipeline segments at intervals based on technical data, risk factors, and engineering analyses. Such a revision would allow PHMSA to establish maximum reassessment intervals, and to 

require short reassessment intervals as conditions warrant. 

Since then, OPS and the industry have gathered additional documentation, data 

and experience that validate the previous request. We believe a clear statutory mandate from Congress authorizing the adoption of risk-based intervals would not reduce safety performance, but would enhance safety through a more efficient and effective allocation of industry and PHMSA resources. 

58 

Review of Legacy PHMSA Regulatory Requirements in Light of New Technology and 

Processes 

One of the benefits of the IMP was the improvement of pipeline management 

practices due to new technology and processes. Much of the justification of the cost 

effectiveness of the new IMP regulatory program was that legacy pipeline safety requirements, such as class location upgrades, would be superseded by new, more sophisticated regulations and practices. While the industry has adopted the new, more 

sophisticated practices and has documented them in consensus standards, redundant legacy OPS regulations, such as mandatory class location upgrades, remain in 

place. This causes an unnecessary overlap in procedures to achieve the same safety 

goals. 

INGAA would request that Congress charge PHMSA and consensus standards organizations such as the ASME with examining whether parts of the present compendium of pipeline safety regulations have become redundant in light of changes 

in technology and processes adopted by more recent regulations. If the record supports a conclusion that such legacy requirements are redundant and unnecessary, 

we ask that such regulations be rescinded in favor of the new (and more effective) 

integrity management requirements. 

Conclusion 

Mr. Chairman, this subcommittee and the Congress can take pride in the fact 

that the pipeline safety efforts embarked upon by you and your colleagues have improved public safety significantly in the last decade. An energy delivery system that 

was, by all measures, already the safest in the nation, has continued to define new 

boundaries for developing a safety culture and reducing risk to the public. Given 

the importance of natural gas in America’s energy future, the construction and operation of a safe transportation system for natural gas is critical. INGAA and its 

members will not be satisfied without continuous safety improvement, but we have 

worked hard in implementing the Congressional goals articulated in the PIPES Act 

and in the PSIA. The safety performance metrics collected by PHMSA from the 

member companies of INGAA demonstrate this commitment. This is an effective 

safety program, and we hope you agree that any changes should build on existing 

programs and successes. 

Thank you for holding this hearing and for inviting me to participate on behalf 

of INGAA. Please let us know if you have any additional questions, or need additional information. 

Senator LAUTENBERG. Thank you very much. 

Mr. Weimer. 

STATEMENT OF CARL WEIMER, EXECUTIVE DIRECTOR, 

PIPELINE SAFETY TRUST 

Mr. WEIMER. Chairman Lautenberg, Ranking Member Thune, 

and members of the Subcommittee: Thank you for inviting me to 

speak today on the important subject of pipeline safety. My name 

is Carl Weimer and I’m the Executive Director of the Pipeline Safety Trust. The Pipeline Safety Trust is the only nonprofit organization in the country that strives to provide a voice for those affected 

by pipelines. With that in mind, we are here today to speak for the 

relatives of the 58 people who have been killed, the 225 people who 

have been injured, and for those who have been burdened by over 

$900 million in property damage from pipeline incidents that have 

occurred since we last spoke to this committee in November 2006. 

We provided many ideas for improvements in our written testimony, but would like to concentrate on just a few of them here this 

afternoon. Our priority for this year’s reauthorization is the expansion of the integrity management rules to more miles of pipeline. 

Integrity management has been one of the most important aspects 

of both the Pipeline Safety Improvement Act of 2002 and the 

PIPES Act of 2006, and it’s what requires that once a pipeline is 

put in the ground that it is ever inspected again. 

59 

Currently only 44 percent of hazardous liquid pipelines and only 

7 percent of natural gas transmission pipelines fall under these important integrity management inspection rules. Of all the deaths 

caused by these types of pipelines since 2002, over 75 percent of 

them have occurred on pipelines not required to meet these rules. 

This summer will be the 10-year anniversary of the Carlsbad, 

New Mexico, pipeline explosion that killed 12 people. In response, 

Congress passed the Pipeline Safety Improvement Act of 2002, 

which required integrity management of natural gas transmission 

pipelines within certain high consequence areas. Unfortunately, 

these areas are still so narrowly defined that they don’t even include the Carlsbad pipeline area where 12 people died. People who 

live and work near pipelines in more rural areas interpret this to 

mean that Congress and PHMSA have decided their lives are not 

worth protecting with these same important integrity management 

rules. 

When integrity management was first conceived, leaders within 

Congress and PHMSA stated that in the future these types of inspection requirements would be expanded. We believe the future is 

now and that the industry now has the experience and the equipment necessary to begin similar inspections on the over 300,000 

miles of pipelines that currently have no such requirements. 

For these reasons, the Trust asks you to direct PHMSA to initiate a rulemaking to implement a similar integrity management 

program on all the pipelines that fall outside of the current rules. 

In the PIPES Act of 2006, Congress made clear its desire that 

states move forward with damage prevention programs. We hope 

Congress will encourage PHMSA to continue to move forward with 

its recent proposed rulemaking regarding damage prevention. 

There is also a huge lack of valid data regarding excavation damage to pipelines that makes it nearly impossible to implement programs strategically and cost-effectively. We hope Congress will require PHMSA to ensure there is a valid mandatory reporting requirement for excavation damage. 

After 2 years of work, a multi-stakeholder group of more than 

150 people from around the country, the Pipelines and Informed 

Planning Alliance, is about to release a report that makes recommendations for actions that local government can take to protect 

people and pipelines through their land use regulations when new 

development is proposed near pipelines. This effort is a holdover 

from the 2002 reauthorization and will implement the recommendations of a Congressionally mandated Transportation Research Board report. 

Such development encroachment near pipelines is a growing 

problem nationwide and the Trust asks that this year Congress authorize $500,000 per year to promote, disseminate, and provide 

technical assistance to local governments regarding the PIPA recommendations so they are actually aware that they exist. 

Finally, there is still a good deal of work to do for PHMSA to finalize the low-stress pipeline mandates of the PIPES Act and to institute similar rules for unregulated sections of natural gas gathering and production pipelines, particularly in urban areas. Technical assistance grants to communities need to be authorized and 

funded so local communities can learn more about the pipelines in 

60 

their midst, and industry public awareness programs need to be 

upgraded to ensure their effectiveness, as the NTSB has recently 

noted in one of their recommendations. 

Congress needs to ensure that PHMSA has the resources necessary to ensure that the many miles of new pipelines being constructed are adequately inspected during construction and that the 

public and local government is adequately involved in the review 

of special permits, spill response plans, and the designation of high 

consequence areas. 

Thank you again for this opportunity to testify today. We hope 

you will consider some of the ideas we have brought forward, and 

we’d be glad to answer any questions now or in the future. 

[The prepared statement of Mr. Weimer follows:] 

PREPARED STATEMENT OF CARL WEIMER, 

EXECUTIVE DIRECTOR, PIPELINE SAFETY TRUST

Good afternoon, Chairman Lautenberg, Ranking Member Thune and members of 

the Subcommittee. Thank you for inviting me to speak today on the important subject of pipeline safety. My name is Carl Weimer and I am testifying today as the 

Executive Director of the Pipeline Safety Trust. I am also a member of the Pipeline 

and Hazardous Materials Safety Administration’s (PHMSA) Technical Hazardous 

Liquid Pipeline Safety Standard Committee, as well as a member of the steering 

committee for PHMSA’s Pipelines and Informed Planning Alliance. I also serve on 

the Governor-appointed Washington State Citizens Committee on Pipeline Safety, 

and bring a local government perspective to these discussions as an elected member 

of the Whatcom County Council in Washington State. 

The Pipeline Safety Trust came into being after the 1999 Olympic Pipe Line tragedy in Bellingham, Washington that left three young people dead, wiped out every 

living thing in a beautiful salmon stream, and caused millions of dollars of economic 

disruption. After investigating this tragedy, the U.S. Department of Justice (DOJ) 

recognized the need for an independent organization that would provide informed 

comment and advice to both pipeline companies and government regulators, and 

would provide the public with an independent clearinghouse of pipeline safety information. The Federal trial court agreed with the DOJ’s recommendation and awarded the Pipeline Safety Trust $4 million which was used as an initial endowment for 

the long-term continuation of the Trust’s mission. 

The vision of the Pipeline Safety Trust is simple. We believe that communities 

should feel safe when pipelines run through them, and trust that their government 

is proactively working to prevent pipeline hazards. We believe that local communities who have the most to lose if a pipeline fails should be included in discussions 

of how best to prevent pipeline failures. And we believe that only when trusted partnerships between pipeline companies, government, communities, and safety advocates are formed, will pipelines truly be safer. 

We also believe that trust in pipeline safety increases in proportion to the amount 

of verifiable scientific information that is readily available for all concerned to review. For the most part outside review increases the confidence in pipeline safety 

as those with concerns learn that in fact pipelines truly are a safe way to transport 

fuels. In those instances when safety has lapsed such review will help to more 

quickly correct the situation and create a push for even greater levels of safety. Consequently, one of the Trust’s highest priorities is to make available as much relevant 

and accurate information as possible for independent review. 

It is hard to ignore the current disaster in the Gulf of Mexico when talking about 

the safety of moving those same fuels by pipeline. In the past few weeks many people have tried to make a connection between that disaster and the safety of our onshore pipeline system. There are certainly many parallel lessons that should be reviewed, but in many ways PHMSA learned these hard lessons 10 years ago when 

pipelines failed in Washington and New Mexico killing 15 people. At that time 

PHMSA, then RSPA, was very much like MMS is today—regulation only when industry approved it, utilizing industry standards even if they had gaps, very little 

enforcement, no transparency to the public, and conflicted in its mission. Fortunately I am happy to report that it is our opinion that PHMSA learned many of 

those hard lessons and has made many significant changes for the better. While 

there is always room for improvement, as we will point out today, PHMSA is a very 

61 

different agency today than MMS, and people should avoid the temptation to paint 

all agencies dealing with oil with the same brush. 

The Pipeline Safety Trust is the only non-profit organization in the country that 

strives to provide a voice for those affected by pipelines. With that in mind, we are 

here today to speak for the relatives of the 58 people who have been killed by pipeline incidents since we last spoke to this committee on November 16, 2006. We are 

speaking for the 225 people who have been injured, and those who have been burdened by over $900 million in property damage from pipeline incidents that have 

occurred since we were last here 4 years ago. 

In my testimony this morning I will cover the following areas that are still in 

need of improvement: 

• Expanding the miles of pipelines that fall under the Integrity Management 

rules. 

• Continuing to push state agencies on damage prevention. 

• Implementing the Pipelines and Informed Planning Alliance (PIPA) recommendations. 

• Correcting the pipeline siting vs. safety disconnect, and ensuring PHMSA’s ability to provide inspections when pipelines are being constructed. 

• Continuing implementation and funding of Technical Assistance Grants to Communities. 

• Continuing to make more pipeline safety information publicly available. 

• Moving forward to address unregulated pipelines and clarifying regulations of 

gathering and production pipelines. 

• Making public awareness programs meaningful and measurable. 

• Implementing expansion of Excess Flow Valve requirements. 

• Concerns with industry developed standards being incorporated into Federal 

regulations. 

Expanding the Miles of Pipelines That Fall under the Integrity 

Management Rules 

In response to horrific pipeline tragedies, Congress required integrity management in High Consequence Areas (HCAs) as a way to protect the people who live, 

work and play near pipelines, as well to protect sensitive environmental areas and 

this Nation’s critical energy infrastructure. Before integrity management, a pipeline 

company could install a pipeline transporting huge quantities of often explosive fuel 

and leave it uninspected indefinitely—even for 50, 60, or 70 years. Even today only 

7 percent of natural gas transmission pipelines and 44 percent of hazardous liquid 

pipelines fall under these inspection programs. 

To be blunt, it is not ‘‘safe’’ to wait until a pipeline explodes to learn about its 

integrity. Consider these examples where people died when pipelines outside of 

High Consequence Areas and thereby not covered by the current integrity management requirements ruptured and exploded: 

• An extended family of 12 that was killed when a pipeline that falls outside of 

the current integrity management requirements failed while they were camping 

at their favorite fishing hole in New Mexico 10 year ago this summer. Tens 

years later this same area is still not protected by the integrity management 

program. 

• Corbin Fawcett who was killed while driving down an interstate highway north 

of New Orleans on a beautiful day in December of 2007 when an natural gas 

pipeline that falls outside of the current integrity management requirements exploded under his car. 

• Maddie and Naquandra Mitchel, a grandmother and her granddaughter, who 

were killed in Mississippi in 2007 trying to escape from their home when a 

pipeline that falls outside of the current integrity management requirements 

ruptured and exploded. 

The examples are too numerous; in fact, since these rules began to be implemented in 2001, over 75 percent of all the deaths caused by these types of pipelines 

have occurred in areas that fall outside of the current integrity management requirements. People who live, work or play near pipelines in a more rural areas interpret this to mean that Congress and PHMSA have decided their lives are not 

worth protecting with these important integrity management rules. 

The current concept of requiring integrity management programs only for pipelines in High Consequence Areas also is not sufficiently protective of America’s economy. Regardless of where a pipeline fails, there will be a significant economic imVerDate Nov 24 2008 07:17 Jul 12, 2011 Jkt 067270 PO 00000 Frm 00065 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\67270.TXT SCOM1 PsN: JACKIE
62 

pact on the downstream markets. For instance, when the El Paso natural gas pipeline failed in 2000 in a non-High Consequence Area, the staff of the Federal Energy 

Regulatory Commission estimated that the restriction in gas supply cost the people 

of California hundreds of millions of dollars. Every time a major liquid pipeline serving a refinery goes down the price of gasoline in the region skyrockets until the 

pipeline can be repaired and supplies returned to normal. Congress experienced this 

not too long ago when a BP pipeline in Alaska failed from corrosion and the American people paid millions of dollars in higher gas prices. When it comes to consumer’s pocketbooks, and the welfare of the economy, every mile of pipeline is of 

high consequence, so every mile should be inspected so that the American people 

have reliable and safe pipeline infrastructure. 

The Pipeline Safety Trust believes that limiting integrity management programs 

to High Consequence Areas made good sense when these programs were just starting nearly 10 years ago. At that time many in the industry had very little experience with these inspection techniques and knew little about how to categorize and 

respond to anomalies found. Furthermore, there was a real shortage of inline inspection tools and experienced contractors to operate them. Hazardous liquid pipeline 

operators have now completed at least one round of inspections and are well into 

the second round. Natural gas transmission operators are approaching completion 

of their first round of inspections. It is clear that the industry now has the experience and infrastructure necessary to move forward with an expansion of integrity 

management so that people who live, work and play near all the pipelines in this 

country are safe. 

Many progressive pipeline operators already apply integrity management rules to 

significantly more miles of their pipelines than required by Federal regulations. 

These companies do this because they think it is good business, and we couldn’t 

agree more. Unfortunately not all companies voluntarily provide these needed safety 

precautions, and even those that do are not required to respond to the problems 

found as they would be if these areas were covered by the integrity management 

rules. It is also important to point out that natural gas pipeline operators are not 

even required to report to PHMSA the problems they find outside of High Consequence Areas. This reporting needs to be mandated so that PHMSA can have a 

better understanding of the safety of this Nation’s pipelines. 

Since integrity management programs began in 2001, more than 34,000 anomalies 

found in High Consequence Areas have been repaired based on integrity management requirements. It is now time to find the thousands of anomalies on those sections of pipelines that fall outside of these areas by expanding integrity management to all hazardous liquid and natural gas transmission pipelines. The American 

people who live, work, and play in these uninspected areas deserve these protections. 

Implementation of Integrity Management rules have been one of the most important aspects of both the Pipeline Safety Improvement Act of 2002 and the Pipeline 

Inspection, Protection, Enforcement and Safety (PIPES) Act of 2006. The earlier Act 

focused mainly on transmission pipelines and the PIPES Act extended Integrity 

Management to the much larger realm of distribution pipelines. All of these efforts 

represent a significant increase in regulations meant to increase pipeline safety, and 

we would like to commend both PHMSA and the industry for the initial implementation of these programs. It is now time to expand this important program to all 

hazardous liquid and natural gas transmission pipelines. 

For these reasons the Trust asks that you direct PHMSA to initiate a rulemaking 

by a date certain to implement a similar Integrity Management program on all the 

pipelines that fall outside of current HCAs. 

Concerns with Possible Changes to Integrity Management 

Since nearly the time integrity management was passed for natural gas transmission pipelines as part of the Pipeline Safety Improvement Act of 2002 some within the natural gas industry have lobbied for a relaxation of the 7-year re-inspection 

interval that Congress set. The pipeline Safety Trust opposes any relaxation of this 

re-inspection interval for the following reasons: 

1. The baseline inspection period has not even been reached yet, and we believe 

that it is necessary to go through two or three re-inspections to determine 

whether the system is actually working and if it makes sense to change the reinspection interval. Some companies have not even completed one round of inspections yet. During the first round many anomalies with the pipelines were 

identified and repaired. Subsequent rounds of inspections should tell us how 

quickly new anomalies appear and at what rates they are growing. Without 

that information from ongoing re-inspections it is too early to propose changing 

the re-inspection interval. 

63 

2. The industry also argues that Instead of a standard re-inspection interval 

that would allow all companies’ results to be compared, each company, based 

on its own internal findings, should be allowed to design its own re-inspection 

program for each individual segment of its pipelines. This engineered, riskbased approach may be feasible, but it places much of the authority to draft the 

requirements with each company unless PHMSA has the extensive resources 

necessary to review each program to ensure it is no less protective than the current seven-year re-inspection intervals. We doubt PHMSA has such resources, 

and this proposed system also includes no way for the public to review and comment on the proposed engineered risk-based re-inspection proposals. 

3. There is also increasing mileage of large high pressure natural gas pipelines 

in areas with very high density populations. The consequences if one of these 

pipelines should fail in such an area would be catastrophic. Before there is any 

consideration to changes in the re-inspection interval for these types of natural 

gas pipelines PHMSA should reassess the safety protocols in place to ensure 

that it is impossible for a pipeline to fail in such an area from any cause that 

is within the operator’s controls (corrosion, materials, operation, maintenance, 

inspections, etc.). 

For these reasons, we continue to oppose any change to the seven-year re-inspection interval for natural gas transmission pipelines. 

Continuing to Push State Agencies on Damage Prevention 

Property owners, contractors, and utility companies digging in the vicinity of pipelines are still one of the major causes of pipeline incidents, and for distribution pipelines over the past 5 years excavation damage is the leading cause of deaths and 

injuries. Unfortunately, not all states have implemented needed changes to their 

utility damage prevention rules and programs to help counter this significant threat 

to pipelines. 

In the PIPES Act of 2006 Congress made clear its desire that states move forward 

with damage prevention programs by defining the nine elements that are required 

to have an effective state damage prevention program. The Trust is pleased that 

PHMSA has recently announced its intent to adopt rules to incorporate these nine 

elements, and their intent to evaluate the states progress in complying with them. 

We also support PHMSA’s plan to exert its own authority to enforce damage prevention laws in states that won’t adopt effective damage prevention laws. We hope Congress will encourage PHMSA to move forward with this proposed rulemaking in a 

timely manner, and make it clear to the states that Federal money for pipeline safety programs depends upon significant progress in implementing better damage prevention programs. 

It may also be necessary for Congress to clarify important parts of good damage 

prevention programs. Many states have exemptions to their damage prevention 

‘‘one-call’’ rules for a variety of stakeholders including municipalities, state transportation departments, railroads, farmers, and property owners. We believe such exemptions, except in cases of emergencies, are unwarranted for municipalities, state 

transportation departments and the railroads, and urge both Congress and PHMSA 

to make it clear that these types of exemptions are not acceptable in an effective 

damage prevention program. While we are skeptical regarding exemptions of any 

type, limited exemptions for the farm community and homeowners in specific circumstances may be necessary to make the programs efficient, affordable and enforceable. 

Although PHMSA likes to call itself a data-driven agency, there is a serious lack 

of data to determine the extent, causes, or perpetrators of excavation damage to 

pipelines. For example, the PHMSA incident database only includes about 70 total 

pipeline incidents nationwide in 2008 caused by excavation damage. Yet the Common Ground Alliance’s 2008 DIRT database reports well over 60,000 excavation 

events that affected the operation of natural gas systems alone. 

Why are PHMSA’s numbers so low? PHMSA only requires natural gas pipeline 

operators to file reports when there is a death, hospitalization, or over $50,000 of 

property damage measured in 1984 dollars (about $90,000+ in today’s dollars). Industry complaints about reporting requirements may be part of the reason that reporting thresholds are so high, but Section 15 of the PIPES Act also required 

PHMSA to respond to a GAO report to ensure that ‘‘incident data gathered accurately reflects incident trends over time,’’ which is why data is normalized to 1984 

dollars. While this makes good sense for tracking property damage, nowhere did 

GAO or Congress recommend that thousands of incidents related to excavation damage be left out of the database thereby creating another data gap making it impossible to track the larger problem of excavation damage trends over time. 

64 

The Common Ground Alliance’s database—while more telling—cannot be relied on 

for complete and valid data for two reasons: (1) reporting is voluntary and consequently of a ‘‘hit and miss’’ nature; and (2) reporting is anonymous, making the 

data not verifiable. Without valid and complete data it will be impossible to actually 

measure whether damage prevention programs are well targeted or effective. 

For these reasons, the Trust asks that Congress direct PHMSA to correct this 

substantial data gap by ensuring a more accurate reporting and database for excavation damage to ensure that the effort and money being spent is well targeted and 

effective. Because most states have taken on the responsibility of operating statebased damage prevention programs it may well be easiest to just have PHMSA require states to adopt reporting requirements as part of their damage prevention programs. 

One existing example is in Texas where in 2007 Texas adopted regulations requiring both pipeline operators and excavators to report excavation damage to pipelines. 

These reports are submitted directly to the Texas Railroad Commission’s website, 

and anyone can search the database for incidents in specific locations, on specific 

pipelines, by specific excavators, or for the individual damage report forms. This system seems to give Texas regulators and involved stakeholders adequate information 

to target damage prevention and enforcement activities, and track improvement 

over time. More information is available at: http://www.rrc.state.tx.us/programs/ 

damageprevention/index.php. 

This type of state-based reporting system can go hand-in-hand with PHMSA’s recent Advanced Notice of Proposed Rulemaking about better defining adequate damage prevention programs. While some consistency between state reporting requirements may be necessary so state programs can be adequately evaluated and compared, this ultimately may be an easier reporting system to institute than either 

the expansion of PHMSA’s or refining of CGA’s. 

Implementing the Pipelines and Informed Planning Alliance (PIPA) 

Recommendations 

Section 11 of the Pipeline Safety Improvement Act of 2002 included a requirement 

that PHMSA and FERC provide a study of population encroachment on and near 

pipeline rights-of-way. That requirement led to the Transportation Research Board’s 

(TRB) October 2004 report Transmission Pipelines and Land Use, which recommended that PHMSA ‘‘develop risk-informed land use guidance for application by 

stakeholders.’’ PHMSA formed the Pipelines and Informed Planning Alliance (PIPA) 

in late 2007 with the intent of drafting a report that would include specific recommended practices that local governments, land developers, and others could use 

to increase safety when development was to occur near transmission pipelines. 

Most large pipelines were placed in rural areas years ago, but as the populated 

areas around our cities expand it has led to a growing encroachment of residential 

and commercial development near large high-pressure pipelines. This increases the 

risk to the pipelines from related construction activities, as well as to the people 

who ultimately live and work nearby if something should go wrong with the pipeline. 

After more than 2 years of work by more than 150 representatives of a wide range 

of stakeholders, the draft report and the associated 46 recommendations are finally 

due to be released sometime this summer. This will be the first time information 

of this nature has been made widely available to local planners, planning commissions, and elected officials when considering the approval of land uses near transmission pipelines. We fully agree with the sentiment of Congress in the Pipeline 

Safety Improvement Act of 2002 that, 

‘‘The Secretary shall encourage Federal agencies and State and local governments to adopt and implement appropriate practices, laws, and ordinances, as 

identified in the report, to address the risks and hazards associated with encroachment upon pipeline rights-of-way . . .’’ 

A recent statewide survey of local government planning directors conducted by the 

Pipeline Safety Trust showed that to successfully implement these needed ‘‘practices, laws, and ordinances’’ will take a good deal of well targeted education and promotion by a wide range of stakeholders outside of the pipeline industry and 

PHMSA. In order to make this effort successful, the Trust asks that this year Congress authorize, just as was authorized in PIPES for the successful promotion of the 

811 ‘‘One-Call’’ number, $500,000/year to promote, disseminate, and provide technical assistance regarding the PIPA recommendations. 

65 

Correcting the Pipeline Siting vs. Safety Disconnect, and Ensuring 

PHMSA’s Ability to Provide Inspections When Pipelines Are Being 

Constructed 

With thousands of new miles of pipelines in the works, the disconnect between 

the agencies that site new pipelines and PHMSA, the agency that is responsible for 

the safety of the pipelines once they are in services, has become quite apparent. 

While siting agencies go through supposed comprehensive environmental review 

processes, these processes are functionally separate from the special permits or response plans or high consequence area analyses that are overseen by PHMSA. Many 

of the PHMSA determinations go through very limited public process (special permits), or processes that take place after the pipeline siting approval is granted 

(emergency response plans), and some are totally kept from the public (high consequence areas). How can local governments and citizens assess the real potential 

impact of a pipeline if the environmental review and the safety review processes are 

so disconnected? 

It also appears that siting agencies such as the Federal Energy Regulatory Commission, the U.S. State Department, and state agencies pay little or no attention 

to the past safety and construction histories of the companies they are granting permits to. These permits, which allow the pipeline companies to build new pipelines, 

also authorize these companies to condemn people’s property. 

About a year ago, PHMSA held a special workshop to go over the numerous problems they found during just 35 inspections of pipelines under construction. These 

inspections found significant problems with the pipe coating, the pipe itself, the 

welding, the excavation methods, the testing, etc. PHMSA’s findings, and stories we 

have heard from people across the country, call into question the current system of 

inspections for the construction of new pipelines. This construction phase is critical 

for the ongoing safety of these pipelines for years to come. Since PHMSA has authority over the safety of pipelines once they are put into service, it makes sense 

to us that during construction they also are conducting field inspections and sufficiently reviewing records to ensure these pipelines are being constructed properly. 

Unfortunately, there is a built-in disincentive for PHMSA to spend the necessary 

time to ensure proper construction. Under current rules PHMSA receives no revenue from these companies until product begins to flow through the pipelines, so 

any staff time spent on these pre-operational inspections has to be paid for from 

money collected for other purposes from already operational pipelines. 

For these reasons, the Pipeline Safety Trust asks that Congress pass new Cost 

Recovery fees, similar to those included in Section 17 of the PIPES act for LNG facility reviews, to allow PHMSA to recoup their costs related to providing safety information during the review process for new pipelines and legitimate inspections 

during the construction phase without taking resources away from other existing activities. 

Continuing the Implementation and Funding of Technical Assistance 

Grants to Communities 

Over the past year and a half, PHMSA has started the implementation of the 

Community Technical Assistance Grant program that was authorized as part of the 

Pipeline Safety Improvement Act of 2002 and clarified in the PIPES Act. Under this 

program more than a million dollars of grant money has been awarded to communities across the country that wanted to hire independent technical advisors so they 

could learn more about the pipelines running through and surrounding them, or be 

valid participants in various pipeline safety processes. 

In the first round of grants, PHMSA funded projects in communities in seventeen 

states from California to Florida. Local governments gained assistance so they could 

better consider risks when residential and commercial developments are planned 

near existing pipelines. Neighborhood associations gained the ability to hire experts 

so they could better understand the ‘‘real’’ versus the imagined issues with pipelines 

in their neighborhoods. And farm groups learned first-hand about the impacts of already-built pipelines on other farming communities so they could be better informed 

as they participate in the processes involving the proposed routing of a pipeline 

through the lands where they have lived and labored for generations. Overall, we 

viewed the implementation of the first round of this new grant program as a huge 

success. 

Ongoing funding for these grants is not clear, so the Trust asks that you ensure 

the reauthorization of these grants to continue to help involve those most at risk 

if something goes wrong with a pipeline. We further ask that you do whatever is 

necessary to ensure that the authorized funds are actually appropriated. 

One area that should be considered with any new grant program is the amount 

of promotion and time it takes to get the word out about new sources of grant 

66 

money. The Pipeline Safety Trust worked hard during the first round to promote 

this program to ensure that local government and citizen groups around the country 

knew about it and applied. Such targeted promotion, especially for a new grant program, is needed to ensure that PHMSA receives enough strong grant applications 

to choose from. During the application period for the second round of these grants, 

promotion was not as well organized and we have since learned from several groups 

around the country that they did not apply because they had no idea the grants 

were available again. While this will certainly correct itself as the knowledge of this 

grant program grows, we hope that PHMSA continues to provide adequate promotion and that Congress will take the long-term view of the value of this program 

while it grows to maturity. 

Finally, we hope that PHMSA will resist the pressure to spend the money on applications that do not meet the Congressional intent of the program. While the second round of grants have not yet been announced, we have heard from some local 

governments around the country that municipal gas utilities have tried to apply for 

these grant funds to undertake pipeline projects that are clearly part of their existing pipeline maintenance and operation requirements. Funding municipal utilities 

with this community technical assistance grant money is clearly outside of the intent of what Congress approved this program for, and will cause a rush by such utilities that will overwhelm this limited funding. We ask that Congress expressly 

state—throughout the reauthorization process and in its final reauthorization legislation—that this grant program is not to fund the activities of any pipeline operator, 

public or private. 

Continuing to Make More Pipeline Safety Information Publicly Available 

Over the past two reauthorization cycles, PHMSA has done a good job of providing increased transparency for many aspects of pipeline safety. In the Trust’s 

opinion, one of the true successes of PIPES has been the rapid implementation by 

PHMSA of the enforcement transparency section of the act. It is now possible for 

affected communities to log onto the PHMSA website (http://primis.phmsa.dot.gov/ 

comm/reports/enforce/Enforcement.html) and review enforcement actions regarding 

local pipelines. This transparency should increase the public’s trust that our system 

of enforcement of pipeline safety regulations is working adequately or will provide 

the information necessary for the public to push for improvements in that system. 

PHMSA has also significantly upgraded their incident data availability and accuracy, and continues to improve their already excellent ‘‘stakeholder communication’’ 

website. 

One area where PHMSA could go even further in transparency would be a webbased system that would allow public access to basic inspection information about 

specific pipelines. An inspection transparency system would allow the affected public 

to review when PHMSA and its state partners inspected particular pipelines, what 

types of inspections were performed, what was found, and how any concerns were 

rectified. Inspection transparency should increase the public’s trust in the checks 

and balances in place to make pipelines safe. We have been told by PHMSA that 

such a system is in the works. We hope that Congress will inquire about the design 

and timeline for implementation of this ‘‘in-the-works’’ system, and if it does not 

meet the above criteria require PHMSA to institute an Inspection Transparency system, just as you required PHMSA to institute the successful Enforcement Transparency in the PIPES Act of 2006. 

There is also a need to make other information more readily available. This includes information about: 

• High Consequence Areas (HCAs). These are defined in Federal regulations and 

are used to determine what pipelines fall under more stringent integrity management safety regulations. Unfortunately, this information is not made available to local government and citizens so they know if they are included in such 

improved safety regimes. Local government and citizens also would have a 

much better day-to-day grasp of their local areas and be able to point out inaccuracies or changes in HCA designations. 

• Emergency Spill Response Plans. As has been learned in the recent Gulf of Mexico tragedy, it is crucial that these types of spill response plans are well designed, adequately meet worst-case scenarios, and use the most up-to-date technologies. While 49 CFR § 194 requires onshore oil pipeline operators to prepare 

spill response plans, including worst case scenarios, those plans are difficult for 

the public to access. To our knowledge the plans are not public documents, and 

they certainly are not easily available documents. 

The review and adoption of such response plans is also a process that does not 

include the public. In fact PHMSA has argued that they are not required to folVerDate Nov 24 2008 07:17 Jul 12, 2011 Jkt 067270 PO 00000 Frm 00070 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\67270.TXT SCOM1 PsN: JACKIE
67 

low any public processes, such as NEPA, for the review of these plans. If the 

Gulf tragedy has taught us nothing else it should have taught us that the industry and agencies could use all the help they can get to ensure such response 

plans will work in the case of a real emergency. 

It is always our belief that greater transparency in all aspects of pipeline safety 

will lead to increased involvement, review and ultimately safety. There are 

many organizations, local and state government agencies, and academic institutions that have expertise and an interest in preventing the release of fuels to 

the environment. Greater transparency would help involve these entities and 

provide ideas from outside of the industry. The State of Washington has passed 

rules that when complete spill plans are submitted for approval the plans are 

required to be made publicly available, interested parties are notified, and there 

is a 30 day period for interested parties to comment on the contents of the proposed plan. We urge Congress to require PHMSA to develop similar requirements for the adoption of spill response plans across the country, and that such 

plans for new pipelines be integrated into the environmental reviews required 

as part of the pipeline siting process. 

• State Agency Partners. States are provided with millions of dollars of operating 

funds each year by the Federal Government to help in the oversight of our Nation’s pipelines. While there is no doubt that such involvement from the states 

increases pipeline safety, different states have different authority, and states 

put different emphasis in different program areas. Each year PHMSA audits 

each participating state program, yet the results of those program audits are 

not easily available. We believe that these yearly audits should be available on 

PHMSA’s website and that some basic comparable metrics for states should be 

developed. 

Moving Forward to Address Unregulated Pipelines and Clarifying 

Regulations of Gathering and Production Pipelines 

After numerous spills from low stress pipelines on Alaska’s North Slope, Congress 

directed PHMSA to move forward with new rules to better regulate them. Section 

4 of PIPES required PHMSA to ‘‘issue regulations subjecting low-stress hazardous 

liquid pipelines to the same standards and regulations as other hazardous liquid 

pipelines’’ (emphasis added) with limited exceptions for pipelines regulated by the 

U.S. Coast Guard and certain short-length pipelines serving refining, manufacturing, or truck, rail, or vessel terminal facilities. This section’s clear directive to 

PHMSA to have these rules adopted by December 31, 2007, has only been partially 

followed since PHMSA decided to implement this directive in a phased approach, 

and so far PHMSA has only adopted phase one of those rules and made no announcement about phase two. Congress needs to require clear answers from PHMSA 

regarding the initiation and implementation of the phase 2 rules. 

Meanwhile, significant drilling for natural gas has led to a large expansion of 

gathering and production pipelines in highly-populated urban areas. For instance, 

in Fort Worth Texas there are already 1,000 producing gas wells within the city limits and at least that many more planned. Development of improved gas drilling 

methods has led to thousands of new wells being drilled and proposed in more populated areas of Texas, Arkansas, Louisiana, Pennsylvania and New York. Pipelines 

will connect all these wells, and the regulatory oversight of these pipelines in these 

areas is less than clear and in some cases non-existent. The standards for PHMSA’s 

rules to determine which pipelines fall under minimum Federal regulations were 

written by the American Petroleum Institute and incorporated by reference into the 

regulations. If the public wants to review these standards they have to buy a copy 

of this part of the Federal regulations from API for $126. What the API written 

standards actually require provides much wiggle room for gas producers to design 

their systems to avoid regulations. PHMSA also only regulates a limited amount of 

these gathering and production pipelines, and leaves the rest of the regulations up 

to the states if they choose to assert any authority. We believe it is time to ensure 

that any gathering or production pipeline in a populated area with similar size and 

pressure characteristics as other currently regulated pipelines fall under the same 

level of minimum Federal regulations. At a minimum we think Congress should require PHMSA or the National Transportation Safety Board to produce a study on 

the onshore gas production and gathering pipelines that are not covered by current 

Federal standards. This study should explain what pipelines are not covered, what 

the extent of them is, how many are located in populated areas, the relative risk, 

and a proposed regulatory regime for inclusion of all these pipelines under minimum Federal standards. 

68 

Making Public Awareness Programs Meaningful and Measurable 

The Pipeline Safety Improvement Act of 2002 required pipeline operators to provide people living and working near pipelines basic pipeline safety information, and 

gave PHMSA the authority to set public awareness program standards and design 

program materials. In response to this Congressional mandate, PHMSA set rules 

that incorporated by reference the American Petroleum Institute’s (API) recommended practice (RP) 1162 as the standard for these public awareness programs. 

According to RP 1162’s Foreword (page iii) of API recommended practice, the intended audiences were not represented in the development of RP 1162, though they 

were allowed to provide ‘‘feedback.’’ The omission of representatives from these audiences from the voting committee reduces the depth of understanding the RP could 

have had regarding the barriers and incentives for such programs, and undercuts 

the credibility of the recommended actions. The public awareness program regulations—49 CFR § 192.616 and 49 CRF § 195.440—mandate that operators comply 

with RP 1162. In essence, this amounts to the drafting of Federal regulations without the equal participation of the stakeholders the regulations are meant to involve. 

With non-technical subject matter, such as this recommended practice deals with, 

it is difficult to justify excluding the intended audiences from the process and allowing the regulated industries to write their own rules. 

This public awareness effort represented a huge and important undertaking for 

the pipeline industry, and as such the effectiveness of it will evolve over time. We 

were happy that the rules included a clause that set evaluation requirements that 

require verifiable continuous improvements. While we understand that the initial 

years of this program have been difficult, we have been disappointed in some of 

these efforts as they were clearly farmed out to contractors to meet the letter of the 

requirement instead of the intent of the requirement. Recently, the National Transportation Safety Board cited the failure of these programs in the investigation report of a deadly pipeline explosion in Mississippi that killed a girl and her grandmother. 

An evaluation of the first 5 years of this program is due this year, and API has 

been working on an update of this recommended practice for some time now. One 

of the draft proposals from API is to remove the requirement to measure whether 

the programs have led to actual changes in behavior. PHMSA plans to hold a workshop on these public awareness programs in late June. We hope that Congress will 

keep a close eye on the discussions of this issue over the coming months and be prepared to step in and clarify that the intent of this program is to change the behavior 

of the intended audiences to make pipelines safer, not to count how many innocuous 

brochures can be mailed. 

Implementing Expansion of Excess Flow Valve Requirements 

One of the Trust’s priorities that was well addressed in the PIPES Act was to require the use of Excess Flow Valves (EFVs) on distribution pipelines for most new 

and replaced service lines in single family residential housing. While this was a 

huge step forward, the National Transportation Safety Board (NTSB) has continued 

to push for an expansion of the use of EVFs in multi-family and commercial applications ‘‘when the operating conditions are compatible with readily available valves.’’ 

From closely following the deliberations of PHMSA’s Large Excess Flow Valve 

Team, it is our opinion that there are thousands of potentially compatible structures 

being constructed or renewed which could be afforded greater safety by the installation of Excess Flow Valves (EFVs). It is clear from the data provided by PHMSA 

(see figure 1 below) that the services lines serving a majority of these types of structure fall within the size constraints of commercially available EFVs. It is also clear 

from the data (see figure 2) that the vast majority of these gas services are provided 

at pressures that avoid the concerns regarding low pressure lines. 

69 

Figure 1 (Source—PHMSA’s—Interim Evaluation: Response To NTSB 

Recommendation P–01–2) 

Figure 2 (Source—PHMSA’s—Interim Evaluation: Response To NTSB 

Recommendation P–01–2) 


624WEIM1.eps 624WEIM2.eps
70 

The one significant hurdle to overcome is to avoid EFVs to structures where the 

demand load varies greatly or could change over time. There are many multi-family 

residential, small office, and retail structures that for all intents and purposes have 

the same load profiles as a single family residence. For these types of applications 

PHMSA and the industry need to move forward with rules to require installation 

of EFVs for new and renewed gas service. 

From our perspective, it would be difficult to engineer the application of EFVs to 

avoid the problems associated with load fluctuation for such structures as hospitals, 

multi-tenant commercial buildings, and industrial facilities. We agree with the industry’s concerns about the installation of EFVs for these types of applications, and 

believe more study is needed both in terms of these large applications as well as 

the effectiveness of EFVs on current applications. 

The real difficulty is drafting rules that clearly define which additional applications are within the needed expansion of the rules and which applications are not. 

We are disappointed that some in the industry—as a way to stop all movement toward improved safety rules—always point to the types of structures that are difficult or impossible to serve with EFVs. Instead, they should be searching for a way 

to increase the safety of thousands of people who live or work within buildings that 

could clearly be served by EFVs. The Pipeline Safety Trust urges Congress to direct 

PHMSA to undertake a rulemaking—as the National Transportation Safety Board 

has requested—that would require EFVs be installed on the many types of structures where ‘‘operating conditions are compatible with readily available valves.’’ 

Concerns with Industry Developed Standards Being Incorporated into 

Federal Regulations 

There has been increasing attention because of the Gulf of Mexico tragedy to the 

practice by Federal agencies of incorporating into their regulations standards that 

outside organizations developed. Like MMS, PHMSA has incorporated by reference 

into its regulations standards developed by organizations made up in whole or in 

part of industry representatives. A review of the Code of Federal Regulations under 

which PHMSA operates finds the following numbers of incorporated standards: 

Standards Incorporated by Reference in 49 CFR Parts 192, 193, 195 

(As of 6/9/2010) 

CFR Part Topic Standards* 

192 Natural and Other Gas 39 

193 Liquefied Natural Gas 8 

195 Hazardous Liquids 38 

Total 85 

*Note: Some standards may be incorporated by reference in more than one CFR Part. 

Those standards were developed by the following organizations: 

American Gas Association (AGA) 

American Petroleum Institute (API) 

American Society for Testing and Materials (ASTM) 

American Society of Civil Engineers (ASCE) 

ASME International (ASME) 

Gas Technology Institute (GTI) 

Manufacturers Standardization Society of the Valve and Fittings Industry, Inc. 

(MSS) 

NACE International (NACE) 

National Fire Protection Association (NFPA) 

Pipeline Research Council International, Inc. (PRCI) 

Plastics Pipe Institute, Inc. (PPI) 

While the Pipeline Safety Trust has not done an extensive review of these organizations or their standard setting practices, it is of great concern to us—and we believe it should be to Congress as well—whenever an organization whose mission is 

to represent the regulated industry is—in essence—writing regulations that members of the organization must follow. A very quick review of the mission statements 

of some of these organizations reveals statements like these below that show, at a 

71 

minimum, a conflict between the best possible regulations for the entire public and 

the economic interests of the industry. 

API—‘‘We speak for the oil and natural gas industry to the public, Congress and 

the executive branch, state governments and the media. We negotiate with regulatory agencies, represent the industry in legal proceedings, participate in coalitions and work in partnership with other associations to achieve our members’ 

public policy goals.’’ 

AGA—‘‘Focuses on the advocacy of natural gas issues that are priorities for the 

membership and that are achievable in a cost-effective way.’’ ‘‘Delivers measurable value to AGA members.’’ 

PPI—‘‘PPI members share a common interest in broadening awareness and creating opportunities that expand market share and extend the use of plastics 

pipe in all its many applications.’’ ‘‘The mission of The Plastics Pipe Institute 

is to make plastics the material of choice for all piping applications.’’ 

PRCI—‘‘PRCI is a community of the world’s leading pipeline companies, and the 

vendors, service providers, equipment manufacturers, and other organizations 

supporting our industry.’’ 

The pipeline industry has considerable knowledge and expertise that needs to be 

tapped to draft standards that are technically correct and that can be implemented 

efficiently. But we also know the industry’s standard setting practices exclude experts and stakeholders who can bring a broader ‘‘public good’’ view to standard setting. We also know that when a regulatory agency needs to adopt industry-developed standards it is a ‘‘red flag’’ that the agency lacks the resources and expertise 

to develop these standards on its own. 

It should be noted that the development of such standards is not an open process 

where interested members of the public or experts outside the industry (such as 

those in universities and colleges) can review the material and comment. One of the 

most ridiculous examples of this one sided process was the development of the Public Awareness standard (API RP 1162) which now governs how pipeline companies 

have to communicate with the affected public. The process was controlled by industry, even though industry has no particular expertise in this type of public awareness or communication. The many possible independent experts and organizations 

in the field of communications and education were not sought and ultimately were 

not a part of the development of this standard. 

Even once the standards are incorporated by reference into Federal regulations 

the standards remain the property of the standard setting organization and are not 

provided by PHMSA in their published regulations. If the public, state regulators, 

or academic institutions want to review the standards they have to purchase a copy 

from the organization that drafted them. In many cases, this further removes review 

of the standards from those outside of the industry. Below are just a handful of examples of the cost to purchase for review the standards that are part of the Federal 

pipeline regulations: 

Sample Cost of Pipeline Safety Standards Incorporated by Reference Into Federal Regulations 

(As of 6/8/2010) 

Standard Organization Code of Federal Regulations 

(Incorporated by Reference) Cost 

ANSI/API Spec 5L/ISO 3183 

‘‘Specification for Line Pipe’’ 

API 49 CFR § 192.55, § 192.112, 

§ 192.113, § 195.106 

$245.00 

ASME B31.4 –2002 

‘‘Pipeline Transportation Systems 

for Liquid Hydrocarbons and 

Other Liquids’’ 

ASME 49 CFR § 195.452 $129.00 

GRI 02/0057 (2002) ‘‘Internal 

Corrosion Direct Assessment of 

Gas Transmission Pipelines 

Methodology’’ 

GTI 49 CFR § 192.927 $295.00 

NACE Standard RP0502–2002 

‘‘Pipeline External Corrosion 

Direct Assessment Methodology’’ 

NACE 49 CFR § 192.923, § 192.925, 

§ 192.931, § 192.935, 

§ 192.939, § 195.588 

$83.00 

A Modified Criterion for 

Evaluating the Remaining Strength 

of Corroded Pipe’’ 

PRCI 49 CFR § 192.933, § 192.485, 

§195.452 

$995.00 

72 

The Pipeline Safety Trust asks that Congress carefully review the use of industry 

developed standards in minimum Federal pipeline safety regulations, as well as the 

development of risk-based programs that are not required to go through any sort 

of public review. 

Summary of Testimony 

As stated previously, the Pipeline Safety Improvement Act of 2002 and the Pipeline Inspection, Protection, Enforcement and Safety (PIPES) Act of 2006, have required many valuable and significant new pipeline safety efforts, including Integrity 

Management, increasing damage prevention efforts, greater transparency, and increasing the number of inspectors and the amount of fines. The Trust is very 

pleased with all of these efforts and does not see the need for any huge new programs during this reauthorization. Our recommendations build upon the important 

foundation that Congress has built during the past 10 years. What is always needed 

is constant vigilance so pipeline safety does not once again return to a system where 

the regulated control the regulators, and where what is easy takes precedence over 

what is safe. 

Thank you again for this opportunity to testify today. The Pipeline Safety Trust 

hopes that you will closely consider the concerns we have raised and the requests 

we have made. If you have any questions now or at anytime in the future, the Trust 

would be pleased to answer them. 

Senator LAUTENBERG. Thank you very much, Mr. Weimer. 

You mentioned the fact that we’ve required excess flow valves. I 

authored a provision in the 2006 PIPES Act that required the devices for single-family homes and I think there is universal approval of this requirement. But they are not required currently for 

apartment or commercial buildings. In the reauthorization of pipeline safety legislation, what can Congress do to protect the people 

who live in dwellings other than single-family homes? I ask you, 

Mr. Weimer. What do you think we can do? 

Mr. WEIMER. Well, NTSB still has a recommendation on the 

table that hasn’t been fully met to include multi-family residences 

and commercial retail types of businesses. I think the key to that— 

and PHMSA has had a work group that looked at this—is when 

the load demand is similar to what a single-family residence is, and 

there are many of those, that they need to move forward on a rulemaking to include those types of businesses. 

There are thousands of structures that have a load demand similar to a single-family residence and PHMSA just needs to come up 

with a rulemaking to define where that line is, because we do agree 

with the industry that there are some situations—chemical plants, 

hospitals—where excess flow valves may just not make sense. But 

there are lots of buildings they do, and we need to expand those 

inclusions. 

Senator LAUTENBERG. Is there technology to do something to 

make these valves more effective where the demand for gas is 

great? So, even if something happens, that the direct flow to one 

user of part of the structure still requires energy? 

Mr. WEIMER. Right. I think it’s obvious from the work group that 

PHMSA has conducted that for the vast majority of the size of 

pipelines and for the load demands, there are already excess flow 

valves available to deal with that. It’s just a matter of clarifying 

and defining where that line is, where you cross into different 

types that have load demands that vary so much that at this point 

excess flow valves don’t make much sense. 

Senator LAUTENBERG. Mr. D’Alessandro, what do you think? The 

industry has voiced concern, and you’ve expressed it, at the expanding use of excess flow valves. However, NTSB and safety advoVerDate Nov 24 2008 07:17 Jul 12, 2011 Jkt 067270 PO 00000 Frm 00076 Fmt 6633 Sfmt 6601 S:\GPO\DOCS\67270.TXT SCOM1 PsN: JACKIE
73 

cates across the country have called for them, to be repetitive, to 

be required in these structures. Given what you’ve said and what 

you’ve heard today, can you commit to working with us, with the 

Committee, to find a practical solution on this issue? 

Mr. D’ALESSANDRO. We look forward to doing that. Our issue is 

the mandatory installation of EFVs on all of the facilities. We think 

for some of them they might fit the occasion to do it, but I think 

in some of the testimony you’ve seen the words ‘‘operating conditions justify.’’ In my testimony I talked about the service line and 

the fluctuation in pressures that happen within the facilities could 

kick off EFVs. But we’d love to work on EFVs and find some type 

of solution. 

Senator LAUTENBERG. I wonder—this question can be answered 

by any one of you—whether or not in those types of buildings there 

ought to be something internal, not unlike a fire safety cannister 

or something like that—more than a cannister, but a unit that 

could be used. There is a significant extra risk in those buildings 

where there are multiple dwellings. 

Anybody volunteer a response to that? We have to do something 

to protect the people who are in those buildings. Their lives are no 

less valuable. Their families are no less of concern. What can we 

suggest as an alternative to not being able to provide excess flow 

valves? 

No volunteers? 

Mr. D’ALESSANDRO. I’ll give it a shot. The excess flow valve really 

protects the customer from an external or a hit before the meter 

set. That would protect them. If anything would happen within 

their own internal piping—and I’m not sure if that’s where you’re 

headed with your question—the excess flow valve would not protect 

that. It would not kick itself off if it’s inside the home. 

Safety—in the public awareness program that we’ve got going on, 

all of us participate in educating our consumers about natural gas, 

about the smell of natural gas, what to do in case they smell natural gas. Our response record of responding when there are gas 

emergencies in the gas distribution pipeline, we take it very serious 

and we all strive to have high standards on that. 

Senator LAUTENBERG. Mr. Felt, a quick question here. BP’s oil 

spill in the Gulf has shown that the company’s response plan was 

completely inadequate. How can we be confident that oil companies 

operating offshore or onshore pipelines have the right response 

plans in place so that they’re adequately prepared for a worst case 

scenario? 

Mr. FELT. Well, sir, I think that if you look at what’s expected 

today, response plans are developed by the pipeline companies, by 

the operators, submitted to the OPS for review and approval. Our 

experience, my experience, has been that when they are submitted 

we’ll get some feedback, either on areas where they’re not adequate 

or some clarification that’s needed. 

Just looking from our own personal company’s standpoint, those 

plans are unique to each facility. They do look at worst case scenarios. They look at the worst case conditions in those worst case 

scenarios. PHMSA I believe is getting ready to come out—we saw 

a draft announcement just recently where they’re going to ask for 

another review in light of what’s happened in the Gulf, just to 

74 

make sure that there are adequate resources to respond and if 

there are any changes please respond within the next 30 days. I 

hope I’m not jumping ahead of OPS, but we did see that announcement coming out. 

Senator LAUTENBERG. Well, certainly this tragedy, this calamity 

that has taken place, puts us all on alert and we have to be much 

more careful about the exposure that something like that happens. 

Mr. FELT. I agree. 

Senator LAUTENBERG. Senator Thune. 

Senator THUNE. Thank you, Mr. Chairman. 

Gentlemen, thank you for your testimony today. Let me ask you 

a question about new technologies. What role do you see new technologies playing to improve the safety of pipelines? 

Mr. SYPOLT. Senator, I’ll take a shot at that to start with. Actually, we’ve seen technology improve over time, that basically has 

been used in our integrity management programs, like in new evolutions or new generations of smart pigs, and those continue to improve. I think that is a very key thing to help us in our integrity 

management programs. So I do think that continued research is a 

very valuable tool. 

Senator THUNE. I think one of the greatest threats to pipeline 

safety and integrity—and it has been talked about at some length 

today—comes from accidental damage due to digging and excavation. I commend PHMSA and the states for developing the OneCall program, which allows excavators to dial 811 anywhere in the 

country and learn the location of pipelines and other utilities before 

digging. 

However, recent accidents demonstrate that we may need to do 

more in this area, and I’m interested in what recommendations you 

might have for improving the One-Call program to prevent excavation damage. Anybody? 

Mr. SYPOLT. I’ll be happy to start it off for you, Senator. I do believe that, with regard to One-Call systems, they are our first line 

of attack to protect the public. Clearly I believe there should be no 

exceptions to One-Call. I think every party should have to call. No 

one should be excepted from safety. 

Second, I think that there has to be a very clear communication 

between the parties with regard to where the activity is being 

done, and then there has to be a thorough follow up and marking 

of the pipelines. Fourthly, the group who’s doing the excavation has 

to work very cautiously around those facilities. 

If all four of those things do not work, I don’t believe there’s 

more regulation that could take care of it. I think regulation is in 

place to do those things, except for the part where certain parties 

are excepted from One-Call systems. 

Mr. FELT. Sir, I’d like to add just one other point to that, and 

that’s the enforceability. There are cases where there’s no consequence for not following the One-Call rules, either for the excavator or the person doing the proper marking. I believe that’s 

something that needs to be addressed as well. 

Mr. WEIMER. One other point, if I could, and I certainly agree 

with everything that Mr. Sypolt and Mr. Felt said. Back to our 

issue of reporting requirements, recently in the two incidents in 

Texas, when we looked at those, the PHMSA database showed that 

75 

on average there are ten incidents a year from damage in the State 

of Texas. The Texas Railroad Commission shows that there are 

18,000 incidents a year from damage. So there’s a big disconnect 

on whose data you’re looking at. 

When we looked at the State of Texas, they have an excellent reporting system that requires both excavators and operators to report any damage to pipelines. That’s why they know they have 

18,000 incidents a year, and it’s available to the public to look at. 

You can scroll through it and organize it by excavator, by pipeline 

company, by city, and look. So you can come up with A–1 Excavators has hit pipelines in Fort Worth, Texas, 10 times in the last 

6 months and make some conclusions from those types of things. 

I think that’s an excellent system that could be adopted in other 

states. 

Senator THUNE. You’ve noted that state authorities have primary 

responsibility over gas distribution pipelines and that many states 

have chosen to adopt regulatory standards that are more stringent 

than Federal ones. Could you describe some of the State regulations that are more stringent and how many states have adopted 

standards that are more stringent, and then perhaps, to follow up, 

are there more stringent state standards or best practices that 

PHMSA could or should consider adopting? I think you just mentioned the State of Texas as an example. But are there some states 

that have more stringent standards and can you give me some examples of those, and are there some things that perhaps the feds 

ought to be adopting that states are already doing? 

Mr. SYPOLT. I believe that the State of Virginia, Senator, has 

probably one of the very best One-Call systems out there. I think 

it serves as a model. One, there’s high participation in it, high-profile participation in it. In the event there are parties who actually 

cause damage, there’s a group that actually assess penalties on 

what they think that group should pay. I think that peer pressure 

has served very well in the State of Virginia, and we’ve been extremely pleased with that One-Call system. 

Senator THUNE. You don’t have to confine it to One-Call. It’s sort 

of a broad question about things the states are doing in terms of 

regulation. 

Mr. WEIMER. One of the other things that has been brought to 

our attention a lot is the difficulty getting hold of PHMSA’s spill 

response plans for liquid and oil pipelines. There are some groups 

even in the Midwest from your own state, I believe, that had to use 

the FOIA to actually get their hands on a spill response program 

so they could review it to see if it adequately protected their area. 

In the state I’m from, the State of Washington, Washington has 

adopted regulations that once a complete spill response program is 

submitted to the State of Washington it opens up a 30-day comment period where the public, universities, interested local governments, have a chance to review and comment on that spill response 

plan. There’s nothing within the Federal regulations that opens up 

spill response plans for any public review or comment. 

Senator THUNE. Thank you. 

Thank you, Mr. Chairman. 

76 

Senator LAUTENBERG. I now call on Senator Udall, and sitting 

next to him is Senator Begich. These are very mountainous states, 

a lot higher than New Jersey’s 1,200-foot highest mountain. 

Senator BEGICH. That’s a mountain? 

Senator LAUTENBERG. But I don’t know whether the problems 

are more difficult. But Senator Udall. 

STATEMENT OF HON. TOM UDALL, 

U.S. SENATOR FROM NEW MEXICO 

Senator UDALL. Thank you, Chairman Lautenberg. I’d like to put 

my opening statement in the record and proceed from there. 

Thank you for doing this hearing. I think the issue of pipeline 

safety is a very important one. As you say, we have mountains, but 

we also have flat areas and desert areas and a variety of problems. 

That’s one of the things I wanted to focus on with the Committee 

today. 

Mr. Weimer emphasized this. We’re almost on the 10-year anniversary of the Carlsbad explosion, where a family of 12 was camping and through no fault of their own they were wiped out in an 

explosion. 

I’m wondering, for our first three witnesses, how do you respond 

to the recommendation by Mr. Weimer that integrity management 

plans be expanded to rural areas, like the area outside Carlsbad 

where the accident occurred 10 years ago? What do you think of 

that? 

Mr. SYPOLT. Senator, I believe that—well, let me start with a few 

facts here. When you look at the natural gas transmission system 

today as it stands, about 49 percent of the transmission system has 

been smart pigged, as opposed to the requirement of only 7 percent 

in HCA areas. So pipelines are already doing much more than just 

the HCA areas. 

We expect, based on surveys from particularly the INGAA membership, that by the end of 2012 we will have pigged 65 percent of 

those pipelines. That being said, we should make sure, though, that 

we do not lose focus on those areas which we believe have the 

greatest impact, where there is the most population and pipelines 

are closest to those. So I think that we already are doing much 

more than just the HCA areas and pipelines basically treat—when 

they find something outside of those HCA areas, they take the 

same corrective actions as they do inside the HCA areas. So I believe much more is being done than the 7 percent required today 

by PHMSA. 

Mr. FELT. Sir, on the liquid side 44 percent are covered already 

under the integrity management plan rules, because 44 percent 

occur within HCAs or affect HCAs. But, like the gas side, much 

more is done than just the minimum 44 percent. In fact, earlier estimates were that the integrity management plan would require 

somewhere in the neighborhood of a couple of hundred million dollars. The industry has spent billions of dollars, and I think that’s 

a reflection of how much more work is being done beyond the minimum requirement. 

I think the danger with requiring all pipelines or all miles of 

pipelines to be treated the same is that you take away the flexibility or the ability to place your dollars where there’s greater emVerDate Nov 24 2008 07:17 Jul 12, 2011 Jkt 067270 PO 00000 Frm 00080 Fmt 6633 Sfmt 6601 S:\GPO\DOCS\67270.TXT SCOM1 PsN: JACKIE
77 

phasis. It’s that flexibility, I think, that we need. The pipeline companies are already doing more than the minimum, but to require 

every mile to be treated the same I think would not be the most 

effective way to manage the system. That’s why the rules were developed with emphasis on HCAs. 

Mr. D’ALESSANDRO. From a distribution point of view, a lot of our 

transmission pipelines that are covered are not piggable. So we 

have to do some type of other assessment. Most of the time it only 

can be direct assessment because we cannot pressurize them or 

hydrotest them because then we put water in our system and we 

create another issue of corrosion within our system. 

We believe—in my testimony I talked about the assessment of 

low-stress transmission pipelines being moved from TIMP over to 

DIMP. That would assist us, that now all pipeline, all mileage, 

would be covered underneath the DIMP robust plan and have a 

risk-based program looking at that. So that is one recommendation 

from a distribution point of view. 

Senator UDALL. Mr. Weimer, would you like to comment on 

those? 

Mr. WEIMER. We certainly agree that the industry has done 

more. There are some companies that almost smart pig 100 percent 

of their pipelines. We commend those companies. The main difference we see is what’s required versus what’s done voluntarily is 

who you have to report that to and who knows that information. 

For the natural gas transmission industry, what’s found outside of 

high consequence areas doesn’t need to be reported to PHMSA and 

what’s found—anomalies found in the pipelines aren’t required to 

be treated the same way they are if they are under the regulations. 

So there’s a big difference between whether you’re doing it voluntarily or whether it’s under the regulation. 

Senator UDALL. Thank you, Chairman Lautenberg, and thank 

you to the panelists. 

[The prepared statement of Senator Udall follows:] 

PREPARED STATEMENT OF HON. TOM UDALL, U.S. SENATOR FROM NEW MEXICO

Mr. Chairman, thank you for holding this hearing today on ensuring the safety 

and security of our Nation’s pipeline infrastructure. 

Almost 10 years ago, in August 2000, New Mexico experienced one of the most 

tragic pipeline accidents in recent memory. 

Twelve members of the same extended family, camping outdoors near Carlsbad, 

New Mexico, were killed in a horrific explosion of a natural gas pipeline early in 

morning. 

The National Transportation Safety Board investigation found the explosion the 

result of corrosion, and that both industry and government attention to pipeline 

safety needed improvement. 

Following that incident, Congress took action, passing the Pipeline Safety Improvement Act of 2002. Congress reauthorized that Act in 2006 and it is time for 

us to get to work again on pipeline safety. 

Pipelines may be the safest form of transportation, compared to trucking or railroads, but that fact is no consolation to the family and friends left behind after fatal 

pipeline accidents. 

That fact also does no cleanup of the environment following pipeline accidents 

that leak hazardous liquids like oil and gasoline into the environment. 

As a result, we must remain vigilant. As recent fatal accidents in Texas have 

shown, including one earlier this month, our work is not complete. 

I look forward to hearing how the pipeline safety programs Congress put in place 

are working and how they can be improved. 

78 

In particular, we must ensure that existing regulations are being enforced and be 

skeptical of waivers and self-regulation. 

Senator LAUTENBERG. Senator Vitter. 

Senator VITTER. Mr. Chairman, I’m going to pass right now. I 

really want to hear more discussion from the panelists. 

Senator LAUTENBERG. Senator Begich. 

STATEMENT OF HON. MARK BEGICH, 

U.S. SENATOR FROM ALASKA 

Senator BEGICH. Thank you, Mr. Chairman. 

Let me, if I can, follow up on Senator Thune’s questions on the 

One-Call. I’m not as familiar with—I understand what they do on 

ground, but do they have a similar situation for offshore? Why I 

ask that is, as you know, pipelines come offshore moving product 

to land facilities, and there is stuff we’re starting to hear about 

where people might be anchoring, for example, might be interfering 

with some of the lines. 

Can you help me understand that a little bit better from your 

own industry? Is that an issue that’s starting to become a problem? 

We’ve heard just a couple indications that as we have more and 

more lines coming in offshore onto land-based facilities and then 

ships who are then also laying anchor, how that all connects—or 

actually, we don’t want them to connect. 

Tell me, is there a One-Call center for that, where there are 

zones that you cannot be anchoring in? And then, if not, what recommendations might you have on this area? For anyone who wants 

to step up on that? 

Mr. SYPOLT. My understanding, Senator, is for offshore, obviously it’s more difficult than onshore, where pipelines are mapped 

very well, GPS coordinates are taken. My understanding is the 

State of Texas is actually looking at a system to really approach 

those offshore pipelines by having them mapped with GPS systems 

and then having ships equipped with those type systems where 

they can either look at their system and see the map of the pipelines or contact the Coast Guard to actually get some feedback as 

to whether or not they’re looking at laying anchor somewhere close 

to a pipeline system. 

But offshore is not as far advanced as we are onshore with OneCall type systems, Senator. 

Senator BEGICH. If I can just interrupt before someone else answers, based on obviously the larger issue, which is the blowout 

and the spill, which is a whole different set of circumstances, is 

this something you think we should accelerate, some more discussion, or is it not that big of a problem that you’ve heard within 

your own associations? 

Mr. FELT. Well, sir, I’ve not heard of it being as much of a problem. But before I would comment one way or the other, I think it 

would be more appropriate to talk to the Office of Pipeline Safety, 

because I think there is that transition period between close to the 

shoreline versus further offshore. I think I heard Ms. Quarterman 

talk about the fact that there is a transition area, and probably understanding more what they’re regulating would be helpful. 

Senator BEGICH. Any other comments from folks on that one? 

[No response.] 

79 

Senator BEGICH. Let me, if I could take another step. As we talk 

about pipelines, we have a big one in Alaska and we’ll have, hopefully soon, maybe, a bigger one moving gas. Do you think PHMSA 

has the capacity, staffing, and authority to deal with these large 

projects in a timely manner, and making sure that they don’t become a bottleneck in the delay of a project of that magnitude? It’s 

a big project for us as we think of the gas line, and as we think 

about this we’re thinking of all the Federal agencies that will be 

touching this line in some form of regulatory process. On big 

projects like this, my instincts tell me that a lot of agencies are 

never geared up to deal with large projects. I may be wrong about 

that, but I want to get some feedback from you of how you see that, 

or their capacity to deal with large projects. 

Mr. SYPOLT. Obviously, Senator, the Alaska pipeline is a huge 

project. It’s outside of the norm. I believe that PHMSA has looked 

at other large projects, similar to the Rockies Express Pipeline that 

was built across the majority of the United States. So they have 

taken on large projects before and watched over those. 

But clearly the Alaska project would be a huge one that would 

require several resources that they probably would be directing in 

that direction for a period of time. 

Senator BEGICH. Do you think they have the—and again, this 

may be an unfair question for you, but do you think they have the 

authority to do whatever kind of reimbursable contracting or anything of that nature to bring those resources to bear as they need 

them for a project of that magnitude? 

Mr. SYPOLT. Senator, I’m not sure that I know that answer. 

Senator BEGICH. That’s fine. 

Anyone else want to comment on that, on their ability? Yes? 

Mr. WEIMER. That’s one concern that we’ve had with a lot of the 

new pipelines. We’ve heard some discussion today of the Keystone 

pipelines and some of those, and the ones in Alaska would be even 

larger. My understanding—and this is something that it probably 

would make sense to question PHMSA about a little more—is 

there’s somewhat of a disincentive built into their fee structure, because their fee structure is based on user fees that they don’t start 

to collect until there’s actually product going through those pipelines. 

So to inspect pipelines that are not yet working, they’re taking 

money that’s coming from other things and trying to divert resources. So there has been some discussion about whether you need 

actual fees for inspections of proposed new pipelines so existing 

pipelines aren’t subsidizing the new operators. 

Senator BEGICH. Let me ask—that’s an interesting question. People hate this when I bring this up at these meetings, but I used 

to be a mayor. When we had building inspections, you always had 

fees to inspect those buildings in the construction phase, as well as 

obviously if you were a commercial building on your annualized inspections. 

Let me ask other people to comment. Do you think there should 

be a fee structure for prior to and during construction of projects, 

say of that size? 

Mr. WEIMER. I think I’m coming at it with my same—because I’m 

an elected county council member, too. 

80 

Senator BEGICH. Oh, good. 

Mr. WEIMER. So to a degree we always try to get fees to cover 

the fees so other people aren’t subsidizing that. So it makes sense 

to us and it’s a way to make sure that they have the resources to 

pay for those things without spreading themselves too thin. Now, 

whether that’s the case or not, that would be questions that you’d 

have to ask PHMSA. 

Senator BEGICH. Anyone else want to comment on that? I know 

industry folks don’t like to always talk about fee issues, but this 

is an opportunity for you. 

[Pause.] 

Senator BEGICH. I knew someone would take the bait. 

Mr. FELT. I agree that you probably have to ask PHMSA about 

the super-large projects. But it hasn’t deterred them so far from inspecting, say, more moderate sized projects. Currently our company 

is involved with a relocation project to accommodate, in the State 

of New Jersey, where the New Jersey Turnpike is widening. We’re 

going to spend well over $100 million on construction in that particular project, and we’re just the relocating part of that project. 

We’ve already been notified that PHMSA inspectors will be out 

there and we’re prepared for that. 

So maybe something of a larger nature has to be discussed separately, but I think for the day-to-day type of work that’s happening 

it appears to me that PHMSA is—— 

Senator BEGICH. Is OK. 

Mr. FELT.—is okay. They’re there, they’re showing up. 

The other thing is that the fees that we’ll be paying down the 

road—if they’re inspecting, I think the approach they’re taking, if 

they’re inspecting up front, they probably won’t have as much need 

to inspect later on. So they’ll be collecting fees, yes, after the fact, 

but it’ll probably more than reimburse the effort they put in up 

front. Now, that’s not for maybe the super-large projects, but probably for all other ones. 

Senator BEGICH. Because we estimate this is probably a 30, 40, 

50, depending on what day it is, billion dollar project. 

One last comment. I know I’ve exceeded my time. 

Mr. D’ALESSANDRO. The only thing I was going to add was, when 

Rocky Express came through Illinois not only was PHMSA inspecting it, but your state OPS was also out there inspecting. So there’s 

more pressure, I think, maybe at the state level because of their 

funding and their staffing. But they’re also out there inspecting 

those large projects. 

Senator BEGICH. Very good. 

Thank you all very much for your time and answers. 

Thank you, Mr. Chairman. 

Senator LAUTENBERG. Senator Vitter, are you still patient? 

Senator VITTER. Yes. 

Senator LAUTENBERG. We’re joined by Senator Pryor and I would 

now ask you to ask any questions that you might have. 

81 

STATEMENT OF HON. MARK PRYOR, 

U.S. SENATOR FROM ARKANSAS 

Senator PRYOR. Thank you. Thank you, Mr. Chairman. I do have 

just a small number. Thank you for your leadership here, and I appreciate the panel being here today, too. 

Let’s see. Mr. Felt, I would like to ask you a question about the 

TransCanada Pipeline. In the approval process, as I understand it, 

because it’s Canada and U.S. there has to be an approval process 

through the State Department; is that right? 

Mr. FELT. That is correct. You’re talking about the gas line—— 

Senator PRYOR. Yes. 

Mr. FELT—coming through? That would probably be more appropriate for one of the other gentlemen. 

Senator PRYOR. OK. 

Mr. FELT. Oh, the oil line you’re talking about? Oh, yes. I’m 

sorry. There is a NEPA process for that, for that pipeline, that’s 

correct. 

Senator PRYOR. And how is that approval process going? Is the 

State Department moving that through or doing the proper due 

diligence they need to do? 

Mr. FELT. I’m really not familiar with the details. I do know that 

it’s going through the process. I heard that it is making progress. 

But that’s really third- or fourth-hand information. 

Senator PRYOR. OK. I know as part of the Gulf oil spill there has 

been some allegations or concerns about MMS being too close to 

the oil industry. I would like to ask about the relationship with 

PHMSA and your industry. So I don’t know who this should be 

best directed to, but if you could tell us about the relationship between PHMSA and your industry and how hard they look at 

things, how difficult the inspections and the approval process are, 

etcetera. So who wants to take that? 

Mr. SYPOLT. I’ll be happy to, Senator. I believe that the PHMSA 

regulations are based on sound engineering practices, so the regulations that they enforce make great sense to the industry. The industry does millions and millions of inspections. Many of those are 

based on certain timeframes and have to be completed within certain timeframes. PHMSA or their agents come out very regularly 

and audit our records. The records are very, very open as far as 

PHMSA or their agents’ ability to look for any particular violations, 

such as being 3 days late on an inspection. 

When you’re doing millions of inspections and you have 1 or 2 

of them that are 3 days late and you end up fined for that, some 

pipeline operators will believe that to be heavy-handed regulation. 

So I think PHMSA is aggressive in their audits and in their enforcement practices. 

Mr. FELT. Sir, I’d like to add a couple points on that. I would say 

that we have a respectful relationship with PHMSA. In addition to 

just auditing records, it has been my experience that they’ll actually go out into the field, and not just the field locations, but the 

remote locations, and look at corrosion readings out in the middle 

of a cornfield somewhere. They’ll look at valves just to make sure 

that they’ve been properly maintained. 

Interestingly enough, the pipeline records, the safety record, has 

been improving over the years, but it seems to me that the number 

82 

of inspections have been increasing, the detailed level of the inspections have been increasing. Unfortunately, the number of fines 

have been increasing, both number and size. To me, that’s a reflection of what I believe is PHMSA raising the bar even while the 

safety performance is improving. 

So I think that’s what the public wants and I’d have to commend 

PHMSA for doing it, even though it’s at the expense of the pipeline 

industry. But I think we all win. 

Senator PRYOR. Did you want to? 

Mr. D’ALESSANDRO. When you look at the PIPES Act and the impact it had on the distribution companies, PHMSA’s been straightforward and fair with us, but they do enforce what they have there. 

From a distribution point of view, they utilize the state agencies on 

inspections and enforcements and follow-ups. 

But we appreciate PHMSA—they’ve been straightforward. 

They’re strict on their rules, but they share them and they’re 

knowledgeable, so we understand what we’re walking into and 

what needs to be corrected. 

Senator PRYOR. One last question on that, and that is that, 

again, with some regulators there’s not a real clear revolving door 

rule or law. Do you know what the rule or law is with PHMSA in 

terms of when someone can leave the agency and go to work for 

a company that has business before the agency? Do you know what 

the rule is on that? 

[No response.] 

Senator PRYOR. Do people in the industry routinely hire ex-employees of PHMSA? 

Mr. FELT. I wouldn’t say routinely. I am aware that it’s happened. I think—and it’s just anecdotal, but I think it’s just as easily seen where they hire people with experience in the industry to 

help them better assess and inspect, and that has been the experience I’ve seen. A lot of the people that are working at the inspector 

level have got prior first-hand experience in the industry. 

Mr. SYPOLT. Senator, I would agree with Mr. Felt. It typically 

goes that they hire people from the industry rather than the industry hires people from PHMSA. 

Senator PRYOR. Thank you, Mr. Chairman. 

Senator LAUTENBERG. Senator Vitter. 

STATEMENT OF HON. DAVID VITTER, 

U.S. SENATOR FROM LOUISIANA 

Senator VITTER. Thank you, Mr. Chairman. 

A couple of questions. For the whole panel: If you look at serious 

incidents, particularly those that cause injury or death, what are 

the top categories of causes related to those serious incidents? I assume corrosion is on that short list. I know that was a factor in 

an explosion that caused a death in Louisiana several years ago. 

Is that on the short list? What else would be on the short list? 

Mr. SYPOLT. Outside excavation, Senator, is the largest impact. 

Corrosion is on that list, but it’s pretty far down, down the list. But 

outside excavation would be the greatest impact. 

Senator VITTER. What else would be high on the list? Anybody? 

Mr. FELT. I believe equipment failure is probably high on the list, 

too. But I would have to say that the third party or excavation 

83 

damage, the reason it’s so high on the list is because you probably—first of all, you’re not prepared for it. That’s why it occurs. 

There’s no warning when it happens. And you’ve probably got an 

operating piece of equipment involved. So it’s not so much that you 

have the release of gas or gasoline; it’s that you have an ignition 

source right there at the time. I think that’s what contributes to 

the severity of the incidents. 

Mr. D’ALESSANDRO. The key in excavation damage, it’s pretty 

broad. The number one issue on excavation damage is people not 

using 811 and making that first call. The second thing is, once the 

lines are marked, there’s proper construction that still has to be 

done around the pipes to secure them. That’s the number two 

issue. 

The number third issue on excavation damage is really mislocating, the locate is not within the 18 inches and it’s mismarked. 

Senator VITTER. Then the second question is about offshore pipelines in particular, which are obviously significant off Louisiana. 

What role does PHMSA play in regulating offshore pipelines, first 

of all, generally speaking? 

Mr. FELT. Sir, I think that PHMSA would be the best people to 

ask. I don’t have offshore pipelines, but I did hear Ms. Quarterman 

talk about the fact that they do have some authority within—I 

can’t remember how many miles of the shoreline. So there’s probably some transition between OPS or PHMSA and MMS, and 

they’d probably be better able to answer that. 

Senator VITTER. Maybe I’ll go back to them with the question. 

Anyone have any direct perspective on that? Do any of you have 

offshore pipelines? 

[No response.] 

Senator VITTER. Thank you, Mr. Chairman. 

Senator LAUTENBERG. Thank you, Senator Vitter. 

You know, I respect so much the fact that safety has been improved over these years, but nevertheless we have a question here 

about the number of accidents since 2006. Not a question, but there 

still were 58 deaths since 2006, $900 million in damages. So the 

mission is to get that down to an even lower level, and I’m sure 

all of you agree with me. I just bring that to your attention so that 

we can continue to look at the possibilities and—this is not intended to be a threat, but at regulation perhaps, or rules that can 

make it even safer. I know that all of you would like that to occur. 

The number of inspectors. Mr. Weimer, we’ve had an increase 

from 2007 of about 40 inspectors. With that, do you have knowledge or an idea as to whether or not we have enough people out 

there to look at these things? I hear of going to the cornfields and 

other very difficult places to find the location. Do we have enough 

people out there to do the job, do you think? 

Mr. WEIMER. Probably a good question for PHMSA. From our 

perspective, there has been significant progress made because of 

the PIPES Act to hire more inspectors. They’ve had some problems 

actually getting those inspectors hired and out in the field. I was 

glad to hear Ms. Quarterman talk about their expedited efforts to 

get those inspectors actually hired and fill those positions. 

In the State of Washington, after the pipeline explosion in Bellingham that killed three children, the State of Washington looked 

84 

at that and decided that the number of inspectors that were available from the Western Region of OPS was not adequate for what 

they wanted to do in the State of Washington. So they got the authority to do their own inspections in Washington and hired I think 

eight inspectors just for the State of Washington, which was far 

more than PHMSA could provide, to provide better inspections. 

Other states have made those same decisions. 

Senator LAUTENBERG. We’ll have to look at that, because again 

safety being the primary issue of today’s hearing. The fact is we 

want to make sure that we have the tools on the government side 

to do what we have to do to ensure as much protection as possible. 

PHMSA and the Federal Energy Regulatory Commission both 

bear responsibility for regulating the development of new natural 

gas pipelines. How can this cooperation be improved to make sure 

that the public has the necessary information on the impact of a 

pipeline to their community and the impact—there will be those 

proposing what the economic result might be, but the fact of the 

matter is that the safety factor being what it is—who is principally 

responsible in your view, and how can that collaboration be improved—between these two agencies? 

Mr. SYPOLT. Mr. Chairman, PHMSA does certainly come out on 

the construction of new pipelines. How does the public—I believe 

that was your question, how do they find out about these pipelines 

and the safety of them? FERC actually holds public awareness 

meetings or public meetings on projects in various communities 

along the pipeline route, where those type discussions do occur. 

The pipelines are there present, FERC is there present, and there’s 

a ton of information given regarding the construction process, and 

there are—on INGAA websites there are many slides that actually 

explain the construction process as well. 

So people have access to that. But during the construction process itself, PHMSA comes out for inspection during the construction, 

sir. 

Senator LAUTENBERG. So the responsibility lies primarily there. 

One of the things that I’ve worked on since I’ve pretty much been 

in the Senate, and that is guaranteeing that the public has a right 

to know about what’s in their area in terms of chemicals or emissions, etcetera. I wonder how we can improve the public’s awareness of what’s in their area and raise their consciousness to a level 

so that they an submit questions if they have any to make sure 

that they’re appropriately protected. 

Mr. WEIMER. Well, Mr. Chairman, if I can take a crack at that 

one. That’s certainly one of our large issues, too, to make sure as 

much information is available as possible, because I think that 

makes everything safer. Even talking about the issue you just 

raised the question about during siting, for gas pipelines you have 

FERC and PHMSA working together. With liquid pipelines, it’s 

even more complicated because you may have the Department of 

State or you may have states trying to do it, and there seems to 

be a disconnect between the safety issues and the siting issues, especially when it comes to information available for people that are 

trying to decide if a pipeline through their area is safe, because 

often PHMSA grants special waivers or special permits for things 

to do with pipelines. They have spill response plan responsibilities. 

85 

They designate high consequence areas in places. Lots of those 

processes are either somewhat secret from even local governments, 

like high consequence areas, or they’re done after the fact as the 

EIS is moving through for the siting. 

So somehow to better coordinate so those processes that PHMSA 

is in charge of are actually integrated into the EIS’s that the states 

or that the Department of State or FERC are doing would be one 

way. 

There are lots of other things. One of the things that we’re really 

looking for and we understand that PHMSA is working on now is 

inspection transparency, so people in communities can look to see 

specific companies, what have they been inspected for, what was 

found, what was done. My understanding is you’ll see PHMSA coming out with a website that will let individuals and communities be 

able to do that. We think that would be a great step forward. 

Senator LAUTENBERG. One of the things that happened in my 

State of New Jersey, that big accident took place in 1994 and that 

raised the recognition. I think that those of you who have cause to 

put down new pipelines in the State of New Jersey know that 

there’s a very interested public in what you’re about to do. So we 

have an inspection team out there of citizens who are concerned 

about themselves, their families, and their community. 

I want to thank you each, all of you who testified here on this 

panel, for a degree of consciousness that you bring to the problem 

and how you hold safety as a principle factor. Please continue to 

do that. 

We’ll keep the record open for a bit so that any questions that 

may not have been asked and want to be asked will be submitted, 

and we would ask your prompt response, hopefully within a week 

of the time that you get the questions. 

Thank you, and this hearing is adjourned. 

[Whereupon, at 4:19 p.m., the hearing was adjourned.] 

(87) 

A P P E N D I X 

RESPONSE TO WRITTEN QUESTIONS SUBMITTED BY HON. JOHN D. ROCKEFELLER IV 

TO HON. CYNTHIA L. QUARTERMAN

Question 1. What has PHMSA found in its evaluations of companies’ oil spill response plans and what additional enforcement mechanisms does PHMSA need to 

make sure companies develop adequate plans? Are companies’ response plans available to the public? 

Answer. PHMSA ensures that oil response plans meet all applicable regulatory 

requirements of 49 CFR Part 194 before it approves them. After an operator submits a proposed plan, PHMSA reviews it fully. If a plan does not meet all the applicable regulatory requirements, PHMSA works with the operator to revise the plan 

and correct any deficiencies. PHMSA has reviewed approximately 450 response 

plans and has ensured that they all meet regulatory requirements. Response plans 

generally include: 

• Procedures and a list of resources for responding, to the maximum extent practicable, to a worst case discharge and to a substantial threat of such a discharge; 

• Certification that the response plan is consistent with the National Contingency 

Plan and specific elements of each applicable Area Contingency Plan; 

• A core plan with: 

» An information summary, 

» Immediate notification procedures, 

» Spill detection and mitigation procedures, 

» Contact information for the oil spill response organization (OSRO), 

» Contact information for Federal, State, and local agencies that the operator 

expects to have pollution control responsibilities or support, 

» Training procedures, 

» Equipment testing, 

» A drill plan that satisfies, or is equivalent to provisions of, the National Preparedness for Response Exercise Program (PREP), and 

» Plan review and revision procedures; 

• An appendix for each response zone included in the plan. If the plan only covers 

one response zone, then this section is a single summary of specific information 

from the core plan; and 

• A detailed description of the operator’s response management system that includes a clearly defined chain of command and identifies sufficient trained personnel to fill each position. 

To date, PHMSA has not received reports from response agencies (e.g., USCG or 

EPA) indicating that PHMSA-approved plans have been inadequate during actual 

pipeline incidents and releases. On June 30, 2010, PHMSA issued an Advisory Bulletin reminding operators of onshore oil pipeline facilities that they must conduct 

a review of their oil spill response plans and submit any updates to their oil spill 

response plans as set forth in § 194.121 within 30 days. 

PHMSA will continue to work with other Federal approving agencies to strengthen the standards and processes for its response plan review to ensure that plans 

adequately address spill risk. PHMSA is planning an oil spill response plan benchmark study with other Federal agencies. The study will review how other Federal 

agencies administer oil spill planning, preparedness and recovery operations. 

PHMSA, through the Secretary of Transportation, needs to have the authority to 

enforce Part 194 of the regulations through civil penalties. PHMSA urges Congress 

to amend 33 U.S.C. 1321(b)(6)(A) to provide it with this authority by indicating that 

88 

agencies who issue regulations pursuant to 33 U.S.C. 1321 have authority to enforce 

those regulations. 

Facility oil spill response plans submitted to PHMSA are available to the public 

through Freedom of Information Act (FOIA) requests. Individual operators may also 

make these plans available on their websites or as requested by the public. 

Question 2. In light of the catastrophic consequences from the recent oil spill in 

the Gulf of Mexico, what steps is PHMSA taking to make sure it is providing sufficient oversight of the offshore pipelines under its jurisdiction? What additional requirements does PHMSA apply to offshore pipes than it does for onshore pipes to 

prevent such environmental disasters? 

Answer. Since the Deepwater Horizon oil spill, PHMSA has reviewed its inspection records for operators of offshore transportation pipelines subject to PHMSA’s 

jurisdiction. It has verified that the facilities of all such operators have been inspected within the past 3 years or are scheduled for inspection this calendar year. 

PHMSA has reviewed accident and incident report data to identify risks that may 

be unique to offshore pipelines. This review indicates that the offshore accident rate 

for offshore liquid pipelines is below the per-mile average for onshore liquid pipelines. In addition, PHMSA has identified certain regulatory actions that should be 

taken, and that it intends to take, to improve its oversight of offshore facilities. 

PHMSA applies the same corrosion control and integrity management requirements to both onshore and offshore pipelines. Offshore gas pipelines, however, have 

a higher rate of corrosion failure than onshore pipelines. PHMSA regulations include additional inspection and reburial requirements for pipelines located in shallow waters of the Gulf of Mexico that could pose a hazard to navigation. Finally, 

PHMSA is considering whether additional or different regulatory requirements 

should be made for offshore pipelines. 

Question 3. Integrity Management Plans are currently only required for High 

Consequence Areas, which cover a limited amount of pipeline mileage. Is this requirement sufficient, or should Integrity Management Plans be expanded to cover 

a wider portion of pipelines? 

Answer. Integrity Management (IM) programs have significantly increased safety 

in High Consequence Areas (HCAs) by ensuring that operators identify potentially 

dangerous anomalies and by increasing operators’ knowledge about the condition of 

their pipelines. 

IM programs help focus operator resources on the areas of greatest risk to the 

public and the environment. The IM regulations complement and are in addition to 

PHMSA’s baseline prescriptive safety requirements. All operators must comply with 

PHMSA’s prescriptive regulations for any pipelines that fall within PHMSA’s jurisdiction. In addition to these baseline regulations, operators must maintain IM programs uniquely suited to address the risks confronting the HCAs on each of their 

pipelines. 

The current IM requirements provide protection that extends beyond just HCAs. 

While operators are only required to assess the pipeline segments that can affect 

HCAs (approximately 44 percent of the Nation’s pipeline mileage), they have actually ‘‘smart pigged,’’ pressure tested, or otherwise assessed a far greater proportion 

(approximately 86 percent) of the total hazardous liquid pipeline mileage. This has 

increased pipeline safety in locations well beyond the HCAs. 

PHMSA intends to review the current rules to determine whether IM requirements should be applied beyond HCAs and, if so, to what extent. 

Question 4. Please describe the process PHMSA uses to inspect the integrity and 

safety of pipe used for pipeline construction. Is this process the same for domestic 

and imported pipe? 

Answer. PHMSA ensures pipe quality through constructionsite inspections during 

pipeline installation. Inspections evaluate installation practices including welding, 

materials documentation, and leak and strength tests of the pipe at the conclusion 

of pipeline installation. The final documentation of pipe serviceability prior to placing a pipeline into service is the PHMSA-mandated hydrostatic test, during which 

the pipeline is tested at a pressure higher than it will ever experience during its 

service life. 

PHMSA regulations reference the professional standard for line pipe, American 

Petroleum Institute (API) standard 5L. API standard 5L provides manufacturing 

standards for pipe used in the oil and natural gas industry. PHMSA inspections include reviews of pipe testing data and certifications that document pipe conformity 

with the manufacturing standards. Any pipe, whether domestic or imported, used 

in a pipeline system under PHMSA’s jurisdiction must comply with these provisions. 

PHMSA takes a proactive approach when it learns of material quality issues, including line pipe issues. In late 2008, in the course of field inspections, PHMSA disVerDate Nov 24 2008 07:17 Jul 12, 2011 Jkt 067270 PO 00000 Frm 00092 Fmt 6601 Sfmt 6621 S:\GPO\DOCS\67270.TXT SCOM1 PsN: JACKIE
89 

covered a potential issue with steel pipe quality when isolated failures occurred in 

the field during hydrostatic testing. PHMSA immediately implemented requirements for determining the extent of the problem with the operator involved and for 

removing low strength pipe from the pipeline system. When PHMSA discovered a 

second operator with similar issues, PHMSA issued a safety Advisory Bulletin to the 

public in May 2009, alerting all pipeline operators to the potential issue and recommending practices to ensure that purchased pipe met PHMSA requirements. 

PHMSA also later published interim guidelines providing specific steps operators 

may take to check for pipe quality issues. In taking action on the pipe quality issue, 

PHMSA acknowledged that although the issue appeared to be isolated to high grade 

steels (X70 and X80), action needed to be taken to prevent a recurrence or a more 

widespread problem. 

Question 5. When a company submits a waiver to construct a pipeline using pipe 

that does not meet regulatory requirements, what steps does PHMSA take to ensure 

the integrity and safety of the pipe? 

Answer. The Federal Pipeline Safety Statute (49 U.S.C. § 60118) permits the Office of Pipeline Safety to waive regulatory requirements by issuing special permits. 

PHMSA issues a special permit only after completing a review that shows that 

waiver of the regulations will not compromise public safety. Typically, an operator 

that requests a special permit must take measures to mitigate any adverse consequences of non-compliance with the regulations. Such measures may include but 

are not limited to: 

• Operating pipelines at reduced pressures; 

• Providing additional cathodic and corrosion protection; 

• Monitoring pipelines more frequently (e.g., by aerial or foot patrols); 

• Installing pipeline instruments that continuously monitor pipeline pressures; 

• Installing high and low pressure alarms and automatic shutdown devices to 

prevent pipeline failure; and 

• Carrying out detection and monitoring activities designed to discover the release of oil. 

RESPONSE TO WRITTEN QUESTION SUBMITTED BY HON. FRANK R. LAUTENBERG TO

HON. CYNTHIA L. QUARTERMAN

Question. The BP oil spill in the Gulf of Mexico showed the disastrous consequences that can occur when a Federal oversight agency fails to do its job. Are 

you confident that PHMSA’s inspectors are performing unbiased inspections and 

that the agency is performing the necessary level of oversight of our Nation’s pipelines? 

Answer. PHMSA is confident that its inspections are unbiased and adequate, and 

that PHMSA is using all the necessary tools to oversee the Nation’s pipelines. Most 

PHMSA inspectors are engineers or have obtained technical college or graduate degrees. All pipeline inspectors also receive extensive formal and informal training 

prior to performing inspections. PHMSA requires all its inspectors to be certified via 

a three-year training course. PHMSA inspects pipelines at all phases of construction 

and operation. PHMSA inspects new pipeline construction. These inspections are 

typically highly resource intensive over a short time span. PHMSA inspectors examine everything from the design to construction to initial operation. PHMSA regularly 

inspects the operating pipelines under its jurisdiction. PHMSA inspects each pipeline operator once every 3 years on average. State partners also assist PHMSA to 

oversee the Nation’s pipelines. PHMSA has a detailed program to verify that its 

State partners are performing adequately. PHMSA conducts targeted inspections to 

ensure that operators who are granted special permits are complying with them. 

PHMSA’s enforcement record demonstrates the success of its inspection program. 

PHMSA issue on average 230 enforcement actions per year, and its collection rate 

on assessed penalties is 99 percent. 

To ensure that PHMSA’s inspectors carry out unbiased inspections, PHMSA requires every inspector to file a financial disclosure report listing all financial interests and outside activities that could create a conflict of interest, or the appearance 

of a conflict of interest, with the inspector’s job responsibilities. This way, PHMSA 

ensures that its inspectors are free from any potential conflicts of interest. In addition, PHMSA provides ethics training to all new hires as well as annual refresher 

training for all inspectors. PHMSA also sends out periodic informational bulletins 

on relevant topics such as gift restrictions, avoiding appearances of impropriety, and 

how to ensure impartiality and integrity when performing one’s job. One such ethics 

90 

bulletin specifically addressed the allegations related to the Federal oversight agency relating to the BP spill. 

RESPONSE TO WRITTEN QUESTIONS SUBMITTED BY HON. MARK PRYOR TO

HON. CYNTHIA L. QUARTERMAN

Question 1. What is the approval process for new trans-national oil pipeline like 

the Keystone XL pipeline project from Alberta, Canada to Houston and Port Arthur? 

Answer. Executive Order 13337 authorizes the U.S. Department of State (DOS) 

to receive applications and issue Presidential permits for the construction, connection, operation, or maintenance of certain facilities (including oil pipelines) at the 

national borders. Presidential permit applications require a DOS project assessment 

pursuant to the National Environmental Policy Act (NEPA) and Section 106 of the 

National Historic Preservation Act (NHPA), as well as an interagency National Interest Determination review. DOS typically requests relevant Federal agencies, including the Department of Transportation (DOT), to submit their opinions during 

this process. PHMSA has provided assistance to the DOS on technical pipeline matters with respect to the Keystone XL project. DOS may also coordinate with affected 

state and local agencies. Additional applications and approvals may be needed depending on state and local laws. Approvals through The National Energy Board 

(NEB) of Canada are required to construct and operate the Canadian portion of 

these lines. 

Keystone XL has requested a special permit from PHMSA to deviate from the design factors in the regulations (49 CFR § 195.106). As part of PHMSA’s review of 

the special permit request, PHMSA is conducting its own environmental assessment 

(EA) in accordance with DOT Order 5610.1C; the National Environmental Policy Act 

(NEPA), 42 U.S.C. §§ 4321–4375; and the Council on Environmental Quality regulations, 40 CFR §§ 1500–1508. The purpose of the EA is to assess whether granting 

a special permit would have a significant impact on the environment. 

Other agencies with which Keystone XL filed applications include: 

• The U.S. Bureau of Land Management, for a grant of right-of-way and temporary use permit allowing construction and operation of the pipeline project 

across certain Federal lands; 

• The Montana Department of Environmental Quality, for a certificate under the 

Montana Major Facilities Siting Act; and 

• The South Dakota Public Utilities Commission, for a permit under the South 

Dakota Energy Conversion and Transmission Facility Act. 

Question 2. Do you know the status of the Keystone XL pipeline project at the 

Department of State and other relevant agencies? 

Answer. The DOS environmental review of the project under NEPA is ongoing. 

On April 16, 2010, a draft Environmental Impact Statement (DEIS) was published 

for public comment. The comment period for the DEIS ended July 2. DOS is currently compiling and responding to the comments, which will inform the Final Environmental Impact Statement (FEIS). The DOS inter-agency National Interest Determination review is underway for 90 days beginning June 16. At the end of the formal EIS and National Interest periods, DOS will decide whether to issue the permit 

and will inform the agencies by Executive Secretariat memo of that decision. 

PHMSA’s review of the special permit request and related EA is also ongoing. 

PHMSA intends to publish draft versions of the special permit analysis and findings 

as well as the EA, and to provide a 30-day public comment period prior to making 

a final decision. 

With respect to other agencies, TransCanada filed its section 52 application with 

the National Energy Board and received approval on March 11, 2010 to construct 

and operate the Canadian portion of the Keystone XL. 

TransCanada filed an application with the U.S. Bureau of Land Management for 

a grant of right-of-way and temporary use permit that would allow construction and 

operation of the pipeline across certain Federal lands. The application is currently 

under review by the agency. 

TransCanada filed an application with the Montana Department of Environmental Quality for a certificate under the Montana Major Facilities Siting Act. The 

application is currently under review by the agency. 

TransCanada filed an application for with the South Dakota Public Utilities Commission for a permit under the South Dakota Energy Conversion and Transmission 

Facility Act and received approval on March 11, 2010. 

Question 3. What regulatory authority will PHMSA have during its construction 

and through the life of its use? 

91 

Answer. Once the State Department has approved the siting, PHMSA will have 

the statutory authority to regulate the design, construction, operation, and maintenance of the Keystone XL pipeline to protect public safety and the environment. 

PHMSA’s regulations cover the full pipeline life cycle, and PHMSA engineers will 

conduct inspections to carry out its responsibilities. 

49 CFR Part 195 prescribes safety standards and reporting requirements for pipeline facilities used in the transportation of hazardous liquids. 49 CFR Part 195, Subpart C prescribes minimum design requirements for new pipeline systems constructed with steel pipe. 49 CFR Part 195, Subpart D prescribes minimum requirements for constructing new pipeline systems with steel pipe. 

PHMSA’s responsibility in pipeline construction is to ensure that the pipeline will 

operate safely once it is placed in service. PHMSA inspects pipeline construction to 

ensure compliance with these requirements. Inspectors review operator-prepared 

construction procedures to verify that they conform to regulatory requirements. Inspectors then observe construction activities in the field to ensure that they are conducted in accordance with the procedures. Additional inspections occur once a pipeline is in service and throughout its lifetime to confirm that it is being operated and 

maintained in accordance with 49 CFR Subpart F. Additional Subparts of Part 195 

that subject operators to inspection and enforcement include Subpart B (Annual, Accident, and Safety Related Condition Reporting), Subpart E (Pressure Testing), Subpart G (Qualification of Pipeline Personnel), and Subpart H (Corrosion Control). 

Question 4. How would you describe the relationship between PHMSA and the oil 

and gas industry? Do you believe there is a revolving door problem between PHMSA 

and the oil and gas industry that needs to be addressed? 

Answer. As a safety oversight and enforcement agency, PHMSA maintains a professional relationship with the oil and gas industry. PHMSA does not have a revolving door. Some of PHMSA’s personnel do have experience in the oil and gas industry. PHMSA has found that their experience enables them to identify safety and 

compliance issues. As inspectors and accident investigators, PHMSA’s personnel see 

first-hand the tragic results of safety shortcuts and non-compliance and have little 

patience for operators who endanger the public and the environment. 

Question 5. Does PHMSA have adequate resources (inspectors) to carry out its authorized goals? 

Answer. Yes. The additional inspection and enforcement positions that Congress 

authorized in Fiscal Years 2009 and 2010 provide PHMSA with an adequate number of pipeline safety inspectors. These positions have enabled PHMSA to conduct 

a wider range of pipeline inspections. 

Question 6. Do exemption requirements for one-call systems in states weaken the 

effectiveness of these programs? 

Answer. Yes. Effective damage prevention programs involve active participation 

and accountability for all stakeholders. However, limited exemptions based on the 

type of excavation activities, such as agricultural tilling or gardening to a minimal 

depth with hand tools, are often included in state one-call laws, and do not generally 

represent a threat to safety. The risks to public safety and the pipeline infrastructure are greater when groups of stakeholders, such as municipalities or state DOTs, 

have blanket exemptions from participating in the one-call process. PHMSA strongly 

supports the elimination of such exemptions and continues to work with the states 

to help them strengthen laws and promote fair, balanced, and inclusive one-call programs. 

Question 7. Are existing penalties for safety violations adequate for pushing industry to focus on safety over revenue? 

Answer. Existing penalty levels have largely been effective. That said, PHMSA 

has been issuing penalties at the top limit of its authority. Increased civil penalty 

levels would be helpful in certain situations for additional deterrent effect. 

Question 8. Should PHMSA have more authority to regulate offshore pipelines? 

Answer. No. PHMSA’s authority to regulate offshore transportation pipelines is 

complemented by the Bureau of Ocean Energy Management’s authority over production on the Outer Continental Shelf and State agencies’ authority over production 

in State waters. 

Question 9. How is PHMSA prepared to respond to a major pipeline failure caused 

by a natural disaster, manmade disaster, or terrorist attack? (New Madrid) 

Answer. When a significant interstate pipeline incident occurs, PHMSA inspectors 

are dispatched from their respective Regional Office to investigate the cause of the 

failure. They monitor effects of response operations on pipelines that may be involved or near to the incident. They determine if there were violations of the Pipeline Safety Regulations that contributed to the incident. They ensure that an operaVerDate Nov 24 2008 07:17 Jul 12, 2011 Jkt 067270 PO 00000 Frm 00095 Fmt 6601 Sfmt 6621 S:\GPO\DOCS\67270.TXT SCOM1 PsN: JACKIE
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tor’s repair procedures provide an adequate level of safety as they restore the line 

to service. In some cases, investigators from Headquarters or other Regional Offices 

are deployed to assist if their specific expertise is necessary. PHMSA has a highly 

trained and experienced inspector force of over 100, most of whom are engineers. 

When incidents occur in natural gas distribution systems, PHMSA’s State partners usually lead the pipeline safety investigation. PHMSA will, in some situations, 

assist in those investigations. PHMSA supports State-level pipeline safety programs 

in 48 states and the District of Columbia through Grants-in-Aid. PHMSA’s State 

partners generally enforce State laws concerning intrastate natural gas distribution 

and master meter systems. In a limited number of cases, State partner agencies also 

inspect interstate hazardous liquid pipeline systems, such as those that transport 

crude and refined oil products, as part of their grant agreement. When a pipeline 

incident involves a spill of either crude or refined oil, PHMSA works with the Federal On-Scene Coordinator (usually an official from the U.S. Environmental Protection Agency or the U.S. Coast Guard) to ensure that the operator mounts a rapid, 

efficient spill response operation, even as PHMSA oversees the operator as it works 

to repair and restore its pipeline to service. 

When an event involves many Federal, State, and local agencies, PHMSA provides 

technical support through Emergency Support Function (ESF) #1 (Transportation) 

and ESF #12 (Energy), consistent with the conduct of operations under the National 

Response Framework. If the event or significant consequences of the event are pipeline-related, PHMSA provides direct assistance to the Incident Commander, as the 

Pipeline Operations Branch of the Operations Division. PHMSA’s representatives 

participate as technical experts concerning pipeline operations, response options, 

and consequence management within the Integrated Command Structure of the incident. 

In addition to incidents in which PHMSA directly oversees a pipeline operator’s 

response to an incident, repair procedures, and eventual restoration of services, 

PHMSA has successfully operated in a wide range of incidents, including those of 

caused by criminal acts. PHMSA has routinely participated as a party in incident 

investigations under primary NTSB jurisdiction in coordination with the Chemical 

Safety and Hazard Analysis Board and others. 

PHMSA worked closely with the Transportation Security Administration for the 

past 2 years to develop protocols involving the FBI, TSA and other DHS elements, 

and the Department of Energy on coordinating the Federal response to threats to 

pipelines. 

Question 10. What do you believe should be the top priorities for PHMSA in light 

of the recent BP disaster? 

Answer. One of PHMSA’s top priorities is to recruit and retain America’s brightest individuals to help oversee the Nation’s pipeline energy supply systems and help 

safeguard the public and the environment. PHMSA must continue to work with all 

stakeholders to address the causes of pipeline failure, including excavation damage 

and corrosion. PHMSA must continue to support PHMSA’s State partners, who 

make up a significant portion of the pipeline safety workforce and who can focus 

on local needs and concerns. PHMSA must promote research and development into 

better ways to assess and assure pipeline safety. In addition to those priorities, 

PHMSA will ensure the adequacy of its oversight of offshore pipelines and oil spill 

response plans. 

RESPONSE TO WRITTEN QUESTION SUBMITTED BY HON. MARK BEGICH TO

HON. CYNTHIA L. QUARTERMAN

Question. Alaska and Hawaii are the only two states in the Nation that do not 

have approved state pipeline safety programs. Pipelines play a key role in safely 

transporting the oil and gas produced on Alaska’s North Slope, Cook Inlet, and 

hopefully soon the National Petroleum Reserve-Alaska and the Chukchi and Beaufort Seas. The Trans-Alaska Pipeline system falls under PHMSA jurisdiction as a 

partner agency of the Joint Pipeline Office. Although cooperation with Alaska appears to be improving, the lack of a strong state pipeline program is still a problem 

because all these systems connect. It also paces unusual resource burdens on 

PHMSA in Alaska. The low stress pipeline spill on the North Slope in 2006 is one 

example of the outcomes of inadequate oversight. It is my understanding that 

PHMSA assists states with cost-sharing grants for pipeline safety programs. What 

steps is PHMSA taking to encourage the State of Alaska to get an approved Pipeline 

Safety program in place? 

Answer. PHMSA has a long history of encouraging Alaska to enter the pipeline 

safety program and has met repeatedly with various stakeholders in Alaska to disVerDate Nov 24 2008 07:17 Jul 12, 2011 Jkt 067270 PO 00000 Frm 00096 Fmt 6601 Sfmt 6621 S:\GPO\DOCS\67270.TXT SCOM1 PsN: JACKIE
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cuss the benefits of a state program. PHMSA executives, as well as regional personnel, have met with Alaskan stakeholders to highlight how such a program would 

help ensure public and environmental safety and provide for an increased focus on 

local issues and concerns. 

PHMSA has developed a good working relationship with all of its State and Federal partners in Alaska and has made a deliberate effort to consistently share information on pipeline issues with them. Although the relationship is good, PHMSA 

seeks a more formal arrangement for the safety oversight of Alaska’s pipelines, especially the intrastate gas distribution pipelines that directly serve the local public. 

Alaska’s Governor will have to determine whether to enter into the Federal pipeline 

safety program. 

PHMSA notes that Alaska does currently regulate some pipelines such as 

flowlines, which are also subject to certain regulatory requirements of the EPA. 

PHMSA is always willing to assist Alaska with inspector training and/or technical 

assistance. 

RESPONSE TO WRITTEN QUESTIONS SUBMITTED BY HON. KAY BAILEY HUTCHISON TO

HON. CYNTHIA L. QUARTERMAN

Question 1. What recommendations do you have for the Committee with respect 

to reauthorizing the pipeline safety program? When can we expect to see a formal 

proposal from the Administration? 

Answer. The Administration’s reauthorization proposal is being reviewed and will 

be transmitted in due course. 

Question 2. Pipeline operators are working to design and build pipelines to make 

transportation of ethanol and ethanol blended fuels by pipeline feasible. PHMSA 

has indicated that its research shows that it is safe to move gasoline blends with 

ethanol up to 10 percent, but that at higher blend levels, questions remain because 

of stress corrosion cracking. Why does a higher concentration of ethanol cause more 

safety problems? 

Answer. High concentrations of ethanol threaten the integrity of storage tanks, 

line pipe, and valves because ethanol is highly oxygenated, and oxygen causes corrosion. The use of higher ethanol fuel mixtures (e.g., 85 percent ethanol (E85) and 

Fuel Grade Ethanol (95 percent ethanol, or E95)) causes ethanol stress corrosion 

cracking. Non-metallic pipeline components such as seals and other elastomers swell 

in the presence of ethanol. If there is an ethanol fuel fire, alcohol resistant foams 

are needed to suppress the fire. PHMSA has a comprehensive and collaborative research strategy to address ethanol pipeline challenges. 

Question 3. What more can be done to prevent pipeline damage caused by hurricane damage? Is any additional Federal authority needed to allow such damage to 

be addressed quickly by pipeline operators? 

Answer. PHMSA supports H.R. 5629, the Oil Spill Accountability and Environmental Protection Act of 2010, which would require pipeline operators to notify the 

Secretary of Transportation of any changes in the operational status of their facilities following a hurricane or other manmade or natural disaster. The proposed bill 

would also require operators to submit damage assessments to the Secretary of 

Transportation within 30 days after the end of a hurricane or other manmade or 

natural disaster. Otherwise, PHMSA believes its regulations adequately address 

damage to pipelines caused by hurricanes by ensuring proper design, materials selection, operations, and regular maintenance. Facilities designed and operated in accordance with PHMSA regulations are expected to survive those forces and conditions likely to be posed by most storms and to be able to resume operations after 

conditions return to normal. 

Question 4. Under the Oil Pollution Act of 1990, PHMSA has been delegated authority over onshore oil spill response plans, but does not have enforcement authority regarding compliance. Instead, PHMSA must refer non-compliance cases to the 

Coast Guard for appropriate enforcement. Does it make sense to you that the Coast 

Guard, rather than PHMSA, has enforcement authority over onshore pipelines? Do 

you recommend that Congress shift that authority to PHMSA? 

Answer. At the time that the Oil Pollution Act was passed, the U.S. Coast Guard 

was part of the Department of Transportation, which meant regulation and enforcement were both delegated to the Secretary of Transportation. Now that the U.S. 

Coast Guard is part of the Department of Homeland Security, enforcement is more 

difficult to coordinate. 

PHMSA, through the Secretary of Transportation, needs to have the authority to 

enforce Part 194 of the regulations through civil penalties. PHMSA urges Congress 

94 

to amend 33 U.S.C. 1321(b)(6)(A) to provide it with this authority, as proposed by 

H.R. 5629, the Oil Spill Accountability and Environmental Protection Act of 2010. 

Question 5. According to PHMSA, Texas is the only state that regulates off-shore 

production pipelines. Do you believe other States should be more pro-active in this 

area? 

Answer. PHMSA has traditionally allowed the states to regulate offshore production pipelines in state waters. States, including Texas, California, Alabama, and 

Mississippi, regulate some pipelines in their waters. Those regulations vary from jurisdiction to jurisdiction. The interpretation and application of those regulations are 

matters of state and local law. That said, PHMSA reserves the right to regulate offshore production lines in state waters as a matter of Federal law. PHMSA is currently reviewing the extent to which states are regulating pipelines in their waters. 

Question 6. What impact does the spill in the Gulf have on PHMSA’s safety priorities? Has it prompted your agency to conduct a review of the safety of off-shore 

pipelines? 

Answer. Since the Deepwater Horizon oil spill, PHMSA has reviewed its inspection records for operators of offshore transportation pipelines subject to PHMSA’s 

jurisdiction. It has verified that the facilities of all such operators have been inspected within the past 3 years or are scheduled for inspection this calendar year. 

PHMSA has reviewed accident and incident report data to identify risks that may 

be unique to offshore pipelines. This review indicates that the offshore accident rate 

for offshore liquid pipelines is below the per-mile average for onshore liquid pipelines. In addition, PHMSA has identified certain regulatory actions that should be 

taken, and that it intends to take, to improve its oversight of offshore facilities. 

PHMSA has conducted a review of its offshore pipeline safety inspection program 

and is considering whether additional or different regulatory requirements should 

be made for offshore transportation pipelines and related facilities. PHMSA has 

identified the need to promulgate regulations for design, construction, operation, 

and maintenance of transportation regulated platforms and transportation pipeline 

risers connected to offshore floating facilities. Consensus standards are currently 

under revision to strengthen the design, construction, and maintenance requirements. PHMSA is participating on the Committees revising the standard and expects to incorporate the standard by reference after a thorough internal review is 

complete. We anticipate this initiative to update regulations will take 2 years. 

PHMSA will be studying the safety oversight of offshore transportation platforms 

by working with the Department of the Interior through the 1996 Memorandum of 

Understanding. In addition, in the next year, PHMSA will examine the regulations 

implemented by State agencies with regulatory authority for offshore production 

and transportation pipelines. 

Question 7. How is integrity management applied to off-shore pipelines? Are there 

special requirements? 

Answer. Offshore hazardous liquid pipelines must be covered by an integrity management program if the pipelines are in, or could affect, a commercially navigable 

waterway or an unusually sensitive area, but there are no special requirements for 

offshore pipelines. 

Offshore gas transmission pipelines are generally not covered by integrity management programs. 

Question 8. As you know, in 2006 the U.S. Government Accountability Office 

(GAO) recommended that Congress consider replacing the 7-year fixed interval for 

reassessments of gas transmission pipelines with a variable schedule based on risk. 

What is the Administration’s position on GAO’s recommendation? When can we expect to have your recommendation? 

Answer. The current law requires a periodic reassessment of facilities subject to 

Integrity Management rules. The longest permitted interval between reassessments 

is once every 7 years. The Administration is enforcing the current law. 

RESPONSE TO WRITTEN QUESTIONS SUBMITTED BY HON. JOHN THUNE TO

HON. CYNTHIA L. QUARTERMAN

Question 1. There seem to be different views on the need to regulate production 

and gathering lines that connect wells together and then transport product to a 

transmission line. I have two questions: Which of these lines are regulated, and by 

whom (Federal or State)? Should all of these lines be subject to safety regulation 

and, if not, why not? 

Answer. Hazardous Liquid and Gas Production Lines: By statute, the Federal 

pipeline safety regulations cannot apply to hazardous liquid pipelines involved with 

95 

1 49 U.S.C. § 60101(a)(22). 2See 40 CFR § 112. 3See 49 CFR § 195. 

onshore production, refining, or manufacturing facilities, and any storage or in-plant 

piping associated with those facilities.1 These facilities and associated piping are 

considered non-transportation-related pursuant to Executive Order 12777 and are 

regulated by the Environmental Protection Agency (EPA).2

Offshore production pipelines on the OCS are regulated by the Department of the 

Interior under the terms of a Memorandum of Understanding with PHMSA. Offshore hazardous production pipelines in state waters are reserved for regulation by 

the states as a matter of policy. 

Hazardous Liquid Gathering Lines: The Federal pipeline safety regulations apply 

to all hazardous liquid gathering lines in non-rural areas and to any pipeline segment, including a hazardous liquid gathering line of any diameter, which crosses a 

commercially-navigable waterway. However, by statute those regulations cannot 

apply to onshore crude oil hazardous liquid gathering lines that are: (1) 6 inches 

or less in nominal diameter, (2) operated at low pressure, and (3) located in a rural 

area which is not unusually sensitive to environmental damage.3

Consistent with that statutory exclusion, the Federal pipeline safety regulations 

only apply to certain ‘‘regulated rural gathering lines.’’ Those lines are onshore gathering lines in rural areas that (1) have a nominal diameter of between 65⁄8 inches 

and 85⁄8 inches; (2) are located within 1⁄4 mile of an unusually sensitive areas; and 

(3) operate at a stress level greater than 20 percent of specified minimum yield 

strength (SMYS). 

Offshore hazardous liquid gathering lines on the OCS are either regulated by the 

Department of the Interior (producer-operated lines) or PHMSA (transporter-operated lines). Offshore hazardous liquid gathering lines in state waters are reserved 

for regulation by the states as a matter of policy. 

Gas Gathering Lines: PHMSA regulates most gas gathering lines. Congress authorized Federal regulation of gas gathering lines based largely on the physical and 

functional characteristics of those lines, including their location, distance from the 

wellhead, operating pressure, throughput, and composition of the transported gas. 

Consistent with those requirements, the Federal pipeline safety regulations do not 

apply to the onshore gathering of gas: (1) through a pipeline that operates by gravity, (2) through a pipeline that does not meet the definition of a ‘‘regulated onshore 

gathering line,’’ and (3) within the inlets of the Gulf of Mexico, except for certain 

underwater inspection and reburial requirements. 

There are two categories of ‘‘regulated onshore gathering lines’’ for purposes of the 

Federal pipeline safety regulations. The first are Type A regulated onshore gathering lines, i.e., metallic lines whose maximum allowable operating pressure 

(MAOP) is 20 percent or more of specified minimum yield strength (SMYS) and nonmetallic lines with an MAOP of more than 125 psig that are in a Class 2, Class 

3, or Class 4 location. The second are Type B gathering lines, i.e., metallic lines 

whose MAOP is less than 20 percent of SMYS and nonmetallic lines with an MAOP 

of 125 psig or less, which are in a Class 2 location (as determined under one of three 

formulas) or in a Class 3 or 4 location. These two categories of gathering lines are 

subject to different requirements as specified further in the pipeline safety regulations. Onshore gas gathering lines in Class 1 locations are not subject to the requirements for ‘‘regulated onshore gas gathering lines.’’ 

Offshore gas gathering lines on the OCS are either regulated by the Department 

of the Interior (producer-operated) or PHMSA (transporter-operated). 

Offshore gas gathering lines in state waters are reserved for regulation by the 

states as a matter of policy. 

Further Regulation: PHMSA believes that the production and gathering of hazardous liquids and gas by pipeline should be subject to effective safety regulations. 

The agency has sought to achieve that objective in a manner consistent with the 

pipeline safety laws and is currently reviewing whether additional or more stringent 

regulation of these activities is appropriate. However, PHMSA cannot regulate a 

pipeline that is excluded from the scope of its authority by statute, and the agency 

is willing to work Congress in determining whether any of these restrictions should 

be repealed or modified. 

Question 2. At the recent pipeline safety hearing before the House Transportation 

and Infrastructure Committee, you mentioned that oil pipelines must have an oil 

spill response program, but that there is no similar requirement for natural gas 

pipelines. What other significant differences exist between oil and gas pipeline regulations? 

96 

Answer. PHMSA is currently completing a comprehensive assessment of the differences between the regulations for gas and oil pipelines, and evaluating whether 

any of these differences suggest significant opportunities to improve current regulations. 

While this study has not been completed, early results suggest that major differences in the regulations are a result of differences in the properties of the materials being transported. For example, natural gas is lighter than air and therefore 

disperses in the atmosphere following release from a pipeline, alleviating the need 

for a ‘‘spill response plan’’ in addition to the required emergency response plan. 

Other differences (not all of which are significant) between oil and gas regulations 

that PHMSA is examining include: 

• Numerous differences in integrity management program regulations. Most derive from differences in the properties of the materials being transported (e.g., 

the definition of High Consequence Area), though some do not (e.g., differences 

in the required timeframe for remediation of defects identified by required assessments). For integrity management inspections, the maximum time interval 

allowed between pipeline segment inspections is 5 years for hazardous liquid 

pipelines and 7 years for gas pipelines. 

• Gas pipeline pressure design factors are based on Class Location, while liquid 

pipeline design factors are based on physical location: onshore vs. navigable waterways and offshore platform. 

• Differences in corrosion control requirements. 

• Differences in hydrotest requirements for oil and gas pipelines. 

• Gas regulations address threaded fittings, and liquid regulations do not. 

• Differences in the regulations for shut-off valves. 

• For burial of pipeline, the liquid regulations lack backfill requirements. 

Question 3. Can you explain for the Committee where your agency’s jurisdiction 

begins and where it ends? 

Answer. Congress has given PHMSA jurisdiction over hazardous liquid and gas 

pipeline systems. That jurisdiction includes authority over gas and liquid transmission pipelines, certain gas and liquid gathering lines, gas distribution pipeline 

systems, and liquefied natural gas (LNG) facilities. PHMSA does not have jurisdiction over gas or liquid production pipeline systems or hazardous liquid refining or 

manufacturing facilities and any storage or in-plant pipeline associated with these 

facilities. 

Congress has directed PHMSA to delegate its authority to regulate certain pipelines to State agencies that are interested and qualified to assume that responsibility. A part of the delegated responsibility is to assure state regulations are at 

least as stringent as Federal regulations. 

PHMSA has jurisdiction over onshore pipeline systems as well as certain parts 

of offshore systems. Other jurisdictional agencies sharing offshore authority include 

DOI, the Coast Guard, and states with ocean or gulf borders. PHMSA has developed 

Memoranda of Understanding (MOU) with individual agencies to clarify offshore responsibilities. Under a 1996 MOU with DOI, DOI inspects the structural integrity 

of offshore platforms. 

Question 4. In addition to safety concerns, we must also ensure the security of 

our Nation’s pipelines. Please tell the Committee how PHMSA coordinates with TSA 

in regards to pipeline security. 

Answer. PHMSA and DHS have agreed that TSA is the lead agency in pipeline 

security. PHMSA supports TSA by providing technical expertise and access to existing intergovernmental relationships, such as PHMSA’s State pipeline safety partner 

agencies. PHMSA communicates frequently with its counterparts at the TSA Transportation Sector Network Management’s Pipeline Security Division (PSD) concerning pipeline incidents, threats to pipelines, and suspicious activities at pipeline 

and energy facilities. PHMSA Inspectors have participated in TSA Pipeline Corporate Security Reviews and Critical Facility Inspections and in DHS’ sponsored Security Reviews of Liquefied Natural Gas facilities. PHMSA and TSA have cooperated on numerous projects including revision of pipeline security guidelines, and 

more recently, development of Security Incident Protocols that extend to the Department of Justice, Department of the Interior, and Department of Energy. We meet 

regularly in accordance with an action plan developed in 2006 and are actively 

working on our joint participation in Sector Coordinating Councils and Government 

Coordinating Councils in support of the National Infrastructure Protection Plan. 

97 

RESPONSE TO WRITTEN QUESTIONS SUBMITTED BY HON. MIKE JOHANNS TO

HON. CYNTHIA L. QUARTERMAN

Question 1. How has your agency been involved with the development of the Environmental Impact Statement (EIS) applicable to the Keystone XL pipeline project? 

Answer. PHMSA is acting as a cooperating agency during the development of the 

EIS. Through that role PHMSA has: 

• Reviewed and provided comments to the State Department’s pre-draft EIS. 

Comments from PHMSA were primarily in the area of pipeline safety, including 

description of the special permit request and examples of draft conditions that 

could be imposed if the special permit request were granted. 

• Shared Supplemental Information received from the operator with the State Department. 

• Attended State Department Public Meetings following issuance of the Draft 

EIS. For those meetings with a Q&A format, PHMSA helped respond to questions related to pipeline safety. 

• Provided additional information to the State Department as needed via e-mail, 

phone calls, and in-person meetings. 

Question 2. Is the State Department required to involve you? 

Answer. Yes. Executive Order 13337 of April 30, 2004, requires the State Department to refer any application for a Presidential permit for a cross-border oil pipeline 

to the Secretary of Transportation. The Executive Order also requires the Secretary 

of State to send pertinent information to the Secretary of Transportation and to request the Secretary’s views. Typically such communications are referred to PHMSA. 

Question 3. To your knowledge, were state pipeline safety inspection authorities 

involved in the Keystone XL EIS? If so, how? 

Answer. Under Executive Order 13337, the Secretary of State may consult with 

such State, tribal, and local government officials and foreign governments as she 

deems appropriate. PHMSA is unaware of whether state pipeline safety inspection 

authorities were involved. It is PHMSA’s understanding that the operator was required to file a separate application with the South Dakota Public Utilities Commission for a permit under the South Dakota Energy Conversion and Transmission Facility Act and received approval on March 11, 2010. Two of the States along the currently proposed route, Oklahoma and Texas, have authority to regulate, inspect, and 

enforce liquid pipeline safety requirements over intrastate liquid pipelines through 

certification by PHMSA’s Office of Pipeline Safety. In Montana, South Dakota, Nebraska, and Kansas, PHMSA regulates, inspects, and enforces intrastate liquid pipeline safety requirements. PHMSA has the authority to inspect, regulate and enforce 

interstate liquid pipelines such as Keystone XL in all states. 

Question 4. The State Department’s EIS for the Keystone XL project lists the Department of Transportation’s Office of Pipeline Safety as an ‘‘Assisting Agency,’’ and 

not as a ‘‘Cooperating Agency.’’ What does that distinction mean in terms of how 

the Department of State completes its work on the EIS, and what does that distinction mean for your involvement in the project? What activities did your office undertake, if any, that would have differed had you been listed as a ‘‘cooperating agency’’? 

Answer. PHMSA is actually a cooperating agency on Keystone XL and has been 

working with the Department of State to address the project’s pipeline safety issues. 

The role of a cooperating agency, as established by the National Environmental Policy Act (NEPA) of 1969, is to engage its staff, skills, and resources to help the lead 

agency with environmental analysis, including any portions of the environmental 

impact statement concerning which the cooperating agency has special expertise. 

PHMSA has cooperated on those analyses for which it has jurisdiction or special expertise with respect to the Keystone pipeline project. 

RESPONSE TO WRITTEN QUESTIONS SUBMITTED BY HON. MARK PRYOR TO

HON. DEBORAH A.P. HERSMAN

Question 1. What are the most important NTSB recommendations currently 

unaddressed? 

Answer. Installation of excess flow valves (EFV) in natural gas distribution pipeline systems has been a recommendation of the Board for nearly 10 years (P–01– 

2). EFVs are installed in service lines and mitigate gas leaks from the service line 

by detecting an abnormally high flow rate. When an excess flow is detected, an EFV 

automatically closes a valve, thus shutting off the flow of gas from the distribution 

line to the service line. 

98 

Pipeline Hazardous Material Safety Administration’s (PHMSA) current mandate 

requires excess flow valves on new or replacement service lines to single family residences only. The NTSB recommends that PHMSA require that excess flow valves 

be installed in all new and renewed gas service lines, regardless of a customer’s 

classification, when the operating conditions are compatible with readily available 

valves. 

The NTSB believes that apartment buildings, other multifamily dwellings, and 

commercial properties are susceptible to the same risks from leaking gas lines as 

single-family residences, and we believe this gap in the law and the regulations 

should be eliminated. 

While the NTSB has not issued recommendations specifically addressing either 

the effective oversight of risk-based assessments in pipeline safety regulation or the 

regulation of low-stress pipelines, these two areas are critical to safeguarding the 

integrity of our Nation’s pipeline systems. 

Effective Oversight 

Over the past decade or more, PHMSA has used a risk-based assessment for regulating the DOT pipeline safety program. PHMSA has successfully built a partnership with various facets of the pipeline industry to develop, implement and execute 

a multi-part pipeline safety program. In the NTSB’s view, all stakeholders, including PHMSA, have come to rely heavily upon this approach. The NTSB believes a 

risk-based approach can work if effective oversight is exercised by PHMSA and the 

pipeline operators. 

The Safety Board also believes that with the risk-based assessment come increased responsibilities for both the individual pipeline operators and PHMSA. Operators must diligently and objectively scrutinize the effectiveness of their programs, 

identify areas for improvement, and implement corrective measures. PHMSA, as the 

regulator, must also do the same in its audits of the operators’ programs and in selfassessments of its own programs. In short, both operator and regulator need to 

verify whether risk-based assessments are being executed as planned, and more importantly, whether these programs are effective. Unfortunately, NTSB has investigated several accidents in which ineffective oversight contributed to the pipeline 

accident. 

Low-Stress Pipelines Regulation Equality 

At the time the PIPES Act was enacted, Federal pipeline safety regulations only 

applied to low-stress pipelines that were located in populated areas, crossed navigable waterways, or carried highly volatile liquids, such as compressed liquefied propane. In a final rulemaking, ‘‘Pipeline Safety: Protecting Unusually Sensitive Areas 

from Rural Onshore Hazardous Liquid Gathering Lines and Low-Stress Lines,’’ published on June 3, 2008, PHMSA issued regulations for rural onshore low-stress pipelines that have a diameter of at least 85⁄8 inches and that are within 1⁄2 mile of an 

area defined as unusually sensitive. Low-stress pipelines meeting these criteria will 

be required to meet 49 CFR Part 195, for hazardous liquid pipelines in its entirety 

by July 2012. 

The final rule also included regulations for rural onshore gathering lines that operate at stress levels greater than 20 percent of the pipe strength, have a diameter 

between 65⁄8 and 85⁄8 inches and are within 1⁄4 mile of an area defined as unusually 

sensitive. (A ‘‘gathering line’’ is defined as a pipeline with a diameter of 85⁄8 inches 

or less that transports petroleum from a production facility.) Under the final rule, 

rural onshore gathering lines will be required to meet Part 195 in part by July 

2011. The safety requirements of Part 195 that will eventually apply to the rural 

onshore gathering lines include annual and accident reporting requirements, establishment of maximum operating pressure, installation of line markers, public education programs, damage prevention programs, corrosion control, and operator qualification programs. 

On June 22, 2010, PHMSA published a follow-up Notice of Proposed Rulemaking 

(NPRM) addressing the regulation of all rural onshore hazardous liquid low-stress 

pipelines. This NPRM represents phase two of PHMSA’s implementation of its mandate in the PIPES Act. In this NPRM, PHMSA proposes safety requirements for all 

rural low-stress pipelines not included under the phase one final rule. This latest 

NPRM does not include any new proposed requirements for onshore rural gathering 

lines. 

The low-stress pipelines captured under the new NPRM include: (1) rural lowstress pipelines of a diameter less than 85⁄8 inches located in or within one-half mile 

of an unusually sensitive area and (2) all other rural low-stress pipelines that were 

not included under phase one. PHMSA estimates that the NPRM will apply to 1,384 

miles of low-stress pipelines not covered by the previous rule. However, the NPRM 

99 

does not broaden the regulation of rural on-shore gathering lines. The NTSB believes that the key to the success of these regulations will be effective oversight exercised by the pipeline operators and PHMSA. 

Question 2. What should Congress do to improve pipeline safety? 

Answer. Over the past decade or more, PHMSA has used a risk-based assessment 

for regulating pipeline safety. The pipeline safety regulations provide the structure, 

content, and scope for many aspects of the overall pipeline safety program. Within 

this regulatory framework, pipeline operators have the flexibility and responsibility 

to develop their individual programs and plans, determine the specific performance 

standards, implement their plans and programs, and conduct periodic self-evaluations that best fit their particular pipeline systems. PHMSA likewise has the responsibility to review pipeline operators’ plans and programs for regulatory compliance and effectiveness. 

The NTSB believes that with the risk-based assessment approach come important 

responsibilities for both the individual pipeline operators and PHMSA. The operator 

and regulator need to verify whether risk-based assessments are being executed as 

planned, and more importantly, whether these programs are effective. Unfortunately, there have been some recent pipeline investigations in which the NTSB discovered that PHMSA and operator oversight of risk-based assessment programs, 

specifically integrity management programs and public education efforts, have been 

lacking and have failed to detect flaws and weaknesses in such programs. 

NTSB is concerned that the level of self-evaluation and oversight currently being 

exercised is not uniformly applied by some pipeline operators and PHMSA to ensure 

that the risk-based safety programs are effective. The NTSB believes that PHMSA 

must establish an aggressive oversight program that thoroughly examines each operator’s decision-making process for each element of its integrity management program. 

Congress can ensure that PHMSA has the needed funding and resources to implement an aggressive oversight program, and require that PHMSA provide periodic 

analyses of its oversight program. 

Question 2a. Should PHMSA have more authority to regulate offshore pipelines? 

Answer. The NTSB believes that PHMSA should have more authority to regulate 

all types and categories of offshore pipelines. The regulation of offshore pipeline systems has not been addressed in recent legislation or regulatory action. Jurisdiction 

over offshore pipelines of all types is complex and currently involves coastal states, 

PHMSA, and the Department of the Interior. The jurisdictional responsibilities are 

based on the location and function of a pipeline (e.g., production versus transportation) rather than on the threat to public safety and the environment from the petroleum and/or natural gas transported. These jurisdictional complexities can easily 

lead to gaps in the regulations and inconsistencies in pipeline safety standards, 

which could be minimized if a more seamless approach to regulating offshore pipelines is taken by giving PHMSA sole jurisdiction over all pipeline systems located 

wholly or partially on the Outer Continental Shelf. 

Currently, PHMSA has the most expertise at the Federal level on pipeline safety 

issues, and would be best suited to work with existing stakeholders to develop and 

implement a simplified and more consistent regulatory program for offshore pipelines. PHMSA would also need the resources to assume such expanded responsibilities. 

The tragedy in the Gulf of Mexico involving the Deepwater Horizon drilling platform is a grim reminder of the damage that a major oil spill can cause. While the 

magnitude of the Deepwater Horizon spill is far greater than any known pipeline 

failure, the events in the Gulf should remind those involved in the pipeline industry 

that all pipelines, offshore and onshore, must be sufficiently safeguarded and regulated in order to protect the public and the environment. 

Question 2b. What would be NTSB’s role in responding to a major pipeline failure 

caused by a natural disaster, manmade disaster, or terrorist attack? 

Answer. Under the NTSB’s operating statute (49 U.S.C. 1131), the NTSB is required to investigate or have investigated a pipeline accident in which there is a 

fatality or substantial property damage, or significant injury to the environment. 

The NTSB can also investigate any accident that the Board decides is catastrophic 

or involves problems of a recurring nature. 

Major catastrophic pipeline failures caused by natural disasters do not occur 

often, but can and have been investigated by the NTSB. In September 1996 the 

NTSB adopted a Pipeline Special Investigation Report—Evaluation of Pipeline Failures during Flooding and of Spill Response Actions, San Jacinto River near Houston, Texas, October 1994, excerpts of which are attached for your reference. The 

NTSB report addressed: (1) the adequacy of Federal and industry standards on deVerDate Nov 24 2008 07:17 Jul 12, 2011 Jkt 067270 PO 00000 Frm 00103 Fmt 6601 Sfmt 6621 S:\GPO\DOCS\67270.TXT SCOM1 PsN: JACKIE
100 

signing pipelines in flood plains, (2) the preparedness of pipeline operators to respond to threats to their pipelines from flooding and to minimize the potential for 

product releases, and (3) the preparedness of the Nation to minimize the consequences of petroleum releases. More often, however, acts of nature, such as the 

washouts of creek and river beds, floods, frost heaves, or lightning strikes, cause 

less than catastrophic incidents. Most NTSB pipeline investigations involve failures 

of designs, materials, operations, maintenance, human error and other factors that 

could be identified as manmade disasters, or attributed to some form of human 

interaction. 

NTSB has established multi-tiered evaluation criteria that can be applied for any 

pipeline accident in order to determine whether an NTSB response is needed, and 

the level of response to be provided. The criteria are based on the danger to the 

public (fatalities and injuries, evacuations, etc.), property damage, and environmental damage. 

According to 49 U.S.C. 1131, the NTSB’s investigation has priority over any other 

investigation by another department, agency, or instrumentality of the Federal Government with a key exception. The NTSB must relinquish its investigative priority 

to the Federal Bureau of Investigation if the Attorney General, in consultation with 

the Chairman of the NTSB, determines that circumstances indicate that the accident may have been caused by a criminal act. The NTSB may provide technical support to the FBI, while continuing its investigation of safety issues resulting from the 

accident. 

EVALUATION OF PIPELINE FAILURES DURING FLOODING AND OF SPILL RESPONSE

ACTIONS, SAN JACINTO RIVER NEAR HOUSTON, TEXAS, OCTOBER 1994 

Pipeline Special Investigation Report—Adopted: September 6, 1996—Notation 6734 

NATIONAL TRANSPORTATION SAFETY BOARD

Washington, DC 

Executive Summary 

Between October 14 and October 21, 1994, some 15 to 20 inches of rain fell on 

the San Jacinto River flood plain near Houston, Texas, resulting in dangerous flooding that far surpassed past flooding experience in the region. The floods forced over 

14,000 people to evacuate their homes and resulted in 20 deaths. 

Due to the flooding, 8 pipelines ruptured and 29 others were undermined both at 

river crossings and new channels created in the flood plain. More than 35,000 barrels (1.47 million gallons) of petroleum and petroleum products were released into 

the river. Ignition of the released products within flooded residential areas resulted 

in 547 people receiving (mostly minor) burn and inhalation injuries. The spill response costs were in excess of $7 million and estimated property damage losses were 

about $16 million. 

With respect to this accident, the Safety Board undertook a special investigation 

that focused on the following safety issues: (1) the adequacy of Federal and industry 

standards on designing pipelines in flood plains, (2) the preparedness of pipeline operators to respond to threats to their pipelines from flooding and to minimize the 

potential for product releases, and (3) the preparedness of the Nation to minimize 

the consequences of petroleum releases. The report also addresses the need for effective operational monitoring of pipelines and for the use of remote- or automatic-operated valves to allow for prompt detection of product releases and rapid shutdown 

of failed pipe segments. 

As a result of its investigation, the Safety Board makes nine safety recommendations: one to the Research and Special Programs Administration, five to the National Response Team, and one each to the American Petroleum Institute, the Association of Oil Pipe Lines, and the Interstate Natural Gas Association of America. 

Introduction 

Serious flooding in the San Jacinto River flood plain near Houston, Texas, in October 1994 caused 8 pipelines to rupture and 29 others to be undermined both at 

river crossings and new channels created in the flood plain. 

The high number of pipelines ruptured and damaged during this incident, and the 

magnitude of the petroleum releases and spill response efforts emphasized the 

threats posed to public safety and the environment by petroleum transportation by 

pipeline. Although pipeline transportation is one of the safest .means for transporting petroleum, it poses great risk potential to the environment because of the 

large volumes of hazardous liquids that can be released when a rupture occurs. 

101 

In a pipeline transport situation, as opposed to other transport options, there is 

greater likelihood of releasing petroleum into environmentally sensitive areas. Concerns about the environmental consequences of releases from pipelines have been 

expressed by the Congress, the States, and local interests. 

Because so many pipelines were damaged during this flood and such large volumes of petroleum and petroleum products were released—requiring a massive environmental response in terms of personnel and equipment—the Safety Board undertook this special investigation to assess the adequacy of Federal and industry standards on designing pipelines in flood plains, the preparedness of pipeline operators 

to respond to threats to their pipelines from flooding and to minimize the potential 

for product releases, and the preparedness of the Nation to minimize the consequences of petroleum releases. 

In the course of the investigation, the Safety Board also discovered evidence reinforcing the need for effective operational monitoring of pipelines and for the use of 

remote- or automatic-operated valves to allow for prompt detection of product releases and rapid shutdown of failed pipe segments. 

Conclusions 

1. The design bases of most pipelines undermined or ruptured during the flood 

did not include study of the flood plain to identify potential threats; rather, operators used only general design criteria applicable at the time the pipelines were installed. 

2. Standards for designing pipelines across flood plains are needed to define the 

multiple threats posed to pipelines and to address the research, study, and future 

considerations that must be used for designing pipelines and periodically reevaluating the integrity of their designs during their operating life. 

3. Most operators of pipelines crossing the San Jacinto River flood plain continued 

operations without evaluating the capability of the pipeline design to withstand the 

threats presented by the flood. 

4. Few pipeline operators took effective response actions during the San Jacinto 

flood to minimize the potential for product releases. 

5. Pipeline operators would have been more likely to have implemented early 

shutdown and/or purging of products from pipe segments crossing the San Jacinto 

flood plain had the Research and Special Programs Administration required them 

to develop plans for responding to substantial threats of a pipeline failure and product discharge. 

6. The response by local, State, and Federal Government agencies to the flood 

emergency was well-managed and effective. 

7. Failed liquid pipelines continue to release excessive volumes of petroleum and 

liquid products into the environment because the Research and Special Programs 

Administration has not established requirements for rapid detection and shutdown 

of failed pipe segments, and the liquid pipeline industry has not incorporated means 

for rapidly detecting, locating, and shutting down failed pipe segments. 

8. Risks to workers and the public were increased significantly when the unified 

command conducted an in-situ bum without having in place appropriate checks and 

balances to ensure that approved procedures and requirements were followed explicitly. 

9. Spill management personnel responding from other regions of the country and 

trained on different incident command procedures created communications, command, and control difficulties because they were not familiar with the incident command structure and procedures in use in the Galveston Bay area. 

10. Implementation of the unified incident command structure and operational 

principles in the National Response Team’s Technical Assistance Document Incident 

Command System/Unified Command will enhance the overall preparedness for responding to petroleum spills. 

11. Some lessons on improving the area’s spill response preparedness were not 

learned primarily because a comprehensive after-action critique was not conducted. 

Recommendations 

As a result of its investigation, the National Transportation Safety Board makes 

the following recommendations: 

—to the Research and Special Programs Administration: 

Require operators of liquid pipelines to address, in their Oil Pollution Act of 1990 

spill response plans, identifying and responding to events that can pose a substantial threat of a worst-case product release. (Class II, Priority Action) (P–96–21) 

—to the National Response Team: 

102 

Make your membership aware of the circumstances and nature of the events in 

the October 1994 environmental response at Houston, Texas, specifically in regard 

to the need for coordinating all planning and operational activities prior to conducting in-situ burn countermeasures. (Class II, Priority Action) (I–96–1) 

Motivate National Response Team agencies to integrate into their area contingency plans the command and control principles contained in Technical Assistance 

Document Incident Command System/Unified Command and encourage them to 

train all personnel assigned management responsibilities in those principles. (Class 

II, Priority Action) (I–96–2) 

Include procedures for implementing your Unified Command/Incident Command 

System that will ensure that all safety-critical operations are coordinated with parties at risk. (Class II, Priority Action) (I–96–3) 

Establish guidance calling for Federal On-Scene Coordinators to conduct a comprehensive after-action critique of each spill response to incorporate the observations of all participating agencies to identify improvements needed in equipment, 

communications procedures, guidance, techniques, and management. (Class II, Priority Action) (I–96–4) 

Request that Federal On-Scene Coordinators document and forward to National 

Response Team headquarters all ‘‘lessons learned’’ developed from after-action critiques for review and implementation nationwide as appropriate. (Class II, Priority 

Action) (I–96–5) 

—to the American Petroleum Institute: 

Take the lead to develop, in cooperation with the Association of Oil Pipe Lines 

and the Interstate Natural Gas Association of America, design and construction 

standards adequate for pipelines to safely cross flood plains and streambeds, including the development of recommended practices for periodically reassessing crossing 

designs in light of changes that have occurred in the flood plain or streambed. 

(Class II, Priority Action) (P–96–22) 

—to the Association of Oil Pipe Lines: 

Develop, in cooperation with the American Petroleum Institute and the Interstate 

Natural Gas Association of America, design and construction standards adequate for 

pipelines to safely cross flood plains and streambeds, including the development of 

recommended practices for periodically reassessing crossing designs in light of 

changes that have occurred in the flood plain or streambed. (Class II, Priority Action) (P–96–23) 

—to the Interstate Natural Gas Association of America: 

Develop, in cooperation with the American Petroleum Institute and the Association of Oil Pipe Lines, design and construction standards adequate for pipelines to 

safely cross flood plains and streambeds, including the development of recommended 

practices for periodically reassessing crossing designs in light of changes that have 

occurred in the flood plain or streambed. (Class II, Priority Action) (P–96–24) 

By the National Transportation Safety Board 

JAMES E. HALL, 

Chairman. 

ROBERT T. FRANCIS II, 

Vice Chairman. 

JOHN A. HAMMERSCHMIDT, 

Member. 

JOHN J. GOGLIA, 

Member. 

GEORGE W. BLACK, JR., 

Member. 

September 6, 1996 

§ 1131. General authority 

(a) General.—— 

(1) The National Transportation Safety Board shall investigate or have investigated (in detail the Board prescribes) and establish the facts, circumstances, and 

cause or probable cause of—— 

(A) an aircraft accident the Board has authority to investigate under section 

1132 of this title or an aircraft accident involving a public aircraft as defined 

by section 40102(a)(37) of this title other than an aircraft operated by the 

Armed Forces or by an intelligence agency of the United States; 

103 

(B) a highway accident, including a railroad grade crossing accident, the Board 

selects in cooperation with a State; 

(C) a railroad accident in which there is a fatality or substantial property damage, or that involves a passenger train; 

(D) a pipeline accident in which there is a fatality, substantial property damage, 

or significant injury to the environment; 

(E) a major marine casualty (except a casualty involving only public vessels) occurring on the navigable waters or territorial sea of the United States, or involving a vessel of the United States, under regulations prescribed jointly by the 

Board and the head of the department in which the Coast Guard is operating; 

and 

(F) any other accident related to the transportation of individuals or property 

when the Board decides—— 

(i) the accident is catastrophic; 

(ii) the accident involves problems of a recurring character; or 

(iii) the investigation of the accident would carry out this chapter. 

(2)(A) Subject to the requirements of this paragraph, an investigation by the 

Board under paragraph (1)(A)–(D) or (F) of this subsection has priority over any investigation by another department, agency, or instrumentality of the U.S. Government. The Board shall provide for appropriate participation by other departments, 

agencies, or instrumentalities in the investigation. However, those departments, 

agencies, or instrumentalities may not participate in the decision of the Board about 

the probable cause of the accident. 

(B) If the Attorney General, in consultation with the Chairman of the Board, 

determines and notifies the Board that circumstances reasonably indicate that 

the accident may have been caused by an intentional criminal act, the Board 

shall relinquish investigative priority to the Federal Bureau of Investigation. 

The relinquishment of investigative priority by the Board shall not otherwise 

affect the authority of the Board to continue its investigation under this section. 

(C) If a Federal law enforcement agency suspects and notifies the Board that 

an accident being investigated by the Board under subparagraph (A), (B), (C), 

or (D) of paragraph (1) may have been caused by an intentional criminal act, 

the Board, in consultation with the law enforcement agency, shall take necessary actions to ensure that evidence of the criminal act is preserved. 

(3) This section and sections 1113, 1116(b), 1133, and 1134(a) and (c)–(e) of this 

title do not affect the authority of another department, agency, or instrumentality 

of the Government to investigate an accident under applicable law or to obtain information directly from the parties involved in, and witnesses to, the accident. The 

Board and other departments, agencies, and instrumentalities shall ensure that appropriate information developed about the accident is exchanged in a timely manner. 

(b) Accidents Involving Public Vessels.—— 

(1) The Board or the head of the department in which the Coast Guard is operating shall investigate and establish the facts, circumstances, and cause or probable 

cause of a marine accident involving a public vessel and any other vessel. The results of the investigation shall be made available to the public. 

(2) Paragraph (1) of this subsection and subsection (a)(1)(E) of this section do not 

affect the responsibility, under another law of the United States, of the head of the 

department in which the Coast Guard is operating. 

(e) Accidents Not Involving Government Misfeasance or Nonfeasance.—— 

(1) When asked by the Board, the Secretary of Transportation may—— 

(A) investigate an accident described under subsection (a) or (b) of this section 

in which misfeasance or nonfeasance by the Government has not been alleged; 

and 

(B) report the facts and circumstances of the accident to the Board. 

(2) The Board shall use the report in establishing cause or probable cause of an 

accident described under subsection (a) or (b) of this section. 

(d) Accidents Involving Public Aircraft.—The Board, in furtherance of its investigative duties with respect to public aircraft accidents under subsection (a)(1)(A) of 

this section, shall have the same duties and powers as are specified for civil aircraft 

accidents under sections 1132(a), 1132(b), and 1134(a), (b), (d), and (f) of this title. 

104 

RESPONSE TO WRITTEN QUESTION SUBMITTED BY HON. KAY BAILEY HUTCHISON TO

HON. DEBORAH A.P. HERSMAN

Question. What recommendations do you have for the Committee with respect to 

reauthorizing the pipeline safety program? 

Answer. NTSB concerns can be grouped into three general areas: excess flow 

valves (EFVs), safety oversight, and low-stress pipeline regulation equality. NTSB 

has recommended the use of EFVs in gas distribution pipeline systems for many 

years. While the NTSB has not issued recommendations specifically addressing either the effective oversight of risk-based assessments in pipeline safety regulation 

or the regulation of low-stress pipelines, these two areas are critical to safeguarding 

the integrity of our Nation’s pipeline systems. 

Apply Excess Flow Valves (EFVs) Equally 

EFVs are installed in natural gas service lines where they connect to the distribution line. EFVs are designed to mitigate gas leaks from the service line by detecting 

an abnormally high flow rate. When an excess flow is detected, an EFV automatically closes, thus shutting off the flow of gas from the distribution line to the service 

line. 

The Pipeline and Hazardous Material Safety Administration’s (PHMSA) current 

mandate under the PIPES Act requires excess flow valves only on new or replacement service lines to single family residences. The NTS13 recommended nearly 10 

years ago (P–01–2) that PHMSA require that excess flow valves be installed in all 

new and replacement gas service lines, regardless of a customer’s classification, 

when the operating conditions are compatible with readily available valves. 

The NTSB believes that apartment buildings, other multifamily dwellings, and 

commercial properties are susceptible to the same risks from leaking gas lines as 

single-family residences, and we believe this gap in the law and the regulations 

should be eliminated. 

Effective Safety Oversight 

Over the past decade or more, PHMSA has used a risk-based assessment for regulating the DOT pipeline safety program. PHMSA has successfully built a partnership with various facets of the pipeline industry to develop, implement and execute 

a multi-part pipeline safety program. In the NTSB’s view, all stakeholders, including PHMSA, have come to rely heavily upon this approach. The NTSB believes a 

risk-based approach can work if effective oversight is exercised by PHMSA and the 

pipeline operators. 

The NTSB also believes that with the risk-based assessment come increased responsibilities for both the individual pipeline operators and PHMSA. Operators 

must diligently and objectively scrutinize the effectiveness of their programs, identify areas for improvement, and implement corrective measures. PHMSA, as the 

regulator, must also do the same in its audits of the operators’ programs and in selfassessments of its own programs. In short, both operator and regulator need to 

verify whether risk-based assessments are being executed as planned, and more importantly, whether these programs are effective. Unfortunately, there have been 

some recent pipeline investigations in which the NTSB discovered indications that 

PHMSA and operator oversight of risk-based assessment programs, specifically integrity management programs and public education programs, has been lacking and 

has failed to detect flaws and weaknesses in such programs. 

Low-Stress Pipelines Regulation Equality 

At the time the PIPES Act was enacted, Federal pipeline safety regulations only 

applied to low-stress pipelines that were located in populated areas, crossed navigable waterways, or carried highly volatile liquids, such as compressed liquefied propane. In a final rulemaking, ‘‘Pipeline Safety: Protecting Unusually Sensitive Areas 

from Rural Onshore Hazardous Liquid Gathering Lines and Low-Stress Lines,’’ published on June 3, 2008, PHMSA issued regulations for rural onshore low-stress pipelines that have a diameter of at least 85⁄8 inches and that are within 1⁄2 mile of an 

area defined as unusually sensitive. Low-stress pipelines meeting these criteria will 

be required to meet 49 CFR Part 195, for hazardous liquid pipelines in its entirety 

by July 2012. 

The final rule also included provisions for rural onshore gathering lines that operate at stress levels greater than 20 percent of the pipe strength, have a diameter 

between 65⁄8 and 85⁄8 inches and are within 1⁄4 mile of an area defined as unusually 

sensitive. (A ‘‘gathering line’’ is defined as a pipeline with a diameter of 85⁄8 inches 

or less that transports petroleum from a production facility.) Under the final rule, 

rural onshore gathering lines will be required to meet Part 195 in part by July 

2011. The safety requirements of Part 195 that will eventually apply to the rural 

105 

onshore gathering lines include annual and accident reporting requirements, establishment of maximum operating pressure, installation of line markers, public education programs, damage prevention programs, corrosion control, and operator qualification programs. 

On June 22, 2010, PHMSA published a follow-up Notice of Proposed Rulemaking 

(NPRM) addressing the regulation of all rural onshore hazardous liquid low-stress 

pipelines. This NPRM represents phase two of PHMSA’s implementation of its mandate in the PIPES Act. 

In this NPRM, PHMSA proposes safety requirements for all rural low-stress pipelines not included under the phase one final rule. This latest NPRM does not include any new proposed requirements for onshore rural gathering lines. 

The low-stress pipelines captured under the new NPRM include: (1) rural lowstress pipelines of a diameter less than 85⁄8 inches located in or within one-half mile 

of an unusually sensitive area and (2) all other rural low-stress pipelines that were 

not included under phase one. PHMSA estimates that the NPRM will apply to 1,384 

miles of low-stress pipelines not covered by the previous rule. However, the NPRM 

does not broaden the regulation of rural on-shore gathering lines. The NTSB believes that the key to the success of these regulations will be effective oversight exercised by the pipeline operators and PHMSA. 

The NTSB believes that PHMSA should have more authority to regulate all types 

and categories of offshore pipelines. The regulation of offshore pipeline systems has 

not been addressed in recent legislation or regulatory action. Jurisdiction over offshore pipelines of all types is complex and currently involves coastal states, 

PHMSA, and the Department of the Interior. The jurisdictional responsibilities are 

based on the location and function of a pipeline (e.g., production versus transportation) rather than on the threat to public safety and the environment from the petroleum and/or natural gas transported. These jurisdictional complexities can easily 

lead to gaps in the regulations and inconsistencies in pipeline safety standards, 

which could be minimized if a more seamless approach to regulating offshore pipelines is taken by giving PHMSA sole jurisdiction over all pipeline systems located 

wholly or partially on the Outer Continental Shelf. 

Currently, PHMSA has the most expertise at the Federal level on pipeline safety 

issues, and would be best suited to work with existing stakeholders to develop and 

implement a simplified and more consistent regulatory program for offshore pipelines. PHMSA would also need the resources to assume such expanded responsibilities. 

The tragedy in the Gulf of Mexico involving the Deepwater Horizon drilling platform is a grim reminder of the damage that a major oil spill can cause. While the 

magnitude of the Deepwater Horizon spill is far greater than any known pipeline 

failure, the events in the Gulf should remind those involved in the pipeline industry 

that all pipelines, offshore and onshore, must be sufficiently safeguarded and regulated in order to protect the public and the environment. 

RESPONSE TO WRITTEN QUESTIONS SUBMITTED BY HON. JOHN THUNE TO

HON. DEBORAH A.P. HERSMAN

Question 1. Today, ethanol and fuel blended with ethanol usually move by truck 

or rail due to technological challenges in moving these products by pipeline. Yet, the 

ability to move ethanol and other biofuels by rail would be safety and less expensive. What recommendations do you have for encouraging the development of ethanol pipelines? 

Answer. Ethanol or ethyl alcohol is a volatile flammable liquid with a significant 

flammability range (concentration in air of 3 percent to 19 percent) and poses a significant fire risk, but ethanol is not corrosive, particularly toxic, or a severe pollutant. (Pure ethanol is found in alcoholic beverages.) Today, ethanol is primarily used 

as a feedstock for the production of various chemical products and as an additive 

in gasoline. Ethanol used for such commercial purposes is denatured, meaning a 

substance is added to the ethanol to deter people from consuming it as an alcoholic 

beverage. 

The commercial demand for ethanol has dramatically risen in recent years because of its use in gasoline. Automotive gasoline containing ethanol is commonly 

transported by hazardous liquid pipelines. Although the NTSB is not aware of any 

existing pipelines dedicated to the transportation of ethanol, the NTSB does not see 

any properties of ethanol that would make it uniquely hazardous to transport by 

pipeline with existing regulations to safeguard people and the environment applied 

to these pipelines. 

106 

Biofuels would likewise be flammable. It is conceivable that a particular biofuel, 

depending on its source and composition, may potentially have corrosive or environmentally harmful properties that a pipeline operator would have to consider in light 

of current regulations. 

Question 2. You note in your written testimony that partnerships between the industry and PHMSA have led to a number of joint initiatives. What lessons can be 

learned from the cooperative relationship between PHMSA, the States, and the oil 

and gas industry that could be beneficial for other industries? 

Answer. Over the past decade or more, PHMSA has used a risk-based assessment 

for regulating pipeline safety. Within this regulatory framework, pipeline operators 

have the flexibility and responsibility to develop their individual programs and 

plans, determine the specific performance standards, implement their plans and 

programs, and conduct periodic self-evaluations that best fit their particular pipeline systems. PHMSA likewise has the responsibility to review pipeline operators’ 

plans and programs for regulatory compliance and effectiveness. 

The NTSB believes that with the risk-based assessment approach come important 

responsibilities for both the individual pipeline operators and PHMSA, and these 

programs can be effective when both parties are fulfilling their responsibilities. Unfortunately, there have been some recent pipeline investigations in which the NTSB 

discovered that PHMSA and operator oversight of risk-based assessment programs, 

specifically integrity management programs and public education efforts, have been 

lacking and have failed to detect flaws and weaknesses in such programs. 

Congress can ensure that PHMSA has the needed funding and resources to implement an aggressive oversight program, and require that PHMSA provide periodic 

analyses of its oversight program. 

RESPONSE TO WRITTEN QUESTIONS SUBMITTED BY HON. MARK PRYOR TO

ROCCO D’ALESSANDRO

Question 1. Do you oppose expanding integrity management inspections? 

Answer. AGA opposes expanding the high consequence area (HCA) definition in 

the Transmission Integrity Management Program (TIMP). Some reasons for not expanding the integrity management HCA definition are: (1) the risk-based integrity 

management inspection philosophy in the pipeline safety statute has proven to be 

effective and is still being implemented, (2) treating all pipeline segments as if they 

posed the same risks is not consistent with the risk-based engineering principles 

built into the pipeline safety Federal code of regulations, 49 CFR 192, and the (3) 

AGA believes there are potential unintended consequences in eliminating risk 

prioritization that could stretch operator safety resources and not allocate them to 

the most critical areas. 

Congress required DOT to establish criteria for operators to identify transmission 

pipelines in densely populated areas, conduct risk analyses, and adopt and implement integrity management programs. To accomplish these tasks, the DOT created 

the HCA concept, which went beyond densely populated areas and included places 

where people are known to congregate on a regular basis. (i.e., churches, playgrounds, recreational areas, etc.) The intent of establishing HCAs was for the natural gas industry to devote its resources toward protecting those areas which represent the greatest risk for the public. Operators were given 10 years to complete 

these assessments and begin reassessments. Baseline assessments will be complete 

by the December 2012 deadline. It should be noted that HCAs for hazardous liquid 

pipelines used a vastly different technical basis from gas transmission pipelines because of the properties transported. These HCAs include unusually sensitive drinking water and ecological resources, high population areas and other populated areas, 

and commercially navigable waterways. 

Some define risk management as the identification, assessment, and prioritization 

of risks followed by coordinated and economical application of resources to minimize, 

monitor, and control the probability and/or impact of unfortunate events. Pipeline 

safety regulations have incorporated risk management principles into regulation for 

decades. The regulations treat pipeline segments differently based upon various factors. Since 1970, natural gas transmission pipelines have used risk-based Class 1, 

2, 3 or 4 locations, which are based upon the concentration of buildings near pipeline corridors, for design, construction, operation and maintenance requirements. 

The transmission integrity management program HCA concept is an enhancement 

to existing risk-based pipeline safety regulations. 

Treating most or all pipeline segments with the assessment requirements applied 

in HCAs would dramatically increase the resources needed for safety without a commensurate improvement in safety. The expansion could have the unintended conVerDate Nov 24 2008 07:17 Jul 12, 2011 Jkt 067270 PO 00000 Frm 00110 Fmt 6601 Sfmt 6621 S:\GPO\DOCS\67270.TXT SCOM1 PsN: JACKIE
107 

sequence of adversely affecting safety if the focus on higher risk areas is diluted by 

a one-size-fits-all approach. 

Question 2. How often do most companies conduct internal integrity assessments? 

Answer. The Transmission Integrity Management Program (TIMP) regulation requires a specific type of integrity assessment every 7 years in HCAs, but operators 

conduct some type of safety assessment on all pipeline segments on a continual 

basis. 

The TIMP regulation requires operators to conduct a prescriptive integrity management assessment every 7 years (49 CFR 192 Subpart O). The integrity assessment interval recommended by the American Society of Mechanical Engineers, 

ASME B31.8S, Managing System Integrity of Gas Pipelines, consensus standard 

does not give a fixed interval for an integrity assessment. Instead it gives a range 

of years based upon historical technical national pipeline performance data and current data on the specific pipeline being analyzed. 

There are many safety assessment intervals built into the pipeline safety code 

separate from the TIMP assessments. For example, there is external corrosion control monitoring annually, leakage surveys from one to four times per year, and patrols from one to four times per year. Importantly, section 192.613 Continuing Surveillance, requires operators to 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. 

Question 3. In light of the recent BP spill and leak events, do you believe there 

is more that industry, Congress, or PHMSA should do to enhance pipeline safety? 

Answer. The BP spill and leak event is not related in any way to pipeline safety. 

Pipeline incidents are rare because of the extensive regulatory structure and operator commitment to safety. PHMSA requires operators to analyzing pipeline accidents and failures, for the purpose of determining the causes of the failure and 

minimizing the possibility of a recurrence. 

One area of pipeline safety that could be enhanced is excavation damage prevention. Although the nine elements in the 2006 PIPES Act were an important achievement for reducing pipeline damages, the greatest impact will actually occur when 

states open up their one-call laws and revise the language so that it adheres to the 

nine elements to create a robust and effective state damage prevention program. 

This may take several years due to the unique timing of state legislative sessions 

and the existence of special interest groups that have no desire in overhauling their 

state damage prevention laws. Still, a handful of states have recently made positive 

changes to their one-call law such as Utah, Indiana and Maryland. 

Many state one-call laws are antiquated and fail to effectively address difficult 

issues, such as enforcement of excavators who fail to follow the one-call process or 

fail to abide by safe digging practices. Without consistent and effective enforcement 

from a recognized authority at the state level, it is impossible to develop an effective 

damage prevention program. Most states either have no agency to enforce the damage prevention laws, or the agency simply does not have the funding to execute its 

responsibilities. Many states give enforcement authority to the attorney general and 

pipeline safety enforcement is neglected because of more pressing priorities by state 

justice departments. AGA is of the position that consistent and effective enforcement 

must be designed so it can hold all entities accountable for pipeline safety. 

Question 4. What do you believe should be the top priorities for PHMSA in light 

of the recent BP disaster? 

Answer. AGA cannot speak on behalf of PHMSA regarding priorities. However, 

over the last 7 months PHMSA has issues two major regulations that must be implemented—Distribution Integrity Management (DIMP) and Control Room Management (CRM). These were priorities set forth by Congress in the Pipeline Improvement, Protection, and Enforcement Act of 2006. The DIMP program requires operators to develop comprehensive integrity management plans that will identify risks 

and implement corrective actions for all piping an operators’ system. The plans will 

facilitate better regulatory oversight. The CRM regulation is a comprehensive control system rule which includes human factors, fatigue management and emergency 

response requirements. These are top priorities for AGA members. 

Question 5. Do you believe PHMSA currently provides enough oversight of our 

Nation’s oil and gas pipelines? 

Answer. Most AGA member companies are under the jurisdiction and oversight 

of state regulators. AGA believes there is sufficient Federal and state oversight of 

pipelines to ensure safety. 

108 

RESPONSE TO WRITTEN QUESTIONS SUBMITTED BY HON. MARK PRYOR TO

TIMOTHY C. FELT

Question 1. What do you believe should be the top priorities for PHMSA in light 

of the recent BP disaster? 

Answer. The liquid pipeline industry remains at a continued state of readiness to 

properly maintain and operate our systems. We are certainly aware of the increased 

focus that the Deepwater Horizon incident will place on our industry. On June 28, 

2010, PHMSA issued an Advisory Bulletin to all operators of liquid pipeline facilities required to develop and submit spill response plans under 49 CFR Part 194. 

The Advisory Bulletin requires all covered operators to review and update, as necessary, their spill response plans to calculate and envision worst-case scenario planning. Operators must examine available resources required to respond to worst-case 

scenarios, and conduct their review (including any updates) within 30 days. Operators were also asked to confirm that drills have been performed at the frequency 

specified in their plans and maintain on-going training with first responders. Pipeline operators already have significant obligations under current regulation to maintain up-to-date response plans that are specifically tailored for each site and also 

include frequent drills and training. We would request that as the Federal Government continues its important oversight work, in light of the Deepwater incident, 

that it provide clear and consistent compliance guidance to affected pipeline operators. 

We do believe there are some constructive steps PHMSA and the Office of Pipeline Safety (OPS) could make to remove gaps in pipeline safety regulation. First, 

PHMSA should encourage states to enhance their damage prevention laws or move 

quickly to improve damage prevention programs in the states that have weak or ineffective laws. Most importantly, PHMSA should remove exemptions for state and 

municipal governments from One-Call requirements. Such exemptions create unnecessary opportunities for third-party damage to pipelines. As I mentioned in my testimony, incidents from excavation damage by third parties accounted for only 7 percent of release incidents from 1999 to 2008. However, 31 percent of all significant 

incidents (those that result in spills of 50 barrels or more, fire, explosion, evacuation, injury or death) came from excavation damage by third parties. AOPL and 

API believe Congress should encourage OPS to move forward to issue a final rule 

on damage prevention based on the October 2009 Advanced Notice of Proposed 

Rulemaking (ANPRM), disallowing any exemptions to One-Call requirements. 

Question 1a. Do you believe PHMSA currently provides enough oversight of our 

Nation’s oil and gas pipelines? 

Answer. The liquids pipeline industry believes that PHMSA is a fair but tough 

regulator with several significant oversight tools, including: random and regular inspections of equipment and facilities, enforcement authority, and fines. PHMSA has 

a set of prescriptive safety regulations and standards that require a diligent focus 

by our industry to remain in compliance. Recently, critics of our industry have unfairly distorted and misconstrued the industry’s constructive working relationship 

with PHMSA, especially on the issue of setting consensus standards. Pipeline operators have every interest in developing best practices that help maintain the integrity 

of their systems, which pushes the industry to achieve operational excellence. It 

should be recognized that PHMSA can require, as well as reject, modifications to 

industry standards before incorporating them by reference. Further, all consensus 

industry standards involve public input under guidelines established by the American National Standards Institute (ANSI), whose Board of Directors are currently 

comprised of individuals from several Federal agencies, including DOE, NIST, 

CPSC, EPA, and DoD. In addition, PHMSA’s Technical Advisory Committee has direct representation from those in the advocacy community to incorporate all points 

of view in the regulatory process. We take issue with those that unfairly criticize 

and malign the reputation of organizations like the American Society of Mechanical 

Engineers (ASME) International and the American Society for Testing and Materials (ASTM) that were involved in setting consensus standards that have been 

adopted by PHMSA. These and other professional organizations provide real-world 

technical expertise and important insight to the regulatory process. The notion that 

the pipeline industry regulates itself is false. The role of Federal safety regulator 

is clearly and strongly performed by PHMSA. 

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RESPONSE TO WRITTEN QUESTIONS SUBMITTED BY HON. MARK PRYOR TO

GARY L. SYPOLT

Question 1. Do you oppose expanding integrity management inspections? 

Answer. We do oppose expanding the High Consequence Area (HCA) definition in 

the legislation to include more pipeline mileage. Currently, these HCAs are defined 

(for natural gas transmission lines) as those pipeline segments located within populated areas. If a pipeline is in an HCA, it is subject to an extra layer of protection 

beyond the existing pipeline safety regulations; in other words, it is subject to the 

Integrity Management Program (IMP) with its accompanying procedural and administrative requirements. The existing safety regulations, which have continually been 

updated since 1970, govern the design, materials, construction, operation and maintenance of all natural gas transmission pipelines and have contributed significantly 

to the safety record of natural gas transmission systems both within HCAs and outside HCAs. The focus of the mandated IMP on reducing risk in populated areas continues to make sense to us in that it allows the pipeline operators to focus its resources on those areas of the pipeline that are more densely populated. 

The mandated IMP program specifically allows three types of inspection technology: hydrostatic pressure testing, direct assessment and internal inspection using 

‘‘smart pigs.’’ The legislation does allow the use of any new technology for inspections, but at this time no new viable inspection technology has been accepted by 

PHMSA. Hydrostatic pressure testing involves isolating a section of pipeline and filling it 

with water and pressuring it far beyond the maximum operating pressure to see if 

the pipe ruptures or leaks. During the process, the pipeline segment must be taken 

out of service for several weeks. The pipeline operator must collect, handle and dispose of large volumes of water used in the testing. Finally, residual water or sediment could present operational problems once the pipeline segment is returned to 

service. 

Direct assessment involves excavating segments of pipeline and physically inspecting them (externally) every time it is inspected. This requires significant excavation work, including tearing up private property and roads, and potentially damaging the pipeline with excavation equipment every time the assessment is done. 

Within the last two decades, smart pig technology has been the ‘‘solution of 

choice’’ for integrity assessments because the alternatives—hydrostatic testing and 

direct assessment—present the aforementioned problems. Smart pigs can be a useful tool for managing corrosion where they are practical to use. However, many natural gas pipelines were constructed in an era before smart pigs were invented. 

These pipelines were engineered to transport natural gas—a highly compressible 

substance—rather than solid devices such as smart pigs. This means that pipeline 

segments with tight bends, telescoping segments, or valves which do not open completely, limit the passage of smart pigs and require extensive excavation and modifications to allow the insertion, passage and retrieval of smart pigs for inspections. 

These pipeline modifications are by far the most costly component of the IMP program. 

As I noted in my testimony, however, we have invested heavily and are already 

inspecting and repairing pipelines- via smart pigs—in much more than just the defined HCAs. For natural gas transmission pipelines, HCAs account for about 7 percent of total mileage, but we expect to actually perform internal inspections and repairs on about 65 percent of total mileage by the end of the baseline Integrity Management Program (IMP) assessments which will be completed in December of 2012. 

Based on this level of performance, I do not believe that integrity management 

inspections should be expanded by legislative mandate. 

Question 2. How often do most companies conduct internal integrity assessments? 

Answer. The Pipeline Safety Improvement Act of 2002 requires that natural gas 

transmission pipelines in HCAs undertake an initial integrity assessment by December 2012, and reassessments every 7 years thereafter. As mentioned previously, 

most of this work is being completed via internal inspections using smart pig devices. 

A consensus standard developed by the American Society of Mechanical Engineers 

(ASME) about a decade ago suggested a reassessment interval of 10 years for most 

high-pressure natural gas transmission pipelines. We believe the ASME standard is 

a logically and technically superior basis for setting reassessment intervals, and we 

hope Congress ultimately permits PHMSA to incorporate such a standard into the 

regulations, rather than the current seven-year mandate. In a report to Congress 

on this question in 2006, the GAO agreed with this position. 

Question 3. In light of the recent BP spill and leak events, do you believe there 

is more that industry, Congress or PHMSA should do to enhance pipeline safety? 

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Answer. First, it should be said that PHMSA and the pipeline safety program 

generally are not comparable to MMS and the events that led to the BP spill. For 

at least the last decade, the pipeline safety program at PHMSA has been characterized by action in the development of new safety standards for a variety of pipeline 

systems. Congress has added a number of mandates to PHMSA in terms of directing 

pipeline safety efforts. The occurrence of pipeline accidents is low, and serious accidents are very rare. The main reason is that industry, the regulator, and the public 

have worked together to put better safety programs and technologies in place. 

Still, more can be done. My testimony covered several ideas, including the implementation of a ‘‘safety culture’’ across the pipeline industry, including our contractors. This culture assists in reducing the workplace accidents which are a significant 

portion of the serious pipeline incidents still occurring. It is also an area where the 

BP experience is instructive. ‘‘Safety culture’’ can be defined as an environment in 

which employees engage in best safety practices whether they are supervised or not. 

In other words, employees are empowered to take the safest path, and are rewarded 

for doing so. This type of culture creates the best environment for avoiding accidents. 

Another area of additional focus, and the largest cause of serious incidents, is excavation damage prevention. This is also a ‘‘safety culture’’ issue but involves many 

stakeholders. Much has been done on this issue in the last 10 years, but more can 

be done. I would like to discuss this further in my answer to the next question. 

The final area of continuing focus is the ongoing development of new materials, 

equipment, and best practices for such items as employee training or equipment 

maintenance. All of these things are important to making continued improvement 

to safety. In my testimony, I included the example of improved smart pig technology. Better standards and technology will ultimately lead to fewer accidents. 

Question 4. What do you believe should be the top priorities for PHMSA in light 

of the recent BP disaster? 

Answer. The top priority for PHMSA, given the BP disaster and the public response, should be maintaining public credibility and trust by focusing on those 

causes of accidents which have the most impact on the public. INGAA believes more 

should be done with respect to excavation damage prevention. Accidental hits to 

pipelines from, for example, construction equipment, tend to be the leading cause 

of deaths and/or injuries associated with our pipelines. While these state-run damage prevention programs have improved significantly over the last decade, more 

needs to be done. The recent accidents in Texas, profiled in my testimony, point to 

this conclusion. Again, a credible damage prevention effort is about more than just 

making the first call to a one-call center. An effective program includes full participation by all excavators and all underground utility operators, accurate and timely 

marking of facilities by utility operators, procedures for due caution by excavators 

working around marked facilities, and effective enforcement of the state regulations. 

Question 5. Do you believe PHMSA currently provides enough oversight of our 

Nation’s oil and gas pipelines? 

Answer. Yes. The safety record of the pipeline industry is testament to this conclusion. 

RESPONSE TO WRITTEN QUESTIONS SUBMITTED BY HON. MARK PRYOR TO

CARL WEIMER

Question 1. What in your view would be the best way to conduct Integrity Management reviews by industry and PHMSA? 

Answer. The Pipeline Safety Trust believes that the basic theory and implementation of the reviews required by Integrity Management programs for Hazardous Liquid and Natural Gas Transmission pipelines is sound, and has led to the detection 

and correction of thousands of potential safety problems. 

Our concern is not so much in the way that Integrity Management reviews are 

conducted, but the limited miles of pipelines that are required to conduct such valuable safety reviews. Currently only 7 percent of natural gas transmission pipelines 

and only 44 percent of hazardous liquid pipelines are required to do these reviews. 

We believe that it is time to require that all of these types of pipelines fall under 

Integrity Management rules so people living in more rural neighborhoods have 

equal safety protection. 

If the Integrity Management program is not to be expanded to all of these types 

of pipelines then there are a couple of things that would at least help increase the 

safety under the existing limited mileage. These include: 

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• Many operators inspect many more miles of pipeline than is required, which is 

a good thing. These operators should be required to report their findings to 

PHMSA on the mileage of pipelines outside of the required areas, and how they 

responded to those findings, in the same way they report findings in the required areas. 

• The definition for determining High Consequence Areas for natural gas transmission pipelines in 49 CFR 192.903 should be changed as follows to significantly increase safety: 

High consequence area means an area established by one of the methods described in paragraphs (1) or (2) as follows: 

(1) An area defined as—— 

(iii) Any area in a Class 1 or Class 2 location where the potential impact 

radius is greater than 660 feet (200 meters), and the area within a potential impact circle contains 20 or more buildings intended for human occupancy 

• It should be made clear that at a minimum during the normal reinspection intervals operators should reassess their entire pipelines to determine if there 

have been any changes in circumstances (such as increase population near the 

pipeline) that would require additional areas to be added to High Consequence 

Area status. 

Question 2. Should PHMSA have more authority to regulate offshore pipelines? 

Answer. PHMSA already has significant authority in the offshore areas within the 

control of the states. While it is clear from the Gulf of Mexico disaster that a comprehensive review of offshore regulations and authority needs to be completed, the 

Pipeline Safety Trust has not considered this to the degree necessary to make a recommendation about whether authority needs to shift from MMS to PHMSA. 

We would suggest that a study be undertaken to compare both the regulations 

and performance under both agencies, and then a good comparison of what needs 

to be strengthened where would be relatively easy. 

One further point that should be addressed regardless of which agency is in 

charge is the implementation of a mandatory damage prevention notification system 

in the offshore waters. Onshore Congress, PHMSA and the pipeline industry have 

all spent significant effort to ensure the implementation of the national 811 ‘‘call 

before you dig’’ number and associated damage prevention awareness. No similar 

system is required in the offshore areas of the Gulf where increasing activities are 

occurring putting underwater pipelines at risk. One such offshore damage prevention system that has been developed that should be studied for possible mandatory 

implementation is GulfSafe. More information about it can be found on their website 

at: http://www.gulfsafe.com/. 

RESPONSE TO WRITTEN QUESTIONS SUBMITTED BY HON. JOHN THUNE TO

CARL WEIMER

Question 1. There seems to he some inconsistency in the treatment of oil pipelines 

compared to gas pipelines in terms of regulation and emergency response requirements. What recommendations do you have for addressing these? 

Answer. I am not sure I understand the question, so would need more information 

regarding what ‘‘inconsistency’’ is being referred to. 

The main inconsistency that we are currently concerned about is the difference 

in attention being spent addressing production, gathering, and flow lines. For oil 

pipelines Congress has asked, and PHMSA is now working toward a rulemaking, 

to implement new regulations on these low-stress oil pipelines. This is important 

work and we support it! Natural gas pipelines have similar production lines, many 

of which are unregulated, or the point where regulations begin is unclear. With a 

huge increase in domestic drilling for natural gas, much of it occurring in more populated areas in places like Texas, New York, and Pennsylvania, there is a need to 

ensure adequate regulation of these types of natural gas pipelines, especially in populated areas. 

We believe that much of our concern about unregulated natural gas pipeline could 

be addressed by the following two changes: 

• Implement a rulemaking to clarify the point where onshore regulated gas gathering lines begin (49 CFR Part 192.8). That point should be defined to ensure 

there are no unregulated gas pipelines off of well pads in class 2, 3, or 4 areas, 

or other ‘‘identified sites’’ where large groups may gather. 

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• Implement a rulemaking to include all Type A gathering lines (49 CFR Part 

192.9) under the full requirements of the Integrity Management program (49 

CFR Part 192 Subpart O) that currently only applies to transmission pipelines. 

Question 2. Do you consider integrity management a success? 

Answer. We do consider Integrity Management of transmission pipelines a success. For both liquid pipelines and natural gas pipelines integrity Management was 

a huge step up in regulations ensuring that transmission pipelines in more populated areas, and areas that could affect sensitive environments, were inspected on 

a regular basis. These required inspections found nearly 35,000 anomalies in need 

of repair on pipelines in the first round of inspections. These are anomalies that 

may not have been found and repaired until leaks, ruptures, or explosions occurred 

under the previous regulations. 

While Integrity Management has been a success it is still limited to only 7 percent 

of natural gas pipelines and 44 percent of liquid pipelines. It is time to expand this 

successful program to all transmission pipelines to ensure that those in more rural 

areas have these same safety benefits, and that our critical fuel transportation network remains viable. 

RESPONSE TO WRITTEN QUESTIONS SUBMITTED BY HON. JOHANNS TO

CARL WEIMER

Question 1. Your testimony recommends that the pipeline safety system be 

changed to correct the ‘‘pipeline siting vs safety disconnect’’ which separates the 

safety function of PHMSA from the siting process. In light of this recommendation, 

what is your view of how PHMSA has been involved in the permitting process for 

the Keystone XL pipeline in Nebraska? 

Answer. We have not been actively involved in the Keystone permitting process, 

but our understanding is that it has proceeded like most other new pipeline permitting processes across the country. In all of those permitting processes, whether 

being overseen by FERC, the Department of State or the states, there is a disconnect between PHMSA’s review and approval of pipeline safety issues (special 

permits, High Consequence Areas, spill response plans, etc.) and the official environmental review that is part of the permitting. These two now separate processes need 

to be integrated into a single process. That way things like spill response plans and 

High Consequence Areas can be developed and publicly reviewed as part of the permitting—not in the separate processes that PHMSA now uses many of which are 

closed to the public. It makes little sense for the Department of State to do an environmental review is such critical things as Spill Response plans (under PHMSA’s 

authority) have not yet been developed or made public. 

One way to better integrate these separate processes would be to require PHMSA 

to be a cooperating agency for all interstate pipeline siting processes, and that all 

parts of a new pipeline’s safety review be a part of that siting review as well. 

Question 2. What specific recommendations would you make for the regulatory 

process that governs the issuance of a Presidential permit? Do these recommendations differ as compared to recommendations for the regulatory process that governs 

pipeline siting for exclusively domestic transport of crude oil? 

Answer. We don’t really see that there should be any real difference in the permitting process between purely domestic pipelines and ones that cross an international border. The recommendations we made above to better integrate permitting 

and pipeline safety would apply to both. 

Question 3. What comments would you offer, if any, concerning the role that state 

authorities play in the regulatory process governing the issuance of Presidential permits for the international transport of crude oil? 

Answer. Unlike the siting of interstate natural gas pipelines, which is controlled 

by FERC, states do have the ability to create pipeline siting agencies for interstate 

hazardous liquid pipelines. We think states should exercise this ability to give them 

control over the siting process, but in reality some states do and some states don’t. 

In the states that do not create such siting agencies the routing and permitting decisions are left up to the pipeline companies and local government. 

It is unclear to us whether a Presidential Permit granted by the State Department preempts the normal state siting authority, or whether those two processes 

can run in parallel to each other. This should be clarified, and at a minimum such 

state agencies should be made cooperating partners in the review by the State Department. 

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PREPARED STATEMENT OF MICHAEL THOMPSON, CHIEF, PIPELINE SAFETY, OREGON

PUBLIC UTILITY COMMISSION AND CHAIRMAN, NATIONAL ASSOCIATION OF PIPELINE

SAFETY REPRESENTATIVES (NAPSR) 

Introduction 

Chairman Lautenberg, Ranking Member Thune, members of the Committee, 

thank you for the opportunity to discuss our role in support of pipeline safety as 

related to reauthorization of the pipeline safety law. This law contains necessary 

protections that our Nation depends on to maintain safety in its energy pipeline network. I am the Chairman of the National Association of Pipeline Safety Representatives (NAPSR) which is a non-profit organization of state pipeline safety personnel 

who serve to support, encourage, develop and enhance pipeline safety in the country. I am pleased to submit this statement for the record on behalf of NAPSR and 

in support of our member states’ efforts, as well as in support of the partnership 

with the Secretary of Transportation to fulfill the mandates of the Pipeline Safety 

Act. 

I will briefly describe the role of the states in maintaining or enhancing pipeline 

safety, where our efforts are currently focused, and what it takes for State programs 

to implement the Federal mandates. 

The States as Stewards of Pipeline Safety 

Since the Pipeline Safety Act was signed into law in 1968, states have been very 

active as stewards of pipeline safety in assisting the U.S. DOT Secretary in carrying 

out the Nation’s pipeline safety program. States act as certified agents for implementing, ensuring and enforcing Federal safety regulations, working in partnership 

with the Secretary. State pipeline safety program personnel are classified as state 

employees providing oversight of state and local safety regulations which in all cases 

are either equivalent or stricter than Federal regulations. This arrangement between the Federal and State government has mutually benefited both State and 

Federal regulators, while ultimately benefiting the local citizens and consumers in 

providing a safe, reliable energy supply and distribution infrastructure. The current 

arrangement, from a Federal perspective, has distinct advantages because state employees are generally less expensive than Federal employees or private contractors, 

have lower travel, maintenance and operating costs, and typically yield the economies of scale that state governments inherently possess. This also allows for greater 

safety oversight because it uses knowledge of local conditions, considerations of local 

concerns, relationships with local first responders and the ability to provide direct 

and immediate feedback to the public. This is indeed a fiscal ‘‘bargain’’ for the Federal agency but more importantly, provides the prerequisite detailed knowledge required for thorough scrutinizing of pipeline operations that the public and this committee demand. 

One other distinct advantage that state programs have over comparable Federal 

oversight is the ability to incorporate and leverage state pipeline safety initiatives 

into a multitude of other existing state review processes that blend safety, reliability 

and rate-making authorities over energy providers, rather than distinct ‘‘silos’’ with 

separate government agencies. 

State pipeline safety personnel represent more than 80 percent of the state/Federal inspection workforce. State inspectors are the ‘‘first line of defense’’ at the community level to promote pipeline safety, underground utility damage prevention, and 

public awareness regarding gaseous and liquid fuel pipelines. 

The responsibility for state pipeline safety programs is carried out by approximately 325 qualified engineers and inspectors in the lower 48 states, District of Columbia and Puerto Rico. Recent statistics indicate that states are responsible for 

pipeline safety covering over 92 percent of 1.9 million miles of gas distribution piping in the nation, 29 percent of 300,000 miles of gas transmission and 32 percent 

of 166,000 miles of hazardous liquid pipelines. State personnel in 11 states act as 

‘‘interstate agents’’ also inspecting interstate gas and liquids pipelines that would 

otherwise be inspected by PHMSA. Based on these percentages, every state inspector is responsible for overseeing/inspecting, more than 5,500 miles of pipeline. That’s 

further than twice the distance from Miami to Seattle. 

Enhancing Pipeline Safety 

Beginning in 1968, when the Pipeline Safety Act was signed into law and now, 

since the passage of the PIPES Act in 2006, states have been working with PHMSA 

in fulfilling the mandates of the resulting law. This is being accomplished in a twopronged approach: (1) on mandates that are simple to carry out, processes are put 

in place that can yield immediate safety benefits (e.g., increased levels of enforcement); and (2) on multi-faceted mandates (e.g., excavation damage prevention) 

114 

states work with the Federal Government, and where appropriate, with private 

stakeholders, to concentrate on developing practical, effective and affordable solutions to implement the various aspects of such mandates. Although such efforts take 

more time, the result is a carefully crafted, sensible approach that is more likely 

to achieve the stated goal of the legislative mandate. 

Essential to the Federal-state partnership in this area are the pipeline safety program managers in each of 52 state agencies which are members of NAPSR. In addition to their intensive inspection oversight work schedules, many take extra time 

to address areas of concern in meeting the existing challenges or with new initiatives and proposals for recommended improvements to pipeline safety. NAPSR currently has members on 27 task groups, with representatives from 33 states working 

with PHMSA on key safety elements of the pipeline safety program. These include, 

but are not limited to, excavation damage prevention, gas distribution integrity 

management, gas transmission and hazardous liquids integrity management, public 

awareness communications, control room management, safety performance data collection and analysis, national consensus standards development, risk-based and integrated inspections, and planning for pipeline right-of-way encroachment. With 

their knowledge and experience about conditions in their states, NAPSR members 

provide unique and valuable expertise to these task groups. 

Four Key Elements in Ensuring Pipeline Safety 

The focus of state efforts is concentrated onto four major elements: 

Comprising the first and basic element in pipeline safety are on-going state inspection efforts of jurisdictional pipeline facilities to verify operator compliance 

with long-standing Federal standards that cover design, installation, initial testing, corrosion control and many operating and maintenance functions. While 

new sets of regulations have been developed to address recently identified 

needs, the on-going enforcement of the original code requirements is essential 

to maintaining the basic levels of safety in our pipeline systems. Oversight of 

properly installed new facilities for example, should minimize future integrity 

issues. 

The second element in pipeline safety is minimizing excavation damage to pipelines. NAPSR members worked with PHMSA in developing the necessary implementation steps for the 9 elements specified in the PIPES Act for excavation 

damage prevention. Our members are now undertaking projects each year that 

help promote One-Call programs and other initiatives to put into practice the 

various components of the 9-element damage prevention program specified in 

the Act. 

The third key element of pipeline safety is pipeline system integrity resulting 

from the last two pipeline safety reauthorizations. Through NAPSR, states 

worked in the recent past with a stakeholder group to develop the foundation 

of the Distribution Integrity Management Program rule. We are now working 

with PHMSA to ensure proper implementation of this rule which adds formalized integrity management coverage of over 1.8 million miles of distribution 

pipelines strictly under state jurisdiction. State programs will be 100 percent 

responsible for this, which is about to undergo the test of time to verify the effectiveness of the corresponding legislative mandate and its regulatory offspring. 

It must be remembered that many states have long had successful integrity 

management programs in the form of additional and accelerated operating and 

maintenance activities, as well as planned pipe replacement programs. These 

programs have been very effective in addressing the local needs of the individual distribution systems throughout the country, and are based on the actual 

circumstances affecting the individual systems. We are the source of many of 

the pipeline safety best practices developed in this area. New Federal requirements have significantly increased the states’ compliance verification workload, 

particularly in the area of written procedures, implementation processes, ongoing data collection and analysis, and recordkeeping. 

Finally, a fourth and critical key element in dealing with pipeline safety is the 

practice of fiscal responsibility through the management of risk. This may include risk-based approaches to pipeline safety to allow the operators under state 

jurisdiction to apply their resources to the areas where they are most needed, 

while enhancing or maintaining safety. Through forums at National Association 

of Regulatory Utility Commissioners (NARUC) and the efforts of NAPSR, we 

work with our Federal partner, PHMSA, to identify such areas. This requires 

ensuring that proper data is collected by our operators and compiled by our program offices, so that risks can be properly identified, assessed and mitigated. 

115 

Here, our NAPSR members are engaged in an on-going effort with PHMSA to 

collect reliable, high quality, relevant data on the characteristics and safety performance of the Nation’s gaseous and hazardous liquid fuel delivery systems. 

The associated costs of all these programs are mostly covered by in-state user 

fees and cost-of-service fees, which are augmented by Federal grant funds derived from Federal user fees—part of which is also paid by intrastate pipelines. 

Our regulatory commissions are directly accountable to the states’ ratepayers 

and are the fiscal guardians responsible for prudent funding decisions balanced 

by the goal of ensuring pipeline safety. 

Part of fiscal responsibility also lies with the Federal Government living up to its 

original promise from the Pipeline Safety Act of 1968 which provided for up to 50 

percent funding of state expenditures for pipeline-safety. Most recently, the PIPES 

Act of 2006 authorized a maximum Federal funding goal of 80 percent of the states’ 

program costs. Still, it can be shown that in 2009, State gas users have paid for 

more than 68 percent of the total pipeline safety program costs. Final FY 2010 figures are not yet available. 

Grant funding of the states through the Federal Pipeline Safety Program is vital 

to enabling the states to ensure the safety of existing pipeline facilities and of new 

pipeline construction projects through state inspection activities. These funds form 

the foundation of the Federal-state partnership that makes it possible to carry out 

the necessary inspection and enforcement work involving pipeline systems of more 

than 9,000 gas distribution, transmission and hazardous liquid companies in the 

U.S. 

The Need to Allow Current Mandates to Work 

Amendments in 1996, 2002, and 2006, to Title 49 USC Chapter 601 have set in 

place additional mandates for pipeline safety in the law. As a result of those amendments, new regulations, technical standards, inspection protocols and training requirements have been or are being adopted. In accordance with Federal certification 

requirements, each state must incorporate these changes into their pipeline safety 

programs, giving rise to an increasing need for accompanying resources in maintaining such programs. Furthermore, it takes time for the more complex mandates of 

the last three pipeline safety reauthorizations to achieve maturity. At this point, we 

do not have conclusive proof that all these mandates are effective in ensuring safety 

of pipeline facilities, but positive effects are becoming noticeable. We feel more ‘‘test 

time’’ is needed, and it seems to us, that added legislative mandates on the PHMSA 

pipeline safety program are not warranted during this period. They may even exacerbate the hardship many state pipeline programs are currently under, as shown 

below. 

Due to prior insufficient appropriations, states have had to grow their programs 

to fulfill the new unfunded mandates and have thus been forced to cover with state 

funds a larger share of the program costs white the Federal share has fallen short 

of the amount authorized by Congress. 

Despite this shortfall in appropriated Federal funding, states have continued to 

improve safety, as is evident from the reduction in serious pipeline incident data 

collected by PHMSA over the past 10 years. The record also clearly demonstrates 

that states in association with PHMSA have made steady progress in implementing 

the many mandates over the past years. 

The PHMSA FY 2009 budget request and ensuing appropriation was a first step 

directed toward fulfilling the goals established by Congress in the 2006 Pipes Act 

(49 U.S.C. Chapter 601) for PHMSA to provide grants for up to 80 percent of the 

states’ yearly expenditures. FY 2010 appropriations further increased funding toward that goal. 

However, Federal grant funds are not just passed along to the states. There is 

a means test for eligibility for such grant funds in the pipeline safety law. Section 

60107(b) requires that state spending (excluding the Federal contribution) on its 

natural gas and hazardous liquid safety programs must at least equal the average 

amount spent in the previous 3 years. This condition has led to an unintended consequence. Fortunately, there is a provision by which the Secretary of Transportation 

is authorized to waive this requirement. 

Unintended Consequence 

It has become apparent that in the absence of such a waiver, this provision could 

have unanticipated negative impacts on state pipeline safety programs and the Federal/state partnership. At one point, PHMSA has even suggested that a legal interpretation of the language indicates that if a state does not maintain its three-year 

average spending level, it could lose eligibility for any grant funds. At the present 

time, states are almost universally experiencing severe economic distress, with reVerDate Nov 24 2008 07:17 Jul 12, 2011 Jkt 067270 PO 00000 Frm 00119 Fmt 6601 Sfmt 6621 S:\GPO\DOCS\67270.TXT SCOM1 PsN: JACKIE
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duced revenues and massive budget shortfalls leading to across-the-board budget 

cuts, hiring and travel restrictions, deferred equipment purchases, and other often 

draconian measures to control state expenditures. For example, in 18 states pipeline 

safety program employees have been furloughed without pay, some for as many as 

21 days. In this environment, it is inevitable that many states will be forced to reduce expenditures for pipeline safety. This is not a reflection of the states’ commitment to pipeline safety, but the reality of the current economic crisis. 

A survey of state pipeline safety agencies conducted by NAPSR shows that more 

than half of the states are experiencing budget cuts with the remainder taking other 

measures and expecting possible budget cuts over the next few years. Not only is 

growth in state programs during these times very unlikely, some cutbacks in state 

expenditures are certain. 

Penalizing states under such circumstances undermines state programs at a time 

when Federal support for their mission is more important than ever. The availability of grant funds to reach adequate funding at the state program level is a very 

important factor in protecting state programs from further cutbacks, and even from 

calls to discontinue the programs entirely. PHMSA has realized this and after about 

8 months of deliberations, waiver requests by states are being carefully considered 

on a state-by-state basis. 

How Reauthorization Can Help 

The currently contemplated reauthorization process could mitigate the unintended 

consequence of Section 60107(b) by specifying that rather than a rolling average of 

the previous Fiscal Years, the 3-year average of state expenditures would be computed on the basis of FY 2004, 2005 and 2006. The rationale for this is that with 

the passage of the PIPES Act in 2006, state programs were given a significant number of added unfunded mandates, that is, mandates whose state funding was not 

matched by increased Federal grant appropriations until FY 2009. An example of 

such a mandate with a potentially huge impact is the requirement for gas Distribution Integrity Management Programs. 

Ideally, the modification to the existing law would further specify that the DOT 

Secretary may grant a waiver of this requirement to a state in the event of special 

circumstances, for reasons that may include a state’s inability to collect sufficient revenue to maintain or increase the state’s share of its safety program as required by 

the above-named section of the law. The precedent for this approach was set during 

passage of the Pipeline Safety improvement Act of 2002 which included provisions 

in the law for pipeline facility risk analysis and integrity management programs. 

Paragraph 60109(c)(5) of the law states that ‘‘the Secretary may waive or modify 

any requirement for reassessment of a facility under paragraph (3)(B) for reasons 

that may include the need to maintain local product supply or the lack of internal 

inspection devices if the Secretary determines that such waiver is not inconsistent 

with pipeline safety.’’ This would allow a faster process for a decision by the Secretary to grant a waiver to a state. 

It is also important to note that even with waivers in place, states will continue 

to be subject to a thorough performance assessment conducted by PHMSA using certification and evaluation criteria that tie such performance to the grant amount provided to the states. 

Conclusions 

Programs mandated by the last three pipeline safety reauthorizations have required and continue to require extensive additional state efforts to address safety 

in areas that include but are not limited to operator qualification requirements, gas 

transmission and liquids pipeline integrity, public awareness communications, excess flow valve installation, pipeline control room management, distribution system 

integrity, and excavation damage prevention. These mandates still need a number 

of years to prove their worth. A hiatus in added legislative mandates would be beneficial by allowing the regulators to focus on the effectiveness of existing mandates 

without detriment to safety. 

As state programs have had to grow to administer and enforce the new requirements, Federal grant monies have not been adequate to fund even 50 percent of the 

costs of providing the safety and compliance activities necessary. The states have 

gradually had to assume a gradually larger share of the costs of providing for the 

majority of the Nation’s pipeline safety programs. This was recognized in the PIPES 

Act, which authorized PHMSA to reimburse a State with up to 80 percent of the 

cost of the personnel, equipment, and activities for pipeline safety in that state, provided that the state met the means test of its funding. This last condition is difficult 

to satisfy due to the magnitude of the financial crisis that has befallen most states. 

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A revision to the language in Section 60107(b) would provide timely financial relief 

via easier state access to grant funding. 

It is now up to this Congressional committee to adjust the authorized funding for 

state pipeline safety grants over the next 4 years and to facilitate state access to 

such funding, so that states can continue to carry out the Congressionally-mandated 

expanded safety programs even during these times of economic distress. Adequate 

funding authorized for state programs will directly lead to more inspectors in the 

field, more frequent inspections of pipeline operators, more thorough inspections and 

fewer pipeline accidents. 

Like you, we understand the importance of our mission to the safety of our citizens, energy reliability and continued economic growth of our Nation. 

Thank you. 

PREPARED STATEMENT OF THE AMERICAN PUBLIC GAS ASSOCIATION

Mr. Chairman and members of the Committee, the American Pubic Gas Association (APGA) appreciates this opportunity to submit testimony on behalf of public gas 

systems to the Committee for this important hearing on pipeline safety. APGA also 

wants to commend the Committee for all the work it has done over the years to 

ensure that America has the safest, most reliable pipeline system in the world. 

APGA is the national association for publicly-owned natural gas distribution systems. There are currently approximately 1,000 public gas systems located in 36 

states. Publicly-owned gas systems are not-for-profit, retail distribution entities 

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. Public gas systems range in size 

from the Philadelphia Gas Works which serves approximately 500,000 customers to 

the City of Freedom, Oklahoma which serves 12 customers. 

Overview 

Safety is the number one issue for public gas systems. No other issue rises to the 

level of safety for the local distribution company (LDC) that provides natural gas 

service to its consumers. Gas utilities are the final step in taking natural gas from 

the production field to the homeowner or business. As such, our members’ commitment to safety is second to none and they keep focused on providing safe and reliable service to their customers. 

Our members receive their natural gas from interstate transmission pipelines. 

Transmission pipelines usually consist of long and straight lines of pipe that have 

a large diameter and are operated at high volumes and high pressures. By contrast, 

the distribution pipelines in LDC’s are generally smaller in diameter (as small as 

1⁄2 inch), and are constructed of several kinds of materials including cast-iron, steel 

and plastic. Distribution pipelines also operate at much lower pressures and always 

carry odorized gas that can be readily detected by smell. 

Public gas systems are an important part of their community. Our members’ employees live in the community they serve and are accountable to local officials (and 

their friends and neighbors). Public gas systems are generally regulated by their 

consumer-owners through locally elected governing boards or appointed officials. 

However, when it comes to pipeline safety, nearly all of our members are regulated 

by an individual State’s pipeline safety office. All of our members must comply in 

the same manner as investor- and privately-owned utilities with pipeline safety regulations issued by the Pipeline and Hazardous Materials Safety Administration 

(PHMSA). This includes belonging to the State ONE-CALL system, marking the location of gas lines when notified of an excavation and notifying other utilities in advance of the utility planning to excavate. Municipal gas utilities are subject to the 

same excavation damage prevention requirements as their investor- and privatelyowned utility counterparts. 

While the manner of safety regulation may be the same, one major difference between the average investor-owned utility and the average public gas system is size: 

in the number of both customers served and employees. Approximately half of the 

1,000 public gas systems have five employees or less. As a result, regulations and 

rules do have a significantly different impact upon a small public gas system than 

they do upon a larger system serving hundreds of thousands or millions of customers with several hundred or even thousands of employees and an in-house engineering staff. 

Implementation of the PIPES Act 

The Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (PIPES 

Act) contained several provisions that addressed safety issues at the LDC level, inVerDate Nov 24 2008 07:17 Jul 12, 2011 Jkt 067270 PO 00000 Frm 00121 Fmt 6601 Sfmt 6621 S:\GPO\DOCS\67270.TXT SCOM1 PsN: JACKIE
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cluding excavation damage prevention. Excavation damage is the leading cause of 

natural gas distribution pipeline incidents and APGA strongly supports efforts to reduce excavation damage. The PIPES Act established an incentive program for states 

to adopt stronger damage prevention programs. Specifically, the Act outlined nine 

elements of effective damage prevention programs. In order to obtain damage prevention program grants from the U.S. Department of Transportation, a state must 

demonstrate, or have made substantial progress toward demonstrating, that its 

damage prevention program has incorporated these nine elements. This flexible approach has allowed states to implement the nine elements in a manner that meets 

their individual needs. 

These elements, along with the 811 national ‘‘Call Before You Dig’’ number, which 

began in May, 2007, have helped address excavation damage. APGA strongly supports this approach to limiting excavation damage which recognizes that government has a responsibility to adopt and enforce effective damage prevention programs. APGA commends Congress and PHMSA for these efforts toward addressing 

excavation damage. 

Distribution Integrity Management 

Another critical component of the PIPES Act was the requirement that LDC’s establish Distribution Integrity Management Programs (DIMP). Even before the 

PIPES Act passed, PHMSA had convened a working group of Federal and state regulators, industry and the public to advise PHMSA on how to approach DIMP. The 

group met over a 12 month period. APGA and its members actively participated in 

the group. In December 2009, PHMSA issued a final regulation on DIMP. APGA 

would also like to commend PHMSA for its leadership and work toward the development of a final rule that will significantly enhance safety. 

The final rule requires all distribution pipeline operators, regardless of size, to implement a risk based integrity management program that addresses seven key elements: 

1. Develop and implement a written integrity management plan. 

2. Know the infrastructure performance. 

3. Identify threats, both existing and of potential future importance. 

4. Assess and prioritize risks. 

5. Identify and implement appropriate measures to mitigate risks. 

6. Measure performance, monitor results, and evaluate the effectiveness of its 

programs, making changes where needed. 

7. Periodically report performance measures to its regulator. 

Basically, a gas distribution system must have a written plan in place and the 

plan must demonstrate an understanding of the gas distribution system, including 

the characteristics of the system and the environmental factors that are necessary 

to assess the applicable threats and risks to the gas distribution system. The operator must also identify additional information needed and provide a plan for gaining 

that information over time through normal activities. The plan must consider eight 

categories of threats to the pipeline system. An operator must consider incident and 

leak history, corrosion control records, continuing surveillance records, patrolling 

records, maintenance history and excavation damage experience to identify existing 

and potential threats. 

A key component of this rule, and one strongly supported by APGA, is that the 

rule was designed to be flexible. The rule allows each LDC to manage its system 

with the goal of improving safety based on the system’s unique performance characteristics, as opposed to following prescriptive rules that could divert resources away 

from the most significant threats for that particular utility. For example, the transmission integrity management rules imposed a fixed, interval, inspection-intensive 

program aimed primarily at detecting corrosion and mechanical damage. A review 

of PHMSA’s annual and incident report data for the 3-year period 2005–2007, found 

that failures on distribution systems due to corrosion was the least likely of the 

eight threats listed in the DIMP rule to result in fatalities, injuries or significant 

property loss. On the other hand, a failure due to excavation damage is eleven times 

more likely to result in a reportable incident than a corrosion-caused failure. Under 

the DIMP rule, each operator must still assess the risk of corrosion, but only take 

additional actions above and beyond current regulations if indicated by its risk assessment. 

The DIMP rule also requires operators to file annual reports with PHMSA listing 

the number of excavation damages that occurred during each calendar year. 

PHMSA adopted the Common Ground Alliance’s Damage Information Reporting 

Tool (DIRT) definition of ‘‘damage’’ which includes ‘‘any impact that results in the 

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need to repair or replace an underground facility due to a weakening, or the partial 

or complete destruction, of the facility, including, but not limited to, the protective 

coating, lateral support, cathodic protection or the housing for the line device or facility.’’ In the past, only excavation damage that resulted in a leak was reported on 

the annual reports, so PHMSA will be receiving significantly more damage reports 

than it collected in the past. This annual report data is available to the public on 

PHMSA’s website allowing PHMSA, the industry, state regulators and the public to 

evaluate trends in excavation damage. 

‘‘SHRIMP’’ 

‘‘SHRIMP,’’ short for ‘‘Simple, Handy, Risk-based Integrity Management Plan,’’ is 

a DIMP plan development tool developed by the APGA Security and Integrity Foundation (SIF). The SIF is a non-profit 501(c)(3) corporation created by APGA in 2004. 

The SIF is dedicated to promoting the security and operational integrity and safety 

of small natural gas distribution and utilization facilities. The SIF focuses its resources on enhancing the abilities of gas utility operators to prevent, mitigate and 

repair damage to the Nation’s small gas distribution infrastructure. The SIF delivers programs and services to the industry through a cooperative agreement with 

PHMSA while working closely with the National Association of Pipeline Safety Representatives (NAPSR) and other state pipeline safety organizations. 

SHRIMP is a web-based tool that walks the user through the steps of developing 

a Distribution Integrity Management Plan, similar to how tax preparation software 

walks users through preparing income tax returns. It asks questions about the material of construction of the distribution system; the results of required inspections 

and tests; the number and causes of leaks on the system and other information relevant to assessing the eight threats in the DIMP rule. Where any threat is elevated, 

SHRIMP offers suggestions for additional actions the user could implement to reduce that threat as well as performance measures to determine whether the additional action chosen is effective at reducing the threat. The output is a complete, 

written DIMP plan customized for the user’s system that meets all the requirements 

of the regulation. SHRIMP is available to all distribution operators (investor owned, 

municipal, master meter, etc) and it is free to the small systems with fewer than 

one thousand customers. 

Control Room Management 

The PIPES ACT also required PHMSA to regulate fatigue and other human factors in pipeline control rooms. PHMSA issued control room management rules in 

December 2009. While these rules may be reasonable when applied to transmission 

pipeline controllers, unfortunately PHMSA’s definition of a controller has the unintended consequences of classifying hundreds of public gas system employees as pipeline controllers. PHMSA’s rule fails to differentiate between Supervisory Control 

and Data Acquisition (SCADA) systems and telemetry systems that simply transmit 

data to a central office. All SCADA systems include telemetry, but all telemetry is 

not SCADA if it provides no means to control the operation of the pipeline. By 

PHMSA’s definition, however, anyone who can display telemetered data on a computer is a controller. 

Distribution systems typically monitor the pressure and flow at the gate stations 

where they receive gas from their transmission pipeline supplier. They may also 

record pressures at various points around the distribution system to ensure there 

is adequate pressure to deliver gas to customers at the extreme ends of the system. 

For years these data were recorded on paper charts, manually collected each day. 

Increasingly utilities are installing telemetry to transmit these data back to the office where it can be periodically reviewed throughout the day by utility managers. 

This allows faster response to low flow/low pressure situations and frees up the personnel who collected pressure charts for other inspection and maintenance activities. 

Some systems allow telemetry to be viewed remotely via the Internet. This telemetry is for business purposes, not public safety. 

Because distribution systems operate at relatively low pressures and are an interconnected network rather than a straight line pipeline, a complete rupture of a distribution line would be unlikely to cause a flow surge or pressure drop detectable 

by the telemetry system. Even were a pressure drop to be detected, all these ‘‘controllers’’ can do is send other personnel to investigate—they have little or no actual 

control over the system and no ability to isolate a suspected leak. 

For years distribution systems operated safety without the ability to monitor 

these data in real time. Even today, many of these ‘‘SCADA systems’’ are left unattended at night and over weekends and holidays. Yet PHMSA’s rules would require 

utilities to implement a fatigue management program for individuals and their supervisors who have access to a SCADA monitor that can safely go unattended over 

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nights and weekends. This rule adds significant costs to a utility’s decision to automate the transmission of operational data back to offices and thus stifles the use 

of telemetry to gas distribution operations. 

APGA’s concerns could be easily addressed were PHMSA to simply adhere to the 

unambiguous language in its controller definition that states a controller is one who 

both monitors AND controls via a SCADA system. Instead, PHMSA stated in the 

preamble to the rule that it believes ‘‘control via a SCADA system’’ actually means 

control via means other than a SCADA system, resulting in the unintended consequences described above. 

Reauthorization 

APGA supports reasonable regulations to ensure that individuals who control the 

Nation’s network of distribution pipelines are provided the training and tools necessary to safely operate those systems. In this regard, over the past several years 

the industry has had numerous additional requirements placed on it, e.g., DIMP, 

excess flow valves, control room management, operator qualification, public awareness and more. Many of our members are in the process of working to comply with 

the administrative burdens of these additional regulations. Given that our members 

are non-profit systems in many cases with limited resources, these additional regulations, while important, do impose an additional operational burden upon them. 

For this reason, APGA strongly supports a clean reauthorization of the Act. 

Should the Committee consider revisions to the Act, there are a number of issues 

APGA would ask the Committee to consider. We urge the Committee to give great 

consideration before imposing any additional regulatory burdens upon LDC’s 

through this reauthorization effort. In terms of reauthorization, APGA is specifically 

concerned about an expansion in the requirements for excess flow valves and potential changes in the funding mechanism for PHMSA. 

Excess Flow Valves (EFVs) 

The PIPES Act included a provision requiring operators to install excess flow 

valves on new and replaced single residential service that operate year around at 

or above 10 pound-force per square inch gauge. Exceptions are provided if EFVs are 

not available, if it is known there are contaminants in the system that would cause 

the EFV to fail or if it is known there are liquids in the system. Prior to this installation requirement, there was a customer notification rule in place that required gas 

systems to make their customers aware of the availability of EFVs and install an 

EFV if the customer was willing to pay installation costs. It was limited to new and 

renewed services because EFVs are installed underground where the ‘‘service line’’ 

to a residence connects to the gas main. If a hole is already open and a new connection to the main is being installed, adding an EFV at that time costs just a fraction 

of what it would cost to install or replace an EFV when no other work is planned 

at the main-service connection. 

Each EFV has a preset closure flow rate. Once installed on a service line it will 

prevent gas from flowing at any flow rate higher than its preset closure flow rate. 

There is no way short of replacing the EFV to change its closure flow rate. This 

is typically not an issue with EFVs on residential service lines since the gas demand 

to a residence does not typically change drastically. A residence will have a relatively constant and predictable gas demand over its lifetime so the EFV can be 

sized accordingly. 

However, APGA is greatly concerned about an expansion of the EFV requirements 

to commercial and industrial businesses and multifamily residences. A commercial 

building, unlike a residential unit, may see huge changes in gas demand as tenants 

in the space move in and out. For example, a space in a strip mall that today is 

occupied by a shoe store could be converted to a restaurant or bakery tomorrow. The 

gas demand could double or triple. That could require replacing the meter, regulator 

and EFV. Since the first two items are above ground, replacement is relatively inexpensive. However, the EFV is buried and replacing it would be very costly, often 

hundreds of times the initial cost of the EFV. To address this problem, an operator 

could install a grossly oversized EFV with closure flow at or near the free flow limits of the service line. However, a valve so oversized would probably not close even 

if the line were ruptured, defeating the purpose of having an EFV on the line in 

the first place. 

The same and additional issues apply to installing EFVs on service lines to industrial customers. The flow rates and operating pressures to many industrial customers exceed the capacity of commercially available EFVs. 

The potential costs of a false closure of the EFV can be significantly greater for 

a commercial or industrial customer than a residence. Both would suffer business 

losses in addition to the inconvenience of no heat or hot water. An evening’s loss 

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of business to a restaurant could run into the thousands of dollars, however some 

industries such as microprocessor chip manufacturers could see millions of dollars 

of product ruined by the loss of temperature control required by their processes. 

The industry has experience with EFVs designed for typical flow rates to singlefamily residences, but has little or no experience with EFVs designed for larger 

flows. 

PHMSA has established a working group of government, industry and public experts to study the issues related to installing large volume EFVs on other than single residential services. We encourage Congress to allow this stakeholder working 

group to proceed toward making specific recommendations on this issue. 

Funding of User Fees 

Under the current formula, user fees for funding PHMSA are collected by natural 

gas transmission operators from their downstream customers. User fees are mandatory costs a natural gas transmission operator can pass through to customers in its 

cost-of-service. This allowable pass-through treatment is similar to other mandatory 

safety program costs. As a result, it is natural gas distribution operators that pay 

the user fees to transportation operators in their transportation rates, and it is the 

natural gas transmission operators that, after collecting the user fees from its customers, pass those fees to PHMSA in the annual pipeline safety user fee assessment. 

APGA supports this current formula and we believe it has worked well over the 

years. APGA is strongly opposed to any changes in the current formula that would 

shift the user fees to the LDC’s. The pipelines currently build these fees into their 

costs and if they believe they are not recovering the costs, they have an option provided to them under Section 4 of the Natural Gas Act to file for a rate increase with 

the Federal Energy Regulatory Commission. Since the Federal Energy Regulatory 

Commission has never turned down a request to include pipeline safety user fees 

in transportation rates charged by interstate pipelines, the decision whether or not 

to pass through all or a portion of the user fees to its customers is completely within 

the pipeline’s discretion. If for business reasons a natural gas transmission operator 

makes a business decision not to pass this safety cost through to one or more of 

its customers (e.g., it wishes to discount rates to certain customers, avoid filing a 

rate case, etc.), any consequence arising from that decision should be borne by that 

natural gas transmission operator. 

Shifting fees to distribution would mean that LDC customers would pay both the 

user fees assessed to the LDC and the fees passed on in transportation rates 

charged by their pipeline supplier. Gas customers served directly from a transmission line would pay a lesser amount of user fees per unit of gas than if the same 

customer were served through the LDC. The current user fee system also greatly 

simplifies fee collection as there are fewer transmission pipeline operators than 

there are LDCs. The current system of user fee collection has worked well for over 

20 years. 

Integrity Management of Low Stress Transmission Lines 

Currently, low stress transmission lines (a line operating below 30 percent of the 

specified minimum yield stress) operated by distribution systems are regulated 

under the Transmission Integrity Management Program (TIMP). It is APGA’s position that those pipelines should be regulated under the Distribution Integrity Management Program (DIMP). The benefit of handling this under DIMP is that TIMP 

focuses on finding mainly corrosion problems. The DIMP rule addresses corrosion 

but also requires distribution operators to consider other threats to integrity including excavation, natural forces, incorrect operations and more. When a high stress 

line corrodes it can suddenly rupture, whereas a low stress line would just start 

leaking, and the leak would get progressively worse over time. The utility has time 

to find it through ongoing leak surveys and patrols and fix it before it threatens 

public safety. Since the big issue with distribution is third-party damage, all the inspections for corrosion are of questionable benefit. 

Conclusion 

Natural gas is critical to our economy, and millions of consumers depend on natural gas every day to meet their daily needs. It is critical that they receive their 

natural gas through a safe, affordable and reliable delivery by their LDC. We look 

forward to working with the Committee toward reauthorization of the Pipeline Safety Act. 

Æ