BP’S PIPELINE SPILLS AT PRUDHOE 

BAY: WHAT WENT WRONG? 

HEARING 

BEFORE THE 

SUBCOMMITTEE ON OVERSIGHT AND 

INVESTIGATIONS 

OF THE 

COMMITTEE ON ENERGY AND 

COMMERCE 

HOUSE OF REPRESENTATIVES 

ONE HUNDRED NINTH CONGRESS 

SECOND SESSION 

SEPTEMBER 7, 2006 

Serial No. 109-135 

Printed for the use of the Committee on Energy and Commerce 

Available via the World Wide Web: http://www.access.gpo.gov/congress/house 

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31-461PDF 
COMMITTEE ON ENERGY AND COMMERCE 

JOE BARTON, Texas, Chairman 

RALPH M. HALL, Texas 

MICHAEL BILIRAKIS, Florida 

 Vice Chairman 

FRED UPTON, Michigan 

CLIFF STEARNS, Florida 

PAUL E. GILLMOR, Ohio 

NATHAN DEAL, Georgia 

ED WHITFIELD, Kentucky 

CHARLIE NORWOOD, Georgia 

BARBARA CUBIN, Wyoming 

JOHN SHIMKUS, Illinois 

HEATHER WILSON, New Mexico 

JOHN B. SHADEGG, Arizona 

CHARLES W. “CHIP” PICKERING, Mississippi 

 Vice Chairman

VITO FOSSELLA, New York 

ROY BLUNT, Missouri

STEVE BUYER, Indiana 

GEORGE RADANOVICH, California 

CHARLES F. BASS, New Hampshire 

JOSEPH R. PITTS, Pennsylvania 

MARY BONO, California 

GREG WALDEN, Oregon 

LEE TERRY, Nebraska 

MIKE FERGUSON, New Jersey 

MIKE ROGERS, Michigan 

C.L. “BUTCH” OTTER, Idaho 

SUE MYRICK, North Carolina 

JOHN SULLIVAN, Oklahoma 

TIM MURPHY, Pennsylvania 

MICHAEL C. BURGESS, Texas 

MARSHA BLACKBURN, Tennessee 

JOHN D. DINGELL, Michigan 

 Ranking Member 

HENRY A. WAXMAN, California 

EDWARD J. MARKEY, Massachusetts 

RICK BOUCHER, Virginia 

EDOLPHUS TOWNS, New York 

FRANK PALLONE, JR., New Jersey 

SHERROD BROWN, Ohio 

BART GORDON, Tennessee 

BOBBY L. RUSH, Illinois 

ANNA G. ESHOO, California 

BART STUPAK, Michigan 

ELIOT L. ENGEL, New York 

ALBERT R. WYNN, Maryland 

GENE GREEN, Texas 

TED STRICKLAND, Ohio 

DIANA DEGETTE, Colorado 

LOIS CAPPS, California 

MIKE DOYLE, Pennsylvania 

TOM ALLEN, Maine 

JIM DAVIS, Florida 

JAN SCHAKOWSKY, Illinois 

HILDA L. SOLIS, California 

CHARLES A. GONZALEZ, Texas 

JAY INSLEE, Washington 

TAMMY BALDWIN, Wisconsin 

MIKE ROSS, Arkansas 

BUD ALBRIGHT, Staff Director 

DAVID CAVICKE, General Counsel

REID P. F. STUNTZ, Minority Staff Director and Chief Counsel

SUBCOMMITTEE ON OVERSIGHT AND INVESTIGATIONS 

ED WHITFIELD, Kentucky, Chairman 

CLIFF STEARNS, Florida 

CHARLES W. “CHIP” PICKERING, Mississippi 

CHARLES F. BASS, New Hampshire 

GREG WALDEN, Oregon 

MIKE FERGUSON, New Jersey 

MICHAEL C. BURGESS, Texas 

MARSHA BLACKBURN, Tennessee 

JOE BARTON, Texas 

 (EX OFFICIO)

BART STUPAK, Michigan 

 Ranking Member 

DIANA DEGETTE, Colorado 

JAN SCHAKOWSKY, Illinois 

JAY INSLEE, Washington 

TAMMY BALDWIN, Wisconsin 

HENRY A. WAXMAN, California 

JOHN D. DINGELL, Michigan 

 (EX OFFICIO)

(II)
CONTENTS 

Page 

Testimony of: 

Malone, Robert A., Chairman and President, BP America, Inc. ........................................ 39 

Marshall, Steve, President, BP Exploration Alaska, Inc. ................................................... 58 

Hostler, Kevin, President and CEO, Alyeska Pipeline Service Co. ................................... 92 

Barrett, Vice Admiral Thomas J., Administrator, Pipeline and Hazardous Materials 

Safety Administration, U.S. Department of Transportation.......................................... 

505 

Fredriksson, Kurt, Commissioner, Alaska Department of Environmental Conservation.. 518 

Additional material submitted for the record: 

Marshall, Steve, President, BP Exploration Alaska, Inc., for the record ........................... 542 

Malone, Robert A., Chairman and President, BP America, Inc., response for the record. 552 

Fredriksson, Kurt, Commissioner, Alaska Department of Environmental Conservation, 

response, response for the record................................................................................... 555 

(III) 

(1) 

BP’S PIPELINE SPILLS AT PRUDHOE 

BAY: WHAT WENT WRONG? 

THURSDAY, SEPTEMBER 7, 2006 

HOUSE OF REPRESENTATIVES, 

COMMITTEE ON ENERGY AND COMMERCE, 

SUBCOMMITTEE ON OVERSIGHT AND INVESTIGATIONS, 

Washington, DC. 

 The committee met, pursuant to call, at 10:15 a.m., in Room 2123 of 

the Rayburn House Office Building, Hon. Greg Walden (Chairman) 

presiding. 

 Members present: Representatives Stearns, Pickering, Walden, 

Burgess, Blackburn, Barton (ex officio), Stupak, DeGette, Schakowsky, 

Inslee, Baldwin, and Dingell (ex officio). 

 Members also present: Representatives Upton, Markey, and Green. 

 Staff present: Mark Paoletta, Chief Counsel for Oversight and 

Investigations; Alan Slobodin, Deputy Chief Counsel for Oversight and 

Investigations; Tom Feddo, Counsel; Andrew Snowdon, Counsel; Tom 

Hassenboehler, Counsel; Dave McCarthy, Chief Counsel for Energy and 

the Environment; Clayton Matheson, Analyst; Ryan Ambrose, 

Legislative Clerk; Matthew Johnson, Legislative Clerk; Chris Knauer, 

Minority Investigator; David Vogel, Minority Research Assistant; Bruce 

Harris, Professional Staff Member; and Chris Treanor, Minority Staff 

Assistant. 

 MR. WALDEN. Good morning and welcome. 

 The Chairman of the subcommittee, Mr. Whitfield, very much 

wanted to be here but had some important legislation he has worked on 

for a considerable length of time on the House floor this morning so I 

will be chairing this hearing in his absence. 

 Today the Oversight and Investigations Subcommittee will examine 

what went wrong on two crude oil pipelines operated by BP that service 

the Prudhoe Bay fields on Alaska’s North Slope, the Nation’s largest 

source of domestic oil. Oil spills on two separate lines within a fivemonth period are a cause of major concern. These spills threaten not 

only the environment but also the reliability of domestic oil production. 

BP’s current marketing slogan is “Beyond petroleum.” Unfortunately, it 

could also stand for “broken pipelines.” 

 In March of this year, BP uncovered a leak in the western 

transmission line. This spill resulted in more than 200,000 gallons, or 

5,000 barrels of crude oil, breaking into the Arctic tundra, the single 
2

largest spill in the history of the North Slope. In early August, BP 

identified areas of significant corrosion on its eastern transmission line 

necessitating an immediate shutdown of that line, a shutdown that 

remains in effect today, cutting the daily production of Prudhoe Bay 

nearly in half. How did two key pipelines, pipelines that transport 8 

percent of this country’s domestic oil, deteriorate so badly that the entire 

production of Prudhoe Bay fields could be in jeopardy? Hopefully 

today’s hearings will yield some of those answers. 

 In public statements and in comments to committee staff during this 

investigation, BP has acknowledged that it made mistakes in its 

corrosion control program, and I commend them for admitting the 

obvious. Hindsight is always 20/20 but it appears BP ignored some red 

flags along the way. 

 First, there is evidence that BP received warnings from company 

employees about the condition of these lines. It is important for us to 

understand exactly what BP knew, when they knew it, what steps BP 

took to verify the allegations, and what actions BP took to respond to the 

concerns raised. 

 Second, BP seems to have ignored the results of its own inspections. 

In 1998, BP inserted the diagnostic probe, also known as a smart pig, 

into the western line to check for corrosion. These pig runs revealed 

moderate internal and external corrosion including six areas of internal 

corrosion at the very site where the March 2006 leak occurred. Despite 

this critical information, however, BP elected to wait until 2006, eight 

years, to conduct another pig run. Unfortunately, the leak occurred 

before that pig run took place and the eastern line was even worse. It had 

not been pigged since 1992. 

 Experts to a person have explained pig runs as an essential element 

of any sound corrosion control program. BP’s own internal corrosion 

procedures tout the merits of small pigging. The question then is, why 

did BP not pig these lines on a more regular basis. Was cost a factor or 

were there other concerns about the condition of these lines such as 

sediment and sludge buildup that prevented the use of pigs. 

 I hope that the BP officials appearing here, Robert Malone, President 

of BP America, and Steve Marshall, President of BP Exploration Alaska, 

will be able to answer some of these questions. Unfortunately, Mr. 

Woollam, BP’s former chief corrosion engineer on the North Slope, has 

elected to assert his Fifth Amendment right not to testify. We will also 

hear today from the Department of Transportation about the steps they 

took following these spills. I am encouraged by the Department of 

Transportation’s confident assertions that BP’s pipeline troubles are an 

isolated incident rather than an industry-wide problem and that the 

Department of Transportation’s Integrity Management Program has 
3

resulted in a steady decline of serious incidents. I look forward to 

learning from Kevin Hostler, President and CEO of Alyeska, what his 

company is doing to ensure the integrity of the Trans Alaska Pipeline in 

the wake of these incidents and how Alyeska is working with BP to help 

get the eastern operating line back in service. I also want to welcome 

Dan Stears from Coffman Engineers and Kurt Fredriksson, 

Commissioner of the Alaska Department of Environmental 

Conservation. Many of the witnesses have traveled a long way to 

participate in today’s hearings and the committee certainly appreciates 

their efforts. 

 Today’s hearing is of tremendous importance to this committee and 

to the American people. Companies that operate oil pipelines have a 

responsibility to maintain the Nation’s crucial energy infrastructure. 

Hopefully what we learn about BP’s incidents on the North Slope will 

help prevent future spills so that both the environment and the reliable 

supply of a vital natural resource will not be compromised again. 

 With that, I now recognize the Ranking Member of the 

Subcommittee on Oversight and Investigations, Mr. Stupak, for 5 

minutes. 

 [The prepared statement of Hon. Greg Walden follows:] 

PREPARED STATEMENT OF THE HON. GREG WALDEN, A REPRESENTATIVE IN CONGRESS 

FROM THE STATE OF OREGON

 Good morning and welcome. The Chairman of the Subcommittee, Mr. Whitfield, 

very much wanted to be here, but has some important legislation on the House floor this 

morning, so I will be chairing this hearing in his absence. 

 Today, the Oversight and Investigations Subcommittee will examine what went 

wrong on two crude oil pipelines operated by BP that service the Prudhoe Bay fields on 

Alaska’s North Slope, the nation’s largest source of domestic oil. Oil spills on two 

separate lines within a 5-month period are a cause of major concern. These spills 

threaten not only the environment, but also the reliability of domestic oil production. 

BP’s current marketing slogan is “Beyond Petroleum.” Unfortunately, it could also stand 

for “Broken Pipelines.” 

 In March of this year, BP uncovered a leak in the Western transmission line. This 

spill resulted in over 200,000 gallons (or 5,000 barrels) of crude oil leaking onto the Artic 

tundra -- the single largest spill in the history of the North Slope. In early August, BP 

identified areas of significant corrosion on its Eastern transmission line, necessitating an 

immediate shut-down of that line -- a shut-down that remains in effect today, cutting the 

daily production of Prudhoe Bay nearly in half. How did two key pipelines -- pipelines 

which transport nearly 8% of this country’s domestic oil -- deteriorate so badly that the 

entire production of the Prudhoe Bay fields could be in jeopardy? Hopefully today’s 

hearing will yield some answers. 

 In public statements and in comments to Committee staff during this investigation, 

BP has acknowledged that it made mistakes in its corrosion-control program. I commend 

them for at least admitting the obvious. Hindsight is always 20/20, but it appears that BP 

ignored some red flags along the way. First, there is evidence that BP received warnings 

from company employees about the condition of these lines. It is important for us to 
4

understand exactly what BP knew, when they knew it, what steps BP took to verify the 

allegations, and what actions BP took to respond to the concerns raised. 

 Second, BP seems to have ignored the results of its own inspections. In 1998, BP 

inserted a diagnostic probe -- also known as a “smart pig” -- into the Western Line to 

check for corrosion. This pig run revealed moderate internal and external corrosion, 

including 6 areas of internal corrosion at the very site where the March 2006 leak 

occurred. Despite this critical information, however, BP elected to wait until 2006 -- 8 

years -- to conduct another pig run. Unfortunately, the leak occurred before that pig run 

took place. And the Eastern Line was even worse -- it had not been pigged since 1992! 

 Experts, to a person, have explained pigging is an essential element of any sound 

corrosion control program. BP’s own internal corrosion procedures tout the merits of 

smart pigging. The question, then, is why did BP not pig these lines on a more regular 

basis? Was cost a factor, or were there other concerns about the condition of these lines -

- such as sediment and sludge buildup -- that prevented the use of pigs? I hope that the 

BP officials appearing here -- Robert Malone, President of BP America, and Steve 

Marshall, President of BP Exploration Alaska -- will be able to answer some of these 

questions. Unfortunately, Mr. Wollam, BP’s former chief corrosion engineer on the 

North Slope, has elected to assert his Fifth Amendment right not to testify. 

 We will also hear today from the Department of Transportation about the steps that 

they took following these spills. I am encouraged by DOT’s confident assertions that 

BP’s pipeline troubles are an isolated incident rather than an industry-wide problem and 

that DOT’s Integrity Management Program has resulted in a steady decline of serious 

incidents. 

 I look forward to learning from Kevin Hostler, President and CEO of Alyeska, what 

his company is doing to ensure the integrity of the Trans Alaska Pipeline in the wake of 

these incidents and how Alyeska is working with BP to help get the Eastern Operating 

Line back in service. 

 I also want to welcome Dan Stears from Coffman Engineers and Kurt Frederickson, 

Commissioner of the Alaska Department of Environmental Conservation. Many of the 

witnesses have traveled a long way to participate in today’s hearing, and the Committee 

certainly appreciates their efforts. 

 Today’s hearing is of tremendous importance to this Committee and the American 

people. Companies that operate oil pipelines have a responsibility to maintain the 

nation’s crucial energy infrastructure. Hopefully, what we learn about BP’s incidents on 

the North Slope will help prevent future spills so that both the environment and the 

reliable supply of a vital natural resource won’t be compromised again. 

 I now recognize the Ranking Member of the Subcommittee on Oversight and 

Investigations, Mr. Stupak, for 5 minutes. 

 MR. STUPAK. Thank you, Mr. Chairman, and thank you for holding 

this hearing. 

 On March 2 of this year, BP discovered that oil was leaking from a 

major transmission line largely responsible for connecting the west oil 

field with the Trans Alaskan Pipeline, TAPS. This spill included almost 

2,700 gallons of crude and became the largest spill in North Slope 

history. Shortly thereafter, a letter was sent by Ranking Member Dingell 

seeking answers to the causes of the WOA, western operating area, line 

failure and BP’s efforts to deal with corrosion. Over the next several 

months, what started as a single spill ended in the shutdown of the entire 
5

Prudhoe Bay field, and for a time, reduction of 8 percent of the U.S. 

domestically produced oil supply. 

 Mr. Chairman, this hearing is about far more than oil spills or 

pipeline corrosion. It is about trying to understand how a company with 

the global standing of BP allowed its North Slope operations to 

deteriorate to where the company professes little understanding of the 

true condition of major operational assets. It is also about why, when the 

Nation is facing ongoing threats to its oil supply abroad, we don’t have a 

better redundancy in an oil field as strategic as Prudhoe Bay. Given the 

record profits of this industry, this aspect of BP’s recent North Slope 

failures was particular egregious. 

 Mr. Chairman, this committee’s investigation into the failures of 

BP’s Alaska operations began shortly after the Department of 

Transportation issuance of their March 15 corrective action order. 

Among the many requirements, that order mandated that BP smart pig a 

number of key lines including both the western operating area line and 

the eastern operating area line. 

 In April of this year, committee staff traveled to Alaska to seek 

answers to the causes of the western operating area line failure and 

determine the implications of the DOT order. In that process, it was 

learned that huge amounts of solids were believed to exist in key lines 

that BP was now ordered to pig. These solids, it was believed, could 

create a number of potential operational challenges. In particular, BP 

might not be able to run smart pigs through these lines because the solids 

were potentially so excessive as to risk pigs becoming stuck in the lines. 

If that occurred, this would essentially block the transit line’s ability to 

deliver oil to the Trans Alaska Pipeline and perhaps shut down large 

parts of the oil field. It was also learned that the dislodging of such 

solids would later have profound consequences on TAPS itself including 

the introduction of corrosion-causing materials into that system and the 

potential for clogging Pump Station number 1 entry screeners. These 

new issues prompted Ranking Member Dingell to send a letter on April 

25 to the Department of Transportation Secretary which posed a number 

of key questions about not only the ability of BP to meet DOT’s March 

15 order but also about the overall condition of BP’s major transit lines. 

 The DOT’s response to that letter raised several troubling issues, 

most notably that BP appeared to lack a fundamental understanding of 

the condition of both its western operating area or eastern operating area 

lines. Moreover, it became clear that despite what appeared to be 

knowledgeable buildup of scale and solids over the years, the company 

inexplicably failed to pig these lines frequently, if at all. In its response, 

DOT also noted that, based on current management information, the 
6

infrequency by BP to pig these lines, and I quote now, “did not represent 

sound management practice for internal corrosion control.” 

 I would like to ask, Mr. Chairman, that this and all the letters from 

Mr. Dingell on this subject be placed in the record. 

 MR. WALDEN. Without objection. 

 MR. STUPAK. Mr. Chairman, I have a number of key questions for 

BP that I hope we will find answers to at this hearing. First, why was it 

that BP relied so heavily on ultrasonic thickness, UT testing, and the use 

of corrosion coupons when BP knew such techniques could not deliver 

data on the underground portions of the western operating area line 

where the caribou cross? The most recent run on the western operating 

area line was last done in 1998 and found that corrosion had increased, 

particularly in low-lying areas similar to the area where the March 2 spill 

occurred. Moreover, why did BP not install a more aggressive plan to 

seek data on these sections, given that the WOA line had a low flow rate 

and was thus subject to water and solid separation? It is not Monday 

morning quarterbacking to suggest that BP should have known it needed 

a plan to physically collect detailed data on these locations, even if it 

included moving soil to access the pipe for more aggressive pigging. 

 Second, why would the EOA, the eastern operating area line, a line 

that failed in August and prompted the entire field shutdown, why was 

that line not smart-pigged at all by BP until DOT ordered it do so? The 

EOA line is a primary transmission line. It is a key asset in BP’s field 

yet this line was left for almost 15 years with not so much as a 

maintenance pig being run through its length. Indeed, the EOA line has 

both a pig launcher and a pig receiver and so was clearly designed for 

pigging. What explains this failure? So far we have not had a 

satisfactory explanation from BP. 

 Third, why is it that there were virtually no redundancies in either the 

eastern oil field or the western oil field which would have allowed BP to 

continue operating after the most recent corrosion problems were 

discovered? As we note today, BP is now seeking to construct a number 

of bypass solutions to reroute oil around the failed eastern operating area 

line. 

 Fourth, why are we suddenly now deciding to replace these lines 

with new pipe knowing that for years such pipes were aging and that 

their original diameter was not designed for the low flow rates both were 

experiencing before they were removed from service? These pipes were 

designed for 800-pounds-per-square-inch flow rate. Today they are only 

at 80- PSI flow rate. Indeed, some have accused BP of running these 

lines to failure or riding the throughput curve. Nonetheless, at a time of 

record profits, I find it remarkable that the first major plan to replace a 
7

mere 20 miles of pipe of such strategic importance as these two lines 

comes post failure. 

 Fifth, when did BP first learn that the solids in these pipes would 

make immediate pigging extremely difficult? In short, why did it 

become such an engineering ordeal to merely determine if pigs could be 

run? If BP knew its lines were increasingly collecting shale, sludge or 

solids, all of which are known to contribute to corrosion, why wouldn’t it 

aggressively attempt to remove such materials regularly? Alyeska, the 

operator of the Trans Alaska Pipeline, sends a scraper pig down its entire 

800-mile length every 14 days, yet the eastern operating area line was 

not pigged a single time in 14 years. Why not? 

 Sixth, more troubling, BP apparently claims it did not know how bad 

its lines were. If BP only became aware of the scale and sediment after 

the DOT order, then why did it know so little so late? Shouldn’t it have 

known about the sediment buildup in the western operating area line 

given the kinds of crude they were pulling from the field? If BP truly 

had a world-class pipe integrity system, shouldn’t it have known about 

the shale buildup in the EOA line, given its earlier history of huge 

problems when it was last pigged in 1992? 

 Seventh, we are now learning that there were a number of troubling 

personnel problems in BP’s corrosion management program on the North 

Slope over the past several years. Though not fully understood, these 

problems apparently create a chilling atmosphere for workers’ ability to 

report health and safety issues and had perhaps at least some impact on 

the effectiveness of BP’s corrosion control efforts. For example, the 

committee is in receipt of an October 20, 2004, report by the Vinson and 

Elkins Law Firm that found that the very people that BP relied upon to 

detect corrosion in both the WOA and EOA line, the Corrosion 

Inspection and Chemical Group, were fraught with worker intimidation 

and harassment from senior management. 

 Eighth, rather than rely on smart pigs to find corrosion in its lines, 

BP relied on what are called corrosion coupons. Coupons are pieces of 

metal that are inserted into a pipe at various locations and are later 

removed and analyzed to determine how much corrosion is taking place 

inside the pipe. Unlike smart pigging, which gives you a view of the 

entire line, coupons only tell you how corrosion is affecting the general 

area where the coupon is located. Nonetheless, according to reports on 

worker intimidation and harassment that I just mentioned, the number of 

coupons used in BP’s operation was reduced by 25 percent for reasons 

that remain unclear. At a time when BP pipes were aging and it was 

already relying on a limited program to detect corrosion, why would the 

company allow such a significant reduction? 
8

 Finally, and I appreciate you letting me go over a little bit, Mr. 

Chairman, what budget pressures were placed on the corrosion 

monitoring group at BP and did such pressures ultimately lead to a 

serious deficiency in BP’s ability to truly assess corrosion risk? For 

example, there is a 2005 memo that I am sure we will get into. There is 

an audit, and all these I am sure we will get into during questions and 

answers. 

 Mr. Chairman, I have gone over my time. Thank you for allowing 

me extra time. I ask to have my entire statement be submitted for the 

record. 

 MR. WALDEN. Without objection. 

 MR. STUPAK. Thank you. 

 [The prepared statement of Hon. Bart Stupak follows:] 

PREPARED STATEMENT OF THE HON. BART STUPAK, A REPRESENTATIVE IN CONGRESS FROM 

THE STATE OF TEXAS

 Thank you Mr. Chairman, and thank you for having this hearing. 

 On March 2nd of this year, BP discovered that oil was leaking from a major 

transmission line largely responsible for connecting its west oilfield (WOA)with the 

Trans-Alaskan Pipeline (TAPS). That spill, included almost 270,000 gallons of crude 

and became the largest spill in North Slope history. Shortly thereafter, a letter was sent 

by ranking Member Dingell seeking answers to the causes of the WOA line’s failure and 

BP’s efforts to deal with corrosion. Over the next several months, what started as a 

single spill ended in the shutdown of the entire Prudhoe Bay field, and for a time, the 

reduction of 8% of the U.S. domestically-produced oil supply. 

 Mr. Chairman, this hearing is about far more than oil spills or pipeline corrosion. It 

is, about trying to understand how a company with the global standing of BP allowed its 

north slope operations to deteriorate to where the company professes little understanding 

of the true condition of major operational assets. It is also about why, when the nation is 

facing threats to its fuel supply abroad, we don’t have better redundancy in a field as 

strategic as Prudhoe Bay. Given the record profits of this industry, this aspect of BP’s 

recent north-slope failures is particularly egregious. 

 Mr. Chairman, this Committee’s investigation into the failures of BP’s Alaska 

operations began shortly after the Department of Transportation’s (DOT) issuance of 

their March 15th Corrective Action Order. Among many requirements, that order 

mandated that BP “smart pig” a number of key lines, including both the Western 

Operating Area (WOA) line and the Eastern Operating Area (EOA) line. 

 In April of this year, Committee staff traveled to Alaska to seek answers to the 

causes of the WOA line’s failure and determine the implications of the DOT order. In 

that process, it was learned that huge amounts of solids were believed to exist in key lines 

that BP was now ordered to pig. These solids -- it was believed -- could create a number 

of potential operational challenges. In particular, BP might not be able to run smart pigs 

through these lines because the solids were potentially so excessive, the cleaning pigs 

risked becoming stuck in the lines. If that occurred, this would essentially block the 

transit line’s ability to deliver oil to the Trans Alaskan Pipeline and perhaps shut down 

large parts of the oilfield. It was also learned that the dislodging of such solids could 

later have profound consequences on TAPS itself, including the introduction of 

corrosion-causing materials into that system and the potential for clogging Pump-Station 

One’s entry strainers. 
9

 These new issues prompted ranking Member Dingell to send an April 25th letter to 

the Department of Transportation’s Secretary, which posed a number of key questions 

about not only the ability of BP to meet DOT’s March 15th order, but also about the 

overall condition of BP’s major transit lines. 

 The DOT’s response to that letter raised several troubling issues. Most notably, that 

BP appeared to lack a fundamental understanding of the condition of both its WOA or 

EOA lines. Moreover, it became clear that despite what appeared to be knowledgeable 

buildup of scale and solids over the years, the company inexplicably failed to pig these 

lines frequently (if at all). In its response, DOT also noted that based on current 

management information, that the infrequency by BP to pig these lines “[did] not 

represent sound management practices for internal corrosion control.” [I would ask that 

this and all of Mr. Dingell’s letters on this subject be placed into the record.] 

 Mr. Chairman, I have a number of key questions for BP that I hope we will find 

answers to at this hearing and I will raise several of them here: 

 First, why is it that BP relied so heavily on ultrasonic thickness (UT) testing and the 

use of corrosion coupons when BP knew such techniques could not deliver data on the 

under ground portions of the WOA line (such as the caribou crossings)? The most recent 

run on the WOA line was last done in 1998 and found that corrosion had increased, 

particularly in low-lying areas similar to the area where the March 2nd spill occurred. 

Moreover, why did BP not install a more aggressive plan to seek data on these sections 

given that the WOA line had a low-flow rate and was thus subject to water and solids 

separation? It is not Monday-morning quarter backing to suggest that BP should have 

known it needed a plan to physically collect detailed data on these locations, even if it 

included removing soil to access the pipe or more aggressive pigging. 

 Second, why was the EAO line -- the line that failed in August and prompted the 

entire field’s shutdown -- not smart-pigged at all by BP until DOT ordered it to do so? 

The EOA line is a primary transmission line. It is a key asset in BP’s field. Yet this line 

was left for almost fifteen years with not so much as a maintenance pig being run through 

its length. Indeed, the EOA line has both a pig launcher and a pig receiver, and so was 

clearly designed for pigging. What explains this failure? So far we do not have a 

satisfactory explanation from BP. 

 Third, why is it that there were virtually no redundancies in either the eastern field 

or the western field which would have allowed BP to continue operating after the most 

recent corrosion problems were discovered? As we know today, BP is now seeking to 

construct a number of bypass solutions to re-route oil around the failed EOA line. 

 Fourth, why are we suddenly now deciding to replace these lines with new pipe 

knowing that for years such pipes were aging and that their original diameter was not 

designed for the low flow rates both were experiencing before they were removed from 

service? These pipes were designed for 800 psi flow rate. Today they are at only 80 psi 

flow rate. Indeed, some have accused BP of “running these lines to failure,” or “riding 

the throughput curve.” Nonetheless, at a time of record profits, I find it remarkable that 

the fist major plans to replace a mere 20 miles of pipe of such strategic importance as 

these two lines, comes post failure. 

 Fifth, when did BP first learn that the solids in these pipes would make immediate 

pigging extremely difficult? In short, why did it become such an engineering ordeal to 

merely determine if pigs could be run? If BP knew its lines were increasingly collecting 

scale, sludge, or solids -- all of which are known to contribute to corrosion -- why 

wouldn’t it aggressively attempt to remove such material regularly? Alyeska -- the 

operator of the trans-Alaskan pipeline sends a scraper pig down its entire 800-mile length 

every 14 days. Yet, the EAO line was not pigged a single time in 14 years. Why? 

 Sixth, more troubling, BP apparently claims it did not know how bad its lines were? 

If BP only became aware of the scale and sediment after the DOT order, then why did it 

know so little, so late? Shouldn’t it have known about the sediment build-up in the WOA 
10

line given the kinds of crude they were pulling from the field? If BP truly had a worldclass pipeline integrity system, shouldn’t it have known about the scale build up in the 

EOA line given its earlier history of huge cleaning problems when it was last pigged in 

1992? 

 Seventh, we are now learning that there were a number of troubling personnel 

problems in BP’s corrosion management program on the north slope over the past several 

years. Though not fully understood, these problems apparently created a “chilling” 

atmosphere in workers’ ability to report health and safety issues, and perhaps had at least 

some impact on the effectiveness of BP’s corrosion-control efforts. For example, the 

Committee is in receipt of an October 20, 2004 report by the Vincent and Elkins law firm 

that found that the very program that BP relied upon to detect corrosion in both the WOA 

and EOA lines -- the Corrosion Inspection and Chemicals Group (CIC) -- was fraught 

with workplace intimidation and harassment from senior management. 

 Eighth, rather than rely on smart pigs to find corrosion in its lines, BP relied upon 

what are called corrosion coupons. Coupons are pieces of metal that are inserted into the 

pipe at various locations and are later removed and analyzed to determine how much 

corrosion is taking place inside the pipe. Unlike smart pigging which gives you a view of 

the entire line, coupons only tell you how corrosion is affecting the general area where 

the coupon is located. Nonetheless, according to the report on worker intimidation and 

harassment I just mentioned, the number of coupons used in BP’s operations was reduced 

by 25% for reasons that remain unclear. At a time when BP’s pipes were aging and it 

was already relying on a limited program to detect corrosion, why would the company 

allow for such a significant reduction? 

 Finally, what budget pressures were placed on the corrosion monitoring group at BP 

and did such pressures ultimately lead to serious deficiencies in BP’s ability to truly 

assess corrosion risks? For example, an April 2005 internal audit of BP’s corrosion 

management system found the following: 

 “Currently [the program’s] budget is set up-front in line with flat lifting cost 

strategy, with corrosion management activities then developed around this budget 

allocation. This strategy to maintain flat lifting costs is driving behaviours 

counterproductive to ensuring integrity and the delivery of an effective management 

system. A more effective and efficient process would be to derive the set of activities 

required to deliver a robust corrosion management system over the longer term, and 

thereafter set the budget based on these activities.” 

 Mr. Chairman, this audit suggests to me, that some in BP had grown concerned that 

cost cutting was having a troubling affect on the company’s ability to design and 

maintain a sound corrosion control program. 

 Mr. Chairman, I could continue on here, but I will save other key findings for the 

question period. Nonetheless, I would like to wind down my statement by welcoming 

our witnesses. 

 In particular, I would like to welcome Mr. Bob Malone, who is now the newlyappointed President of BP America. I would like to point out -- Mr. Malone -- that you 

have an excellent reputation with this Committee. During the early 1990s when it was 

Alyeska -- the operator of the Trans-Alaskan Pipeline -- that was in so much trouble, it 

was in part your leadership as president that helped turn the company around. Over the 

years you have voluntarily worked closely with this Committee to keep us apprised of 

developments both while at Alyeska and later, while at BP. I thank you for your 

assistance in that regard and your interaction with this Committee was helpful and 

appreciated. 

 Nonetheless, in your current position, I truly believe that the situation on the North 

Slope demands your full attention, as it is frankly an embarrassment to your company. 

Like with the mess you found at Alyeska, this Committee is expecting that you will fully 

investigate and evaluate what broke down on the north slope and then pursue major fixes, 
11

whether financial or personnel. This nation cannot allow the kinds of fiascos we have 

witnessed over the past several months to continue with the nation’s energy supply. This 

Committee is expecting answers and results and ultimately getting this field back up 

running in a professional and reliable manner. The public will expect nothing less, and 

neither should this Committee. 

 Mr. Chairman, thank you again for holding this hearing, and with that, I yield back. 

 MR. WALDEN. We will try to stick to the 5 minutes, but I know a lot 

of work has gone into this on both sides of the aisle, and as the Ranking 

Member, I thought it appropriate to accede you additional time. 

 MR. STUPAK. Thank you. 

 MR. WALDEN. I would now like to recognize the Chairman of the 

full committee, the very able and honorable Joe Barton. Mr. Barton. 

 CHAIRMAN BARTON. Thank you, Mr. Chairman, for chairing this 

hearing today. I hope that the testimony is going to provide us some 

answers about the recent crude spills on the North Slope of Alaska. I 

also hope that it is going to provide some answers about what is being 

done and what will continue to be done to prevent those very serious 

incidents from happening in the future. 

 The spills occurred on two transmission lines that move oil produced 

from Prudhoe Bay to the Trans Alaska Pipeline. BP Exploration of 

Alaska Incorporated, which is an operating unit of British Petroleum, is 

responsible for the operation and maintenance of those crude oil 

transmission lines. I think it is obvious, but we do need to emphasize 

that these lines move approximately 400,000 barrels of crude oil per day 

to markets. That is roughly 8 percent of the United States’ domestic oil 

production. Given that fact, the safe, responsible and reliable operation 

of these pipelines is of paramount concern to this committee and to the 

country. It is critical that no further leaks occur on these lines. It is 

paramount to avoid the threat to human life and the environment. It is 

also important to our national security that the oil from Prudhoe Bay be 

reliably and safely transported on a daily basis. 

 On Sunday, August 6, BP announced the complete shutdown of the 

Prudhoe Bay oil field. The following Monday, the price that BP and 

others commanded on the world market for their crude oil jumped 3 

percent to nearly $77 a barrel. This decision came on the heels of an 

accident last March when BP’s western transmission lines at Prudhoe 

Bay leaked about 200,000 gallons of oil from a corroded pipe. Between 

that incident and the leak in August from the eastern transmission line, 

BP had repeatedly assured this committee, our staffs and me personally 

that the corrosion of that pipeline that failed in March was an anomaly. 

BP told us that their corrosion control program was effective, that they 

were monitoring on a constant basis and they were mitigating corrosion 

in the pipelines at Prudhoe Bay. If the March leak was an anomaly, why 
12

did BP suddenly shut down production from the entire Prudhoe Bay oil 

field in August due to excessive corrosion discovered in the eastern 

crude oil transmission lines? In fact, we now know that BP had failed to 

carefully inspect and maintain these pipelines. The decision to shut 

down the pipeline in August seems to be the direct result of a 

requirement to pig the eastern line because of last March’s spill on the 

western line. 

 Pipeline experts and other pipeline operators have explained to us 

that internal inspection of pipelines, what is called smart pigging, is the 

most reliable, complete and informative way to assess the integrity of a 

pipeline’s walls, interior walls. U.S. Department of Transportation 

officials explained to the committee staff that BP’s failure to pig these 

lines regularly is unsound management. Other methods are available but 

pigging has a distinct advantage. I understand that pigging is relatively 

inexpensive on a pipeline that has been designed for it. We might point 

out at this point in tine that last year BP reported record earnings of over 

$25 billion, $25 billion, and that the Prudhoe Bay field is and was the 

lodestar of the BP production. Prior to this year’s incidents, not either 

the western or the eastern gathering line that BP has been operating had 

been smart pigged for years. The western line was last maintenance 

pigged and smart pigged in 1998. That is eight years ago, or seven years 

ago. The eastern line was last maintenance pigged in 1990 and smart 

pigged in 1992, 14 years ago. By comparison, executives at Alyeska, the 

pipeline company operating the larger Trans Alaska Pipeline System, 

informed subcommittee staff that their line is maintenance pigged every 

two weeks, every two weeks, and smart pigged at least once every three 

years. 

 We now know that BP officials have admitted, and I am expecting 

that they will again say so today, that their corrosion control and 

inspection program for Prudhoe Bay was flawed and that in hindsight, 

BP should have been pigging these transmission lines in hindsight. Well, 

hindsight is better than blind sight, I guess, but it is not a substitute for 

ongoing sound management practices. 

 I suppose that this committee and Congress is expected to shrug our 

shoulders and say, well, now they get it, but the clever use of perfect 

hindsight to excuse consistent failure just doesn’t cut it. Years of 

neglecting to inspect for the most vital gathering oil pipelines in this 

country is not acceptable. BP’s neglect is having as we speak an adverse 

and disruptive effect on the American economy, American consumers 

and national security. That is not acceptable. If a company, one of the 

world’s most successful oil companies, can’t do simple, do basic 

maintenance needed to keep the Prudhoe Bay field operating safely 

without interruption, maybe it shouldn’t operate the pipeline. Maybe we 
13

should find a way to get a different operator through the private market 

sale of this pipeline and let somebody else do it. 

 This hearing will largely focus on BP’s failure to responsibly operate 

the Prudhoe Bay transmission lines but these two incidents of which the 

March spill also happens to be the continuing subject of a Federal grand 

jury are only part of this company’s recent and unfortunately notorious 

track record. The Prudhoe Bay spill comes on the heels of the British 

Petroleum Texas City Refinery disaster that killed 15 people in 2005. 

 Now, I know that BP is investing significant amounts of time, energy 

and resources to bring Prudhoe Bay back at the full capacity and to 

address the very serious corrosion problems that have been discovered, 

but this is all after the fact. I understand that sludge and sediment issues 

existed in the lines for quite some time, that BP knew about the flaws in 

its corrosion control program. Impurities like sludge, sediment and water 

induce corrosion and provide a place for corrosion to hide. 

 Maybe I have the wrong impression, but it seems to me that BP was 

betting the company and their field that this field would be depleted 

before major parts of the pipeline failed and needed to be replaced. BP’s 

policies are as rusty as its pipelines. I am very concerned about the 

specific incident but I am even more concerned about BP’s corporate 

culture of seeming indifference to safety and environmental issues, and 

this comes from a company that prides itself in their ads on protecting 

the environment. Shame, shame, shame. 

 And I want to say something else before I conclude, Mr. Chairman. 

During the course of this investigation, the committee has been informed 

by certain individuals that we were trying to interview at the staff level 

that they are reluctant to come forward to provide information due to 

concerns over possible retribution throughout the oil industry in Alaska. 

I want to make it perfectly clear that if we find that any person is 

threatened, intimidated or attempted to be retaliated against as a result of 

cooperating with this committee, I will use every bit of power that I have 

as Chairman of the full committee to ensure that the retaliator is 

prosecuted to the fullest extent of the law, and to the extent that that 

retaliation against an individual is condoned by any corporate official, I 

will exercise the same authority against those officials. We are going to 

get to the bottom of this. We are going to make sure that the facts are in 

the public purview and we are going to, if necessary, change Federal law 

to do everything possible to minimize this happening again. 

 Mr. Chairman, I look forward to today’s testimony. I hope we get 

the answers we need. If not, I am sure the subcommittee will continue to 

conduct aggressive oversight on a bipartisan basis on this issue. 

 With that, I yield back the balance of my time. 

 [The prepared statement of Hon. Joe Barton follows:] 
14

PREPARED STATEMENT OF THE HON. JOE BARTON, CHAIRMAN, COMMITTEE ON ENERGY 

AND COMMERCE

 Thank you, Mr. Chairman, for holding this hearing. I hope that the testimony today 

will provide us with some satisfactory answers about several recent crude oil spills on the 

North Slope of Alaska, and what is going to be done to prevent these very serious 

incidents in the future. The spills occurred on two transmission pipelines that move oil 

produced from Prudhoe Bay to the Trans-Alaska Pipeline System. BP Exploration 

(Alaska), Inc. – an operating unit of BP – is responsible for the operation and 

maintenance of those crude oil transmission lines. 

 I want to emphasize that these lines move nearly 400,000 barrels of crude oil a day 

to market. That’s roughly 8 percent of the country’s domestic oil production. Given that 

fact, the safe, responsible, and reliable operation of these pipelines is of paramount 

concern to this Committee. 

 It is critical that no further leaks occur on these lines. We certainly want to avoid 

the threat to human lives and the environment, but it is also imperative to our national 

security that this oil be reliably transported. On Sunday, August 6th, BP announced the 

complete shutdown of the Prudhoe Bay oil field, and the following Monday the price BP 

and others commanded on the world market jumped 3 percent, to nearly $77 per barrel. 

 Americans had already been facing record-high gasoline prices. Did BP think that 

shutting in 8 percent of U.S. production would relieve American consumer prices? We 

don’t need prices suddenly kicked higher because the company responsible for bringing a 

vital part of this country’s oil to market isn’t taking care of the pipelines. BP owes 

Americans a higher standard of operation. These are energy resources which this country 

needs and they control. 

 In March of this year, BP’s Western transmission line at Prudhoe Bay leaked about 

200,000 gallons of oil from a corroded pipe. Between that incident and the leak in 

August from the Eastern transmission line, BP had repeatedly assured me, through staff, 

that the corrosion of the pipeline that failed in March was an anomaly. BP told us that 

their corrosion control program was effectively monitoring and mitigating corrosion in 

the pipelines at Prudhoe Bay. 

 If the March leak was an anomaly, why did BP suddenly shut down production from 

the entire Prudhoe Bay oil field in August due to excessive corrosion discovered in the 

Eastern crude oil transmission lines? In fact, what we now know is that BP has failed to 

carefully inspect and maintain these pipelines. 

 Pipeline experts and other pipeline operators have explained to us that internal 

inspection of pipelines – what is called smart-pigging – is the most reliable, complete, 

and informative way to assess the integrity of a pipeline’s walls. U.S. Department of 

Transportation officials have explained to us that for BP’s failure to pig these lines 

regularly is unsound management. Other methods are available, but pigging has distinct 

advantages. I understand that pigging is relatively inexpensive on a pipeline that has 

been designed for it. 

 Yet prior to this year’s incidents, BP’s pipelines had not been smart-pigged for many 

years. The Western line was last maintenance-pigged and smart-pigged in 1998. The 

Eastern line was last maintenance-pigged in 1990 and smart-pigged in 1992. By 

comparison, executives at Alyeska, the pipeline company operating the Trans-Alaska 

Pipeline System, informed the Subcommittee that TAPS is maintenance-pigged every 

two weeks, and smart-pigged every three years. I know that BP officials have admitted, 

as I expect they will also do here today, that their corrosion control and inspection 

program for Prudhoe Bay was flawed, and that in hindsight BP should have been pigging 

these transmission lines. 

 I suppose that we’re expected to shrug and say, "Well, now they get it." But the 

clever use of perfect hindsight to excuse consistent failure just doesn’t cut it. Years of 
15

neglecting to inspect two of the most vital oil pipelines in this country is simply 

unacceptable. Nor are the adverse and disruptive effects on the American economy, 

American consumers, and national security in any way acceptable. If a company -- a 

very successful company -- can’t do the basic maintenance needed to keep Prudhoe Bay’s 

oil field operating safely and without interruption, then maybe it shouldn’t be operating 

the pipeline. 

 This hearing will largely focus on BP’s failure to responsibly operate the Prudhoe 

Bay transmission lines, but these two incidents – of which the March spill also happens to 

be the subject of a federal grand jury – are only part of the company’s recent and 

notorious track record. The Prudhoe Bay spills come on the heels of the BP Texas City 

refinery disaster that killed 15 people in 2005. 

 I know that BP is investing significant amounts of time, energy, and resources to 

bring Prudhoe Bay back up to full capacity and to address the very serious corrosion 

problems that have been discovered, but that is all after the fact. I understand that sludge 

and sediment issues existed in the lines for quite some time, and that BP knew about the 

flaws in its corrosion control program. Impurities like sludge, sediment, and water 

induce corrosion, and provide a place for corrosion to hide. Maybe I have the wrong 

impression, but it seems that BP might have been betting that the field would be depleted 

before major parts of the pipeline failed and needed replacement. BP’s policies are as 

rusty as its pipelines. 

 Mr. Chairman, I look forward to today’s testimony. I hope we can get all the 

answers we need; and if not, then I hope that the Subcommittee will continue to conduct 

its oversight work on these issues. I yield back the remainder of my time. 

 MR. WALDEN. Thank you, Mr. Chairman. 

 I would like to ask unanimous consent that members of the 

subcommittee who may not be present or are present and have written 

testimony or opening statements they would like to be submitted for the 

record may do so without objection, and I have the statement of the 

Honorable Ed Whitfield, Chairman of the Subcommittee on Oversight 

and Investigation, that we will enter into the record. We will have seven 

days for that. 

 At this point I would turn to the Ranking Member of the committee, 

the Honorable Mr. Dingell, for opening statement. 

 MR. DINGELL. Mr. Chairman, thank you. I commend you for 

holding this hearing. 

 I must confess myself disappointed at our reasons for being here 

today. We face many challenging energy issues ranging from high prices 

of oil and natural gas to the continued development of renewable fuels 

and the nagging problem of nuclear waste. That we find ourselves 

conducting oversight of an oil company that seems to be having trouble 

managing its core business in this day and age is indeed discouraging. 

Nevertheless, events relating to BP’s performance over the last six 

months necessitate this hearing and I hope that we will learn what went 

wrong and what has to be done to assure that it does not happen again. 

 I welcome our witnesses here today, particularly Mr. Malone, 

President of BP North America. Mr. Malone is not a stranger to this 

committee during difficult times. I note that he has been straightforward 
16

and honest in his previous appearances and has kept his commitments 

made to the committee. His challenge today is quite difficult and I hope 

that his participation will assist this committee to get to the bottom of 

what went wrong here. 

 On March 2, 2006, a BP worker discovered a leak in an oil 

transmission line in the western operating area of Prudhoe Bay, Alaska. 

This previously unregulated pipeline had been leaking for approximately 

five days prior to the discovery and it spilled something like 270,000 

gallons of crude oil into the Arctic tundra, making it the worst spill in the 

history of the North Slope. 

 On March 15, the Department of Transportation placed its line and 

other low-stress BP lines under its jurisdiction and required BP to 

thoroughly inspect the lines, to clean them and to analyze their condition 

using a smart pig. After extensive testing and the discovery of two 

additional leaks, BP reached the conclusion that the status of its transit 

lines was indeterminate and decided to proceed with an orderly shutdown 

of Prudhoe Bay. World oil markets reacted to the possibility of an 8 

percent less domestic production shutdown by bidding up the price of 

crude to just over $76 per barrel which will be paid by American 

consumers. 

 For an oil company of BP’s size and reputation to allow two of its 

most critical transit lines to the America’s largest producing oil fields to 

reach such a sorry state of affairs is staggering. What went wrong? Did 

cost-cutting prove to be the undoing of standard maintenance? Did 

management turn a blind eye to problems on the line that at best it should 

have known about or at worst knew about and decided to ignore? We 

need those answers, because without those answers, we aren’t going to 

know what should be done either by the regulatory agencies or by the 

Federal government or by the Congress. 

 The one bit of good news here is that the Department of 

Transportation has taken action since the initial spill in last March. The 

department has been reasonably aggressive in its enforcement of the 

initial corrective action order and subsequent amendments and 

responsive to the letters that I and others have sent asking questions 

about this matter. There are, however, two things that trouble me very 

much. First, the lines that failed were exempt from regulation by DOT 

itself despite longstanding concerns in the Congress that low-stress 

pipelines could pose significant risk. For a field that produces nearly 8 

percent of American domestic production to have its main two lines left 

unregulated it simply unacceptable and needlessly risky. As we go 

forward, the Federal government must take a fresh look at critical energy 

infrastructure regardless of its present regulatory status. 
17

 Second, DOT should propose rules to regulate low-stress pipelines. 

At first glance, the rule appears inadequate and applies less rigorous 

standards to these lines than recent events would warrant. Furthermore, 

the rule leaves some 4,300 miles of low-stress lines without any 

regulation at all, not even the bare minimum requirement to manage for 

corrosion and to report spills. The proposed rule is eerily reminiscent of 

the Nation’s view and experience with the industry which favored the 

industry preferred proposals and leads me to conclude that my increasing 

confidence in the performance of the Pipeline and Hazardous Materials 

Safety Administration on Pipeline Safety has been misplaced. I know 

our colleagues who are on the committee will be working together on the 

upcoming pipeline safety reauthorization to correct these deficiencies 

and this hearing will give us some reference as to what this committee 

must do and what we can expect from the Administration in terms of its 

administration of the statutes. 

 Mr. Chairman, thank you for holding this important hearing. 

 MR. WALDEN. Thank you. I appreciate your comments and your 

participation. Now we will go to other committee members, and I 

remind you, you have 5 minutes for your opening statements, and with 

that, Mrs. Blackburn. 

 MRS. BLACKBURN. Thank you, Mr. Chairman. I do want to thank 

you for holding the hearing and I want to thank the witnesses for 

presenting this committee with information on this issue. I will have to 

say I wish we were focused on a more positive topic. I wish it were 

something about achieving energy independence or new fuel usages, et 

cetera, and that it was not a hearing about failed policies, but we thank 

you for being here to visit with us. 

 I have several concerns on how BP maintained their oil pipelines and 

if their maintenance met the industry standards on corrosion prevention. 

Specifically, I would like to hear from our witnesses to discuss their 

known best practices and how those were implemented and how often 

extensive testing of oil pipelines should have taken place, as to how often 

it did take place, and I hope that you will present us with specifics. 

 My reading and research and preparing for the hearing today have 

led me to an understanding that most of the pipelines in Prudhoe Bay 

were not thoroughly inspected for over a decade and that warnings from 

engineers for more testing went unheeded, and I think you have heard 

that from some of the other members here who have already spoken 

today. That is of concern. It is not acceptable and I think it is quite 

appropriate for all of us to expect better from you and from your 

company and from a company that promotes itself as a safe and 

environmentally friendly energy company. 
18

 Another concern I have is how BP was prepared for an eventuality 

such as this. Currently, the eastern oil fields of the Bay are shut down 

for the next 6 months, which means that BP is not pumping 200,000 

barrels of oil each and every day. It is unfortunate for you all. It is 

unfortunate for the American public. It is a loss from what I understand 

of about $14 million each day to your company. I want to hear from BP 

why they were not prepared for this and why it will take approximately 6 

months before the fields are ready to operate again and what the ramp-up 

process will be as you look toward bringing that line back online. 

 Mr. Chairman, when events such as this occur in the U.S. and affect 

a critical market such as our oil supply, Congress needs to examine the 

safety and the inspection standards so that another accident like this does 

not happen again. 

 So I thank you for the information that you will bring to us, for the 

testimony that you have already supplied, and Mr. Chairman, I look 

forward to the time of questions. 

 MR. WALDEN. Thank you, and the gentlelady yields back her time. 

The Chair now recognizes the gentlewoman from Colorado, Ms. 

DeGette. 

 MS. DEGETTE. Thank you, Mr. Chairman. Mr. Chairman, the story 

unfolding at Prudhoe Bay in recent months has grown much more 

alarming as we learn new facts. Just as we heard this morning from the 

other members of this committee, it appears that this whole mess was 

preventable. Had BP exercised even basic periodic maintenance of its 

pipelines, they would not have had to order the shutdown of the 

country’s number one domestic oil field at a time both strategically and 

economically that this country needed that oil field to be open. 

 We are all well aware of BP’s aggressive advertising campaign, 

portraying it as the environmentally responsible and socially conscious 

oil company, so why then did it allow the condition of its low-stress 

pipeline to deteriorate to the point of the corrosion-induced spill of 

270,000 of crude oil? Was it purely for cost-saving reasons as this April 

2005 internal audit document intimates? These pipes are in such poor 

condition now we are told that they are going to need to be completely 

replaced. As I mentioned a minute ago, this was all preventable. Mr. 

Chairman, it is my understanding, and we discussed earlier, that smart 

pigging, though relatively inexpensive, is the single best way to detect 

corrosion. Now, I am no engineer but it seems to me that this high-tech 

procedure gives quite a bang for the buck and it perplexes me that the 

lines haven’t been pigged in some cases since 1992. Now, I would think 

that the potential damage to BP’s infrastructure, reputation and bottom 

line would have been enough to compel it to take care of its pipes but 

apparently this is not so. 
19

 I applaud BP’s efforts in advertising campaigns to move beyond 

petroleum to help foster a more sustainable energy future and to become 

a truly compassionate corporate leader, but maybe it should start by 

sticking to the basics and begin to focus on rudimentary pipe 

maintenance as much as it has on PR. BP will undoubtedly assure us 

today that its corrosion prevention methodology in the run-up to this 

crisis was fully compliant with existing regulations. I look forward to 

hearing from the Department of Transportation as to whether that is true 

and whether or not we have adequate regulations. 

 Also, I am interested in hearing the contrasting testimony from the 

Trans Alaska Pipeline which pigs their lines every three years. BP may 

have believed that using coupons and ultrasonic testing were sufficient to 

protect the infrastructure but other industry leaders went well above and 

beyond regulatory requirements to properly maintain their pipes and they 

have avoided the problems that we have seen in recent months. 

 I am glad that the DOT is here with us today because the department 

has done an excellent job in responding to this crisis and deserves credit 

for its rapid response. While I am pleased at the DOT’s new regulations 

issued in the aftermath of the Prudhoe Bay spill, I fear that they may not 

be adequate. 

 I am also dismayed as I am often these days with what has become 

an even more reactionary Federal government. It seems to me that we 

have the tendency to ignore major issues like this, exercising limited 

oversight and only after a crisis happens do we jump to fix a problem 

that should have been prevented in the first place. Perhaps we should 

have seen this coming. I hope to hear from the Federal officials today 

whether we should have predicted a major oil spill like this given the lax 

regulation of the low-pressure lines in unpopulated areas. 

 And frankly, Mr. Chairman, the United States Congress is not 

entirely without blame either. The Pipeline Safety Act reauthorization 

has languished in Congress for months. I hope some good will come out 

of this mess and that would be passage of this important legislation 

sooner rather than later. 

 Mr. Chairman, I am looking forward to probing these and other 

issues, and again, I want to thank you for holding this hearing, and I 

yield back. 

 [The prepared statement of Hon. Diana DeGette follows:] 
20

PREPARED STATEMENT OF THE HON. DIANA DEGETTE, A REPRESENTATIVE IN CONGRESS 

FROM THE STATE OF COLORADO
21
22
23
24

 MR. WALDEN. I appreciate your participation and your comments. 

Just for the committee’s edification and for the audience as well, we have 

been called to the floor for a vote on the rule. It is just one vote and then 

there will be a break at three to four hours before our next series of votes. 

We are going to continue to take opening statements during this period. 

The Chairman has gone over to vote and will come back and take the 

chair so I can go vote. Meanwhile, I will work through our list, and I 

have Dr. Burgess and then Ms. Baldwin next, and there are 11 minutes 
25

left in--oh, I am sorry. I actually have Mr. Inslee. It is Burgess, Inslee, 

Stearns, Baldwin. So Dr. Burgess for 5. 

 MR. BURGESS. Thank you, Mr. Chairman, and I want to thank you 

also for convening this hearing this morning. I want to thank our 

witnesses for being here with us. The remarks of the full committee 

Chairman, Chairman Barton, certainly echo my sentiments on this issue 

and I won’t belabor those points that he has already brought up, but like 

most of my constituents, I was extremely concerned to learn of the oil 

spill in Alaska last March. It was the largest spill so far in Alaska but it 

is hoped that that remains the case. The spill posed a risk to both the 

environment and our domestic supply of oil. Experts believe that there 

will be no permanent environmental damage from the spill, and that is 

the good news, but we must ensure that the pipeline maintenance 

practices do not jeopardize the environment or expose us to further 

disruptions in our supply. While I believe that British Petroleum’s initial 

decision in August to shut down the Prudhoe Bay field following the 

discovery of corrosion was prudent, I am also troubled by the fact that 

the situation could have been prevented. What is especially troubling is 

these transmission pipelines had not been pigged either with the scraping 

pig or smart pig since 1992 or 1998. Pigging is not a new technology but 

it is and should be a standard industry practice, and I would like to hear 

from our panel if in fact that there is recognition otherwise within the 

industry. 

 BP’s failure to conduct this type of routine maintenance put in 

jeopardy our ability to access the crude oil produced by the entire field. 

The Prudhoe Bay field accounts for 5 percent of domestic production, 

400,000 barrels per day as we have heard several times this morning, so 

the temporary loss of this supply has the potential to significantly impact 

oil prices. 

 We also had, the Chairman brought up the Texas City situation 

where 15 people were killed in my home State of Texas and while that 

may have been a preamble to the other problems that have now surfaced 

in Prudhoe Bay, I know it is difficult to separate out the complexities of 

the corporate structure but stipulating what the Chairman brought up that 

there was a significant profit earned by BP last year, I think this 

committee would be interested in knowing what commitment is going to 

be made in investing those profits in further maintenance and further 

assurances that these two types of accidents do not occur again in the 

future. Maintenance is just one of the primary responsibilities of the 

company that is managing the Prudhoe Bay fields, but I am looking 

forward to hearing from BP about what happened and having the 

opportunity to question the witnesses appearing before us today. 

 Thank you, Mr. Chairman. I will yield back. 
26

 MR. WALDEN. Thank you, Dr. Burgess. Now I will recognize the 

gentleman from Washington State, Mr. Inslee, for 5 minutes. 

 MR. INSLEE. In 1999, another pipeline company didn’t do its job. A 

fireball erupted in Bellingham, Washington, and killed two young boys 

and a young man, and one of the parents of one of those children called 

me the other day when this happened and basically asked a question, 

when will they ever learn, and I think that is a pretty good question. 

When will they ever learn? 

 What is so profoundly disappointing in this circumstance is that this 

is not a matter of hindsight. This is a profound lack of foresight and 

responsibility by this particular company, and the reason we know that 

is, back in 2001, an engineering company from Seattle, Washington, did 

a preliminary draft of a report with the specific purpose of reviewing this 

protocol for maintaining these pipes included smart pigging as something 

that would be the most effective protocol to prevent this leak. We found 

a specific memo from this company, Coffman Engineering in Seattle, 

Washington, and it said, “Smart pigging is the only inspection technique 

capable of looking at the whole internal and external corrosion picture.” 

British Petroleum, instead of deciding to smart pig, decided to quash that 

information from the public. That information never showed up in the 

public record until it was disclosed after this incident. That is a crying 

shame, and we are going to find out why that happened because this was 

a conscious, willful decision by the particular corporation involved here 

not to do smart pigging that they knew was an effective way of providing 

repair. This is not a matter of hindsight. This is a matter of lack of 

responsibility and foresight. And that is a good question, when will they 

ever learn? 

 Now, that is the profoundly obvious lesson of what happened here, 

but there is another profound one that is not so obvious. You know, I 

was amazed at what lessons people will take from a tragedy like this. 

One of my colleagues suggested that the lesson we should take from this 

is we need to drill more oil wells in the Arctic wildlife refuge. He said, 

you know, we need to expand our oil production capability. Well, I 

thought that was interesting. That would be sort of like after the 

Hindenburg saying the problem here is, we need more blimps; that is the 

whole problem, we don’t have enough blimps. I don’t think that is the 

lesson to be drawn from this. Eight percent of production has now been 

reduced because of one pipeline failure. The lesson is, we need a more 

diversified energy future for this country. We need a biofuels segment to 

our energy production capacity. We need development of cellulosic 

ethanol plants so we can displace some of our dependence on these 

vulnerable systems that have been reduced now 8 percent and yet a 3 

percent spike that Mr. Barton suggested just from the loss of this one 
27

pipeline. We need a whole new energy policy. And I like the fact that 

British Petroleum has spent millions of dollars on things like this and that 

their plans for biofuels are growing, which is impressive PR, but 

unfortunately, their efforts are less than .2 percent of just their net profits 

this year of $26 billion. That is not a sincere effort. It is not enough. 

And I would agree with my colleague, Ms. DeGette, that Congress has a 

responsibility because it is an abysmal failure of Congress as well. You 

know, it is not just pipelines that lack integrity. It is our whole energy 

system in this country and Congressional inaction that lacks integrity of 

having a real energy policy that will be diversified and truly 

environmentally friendly, which this current policy is not. 

 So I am confident, relatively confident, that we will close this 

massive loophole, we will get regulation ultimately of this, but it is not 

enough. We need an energy policy in this country that will not leave us 

exposed to these terrible price spikes that we have when we have this 

vulnerable system go down. So I am hopeful that it is not just the 

obvious lessons that we learn but the more profound ones. I look 

forward in this hearing to find out why this Coffman Engineering report 

was not made available, why the public didn’t know about this, why this 

was not done, and why the belts-and-suspenders approach to pipeline 

management was not followed. 

 It is obvious you need a belt-and-suspenders approach to pipeline 

management. This corporation is dependent on ultrasound, which is 

great technology, but it is like a CAT scan that only takes one slice 

through your body and doesn’t look at the rest of your body. It is very, 

very good for that one slice. Ultrasound was very, very good for the one 

tiny slice of this pipeline they did but they ignored the rest of it at our 

peril, and we are going to get to the bottom of why this happened and 

make sure it doesn’t happen again. 

 MR. WALDEN. I want to thank the gentleman for his comments. The 

full Chairman is going to take over the gavel so that we can go vote in 

the remaining 2 and a half minutes. 

 CHAIRMAN BARTON. We are going to continue the hearing but we 

have a number of members that wish to do opening statements, so the 

first one back gets to do an opening statement and we will alternate until 

we get regular order when everybody else gets back. 

 MR. STEARNS. Thank you, Mr. Chairman. Thank you for going 

ahead and having this hearing for this investigation. 

 As I understand, later on today one of the persons is going to take the 

Fifth, and having been through several oversight hearings, when you see 

an individual take the Fifth it means he does not want to testify under 

oath, and that should be a concern for all of us when we are trying to just 

explore the truth here. 
28

 In a larger sense, BP has to realize they have been given a public 

trust because of the impact of oil on our national security and our 

economy yet it would appear they failed to exercise this trust, so this is 

our concern today, especially in light of the fact that someone is going to 

take the Fifth and will not testify openly, clearly and honestly. 

 Now, the Department of Transportation monitors a lot of sensitive 

lines in this country in urban areas, environmental areas, but obviously 

not in areas that appear to be low-stress lines, low-pressure areas like in 

the tundra of Alaska. Yet these lines are vital, and even though the 

Department of Transportation does not monitor these lines, it would 

seem to me BP would want to be scrupulously careful to protect these 

lines because of their strategic value. Yet today we are here realizing 

that that did not occur. Fortunately, it appears it is not having a large 

impact on the price of oil. There has been a lot of trading, future trading, 

and as a result of trading and the surplus oil, it appears the price of 

gasoline is coming down. So despite BP’s troubles, our oil infrastructure 

appears to be in reasonable shape but a concern we all should have is, as 

I understand, is 5,000 barrels of oil were dumped onto the environment. 

We are going to have somebody from the government that is going to 

explain to us about this cleanup and whether it was sufficient. Did BP 

act quickly and do it in such a way that there was no environmental 

damage? But think of that amount of oil in any kind of other area where 

there would be high urban or high environmental problems, what that 

would do and the enormous cost and effort it would create. So again, BP 

should realize that they have a fiduciary responsibility that goes beyond 

just the bottom line. 

 While many pipes are getting old, data from the Department of 

Transportation’s Office of Pipeline Safety indicates a broad decline in 

the number of pipeline accidents from 245 in 1994 to 136 in 2005 with 

only 57 through July. So in light of the fact that we have these statistics 

and a broad decline, it is still a concern what happened. 

 The Department of Transportation has worked with BP to assess the 

extent of corrosion in its transmission lines and to prevent any repeal of 

these leaks. The department has also recently proposed a rule to cover 

the low-stress transmission lines we are discussing today, and that is a 

question for us as members of Congress should we implement legislation 

to do that. Right now we have no direct oversight authority up in the 

tundra there, and we should give it. 

 So Mr. Chairman, I appreciate this opportunity again to have the 

opportunity to question BP’s executives, and I look forward to hearing 

their testimony and to make sure that this does not occur again and we as 

legislators can do that to make sure the Department of Transportation is 
29

involved where we have strategic value and we have public trust 

involved. Thank you. 

 CHAIRMAN BARTON. We thank the gentleman. The gentlelady from 

Wisconsin, Ms. Baldwin. 

 MS. BALDWIN. Thank you, Mr. Chairman. It is very important that 

we are holding this hearing today. Not only must we address what went 

wrong at Prudhoe Bay but we must examine how we can prevent it from 

ever occurring again. We have had some time to mull over the shutdown 

since it was first announced earlier last month, and time and time again, I 

simply find myself at a loss. I am frustrated that BP shut down 8 percent 

of domestic oil supply, I am angry that gas prices were pushed even 

higher during the peak summer season, and I am concerned that the 

Alaskan environment has been dealt a blow from which it will not 

quickly rebound. 

 But even more troubling is a trend that I see among companies that 

can only be described as a lack of corporate responsibility. Many of us 

can remember a time when our communities were proud to associate 

themselves with big companies that made their home in nearby towns. 

These companies realized that their long-term success depended upon 

investing in and improving the community, not just focusing on the 

bottom line. BP Alaska was such a company. It has been one of 

Alaska’s largest employers, providing more than 1,300 jobs to State 

workers. It has supported Alaska’s communities, offering millions of 

dollars for charitable giving and it has played a large role in the social 

fabric of the community. In return, the community trusted BP. They 

trusted that BP was listening to its workers, investing in its infrastructure 

and protecting the surrounding environment, but sadly, somewhere along 

that way, the trust has been broken. Consideration of the world in which 

neighbors and consumers live and work seems to have disappeared from 

BP executives’ radar screens, and what has been left behind in Alaska is 

muck on the ground and distaste, not only among Alaskans but among all 

Americans. 

 The BP shutdown has brought to light what happens when a 

company turns its back on its responsibilities. It allowed years to pass, 

years to pass without inspecting the critical pipeline that carries 400,000 

barrels of oil a day. Executives ignored workers who raised safety 

concerns and consumers have been left to foot the bill. The cost for BP 

is not simply calculated in lost production or replacing corroded pipes. 

Rather, it must also include the disappointment of loyal customers, the 

damage to Alaska’s pristine environment and the violation of the 

community’s trust. 

 Mr. Chairman, I recognize that we cannot force companies to elevate 

their commitment to corporate responsibility above profits, but we can 
30

find a way to ensure that companies are not abandoning their critical 

infrastructure by running their pipelines to failure or what is known as 

riding the throughput curve. The mess of a company’s negligence must 

not be borne by the consumer, the environment or the community. 

Rather, companies must stand up and take responsibility and BP must be 

held accountable for its actions or inactions. 

 I am hopeful that the series of hearings that Congress is holding on 

this matter will force us to look at the way pipeline safety is regulated so 

that future disruptions will not occur, and more importantly, I hope this 

incident and these hearings will encourage other companies to look at 

their actions and keep corporate responsibility and public trust in mind as 

they decide what sort of commitment they make to public safety and 

maintenance. 

 Thank you, and I yield back the balance of my time, Mr. Chairman. 

 CHAIRMAN BARTON. The gentlelady yields back. Does the 

gentlelady from Chicago, Ms. Schakowsky, wish to make an opening 

statement? 

 MS. SCHAKOWSKY. Thank you, Mr. Chairman, and thank you, 

Ranking Member Stupak, for convening today’s oversight hearing into 

BP’s pipeline oil spills at Prudhoe Bay in Alaska. 

 Probably everything that needs to be said is said but I think it was 

Mo Udall that said, not everyone has said it, so I am going to say a few 

things about that as well. 

 I am really glad that we are taking the time to closely review what is 

going on at Prudhoe Bay over the last several years. However, what is 

obvious to me and to my constituents and to any reasonable person 

reviewing the facts of the case is that BP, a company that raked in over 

$7 billion in profits in the second quarter of this year alone neglected to 

conduct even remotely adequate or responsible maintenance on its 

operating lines in the greater Prudhoe Bay field. 

 Aside from environmental stewardship obligations, it seems like 

plain common sense to me and I think to just about everyone on this 

committee that a company extracting oil as a means of profit would want 

to routinely conduct thorough inspections of its pipelines to ensure safe 

transport of the product. Why BP refused to do it for years is something 

I want to know. Hopefully we will get some clue about that today. 

 BP has presented troubling indicators of diminishing quality in 

previous years and conducted no major investigation or corrective action, 

and despite discovering a leak on its western pipeline on March 2 of this 

year, which put over 200,000 gallons of oil in the Alaskan tundra and 

was the single largest leak in history on the North Slope, BP attempted to 

get out of conducting further review of its lines as had been ordered by 

the Department of Transportation on March 15. 
31

 Instead of doing the right thing and what would have been smart 

business and conduct an immediate internal investigation of all its lines, 

BP waited until June 6 and asked for relief and a pass on DOT’s previous 

pigging order to conduct a thorough internal review of its lines, and it 

wasn’t until late July, almost five months after the enormous leak was 

discovered and after it was further ordered by DOT that BP finally 

conducted internal testing. The results demonstrated numerous areas of 

concern and yet another leak. Finally, on August 6, more than five 

months after the initial March 2 leak was discovered, BP shut down 

production from its greater Prudhoe Bay field. It is astonishing and 

infuriating that any company entrusted by the public and the government 

to ensure level of safety for our environment and its use of natural 

resources to turn a profit, that it would be so irresponsible, but it is truly 

beyond comprehension that a company that is so grossly profitable 

would willfully avoid routine detailed inspection and maintenance on its 

pipelines. As has been mentioned now several times, BP as it turns out 

had not taken an in-depth internal look at its pipeline on its eastern line 

since 1992 and its western line since 1998. That is 14 and 8 years, 

respectively. If this company had spent as much on inspections, safety 

and maintenance as it does on advertising and lobbying for tax cuts, none 

of us would have to be here today in this hearing. BP executives could 

be counting their bonuses and the public would be assured of the 

company’s pipeline integrity. Instead, BP chose to bury its head in the 

sand and tundra and operate a see-no-evil approach to its Prudhoe Bay 

operations. 

 This company has a lot of explaining to do, and as lawmakers on this 

committee, we all need to ask ourselves if our policies are adequate, if 

we can afford to trust companies like BP to do the right thing and if we 

can continue to rely so heavily on energy products that present such risks 

to our environment, our bank accounts and our economy. 

 I wanted to mention that my friend from Chicago, national leader 

Reverend Jesse Jackson, was here today. His organization has taken a 

great interest in this, is leading weekly pickets across the Nation at BP 

stations in several cities including Washington, D.C., and Chicago, Los 

Angeles, Atlanta, Detroit, Michigan, raising the questions that all 

consumers are asking right now, why are the profits so high at BP and 

yet we cannot be sure that they--we know that they are not doing the kind 

of maintenance and safety inspections that are needed. 

 All of us need to focus in on this, including the company, and I 

welcome our witnesses today. Thank you. 

 MR. WALDEN. I thank the gentlelady for her comments. The chair 

would now--we are waiting for Mr. Pickering, but in his absence, we will 

now go to Congressman Markey, who is not a member of the 
32

subcommittee but we welcome your participation today, and you are 

recognized for a 5-minute opening statement. 

 MR. MARKEY. Thank you, Mr. Chairman, very much, and I 

appreciate the courtesy of allowing me to speak on this issue in this 

subcommittee. I have been a member of the Energy Committee for 30 

years, and this is one of the low points of those 30 years. This is without 

question an issue which has had a profound impact on the American 

public. At a minimum, they have had to have paid now tens or hundreds 

of millions of extra dollars at the pump because of the spike in the price 

of gasoline that occurred because of this accident. That is the beginning 

of the price that the public has to pay for this kind of a problem 

manifesting itself. 

 British Petroleum’s marketing campaign claims that BP stands for 

Beyond Petroleum but today we are finding that BP stands for a 

company with bloated profits that failed to fix bad pipelines and the 

consumer at the pump is responsible for paying the price. It appears to 

me that management at BP’s Alaska operation knew that they were 

essentially driving a car with over 100,000 miles on it without bothering 

to spend the money and time needed to properly maintain it. So it seems 

to me that BP senior management can’t have been surprised that it broke 

down eventually. BP’s corrosion management set up a testing system 

that was designed to save money but it failed miserably at ensuring the 

integrity of these critical pipelines. BP had a 2004 report from its 

attorneys at Vinson and Elkins that pointed out some of these problems. 

BP also had a 2005 audit report that reaffirmed the problems’ continued 

existence but BP doesn’t appear to have revamped the pipeline corrosion 

control systems after these warnings. It doesn’t appear that the 

allegations of harassment or retaliation against whistleblowers were 

thoroughly investigated by and adequately responded to by senior 

management at BP. These whistleblowers are public interest Paul 

Reveres signaling a warning that something could go wrong so that the 

public interest could be protected. Those warnings were ignored. This is 

simply unacceptable. 

 BP is one of the largest oil companies in the world. It is an 

extraordinarily profitable company. It clearly has the money to be able 

to properly maintain their pipelines, and BP failed to do so. Instead, BP 

appears to have pursued a strategy of maximizing short-term profits at 

the expense of maintaining the integrity of those pipelines. BP appears 

to have ignored internal evidence that such a strategy would result in 

leaks and there are some indications that those within the company who 

raise concerns about this strategy would be harassed and retaliated 

against. 
33

 I would hope that before this committee takes up any pipeline safety 

reauthorization that we would get to the bottom of what happened here 

and make appropriate adjustments to the law to ensure that this type of 

problem does not happen again. We should not legislate in the area of 

pipeline safety until we understand completely what happened at BP, 

make an industry example and then change the laws of our country to 

ensure that it never happens again. I thank you again, Mr. Chairman, for 

your courtesy. 

 MR. WALDEN. You are welcome, and Mr. Stearns reminds me that I 

should have asked UC, unanimous consent, to allow members who are 

not on the subcommittee the opportunity to provide an opening 

statement, so I will do that, because Mr. Green is next. I ask unanimous 

consent to allow Mr. Green to offer an opening statement. Is there any 

objection? Hearing none, Mr. Green. 

 MR. GREEN. Thank you, Mr. Chairman, again. Thank you for 

allowing those of us who are not on the committee although serve on the 

Energy Subcommittee, and this hearing is very important, particularly in 

the area where I come from in Houston. I would like to keep my remarks 

brief because I really want to hear from our panelists but I am glad to be 

here today to express my frustration with the events in Alaska that 

caused this hearing today. 

 Last year we had two natural disasters, Hurricanes Katrina and Rita, 

that blocked domestic oil supplies at a very critical time, the summer 

driving season. We may dodge that bullet this year but the American 

drivers had to deal with a manmade disaster this year when BP’s Alaska 

pipeline sprung a leak and had to be shut down due to corrosion. I have 

not reviewed all the documents that our subcommittee has obtained but 

what I have heard so far is not good. Corrosion on the pipeline does not 

seem to have taken BP by surprise, rather there were numerous warning 

signs that were underestimated or ignored. Even large corporations can 

have bureaucratic problems dealing with maintenance issues, but 

unfortunately, this is not the first time we have seen something like this 

with British Petroleum. Just last year, an explosion at a BP refinery in 

Texas City that is close to our district, in fact, it could be in it because I 

have all the other refineries in the Gulf Coast area it seems like, killed 15 

contractors who were working in a temporary building placed too near to 

dangerous equipment, and again, the information that I understand from 

Federal investigators found several safety problems and the investigation 

is still ongoing and it makes two major public safety disasters in two 

years. 

 Mr. Malone, I know you are new to your job and we appreciate the 

fact that you are here to face this music but we need more than honesty 

and sincere apologies at this point. We need concrete action and some 
34

assurance that BP is going to spend the necessary resources on safety. 

When you own a pipeline or refinery, Congress and the American people 

expect you to invest the necessary amount in safety to protect our 

economy, the environment and human life. This committee should look 

at our pipeline safety legislation to make sure we are keeping our 

responsibility to improve safety at these low-stress oil pipelines. 

However, I don’t want to have a pipeline safety accident hold up pipeline 

safety legislation that would make our pipelines actually safer. Mr. 

Chairman and Ranking Member, thank you for holding this hearing and 

allowing me to participate, and I look forward to authorizing the pipeline 

safety legislation in this Congress, I hope, in light of the accidents that 

have happened, and I yield back my time. 

 [Additional statement submitted for the record follows:] 

PREPARED STATEMENT OF THE HON. ED WHITFIELD, CHAIRMAN, SUBCOMMITTEE ON 

OVERSIGHT AND INVESTIGATIONS

 Today, the Subcommittee on Oversight and Investigations will examine the facts 

and circumstances surrounding two spills on crucial crude oil transmission pipelines 

operated by BP in Prudhoe Bay, Alaska. We will look at BP’s decisions and actions 

concerning the maintenance and operation of these pipelines in order to better understand 

how the corrosion occurred and what can be done to prevent similar problems in the 

future. 

 In March this year, BP discovered the leak of roughly 5,000 barrels of crude on the 

Western Operating line, the largest spill in the history of the North Slope. Just a few 

months later, BP discovered serious corrosion problems in its Eastern Operating line, 

which forced it to shut down the line, effectively cutting production from the Prudhoe 

Bay field in half. BP cannot even say with any degree of certainly when it will be able to 

get this line back into operation. 

 There have been a series of maintenance and safety problems involving BP over the 

past several years that are troubling, including the Texas City refinery disaster and the 

recent leaks on the North Slope. Are these isolated incidents, or are they the result of 

fundamental problems within the company? I hope that the BP executives testifying 

before the Subcommittee today will be able to provide some assurances in this regard. 

As stewards of critical energy infrastructure, all pipeline operators, including BP, bear a 

tremendous responsibility. 

 I would like to thank all of the witnesses, and I hope that today’s hearing will 

illuminate the facts of the situation surrounding BP’s pipelines so that this Committee can 

help ensure a safe and reliable energy infrastructure. 

 MR. WALDEN. I appreciate the gentleman yielding back the time and 

his comments and participation in our hearing. With that, we are going 

to ask the following witnesses to come up to the table. Mr. Richard 

Woollam of BP, formerly corrosion engineer, formerly the manager of 

the CIC; Mr. Robert A. Malone, Chairman and President, BP America; 

Mr. Steve Marshall, president, BP Exploration Alaska; Mr. Kevin 

Hostler, President and CEO of Alyeska Pipeline Service Company; and 
35

Mr. C. Dan Stears of Coffman Engineers. If you would come forward 

and be seated at the table. 

 As you know, when conducting an investigative hearing, this 

subcommittee follows the practice of taking testimony under oath. So 

now that you are comfortable, I am going to ask you to all rise and if you 

would raise your right hand. 

 [Witnesses sworn] 

 MR. WALDEN. Please be seated. Under the rules of the House and 

this committee, you have the right to be advised by counsel as to your 

constitutional rights. Do you have legal counsel here today, Mr. 

Woollam? 

 MR. WOOLLAM. Yes. 

 MR. WALDEN. And can you identify that counsel for us, please? 

 MR. WOOLLAM. Yes, Mr. Jim Torgesen with Heller Erman. 

 MR. WALDEN. Mr. Malone? 

 MR. MALONE. Yes, I do. 

 MR. WALDEN. Can you turn on your microphone there, sir? Thank 

you. 

 MR. MALONE. I have Ron Phillipe here. 

 MR. WALDEN. All right. Mr. Phillipe, welcome. Mr. Marshall? 

 MR. MARSHALL. Yes, I do, Mr. David Bukey. 

 MR. WALDEN. All right. Thank you. Mr. Hostler? 

 MR. HOSTLER. Yes, that is right, Hostler. 

 MR. WALDEN. Hostler. No counsel? 

 MR. HOSTLER. No. 

 MR. WALDEN. And Mr. Stears? 

 MR. STEARS. Yes, I do. 

 MR. WALDEN. Can you turn on that mic? That didn’t help either. 

Sorry. Try again. 

 MR. STEARS. It indicates it is on. 

 MR. WALDEN. There we go. Now it is. All right. Thank you. The 

chair will now recognize you for purposes of making an opening 

statement if you so desire. Mr. Woollam? 

TESTIMONY OF ROBERT A. MALONE, CHAIRMAN AND 

PRESIDENT, BP AMERICA, INC.; STEVE MARSHALL, 

PRESIDENT, BP EXPLORATION ALASKA, INC.; KEVIN 

HOSTLER, PRESIDENT AND CEO, ALYESKA PIPELINE 

SERVICE CO.; AND C. DAN STEARS, CATHODIC 

PROTECTION SPECIALIST, COFFMAN ENGINEERS, INC. 

 MR. WOOLLAM. Mr. Chairman, I have no prepared statement. 

Based upon the advice of counsel, I respectfully will not answer 
36

questions based upon my right under the Fifth Amendment of the United 

States Constitution. I ask that my counsel’s written letter of this morning 

to the committee be entered into the record. 

 MR. WALDEN. Without objection. Mr. Malone, welcome. 

 [The information follows:] 
37

 MR. MALONE. Thank you, Mr. Chairman. 

 Mr. Chairman, members of the subcommittee, good morning. My 

name is Bob Malone. I am the Chairman and President of BP America. 

I am joined today by Mr. Steve Marshall, who heads our Alaskan 

operations. 

 BP America’s recent operating failures are unacceptable. They have 

fallen short of what you and the American people expect from BP and 

they have fallen short of what we expect of ourselves. We must and will 

work hard to fix the problems, and in doing so, regain your trust and that 

of the American people. We know we will be measured by what we do, 

not what we say. 

 I assumed this role on July 1 and immediately began to visit our 

facilities, meet with our employees and learn about our current 

operations. On August 6 I received word of severe corrosion in our of 

our transit lines in Alaska. The decision was made to shut down 

protection to avert any possibility of an oil spill and to prevent damage to 

the environment. We then conducted extensive testing of the transit lines 

on the western side of the field, assured ourselves they were fit for 

service and maintained production of about 200,000 barrels a day. 

Preventing environmental damage and protecting the safety of our 

employees and contractors are absolute priorities. We fully recognize 

this decision was not without consequences but it was the right thing to 

do. Many were concerned about the impact on crude oil and gasoline 
38

supplies. BP brought in cargos of crude oil from around the world and 

other suppliers did the same. A short-term supply shortage did not occur 

and we continue to acquire stocks to replace the production that is still 

shut down. BP is fully committed to restoring production from Prudhoe 

Bay as soon as we are confident that it can be done in a safe and 

environmentally responsible way. 

 Across BP, we have taken a number of actions to ensure that our 

businesses are run in a manner that meets our expectations and yours. I 

would like to highlight a few of those. These were announced--some of 

these were announced by John Browne on July 1 and they included my 

appointment. 

 First, I retained three of the foremost corrosion experts in the world 

to evaluate and make recommendations for improving the corrosion 

management program in Alaska. BP has added an additional $1 billion 

to the $6 billion already earmarked to upgrade all aspects of safety at our 

U.S. refineries and for the integrity management in Alaska. I have 

appointed former U.S. District Justice Stanley Sporkin as an independent 

ombudsman reporting directly to me. I have asked Judge Sporkin to 

conduct a review of all worker allegations that have been raised on the 

North Slope since 2000. I have established an operational advisory 

board that is composed of 15 of our most senior business leaders in the 

United States, who will advise me on safety operational integrity and 

compliance. I am in the process of recruiting an external advisory board 

to assist and advise me in the monitoring of BP’s U.S. businesses with 

particular focus on safety, operational integrity, compliance and ethics. I 

am building an internal team of experts who will be employed to look at 

safety, process safety, operational integrity and compliance and ethics. I 

continue to meet with our employees to reinforce our expectations of 

them to ensure that BP operations are safe, to remind they have a 

responsibility and a right to shut down any process they feel is unsafe, 

and that I encourage them to raise concerns of anything that has to do 

with safety and environmental integrity. 

 I am personally committed to rebuilding the public’s confidence in 

BP America. I have the full support of our Chief Executive, John 

Browne, our executive leadership and the entire BP group. I have been 

given all the authority necessary to accomplish this task. Bringing our 

operations to the level of excellence you expect and we demand is going 

to take time. 

 If the subcommittee would like, I would be happy to report back in 6 

months and periodically thereafter to indicate to you the progress that we 

are making, and we will participate and cooperate with you in an open 

and honest fashion. Thank you, Mr. Chairman. 

 [The prepared statement of Robert A. Malone follows:] 
39

PREPARED STATEMENT OF ROBERT A. MALONE, CHAIRMAN AND PRESIDENT, BP AMERICA,

INC. 
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 MR. WALDEN. Mr. Malone, thank you for your testimony today. 

We look forward to discussing this issue more with you as we open up 

into questions in a few moments. 

 Mr. Marshall, welcome. We are delighted to have you with us today 

and we look forward to your comments on this issue. 
56

 MR. MARSHALL. Mr. Chairman, members of the subcommittee, 

thank you for the opportunity to be here today. I am Steve Marshall, 

President of BP Exploration Alaska. 

 In the past 6 months, we have had two leaks from the oil transit lines 

at Prudhoe Bay. These spills occurred on my watch, and as President, I 

am in charge of the overall business in Alaska and the buck stops with 

me, and I commit that I and my team will do everything we can to rectify 

this situation, going forward and doing everything to get production back 

as quickly and as safely as we can and apply the lessons that we continue 

to learn from these two events in our forward programs. 

 We take very seriously the public trust, the trust of government, our 

serious role of protecting the environment. Both spills have been fully 

cleaned up. We have received a number, several comments from 

external sources about the quality of that cleanup and we believe at this 

point there will be no lasting damage to the environment. We won’t 

know the exact cause of the spills until we complete the failure analysis 

of the pipe, and that work still remains to be done. We did believe we 

had a very comprehensive corrosion management system covering over 

1,500 miles of oil pipelines, flow lines, gathering lines and transit lines. 

Inspections that we did told us time and again that these transit lines 

were in good shape. Clearly, in retrospect, since these leaks, it has 

clearly identified gaps in our program and we are going to take the 

learnings and apply them going forward. 

 On August 6, the pigging data that we received was very unexpected. 

We encountered a 23-barrel leak from a pipeline. Something was 

happening to our flow lines which we didn’t understand and we took the 

only action we believed we could to prevent the potential of a major spill 

in shutting down Prudhoe Bay until we could confirm the integrity of the 

remaining lines. Over the next five days we brought in hundreds of 

people to complete inspections on the western transit line, sufficient 

inspections to give us confidence the line there was in good enough 

shape to keep production on, so we never actually shut down the western 

side of the line, and today we have in excess of 200,000 barrels a day 

producing from the west side and we have heightened surveillance and 

contingency plans in place in the remote event of a further incident. 

 On the east side of the field, we are pursuing two operations. We are 

vigorously inspecting the lines. To date we have completed over 4,500 

inspections and we are aggressively pursuing bypasses for each of the 

facilities to get them into existing lines which are known to be of good 

condition. We expect those bypasses to be complete by the end of 

October. 

 Where next? What we believe so far is that the inspections that we 

have completed on the west and the east indicate that 10 of 16 miles of 
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transit lines are in good condition and we are working with the DOT to 

understand whether we can bring back the eastern side of the field in 

order to smart pig that operation as soon as possible. A very good 

discussion is going on with the DOT in that respect. 

 So looking ahead, step one, we will pig and smart pig the 10 miles of 

remaining transit lines and we will implement routine pigging and smart 

pigging going forwards on all of our transit lines. Two, we will 

determine the corrosion cause and modify our corrosion management 

system going forward. Three, we will include all of BP’s operated transit 

lines, all 122 miles of those lines, in the DOT’s PIM program, pipeline 

integrity management program. And fourth, we will replace 60 miles of 

transit lines at Prudhoe Bay. Fifth, we have already made organizational 

changes, added a technical director to define and establish operating 

standards and to verify that those standards are indeed being met by the 

business. 

 We have a lot to do but we will get it done, and since 2000, we have 

completed many internal and external reviews of our corrosion 

management program. We have covered everything from the work 

environment to the technical integrity of the program to the integrity of 

our data that we use. I rely daily on teams of experts in Alaska to 

manage corrosion management, indeed as I rely on many teams to 

manage the entirety of our business in the State. 

 But it doesn’t stop there. I welcome challenge, scrutiny, whether it 

comes from government, whether it comes from partners, whether it 

comes from external consultants, indeed whether it comes from the 

workforce. Having worked on the slope for five years, I know the 

importance of getting worker input. It just good business and I take very 

seriously any way we can to shine a spotlight on our systems and am 

determined to make improvements. We have had State reviews, multiple 

internal audits including two reviews by our chief engineer. As we have 

gone back on any of those reviews, no one pointed to the east transit 

lines as a particular problem. If they had, we would have acted on it. 

 I deeply regret this situation occurring on my watch after five years. 

Everyone has talked about the importance of this. I regret it very deeply. 

I am determined to do what we can to get production back safely, quickly 

and efficiently. Thank you. 

 [The prepared statement of Steve Marshall follows:] 
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PREPARED STATEMENT OF STEVE MARSHALL, PRESIDENT, BP EXPLORATION ALASKA, INC. 
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 MR. WALDEN. Thank you, Mr. Marshall. If you welcome scrutiny, 

you are going to feel real welcome here today. 

 Mr. Hostler, thank you for being here, sir, and we look forward to 

your comments. 

 MR. HOSTLER. Mr. Chairman, distinguished members, thank you for 

inviting me to appear before your subcommittee. 

 I am Kevin Hostler and I am President and CEO of Alyeska Pipeline 

Service Company. I am here representing 1,600 employees and 
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contractors who operate and maintain the Trans Alaska Pipeline System, 

or TAPS. We understand the critical importance of our operation of this 

system to the State of Alaska and to the Nation. 

 I am here today to answer two fundamental questions I believe you 

have about our operation. First, to address the question of the potential 

for accelerated corrosion on our operations at TAPS, and second, to 

address the impact of reduced throughout as a result of the recent spills. 

My written testimony covers the fundamentals of both of these questions. 

It also provides a clear description of our integrity management program. 

We have a thorough integrity management program that has been vetted 

by regulators. My team and I are confident that the steps we have taken 

to mitigate the potential for accelerated corrosion are the right ones. In 

my written testimony, you will find a description of our routine 

monitoring and maintenance program to prevent both internal and 

external corrosion in the main line as well as in our pump stations and 

terminal. I would be happy to answer any questions regarding our 

integrity management program, about the potential for corrosion in the 

TAPS system, the impact of low throughput on our system, or any other 

question you may have. 

 I would like to repeat that I represent a team of high-quality people 

who operate and maintain this system, a system that has delivered 15 

billion barrels of oil to the American public. I am confident our 

employees are capable of dealing with the challenges ahead and would 

bring any issue that they had to our attention, any issue that impacts the 

integrity of our pipeline. 

 I thank the subcommittee for this opportunity. 

 [The prepared statement of Mr. Kevin Hostler follows:] 
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PREPARED STATEMENT OF KEVIN HOSTLER, PRESIDENT AND CEO, ALYESKA PIPELINE 

SERVICE CO. 

 Thank you for the opportunity to address the subcommittee about the trans-Alaska 

pipeline and Alyeska Pipeline Service Company. My name is Kevin Hostler and I am the 

President & CEO of Alyeska Pipeline Service Company. I am here today representing 

the 1600 people who operate and maintain the Trans Alaska Pipeline System – or TAPS. 

Our company was founded in 1970 to design, construct, and operate TAPS to safely and 

efficiently move oil from the North Slope of Alaska through the Valdez Marine Terminal 

800 miles to the south. Alyeska Pipeline Service Company is owned by a consortium of 

five companies: BP Pipelines (Alaska) Inc., ConocoPhillips Transportation Alaska, Inc., 

ExxonMobil Pipeline Company, Unocal Pipeline Company, and Koch Alaska Pipeline 

Company. 
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 I am here today to discuss two important issues: to provide the committee with 

assurance about corrosion prevention on TAPS through our integrity management 

program; and to provide insight into the challenges we may face due to reduced 

throughput in the TAPS mainline and how we will manage these challenges. 

 I will also explain how Alyeska has been involved with managing any potential 

solids generated by Prudhoe Bay oil field pigging operations. 

 The issues outlined in this testimony are important to me, our employees, and our 

stakeholders. I take seriously the responsibility I have to run a safe operation that is 

properly maintained to transport the oil we receive. Safety is our first priority in 

resolving the issues we currently face. 

 Since the March 2006 Prudhoe Bay spill by – and continuing through the August 

spill and production shutdown, we have offered our assistance to and worked with BP 

Exploration Alaska Inc. (BPXA) on a wide range of operational issues. We have offered 

response personnel and equipment; we received a technical briefing on the root causes of 

the March spill; conducted and then shared our impact assessment analysis of the impact 

of potential pigging solids being introduced into the TAPS mainline; discussed various 

options to address these solids; and completed construction of a bypass line to offer a 

method to receive and process any solids generated by Prudhoe Bay pigging activities. 

CORROSION CONTROL AND INTEGRITY MANAGEMENT ON TAPS

 Alyeska has not found evidence of accelerated corrosion in the TAPS mainline. 

After the Prudhoe Bay spill in March, our operations and engineering personnel reviewed 

our corrosion control program and have been implementing enhancements identified 

during this review. 

 When I learned that the apparent cause of the spill was corrosion, I asked my 

integrity engineering staff and my pipeline operations staff to provide me with assurance 

that accelerated corrosion was not a threat to TAPS integrity and what additional 

precautions, beyond our existing program, should we undertake. This technical group 

held a brainstorming session to think through all of the potential impacts to TAPS based 

upon what we knew about the March spill. From this we created a Top Ten list of issues 

we should pursue from an integrity perspective. The review verified we have a solid 

corrosion control program and did not identify any immediate corrosion related threats to 

TAPS. Alyeska staff are making satisfactory progress on the issues in the list. I have 

shared this list and a status matrix with committee staff. I will answer any questions from 

the subcommittee about this list. 

 Specific to potential accelerated corrosion on TAPS similar to what BPXA reported, 

the first place we believe we would see this type of corrosion would be in the piping at 

Pump Station One. As part of our Top Ten list, we added several new corrosion 

monitoring locations at Pump Station One, including the deadlegs at the station. 

Deadlegs are sections of pipe inside the Pump Stations that have no active flow. As an 

additional precaution we have increased our corrosion inhibitor injection volumes by 

about 25% throughout the system. 

 It is important to note that TAPS generally benefits from the co-mingling of the oil 

from all of the North Slope fields before they enter the mainline. In addition, TAPS 

benefits from a velocity in the mainline that is greater than the lines feeding into the 

system at Pump Station One. This multi-field mixing action and velocity reduces the risk 

of sediment and water from dropping out of the oil stream. This is worth noting because 

standing water is where we would most likely encounter significant internal corrosion in 

TAPS. 

 Also of note from our Top Ten list, we moved forward our 2007 smart pig run to 

2006. The first part of the TAPS mainline was pigged the first week in August and the 

remainder of the line will be pigged by the end of the year. I requested that the data from 

this pig run be analyzed expeditiously so that we can compare it with the 2004 data to 
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determine if additional integrity actions are necessary. Since the startup of TAPS we 

have run 60 inline inspections. This 2006 pig run will be the 61st smart pig run on TAPS. 

These smart pigs have identified minimal pipe wall loss due to internal corrosion. 

 Alyeska has not identified any wall loss due to corrosion that exceeds Alyeska’s internal 

criteria for wall loss, which is stricter or more conservative than the federal DOT 

regulatory criteria. 

 While we have a lot of faith in our pigging program based upon nearly 30 years of 

experience, we do continue to challenge ourselves to make sure we are evaluating the 

right things on TAPS. It is a process of continuous improvement. 

 Alyeska analyzes the pig run data for anomalies. From this our engineers make 

recommendations about what sections of the pipeline should be physically looked at for 

additional validation and possible repair. This is what we call our integrity investigations. 

We investigate sections of the pipeline – above and below ground – to determine the 

significance of anomalies, including corrosion in those areas. Based upon this 

assessment the appropriate corrective actions are taken, including repairing the section of 

pipe with a sleeve. Since initial startup of TAPS operations in 1977, we have made 656 

below ground investigations and 293 above ground investigations. 

 We run a cleaning pig through the entire pipeline every seven to fourteen days. A 

cleaning pig pushes wax, water, and sediment that may accumulate within the pipeline 

down the line for removal. Further, as throughput declines this will be an even more 

important tool because it will remove water that may drop out of the crude oil at slower 

velocities. 

 In addition to pigging and integrity investigations, our corrosion control program 

also includes the following: 

• Corrosion inhibitor is injected in the deadlegs at the pump stations and Valdez 

Marine Terminal every two weeks. Deadleg corrosion management is not new 

to us. We have had a deadleg corrosion program since the early 1990’s. This 

program includes a manual ultra sonic inspection of the dead legs on a regular 

basis. The frequency of the investigations is based on engineering analysis and 

calculated corrosion rates. 

• Buried pipeline sections were coated and wrapped with tape to protect the steel 

from the environment. (Aboveground pipe has minimal external corrosion 

risk.) 

• A cathodic protection (CP) system passively and actively protects the below 

ground pipe from external corrosion. The passive CP system uses sacrificial 

zinc and magnesium anodes which preferentially corrode, thus protecting the 

pipeline from corrosion (similar to the zinc anodes in home water tanks). The 

active system applies electrical current to the pipeline to prevent corrosion. 680 

CP coupons and 1018 CP test stations are placed along the pipeline to provide a 

way to measure CP effectiveness. Cathodic protection monitoring including 

CP coupons and close interval survey verifies the system data. This survey is 

performed on one-third of the pipeline each year. Areas failing to meet CP 

criteria are either mitigated or if of a minor nature, the system is electrically 

adjusted and resurveyed the following year. We are working with the DOT to 

assess low CP readings on the last 20 miles of the mainline to determine 

appropriate remedial actions. 

• Our facilities corrosion monitoring program includes the use of coupons to 

assess and monitor internal corrosion rates. 

 Alyeska’s corrosion control program is annually monitored by the Joint Pipeline 

Office and is audited routinely by the DOT. 

 Our corrosion control program is a part of our Integrity Management Program. 

Alyeska operates its Integrity Management Program through a controlled document (IM-
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244) titled, “TAPS Integrity Management Program for High Consequence Areas”. This 

is one of the first documents I read upon arriving at Alyeska and was impressed by the 

breadth and depth of our program. If you are interested in reviewing a copy of the 

program, I would be happy to provide it for you. 

 This document is subject to periodic inspections by the U.S. Department of 

Transportation Office of Pipeline Safety as a part of our DOT regulatory program. The 

DOT has inspected this program in 2002, 2003, 2004 and will do so again this October. 

 The Grant and Lease Right of Way agreements require Alyeska to have a 

comprehensive corrosion control program. Corrosion management is extensive and 

monitored by the Joint Pipeline Office to ensure we are meeting its requirements in 

addition to those of the DOT. JPO required Alyeska to develop a comprehensive 

approach to corrosion monitoring activities on TAPS and this became the Corrosion 

Control Management Plan (CCMP) adopted in 2000. The CCMP has been incorporated 

into IM-244. 

 Alyeska’s Integrity Management Program has the following objectives: 

• Prevent leaks to protect public safety and the environment 

• Comply with State and Federal regulations 

• Manage risks – assess, prevent, or mitigate 

• Preserve our assets thus providing reliable oil transportation 

• Provide stakeholder assurance 

 We have a number of major elements within the Integrity Management Program for 

the mainline pipe. We also focus on internal corrosion on the piping in our pump stations 

and the Valdez Marine Terminal. The major elements of our Integrity Management 

Program are: 

• Mainline pipeline inspection: Corrosion In Line Inspection; Curvature and 

Deformation In Line Inspection 

• Cathodic Protection (CP): CP Monitoring; CP System Improvements 

• Aboveground Pipeline Support System: AG Monitoring and Maintenance; 

Vertical Support Member Monitoring and Maintenance; Pipeline Bridges 

• Valve Maintenance Program

• Right of Way Monitoring and Maintenance: ROW Monitoring and 

Surveillance; Rivers and Floodplain Monitoring 

• Earthquake Preparedness: Earthquake Monitoring; Fault Monitoring; Seismic 

Design Control; Seismic Housekeeping 

• Leak Detection System

• Overpressure Protection System

• Pump Station Facilities: Piping Systems; Tanks 

• Valdez Marine Terminal Facilities: Piping Systems; Tanks 

• Oil Spill Response and Contingency Planning

• Fuel Gas Line. 

 As you can see we have a commitment to a comprehensive, systematic, and 

documented approach to integrity management, including corrosion monitoring and 

mitigation. 

 Additionally, I want to stress that our program is primarily focused on preventing a 

leak. Should we encounter a pipeline discharge, we have also worked diligently to be 

prepared to respond to an incident. We have an approved oil discharge prevention and 

contingency plan (C-Plan) that guides our response efforts. The plan is reviewed and 

approved by four regulatory agencies: the Alaska Department of Environmental 

Conservation; the Environmental Protection Agency; the U.S. Department of 

Transportation; and the Bureau of Land Management. We also have a large inventory of 
96

contingency repair equipment and materials that includes a wide range of replacement 

piping, stopples, and leak clamps. We exercise our personnel and equipment on a regular 

basis. It remains our goal through our Integrity Management program to avoid an oil 

discharge. However, I want the committee to know that we are prepared for an incident 

and can respond in a timely manner. 

PRUDHOE BAY TRANSIT LINE PIGGING SOLIDS

 Alyeska has constructed pipe and processing facilities at Pump Station One that will 

allow us to receive pigging solids from BPXA transit line pigging operations without 

exposing TAPS to unacceptable risks. 

 Upon learning about the potential for substantial solids in the Prudhoe Bay transit 

lines, I established a technical team to undertake a thorough risk assessment of the 

potential impacts from the solids to TAPS equipment, systems, and operations, and 

regulatory requirements. I asked them to determine if we could manage the solids in the 

mainline or into our tanks at Pump Station One. My priority was that any solution not 

adversely impact TAPS safety or integrity, nor the safe and efficient transportation of oil, 

which is our responsibility as a common carrier pipeline. The impacts assessment clearly 

raised concerns about allowing solids into the mainline and therefore I made the decision 

that we would not allow this to happen. We shared this position with BPXA and 

interested stakeholders in May. 

 Some of the concerns we had with the potential for a high concentration of solids 

that may be liberated in a short time period include: clogging and damage to strainers 

potentially resulting in a blockage; impacts and damage to meters; impacts or blocking 

transmitter and safety instrument devices that could result in an immediate shutdown of a 

pump station; solids potentially settling in station piping, valves and deadleg piping 

making it difficult to remove; impacts to pressure transmitters and leak detection systems; 

and potentially impacting valves and valve seats, drain lines, strainer baskets as the solids 

passed through each facility. 

 Since that time, we have been working with BPXA to determine the best path 

forward and at their request in August we constructed a temporary line to allow the solids 

to bypass Pump Station 1 piping directly from Skid 50 into a storage tank (Tank 110) for 

temporary storage and then removal and disposal. We will decant the oil received from 

the pigging operations through a line from the tank to our pump station. The solids will 

be processed via centrifuges and clean, marketable oil will be injected into TAPS for 

transportation to market. Remaining water and solids will be managed in compliance 

with federal, state and local laws. Tank 110 was scheduled for routine maintenance next 

summer and any remaining solids will be disposed of when we clean out the tank. 

 This bypass line and processing capacity should be operational no later than the 

middle of September. 

 As we were provided with updated information regarding the volume and 

constituency of the pigging solids in the various lines, we have been able to make 

appropriate decisions. We have approved of the pigging of those lines where we 

reasonably believe we can support the pigging without adverse impact to TAPS. An 

example of this is the pigging that proceeded with the Lisburne transit line. As BPXA 

ran more aggressive cleaning pigs through the Lisburne line we monitored our 

instruments closely to ensure the pigging envelope did not push solids into our system. 

Prior to approving acceptance of Lisburne pigging solids we agreed that the estimates of 

the amount of potential solids would not adversely impact TAPS. BPXA Lisburne 

pigging commenced on June 10th and was concluded on June 16th with the running of a 

smart pig through the line. The data from pigging this line demonstrated that this was an 

accurate estimate and the data from this was incorporated into the estimates and analysis 

for the remaining transit lines. 
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 Throughout this process there have been many meetings and discussions about the 

implications and impacts associated with solutions to address the potential for solids in 

amount that could cause adverse impacts on TAPS from the transit lines. Alyeska was 

researching two options that TAPS could perform and BPXA was exploring two options 

they could perform. The bypass line we constructed has been our preferred option since 

we determined the volume of potential solids in the remaining transit lines would have an 

adverse impact if received directly into the TAPS mainline. 

OPERATING TAPS AT REDUCED THROUGHPUT 

 Based upon technical reviews conducted to date, it is likely, although not certain, 

that Alyeska will be able to safely manage lower throughputs associated the partial 

suspension of Prudhoe Bay production. To do this, Alyeska will need to resolve several 

technical challenges outlined below. 

 Upon learning of the decision to shutdown the Prudhoe Bay field, I called up our 

Crisis Management Team and asked them to look at the short and long term issues this 

would have upon the operation of TAPS. For the short term, I wanted to know what 

issues we would face for significantly lower throughputs. My Oil Movements, 

Operations, and Engineering team put together a plan that would allow for continuous 

operations down to 400,000 barrels per day. The first night following the news, we ran 

the system at 500,000 bpd and the second night tested it at 400,000 bpd. While this is not 

an ideal operating situation our initial report is that it is workable. 

 We then began looking at the long term challenges this presents for TAPS and this 

analysis continues today. While we are confident we can operate normally down to 

500,000 barrels per day, we will face challenges as throughput drops below this rate. 

Among the more significant challenges we are currently evaluating are: 

• Managing issues associated with cooler temperatures of the oil, particularly in 

the winter, and the potential for water and paraffin drop out from the oil; 

• Managing the efficiency of the biological treatment process of our ballast water 

plant because of lower ballast water flows due to reduced tanker traffic to the 

Valdez Marine Terminal; and 

• Managing the potential for increased vibration due to slack line conditions at 

the three mountain passes the pipeline must cross; 

 Alyeska technical experts are evaluating all of these issues to determine the full 

extent of the potential impacts upon TAPS. They are establishing appropriate mitigating 

plans for my management team to consider. From our perspective, we definitely have 

challenges in front of us due to the Prudhoe Bay shutdown. I also know that I have some 

of the best technical resources available for this situation. I want each of you to know 

that our decisions will be based upon the safe operation of TAPS and with no adverse 

impacts to the integrity of TAPS. 

 In conclusion, I wish to restate that we have not seen accelerated corrosion on 

TAPS. We have a healthy concern for the potential for increased rates of corrosion and 

what that could mean to TAPS. I believe we have the right programs and people to 

address corrosion and integrity management on TAPS. 

 We will continue to work with BPXA on the best path forward regarding the pigging 

solids – one that does not compromise the integrity of our system. We have the right 

people assigned to this task and I trust their ability to accomplish this task safely. 

 And last, we share your concerns about operating TAPS at lower throughputs. 

We’re looking at all of the potential impacts this will have on our system and will 

develop responsible plans to mitigate these impacts. I have qualified people working on 

these challenges and they understand my expectations that we proceed with the safety 

and integrity of our operations as our first priority. It is worth noting that our $500 
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million dollar pipeline upgrade project will introduce significantly more flexibility into 

our ability to manage through a situation like the one we are facing today. 

 I thank you for this opportunity to discuss Alyeska and TAPS operations and 

welcome any questions you may have about our operations. 

 MR. WALDEN. Mr. Hostler, thank you for being here today. 

 Mr. Stears, do you have an opening statement this morning? 

 MR. STEARS. I have no opening statement. I am just here to 

cooperate and to help answer questions. 

 MR. WALDEN. Thank you very much. We appreciate the opening 

statements of all of you and your participation in this oversight hearing. 

 Mr. Woollam, I am going to start with you. I know you indicated in 

your brief opening comments you were going to assert the Fifth 

Amendment, which is certainly your right under the Constitution. The 

committee believes that in order to assert that amendment, it needs to be 

in response to a question and so with that, Mr. Woollam, you were 

formerly in charge of the Corrosion Inspection and Chemicals Group at 

BP Exploration Alaska, Incorporated. You were the decision-making 

manager and engineer responsible for all operations related to corrosion 

control and monitoring of the pipelines operated by BP at Prudhoe Bay. 

The subcommittee has learned from several sources that numerous red 

flags were raised about the integrity of the Prudhoe Bay pipelines while 

you were in charge of the CIC group including the 2000 final draft 

Coffman report. Yet in 2002 you initiated and implemented a plan to 

reduce the manpower of a key pipeline corrosion monitoring team by 25 

percent. So my question, Mr. Woollam, when did you become aware of 

the pipeline integrity problems faced by the Prudhoe Bay transmission 

lines including concerns about accelerated localized corrosion, microbial 

corrosion and that the failure to send maintenance pigs or smart pigs 

down the transmission lines was placing those pipelines at high risk of 

failure. 

 MR. WOOLLAM. Mr. Chairman, based upon the advice of counsel, I 

respectfully will not answer questions based upon my right under the 

Fifth Amendment of the United States Constitution. 

 MR. WALDEN. Mr. Woollam, are you refusing to answer all of our 

questions based on the right against self-incrimination afforded to you 

under the Fifth Amendment of the U.S. Constitution? 

 MR. WOOLLAM. Yes, Mr. Chairman. 

 MR. WALDEN. And is it your intention to assert such right in 

response to all further questions from the subcommittee today? 

 MR. WOOLLAM. Yes, Mr. Chairman. 

 MR. WALDEN. Given that, if there are no further questions from the 

members, I will dismiss you at this time subject to the right of the 
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subcommittee to recall you if necessary, and at this time you are excused, 

sir. 

 MR. WOOLLAM. Thank you. 

 MR. WALDEN. Thank you. 

 Mr. Marshall, according to information provided by British 

Petroleum, the western operating line had not been pigged since 1998 

and the eastern operating line had not been pigged since 1992. Why was 

there not more regular pigging of these transit lines? 

 MR. MARSHALL. Mr. Chairman, you are indeed correct. The 

western line was pigged and smart pigged in 1998. We recovered a very 

insignificant amount of solids, less than two cubic yards, from that pig 

run. The line indicated it was in good condition. What we have in each 

intervening year is a series of ultrasonic testing at various points along 

the line to basically confirm and corroborate the information from the 

smart pig run. We also have electrical resistance probes, coupons, and 

all of this is on the back of a very comprehensive program of corrosion 

inhibition across the entirety of the operations going all the way back to 

the well head, through the gathering lines, through the flow lines, 

through our facilities, so we are watching all of the corrosion at those 

points. 

 MR. WALDEN. Could you turn to Exhibit 4 in the book, which you 

should have at the witness table. Do we have a book at the witness 

table? Our staff will be bringing that to you. I will go ahead. On page 

2, it says--this Exhibit 4, page 2, it says, “For example, smart pigs can 

inspect the service of an entire pipeline. Smart pigs and other automated 

techniques are helpful in identifying locations that should be more 

closely monitored using one of the point inspection methods, e.g., visual, 

ultrasonic, radiographic. Smart pigs can also provide assurance that the 

spot inspections are truly representative of the pipeline condition.” 

Given that BP’s own internal corrosion procedures highlight the merits 

of smart pigging, and that is what I was reading from, can you explain 

the lack of the smart pigs on these lines? I mean, I think that is what we 

are getting at here in the committee. We understand you do these other 

checks. Why when Alyeska is running smart pigs down the TAP every 

two weeks, why would it be years in between when you would run smart 

pigs down these feeder lines? 

 MR. MARSHALL. Again, Mr. Chairman, we looked at the data from 

1998, confirmed the line was in good condition, did the ultrasonic 

testing. We did see some increases in corrosion starting in 2004 and 

2005, and at that point we did take the action to increase the frequency of 

testing and-- 

 MR. WALDEN. But not with smart pigs. 
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 MR. MARSHALL. And commissioned a smart pig in 4Q of 2005 to be 

run this year. Unfortunately, that smart pig was not run before the spill 

but it was planned and budgeted for in Prudhoe Bay’s budget this year. 

 MR. WALDEN. How much does it cost? What do you have to budget 

for a smart pig to run down those lines? 

 MR. MARSHALL. To the best of my knowledge, it is not a huge 

amount. 

 MR. WALDEN. So budget is really not the issue? 

 MR. MARSHALL. Budget is not the issue, no. 

 MR. WALDEN. Okay. Please turn to Exhibit 7 again in this. This 

document is an instant investigation report on the March 2006 spill on 

the western operating line. According to the report, the leak occurred at 

a buried caribou crossing. Aren’t bends and low points in the line such 

as buried crossings at higher risk of corrosion because of sludge, 

sediment, scale and/or water that tend to build up at these locations, 

particularly in low-flow lines? Aren’t these dips in the line really more 

subject to this type of failure and corrosion? 

 MR. MARSHALL. Mr. Chairman, I am not a corrosion expert but 

certainly the lines on the west side of Prudhoe Bay have a number of 

road crossings and caribou crossings where there are elevation changes. 

What appears to have occurred is the--we believe the accumulation of 

solids which had occurred perhaps more recently than we might have 

expected in these low areas. 

 MR. WALDEN. On page 11 of the report, it points out that the 1998 

smart pigging of the western operating line showed “moderate internal 

and external corrosion” with many areas having 30 percent to 50 percent 

wall loss. The pig run specifically identified six locations within the 

caribou crossing that was the site of the March leak where internal 

corrosion pitting was occurring. Given these results, why didn’t BP 

accelerate the schedule for the next pigging? Again, this was back in 

1998 and it identified some areas with 30 to 50 percent wall loss. 

 MR. MARSHALL. Mr. Chairman, my understanding here is that the 

30 to 50 percent wall thickness loss is not actually generalized wall loss. 

It is pitting corrosion, discrete pitting corrosion, generally at the 6:00 

position in the bottom of the line, and the inspections that we did, the 

ultrasonic testing, was done and the coupons were looked at four times 

per year, twice the industry average on those lines, to confirm the 

deterioration in the system was not occurring at a greater rate. 

 MR. WALDEN. Well, on page 6 it says that, and I quote again, “With 

the exception of smart pig runs, there isn’t a way to directly monitor 

internal corrosion inside of the cased pipe road and caribou crossings 

without having to excavate the crossing and remove the outer casing 

from the pipe.” So despite being aware of pitting and corrosion at this 
101

crossing and knowing that these points were not accessible for ultrasonic 

testing, BP nonetheless decided to wait 8 years between smart pig runs, 

right? 

 MR. MARSHALL. We did encounter some increased corrosion in-- 

 MR. WALDEN. In the dips? 

 MR. MARSHALL. In the-- 

 MR. WALDEN. In the crossings? 

 MR. MARSHALL. I can’t say they were actually at the crossings. The 

inspection points we were doing through ultrasonic testing, we did start 

to see some increases in 2004 and critically in 2005 which led to the 

establishment of the smart pig run scheduled for 2006. 

 MR. WALDEN. So where the problem really was, was in the place 

where the leak occurred in the caribou crossing, right? 

 MR. MARSHALL. Sorry. Could you repeat the question again? 

 MR. WALDEN. Well, let me go to the exhibit here, and it says, “The 

accuracy of the smart pig data was”--I assume it should be were--

”confirmed the follow-up UT inspections. The ‘98 smart pig run also 

identified six specific areas inside this caribou crossing where internal 

corrosion pitting was occurring. Percent wall loss at these six locations 

in this particular caribou crossing showed relatively low line wall loss of 

between 5 and 25 percent.” The leak was one of these six locations and 

had a wall thickness loss of 9 percent in the 1998 pig run. So you are 

seeing leaks where there wasn’t even earlier identified much wall loss, 

right, if it was 9 percent, and yet the leak then occurred in one of those 

areas. It would seem to me that you are really missing the boat by not 

putting those smart pigs in there. 

 MR. MARSHALL. Mr. Chairman, we believe that the changing 

conditions on the western side of the field had some bearing on that. We 

will not be able to confirm that absolutely until we do the laboratory 

analysis of the failed pipe. 

 MR. WALDEN. Let me ask you this. In other operations you may be 

familiar with, with similar feed lines outside of Prudhoe Bay, do 

companies run smart pigs on a regular basis, regular being more than 

every eight years? 

 MR. MARSHALL. Mr. Chairman, I am not a pipeline expert. I have 

to state that. I am aware of some lines that are pigged. I am also aware 

that some lines are not pigged. But I can’t give you exact details of that. 

 MR. WALDEN. Your written testimony notes that BP runs nearly 370 

maintenance pig runs per year on the North Slope. Why have none of 

these been run on these key transmission lines for the last eight years? 

And that is the heart of what we are after here. 

 MR. MARSHALL. Mr. Chairman, we have a very--notwithstanding 

these leaks, we have a very comprehensive corrosion management 
102

system. It is one that is recognized by many as being very 

comprehensive in that it covers 1,500 miles of pipelines all the way 

through the facilities. Notwithstanding the leaks though, we tend to 

focus--we do focus all of our efforts where we believe the risk of 

corrosion to be the highest. That typically is where we have gas and 

water, where it is three-phase flow. We have high carbon dioxide 

content in the gas. Left unchecked, that can corrode about a quarter of an 

inch of steel per year. That is where we put the vast majority of our 

efforts upstream. 

 MR. WALDEN. Given all that though, clearly in this case the 

procedures and protocols failed your company and the American people, 

right? I mean, because you ended up with these leaks and now you have 

discovered basically you are going to have to replace how many miles of 

the pipe? 

 MR. MARSHALL. We are going to replace 16 miles of pipe. Even 

though we believe 10 miles are actually in good condition, we have 

committed to replace all 16 with lower diameter pipe which will provide 

a firm foundation for future business for a field that has the potential now 

to run for many, many years with the prospect of gas pipeline coming 

down the line. 

 MR. WALDEN. My time has expired. I turn to the gentleman from 

Michigan, Mr. Stupak, for 10. 

 MR. STUPAK. Thank you, Mr. Chairman. Mr. Marshall, if I may 

continue. The Chairman asked you a lot about the western operating 

area line. I want to ask you about the eastern operating line. And if you 

can, just answer yes or no, I would appreciate that. It is the eastern 

operating line that had the August spill. Is that correct? 

 MR. MARSHALL. The eastern line from Flow Station 2 to Flow 

Station 1, yes. 

 MR. STUPAK. And the eastern operating line was last pigged 

somewhere around 1992? 

 MR. MARSHALL. I believe the eastern line was pigged in the early 

1990s, maintenance pigged, and smart pigged just after that. 

 MR. STUPAK. Isn’t it true that when the line was last pigged, it had 

significant scale buildup and possibly other materials that made pigging 

so difficult that it caused problems downstream for the operators at the 

Trans Alaskan Pipeline? 

 MR. MARSHALL. Mr. Congressman, since the March spill, I have 

become aware of discussions about solids occurring in those lines and 

yes, indeed-- 

 MR. STUPAK. Caused problems for the operators down the line? 

The strainers were-- 
103

 MR. MARSHALL. The strainers were plugging with scale, as I 

understood. 

 MR. STUPAK. And that was 1992? 

 MR. MARSHALL. I believe it was in the early 1990s. I can’t give 

you the exact date. 

 MR. STUPAK. Okay. Isn’t it true that it is generally the solids 

including scale and sediment can be a contributing factor for corrosive 

activity because they can trap water or other corrosion-causing 

organisms against the pipe wall? Is that true? 

 MR. MARSHALL. I am not a corrosion expert but I do believe that is 

to be true, yes. 

 MR. STUPAK. Okay. And isn’t it true that sludge, sediment and 

scale can also make it harder for corrosive inhibitors to effectively reach 

the pipe wall and therefore make them less effective in reducing 

corrosion? 

 MR. MARSHALL. Again, I am not a corrosion expert but I do believe 

that to be a possibility, yes. 

 MR. STUPAK. But you are the head of the corrosion program up here 

on the North Slope, right? 

 MR. MARSHALL. No, I am President of the-- 

 MR. STUPAK. President of the--I am sorry. 

 MR. MARSHALL. I do rely on a lot of people to give me advice on all 

aspects of business including corrosion. 

 MR. STUPAK. Well, on the eastern operating area line, it has a pig 

receiver and a pig launcher, and so it was designed to accept a pig to go 

through line, right? 

 MR. MARSHALL. That is my understanding, yes. 

 MR. STUPAK. Can we go to photo number 8 right here? This was 

taken by the committee staff. That is the pigs in your warehouse up 

there, and you can see all of them, different sizes and for all parts of it. 

Then why in your best estimation was the eastern line never pigged since 

1992? You have all this equipment in here, different sizes, to get it 

through the line. Why wasn’t it done since 1992 if you had the best 

comprehensive corrosion program in the world? 

 MR. MARSHALL. Mr. Congressman, I cannot comment on the period 

from the early 1990s through to 2000. When BP took over operation of 

the eastern transit lines in 2000 as a result of the ARCO merger, we 

instituted ultrasonic testing. It was something we instituted of the eastern 

transit lines. Only two-- 

 MR. STUPAK. Photo 7, please. Photo 7. See, my problem with the 

ultrasound, if you had started this in 2000 when you took over the line, it 

is so tedious. I mean, all you do is take a little swab and put it on part of 

the pipe and then you do a detection much like an ultrasound, correct? 
104

 MR. MARSHALL. That is correct. 

 MR. STUPAK. And that is only where the swab is, and you can do 

very little pipe, and those underground, like the caribou crossing, where 

we had the spill earlier, you can’t do that because it is underground, so 

that doesn’t seem very effective. So that is why I am thinking, well, why 

would you go to ultrasound, not pig it then in 2000 if you didn’t know 

the quality of it? You are trying to prevent spills and improve the flow 

of oil? If you took it over in 2000, if you were unsure of the quality and 

the corrosion problem, why didn’t you pig it then if it is already designed 

for pigging? 

 MR. MARSHALL. I can’t comment specifically on decisions that 

were made in 2000 or not. What I can say is that only two years 

previously, the western area transit-- 

 MR. STUPAK. I am talking eastern now, eastern line. I want to stay 

with the eastern line. The Chairman got you on the western. I am on 

eastern. 

 MR. MARSHALL. If you just allow me-- 

 MR. STUPAK. Sure. 

 MR. MARSHALL. --a few minutes to explain how the west has 

relevance, potential relevance to the east. Only two years previously, BP 

in operating the western lines had pigged and smart pigged those western 

transit lines. The indications were given that the lines were in good 

condition. We were taking over the eastern transit lines as a result of the 

ARCO merger. Those transit lines are broadly similar in geometry, eight 

miles on either side handling essentially the same fluids. We instituted a 

spot check of the ultrasonic testing and essentially confirmed a very 

similar condition of the eastern transit lines as the west. 

 MR. STUPAK. I don’t mean to be argumentative, but all of our 

reports show that even the western line in 1998 had corrosion problems, 

and if it had been 1992 until 2000 when you took over, 8 years, and now 

we are 6 years later, 14 years, it was never pigged. If you knew in 1998 

when they did the pigging on the western line there were corrosion 

problems, I think it would lead you to at least look at the eastern line a 

little bit closer. I don’t mean to be argumentative with you but common 

sense will tell you that. 

 Mr. Hostler, if I may, you scrape your entire 800-mile line every 14 

days. Is there a reason for that other than reducing drag on the pipe? 

Why is it generally a good idea for pipeline maintenance, in other words? 

 MR. HOSTLER. Congressman, it is rather simple. We do that every 

14 days just to keep the pipe in good, clean condition. 

 MR. STUPAK. Can corrosion start in 14 days? 
105

 MR. HOSTLER. No, no, but we worry about the buildup of solids or 

liquids, water, in the pipeline and so we run a cleaning pig, a mechanical 

pig, every 14 days. 

 MR. STUPAK. Okay. Mr. Marshall, let me ask you this then. When 

did BP first know that major solids to the amount that the line could not 

easily be pigged were in the eastern operating area line--eastern line? 

 MR. MARSHALL. Mr. Congressman, to the best of my knowledge, 

the discussions started after the March spill. That was when it was first 

brought to my attention when conversations turned to the existence of 

solids, recollections of the problems that had occurred in the early 1990s 

with the plugged strainers and it caused us to consider what might be the 

worst case, solids accumulation in these lines. We wanted to-- 

 MR. STUPAK. Okay, so that was March and that was after the 

Department of Transportation issued its corrective action order, and from 

what I understand, you spent a considerable amount of time engineering 

efforts to determine how significant the sludge and scale buildup was in 

both the eastern and western line. Isn’t that correct? 

 MR. MARSHALL. Sorry. Could you repeat your-- 

 MR. STUPAK. Sure. After you got your corrective action order, you 

spent a lot of time engineering that, that is what you are telling me, to 

determine how much buildup did you have in the eastern and western 

line. Isn’t that correct? 

 MR. MARSHALL. That is correct. Yes. 

 MR. STUPAK. Did you have any information prior to the Department 

of Transportation March 15 corrective order about the buildup in the 

eastern line? 

 MR. MARSHALL. I can’t speak for every level of the organization 

but I became aware of that after the March 2 spill. 

 MR. STUPAK. Well, if you had no idea how much scale, sludge or 

other deposits were in your lines, then what does that say about BP’s 

understanding of the quality of its pipelines? How can BP say it had a 

good integrity management plan of its pipelines if it doesn’t know the 

true condition of its pipes and the volume of solids they contain? 

 MR. MARSHALL. Certainly we have relied extensively on the 

pigging data from 1998 on the western where we had recovered-- 

 MR. STUPAK. I am still on the eastern one, because last time you 

pigged that was 1992. It is the major line. I mean, we had to shut that 

down. So how can you sit here today and say you have a good integrity 

management plan of its pipes when you do not know the true condition 

of the pipes or the volumes of the solids they contain and the last time it 

was pigged was 1992? So I see a contradiction here. It sounds like you 

didn’t really explore it until you got the corrective order from the 

Department of Transportation in March of 2006. 
106

 MR. MARSHALL. It was certainly the spill that caused us to consider 

what might be the implications of pigging those lines. 

 MR. STUPAK. Right. How would you not know that something is 

causing corrosion? How would you not know that? I guess that is the 

best way to put it. You saw it in the western line in 1998, the one that 

hadn’t been pigged since 1992. You know your PSI is going down, 

don’t you, the pounds, the pressure to move the oil through? You know 

that is going down every year, right? What was it in 1992? Do you 

know? 

 MR. MARSHALL. I don’t have that information. 

 MR. STUPAK. They tell us it was about 800, and at the time of the 

spill it is down to 80. You have lost 10 times the pressure. That in itself 

tells you right there that we have a problem with the corrosion, doesn’t 

it? 

 MR. MARSHALL. Certainly velocity of fluid through the line appears 

to be one of the indicators. The two sections of line that have failed, the 

two three-mile sections-- 

 MR. STUPAK. And isn’t another thing you look at is how much oil 

you are getting out? Isn’t most of the stuff you are getting out right now, 

isn’t that mostly water and sand and less and less oil each year from 1992 

to 2006? 

 MR. MARSHALL. You are absolutely correct about the water, 

Congressman. 

 MR. STUPAK. And therefore if you got more water, isn’t that going 

to cause corrosion and buildup in these lines? 

 MR. MARSHALL. Mr. Congressman, the facilities upstream, the flow 

stations and gathering centers, are designed to take out the water. We 

operate to the same-- 

 MR. STUPAK. But it doesn’t take it all out. We know that, and we 

know where there are dips in there. That is where it settles and that is 

when we have problems. You have slow flow, less oil coming up, more 

sand and water. How could you not know that there was buildup and 

solids and how could you not pig since 1992? I guess I am just baffled 

on that. 

 MR. MARSHALL. Mr. Congressman, if I could try and offer my 

perspective on that. Certainly the conditions of the reservoir are 

changing. You are absolutely correct. As the oil production has 

dropped, the water production increases. We certainly see some solids 

from the west, not necessarily from the east, but the facilities, the 

producing facilities, the flow stations and gathering centers, are designed 

to take the incoming flows from the wells down to the same 

specification, the .35 bottom sediment and water specification that has 

been in existence for 29 years at Prudhoe Bay. Our records show that the 
107

performance of those facilities is indeed broadly similar over the years so 

those facilities are actually operating and there isn’t increasing amounts 

of water through those transit lines than there has been over time. 

 MR. STUPAK. Thank you, Mr. Chairman. 

 MR. WALDEN. Thank you. The chair now recognizes the gentleman 

from Texas, Dr. Burgess, for 10 minutes. 

 MR. BURGESS. Thank you, Mr. Chairman. Maybe we could just 

stay on this subject for a moment, Mr. Marshall, the allegations that BP 

did not pig the lines more frequently because of concerns that there was 

so much sediment, sludge or scale in the lines that the pigs might get 

stuck or unacceptable levels of junk would get flushed into the Trans 

Alaska Pipeline. Are those reflections accurate? 

 MR. MARSHALL. Mr. Congressman, certainly those are some of the 

conversations we have had in BP and talking with Alyeska. We are 

concerned about any downstream impacts that the pigging operations 

might have had. We wanted to fully understand what the implications of 

any pigging operation would need to be. We made some very early 

estimates of what a worst case solids buildup might have been. We did 

some subsequent testing using gamma ray analysis, thermal imaging and 

velocity calculations and determined those initial estimates were very 

conservative. We determined that the actual solids level was about 10 

percent of those initial estimates. It did take us some time to get to that 

point. In retrospect, I wish we could have done that quicker. I would say 

that. But once we determined that those solids levels were indeed lower, 

we have been aggressively pursuing two options to enable pigging 

without impacting the strainers or the downstream operations. There has 

been a crossover back into our existing facilities that we can pig into that 

through Flow Station 3 and we have been working with Alyeska to 

institute a crossover into one of the Pump Station 1 tanks. Both of those 

crossovers are essentially complete and now we are working with the 

Department of Transportation to determine whether the inspections we 

have completed on the east side are sufficient enough to allow us to go 

ahead and start pigging and start pigging the eastern transit line to 

determine the condition it is in. 

 MR. BURGESS. On the--in the evidence binder that you have, Exhibit 

20, there are some handwritten notes that appear to indicate that as a 

result of pigging by ARCO in the eastern operating line in 1990, so much 

debris was generated that it caused severe damage to Alyeska’s strainers 

at Pump Station 1. There were also apparently some debris problems 

during a September 1991 pig run. Was BP ever made aware of these 

problems either before or after it acquired the eastern operating line from 

ARCO? 
108

 MR. MARSHALL. Mr. Congressman, I haven’t seen this particular 

copy of this document. What I am aware of personally is that it was only 

after the spill that the conversations around solids really started to take 

hold. It was in the last few weeks that we actually spoke to the--a 

member of my team actually spoke to the engineer with ARCO who 

actually was involved in these pigging runs, and what I understand to be 

the result of that was that the lines were indeed cleaned, they were 

pigged with maintenance pigs and that the smart pig was run but we 

didn’t get good data or ARCO did not get good data from that smart pig 

run. We understand there was scale buildup in the strainers at Pump 

Station 1 and that is why we are actually pursuing the bypasses now to 

allow pigging to alternative locations so we don’t jeopardize those 

strainers and meters at Pump Station 1. 

 MR. BURGESS. That is a 15-year time jump though from when 

ARCO did that investigation to when the leak occurred, so I mean, that 

was a significant amount of time involved between the pigging that 

showed some scale buildup and the demonstration of a problem with the 

leak. Is that--am I correct in that? 

 MR. MARSHALL. It is 15 or 16 years, yes. 

 MR. BURGESS. Well, let me ask you this. If the company didn’t 

have concerns about the possibility of buildup in the lines, why didn’t it 

pig the lines immediately after the corrective action order was issued by 

the Department of Transportation in March of 2006? 

 MR. MARSHALL. It was only when we started--after the March spill, 

it was only when we started thinking about the implications of pigging 

either the east line or the west line that we started to have conversations 

with Alyeska and the concerns were raised about the potential of solids, 

and that is when we did some estimates and then we did the further 

testing as I said. One of the other things that precluded us from doing a 

rapid pigging of the line, we originally indicated that we would intend to 

pig the western line within 3 months of the spill and as it turned out, the 

Department of Justice required a section of the failed line to be 

preserved, and not to be able--and to not pig the line in the west to 

disturb the solids and the sediment that may exist on that failed section of 

line. So that has proved to be a difficulty and we have not been able to 

use the pig launcher on the western section of the line to pig to Pump 

Station 1. In order to pig the remainder of the west, we are installing a 

34-inch launcher at GC-1, at Gathering Center 1, to enable the 5-mile 

section of line to be pigged. We expect that work to be completed in 

October and we will be able to pig that line shortly after that. 

 MR. BURGESS. Let me just ask an opinion or ask your opinion that, 

would the company BP have an obligation to know the condition of its 

lines at all times? 
109

 MR. MARSHALL. I am not sure of my opinion. I need to think about 

that. We strive to understand the condition of all of our equipment and 

lines. 

 MR. BURGESS. But as someone on the other side pointed out, it is 

your core business. I think Mr. Dingell said your core business is the 

recovery and delivery of oil to the Nation’s energy supply. 

 MR. MARSHALL. And we spend-- 

 MR. BURGESS. And the pipelines are a critical part of that. 

 MR. MARSHALL. Indeed, we spend considerable amounts of money. 

We have increased the corrosion spent 80 percent since I have been in 

Alaska. We spread that effort over the areas where we judge the 

corrosion risk likely to have corrosion to be the highest, so we--clearly in 

retrospect, this is something we missed. 

 MR. BURGESS. Now, Admiral Barrett has publicly expressed 

significant concern, disappointment about BP’s failure to plan for, invest 

in bypass solutions for the Prudhoe Bay transmission lines. Why did BP 

not have any contingencies in place for crucial transmissions so that a 

complete shutdown could have been avoided? 

 MR. MARSHALL. Mr. Congressman, there are a number of lines on 

the North Slope, a considerable number of flow lines carrying different 

products various places. The western side of Prudhoe Bay, which is the 

side of Prudhoe Bay that BP has operated since 1977, indeed has a 

number of bypass options there. We were able to use one of those, a 24-

inch line, on the back of the GC-2 transit line failure, to bring the 

majority of GC-2’s production over to Pump Station 1. We were able to 

take advantage of that. Unfortunately, there are not the same level of 

bypasses and options designed in to the eastern side of the field. I can’t 

go back and comment on the design basis from the 1970s but we are 

working very diligently now to implement the bypasses to the Endicott 

and Lisburne flow lines. We expect to have those done and the potential 

to have the field fully back up to over 400,000 barrels a day by the end of 

October subject to DOT approval. 

 MR. BURGESS. Mr. Hostler, does Alyeska have redundancies or 

contingency plans in place? 

 MR. HOSTLER. Yes, Congressman, we do. You know, our first 

focus is on preventing any type of oil spill or leakage from the pipeline 

but we do have contingency repair equipment in place. We have 

additional pipe in place so that if we do have a spill, we can replace the 

damaged area. In addition to that, as a result of the bullet hole that we 

experienced in the early part of this decade, we have bullet hole repair 

equipment and items like that that are available to us. In addition, we 

have built redundancy in our pumping system that allows us to continue 

to operate in the event of a shutdown. 
110

 MR. BURGESS. Great. I will take that as a yes. 

 Mr. Marshall, my time is just about up and there is a series of 

questions that relate to the Vinson and Elkins redacted report which I in 

fact just received this morning about the whistleblower concerns and I 

am concerned about some of the health and safety issues that were raised 

in this, and Mr. Chairman, I am going to ask permission to submit these 

questions in writing for the record, but I would just ask in the two 

seconds I have left, Mr. Marshall, that it appears that there have been--

some of these concerns have been going on for several years, that when 

we had an individual just take the Fifth Amendment here on your panel, 

were there concerns over the behavior of someone on your team who was 

supposed to be overseeing some of these issues and listening to the 

concerns of the employees who actually operated and administered the 

pipeline? 

 MR. MARSHALL. Yes, there was. I first became aware of some 

employee concerns in this particular area to the best of my knowledge in 

early 2003. Those concerns were raised through our safety committee, 

and at the same time to one of our external contacts that we have. We 

have a number of avenues there. 

 MR. BURGESS. And again, I am going to submit these questions in 

writing and I would appreciate an answer, but can you reassure the 

committee with all of the problems that we have seen, not just in Alaska 

but in my home State of Texas where 15 people died, that the people 

who bring up health and safety concerns, whether they be whistleblowers 

or just regular people who are voicing concerns, that those concerns are 

being addressed and that there is not retaliation brought against 

employees who bring up these problems? 

 MR. MARSHALL. You have my absolute assurance on that, that that 

is totally against BP’s policy. We--I don’t care where employee 

concerns are raised, through one of our internal channels, externally, I 

don’t care where they are raised, as long as they are raised. If we get 

specificity so we can go out and external what the issue is, we will 

investigate it, take the appropriate action and move on. That is just 

simply good business. As I said earlier, I worked on the slope for five 

years. It is the people on the slope that know what is working well, what 

isn’t, and if any of us ignore those concerns, that is just simply not good 

business. 

 MR. BURGESS. I have been there. There is not much margin for 

error in that environment. 

 Mr. Chairman, you have been very indulgent and I will yield back. I 

do want to submit these questions-- 

 MR. WALDEN. Without objection, the questions will be submitted. 

We look forward to your answers. 
111

 Before I go to Mr. Dingell, I just want to clarify one thing I think I 

heard you say. Did you say the Department of Justice has subpoenaed a 

piece of the pipe? 

 MR. MARSHALL. That is correct. 

 MR. WALDEN. Do you know why they would have done that? That 

seems like a rather extraordinary piece of evidence to-- 

 MR. MARSHALL. I believe it is to understand and do the testing on 

the corrosion mechanism and confirm what the basis for that leak in the 

GC-2 line was. 

 MR. WALDEN. Why would the Department of Justice do that though 

as opposed to the Department of Transportation? 

 MR. MARSHALL. This is part of the criminal investigation going into 

the potential violation of the Clean Water Act. 

 MR. WALDEN. I see. Thank you. Mr. Dingell. 

 MR. DINGELL. Mr. Chairman, I thank you. 

 Mr. Marshall, as the President of BP Exploration Alaska, you are 

primarily responsible for the operation of the Prudhoe Bay field. Is that 

correct? Yes or no? 

 MR. MARSHALL. I am responsible for all of BP’s activities in 

Alaska. 

 MR. DINGELL. Great. And you have held that position for how 

long? 

 MR. MARSHALL. I arrived in September 2001. 

 MR. DINGELL. Thank you. With regard to the oil transit line that 

failed in the western operating area of Prudhoe Bay in March, isn’t it true 

that the last time that line was inspected and smart pigged was 1998? 

 MR. MARSHALL. The last time it was smart pigged indeed was 1998, 

yes. 

 MR. DINGELL. Are you familiar with the term “viscous oil”? 

 MR. MARSHALL. Yes, I am. 

 MR. DINGELL. If so, would you agree that the characterization of 

that production of this type of oil is known to increase the amount of 

water in the crude stream and the amount of sediment also known as 

sand fines or flower? Is that true? 

 MR. MARSHALL. Mr. Congressman, I am aware that the production 

of viscous oil does indeed produce more sands through the well bore into 

the flow lines and into the facilities, yes. 

 MR. DINGELL. Okay. Isn’t it true that a buildup of these flower 

sands in a line could cause corrosion either by trapping water beneath 

them or by providing an environment in which bacteria could flourish? 

 MR. MARSHALL. Mr. Congressman, I am not a corrosion expert. I 

believe that to be a possibility. In this particular case, it is only when we 

do the failure analysis of the pipe will we truly understand what 
112

mechanism actually caused the failure of both the east and west transit 

lines. 

 MR. DINGELL. All right. Now, isn’t it true that BP did not schedule 

a maintenance pig run through the western transit line in 2000 when it 

began to increase the amount of viscous oil in the line? 

 MR. MARSHALL. Mr. Congressman, the viscous oil production 

actually started in 2004 when we started drilling the western flank of 

Prudhoe Bay from the Orion field. So that was a 2004 startup, I believe. 

 MR. DINGELL. Let me do the question again, if you please, sir, and 

the question is this, and all it really requires is a yes or no. Isn’t it true 

that BP did not schedule a maintenance pig run through the western 

transit line in 2000 when it began to increase the amount of viscous oil in 

that line? Is it true or false? 

 MR. MARSHALL. I am not sure I can answer your question, Mr. 

Congressman. 

 MR. DINGELL. Well, let me read this. This language says this: 

“Electronic data collected during the investigation in graph below 

documents an increase in viscous oil production at GC-2 from 

approximately 1,500 BPD in January 2000 through a production high of 

16,098 BPD in October 30. G-2 produces more viscous oil than any 

other facility on the North Slope and today represents approximately 15 

percent of total GC-2 production.” Is that a true statement? 

 MR. MARSHALL. I can’t comment on the statement. I haven’t seen 

that. My understanding, Mr. Congressman, is that we did not start 

viscous oil production until 2004--2000. 

 MR. DINGELL. Now, the document is regarding the GC transit line 

spill at Prudhoe Bay western areas or rather western operating area 

March 2, 2006, incident investigation report. That is a BP document. 

 MR. MARSHALL. I am not familiar with the specific reference but I 

would be happy to look into that and provide back to the subcommittee a 

specific answer. 

 MR. DINGELL. I find myself somewhat hard-placed to ask questions 

when you are not prepared to answer. Let me ask another question. Isn’t 

it true that since 2000 BP’s production of viscous oil moving through the 

western transit line increased from 1,500 barrels a day to a high of 

16,000 as reported in the document from BP which I just read to you? 

 MR. MARSHALL. Mr. Congressman, I don’t have the information 

available to me to be able to confirm or corroborate that. I would be 

happy to look into it. The increases in viscous oil production occurred 

primarily when we started drilling the Orion field in 2004 but I would be 

happy to look into the specifics-- 

 MR. DINGELL. Mr. Marshall, I want to be courteous to you but I 

have a limited amount of time and I am trying to get answers to questions 
113

that I think we should agree are important. Now, I assume you are 

aware, Mr. Marshall, of internal BP data that suggests that the amount of 

sediment moving through the western transit lines was increasing and 

that the increase was commensurate with the amount of viscous oil that 

you are moving through the line. Now, this is from the Chapman Report, 

page 14. Just yes or no. 

 MR. MARSHALL. I am not in a position to say yes or no. I am sorry, 

Mr. Congressman. 

 MR. DINGELL. All right. Now, are you aware of a report issued by 

John Baxter, an employee of BP, entitled Alaska Transit Pipeline 

Technology Review released in April of 2006, yes or no? 

 MR. MARSHALL. Yes, I am. 

 MR. DINGELL. That report indicates that since the introduction of 

viscous oil in the western transit lines, one of your gathering centers had 

experienced a number of upsets which resulted in increased amounts of 

water and sediment being released into the transit line. Are you aware of 

this? 

 MR. MARSHALL. Yes, I am. 

 MR. DINGELL. Now, the Baxter Report cites an upset of nearly 

10,000 barrels of water being unintentionally released from Gathering 

Center 2 into the western oil transit line. Isn’t it true that you did not run 

a maintenance pig after this event in the western transit line to ensure 

that the water didn’t get trapped in low-lying spots in the line? 

 MR. MARSHALL. It is correct that we did not run a pig after that 

incident, yes. 

 MR. DINGELL. You did not. Given all this, isn’t it true that you had 

potentially corrosive agents in your lines as a result of increased 

production of viscous oil and that you should have scheduled a 

maintenance pig run sooner than the 8-year interval that you had this line 

on? 

 MR. MARSHALL. I am not sure I am in a position to say that there 

was definitive evidence of that. 

 MR. DINGELL. Well, that is-- 

 MR. MARSHALL. Clearly in retrospect, you know, pigging would 

have been a positive step we could have taken-- 

 MR. DINGELL. Well, let us-- 

 MR. MARSHALL. --to clean those lines. 

 MR. DINGELL. --look at this. Alyeska, which runs a pipeline with 

which I am sure you are familiar, said this in their testimony today: “We 

run a cleaning pig through the entire pipeline system every seven to 14 

days. A cleaning pig pushes wax, water and sediment that may 

accumulate within the pipeline down the line for removal. Further, as 

throughput declines, this will be an even more important tool because it 
114

will remove water that may drop out of the crude oil at slower 

velocities.” Now, how many times did you run maintenance pigs 

through the western line and how many times did you run them through 

the eastern line? 

 MR. MARSHALL. We ran-- 

 MR. DINGELL. Just the maintenance pig. 

 MR. MARSHALL. We ran maintenance pigs in 1990 and 1998 and we 

ran smart pigs in 1990 and 1998. 

 MR. DINGELL. Why didn’t you run them more often? You knew 

that the amount of viscous oil that was being put through the line was 

increasing on a continuing basis and you knew that that changed the 

characteristics of the oil, or at least you should have, and you knew that 

that oil because of its changing characteristics had a potential for 

increasing the risk of increased corrosion because of acid formation or 

other things such as water which might have created problems but you 

didn’t do anything at all about increasing the number of times that you 

ran a pig through the line or checked to see whether the change in the 

quality of the oil going through the line was going to impair the 

capability of the line to resist corrosion. 

 MR. MARSHALL. Mr. Congressman, certainly as the viscous oil 

increased more significantly in 2004 and 2005, we were aware of, as you 

pointed out, a number of the incidents there but the general quality of the 

crude oil there is sales-quality crude oil which is-- 

 MR. DINGELL. It is still quality crude oil but it has got more viscous 

oil in it, a significant increase as we have already shown in the questions. 

 MR. MARSHALL. But the viscous oil in and of itself does not--is not 

a corrosive agent. 

 MR. DINGELL. Well, let us look at the numbers again. The Baxter 

Report cites an upset of nearly 10,000 barrels of water being 

unintentionally released from Gathering Center 2 and the western oil 

transit line. Also, as we discussed earlier in my questions, you had a 

significant increase in the amount of viscous oil that you are moving 

through the line and other things which had a potential risk in terms of 

increasing corrosion. BP’s production of viscous oil increased from 

1,500 barrels a day to 16,000 barrels in 2005. Is that a significant 

increase or not? 

 MR. MARSHALL. Certainly that is the increase as mentioned earlier 

that when the Orion field came in, we saw the increase start in 2004 into 

2005. 

 MR. DINGELL. Doesn’t that warn you that you ought to do 

something about it to check to see what is happening? I trust in God but 

I know he expects me to lift my end of the log and find out whether I am 

doing what I should be doing or whether it is going to have the proper 
115

effect. Obviously you are a very trusting man and it is very clear to me 

you have great trust in God but don’t you have some responsibility to do 

a little better job of running pigs through to find out what is going on? 

 MR. MARSHALL. Mr. Congressman, indeed in 2005, we did plan and 

schedule a smart pig run. 

 MR. DINGELL. You told me about three times that you ran pigs 

through there and Alyeska does it every seven to 14 days. They are 

running the same oil you are. Are they smarter than you or less trusting 

than you, or what is the situation there? 

 MR. MARSHALL. Mr. Congressman, pigs and smart pigs are run for 

many different reasons. We run 370--about 370 pigs every year on our 

lines. 

 MR. DINGELL. Now here again is from attorney-client privilege ATP 

Technological Review. It says here: “With such a release, it is most 

likely that some water and also basic sediment will be held back in the 

lower elevation sections of the O-21 line.” Now, that is where this 

occurred. It occurred in the lower elevation sections. And what did you 

do to prevent this holdback or to find out if this holdback was going to 

create you any problems? 

 MR. WALDEN. Mr. Marshall, I am going to go ahead and let you 

answer that and then I-- 

 MR. DINGELL. Mr. Chairman, you have been most kind. 

 MR. WALDEN. We need to move on. 

 MR. DINGELL. I am not sure I am getting answers anyhow so I am 

happy to yield back. 

 MR. WALDEN. Mr. Marshall, go ahead and respond. 

 MR. MARSHALL. Mr. Congressman, we did schedule a maintenance 

pig and cleaning pig run in 2005. It is my regret that that was too late. 

 MR. DINGELL. Thank you. Mr. Chairman, thank you for your 

courtesy. 

 MR. WALDEN. Absolutely, Mr. Dingell. 

 The Chair now recognizes the full committee chairman, Mr. Barton. 

 CHAIRMAN BARTON. Thank you, Mr. Chairman. 

 Mr. Stears, you work for Coffman Engineering or Engineers. What 

is your company’s relationship with the State of Alaska and with British 

Petroleum? 

 MR. STEARS. We are providing corrosion expertise or corrosion 

expert opinions for the State of Alaska on BP’s program. 

 CHAIRMAN BARTON. So would you say your client is the State of 

Alaska or is your client British Petroleum? 

 MR. STEARS. Our client is the State of Alaska. 

 CHAIRMAN BARTON. State of Alaska. So you are a private 

contractor helping the State of Alaska do oversight on some of these 
116

issues with the various, I assume all the pipelines or is it just these 

particular pipelines? 

 MR. STEARS. It is the non-common-carrier pipelines. 

 CHAIRMAN BARTON. Okay. Do you--we have repeatedly been told 

that there is no Federal regulation of these particular lines because they 

are low-pressure lines and they are also an intrastate commerce. What is 

the definition of low pressure versus high pressure in an oil pipeline? 

 MR. STEARS. I don’t have that information. 

 CHAIRMAN BARTON. Does anybody know the difference? No one? 

I can’t believe I have asked a question-- 

 MR. HOSTLER. Congressman, I believe the answer is, any time a line 

operates below 20 percent of its design pressure, it is considered a lowpressure line, but I would confirm that with the DOT. 

 CHAIRMAN BARTON. So there is not a specific pressure, it is 

depending on the capacity? 

 MR. HOSTLER. The capacity of the pipeline that is installed, but I 

would confirm that with the DOT this afternoon. 

 CHAIRMAN BARTON. All right. Now, these lines that are in question 

are called gathering lines. Now, in Texas, a gathering line is a much 

smaller line. I am told these are 34-inch-diameter lines. Is that correct? 

 MR. MARSHALL. Thirty-inch and 34-inch, Mr. Congressman. That 

is correct. 

 CHAIRMAN BARTON. So I am told that each of these lines was 

transporting about 200,000 barrels of oil a day. What is the capacity of 

these lines? What could they transport? 

 MR. MARSHALL. Mr. Congressman, I don’t know the ultimate 

capacity. I do know that at the peak, Prudhoe Bay was producing in 

excess of a million barrels a day, and-- 

 CHAIRMAN BARTON. So each of these lines at peak would have been 

transporting 500,000 barrels a day? 

 MR. MARSHALL. I can confirm that. I would say probably at least 

and maybe even more but I will get back to you with a more specific 

number on that. 

 CHAIRMAN BARTON. All right. Now, I am an engineer but I am not 

a petroleum engineer or hydrostatic engineer, and in fluid mechanics, I 

made a D, so I am--I did pass but just by the skin of my teeth. 

 MR. WALDEN. I figured you made an R. 

 CHAIRMAN BARTON. An R? A pipeline that could carry 500,000 

barrels a day, that it is only carrying 200,000 barrels a day, if a layman, if 

we did a cross section and looked inside that pipeline, would it be full, 

would the total volume be oil or would it be half full and you would have 

air above the oil? 
117

 MR. MARSHALL. I am a mechanical engineer so but even with that, I 

would say that the pipeline remains full and it is a function of the 

velocity-- 

 CHAIRMAN BARTON. That is what I would think, so it would have to 

be full in order to push the oil through the pipeline. 

 MR. MARSHALL. That is correct. It is pumped through from each of 

the flow stations or gathering centers and the line is full. It is simply the 

500,000 barrels a day versus 200 results in low velocities through that 

line. 

 CHAIRMAN BARTON. Now, we have--these pipelines that are under 

question today, I assume that they have been in service for over 30 years. 

Is that correct? 

 MR. MARSHALL. Mr. Congressman, the lines have been in service 

for--since June 1977. 

 CHAIRMAN BARTON. Okay. So almost 30 years. And they were 

designed to carry much more oil than they are carrying today so they are 

operating under much lower pressure than they were designed to operate 

under, and the probability based on the inspection reports that we have is 

that there is sludge and water and other sediment in there. So was it a 

decision of BP that they didn’t have to do the smart pigs or the 

maintenance pigs because the pressure differential was down and there 

wasn’t as much pressure on the wall? 

 MR. MARSHALL. Mr. Congressman, I am not aware of any--

personally aware of any discussions that led to that conclusion. 

 CHAIRMAN BARTON. Okay. Well, I want to ask the gentleman from 

Alyeska, Mr. Hostler, your company, which operates the Trans Alaska 

pipeline which is the much bigger pipeline. It is, what, 5 feet in 

diameter? 

 MR. HOSTLER. Four feet, sir. 

 CHAIRMAN BARTON. Four feet in diameter. So it is not much bigger 

than these lines. You inspect your line every two weeks. BP--with the 

pig, clean it every two weeks--BP doesn’t do it at all except by 

exception. Why is your operating procedure so much different than BP’s 

was? It is the same oil and the--I actually thought the line was much 

bigger but apparently it is not that much bigger so why are you doing 

something every two weeks that BP basically wasn’t doing at all? 

 MR. HOSTLER. Well, Congressman, I can’t speak for BP but the 

reason as we spoke earlier today that we clean the line every two weeks 

is one, for hydraulics, as mentioned, and two, to take out any 

accumulation of solids or water in the system and then we smart pig 

every three weeks as has been mentioned as well. 

 CHAIRMAN BARTON. But what is--this is kind of key to the whole 

issue here. Why would BP on their 34-inch-diameter lines of which they 
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had two not do what you are doing on one 48-inch line? What is the 

difference in management approach there? It is the same oil. 

 MR. MARSHALL. Mr. Congressman, we didn’t believe we had a 

corrosion problem in those lines. Clearly in retrospect, in two sections of 

those lines, the eastern sections of those lines, the two three-mile sections 

that have failed, we did. The inner 10 miles of those 16 miles appear to 

be in far better shape based on the inspections so far but clearly in 

retrospect, the corrosion did occur. 

 CHAIRMAN BARTON. Well, now, we have in our reference book for 

this hearing tabs 9, 10 and 11 which deal with an inspection report that 

Coffman Engineering prepared back in 2001 and the State of Alaska 

environmental officer, a lady named Susan Harvey, has told our 

committee staff that the draft report which was critical of BP’s corrosion 

control program was extensively changed after she was removed from 

the project and she feels like that she was removed because of pressure 

by BP to remove her, and the subsequent final report that came out was 

much different and less critical of BP’s corrosion control program. So 

how could it be, Mr. Marshall, that BP wasn’t aware of some of these 

problems because at least they are implicitly alluded to in this 2001 draft 

report which BP objected to? 

 MR. MARSHALL. Mr. Congressman, I am not aware of Susan 

Harvey’s involvement. I don’t have any information-- 

 CHAIRMAN BARTON. Are you aware of the debate over the report 

that the Coffman associates helped prepare in 2001? 

 MR. MARSHALL. I became aware of that after the March spill and 

we launched an investigation into the reports from the 2000 program, I 

believe the one in question. We interviewed as many people as we 

could, both with Coffman and with BP and with the Department of 

Environmental Conservation. While we haven’t been able to interview 

everybody, we found no evidence of pressure to change those reports. 

What I understand to have been the case was this was the first report that 

was produced as part of the charter agreement with the State that BP and 

indeed the other operator, ConocoPhillips, was preparing and that as we 

developed this report, there were some conclusions drawn that appeared 

to BP to be perhaps not quite accurate, that the Coffman and the State did 

not have all the information that we could have provided. 

 CHAIRMAN BARTON. But when this report happened back in 2001--

you have been in your current position since 2001. Is that not correct? 

 MR. MARSHALL. That is correct, yes. 

 CHAIRMAN BARTON. And you are testifying under oath here, you 

did not have any knowledge of this draft report in 2001? 

 MR. MARSHALL. I did not. I wasn’t even aware of a Coffman report 

at that time, no. That is correct. 
119

 CHAIRMAN BARTON. And you became aware of this situation when? 

 MR. MARSHALL. After the March spill. 

 CHAIRMAN BARTON. Okay. This year? 

 Okay. I have got one final question. We have got all kinds of 

anecdotal--evidence is too strong a term but we have been told by a 

number of individuals that the reason BP decided to discontinue pigging 

was because the last time they attempted it, there was so much sludge in 

the line that it fouled the screens at the endpoint of the pipeline and that 

because of that, BP just decided the field was depleting and it wasn’t 

worth messing with and they would rely on other means to do 

inspections for corrosion. So my question is to you, Mr. Marshall, isn’t 

it normal in a pipeline that you are going to have sediment and sludge 

buildup? I mean, that should be, I would think--and again, I am not a 

pipeline engineer, but I would think that would be a problem that you 

know is going to occur and that you would take steps to manage as it 

occurred. Am I wrong in that assumption? 

 MR. MARSHALL. Mr. Congressman, I can’t comment definitively 

that all pipelines necessarily have solids. Our experience has been that 

some do, some don’t. It depends on-- 

 CHAIRMAN BARTON. Well, this is one that you know did. I mean, 

you knew the last time you tried to put a pig through one of these lines 

that there was sediment and sludge and material in it that wasn’t oil. I 

mean, that is a fact. 

 MR. MARSHALL. What I understand to be the case--again, if I 

separate the east and west for one second. On the west, which is what 

BP pigged in 1998, we received virtually no solids, less than two cubic 

yards out of 10 miles of pipe which is a very relatively low amount of 

solids. I understand when ARCO tried to pig the eastern lines in the 

early 1990s, there was considerable scale. I am not aware if there were 

other solids other than calcium scale that had build up on the inside of 

the pipeline which did indeed cause some fouling of the screens and 

strainers at Pump Station 1. 

 CHAIRMAN BARTON. But that would tell me, the last statement, that 

you needed to do more maintenance pigging, you needed to have some 

program to get that out of the pipeline and again, not being a pipeline 

engineer, I can’t state this definitively but it would seem to me that that 

would be an engineeringly manageable problem, that you would take 

steps to prevent that and clean it out and keep it clean, and apparently the 

BP action was to do nothing, to just say okay, we can’t run a pig through 

here, there is too much garbage in the line and so we are not going to 

mess with it, and to me, that seems to be 180 degrees from what you 

should do. Apparently you are doing today what you should have done a 

long time ago. You are building a bypass line. You are doing some 
120

cutout valves. You are doing all this stuff to rectify the problem today. 

The only thing that is different between today and the early 1990s is that 

you have got the United States Congress watching you and you have got 

the State of Alaska watching you and it has become an environmental 

disaster. 

 MR. MARSHALL. Mr. Congressman, to my knowledge, I found no 

evidence so far of any deliberate decisions to not pig those lines because 

of solids. We are still looking at that but I have found no evidence so far 

to say that is indeed the case. 

 CHAIRMAN BARTON. Well, you have got a different operator 

operating the main line that goes from the gathering station down to 

Valdez that does maintenance inspection pigging every two weeks. It is 

the same oil coming from the same oil field coming from your two 

transit pipelines. They are doing something every two weeks routinely 

that your company has only attempted intermittently on either line over 

the last 15 years. I mean, it just--there has to be a conscious decision 

somewhere in your chain of command to ignore the reports that are 

coming out. I mean, the corrosion manager for BP took the Fifth 

Amendment, which he has got the right to do, but I cannot believe that he 

is the only one in the company that knew about this problem. It just 

doesn’t make sense. 

 So my time has expired, Mr. Chairman, I would yield back. I hope 

we continue to-- 

 MR. WALDEN. Before you do that, Mr. Chairman, I would like to 

ask unanimous consent to enter into the record the committee’s hearing 

book dated Thursday, September 7, 2006, BP’s Pipeline Spills at 

Prudhoe Bay: What Went Wrong? It is the document binder from the 

Subcommittee on Oversight and Investigations. And so without 

objection, I will enter that into the record. Mr. Chairman. 

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 CHAIRMAN BARTON. Mr. Chairman, I want to make clear that when 

I mentioned Susan Harvey’s name, we approached her, the committee 

staff approached her. She did not voluntarily come forward. It is at our 

request, the committee staff, that we interviewed her. 

 MR. WALDEN. Thank you. The Chair now recognizes the 

gentleman from Washington, Mr. Inslee, for 10 minutes. 

 MR. INSLEE. Thank you. Mr. Malone and Mr. Marshall. I want to 

do something that I think will be unique at this hearing and saying one 

good thing about British Petroleum, and that is that you have met Kyoto 

targets in your internal operations for reducing carbon dioxide. You 

have demonstrated the ability to keep our economy going while reducing 

carbon dioxide emissions. That is a good thing you have done. I want to 

note that in this hearing. But I also want to note profound 

disappointment in this abysmal corporate record on this particular 

maintenance issue, and the reason is, is that it appears from even a 

cursory review of this that this was not some sort of oversight. You 

know, people run red lights; we are all human. But this was a very 

willful, deliberate, clear, premeditated, if you will, decision not to do this 

known maintenance procedure of using smart pigs, and what leads me to 

that conclusion, looking at this report, a preliminary draft of the report by 

Coffman Engineers, this says out of Anchorage, it is entitled Corrosion 

Monitoring of Non-Common-Carrier North Slope Pipelines. It was 

received by the Department of Alaska on November 2, 2001. This was 

their preliminary draft, and their preliminary draft made repeated 

references to the efficacy of smart pigging these lines. I look at the 

preliminary draft before British Petroleum got their hands on it. It had 

lines such as, “Smart pigging is the only inspection technique capable of 

looking at the whole internal and external corrosion picture.” That 

disappeared after British Petroleum talked to these engineers. No such 

reference in the final report. We have a line saying “Some questions 

which arise after reading the report are, does BP pig every non-commoncarrier pipeline of suitable diameter.” That line disappears from the final 

report. We have a line saying, “Are there plans to install/configure EOA 

pipelines for smart pigs?” Gone in the final report. “Are baseline smart 
474

pig runs performed on newly commissioned lines?” Gone on the final 

report. “How are lines selected for smart pigging and what is the recur”-

- that is what it says--”frequency of inspection.” It means recurrence. 

Gone in the final report. There are loads of language like this in this 

report that is gone after British Petroleum started to work on this report, 

and to use a bit of a British understatement, it turned an inspection report 

into a bit of a whitewash, and so we are here today. Now, I understand, I 

think, your logic that you decided just to rely on ultrasound inspections 

in lieu of doing smart pigging. It is a very sensitive, exquisitely effective 

tool but it only affects a very small part of the pipeline. When you put a 

sensor on the pipeline, it only gives you data for a very small section. 

How wide is that? When you put one of these monitors, how wide is that 

section? 

 MR. MARSHALL. It is one-foot sections. 

 MR. INSLEE. One-foot sections. So when you put this monitor, you 

are only getting data for one foot of the pipeline at a time and you go to 

various places and you get one-foot slices. What percentage of the 

pipeline did you get real data for when you do that? Just give me a 

ballpark. Fifty percent, 10 percent, half a percent? 

 MR. MARSHALL. I can’t give you an honest--an exact number. I 

think it varies on the different lines. 

 MR. INSLEE. It is probably less than 5 percent, isn’t it? 

 MR. MARSHALL. I can get you an answer. I will come back with a-- 

 MR. INSLEE. Well, the point is to me, isn’t that a fair metaphor for 

like a CT scan? You go to the doctor, that takes little slices of your 

body, and it is like giving it a CAT scan but you have just got little slices, 

not the whole enchilada. That is why this report specifically brought up 

the issue and said, “Smart pigging is the only inspection technique 

capable of looking at the whole internal and external corrosion picture.” 

Now, that was in their preliminary report. Then they talked to BP and 

then in the final report that language disappeared. Is that accurate? 

 MR. MARSHALL. We have investigated, as I said. When that issue 

came to light, we investigated the two drafts, the draft and the final 

report, and we interviewed every--a number of people involved in that 

preparation of that report and were involved on both sides of the 

discussion. We haven’t interviewed everybody but so far we have 

identified no pressure. I think that is a fair question there for Coffman to 

address in terms of why certain things were kept in and certain things 

were kept out. I don’t believe BP wrote that final report. It was still a 

Coffman report. But so far we found no evidence of pressure on 

Coffman Engineering to change that report. 
475

 MR. INSLEE. Well, I am not sure I have to refer to violations of the 

Geneva Treaty as far as pressure. There was communication between BP 

and Coffman before this final report, right? 

 MR. MARSHALL. Absolutely. There were-- 

 MR. INSLEE. Coffman does a lot of work in the oil and gas industry, 

don’t they? 

 MR. MARSHALL. Absolutely. There were discussions between 

Coffman, the State Department of Environmental Conservation, BP and 

indeed ConocoPhillips who are working this first draft of report and I 

would say with any audit, it is normal and customary to sit down, discuss 

drafts, you know, provide additional information, you know, perhaps 

draw different conclusions from the data that is subsequently presented. 

I believe that was a large part of what was discussed between the draft 

and the final report. 

 MR. INSLEE. But it is not normal when an engineering outside 

consultant suggests that you consider doing the smart pigging and 

specifically says it is the only thing that gives you data for the pipeline--

by the way, you agree with that, don’t you? 

 MR. MARSHALL. Smart pigging gives an indication across the entire 

pipeline length and girth of where corrosion may be occurring which 

then has to be subsequently checked to precisely define what that level of 

corrosion is. 

 MR. INSLEE. I want to make sure I understand you. Smart pigging is 

the only thing that gives you data for the entire internal section of the 

pipeline that does not require you drawing assumptions that tiny little 

pieces of the pipeline are the same as the pieces you checked? 

 MR. MARSHALL. I am not a pipeline expert, Mr. Congressman. I 

believe that the path we are on with the east line and the west line right 

now of ultrasonically testing the entire length of the line will give the 

same kind of indications. 

 MR. INSLEE. But you didn’t do that, did you? 

 MR. MARSHALL. No, we did the spot checks. 

 MR. INSLEE. You did spot checks, and I can tell you when Congress 

became somewhat experts on this, we required smart pigging essentially 

for the internal sections of these main lines, and obviously the TAPS 

system uses as well, you know, both cleaning and inspection purposes. 

So I just have to tell you that, haven’t you concluded that your 

communications to this outside expert had some bearing in keeping the 

public from knowing that smart pigging was, A, an option to you, B, that 

it had been considered, and C, that you decided, you made a conscious 

decision not to do it? 

 MR. MARSHALL. I have no evidence to support those allegations, 

quite frankly. 
476

 MR. INSLEE. Do you have any other suggestion why this outside 

expert on their own desire or concern would all of a sudden whitewash 

this report? 

 MR. MARSHALL. I think it is a question maybe addressed to 

Coffman Engineering. I don’t have any information which would 

eliminate that. 

 MR. INSLEE. Are you telling me that your investigation did not give 

you any reason to believe that British Petroleum asked Crowley to take 

this information out of the report--Coffman. Excuse me. 

 MR. MARSHALL. I don’t have any information to support that. What 

I do understand is that more data was provided from the initial basis. 

This was the first report that was done after the charter agreement. 

 MR. INSLEE. I have to tell you too, one of the disappointments of my 

constituents is the public relations effort by the organization to I think 

indicate that the organization is going in an environmentally friendly 

manner, and we made reference to this. I saw this advertisement in 

Autobahn magazine just this week. It says our plans for biofuels are 

growing, and I think any step forward I suppose is great, but I just want 

to ask while I have you here, there are 170,000 pumps, gas station pumps 

in America. There are about 858 that have E85 available, ethanol for 

consumers. What can you tell us as to when British Petroleum will have 

25 percent of its stations having E85 pumps available? 

 MR. MALONE. Congressman, if I might, I don’t have that exact 

figure but I will get it for you. We are moving to have E85 pumps in 

certain of our markets right now but I don’t have the number and 

locations with me today. If I could though, Congressman, just on your 

point about our values around the environment, I would say we just 

acquired two wind companies. We are investing some $500 million into 

biofuels research which we think is very important, and we also have a 

very aggressive program in working with alternative fuels, and I would--

whether the advertising is the issue but just so you know, the core values 

are real. 

 MR. INSLEE. Let me--we would applaud any step forward so we 

appreciate those steps forward including, as I indicated, your CO2

reduction. But I have to tell you, a $50 million-a-year investment in 

biofuels is less than chicken feed for a company that has $26 billion of 

profit this year. It is less than .2 percent of your net profits, not just your 

gross. Our Nation needs a new energy future for this country. We 

believe your corporation is capable, should it decide, of having a 

meaningful role in that, and we hope both Congress will act--it will take 

a new Congress but eventually we are going to act, and we hope you will 

be part of that, and I hope that as part of this hearing, perhaps you can go 

back to corporate headquarters and say maybe we need to redouble that 
477

effort as our penance for this massive abysmal failure. That would be a 

good result of this. I hope you will take that message back to your 

leader, who has done good work in this effort. Thank you. 

 MR. WALDEN. The chair now recognizes the gentlewoman from 

Wisconsin, Ms. Baldwin. 

 MS. BALDWIN. Thank you, Mr. Chairman. I would like to focus 

some questions for Mr. Marshall on the corrosion management group 

and I think it is also known as the CIC, the Corrosion Inspection and 

Chemicals Group. Are you aware of an internal audit issued in April of 

last year called BPXA Corrosion Management System Technical 

Review? 

 MR. MARSHALL. Could you explain the--I am sorry. Which one 

again? 

 MS. BALDWIN. Are you aware of an internal audit issued in April of 

last year called the BPXA Corrosion Management System Technical 

Review? 

 MR. MARSHALL. Yes, I am. I am sorry. 

 MS. BALDWIN. And in that report, under the section called budget 

processing, is the following finding, and I am just going to quote from 

that: “Currently, the budget is set up-front in line with flat lifting cost 

strategy, with corrosion management activities then developed around 

this budget allocation. This strategy to maintain flat lifting costs is 

driving behaviors counterproductive to ensuring integrity and the 

delivery of an effective management system. A more effective and 

efficient process would be to derive the set of activities required to 

deliver a robust corrosion management system over the longer term and 

thereafter set the budget based on these activities.” Mr. Marshall, this 

report seems to suggest that there was pressure at BP to reduce 

expenditures on its corrosion program. Would you agree with that? 

 MR. MARSHALL. I would say--I would make several comments, 

Congresswoman. The fact of bringing in our chief engineer to review 

this program I think it is an indication that while many had considered 

our corrosion program to be comprehensive, we were prepared to subject 

that to some scrutiny, to shine a spotlight on the program and find out 

where we could make improvements, and indeed, the perception of flat 

units costs was still there when the team issued that report in 2005. The 

same team came back in 2006 and said action had been taken. They had 

seen a considerable change in 12 months in their follow-up report. One 

of my regrets in terms of, I have thought long and hard in the last 5 to 6 

months about what I could have done differently. That has occupied a 

big part of my time. And one of the things I regret is that I didn’t do 

more to change the perception inside our team about spending money 

because the reality of what we have done or what has happened since I 
478

have been there is our lifting costs, which are a measure of spending 

divided by how much production, has gone from $1.89 a barrel to $5.22 

a barrel. Our corrosion spend has increased by 80 percent. Our major 

repair spend has gone up threefold. But I recognize that still it takes a 

huge effort to change the perceptions of cost cutting that were a feature 

of the late 1990s when we experienced $9 and $10 oil and the industry 

took some significant belt-tightening under its way. I believe that that 

caused some poor practices, and certainly when I arrived in Alaska in 

2001, the organization wasn’t in good shape. We had a poor relationship 

with our workforce, we had some issues around maintenance, and one of 

my goals has been to change both of those. I am proud to say that the 

conditions today are far better than they were. They are clearly a long 

way short of being good enough, and I do regret that. But this is a long 

journey and we are going to re-establish that track record with our staff 

and with the public. 

 MS. BALDWIN. Mr. Marshall, I want to continue to explore this 

topic. I think you already acknowledged awareness of the investigative 

report from the law firm of Vinson and Elkins, October 20, 2004. They 

were charged with looking into allegations of workplace harassment and 

corrosion data falsification in the CIC, the Corrosion Inspection and 

Chemicals Group. So you are aware of this report, correct? 

 MR. MARSHALL. I am, yes. 

 MS. BALDWIN. Okay. What prompted Vinson and Elkins to conduct 

that review? Can you give us some brief history of that and what were 

the allegations? 

 MR. MARSHALL. Congresswoman, yes. I became aware of this 

issue in early 2003, an issue of alleged harassment in the corrosion 

group. That issue was raised through two channels: one, through our 

employee-run safety committee, and concurrently through one of our 

external contacts who represents one of the channels for workers to use. 

That was a channel that I was instrumental in setting up and that resulted 

in investigation by two outside counsel, Billy Guard and Paul Floudy, 

who went up and reviewed the situation in the corrosion group. They 

confirmed and established that there was an atmosphere of intimidation 

that was potentially suppressing safety concerns. The recommendation 

of that review was that the CIC manager, Mr. Woollam, should undergo 

coaching and counseling and change his working practice. That was 

their recommendation. We followed up with that. Mr. Woollam did 

indeed take on that training, and by some measures and follow-up was 

willing to kind of take that on. The following year in 2004, Billy Guard 

and Paul Floudy returned to the slope on a different issue and did some 

checking and were still concerned that there was a chilled atmosphere in 

the CIC team. On that basis, we said we needed to perform a more 
479

comprehensive review and that was the Vinson and Elkins review, so 

that was a very extensive review of everything from falsification of data, 

the workplace harassment, and my recollection of the Vinson and Elkins 

report is that while there was no apparent continuation of harassment 

from Mr. Woollam, the chilled atmosphere still remained. There was a 

legacy of chilled atmosphere and the recommendation from that team 

was that Mr. Woollam should be taken out of a supervisory role. I took 

that action one step further and believed in Mr. Woollam’s best interests 

and in BP’s best interests that Mr. Woollam should be removed to a nonsupervisory role outside of Alaska, and that was what was done. 

 MS. BALDWIN. So bad were the allegations coming from this group 

that the EPAs’ Region 10 Office of Suspensions and Debarment and the 

U.S. District Court’s Anchorage Office of Probation and Pretrial 

Services asked BP to look into these harassment claims. Isn’t that true? 

 MR. MARSHALL. I believe that is correct, yes. 

 MS. BALDWIN. And then back on the budgetary implications of this, 

Mr. Marshall, one of the issues mentioned in this report that seemed to 

cause so much strife among BP’s corrosion inspectors was when the 

manager of the program decided to reduce the amount of staff and 

corrosion inspection points by 25 percent, and let me again quote from 

page 17 of the report. I quote: “It is not clear exactly what motivated the 

CIC manager to insist that the coupon crew be reduced from eight 

workers to six. During our interview of him, he told us there was no 

budget pressure as the CIC budget was increasing at the time. It appears 

to have been driven by a metric he developed that total coupon pulls had 

been reduced by 25 percent which he believed had to translate to a 25 

percent reduction in crew size.” Mr. Marshall, given that BP’s facilities 

were aging and the amount of water in the field as we have heard in 

previous questions was increasing and the quality of oil coming from the 

reservoir was increasingly capable of causing corrosion, why would BP 

opt to cuts its coupon pulls by 25 percent, and who made this decision 

and why was it made? 

 MR. MARSHALL. The issue of the coupon crew reduction was one of 

the foundations of the initial review by Billy Guard and Paul Floudy. It 

was one that was raised in 2003. That was looked at. We took action on 

that and increased the crew size back to the full complement and 

performed the corrosion coupon pulling back to its pre-existing level, so 

we took action on that basis. 

 MS. BALDWIN. Mr. Chairman, I see that I have run out of time. I 

would also like to submit some further questions relating to this-- 

 MR. WALDEN. Without objection. 

 MS. BALDWIN. --CIC group in follow-up. Thank you. 

 MR. WALDEN. The Chair now recognizes Mr. Markey for questions. 
480

 MR. MARKEY. Thank you, Mr. Chairman. Mr. Marshall, the Vinson 

and Elkins report depicts that a major chilling atmosphere existed in the 

CIC group. On page 2 of the report is the following conclusion from the 

Vinson and Elkins investigative team. Let me quote: “Our overall 

conclusion is that there is an atmosphere in the CIC group that chills 

reporting HSE concerns, especially among several employees of the 

coupon crew.” Mr. Marshall, do you believe that this chilling 

atmosphere had any impact on the quality of this program? 

 MR. MARSHALL. Mr. Congressman, I can’t definitively say that it 

did but I would say this, that we don’t tolerate--I don’t tolerate chilled 

atmospheres, harassment. We did take steps to make sure that we are 

doing everything we can, not only with our BP supervisors but also with 

our contractor supervisors. 

 MR. MARKEY. But did this chilling effect have any impact on the 

safety or quality of the program at that time? 

 MR. MARSHALL. I have no information to know that there was a 

direct correlation. Clearly the potential exists but I don’t have any 

evidence that something was suppressed that could have resulted in an 

improvement. 

 MR. MARKEY. Well, when whistleblowers don’t come forward 

because they are frightened obviously, they can be, and in this instance I 

think probably it was serious safety issues that were compromised, it 

appears that the manager of the CIC group, according to this report, had 

an extremely abrasive management style. Is that correct? 

 MR. MARSHALL. That is one of the conclusions, yes. 

 MR. MARKEY. So bad were the allegations coming from this group 

that EPA’s Region 10 Office of Suspensions and Debarment and the U.S. 

District Court’s Anchorage Office of Probation and Pretrial Services 

asked BP to look into these harassment claims. Isn’t that correct? 

 MR. MARSHALL. That is correct, yes. 

 MR. MARKEY. Mr. Marshall, one allegation on page 10 of the 

Vinson and Elkins report’s appendix notes the following allegation: 

“The Corrosion Inspection and Chemicals manager is brutal and screams 

and shouts at contractors.” Here is what the Vinson and Elkins report 

found: “Status: We have been informed that the Corrosion Inspection 

and Chemicals manager had very poor communications skills but has 

recently been improving. This is a very common perception.” Mr. 

Marshall, given the chilled atmosphere experienced by the employees 

and apparent abrasive personality of its manager, would you think that 

this was a favorable atmosphere to recommend that BP explore other 

types of corrosion detection technology such as more frequent runs of 

smart pigs which can be costly? 
481

 MR. MARSHALL. I am aware certainly of the conclusions of the 

report. I agree with the conclusions of the report in terms of the abrasive 

nature, the intimidation, and we have taken steps to change that. What I 

am not clear about is the linkage of that to the pigging runs. I have no 

evidence-- 

 MR. MARKEY. Does that report not lead to the conclusion that an 

individual would risk losing their job if they made such 

recommendations and that they were not consistent with what the CIC 

manager wanted? Let me ask you this. What happened to the CIC 

manager after Vinson and Elkins did this internal report? What did you 

do? 

 MR. MARSHALL. The recommendation from both the Billy Guard 

review and the Vinson and Elkins review was to take action and we 

followed that action. Indeed, the Vinson and Elkins action was to 

remove Mr. Woollam from a supervisory role, which we did, and I took 

that one step further and said it was in Mr. Woollam’s best interests and 

indeed BP’s best interests to move him out of Alaska, which is what 

happened. 

 MR. WALDEN. Mr. Markey, just a point of interest. You might want 

to turn to page 6 of the Vinson Elkins report of the appendix, number 26. 

It would be number 26 of page 6 of the appendix. It is more along the 

lines of what you are raising. 

 MR. MARKEY. Thank you, Mr. Chairman. I appreciate it. Could I 

ask you, Mr. Malone, do you believe that the chilled atmosphere in the 

CIC group had any impact on the quality or capability of the corrosion 

program? 

 MR. MALONE. Congressman Markey, I don’t have--I read the report. 

I don’t have any direct evidence yet to be able to give you an answer on 

that. 

 MR. MARKEY. Mr. Marshall, on page 7 of the appendix of the 

Vinson and Elkins investigation is the following allegation: 

“Independent corrosion experts who are all formerly contractors working 

on Prudhoe Bay have resigned their positions over the last few years 

allegedly due to their growing worries over the potential for a serious 

incident on the field.” Vinson and Elkins, according to their report, 

looked briefly into this allegation though how much is unclear, and this 

is what they concluded: “Status: We have been told by one person that 

an operator resigned because of concerns over pipe integrity. Others 

suggested that this is not why he resigned. We have tried to contact that 

individual to interview him and have thus far been unsuccessful. We are 

aware of no other persons who could possibly fit this description.” Mr. 

Marshall, has BP attempted any further efforts to locate this individual? 
482

 MR. MARSHALL. I am not aware that we have. That doesn’t mean to 

say that we have not done that. I am just not aware of it. 

 MR. MARKEY. Well, I would say that that was a big mistake. Mr. 

Marshall, has BP attempted to look further into the general allegations 

that independent corrosion experts felt that something was amiss in BP’s 

corrosion management program and that this might explain the failures to 

truly understand the condition of your lines? 

 MR. MARSHALL. We take very seriously any allegations, safety 

concerns that are raised about our programs. It doesn’t matter where 

they come from, whether they come through our internal channels or 

external channels. The only thing we need to do is be able to understand 

where there are specifics rather than general concerns. We have 

investigated hundreds, literally hundreds of allegations and issues since I 

have been back in Alaska in 2001. Where we have specifics, where there 

is specific equipment or specific lines, we can go investigate that and 

take the appropriate action. The only thing I find very difficult and the 

team finds difficult is where we have, you know, general allegations 

which are very difficult to address. 

 MR. MARKEY. Mr. Marshall, earlier this year you stated that BP was 

unaware of the problems that ARCO had when they had last tried to pig 

the eastern lines back in 1992, and that you weren’t aware of the 

problems that Alyeska had experienced downstream as a result of 

ARCO’s pigging of the line. Did BP do any due diligence review of the 

condition of ARCO’s pipelines in Alaska prior to your acquisition of the 

company? 

 MR. MARSHALL. I am aware there was considerable amount of due 

diligence done across- 

 MR. MARKEY. Who did that due diligence? 

 MR. MARSHALL. I don’t have that information. 

 MR. MARKEY. Did that due diligence review indicate any potential 

corrosion problems or solids buildup problems within ARCO’s lines? 

 MR. MARSHALL. I am not aware of any but I am just not in 

possession of that information. I would be happy to go back and 

reconfirm that with the transfer documents. 

 MR. MARKEY. Now, after the ARCO merger, were any of the 

former ARCO employees responsible for corrosion management and 

control kept on by BP? 

 MR. MARSHALL. I don’t know the answer to that question. 

 MR. MARKEY. Wouldn’t, Mr. Marshall, those individuals have 

knowledge of the solids buildup problem and the difficulties that the last 

pig run through the eastern line had created downstream? 

 MR. MARSHALL. I suspect so. I don’t know that for sure but I 

would imagine that is the case. 
483

 MR. MARKEY. So wouldn’t there be someone at BP who knew about 

the problems that had existed before the sale was consummated? 

 MR. MARSHALL. I don’t--I am not able to confirm that. 

 MR. MARKEY. You haven’t found that out yet? 

 MR. MARSHALL. No. 

 MR. MARKEY. After six months? 

 MR. MARSHALL. We have contacted the ARCO engineer that was in 

charge of that pigging operation in the last few weeks and-- 

 MR. MARKEY. You understand, Mr. Marshall, that Congressional 

expert is an oxymoron? We are only experts compared to other 

Congressmen. You have had six months to ask all of these questions 

which I am asking right now which directly go to the question of how 

much BP knew and when they knew it and you are telling me that these 

questions have yet to be asked in terms of what that transition period 

produced in terms of information for your company in terms of the 

corrosion inside of those pipelines, and frankly, I just don’t believe it. I 

don’t believe that in a company of your stature and expertise that no one 

was asking these questions at that time, and it is six months later and a 

Congressional committee should not be the one prompting you to go and 

to get the answers to those questions, and if I may, Mr. Chairman, I have 

one final question with your indulgence. If BP had no knowledge that 

pigging the eastern line would cause problems downstream for Alyeska 

prior to the March 2006 spill, why is it that BP chose not to pig the 

eastern line? Earlier you said you run about 370 pigs through your lines 

in Alaska but apparently these eastern and western lines weren’t pigged. 

Why is that? 

 MR. MARSHALL. Mr. Congressman, the 350 to 400 pigs that we run 

every year are focused on those lines where we believe the probability of 

corrosion is to be the highest, water lines, gas lines, three-phase flow 

lines, typically the lines upstream of these transit lines. Clearly in 

retrospect, we should have pigged these lines, and going forward, we 

absolutely commit to a full program of very frequent maintenance 

pigging and smart pigging. 

 MR. MARKEY. Thank you, Mr. Chairman. 

 MR. WALDEN. Thank you. The Chair recognizes Mr. Green. 

 MR. GREEN. Thank you, Mr. Chairman, and I appreciate the 

patience of the Chair in allowing those of us on the full committee but 

not on the subcommittee. You know, I represent a district in Houston 

that has both refineries and pipelines and we live and work around them 

our whole lives, and I guess what bothers me is the testimony today and 

following the questions is that our country needs the energy, and when a 

company like BP that both at the refinery in Texas City and the pipeline 

not only the last six months of publicity but today at this hearing, and it 
484

just makes it so much harder for us to be able to deal with energy 

matters, even though some of our districts are so dependent on it. And 

whether somebody on the east or west coast wants to drill off their coasts 

or they want a pipeline, you know, they still want their lights turned on 

and they still want something in that gas station whether it is E85 or 

refined product, and when a company like BP does this, it sets a bad 

tone. You are not a third-rate company, you know, you are not a tier 

down. You are one of the largest in the world, and that is what is 

frustrating to us who know that our country has to have energy, and in 

Texas we have tried to provide it for 100 years, and that is the frustration 

I hear today, and it is frustration from the Chairman of the committee but 

also from those of us who have a lot of facilities. We do everything in 

our district from downstream to upstream. We drill and we also have 

chemical facilities. So that is what bothers me. 

 Mr. Malone, the allegations in the Texas City, and I want to talk 

about and in Alaska, have been made and hopefully the committee and 

the Federal investigators get to the bottom of it, but it just seems like 

there has been lower investment on maintenance and safety,which means 

less employment for my district because I have people that either work 

for the companies or they work for the contracting companies. Can you 

tell me about BP’s plans for investment in maintenance and safety in the 

facilities both in Texas City and Alaska? As what you have learned in 

your short term there, do you see a change in the culture in BP because, 

you know, I see it both in the refinery side but we see it in the pipeline 

side. 

 MR. MALONE. Congressman, if I could, I just want to start with your 

disappointment. We are equally as disappointed, and we are in action, 

and in Texas City, we have done a number of items including an 

additional billion dollar investment into that side where we are going to 

look at the process safety systems, we are making the capital expenditure 

and the changes in management, all the actions that are necessary to 

assure ourselves of the safety of Texas. 

 MR. GREEN. Okay. Let me follow up on that. I know you have 

created a special committee that Secretary Baker chairs. Does that 

committee include people from the bargaining unit in Texas City? 

 MR. MALONE. It includes a union representative from the United 

Steelworkers. 

 MR. GREEN. Okay. Thank you. That is something--one of the 

questions that I really was concerned about because if we are going to 

solve the problem, it needs to be not only for folks in the front office but 

folks who actually do everything along the way, and I hope that that 

committee’s recommendations will be taken seriously, because again, 

you set the standard whether it is Texas City, and again, I have lots of 
485

refineries along the Houston ship channel. I want to make sure, you 

know, that the problems are fixed because I don’t want to see that happen 

in one of mine. I didn’t want to see it happen in Texas because I actually 

lost a constituent, a contract worker from Bay Town, who is part of our 

district. 

 Mr. Marshall, I know that there has been some discussions on why 

there weren’t smart pigs technologically but, you know, I remember 

being in Alaska in the 1980s as a State legislator, and when ARCO ran it 

and they talked about how the safety of these smart pigs but you are 

telling me that the engineering of that east and west lines when they were 

built were not made to handle the smart pigs to be able to tell? 

 MR. MARSHALL. Sorry, Mr. Congressman. Let me reestablish, that 

is not the impression I wish to leave with my remarks. What I was 

referring to earlier was I think in response to a question about whether 

there were alternatives in the event of issues whether we could divert the 

flow from one pipeline to another, and certainly what I was referring to 

on the west was that we had alternative bypasses that we could use. 

Indeed, we had actually used one of those bypasses to route oil from 

Gathering Center 2 to Gathering Center 1 once the OT-21 line failed. 

The pigging and smart pigging facilities on the east and the west were 

installed from day one so they do have them. 

 MR. GREEN. Okay. And I know you used alternatives and I guess 

the next question, British Petroleum is such a huge company, do you 

have actually part of your company that will do the smart pigging or is 

that something you contract? 

 MR. MARSHALL. We have expertise inside the company but the 

specifics associated with the smart pigging, we rely on a variety of 

contractors, well known, world known contractors to actually-- 

 MR. GREEN. So if somebody in BP decides that I think there is 

enough question about this line and it seems like just what the 

subcommittee has brought together in 2001 the discussion went back and 

forth between BP on the final draft of the Coffman Engineers report, it 

just seems like somebody would have said maybe we ought to smart pig 

that line and not wait 8 to 10 years. Can someone in BP actually say yes, 

we need to do it, and you know, that is what bothers me that if is a cost 

issue, and I know oil was $10 a barrel not that long ago, I am sure it is 

$60 now or $70, but--and I know cost considerations but when we have 

different agencies saying there is a problem with the pipeline, then it 

would seem like the next step would be someone from the company 

would say okay, we have a problem, instead of negotiating the report 

language, ought to say maybe we ought to actually smart pig that and see 

what we have in that line, at least more often than every 8 years. Has 

that been a discussion, particularly since after the line? 
486

 MR. MARSHALL. Certainly, Mr. Congressman, since the leaks that 

has been a very strong discussion and certainly in retrospect, I think 

everybody in BP including everybody in BP Alaska says that if we could 

do it again, we would have pigged and smart pigged those lines. 

 MR. GREEN. And to set the tone for the industry though because the 

technology again has been around for a long time. You know, I know 

there are cheaper methods you can use but why would a company not on 

a regular basis, not every 10 years or when your technology--why would 

they not want to just say I am going to invest in that smart pig to make 

that determination? 

 MR. MARSHALL. Let me stress, Congressman, this is not an issue of 

cost. Safety and integrity spending in BP are the highest things. They 

don’t get cut. They are the things that get through the budget so that is 

not something that--cost is not a consideration. 

 MR. GREEN. Well, why again would we see a report again 

negotiating the language in 2001 on a report with Alaska, the State of 

Alaska, but why wouldn’t there have been a decision to actually smart 

pig those lines in 2003 or 2004 before it broke in 2006? 

 MR. MARSHALL. Mr. Congressman, I-- 

 MR. GREEN. I appreciate the Mister, but you don’t have to call us 

that. They do a lot of things to us in D.C. You know, they don’t have to 

call us Mister. 

 MR. MARSHALL. Thank you. 

 MR. GREEN. They can’t change our name. 

 MR. MARSHALL. The thing I am not clear about and I will look into 

is whether the references in the draft report, the draft of the Coffman 

report were referring to smart pigging the transit lines or to the flow 

lines, the other 1,500 miles or so of lines that we have on the North 

Slope. We do have a very active program of maintenance pigging, as I 

said earlier, 350 to 400 every year. We have inline inspections, i.e., 

smart pigging, on a number of our lines, whether they are regulated, and 

indeed many lines which aren’t regulated. This is not an issue of cost. 

This was simply an issue of where we judged the likelihood of corrosion 

to be the highest, and we didn’t get this one right. 

 MR. GREEN. Well, I know I only have a minute left, and Mr. 

Chairman, I would hope that whatever comes out of the investigating 

committee, that we may need to see legislation. But I would hope that 

whether it is British Petroleum or any other pipeline company would 

actually use the technology that has been available on a more regular 

basis because when it does break, it is just not near worth you sitting here 

today and all the problems that you are going through and also for the 

nature of our country because we have to have the energy, and the 

message that is being sent today is that if we need to do a pipeline 
487

somewhere else, and I have been involved in lots of pipelines whether it 

is crude or refined products different places, it is difficult. So if we can’t 

be assured that the people running those pipelines are going to maintain 

them and monitor them with the technology that is available now, then it 

is going to be very difficult to do it, and we fight these battles in this 

committee all the time and on the floor and I know in the Senate so, you 

know, you being here today may set us back on trying to make sure that 

we can deal with it. And I know Mr. Inslee has got the legislation on 

alternatives, which is great, but for the next 20 to 30 years, hydrocarbons 

is what is going to keep our country running, and sure, we may be able to 

use ethanol, we may be able to use other things, and I support that, but I 

know we have to have hydrocarbons and we need more. We need 

obviously the North Slope, we need Anwar, we need the discovery that 

Chevron did, and if we can’t be assured that it is going to be done safely, 

it is going to be very difficult in the halls of Congress, much less in the 

courtrooms around the country, for companies that don’t do the right 

thing. 

 MR. MARSHALL. Mr. Chairman, if I could make a comment there, it 

wasn’t a question, but I am very conscious of the impact we have had to 

many constituencies, to the State of Alaska, to the Nation, the disruption 

in oil supply. It is something that I have taken very strong personal 

disappointment in as has the entire Alaska team. I am also conscious of 

how we have let down the industry. A track record takes a long time to 

build, and it is very easy to lose, but I am proud to say I work for a 

company that will learn and will do the right thing. We are committed to 

investing whatever it is we need to to reestablish confidence. It may take 

time. We are going to work with the Department of Transportation to 

not only meet their standards but exceed their standards, not just bring in 

technology but the best technology. If we can help the industry do that 

better, we are committed to doing that. 

 MR. GREEN. Mr. Chairman, it is sad that when we have an accident 

like at Texas City Refinery, where the contract trailer was too close to a 

unit, or something in Alaska, we see the loss of both lives in Texas City 

but also the problems in Alaska, but I would hope that we would see 

legislation from it and again, a reinvigoration of not only British 

Petroleum but other companies to make sure that we provide that energy 

that our country needs. 

 MR. WALDEN. Thank you for your participation in the hearing 

today, Mr. Green. I now recognize the gentleman from Florida, Mr. 

Stearns, for 10 minutes. 

 MR. STEARNS. Thank you, Mr. Chairman. Mr. Marshall, let me just 

ask you, what is the status of Mr. Woollam? Has he been fired or what is 

his position now? 
488

 MR. MARSHALL. Mr. Woollam doesn’t actually work-- 

 MR. STEARNS. Does he still work for BP? 

 MR. MARSHALL. He still works for BP. He doesn’t work actually in 

Alaska so I don’t--I would call on Mr. Malone to make a comment on 

that. 

 MR. STEARNS. Mr. Malone, where does Mr. Woollam work now, 

and he is still an employee of BP, right? 

 MR. MALONE. Yes, he is. He has been put on leave. 

 MR. STEARNS. He was put on leave, but does he come to work every 

day? 

 MR. MALONE. No, he will not. 

 MR. STEARNS. And have your people done an investigation and 

spent some time talking to him to get his side of the story or did you just 

put him on leave and that is it? 

 MR. MALONE. The attorneys have spoken, Congressman, and they 

have spoken to him. 

 MR. STEARNS. So your attorneys have talked to his attorney? 

 MR. MALONE. Yes, and to him. Our attorneys have spoken to him. 

 MR. STEARNS. But he is still under payroll, right? 

 MR. MALONE. He has been put on leave but yes, he is on the 

payroll. 

 MR. STEARNS. All right. Thank you. Mr. Marshall, you just 

mentioned that--and I just want to make sure I understand this better. 

You mentioned that safety and integrity programs don’t get cut in your 

corporation, and I guess the question is, do budgetary expenditures 

impact the bonus of individual managers? So the first question that I 

have for you is, do budgetary expenditures--if a person meets his budget, 

does that impact the bonus of your individual managers? Just yes or no. 

I would think that is pretty easy. I mean, if I have a budget and you give 

me a budget and I keep under budget, I guess that is positive, isn’t it? 

 MR. MARSHALL. Costs aren’t a direct linkage between reward and 

bonus in BP. 

 MR. STEARNS. Right, so the bonus is directly proportionate to the 

budget? 

 MR. MARSHALL. No. Sorry, no. I did not mean to leave that 

impression. It is not a direct linkage. 

 MR. STEARNS. There is a linkage? 

 MR. MARSHALL. No, there is not. 

 MR. STEARNS. Not? So if a person is way over budget because he 

or she says we need more safety and integrity in this program, we need a 

lot more money, that doesn’t affect his-- 
489

 MR. MARSHALL. Bonuses are set on the basis of a balanced 

scorecard, what we call a balanced scorecard of a suite of performance 

metrics for the business. 

 MR. STEARNS. Okay, and the budgetary is not one of them? 

 MR. MARSHALL. The budget is included in there but there is very 

little-- 

 MR. STEARNS. Oh, okay. I see. Okay. I had the privilege to be here 

for the oversight’s investigation of Enron, and during that investigation, 

we found that when Sharon Watkins went to her boss and talked about 

the problems in Enron, her boss gave the problem to Vinson and Elkins 

as a consulting firm and so it appears that at this point it is sort of a 

parallel just in that sense, that Vinson and Elkins is doing an analysis for 

you folks instead of you folks going out, investigating and saying we are 

going to make some action here, we are going to take these complaints 

from the EPA that came in. You sort of punted it to Vinson and Elkins. 

That is the same thing Enron--I am not implying anything. I am just 

saying, I was struck by the similarities, that you certainly punted this to 

Vinson and Elkins and said okay, you do analysis, we are not going to do 

it, you do it for us. Now, they came up--the Vinson and Elkins report 

contains an appendix of 72 allegations about the corrosion control 

program and specific safety concerns. The question for you, Mr. 

Marshall, is have all of these issues been addressed to your satisfaction 

and completely corrected, remedied, if necessary, since BP received the 

law firm’s report? 

 MR. MARSHALL. There was a series of actions coming out of that 

report. We converted those actions into a management plan and yes, 

indeed, I can confirm that all those actions have been taken. 

 MR. STEARNS. So there is no more corrective action necessary? 

 MR. MARSHALL. The actions coming from the Vinson and Elkins 

report have all been acted on. 

 MR. STEARNS. On page 5 of the appendix, allegation number 19 

mentions that agency inspectors are directed to inspect only good areas 

of the pipeline, although Vinson and Elkins found no evidence of this. 

Can you speak to the relationship between the Alaska Department of 

Environmental Conservation and BP Alaska? Can and do inspectors go 

wherever they want when inspecting BP’s pipeline? Is it true, that what 

is stated is true? 

 MR. MARSHALL. To the best of my knowledge, I believe that is true, 

and not only that, I would welcome open scrutiny wherever agencies 

demand to go. I think that is-- 

 MR. STEARNS. So they can go wherever they want? 

 MR. MARSHALL. In my opinion, I welcome that, yes. 
490

 MR. STEARNS. On page 3 of the appendix, allegation number 10 and 

11 describe concerns that over the past several years there have been 

concerns raised about cost cutting and that corrosion control and 

monitoring was suffering, that serious damage was occurring to the 

pipelines and infrastructure. Has there been cost cutting in the corrosion 

program over the past seven years--several years? 

 MR. MARSHALL. Since I arrived in 2001, our corrosion spend has 

gone up 80 percent. It has increased every year and will continue to 

increase going forward. 

 MR. STEARNS. On page 4 of the appendix, allegation number 13 

discusses an allegation of data scrubbing, and allegation number 17 

describes concerns that corrosion field data was being manipulated. 

What does the report mean that no evidence was found on manipulation? 

In other words, the status comment doesn’t explain where the 

investigation looked for evidence and seems to imply that data may 

receive a “positive spin” and isn’t spin and manipulation the same thing? 

 MR. MARSHALL. I am not aware of anything beyond what the 

Vinson and Elkins report found. We take very seriously any allegations 

of data manipulation. It is not in a business’s best interest to falsify data 

or for any individual to falsify data so we take that very seriously, and 

we found no evidence that data had been manipulated for any purpose. 

 MR. STEARNS. Mr. Hostler, there is a question for you. Since TAPS 

provides a significant percentage of Americans’ energy security and 

evidently will for some time to come, could you tell the committee what 

your primary concerns are with respect to the TAPS system and what are 

you doing about these concerns? 

 MR. HOSTLER. Congressman, thank you. If you look at our risks, 

our primary concerns are security of the pipeline. I think everybody in 

this room knows the importance of this line and its security and a lot of 

good work is being done there. I will come back to it. We do worry 

about the potential for mechanical damage associated with work along 

the pipeline and we do worry about corrosion as we have been talking 

about today, both internal and external, and so we have a comprehensive 

integrity management program to look at all that. But the one action I 

would like to talk about is as a learning from the spill on March 2 and the 

learning from the follow-up, we have been putting a lot of effort into our 

corrosion program. One of the things that we have done is, we have 

actually initiated an intelligent pig run this year, one year prior to our 

next scheduled run in 2007. So we have taken the instances around the 

Prudhoe Bay spills and learned from that and put an action plan in place, 

not to discount any of the other areas that we have concerns around. 

 MR. STEARNS. Would you agree that regular pigging is even more 

important as throughput declines? 
491

 MR. HOSTLER. Yes, sir. 

 MR. STEARNS. As a pipeline operator, would you expect to see 

regular pigging of low-stress lines where the oil moves at a slower 

velocity? 

 MR. HOSTLER. In the low-stress lines, yes, sir. 

 MR. STEARNS. Okay. Are you aware of any crude oil pipeline that 

is not pigged as part of a regular corrosion maintenance program, leaving 

aside lines that may not be piggable due to sharp turns in the line or other 

structural obstacles? 

 MR. HOSTLER. Leaving aside those lines that have those types of 

problems, no, sir, I am not aware of any that are not pigged as a routine 

maintenance program. 

 MR. STEARNS. Prior to the March 2006 leak and the subsequent 

examination of these lines, were you aware that there might be sludge, 

sediment and/or scale problems with these transmission lines? 

 MR. HOSTLER. Prior to March 2? No, I wasn’t, but I had only been 

in place about five months, and I don’t--I cannot find any records or 

notice, indication within our organization that we were concerned or 

aware of the issues with EOA and WOA line. 

 MR. STEARNS. Thank you, Mr. Chairman. 

 MR. WALDEN. Thank you, Mr. Stearns. I think we have--everybody 

has had an opportunity to ask questions who are here so we will go into a 

second round, and I will yield myself 10 minutes. 

 Mr. Stears, can you briefly explain what Coffman Engineers does 

and who you are? 

 MR. STEARS. Coffman Engineers is a multi-disciplined engineering 

company. We have offices in Seattle, Spokane, Los Angeles and 

Anchorage. 

 MR. WALDEN. In Anchorage. Could you turn to Exhibit 10 in the 

binder there and could you please describe what is the Coffman report 

regarding Prudhoe Bay corrosion control? 

 MR. STEARS. It is an overview of BP’s program and it gives the 

reader a description of what the program consists of and areas for 

improvement. 

 MR. WALDEN. And this is done for whom? 

 MR. STEARS. For the State of Alaska. 

 MR. WALDEN. And exactly what does the State of Alaska do with 

the Coffman reports that you submit to them in final form and how does 

the State utilize your analysis? 

 MR. STEARS. I am not positive of that. I do know they forward the 

results to BP but other than that, I don’t know what they do with it. 
492

 MR. WALDEN. Okay. Turning to tab 9, this is BP’s response to the 

final draft. As you are aware, BP is highly critical of the Coffman final 

draft, correct? 

 MR. STEARS. That is correct. 

 MR. WALDEN. And if you can now turn to tab 26, Richard 

Woollam’s November 12, 2001, e-mail says that at the November 5 meet 

and confer that Coffman “seemed unwilling to discuss BP/PAI’s 

concerns.” So Mr. Stears, was Coffman surprised or frustrated by BP’s 

response, given your view that you had satisfied the scope of the work? 

 MR. STEARS. This is the first time that I have actually seen this in 

person. I talked briefly with your staff about it. Yes, it is my 

understanding that BP was upset. 

 MR. WALDEN. Right, but was Coffman surprised or frustrated by 

BP’s response? 

 MR. STEARS. My role in the program to begin with was, I was the 

manager of the corrosion engineering group so I just had a supervisory 

role, and I had to take the responses of my staff that was the direct 

project engineers on that. 

 MR. WALDEN. Were Bierry and Watts frustrated? They work for 

you right? 

 MR. STEARS. Yes. Tim Bierry did work for me. Mike Watts was a 

subcontractor to us, and-- 

 MR. WALDEN. Were they frustrated? 

 MR. STEARS. I would say it at certain points yes, they met a level of 

frustration. 

 MR. WALDEN. And why was that? 

 MR. STEARS. Well, to begin with, this was the very beginning of this 

program, and so the roles and responsibilities, the reporting metrics, 

things of that nature were all being agreed upon and actually discussed 

both with the State and the operators at that time, and so amongst those 

discussions, there was quite a bit of give and take, if you will, as far as 

what should or should not be in the program because there were already 

some things that were agreed upon with the State and the operators 

before Coffman got involved. 

 MR. WALDEN. Is that what should be in your analysis or what 

should be in the program? I mean, the findings of your report, is that 

what was in disagreement here or what the scope of the report-- 

 MR. STEARS. The scope of the report would be a better clarification 

of that. 

 MR. WALDEN. So the frustration that people who worked under you 

had with BP was over what should be considered? 

 MR. STEARS. What should be considered in the actual report as well 

as what should be talked about in the meet and confers. 
493

 MR. WALDEN. All right. Did Larry Dietrich or Mr. Fredriksson or 

any other ADEC employee ever instruct or pressure Coffman Engineers 

in any way to change the tone and content of the 2000 Coffman report? 

 MR. STEARS. No, not that I am aware of. 

 MR. WALDEN. Could you turn to tab 29? 

 MR. MARSHALL. Mr. Chairman, I apologize for the interruption. 

Could I be excused to go to the bathroom, please? 

 MR. WALDEN. Well, okay. Yes, of course. And then if--yes, 

absolutely. Anyway, if you turn to tab 29, this e-mail from Richard 

Woollam dated November 25, 2001, criticizes Coffman for a lack of 

sophistication and not thinking through the consequences if your final 

draft were really the final document. Can you respond to this criticism? 

Was it Coffman’s job to be concerned about public reaction or 

consequences of the report? 

 MR. STEARS. No, it was our obligation to meet the contract 

requirements with the State of Alaska. 

 MR. WALDEN. Was Richard Woollam worried about the public 

response to the report that was as critical of BP’s corrosion program as 

the Coffman final draft had been? 

 MR. STEARS. Could you please repeat that? 

 MR. WALDEN. Was Richard--do you know if Richard Woollam 

worried about the public response to the report--to a report that was as 

critical of BP’s corrosion control program as the Coffman final draft had 

been? Was he worried about the final draft and the public’s reaction to 

it? 

 MR. STEARS. I don’t know about this one in particular. Mr. 

Woollam has on several occasions expressed a concern that accurate 

information be provided so that the public understands it. 

 MR. WALDEN. Could you turn to tab 28? Tab 28 criticizes Coffman 

for not having sufficient review of the final draft at senior levels. You 

were the supervisor in charge of the final draft, were you not? 

 MR. STEARS. I was. 

 MR. WALDEN. And do you have a response to this criticism? 

 MR. STEARS. Where are you reading from, please? 

 MR. WALDEN. Tab 28. Let me double check to make sure I gave 

you the right tab number. My apologies. We are one off, tab 29, and it 

is the second bullet point, lack of review I believe that the final draft was 

issued by Coffman ADEC without review at senior levels within 

Coffman and/or ADEC. There had been issues about balance and the 

report being public would not have occurred, and that is from Mr. 

Woollam. 
494

 MR. STEARS. Yes, Mr. Woollam was inaccurate in that. There were 

several reviews internal, first of all, between the engineers that were 

working on it and then I did review the draft as well as the final. 

 MR. WALDEN. Mr. Malone, in Mr. Marshall’s absence, because the 

next set of questions I have is actually for Mr. Marshall, and speaking of 

Mr. Marshall, your timing is exquisite. I have been asking Mr. Stears 

about the Coffman report and some of Mr. Woollam’s criticisms and 

concerns as expressed in e-mails and elsewhere. Mr. Marshall, at tabs 10 

through 15 are documents prepared for the State of Alaska by Coffman 

Engineers regarding BP Alaska’s corrosion control program. Can you 

explain the significance of these reports from BP’s perspective, the 

Coffman reports? Do you consider them to be binding documents or 

helpful documents? 

 MR. MARSHALL. Mr. Chairman, thank you for the break. 

 MR. WALDEN. Yes, absolutely, and if other members need to do 

that, let me know. 

 MR. MARSHALL. These reports I would say are important 

documents for BP. 

 MR. WALDEN. Do you consider them binding documents? 

 MR. MARSHALL. From a legal perspective? I am not sure I 

understand the legality of the term to be able to say what it is. 

 MR. WALDEN. And I am not a lawyer so--but if you have the 

Coffman report that goes to the State of Alaska, do you look at that like 

you would, say, an internal audit and follow it precisely and say we have 

got to address these issues? 

 MR. MARSHALL. Any document which goes outside the company, 

we want to ensure its veracity, its accuracy. We want to provide the 

transparency on our operations, absolutely. 

 MR. WALDEN. But on these Coffman reports, do you basically 

consider whatever they say that you are basically bound to follow? 

 MR. MARSHALL. I haven’t looked into the implications of Coffman, 

if there are specific issues there that I am not aware of, but on the basis 

of your question I would say that we would work to follow 

recommendations that Coffman came up with. We take those on board 

and incorporate those into our business practices. 

 MR. WALDEN. All right. Did you direct Richard Woollam or 

anyone else at BP to pressure ADEC in any way, in any way to change 

the tone and content of the 2000 Coffman report? 

 MR. MARSHALL. No, sir. 

 MR. WALDEN. In November of 2001, did you personally place any 

pressure or request of ADEC in any way to change the tone and content 

of the 2000 Coffman report? 

 MR. MARSHALL. No, sir. 
495

 MR. WALDEN. Have you ever directed any employee at BP to 

contact ADEC or any other State official to request the removal of an 

ADEC employee from oversight work on the North Slope? 

 MR. MARSHALL. No, sir. 

 MR. WALDEN. Okay. Were you aware that Susan Harvey told 

Richard Woollam that she was only willing to make changes to the draft 

of the 2000 Coffman report if BP could show factual errors? 

 MR. MARSHALL. No, I was not aware of that comment. 

 MR. WALDEN. And what would your reaction be if you knew that 

was her comment? 

 MR. MARSHALL. Sorry. Could you repeat the comment again, 

please? 

 MR. WALDEN. The comment is that Susan Harvey told Richard 

Woollam that she was only willing to make changes to the draft of the 

2000 Coffman report if BP could show factual errors. 

 MR. MARSHALL. Again, not having much time to kind of consider 

that, my reaction would be that, that would be a very reasonable request. 

We have got to--I think any organization needs to make conclusions 

based on truth and fact. If we were unable to provide facts to shift or 

adjust a conclusion, that prior conclusion should still stand. If there is 

new information or information we hadn’t provided, if it was an 

omission, I think that is something we would want to offer into the 

record-- 

 MR. WALDEN. Absolutely. 

 MR. MARSHALL. --for consideration. 

 MR. WALDEN. All right. That wraps up my questions. Thank you, 

sir. Mr. Stupak. 

 MR. STUPAK. Thank you, Mr. Chairman. We have been talking a 

lot from 1992 to 2006 and the pipeline came online in June of 1977. Is 

that right? 

 MR. MARSHALL. Yes. 

 MR. STUPAK. Can you tell me, Mr. Malone or Mr. Marshall or 

anyone else at the table, if the lines were pigged at all between 1977 and 

1992, during that 15-year span? 

 MR. MARSHALL. I am only aware of the western area line being 

pigged in 1990. 

 MR. STUPAK. Okay. Eastern was pigged in 1992, I think. 

 MR. MARSHALL. That is correct. What I don’t have in front of me 

but I can find out is, were there any earlier pig runs on that-- 

 MR. STUPAK. Yes, I would like to know that because you have a 15-

year block there and we are talking about a four-year block. If you are 

pigging in the 15-year block when the oil is flowing a little quicker, a 

little stronger, I would think that it would be helpful to us because I think 
496

the only smart pigging we have, as you said, is the late 1980s on the 

western line. What I am hearing and the way I would guess I would 

paraphrase BP’s testimony today was that we believe we had a good 

corrosion prevention program but we didn’t believe we had corrosion. Is 

that fair? You are sitting there telling us you have this integrity in this 

program so are you saying therefore we didn’t believe we had it? When 

you did pigging before, you had all kinds of problems. 

 MR. MARSHALL. We didn’t believe we had aggressive corrosion in 

these lines until we started to see indications of that in the 2004-2005 

time frame. The data that we had, and I do stress that it is based on the 

data that we had, the information that we had-- 

 MR. STUPAK. In 2004-2005? 

 MR. MARSHALL. In 2004-2005 indicated an increase in corrosion on 

the western area line. 

 MR. STUPAK. Let me ask--Mr. Malone, let me ask you this question. 

This question came up, and I ask this question respectfully because I was 

just--I have been in and out of this hearing today because when 

constituents come from northern Michigan, even though I am stuck all 

day in these hearings, I still like to try to meet with them. We were 

talking, you know, we are at this hearing today, and a couple of them 

brought up the fact that on the Today show, they asked you a question 

about how you spend, based on the profits of BP, like one-quarter of a 

penny for maintenance of the lines and then I think Matt Lauer asked you 

if you were going to--the cost to do this replacement, I think you are 

doing, what, 16 miles of pipes or something like that. That has pretty 

tremendous cost to the company, so therefore to the average American 

consumer, will the cost of gas go up because of this pipeline problem or 

will you just take it out of profits. 

 MR. MALONE. Well, first of all, the way the global market works, 

Congressman, and particularly once the incident occurred, we didn’t see 

a rise in the price of gas-- 

 MR. STUPAK. That is my next question. Go ahead. 

 MR. MALONE. Because we were able to get supply into the west 

coast. We actually brought in about-- 

 MR. STUPAK. Well, when will we start to feel the pinch here and 

when will the price go up then from BP’s point of view? Isn’t that what 

you are basically telling us, we haven’t seen the pinch yet because other 

supply is adequate? 

 MR. MALONE. Congressman, if I can, I would like to submit that for 

the record because--forward a response back to you because I am not 

quite sure how that would work and I need to consult with-- 

 MR. STUPAK. Because here is the question that constituents want to 

know: Since this has been announced, gas prices have gone down, but 
497

yet if we don’t have as much oil coming in available to this country, but 

prices are going down, therefore they should not go up even with your 

added costs as prices go down, right? And that is sort of what they asked 

me out in the hall and I said okay, good question, I will ask. 

 MR. MALONE. I will get that for you, Congressman. My apologies 

for not-- 

 MR. STUPAK. No, no, no problem. And by the way, Mr. Malone, at 

least on this side of the dais, I am sure on both sides, you had worked in 

the 1990s, right, in Alaska before for BP? 

 MR. MALONE. Yes, I did. 

 MR. STUPAK. And you were called over to England and no sooner 

got there and this happened? 

 MR. MALONE. I was in Alaska and I ran Alyeska also for a period of 

time but I had a four-year stent with BP Shipping Limited in England. 

 MR. STUPAK. Well, I know they indicated that in the past when we 

had some problems in Alaska, you were one of the people who stepped 

forward and got it corrected and cleaned up and we are hoping the same 

thing will happen here, so a lot of people up here were glad to see you 

take this position and we have faith that you will get this thing cleaned 

up as soon as possible. 

 Mr. Marshall, let me ask you this. Isn’t it true that both the eastern 

and the western pipes are now low-stress lines and that they were 

originally designed to hold greater amounts of oil and that the flow rate 

of this oil was originally much higher, right? It was 800 PSI at one time 

and we are down to 80 PSI now? 

 MR. MARSHALL. Congressman, I am not in a position to say what 

the pressure was. The flow rate was much higher. 

 MR. STUPAK. Was much higher than it is now? 

 MR. MARSHALL. At the time, and compared to what it is right now, 

yes. That is correct. 

 MR. STUPAK. And if we can have photo number 3 up. And these are 

the current lines now in fact as soon as we get it up here. The red one is 

the one where we are working on now. This is where the March spill 

occurred. Again, our staff was up there over the break and took these 

photographs. So why were such strategic lines in the eastern and the 

western lines which are both low flow and thus susceptible to corrosion 

not replaced with smaller diameter lines earlier? Why did we have to 

wait for total failure to get to the point of now deciding to replace them 

with smaller diameter lines? I think the question earlier was 34-inch 

lines and now they are going to be replaced by smaller ones to get the 

flow going to keep the corrosion out, right? 

 MR. MARSHALL. And again, until we get the failure analysis of the 

pipe from both the OT-21’s failed section which this is and the Flow 
498

Station 2 line, it is still only a theory that velocity is a factor. It is 

emerging as a more likely factor than it might have been at the time of 

the March spill but it still only one factor. There may be others as well 

including microbial-- 

 MR. STUPAK. Sure. The faster the flow, usually keeps the corrosion 

out, right? The water is moving and everything is moving. 

 MR. MARSHALL. Velocity is certainly a factor to prevent dropping 

out of solids or liquid but equally the effectiveness of corrosion 

inhibitors going through the line and the existence of bacteria and the 

effectiveness of bactericide to prevent the growth of bacteria are also 

factors. 

 MR. STUPAK. BP provided the committee with an internal report it 

issued on June 7, 2006, called the Alaska Transit Technology Review. 

Are you familiar with that Alaska Transit Technology Review? 

 MR. MARSHALL. Yes. 

 MR. STUPAK. Sometimes referred to as the Baxter report. 

 MR. MARSHALL. Yes. 

 MR. STUPAK. And it was done after the March 2 spill, right, and you 

are familiar with that one? 

 MR. MARSHALL. I am aware of that report, yes. 

 MR. STUPAK. Okay. On page 6--I realize there are no page numbers 

but if you go to page 6, there is a series of bullet points, and let me quote 

from the first bullet-- 

 MR. MARSHALL. Excuse me, Congressman. Which tab is that? 

 MR. STUPAK. Hang on. Let me get it. 

 MR. MARSHALL. I have got it. 

 MR. STUPAK. You got it? Okay. I know the pages aren’t numbered 

but on page 6 there, you will find these bullet points, and the first one 

says, I am quoting now, “Where sand deposits and entrained water are 

able to drop out from the fluid stream onto the bottom of the pipeline as a 

result of the low-velocity flow, this creates ideal conditions for the 

proliferation of sulfate-reducing bacteria (SRB) on the pipe surface. The 

most likely cause of the accelerated corrosion is therefore believed to be 

the micro-influenced corrosion (MIC) under sediment deposit onto the 

bottom of the pipe, and you were just talking about the MIC. So my 

question is then, Mr. Marshall, when did BP first suspect that such 

sediments were collecting in the western pipe? 

 MR. MARSHALL. Mr. Congressman, to the best of my knowledge, 

certainly from my perspective, the existence of solids in that line 

occurred after the March spill. Certainly the existence of solids upstream 

of that transit line were known before that. 

 MR. STUPAK. I am not necessarily talking about the solids. 

 MR. MARSHALL. I am sorry. I misheard the question then. 
499

 MR. STUPAK. When were you--when did BP first suspect--I mean, 

this is a report they provided in June--first suspect that sediments were 

collecting in that western line? March, after the spill, or before? 

 MR. MARSHALL. After the spill. Certainly from my perspective, 

after the spill. 

 MR. STUPAK. When was the water and sediment drop-out as a 

potential corrosion contributor first suspected by BP? Was it before or 

after the March spill? 

 MR. MARSHALL. I don’t have any specific evidence of when that 

may have occurred at some level in our organization. I do know that we 

experienced planned upsets. I do know that we experienced sediment 

drop-out in Gathering Center 2 as a result of the startup of viscous oil 

production in 2004 and 2005. We did take action to remove those solids 

at that time. 

 MR. STUPAK. In 2004-2005? 

 MR. MARSHALL. In 2004-2005 timeframe. 

 MR. STUPAK. Did you try to remove the solids? 

 MR. MARSHALL. We basically installed sand jets into a number of 

our vessels. As the solids-- 

 MR. STUPAK. How far would a jet blow the sand then? 

 MR. MARSHALL. It blows it into a container which we then take 

away and we dispose of the solids in the appropriate way, so they are 

actually removed from the facilities or from wherever they accumulate 

and are disposed of there. 

 MR. STUPAK. But you didn’t scrape the pipe though? 

 MR. MARSHALL. No. The expectation was that the solids would 

accumulate where they are designed to accumulate inside the separators, 

the big vessels that exist inside Gathering Center 2, which are designed 

to separate the oil, gas and water, and indeed any solids from the crude 

oil stream. 

 MR. STUPAK. But in 1992 you knew that wasn’t happening because 

on the eastern pipes that is when you had all the problems with the 

strainers. 

 MR. MARSHALL. I should stress that my understanding of what 

occurred in the early 1990s on the eastern side was actually calcium 

carbonate scale, not solids. 

 MR. STUPAK. But still, it would be enough to disrupt the flow of the 

pipe, and you said earlier in your testimony what was happening on the 

western you figured was happening on the eastern, so in 1992 if you 

figure it is happening on the eastern, why didn’t you figure it was 

happening on the western? If it holds true for one, it holds true for the 

other. 
500

 MR. MARSHALL. The existence of calcium carbonate scale is 

something which is more of a factor on the eastern side of the field in the 

same way that the viscous oil is only evident on the west. The calcium 

carbonate scale as we have looked into it, tends to be a factor more on 

the east than it is on the west, certainly in terms of how it translates to the 

transit lines. 

 MR. STUPAK. Thank you. 

 MR. WALDEN. Thank you. We have a vote on the floor. Mr. Inslee. 

 MR. INSLEE. Thank you. Mr. Malone and Mr. Marshall, I asked you 

about this Coffman report earlier where there were very significant 

deletions from the report, from the preliminary draft before it went to BP, 

deletions about the fact that smart pigging is the only inspection 

technique capable of looking at the entire internal structure of the pipe. 

A statement, the actual magnitude of the corrosion increase is not 

reported. That was deleted. A statement, external corrosion inspection 

levels are not consistent with the relative risk. That was deleted. A 

statement that no differentiation between weight loss and pitting 

corrosion are discussed. That was deleted. No statistics on the extent of 

corrosion defects reported. That was deleted. You can go through this 

report, there are just reams of negative critical statements in the original 

report sent in to the State of Alaska by Coffman contractors that were 

then deleted after communications with British Petroleum. So the 

question is, how did that happen and why did that happen? It is 

disturbing to me that the public only found out about that after this 

incident, that these deletions occurred. What I want to ask you about is 

this disturbing e-mail that we just saw. It is an e-mail dated November 

11, 2001, 9 days after the original Coffman report was submitted, so 

nine-- 

 MR. WALDEN. For the record, Mr. Inslee, that is tab 25. 

 MR. INSLEE. Thank you. Nine days after the original was submitted, 

here is an e-mail from Mr. Woollam, the gentleman who took the Fifth 

Amendment in charge of this program, BP employee, it says, “Michelle, 

could you please do a little research for me in a hurry? I want to know if 

BP Exploration Alaska, Inc. has any contracts with Coffman Engineers, 

and if so, what and who is the contract CAM, if any. My understanding 

is that they have a general services contract but have been unable to find 

out any more than this. Thanks, Richard.” Now, frankly, it is hard for 

me to imagine another reason out of the blue this gentleman would be 

asking if Coffman has any other contracts with British Petroleum other 

than perhaps we have a way of influencing their behavior. Do you have 

any suggestion why this gentleman would have all of a sudden asked 

about Coffman contracts with BP other than perhaps finding a way to 

influence their behavior? 
501

 MR. MARSHALL. I have not seen this e-mail before and I really 

cannot comment on what Mr. Woollam’s intent would be. Could I offer 

one alternative though, that one of the things that--if we engage with any 

company that is working for a third party, we need to make sure that we 

don’t have any conflicts of interest in the dealings with them. I am not 

suggesting that was the case but that is certainly a possibility to avoid 

conflict of interest. 

 MR. WALDEN. Mr. Inslee, just as a point for the record, I am told by 

staff that actually that document is a cited document in the Feldman 

report. 

 MR. MARSHALL. I have not actually read it, so-- 

 MR. INSLEE. Thank you. Given the attitude we have heard about 

this particular individual and the difficulties, your suggestion while 

creative I suspect probably was not the case. We will leave that to other 

discussion. But it is of great concern that we had this failure now about 

something exactly that this contractor pointed to. You have discussions 

with BP, there are deletions to the report and bang, you got this process 

now that is reduced by 8 percent, the total production of our domestic 

capacity. You can see why that causes us some great concern here. 

 I want to ask you about one suggestion I made. BP has had now 

what is a significant black eye. I think we would all agree with that on a 

failure of this responsibility and I think Mr. Malone and Mr. Marshall 

recognize that. The question is, what do you do as a corporation right 

now. I suggested sincerely that it would make sense to go back and talk 

to your highest decision-makers about finding a way to demonstrate your 

commitment to being an environmentally responsible company, and the 

reason this idea comes up is, Mr. Green was talking about how maybe 

we are, you know, decades away from having a more ethanol-based 

economy. I don’t think it is decades. Brazil today has 40 percent of all 

their fuel essentially as its ethanol, it is domestically produced. This is 

the here and now. They drive flex fuel cars that drive either--operate 

either on gasoline or ethanol and they work great, and you pull up to 

your pump and you see which one is cheaper, the ethanol or the gasoline 

that day, and fully 40 percent of their fuel source is from that. This is 

something that we are capable of doing. But when I talk to the Brazilian 

leader who is responsible for developing that protocol and basically 

asked for his advice, what do you have to do to get there as a national. 

He said frankly, you have got to break the arms of the oil and gas 

industry because they resist putting these pumps in and they control the 

infrastructure. Now, there are 170,000 pumps in the United States for 

gasoline today and there are about 858 for E85 ethanol when almost 

every single station in Brazil makes that available to its consumers and 

they essentially broke the elbows of the oil and gas industry in Brazil to 
502

make that happen. We don’t want to have to go through that. We would 

like British Petroleum, that controls a very significant part of the 

infrastructure of this country, to make a very specific corporate 

commitment to getting E85 pumps into their stations as fast as they can. 

This is very possible. The USDA has done a very sophisticated analysis 

and found that we could have 30 percent of our transportation needs at a 

minimum within 30 years from ethanol domestically produced but we 

need your leadership to put those pumps in to develop how we do this. 

Now, the Brazilian also told me, don’t let those oil and gas guys tell you 

they can’t deliver it by pipeline either because we do it down there in 

Brazil. So I guess the question I have for you, given your experience 

here, which probably hasn’t been too comfortable, rightfully so, isn’t it a 

legitimate thing for you to go back and talk to your leadership and say 

here is one option for us as a corporation to demonstrate moving forward 

after this debacle to say let us double our commitment to ethanol 

production in this country; let us make some specific numerical targets of 

how many E85 pumps we are going to have in our filling stations across 

this country, and you have got a lot of them in the State of Washington 

and I love to see them there. What do you think of that idea, going back 

and talking to Sir Henry Brown and say let us come up with a numerical 

target and let us meet it. 

 MR. WALDEN. Mr. Inslee, just for the record too, we are down to 3 

minutes. 

 MR. INSLEE. All right. I am done. That is my last question. 

 MR. MALONE. I would say, Congressman, I felt kind of bad because 

when we bumped heads the last time, I think we were both bumping 

heads on stuff we both agreed with. I will have that discussion and I 

have some ideas of my own. If I could, I will come back and see you on 

that and I will also talk to John Browne, who has a very, very strong 

commitment as I do, and I will be back directly in touch with you. 

 MR. INSLEE. Thank you. 

 MR. WALDEN. Thank you, Mr. Inslee. Thank you, Mr. Malone. 

And just finally as we begin to dismiss this panel and recess the 

committee while we vote on the floor, Mr. Marshall, in light of Miss 

Harvey’s statement to the staff that she was only willing to consider 

factual changes to the Coffman report, can you see how it looks a little 

suspicious that Ms. Harvey gets removed from the project and then the 

tone and overall conclusions of the final report are changed significantly? 

I mean, it raises some red flags for us. 

 MR. MARSHALL. Certainly I can understand and appreciate that. I 

just don’t have any information to offer any further illumination to that. 

 MR. WALDEN. Understood. Thank you. I want to thank the panel 

members for being here today. I know it has been a long day already. 
503

We have a second panel after this. We have about five votes on the 

House floor. We will reconvene as soon as we can get back here, but 

you all are free to go and we again appreciate the work you are doing and 

your participation in this hearing. The committee will stand in recess. 

 [Recess] 

 MR. BURGESS. The committee will reconvene and at this point I 

would like to call forward our second panel, Vice Admiral Thomas J. 

Barrett, U.S. Coast Guard, retired, Administrator for Pipeline and 

Hazardous Materials Safety Administration, U.S. Department of 

Transportation; Ms. Stacey Gerard, the Chief Safety Officer, Office of 

Pipeline Safety, Pipeline and Hazardous Materials Safety 

Administration, United States Department of Transportation; and Mr. 

Kurt Fredriksson, Commissioner, Alaska Department of Environment 

Conservation, and I want to thank you all for your forbearance. I know it 

has been a long afternoon while we dealt with pressing matters before the 

country. You are aware the committee is holding an investigative 

hearing and when doing so has had the practice of taking testimony 

under oath. Do you have any objection to testifying under oath? The 

Chair then advises you that under the rules of the House and the rules of 

the committee, you are entitled to be represented by counsel. Do you 

have any desire to be advised by counsel during your testimony today? 

In that case, if you will rise and raise your right hand, I will swear you in. 

 [Witnesses sworn] 

 MR. BURGESS. You are now under oath. You may give a 5e-minute 

summary of your written statements. Admiral Barrett, please, sir, you 

may begin your 5 minutes. 

TESTIMONY OF VICE ADMIRAL THOMAS J. BARRETT, 

USCG (RET.), ADMINISTRATOR, PIPELINE AND 

HAZARDOUS MATERIALS SAFETY ADMINISTRATION, 

U.S. DEPARTMENT OF TRANSPORTATION; AND KURT 

FREDRIKSSON, COMMISSIONER, ALASKA 

DEPARTMENT OF ENVIRONMENTAL CONSERVATION 

 VICE ADMIRAL BARRETT. Thank you, Mr. Chairman and members 

of the subcommittee, for the opportunity to discuss recent actions of the 

Pipeline and Hazardous Materials Safety Administration overseeing the 

safe operation of BP exploration pipelines at Prudhoe Bay, Alaska. 

 Our agency mission is achieving and maintaining safe, 

environmentally sound and reliable operation of the Nation’s pipeline 

transportation system. In practice, this requires understanding the 

condition of pipelines and ensuring that operators take actions to prevent 

and address any unsafe conditions. 
504

 As you know, the first responsibility for safety rests with the pipeline 

operator. Since the spill of approximately 5,000 barrels of crude oil from 

the BP-operated low-stress line at Prudhoe Bay on March 2, PHMSA has 

been on the job to ensure safe operations. The line where the spill 

occurred had not been federally regulated. In mid-March, using our 

statutory authority, we asserted Federal jurisdiction over the failed line 

and other BP unregulated low-stress lines at Prudhoe Bay, a total of 22 

miles of transit line. We subsequently issued a series of orders to the 

operator to upgrade safety. These related to understanding conditions of 

the lines and ensuring the operator was taking all necessary measure to 

assure their safety. We ordered BP to run cleaning pigs to remove solids 

from the lines, run inline inspections, or smart pigs to understand the 

conditions of the lines from the inside out. We directed extensive 

ultrasound testing and an enhanced corrosion management plan. We 

directed external surveillance using infrared detectors to detect any leaks 

and also the development of plans to manage solids in a way that 

prevented any risk to the Trans Alaska Pipeline. 

 It was as a result of the pigging that we ordered that BP discovered 

the wall loss and leaks on a line segment in the eastern operating area 

that led to the production shutdown on 6 August. Our personnel have 

been on the job tirelessly since March overseeing and directing these 

actions. We brought on additional technical resources from Oak Ridge 

National Laboratory, and along with my western regional director, Mr. 

Chris Hoydell, and my chief safety operator, Ms. Gerard, I visited 

Anchorage and Prudhoe Bay in early July to assess the situation 

firsthand. I met with my field inspectors, BP and Alyeska executives, 

State officials including Commissioner Fredriksson, and the Joint 

Pipeline Office. The Acting Secretary of Transportation, Maria Cino, 

visited in August and I went back last week to reassess progress and 

compliance with our orders. While this was progressing, we also put an 

inspection team on the Trans Alaska Pipeline and updated our risk 

assessment on other lines on the North Slope to minimize risks of any 

ripple effects from the BP incidents. 

 BP is finally making progress in addressing our concerns but the 

operators’ management of the lines in the years leading up to the March 

incident and their initial response to our orders was disappointing. 

Frankly, we do not understand why BP did not more aggressively 

address the corrosion problems that led to these leaks. Given the 

multiple risk factors for corrosion in the Prudhoe Bay environment and 

the low velocities on these lines, it is mystifying that BP did not run 

cleaning pigs regularly on these transit lines. Most pipeline operators 

demonstrate a higher standard of care than this regardless of whether 

they are federally regulated or not. 
505

 The overall safety record of the U.S. pipeline is good and getting 

progressively better. We are seeing a steady decline in the number of 

pipeline incidents that cause serious harm to people or the environment, 

and on August 31, the Administration proposed robust new safety 

requirements for low-stress pipelines in unusually sensitive 

environmental locations in rural areas including the BP lines at Prudhoe 

Bay. These rules have been in development since 2004, well in advance 

of these spills. Most of the lines involved are far smaller than the BP 

Prudhoe Bay lines. Low-stress lines in populated areas and near 

navigable waterways were already covered by our regulations. As this is 

a proposal, we are seeking public and stakeholder input about it 

including the scope of coverage and the requirements that should be 

included. 

 I also want to touch on our reauthorization proposal. One exception 

to the positive safety trends we see across the industry is damage caused 

by excavation on gas distribution systems. This poses serious life safety 

risks and the number of incidents of this type is increasing. These lines 

are regulated by our State partners. The Administration’s pipeline safety 

reauthorization proposal would greatly enhance the State’s ability to 

improve damage prevention and more effective address this risk, and I 

am pleased to see this priority being address by this committee. 

 Mr. Chairman, I want to assure you and members of the 

subcommittee that the Administration, the Acting Secretary and the 

dedicated men and women of PHMSA, by the way whose work at 

Prudhoe Bay I am enormously proud of, share your strong commitment 

to improving the safety, reliability and the public confidence in our 

pipeline transportation systems. We understand the importance of our 

mission to the citizens, communities and energy security and continued 

economic growth of this country. 

 With your permission, I will submit my written statement for the 

record and am pleased to answer any questions you may have. Thank 

you, sir. 

 [The prepared statement of Vice Admiral Thomas J. Barrett follows:] 

PREPARED STATEMENT OF VICE ADMIRAL THOMAS J. BARRETT, ADMINISTRATOR, PIPELINE 

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

TRANSPORTATION

September 7. 2006

I. INTRODUCTION

 Chairman Barton, Ranking Member Dingell, members of the Subcommittee, thank 

you for the invitation to appear today. I am pleased to discuss the actions of the 

Department of Transportation’s Pipeline and Hazardous Materials Safety Administration 

(PHMSA) to oversee safe operations of BP Exploration pipelines on the North Slope of 

Alaska. 
506

 The responsibility for safety rests first with the operator. Our mission is achieving 

and maintaining the safe, environmentally sound and reliable operation of the nation’s 

pipeline transportation system. This requires understanding the condition of pipelines in 

the U.S. and assuring that operators take action to address any unsafe condition. We 

manage oversight based on risk and take a “systems approach” to setting priorities. We 

make full use of the authority given us in the Pipeline Safety Improvement Act of 2002. 

Our progress with integrity management programs positioned us well to take effective 

action when the BP low stress transit line failed in Prudhoe Bay March 2nd. I believe 

quick DOT/PHMSA action was crucial to improving the performance of BP since the 

first incident. Only as a result of additional controls we imposed could limited operation 

of these key pipelines continue. 

 Over the past six years, PHMSA has designed and executed a risk-based systems 

approach to oversight of the national pipeline infrastructure. As to regulatory framework, 

we undertook rulemaking projects on a risk prioritized basis, acting first on those parts of 

the infrastructure that posed the greatest risk to people and then the environment. To 

begin the program, we defined high consequence areas and mapped the locations, 

including areas unusually sensitive to environmental damage, previously defined in 

regulation in 2000, in the National Pipeline Mapping System. We completed and 

implemented regulations which provided integrity management protections for people 

and the environment that could be affected by a failure from high pressure, large and 

small hazardous liquid pipelines and provided protections to people that could be affected 

by high pressure gas transmission pipelines. We began considering this rulemaking in 

2003, with discussion in our advisory committees, followed by public meetings in 2004. 

 The BP transit pipelines that failed in Prudhoe Bay were not regulated by DOT. On 

August 31 we offered a proposal to bring these lines under Federal oversight. Our 

rulemaking proposal provides for robust integrity protections, including corrosion control 

with cleaning and continuous monitoring, integrity assessment, leak detection and other 

measures for low stress pipelines. The proposal is the last remaining element in our 

regulatory framework designed to protect unusually sensitive environmental areas from 

low pressure pipelines in rural locations. The proposal would mandate a level of care 

well in excess of what BP had in place in the lines that failed. The recent BP pipeline 

failures in Alaska are not indicative of the safety of the national pipeline infrastructure 

which has a steadily improving safety record. Furthermore, BP’s low stress lines in 

Alaska are not a characteristic of other low stress pipelines in the U.S. lower 48 states. 

We believe that most other unregulated low stress pipelines are operated to a higher 

standard of care similar to that underlying our regulatory proposal, based on the record 

developed in connection with our rulemaking proposal. 

 Since the March 2 spill of 200,000 gallons of crude oil we have been working 

steadily to ensure BP adequately addresses the safety, integrity and reliability of all of the 

company’s pipelines. While PHMSA was not previously regulating BP’s three low 

pressure transit lines in Prudhoe Bay, following the spill we exercised our statutory 

authority to protect life and the environment. These pipelines will remain under DOT 

orders as long as we believe they pose a threat to life and the environment. 

II. WHAT DOT HAS DONE TO RESPOND TO THE FAILURES

 PHMSA has been on the job since the response began. When the accident occurred 

on a segment of 34” diameter above ground pipeline in the Western Operating Area 

referred to as OT21 on March 2, we offered our assistance on cleanup to the Unified 

Command conducting the response operation, under leadership of the Environmental 

Protection Agency (EPA). Shortly thereafter, PHMSA notified EPA, the Department of 

the Interior, and state agencies, as well as the Joint Pipeline Office (JPO), of our intent to 

exercise statutory jurisdiction over these three transit lines by issuing a Corrective Action 

Order (CAO) and bring them under the regulatory authority of the DOT, essentially 
507

taking the Federal oversight role in the remediation and repair of the failed line. Our 

order covered the Western Operating Area line, which failed in March, as well as the 

Eastern Operating Area and the Lisburne lines, a total of 22 miles. Our mission is and 

remains ascertaining the condition of these lines, understanding the failure mechanisms, 

and assuring that the operator takes all needed action to keep them operating safely in the 

future. 

 Our Corrective Action Order started with the fundamentals of requiring BP 

Exploration Alaska, Inc. (BPXA) to determine the condition of its pipelines and to repair 

defects. First, we ordered BPXA to run what are known as cleaning or maintenance pigs 

in order to remove solids in the line and to perform in-line inspections, known as smart 

pigging, in order to understand the pipe condition from the inside out. Second, we 

directed more frequent testing, and an enhanced corrosion management plan, including 

changing the mix of corrosion inhibitors to improve corrosion prevention. We required 

running cleaning pigs on a routine basis to remove water and other constituents that could 

contribute to internal corrosion. Third, we set standards for assuring integrity of each of 

BPXA’s low stress pipelines in service. Fourth, we dispatched the first of many 

inspection teams to inspect the pipe that failed, assess the cause of failure, review 

operations and maintenance records, monitor operations, including testing, inspect 

repairs, and verify compliance with our requirements. Our inspection indicated the 

probable cause of the failure on March 2 to be internal corrosion. According to records 

provided by BPXA to the agency, the line that failed had been operating at a very low 

pressure, well below the 20 percent of designed yield strength that would have been the 

threshold for DOT regulation. BPXA’s records indicate that this pipeline was designed 

to operate at approximately 825 psi and BPXA was operating it at about 80 psi. Most of 

the line is above ground on vertical and horizontal supports. The pipeline is bare steel 

pipe, covered with thermal insulation, surrounded with a steel jacket. The pipeline had 

been hydrostatically tested in 1977, and was internally inspected with a smart pig in 1990 

and 1998. We found no history of previous failure. A leak detection system was installed 

and working but did not sound during the leak. 

 Until recently, BPXA has not moved as swiftly as we would have expected to 

comply with key requirements of our orders – namely, the requirements to clean and 

smart pig its low stress lines. We provided an extension in March to allow BPXA to 

collect more information, and a second extension in April, pushing the first deadline to 

June 12, 2006, more than three months after the spill. Soon after we issued the order, 

BPXA advised PHMSA that it would not be able to comply with the requirements to 

“smart pig” the lines within the specified time period, the critical step in meeting our 

objective of having the best possible understanding of the condition of the pipelines. 

 On May 23, PHMSA dispatched a more comprehensive field investigative team to 

evaluate all potential integrity threats to the transit lines along with BPXA programs to 

mitigate those threats. The team reviewed BPXA’s overall program to manage the transit 

lines, assessed findings emerging from the monitoring plan, reviewed inspection records, 

observed testing procedures used on the transit lines, toured all facilities, interviewed 

technicians, reviewed qualifications of personnel, inspected test records, and reviewed 

the leak detection system. The team suggested improvements for BPXA’s Interim 

Monitoring Strategy such as increased corrosion monitoring points to reduce the potential 

that vulnerable locations not be overlooked. PHMSA directed BPXA to increase the 

inspection frequency to provide an early warning of any unanticipated corrosion 

acceleration. We directed that more stringent repair thresholds be incorporated in the 

program and asked that communications be improved between analysts and field teams. 

We also required improved patrolling of the lines. Since the May field inspection, we 

have maintained a field oversight presence at all times to ensure the operator was taking 

the actions necessary to maintain safety. 
508

 Based on our analysis to date, we believe that internal corrosion, induced by 

microbial activity, caused the pipe to deteriorate at the point where it failed on March 2 – 

a low section in a caribou crossing. Typically, operators control this type of corrosion 

through a combination of cleaning pigs and biocide injections. The cleaning pig is 

usually necessary to deliver the biocide to the pipe wall and to disperse active bacteria 

colonies. 

 We do not understand why BPXA did not address these problems more aggressively 

much earlier. BPXA could have used cleaning pigs to clean out liquids accumulating in 

low spots within its low stress pipelines. Further, there is a high likelihood that cleaning 

pigs would have improved the effectiveness of the biocide or corrosion inhibitor by 

getting the chemicals to the wall of pipeline without the interference of solids and other 

deposits. Given the many risk factors in the North Slope environment, including use of 

water in the production process, the chemistry of the crude oil product itself, and the 

varied geologic factors in the production field, it is very puzzling that BP did not choose 

to run cleaning pigs. From information provided by companies who operate in less 

challenging environments in response to the public meetings held in conjunction with the 

rulemaking for low stress pipelines, we believe most operators demonstrate a higher 

standard of care in their operations, regardless of whether they are federally regulated or 

not. 

 On June 6, BPXA sought a further extension of the deadlines for the pigging, 

contending that factors beyond their control would make it impossible to complete the 

required pigging until the latter half of 2007. They proposed an alternative plan they 

claimed would provide safety equal to what could be accomplished with a smart pig until 

the three transit lines could be smart pigged. We denied the requested extension but 

issued an order making clear to BP that we were not requiring it to shut down its 

operations on the basis of its failure to meet the pigging deadlines. We had preliminarily 

reviewed the alternative test procedures and the testing data furnished by BPXA, and did 

not believe that a shutdown was required for safety. Our order expressly reserved all 

other enforcement options with respect to BP’s failure to comply with the deadlines. 

 PHMSA engineers were very concerned about the primary reason BPXA gave for its 

alleged inability to complete pigging -- build up of solids, including impurities in the 

product stream such as waxes and other materials. Alyeska, the operator of the TransAlaska Pipeline (TAPS), had notified PHMSA about its concerns with adverse impact on 

its pipeline if these solids should be allowed to pass through from BPXA to TAPS. The 

Joint Pipeline Office (JPO), which coordinates TAPS issues, had concerns as well, and 

ensuring the continued safe operation of TAPS is a primary concern of PHMSA. 

 To address those concerns, PHMSA needed to understand the amount, composition 

and density of this “sludge” material and how it would be handled before we could allow 

BPXA to proceed with pigging to be sure that BPXA operations could pose no risk to the 

safety and reliability of the Trans-Alaska Pipeline System. Alyeska needed to be certain 

about its ability to handle the waste. BPXA put forward preliminary estimates of as 

much as 12 inches of sludge, with varying amounts in different segments of its 22 miles 

of transit lines. After several weeks, BP revised its estimate of the amounts of sludge in 

the lines downward. PHMSA still does not have a confident estimate of the amount of 

sludge in the line segments that have not yet been pigged. BPXA also took months to 

develop plans to handle the removal of sludge. Based on a conclusion that there was 

limited sludge in the Lisburne line, BPXA pigged that line in June. 

 Because of the delay in resolving this and other issues, in early July, my Chief 

Safety Officer, Ms. Stacey Gerard, and my Western Regional Director, Mr. Chris Hoidal, 

and I traveled to Prudhoe Bay and Anchorage to meet with BPXA and Alyeska 

executives, JPO officials and State of Alaska representatives and to see first hand what 

BPXA was doing to comply with our order and to overcome any engineering or other 

issues that would complicate or delay maintenance and smart pigging required on each of 
509

the lines. Our assessment was that BPXA was not pursuing all available options for 

handling the sludge and preparing for pigging. We were concerned they were exploring a 

single option, one at a time, rather than considering multiple options, and not working or 

communicating effectively. I was dismayed at the slow rate of progress and observed 

difficulty in problem solving, poor communications, delay in ordering needed parts and 

equipment, and failure to take actions necessary to ascertain fully the condition of the 

pipelines and to address the conditions uncovered. 

 For example, BPXA told us in May of the need to order valves and stopples to 

isolate a certain section of the failed pipeline and the need to move the pig launcher 

around the failed site. Two months later, during our July visit, we learned that some parts 

were still not ordered. It is still not clear to us that it was impossible to make plans to 

remove the solids and begin pigging operations by the June 12 deadline in our order. 

 Subsequent to this visit, on July 20, we issued an amendment (Amendment Number 

One) to our original order intended to address these deficiencies by mandating that 

BPXA develop specific plans and timetables or parallel tactics to expedite pigging 

operations on lines that had not yet been cleaned. We required development of 

preliminary engineering design and an implementation plan to install a permanent facility 

for handling solids resulting from cleaning pig operations plus a concurrent contingency 

plan for a bypass around TAPS Pump Station (PS)-1 facilities so solids could be 

delivered into storage. This action would assure that sediment in the product stream 

picked up in pigging would be safely managed in tanks to avoid contamination and 

maintain the safety of TAPS. We required a comprehensive engineering plan for the 

draining or “de-oiling” of approximately 17,000 barrels of oil contained in the idled 

OT21 line segment that failed in March. We also ordered the taking of wall samples and 

gamma ray photography post pigging to gain the best possible understanding of the real 

time levels of remaining solids. 

 By the end of July, BPXA was finally making progress to address our safety 

concerns and to restore reliable energy transportation service. I am pleased to report that 

as a result of these orders extracting product from the OT 21 segment of line was 

completed in late August. The PS-1 bypass – aimed at delivering solids from the WOA 

line through the use of a bypass line into TAPS storage tanks was successfully hydrotested in early September and that an alternate bypass, “the Fizzy Bypass,” will be 

completed at the end of September. All these steps are necessary to get us to our goal of 

understanding the condition of these pipelines and making sure the operator is doing all 

that is needed to operate them safely. 

 In our observation however, progress has also been impaired by operator error on 

the startup of the production line damaged by falling equipment near the Lisburne line, 

and failure to maintain backup compressors. Discovery of asbestos on the WOA and 

BP’s need to provide worker protection delayed testing on the WOA. While these 

missteps may not appear to have a direct bearing on the low-stress line corrosion issues, 

failure to understand and manage change in operations always poses safety risks. 

 On July 22, 2006, 37 days after the deadline established in our March order, BPXA 

performed the smart pigging ordered by PHMSA on the 30 inch segment of the FS2-FS1 

Eastern Operation Area pipeline. BP informed us of the results of the testing on August 

4. The report identified 16 locations of wall loss in excess of 70 percent, including two 

over 80 percent, at 12 separate areas. While the failure on the Western line occurred on a 

low spot in a caribou crossing, the locations of severe wall loss on the Eastern line were 

on straight pipe. 

 On August 6, BPXA reported that it discovered a leak while in the process of 

performing direct examination of the EOA as a follow-up to the pig inspection. On the 

basis of this leak and the discovery of several other locations that were beginning to leak, 

BPXA initially reported to us its decision to shut down this and the Western line. BPXA 

explained that its decision was based on a complete lack of understanding of the 
510

corrosion that could cause this type of wall loss. BPXA subsequently decided to keep the 

Western line operating and to consider restarting the 34” segment of the Eastern line. 

 In response to this second spill on the Eastern line, PHMSA issued a second 

amendment to its order (Amendment Number Two) requiring additional rigorous, 

automated ultrasonic inspections on a continuous basis of the company’s entire North 

Slope pipeline network and outlining the standards BPXA would need to meet to restart 

its pipeline. Prior to completion of smart pigging, we need to have the best possible 

factual information about the condition of the pipelines. The order required the conduct 

of four daily ground patrols using heat-seeking infrared equipment to spot leaks along the 

entire length of the 22 miles of oil transit lines. The order required continuous automated 

ultrasonic testing on the outside of the operating portion of the Western line, including 

the stripping of the insulation to apply the instrument directly to the pipeline. This 

technology is producing promising results. The order also required the de-oiling of the 

failed segment of the Eastern line and specified the testing that would be needed on the 

Eastern line until it could be smart pigged, and as a condition of smart pigging. 

 In addition to imposing new requirements for BPXA, PHMSA further stepped up its 

presence in Alaska to respond to new threats presented by the August 6 failure. Our first 

concern was the impact of transit line shutdown on the Trans-Alaska Pipeline System. 

Reduced product flow from the BPXA transit lines could cause new safety risks to the 

TAPS pipeline. The hydraulics of the pipeline is set to operate at a certain threshold of 

product flow. It was necessary to determine whether the operation could be adjusted to a 

lower level flow. A reduced level of flow can cause vibrations to occur over certain high 

elevation passes, causing PHMSA to question whether it would be necessary to monitor 

strain. Long-term reduced flow rate could also cause an environment more susceptible to 

internal corrosion. We have determined that Alyeska can adjust the hydraulics to operate 

at a lower flow rate, that it is monitoring the strain caused by vibrations, and that it has an 

aggressive cleaning pig program to minimize internal corrosion. 

 Given the impact of the BPXA line shut down, we were concerned about any 

immediate risk that could lead to a shutdown on any of the other feeder lines to TAPS. 

We therefore deployed a team to update our knowledge of the risks to these other 

pipelines, including those at the Kuparuk, Alpine, Badami, North Star, Oliktok and Milne 

Point fields. We were particularly concerned about a nine-mile section of non-piggable 

line on Kuparuk. While we have some long-term integrity management concerns, no 

immediate concerns were detected. 

 We are working with BPXA on its plan to restart the 34” diameter section of the 

Eastern line (the line with extensive corrosion discovered in August) and the conditions it 

would need to meet to satisfy our safety concerns. Given that BPXA was not able to 

sufficiently explain the causes of the corrosion on the Eastern line, and the potential 

extent of damage to the pipe wall, PHMSA has required that BPXA demonstrate that the 

Eastern line is in safe condition for pigging operation. PHMSA needs to be sure that the 

wall condition is satisfactory to return flow to the line and pass a smart pig through it, 

without causing another failure. On August 29, PHMSA provided very detailed written 

guidance to BPXA as to how it must demonstrate the Eastern line’s integrity prior to 

commencing pigging operations and make appropriate arrangements for spill 

contingencies. PHMSA will not authorize restart until we have analyzed adequate data 

without undue reliance on the results of data collected on the in-service segment of the 

Western line. 

 Given recent progress with the terms of the amendments to our CAO, we are 

hopeful that smart pigging of the 60 percent of the 22 miles of low stress pipelines that 

have not been tested will be started later this fall. 
511

 PHMSA will maintain the high level of oversight needed to enforce compliance. 

III. DOT’S REGULATION OF LOW STRESS LINES

 The BXPA lines that failed on the North Slope were unregulated by DOT/PHMSA. 

On August 31, PHMSA proposed new safety requirements that would bring these lines 

under regulation. Our proposed rule applies to facility operators of hazardous liquid 

gathering and low stress pipelines in rural areas. We already regulated low stress lines in 

populated areas and crossing commercially navigable waterways. 

 We have taken a risk-based approach – we intend to protect all lines that, in the 

event of a failure, could spill into an unusually sensitive area, or USA, a term we have 

already defined in our regulations. We have determined these to be low stress lines 

within a 1⁄4 mile of a USA and of a diameter of 8 5/8 inches or more. Our assessment of 

which lines to regulate is based on how they can impact a USA, based on the pressure of 

the line and the volume of product that could be spilled. Based on data provided to us by 

operators of rural low-stress pipelines, spills from these types of lines have not traveled 

beyond a quarter of a mile from the pipelines, and three quarters of those spills have 

traveled no more than about 100 feet. 

 The proposal addresses the need to provide additional and robust integrity protection 

to areas where oil pipelines in rural areas could affect drinking water resources, 

endangered species and other ecological resource concerns. This proposed rule will 

enhance corrosion protection by including cleaning and continuous monitoring, integrity 

assessment, and leak detection. It would require operators of these lines to follow safety 

rules for design, construction, testing, and maximum operating pressure. In addition, the 

proposal would require operators to protect the lines from corrosion and excavation 

damage, install and maintain line markers, establish operator qualification and damage 

prevention programs, provide public education, and report accidents and safety-related 

conditions. 

 Most low stress lines in the lower 48 States of the U.S. bear little resemblance in 

their diameter to the low stress lines that BPXA operates on the North Slope. Most of the 

lines in the lower 48 States are very short in length and small in diameter. We believe 

that most operators of unregulated crude oil low stress lines have programs in place to 

regularly clean and test their pipelines. We believe the regulation we have proposed will 
512

better protect rural environmental areas. We have asked a number of questions in the 

notice of proposed rulemaking to get the best possible information to complete the 

proposal, including whether we should extend protections beyond the 1⁄4 mile area, 

whether if we should require all unregulated lines to report spills, and whether 

implementation time frames are appropriate, and other questions. We can modify the 

regulatory proposal as needed based on the information that becomes available on the 

docket. 

IV. THE U.S. PIPELINE INFRASTRUCTURE IS SOUND

 As unfortunate as the recent Alaska incidents are, they are not a bellwether for the 

health of the majority of the energy pipeline infrastructure. It is in much better shape. 

PHMSA has designed and is implementing a strong risk-based systems approach to 

ensure the safety and reliability of our nation’s energy pipeline infrastructure. Our 

regulation is having positive results. The number of serious incidents in which people or 

the environment are harmed is steadily declining, particularly on oil pipelines. 

Serious Pipeline Incidents

(Incidents involving death or injury, 1986-2005)

0

20

40

60

80

100

1986 1988 1990 1992 1994 1996 1998 2000 2002 2004

Trendline

Source: DOT/PHMSA Incident Data

 Our data shows the integrity management program on hazardous liquid pipelines is 

working. Comparing the five year periods before and after integrity management 

programs were implemented on hazardous liquid pipelines, spill frequency dropped 18 

percent and volumes spilled dropped 35 percent. 
513

Hazardous Liquid Pipeline Accidents (1996-2005)

 Before/After Implementation of Integrity Management

(Adjusted for comparability in reporting criteria over time)

0

50

100

150

200

250

1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Source: DOT/PHMSA Incident Data

5-yr average before Integrity 

Management = 141/yr. 5-yr average after Integrity 

Management = 115/yr.

Hazardous Liquid Pipeline Spills

Amount Spilled, in Barrels (1986-2005)

(Adjusted, spills of 50 barrels or more)

0

50,000

100,000

150,000

200,000

250,000

1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Source: DOT/PHMSA Incident Data

5-yr average before Integrity 

Management = 156,000 bbls/yr

5-yr average after Integrity 

Management = 99,000 bbls/yr

 The leading causes of failure on hazardous liquid transmission pipelines are down 

nearly 50 percent since the integrity management programs were put in place in 2000. 

 Operators have a better understanding of the condition of their pipelines and the 

pipelines are in better condition. Safety programs are improving to sustain improved 

performance in the future. PHMSA closely monitors operator-specific performance and 

flags companies whose performance is falling for more intense oversight and inspection. 

We had flagged BP as one of those companies, prior to the accident in March. We have 

several enforcement actions in place against BPXA affiliate BP Pipelines (Alaska) Inc. 
514

for shortcomings in its integrity management on regulated lines in Alaska. We have 

taken actions in recent years against BP North America for compliance issues in the 

lower 48 States. We intervene with operator executives to prevent accidents, usually 

before they happen, not just respond after the fact, and make full use of all our 

enforcement options, including civil penalties at the higher level authorized under the 

Pipeline Safety Act of 2002. 

V. LET’S NOT LOSE SIGHT OF THE MOST PRESSING SAFETY 

PROBLEM

 In the past few years, PHMSA has taken a hard look at incidents, their causes and 

what can be done to prevent them. One thing is clear-the leading cause of incidents (42 

percent of total) in which people are hurt or killed is construction-related damage causing 

an immediate rupture or damage that later grows to failure. This occurs most often on the 

distribution systems that run through the neighborhoods where people live and work. 

Gas Distribution Incidents (1996-2005)

By Major Cause

Corrosion (3%)

Material Failure

(5%)

Human Error 

(5%)

Other outside 

Force Damage 

(7%)

Other (24%)

Natural Force 

Damage (14%)

Excavation 

Damage

(42%)

Source:

DOT/PHMSA

Incident Data

 Unfortunately, since 1996, incidents of construction-related damages on distribution 

systems have clearly increased as much as 49 percent, and this in areas where people are 

most likely to be hurt. 
515

Gas Distribution Incidents

Caused by Excavation Damage

(1996-2005)

0

10

20

30

40

50

60

70

80

1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Source: DOT/PHMSA Incident Data

Trendline

 This part of the pipeline system, the distribution network, is almost entirely under 

the jurisdiction of States, our foremost partners in pipeline safety. These incidents are 

almost entirely preventable. We need to help States do more, and we need new authority 

to make this happen. 

 The Secretary of Transportation recently submitted to Congress the Administration’s 

legislative proposal to reauthorize and improve pipeline safety and protection for the 

environment, and also to enhance infrastructure reliability. The proposal, the “Pipeline 

Safety and Reliability Improvement Act of 2006” aims to build on our progress in 

achieving the mandates of the 2002 Act by placing more emphasis on damage prevention 

and enhancing state programs’ oversight of pipelines. 

 Our progress on completing recent and past mandates and recommendations is 

attached. 

 These reauthorization concepts have been generally supported across our 

stakeholder community, including the Federal and State family, and we are pleased to see 

many of the same priorities reflected in the Committee’s proposal.

VI. Conclusion

 I assure the members of this Subcommittee, that the Administration, Acting 

Secretary Cino, and the dedicated men and women of PHMSA share your strong 

commitment to improving safety, reliability, and public confidence in our Nation’s 

pipeline infrastructure. 

 Like you, we understand the importance of our mission to the safety of our citizens 

and the energy security and continued economic growth of our great Nation. 

 Thank you. 

 I would be pleased to answer any questions you may have. 

 ### 
516

 Attachments: 

 PHMSA Mandate Progress Chart 

 PHMSA Mandate Progress Graph 

 MR. BURGESS. Thank you. Without objection, your written 

statement will be submitted for the record. We will now hear from Mr. 

Fredriksson for 5 minutes. 

 MR. FREDRIKSSON. Mr. Chairman, members of the subcommittee, 

thank you for the opportunity to testify before the subcommittee 

regarding your review of BP’s recent crude oil transmission pipeline 

failures on Alaska’s North Slope. My testimony today will focus on the 

Alaska Department of Environment Conservation’s responsibilities for 

oil spill prevention and response in Alaska. 

 To begin, I want to emphasize to the subcommittee that a thorough 

fact-finding investigation of BP’s management of the North Slope oil 

field is being conducted by my department and the Alaska Department of 

Law. As part of the ongoing investigation, I have served subpoenas on 

BP and other holders of the Prudhoe Bay leases to preserve all 

documents related to this occurrence and pipeline corrosion going back 

to 1996. After the State’s investigation is complete, appropriate legal 

action will be taken to protect Alaska’s interests. 

 The mission of my department is to protect public health and the 

environment. Alaska’s legislature has provided the department with a 

very broad and comprehensive authority to carry out this mission. As the 

department’s commissioner, I have a duty to adopt and enforce 

regulations for controlling the release of pollution to Alaska’s air, land 

and water. I take very seriously the department’s duty to prevent and 

respond to the unauthorized release of oil and hazardous substances. 

 Prevention of spills is a major topic for today’s hearing. However, it 

is important that I briefly describe the department’s role in spill response. 

Under Alaska law, any person causing an oil spill must immediately 

clean up and contain the spill to the State’s satisfaction. If the 

department determines the response to a spill is not adequate, it may 

undertake the cleanup itself. The response by BP and others to the 

Gathering Center 2 and Flow Station 2 pipeline spills has been 

exemplary. The spills were quickly contained, oil removed, damage to 

health and wildlife prevented and impact to the environment minimized. 

The Alaska Department of Environmental Conservation is also 

authorized to adopt and enforce spill prevention regulations for pipelines. 

Since 1992, the department has enforced regulatory leak detection 

requirements on crude oil transmission lines. There are currently no 

State corrosion control requirements for crude oil transmission lines. At 

this time there are also no State regulatory requirements for corrosion 
517

control or leak detection on flow lines. However, that is about to change 

as I will describe later in my testimony. 

 In the late 1990s, discussions between the State of Alaska, BP and 

ARCO as part of the BP-ARCO merger led to a charter agreement for 

development of the Alaskan North Slope that included several 

environmental commitments, one of which addressed pipeline corrosion. 

Under the provisions of the charter agreement, BP committed to report 

annually to my department on their current and projected corrosion 

monitoring, maintenance and inspection practices to assess and to 

remedy potential or actual corrosion and other structural concerns related 

to North Slope pipelines. Corrosion performance management reports 

have been submitted by BP annually since 2000. Each report has been 

independently reviewed by Coffman Engineers Incorporated, a nationally 

recognized independent engineering firm under contract with my 

department. Based on information provided by the charter agreement, 

the department joined with other governmental and non-governmental 

stakeholders in 2004 to review and update Alaska’s spill prevention 

regulations. This review led the department to propose new corrosion 

control regulations for flow lines. The State placed a high priority on 

proposing corrosion control regulations for the flow lines because they 

carry a highly corrosive mixture of oil, gas and water, they have a history 

of leaking, and because they represent the vast majority of the pipelines 

on the North Slope of Alaska. Relatively speaking, the crude oil 

transmission pipelines were considered a much lower risk. The flow line 

regulations were 2 years in the making and were ready for adoption at 

the time of the GC-2 crude oil transmission pipeline spill which occurred 

in March of this year. The department immediately considered adding 

crude oil transmission lines to the regulatory package at the time of the 

GC-2 spill but decided against their inclusion because it would delay 

implementation of the flow line regulations. We also wanted to complete 

the investigation into the cause of the GC-2 pipeline failure so that our 

regulations would benefit from the lessons learned from that incident. 

Although information is still being generated and investigations such as 

this hearing are ongoing for the GC-2 and FS-2 incidents, it is apparent 

that the current corrosion management programs for crude oil 

transmission lines should be revised and expanded so as to be able to 

detect the effects of previously unrecognized corrosion mechanisms that 

could adversely impact the future safe operation of the infrastructure on 

the North Slope. A separate State regulatory proposal for crude oil 

transmission lines remains under consideration pending further review of 

the actions recently proposed by the U.S. Department of Transportation’s 

Pipeline and Hazardous Materials Safety Administration. 
518

 Pipeline corrosion issues are technically complex and the State’s 

resources must be matched to the appropriate level of oversight. 

Following the GC-2 spill in March of this year, the Alaska Department 

of Environmental Conservation created an interagency Arctic Pipeline 

Technology Team with the Alaska Department of Natural Resources and 

the Alaska Oil and Gas Conservation Commission to coordinate the 

State’s oversight of North Slope pipeline integrity. The Pipeline 

Technology Team is planning to hold a pipeline integrity conference in 

Alaska this winter to examine the latest pigging technology and best 

practices for corrosion management, monitoring and inspection for 

pipelines in Arctic climates. 

 To summarize, BP has accepted responsibility for correcting their 

pipeline failure and the governor has directed the Department of Law and 

my department to ensure that they are held accountable. Once 

discovered, the spills were contained and cleaned up with minimal 

environmental damage. Some of the best industry and government 

engineering experts are working the problems. The defective pipelines 

will be replaced. The State flow line regulations are expected to be in 

effect by the end of the calendar year, and we will be reviewing the 

rulemaking proposed by the Pipeline and Hazardous Materials Safety 

Administration to determine what additional actions the State should 

take. 

 Thank you for the opportunity to testify before the subcommittee. I 

would be happy to answer any questions. 

 [The prepared statement of Kurt Fredriksson follows:] 

PREPARED STATEMENT OF KURT FREDRIKSSON, COMMISSIONER, ALASKA DEPARTMENT OF 

ENVIRONMENTAL CONSERVATION

 Good morning. My name is Kurt Fredriksson, and I am the Commissioner of the 

Alaska Department of Environmental Conservation (ADEC). Thank you for the 

opportunity to testify before the Subcommittee regarding your review of BP’s recent 

crude oil transmission pipeline failures on Alaska’s North Slope. 

 Hearings like this should provide assurances to the people of the United States that 

Congress and the State of Alaska are diligent and vigilant in overseeing the responsible 

development of Alaska’s important natural gas and oil resources. 

 My testimony today will focus on the Alaska Department of Environmental 

Conservation’s responsibilities for oil spill prevention and response in Alaska. As 

requested by the Subcommittee, I will address the question of what went wrong with 

BP’s pipeline spills, and explain what I also believe went right with these events. 

 To begin I want to emphasize to the Subcommittee that a thorough fact-finding 

investigation of BP’s management of the North Slope oil field is being conducted by my 

department and Alaska’s Department of Law. As part of the ongoing investigation, I 

have served subpoenas on BP and other holders of the Prudhoe Bay leases to preserve all 

documents related to this occurrence and pipeline corrosion going back to 1996 

(enclosure 1). After the State’s investigation is complete, appropriate legal action will be 

taken to protect Alaska’s interests. 
519

 The mission of ADEC is to protect public health and the environment. Alaska’s 

legislature has provided the Department with very broad and comprehensive authority to 

carry out this mission. As the department’s Commissioner, I have a duty to adopt and 

enforce regulations for controlling the release of pollution to Alaska’s air, land, and 

water. 

 I take very seriously the department’s duty to prevent and respond to the 

unauthorized release of oil and hazardous substances. 

 Prevention of spills is a major topic for today’s hearing, however, it’s important that 

I briefly describe ADEC’s role in spill response. 

 Under Alaska law any person causing an oil spill must immediately contain and 

cleanup the spill to the satisfaction of ADEC. If ADEC determines the response to a spill 

is not adequate it may undertake cleanup itself. The spiller is also strictly liable for the 

state’s costs incurred to respond to, and oversee the cleanup. 

 The response by BP and others to the Gathering Center-2 and Flow Station-2 

pipeline spills has been exemplary. The spills were quickly contained, oil removed, 

damage to health and wildlife prevented, and impact to the environment minimized. 

 In addition to its responsibilities for spill response, ADEC is also authorized to adopt 

spill prevention regulations for pipelines. Because of the complex and sometimes 

conflicting pipeline nomenclature in use by various state and federal agencies let me start 

by clarifying ADEC pipeline regulatory terminology. 

 There are many different types of pipelines operating on the North Slope carrying 

many different types of liquids and gas for many different purposes. For purposes of this 

testimony I will focus on aboveground pipelines on the North Slope that are subject to the 

state’s spill prevention authorities (enclosure 2). Pipelines that carry crude oil, water and 

gas from the wellhead to a processing facility are called flow lines. Flow lines carry the 

most corrosive fluids and make up the majority of the pipelines on the North Slope. 

Seawater injection and produced water pipelines are included in our definition of flow 

lines. 

 Pipelines which carry crude oil from the separation facility are defined as crude oil 

transmission pipelines. These are single phase pipelines which carry crude oil that has 

been processed to remove the water and gas carried by the flow lines. 

 Since 1992, the department has enforced regulatory leak detection requirements on 

crude oil transmission lines. There are currently no state corrosion control requirements 

for crude oil transmission lines. At this time there are also no state regulatory 

requirements for corrosion control or leak detection on flow lines. However, that is about 

to change as I will describe later in my testimony. 

 The original Plan of Development for the Prudhoe Bay reservoir projected a 42% 

recovery of crude oil or approximately 9.6 billion barrels. Based on these estimates 

Prudhoe Bay was not expected to be producing oil after 1997. Fortunately, 

advancements in oil field recovery technology extended the life of the Prudhoe Bay field. 

In the late 1990’s discussions between the State of Alaska, BP and ARCO as a part of the 

BP/ARCO merger, led to a “Charter Agreement” for development of the Alaskan North 

Slope that included several environmental commitments (enclosure 3). 

 With extended crude oil production from Prudhoe for another generation in mind, 

the State negotiated seven environmental commitments in the Charter Agreement with 

the Prudhoe Bay operators including a specific commitment concerning corrosion that 

specifies; 

BP and ARCO will, in consultation with ADEC, develop a performance 

management program for the regular review of BP’s and ARCO’s corrosion 

monitoring and related practices for non-common carrier North Slope pipelines 

operated by BP or ARCO. This program will include meet and confer working 

sessions between BP, ARCO and ADEC, scheduled on average twice per year, 
520

reports by BP and ARCO of their current and projected monitoring, maintenance 

and inspection practices to assess and to remedy potential or actual corrosion and 

other structural concerns related to these lines, and ongoing consultation with 

ADEC regarding environmental control technologies and management practices. 

 Corrosion performance management reports have been submitted annually since 

2000 and are independently reviewed and audited by a nationally recognized independent 

engineering firm. The reports are technically oriented, and intended to ensure a corrosion 

management program is in place for the life of the North Slope oil fields. The annual 

reports are available on the department’s website at: 

www.dec.state.ak.us/spar/ipp/corrosion/index.htm. 

 The engineering review process and reporting metrics for the annual reports were 

developed during the first year of the agreement to promote the free exchange of 

engineering viewpoints through report drafts, meet and confer sessions, and technical 

meetings to clarify questions, agree on metrics for reporting, review the application of 

various engineering standards, and analyze a host of complex technical matters. The 

process allows all parties to offer their judgment and criticism and opposing viewpoints. 

 Based on information provided by the Charter Agreement, the department joined 

with other governmental and non governmental stakeholders in 2004 to review and 

update Alaska’s spill prevention regulations. This review led the department to propose 

new corrosion control regulations for flow lines. 

 The rationale and documented basis of need for regulating flow lines is described in 

the summary document for the rule making (enclosure 4). In essence, state corrosion 

control regulations were developed for the flow lines first because they carry a highly 

corrosive mixture of oil, gas and water; because they have a history of leaking; and 

because they represent the vast majority of the pipelines on the North Slope of Alaska. 

Relatively speaking, the crude oil transmission pipelines were considered a much lower 

risk. The flow line regulations were two years in the making and were ready for adoption 

at the time that the GC-2 crude oil transmission pipeline spill occurred in March. The 

department immediately considered adding crude oil transmission lines to the regulatory 

package at the time of the spill but decided against their inclusion because the additional 

time required to re-public notice and conduct a hearing would unnecessarily delay 

implementation of the flow line regulations which were otherwise ready for adoption. 

We also wanted to complete the investigation into the cause of the GC-2 pipeline failure 

so that our regulations would benefit from the lessons learned from that incident. A 

separate state regulatory proposal for crude oil transmission lines remains under 

consideration pending further review of the actions recently proposed by the U.S. 

Department of Transportations Pipeline and Hazardous Materials Safety Administration. 

 Although information is still being generated and investigations are ongoing for the 

GC-2 and FS-2 incidents, it is apparent that the current corrosion management programs 

for crude oil transmission lines should be revised and expanded so as to be able to detect 

the effects of previously unrecognized corrosion mechanisms that could adversely impact 

the future safe operation of the infrastructure on the North Slope. 

 Pipeline corrosion issues are technically complex and the state’s resources must be 

matched to the appropriate level of oversight. Following the GC-2 spill in March of this 

year, ADEC joined the Alaska Department of Natural Resources, and the Alaska Oil and 

Gas Conservation Commission in creating an interagency Arctic Pipeline Technology 

Team to coordinate the state’s pipeline integrity oversight. The purpose and structure of 

the team is described in the Memorandum of Agreement between the three agencies 

(enclosure 5). Funding for the team leader, agency support costs, and technical 

consulting assistance is provided under the Charter Agreement. In addition, the 

department has directed $500,000 from the Charter Agreement be invested in a Pipeline 

Integrity Conference held in Alaska this winter to examine the latest technology and best 
521

practices for corrosion management, monitoring and inspection, and leak detection for 

pipelines in arctic climates. 

 To summarize, BP has accepted responsibility for correcting their pipeline failure 

and the Governor has directed the Department of Law and my department to ensure they 

are held accountable. Once discovered, the spills were contained and cleaned up with 

minimal environmental damage. Some of the best industry and government engineering 

experts are working the problems. The defective pipelines will be replaced. The state 

flow line regulations are expected to be in effect by the end of the calendar year and we 

will be reviewing the rule making proposed by the Pipeline and Hazardous Materials 

Safety Administration to determine what additional actions the state should take. 

 The good news for America is that production from Prudhoe Bay did not end in 

1997 with 9.6 billion barrels. Approximately 11.3 billion barrels has now been recovered 

from Prudhoe Bay with expectations of pumping yet another 2 billion barrels. Extracting 

more oil from existing fields helps meet the nation’s energy needs. Pipes can be fixed 

and production can be restored because Prudhoe Bay is not out of oil. Lessons will be 

learned from the state and federal investigations of these pipeline failures and technical 

review by our Arctic Pipeline Technology Team. Extended production from the Prudhoe 

Bay field will continue to supply the nation’s energy needs with an enhanced level of 

safety and oversight. 

 MR. BURGESS. Thank you, Mr. Fredriksson. We will get to 

questions in just a moment. Ms. Gerard, we are willing and able to take 

your 5-minute testimony now--very well. 

 Admiral Barrett, thank you for your testimony. How would you 

describe the condition of BP’s Prudhoe Bay transmission lines at the 

time the Pipeline and Hazardous Materials Safety Administration issued 

the corrective action order in March of 2006? 

 VICE ADMIRAL BARRETT. I would say they fundamentally didn’t 

understand the condition of the lines, and if you look at our order, it was 

directed at accomplishing two things. It was clearly to understand the 

correction of the lines, ordering additional inspections to again better 

understand the actual conditions on those lines, and then directing 

appropriate safety controls, and we are still working that process 

forward, but I would say fundamentally, the condition of the lines is 

evidenced by the two leaks, one on the western side and one on the 

eastern side, and the basic underlying problems is, those conditions were 

not understood. 

 MR. BURGESS. Well, if I may ask, what explanation has BP given 

for the failure of the western operating line that resulted in the March 

2006 leak? 

 VICE ADMIRAL BARRETT. They haven’t given us a satisfactory 

explanation of the corrosion modeling on that line. As you know, the 

likely cause, although it is still being investigated, was pitting, if you 

will, or biologically induced or promoted corrosion in a low spot on the 

line, and that spot was simply not identified. The pigging--I heard some 

of the earlier testimony. That line was--that spot on that line was not 
522

picked up as a problem area and was not assessed using ultrasound or 

other means to accurately pin down that the problem existed. 

 MR. BURGESS. We heard earlier described ultrasound as being rather 

a tedious way to go about pipeline inspection. Is that correct, or can 

ultrasound be done in an expedient fashion? 

 VICE ADMIRAL BARRETT. It is an effective tool. Typically what 

happens, if you look at how the internal corrosion issues are assessed, is 

a couple of things. One is, the lines are typically swept by maintenance 

or cleaning pigs to keep the line clean, keep sludge from building up on 

the sides of the lines, allow your corrosion inhibitors to work on the side 

of the line, and once the sludge or the scale is cleaned, then you would 

want to run the cleaning, the sensor pigs down the line and get a picture, 

and the sensor pig will indicate where there are possible problems on the 

line. You might--it might show risk of wall loss to some degree, maybe 

50 percent or 20 percent or 70 percent. On the eastern lines, some spots 

it exceeded 80 percent when they ultimately ran it. But typically then 

you go out with tools like the ultrasound to get a much more accurate 

detailed picture at the sites, the specific sites where the sensor indicates 

you may have a problem. So it is not really designed to run a whole line 

but it is very effective at getting a better picture on a particular spot, 

about a 12-inch site on a line. 

 MR. BURGESS. On the eastern side, what explanation has BP given 

for the problems with the eastern operating line that caused BP to shut 

that line down in August? 

 VICE ADMIRAL BARRETT. What they said basically was they their 

corrosion modeling completely failed. They had no explanation of what 

might have caused the seeps and weeps. The inline inspection was done 

because we ordered it on that line. Once it turned up these sites, they 

went out and looked at it, but fundamentally, they had no explanation as 

to what could have caused that, and also, the lines are different. On the 

western side, it is a line with many more frequent elevation changes. On 

the eastern side, it is much more straight pipe, so to the extent they had 

an explanation on the western side that said it was a low spot, maybe 

water collected, maybe it wasn’t swept out enough, on the eastern side it 

is pretty much straight line and the same explanation would not apply, 

and what I would also add is, and I haven’t seen it and perhaps you have 

it in your records, but I have seen this discussion about 16--when that pig 

run came back, about 16 spots with significant wall loss, but if you 

looked a little broader, you would see, I think the number I saw was 

about 187 spots with wall loss approaching 50 percent. This was not an 

isolated couple of spots. This was a number of spots where you had a 

substantial problem, and frankly, they had no explanation. 
523

 MR. BURGESS. What were some of the major program weaknesses 

that the Department of Transportation found? 

 VICE ADMIRAL BARRETT. Well, I think again to walk back through 

it, fundamentally you have to understand the condition of the line both 

externally and internally from a corrosion point of view, and the 

fundamental problem was, they were simply not running cleaning pigs, 

they were not running inline inspection tools. Some of the aspects of 

their program are perfectly fine for the limited purpose. You heard 

discussion about the coupons, managing--you know, they give an 

indication of progressive wall loss. That is perfectly acceptable but it 

wouldn’t get at the type of pitting and biologically induced corrosion you 

have here. Now, the operators up there on the North Slope, the fact you 

may have biological corrosion as well as chemical corrosion is well 

known. You are injecting water into the wells, frequently seawater, so 

you get biological organisms in there and despite the production process, 

some of them can stay in your product and migrate down the line. So 

you have to manage against that risk, and BP did not have an effective 

way of doing it. And again, we are investigating and we will pin down 

as exactly as we can what went on with a view towards preventing this in 

the future, but for example, they had--they inject corrosion inhibitors. 

That would be a fairly common practice. As near as I could tell, they 

weren’t measuring the effectiveness of those corrosion inhibitors down 

the line and they were not taking into account the fact that those 

inhibitors may have been held off the pipe wall by the buildup of sludge 

as you have heard. 

 So that is a long answer, but fundamentally, some answers of their 

program were fine. Basically it was not comprehensive and it was not 

comprehensive enough to address the risks, the corrosion risks on that 

line. 

 MR. BURGESS. Well, do you think some of these problems are not 

just limited to BP but they are more of an industry-wide problem? 

 VICE ADMIRAL BARRETT. No, sir, I don’t. Frankly, the problems 

we see on these lines are not replicated elsewhere, even in Prudhoe Bay 

or elsewhere in the industry. The standard of care generally used--you 

heard Mr. Hostler from Alyeska talk earlier about the fact that they run 

maintenance pigs down the TAPS about every 14 days. Well, each line 

is different. There are different sizes. They run different products. The 

product coming out of the western--onto the western lines is different 

than the product coming out of fields on the eastern side. But typically 

up on the North Slope and generally in the industry, you would see 

maintenance pigs every couple of weeks, certainly every couple of 

months, but not never on lines of this type. 
524

 MR. BURGESS. Ms. Gerard, if I could ask you, is it true that BP has 

strongly resisted the Department of Transportation’s efforts to put all 100 

miles of its federally regulated lines in Alaska into the integrity 

management program? 

 MS. GERARD. That is certainly true. 

 MR. BURGESS. What justification did BP give for refusing to put all 

of its 100 miles of regulated pipelines in Alaska into the integrity 

management program? 

 MS. GERARD. By their risk assessment, they didn’t think that a leak 

would hurt the species that live in the area that are intended to be 

protected by law. 

 MR. BURGESS. Was there a similar justification for the effect on the 

human population? 

 MS. GERARD. There was. In that case, it was the employees of the 

company had been trained in emergency response procedures and 

therefore they didn’t need to have the benefit of the integrity and 

protection. 

 MR. BURGESS. Well, what then was the ultimate outcome when we 

had the leaks as described? 

 MS. GERARD. These lines that I am describing are 96 miles of the 

regulated high-pressure lines, not the low-stress lines, and eventually we 

had to order them to comply with the integrity management 

requirements. 

 MR. BURGESS. As a result of that, was it necessary to order anyone 

else into the integrity management program? 

 MS. GERARD. No. In fact, quite the opposite. We had originally 

estimated that about 25 percent of the high-pressure transmission miles 

would be determined to be necessarily protected by integrity 

management requirements and the actual amount the other companies 

besides BP put in was about 80 percent. 

 MR. BURGESS. Thank you. Admiral Barrett, are you satisfied with 

the pace of BP’s repairs to Prudhoe Bay transmission pipelines in the 

wake of the events in March and August? 

 VICE ADMIRAL BARRETT. Right now, BP is progressing and doing 

some of the things we thought should have been done a long time ago. 

In general terms, their actions prior to the March spill were a 

disappointment. Initially after we issued our initial order, the response 

and actions to implement that order in my view were too slow. That is 

one of the reasons I went up there in July, and right now they are doing 

things in compliance with our order and-- 

 MR. BURGESS. Have they made every conceivable effort to meet 

with the deadlines and requirements set forth in your corrective action 

order? 
525

 VICE ADMIRAL BARRETT. I wouldn’t speculate but we have 

reserved all our enforcement actions or options on that. I mean, I would 

say going back from March through today, I would say no, they were 

moving slower than I thought they could have moved, and that was one 

of the reasons we went up and met with them. 

 MR. BURGESS. And we appreciate you doing so. Now, BP filed a 

petition with PHMSA on June 6 stating it would be unable to comply 

with several of the deadlines in the corrective action order for reasons 

“outside of its control.” Do you know what some of those reasons were? 

 VICE ADMIRAL BARRETT. I don’t want to speculate, but I don’t 

accept that argument. If you look at what is going on up there now, for 

example, we have ordered them to pig the lines. The obstacle to pigging 

that BP--they had to manage the solids to Alyeska. That is a crucial 

issue. Safety of the Trans Alaska Pipeline is a major concern of mine, 

and what is going on up there now is, they are running bypass lines. You 

heard discussion of the taking bypass from skid 50 into tank 110. These 

actions are happening now. Why they couldn’t have happened months 

ago eludes me frankly. 

 MR. BURGESS. Thank you, and I appreciate your candor. I now 

recognize the Chairman of the--I am sorry--the Ranking Member of the 

full committee, Mr. Dingell. 

 MR. DINGELL. Mr. Chairman, you are most gracious. Thank you. 

 On page 20, Admiral, of your statement, I read these words: 

“PHMSA closely monitors operator-specific performance and flags 

companies whose performance is falling for more intense oversight and 

inspection. We had flagged BP as one of these companies prior to the 

accident in March. We have several enforcement actions in place against 

BPXA affiliate BP Pipelines Alaska, Inc. for shortcomings in its integrity 

management on regulated lines in Alaska.” What does that mean? What 

are you telling us? 

 VICE ADMIRAL BARRETT. Mr. Dingell, that is the same issue that 

Ms. Gerard alluded to a few minutes ago, that on the 100 other miles of 

pipeline that they have up there that are subject and have been subject to 

DOT regulation, the high-stress lines, getting all of those lines under the 

integrity management program, which we feel is essential to effective 

risk management and safety, frankly was resisted by BP right up until 

after the March spill, and so it is the type of thing that again would have 

caused us to question their commitment. We actually issued an order 

directing amendments to make them bring those lines into the full-up 

integrity management program, and subsequent to the spill in March and 

the actions we took then, they have now done so, but that went on over a 

2 or 3 year period. 

 MR. DINGELL. Ms. Gerard, do you have any comments to add? 
526

 MS. GERARD. The key safety action that they were resisting was 

pigging, smart pigging. 

 MR. DINGELL. I wanted to get to this. Admiral, Ms. Gerard, do 

these matters relate to pigging, not pigging, improper pigging or anything 

else related to that kind of action either with regard to maintenance 

pigging or with regard to the kind of pigging that you do with smart 

pigs? 

 VICE ADMIRAL BARRETT. The integrity assessment program which 

is part of the integrity management program would require them to take 

those actions, the smart pig. 

 MR. DINGELL. Ms. Gerard? 

 MS. GERARD. Specifically, smart pig. We did not specify cleaning 

pigs in the integrity management rule. 

 MR. DINGELL. Okay. We will probably be sending you a letter to 

ask for additional information on these matters. Mr. Barrett, the current 

regulations governing hazardous liquid pipelines exempt certain 

pipelines operating at low stress from DOT regulation. That is correct, is 

it not? 

 VICE ADMIRAL BARRETT. Yes, sir, they do. That is what we have 

just proposed. 

 MR. DINGELL. In fact, the lines that failed in Alaska fell under this 

exemption. Isn’t that true? 

 VICE ADMIRAL BARRETT. Yes, sir, it is. 

 MR. DINGELL. Can you explain to the committee why these lines 

were exempt from regulation? Was it a result of DOT action or 

something the Congress ordered the department to do? 

 VICE ADMIRAL BARRETT. Sir, we had been working for the 2 years 

previously to bring these lines under regulation. Frankly, our highest 

priority in the agency over the past several years was life safety, getting 

on high-stress liquid and gas lines that run in populated areas that 

threaten, you know, as you would expect, communities where people 

live, that threaten schools, that took on a higher priority within the 

agency. But clearly these low-stress lines in unusually sensitive areas 

were identified as an area that needed to be brought under regulation and 

the agency was going through the process to develop-- 

 MR. DINGELL. Admiral, as I understand this matter, your regulations 

control which pipelines are under regulation and which are not. Lowpressure pipelines are under regulation or not? 

 VICE ADMIRAL BARRETT. Certain low-pressure pipelines that run in 

populated areas and that run near navigable waters are already regulated 

and so the lines we are talking about not regulated are those that operate 

in rural areas and ones in-- 

 MR. DINGELL. Now, why were these not regulated? 
527

 VICE ADMIRAL BARRETT. Well, again, we were moving to-- 

 MR. DINGELL. Because of the regulation. So you were moving to 

adopt a regulation-- 

 VICE ADMIRAL BARRETT. Yes, sir. 

 MR. DINGELL. --which covered these rather than just putting them 

under control because you had-- 

 VICE ADMIRAL BARRETT. Yes, sir. We had to put them under 

control because we-- 

 MR. DINGELL. --to function under an existing regulation. Is that 

right? 

 VICE ADMIRAL BARRETT. That is correct, sir. 

 MR. DINGELL. Can you tell us when you would expect to complete 

that regulation? 

 VICE ADMIRAL BARRETT. Sir, we issued the regulation on the 31st 

of August as a proposed rulemaking. 

 MR. DINGELL. On the 31st of? 

 VICE ADMIRAL BARRETT. August of this year. 

 MR. DINGELL. Of this year? 

 VICE ADMIRAL BARRETT. Yes, sir. It is open for 60-day comment. 

We obviously are open to suggestions--it is a proposal--as to the scope of 

the rulemaking and the requirements that are included in it, and at the 

conclusion of that 60-day period, we will assess any comments or input 

we get and then issue a final rule. 

 MR. DINGELL. Now, Admiral, I wonder, does DOT currently 

regulate other lines in the Prudhoe Bay field? 

 VICE ADMIRAL BARRETT. Absolutely, yes, sir. 

 MR. DINGELL. Which ones? 

 VICE ADMIRAL BARRETT. We operate--we regulate all the highstress lines up there operated by BP and other operators on the field, 

about 400 miles of lines up there actually. 

 MR. DINGELL. But you don’t--do you regulate any other low-stress 

or low-pressure pipelines up there in the field? 

 VICE ADMIRAL BARRETT. Not until this rule is issued. 

 MR. DINGELL. Until the rule is issued? 

 VICE ADMIRAL BARRETT. Yes, sir. 

 MR. DINGELL. You haven’t gotten around to regulating any of them, 

have you? 

 VICE ADMIRAL BARRETT. It would be the same situation as the BP 

low-stress lines. There are other low-stress lines up there that-- 

 MR. DINGELL. Now, prior to the spill, was the department concerned 

that it didn’t have any information on the two key transit lines in 

America’s largest-producing oil field? 
528

 VICE ADMIRAL BARRETT. Yes, sir, we were, of course we would be. 

In fact, we had inspectors check the lines occasionally to make sure that 

they were being operated at low stress. In other words, if they-- 

 MR. DINGELL. Would you give us the dates on which those 

inspections took place? 

 VICE ADMIRAL BARRETT. Sir, I would be pleased to provide that for 

the record. 

 MR. DINGELL. And if you please, would you also tell us what the 

inspectors reported. 

 VICE ADMIRAL BARRETT. Absolutely. 

 MR. DINGELL. So we have an understanding of that. Now, can you 

tell us what your concerns were? 

 VICE ADMIRAL BARRETT. As indicated, and I believe there was 

some discussion earlier, these lines in order to be considered low stress 

and exempt from our oversight had to operate at less than 20 percent of 

the maximum rated strength on the line, and so if they ran above 20 

percent of the maximum rated strength, they would have come under the 

full oversight applied to high-stress lines. The western area line I believe 

was rated at about 850. It was being operated down around 80, I believe, 

but we would have had inspectors check to make sure that the line in fact 

was being operated as a low-stress as opposed to a high-stress line. 

 MR. DINGELL. Are you telling us that you need reporting and 

disclosure and maintenance authority on these lines or do you have that 

authority now? 

 VICE ADMIRAL BARRETT. We do have the authority and that is--we 

are using that authority to both-- 

 MR. DINGELL. So you don’t need any authority in these areas: 

reporting, disclosure or-- 

 VICE ADMIRAL BARRETT. No, sir. We have the authority to issue 

the regulations or to do it by order as we have done with BP over the past 

several months. 

 MR. DINGELL. Now, the department though took no action on the 

concerns that you had with regard to this field. Is that right? You had 

concerns and you had concerns enough to send inspectors out to take a 

look at the field but you didn’t take, as I gather, any regulatory action. 

Am I correct in assuming that you didn’t respond because your own--

because the absence of regulations controlling or regulating those 

pipelines were not on the books. Is that right? 

 VICE ADMIRAL BARRETT. Correct, sir. The-- 

 MR. DINGELL. All right. Now, is it safe to say that if the DOT had 

concerns with these transit lines in Prudhoe Bay, the department 

wouldn’t have been able to act on these concerns absent an accident 
529

because of the department’s own regulatory exemption. Is that a fair 

statement? 

 VICE ADMIRAL BARRETT. Yes, sir. We would have required an 

imminent hazard, which we--which took place in March with the spill, 

but under our requirements, our ability to act absent a regulatory regime 

would have required an imminent threat to safety or health and-- 

 MR. DINGELL. All right. Now, is it true that your current proposed 

rules on low-stress lines leave some 4,300 miles of low-stress lines 

completely unregulated without requirements to report accidents or to 

manage for corrosion? 

 VICE ADMIRAL BARRETT. That is--yes, sir, that is an estimate but 

the--one of the questions we asked in the rulemaking proposal was 

whether even absent a regulatory oversight, additional reporting 

requirements ought to be imposed with respect to those lines. That is one 

of-- 

 MR. DINGELL. It kind of looks to me like you may have another spill 

coming down the road at you in some of these 4,300 miles of unregulated 

line because, remember, not only do you not regulate them, but you don’t 

have reporting and you don’t have disclosure and you don’t have 

maintenance authority under your own regulations. What are you going 

to do about that? 

 VICE ADMIRAL BARRETT. A lot of these lines are overseen at the 

State level by States. They are for the most part much smaller than the 

type of lines BP is operating up here. We are talking 30- and 34-inch 

lines. Most of the lines that would fall outside the scope of our proposal 

are down below probably 16 inches at most. They are much smaller 

lines, carry less product. 

 MR. DINGELL. The line that--the two lines that you shut down were 

unregulated by you. Were they regulated by the State? 

 MR. FREDRIKSSON. Congressman Dingell, no they were not. They 

were regulated to the extent that we had leak detection on the-- 

 MR. DINGELL. Well, why are you so comfortable then that these 

lines that you are not going to regulate in this 4,300 miles are regulated 

by the States? 

 VICE ADMIRAL BARRETT. Well, we looked at the spill history on the 

lines and the risk the lines posed, and again, we are capturing lines that 

affect or could affect unusually sensitive areas, not everywhere that the 

lines run, and usually the sensitive areas, we have defined them in the 

proposal to include areas where there are threatened or endangered 

species or a community water supply-- 

 MR. DINGELL. I am curious, Admiral, which is a sensitive area and a 

line which traverses a sensitive area? 

 VICE ADMIRAL BARRETT. Again, I-- 
530

 MR. DINGELL. I think-- 

 VICE ADMIRAL BARRETT. --I want to-- 

 MR. DINGELL. --here you might have told me and BP might have 

told me that none of these lines that we are addressing today where you 

have had the accident would have been transiting across a sensitive area. 

 VICE ADMIRAL BARRETT. Well, we obviously didn’t agree with 

BP’s assessment of that and we have mapped the unusually sensitive 

areas so they can be identified. 

 MR. DINGELL. Well, I think-- 

 MR. BURGESS. The gentleman’s time has expired. 

 MR. DINGELL. I do thank you, Mr. Chairman. 

 MR. BURGESS. And I apologize to the Ranking Member of the 

subcommittee, Mr. Stupak. 

 MR. STUPAK. No problem. 

 MR. BURGESS. I should have recognized him first. I violated 

protocol, but Mr. Stupak, you are now recognized. 

 MR. STUPAK. Admiral, you said that on the eastern pipeline there, 

BP said there was 16 spots of concern. You said there is more like 187. 

 VICE ADMIRAL BARRETT. Yes, sir. I have seen the report. There 

were 16 very serious spots where there was wall loss, in some cases up 

over 80 percent, but if you are looking at the risk profile there, we would 

be looking at wall losses in locations where you might have only seen it, 

say, down at 50 percent, might not require--it might not be as serious but 

it is still indicating a problem. 

 MR. STUPAK. Well, you said you had seen the report. Do you know 

the date of that report? 

 VICE ADMIRAL BARRETT. I can get that information and provide it 

for the record. 

 MR. STUPAK. Was it this year? 

 VICE ADMIRAL BARRETT. It is the result of the pigging--it is a result 

of the ILI, the pig run. 

 MR. STUPAK. That has been done after the-- 

 VICE ADMIRAL BARRETT. And the follow-up ultrasounds based on 

the areas identified, but we could certainly provide that for you. 

 MR. STUPAK. When did Department of Transportation first learn 

that major solids, amounts that could not easily be pigged, were in the 

eastern operating area line, and so when does--when did you first learn 

that? Again, this year? 

 VICE ADMIRAL BARRETT. It would have been this year after the 

spill when we put inspection teams up on the lines, and we spoke also 

with Alyeska Pipeline. There were concerns, significant concerns, and I 

actually went out and looked at Alyeska and met with them to discuss 

that, but it would have been subsequent to the March spill 
531

 MR. STUPAK. Do you have any idea--or when do you believe that 

BP would have learned of this blockage? 

 VICE ADMIRAL BARRETT. I can’t speak to when they would have 

learned. I can provide you exactly when they would have identified the 

issue to us, which would probably have been back in late March or early 

April. 

 MR. STUPAK. When should they have learned of the blockage? 

 VICE ADMIRAL BARRETT. Again, our assessment was they should 

have been regularly maintenance pigging the lines to prevent that from 

coming up. 

 MR. STUPAK. And they didn’t regularly pig the lines, so you and 

Ms. Gerard were talking about they resisted the integrity management 

program over a period of 2 to 3 years? 

 VICE ADMIRAL BARRETT. Yes, sir. 

 MR. STUPAK. And when I say “they” I mean BP. Well, who would 

enforce the integrity management program? 

 VICE ADMIRAL BARRETT. We would, and we issued orders to BP to 

ensure that they brought that program to bear. 

 MR. STUPAK. So for 2 to 3 years, was it a negotiation with BP then? 

I mean, I just can’t understand why DOT would not just say hey, look, 

we have been going at this for a year, let us just put forth an enforcement 

rule. 

 VICE ADMIRAL BARRETT. We did, but it is a little more complicated 

in the sense that they would have--once you bring them in, they would 

have to bring forward with that a plan to assess the condition of the lines, 

but, you know, I can’t speak to all the decisions there, maybe Ms. Gerard 

can, but from my point of view, it probably took too long. 

 MR. STUPAK. Well, did they ever bring forth a plan to check this 

line then? 

 VICE ADMIRAL BARRETT. Eventually they did but as I-- 

 MR. STUPAK. When was that? 

 VICE ADMIRAL BARRETT. It was after the March spill. 

 MR. STUPAK. Everything seems to be after March. 

 VICE ADMIRAL BARRETT. Yes. Maybe Ms. Gerard, do you have 

any amplifying data there? We can provide the data we have-- 

 MR. STUPAK. Go ahead, Ms. Gerard. 

 MS. GERARD. Just to clarify, the initial enforcement action is called 

a notice of amendment, which is an enforcement tool used to make the 

company modify their plans. They are entitled to due process and 

hearings and-- 

 MR. STUPAK. Sure. 

 MS. GERARD. --they brought forth information arguing with us 

about the fact that they couldn’t possibly affect the threatened 
532

endangered species and so we went back and forth for a while until we 

said enough is enough, we are ordering you, directing you, used a 

tougher tool, order directing amendment. 

 MR. STUPAK. So when was that order directing amendment? Any 

idea? 

 MS. GERARD. April. 

 MR. STUPAK. After March. Okay. So if you have to go through this 

and the State, right, Mr. Fredriksson, doesn’t have any enforcement on 

this risk management program? 

 MR. FREDRIKSSON. That is correct, Congressman Stupak. Our 

authority is over leak detection and the actual spill itself. 

 MR. STUPAK. Mr. Fredriksson, let me ask you this. In 2001, were 

you, Commissioner Michelle Brown and Larry Dietrich warned by your 

staff that BP’s pipeline leak detection system had been out of compliance 

since 1997? 

 MR. FREDRIKSSON. No, sir. 

 MR. STUPAK. In 2001, did BP request a waiver from your 

department to avoid installing leak detection systems on the Prudhoe Bay 

pipelines? 

 MR. FREDRIKSSON. Not that I am aware of, no, sir. 

 MR. STUPAK. In 2001, did your department staff recommend 

enforcement against BP for failure to install the required leak detection 

system? 

 MR. FREDRIKSSON. I would have to check the records on that, 

Congressman Stupak. I do recall there was an incident that did fall 

within the leak detection, not moving forward on that. We took action to 

ensure that that moved ahead expeditiously. We took enforcement-- 

 MR. STUPAK. Well, that was all 2001, so what did you do to make 

sure it moved forward expeditiously? 

 MR. FREDRIKSSON. It is my understanding that--I would have to 

check the records. I just can’t speak to it in absolute terms. But I do 

know the leak detection system was put in place and tested and-- 

 MR. STUPAK. Do you know when leak-- 

 MR. FREDRIKSSON. I don’t have the date, no. 

 MR. STUPAK. Before the spills though, right? 

 MR. FREDRIKSSON. Before the spills. 

 MR. STUPAK. And how come it didn’t work if it was put in place 

and tested and everything? How come it didn’t work? 

 MR. FREDRIKSSON. Congressman Stupak, the State’s leak detection 

requirement is 1 percent of the throughout in a 24-hour period. This 

flow, this leak from this particular incident on GC-2 was too small to 

trigger an alarm with that leak detection sensitivity. 
533

 MR. STUPAK. Well, if you remember that, then let me go back and 

ask you the first couple questions. Were you, Commissioner Michelle 

Brown or Larry Dietrich warned by your staff that BP pipeline leak 

detection systems had been out of compliance since 1997? 

 MR. FREDRIKSSON. I don’t have any recollection that those specific-

- 

 MR. STUPAK. But if someone told us that or reported that to this 

committee, you wouldn’t be surprised or you couldn’t dispute it, could 

you? 

 MR. FREDRIKSSON. I would be surprised to learn that the department 

management had been warned that BP was out of compliance for--I 

believe that is a 4-year period. 

 MR. STUPAK. Right, and did--my second question that you didn’t 

have any knowledge of, let me ask you again. Did BP request a waiver 

from your department to avoid installing leak detection systems on the 

Prudhoe Bay pipelines? 

 MR. FREDRIKSSON. I can’t speak definitely. I can’t recall. 

 MR. STUPAK. Did your department receive complaints from 

individuals that BP was out of compliance with the integrity management 

system or program, I should say? 

 MR. FREDRIKSSON. The department has received a number of 

complaints over the years with respect to BP operations from a number 

of different sources. 

 MR. STUPAK. How many complaints? Would you know? 

 MR. FREDRIKSSON. I would not know offhand. 

 MR. STUPAK. Do you know how many complaints were on 

corrosion or concerning corrosion problems? 

 MR. FREDRIKSSON. I don’t have the exact number, no. 

 MR. STUPAK. More than two? 

 MR. FREDRIKSSON. With respect to corrosion? I wouldn’t be 

surprised if it was more than two and less than a half dozen. 

 MR. STUPAK. Between two and six then. Okay. In 2001, did your 

staff warn you that Prudhoe Bay pipelines lacked appropriate equipment 

to evacuate oil out of the line in the event of a pipeline failure and 

recommended that BP be required to add pumps and tanks to be able to 

rapidly evacuate the pipelines? 

 MR. FREDRIKSSON. I don’t have a recollection of that, no. 

 MR. STUPAK. Okay. Did the Alaska Department of Environmental 

Conservation staff present you, Commissioner Michelle Brown and 

Larry Dietrich with photos of sagging pipelines, poor pipeline 

maintenance practice and other inspection deficiencies at BP facilities? 

 MR. FREDRIKSSON. I--let me speak to the sagging pipelines. I don’t 

have any recollection on the other topics. I know I provided staff with a 
534

photograph of a sagging pipeline from a trip I took to the North Slope 

and asked them to follow up on it. 

 MR. STUPAK. And did they follow up on it? 

 MR. FREDRIKSSON. To my knowledge, they did. 

 MR. STUPAK. They did? 

 MR. FREDRIKSSON. I delivered the message down to the industry 

preparedness program to have them look into that. 

 MR. STUPAK. Well, wouldn’t staff report back since you are the guy 

who is providing the photos of sagging pipelines? 

 MR. FREDRIKSSON. I assumed it was taken care of. I don’t recall if 

there was a report back, to be honest. 

 MR. STUPAK. Well, did you, Commissioner Michelle Brown or 

Larry Dietrich require BP to take any action to improve the oil spill 

prevention measures for their pipelines as a result of your staff warnings? 

 MR. FREDRIKSSON. Then-Commissioner Brown, I was then deputy 

commissioner, Larry Dietrich was the director of spill prevention 

response, the actions we took with respect to corrosion were 

characterized best in the charter agreement. In 1999, recognizing ARCO 

and BP were going to merge, we identified a number of issues that we 

wished the oil companies to address on the North Slope, seven to be 

exact, one of which was with respect to corrosion. 

 MR. STUPAK. That was 1999 and you made seven recommendations. 

Did you follow up? Did the Alaska Department of Environmental 

Conservation follow up to see if those seven were implemented? 

 MR. FREDRIKSSON. Yes, we did, sir. 

 MR. STUPAK. And were they implemented? 

 MR. FREDRIKSSON. They were implemented. 

 MR. STUPAK. Okay. Then can you explain to me then how the 

Coffman Engineering November 2001 report to you stated, and I am 

quoting, “External corrosion is the most immediate threat to pipeline 

integrity for BPXA.” Were there four pipeline leaks during the 2000-

2001 at BP facilities due to external corrosion? 

 MR. FREDRIKSSON. I don’t have the record. I would not be 

surprised that there would be. 

 MR. STUPAK. Well, if in 1999 they did the seven things you told 

them to do, how come 2 years later you have four pipeline leaks in not 

even a year after this agreement was agreed to? 

 MR. FREDRIKSSON. With respect to the corrosion program that we 

were investigating, we needed to learn what in fact ARCO and BP 

merger would do with respect to their corrosion program. We needed to 

understand how the ARCO corrosion management policy dovetailed with 

the BP corrosion monitoring policy. We needed to see--we needed to 

learn what steps BP now was taking to manage corrosion. 
535

 MR. STUPAK. But if you had to learn all this stuff you said in 1999, 

you gave them a list of things to do. 

 MR. FREDRIKSSON. That is correct. The agreement was signed in-- 

 MR. STUPAK. So you learned these things before 1999, right, and 

these were the things you wanted done? 

 MR. FREDRIKSSON. Congressman Stupak, the department was 

concerned about corrosion before 1999. We recognized there was an 

aging oil field. We recognized that BP and ARCO were going to merge. 

Both companies had corrosion monitoring programs, inspection control 

programs. We wanted to learn how those--how that was going to 

dovetail through the merger. We required through the agreement a 

commitment that BP make to the State to pursue a corrosion monitoring 

program and to report annually to the department. It has done so. That 

corrosion monitoring reporting has resulted in rules that the department 

has now adopted for corrosion regulation on flow lines. The vast 

majority of the pipelines on the North Slope are flow lines. High 

corrosivity-- 

 MR. STUPAK. That is fine, and I agree with all that stuff, but if no 

one is enforcing it, it means absolutely nothing. So-- 

 MR. FREDRIKSSON. The regulations-- 

 MR. STUPAK. --let me ask my last question because my time is up. 

What real, measurable improvements has the Alaska Department of 

Environmental Conservation required BP to take t0 improve oil spill 

prevention on their pipeline systems in the last 5 years? 

 MR. FREDRIKSSON. Through the charter-- 

 MR. STUPAK. The last 5 years, yes. 

 MR. FREDRIKSSON. Congressman Stupak, through the charter 

agreement, one, we have negotiated a charter agreement. Within that 

charter agreement, we have a number of spill prevention and response 

elements, one specific to corrosion. With respect to the corrosion, the 

corrosion evaluation that has resulted from that charter agreement has led 

the department to adopt through rulemaking regulations that will soon be 

in effect and we fully expect to enforce those rules with respect to 

corrosion on flow lines. 

 MR. STUPAK. Sure, that is all stuff on paper. I asked for real, 

measurable improvements. 

 MR. FREDRIKSSON. I-- 

 MR. STUPAK. There has been none, has there? 

 MR. FREDRIKSSON. Congressman Stupak, if you want to measure it 

in terms of equipment, if you want to measure it in terms of spill 

response, research, there has been a lot of work done over the last 5 years 

with respect to spill response preparedness and spill response research. 

There has been a tremendous amount of work done on cleanup of the 
536

North Slope from abandoned drums. There has been a tremendous 

amount of work by cleanup of contaminated sites, all of which was done 

under the charter agreement. 

 MR. STUPAK. That is great, but I want to know about this pipeline, 

not abandoned barrels and things like that. So it sounds like the State is 

asleep at the switch here, or what? 

 MR. FREDRIKSSON. I think just the opposite. Congressman Stupak, 

the regulations are not adopted overnight. Those regulations that we 

have adopted, corrosion control, need to be done carefully, they need to 

be based on the best science and they need to involve the public all along 

including the Federal agencies that are affected in this particular issue. 

Spending 2 years to, one, assimilate the information we had with respect 

to corrosion into a regulatory package which then goes through the 

rulemaking process for adoption, I don’t consider it to be a stand back 

and do nothing exercise. I am proud of the fact that we got those 

regulations in effect. I expect them to be enforced. I expect them to 

show a measurable improvement in the situation with respect to flow 

lines. 

 MR. STUPAK. I agree, and when I asked for measurable 

improvements, you couldn’t give me any, so okay. Nothing further, Mr. 

Chairman. 

 MR. BURGESS. The gentleman’s time has expired. The Chair 

recognizes Mr. Markey from the full committee. 

 MR. MARKEY. I thank the Chair very much. 

 MR. BURGESS. I would like to recognize you for 5 minutes but he 

told me I had to recognize you for 10. You are recognized. 

 MR. MARKEY. Meaning it is bad news for you at the table. He was 

trying to say that very delicately. 

 Admiral Barrett, the Department of Transportation has recently 

proposed a draft rulemaking to regulate some low-stress pipelines. How 

many miles of currently unrelated low-stress pipelines would be subject 

to regulation by your department under that proposed rule? 

 VICE ADMIRAL BARRETT. This rule would bring about 1,300 miles 

of additional lines, low-stress and gathering lines, under our oversight. 

 MR. MARKEY. When BP’s negligence has shown us that pipelines 

that are regulated are far better maintained than those that are not, why 

has the Department of Transportation proposed to allow DOT to regulate 

less than 14 percent of the 5,000 miles of currently unrelated low-stress 

pipelines like the ones up in Prudhoe Bay? 

 VICE ADMIRAL BARRETT. The lines--our estimate--a lot of these 

lines are not currently mapped so we are using an estimate but in general, 

the risks posed by many of these lines--many of these lines are much 

smaller and don’t affect unusually sensitive areas. That is areas where 
537

there is an endangered or threatened species. We already regulate lines 

like this that operate in populated areas or in navigable waters so simply 

the risk assessment and the impact--these are very small lines in many 

cases, a mile or two, much smaller than the BP lines for the most part. 

BP’s are 30-, 34-inch. These lines are down at the 8-inch to 16-inch size, 

and frankly, the risks and the benefit equation is not as large. We look 

closely-- 

 MR. MARKEY. It is not as large but why wouldn’t you regulate, you 

know, if you know that the regulation itself serves as a deterrent to 

negligence? 

 VICE ADMIRAL BARRETT. Well, there is a cost to complying with 

these regulations-- 

 MR. MARKEY. A cost to BP? 

 VICE ADMIRAL BARRETT. Not to BP. BP would be covered by 

these regulations clearly. 

 MR. MARKEY. It is a cost to whom? 

 VICE ADMIRAL BARRETT. I thought your question was, if we 

brought more of these lines under-- 

 MR. MARKEY. I am sorry. The cost runs to whom? 

 VICE ADMIRAL BARRETT. The operator of the line, in many cases 

small businesses where the cost burdens would be significant. 

 MR. MARKEY. Okay. So you are saying that they are basically 

given a small-business exemption? 

 VICE ADMIRAL BARRETT. I am sorry, and what I would also say is 

this is a proposal and we are soliciting comments, and if stakeholders or 

the public feel that we should cover more or less lines, that the scope of 

the rule is too narrow, too broad or that the requirements should be more 

or less stringent, we are happy to take that data and input, consider it and 

if appropriate, adjust. It is a proposal. 

 MR. MARKEY. Did your department do an estimate of what the cost 

to big oil companies would be if you were to regulate low-stress 

pipelines under their control? 

 VICE ADMIRAL BARRETT. We do have a cost estimate in the notice 

and I don’t recall it offhand but I would be glad to provide that. 

 MR. MARKEY. Is that a different cost-benefit analysis when you 

have a large, large company that has low-stress pipelines? 

 VICE ADMIRAL BARRETT. The cost benefit of the rule is looked at as 

a package but we are also required-- 

 MR. MARKEY. I understand where it might be different for a small 

business but how about for a big oil company? When companies are 

making $25, $30 billion a year, it is-- 

 VICE ADMIRAL BARRETT. Again, the large companies like BP, the 

type of lines we are talking about on the North Slope would be covered. 
538

 MR. MARKEY. Don’t you think, Admiral, that when BP made $7.27 

billion in profits during the last quarter of this year that they and other 

big oil companies can afford to pay to ensure that there is not a similar 

case of negligence, spill or shutdown elsewhere? 

 VICE ADMIRAL BARRETT. Well, I would come at it this way, sir, is 

that our obligation and our commitment is to ensure that pipelines 

operate safely, and if you are going to be in a business, you have to make 

the--the first responsibility for safety rests with the operator, and if you 

are going to be in this business, you have to make the investment 

necessary to operate your lines safely, and that is our responsibility to 

make sure that happens. 

 MR. MARKEY. Admiral, is there any requirement under these 

proposed regulations that companies must use internal inspection devices 

such as smart pigs and other pigs? 

 VICE ADMIRAL BARRETT. Yes, sir, but--and this is frequently--and I 

have heard some comment misunderstood. Even on many lines, there 

are segments of lines where you cannot use an inline inspection device. 

You may have telescoping lines, you may have bends and turns in the 

lines, and so we expect the company that is regulated with the integrity 

assessment program we have to bring forward a program that generally 

requires use of smart pigs but also would provide for alternatives, 

hydrostatic testing, radiological assessments, ultrasound assessments to 

get at areas where smart pigs are simply not feasible. So when you look 

at the rules, the language will allow for tools other than smart pigs and it 

is--what we do require is a complete understanding of the condition of 

the line. 

 MR. MARKEY. So it doesn’t require them the use of smart pigs? 

 VICE ADMIRAL BARRETT. It generally would require that they have 

a program in place to provide-- 

 MR. MARKEY. I understand that, but it is possible, in other words, 

for BP to put corrosion inhibitors into the oil using ultrasonic testing, 

doing these coupon pulls, all of which have been found to be woefully 

inadequate compared to running the pigs through the lines, and BP could 

have then deemed what they did to be sufficient under the proposed 

regulations even though it is clear that they are inadequate-- 

 VICE ADMIRAL BARRETT. No, sir. 

 MR. MARKEY. --compared to running the pigs. 

 VICE ADMIRAL BARRETT. The programs BP had in place up there 

would have failed under the regulation we are proposing. We, not BP, 

are the ones who make the assessment of the adequacy of the program 

and if we feel it is inadequate-- 

 MR. MARKEY. And why would it have failed and how would it have 

failed? 
539

 VICE ADMIRAL BARRETT. Because the corrosion program they had 

in place did not provide a comprehensive picture of the conditions of that 

line, specifically, the internal corrosion risks on those lines, and we 

would not have accepted that and our program would not accept it. 

 MR. MARKEY. Mr. Fredriksson, I have been told that BP is supposed 

to have in place a fund to ensure that at the end of its useful life, that 

these pipelines are safely decommissioned and dismantled without any 

harm to the environment obviously for the rest of eternity. Is that true? 

 MR. FREDRIKSSON. That is my understanding. That would fall 

under the State lease requirements which I am not responsible for so I 

can’t speak definitely-- 

 MR. MARKEY. Well, just tell me what you do know about it then. 

How much money is supposed to be in that program in just ballpark 

numbers? 

 MR. FREDRIKSSON. I have no idea. 

 MR. MARKEY. Do you know that there is supposed to be such a 

program? 

 MR. FREDRIKSSON. I understand there is a dismantling and removal 

provision but I have no understanding-- 

 MR. MARKEY. Can I just-- 

 MR. FREDRIKSSON. --or knowledge of the specifics. 

 MR. MARKEY. Your title is commissioner, Alaska Department of 

Environmental Conservation. Is that right? 

 MR. FREDRIKSSON. That is correct. 

 MR. MARKEY. And you are saying that this whole program of 

putting together a fund to make sure that these pipelines don’t harm the 

environment is something that just hasn’t come across your desk at all? 

You don’t have conversations with people about it at all? 

 MR. FREDRIKSSON. No, that is correct. The actual removal at the 

end of the life is a lease arrangement and lease obligation under the 

Department of Natural Resources. 

 MR. MARKEY. It would just seem to me that the Department of 

Environmental Conservation has a pretty big, you know, stake at least in 

knowing about what is going to happen when these pipelines get 

dismantled but I will take you at your word. I am told that there is a 

multi-billion-dollar fund which is supposed to be out in place and I have 

also been told that BP has not funded it, that there isn’t adequate money 

in this decommissioning fund and that instead BP is taking the profits 

and expatriating it and they are drilling in countries around the world but 

they have left this fund that is supposed to be there for the 

decommissioning of these pipelines relatively empty, which would seem 

to me to follow pretty clearly along the same lines as their lack of 
540

attention to this pipeline safety issue in general. But you are saying that 

is nothing you know about? 

 MR. FREDRIKSSON. Congressman Markey, that does not fall under 

the purview of DEC. 

 MR. MARKEY. It sounds pretty scary to me, in fact, that if this 

information that I have been given is accurate in terms of the long-term 

protection of the environment up in Alaska. I am going to pursue that, 

Mr. Chairman, as a line of independent questioning to the State of Alaska 

and to BP through you to the State and to BP. 

 Admiral Barrett, you say in your testimony that your department 

believes that most other unregulated low-stress pipelines in the lower 48 

States are operated to a higher standard of care. Since you currently have 

regulatory oversight over those lines, what information are you basing 

that belief on? 

 VICE ADMIRAL BARRETT. Sir, in developing--as I indicated-- 

 MR. MARKEY. I am sorry. You have no regulatory jurisdiction over 

it. What is the basis for you making that-- 

 VICE ADMIRAL BARRETT. As I indicated, over the past 2 years or 

more than 2 years actually, we have been developing this rulemaking to 

bring these low-stress and gathering lines under our oversight, and in the 

course of public hearings and in the course of developing the record for 

that rulemaking, we were in fact asking about maintenance practices on 

the lines, what people generally were doing or not doing, and it was part 

of the record, and you also have the history of the regulated lines in 

places like the North Slope as Mr. Hostler testified. 

 MR. MARKEY. It sounds to me, Admiral Barrett, that you are relying 

upon the representations of companies, the same kind of representations 

that was relied upon when BP was saying that they had done the job, and 

I just think that at this point, Admiral, that we should discontinue that 

reliance upon company assertions that save them money in the short run 

while exposing the environment and the public to great risk in the long 

run, and I just think it is time for you to end that presumption that I think 

has been extended to the industry. Thank you, Mr. Chairman. 

 MR. BURGESS. I don’t think that was in the form of a question, so it 

probably doesn’t require a response. 

 Admiral Barrett, if I could be permitted one follow-up question. 

Isn’t it true that during the 2001 debate on high-pressure lines, it was 

estimated that only 22 percent of the lines were covered but 82 percent of 

the lines ended up being covered? 

 VICE ADMIRAL BARRETT. Sir, as we bring any system or piece of 

the pipeline system under our regulatory authority, we actually get out on 

the ground, inspect the situation, inspect the lines, determine, as I said, 

like on the low-stress lines, these are estimates. A lot of these lines are 
541

not mapped. But once this rulemaking is in place, we will get out there, 

check those lines, check other lines in the area, and if it seems they fit 

within the ambit of the rule, we will bring them under our authority. So 

you are exactly correct. We inspect aggressively as well as issue rules. 

 MR. BURGESS. So the same thing could happen here on the lowpressure lines? 

 VICE ADMIRAL BARRETT. Yes, sir, it could. 

 MR. BURGESS. Thank you very much. 

 MR. STUPAK. Just one follow-up question. 

 MR. BURGESS. Sure. 

 MR. STUPAK. Mr. Fredriksson, I want to go back to the year 2000. I 

asked a number of questions about it. And as a result, let me ask you this 

question. Did the Alaska Department of Environmental Conservation 

recommend that settlement of the enforcement action for BP’s failure to 

install the required leak detection systems include a requirement to smart 

pig these lines, enhance the corrosion control programs and require nondestructive testing examination? 

 MR. FREDRIKSSON. Congressman Stupak, I can’t answer that 

question. I don’t know. 

 MR. STUPAK. Why wouldn’t you know? You are the commissioner. 

 MR. FREDRIKSSON. I am a commissioner where we have many 

different settlements arranged through the Department of Law and 

enforcement actions. We deal with many enforcement actions. My 

recollection of what happened in an enforcement action in 2000 when I 

was not a commissioner, I don’t have that information. I would be happy 

to look it up and get back to the subcommittee on that. 

 MR. STUPAK. Okay. Maybe I will submit these in writing then 

because I think you could go back and look up and see if there were any 

enforcement actions for BP during these recent years. Thanks. 

 MR. BURGESS. Thank you, Mr. Stupak. Do you yield back? 

 MR. STUPAK. Yes. 

 MR. BURGESS. Very well. I think that concludes our testimony. I 

may have one additional question for Mr. Fredriksson that I will submit 

as a written question but it has been a long day. Again, I appreciate 

everyone’s forbearance on this. It is an important subject. This 

committee will stand in adjournment. 

 [Whereupon, at 4:37 p.m., the subcommittee was adjourned.] 
542

RESPONSE FOR THE RECORD OF STEVE MARSHALL, PRESIDENT, BP EXPLORATION ALASKA,

INC. 
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RESPONSE FOR THE RECORD OF ROBERT A. MALONE, CHAIRMAN AND PRESIDENT, BP

AMERICA, INC. 
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RESPONSE FOR THE RECORD OF KURT FREDRIKSSON, COMMISSIONER, ALASKA 

DEPARTMENT OF ENVIRONMENTAL CONSERVATION
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