i i

This report is dedicated to the 11 men who lost 

their lives on the Deepwater Horizon rig on April 20, 

2010 and to their families, in hope that this report 

will help minimize the chance of another such 

disaster ever happening again.

Jason Anderson 

Aaron Dale Burkeen 

Donald Clark 

Stephen Curtis

Gordon Jones 

Roy Wyatt Kemp 

Karl Dale Kleppinger, Jr. 

Blair Manuel 

Dewey Revette 

Shane Roshto 

Adam Weise

Dedication
ii

Acknowledgements

We wish to acknowledge the many individuals and organizations, government officials 

and agencies alike that offered their views and insights to the Commission. We would 

especially like to express our gratitude to the Coast Guard’s Incident Specific Preparedness 

Review (ISPR) for allowing Commission staff to participate in its interviews and 

discussions, which was invaluable to the preparation of this report. (A copy of the Coast 

Guard’s ISPR report can be found at the Commission’s website at www.oilspillcommission.

gov). We would also like to thank Chevron for performing the cement tests that proved so 

critical to our investigation into the Macondo well blowout. 

We also thank the Department of Energy, which served as our supporting agency, and 

all of the Department employees whose assistance was so essential to the success and 

functioning of the Commission. In particular, we would like to thank Christopher Smith, 

Deputy Assistant Secretary for Oil and Natural Gas, who acted as the Commission’s 

Designated Federal Officer, as well as Elena Melchert, Petroleum Engineer in the Office of Oil 

and Gas Resource Conservation, who served as the Committee Manager.

But most importantly, we are deeply grateful to the citizens of the Gulf who shared their 

personal experiences as Commissioners traveled in the region, providing a critical human 

dimension to the disaster and to our undertaking, as well as the many people who testified 

at the Commission’s hearings, provided public comments, and submitted statements to 

our website. Together, these contributions greatly informed our work and led to a better 

report. Thank you one and all.

Copyright, Restrictions, and Permissions Notice 

Except as noted herein, materials contained in this report are in the public domain. Public domain 

information may be freely distributed and copied. However, this report contains illustrations, 

photographs, and other information contributed by or licensed from private individuals, companies, 

or organizations that may be protected by U.S. and/or foreign copyright laws. Transmission or 

reproduction of items protected by copyright may require the written permission of the copyright owner. 

When using material or images from this report we ask that you credit this report, as well as the source 

of the material as indicated in this report.] Permission to use materials copyrighted by other individuals, 

companies or organizations must be obtained directly from those sources.

This report contains links to many Web sites. Once you access another site through a link that we 

provide, you are subject to the use, copyright and licensing restrictions of that site. Neither the 

Government nor the National Commission on the BP/Deepwater Horizon Oil Spill and Offshore Drilling 

(Commission) endorses any of the organizations or views represented by the linked sites unless expressly 

stated in the report. The Government and the Commission take no responsibility for, and exercise no 

control over, the content, accuracy or accessibility of the material contained on the linked sites.

Cover Photo: © Steadfast TV 

ISBN: 978-0-16-087371-3 
iii iii

Deep Water

The Gulf Oil Disaster and the Future 

of Offshore Drilling 

Report to the President 

National Commission on the BP Deepwater Horizon 

Oil Spill and Offshore Drilling 

January 2011 
iv

Commission Members

Bob Graham, Co-Chair 

Cherry A. Murray

Donald F. Boesch

Fran Ulmer

Frances Beinecke

William K. Reilly, Co-Chair

Terry D. Garcia
v v

Table of Contents

Foreword

PART I: The Path to Tragedy

Chapter 1

“Everyone involved with the job...was completely satisfied....” 

The Deepwater Horizon, the Macondo Well, and Sudden Death on the Gulf of Mexico

Chapter 2 

“Each oil well has its own personality” 

The History of Offshore Oil and Gas in the United States

Chapter 3 

“It was like pulling teeth.” 

Oversight—and Oversights—in Regulating 

Deepwater Energy Exploration and Production in the Gulf of Mexico

PART II: Explosion and Aftermath: 

The Causes and Consequences of the Disaster

Chapter 4 

“But, who cares, it’s done, end of story, [we] will probably 

be fine and we’ll get a good cement job.” 

The Macondo Well and the Blowout

Chapter 5 

“You’re in it now, up to your neck!” 

Response and Containment

Chapter 6

“The worst environmental disaster America has ever faced.” 

Oiling a Rich Environment: Impacts and Assessment

Chapter 7

“People have plan fatigue . . . they’ve been planned to death” 

Recovery and Restoration

PART III: Lessons Learned: 

Industry, Government, Energy Policy

Chapter 8 

“Safety is not proprietary.” 

Changing Business as Usual

Chapter 9 

“Develop options for guarding against, and mitigating the impact of, oil spills associated 

with offshore drilling.” Investing in Safety, Investing in Response, Investing in the Gulf

Chapter 10 

American Energy Policy and the Future of Offshore Drilling

Endnotes 

Appendices

Appendix A: Commission Members

Appendix B: List of Acronyms

Appendix C: Executive Order

Appendix D: Commission Staff and Consultants

Appendix E: List of Commission Meetings

Appendix F: List of Staff Working Papers

Index

vi

xiii

1

21

55

87

89

129

173

197

215

217

249

293

307

356

358

359

362

365

366

368
vi

Photo: Susan Walsh, Associated Press 

Foreword

The explosion that tore through the Deepwater Horizon drilling rig last April 20, as the rig’s 

crew completed drilling the exploratory Macondo well deep under the waters of the Gulf of 

Mexico, began a human, economic, and environmental disaster.

Eleven crew members died, and others were seriously injured, as fire engulfed and 

ultimately destroyed the rig. And, although the nation would not know the full scope 

of the disaster for weeks, the first of more than four million barrels of oil began gushing 

uncontrolled into the Gulf—threatening livelihoods, precious habitats, and even a unique 

way of life. A treasured American landscape, already battered and degraded from years of 

mismanagement, faced yet another blow as the oil spread and washed ashore. Five years 

after Hurricane Katrina, the nation was again transfixed, seemingly helpless, as this new 

tragedy unfolded in the Gulf. The costs from this one industrial accident are not yet fully 

counted, but it is already clear that the impacts on the region’s natural systems and people 

were enormous, and that economic losses total tens of billions of dollars.

On May 22, 2010, President Barack Obama announced the creation of the National 

Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling: an independent, 

nonpartisan entity, directed to provide a thorough analysis and impartial judgment. The 

President charged the Commission to determine the causes of the disaster, and to improve 

the country’s ability to respond to spills, and to recommend reforms to make offshore 

energy production safer. And the President said we were to follow the facts wherever they 

led. 

This report is the result of an intense six-month effort to fulfill the President’s charge. 
vii vii

From the outset, the Commissioners have been determined to learn the essential 

lessons so expensively revealed in the tragic loss of life at the Deepwater Horizon and the 

severe damages that ensued. The Commission’s aim has been to provide the President, 

policymakers, industry, and the American people a clear, accessible, accurate, and fair 

account of the largest oil spill in U.S history: the context for the well itself, how the 

explosion and spill happened, and how industry and government scrambled to respond 

to an unprecedented emergency. This was our first obligation: determine what happened, 

why it happened, and explain it to Americans everywhere.

As a result of our investigation, we conclude:

•	 The explosive loss of the Macondo well could have been prevented. 

•	 The immediate causes of the Macondo well blowout can be traced to a series of 

identifiable mistakes made by BP, Halliburton, and Transocean that reveal such 

systematic failures in risk management that they place in doubt the safety culture of 

the entire industry. 

•	 Deepwater energy exploration and production, particularly at the frontiers of 

experience, involve risks for which neither industry nor government has been 

adequately prepared, but for which they can and must be prepared in the future. 

•	 To assure human safety and environmental protection, regulatory oversight of 

leasing, energy exploration, and production require reforms even beyond those 

significant reforms already initiated since the Deepwater Horizon disaster. Fundamental 

reform will be needed in both the structure of those in charge of regulatory oversight 

and their internal decisionmaking process to ensure their political autonomy, 

technical expertise, and their full consideration of environmental protection concerns. 

•	 Because regulatory oversight alone will not be sufficient to ensure adequate safety, 

the oil and gas industry will need to take its own, unilateral steps to increase 

dramatically safety throughout the industry, including self-policing mechanisms that 

supplement governmental enforcement. 

•	 The technology, laws and regulations, and practices for containing, responding to, 

and cleaning up spills lag behind the real risks associated with deepwater drilling into 

large, high-pressure reservoirs of oil and gas located far offshore and thousands of 

feet below the ocean’s surface. Government must close the existing gap and industry 

must support rather than resist that effort. 

•	 Scientific understanding of environmental conditions in sensitive environments in 

deep Gulf waters, along the region’s coastal habitats, and in areas proposed for more 

drilling, such as the Arctic, is inadequate. The same is true of the human and natural 

impacts of oil spills. 
viii

We reach these conclusions, and make necessary recommendations, in a constructive spirit: 

we aim to promote changes that will make American offshore energy exploration and 

production far safer, today and in the future.

More broadly, the disaster in the Gulf undermined public faith in the energy industry, 

government regulators, and even our own capability as a nation to respond to crises. It 

is our hope that a thorough and rigorous accounting, along with focused suggestions for 

reform, can begin the process of restoring confidence. There is much at stake, not only for 

the people directly affected in the Gulf region, but for the American people at large. The 

tremendous resources that exist within our outer continental shelf belong to the nation as 

a whole. The federal government’s authority over the shelf is accordingly plenary, based 

on its power as both the owner of the resources and in its regulatory capacity as sovereign 

to protect public health, safety, and welfare. To be allowed to drill on the outer continental 

shelf is a privilege to be earned, not a private right to be exercised.

“Complex Systems Almost Always Fail in Complex Ways”

As the Board that investigated the loss of the Columbia space shuttle noted, “complex 

systems almost always fail in complex ways.” Though it is tempting to single out one 

crucial misstep or point the finger at one bad actor as the cause of the Deepwater Horizon

explosion, any such explanation provides a dangerously incomplete picture of what 

happened—encouraging the very kind of complacency that led to the accident in the first 

place. Consistent with the President’s request, this report takes an expansive view.

Why was a corporation drilling for oil in mile-deep water 49 miles off the Louisiana 

coast? To begin, Americans today consume vast amounts of petroleum products—some 

18.7 million barrels per day—to fuel our economy. Unlike many other oil-producing 

countries, the United States relies on private industry—not a state-owned or -controlled 

enterprise—to supply oil, natural gas, and indeed all of our energy resources. This basic 

trait of our private-enterprise system has major implications for how the U.S. government 

oversees and regulates offshore drilling. It also has advantages in fostering a vigorous and 

competitive industry, which has led worldwide in advancing the technology of finding and 

extracting oil and gas.

Even as land-based oil production extended as far as the northern Alaska frontier, the oil 

and gas industry began to move offshore. The industry first moved into shallow water 

and eventually into deepwater, where technological advances have opened up vast new 

reserves of oil and gas in remote areas—in recent decades, much deeper under the water’s 

surface and farther offshore than ever before. The Deepwater Horizon was drilling the 

Macondo well under 5,000 feet of Gulf water, and then over 13,000 feet under the sea 

floor to the hydrocarbon reservoir below. It is a complex, even dazzling, enterprise. The 

remarkable advances that have propelled the move to deepwater drilling merit comparison 

with exploring outer space. The Commission is respectful and admiring of the industry’s 

technological capability.
ix ix

But drilling in deepwater brings new risks, not yet completely addressed by the reviews 

of where it is safe to drill, what could go wrong, and how to respond if something does 

go awry. The drilling rigs themselves bristle with potentially dangerous machinery. The 

deepwater environment is cold, dark, distant, and under high pressures—and the oil and 

gas reservoirs, when found, exist at even higher pressures (thousands of pounds per 

square inch), compounding the risks if a well gets out of control. The Deepwater Horizon

and Macondo well vividly illustrated all of those very real risks. When a failure happens 

at such depths, regaining control is a formidable engineering challenge—and the costs of 

failure, we now know, can be catastrophically high.

In the years before the Macondo blowout, neither industry nor government adequately 

addressed these risks. Investments in safety, containment, and response equipment and 

practices failed to keep pace with the rapid move into deepwater drilling. Absent major 

crises, and given the remarkable financial returns available from deepwater reserves, the 

business culture succumbed to a false sense of security. The Deepwater Horizon disaster 

exhibits the costs of a culture of complacency.

The Commission examined in great detail what went wrong on the rig itself. Our 

investigative staff uncovered a wealth of specific information that greatly enhances our 

understanding of the factors that led to the explosion. The separately published report of 

the chief counsel (a summary of the findings is presented in Chapter 4) offers the fullest 

account yet of what happened on the rig and why. There are recurring themes of missed 

warning signals, failure to share information, and a general lack of appreciation for the 

risks involved. In the view of the Commission, these findings highlight the importance 

of organizational culture and a consistent commitment to safety by industry, from the 

highest management levels on down.*

But that complacency affected government as well as industry. The Commission has 

documented the weaknesses and the inadequacies of the federal regulation and oversight, 

and made important recommendations for changes in legal authority, regulations, 

investments in expertise, and management.

The Commission also looked at the effectiveness of the response to the spill. There were 

remarkable instances of dedication and heroism by individuals involved in the rescue and 

cleanup. Much was done well—and thanks to a combination of good luck and hard work, 

the worst-case scenarios did not all come to pass. But it is impossible to argue that the 

industry or the country was prepared for a disaster of the magnitude of the Deepwater 

Horizon oil spill. Twenty years after the Exxon Valdez spill in Alaska, the same blunt 

response technologies—booms, dispersants, and skimmers—were used, to limited effect. 

On-the-ground shortcomings in the joint public-private response to an overwhelming 

spill like that resulting from the blowout of the Macondo well are now evident, and 

demand public and private investment. So do the weaknesses in local, state, and federal 

coordination revealed by the emergency. Both government and industry failed to anticipate 

and prevent this catastrophe, and failed again to be prepared to respond to it.

*The chief counsel’s investigation was no doubt complicated by the lack of subpoena power. Nonetheless, Chief Counsel Bartlit did an extraordinary job building the 

record and interpreting what he learned. He used his considerable powers of persuasion along with other tools at his disposal to engage the involved companies in 

constructive and informative exchanges.
x

If we are to make future deepwater drilling safer and more environmentally responsible, 

we will need to address all these deficiencies together; a piecemeal approach will surely 

leave us vulnerable to future crises in the communities and natural environments most 

exposed to offshore energy exploration and production. 

The Deepwater Drilling Prospect

The damage from the spill and the impact on the people of the Gulf has guided our work 

from the very beginning. Our first action as a Commission was to visit the Gulf region, 

to learn directly from those most affected. We heard deeply moving accounts from 

oystermen witnessing multi-generation family businesses slipping away, fishermen 

and tourism proprietors bearing the brunt of an ill-founded stigma affecting everything 

related to the Gulf, and oil-rig workers dealing with mounting bills and threatened 

home foreclosures, their means of support temporarily derailed by a blanket drilling 

moratorium, shutting down all deepwater drilling rigs, including those not implicated in 

the BP spill. 

Indeed, the centrality of oil and gas exploration to the Gulf economy is not widely 

appreciated by many Americans, who enjoy the benefits of the energy essential to their 

transportation, but bear none of the direct risks of its production. Within the Gulf region, 

however, the role of the energy industry is well understood and accepted. The notion of 

clashing interests—of energy extraction versus a natural-resource economy with bountiful 

fisheries and tourist amenities—misses the extent to which the energy industry is woven 

into the fabric of the Gulf culture and economy, providing thousands of jobs and essential 

public revenues. Any discussion of the future of offshore drilling cannot ignore these 

economic realities. 

But those benefits have imposed their costs. The bayous and wetlands of Louisiana have 

for decades suffered from destructive alteration to accommodate oil exploration. The Gulf 

ecosystem, a unique American asset, is likely to continue silently washing away unless 

decisive action is taken to start the work of creating a sustainably healthy and productive 

landscape. No one should be deluded that restoration on the scale required will occur 

quickly or cheaply. Indeed, the experience in restoring other large, sensitive regions—the 

Chesapeake Bay, the Everglades, the Great Lakes—indicates that progress will require 

coordinated federal and state actions, a dedicated funding source, long-term monitoring, 

and a vocal and engaged citizenry, supported by robust non-governmental groups, 

scientific research, and more.

We advocate beginning such an effort, seriously and soon, as a suitable response to the 

damage and disruption caused by the Deepwater Horizon emergency. It is a fair recognition 

not only of the costs that energy exploitation in the Gulf has, for decades, imposed on the 

landscape and habitats—and the other economic activities they support—but also of the 

certainty that Americans will continue to develop the region’s offshore energy resources. 

For the simple fact is that the bulk of our newly discovered petroleum reserves, and the 

best prospects for future discoveries, lie not on land, but under water. To date, we have 
xi xi

made the decision as a nation to exploit the Gulf’s offshore energy resources—ruling 

much of the Florida, Atlantic, and Pacific coasts out of bounds for drilling. The choice of 

how aggressively to exploit these resources, wherever they may be found, has profound 

implications for the future of U.S. energy policy, for our need to understand and assure 

the integrity of fragile environmental resources, and for the way Americans think about 

our economy and our security. Although much work is being done to improve the fuelefficiency of vehicles and to develop alternative fuels, we cannot realistically walk away 

from these offshore oil resources in the near future. So we must be much better prepared 

to exploit such resources with far greater care.

The Commission and Its Work

While we took a broad view of the spill, it could not be exhaustive. There is still much 

we do not know—for instance, the blowout preventer, the last line of defense against 

loss of well control, is still being analyzed; and the Deepwater Horizon itself, after its 

explosive destruction, remained out of reach during our investigation. The understandable, 

immediate need to provide answers and concrete suggestions trumped the benefits of 

a longer, more comprehensive investigation. And as we know from other spills, their 

environmental consequences play out over decades—and often in unexpected ways. 

Instead, the Commission focused on areas we thought most likely to inform practical 

recommendations. Those recommendations are presented in the spirit of transforming 

America into the global leader for safe and effective offshore drilling operations. Just 

as this Commission learned from the experiences of other nations in developing our 

recommendations, the lessons learned from the Deepwater Horizon disaster are not 

confined to our own government and industry, but relevant to rest of the world. 

We wish we could say that our recommendations make a recurrence of a disaster like 

the Macondo blowout impossible. We do not have that power. No one can eliminate all 

risks associated with deepwater exploration. But when exploration occurs, particularly in 

sensitive environments like the Gulf of Mexico or the Arctic, the country has an obligation 

to make responsible decisions regarding the benefits and risks.

The report is divided into three sections.

Chapters 1 through 3 describe the events of April 20th on the Deepwater Horizon, and, 

more important, the events leading up to it in the preceding decades—especially how the 

dramatic expansion of deepwater drilling in the Gulf was not met by regulatory oversight 

capable of ensuring the safety of those drilling operations. 

Chapters 4 through 7 lay out the results of our investigation in detail, highlighting the 

crucial issues we believe must inform policy going forward: the specific engineering and 

operating choices made in drilling the Macondo well, the attempts to contain and respond 

to the oil spill, and the impacts of the spill on the region’s natural resources, economy, and 

people—in the context of the progressive degradation of the Mississippi Delta environment. 
xii

Chapters 8 through 10 present our recommendations for reforms in business practices, 

regulatory oversight, and broader policy concerns. We recognize that the improvements 

we advocate all come with costs and all will take time to implement. But inaction, as we 

are deeply aware, runs the risk of real costs, too: in more lost lives, in broad damage to 

the regional economy and its long-term viability, and in further tens of billions of dollars 

of avoidable clean-up costs. Indeed, if the clear challenges are not addressed and another 

disaster happens, the entire offshore energy enterprise is threatened—and with it, the 

nation’s economy and security. We suggest a better option: build from this tragedy in a 

way that makes the Gulf more resilient, the country’s energy supplies more secure, our 

workers safer, and our cherished natural resources better protected.

Our Thanks and Dedication

We thank President Obama for this opportunity to learn thoroughly about the crisis, 

and to share our findings with the American public. We deeply appreciate the effort 

people in the affected Gulf regions made to tell us about their experiences, and the time 

and preparation witnesses before the Commission dedicated to their presentations. We 

have come to respect the seriousness with which our fellow Commissioners assumed 

our joint responsibilities, and their diverse expertise and perspectives that helped make its 

work thorough and productive. On their behalf, we wish to recognize the extraordinary 

work the Commission’s staff—scientists, lawyers, engineers, policy analysts, and more—

performed, under demanding deadlines, to make our inquiries broad, deep, and effective; 

and we especially highlight the leadership contributions of Richard Lazarus, executive 

director, and Fred Bartlit, chief counsel. Together, they have fulfilled an extraordinary 

public service.

Finally, to the American people, we reiterate that extracting the energy resources to 

fuel our cars, heat and light our homes, and power our businesses can be a dangerous 

enterprise. Our national reliance on fossil fuels is likely to continue for some time—and 

all of us reap benefits from the risks taken by the men and women working in energy 

exploration. We owe it to them to ensure that their working environment is as safe as 

possible. We dedicate this effort to the 11 of our fellow citizens who lost their lives in the 

Deepwater Horizon explosion.

Bob Graham, Co-Chair 

William K. Reilly, Co-Chair
xiii xiii

Part I 

The Path to Tragedy

On April 20, 2010, the 126 workers on the BP Deepwater Horizon

were going about the routines of completing an exploratory 

oil well—unaware of impending disaster. What unfolded would 

have unknown impacts shaped by the Gulf region’s distinctive 

cultures, institutions, and geography—and by economic forces 

resulting from the unique coexistence of energy resources, 

bountiful fisheries and wildlife, and coastal tourism. The oil and 

gas industry, long lured by Gulf reserves and public incentives, 

progressively developed and deployed new technologies, at 

ever-larger scales, in pursuit of valuable energy supplies in 

increasingly deeper waters farther from the coastline. Regulators, 

however, failed to keep pace with the industrial expansion and 

new technology—often because of industry’s resistance to more 

effective oversight. The result was a serious, and ultimately 

inexcusable, shortfall in supervision of offshore drilling that 

played out in the Macondo well blowout and the catastrophic oil 

spill that followed. Chapters 1 through 3 describe the interplay 

of private industry and public oversight in the distinctive Gulf 

deepwater context: the conditions that governed the deployment 

of the Deepwater Horizon and the drilling of the Macondo well.

xiii

Chapter One 1 1

The Deepwater Horizon, the 

Macondo Well, and Sudden Death 

on the Gulf of Mexico

At 5:45 a.m. on Tuesday, April 20, 2010, a 

Halliburton Company cementing engineer sent 

an e-mail from the rig Deepwater Horizon, in 

the Gulf of Mexico off the Louisiana coast, to his 

colleague in Houston. He had good news: “We have 

completed the job and it went well.”1 

Outside in the Gulf, it was still dark—beyond the 

glare of the floodlights on the gargantuan rig, the 

four decks of which towered above the blue-green 

water on four huge white columns, all floating 

on massive pontoons. The oil derrick rose over 20 

stories above the top deck. Up on the bridge on the 

main deck, two officers monitored the satelliteguided dynamic positioning system, controlling 

thrusters so powerful that they could keep the 

33,000-ton Deepwater Horizon centered over a well 

even in high seas. The rig’s industrial hum and loud 

mechanical noises punctuated the sea air as a slight 

breeze blew in off the water. The crew worked on 

Chapter One

“Everyone 

involved with 

the job . . . 

was completely 

satisfied. . .”

Pride of the Transocean fleet of offshore drilling rigs, Deepwater Horizon rides 

calmly on station 40 miles off the Louisiana coast. The $560-million-dollar 

rig, under lease to BP, was putting the finishing touches on the oil company’s 

18,000-foot-deep Macondo well when it blew out and escaping methane gas 

exploded. Eleven workers died in the inferno. According to the government’s 

estimates, by the time the well was sealed months later, over 4 million barrels of 

oil had spilled into the Gulf. 

< Photo courtesy of Transocean
2 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

the well bore, aiming always to keep the pressure inside the well balancing the force exerted 

by the surrounding seabed.2

By the time the Halliburton engineer had arrived at the rig four days earlier to help cement 

in the two-and-a-half-mile-deep Macondo well, some crew members had dubbed it “the 

well from hell.”3 Macondo was not the first well to earn that nickname;4 like many 

deepwater wells, it had proved complicated and challenging. As they drilled, the engineers 

had to modify plans in response to their increasing knowledge of the precise features of the 

geologic formations thousands of feet below. Deepwater drilling is an unavoidably tough, 

demanding job, requiring tremendous engineering expertise.

BP drilling engineer Brian Morel, who had designed the Macondo well with other BP 

engineers including Mark Hafle, was also on board to observe the final stages of work at 

the well.5 In an April 14 e-mail, Morel had lamented to his colleagues, “this has been [a] 

nightmare well which has everyone all over the place.”6 BP and its corporate partners on 

the well, Anadarko Petroleum and MOEX USA, had, according to government reports, 

budgeted $96.2 million and 51 days of work to drill the Macondo well in Mississippi 

Canyon Block 252.7 They discovered a large reservoir of oil and gas, but drilling had been 

challenging. 

As of April 20, BP and the Macondo well were almost six weeks behind schedule and more 

than $58 million over budget.8 The Deepwater Horizon was not originally meant to drill 

Macondo. Another giant rig, the Marianas, had initiated work on the well the previous 

October.9 Drilling had reached more than 9,000 feet below the ocean surface (4,000 feet 

below the seabed), with another 9,000 feet to go to “pay zone” (the oil and gas reservoir), 

when Hurricane Ida so battered the rig on November 9 that it had to be towed in for repair. 

Both Marianas and Deepwater Horizon were semisubmersible rigs owned by Transocean, 

founded in Louisiana in 1919 as Danciger Oil & Refining Co. and now the world’s largest 

contractor of offshore drilling rigs.10 In 2009, Transocean’s global fleet produced revenues 

of $11.6 billion.11 Transocean had consolidated its dominant position in the industry in 

November 2007 by merging with rival GlobalSantaFe.12 

Deepwater Horizon, built for $350 million,13 was seen as the outstanding rig in 

Transocean’s fleet; leasing its services reportedly cost as much as $1 million per day. 

Since Deepwater Horizon’s 2001 maiden voyage to the Gulf, it had been under contract 

to London-based BP (formerly known as British Petroleum). By 2010, after numerous 

acquisitions, BP had become the world’s fourth-largest corporation (based on revenue)14

producing more than 4 million barrels of oil daily from 30 countries.* Ten percent of BP’s 

output came from the Gulf of Mexico, where BP America (headquartered in Houston) 

was the largest producer. But BP had a tarnished reputation for safety. Among other BP 

accidents, 15 workers died in a 2005 explosion at its Texas City, Texas, refinery; in 2006, 

there was a major oil spill from a badly corroded BP pipeline in Alaska. 

* * * *

*A barrel equals 42 gallons.
Chapter One 3 3

Deepwater Horizon had arrived at the Macondo lease site on January 31, at 2:15 p.m. It 

was 55 degrees, chilly and clear—the night of a full moon. About 126 people were aboard: 

approximately 80 Transocean employees, a few BP men, cafeteria and laundry workers, 

and a changing group of workers contracted for specialized jobs. Depending on the status 

of the well, these might include Halliburton cementers, mud loggers from Sperry Sun (a 

Halliburton subsidiary), mud engineers from M-I SWACO (a subsidiary of Schlumberger, 

an international oilfield services provider), remotely operated vehicle technicians from 

Oceaneering, or tank cleaners and technicians from the OCS Group. The offices and living 

quarters were on the two bottom decks of the rig. Helicopters flew in and out regularly 

with workers and supplies, landing on the top-deck helipad, and service ships made regular 

visits.

At its new Macondo assignment, Deepwater Horizon floated in 4,992 feet of water just 

beyond the gentle slope of the continental shelf in the Mississippi Canyon.15 The seabed 

far below was near-freezing, visible to the crew only via cameras mounted on the rig’s 

subsea remotely operated vehicle. Another two and a half miles below the seabed was 

the prize BP sought: a large reservoir of oil and gas from the Middle Miocene era trapped 

in a porous rock formation at temperatures exceeding 200 degrees.16 These deepwater 

hydrocarbon fields, buried far below the seabed—not just in the Gulf, but in other oil-rich 

zones around the world, too—were the brave new oil frontier. The size of some deepwater 

fields was so huge that the oil industry had nicknamed those with a billion barrels or more 

“elephants.”17

Drilling for oil had always been hard, dirty, dangerous work, combining heavy machinery 

and volatile hydrocarbons extracted at high pressures. Since 2001, the Gulf of Mexico 

workforce—35,000 people, working on 90 big drilling rigs and 3,500 production 

platforms—had suffered 1,550 injuries, 60 deaths, and 948 fires and explosions.18

The rig never slept. Most workers on Deepwater Horizon, from BP’s top “company man” 

down to the roustabouts, put in a 12-hour night or day shift, working three straight 

weeks on and then having three weeks off. Rig workers made good money for the 

dangerous work and long stints away from home and family. Top rig and management 

jobs paid well into six figures.

On the morning of April 20, Robert Kaluza was BP’s day-shift company man on the 

Deepwater Horizon. On board for the first time, he was serving for four days as a relief 

man for Ronald Sepulvado, a veteran well-site leader on the rig. Sepulvado had flown back 

to shore April 16 for a required well-control class.19 

During the rig’s daily 7:30 a.m. operations conference call to BP in Houston, engineer 

Morel discussed the good news that the final cement job at the bottom of the Macondo 

well had gone fine.20 To ensure the job did not have problems, a three-man Schlumberger 

team was scheduled to fly out to the rig later that day, able to perform a suite of tests to 

examine the well’s new bottom cement seal.21 
4 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

According to the BP team’s plan, if the cementing went smoothly, as it had, they could skip 

Schlumberger’s cement evaluation. Generally, the completion rig would perform this test 

when it reopened the well to produce the oil the exploratory drilling had discovered. The 

decision was made to send the Schlumberger team home on the 11:00 a.m. helicopter, thus 

saving time and the $128,000 fee. As BP Wells Team Leader John Guide noted, “Everyone 

involved with the job on the rig site was completely satisfied with the [cementing] job.”22

At 8:52 a.m., Morel e-mailed the Houston office to reiterate: “Just wanted to let everyone 

know the cement job went well. Pressures stayed low, but we had full returns on the entire 

job...We should be coming out of the hole [well] shortly.” At 10:14 a.m., David Sims, BP’s 

new drilling operations manager in charge of Macondo, e-mailed to say, “Great job guys!”

* * * *

The rest of the day would be devoted to a series of further tests on the well—positiveand negative-pressure tests—in preparation for “temporary abandonment.”* During the 

positive-pressure test, the drill crew would increase the pressure inside the steel casing 

and seal assembly to be sure they were intact. The negative-pressure test, by contrast, 

would reduce the pressure inside the well in order to simulate its state after the Deepwater 

Horizon had packed up and moved on. If pressure increased inside the well during the 

negative-pressure test, or if fluids flowed up from the well, that would indicate a well 

integrity problem—a leak of fluids into the well. Such a leak would be a worrisome sign 

that somewhere the casing and cement had been breached—in which case remedial work 

would be needed to reestablish the well’s integrity.

At 10:43 a.m., Morel, about to leave the rig on the helicopter with the Schlumberger team, 

sent a short e-mail laying out his plan for conducting the day’s tests of the well’s integrity 

and subsequent temporary abandonment procedures. Few had seen the plan’s details when 

the rig supervisors and members of the drill team gathered for the rig’s daily 11:00 a.m. 

pre-tour meeting in the cinema room. “Basically [we] go over what’s going to be taking 

place for today on the rig and the drill floor,” said Douglas Brown, chief mechanic.23

During the rig meeting, the crew on the drill floor was conducting the Macondo well’s 

positive-pressure test.24 The positive-pressure test on the casing was reassuring, a 

success.25 There was reason for the mood on the rig to be upbeat. Ross Skidmore, a subsea 

engineer explained, “When you run the last string of casing, and you’ve got it cemented, 

it’s landed out, and a test was done on it, you say, ‘This job, we’re at the end of it, we’re 

going to be okay.’”26

At noon, the drill crew began to run drill pipe into the well in preparation for the negativepressure test later that evening.27 By now, it was a sunny afternoon. Transocean’s top 

men on the rig, Jimmy Harrell and Captain Curt Kuchta, were standing together near the 

helipad, watching a helicopter gently land. Kuchta had come in from New Orleans just 

* Temporary abandonment describes the process, after successful exploration, for securing the well until the production platform can be brought in for the purpose of 

extracting the oil and gas from the reservoir.
Chapter One 5 5

that morning to begin his three-week hitch. Harrell was the top Transocean man on the 

rig when—as now—the well was “latched up.” Captain Kuchta, who had served on the 

Deepwater Horizon since June 2008, was in command when the vessel was “unlatched” 

and thus once again a maritime vessel. 28

The helicopter landed, the doors opened, and four Houston executives stepped out to begin 

their 24-hour “management visibility tour.”29 Harrell and Kuchta greeted the VIPs.30 Two 

were from Transocean: Buddy Trahan, vice president and operations manager for assets, 

and Daun Winslow, a one-time assistant driller who had worked his way up to operations 

manager. BP’s representatives were David Sims, the new drilling operations manager (he 

had sent the congratulatory e-mail about the cement just that morning), and Pat O’Bryan, 

vice-president for drilling and completions, Gulf of Mexico Deepwater.31 

At about 4:00 p.m., Harrell began his escorted tour of the Deepwater Horizon for the 

VIPs.32 He was joined by Chief Engineer Steve Bertone, on board since 2003, and senior 

toolpusher Randy Ezell, another top man on the rig. 33 Like Harrell, Ezell was an offshore 

veteran. He had worked for 23 years with Transocean34 and was now the senior man in 

charge of the drilling floor. He had been on the rig for years. If any people knew this rig, 

they were Harrell, Bertone, and Ezell; they showed the VIPs around.

At 5:00 p.m., the rig crew, including toolpusher Wyman Wheeler, began the negativepressure test.35 After bleeding pressure from the well, the crew would close it off to check 

whether the pressure within the drill pipe would remain steady. But the pressure repeatedly 

built back up. As the crew conducted the test, the drill shack grew crowded.36 The night 

crew began arriving to relieve the day shift, and Harrell brought the VIPs through as part 

of their tour.37

“There was quite a few people in there,” said Transocean’s Winslow. “I tapped Dewey 

Revette on the shoulder. He was the driller master. I said, ‘Hey, how’s it going, Dewey? You 

got everything under control here?’

“And he said, ‘Yes, sir.’

“And there seemed to be a discussion going on about some pressure or a negative test. And 

I said to Jimmy [Harrell] and Randy Ezell, ‘Looks like they’re having a discussion here. 

Maybe you could give them some assistance.’ And they happily agreed to that.”38 Bertone 

took over the tour, wandering on to look at the moon pool, down toward the pontoons 

and the thrusters.39

The two shifts continued to discuss how to proceed. It was about 6:00 p.m. Jason 

Anderson, a tool pusher, turned to Ezell and said, “Why don’t you go eat?”40

Ezell had originally planned to attend a meeting with the VIPs at 7:00 p.m. He replied, “I 

can go eat and come back.”41
6 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Anderson was from Bay City, Texas, and had been on the rig since it was built; he was 

highly respected as a man who understood the finer points of deepwater well control. 

This was his final shift on the Deepwater Horizon: he had been promoted to teaching in 

Transocean’s well-control school, and he was scheduled to fly out the next day. He told 

Ezell, “Man, you ain’t got to do that. I’ve got this. Don’t worry about it. If I have any 

problems at all with this test I’ll give you a call.”42

“I knew Jason well,” said Ezell, “I’ve worked with him for all those years, eight or nine 

years....He was just like a brother. So I had no doubt that if he had any indication of any 

problem or difficulty at all he would have called me. So I went ahead and ate. I did attend 

the meeting with the dignitaries.”43

Wheeler was “convinced that something wasn’t right,” recalled Christopher Pleasant, a 

subsea supervisor. Wheeler couldn’t believe the explanations he was hearing. But his shift 

was up.44

Don Vidrine, the company man coming on the evening shift, eventually said that another 

negative test had to be done.45 This time the crew members were able to get the pressure 

down to zero on a different pipe, the “kill line,” but still not for the drill pipe, which 

continued to show elevated pressure.46 According to BP witnesses, Anderson said he had 

seen this before and explained away the anomalous reading as the “bladder effect.”47

Whether for this reason or another, the men in the shack determined that no flow from the 

open kill line equaled a successful negative-pressure test.48* It was time to get on with the 

rest of the temporary abandonment process. Kaluza, his shift over, headed off duty.49

At 7:00 p.m., after dinner, the VIPs had gathered in the third floor conference room with 

the rig’s leadership. According to BP’s Patrick O’Bryan, the Deepwater Horizon was “the 

best performing rig that we had in our fleet and in the Gulf of Mexico. And I believe it was 

one of the top performing rigs in all the BP floater fleets from the standpoint of safety and 

drilling performance.” O’Bryan, at his new job just four months, was on board in part to 

learn what made the rig such a stand-out.50 Despite all the crew’s troubles with this latest 

well,51 they had not had a single “lost-time incident” in seven years of drilling.52

The Transocean managers discussed with their BP counterparts the backlog of rig 

maintenance. A September 2009 BP safety audit had produced a 30-page list of 390 items 

requiring 3,545 man-hours of work.53 The managers reviewed upcoming maintenance 

schedules and discussed efforts to reduce dropped objects and personal injuries: on a rig 

with cranes, multiple decks, and complicated heavy machinery, errant objects could be 

deadly.54

Around 9:00 p.m., Transocean’s Winslow proposed they all go visit the bridge, which had 

not been part of their earlier tour. According to David Sims, the bridge was “kind of an 

impressive place if you hadn’t been there...[l]ots of screens...lots of technology.”55 The four 

* The precise content of this particular conversation is disputed and is considered more fully in Chapter 4.
Chapter One 7 7

men walked outside. The Gulf air was warm and the water calm as glass. Beyond the glare 

of the rig’s lights, the night sky glimmered with stars. 

* * * * 

After concluding that the negative-pressure test was successful, the drilling crew prepared 

to set a cement plug56 deep in the well—3,000 feet below the top of the well. 57 They 

reopened the blowout preventer and began pumping seawater down the drill pipe to 

displace the mud and spacer* from the riser (the pipe that connected the rig to the well 

assembly on the seafloor below).58 When the spacer appeared up at the surface, they 

stopped pumping because the fluid had to be tested to make sure it was clean enough to 

dump it in the Gulf, now that it had journeyed down into the well and back. By 9:15 p.m., 

the crew began discharging the spacer overboard.59 

* * * * 

Inside the bridge, Captain Kuchta welcomed visitors Sims, O’Bryan, Trahan, and 

Winslow.60 The two dynamic-positioning officers, Yancy Keplinger and Andrea Fleytas, 

were also on the bridge.61 Keplinger was giving the visitors a tour of the bridge while 

Fleytas was at the desk station.62 The officers explained how the rig’s thrusters kept the 

Deepwater Horizon in place above the well, showed off the radars and current meters, and 

offered to let the visiting BP men try their hands at the rig’s dynamic-positioning video 

simulator.63 

Winslow watched as the crew programmed in 70-knot winds and 30-foot seas, and 

hypothetically put two of the rig’s six thrusters out of commission. Then they put the 

simulator into manual mode and let Sims work the hand controls to maintain the rig’s 

location. Keplinger was advising about how much thrust to use. Winslow decided it was a 

good moment to go grab a quick cup of coffee and a smoke. He walked down to the rig’s 

smoking area, poured some coffee, and lit his cigarette.64

* * * * 

Senior Toolpusher Randy Ezell left the evening meeting with BP feeling pleased at their 

praise “on how good a job we had done...How proud they were of the rig.” He stopped in 

at the galley to get a beverage before continuing to his office. At 9:20, he called Anderson 

up on the rig floor and asked, “‘How did your negative test go?’”65 

Anderson: “It went good. . . . We bled it off. We watched it for 30 minutes and we had no 

flow.” 

Ezell: “What about your displacement? How’s it going?”

Anderson: “It’s going fine. . . . It won’t be much longer and we ought to have our spacer 

back.” 

* As described more fully in Chapter 4, a “spacer” is a liquid that separates drilling mud used during the drilling operations from the seawater that is pumped in to 

displace the mud once drilling is complete.
8 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Ezell: “Do you need any help from me?”

Anderson: “No, man. . . . I’ve got this. . . . Go to bed. I’ve got it.” 

Ezell concluded: “Okay.”66

Ezell walked to his cabin. He had worked with Anderson since the rig came from the 

shipyard. He had complete confidence in him. “Jason was very acute on what he did. . . 

he probably had more experience as far as shutting in for kicks than any individual on 

the Deepwater Horizon.” So Ezell prepared for bed, called his wife, and then turned off the 

lights to watch a bit of TV before going to sleep.67

* * * * 

Up on the bridge, O’Bryan was taking his turn on the simulator.68 Sims had stepped to the 

opposite side of the bridge when he felt a distinct high-frequency vibration.69

Captain Kuchta looked up and remarked “What’s that?” He strode to the port-side door and 

opened it.70 Outside, O’Bryan could see the supply vessel Bankston glistening with what 

looked like drilling mud.71 The captain shut the door “and told everybody to stay inside.”72

Then there began a hissing noise.73

* * * * 

BP’s Vidrine had headed back to his office to do paperwork. He had been there about 10 to 

15 minutes when the phone rang. It was Anderson, who reported “they were getting mud 

back and were diverting to the gas buster.” Vidrine grabbed his hard hat and started for the 

drill floor. By the time he got outside, “[t]here was mud and seawater blowing everywhere, 

there was a mud film on the deck. I decided not to continue and came back across.”74

* * * * 

Down in Ezell’s cabin, he was still watching TV when his phone rang. It was assistant 

driller Steve Curtis calling, also from the rig floor. “We have a situation. ...The well is 

blown out. . . . We have mud going to the crown.” Ezell was horrified. “Do y’all have it 

shut in?”75

Curtis: “Jason is shutting it in now. . . Randy, we need your help.”

Ezell: “Steve, I’ll be—I’ll be right there.”76

He put on his coveralls, pulled his socks on, and opened the door to go across the hall to 

his office for his boots and hard hat. Once in the hall, “a tremendous explosion... blew me 

probably 20 feet against a bulkhead, against the wall in that office. And I remember then 

that the lights went out, power went out. I could hear everything deathly calm.”77

* * * * 
Chapter One 9 9

Up on the main deck, gantry crane operator Micah Sandell was working with the 

roustabouts. “I seen mud shooting all the way up to the derrick. . . . Then it just 

quit. . . I took a deep breath thinking that ‘Oh, they got it under control.’ Then all the 

sudden the. . . mud started coming out of the degasser. . . so strong and so loud that it just 

filled up the whole back deck with a gassy smoke. . . loud enough. . . it’s like taking an air 

hose and sticking it in your ear. Then something exploded. . . that started the first fire...on 

the starboard side of the derrick.”78

Sandell jumped up and turned off the crane cab’s air conditioner, worried that the gas 

would come in. “And about that time everything in the back just exploded at one time. 

It. . . knocked me to the back of the cab. I fell to the floor. . . put my hands over my head 

and I just said, ‘No, God, no.’ Because I thought that was it.”79 Then the flames pulled back 

from his crane and began to shoot straight up, roaring up and over the 20-story derrick.80

* * * * 

Down in the engine control room, Chief Mechanic Douglas Brown, an Army veteran 

employed by Transocean, was filling out the nightly log and equipment hours. He had 

spent the day fixing a saltwater pipe in one of the pontoons. First, he noticed an “extremely 

loud air leak sound.” Then a gas alarm sounded, followed by more and more alarms 

wailing. In the midst of that noise, Brown noticed someone over the radio. “I heard the 

captain or chief mate, I’m not sure who, make an announcement to the standby boat, the 

Bankston, saying we were in a well-control situation.”81 The vessel was ordered to back off 

to 500 meters. 82 

Now Brown could hear the rig’s engines revving. “I heard them revving up higher and 

higher and higher. Next I was expecting the engine trips to take over. . . . That did not 

happen. After that the power went out.” Seconds later, an explosion ripped through the 

pitch-black control room, hurtling him against the control panel, blasting away the floor. 

Brown fell through into a subfloor full of cable trays and wires. A second huge explosion 

roared through, collapsing the ceiling on him. All around in the dark he could hear people 

screaming and crying for help.83

Dazed and buried in debris, he pulled himself out of the subfloor hole. In front of him 

appeared Mike Williams, chief electronic technician, blood pouring from a wound on his 

forehead, crawling over the rubble, screaming that he had to get out.84

* * * * 

Steve Bertone, the rig’s chief engineer, had been in bed, reading the first sentence of his 

book, when he noticed an odd noise. “As it progressively got louder, it sounded like a 

freight train coming through my bedroom and then there was a thumping sound that 

consecutively got much faster and with each thump, I felt the rig actually shake.”85 After 

a loud boom, the lights went out.86 He leapt out of bed, opening his door to let in the 

emergency hall light so he could get dressed.87 The overhead public-address system crackled 

to life: “Fire. Fire. Fire.” 88 
10 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

The air smelled and tasted of some kind of fuel. A second explosion roared through, 

flinging Bertone across his room. He stood up, pulled on his coveralls, work boots, and 

hard hat, and grabbed a life vest. Out in the hall, clogged with debris from blown-out 

walls and ceilings, four or five men stood in shock. Bertone yelled to them to go out by the 

port forward or starboard forward spiral staircases and report to their emergency stations. 

He ran toward the bridge.89

He went to the portside back computer, the dynamic positioning system responsible for 

maintaining the rig’s position. “I observed that we had no engines, no thrusters, no power 

whatsoever. I picked up the phone which was right there and I tried calling extension 2268, 

which is the engine control room. There was no dial tone whatsoever.” It was then that 

Bertone looked out to the bridge’s starboard window. “I was fully expecting to see steel 

and pipe and everything on the rig floor.” “When I looked out the window, I saw fire from 

derrick leg to derrick leg and as high as I could see. At that point, I realized that we had 

just had a blowout.”90

Fleytas hit the general alarm.91 The alarm went off: “Report to emergency stations and 

lifeboats.” The rig crew heard: “This is not a drill. This is not a drill.”92 Fleytas, realizing 

that the rig had not yet issued a Mayday call, sent it out.93 Out in the dark of the Gulf, 

three friends on the 31-foot Ramblin’ Wreck were out on the water for a day of tuna 

fishing.94 Around 9:45 p.m., Bradley Shivers trained his binoculars at a brilliant light 

in the distance and realized it must be an oil rig on fire.95 On their radio, they heard, 

“Mayday, Mayday, Mayday, this is the Deepwater Horizon. We are on fire.”96 At that 

moment they “heard and felt a concussive sonic boom.”97 The Ramblin’ Wreck headed to 

the scene, their first tuna outing of the year cut short. 98

Bertone was now back to his station on the bridge, thinking, “The engines should be 

starting up because in approximately 25 to 30 seconds two engines start up, come 

online. . . . There was still no power of any kind. No engines starting; no indication of 

engines starting.”99 

At that moment, the water-tight door to his left banged open and he heard someone 

say, “The engine room ECR [engine control room] and pump room are gone. They are 

all gone.” Bertone turned around, “What do you mean gone?” The man speaking was 

so coated in blood Bertone had no idea who he was. Then he recognized the voice. It was 

Mike Williams. Bertone saw how badly lacerated Williams’s forehead was, grabbed a roll 

of toilet paper from the bathroom, pressed it on the wound to staunch the bleeding, and 

ordered, “Hold this here.”100 

Then he went back to his station and looked at his screen. “There was still nothing, no 

engines starting, no thrusters running, nothing. We were still [a] dead ship.”101

He heard the water-tight door slam again and saw another man soaked in blood, holding 

a rag to his head, repeating, “I’m hurt. I’m hurt bad, Chief. I’m hurt real bad.” It was the 

voice of Brent Mansfield, a Transocean marine engineer. Bertone pulled back Mansfield’s 
Chapter One 11 11

hand holding a rag, saw the head wound, and ran over to the bridge door and yelled down 

to the life-vessel area, “We need a medic up here now.”102

* * * * 

After the explosion, Randy Ezell lay buried under the blown-out walls and ceilings of the 

toolpusher’s office. The room was dark and smoky, the debris atop him so heavy he could 

barely move. On the third try, adrenalin kicked in. “I told myself, ‘Either you get up or 

you’re going to lay here and die.’” Pulling hard on his right leg, he extricated it and tried 

to stand up. “That was the wrong thing to do because I immediately stuck my head into 

smoke. . . .I dropped back down. I got on my hands and knees and for a few moments I 

was totally disoriented.” He wondered which way the door was. He felt air. He crawled 

through the debris toward the door and realized the “air” was methane. He could feel the 

droplets. He was crawling slowly atop the rubble in the pitch-black hall when he felt a 

body.103 

Ezell then saw a bobbing beam of light. Stan Carden, the electrical supervisor, came round 

the corner. Carden had a light that bounced off shattered walls and collapsed ceilings in 

the pitch-black corridor, giving glimpses into rooms on each side wrecked by the power of 

the blast.104 Stumbling into what was left of the hall was Offshore Installation Manager 

Jimmy Harrell, who had been in the shower when the rig exploded;105 he had donned 

coveralls, and now was groping his way out of what was left of his room. “I think I’ve got 

something in my eyes,” Harrell said. He had no shoes. “I got to see if I can find me some 

shoes.”106 

Carden and Ezell tugged debris off the man they now recognized as Wyman Wheeler. Chad 

Murray, Transocean’s Chief Electrician, also appeared in the hall with a flashlight, and was 

immediately dispatched to find a stretcher for the injured man.107

Believing it would save time to walk Wheeler out, Ezell slung Wheeler’s arm around his 

shoulder. Wheeler groaned, “Set me down . . . . Y’all go on. Save yourself.”108

Ezell said, “No, we’re not going to leave you. We’re not going to leave you in here.”109 

Just then, they heard another voice from under the rubble: “God help me. Somebody please 

help me.” Near the ruins of the maintenance office the flashlight picked out a pair of feet 

jutting from the rubble. It was the visiting Transocean manager, Buddy Trahan, badly 

injured. By now Murray was there with a stretcher. Ezell, Carden, and Murray dragged 

away the remains of ceilings and walls trapping Trahan and loaded him on the stretcher. 

Carden and Murray carried him through the smoke and dark to the bow of the rig and the 

lifeboats.110

Outside, the derrick fire roared upward into the night sky, an inferno throwing off 

searing heat and clouds of black smoke. The blinding yellow of the flames was the only 

illumination except for the occasional flashlight. The rig’s alarms were going off, while 

over the public announcement system Keplinger yelled, “THIS IS NOT A DRILL!”111 As the 
12 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

crew struggled out of the blasted quarters, galley, and offices, in various states of undress, 

they converged in a chaotic and panicked mass at the lifesaving vessels, putting on life 

vests.112

Sandell, the gantry crane operator, had escaped and come around the port side of the deck 

to the life vessels. “It was a lot of screaming, just a lot of screaming, a lot of hollering, a 

lot of scared people, including me, was scared. And trying to get people on boats. It was 

very unorganized—we had some wounded we was putting in the boat. Had people on the 

boat yelling, ‘Drop the boat, drop the boat,’ and we still didn’t have everybody on the boat 

yet. We was still trying to get people on the boat and trying to calm them down enough 

to—trying to calm them down enough to get everybody on the boat. And there was people 

jumping off the side. We was trying to get an accurate count and just couldn’t get an 

accurate count because people were just jumping off the boat.” 113

* * * * 

On the Bankston, Captain Alwin J. Landry was on the bridge updating his log when his 

mate noticed the mud. Landry stepped out and saw “mud falling on the back half of my 

boat, kind of like a black rain.” He called the Deepwater Horizon bridge to say, “I’m getting 

mud on me.” Landry instructed his crew to get inside. The Deepwater Horizon called back 

and told him to move back 500 meters.114 A crew member noticed a mud-covered seagull 

and egret fall to the deck.115 Shortly after, Landry saw the rig explode. Before the ship 

could move away, his crew had to detach the long mud transfer hose connecting them to 

the rig.116 

As they scrambled to disconnect, the Bankston slowly moved 100 meters back, then 500 

meters. As the rig went dark, and secondary explosions rocked the decks, the Bankston

turned on its searchlight. Landry could see the Deepwater Horizon crew mustering by the 

portside life vessels. “That’s when I seen the first of three or four people jump to the water 

from the rig.”117 

One of those was Gregory Meche, a compliance specialist. After five minutes of the chaos 

around the lifeboats, and a series of large explosions, he headed down to the lower deck. He 

jumped into the water.118

Antonio Gervasio, the Bankston’s relief chief, and two others began launching the ship’s 

fast rescue craft.119 Within a minute or two of the explosions, they got the boat lowered 

into the water, and noticed how calm the Gulf was.120 “I saw the first person jump in 

the water. So I told one of the guys to keep an eye on him.”121 The rig life jackets were 

reflective, and as the fast craft made its first sweep round from one side of the burning rig 

to the other, they hauled Meche and two or three others out of the water.122 

* * * * 

Back on the rig, Transocean’s Winslow had made his way from the coffee shop to the 

lifeboats, surviving the second blast’s wave of concussive force, which blew in the 
Chapter One 13 13

corridor’s walls and ceilings. On the deck, a firestorm of flames roared in the night sky 

above the derrick.123 

Winslow directed the dazed crew toward the covered life-saving vessels, instructing the 

first arrivals, “We need to make sure we get a good head count.” Seeing Captain Kuchta 

standing at the starboard bridge door, he ran up, and said people should evacuate. Kuchta 

answered, “Okay.” Panic was building as the derrick fire roared. Winslow heard someone 

yelling that people were jumping overboard. As the lifeboats filled, crew members were 

screaming to lower the boats.124 But not everyone was there.125 Carden and Murray 

appeared with Trahan on the stretcher and handed him into the vessel, where he was laid 

out.126 People in the boat screamed, “We’ve got to go! We’ve got to go!”127 

A man in his life vest was hanging on the rig handrails, preparing to drop overboard. 

Winslow said, “Hey, where are you going? There’s a perfectly good boat here. Do you trust 

me?” He and another crew member coaxed the man down and into one of the life vessels, 

where people were still screaming to leave. Down below in the water, the crew could see 

swaths of burning oil rising and falling with the gentle swell. The jumpers were visibly 

bobbing and swimming in their life vests shining with fluorescent strips. The Bankston’s

fast rescue craft was hauling them out of the water. 128

By now, Winslow began to wonder why the derrick was still roaring with flames. Hadn’t 

the blowout preventer been activated, sealing off the well and thus cutting off fuel for the 

conflagration? He headed to the bridge. Kuchta said, “We’ve got no power, we’ve got no 

water, no emergency generator.”129

Steve Bertone was still at his station on the bridge and he noticed Christopher Pleasant, one 

of the subsea engineers, standing next to the panel with the emergency disconnect switch 

(EDS) to the blowout preventer.130 

Bertone hollered to Pleasant: “Have you EDSed?”131

Pleasant replied he needed permission. Bertone asked Winslow was it okay and Winslow 

said yes.132

Somebody on the bridge yelled, “He cannot EDS without the OIM’s [offshore installation 

manager’s] approval.”133 

Harrell, still dazed, somewhat blinded and deafened, had also made it to the bridge, as had 

BP’s Vidrine. 134 With the rig still “latched” to the Macondo well, Harrell was in charge. 

Bertone yelled, “Can we EDS?” and Harrell yelled back, “Yes, EDS, EDS.”135

Pleasant opened the clear door covering the panel and pushed the button.

Bertone: “I need confirmation that we have EDSed.”

Pleasant: “Yes, we’ve EDSed.”

Bertone: “Chris, I need confirmation again. Have we EDSed?”

Pleasant: “Yes.”
14 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Bertone: “Chris, I have to be certain. Have we EDSed?”

Pleasant: “Yes.” He pointed to a light in the panel.136

By now BP’s O’Bryan, who saw red lights on the EDS panel, had put on a life vest. He 

looked at his colleague, Sims, and said they should head to the lifeboats. Outside, the 

conflagration continued to rage, a brilliant blinding yellow that threw off a deafening roar 

and blistering heat. As the fire raged on, new explosions rang out, spewing hot debris. 

O’Bryan, unsure of which life vessel he should board, recalled being given a notice at his 

safety orientation listing his boat. He pulled it out of his back pocket: Lifeboat 2. He figured 

out which one it was, stepped into the dark interior and squeezed into a seat.137 Some 

people were screaming, “We’ve got to go. We’ve got to go.”138 BP’s Robert Kaluza had 

made his way up from his cabin and had boarded a lifeboat.139

Winslow had returned to the lifeboats. He yelled over the noise to the panicked crew 

members, “We’ve got plenty of time.” Then he looked up at the sky-high flames engulfing 

the derrick: “Right about that time is when the traveling equipment, the drilling blocks 

and whatnot on the derrick fell. They were probably 40 to 50 foot in the air, you know, 

weigh 150,000 pounds, and they didn’t make any noise [when they fell]. So at that time, I 

instructed the boat to my right, which would have been the port survival boat, to depart. 

They did.”140

Winslow then helped lower his own life vessel over approximately 125 feet to the Gulf.141 

Winslow discovered the lifeboat windows were obscured by mud.142 He opened the hatch 

and pointed the coxswain toward the Bankston vessel; he then clambered out onto the 

outside so that he could grab the rope thrown to him by the Bankston crew.143 The 

Bankston had made radio contact and Captain Landry instructed the vessels to come round 

to his starboard side, sheltered from the rig.144 

* * * * 

The rig life vessels were not the only small craft fleeing the firestorm. Four high-school 

buddies out fishing had sailed up to the rig around 7:30 p.m. on their 26-foot catamaran 

and settled in by the pontoons.145 The rig’s blazing lights attracted small fish, which in 

turn attracted tuna. About two hours later, the group noticed water flowing out of the 

rig’s pipes, followed by blowing gas. One young man had worked on rigs and began 

yelling, “Go, go, go, go, GOOOOO!” The owner pointed the boat away from the rig and 

gunned the engine. Then the lights went out and the rig blew.146 

* * * * 

Back up on the Deepwater Horizon bridge, Bertone asked Captain Kuchta’s permission to 

go to the standby generator room to try to manually start it. He assumed that the EDS 

had worked. “My thinking at that point was the BOP [blowout preventer] had unlatched, 

what remaining fuel would be in the riser it would burn away and we were going to need 

power, as well as fire pumps.”147
Chapter One 15 15

As Bertone left, Mike Williams, his head wounds no longer bleeding, said, “You’re not 

going alone, Chief.” 

“Well, come on.”148

Paul Meinhart, a motorman, joined them. As Bertone ran to the standby generator room, 

he looked up at the derrick where the crown should be. “I could see nothing but flames 

way past the crown.” The noise, heat, and smoke were ferocious. The deck was slick, 

almost an inch and a half deep with something thick like mucus. Bertone thought to 

himself as he tried not to slip, “Why is all this snot on the deck.” They passed the blowoutpreventer house, a huge door that seemed 80 to 90 feet tall and 50 feet wide; they looked 

down into the moon pool and saw only solid flames.149 

Inside the standby generator room, Bertone flipped the switch from automatic to manual, 

hitting the reset and the start button. “There was absolutely no turning over of the 

engine. I tried it again, the reset button and the start. Again, nothing happened.” He reset 

other functions, and turned the switch for the automatic sync on the standby generator 

to manual. “I ran back to the panel and again, tried the reset and the start. There was 

no turning over of the engine whatsoever.” They made yet another effort using different 

batteries. Nothing. Bertone yelled, “That’s it. Let’s go back to the bridge. It’s not going to 

crank.”150

When they opened the water-tight door to walk back out to the bridge, the heat struck like 

a blast furnace. The derrick fire roared into the sky, billowing black smoke. The rig had not 

unlatched from the well. On the bridge, Kuchta was standing with the door open watching 

the lifeboat station. The first lifeboat had departed, while the second vessel was visible in 

the burning water just pulling away from the rig.151

Bertone returned to the bridge, looked through the open door, and yelled to Williams 

and Meinhart, “That’s it, abandon ship. Let’s go.” He turned to Keplinger and Fleytas, 

still manning their radios. He shouted over the noise, “That’s it. Abandon ship. Let’s go, 

now.”152

* * * * 

Randy Ezell had stayed with Wyman Wheeler in the blasted-out hallway in the dark. “I 

told him I wasn’t going to leave him and I didn’t. And it seemed like an eternity, but it was 

only a couple of minutes before they [Murray and Carden] came back with the second 

stretcher. We were able to get Wyman on that stretcher and we took him to the bow of the 

rig.” They emerged from the living quarters to feel the blast of the fire roaring skyward, 

the sound deafening, the heat roasting. “[T]he first thing I observed is both of the main 

lifeboats had already been deployed,” said Ezell, “and they left. I also looked to my left and 

I saw Captain [C]urt and a few of his marine crew starting to deploy a life raft. And we 

continued down the walkway till we got to that life raft and we set the stretcher down.”153

They got a life vest onto Wheeler.154
16 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Chief Mate David Young and Bertone “hooked the life raft up and proceeded to crank it up 

out of its lift, rotated [it] around to the side of the rig and then drop[ped] it—drop[ped] it 

out so that you could inflate the raft and you could be clear of the rig.” A rope attached to 

a balky shackling device refused to give. Bertone yelled for a knife to cut the rope. Nobody 

had one. No pocket knives were allowed on the rig. Williams found a gigantic nail-clipperlike device and used it to unscrew the stuck shackle, freeing the rope. The life raft moved 

out over the side of the rig. Young got in. Behind them, explosions punctuated the heat, 

noise, and dark. Thick, acrid smoke was rolling over the deck.155

Bertone rushed over to the gurney and with Ezell’s help maneuvered Wheeler toward the 

raft. The two men shoved Wheeler off and in. More explosions and searing heat engulfed 

them. The flames were spreading further up and around the rig toward them. Bertone 

leaped in the life raft. Even through his leather gloves he could feel the heat. Fleytas jumped 

in and the raft lurched back and forth. She cried out, “We’re going to die. We’re going to 

die.” Bertone felt the same way as the raft filled with smoke and the flames leapt closer. “I 

honestly thought we were going to cook right there.” The life raft rocked back and forth in 

the air between the rig decks, and then began—herky-jerky—to descend. 156

They touched the water, which was ablaze. Someone yelled, “Where are the paddles?” 

Bertone jumped out and grabbed the rope and began swimming, pulling the life raft away 

from the rig. Murray and Minehart jumped into the water to help pull the raft along. 

Bertone looked up and saw “a tremendous amount of smoke bellowing out from under the 

rig.” At that moment boots appeared out of the smoke: it was Captain Kuchta, jumping 

into the water. Unable to get into the raft in the confusion, he leaped over 100 feet. He 

splashed into the Gulf five feet from Bertone. Then a second person came flying through 

the air, out of the thick smoke, crashing into the water: Keplinger had jumped, too.157

By now, Bertone and his men had managed to pull the life raft far enough away from the 

rig that they could see the circular helipad silhouetted against the flames. Bertone could see 

someone running at full speed across the helipad deck and then leaping off the rig. It was 

Mike Williams, the electronics technician.158 Williams splashed down nearby, resurfaced, 

and began swimming toward the Bankston.

159

Bertone felt the life raft no longer moving forward.160 So did Fleytas. She rolled out of the 

raft into the water and began to swim.161 Someone hollered, “The painter line is tied to the 

rig.”162 Bertone could see the painter line go taut. Murray screamed, “Help. We need help 

over here.”163

Bertone spotted the Bankston’s fast rescue craft, its two lights flashing 50 or 60 yards 

away. The boat had stopped to haul two men from the water. Bertone and others 

screamed, “We need a knife. We need a knife.” As the rescue craft neared, Kuchta swam to 

get a large foldable pocket knife, swam back, and cut the rope.164 Heat and smoke boiled 

out from the rig.

Murray and Carden tied a rope to the fast rescue craft, which towed them to the Bankston. 

Bertone helped lift the injured man (whom he finally learned was Wheeler) onto a stretcher 
Chapter One 17 17

on the flat bottom of the rescue craft.165 The Bankston crew then used its crane to gently 

lift the stretcher to the deck. By 11:45 p.m., the life boats were empty. 

Captain Kuchta went directly to the bridge, where he worked with others “to see who had 

firefighting capacity,” among other matters.166 Sims and Winslow were already there, 

organizing BP’s and Transocean’s response.167 Harrell remained on the main deck with 

the traumatized rig crew, many still half dressed, lacerated, or soaked from being in the 

sea. The crew filled the 260-foot Bankston’s lounge, galley, and parts of the main deck, 

including a temporary medical area.168 Some lay in the bunks.169 The Bankston crew pulled 

out whatever dry clothes and boots they had, and handed them to the survivors.170 With 

both life vessels and the life raft secured to the Bankston, the Deepwater Horizon leaders 

could try to take muster.171 There had been 126 people on the rig when the well blew 

out.172 In the confusion, no one yet knew exact counts, but conspicuously missing were 

those working the drill floor.

* * * * 

The Bankston was now jammed with the survivors.173 Some cried, others prayed—

grateful to be alive. Bertone went out to the makeshift hospital on the main deck to tend 

to Mansfield, prostrate on the floor, his head swathed in bandages and gauze, his neck in 

a brace, his mouth covered with an oxygen mask. Bertone stayed with him, adjusting his 

oxygen mask and keeping him conscious. On a bed nearby was Buddy Trahan and Bertone 

talked to him, to keep him awake, too.174

When the first Coast Guard helicopter arrived at 11:22 p.m., it lowered a “rescue 

swimmer” to oversee medical evacuation of the injured.175 Bertone helped to move Trahan, 

who was severely injured, onto a gurney.176 More helicopters would be coming to 

evacuate the 16 injured crew members to hospitals on the mainland.177 

On board the Bankston, the atmosphere was grim. The crew was forbidden to call home 

until there was more definitive information. 178 By 11:30 p.m., the managers had taken 

a final muster and 11 men were missing: Jason Anderson, Dale Burkeen, Donald Clark, 

Stephen Curtis, Roy Kemp, Gordon Jones, Karl Dale Kleppinger, Blair Manuel, Dewey 

Revette, Shane Roshto, and Adam Weise. 

The survivors sat on the boat in shock and watched the firestorm on the rig rage unabated, 

its plume of black smoke boiling up high into the night. At 1:30 a.m., the rig listed and 

rotated in the wake of more secondary explosions. Work boats, which had begun arriving 

and spraying water on the rig in response to the Mayday call, moved back.179 By 2:50 

a.m., the Deepwater Horizon had spun 180 degrees and, its dynamic positioners dead, 

moved 1,600 feet from the well. By 3:15 a.m., when the U.S. Coast Guard cutter Pompano

arrived on the scene,180 the rig was listing heavily. Dennis Martinez realized his dead 

father’s ring, which he removed only when working, was still on the rig.181

The three men in the Ramblin’ Wreck had continued to scour the waters near the rig, 

looking for survivors or the dead. Several times, they spotted what they thought might be 
18 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

a body, only to find it was debris.182 They heard rumbling sounds coming from deep below 

the surface of the water—possibly underwater explosions as the rig burned, exploded, 

listed, and drifted. Frightened, they still kept to their search. After rescue boats came on the 

scene, they ferried medical supplies between one of those and the Bankston. At 3:00 a.m., 

the three fishermen headed home.

On the Bankston, the Deepwater Horizon crew deeply wished they could do the same. As 

the largest boat in the vicinity, the Bankston had been ordered by the Coast Guard to stay 

put while the search and rescue effort unfolded. The search helicopters buzzed overhead, 

methodically surveying one sector after another. Once the 16 injured were evacuated, said 

Bertone, “[I] made my way up to one of the upper levels and sat there and watched the rig 

burn.”183 As oil and gas exploded up and out of the riser, the towering flames set fire to 

tanks and pipes, sending yet more roiling black smoke high into the sky. 

Sitting there hour after hour watching the conflagration with all its cascading smaller 

explosions was “one of the most painful things we could have ever done,” said Randy 

Ezell. “To stay on location and watch the rig burn. Those guys that were on there were 

“I could see nothing but flames way past the crown,” chief engineer Steve Bertone recalled of the dramatic moments before he ordered 

crew members to abandon the rig. Of the 115 survivors, 16 were seriously injured and medevaced to hospitals. Ninety-nine others, including 

Bertone, were transported to the mainland by the rescue vessel Bankston. Roughly 36 hours after the first explosion, Deepwater Horizon

sank to the bottom. It was April 22—Earth Day. 

Gerald Herbert/Associated Press
Chapter One 19 19

our family. It would be like seeing your children or your brothers or sisters perish in that 

manner. And that—that put some mental scarring in a lot of people’s heads that will never 

go away. I wish that we could, to the bare minimum, have moved away from the location 

or something where we didn’t just have to sit there and review that many hours. That was 

extremely painful.”184

Not until 8:13 that morning, when many boats were on the scene, did the Bankston get 

permission to set sail with the 99 survivors on board for Port Fourchon, Louisiana, the 

sprawling oil-supply depot that was its home base. The Coast Guard’s coordinated search 

had located no further crew—dead or alive. An hour into the Bankston’s 114-mile journey 

back to shore, it stopped at the Ocean Endeavor rig to take on two medics.185 BP’s Sims 

and Transocean’s Winslow, along with subsea engineers Mark Hay and Chris Pleasant, 

debarked to await the Max Chouest. They would return to the burning rig and dispatch a 

remotely operated vehicle down to the burning rig’s blowout preventer. The plan was to 

activate it with a so-called “hot stab” of hydraulic fluid to finally close in the wellhead.186

It was a clear spring day as the Bankston sailed along through the Gulf, passing the 

many offshore platforms that dot its blue waters. At 2:09 p.m., the Bankston pulled in 

at the gargantuan Matterhorn production rig to take on more supplies: tobacco, water, 

and coveralls.187 Officials from the Coast Guard and Minerals Management Service 

also boarded. There was still almost a 12-hour journey to Port Fourchon. Officials 

intended to gather information while memories were still fresh. At 6:35 p.m., the federal 

officials began conducting interviews, asking each crew member to write a witness 

statement describing the events they experienced leading up to the blowout and then the 

abandonment of the rig. The Bankston chugged toward the Louisiana coast as night fell. 

The crew, speaking among themselves, wondered how such a calamity had befallen their 

rig.

At 1:27 a.m. on Earth Day, Thursday, April 22, 27 hours after the crew had fled the 

exploding Deepwater Horizon, the Bankston berthed in slip 1 at the C-Port terminal at Port 

Fourchon.188 The exhausted men and women walked on to land. Arrayed before them was 

a table stacked with forms and surrounded by uniformed officials and company managers. 

Beyond that stood a long row of portable toilets. As each crew member walked up, he 

or she was handed a small plastic cup. Per federal regulations, they would all be drugtested.189 The investigation of the Deepwater Horizon disaster had begun. 

Chapter Two 21 21

The History of Offshore Oil and Gas 

in the United States 

March 1938 was an eventful month in the 

history of oil. Mexico nationalized its oil industry, 

establishing a precedent. Standard Oil of California 

(which later became Chevron) completed the first 

discovery well in Saudi Arabia—still the greatest oil 

find on record today. And during that same month, 

the first production of offshore oil took place in the 

Gulf of Mexico. 

Beginning in the 1890s, oil companies had 

drilled wells in the ocean, but from wooden 

piers connected to shore. In the 1930s, Texaco 

and Shell Oil deployed moveable barges to drill 

in the south Louisiana marshes, protected from 

extreme conditions in the ocean. In 1937, two 

independent firms, Pure Oil and Superior Oil, finally 

plunged away from the shoreline, hiring Texas 

construction company Brown & Root to build the 

first freestanding structure in the ocean. It was 

located on Gulf of Mexico State Lease No. 1, in 14 

feet of water, a mile-and-a-half offshore and 13 

miles from Cameron, Louisiana, the nearest coastal 

community. In March 1938, this structure brought 

in the first well from what was named the Creole 

Field.1

Chapter Two

“Each oil well 

has its own

personality”

Getting their feet wet for the first time, oil derricks march into the Pacific and the 

Summerland Oil Field near Santa Barbara, California, at the start of the 20th century. Over the next decades, innovation followed offshore innovation, propelling 

the industry and helping fuel the nation’s remarkable economic expansion. Yet 

as companies drilled ever deeper and farther from shore, technological hurdles 

rose ever higher—and risks grew ever greater. 

G.H. Eldridge/U.S. Geological Survey 
22 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

The Creole platform severed oil extraction from land—and did so profitably, setting in 

motion the march of innovation into ever-deeper waters and new geological environments 

offshore. The Gulf of Mexico, where offshore drilling began, remained a vital source of oil 

and gas for the United States. The large, sand-rich depositional system of the Mississippi 

River that spilled onto the continental margin for tens of millions of years created a worldclass petroleum province. The salt domes that pocked the Gulf basin provided excellent 

traps for hydrocarbons. Prior to 1938, oil hunters had made hundreds of discoveries on 

domes under the Louisiana and Texas coastal plain. There was no reason to believe that this 

geology would stop at the shoreline. 

The Creole platform highlighted the risks as well as rewards encountered offshore. A 

hurricane knocked out many of the pilings during construction. The lack of crew quarters 

on the platform created hardship for workers commuting to and from shore on shrimp 

boats. Many more challenges lay ahead as the marine environment imposed unique 

hazards on oil companies trying to adapt land-drilling methods offshore. They would 

have to squeeze complex drilling and production facilities onto small standing or floating 

platforms in a region exposed to hurricane-force winds and waves. High costs intensified 

pressures to find speedy solutions to problems and get the oil flowing. The remoteness 

of facilities and their space constraints amplified the perils of working under adverse 

conditions with dangerous equipment and combustible materials. “Nobody really knew 

what they were doing at that time,” recalled a member of Kerr-McGee’s earliest offshore 

drilling crew. “It was blow-by-blow. And it wasn’t easy living out there.”2

As geologists and drillers made discoveries in deeper water, development would stall at 

a limiting depth, sometimes for several years, until advances were made in production 

technology to catch up with exploration. Blowouts, drilling-vessel disasters, and platform 

failures often forced engineers back to the drawing board. Steadily, the offshore industry 

pioneered ways to meet economic and environmental challenges offshore, first in the Gulf 

and then around the world. But the risks never went away.

Wading Into Shallow Water 

On August 15, 1945, the day after the Japanese surrender in World War II, the U.S. 

government lifted gasoline and fuel-oil rations. In the first five years after the war, 

Americans bought an astounding 14 million automobiles, increasing the number of cars in 

service to 40 million. By 1954, Americans were purchasing 7 million tankfuls of gasoline 

per day.3 This booming demand for gasoline, coupled with growing use of home heating 

oil, vaulted petroleum ahead of coal as the leading source of energy in the United States.

Early Technologies 

To meet soaring demand, oil firms embarked on a quest to find new reserves. The intrepid 

ones returned to the Gulf to drill on leases offered by Louisiana—and made use of wartime 

technologies and equipment. Sonar and radio positioning developed for warfare at sea 

proved valuable for offshore exploration. The Navy trained schools of divers in underwater 
Chapter Two 23 23

FIGURE 2.1: Timeline of Major Events

1896 First offshore oil production in the United States—from wooden piers off 

 Summerland, California

1938 First Gulf of Mexico discovery well in state waters; first free-standing production 

 platform in the ocean—Creole field offshore Louisiana

1947 First well drilled from fixed platform offshore out-of-sight-of-land in Federal waters 

 —Kermac 16 offshore Louisiana

1953 Submerged Lands Act & Outer Continental Shelf Lands Act

1954 First federal Outer Continental Shelf lease sale & Maiden voyage of the Mr. Charlie 

 submersible drilling vessel, industry’s first “day rate” contract 

1962 First semi-submersible drilling vessel, Blue Water 1, and first subsea well 

 completion

1969 Santa Barbara blowout/oil spill (California)

1978 Shell Oil Company’s Cognac production platform (first in 1,000 feet of water) 

 & OCS Lands Act Amendments

1981 First Congressional Outer Continental Shelf leasing moratorium

1982 Creation of the Minerals Management Service (MMS)

1988 Piper Alpha disaster in the North Sea

 

1994 First production from Shell’s Auger tension-leg platform in 2,860 feet of water

1995 Deepwater Royalty Relief Act

1996 First spar production facility in the Gulf of Mexico at the Neptune field

1999 Discovery of BP’s Thunder Horse field in 6,000 feet of water; at 1 billion barrels of oil 

 equivalent, the largest discovery in the Gulf of Mexico

2006 Successful test at the Jack 2 field, in 7,000 feet of water and more than 20,000 feet 

 below the seafloor, establishing the viability of the deepwater Lower Tertiary play

2010 Arrival of Deepwater Horizon at Macondo well in January

History of Offshore Oil and Gas in the United States
24 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

salvage operations and introduced new diving techniques, seeding the diving business that 

became vital to offshore operations. Construction companies, such as Brown & Root and 

J. Ray McDermott, and numerous boat operators acquired war-surplus landing craft and 

converted them to drilling tenders, supply and crew boats, and construction and pipelaying 

vessels.4

In 1947, Kerr-McGee Oil Industries drilled the first productive well “out-of-sight-of-land,” 

on a platform located in 18 feet of water, 10.5 miles off the Louisiana coast in the Ship 

Shoal area. The Kermac 16 platform used a war-surplus tender barge to house drilling 

mud and other supplies, plus the workers’ quarters, thereby reducing the size and cost of a 

self-contained drilling and production platform—an important advantage in case of a dry 

hole. In 1948, Humble Oil (the Texas affiliate of Standard Oil of New Jersey, later renamed 

Exxon) introduced the concept of latticed steel templates, or “jackets,” which provided 

greater structural integrity than platforms built with individual wood piles.5

Drilling Revived

To explore and develop their new leases obtained from the federal government (see Chapter 

3 on the origin of federal leasing), oil firms tapped into the Gulf Coast oil-service sector, 

but they also promoted the formation of a distinct offshore industry by contracting 

out for specialized services in marine geophysical surveying, offshore engineering and 

construction, transportation (boats and helicopters), diving, and mobile drilling.6

Mobility in drilling was crucial to the offshore industry’s long-term viability. The costs 

of drilling exploratory or “wildcat” wells from fixed platforms, most of which would not 

discover oil, were prohibitive. In 1954, the Offshore Drilling and Exploration Company 

capitalized on a novel approach to the quest for mobility, using its $2 million Mr. Charlie 

“submersible” drilling barge. Mr. Charlie’s hull could rest submerged on the bottom in 30 

feet of water for drilling, and then be refloated and moved to other locations, like a bee 

moving from flower to flower to extract nectar. Working for Shell Oil on the industry’s 

first “day-rate” contract ($6,000 per day), Mr. Charlie drilled and developed two of 

the Gulf Coast’s largest oil fields, in the East Bay just off the South Pass outlet of the 

Mississippi River. “That’s a great rig you have there!” exclaimed Shell’s New Orleans vice 

president after the first well. “I can see the day when you will need several more of them.”7

Giant salt-dome fields discovered offshore Louisiana—Shell’s East Bay and West Delta, the 

California Company’s (Chevron) Bay Marchand and Main Pass, Magnolia’s (Mobil) Eugene 

Island, and Humble Oil’s Grand Isle, all under less than 30 feet of water—encouraged 

operators to move farther out in the Gulf. As Offshore Drilling and Exploration expanded 

its submersible fleet, other companies such as the Zapata Offshore Company (formed in 

1954 by future U.S. President George H.W. Bush), experimented with “jack-up” rigs. These 

rigs jacked their platforms out of the water by extending a series of cylindrical or trusstype legs to the bottom, taking drilling into water depths exceeding 100 feet. By 1957, 23 

mobile units were operating along the Gulf and 11 more were under construction.8

Drilling offshore was a relatively costly proposition in the 1950s (a Gulf oil executive 

described it as “a billion-dollar adventure in applied science”9), but it was astoundingly 
Chapter Two 25 25

successful. In 1956, 26 percent of offshore exploratory wells struck oil and gas, compared 

to just 11 percent onshore. Of these wells, 1 in 20 discovered fields with more than 50 

million barrels of reserves—more than five times the equivalent success rate of onshore 

wells. By 1957, there were 446 production platforms in federal and state waters. Wells 

offshore Louisiana and Texas were producing 200,000 barrels a day, feeding the vast 

refinery complexes that already existed along the Mississippi River between New Orleans 

and Baton Rouge, in the “Golden Triangle” of coastal East Texas (Beaumont–Port Arthur–

Orange), and along the Houston Ship Channel. Offshore wells accounted for 3 percent of 

total U.S. production, but the percentage was rising.10

Pushing Beyond Limits

In the late 1950s, the frantic pace of Gulf offshore exploration slowed. Costs increased 

significantly in water depths beyond 60 feet (then the definition of “deepwater”). A few 

jack-up rigs capsized in rough seas. After Glasscock Drilling Company’s Mr. Gus drilled 

a $1 million dry hole for Shell in 100 feet of water in 1956, the vessel sank in transit 

a year later during Hurricane Audrey. Beyond the damage to offshore infrastructure, 

Audrey destroyed the support center of Cameron, Louisiana, where an estimated 500 

people tragically perished. Underwater pipelines, necessary for bringing oil to shore, were 

expensive and tricky to place in deeper water. A national recession in 1958, an oversupply 

of crude oil from growing imports, and declining finds in deeper waters tempered 

enthusiasm for new exploration. At the same time, Louisiana’s legal challenge to the statefederal boundary offshore delayed federal lease sales for several years beginning in 1955. 

Some people in industry thought this did not matter: they believed offshore exploration 

had reached its limits.11 Others were more optimistic.

Shell’s Frontier Technology and the 1960s Boom

In August 1962, after seven years of research and development, Shell announced it had 

successfully tested a new kind of “floating drilling platform,” redefining the marine 

geography of commercially exploitable hydrocarbons. The Blue Water 1 was a converted 

submersible consisting of three large columns on each side that connected the drilling 

platform to a submerged hull. Giant mooring lines kept the vessel on position. Until then, 

companies had been experimenting with ship-shaped vessels called “drillships” to explore 

in water depths beyond 150 feet, but these could not withstand heavy wave action. 

Because the Blue Water 1’s hull could be ballasted to rest safely below wave level, the 

vessel was remarkably stable. Classified as the first “semisubmersible,” the Blue Water 1

made its successful test in 300 feet of water, and it was equipped to operate in 600 feet. 

Complementing the new floating platform, Shell tested the first successful subsea wellhead 

completion using remote controls. As one Shell representative told reporters, “We’re 

looking now at geology first, and then water depths.”12

The achievement was akin to John Glenn’s space orbit the same year. Even more 

astonishing was Shell’s decision, in early 1963, to share its technology with other 

companies. At its three-week “School for Industry,” seven companies and the U.S. 
26 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Geological Survey paid $100,000 each to learn about Shell’s “deepwater” drilling 

program—thereby ensuring that suppliers and contractors were up to speed and that there 

would be at least some competition from other oil companies for deepwater leases (which 

otherwise would not be awarded at auction). The diffusion of Shell’s technology led to 

the construction of semisubmersibles in Gulf Coast shipyards and enabled the industry to 

move into deeper water.13

Federal policies also helped accelerate offshore exploration and development. Oil import 

quotas went into effect in 1959 and were tightened in 1962. These measures protected the 

domestic market for higher-cost offshore oil. In 1960 and 1962, sensing pent-up demand 

after the hiatus in federal leasing during the late 1950s, the Bureau of Land Management 

auctioned large swaths of Gulf acreage. The response was overwhelming: in the historic 

March 1962 sale, 411 tracts, totaling nearly two million acres, were leased—more than in 

all previous sales combined. The sale opened up new areas off western Louisiana and Texas 

and extended the average depth of leases to 125 feet. Because so much land was put up 

for auction, the “cash bonus” price for the average lease was driven down, enabling more 

companies to participate in the Gulf.14 

Drilling on that vast inventory of leases set off one of the greatest industrial booms 

the Gulf Coast had ever seen. By September 1963, nearly 90 drilling operations were in 

progress. Workers flocked from around the Gulf region to take high-paying jobs offshore 

or in the growing support centers of New Orleans, Morgan City, Lafayette, Beaumont, 

and Houston. Although exploratory success offshore Louisiana in the immediate years 

after 1962 could not match the extraordinary record of the late 1950s, the discovery rate 

for large fields of 100 million barrels or more was impressive: 155 for offshore Louisiana 

versus 3,773 for the United States as a whole. By 1968, 14 of the 62 large fields discovered 

in the United States were offshore Louisiana, and 11 of those 14 lay either wholly or 

partially within federally administered areas. Total offshore production from the Gulf of 

Mexico rose from 348,000 barrels per day in 1962 (4.8 percent of total U.S. production) to 

915,000 barrels per day in 1968 (8.6 percent of the U.S. total), and most of this increase 

came from federal areas, especially acreage leased in 1962.15

The March 1962 sale had another consequential effect onshore: the $445 million in cash 

bonuses earned by the government alerted many officials to the importance of outer 

continental shelf leases as a source of federal revenue. The next year, the Bureau of Land 

Management opened an office in Los Angeles and offered the first oil and gas leases off the 

coasts of Oregon and Washington. Three years later, the Bureau offered the first leases in 

California’s Santa Barbara Channel. The federal outer continental shelf leasing program 

thus took on national scope.16

Pushing Technological Frontiers—and Physical Limits

Meanwhile, technological innovations revitalized the Gulf offshore industry and generated 

interest in other ocean basins. New well designs and well-logging techniques resolved 

deep subsurface drilling problems and reduced well costs. Drilling experiments in extreme 

water depths, such as Project “Mohole” funded by the National Science Foundation, set the 

stage for dramatic advances in future oil exploration. In 1962, Shell equipped the drillship 
Chapter Two 27 27

Eureka with the first automatic dynamic positioning system and embarked on a coredrilling program in 600 to 4,000 feet of water in the Gulf. Eureka’s cores confirmed for the 

first time that oil had been generated in the sands that the Mississippi River had deposited 

over eons in the broad alluvial valley extending beyond the continental shelf into the 

deep Gulf. Then, beginning in 1968, the Joint Oceanographic Institutions for Deep Earth 

Sampling project launched the famous voyage of the Glomar Challenger drillship, whose 

core samples gave further evidence of oil generation in extreme ocean depths.17

Although exploratory drilling capabilities raced ahead of commercial producing depths—a 

recurring theme in the history of offshore oil—the industry nevertheless made great 

advances during the 1960s in all phases of offshore exploration and production. Among 

other innovations, digital sound recording and processing greatly enhanced the quality 

of seismic data and fortified geoscientists’ ability to interpret subsurface geology. 

Improvements in soil-boring techniques led to greater understanding of seabed soil 

mechanics and foundations. Higher-strength steel yielded stronger jacket construction 

and the use of larger equipment to install larger rigs. Digital computers made possible 

the three-dimensional modeling of platform jacket designs. Together, these developments 

moved production operations into 350-foot water depths by 1969.18

Toward the end of the decade, however, the cost of bringing in productive leases began 

to outrun the price of oil, which had remained at $2 to $3 per barrel in the United States 

since the end of World War II. Many of the large, easy-to-identify structures in the Gulf 

had been picked over and drilled. Some companies were fooled by geology into making 

costly mistakes. At a federal offshore Texas sale in 1968, for example, a Humble-Texaco 

partnership staked $350 million on leases that yielded nothing. Offshore Texas, it turned 

out, proved to be largely gas-prone, but regulated prices made natural gas less profitable 

than oil.19

Hurricanes wreaked havoc with production. In 1961, Hurricane Carla triggered soil 

movements in the Mississippi Delta that destroyed a large number of pipelines. Hilda 

(1964) and Betsy (1965) knocked out 20 platforms and damaged 10 others, as 70-foot 

wave heights, far exceeding earlier estimates, overwhelmed platform decks. Camille (1969), 

a Category 5 hurricane, passed directly over 300 platforms, most of which survived the 

waves, but the storm caused violent mud slides that wiped out three large platforms in 

300 feet of water.20

On top of the business failures and natural disasters, the sheer technological challenges 

and the necessity to complete work as quickly as possible compromised safety. Project 

profitability depended on how soon production could be brought online. Drilling vessels 

were contracted on day-rates, increasing time pressures. Production processes were highly 

interdependent: delay in one place could cause delays elsewhere. So there were relentless 

demands to drill the wells, install the platforms, and get the oil and gas flowing. “When 

I first started working, they didn’t care whether they killed you or not!” remembered one 

offshore veteran. “In other words, ‘we are going to get it done, regardless.’ There was no 

suing like people are suing now. Back then, if you got hurt, they just pushed you to the 

side and put somebody else in.”21
28 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Accident rates for mobile drilling vessels remained unacceptably high, especially for jackups. Blowouts, helicopter crashes, diving accidents, and routine injuries on platforms 

were all too common. Facilities engineering on production platforms was a novel concept. 

Platforms often had equipment squeezed or slapped together on the deck with little concern 

or foresight for worker safety. Crew quarters, for example, could sometimes be found 

dangerously close to a compressor building.22

Federal oversight followed the philosophy of “minimum regulation, maximum 

cooperation.”23 Between 1958 and 1960, the U.S. Geological Survey Conservation Division, 

the regulatory agency then overseeing offshore drilling, issued outer continental shelf 

Orders 2 through 5, requiring procedures for drilling, plugging, and abandoning wells; 

determining well productivity; and the installation of subsurface safety devices, or “storm 

chokes.” But the Offshore Operators Committee (representing leaseholders) persuaded 

regulators to dilute Order 5 to permit waivers on requirements for storm chokes. 

Significantly, the orders neither specified design criteria or detailed technical standards, 

nor did they impose any test requirements. Companies had to have certain equipment, 

but they did not have to test it to see if it worked.24 In general, as a 1973 National 

Science Foundation study concluded, “the closeness of government and industry and the 

commonality of their objectives have worked against development of a system of strict 

accountability.”25

Lax enforcement contributed to the lack of accountability. The U.S. Geological Survey 

freely granted waivers from complying with orders and did not inspect installations 

regularly. Federal and state regulatory bodies were underfunded and understaffed. In 1969, 

the Gulf region’s lease management office had only 12 people overseeing more than 1,500 

platforms. Even those trained inspectors and supervisors often lacked experience in the oil 

business and a grasp of its changing technological capabilities. “Each oil well has its own 

personality, is completely different than the next, and has its own problems,” observed one 

consultant in 1970. “It takes good experienced personnel to understand the situation and 

to cope with it.” Too often on drilling structures, he complained, one found inexperienced 

supervisors; employees who overlooked rules and regulations (the purpose of which 

they did not understand); and, perhaps most troubling, even orders from bosses to cut 

corners—all of which created conditions for an “explosive situation.”26

Explosive Situations

On January 28, 1969, a blowout on Union Oil Company Platform A-21 in the Santa 

Barbara Channel released an 800-square-mile slick of oil that blackened an estimated 30 

miles of California beaches and lethally soaked sea birds in the gooey mess. Although the 

well’s blowout preventer worked, an inadequate well design allowed the hydrocarbons 

to escape through near-surface ruptures beneath the seafloor. Union Oil had received a 

waiver from the U.S. Geological Survey to set casing at a shallower depth than required 

by Order 2, highlighting the lack of accountability that had come to characterize offshore 

operations.27 The 11-day blowout spilled an estimated 80,000 to 100,000 barrels of oil28—
Chapter Two 29 29

the largest offshore drilling accident in American waters until the Macondo blowout. It 

generated intense opposition to offshore oil in California, but the fallout also reverberated 

nationally, setting the stage for the passage of the National Environmental Policy Act 

(NEPA), a symbol of the growing strength of the national environmental movement, as 

well as a host of other increasingly demanding environmental protection laws throughout 

the 1970s (See Chapter 3).29

Offshore operators suddenly faced a potentially hostile political and regulatory climate. 

Ten days after the accident, Secretary of the Interior Walter Hickel, with the support of 

President Richard Nixon, issued a moratorium on all drilling and production in California 

waters. In April, Secretary Hickel completed a preliminary assessment of the leases affected 

by the moratorium and allowed 5 of the 72 lessees to resume drilling or production. In 

August, the Interior Department issued completely revised outer continental shelf Orders 

1–7—the first update since the orders were established—with more specific requirements 

about company plans and equipment for prevention of pollution and blowouts. It also 

issued new Orders 8 and 9 on the installation and operations of platforms and pipelines. 

These were the first rules in which the department claimed authority to prohibit leasing in 

areas of the continental shelf where environmental risks were too high.30 

The industry protested the new outer continental shelf regulations, but calamities in the 

Gulf undermined its case. In February 1970, Chevron’s Platform C in Main Pass Block 41 

blew out and caught fire. The spill forced a postponement of a federal lease sale, damaged 

SANTA BARBARA OIL SPILL

Oil from a ruptured well surrounds a platform six miles off the coast of Santa Barbara. The 1969 spill, an estimated 100,000 barrels, was the 

largest in U.S. waters prior to 2010. Some 30 miles of shoreline were fouled, and thousands of birds died along with fish, dolphins, and sea 

lions. The incident drew public outcry and triggered environmental-protection legislation. Today, Platform A-21 is still operating. 

Associated Press
30 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

wildlife, and drew a $31.5 million suit against the company by Louisiana oyster fishermen 

and a $70 million suit from shrimp fishermen. Chevron was also fined $1 million for 

failing to maintain storm chokes and other required safety devices—the first prosecution 

under the 1953 Outer Continental Shelf Lands Act. The Justice Department also obtained 

judgments against other major oil and gas companies for similar violations. Then, in 

December, Shell suffered a major blowout on its Platform B in the Bay Marchand area, 

killing four men and seriously burning and injuring 37 others. Investigators attributed the 

accident to human error resulting from several simultaneous operations being performed 

without clear directions about responsibility. It took 136 days to bring 11 wild wells under 

control, at a cost of $30 million. The failure or leaking of subsurface-controlled storm 

chokes contributed to the size of the conflagration.31

In the wake of these disasters, the government further strengthened its regulatory 

program. The Interior Department again revised and expanded outer continental shelf 

orders to mandate new requirements: surface-controlled storm chokes; the testing of safety 

devices prior to and in use; more careful control of drilling and casing operations; prior 

approval of plans and equipment for exploration and development drilling; and updated 

practices and procedures for installing and operating platforms. To enforce the new 

regulations, the U.S. Geological Survey tripled its force of inspectors and engineers, ceased 

using industry-furnished transportation for inspections, and introduced a more systematic 

inspection program based on newly developed criteria.32

In response, the Offshore Operators Committee and the industry’s Offshore Safety and 

Anti-Pollution Equipment Committee worked closely with the U.S. Geological Survey both 

in advising changes in the outer continental shelf orders and in promptly drafting a new 

set of American Petroleum Institute (API) “recommended practice” guidance documents 

for the selection, installation, and testing of safety devices, as well as for platform design. 

The major offshore operators revamped personnel training for offshore operations, and 

they formed an organization called Clean Gulf Associates to upgrade oil-spill handling 

capabilities.33 Certifying agencies issued new standards and guidelines for mobile drilling.34

In addition, the industry’s annual Offshore Technology Conference, first held in 1969, 

became an important forum for publishing and sharing technical information that led to 

safer designs and operations.35

The industry’s safety record in the Gulf improved significantly after the new regulations 

and practices were introduced: the reported incidence and rate of fatalities and injuries 

decreased, as did the rate of fires and explosions.36 During the 1970s and 1980s, the 

frequency of blowouts did not decline significantly, but there was a sharp drop in the 

number of catastrophic blowouts, and fewer casualties and fatalities were associated with 

them.37

Design and equipment problems were steadily being solved. But reducing accidents caused 

by human error, poor safety management, or simultaneous operations continued to be a 

vexing challenge.

<
Chapter Two 31 31

Constrained Expansion

As new regulations brought more caution to offshore oil development, countervailing 

forces emerged to speed it up. Domestic oil supply could not keep up with demand. 

In the postwar period, Americans’ consumption of petroleum—largely for operating 

automobiles—climbed dramatically, rising steadily from 243 gallons of motor gasoline per 

capita in 1950 to 463 gallons per capita in 1979.38

U.S. oil production peaked, however, in 1970. Along with the OPEC oil embargo of 1973 

and consequent skyrocketing price of oil products, this event spurred the quest to develop 

new offshore reserves. With crude oil prices tripling to $10 per barrel, oil companies could 

justify more expensive offshore drilling and development. Under the mandate of “Project 

Independence,” the Nixon Administration announced a dramatic increase in the pace of 

leasing in the Gulf and a resumption of sales off the Atlantic, Pacific, and Alaskan coasts. 

At the March 1974 federal lease sale of offshore Louisiana acreage, the industry spent a 

record $2.17 billion in cash bonuses for leases covering 522,000 acres, including a few 

tracts ranging beyond 1,000-foot depths.39

The First Deepwater Play

In June 1975, Shell made a monumental discovery on one of those new leases. Shell 

geophysicists had employed an innovative seismic technique called “bright spot” to 

lead drillers to an attractive prospect, code-named Cognac, in 1,000 feet of water in the 

Mississippi Canyon, not far from the mouth of the great river. The drilling uncovered an 

estimated 100-million-barrel reserve.40 Cognac pioneered other discoveries in what would 

come to be known as the “Flex Trend,” an area in the Gulf that reaches just beyond the 

edge of the continental shelf, where there is a flex in the seafloor. The Flex Trend would 

be the world’s first true oil play in 1,000-foot water depths, the modern definition of 

“deepwater.”41

When Shell purchased its leases, it did not yet have a design concept for deepwater 

production. Barges were not big enough to launch a 1,025-foot steel jacket in one piece. 

Therefore, adapting Exxon’s precedent—the company installed its Hondo jacket in 850 feet 

of water in the Santa Barbara channel in 1976—Shell chose to build the Cognac structure 

in three pieces and assemble them vertically in place. The complex, nerve-wracking 

installation inflated total development costs to nearly $800 million. But Cognac was both 

a technical and commercial success. It won the American Society of Civil Engineers 1980 

award for “Outstanding Civil Engineering Achievement,” the first ever received by an oil 

company. Production commenced in 1979, just as the supply shock caused by the Iranian 

Revolution drove the price of oil to nearly $40 per barrel.42

Along with Hondo and major developments in the North Sea pioneered by Phillips, Conoco, 

and BP, Cognac paved the way for truly enormous offshore engineering-construction 

projects. In 1976, Brown & Root and J. Ray McDermott opened giant new construction 

yards at Harbor Island, near Corpus Christi Bay, to accommodate the assembly and 

load-out of deepwater structures. In these yards, they built jackets lighter and cheaper 
32 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

than Cognac and launched them in single pieces. In the late 1970s, Brown & Root built a 

700-foot structure for Chevron’s Garden Banks field, and a 650-foot jacket for Atlantic 

Richfield. In 1980–1981, McDermott built two platforms for Union Oil in the 1,000-foot 

waters of the East Breaks area, 100 miles south of Galveston. During 1979–1983, Brown 

& Root built and installed a novel “guyed tower” for Exxon in 1,000 feet of water just 

southwest of Cognac.43 

Even as rising oil prices and declining onshore production in the late 1970s spurred them 

on, Gulf oil operators encountered economic and geological constraints. Bonus bids soared 

beyond the estimated value of the oil that might be discovered and produced: the September 

1980 sale in New Orleans, for example, brought in $2.8 billion in cash bonuses, shattering 

all previous records. During the 1970s, the bonus paid per barrel of oil equivalent 

discovered by the largest producing companies increased four- to five-fold, undermining 

the economics of deepwater.44 Furthermore, initial production rates from some of the 

early producing wells in the Flex Trend proved disappointing. Many industry exploration 

managers came to believe that after 25 years of development, only lean prospects remained 

in the Gulf. The best hope for increasing national reserves, they concluded, was from other 

parts of the U.S. outer continental shelf.45

Beyond the Shelf

Rising lease bonuses still did not deter major companies (such as Chevron, Exxon, Mobil, 

and Amoco), along with some of the larger independents (such as Pennzoil, Union, and 

Tenneco), from drilling and developing fields in the deepwater Flex Trend. But discoveries 

could not offset overall production declines in the Gulf. Oil production on the shelf had 

peaked at just above 1 million barrels per day in 1972; by 1978, it had fallen below 

800,000 barrels per day. Because discoveries in the Flex Trend play were relatively small, 

with fairly low flow rates, most Gulf oil and gas still came from shallow water, despite 

declining overall production there. In 1970, the average production-weighted depth of oil 

extracted from the Gulf was just 100 feet, and by 1980 it was still less than 200 feet.46 

Many managers had concluded that there would never be economic developments more 

than 60 miles from shore. Other experts became convinced that significant oil-bearing 

sands would never be found beyond the continental shelf. “But what conventional wisdom 

really tells you,” as one Shell geophysicist explained, “is that you just don’t know what 

you don’t know.”47

At just that time, some scientists from industry and academia had begun to piece together 

a regional picture of the geology deep underneath the Gulf by combining information from 

cores with a regional seismic survey shot out into deepwater. This picture showed that 

massive salt pillars, or diapirs, had squeezed up from the mother layer of salt deposited 

beginning 165 million years ago, when the Gulf of Mexico was slowly forming. As the 

diapirs pinched up, sandstone overlaying the salt slowly subsided, forming cup-shaped 

“mini-basins” featuring different kinds of configurations for trapping oil. These sandstone 

formations were named “turbidites” (they had been deposited when ancient underwater 
Chapter Two 33 33

rivers, called turbidity currents, channeled huge volumes of sediment onto the continental 

margin). The structural anomalies in these mini-basins looked similar to productive 

features on the shelf, but the spotty seismic coverage allowed for only speculative 

knowledge of their potential, at best. Shell, always the leader in Gulf frontier exploration, 

had drilled a number of wells in similar rocks along the margin of the continental shelf. 

Turbidites in deepwater were potentially much larger, less faulted, and might have 

prolific flow rates. At least in theory, they would require fewer wells, making them more 

attractive as economically exploitable reservoirs of oil.48

During 1978–1980, hoping to test its theories about the regional geology, Shell nominated 

deepwater tracts for auction. But no other companies seconded its nominations, so the 

government never selected the tracts for sales.49 Then, in 1982, the Interior Department 

announced a new system of area-wide offshore leasing. This policy put into play entire 

planning areas (e.g., the central Gulf of Mexico) up to 50 million acres, rather than 

rationing tracts through a tedious nomination and selection process. Companies could bid 

on any tract they wanted in a lease sale for a given planning area, thus giving them access 

to far more extensive offshore acreage at significantly less cost.50

 

Strong political opposition to area-wide leasing by some coastal states and environmental 

organizations stymied its effective use in other parts of the nation (see Chapter 3), but 

not in the Gulf, where oil companies had long operated. Established infrastructure and 

abundant geological information there could be put to more flexible use under a more 

open system. Oil companies responded to area-wide leasing by bidding aggressively for 

attractive blocks on the continental shelf, while making a number of speculative bids on 

acreage ranging into 3,000-foot depths beyond the edge of the shelf. The May 25, 1983 

sale harvested a record $3.47 billion in high bonus bids. All told, in seven lease sales 

held from 1983 to 1985, the Interior Department, through the newly formed Minerals 

Management Service (see Chapter 3), leased 2,653 tracts, more than had been leased in all 

the federal sales since 1962 combined. About 600 of these tracts lay in deepwater beyond 

1,000 feet.51 

Shell acquired the lion’s share of deepwater tracts in the March 1983 sale and immediately 

started drilling. In 1982, it had leased Sonat Offshore Drilling’s Discoverer Seven Seas, one 

of the few vessels rated for 6,000-foot depths. Shell then spent more than $40 million 

to extend the vessel’s depth capability with a larger marine riser, enhanced dynamic 

positioning, and a new remote-operated vehicle to enable sophisticated work where human 

divers could not venture. In October 1983, the Seven Seas made a major discovery at 

Shell’s Bullwinkle prospect, establishing the deepwater “Mini-Basin Play,” which targeted 

the turbidite sandstones in the basins flanking the salt structures.52 

In the next central Gulf area-wide sale, in April 1984, many different operators jumped 

in to compete for deepwater tracts. This prompted Shell to move quickly in deploying the 

Shell America, a $45 million custom-designed, state-of-the-art seismic vessel that provided 

company geophysicists with high-quality, proprietary seismic data. Armed with these data 

and other intelligence gained from drilling its 1983 leases, Shell dominated the May 1985 

sale, winning 86 of 108 tracts on which it bid, in water depths ranging to 6,000 feet. For 
34 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Shell, pushing deeper was an imperative for its operations in the United States, as onshore 

reserves continued to decline. “Exploration has been called a poker game,” explained one 

Shell official. “But there’s more to it than that. In this game, we don’t have chips or coins 

or dollar bills that can change hands over and over again. We’re dealing with a declining 

resource base, and every barrel we find is never going to be found again.”53

The Era of Uncertainty

The long cycles of oil exploration and development do not always align well with the 

shorter cycles of the economy. Just as Shell bet heavily on deepwater, the severe recession 

in 1981 further depressed falling oil demand. For the first time in 34 years, U.S. oil 

consumption hit a plateau and began declining.54 The now “forgotten victory” of energy 

conservation and efficiency measures passed in the mid-1970s, in response to historically 

high oil prices, reversed the long trend of an increasingly petroleum-intense U.S. economy. 

During 1985–1986, oil prices collapsed to $10 per barrel, as international producers 

saturated the global market with crude.55

Expensive Gulf development projects were canceled or shelved. Construction of mobile 

drilling vessels and other kinds of offshore-servicing equipment fell sharply. Unemployed 

oilfield workers transitioned into new trades, or migrated from southern Louisiana in 

search of better opportunities. This human and capital flight marked the beginning of 

what one scholar called “the inevitable disassembly of the offshore system and its onshore 

support network for the Gulf of Mexico.”56 

The offshore projects that went forward faced intimidating challenges. Shell drilled 

some dry holes costing more than $10 million apiece. Development stretched the limits 

of technological and financial resources. To produce oil from the Bullwinkle field, the 

company installed in 1988 a $500 million fixed platform, 162 stories high—taller than 

Chicago’s Sears Tower (now the Willis Tower), the tallest building in the world at the time. 

The Bullwinkle platform was the largest and last conventional jacket of its kind. The scale 

and costs of constructing anything bigger were simply prohibitive.57

Moving deeper would require alternative production methods: subsea wells, tension-leg 

platforms, or floating systems. Operators had put subsea wells to use in the North Sea, 

but they were still extremely expensive. The tension-leg platform was an innovative 

concept consisting of a production facility situated on a floating hull held in place by long 

tendons that kept the hull from bobbing like a cork but allowed some degree of side-to-side 

motion. In 1984, Conoco installed the first full-scale design of this type in the North Sea, 

in 485 feet of water, and in 1989 the company placed its Jolliet mini-tension-leg platform 

in 1,760 feet of water in the Gulf.58 But tension-leg platforms would have to be scaled up 

for major projects in deepwater. In 1987–1988, Placid Oil developed a field in 1,500 feet 

of water with a floating production facility converted from a semisubmersible drilling 

vessel. But Placid soon abandoned the development, sold the semisubmersible, and sought 

bankruptcy protection.59
Chapter Two 35 35

The deepwater costs were matched by the safety and environmental risks. In 1985, an 

Office of Technology Assessment study of Arctic and deepwater oil drilling highlighted 

the “special safety risks” of “harsh environments and remote locations.” It identified “a 

need for new approaches to preventing work-related injuries and fatalities in coping with 

new hazards in the hostile Arctic and deepwater frontiers.” It also presciently warned of 

the glaring deficiencies in safety oversight offshore, observing that “there is no regulatory 

requirement for the submission of integrated safety plans which address technical, 

managerial, and other aspects of offshore safety operations.”60 

Setbacks in the Arctic

As the study indicated, deepwater was not the only frontier that captured the industry’s 

interest. In the 1980s, companies also had their sights set on the Arctic region, then 

thought to have the highest resource potential in the United States. Since the 1960s, major 

firms had produced oil from Alaska’s Kenai Peninsula and Cook Inlet. In 1977, the massive 

onshore Prudhoe Bay field on the North Slope started pumping oil through the TransAlaska Pipeline. Many explorers expected to find the next great oil frontier to the north 

of Prudhoe Bay, in the Bering, Beaufort, and Chukchi Seas. Although the industry lost a 

contentious struggle to gain access to the Bering Sea’s Bristol Bay, home to the world’s 

largest commercial salmon fishery, they did win the right to lease and drill in the Beaufort 

and Chukchi Seas.61

Deep Sea Monsters

DER SPIEGEL 19/2010
36 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Everywhere operators drilled offshore Alaska, however, they came up empty. Either they 

found no source rocks or the deposits they did find were not large enough at that time to 

turn a profit in the Arctic’s forbidding environment. After a costly dry hole at a prospect 

called Mukluk in the Beaufort Sea and some futile efforts to explore in the Chukchi 

Sea, the industry temporarily lost its craving for the Arctic. The public-relations fallout 

from the Exxon Valdez oil spill in 1989, which resulted in congressional and presidential 

moratoriums on leasing in Bristol Bay, contributed to the industry’s suspended interest in 

offshore Alaska.62

Renewed Focus on the Gulf of Mexico

The mid-1980s collapse in oil prices also ruined many companies’ appetite for further 

leasing in the deepwater Gulf of Mexico. But Shell and others chose to take a longer-term 

view—a decision reinforced by the failures in Alaska. Additional reinforcement came in 

1987, when the Minerals Management Service reduced the minimum bid for deepwater 

tracts from $900,000 to $150,000—enabling companies to lock up entire basins for 10 

years for only a couple million dollars.63 During the next five years, despite flat oil and gas 

prices, the industry acquired 1,500 tracts in deepwater.64

Shell’s December 1989 announcement of a major discovery at a prospect called Auger, 

located in the Garden Banks area 136 miles off the Louisiana coast, spurred further 

interest. Two years earlier, Global Marine’s new, giant semisubmersible, the Zane Barnes, 

struck oil for Shell after drilling through 2,860 feet of water and another 16,500 feet 

beneath the seafloor. Shell kept the discovery quiet as it delineated the extent of the field, 

which turned out to contain an estimated 220 million barrels of oil equivalent, the 

company’s third-largest offshore discovery in the Gulf. Underpinning Shell’s decision to 

go forward with Auger was the discovery of relatively high flow rates from the turbidite 

sands at Bullwinkle, where engineers found they could open the wells to 3,500 barrels 

per day (three times the rate considered good for a well on shallower parts of the Gulf 

continental shelf). If Auger had similar flow rates, the field could be profitably developed, 

even in water more than twice as deep as Bullwinkle’s. Few people knew that Auger was 

only one of a number of Shell deepwater discoveries.65

As the company formulated an ambitious strategy to launch a series of major platforms, 

a gloomy economic outlook tempered Shell’s euphoria over the Auger discovery and 

production breakthrough at Bullwinkle. The projected cost of developing Auger exceeded 

$1 billion. In appraising the next prospect, code-named Mars, Shell’s exploration managers 

looked for ways to save money and offload some of the financial risk; accordingly, in 

1988, they brought in British Petroleum (BP) as a partner with a 28.5 percent interest in 

the project.66

At the time, Mars seemed like a risky endeavor, with low probability for a major discovery. 

Furthermore, BP posed little threat. The company had been kicked out of Iran and Nigeria 

in 1979 and was struggling with a bloated management structure, poorly performing 

global assets, and uninspired leadership. Shell viewed BP as merely a banker.67

<
Chapter Two 37 37

All that changed in 1989, when Sonat’s Discoverer Seven Seas drilled into Mars. The field, 

located due south of the mouth of the Mississippi, lay in nearly 3,000 feet of water. The 

discovery well encountered multiple oil- and gas-bearing layers stacked on top of each 

other over several hundred meters. Mars was more than twice the size of Auger—the 

largest field discovered in the Gulf in 25 years. For Shell, Mars promised a big payoff for 

large bets on deepwater leases. For the industry, Mars confirmed the Mini-Basin trend in 

the Gulf as a bona fide play. For BP, Mars allowed the company’s managers, engineers, 

and scientists to go to school on Shell’s deepwater technology. Perhaps just as importantly, 

according to BP’s chief in the United States, “Mars saved BP from bankruptcy.”68

During the next several years, major oil companies—and even more significantly, 

contractors in the offshore service industry—propelled the evolution of technology in 

innovative new directions. The 1970s revolution in digital, three-dimensional (3-D) seismic 

imaging, pioneered by Geophysical Services Inc. (GSI), and the 1980s move to computer 

workstations, which enabled faster processing of the data generated in such surveys, 

combined to enhance dramatically the industry’s accuracy in locating wells for field 

development—a critical factor when drilling a single well in deepwater could cost as much 

as $50 million. Beyond development drilling, 3-D seismic imaging boosted the success 

of wildcat discovery wells from less than 30 percent to 60 or 70 percent. As the major 

companies began to divest from older producing properties in favor of new deepwater 

prospects, smaller firms purchased older properties and redeveloped them with significant 

reserve additions using 3-D seismic imaging. In all, 3-D seismic imaging effectively tripled 

or even quadrupled the estimated amount of oil and gas reserves in the Gulf of Mexico.69

Drilling and subsea engineering advanced in similar fashion. Drilling contractors developed 

a new generation of vessels that took drilling from 5,000 to 10,000 feet of water, and 

from 20,000 to 30,000 feet of sub-seafloor depth. New directional drilling techniques, 

made possible by “downhole steerable motors,” allowed engineers to maneuver a well from 

vertical to horizontal to achieve greater accuracy and more fully exploit reservoirs. Drillers 

also found ways to obtain information from deep inside wells, using “measurementswhile-drilling” tools and sensors that provided position, temperature, pressure, and 

porosity data while the borehole was being drilled. Improvements in marine risers using 

lightweight composite materials and tensioners, along with new methods for preventing 

oil from cooling and clogging in deepwater pipelines, enabled the industry to make long 

tiebacks between subsea wells and production facilities. To support subsea installation and 

operations, the industry turned to sophisticated remote-operated vehicles mounted with 

TV cameras and umbilical tethers containing fiber-optic wire for the transmission of vivid 

images.70

Even as the major operators pushed into deepwater, they outsourced more of the research 

and development (R&D) of new technologies. The bust of the 1980s had driven the 

exploration and production companies to decrease internal R&D and adopt policies of 

buying expertise as needed, rather than cultivating it from within. R&D investments in 

oil exploration and production by the major companies declined from nearly $1.3 billion 

in 1982 to $600 million by 1996. According to a National Petroleum Council study, 

“This ‘buy versus build’ strategy resulted in a significant reduction in the number of 
38 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

skilled people within operating companies who understood technology development 

and deployment.”71 Service companies (Schlumberger, Halliburton, Baker Hughes, and 

Oceaneering) became the major source of technology development. An illustration of this 

trend was the Texaco-initiated “Deep Star” consortium, established in 1992, through which 

offshore operators funded contractor-generated R&D.72

Rapid technological advances in the early 1990s did not immediately translate into more 

economically feasible practices. Cost overruns, delays, and strained relationships with 

contractors plagued the fabrication and installation of Shell’s giant tension-leg platform 

for Auger, the industry’s bellwether deepwater project. Further, Shell discovered that crude 

oil from the Auger field was sour (containing sulfur, which had to be separated out at 

the refinery) and thus had to be discounted. The company’s only salvation on the project 

depended on Auger’s wells flowing at a higher rate than Bullwinkle’s.73

Auger Pays Off

Fortunately for Shell and the offshore industry, the wells did not disappoint. In the spring 

of 1994, Shell began to bring in wells at Auger that flowed at more than 10,000 barrels 

per day. Even with oil prices at $20 per barrel or less, deepwater now promised handsome 

profits. The Auger wells confirmed the reservoir model for turbidites in deepwater and 

even exceeded Shell’s most optimistic estimates. Engineers designed Auger to handle 42,000 

barrels of oil (and 100 million cubic feet of gas) per day from 24 wells, but by July the 

first three wells were already producing 30,000 barrels per day. “Debottlenecking” efforts 

eventually raised Auger’s capacity to 105,000 barrels of oil and 420 million cubic feet of 

gas per day by the late 1990s.74

Auger’s prodigious output also made subsea completions (with the wellhead located on 

the ocean floor rather than on a surface production platform) economic in the Gulf, as 

they had been in the North Sea. With tension-leg platforms like Auger, subsea completions 

became important as a component of an early production system or as a remote subsea 

development. Large fields or clusters of smaller fields, which otherwise would not justify 

the expense of multiple or larger platforms, could thus be profitably developed.75

Auger’s many blessings came at a cost to Shell and the environment. Expanding 

production at Auger was extremely challenging. At the start of production in April 1994, 

Shell continuously flared or vented between one and six million cubic feet of natural gas 

per day, without the required federal permission. The flaring and venting continued for 

more than four years until the Minerals Management Service announced it had discovered 

this violation as well as Shell’s failure to record and report the releases. In a 2003 civil 

settlement, Shell agreed to pay $49 million, an amount equivalent to the value of about 

two weeks of production from Auger. If the company was chastened after having to admit 

to these serious violations, Shell management also must have been tempted to look at this 

charge as an incidental cost of doing business in the deepwater Gulf. 76
Chapter Two 39 39

Deepwater Treasures

The productivity of the Auger wells made the Gulf of Mexico the hottest oil play in the 

world. And it was mostly about oil. Deepwater proved to be largely oil-prone. The source 

rocks for most of the deepwater region are an Upper Jurassic kerogen that generates 

natural gas only when subjected to very high temperatures. But subterranean thermal 

gradients and source-rock temperatures in the deep Gulf are quite modest, despite the 

enormous pressures exerted several miles below the seabed. The massive amounts of salt 

(see below) has acted like a heat sink, keeping hydrocarbons from getting too hot and thus 

cooking up large amounts of natural gas.77

Despite downward pressure on oil prices in the late 1990s, the promise of prolific 

production from deepwater was too much to resist. Exploration and production firms 

with deepwater leases consolidated their positions. Companies that had sat on the sidelines 

during the 1980s stampeded into unclaimed areas. Newly developing or commercialized 

exploration and production technologies found vibrant new markets. Contractors all 

along the Gulf Coast and, indeed, around the world, geared up for a surge of activity. Port 

Fourchon, Louisiana’s southernmost port on the tip of Lafourche Parish, came to life as the 

jumping-off point for supplying and servicing deepwater operations in the Gulf.78

AUGER TENSION-LEG PLATFORM

Like a giant alien creature, a scale rendering of a tension-leg drilling platform is superimposed over New Orleans. Built by Shell to tap its 

Auger deepwater field some 200 miles southwest of the city, the huge platform uses steel mooring cables to stabilize its 3,000-foot legs and 

can drill 20,000 feet below the seafloor. The platform augured well for Shell in the late 1990s, delivering 100,000 barrels of oil a day.

Courtesy of Shell
40 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

The next landmark on the horizon for deepwater drilling was Mars. In July 1996, Shell 

began producing from its Mars platform, six months before NASA launched its Pathfinder 

probe to the planet Mars. At a total cost of $1 billion, Shell’s Mars was more than three 

times as expensive as the Mars Pathfinder, and its remote technologies and engineering 

systems were arguably more sophisticated. The investment of money and technology paid 

dividends: the Mars platform tapped into the largest field discovered in the United States 

since Alaska’s Prudhoe Bay. Creating a system to produce the field also established a new 

paradigm for large projects and revealed how exploration and production strategy was 

being reshaped in the Gulf.79

To reduce costs and avoid the headaches experienced at Auger, Shell introduced a different 

contracting model at Mars based on “alliances,” including the sharing of technology and 

patents. Shell ended up giving away more than BP, which had little deepwater experience. 

But the costs and risks were too large to go it alone, as Shell had usually preferred to do. 

The partners carried the alliance concept over to their relationship with contractors, who 

built the tension-leg platform hull, fabricated the topsides, and integrated the two. The 

project team brought in contractors early on to collaborate on developments and share 

risks and rewards. The key advantage of this approach was that it reduced the so-called 

“cycle time” of design, bidding, and contracting by an estimated six to nine months.80 On a 

platform such as Mars, where the first well came in at 15,000 barrels per day, the timevalue of money made at the beginning rather than at the end of the platform’s life was 

quite significant. Shell’s contracting model at Mars, replicated on its subsequent tensionleg platforms, established the growing importance of alliance networks for global oil and 

gas developments in technologically complex frontier regions characterized by high costs 

and risks.81

In the late 1990s, having control of one-third of all Gulf leases in depths greater than 

1,500 feet, Shell rolled out one tension-leg platform after the other.82 In 1997, a Mars 

“clone” called Ram-Powell, developed in a joint venture with Exxon and Amoco, went 

on-stream in 3,200 feet of water 80 miles southeast of Mobile, Alabama. In March 1999, 

Shell and its minority partners, BP, Conoco, and Exxon, started up the massive Ursa, on a 

lease two blocks to the east of Mars. Nearly double the weight of Mars, Ursa was designed 

to accommodate astounding initial well-production rates of 30,000 barrels per day; in 

September 1999, a well at Ursa broke all records with a production rate of nearly 50,000 

barrels of oil equivalent per day. Finally, in 2001, Shell brought in production from the 

Brutus platform, which tapped into a 200-million-barrel field in 3,000 feet of water in the 

Green Canyon.83

Shell’s new technologies solidified the company’s position as the leader in the Gulf. Its 

tension-leg platforms, as well as major fixed platforms such as Bullwinkle and West Delta 

143, not only produced hydrocarbons from the fields beneath them, but also served as 

hubs used to take and process oil and gas production from satellite subsea wells, thus 

extending the life of those platforms once their own production declined. Deepwater 

output from Shell’s platforms and subsea wells, and eventually from other companies 

in the vicinity, fed into network of Shell-owned or operated crude-oil trunk pipelines, 

gathering systems, and natural-gas pipelines. Shell also made special arrangements to 
Chapter Two 41 41

transport crude oil production from its growing deepwater properties into the Clovelly 

storage facilities owned by the Louisiana Offshore Oil Port in South Louisiana. By 2001, 

Shell operated 11 of the 16 key oil trunk pipelines servicing deepwater.84

Shell’s lead in the deepwater Gulf was substantial but not unassailable. During the latter 

half of the 1990s, many companies gained ground, including a rising percentage of small 

and midsized independents. But the only company that chased down and eventually 

overtook Shell was BP.

Deeper Still 

In the 1990s, technological breakthroughs in imaging and drilling through massive salt 

sheets opened a new “subsalt” play, first on the shelf and then ranging into deepwater. 

Discoveries in at least four different “fold belts” across the Gulf of Mexico extended the 

search for oil into “ultra-deepwater” and led to another wave of innovation in floating 

production. In 1990, most oil and gas from the Gulf had still come from shallow water; 

average production-weighted depth had barely reached 250 feet. By 1998, the weighted 

average passed the 1,000-foot milestone, at which point deepwater production (at about 

700,000 barrels per day of oil and 2 billion cubic feet per day of gas) surpassed that from 

shallow water for the first time.85 

As the industry moved deeper, the abandonment and decommissioning of older platforms 

on the shelf became a thriving business. During the 1990s, 1,264 platforms were removed, 

more than twice the total prior to 1990; after 2000, removals continued at a rate of 150 

FIGURE 2.4: Wells Drilled in the Gulf of Mexico by Water Depth, 1940-2010

Wells Drilled in the Gulf of Mexico by Water Depth, 1940-2010

Year

Source: Commission staff, adapted from Bureau of Ocean Energy Management, Regulation and Enforcement

12,000

10,000

8,000

6,000

4,000

2,000

0

Water Depth

1940 1950 1960 1970 1980 1990 2000 2010
42 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

per year.86 Some obsolete platforms found use as “artificial reefs” through a creative 

program, coordinated by the Minerals Management Service and the states of Texas and 

Louisiana, to place old platforms in specially designated locations on the sea bottom, where 

they attracted marine life much like natural reefs.87

Meanwhile, another relaxation in the terms of access to Gulf of Mexico leases, in the 

form of the Deepwater Royalty Relief Act (see Chapter 3), helped sustain the oil industry 

in deepwater. Deepwater royalty relief no doubt enticed some oil companies, especially 

non-majors, into deepwater. But judging from the huge upswell in bidding at the May 

1995 Central Gulf of Mexico sale, before royalty relief was enacted, the race appeared to 

be already under way.88 Oil explorers were clearly gunning for fields like Auger with high 

flow rates and high ultimate reserves. Many of them were also on the hunt for petroleum 

in a new geological location: beneath the Gulf’s massive sheets of salt. 

Subsalt Discoveries

Salt is the dominant structural element in the Gulf of Mexico petroleum system. Oil 

explorers had long ago discovered oil trapped against the flanks of salt domes or between 

the salt diapirs in the deepwater mini-basins. But geologists had typically assumed that 

there could be no oil reservoirs lying beneath any salt they encountered. By the 1970s, 

advancing knowledge about the basin’s regional geology suggested that oil could be found 

under the salt. In many places, the salt pillars that extruded upward into sandstone and 

shale flowed horizontally in elastic plumes over vast expanses of younger, potentially oilbearing sediment that extend more than 35,000 square miles across the Gulf. Geologists 

invented new terminology to describe different kinds of salt formations in the picture they 

pieced together—canopies, tongues, nappes, egg crates, and turtle domes—and established 

a special subfield of geology to explain how the salt moves. What they were really 

interested in, however, was what lay beneath the salt.89

The subsalt play began in 1990, when Exxon (with partner Conoco) made the first 

discovery at a prospect called Mickey. Located in 4,352 feet of water on the Mississippi 

Canyon 211 lease (about 10 miles northeast of where BP would later drill Macondo), 

Mickey was not then large enough to put into production.* Two years later, Chevron 

drilled a well in Garden Banks 165 through almost 7,000 feet of salt and another 

5,000 feet of subsalt sediment. The well found no oil, but was a milestone because it 

demonstrated that the technology existed to drill through an enormous body of salt.90

Finally, in 1993, Phillips Petroleum announced the first commercial subsalt oil discovery. 

Years earlier, Phillips had begun to look systematically for places where salt sheets might 

be obscuring oil reservoirs. In 1989, the firm acquired 15 leases including one at a location 

called Mahogany. It was a speculative move. Salt plays tricks with seismic sound waves, 

which travel through salt at a much higher velocity than through the surrounding 

sediments and also get refracted, much as the image of a pencil is bent when it is stuck 

in a glass of water. Obtaining clear images of rocks in their proper location under the salt 

seemed almost impossible. To get a better focus, Phillips shot a 3-D seismic survey over 

* Ten years later, Exxon developed the prospect as a subsea natural gas development called Mica.
Chapter Two 43 43

the prospect. And to share the substantial expenses of conducting the survey and drilling 

through the salt—twice the cost of a normal well—the company took on Anadarko and 

Amoco as partners. Phillips’s geophysicists then processed the seismic data with a newly 

developed computing algorithm, yielding a picture sufficiently improved to make an 

informed stab at the target. The first well, drilled by a Diamond Offshore semisubmersible, 

passed through 3,800 feet of salt, at one point encountering unstable rock that threatened 

to collapse the well. Eventually, the drill hit a 100-million-barrel field. In 1996, Phillips’s 

Mahogany platform began producing at 20,000 barrels per day.91

The subsalt play progressed, haltingly, from Mahogany. Drilling through salt involved 

myriad technical complications. Under high temperature and pressure, salt masses flow, 

creep, and deform like plastic; this movement can shift the well casing and production 

tubing. These wells also had to be drilled to great depths, escalating costs. And limitations 

on computer power made it difficult to obtain reliable seismic images from beneath the 

salt, adding risk to exploration. Subsalt wells missed hydrocarbons a lot more often than 

they hit them.92

As operators drilled a string of dry holes, the post-Mahogany euphoria ebbed. In the 

1995–1997 lease sales, companies began to turn from shallow subsalt prospects, pursuing 

instead ultra-deepwater (greater than 5,000 feet) prospects, looking for easier-to-image 

drilling targets in foldbelts formed by the lateral movement of salt and sediment. In 1995, 

Oryx Energy made a discovery at Neptune, opening a new play in the Western Atwater 

Foldbelt. The next year Shell announced a strike at its Baha prospect in the far western 

Gulf. This discovery initiated the Perdido Foldbelt play in more than 8,000 feet of water.93

A deeper ocean frontier, once again, beckoned the industry.

An Industry Restructured—and Globalized

As geologists and geophysicists in Houston dedicated themselves to solving the riddles 

presented by depths of the Gulf of Mexico, the world oil industry began a radical 

restructuring. Oil and gas companies had not yet recovered from the 1980s bust when oil 

prices swooned again in the late 1990s, driven in large part by the drop in global demand 

precipitated by the Asian financial crisis. Increased shareholder pressure on oil firms to 

improve short-term financial results and longer-term profitability spurred one of the 

greatest merger movements in history. In 1998, BP acquired Amoco. The next year, Exxon 

merged with Mobil in an $80 billion deal to create the world’s largest company. BP-Amoco 

countered by acquiring ARCO; Total merged with Fina and Elf (renamed Total in 2003); 

Chevron combined with Texaco; and, finally, Conoco and Phillips joined to create the 

sixth “super major” (along with Royal Dutch Shell). During these consolidations, many 

companies relocated staff from New Orleans and elsewhere to Houston, reinforcing that 

city’s claim as the international oil capital.94
44 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Mergers boosted results as management pared away overlapping functions and laid 

off employees, reinforcing the trend toward outsourcing R&D and reducing internal 

technological expertise. Mergers benefitted the oil industry, on the other hand, by 

equipping firms with new capital reserves needed to finance long-term growth strategies—

some of them dependent on riskier, but potentially higher-return, ventures. The deepwater 

Gulf figured significantly in the growth strategies of all the “super major” oil companies—

albeit as only one among several frontier provinces worldwide. They took renewed interest 

in Arctic and sub-Arctic regions and began to invest in other deepwater basins from the 

northeast Atlantic west of the Shetland Islands, to the Campos Basin off Brazil, to West 

Africa’s Gulf of Guinea and offshore Angola, to northwest Australia. By the early 2000s, 

analysts regarded the three provinces rimming the central Atlantic Ocean—the Gulf of 

Mexico, Brazil, and West Africa—as the “New Golden Triangle,” the place where the largest 

future reserves were likely to be found.95

Echoing the oil companies, consolidation also swept through offshore contractors. After 

half of the world’s seismic crews were idled in 1999 due to a price collapse early in the 

year, the ensuing shakeout left only handful of seismic contractors, led by Western-Geco, 

owned by Schlumberger and Baker-Hughes; Petroleum Geo-Services; and CGG and Veritas 

(which merged in 2007). The major oil-service companies, which provided a variety of 

drilling, evaluation, well-completion, and production services, began to combine at the 

same time (notable was the 1998 merger between the oilfield giants, Halliburton and 

Dresser Industries). Most significantly, the drilling-contractor industry—continuously 

in the process of mergers, acquisitions, and bankruptcies—consolidated further. In 

1999, Sedco-Forex and Transocean, themselves the products of earlier mergers, became 

Transocean Sedco Forex, later simplified as Transocean. In 2000, it acquired R&B Falcon, 

whose assets included a semisubmersible under construction in Korea by Hyundai Heavy 

Industries called the Deepwater Horizon. In 2001, Global Marine merged with Santa Fe, 

and six years later this firm became part of the modern Transocean, by far the largest 

offshore drilling firm in the world.

During this era, offshore oil exploration and production became an increasingly global 

enterprise. U.S. operators searched for oil in deepwater basins outside the Gulf of Mexico, 

and more than ever, companies such as Norway’s Statoil, Brazil’s Petrobras, and France’s 

Total were drilling in the Gulf. Shipyards along the Gulf Coast—the pioneers in design 

and construction of mobile offshore drilling units—had by the 1990s almost totally 

surrendered this work to competitors in Korea and Singapore. Many of the largest offshore 

engineering, construction, and pipelaying firms (Heerema Marine Contractors, Technip, 

Worley Parsons, and others) were globally oriented companies based outside the United 

States.96

Offshore contractors headquartered in the Gulf survived by expanding internationally. 

Morgan City’s J. Ray McDermott branched out around the world more aggressively 

after the 1980s industry depression and eventually moved its headquarters to Houston. 

Louisiana-based Gulf Island Fabricators, Chet Morrison Contractors, Global Industries, and 

even Frank’s Casing Crew and Rental Tools grew from small, family-owned firms servicing 

operations in the Gulf to become major offshore contractors active worldwide. 
Chapter Two 45 45

BP’s Moment

In the late 1990s, the global company making the biggest news in the Gulf of Mexico was 

BP. Founded in 1908 and since 1954 named British Petroleum, it had for decades built its 

business around access to crude oil from Iran and neighboring Middle Eastern countries. In 

the 1960s and 1970s, BP achieved great success in discovering and developing oil reserves 

in the North Sea and in Alaska’s Prudhoe Bay. By the early 1990s, however, BP had been 

exiled from the Middle East and Nigeria. Production from Prudhoe and the North Sea were 

in decline. Billions of dollars had been invested in unprofitable nonpetroleum ventures. 

And an ambitious exploration program had yet to bear fruit. The company tottered on the 

brink of bankruptcy.97 

Sir John Browne, a forceful exploration manager whose father had also worked for 

BP, orchestrated its stunning turnaround. In the 1980s, as executive vice president of 

Sohio, BP’s American subsidiary, he reined in spending and cut staff in order to place the 

company on better footing. Returning to London in 1989, he reorganized BP’s exploration 

arm; Browne slashed expenditures, established a rigid—if not ruthless—performance ethic, 

and refocused on high-risk but potentially high-reward opportunities. Upon becoming 

chief executive in 1995, he directed a major part of BP’s upstream focus to the deepwater 

Gulf. In the deals he negotiated to acquire Amoco and ARCO, BP emerged with a greatly 

expanded portfolio of Gulf leases and assets.98

In the late 1990s, BP’s Gulf exploration team made a series of remarkable deepwater 

discoveries. Once the fields came online, they vaulted BP ahead of Shell as the Gulf’s 

largest oil producer. BP prided itself as a “fast follower,” rather than an “early adopter,” in 

exploiting technological innovations. BP had closely followed Shell at Mars and quickly 

applied what it had learned to develop the Marlin field with a tension-leg platform in 

3,400 feet of water. BP also joined with Exxon in developing deepwater discoveries at 

the Hoover and Diana fields in the western Gulf. After the string of subsalt dry holes 

in the mid-1990s, some of BP’s competitors began looking for other kinds of plays the 

Gulf might still present. Shell shifted to managing production from its large number of 

deepwater developments. But BP sprang faster than anyone to confront the Gulf’s nagging 

exploration challenge—the salt. 99

In a costly and complex undertaking, BP combined new advances in computer processing 

for 3-D seismic imaging with new methods of acquiring seismic data from multiple 

directions to gather a better understanding of the salt history, stratigraphy, and the 

sources and migration pathways of oil in deepwater. BP’s scientists and engineers found 

geographically promising areas just as large as those discovered and profitably exploited 

on the shallower continental shelf. Based on their analyses, they began to believe that the 

deepwater frontier could ultimately hold 40 billion barrels of commercially exploitable 

oil—four times the prevailing estimates. Said Dave Rainey, BP’s deepwater exploration 

manager, “One of the lessons we have learned about the Gulf of Mexico is never to take it 

for granted.”100
46 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

A new generation of drilling vessels coming onto the market, along with advances in 

drilling, encouraged BP to take the risk to explore those prospects. Outpacing most of the 

industry by a year, the company shifted its sights to prospects in much deeper waters. Rich 

rewards followed with a historic string of giant oil finds in subsalt formations ranging 

out to 7,000 feet of water. In 1998, BP struck oil in the deepwater subsalt of the Green 

Canyon’s Mississippi Fan Foldbelt at Atlantis (minority partner BHP Billiton) and Mad Dog 

(minority partners BHP Billiton and Chevron), two of the largest fields ever discovered in 

the Gulf of Mexico. Atlantis’s original reserves estimates were 400–800 million barrels of 

oil equivalent and Mad Dog’s were placed at 200–450 million barrels. In 1999, working 

for BP (and minority partner Exxon) in 6,000 feet of water in the Mississippi Canyon, 

Transocean’s Discoverer Enterprise drilled the largest Gulf field of all time, a subsalt 

prospect called Crazy Horse (subsequently renamed Thunder Horse), containing more than 

1 billion barrels of recoverable reserves. That find alone catalyzed yet another rebirth of 

offshore oil in the Gulf of Mexico.101 

The discoveries kept coming. A month later, BP made another oil and gas hit at Horn 

Mountain (150 million barrels of original reserves) in the Mississippi Canyon. In 2000, 

BP and Shell discovered a major above-the-salt deposit at Holstein (more than 200 million 

barrels) near the Mad Dog and Atlantis fields in the Green Canyon. The same year, 

those two partners announced their Na Kika project, a joint subsea development of five 

independent fields tied back to a central semi-submersible floating production facility, an 

industry first for the Gulf of Mexico. In 2001, BP found another giant oilfield, containing 

0

1

2

3

4

5

6

7

8

Barrels of Oil Per Day (Millions)

Year

1990200020082015

• Alaska

• Offsore Lower 48

• Onshore Lower 48

Source: Commission Staff, Adapted from U.S. Energy Information Administration

20252035

FIGURE 2.5: U.S. Crude Oil Production, 1990-2035 (projected) 

As this chart makes clear, overall production of crude oil in the U.S. has been declining for decades. However, production from deepwater 

wells in the Gulf of Mexico (Offshore Lower 48) is on the rise.
Chapter Two 47 47

500 million barrels, called Thunder Horse North.102 Also that year, BP and yet another 

partner, Chevron, discovered a 100 million barrel field in 7,000 feet of water at their 

Blind Faith prospect in the Mississippi Canyon. (In the harsh glare of hindsight following 

the Macondo blowout, the executive director of the Natural Resources Defense Council 

commented that, in the name Blind Faith, “It would be hard to find a more fitting symbol 

of the oil industry’s steady and assertive advance into the Gulf’s deep waters, or the 

corporate thinking behind it.”103)

In August 2002, BP’s Browne boldly announced that the company would spend $15 

billion during the next decade on drilling and developing these discoveries. BP had 

become the largest-acreage holder in the deepwater Gulf, with more than 650 tracts in 

water depths greater than 1,500 feet, and in possession of one-third of all deepwater 

reserves then discovered. The deepwater Gulf of Mexico, Browne asserted, would be the 

“central element” of BP’s growth strategy.104 “The question is how they will manage the 

embarrassment of riches they have,” said one analyst at the time. “They have a bunch of 

projects and they need to coordinate people and contractors. There is the sheer scale of the 

facilities and the size of the investment required—all this before a drop of oil ever comes 

out of the ground.”105

Clouds on the Horizon

After BP’s impressive discoveries, the industry dove into deeper waters across the Gulf. 

From 2001 to 2004, operators found 11 major fields beneath water 7,000 feet deep or 

more. Most deepwater discoveries were made in relatively young sandstones of the lower 

Miocene era. But companies increasingly explored down into the deeper and older Paleogene 

or “Lower Tertiary” strata found in the foldbelts near the edge of the Sigsbee Escarpment, a 

salt sheet that resembles a near-surface moonscape extending to the base of the continental 

slope. In 2006, Chevron and its partners Devon Energy and Statoil disclosed promising test 

results from a two-year-old discovery at its Jack prospect, proving that Lower Tertiary 

reservoirs could produce oil at pressures encountered at great depths, creating excitement 

that the Lower Tertiary play might ultimately yield between 3 billion and 15 billion barrels 

of hydrocarbons—collectively rivaling the size of the great Prudhoe Bay discovery. This 

implied a future for ultra-deep drilling, ranging out to 10,000-foot water depths and 

25,000 feet beneath the seafloor. Reported the Oil & Gas Journal, “The Jack-2 test results 

boost confidence in that potential and highlight the central role technology plays in future 

supply.”106

The industry was in need of a confidence booster after the previous three years of 

development challenges that had sorely tested BP’s and the industry’s confidence and 

conviction about deepwater.

BP’s decision to develop multiple deepwater fields at once was an incredibly ambitious 

undertaking. Its program focused on the major fields at Holstein (a discovery above the 

salt), Mad Dog, Atlantis in the Green Canyon, and Thunder Horse in the Mississippi 
48 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Canyon—with total potential reserves of 2.5 billion barrels of oil, in water ranging from 

4,000 to 7,000 feet deep, requiring wells reaching 30,000 feet in total depth. To produce oil 

at these places, BP selected “truss spars” for Holstein and Mad Dog, and semisubmersibles 

(such as the one BP and Shell had introduced at Na Kika), for Thunder Horse and 

Atlantis.107 

Beyond about 4,000-foot depths, the weight of tension cables was too great, so BP could 

not employ tension-leg platforms, the workhorses at Shell’s first deepwater projects. The 

spar, successfully demonstrated in 1996, is a giant buoy consisting of a large-diameter, 

vertical cylinder supporting a deck for drilling and processing. Its deep-draft floating 

caisson keeps about 90 percent of the structure underwater, giving the structure favorable 

motion characteristics. During 2000–2005, Kerr-McGee (acquired by Anadarko in 2006) 

went on to pioneer several innovations in spar designs.108

BP’s choice between spars and semisubmersible production facilities depended upon 

different economic, functional, and safety factors at each field. All four projects would be 

linked by pipeline to a platform hub, where crude oil would be transferred into a 390-

mile pipeline, the Cameron Highway, and transported to refineries at Texas City and Port 

Arthur. All four projects, as well as Na Kika, also would connect to the BP-operated Mardi 

Gras transportation system, itself a billion-dollar project that integrated five different 

BP Thunder Horse Platform

BP’s mighty Thunder Horse platform was out-muscled by Hurricane Dennis in 2005 as it was being readied for service. Evacuated crews 

returned to find the semi-submersible production facility listing badly. After repairs and thorough analysis, additional problems were 

discovered that put the platform further behind schedule. For BP it was worth the wait: By 2009 Thunder Horse was producing a whopping 

quarter-million barrels a day.

Getty Images/U.S. Coast Guard photo/PA3 Robert M. Reed/digital version by Science Faction
Chapter Two 49 49

pipelines covering a total of 450 miles, with capacity to transport 1 million barrels of 

crude and 1.5 billion cubic feet of natural gas per day. The selection and development of 

technology on all these projects was a major challenge at every step, given the extreme 

water depths, reservoir conditions, and associated environmental issues. Thunder Horse 

had an unusually high pressure/high temperature reservoir. Atlantis was located under 

complex seafloor topography near the steep Sigsbee escarpment, and a large portion of the 

field was subsalt. Mad Dog lay under a massive salt canopy, causing large uncertainties 

in describing the actual reservoir. The Holstein geology forced BP to use a spar with wells 

housed on the platform. As BP production managers admitted in 2004, “None of the 

projects can be categorized as ‘business as usual.’”109

The $5 billion Thunder Horse project was especially challenging. A major incident in 

drilling occurred even before the semisubmersible facility was put in place. In May 2003, 

the top of the drilling riser on the Discoverer Enterprise broke loose from the vessel, 

ripped apart again 3,000 feet under the surface, and left the lower marine riser package 

to collapse on and around the top of the blowout preventer, where the riser and drill pipe 

snapped off. The blowout preventer’s blind shear rams were activated and worked as 

designed, averting any spill. “No one was hurt, and the well was secure,” BP reported, “but 

the initial scene was daunting.”110

An even bigger scare awaited the Thunder Horse semisubmersible production facility, 

which was towed to the field and moored on location in April 2005. As work proceeded to 

connect the predrilled subsea wells and commission all the facilities above and below the 

• 1975–1989 • 2004–2005

• 1990–1999 • 2006–2007

• 2000–2003 • 2008

7500 ft

5000 ft

1500 ft

1000 ft

FIGURE 2.6: Deep Discoveries
50 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

water, Hurricane Dennis neared in July, forcing the evacuation of all personnel and leaving 

the production facility unmanned. “No one could have anticipated the major shock that 

awaited the first helicopter flights after the storm had passed,” according to one official BP 

account. The columns and other areas of the hull had filled with water, causing the facility 

to list to one side. Investigations later revealed that a valve in the bilge and ballast system 

had been installed backward, allowing seawater to move into the hull, a failure exacerbated 

by electrical pathways that were not watertight. Had BP not arrived when it did, the 

structure might have been lost. Crisis management crews were able to right the facility 

within a week, but reworking Thunder Horse’s hull systems delayed commissioning for 

a year. Similar work on the Atlantis semisubmersible production platform pushed its 

installation back several months, too, until July 2006.111

Nor was that the end of BP’s major shocks—it discovered that a weld had cracked open on 

one of the Thunder Horse manifolds that collected oil from the network of satellite subsea 

wells. The company made the difficult decision to pull out all the manifolds and subsea 

equipment that had a similar weld configuration— adding hundreds of millions of dollars 

to the cost of the project. After a lengthy investigation, engineers found that minute cracks 

had formed in the thermal insulation on the manifold pipe work, leading to reactions that 

embrittled the weld interface. BP and contractors developed new weld techniques, created 

more rigorous inspection and assurance procedures, and refurbished all the affected subsea 

equipment on Thunder Horse and at Atlantis. Thunder Horse finally delivered its first oil 

on June 2008, three years behind schedule.112 By March 2009, production ramped up to 

250,000 barrels per day, 4.5 percent of total U.S. daily production. (Atlantis went online a 

year before Thunder Horse, in 2007, but BP has been dogged by accusations that Atlantis 

has not been in compliance with safety and environmental regulations.113)

Damaging Hurricanes

BP was not alone confronting environmental challenges. During 2002 and 2004–2005, 

hurricanes ravaged the Gulf Coast, with major impacts on offshore infrastructure and 

operations. In September 2002, Hurricane Lili blew into the heart of the Ship Shoal, Eugene 

Island, and South Marsh Island areas, damaging platforms and pipelines. Two years later, 

Ivan—a Category 4 storm—swept through the alley east of the Mississippi River delta, 

causing mudflows and anchor-dragging by mobile drilling units that tore up undersea 

pipelines. The following year, Hurricane Katrina flooded New Orleans and points east, with 

horrible effects. Offshore, Katrina destroyed 47 platforms and extensively damaged another 

20. The 1,000-ton drilling rig on Shell’s Mars platform collapsed, prompting an aroundthe-clock onsite recovery effort.

A month later, Hurricane Rita, storming farther west, wiped out 66 platforms and broke 

up another 32. Rita capsized Chevron’s Typhoon, an unfortunately named mini-tensionleg platform. The majority of the platforms obliterated in these two storms were from 

an early generation of Gulf facilities, more than 30 years old. The two hurricanes also 

damaged more than 70 vessels and nearly 130 oil and natural gas pipelines, as they hit 

more prolific and sensitive areas than previous storms and, accordingly, caused much more 

extensive damages. Ominously, the short interval between the two storms exhausted the 

resources available for normal recovery and overwhelmed support bases.114
Chapter Two 51 51

The Oil Industry and Deepwater Technology 

at Decade’s End

As the end of the decade approached, the offshore industry in the Gulf had recovered from 

hurricane devastation and pressed on with deepwater and ultra-deepwater developments. 

Although many independent companies (such as Anadarko, Hess, BHP, Newfield, 

Marathon, and Mariner) had substantial deepwater leases and were actively exploring and 

developing them, the edge of the frontier was mainly the playground of the super-majors 

and firms with partial government ownership, such as Norway’s Statoil and Brazil’s 

Petrobras.115

In September 2009, Transocean’s Deepwater Horizon semisubmersible made a historic 

discovery for BP at the company’s Tiber prospect in the Keathley Canyon. Drilling in 4,000 

feet of water and to a world-record total depth of 35,055 feet, Deepwater Horizon tapped 

in a pool of crude estimated to contain 4 to 6 billion barrels of oil equivalent, one of the 

largest U.S. discoveries. Six months later, in March 2010, Shell (with partners Chevron 

and BP) started production at its Perdido spar in 8,000 feet of water in the Alaminos 

Canyon. A hub for the development of three fields, Perdido was the world’s deepest 

offshore platform, and the first project to pump oil and gas from the Lower Tertiary. Other 

Lower Tertiary developments were coming onto the horizon. Later in the year, Petrobras 

planned to develop the Gulf’s first floating production, offloading, and storage facility to 

produce from Lower Tertiary reservoirs at its Cascade and Chinook prospects. By 2010, the 

industry had announced 19 discoveries in the Lower Tertiary trend, 14 of them containing 

more 100 million barrels of oil equivalent.116

Technical Tests

The fanfare around these discoveries and developments could not disguise the fact that the 

technical challenges of ultra-deepwater drilling and production and the subsalt geology 

remained unique and formidable. Water depths are extreme, down to 10,000 feet. Total 

well depths, as Tiber demonstrated, can go beyond 30,000 feet. Well shut-in pressures can 

surpass 10,000 pounds per square inch. Bottom-hole temperatures can exceed 350 degrees 

Fahrenheit. Salt- and tar-zone formations can be problematic. The sandstone reservoirs 

are tightly packed, and ensuring hydrocarbon flow through risers and pipelines can be 

difficult. According to a 2008 report from Chevron engineers for the Society of Petroleum 

Engineers, all these factors “separate many [Gulf of Mexico] deepwater and ultradeepwater wells from deepwater and ultra-deepwater wells in other parts of the world.”117

Drilling in extreme water depths poses special challenges. Risers connecting a drilling 

vessel to the blowout preventer on the seafloor have to be greatly lengthened, and they 

are exposed to strong ocean currents encountered in the central Gulf. Managing higher 

volumes of mud and drilling fluid in these long risers makes drillers’ jobs more demanding. 

Connecting and maintaining blowout preventers thousands of feet beneath the surface 

can only be performed by remote-operating vehicles. A 2007 article in Drilling Contractor

described how blowout preventer requirements got tougher as drilling went deeper, because 

of low temperatures and high pressures at the ocean bottom. The author discussed taking 
52 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

advantage of advances in metallurgy to use higher-strength materials in the blowout 

preventers’ ram connecting rods or ram-shafts. More generally, he suggested “some 

fundamental paradigm shifts” were needed across a broad range of blowout-preventer 

technologies to deal with deepwater conditions.118 

Under such conditions, methane hydrates raised a host of serious problems. Methane 

gas locked in ice (“fire ice”) forms at low temperature and high pressure, and can often 

be found in sea-floor sediments. Temperature and pressure changes caused by drilling, 

or even by natural conditions, can activate the release of 160 cubic feet of gas from 

one cubic foot of methane, collapsing surrounding sediment, and thus destabilizing the 

drilling foundation. Hydrates can also present well-control problems. As hydrocarbons 

are produced and transported in cold temperatures and high pressures, hydrates can form 

and block the flow through deep pipelines and other conduits. Government, academic, and 

industry research programs on hydrates and associated flow problems begun in the 1990s 

are continuing.119

More broadly, knowledge about localized geology, types of hydrocarbons, and pressure 

profiles in ultra-deepwater wells is still not thoroughly developed. Geological conditions are 

complicated and vary from prospect to prospect, and from well to well. Each well, indeed, 

has its own “personality” that requires maintaining an extremely delicate balance between 

the counteracting pressures of the subsurface formation and drilling operation. Beneath 

the salt, pressures in the pores of the sediment are exceedingly hard to predict. Reservoirs in 

the Lower Tertiary are thicker and with higher viscosity than the fluids found in younger 

rock. Finally, ultra-deepwater developments are far removed from shore and thus from 

established infrastructure. As a BP technical paper prepared for the May 2010 Offshore 

Technology Conference noted, “the trend of deepwater discoveries in the [Gulf of Mexico] 

is shifting toward one with greater challenges across many disciplines represented by the 

conditions of Lower Tertiary discoveries.”120

Nevertheless, the challenges seemed manageable and the rewards appeared worth the 

perceived risk. The offshore industry had enjoyed a long run in the Gulf without an 

environmental catastrophe. The hurricanes of mid-decade had caused widespread damage, 

but not a major offshore spill. In recent years, the industry had touted its relatively clean 

record in the Gulf as a justification to allow exploration elsewhere. As oil prices climbed 

from 2003 to 2008, peaking at over $140 per barrel, so did the industry’s interest in 

exploring other frontier areas, especially offshore Alaska. In 2007, Shell and Total bid 

aggressively for federal leases offered in the Beaufort Sea, and in 2008, Shell spent $2.1 

billion for leases in the Chukchi Sea. The following year, however, a lawsuit in a federal 

appeals court challenging the Minerals Management Service’s environmental studies 

preceding the sale held up applications for permits to drill on these leases.121

Still, from 2008 through early 2010, both government and industry were largely bullish 

about the potential of offshore drilling for the nation’s future. Not incidentally, both were 

earning even greater revenues from ever-more ambitious exploration. In 2008, President 

George W. Bush and Congress ended the leasing moratoriums on vast stretches of the U.S. 

outer continental shelf, and Bush proposed opening new areas for exploration. In a March 
Chapter Two 53 53

31, 2010 announcement, President Barack Obama scaled back Bush’s plan, but he left open 

the possibility of expanding offshore leasing beyond the Gulf of Mexico and Alaska. The 

President defended his position by observing, “oil rigs today generally don’t cause spills.”122

As President Obama spoke, Transocean’s Deepwater Horizon—fresh from completing 

BP’s spectacular find at Tiber a few months earlier—was busy drilling on BP’s Mississippi 

Canyon 252 lease, in approximately 5,000 feet of water. BP had named the prospect 

Macondo, after the fictional town in Gabriel Garcia Marquez’s novel, One Hundred Years 

of Solitude. The fate of the town of the Macondo, as described in a memorable passage by 

Marquez, presaged the fate of the Macondo well and summed up the challenges facing the 

industry as a whole as it plumbed the depths of the Gulf:

It was as if God had decided to put to the test every capacity for surprise and 

was keeping the inhabitants of Macondo in a permanent alternation between 

excitement and disappointment, doubt and revelation, to such an extreme that no 

one knew for certain where the limits of reality lay.123

Chapter Three 55 55

Oversight—and Oversights—in 

Regulating Deepwater Energy 

Exploration and Production in the 

Gulf of Mexico

The Deepwater Horizon rig sank on April 22, 

2010, two days after the Macondo well blowout 

and explosion that killed 11 workers. Not long 

after the tragedy, its repercussions shifted to the 

Minerals Management Service (MMS), the federal 

agency responsible for overseeing the well’s drilling 

and operation. Nineteen days after the rig sank, 

Secretary of the Interior Ken Salazar announced his 

intention to strip MMS’s safety and environmental 

enforcement responsibilities away from its leasing, 

revenue collection, and permitting functions, 

and to place the former within a “separate and 

independent” entity.1 A week later, he announced 

MMS would be reorganized into three separate 

entities with distinct missions: a Bureau of Ocean 

Energy Management; a Bureau of Safety and 

Environmental Enforcement; and an Office of 

Natural Resources Revenue.2 And, by June 19, 

the Secretary had discarded the “MMS” name 

altogether.3 Like the Deepwater Horizon, MMS had 

ceased to exist. 

The rig’s demise signals the conflicted evolution—

and severe shortcomings—of federal regulation 

of offshore oil drilling in the United States, and 

particularly of MMS oversight of deepwater 

Chapter Three

“It was like 

pulling teeth.”

The often competing goals of energy independence and environmental 

protection collide at the Department of the Interior, which historically has held 

broad regulatory authority in both realms. For nearly three decades a single 

departmental agency, the Minerals Management Service, was at the center of 

the offshore-oil saga.

Mark Wilson/Getty Images
56 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

drilling in the Gulf of Mexico. The regulatory context for the leasing procedures and 

safety and environmental oversight that led up to the Macondo blowout took shape in 

the 1970s, when two conflicting priorities dominated the political landscape. The first to 

appear, in the early 1970s, was the public mandate for environmental protection, which 

prompted enactment of an extraordinary series of sweeping regulatory laws intended, 

in the language of the National Environmental Policy Act, to “create and maintain 

conditions under which man and nature can exist in productive harmony.”4 The second 

was the nation’s drive for energy independence; it led to new policies designed to increase 

domestic production and decrease American reliance on foreign energy supplies. Oil served 

as a catalyst for both: the Santa Barbara oil spill in 1969 helped to promote passage 

of demanding environmental protection mandates, and the OPEC oil embargo of 1973 

amplified the urgency of efforts to make the nation more energy self-sufficient. 

The federal regulation of offshore drilling awkwardly combined the two priorities, as a 

series of Congresses, Presidents, and Secretaries of the Interior—responding to competing 

constituencies in explicitly political ways—sought to reconcile the sometimes conflicting 

goals of environmental protection, energy independence, and revenue generation. In some 

offshore regions, oil drilling was essentially banned in response to environmental concerns. 

Elsewhere, most notably in the Gulf, some environmental protections and safety oversight 

were formally relaxed or informally diminished so as to render them ineffective, promoting 

a dramatic expansion of offshore oil and gas production and billions of dollars in federal 

revenues. 

The origins of MMS vividly illustrate that political compromise. Secretary of the Interior 

James Watt created the agency with great fanfare in January 1982, aiming from the 

outset to promote domestic energy supplies by dramatically expanding drilling on the 

outer continental shelf. He combined, in one entity, authority for regulatory oversight 

with responsibility for collecting for the U.S. Treasury the billions of dollars of revenues 

obtained from lease sales and royalty payments from producing wells.5 From birth, MMS 

had a built-in incentive to promote offshore drilling in sharp tension with its mandate to 

ensure safe drilling and environmental protection. 

Revenue generation—enjoyed both by industry and government—became the dominant 

objective. But there was a hidden price to be paid for those increased revenues. Any 

revenue increases dependent on moving drilling further offshore and into much deeper 

waters came with a corresponding increase in the safety and environmental risks of such 

drilling. Those increased risks, however, were not matched by greater, more sophisticated 

regulatory oversight. Industry regularly and intensely resisted such oversight, and neither 

Congress nor any of a series of presidential administrations mustered the political support 

necessary to overcome that opposition. Nor, despite their assurances to the contrary, did 

the oil and gas industry take the initiative to match its massive investments in oil and gas 

development and production with comparable investments in drilling safety and oil-spill 

containment technology and contingency response planning in case of an accident. 

On April 20, the inherent risks of decades of inadequate regulation, insufficient investment, 

and incomplete planning were realized in tragic fashion. MMS no doubt can fairly boast 
Chapter Three 57 57

of many hardworking individual public servants who have in good faith sought to 

achieve their agency’s important safety mission over sustained industry opposition. But, 

notwithstanding their individual efforts and accomplishments, the overall picture of MMS 

that has emerged since April 20 is distressing. MMS became an agency systematically 

lacking the resources, technical training, or experience in petroleum engineering that 

is absolutely critical to ensuring that offshore drilling is being conducted in a safe and 

responsible manner. For a regulatory agency to fall so short of its essential safety mission 

is inexcusable.

This chapter is divided into three parts. The first part describes the emergence of MMS as 

the dominant federal regulatory agency responsible for overseeing the offshore oil and gas 

industry. The second part examines the performance of MMS over time, with particular 

focus on its efforts to promote drilling safety and the institutional, political, and cultural 

impediments to its success. Finally, the third part explores in more detail the application 

of environmental protection requirements to offshore drilling, highlighting the particular 

ways in which the requirements were effectively diminished or ignored. 

Creation of a Cross-Purposes Regulator

The federal government’s authority to regulate oil and gas leasing activities on the outer 

continental shelf is not merely an expression of the government’s traditional authority to 

regulate private activities affecting public health, safety, and welfare. Its authority is even 

more sweeping in nature and further arises out of the nation’s ownership of the natural 

resources on the outer continental shelf and the federal government’s corresponding power 

and responsibility to manage and protect those invaluable resources on behalf of current 

and future generations of Americans. As described by the Constitution’s Property Clause, it 

is the “power to dispose and make all needful rules and regulations respecting the territory 

or other property belonging to the United States.”6 The federal government, accordingly, 

has plenary authority, essentially “without limitations,”7 “to prescribe the conditions upon 

which others may obtain rights in” natural resources located on properties that belong 

to the nation as a whole.8 Because, moreover, of the national security implications of 

those resources, especially energy resources, that national power further implicates the 

President’s broad authority as Commander-in-Chief to ensure the maintenance of sufficient 

energy supplies to keep the nation secure.9

Rights and Riches: The Early Skirmishes over the Outer Continental Shelf

The foundations of federal regulation of offshore oil and gas development were laid in the 

Outer Continental Shelf Lands Act of 1953.10 That initial legislation gave the Department 

of the Interior diverse and potentially contradictory responsibilities for offshore mineral 

development. The vigorous debates preceding enactment of the new law and its early 

implementation gave the impression that it was all about the money.11

The potential windfall from leasing public land offshore to private companies for 

mineral development provoked an intense dispute between coastal states and the federal 
58 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

government. In 1945, President Harry Truman had proclaimed federal authority 

over the subsoil of the U.S. continental shelf. California, Texas, and Louisiana defied 

this proclamation and continued to lease offshore land, prompting suits by the U.S. 

Department of Justice. The Supreme Court ruled against California in 1947 and against 

Louisiana and Texas in 1950, declaring that the federal government possessed “paramount 

rights” that transcended the states’ rights of ownership.12 Offshore leasing and exploration 

stalled for three years, as Congress and the 1952 presidential candidates postured around 

proposals to return submerged coastal lands to the states.13 That conflict was largely 

resolved in the Submerged Lands Act, passed in 1953, two months before the Outer 

Continental Shelf Lands Act: states would control three nautical miles out from the 

shoreline (9 nautical miles for Texas and western Florida due to historic claims).14 The 

“outer continental shelf”—seaward of state lands—was claimed by the federal government. 

Estimates of the value of federal land offshore ranged from $40 billion to $250 billion.15

President Truman had called on the nation to postpone mineral development in the federal 

offshore area, foregoing the revenues immediately available. He argued that setting the 

federal offshore area aside, in the Naval Petroleum Reserve, would ensure that the oil 

and gas would be there later when needed for strategic purposes.16 But the congressional 

debates in 1953, under President Dwight Eisenhower, focused on what to do with this 

attractive new source of revenue. Various senators proposed dedicating the funds to deficit 

reduction or to education. But in the end, the new money from lease sales, rents, and 

royalties would flow into the general treasury.17

The first leases. During the first week of September 1954, Secretary of the Interior 

Douglas McKay announced the first federal lease sale: rights to explore 748,000 acres 

off the coast of Louisiana.18 When the sealed bids were opened on October 13, half the 

available acreage was leased with winning bids totaling $130 million. The next month, 

a similar sale off the Texas coast yielded $23 million.19 The promise of a new stream of 

federal revenue had come to pass.

The Rise of Environmental Law

At the outset, environmental restrictions on offshore drilling were very limited. The 1953 

legislation governing offshore mineral development authorized the Interior Department to 

prescribe rules “for the prevention of waste and conservation of natural resources” of the 

outer continental shelf,20 but “conservation” at that time mostly referred to the desire not 

to waste the resource physically by destroying the oil and gas reservoir. The Department 

did announce, however, that the Fish and Wildlife Service would have to approve all 

offshore drilling in wildlife refuges and that oil and gas leasing there that endangered “rare” 

wildlife species (like whooping cranes or trumpeter swans) would not be allowed.21

Federal offshore leasing policy remained largely unchanged until a Union Oil Company 

well located in the Santa Barbara Channel blew out on January 28, 1969 (described in 

Chapter 2). The Interior Department toughened its rules in response to the spill (after first 

issuing a moratorium on offshore drilling and production in California waters pending 

those new rules), the first changes since 1953.22 And, at that time Congress was already 

taking up legislation in response to heightened awareness of a host of environmental 
Chapter Three 59 59

problems, now punctuated by the Santa Barbara spill. Starting with the National 

Environmental Policy Act (NEPA), signed into law on January 1, 1970,23 Congress enacted 

sweeping new environmental protection and resource conservation laws that dramatically 

changed the federal role in overseeing activities that polluted the air or water or that 

exploited the nation’s natural resources on public lands—including offshore oil and gas 

development.24

Given its bold promises of preserving the environment for future generations, NEPA is 

often referred to as the Magna Carta of the nation’s environmental laws. It requires federal 

agencies to prepare “environmental impact statements” for all proposed “major Federal 

actions significantly affecting the quality of the human environment” in order to ensure 

that decisions are based on full consideration of their environmental consequences.25

Although it is far from clear that either Congress or the President appreciated NEPA’s full 

import, federal courts quickly embraced the law, applying its procedural requirements 

strictly and enjoining agency actions found to be in violation.26

In order to provide the science needed for the environmental reviews and consultations 

directed by these statutes, the Department of the Interior created the “Environmental 

Studies Program” in 1973.27 The program was established to provide information on the 

geological, physical, biological, and chemical characteristics of offshore oil and gas leasing 

areas. It was initially focused on scientifically characterizing areas and providing baseline 

environmental data, but later shifted its focus to research directly linked to resource 

management decisions by the offshore leasing program.28 

NEPA was just the first among approximately 20 new laws enacted during the 1970s that 

aimed to advance environmental protection by curbing pollution of the nation’s waters, 

air, or land; manage commercial activities that sought to exploit the nation’s natural 

resources, including mining and forestry; manage the coastal zone prudently; control 

noise; regulate toxic substances; and protect endangered species—among other goals.29

Amid this rapid, extensive transformation of the nation’s environmental protection and 

natural resource management laws, one had particular significance for federal oversight of 

offshore drilling: the Outer Continental Shelf Lands Act Amendments of 1978. It was the 

last major natural resource law that Congress passed during the 1970s—and so embodies 

the shifting nature of national politics from the decade’s beginning to its end.

Energy Independence vs. Environmental Protection: 

Conflicting Aims in High Relief

Although Americans’ embrace of environmental protection persisted throughout the 

decade, the 1973 oil embargo prompted ambitious efforts to promote the nation’s energy 

independence. President Richard Nixon proposed a dramatic expansion of offshore oil and 

gas development, including in frontier areas around most of the nation’s coast. President 

Jimmy Carter created the Department of Energy in 1977 and secured passage of the 

National Energy Act of 1978, consisting of five separate laws, some designed to promote 

development of domestic energy supplies and others to encourage energy conservation.30
60 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

The Outer Continental Shelf Lands Act Amendments, also enacted that year, not 

surprisingly reflected the tension between the nation’s environmental and energy 

independence goals. Those skeptical of accelerated offshore leasing—including many 

coastal states, local governments, fishermen, and environmentalists—sought, to that end, 

opportunities to ensure that offshore oil and gas leasing complied with strict safeguards 

and a greater voice in the decisionmaking process. They were concerned about the broad 

discretion the Act conferred on the Secretary of the Interior over control and management 

of offshore energy resources. 

By contrast, advocates for expanded domestic production wanted to ensure that the new 

legislation did not allow environmental protection laws to stifle exploration, development, 

and production of significant offshore oil and gas reservoirs. They were aware that 

environmental organizations had used NEPA successfully to challenge a proposed lease 

sale, covering almost 380,000 acres offshore Louisiana and Mississippi, on the grounds 

that the Interior Department had failed to first prepare an adequate environmental impact 

statement. The federal courts had agreed and enjoined the sale in January 1972.31 Coastal 

states and environmentalists had since launched challenges against other lease sales. 

Congress began to hold hearings on revamping the federal offshore leasing program in 

1974—just after the oil embargo and not long after those early environmental challenges.32

The law that emerged in 197833 included findings on the need to reduce the nation’s 

dependence on “imports of oil from foreign nations,” the potential to increase production 

of oil and gas on the outer continental shelf significantly “without undue harm or damage 

to the environment,” and the need to review “environmental and safety regulations 

relating to activities on the Outer Continental Shelf . . . in light of current technology 

and information.”34 The Act’s purposes included “expedited exploration and development 

of the Outer Continental Shelf” and the “development of new and improved technology 

for energy resource production which will eliminate or minimize risk of damage to the 

human, marine, and coastal environments.”35 

The 1978 Act fundamentally transformed federal offshore leasing. The law added detailed 

procedures governing the leasing of rights to explore, develop, and produce the resources of 

the outer continental shelf. The offshore program was divided into four distinct stages:

•	 Development by the Secretary of the Interior of a “schedule of proposed lease sales 

indicating, as precisely as possible, the size, timing, and location of leasing activity 

which he determines will best meet national energy needs for the five-year period 

following its approval or reapproval”;36

•	 Lease sales by the Secretary pursuant to that five-year schedule;

•	 Submission by lessees of exploration plans for the Secretary’s approval; and

•	 Upon discovery of oil and gas in commercial quantities, submission of development 

and production plans by lessees for the Secretary’s approval.

The Act further requires lessees to apply for the Secretary of the Interior’s permission 

prior to drilling any wells, pursuant to an approved exploration plan37 or, in most areas, 

pursuant to a development and production plan.38 
Chapter Three 61 61

At the same time, the statute also made clear that environmental safeguards are a relevant, 

important part of the Secretary’s decisionmaking. For instance, it charged the Secretary 

“to obtain a proper balance between the potential for environmental damage, the potential 

for discovery of oil and gas, and the potential for adverse impact on the coastal zone.”39

The law also expressly required the Secretary to prepare a series of “environmental studies” 

PRE-LEASE

POST-LEASE

EXPLORATION PLAN SUBMITTED

APPLICATION FOR PERMIT TO DRILL APPROVED | PERMITS GRANTED

EXPLORATION DRILLING STARTS

FIRST EXPLORATION WELL COMPLETED

NOTICE OF SALE

SALE

DEFINE SALE AREA

CALL FOR INFORMATION PUBLISHED

LEASES ISSUED

DELINEATION DRILLING

SOLICIT COMMENTS

PROPOSED PROGRAM DRAFT

5-YEAR PROGRAM ANNOUNCED

PROPOSED FINAL DRAFT

DRAFT PROPOSED PROGRAM PUBLISHED

DEVELOPMENT & PRODUCTION PLAN APPROVED

DEVELOPMENT & PRODUCTION PLAN

PRODUCTION WELL APPLICATION

• Stage I: Develop 5-Year Program

• Stage II: Planning for Specific Sale

• Stage III: Exploration Plan Approval

• Stage IV: Development & Production Plan Approval

FIRST OIL/GAS PRODUCTION

FIGURE 3.1: Outer Continental Shelf Oil and Gas Leasing, Exploration & Development Process

Four major steps guide the Outer Continental Shelf leasing and development process, from the decision to open an area to drilling, to the 

operations during oil and gas production. Before a lease is granted, Stage I establishes the “5-Year Program,” setting the schedule and 

possible locations for individual lease sales, and Stage II lays out the details by which each individual lease sale is conducted. After a 

company acquires a lease, Stage III plans and executes the oil and gas exploration activities, and Stage IV plans and executes the oil and 

gas development and production operations.
62 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

to assess the environmental impacts of activities on the outer continental shelf,40 and 

“the Secretary of the Department in which the Coast Guard is operating” (currently the 

Department of Homeland Security) to promulgate “safety regulations.”41 Such regulations 

were to include “the use of the best available and safest technologies which the Secretary 

[of the Interior] determines to be economically feasible, wherever failure of equipment 

would have a significant effect on safety, health, or the environment.”42 But this 

potentially demanding requirement included an exception “where the Secretary determines 

that the incremental benefits are clearly insufficient to justify the incremental costs of 

utilizing such technologies.”43

The Gulf of Mexico exemption. Offsetting the apparent interest in environmental review, 

the Act reflected a carefully calibrated political compromise designed to promote offshore 

drilling: it expressly exempted leases in the “Gulf of Mexico” from the law’s requirement 

that development and production pursuant to an oil and gas lease must be based on and 

consistent with a “development and production plan” submitted by the lessee and approved 

by the Secretary of the Interior.44 (No comparable exception applied to “exploration plans,” 

which all lessees were required to submit for approval prior to conducting such drilling, 

which naturally occurs prior to development and production.45) The telling compromise 

lay in the details: the law specified that a development and production plan must set forth 

“the environmental safeguards to be implemented”46 and the Secretary must at least once 

declare the approval of a development and production plan in any area “to be a major 

Federal action”—language which triggers NEPA’s requirement for an impact statement 

detailing the environmental consequences of development and production.47 Therefore, 

by exempting leases in the Gulf from the required “development and production plan,” 

the Act was also exempting such leases from the related requirement of at least one NEPA 

impact statement.48 And the Act included one further bit of congressional horse-trading. 

It authorized the Secretary of the Interior to reinstate the development and production 

plan requirements, including NEPA review, for an oil and gas lease located in the eastern

planning area of the Gulf abutting the western coastline of Florida, leaving only the central

and western Gulf planning areas off limits from such requirements.49 

The legislative history makes clear that this was a deal brokered between the Carter 

administration, the oil and gas industry, Congress, and Gulf states. Industry had argued 

that NEPA and similar requirements could lengthen the interval between leasing and 

production by three to six years. In response to this concern, Congress amended the bill 

to draw a distinction between the Gulf of Mexico, where such consultation would not 

be required, and other offshore areas where it would. The rationale for singling out the 

Gulf of Mexico for less environmental oversight than other parts of the nation’s offshore 

was that the oil and gas industry in the Gulf was already mature and therefore the 

environmental risks were already better known than they were in “frontier” areas. This 

rough geographically-defined generalization took no account of the Gulf’s remarkable 

fisheries, or the economic importance of the region’s beaches to the tourism industry. 

Secretary of the Interior Cecil Andrus sought administrative discretion to require the full 

environmental review even in some non-frontier areas if drilling in those areas proved 

to present heightened environmental risks,50 but the final legislation made that further 

concession only for a part of the Gulf.51
Chapter Three 63 63

A compromise comes undone. Whatever compromise Congress and President Carter 

may have thought they had struck in the 1978 legislation quickly unraveled. In the first 

five-year leasing schedule issued in June 1980, Secretary Andrus offered 55 million acres, 

and proposed Lease Sale 53 along the Pacific Coast. Unlike previous sales, which had been 

concentrated on one geographic region, Lease Sale 53 called for nominations of tracts from 

the Santa Barbara Channel all the way up the California coast to the Oregon border. Fierce 

opposition immediately greeted the proposed leasing schedule and Lease Sale 53. California 

and Alaska filed lawsuits challenging the legality of the leasing schedule under the 1978 

law. After huge public rallies, Secretary Andrus formally withdrew the entire northern and 

central California portion of the proposed sale.52

The Creation of the Minerals Management Service (MMS)

Against a backdrop of rising inflation, record interest rates, further turbulence in the 

oil market following the 1979 Iranian revolution, and a severe recession, the politics 

of offshore drilling became even more volatile early in the administration of President 

Ronald Reagan, who was inaugurated in January 1981. Perhaps not surprisingly, after 

the upwelling of new regulatory powers under Presidents Nixon, Ford, and Carter, the 

new President made clear from the outset his view that government regulation was a 

leading cause of the nation’s problems—a drag on the nation’s economy in general and the 

development of its rich natural resources in particular. 

Secretary of the Interior James Watt shared that outlook and focused his early regulatory 

reform efforts on offshore drilling. He quickly vowed to lease a billion acres of the outer 

continental shelf—virtually the entire area—for oil and gas exploration.53 And he made 

clear his commitment to maintaining that objective, notwithstanding enormous criticism: 

“If the press is here,” he declared during a National Ocean Industries Association meeting in 

April 1982, “I hope they will write this down. We will offer one billion acres for leasing in 

the next five years. We will not back away from our plans to have 42 lease sales.”54

MMS originated in this context, driven by the administration’s desire to ensure that it 

obtained the financial fruits of its plan for this massive expansion in offshore drilling. With 

the dramatic increase in oil prices over the previous decade, royalties and revenues from 

federal oil and gas resources had already become the second largest revenue source for the 

U.S. Treasury. (A September 1980 lease sale in New Orleans had demonstrated the sums 

potentially at stake, bringing in a record $2.8 billion of cash bonuses, far more than any 

prior lease sale; see Chapter 2.) Clearly, this was a consequential way to secure revenue 

without needing to raise taxes. 

Revenue collection and regulation, separated. Until this time, the Interior Department’s 

Bureau of Land Management and Bureau of Indian Affairs had been responsible for 

collecting royalties for mining and drilling on federal and Indian lands, respectively—and 

regulatory oversight of offshore exploration and energy production had been vested in the 

U.S. Geological Survey’s Conservation Division. 

But the department’s management of royalties was subjected to frequent criticism. In 

July 1981, the administration created a Commission on Fiscal Accountability of the 
64 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Nation’s Energy Resources, charged with reviewing and recommending changes in the 

system for collecting royalties. Reporting the next January, the commission concluded 

that “[m]anagement of royalties for the nation’s energy resources has been a failure for 

more than 20 years. . . . [T]he oil and gas industry is not paying all the royalties it rightly 

owes. The government’s royalty recordkeeping . . . is in disarray.”55 It accordingly called 

for a complete overhaul, including a wholesale reorganization of Interior Department 

responsibility for overseeing royalty collection from federal and Indian lands. 

Mixing oil and water: revenue-collection and regulation combined. Using the discretion 

conferred on him in the 1978 Outer Continental Shelf Lands Act Amendments, Secretary 

Watt moved quickly, issuing Secretarial Order No. 3071 on January 19, creating the 

Minerals Management Service. Moving beyond the commission recommendations for 

reform of royalty collection, he provided that the new agency would also absorb offshore 

leasing and oversight responsibilities from the U.S. Geological Survey. There is no available 

formal record of his reasoning for this further step, but the most likely reasons are revealed 

by a memorandum written by the Chief of the Conservation Division, Don Kash, dated 

December 11, 1981, just a few weeks earlier. In that memo, Kash vigorously argued in 

favor of relocating responsibilities for lease management from the Conservation Division 

into a new independent agency within the Interior Department—precisely what the 

Secretary then did. 

$0

$4

$10

$16

$20

Nominal Dollars (Billions)

Year*

195519601965197019751980198519901995200020052010

• Other Revenues

• Lease Bonuses

• Royalties

Source: Commission Staff, Adapted from DOI

*Calendar year from 1955–2000; scal year from 2001–2010

$2

$6

$8

$18

$14

$12

FIGURE 3.2: Federal Revenues from the Outer Continental Shelf, 1955-2010

Sources: Minerals Revenue Management, Total Federal offshore mineral revenue collections, Calendar Years 1953-2000, 2001, 7, 

http://www.onrr.gov/Stats/pdfdocs/coll_off.pdf; Office of Natural Resources Revenue, Total Federal Offshore Reported Royalty Revenues, 

http://www.onrr.gov/ONRRWebStats/Home.aspx. 

Revenues from lease bonuses can occasionally dwarf royalties. A single 2008 lease sale in the Chukchi Sea, Alaska, brought in a record cash 

bonus of $2.6 billion. 

* Calendar year from 1955-200; fiscal year from 2001-2010
Chapter Three 65 65

But Secretary Watt’s decision did not fully reflect Kash’s concerns. The latter had worried 

that the controversial politics of lease management were “sullying the [U.S. Geological] 

Survey’s scientific reputation” and threatened its “science ethos” and “scientific virtue.” 

The collision of cultures between those engaged in scientific research and those engaged 

in lease management was a “continuing source of irritation” and “bitterness” within the 

U.S. Geological Survey. He was concerned that lease management would increasingly 

take priority, draining resources from the research that should be the hallmark of the 

U.S. Geological Survey. Finally, Kash described problems that leasing management would 

face going forward—foremost among them a tendency toward myopic thinking and 

inadequately trained personnel. On that last issue, he pointed out that the government 

could not retain “geologists and geophysicists associated with [outer continental shelf] 

activities” because they “can move to an industrial or business concern for a substantial 

increase in pay, almost at will.” Kash recommended a series of steps to attract and train 

personnel capable of overseeing the management of offshore oil and gas activities.56

Secretary Watt organized two distinct programs within his newly-minted MMS: 

the Offshore Energy and Minerals Management program and the Minerals Revenue 

Management program. (He rejected the General Accounting Office’s recommendation, 

which industry had opposed, that MMS also assume responsibility for onshore oil and 

gas leasing; the Bureau of Land Management retained that regulatory authority.57) The 

result was that the same agency became responsible for regulatory oversight of offshore 

drilling—and for collecting revenue from that drilling.

The Billion-Acre Leasing Land Rush

It did not take long for Secretary Watt to make sure that his new agency was fully 

engaged. In July 1982, just after MMS’s birth, he issued a new five-year plan that 

envisioned leasing nearly one billion acres of the outer continental shelf from August 

1982 to June 1987—18 times the 55 million acres offered by the first five-year plan of 

June 1980. To meet this ambitious program, he scheduled 41 sales over the ensuing five 

years; divided the billion acres into 18 planning areas, ranging in size from 8 million to 

133 million acres; and established a streamlined process for leasing in those areas. Under 

this new process, MMS would no longer lease just those tracts previously designated by 

industry to be of interest, but would instead offer vast acreage on an “area-wide” basis.58

As described in Chapter 2, area-wide leasing promoted significant new discoveries of large 

oil-bearing formations in contrast to the smaller fields found in shallower depths. Those 

additional discoveries in fact led to major technological advances and increased exploration 

of oil and gas reservoirs in Gulf waters. But the federal revenues generated fell short of 

expectations. With such a large increase in supply, the price offered for leases declined. 

The Sierra Club claimed that Secretary Watt’s plans for accelerated leasing would cost the 

U.S. Treasury $77 billion over the five-year period.59 Moreover, the Gulf states persuaded 

Congress to increase their share of leasing revenues as compensation for physical drainage 

of oil and gas from reservoirs within state jurisdiction by offshore activities of federal 

lessees. In 1986, Congress amended the federal law to guarantee that the Gulf states would 

receive 27 percent of the revenues from leases in the federal zone three nautical miles 
66 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

beyond state waters.60 Previously the law had provided only that states should receive 

a “fair and equitable” portion of those revenues, an ambiguous standard that invited 

disagreement between the federal and state governments concerning what that portion 

should be. 

The Gulf of Mexico’s still-more-special status. The distinction first drawn in the 1978 

Act between offshore drilling in the Gulf of Mexico and in other parts of the nation was 

widened further during the 1980s and 1990s. What began as a policy allowing offshore 

drilling in the Gulf under a more relaxed regulatory regime than applied elsewhere 

gradually became a policy of allowing offshore drilling, as a practical matter, almost only

in the Gulf.

Court challenges quickly greeted Secretary Watt’s efforts to expand offshore leasing 

throughout the United States. But decisively, Congress, not court rulings, ended the 

Secretary’s plan and effectively singled out the Gulf for offshore drilling. In a series of 

Watt and Reagan

In January 1982, President Reagan’s Interior Secretary, James Watt, created the Minerals Management Service (MMS) in support of his goal 

to open unprecedented reaches of U.S. territorial waters to oil and gas exploration. MMS had a conflicting and ultimately disastrous mandate: 

to both regulate offshore energy leases and collect the revenue they generated. 

Frank Johnston/The Washington Post via Getty Images
Chapter Three 67 67

recurring one-year moratoriums imposed on the Interior Department’s annual budgets, 

the House Appropriations Committee effectively prohibited everything from new leasing 

activities to exploration and development on existing leases in areas all over the outer 

continental shelf outside the Gulf of Mexico and a few sub-regions off of Alaska.61 From 

1982 to 1993, the area covered by these moratoriums expanded from 0.7 million acres 

to 266 million.62 The persistent unpopularity of offshore drilling outside the Gulf was 

underscored by President George H.W. Bush. Despite his background as a former Gulf 

state (Texan) oil-industry executive, he issued a memorandum in June 1990 that canceled 

all scheduled sales off of the California, southern Florida,* North Atlantic, Washington, 

and Oregon coasts and withdrew those areas from leasing until after 2000 (Alaska was 

not mentioned). At the same time, the President began a process to buy back existing 

leases in the eastern Gulf of Mexico; he established the proposed Monterey Bay Marine 

Sanctuary, banning oil and gas leasing there; and he prepared legislation to provide coastal 

communities directly affected by outer continental shelf development with a greater share 

of revenues from development and more voice in decisionmaking.63

Secretary Watt’s promise of offshore drilling throughout the outer continental shelf was 

never realized. But he succeeded in creating an agency (MMS) and a method of leasing 

(via area-wide sales) that dramatically expanded the reach of offshore drilling in one 

place: the Gulf of Mexico. In that one oil- and gas-rich region, that same agency would 

increasingly struggle to keep up with the pace of industry expansion, while juggling four 

distinct responsibilities—offshore leasing, revenue collection and auditing, permitting 

and operational safety, and environmental protection—requiring different skill sets and 

cultures. 

Impediments to Safety Regulation

The federal government has never lacked the sweeping authority required to control 

whether, when, and how valuable oil and gas resources located on the outer continental 

shelf are leased, explored, or developed. As described at the outset, the government’s 

authority is virtually without limitation, traceable to both its authority as proprietor 

and as sovereign, then further bolstered by the President’s inherent authority as Chief 

Executive and Commander-in-Chief to ensure the security of the nation. The root problem 

has instead been that political leaders within both the Executive Branch and Congress have 

failed to ensure that agency regulators have had the resources necessary to exercise that 

authority, including personnel and technical expertise, and, no less important, the political 

autonomy needed to overcome the powerful commercial interests that have opposed more 

stringent safety regulation. 

* Although Florida’s jurisdiction offshore extends to 9 nautical miles, Florida has not joined those other states in favoring significant offshore oil and gas drilling. Florida 

has instead supported continuing moratoriums on drilling in the outer continental shelf off the Florida coast. Nor has the State sought to promote such drilling within its 

territorial jurisdiction offshore. Florida’s principal reason has been to protect its coast from the potential adverse environmental consequences of drilling activity, including 

oil spills. See Robert Gramling, Oil on the Edge: Offshore Development, Conflict, Gridlock (Albany, NY: SUNY Press, 1996), 13. 
68 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Safety on the Outer Continental Shelf: Increasing Risk, Absence of Necessary 

Regulatory Reform, and Decreasing Government Oversight Capacity 

Modern oil and gas drilling rigs and producing platforms are, in effect, enormous 

floating machines, densely equipped with powerful engines and responsible for keeping 

within geologic formations large volumes of highly combustible hydrocarbons at high 

temperatures and pressures. For all their productivity, the rigs expose their crews to the 

risks of injury or death if not properly operated and maintained—risks compounded for 

operations conducted in progressively deeper waters, ever farther from shore. 

From its creation until the Macondo well blowout, MMS was the federal agency primarily 

responsible for leasing, safety, environmental compliance, and royalty collection from 

offshore drilling.* In carrying out its duties, MMS subjected oil and gas activities to an 

array of prescriptive safety regulations: hundreds of pages of technical requirements for 

pollution prevention and control, drilling, well-completion operations, oil and gas wellworkovers (major well maintenance), production safety systems, platforms and structures, 

pipelines, well production, and well-control and -production safety training.64 As required 

by the 1978 Act, MMS also attempted to conduct both annual and periodic unscheduled 

(unannounced) inspections of all offshore oil and gas operations to try to assess compliance 

with those requirements. Agency officials have tried to meet the requirement for annual 

inspections of the operation of safety equipment designed to prevent blowouts, fires, spills, 

and other major accidents. In both annual and unannounced inspections, MMS officials 

used a national checklist, covering categories such as pollution, drilling, well completion, 

production, crane, electrical, and personal safety. Most inspections tend to cover a subset 

of the elements on the list. Roughly 20 percent of the matters for inspection (those for the 

production meters) are not related to safety.65 

But over time, MMS increasingly fell short in its ability to oversee the offshore oil industry. 

The agency’s resources did not keep pace with industry expansion into deeper waters and 

industry’s related reliance on more demanding technologies. And, senior agency officials’ 

focus on safety gave way to efforts to maximize revenue from leasing and production. 

The “Safety Case” and MMS’s Inability to Adopt New Practices

By the early 1990s, some MMS officials had begun to rethink the agency’s approach to 

safety oversight of the offshore industry. In the wake of an accumulation of accidents in 

U.S. waters, and several devastating accidents elsewhere around the globe, they had come 

to appreciate that a command and control, prescriptive approach to regulation did not 

adequately address the risks generated by the offshore industry’s new technologies and 

exploration, development, and production activities, including industrial expansion into 

deeper waters. 

In March 1980, the Alexander Kielland—built as a drilling rig but under lease to Phillips 

Petroleum Company to house offshore workers at the Ekofisk Field in the Norwegian 

North Sea—capsized, killing 123 of the 212 people on board the “flotel.” Two years 

* Other federal agencies, including the United States Coast Guard, Department of Transportation, Occupational Safety and Health Administration, Environmental 

Protection Agency, and National Oceanic and Atmospheric Administration possess regulatory authority over discrete aspects of oil and gas operations offshore. 
Chapter Three 69 69

later, during preparation for an approaching North Atlantic storm, the Ocean Ranger 

semisubmersible drilling the Hibernia field for Mobil Oil of Canada, sank off the coast 

of Newfoundland; all 84 crew members were lost in the freezing-cold waters. And in 

July 1988, the Piper Alpha production platform operated by Occidental Petroleum 120 

miles northeast of Aberdeen, Scotland, exploded and sank, killing 167 people, including 2 

rescuers.66 Although the causes of the three accidents varied, they all involved international 

operations of U.S.-based oil and gas companies. Common contributing factors included 

inadequate safety assurance, worker training, and evacuation procedures. Poor 

communication and confusion about lines of authority amplified the death toll in at least 

two of the accidents. 

The Norwegian government responded to the loss of the Alexander Kielland by 

transforming its approach to industry operations. Under the new regime, rather than 

relying solely on prescribed operational and safety standards, the government required the 

industry to demonstrate thorough consideration of all risks associated with the structures 

and operations for a drilling or production plan. The regulator no longer “approved” 

operations. Shifting the burden of demonstrating safety to the operator, the regulator 

would instead now “consent” to development activity proceeding only upon the operator’s 

demonstration that sufficient safety and risk management systems were in place. 

The Piper Alpha accident and the subsequent investigation led by Lord Cullen had a similar 

impact on United Kingdom regulation. As in Norway, the previous prescriptive regulatory 

approach evolved into one where regulations were supplemented with a requirement 

for companies to demonstrate to the regulator that they had undertaken a thorough 

assessment of risks associated with an activity and they had adequate safety and risk 

management systems to address those risks.

All these foreign regulators—the United Kingdom, Norway, and Canada—had previously 

relied on the kind of prescriptive approach used in the United States, but in the aftermath 

of these fatal accidents in harsh, remote offshore environments, authorities elsewhere 

concluded that adding a risk-based approach was essential. They faulted reliance on 

the “prescriptive regulation with inspection model” for being fundamentally reactive 

and therefore incapable of driving continuous improvement in policies and practices.67

According to Magne Ognedal, the Director General of the Norwegian Petroleum Safety 

Authority, the prescription-only model engendered hostility between the parties and put 

the risk—legal and moral—onto the regulator to accommodate changing technology, 

geology, and location, rather than onto the operator, where the responsibility rightly 

belonged.68 Under the new safety-management model, minimum standards for structural 

and operational integrity (well control, prevention of fires and explosions, and worker 

safety) remained in place. But the burden now rested on industry to assess the risks 

associated with offshore activities and demonstrate that each facility had the policies, 

plans, and systems in place to manage those risks. In the United Kingdom, such riskmanagement plans were called a “Safety Case.”
70 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

On March 19, 1989, while the Piper Alpha accident was still under review, a platform 

operated by ARCO exploded in the South Pass Block 60 off the Louisiana coast. An 

uncontrolled release of liquid hydrocarbons ignited, destroying the platform and killing 

seven people. An MMS investigation concluded that poor management of a repair 

operation was to blame: not only was there an “absence of detailed and coordinated 

planning for the project,” there was a dearth of much-needed “oversight over contractor 

activities.”69

After South Pass Block 60, the latest in the series of tragic accidents involving U.Sbased companies, MMS convened an internal task force to review its offshore drilling 

inspection and enforcement program by October 1989. That same year, the agency 

also commissioned the Marine Board of the National Research Council to make 

recommendations for overhauling MMS’s regulatory program to best fulfill its safety 

mission at current levels of staffing and budget.70 The Marine Board’s report, delivered 

in January 1990,71 concluded that MMS’s emphasis on a list of “potential incidents of 

non-compliance” could lead to an attitude on the part of an operator that compliance 

with the list equals safety, thereby diminishing “recognition of [the operator’s] primary 

responsibility for safety.”72 The report recommended that MMS place its primary emphasis 

on the detection of potential accident-producing situations—particularly those involving 

human factors, operational procedures, and modification of equipment and facilities—

rather than scattered instances of noncompliance with hardware specifications. 

The Marine Board found that MMS needed to upgrade its program to address changes in 

the operating environment on the outer continental shelf—including its aging platforms, 

more complex systems and operations, activities in deeper water at greater distances from 

shore, and changing characteristics of operating companies. Further, the Board urged 

continuation of frequent and comprehensive inspections of facilities engaged in drilling 

and workover operations, including the conduct of the operations themselves, because of 

“(1) the high frequency of events per unit for these facilities as compared to production 

facilities, and (2) the large population of workers on each facility. . . .” Overall, the Board 

recommended that MMS cultivate a more proactive inspector corps and develop a greater 

focus on identifying emerging safety risks.73

Safety reform run aground. Unfortunately, by the time the Marine Board delivered 

its report, hardly anyone was listening. Five days after the South Pass Block tragedy 

in March 1989, the Exxon Valdez ran aground in Prince William Sound, spilling an 

estimated 11 million gallons of crude oil on the Alaskan shore. The Board’s calls for 

change were thus presented to a government still preoccupied with cleanup duties in Prince 

William Sound and to a nation attuned to demands for requiring double-hulled tankers. 

Ironically, Congress enacted the Oil Pollution Act of 1990, but failed to address any of the 

regulatory deficiencies identified by the Marine Board, while adding to MMS’s regulatory 

responsibilities (the agency was charged, under the Act and a supplementary Presidential 

Executive Order74 with overseeing offshore pipelines and oil-spill response planning and 

prevention).75 The agency’s already scarce regulatory resources were stretched even 

thinner. 
Chapter Three 71 71

MMS nonetheless tried to take the initiative for regulatory reform. In July 1991, in 

response to the Marine Board report and MMS’s own internal task force report, MMS 

published a notice requesting comments on alternative strategies to promote safety 

and environmental protection, specifically a requirement that outer continental shelf 

lessees and/or operators develop, maintain, and implement “a safety and environmental 

management program (SEMP), similar to the United Kingdom’s Formal Safety Assessment 

or Norway’s Concept Safety Evaluation programs.”76 Declaring that lessees and operators 

already had “full responsibility to plan and prepare for the overall safety and reliability 

of Outer Continental Shelf operations,” MMS asserted that requiring SEMP would help to 

enhance offshore safety and environmental protection.77 Acknowledging the difference in 

scale and scope of the activities between the Gulf of Mexico and the North Sea—as the Gulf 

consists of many more, but smaller facilities78—MMS sought in its request for comments 

“to determine the degree to which such programs exist and to draw upon that experience 

in establishing the requirements for a management control program.”79

Reform indefinitely frozen in time. At the time of the Macondo blowout—almost 20 

years after its original proposal—MMS had still not published a rule mandating that all 

operators have plans to manage safety and environmental risks. The agency’s efforts to 

adopt a more rigorous and effective risk-based safety regulatory regime were repeatedly 

revisited, refined, delayed, and blocked alternatively by industry or skeptical agency 

political appointees.80 MMS thus never achieved the reform of its regulatory oversight of 

drilling safety consonant with practices that most other countries had embraced decades 

earlier. 

Industry served as an initial impediment to MMS reform efforts—and has largely remained 

so. In late 1991, the American Petroleum Institute asked the agency to postpone action in 

order to allow the institute itself to develop an offshore safety standard.81 MMS agreed, 

and actively participated in the institute’s committee-based process over the next two 

years. The American Petroleum Institute’s “recommended practice” guidance document 

was published in May 1993—the same month that the UK Safety Case regulations came 

into force.82 Missing from the first edition of the Institute’s guideline, however, was a key 

element of standard process safety management83—nor did it even cover drilling rigs,84

clearly an integral element in operating offshore. 

MMS announced in June 1994 that it would continue evaluating the new safety concept 

for two additional years in order to determine whether it should be mandated85—a deadline 

it soon extended by yet another year, delaying a final decision until late 1997.86 In the 

meantime, the agency urged companies to adopt safety and environmental management 

systems voluntarily, and hinted that wide industry participation might prevent a formal 

rulemaking.87 

By this time, there appears to have been a working assumption within both the agency 

and the industry it was charged with overseeing that technological advances had made 

equipment remarkably reliable. As one MMS official put it in 1996, conceding that the best 

the agency could do with available resources was to encourage voluntary compliance with 

SEMP, “We want to approach our relationship with the offshore industry more as a partner 
72 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

than a policeman. We need to create an atmosphere where the primary concern is to fix the 

problem, not the blame”—an apt characterization for a period of “regulatory reform” in 

Congress and fiscal restraint nationwide.88 

Holy Grail or Poisoned Chalice? The MMS voluntary approach to risk assessment was 

met with skepticism by regulators in the North Sea. At a May 1996 industry forum in 

Houston, Texas, an official with the UK Health and Safety Executive (HSE) compared the 

two safety regimes in a presentation titled US Voluntary SEMP Initiative: Holy Grail or 

Poisoned Chalice? “Last year, with the safety cases of most UK rigs already accepted well 

ahead of the deadline, IADC [the International Association of Drilling Contractors] told us 

they were pleased to be operating a premium fleet in North Sea and that HSE was not to 

think of relaxing the safety case requirements.” By contrast, he described the voluntary 

SEMP scheme as an unrealistic halfway position, while noting that “both the US and the 

UK need more time to find out which way provides the best lasting effect.”89 

Almost a decade later, MMS was no more successful when it tried to resurrect movement 

toward even a weakened version of a safety and environmental management rule. In May 

2006, when MMS finally proposed a rule on “Safety and Environmental Management 

Systems”—the successor to the long-moribund SEMP initiative—its proposed rule was 

limited in its reach. The proposal would have required that only 4 of the 12 widely 

accepted elements of industrial process safety management be put into place. Industry 

opposition even to this watered-down proposal was swift. And, ultimately, it was only 

after the Macondo well blowout four years later that the federal agency finalized a more 

comprehensive, mandatory SEMP rule. 

Other MMS regulatory initiatives critical to safety faced strong and effective opposition. 

In 2003, the White House stiffly opposed MMS’s efforts to update its requirements for the 

reporting of key risk indicators.90 (MMS had proposed that all unintentional gas releases 

be reported, because even small gas leaks can lead to explosions.91) “It was like pulling 

teeth,” one senior MMS official involved with the process told the Commission: “We never 

got positive cooperation” from either industry or the Office of Management and Budget.92

The Offshore Operators Committee, an industry association, vehemently objected that the 

requirement would be too burdensome and not conducive to safety; MMS disagreed, yet 

the final rule in 2006 mandated that a gas release be reported to MMS only if it resulted 

in an “equipment or process shut-in,” or mechanical closure—a much less complete 

standard.93

Safety Regulation on a Starvation Diet

During the 1990s, the resources available to MMS decreased precipitously just as it 

faced a dramatic increase in the offshore activity it was charged with overseeing—and 

matters only deteriorated thereafter. Perversely, MMS’s budget reached its lowest point 

in November 1996,94 just as major development activities in deepwater were expanding. 

That December, the Houston Chronicle reported with tragic detail an 81 percent increase 

in offshore fires, explosions, and blowouts in the Gulf since 1992.95 The oil and gas 

industry drilled a record number of Gulf wells in 1997—many in deepwater.96 By 1999, 

oil production from deepwater eclipsed production from shallow water for the first 
Chapter Three 73 73

time.97 Oil production in the Gulf grew from 275 million barrels in 1990 (when only 4.4 

percent of that volume came from deepwater wells) to 567 million barrels in 2009 (when 

deepwater wells yielded more than 80 percent of the total).98 

Changing technology and changing industry structure outpacing regulations. As 

MMS’s resources lagged behind the industry’s expansion into deepwater drilling—with its 

larger-scale and more demanding technology, greater pressures, and increasing distance 

from shore-based infrastructure and environmental and safety resources—the agency’s 

ability to do its job was seriously compromised.99 Of particular concern, MMS was unable 

to maintain up-to-date technical drilling-safety requirements to keep up with industry’s 

rapidly evolving deepwater technology. As drilling technology evolved, many aspects of 

drilling lacked corresponding safety regulations. The regulations increasingly lagged behind 

industry and what was happening in the field.

When industry contended that blowout-preventer stacks—the critical last line of defense 

in maintaining control over a well—were more reliable than the regulations recognized, 

warranting less frequent pressure testing, MMS conceded and halved the mandated 

0

50

100

150

200

250

600

Barrels of Oil (Millions)

Year

19901991199219931994199519961997199819992000200120022003200420052006200720082009

• Ultra-Deep (5,000+ ft)

• Deep (1,000–4,999 ft)

• Shallow (0–999 ft)

 OEMM Enacted Budget 1984 1985 1986 1987 1988 1989

$0

$50

$100

$150

$200

$250

$300

Real 2005 Doallars (Millions)

FIGURE 3.3: MMS Budget and Gulf of Mexico Crude Oil Production, 1984-2009

Sources: “Budget Division: Congressional Budget Justifications,” Bureau of Ocean Energy Management, Regulation, and Enforcement, 

http://www.boemre.gov/adm/budget.html; Minerals Management Service, Deepwater Gulf of Mexico 2009: Interim Report of 2008 Highlights,

(May 2009), 71-72, http://www.gomr.boemre.gov/PDFs/2009/2009-016.pdf; U.S. Energy Information Administration, This Week in Petroleum: 

Production, Proved Reserves and Drilling in the Ultra-Deepwater Gulf of Mexico, (May 26, 2010), http://www.eia.gov/oog/info/twip/

twiparch/100526/twipprint.html. 

In the last twenty years, MMS’s leasing, environmental, and regulatory budget decreased or remained static while deepwater oil production in 

the Gulf of Mexico boomed. Note: OEMM (Office of Energy and Minerals Management) has responsibility for renewable energy, leasing and 

environmental, resource evaluation, regulatory, and information management programs. It does not include revenue management or general 

administration.
74 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

frequency of tests.100* Soon afterward, a 

series of third-party technical studies raised 

the possibility of high failure rates for the 

blowout preventers’ control systems, annular 

rams, and blind-shear rams under certain 

deepwater conditions and due to changes in the 

configuration and strength of drill pipe used 

by industry.101 Two studies commissioned by 

MMS found that many rig operators, by not 

testing blowout preventers, were basing their 

representations that the tool would work “on 

information not necessarily consistent with the 

equipment in use.”102 Yet, MMS never revised 

its blowout-preventer regulations nor added 

verification as an independent inspection item 

in light of this new information.103

Nor did MMS adapt its regulatory framework 

in response to significant ways in which the 

oil and gas industry has changed over time. 

In particular, the industry has witnessed a 

rise in specialized service contractors, such 

as Halliburton and Transocean that serviced 

BP at the Macondo well. When the lessee 

directly regulated by the government is itself 

not performing many of the activities critical to well safety, that separation of functions 

poses heightened challenges for the regulator. But there was no apparent effort by MMS to 

respond to those challenges by making the service companies more accountable.

Permit “shopping.” With increasing industry activity, MMS regulators could not possibly 

keep pace. The oil and gas industry works 24/7, but MMS regulators generally work 

regular office hours, requiring “on-call” responsibility to be assigned to individual senior 

engineers. Those engineers, however, work at a marked disadvantage because they cannot 

gain access to the permit database from off-site locations due to security concerns.104 

Even during normal business hours, the Gulf of Mexico office lacks a sufficient number 

of engineers to process permit reviews with necessary scrutiny. From 2005 to 2009, the 

number of applications for drilling permits in just the MMS New Orleans District increased 

71 percent: from 1,246 to 2,136.105 Without enough engineers in the Gulf of Mexico 

district office to process all the applications, some operators literally “shop around.” They 

“contact district offices outside the appropriate jurisdictional area . . . to find an engineer 

who will eventually give approval.”106

Inspections forgone. Not surprisingly, with diminished resources, MMS inspections 

became less effective, as the Interior Department’s Inspector General reported in 1999.107

* “The MMS said the revised testing requirements could save industry $35-46 million per year without compromising safety.” See “MMS eases rule for BOP testing,” Oil & 

Gas Journal, June 8, 1998, 32.

Waiting their turn, lengths of colored drill pipe stack up 

aboard a Transocean rig. Independent studies suggest that 

failures of crucial blowout preventer components could 

be caused in part by industry-driven changes to drill-pipe 

strength and configuration. 

Derick E. Hingle/Bloomberg via Getty Images

Drill Pipe
Chapter Three 75 75

The frequency of unannounced inspections plummeted.108 Although the raw incident 

data are online, MMS last produced an analysis of offshore incidents—critical data for 

promoting the safety of offshore operations—for calendar year 2000.109 And MMS’s 

progressive reduction in oversight relative to the level of industry activity occurred just 

as the industry struggled to find highly trained staff needed to work the expanding 

population of deepwater drilling rigs.110 Precisely when the need for regulatory oversight 

intensified, the government’s capacity for oversight diminished. 

Overlaps and “underlaps.” The lack of resources extended beyond MMS. The United 

States Coast Guard is responsible for regulating the “safety of life and property on Outer 

Continental Shelf (OCS) facilities, vessels, and other units engaged in OCS activities.”111

Because most drilling rigs and even some production platforms fall under the definition of 

“vessels,” part of the responsibility for regulating their safe operation (and full authority 

for certifying their seaworthiness) is within the jurisdiction of the Coast Guard.112 But 

just when the need for Coast Guard oversight increased during the 1990s—as industry 

drilled in deeper waters farther offshore and used more ambitious floating drilling and 

production systems—it, too, faced more severe budgetary restraints. Accordingly, the 

Coast Guard failed to update its marine-safety rules—the last major revision was in 

1982113—to reflect the industry’s new technology. The resource plight worsened further 

following the terrorist attacks of September 11, 2001, given the nation’s overriding need 

to focus on border and port security. The Coast Guard’s “solution”—to transfer much of 

Number of MMS Inspections in the Gulf of Mexico, 1990-2009

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

Year

Number of Inspections

19901991199219931994199519961997199819992000200120022003200420052006200720082009

• Announced

• Unannounced

Source: Bureau of Ocean Energy Management, Regulation, and Enforcement data upon National Commission Staff 

request to the Department of the Interior

FIGURE 3.4: MMS Inspections in the Gulf of Mexico, 1990-2009

Source: Bureau of Ocean Energy Management, Regulation, and Enforcement data upon National Commission Staff request to the 

Department of the Interior.

“Unannounced” or surprise inspections of offshore oil and gas activity grew increasingly rare over time. Less than 3% of MMS inspections 

conducted in 2009 were unannounced.
76 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

its responsibility for fixed platform safety to MMS in 2002114—eerily echoed earlier cycles 

of expanding MMS’s mandate in the face of inadequate resources, stretching its capabilities 

thinner still. The practical effect of the Coast Guard and MMS’s shared responsibility for 

offshore safety has been the presence of “overlaps” in jurisdiction that have required the 

renegotiation of informal interagency agreements ever since 1989—the continuance of 

which has left MMS with “underlaps” in resources.115

The Culture of Revenue Maximization 

When Interior Secretary Watt moved regulatory oversight of offshore energy exploration 

and production to a new entity that was also responsible for collecting revenue from the 

activity it regulated, he created a new agency that inexorably came to be dominated by its 

focus on maximizing that revenue. 

For at least the past 15 years, every former MMS Director has freely acknowledged that 

the royalty issues have taken most of the Director’s time—at the expense of offshore 

regulatory oversight.116 In 1995, as the United States faced global competition for oil 

exploration and development capital during a period of low prices, Congress enacted the 

Deep Water Royalty Relief Act.117 It provided a suspension of royalty payments on a 

portion of new production from deepwater operations. 

But when prices and volumes increased, the sheer amount of money at stake—literally 

billions of dollars (MMS total onshore and offshore revenues for 2008 were $23 

billion118)—compelled even greater attention, as the White House, members of Congress, 

and certainly the states each advanced competing notions of how those sums might best 

be spent.* Litigation, new regulations, and legislation designed to increase one party’s 

relative share of such massive sums have been a constant feature of managing the flow of 

royalties from onshore and offshore energy production. Such disputes have invariably been 

controversial, politically sensitive, and time-consuming for MMS decisionmakers.119 

Agency leadership and technical expertise. Agency personnel naturally look to agency 

leadership to signal what constitutes their primary mission, including the expertise and 

experience that such leaders bring with them. In the case of MMS, those signals were 

profoundly disturbing, yet nonetheless consistent over time. No one who has led MMS 

since it was created almost 30 years ago has possessed significant training or experience in 

petroleum engineering or petroleum geology, or any significant technical expertise related 

to drilling safety.

In the absence of a clear statement from the top about the necessity for such expertise to 

ensure drilling safety, it should be no surprise that MMS personnel have suffered from 

the loss of essential expertise throughout their ranks. Indeed, the lack of requisite training 

is abysmal. According to a recent survey conducted at the request of the Secretary of 

the Interior, “[a]lmost half of the [MMS] inspectors surveyed do not believe they have 

received sufficient training.” MMS, unlike Interior’s Bureau of Land Management (which 

* Because of a bureaucratic mistake within Interior, however, federal lease sales held in 1998 and 1999 failed to include price thresholds in each lease, meaning that 

those lessees received relief from royalty payments even though higher oil prices made such relief wholly unnecessary. The Government Accountability Office has 

estimated that the error could cost the government at least $10 billion and perhaps as much as $80 billion. Government Accountability Office, “Oil and Gas Royalties – 

Royalty Relief Will Likely Cost the Government Billions, but the Final Costs Have Yet to Be Determined” (January 18, 2007), 3, 5.
Chapter Three 77 77

inspects onshore oil and gas drilling operations), has no “oil and gas inspection certification 

program” and no exam “is required of each inspector in order to be certified.” MMS “does 

not provide formal training specific to the inspections process, and does not keep up with 

changing technology. Some inspectors noted that they rely on industry representatives to 

explain the technology at a facility.”120

The Macondo well blowout makes all too clear the cost of such a departure from the 

standards of excellence that the nation expects from its public servants. As described in 

Chapter 4, the MMS personnel responsible for reviewing the permit applications submitted 

to MMS for the Macondo well were neither required nor prepared to evaluate the aspects 

of that drilling operation that were in fact critical to ensuring well safety. The regulations 

did not mandate that MMS regulators inquire into the specifics of “rupture disks,” “long 

string” well designs, cementing process, the use of centralizers, lockdown sleeves, or the 

temporary abandonment procedures (see Chapter 4). And, no doubt for that same reason, 

the MMS personnel responsible for deciding whether the necessary drilling permits were 

granted lacked the expertise that would have been necessary in any event to determine the 

relative safety of the well based on any of these factors.* 

Agency integrity and pockets of corruption. The preoccupation with revenues did not 

merely divert MMS leaders’ attention from drilling safety. It also allowed the ethical culture 

to degenerate in a few isolated offices, leading to serious charges of abuse of government 

authority and even charges of criminal misconduct by a few individuals. This conduct was 

far removed from the daily work of almost all those agency personnel who performed 

regulatory oversight of offshore drilling. But the conduct of a few working elsewhere in 

the agency unfairly cast a cloud over the agency as a whole, especially in the immediate 

aftermath of the Macondo well blowout, providing a ready reminder of the critical 

importance of public trust in the management of the nation’s resources. 

The most notorious example arose from the “royalty in kind” program, based in Denver, 

Colorado. Under the program, MMS exercised its option to accept royalty payments “in 

kind” rather than in cash.†

 A September 2008 Inspector General’s report implicated more 

than a dozen employees in the Denver royalty-in-kind office in unethical and criminal 

conduct.121 Those MMS staff had also socialized with, and received a wide array of gifts 

from, companies with whom they were conducting business. The Inspector General 

further acknowledged that although “99.9 percent of [Interior] employees are hardworking, ethical, and well-intentioned[,] . . . the conduct of a few has cast a shadow on an 

entire bureau.”122

Nor was unethical conduct limited to MMS’s revenue collections. It extended to some of 

those who worked on overseeing offshore oil and gas activities in the Gulf of Mexico. 

An Inspector General’s investigation in 2010 revealed that prior to 2007, “a culture of 

* See, e.g., Written submission to the National Commission from MMS permitting official, November 5, 2010 (“I did not know they were using nitrogen foamed cement. . 

. . [I]t would not have mattered under the regulations. We do not do any evaluations of types of cement.”) id. (“I do not recall them informing me as to why they decided 

not to drill to that length. . . . We do not need an explanation as to why a well is not drilled to the proposed depth.”).; id. (“At the time I reviewed the APD [drilling permit 

application], my knowledge of rupture disks was limited to what I had learned from the previous drilling engineer when working with him learning the review process.”); 

id. (“I did not receive training on lock down sleeve setting procedures.”).

†

The royalty-in-kind program allowed MMS to market the natural gas or oil to establish a reference against which it could evaluate industry reports of their market value.
78 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

accepting gifts from oil and gas companies was prevalent throughout the MMS Lake 

Charles[, Louisiana] office.” “[A] number of MMS employees at th[at] district office 

admitted to attending sporting events prior to 2007 in which oil and gas production 

companies sponsored teams, as well as receiving lunches and accepting gifts.” The 

investigation found that one employee had conducted inspections on a company’s oil 

platforms while in the process of negotiating (and later accepting employment) with 

the company.123 Here again, the actions of a few damaged the reputation of the agency 

as a whole, and demoralized the vast majority of MMS employees who avoided such 

conflicts.124 In January 2009, only days after taking office, Secretary Salazar met with 

MMS employees and announced an ethics reform initiative in response to the problems 

identified at MMS and elsewhere in the agency.125

Mismanagement and Misdirection 

Perhaps because of the cumulative lack of adequate resources, absence of a sustained 

agency mission, or sheer erosion of professional culture within some offices, MMS 

came progressively to suffer from serious deficiencies of organization and management: 

the fundamental traits of any effective institution. According to the Outer Continental 

Shelf Safety Oversight Board,* MMS lacks “a formal, bureau-wide compilation of rules, 

regulations, policies, or practices pertinent to inspections, nor does it have a comprehensive 

handbook addressing inspector roles and responsibilities.” As a result, the Board concluded, 

“policies and enforcement mechanisms vary among the [Gulf of Mexico] districts and 

the regions, and there is no formal process to promote standardization, consistency, and 

operational efficiency.”126

The Safety Oversight Board singled out MMS’s handling of inspections for pointed 

criticism. For example, management promoted inspections by single inspectors in order 

to increase the total number of inspections, even though “most inspectors interviewed 

said that two-person teams would increase efficiencies, eliminate reliance on an operator 

representative for observations on safety tests, improve the thoroughness of the inspection, 

and reduce the ability of operators to successfully pressure an inspector not to issue [a 

citation].” The Board’s interviews revealed “staff concerns regarding a perceived emphasis 

on the quantity rather than quality of inspection.”127 

The agency’s management shortcomings were underscored, and compounded, by lack of 

communication and inconsistencies among its three regional offices for the Gulf of Mexico, 

the Pacific, and Alaska. The directors of each regional office naturally adapted practices 

to best suit the specific characteristics and needs of the region. But by acting in parallel 

fashion, with little coordination in decisionmaking and resource allocation, program 

implementation, regulatory interpretation, and enforcement policies became inconsistent, 

undermining the integrity of MMS’s work.128 For example, the Safety Oversight Board 

found that “the Pacific Region employs 5 inspectors to inspect 23 production facilities—a 

ratio of 1 inspector for every 5 facilities. By contrast, the [Gulf of Mexico Region] employs 

55 inspectors to inspect about 3,000 facilities—a ratio of 1 inspector for every 54 

facilities.” 129 

* Secretary Salazar created the Outer Continental Shelf Safety Oversight Board in the immediate aftermath of the Macondo well blowout and charged the Board with 

reviewing the effectiveness of MMS’s management. The Board issued its report on September 1, 2010.
Chapter Three 79 79

Ultimately, MMS was unable to ensure that its staffing capabilities and competencies kept 

pace with the changing risks and volume of offshore activity. As the Safety Oversight 

Board concluded, the Gulf of Mexico “district offices did not have a sufficient number of 

engineers to efficiently and effectively conduct permit reviews.”130 As the Chief of the U.S. 

Geological Survey’s Conservation Division had warned nearly 30 years earlier,131 salaries—

for engineers stuck in the midranges of the federal pay scale—were far too low to attract 

individuals possessing the experience and expertise needed to oversee the increasingly 

complicated oil and gas drilling activities in the deepwater Gulf.132 At the most elementary 

level, MMS frequently lacked defined qualifications that new employees must meet before 

they start performing their jobs, or clear procedures for on-the-job training. The Board 

report further observed that the “amount of time and the structure of this training vary 

from office to office and from inspector to inspector,” and it concluded that the on-the-job 

training “does not address the need for substantive, consistent training in all aspects of the 

job.”133 

An Environment Unfavorable to Responsible Drilling 

Erosion of Environmental-Protection Safeguards in the Gulf of Mexico

Even as oversight of drilling safety became less effective while the industry pursued more 

demanding deepwater plays in the Gulf of Mexico, environmental safeguards eroded, 

too—putting the rich natural resources of the Gulf waters and the surrounding coasts at 

increasing risk. 

The legislative promise. The 1978 Outer Continental Shelf Lands Act Amendments 

promised full consideration of concerns for environmental protection. The Act provides 

that “[m]anagement of the outer Continental Shelf shall be conducted in a manner which 

considers economic, social, and environmental values of the renewable and nonrenewable 

resources contained in the outer Continental Shelf, and the potential impact of oil and 

gas exploration on other resource values of the outer Continental Shelf and the marine, 

coastal, and human environments.”134 It further requires that the timing and location 

of exploration, development, and production of oil and gas take environmental factors 

into consideration, including: existing ecological characteristics; an equitable sharing 

of development benefits and environmental risks among the regions; the relative 

environmental sensitivity and marine productivity of areas; and relevant environmental 

and predictive information.135 Based on an evaluation of these and other factors, the Act 

directsthe Secretary of the Interior to select the “timing and location of leasing, to the 

maximum extent practicable, so as to obtain a proper balance between the potential for 

environmental damage, the potential for the discovery of oil and gas, and the potential for 

adverse impact on the coastal zone.”136 

A host of other laws, many enacted by Congress during the 1970s surge of environmental 

legislation, buttress these promised priorities. Of particular relevance to oil and gas leasing 

on the outer continental shelf is the National Environmental Policy Act requirement that 

federal agencies prepare environmental impact statements for all major federal actions 
80 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

significantly affecting the human environment.137 Those detailed statements must include 

not only discussion of the immediate adverse impacts on the natural environment that 

might result from the federal action, but also the “socio-economic”* effects of those 

impacts.138 The Magnuson-Stevens Fishery Conservation and Management Act requires 

agencies to analyze the potentially adverse impacts of oil and gas activities on fish habitat 

and populations, and provide conservation measures to mitigate those impacts.139 The 

Endangered Species Act requires federal agencies to determine the potential adverse impact 

of oil and gas activities on endangered and threatened species, limits activities that harm 

individual members of such species, and bars altogether activities that place such species 

in jeopardy.140 The Marine Mammal Protection Act imposes limits on activities that 

injure or even harass marine mammals.141 The National Marine Sanctuaries Act requires 

consultations to guard against harm to marine sanctuary resources from oil and gas 

leasing activities.142 The federal Clean Water Act imposes permitting requirements on any 

discharge of pollutants into navigable waters from such activities.143 And, the Oil Pollution 

Act of 1990,144 supplemented by a Presidential Executive Order,145 imposes a panoply of 

oil-spill planning, preparedness, and response requirements on fixed and floating facilities 

engaged in oil and gas exploration, development, and production on the outer continental 

shelf. 

Promise vs. practice. But some of these apparent statutory promises dim upon closer 

examination. The Outer Continental Shelf Lands Act routinely requires consideration of 

environmental protection concerns in leasing location and timing—but ultimately gives 

the Secretary of the Interior tremendous discretion in deciding what weight to give those 

concerns.146 The balance ultimately struck depends largely on the politics of the moment. 

The Secretary can assign significant weight to environmental protection concerns—or not. 

And in fact, parts of the 1978 Act arguably stack the deck against full consideration of 

environmental concerns. For instance, the law provides that the Secretary must approve 

a lessee’s exploration plan within 30 days of submission.147 If environmental review is to 

occur after plan submission, that timetable effectively precludes the kind of exacting review 

necessary to ensure that the Act’s environmental safeguards can be achieved. It would, in 

effect, be a statement by Congress that the rush to energy exploration is too important to 

be delayed.

The Act also expressly singles out the Gulf of Mexico for less rigorous environmental 

oversight under NEPA. As a result of political compromise with oil and gas interests, the 

Act exempts lessees from submitting development and production plans (which include 

environmental safeguards) for agency approval. Accordingly, Gulf leases, unlike those 

applicable to other offshore areas, are not subject to the requirement of at least one NEPA 

environmental impact statement for development plans for a particular geographic area.148 

None of the other statutes includes such a stark exception, but their effects still are more 

limited than it might at first seem. For instance, both the Endangered Species Act and the 

*

 As the Macondo well blowout makes clear, the socio-economic effects of an oil spill are hardly an incidental concern. As described in Chapter 6, the economic costs 

of the spill to the Gulf states can be measured in the billions of dollars. Yet absent careful NEPA review, there are no assurances that these potential consequences of a 

decision to lease, explore, develop, or drill in any given location will be carefully considered by the governmental decisionmaker before the decision is made.
Chapter Three 81 81

Clean Water Act impose tough substantive limits on activities. But each has only a narrow, 

discrete focus and statutory trigger: threats to endangered or threatened species or their 

critical habitat under the Endangered Species Act or, under the Clean Water Act, only the 

incidental aspects of oil and gas activities that discharge pollutants into navigable waters 

(unless, of course there is an oil spill). 

Neither the Magnuson-Stevens Act nor the Marine Sanctuaries law imposes any 

mandatory substantive limitation on oil and gas activities offshore. Each instead authorizes 

the National Oceanic and Atmospheric Administration (NOAA) to make recommendations 

to MMS about possible adverse environmental impacts (to fish habitat and marine 

sanctuaries) and appropriate conservation measures. Congress clearly assigned NOAA 

this central role because it is the federal agency most expert on ocean science and has 

a clear mission to serve as the steward safeguarding the nation’s ocean resources. But, 

notwithstanding that assignment, neither law provides any corresponding obligation on 

the part of MMS to heed NOAA’s advice. MMS can, and has, on occasion given little or no 

weight to NOAA’s views; according to NOAA officials, that causes some NOAA scientists to 

expend fewer resources on generating such views.

As a result, although the various laws create the potential for comprehensive 

environmental protection in oil and gas drilling on the outer continental shelf, neither 

alone nor in combination do any of the laws come close to ensuring a reasonable level of 

overall environmental protection applicable to all aspects of oil and gas activities on the 

outer continental shelf. Whether they have achieved their statutory objectives has therefore 

historically depended instead entirely on the discretionary determinations of MMS officials.

Limiting NEPA. The Department of the Interior and MMS also took a series of steps that 

further limited the potential for NEPA to ensure government decisions were based on 

full consideration of their environmental consequences. Erosion of NEPA’s application 

to offshore oil and gas activities began, as noted, when Congress exempted a category 

of leasing activities in the Gulf of Mexico from NEPA review. The Interior Department, 

however, subsequently took that legislative exemption and unilaterally expanded its scope 

beyond those original legislative terms. 

Although the 1978 Act exempted only the Interior Department’s review of a lessee’s 

“development and production plan” from the environmental impact statement process, 

Interior unilaterally extended that exemption. In January 1981, the Department 

promulgated final rules declaring that exploration plans in the central and western 

Gulf of Mexico were “categorically excluded” from NEPA review.* At that same time, 

the Department also categorically excluded from NEPA review applications to drill wells 

(for exploration or subsequent development and production of oil and gas) “when said 

well and appropriate mitigation measures are described in an approved exploration plan, 

development plan, or production plan.”149 In 1986, MMS scaled back the categorical 

*

 The President’s Council on Environmental Quality, which is responsible for the administration of NEPA, has promulgated a regulation that permits agencies to create 

“categorical exclusions” from NEPA review for categories of minor activities that can be reasonably assumed in advance not to have significant environmental impacts. 

See 40 C.F.R. § 1508.4.
82 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

exclusion to account for the possibility that NEPA review would be needed for these 

activities in certain narrowly defined “extraordinary circumstances.” Extraordinary 

circumstances include those actions that have highly uncertain and potentially significant 

environmental effects or involve unique or unknown environmental risks.150 

But because MMS personnel were apparently reluctant to conclude that such extraordinary 

circumstances were present, the rule in practice in the Gulf of Mexico was the categorical 

exclusion—rather than the exception to that exclusion. MMS staff have reported that 

leasing coordinators and managers discouraged them from reaching conclusions about 

potential environmental impacts that would increase the burden on lessees, “thus 

causing unnecessary delays for operators.” The Safety Oversight Board also noted that 

“[s]ome [MMS] environmental staff also reported that environmental assessments for 

smaller operators may be minimized if the [Regional Office of Field Operations] manager 

determines that implementing the recommendation may be too costly.”151

With regard to NEPA specifically, some MMS managers reportedly “changed or minimized 

the [MMS] scientists’ potential environmental impact findings in [NEPA] documents to 

expedite plan approvals.” According to several MMS environmental scientists, “their 

managers believed the result of NEPA evaluations should always be a ‘green light’ to 

proceed.” In some cases, there may also have been built-in employee financial incentives 

that “distort[ed] balanced decision-making” to the extent that “[e]mployee performance 

plans and monetary awards [were] . . . based on meeting deadlines for leasing or 

development approvals.”152 

Finally, just as a matter of sheer practicality, MMS personnel plainly lacked the substantial 

resources that would have been required to engage in meaningful NEPA review in light of 

the extraordinary expansion of leasing activity in the Gulf. There were literally hundreds 

of exploration, development, and production plans, as well as individual permit drilling 

applications to be processed. No President ever sought for MMS the level of resources that 

would have been required to prepare individual assessments concerning whether each of 

those activities required an environmental impact statement, let alone such a statement for 

those that did. Nor did Congress. It should be no surprise under such circumstances that a 

culture of complacency with regard to NEPA developed within MMS, notwithstanding the 

best intentions of many MMS environmental scientists. 

The Macondo Well

The gap between the protections promised by environmental statutes and regulations and 

actual practice is fully illustrated in the review and permitting of the Macondo well itself. 

MMS engaged in no NEPA review of the well’s permitting, and neither MMS nor other 

federal agencies gave significant attention to the environmental mandates of other federal 

laws.

NEPA. MMS performed no meaningful NEPA review of the potentially significant adverse 

environmental consequences associated with its permitting for drilling of BP’s exploratory 

Macondo well. MMS categorically excluded from environmental impact review BP’s initial 

and revised exploration plans—even though the exploration plan could have qualified for 
Chapter Three 83 83

an “extraordinary circumstances” exception to such exclusion, in light of the abundant 

deep-sea life in that geographic area and the biological and geological complexity of that 

same area.153 MMS similarly categorically excluded from any NEPA review the multiple 

applications for drilling permits and modification of drilling permits associated with the 

Macondo well. The justification for these exclusions was that MMS had already conducted 

NEPA reviews for both the Five-Year Program and the Lease Sale that applied to the 

Macondo well. The flaw in that agency logic is that both those prior NEPA reviews were 

conducted on a broad programmatic basis, covering huge expanses of leased areas of which 

the Macondo well was a relatively incidental part. Neither, moreover, included a “worst 

case analysis” because the President’s Council on Environmental Quality had eliminated the 

requirement for such analysis under NEPA for all federal agencies in 1986.154 As a result, 

none of those prior programmatic reviews carefully considered site-specific factors relevant 

to the risks presented by the drilling of the Macondo well.* 

Fishery conservation and management. Under the Magnuson-Stevens Fishery 

Conservation and Management Act, federal agencies must consult with NOAA on all 

activities (or proposed activities) authorized, funded, or undertaken by the agency that 

may adversely affect essential fish habitat. For the Gulf of Mexico, accordingly, NOAA 

prepared a “programmatic” Essential Fish Habitat Consultation for the entire Gulf.155 To 

similar effect, MMS complied with the Magnuson-Stevens consultation requirement by 

preparing Essential Fish Habitat Assessments that looked at offshore oil and gas leasing 

activities in the Gulf broadly.156 Neither NOAA nor MMS considered the possible adverse 

impacts of any one well, such as the Macondo well, in isolation. Nor would it have been 

practical for them to do so in light of their understandable focus on possible cumulative 

impacts on fish populations from many offshore leasing activities. What is more telling, 

however, is that to the extent that the MMS Assessment identified potential threats to 

essential fish habitat and marine fishery resources from oil spills, both NOAA and MMS 

ultimately relied exclusively on conservation measures included in oil-spill response plans 

prepared by the oil and gas industry pursuant to the Oil Pollution Act of 1990 to address 

those threats.157 For the Macondo well, both agencies assumed that BP’s plan would 

adequately address those threats and therefore there was no need to seek to do so directly 

through the Magnuson-Stevens Act. There was, however, little reason to assume that 

those plans were in fact up to the task.

Oil Pollution Act of 1990 and Oil Spill Response Plans. Under the Oil Pollution Act of 

1990, as supplemented by a Presidential Executive Order, MMS is responsible for oilspill planning and preparedness as well as select response activities for fixed and floating 

facilities engaged in exploration, development, and production of liquid hydrocarbons 

and for certain oil pipelines. The agency requires all owners or operators of offshore 

oil-handling, storage, or transportation facilities to prepare Oil Spill Response Plans. 

MMS regulations detail the elements of the response plan (an emergency-response action 

plan, oil-spill response equipment inventory, oil-spill response contractual agreements, a 

* For instance, bluefin tuna are both commercially vital and biologically significant as predators in the Gulf. But in the relevant Five-Year (2007–2012) Programmatic 

Environmental Impact Statement on the entire offshore leasing program—covering the entire outer continental shelf of the United States—MMS discusses potential 

impacts of leasing activities on bluefin tuna in one sentence. Subsequent MMS environmental impact statements for lease sales within the Gulf of Mexico contained 

no significant or geographically-focused analysis of the potential impacts on bluefin tuna. And, in finally permitting the drilling of the Macondo well, MMS categorically 

excluded the action from any NEPA review, and thus conducted no analysis of the potential impacts of drilling on bluefin tuna, based on the rationale that it had already 

adequately reviewed environmental impacts in its prior reviews.
84 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

calculation of the worst-case discharge scenario, plan for dispersant use, in-situ burning 

plan, and information regarding oil-spill response training and drills).158 The emergencyresponse plan is supposed to be the core of the overall plan, and in turn is required to 

include information regarding the spill-response team; the types and characteristics of oil 

at the facilities; procedures for early detection of a spill; and procedures to be followed in 

the case of a spill.159

But neither BP, in crafting its Oil Spill Response Plan for the Gulf of Mexico applicable 

to the Macondo well, nor MMS in approving it, evidenced serious attention to detail.160

For instance, the BP plan identified three different worst-case scenarios that ranged from 

28,033 to 250,000 barrels of oil discharge and used identical language to “analyze” 

the shoreline impacts under each scenario.161 To the same effect, half of the “Resource 

Identification” appendix (five pages) to the BP Oil Spill Response Plan was copied from 

material on NOAA websites, without any discernible effort to determine the applicability of 

that information to the Gulf of Mexico. As a result, the BP Oil Spill Response Plan described 

biological resources nonexistent in the Gulf—including sea lions, sea otters, and walruses.* 

Even more troubling, the MMS Gulf of Mexico Regional Office approved the BP plan 

without additional analysis. There is little in that approval to suggest that BP and MMS 

gave close scrutiny to the contents of the Oil Spill Response Plan. The Regional Office’s 

routine practice was to review and approve oil-spill response plans within 30 days of their 

receipt. Absent any legal requirement to do so, the office did not distribute submitted plans 

to other federal agencies for review or comment, nor did it seek public review or comment. 

The inescapable conclusion is striking, and profoundly unsettling. Notwithstanding 

statutory promises of layers of required environmental scrutiny—by NEPA, the 

Magnuson-Stevens Act, the Outer Continental Shelf Lands Act, and the Oil Pollution 

Act—and the potential application of some of the nation’s toughest environmental 

restrictions—the Endangered Species Act and Clean Water Act—none of these laws resulted 

in site-specific review of the drilling operations of the Macondo well. The agency in 

charge, MMS, lacked the resources and committed agency culture to do so, and none of 

the other federal agencies with relevant environmental expertise had adequate resources or 

sufficient statutory authority to make sure the resulting gap in attention to environmental 

protection concerns was filled.†

 

Federal oversight of oil and gas activities in the Gulf of Mexico—almost the only area 

where substantial amounts of drilling were taking place—took a generally minimalist 

approach in the years leading up to the Macondo explosion. The national government 

failed to exercise the full scope of its power, grounded both in its role as owner of 

the natural resources to be developed and in its role as sovereign and responsible for 

ensuring the safety of drilling operations. Many aspects of national environmental law 

* The BP plan does not appear to be an aberration. It was prepared by a contractor who also prepared the Gulf of Mexico plans for Chevron, ConocoPhillips, 

ExxonMobil, Shell, and other companies operating in the Gulf. The result is four nearly identical plans that repeat the same mistakes found in the BP plan applicable to 

the Macondo well. 

† The President’s decision in March 2010 to expand offshore oil and gas leasing is a more recent example of the absence of full consideration of environmental 

protection concerns. According to their testimony before the Commission in August 2010, the White House did not ask either the Chair of the President’s Council on 

Environmental Quality or the Administrator of NOAA to be directly involved in reviewing the plans before the President’s decision. See Testimony of The Honorable Nancy 

Sutley, Chair, Council on Environmental Quality, and The Honorable Jane Lubchenco, Administrator, NOAA, Hearing before the National Commission, August 25, 2010. 
Chapter Three 85 85

were ignored, resulting in less oversight than would have applied in other areas of the 

country. In addition, MMS lacked the resources and technical expertise, beginning with its 

leadership, to require rigorous standards of safety in the risky deepwater and had fallen 

behind other countries in its ability to move beyond a prescription and inspection system 

to one that would be based on more sophisticated risk analysis. 

In short, the safety risks had dramatically increased with the shift to the Gulf’s 

deepwaters, but Presidents, members of Congress, and agency leadership had become 

preoccupied for decades with the enormous revenues generated by such drilling rather than 

focused on ensuring its safety. With the benefit of hindsight, the only question had become 

not whether an accident would happen, but when. On April 20, 2010, that question was 

answered. 
86
87 87

Part II

Explosion and Aftermath: The Causes 

and Consequences of the Disaster

The loss of control of the Macondo well; the resulting explosion, 

fire, and destruction of the Deepwater Horizon rig; and the 

ensuing spill of nearly 5 million barrels of oil before the well was 

capped on July 15 reflect specific decisions about well design, 

construction, monitoring, and testing. The Commission’s detailed 

analysis (Chapter 4) explains those actions in the context of this 

specific reservoir and subsurface geology as well as the regulatory 

framework and practices that affected those business decisions. 

Once the rig was destroyed and the uncontrolled flow of oil began 

leaking into the Gulf, industry and government struggled to 

contain and respond to the spill—prompting important questions 

about public and private authority, technical capability and 

capacity, and the current state of the art in addressing such crises. 

Understanding of the Gulf ecosystem and the regional economy 

underlies an early assessment of the spill’s impacts and how to 

restore damaged natural resources, respond to economic losses, 

and address adverse impacts on human health. Chapters 4, 5, 6, 

and 7 address the related issues of containment and response, 

impact assessment, recovery, and restoration.

Chapter Four 89 89

The Macondo Well and the Blowout

In March 2008, BP paid a little over $34 million to 

the Minerals Management Service for an exclusive 

lease to drill in Mississippi Canyon Block 252, 

a nine-square-mile plot in the Gulf of Mexico. 

Although the Mississippi Canyon area has many 

productive oil fields, BP knew relatively little about 

the geology of Block 252: Macondo would be its 

first well on the new lease. BP planned to drill the 

well to 20,200 feet, both to learn more about the 

geology of the area and because it thought—based 

on available geological data—that it might find an 

oil and gas reservoir that would warrant installing 

production equipment at the well.1 At the time, BP 

would have had good reason to expect that the well 

would be capable of generating a large profit. 

Little more than two years later, however, BP 

found itself paying out tens of billions of dollars to 

Chapter Four

“But, who 

cares, it’s 

done, end of 

story, [we] will 

probably be 

fine and we’ll 

get a good 

cement job.”

Fighting a losing battle, fireboats pour water onto the doomed rig in the hours 

after the Macondo well blowout. The tragic loss of the Deepwater Horizon at 

the close of the complex drilling project resulted from a series of missteps and 

oversights and an overall failure of management. 

< U.S. Coast Guard photo
90 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

contain a blowout at the Macondo well, mitigate the damage resulting from the millions 

of gallons of oil flowing from that well into the Gulf of Mexico, and compensate the 

hundreds of thousands of individuals and businesses harmed by the spill. And that is 

likely just the beginning. BP, its partners (Anadarko and MOEX), and its key contractors 

(particularly Halliburton and Transocean) face potential liability for the billions more 

necessary to restore natural resources harmed by the spill. 

The well blew out because a number of separate risk factors, oversights, and outright 

mistakes combined to overwhelm the safeguards meant to prevent just such an event 

from happening. But most of the mistakes and oversights at Macondo can be traced 

back to a single overarching failure—a failure of management. Better management by 

BP, Halliburton, and Transocean would almost certainly have prevented the blowout 

by improving the ability of individuals involved to identify the risks they faced, and to 

properly evaluate, communicate, and address them. A blowout in deepwater was not a 

statistical inevitability. 

The Challenges of Deepwater Drilling at the Macondo Well 

High Pressures and Risk of a Well Blowout

Oil forms deep beneath the Earth’s surface when organic materials deposited in ancient 

sediments slowly transform in response to intense heat and pressure. Over the course 

of millions of years, these materials “cook” into liquid and gaseous hydrocarbons. The 

transformed materials can flow through porous mineral layers, and tend to migrate 

upward because they are lighter than other fluids in the pore spaces. If there is a path 

that leads to the surface, the hydrocarbons will emerge above ground in a seep or tar pit. 

If an impermeable layer instead blocks the way, the hydrocarbons can collect in porous 

rock beneath the impermeable layer. The business of drilling for oil consists of finding and 

tapping these “pay zones” of porous hydrocarbon-filled rock. 

Pore Pressure and Fracture Gradient

Pore pressure is the pressure exerted by fluids in the pore space of rock. If drillers do not balance 

pore pressure with pressure from drilling fluids, hydrocarbons can flow into the wellbore (the hole 

drilled by the rig, including the casing) and unprotected sections of the well can collapse. The porepressure gradient, expressed as an equivalent mud weight, is a curve that shows the increase of 

pore pressure in a well by depth. 

Fracture pressure is the pressure at which the geologic formation is not strong enough to withstand 

the pressure of the drilling fluids in a well and hence will fracture. When fracture occurs, drilling fluids 

flow out of the wellbore into the formation instead of circulating back to the surface. This causes 

what is known as “lost returns” or “lost circulation.” The fracture gradient, expressed as an equivalent 

mud weight, is a curve that shows the fracture pressure of rocks in a well by depth.
Chapter Four 91 91

The weight of the rocks above a pay zone can generate tremendous pressure on the 

hydrocarbons. Typically, the deeper the well, the higher the pressure—and the higher the 

pressure, the greater the challenges in safely tapping those hydrocarbons. The first oil wells 

were drilled on land and involved relatively low-pressure oil reservoirs. As oil companies 

drilled farther offshore, they encountered large hydrocarbon deposits, often in more 

porous and permeable geologic formations, and, like at the Macondo well, at ever-higher 

pressures. 

The principal challenge in deepwater drilling is to drill a path to the hydrocarbon-filled 

pay zone in a manner that simultaneously controls these enormous pressures and avoids 

fracturing the geologic formation in which the reservoir is found. It is a delicate balance. 

The drillers must balance the reservoir pressure (pore pressure) pushing hydrocarbons into 

the well with counter-pressure from inside the wellbore. If too much counter-pressure is 

used, the formation can be fractured. But if too little counter-pressure is used, the result 

can be an uncontrolled intrusion of hydrocarbons into the well, and a discharge from the 

well itself as the oil and gas rush up and out of the well. An uncontrolled discharge is 

known as a blowout.

Drill Pipe, Mud, Casing, Cement, and Well Control

Those drilling in deepwater, just like those drilling on land, use drill pipe, casing, mud, and 

cement in a series of carefully calibrated steps to control pressure while drilling thousands 

of feet below the seafloor to reach the pay zone. Drilling mud, which is used to lubricate 

and cool the drill bit during drilling, plays a critical role in controlling the hydrocarbon 

pressure in a well. The weight of the column of mud in a well exerts pressure that 

counterbalances the pressure in the hydrocarbon formation. If the mud weight is too low, 

fluids such as oil and gas can enter the well, causing what is known as a “kick.” But if the 

mud weight is too high, it can fracture the surrounding rock, potentially leading to “lost 

returns”—leakage of the mud into the formation. The rig crew therefore monitors and 

adjusts the weight (density) of the drilling mud as the well is being drilled—one of many 

sensitive, technical tasks requiring special equipment and the interpretation of data from 

difficult drilling environments. 

Drilling Terminology

Drilling through the seafloor does not differ fundamentally from drilling on land. The crews on any 

drilling rig use rotary drill bits that they lubricate and cool with drilling mud—an ordinary name for what 

is today a sophisticated blend of synthetic fluids, polymers, and weighting agents that often costs 

over $100 per barrel. The rig crews pump the mud down through a drill pipe that connects with and 

turns the bit. The mud flows out holes in the bit and then circulates back to the rig through the space 

between the drill pipe and the sides of the well (the annulus), carrying to the surface bits of rock called 

cuttings that the drill bit has removed from the bottom of the well. When the mud returns to the rig at 

the surface, the cuttings are sieved out and the mud is sent back down the drill string. The mud thus 

travels in a closed loop. 

As the well deepens, the crew lines its walls with a series of steel tubes called casing. The casing 

creates a foundation for continued drilling by reinforcing upper portions of the hole as drilling 

progresses. After installing a casing string, the crews drill farther, sending each successive string of 

casing down through the prior ones, so the well’s diameter becomes progressively smaller as it gets 

deeper. A completed deepwater well typically telescopes down from a starting casing diameter of 

three feet or more at the wellhead to a diameter of 10 inches or less at the bottom. 
92 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Casing strings, which are a series of steel tubes installed to line the well as the drilling 

progresses, also help to control pressures. First, they protect more fragile sections of the 

well structure outside the casing from the pressure of the mud inside. Second, they prevent 

high-pressure fluids (like hydrocarbons) outside the casing from entering the wellbore 

and flowing up the well. To secure the casing, crews pump in cement to seal the space 

between the casing and the wellbore. If a completed well can yield economically valuable 

oil and gas, the crews can initiate production by punching holes through the casing and 

surrounding cement to allow hydrocarbons to flow into the well. 

Designed and used properly, drilling mud, cement, and casing work together to enable 

the crew to control wellbore pressure. If they fail, the crew can, in an emergency, close 

powerful blowout-preventer valves that should seal off the well at the wellhead. 

Deepwater Horizon Arrives and Resumes Drilling the Well

After purchasing the rights to drill in Block 252, BP became the legal “operator” for any 

activities on that block. But BP neither owned the rigs, nor operated them in the normal 

sense of the word. Rather, the company’s Houston-based engineering team designed the 

well and specified in detail how it was to be drilled. A team of specialized contractors would 

then do the physical work of actually drilling the well—a common industry practice. 

Transocean, a leading owner of deepwater drilling rigs, would provide BP with a rig and 

the crew to run it. Two BP “Well Site Leaders” (the “company men”) would be on the rig 

at all times to direct the crew and contractors and their work, and would maintain regular 

contact with the BP engineers on shore.

BP actually used two Transocean rigs to drill the Macondo well. The Marianas began work 

in October 2009 and drilled for 34 days, reaching a depth of 9,090 feet, before it had to 

stop drilling and move off-site to avoid Hurricane Ida. As described in Chapter 1, the storm 

nevertheless damaged the rig badly enough that BP called in the Deepwater Horizon to take 

over. 

While the Marianas had been anchored in place with huge mooring chains, the Deepwater 

Horizon was a dynamically positioned mobile offshore drilling unit (MODU).2 It relied 

on thrusters and satellite-positioning technology to stay in place over the well. Once the 

rig arrived on January 31, 2010, and began drilling operations, Transocean’s Offshore 

Installation Manager Jimmy Harrell took over responsibility as the top Transocean 

employee on the rig. 

When the Deepwater Horizon arrived, its first task was to lower its giant blowout 

preventer (BOP) onto the wellhead that the Marianas had left behind. The BOP is a stack 

of enormous valves that rig crews use both as a drilling tool and as an emergency safety 

device. Once it is put in place, everything needed in the well—drilling pipe, bits, casing, and 

mud—passes through the BOP. Every drilling rig has its own BOP, which its crew must 

test before and during drilling operations. After a week of surface testing, the Deepwater 
Chapter Four 93 93

Horizon rig crew lowered the 400-ton device down through a mile of seawater and used 

a remotely operated vehicle (ROV) to guide it so that it could be latched onto the wellhead 

below. 

The Deepwater Horizon’s blowout preventer had several features that could be used to 

seal the well. The top two were large, donut-shaped rubber elements called “annular 

preventers” that encircled drill pipe or casing inside the BOP. When squeezed shut, they 

sealed off the annular space around the drill pipe. The BOP also contained five sets of metal 

rams. The “blind shear ram” was designed to cut through drill pipe inside the BOP to seal 

off the well in emergency situations. It could be activated manually by drillers on the rig, 

by an ROV, or by an automated emergency “deadman system.” A casing shear ram was 

designed to cut through casing; and three sets of pipe rams were in place to close off the 

space around the drill pipe. 

Below the wellhead stretched four telescopic casing strings installed by the Marianas to 

reinforce the hole it had begun drilling. The Deepwater Horizon crew proceeded to drill 

deeper into the Earth, setting progressively smaller-diameter casing strings along the way 

as required. (Figure 4.1) They cemented each new string into place, anchoring the well to—

and sealing the well off from—the surrounding rock. 

“Lost Circulation” Event at the Pay Zone, and a Revised Plan for the Well

By early April, the Deepwater Horizon crew had begun to penetrate the pay zone—the 

porous hydrocarbon-bearing rock that BP had hoped to find. But on April 9, they suffered 

a setback. At 18,193 feet below sea level, the pressure exerted by the drilling mud exceeded 

FIGURE 4.1: Macondo Well Schematic

TrialGraphix
94 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

the strength of the formation. Mud began flowing into cracks in the formation instead of 

returning to the rig. The rig had to stop drilling until the crew could seal the fracture and 

restore mud circulation.3

Lost circulation events are a fact of life in the oil business. The crew responded with a 

standard industry tactic. They pumped 172 barrels of thick, viscous fluid known as a 

“lost circulation pill” down the drill string, hoping it would plug the fractures in the 

formation.4 The approach worked, but BP’s on-shore engineering team realized the 

situation had become delicate. They had to maintain the weight of the mud in the wellbore 

at approximately 14.0 pounds per gallon (ppg) in order to balance the pressure exerted by 

hydrocarbons in the pay zone.5 But drilling deeper would exert even more pressure on the 

formation, pressure that the BP team measured in terms of equivalent circulating density 

(ECD). The engineers calculated that drilling with 14.0 ppg mud in the wellbore would 

yield an ECD of nearly 14.5 ppg—enough of an increase that they risked further fracturing 

of the rock and more lost returns. 

The engineers concluded they had “run out of drilling margin”: the well would have to 

stop short of its original objective of 20,200 feet.6 After cautiously drilling to a total depth 

of 18,360 feet, BP informed its lease partners Anadarko and MOEX that “well integrity and 

safety” issues required the rig to stop drilling further.7

At that point, Macondo was stable. Because the column of drilling mud in the wellbore 

was heavy enough to balance the hydrocarbon pressure, BP and its contractors, including 

Transocean, were able to spend the next five days8 between April 11 and 15 “logging” the 

open hole with sophisticated instruments. Based on the logging data, BP concluded that it 

had drilled into a hydrocarbon reservoir of sufficient size (at least 50 million barrels9) and 

pressure that it was economically worthwhile to install a final “production casing” string 

that BP would eventually use to recover the oil and gas.

Preparing the Well for Subsequent Production

The engineers recognized that the lost circulation problems and delicacy of the rock 

formation at the bottom of the well would make it challenging to install the production 

casing.10 After the rig crew lowered the casing into its final position, Halliburton would 

cement it into place. Halliburton would pump a specialized cement blend down the inside 

of the casing string; when it reached the end of the casing, cement would flow out the 

bottom and up into the annular space between the casing and the sides of the open hole. 

Once cured, the cement would bond to the formation and the casing and—if all went 

Equivalent Circulating Density (ECD)

A column of fluid will exert an amount of pressure on its surroundings that can be calculated if one 

knows the height of the column and the density of the fluid. If one pumps the fluid to make it circulate 

through the column, it will exert even more pressure. Equivalent circulating density or ECD is used 

to describe the total effective pressure that a column of drilling mud exerts on a formation as it is 

circulated through the drill string and back up the wellbore. To pump a given fluid faster or through 

narrower restrictions, it has to be pumped at greater pressure, and this, in turn, increases the ECD. 
Chapter Four 95 95

well—seal off the annular space. BP and Halliburton had cemented the previous casing 

strings at Macondo, and this cement job would be particularly important. The first 

attempt at cementing any casing string is commonly called the primary cement job. For a 

primary cement job to be successful, it must seal off, or “isolate,” the hydrocarbon-bearing 

zone from the annular space around the casing and from the inside of the casing itself. 

The Engineers Select a “Long String” Casing

BP’s design team originally had planned to use a “long string” production casing—a single 

continuous wall of steel between the wellhead on the seafloor, and the oil and gas zone at 

the bottom of the well. But after the lost circulation event, they were forced to reconsider. 

As another option, they evaluated a “liner”—a shorter string of casing hung lower in the 

well and anchored to the next higher string. (Figure 4.2) A liner would result in a more 

complex—and theoretically more leak-prone—system over the life of the well. But it would 

be easier to cement into place at Macondo.

On April 14 and 15, BP’s engineers, working with a Halliburton engineer, used 

sophisticated computer programs to model the likely outcome of the cementing process. 

When early results suggested the long string could not be cemented reliably, BP’s 

FIGURE 4.2: “Long String” vs. “Liner”

Two options for the Macondo production casing.

TrialGraphix
96 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

design team switched to a liner. But that shift met resistance within BP.11 The engineers 

were encouraged to engage an in-house BP cementing expert to review Halliburton’s 

recommendations. That BP expert determined that certain inputs should be corrected. 

Calculations with the new inputs showed that a long string could be cemented properly. 

The BP engineers accordingly decided that installing a long string was “again the primary 

option.”12

Centralizers and the Risk of Channeling

Installing the agreed-upon casing was a major job. Even moving at top speed, the crew on 

the Deepwater Horizon needed more than 18 hours just to lower a tool, such as a drill bit, 

from the rig floor to the bottom of the well, 18,000 feet below sea level. Assembling the 

production casing section-by-section and lowering the lengthening string down into the 

well below would require roughly 37 hours.13

As the crew gradually assembled and lowered the casing, they paused several times to 

install centralizers (Figure 4.3) at predetermined points along the casing string. Centralizers 

are critical components in ensuring a good cement job. When a casing string hangs in 

the center of the wellbore, cement pumped down the casing will flow evenly back up the 

annulus, displacing any mud and debris that were previously in that space and leaving a 

clean column of cement. If the casing is not centered, the cement will flow preferentially 

up the path of least resistance—the larger spaces in the annulus—and slowly or not at all 

in the narrower annular space. That can leave behind channels of drilling mud that can 

severely compromise a primary cement job by creating paths and gaps through which 

pressurized hydrocarbons can flow. 

BP’s original designs had called for 16 or more centralizers to be placed along the 

long string.14 But on April 1, team member Brian Morel learned that BP’s supplier 

(Weatherford) had in stock only six “subs”15—centralizers designed to screw securely into 

place between sections of casing. The alternative was to use 

“slip-on” centralizers—devices that slide onto the exterior of 

a piece of casing where they are normally secured in place by 

mechanical “stop collars” on either side. These collars can either 

be welded directly to the centralizers or supplied as separate 

pieces. The BP team—and Wells Team Leader John Guide in 

particular—distrusted slip-on centralizers with separate stop 

collars because the pieces can slide out of position or, worse, 

catch on other equipment as the casing is lowered.16 

Shortly after the BP team decided on the long string, Halliburton 

engineer Jesse Gagliano ran computer simulations using 

proprietary software called OptiCem, in part to predict whether 

mud channeling would occur. OptiCem calculates the likely 

outcome of a cement job based on a number of variables, 

including the geometry of the wellbore and casing, the size 

and location of centralizers, the rate at which cement will be 

pumped, and the relative weight and viscosity of the cement 

FIGURE 4.3: Centralizer Sub

Centralizer “subs” screw into place 

between sections of casing.

Weatherford
Chapter Four 97 97

compared to the mud it displaces. Gagliano’s calculations suggested that the Macondo 

production casing would need more than six centralizers to avoid channeling. 

Gagliano told BP engineers Mark Hafle and Brett Cocales about the problem on the 

afternoon of April 15.17 With de facto leader John Guide out of the office, Gregory Walz, 

the BP Drilling Engineering Team Leader, obtained permission from senior manager David 

Sims to order 15 additional slip-on centralizers—the most BP could transport immediately 

in a helicopter. That evening, Gagliano reran his simulations and found that channeling 

due to gas flow would be less severe with 21 centralizers in place. Late that night, Walz 

sent an e-mail to Guide explaining that he and Sims felt that BP needed to “honor the 

[OptiCem] modeling to be consistent with our previous decisions to go with the long 

string.”18

When Guide learned the next day of the decision to add more centralizers, he initially 

deferred, but then challenged the decision. Walz had earlier assured Guide that the 15 

additional centralizers would be custom-designed 

one-piece units that BP had used on a prior well 

and would limit the potential for centralizer 

“hang up.”19 But when the centralizers arrived, 

BP engineer Brian Morel, who happened to be 

out on the rig, reported that the centralizers 

were of conventional design with separate stop 

collars. Morel e-mailed BP drilling engineer 

Brett Cocales to question the need for additional 

centralizers.20 Cocales responded that the team 

would “probably be fine” even without the 

additional centralizers and that “Guide is right 

on the risk/reward equation.”21

Guide pointed out to Walz that the new 

centralizers were not custom-made as 

specified.22 “Also,” he noted, “it will take 10 hrs 

to install them.” He complained that the “last 

minute addition” of centralizers would add 45 

pieces of equipment to the casing that could 

come off during installation, and concluded by 

saying that he was “very concerned.” In the end, 

Guide’s view prevailed; BP installed only the six 

centralizer subs on the Macondo production 

casing.

Lowering the Casing String Into Position

Early on the morning of April 18, with a 

centralizer plan in hand, the rig crew finally 

began assembling and lowering the long string 

into position. The leading end of the casing, 

The shoe track, showing the float collar assembly at the top 

and the reamer shoe at the bottom.

TrialGraphix

FIGURE 4.4: Shoe Track
98 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

the “shoe track,” began with a “reamer shoe”—a bullet-shaped piece of metal with three 

holes designed to help guide the casing down the hole. (Figure 4.4) The reamer shoe was 

followed by 180 feet of seven-inch-diameter steel casing. Then came a Weatherfordmanufactured “float collar,” a simple arrangement of two flapper (float) valves, spaced one 

after the other, held open by a short “auto-fill tube” through which the mud in the well 

could flow. As the long string was lowered down the wellbore, the mud passed through 

the holes in the reamer shoe and auto-fill tube that propped open the float valves, giving it 

a clear flow path upward.

Preparation for Cementing—and Unexpected Pressure Anomalies in the Well

The long string was installed in its final position early on the afternoon of April 19. With 

the top end of the string seated in the wellhead and its bottom end located just above the 

bottom of the wellbore, the crew’s next job was to prepare the float-valve system for 

cementing. During the cementing process, fluids pumped into the well should flow in 

a one-way path: down the center of the last casing string, out the bottom, and up the 

annulus (between the exterior of the steel casing and the surrounding rock formations). 

To ensure unidirectional flow, the crew needed to push the auto-fill tube downward, so 

it would no longer prop open the float valves. With the tube out of the way, the flapper 

valves would spring shut and convert from two-way valves into one-way valves that 

would allow mud and cement to flow down the casing into the shoe track, but prevent 

any fluid from reversing direction and coming back up the casing. Once the float valves 

had converted, Halliburton could pump cement down through the casing and up around 

the annulus; the valves would keep cement from flowing back up the casing once the crew 

stopped pumping.

To convert the float valves, that evening the crew began pumping mud down through the 

casing. Based on Weatherford’s specifications, the valves should convert once the rate of 

flow though holes in the auto-fill tube had reached roughly 6 barrels per minute (bpm), 

causing a differential pressure on the tube of approximately 600 pounds per square inch 

(psi).23 But the crew hit a stumbling block. They pumped fluids into the well, eventually 

pressuring up to 1,800 psi, but could not establish flow. 

Well Site Leader Bob Kaluza and BP engineer Morel24 called Guide, their supervisor on 

shore. In consultation with Guide and Weatherford staff, the rig team decided to increase 

the pump pressure in discrete increments, hoping eventually to dislodge the auto-fill 

tube.25 On their ninth attempt, pump pressure peaked at 3,142 psi and then suddenly 

dropped as mud finally began to flow. Significantly, however, the pump rate of mud into 

the well and through the shoe track thereafter never exceeded approximately 4 bpm.26

BP’s team concluded that the float valves had converted, but noted another anomaly. The 

drilling-mud subcontractor, M-I SWACO, had predicted that it would take a pressure of 

570 psi to circulate mud after converting the float valves.27 Instead, the rig crew reported 

that circulation pressure was much lower: only 340 psi. BP’s Well Site Leader Bob Kaluza 

expressed concern about low circulating pressure.28 He and the Transocean crew switched 

circulating pumps to see if that made a difference, and eventually concluded that the 

pressure gauge they had been relying on was broken.29 Believing they had converted the 
Chapter Four 99 99

float valves and reestablished mud circulation in the well, BP was ready at last to pump 

cement down the production casing and complete the primary cement job.

The Inherently Uncertain Cementing Process

Cementing an oil well is an inherently uncertain process. To establish isolation across a 

hydrocarbon zone at the bottom of a well, engineers must send a slug of cement down 

the inside of the well. They then pump mud in after it to push the cement down until it 

“turns the corner” at the bottom of the well and flows up into the annular space. If done 

properly, the slug of cement will create a long and continuous seal around the production 

casing, and will fill the shoe track in the bottom of the final casing string. But things 

can go wrong even under optimal conditions. If the cement is pumped too far or not far 

enough, it may not isolate the hydrocarbon zones. If oil-based drilling mud contaminates 

the water-based cement as the cement flows down the well, the cement can set slowly 

or not at all. And, as previously noted, the cement can “channel,” filling the annulus 

unevenly and allowing hydrocarbons to bypass cement in the annular space. Given the 

variety of things that can go wrong with a cement job, it is hardly surprising that a 2007 

MMS study identified cementing problems as one of the “most significant factors” leading 

to blowouts between 1992 and 2006.30

Even following best practices, a cement crew can never be certain how a cement job at 

the bottom of the well is proceeding as it is pumped. Cement does its work literally miles 

away from the rig floor, and the crew has no direct way to see where it is, whether it is 

contaminated, or whether it has sealed off the well. To gauge progress, the crew must 

instead rely on subtle, indirect indicators like pressure and volume: they know how much 

cement and mud they have sent down the well and how hard the pumps are working to 

push it. The crew can use these readings to check whether each barrel of cement pumped 

into the well displaces an equal volume of drilling mud—producing “full returns.” They 

can also check for pressure spikes to confirm that “wiper plugs” (used to separate the 

cement from the surrounding drilling mud) have landed on time as expected at the bottom 

of the well. And they can look for “lift pressure”—a steady increase in pump pressure 

signifying that the cement has turned the corner at the bottom of the well and is being 

pushed up into the annular space against gravity. 

While they suggest generally that the job has gone as planned, these indicators say little 

specific about the location and quality of the cement at the bottom of the well. None of 

them can take the place of pressure testing and cement evaluation logging (see below). 

The Cementing Design: Critical Decisions for a Fragile Formation

In the days leading up to the final cementing process, BP engineers focused heavily on 

the biggest challenge: the risk of fracturing the formation and losing returns. John Guide 

explained after the incident that losing returns “was the No. 1 risk.”31 He and the other 

BP engineers worried that if their cementing procedure placed too much pressure on the 

geologic formation below, it might trigger another lost-returns event similar to the one on 

April 9. In this case, critical cement—not mud—might flow into the formation and be lost, 

potentially leaving the annular space at the bottom of the well open to hydrocarbon flow. 
100 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

The BP team’s concerns led them to place a number of significant constraints on 

Halliburton’s cementing design. The first compromise in BP’s plan was to limit the 

circulation of drilling mud through the wellbore before cementing. Optimally, mud in the 

wellbore would have been circulated “bottoms up”—meaning the rig crew would have 

pumped enough mud down the wellbore to bring mud originally at the bottom of the well 

all the way back up to the rig. There are at least two benefits to bottoms up circulation. 

Such extensive circulation cleans the wellbore and reduces the likelihood of channeling. And 

circulating bottoms up allows technicians on the rig to examine mud from the bottom of 

the well for hydrocarbon content before cementing. But the BP engineers feared that the 

longer the rig crew circulated mud through the casing before cementing, the greater the 

risk of another lost-returns event. Accordingly, BP circulated approximately 350 barrels 

of mud before cementing, rather than the 2,760 barrels needed to do a full bottoms up 

circulation.32 

BP compromised again by deciding to pump cement down the well at the relatively low 

rate of 4 barrels or less per minute.33 Higher flow rates tend to increase the efficiency with 

which cement displaces mud from the annular space. But the increased pump pressure 

required to move the cement quickly would mean more pressure on the formation (ECD) 

and an increased risk of lost returns. BP decided to reduce the risk of lost returns in 

exchange for a less-than-optimal rate of cement flow. 

BP made a third compromise by limiting the volume of cement that Halliburton would 

pump down the well. Pumping more cement is a standard industry practice to insure 

against uncertain cementing conditions: more cement means less risk of contamination 

and less risk that the cement job will be compromised by slight errors in placement. 

But more cement at Macondo would mean a higher cement column in the annulus, 

which in turn would exert more pressure on the fragile formation below. Accordingly, 

BP determined that the annular cement column should extend only 500 feet above the 

uppermost hydrocarbon-bearing zone (and 800 feet above the main hydrocarbon zones), 

and that this would be sufficient to fulfill MMS regulations of “500 feet above the 

uppermost hydrocarbon-bearing zone.”34 However, it did not satisfy BP’s own internal 

guidelines, which specify that the top of the annular cement should be 1,000 feet above 

the uppermost hydrocarbon zone.35 As designed, BP would have Halliburton pump a total 

of approximately 60 barrels of cement down the well—a volume that its own engineers 

recognized would provide little margin for error.36 

Finally, in close consultation with Halliburton, BP chose to use “nitrogen foam cement”—a 

cement formula that has been leavened with tiny bubbles of nitrogen gas, injected into 

the cement slurry just before it goes down the well. This formula was chosen to lighten 

the resulting slurry from approximately 16.7 ppg to 14.5 ppg—thereby reducing the 

pressure the cement would exert on the fragile formation. The bubbles, in theory, would 

also help to balance the pore pressure in the formation and clear the annular space of mud 

as the cement flowed upward. Halliburton is an industry leader in foam cementing, but 

BP appears to have had little experience with foam technology for cementing production 

casing in the Gulf of Mexico.37
Chapter Four 101 10

The Cement Slurry: Laboratory Analyses

A cement slurry must be tested before it is used in a cement job. Because the pressure 

and temperature at the bottom of a well can significantly alter the strength and curing 

rate of a given cement slurry—and because storing cement on a rig can alter its chemical 

composition over time—companies like Halliburton normally fly cement samples from the 

rig back to a laboratory shortly before pumping a job to make sure the cement will work 

under the conditions in the well. The laboratory conducts a number of tests to evaluate the 

slurry’s viscosity and flow characteristics, the rate at which it will cure, and its eventual 

compressive strength. 

When testing a slurry that will be foamed with nitrogen, the lab also evaluates the 

stability of the cement that results. A stable foam slurry will retain its bubbles and overall 

density long enough to allow the cement to cure. The result is hardened cement that has 

tiny, evenly dispersed, and unconnected nitrogen bubbles throughout. If the foam does not 

remain stable up until the time the cement cures, the small nitrogen bubbles may coalesce 

into larger ones, rendering the hardened cement porous and permeable.38 If the instability 

is particularly severe, the nitrogen can “break out” of the cement, with unpredictable 

consequences.

On February 10, soon after the Deepwater Horizon began work on the well, Jesse Gagliano 

asked Halliburton laboratory personnel to run a series of “pilot tests” on the cement blend 

stored on the Deepwater Horizon that Halliburton planned to use at Macondo.39 They 

tested the slurry40 and reported the results to Gagliano. He sent the laboratory report to BP 

on March 8 as an attachment to an e-mail in which he discussed his recommended plan for 

cementing an earlier Macondo casing string.41

The reported data that Gagliano sent to BP on March 8 included the results of a single foam 

stability test. To the trained eye, that test showed that the February foam slurry design 

was unstable. Gagliano did not comment on the evidence of the cement slurry’s instability, 

and there is no evidence that BP examined the foam stability data in the report at all.

Documents identified after the blowout reveal that Halliburton personnel had also 

conducted another foam stability test earlier in February. The earlier test had been 

conducted under slightly different conditions than the later one and had failed more 

severely.42 It appears that Halliburton never reported the results of the earlier February test 

to BP. 

Halliburton conducted another round of tests in mid-April, just before pumping the final 

cement job. By then, the BP team had given Halliburton more accurate information about 

the temperatures and pressures at the bottom of the Macondo well, and Halliburton 

had progressed further with its cementing plan. Using this information, the laboratory 

personnel conducted several tests, including a foam stability test, starting on approximately 

April 13. The first test Halliburton conducted showed once again that the cement slurry 

would be unstable.43 The Commission does not believe that Halliburton ever reported this 

information to BP. Instead, it appears that Halliburton personnel subsequently ran a second 

foam stability test, this time doubling the pre-test “conditioning time” to three hours.44
102 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

The evidence suggests that Halliburton began the second test at approximately 2:00 a.m. 

on April 18.45 That test would normally take 48 hours. Halliburton finished pumping 

the cement job just before 48 hours would have elapsed.46 Although the second test at 

least arguably suggests the foam cement design used at Macondo would be stable, it is 

unclear whether Halliburton had results from that test in hand before it pumped the job. 

Halliburton did not send the results of the final test to BP until April 26, six days after the 

blowout.47

Evaluating the Cementing Job

Transocean’s rig crew and Halliburton’s cementers finished pumping the primary cement 

job at 12:40 a.m. on April 20.48 Once the pumps were off, a BP representative and Vincent 

Tabler of Halliburton performed a check to see whether the float valves were closed and 

holding. They opened a valve at the cementing unit to see whether any fluid flowed from 

the well. If more fluid came back than expected, that would indicate that cement was 

migrating back up into the casing and pushing the fluids above it out of the top of the 

well. Models had predicted 5 barrels of flow back. According to Brian Morel, the two men 

observed 5.5 barrels of flow, tapering off to a “finger tip trickle.”49 According to Morel, 5.5 

barrels of flow-back volume was within the acceptable margin for error.50 Tabler testified 

that they watched flow “until it was probably what we call a pencil stream,” which 

stopped, started up again, and then stopped altogether.51 While it is not clear how long the 

two men actually watched for potential flow, they eventually concluded the float valves 

were holding.

With no lost returns, BP and Halliburton declared the job a success. Nathaniel Chaisson, 

one of Halliburton’s crew on the rig, sent an e-mail to Jesse Gagliano at 5:45 a.m. saying, 

“We have completed the job and it went well.”52 He attached a detailed report stating that 

the job had been “pumped as planned” and that he had seen full returns throughout the 

process.53 And just before leaving the rig, Morel e-mailed the rest of the BP team to say 

“the Halliburton cement team . . . did a great job.”54

At the 7:30 a.m. morning meeting with contractors on the rig, the BP team concluded the 

cement job went well enough to send home a team of technicians from Schlumberger who 

had been standing by on the rig for at least one day already55 waiting to perform a suite of 

cement evaluation tests on the primary cement job, including cement bond logs.56 The BP 

team relied on a “decision tree” that Guide and BP engineers had prepared beforehand. The 

Cement Evaluation Tools

Cement evaluation tools (including “cement bond logs”) test the integrity of cement in the annular 

space around a casing. The tools measure whether and to what extent cement has bonded to the 

outside of the casing and formation, and the location and severity of any channels through the 

cement. Although a modern cement evaluation combines several different instruments, the primary 

approach is to analyze the casing’s response to acoustic signals. Just as a muffled bell sounds 

different than a free-swinging bell, a well casing will respond differently depending on the volume 

and quality of cement around it. Cement evaluation tools do have important limits. Among other 

things, they work better after the cement has had time to cure completely. They also cannot evaluate 

cement in the shoe track of a casing, or in the annular space below the float valves. 
Chapter Four 103 103

primary criterion BP appears to have used to determine whether to perform the cement 

evaluation test was whether there were “[l]osses while cementing [the] long string.”57

Having seen no lost returns during the cement job, BP sent the Schlumberger team home 

and moved on to prepare the well for temporary abandonment.

Temporary Abandonment and Preparing to 

Move On to the Next Job 

Once BP decided to send the Schlumberger team home, Deepwater Horizon’s crew began 

the final phase of its work. Drilling the Macondo well had required a giant offshore rig 

of Deepwater Horizon’s capabilities. By contrast, BP, like most operators, would give 

the job of “completing” the well to a smaller (and less costly) rig, which would install 

hydrocarbon-collection and -production equipment. To make way for the new rig, the 

Deepwater Horizon would have to remove its riser* and blowout preventer from the 

wellhead—and before it could do those things, the crew had to secure the well through a 

process called “temporary abandonment.” 

Four features of the temporarily abandoned well are worth noting. First is the single 

300-foot-long cement plug inside the wellbore. MMS regulations required BP to install 

a cement plug as a backup for the cement job at the bottom of the well. Second is the 

location of the cement plug: BP planned to put it 3,300 feet below the ocean floor, or 

“mud line” (which was deeper than MMS regulations allowed without dispensation, and 

deeper than usual).58 Third is the presence of seawater in the well below the sea floor: BP 

planned to replace 3,000 feet of mud in the wellbore above the cement plug with much 

FIGURE 4.5: Temporary Abandonment

The status of the well before and after temporary abandonment.

TrialGraphix

* The riser is the piping that connects the drilling rig at the surface with the BOP at the wellhead on the seafloor.
104 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

lighter seawater (seawater weighs roughly 8.6 ppg, while the mud in the wellbore weighed 

roughly 14.5 ppg). Fourth is the lockdown sleeve—a mechanical device that locks the long 

casing string to the wellhead to prevent it from lifting out of place during subsequent 

production operations. (Figure 4.5)

At 10:43 a.m., Morel e-mailed an “Ops Note” to the rest of the Macondo team listing the 

temporary abandonment procedures for the well.59 It was the first time the BP Well Site 

Leaders on the rig had seen the procedures they would use that day. BP first shared the 

procedures with the rig crew at the 11 a.m. pre-tour meeting that morning.60 The basic 

sequence was as follows: 

1. Perform a positive-pressure test to test the integrity of the production casing;

2. Run the drill pipe into the well to 8,367 feet (3,300 feet below the mud line);

3. Displace 3,300 feet of mud in the well with seawater, lifting the mud above the BOP 

and into the riser;

4. Perform a negative-pressure test to assess the integrity of the well and bottom-hole 

cement job to ensure outside fluids (such as hydrocarbons) are not leaking into the 

well;

5. Displace the mud in the riser with seawater;

6. Set the surface cement plug at 8,367 feet; and

7. Set the lockdown sleeve.61

The crew would never get through all of the steps in the procedure.

BP’s Macondo team had made numerous changes to the temporary abandonment 

procedures in the two weeks leading up to the April 20 “Ops Note.” For example, in its 

April 12 drilling plan, BP had planned (1) to set the lockdown sleeve before setting the 

surface cement plug and (2) to set the surface cement plug in seawater only 6,000 feet 

below sea level (as opposed to 8,367 feet). The April 12 plan did not include a negativepressure test.62 On April 14, Morel sent an e-mail entitled “Forward Ops” setting forth a 

different procedure, which included a negative-pressure test but would require setting the 

surface cement plug in mud before displacement of the riser with seawater.63 On April 16, 

BP sent an Application for Permit to Modify to MMS describing a temporary abandonment 

procedure that was different from the procedure in either the April 12 drilling plan, the 

April 14 e-mail, or the April 20 “Ops Note.”64 There is no evidence that these changes went 

through any sort of formal risk assessment or management of change process. 

Lockdown Sleeve

Before the Macondo blowout, a lockdown sleeve was not generally considered a safety mechanism 

or barrier to flow prior to the production phase of the well. Drilling rigs did not generally set lockdown 

sleeves. Rather, completion or production rigs did so after the drilling phase. BP decided to have 

the Deepwater Horizon set the lockdown sleeve because the Horizon could do the job more quickly 

than the completion rig. Based on the Macondo event, and given early concerns that upward forces 

during the blowout had approached or exceeded the force needed to lift the production casing 

up out of its seat in the wellhead, the Commission believes operators should consider installing a 

lockdown sleeve or other device to lock the casing hanger in place as part of drilling operations (or, 

at the very least, at the outset of temporary abandonment). 
Chapter Four 105 105

Countdown to Blowout

The first step in the temporary abandonment was to test well integrity: to make sure there 

were no leaks in the well.

The Positive-Pressure Test

The positive-pressure test evaluates, among other things, the ability of the casing in 

the well to hold in pressure. MMS regulations require a positive-pressure test prior to 

temporary abandonment.65 To perform the test at Macondo, the Deepwater Horizon’s crew 

first closed off the well below the BOP by shutting the blind shear ram (there was no drill 

pipe in the well at the time).66 Then, much like pumping air into a bike tire to check for 

leaks, the rig crew pumped fluids into the well (through pipes running from the rig to the 

BOP) to generate pressure and then checked to see if it would hold. 

The crew started the positive-pressure test at noon.67 They pressured the well up to 250 

psi for 5 minutes, and then pressured up to 2,500 psi and watched for 30 minutes. The 

pressure inside the well remained steady during both tests, showing there were no leaks in 

the production casing through which fluids could pass from inside the well to the outside. 

The drilling crew and BP’s Well Site Leader Bob Kaluza considered the test successful. Later 

in the afternoon, Kaluza showed visiting BP executive Pat O’Bryan the pressure chart from 

the test; O’Bryan remarked, “Things looked good with the positive test.”68 

The Negative-Pressure Test: Unexpected Pressure Readings 

The negative-pressure test checks not only the integrity of the casing, like the positivepressure test, but also the integrity of the bottomhole cement job. At the Macondo well, the 

negative-pressure test was the only test performed that would have checked the integrity 

of the bottomhole cement job. 

Instead of pumping pressure into the wellbore to see if fluids leak out, the crew removes

pressure from inside the well to see if fluids, such as hydrocarbons, leak in, past or 

through the bottomhole cement job. In so doing, the crew simulates the effect of 

removing the mud in the wellbore and the riser (and the pressure exerted by that mud) 

during temporary abandonment. If the casing and primary cement have been designed 

and installed properly, they will prevent hydrocarbons from intruding even when that 

“overbalancing” pressure is removed.69 First, the crew sets up the well to simulate the 

expected hydrostatic pressure exerted by the column of fluids on the bottom of the well in 

its abandoned state. Second, the crew bleeds off any pent-up pressure that remains in the 

well, taking it down to 0 psi. Third, the crew and Well Site Leaders watch to make sure 

that nothing flows up from and out of the well and that no pressure builds back up inside 

of the well. If there is no flow or pressure buildup, that means that the casing and primary 

cement have sealed the well off from external fluid pressure and flow. A negative-pressure 

test is successful if there is no flow out of the well for a sustained period and if there is no 

pressure build-up inside the well when it is closed at the surface. 

To conduct a proper negative test at Macondo, BP would have to isolate the well from the 

effect of the 5,000-foot-plus column of drilling mud in the riser and a further 3,300-foot 

column of drilling mud below the seafloor. Those heavy columns of mud exerted much 
106 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

more pressure on the well than the seawater that would replace them after temporary 

abandonment. Specifically, the pressure at the bottom of the well would be approximately 

2,350 psi lower after temporary abandonment than before.70 Once this pressure was 

removed, the downward force of the column of fluids in the well would be less than the 

pressure of the hydrocarbons in the reservoir, so the well would be in what is called an 

“underbalanced” state. It was therefore critical to test and confirm the ability of the well 

(including the primary cement job) to withstand the underbalance. If the test showed 

that hydrocarbons would leak into the well once it was underbalanced, BP would need to 

diagnose and fix the problem (perhaps remediating the cement job) before moving on, a 

process that could take many days. 

The crew began the negative test of Macondo at 5:00 p.m. Earlier in the day, the crew had 

prepared for the negative test by setting up the well to simulate the planned removal of 

the mud in the riser and 3,300 feet of drilling mud in the wellbore. The crew ran the drill 

pipe down to approximately 8,367 feet below sea level and then pumped a “spacer”—a 

liquid mixture that serves to separate the heavy 

drilling mud from the seawater—followed by 

seawater down the drill pipe to push (displace) 

3,300 feet of mud from below the mud line to 

above the BOP. (Figure 4.6) 

While drilling crews routinely use water-based 

spacer fluids to separate oil-based drilling mud 

from seawater, the spacer BP chose to use 

during the negative pressure test was unusual. 

BP had directed M-I SWACO mud engineers on 

the rig to create a spacer out of two different 

lost-circulation materials left over on the 

rig—the heavy, viscous drilling fluids used 

to patch fractures in the formation when the 

crew experiences lost returns.71 M-I SWACO 

had previously mixed two different unused 

batches, or “pills,” of lost-circulation materials 

in case there were further lost returns.72 BP 

wanted to use these materials as spacer in order 

to avoid having to dispose of them onshore 

as hazardous waste pursuant to the Resource 

and Conservation Recovery Act, exploiting an 

exception that allows companies to dump waterbased “drilling fluids” overboard if they have 

been circulated down through a well.73 At BP’s 

direction, M-I SWACO combined the materials to 

create an unusually large volume of spacer that 

had never previously been used by anyone on 

the rig or by BP as a spacer, nor been thoroughly 

tested for that purpose.74 

Seawater (blue) displaces mud (brown) from wellbore and 

riser, with spacer fluid separating the two.

TrialGraphix

FIGURE 4.6: Displacing Mud With Spacer and 

Seawater Before the Negative Pressure Test
Chapter Four 107 107

Once the crew had displaced the mud to above the BOP, they shut an annular preventer 

in the BOP, isolating the well from the downward pressure exerted by the heavy mud and 

spacer in the riser. The crew could now perform the negative-pressure test using the drill 

pipe: it would open the top of the drill pipe on the rig, bleed the drill pipe pressure to zero, 

and then watch for flow. The crew opened the drill pipe at the rig to bleed off any pressure 

that had built up in the well during the mud-displacement process. The crew tried to bleed 

the pressure down to zero, but could not get it below 266 psi. When the drill pipe was 

closed, the pressure jumped back up to 1,262 psi. 

Around this time, the driller’s shack was growing crowded. The night crew was arriving in 

preparation for the 6:00 p.m. shift change, which meant that both toolpushers—Wyman 

Wheeler and Jason Anderson—and both Well Site Leaders—Bob Kaluza and Don Vidrine—

were present. In addition, a group of visiting BP and Transocean executives entered as part 

of a rig tour escorted by Transocean Offshore Installation Manager Jimmy Harrell.75 It 

was apparent to at least one member of the tour that the crew was having a “little bit of a 

problem.”76 

The crew had noticed that the fluid level inside the riser was dropping, suggesting that 

spacer was leaking down past the annular preventer, out of the riser, and into the well 

(Figure 4.7). Harrell, who stayed behind in the drill shack as the tour continued, ordered 

the annular preventer closed more tightly to stop the leak.77 Harrell then left the rig floor.

With that problem solved, the crew refilled the riser and once again opened up the drill pipe 

and attempted a second time to bleed the pressure down to 0 psi. This time, they were able 

to do so. But when they shut the drill pipe in again, the pressure built back up to at least 

773 psi. The crew then attempted a third time to bleed off the pressure from the drill pipe, 

and was again able to get it down to 0 psi. When the crew shut the well back in, however, 

the pressure increased to 1,400 psi. At this point, the crew had bled the drill-pipe pressure 

down three times, but each time it had built back up. For a successful negative-pressure 

test, the pressure must remain at 0 psi when the pipe is closed after the pressure is bled off. 

The Transocean crew and BP Well Site Leaders met on the rig floor to discuss the readings. 

In addition to Kaluza, Vidrine, and Anderson, Dewey Revette (Transocean’s on-duty 

driller) and BP Well Site Leader trainee Lee Lambert were there. According to post-incident 

statements from both Well Site Leaders, Anderson said that the 1,400 psi pressure on the 

drill pipe was being caused by a phenomenon called the “bladder effect.”78 According to 

Lambert, Anderson explained that heavy mud in the riser was exerting pressure on the 

annular preventer, which in turn transmitted pressure to the drill pipe. Lambert said that 

he did not recall anyone agreeing or disagreeing with Anderson’s explanation.79

According to Harrell, after a lengthy discussion, BP Well Site Leader Vidrine then insisted 

on running a second negative-pressure test, this time monitoring pressure and flow on the 

kill line rather than the drill pipe. (The kill line is one of three pipes, each approximately 3 

inches in diameter, that run from the rig to the BOP to allow the crew to circulate fluids 

into and out of the well at the sea floor.) The pressure on the kill line during the negativepressure test should have been identical to the pressure on the drill pipe, as both flow 
108 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

paths went to the same place (and both should have been filled with seawater). Vidrine 

apparently insisted the negative test be repeated on the kill line because BP had specified 

that the test would be performed on the kill line in a permit application it submitted earlier 

to MMS.80

For the second test, the crew opened the kill line and bled the pressure down to 0 psi. A 

small amount of fluid flowed, and then stopped.81 Rig personnel left the kill line open for 

30 minutes but did not observe any flow from it. The test on the kill line thus satisfied the 

criteria for a successful negative pressure test—no flow or pressure buildup for a sustained 

period of time. But the pressure on the drill pipe remained at 1,400 psi throughout. The 

Well Site Leaders and crew never appear to have reconciled the two different pressure 

readings.82 The “bladder effect” may have been proposed as an explanation for the 

anomaly—but based on available information, the 1,400 psi reading on the drill pipe could 

Spacer fluids (orange) leak past annular preventer.

TrialGraphix

FIGURE 4.7: Fluids Leak Past Annular Preventer
Chapter Four 109 109

only have been caused by a leak into the well. Nevertheless, at 8 p.m., BP Well Site Leaders, 

in consultation with the crew, made a key error and mistakenly concluded the second 

negative test procedure had confirmed the well’s integrity. They declared the test a success 

and moved on to the next step in temporary abandonment. 

Displacing Mud from the Riser—and Mounting Signs of a Kick 

At 8:02 p.m., the crew opened the annular preventer and began displacing mud and 

spacer from the riser. Halliburton cementer Chris Haire went to the drill shack to check on 

the status of the upcoming surface cement plug job. Revette and Anderson told him the 

negative-pressure test had been successful and that Haire should prepare to set the surface 

cement plug.83

Revette sat down in his driller’s chair to monitor the well for kicks—any unplanned 

influxes of gas or fluids—and other anomalies. As gaseous hydrocarbons in a kick rise up 

the wellbore, they expand with ever-increasing speed—a barrel of natural gas at Macondo 

could expand over a hundredfold as it traveled the 5,000 feet between the wellhead and 

the rig above.84 And as the gas expands, it pushes mud upward faster and faster, reducing 

the pressure on the gas and increasing the speed of the kick—making it imperative that rig 

crews recognize and respond to a kick as early as possible.

The individuals responsible for detecting kicks on a rig include the driller, assistant drillers, 

and the mudlogger.85 Dewey Revette was the driller on duty at the time; the two assistant 

drillers on duty were Donald Clark and Stephen Curtis. Joseph Keith of Sperry Sun was the 

mudlogger. 

These individuals look for kicks by monitoring real-time data displays in the driller’s 

shack, mudlogger’s shack, and elsewhere on the rig. They watch two primary parameters. 

The first, and most reliable when available, is the volume of mud in the active pits. The 

volume of mud sent from the active pits into the well should equal the volume of mud 

returning to the active pits from the well. An increase in volume is a powerful indicator 

that something is flowing into the well. 

Second, under normal circumstances, the volume and rate of flow of fluids coming from 

the well should equal the volume and rate of flow of fluid pumped into the well. If flow 

out of the well is greater than flow into the well, it is a strong indicator that a kick may be 

under way. 

In addition to these two primary parameters, the crew can perform visual “flow checks.” 

There were a number of cameras and stations on the Deepwater Horizon where the driller, 

mudlogger, and others could observe whether fluids were flowing from the well. When 

Active Pit System

Rigs contain multiple mud pits. The Deepwater Horizon had 20 in all. Various fluids can be stored 

in these pits, including drilling mud. The active pit system is a subset of the mud pits that the driller 

selects for monitoring purposes.
110 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

the pumps are shut off and mud is no longer being sent into the well, flow out of the well 

should stop. Visual flow checks are a reliable way to monitor for kicks when pumps are 

off and are often used to confirm other kick indicators.

Finally, the driller and mudlogger also monitor drill-pipe pressure, but it is a more 

ambiguous kick indicator than the other parameters because there can be many reasons 

for a change in drill pressure. If drill-pipe pressure decreases while the pump rate remains 

constant, that may indicate that hydrocarbons have entered the wellbore and are moving 

up the well past the sides of the drill pipe. The lighter-weight hydrocarbons exert less 

downward pressure, meaning the pumps do not need to work as hard to push fluids into 

the well. If drill-pipe pressure increases while the pump rate remains constant, that may 

indicate that heavier mud is being pushed up from below (perhaps by hydrocarbons) and 

displacing lighter fluids in the well adjacent to the drill pipe. Unexplained changes in drillpipe pressure may not always indicate a kick, but when observed should be investigated. 

The crew should shut down the pumps and monitor the well to confirm it is static; if they 

are unable to do so, they should shut in the well until the source of the readings can be 

determined. 

The Deepwater Horizon had two separate systems for collecting and displaying real-time 

data. The “Hitec” system, owned by Transocean, was the source on which the Deepwater 

Horizon’s drilling crew typically relied for monitoring the well. The “Sperry Sun” 

system—installed and operated by a Halliburton subsidiary at BP’s request—sent data 

back to shore in real time, allowing BP personnel to access and monitor this data from 

anywhere with an Internet connection.*

 Individuals on the rig could monitor data from the 

Sperry Sun system as well.

Once the crew began displacing the riser with seawater at 8:02 p.m., they confronted the 

challenge of dealing with all of the returning mud. The driller repeatedly rerouted the mud 

returns from one pit to another in order to accommodate the incoming volume.86 During 

that time, the crew also sent mud from other locations into the active pit system.87 It is

not clear whether the driller, assistant drillers, or mudlogger could adequately monitor 

active pit volume (or flow-in versus flow-out) during that time given all the activity. 

Nevertheless, things appear to have been relatively uneventful until 9:00 p.m. Drillpipe pressure was slowly but steadily decreasing over that time as lighter seawater 

displaced heavy drilling mud in the riser, lowering the pressure in the well and making it 

progressively easier to push seawater down into the well through the drill pipe.88

At approximately 9:01 p.m., however, drill-pipe pressure (shown by the red line in Figure 

4.8) began slowly increasing, despite the fact that the pump rate remained constant.89 

Over the next seven minutes, it crept slowly upward from 1,250 to 1,350 psi.90 While the 

* It is difficult, if not impossible, to know precisely what the driller, assistant drillers, and mudloggers were doing and what data they were 

looking at between 8:00 p.m. and the first explosion at 9:49 p.m. Both the Hitec and Sperry Sun displays can be customized, and each 

operator typically has his own preferred set-up. Moreover, the full Hitec data set sank with the rig, leaving only the Sperry Sun subset of the 

data behind. Because the Sperry Sun data are all that is now available, the Commission focuses upon that data while recognizing that it is at 

best an approximation of what the driller, mudlogger, and others on the rig may have been looking at in the hours and minutes leading up to 

the blowout. 
Chapter Four 111 11

magnitude of the increase may have appeared only as a subtle trend on the Sperry Sun 

display, the change in direction from decreasing to increasing was not. 91 

Had someone noticed it, he would have had to explain to himself how the drill-pipe 

pressure could be increasing while the pump rate was not. One possible reason might have 

been that hydrocarbons were flowing into the well and pushing heavy drilling mud up 

past the drill pipe. 

The crew may have been distracted by other matters. At about that time, the last of the 

mud in the riser was arriving at the rig.92 After that point, the next returning fluid would 

be the 400-plus barrels of spacer the crew had pumped into the well during the negativepressure test. BP planned to dump that spacer overboard, but, according to regulations, 

would first have to run a test to make sure that it had removed all of the oil-based mud 

from the riser.93

Sperry Sun drill-pipe pressure data (in red).

FIGURE 4.8: Increasing Drill-Pipe Pressure
112 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

At 9:08 p.m., the crew shut down the pumps to perform this “sheen test.”94 They closed a 

valve on the flow line that had been carrying fluids from the well to the pit system.95 Mud 

engineer Greg Meche sampled the fluid and had it tested. Well Site Leader Vidrine waited 

for confirmation that there was no oily “sheen” on the returning spacer.96 And mudlogger 

Joseph Keith performed a visual flow check to ensure the well was not flowing while the 

pumps were off. According to Keith, there was no flow.97 

The pumps were shut down for 6 minutes, from 9:08 p.m. to 9:14 p.m. Meche took a 

sample of the returning fluid from the shaker house*

 and went to the mud lab to run the 

test.98 He then returned to the shaker house, weighed the sample, and spoke with another 

of the mud engineers about the results.99 When Vidrine learned the results, he signed off 

on the test and the crew turned the pumps back on.100

What nobody appears to have noticed during those six minutes (perhaps as a result of all 

of the activity) was that drill-pipe pressure was increasing again. With the pumps off, the 

drill-pipe pressure (red line in yellow box in Figure 4.8) should have stayed constant or 

gone down. Instead, it went up by approximately 250 psi.101 This increase in pressure was 

clear in the Sperry Sun data, and likely would have been clearer on the Hitec display. Had 

someone noticed it, he would have recognized this as a significant anomaly that warranted 

further investigation before turning the pumps back on. But by 9:14 p.m., the crew 

turned the pumps back on, obscuring the signal. Drill-pipe pressure increased, but so did 

the pump rate.102

Four minutes later, a pressure-relief valve on one of the pumps blew.103 Revette organized 

a group of crewmembers to go to the pump room to fix the valve. The group included 

derrickhand Wyatt Kemp, floorhands Shane Roshto and Adam Weise, and possibly one of 

the assistant drillers.104 These men were still attending to the repair at the time of the first 

explosion.105

At about 9:20 p.m., senior toolpusher Randy Ezell called the rig floor and asked Jason 

Anderson about the negative-pressure test. Anderson responded that, “It went good.” Ezell

then asked about the displacement. Anderson reassured Ezell, “It’s going fine. . . . I’ve got 

this.”106

Shortly before 9:30 p.m., Revette noticed an odd and unexpected pressure difference 

between the drill pipe and the kill line. At roughly 9:30 p.m., the crew shut off the 

pumps to investigate.107 At about that time, Chief Mate David Young arrived at the rig 

floor to discuss the upcoming cement plug job with Revette and Anderson.108 Young 

witnessed Revette and Anderson having a calm discussion about a “differential pressure.”109 

Anderson informed Young that the cement plug would be delayed.110

The drill-pipe pressure initially decreased after the pumps were turned off, but then 

increased by 550 psi over a 5.5 minute period.111 (Figure 4.9) Meanwhile, the pressure 

on the kill line remained significantly lower. At approximately 9:36 p.m., Revette ordered 

*

 The “shaker house” is a room or small separate structure on the rig for “shale shakers”—sieves and shakers that remove cuttings from the 

mud as it comes out of the well. 
Chapter Four 113 113

floorhand Caleb Holloway to bleed off the drill-pipe pressure, in an apparent attempt to 

eliminate the difference.112 The drill-pipe pressure initially dropped off as expected, but 

immediately began climbing again.113 Young and Anderson left the rig floor.114 Despite the 

mounting evidence of a kick, however, neither Revette nor Anderson performed a visual 

flow check or shut in the well.

At 9:39 p.m., drill-pipe pressure shifted direction and started decreasing.115 In retrospect, 

this was a very bad sign. It likely meant that lighter-weight hydrocarbons were now 

pushing heavy drilling mud out of the way up the casing past the drill pipe. 

Diversion and Explosion

Sometime between 9:40 and 9:43 p.m., drilling mud began spewing from the rotary onto 

the rig floor. This appears to have been the first moment Revette or others realized that 

a kick had occurred. At about that time, Anderson and assistant driller Stephen Curtis 

returned to the rig floor.116

Sperry Sun drill-pipe pressure data (in red).

FIGURE 4.9: Fluctuating Drill-Pipe Pressure
114 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

The men took immediate action. First, they routed the flow coming from the riser through 

the diverter system, deciding to send it into the mud-gas separator rather than overboard 

into the sea (which was another option).117 Second, they closed one of the annular 

preventers on the BOP to shut in the well.118 At roughly 9:45 p.m., assistant driller Curtis 

called senior toolpusher Ezell to tell him that the well was blowing out, that mud was 

going into the crown on top of the derrick, and that Anderson was shutting the well in.119

Their efforts were futile. By the time the rig crew acted, gas was already above the BOP, 

rocketing up the riser, and expanding rapidly. At the Commission’s November 8, 2010, 

hearing, a representative from Transocean likened it to “a 550-ton freight train hitting 

the rig floor,” followed by what he described as “a jet engine’s worth of gas coming out 

of the rotary.”120 The flow from the well quickly overwhelmed the mud-gas separator 

system. Ignition and explosion were all but inevitable. The first explosion occurred at 

approximately 9:49 p.m. On the drilling floor, the Macondo disaster claimed its first 

victims. 

The Well is Not Sealed by the Blowout Preventer

The BOP is designed to contain pressure within the wellbore and halt an uncontrolled flow 

of hydrocarbons to the rig. The Deepwater Horizon’s BOP did not succeed in containing the 

Macondo well. 

Witness accounts indicate that the rig crew activated one of the annular preventers around 

9:41 p.m., and pressure readings suggest they activated a variable bore ram (which closes 

around the drill pipe) around 9:46 p.m.121 Flow rates at this point may have been too 

high for either the annular preventer or a variable bore ram to seal the well. (Earlier kick 

detection would have improved the odds of success.)

After the first explosion, crewmembers on the bridge attempted to engage the rig’s 

emergency disconnect system (EDS). The EDS should have closed the blind shear ram, 

severed the drill pipe, sealed the well, and disconnected the rig from the BOP.122 But none 

of that happened. Amid confusion on the bridge, and initial hesitancy from Captain 

Kuchta, subsea supervisor Chris Pleasant rushed to the main control panel and pushed 

the EDS button.123 Although the panel indicators lit up, the rig never disconnected.124 It is 

possible that the first explosion had already damaged the cables to the BOP, preventing the 

disconnect sequence from starting.

Diverter System 

The diverter system provides two alternate paths for gas or gas-bearing mud returning to the rig from 

the well. The first path is through the mud-gas separator (“MGS”). The MGS consists of a series of 

pipes, valves, and a tank configured to remove gas entrained in relatively small amounts of mud. The 

gas is then vented from an outlet valve located high on the derrick. The MGS cannot accommodate 

substantial rates of mud flow. The second path is overboard. The diverter system has two 14-inch 

pipes, one starboard and one portside, through which flow can be sent overboard on the downwind 

side of the rig.
Chapter Four 115 115

Even so, the BOP’s automatic mode function (the “deadman” system) should have 

triggered the blind shear ram after the power, communication, and hydraulics connections 

between the rig and the BOP were cut. But the deadman failed too. Although it is too early 

to tell at this point, this failure may have been due to poor maintenance. Post-incident 

testing of the two redundant “pods” that control the deadman revealed low battery charges 

in one pod and defective solenoid valves in the other. If those problems existed at the time 

of the blowout, they would have prevented the deadman system from working.125*

The Immediate Causes of the Macondo Well Blowout 

As this narrative suggests, the Macondo blowout was the product of several individual 

missteps and oversights by BP, Halliburton, and Transocean, which government regulators 

lacked the authority, the necessary resources, and the technical expertise to prevent. 

We may never know the precise extent to which each of these missteps and oversights 

in fact caused the accident to occur. Certainly we will never know what motivated the 

final decisions of those on the rig who died that night. What we nonetheless do know 

is considerable and significant: (1) each of the mistakes made on the rig and onshore by 

industry and government increased the risk of a well blowout; (2) the cumulative risk that 

resulted from these decisions and actions was both unreasonably large and avoidable; and 

(3) the risk of a catastrophic blowout was ultimately realized on April 20 and several of 

the mistakes were contributing causes of the blowout. 

The immediate cause of the Macondo blowout was a failure to contain hydrocarbon 

pressures in the well. Three things could have contained those pressures: the cement at 

the bottom of the well, the mud in the well and in the riser, and the blowout preventer. 

But mistakes and failures to appreciate risk compromised each of those potential barriers, 

steadily depriving the rig crew of safeguards until the blowout was inevitable and, at the 

very end, uncontrollable.

Cementing

Long string casing vs. liner. BP’s decision to employ a long string was not unprecedented. 

Long strings are used with some frequency by other operators in the Gulf of Mexico, 

although not very often at wells like Macondo—a deepwater well in an unfamiliar 

geology requiring a finesse cement job.126 It is not clear whether the decision to use a long 

string well design contributed directly to the blowout:127 But it did increase the difficulty 

of obtaining a reliable primary cement job in several respects,128 and primary cement 

failure was a direct cause of the blowout. The long string decision should have led BP and 

Halliburton to be on heightened alert for any signs of primary cement failure. 

Number of centralizers. The evidence to date does not unequivocally establish whether the 

failure to use 15 additional centralizers was a direct cause of the blowout. But the process 

* The Commission has not yet determined whether the BOP failed to operate as designed or whether any of the factors discussed 

contributed to such a failure. The Commission believes it is inappropriate to speculate about answers to those questions at this time. Test 

records of critical emergency backup systems have not yet been made available. More importantly, a government-sponsored forensic 

analysis of the BOP is still under way; when completed, that should shed light on why the BOP failed to shut in the Macondo well.
116 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

by which BP arrived at the decision to use only six centralizers at Macondo illuminates the 

flaws in BP’s management and design procedures, as well as poor communication between 

BP and Halliburton. 

For example, it does not appear that BP’s team tried to determine before April 15 whether 

additional centralizers would be needed. Had BP examined the issue earlier, it might have 

been able to secure additional centralizers of the design it favored. Nor does it appear that 

BP based its decision on a full examination of all potential risks involved. Instead, the 

decision appears to have been driven by an aversion to one particular risk: that slip-on 

centralizers would hang up on other equipment. 

BP did not inform Halliburton of the number of centralizers it eventually used, let alone 

request new modeling to predict the impact of using only six centralizers.129 Halliburton 

happened to find out that BP had run only six centralizers when one of its cement 

engineers overheard a discussion on the rig.130

Capping off the communication failures, BP now contends that the 15 additional 

centralizers the BP team flew to the rig may, in fact, have been the ones they wanted. BP’s 

investigation report states that BP’s Macondo team “erroneously believed” they had been 

sent the wrong centralizers.131 To this day, BP witnesses provide conflicting accounts as to 

what type of centralizers were actually sent to the rig. 

BP’s overall approach to the centralizer decision is perhaps best summed up in an e-mail 

from BP engineer Brett Cocales sent to Brian Morel on April 16. Cocales expressed 

disagreement with Morel’s opinion that more centralizers were unnecessary because the 

hole was straight, but then concluded the e-mail by saying 

But, who cares, it’s done, end of story, [we] will probably be fine and we’ll get a good 

cement job. I would rather have to squeeze [remediate the cement job] than get stuck 

above the WH [wellhead]. So Guide is right on the risk/reward equation.132

Float-valve conversion and circulating pressure. Whether the float valves converted, let 

alone whether “unconverted” float valves contributed to the eventual blowout, has not yet 

been, and may never be, established with certainty. But, what is certain is that BP’s team 

again failed to take time to consider whether and to what extent the anomalous pressure 

readings may have indicated other problems or increased the risk of the upcoming cement 

job.

BP’s team appears not to have seriously examined why it had to apply over four times the 

750 psi design pressure to convert the float valves. More importantly, the team assumed 

that the sharp drop from 3,142 psi meant the float valves had in fact converted. That was 

not at all certain. The auto-fill tube was designed to convert in response to flow-induced

pressure. Without the required rate of flow, an increase in static pressure, no matter how 

great, will not dislodge the tube. 
Chapter Four 117 117

While BP’s Macondo team focused on the peak pressure reading of 3,142 psi and the fact 

that circulation was reestablished, it does not appear the team ever considered whether 

sufficient mud flow rate had been achieved to convert the float valves. They should have 

considered this issue. Because of ECD concerns, BP’s engineers had specified a very low 

circulating pump rate—lower than the flow rate necessary to convert the float valves. BP 

does not appear to have accounted for this fact. 

Cement evaluation log decision. The BP team erred by focusing on full returns as the sole 

criterion for deciding whether to run a cement evaluation log. Receiving full returns was a 

good indication that cement or other fluids had not been lost to the weakened formation. 

But full returns provided, at best, limited or no information about: (1) the precise location 

where the cement had ended up; (2) whether channeling had occurred; (3) whether the 

cement had been contaminated;133 or (4) whether the foam cement had remained stable. 

Although other indicators—such as on-time arrival of the cement plugs and observation 

of expected lift pressure—were reassuring, they too provided limited information. Other 

cement evaluation tools could have provided more direct information about cementing 

success. 

Cement evaluation logs plainly have their limitations, particularly at Macondo. But while 

many companies do not run cement evaluation logs until the completion phase, BP should 

have run one here—or sought other equivalent indications of cement quality in light of the 

many issues surrounding and leading up to the cement job. BP’s own report agrees.134 

Foam cement testing. As explained in an October letter written by the Commission’s Chief 

Counsel, independent cement testing conducted by Chevron strongly suggests the foam 

cement slurry used at Macondo was unstable.135 As it turned out, Chevron’s tests were 

consistent with several of Halliburton’s own internal test results, some of which appear 

never to have been reported to BP. 

Halliburton’s two February tests both indicated that the foam cement slurry would be 

unstable, which should have prompted the company to reconsider its slurry design.136

It is irrelevant that the February tests were performed on a slightly different slurry than 

was actually pumped at Macondo or that assumptions about down-hole temperatures 

and pressures in February had changed by April 19. Under the circumstances, Halliburton 

should have examined why the February foam cement slurry was unstable, and should 

have highlighted the problematic test results for BP. 

The two April foam stability tests further illuminate problems with Halliburton’s cement 

design process. Like the two February tests, the first April test indicated the slurry was 

unstable.*

 This should have prompted Halliburton to review the Macondo slurry design 

immediately, especially given how little time remained before the cement was to be 

pumped. There is no indication that Halliburton ever conducted such a review or alerted BP 

to the results. It appears that Halliburton personnel responded instead by modifying the

* Halliburton contends that its lab personnel performed this test improperly, but has not yet produced adequate evidence to support this 

assertion.
118 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

test conditions—specifically, the pre-testing conditioning time—and thereby achieving an 

arguably successful test result. 

Halliburton has to date provided nothing to suggest that its personnel selected the final 

conditioning time based on any sort of disciplined technical analysis of the Macondo well 

conditions.137 Moreover, Halliburton has not yet provided the Commission with evidence to 

support its view that cement should be “conditioned” for an extended time before stability 

testing. Given the apparent importance of this view, it should have been supported by 

careful pre-incident technical analysis and actual physical testing. At present, it appears 

only to be an unconfirmed hypothesis.

Even more serious, Halliburton documents strongly suggest that the final foam stability 

test results indicating a stable slurry may not even have been available before Halliburton 

pumped the primary cement job at Macondo.138 If true, Halliburton pumped foam cement 

into the well at Macondo at a time when all available test data showed the cement would 

be, in fact, unstable. 

Risk evaluation of Macondo cementing decisions and procedures. BP’s fundamental mistake 

was its failure—notwithstanding the inherent uncertainty of cementing and the many 

specific risk factors surrounding the cement job at Macondo—to exercise special caution 

(and, accordingly, to direct its contractors to be especially vigilant) before relying on the 

primary cement as a barrier to hydrocarbon flow. 

Those decisions and risk factors included, among other things: 

•	 Difficult drilling conditions, including serious lost returns in the cementing zone;

•	 Difficulty converting float equipment and low circulating pressure after purported 

conversion;

•	 No bottoms up circulation;

•	 Less than recommended number of centralizers;

•	 Low rate of cement flow; and

•	 Low cement volume. 

Based on evidence currently available, there is nothing to suggest that BP’s engineering 

team conducted a formal, disciplined analysis of the combined impact of these risk 

factors on the prospects for a successful cement job. There is nothing to suggest that BP 

communicated a need for elevated vigilance after the job. And there is nothing to indicate 

that Halliburton highlighted to BP or others the relative difficulty of BP’s cementing plan 

before, during, or after the job, or that it recommended any post-cementing measures to 

confirm that the primary cement had in fact isolated the high-pressure hydrocarbons in 

the pay zone. 

Negative-Pressure Test 

Even when there is no reason for concern about a cement job, a negative-pressure test is 

“very important.”139 By sending Schlumberger’s cement evaluation team back to shore, BP 

chose to rely entirely on the negative-pressure test to directly evaluate the integrity of the 

primary cement at Macondo. 
Chapter Four 119 119

It is now undisputed that the negative-pressure test at Macondo was conducted and 

interpreted improperly. For instance, BP used a spacer that had not been used by anyone 

at BP or on the rig before, that was not fully tested, and that may have clogged the kill 

line.140 The pressure data were not ambiguous. Rather, they showed repeatedly that 

formation fluids, in this case hydrocarbons, were flowing into the well. The failure to 

properly conduct and interpret the negative-pressure test was a major contributing factor 

to the blowout. 

Given the risk factors surrounding the primary cement job and other prior unusual events 

(such as difficulty converting the float valves), the BP Well Site Leaders and, to the extent 

they were aware of the issues, the Transocean crew should have been particularly sensitive 

to anomalous pressure readings and ready to accept that the primary cement job could 

have failed.141 It appears instead they started from the assumption that the well could not 

be flowing, and kept running tests and coming up with various explanations until they 

had convinced themselves their assumption was correct.142

The Commission has identified a number of potential factors that may have contributed to 

the failure to properly conduct and interpret the negative pressure test that night: 

•	 First, there was no standard procedure for running or interpreting the test in either 

MMS regulations or written industry protocols. Indeed, the regulations and standards 

did not require BP to run a negative-pressure test at all. 

•	 Second, BP and Transocean had no internal procedures for running or interpreting 

negative-pressure tests, and had not formally trained their personnel in how to do so. 

•	 Third, the BP Macondo team did not provide the Well Site Leaders or rig crew with 

specific procedures for performing the negative-pressure test at Macondo. 

•	 Fourth, BP did not have in place (or did not enforce) any policy that would have 

required personnel to call back to shore for a second opinion about confusing data. 

•	 Finally, due to poor communication, it does not appear that the men performing 

and interpreting the test had a full appreciation of the context in which they were 

performing it. Such an appreciation might have increased their willingness to believe 

the well was flowing. Context aside, however, individuals conducting and interpreting 

the negative-pressure test should always do so with an expectation that the well 

might lack integrity.

Temporary Abandonment Procedures 

Another factor that may have contributed to the blowout was BP’s temporary 

abandonment procedure. 

First, it was not necessary or advisable for BP to replace 3,300 feet of mud below the 

mud line with seawater. By replacing that much heavy drilling mud with much lighter 
120 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

seawater, BP placed more stress on the cement job at the bottom of the well than necessary. 

BP’s stated reason for doing so was its preference for setting cement plugs in seawater 

rather than mud.143 While industry experts have acknowledged that setting cement plugs 

in seawater can avoid mud contamination and that it is not unusual for operators to 

set cement plugs in seawater,144 BP has provided no evidence that it or another operator 

has ever set a surface cement plug so deep in seawater (particularly without additional 

barriers). The risks BP created by its decision to displace 3,300 feet of mud with seawater 

outweighed its concerns about cement setting better in seawater than in mud. As BP has 

admitted, cement plugs can be set in mud.145 BP also could have set one or more noncement bridge plugs (which work equally well in mud or seawater).146 No evidence has yet 

been produced that the BP team ever formally evaluated these options or the relative risks 

created by removing 3,300 feet of mud. 

It was not necessary to set the cement plug 3,300 feet below the mudline. The BP Macondo 

team chose to do so in order to set the lockdown sleeve last in the temporary abandonment 

sequence to minimize the chances of damage to the sleeve. Setting the lockdown sleeve 

would require 100,000 pounds of force. The BP Macondo team sought to generate that 

force by hanging 3,000 feet of drill pipe below the sleeve—hence the desire to set the 

cement plug 3,000 feet below the mud line. BP’s desire to set the lockdown sleeve last did 

not justify the risks its decision created. BP could have used other proven means to protect 

the lockdown sleeve if set earlier in the process. It also did not need 3,000 feet of space 

to generate 100,000 pounds of force.147 Merrick Kelley, the individual at BP in charge of 

lockdown sleeves in the Gulf of Mexico, told Commission staff that he had recommended 

setting the plug roughly 1,300 feet below the mud line (using heavier drill pipe), rather 

than 3,300 feet down. That would have significantly increased the margin of safety for the 

well.148

The most troubling aspect of BP’s temporary abandonment procedure was BP’s decision 

to displace mud from the riser before setting the surface cement plug or other barrier in 

the production casing.149 During displacement of the riser, the BOP would be open, leaving 

the cement at the bottom of the well (in the annulus and shoe track) as the only physical 

barrier to flow up the production casing between the pay zone and the rig.150 Relying so 

heavily on primary cement integrity put a significant premium on the negative-pressure 

test and well monitoring during displacement, both of which are subject to human error. 

BP’s decision under these circumstances to displace mud from the riser before setting 

another barrier unnecessarily and substantially increased the risk of a blowout. BP could 

have set the surface cement plug, or a mechanical plug, before displacing the riser.151 BP 

could have replaced the mud in the wellbore with heavier mud sufficient to overbalance the 

well.152 It is not apparent why BP chose not to do any of these things. 

Kick Detection 

The drilling crew and other individuals on the rig also missed critical signs that a kick was 

occurring. The crew could have prevented the blowout—or at least significantly reduced its 

impact—if they had reacted in a timely and appropriate manner. What is not now clear is 

precisely why the crew missed these signals. 
Chapter Four 121 12

The Sperry Sun data available to the crew from between 8:00 p.m. and 9:49 p.m. reveal 

a number of different signals that if observed, should at least have prompted the driller to 

investigate further, for instance, by conducting a visual flow check, and then shutting in 

the well if there were indications of flow. For instance, the increasing drill-pipe pressure 

after the pumps were shut down for the sheen test at 9:08 p.m. was a clear signal that 

something was happening in the well. Similarly, at roughly 9:30 p.m., the driller and 

toolpusher recognized an anomalous pressure difference between the drill pipe and kill 

line.153 Both of these signals should have prompted action—especially the latter: it was 

clearly recognized by the crew and echoed the odd pressure readings observed during 

the negative-pressure test. The crew should have done a flow check and shut in the well 

immediately upon confirmation of flow.

Why did the crew miss or misinterpret these signals? One possible reason is that they 

had done a number of things that confounded their ability to interpret signals from the 

well. For instance, after 9:08 p.m., the crew began sending fluids returning from the well 

overboard, bypassing the active pit system and the flow-out meter (at least the Sperry Sun 

flow-out meter). Only the mudlogger performed a visual flow check.154

It was neither necessary nor advisable—particularly where the cement at the bottom (in 

the annulus and shoe track) was the only barrier between the rig and pay zone—to bypass 

the active system and flow-out meter or to perform potentially confounding simultaneous 

operations during displacement of the riser. For instance, the crew could have routed the 

seawater through the active pit system before sending it into the well. 

In the future, the instrumentation and displays used for well monitoring must be 

improved. There is no apparent reason why more sophisticated, automated alarms and 

algorithms cannot be built into the display system to alert the driller and mudlogger when 

anomalies arise. These individuals sit for 12 hours at a time in front of these displays. 

In light of the potential consequences, it is no longer acceptable to rely on a system 

that requires the right person to be looking at the right data at the right time, and then 

to understand its significance in spite of simultaneous activities and other monitoring 

responsibilities. 

Diversion and Blowout Preventer Activation 

The crew should have diverted the flow overboard when mud started spewing from the 

rig floor. While that ultimately may not have prevented an explosion, diverting overboard 

would have reduced the risk of ignition of the rising gas. Considering the circumstances, 

the crew also should have activated the blind shear ram to close in the well. Diverting 

the flow overboard and/or activating the blind shear ram may not have prevented the 

explosion, but likely could have given the crew more time and perhaps limited the impact 

of the explosion. 
122 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

There are a few possible explanations for why the crew did neither:

•	 First, they may not have recognized the severity of the situation, though that seems 

unlikely given the amount of mud that spewed from the rig floor. 

•	 Second, they did not have much time to act. The explosion occurred roughly six to 

eight minutes after mud first emerged onto the rig floor. 

•	 Finally, and perhaps most significantly, the rig crew had not been trained adequately 

how to respond to such an emergency situation. In the future, well-control 

training should include simulations and drills for such emergencies—including the 

momentous decision to engage the blind shear rams or trigger the EDS. 

The Root Causes: Failures in Industry and Government

Overarching Management Failures by Industry

Whatever irreducible uncertainty may persist regarding the precise contribution to the 

blowout of each of several potentially immediate causes, no such uncertainty exists about 

the blowout’s root causes. The blowout was not the product of a series of aberrational 

decisions made by rogue industry or government officials that could not have been 

anticipated or expected to occur again. Rather, the root causes are systemic and, absent 

significant reform in both industry practices and government policies, might well recur. 

The missteps were rooted in systemic failures by industry management (extending beyond 

BP to contractors that serve many in the industry), and also by failures of government to 

provide effective regulatory oversight of offshore drilling. 

The most significant failure at Macondo—and the clear root cause of the blowout—was a 

failure of industry management. Most, if not all, of the failures at Macondo can be traced 

back to underlying failures of management and communication. Better management of 

decisionmaking processes within BP and other companies, better communication within 

and between BP and its contractors, and effective training of key engineering and rig 

personnel would have prevented the Macondo incident. BP and other operators must 

have effective systems in place for integrating the various corporate cultures, internal 

procedures, and decisionmaking protocols of the many different contractors involved in 

drilling a deepwater well.

BP’s management process did not adequately identify or address risks created by late 

changes to well design and procedures. BP did not have adequate controls in place to ensure 

that key decisions in the months leading up to the blowout were safe or sound from 

an engineering perspective. While initial well design decisions undergo a serious peerreview process155 and changes to well design are subsequently subject to a management 

of change (MOC) process,156 changes to drilling procedures in the weeks and days before 

implementation are typically not subject to any such peer-review or MOC process. At 

Macondo, such decisions appear to have been made by the BP Macondo team in ad hoc
Chapter Four 123 123

fashion without any formal risk analysis or internal expert review.157 This appears to have 

been a key causal factor of the blowout.

A few obvious examples, such as the last-minute confusion regarding whether to run six 

or 21 centralizers, have already been highlighted. Another clear example is provided by the 

temporary abandonment procedure used at Macondo. As discussed earlier, that procedure 

changed dramatically and repeatedly during the week leading up to the blowout. As of 

April 12, the plan was to set the cement plug in seawater less than 1,000 feet below the 

mud line after setting the lockdown sleeve. Two days later, Morel sent an e-mail in which 

the procedure was to set the cement plug in mud before displacing the riser with seawater. 

By April 20, the plan had morphed into the one set forth in the “Ops Note”: the crew 

would remove 3,300 feet of mud from below the mud line and set the cement plug after 

the riser had been displaced. 

There is no readily discernible reason why these temporary abandonment procedures could 

not have been more thoroughly and rigorously vetted earlier in the design process.158 It 

does not appear that the changes to the temporary abandonment procedures went through 

any sort of formal review at all. 

Halliburton and BP’s management processes did not ensure that cement was adequately 

tested. Halliburton had insufficient controls in place to ensure that laboratory testing 

was performed in a timely fashion or that test results were vetted rigorously in-house or 

with the client. In fact, it appears that Halliburton did not even have testing results in its 

possession showing the Macondo slurry was stable until after the job had been pumped. It 

is difficult to imagine a clearer failure of management or communication. 

The story of the foam stability tests may illuminate management problems within BP as 

well. By early April, BP team members had recognized the importance of timely cement 

testing.159 And by mid-April, BP’s team had identified concerns regarding the timeliness 

of Halliburton’s testing process.160 But despite their recognition that final changes to the 

cement design (made to accommodate their concerns about lost returns) might increase the 

risks of foam instability,161 BP personnel do not appear to have insisted that Halliburton 

complete its foam stability tests—let alone report the results to BP for review—before 

ordering primary cementing to begin. 

BP, Transocean, and Halliburton failed to communicate adequately. Information appears to 

have been excessively compartmentalized at Macondo as a result of poor communication. 

BP did not share important information with its contractors, or sometimes internally even 

with members of its own team. Contractors did not share important information with 

BP or each other. As a result, individuals often found themselves making critical decisions 

without a full appreciation for the context in which they were being made (or even 

without recognition that the decisions were critical). 

For example, many BP and Halliburton employees were aware of the difficulty of the 

primary cement job. But those issues were for the most part not communicated to the 

rig crew that conducted the negative-pressure test and monitored the well. It appears that 
124 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

BP did not even communicate many of those issues to its own personnel on the rig—in 

particular to Bob Kaluza, who was on his first hitch as a Well Site Leader on the Deepwater 

Horizon. Similarly, it appears at this time that the BP Well Site Leaders did not consult 

anyone on shore about the anomalous data observed during the negative-pressure test.162

Had they done so, the Macondo blowout may not have happened. 

Transocean failed to adequately communicate lessons from an earlier near-miss to its crew.

Transocean failed to adequately communicate to its crew lessons learned from an eerily 

similar near-miss on one of its rigs in the North Sea four months prior to the Macondo 

blowout. On December 23, 2009, gas entered the riser on that rig while the crew was 

displacing a well with seawater during a completion operation. As at Macondo, the rig’s 

crew had already run a negative-pressure test on the lone physical barrier between the 

pay zone and the rig, and had declared the test a success.163 The tested barrier nevertheless 

failed during displacement, resulting in an influx of hydrocarbons. Mud spewed onto 

the rig floor—but fortunately the crew was able to shut in the well before a blowout 

occurred.164 Nearly one metric ton of oil-based mud ended up in the ocean. The incident 

cost Transocean 11.2 days of additional work and more than 5 million British pounds in 

expenses.165 

Transocean subsequently created an internal PowerPoint presentation warning that 

“[t]ested barriers can fail” and that “risk perception of barrier failure was blinkered by the 

positive inflow test [negative test].”166 The presentation noted that “[f]luid displacements 

for inflow test [negative test] and well clean up operations are not adequately covered 

in our well control manual or adequately cover displacements in under balanced 

operations.”167 It concluded with a slide titled “Are we ready?” and “WHAT IF?” containing 

the bullet points: “[h]igh vigilance when reduced to one barrier underbalanced,” 

“[r]ecognise when going underbalanced—heightened vigilance,” and “[h]ighlight what the 

kick indicators are when not drilling.”168

Transocean eventually sent out an “operations advisory” to some of its fleet (in the North 

Sea) on April 14, 2010, reiterating many of the lessons learned and warnings from the 

presentation. It set out “mandatory” actions to take, acknowledging a “Lack of Well 

Control preparedness during completion phase,” requiring that “[s]tandard well control 

practices must be maintained through the life span of the well” and stating that “[w]ell 

programs must specify operations where a single mechanical barrier . . . is in effect and a 

warning must be included to raise awareness. . . .”169

The language in this “advisory” is less pointed and vivid than the language in the earlier 

PowerPoint. Moreover, according to Transocean, neither the PowerPoint nor this advisory 

ever made it to the Deepwater Horizon crew.170

Transocean has suggested that the North Sea incident and advisory were irrelevant to what 

happened in the Gulf of Mexico. The December incident in the North Sea occurred during 

the completion phase and involved failure of a different tested barrier. Those are largely 
Chapter Four 125 125

cosmetic differences. The basic facts of both incidents are the same. Had the rig crew been 

adequately informed of the prior event and trained on its lessons, events at Macondo may 

have unfolded very differently.171

Decisionmaking processes at Macondo did not adequately ensure that personnel fully 

considered the risks created by time- and money-saving decisions. Whether purposeful or 

not, many of the decisions that BP, Halliburton, and Transocean made that increased the 

risk of the Macondo blowout clearly saved those companies significant time (and money).*

There is nothing inherently wrong with choosing a less-costly or less-time-consuming 

alternative—as long as it is proven to be equally safe. The problem is that, at least in regard 

to BP’s Macondo team, there appears to have been no formal system for ensuring that 

alternative procedures were in fact equally safe. None of BP’s (or the other companies’) 

decisions in Figure 4.10 appear to have been subject to a comprehensive and systematic 

risk-analysis, peer-review, or management of change process. The evidence now available 

does not show that the BP team members (or other companies’ personnel) responsible for 

these decisions conducted any sort of formal analysis to assess the relative riskiness of 

available alternatives. 

* The Commission cannot say whether any person at BP or another company at Macondo consciously chose a riskier alternative because it 

would cost the company less money. 

FIGURE 4.10: Examples of Decisions That Increased Risk At Macondo While Potentially Saving Time

Decision

Was There A Less Risky 

Alternative Available?

Less Time Than 

Alternative? Decision-maker

Not Waiting for More 

Centralizers of Preferred Design Yes Saved Time BP on Shore

Not Waiting for Foam Stability Test 

Results and/or 

Redesigning Slurry

Yes Saved Time

Halliburton

(and Perhaps BP)

on Shore

Not Running Cement 

Evaluation Log Yes Saved Time BP on Shore

Using Spacer Made from 

Combined Lost Circulation 

Materials to Avoid Disposal Issues

Yes Saved Time BP on Shore

Displacing Mud from Riser Before 

Setting Surface Cement Plug Yes Unclear BP on Shore

Setting Surface Cement Plug 3,000 

Feet Below Mud Line in Seawater Yes Unclear BP on Shore

(Approved by MMS)

Not Installing Additional 

Physical Barriers During Temporary 

Abandonment Procedure

Yes Saved Time BP on Shore

Not Performing Further Well Integrity Diagnostics in Light of Troubling 

and Unexplained Negative Pressure 

Test Results

Yes Saved Time BP (and Perhaps 

Transocean) on Rig

Bypassing Pits and 

Conducting Other 

Simultaneous Operations 

During Displacement

Yes Saved Time

Transocean 

(and Perhaps BP) 

on Rig
126 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Corporations understandably encourage cost-saving and efficiency. But given the dangers 

of deepwater drilling, companies involved must have in place strict policies requiring 

rigorous analysis and proof that less-costly alternatives are in fact equally safe. If BP had 

any such policies in place, it does not appear that its Macondo team adhered to them. 

Unless companies create and enforce such policies, there is simply too great a risk that 

financial pressures will systematically bias decisionmaking in favor of time- and costsavings. It is also critical (as described in greater length in Chapter 8) that companies 

implement and maintain a pervasive top-down safety culture (such as the ones described 

by the ExxonMobil and Shell CEOs at the Commission’s hearing on November 9, 2010) 

that reward employees and contractors who take action when there is a safety concern 

even though such action costs the company time and money.172 

Of course, some decisions will have shorter timelines than others, and a full-blown peerreviewed risk analysis is not always practicable. But even where decisions need to be made 

in relatively short order, there must be systems in place to ensure that some sort of formal 

risk analysis takes place when procedures are changed, and that the analysis considers the 

impact of the decision in the context of all system risks. If it turns out there is insufficient 

time to perform such an analysis, only proven alternatives should be considered. 

Regulatory Failures

Government also failed to provide the oversight necessary to prevent these lapses in 

judgment and management by private industry. As discussed in Chapter 3, MMS 

regulations were inadequate to address the risks of deepwater drilling. Many critical 

aspects of drilling operations were left to industry to decide without agency review. For 

instance, there was no requirement, let alone protocol, for a negative-pressure test, the 

misreading of which was a major contributor to the Macondo blowout. Nor were there 

detailed requirements related to the testing of the cement essential for well stability.

Responsibilities for these shortfalls are best not assigned to MMS alone. The root cause can 

be better found by considering how, as described in Chapter 3, efforts to expand regulatory 

oversight, tighten safety requirements, and provide funding to equip regulators with the 

resources, personnel, and training needed to be effective were either overtly resisted or not 

supported by industry, members of Congress, and several administrations. As a result, 

neither the regulations nor the regulators were asking the tough questions or requiring the 

demonstration of preparedness that could have avoided the Macondo disaster. 

But even if MMS had the resources and political support needed to promulgate the kinds 

of regulations necessary to reduce risk, it would still have lacked personnel with the kinds 

of expertise and training needed to enforce those regulations effectively. The significance of 

inadequate training is underscored by MMS’s approval of BP’s request to set its temporary 

abandonment plug 3,300 feet below the mud line. At least in this instance, there was a 

MMS regulation that potentially applied. MMS regulations state that cement plugs for 

temporary abandonment should normally be installed “no more than 1,000 feet below 

the mud line,” but also allow the agency to approve “alternate requirements for subsea 

wells case-by-case.”173 Crucially, alternate procedures “must provide a level of safety and 

environmental protection that equals or surpasses current MMS requirements.”174
Chapter Four 127 127

BP asked for permission to set its unusually deep cement plug in an April 16 permit 

application to MMS.175 BP stated that it needed to set the plug deep in the well to minimize 

potential damage to the lockdown sleeve, and said it would increase the length of the 

cement plug to compensate for the added depth. An MMS official approved the request 

in less than 90 minutes.176 The official did so because, after speaking with BP, he was 

persuaded that 3,000 feet was needed to accommodate setting the lockdown sleeve, which 

he thought was important to do. It is not clear what, if any, steps the official took to 

determine whether BP’s proposed procedure would “provide a level of safety . . . that 

equal[ed] or surpass[ed]” a procedure in which the plug would have been set much higher 

up in the well. 

MMS’s cursory review of the temporary abandonment procedure mirrors BP’s apparent 

lack of controls governing certain key engineering decisions. Like BP, MMS focused its 

engineering review on the initial well design, and paid far less attention to key decisions 

regarding procedures during the drilling of the well. Also like BP, MMS did not assess the 

full set of risks presented by the temporary abandonment procedure. The limited scope of 

the regulations is partly to blame. But MMS did not supplement the regulations with the 

training or the processes that would have provided its permitting official with the guidance 

and knowledge to make an adequate determination of the procedure’s safety. 

* * * *

Deepwater drilling provides the nation with essential supplies of oil and gas. At the 

same time, it is an inherently risky business given the enormous pressures and geologic 

uncertainties present in the formations where oil and gas are found—thousands of feet 

below the ocean floor. Notwithstanding those inherent risks, the accident of April 20 was 

avoidable. It resulted from clear mistakes made in the first instance by BP, Halliburton, and 

Transocean, and by government officials who, relying too much on industry’s assertions 

of the safety of their operations, failed to create and apply a program of regulatory 

oversight that would have properly minimized the risks of deepwater drilling. It is now 

clear that both industry and government need to reassess and change business practices to 

minimize the risks of such drilling.

The tragic results of that accident included the immediate deaths of 11 men who 

worked on the rig, and serious injury to many others on the rig at the time of the 

explosion. During the next few hours, days, weeks, and ultimately months, BP and 

the federal government struggled with their next great challenge: containing the spill 

and coordinating a massive response effort to mitigate the threatened harm to the Gulf 

of Mexico and to the Gulf coast. They faced the largest offshore oil spill in the nation’s 

history—and the first from a subsea well located a mile beneath the ocean’s surface. 

Chapter Five 129 129

Response and Containment

No single story dominated newspaper headlines 

on April 21 and 22. America’s most-read papers 

led with articles about the progress of financial 

reform legislation; the Supreme Court’s 8–1 ruling 

in a case about video depictions of animal cruelty 

and the First Amendment; the death of civil rights 

leader Dorothy Height; and the Food and Drug 

Administration’s plans to target sodium content 

in packaged foods.1 Editors appear to have viewed 

these as slow news days. The New York Times, for 

example, ran a front-page story on April 22 about 

how travelers in Europe were coping with flight 

cancellations caused by volcanic ash, titled “Routine 

Flights Become Overland Odysseys, Minus Clean 

Socks.”2

A reader who flipped 12 more pages into the 

Times would have encountered a less lighthearted 

headline: “11 Remain Missing After Oil Rig Explodes 

Off Louisiana.”3 USA Today and the Wall Street 

Journal covered the Deepwater Horizon explosion 

on their front pages on April 22.4 The articles 

described the tragic accident and ensuing searchand-rescue operation—USA Today said it “could be 

one of the worst offshore drilling accidents in U.S. 

history”5—but did not discuss the potential for 

environmental calamity. As the Los Angeles Times

put it, “Coast Guard experts worked to assess any 

environmental cleanup that may be necessary. . . 

Chapter Five

“You’re in it 

now, up to 

your neck!”

Shrimp boats skim oil off the coast of Louisiana in mid-May. At its peak, the 

response to the spill involved over 45,000 people and thousands of watercraft, 

including private “vessels of opportunity” put to work by BP. The well was finally 

capped on July 15—87 days after the explosion. 

< Tyrone Turner/Photo courtesy of National Geographic
130 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

[b]ut the main focus was on the missing workers.”6 Other dimensions of the disaster 

would emerge in the days that followed.

The Early Response (April 20–28)

On the night of April 20, as the Deepwater Horizon burned and the rig’s survivors huddled 

on the Bankston, the response began. Coast Guard helicopters from the Marine Safety 

Unit in Morgan City, Louisiana searched for missing crew members. The first Coast Guard 

cutter to join the search was the Pompano, with others to follow. An offshore supply vessel 

found two burned life rafts. Coast Guard responders knew that approximately 700,000 

gallons of diesel fuel were on the rig and could spill into the Gulf. By 10:00 the next 

morning, planes involved in the search for survivors reported a variably-colored sheen, 

two miles long by half a mile wide, on the water.

The Captain of the Marine Safety Unit, Joseph Paradis, directed these preliminary efforts. 

He became the first Federal On-Scene Coordinator under what is known as the National 

Contingency Plan, a set of federal regulations prescribing the government’s response to 

spills and threatened spills of oil and other hazardous materials.*

 Under the Plan, when a 

spill occurs in coastal waters, the Coast Guard has the authority to respond.7

As the search and rescue continued on April 21, the oily sheen grew, more Coast Guard 

personnel and resources became involved, and Rear Admiral Mary Landry took over as 

Federal On-Scene Coordinator. The commander of Coast Guard District 8 (which includes, 

among other regions, the Gulf coast from Texas to the Florida panhandle), she would 

remain Federal On-Scene Coordinator until June 1. While the firefighting efforts continued, 

she told reporters, “We are only seeing minor sheening on the water. . . . We do not see a 

major spill emanating from this incident.”8 At this point, Admiral Landry’s concern was 

the fuel oil that could spill from the rig, though she cautioned, “We don’t know what’s 

going on subsurface.”9

As Coast Guard vessels continued the search and rescue operation, private offshore supply 

vessels sprayed water on the fire. Transocean hired Smit Salvage Americas, a salvage 

company, to try to save the rig. There was confusion about whether Transocean, the Coast 

Guard, the salvage company, or anyone at all was directing the firefighting operations.†

Captain James Hanzalik, Chief of Incident Response in District 8, would later say that the 

Coast Guard, which was focused on the search and rescue and then on the spreading oil, 

“monitored what was going on, but [was] not directing any firefighting resources.”10 By 

the morning of April 21, the rig was listing. At 11:53 that evening, it shifted and leaned 

even more.

At 10:22 a.m. on April 22, the rig sank, taking with it the diesel fuel still on board. By 

that time, the Coast Guard had established an Incident Command Post in a BP facility in 

Houma, Louisiana. BP had formed a command post in its corporate headquarters in 

* Created in 1968, the National Contingency Plan has been amended and expanded in the years since. The Oil Pollution Act of 1990 substantially expanded the Plan in 

response to the Exxon Valdez spill. † The Coast Guard/Bureau of Ocean Energy Management, Regulation, and Enforcement Deepwater Horizon Joint Investigation Team, which plans to issue a report in 

March 2011, is examining the firefighting efforts.
Chapter Five 131 13

Houston, Texas shortly after the explosion, and the Coast Guard established an Incident 

Command Post there as well.

These Incident Command Posts, along with one in Mobile, Alabama, and others established 

later, would become the centers of response operations, with their activities directed by the 

Federal On-Scene Coordinator as part of the government’s Unified Command. The latter is 

a command structure, created and implemented by the National Contingency Plan, which 

integrates the “responsible party” (here, BP) with federal and state officials “to achieve an 

effective and efficient response.”11 The Coast Guard established a Unified Area Command—

headquarters for the regional spill response—on April 23 in Robert, Louisiana, later moving 

it to New Orleans. It eventually included representatives from the federal government, 

Louisiana, Alabama, Mississippi, Florida, and BP. 

Other federal agencies—including the National Oceanic and Atmospheric Administration 

(NOAA) and Minerals Management Service (MMS)*

—immediately sent emergency 

responders to the Unified Area Command and Incident Command Posts. A host of senior 

officials, including Secretary of the Interior Ken Salazar and Secretary of Homeland 

Security Janet Napolitano, briefed the President on their departments’ efforts on the 

afternoon of April 22.12 Members of the National Response Team, drawn from the 16 

federal agencies responsible for coordinating emergency preparedness and response to 

oil- and hazardous-substance-pollution incidents,13 began conducting daily telephone 

meetings.

Even before the rig sank, BP and Transocean directed their attention to the 53-foot-tall 

blowout preventer (BOP) stack sitting atop the Macondo well. At about 6:00 p.m. on April 

21, BP and Transocean began using remotely operated vehicles to try to close the BOP and 

stop the flow of oil and gas fueling the fire.

These early operations primarily attempted to activate the BOP’s blind shear ram and 

seal off the well. During the attempts, MMS officials were embedded, as observers, in 

the operations centers at Transocean and BP headquarters in Houston. Because of the 

emergency, on-scene personnel from BP, Transocean, and Cameron (the company that 

manufactured the BOP) made decisions without the need for government approvals. 

Beginning on April 21 and continuing throughout the effort to control the well, Secretary 

Salazar received daily updates through conference calls with BP’s technical teams.

The initial news was encouraging. On April 23, Admiral Landry told the press that, 

according to surveillance by remotely operated vehicles, the BOP, although “[i]t is not 

a guarantee,” appeared to have done its job, sealing off the flow of oil and preventing 

any leak.14 The good news did not last. The Coast Guard suspended its search for the 11 

missing workers later that day. And, when Admiral Landry spoke, remotely operated 

vehicles had not yet surveyed the entire length of the broken riser pipe—previously 

* On June 18, 2010, Secretary of the Interior Ken Salazar ordered that the Minerals Management Service be officially renamed the Bureau of Ocean Energy Management, 

Regulation, and Enforcement. For consistency, throughout this chapter, we refer to the agency as the Minerals Management Service (MMS), its name at the time of the 

April 20 blowout. 
132 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

connecting the well to the now-sunk Deepwater 

Horizon—that still jutted out of the top of the BOP. 

By mid-afternoon on April 23, the vehicles had 

discovered that oil was leaking from the end of the 

riser, where it had broken off from the Deepwater 

Horizon when the rig sank. By the next morning, 

the vehicles had also discovered a second leak from 

a kink in the riser, located above the BOP. On April 

24, Unified Command announced that the riser was 

leaking oil at a rate of 1,000 barrels per day.15 This 

number appears to have come from BP, although 

how it was calculated remains unclear.16

As BP realized that the early efforts to stop the flow 

of oil had failed, it considered ways to control the 

well other than by triggering the BOP. A primary 

option was to drill a relief well to intersect the 

Macondo well at its source and enable a drilling rig 

to pump in cement to stop the flow of oil. While it 

could take more than three months to drill, a relief 

well was the only source-control option mentioned by name in BP’s Initial Exploration 

Plan.17 Industry and government experts characterized a relief well as the only likely and 

accepted solution to a subsea blowout.18 BP had begun looking for available drilling rigs on 

the morning of April 21; it secured two, and began drilling a primary relief well on May 2 

and a back-up well insisted upon by Secretary Salazar on May 17.19

Responders, meanwhile, shifted their focus to the release of large amounts of oil. Although 

the National Contingency Plan requires the Coast Guard to supervise an oil-spill response 

in coastal waters, it does not envision that the Coast Guard will provide all, or even most, 

of the response equipment. That role is filled by private oil-spill removal organizations, 

which contract with the oil companies that are required to demonstrate response 

capacity. BP’s main oil-spill removal organization in the Gulf is the Marine Spill Response 

Corporation, a nonprofit created by industry after the Exxon Valdez disaster to respond to 

oil spills. The Marine Spill Response Corporation dispatched four skimmers within hours 

of the explosion.20 BP’s oil-spill response plan for the Gulf of Mexico claimed that response 

vessels provided by the Marine Spill Response Corporation and other private oil-spill 

removal organizations could recover nearly 500,000 barrels of oil per day.21

Despite these claims, the oil-spill removal organizations were quickly outmatched. While 

production technology had made great advances since Exxon Valdez (see Chapter 2), spillresponse technology had not. The Oil Pollution Act of 1990, by requiring double hulls 

in oil tankers, had effectively reduced tanker spills.22 But it did not provide incentives 

for industry or guaranteed funding for federal agencies to conduct research on oil-spill 

response. Though incremental improvements in skimming and boom had been realized in 

Oil spews unchecked from the Deepwater Horizon’s 

severed riser in this video frame taken May 26. When 

the rig sank, the riser broke off, settling on the sea floor. 

© BP p.l.c
Chapter Five 133 133

the intervening 21 years, the technologies used in response to the Deepwater Horizon and 

Exxon Valdez oil spills were largely the same.23 

If BP’s response capacity was underwhelming, some aspects of its response plan were 

embarrassing. In the plan, BP had named Peter Lutz as a wildlife expert on whom it 

would rely; he had died several years before BP submitted its plan. BP listed seals and 

walruses as two species of concern in case of an oil spill in the Gulf; these species never 

see Gulf waters. And a link in the plan that purported to go to the Marine Spill Response 

Corporation website actually led to a Japanese entertainment site.24 (Congressional 

investigation revealed that the response plans submitted to MMS by ExxonMobil, Chevron, 

ConocoPhillips, and Shell were almost identical to BP’s—they too suggested impressive but 

unrealistic response capacity and three included the embarrassing reference to walruses.25

See Chapter 3 for more discussion of these plans.) 

By April 25, responders had started to realize that the estimated spill volume of 1,000 

barrels per day might be inaccurate. Dispersants applied to break up the surface slick were 

not having the anticipated effect. Either the dispersants were inexplicably not working, or 

the amount of oil was greater than previously suspected. Between April 26 and April 28, 

BP personnel within Unified Command reportedly said that they thought 1,000 to 6,000 

barrels were leaking each day.26

To alert government leadership that the spill could be larger than 1,000 barrels per day, a 

NOAA scientist created a one-page report on April 26 estimating the flow rate at roughly 

5,000 barrels per day. He based this estimate on other responders’ visual observations of 

the speed with which oil was leaking from the end of the riser, as well as the size and color 

of the oil slick on the Gulf’s surface.27 Both methodologies, the scientist recognized, were 

highly imprecise: he relied on rough guesses, for example, of the velocity of the oil as it 

left the riser and the thickness of the surface slick. He told a NOAA colleague in Unified 

Command that the flow could be 5,000 to 10,000 barrels per day.28 At a press conference 

on April 28, Admiral Landry stated, “NOAA experts believe the output could be as much as

5,000 barrels” (emphasis added).29

Although it represented a five-fold increase over the then-current figure, 5,000 barrels 

per day was a back-of-the-envelope estimate, and Unified Command did not explain 

how NOAA calculated it. Nevertheless, for the next four weeks, it remained the official 

government estimate of the spill size.

The Response Ramps Up (April 29–May 1)

At the peak of the response, more than 45,000 people participated.30 In addition to 

deploying active-duty members to the Gulf, the Coast Guard called up reservists. Some 

1,100 Louisiana National Guard troops served under the direction of Unified Command.31

The Environmental Protection Agency (EPA), NOAA, and other federal agencies shifted 

hundreds of responders to the region.

Consistent with the Unified Command framework, BP played a major role from the outset. 

Most Coast Guard responders had a BP counterpart. For instance, Doug Suttles, BP’s Chief 
134 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Operating Officer of Exploration and Production, was the counterpart to the Federal OnScene Coordinator. BP employees were scattered through the command structure, in roles 

ranging from waste management to environmental assessment. Sometimes, a BP employee 

supervised Coast Guard or other federal responders. 

The preference under the National Contingency Plan is for the Federal On-Scene 

Coordinator to supervise response activities while the responsible party conducts—and 

funds—them. When a spill “results in a substantial threat to public health or welfare of 

the United States,” the Plan requires the Federal On-Scene Coordinator to direct all response 

efforts.32 The Coast Guard also has the option to “federalize” the spill—conducting and 

funding all aspects of the response through the Oil Spill Liability Trust Fund, and later 

seeking reimbursement from the responsible party.33 But in most spills, especially when 

In a joint press briefing, BP Chief Operating Officer of Exploration and Production Doug Suttles takes the podium alongside Federal OnScene Coordinator and Coast Guard Rear Admiral Mary Landry. The Coast Guard considered BP a co-combatant in the effort to battle the oil. 

U.S. Coast Guard photo/Petty Officer 3rd Class Cory J. Mendenhall
Chapter Five 135 135

the responsible party has deep pockets and is willing to carry out response activities, 

federalizing is not preferred. Coast Guard leaders, shaped by their experience implementing 

the National Contingency Plan through a unified command system, viewed the responsible 

party as a co-combatant in the fight against the oil. From their perspective, BP took its role 

as responsible party seriously and had an open checkbook for response costs.*

 That did not 

mean BP was happy to pay. Tony Hayward, the Chief Executive Officer of BP, reportedly 

asked board members, “What the hell did we do to deserve this?”34

Though willing to fund and carry out the response, BP had no available, tested technique 

to stop a deepwater blowout other than the lengthy process of drilling a relief well. Forty 

years earlier, the government had recognized the need for subsea containment technology. 

In 1969, following the Santa Barbara Channel spill, the Nixon administration had issued 

a report recommending, in part, that “[u]nderwater methods to collect oil from subsea 

leaks should be developed.”35 For deepwater wells, however, such development had never 

occurred. Within a week of the explosion, BP embarked on what would become a massive 

effort to generate containment options, either by adapting shallow-water technology to 

the deepwater environment, or by designing entirely new devices. Different teams at BP’s 

Houston headquarters focused on different ways either to stop the flow of oil or to collect 

it at the source. Each team had what amounted to a blank check. As one contractor put it, 

“Whatever you needed, you got it. If you needed something from a machine shop and you 

couldn’t jump in line, you bought the machine shop.”36

While the Coast Guard oversaw the response at the surface, MMS primarily oversaw 

source-control operations. BP would draft detailed procedures describing an operation 

it wished to perform around the wellhead. MMS and Coast Guard officials in Houston 

participated in the drafting process to help identify and mitigate hazards, including risks 

to worker safety. At Unified Area Command, Lars Herbst, MMS Gulf of Mexico Regional 

Director, or his deputy, Mike Saucier, would review and approve the procedures, before 

the Federal On-Scene Coordinator gave the final go-ahead. This hierarchy of approvals 

remained in place throughout the containment effort.

MMS was the sole government agency charged with understanding deepwater wells 

and related technology, such as BOPs. But its supervision of the containment effort was 

limited, in line with its role in overseeing deepwater drilling more generally. Its staff did 

not attempt to dictate whether BP should perform an operation, determine whether it had 

a significant likelihood of success, or suggest consideration of other options. This limited 

role stemmed in part from a lack of resources. At most, MMS had four to five employees 

in Houston trying to oversee BP’s efforts. One employee described his experience as akin to 

standing in a hurricane.

Interviews of MMS staff members involved in the containment effort also suggest that 

the agency did not view itself as capable of, or responsible for, providing more substantive 

oversight. One MMS employee asserted that BP, and industry more broadly, possessed 10 

* The day the rig exploded, the emergency reserve available to the Federal On-Scene Coordinator in the Oil Spill Liability Trust Fund and not obligated to other ongoing 

response actions amounted to $18,600,000. In contrast, by November 11, 2010, BP had paid $580,977,461 to the federal government for response costs. BP’s total expenditures on the response also included payments to states and to contractors it hired directly. Paul Guinee, e-mail to Commission staff, November 16, 2010; BP, Claims 

and Government Payments Gulf of Mexico Oil Spill Public Report (November 11, 2010).
136 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

times the expertise that MMS could bring to bear on the complex problem of deepwater 

spill containment. Another pointed out that MMS had trouble attracting the most talented 

personnel, who are more likely to work in industry where salaries are higher. A third MMS 

employee stated that he could count on one hand the people from the agency whom he 

would trust to make key decisions in an effort of this magnitude. Perhaps most revealingly, 

two different MMS employees separately recalled being asked—one by Secretary Salazar, 

and the other by Assistant Secretary Tom Strickland—what they would do if the U.S. 

government took over the containment effort. Both said they would hire BP or another 

major oil company.

Though the Coast Guard and MMS believed they had to work closely with BP, others in 

government did not share this view of the relationship with the responsible party. At an 

April 29 press conference with several senior administration officials, Coast Guard Rear 

Admiral Sally Brice O’Hara referred to BP as “our partner,” prompting Secretary Napolitano 

to emphasize, “They are not our partner.”37 Secretary Salazar later said on CNN that the 

government would keep its “boot on the neck” of BP.38 

While struggling to explain its oversight role to the public, the federal government 

increased its commitment to the spill response. On April 29, a week after the rig sank and 

a day after the flow-rate estimate rose to 5,000 barrels per day, the Coast Guard designated 

the disaster a “Spill of National Significance”39—the first time the government had used 

that designation. A Spill of National Significance is one “that due to its severity, size, 

location, actual or potential impact on the public health and welfare or the environment, 

or the necessary response effort, is so complex that it requires extraordinary coordination 

of federal, state, local, and responsible party resources to contain and clean up the 

discharge.”40 The designation permitted a National Incident Commander to “assume the 

role of the [Federal On-Scene Coordinator] in communicating with affected parties and the 

public, and coordinating federal, state, local, and international resources at the national 

level.”41 Other than the quoted sentence, the National Contingency Plan is silent on the role 

of the National Incident Commander, who can fill the position, and what tasks he or she 

will handle. As a result, there is no clear line between the National Incident Commander’s 

responsibilities and those of the Federal On-Scene Coordinator. During the Deepwater 

Horizon spill response, the National Incident Commander coordinated interagency efforts 

on the wide variety of issues responders faced, and dealt with high-level political and media 

inquiries, while the Federal On-Scene Coordinator generally retained oversight of day-today operations. More than anyone else, the National Incident Commander became the face 

of the federal response. When President Obama visited the Gulf on May 2, a fisherman 

asked who would pay his bills while he was out of work; the President responded that the 

National Incident Commander would take care of it.42

On May 1, Secretary Napolitano announced that Admiral Thad Allen, the outgoing 

Commandant of the Coast Guard and then its only four-star Admiral, would serve as 

National Incident Commander.43 Admiral Allen was well known in the Gulf. He had 

previously overseen the ocean rescue and return to Cuba of Elian Gonzalez in 1999; the 

Coast Guard’s work securing harbors along the Eastern Seaboard after the attacks of 

September 11, 2001; and the federal response to Hurricanes Katrina and Rita, after the 
Chapter Five 137 137

Bush Administration asked him to replace the stumbling director of the Federal Emergency 

Management Agency, Michael Brown, as the lead federal official.44 His leadership during 

Katrina was widely considered a success. A Baton Rouge Advocate editorial published near 

the end of his time in the Gulf highlighted his local popularity and thanked him for his 

service.45 Less celebrated in the media, but no less important for the task facing him as 

National Incident Commander, was Admiral Allen’s role overseeing a 2002 simulation that 

tested the readiness of the Coast Guard and other agencies to respond to a Spill of National 

Significance off the coast of Louisiana.46 As Commandant, Admiral Allen was already 

participating in the response, and he put off his scheduled retirement when he became 

National Incident Commander. 

As the National Incident Command took shape in early May, BP’s efforts to stop the 

flow of oil continued to focus on actuating the BOP, which BP still believed was the 

best chance of quickly shutting in the well. These efforts were plagued by engineering 

and organizational problems. For instance, it took nearly 10 days for a Transocean 

representative to realize that the stack’s plumbing differed from the diagrams on which 

BP and Transocean were relying, and to inform the engineers attempting to trigger one of 

the BOP’s rams through a hydraulic panel that they had been misdirecting their efforts.47

(Without properly recording the change, Transocean had reconfigured the BOP; the panel 

Surrounded by orange containment boom, National Incident Commander Admiral Thad Allen speaks to the press in Venice, Louisiana. The 

outgoing Coast Guard Commandant postponed his retirement to assume the post, drawing on his experience leading the federal response 

to Hurricane Katrina and overseeing oil-spill readiness exercises in the Gulf. 

Steven Johnson/Miami Herald/MCT via Getty Images
138 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

that was supposed to control that ram actually operated a different, “test” ram, which 

could not stop the flow of oil and gas.48 BP Vice President Harry Thierens, who was BP’s 

lead on BOP interventions, stated afterward that he was “quite frankly astonished that this 

could have happened.”49) While this and other problems delayed BP’s efforts, the flow of 

oil and sand continued to wear down the BOP’s parts, making closure more difficult.50

BP stopped trying to close the BOP on May 5.51 By May 7, it had concluded that 

“[t]he possibility of closing the BOP has now been essentially exhausted.”52 In mid-May, 

at the suggestion of Secretary of Energy Steven Chu, BP undertook gamma-ray imaging 

of the BOP, which lacked instrumentation to show the position of its rams.53 The imaging 

indicated that, although the blind shear ram had closed at least partially, oil continued to 

flow past it.

The “Social and Political Nullification” of the National Contingency Plan 

(April 29–May 1)

The hurricane-stricken Gulf states are all too familiar with emergency response; all are 

among the top dozen states in number of declared major disasters.54 State and local 

officials in the Gulf are accustomed to setting up emergency-response structures pursuant 

to the Stafford Act, under which the federal government provides funding and assists state 

and local governments during a major disaster.55 In contrast, the National Contingency 

Plan, which governs oil spills, gives the Federal On-Scene Coordinator the power to direct 

all response actions.56 Thus, while the Stafford Act envisions a state-directed (though in 

part federally funded) response, the National Contingency Plan puts federal officials in 

charge.

State and local officials chafed under federal control of the response. Louisiana Governor 

Bobby Jindal’s advisors reportedly spent days trying to determine whether the Stafford Act 

or the National Contingency Plan applied.57 On April 29, Governor Jindal declared a state 

of emergency in Louisiana, authorizing the director of the Governor’s Office of Homeland 

Security and Emergency Preparedness to undertake any legal activities deemed necessary to 

respond and to begin coordinating state response efforts.58 These efforts took place outside 

of the Unified Command framework. The Governors of Mississippi, Alabama, and Florida 

followed suit, declaring states of emergency the next day.59

At the outset of the spill, the pre-designated State On-Scene Coordinators for Louisiana, 

Alabama, and Mississippi participated in Unified Command.60 These individuals were 

career oil-spill responders: familiar with the National Contingency Plan, experienced 

in responding to spills, and accustomed to working with the Coast Guard. Some had 

participated in the 2002 spill exercise run by Admiral Allen. They shared the Coast Guard’s 

view that the responsible party is an important ally, not an adversary, in responding to a 

spill. 

During this spill, however, the Governors and other state political officials participated in 

the response in unprecedented ways, taking decisions out of the hands of career oil-spill 

responders. These high-level state officials were much less familiar with spill-response 
Chapter Five 139 139

planning. In addition to the National Contingency Plan, each Coast Guard sector is an 

“Area” with an Area Contingency Plan created by relevant state and federal agencies. When 

confronted with a contingency plan setting out how the federal and state governments 

were supposed to run an oil-spill response, one high-level state official told a Coast Guard 

responder that he never signed it. According to the Coast Guard officer, the state official 

was not questioning whether his signature appeared on the document, but asserting that 

he had not substantively reviewed the plan.61 State and local officials largely rejected the 

pre-spill plans and began to create their own response structures. 

Because the majority of the oil would come ashore in Louisiana, these issues of control 

mattered most there. Louisiana declined to empower the officials that it sent to work 

with federal responders within Unified Command, instead requiring most decisions to go 

through the Governor’s office. For example, the Louisiana representative at Unified Area 

Command could not approve the daily agenda of response activities.62 Responders worked 

around this problem, but it complicated operations.

Local officials were even less familiar with oil-spill planning, though they had robust 

experience with other emergencies. Under Louisiana law, Parish Presidents exercise 

substantial authority—mirroring that of the Governor—during hurricanes and other 

natural disasters.63 The parishes wanted to assert that same control during the spill, and 

many used money distributed by BP to purchase their own equipment and establish their 

own operating centers outside of Unified Command. Eventually, the Coast Guard assigned 

a liaison officer to each Parish President, who attempted to improve relationships with the 

parishes by providing information and reporting back to Unified Command on local needs. 

Local resentment became a media theme and then a self-fulfilling prophesy. Even those 

who privately thought the federal government was doing the best it could under the 

circumstances did not say so publicly.64 Coast Guard responders watched Governor 

Jindal—and the TV cameras following him—return to what appeared to be the same spot 

of oiled marsh day after day to complain about the inadequacy of the federal response, 

even though only a small amount of marsh was then oiled. When the Coast Guard sought 

to clean up that piece of affected marsh, Governor Jindal refused to confirm its location.65

Journalists encouraged state and local officials and residents to display their anger at the 

federal response, and offered coverage when they did. Anderson Cooper reportedly asked a 

Parish President to bring an angry, unemployed offshore oil worker on his show. When the 

Parish President could not promise the worker would be “angry,” both were disinvited.66

As the media coverage grew more frenzied, the pressure increased on federal, state, 

and local officials to take action and to avoid being seen as in league with BP. What 

Admiral Allen would later call “the social and political nullification” of the National 

Contingency Plan, which envisions “unity of effort” between the federal government, state 

governments, and the responsible party, was well underway.67

Spill Impacts and Efforts To Help 

Effects on the Gulf economy, environment, and way of life increased as the spill dragged 

on and oil crept closer to shorelines. Concerns about fisheries took hold immediately. The 
140 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Gulf of Mexico is home to crab, shrimp, oyster, and finfish fisheries, all of which were 

affected by the oil. The Louisiana Department of Wildlife and Fisheries and the Department 

of Health and Hospitals began closing fisheries and oyster grounds in state waters—

three miles or less from shore—on April 30. State fishery closures continued piece by 

piece, beginning on June 2 in Alabama, June 4 in Mississippi, and June 14 in Florida.68

NOAA’s Office of Response and Restoration began conducting flyovers and modeling the 

movement of the oil beginning April 23.69 Responders used these daily trajectory forecasts 

to anticipate where oil would be over the next 24- and 48-hour periods. Based on the 

forecasts, as well as sampling in or near affected areas, the federal fishery closures began 

on May 2. Through an emergency rule, NOAA’s National Marine Fisheries Service first 

closed an area spanning approximately 6,817 square miles, or 3 percent of the Gulf federal 

fishing zone.70 On May 7, NOAA increased the closed area to 4.5 percent of that zone.71 A 

week later, it extended the closures indefinitely.72 NOAA continued to close additional areas, 

and on June 2—at the peak of the closures—it prohibited all fishing in nearly 37 percent of 

the Gulf zone.73

Although unable to fish, many fishermen were not content to lay idle. As contractors 

and subcontractors set up camp in towns across the Gulf to carry out response activities, 

residents viewed them with suspicion. People in Lafourche Parish, for example, worried 

about the out-of-state oil-spill-response contractors who took over their shores bringing 

crime and taking away spill-related job opportunities.74 Parish Presidents pushed BP 

and Unified Command to give clean-up jobs to residents and, in the newly out-of-work 

fishermen, saw a fleet of experienced captains who were more familiar with the intricate 

shoreline than any out-of-state oil-spill responders. 

The Vessels of Opportunity program was BP’s answer, and a way for BP to provide some 

income to affected residents outside of the formal claims process. Through the program, 

BP employed private vessels to conduct response efforts such as skimming, booming, and 

transporting supplies. Vessels of opportunity made between $1,200 and $3,000 per day, 

depending on the size of the boat. Individual crew members made $200 for an eight-hour 

day.75 But the program had delays and problems. BP and the Coast Guard were slow to 

develop eligibility requirements (such as an operable VHF-FM radio) for boats.76 Initially, 

there was not enough work. Later, residents and Parish Presidents complained that BP was 

not sufficiently targeting out-of-work fishermen at whom the program was ostensibly 

directed, and that wealthy or non-local boat owners were taking advantage of poor 

oversight to gain spots in the program. Eventually, BP established a verification process 

that prioritized boats registered with the state before March 2010 and that accepted only 

one boat per owner.77 The group that may have lost out the most on the program was 

the large population of Vietnamese-American fishermen. Many had arrived in the region 

as refugees and struggled with the lack of Vietnamese-language training.78 (Chapter 6 

discusses the impacts of the spill on minority fishing communities.)

Angry that BP was deploying non-local boats in his parish waters, Craig Taffaro, President 

of St. Bernard Parish, started his own program using the commercial fishing fleet based 

there. He submitted invoices to BP, which it paid. The State of Louisiana also began its 

own program, as did Plaquemines and Jefferson Parishes.79 Unified Command struggled 
Chapter Five 141 14

to coordinate this floating militia of independent vessels and to give them useful response 

tasks. Having hundreds of vessels look for oil did not contribute significantly to the 

response, because aircraft were more effective at spotting oil.80 Placing boom requires 

skill and training, and responders differed in their judgments of how much the vessels 

contributed. 

In addition to overseeing the Vessels of Opportunity program, Unified Command needed to 

ensure that all workers, whether on boats or on shore, were adequately trained and taking 

safety precautions. The Occupational Safety and Health Administration (OSHA) began 

working with Unified Command at the end of April; under the National Contingency Plan, 

all response actions must comply with OSHA’s training and safety requirements.81 OSHA 

established rules regarding protective equipment and, because the response relied in part on 

untrained workers, a shortened training course.82 Residents were eager to take on cleanup jobs, but some worried that, notwithstanding OSHA’s involvement, response-related 

work would affect their health.83 (Chapter 6 discusses the impacts of response activities on 

health.)

Health issues for non-workers were thornier. The Centers for Disease Control and 

Prevention represents the Department of Health and Human Services on the National 

Response Team and had participated in recent spill training exercises. The Centers for 

Disease Control, however, had not foreseen that an oil spill could affect the health of 

the broader population and had not fully considered the role health agencies might play 

in a spill response.84 Others in the Department, including the Assistant Secretary for 

Preparedness and Response, had not either.85 Consequently, the Department had to consider 

during the disaster how it would fund spill-related activities, because BP would have to 

pay only for those deemed response measures by Unified Command. The Department was 

concerned that neither the Oil Spill Liability Trust Fund nor BP would reimburse it for 

activities such as long-term health surveillance, and negotiations over what costs qualified 

for reimbursement took time.86 At the request of Unified Command, Health and Human 

Services eventually, in June, sent a Senior Health Policy Advisor to support the National 

Incident Commander on public health issues.87

The spill affected wildlife health as well. On April 30, the Times-Picayune reported the 

recovery of the first oiled bird.88 From then on, crude-covered animals were a fixture 

in the media coverage and public perceptions of the disaster. The U.S. Fish and Wildlife 

Service, NOAA’s Fisheries Service, state wildlife agencies, and academic organizations 

oversaw animal response and rehabilitation efforts.89 Wildlife responders took recovered 

animals to one of several treatment centers, washing, monitoring, and then releasing 

them.90 According to the Audubon Society, more than 12,000 volunteers signed up to help 

with these efforts during a single week in early May.91 Not all offers of assistance were 

accepted. Some groups that could have provided skilled wildlife responders, such as the 

National Wildlife Federation, felt discouraged from helping; in their view, there was no 

effective process for integrating skilled volunteers into the response structure.92 Would-be 

volunteers worried that animal mortality was greater than it would have been had more 

rescuers been out looking for oiled animals.93 (Chapter 6 discusses impacts on wildlife in 

detail.)
142 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Along with volunteering for wildlife rescue, members of the general public submitted to 

BP and the Coast Guard numerous ideas for how to clean up the oil or plug the well. For 

instance, movie star Kevin Costner argued for the use of his oil-water separator, and BP 

eventually purchased 32 units.94 Citizens without Costner’s resources had more trouble 

getting their ideas reviewed. On June 4, the Coast Guard established the Interagency 

Alternative Technology Assessment Program to receive, acknowledge, and evaluate ideas.95

The program received about 4,000 submissions.96 Most of the proposals were not viable 

or required too much time for development into operational response tools.*

 As ideas came 

in, the Coast Guard screened them and sent the most promising to the Federal On-Scene 

Coordinator, who ended up testing about a dozen during the course of the spill. None was 

implemented on a large scale, but the Coast Guard plans to use some of the proposals in its 

spill-response research.97

Foreign companies and countries also offered assistance in the form of response 

equipment and vessels. The Coast Guard and National Incident Command accepted 

some of these offers and rejected others.98 News reports and politicians alleged that the 

federal government turned away foreign offers of assistance because of the Jones Act, a 

law preventing foreign vessels from participating in trade between U.S. ports.99 While 

decisionmakers did decline to purchase some foreign equipment for operational reasons—

* Although intellectual property concerns prohibit the Coast Guard from disclosing the proposals actually submitted, news outlets reported that individuals suggested 

ideas like dumping popcorn from airplanes; soaking up the oil with packing peanuts, sawdust, kitty litter, and air conditioning filters; and using liquid nitrogen to freeze 

the oil. Julie Schmit, “After BP Oil Spill, Thousands of Ideas Poured in for Cleanup,” USA Today, November 15, 2010; John W. Schoen, “BP’s Suggestion Box Is Spilling 

Over,” MSNBC, May 14, 2010.

Free once more, a pair of pelicans test their wings in Aransas National Wildlife Refuge after being de-oiled and nursed back to health. 

Taking part in the release are veterinarian Sharon Taylor and Refuge manager Dan Alonso. Over a thousand birds affected by the spill were 

rehabilitated; thousands of others were not so fortunate. 

U.S. Coast Guard photo/Petty Officer 3rd Class Robert Brazzell
Chapter Five 143 143

for example, Dutch vessels that would have taken weeks to outfit and sail to the region, 

and a Taiwanese super-skimmer that was expensive and highly inefficient in the Gulf—

they did not reject foreign ships because of Jones Act restrictions.100 These restrictions did 

not even come into play for the vast majority of vessels operating at the wellhead, because 

the Act does not block foreign vessels from loading and then unloading oil more than three 

miles off the coast.101 When the Act did apply, the National Incident Commander appears 

to have granted waivers and exemptions when requested.102

In the end, the response technology that created the most controversy was not a 

mechanical tool like a skimmer or oil-water separator, but a chemical one.

Initial Dispersant Decisions (April 30–May 10)

Even before they were certain that oil was spilling into the Gulf, responders had readied 

planes full of dispersants to use in a potential response. Dispersants include surfactants 

that break down oil into smaller droplets, which are more likely to dissolve into the 

water column.103 On April 24, once Unified Command knew a leak existed and coastal 

impacts were possible, Admiral Landry told reporters: “We have one-third of the world’s 

dispersant resources on standby. . . . Our goal is to fight this oil spill as far away from the 

coastline as possible.”104 Faced with what one Coast Guard captain called a “tradeoff of bad 

choices” between spraying chemicals on the water or watching more oil reach the shore,105

responders would wield dispersants in the battle against oil for the next 12 weeks, using 

novel methods and unprecedented volumes. 

Dispersants do not remove oil from the water altogether. Energy from wind and waves 

naturally disperses oil, and dispersants accelerate this process by allowing oil to mix 

with water. Dispersed oil is diluted as it mixes vertically and horizontally in the water 

column.106 Using dispersants has several potential benefits. First, less oil will reach 

shorelines and fragile environments such as marshes.107 Second, animals and birds that 

float on or wade through the water surface may encounter less oil.108 Third, dispersants 

may accelerate the rate at which oil biodegrades.109 Finally, responders to an oil spill can 

use dispersants when bad weather prevents skimming or burning. But dispersants also 

pose potential threats. Less oil on the surface means more in the water column, spread 

over a wider area, potentially increasing exposure for marine life. Chemically dispersed 

oil can be toxic in both the short and long term. Moreover, some studies have found that 

dispersants do not increase biodegradation rates—or may even inhibit biodegradation.110

At the direction of the Federal On-Scene Coordinator, responders first sprayed dispersants 

on the surface oil slick on April 22.111 Long before the spill, interagency “Regional Response 

Teams” had evaluated and preauthorized the use of specific dispersants in the Gulf of 

Mexico, with limits as to geographic areas where the chemicals could be applied, but not 

on overall volume or duration of use.112 The teams included representatives from relevant 

state governments and from federal agencies with authority over oil spills, including 

the Coast Guard, EPA, the Department of the Interior, and NOAA. Preauthorization, 

requiring the concurrence of the Team, allows the Federal On-Scene Coordinator to employ 

dispersants immediately following a spill.113 Timing matters, because the chemicals 
144 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

are most effective when oil is fresh, before it has weathered and emulsified.114 Without 

preauthorization, responders can still use dispersants during a spill if EPA and state 

authorities approve.115 With the permission of the Federal On-Scene Coordinator, BP and 

its contractors applied 14,654 gallons of the dispersant Corexit on the surface during the 

week of April 20 to 26.116

Under the terms of the preauthorization, Corexit was a permissible dispersant because EPA 

listed it on the National Contingency Plan Product Schedule. EPA obtains toxicity data from 

the manufacturer before placing a dispersant on that schedule.117 Some toxicologists have 

questioned the reliability and comparability of the testing by manufacturers.118 Moreover, 

the required testing is limited to acute (short-term) toxicity studies on one fish species and 

one shrimp species;119 it does not consider issues such as persistence in the environment 

and long-term effects.

Dispersant use increased during the first weeks of the spill. From April 27 to May 3, 

responders applied 141,358 gallons to the surface. The following week, they applied 

168,988 gallons. The Coast Guard and other responders had often deployed dispersants 

to respond to spills, but never in such volumes; during the Exxon Valdez spill, responders 

sprayed about 5,500 gallons, and that use was controversial.120

Faced with high-volume dispersant use, Gulf residents became concerned that the chemicals 

were just as bad as the spilled oil itself. Some workers reported nausea and headaches after 

coming into contact with dispersants.121 However, OSHA found no evidence of unsafe 

dispersant exposure among responders.122 Environmental groups pressured Nalco, the 

company that manufactures Corexit, to disclose its formula. Although it had given the 

formula to EPA during the pre-listing process, Nalco declined to make the formula public, 

citing intellectual property concerns.123 This decision did not reassure the citizens of the 

Gulf.

As the volume of dispersants sprayed on the surface grew, BP raised the idea of applying 

dispersants directly at the well, rather than waiting for the oil to reach the surface a mile 

above.124 Responders had never before applied dispersants in the deep sea. Within Unified 

Command, some scientists were cautiously optimistic. They hoped that, in addition to 

reducing shoreline impacts, subsea application would mean less dispersants used overall, 

because they would be more effective in the turbulent subsea environment. Responders 

would later conclude that subsea dispersant application also helped to protect worker 

health by lowering the concentrations of volatile organic compounds at the surface.125

But responders were concerned about the absence of information on the effects of 

dispersants in the deepwater environment. No federal agency had studied subsea dispersant 

use and private studies had been extremely limited.126 BP’s Hayward was less than helpful; 

he told a British newspaper, “The Gulf of Mexico is a very big ocean. The amount of 

volume of oil and dispersant we are putting into it is tiny in relation to the total water 

volume.”127 While federal officials did not possess the scientific information they needed to 

guide their choices, they had to make choices nevertheless.
Chapter Five 145 145

From April 30 to May 10, scientists within Unified Command worked intensively to create 

a monitoring protocol for subsea dispersant use that would detect adverse environmental 

effects and provide criteria for when the use was appropriate. It was unclear whether the 

preauthorizations by the Regional Response Teams covered subsea dispersant use. EPA 

believed they did not and wanted to make decisions about such use at a high level within 

the agency. But it had trouble establishing clear and rapid communication, both internally 

and outside the agency.128 This slowed creation and review of the testing protocols, while 

Coast Guard responders and NOAA scientists chafed at the delay.

On May 10, after several rounds of testing and revision, EPA adopted a testing protocol 

created by NOAA and BP scientists as its directive regarding subsea dispersant use. The 

directive, as later amended by EPA, limited subsea application to 15,000 gallons per day 

and required monitoring and compliance with environmental toxicity guidelines.129

Administrator Lisa Jackson ultimately gave EPA’s approval for subsea dispersant use and 

would later call it the hardest decision she ever made.130 Observed toxicity levels never 

exceeded the guidelines in EPA’s directive, and responders continued to apply dispersants at 

the source until BP capped the well.

Deploying the Containment Dome (May 6–8) 

While scientists tried to determine if subsea dispersant use was even possible, BP engineers 

simultaneously worked to contain and recover oil until they could kill the well. Within 

days of discovering the leaks from the broken riser on the sea floor, they began to consider 

use of a large containment dome. The idea was to place the dome, also known as a 

cofferdam, over the larger of the two leaks, with a pipe at the top channeling oil and gas to 

the Discoverer Enterprise, a ship on the surface. BP already had several cofferdams, which 

it had used to provide safe working space for divers repairing leaks from shallow-water 

wells following Hurricanes Katrina and Rita.131 By May 4, BP had finished modifying for 

deep-sea use and oil collection a preexisting dome that was 14 feet wide, 24 feet long, 

and 40 feet tall.132 Following an MMS inspection of the Discoverer Enterprise, BP began to 

lower the 98-ton dome to the sea floor late in the evening of May 6.133

The likelihood of collecting oil with the cofferdam was uncertain. BP’s Suttles publicly 

cautioned that previous successful uses had been in much shallower water.134 BP 

recognized that chief among potential problems was the risk that methane gas escaping 

from the well would come into contact with cold sea water and form slushy hydrates, 

essentially clogging the cofferdam with hydrocarbon ice.135 Notwithstanding the 

uncertainty, BP, in a presentation to the leadership of the Department of the Interior, 

described the probability of the containment dome’s success as “Medium/High.”136 Others 

in the oil and gas industry were not so optimistic: many experts believed the cofferdam 

effort was very likely to fail because of hydrates.137

The effort did fail, for that reason. Although BP had a plan to deal with hydrates once 

the cofferdam was in place, it had not planned to mitigate hydrate formation during 

installation.138 When crews started to maneuver the cofferdam into position on the evening 

of May 7, hydrates formed before they could place the dome over the leak, clogging the 
146 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

opening through which oil was to be funneled.139 According to Richard Lynch, a vice 

president overseeing the effort, BP never anticipated hydrates developing this early.140

Because hydrocarbons are lighter than water, the containment dome became buoyant as 

it filled with oil and gas while BP tried to lower it. BP engineers told Lynch that they had 

“lost the cofferdam” as the dome, full of flammable material, floated up toward the ships 

on the ocean surface. Averting a potential disaster, the engineers were able to regain control 

of the dome and move it to safety on the sea floor.141 In the wake of the cofferdam’s 

failure, one high-level government official recalled Andy Inglis, BP’s Chief Executive Officer 

of Exploration and Production, saying with disgust, “If we had tried to make a hydrate 

collection contraption, we couldn’t have done a better job.”142

Inaccurate estimates of the well’s flow also affected the cofferdam effort. According to 

Suttles, during this time, no one at BP believed the flow was greater than 13,000 to 14,000 

barrels per day.143 The government’s then-current estimate of the flow was 5,000 barrels 

per day. The far larger volume of the actual flow—about 60,000 barrels per day, according 

to the government’s now-current estimate—may be part of the reason hydrates formed 

more quickly than expected.144 Moreover, BP had publicly predicted that the cofferdam 

would remove about 85 percent of the oil spilling into the sea.145 But the ship it planned 

to connect to the cofferdam was capable of processing a maximum of 15,000 barrels per 

day.146 While BP may have misjudged the probability of success, its decision to deploy the 

dome instead of another containment device appears to have turned more on timing than 

on perceived effectiveness: the dome was largely off-the-shelf and therefore ready to use in 

early May, before other equipment.147

With the failure of the cofferdam highlighting the shortage of viable options to contain and 

control the well, somewhat outlandish suggestions filled the void. In mid-May, a Russian 

newspaper suggested detonating a nuclear weapon deep within the well to stop the flow 

of oil, as the former Soviet Union had done on a number of occasions.148 BP moved on: a 

little over a week after giving up on the cofferdam, on May 16, it was able to deploy a new 

collection device. Named the Riser Insertion Tube Tool, the device was a tube, four inches 

in diameter, that fit into the end of the riser and carried oil and gas up to the Discoverer 

Enterprise. This tool, BP’s first effective means of containment, collected approximately 

22,000 barrels of oil over its nine days of use.

Flow-Rate Estimates Creep Up (May 27)

After Unified Command announced its best estimate of the flow rate as 5,000 barrels per 

day on April 28, a number of independent scientists began to register their disagreement. 

BP had contacted scientists at the Woods Hole Oceanographic Institution on May 1 about 

undertaking diagnostic work on the BOP and measuring the flow using a remotely 

operated vehicle with sonar and acoustic sensors. But BP cancelled the Woods Hole project 

on May 6 to instead deploy the containment dome.149 Based on satellite imagery of the 

surface slick, other non-government scientists arrived at estimates in late April and early 

May ranging from 5,000 to 26,500 barrels of oil per day.150 Using the appearance of 

oil on the surface to assess flow from a source 5,000 feet below is inherently unreliable, 

but the outside scientists had no other data. That changed on May 12, when BP released 
Chapter Five 147 147

a 30-second video of oil and gas streaming from the end of the broken riser. Within 24 

hours, independent scientists had seized on this information and published three new 

estimates of the combined flow of oil and gas that ranged from 20,000 to 100,000 

barrels per day.151 On May 18, BP released another video, this time of the leak at the 

kink. Combining estimated flow from the two sources, a non-government scientist, Steve 

Wereley, testified before Congress that approximately 50,000 barrels of oil per day were 

flowing into the Gulf.152

BP dismissed these new estimates, with spokesman Bill Salvin stating, “We’ve said all 

along that there’s no way to estimate the flow coming out of the pipe accurately.”153 The 

government disagrees with Salvin’s claim: according to Marcia McNutt, Director of the 

U.S. Geological Survey, if a similar blowout occurs in the future, the government will be 

able to quickly and reliably estimate the flow rate using the very oceanographic techniques 

that Woods Hole was prepared to use on May 6.154*

 At the time, the government responded 

to the independent estimates by devoting greater resources to the question of flow rate. On 

May 19, the National Incident Command created an interagency Flow Rate Technical Group 

and charged it with generating a preliminary flow rate as soon as possible and, within two 

months, a final estimate based on peer-reviewed methodologies. On May 23, at Secretary 

Salazar’s recommendation, the National Incident Command appointed McNutt the leader.

The Group consisted of both government and non-government scientists, and included 

subgroups using different methodologies. It published its first estimate on May 27, stating: 

“The only range of flow rates that is consistent with all 3 of the methods considered by the 

[the Group] is 12,000 to 19,000 barrels per day. Higher flow rates [of up to 25,000 barrels 

per day] are consistent with the data considered by [one subgroup].”155 The Group released 

little additional information about its calculations. A few days later, it issued a two-page 

report stating that the 12,000 to 25,000 barrel range represented the “lower bound” of one 

subgroup’s estimates, and that this subgroup had chosen not to release its “upper bound” 

estimates, deeming them speculative because of “unknown unknowns.”156

Responders uniformly contended that they were responding to the oil as it appeared on the 

water’s surface, and that the problems with quantifying the flow from the source did not 

affect their ability to respond. In response to a congressional inquiry later in the summer 

about dispersant use, however, Admiral Allen indicated that early dispersant decisions were 

based on the 5,000 barrels per day figure, and that the higher estimate from the Flow Rate 

Technical Group “spurred responders to consider reassessing the strategy for the use of 

dispersants as well as other oil recovery methods.”157

Later studies would conclude that 12,000 to 25,000 barrels a day was still a significant 

underestimate of the amount of oil streaming into the Gulf. 

* At the behest of the Coast Guard, Woods Hole used its sonar and acoustic technology on May 31 to gather data that later yielded a flow-rate estimate of 58,000 barrels 

per day. On June 21, Woods Hole, again with the support of the Coast Guard, collected source samples, which initially demonstrated that 43.7 percent of the total flow 

was oil, while the remainder was gas. (Woods Hole has since revised this figure to 42.8 percent.)
148 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

The Top Kill and Junk Shot (May 26–28)

Throughout May, the federal government increased its presence in Houston, the hub of 

the well-control effort. In early May, scientists and engineers from three Department of 

Energy national laboratories began to work on-site with BP on containment. On May 7, 

Secretary Salazar asked McNutt, who had traveled to the Gulf with him on May 4, to 

remain in Houston. Finally, on May 10, President Obama directed Secretary Chu to form a 

team of government officials and scientists to work with BP on source control.158 On May 

11, Secretary Chu called several prominent scientists and asked them to join him the next 

morning for a meeting in Houston.159

The May 12 meeting signified the beginning of an oversight role for Secretary Chu and 

his team of science advisors. Secretary Chu is a Nobel Prize-winning physicist who had 

previously directed the Lawrence Berkeley National Laboratory, where he had led an effort 

to expand research into synthetic biofuels.160 Though well known for his wide-ranging 

intelligence, Secretary Chu was not an oil and gas or drilling expert. During the following 

weeks, he immersed himself in the finer points of petroleum engineering and became 

intimately involved in decisionmaking with respect to containment of the well.

Although they were highly respected within their fields of study, the members of the 

advisory team had limited experience with well control and varying levels of experience 

with petroleum engineering generally. Secretary Chu assumed—correctly—that BP had 

Top government officials work on source control out of BP’s Houston headquarters. At center is Secretary of Energy Steven Chu, flanked by 

Secretary of the Interior Ken Salazar (right) and Director of Sandia National Laboratories Tom Hunter. 

Unified Area Command, Deepwater Horizon Response
Chapter Five 149 149

already hired a host of containment experts, and he wanted advisors known for creative 

thinking. His principal deputy on the team, Tom Hunter, was about to retire from his 

position as Director of Sandia National Laboratories. Along with McNutt, Hunter served 

as a link between the on-site government scientists and engineers and the rest of Secretary 

Chu’s science advisors, who were for the most part based elsewhere. Another team 

member, Richard Garwin, helped design the world’s first hydrogen bomb and had worked 

to extinguish oil fires in Kuwait following the first Gulf War. Alexander Slocum, an MIT 

professor who holds about 70 patents, had done some previous work on drilling design. 

George Cooper had been the head of the Petroleum Engineering Program at the University 

of California, Berkeley. 

The role of both the national laboratories scientists and Secretary Chu’s advisors took time 

to evolve from helping BP diagnose the situation—for instance, using gamma-ray imaging 

to show the position of the BOP’s rams—to substantively overseeing BP’s decisions on 

containment. In part, this was because the Secretary of Energy, his team of advisors, and 

the national laboratories personnel lacked a formal role within Unified Command. Their 

supervision was informally grafted onto the command framework.

In addition, the national laboratories team did not immediately integrate itself into the 

existing source-control structure, led by MMS and the Coast Guard. While MMS, the Coast 

Guard, and McNutt worked out of offices on the third floor of BP’s Houston headquarters, 

the national laboratories team sat on the eighteenth floor.161 One MMS staff member who 

was in Houston from late April through early July said that he never interacted with the 

national laboratories team: they never reached out to him, and he had no idea what they 

were working on. Perhaps because the lines of authority were unclear, BP’s sharing of data 

with the government science teams was uneven at first. BP gave information when asked, 

but not proactively, so government officials had to know what data they needed and ask 

for it specifically.162 Finally, both the national laboratories team and the science advisors 

had to educate themselves on the situation, and on deepwater petroleum engineering, 

before they knew enough to challenge BP and participate in high-level decisionmaking.163

With more substantive government oversight on the way but not yet in place, BP moved 

toward its first attempt to kill the well completely, via procedures called the “top kill” 

and “junk shot.” Those names were fodder for late night comics: Jay Leno suggested 

that the top kill “sound[ed] like some bad Steven Seagal movie from the ‘80s.”164 In fact, 

both procedures are standard industry techniques for stopping the flow from a blownout well (though they had never been used in deepwater165). A top kill—also known as a 

momentum or dynamic kill—involves pumping heavy drilling mud into the top of the 

well through the BOP’s choke and kill lines, at rates and pressures high enough to force 

escaping oil back down the well and into the reservoir. A junk shot complements a top 

kill. It involves pumping material (including pieces of tire rubber and golf balls) into the 

bottom of a BOP through the choke and kill lines. That material ideally gets caught on 

obstructions within the BOP and impedes the flow of oil and gas. By slowing or stopping 

the flow, a successful junk shot makes it easier to execute a top kill.
150 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

BP’s top-kill team began work in the immediate aftermath of the initial efforts to trigger 

the BOP.166 In planning the operation, both BP and federal engineers modeled different 

scenarios based on different rates at which oil might be flowing from the well. National 

laboratories engineers used the then-current flow-rate estimate of 5,000 barrels per day.167

Paul Tooms, BP’s Vice President of Engineering, recalled that given the planned pumping 

rates, the top kill was unlikely to succeed with flow rates greater than 15,000 barrels of 

oil per day.168 A senior administration official similarly recalled being told by a BP engineer 

that the top kill would not work if the flow rate exceeded 13,000 barrels per day.169

With the approval of the Federal On-Scene Coordinator, the top kill began on the afternoon 

of May 26. Secretary Chu and some members of his science team were in the command 

center in Houston.170 During three separate attempts over three consecutive days, BP 

pumped mud at rates exceeding 100,000 barrels per day and fired numerous shots of 

junk into the BOP.171 During each effort, pressures within the well initially dropped, but 

then flattened, indicating that the top kill had stopped making progress.172 After the third 

unsuccessful attempt, BP and the government agreed to discontinue the strategy.173

As with the cofferdam, BP struggled with public communications surrounding the top 

kill. At the time, both industry and government officials were highly uncertain about the 

operation’s probability of success. One MMS employee estimated that probability as less 

than 50 percent, while a BP contractor said that he only gave the top kill a “tiny” chance 

to succeed.174 But BP’s Hayward told reporters, “We rate the probability of success between 

60 and 70 percent.”175 After the top kill failed, that prediction may have lessened public 

confidence in BP’s management of the effort to control the well.

The Federal Role Increases (Late May) 

By late May, the competence and effectiveness of the federal response was under assault. 

Polls showed that 60 percent of adults thought the government was doing a poor job of 

handling the spill.176 News articles chronicled local anger that BP appeared in charge of 

clean-up efforts.177 The government’s estimate of the flow rate was climbing and, with the 

failure of the top kill, no end to the spill was in sight. 

On May 28, President Obama made his second trip to the region to see response efforts 

and meet with state and local leaders. Plaquemines Parish President Billy Nungesser would 

later claim, incorrectly, that he had not been invited to this important meeting.178 He 

told the Plaquemines Gazette that he had smuggled himself and another Parish President 

across bays and bayous and through an armada of state boats, gaining access only after 

threatening to call Anderson Cooper.179

The meeting with the President occurred at the Coast Guard station in Grand Isle, 

Louisiana, and included, among others, Governor Jindal, Florida Governor Charlie Crist, 

Alabama Governor Bob Riley, Louisiana Senators David Vitter and Mary Landrieu, 

Louisiana Congressman Charlie Melancon, New Orleans Mayor Mitch Landrieu, Lafourche 

Parish President Charlotte Randolph, and Parish President Nungesser.180 President Obama 

emphasized the seriousness with which the government was treating the spill, announcing 

at a press conference after the meeting that he would triple the federal manpower and 
Chapter Five 151 15

equipment involved in the 

response.181 Though Coast Guard 

responders believed they were 

already dedicating every available 

resource to the spill, and did not see 

across-the-board “tripling” as the 

best use of resources, they dutifully 

attempted to triple the personnel 

engaged and boom deployed. 

They chronicled their progress in 

Louisiana in a report titled “Status 

on Tripling.”182

While in Grand Isle, President 

Obama also received an “earful” 

about Louisiana’s proposal to build 

massive offshore sand berms as 

a physical obstacle to oil, which 

the National Incident Command had declined to approve in its entirety.183 Parish President 

Nungesser, seated immediately to the President’s left, was the first attendee to speak at the 

meeting and was adamant about the need for the entire berms project. Governor Jindal 

echoed him. In line with the federal government’s effort to be more responsive to local 

demands, President Obama turned to Admiral Allen and asked him, in front of the berms’ 

strongest proponents, to figure out a solution.184

The “tripling” order and promise to promptly reevaluate the berms project were only 

two of many actions at the end of May by which the federal government attempted 

to demonstrate its focus on the Deepwater Horizon disaster and commitment to 

the communities in the Gulf. The President signed the Executive Order creating this 

Commission on May 21.185 On May 27, he announced a moratorium on offshore 

deepwater drilling and held a press conference about the administration response.186

The same day, Elizabeth Birnbaum, the head of MMS, resigned—“on her own terms and 

on her own volition,” according to Secretary Salazar.187 Most symbolically, the federal 

government stopped holding joint press conferences with BP. From June 1 on, Admiral 

Allen gave his own daily press briefing.188 But local officials continued to attack the 

adequacy of the federal response and to assert that that BP was running the response 

effort. 

The Battles over Boom and Berms (May to June) 

While the response had many dimensions, local communities fixated on the deployment of 

boom to prevent oil from washing ashore. Although not the most effective response tool, 

boom is a measurable, physical object that visibly stops oil. Residents could not see sourcecontrol efforts on the ocean floor or skimming far out in the Gulf, but they could see 

boats laying ribbons of bright orange or yellow floating boom to protect their shorelines. 

According to one Terrebonne Parish resident, boom was eye candy—seeing it gave him a 

sense of satisfaction (even if it did not do much).189

Under fire, President Barack Obama meets with dissatisfied state and local 

officials in Grand Isle, Louisiana on May 28, during his second visit to the 

Gulf since the spill began. Visible clockwise from the President: Plaquemines 

Parish President Billy Nungesser, Louisiana Governor Bobby Jindal, New 

Orleans Mayor Mitch Landrieu, Grand Isle Mayor David Camardelle, and Florida 

Governor Charlie Crist. 

David Grunfeld/The Times-Picayune. Photo © 2010 The Times-Picayune 

Publishing Co., all rights reserved. Used with permission of The Times-Picayune.
152 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

The Moratorium 

On May 27, after a 30-day interagency examination of deepwater drilling 

operations, Secretary Salazar directed MMS to issue a six-month moratorium on all 

drilling at a water depth of more than 500 feet in the Gulf of Mexico and the Pacific 

Ocean. Department officials justified the moratorium as providing time for this 

Commission to do its work and for MMS to undertake needed safety reforms. The 

moratorium took effect on May 30 and halted work on 33 offshore deepwater rigs 

in the Gulf.

The oil and gas industry, local communities, and elected officials from the region 

immediately criticized the action. Senator Landrieu testified before this Commission 

in July that the moratorium was “unnecessary, ill-conceived and has actually 

created a second economic disaster for the Gulf Coast that has the potential 

to become greater than the first.” On July 30, BP established a $100 million 

charitable fund to assist rig workers experiencing economic hardship because of the 

moratorium.

The federal government concluded that the moratorium’s impact would be less 

severe. On September 16, a federal interagency report stated that the moratorium 

“may temporarily result in up to 8,000 to 12,000 fewer jobs in the Gulf Coast,” 

with these losses attributed mostly to small businesses. Louisiana elected officials 

criticized the report’s methodology and the decision to conduct this analysis after, 

instead of before, the moratorium began. 

A group of companies that provide support services for deepwater drilling vessels 

challenged the moratorium in federal district court in Louisiana. On June 22, 

the court ruled that the moratorium violated the Administrative Procedure Act 

and enjoined its continued enforcement. The federal government asked the Fifth 

Circuit Court of Appeals to stay the district court’s ruling, but the Fifth Circuit 

denied that request on July 8. The Department of the Interior then issued a revised 

moratorium on July 12, which limited drilling based on the equipment a rig used 

rather than the depth of the wellhead. Neither the first nor the second moratorium 

provided a company with the option of avoiding the bar on drilling by proving the 

safety of its rig operations to the government. A second group of offshore support 

companies challenged the revised moratorium. Before the district court could rule 

on this new lawsuit, the Department lifted the moratorium on October 12, seven 

weeks ahead of its scheduled November 30 expiration.

On September 30, a few weeks before lifting the moratorium, the Department 

promulgated new regulations on topics such as well casing and cementing, 

blowout preventers, safety certification, emergency response, and worker training. 

Compliance with the new rules is a prerequisite for both shallow and deepwater 

drilling permits. Some companies called these new requirements a “de facto 

moratorium” because of the time needed to meet them and for the Department to 

verify compliance.
Chapter Five 153 153

Boom became a symbol of federal responsiveness to local communities. NOAA scientists 

worked through the night, every night, to prepare oil trajectory forecasts for federal 

responders to review as they began their days.190 Responders used those forecasts to plan 

their actions, including where to place boom. Federal responders thought that officials 

and residents complaining about lack of boom did not understand their strategy for 

deployment; officials and residents thought that federal responders were inattentive to 

local needs.191 The National Incident Command was not deaf to these complaints and gave 

an unofficial order to “keep the parishes happy.”192 Coast Guard responders distributed 

many miles of boom according to political, rather than operational, imperatives. They felt 

hamstrung by the outrage that resulted when a parish or state felt slighted by allocation 

decisions, so they placed boom wherever they could.193

Every Governor wanted more boom. When the oiling risk was highest in Louisiana, the 

Coast Guard directed boom there. Governor Riley of Alabama contended that this decision 

left his state’s shoreline in danger.194 At a press conference in mid-May, Governor Jindal 

said that the containment boom provided to Louisiana by the Coast Guard and BP was 

inadequate, while local officials behind him held up pictures of oil-coated pelicans.195

Florida Department of Environmental Protection Secretary Mike Sole told reporters, “A lot 

of the decisions about Florida are being made in Mobile.” He said he had warned the Federal 

On-Scene Coordinator, “Florida is important. We have 770 miles of shoreline to protect. I’m 

concerned that we’re not getting enough focus on Florida.”196

A vessel places containment boom in Louisiana’s Barataria Bay. Hundreds of miles of boom were deployed along the Gulf coast, but 

politicians clamored for more of the highly visible barriers. 

U.S. Coast Guard photo/Petty Officer 3rd Class Ann Marie Gorden
154 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

The competition for boom occurred at the parish and town levels as well. St. Bernard 

Parish had its own contractor bring in boom; it then sought to make the Coast Guard 

purchase and deploy that boom locally.197 Some parishes reportedly ordered boom directly 

from suppliers and told them to “send the bill to BP.”198 Lafourche Parish kept demanding 

more boom—until it realized that certain skimmers were more effective and began 

demanding those skimmers instead.199 Unified Command struggled to track how much 

boom was deployed and where.

Initially, responders made booming decisions based on their knowledge of the region’s 

geography, the location of environmentally sensitive areas, and NOAA’s oil trajectory 

forecasts. The oil-spill planning documents did not lay out a specific booming map, 

because the coastal ecosystem, particularly in the marshes, frequently changes. Unified 

Command eventually brought the Parish Presidents together to review boom plans that 

each parish had created. Some were infeasible—for instance, requesting that boom be 

placed in tidal passes where currents would drive oil under the boom or else damage it. 

In addition to worrying about useless or unnecessary boom, responders were concerned 

that storms could blow it into delicate marsh habitat. They deployed boom based on local 

pressures only to pull it away during bad weather.200

Once parishes had boom, they did not want to let it go. On July 22, Parish President 

Nungesser threatened to blow out the tires of trucks carrying away boom as the Coast 

Guard prepared for Tropical Storm Bonnie. Though he claimed that he was joking, the FBI 

called to reprimand him.201 Other Parish Presidents issued orders prohibiting the removal 

of response equipment from their parishes and threatened Coast Guard responders with 

arrest.202 Officials asked responders to measure “feet of boom deployed”—a statistic that 

was time-consuming to generate and had little value in assessing response efforts.203 All of 

these problems distracted responders from their focus on cleaning up the spill.

The boom wars never reached a resolution. Responders knew that in deploying boom they 

were often responding to the politics of the spill rather than the spill itself. And the miles of 

boom along the coastline still did not prevent oil from washing up on the shore. 

The boom wars were relatively civil, however, compared to the struggle among the State of 

Louisiana, the Army Corps of Engineers, the National Incident Command, and, ultimately, 

the White House over berms. Reinforcing barrier islands had long been a component 

of Louisiana’s and Plaquemines Parish’s coastal restoration plans.204 But by early 

May, Governor Jindal and Parish President Nungesser had seized on an idea (originally 

proposed by Deltares, a Dutch independent research institute, together with Van Oord, 

a Dutch dredging and marine contractor) to construct massive, linear sand berms along 

Louisiana’s barrier islands for spill response, to guard the coastline from oil.205 The berms 

project presented an opportunity for Louisiana to take the lead on a large-scale response 

measure—with BP footing the bill. Moreover, after the spill ended, the berms’ purpose 

could “pivot” from response to coastal restoration.206

On May 11, Louisiana’s Office of Coastal Protection and Restoration applied to the Corps 

for an emergency permit to construct berms to “enhanc[e] the capability of the islands to 
Voices from the Gulf 155 155

Voices from the Gulf

“If I was a mom, what would I do?”

Sheryl Lindsay, Orange Beach 

Weddings, Orange Beach AL

When Sheryl Lindsay picked up the April 21 Mobile 

Press-Register and read the headline, “At least 

11 workers sought after gulf rig explosion,” she 

recalled, “My heart went out to the workers on that 

rig, the victims and their families. I couldn’t believe 

what had happened.” The newspaper reported that 

six of the Deepwater Horizon survivors had been 

flown to a Mobile, Alabama, trauma unit. 

For six years, Lindsay had been president of Orange Beach Weddings, which coordinated and 

arranged “The Wedding of Your Dreams” on Alabama’s Gulf Coast near the Florida line. Her 

offices on Perdido Boulevard overlooked the pristine white sand beaches of Orange Beach, 

Alabama—one of her firm’s specialties was elegant beach ceremonies and festivities. Her busy 

season was starting, with 73 weddings booked for 2010. She worked with numerous contractors, 

from wedding planners and caterers to ministers and photographers. She knew that BP’s 

Macondo well was now spewing oil; “But I never thought it would affect us here.”

On April 30, the day after the U.S. Coast Guard declared the Macondo blowout a “spill of national 

significance,” Lindsay was in her office when the phone rang. It was her first cancellation. “When 

the bride called to cancel, she said it was because of the spill. She didn’t want her guests coming 

down to find oil on the beaches. She didn’t want to come if they couldn’t swim or eat the seafood. 

That’s when I knew.”

In the wake of the oil spill, “Every time the phone rang, all we got was another cancellation—or 

someone asking how bad it was down here. I became a counselor for these brides. Orange 

Beach is a popular spot for destination weddings, and many of my brides come from out of state. 

But if girls’ weddings were still a few months out, they still had time to change plans and move 

the wedding somewhere else. A lot of girls asked me what they should do—they were worried 

about the smell, whether the guests could swim and the quality of the seafood.” She continued, 

“This was their big day. It was tough. And you think, ‘If I was a mom, what would I do?’”

“What’s funny,” Lindsay said, “is we only had about three bad weeks where oil was washing on 

shore and BP was staging clean-up on the beach. That was in June. The rest of the summer 

the beaches were pretty much clean but folks still didn’t come down.” As the spill gushed on, 

Lindsay began to realize she had no idea what the next year would look like, but it didn’t look 

good. She did not think she could afford to renew her office lease. In 2009, she had taken out a 

small business loan from the local bank for $55,000 to expand her firm, but now she began to 

fear she could not meet those payments as her business diminished.

Michelle Rolls-Thomas/Associated Press
156 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

reduce the inland movement of oil from the BP Deepwater Horizon Oil Spill.”207 Colonel 

Alvin Lee, two months shy of the end of his three-year tour as the Commander of the 

Corps for the District of New Orleans, cancelled a long-scheduled vacation, and the Corps 

immediately sought comments on the proposal from relevant federal and state agencies.208

The patience of Louisiana officials quickly wore thin. On May 17, Governor Jindal’s office 

summoned Colonel Lee to the New Orleans airport for a meeting that included three Parish 

Presidents, the Chairman of the Office of Coastal Protection and Restoration, the Adjutant 

General for Louisiana, and the Governor himself. The group’s message to Colonel Lee was 

clear: approve the berms project, and do it quickly.209 The entire Louisiana congressional 

delegation wrote Colonel Lee on May 20, to “implore [him] to immediately approve 

the emergency authorization request” for the Louisiana berms.210 In a May 21 letter 

to President Obama, Senator Vitter asked the President to stop the “tragic bureaucratic 

stranglehold” and to “make this happen now.”211

The Corps reviewed agency comments, conducted its own evaluation of the project, and 

engaged in dialogue with state officials. On May 27—just 16 days after it had received 

Louisiana’s application—the Corps approved the issuance of an emergency permit for 

a significantly scaled-back berms project: six “reaches” totaling 39.5 miles in length.212

During the review process, commenting agencies expressed skepticism that the berms could 

be constructed in time to be effective for spill response and concern that partially completed 

berms would do more environmental harm than good.213 The Corps’ job, however, was to 

analyze the “feasibility and environmental impacts” of the berms. The National Incident 

Commander had the task of determining whether the berms would be “effective. . . in 

combating the oil spill.”214 That determination was necessary to make BP pay for the 

project as a response measure.

The same day the Corps approved the six reaches, Admiral Allen authorized one of the six 

as a prototype oil-spill response mechanism.215 Earlier in May, an interagency task force 

had advised the National Incident Command that the project would not be an effective 

spill-response measure, in part because the berms could not be constructed in time to fight 

the spill.216 But public and political pressure had been unyielding. In an attempt to balance 

both sets of concerns, on May 22, Admiral Allen e-mailed an idea to his deputy: “What 

are the chances we could pick a couple of no brainer projects and call them prototypes to 

give us some trade space on the larger issue and give that to Jindal this weekend?”217 Five 

days later, the National Incident Command announced its approval of one prototype berm, 

to cost $16 million.218 The accompanying press release promised that additional berms 

could be constructed if the approved section proved effective. Building even one prototype 

segment would take months, however, and the segment would then need to be analyzed. 

Any further construction therefore would not begin until the fall. 

But because of the meeting in Grand Isle on May 28, where Parish President Nungesser 

and Governor Jindal urged President Obama to approve the entire project, the National 

Incident Command would change course. At the meeting, the President turned to Admiral 

Allen and, in front of the assembled Governors and other leaders, asked him to assemble a 

group of experts to examine the merits of Louisiana’s proposal as a spill-response measure. 
Chapter Five 157 157

Admiral Allen replied that this might take some time. It was the Friday afternoon before 

Memorial Day weekend. But the President pushed, asking, “Can you do it next week?” 

Admiral Allen, put on the spot, pledged to do his best.219

After the meeting, Governor Jindal immediately announced that the President had “agreed 

that work on the first segment must begin immediately” and that the federal government 

would decide “within two to three days” whether the additional five segments should 

proceed.220 Parish President Nungesser told a similar story to Anderson Cooper on CNN 

that evening, saying “The President committed by early next week, we will have an answer 

and I believe that he’s going to task BP.”221 

On June 1, Admiral Allen convened a summit in New Orleans “which included members of 

academia [one from Louisiana State University and a second from the University of New 

Orleans], federal trustees, fish and wildlife service and NOAA,” as well as Governor Jindal 

and Parish President Nungesser. Although some experts at the summit expressed concern 

about causing harm to the environment, the discussion focused on the berms’ potential to 

protect marshlands.222 The politics of the project remained close at hand: Parish President 

Nungesser walked out, calling the meeting a “Dog and Pony Show,”223 only to return in 

time to speak at the end. Governor Jindal continued to express his frustration and pressed 

for approval of all six reaches covered by the Corps permit.224 In the face of the spill and in 

front of the Louisiana politicians, no one directly opposed the berms, and a “preponderance 

of opinion” at the summit suggested the berms would be an effective response measure.225

That evening, following the summit, Admiral Allen and BP’s Hayward had dinner together 

in New Orleans to discuss the berms.226 The following afternoon, Admiral Allen gave the 

go-ahead to all six reaches approved by the Corps, to be funded by BP.227 BP estimated the 

cost to be $360 million, double the entire amount it had spent as of early June in “helping 

the region respond to the oil spill.”228 The Corps pegged the cost at $424 million.229

Louisiana awarded contracts for the project to Shaw Group, a Baton Rouge-based 

engineering, construction, and environmental services firm, and C.F. Bean LLC, a dredging 

contractor based in Plaquemines Parish.230 Shaw estimated that five of the six berm reaches 

would be completed by November 1, and that the sixth would be completed by the end of 

November.231 The National Incident Command estimated that the construction time for all 

six reaches would be six to nine months.232 Even if those estimates had been correct, the 

project would have been nowhere close to complete by the time the government expected 

BP to kill the Macondo well with a relief well. As it happened, all of the estimates were far 

too rosy. Only a fraction of the planned reaches would be finished before the spill ended, 

and very little oil would be captured.

From Containment to Collection (Late May to Early July)

Following the unsuccessful top kill, BP teams in Houston met through the night of May 

28 to assess the operation.233 Some meetings occurred behind closed doors, without 

government participation. At one point, Herbst of MMS and Admiral Kevin Cook, who 

had been dispatched by Admiral Allen to be his representative in Houston, entered a 

meeting and stated that they had a right to be present. Apparently, government officials 
158 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

had not previously insisted on joining these types of meetings, and BP personnel were 

surprised by the interruption.234 The failure of the top kill marked a turning point for the 

government science teams, with the government significantly increasing its oversight of 

the containment effort.

The next morning, BP presented its analysis of why the top kill failed to stop the flow 

of oil. The analysis focused on the well’s 16-inch casing, the outermost barrier between 

the well and the surrounding rock for more than 1,000 vertical feet. That casing was 

purposely fabricated with three sets of weak points, called rupture disks. During the well’s 

production phase, the hot oil coursing through the production casing, which is inside the 

16-inch casing, would lead to a buildup of pressure in the well. If the pressure buildup was 

too high, it could cause the collapse of one of the two casings. The disks were designed to 

rupture and relieve this potential buildup of pressure before a casing collapsed.

The disks could rupture in two ways. If pressure between the 16-inch casing and the 

production casing were too high, the rupture disks would burst outward before the 

production casing collapsed. If pressure outside the 16-inch casing were too high, the 

rupture disks would collapse inward before the casing itself collapsed.235 Once ruptured, 

the disks would create small holes in the 16-inch casing, bleeding built-up pressure off into 

the rock. According to BP’s top-kill analysis, pressures created by the initial blowout could 

have caused the rupture disks to collapse inward, compromising the well’s integrity.236

BP believed that the mud it had pumped down the well during the top kill could have 

gone out into the rock through the rupture disks, instead of staying within the well and 

pushing oil back down into the reservoir as intended.237

Collapse of the rupture disks was only one of BP’s possible explanations for the 

unsuccessful top kill.238 But the company presented it to the government as the most likely 

scenario.239 Although the government science teams did not fully accept BP’s analysis of 

what happened to the mud, they agreed that the rupture disks could have collapsed during 

the blowout, and that the integrity of the well had to be considered in future containment 

efforts.240 In retrospect, government officials have suggested that the top kill likely failed 

because the rate at which oil was flowing from the well was many times greater than the 

then-current 5,000 barrels-per-day estimate. Because BP did not pump mud into the well 

at a rate high enough to counter the actual flow, oil and gas from the well pushed mud 

back up the BOP and out of the riser.241

BP had previously said that, if the top kill failed, its next step might be to install a second 

BOP on top of the existing one to shut in the well.242 But now, the company engineers 

viewed the possibility that the rupture disks had collapsed as a reason to discard capping 

the well as an option.243 If BP shut the well in, oil and gas could flow out the rupture disks 

and into the rock surrounding the well in a “broach” or “underground blowout.” From 

there, the hydrocarbons could rise through the layers of rock and flow into the ocean 

from many points on the sea floor. This would make containment nearly impossible, at 

least until the completion of a relief well. Thus, in the aftermath of the top kill, BP and 

the government focused on trying to collect the oil, with the relief wells still providing the 

most likely avenue for killing the well altogether.244
Chapter Five 159 159

BP had a team ready to proceed with new collection tools almost immediately.245 On May 

29, the company and the government announced that BP would attempt to cut off the 

portion of the riser still attached to the top of the BOP and install a collection device—the 

“top hat”—which would then be connected via a new riser to the Discoverer Enterprise 

above.246 BP began installing the device on June 1, and had the top hat in place and 

functioning by 11:30 p.m. on June 3. Having learned from its cofferdam experience, BP 

injected methanol to prevent formation of hydrates. By June 8, the Discoverer Enterprise 

was collecting nearly 15,000 barrels of oil per day.

BP also developed a system to bring oil and gas to the surface through the choke line on 

the BOP. BP outfitted the Q4000, a vessel involved in the top-kill effort, with collection 

equipment, including an oil and gas burner imported from France. After it became 

operational on June 16, the Q4000 system was able to process and burn up to 10,000 

barrels of oil per day.*

On occasion, BP was overly optimistic about the percentage of the oil it could remove 

or collect. On June 1, Suttles said that he expected the top hat, when connected to the 

Discoverer Enterprise, to be able to collect the “vast majority” of the oil.247 Within days, it 

became apparent that the top hat and Discoverer Enterprise were inadequate. On June 6, 

Hayward told the BBC that, with the Q4000 in place, “we would very much hope to be 

containing the vast majority of the oil.”248 But when the Q4000 came online in mid-June, 

the two vessels’ joint capacity of 25,000 barrels per day was still insufficient. 

* Over the course of June and early July, BP worked on further expanding its containment system, which it asserted would eventually be able to collect up to 90,000 

barrels of oil per day. BP never used the complete system, based around two freestanding risers connected to the choke and kill lines on the BOP, because it succeeded 

in capping the well on July 15.

Transocean’s huge drill ship the Discoverer Enterprise, its derrick towering 400 feet above the sea, and Helix’s Q4000 (foreground) sit over 

the gushing wellhead. Together the vessels were able to recover up to 25,000 barrels of oil per day. 

Julie Dermansky ©2010
160 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

It is unclear whether BP could have increased its collection capacity more rapidly than it 

did. BP’s Lynch said that the speed at which the company brought capacity online was 

limited solely by the availability of dynamically positioned production vessels.*

 One senior 

Coast Guard official challenged BP’s definition of availability: he suggested that BP did 

not consider options such as procuring ships on charter with other companies until the 

government pushed it to do so. Obtaining another production vessel might have enabled 

BP to collect oil through the BOP’s kill line at a rate comparable to that of the Q4000.

249

Continued Conflict about Dispersant Use (May 10–July 14)

Because of the insufficient collection capacity, oil continued to flow into the Gulf. Though 

the subsea use of dispersants proved helpful in preventing huge surface slicks, it did not 

initially have the predicted effect of reducing the total volume of dispersants applied. At 

a May 24 press conference, EPA Administrator Jackson announced that the government 

was instructing BP to “take immediate steps to significantly scale back the overall use 

of dispersants” and expressed EPA’s belief that “we can reduce the amount of dispersant 

applied by as much as half, and I think probably 75 percent, maybe more.”250 A Coast 

Guard–EPA letter and joint directive issued two days later instructed BP to “eliminate the 

surface application of dispersants,” except in “rare cases when there may have to be an 

exemption.”251

Despite this directive, surface use of dispersants continued. When surveillance aircraft 

spotted oil and no other method of cleaning it up was available in the area, BP would 

ask for an exemption from the Federal On-Scene Coordinator, who would then seek EPA’s 

approval. The Coast Guard could not unilaterally allow the exemption; EPA had the final 

vote. 

EPA expressed frustration that BP sought regular exemptions, and it repeatedly asked for 

more robust explanations of why BP could not use mechanical recovery methods, such 

as skimming and burning, instead of dispersants.252 Coast Guard responders, who viewed 

dispersants as a powerful tool to protect the coastline, wondered why EPA wanted to 

cast aside the advance planning that went into the preauthorization of surface dispersant 

use.253

These different perspectives on dispersants led to conflicts between EPA and the Coast 

Guard. For example, on June 7, BP requested permission to spray dispersants on several 

large slicks. Despite Federal-On Scene Coordinator Rear Admiral James Watson’s statement 

that he had “determined aerial dispersant the best and only way to mitigate the pending 

landfall effect of the oil spotted,” EPA would not approve the exemption.254 The Coast 

Guard captain leading the majority of front-line operations was furious. “It would be a 

travesty,” he wrote, “if the oil hits the beach because we did not use the tools available to 

fight this offshore. This responsibility needs to be placed squarely in EPA’s court if it does 

hit the shoreline.”255 Later that day, without having received responses to its requests for 

additional data, EPA threatened to issue a directive “to stop the use of all dispersants.”256

* Dynamically positioned vessels have computer-controlled systems that maintain the vessel’s exact position and direction, despite external factors such as wind, waves, 

and current.
Chapter Five 161 16

The working relationship between the agencies improved over time, with more complete 

justifications for dispersant use included in the daily requests for exemptions.257 But 

disagreements came to a boil again in mid-July. By this point, EPA had finally installed 

a senior official, Assistant Administrator for Solid Waste and Emergency Response 

Mathy Stanislaus, on the ground at Unified Area Command.258 On July 13, BP’s head 

of dispersant operations made a request to apply 10,000 gallons to slicks.259 The request 

ultimately went to Stanislaus, who denied it, noting that skimming in particular had been 

extremely effective over the past few days.260 The Federal On-Scene Coordinator (by this 

time Rear Admiral Paul Zukunft) replied that he could not “take the dispersant tool out of 

my kit when” oil threatened to hit environmentally sensitive areas in Louisiana. “We spent 

over a month cleaning Barataria Bay with over 1500 people and 600 vessels,” he added, 

“and still incurred significant wildlife kills while exposing these clean-up crews to extreme 

heat conditions. That is the trade-off option where dispersants come into play. . . .”261 The 

back-and-forth continued, with BP ultimately prohibited from using dispersants on July 

14.262 The capping of the well the next day tabled the conflict. 

Months later, Admiral Allen and Administrator Jackson would say that they had 

cooperated closely, nearly attained the goal of a 75 percent reduction in dispersant use, and 

were satisfied with the use of dispersants to mitigate the spill.263

The Well Is Finally Capped (Late June to July 15—and Beyond)

Meanwhile, in Houston, the government continued to develop a more effective structure 

for oversight of well control. The basic elements of the structure were in place by midMay, and the roles of the different government teams were better defined by mid-June. 

MMS and the Coast Guard continued to focus on identifying hazards in BP’s technical 

procedures; personnel from the national laboratories and the U.S. Geological Survey 

provided information and analyses to the science advisors and BP; and the science advisors 

conducted their own independent analyses and helped inform the government’s ultimate 

decisionmakers, including Secretary Chu, Secretary Salazar, McNutt, Hunter, Carol 

Browner (Director of the White House Office of Energy and Climate Change Policy), and 

Admiral Allen.264

Following the failure of the top kill, BP began presenting its source-control plans for review 

by these government teams. The science advisors would question BP’s assumptions, 

forcing it to evaluate worst-case scenarios and explain how it was mitigating risks.265 The 

government saw its pushback as essential because BP would not, on its own, consider 

the full range of possibilities.266 According to one senior government official, before the 

increased supervision, BP “hoped for the best, planned for the best, expected the best.”267

BP often found the supervision frustrating. Tooms, BP’s Vice President of Engineering, 

believed that the government science advisors unnecessarily slowed the containment effort, 

arguing that scientists consider risk differently than engineers and that BP had expertise in 

managing risk.268 BP, however, was not in the best position to tout that expertise: its well 

had just blown out. 

In mid- to late June, the government teams also began to seek more frequent input 

from other oil companies, primarily through large conference calls of 30 or more people. 
162 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Although BP had previously turned to others in industry for advice, it had generally asked 

discrete questions about aspects of source control. The government teams, by contrast, 

asked other companies to comment on BP’s overall plans and to help force BP to consider 

contingencies. BP, which believed its competitors suffered from a conflict of interest, 

did not appreciate the increased industry involvement. After one meeting in which BP’s 

competitors aggressively challenged its plans, BP refused to meet with them again, forcing 

the government teams to schedule separate meetings.269 

The conference calls were somewhat disorganized, with no agenda and participants 

sometimes not knowing who was speaking. One industry participant recalled an instance 

when he was chagrined to learn he had been talking to Secretary Chu without realizing 

it.270 A senior government official noted that some colleagues viewed BP’s conflict-ofinterest concerns as valid and took the competitors’ advice “with a grain of salt.”271 But 

government personnel generally found the industry participation helpful.

The science advisors’ oversight increased substantially during June. On June 18, Secretary 

Chu sent an e-mail to the advisory team as well as some national laboratories scientists, 

describing their expanded role. The e-mail cited a scene from the classic World War II 

movie The Guns of Navarone, and quoted the character played by Gregory Peck: “[Y]our 

bystanding days are over! You’re in it now, up to your neck! They told me that you’re 

a genius with explosives. Start proving it!” Recognizing that there were “[p]robably no 

shaped charges to be used on this mission,” Secretary Chu wrote that “the rest rings true.” 

He enclosed a directive that Admiral Watson, the Federal On-Scene Coordinator, would issue 

the next day, formally requiring BP to submit any “pending decision” on containment to 

the government “for review.”272

The role of the science advisors and the on-site scientists increased just as the sourcecontrol effort approached a critical phase. By late June, BP was well on its way toward 

deploying a “capping stack,” which, once installed on top of the BOP, would enable BP to 

shut in the well. The capping stack was essentially a smaller version of a BOP, similarly 

designed to stop the flow of oil and gas. BP had internally discussed installing a tightsealing cap within a week of the blowout.273 Following the top kill, however, BP and the 

government had shelved the idea of shutting in the well, in part because of concerns that 

the rupture disks in the well’s 16-inch casing had collapsed, potentially allowing oil to 

flow out of the well into the rock. The government and BP had to take these concerns into 

account when planning for use of the capping stack.

Secretary Chu and Hunter briefed the President on the capping stack in late June or 

early July, and he approved its use. The government appears to have delayed installation 

for a few days, however, to continue analyzing the significant risks of shutting in 

the well.274 One critical analysis involved the geology surrounding the Macondo well. 

The government’s scientific Well Integrity Team concluded that it would take a total 

of approximately 100,000 barrels of oil flowing through the rupture disks into the 

surrounding rock for oil to create paths through the rock to the sea floor. The Team further 

concluded that such paths were likely to close or “heal” if BP and the government detected 

oil flow into the rock and reopened the capping stack with sufficient speed. To spot any 
Voices from the Gulf 163 163

Voices from the Gulf

“This unnatural, unnatural 

catastrophe. . . .”

Al & Sal Sunseri, P&J Oyster Company, 

New Orleans, LA

Al and Sal Sunseri are co-owners of P&J Oyster Company, their 

family’s 134-year-old business in the French Quarter of New Orleans. 

P&J processes and sells some 60,000 Louisiana oysters to the city’s 

best restaurants and local oyster bars on a typical day. When Al 

first heard about the Deepwater Horizon rig accident, he recalled 

thinking, “‘What a terrible thing for those people.’” He added, “I 

didn’t think more about it because the Coast Guard and everyone 

said it would be limited.”

Al’s routine remained unchanged in the days after the Deepwater 

Horizon blowout and fire: early mornings bustling with deliveries, the din of his skilled shuckers 

pounding and prying open oysters, preparing orders. Then, on Saturday, April 24, the Sunseris 

and the rest of America heard that oil was leaking from the rig’s broken riser. With each passing 

day, the news only got worse. 

P&J oysters are an institution in New Orleans, a celebrated brand proudly listed on local menus 

as a promise of taste and quality. P&J specializes in Louisiana oysters; most of their suppliers 

farm in the Barataria Basin, west of the Mississippi River. P&J had survived floods, the Great 

Depression, and even Hurricane Katrina. But now, the Sunseri family and the staff were all at the 

mercy of a runaway oil spill, with no end in sight. 

Throughout May, the Macondo well gushed on unchecked, and by early June, the government 

had closed Louisiana oyster beds. The Sunseris had taken over from their father 25 years earlier. 

Now, for the first time, they had to lay off 11 skilled shuckers. “These ladies here, those guys—I 

grew up with them,” Al said. “We were in our twenties when we started.” Longtime employee 

Wayne Gordon, 42, had been shucking at P&J since he was 18: “Twenty-four years. I cannot 

imagine not being here.” As the shuckers worked their way through what was to be the final 

pile of succulent Louisiana shellfish, the owner of a nearby restaurant appeared with a breakfast 

buffet of scrambled eggs, fried ham, grits, and biscuits. “After a funeral, we bring food,” said the 

restaurateur, a longtime customer.

Al’s son Blake, 24, has spent the past three years learning the business, intent on becoming the 

sixth family generation to run it. “This is a real devastating event for me,” he said. “This is my 

home, it feels like I don’t really have a say in what’s going on around me.” He could have been 

speaking for millions of his fellow Americans, all along the Gulf of Mexico coast, who suddenly 

found themselves and their worlds facing ruin from what his uncle, Sal, called “this unnatural, 

unnatural catastrophe.”

The Louisiana Seafood Marketing 

and Promotion Board
164 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

problem quickly enough to avoid lasting damage, the Team recommended monitoring 

shut-in pressure at the BOP as well as visual, seismic, sonar, and acoustic data.275

Because shutting the capping stack would increase the pressure inside the well, the 

government was also concerned about bursting either the rupture disks (if they had not 

already collapsed) or another weak point in the casings. One industry executive recalled 

discussing this issue on a conference call with the science advisors; he expressed his view 

that allowing the pressure to climb above the level recorded during the top kill would be 

traveling into uncharted territory, with uncertain risks. 

On July 9, as analysis of these risks continued, Admiral Allen authorized BP to install the 

capping stack, but not to close it.276 The extremely complicated operation began the next 

day. After removing the top hat from the top of the riser, remotely operated vehicles had to 

unbolt the stub of riser connected to the top of the Deepwater Horizon BOP stack, remove 

this stub, look for any pieces of drill pipe sticking up through the top of the BOP stack, 

slide the capping stack into place, and bolt it to the BOP stack. The process went smoothly, 

and BP finished installing the capping stack without incident by July 12. Suttles described 

this installation as the best operation of the entire source-control effort.277

BP next prepared to temporarily close the capping stack in a planned “well integrity test,” 

to determine whether the well had been compromised and oil could flow into the rock 

formation. In a July 12 letter, Admiral Allen formally authorized the test to begin.278

But it did not. About two hours before the test was supposed to start, the government 

teams met with BP and industry representatives, including from Exxon (in person) and 

Shell (by phone). Secretary Chu and Admiral Allen were both present in person. BP faced 

significant criticism of the wisdom of attempting the test, with Exxon and Shell raising 

concerns associated with shutting in the well that had yet to be considered by BP or the 

government.279 In the most extreme scenario, one industry expert suggested that an 

underground blowout could cause the sands around the wellhead to liquefy and the entire 

BOP to disappear into the sea floor.280 Because Secretary Chu and the science advisors 

believed that these risks required further study, Admiral Allen delayed the test to allow for 

24 hours of additional analysis.281

Overnight, the government science teams reached out to industry and academia for help. 

By 10:00 the next morning, experts had reassured the government that catching a leak 

early enough would prevent catastrophic consequences.282 With the government teams 

satisfied, Admiral Allen reauthorized the well integrity test. The test was to last from 6 to 

48 hours, and BP had to monitor pressure, sonar, acoustic, and visual data continuously, 

as recommended by the Well Integrity Team.283 Secretary Chu required BP to dedicate two 

remotely operated vehicles to visually monitor for leaks at the wellhead.

Although the Well Integrity Team had calculated that it would take a leak of approximately 

100,000 barrels for oil and gas to reach the sea floor, the government was prepared to 

permit a leak of only 20,000 barrels before requiring the capping stack to be reopened.284

Using an estimate for the expected pressure at shut-in derived from BP’s modeling of the 

reservoir, the Team developed guidelines for the length of the test.285 If the pressure at shutin was less than 6,000 pounds per square inch, major well damage was likely—BP would 
Chapter Five 165 165

have to terminate the test within six hours and reopen the well. If the shut-in pressure was 

greater than 7,500 pounds per square inch, the risk of a leak was low, and the test could 

proceed for the full 48 hours. Finally, if the shut-in pressure was between 6,000 and 7,500 

pounds per square inch, the risk of a leak was uncertain—either there was a medium-sized 

leak or the reservoir was highly depleted. Under this scenario, the test could proceed for 24 

hours. (See Figure 5.1.) If the pressure was too high, there was also the risk of causing a 

new rupture.

After a 24-hour delay to repair a minor leak, BP shut the stack and began the well 

integrity test at about 2:25 p.m. on July 15.286 For the first time in 87 days, no oil flowed 

into the Gulf of Mexico. Initial wellhead pressure readings were just over 6,600 pounds per 

square inch—in an uncertain middle range that one senior administration official termed 

“purgatory”—and rising slowly.287 Later that afternoon, the science advisors, including 

McNutt and Hunter, met with Secretaries Salazar and Chu to determine whether to keep 

the well shut in. Based on the early pressure data, the group appears to have been firmly in 

favor of reopening the well. Garwin, who had opposed even undertaking the well integrity 

test, voiced the strongest opinion, arguing BP ought to stop the test immediately and 

wondering whether it was already too late. No one at the meeting appears to have argued 

in favor of keeping the well closed.288

Following the science team meeting, Admirals Allen and Cook, Browner, Secretaries 

Chu and Salazar, and McNutt had a series of conversations to determine how to 

proceed. Keeping the capping stack shut could cause an underground blowout and, in 

the worst case, loss of a significant portion of the 110-million-barrel reservoir into the 

Gulf.289 This risk had to be balanced against the benefit of stopping the spill, a continuing 

FIGURE 5.1: Protocol for Well Integrity Test
166 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

environmental disaster. The government decisionmakers recognized that the public wanted 

the well plugged and the flow of oil into the Gulf stopped, but the risk of causing greater 

harm was real.

Admiral Cook made the argument that eventually prevailed. He reminded the others that, 

before the test began, BP and the government had considered the possibility of pressure 

measurements like those being observed. Both had agreed that, in such a case, the test 

should last 24 hours, with consultation between the parties before reopening the well.290

The government leaders decided that they should follow this protocol: the stack would 

stay closed overnight.

This additional time proved critical. Using a single cell-phone photograph of the plot of 

initial pressure readings, Paul Hsieh, a U.S. Geological Survey scientist then in Menlo 

Park, California, worked overnight to develop an explanation of the results of the test, 

including the lower-than-expected shut-in pressure. Pre-test expectations had been based 

on an incomplete understanding of the reservoir’s geometry and on pressure readings 

from a single gauge at the bottom of the BOP, which was only accurate to plus or minus 

400 pounds per square inch and functioning sporadically. At the government’s behest, 

BP had equipped the capping stack with pressure gauges.291 Following the shut-in of the 

well, those gauges provided accurate pressure data for the first time. Using that data along 

with a flow-rate estimate of 55,000 barrels per day and BP’s estimate that the reservoir 

contained 110 million barrels of oil, Hsieh was able to generate a model that predicted the 

observed shut-in pressure without having to assume a significant oil and gas leak into the 

rock formation.292

The next morning, the government principals and the science advisors—who had been 

convinced that reopening the stack was necessary—hosted a meeting. Both BP and Hsieh 

made presentations explaining the observed pressures at shut-in, with BP arguing that the 

well should remain capped.293 Participants had different recollections as to whether Hsieh’s 

or BP’s presentation carried more weight. But the outcome of the meeting was clear: the 

stack would stay shut, with the government reevaluating that decision every six hours.

While it went unrealized at the time, a critical point had passed. As intense monitoring 

of the area around the wellhead continued over the next several days, Hsieh’s model 

continued to predict the behavior of the well, and a leak into the formation became 

progressively less likely.294 Although the well integrity test had originally been scheduled 

to last a maximum of 48 hours, Admiral Allen began to extend it in 24-hour increments 

beginning on July 17. At his July 24 press briefing, he stated what was by then plain: “our 

confidence [in the capping stack] is increasing and we have better integrity in the well than 

we may have guessed.”295

Meanwhile, on July 19, BP publicly raised the possibility of killing the well before 

completing a relief well, through a procedure called a “static kill.”296 Like the top kill, the 

static kill involved pumping heavy drilling mud into the well in an effort to push oil and 

gas back into the reservoir. But because the oil and gas were already static, the pumping 

rates required for the static kill to succeed were far lower than for the top kill.
Chapter Five 167 167

The primary concern with the static kill was the pressure it would put on the well. On 

July 28, BP received an unsolicited letter from Pat Campbell, a Vice President at Superior 

Energy Services, which owned BP contractor Wild Well Control, recommending in no 

uncertain terms that the static kill not proceed. Campbell, who had worked with legendary 

well-control expert Red Adair, reiterated a point already raised by others in the industry: 

that the only pressure the well could withstand for certain was the current shut-in 

pressure (approximately 6,920 pounds per square inch at the time he wrote).297 

Despite these issues, after some delays caused by weather and work on the first relief well, 

the government approved the plan for the static kill on August 2.298 A mud injection test 

began on August 3, and pressure at the wellhead increased only slightly before beginning 

to drop.299 Based on the positive results of the test, BP began slowly pumping more drilling 

mud into the well later that same day. By 11:00 p.m., the static kill had succeeded.300 The 

following evening, Admiral Allen authorized BP to follow the mud with cement.301 BP 

finished cementing the next day. On August 8, Admiral Allen reported that the cement had 

been pressure-tested and was holding.302

The Fate of the Oil (August 4)

On August 4, the same day it announced the static kill’s success, the federal government 

released a 5-page report titled BP Deepwater Horizon Oil Budget: What Happened to the 

Oil?, as well as a 10-page supporting document titled Deepwater Horizon MC252 Gulf 

Incident Oil Budget.303 The “Oil Budget” provided the government’s first public estimate 

of the total volume of oil discharged during the spill—roughly 4.9 million barrels. The 

government arrived at this number using its current flow-rate estimate, which ranges 

from 62,200 barrels per day on April 22 to 52,700 barrels per day on July 14, just 

before the capping stack stopped the flow.304 *

 The Oil Budget also described the efficacy of 

different response methods. 

The Oil Budget was originally an operational tool, intended as a guide for responders, not 

as the basis for a scientific report on what happened to the oil. Nonetheless, in late July, 

the White House decided to publicly release the Oil Budget and asked NOAA to take the 

lead on drafting a short report to introduce the tool.305 The Budget cleared the interagency 

review process in time for its August 4 release.†

The White House’s Browner appeared on six morning newscasts on August 4 to discuss 

both the successful static kill and the Oil Budget report. On NBC, MSNBC, and ABC, she 

told viewers that, according to the report, “the vast majority,” or approximately threequarters, of the oil “is gone” or “appears to be gone.”‡

 The Budget, however, did not 

* The government’s estimate, which is current as this report goes to press, has an uncertainty factor of ±10 percent. It is the Commission’s understanding that the 

government’s Flow Rate Technical Group will issue a final report in January 2011. In a peer-reviewed paper published in Science Express on September 23, 2010, 

Timothy Crone and Maya Tolstoy of Columbia University’s Lamont-Doherty Earth Observatory estimated that the total release was roughly 5.2 million barrels—slightly 

higher than the government’s estimate. While BP has not released its own flow-rate figures, it has suggested that the government’s estimate of the total amount of oil 

released from the Macondo well is 20 to 50 percent too high.

† During the review process, EPA expressed concerns about the pie chart’s potential to obscure the uncertainty of the government’s estimates. Lisa Jackson, e-mail to 

Jane Lubchenco, July 31, 2010. For example, EPA recommended that NOAA combine chemically and naturally dispersed oil into a single category because there was 

not enough information to accurately distinguish between the two mechanisms. Bob Perciasepe, e-mail to Jane Lubchenco and others, July 31, 2010; Bob Perciasepe, 

e-mail to Stephen Hammond and others, August 1, 2010. NOAA disagreed. Administrator Jane Lubchenco asserted that combining the two categories would not 

decrease any uncertainty and that “‘[c]hemically dispersed’ is part of the federal response and ‘naturally dispersed’ is not, and there is interest in being able to sum up 

the federal response efforts.” Jane Lubchenco, e-mail to Bob Perciasepe and others, August 1, 2010.

‡ On the other three shows, Browner similarly stated that “what the scientists are telling us is that the vast majority of the oil has been cleaned, it’s been captured, it’s 

been skimmed, it’s been burned, mother nature has done its part” (Fox News); “our scientists are telling us that the vast majority of the oil has been contained, it’s been 

burned, it’s been cleaned” (CBS); and “our scientists and external scientists believe that the vast majority of the oil has now been contained, it’s been skimmed, mother 

nature has done its part, it’s been evaporated” (CNN).
168 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

show that most of the oil was gone. The three-quarters of the oil not in the “remaining” 

category included “dissolved” and “dispersed” oil that was potentially biodegrading, 

but not necessarily gone. By 9:00 a.m., NOAA Administrator Jane Lubchenco e-mailed 

Browner’s deputy and other officials to express her concern “that the oil budget is being 

portrayed as saying that 75% of the oil is gone”: “It’s not accurate to say that 75% of the 

oil is gone. 50% of it is gone—either evaporated or burned, skimmed or recovered from the 

wellhead.” Lubchenco asked the officials to “help make sure” the error was corrected.306*

She had made the same point to the White House before the Budget rollout; a July 30 

e-mail to Browner’s deputy had emphasized that Lubchenco opposed grouping dispersed 

oil with recovered oil because the former was “still out there or [was] being degraded.”307

At a press briefing that afternoon, Browner said that the report had “been subjected to a 

scientific protocol, which means you peer review, peer review, and peer review.” Earlier in 

the same briefing, Lubchenco had said “[t]he report was produced by scientific experts from 

a number of different agencies, federal agencies, with peer review of the calculations that 

went into this by both other federal and non-federal scientists.”308 The Budget, however, 

was not “peer-reviewed” as the scientific community uses that term. Many of the outside 

scientists listed as reviewers had not even seen the final report. 

The rollout of the Oil Budget drew immediate criticism, with scientists pointing out that 

Browner’s optimism about the percentage of the oil that was gone was unsupported, 

especially because of the uncertain rate of biodegradation.309 Moreover, after a summer 

of ever-increasing official estimates of the spill’s size, the public was dubious of the 

government’s conclusions. As aTimes-Picayune editorial noted, “From the start of the 

* The U.S. Geological Survey, which had also been involved in developing the Oil Budget tool and editing the report, expressed similar misgivings about the portrayal of 

the report. At 11:00 a.m., U.S. Geological Survey scientist Mark Sogge told a colleague, “We need to keep in mind, and make it clear to others, that this is NOT a [U.S. 

Geological Survey] product.” Mark Sogge, e-mail to Stephen Hammond, August 4, 2010. 

FIGURE 5.2: August 4 Oil Budget

* Oil in these three categories is 

currently being degraded 

naturally.

Residual*

26%

Evaporated or 

Dissolved

25%

Direct Recovery

from

Wellhead

17%

Naturally

Dispersed*

16%

Burned

5%

Skimmed

3%

Unified 

Command 

Response 

Operations

Residual includes oil 

that is on or just below 

the surface as light 

sheen and weathered 

tar balls, has washed 

ashore or been 

collected from the 

shore, or is buried in 

sand and sediments.

Chemically

Dispersed*

8%

Deepwater Horizon Oil Budget

Based on estimated release of 4.9m barrels of oil
Chapter Five 169 169

disaster. . . the government has badly underestimated the amount of oil spewing from 

the runaway well. That poor track record makes people understandably skeptical of [the 

Oil Budget] report.”310 Lubchenco has since acknowledged that she was “in error” when 

claiming that the Oil Budget had been peer-reviewed.311 NOAA has emphasized that the 

report’s “purpose was to describe the short-term fate of the oil and to guide immediate 

efforts to respond to the emergency” rather than to “provide information about the impact 

of the oil” or “indicate where the oil is now.”312

NOAA supplied these explanations on November 23, when it released a new version of 

the Oil Budget: Oil Budget Calculator Technical Documentation, a peer-reviewed report 

of over 200 pages that gave the formulas used and updated the percentages in the 

original budget.313 The new version’s biggest change was its estimate of the amount of 

oil chemically dispersed, which doubled from 8 percent to 16 percent. Of this additional 

8 percent, 3 percent came from the “naturally dispersed” category, 2 percent from the 

“evaporated or dissolved” category, and 3 percent from the “residual” category. (These 

changes brought the total amount of “residual” oil down from 26 to 23 percent.) 

As a tool for responders, the Oil Budget indicated that response and containment operations 

collected, eliminated, or dispersed about 41 percent of the oil, with containment (“direct 

recovery from wellhead”) the most effective method, and chemical dispersants breaking 

down a substantial fraction. Response technology (skimming or burning) removed—as 

opposed to dispersed—only 8 percent of the oil. Dispersion of the oil before it reached the 

surface limited the amount that responders could skim, burn, or disperse at the surface. 

Nevertheless, responders considered burning an important success: it had never before been 

attempted on this scale, and burning techniques advanced during the spill.314 Skimming 

was less of a success: despite the participation of hundreds of ships and thousands of 

people, it collected only 3 percent of the oil. 

The least effective response technology was the berms, which the Oil Budget documents 

do not even mention. By the time BP capped the well on July 15—day 44 of the berm 

construction project—Louisiana’s contractor estimated that 10 percent of one reach—6 

percent of the total project—had been completed.315 In late May, Governor Jindal had 

asserted that “[w]e could have built 10 miles of sand [berms] already if [the Corps] would 

have approved our permit when we originally requested it.”316 In fact, it took five months 

to build roughly 10 miles of berms, at a cost of about $220 million.317 Estimates of how 

much oil the berms collected vary, but none is much more than 1,000 total barrels.318 On 

November 1, Governor Jindal announced plans to convert the berms into part of a longterm coastal restoration project, which BP would continue to fund. In his recently released 

book, the Governor maintained that the berms were “one of the most effective protection 

measures” against oil reaching the Louisiana coast.319

The End of the Well, but Not the End of the Response

In mid-September, the first relief well—which BP had begun drilling in early May—finally 

intercepted the Macondo well, allowing BP to pump in cement and permanently seal the 

reservoir. On September 19, 152 days after the blowout, Admiral Allen announced: “the 

Macondo 252 well is effectively dead.”320
170 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

But fears about health and safety did not die with the well. Some Gulf residents continued 

to believe that BP had used dispersants onshore, nearshore, at night, and without 

government approval, and that it had continued using them after it capped the well. The 

Commission has not seen credible evidence supporting these claims. NOAA reopened onethird of the area closed to fishing on July 22 and continued to reopen additional sections 

based on a testing and sampling protocol developed and implemented with the Food and 

Drug Administration.321 But some scientists questioned the protocol, while some fishermen 

were hesitant to give up income from the Vessels of Opportunity program and return to 

their regular jobs in the midst of public concern about Gulf seafood.322 (Chapter 6 discusses 

seafood safety.)

Residents also had to cope with the miles of used boom and other debris. Despite the typical 

spill-responder uniform of rubber gloves and protective coveralls, BP planned to send 

the thousands of tons of oily debris generated over the summer to ordinary municipal 

landfills.323 Wastes from oil exploration and production are classified as non-hazardous by 

law and do not require specialized disposal.324 Although the federal government generally 

does not supervise the disposal of non-hazardous waste, on June 29, the Coast Guard 

and EPA issued a directive requiring BP to test its waste for hazardous elements, publicize 

the results, and consult with the communities where the waste was to be stored.325 In 

addition, EPA announced it would conduct its own twice-monthly testing of the debris 

and would post the results online.326 BP was initially slow to release its testing data. After 

receiving a sternly-worded letter from Federal On-Scene Coordinator Admiral Zukunft 

on July 24, however, it started regularly posting the results on its website.327 EPA began 

sampling the waste and posting the test data as well, after some criticism and delay.328 As 

of November 17, EPA’s tests had not shown any of the waste to be hazardous.329

As BP and EPA implemented the waste directives, environmental justice activists argued 

that BP was dumping the debris disproportionately in poor and non-white communities.330

Residents of Harrison County, Mississippi fiercely opposed the disposal of oiled waste in 

their Pecan Grove landfill, and BP agreed not to use it.331 Environmental justice advocate 

and scholar Robert Bullard contended that the racial makeup of Harrison County was a 

factor, and EPA objected to BP’s decision.332 The Federal On-Scene Coordinator instructed 

BP to follow the approved waste plan, noting that “[a]llowing one community to reject 

acceptance of waste. . . may complicate remaining waste disposal efforts.” BP began to use 

the site for waste staging, though not for disposal.333

With the well sealed, the number of responders in the Gulf decreased. The National Incident 

Command officially stood down on October 1.334 Admiral Allen turned over the remaining 

tasks to Federal On-Scene Coordinator Admiral Zukunft and finally retired. BP started to 

shut down some of its programs, and Coast Guard responders started to head to their 

next posts. The spill and the emergency response had ended. Figuring out the extent of the 

damage, and how to repair it, had begun.
Voices from the Gulf 171 17

Voices from the Gulf

“I don’t know what to do with 

myself.”

Dean Blanchard, Dean Blanchard 

Seafood Inc., Grand Isle, LA

Dean Blanchard runs Louisiana’s biggest shrimp 

business, on Grand Isle—a Mississippi River Delta 

barrier island 50 miles south of New Orleans, fully 

exposed to the Gulf of Mexico. During the warm months 

of a typical shrimp season, Blanchard Seafood and its 

extensive network of bayside wharves are a frenetic 

cacophony of languages and accents—Spanish, 

Vietnamese, a smattering of Cajun French, and the 

various Deep South dialects—as more than a thousand 

fishermen offload the catch from their shrimping vessels. 

The shrimp are sorted by size and dispatched into the 

world.

During 30 years in business, Blanchard had become one of the nation’s principal suppliers—and 

a multi-millionaire. In season, he bought as much as 500,000 pounds of shrimp daily from more 

than a thousand fishermen. The cold 2009-2010 winter had raised high hopes: “Every 10 years, 

when you get a cold winter, you get a really good shrimp crop,” he explained. “We were licking 

our chops.”

But with the Macondo well gushing more than 50,000 barrels of oil a day, and no end in sight, the 

brown shrimp season had been canceled just as it was about to start. By mid-May, tar balls and 

oil had started washing up onto Grand Isle’s wetlands and beaches. By mid-June, Blanchard 

figured, “I’ve lost $15 million of sales in the last 50 days. That would have been $1 million in my 

pocket.” The usually busy docks were quiet, the only activity the occasional coming and going 

of boats and crews working for BP cleaning and containing the oil.“I don’t know what to do with 

myself,” Blanchard explained. “I built all this over the last 30 years, and now for what?” “We’ve 

got 1,400 vessels that go and catch shrimp, come to our facility.” Now, he continued, “basically 

we’ve lost all our customers because we can’t supply them.”

For decades, oil and seafood had mixed comfortably in Louisiana’s coastal culture. Each year 

Morgan City hosted the annual Shrimp and Petroleum Festival, a rollicking celebration of the 

state’s two high-profile economic mainstays. Oil has long provided the region’s best-paying jobs, 

and the revenue to finance everything from state roads to free school books. The maritime world 

of seafood has deeper cultural roots, and provides a living and a way of life along the gulf coast, 

one of the nation’s most productive fishing waters. Many families had members in both worlds. 

Indeed, Blanchard’s own grandfather had made a fortune servicing the offshore oil industry.

But now those two worlds had collided—and everything seemed at risk. 

Susan Poag/The Times-Picayune. Photo © 2010 The 

Times-Picayune Publishing Co., all rights reserved. 

Used with permission of The Times-Picayune.

Chapter Six 173 173

Oiling a Rich Environment: Impacts 

and Assessment

When President Barack Obama addressed the nation 

from the Oval Office on June 15—nearly two 

months after the Macondo well began gushing 

crude oil and one month before engineers subdued 

it—he said: 

Already, this oil spill is the worst environmental 

disaster America has ever faced. And unlike an 

earthquake or a hurricane, it’s not a single event 

that does its damage in a matter of minutes or 

days. The millions of gallons of oil that have 

spilled into the Gulf of Mexico are more like an 

epidemic, one that we will be fighting for months 

and even years.1

The Deepwater Horizon blowout produced the 

largest accidental marine oil spill in U.S. history,2

an acute human and environmental tragedy. Worse 

still, as discussed in Chapter 7, it occurred in the 

midst of environmental disasters related to landbased pollution and massive destruction of coastal 

wetlands—chronic crises that proceed insidiously 

and will require not months but decades of national 

effort to address and repair. 

Chapter Six

“The worst 

environmental 

disaster 

America has 

ever faced.”

A lone beachgoer encounters bands of oil along Alabama’s Orange Beach. 

Though wind and currents helped keep most of the spilled oil offshore, all told 

some 650 miles of Gulf Coast habitat were oiled to one degree or another—

Louisiana was hardest hit—impacting ecosystems, the economy, and human 

health. 

< Tyrone Turner/Photo courtesy of National Geographic
174 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Laws guide resolution of damages from the spill itself. There is a suite of policies and 

programs aimed at improving discrete environmental issues within the Gulf and along 

its coast. The law also provides compensation for direct economic impacts. This chapter 

analyzes these immediate impacts, not only on the natural environment but also on the 

economy and on human health in the affected region. Unfortunately, the human-health 

effects are the least-recognized fallout from the spill, and those least-well addressed in 

existing law and policies.

The Impact on Nature

The Deepwater Horizon oil spill immediately threatened a rich, productive marine 

ecosystem. To mitigate both direct and indirect adverse environmental impacts, BP and the 

federal government took proactive measures in response to the unprecedented magnitude 

of the spill.3 Unfortunately, comprehensive data on conditions before the spill—the natural 

“status quo ante” from the shoreline to the deepwater Gulf—were generally lacking.4 Even 

now, information on the nature of the damage associated with the released oil is being 

realized in bits and pieces: reports of visibly oiled and dead wildlife, polluted marshes, and 

lifeless deepwater corals. Moreover, scientific knowledge of deepwater marine communities 

is limited, and it is there that a significant volume of oil was dispersed from the wellhead, 

naturally and chemically, into small droplets.5 Scientists simply do not yet know how to 

predict the ecological consequences and effects on key species that might result from oil 

exposure in the water column, both far below and near the surface.6 

Much more oil might have made landfall, but currents and winds kept most of the oil 

offshore, and a large circulating eddy kept oil from riding the Loop Current toward the 

Florida Keys.7 Oil-eating microbes probably broke down a substantial volume of the 

spilled crude, and the warm temperatures aided degradation and evaporation8—favorable 

conditions not present in colder offshore energy regions.9 (Oil-degrading microbes are 

still active in cold water, but less so than in warmer water.) However widespread (and in 

many cases severe) the natural resource damages are, those observed so far have fallen 

short of some of the worst expectations and reported conjectures during the early stages 

of the spill.10 So much remains unknown that will only become clearer after long-term 

monitoring of the marine ecosystem. Government scientists (funded by the responsible 

party) are undertaking a massive effort to assess the damages to the public’s natural 

resources. Additionally, despite significant delays in funding and lack of timely access 

to the response zone, independent scientific research of coastal and marine impacts is 

proceeding as well. 

A rich marine ecosystem. Particularly along the Louisiana coast, the Gulf of Mexico is 

no stranger to oil spills.11 But unlike past insults, this one spewed from the depths of the 

ocean, the bathypelagic zone (3,300–13,000 feet deep). Despite the cold, constant darkness 

and high pressure (over 150 atmospheres), scientists know that the region has abundant 

and diverse marine life. There are cold-water corals, fish, and worms that produce light 

like fireflies to compensate for the perpetual night. Bacteria, mussels, and tubeworms have 

adapted to life in an environment where oil, natural gas, and methane seep from cracks in 

the seafloor. Endangered sperm whales dive to this depth and beyond to feed on giant squid 

and other prey.12 
Chapter Six 175 175

Higher up the water column, light and temperature gradually increase and the ascending 

sperm whales—and Macondo well oil—encounter sharks, hundreds of fish species, shrimp, 

jellyfish, sea turtles, and dolphins. As the sperm whales surface for air at the bright and 

balmy Gulf surface, they pass through multitudes of plankton, floating seaweed beds, and 

schools of fish. Some of these fish species spend their early lives in the coastal waters and 

estuaries; others travel along annual migration routes from the Atlantic Ocean to the Gulf. 

The floating seaweed beds (sargassum), fish larvae, and plankton drift with the surface 

currents and are driven by the wind—as is the oil rising from below. The critical sargassum 

habitats lure sea turtles, tuna, dolphins, and numerous game fish to feed on the snails, 

shrimp, crabs, and juvenile species that seek shelter and food in the seaweed.13 

Overhead are multitudes of seabirds—among them brown pelicans, northern gannets, 

and laughing gulls—that in turn feed in the ocean and coastal estuaries.14 Dozens of bird 

species fly the Mississippi migration route each year, a major attraction for bird watchers, 

who flock to coastal Louisiana and Texas to catch a glimpse of migrating and resident 

shorebirds and nesting seabirds. Some of these birds feed on estuarine shrimp, fish, and 

crabs; others depend on shellfish and other small organisms that populate the expansive 

mudflats. Larger wading birds stalk their prey in the shallow water of mangroves, 

marshes, and other habitats that shelter fish and frogs. Raptors, including ospreys, bald 

eagles, and peregrine falcons, also pluck their prey from any of these environments and 

carry it to their perches.

As the unprecedented volume of oil gushing from the Macondo blowout reached the 

surface, it had the potential to affect all of these marine and coastal organisms and to 

wash into the salt marshes, mudflats, mangroves, and sandy beaches—each in its way an 

A dark tongue of oil invaded sensitive wetlands last May near Grand Isle, Louisiana, despite the presence of booms deployed to stop it. In 

a hopeful development over the summer, scientists found new plant growth in similarly oiled marshes, indicating that oil had not penetrated 

into root systems. 

Patrick Semansky/Associated Press

Elmer’s Island in Grand Isle, La.
176 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

essential habitat at one or more stages of many species’ lifecycles.15 And these marine and 

coastal species are so interdependent that a significant effect on any one has the potential to 

disturb several existing populations in this complex food web.16 

Encountering oil. Organisms are exposed to oil through ingestion, filtration, inhalation, 

absorption, and fouling.17 Predators may ingest oil while eating other oiled organisms or 

mistaking oil globules for food. Filter feeders—including some fish, oysters, shrimp, krill, 

jellyfish, corals, sponges, and whale sharks—will ingest minute oil particles suspended in 

the water column. Surface-breathing mammals and reptiles surrounded by an oil slick 

may inhale oily water or its fumes. Birds are highly vulnerable to having their feathers 

oiled, reducing their ability to properly regulate body temperature.18 Moderate to heavy 

external oiling of animals can inhibit their ability to walk, fly, swim, and eat. Similarly, 

oiling of plants can impede their ability to transpire and conduct photosynthesis, and 

oiling of coastal sediments can smother the plants they anchor and the many organisms 

that live below. 

Americans watched as the oil eventually came to rest along intermittent stretches of the 

Gulf coast. Before it arrived, scientists rushed to collect crucial baseline data on coastal and 

water-column conditions. Some of the oil propelled up from the wellhead was dispersed by 

natural and chemical means (as described in Chapter 5), creating a deep-ocean plume of oil 

droplets and dissolved hydrocarbons.19 A portion of the oil that rose to the surface was 

also naturally and chemically dispersed in the shallow water column.20 

The oil that made landfall was fairly “weathered,” consisting of emulsions of crude oil and 

depleted of its more volatile components. More than 650 miles of Gulf coastal habitats—

Wildlife biologist Mark Dodd surveys a raft of oil-soaked sargassum, also known as gulfweed. The floating beds are home to snails, shrimp, 

crabs, and other small creatures that—oiled or not—are ingested by turtles, dolphins, tuna, and game fish. 

Blair Witherington/FWC

Oiled Sargassum
Chapter Six 177 177

salt marsh, mudflat, mangroves, and sand beaches—were oiled; more than 130 miles have 

been designated as moderately to heavily oiled. Louisiana’s fragile delta habitats bore the 

brunt of the damage, with approximately 20 additional miles of Mississippi, Alabama, and 

Florida shorelines moderately to heavily oiled.21 Light oiling and tar balls extended east to 

Panama City, Florida. Except for occasional tarballs, Deepwater Horizon oil never reached 

Texas or the tourism centers along the southwest Florida coast.22 

Assessing the mixture of oil and life at the water’s edge. The most biologically productive 

area along a sandy beach occurs where seaweed and other organic materials wash up 

just above the high tide line in the “wrack zone.” Here, shorebirds forage for insects and 

other small organisms. As oil moves onto a beach with the rising tide, it is deposited in the 

wrack zone. Removing oiled wrack is the most prudent means of removing the oil—but 

doing so removes the living community, too. As the response to the spill proceeded, the 

Audubon Society evaluated wrack density along shorelines; it found that the wrack density 

on beaches east of the Mississippi River, where cleanup activities occurred, was “nearly 

absent,” indicating “diminished habitat quality.”23

Few beachgoers realize that millions of microscopic organisms live in the Gulf’s soggy 

sands between high and low tide. By comparing samples taken before and after beaches 

were oiled, Holly Bik of the University of New Hampshire’s Hubbard Center for Genome 

Studies, together with scientists at Auburn University and the University of Texas, 

hopes to determine the impact on this understudied community of sediment-dwelling 

microfauna.24

Tidal mudflats, generally devoid of vegetation and exposed at low tide, are more sensitive 

to pollutants than beaches.25 The Louisiana delta and the estuarine bays of Mississippi 

and Alabama have large expanses of tidal mudflats, which support dense populations 

of burrowing species (vulnerable to smothering), foraging birds, crabs, and other 

organisms.26 As oil settles on the flats, crabs and other burrowing animals help mix the oil 

into the sediment layer (an ecological process called bioturbation), extending the potential 

damage below the surface.27

Salt marsh and mangroves are both highly productive and sensitive habitats. Marsh 

grasses tolerate surface coating by weathered oil fairly well, but they will die if oil 

penetrates the saturated sediments and is absorbed by the root system.28 When that 

happens, the plants’ root systems degrade, making the marsh much more susceptible to 

erosion and threatening the habitat on which a wide variety of animals depend. People 

and equipment deployed in response to the spill can themselves damage the marsh; for 

example, summer storms pushed boom (used to corral waterborne oil) deep into the 

marshes, from which it could only be removed by intrusive methods that caused additional 

harm to the marsh topography.29 Scientists working in oiled marshes observed new plant 

growth during the summer of 2010—a positive sign that oil had not penetrated into the 

rich, organic soils and inhibited root systems.30 Professor Eugene Turner of Louisiana State 

University’s Coastal Ecology Institute plans to study the effects of oil on the local salt 

marshes for at least the next year. His preliminary observations, through the fall of 2010, 

indicate some stress resulting in loss of marsh along its edge, but the estimated loss “pales 
178 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

in comparison” to the annual loss associated with dredging and flood protection (described 

in Chapter 7).31

The marine impacts. When water temperatures warm in the late spring, female oysters 

release millions of eggs into the water column. The timing of the Macondo oil spill may 

have been detrimental to oyster reproduction and the spawning of many other species.32

Submerged oil floating in the nearshore water column poses potential threats to diverse 

shellfish and fish species. Although the impacts are not yet known, the presence of oil in 

the nearshore environment has been documented. Oil that reached the Gulf’s estuarine 

waters forced closures of and likely damaged substantial tracts of Louisiana oyster beds.33

Oyster mortality observed in the highly productive areas of Barataria Bay and Breton 

Sound, estuaries that flank the lower Mississippi River, appear to be due, in large part, to 

the flood of fresh water introduced through river diversions in what many believe was a 

futile attempt to keep oil from entering the estuarine areas.34 

Beyond their commercial import, oysters are a keystone species—an organism that exerts 

a shaping, disproportionate influence on its habitat and community.35 A single adult 

oyster can filter more than one gallon of water per hour, effectively removing impurities—

including oil—from the water column.36 Oyster reefs established on an estuary’s muddy 

bottom can increase the surface area fifty-fold, creating intricate habitats for crabs, small 

fish, and other animals, which in turn sustain larger species.37 

Harriet Perry, Director of the Center for Fisheries Research and Development at the 

University of Southern Mississippi, and scientists at Tulane University are studying the 

potential effects of oil on larvae of blue crabs, another keystone species. The slick from the 

Macondo oil spill ultimately covered about 40 percent of the offshore area used by larvae 

of the northern Gulf’s estuarine-dependent species.38 The Gulf coast’s blue crab population 

had already declined considerably during the past 8 to 10 years as a result of a regional 

drought.39 Perry and other scientists raced to take samples before the oil arrived and then 

after, hoping to be able to separate the oil-related impacts on wildlife from climate-related 

changes.40 

Many large fish species are dependent on the health of the estuarine and marine habitats 

and resources. The National Oceanic and Atmospheric Administration (NOAA) noted that 

species with “essential fish habitat”41 near the oil spill include scalloped hammerhead, 

shortfin mako, silky, whale, bigeye thresher, longfin mako, and oceanic whitetip sharks; 

and swordfish, white marlin, blue marlin, yellowfin tuna, bluefin tuna, longbill spearfish, 

and sailfish. Other important Gulf fish include red snapper, gag grouper, gray triggerfish, 

red drum, vermilion snapper, greater amberjack, black drum, cobia and dolphin (mahimahi); coastal migratory open-water species, such as king and Spanish mackerel; and 

open-water sharks.42

Oil in the water column affects fish and other marine organisms through dermal contact, 

filtration, or ingestion. How much oil they accumulate depends on its concentration in 

food, water, and sediments they encounter, time and exposure, and the characteristics of 

each species—particularly the extent of their fatty tissue. Although oil is not very soluble 
Voices from the Gulf 179 179

Voices from the Gulf

“I have to make house payments 

and boat payments.” 

Ve Van Nguyen,

Oysterman, Buras, LA

Ve Van Nguyen was an 

oystermen working for one of 

the suppliers to P&J Oyster 

Company. A Vietnamese 

refugee who fled his homeland 

with his wife and young family 

in a boat in 1978, Van Nguyen 

had made it to the United 

States. He eventually settled in 

Buras, located in Plaquemines 

Parish in 1983, joining a large 

Vietnamese and Cambodian 

community that found limited 

English skills no impediment to earning a living fishing and shrimping. He had been a fisherman 

in Vietnam, and as he explained in his native language, “I grew up near the sea and I’m used to 

eating seafood. I wanted to live where there’s lots of seafood.” He and his wife had both worked 

on the water, and in recent years they had purchased two specially outfitted oystering boats, 

in addition to two other boats used for gill fishing. They had loans to repay. In 2009, when they 

had $80,000 in income from harvesting oysters, that was not a problem. Their four children were 

grown, with one still at home.

When Van Nguyen heard on television about the oil spill, he recalls, “I felt that I was going crazy 

and was really worried that I can’t work anymore. I was afraid that the oil would spread and 

people can’t eat what we catch so I wouldn’t be able to work. So I was going through a mental 

crisis.” Louisiana has about 25,000 Vietnamese Americans. 

All through May, the Macondo well gushed oil as the government was closing Louisiana oyster 

beds. Ve Van Nguyen and his wife both found interim work using their boats to install booms 

against the spreading oil slicks, as part of BP’s clean up. But he made nowhere near as much 

money as he would have harvesting oysters. Like so many others around the Gulf, he said, 

“I worry about myself and my wife. I don’t know how we can make it.” He had received some 

BP payments, but wondered how long those would go on? “I have to make house payments 

and boat payments.” At age 60, he was no longer young, but certainly expected to continue 

oystering. But now, if BP does not compensate him for an amount similar to the lost income, “I 

can’t do anything except for applying for welfare and food stamps.” He had had his four boats 

towed back to his house. The future? “Everyone is worried and scared about that. They are 

scared of poisoning so we have to rely on the government to take care of it. I don’t know what will 

happen.”

Claire Luby
180 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

in water, oil and lipids do mix very well, so high concentrations of petroleum can be found 

in the fat-rich tissues of the liver, brain, kidneys, and ovaries. Muscle generally has the 

lowest lipid concentrations, but fish with fatty flesh can accumulate more oil than leaner 

species.43 Oil constituents can be transferred through the food chain: heavier hydrocarbons 

can be passed from water to phytoplankton and then to zooplankton, or from sediments 

to polychaete worms and eventually to fish.44 Because animals that are several steps 

up the food chain, like small fish, have the capability to metabolize hydrocarbons fairly 

rapidly, their predators will actually not accumulate much from eating them. Accordingly, 

bioaccumulation of toxic oil components does occur in fish, but biomagnification, with 

increasingly higher concentrations in animals at each level, does not occur.45

It would be impossible to sample and assess each of the thousands of marine fish and other 

species inhabiting the open-ocean water column. But scientists monitoring the spill along 

the shorelines and aboard research vessels have sampled plankton, shellfish, fish, water, 

sediment, and other environmental media to better understand the potential impacts on all 

terrestrial and marine organisms.46 Tens of thousands of samples have been collected. They 

will likely analyze the samples to determine concentrations of oil and dispersants, and 

combine that information with existing data on species populations and distributions to 

model the potential impact of contamination in the water column on different species.

In addition, large fish—like bluefin tuna and whale sharks (the world’s largest fish)—

mammals, and turtles are being tagged with tracking devices so scientists can follow 

Sad testament to the spill, a sea turtle lies dead beside the black tide that took its life along East Grand Terre Island in Louisiana. As of 

November 2010, the carcasses of more than 600 of the endangered reptiles had been collected. Countless others undoubtedly perished.

Benjamin Lowy/Edit by Getty Images

Turtle in East Grande Terre Island, LA
Chapter Six 181 18

their movements in the hope of learning how they have been affected by the spill.47 By 

overlaying maps of the extent of the oil spill, derived from satellite images from the 

European Space Agency, with simulations of bluefin tuna spawning grounds and models 

of larval development, the Ocean Foundation estimated that the spill could have affected 20 

percent of the 2010 season’s population of bluefin tuna larvae, further placing at risk an 

already severely overfished species.48

Birds, mammals, turtles. Oiled birds are often the most visually disturbing and widely 

disseminated images associated with a major oil spill—as in the landmark Santa Barbara 

accident of 1969.49 Through November 1, 2010, wildlife responders had collected 8,183 

birds, 1,144 sea turtles, and 109 marine mammals affected by the spill—alive or dead, 

visibly oiled or not.50 Given the effects of hiding, scavenging, sinking, decomposition, and 

the sheer size of the search area, many more specimens were not intercepted.51 Therefore, 

scientists will assess the estimated total damage by applying a multiplier to the final 

observed number of casualties, and will likely issue separate estimates of sub-lethal effects 

and the impact of the spill on future populations. 

In September 28 testimony before the Commission, Jane Lyder, Deputy Assistant Secretary 

of the Department of the Interior for Fish and Wildlife and Parks, said that “With more 

than 60 percent of the data verified, the three most affected [bird] species appear to 

be Brown Pelicans, Northern Gannets, and Laughing Gulls.” She added that “The fall 

migration is underway. Songbirds and shorebirds began their migration to the Gulf coast 

in July. Waterfowl began arriving in late August and early September. We know there are 

significant impacts to marsh and coastal wetland habitats along sections of the Louisiana 

coast, particularly near Grand Isle, Louisiana. We are continuing to monitor what the full 

impact will be to migratory birds and other wildlife.”52

The potential impact on marine mammals and sea turtles is harder to assess. Tim Ragen, 

Executive Director of the federal Marine Mammal Commission, testifying before a House of 

Representatives subcommittee on June 10, 2010, could only conclude, “Unfortunately, the 

scientific foundation for evaluating the potential effects of the Deepwater Horizon spill on 

many marine mammals inhabiting the Gulf is weak.”53

According to NOAA, “Of the 28 species of marine mammals known to live in the Gulf 

of Mexico, all are protected, and six (sperm, sei, fin, blue, humpback and North Atlantic 

right whales) are listed as endangered under the Endangered Species Act.” Also of note, “At 

least four species of threatened/endangered sea turtles (Kemp’s ridley, green, leatherback, 

and loggerhead) are residents of the northern Gulf of Mexico and are represented by all life 

stages. A fifth species, the hawksbill turtle, can be found in the southern Gulf. The only 

nesting beaches in the world for Kemp’s ridley turtles are in the western Gulf of Mexico.”54

As of November 1, the Unified Area Command reported that nine marine mammals had 

been collected alive (and three were released).55 One hundred mammals were collected dead, 

though only four of those were visibly oiled. Most of the marine mammal mortalities were 

bottlenose dolphins.56 Also among the dead was one juvenile sperm whale; it was found 

floating more than 70 miles from the source of the spill, reportedly unoiled.57 More than 

600 dead sea turtles were collected.58 
182 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Deepwater plumes of dispersed oil. The highly visible damage to wildlife aside, public and 

scientific concern about the Deepwater Horizon spill—at unprecedented water depths—

has for some time focused on the impacts of an invisible subsurface “plume,” or more 

accurately “clouds” of minute oil droplets moving slowly over the seabed. As of November 

2010, three independent, peer-reviewed studies59 confirmed the presence of a deepwater 

plume of highly dispersed oil droplets and dissolved gases at between 3,200 and 4,200 feet 

deep and extending for many miles, primarily to the southwest of the wellhead. 

How will such substances affect the deepwater environment? One concern centered 

on decomposition and the resulting depletion of the oxygen supply on which aquatic 

species depend. Bacterial decomposition begins quickly for the light hydrocarbon gases, 

propane and ethane, but more slowly for the heavier hydrocarbons typically present in 

a liquid form and for the predominant gas, methane. The blooms of bacteria stimulated 

by lighter hydrocarbons prime the populations for degradation of other hydrocarbons. 

The degradation rates are sufficient to reduce the dissolved oxygen concentrations in 

the plume, but not to harmfully low levels associated with dead zones, where aquatic 

species cannot survive.60 Subsequent mixing with adjacent, uncontaminated waters by 

slow-flowing currents appears to have been sufficient to prevent any further depletion of 

dissolved oxygen in the aging plumes.61 These findings do not rule out potential impacts 

of deepwater oil and dispersant concentrations on individual species.62 Chemical analyses 

of water samples taken from the established deepwater plume in May 2010 suggest that 

hydrocarbon concentrations were high enough at the time to cause acute toxicity to 

exposed organisms,63 although concentrations declined over several miles from the well as 

the plume mixed with the surrounding water. 

Federal scientists have estimated that about 15 percent of the oil escaping the wellhead 

was physically dispersed by the fluid turbulence around the flow of oil and gas. The 

deepwater plume would have formed even if chemical dispersants had not been injected 

at the wellhead. But the addition of 18,379 barrels of dispersants to the discharging oil 

and gas stream may have increased the volume of oil in the deepwater plumes to a degree 

comparable to that from physical dispersion alone.64 As of late 2010, there have been 

unconfirmed reports of oil deposited on the seafloor in the vicinity of the Macondo well.65

If confirmed by chemical analyses, this would not be particularly surprising because 

oil droplets can become entrained in denser particulate matter, including the flocks of 

organic matter (referred to by scientists as “marine snow”) that characterize open-ocean 

waters, and settle on the ocean floor. There have also been recent reports of dead or dying 

deepwater corals living on rock outcrops that could have been impinged by the deep 

plumes.66 

Because the Deepwater Horizon spill was unprecedented in size, location, and duration,67

deepwater ecosystems were exposed to large volumes of oil for an extended period. It 

will take further investigation and more time to assess the impacts on these ecosystems, 

their extent and duration. Unfortunately, except for studies that have focused on rare and 

specialized communities associated with rocky outcrops or seeps, scientific understanding 

of the deepwater Gulf ecosystem has not advanced with the industrial development of 

deepwater drilling and production.68 
Chapter Six 183 183

Natural Resource Damage Assessment 

The federal Oil Pollution Act (OPA or the Act) creates a process for assessing the damages 

caused by an oil spill and then the expenditure of monies collected to address those 

damages. To that end, the Act formally designates “natural resource trustees,” who are 

responsible for assessing the “natural resources damages” of the spill.69 (Figure 6.1) The 

trustees accordingly prepare a “natural resource damage assessment” that seeks to quantify 

oil-spill damages to: (1) public natural resources; (2) the services they provide (e.g., oysters 

provide water filtration); and (3) the public’s lost use of those resources.70 For the Macondo 

spill, NOAA and the Department of the Interior are leading the effort as trustees on behalf 

of the federal government.71 The Department of Defense will also participate on behalf of 

affected military property along the Gulf coast.72 The federal representatives will be joined 

by natural resource trustees from the five Gulf States.73 

Identifying and quantifying damages, particularly where complex ecosystems are involved, 

present enormous challenges. Developing sound sampling protocols that cover adequate 

time scales, teasing out the effects of other environmental disturbances, and scaling the 

damages to the appropriate restoration projects often takes considerable time. A typical 

damage assessment can take years. Two sets of determinations—one concerning the 

baseline conditions against which damages to each species or habitat will be assessed and 

Wellhead

BIRDS

 • Aerial surveys

 • Ground surveys

 • Nearshore boat

 surveys 

 • Offshore boat 

 surveys

 • Radio telemetry

TERRESTRIAL AND

AQUATIC SPECIES

 • Ground surveys

 • Observations of the 

 quality of habitat

HUMAN USE

 • Aerial surveys 

 • Ground surveys 

WATER COLUMN

AND SEDIMENTS

 • Water quality surveys 

 • Transect surveys to 

 detect submerged oil

 • Oil plume modeling 

 • Sediment sampling

AQUATIC

VEGETATION

 • Aerial surveys 

 • Field surveys in 

 large beds of 

 aquatic vegetation

SHORELINES

 • Aerial surveys 

 • Ground surveys

 • Observations of the

 quality of habitat 

 • Measurements of 

 subsurface oil near the 

 shore 

FISHERIES

 • Plankton surveys

 • Invertebrate surveys

 • Adult fish surveys

 • Larval fish surveys

SHELLFISH

 • Oyster surveys

 • Tissue and

 sediment 

 sampling

 • Mussel collection

 • Shrimp collection

TURTLES AND

MARINE MAMMALS

 • Aerial surveys 

 • Tissue sampling 

 • Acoustic

 monitoring

 • Satellite tagging

CORALS

 • Coral surveys

 • Tissue collections

 • Contaminant 

 surveys

Figure 6.1: Assessment Categories for Natural Resource Damage Assessment

This figure represents the various natural resource categories being assessed as part of the Deepwater Horizon Natural Resource Damage 

Assessment. Such an assessment, which always follows an oil spill, is used to make the public whole for ecological damages caused by a 

spill. This graphic illustrates the three-dimensional challenges that an assessment of a deep sea blowout presents.

NOAA (adapted)
184 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

another concerning the quantification of those damages—are particularly difficult and 

consequential in terms of the overall results. 

The goal of a natural resource damage assessment is “to make the environment and 

public whole for injuries to natural resources and services resulting from [an oil spill].”74

The injury is quantified by reference to baseline conditions: “the condition of the natural 

resources and services that would have existed had the incident not occurred.”75 But 

making this determination is often inherently difficult and highly contentious. Without 

well-established baseline conditions, there can be inaccurate quantification of damages 

or required restoration. Given that the ecological baseline can vary seasonally, annually, 

and over much longer time scales, it can be difficult to pinpoint the exact condition of 

an ecosystem prior to a spill. Because long-term historical data are often nonexistent 

or discontinuous, natural resource trustees are likely to be disadvantaged by a lack of 

sufficient information to fully characterize the condition of relevant ecosystems prior to 

the incident in question.76

As OPA regulations indicate, “baseline” for purposes of damage assessment is generally 

considered to be the condition of the resource just prior to the spill.77 The precise 

application of this definition has particular importance in the Gulf of Mexico context, 

where many coastal habitats have been substantially degraded over decades—even 

centuries—under the pressure of ever-expanding industrial, commercial, and residential 

development. The natural resource damage assessment regulations, as generally applied, 

require that BP and other potentially responsible parties restore Gulf resources to their 

functioning level as of April 19, 2010—by which point the Gulf ecosystem in April 2010 

was already weakened.78 In this context, effective long-term restoration will require the 

stabilization and eventual reversal of a number of long-standing, damaging trends. 

The effort to thoroughly address the ecological impacts of this historic pollution event 

is unprecedented in scale. Thousands of samples have been collected from dozens of 

research cruises. Hundreds of miles of coastline have been observed and sampled.79 Marine 

mammals and turtles are being observed aerially and monitored by satellite or radio 

tracking devices.80 The assessment of natural resources damages is the largest and most 

complex that the government has ever undertaken to assess oil spill impacts. 

Supporting independent scientific research. Apart from these governmental efforts, 

independent scientists have also sought to study the spill’s impacts. But funding for 

academic and other scientists in the days and weeks immediately after the spill was 

limited.81 As a result,the nation lost a fleeting opportunity to maximize scientific 

understanding of how oil spills—particularly in the deep ocean—adversely affect individual 

organisms and the marine ecosystem. Such research depends on sampling, measurements, 

and investigations that can be accomplished only during and right after the spill. 

The National Science Foundation tried to fill the gap by funding studies under its Grants 

for Rapid Response Research (RAPID) Program, aimed at better understanding potential 

impacts to coastal and marine habitats and resources.82 Through September 2010, the 

Foundation funded 167 Deepwater Horizon research projects totaling $19.4 million.83 The 

Foundation became practically the sole provider of emergency funding for independent 
Chapter Six 185 185

scientists as the disaster unfolded. Nevertheless, the Program was not a panacea—because 

individual RAPID grants cannot exceed $200,000 per year, many scientists were left 

to seek additional funding to pay for the necessary, costly chemical analyses of their 

environmental samples. 

In May, BP committed to provide $500 million for independent research on ecosystem 

assessment, impacts, and recovery efforts. Unfortunately, for multiple procedural and 

political reasons, by late November 2010 BP had only allocated a small portion of that 

money.84 BP has since announced that it intends to work through the Gulf of Mexico 

Alliance, an organization led by the five Gulf coast governors, to implement this research 

program.85 Here too, meaningful scientific inquiry will need to include long-term 

monitoring of the impacts of the spill on the Gulf’s marine and coastal ecosystems. 

With numerous studies under way through both the government’s damage-assessment 

process and independent scientific research, the published literature regarding 

environmental impacts from the Macondo blowout can be expected to grow substantially. 

Major research commitments, totaling hundreds of millions of dollars, have already been 

made.86

Economic Impacts

The Deepwater Horizon oil spill put at risk two enormous economic engines that rely on it. 

Tourism and fishing, the industries affected as collateral damage, were highly sensitive to 

both direct ecosystem harm and, indirectly, public perceptions and fears of tainted seafood 

and soiled beaches. For this reason, whatever uncertainty may exist about the immediate 

and long-term adverse environmental impacts of the oil spill, no such uncertainty exists 

in terms of the significant adverse economic effects—especially from loss of confidence in 

commercial fishing.87 The Gulf coast’s economy depends heavily on commercial fisheries, 

tourism, and energy production88—each directly and immediately affected by the oil 

gushing from the Macondo well. Federal and state closures of commercial fisheries—a 

precautionary public-health measure—at once suspended much of the fishing and 

processing industry;89 public concern nationwide that seafood was not safe to eat further 

compounded the economic impact along the Gulf.90 Similarly, public perception that 

otherwise clean beaches were, or would become, oiled or that air quality during peak 

vacation season was impaired led to declines in hotel bookings, restaurant seatings, and 

a wide array of coastal activities.91 Claims for losses have been submitted by real-estate 

agents and developers,92 fishing charters,93 and even an Alabama dentist who alleged a loss 

of summer customers.94 And the Gulf oil and gas industry, its workers, and the regional 

economy were affected as the federal government imposed a moratorium (described in 

Chapter 5) on deepwater drilling intended to prevent another disastrous spill while the 

causes and consequences of the blowout were evaluated.95 

That BP agreed to place in escrow a $20 billion fund to help address financial losses, at 

President Obama’s urging, indicates the magnitude of the economic impact from the loss of 

control of this one deepwater well.96 In its first eight weeks of operation, as of November 

23, the independently administered Gulf Coast Claims Facility had paid out more than 

$2 billion to approximately 127,000 claimants.97 By comparison, during its two-year 
186 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

lifespan, the September 11th Victim Compensation Fund awarded just over $7 billion to 

5,560 individual claimants.98 

It is currently not clear, however, the extent to which the enormous indirect economic 

impacts associated with loss of consumer confidence and injuries to the Gulf coast “brand” 

will ultimately be deemed compensable and that resulting uncertainty has generated 

intense debate among diverse government entities, local communities, interest groups, and 

BP. The federal Oil Pollution Act, for instance, does expressly recognize the appropriateness 

of compensation for “loss of profits or impairment of earning capacity resulting from 

property loss or natural resource injury.”99 But there is no easy legal answer to the 

question of how closely linked those lost profits or earnings must be to the spill before 

they should be deemed compensable. The search for such a rational endpoint for liability 

has already stymied the Gulf Coast Claims Facility in its processing of claims.100 The 

absence of clear and fair procedures for systematically evaluating such claims deserves 

focused attention as the lessons from the Deepwater Horizon oil spill are learned. 

The major industries in the “hardest working basin.” Florida State University 

oceanographer Ian McDonald has called the Gulf of Mexico “the hardest working of our 

ocean basins.”101 The southern coast of the United States produces more than one-third 

• $0–$200,000 • $1,000,000–$1,200,000 • $2,000,000+

• $200,000–$400,000 • $1,200,000–$1,400,000

• $400,000–$600,000 • $1,400,000–$1,600,000

• $600,000–$800,000 • $1,600,000–$1,800,000

• $800,000–$1,000,000 • $1,800,000–$2,000,000

Source: 2007 U.S. Economic Census

Note: Tourism includes: sporting goods stores, scenic/sightseeing transport (water), fishing clubs/guides, hunting/fishing reserves, 

camps, boat rentals, hotels, casinos, and nature parks. Fishing inlcudes: finfish, shellfish, other seafood, canning, frozen seafood,

seafood markets and wholesalers.

TX

FL

AL LA

MS GA

Houston

New Orleans

Miami

Mobile

Corpus

Christi

Tampa

Figure 6.2: Annual Tourism & Fishing Revenue: Economic Activity by County

Source: 2007 U.S. Economic Census

Note: Tourism includes: sporting goods stores, scenic/sightseeing transport (water), fishing clubs/guides, hunting/fishing reserves, 

camps, boat rentals, hotels, casinos, and nature parks. Fishing inlcudes: finfish, shellfish, other seafood, canning, frozen seafood,

seafood markets and wholesalers.
Chapter Six 187 187

of the nation’s domestic seafood supply,102 including most of the shrimp, crawfish, blue 

crabs, and oysters.103 It produces one-third of all domestic oil,104 and claims four of the top 

seven trading ports by tonnage.105 The northern Gulf also provides diverse fish nursery 

and feeding grounds in the form of expansive marshes, mangrove stands, swamp forests, 

and seagrass beds, and boasts some of best beaches and waters in the United States for 

recreation and tourism.106 Coastal tourism and commercial fisheries generate more than 

$40 billion of economic activity annually in the five Gulf States.107 (Figure 6.2) 

In 2008, according to NOAA, Gulf commercial fishermen harvested 1.27 billion pounds 

of finfish and shellfish that earned $659 million in total landings revenue.108 Other 

contributors to the total Gulf fishing economy are seafood processors, warehouses, 

distributors, and wholesalers. Gulf fishermen land 73 percent of the nation’s shrimp—half 

from Louisiana waters. Louisiana accounts for 67 percent of the nation’s oyster production 

and 26 percent of the blue crab production.109 

As described in Chapter 5, NOAA and state fisheries agencies responded to the Deepwater 

Horizon spill by closing huge portions of the Gulf to commercial and recreational fishing. 

At the most extensive point, 88,522 square miles of the Gulf of Mexico were closed to 

fishing110—one-third of the U.S. portion of the Gulf of Mexico, an area larger than the six 

New England states. In mid-June, NOAA and the Food and Drug Administration (FDA) 

released a protocol for reopening fisheries that would apply consistently to state and 

federal waters while striking a balance between keeping tainted seafood from market and 

unnecessarily crippling the seafood industry.111What ensued was likely the most rigorous 

seafood-testing campaign in U.S. history. 

By late September, when nearly 32,000 square miles of the Gulf were still closed to 

fishing,112 government officials made strong statements about the safety of seafood caught 

in reopened areas. “The shrimp, fish, and crabs are perfectly safe to eat,” claimed Bob 

Dickey, Director of Seafood Science and Technology at the FDA.113 Bill Walker, Executive 

Director of the Mississippi Department of Marine Resources, pronounced that “based 

on credible scientific data collected using federally-approved sampling and analytical 

techniques, Mississippi seafood has been safe and healthy to eat throughout the entirety 

of this event.”114 NOAA Administrator Jane Lubchenco stated, “I have confidence in our 

protocols and have enjoyed Gulf seafood each trip I’ve made to the region.”115 

But despite these assurances, some citizens continue to doubt the safety of Gulf 

seafood. "Everybody's credibility has been damaged by all this," said Ian MacDonald. He 

continued, "[The] many changes of course that NOAA took. The great concern about [the 

Environmental Protection Agency] and the licensing of dispersant use. The fact of the way 

it was handled has undermined public confidence."116 Florida journalist Travis Pillow asked, 

“If people couldn’t believe [the government’s] estimates of how much oil was gushing into 

the Gulf, how could they believe their reassurance that beaches were clean or seafood was 

safe?”117 

Constant media coverage about the spill also plainly shaped citizens’ perception of the 

risks to public health. According to Timothy Fitzgerald, Senior Policy Analyst for the 
188 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Environmental Defense Fund’s Ocean Program, “Most people have very little connection 

to, or understanding of, the fish they buy,”118 increasing their reliance on mass media 

to inform their decisions.119 Scott Dekle, general manager of the VersaCold Atlas seafood 

warehouse, noted that news of the spill “got plastered all over the local and national media 

day after day after day. No one sees Anderson Cooper now standing outside Southern 

Seafood saying, ‘This is great.’”120 As a result, the public has come to associate Gulf 

seafood with oil. In August, Jonah Berger, a marketing professor at the University of 

Pennsylvania’s Wharton School, said of Gulf seafood, “[R]ight now, the only association is 

a negative one, and so it’s going to be much harder for that association to disappear.”121

Most commercial Gulf seafood species seem to have emerged from the oil spill without any 

clear evidence of taint or contamination.122 The real impact here is the reputational damage 

to Gulf seafood as a safe brand. Continued government testing, improvements in public 

outreach, and a coordinated marketing campaign may be needed to expedite its recovery. 

After several requests over several months, BP relented in early November and agreed to 

give Louisiana $48 million and Florida $20 million for seafood testing and marketing.123

As of early December, BP is considering a similar request from Alabama.124

Vendor Sign at Taste of Chicago

Perception is reality for the Gulf seafood industry. The economic calamity that descended when commercial fisheries were closed as a healthsafety precaution should have been alleviated when they reopened, but the public still wasn’t buying. Fact: After a rigorous testing campaign, 

most commercial species appear untainted.

Albert Ettinger
Voices from the Gulf 189 189

Voices from the Gulf

“We were called liars when we said 

we didn’t have oil on the beaches” 

Patricia Denny, Destin, FL

On May 2, 1985, Patricia Denny took a job as a secretary in a brand 

new real estate company in Destin, Florida, a small Emerald Coast 

family beach town proud of its white beaches and green waters. She 

married, had two girls, and worked hard at Holiday Isle Properties, rising 

to General Manager, where she managed 177 vacation rentals. In 2009, 

her longtime boss retired and Denny became the owner. “I was beyond 

excited. My dream was coming true—all the late hours, 7-day work 

weeks. Something I felt so passionate about was finally happening.” 

In her 24 years as a property manager, Denny has weathered some 

tough years: “I truly never thought things could be worse than 2004-5. Not only did the real estate 

market come to an abrupt halt, we had hurricane after hurricane. . . . But we rebounded on our 

own—no hand-outs, no help from government or our insurance company.”

In late April 2010, when Denny saw the news on TV about the Deepwater Horizon explosion, “I 

remember thinking, ‘How awful,’ but the news reported that BP was going to stop the oil from 

spewing and all would be well. . . . Then NOAA predicted a shift in the weather and that impact 

from the oil was imminent. I was devastated. I couldn’t sleep, I couldn’t eat. It was the worst 

time of my life. Everything was at risk—my home, my income, my children’s education, my three 

employees who are like a family to me.” 

In early May, to show that their pristine beaches were still sugary white, “We started filming 

daily and sometimes twice daily a video for YouTube called Shore Shots. It involved one of my 

employees standing in front of the camera and showing the Gulf of Mexico and the lack of oil 

despite being told otherwise. . . . It was not always well received. We were called liars when we 

said we didn’t have oil on the beaches and told we were poisoning people with Corexit for our 

own greedy gain. It was definitely tough.

“By July the oil was here. No way I could prevent it from coming on – revenue dropped 

significantly. By August it was awful. No one, I mean no one, believed that we weren’t covered in 

oil similar to the Exxon Valdez.”

Denny’s older daughter was a junior and biology major at the University of Alabama in 

Birmingham. As the cancellations rolled in, the young woman withdrew from college in July for 

what would have been her senior year. She moved home to help her mother run the company.“ It 

breaks my heart to see her do this,” says Denny. “I am hoping she can go back sometime in the 

future but at this time I don’t know when that is.”*

*In early December 2010, Denny received compensation for her losses from the Gulf Coast 

Claims Facility, administered by Kenneth Feinberg and funded by BP.

Joe Mayer
190 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Public Health Precautions

A sign of the times is posted at a public beach in Alabama. Long viewed strictly as environmental disasters, major oil spills can be hazardous 

to human health, beyond direct fatalities or injuries. Many Gulf Coast residents have complained of respiratory problems and headaches, and 

depressive illness has skyrocketed. 

Rocky Kistner/NRDC
Chapter Six 191 19

Coastal tourism. The Gulf coast generates an estimated $19.7 billion of tourism activity 

annually.125 Florida accounts for more than 50 percent of the total126 and, accordingly, 

attributes enormous actual and potential losses in tourism-related revenue to the oil spill. 

Quantifying such losses and the value of reputational damage may be even more difficult 

than assigning a value to the indirect losses suffered by the Louisiana fishing industry. 

Furthermore, responsibility for compensating those who may have suffered the indirect 

financial losses poses challenges of law, administration, and equity. 

Floridians expressed frustrations with the news coverage of the oil spill—not all of it 

accurate. As described by Keith Overton, Chairman of the Florida Restaurant and Lodging 

Association and Chief Operating Officer of the TradeWinds Island Resorts in St. Pete Beach, 

in testimony before the Commission in July 2010, “These losses have occurred in our area, 

in the Tampa Bay area, without a single drop of oil ever reaching our beach and that is true 

for most of Florida. Pensacola has had some oil but the rest of the Panhandle is in pretty 

good shape right now. But you wouldn’t know that if you looked at the national news 

media or you read the newspaper each day.”127 With dismay, he described a newscast that 

showed footage of President Obama walking along an unoiled Pensacola beach in midJune, but with superimposed oil dripping down the screen behind him. 

Just as the potential extent of the spill’s impact was coming into focus, Michael Hecht, 

President of Greater New Orleans, Inc., a regional economic alliance in southeast Louisiana, 

testified in July that “going forward . . . this perception, this brand issue, is incredibly 

important.”128 A Louisiana-commissioned national poll conducted in early August 2010 

found that 29 percent of respondents who were planning to visit the state said they were 

actively canceling or postponing their visits because of the oil spill.129 Overton noted that 

the downturn in hotel reservations through June 2010 in unoiled Pinellas County had cost 

roughly $70 million and could total in the billions for the Florida Panhandle. 

Human Health 

Because oil spills have historically been viewed as environmental disasters, affecting 

nature, the Oil Pollution Act of 1990 and related policies offer fewer tools for addressing 

the human dimensions of such accidents. But in the case of the Macondo blowout—of 

unprecedented size, affecting a broad area, and the entire regional economy—assessment 

of impacts must also include the effects on human health, mental and physical. The 

Deepwater Horizon crew of course bore the immediate, devastating effects of the rig’s 

destruction: 11 deaths, 17 injuries, and the unquestioned trauma of losing colleagues; the 

terror of the explosions and fires, the harrowing rescue, and the sense of involvement in 

the wider damages that ensued; and the rigors of the investigations and recovery efforts 

since. 

But the tangible human health effects are more widespread. It was certainly a cruel, added 

misfortune that the Macondo spill bore down most heavily on southern Louisiana, less 

than five years after Hurricane Katrina ravaged the Louisiana and Mississippi coast, ruined 

much of New Orleans, killed hundreds, drove some of the population away permanently 

(including essential medical professionals), devastated the local economy, and shocked 

the nation with images of disorder and suffering. An unfortunate lesson of the oil spill is 
192 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

that the nation was not well prepared for the possibility of widespread, adverse effects on 

human health and mental well-being, especially among a particularly vulnerable citizenry. 

Gulf communities have long-time residents with strong roots to the region. Of coastal 

Louisiana residents surveyed after the spill, 60 percent of respondents reported living in 

their communities their entire lives and another 21 percent had lived there at least 20 

years.130 This context of regional and cultural ties to their communities exacerbates the 

worry and stress caused by the oil spill. Nearly 60 percent of respondents reported feeling 

worried almost constantly during the week prior to being surveyed because of the spill.131

Louisiana shrimper Donald Johnfroe, Jr., said, “Everything I’m making now is going 

to pay off debt from this summer. I’m behind on my child-support payments, house 

payments. I need money.”132 Residents are worried about the economy, their way of life, 

and the stability of their communities. All of these factors play a role in affecting their 

health. 

During the Commission’s first public hearing in New Orleans on July 12–13, 

representatives of community groups focused on the psychological impacts. “Our people 

are used to tragedies and pulling themselves up from their bootstraps . . . but no one 

is saved from depression and fear,” said Sharon Gauthe, Executive Director of Bayou 

Interfaith Shared Community Organizing. Grace Scire, Gulf coast Regional Director for 

Boat People SOS, told the Commission about her experiences working with the Vietnamese, 

Laotian, and Cambodian communities in the Gulf: “People are so dejected—it’s not even 

the word for that—they’re still recovering from Katrina.”133 Both speakers emphasized the 

need for additional community mental health services. 

-5%

0%

5%

10%

15%

20%

25%

30%

 

Source: Gallup-Heathways Well-Being Index Change Since April 20th 2010

Recent Changes in Emotional Well Being Along the Gulf Coast

Clinical Diagnoses of depression

Stress

Sadness

Worry

Inland Counties Non-Gulf States Gulf Facing

Counties

Figure 6.3: Recent Changes in Emotional Well Being Along the Gulf Coast

This figure depicts the recent changes in emotional well-being along the Gulf coast, as indicated in the Gallup Survey conducted April 21 to 

August 6, 2010. 

Gaullup-Heathways Well-Being Index Change Since April 20th 2010
Chapter Six 193 193

Industry and government responders did not adequately anticipate or address the 

magnitude of potential health impacts. Meanwhile, many citizens were coping with 

physical ailments (e.g., respiratory problems, headaches) and stress. Though health 

agencies eventually issued personal protective equipment guidelines for response workers 

and created a registry of these newly trained personnel, they missed the crucial window 

for screening their baseline physical health before the workers were directly exposed to oil 

products.134

Although many of the behavioral and psychological effects of the oil spill remain 

unknown, a Gallup survey of nearly 2,600 residents revealed that medical diagnoses of 

depressive illness had increased by 25 percent since the rig explosion.135 The “well-being 

index” included in the Gallup study showed that coastal residents reported being stressed, 

worried, and sad more often than their inland counterparts (Figure 6.3). 

There is also an indication that domestic violence increased. Between April and June 2010, 

the Administration for Children and Families observed a spike in calls to the National 

Domestic Violence Hotline from Gulf coast states, most notably in Louisiana.136 Such broad 

community impacts suggest the need to monitor and respond to longer-term effects as 

warranted, and to pay special attention to especially vulnerable populations along the Gulf 

coast, including children, minority fishing communities, and Indian tribes. 

Children and families. Children are particularly vulnerable to disruption in social, familial, 

and community stability as a result of disaster. A study conducted after Katrina found 

that children exposed to the hurricane were five times more likely to suffer from serious 

emotional disturbances than they were before the hurricane.137 Although the direct impacts 

of the oil spill of course cannot be compared to the utter devastation wrought on entire 

communities by Katrina, some studies have already begun to document the spill’s impact 

on children and families. A telephone survey of more than 900 coastal Louisiana adults 

two months after the spill began indicated that 46 percent felt they were unable to take 

care of their families as well as they would like.138 In another survey of more than 1,200 

adults living within 10 miles of the coast, parents from Louisiana and Mississippi reported 

that more than one-third of their children were suffering mental or physical health effects 

as a result of the oil spill. The most significant health impact was reported among families 

earning less than $25,000 annually.139

Exactly what proportion of health symptoms is attributable to the oil spill? Meaningful 

measurement is difficult at best. The preliminary findings of one academic study reported 

an “exposure differential” between exposed and non-exposed subjects.140 Adults and 

children who were directly exposed to oil were, on average, twice as likely to report new 

physical or mental health issues as those who were not.141

Minority fishing communities. Another sensitive community is the 40,000 Southeast 

Asian immigrants who live along the Gulf coast (primarily Vietnamese, but also Laotians 

and Cambodians, many of them refugees from the decades-long wars in that region), 

one-fifth of who are fishermen.142 Most of these families suffered direct, grievous harm 

from the 2005 hurricanes143 and now face the spill-related loss of their livelihoods for an 
194 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

uncertain duration. Many of the fishermen speak little or no English, making their access 

to the Gulf Coast Claims Facility especially challenging144 and posing difficulties in finding 

work outside the fishing industry. As the Commission heard in July, the cultural stigma 

associated with mental health problems in some of these communities complicates efforts 

to help those in need.145

Tribal communities. According to Brenda Robichaux, former principal Chief of the United 

Houma Nation, tribal communities on the coast are paying “the ultimate price” for 

both the mismanagement of the Mississippi River Delta over the past half-century (see 

discussion in Chapter 7) as well as the development of the offshore oil industry.146 Both 

activities have contributed to the loss of wetlands and the destruction of barrier islands, 

which play crucial roles in protecting the tribes from major storms. Just as they began 

to recover from four hurricanes in three years, many members of Gulf coastal tribal 

communities for whom fishing is a lifestyle and a livelihood, suffered directly from the oil 

spill and face a difficult future. 

Long-term health effects. The long-term health impacts of oil spills remain largely 

uncertain, but research conducted in the wake of other disasters provides some insight. A 

survey conducted one year after Exxon Valdez found that cleanup workers classified as 

being subjected to “high exposure” were 3.6 times as likely to have a generalized anxiety 

disorder and 2.9 times as likely to have post-traumatic stress disorder as members of 

an unexposed group.147 Alaska Natives were particularly prone to effects of chemical 

exposure and, for cultural reasons, less likely to seek mental health services.148 Unlike 

natural disasters, where mental health consequences generally dissipate relatively quickly, 

technological disasters are known to have chronic impacts on affected individuals and 

communities—a problem that is worsened as issues of fault and compensation are 

negotiated or litigated over an extended period.149 Important symptoms include depression, 

substance abuse, domestic violence, psychological disorders, and disruption of family 

structures.150 Evidence of these effects, as noted, has already appeared in the Gulf coast 

communities most directly influenced by the oil spill.151 

To date, the Gulf Coast Compensation Fund has maintained that it will not pay damages 

for mental illness caused by the spill. According to its administrator, Kenneth Feinberg: 

“If you start compensating purely mental anguish without a physical injury—anxiety, 

stress—we'll be getting millions of claims from people watching television. You have to 

draw the line somewhere.”152 The affected Gulf coast states’ health departments (excluding 

Texas) received $42 million for mental health from BP, and the Substance Abuse and Mental 

Health Administration received $10 million.153 

Because no biological specimens were taken at the outset of the response, the study of 

future health effects will be constrained by a lack of baseline data. No biological samples 

were taken from cleanup workers before or immediately after their exposure to oil. More 

generally, given the unreliability of surveillance in the days and weeks after the spill, the 

quality of any baseline data for studies on long-term health effects was compromised. 

For future emergency response efforts, the government should have enhanced authority 

to ensure adequate baseline data and surveillance measures.154 In the meantime, at a 
Chapter Six 195 195

minimum, long-term monitoring of Deepwater Horizon responders’ health and of 

community health in the most affected coastal areas is warranted and scientifically 

important. 

However, the focus on long-term research cannot overshadow the need to provide 

immediate medical assistance to affected communities, which have suffered from 

limited access to healthcare services.155 In the years following Hurricane Katrina, many 

of the damaged healthcare facilities were not rebuilt or replaced, including the major 

provider of indigent care, Louisiana State University Charity Hospital.156 This left coastal 

communities vulnerable and lacking adequate access to care.157 The greatest damage 

to Louisiana’s health-services infrastructure was in Region One (Orleans, Jefferson, St. 

Bernard, and Plaquemines Parishes).158 A year after the storm, New Orleans had been 

federally designated as a health professional shortage area (HPSA) for primary care, mental 

healthcare, and dental care. By 2008, 86 percent of Louisiana’s parishes were HPSAdesignated, with Medicaid and uninsured residents hardest hit.159 Resources including 

federal Primary Care Access Stabilization Grants were made available to the state160 and 

by August 2010, five years after Katrina, substantial progress had been made in restoring 

healthcare resources through a redesigned primary-care safety net.161

* * * *

Assessing the environmental, economic, and human health damages from the Deepwater 

Horizon oil spill is, of course, only the threshold challenge. The even larger challenge now 

facing the Gulf is how to achieve its restoration, notwithstanding years of failed efforts to 

recover from past destruction.

Chapter Seven 197 197

Recovery and Restoration 

Whatever the final tally of shorelines oiled, fishing 

days lost, and waterfowl killed, the Deepwater 

Horizon oil spill touched virtually every aspect of 

life on the Gulf of Mexico coast— and far beyond. 

Tens of thousands of residents draw fish and 

seafood from the Gulf’s waters, which supply 

much of the nation. Many thousands more produce 

oil and gas from its buried stores. Gulf coast ports 

handle enormous volumes of grain and freight 

leaving American farms and factories and goods 

arriving from abroad. Vacationers come from across 

the country and around the globe to sun and swim 

on Gulf coast beaches. 

But even before the highly visible damages caused 

by the spill became clear, many of those crucial 

Gulf resources faced long-term threats. Indeed, 

the Louisiana coast—that essential borderland and 

nursery to the nation’s richest fisheries—has hit a 

dark trifecta. First, more than 2,300 square miles1

of coastal wetlands (an area larger than the State 

of Delaware) have been lost to the Gulf since the 

United States raised the massive levees along the 

lower Mississippi River after the devastating Great 

Flood of 1927. Exceptionally powerful hurricanes, 

always a threat to the region, struck the coast in 

Chapter Seven

“People have 

plan fatigue . . . 

they’ve been 

planned to 

death” 

Satellite-eye views of the Gulf a month after the Macondo blowout reveal the 

extent of the spill. Oil appears lighter or darker in the photograph depending on 

the relative angles of sun and camera. 

< NASA/GSFC, MODIS Rapid Response
198 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

2005 (Katrina and Rita) and 2008 (Gustav and Ike), causing even more wetland loss and 

erosion. Second, low-oxygen bottom waters were in the process of forming a massive 

“dead zone” extending up to 7,700 square miles during the summer of 2010. Referred 

to as hypoxia, this phenomenon has intensified and expanded since the early 1970s2

as a result of nutrient pollution, mainly from Midwestern agriculture. And finally, the 

Deepwater Horizon disaster made matters worse: 11 rig workers killed in the explosion 

and 17 injured;3 many thousands of people out of work; birds and sea animals killed and 

significant habitats damaged or destroyed. 

These three protracted tragedies—coastal land loss, hypoxia, and the oiling itself—set up 

the central question for recovery from the spill: can or should such a major pollution 

event steer political energy, human resources, and funding into solutions for a continuing, 

systemic tragedy? The spill itself is a regional issue, but the slow-motion decimation of the 

Gulf of Mexico’s coastal and marine environment—created by federal and state policies, 

and exacerbated by energy infrastructure and pollution—is an unmet national challenge. 

MACONDO WELL

(site of Deep water

Horizon blowout)

FLOR I DA

GEO R G I A

LOUI S IAN A

MISSISSIPPI ALA BAM A

e Lake

Pontchartrain

M ississippi

0 mi 50

0 km 50

Tampa

New 

Orleans

Houma

Biloxi

Baton Rouge

Mobile

Pensacola

Panama City

Tallahasse

Oil

• Very Light Oiling

• Light Oiling

• Medium Oiling

• Heavy Oiling

Tarballs

• Light Tarballs

• Medium Tarballs

• Heavy Tarballs

Surface Oil*

• 1 to 10 Days

• 10 to 30 Days

• More than 30 Days

FIGURE 7.1: Maximum Extent of Oil

Surface Oiling Surveys: May 17 - July 25 

Shoreline Oiling: Most severe oiling observed through November

Map courtesy of National Geographic (surface oil) and modified by Commission staff, NOAA/Coast Guard SCAT map (shoreline oiling)
Chapter Seven 199 199

Beyond these acute effects, the wider American public might not understand (and certainly 

has not given high priority to addressing) the root problems affecting the interrelated 

Mississippi River–Gulf of Mexico system that extends into the nation’s heartland. Absent 

a comprehensive approach and national commitment to the Gulf coastal ecosystems, 

there are insufficient authorities and inadequate funds available to address the costly 

and progressive environmental losses now underway. In the aftermath of the Deepwater 

Horizon spill, state and federal authorities have moved to link spill recovery to more 

comprehensive reforms that were already in progress.4

A comprehensive response to the oil spill (and preparedness for the future) requires a 

national vision for restoring the waters, land, and their ecosystems to health. “Restoration” 

is the term of art for attempting to bring natural resources back after a spill. It also 

describes the recovery of large ecosystems by addressing the longstanding environmental 

problems that have caused their deterioration. The goal of any such effort is not 

necessarily to rebuild wetlands and barrier islands so that the coast looks like it did 100 

years ago, but rather to reintroduce elements of the natural system so that the Mississippi 

River Delta—the epicenter of the threatened coastal region—can begin to heal itself.5

To that end, conversations about repairing the Gulf coast and marine ecosystems 

increasingly aim at restoring the region’s natural “resilience.”6 Prior to the spill, Gulf 

states and federal authorities were already in various stages of restoring parts of the Gulf. 

Numerous ecosystem challenges now face the regions of the Gulf coast affected by the 

Deepwater Horizon spill. Barrier islands and shorelines are eroding from Florida to Texas. 

Essential habitats in coastal bays and estuaries have been lost to or degraded by pollution, 

energy or other development, changes in freshwater inflows, and overfishing.7

The largest and most formidable challenges, however, are to bring balance and efficiency 

to the Gulf’s shared marine resources, and to address the rapid and continuous loss of 

wetlands, barrier islands, and shorelines comprising the Mississippi Delta and associated 

Chenier Plain of southwestern Louisiana. While many areas along the Gulf Coast require 

such restoration, the Mississippi Delta and the Gulf itself requires special attention.

Advancing Restoration Options for Offshore Ecosystems and Resources

Beyond restoration of Delta and other coastal ecosystems, a broader restoration effort—

guided by new research and an understanding of what long-term damages may be 

resulting from the spill—seeks to improve the environmental quality of the marine habitat. 

These issues link a complex web of problems (including the annual appearance of the lowoxygen dead zone in waters of the Louisiana-Texas continental shelf) with the continued 

efforts to conserve the biodiversity and resources of offshore ecosystems. 

Implementing the Gulf Hypoxia Action Plan. Hypoxia kills or excludes most marine 

animals over vast areas of the continental shelf. Scientific investigations have shown that 

such extensive and severe hypoxia is a recent phenomenon, fueled by the increased loads 

of nutrients carried down the Mississippi and Atchafalaya rivers, largely as a result of 

fertilizers used to support intense agriculture within the river basin.8 Phytoplankton bloom 

thanks to the nutrients, and the process of their decay depletes oxygen over thousands of 
200 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

square miles of seabed. These hypoxic seafloor habitats could become prime candidates for 

restoration efforts in the aftermath of the Deepwater Horizon disaster. 

A plan of action produced in 2001 and updated in 2008 by the Mississippi River Gulf of 

Mexico Watershed Nutrient Task Force*

 outlines how to proceed.9 The Action Plan aims 

to reduce the average extent of the hypoxic zone to less than 5,000 square kilometers 

(1,930 square miles), or about one-fourth the area affected in 2010, by reducing the 

discharges of nitrogen and phosphorus into the Gulf. The original target date for achieving 

this goal was 2015, but implementation has languished. As part of a comprehensive 

restoration program, regulations that limit discharges under the Clean Water Act could be 

more rigorously applied, and federally-authorized conservation programs could be better 

targeted to achieve greater results. Hypoxia abatement should also be integrated with 

coastal ecosystem restoration in order to optimize nutrient removal by river diversions 

and to reduce the risks of injecting greater nutrient loads into the waters of the continental 

shelf.

Marine spatial planning. The U.S. part of the Gulf of Mexico is already as 

compartmentalized as any water body in the world. The Department of the Interior divides 

FIGURE 7.2: Coastal Marine Users

NOAA

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Industrial

• Shipping

• Military

• Oil Lighting Area

• Oil Platform

Preservation

• Marine Sanctuary

• Coastal Preserve

• National Wildlife

 Refuge & Shoreline

Manage

• Fisheries Management Area

• Water Magagement Area

• Wildlife Magagement Area

• State Magagement Area

Other

• Research Area

• Archeological

* The Task Force consists of state and natural resources agencies and federal agencies, including NOAA, EPA, the Departments of 

Agriculture and of the Interior, and the Army Corps of Engineers.
Chapter Seven 201 20

the northern Gulf into a grid for administrative purposes. Oil and gas companies lease 

individual blocks within this grid for exploration and production.10 Other entities manage 

the Gulf to maximize their own benefit—for fishing, tourism, or conservation. 

All this activity also makes the Gulf a crowded space administratively, with coordination 

insufficient to resolve potential conflicts among oil and gas development, fishing, 

navigation, and military operations. The Deepwater Horizon disaster occurred at a time 

when U.S. policy toward its waters was under significant revision. The National Oceans 

Council, created by Executive Order in July 2010,11 is authorized to set and manage 

executive-branch marine policy and to implement recommendations of a task force 

appointed by President Obama in 2009.12

Among the most significant initiatives are steps that would reorganize—or in some 

cases organize—how Americans benefit from resources in federal waters. Scientists and 

policy advocates use the phrase “coastal and marine spatial planning” to describe a suite 

of technologies, best practices, and inter-industry networking to optimize the use of 

resources for all.13 In the Gulf of Mexico, where the oil and gas industry has a very large 

presence, marine spatial planning can help lead to better oversight, and in the event of an 

accident, better communication among all users. Massachusetts and Rhode Island recently 

formalized this approach to their state waters.14 Norway has implemented planning in its 

crowded northern waters, an area which includes oil and gas infrastructure.15

More a management or governance strategy than a discrete program, marine spatial 

planning is evolutionary in nature. The Department of the Interior is already charged to 

manage energy resources on the outer continental shelf in a way that is, among other 

requirements, “consistent with the need . . . to balance orderly resource development 

with protection of the human, marine, and coastal environments.”16 Proponents expect 

federal and statewide marine spatial planning to bring together agencies, jurisdictions, and 

communities to share information and best practices—and in so doing, better balance the 

many interests on and beneath the water.17

Marine protected areas. Within the context of coastal and marine spatial planning, there 

are opportunities for protection and restoration of resources harmed not only by the 

present oil spill, but also by oil and gas development generally and other commercial 

activities. Marine protected areas have been effective as a means to conserve marine 

biodiversity and enhance the resilience of fish stocks in the face of harvest pressures.18

Strategically selected and designated marine protected areas could be an effective way 

to restore offshore ecosystems within the framework of a comprehensive restoration 

program. Modern management tools can go a long way toward making Gulf fisheries 

more robust by preventing overfishing. The Deepwater Horizon disaster delayed the start 

of a new National Oceanic and Atmospheric Administration (NOAA) fisheries management 

policy. On November 4, 2010, the “NOAA Catch Share Policy” went into effect. The policy 

divides the total allowable catch in a fishery into shares held by individuals and various 

entities. The holders of the catch shares must cease fishing once they have reached their 

limit. This is one step toward protecting the health of commercial and recreational fisheries. 
202 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Toward a Functioning Delta 

The Delta difference. The land at the mouth of the Mississippi River differs from that of 

neighboring regions: the underlying rock is hundreds of feet below the surface,19 buried 

by mud deposited over many millennia. River-borne sediment has, literally, created the 

land—a coastal habitat of remarkable biological productivity, and a buffer that protects the 

densely settled land upriver from the full force of battering waves. But the sea constantly 

carries that coastal land away.

The Mississippi River, extending some 2,300 miles upstream to Minnesota, runs through 

the heart of the third largest watershed in the world (after the Amazon and the Congo). 

Water enters its basin from 31 states. Water from the northern reaches of the basin can 

take a month to reach the Gulf. About two weeks after the historic rains that flooded 

Nashville and killed at least 31 people across the southeast in May 2010, the water flowed 

past New Orleans; when it entered the Gulf, that freshwater swell may have helped keep 

oil-covered offshore waters away from marshes in the spill’s early days.20

As the Mississippi meanders south, it picks up silt, sand, and organic materials. Under 

largely natural conditions (before the 1930s), the river cast this sediment across the 

wetland plain before draining into the Gulf. The accumulating material attracts the 

microbes and marsh grasses that undergird the coastal ecosystem. During the 7,000 to 

8,000 years since the end of the last ice age, the Mississippi has shaped and reshaped its 

delta—even, on occasion, carving wholly new routes to the Gulf.

FIGURE 7.3: Coastal Vulnerability Index

Coastal Vulnerability Index (CVI)

• Very High

• High

• Moderate

• Low

USGS National Assessment of Coastal Vulnerability to Future Sea-Level Rise –Open File Report 00-179
Voices from the Gulf 203 203

Voices from the Gulf

“Louisiana is paying a grave price 

for what the rest of the country is 

enjoying.”

Brenda Dardar Robichaux,

Former Chief of the United Houma Nation, 

Raceland, LA 

Brenda Dardar Robichaux could not help noticing as the local 

coastline, ditched for oil-related navigation and pipeline corridors, 

progressively disappeared all through Terrebonne, Lafourche, 

Jefferson, St. Mary, St. Bernard and Plaquemines parishes. 

As Principal Chief (from 1997 until 2010) of the 17,000-member United Houma Nation, whose 

people lived in and made their livelihoods from the coastal lands of southeastern Louisiana, she 

said, “We have seen small canals turn into large bayous; we have watched hundreds of acres 

of wetlands wash away; we have seen freshwater bayous turn into saltwater.” And her people 

have become exposed to severe risks: “Hurricanes Gustav and Ike destroyed our community on 

Isle de Jean Charles because we no longer have the barrier islands protecting us. Today Isle de 

Jean Charles is just a sliver of what it once was. The length of the island is still several miles, but 

the width is maybe an acre. When I was little there were fields that we [the Houma People] raised 

cattle and horses on. We had gardens and the kids played baseball. Now there is no such thing. 

The backyards are water.”

Former Chief Robichaux initially saw some possible good coming from the spill: serious attention 

being paid to coastal restoration. “The spill certainly adds another level of awareness to the 

problem—like Katrina did—but we need major change now, and not just little projects. When the 

oil spill happened, I was hopeful that all the attention it was bringing might finally wake people 

up. I was optimistic. I was thinking if we’re ever going to get vision for coastal restoration off the 

ground, now is the time. But I don’t see that happening.”

For centuries, the United Houma Nation’s culture and economy have been entwined with the 

bounty of the gulf. “Our people follow the seasons,” Robichaux explained. “In the summer we 

catch shrimp, crabs, and garfish. In the winter we harvest oysters and trap nutria, muskrat, and 

otters...Houma fishermen are intimately familiar with the lakes and bayous of our region. They 

know the stories of how these places got their names. They know how the tides flow and the 

winds blow... All of these traditions are in danger of disappearing.”

 Like all Americans, she knew well the nation’s dependence on oil: “Louisiana is paying a grave 

price for what the rest of the country is enjoying, whether it’s seafood or what oil and gas provide. 

But our tribal citizens are paying the ultimate price, because we live along the coast of southeast 

Louisiana. We as a nation, not only people in Louisiana, not just people on the coast, but the 

nation, need to evaluate our dependency on oil and gas. We need to re-evaluate our entire 

lifestyle. It’s not just a Gulf Coast issue.”

Dennis Woltering 
204 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Beginning late in the nineteenth century, the Atchafalaya River in southern Louisiana 

captured an increasing share of Mississippi waters, greatly reducing flow into the lower 

part of the Mississippi.21 Were nature left to itself, the flow would have diverted over 

time primarily to the Atchafalaya, which provides a much shorter route to the Gulf. This 

change would have been catastrophic to communities and industry along the lower river, 

leaving the port of New Orleans on a silted-in bayou without a freshwater supply. To 

forestall that switch in river channels, the U.S. Army Corps of Engineers built the Old 

River Control Structures: a series of dams, completed in 1963, that ensure 70 percent 

of Mississippi waters flow past New Orleans and 30 percent reach the Gulf through the 

Atchafalaya. All other distributaries of the great river have been closed.22

Managing the river for human ends—to improve navigation and control flooding with 

artificial levees—accelerates the natural deterioration of coastal wetlands and landforms. 

Flooding is the process that feeds this landscape, causing the accretion of sediments 

through which nature constructed the Delta. Under human control, the river now carries 

that sediment out into the Gulf, where it is deposited beyond the reach of natural deltaic 

processes, breaking the Delta’s means for self-preservation. Managing the flow down 

the Atchafalaya was only the most recent intervention that has disrupted the natural 

mechanisms at work in the Delta. Addressing the central issue of the Delta’s functioning 

lies at the core of strategies for long-term restoration. 

The sediment problem. The re-engineering of the Mississippi River system—resulting in the 

“sediment starvation” of the Delta—began even before the Great Flood of 1927, when 145 

levees failed, at least 246 people died, and floodwaters throughout the river basin caused 

the modern equivalent of $2 billion to $5 billion in damage.23 It accelerated after that 

flood, when the Flood Control Act of 1928 authorized an epic levee-building program.24

The Mississippi River and Tributaries Project engaged the Corps in building levees to contain 

floods, constructing strategic floodways, improving the river channels for shipping and 

floodwater carrying capacity, and reconstructing tributary basins for flood control. The 

Corps now manages the resulting protective system, with 2,203 miles of levees.25

As flooding decreased, and improved river traffic and long-distance shipping allowed 

local communities to grow, the closure of the Mississippi’s crevasses, flood plains, and 

distributaries had the unforeseen consequence of endangering the very communities that 

enjoyed those benefits. In written remarks to the Commission, Senator Mary Landrieu 

decried the “strangulation” of nature: “For more than a century, the federal government 

has mismanaged critical water-resource projects, placing delicate ecosystems like the 

Mississippi River Delta at extreme risk of complete and utter collapse.”26 The loss of 

protective wetlands, like a catastrophic oil spill, is a manmade disaster. 

In effect, the system built by the Corps is causing southern Louisiana to disappear (even 

though the Corps has, during the past 20 years, begun taking steps to offset these 

unforeseen consequences).27 The annual sediment load reaching the Delta has decreased 

from 400 million metric tons before 1900 to 145 million metric tons in recent years. And 

very little of that reaches wetlands.28 
Chapter Seven 205 205

Rising waters. Even as the altered river delivers less sediment to replenish the Delta, the 

relative sea level is rising in southern Louisiana—the net result of land subsidence and 

actual sea level rise.29 Subsidence is a critical problem in the Gulf region, which naturally 

sinks 1 to 5 millimeters per year. In some places near the outer Delta, subsidence is nearly 

10 millimeters per year, largely from manmade impacts.30 It is particularly intense in the 

Delta, where the Gulf has swallowed more than 2,300 square miles of coastal wetlands 

since the early part of the twentieth century.31 Explanations for the phenomenon vary. 

One is that sediment rich in organic material behaves like a sponge: squeeze out the water 

and it shrinks.32 Another relates to deep tectonic faulting.33 A third correlates hydrocarbon 

extraction with subsidence-driven wetland loss.34 Whatever the reason, the channeling of 

river sediment into the Gulf is interrupting natural land generation, and the region cannot 

keep pace with relative sea level rise. 

Navigation and channeling the wetlands. Relative sea level rise endangers marsh grasses 

and other swamp trees as they become subject to inundation by the salty Gulf. At the 

same time, the growing oil and gas industry dredged 10,000 miles of canals through 

Louisiana’s wetlands in order to move in drilling barges or lay pipelines, leaving arrowstraight channels through what had been a convoluted maze.35 Dredged sediment lines the 

canal: artificial banks change water flow and prevent flooding, so sediment mobilized by 

tidal flows cannot replenish the land. Water forms pools behind the banks, submerging 

marsh. And the channels admit saltwater flow into brackish and freshwater environments, 

FIGURE 7.4: Louisiana Coastal Erosion

• Land Loss 1932–2000

• Land Gain 1932–2000

• Projected Land Loss 2000–2050

• Projected Land Gain 2000–2050

Mobile

New Orleans

Houma

Baton Rouge

Lake Charles

USGS Open File Report 2009-11-0408
206 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

jeopardizing the overall ecosystem. Researchers have reached no solid consensus on 

how much wetland loss to attribute to the canals’ direct and indirect effects, although 

some scientists attribute 35 percent to the canals’ indirect effects.36 In 2009, a Minerals 

Management Service study concluded, “The construction of outer continental shelf-related 

pipelines through coastal ecosystems can cause locally intense habitat changes, thereby 

contributing to the loss of critically important land and wetland areas” through their 

conversion to open water, or from freshwater marsh into saltwater marsh.37

Congress and the Corps put the most well known of the navigation canals out of business 

in 2008. The Corps in 1968 finished the Mississippi River Gulf Outlet—affectionately, 

or derisively, called “Mr. Go” (MRGO)—a straight shot from the Gulf to the Port of 

New Orleans. This canal’s story is emblematic of the larger problem of wetland canals’ 

environmental impacts. The 66-mile outlet shortened and simplified ships’ approach 

to the port. Heralded as a boon to economic development, the project never proved 

transformative—except environmentally. Construction destroyed the existing ecosystems 

and excavated more than 270 million cubic yards of material—slightly more than was 

removed to build the Panama Canal.38 The project converted about 3,350 acres of fresh 

or intermediate marsh and 8,000 acres of cypress swamps into brackish marsh. Nearly 

20,000 acres of brackish marsh and swamp became saline marsh. More than 5,000 acres 

of marsh next to the channel had disappeared by 1996.39 Maintenance costs increased 

significantly over the years, including costs related to hurricanes—even as shipping 

through the canal declined. The Corps estimated that the canal would require $22.1 million 

per year in dredging, or about $12,657 per ship every day. By the late 1990s, multiple 

stakeholders had pressed the Corps to close the canal.40

That was before Katrina. As the hurricane approached Louisiana’s eastern coast, its storm 

surge pushed into the shipping channel, breaching levees, thereby contributing to the 

flooding of New Orleans.41 Congress de-authorized the Mississippi River Gulf Outlet canal 

in 2008 and a contractor sealed off its southern entrance with rock fill in 2009.42 Congress 

has undertaken no similar effort to address the ongoing harm caused by vast network 

of canals and infrastructure built into the wetlands—incursions that have hastened by 

decades the demise of the already sediment-starved Delta. 

Planning without end. By the early 1950s, Gulf coast researchers had become aware of 

gaps in understanding how coasts naturally worked. In 1952, Louisiana State University 

created a Coastal Studies Institute. Scientists there and elsewhere sought to explain the 

relationship between floods breaching natural levees and the health of marshland and 

barrier islands fed by the sediment.43

The U.S. Fish and Wildlife Service in 1959 sent the Corps a memorandum suggesting 

that the declining health of oyster reefs caused by increasing salinity might be addressed 

by diverting fresh water from the Mississippi into discrete areas.44 The first diversion, at 

Caernarvon, was authorized in 1965, and two years later Congress instructed the Corps 

to develop a strategy “in the interest of hurricane protection, prevention of saltwater 

intrusion, preservation of fish and wildlife, [and] prevention of erosion.”45 A 1973 

report to the Corps suggested diversions to deliver sediment and lower salinity.46 A 1979 
Chapter Seven 207 207

study examined the economic impacts of wetland loss, with guidelines that “center on 

avoiding the disruption of wetland hydrology,” and found that land loss was greater 

than previously measured.47 Eight years later, a new group called the Coalition to Restore 

Coastal Louisiana suggested the same strategy: fix the hydrology.48 In the 20 years 

since, a few small-scale programs and many reports have directed the state and federal 

governments to fix the hydrology. None approach the necessary scale for meaningful 

restoration49, although they have provided smaller successes and helpful organizational 

models.

Simulations predict that, at the current rate of land loss, much of southern Louisiana will 

disappear by 2100. The region will transition from marshy lowlands to a fully aquatic 

system because of erosion and submergence,50 leaving New Orleans an expensive island 

fortress.

Among efforts to identify and begin to address the problem are these highlights:

•	 Louisiana Act 6. In 1989, the Louisiana legislature passed Act 6, establishing a 

wetlands authority and an executive office to prioritize and manage a restoration 

strategy and projects. 

•	 The Coastal Wetlands, Planning, Protection and Restoration Act. The following year, 

Congress enacted the so-called Breaux Act, named for its sponsor, Louisiana Senator 

John Breaux. It authorizes civil works aimed at marsh regeneration, shoreline 

protection, barrier-island reconstruction, hydrologic engineering, and the use of 

dredged material for restoration purposes. The Act has a dedicated funding source, 

the Sport Fish Restoration and Boating Trust Fund, which receives taxes on gasoline 

for motorboats and other small engines, and on sport-fishing equipment.51 The 

taxes have yielded between nearly $30 million and $80 million per year.52 Programs 

under the Act, which involve collaboration among Louisiana and five federal agencies 

including the Corps, have been credited with protecting 110,000 acres of wetlands.53

In 1998, more ambitiously, the Breaux Act agencies agreed to the recommendations 

of Coast 2050, an 18-month feasibility study for coastal restoration. The report 

was based upon original research and 65 public meetings, and was supported by 

20 coastal parishes. The report’s recommendations were aimed at allowing healthy 

flows of sediment into the Mississippi, preserving salinity levels and land critical 

to sensitive habitats, and diverting sediment-rich fresh water to replenish starving 

marsh.54

In 2004, the Corps produced its Louisiana Coastal Area Comprehensive Coastwide 

Ecosystem Restoration report, a package of projects meant to meet the coastal 

challenges. This led to creation of the Louisiana Coastal Area Ecosystem Restoration 

Program under the 2007 Water Resources Development Act. After the Office of 

Management and Budget opposed the high price tag of a more comprehensive 

proposal—about $14 billion—the Corps slimmed its initial implementation down to 

15 projects that would together cost more than $2 billion.55
208 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Katrina’s aftermath. Weeks after Hurricane Katrina ravaged much of coastal Louisiana 

and Mississippi, the Louisiana legislature established a Coastal Protection and Restoration 

Authority that combined responses to wetland loss and hurricane risk—related goals 

separated in state bureaucracy. In September 2006, Louisianans approved a constitutional 

amendment that explicitly ties state revenues from oil and gas activities in federal waters to 

storm protection and rebuilding wetlands.56

The relative priority of the two goals is not yet certain. Although one rule of thumb for 

the Louisiana coast holds that each 2.7 square miles of marshland reduces a hurricane’s 

storm surge by one foot,57 the relationship has not been easy to precisely quantify. In 

the meantime, construction for storm protection is tangible and has been readily funded. 

The Corps has been able to fast-track building new levees to protect New Orleans from 

the projected “100-year storm”; the project should be completed in 2011—just five years 

after it began. By contrast, direct instructions and guaranteed funding have mostly eluded 

restoration efforts. The state has engaged the Corps to design and build two new, large 

levee systems, but their effects on southern Louisiana communities and wetland survival 

are still being studied.58 Traditional flood protection usually involves “hard-engineering,” 

essentially levee-building. Part of the promise of the state’s newly organized approach is 

in protective “soft-engineering,” or regenerating wetlands and barrier islands for the dual 

purposes of ecosystem restoration and storm protection. 

Congress also asked the Corps to develop comprehensive statewide hurricane-protection 

options after Hurricanes Katrina and Rita. The Department of Defense Appropriation 

Act of 2006 directed the Corps to design a suite of improvements to the Louisiana and 

Mississippi coasts, including improvements for “hurricane and storm damage reduction, 

prevention of saltwater intrusion, preservation of fish and wildlife, prevention of erosion, 

and other related water resource purposes at full Federal expense.”59 A September 2009 

Chief of Engineers’ report suggested 12 projects for Mississippi, costing more than $1 

billion, that would help restore barrier islands, beaches, sensitive habitats, and coastal 

ecosystems. Congress has appropriated $439 million to implement Mississippi’s program 

so far.60 The Corps has also drafted a counterpart Louisiana Coastal Protection and 

Restoration Final Technical Report,61 but the future of the Louisiana program is uncertain, 

as the report includes a wide range of options rather than a specific plan. 

Other sources of funding for sustained restoration efforts include the State of Louisiana’s 

Coastal Protection and Restoration Fund, about $25 million a year from state mineral 

income plus budget surpluses in 2007–2009;62 the federal Coastal Impact Assistance 

Program, which authorizes $250 million split among six states in each fiscal year from 

2007–2010 to fund natural resources recovery, conservation, and protective measures;63

and the federal Gulf of Mexico Energy Security Act, in which participating Gulf states (all 

but Florida) share 37.5 percent of federal offshore revenue from new lease areas for use in 

coastal protection, including onshore infrastructure projects that mitigate the impacts of 

outer continental shelf energy activities.64
Voices from the Gulf 209 209

Voices from the Gulf

“An entire culture being washed 

away by crude oil and chemicals”

Clarence R. Duplessis, 

Commercial Fisherman, Davant, LA 

When Clarence R. Duplessis was born 

in 1945 in the small Gulf Coast fishing 

community of Davant, just north of Pointe-ala-Hache, he became the seventh generation 

of his family to live in Plaquemines Parish, 

Louisiana. After high school, Duplessis, 

joined the U.S. Marine Corps, served a tour 

of duty in Vietnam, and met his wife, Bonnie, 

who served in the Navy.

Upon their return to Louisiana, Mr. Duplessis found work at the Kaiser Aluminum plant in 

Chalmette, La. In 1989, when the plant shut, he says, “I had a young family to feed, clothe, 

and educate. This. . . was a problem with a solution. I was still young and had experience with 

shrimping and oystering. I had salt water in my veins at birth. I went fishing and my children paid 

their college tuition by working as deckhands. 

“In 2005, Hurricane Katrina hit us with a crippling blow. Wow! A major problem!. . . My wife and I 

lost everything we owned in Hurricane Katrina. . . Even then, though the entire region was wiped 

out and the insurance companies packed their bags and left us, there was still a solution...The 

fishing communities and people of South Louisiana are some of the hardest working, defiant yet 

kindest people on God’s earth. After the storm we faced the difficult task of rebuilding, but that 

was the solution. 

“Now, five years later we are facing the Deepwater Horizon oil spill. This is the worst of our 

problems because we have no answers, no solutions, only questions. As we watch our livelihood 

and even an entire culture being washed away by crude oil and chemicals that no one knows the 

long term effects of, we ask: [W]ill we have the mortgage payment next month? . . . How long will 

this last? Will I be able to go oystering next year or ever again? How long will it take the fisheries 

to recover?. . . Will BP do what is right or will they pack their bags and leave us like the insurance 

companies did? What can I do to survive?...I have a thousand questions and no answers. Now, I 

hope you can understand why this problem is the worst of my life!”

Claire Luby 
210 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Toward coordinated strategies and action. In the fall of 2009, President Obama directed 

the Council on Environmental Quality and the Office of Management and Budget to cochair a Louisiana-Mississippi Gulf Coast Ecosystem Restoration Working Group, made 

up of federal agency and state representatives.65 Six months later—about six weeks 

before the Deepwater Horizon exploded—the group presented a “road map” for federalstate collaboration and set out 2010–2011 deadlines for advancing policymaking.66 The 

President’s fiscal year 2011 budget requested $19 million for construction, sediment use, 

and river diversions and $16.6 million for studies of eventual restoration projects. 

After the spill, the President in June commissioned Secretary of the Navy and former 

Governor of Mississippi Ray Mabus to study Gulf coast recovery and propose ways to 

address chronic Gulf marine and coastal issues. The resulting “Mabus report,” published on 

September 28, 2010, analyzed ecosystem restoration, human health, economic recovery, 

and the nonprofit sector.67 A week later, the President issued Executive Order 13554, 

creating a Gulf Coast Ecosystem Restoration Task Force comprised of federal agency and 

state representatives to “coordinate intergovernmental responsibilities, planning, and 

exchange of information so as to better implement Gulf Coast ecosystem restoration and to 

facilitate appropriate accountability and support throughout the restoration process.”68

In the course of his work, Secretary Mabus repeatedly referred to the rising public 

impatience with plans unaccompanied by action. As he put it in June, “I also understand 

that people have plan fatigue, that they’ve been planned to death.”69 In the meantime, at 

current erosion rates, an area of the Delta the size of a football field is consumed by Gulf 

waters every hour.70

Identifying options for funding and governance. The twentieth-century re-engineering 

of the Mississippi River basin, and subsequent piecemeal efforts to restore its nourishing 

flows of water and sediment, teach important lessons about any future, comprehensive 

approach to coastal management. Many of the re-engineering projects have provided only 

incremental gains.71 Discrete restoration projects, moreover, are unable to reverse the loss 

of Delta land and habitats in the aggregate. The many layers of federal, state, and local 

authorities—some overlapping and conflicting—make it difficult as a practical matter to 

devise, implement, and make mid-course corrections to a strategy for restoration. And 

secure, sustained sources of funding on the scale required to do the necessary work are 

not now in place.72 The contrast with the reconstruction of the protective hurricane levees 

around New Orleans from 2006 through 2011 could not be clearer. 

Estimates of the cost of Gulf restoration, including but not limited to the Mississippi 

Delta, vary widely, but according to testimony before the Commission, full restoration of 

the Gulf will require $15 billion to $20 billion: a minimum of $500 million annually for 

30 years.73 Current funding sources do not approach those figures. Beginning in 2017, 

Phase II of the Gulf of Mexico Energy Security Act,74 which governs sharing of oil-related 

revenues, will begin to bring large amounts of money to the Gulf States. Much of this 

could be directed to restoration. 
Chapter Seven 211 21

The Deepwater Horizon disaster provides a significant opportunity to begin funding 

restoration sooner. It will generate monies that can be directed to jumpstart key Gulf 

restoration projects. And it can provide the basis for launching a long-needed federal-state 

entity capable of managing the restoration effort over the longer term, guided by a clear 

set of principles. 

In the aftermath of the spill, the responsible party (or parties) will be liable for damages 

in the amount necessary for “restoring, rehabilitating, replacing, or acquiring the 

equivalent of” natural resources harmed by the spill.75 The responsible party will also 

pay fines if found in violation of federal laws. The maximum civil penalties under the 

Clean Water Act could range from $4.5 billion to $21 billion, depending upon findings of 

negligence and the calculation of barrels discharged. The Act provides for a civil penalty 

for unpermitted discharges of up to $37,500 per day of violation or up to $1,100 per 

barrel of oil discharged. In the case of an operator’s gross negligence or willful misconduct, 

the penalty becomes not less than $140,000 and not more than $4,300 per barrel of oil 

discharged.76 Criminal fines could be large, as well.77 A negligent violation of the Clean 

Water Act’s criminal provision is subject to a fine of between $2,500 and $25,000 per day 

of violation for a first violation and up to $50,000 per day for subsequent violations.78 For 

knowing violations of the Act, criminal fines range between $5,000 and $50,000 per day 

of violation for a first conviction, and up to $100,000 per day for subsequent violations.79

Civil and criminal fines are both deposited in the Oil Spill Liability Trust Fund, established 

after the Exxon Valdez spill to help pay for cleanup and certain damages after a spill, but 

use of that Fund is restricted.80 

The Mabus report, as well as regional members of Congress and Governors from the Gulf, 

have proposed directing a significant amount of the penalty funds to long-term ecosystem 

restoration in the Gulf (and in the case of the Mabus report, to economic and health 

recovery as well). Secretary Mabus recommended that the President urge Congress to pass 

legislation to dedicate some of the penalties for those purposes. 

Legislative proposals to establish a coordinating and decisionmaking council, as 

recommended in Secretary Mabus’s report,81 call for a state-federal governing entity that 

has authority to prioritize restoration projects based on a comprehensive strategic plan. 

Although the details of early proposals varied, most recognized the need for a single, Gulfwide decisionmaking authority and a strong leadership commitment to fund only those 

projects that conform to an agreed-upon vision for long-term restoration. 

Planning and program design for any comprehensive Gulf restoration effort will have to be 

based on sound science. In different circumstances, the Exxon Valdez Trustee Council Science 

Panel reviewed all proposed projects both for technical merit and for consistency with the 

overall restoration goals (as set forth in the Restoration Plan) and annual work plans.82

This effort, although encompassing projects of a different nature and scope than those in 

the Gulf, enabled effective scientific communication with the Trustee Council.83
212 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

A successful Gulf-wide scientific process would likewise be structured to allow meaningful 

and timely input by scientists into the decisionmaking process. Ideally, it would provide 

a science program with the resources to evaluate individual projects for consistency with 

a comprehensive plan; to research long-term restoration issues; and to develop and apply 

performance measures and indicators of long-term restoration that allow decisionmakers 

to adjust the plan based on new science or changed circumstances. Particularly with respect 

to long-term research issues, the diverse resources and expertise of the federal government 

should be brought to bear. 

Finally, no authority will succeed without the confidence and support of the citizens of 

the region. Leaders of restoration efforts emphasize the importance of gaining the support 

of those most directly affected by restoration projects. Local citizen support is important 

for several reasons: it can reduce delay of projects due to litigation or other opposition; 

it contributes to political support for overall goals and funding, in the short and long 

terms; and it contributes to overall trust in government, which results in support for local 

projects.84 Any structure should therefore include a citizens’ advisory council to provide 

formal advice and a direct line to citizens’ concerns. 

Putting Restoration on the Agenda

Speaking to the nation in June 2010 from the Oval Office, President Obama clearly linked 

spill recovery and long-term stewardship: “The oil spill represents just the latest blow to 

a place that’s already suffered multiple economic disasters and decades of environmental 

degradation that has led to disappearing wetlands and habitats. And the region still hasn’t 

recovered from Hurricanes Katrina and Rita. That’s why we must make a commitment 

to the Gulf Coast that goes beyond responding to the crisis of the moment.”85 In midJuly, Louisiana Governor Bobby Jindal announced his “Agenda for Revitalizing Coastal 

Louisiana,” which extols Louisianans’ resilience both in general and in recovering from the 

2005 and 2008 storms: “There is not a doubt in my mind that we will recover and restore 

our coast and our wetlands to not only be Sportsman’s Paradise again, but to be an even 

more plentiful source of abundant natural resources than ever before.”86

“Restoration” itself has several specified meanings. NOAA defines post-spill restoration 

under the Oil Pollution Act as “the goal of a natural resource damage assessment, which 

involves rehabilitating, replacing, or acquiring the equivalent of injured natural resources 

and the services they provided.”87 In some cases after an oil spill, natural resource 

trustees—such as the involved state and federal agencies—and the party responsible for the 

spill can alter the charge. For example, the concept of “enhancement” that emerged after 

Exxon Valdez gave trustees additional latitude in restoring Prince William Sound and its 

ecological region.88 This addition enabled planners to strive for improvements, rather than 

returning to a baseline.

Nature has no baseline: natural systems change and evolve continuously. “Restoration” 

therefore should have another, broader meaning. In the Gulf, it must encompass reversing 

the progressive erosion of coastal land and habitats that buffer human communities 

from storms and sustain the area’s biological productivity. In this context, restoration 

does not imply returning landforms to a particular map, but rather making the river, 
Chapter Seven 213 213

Delta, and Gulf coastal and marine systems more resilient. The economies of the 

Gulf—fisheries, energy, and tourism—are as rooted in the environment as any in the 

developed world. Restoration, or restored resilience, represents an effort to sustain these 

diverse, interdependent activities and the environment on which they depend for future 

generations. 
214
215 215

Part III

Lessons Learned: Industry, Government, 

Energy Policy

The private oil and gas industry is the lead actor in exploration and 

production of Gulf energy resources. In the wake of the BP Deepwater 

Horizon disaster—a crisis that was unanticipated, on a scale for 

which companies had not prepared to respond—changes in safety 

and environmental practices, safety training, drilling technology, 

containment and clean-up technology, preparedness, corporate 

culture, and management behavior will be required if deepwater 

energy operations are to be pursued in the Gulf—or elsewhere. 

Maintaining the public trust and earning the privilege of drilling on 

the outer continental shelf requires no less. As Chapter 8 explains, 

some of the required responses are under way; for other measures, 

there are useful precedents from other industries. Beyond the oil 

and gas industry’s response, the inadequacies in permitting and 

regulatory standards, practices, and oversight revealed by the crisis 

have already caused significant changes in the federal rules and 

procedures for deepwater drilling. But further action, including the 

creation of an independent safety authority, is clearly warranted, as 

described in Chapter 9.

Finally, the interplay of public incentives, security considerations, 

energy conservation and use, and alternative energy sources, among 

other factors, will shape future deepwater drilling in the Gulf and 

in other frontier areas, as discussed in Chapter 10. Because some of 

those frontiers are defined by greater well depths and pressures, and 

others are in settings as yet untapped (the Arctic, in particular)—with 

economies, environmental resources, and community characteristics 

different from those tested so severely in and along the Gulf Coast—

learning the right lessons from the BP Deepwater Horizon, and 

adapting them to different contexts, must thoroughly inform the 

future of America’s offshore oil policy.

Chapter Eight 217 217

Changing Business as Usual

The Deepwater Horizon blowout, explosion, and 

oil spill did not have to happen. Previous chapters 

have explained the immediate and root causes for 

why they nonetheless did. The American public, 

government, and the oil and gas industry need to 

understand what went wrong so they can pursue 

the changes required to prevent such devastating 

accidents from recurring. 

This chapter examines how petroleum companies 

have been managing the risks associated with 

finding and producing oil and how they can 

do it better, individually and as a responsible 

industry overall. The record shows that without 

effective government oversight, the offshore 

oil and gas industry will not adequately reduce 

the risk of accidents, nor prepare effectively to 

respond in emergencies. However, government 

oversight, alone, cannot reduce those risks to 

the full extent possible. Government oversight 

(see Chapter 9) must be accompanied by the 

oil and gas industry’s internal reinvention: 

sweeping reforms that accomplish no less than a 

fundamental transformation of its safety culture. 

Only through such a demonstrated transformation 

will industry—in the aftermath of the Deepwater 

Horizon disaster—truly earn the privilege of access 

to the nation’s energy resources located on federal 

properties.

Chapter Eight 

“Safety is not 

proprietary.”

Even as Deepwater Horizon burns, oil from the blown out well begins to spread 

across the Gulf. Preventing such disasters in the future will take more effective 

government oversight. Most crucial, however, will be the oil and gas industry’s 

commitment to fundamentally transform its own safety culture. 

< Gerald Herbert/Associated Press
218 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Offshore oil and gas exploration and production are risky. But even the most inherently 

risky industry can be made much safer, given the right incentives and disciplined systems, 

sustained by committed leadership and effective training. The critical common element is 

an unwavering commitment to safety at the top of an organization: the CEO and board of 

directors must create the culture and establish the conditions under which everyone in a 

company shares responsibility for maintaining a relentless focus on preventing accidents. 

Likewise, for the entire industry, leadership needs to come from the CEOs collectively, who 

can apply pressure on their peers to enhance performance. 

Properly managed, the presence of risk does not mean that accidents have to happen. As 

Magne Ognedal, Director General of Norway’s Petroleum Safety Authority, put it: “risk 

must be managed at every level and in every company involved in this business. . . . In this 

way, risk in the petroleum sector can be kept at a level society is willing to accept. And we 

can reduce the probability that major accidents will hit us again.”1 

BP’s Safety Culture

BP has proclaimed the importance of safety for its vast worldwide operations. “Our goal 

of ‘no accidents, no harm to people and no damage to the environment’ is fundamental to 

BP’s activities,” stated the company’s Sustainability Review 2009. “We work to achieve 

this through consistent management processes, ongoing training programmes, rigorous 

risk management and a culture of continuous improvement.” It added that “creating a safe 

and healthy working environment is essential for our success. Since 1999, injury rates and 

spills have reduced by approximately 75%.”2 

Yet despite the improvement in injury and spill rates during that decade, BP has caused 

a number of disastrous or potentially disastrous workplace incidents that suggest its 

approach to managing safety has been on individual worker occupational safety but not 

on process safety. These incidents and subsequent analyses indicate that the company does 

not have consistent and reliable risk-management processes—and thus has been unable to 

meet its professed commitment to safety. BP’s safety lapses have been chronic.

Refinery accidents. Between May 29 and June 10, 2000, BP’s Grangemouth Complex 

on Scotland’s Firth of Forth suffered three potentially life-threatening accidents: a powerdistribution failure leading to the emergency shutdown of the oil refinery; the rupture of 

a main steam pipe; and a fire in the refinery’s fluidized catalytic cracker unit (which turns 

petroleum into gasoline).3 The U.K. Health and Safety Executive investigated the incidents. 

About the power loss, it said: “Subsequent investigations revealed a number of weaknesses 

Safety Culture

The United Kingdom Health and Safety Executive formally defines the safety culture of 

an organization as “the product of individual and group values, attitudes, and perceptions, 

competencies, and patterns of behavior that determine the commitment to, and the style and 

proficiency of, an organisation’s health and safety management.” A more popular description is 

that safety culture means doing the right thing even when the no one is watching. There are two 

kinds of safety: occupational safety, which refers to keeping people safe, and process safety,

which refers to the procedures for minimizing risk more generally. 
Chapter Eight 219 219

in the safety management systems on-site over a period of time which contributed to the 

succession of events that resulted in the power distribution failure.”4 

It made virtually the same comment about the other two incidents.5 The Executive’s wider 

conclusions included: 

•	 “BP Group policies set high expectations but these were not consistently achieved 

because of organisational and cultural reasons;

•	 “BP Group and Complex Management did not detect and intervene early enough on 

deteriorating performance;

•	 “BP failed to achieve the operational control and maintenance of process and systems 

required by law;

•	 “The BP Task Force findings and recommendations properly addressed the way 

forward to ensure safe and reliable operations at the Complex.”6

North Sea platforms. It was not only BP’s refineries that had problems. In November 

2003, a gas line ruptured on BP Forties Alpha platform in the North Sea, flooding the 

platform with methane. It was a windy day and there was no spark to ignite the gas,7 so 

the platform avoided the fate of the Piper Alpha (operated by Occidental Petroleum), where 

a blown gas line led to explosions that killed 165 crew members and 2 rescuers in 1988 

(see Chapter 3).8 BP admitted breaking the law by allowing pipes to corrode on the Forties 

Alpha and paid a $290,000 fine.9

On the platform that Thursday, November 27, 2003, was a BP engineer named Oberon 

Houston, who later resigned from the company. He told the Commission that BP focused 

heavily on personnel safety and not on maintaining its facilities. He added that BP was 

preparing to sell the depleted field, and was running it at minimum cost: “The focus on 

controlling costs was acute at BP, to the point that it became a distraction. They just go 

after it with a ferocity that is mind-numbing and terrifying. No one’s ever asked to cut 

corners or take a risk, but it often ends up like that.”10

The Texas City refinery explosion: a deficient safety culture. On March 23, 2005, a blast 

at BP’s Texas City refinery—the third largest refinery in the United States—killed 15 

people and injured more than 170.11 A U.S. Chemical Safety Board report on the Texas 

City refinery explosion found a recurring pattern. It concluded that “BP Group did not 

systematically review its refinery operations and corporate governance worldwide to 

implement needed changes identified in the Health and Safety Executive report and in its 

own Task Force report, even though the Group Chief Executive told staff in October 2000 

edition of BP’s in-house magazine that BP would learn lessons from Grangemouth and 

other incidents.”12

Testifying in 2007 about the Texas City event before a U.S. Senate Subcommittee, Carolyn 

W. Merritt, Chairman and CEO of the Chemical Safety Board, described the equipment 

that caused the blast as “1950s-era” and “unsafe,” and stressed that it was equipment that 

“many companies around the world ha[d] long since eliminated. . . .”13 Merritt added that 

BP had in fact considered eliminating the equipment in 2002, which had by then already 
220 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Explosion at BP’s Texas City Refinery

BP is no stranger to serious accidents. In March 2005, an explosion rocked the company’s Texas City refinery near Houston; 15 workers lost 

their lives. One year later a BP pipeline on Alaska’s North Slope ruptured, spilling more than 200,000 gallons of oil onto the fragile tundra. Yet, 

the report notes, in recent years the company’s safety record in the Gulf of Mexico has been excellent.

William Philpott/AFP/Getty Images
Chapter Eight 221 22

resulted in “a number of serious releases,” but had ultimately declined to do so “[f]or a 

variety of reasons—including cost pressures” and BP’s ability to take advantage of “the 

existence of an exemption under [U.S. Environmental Protection Agency] air 

regulations. . . .”14 

The Safety Board’s report on Texas City noted that “while most attention was focused on 

the injury rate, the overall safety culture and process safety management program had 

serious deficiencies. Despite numerous previous fatalities at the Texas City refinery (23 

deaths in the 30 years prior to the 2005 disaster) and many hazardous material releases, 

BP did not take effective steps to stem the growing risks of a catastrophic event.”15 The 

report added: “Cost-cutting and failure to invest in the 1990s by Amoco (who merged 

with BP in 1998) and then BP left the Texas City refinery vulnerable to a catastrophe. BP 

targeted budget cuts of 25 percent in 1999 and another 25 percent in 2005, even though 

much of the refinery’s infrastructure and process equipment were in disrepair. Also, 

operator training and staffing were downsized.”16 

The Safety Board further singled what it characterized as the “organizational causes 

embedded in the refinery’s culture,” including: 

•	 “BP Texas City lacked a reporting and learning culture. Reporting bad news was not 

encouraged, and often Texas City managers did not effectively investigate incidents or 

take appropriate corrective action. 

•	 “BP Group lacked focus on controlling major hazard risk. BP management paid 

attention to, measured, and rewarded personal safety rather than process safety. 

•	 “BP Group and Texas City managers provided ineffective leadership and oversight. 

BP management did not implement adequate safety oversight, provide needed 

human and economic resources, or consistently model adherence to safety rules and 

procedures. 

•	 “BP Group and Texas City did not effectively evaluate the safety implications of major 

organizational, personnel, and policy changes.” 17

At the Chemical Safety Board’s instigation, BP established its own independent panel to 

review its safety procedures and find ways to improve them.18 That panel, chaired by 

former U.S. Secretary of State James Baker III, issued its report a few months before the 

Chemical Board report in 2007. The Baker panel was no more charitable in its assessment. 

The panel found that BP management had not distinguished between occupational safety—

concern over slips, sprains, and other workplace accidents—and process safety: hazard 

analysis, design for safety, material verification, equipment maintenance, and processchange reporting. And the panel further concluded that BP was not investing leadership 

and other resources in managing the highest risks.19 

The Baker panel especially faulted BP for failing to learn the lessons of Grangemouth by 

repeating them in the events leading up to the Texas City refinery explosion. According to 

the panel, “in its response to Grangemouth, BP missed an opportunity to make and sustain 

company-wide changes that would have resulted in safer workplaces for its employees and 

contractors.”20 Underscoring the depth of the organizational problem facing BP, the panel 
222 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

singled out for criticism BP’s overall approach to accident analysis: “BP’s investigation 

system has not instituted effective root cause analysis procedures to identify systemic 

causal factors.”21 

Prudhoe Bay pipeline leak. In March 2006—one year after the Texas City refinery 

explosion and one year before the Chemical Safety Board report on it—BP had yet another 

significant industrial accident. Its network of pipelines in Prudhoe Bay, Alaska, leaked 

212,252 gallons of oil into the delicate tundra environment—the worst spill ever recorded 

on the North Slope.22 The leak went undetected for as long as five days. 23 Upon analysis, 

the pipes were found to have been poorly maintained and inspected.24 BP paid more than 

$20 million in fines and restitution.25 

Progress in follow-up on the safety recommendations. The Baker panel report contained 

10 recommendations “intended to promote significant, sustained improvements in BP’s 

process safety performance.”26 Recommendation nine advocated that BP establish an 

independent expert to monitor and report on its progress in executing the panel’s other 

recommendations in its U.S. refineries, in refining management, and at the BP board and 

executive management levels.27 In the executive summary of the third annual report of 

that expert, covering January–December 2009, he remarked that: 

Delivery against milestones related to implementation of the Recommendations remains 

a critical performance objective for the U.S. refineries. Virtually all of the milestones in 

the U.S. Refining’s 2009 plans were delivered on schedule. 

“While significant gaps have been closed and most of the new systems, processes, 

standards, and practices required for continued process safety improvements have 

been developed, much work remains to be done to fully implement them. BP must 

now demonstrate improved capability for systematic management of these systems, 

processes, standards, and practices so it can accelerate the overall pace of implementing 

the Recommendations.28 

The independent expert also noted, apropos of the Baker panel report’s final 

recommendation that BP use the lessons learned from the Texas City tragedy to transform 

the company into a recognized industry leader in process safety management: 

BP is striving to transform the company into a recognized industry leader in process 

safety . . . and . . . has made significant improvements each year in response 

to all Recommendations. However, much work remains to fully implement the 

Recommendations. . . . BP will be an industry leader when its process safety 

performance is superior to that of its peers, and its peers recognize BP as a true leader 

to emulate.29 

In recent years in the Gulf of Mexico, BP’s safety offshore drilling record was 

reportedly excellent.30 
Chapter Eight 223 223

Deepwater Horizon

BP’s safety culture failed on the night of April 20, 2010, as reflected in the actions of 

BP personnel on- and offshore and in the actions of BP’s contractors. As described in 

Chapter 4, BP, Halliburton, and Transocean did not adequately identify or address risks of 

an accident—not in the well design, cementing, or temporary abandonment procedures. 

Their management systems were marked by poor communications among BP, Transocean, 

and Halliburton employees regarding the risks associated with decisions being made. The 

decisionmaking process on the rig was excessively compartmentalized, so individuals on 

the rig frequently made critical decisions without fully appreciating just how essential 

the decisions were to well safety—singly and in combination. As a result, officials made 

a series of decisions that saved BP, Halliburton, and Transocean time and money—but 

without full appreciation of the associated risks. 

BP conducted its own accident investigation of Deepwater Horizon, but once again kept 

its scope extremely narrow.31 Professor Najmedin Meshkati of the University of Southern 

California, Los Angles—a member of the separate National Academy of Engineering 

committee investigating the oil spill—criticized BP’s accident report for neglecting to 

“address human performance issues and organizational factors which, in any major 

accident investigation, constitute major contributing factors.” He added that BP’s 

investigation also ignored factors such as fatigue, long shifts, and the company’s poor 

safety culture.32 

Upon reading the BP report, this Commission’s Chief Scientific and Engineering Advisor, 

Richard Sears, commented that “it appeared that for BP, the accident happened at 9:49 p.m. 

on April 20; whereas in some ways, the blowout began in early 2009 when they initially 

designed the well.”33 

The Culture on the Rig

BP was operator of the Macondo well and in that capacity had both the overall 

responsibility for everything that went on and was in the best position to promote a 

culture of safety on the rig, including in the actions of its two significant contractors, 

Halliburton and Transocean. But the extensive involvement of those contractors in the 

mistakes that caused the Macondo well blowout underscores the compelling need for a 

fundamental shift in industry culture that extends beyond BP. As described in Chapter 

2, offshore drilling and energy production involve a complex interrelationship among 

companies. No single company—not even at the major integrated oil companies—performs 

the full panoply of activities required for oil and gas drilling. All contract out for the 

services of other companies for critical aspects of their operations. For this same reason, 

whatever the specific contractual relationships, operating safely in this environment clearly 

demands a safety culture that encompasses every element of the extended drilling services, 

and operating industry. 

Transocean, for instance, was a major contractor for the Macondo well and is the world’s 

largest operator of offshore oil rigs, including the Deepwater Horizon; Transocean 

personnel made up the largest single contingent on the rig at the time of the accident, and 

9 of the 11 men who died on April 20 worked for the company. As described in Chapter 4, 
224 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

a number of the mistakes made on the rig can be directly traced to Transocean personnel, 

including inadequate monitoring of the Macondo well for problems during the temporary 

abandonment procedures and failure to divert the mud and gas away from the rig during 

the first few minutes of the blowout. 

A survey of the Transocean crew regarding “safety management and safety culture” 

on the Deepwater Horizon conducted just a few weeks before the accident hints at the 

organizational roots of the problem.34 The research, conducted at Transocean’s request, 

involved surveys and interviews with hundreds of employees onshore and on four rigs, 

including Deepwater Horizon, which was surveyed from March 12 to March 16. The 

reviewers found Deepwater Horizon “relatively strong in many of the core aspects of 

safety management.”35 But there were also weaknesses. Some 46 percent of crew members 

surveyed felt that some of the workforce feared reprisals for reporting unsafe situations, 

and 15 percent felt that there were not always enough people available to carry out work 

safely.36 Some Transocean crews complained that the safety manual was “unstructured,” 

“hard to navigate,” and “not written with the end user in mind”; and that there is “poor 

distinction between what is required and how this should be achieved.”37 According to 

the final survey report, Transocean’s crews “don’t always know what they don’t know. 

[F]ront line crews are potentially working with a mindset that they believe they are fully 

aware of all the hazards when it’s highly likely that they are not.”38 

Halliburton, BP’s other major contractor for the Macondo well, is one of the world’s 

largest providers of products and services to the energy industry.39 It has offices in 

70 countries, and Halliburton-affiliated companies have participated in the majority 

of producing deepwater wells and contributed to most of the world’s deepwater well 

completions.40 Yet notwithstanding its clear experience and expertise in cementing—a $1.7 

billion business for the company in 200941—Halliburton prepared cement for the Macondo 

well that had repeatedly failed Halliburton’s own laboratory tests (see Chapter 4). And 

then, despite those test results, Halliburton managers onshore let its crew and those of 

Transocean and BP on the Deepwater Horizon continue with the cement job apparently 

without first ensuring good stability results. 

Halliburton also was the cementer on a well that suffered a blowout in August 2009, 

in the Timor Sea off Australia. The Montara rig caught fire and a well leaked tens of 

thousands of barrels of oil over two and a half months before it was shut down.42 The leak 

occurred because the cement seal failed, the government report into the accident found. 

However, the report said it would not be appropriate to criticize Halliburton, because the 

operator “exercised overall control over and responsibility for cementing operations.”43 The 

inquiry concluded that “Halliburton was not required or expected to ‘value add’ by doing 

more than complying with [the operator’s] instructions.”44 In this, Montara offers yet 

another example of a lack of communication between operators and service providers and 

of the gaps between the silos of expertise that exist in the deepwater oil and gas industry.

Absence of Adequate Safety Culture in the Offshore U.S. Oil and Gas Industry

As noted, the offshore oil and gas industry is inherently risky, beginning with the initial 

exploratory activities and continuing through the transportation of oil and gas produced 
Chapter Eight 225 225

from the wells. The drilling rigs are themselves dangerous places to work, dense with 

heavy equipment, hazardous chemicals, and flammable oil and gas—all surrounded 

by the open-sea environment far from shore, where weather and water conditions can 

change rapidly and dramatically. The seriousness of these risks to worker safety and the 

environment are underscored by the sheer number of accidents, large and small, that have 

occurred in oil and gas drilling activities in the Gulf, even in the absence of a major spill 

since the 1979 Ixtoc spill, until the Macondo blowout (see graphic).45 No operator or lessee 

is immune from these safety challenges. 

But the pervasive riskiness of exploring for and producing offshore oil and gas does not 

explain the extent to which approaches to safety differ among companies, nor why they 

differ within companies depending on where they are working. From 2004 to 2009, 

fatalities in the offshore oil and gas industry were more than four times higher per personhours worked in U.S. waters than in European waters, even though many of the same 

companies work in both venues.46 This striking statistical discrepancy reinforces the view 

that the problem is not an inherent trait of the business itself, but rather depends on the 

differing cultures and regulatory systems under which members of the industry operate. 

The American Petroleum Institute: expert or advocate? In the United States, the 

American Petroleum Institute (API) has played a dominant role in developing safety 

standards for the oil and gas industry.47 And it clearly possesses significant, longstanding 

technical expertise. API produces standards, recommended practices, specifications, codes, 

technical publications, reports, and studies that cover the industry and are utilized around 

the world.48 In conjunction with API’s Quality Programs, many of these standards form 

the basis of API certification programs.49 And the U.S. Department of the Interior has 

historically adopted those recommended practices and standards, developed by technical 

experts within API, as formal agency regulations.50

Based on this Commission’s multiple meetings and discussions with leading members 

of the oil and gas industry, however, it is clear that API’s ability to serve as a reliable 

standard-setter for drilling safety is compromised by its role as the industry’s principal 

lobbyist and public policy advocate. Because they would make oil and gas industry 

operations potentially more costly, API regularly resists agency rulemakings that 

government regulators believe would make those operations safer, and API favors 

rulemaking that promotes industry autonomy from government oversight.51 

According to statements made by industry officials to the Commission, API’s proffered 

safety and technical standards were a major casualty of this conflicted role. As described by 

one representative, API-proposed safety standards have increasingly failed to reflect “best 

industry practices” and have instead expressed the “lowest common denominator”—in 

other words, a standard that almost all operators could readily achieve. Because, moreover, 

the Interior Department has in turn relied on API in developing its own regulatory safety 

standards, API’s shortfalls have undermined the entire federal regulatory system.52 

As described in Chapter 4, the inadequacies of the resulting federal standards are evident in 

the decisions that led to the Macondo well blowout. Federal authorities lacked regulations 
226 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

FIGURE 8.1: Loss of Well Control Accidents

Between 1996 and 2009, in the U.S. Gulf of Mexico, there were 79 reported loss of well control 

accidents—when hydrocarbons flowed uncontrolled either underground or at the surface. 

The regulator considers the following three factors when determining whether or not an accident will 

undergo a panel investigation: the actual and potential severity of the incident; the complexity of the 

incident; and, the probability of similar incidents occurring.

Loss of Well Control Accidents & Consequences

Date Company Consequence Code

01/24/96 Oryx Energy Company

11/10/96 Norcen Explorer, Inc.

11/27/96 Tana Oil and Gas Corporation

12/03/96 Amoco Production Company

01/10/97 BHP Petroleum, Inc.

03/04/97 Shell Offshore, Inc.

04/01/97 American Exploration Company

05/31/97 Houston Exploration Company

10/20/97 Freeport-McMoRan Resource Partners

01/06/98 Hall-Houston Oil Company

01/16/98 Chevron U.S.A., Inc.

04/30/98 Vastar Resources Inc.

07/08/98 Newfield Exploration Company

11/22/98 Ocean Energy Inc.

12/09/98 Petrobras America Inc.

02/10/99 Union Pacific Resources Company

Loss of Well Control Accidents and Resulting Consequences

• Loss of Well Control

• Panel Investigation

• Fire or Explosion

• Fatalities

• Fire or Explosion with Fatalities or Injuries

Source: Bureau of Ocean Energy Management, Regulation, and Enforcement
Chapter Eight 227 227

08/11/99 Freeport McMoran Sulphur Inc.

09/09/99 Newfield Exploration Company

12/02/99 Apache Corporation

12/05/99 Freeport McMoran Sulphur LLC

01/02/00 Callon Petroleum Operating Company

01/05/00 Apache Corporation

01/12/00 Murphy Exploration & Production Company

02/28/00 Murphy Exploration and Production Company

03/22/00 Forcenergy Inc.

04/07/00 Union Oil Company of California

08/15/00 Houston Exploration Company

11/18/00 Houston Exploration Company

03/01/01 Forest Oil Corporation

04/02/01 Newfield Exploration Company

04/04/01 Matrix Oil & Gas, Inc.

05/10/01 Devon Energy Production Company

05/24/01 BHP Petroleum (Americas) Inc.

07/06/01 Tri-Union Development Corporation

07/13/01 William G. Helis Company

10/24/01 Argo, L.L.C.

11/21/01 BP Amoco Corporation

01/12/02 BP Amoco Corporation

08/08/02 BP Exploration & Oil Inc

09/07/02 El Paso Production Oil & Gas Company

10/03/02 Murphy Exploration & Production Co. 

11/14/02 BP Exploration & Production Inc.

12/06/02 Kerr McGee Corporation

03/08/03 Anadarko E&P Company

04/12/03 Helis Oil & Gas Corporation

04/22/03 ChevronTexaco Corporation

09/02/03 Manti Operating Company

12/04/03 Walter Oil & Gas Corporation

02/09/04 Energy Partners, Ltd.

02/17/04 Orca Energy (Dunhill), L.P.

02/22/04 ATP Oil & Gas Corporation

10/21/04 Amerada Hess Corporation

03/08/05 Hunt Oil Company

05/28/05 W & T Offshore, Inc.

11/30/05 W & T Offshore, Inc.

12/01/05 Chevron USA.

02/20/06 Forest Oil Corporation

11/18/06 Dominion Exploration & Production, Inc.

01/23/07 Fairways Offshore Exploration, Inc.

03/16/07 East Cameron Partners, LP

06/24/07 Stone Energy Corporation

08/22/07 Apache Corporation

09/07/07 Eni US Operating Co. Inc.

11/20/07 BP Corporation North America Inc.

12/03/07 Rooster Petroleum, LLC

02/14/08 Apache Corporation

04/23/08 Apache Corporation

04/26/08 LLOG Exploration Offshore, Inc.

05/06/08 Mariner Energy, Inc.

08/19/08 Energy Resource Technology GOM, Inc.

10/31/08 Chevron U.S.A. Inc.

11/01/08 Union Oil Company of California

12/20/08 El Paso E&P Company, L.P.

04/19/09 LLOG Exploration Offshore, Inc.

04/23/09 Stone Energy Corporation

05/27/09 Stone Energy Corporation

08/26/09 Stone Energy Corporation

12/22/09 Not Listed

12/29/09 Murphy Exploration & Production Company
228 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

covering some of the most critical decisions made on the Deepwater Horizon that affected 

the safety of the Macondo well. For instance, notwithstanding the enormously important 

role cementing plays in well construction—especially in the high-pressure conditions 

often present in deepwater drilling—there were no meaningful regulations governing the 

requirements for cementing a well and testing the cement used. Nor were there regulations 

governing negative-pressure testing of the well’s integrity—a fundamental check against 

dangerous hydrocarbon incursions into an underbalanced well. On many of these critical 

matters, the federal regulations either failed to account for the particular challenges of 

deepwater drilling or were silent altogether.

For years, API also led the effort to persuade the Minerals Management Service not to 

adopt a new regulatory approach—the Safety and Environmental Management System 

(SEMS)—and instead has favored relying on voluntary, recommended safety practices.53 

Safety and environmental management systems are used in similar forms in other 

parts of the world and many credit them with the better safety records achieved outside 

U.S. waters (see Chapter 3). Beginning early in the last decade, the trade organization 

steadfastly resisted MMS’s efforts to require all companies to demonstrate that they have 

a complete safety and environmental management system54 in addition to meeting more 

traditional, prescriptive regulations—despite the fact that this is the direction taken in other 

countries in response to the Piper Alpha rig explosion in the late 1980s.55 Indeed, many 

operators in the Gulf were used to this safety-based approach on their rigs in the North 

Sea and Canada. It was not until this past September—after the Macondo blowout—that Fatalities per 100 Million Manhours

• United States

• North America

• Europe

Note: Europe for the International Regulators’ Forum Data Represents the United Kingdom, Norway, and the Netherlands

Source: IADC Incident Statistics Program, International Association of Drilling Contractors, http://www.iadc.org/asp.htm; 

 Safety Performance Indicators, International Association of Oil & Gas Producers, http://www.ogp.org.uk/;

 IRF Country Performance Measures, International Regulators’ Forum, 

 http://www.irfoffshoresafety.com/country/performance/.

0

1

2

3

4

5

6

7

8

International Association

of Drilling Contractors

2004–2009

International Association

of Oil & Gas Producers

2004–2009

International 

Regulators’ Forum

2007–2009

FIGURE 8.2: Fatalities from Offshore Oil and Gas Operations

Note: Europe for the International Regulators’ Forum Data Represents the United Kingdom, Norway, and the Netherlands

Source: IADC Incident Statistics Program, International Association of Drilling Contractors, http://www.iadc.org/asp.htm; 

 Safety Performance Indicators, International Association of Oil & Gas Producers, http://www.ogp.org.uk/;

 IRF Country Performance Measures, International Regulators’ Forum, 

 http://www.irfoffshoresafety.com/country/performance/.
Chapter Eight 229 229

the Department of the Interior was finally able to announce a new, mandatory Safety and 

Environmental Management System:56 almost two decades after the approach was adopted 

in the United Kingdom, where it is called the “safety case.”57 Moreover, API opposed 

revisions to the incident reporting rule that would have helped better identify safety 

risks.58

Decreasing safety-related research and development. Safely managing industrial hazards 

for oil and gas drilling requires experience and knowledge: knowing not only which actions 

to perform at various points on a checklist during a procedure, but also basic knowledge 

of the interactions of oil, gas, cement, drilling mud, sand, rock, and salt water that enables 

correct decisions when unexpected events occur. Yet such knowledge and experience within 

the industry may be decreasing. 

The chair of the University of Texas’s Department of Petroleum and Geosystems 

Engineering, Tad Patzek, testified before Congress in 2010 that “the oil and gas industry 

has eliminated most of its research capabilities, which three decades ago allowed it to 

rapidly expand deepwater production.”59 “Academic research has been important but small 

in scale and permanently starved of funding,” Patzek continued. “The depletion of industry 

research capabilities and the starvation of academia that educates the new industry leaders 

have resulted in a scarcity of experienced personnel that can grasp the complexity of 

offshore operations and make quick and correct decisions.”60 Nor, Patzek stressed, could 

industry depend upon contractors to fill the safety gap: “The individual contractors have 

different cultures and management structures, leading easily to conflicts of interest, 

confusion, lack of coordination, and severely slowed decision-making.”61*

Hazardous Industries Can Become Safer 

Even inherently risky businesses can be made much safer, given the right motivations and 

systems-safety management practices. Civil aviation and nuclear-fueled electric power 

are two good examples of industries that have had to manage the risk of catastrophic 

failures and losses. In the public sector, the United States Navy also faced the challenge of 

improving safety in its nuclear-power vessels—and did so. 

The primary motivation for improving safety in each instance is that neither the public 

(as consumers and as voters) nor the government would allow such enterprises to 

operate if they suffered many accidents. People would not board planes if an unacceptable 

number crashed. The reaction to the contained partial core meltdown at the Three Mile 

Island power plant in 1979 has kept the industry from expanding in the United States for 

more than three decades.62 And, nuclear submarines carry highly skilled crews and are 

enormously expensive to build (not to mention carrying a fuel source that would pose 

wide dangers in case of a leak)—all factors that compel the Navy to put a premium on safe 

practices. 

*

 According to Michael Bromwich, Director of the Interior Department’s Bureau of Ocean Energy Management, Regulation and Enforcement, 

the chairs of university departments of petroleum engineering whom he recently visited “expressed great concern about the level of R&D in 

the private sector into drilling and drilling safety.”
230 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Civil aviation. The airline industry, for instance, is well aware that the industry as a whole 

suffers if the public lacks trust in the safety of any one company. The Federal Aviation 

Administration (FAA) is responsible for the safety of civil aviation,63 and the airline 

industry lends resources to bolster government oversight.64 The government enhances its 

oversight abilities by relying heavily on private Designated Engineering Representatives—

either consultants or employees of aircraft manufacturers such as Boeing.65 These 

engineers work for their employers and may approve, or recommend approval of, 

technical data provided to the FAA for the company.66 It is a good example of industry and 

government “sharing” experts.67 

Boeing itself has worked closely with the FAA to improve safety performance.68 In the 

1950s, only 20 percent of Americans were willing to fly, and there were 14 to 15 major 

accidents a year.69 Boeing had a strong incentive to improve performance, and attitudes 

toward aviation, if it were to grow its commercial business. Despite an enormous increase 

(ten- to twentyfold) in airline flight operations between 1955 and 1991, the number of 

accidents fell to approximately four to five per year, one-fourth the annual rate in the 

1950s.70 

The nuclear Navy. Turning from the skies to the sea, between 1915 and 1963, the U.S. 

Navy lost about one submarine every three years to noncombat causes.71 In 1963, when 

the nuclear-powered USS Thresher was lost during a deep test dive, 112 naval personnel 

and 17 civilians perished.72 The Navy investigation found that a deficient silver-braze 

joint in a piping system had failed, flooding the engine room.73 The investigation went 

far beyond immediate causes and “found deficient specifications, shipbuilding practices, 

and maintenance practices, along with inadequate documentation of construction and 

maintenance actions and deficient operational procedures.”74 After the Thresher loss, 

Admiral Hyman Rickover, then head of the nuclear Navy, told his staff to establish a 

system to ensure that such an accident would never recur.75 The new SUBSAFE system 

was established within 54 days of the loss of the Thresher, and no SUBSAFE-certified 

submarine has since been lost.76

SUBSAFE has two goals, both crucial for submarines: maintaining the watertight integrity 

of the hull, and maintaining operability and integrity of critical systems that allow 

control and recovery from a flooding hazard.77 The system covers the administrative, 

organizational, technical, design, material-control, fabrication, testing, work-control, 

auditing, and certification aspects of submarine development and operations (see sidebar).78

As important as procedures, SUBSAFE establishes a mindset—in this case, a questioning 

attitude and what the officers call chronic uneasiness, summarized in the saying, “Trust, 

but verify.”79 

Another critical component of SUBSAFE is a separation of powers—no simple achievement 

in an organization as homogeneous and hierarchical as the Navy. In fact, there is always 

a dynamic tension among the Platform Program Managers (responsible for the costs, 

schedule, and quality of ships under their control), the Independent Technical Authority, 

and the Independent Safety and Quality Assurance Authority—the nuclear Navy’s “threelegged stool.”80 The Platform Managers can select only from a set of acceptable design 

options, to ensure that safety is not traded off for performance.81 The Technical Authority 
Chapter Eight 231 23

approves these acceptable options.82 The Safety Authority is responsible for administering 

SUBSAFE and enforcing compliance.83

SUBSAFE involves a great deal of certification (of design, materials, fabrication, and 

testing), and the overall SUBSAFE certification must be maintained through the life of the 

vessel.84 Audits assure compliance, and the audits are treated not so much as exams by 

outsiders but as constructive learning experiences.85 Continuous training and education of 

personnel are emphasized. 86 Many of the civilian contracting companies that service the 

nuclear Navy also service the offshore oil and gas industry and seem to cope well with the 

rigorous nature of the SUBSAFE system.87 

Learning from Accidents: Exxon, Shell, and Bhopal 

The Navy learned from the loss of the USS Thresher and set up an effective safety system. 

The American oil and gas industry must learn from the loss of the Deepwater Horizon and 

do the same today. 

The Exxon Valdez aftermath. Among oil and gas companies, ExxonMobil’s wake-up call 

came in 1989, when its Exxon Valdez tanker struck a reef in Prince William Sound, Alaska, 

and spilled approximately 11 million gallons of crude oil.88 Until the Deepwater Horizon

disaster, this was the biggest spill in U.S. waters.89 The spill covered thousands of miles 

of pristine waters and coastal areas, killing marine mammals, fish, and seabirds, and 

damaging the livelihoods of the people who lived and worked in the region.90 A fatigued 

and overworked crew, inadequate safety escort vessels, and a single hulled tanker have been 

cited among the causes of the accident.91 Exxon spent approximately $2.1 billion in cleanup costs, and, pursuant to a settlement with the United States and Alaska, agreed to pay a 

criminal fine of $150 million ($125 million of which was forgiven in light of its cleanup 

efforts), $100 million in criminal restitution, and $900 million to settle civil claims, subject 

to a reopener provisions allowing for an additional $100 million.92*

*

 A private civil lawsuit has been under way for the past two decades. A jury initially awarded the plaintiffs $287 million in actual damages and 

$5 billion in punitive damages, but the Supreme Court subsequently ruled that punitive damages could not exceed twice actual damages, or 

$507.5 million. Exxon Shipping Co. v. Baker, 554 U.S. 471 (2008). 

Principles of the Naval “SUBSAFE” System

•	 Top management commitment to safety 

•	 Clear and written safety requirements

•	 Education, not just training

•	 Regular rewriting of requirements

•	 Separation of powers and assignment of responsibilities

•	 Emphasis on rigor, technical compliance, and work discipline

•	 Documentation capturing what is done and why it is done

•	 Participatory audit approach, and requirements for objective quality evidence

•	 Program based on written procedures, not personality-driven

•	 Continual certification of a facility

•	 Accountability and accompanying responsibility

•	 Special efforts to be vigilant against complacency
232 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Following the spill, both government policy and industry practice changed dramatically. 

Congress enacted the Oil Pollution Act of 1990 and Exxon introduced its Operations 

Integrity Management System (OIMS) in 1992.93 ExxonMobil CEO Rex Tillerson told the 

Commission’s November 9 hearing that “OIMS is a rigorous 11-point set of elements 

designed to identify management and hazard risks. Its framework covers all aspects of 

safety, including management leadership and accountability; design, construction and 

maintenance of facilities; emergency preparedness; management of change; assessment of 

performance; and, of course, thorough inquiries into accidents and incidents.”94 

“OIMS guides the activities of each of ExxonMobil's more than 80,000 employees,” he 

continued, “as well as our third-party contractors around the world. Over time it has 

become embedded into everyday work processes at all levels. Through OIMS, ExxonMobil 

monitors, benchmarks, and measures aspects of our safety performance. Its structure and 

standards are shared and communicated the world over.”95 “Safety is not proprietary,” 

Tillerson added. “And for this reason ExxonMobil shares its best practices within our 

industry and across other industries. We seek to learn from others.”96 The reported 

improvements in the company’s safety and environmental performance have been 

impressive. In 2009, the company reported that it had received a rating of 10 out of 10 

from GovernanceMetrics International, placing it among the top one percent of companies 

Exxon Valdez Oil Spill

The crippled tanker Exxon Valdez lies atop Bligh Reef off the coast of Alaska two days after running aground on March 24, 1989. More than 

a quarter-million barrels of oil leaked into Prince William Sound, wreaking environmental havoc and becoming the largest spill in U.S. waters 

until the Deepwater Horizon disaster.

Natalie B. Fobes/National Geographic/Getty Images
Chapter Eight 233 233

rated.97* It also reported that it had had no spills from a marine vessel between 2006 and 

2009, and that in 2009 it continued to lead the industry with combined employee and 

contractor workforce lost-time incident rates at best-ever levels.98 

Shell’s safety response. Shell, a long-time leader in Gulf of Mexico operations (before BP 

surpassed it, as described in Chapter 2), has had its own safety problems. Two men died in 

a gas leak on the company’s Brent Bravo platform in 2003; former Shell senior manager 

Bill Campbell, who had earlier led a safety review, said after the accident that his 1999 

warnings had been ignored by the company.99 Shell denied that it operated at high levels of 

risk.100 

Shell subsequently tightened and simplified its safety rules.101 Shell also has promoted the 

use of the “safety case” worldwide (a risk-management approach to regulation described 

in Chapter 3).102 It has adopted the safety-case approach even in the United States, where 

it is not required to do so, and has promoted it for the industry more broadly.103 Marvin 

Odum, president of Shell Oil Company and director of Shell’s Upstream Americas business, 

told the Commission’s November 9 hearing that “the safety case in deepwater drilling 

shows how we identify and assess the hazards on a rig; how we establish the barriers to 

prevent and control those hazards; how we assign the critical activities needed to maintain 

the integrity of these barriers.”104 

Odum said that Shell also encourages workers to call for work to stop when they suspect 

that something is proceeding improperly, and gives awards to these “Goal Zero Heroes” 

(referring to the corporate goal of zero accidents).105 He added that audits are key to 

system safety and that “in 2009, DuPont administered its safety and culture survey in our 

drilling organization, comparing us to the world's best across a range of industries. While 

we ranked world-class overall, improvement areas were identified.”106 

Bhopal and Responsible Care. The chemical industry’s Responsible Care initiative was 

developed in Canada and launched in 1985 after the disastrous 1984 chemical leak in 

Bhopal, India.107 It operates in 53 countries and describes itself as “the chemical industry's 

global voluntary initiative under which companies, through their national associations, 

work together to continuously improve their health, safety and environmental 

performance, and communicate with stakeholders about their products and processes 

in the manufacture and supply of safe and affordable goods that bring real benefits to 

society.”108 The American Chemistry Council can expel member firms for non-compliance 

with Responsible Care.109 Subsequent analysis, however, suggests that the program’s 

success has turned less on the availability of such formal sanctions and more on informal 

disciplinary mechanisms such as peer pressure and institutional norms of compliance: 

“Executives from leading firms pressure their non-compliant counterparts at industry 

meetings to adopt and adhere to the industrial codes.”110 

Of course, in drawing lessons from prior accidents, it is essential that they be projected 

beyond the particular circumstances of the accident at hand, to guide present and future 

*

 Governance Metrics International (GMI) is an independent governance research and ratings firm providing institutional investors an 

objective way of assessing corporate governance risk as well as governance leaders in their portfolios. 
234 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

performance, lest government regulators and industry leaders make the classic mistake of 

“preparing to fight the last war.” As discussed in Chapters 3 and 5, despite the steps taken 

in the aftermath of Exxon Valdez to enhance transportation safety and oil spill response 

from a tanker spill, too little effort was made to take those lessons and apply them more 

broadly to the risks associated with the future of offshore drilling, in the deepwater of the 

Gulf. 

Industry Self-Policing as a Supplement to Government Regulation 

One of the key responsibilities of government is to regulate—to direct the behavior of 

individuals and institutions according to rules. Many businesses and business groups are 

involved in internal standard-setting, evaluation, and other activities that constitute selfpolicing or self-regulation. Such oversight can be conducted by a private entity established 

and supported by an industry to ensure safe operations by individual members (among 

other purposes), often because industry leaders recognize that a misstep by any one 

member necessarily has significant repercussions for them all. But even in industries with 

strong self-policing, government also needs to be strongly present, providing oversight 

and/or additional regulatory control—responsibilities that cannot be abdicated if public 

safety, health, and welfare are to be protected. 

The logic of self-policing. Industry-standard setting and self-policing organizations 

are widespread in the United States and in most industrialized nations—typically for 

operations marked by technical complexity, such as the chemical, nuclear power, civil 

aviation, and oil and gas industries, where government oversight is also present. These 

processes coexist where there are, as a practical matter, relatively limited numbers of 

people with the requisite expertise and experience, making it hard for government to be 

able to rely solely on its own personnel (especially when government cannot compete with 

private-sector salaries for those experts). Support for standard-setting and self-policing 

also arises in industries whose reputations depend on the performance of each company, 

and where significant revenues are at stake—witness both the airline industry’s private 

Designated Engineering Representatives (discussed above) and the Institute of Nuclear 

Power Operations (see below). Though the Navy is a government organization, SUBSAFE is 

also an example of self-policing to help assure the safety of its nuclear submarines. 

The limits of unregulated self-policing. Industry self-policing is not a substitute for 

government but serves as an important supplement to government oversight. And the cost 

of forgetting that essential premise can be calamitous. In the financial sector, for example, 

the Securities and Exchange Commission’s Consolidated Supervised Entities Program had, 

in 2004, delegated regulatory risk assessment of global investment bank conglomerates 

to the banks themselves.111 The program was designed to cover a regulatory gap left by 

Congress amid changes in global finance, but it was entirely voluntary.112 Four years later, 

Securities and Exchange Commission Chairman Christopher Cox ended the program, 

declaring it a failure—indeed “fundamentally flawed”—after companies like Bear Sterns 

failed to adequately assess the risk of a sharp downturn in housing prices on their large, 

leveraged investments in mortgage-backed securities.113 
Chapter Eight 235 235

A second cautionary tale involves an environmental disaster. When political opposition 

stymied federal and state regulation of toxic coal ash and other residues from power 

generation, the electric utilities that had opposed regulations deferred to the Utilities Solid 

Wastes Activities Group’s voluntary “Action Plan” to manage such wastes.114 The U.S. 

Environmental Protection Agency stepped back from regulating such hazards.115 And, in 

2008, an earthen dam containing coal ash gave way in eastern Tennessee, releasing more 

than a billion gallons of coal ash across a large portion of Roane County and polluting 

rivers that carried the hazardous wastes farther afield.116 

The Nuclear Model 

The risk-management challenges presented by nuclear power are in some respects 

analogous to those presented by deepwater drilling: the dependence on highly sophisticated 

and complex technologies, the low probability/catastrophic consequences nature of the 

risks generated, and the related tendency for a culture of complacency to develop over 

time in the absence of major accidents. For the nuclear power industry, it took a crisis—

the partial meltdown in 1979 of the radioactive core in Unit Two at the Three Mile Island 

Nuclear Generating Station—to prompt a transformation of its safety culture.117 But that 

is what industry accomplished and reportedly with significant, positive results.118 For that 

reason, the nuclear power industry’s method of transforming business-as-usual practices 

offers a useful analogue as the oil and gas industry now seeks to do the same more than 

30 years later. 

The first recommendation of the President’s Commission that investigated the root causes 

of the Three Mile Island accident was directed to industry, and made clear the extent to 

which the industry need to transform its safety culture:

[T]he nuclear industry must dramatically change its attitudes toward safety and 

regulations. The Commission has recommended that the new regulatory agency 

prescribe strict standards. At the same time . . . the industry must also set and police its 

own standards of excellence to ensure the effective management and safe operation of 

nuclear power plants.119

Two months later, in December 1979, the nuclear power industry created the Institute of 

Nuclear Power Operations (INPO), a nonprofit organization with the ambitious mission 

“to promote the highest levels of safety and reliability—to promote excellence—in the 

operation of commercial nuclear power plants.”120 

INPO’s structure more closely resembles the utilities it “regulates” than it does the 

Nuclear Regulatory Commission (NRC), the federal regulatory agency whose work INPO 

is designed to complement. INPO’s president answers to a board of directors, consisting 

of senior industry executives—mainly CEOs.121 A few years after its founding, INPO 

established its own inspection process, based on its studies of what needed inspecting and 

how to do so.122 Today, nuclear power plant inspections are thorough, but not adversarial. 

Because many INPO inspectors are nuclear employees drawn from other power plants, 

a great deal of cross-fertilization of knowledge occurs, and strong peer relationships are 

created.123 INPO’s normative system establishes a structured way of thinking about plant 
236 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

operations by translating these matters into the language of responsibility as it spells 

out what it means to occupy a particular role and what it means to behave in a manner 

appropriate to that position.124

Inspection teams and procedures. INPO inspection teams usually number about 20 people: 

one-third are permanent, full-time inspectors; one-third are on loan from the industry for 

18 to 24 months; and the remainder are peer evaluators on loan just for that particular 

inspection (but these cannot be from the utility being inspected).125

Each of the 66 nuclear sites (encompassing 104 reactors, operated by 26 utilities) is 

inspected every 24 months.126 Inspectors rotate through assignments; each inspector 

averages 4 to 5 inspections per year. (Besides the major inspection of each site every two 

years, INPO performs a series of other evaluations and provides other safety-oriented 

services throughout the year. For example, utilities’ training programs are evaluated 

and accredited every 24 months.)127 Importantly, INPO is not the sole source of plant 

inspections, but instead serves as a significant supplement. Nuclear insurers, the 

Occupational Safety and Health Administration, and the NRC also conduct inspections; 

INPO coordinates with the NRC and other inspectors to avoid schedule conflicts.128

Nor is there anything casual about an INPO inspection. It is thorough and careful, 

extending for five to six weeks: two weeks of preparation and analysis of pre-delivered 

data from the site, two weeks on the site, a week of internal review and report writing by 

functional and cross-functional sub-teams, and perhaps another week reviewing with the 

INPO president.129 Any lessons learned that are deemed valuable to the rest of the industry 

are posted on INPO’s private online portal, but the name of the site is scrubbed from the 

text.130 All plants respond to INPO’s assessment reports by documenting actions planned 

to address any reported problems. A poorly performing plant will receive higher attention 

from INPO to see if the plant’s responsive actions are on track. INPO will also work to give 

them help or coordinate help from other stations.131 Furthermore, assessment results are 

never revealed to anyone other than the utility CEOs and site managers, but INPO formally 

meets with the NRC four times a year to discuss trends and information of “mutual 

interest.” And if INPO has discovered serious problems associated with specific plants, it 

notifies the NRC.132 

The performance evaluation. INPO considers at each plant such metrics as consistency 

of operations, safety-system performance, and workers’ collective radiation exposure.133

But its Plant Performance Assessments are the real backbone of its work. These exercises 

figuratively deconstruct and reconstruct the plants, looking into all aspects of operations, 

maintenance, and engineering. The inspection teams evaluate processes and behaviors that 

cross organizational boundaries such as safety culture, self-assessment, corrective action, 

operating experience, human performance, and training. The performance of operations 

and training personnel during simulator exercises is included in each evaluation. Where 

possible, observations of plant startups, shutdowns, and major planned changes are also 

included.134
Chapter Eight 237 237

INPO strongly discourages a rule-bound, compliance-oriented approach that would 

encourage a mentality of ticking boxes—and in fact its reports are not in checklist 

form.135 Many of the risk factors that nuclear companies must deal with are beyond 

their control. One issue that is clearly within the industry’s control is standardization: 

of design requirements, resulting advanced designs, and operations. The industry has 

devoted significant time and resources to this issue over the past few decades.136 “Good 

practice” documents are written with an eye toward processes that are applicable across 

the industry.137

From the control room to the CEO. INPO directly connects those responsible for the 

day-to-day operations of nuclear plants with senior management.138 Two INPO Industry 

Review Groups, which act in an advisory capacity to senior management, enable lowerlevel employees involved in plant operations to communicate with vice presidents and 

division directors.139 Review groups also assess INPO programs and evaluate INPO’s 

performance itself.140 The existence of these groups reflects INPO’s commitment to tie 

together senior management and lower-level, operational employees. 

INPO’s influence. In addition to its individual site evaluations, INPO hosts an industry 

“CEO Conference,” usually each November, which includes numerous speakers from 

nuclear organizations and also some non-nuclear companies, with a focus on nuclear 

safety.141 During this conference, the INPO president gathers only the 26 utility CEOs 

in a private room to reveal to all the executives the grades for each site, based on the 

assessments.142 These grades range from one (most favorable) to five. Approximately 40 

percent of the grades are INPO 1, 40 to 50 percent are INPO 2, and 10 to 15 percent are 

INPO 3 or 4. (The last time any site was given a grade of 5 was in the late 1980s.)143 An 

INPO 5 indicates a site with significant operational problems, triggering a shutdown. 

And a grade of INPO 4 requires a verbal explanation by the affected CEO on the spot.144

This meeting is not intended to shame or punish, but to put the facts on the table. CEOs 

with low-rated plants typically will describe to their peers what comprehensive actions 

they are undertaking to address the causes of the problems. All CEOs recognize that it 

is in everybody’s interest to help lower performers operate better. At the larger dinner, 

with all conference attendees present, INPO announces and congratulates only the INPO 1 

plants.145 A former Chief Nuclear Officer of a major utility described INPO 1 as equivalent 

to receiving an Academy Award.146 

Presentation of relative standings before the rest of the industry produces a high level 

of peer pressure; as one CEO put it, “You get the whole top level of the utility industry 

focused on the poor performer.”147 It also gives the industry the ability to “clean out” poor 

management. Because INPO’s directors are industry peers, CEOs may become aware of 

a company taking too much risk and offer to loan people to help the “underperformer” 

come up to speed.148

The impact on insurance premiums. Although the Price-Anderson Act limits the liability 

of those who operate nuclear power plants in the case of an accident, owners of nuclear 

plants insure through Nuclear Electric Insurance Limited, an industry mutual insurance 

company, against losses associated with on-site problems such as power interruptions, 
238 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

decontamination, and physical property damage.149 Nuclear Electric Insurance Limited is 

allowed to visit INPO’s office at least once a year to view the assessment ratings (but they 

are not provided with copies).150 And, like any other insurance company, Nuclear Electric 

Insurance Limited sets insurance premiums based on its assessment of risk. Sites with 

top INPO ratings are charged lower premiums than stations with lower ratings.151 NEIL 

requires that license holders be active members of INPO or that they notify NEIL formally 

and promptly if they stop being a member – and they must show NEIL how they will 

accomplish a level of oversight equivalent to what INPO provides. This has never occurred.

In reality, NEIL's board would quickly discuss removal of insurance coverage should a 

member choose to drop out of INPO activities.152 So utilities have a tremendous financial 

incentive to carry out INPO's recommendations.153

Compensation competitive with industry. INPO has about 400 employees, including about 

60 on long-term loan from its member utilities. Of the total staff and management cadre, 

250 are nuclear technical personnel.154 INPO can do its job only if its employees possess 

technical expertise at least equal to that possessed by those in the industry INPO is charged 

with overseeing. To a certain extent, INPO achieves that standard by relying on experts on 

loan from industry for extended periods of time.155 But to ensure that INPO’s own full-time 

personnel possess the requisite qualifications, industry salaries are benchmarked, and INPO 

provides its employees comparable compensation.156 INPO has therefore not suffered from 

the expertise gap too often evident with government inspectors (witness the issue raised at

the founding of the Minerals Management Service, as discussed in Chapter 3). INPO can pay 

these higher salaries because it is not subject to the same budgetary constraints faced by a 

public agency. Each utility contributes to INPO’s budget based on the number of reactors it 

owns. Budgets are approved by INPO’s board each autumn. (INPO’s fiscal year 2010 budget 

was $99 million, with more than $100 million budgeted for 2011.)157

INPO “clout” and industry acceptance. INPO’s ability to achieve widespread acceptance 

within the nuclear power industry was not preordained. The new self-policing enterprise 

had to earn the necessary reputation for fairness and integrity over time.158 A formative 

moment in gaining the necessary stature occurred in 1988, when INPO helped bring about 

the firing of a utility’s corporate leadership following a plant shutdown.159 Beginning 

in December 1984, INPO inspectors reported pervasive safety problems at Philadelphia 

Electric’s Peach Bottom nuclear plant—including incidents of employees literally sleeping 

on the job. When INPO was dissatisfied with the plant’s response to these concerns, it 

scheduled more inspections and meetings with Philadelphia Electric officials, and sent 

letters further detailing the depth of its concerns. These concerns prompted the NRC to 

order a shutdown of the plant, and when Philadelphia Electric submitted a recovery plan to 

the Commission to restart the plant, an INPO-convened industry panel sharply condemned 

the plan as seriously flawed. INPO and the NRC worked closely and cooperatively, with 

INPO so harshly criticizing Philadelphia Electric’s management that several top executives 

ultimately lost their jobs. From then on, the message within the industry was clear: “INPO 

has a great deal of clout” and Peach Bottom became a symbol of INPO’s new power. 160
Chapter Eight 239 239

Although INPO has its detractors,* it does appear to have helped the nuclear power 

industry improve and maintain performance and safety during the past three decades. 

INPO has helped the industry measure its progress in improving safety standards and 

has served as a vehicle for making advances in control-room design, plant and personnel 

performance, training and qualification, self-regulation, emergency response, maintenance, 

and radiation protection, among other areas.161 During the past 30 years, the nuclear 

industry has improved plant efficiency, significantly reduced the number of automatic 

emergency reactor shutdowns per year, and reduced collective radiation accident rates by 

a factor of six compared to the 1980s.162 The industry has achieved these milestones, in 

part, through INPO’s role in promoting a strong nuclear safety culture and presenting 

performance objectives and criteria to help the industry strive for and surpass safety 

goals.163 

An INPO for Oil? 

In the aftermath of the Deepwater Horizon spill, could the oil and gas industry similarly 

improve its safety culture by creating a self-policing entity like INPO as a supplement 

to government oversight? There are clear parallels that would strongly support such an 

effort, but also some equally clear differences between the oil and gas industry and the 

nuclear power industry that at least caution against wholesale adoption of the INPO 

model. 

Similarities: Need, incentive, and means. The reason the INPO model holds promise is 

because the oil and gas industry, like the nuclear power industry after Three Mile Island, 

has both the substantial economic resources and the necessary economic incentive to make 

it happen. INPO was formed because doing so was in industry’s self-interest.164 As the 

Deepwater Horizon disaster made unambiguously clear, the entire industry’s reputation, 

and perhaps its viability, ultimately turn on its lowest-performing members.†

 If any one 

company is involved in an accident with widespread and potentially enormous costs, 

like those that followed the Macondo blowout, everyone in the industry—companies 

and employees—suffers, as do regional economies and the nation as a whole. No one, in 

industry or in government, can afford a repeat of the Macondo explosion and spill. Also, as 

the enormous sums that BP was willing and able to expend to contain and respond to the 

Gulf spill make clear (see Chapter 5), the oil and gas industry possesses the financial means 

to fund a very healthy and effective self-policing organization akin to INPO. 

A second fundamental parallel is that no one in the oil and gas industry has the unilateral 

right to engage in offshore drilling on the outer continental shelf any more than a utility 

has the right to construct and operate a nuclear power plant absent federal governmental 

approval. Indeed, the extent of governmental authority is even greater in the offshore 

context. The oil and gas industry does not own the valuable energy resources located on 

the outer continental shelf, which belong to the American people and are managed by the 

federal government on their behalf. As described in Chapter 3, the government accordingly 

*

 The Union of Concerned Scientists has on occasion faulted INPO (and the Nuclear Regulatory Commission) for not inspecting some plants 

with sufficient rigor and skepticism, and has pointedly raised the issue whether the fact that industry pays for INPO’s services presents a 

conflict of interest that compromises its essential impartiality.

† This was also the case in the INPO context; in part, industry mobilized to unify “in reaction to a mutual internal threat, unsafe nuclear 

utilities.” Joseph Rees, Hostages of Each Other (Chicago: The University of Chicago Press 1994), 44.
240 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

possesses sweeping authority to dictate the terms of private access to those resources in 

its lease agreements with private parties. And, in particular, government could decide to 

condition such access, either directly or indirectly, on participation with an industry safety 

institute.

A third clear parallel is the possibility in both contexts—offshore drilling and nuclear 

power—for industry self-policing to supplement government regulation.165 As 

described in Chapter 3, government regulators need to improve their in-house technical 

expertise dramatically,166 but they are unlikely ever to possess technical expertise truly 

commensurate with that of private industry. The salary differential, combined with the 

sheer depth of industry expertise on a wide variety of topics critical to understanding and 

managing offshore drilling operations, would make that goal illusory. Such expertise is, 

however, a prerequisite for the thorough, rigorous inspections required to ensure safe 

operation of dozens of deepwater exploration rigs and production platforms (the former 

operating in multiple locations and different geologies each year)167—a number that 

rises sharply if installations in shallower Gulf waters are included. By supplementing 

governmental oversight, with the kind of self-policing accomplished by INPO for nuclear 

power, that gap in expertise can be sharply narrowed. Government can never abdicate its 

ultimate responsibility to ensure drilling safety, but it can effectively take advantage of 

industry expertise to meet that objective. 

Differences that warrant modifying the INPO model. But there are also clear differences 

between the two industries that would require a differently defined self-policing entity 

for offshore oil and gas. For instance, the U.S. nuclear power industry is based at a 

limited number of fixed sites, using a small number of known technological designs, and 

operated by an industry subject to comprehensive public regulation168—from permission 

to construct facilities through detailed oversight of design, operations, and maintenance. 

The oil and gas industry is structured much differently. As described by ExxonMobil’s 

Tillerson, his industry “is moving to different locations, different environments, evolving, 

all kinds of technologies being introduced.”169 For this reason, he explained, while the oil 

and gas industry can “look at the principles around INPO in terms of how do you share 

best practices, how do you assess where the companies are operating at certain levels of 

competency?”170, he appeared to suggest there would be limits in the application of every 

aspect of the INPO model to offshore drilling for oil and gas. 

The oil and gas industry is more fragmented and diversified in nature—from integrated 

global oil companies to independent exploration and drilling enterprises—and therefore less 

cohesive than the nuclear power operators who joined to establish INPO.* As a result, it 

could be more challenging to create an INPO-like organization. And oil and gas executives 

would need assurances that any industry-wide efforts to promote better safety did not 

subsequently serve as the basis for claims that industry had violated antitrust laws.

Finally, concerns about potential disclosure to business competitors of proprietary 

information might make it harder to establish an INPO-like entity in the oil and gas 

*

 Prior to the Three Mile Island accident, however, the nuclear power industry was reportedly far less cohesive than it became after that accident. See Rees, Hostages of Each Other, 42 (“when officials describe the pre-TMI nuclear industry, a collective portrait emerges in which 

each nuclear utility behaved like an ‘island unto itself’ or ‘independent barony.’ In short, the industry was fragmented.”) (emphasis in original).
Chapter Eight 241 24

industry. Technology and design apparently are more uniform in nuclear power than in 

offshore drilling. For this reason, Michael Bromwich, Director of the Bureau of Ocean 

Energy Management, Regulation, and Enforcement (the successor to MMS), cautioned 

that an INPO-like approach might run into problems if companies perceived the potential 

for inspections of offshore facilities to reveal “technical and proprietary and confidential 

information that companies may be reluctant to share with one another.”171 

Essential Features of a Self-Policing Safety Organization for the Oil and Gas 

Industry 

Like the nuclear power industry in 1979—in the immediate aftermath of the Three Mile 

Island accident—the nation’s oil and gas industry needs now to embrace the potential for 

an industry safety institute to supplement government oversight of industry operations. 

Akin to INPO, such a new safety institute can provide the nation with the assurances of 

safety necessary to allow the oil and gas industry access to the nation’s energy resources 

on the outer continental shelf. To be sure, the significant differences between the two 

types of industries warrant significant differences in the precise structure and operation of 

their respective industry safety institutes. But, as elaborated below, the basic, successful 

principles upon which the INPO model is premised can serve as the touchstones for the oil 

and gas industry in establishing its own. 

Credibility. To be credible, any industry-created safety institute would need to have 

complete command of technical expertise available through industry sources—and 

complete freedom from any suggestion that its operations are compromised by multiple 

other interests and agendas. As a consensus-based organization, the American Petroleum 

Institute (API) is culturally ill-suited to drive a safety revolution in the industry. For this 

reason, it is essential that the safety enterprise operate apart from the API. As described 

above and in Chapter 3, API’s longstanding role as an industry lobbyist and policy 

advocate—with an established record of opposing reform and modernization of safety 

regulations—renders it inappropriate to serve a self-policing function. In the aftermath 

of the Deepwater Horizon tragedy, the Commission strongly believes that the oil and 

gas industry cannot persuade the American public that it is changing business-as-usual 

practices if it attempts to fend off more effective public oversight by chartering a selfpolicing function under the control of an advocacy organization.

An industry-wide commitment to rigorous auditing and continuous improvement. The 

INPO experience makes clear that any successful oil and gas industry safety institute 

would require in the first instance strong board-level support from CEOs and boards 

of directors of member companies for a rigorous inspection and auditing function. 

Such audits would need to be aimed at assessing companies’ safety cultures (from 

design, training, and operations through incident investigation and management of 

improvements) and encouraging learning about and implementation of enhanced practices. 

As at INPO, the inspection and auditing function would need to be conducted by safety 

institute staff, complemented by experts seconded from industry companies, able to 

analyze the full range of technologies and practices, and designed to promote crosscompany learning and shared responsibility while protecting proprietary information. 
242 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

There would also need to be a commitment to share findings about safety records and 

best practices within the industry, aggregate data, and analyze performance trends, 

shortcomings, and needs for further research and development. Accountability could be 

enhanced by a requirement that companies report their audit scores to their boards of 

directors and insurance companies.

The main goal is to drive continuous improvement in every company’s standards and 

performance, measured against global benchmarks. The means, to that end, include the 

safety auditor’s reviews; insurer evaluations of risk; and management recognition of and 

incentives for effective behavior. Senior leadership would be accountable to the company’s 

board of directors, who in turn would be accountable to investors. 

In a broader sense, the industry’s safety institute could facilitate a smooth transition 

to a regulatory regime based on systems safety engineering and improved coordination 

among operators and contractors—the principles of the U.K.’s “safety case” that shifts 

responsibility for maintaining safe operations at all times to the operators themselves. It 

should drive continuous improvement in standards and practices by incorporating the 

highest standards achieved globally, including (but not exclusively) those set by the API. 

An initial set of standards and scope of operation. The industry needs to benchmark 

safety and environmental practice rules against recognized global best practices. The Safety 

and Environmental Management Program Recommended Practice 75 (API RP 75) developed 

in 1993 by the API and incorporated by reference in the Department of the Interior’s new 

workplace safety rules, adopted in October 2010, is a reasonable starting point.172 Updates 

to those safety rules are needed immediately, but a new industry safety institution could 

make a credible start by requiring members to adopt all safety standards promptly—and 

mandating that the companies, in turn, require that their contractors and service providers 

comply with the new safety rules. 

Because the number of offshore drilling operations subject to potential inspection is much 

greater than the number of nuclear sites INPO must review (although the number of 

exploratory rigs on the outer continental shelf is comparable to the number of nuclear 

plant sites), any new oil and gas industry safety institution will likely need, as a practical 

matter, to phase in its inspections over time. Accordingly, the safety institute will need to 

identify those operations that present the greatest risks because of the type of drilling (for 

example, deepwater or ultra-deepwater), the challenges of drilling in a particular kind of or 

less-well-known geologic formation, or the location of the operation in a remote frontier 

area where containment and response resources may be fewer.* Over time, the safety 

institute might move to cover more offshore operations to reduce the risk of accidents that 

can lead to loss of life or property, or environmental damage. 

*

 Given the speed with which companies are moving into ever deeper, less well understood geologic formations, the institute will have to 

move quickly. 
Chapter Eight 243 243

Industry Responsibilities for Containment and Response

Industry’s responsibilities do not end with efforts to prevent blowouts like that at the 

Macondo well. They extend to efforts to contain any such incidents as quickly as possible 

and to mitigate the harm caused by spills through effective response efforts. As described 

in Chapter 5, once a spill occurs, the government must be capable of taking charge of those 

efforts. But government depends upon the resources and expertise of private industry 

to contain a blown-out well and to respond to a massive subsea oil spill. Chapter 5 also 

explains how woefully unprepared both government and industry were to contain or 

respond to a deepwater well blowout like that at Macondo. All parties lacked adequate 

contingency planning, and neither government nor industry had invested sufficiently 

in research, development, and demonstration to improve containment or response 

technology. Notwithstanding its promises in the aftermath of Exxon Valdez that industry 

would commit significant funds to support more research and development in response 

technology—through the “Marine Spill Response Corporation,” for example—those 

commitments were soon forgotten as memories dimmed.173

From now on, the oil and gas industry needs to combine its commitment to transform its 

safety culture with adequate resources for containment and response. Large-scale rescue, 

response, and containment capabilities need to be developed and demonstrated—including 

FIGURE 8.3: Schematic of the Marine Well Containment System

Courtesy of the Marine Well Containment Company LLC
244 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

equipment, procedures, and logistics—and enabled by extensive training, including fullscale field exercises and international cooperation. 

To that end, at least two industry spill containment initiatives have emerged that build on 

ideas and equipment that were deployed in response to the Macondo blowout and spill. The 

nonprofit Marine Well Containment Company, created in July 2010 by four of the five 

major, integrated oil and gas companies (with BP subsequently announcing its intention 

to join), is a significant step toward improving well containment capability in the Gulf of 

Mexico.174 The four founding companies have committed $1 billion for startup costs to 

develop the Marine Well Containment Company’s rapid-response system, which includes 

modular containment equipment that can be used to collect oil flowing from a blown-out 

deepwater well. The system is designed to mobilize within 24 hours and be operational 

within weeks, ready to contain spills 10,000 feet below the surface, at volumes up to 

100,000 barrels per day.175 Although many of the details surrounding the company’s 

governance and membership structure have not yet been finalized, membership is open 

to all oil and gas operators in the Gulf of Mexico. Nonmembers will be able to gain access 

through service contracts.176 

The second spill containment initiative is being coordinated by Helix Energy Solutions 

Group, which played a major role in the Macondo well containment efforts. Helix is 

seeking industry participation to make permanent modifications to the equipment it 

used in responding to the Macondo blowout and spill. It offers more modest containment 

capacity than the Marine Well Containment Company—less than the 100,000 barrels per 

day without additional investment—but at a lower cost. Although Helix maintains that it 

is not in competition with the Marine Well Containment Company,177 its system appears 

to be attracting the interest of many of the independent oil and gas producers in the Gulf, 

who have expressed concerns about cost of and access to the Marine Well Containment 

Company.178 

The Marine Well Containment Company and Helix spill containment proposals are 

promising, but they have at least two fundamental limitations. First, the systems are not 

designed to contain all possible catastrophic failures, only the next Deepwater Horizontype spill. For instance, while both systems are designed to contain quickly the kind of 

blowout that happened at Macondo, they would not be able to contain a spill of the 

type that occurred in the Gulf of Mexico in 1979 during the Ixtoc oil spill, where the rig 

collapsed on top of the well. In addition, neither the Marine Well Containment Company’s 

planned capabilities nor Helix’s go past 10,000 feet despite the fact that current drilling 

technology extends beyond this depth.

Second, and perhaps most important, it seems that neither the Marine Well Containment 

Company nor the Helix system is structured to ensure the long-term ability to innovate 

and adapt over time to the next frontiers and technologies. What resources, if any, either 

initiative will dedicate to research and development going forward are unclear. The Marine 

Well Containment Company, in particular, could become another Marine Spill Response 

Corporation (as described in Chapter 5)—an industry nonprofit initiative created in 

response to a major oil spill that becomes underfunded and fails to innovate over time—if 
Chapter Eight 245 245

it does not implement specific policies and procedures to monitor and guarantee its longterm readiness as well as funding and investment levels. 

The primary long-term goal of a spill containment company or consortia should be to 

ensure that an appropriate containment system is readily available to contain quickly 

spills in the Gulf of Mexico with the best available technology. Any spill containment 

company or consortia should ensure that it remains focused on this goal, even when 

doing so potentially conflicts with the short-term interests of its founding companies, 

in the case of Marine Well Containment Company, or the parent company, in the case 

of Helix. An independent advisory board, with representatives from industry, the federal 

government, state and local governments, and environmental groups could help keep any 

spill containment initiative focused on innovative, adaptive, effective spill response over the 

long term. 

As next-generation equipment is developed, industry must ensure that its containment 

technology is compatible with its wells. For instance, it may be useful to consider 

design modifications to blowout preventer stacks that would allow for more expeditious 

hook-ups of injection and evacuation networks and hoses, reducing the capital costs 

and increasing the flexibility of the spill containment companies or consortia. Capping 

and containment options should also be developed in advance to contain blowouts from 

platform wells. 

Managing Liability 

The market has a financial mechanism for encouraging risk-managing behaviors: the 

cost of insurance. In the wake of Deepwater Horizon oil spill, early reports indicated 

that insurance premiums rose by as much as 15 to 25 percent in shallow waters and 

up to 50 percent for deepwater rigs.179 An energy underwriter predicted that premiums 

for deepwater operations would rise 25–30 percent and by 100 percent for deepwater 

drilling.180 Companies insure for many perils, and a major reinsurer has represented to 

the Commission that there is ample additional coverage for most risks. The significant 

exception is third-party liability, about which there remains considerable uncertainty.181

The liability cap. Under the Oil Pollution Act of 1990 (the Act), responsible parties, 

including the lessees of offshore facilities, are strictly liable for removal costs and certain 

damages resulting from a spill.182 Compensable damages are defined in the Act.183 Removal 

costs themselves are unlimited, but there is a cap on liability for damages: for offshore 

facilities, $75 million.184 The cap does not apply in cases of gross negligence, violation of 

an applicable regulation, or acts of war, and does not limit the amount of civil or criminal 

fines that might be imposed for violations of federal law, such as the Clean Water Act, nor 

does it limit damages under state law.185 

As it became apparent that the damages from the Deepwater Horizon oil spill were likely 

to be orders of magnitude greater than the existing cap, Congress began to consider raising 

that cap significantly (to as much as $10 billion) or even eliminating it altogether.186 The 

arguments in favor of such a change are straightforward. The amount of potential damage 

caused by a major spill clearly exceeds the existing caps, and one cannot fairly assume 
246 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

that the responsible party causing a future spill will, like BP, have sufficient resources to 

fully compensate for that damage. Nor should the spill’s victims or federal taxpayers have 

to pay the bill for industry’s shortcomings. Increasing liability limits would also serve as 

a powerful incentive for companies to pay closer attention to safety, including investing 

more in technology that promotes safer operations. 

Notwithstanding these arguments in favor of at least raising the liability cap, legislative 

efforts quickly stalled when members of Congress learned more about the potential impact 

on the structure of the oil and gas industry. A substantial portion of the offshore industry 

in the Gulf is made up of smaller, independent operators who fear that they would be 

unable to afford the dramatically higher insurance premiums that would result from 

a significant raising or elimination of the cap.187 The concern is that lifting the liability 

cap immediately could have a harmful, anticompetitive impact on the independents and 

their thousands of employees and other commercial interests. Both large and small firms 

argue that the result would be detrimental, among other reasons, because the independent 

producers develop many smaller and end-of-life oil fields that the larger firms find 

uneconomic. 

Apart from the handful of major companies, like BP, none in the oil and gas industry have 

the ability to self-insure against a major accident. But under current law, no company 

operating in the Gulf has had to demonstrate financial capacity to cover liabilities 

amounting to anything close to the cost of the BP spill—extending into the tens of billions 

of dollars.188 Analysts have suggested that the insurance industry could adjust over time 

to the demand for capacity.189 In fact, Munich Re announced on September 12, 2010, that 

it has developed a new concept for insuring offshore oil drilling, which has the potential 

to create coverage on the order of $10–20 billion per drilling operation.190 Other proposals 

include mutual insurance funds that would pool risks.191 The effectiveness of such 

mechanisms is currently unknown.192 Congress and industry are considering a series of 

more nuanced measures that, while raising the cap, also seek to anticipate and mitigate 

the potentially adverse impact on the smaller, independent operators in the Gulf without 

distorting incentives to avoid accidents to begin with, or to be adequately prepared to 

respond to and contain spills that do occur. None of these proposals had been enacted by 

the end of 2010. 
Chapter Eight 247 247

The Challenge of Change 

Changing institutional culture and behavior is rarely easy. Business interests naturally 

prefer stable laws and market conditions that allow planning and investments (which can 

run into the billions of dollars for extensive deepwater operations in the Gulf) based on 

a clear understanding of what the future holds. But in the aftermath of the Deepwater 

Horizon spill, the operating environment and legal regime have been in constant flux. 

Beginning with a drilling moratorium, the industry has been struggling since the spring 

to recover from the nation’s loss of trust in the safety of its operations, especially in the 

deepwater Gulf. 

The oil and gas industry needs now to regain that trust, but doing so will require it to 

take bold action to make clear that business will no longer be conducted as usual in the 

Gulf. Industry must seize the opportunity to demonstrate that it is fully committed to 

subjecting its own internal operations to fundamental change and not merely because 

it is being forced to do so. Underscoring the sincerity and depth of their commitment to 

embracing a new safety culture, company leaders will need to lead the effort to guarantee 

that risk management improves throughout the industry to ensure that the mistakes made 

at the Macondo well are not repeated. And those leaders must also demonstrate an equal 

commitment to ensuring adequate containment and response technology and resources in 

case another spill happens. Only then will the oil and gas industry truly demonstrate that 

it is ready, willing, and able to engage in the kind of responsible offshore drilling practices 

upon which the nation’s basic energy supplies depend. 

Chapter Nine 249 249

Investing in Safety, Investing in 

Response, Investing in the Gulf

Introduction

The President asked this Commission to “develop 

options for guarding against, and mitigating 

the impact of, oil spills associated with offshore 

drilling”1 in recognition of the compelling need to 

balance the nation’s interest in offshore energy 

resources with protection of our rich marine 

and coastal environments. To that end, previous 

chapters of this report have detailed the complex 

web of decisions, actions, and circumstances 

Chapter Nine 

“Develop 

options for 

guarding 

against, and 

mitigating 

the impact 

of, oil spills 

associated 

with offshore 

drilling.”

Ugly fallout from the spill, tarballs foul a beach near Venice, Louisiana. The report sets out a 

broad array of recommendations for action by the federal government to better manage and 

protect the nation’s offshore energy resources. Two overarching and convergent goals: minimize 

the risk of another major spill along with its economic and environmental consequences—and 

be prepared when it happens. 

< Win McNamee/Getty Images
250 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

that set the stage for the BP Deepwater Horizon disaster. Among the chief actors in that 

web was the government itself, which played a key role both in setting the policies that 

shaped offshore oil and gas activities in the Gulf over the course of many decades, and in 

overseeing responses to the spill once it began.

This chapter presents the Commission’s recommendations for addressing the causes and 

consequences of the spill with a focus on the government’s role (recommendations targeted 

to industry are presented in Chapter 8). The recommendations reflect the government’s 

sweeping sovereign authority as both owner of the seabed and water column and as 

the regulator of activities, with the overriding responsibility to manage and protect the 

valuable resources of the Outer Continental Shelf (OCS) on behalf of current and future 

generations of Americans. They are grouped in seven distinct areas: 

A. Improving the Safety of Offshore Operations

B. Safeguarding the Environment

C. Strengthening Oil Spill Response, Planning, and Capacity

D. Advancing Well-Containment Capabilities

E. Overcoming the Impacts of the Deepwater Horizon Spill and Restoring the Gulf

F. Ensuring Financial Responsibility

G. Promoting Congressional Engagement to Ensure Responsible Offshore Drilling 

The sections that follow summarize the context and rationale for each of the Commission’s 

specific recommendations. Other chapters of this report, as well as staff working papers 

published by the Commission and available at www.oilspillcommission.gov,*

 provide 

additional detail and further support for the recommendations. Chapter 10 presents 

additional recommendations concerning the future of offshore drilling, including 

prospective drilling in the Arctic.

A. Improving the Safety of Offshore Operations

As detailed in Chapters 3 and 4, and in staff working papers, federal efforts to regulate the 

offshore oil and gas industry have suffered for years from cross-cutting purposes, pressure 

from political and industry interests, a deepening deficit of technical expertise, and severely 

inadequate resources available to the government agencies tasked with the leasing function 

and regulation. In the aftermath of the Deepwater Horizon oil spill, the Department of the 

Interior has already taken a series of significant and important steps to improve regulatory 

oversight of offshore drilling. But given the deep-rooted problems that had existed at the 

Department’s Minerals Management Service (MMS) before the spill occurred, and the near 

certainty that the oil and gas industry will seek to expand into ever more challenging 

environments in the years ahead, a more comprehensive overhaul of both leasing and 

the regulatory policies and institutions used to oversee offshore activities is required. The 

necessary overhaul, to be successful, must address three core issues: (1) reducing and 

managing risk more effectively using strategies that can keep pace with a technologically 

* A list of staff working papers can be found in Appendix F.
Chapter Nine 251 25

complex and rapidly evolving industry, particularly in high-risk and frontier areas; 

(2) assuring the independence and integrity of government institutions charged with 

protecting the public interest; and (3) securing the resources needed to provide a robust 

capability to execute the leasing function and adequate regulatory oversight. 

1. The Need for a New Approach to Risk Assessment and Management

As described in Chapter 3 and staff working papers, neither the industry’s nor the federal 

government’s approaches to managing and overseeing the leasing and development of 

offshore resources have kept pace with rapid changes in the technology, practices, and 

risks associated with the different geological and ocean environments being explored 

and developed for oil and gas production. Nor do these approaches reflect the significant 

changes that have occurred in the structure of the oil and gas industry itself—especially 

the rise of specialized service contractors and the general trend toward outsourcing 

multiple functions. When the operator directly regulated by the government does not itself 

perform many of the activities critical to well safety, regulators face additional challenges 

due to the separation of these functions. However, MMS did not change its regulatory 

oversight to respond to these industry changes by making the service companies more 

accountable. In other countries, operators of drilling are required to demonstrate to the 

regulators their own fitness and risk management systems. 

Also missing has been any systematic updating of the risk assessment and risk 

management tools used as the basis for regulation. MMS attempted under several 

administrations to promulgate regulations that would have required companies to manage 

all of their activities and facilities, and those of their contractors, under a documented 

Safety and Environmental Management System (SEMS). But, in the face of industry 

opposition, MMS did not adopt such a requirement until September 2010, after the BP 

Deepwater Horizon disaster. Industry objections also derailed a past MMS proposal to 

expand data reporting requirements as part of an effort to track and analyze offshore 

incidents and to identify safety trends and lagging and leading indicators. The proposal was 

abandoned when the Office of Management and Budget agreed with industry complaints 

about compliance cost (industry also complained about the potential for overlap with 

Coast Guard reporting requirements). As a result, there has historically been no legal 

requirement that industry track or report instances of uncontrolled hydrocarbon releases 

or “near misses”—both indicators that could point to a heightened potential for serious 

accidents. The United States has the highest reported rate of fatalities in offshore oil and 

gas drilling among its international peers, but it has the lowest reporting of injuries. This 

striking contrast suggests a significant under-reporting of injuries in the United States and 

highlights the need for better data collection to ensure needed attention to worker safety. 

Government agencies that regulate offshore activity should reorient their regulatory 

approaches to integrate more sophisticated risk assessment and risk management practices 

into their oversight of energy developers operating offshore. They should shift their focus 

from prescriptive regulations covering only the operator to a foundation of augmented 

prescriptive regulations, including those relating to well design and integrity, supplemented 

by a proactive, risk-based performance approach that is specific to individual facilities, 
252 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

operations, and environments. This would be similar to the “safety case”* approach that 

is used in the North Sea, which requires the operator and drilling rig owners to assess the 

risks associated with a specific operation, develop a coordinated plan to manage those risks, 

integrate all involved contractors in a safety management system, and take responsibility 

for developing and managing the risk management process. 

To accomplish these goals of creating a new approach to risk assessment and management, 

the Commission offers the following three recommendations:

Recommendations

A1: The Department of the Interior should supplement the risk-management program 

with prescriptive safety and pollution-prevention standards that are developed and 

selected in consultation with international regulatory peers and that are at least as 

rigorous as the leasing terms and regulatory requirements in peer oil-producing 

nations.

A2: The Department of the Interior should develop a proactive, risk-based 

performance approach specific to individual facilities, operations and environments, 

similar to the “safety case” approach in the North Sea. 

A3: Working with the International Regulators’ Forum and other organizations, 

Congress and the Department of the Interior should identify those drilling, production, 

and emergency-response standards that best protect offshore workers and the 

environment, and initiate new standards and revisions to fill gaps and correct 

deficiencies. These standards should be applied throughout the Gulf of Mexico, 

in the Arctic, and globally wherever the international industry operates. Standards 

should be updated at least every five years as under the formal review process of the 

International Organization for Standardization (ISO). 

More specifically, the following actions are needed to truly transition to a proactive, riskbased performance approach: 

 

•	 Engage a competent, independent engineering consultant to review existing 

regulations for adequacy and “fit for purpose” as a first step toward benchmarking 

U.S. regulations against the highest international standards. Following this review, 

develop and implement regulations for safety and environmental protection that are 

at least as rigorous as the regulations in peer oil-producing nations. A new regulatory 

entity for safety and environment (as described below) should ensure that while 

engaged in petroleum activities all drilling and production platforms are certified and 

operating at the highest level of international regulatory practice. 

•	 Require operators to develop a comprehensive “safety case” as part of their 

exploration and production plans—initially for ultra-deepwater (more than 5,000 

* The term “safety case” is a shorthand expression for a comprehensive and structured set of safety documentation that provides a basis for determining whether a risk 

management system for a specific vessel or equipment is adequately safe for a given application in a given environment.
Chapter Nine 253 253

feet) areas, areas with complex geology, and any other frontier or high-risk areas—

such as the Arctic. In addition, for lease sales in those and other areas, prospective 

lessees should be required to demonstrate competence, based on experience, financial 

capacity, and expertise, as a prequalification for bidding. 

•	 Expand Safety Environmental Management System requirements to include regular 

third-party audits at three- to five-year intervals and certification. These plans should 

be expanded for frontier areas to encompass the full range of risk assessment and 

management. 

•	 For both new and transferred leases, require the operator to participate in a 

new safety institute or agree to expert audits, and to contribute to safety and 

environmental research and development. Approval to transfer leases sold prior to 

this requirement should be conditioned on the new requirements based on risk factors 

related to the specific requirements of the lease. The lease stipulation should also 

include the requirement that the operator possess adequate capability to contain and 

respond to an oil spill, and sufficient financial capacity to compensate for damages 

caused by a spill. 

•	 To cultivate and maintain government expertise on offshore drilling safety: 

(1) Establish a process under the auspices of the National Academy of Engineering 

to identify criteria for high-risk wells and develop methodology to assess those 

risks. This process should include, to the extent that the National Academy deems 

appropriate, input from experts in the U.S. Geological Survey, the Department of 

Energy, NOAA, and academia. Furthermore, the Department of the Interior should 

develop in-house competence to perform such sophisticated risk assessments. 

Such evaluations could guide the transition to a system where all operators and 

contractors are required to demonstrate an integrated, proactive, risk management 

approach prior to leases being granted or receiving permits for exploration wells and 

major development projects. As noted above, these efforts should initially focus on 

areas with complex geology, ultra-deep water, and any other frontier or high-risk 

areas—such as the Arctic.

(2) Establish a coordinated, interagency research effort to develop safer systems, 

equipment, and practices to prevent failures of both design and equipment in the 

future. The federal government has relevant expertise in areas such as the application 

of remote sensing and diagnostics, sensors and instrumentation, and command 

electronics that could and should be transferred to the offshore industry.*

 The UltraDeepwater and Unconventional Natural Gas and Other Petroleum Resources Program, 

an existing research and development program created by statute and managed by 

the Secretary of Energy, should be refocused toward mitigating the risks of offshore 

operations.

* Secretary of Energy Steven Chu advised the Commission on the capacity within the Department of Energy, the Nuclear Regulatory Commission, the Federal Aviation 

Administration and elsewhere in the federal government to undertake sophisticated risk and technology assessments. The Department of Energy and the national 

laboratories have the depth and breadth of research and technical experience in such areas as high-performance computing, image processing, mechanical/structural 

stress analysis, complex fluid flow simulations, and other areas that proved instrumental in diagnosing the state of the Macondo well blowout preventer and in assessing 

plans to stop the leak. 
254 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

•	 Develop more detailed requirements for incident reporting and data concerning 

offshore incidents and “near misses.” Such data collection would allow for better 

tracking of incidents and stronger risk assessments and analysis. In particular, such 

reporting should be publicly available and should apply to all offshore activities, 

including incidents relating to helicopters and supply vessels, regardless of whether 

these incidents occur on or at actual drilling rigs or production facilities. In addition, 

Interior, in cooperation with the International Regulators Forum, should take the 

lead in developing international standards for incident reporting in order to develop a 

consistent, global set of data regarding fatalities, injuries, hydrocarbon releases, and 

other accidents. Sharing information as to what went wrong in offshore operations, 

regardless of location, is key to avoiding such mistakes. 

•	 Lead in the development and adoption of shared international standards, particularly 

in the Gulf of Mexico and the Arctic. Transparent information and data sharing 

within the offshore industry and among international regulators is critical to 

continuous improvement in standards and risk management practices. The United 

States shares the waters of the Gulf of Mexico and its sub-surface resources with 

Cuba and the Republic of Mexico. After many decades of declining investment and 

production in the Mexican part of the Gulf by PEMEX, the national oil company, 

a recent Mexican Supreme Court ruling has created the opportunity for U.S. and 

other foreign oil and gas companies to enter Mexican waters. PEMEX has indicated 

its intention to auction deepwater contracts beginning in 2012. Separately, Cuba has 

already leased blocks 50 miles off the coast of Florida with reported plans for seven 

exploration wells by 2014. Agreement on standards for operations should be part of 

any negotiation to define the maritime boundary between the United States, Mexico, 

and Cuba in the eastern Gulf of Mexico. The need for international standards for 

activities in the Arctic is also unquestioned: the United States has already awarded 

leases in the region and now it is incumbent on the United States to push for such 

standards. 

•	 Provide protection for “whistleblowers” who notify authorities about lapses in 

safety. All offshore workers have a duty to ensure safe operating practices to prevent 

accidents. To ensure all workers, regardless of employer, will take appropriate action 

whenever necessary, Congress should amend the Outer Continental Shelf Lands Act or 

specific safety statutes to provide the same whistleblower protection that workers are 

guaranteed in other comparable settings.

2. The Need for a New, Independent Agency 

As described in detail in Chapter 3, primary responsibility for regulating the offshore 

oil and gas industry prior to the Deepwater Horizon accident was consolidated in a 

single agency, MMS. MMS was not only responsible for offshore leasing and resource 

management; it also collected and disbursed revenues from offshore leasing, conducted 

environmental reviews, reviewed plans and issued permits, conducted audits and 

inspections, and enforced safety and environmental regulations. And though the revenue 

management and resource management functions of MMS were separated into two 

distinct divisions, the mingling of distinct statutory responsibilities—each of which 
Chapter Nine 255 255

required different skill sets and fostered different institutional cultures—led inevitably to 

internal tensions and a confusion of goals that weakened the agency’s effectiveness and 

made it more susceptible to outside pressures. 

At the core of this tension was a trade-off between, on the one hand, promoting the 

“expeditious and orderly development” of offshore resources, as mandated by the Outer 

Continental Lands Act of 1978, while also ensuring, on the other hand, that offshore 

development proceeded in a manner that protected human health, safety, and the 

environment. Over the course of many years, political pressure generated by a demand 

for lease revenues and industry pressure to expand access and expedite permit approvals 

and other regulatory processes often combined to push MMS toward elevating the former 

goal over the latter. At the same time, the fact that MMS lacked either a clearly articulated 

mission or adequate guidance for balancing its different missions led to inefficient 

management and a tendency to defer to industry, which successfully sought congressional 

and political intervention to shorten time frames for plan and permit reviews, blocked 

royalty valuation rulemakings, and advocated to delay and weaken rules aimed at 

improving the safety management of operations. 

All of these problems were compounded by an outdated organizational structure, a chronic 

shortage of resources, a lack of sufficient technological expertise, and the inherent difficulty 

of coordinating effectively with all the other government agencies that had statutory 

responsibility for some aspect of offshore oil and gas activities. Besides MMS, other offices 

of the Department of the Interior as well as the Departments of Transportation, Commerce, 

Defense, and Homeland Security, and the Environmental Protection Agency (EPA) were 

involved in some aspect of the industry and its many-faceted facilities and operations, 

from workers on production platforms to pipelines, helicopters, drilling rigs, and supply 

vessels. 

Not surprisingly, the Macondo well failure in April 2010 turned a harsh spotlight on all 

these bureaucratic inadequacies and shortcomings. And shortly after the accident, Interior 

Secretary Ken Salazar renamed MMS the Bureau of Ocean Energy Management, Regulation 

and Enforcement (BOEMRE) and announced a plan to split its responsibilities into three 

separate offices.*

Although the proposed reorganization of Interior’s offshore leasing, safety, and revenue 

management program represents a significant improvement, it does not adequately 

address the deeper problem of fully insulating the Department’s safety and environmental 

protection functions from the pressures to increase production and maximize lease 

revenues. 

* The use of “BOEMRE” will be limited here to actions since MMS was renamed.
256 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Recommendations 

A4: Congress and the Department of the Interior should create an independent 

agency within the Department of the Interior with enforcement authority to oversee 

all aspects of offshore drilling safety (operational and occupational), as well as 

the structural and operational integrity of all offshore energy production facilities, 

including both oil and gas production and renewable energy production. 

A5: Congress and the Department of the Interior should provide a mechanism, 

including the use of lease provisions for the payment of regulatory fees, for adequate, 

stable, and secure funding to the key regulatory agencies—Interior, Coast Guard, and 

NOAA—to ensure that they can perform their duties, expedite permits and reviews as 

needed, and hire experienced engineers, inspectors, scientists, and first responders.

(See Recommendation G2.) 

The roles and responsibilities of the former MMS should be separated into three entities 

with clearly defined statutory authorities. One entity would be responsible for offshore 

safety and environmental enforcement; another would perform functions related to 

leasing and environmental science; and the third would manage natural resource revenues. 

The safety and environment enforcement authority or entity, in particular, should have 

primary statutory responsibility for overseeing the structural and operational integrity 

of all offshore energy-related facilities and activities, including both oil and gas offshore 

drilling and renewable energy facilities.

•	 A new office of safety should consolidate responsibility for safety—including 

infrastructure and operational integrity, as well as spill prevention and response—for 

all offshore fossil fuel and renewable resource development activities, structures, and 

workers. It should be an independent agency housed at the Department of the Interior 

to facilitate coordination with a new office for leasing and environmental science. 

Congress should enact an organic act to establish its authorities and responsibilities, 

consolidating the various responsibilities now under the Outer Continental Shelf 

Lands Act, the Pipeline Safety Act, and Coast Guard authorizations. The new office 

should have primary authority over facilities, structures, and units for offshore 

oil and gas drilling, production, and renewable energy that are engaged in energyrelated activities, including authority to establish and enforce specific safety and 

environmental protection requirements for these units as well as requirements for 

operators who may be leasing the facilities. 

•	 Congress should review and consider amending where necessary the governing 

statutes for all agencies involved in offshore activities to be consistent with 

the responsibilities functionally assigned to those agencies. The safety-related 

responsibilities of the new offshore safety agency should be included in a separate 

statute. (Further specifics regarding the Commission’s recommended organizational 

structure for new offices to regulate safety and leasing are discussed below). 
Chapter Nine 257 257

•	 To ensure that Interior has the ability to provide adequate leasing capabilities and 

regulatory oversight for the increasingly complex energy-related activities being 

undertaken on the OCS, budgets for these new offices as well as existing agencies 

should come directly from fees paid by the offshore industry, akin to how fees 

charged to the telecommunications industry pay for the expenses of the Federal 

Communications Commission, which is essentially fully funded by such regulated 

industry payments. Through this mechanism, Congress, through legislation, 

and Interior, through lease provisions,2 could expressly oblige lessees to fund the 

regulation necessary to allow for private industry access to the energy resources on 

the OCS, including renewables. Under existing law, the oil and gas industry already 

pays inspection fees that currently amount to about $10 million per year or about 

3 percent of BOEMRE’s annual budget, but this amount can and should be increased 

significantly. (See Recommendation G2.) 

Implementing the Commission’s recommendation to reorganize the former MMS into three 

offices and to enhance these offices’ technical capacities will require a sustained effort over 

a period of years. The President or Interior Secretary should effect this reorganization to 

the extent possible administratively and request congressional enactment to confirm its 

permanence and provide for the statutory recognition of a term of office for the director of 

safety and environmental regulation.

PROPOSED Reorganization of the Former MInerals 

Management Service

Offshore Safety Authority: This office would exercise independent statutory 

authority over technical and operational safety in all phases of OCS energy resource 

development projects, including the planning, designing, constructing, operating, and 

decommissioning of facilities and projects, and will have overall responsibility for 

fostering safe and environmentally sound offshore energy operations. The new agency 

would oversee all non-economic aspects of the operations and structures involved in 

drilling and production of oil and gas, pipelines, and wind towers, wave, tidal, and 

other renewable technologies located on the federal offshore zone. The new safety and 

environment authority would also have the lead coordination role in relation to other 

regulators with independent authority over offshore oil and gas activities, including 

EPA, NOAA and the Coast Guard. 

Key responsibilities include:

•	 Reviewing and approving (or denying) all permits under exploration, development, 

and production plans. 

•	 Inspecting all offshore operations by expert teams through scheduled and 

unannounced inspections. 

•	 Auditing or otherwise requiring certification of operator health, safety, and 

environmental management systems. 
258 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

•	 Evaluating eligibility for lessees based on safety and environmental 

qualifications. 

•	 Reviewing and approving the safety and feasibility of any environmental 

mitigation activities prescribed by National Environmental Policy Act (NEPA) 

documents and other environmental consultations, authorization, or 

permits in addition to enforcing such requirements over the duration of an 

operation. 

•	 Collecting and analyzing leading and lagging indicators from all active 

parties for full risk evaluation. 

•	 Promulgating all structural integrity, process, and workplace safety rules 

and regulations in order to create a foundation of prescriptive regulations to 

supplement performance-based (“safety case”) regulations. 

•	 Providing technical review and comment on the five-year leasing program 

and individual lease sales. 

•	 Providing technical review of spill response and containment plans. 

•	 Reviewing and approving all spill response and containment plans and 

advising the new safety authority on environmental considerations. 

•	 Investigating all accidents and other significant events that could have 

potentially turned catastrophic.

The organization and staffing composition should be decided during a transition 

period, when the areas and activities are analyzed and categorized by risk. The 

director of the new organization should be a qualified executive with a relevant 

engineering or technical background, and should be appointed by the President 

for a five- to six-year term and confirmed by the Senate. In addition, the new 

agency should have classifications and salary scales for engineering and technical 

staff and inspectors similar to those of the Nuclear Regulatory Commission. 

Leasing and Environmental Science Office: This office would act as the leasing 

and resource manager for conventional and renewable energy and other mineral 

resources on the OCS. Charged with fostering environmentally responsible and 

efficient development of the OCS, the office would ensure that the American 

people both receive fair market value for the rights conveyed and that the 

nation’s rich marine environment remains protected. The United States cannot 

afford a repetition of the kind of contractual drafting mistake that, as described 

in Chapter 3, is literally costing the nation tens of billions of dollars in lost 

revenues. 
Chapter Nine 259 259

Key responsibilities include: 

•	 Conducting OCS resource planning processes, including the five-year leasing 

program and individual lease sales. 

•	 Conducting individual lease sales for oil, gas, and renewable energy facilities 

offshore. 

•	 Promulgating rules and regulations with respect to lease terms, resource 

access, and use. 

•	 Approving non-engineering or operations aspects of exploration, 

development, and production plans, subject to review by the new safety 

authority to ensure no conflicts with permitting requirements for 

infrastructure and operations. 

•	 Reviewing and approving all spill response and containment plans and 

advising the new safety authority on environmental considerations. 

•	 Making resource management decisions, such as those related to 

timing of reservoir abandonment and shared reservoir issues, 

unitization, commingling, and optimizing oil and gas recovery. 

•	 Reviewing and approving permits for seismic activities. 

•	 Conducting NEPA reviews at all relevant phases and coordinating 

other environmental reviews when appropriate 

•	 Administering the Environmental Studies Program. 

The leasing and environmental science office would include two distinct divisions: 

a leasing and resource evaluation division and an environmental science division. 

To provide an important and equitable voice for environmental concerns during 

the five-year planning process and lease awards, the environmental science 

division would be structured with a separate line of reporting to the Assistant 

Secretary overseeing offshore drilling and the environmental science division 

would be led by a Chief Scientist. The Chief Scientist’s responsibilities would 

include, but not be limited to, conducting all NEPA reviews and coordinating 

other environmental reviews when appropriate and administering the 

Environmental Studies Program. The Chief Scientist’s expert judgment on 

environmental protection concerns would be accorded significant weight in the 

leasing decision-making process, including on questions concerning whether and 

where leasing should occur and what environmental protection and mitigation 

conditions should be placed on leases that are issued. The new organization 

and process would also include enhanced review of environmental decisions 

and enforcement by the safety authority. It should track all mitigation efforts 

from NEPA documents and other environmental reviews to assist the new safety 

authority in its environmental enforcement duties.
260 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Office of Natural Resources Revenue (ONRR): Revenue collection and auditing 

functions would remain with the Assistant Secretary for Policy, Management, 

and Budget as per the recent re-organization implemented by Secretary Salazar.

B. Safeguarding the Environment

The adequacy of the existing regulatory regime to assure the environmental safety 

of offshore drilling (as distinct from worker or occupational safety) has come 

under a great deal of scrutiny since the Deepwater Horizon incident. In its work on 

this question, the Commission focused on two issues: (1) the application of NEPA 

requirements to the offshore leasing process and (2) the need for better science 

and greater interagency consultation to improve decision-making concerning the 

management of offshore resources. 

1. The Need to Revise and Strengthen NEPA Policies and Practices in the 

Offshore Drilling Context

The Commission has reviewed the leasing and permitting processes that MMS 

followed in the Gulf of Mexico before the Deepwater Horizon incident. The results 

lead the Commission to conclude that the breakdown of the environmental 

review process for OCS activities was systemic and that Interior’s approach to 

the application of NEPA requirements in the offshore oil and gas context needs 

significant revision. In particular, the application of tiering, the use of categorical 

exclusions, the practice of area-wide leasing, and the failure to develop formal NEPA 

guidance for the agency all contributed to this breakdown. 

Tiering. Under MMS, the NEPA process for offshore oil and gas leasing relied heavily 

on “tiering”—a practice under which a broad environmental impact statement 

was used to cover “general matters” across a large area, while issues specific to 

a particular site or smaller area were addressed through “subsequent narrower 

statements of environmental analyses.”3 Tiering was meant to encourage more 

thorough reviews at each subsequent stage of the offshore leasing process, and 

to avoid the duplication of general information that would have been covered in 

previous environmental reviews. As applied by MMS, however, tiering was not 

always consistent with its original purpose: instead, it created a system where 

deeper environmental analysis at more geographically targeted and advanced 

planning stages did not always take place. 

 

Categorical Exclusions. The Council on Environmental Quality’s implementing 

regulations for NEPA define “categorical exclusions” as “a category of actions 

which do not individually or cumulatively have a significant effect on the human 

environment . . . and for which, therefore, neither an environmental assessment 

nor an environmental impact statement is required.”4 MMS has historically applied 

categorical exclusions to both Exploration Plans and Development Operations 

Coordination Documents5 in the Gulf of Mexico. Although there are legitimate 

differences between the Gulf and other regions of the OCS, the basis for such a wide 
Chapter Nine 261 26

disparity in the use of categorical exclusions is questionable. And in the aftermath of the 

BP Deepwater Horizon spill, it is difficult to argue that deepwater drilling is an activity that 

does not present at least some potentially significant risk of harm to the environment of 

the Gulf. That is no doubt why, prompted by a comprehensive review of MMS’s use of 

categorical exclusions by the Council on Environmental Quality, Interior announced in 

August 2010 that it would restrict its use of categorical exclusions for offshore oil and 

gas development “to activities involving limited environmental risk,” while it undertakes a 

comprehensive review of its NEPA process.6

Area-Wide Leasing. OCS lease sales cover such large geographic areas that meaningful 

NEPA review is difficult. A decision to dramatically increase the size of lease sales—

known as area-wide leasing—was made over 20 years ago at the request of industry; 

it has necessitated environmental analyses of very large areas at the lease sale stage. For 

example, the Final Environmental Impact Statement for the 2007–2012 multi-lease sales 

in the Gulf of Mexico covered more than 87 million acres,7 while the Final Environmental 

Impact Statement for Chukchi Sea Lease Sale 193 covered about 34 million acres.8 Given 

that 2008 lease sales in the Central Gulf of Mexico and the Chukchi Sea attracted almost 

$3.7 billion and almost $2.7 billion in high bids, respectively, it is appropriate to conduct 

environmental reviews on a finer geographic scale before private-sector commitments of 

this magnitude are made to purchase leases. 

NEPA Guidance. Though expected to prepare a handbook on NEPA requirements,9 MMS 

never developed formal NEPA guidance. As the Government Accountability Office noted in 

a review of the MMS Alaska Region Office: “The lack of a comprehensive NEPA guidance 

handbook, combined with high staff turnover, leaves the process for meeting NEPA 

requirements ill-defined for the analysts charged with developing NEPA documents.”10

BOEMRE is currently in the process of developing an internal NEPA guidance document—a 

step that should ensure a higher level of NEPA consistency and transparency across 

regions. 

Recommendation

B1: The Council on Environmental Quality and the Department of the Interior should 

revise and strengthen the NEPA policies, practices, and procedures to improve the 

level of environmental analysis, transparency, and consistency at all stages of the 

OCS planning, leasing, exploration, and development process.

Interior should take the following steps to strengthen NEPA review of the offshore leasing 

process:

•	 The new office of leasing and environmental science should, in consultation with the 

Council on Environmental Quality, develop and make public a formal NEPA handbook 

within one year. The handbook should address the issue of tiering and provide 

guidelines for applying NEPA in a consistent, transparent, and appropriate manner to 

decisions affecting OCS oil and gas activities. 
262 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

•	 Interior should require, through this formal NEPA handbook, environmental impact 

statements for both the Five-Year Plan and for specific lease sales before plans for 

exploration, development, and production are approved in areas with complex 

geology, in ultra-deepwater, and in the Arctic and other frontier areas. Exploration 

plans and development and production plans in all other areas should be subject to 

NEPA review consistent with the Council on Environmental Quality’s implementing 

regulations. 

•	 In less well-explored areas, Interior should reduce the size of lease sales so their 

geographic scope allows for a meaningful analysis of potential environmental 

impacts and identification of areas of ecological significance. A bidder on tracts in 

these areas and all other areas should be able to demonstrate, in addition to financial 

prequalification and ability to contain a maximum-size spill, experience operating in 

similar environments and a record of safe, environmentally responsible operation—

either in the United States or as verified by a peer regulator for another country. The 

distinction between the OCS and less well-explored areas in the Gulf should be defined 

by the new entity in charge of leasing and environmental science.

•	 Congress should amend the Outer Continental Shelf Lands Act to extend the 30-day 

deadline for approving exploration plans to 60 days. In addition, MMS should not 

consider such plans officially “submitted” until all of the required content, necessary 

environmental reviews, and other analyses are complete and adequate to provide 

a sound basis for decision-making. Exploration and development plans would be 

considered higher-level plans for purposes of agency review and approval under a 

reorganized regulatory structure. The office of safety and environment, separate from 

the office (or division) of leasing, would be responsible for permitting and approving 

well designs, drilling plans, and any structures. 

2. The Need for Greater Interagency Consultation

Under OCSLA, it is up to the Secretary of the Interior to choose the proper balance between 

environmental protection and resource development. In making leasing decisions, the 

Secretary is required to solicit and consider suggestions from any interested agency, but 

he or she is not required to respond to the comments or accord them any particular 

weight. Similar issues arise at the individual lease sale stage and at the development and 

production plan stage. As a result, NOAA—the nation’s ocean agency with the most 

expertise in marine science and the management of living marine resources—effectively has 

the same limited role as the general public in the decisions on selecting where and when 

to lease portions of the OCS. A more robust and formal interagency consultation process 

is needed—with the goal of identifying precise areas that should be excluded from lease 

sales because of their high ecological importance or sensitivity. In addition to NOAA, other 

federal agencies that should be involved include the U.S. Fish and Wildlife Service and EPA.

Strengthened interagency coordination on offshore oil and gas activities will also be 

important in implementing the final recommendations of the Interagency Ocean Policy 

Task Force. These recommendations, adopted by President Obama by Executive Order on 

July 19, 2010, mandate a new national ocean policy that includes a framework for coastal 
Chapter Nine 263 263

and marine spatial planning, as well as a comprehensive, adaptive, integrated, transparent, 

ecosystem- and science-based process for analyzing current and anticipated uses of ocean, 

coastal, and Great Lakes areas.11 Coastal and marine spatial planning applies a multisector approach in an effort to simultaneously reduce user conflicts and environmental 

impacts associated with ocean and coastal activities. Integrating five-year leasing plans and 

associated leasing decisions with the coastal and marine spatial planning process will be 

an important step toward assuring the sustainable use of ocean and coastal ecosystems. It 

could also reduce uncertainty for industry and provide greater predictability for potential 

users of different areas.

To ensure that offshore oil and gas development and production proceed in ways that 

minimize adverse impacts to the natural and human environment, decisions about these 

activities must be grounded in strong science. With respect to funding the necessary 

science, the Outer Continental Shelf Lands Act requires Interior to study the “assessment 

and management of environmental impacts on the outer Continental Shelf and coastal 

areas that might be affected by oil and gas or other mineral developments. . . .”12 Initiated 

in 1973, funding for the Environmental Studies Program at Interior peaked in 1976 at 

roughly $55 million, but had fallen to less than $20 million during most of the 1990s and 

2000s. It was only recently increased to approximately $30 million.13

Future research must be conducted in a systematic way that strategically enhances 

understanding of the impacts of oil and gas activities and provides regulators with the 

timely and scale-appropriate information required for sound decisions. Long-term studies 

that provide critical scientific information on OCS frontier or lesser known areas,*

 or 

systematic efforts to fill data gaps in areas with existing oil and gas activity, can help 

ensure that the selection of new leasing areas is informed by a full understanding of 

potential impacts on important ecological resources. In frontier areas, it will be important 

to collect data on prevailing environmental conditions on a broad geographic scale, not just 

at individual lease sites. Additionally, post-development ecological monitoring is critical to 

understanding the impacts of oil and gas activities and to facilitate an adaptive approach 

to environmental management. Expanded coordination and cooperation on scientific 

research efforts with NOAA, the U.S. Geological Survey, and other agencies with relevant 

expertise can improve the quality of science available for OCS decision-making. Much of 

this research will also be relevant to other offshore activities, including the development of 

offshore wind resources. 

Recommendations

 B2: The Department of the Interior should reduce risk to the environment from OCS 

oil and gas activities by strengthening science and interagency consultations in the 

OCS oil and gas decision-making process. 

* The term “frontier areas” include areas of the OCS that either have never been leased, or have not been leased in many years. It includes the Arctic (Beaufort and 

Chukchi Seas) and the Atlantic and portions of the Pacific. 
264 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

B3: Congress, by enacting legislation, and the Department of the Interior, through 

its lease provision, should require the oil and gas industry to pay fees that 

support environmental science and regulatory review related to OCS oil and gas 

activities to enable cooperating agencies to carry out these responsibilities. (See 

Recommendation G2.)

Several actions are needed to implement these recommendations: 

•	 Congress should amend the Outer Continental Shelf Lands Act to provide NOAA 

with a formal consultative role during the development of five-year lease plan and 

lease sale stages. Consultation should occur no later than 60 days in advance of final 

Department of the Interior decisions on lease plans and sales. Specifically, NOAA 

should provide comments and recommendations concerning specific geographic areas 

that should be excluded from the leasing program or treated in a specific manner 

due to their ecological sensitivity or for other reasons relevant to NOAA’s ocean and 

coastal science expertise. Interior must adopt NOAA’s recommendations unless the 

Department determines that doing so would be inconsistent with important national 

policy interests. Moreover, Interior must publish in writing its rationale for rejecting 

NOAA’s recommendation. 

•	 The Department of Energy, NOAA, the U.S. Geological Survey, and other interested 

agencies should establish a joint research program to systematically collect critical 

scientific data, fill research gaps, and provide comprehensive, ecosystem-based 

scientific reviews of OCS areas that are currently or will likely be open for oil and 

gas leasing, and for offshore areas being considered for the siting of sources of 

renewable energy such as wind power. This program should build on existing data; 

should aim to supplement data collected from individual lease sites by industry to 

develop information for broader geographic areas; and should engage the non-federal 

scientific community through such mechanisms as the National Oceanographic 

Partnership Program. The research should outline and develop the necessary data 

for: (1) decision-making related to future leasing, exploration, and development; 

(2) measuring and monitoring impacts on ecological resources; and (3) providing 

necessary data for natural resource damage assessment should an oil spill occur. 

•	 The National Academy of Sciences should regularly evaluate the government’s studies 

program in this area, preferably at five-year intervals. 

•	 Together with NOAA, the new division of environmental science under the direction of 

the Chief Scientist in the Office of Leasing and Environmental Science should develop 

an environmental monitoring program or set of protocols to be implemented by oil 

and gas companies at lease sites once exploration and development and production 

activities begin. Areas of ecological interest and areas where data gaps exist should be 

targeted for monitoring programs. In addition, monitoring should be conducted in 

a way that is independently verifiable and allows for comparisons across individual 

sites. Companies should provide all monitoring data to the federal government.
Chapter Nine 265 265

•	 NOAA and other federal agencies with appropriate expertise should be encouraged to 

act as cooperating agencies in NEPA reviews of offshore energy production activities, 

including exploration and development plans and drilling permit applications. Federal 

agencies that submit comments to Interior as part of a NEPA process should receive 

a written response indicating how the information was applied and if it was not 

included, why it was not included.

C. Strengthening Oil Spill Response, Planning, and 

Capacity

Just as the events of April 20, 2010 exposed a regulatory regime that had not kept up 

with the industry it was responsible for overseeing, the events that unfolded in subsequent 

weeks and months made it dismayingly clear that neither BP nor the federal government 

was prepared to deal with a spill of the magnitude and complexity of the Deepwater Horizon

disaster. This section discusses the Commission’s recommendations in the area of oil spill 

response and planning. Broadly speaking they address three critical issues or gaps in the 

government’s existing response capacity: (1) the failure to plan effectively for a large-scale, 

difficult-to-contain spill in the deepwater environment or potentially in the Arctic; (2) the 

difficulty of coordinating with state and local government officials to deliver an effective 

response; and (3) a lack of information and understanding concerning the efficacy of 

specific response measures, such as dispersants and berms. 

1. The Need for Improved Oil Spill Response Planning

Oil spill response planning and analysis across the government needs to be overhauled in 

light of the lessons of the Deepwater Horizon blowout. A common interagency approach to 

analyzing oil spill risks and a common understanding of the issues and impacts involved 

are needed and must be consistently incorporated in environmental reviews, consultations, 

and authorizations. Environmental review and spill planning currently occurs at different 

levels within the government and industry, and these reviews and plans have not been 

sufficiently coordinated to ensure either searching review of industry plans or adequate 

preparation. 

One of the common threads that runs through many of the environmental review 

documents prepared for Gulf of Mexico oil and gas activities in the years leading up to the 

Deepwater Horizon spill was their reliance on MMS oil spill risk and impact analyses. To the 

extent that any of these documents contained errors or incomplete information, those gaps 

and errors carried through to subsequent environmental reviews by other agencies. 

The government’s spill-response planning occurs largely outside of MMS. The National 

Contingency Plan, mandated by the Clean Water Act, prescribes the nationwide response 

structure for spills of oil or releases of hazardous substances and creates a tiered planning 

process. Regional Response Teams include representation from federal agencies and state 

governments, and develop Regional Contingency Plans as well as preauthorization 

protocols for certain response strategies. The Area Committees, which develop Area 
266 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Contingency Plans, similarly include federal and state representatives but are led by 

the Coast Guard. (The Coast Guard and EPA co-chair the regional teams.) The Area 

Contingency Plans are the most specific and the most relied-upon during the response to a 

spill.

While industry spill response plans must “be consistent with the requirements of the 

National Contingency Plan and Area Contingency Plans,”14 those industry plans presently 

require only the approval of BOEMRE.15 Its regulations outline what needs to be included 

in these plans and direct the company to include information about a worst case scenario, 

including how to calculate the volume of oil, determine its trajectory, and a response 

strategy.16 As noted above, MMS oil spill risk and impacts modeling formed the basis of 

the required analysis. These response plans were not distributed to any federal agencies 

for review and comment outside of MMS. Additionally, only a small number of the plans 

developed for the Gulf were sent to the existing Office of Leasing and Environment for 

detailed environmental review within MMS or shared with other federal agencies with 

relevant expertise, such as NOAA or the Coast Guard. Finally, no provision was made for 

any form of public review or comment, and plans were not available to the public after 

they received MMS approval. 

 

Recommendation 

C1: The Department of the Interior should create a rigorous, transparent, and 

meaningful oil spill risk analysis and planning process for the development and 

implementation of better oil spill response.

Several steps are needed to implement a rigorous, transparent, and meaningful oil spill risk 

analysis and planning process:

•	 Interior should review and revise its regulations and guidance for industry oil spill 

response plans in light of the lessons learned from the Deepwater Horizon experience. 

•	 A new process for reviewing spill response plans is needed. This process should ensure 

that all critical information and spill scenarios are included in the plans, including 

oil spill containment and control methods to ensure that operators can deliver the 

capabilities indicated in their response plans. In addition, the new entity within 

Interior that is charged with overseeing offshore safety and environmental protection 

will have to verify operator capability to perform according to the plans. 

•	 Interior must ensure that adequate technical expertise exists within the staff 

responsible for reviewing and approving spill response plans. 

•	 In addition to the Department of the Interior, other agencies with relevant scientific 

and operational expertise should play a role in evaluating spill response plans to 

verify that operators can conduct the response and containment operations detailed 

in their plans. Specifically, oil spill response plans, including source-control measures, 

should be subject to interagency review and approval by the Coast Guard, EPA, 
Chapter Nine 267 267

and NOAA. Other parts of the federal government, such as Department of Energy 

national laboratories that possess relevant scientific expertise, could be consulted. This 

would help remedy the past failure to integrate multiple area, regional, and industry 

response plans, by involving the agencies with primary responsibility for government 

spill response planning in oversight of industry planning. Plans should also be made 

available for a public comment period prior to final approval and response plans 

should be made available to the public following their approval. 

•	 Interior should incorporate the “worst-case scenario” calculations from industry 

oil spill response plans into NEPA documents and other environmental analyses or 

reviews. This does not mean that Interior would be required to conduct a “worst-case 

scenario analysis” under NEPA, but it does mean that Interior would use industry’s 

worst-case estimates for potential oil spill situations in its environmental analyses.

2. The Need for a New Approach to Handling Spills of National Significance

The Macondo well blowout caused the largest accidental oil spill in history—one that 

presented an unprecedented challenge to the response capability of both government and 

industry. Clearly, neither was adequately equipped: In fact it was quickly evident that even 

the response capacity indicated in industry’s spill response plans did not exist. Though 

the National Contingency Plan permitted the government to designate the spill as one of 

“national significance,” this designation did not trigger any procedures other than allowing 

the federal government to name a National Incident Commander.

The spill’s magnitude calls into question whether the National Contingency Plan 

establishes an appropriate relationship between the federal government and the responsible 

party, as the public demanded in the weeks and months following the Deepwater Horizon

spill that the government demonstrate control of the response. The responsible party 

that caused the spill is clearly legally responsible for containing the spill and mitigating 

its harmful consequences. The federal government, not the responsible party, must be in 

charge of those efforts. As this spill demonstrated, the government unfortunately lacked 

both the expertise and the capacity to oversee aspects of the response at the outset of the 

spill—particularly the effort to control the well. Only as the full scope of the disaster 

unfolded and the government gathered and focused its resources from a variety of agencies 

was the government ultimately able to take charge. 

Recommendation

 C2: EPA and the Coast Guard should establish distinct plans and procedures for 

responding to a “Spill of National Significance.”

Under existing law, EPA is the federal agency responsible for developing a National 

Contingency Plan, which is the federal government’s blueprint for responding to both oil 

spills and hazardous substances releases. In light of the Deepwater Horizon oil spill, EPA 

should amend or issue new guidance on the National Contingency Plan to add distinct 

plans and procedures for Spills of National Significance. In those amendments, EPA should:
268 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

•	 Increase government oversight of the responsible party, based on the National 

Contingency Plan’s requirement that the government “direct” the response where a 

spill poses a substantial threat to public health or welfare.17 

•	 Augment the National Response Team and Regional Response Team structures to 

establish additional frameworks for providing interagency scientific and policymaking 

expertise during a spill. Further, EPA, NOAA, and the Coast Guard should develop 

procedures to facilitate review and input from the scientific community—for 

example, by encouraging disclosure of underlying methodologies and data. 

•	 Create a communications protocol that accounts for participation by high-level 

officials who may be less familiar with the National Contingency Plan structure and 

create a communications center within the National Incident Command—separate 

from the joint information center established in partnership with the responsible 

party—to help transmit consistent and complete information to the public.

3. The Need to Strengthen State and Local Involvement

The response to the Deepwater Horizon disaster showed that state and local elected officials 

had not been adequately involved in oil spill contingency planning, though career 

responders in state government had participated extensively in such planning. Before 

the Deepwater Horizon spill, state and local elected officials were not regular participants 

in Area Committee meetings or familiar with local Area Contingency Plans. The Coast 

Guard and Area Committee member agencies had done little to reach out to state and 

local elected officials. These state and local officials were more familiar with hurricane 

response under the Stafford Act, in which the federal government provides funding and 

supports state and local governments, but does not control emergency response operations. 

As a result, state and local political officials had incorrect expectations about their roles. 

They understandably wanted to be responsive to citizens who were concerned about the 

spill and, regardless of the official response plans, sought state and local governmental 

assistance. 

Unfamiliarity with, and lack of trust in, the federal response manifested itself in competing 

state structures and attempts to control response operations that undercut the efficiency 

of the response overall. Federal responders improved their relationship with state and local 

officials as the response progressed—but had better coordination and communication 

existed sooner, that relationship could have been more productive in the early days of the 

spill response. Moreover, increased citizen involvement before a spill occurs could create 

better mechanisms to utilize local citizens in response efforts, provide an additional layer 

of review to prevent industry and government complacency, and increase public trust in 

response operations.

Recommendation

C3: EPA and the Coast Guard should bolster state and local involvement in oil spill 

contingency planning and training and create a mechanism for local involvement 

in spill planning and response similar to the Regional Citizens’ Advisory Councils 

mandated by the Oil Pollution Act of 1990.
Chapter Nine 269 269

EPA and the Coast Guard, as the chair and vice-chair of the National Response Team, 

should issue policies and guidance for increased state and local involvement in oil spill 

contingency planning and training. This guidance should provide protocols to:

•	 Include local officials from areas at high risk for oil spills in training exercises. 

•	 Establish liaisons between the Unified Command and affected local communities at 

the outset of a spill response. 

•	 Add a local on-scene coordinator position to the Unified Command structure. 

•	 Provide additional clarification and guidance to federal, state, and local officials on 

the differences between emergency response under the Stafford Act and under the 

National Contingency Plan.

In addition, a mechanism should be created for ongoing local involvement in spill 

planning and response in the Gulf. In the Oil Pollution Act of 1990, Congress mandated 

citizens’ councils for Prince William Sound and Cook Inlet. In the Gulf, such a council 

should broadly represent the citizens’ interests in the area, such as fishing and tourism, 

and possibly include representation from oil and gas workers as ex-officio, non-voting 

members. The citizens’ group could be funded by Gulf lease holders. The Commission 

further recommends that federal regulators be required to consult with the council 

on relevant issues, that operators provide the council with access to records and other 

information, and that entities (either in industry or in government) declining the council’s 

advice submit their reasons to the council in writing.

4. The Need for Increased Research and Development to Improve Spill 

Response 

The technology available for cleaning up oil spills has improved only incrementally since 

1990. Federal research and development programs in this area are underfunded: In fact, 

Congress has never appropriated even half the full amount authorized by the Oil Pollution 

Act of 1990 for oil spill research and development. In addition, the major oil companies 

have committed minimal resources to in-house research and development related to spill 

response technology. Oil spill removal organizations are underfunded in general and 

dedicate few if any resources to research and development. Though some commentators 

and industry representatives have argued that more research and development would not 

have allowed for a more effective spill response because no technology will ever collect 

more than a fraction of spilled oil, the fact is that neither industry nor government has 

made significant investments in improving the menu of response options or significantly 

improved their effectiveness. Thus any argument about the limited potential of response 

technology is speculative. After the Deepwater Horizon spill, agencies, industry, and 

entrepreneurs focused attention on developing new response technologies for the first time 

in 20 years, and a number of promising options emerged within a relatively short period 

of time—including beach-cleaning machines, subsea dispersant delivery systems, and new 

in situ burning techniques. 
270 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Recommendation

C4: Congress should provide mandatory funding for oil spill response research and 

development and provide incentives for private-sector research and development. 

Specifically, Congress should provide mandatory funding (i.e. funding not subject to the 

annual appropriations process) at a level equal to or greater than the amount authorized 

by the Oil Pollution Act of 1990 to increase federal funding for oil spill response research 

by agencies such as Interior, the Coast Guard, EPA, and NOAA—including NOAA’s Office 

of Response and Restoration. To be sure, such mandatory appropriations are rarely done, 

but they are not unprecedented. Congress has included such a provision when, as here, 

Congress seeks to target appropriations to support a discrete category of activities where 

Congress perceives that the need is high and the concern is great that the desired activity 

will otherwise go unfunded over a sustained period of time. For instance, Congress has 

provided for an annual mandatory appropriation of $100 million for emergency highway 

repairs for those damaged by natural disasters or catastrophic failures.18 Congress also 

provided for mandatory funding for five years for several farm conservation programs 

in the Farm Security and Rural Investment Act of 2002.19 By similarly removing oil spill 

research and development funding from the ordinary appropriations process, Congress 

can avoid the experience that followed the Exxon Valdez spill, when support for response 

research and development decreased over time. Moreover, Congress can comply with its 

pay-as-you-go rules by supporting increased research and development funding with a fee 

on offshore lessees. (See Recommendation G2.)

An advisory board, made up of experts from relevant offices of the Department of the 

Interior, U.S. Geological Survey, Department of Energy, EPA, and NOAA, as well as from 

professional societies, academia, industry, and non-governmental organizations, should be 

established to develop a research agenda and roadmap. In addition, to promote increased 

research investments by industry, the Coast Guard should revise its Effective Daily 

Recovery Capacity regulations to encourage the development and use of more efficient 

oil recovery equipment. At the same time, EPA should revise its oiled-water discharge 

regulations and streamline its permitting process for open-water testing. Finally, Congress 

and the Administration should encourage private investment in response technology more 

broadly, including through public-private partnerships and a tax credit for research and 

development in this area. 

5. The Need for New Regulations to Govern the Use of Dispersants

The decision to use dispersants involves difficult tradeoffs: If dispersants are effective, less 

oil will reach shorelines and fragile marsh environments, but more dispersed oil will be 

spread throughout the water column. Prior to the Deepwater Horizon incident, the federal 

government had not adequately planned for the use of dispersants to address such a large 

and sustained oil spill, and did not have sufficient research on the long-term effects of 

dispersants and dispersed oil to guide its decision-making. Officials had to make decisions 

about dispersant use without important relevant information or the time to gather 

such information. Under the circumstances, however, the Commission believes that the 

National Incident Commander, Federal On-Scene Coordinators, and EPA Administrator 
Chapter Nine 271 27

made reasonable decisions regarding the use of dispersants at the surface and in the subsea 

environment. 

Recommendation 

C5: EPA should update and periodically review its dispersant testing protocols for 

product listing or pre-approval, and modify the pre-approval process to include 

temporal duration, spatial reach, and volume of the spill.

EPA should update its dispersant testing protocols and require more comprehensive testing 

prior to listing or pre-approving dispersant products. The Coast Guard and EPA, as cochairs of the Regional Response Teams and leaders of the Area Contingency Plan drafting 

process, should modify pre-approvals of dispersant use under the National Contingency 

Plan to establish procedures for further consultation based on the temporal duration, 

spatial reach, or volume of the spill and volume of dispersants that responders are seeking 

to apply. EPA and NOAA should conduct and encourage further research on dispersants, 

including research on the impacts of high-volume and subsea use of dispersants, the longterm fate and effects of dispersants and dispersed oil, and the development of less toxic 

dispersants. 

6. The Need to Re-evaluate the Use of Offshore Barrier Berms in Spill 

Response

Offshore barrier berms generally do not constitute a viable spill response measure for 

several reasons. These reasons include the time and cost of construction, and the highly 

variable and dynamic marine environment that limit effectiveness and pose the potential 

for negative environmental impacts resulting from dredging and filling. Thus, for instance, 

barrier berms constructed off the shores of Louisiana in response to the Deepwater Horizon 

spill could not be considered a success. Only a fraction of the project (approximately 6 

percent) was completed by the time the well was capped, and no estimate of the amount 

of oil trapped by the berms is much more than 1,000 total barrels. In fact, the Louisiana 

berms project stands out as the most expensive and perhaps most controversial response 

measure deployed to fight the Deepwater Horizon spill. The decision to approve the project 

as one of the oil spill response techniques to be funded by the responsible party was 

based primarily on the demands of local and regional interests rather than on a scientific 

assessment of its likely efficacy. 

Recommendation

C6: The Coast Guard should issue guidance to establish that offshore barrier berms 

and similar dredged barriers generally will not be authorized as an oil spill response 

measure in the National Contingency Plan or any Area Contingency Plan. 
272 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

D. Advancing Well-Containment Capabilities

As described in Chapter 5, the most obvious, immediately consequential, and 

plainly frustrating shortcoming of the oil spill response set in motion by 

the events of April 20, 2010 was the simple inability—of BP, of the federal 

government, or of any other potential intervener—to contain the flow of oil 

from the damaged Macondo well. Clearly, improving the technologies and 

methods available to cap or control a failed well in the extreme conditions 

thousands of feet below the sea is critical to restoring the public’s confidence 

that deepwater oil and gas production can continue, and even expand into new 

areas, in a manner that does not pose unacceptable risks of another disaster. 

Better technology and methods are also needed to gather accurate information 

in the event of an accident or failure. This section discusses the Commission’s 

recommendations for advancing well-containment capabilities in the wake of 

the Macondo well blowout. 

1. The Need for Government to Develop Greater Source-Control Expertise

As described in Chapter 5, at the time of the Macondo well blowout on April 

20, the U.S. government was unprepared to oversee a deepwater source-control 

effort. Though the public expected federal authorities to take charge once the 

accident occurred, neither MMS nor the Coast Guard had the expertise or 

resources to supervise BP’s well-containment efforts. Once the Secretary of 

Energy’s science team, the U.S. Geological Survey, the national laboratories, and 

other sources of scientific expertise became involved, the government was able 

to substantively supervise BP’s decision-making, forcing the company to fully 

consider contingencies and justify its chosen path. The government’s oversight 

effort was assisted by outside industry experts, although their involvement 

also raised some concerns (about conflicts of interest, sharing of proprietary 

information, and potential liability for participants) that were never resolved.

Recommendation

D1: The National Response Team should develop and maintain expertise 

within the Federal government to oversee source-control efforts. 

The National Response Team should create an interagency group—including 

representation from the Department of the Interior, Coast Guard, and the 

Department of Energy and its national laboratories—to develop and maintain 

expertise in source control, potentially through public-private partnerships. The 

proposed Ocean Energy Safety Institute at the Department of the Interior could 

play a role in developing such expertise.

In addition, EPA should amend the National Contingency Plan to:

•	 Define and institutionalize the role of federal agencies and the national laboratories 

that possess relevant scientific expertise in source-control. 
Chapter Nine 273 273

Create a mechanism for involving outside industry experts in source-control design 

and oversight.

2. The Need to Strengthen Industry’s Spill Preparedness

Beyond attempting to close the blowout preventer stack, no proven options 

for rapid source control in deepwater existed when the blowout occurred. 

BP’s Initial Exploration Plan for the area that included the Macondo prospect 

identified only one response option by name: a relief well, which would 

take months to drill. Although BP was able to develop new source-control 

technologies in a compressed timeframe, the containment effort would have 

benefited from prior preparation and contingency planning.

Recommendation

D2: The Department of the Interior should require offshore operators to 

provide detailed plans for source control as part of their oil spill response 

plans and applications for permits to drill.

Consistent with the enhanced planning process described above in 

Recommendation C1, oil spill response plans should be required to include 

detailed plans for source control. These plans should demonstrate that an 

operator’s containment technology is immediately deployable and effective. 

(BOEMRE has recently issued a Notice to Lessees requiring operators to 

demonstrate, as part of the spill response planning process, that they have 

“access to and can deploy surface and subsea containment resources that would 

be adequate to promptly respond to a blowout or other loss of well control.”20 

In enforcing this Notice, BOEMRE must ensure that operators provide detailed 

descriptions of their technology and demonstrate that it is deployable and 

effective.) 

In applications for permits to drill, the Department of the Interior should 

require operators to provide a specific source-control analysis for each well. 

The analysis must demonstrate that an operator’s containment technology is 

compatible with the well. (The Department of the Interior could implement this 

requirement through amendments to existing regulations21 or through a Notice 

to Lessees.22 The latter option could be implemented more quickly, though the 

former might be more permanent.)

As with oil spill response plans, source-control plans should be reviewed and 

approved by agencies with relevant expertise, including the Department of the 

Interior and the Coast Guard. 
274 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

3. The Need for Improved Capability to Develop Accurate Flow Rate Estimates 

As described in Chapter 5, early flow rate estimates were highly variable and 

difficult to determine accurately. However, the understated estimates of the 

amount of oil spilling from the Macondo well appear to have impeded planning 

for and analysis of source-control efforts like the cofferdam and especially the 

top kill. U.S. Geological Survey Director Marcia McNutt stated that if a similar 

blowout occurs in the future, the government will be able to quickly and 

reliably estimate oil flow using the oceanographic techniques that eventually 

provided an accurate estimate of the flow rate from the Macondo well.23

Recommendation

 D3: The National Response Team should develop and maintain expertise 

within the federal government to obtain accurate estimates of flow rate or 

spill volume early in a source-control effort. 

The National Response Team should create an interagency group—including 

representation from the Department of the Interior, the Coast Guard, the 

national laboratories, and NOAA—to develop and maintain expertise in 

estimating flow rates and spill volumes, potentially through consultation with 

outside scientists.

In addition, EPA should amend the National Contingency Plan to create a 

protocol for the government to obtain accurate estimates of flow rate or spill 

volume from the outset of a spill. This protocol should require the responsible 

party to provide the government with all data necessary to estimate flow rate 

or spill volume.

4. The Need for a More Robust Well Design and Approval Process

Among the problems that complicated the Macondo well-containment effort 

was a lack of reliable diagnostic tools. The Deepwater Horizon blowout preventer 

had one pressure gauge accurate to plus or minus 400 pounds per square inch. 

This meant BP and the government could not get accurate pressure readings, 

which in turn hampered their ability to estimate the oil flow rate, undertake 

reservoir modeling, and plan for source control operations. In addition, the 

blowout preventer lacked a means of indicating whether and to what extent 

its rams and annular preventers had closed. Without such instruments, the 

government and BP expended significant resources on basic data-collection such 

as obtaining gamma-ray images of the blowout preventer and adding pressure 

sensors to the top hat after it was deployed. Meanwhile, the presence of rupture 

disks in the Macondo well’s 16-inch casing led to concerns about well integrity 

that further complicated the source-control effort. BP had not considered the 

impact of these disks on post-blowout containment when it designed the well.24
Chapter Nine 275 275

Recommendation 

D4: The Department of the Interior should require offshore operators 

seeking its approval of proposed well design to demonstrate that: 

•	 Well components, including blowout preventer stacks, are equipped with 

sensors or other tools to obtain accurate diagnostic information—for example, 

regarding pressures and the position of blowout preventer rams. 

•	 Wells are designed to mitigate risks to well integrity during post-blowout 

containment efforts.

E. Overcoming the Impacts of the Deepwater Horizon

Spill and Restoring the Gulf

As described in Chapters 6 and 7, even before the Macondo well was finally capped and 

oil stopped flowing, major efforts were underway to mitigate and begin to repair the 

environmental and economic harm caused by the spill. Those efforts are continuing—and 

likely will for years. Nevertheless, any effort to draw lessons learned from the Deepwater 

Horizon spill for the purpose of developing options (as the Commission’s charter states) to 

“guard against, and mitigate the impact of, any oil spills associated with offshore drilling 

in the future” would necessarily be incomplete without an early appraisal of progress 

toward longer-term restoration in the Gulf. This section describes the actions and initiatives 

that have been launched to assess and overcome the impacts of the spill, and presents the 

Commission’s recommendations for steps that should be taken to ensure the following 

three goals are met:

•	 The environment and the economy of the Gulf region recovers as completely and as 

quickly as possible, not only from the direct impacts of the spill, but from the decades 

of degradation that preceded it; 

•	 The people of the Gulf are fairly compensated for the direct and indirect impacts of 

the spill; and 

•	 Lessons learned from restoration efforts in the Gulf—including advances in scientific 

understanding, data collection, mitigation technologies and techniques, planning, 

and institutional coordination—result in enhanced capacity to remedy the impacts of 

future offshore oil spills and better manage the myriad economic, environmental, and 

social interests that must be balanced in the Gulf and other critical offshore areas.

1. The Need for Improved Understanding of Oil Spill Impacts, Particularly in the 

Deepwater Environment

A sophisticated understanding of the full range of impacts from a large-scale oil spill is 

critical to effective recovery and restoration efforts. Because, however, the concentration 

and toxicity of oil dissipate rapidly within the first few days to weeks of exposure to the 

elements, the window of opportunity to collect data in the aftermath of an accident is 
276 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

narrow. For this reason, advance planning and rapid response mechanisms, are essential to 

capitalize on research opportunities. 

Independent scientists, many of who are long-time scholars of the Gulf ecosystem 

or have unique capabilities, were eager to study the spill and contribute to the 

injury assessment. However, the independent science community’s ability to 

participate early on was hampered by a lack of timely access to the response zone. 

This had the effect of diminishing what was learned from the spill. 

Recommendation

E1: The Coast Guard, through the Federal On-Scene Coordinator, should provide 

scientists with timely access to the response zone so that they can conduct 

independent scientific research during an oil spill response and long-term monitoring 

in the future. 

The National Science Foundation, in consultation with the new National Ocean 

Council, should expand on its RAPID grant program to create a framework under 

which independent science during a spill can be coordinated, with an emphasis 

on data-sharing, communication, and timely access within the response zone. 

By ensuring that independent scientists can receive expedited funding after an 

oil spill, government will gain a more complete understanding of spill-related 

environmental impacts. A demonstrated commitment to independent science will 

also serve to bolster public confidence and trust. The rush to study the impacts 

of the Deepwater Horizon spill put a strain on existing scientific resources in the 

Gulf. Independent, industry, and government scientists all wrangled for funding, 

equipment and vessels, often duplicating efforts in the process. A program that 

effectively coordinates research initiatives and resources will provide a significant 

added value to the scientific community under exigent conditions. 

2. The Need for Fair, Transparent Compensatory Restoration Based on Natural 

Resource Damage Assessments

As described in Chapter 6, the Deepwater Horizon spill caused substantial damage to natural 

resources and habitats across the Gulf coast and in the deepwater offshore environment. 

Damages to natural resources are formally assessed subject to regulations established 

under the Natural Resource Damage Assessment provisions of the Oil Pollution Act. The 

Act requires that the public be compensated for injury to and lost use of public resources. 

The regulation provides that compensation should be “in-place” and “in-kind” wherever 

possible, thereby favoring restoration measures with a connection to oil spill impacts. The 

Deepwater Horizon spill is unprecedented in that five Gulf States were affected, each with 

its own restoration agenda, even though most of the damage occurred in Louisiana. The 

damage offshore is unprecedented and unknown. The Trustees*

 responsible for the damage 

assessment are under pressure to approve projects with an “equitable” (i.e., each state 

* The Natural Resource Damage Assessment regulation provides for the designation of affected state, federal, and tribal Trustees to conduct the damage assessment 

of natural resources, achieve agreement on restoration goals, and design and implement restoration projects to meet those goals. In this case, the Trustees comprise 

designated federal and state officials who are encouraged to work together and achieve consensus on restoration goals and projects though a Trustee Council. While the 

regulation supports cooperation, it does not explicitly require consensus by the Trustees. If certain Trustees disagree with the direction of the Natural Resource Damage 

Assessment process, they are free to break away from the Council and seek reimbursement for natural resource damages on their own. 
Chapter Nine 277 277

receives an equal portion) allocation of resources that may not be entirely consonant with 

the “in-place, in-kind” requirement. 

Another challenge for the Trustees is assessing and providing compensatory restoration 

for the potentially significant marine and deepwater impacts associated with this spill. 

Historically, most applications of the Natural Resource Damage Assessment process have 

focused on coastal restoration, but the Macondo well, which spilled oil 5,000 feet below 

the surface, may have damaged organisms in the water column or on the sea floor for 

which there should be compensation as well.

Recommendation

E2: The Trustees for Natural Resources should ensure that compensatory restoration 

under the Natural Resource Damage Assessment process is transparent and 

appropriate.

Restoration decisions must be transparent, appropriate, and apolitical. The Trustees should 

appoint an independent scientific auditor to ensure that projects are authorized on the 

basis of their ability to mitigate actual damages caused by the spill, with special care 

taken to assess and compensate poorly understood marine impacts. Further, any potential 

settlement agreement between the responsible party and the Trustees should provide for 

long-term monitoring of affected resources for a period of at least three to five years, as 

well as “enhancement”*

 beyond the baseline. By hewing closely to the “in-place” and “inkind” principles that underpin Natural Resource Damage Assessment regulations, Trustees 

will help ensure that injured public resources, and the communities that rely on them, 

are made whole to the fullest extent possible, regardless of state and federal boundaries. A 

focus on ocean impacts will provide an invaluable opportunity—missed during the Ixtoc 

spill of 1979—to assess and remediate damage to marine ecosystems after an oil spill.

3. The Need to Address Human Health Impacts, Especially Among Response 

Workers and in Affected Communities

As described in Chapter 6, the National Contingency Plan overlooks the need to respond 

to widespread concerns about human health impacts. For smaller oil spills, the response 

effort is generally carried out by trained oil spill response technicians, but given the scale of 

the response to the Deepwater Horizon spill and the need to enlist thousands of previously 

untrained individuals to clean the waters and coastline, many response workers were 

not screened for pre-existing conditions. This lack of basic medical information, which 

could have been collected if a short medical questionnaire had been distributed, limits 

the ability to draw accurate conclusions regarding long-term physical health impacts. 

Additionally, residents of coastal communities may believe that they suffered adverse 

health consequences resulting from both chemical exposure from the spill itself and the 

mental stress occasioned by the spill’s assault on their livelihoods.

* “Enhancement” is a term coined during settlement negotiations after the Exxon Valdez oil spill of 1989. It requires the responsible party to fund restoration beyond that 

needed merely to return injured resources to baseline conditions. Rather, any funding should be sufficient to ensure that restoration leaves the affected system better off 

than before a spill. 
278 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Adequate funding and resources were not in place to deal with claims of physical and 

mental illness among Gulf coast residents resulting from, or exacerbated by, the spill, 

response actions, and the resulting impacts. Whether allegations that the spill created 

health problems for responders and Gulf Coast residents are warranted does not change the 

perception among some that government has not been responsive to health concerns.

The National Contingency Plan contains no specific guidance for responding to public 

health impacts of an oil spill or hazardous substances release. By contrast, the National 

Response Framework—which provides the structure for a national response to terrorist 

attacks, major disasters, and other kinds of emergencies—incorporates a protocol for 

responding to public health exigencies. 

Recommendation

E3: EPA should develop distinct plans and procedures to address human health 

impacts during a Spill of National Significance.

EPA should amend the National Contingency Plan to add distinct procedures to address 

human health impacts during a Spill of National Significance. Spills of this magnitude 

necessarily require a significant clean-up effort, potentially exposing workers to toxic 

compounds in oil and dispersants. Additionally, residents of coastal communities may 

suffer adverse health consequences due to both chemical exposure from the spill itself, 

and the mental stress occasioned by the assault on their livelihoods or way of life. With 

respect to worker health and safety, existing authorities25 should be strengthened to ensure 

consistent application of medical screening and surveillance procedures for both formal 

response contractors and ad hoc citizen responders. Regarding public health, a medical 

services protocol similar to the Public Health and Medical Services Annex of the National 

Response Framework should be incorporated to ensure emergency medical care, timely 

dissemination of public health information,26 and medical monitoring and surveillance.27 

Furthermore, a public health protocol requiring the collection of adequate baseline data 

and long-term monitoring would allow researchers to assess the human dimensions of oil 

spills with greater accuracy. Without sound data on the causal or correlative relationships 

between chemical (i.e., oil and dispersants) exposure and human health, a number of 

response methods may be used inappropriately—including the provision of appropriate 

protective gear for cleanup workers.28 

4. The Need to Restore Consumer Confidence 

As described in Chapter 6, images of spewing oil and oiled beaches in newspapers and on 

television set the stage for public concern regarding the safety of Gulf seafood. Additional 

factors contributed to the lingering impression that the public could not trust government 

assurances that the seafood was safe: the unprecedented volumes of dispersants used, 

confusion over the flow rate and fate of the oil, frustration about the government’s 

relationship with BP in spill cleanup, and lawsuits filed by fishermen contesting the 

government’s assurance of seafood safety. The economic blow to the Gulf region associated 

with this loss of consumer confidence is sizable. BP gave Louisiana and Florida $68 million 
Chapter Nine 279 279

for seafood testing and marketing, as well as money to assess impacts on tourism and 

fund promotional activities. As of early December, BP was considering a similar request 

from Alabama.

In future spills, however, there is no guarantee that a responsible party will have the 

means or the inclination to compensate such losses. Such indirect financial harms are 

currently not compensable under the Oil Pollution Act. Nevertheless, losses in consumer 

confidence are real and Congress, federal agencies, and responsible parties should consider 

ways to restore consumer confidence in the aftermath of a Spill of National Significance. 

Recommendation

E4: Congress, federal agencies, and responsible parties should take steps to restore 

consumer confidence in the aftermath of a Spill of National Significance.

5. The Need for a Long-Term Restoration Effort that Is Well Funded, 

Scientifically Grounded, and Responsive to Regional Needs and Public Input

As described in Chapter 7, a lack of sustained and predictable funding, together with 

failed project coordination and long-term planning, have resulted in incomplete and often 

ineffective efforts to restore the Gulf’s natural environment. Currently, no funding source 

exists to support regional restoration efforts. Estimates of the cost of Gulf restoration 

vary widely, but according to testimony before the Commission, fully restoring the 

Gulf will require $15 billion–$20 billion, or a minimum of $500 million per year, over 

30 years. While a number of different sources currently provide funding to individual 

states for restoration, none of these sources provides funds for Gulf-wide coastal and 

marine restoration and none is sufficient to support the sustained effort required. Most 

policymakers agree that without a reliable source of long-term funding, it will be 

impossible to achieve restoration in the Gulf. 

Several Gulf States and the federal government have filed or are expected to file suit 

against BP and other companies involved in the spill, which will likely create opportunities 

to direct new restoration funds to the region. In some cases, congressional action will 

be required to ensure that funds are directed to this purpose. Meanwhile, Congress has 

already begun considering other potential funding sources, including a higher per-barrel 

tax on oil production, increased royalties or fees, and direct appropriations for Gulf-wide 

restoration through the normal federal budget process. Although many of these proposals 

face political hurdles, the fact remains that resources are needed if progress on coastal 

restoration is to continue. Inaction is a prescription for further degradation: since many 

Gulf ecosystems were already fragile and deteriorating before the spill, maintaining the 

status quo amounts to accepting their continued decline, with the longer-term risks and 

vulnerabilities this entails. 

In order for funding to be most efficiently directed at long-term restoration, a decisionmaking body is needed that has authority to set binding priorities and criteria for 

project funding. The Gulf Coast Ecosystem Restoration Task Force is now in place; it was 

recommended by a September 2010 report on restoration from Secretary of the Navy Ray 
280 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Mabus to the President and subsequently established by Presidential Executive Order.29 

According to the language of the Executive Order, the job of the Task Force is to begin 

coordinating the different restoration projects being undertaken by various jurisdictions 

in the Gulf, coordinating related science activities, and engaging stakeholders. However, 

as many in Congress and the Administration have suggested, the Task Force lacks some 

features necessary to effectively direct long-term restoration efforts in the Gulf—most 

importantly the ability to set binding goals and priorities. A number of critical issues 

remain to be addressed, including how to allocate funding in a way that addresses the 

relative restoration needs of individual states; how to balance the roles and interests of 

the state and federal governments; how to ensure that decisions are made efficiently and 

quickly; how to incorporate good science without unduly slowing valuable projects; and 

how to incorporate meaningful public input. 

Recommendations

E5: Congress should dedicate 80 percent of the Clean Water Act penalties to longterm restoration of the Gulf of Mexico.

E6: Congress and federal and state agencies should build the organizational, 

financial, scientific, and public outreach capacities needed to put the restoration effort 

on a strong footing.

The Commission’s recommendations share much common ground with those outlined in 

Secretary Mabus’s report this past September. For instance, the Commission recommends 

that Congress—recognizing that dedicated, sustained funding is necessary to accomplish 

long-term Gulf of Mexico ecosystem restoration—should direct 80 percent of Clean Water 

Act penalties to support implementation of a region-wide restoration strategy. Directing 

such payments to the Gulf could, for the next 10 years, provide significant funding. If 

litigation arising from the spill results in civil or criminal penalties, a global settlement 

of litigation should include supplemental environmental projects*

 and community 

service projects that direct payments to the Gulf. Should Clean Water Act penalties not be 

redirected toward Gulf ecosystem restoration, Congress should consider other mechanisms 

for a dedicated funding stream not subject to annual appropriations. 

The Commission recommends that Congress establish a joint state-federal Gulf Coast 

Ecosystem Restoration Council. The structure of the Exxon Valdez Oil Spill Trustee Council 

should inform the structure of the Gulf Coast Council on the question of the relative 

representation of the federal and state governments on the council. The Gulf Coast Council 

should implement a restoration strategy for the region that is compatible with existing 

state restoration goals. This strategy should set short- and long-term goals with criteria 

for selecting projects for funding. Key criteria should include (1) national significance; (2) 

contribution to achieving ecosystem resilience; and (3) the extent to which national policies 

such as related to flood control, oil and gas development, agriculture, and navigation 

directly contributed to the environmental problem. 

* “Supplemental environmental projects” are projects that a defendant agrees to undertake as part of a settlement with government of an enforcement action and that are 

above and beyond those necessary to comply with applicable legal requirements. 
Chapter Nine 281 28

Experience in major restoration endeavors, including those in the Gulf, has shown that, 

absent binding goals to drive the process, restoration projects are insufficiently funded, 

focused, or coordinated. Establishing a region-wide council to coordinate agency activities 

represents a necessary first step, but without authority to set priorities and resolve 

conflicts, such a council will be hampered in its ability to achieve environmental goals. The 

Commission recommends that a region-wide council for the Gulf be given authority to 

set priorities that will govern the expenditure of funds and resolve any conflicts regarding 

eligibility of projects. The council should further define specific categories of projects that 

could meet each of the three criteria listed above. Projects could be categorized in a number 

of ways—for example, by habitat (key estuaries, sea grass, wetlands, coral reefs); by goal 

(biological productivity and ecosystem function, improving resilience, restoring fisheries); 

or by specific project type (river diversion, beach nourishment).

The Commission believes that having a comprehensive, binding strategy to guide the 

restoration effort is critical to success. By elaborating on the goals set by the governing 

entity and by providing specific milestones and restoration objectives, such a strategy 

would focus the overall effort and help ensure that projects are not duplicative. The 

strategy could also include a map that ties projects to specific places and provide a useful 

mechanism for public involvement. Congress should also ensure that the priorities and 

decisions of the Gulf Coast Council are informed by input from a Citizens Advisory Council 

that represents diverse stakeholders.

Finally, but essentially, restoration decisions must be rooted in science. An approach that 

draws heavily on information and advice from scientists will result in project selection 

and funding allocations that are more likely to lead to an effective region-wide restoration 

strategy. It will also advance transparency in decision-making and enhance credibility with 

the public. The Commission accordingly recommends the establishment of a Gulf Coast 

Ecosystem Restoration Science and Technology Program that would address these issues 

in three ways: 1) by creating a scientific research and analysis program, supported by the 

restoration fund, that is designed to support the design of scientifically sound restoration 

projects; 2) by creating a science panel to evaluate individual projects for technical 

effectiveness and consistency with the comprehensive strategy; and 3) by supporting 

adaptive management plans based on monitoring of outcomes scaled both to the strategy 

itself and to the individual projects or categories of projects included in it.

6. The Need for Better Tools to Balance Economic and Environmental Interests 

in the Gulf 

Federal agencies charged with managing activities within the U.S. Exclusive Economic 

Zone have tended to work largely in isolation from one another. Responsive to the 

recommendations of the 2004 U.S. Commission on Ocean Policy, President Obama in 

June 2009 directed two dozen federal departments and agencies to provide in-depth 

recommendations about how federal policy can address inefficiencies in the nation’s 

traditionally ad hoc management of its seas. The Interagency Ocean Policy Task Force 

reported in the summer of 2010; its recommendations were subsequently included in a 

Presidential Executive Order, issued on July 15, 2010, that created a new National Ocean 

Council to coordinate federal marine policy. 
282 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Prominent recommendations included a requirement that key regional and federal 

authorities develop and implement coastal and marine spatial planning, for ocean users 

and the public. This system is designed to optimize marine productivity. More broadly, 

scientific advice grounded in peer-reviewed empirical research inform strategy and decisionmaking in ocean management, including for energy, shipping, national defense, sustainable 

fisheries, and conservation. 

Recommendation 

E7: The appropriate federal agencies, including EPA, Interior, and NOAA, and the 

Trustees for Natural Resources should better balance the myriad economic and 

environmental interests concentrated in the Gulf region going forward. This would 

include improved monitoring and increased use of sophisticated tools like coastal 

and marine spatial planning. Many of these tools and capacities will also be important 

to manage areas of the OCS outside the Gulf. 

The Commission recommends that as a part of management and restoration efforts in the 

marine environment greater attention should be given to new tools for managing ocean 

resources, including monitoring systems and spatial planning. Marine scientists have 

emerged from the Deepwater Horizon incident with more precise questions to investigate 

and a better sense of monitoring needs in the Gulf of Mexico, which because of its multiple 

uses and economic value should be a national priority. To that end, the National Ocean 

Council should work with the responsible federal agencies, industry and the scientific 

community to expand the Gulf of Mexico Integrated Ocean Observing System, including 

the installation and maintenance of an in situ network of instruments deployed on selected 

production platforms. Participation in this system by industry should be regarded as a 

reasonable part of doing business in nation’s waters. 

Coastal and marine spatial planning has the potential to improve overall efficiency and 

reduce conflicts among ocean users. Congress should fund grants for the development of 

regional planning bodies at the amount requested by the President in the fiscal year 2011 

budget submitted to Congress. Ocean management should also include more strategically 

sited Marine Protected Areas, including but not limited to National Marine Sanctuaries, 

which can be used as “mitigation banks” to help offset harm to the marine environment. 

Given the economic and cultural importance of fishing in the Gulf region—and the 

importance of Gulf seafood to the rest of the country—scientifically valid measures, 

such as catch share programs, should be adopted to prevent overfishing and ensure the 

continuity of robust fisheries. 

Marine spatial planning was designed to ensure that myriad ocean management decisions 

are compatible and consistent, that they make sense. In the decades since marine protection 

began, scientists have developed a much more robust understanding of the Gulf’s physical 

and ecological processes. Now, for example, Marine Protected Areas can be used—and 

should be used—to ensure the continuity and robustness of fisheries into the future. 

Rationalizing ocean use around this much improved scientific understanding—for example, 

by identifying which parts of the ocean are appropriate (or inappropriate) for certain 
Chapter Nine 283 283

uses—should serve to maximize the productivity of natural systems and end inefficient or 

harmful practices that have accumulated over time. 

F. Ensuring Financial Responsibility

As described in Chapter 6, oil spills cause a range of harms, both economic and 

environmental, to individuals and ecosystems. The Oil Pollution Act makes the party 

responsible for a spill liable for compensating those who suffered as a result of the 

spill—through property damage, lost profits, and other economic injuries—and for 

restoring injured natural resources. The Act also provides an opportunity to make claims 

for compensation from a dedicated Oil Spill Liability Trust Fund. The Oil Pollution Act, 

however, imposes limits on both the amount for which the responsible party is liable, and 

the amount of compensation available through the trust fund. In the case of the Deepwater 

Horizon spill, BP (a responsible party) has placed $20 billion in escrow to compensate 

private individuals and businesses through the independent Gulf Coast Claims Facility. 

But if a less well capitalized company had caused the spill, neither a multi-billion dollar 

compensation fund nor the funds necessary to restore injured resources, would likely have 

been available. 

It is critical that compensation to victims be paid in full, and that the process for receiving 

compensation is swift and efficient. The Commission offers recommendations that would 

increase assurances that responsible parties are able to compensate victims (and at the 

same time strengthens incentives to prevent accidents in the first place), and that the Oil 

Spill Liability Trust Fund provide any compensation not provided by responsible parties. It 

also recommends a close review of the Gulf Coast Claims Facility process to determine its 

effectiveness in adjudicating compensation claims and its value as a model for future Spills 

of National Significance. 

1. The Need to Increase Existing Limitations on Responsible Party Liability 

Liability for damages from spills from offshore facilities is capped under the Oil Pollution 

Act at $75 million, unless it can be shown that the responsible party was guilty of gross 

negligence or willful misconduct, violated a federal safety regulation, or failed to report the 

incident or cooperate with removal activities, in which case there is no limit on damages 

(see Chapter 8). Claims up to $1 billion above the $75 million cap for certain damages can 

be made to, and paid out of, the Oil Spill Liability Trust Fund, which is currently supported 

by an 8-cent per-barrel tax on domestic and imported oil. 

The Oil Pollution Act also requires responsible parties to “establish and maintain evidence 

of financial responsibility,” generally based on a “worst-case discharge” estimate. In the 

case of offshore facilities, necessary financial responsibility ranges from $35 million to 

$150 million. The financial responsibility requirement provides a direct link between the 

Oil Pollution Act and insurance, as the Act provides that financial responsibility may be 

“established by any one, or by any combination, of the following methods” if determined 

by the Secretary of the Interior to be acceptable: “evidence of insurance, surety bond, 
284 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

guarantee, letter of credit, qualification as a self-insurer, or other evidence of financial 

responsibility.”

There are two main problems with the current liability cap and financial responsibility 

dollar amounts:

•	 Lack of Adequate Safety Incentives: A threshold problem with any damages cap 

that limits liability well below levels that may actually be incurred is that such a 

cap distorts the incentives of industry participants to adopt cost-effective safety 

precautions. Decisions regarding safety precautions are made for a variety of reasons, 

some of which cannot be influenced by policy measures. The relatively modest 

liability cap and financial responsibility requirements provide little incentive for oil 

companies to improve safety practices. 

•	 Inadequate Damages Compensation: BP’s damages from the Deepwater Horizon spill 

will total in the tens of billions of dollars. The company has already paid claims that 

measure in the billions, and has waived the statutory $75 million cap. But there is 

no guarantee that other companies in the future will agree to waive the cap. And if 

an oil company with more limited financial means than BP had caused the Deepwater 

Horizon spill, that company might well have declared bankruptcy long before paying 

fully for all damages. In the case of a large spill, the Oil Spill Liability Trust Fund 

would likely not provide sufficient backup. Thus, a significant portion of the injuries 

caused to individuals and natural resources, as well as government response costs, 

could go uncompensated. 

Any discussion of increasing liability caps and financial responsibility requirements must 

balance two competing public policy concerns: first, the goal of ensuring that the risk 

of major spills is minimized, and in the event of a spill, victims are fully compensated; 

and second, that increased caps and financial responsibility requirements to do not drive 

competent independent oil companies out of the market. A realistic policy solution also 

requires an understanding of the host of complex economic impacts that could result from 

increases to liability caps and financial responsibility requirements. 

Recommendation 

F1: Congress should significantly increase the liability cap and financial responsibility 

requirements for offshore facilities.

To address both the incentive and compensation concerns noted above, Congress should 

significantly raise the liability cap. Financial responsibility limits should also be increased, 

because if an oil company does not have adequate resources to pay for a spill, the 

application of increased liability has little effect: Should a company go bankrupt before 

fully compensating for a spill, its liability is effectively capped. If, however, the level of 

liability imposed and the level of financial responsibility required are set to levels that bear 

some relationship to potential damages, firms will have greater incentives to maximize 

prevention and minimize potential risk of oil spills30 and also have the financial means to 

ensure that victims of spills do not go uncompensated.
Chapter Nine 285 285

Legislative attempts to raise the cap and financial responsibility requirements to 

significantly higher levels have been met with the argument that these changes will 

cause insurance carriers to drop oil pollution coverage, leading to an exodus of small and 

independent companies from the offshore drilling market. The counter-argument is that oil 

companies should bear the social costs of their activities, and if those costs are too large or 

unpredictable to be insurable, then it is appropriate that these companies exit the market. 

There is legitimacy to aspects of both arguments. A company should not be able to cause 

billions of dollars of damage and walk away, simply because its operations contribute to 

the economy of the Gulf. Nor should smaller companies that can demonstrate the ability to 

drill safely and to pay for damages resulting from a large spill be forced out of the market. 

However, smaller companies that cannot demonstrate financial responsibility and meet risk 

requirements set and monitored by the Department of the Interior or a third party should 

not be allowed to make others pay for the costs of their accidents. 

One option for keeping competent independents in the market is a mutual insurance pool. 

Under such an arrangement, individual companies engaged in offshore drilling would pay 

premiums into a pool, which would pay out damages caused by a company as a result of 

a spill. A possible downside is that the mutual pool could have the effect of undercutting 

incentives individual firms might otherwise have to improve safety practices—but 

this problem could be addressed, for example, by tying premium levels to the financial 

and safety risk posed by an individual company’s activities. This option would allow 

companies to demonstrate financial responsibility for the cost of spills, at least to the limit 

paid out by the pool. 

Another option would be to phase in increases in the liability cap and financial 

responsibility requirements, which would allow the insurance industry a period 

of adjustment. Although any increase in liability limits and financial responsibility 

requirements would test the capacity of the offshore drilling insurance market, over time 

such a change would almost certainly stimulate an increase in insurance capacity. A 

phased-in approach would allow Congress to re-assess any concerns about limited capacity 

in the insurance industry in light of actual experience. 

Finally, regardless of how insurance is provided, smaller firms could be encouraged to 

partner with firms with greater financial resources. It should be noted that “joint ventures” 

between larger and smaller companies already exist; thus a policy change may not be 

necessary to encourage such arrangements.

2. The Need to Increase Limitations on Payments from the Oil Spill Liability 

Trust Fund 

If liability and financial responsibility limits are not set at a level that will ensure payment 

of all damages for spills, then another source of funding will be required to ensure full 

compensation. The federal government could cover additional compensation costs, but 
286 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

this approach requires the taxpayer to foot the bill. Therefore, Congress should raise 

the Oil Spill Liability Trust Fund per-incident limit because the current limits are clearly 

inadequate. 

Recommendation

F2: Congress should increase the limit on per-incident payouts from the Oil Spill 

Liability Trust Fund.

Raising the Oil Spill Liability Trust Fund’s per-incident limit will require the Fund to 

grow through an increase of the per-barrel tax on domestic and imported oil production. 

An alternative would be to increase the Trust Fund through a surcharge by mandatory 

provisions in drilling leases triggered in the event that there are inadequate sums available 

in the Fund. An increase in the Oil Spill Liability Trust Fund’s per-incident limit would 

not provide an incentive to offshore facilities to mitigate risks, because risks are pooled 

and the Oil Spill Liability Trust Fund is funded by parties other than those who engage 

in offshore drilling activities. But raising the limit would help ensure that victims have 

access to compensation without the need to seek further specific funding from Congress, or 

otherwise burdening the taxpayer.

3. The Need for Better Auditing and Monitoring of Risk

The Interior Department currently determines financial responsibility levels based on 

potential worst-case discharges, as required by the Oil Pollution Act. Although the agency’s 

analysis to some degree accounts for the risk associated with individual drilling activities, it 

does not fully account for the range of factors that could affect the cost of a spill, and thus 

the level of financial responsibility that should be required. Interior should analyze a host 

of specific, risk-related criteria when determining financial responsibility limits applicable 

to a particular company, including, but not limited to: geological and environmental 

considerations, the applicant’s experience and expertise, and applicable risk management 

plans. This increased scrutiny would provide an additional guard against unqualified 

companies entering the offshore drilling market. 

Recommendation

F3: The Department of the Interior should enhance auditing and evaluation of the 

risk of offshore drilling activities by individual participants (operator, driller, other 

service companies). The Department of the Interior, insurance underwriters, or other 

independent entities should evaluate and monitor the risk of offshore drilling activities 

to promote enhanced risk management in offshore operations and to discourage 

unqualified companies from remaining in the market. 

If liability and financial responsibility limits are raised, increased liabilities will be borne by 

insurance carriers, which will have a strong incentive to promote new safety techniques 

and methods, as well as to monitor risk. Insurance carriers might insist on certification 

of operators by an independent entity devoted to identifying best safety practices and 

monitoring risk, such as a self-policing safety organization for the oil and gas industry, as 
Chapter Nine 287 287

recommended in Chapter 8. Insurers or a self-policing safety organization for the industry 

also could provide a guard against unqualified companies entering the offshore drilling 

market. 

4. The Need for Assessment of the Existing Claims Process 

The Oil Pollution Act holds the responsible party liable for private claims brought 

by individuals or businesses for removal costs and certain damages. All claims 

must first be presented to the responsible party, but if the responsible party denies 

a claim, the claimant may pursue an in-court action or present an uncompensated 

claim for payment to the Oil Spill Liability Trust Fund. The Gulf Coast Claims 

Facility (Claims Facility), which is independently administered on behalf of BP (the 

responsible party), has established a claims processing mechanism that attempts 

to resolve claims against the responsible party outside of the courts.31 Kenneth 

Feinberg, formerly Special Master for the September 11th Victim Compensation 

Fund, administers the $20 billion escrow account through the Claims Facility. 

Eligible claims include: (1) removal and clean-up costs; (2) physical damages to 

real or personal property; (3) lost profits or impairment of earning capacity; (4) 

loss of subsistence use of natural resources; and (5) physical injury or death. The 

Facility does not pay claims brought by the government, or related to real estate, 

the moratorium, or the Vessel of Opportunity program.32 

To date, some claimants have been dissatisfied with decisions to deny certain claims and 

with the amount and timeliness of compensation received from approved claims, which 

has required Feinberg to reconsider the rules and processes in place for reimbursement. 

The United States Department of Justice sent a letter to Feinberg on September 17, 2010, 

urging expediency.33 In response, the Claims Facility noted that the large number of 

fraudulent and undocumented claims have slowed the process.34 Nonetheless, after 

the September 17 letter, Feinberg made several adjustments to the program including 

streamlining processing time and removing geographic proximity to the oil spill as bar 

against payment, Feinberg also extended the timeframe within which claimants could 

receive interim payments without waiving their right to pursue litigation.35 As of 

December 11, 2010, the Claims Facility has paid more than $2.4 billion in claims to more 

than 164,000 claimants.36 The Commission believes it would be useful to evaluate the 

effectiveness of the Claims Facility as a means of informing the compensation process in 

future large spills. 

Recommendation

F4: The Department of Justice’s Office of Dispute Resolution should conduct 

an evaluation of the Gulf Coast Claims Facility once all claims have been paid 

out, in order to inform claims processes in future Spills of National Significance. 

The evaluation should include a review of the process, the guidelines used for 

compensation, and the success rate for avoiding law suits.
288 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

G. Promoting Congressional Engagement to Ensure 

Responsible Offshore Drilling

The Commission’s recommendations in this report include some directed to 

Congress for specific legislation, and others directed to various specific federal 

agencies, responsible parties, and the oil and gas industry in general. The 

several recommendations directed to Congress, however, also highlight a further 

lesson: the need for Congress to engage more systematically in ensuring the 

safety of drilling in the OCS and environmental protection. This includes more 

active congressional oversight, and also includes congressional action to ensure 

that those in government responsible for safety oversight and environmental 

protection review have the resources necessary to do their jobs. To that end, 

this final set of recommendations addresses the need for Congress itself to take 

affirmative steps to ensure responsible offshore drilling. 

1. The Need for Congressional Awareness and Engagement

In the years between the Exxon Valdez spill and the spring of 2010, Congress, like much of 

the nation, appears to have developed a false sense of security about the risks of offshore 

oil and gas development. Congress showed its support for offshore drilling in a number of 

ways, but did not take any steps to mitigate the increased perils that accompany drilling 

in ever-deeper water. Until the Deepwater Horizon exploded, 11 rig workers lost their lives, 

and millions of barrels of oil spilled into the Gulf of Mexico, Congress had not introduced 

legislation to address the risks of deepwater drilling.

The congressional committee structure makes it much harder to focus on safety and 

environmental issues associated with offshore oil and gas development. In the 111th

Congress, multiple committees in both chambers claimed jurisdiction over offshore energy 

development. The House Natural Resources Committee, for example, had jurisdiction 

over “mineral land laws and claims and entries there under” and “mineral resources 

of public lands.” Its Subcommittee on Energy and Mineral Resources was specifically 

charged with oversight of “conservation and development of oil and gas resources of 

the Outer Continental Shelf.” But the House Committee on Energy and Commerce 

oversaw “exploration, production, storage, supply, marketing, pricing, and regulation 

of energy resources, including all fossil fuels,” as well “national energy policy generally.” 

Similarly, the jurisdiction of the Senate Committee on Energy and Natural Resources 

included “extraction of minerals from oceans and Outer Continental Shelf lands,” and its 

Subcommittee on Energy was responsible for oversight of “oil and natural gas regulation” 

generally. By contrast, the Senate Committee on Environment and Public Works claimed 

oversight over “environmental aspects of Outer Continental Shelf lands.” Yet, during the 

110th and 111th Congresses, none of the subcommittees of environment and public works 

claimed oversight specifically over OCS lands issues. 

In neither the House nor the Senate are any of these committees charged with directly 

overseeing the safety and environmental impacts of offshore development, separate from 

the conflicting goal of resource development and royalties. The House Committee on 
Chapter Nine 289 289

Education and Labor and the Senate Committee on Health, Education, Labor, and Pensions 

both emphasize occupational safety and health. But neither committee appears to focus 

on process safety—the vital approach identified by this Commission’s investigation that 

encompasses procedures for minimizing adverse events such as effective hazard analysis, 

management of risk, communication, and auditing. Finally, no oversight of any of 

these matters has been conducted by any of the several House or Senate committees or 

subcommittees responsible for the nation’s tax policies or overall appropriations process, 

notwithstanding the significant impact those policies and appropriations have on both the 

extent of energy industry activities on the OCS and the government’s ability to oversee 

that activity effectively. 

After the Deepwater Horizon explosion and resulting oil spill, numerous committees took an 

interest in offshore safety and environmental issues and held hearings. In short, it took a 

catastrophe to attract congressional attention.

Recommendation

G1: Increase and maintain congressional awareness of the risks of offshore drilling 

in two ways. First, create additional congressional oversight of offshore safety and 

environmental risks. Second, require the appropriate congressional committees to 

hold an annual oversight hearing on the state of technology, application of process 

safety, and environmental protection to ensure these issues receive continuing 

congressional attention. 

•	 The House and Senate Rules Committee should each assign a specific committee or 

subcommittee to oversee process safety and environmental issues related to offshore 

energy development. These committees should also be given the task of overseeing 

the Offshore Safety Authority, the creation of which this Commission has separately 

recommended. 

•	 Congress should require the Secretary of the Interior to submit an annual public 

report on energy offshore development activities to the applicable congressional 

committees. This report should focus on the Department’s progress in improving 

its prescriptive safety regulations; steps taken by industry and the Department to 

improve facility management; the Department’s progress in implementing a stronger 

environmental assessment program, including developing improved NEPA guidelines; 

and on any other steps taken by industry or the Department to address safety and 

environmental concerns offshore. The report should also detail the industry’s safety 

and environmental record during the previous 12 months. Finally, the report should 

highlight any areas in which the Department believes industry is not doing all that it 

can to promote safety and the environment and any areas where additional legislation 

could be helpful to the Department’s efforts. 

•	 Congress should require the Department of the Interior’s Office of Inspector General 

to submit an independent annual public report to the applicable congressional 

committees. The report should provide an independent description of the Offshore 
290 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Safety Authority’s activities over the previous 12 months, including its efforts to 

improve offshore safety and to investigate accidents and other significant offshore 

incidents. The report should also include the Inspector General’s evaluation of the 

Authority’s efforts and the Inspector General’s recommendations for improvement.

2. The Need for Adequate Funding for Safety Oversight and Environmental 

Review

Many of the earlier recommendations require adequate congressional funding in order to be 

implemented effectively. For instance, the new Offshore Safety Authority at Interior cannot 

be expected to succeed in meaningfully overseeing the oil and gas industry if Congress 

does not ensure it has the resources to do so. Agencies cannot conduct the scientific and 

environmental research necessary to evaluate impacts of offshore development if they do 

not receive adequate support from Congress. In short, Congress needs to make funding the 

agencies regulating offshore oil and gas development a priority in order to ensure a safer 

and more environmentally responsible industry in the future.

BOEMRE currently receives a portion of its funding from offsetting collections from 

industry. In its Fiscal Year 2011 Budget Justification, it requested that just less than half 

of its budget—$174.9 million—come from these collections.37 The oil and gas industry, 

however, should do significantly more and provide the funds necessary for regulation of 

offshore oil and gas operations and oil spill preparedness planning. The amount of funding 

needs to keep pace as industry moves into ever-more challenging depths and geologic 

formations because the related challenges of regulatory oversight likewise increase. This 

could be accomplished many different ways. Congress could, for instance, raise the 

inspection fees already imposed on facilities operating on the OCS—currently offsetting 

about three percent of BOEMRE’s annual budget—or impose a differently based annual 

regulatory fee on new and existing leases. Or Congress could instruct the Department 

of the Interior to include lease provisions that require the imposition of regulatory fees. 

Interior already possesses broad authority to include in leases “such rental and other 

provisions as the Secretary may prescribe at the time of offering the area for lease.”38

No matter the precise mechanism, the oil and gas industry would be required to pay 

for its regulators, just as fees on the telecommunications industry support the Federal 

Communications Commission. Regulation of the oil and gas industry would no longer be 

funded by taxpayers but instead by the industry that is being permitted to have access to 

a publicly-owned resource. Future Congresses would therefore have less incentive to reduce 

agency funding. 

Recommendation

G2: Congress should enact legislation creating a mechanism for offshore oil and gas 

operators to provide ongoing and regular funding of the agencies regulating offshore 

oil and gas development.
Chapter Nine 291 29

The President asked this Commission to recommend not only “improvements to Federal 

laws, regulations, and industry practices applicable to offshore drilling,” but also 

“organizational or other reforms of Federal agencies or processes necessary to ensure 

such improvements are implemented and maintained.” In carrying out this charge, the 

Commission has been mindful of the dangers of “fighting the last war”: that is, addressing 

the specific failures revealed by the Deepwater Horizon disaster, but neglecting to anticipate 

future problems whose contours are yet unknown. Our recommendations—for a new 

approach to risk assessment and management; a new, independent agency responsible for 

safety and environmental review of offshore drilling; stronger environmental review and 

enforcement; a reorientation of spill response and containment planning; and a revision of 

liability rules to better protect victims and provide proper incentives to industry—aim to 

establish an oversight regime that is sufficiently strong, expert, well-resourced, and flexible 

to prevent the next disaster, not the last. The oil and gas industry—remarkable for its 

technological innovation and productivity—needs government oversight and regulation 

that can keep pace. 

Chapter Ten 293 293

Introduction

The BP Deepwater Horizon disaster undermined 

public faith in the oil and gas industry, in 

government regulators, and even in America’s 

ability to respond to crises. The disaster raised 

serious questions about our nation’s ability 

to manage and protect for current and future 

generations the invaluable natural resources of the 

outer continental shelf and the multiple uses they 

sustain—the patrimony of all Americans. Based 

on the Commission’s thorough and vigorous 

accounting of this tragedy, the central lesson to be 

drawn from the catastrophe is that no less than 

an overhauling of both current industry practices 

and government oversight is now required. The 

changes necessary will be transformative in 

their depth and breadth, requiring an unbending 

commitment to safety by government and industry 

to displace a culture of complacency. Drilling in 

deepwater does not have to be abandoned. It can 

be done safely. That is one of the central messages 

of this report. The reforms proposed herein are 

intended to do for this industry what new policies 

and practices have done for other high-risk 

industries after their disasters.

Chapter Ten

American 

Energy Policy 

and the Future 

of Offshore 

Drilling

It was clear sailing for a fleet of oil rigs off Louisiana in April 2009. The 

Deepwater Horizon disaster a year later was a tragic wake-up call. Moving 

forward, offshore drilling in the Gulf of Mexico or in new U.S. frontiers will 

require, in the words of the report, “unbending commitment to safety by 

government and industry.”

< Benjamin Lowy/VII Network/Associated Press
294 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

The potential for such a transformation to ensure productive, safe, and responsible 

offshore drilling is significant, and provides reason for optimism even in the wake of a 

disaster.

The significance of the Deepwater Horizon disaster, however, is broader than just its 

relevance to the future of offshore drilling. The disaster signals the need to consider the 

broader context of the nation’s patterns of energy production and use, now and in the 

future—the elements of America’s energy policy. The explosion at the Macondo well and 

the ensuing enormous spill—particularly jarring events because of the belief they could 

never happen—force a reexamination of many widely held assumptions about how to 

reconcile the risks and benefits of offshore drilling, and a candid reassessment of the 

nation’s policies for the development of a valuable resource. They also support a broader 

reexamination of the nation’s overall energy policy. 

Offshore oil and gas will continue to be an important part of the nation’s domestic energy 

supply for many decades. Offshore wells yield one-third of current U.S. oil production,1 

and in recent decades helped offset declines in production elsewhere in the United States 

(U.S. production peaked in 1970).2 That already-crucial role is likely to increase. The area 

of federal jurisdiction, the outer continental shelf, contains an estimated 85 billion barrels 

of oil in technically recoverable resources3 —more than all onshore resources and those in 

the shallower state waters combined.

4 The future of domestic oil production will rely to 

a substantial extent on current outer continental shelf sources and further development 

of deposits there—in progressively deeper, more distant waters, and perhaps in such 

challenging environs as the Alaskan Arctic. Whether we explore for and produce oil and 

gas from those prospective reserves, and if so, under what conditions, depends crucially on 

taking to heart the lessons we learn from the Deepwater Horizon disaster and the energy 

policies we put in place.

Important decisions about whether, when, where, and how to engage in offshore drilling 

cannot be made wisely if they are made in a vacuum. Policies about offshore drilling 

should be powerfully shaped by economic, security, pace of technology, safety, and 

environmental concerns. Offshore drilling will certainly be an important part of any 

national energy policy. But it is only a part of the picture, and its relative importance today 

will not, and should not, be the same a half-century from now. The nation must begin a 

transition to a cleaner, more energy-efficient future. Nonrenewable oil and gas resources 

are just that—nonrenewable—which means any nation forging an energy policy for the 

future must develop the technologies that provide maximum energy efficiency and create 

renewable substitutes. Otherwise, the nation’s security and well-being will be increasingly 

dependent on diminishing supplies of nonrenewable resources, and even more dependent on 

supplies from foreign sources. 

Domestic consumption of oil has exceeded domestic production since the late 1940s, 

making the country increasingly dependent on imports, which now supply about 52 

percent of U.S. needs compared to 42 percent in 1990. In the near term, oil from federal 

offshore lands helps moderate America’s dependence on imported supplies, lessening the 

current trade deficit and contributing to national security. 
Chapter Ten 295 295

The government also reaps significant revenues from the leasing of federal lands and 

the collection of royalties on production—typically, billions of dollars per year. The 

development of offshore energy resources contributes substantially to local economies, 

supporting businesses small and large and employing tens of thousands of workers. 

But any sensible energy policy must recognize the substantial risks that accompany these 

real benefits, in addition to the dangers of an economy and national security dependent 

on nonrenewable energy supplies. The impressive technologies developed for offshore 

drilling and production have not been accompanied by comparable improvements in safety 

and environmental protection. As Americans now know, three major companies failed to 

apply rigorous process safety measures to their drilling operations in the Gulf of Mexico: 

Halliburton and Transocean, which service drilling operations throughout the Gulf, along 

with BP —underscoring the systemic nature of the offshore industry’s problems. 

This Commission has documented and explained these tragic failures, and in this report 

has recommended a comprehensive, integrated set of reforms required to improve the 

performance of the offshore oil and gas industry, as appropriately overseen by an effective 

regulatory authority. A safe offshore oil and gas industry matters—both because the 

costs of needlessly risky behavior are so high, and because the nation is so dependent on 

offshore energy supplies. In light of present knowledge, inaction is a policy of dangerous 

default—of continuing to rely on chance and luck to avoid a “next time.” American citizens 

will demand and will hold the oil and gas industry and government officials responsible 

for creating the conditions under which a robust offshore oil and gas industry can operate 

safely and co-exist with human health, environmental protection, and other economic 

activities. 

Weighing National Security, the Economy, Human Safety, and the Environment

In contemporary America, petroleum is woven into every aspect of our lives. The 

continuous availability of oil products—gasoline, diesel, and jet fuel—powers the mobility 

that has become key to a strong economy. Military operations, the movement of food and 

other commercial products, and personal travel would all grind to a halt without oil—at 

least as our society is organized today. Yet growing demand for oil around the world, 

particularly in the huge and rapidly developing economies of Asia, ensures heightened 

competition for supplies, putting upward pressure on oil prices. That poses a long-term 

challenge for the United States, which is not and cannot be self-sufficient in oil supply. 

At the same time, scientific evidence has continued to mount on the interconnections 

among the use of all carbon-based fuels, including oil and natural gas, the growing 

concentrations of greenhouse gases, and global climate change.5 Energy policy thus 

embraces considerations of national security, the economy, environmental protection, 

the need to limit climate change, the pace of development of renewable energy sources 

and nonpetroleum dependent vehicles, human health and safety, and unique regional 

conditions.

Security and petroleum resources. The major American security risk derives from oil’s 

predominant role in transportation: 72 percent of oil consumed in the United States in 

2009 was used for transportation—and 94 percent of transportation relied on oil.6 As 

the National Academy of Sciences recently concluded, the nation “needs to lower its 
296 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

dependence on fragile supply chains for some energy sources, particularly petroleum at 

present and possibly natural gas in the future, and to avoid the impacts of this dependence 

on our nation’s economy and national security.”7 The good news is that energy-efficient 

technologies exist today that can in the near term moderate the nation’s demand for oil 

and change the mix of supplies of electricity and energy over time. But changing existing 

reliance on oil in general and oil imports in particular will require a major overhaul of our 

energy and transportation systems, a challenging shift that would require strong public 

leadership, and would take decades to effect even if we agreed on the course of action 

tomorrow. 

Recent events have made clear the magnitude of the stakes. The United States has 

repeatedly been surprised by sudden interruptions in the oil supply from various 

unexpected events—underscoring the nation’s potential vulnerability. These include 

politically motivated production cuts by oil-exporting countries (the oil embargo of 1973-

1974); border wars between oil exporters (between Iraq and Iran in 1980-1988, and Iraq 

and Kuwait in 1990-1991); strife and unrest within several oil-exporting countries; and 

severe weather events affecting offshore oil production or coastal refineries (Hurricanes 

Katrina and Rita in 2005 and Ike in 2008—all in the Gulf of Mexico). Energy planners also 

worry about the possibility that the Straits of Hormuz—the only sea passage to the open 

ocean for the bulk of Persian Gulf petroleum exports—could be closed, or that a major oil 

pipeline somewhere in the world could be ruptured by accident or attack.

Even absent an actual interruption in supplies, our reliance on foreign oil is a national 

security concern. Hostile exporting nations can use the threat of interrupting supplies to 

pressure the United States. Money spent on foreign oil can also end up in the hands of 

terrorists or be used to build nuclear or develop biological weapons in nations flouting the 

international atomic and biological regulatory regimes. The ultimate nightmare would 

be an America depleted of petroleum, which has failed to make a sufficient transition to 

alternative sources, facing another Pearl Harbor or the aftershocks of 9/11.

Since “Colonel” Drake first struck oil at his Pennsylvania site in 1859, the United States 

has already extracted over 200 billion barrels of oil from its territory8—more than our 

estimated remaining reserves. The United States did not relinquish its position as the 

world’s leading producer until 19749—but now it finds itself credited with only 1.4 

percent of the world’s proved oil reserves, while consuming 22 percent of the global 

supply annually.10 (The use of advanced extraction technologies and a relatively favorable 

investment climate have enabled the United States to remain the world’s third-largest oil 

producer, despite its relatively meager reserves.) 

Would the country’s security interests be better served by developing domestic oil 

resources as rapidly as possible—or by reserving some for future generations? President 

Harry Truman argued that federal offshore oil resources should become part of the naval 

petroleum reserve system, leaving the oil in the ground for later development (see Chapter 

3). In recent decades, the concept of the Naval Petroleum Reserve has been superseded by a 

more readily accessible Strategic Petroleum Reserve, which currently contains more than 

700 million barrels of unrefined crude oil stored in Louisiana and Texas salt caverns along 
Chapter Ten 297 297

the Gulf coast where it is available for national emergencies (such as sudden disruptions 

of supply).11 That provides some insurance—but only about 75 days of supply at the 

current rate of U.S. imports, and clearly not sufficient to displace any long-term decline 

in domestic production or respond to a spike in demand. The United States has kept some 

areas of the outer continental shelf off-limits for oil and gas production: to protect their 

unique and valuable environmental characteristics, to avoid incurring risks to major 

industries such as fishing and tourism, or to maintain open waters for testing of military 

armaments and training exercises over the Gulf. One way of viewing these areas where 

drilling is prohibited—Atlantic Coast, Eastern Gulf of Mexico and Florida coast and the 

coasts of Northern California, Oregon, and Washington—is as energy sources held in 

reserve.

National economic implications. The domestic oil and gas sector is a major employer, 

particularly in fuel-producing regions. Fluctuations in oil and gas prices generally 

pass quickly through to energy-intensive sectors of the economy: trucking, airlines, 

agriculture, and petrochemicals such as plastics. Although energy’s share of the economy 

has diminished in recent decades, Americans paid $740 billion for oil and gas products 

in 2007,12 and energy prices still have a major impact on inflation. Because oil and gas 

behave and are traded as commodities, their prices can undergo large changes even apart 

from immediate supply and demand factors. This volatility, from all sources, can make 

it difficult for businesses and individuals to plan and adhere to their budgets for energy 

costs. Price jolts stemming from undependable supplies can have major, adverse effects on 

the whole economy. Economists Hillard Huntington and Stephen Brown have found that 

“Historical experience shows that the Gross Domestic Product (GDP) losses associated with 

oil supply shocks can be considerable.”13 Most strikingly, they noted that 10 of the 11 

U.S. recessions since World War II were preceded by sharply rising oil prices.

Given Americans’ consumption of petroleum products in excess of domestic supply, the 

country runs a staggering trade imbalance. Between 2004 and 2009, the U.S. trade balance 

for oil and gas ranged between negative $186 billion and negative $414 billion per year—

typically exceeding the much-publicized trade deficit with China.14 Economic theories of 

comparative advantage may suggest that particular trade deficits are not worrisome—but 

the large, sustained trade deficit incurred to import petroleum, particularly, makes energy a 

significant factor in America’s overall trade, deficit, and financing strategies and challenges.

Environmental and safety challenges. This report has documented in painful detail the 

far-reaching environmental consequences of catastrophic accidents involving the extraction 

of oil from offshore sources, and the associated risks to workers’ safety from drilling, 

refinery operations, and the emergency clean-up of spills. Further environmental damage 

occurs when oil products are used as transportation fuels. Emissions released when fuel 

is burned are generally controlled under federal law, but can still (in combination with 

emissions from combustion to generate electricity) create conditions that can cause serious 

health consequences for the American public and serious ecological consequences for our 

natural systems, forests, and waters. And the combustion of all fossil-based carbon fuels 

(oil, gas, and coal) has long-term impacts on the increasing volume of greenhouse gases in 

the atmosphere and the warming climate. Transportation fuels contribute one-third of U.S. 
298 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

carbon emissions, making them the nation’s second-largest source contributing to climate 

change. 

Criteria for balanced energy policy. Reconciling the multiple, sometimes conflicting aims 

that underlie any transportation-related American petroleum energy policy depends on six 

criteria:

•	 Maintaining a sufficient reserve of petroleum to protect American national security 

should access to foreign sources be lost or become unreliable; 

•	 Requiring energy-efficient automobiles and other vehicles (among other sources of 

consumption) to reduce fuel use, and promoting energy-efficient transit alternatives;

•	 Promoting the development of clean and domestically produced alternative fuels or 

sources of power for transportation;

•	 Managing the inherent risks of domestic production of oil and gas—including from 

offshore areas—while considering the short- and long-term availability of these fuels;

•	 Requiring safe operations to protect human health; and

•	 Protecting the natural environment, including steps to limit climate change. 

Reasonable people can disagree about the relative importance of these criteria—and have 

over time. President Truman ordered a postponement of mineral development on the outer 

continental shelf in order to ensure oil and gas would be there later for strategic purposes. 

During the 1970s, Congress adopted legislation to maximize environmental protection, 

and then to expand energy production (as discussed in Chapter 3)—but over the long term, 

none can be pursued to the exclusion of the others. It is notable, moreover, that various 

policies have had significant effects on U.S. energy use and production. For example, the 

country has achieved intermittent but sizable increases in automobiles’ fuel efficiency; 

major reductions in tailpipe emissions from gasoline-fueled vehicles; and less reliance on 

oil to generate electricity.15 At several points during the past four decades, consumption of 

oil in the United States actually declined for several years (in some cases reflecting adverse 

economic conditions, and in others successful public policies and adoption of technological 

advances).16

The United States today pursues many discrete policies bearing on all of these issues: 

vehicle-fuel efficiency standards, subsidies for ethanol production for fuel, research into 

alternative fuels, varying incentives for production of electricity by wind and solar 

power, and so on. In the aggregate, they are, de facto, the nation’s energy policy. But 

they do not constitute a comprehensive, coherent strategy—such as recently called for 

by both the National Research Council17 and the President’s Council of Advisors on 

Science and Technology18—one that encompasses all of these elements, identifies tradeoffs 

and priorities, and implements them through incentives, investments in research and 

development, regulations, and tax policy. Difficult though it may be to arrive at such a 

consensus, it would provide guidance on balancing the risks and rewards of oil and gas 

development in especially challenging or sensitive locations, offshore or elsewhere. It is 

possible—and imperative—to manage that balance over time for offshore development of 

oil and gas as part of that overall policy.
Chapter Ten 299 299

Learning from the Macondo Disaster: The Gulf of Mexico

This report describes in great detail what went wrong on the Deepwater Horizon and in 

the drilling of the Macondo well, and the well blowout’s staggering cost. As the nation 

considers exploring for and producing energy from offshore frontiers, we have a new 

opportunity to do things right. Some of those frontiers are in deeper waters or unexplored 

areas of the Gulf of Mexico. Others are at the far extreme of the country, in both distance 

and climate in Alaska. 

Improving safety and environmental integrity immediately. It will take several years to 

fully implement the stringent new safety regime this Commission has recommended—

essential changes from doing business as usual in the Gulf of Mexico. But it is not 

necessary to put deepwater drilling on hold until all the changes are in place. The national 

and regional energy and economic imperatives can be reconciled effectively with the equally 

urgent needs to assure human safety and environmental integrity in the Gulf context, now 

and in the long term.

Several benchmarks must be met for exploratory drilling to resume on existing leases, 

and for operations to begin on new ones. Operators must assure that better practices for 

maintaining well integrity and the isolation of hydrocarbons are used at all times. And 

they must insist upon heightened vigilance throughout all the steps from the inception of 

well design to the consideration of changes during drilling operations. Similarly, protocols 

for testing of blowout preventers must be put in place and enforced. The industry 

must also demonstrate that it is deploying readily available and effective systems for 

containment and response.

As the energy industry works to satisfy these requirements, the Department of the Interior 

must work promptly to reorganize its divisions, augment its regulatory staff, and enhance 

their skill. The American public has every reason to insist that Congress provide regulators 

with adequate resources to do their vital job—and that the industry apply its resources 

and expertise to improving practices. Both must focus on the substantial challenges of 

making offshore drilling safe, reliable, and productive. The circumstances demand a shared 

commitment by government and industry to work for immediate and long-term reforms 

that allow deepwater exploratory drilling to resume quickly and safely. And, to that end, 

industry should be ready to pay fees as part of their lease agreements in order to ensure 

that government overseers have the resources required to get the job done in a rigorous 

and timely fashion. 

Emerging challenges from ultra-deepwater drilling. That shared commitment must extend 

beyond current conditions. While correcting the many problems revealed at the Macondo 

well, both industry and government must anticipate and adjust to new challenges arising 

in the Gulf. Current technology enables drilling in water twice as deep as Macondo. 

Drilling at such depths requires all parties to set their standards still higher for difficult 

issues such as remote containment systems in water depths with extreme pressures and 

very limited human access, as well as different geological pressures and formations and 

mixes of hydrocarbons. Desire to tap resources in deeper waters should be accompanied by 

equivalent investments in subsea equipment, operator training, research and development 
300 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

for containment and response technologies, demonstrated financial capacity, and 

continuous improvement in and communication of industry practices devoted to safety.

The emerging international challenge. Drilling for oil in the Gulf of Mexico is not solely a 

matter for U.S. consideration. Both Mexico and Cuba have expressed interest in deepwater 

drilling in the Gulf in the near future. Pemex, Mexico’s state-owned petroleum company, 

and Cuba, through both the Spanish company Repsol and the large Russian oil and gas 

production company Gazprom, in which the Russian government maintains a controlling 

stake,19 have either actually drilled exploratory and production wells or are likely 

soon to do so.20 Potential drilling sites are close enough to waters and land within U.S. 

jurisdiction—Cuba’s mainland lies only 90 miles from Florida’s coast and the contemplated 

wells only 50 miles—that if an accident like the Deepwater Horizon spill occurs, fisheries, 

coastal tourism, and other valuable U.S. natural resources could be put at great risk.

It is in our country’s national interest to negotiate now with these near neighbors to 

agree on a common, rigorous set of standards, a system for regulatory oversight, and 

the same operator adherence to the effective safety culture called for in this report, along 

with protocols to cooperate on containment and response strategies and preparedness in 

case of a spill. Though some precedent exists for a direct agreement between the United 

States and Cuba, Mexico may prove an important partner in developing such an agreement 

covering the entire Gulf of Mexico. In any event, the U.S. objectives should be to prevent 

drilling by companies unwilling or unprepared to meet the high safety standards essential 

to extracting oil and gas resources responsibly and to have a verification process to ensure 

compliance.

Beyond the Gulf of Mexico: Frontier Regions 

The nation’s demand for domestic oil production will push the boundaries of technology 

and geography. The industry will develop new exploration and extraction techniques 

and equipment in new areas in the decades ahead. Drilling safely in the Gulf of Mexico 

requires a new industry safety culture and significantly improved regulatory oversight. 

Those reforms, and further heightened vigilance, will be required for oil exploration and 

production in frontier offshore regions. When the Macondo blowout dumped enormous 

volumes of oil into the Gulf waters, scientists and policymakers realized how little was 

known about biological systems, environmental conditions, and even key aquatic and 

coastal species. Leasing of vast acreage combined with weak policies and limited funding 

had resulted in inadequate studies of unique habitats and sensitive environmental features 

where greater caution should be exercised. What information was available was often not 

shared, or was disregarded, in leasing and permitting decisions. And little, if any, research 

or policy existed to address human health impacts and the risks to responders from a 

major spill, or the far-reaching effects of such a disaster on other businesses dependent on 

the region’s resources.

In addition to these challenges, each frontier area presents important differences in 

implementing any drilling program—different geologies, hydrocarbon formations, 

coastal communities and environments, and climate conditions, to mention some. Federal 

waters of the United States other than the central and western Gulf of Mexico, parts of 
Chapter Ten 301 30

Southern California, and the Lower Cook Inlet in Alaska would be regarded as frontier 

territory. In the late 1970s, attention turned briefly to areas off of northern California 

and Massachusetts (Georges Banks), and in the early 1980s, the potential of the outer 

continental shelf off Alaska attracted considerable investment (see Chapter 2). In recent 

years, the focus has turned to exploring in the Atlantic Ocean off the state of Virginia; in 

the eastern Gulf of Mexico; and, most notably, to taking another serious look at offshore 

regions in the Alaskan Arctic. Drilling water depths of 10,000 feet or more anywhere 

in the Gulf of Mexico might also be considered opening a new frontier, given the new 

technologies required.

In March 2010, President Obama and Interior Secretary Ken Salazar announced a plan 

to open the eastern Gulf and parts of the Atlantic coast—including offshore Virginia—

to oil and gas exploration (subject to studies of the suitability of doing so in each area, 

and to the lifting of a congressional moratorium restricting drilling in the eastern Gulf). 

But on December 1, in the wake of the Deepwater Horizon experience and the resulting 

broad restructuring of regulations and the federal oversight capabilities, Secretary Salazar 

announced that the Administration would not proceed with drilling in areas where there 

are “no active leases” during the next five-year leasing plan. As a result, exploration and 

production in certain frontier areas—the eastern Gulf and off of the Atlantic and Pacific 

coasts—are deferred. The Secretary also indicated that plans for 2011 drilling in Alaska’s 

Beaufort Sea would be subjected to additional environmental assessments. There will 

consequently be a continuing examination of the various stages of drilling, if pursued, 

consistent with national energy policy and with a full awareness of the risks and of the 

values that must be balanced in each region, and with assurance that operators rigorously 

adhere to the best practices of a functioning safety culture.

By their very location and nature, these frontier areas differ from the Gulf of Mexico and 

in important respects from each other. Environmental and biological conditions are at least 

as well understood along the Atlantic coast as in the Gulf—and there are also important 

facilities, such as Coast Guard installations in place; in contrast, equivalently detailed 

geological and environmental information does not exist for the Arctic exploration areas of 

greatest interest for energy exploration—and industry and support infrastructures are least 

developed, or absent, there. In the near term, the Alaskan frontier is likely to attract the 

greatest attention, and to require the closest scrutiny, given the potential energy resources 

and the physical and environmental challenges of pursuing them safely.

Large prospects in offshore Alaska. The interest in offshore Alaska reflects the likelihood of 

finding significant new sources of oil:21 the Chukchi and Beaufort Sea areas off Alaska’s 

north coast rank behind only the Gulf of Mexico in estimated domestic resources.22 The 

most recent federal lease sales for the Beaufort Sea, from 2003 to 2008, netted $98 million, 

reflecting high levels of industry interest. And despite its remoteness and harsh conditions, 

the Chukchi Sea—with vast potential resources—attracted over $2.6 billion in high bids 

for almost 2.8 million acres, including $2.1 billion from Shell Oil Company, during a 2008 

lease sale.23 
302 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

If deemed feasible, new offshore Alaskan oil production may be well-timed to offset the 

sustained decline in output elsewhere in Alaska. Oil production in the state (primarily from 

the onshore field at Prudhoe Bay) has decreased by more than two-thirds, from the 1988 

peak of 2 million barrels per day to 645,000 barrels per day in 2009.24 Depending on 

future prices, this decline could constitute a threat to the state’s economy, which is highly 

dependent on oil and gas revenues and related employment. The Energy Information 

Administration projects that Alaska’s production will continue to decline, to just 420,000 

barrels per day by the end of this decade.25 Such declines could threaten the viability of 

the Trans-Alaska Pipeline System, which transports oil from the North Slope to the port at 

Valdez.

Despite the Energy Information Administration’s pessimism about long-term production 

trends in Alaska, other projections show a potential upswing26 An optimistic scenario 

developed in 2009 study by Northern Economics for Shell Exploration and Development 

projects production from multiple Alaska outer continental shelf sites beginning in 2018 

and eventually peaking at 1.8 million barrels of oil per day.27 (New pipelines would need 

to be built to connect these reservoirs, if brought into production, to the Trans-Alaska 

Pipeline System.) 

But finding and producing those potentially important supplies of oil offshore Arctic 

Alaska requires the utmost care, given the special challenges and risks associated with this 

frontier. Many of these challenges also arise elsewhere in the world, as Russia, Norway, 

Canada, and Denmark (Greenland) evaluate their Arctic oil and gas resources. The Alaskan 

Arctic is characterized by extreme cold, extended seasons of darkness, hurricane-strength 

storms, and pervasive fog—all affecting access and working conditions. The Chukchi and 

Beaufort Seas are covered by varying forms of ice for eight to nine months a year. These 

conditions limit exploratory drilling and many other activities to the summer months. 

The icy conditions during the rest of the year pose severe challenges for oil and gas 

operations and scientific research. And oil-spill response efforts are complicated year-round 

by the remote location and the presence of ice, at all phases of exploration and possible 

production.

The geological pressures in hydrocarbon deposits in shallow seas off Alaska are likely to be 

substantially below those encountered at Macondo, reducing some of the risks of a major 

blowout and challenges of containment. But oil spilled off Alaska (from blowouts, pipeline 

or tanker leaks, or other accidents) is likely to degrade more slowly than that found in 

the Gulf of Mexico because of lower water temperatures, reduced mixing of the oil into 

the water due to the presence of ice, and the shallower depths through which oil would 

travel from the wellhead to the surface. Some think the slow weathering could facilitate 

the skimming and in situ burning of escaped oil under ideal weather conditions, but the 

slow pace of natural dispersion means that oil would linger much longer in the marine 

environment. And serious questions remain about how to access spilled oil when the area 

is iced over or in seasonal slushy conditions. 
Chapter Ten 303 303

The Arctic ecosystem, the need for scientific information and informed decision-making, 

and Alaska native peoples. The stakes for drilling in the U.S. Arctic are raised by the 

richness of its ecosystems. The marine mammals in the Chukchi and Beaufort are among 

the most diverse in the world, including seals, cetaceans, whales, walruses, and bears. The 

Chukchi Sea is home to roughly one-half of America’s and one-tenth of the world’s polar 

bears.28 In November 2010, the U.S. Fish and Wildlife Service ruled that a large part of 

the polar bears’ “critical habitat” included sea ice in the Beaufort and Chukchi Seas.29 The 

Chukchi and Beaufort Seas also support millions of shorebirds, seabirds, and waterfowl, as 

well as abundant fish populations. 

It is known that these are vibrant living systems, but scientific research on the ecosystems 

of the Arctic is difficult and expensive. Good information exists for only a few species, 

and even for those, just for certain times of the year or in certain areas. As a result, 

the Commission recommends an immediate, comprehensive federal research effort to 

provide a foundation of scientific information on the Arctic (with periodic review by the 

National Academy of Sciences), and annual stock assessments for marine mammals, fish, 

and birds that use the Beaufort and Chukchi Seas. This initiative should be coordinated 

with the state of Alaska, native organizations, academic institutions, non-governmental 

organizations, the private sector, and international partners. The information generated 

should be capable of informing decision-making related to oil and gas leasing, exploration, 

and development and production in the Arctic; measuring and monitoring impacts of oil 

and gas development on Arctic ecological resources; natural resource damage assessment 

should an oil spill occur and protocols in any treaty negotiated among the Arctic nations. 

The existing gaps in data also support an approach that distinguishes in leasing decisions 

between those areas where information exists and those where it does not, as well as 

where response capability may be less and the related environmental risks may therefore be 

greater. The need for additional research should not be used as a de facto moratorium on 

activity in the Arctic, but instead should be carried out with specific timeframes in mind in 

order to inform the decision-making process. 

The Inupiat Eskimos of Alaska’s remote arctic and subarctic communities rely heavily for 

their subsistence on resources from the marine environment, particularly bowhead whales. 

Bowhead whales can reach 60 feet in length and weigh more than 120,000 pounds. They 

migrate from Russian to Canadian waters and back through the Chukchi and Beaufort 

Seas.30 They are the most important subsistence animal for the coastal communities of 

northwest and northern Alaska.31 Whale hunting and the customs surrounding it are also 

an important part of their cultural heritage. Oil and gas development has the potential, 

directly or indirectly, to affect hunting success or the habitats of species important to 

subsistence. (Of course, offshore oil development could play a positive economic role in 

the native communities; some Inupiat whaling captains also work in the oil industry, for 

instance.) An Arctic Regional Citizens Council could help assure the active participation of 

the people who know this region the best in planning and response.

Arctic spill response and containment. The remoteness and weather of the Arctic frontier 

create special challenges in the event of an oil spill. Successful oil-spill response methods 

from the Gulf of Mexico, or anywhere else, cannot simply be transferred to the Arctic. 
304 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Industry and academic organizations are conducting research on response to oil on ice, 

but more needs to be done. A comprehensive interagency research program to address 

oil-spill containment and response issues in the Arctic should be developed, funded, and 

implemented within the federal government. Spill trajectory and weather models based on 

Arctic conditions must also be developed. This research should be funded promptly by the 

Oil Spill Liability Trust Fund, and the resulting analysis should inform when and where 

leasing occurs. 

The National Contingency Plan requires the Coast Guard to oversee oil-spill planning 

and preparedness, and to supervise an oil-spill response in coastal waters. Current 

federal emergency response capabilities in the region are very limited: the Coast Guard 

operations base nearest to the Chukchi region is on Kodiak Island, approximately 1,000 

miles from the leasing sites. The Coast Guard does not have sufficient ice-class vessels 

capable of responding to a spill under Arctic conditions: two of its three polar icebreakers 

have exceeded their service lives and are non-operational.32 In addition to overseeing spill 

response, the Coast Guard provides search and rescue capabilities in other areas. Without 

a presence in the Arctic, it would be very difficult for the Coast Guard to conduct any 

emergency search and rescue operations. 

To deal with these serious concerns about Arctic oil-spill response, containment, and 

search and rescue, the Commission recommends three approaches before the Department 

of the Interior makes a fully informed determination that drilling in a particular area is 

appropriate. First, the Department of the Interior should ensure that the containment and 

response plans proposed by industry are adequate for each stage of development and that 

the underlying financial and technical capabilities have been satisfactorily demonstrated in 

the Arctic. Second, the Coast Guard and the oil companies operating in the Arctic should 

carefully delineate their respective responsibilities in the event of an accident, including 

search and rescue, and then must build and deploy the necessary capabilities. Third, 

Congress should provide the resources to establish Coast Guard capabilities in the Arctic, 

based on the Coast Guard’s review of current and projected gaps in its capacity. 

International standards for Arctic oil and gas. The Arctic is shared by multiple countries, 

many of which are considering or conducting oil and gas exploration and development. 

The extreme weather conditions and infrastructure difficulties are not unique to the U.S. 

Arctic. The damages caused by an oil spill in one part of the Arctic may not be limited to 

the waters of the country where it occurred. As a result, the Commission recommends that 

strong international standards related to Arctic oil and gas activities be established among 

all the countries of the Arctic. Such standards would require cooperation and coordination 

of policies and resources. The Arctic Council33 has begun work in this direction, updating 

its voluntary Arctic Offshore Oil and Gas Operation Guidelines in 2009. The International 

Standards Organization is also developing international standards for Arctic offshore 

structures that would apply to the activities of petroleum and natural gas industries in 

Arctic and cold regions. These guidelines are expected to specify requirements and provide 

recommendations and guidance for the design, construction, transportation, installation, 

and removal of offshore structures in the Arctic. Additional work is needed to strengthen 
Chapter Ten 305 305

these guidelines and standards, ensuring that they are both consistent and mandatory 

across the entire Arctic, and the United States could pay an important leadership role in 

securing these vital safeguards. 

Bringing the potentially large oil resources of the Arctic outer continental shelf into 

production safely will require an especially delicate balancing of economic, human, 

environmental, and technological factors. Both industry and government will have to 

demonstrate standards and a level of performance higher than they have ever achieved 

before. One lesson from the Deepwater Horizon crisis is the compelling economic, 

environmental, and indeed human rationale for understanding and addressing the 

prospective risks comprehensively, before proceeding to drill in such challenging waters. 

Conclusion

Creating and implementing a national energy policy will require enormous political effort 

and leadership—but it would do much to direct the nation toward a sounder economy 

and a safer and more sustainable environment in the decades to come. In the meantime, 

decisions about offshore drilling—one crucial element in any discussion of energy supply—

remain controversial. The reaction to the December 1 decision to defer offshore exploration 

and production in the eastern Gulf of Mexico and along the Atlantic and Pacific coasts 

illustrates the polarization of opinion. Energy companies, seeking to pursue potential 

reserves in brand-new frontiers, criticized the announcement for closing off too many 

areas. Others, more concerned about environmental protection and national security, 

however, questioned why the Secretary was even considering allowing future drilling in 

these areas at all. And there were sharp differences in response among public officials in 

different regions, reflecting their local economies and sources of revenues.

These reactions echo the divided opinions presented to this Commission throughout its 

work. Though the Commission heard many ideas for improving safety and other aspects 

of offshore drilling, we also heard from Americans who advocate no future drilling 

whatsoever; they cited the adverse effects of fossil fuels on the climate, environmental 

damage, safety, and other factors.

Whether additional offshore drilling proceeds soon, in the longer term, or never depends 

on evolving public opinion. Given Americans’ consumption of oil, finding and producing 

additional domestic supplies will be required in coming years, no matter what sensible and 

effective efforts are made to reduce demand—in response to economic, trade, and security 

considerations, and the rising challenge of climate change.

The extent to which offshore drilling contributes to augmenting that domestic supply 

depends importantly on rebuilding public faith in existing offshore energy exploration and 

production. That rebuilding begins with a clear, independent explanation of what happened 

at the Macondo well in April 2010, and of the reforms required in the wake of that 

terrible tragedy. That has been the work of this Commission, published in this report; the 

forthcoming separate report of the Commission’s Chief Counsel; and background materials 

available on the Commission’s website. Together, they present a clear, independent, 
306 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

unvarnished picture of what happened and why—and of the major reforms the nation 

must adopt. 

This Commission proposes in this report a series of recommendations that will enable 

the country and the oil and gas industry to move forward on this one critical element of 

U.S. energy policy: continuing, safe, responsible offshore oil drilling to meet our nation’s 

energy demands over the next decade and beyond. Our message is clear: both government 

and industry must make dramatic changes to establish the high level of safety in drilling 

operations on the outer continental shelf that the American public has the right to expect 

and to demand. It is now incumbent upon the Congress, the executive branch, and the oil 

and gas industry to take the necessary steps. Respect for the 11 lives lost on that tragic 

day last April requires no less.
Endnotes 307 307

ENDNOTES

The Commission has reviewed thousands of pages of documents from dozens of government agencies, private companies, and other entities, and interviewed hundreds of witnesses from these same agencies, companies, and entities. 

When possible, we include all pertinent details in the following endnote citations for those documents and interviews 

that have contributed to this report. Many documents and interviews, however, were disclosed or given to the Commission on a confidential basis. For these “non-public” sources, our citations include only as much detail as we can comfortably disclose while still respecting the privacy concerns of the source (e.g., “non-public BP document,” “interview 

with government official,” “interview with Coast Guard official”).

The vast majority of non-public material that we cite in the endnotes below comes from documents and interviews 

provided by four government agencies—the Chemical Safety Board, the Coast Guard, the Department of Energy, and 

the Department of the Interior—and ten companies—BP, Cameron, Chevron, Dril-Quip, ExxonMobil, Halliburton, Schlumberger, Shell, Transocean, and Weatherford. In addition, the Commission participated in the Coast Guard’s Incident 

Specific Preparedness Review of the BP Deepwater Horizon spill, through which dozens of officials from a variety of 

federal and state agencies, federal, state, and local elected officials, and executives and personnel from private companies 

and other spill response-related entities have been interviewed. All Coast Guard Incident Specific Preparedness Review 

interviews are also cited as non-public. Finally, the Commission has interviewed many Gulf Coast residents who wish 

to remain anonymous. These interviews are cited as non-public as well.

Chapter One

1 Internal Halliburton document (HAL_0011208); Testimony of Nathaniel Chaisson, Hearing before the Deepwater 

Horizon Joint Investigation Team, August 24, 2010, 423. This report cites many “Internal documents” that the 

Commission received from companies, including BP, Halliburton, and Transocean. Those internal documents are 

identified by their document production serial numbers when available, which were assigned by the entity that 

provided them. 

2 Internal BP document (BP, presentation to Commission, August 9, 2010, slides 5 & 12). 

3 Testimony of Nathaniel Chaisson, 411; U.S. Department of Energy, Well Configuration (BP document made public by 

the Department of Energy), http://www.energy.gov/open/documents/3.1_Item_2_Macondo_Well_07_Jun_1900.pdf; 

Testimony of Natalie Roshto, Hearing before the Deepwater Horizon Joint Investigation Team, July 22, 2010, 15. 

4 Testimony of Michael Williams, Hearing before the Deepwater Horizon Joint Investigation Team, July 23, 2010, 

35–36. 

5 Testimony of John Guide, Hearing before the Deepwater Horizon Joint Investigation Team, July 22, 2010, 260–266; 

Testimony of James Wilson, Hearing before the Deepwater Horizon Joint Investigation Team, October 6, 2010, 176. 

6 Brian Morel, e-mail message to Richard Miller and Mark Hafle, April 14, 2010, 13:31, http://energycommerce.house.

gov/documents/20100614/BP-April14.Email.calling.Macondo.a.nightmare.well.pdf. 

7 BP, “GoM Exploration Wells: MC 252 #1—Macondo Prospect Well Information,” September 2009, http://

bpoilresponse.markimoore.com/blog/bp-media/docs/Macondo.Prospect.Well.Information.pdf. 

8 Testimony of Richard Tink, Hearing before the Deepwater Horizon Joint Investigation Team, May 26, 2010, 392; 

Deepwater Horizon Joint Investigation Team, AFE Summary for the Macondo Well, October 7, 2010, http://www.

deepwaterinvestigation.com/external/content/document/3043/914919/1/AFE%20Summary%20for%20the%20

Macondo%20Well.pdf. 

9 BP, Deepwater Horizon Accident Investigation Report (September 8, 2010), 17. 

10 Transocean, Our Company, http://www.deepwater.com/fw/main/Our-Company-2.html. 

11 Press Release, Transocean, Transocean Ltd. Reports Fourth Quarter and Full-Year 2009 Results, February 24, 2010. 

12 Press Release, Transocean, Transocean Inc. and GlobalSantaFe Corporation Agree to Combine, July 23, 2007. 

13 “Contractors ordering offshore rigs on speculation,” Drilling Contractor, May/June 2002. 

14 “Global 500,” CNNMoney.com, July 26, 2010, http://money.cnn.com/magazines/fortune/global500/2010/full_

list/index.html. 

15 Internal Transocean documents (TRN-HCJ 93526, 93528). 

16 Internal BP document (BP-HZN-MBI 126338); Internal BP document (BP-HZN-OSC 5378).

17 “Brazil Pins Hopes on Massive, untapped Oil Fields,” NPR, December 1, 2009, http://www.npr.org/templates/story/

story.php?storyId=120966523. 

18 Bureau of Ocean Energy Management, Regulation, and Enforcement, Installations, Removals, and Cumulative Totals 

of Offshore Production Facilities in Federal Waters; 1959–2010, February 2010, http://www.boemre.gov/stats/PDFs/

OCSPlatformActivity.pdf.; Bureau of Ocean Energy Management, Regulation and Enforcement, OCS Incidents/Spills 

by Category: 1996–2005, October 19, 2007, http://www.boemre.gov/incidents/Incidents1996-2005.htm; Bureau 

of Ocean Energy Management, Regulation, and Enforcement, OCS Incidents/Spills by Category: 2006-2010, July 10, 

2010, http://www.boemre.gov/incidents/IncidentStatisticsSummaries.htm. 
308 National Commission on the BP Deepwater Horizon OIl Spill and Offshore Drilling

19 Testimony of Ronald Sepulvado, Hearing before the Deepwater Horizon Joint Investigation Team, July 23, 2010, 7, 

14, 34.

20 Testimony of John Guide, 23.

21 Ibid., 43–44 and 189; Schlumberger, “Oilfield Glossary: cement bond log,” accessed November 19, 2010, http://

www.glossary.oilfield.slb.com/Display.cfm?Term=cement%20bond%20log. 

22 Testimony of John Guide, 43–44, 189–191. 

23 Testimony of Douglas Brown, Hearing before the Deepwater Horizon Joint Investigation Team, May 26, 2010, 88, 

91.

24 Testimony of Jimmy Harrell, Hearing before the Deepwater Horizon Joint Investigation Team, May 27, 2010, 77; 

Internal Transocean document (TRN-HCDC 92).

25 Internal Transocean document (TRN-HCDC 92); BP, Deepwater Horizon Accident Investigation Report, 82.

26 Testimony of Ross Skidmore, Hearing before the Deepwater Horizon Joint Investigation Team, July 20, 2010, 264.

27 BP, Deepwater Horizon Accident Investigation Report, 24.

28 Testimony of Jimmy Harrell, 38, 113; Testimony of Curt Kuchta, Hearing before the Deepwater Horizon Joint Investigation Team, May 27, 2010, 166, 183, 184.

29 Testimony of Daun Winslow, Hearing before the Deepwater Horizon Joint Investigation Team, August 24, 2010, 188 

and 191.

30 Testimony of Jimmy Harrell, 113; Testimony of Curt Kuchta, 184.

31 Testimony of David Sims, Hearing before the Deepwater Horizon Joint Investigation Team, August 26, 2010, 119.

32 Testimony of Daun Winslow, Hearing before the Deepwater Horizon Joint Investigation Team, August 23, 2010, 442. 

33 Testimony of Stephen Bertone, Hearing before the Deepwater Horizon Joint Investigation Team, July 19, 2010, 29, 

33; Testimony of Randy Ezell, Hearing before the Deepwater Horizon Joint Investigation Team, May 28, 2010, 279.

34 Testimony of Randy Ezell, 275.

35 BP, Deepwater Horizon Accident Investigation Report, 24.

36 Testimony of Stephen Bertone, 33.

37 Ibid.; Testimony of Randy Ezell, 280.

38 Testimony of Daun Winslow, August 23, 2010, 443.

39 Testimony of Stephen Bertone, 33–34; Testimony of Daun Winslow, August 23, 2010, 443.

40 Testimony of Randy Ezell, 281.

41 Ibid.

42 Ibid.

43 Ibid.

44 Testimony of Chris Pleasant, Hearing before the Deepwater Horizon Joint Investigation Team, May 28, 2010, 115, 

281.

45 Ibid., 116–118; Testimony of Jimmy Harrell, 117.

46 John R. Smith, Review of Operational Data Preceding Explosion on Deepwater Horizon in MC252, July 1, 2010, 

11–12. 

47 Testimony of Lee Lambert, Hearing before the Deepwater Horizon Joint Investigation Team, July 20, 2010, 291; 

Internal BP documents (BP-HZN-CEC 20347, 20178).

48 Internal BP documents (BP-HZN-CEC 20347, 20178).

49 Internal BP document (BP-HZN-MBI 21265). 

50 Testimony of Patrick O’Bryan, Hearing before the Deepwater Horizon Joint Investigation Team, August 26, 2010, 

364–365, 393.

51 Brian Morel, e-mail message to Richard Miller and Mark Hafle.

52 Testimony of Jimmy Harrell, 13.

53 BP, Deepwater Horizon Follow Up Rig Audit, Marine Assurance Audit and Out of Service Period, September 2009, 2, 

18–48; Internal BP document (BP-HZN-MBI 136211).

54 Testimony of Patrick O’Bryan, 364.

55 Testimony of David Sims, Hearing before the Deepwater Horizon Joint Investigation Team, May 29, 2010, 172, 313.

56 BP, Deepwater Horizon Accident Investigation Report, 25; Internal BP document (BP-HZN-CEC 17621).
Endnotes 309 309

57 BP, Deepwater Horizon Accident Investigation Report, 33.

58 Ibid., 25; Testimony of Chris Pleasant, 118–119.

59 Testimony of John Gisclair, Hearing before the Deepwater Horizon Joint Investigation Team, October 8, 2010, 

131–132.

60 Testimony of Curt Kuchta, 185–186; Testimony of Jimmy Harrell, 12.

61 Testimony of Yancy Keplinger, Hearing before the Deepwater Horizon Joint Investigation Team, October 5, 2010, 

128–129. 

62 Ibid.; Testimony of Andrea Fleytas, Hearing before the Deepwater Horizon Joint Investigation Team, October 5, 2010, 

16; Testimony of Daun Winslow, August 23, 2010, 296.

63 Testimony of Daun Winslow, August 23, 2010, 295; Testimony of Pat O’Bryan, 366.

64 Testimony of Daun Winslow, August 23, 2010, 295–296.

65 Testimony of Randy Ezell, 281, 282, 294.

66 Ibid., 282.

67 Ibid., 281-282, 311.

68 Testimony of Patrick O’Bryan, 219–220.

69 Testimony of David Sims, August 26, 2010, 163.

70 Ibid., 317; Testimony of Patrick O’Bryan, 367.

71 Testimony of David Sims, August 26, 2010, 174.

72 Ibid., 367.

73 Testimony of Patrick O’Bryan, 367.

74 Internal BP documents (BP-HZN-MBI 21418, 21420); BP, Deepwater Horizon Accident Investigation Report, 150.

75 Testimony of Randy Ezell, 282, 283.

76 Ibid., 283.

77 Ibid., 283–284. 

78 Testimony of Micah Sandell, Hearing before the Deepwater Horizon Joint Investigation Team, May 29, 2010, 8, 10, 

12.

79 Ibid., 11.

80 Internal BP documents (Deepwater Horizon Schematic; BP August 9, 2010 presentation to Oil Spill Commission, slide 

5 ).

81 Testimony of Douglas Brown, 88–89, 92–93.

82 Testimony of Paul Meinhart, Hearing before the Deepwater Horizon Joint Investigation Team, May 29, 2010, 28

83 Testimony of Douglas Brown, 93–94.

84 Ibid., 94–95.

85 Testimony of Steve Bertone, Hearing before the Deepwater Horizon Joint Investigation Team, July 19, 2010, 28, 34. 

86 Testimony of James Nicholas Wilson, Hearing before the Deepwater Horizon Joint Investigation Team, October 13, 

2010, 10; Testimony of Steve Bertone, 35.

87 Testimony of Steve Bertone, 35.

88 Testimony of Gregory Meche, Hearing before the Deepwater Horizon Joint Investigation Team, May 28, 2010, 198.

89 Testimony of Steve Bertone, 35–36.

90 Ibid.

91 Testimony of Andrea Fleytas, 14.

92 Testimony of Gregory Meche, 235.

93 Testimony of Andrea Fleytas, 14.

94 Complaint at 2, Shivers v. BP Plc., No. 10-cv-381 (S.D. Ala. July 20, 2010). 

95 Ibid.

96 Ibid.

97 Ibid.
310 National Commission on the BP Deepwater Horizon OIl Spill and Offshore Drilling

98 Ibid.; Tracey Dalzell Walsh, “Forced To Become Emergency Workers, Fishermen Say BP Never Even Said Thanks,” 

Courthouse News Service, July 22, 2010.

99 Testimony of Steve Bertone, 37. 

100 Ibid., 37–38.

101 Ibid., 38.

102 Ibid., 38–39.

103 Testimony of Randy Ezell, 284–285.

104 Ibid., 285.

105 Testimony of Yancy Keplinger, 165.

106 Testimony of Randy Ezell, 285–286.

107 Ibid., 286.

108 Ibid.

109 Ibid., 286–287.

110 Ibid., 287.

111 Testimony of Yancy Keplinger, 152; Testimony of Tyrone Benton, Hearing before the Deepwater Horizon Joint Investigation Team, July 23, 2010, 250.

112 Testimony of Gregory Meche, 209; Testimony of David Young, Hearing before the Deepwater Horizon Joint Investigation Team, May 27, 2010, 327; Testimony of Randy Ezell, 283; Testimony of Jimmy Harrell, 65; Testimony of 

Yancy Keplinger, 153.

113 Testimony of Micah Sandell, 11–13.

114 Testimony of Capt. Alwin Landry, Hearing before the Deepwater Horizon Joint Investigation Team, May 11, 2010, 

98–100. 

115 Testimony of Paul Erickson, Hearing before the Deepwater Horizon Joint Investigation Team, May 11, 2010, 

231–232.

116 Testimony of Capt. Alwin Landry, 101–102.

117 Ibid., 104–105.

118 Testimony of Gregory Meche, 202, 211, 223.

119 Testimony of Anthony Gervasio, Hearing before the Deepwater Horizon Joint Investigation Team, May 11, 2010, 

173, 187–188.

120 Ibid., 187; Testimony of Kevin Robb, Hearing before the Deepwater Horizon Joint Investigation Team, May 11, 

2010, 42.

121 Testimony of Anthony Gervasio, 189.

122 Ibid., 105, 190; Testimony of Gergory Meche, 223.

123 Testimony of Daun Winslow, August 23, 2010, 447–448.

124 Ibid., 448–449, 452.

125 Testimony of Mark Hay, Hearing before the Deepwater Horizon Joint Investigation Team, May 28, 2010, 225.

126 Testimony of Daun Winslow, August 23, 2010, 452; Testimony of Randy Ezell, 287.

127 Testimony of Daun Winslow, August 23, 2010, 452.

128 Ibid., 449–450, 452; Testimony of Randy Ezell, 289; Testimony of Anthony Gervasio, 190, 199.

129 Testimony of Daun Winslow, August 23, 2010, 450; BP, Deepwater Horizon Accident Investigation Report, 123.

130 Testimony of Daun Winslow, August 23, 2010, 450; Testimony of Steve Bertone, 39.

131 Testimony of Steve Bertone, 39.

132 Ibid.

133 Ibid.

134 Testimony of Daun Winslow, August 23, 2010, 451; Testimony of Steve Bertone, 39.

135 Testimony of Steve Bertone, 39.

136 Ibid.

137 Testimony of Patrick O’Bryan, 368, 396.

138 Testimony of Daun Winslow, August 23, 2010, 452.
Endnotes 311 31

139 Internal BP Document (BP-HZN-MBI 21277). 

140 Testimony of Daun Winslow, August 23, 2010, 451–452.

141 Internal BP Document (BP August 9, 2010 presentation to Oil Spill Commission, slide 13).

142 Testimony of Daun Winslow, August 23, 2010, 454.

143 Ibid., 454–455.

144 Testimony of Yancy Keplinger, October 5, 2010, 157.

145 Associated Press, “‘The Real Deal’: Survivors recall the Deepwater Horizon explosion,” Press-Register, May 9, 2010. 

146 Ibid.; BP, Deepwater Horizon Accident Investigation Report, 103. 

147 Testimony of Steve Bertone, 39–40.

148 Ibid., 40.

149 Ibid., 40–41.

150 Ibid., 41–43.

151 Ibid., 43.

152 Ibid.

153 Testimony of Randy Ezell, 288.

154 Testimony of Steve Bertone, 44.

155 Ibid., 44–46.

156 Ibid., 45–46.

157 Ibid., 46–47.

158 Ibid., 47–48.

159 Testimony of Michael Williams, 26.

160 Testimony of Steve Bertone, 48.

161 Testimony of Andrea Fleytas, 15.

162 Testimony of Steve Bertone, 48.

163 Ibid.

164 Ibid., 48–49.

165 Ibid., 48.

166 Testimony of Curt Kuchta, 219.

167 Testimony of Daun Winslow, August 28, 2010, 467.

168 Testimony of Steve Bertone, 50.

169 Ibid.

170 Testimony of Anthony Gervasio, 197.

171 Testimony of Steve Bertone, 49.

172 Internal Transocean document (TRN-USCG_MMS 30428).

173 Testimony of Anthony Gervasio, 224.

174 Testimony of Steve Bertone, 50.

175 Testimony of Capt. Alwin Landry, 112.

176 Testimony of Steve Bertone, 51.

177 Testimony of Kevin Robb, Hearing before the Deepwater Horizon Joint Investigation Team, May 11, 2010, 44.

178 Ian Urbina and Justin Gillis, “Workers On Oil Rig Recall a Terrible Night of Blasts,” New York Times, May 7, 2010.

179 Internal BP Document (BP-HZN-MBI 143366). 

180 Testimony of Alwin Landry, 115.

181 Urbina and Gillis, “Workers On Oil Rig Recall a Terrible Night of Blasts.”

182 Walsh, “Forced to Become Emergency Workers, Fishermen Say BP Never Even Said Thanks.”

183 Testimony of Steve Bertone, 52; Ibid., 48–53.

184 Testimony of Randy Ezell, 330.
312 National Commission on the BP Deepwater Horizon OIl Spill and Offshore Drilling

185 Testimony of Alwin Landry, 120–121.

186 Testimony of Daun Winslow, August 28, 2010, 44–45.

187 Testimony of Capt. Alwin Landry , 121–122.

188 Ibid., 125–126.

189 Ibid., 126.

Chapter Two

1 Joseph Pratt, Tyler Priest, and Christopher Castaneda, Offshore Pioneers: Brown & Root and the History of Offshore 

Oil and Gas (Houston: Gulf Publishing, 1997), 7–13; “First Well in Gulf of Mexico Was Drilling Just 25 Years Ago,” 

Offshore (October 1963): 17–19.

2 Quoted in Tom Zoellner, “Oil and Water: The Adventure of Getting One from Deep Beneath the Other,” Invention and 

Technology (Fall 2000): 48.

3 Daniel Yergin, The Prize: The Epic Quest for Oil, Money, and Power (New York: Simon and Schuster, 1992), 409.

4 Pratt, Priest, and Castaneda, Offshore Pioneers, 15–52, 137–157.

5 Ibid., 21–25.

6 Tyler Priest, “Extraction Not Creation: The History of Offshore Petroleum in the Gulf of Mexico,” Enterprise & Society

8, no. 2 (June 2007): 240.

7 Alden J. LaBorde, My Life and Times (New Orleans: LaBorde Printing Company, 1996), 174.

8 James W. Calvert, “Gulf Offshore Activity Booming,” World Petroleum (January 1957): 48.

9 Ben C. Belt, “Louisiana and Texas Offshore Prospects,” Drilling (March 1956): 119. 

10 “Special Offshore Report,” World Oil (May 1957): 118; Calvert, “Gulf Offshore Activity Booming,” 48.

11 Pratt, Priest, and Castaneda, Offshore Pioneers, 36–48.

12 Tyler Priest, The Offshore Imperative: Shell Oil’s Search for Petroleum in Postwar America (College Station: Texas 

A&M Press, 2007), 81–91.

13 Ibid., 95–98.

14 Tyler Priest, “Auctioning the Ocean: The Creation of the Federal Offshore Leasing Program, 1954-1962,” History of 

the Offshore Oil and Gas Industry in Southern Louisiana: Vol. 1: Papers on the Evolving Offshore Industry (Minerals 

Management Service OCS Study 2004-049, 2008).

15 U.S. Department of Interior, “Petroleum and Sulfur on the U.S. Continental Shelf,” internal study, August 1969, box 

134, Central Classified Files, 1969–1972, Record Group 48, Records of the Secretary of Interior, National Archives and 

Records Administration (NARA), College Park, MD.

16 Priest, “Auctioning the Ocean,” 113.

17 On Project Mohole and JOIDES, see David K. van Keuren, “Breaking New Ground: The Origins of Scientific Ocean 

Drilling,” in The Machine in Neptune’s Garden: Historical Perspectives on Technology and the Marine Environment, 

eds. Helen M. Rozwadowski and David K. van Keuren (Sagamore Beach, MA: Science History Publications, 2004), 

183–210. On Shell’s Eureka project, see Priest, The Offshore Imperative, 97, 218.

18 F. P. Dunn, “Deepwater Production: 1950-2000” (Offshore Technology Conference [OTC] Paper 7627, Houston, TX, 

May 1994).

19 Priest, The Offshore Imperative, 127–130.

20 Ibid.

21 Cliff Hernandez, interview by Andrew Gardner, May 1, 2001, New Iberia, LA, History of the Offshore Oil and Gas 

Industry in Southern Louisiana, Houston History Archives, M.D. Anderson Library Special Collections, University 

of Houston, Houston, TX. This interview is one of approximately 450 oral histories conducted for History of the 

Offshore Oil and Gas Industry in Southern Louisiana, Minerals Management Service OCS Study 2004-049 (2008).

22 Ken Arnold, interview with Tyler Priest, May 10, 2004, Houston, TX, History of the Offshore Oil and Gas Industry 

in Southern Louisiana, Houston History Archives, M.D. Anderson Library Special Collections, University of Houston, 

Houston, TX. 

23 Don E. Kash et al., Energy Under the Oceans: A Technology Assessment of Outer Continental Shelf Oil and Gas Operations (Norman: University of Oklahoma Press, 1973), 104.

24 U.S. Geological Survey, Monthly Engineering Reports Vol. 128 (December 1958) and Monthly Engineering Reports

Vol. 144 (February 1960), RG 57, Records of the U.S. Geological Survey, NARA.

25 Kash et al., Energy Under the Oceans, 105.

26 Neil R. Etson to President Nixon, March 18, 1970, Central Classified Files, 1968-1974, Box 71, RG 57, Records of the 
Endnotes 313 313

U.S. Geological Survey, NARA. 

27 Kash et al., Energy Under the Oceans, 104. 

28 Robert E. Kallman and Eugene D. Wheeler, Coastal Crude in a Sea of Conflict (San Luis Obispo: Blake Printery and 

Publishing, 1984), 63.

29 Riley E. Dunlap and Angela G. Mertig, American Environmentalism: The U.S. Environmental Movement, 1970–1990

(Philadelphia: Taylor and Francis, 1992).

30 Russell Wayland, “The New Federal OCS Regulations in the Light of Santa Barbara,” (Society of Petroleum Engineers 

[SPE] Paper 2780, San Francisco, CA, November 1969); Richard B. Krahl and David W. Moody, “Gulf Coast Lease 

Management Inspection Program” (OTC Paper 1714, Houston, TX, May 1972), 846.

31 M.D. Reifel, “Offshore Blowouts and Fires,” in The Technology of Offshore Drilling, Completion and Production, ETA 

Offshore Seminars, Inc. (Tulsa: The Petroleum Publishing Company, 1976), 239–257; “The Wicked Witch is Dead,” 

Shell News no. 2 (1978): 2–8; and R.C. Visser, “Offshore Platform Accidents, Regulations, and Industry Standards” 

(OTC Paper 7118, Houston, TX, May 1993). 

32 Krahl and Moody, “Gulf Coast Lease Management Program;” Donald Solanas, “Update—OCS Lease Management 

Program” (OTC Paper 1754, Houston, TX, April/May, 1973); E.W. Standley to Jack W. Boller, February 15, 1972, 

Central Classified Files, 1969–1972, Box 136, Part 13, RG 48, Records of the Secretary of Interior, NARA.

33 K. E. Arnold, P. S. Koszela, and J. C. Viles, “Improving Safety of Production Operations in the U.S. OCS” (OTC Paper 

6079, Houston, TX, May 1989).

34 Peter Lovie, “Classification and Certification of Offshore Drilling Units,” in The Technology of Offshore Drilling, 

Completion and Production, ETA Offshore Seminars, (Tulsa: The Petroleum Publishing Company, 1976), 389–413. 

35 Dunn, “Deepwater Production.” 

36 See data in National Academy of Sciences, Committee on Assessment of Safety of OCS Activities, Safety and Offshore 

Oil (Washington D.C.: National Academy Press, 1981).

37 E. P. Danenberger, “Outer Continental Shelf Drilling Blowouts, 1971-1991” (OTC Paper 7248, Houston, TX, May 

1993).

38 U.S. Energy Information Administration (EIA), “Petroleum,” Table 5.13.c, in Annual Energy Review 2009 (Washington, D.C.: U.S. EIA, 2010), http://www.eia.gov/emeu/aer/petro.html.

39 “Bidders Snub Most Deepwater Tracts,” Oil and Gas Journal (April 8, 1974): 36. 

40 Priest, The Offshore Imperative, 191–195.

41 Stephen P.J. Cossey, “Celebrations Began with Cognac,” AAPG Explorer (September 2004), http://www.aapg.org/

explorer/2004/09sep/gom_history.cfm.

42 Priest, The Offshore Imperative, 196–201.

43 Pratt, Priest, and Castaneda, Offshore Pioneers, 83–90.

44 “Gulf Lease Sale Shatters Two Records,” Oil & Gas Journal (October 6, 1980): 34; Charlie Blackburn, quoted in Priest, 

The Offshore Imperative, 216; D.A. Holmes, “1970-1986 Lookback of Offshore Lease Sales in the Gulf of Mexico 

Cenozoic,” interoffice memorandum, Shell Offshore Inc., August 24, 1987.

45 Priest, The Offshore Imperative, 209–215.

46 Juan Carlos Boué with Edgar Jones, A Question of Rigs, of Rules, or of Rigging the Rules? Upstream Profits and Taxes 

in U.S. Gulf Offshore Oil and Gas (Oxford: Oxford University Press, 2007), 17.

47 Rich Sears, “A Brief History of Deepwater” (draft prepared for the National Commission, August 2010).

48 Paul Voosen, “Gulf of Mexico’s Deepwater Oil Industry Is Built on Pillars of Salt,” New York Times, July 28, 2010; 

Gary Steffens and Neil Braunsdorf, “The Gulf of Mexico Deepwater Play: 50 Years from Concept to Commercial Reality” (AAPG Distinguished Lecture Series, 1997–1998).

49 Priest, The Offshore Imperative, 218–220.

50 Juan Carlos Boué and Gerardo Lyando, U.S. Gulf Offshore Oil: Petroleum Leasing and Taxation and Their Impact on 

Industry Structure, Competition, Production, and Fiscal Revenues (Oxford: Oxford Energy Institute, 2002).

51 Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE), “Gulf of Mexico Oil and Gas Leasing 

Offerings,” http://www.gomr.boemre.gov/homepg/lsesale/swiler/swiler.html.

52 Priest, The Offshore Imperative, 221–222.

53 “The Time to Start Looking is Now,” Shell News no. 4 (1984): 16.

54 By 1990, Americans consumed less gasoline on a per capita basis (437 gallons per year) than they did in 1979. U.S. 

Energy Information Administration (EIA), Annual Energy Review, Petroleum, Table 5.13.c, http://www.eia.gov/

emeu/aer/petro.html.

55 On the forgotten victory of energy conservation and efficiency, see Jay Hakes, A Declaration of Energy Independence: 

How Freedom from Foreign Oil Can Improve National Security, Our Economy, and the Environment (Hoboken: John 

Wiley & Sons, 2008), 41–71.
314 National Commission on the BP Deepwater Horizon OIl Spill and Offshore Drilling

56 Robert Gramling, Oil on the Edge: Offshore Development, Conflict, Gridlock (Albany, NY: SUNY Press, 1996), 118.

57 “Bullwinkle Takes Shape,” Shell News no. 6 (1987): 2–7; “Rising Above the Crowd,” Shell News no. 6 (1988): 28–34.

58 “How Conoco Developed the Tension-Leg Platform,” Ocean Industry, August 1984, 35–46.

59 Tom Curtis, “Lifestyles of the Rich and Bankrupt,” Texas Monthly, March 1988, 90.

60 Congress of the United States, Office of Technology Assessment, Oil and Gas Technologies for the Arctic and Deepwater: Summary (Washington: GPO, 1985), 22–23.

61 On the struggle over Bristol Bay, see Charles Frederick Lester, “The Search for Dialogue in the Administrative State: 

The Politics, Policy, and Law of Offshore Development” (Ph.D. dissertation, University of California, Berkeley, 1992), 

113–146. 

62 Priest, The Offshore Imperative, 209–215.

63 Steffens and Braunsdorf, “The Gulf of Mexico Deepwater Play.”

64 BOEMRE, “Gulf of Mexico Oil and Gas Leasing Offerings,” http://www.gomr.boemre.gov/homepg/lsesale/swiler/

swiler.html.

65 Priest, The Offshore Imperative, 237–251.

66 Ibid., 254–255.

67 Ibid., 253–261; “Launch Pad into the Deep,” Houston Chronicle, August 17, 1997.

68 Bob Horton quoted in Tom Bower, Oil: Money, Politics, and Power in the 21st Century (New York: Grand Central 

Publishing, 2009), 19.

69 William A. Schneider, “3-D Seismic: A Historical Note,” The Leading Edge (March 1998): 375; “Looking Ahead in Marine and Land Geophysics—A Conversation with Woody Nestvold and Ian Jack,” The Leading Edge (October 1995): 

1061–1067.

70 “Exploring the Ocean’s Frontiers,” Time, December 17, 1990, 98; “Offshore Oil: How Deep Can They Go?” Popular 

Science, January 1992): 80–97.

71 “Oil and Gas Technology Development,” (Topic Paper #26, National Petroleum Council Global Oil & Gas Study, 

November 22, 2006), 16. This topic paper was one of 38 working documents used to produce the 2007 National 

Petroleum Council study, Facing the Hard Truths About Energy http://www.npchardtruthsreport.org/. 

72 Susanne S. Pagano, “Offshore Drilling, Production—New Waves of Technology,” Sea Technology (April 1991): 19–21; 

“There’s Oil Down There . . . Way Down There,” Texas Shores 31, no. 1 (Spring 1998): 14–15.

73 Priest, The Offshore Imperative, 243–251.

74 “Shell Marks Progress in Deepwater Gulf,” Oil & Gas Journal 93, no. 46 (November 13, 1995); “Debottlenecking 

Removes Auger Production Constraints,” Oil & Gas Journal 94, no. 46 (November 11, 1996).

75 Priest, The Offshore Imperative, 251–253.

76 Press Release, Minerals Management Service, Shell to Pay $49 Million in Settlement Agreement with Minerals Management Service, August 5, 2003.

77 Boué and Jones, A Question of Rigs, 130.

78 F. Jay Schempf, “New Study Finds Port Fourchon ‘Vital’ to U.S. Economy,” Offshore (March 1, 2008).

79 D.G. Godfrey et al., “The Mars Project Overview” (OTC Paper 8368, Houston, TX, May 1997).

80 Ibid.

81 David Ernst and Andrew M.J. Steinhubl, “Alliances in Upstream Oil and Gas,” McKinsey Quarterly 2 (1997).

82 Jeff Ryser, “Hot Play in the Gulf,” Texas Business (August 1995): 33.

83 “The Cloning of Mars,” Shell News 64, no. 1 (1996): 8–13; Michael Davis, “Shell Oil Goes Deep in Gulf,” Houston 

Chronicle, April 9, 1999; Priest, The Offshore Imperative, 260–262.

84 Mary Judice, “Out of the LOOP,” Times Picayune, September 17, 1995; C.G. Steube, “Addressing Transportation Needs 

for Deepwater Gulf of Mexico” (OTC Paper 13169, Houston, TX, April/May 2001).

85 Boué and Jones, A Question of Rigs, 17.

86 Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE), “Installations, Removals, and Cumulative Totals of Offshore Production Facilities in Federal Waters: 1959-2010,” www.boemre.gov/stats/PDFs/OCSPlatformActivity.pdf.

87 Dolly Jorgenson, “An Oasis in a Watery Desert: Discourses on an Industrial Ecosystem in the Gulf of Mexico Rigs-toReefs Program,” History and Technology 25, no. 4 (November 2009): 343–364.

88 Press Release, Minerals Management Service, High Bids Total $307 Million in Central Gulf of Mexico Lease Sale 152, 

May 10, 1995, http://www.boemre.gov/ooc/press/1995/50037.txt.

89 Voosen, “Gulf of Mexico’s Deepwater Oil Industry Is Built on Pillars of Salt”; Helen Thorpe, “Oil and Water,” Texas 
Endnotes 315 315

Monthly (February 1996): 140–141.

90 Scott L. Montgomery and Dwight Moore, “Subsalt Play, Gulf of Mexico: A Review,” AAPG Bulletin 81, no. 6 (June 

1997): 875–876.

91 Rhonda Duey, “Pioneering a Global Play,” Hart’s E&P (July 1, 2009); Thorpe, “Oil and Water,” 142.

92 R.R. Israel et al., “Challenges Evolve for Directional Drilling Through Salt in Deepwater Gulf of Mexico,” Drilling 

Contractor (May/June 2008), http://drillingcontractor.org/challenges-evolve-for-directional-drilling-through-saltin-deepwater-gulf-of-mexico-1622.

93 David Ivanovich, “Gulf is Heart of Deepwater Drilling,” Houston Chronicle, May 4, 1997.

94 Brian Knowlton, “Oil Growth Boomerangs on Houston,” International Herald Tribune, April 1, 2002.

95 David Townshend, “Golden Triangle Dominates,” Petroleum Economist, October 2002.

96 Tim Colton and LaVar Huntziner, A Brief History of Shipbuilding in Recent Times (Alexandria, VA: CNA Corporation, 

2002); Mike Hunt and Lenny Gary, “Gulf of Mexico Fabrication Yards Built 5,500 Platforms Over 50 Years,” Offshore

(January 2000).

97 Ronald W. Ferrier, The History of the British Petroleum Company, Vol. 1: The Developing Years, 1901–1932 (Cambridge: Cambridge University Press, 1982); J.H. Bamberg, The History of British Petroleum, Vol. 2: The Anglo-Iranian Years, 1928–1945 (Cambridge: Cambridge University Press, 1994); and James Bamberg, British Petroleum and 

Global Oil, 1950–1975: The Challenge of Nationalism (Cambridge: Cambridge University Press, 2000). 

98 Agis Salpukas, “BP Amoco’s Leader Remakes An Oil Giant, Again,” New York Times, April 1, 1999.

99 Kathy Shirley, “Vision Led to Crazy Horse Find,” AAPG Explorer, March 2002.

100 Ibid.

101 Kristen Hays, “After All of Thunder Horse’s Problems, BP Looks Ahead To Seeing A Return On Its Enormous Investment In The Platform, Payoff Is A Long Time in Coming,” Houston Chronicle, November 18, 2007.

102 Ibid.

103 Peter Lehner with Bob Deans, In Deep Water: The Anatomy of a Disaster, the Fate of the Gulf, and Ending Our Oil 

Addiction (New York: The Experiment, 2010), 63. 

104 “Deepwater GOM New Focus of BP Growth Strategy,” Oil & Gas Journal 100, no. 33 (August 19, 2002): 36.

105 Neela Banerjee,“This Oil’s Domestic, but It’s Deep and It’s Risky,” New York Times, August 11, 2002.

106 “The Jack-2 Perspective,” Oil & Gas Journal 104, no. 34 (September 11, 2006): 17.

107 B.F. Thurmond, D.B.L. Walker, H.H. Banon, A.B. Luberski, M.W. Jones, and R.R. Peters, “Challenges and Decisions in 

Developing Multiple Deepwater Fields” (OTC Paper 16573, Houston, TX, May 2004).

108 K.L. Marshall and G.H. Smith, “Inspection Management Experience for a Fleet of Spars in the Gulf of Mexico” (OTC 

Paper 17619, Houston, TX, May 2005); C. Jim Thibodeaux, R. Don Vardeman, and Charles E. Kindel, “Nansen/

Boomvang Projects: Overview and Project Management” (OTC Paper 14089, Houston, TX, May 2002).

109 Thurmond et al., “Challenges and Decisions in Developing Multiple Deepwater Fields.”

110 Bill Kirton, Gary Wulf, and Bill Henderson, “Thunder Horse Drilling Riser Break—The Road to Recovery” (SPE Paper 

90628, 2004).

111 Simon Todd and Dan Replogle, “Thunder Horse and Atlantis: The Development and Operation of Twin Giants in the 

Deepwater Gulf of Mexico” (OTC Paper 20395, Houston, TX, May 2010).

112 Ibid.

113 Laurel Brubacker Calkins, “BP Sued by Watchdog Group over Atlantis Platform,” Bloomberg, September 13, 2010, 

http://www.bloomberg.com/news/2010-09-10/bp-sued-over-alleged-safety-gaps-at-atlantis-production-platform.html. 

114 Det Norske Veritas, Pipeline Damage Assessment from Hurricane Ivan in the Gulf of Mexico, (Minerals Management 

Service Report No. 440 38570, May 8, 2006). Includes data on damages from hurricanes through 2005.

115 Lesley D. Nixon et al., Deepwater Gulf of Mexico 2009: Interim Report of 2008 Highlights (OCS Report, MMS 2009-

016, 2009), https://www.gomr.mms.gov/homepg/espis/espisfront.asp. 

116 “BP Taps Vast Pool of Crude in Deepest Oil Well,” Associated Press, September 2, 2009; Brett Clanton, “Shell’s Perdido 

First to Produce in Key Deep Water Gulf Region,” Houston Chronicle, March 31, 2010; Brett Clanton, “Chevron 

Plans New Floating City,” Houston Chronicle Energy Watch blog, FuelFix, October 21, 2010, http://fuelfix.com/

energywatch/2010/10/21/chevron-plans-new-floating-city/.

117 Frank Close, Bob McCavitt, and Brian Smith, “Deepwater Gulf of Mexico Development Challenges Overview,” (SPE 

Paper 113011, 2008), 2.

118 Melvyn Whitby, “Design Evolution of a Subsea BOP: Blowout Preventer Requirements Get Tougher as Drilling Goes 

Ever Deeper,” Drilling Contractor (May/June 2007). 

119 Mary C. Boatman and Jennifer Peterson, Oceanic Gas Hydrate Research and Activities Review (OCS Report MMS 
316 National Commission on the BP Deepwater Horizon OIl Spill and Offshore Drilling

2000-017, U.S. Department of Interior, Minerals Management Service, Gulf of Mexico OCS Region, 2000).

120 Fergus Addison, Kevin Kennelley, and Fikry Botros, “Future Challenges for Deepwater Developments” (OTC Paper 

20404, Houston, TX, May 2010).

121 Center for Biological Diversity v. U.S. Department of the Interior, 563 F.3d 466 (D.C. Cir. 2009). 

122 The White House, Office of the Press Secretary, Remarks by the President in a Discussion on Jobs and the Economy 

in Charlotte, North Carolina, April 2, 2010, http://www.whitehouse.gov/the-press-office/remarks-president-adiscussion-jobs-and-economy-charlotte-north-carolina.

123 Gabriel Garcia Marquez, One Hundred Years of Solitude, translated by Gregory Rambassa (New York: Avon Books, 

1970), 212.

Chapter Three

1 Press Release, U.S. Department of the Interior, Salazar Launches Safety and Environmental Protection Reforms to 

Toughen Oversight of Offshore Oil and Gas Operations, May 11, 2010, http://www.doi.gov/news/pressreleases/

Salazar-Launches-Safety-and-Environmental-Protection-Reforms-to-Toughen-Oversight-of-Offshore-Oil-and-GasOperations.cfm.

2 Press Release, U.S. Department of the Interior, Salazar Divides MMS’s Three Conflicting Missions, May 19, 2010, 

http://www.doi.gov/news/pressreleases/Salazar-Divides-MMSs-Three-Conflicting-Missions.cfm; Secretary of 

the Interior, Establishment of the Bureau of Ocean Energy Management, the Bureau of Safety and Environmental 

Enforcement, and the Office of Natural Resources Revenue, No. 3299 (May 19, 2010), http://www.doi.gov/

deepwaterhorizon/loader.cfm?csModule=security/getfile&PageID=32475.

3 Secretary of the Interior, Change of the Name of the Minerals Management Service to the Bureau of Ocean Energy 

Management, Regulation, and Enforcement, No. 3302 (June 18, 2010), http://www.doi.gov/deepwaterhorizon/

loader.cfm?csModule=security/getfile&PageID=35872.

4 42 U.S.C. § 4331(a).

5 U.S. Department of the Interior, “Statement by Secretary of the Interior James Watt Instituting Changes in the 

Mineral Royalty Management Program – July 21, 1982,” Commission on Fiscal Accountability of the Nation’s 

Energy Resources: Subject Files, 1981–1982, RG 48, Entry 994, Box 1 (National Archives and Records Administration, 

Washington, DC).

6 U.S. Constitution, Art IV, § 3, cl. 2.

7 Kleppe v. New Mexico, 426 U.S. 529, 539 (1976), quoting United States v. San Francisco, 310 U.S. 16, 29 (1940). 

8 Utah Power & Light Co. v. United States, 243 U.S. 389, 405 (1917); Kleppe v. New Mexico, 426 U.S. at 540 (“Congress 

exercises the powers of both a proprietor and of a legislature over the public domain.”). 

9 United States v. Midwest Oil, 236 U.S. 459, 466–68, 474–83 (1915). (Upholding authority of the president to 

withdraw unilaterally from private disposition valuable energy resources located on public lands in order to protect 

those resources while Congress considers legislation for their retention in national ownership).

10 Outer Continental Shelf Lands Act, 42 U.S.C. §§ 1331–1356a.

11 E.R. Bartley, The Tidelands Oil Controversy: A Legal and Historical Analysis (Austin: University of Texas Press, 1953); 

Tyler Priest, “Claiming the Coastal Sea: The Battle for the Tidelands, 1937–1953,” History of the Offshore Oil and Gas 

Industry in Southern Louisiana: Vol. 1: Papers on the Evolving Offshore Industry, MMS OCS Study 2004-049 (New 

Orleans: U.S. Department of the Interior, Minerals Management Service, 2008), 67–90, https://www.gomr.mms.

gov/homepg/espis/espisfront.asp. 

12 See United States v. California, 332 U.S. 19, 35 (1947); United States v. Louisiana, 339 U.S. 699 (1950); United 

States v. Texas, 339 U.S. 707 (1950).

13 Priest, “Claiming the Coastal Sea: The Battle for the Tidelands, 1937–1953.” 

14 Other states petitioned for the 9-nautical-mile boundary in the federal courts, but failed to prevail. 

15 “Oil Shelf Bill Enacted; President Reaffirms U.S. Title to Outer Offshore Deposits,” New York Times, August 8, 1953, 

27.

16 Richard Vietor, Energy Policy in America since 1945: A Study of Business-Government Relations (New York: Cambridge University Press, 1984), 19.

17 E.R. Bartley, The Tidelands Oil Controversy: A Legal and Historical Analysis.

18 “Interior Expects Big Things from . . . Offshore Lease Sale,” Oil and Gas Journal, September 13, 1954, 96.

19 Diane Austin et al., History of the Offshore Oil and Gas Industry in Southern Louisiana, Volume 1: Papers on the 

Evolving Offshore Industry, OCS Study MMS 2008-042 (New Orleans: U.S. Department of the Interior, Minerals 

Management Service, September 2008), 97–98, http://www.gomr.boemre.gov/PI/PDFImages/ESPIS/4/4530.pdf.

20 43 U.S.C § 1334. 

21 “Oil and Gas Leases Bow to Rare Wildlife Species,” New York Times, December 9, 1955.
Endnotes 317 317

22 John C. Whitaker, Striking a Balance: Environment and Natural Resources Policy in the Nixon-Ford Years (Washington, D.C.: American Enterprise Institute, 1976), 267–268; Russell Wayland, “The New Federal OCS Regulations in 

the Light of Santa Barbara” (Society of Petroleum Engineers [SPE] Paper 2780, San Francisco, CA, November 1969); 

Richard B. Krahl and David W. Moody, “Gulf Coast Lease Management Inspection Program,” (Offshore Technology 

Conference [OTC] Paper 1714, 1972), 846.

23 National Environmental Policy Act of 1969, 42 U.S.C. § 4321-4370h.

24 Richard J. Lazarus, The Making of Environmental Law, (Chicago: University of Chicago Press, 2004), 70. 

25 42 U.S.C. § 4332(c).

26 Calvert Cliffs Coordinating Committee v. Atomic Energy Commission, 449 F.2d 1109 (D.C. Cir. 1971).

27 National Research Council, Assessment of the U.S. Outer Continental Shelf Environmental Studies Program: III. 

Social and Economic Studies (The National Academies Press: Washington, DC, 1992), http://www.nap.edu/catalog.

php?record_id=2062.

28 U.S. Department of the Interior, Leasing Oil and Natural Gas Resources: Outer Continental Shelf (Washington, D.C.: 

U.S. Department of the Interior, 2005), 12, http://www.boemre.gov/ld/PDFs/GreenBook-LeasingDocument.pdf.

29 Lazarus, The Making of Environmental Law, 70 (listing 18 statutes, and not including several such as the Magnuson 

Fishery Management and Conservation Act of 1976).

30 The five laws included the Public Utility Regulatory Policies Act, Pub. L. No. 95-617, Energy Tax Act, Pub. L. No. 95-

618, National Energy Conservation Policy Act, Pub. L. No. 95-619, Power Plant and Industrial Fuel Use Act, Pub. L. 

No. 95-620, and Natural Gas Policy Act, Pub. L. No. 95-621. 

31 Natural Resources Defense Council v. Morton, 458 F.2d 827 (D.C. Cir. 1972).

32 Outer Continental Shelf Leasing Program: Hearings before the H. Comm. on Appropriations, 93rd Cong., 2d Sess. 

(1974).

33 Outer Continental Shelf Lands Act, Pub. L. No. 95-372, 92 Stat. 629 (1978).

34 43 U.S.C. § 1801.

35 43 U.S.C. § 1802.

36 43 U.S.C. § 1344.

37 43 U.S.C. § 1340.

38 43 U.S.C. § 1351. 

39 43 U.S.C. § 1344(a)(3).

40 43 U.S.C. § 1346.

41 43 U.S.C. § 1347(c).

42 43 U.S.C. § 1347(b).

43 43 U.S.C. § 1347(b)

44 43 U.S.C. § 1351.

45 43 U.S.C. § 1340.

46 43 U.S.C. § 1351(c)(3).

47 43 U.S.C. § 1351(e)(1).

48 43 U.S.C. § 1351(e)(1).

49 43 U.S.C. § 1531(l). 

50 See S. Rep. No. 95-285, at 154–5 (reprinting letter from Secretary of the Interior Cecil Andrus). 

51 See S. Rep. No. 95-285, at 50, 62, 82, 144–5.

52 Robert Gramling, Oil on the Edge: Offshore Development, Conflict, Gridlock (Albany: SUNY Press, 1996), 121. 

53 Charles Babcock, “Watt Defies Critics of Plan for Oil Leases,” Washington Post, July 7, 1981, A3.

54 “Problems with Government,” Ocean Industry (April 1982): 21.

55 Commission on Fiscal Accountability of the Nation’s Energy Resources, Fiscal Accountability of the Nation’s Energy 

Resources (Washington, D.C.: January 1982), xv, http://www.onrr.gov/Laws_R_D/frnotices/PDFDocs/linowesrpt1-5.pdf.

56 Don E. Kash, Lease Management Activities in the Geological Survey, Commission on Fiscal Accountability of the Nation’s Energy Resources: Technical Reports, 1981–1982, RG 48, Entry 998, Box 10, File 239, National Archives and 

Records Administration, 8, 9, 27.

57 “Industry Warning Watt Against Transfer of BLM Leasing Functions to MMS,” Inside Energy/with Federal Lands, 

November 1, 1982, 11. 
318 National Commission on the BP Deepwater Horizon OIl Spill and Offshore Drilling

58 G. Kevin Jones, “Outer Continental Shelf Oil and Gas Development During the Reagan Administration—Part 1,” Western New England Law Review 12, 1, (1990):8–13. 

59 “Interior Denies Oil Leasing Plan Will Cost $77 Billion,” Associated Press, September 28, 1982.

60 43 U.S.C. § 1337.

61 Charles Lester, “Contemporary Federalism and New Regimes of Ocean Governance: Lessons from the Case of Outer 

Continental Shelf Oil Development,” Ocean & Coastal Management 23 (1994), 14.

62 National Research Council Committee on Marine Area Governance and Management, Striking a Balance: Improving 

Stewardship of Marine Areas (Washington, D.C.: National Academy of Sciences, 1997), 37, http://www.nap.edu/

openbook.php?record_id=5797&page=37. 

63 President George H.W. Bush, “Statement on Outer Continental Shelf Oil and Gas Development,” (June 26, 1990), 

http://bushlibrary.tamu.edu/research/public_papers.php?id=2035&year=1990&month=6.

64 30 C.F.R. pt. 250.

65 U.S. Department of the Interior, Documents pertaining to offshore inspection types and practices produced to the Oil 

Spill Commission, August 2010.

66 Jan Erik Vinnem, Offshore Risk Assessment: Principles, Modelling and Applications of QRA Studies, 2nd ed. (London: 

Springer Studies in Reliability Engineering, 2007), 91, 100, 102.

67 Petroleum Safety Authority of Norway, “From Prescription to Performance in Petroleum Supervision,” March 12, 

2010, http://www.ptil.no/news/from-prescription-to-performance-in-petroleum-supervision-article6696-79.html.

68 Magne Ognedal, interview with Commission staff, November 10, 2010. 

69 E.P. Danenberger et al., Investigation of March 19, 1989 Fire, South Pass Block 60 Platform B, Lease OCS-G 1608, 

OCS Report MMS 90-0016 (New Orleans: U.S. Department of the Interior, Minerals Management Service, April 

1990): 15, http://www.gomr.boemre.gov/PDFs/1990/90-0016.pdf.

70 Marine Board of the National Research Council Committee on Alternatives for Inspection of Outer Continental Shelf 

Operations, Alternatives for Inspecting Outer Continental Shelf Operations (Washington: National Academy Press, 

1990): 3, http://www.nap.edu/openbook.php?record_id=1517&page=1.

71 Minerals Management Service, Final Report, Findings and Recommendations, MMS Task Force on OCS Inspection and 

Enforcement (Washington, D.C.: U.S. Department of the Interior, Minerals Management Service, February 1990), 

1-3. 

72 Marine Board, Alternatives for Inspecting Outer Continental Shelf Operations, 80. 

73 Ibid., 82. 

74 Exec. Order No. 12,777, 56 Fed. Reg. 54,757 (October 22, 1991). 

75 E.P. Danenberger, “Changes in the Minerals Management Service Offshore Regulatory Programs Resulting From the 

Oil Pollution Act of 1990” (Offshore Technology Conference [OTC] Paper 6823, May 1992), 150.

76 Oil and Gas and Sulphur Operations in the Outer Continental Shelf, 56 Fed. Reg. 30,400 (July 2, 1991).

77 Ibid.

78 Salient differences were, as MMS noted, that “Platforms in the GOM are typically smaller, technically less sophisticated, produce fewer hydrocarbons, and operate in less severe environmental conditions [than North Sea platforms]. 

The number of personnel on OCS platforms is significantly smaller than on North Sea platforms. There is, however, 

a substantially greater number of OCS platforms in the GOM, over 3,800.” Marshall Courtois, William Hauser, and 

Paul Schneider, “Minerals Management Service Safety and Environmental Management Program: Evolution of the 

Concept,” (Offshore Technology Conference [OTC] Paper 6822, May 1992), 145. 

79 Oil and Gas and Sulphur Operations in the Outer Continental Shelf, 56 Fed. Reg. 30,400 (July 2, 1991).

80 Former senior MMS officials, interviews with Commission staff, August and September 2010; Offshore Operators 

Committee, “Oil, Gas, and Sulphur Operations in the Outer Continental Shelf (OCS)—Safety and Environmental 

Management Systems,” Public Comment (May 22, 2006), http://www.boemre.gov/federalregister/PDFs/AD15-

OOCcomments5-22-06.pdf. 

81 T.A.F. Powell, “US Voluntary SEMP Initiative: Holy Grail or Poisoned Chalice?” (Offshore Technology Conference [OTC] 

Paper 8111, May 1996): 828.

82 E.O. Redd, Jean Chevallier, and Ian Paterson, “Preparing a Safety Case: A Drilling Contractor’s Experience” (Society of 

Petroleum Engineers [SPE] Paper 27293, January 1994): 799.

83 L.D. Easley, J.E. Stark, and R.A. Bradford, “Implementing API RP 75 ‘Recommended Practice for Development of a 

Safety and Environmental Program for Outer Continental Shelf (OCS) Operations and Facilities’” (Offshore Technology Conference [OTC] Paper 7384, May 1994): 130.

84 American Petroleum Institute, Recommended Practices for Development of a Safety and Environmental Management 

Program for Outer Continental Shelf (OCS) Operations and Facilities, Recommended Practice 75, 1st ed. (Dallas, TX: 

May 15, 1993).

85 Oil and Gas and Sulphur Operations in the Outer Continental Shelf, 59 Fed. Reg. 33,779 (June 30, 1994).
Endnotes 319 319

86 Safety and Environmental Management Program (SEMP) on the Outer Continental Shelf (OCS), 61 Fed. Reg. 37,493 

(July 18, 1996).

87 Ibid.

88 Patrick Crow, “New slant on safety,” Oil & Gas Journal (July 22, 1996): 23.

89 TA.F Powell, “US Voluntary SEMP Initiative: Holy Grail or Poisoned Chalice?” (Offshore Technology Conference [OTC] 

Paper 8111, 1996).

90 E.P. Danenberger, interview with Commission staff, September 2, 2010; E.P. Danenberger, e-mail message to Commission staff, October 25, 2010.

91 Oil and Gas and Sulphur Operations in the Outer Continental Shelf–Incident Reporting Requirements, 68 Fed. Reg. 

40,585 (July 8, 2003).

92 E.P. Danenberger, interview with Commission staff, September 2, 2010; E.P. Danenberger, e-mail message to Commission staff, October 25, 2010.

93 Oil and Gas and Sulphur Operations in the Outer Continental Shelf—Incident Reporting Requirements, 71 Fed. Reg. 

19,640 (April 17, 2006).

94 Commission staff analysis of Bureau of Ocean Energy Management, Regulation and Enforcement data. See http://

www.boemre.gov/adm/budget.html.

95 Jim Morris, “Lost at Sea/OFFSHORE RISKS/Safety concerns return with rise of oil, gas boom,” Houston Chronicle, 

December 22, 1996, http://www.chron.com/CDA/archives/archive.mpl?id=1996_1384981.

96 Commission staff analysis of Bureau of Ocean Energy Management, Regulation and Enforcement data. See http://

www.gomr.boemre.gov/homepg/fastfacts/WaterDepth/wdmaster.asp.

97 Commission staff analysis of Bureau of Ocean Energy Management, Regulation and Enforcement data; Minerals 

Management Service, U.S. Offshore Milestones (as of August 2006): 5. See http://www.boemre.gov/stats/PDFs/

milestonesAUG2006.pdf. 

98 Commission staff analysis of Bureau of Ocean Energy Management, Regulation and Enforcement and U.S. Energy Information Administration data. See http://www.gomr.boemre.gov/PDFs/2009/2009-016.pdf, 71–72; http://www.

eia.gov/oog/info/twip/twiparch/100526/twipprint.html.

99 Commission staff analysis of MMS yearly budget request and enactments, by nominal and real (2005) dollars.

100 Tetrahedron, Inc., Reliability of Blowout Preventers Tested Under Fourteen and Seven Days Time Interval: Study 

Report, Submitted to Minerals Management Service, Department of the Interior, MMS Technology Assessment & 

Research Project 253, “Blowout Preventer Study” (December 20, 1996), http://www.boemre.gov/tarprojects/253/

AA.PDF.; Blowout Preventer (BOP) Testing Requirements for Drilling and Completion Operations, 63 Fed. Reg. 

29,604 (June 1, 1998).

101 Per Holand, Reliability of Subsea BOP Systems for Deepwater Application, Phase II DW, SINTEF Report STF38 

A99426 (November 7, 1999); Per Holand, Deepwater Kicks and BOP Performance, SINTEF Report STF38 A01419 

(July 24, 2001); WEST Engineering Services, Inc., Mini Shear Study for U.S. Minerals Management Service, Requisition No. 2-1011-1003 (December 2002); WEST Engineering Services, Inc., Shear Ram Capabilities Study for U.S. 

Minerals Management Service, Requisition No. 3-4025-1001 (September 2004).

102 WEST Engineering Services, Inc., “Comments by WEST Engineering Services, Houston, Texas, to The National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling” (November 12, 2010): 3.

103 David Barstow and others, “Regulators Failed to Address Risks in Oil Rig Fail-Safe Device,” New York Times, June 20, 

2010, www.nytimes.com/2010/06/21/us/21blowout.html.

104 U.S. Department of the Interior, Outer Continental Shelf Safety Oversight Board, Report to the Secretary of the 

Interior (September 1, 2010), 6.

105 Ibid.

106 Ibid.

107 U.S. Department of the Interior, Office of Inspector General, Survey Report: Offshore Civil Penalties Program, Minerals Management Service (March 30, 1999), http://www.doioig.gov/images/stories/reports/pdf/99-I-374.pdf.

108 Commission staff analysis of Bureau of Ocean Energy Management, Regulation and Enforcement data provided to 

the Commission by the Department of the Interior of unannounced MMS inspections of MODUs/drilling rigs, 1990 

(1,985 inspections) to 2009 (85 inspections). The pivotal change occurs in 1998–1999, as the numbers drop from 

864 to 41 in the span of one year. 

109 Yearly MMS Incident Summary Reports are available at http://www.boemre.gov/incidents/IncidentStatisticsSummaries.htm. 

110 “Deepwater Gulf of Mexico production rising,” Oil & Gas Journal (November 1, 1999): 34 (“In 1999, 11 more 

deepwater development production projects in the gulf have already begun producing or are on the verge of doing 

so”); Michael Davis, “LEARNING THE DRILL/The oil patch rebound brought with it a need for drilling companies 

to find, train and keep people to work the rigs,” Houston Chronicle (February 1, 1998): 1 (“A shortage of qualified 

personnel has been a nagging problem since the oil patch has come back in the past year. But over the next two 

years some 50 new offshore jack-up rigs, semi-submersibles and drill ships currently being built or converted will 
320 National Commission on the BP Deepwater Horizon OIl Spill and Offshore Drilling

go into operation. Finding qualified crews to operate these increasingly high tech drilling rigs is a major worry for 

drilling companies.”). 

111 33 C.F.R. § 140.1.

112 46 C.F.R. pt. 2.

113 Curry L. Hagerty and Jonathan L. Ramseur, Deepwater Horizon Oil Spill: Selected Issues for Congress, (Washington, D.C.: Congressional Research Service, July 15, 2010): 37. The Coast Guard proposed new safety rules in 1999, 

which triggered significant industry opposition, and has not since made those rules final. Outer Continental Shelf 

Activities, Notice of Proposed Rulemaking, 64 Fed. Reg. 68,416 (December 7, 1999). 

114 Inspection Under, and Enforcement of, Coast Guard Regulations for Fixed Facilities on the Outer Continental Shelf by 

the Minerals Management Service, 67 Fed. Reg. 5912 (February 7, 2002).

115 The MMS and the United States Coast Guard have signed three governing Memoranda of Understanding (in 1989, 

1999, and 2004, with supporting Memoranda of Agreement) in order to clarify roles and responsibilities related to 

workplace safety and the approval of technical systems and equipment that are applicable to both drilling and marine systems on offshore oil and gas facilities. See http://www.boemre.gov/regcompliance/MOU/MOUindex.htm. 

116 S. Elizabeth Birnbaum, interview with Commission staff, August 2010; Randall B. Luthi, interview with Commission staff, August 2010; Thomas R. Kitsos, interview with Commission staff, August 2010. 

117 Deepwater Royalty Relief Act of 1995, Pub. L. 104-58, 109 Stat. 563 (1995).

118 Press Release, U.S. Department of the Interior, Secretary Salazar Launches Ethics Reform Initiative in Meeting 

with Minerals Management Service Employees, January 29, 2009, http://www.doi.gov/news/pressreleases/2009_01_29_release.cfm.

119 For example, in 2006, Congress responded to Gulf state demands for greater revenues by enacting the Gulf of 

Mexico Energy Security Act, which provides that Alabama, Louisiana, Mississippi, and Texas and the coastal political 

subdivisions will receive 37.5 percent of all revenue (bonus bids, rentals, and royalty production) for new leases in 

the 5 million acres in the Eastern Gulf and the 5.8 million acres in the Central Gulf. See http://www.boemre.gov/

ooc/press/2008/FactSheet-MMSGOMSecurityActMARCH202008.htm. The Fiscal Year 2010 allocation to the four 

Gulf States and their political subdivisions was approximately $866 million. See http://www.boemre.gov/offshore/

PDFs/GOMESAFY2010Final.pdf. 

120 U.S. Department of the Interior, Outer Continental Shelf Safety Oversight Board, Report to the Secretary of the 

Interior (September 1, 2010), 11.

121 U.S. Department of the Interior, Office of the Inspector General, MMS Oil Marketing Group–Lakewood, September 

10, 2008.

122 U.S. Department of the Interior, Office of the Inspector General, MMS Oil Marketing Group–Lakewood, Report 

Transmittal Letter, September 9, 2008, 3, http://www.doioig.gov/images/stories/reports/pdf/RIKinvestigation.pdf.

123 Department of the Interior Office of the Inspector General, Minerals Management Service, Island Operating Company, et al., (May 25, 2010), 7, http://www.doioig.gov/images/stories/reports/pdf/IslandOperatingCo.pdf.

124 Ibid.

125 Press Release, U.S. Department of the Interior, Secretary Salazar Launches Ethics Reform Initiative in Meeting 

with Minerals Management Service Employees, January 29, 2009, http://www.doi.gov/news/pressreleases/2009_01_29_release.cfm.

126 U.S. Department of the Interior, Outer Continental Shelf Safety Oversight Board, Report to the Secretary of the 

Interior (September 1, 2010), 8.

127 Ibid., 13.

128 Ibid., 8, 13.

129 Ibid., 13.

130 Ibid., 6.

131 Don E. Kash, Lease Management Activities in the Geological Survey, Commission on Fiscal Accountability of the Nation’s Energy Resources: Technical Reports, 1981–1982, RG 48, Entry 998, Box 10, File 239, National Archives and 

Records Administration, 27.

132 U.S. Department of the Interior, Outer Continental Shelf Safety Oversight Board, Report to the Secretary of the 

Interior (September 1, 2010), 11–12.

133 Ibid., 11.

134 43 U.S.C. § 1344.

135 43 U.S.C. § 1344.

136 43 U.S.C. § 1344(a)(3). 

137 42 U.S.C. § 4332.

138 40 C.F.R. § 1508.8 (“Effects includes ecological . . ., aesthetic, historic, cultural, economic, social, or health, whether 

direct, indirect, or cumulative”). 
Endnotes 321 32

139 16 U.S.C. §§ 1801-1891d.

140 16 U.S.C. §§ 1531-1544.

141 16 U.S.C. §§ 1361-1423h.

142 16 U.S.C. §§ 1431-1445c-1.

143 33 U.S.C. §§ 1251-1387.

144 33 U.S.C. §§ 2701-2762.

145 Exec. Order No. 12,777, 56 Fed. Reg. 54,757 (October 22, 1991).

146 43 U.S.C. §1344.

147 43 U.S.C. §1340(c)(1).

148 It appears to be understood that the meaning of this language is that an environmental impact statement is not 

required for the Gulf of Mexico, but it should be pointed out that is not the compelled or obvious reading of the 

language. The provision can also be fairly read to say no more than at least one impact statement has to be prepared 

for areas outside the Gulf and not address the issue, one way or another, concerning the application of NEPA within 

the Gulf. That potentially significant nuance, however, is beyond the scope of this report’s inquiry. 

149 National Environmental Policy Act; Revised Implementing Procedures, 45 Fed. Reg. 75336 (proposed Nov. 14, 1980) 

(proposed NEPA rules); National Environmental Policy Act; Revised Implementing Procedures, 46 Fed. Reg. 7485 

(Jan. 23, 1981) (final NEPA rules); see 516 Departmental Manual, 2.3.A(2) (1980). 

150 43 C.F.R. § 46.215

151 U.S. Department of the Interior, Outer Continental Shelf Safety Oversight Board, Report to the Secretary of the 

Interior (September 1, 2010), 20.

152 Ibid.

153 516 Departmental Manual 15.4.C (providing for exceptions from categorical exclusion in certain “extraordinary 

circumstances,” including when there are highly uncertain and potentially significant environmental effects). 

154 51 Fed. Reg. 15,624 (1986).

155 NOAA Fisheries Service, Southeast Regional Office, letter to MMS dated July 1, 1999 (subsequently updated in 2006, 

2007, and 2008).

156 Essential Fish Habitat Assessment for the Minerals Management Service Programmatic Consultation for Gulf of 

Mexico Outer Continental Shelf (OCS) Oil and Gas Activities (June 4, 1999). 

157 NOAA Fisheries Service, Southeast Regional Office, letter to MMS dated July 1, 1999 (subsequently updated in 2006, 

2007, and 2008). 

158 30 C.F.R. § 254.21.

159 30 C.F.R. § 254.23.

160 The Response Group on behalf of ExxonMobil, Gulf of Mexico Regional Oil Spill Response Plan (August 2009), Rev. 

5; The Response Group on behalf of ConocoPhillips, Gulf of Mexico Regional Oil Spill Response Plan (April 2010), 

Rev. 6; The Response Group on behalf of Chevron, Gulf of Mexico Regional Oil Spill Response Plan (February 2010), 

Version 3; The Response Group on behalf of Shell Offshore Inc., Gulf of Mexico Regional Oil Spill Response Plan, 

(June 2010), Rev. 6.1. 

161 The Response Group on behalf of BP, Regional Oil Spill Response Plan-Gulf of Mexico (June 30, 2009), App. H: 5, 17, 

and 32.

Chapter Four

1 John Guide (BP), interview with Commission staff, September 17, 2010. 

2 Internal Transocean document (TRN-HEC 90686). Internal documents are identified by their document production 

serial numbers when available, which were assigned by the entity that provided them.

3 Internal BP document (BP-HZN-MBI 126338).

4 Internal Transocean document (TRN-USCG-MMS 11597).

5 Internal BP document (BP-HZN-MBI 126338).

6 Ibid.

7 Ibid. Three companies own the Macondo well. BP has a 65 percent share, Anadarko Petroleum Corporation has a 25 

percent share, and MOEX Offshore has a 10 percent share. BP maintained regular contact with Anadarko and MOEX 

throughout the drilling of the well. 
322 National Commission on the BP Deepwater Horizon OIl Spill and Offshore Drilling

8 Internal Transocean documents (TRN-USCG-MMS 11600, 11605, 11609, 11613, 11617, 11621, 11625). 

9 Brett Clanton, “New tactic might seal leaking well sooner, BP CEO says,” Houston Chronicle, May 5, 2010.

10 Gregory Walz (BP), interview with Commission staff, October 6, 2010. 

11 Testimony of Gregory Walz, Hearing before the Deepwater Horizon Joint Investigation Team, October 7, 2010, 

157–59.

12 Internal BP document (BP-HZN-MBI 143300) (emphasis added).

13 Internal BP documents (BP-HZN-MBI 136937, 136941). 

14 Internal BP document (BP-HZN-CEC 8848-58).

15 Internal BP document (BP-HZN-MBI 129238-39).

16 Guide, interview. Indeed, just days before the running of the long string at Macondo, another well drilled by Transocean’s DD3 suffered just such a complication. Ibid. 

17 Testimony of Jesse Gagliano, Hearing before the Deepwater Horizon Joint Investigation Team, August 24, 2010, 320.

18 Internal BP document (BP-HZN-CEC 22433). Walz also noted that the flight carrying centralizers would not increase 

costs. Ibid.

19 Guide, interview. BP had special one-piece bolt-on centralizers made for the Thunder Horse project. Ibid. 

20 Internal BP document (BP-HZN-MBI 128379).

21 Internal BP document (BP-HZN-CEC 22669).

22 Internal BP document (BP-HZN-CEC 22433).

23 Testimony of Steve Lewis, Hearing before the National Commission, November 9, 2010, 93–94; Internal BP document 

(BP-HZN-MBI 129226). Prior to conversion, a small ball drops from the top of the float valves to block the main path 

through the auto-fill tube, leaving only two small holes on the side of the tube through which mud can flow. Ibid. 

24 The Well Site Leaders—Bob Kaluza and Don Vidrine—would normally have been on the rig. Morel, a relatively junior 

BP engineer, had flown to the rig out of a professional interest in learning more about the cementing process. Guide, 

interview. 

25 Bryan Clawson (Weatherford), interview with Commission staff, October 28, 2010; BP, Deepwater Horizon Accident 

Investigation Report (September 8, 2010), 70.

26 Testimony of Steve Lewis, 96; Internal Transocean document (TRN-USCG_MMS 11638). 

27 Internal BP document (BP-HZN-MBI 137367). 

28 Ibid.; Testimony of Nathaniel Chaisson, Hearing before the Deepwater Horizon Joint Investigation Team, August 24, 

2010, 432.

29 Internal BP documents (BP-HZN-MBI 137367, 21304). Since the incident, BP has argued that the M-I SWACO models 

predicted an erroneously high circulation pressure, and that the readings the crew observed were proper. This may 

ultimately explain the readings, but it does not explain why the BP Macondo team dismissed them as the result of a 

broken pressure gauge. 

30 David Izon, E.P. Danenberger, and Melinda Mayes, “Absence of fatalities in blowouts encouraging in MMS study of 

OCS incidents 1992-2006,” Well Control July/August (2007), 84. 

31 Testimony of John Guide, Hearing before the Deepwater Horizon Joint Investigation Team, July 22, 2010, 87.

32 John Gisclair, Sperry Sun data, April 20, 2010 (annotations, September 20, 2010). Commission calculation based on 

internal Halliburton document (HAL_10994).

33 Internal BP document (BP-HZN-MBI 127537-39); Internal Halliburton document (HAL_11196).

34 30 C.F.R. § 250.421.

35 Internal BP document (BP-HZN-MBI 193549). BP’s internal guidelines further specify that centralization should 

extend 100 feet above any such hydrocarbon-bearing zones. If either the top of cement or centralization requirements 

are not met, the guidelines require that the actual top of cement should be confirmed by a “proven cement evaluation 

technique.” Ibid. 

36 Internal BP documents (BP-HZN-MBI 143295, BP-HZN-CEC 22663); BP, Deepwater Horizon Accident Investigation 

Report, 34.

37 Document provided to the Commission by Halliburton entitled “Halliburton GoM Foam Jobs 2002–2010.”

38 S.L. Pickett and S.W. Cole, “Foamed Cementing Technique for Liners Yields Cost-Effective Results” (Society of Petroleum Engineers SPE Paper #27679, Midland, Texas, March 1994), 523–24. 

39 Halliburton had delivered the slurry blend to the Deepwater Horizon several months earlier. It had developed the blend 

to match the temperature and pressure profile of the well that Deepwater Horizon had drilled immediately prior to 

Macondo—another BP well called Kodiak. Jesse Gagliano (Halliburton), interview with Commission staff, September 

10, 2010. 
Endnotes 323 323

40 At this point, it appears that lab personnel replicated the dry blend recipe that was on the rig using off-the-shelf materials from their lab. For later tests, Halliburton sent samples of the cement that was actually on the Horizon back to 

the lab and directly tested those materials. 

41 Internal BP document (BP-HZN-MBI 109218).

42 Internal Halliburton document (HAL_DOJ 68).

43 Internal Halliburton document (HAL_DOJ 36).

44 Internal Halliburton document (HAL_DOJ 43).

45 Ibid.

46 Internal BP document (BP-HZN-MBI 136946-47).

47 Internal BP document (BP-HZN-MBI 171151).

48 Internal BP document (BP-HZN-MBI 136946-47).

49 Internal BP document (BP-HZN-CEC 20234).

50 Ibid.

51 Testimony of Vincent Tabler, Hearing before the Deepwater Horizon Joint Investigation Team, August 25, 2010, 

22–23, 36. 

52 Internal Halliburton document (HAL_0011208).

53 Internal BP document (BP-HZN-MBI 137370).

54 Internal BP document (BP-HZN-MBI 129141).

55 Internal Transocean document (TRN-USCG_MMS 30422); Internal Schlumberger document (SLB-EC-2).

56 Testimony of John Guide, 44–45. 

57 Internal BP document (BP-HZN-MBI 143304).

58 Testimony of John Guide, 298 (the cement plug was “deeper than normal”); Testimony of Ronald Sepulvado, Hearing 

before the Deepwater Horizon Joint Investigation Team, July 20, 2010, 145 (“the top of the surface plug is normally 

at 500 feet below the wellhead”).

59 Internal BP document (BP-HZN-CEC 8574).

60 Testimony of Jimmy Harrell, Hearing before the Deepwater Horizon Joint Investigation Team, May 27, 2010, 118.

61 Internal BP document (BP-HZN-CEC 8574).

62 Internal BP document (BP-HZN-CEC 21260-279).

63 Internal BP document (BP-HZN-MBI 126928). 

64 Internal BP document (BP-HZN-OSC 1438).

65 30 C.F.R. § 250.423.

66 The blind shear rams closed and sealed as expected during the positive-pressure test. This fact suggests that the rams 

were capable of sealing the well when the blowout occurred. But the evidence is inconclusive on its own; during the 

positive-pressure test the crew closed the blind shear rams using a low pressure hydraulic system, rather than the 

high pressure hydraulic system that would have activated the rams in the event of a blowout. 

67 Internal Transocean document (TRN-HCEC 90).

68 Testimony of Patrick O’Bryan, Hearing before the Deepwater Horizon Joint Investigation Team, August 26, 2010, 

360.

69 Testimony of David Sims, Hearing before the Deepwater Horizon Joint Investigation Team, August 26, 2010, 204. 

There were no regulations or industry standards guiding the conduct or interpretation of negative-pressure tests at 

the time of the Macondo blowout. The absence of any such guidance may have contributed to the failure to conduct 

and interpret the test correctly here. 

70 This calculation is based on approximate values of the depths and mud weights involved. 

71 Testimony of Leo Lindner, Hearing before the Deepwater Horizon Joint Investigation Team, July 19, 2010, 297; BP, 

Deepwater Horizon Accident Investigation Report, app. Q, 1. 

72 BP, Deepwater Horizon Accident Investigation Report, 83. 

73 Testimony of Leo Lindner, 308–11. The exclusion for “[d]rilling fluids, produced waters, and other wastes associated 

with the exploration, development, or production of crude oil, natural gas or geothermal energy” is found at 40 

C.F.R. § 261.4. 

74 Testimony of Leo Lindner, 276–79, 297, 359–60; Internal BP document (BP-HZN-BLY 47100).

75 Testimony of Randy Ezell, Hearing before the Deepwater Horizon Joint Investigation Team, May 28, 2010, 279–81.

76 Testimony of Daun Winslow, Hearing before the Deepwater Horizon Joint Investigation Team, August 24, 2010, 219; 
324 National Commission on the BP Deepwater Horizon OIl Spill and Offshore Drilling

Testimony of Randy Ezell, 279.

77 Testimony of Randy Ezell, 279.

78 Testimony of Lee Lambert, Hearing before the Deepwater Horizon Joint Investigation Team, July 20, 2010, 292. 

Transocean disputes these accounts. It points out that the only individuals who have stated that Anderson advanced 

the “bladder effect” theory are BP employees. 

79 Testimony of Lee Lambert, 292.

80 Testimony of Jimmy Harrell, 117; Internal BP documents (BP-HZN-MBI 127909, BP-HZN-CEC 20189-90). While 

that may have been Mr. Vidrine’s stated reason for running the test on the kill line, the Commission notes that the 

negative-pressure test performed at Macondo—whether on the drill pipe or kill line—was different from the negativepressure test described in the Application for Permit to Modify. Testimony of Mark Bly, Hearing before the National 

Commission, November 8, 2010, 293–95.

81 BP, Deepwater Horizon Accident Investigation Report, 86.

82 There are several possible explanations for the inconsistent readings on the drill pipe and kill line. One possibility is 

that the viscous spacer that had leaked through the annular preventer migrated into and clogged the kill line. John 

Smith, Review of Operational Data Preceding Explosion on Deepwater Horizon in MC252 (July 1, 2010), 20–21. 

Another possibility is that a valve was inadvertently closed that should have been open. BP, Deepwater Horizon Accident Investigation Report, 87. A third, more remote, possibility is that hydrocarbons coming up the well formed solid 

hydrates when they hit the cold seawater and those hydrates clogged the kill line. Guide, interview. 

83 Testimony of Christopher Haire, Hearing before the Deepwater Horizon Joint Investigation Team, May 28, 2010, 247. 

84 For example, a bubble of gas, under ideal conditions, would expand approximately 166-fold. This number differs 

under actual conditions based on fluid properties and flow. 

85 Mudloggers operate systems that collect and transmit real-time data from sensors on the rig. BP employed mudloggers from Sperry Drilling (a Halliburton subsidiary) on the Deepwater Horizon. 

86 The driller first sent mud to pits 9 and 10, then switched to pit 7, and then switched to pit 6. Sperry Sun data, April 

20, 2010, 20:10–21:18. 

87 Ibid., 20:28–20:36, 20:58–21:06.

88 Ibid., 20:20–21:01.

89 Ibid., 21:01.

90 Ibid., 21:01–21:08.

91 The Commission believes, based on interviews of the mudloggers on the Horizon, that the Hitec system may have 

shown a more obvious trend because it displays numeric values as opposed to trend lines such as those seen in the 

Sperry data shown in the text. Joseph Keith (Sperry), interview with Commission staff, October 6, 2010; Cathleenia 

Willis (Sperry), interview with Commission staff, October 21, 2010. 

92 Testimony of Greg Meche, Hearing before the Deepwater Horizon Joint Investigation Team, May 28, 2010, 207–09. 

93 40 C.F.R. §§ 261.4, 435.11.

94 Testimony of Greg Meche, 207–09, 219.

95 Keith, interview. 

96 Internal BP document (BP-HZN-MBI 21415).

97 Keith, interview. Given what we now know, it is all but impossible that the well was not flowing as of 9:08 p.m. 

BP, Deepwater Horizon Accident Investigation Report, 25; Smith, Review of Operational Data Preceding Explosion on 

Deepwater Horizon, 22–23. Other than faulty memory, the only apparent explanations for Mr. Keith’s statement are 

that the crew had already closed off the portion of the flow line Mr. Keith was watching or that Mr. Keith watched 

for an inadequate period of time. Keith, interview; Darryl Bourgoyne (LSU), interview with Commission staff, November 23, 2010. 

98 Testimony of Greg Meche, 207–09.

99 Ibid.

100 Internal BP document (BP-HZN-MBI 21415).

101 Sperry Sun data, April 20, 2010, 21:08–21:14.

102 Ibid., 21:14–21:15.

103 Ibid., 2010, 21:17–21:18.

104 Testimony of Chad Murray, Hearing before the Deepwater Horizon Joint Investigation Team, May 27, 2010, 

335–36. 

105 Ibid., 336.

106 Testimony of Randy Ezell, 282. 

107 Testimony of Bill Ambrose, Hearing before the National Commission, November 8, 2010, 381. 
Endnotes 325 325

108 David Young (Transocean), interview with Commission staff, November 19, 2010.

109 Testimony of David Young, Hearing before the Deepwater Horizon Joint Investigation Team, May 27, 2010, 259. 

110 Young, interview. 

111 Sperry Sun data, April 20, 2010, 21:08–21:14.

112 Bill Ambrose (Transocean), interview with Commission staff, September 21, 2010.

113 Sperry Sun data, April 20, 2010, 21:38.

114 Young, interview. 

115 Sperry Sun data, April 20, 2010, 21:38–21:42.

116 Testimony of Randy Ezell, 283; Young, interview. 

117 Testimony of Micah Sandell, Hearing before the Deepwater Horizon Joint Investigation Team, May 29, 2010, 10. 

118 Testimony of Christopher Pleasant, Hearing before the Deepwater Horizon Joint Investigation Team, May 28, 2010, 

173.

119 Testimony of Randy Ezell, 283. 

120 Testimony of Bill Ambrose, 244. 

121 Smith, Review of Operational Data Preceding Explosion on Deepwater Horizon, 14; Testimony of Bill Ambrose, 

252–53; BP, Deepwater Horizon Accident Investigation Report, 28.

122 Testimony of Christopher Pleasant, 165.

123 Ibid., 123.

124 Ibid.

125 Various parties have suggested other causes for the deadman’s failure, including leaks, overdue equipment certification, and improper modifications. 

126 Interview with industry expert, September 24, 2010. 

127 After the blowout, some industry CEOs testified they would never have used a long string production casing, suggesting there was a causal connection between BP’s choice of the long string and the blowout. Hearing Before the 

Subcomm. on Energy and Environment, 111th Cong. 104 (June 15, 2010) (statements of John Watson, Chairman 

and Chief Executive Officer, Chevron Corporation; and Rex Tillerson, Chairman and Chief Executive Officer, ExxonMobil). 

128 First, the long string required the cement to travel through a longer stretch of steel casing—roughly 12,000 feet longer—before reaching its final destination, potentially increasing the risk of cement contamination. Second, because it 

can require higher cement pumping pressure, a long string design can lead to the selection of lower cement volumes, 

lower densities, and lower pump rates. Third, the cement job at the bottom of a long string is more difficult to 

remediate than one at the bottom of a liner. 

129 Internal BP document (BP-HZN-MBI 128489); BP, Deepwater Horizon Accident Investigation Report, 64 (“the BP 

Macondo well team did not ask for the OptiCem model to be re-run”). This may have been because of Mr. Guide’s 

distrust of the OptiCem model. Testimony of John Guide, 275 (“it’s wrong a lot”). When Halliburton rig personnel 

eventually informed Gagliano of BP’s decision themselves, he responded by e-mailing BP modeling data suggesting 

again that more centralizers would be needed to prevent channeling. Internal BP document (BP-HZN-MBI 128708). 

130 Testimony of Jesse Gagliano, 259; Testimony of Nathaniel Chaisson, 415. 

131 BP, Deepwater Horizon Accident Investigation Report, 35. Mr. Guide disagreed with the BP report’s conclusion in an 

interview with Commission staff. Guide, interview. 

132 Internal BP document (BP-HZN-CEC 22670). 

133 Ronald Sepulvado (BP), interview with Commission staff, September 1, 2010. 

134 BP, Deepwater Horizon Accident Investigation Report, 66.

135 Fred Bartlit, letter to the National Commission, October 28, 2010 (reporting the results of cement testing).

136 If BP were looking, the one February test actually reported to BP could have prompted BP to question the design 

as well. BP argues that its failure to do so here is understandable given that it had hired one of the world’s leading 

cementers specifically for purposes of designing and testing the cement slurry. 

137 To the contrary, Halliburton’s selection of conditioning time appears to have been haphazard at best. Lab personnel used different conditioning times (ranging from zero conditioning time to three hours) in each of the four foam 

stability tests that they conducted. 

138 Internal Halliburton document (HAL_DOJ 43). 

139 Testimony of Daun Winslow, 209; Guide, interview.

140 Moreover, once the BP Well Site Leaders and crew realized that the annular preventer was leaking, they should have 

circulated out any spacer that had migrated below the annular preventer prior to continuing with the test. Testi-
326 National Commission on the BP Deepwater Horizon OIl Spill and Offshore Drilling

mony of John Smith, Hearing before the National Commission, November 9, 2010, 140–41. 

141 The Commission agrees with others that there is no such thing as a “bladder effect” that could account for the pressures the rig crew was observing. There was no apparent explanation for the 1400 psi on the drill pipe other than 

that the well was flowing. 

142 Transocean asserts that its personnel, including the driller and toolpusher, were not “in any way responsible for 

interpreting the negative pressure test or making the decision that the well was secure and work could properly proceed.” Rachel Clingman, letter to Commission staff, November 16, 2010, 1. As the Commission’s staff made clear at 

the November 8, 2010 hearing, the Commission is not tasked with deciding legal responsibility. Based on available 

evidence, however, Revette and Anderson agreed the negative-pressure test was a success and did not stop the job 

before moving on to the remaining temporary abandonment procedures. Testimony of Lee Lambert, 291; Internal 

BP documents (BP-HZN-CEC 20347, 20178).

143 Guide, interview.

144 Benjamin Powell, “BP Response to Presidential Commission’s Preliminary Technical Conclusions,” letter to Commission staff, November 22, 2010, att. 1, 3 (citing Hearing Before the Senate Comm. on Energy and Natural Resources, 

111th Cong. (May 11, 2010) (statement of Testimony of Tim Probert, Halliburton President, Global Business Lines, 

Chief Health, Safety and Environmental Officer)).

145 Testimony of Mark Bly, 213; Testimony of Charlie Williams, Hearing before the National Commission, November 9, 

2010, 45.

146 Testimony of Steve Lewis, 54, 124. BP argues that “[t]he use of additional mechanical plugs would have brought 

its own additional risks.” Powell, letter, att. 1, 6 (citing API, Recommended Practice 65—Part 2 (May 2010), § 3.1); 

Guide, interview. However, BP does not present any evidence that the Macondo team in fact evaluated those risks or 

compared them with the risks of setting a single surface cement plug in seawater 3,300 feet below the mud line. 

147 Merrick Kelley (BP), interview with Commission staff, October 22, 2010; Industry expert, interview.

148 BP asserts that “[u]sing drill collars would have required unracking the drill pipe on the rig and then locating and 

re-racking drill collars—a set of additional operations with attendant risks.” Powell, letter, att. 1, 5. BP does not 

provide any evidence to substantiate the extent of such “attendant risks” or whether they outweighed the risks of 

the procedure BP chose. Most significantly, BP offers no evidence that its Macondo team ever considered such risks 

or performed a rigorous comparative risk analysis. 

149 Internal BP document (BP-HZN-CEC 8574). 

150 Testimony of Mark Bly, 308. BP has suggested that the float valves provided an additional barrier to flow. BP, 

Deepwater Horizon Accident Investigation Report, 68. The Commission does not agree that float valves, even when 

converted, constitute a distinct physical barrier to flow, but instead reinforce the cement in the shoe track. Clawson, 

interview (indicating that Weatherford does not consider the float collar to be a barrier to hydrocarbons); API, 

Recommended Practice 65—Part 2 (May 2010), §§ 3.4, 4.4.3 (float valves not included in the list of subsurface 

mechanical barriers; float equipment used to prevent cement from flowing back into the casing). 

151 Testimony of Darryl Bourgoyne, Hearing before the National Commission, November 9, 2010, 133.

152 Testimony of Charlie Williams, 46–53. 

153 Testimony of Bill Ambrose, 380–84. 

154 Between 8:00 and 9:49 p.m., the crew was performing a number of other activities that may have further confounded the data or at least distracted the driller. The crew was emptying various tanks on the rig into the active pit 

system, including “trip tanks” and “sand traps,” which may have masked increased flow out of the well into the active pit system. At 9:18 p.m., a valve on one of the pumps blew, and a number of crew members from the rig floor 

went to fix it. Finally, the crew was operating one or both of the cranes on the main deck, which could have affected 

flow-out and volume readings. 

155 Internal BP document (BP-HZN-OSC 5420). 

156 Guide, interview. 

157 Ibid.; Internal BP document (BP-HZN-MBI 193529-39).

158 It appears that the chain of command and responsibilities at BP during the execute phase were not well-understood 

by the Macondo Engineering Team Leader. When asked during an interview who was responsible for designing or 

amending the temporary abandonment procedures, the Macondo Engineering Team Leader said he would need to 

look at the company’s chart of roles and responsibilities. Walz, interview. 

159 Internal BP document (BP-HZN-MBI 117603).

160 Internal BP document (BP-HZN-MBI 128542).

161 Internal BP document (BP-HZN-OSC 6224).

162 There is a dispute as to whether BP personnel called back to shore that evening to discuss the data observed during 

the negative-pressure test. The Commission staff has to date seen no direct evidence of such a call. The staff’s investigation is ongoing.

 

163 Internal BP document (BP-HZN-BLY 38354).

164 Internal BP document (BP-HZN-BLY 38355).
Endnotes 327 327

165 Internal BP document (BP-HZN-BLY 38354).

166 Internal BP document (BP-HZN-BLY 38361).

167 Ibid.

168 Internal BP document (BP-HZN-BLY 38362).

169 Internal Transocean document (TRN-PC 3227).

170 Transocean states that on April 5, 2010, it posted a short, two-page version of this advisory to an internal electronic 

document platform, which supervisors on the Deepwater Horizon had access to. But the advisory was limited to 

completion operations, and, as of this writing, Transocean has not offered any evidence that anyone on the rig actually saw or reviewed the advisory.

171 The industry and the international community also failed to adequately communicate lessons learned from the 

Montara blowout, which for ten weeks beginning on August 21, 2009 spewed between 400 and 1500 barrels per 

day of oil and gas into the Timor Sea approximately 150 miles off the northwest coast of Australia. David Borthwick, Report of the Montara Commission of Inquiry (The Montara Commission of Inquiry, Australia, June 2010), 

5, 26. According to the Report of the Montara Commission of Inquiry, released on November 24, 2010, many of 

the technical and managerial causes of the Montara blowout track those at Macondo. For instance, the Commission 

of Inquiry concluded that the cement job in the “9 5/8” casing shoe failed, that there were numerous risk factors 

surrounding the cement job that went unheeded, and that the cement job was not properly pressure tested. Ibid., 7. 

According to the Commission of Inquiry:

The multiple problems in undertaking the cement job—such as the failure of the top and bottom plugs to create a seal after “bumping,” the failure of the float valves and an unexpected rush of fluid—should have raised 

alarm bells. Those problems necessitated a careful evaluation of what happened, the instigation of pressure 

testing and, most likely, remedial action. No such careful evaluation was undertaken. The problems were not 

complicated or unsolvable, and the potential remedies were well known and not costly. This was a failure of 

“sensible oilfield practice 101.”

Ibid. The Commission of Inquiry went on to conclude that while the “absence of tested barriers was a proximate 

cause of the Blowout,” the deeper failure was a systemic failure of management on the part of the operator, PTTEP 

Australasia. Ibid., 9. 

172 Testimony of Rex Tillerson, Hearing before the National Commission, November 9, 2010, 250–52; Testimony of 

Marvin Odum, Hearing before the National Commission, November 9, 2010, 278–79.

173 30 C.F.R. § 250.1721(d).

174 30 C.F.R. § 250.141(a).

175 Internal BP document (BP-HZN-OSC 1436).

176 Internal BP document (BP-HZN-MBI 127906). MMS approved a number of other requests by BP for deviations on 

the Macondo well. None of those other approvals appear to have contributed to the blowout. However, they do suggest that the MMS staff did not spend much time deciding whether to grant the requests, which may have been due 

to the severe funding and staffing shortages in the New Orleans office. 

Chapter Five

1 Brady Dennis and Shailagh Murray, “GOP Changes Tone on Financial Bill,” Washington Post, April 21, 2010; Edward 

Wyatt and David M. Herszenhorn, “Bill on Finance Wins Approval of Senate Panel,” New York Times, April 22, 2010; 

Jim Puzzanghera, “In N.Y., Obama to Push for Financial Overhaul,” Los Angeles Times, April 22, 2010; Adam Liptak, 

“Justices Reject Ban on Depicting Animal Cruelty,” New York Times, April 21, 2010; Joan Biskupic, “High Court 

Negates Animal Cruelty Law as Too Broad, 8-1” USA Today, April 21, 2010; Jess Bravin, “Court Voids Law on Animal 

Cruelty,” Wall Street Journal, April 21, 2010; Bart Barnes, “A Movement’s Matriarch,” Washington Post, April 21, 

2010; Andrew Zajac and Melissa Healy, “FDA Puts the Pinch on Salt,” Los Angeles Times, April 21, 2010.

2 Neil MacFarquhar, “Routine Flights Become Overland Odysseys, Minus Clean Socks,” New York Times, April 22, 2010.

3 Campbell Robertson, “11 Remain Missing After Oil Rig Explodes Off Louisiana,” New York Times, April 22, 2010.

4 Rick Jervis, “Gulf Blast Appears to be ‘Blowout’,” USA Today, April 22, 2010; Ben Casselman, Russell Gold, and Angel 

Gonzalez, “Blast Jolts Oil World,” Wall Street Journal, April 22, 2010.

5 Jervis, “Gulf Blast Appears to be ‘Blowout.’”

6 Richard Fausset, “Oil Rig Explodes; 11 Missing,” Los Angeles Times, April 22, 2010.

7 40 C.F.R. § 300, Subpart D.

8 Paul Purpura et al., “Search continues for 11 missing in rig blast,” Times-Picayune, April 22, 2010.

9 Paul Rioux and Chris Kirkham, “Search for 11 Workers Missing After Oil Rig Explosion Is Expected To Be Called Off 

Friday,” Times-Picayune, April 22, 2010.

10 Testimony of Captain James Hanzalik, Hearing Before the Deepwater Joint Investigation Team, October 4, 2010, 29-

30.
328 National Commission on the BP Deepwater Horizon OIl Spill and Offshore Drilling

11 40 C.F.R. § 300.305(c). 

12 Press Release, White House, Statement by the Press Secretary on the President’s Oval Office Meeting to Discuss the 

Situation in the Gulf of Mexico, April 22, 2010. 13 40 C.F.R. § 300.175(b).

14 Leslie Kaufman, “Search Ends for Missing Oil Rig Workers,” New York Times, April 23, 2010.

15 Press Release, Unified Command, Unified Command Continues to Respond to Deepwater Horizon, April 25, 2010.

16 Interview with Coast Guard official, August 27, 2010.

17 BP, Initial Exploration Plan, Mississippi Canyon Block 252 (February 23, 2009), § 2.6.

18 Doug Suttles, interview with Commission staff, October 13, 2010; Interviews with Minerals Management Service 

officials, October 15, 2010; Interview with well control expert, October 14, 2010.

19 Press Release, BP, Work Begins To Drill Relief Well To Stop Oil Spill, May 4, 2010; White House, Ongoing Response 

Timeline, May 17, 2010; David Hayes, memo to Commission staff, November 12, 2010.

20 Joe Stephens and Mary Pat Flaherty, “Oil Industry Cleanup Organization Swamped by BP Spill,” Washington Post, 

June 29, 2010.

21 The Response Group on behalf of BP, Regional Oil Spill Response Plan-Gulf of Mexico (June 30, 2009), App. H: 40.

22 Jonathan Ramseur, Oil Spills in U.S. Coastal Waters: Background, Governance, and Issues for Congress (Congressional Research Service, 2008), 2. 

23 Joint Industry Oil Spill Preparedness and Response Task Force, Joint Industry Recommendations to Improve Oil Spill 

Preparedness and Response (September 3, 2010), V-3, V-5; Henry Fountain, “Advances in Oil Spill Cleanup Lag Since 

Valdez,” New York Times, June 24, 2010.

24 Sarah L. Milton et al., “Obituary Peter L. Lutz,” Journal of Experimental Biology 208 (2005): 2817–18; Regional Oil 

Spill Response Plan-Gulf of Mexico App. F:19, § 11:7, App. E.

25 Opening Statement of Chairman Edward Markey, “Drilling Down on America’s Energy Future: Safety, Security, and 

Clean Energy,” Hearing Before the House Committee on Energy and Commerce, Subcommittee on Energy and Environment, 111th Congress (June 15, 2010).

26 Interview with NOAA scientist, August 20, 2010; Interview with NOAA scientist, October 13, 2010.

27 NOAA Scientist, Estimation of the Oil Released from Deepwater Horizon Incident, April 26, 2010; Mark Miller, e-mail 

to Martha Garcia, June 14, 2010. 

28 Interview with NOAA scientist, August 30, 2010; Interview with NOAA scientist, October 13, 2010.

29 Press Conference, Admiral Mary Landry and Doug Suttles, New Orleans, LA, April 28, 2010.

30 Press Release, Deepwater Horizon Incident Joint Information Center Update: The Ongoing Administration-Wide 

Response to the BP Deepwater Horizon Oil Spill, July 15, 2010.

31 Paul Purpura, “Guard Troops Going Home,” Times-Picayune, October 21, 2010.

32 40 C.F.R. § 300.322(b).

33 40 C.F.R. § 300.305(d).

34 Clifford Krauss, “Oil Spill’s Blow to BP’s Image May Eclipse Its Cost,” New York Times, April 29, 2010.

35 Office of Science and Technology, First Report of the President’s Panel on Oil Spills (1969), 9.

36 Interview with well control expert, October 14, 2010.

37 Transcript, Office of the Press Secretary, Press Briefing on the BP Oil Spill in the Gulf Coast, April 29, 2010.

38 Transcript, State of the Union with Candy Crowley, CNN, May 2, 2010.

39 40 C.F.R. § 300.323; Campbell Robertson, “White House Takes a Bigger Role in the Oil Spill Cleanup,” New York 

Times, April 29, 2010. 

40 40 C.F.R. § 300.5.

41 40 C.F.R. § 300.323(c).

42 Interview with Coast Guard official, November 12, 2010.

43 Press Release, Deepwater Horizon Incident Joint Information Center, Coast Guard Commandant Admiral Thad Allen 

Designated National Incident Commandant For Continued Response To BP Oil Spill, May 1, 2010.

44 Thom Shanker, “Commander Accustomed to Scrutiny and Crises,” New York Times, September 10, 2005; Matthew 

L. Wald, “A New, Experienced Protector for Navy in Home Waters,” New York Times, November 9, 2001; Elizabeth 

Bumiller, “Casualty of Firestorm: Outrage, Bush, and FEMA Chief,” New York Times, September 10, 2005.

45 Editorial, “Allen Candid About Recovery,” Advocate, December 11, 2005.

46 Jim Tankersley, “The Government’s ‘Rock Star’ in Charge of the Oil Spill,” Los Angeles Times, June 1, 2010.
Endnotes 329 329

47 Testimony of Harry Thierens, Hearing before the Deepwater Horizon Joint Investigation Team, August 25, 2010, 

104–5. 

48 Henry Fountain, “Notes from Wake of Blowout Outline Obstacles and Frustration,” New York Times, June 21, 2010; 

Non-public BP document, May 6, 2010.

49 Testimony of Harry Thierens, 106. 

50 Government science advisor, e-mail to Commission staff, October 7, 2010; Testimony of William Stringfellow, Hearing before the Deepwater Horizon Joint Investigation Team, August 25, 2010, 352.

51 BP, Deepwater Horizon Accident Investigation Report (September 8, 2010), 150.

52 Non-public BP document, May 7, 2010.

53 David Barstow et al., “Regulators Failed to Address Risks in Oil Rig Fail-Safe Device,” New York Times, June 20, 2010; 

Interview with senior administration official, November 8, 2010.

54 FEMA, “Disasters Declared by Year or State,” http://www.fema.gov/news/disaster_totals_annual.fema.

55 42 U.S.C. §§ 5121-5206.

56 40 C.F.R. § 300.105(c)(3).

57 Interview with government official, August 24, 2010.

58 Press Release, Office of the Governor, Governor Jindal Issues State Declaration of Emergency for Oil Leak, April 29, 

2010.

59 Press Release, Governor Barbour Issues State of Emergency for Mississippi Gulf Coast, April 30, 2010; Press Release, 

Gov. Riley Declares State of Emergency to Prepare for Oil Approaching Alabama Coast, April 30, 2010; State of 

Florida, Office of the Governor, Executive Order Number 10-99 (Emergency Management—Deepwater Horizon), April 

30, 2010.

60 Interview with government official, August 24, 2010; Interview with government official, September 13, 2010; 

Interview with government official, September 15, 2010.

61 Interview with Coast Guard official, August 31, 2010.

62 Interview with BP official, October 22, 2010; Interview with government official, October 5, 2010; Interview with 

government official, August 24, 2010; Interview with Coast Guard official, August 25, 2010.

63 La. Rev. Stat. § 29: 727. 

64 Interview with government official, October 8, 2010.

65 Interview with Coast Guard official, October 20, 2010.

66 Interview with government official, October 8, 2010; Interview with government official, October 14, 2010.

67 Testimony of Admiral Thad Allen, National Incident Commander, Hearing before the National Commission, September 27, 2010.

68 Press Release, In Precautionary Move, LDWF and DHH Announce Closures Due to Oil Spill, April 30, 2010; Press 

Release, Alabama Department of Conservation and Natural Resources, Some State Waters Closed to Fishing, June 2, 

2010; Press Release, Mississippi Department of Marine Resources, Revised Precautionary Closure: Portions of Mississippi Marine Waters Reopen to Commercial and Recreational Fishing, June 4, 2010; Florida Fish and Wildlife Conservation Commission, Order No. EO 10-29, Emergency Closure of State Waters of the Gulf of Mexico in response to the 

Deepwater Horizon Oil Spill, June 13, 2010.

69 NOAA, Office of Response and Restoration, Oil Forecast Outlook (April 23, 2010). 

70 Fisheries of the Caribbean, Gulf of Mexico, and South Atlantic; Emergency Fisheries Closure in the Gulf of Mexico Due 

to the Deepwater Horizon Oil Spill, 75 Fed. Reg. 24,822 (May 6, 2010); NOAA Fisheries Service, Deepwater Horizon/

BP Oil Spill: Size and Percent Coverage of Fishing Closures Due to BP Oil Spill (November 15, 2010), http://sero.nmfs.

noaa.gov/ClosureSizeandPercentCoverage.htm. 

71 Fisheries of the Caribbean, Gulf of Mexico, and South Atlantic; Amendment to Emergency Fisheries Closure in the 

Gulf of Mexico Due to the Deepwater Horizon Oil Spill, 75 Fed. Reg. 26,679 (May 12, 2010); NOAA, Deepwater Horizon/BP Oil Spill: Size and Percent Coverage of Fishing Closures Due to BP Oil Spill.

72 Fisheries of the Caribbean, Gulf of Mexico, and South Atlantic; Emergency Fisheries Closures in the Southeast Region 

Due to the Deepwater Horizon Oil Spill; Amendment 2, 75 Fed. Reg. 27,217 (May 14, 2010).

73 NOAA, Deepwater Horizon/BP Oil Spill: Size and Percent Coverage of Fishing Closures Due to BP Oil Spill.

74 Interview with government official, October 12, 2010.

75 BP, “Factsheet on BP Vessels of Opportunity Program” (July 7, 2010), 4, http://www.bp.com/liveassets/bp_internet/

globalbp/globalbp_uk_english/incident_response/STAGING/local_assets/downloads_pdfs/factsheet_bp_vessels_of_opportunity_program.pdf.

76 National Incident Command, National Incident Commander Strategy Implementation Plan Version 5.0 (2010), 

474–75. 
330 National Commission on the BP Deepwater Horizon OIl Spill and Offshore Drilling

77 BP, Factsheet on BP Vessels of Opportunity Program, 2.

78 Bruce Nolan, “Many Vietnamese fishers isolated by language from oil spill aid,” Times-Picayune, May 7, 2010; 

Mireya Navarro, “Spill Takes Toll on Gulf Workers’ Psyches,” New York Times, June 16, 2010; Jessica Ravitz, “Vietnamese Fishermen in Gulf Fight to Not Get Lost in Translation,” CNN, June 25, 2010.

79 BP, Factsheet on BP Vessels of Opportunity Program 5. 

80 Interview with BP official, October 22, 2010.

81 40 C.F.R. § 300.150.

82 Rebecca Bratspies et al., From Ship to Shore: Reforming the National Contingency Plan to Improve Protections for Oil 

Spill Cleanup Workers (Center for Progressive Reform, September 2010), 8–9.

83 Interview with responder, November 17, 2010; Bryan Walsh, “Assessing the Health Effects of the Oil Spill,” Time, 

June 25, 2010. 

84 Scott Deitchman, interview with Commission staff, November 29, 2010.

85 Nicole Lurie, interview with Commission staff, October 6, 2010.

86 Ibid.

87 Deitchman, interview; Lurie, interview; Strategy Implementation Plan, 252.

88 Molly Reid, “Only One Oil-slicked Bird Rescued so far from Gulf of Mexico Oil Spill,” Times-Picayune, April 30, 2010.

89 U.S. Fish and Wildlife Service, “Cumulative Impacts to Wildlife and Actions to Protect Wildlife in the Gulf of Mexico” 

(November 25, 2010), http://www.fws.gov/home/dhoilspill/pdfs/CumulativeImpactsBP.pdf. 

90 U.S. Fish and Wildlife Service, “Oil Spill Response” (May 2010), http://www.fws.gov/home/dhoilspill/pdfs/OilSpillFactSheet.pdf. 

91 Michele Wilson, “Oil Spill Update: Two More Birds Recovering, BP and Other Execs Point Fingers, and More,” Audubonmagazine.org, May 12, 2010.

92 Interview with wildlife responder, October 26, 2010; Interview with representatives of wildlife organizations, October 

15, 2010. 

93 Craig Pittman, “Bird rescue experts kept on sideline after gulf oil spill,” St. Petersburg Times, September 5, 2010; 

Interview with wildlife responder, October 26, 2010.

94 Testimony of Kevin Costner, “Deluge of Oil Highlights Research and Technology Needs for Effective Cleanup of Oil 

Spills,” Hearing Before the House Committee on Science and Technology, 111th Congress (June 9, 2010); Fountain, 

“Advances in Oil Spill Cleanup Lag Since Valdez.”

95 Press Release, Deepwater Horizon Joint Information Center, New Effort to Collect; Review Oil Spill Response Solutions 

Announced, June 4, 2010.

96 Commander Todd Offutt, e-mail to Commission staff, November 17, 2010.

97 Interview with Coast Guard official, September 2, 2010.

98 White House Office of the Press Secretary, Press Briefing by Press Secretary Robert Gibbs and National Incident Commander Thad Allen, July 1, 2010; U.S. Department of State, Deepwater Horizon Oil Spill Response: International 

Offers of Assistance from Governments and International Bodies Chart, June 18, 2010.

99 46 U.S.C. § 688.

100 Interview with Coast Guard officials, August 3, 2010; API Joint Oil Spill Preparedness and Response Task Force, 

interview with Commission staff, October 12, 2010; Scott Segal and Kevin Ewing, interview with Commission staff, 

October 14, 2010; H. Clayton Cook Jr., Letter to the Editor, “Don’t Blame Delays on Jones Act,” Wall Street Journal, 

July 20, 2010; U.S. Department of Homeland Security, Jones Act Fact Sheet (July 6, 2010), http://www.deepwaterhorizonresponse.com/external/content/document/2931/784459/1/USCG-Jones%20Act.pdf.

101 U.S. Department of Homeland Security, Jones Act Fact Sheet; Press Release, Deepwater Horizon Joint Information 

Center, Admiral Allen Provides Guidance to Ensure Expedited Jones Act Waiver Processing Should It Be Needed, June 

15, 2010.

102 Non-public Coast Guard documents, June 29, 2010, June 30, 2010, and July 9, 2010.

103 Coastal Response Research Center, Research & Development Needs for Making Decisions Regarding Dispersing Oil

(April 2006), 1.

104 Ramon Antonia Vargas, “Oil is Leaking from Well at Deepwater Horizon Explosion Site,” Times-Picayune, April 24, 

2010.

105 Interview with Coast Guard official, October 29, 2010. 

106 National Research Council, Committee on Understanding Oil Spill Dispersants, Oil Spill Dispersants: Efficacy and 

Effects (2005), 2.

107 Coastal Response Research Center, 1. 108 National Research Council, Oil Spill Dispersants, 196, 274.
Endnotes 331 33

109 Merv Fingas, A Review of Literature Related to Oil Spill Dispersants, 1997-2008 (September 2008), 18 http://www.

pwsrcac.org/docs/d0053000.pdf.

110 Ibid., 25.

111 Non-public Coast Guard document, April 23, 2010.

112 RRT-6, FOSC Dispersant Pre-Approval Guidelines And Checklist (2001), iii-iv, http://www.losco.state.la.us/pdf_

docs/RRT6_Dispersant_Preapproval_2001.pdf; Region IV Regional Response Team Response and Technology Committee Dispersant Workgroup, Use of Dispersants in Region IV (1996), ii-1, http://www.nrt.org/production/NRT/

RRTHome.nsf/Resources/DUP/$file/1-RRT4DISP.PDF. 

113 40 C.F.R. § 300.910(a).

114 S.L. Ross Environmental Research, Ltd., Technology Assessment of the Use of Dispersants on Spills from Drilling and 

Production Facilities in the Gulf of Mexico Outer Continental Shelf (December 2000), Summary-1; Robert J. Fiocco 

and Alun Lewis, “Oil Spill Dispersants,” 1 Pure Applied Chemistry (1999): 31.

115 40 C.F.R. § 300.910(b).

116 Figures on the volume of dispersant use are either taken directly from, or calculated based on data in, the Operations 

and Ongoing Response daily reports for the Deepwater Horizon Response, available at www.restorethegulf.gov. 

117 40 C.F.R. § 300.915 (a)(8).

118 David Biello, “Is Using Dispersants on the BP Gulf Oil Spill Fighting Pollution with Pollution?” Scientific American, 

June 18, 2010.

119 40 C.F.R. § 300.915; 40 C.F.R. Part 300 Appendix C.

120 National Research Council, Oil Spill Dispersants, 68–69; Samuel K. Skinner and William K. Reilly, The Exxon Valdez 

Oil Spill: A Report to the President (May 1989), 17, App. A. 

121 David Hammer, “BP Clashes with Critics on Gulf of Mexico Oil Crisis Response,” Times-Picayune, May 31, 2010.

122 Elana Schor, “BP Continues to Use Surface Dispersants in Gulf Despite EPA Directive,” New York Times, June 24, 

2010.

123 Ernest Scheyder, “Nalco CEO on Gulf Coast to Defend Dispersant,” Reuters, June 3, 2010.

124 Interview with NOAA scientist, October, 21, 2010; Testimony of Lisa Jackson, Hearing before the National Commission, September 27, 2010. 

125 Dana Tulis and Mathy Stanislaus, interview with Commission staff, October 1, 2010.

126 Kenneth Meade, e-mail to Commission staff, September 27, 2010.

127 Tim Webb, “BP Boss Tony Hayward Admits Job is on the Line Over Deepwater Oil Spill,” The Guardian, May 14, 

2010.

128 Tulis and Stanislaus, interview.

129 EPA, Dispersant Monitoring and Assessment Directive for Subsurface Dispersant Application, May 10, 2010; EPA, 

Dispersant Monitoring and Assessment Directive for Subsurface Dispersant Application—Addendum 1, May 14, 

2010; EPA, Dispersant Monitoring and Assessment Directive, May 20, 2010; EPA, Dispersant Monitoring and Assessment Directive—Addendum 3, May 26, 2010.

130 Testimony of Lisa Jackson, September 27, 2010. 

131 Richard Lynch, interview with Commission staff, October 13, 2010; Suttles, interview.

132 Press Release, BP, Work Begins to Drill Relief Well to Stop Oil Spill, May 4, 2010.

133 Press Release, White House, The Ongoing Administration-Wide Response to the Deepwater BP Oil Spill, May 6, 2010; 

“Deepwater Team Attempts To Put 100-Tonne Box over Blown-out Oil Well,” Associated Press, May 7, 2010; Matthew Bigg, “Oil From Gulf Spill Creeps Ashore in Louisiana,” Reuters, May 6, 2010.

134 Ian Urbina, Justin Gillis, and Clifford Krauss, “On Defensive, BP Readies Dome to Contain Spill,” New York Times, 

May 3, 2010.

135 Suttles, interview; Lynch, interview.

136 Non-public BP document, May 7, 2010.

137 Interview with well control expert, October 14, 2010; Interview with drilling expert, October 1, 2010.

138 Lynch, interview.

139 Campbell Robertson, “New Setback in Attempt to Contain Gulf Oil Spill,” New York Times, May 8, 2010.

140 Lynch, interview.

141 Clifford Krauss, Henry Fountain, and John M. Broder, “Acrimony Behind the Scenes of Gulf Oil Spill,” New York 

Times, August 26, 2010.

142 Interview with U.S. Geological Survey official, October 21, 2010.
332 National Commission on the BP Deepwater Horizon OIl Spill and Offshore Drilling

143 Suttles, interview.

144 Interview with U.S. Geological Survey official, October 21, 2010; Interview with Minerals Management Service official, October 15, 2010; Interview with well control expert, October 14, 2010.

145 Sam Dolnick and Henry Fountain, “Unable to Stanch Oil, BP Will Try To Gather It,” New York Times, May 5, 2010.

146 Clifford Krauss and Michael Cooper, “Cap Slows Gulf Oil Leak as Engineers Move Cautiously,” New York Times, June 

5, 2010.

147 Lynch, interview.

148 Jeremy Hsu, “Why Don’t We Just Drop a Nuclear Bomb on the Gulf Oil Spill?” Christian Science Monitor, May 13, 

2010.

149 Testimony of Richard Camilli, “Sizing up the BP Oil Spill: Science and Engineering Measuring Methods,” Briefing 

Before the Subcommittee on Energy and Environment of the House Committee on Energy and Commerce, 111th 

Congress (May 19, 2010). 

150 John Amos, “Gulf Oil Spill Rate Must Be Much Higher Than Stated—6 Million Gallons So Far?”, Skytruth.org, April 

27, 2010, http://blog.skytruth.org/2010/04/gulf-oil-spill-rate-must-be-much-higher.html; John Amos, “Gulf 

Oil Spill—Bigger Than Exxon Valdez,” Skytruth.org, April 28, 2010, http://blog.skytruth.org/2010/04/gulf-oilspill-bigger-than-exxon-valdez.html; John Amos, “Gulf Oil Spill—New Spill Calculation—Exxon Valdez Surpassed 

Today,” Skytruth.org, May 1, 2010,http://blog.skytruth.org/2010/05/gulf-oil-spill-new-spill-rate.html. 

151 Richard Harris, “Gulf Spill May Far Exceed Official Estimates,” National Public Radio, May 14, 2010, http://

www.npr.org/templates/story/story.php?storyId=126809525. 

152 Testimony of Steven Wereley (Professor, Purdue University), “Sizing up the BP Oil Spill: Science and Engineering 

Measuring Methods,” Briefing Before the Subcommittee on Energy and Environment of the House Committee on 

Energy and Commerce, 111th Congress (May 19, 2010).

153 Harris, “Gulf Spill May Far Exceed Official Estimates.”

154 Transcript, Marcia McNutt, Deepwater Blowout Containment Conference, September 22, 2010.

155 Press Release, Deepwater Horizon Incident Joint Information Center, Flow Rate Group Provides Preliminary Best 

Estimate of Oil Flowing From BP Oil Well, May 27, 2010.

156 Marcia McNutt, Summary Preliminary Report from the Flow Rate Technical Group (June 2, 2010).

157 Admiral Thad Allen, letter to Honorable Edward J. Markey, October 1, 2010, 12.

158 Press Release, U.S Department of Energy, Secretary Salazar and Secretary Chu To Meet with Scientists and Engineers 

at BP Houston Command Center, May 11, 2010.

159 Interview with U.S. Department of Energy official, November 8, 2010; Interview with government science advisor, 

October 5, 2010; Interview with government science advisor, October 6, 2010.

160 Kenneth Chang and Andrew Revkin, “At a Sleek Bioenergy Lab, a Lens on a Cabinet Pick,” New York Times, December 

22, 2008.

161 Paul Tooms, interview with Commission staff, October 13, 2010; Interviews with Minerals Management Service 

officials, October 15, 2010; Interview with Coast Guard official, October 18, 2010.

162 Interview with U.S. Department of Energy official, November 8, 2010; Interview with Coast Guard official, October 

18, 2010; Interview with government science advisor, October 5, 2010.

163 Interview with government science advisor, October 1, 2010; Interview with U.S. Department of Energy scientist, 

October 26, 2010.

164 “Leno: ‘Junk Shot,’” New York Times, June 1, 2010.

165 Campbell Robertson, Clifford Krauss, and John M. Broder, “Oil Hits Home, Spreading Arc of Frustration,” New York 

Times, May 24, 2010.

166 Lynch, interview.

167 Non-public U.S. Department of Energy document, May 17, 2010; Non-public U.S. Department of Energy document, May 19, 2010. 

168 Tooms, interview.

169 Interview with U.S. Department of the Interior official, October 21, 2010.

170 Interview with government science advisor, October 6, 2010.

171 Non-public BP document, May 31, 2010.

172 Suttles, interview.

173 Interview with government science advisor, October 6, 2010; Suttles, interview; Tooms, interview.

174 Interview with Minerals Management Service official, October 15, 2010; Interview with well control expert, October 

14, 2010.
Endnotes 333 333

175 Robertson, Krauss, and Broder, “Oil Hits Home, Spreading Arc of Frustration.”

176 Mimi Hall, Rick Jervis, and Allen Levin, “Is Oil Spill Becoming Obama’s Katrina?,” USA Today, May 27, 2010. 177 Matthew Daly, “Month After Oil Spill, Why Is BP Still in Charge?,” ABC News, May 21, 2010, http://abcnews.

go.com/Business/wireStory?id=10713257.

178 Interview with Coast Guard official, November 12, 2010.

179 Frank McCormack, “Privateer Perfection,” Plaquemines Gazette, June 7, 2010.

180 Paul Rioux, “President Barack Obama in Grand Isle after Touring Beach in Port Fourchon,” Times-Picayune, May 28, 

2010.

181 Paul Rioux, “President Barack Obama Promises No Retreat from Gulf of Mexico Oil Spill Response,” Times-Picauyne, 

May 28, 2010.

182 Interview with Coast Guard official, August 26, 2010; Interview with Coast Guard official, September 2, 2010; 

Non-public Coast Guard document, June 14, 2010.

183 Jeffrey Ball and Jonathan Weisman, “Slippery Start: U.S. Response to Spill Falters,” Wall Street Journal, June 16, 

2010. 

184 Interview with Coast Guard official, November 12, 2010.

185 Executive Order No. 13543, National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling, 75 

Fed. Reg. 29,397, May 21, 2010.

186 Peter Baker, “Obama Extends Moratorium; Agency Chief Resigns,” New York Times, May 27, 2010. 

187 Gardner Harris, “Minerals Management Service Director Resigns Over Spill,” New York Times, May 27, 2010.

188 Mike Allen, “Gulf Commander to Begin Solo Briefings,” Politico, May 31, 2010. 

189 Interview with government official, October 8, 2010.

190 Interview with NOAA officials, November 18, 2010.

191 Interview with Coast Guard official, August 24, 2010; Interview with Coast Guard official, August 30, 2010.

192 Interview with Coast Guard official, August 24, 2010; Interview with Coast Guard official, August 31, 2010.

193 Non-public Coast Guard document, October 12, 2010.

194 Holbrook Mohr, Justin Pritchard, and Tamara Lush, “BP’s Gulf Oil Spill Response Plan Lists the Walrus as a Local 

Species. Louisiana Gov. Bobby Jindal Is Furious.,” Christian Science Monitor, June 9, 2010; Interview with Coast 

Guard official, Aug. 31, 2010.

195 Campbell Robertson, “Louisiana Officials Threaten Action if Spill Response Proves Inadequate,” New York Times, 

May 23, 2010.

196 Craig Pittman and Rebecca Catalanello, “BP Plan to Protect Florida From Oil Spill Inadequate, Officials Say,” St. 

Petersburg Times, May 3, 2010. 

197 Interview with government official, October 13, 2010.

198 Non-public Coast Guard document, October 12, 2010.

199 Interview with government official, October 12, 2010.

200 Interview with Coast Guard official, August 30, 2010; Interview with government official, August 24, 2010.

201 Liz Robbins and Campbell Robertson, “Tension Among Officials Grows as Storm Nears,” New York Times, July 23, 

2010.

202 Angel Gonzalez, “Locals to BP: Don’t Leave Town Yet,” Wall Street Journal, Aug. 1, 2010; Interview with Coast 

Guard official, August 26, 2010.

203 Interview with Coast Guard official, August 25, 2010; Interview with Coast Guard official, October 24, 2010; Nonpublic Coast Guard document, June 14, 2010.

204 U.S. Department of Homeland Security, Summary of Ineligible PWs for Barrier Islands (November 11, 2010); Tod 

Wells, e-mail to Commission staff, November 8, 2010; Tim Padgett, “Dredge, Baby, Dredge: Can Sand Stop the Oil?,” 

Time, June 1, 2010. 

205 Van Oord and Deltares, Save the Delta, The Dutch Perspective, May 6, 2010; Chris Kirkham, “Gov. Bobby Jindal and 

Plaquemines Officials Float Plan to Rebuild Barrier Islands to Stop Encroaching Oil,” Times-Picayune, May 8, 2010. 

206 Interview with Coast Guard official, August 30, 2010; Mark Schleifstein, “Barrier Berm Advocates Not Deterred by 

Environmental Regulators’ Misgivings,” Times-Picayune, September 20, 2010.

207 Kristi Cantu, letter to Pete J. Serio, May 11, 2010. 

208 Colonel Alvin Lee, interview with Commission staff, October 28, 2010. 

209 Colonel Lee, interview; Press Release, Governor’s Office of Homeland Security and Emergency Preparedness, Governor Jindal & Coastal Parish Leaders Meet with Army Corps of Engineers to Stress Importance of Approving Dredg-
334 National Commission on the BP Deepwater Horizon OIl Spill and Offshore Drilling

ing Plan, May 17, 2010. 

210 Senator Mary Landrieu et al., letter to Colonel Alvin Lee and Admiral Thad Allen, May 20, 2010.

211 Senator David Vitter, letter to President Barack Obama, May 21, 2010.

212 Press Release, Army Corps of Louisiana, Corps Decision on State’s Emergency Permit Request, May 27, 2010; Army 

Corps of Engineers, “New Orleans District Emergency Permit Request Action,” June 1, 2010, http://www.mvn.

usace.army.mil/pao/MVNIPR1June2010Final.pdf.

213 Agency comments were compiled by the Army Corps of Engineers at http://www.mvn.usace.army.mil/news/

Emergency%20Permit%20Documents%20Compressed%20FINAL.pdf. 

214 Transcript, Press Briefing by National Incident Commander, June 2, 2010.

215 Press Release, Deepwater Horizon Incident Joint Information Center, Admiral Allen Approves One Section of Louisiana Barrier Island Project Proposal as Part of Federal Oil Spill Response, May 27, 2010.

216 NIC Decision Support Document Regarding Barrier Island Proposal Based Upon Interagency Solutions Group Discussion and Army Corps of Engineers NOD 20 Permit Discussions, May 17, 2010; Draft, Berm Construction and 

Spill Response, U.S. Department of Homeland Security, May 19, 2010; Berm Construction and Spill Response, U.S. 

Department of Homeland Security, May 25, 2010. 

217 Admiral Thad Allen, e-mail to Captain Mike White, May 22, 2010.

218 Mark Schleifstein, “Sand Berm to Protect Barataria Bay Wetlands Gets Federal OK,” Times-Picayune, May 27, 2010.

219 Interview with Coast Guard official, November 12, 2010. 

220 Press Release, Governor’s Office of Homeland Security and Emergency Preparedness, Governor Jindal: President 

Promised Sand-Boom Plan Progress in Days, Need Swift Action, May 28, 2010.

221 Transcript, Anderson Cooper 360 Degrees, “BP Cleanup Sham; President Obama Visits Louisiana; Oystermen in 

Jeopardy,” CNN, May 28, 2010. 

222 Transcript, Press Briefing by National Incident Commander Admiral Thad Allen, June 2, 2010.

223 Bigad Shaban, “Upset Nungesser Walks Out on Coast Guard Meeting,” www.ltv.com, June 1, 2010. 

224 National Incident Command, Summary of NIC Barrier Island Berm Meeting, June 1, 2010.

225 Admiral Thad Allen, interview with Commission staff, November 2, 2010; Denise Reed, interview with Commission 

staff, November 16, 2010; Interview with Coast Guard official, November 12, 2010.

226 Glenn Thrush, “Carville Doesn’t Regret Ripping W.H.,” Politico, June 2, 2010. 

227 Press Release, National Incident Command, National Incident Commander Admiral Allen Directs BP to Pay for Five 

Additional Barrier Island Projects in Louisiana, June 2, 2010.

228 Mark Kaufman, “BP Says More La. Barrier Island Berms Will Cost $360 Million,” Washington Post, June 3, 2010.

229 William Grawe, e-mail to Admiral Thad Allen, June 2, 2010.

230 “Shaw Group Wins Contract to Build Barrier Island Temporary Berms,” Times-Picayune, June 4, 2010; Jeffrey Ball, 

“Accusations Fly in Sand-Berm Project,” Wall Street Journal, October 12, 2010.

231 Shaw’s Environmental & Infrastructure Group, Shaw Barrier Berm Project—Daily Report Day 43, July 14, 2010.

232 Sean Smith, e-mail to Juliette Kayyem, Department of Homeland Security, May 27, 2010.

233 Tooms, interview.

234 Interview with Coast Guard official, October 18, 2010; Interview with Minerals Management Service official, October 15, 2010.

235 Internal BP document (BP-HZN-MBI 143338-50).

236 Tooms, interview; Non-public BP document, May 31, 2010.

237 Non-public BP document, May 29, 2010.

238 Tooms, interview.

239 Interview with Coast Guard official, October 18, 2010; Interview with U.S. Geological Survey official, October 21, 

2010.

240 Interview with U.S. Geological Survey official, October 21, 2010; Non-public government document, June 1, 2010.

241 Interview with U.S. Geological Survey official, October 21, 2010; Interview with U.S. Department of Energy official, September 17, 2010.

242 Non-public BP document, May 23, 2010; Non-public BP document, May 25, 2010; Daniel Squire, letter to Commission staff, November 2, 2010, att. 1, 2. 

243 Non-public BP document, May 31, 2010; Non-public BP document, May 29, 2010.

244 Non-public BP document, May 31, 2010; Non-public BP document, May 29, 2010.
Endnotes 335 335

245 Lynch, interview.

246 Deepwater Horizon Response Joint Information Center, Ongoing Administration-Wide Response to the Deepwater BP 

Oil Spill, May 29, 2010; Press Release, BP, Update on Gulf of Mexico Oil Spill, May 29, 2010.

247 Helene Cooper and Peter Baker, “U.S. Opens Criminal Inquiry into Oil Spill,” New York Times, June 1, 2010.

248 “BP Chief Hopes Cap Will Capture Most of Gulf Oil,” Reuters, June 6, 2010.

249 Doug Suttles, letter to Admiral James Watson, June 9, 2010 (suggesting that with the Clear Leader attached to the 

kill line, BP could collect 5-10,000 barrels per day).

250 Lisa Jackson, EPA Conference Call on Dispersant Use in the Gulf of Mexico with U.S. Coast Guard Rear Admiral 

Landry, May 24, 2010.

251 EPA, Dispersant Monitoring and Assessment Directive—Addendum 3, May 26, 2010.

252 Dana Tulis, e-mail to Admiral James Watson, June 7, 2010.

253 Captain James Hanzalik, e-mail to Captain Anthony Lloyd, June 8, 2010.

254 Admiral James Watson, e-mail to Dana Tulis, et al., June 7, 2010; Dana Tulis, e-mail to Admiral James Watson, 

June 7, 2010.

255 Captain James Hanzalik, e-mail to Captain Anthony Lloyd, June 8, 2010.

256 Dana Tulis, e-mail to Admiral James Watson, June 8, 2010.

257 Mathy Stanislaus, e-mail to Admiral James Watson, July 9, 2010, att.

258 Stanislaus, interview.

259 Charles Huber, e-mail to Commander William Carter and Captain Roger Laferriere, July 13, 2010.

260 Mathy Stanislaus, e-mail to Admiral Paul Zukunft, July 13, 2010.

261 Admiral Paul Zukunft, e-mail to Mathy Stanislaus, July 14, 2010.

262 EPA, “July 11-14 Dispersant Request Summary,” (provided to Commission staff October 21, 2010). 

263 Matthew L. Wald, “Despite Directive, BP Used Dispersant Often, Panel Finds,” New York Times, July 31, 2010; “Allen 

‘Satisfied’ with Dispersant Use in Gulf Oil Disaster,” CNN, August 2, 2010.

264 Interview with U.S. Department of Energy official, October 25, 2010; Interview with Coast Guard official, October 

18, 2010.

265 Interview with U.S. Geological Survey official, October 21, 2010; Interview with U.S. Department of Energy official, 

October 25, 2010; Interview with U.S. Department of Energy official, October 26, 2010.

266 Interview with U.S. Department of Energy official, November 8, 2010.

267 Interview with U.S. Geological Survey official, October 21, 2010.

268 Tooms, interview.

269 Interview with U.S. Department of Energy official, November 8, 2010.

270 Interview with industry expert, October 14, 2010.

271 Interview with U.S. Geological Survey official, October 21, 2010.

272 Secretary Steven Chu, e-mail to Arun Majumdar and others, June 18, 2010; Admiral James Watson, letter to Doug 

Suttles, June 19, 2010.

273 Suttles, interview; Tooms, interview.

274 Daniel Squire, letter to Commission staff, November 2, 2010, att. 3; Lynch, interview; Tooms, interview; Non-public U.S. Department of Energy document, July 6, 2010.

275 Interview with U.S. Geological Survey official, October 20, 2010; Non-public government science advisor document, 

July 2, 2010; Interview with industry expert, October 14, 2010.

276 Admiral Thad Allen, letter to Bob Dudley, July 9, 2010.

277 Suttles, interview.

278 Admiral Thad Allen, letter to Bob Dudley, July 12, 2010.

279 Interview with U.S. Department of Energy official, October 26, 2010; Interview with industry expert, October 28, 

2010.

280 Interview with U.S. Department of Energy official, November 8, 2010; Non-public government science advisor 

document, July 13, 2010.

281 Statement from National Incident Commander Admiral Thad Allen on Well Integrity Test, July 13, 2010.

282 Interview with U.S. Department of Energy official, November 8, 2010.
336 National Commission on the BP Deepwater Horizon OIl Spill and Offshore Drilling

283 Admiral Thad Allen, letter to Bob Dudley, July 14, 2010.

284 Interviews with U.S. Geological Survey official, October 20, 2010; Non-public U.S. Department of Energy document, July 11, 2010. 

285 Non-public government document, July 11, 2010; Interview with U.S. Department of Energy official, October 25, 

2010.

286 Campbell Robertson and Henry Fountain, “BP Says Oil Flow Has Stopped as Cap Is Tested,” New York Times, July 

15, 2010.

287 Interview with U.S. Department of Energy official, November 8, 2010; Non-public U.S. Department of Energy 

document, July 16, 2010; Non-public government science advisor document, July 15, 2010.

288 Interview with U.S. Department of Energy official, October 26, 2010; Interview with Minerals Management Service 

official, October 15, 2010; Interview with U.S. Department of Energy official, October 21, 2010; Non-public government science document, July 15, 2010.

289 Interview with U.S. Department of Energy official, October 25, 2010; Interview with U.S. Department of Energy 

official, October 26, 2010; Interview with U.S. Geological Survey official, October 21, 2010.

290 Interview with Coast Guard official, October, 18, 2010; Interview with U.S. Geological Survey official, October 21, 

2010.

291 Non-public U.S. Department of Energy document, June 30, 2010. 

292 Interview with U.S. Geological Survey official, October 21, 2010; Interview with U.S. Geological Survey official, 

October 21, 2010.

293 Tooms, interview; Interview with U.S. Geological Survey official, October 21, 2010; Interview with U.S. Geological 

Survey official, October 21, 2010.

294 Interview with U.S. Geological Survey official, October 21, 2010.

295 Transcript, Press Briefing by National Incident Commander Admiral Thad Allen and NOAA Administrator Dr. Jane 

Lubchenco, July 24, 2010.

296 Bob Dudley, letter to Admiral Thad Allen, July 19, 2010.

297 Pat Campbell, letter to Richard Lynch, July 28, 2010; Henry Fountain, “Expert is Confident about Sealing Oil Well,” 

New York Times, May 24, 2010; Interview with industry expert, October 14, 2010.

298 Transcript, Press Briefing by National Incident Commander Admiral Thad Allen, August 2, 2010.

299 Press Release, BP, Static Kill Injectivity Testing Commences on MC252 Well, August 3, 2010; Non-public U.S. Department of Energy document, August 3, 2010.

300 Press Release, BP, MC252 Well Reaches Static Condition; Well Monitoring Underway, August 4, 2010.

301 Statement by National Incident Commander Admiral Thad Allen, August, 4 2010.

302 Face the Nation, CBS News, August 8, 2010.

303 Deepwaer Horizon MC252 Gulf Incident Oil Budget (August 4, 2010); Jane Lubchenco et al., BP Deepwater Horizon 

Oil Budget: What Happened to the Oil? (August 4, 2010).

304 Deepwater Horizon MC252 Gulf Incident Oil Budget, 1.

305 Heather Zichal, e-mail to Jane Lubchenco, July 29, 2010.

306 Jane Lubchenco, e-mail to Sean Smith and others, August 4, 2010.

307 Margaret Spring, e-mail to Heather Zichal and others. July 30, 2010.

308 Transcript, Press Briefing by Press Secretary Robert Gibbs, Admiral Thad Allen, Carol Browner, and Dr. Lubchenco, 

August 4, 2010.

309 David A. Fahrenthold, “Scientists Question Government Team’s Report of Shrinking Gulf Oil Spill,” Washington Post, 

August 5, 2010; Katie Howell, “White House, Critics Reach Stalemate in Dispute Over Oil Budget in Gulf,” New York 

Times, August 23, 2010.

310 Editorial, “Do the Math on the Spill,” Times-Picayune, August 6, 2010.

311 Press Conference, Jane Lubchenco Discusses Federal Peer-Reviewed “Oil Budget” Technical Documentation, November 

23, 2010.

312 Press Release, NOAA, Federal Interagency Group Issues Peer-Reviewed ‘Oil Budget’ Technical Documentation, November 23, 2010.

313 Federal Interagency Solutions Group, Oil Budget Science and Engineering Team, Oil Budget Calculator Technical 

Documentation (November 2010).

314 Interview with Coast Guard official, October 24, 2010.

315 Shaw’s Environmental & Infrastructure Group, Shaw Barrier Berm Project—Daily Report Day 44 (July 15, 2010).
Endnotes 337 337

316 Padgett, “Dredge, Baby, Dredge: Can Sand Stop the Oil?”

317 Press Release, Office of the Governor, Governor Jindal Announces Agreement with BP for Seafood Safety, Coastal 

Restoration & Tourism Funding, November 1, 2010. 

318 Cain Burdeau, “EPA: Louisiana’s Sand Berms Not Stopping Much Oil,” Associated Press, September 10, 2010; Mark 

Ballard, “EPA Opposes La. Berms,” Advocate, September 9, 2010; John Maginnis, “Louisiana’s Sand Berms Challenged,” Times-Picayune, September 15, 2010; Interview with government official, September 22, 2010; Transcript, 

Meet the Press, November 21, 2010 (Governor Jindal stating “[w]e’ve collected thousands of pounds of oily debris 

off these berms”); Oil Budget Technical Documentation, 34 (“Based upon past spills, the oil content of collected 

debris mass is only a few percent.”).

319 Bobby Jindal, Leadership and Crisis 6 (Washington, D.C.: Regnery Publishing, Inc., 2010).

320 Statement from Admiral Allen on the Successful Completion of the Relief Well, September 19, 2010.

321 Press Release, NOAA, NOAA Reopens One-Third of Closed Gulf Fishing Area, July 22, 2010; Press Release, NOAA, 

NOAA Reopens More Than 8,000 Square Miles in the Gulf of Mexico to Fishing, November 15, 2010.

322 Kim Murphy, “A Poor Appetite for Gulf Seafood,” Los Angeles Times, August 26, 2010; Interview with government 

official, October 15, 2010.

323 Krissah Thompson, “Waste from BP Oil Spill Cleanup Has Gulf Residents Near Landfills Concerned,” Washington 

Post, August 16, 2010.

324 40 C.F.R. § 261.4(b)(5).

325 Admiral James Watson and Al Armendariz, Recovered Oil, Contaminated Materials and Liquid and Solid Wastes 

Management Directive (June 29, 2010).

326 Elana Schor, “How Has BP’s Oily Waste Escaped ‘Hazardous’ Label?,” New York Times, July 20, 2010.

327 Admiral Paul Zukunft, letter to Doug Suttles, July 24, 2010; BP, “Waste and Recoverable Material Tracking,” http://

www.bp.com/genericarticle.do?categoryId=9034343&contentId=7063466.

328 Schor, “How Has BP’s Oily Waste Escaped ‘Hazardous’ Label?”; EPA, “Waste Sampling Strategy and Results,” http://

www.epa.gov/bpspill/waste.html#sampling_strategy; Stanislaus, interview.

329 EPA, “Waste Management on the Gulf Coastline,” http://www.epa.gov/bpspill/waste.html.

330 Robert Bullard and Al Huang, “Oil’s Toxic Legacy Not Erased,” Politico, August 13, 2010.

331 Lesley Clark and Fred Tasker, “Oil-Soaked Waste Worries Gulf Coast Landfills’ Neighbors,” McClatchy Newspapers, 

July 30, 2010; Robert Bullard, “Government Allows BP to Dump Oil-Spill Waste on Black Communities,” OpEdNews.com, July 22, 2010.

332 Stanislaus, interview.

333 Admiral Paul Zukunft, letter to Mike Utsler, August 9, 2010; Stanislaus, interview.

334 “Statement from Admiral Allen on the Transfer of Oversight Responsibilities, October 1, 2010.

Chapter Six

1 President Barack Obama, “Remarks by the President to the Nation on the BP Oil Spill” (June 15, 2010) http://www.

whitehouse.gov/the-press-office/remarks-president-nation-bp-oil-spill].

2 Campbell Robertson and Clifford Krauss, “Gulf Spill Is the Largest of Its Kind, Scientists Say,” New York Times, August 

2, 2010.

3 EPA, Government Response to the BP Oil Spill: Odors from the BP Spill (June 2010), http://www.epa.gov/bpspill/

reports/odorfactsheet.pdf (announcing help line for residents experiencing oil-related odors); Press Release, NOAA, 

Administration Launches Dockside Chats to Promote Gulf Seafood Safety Awareness, August 25, 2010, http://www.

restorethegulf.gov/release/2010/08/25/administration-launches-dockside-chats-promote-gulf-seafood-safetyawareness; BP, Claims and Government Payments Gulf of Mexico Oil Spill Public Report (November 18, 2010).

4 Testimony of Timothy Ragen, Executive Director of the U.S. Marine Mammal Commission, “The Short and LongTerm Impacts of the Deepwater Horizon Oil Spill,” Hearing Before the House Subcommittee on Insular Affairs, 

Oceans, and Wildlife, 111th Congress (June 10, 2010); Kim B. Ritchie and Brian D. Keller, eds., A Scientific Forum on 

the Gulf of Mexico: The Islands in the Stream Concept (NOAA, January 23, 2008), 6–8; Elliott A. Norse and John 

Amos, “Impacts, Perception, and Policy Implications of the Deepwater Horizon Oil and Gas Disaster,” Environmental 

Law Reporter 40, no. 11 (2010): 11071; Deepwater Horizon Oil Spill: Scientific Symposium Meeting Summary

(Consortium for Ocean Leadership, June 23, 2010), 15–16.

5 Federal Interagency Solutions Group, Oil Budget Science and Engineering Team, Oil Budget Calculator Technical 

Documentation (November 2010).

6 Curtis Morgan, “Another sign of oil spill recovery in the Gulf: Oil in the Gulf has dissipated and degraded into barely 

detectable concentrations, although federal scientists say it’s too soon to say the threat is over,” Miami Herald, 
338 National Commission on the BP Deepwater Horizon OIl Spill and Offshore Drilling

September 8, 2010.

7 Brian Hamacher, “Wind Keeps Oil From Loop Current & Away From Florida Shores,” Associated Press, July 19, 2010.

8 Richard Camilli et al., “Tracking Hydrocarbon Plume Transport and Biodegradation at Deepwater Horizon,” Science

330, no. 6001 (2010): 201–204; David Valentine et al., “Propane Respiration Jump-Starts Microbial Response to a 

Deep Oil Spill,” Science 330, no. 6001 (2010): 204–208; Terry Hazen et al., “Deep-Sea Oil Plume Enriches Indigenous 

Oil-Degrading Bacteria”, Science 330, no. 6001 (2010): 208–211.

9 Alan Krupnick et al., “A Framework for Understanding the Costs and Benefits of Deepwater Drilling Regulation” 

(DRAFT) (Resources for the Future, 2010). 

10 Leslie Kaufman and Shaila Dewan, “Gulf May Avoid Direst Predictions After Oil Spill,” New York Times, September 

13, 2010. 

11 NOAA, Other Significant Oil Spills in the Gulf of Mexico, http://sero.nmfs.noaa.gov/sf/deepwater_horizon/1890_

HistoricalSpillsGulfofMexico.pdf.

12 Darryl L. Felder and David K. Camp, Gulf of Mexico Origin, Waters, and Biota: Volume I, Biodiversity (Corpus Christi, 

TX: Texas A&M University Press, 2009).

13 Ibid.

14 Christine Ribic et al., “Distribution of Seabirds in the Northern Gulf of Mexico in Relation to Mesoscale Features: 

Initial Observations,” ICES Journal of Marine Science 54 (1997): 545–551.

15 S. Heileman and N. Rabalais, Gulf of Mexico: Large Marine Ecosystem Brief #5 (NOAA, 2009), http://www.lme.

noaa.gov/index.php?option=com_content&view=article&id=51:lme5&catid=41:briefs&Itemid=72.

16 David Biello, “The BP Spill’s Growing Toll on the Sea Life of the Gulf,” Yale Environment 360, June 9, 2010, http://

e360.yale.edu/content/feature.msp?id=2284.

17 Holly K. Ober, Effects of Oil Spills on Marine and Coastal Wildlife (University of Florida, May 2010).

18 International Bird Rescue Research Center, How Oil Affects Birds: Just a little bit of oil can be deadly (2010), http://

www.ibrrc.org/pdfs/IBRRC-How-oil-affects-birds.pdf. 

19 Camilli et al., “Tracking Hydrocarbon Plume Transport,” 201–204.

20 Oil Budget Calculator Technical Documentation.

21 White House, Ongoing Administration-Wide Response to the Deepwater BP Oil Spill: By the Numbers to Date (August 

23, 2010), http://www.restorethegulf.gov/release/2010/08/23/ongoing-administration-wide-response-deepwaterbp-oil-spill.

22 Unified Area Command, Shoreline Clean-up and Assessment Technique (SCAT) Map -- Maximum Oiling by Zone: 

Florida, November 11, 2010.

23 Audubon Society, Oil and Birds: Too Close for Comfort. Louisiana’s Coast Six Months into the BP Disaster (October 

2010).

24 Dr. Holly Bik (University of New Hampshire), interview with Commission staff, October 28, 2010.

25 NOAA, Environmental Sensitivity Index: Alabama (August 2007), 1, http://response.restoration.noaa.gov/book_

shelf/1458_SampleESI_AL2007.pdf.

26 Joseph Dineen, Tidal Flat Habitats (Smithsonian Institution, 2010), http://www.sms.si.edu/irlspec/Tidal_Flats.htm.

27 V. Grossi et al., “Burial, Exportation and Degradation of Acyclic Petroleum Hydrocarbons Following a Simulated Oil 

Spill in Bioturbated Mediterranean Coastal Sediments,” Chemosphere 48, no. 9 (2002): 947–954.

28 Qianxin Lin and Irving Mendelssohn, “Evaluation of Tolerance Limits for Restoration and Phytoremediation with 

Spartina Alterniflora in Crude Oil-Contaminated Coastal Salt Marshes,” in Proceedings of the 2008 International 

Oil Spill Conference (Washington, D.C.: American Petroleum Institute, 2008), 869-874, http://www.iosc.org/papers/2008%20148.pdf. 

29 Jeffrey Ball, “Storm-Tossed Boom Complicates Spill Cleanup,” Wall Street Journal, July 27, 2010.

30 Dr. Eugene Turner (Professor, Louisiana State University), e-mail to Commission staff, November 24, 2010.

31 Dr. Eugene Turner (Professor, Louisiana State University), interview with Commission staff, November 4, 2010.

32 Bob Marshall, “Oysters are uniquely sensitive to Gulf of Mexico oil spill,” Times-Picayune, May 25, 2010. 

33 NOAA, MC252 Shoreline Current Oiling Situation Map – LA: As of 8/03/2010; Louisiana Department of Wildlife and 

Fisheries, Oil Spill Response: Closure Maps, http://www.wlf.louisiana.gov/oilspill.

34 Nicole Santa Cruz and P.J. Huffstutter, “Effort to Keep Oil Spill at Bay Tips Ecological Balance,” Los Angeles Times, 

August 3, 2010. 

35 L. Scott Mills, Michael E. Soule and Daniel F. Doak, “The keystone-species concept in ecology and conservation,” 

BioScience 43, no. 4 (1993): 219–224.

36 Mississippi Department of Marine Resources, Rebuilding Mississippi’s Oyster Reefs (Fall 2009).

37 Scott McMillion, The Reef Makers (Nature Conservancy, 2010).
Endnotes 339 339

38 “The effect of the oil spill on Gulf fisheries: An Interview with Harriet Perry,” Mississippi Public Broadcasting, August 

17, 2010.

39 Harriet Perry, interview with Commission staff, October 28, 2010.

40 Ibid.

41 16 U.S.C. § 1802(10). 

42 NOAA, Affected Gulf Resources (2010), http://www.gulfspillrestoration.noaa.gov/oil-spill/affected-gulf-resources/.

43 NOAA, Bioaccumulation of Oil Chemicals in Seafood (May 2010).

44 Ibid.

45 Biello, “The BP Spill’s Growing Toll On the Sea Life of the Gulf.” 

46 NOAA, Affected Gulf Resources; National Incident Command Joint Analysis Group, Review of Preliminary Data to 

Examine Oxygen Levels In the Vicinity of MC252#1: May 8 to August 9, 2010 (August 16, 2010).

47 NOAA, Mississippi Canyon 252 Incident: Work Plan for the Collection of Data to Determine Impacts of the Deepwater 

Horizon Mississippi Canyon 252 Incident on Endangered and Protected Marine Mammals in the Northern Gulf (June 

14, 2010); NOAA, Mississippi Canyon 252 Incident: Preassessment Plan to Determine Potential Exposure and Injuries 

of Nesting and Hatchling Loggerhead Sea Turtles (July 28, 2010); NOAA, Mississippi Canyon 252: Preassessment 

plan to Determine Potential Exposure and Injuries of Nesting and Hatchling Kemp’s Ridley Turtles (August 31, 2010; 

Testimony of Steve Murawski (NOAA Director of Scientific Programs), Hearing before the National Commission, 

September 28, 2010.

48 “Bluefin Tuna Hit Hard by ‘Deepwater Horizon’ Disaster,” European Space Agency News, October 18, 2010, http://

www.esa.int/esaCP/SEM1K4WO1FG_index_0.html.

49 Mike Soraghan, “As Spill Drifts Toward Gulf Shores, Oil Companies Brace for Political Whirlwind,” New York Times, 

April 29, 2010. 

50 Unified Area Command, Deepwater Horizon Response Consolidated Fish and Wildlife Collection Report (November 1, 

2010).

51 Steve Hampton, Estimating Bird Mortality (California Department of Fish and Game, November 2004).

52 Testimony of Jane Lyder, Deputy Assistant Secretary Fish and Wildlife and Parks, Hearing before the National Commission, September 28, 2010. 

53 Our Natural Resources at Risk: The Short and Long-Term Impacts of the Deepwater Horizon Oil Spill, Before the 

House Subcommittee on Insular Affairs, Oceans, and Wildlife, 111th Cong. (June 10, 2010) (Statement of Timothy 

Ragen, Executive Director of the U.S. Marine Mammal Commission).

54 NOAA, Affected Gulf Resources.

55 Unified Area Command, Deepwater Horizon Response Consolidated Fish and Wildlife Collection Report. 

56 NOAA, Sea Turtles, Dolphins, and Whales and the Gulf of Mexico Oil Spill (2010), http://www.nmfs.noaa.gov/pr/

health/oilspill.htm.

57 Joseph Schuman, “Dead Sperm Whale Found Near BP Oil Spill,” AOL News, June 17, 2010.

58 NOAA, Sea Turtles, Dolphins, and Whales and the Gulf of Mexico Oil Spill.

59 Camilli et al., “Tracking Hydrocarbon Plume Transport”; Valentine et al., “Propane Respiration Jump-Starts Microbial 

Response to a Deep Oil Spill”; Hazen et al., “Deep-Sea Oil Plume Enriches Indigenous Oil-Degrading Bacteria.”

60 National Incident Command Joint Analysis Group, Review of Preliminary Data to Examine Oxygen Levels In the 

Vicinity of MC252#1: May 8 to August 9, 2010 (August 16, 2010).

61 Ibid.

62 Ibid.

63 A. Diercks et al., “Characterization of Subsurface Polycyclic Aromatic Hydrocarbons at the Deepwater Horizon Site,” 

Geophysical Research Letters 37 (2010).

64 Oil Budget Calculator Technical Documentation.

65 Cain Burdeau and Seth Borenstein, “Where’s the oil? On the Gulf floor, scientists say,” Associated Press, September 13, 

2010; Steve Newborn, “Oil Found Deep in Gulf is Toxic to Tiny Marine Life,” WUSF News, August 17, 2010, http://

www.wusf.usf.edu/news/2010/08/17/oil_found_deep_in_gulf_is_toxic_to_tiny_marine_life.

66 Mark Schrope, “Oil spill cruise finds field of dead coral: Scientific Expedition Assesses Deep-Sea Damage in the Gulf of 

Mexico,” Nature News, November 5, 2010, http://www.nature.com/news/2010/101105/full/news.2010.589.html.

67 NOAA, “10 Famous Spills” (NOAA Incident News), http://www.incidentnews.gov/famous.

68 Kim B. Ritchie and Brian D. Keller, eds., A Scientific Forum on the Gulf of Mexico: The Islands in the Stream Concept

(NOAA, January 23, 2008), 6–8; John Farrington and Judith McDowell, “Mixing Oil and Water: Tracking the Sources 

and Impacts of Oil Pollution in the Marine Environment,” Oceanus Magazine 42, no. 3 (2004): 1–4, http://www.
340 National Commission on the BP Deepwater Horizon OIl Spill and Offshore Drilling

whoi.edu/cms/files/dfino/2005/4/v42n3-farrington_2285.pdf; Elliott A. Norse and John Amos, “Impacts, Perception, and Policy Implications of the Deepwater Horizon Oil and Gas Disaster,” Environmental Law Reporter 40, no. 

11 (2010): 11071; Deepwater Horizon Oil Spill: Scientific Symposium Meeting Summary (Consortium for Ocean 

Leadership, June 23, 2010), 15–16. 

69 33 U.S.C. § 2706.

70 15 C.F.R. § 990.30; NOAA, Injury Assessment: Guidance Document for Natural Resource Damage Assessment Under 

the Oil Pollution Act of 1990 (August 1996).

71 NOAA, Gulf Spill Restoration: Co-Trustees (2010), http://www.gulfspillrestoration.noaa.gov/about-us/co-trustees/. 

72 Discharge of Oil From Deepwater Horizon/Macondo Well, Gulf of Mexico; Intent to Conduct Restoration Planning, 75 

Fed. Reg. 60,800 (Oct. 1, 2010).

73 NOAA, Gulf Spill Restoration: Co-Trustees. 

74 15 C.F.R. § 990.10.

75 15 C.F.R. § 990.30.

76 Ritchie and Keller, eds., A Scientific Forum on the Gulf of Mexico: The Islands in the Stream Concept, 6–8.

77 15 C.F.R. § 990.30; NOAA, Injury Assessment: Guidance Document for Natural Resource Damage Assessment Under 

the Oil Pollution Act of 1990. 

78 S.M. Gagliano, “Canals, Dredging, and Land Reclamation in the Louisiana Coastal Zone” in Hydrologic and Geologic 

Studies of Coastal Louisiana, Report no. 14 (Center for Wetland Studies, Louisiana State University, 1973); Robert A. 

Morton et al., Rapid Subsidence and Historical Wetland Loss in the Mississippi Delta Plain: Likely Causes and Future 

Implications (U.S. Geological Survey, 2005); Testimony of Senator Mary Landrieu, Louisiana, Hearing before the 

National Commission, September 28, 2010.

79 NOAA, Deepwater BP Oil Spill, Natural Resource Damage Assessment: NRDA by the Numbers, November 1, 2010, 

http://www.gulfspillrestoration.noaa.gov/wp-content/uploads/2010/11/FINAL-NRDA_by_the_Numbers_11.03.

pdf.pdf. 

80 NOAA, Mississippi Canyon 252 Incident: Work Plan for the Collection of Data to Determine Impacts of the Deepwater 

Horizon; NOAA, Mississippi Canyon 252 Incident on Endangered and Protected Marine Mammals in the Northern 

Gulf; NOAA, Mississippi Canyon 252 Incident: Preassessment Plan to Determine Potential Exposure and Injuries of 

Nesting and Hatchling Loggerhead Sea Turtles; NOAA, Mississippi Canyon 252: Preassessment plan to Determine 

Potential Exposure and Injuries of Nesting and Hatchling Kemp’s Ridley Turtles; Testimony of Steve Murawski, 

September 28, 2010.

81 Shaila Dewan, “The Oil Spill’s Money Squeeze,” New York Times, September 12, 2010.

82 Press Release, National Science Foundation, Gulf Oil Spill: NSF Awards Grant to Study Effects of Oil and Dispersants 

on Louisiana Salt Marsh Ecosystem, August 16, 2010.

83 Phil Taylor (Head, Oceans Section, Division of Ocean Sciences, National Science Foundation), e-mail to Commission 

staff, December 9, 2010.

84 Dewan, “The Oil Spill’s Money Squeeze.” 

85 Press Release, BP, BP and the Gulf of Mexico Alliance Announce Implementation of BP’s $500 Million Independent 

Research Initiative, September 29, 2010, http://www.bp.com/genericarticle.do?categoryId=2012968&content

Id=7065262. 

86 Sea Grant, Oil Spill in the Gulf of Mexico: Deepwater Horizon Oil Spill Research and Monitoring Activities Database

(2010), http://gulfseagrant.tamu.edu/oilspill/database.htm. 

87 “Gulf Seafood Industry Works to Wipe Oil Off Image,” National Public Radio, August 20, 2010; Louisiana Office of 

Tourism, Regional Effects on Perception/BP Oil Spill Survey Wave 1 Results (June 30, 2010); University of Minnesota Food Industry Center, “Continuous Consumer Confidence in Food Safety/Defense Tracking” (presentation, FDA 

Symposium, September 16, 2010).

88 U.S. Census Bureau: 2007 Economic Census, 2007 Summary Tables: Selected Statistics by Economic Sector. 

89 NOAA, Deepwater Horizon/BP Oil Spill: Federal Fisheries Closure and Other Information (2010), http://sero.nmfs.

noaa.gov/deepwater_horizon_oil_spill.htm.

90 Testimony of Timothy Fitzgerald, Environmental Defense Fund, Hearing before the National Commission, September 

28, 2010.

91 Testimony of Lt. Gov. Scott Angelle, Louisiana, Hearing before the National Commission, September 28, 2010.

92 Campbell Robertson, “As Claims for Spill Losses Shift to Administrator, Queries Follow,” New York Times, August 23, 

2010. 93 Rob Shaw, “Clearwater BP Office Shells out for Claims,” Tampa Bay Online, August 8, 2010, http://www2.tbo.com/

content/2010/aug/08/na-clearwater-bp-office-shells-out-for-claims/.

94 David Fahrenthold and Kimberly Kindy, “Six Months After the Spill, BP’s Money is Changing the Gulf as Much as the 

Oil,” Washington Post, October 20, 2010.

95 Inter-Agency Economic Report: Estimating the Economic Effects of the Deepwater Drilling Moratorium on the Gulf 
Endnotes 341 34

Coast Economy (September 16, 2010), http://www.esa.doc.gov/drilling_moratorium.pdf.

96 Press Release, BP, BP Establishes $20 Billion Claims Fund for Deepwater Horizon Spill and Outlines Dividend Decisions, 

June 16, 2010, http://www.bp.com/genericarticle.do?categoryId=2012968&contentId=7062966; Steven Mufson, 

“BP Details Plan for $20 Billion Claim Fund for Oil Spill in the Gulf of Mexico,” Washington Post,” June 17, 2010.

97 Gulf Coast Claims Facility, GCCF Program Statistics - Overall Summary, November 23, 2010.

98 Kenneth Feinberg, Final Report of the Special Master for the September 11th Victim Compensation Fund of 2001, 

Volume 1 (2010). 

99 33 U.S.C. § 2702(b)(2)(E). The Oil Pollution Act recognizes the following categories of damages: (1) injury to natural 

resources (recoverable by federal or state trustees); (2) loss of real or personal property and any resultant economic 

losses (recoverable by an owner of that property); (3) loss of subsistence use of natural resources (recoverable by a 

subsistence user); (4) loss of revenues resulting from destruction of property or natural resource injury (recoverable 

by a government claimant); (5) loss of profits or impairment of earning capacity resulting from property loss or 

natural resource injury (recoverable by any claimant); and (6) costs of providing extra public services during or after 

spill response (recoverable by a government claimant); 33 U.S.C. § 2702(b)(2). 

100 David Segal, “Should BP’s Money Go Where the Oil Didn’t?,” New York Times, October 23, 2010 (noting that Kenneth Feinberg has “hired one of the country’s foremost scholars on torts . . . to write a memorandum about the 

validity and value of proximity claims.”). 

101 John Flesher, “Gold Rush On The Gulf: Researchers Clamor For Cash,” ABC News, September 29, 2010.

102 Mary Rickard, “Gulf Coast oil spill chills seafood industry,” Reuters, May 12, 2010; Kat Kinsman and Sarah LeTrent, 

“Gulf Coast Chefs, Fishermen Fight Tide of Misinformation,” CNN, May 12, 2010.

103 NOAA, NOAA’s Oil Spill Response: Fish Stocks in the Gulf of Mexico (May 12, 2010), http://www.response.restoration.noaa.gov/book_shelf/1886_Fish-Stocks-Gulf-fact-sheetv2.pdf.

104 U.S. Energy Information Administration, Gulf of Mexico Fact Sheet (October 2010), http://www.eia.doe.gov/special/gulf_of_mexico/index.cfm.

105 EPA, General Facts about the Gulf of Mexico, http://www.epa.gov/gmpo/about/facts.html#resources.

106 NOAA, The Gulf of Mexico at a Glance: A Tool for the Gulf of Mexico Alliance and the American Public (June 2008), 

http://gulfofmexicoalliance.org/pdfs/gulf_glance_1008.pdf. 

107 U.S. Census Bureau: 2007 Economic Census, Statistics by Economic Sector. Compiled data from Gulf coast counties using the following industry codes: 451110, 487210, 713990, 114210, 721214, 532292, 721110, 721120, 

712190, 721199, 114111, 114112, 114119, 311711, 311712, 424490, 445220, 424420, 424460. 

108 NOAA, NOAA’s Oil Spill Response: Fish Stocks in the Gulf of Mexico (May 12, 2010), http://www.response.restoration.noaa.gov/book_shelf/1886_Fish-Stocks-Gulf-fact-sheetv2.pdf.

109 Ibid.

110 NOAA, Deepwater Horizon/BP Oil Spill: Size and Percent Coverage of Fishing Area Closures Due to BP Oil Spill

(2010), http://sero.nmfs.noaa.gov/ClosureSizeandPercentCoverage.htm. 

111 NOAA, Protocol for Interpretation and Use of Sensory Testing and Analytical Chemistry Results for Re-Opening OilImpacted Areas Closed to Seafood Harvesting (June 18, 2010). 

112 NOAA, Deepwater Horizon/BP Oil Spill: Size and Percent Coverage of Fishing Area Closures Due to BP Oil Spill.

113 Rob Holbert, “Spreading the Word about Gulf Seafood,” Lagniappe 215, October 5, 2010.

114 Testimony of William Walker, Executive Director Mississippi Department of Marine Resources, Hearing before the 

National Commission, September 28, 2010.

115 Remarks of Jane Lubchenco, NOAA Administrator, American Bar Association’s Section of Environment, Energy, and Resources Law Summit, New Orleans, September 30, 2010, http://www.noaanews.noaa.gov/stories2010/20101001_lubchenco_seer.html. 

116 Brad Jacobson, “Is Gulf Seafood Really Safe to Eat? Government Withholding Key Data on Seafood Testing, Scientists 

Say,” AlterNet, October 7, 2010, http://www.alternet.org/food/148433/is_gulf_seafood_really_safe_to_eat_government_withholding_key_data_on_seafood_testing,_scientists_say.

117 Travis Pillow, “Low Ball Spill Estimates May Have Hurt Florida Tourism,” The Florida Independent, October 7, 2010.

118 Testimony of Timothy Fitzgerald, Environmental Defense Fund, Hearing before the National Commission, September 

28, 2010.

119 Jean R. Kinsey et al., “Index of Consumer Confidence in the Safety of the Food System,” American Journal of Agricultural Economics 91, No. 5 (2009): 1470–1476 (citing H.G. Zucker, “The Variable Nature of News Media Influence,” in Communication Yearbook 2, ed. B.D. Ruben [New Brunswick, NJ: Transaction Books, 1978], 225–40).

120 Holbert, “Spreading the Word about Gulf Seafood.” 

121 Wendy Kaufman, “Gulf Seafood Industry Works to Wipe Oil Off Image,” National Public Radio, August 20, 2010.

122 Press Release, NOAA, NOAA and FDA Announce Chemical Test for Dispersant in Gulf Seafood; All Samples Test Within Safety Threshold, October 29, 2010, http://www.noaanews.noaa.gov/stories2010/20101029_seafood.html.
342 National Commission on the BP Deepwater Horizon OIl Spill and Offshore Drilling

123 Press Release, BP, Seafood Safety, Tourism and Coastal Restoration Funding Announced, November 1, 2010, http://

www.louisianagulfresponse.com/go/doc/3047/940587/; Press Release, Florida Department of Agriculture and Consumer Services, Bronson Announces That BP Will Pay $20 Million To Fund Seafood Inspections, Marketing Efforts In 

Wake Of Oil Spill, October 25, 2010. http://www.doacs.state.fl.us/press/2010/10252010_2.html.

124 Paul Quinlan, “Gulf Spill: Ala., La. fighting over potential billions in BP penalties,” Energy & Environment Daily, 

November 23, 2010.

125 U.S. Census Bureau: 2007 Economic Census, Statistics by Economic Sector. Compiled data from Gulf coast counties using the following industry codes: 451110, 487210, 713990, 114210, 721214, 532292, 721110, 721120, 

712190, 721199. 

126 Ibid.

127 Testimony of Keith Overton, Louisiana Shrimp Association, Hearing before the National Commission, July 12, 2010.

128 Testimony of Michael Hecht, President Greater New Orleans Inc., Hearing before the National Commission, July 12, 

2010.

129 Louisiana Office of Tourism, Effects on Perception/BP Oil Spill Survey Wave 2 Results (August 16, 2010), http://crt.

louisiana.gov/tourism/research/Documents/2010-11/NationalOilSpillReport20100816.pdf.

130 Matthew R. Lee and Troy C. Blanchard, Health Impacts of Deepwater Horizon Oil Disaster on Coastal Louisiana Residents (Louisiana State University, July 2010), http://www.lsu.edu/pa/mediacenter/tipsheets/spill/publichealthreport_2.pdf. 

131 Ibid.

132 Brian Skoloff, “Final Well Sealing Small Comfort to Gulf Residents,” ABC News, Sept. 16, 2010.

133 Testimony of Grace Scire, Gulf Coast Regional Director, Boat People SOS, Hearing before the National Commission, 

July 13, 2010. 

134 Administration health officials (Department of Human Health Services, National Institute of Health, National 

Institute of Environmental Health Sciences, and Occupational Safety and Health Administration), interviews with 

Commission staff, October 5, 2010.

135 Dan Witters, “Gulf Coast Residents Worse Off Emotionally after BP Oil Spill,” Gallup, September 28, 2010, http://

www.gallup.com/poll/143240/gulf-coast-residents-worse-off-emotionally-oil-spill.aspx. 

136 Jonathan White (Program policy Analyst, Administration for Children & Families), e-mail to Commission staff, 

November 16, 2010.

137 David Abramson et al., Impact on Children and Families of the Deepwater Horizon Oil Spill: Preliminary Findings of 

the Coastal Population Impact Study (National Center for Disaster Preparedness, August 3, 2010).

138 Matthew Lee et al., Health Impacts of Deepwater Horizon Oil Disaster on Coastal Louisiana Residents, (Louisiana 

State University, July 2010).

139 Abramson et al., Impact on Children and Families of the Deepwater Horizon Oil Spill.

140 Ibid.,9.

141 Ibid.

142 Testimony of Grace Scire.

143 Sharon Cohen, “Vietnamese ‘Lost’ as Gulf Oil Spill Hits Community Hard,” Associated Press, July 11, 2010.

144 Hearing on Ensuring Justice for Victims of the Gulf Coast Oil Disaster, Before the Committee on the Judiciary, 111th 

Cong. (2010) (statement of Kenneth Feinberg, Administrator, Gulf Coast Claims Facility).

145 Hearing before the National Commission, Panel 5: Community and Ecological Impacts, July 13, 2010.

146 Brenda Robichaux (Houma Nation), interview with Commission staff, October 2010.

147 Lawrence Palinkas et al., “Community Patterns of Psychiatric Disorders after the Exxon Valdez Oil Spill,” American 

Journal of Psychiatry 150 (1993): 1517-1523.

148 Ibid.

149 Catalina Arata et al., “Coping with Technological Disaster: An Application of the Conservation of Resources Model to 

the Exxon Valdez Oil Spill,” International Society for Traumatic Stress 13, no. 1 (2000): 23–39.

150 Stephen Braud and Jack Kruse, eds., Synthesis: Three Decades of Research on Socioeconomic Effects Related to Offshore Petroleum Development in Coastal Alaska (Minerals Management Service, May 2009), 306.

151 Gina Solomon and Sarah Janssen, “Health Effects of the Gulf Oil Spill,” Journal of the American Medical Association 

304, no. 10 (2010): 1118–1119. 

152 Hearing on Ensuring Justice for Victims of the Gulf Coast Oil Disaster, Before the Committee on the Judiciary, 111th 

Cong. (2010) (statement of Kenneth Feinberg, Administrator, Gulf Coast Claims Facility).

153 SAMSA, “Gulf States Receive $52 Million from BP for Behavioral Health,” SAMSA News 18, no. 4 (July/August 

2010), http://www.samhsa.gov/samhsanewsletter/Volume_18_Number_4/GulfStates.aspx.
Endnotes 343 343

154 National Institutes of Health officials, interviews with Commission staff, October 2010. 

155 Louisiana Office of Public Health, State Narrative for Louisiana: Maternal and Child Health Title V Block Grant, 

Application for 2008/Annual Report for 2006 (October 4, 2007); See also “Agenda, Interagency Meeting – Gulf Oil 

Spill Workers’ Study” (NIH Campus, Bethesda, Maryland, August 19, 2010), http://www.niehs.nih.gov/about/od/

programs/docs/agenda-aug19-2010.pdf.

156 Editorial, “Ruling in Charity Hospital case is a significant victory: An editorial,” Times-Picayune, April 4, 2010. 

157 Robin Rudowitz, Diane Rowland, and Adele Shartzer, “Health Care In New Orleans Before and After Hurricane Katrina,” Health Affairs 25, no. 5 (2006): 393–406.

158 Ibid.

159 Louisiana Office of Public Health, State Narrative for Louisiana: Maternal and Child Health Title V Block Grant.

160 U.S. Government Accountability Office, Hurricane Katrina: Federal Grants Have Helped Health Care Organizations 

Provide Primary Care, but Challenges Remain (July 2009).

161 Karen B. DeSalvo, “Community Health Clinics: Bringing Quality Care Closer to New Orleanians,” in The New Orleans Index at Five, Amy Liu and Allison Plyer, eds. (Brookings Institution, August 2010).

Chapter Seven

1 Louisiana Coastal Protection and Restoration Authority, Fiscal Year 2011 Annual Plan: Integrated Ecosystem 

Restoration and Hurricane Protection in Coastal Louisiana (April 2010), 2–3.

2 U.S. Environmental Protection Agency, Mississippi River Gulf of Mexico Watershed Nutrient Task Force, Hypoxia 101, 

http://www.epa.gov/owow_keep/msbasin/hypoxia101.htm.

3 Complaint at ¶ 28, Louisiana v. Triton Asset Leasing GmBH al., No. 2:10-cv-03059 (E.D. La. September 14, 2010). 

4 Ray Mabus, America’s Gulf Coast: A Long Term Recovery Plan after the Deepwater Horizon Oil Spill (September 28, 

2010).

5 Charles Simenstad et al., “When is Restoration Not? Incorporating Landscape-Scale Processes to Restore Self-Sustaining 

Ecosystems in Coastal Wetland Restoration,” Ecological Engineering 26, no. 1 (2006): 28, 31.

6 For background about “resiliency,” see C.S. Holling, “Resilience and Stability of Ecological Systems,” Annual Review of 

Ecology and Systematics 24 (1973): 1–23.

7 Mabus, America’s Gulf Coast: A Long Term Recovery Plan after the Deepwater Horizon Oil Spill, 26.

8 U.S. Geological Survey, The Gulf of Mexico Hypoxic Zone, http://toxics.usgs.gov/hypoxia/hypoxic_zone.html. 

9 Mississippi River/Gulf of Mexico Watershed Nutrient Task Force, Gulf Hypoxia Action Plan 2008—For Reducing, 

Mitigating, and Controlling Hypoxia in the Northern Gulf of Mexico and Improving Water Quality in the Mississippi 

River Basin (2008).

10 Bureau of Ocean Energy Management, Regulation and Enforcement, Leasing, http://www.gomr.boemre.gov/

homepg/lsesale/lsesale.html.

11 Executive Order 13547, Stewardship of the Ocean, Our Coasts, and the Great Lakes, 75 Fed. Reg. 43023, July 22, 

2010.

12 White House Council on Environmental Quality, Final Recommendations of the Interagency Ocean Policy Task Force

(July 19, 2010).

13 For an overview of issues in Gulf of Mexico marine policy, see Linwood Pendleton, Larry Crowder, Daniel Dunn, Clare 

Fieseler, Morgan Gopnik, Catherine Latanich, Mike Orbach, Steve Roady, Mary Turnipseed, Cindy van Dover, “Marine 

Protection in the Gulf of Mexico: Current Policy, Future Options, and Ecosystem Outcomes,” Policy Brief, Nicholas 

Institute for Environmental Policy Solutions, Duke University (October 2010). Elliott Norse (Marine Conservation 

Biology Institute), interview with Commission staff, October 18, 2010; Larry McKinney (Harte Institute for Gulf 

of Mexico Studies), interview with Commission staff, October 18; 2010 Sandra Whitehouse (Ocean Conservancy), 

interview with Commission staff, October 20, 2010; Deerin Babb-Brott (Massachusetts Office of Coastal Zone 

Management), interview with Commission staff, October 21, 2010; Barry Gold (Moore Foundation), interview with 

Commission staff, Sept. 13, 2010.

14 NOAA, Coastal and Marine Spatial Planning Examples, http://www.msp.noaa.gov/examples/index.html.

15 United Nations Educational, Scientific and Cultural Organization (UNESCO), Marine Spatial Planning Initiative: Norway, http://www.unesco-ioc-marinesp.be/spatial_management_practice/norway.

16 Bureau of Ocean Energy Management, Regulation and Enforcement, Outer Continental Shelf Lands Act, http://www.

gomr.boemre.gov/homepg/regulate/regs/laws/ocslasht.html.

17 For geospatial maps on uses of Gulf resources, see NOAA, Multipurpose Marine Cadastre, http://csc-s-web-p.csc.

noaa.gov/MMC.

18 Cornelius Hammer et al., “Framework of stock-recovery strategies: analyses of factors affecting success and failure,” 
344 National Commission on the BP Deepwater Horizon OIl Spill and Offshore Drilling

ICES Journal of Marine Science 67 (2010): 1849–1855.

19 For background overview of deltaic science described in this section, see, e.g., Committee on the Restoration and 

Protection of Coastal Louisiana, Drawing Louisiana’s New Map: Addressing Land Loss in Coastal Louisiana (National 

Research Council, 2006), 29–42; James M. Coleman, Harry H. Roberts, and Gregory W. Stone, “Mississippi River 

Delta: An Overview,” Journal of Coastal Research 14, no. 3 (1998): 698–716; John W. Day Jr. et al., “Restoration of 

the Mississippi Delta: Lessons from Hurricanes Katrina and Rita,” Science 315, no. 5819 (2007): 1679–1684.

20 “Storm Death Toll at 31 as Floodwaters Recede,” CNN, May 6, 2010; Paul Kemp, “Use the Mississippi River to stop 

the oil,” CNN, June 13, 2010. The approximate travel time of water along the Ohio and then Mississippi Rivers can 

be estimated by noting the sequence of peak water levels along the river, in the National Weather Service’s Lower 

Mississippi River Forecast Center, particularly the summary data for weeks ending in May 5, 2010, and May 12, 

2010. River Summary Archives for these dates and the rest of 2010 can be found here: http://www.srh.noaa.gov/

lmrfc/?n=riversummaryarchive.

21 For description of Atchafalaya diversion, see, e.g., Martin Reuss, Designing the Bayous: The Control of Water in the 

Atchafalaya Basin, 1800-1995 (Alexandria, VA: Texas A&M University Press, 2004).

22 U.S. Geological Survey, Northern Gulf of Mexico (NGOM) Ecosystem Change and Hazard Susceptibility Project—

Overview (2010), http://ngom.usgs.gov/overview/intro.html.

23 Kevin Kosar, Disaster Response and Appointment of a Recovery Czar: The Executive Branch’s Response to the Flood of 

1927 (Congressional Research Service, 2005).

24 33 U.S.C. § 702c (1928).

25 U.S. Army Corps of Engineers, The Mississippi River & Tributaries (Mr&T) Project (2010), http://www.mvn.usace.

army.mil/bcarre/missproj.asp.

26 Testimony of Senator Mary Landrieu, Louisiana, Hearing before the National Commission, September 28, 2010.

27 Coastal Wetlands Planning, Protection, And Restoration Act: Summary of Wetland Benefits for Priority List Projects 

(2010), http://www.lacoast.gov/reports/wva/CWPPRA%20project%20benefits%202010-06-18.pdf; U.S. Army 

Corps of Engineers, Louisiana Coastal Area Ecosystem Restoration Plan (2010), http://www.lca.gov/.

28 Robert H. Meade and John A. Moody. “Causes for the decline of suspended-sediment discharge in the Mississippi River 

system, 1940-2007,” Hydrological Process 24 (2010): 35–49; Robert B. Jacobson, Dale W. Blevins and Chance J. 

Bitner, “Sediment Regime Constraints on River Restoration—an Example from the Lower Missouri River,” Geological 

Society of America Special Papers 451 (2009): 1–22.

29 Day et al., “Restoration of the Mississippi Delta: Lessons from Hurricanes Katrina and Rita,” 1682.

30 Robert Morton et al., Rapid Subsidence and Historical Wetland Loss in the Mississippi Delta Plain: Likely Causes and 

Future Implications, (U.S. Geological Survey, 2005). 

31 John Barras et al., Land Area Change in Coastal Louisiana—a Multidecadal Perspective (from 1956 to 2006) (U.S. 

Geological Survey, 2008). 

32 Torbjorn Tornqvist et al., “Mississippi Delta Subsidence Primarily Caused by Compaction of Holocene Strata,” Nature 

Geoscience 1 (2008): 173–176.

33 Roy Dokka, “Modern-Day Tectonic Subsidence in Coastal Louisiana,” Geology 34, no. 4 (2006): 281–84.

34 Robert Morton, “Evidence of Regional Subsidence and Associated Interior Wetland Loss Induced by Hydrocarbon Production, Gulf Coast Region, USA,” Environmental Geology 50 (2006): 261–74.

35 Committee on the Restoration and Protection of Coastal Louisiana, Drawing Louisiana’s New Map: Addressing Land 

Loss in Coastal Louisiana (National Research Council, 2006), 48.

36 James G. Gosselink, “Comments on ‘Wetland Loss in the Northern Gulf of Mexico: Multiple Hardworking Hypotheses,’” Estuaries 24, no. 4 (August 2001), 636–651.

37 James B. Johnston, Donald R. Cahoon and Megan K. La Peyre, Outer Continental Shelf (OCS)-Related Pipelines and 

Navigation Canals in the Western and Central Gulf of Mexico: Relative Impacts on Wetland Habitats and Effectiveness 

of Mitigation (Minerals Management Service, 2009), 157.

38 Richard Campanella, Time and Place in New Orleans: Past Geographies in the Present Day (Gretna, LA: Pelican Publishing Company, Inc., 2002), 78; Panama Canal Authority, Frequently asked questions, http://www.pancanal.com/

eng/general/canal-faqs/index.html.

39 U.S. Army Corps of Engineers, Integrated Final Report to Congress and Legislative Environmental Impact Statement 

for the Mississippi River—Gulf Outlet Deep-Draft De-Authorization Study (June 2008), 6.

40 Gary P. Shaffer et al., “The MRGO Navigation Project: A Massive Human-Induced Environmental, Economic, and 

Storm Disaster,” Journal of Coastal Research, Special Issue 54 (2009): 206–224; R.H. Caffey and B. Leblanc, ‘Closing’ 

the Mississippi River Gulf Outlet: Environmental and Economic Considerations (LACoast.gov, 2002).

41 Day et al., “Restoration of the Mississippi Delta: Lessons from Hurricanes Katrina and Rita,” 1679–1684.

42 U.S. Army Corps of Engineers, MRGO Navigation Channel Closure (2010), http://www.mrgo.gov/MRGO_Closure.

aspx.

43 James Coleman, “James P. Morgan: Scientific Contributions,” Journal of Coastal Research 14, no. 3 (1998): 868–69.
Endnotes 345 345

44 Avenal v. United States, 33 Fed. Cl. 778 (1995).

45 National Research Council, Panel on River Basin and Coastal Systems Planning, Committee to Assess the U.S. Army 

Corps of Engineers Methods of Analysis and Peer Review for Water Resources Project Planning, River Basins and 

Coastal Systems Planning Within the U.S. Army Corps of Engineers (2004): 104. 

46 S.M. Gagliano, “Canals, Dredging, and Land Reclamation in the Louisiana Coastal Zone” in Hydrologic and Geologic 

Studies of Coastal Louisiana, Report no. 14 (Center for Wetland Studies, Louisiana State University, 1973).

47 N.J. Craig, R.E. Turner, and J.W. Day Jr., “Land Loss in Coastal Louisiana (U.S.A.)” Environmental Management 3, 

no. 2 (1979): 133–144. 

48 Paul Kemp, Vice-President, National Audobon Society, interview with Commission staff, October 7, 2010.

49 Denise Reed, “Seeing the Future of the Louisiana Coast,” in After the Storm: Restoring America’s Gulf Coast Wetlands, 

A Special Report of the National Wetlands Newsletter (Washington, D.C.: Environmental Law Institute, 2006), 45.

50 Michael Blum and Harry Roberts, “Drowning of the Mississippi Delta due to Insufficient Sediment Supply and Global 

Sea-Level Rise,” Nature Geoscience (June 28, 2009): 489–490.

51 U.S. General Accountability Office, Coastal Wetlands: Lessons Learned from Past Efforts in Louisiana Could Help 

Guide Future Restoration and Protection (December 14, 2007), 10.

52 U.S. Army Corps of Engineers, Coastal Wetlands Planning, Protection & Restoration Act (2010), http://www.mvn.

usace.army.mil/pd/cwppra_mission.htm.

53 Mark Schleifstein, “Breaux Act Anniversary Marks 20 Years of Coastal Restoration Progress,” Times-Picayune, April 

8, 2010; Caring for Coastal Wetlands: The Coastal Wetlands Planning, Protection and Restoration Act (LaCoast.gov, 

November 2007), http://lacoast.gov/new/Pubs/Report_data/Caring.aspx.

54 Louisiana Wetlands Conservation and Restoration Task Force and the Wetlands Conservation and Restoration Authority, Coast 2050: Toward a Sustainable Coastal Louisiana, an Executive Summary (Louisiana Department of Natural 

Resources, 1998).

55 Joel Bourne, “Gone with the Water,” National Geographic, October 2004; Water Resources Development Act of 2007, 

Pub. L. No. 110-114, Title VII, 121 Stat. 1041, 1270–1283 (2007).

56 State of Louisiana, Coastal Protection & Restoration: Funding Sources, http://www.coastal.la.gov/index.cfm?md=pa

gebuilder&tmp=home&nid=123&pnid=79&pid=82&catid=0&elid=0.

57 Donald T. Resio and Joannes J. Westerink, “Modeling the physics of storm surges,” Physics Today 61, no. 9 (September 2008): 32–38.

58 Louisiana Office of Coastal Protection and Restoration, Library, Coastal Initiatives & Programs, “http://coastal.la.gov/

index.cfm?md=pagebuilder&tmp=home&nid=82&pnid=76&pid=77&catid=0&elid=0 (“Donaldsonville to the Gulf 

Panel” and “Morganza to the Gulf Project”).

59 U.S. Army Corps of Engineers, Mississippi Coastal Improvement Program (MsCIP) Interim Report (2006).

60 Supplemental Appropriations Act of 2009, H.R. 2346, Title IV. 

61 U.S. Army Corps of Engineers, Louisiana Coastal Protection and Restoration (LACPR): Final Technical Report (June 

2009).

62 Louisiana Coastal Protection and Restoration Authority, Fiscal Year 2008 Annual Plan: Ecosystem Restoration and 

Hurricane Protection in Coastal Louisiana (April 2007); Coastal Protection and Restoration Authority of Louisiana, 

Fiscal Year 2011 Annual Plan: Integrated Ecosystem Restoration and Hurricane Protection in Coastal Louisiana, (Baton Rouge, 2010): xiii.

63 Bureau of Ocean Energy Management, Regulation and Enforcement, Coastal Impact Assistance Program (CIAP), 

http://www.boemre.gov/offshore/ciapmain.htm.

64 Bureau of Ocean Energy Management, Regulation and Enforcement, Gulf of Mexico Energy Security Act (GOMESA), 

http://www.boemre.gov/offshore/GOMESARevenueSharing.htm.

65 White House Council on Environmental Quality, Gulf Coast Ecosystem Restoration, http://www.whitehouse.gov/

administration/eop/ceq/initiatives/gulfcoast.

66 Louisiana-Mississippi Gulf Coast Ecosystem Restoration Working Group, Roadmap for Restoring Ecosystem Resiliency 

and Sustainability (March 2010).

67 Mabus, America’s Gulf Coast: A Long Term Recovery Plan after the Deepwater Horizon Oil Spill.

68 Executive Order 13554: Establishing the Gulf Coast Ecosystem Restoration Task Force, 75 Fed. Reg. 62313, October 5, 

2010. 

69 Frank Donze, “Gulf Coast Restoration Chief Ray Mabus has no Oil Spill Answers Just Yet,” Times-Picayune, June 29, 

2010.

70 Estimate based on John Barras, Land Area Change in Coastal Louisiana—a Multidecadal Perspective (from 1956 to 

2006) (U.S.Geological Survey, 2008). 71 Louisiana-Mississippi Gulf Coast Ecosystem Restoration Working Group, Roadmap for Restoring Ecosystem Resiliency 

and Sustainability, 2–3.
346 National Commission on the BP Deepwater Horizon OIl Spill and Offshore Drilling

72 Testimony of Brian McPeek, Regional Managing Director for North America, The Nature Conservancy, Hearing before 

the National Commission, September 28, 2010. 

73 Testimony of James T.B. Tripp, Senior Counsel, Environmental Defense Fund, Hearing before the National Commission, Sept 28, 2010; Testimony of Brian McPeek.

74 Gulf of Mexico Energy Security Act of 2006, Pub. L. 109-432. 

75 33 U.S.C. § 2706(e).

76 33 U.S.C. § 1321(b)(7); 40 C.F.R. § 19.4. According to the current official government estimate, the Macondo well 

released approximately 4.9 million barrels of oil over the course of the spill (±10 percent), roughly 830,000 barrels of which were captured at the wellhead using the top hat and other devices. Deepwater Horizon MC252 Gulf 

Incident Oil Budget (August 1, 2010), http://www.noaanews.noaa.gov/stories2010/PDFs/DeepwaterHorizonOilBudget20100801.pdf); Joel Achenbach and David Fahrenthold, “Oil spill dumped 4.9 million barrels into Gulf of 

Mexico, latest measure shows,” Washington Post, August 3, 2010 (range is $4.5 billion to $18 billion, based on 

estimated 4.1 million barrels discharged); Jonathan Tilove, “BP disputes government estimates of volume of Gulf of 

Mexico oil spill;” Times-Picayune, December 3, 2010 (penalties could be as high as $21 billion, based on estimate of 

4.9 million barrels discharged). BP has not released its own estimate for the total release from the well, but it disputes 

the government’s figures on the grounds that, among other things, they fail to take into account “significant flow 

impediments” and “rely on incomplete or inaccurate information, rest in large part on assumptions that have not 

been validated, and are subject to far greater uncertainties than have been acknowledged.” BP, letter to the National 

Commission, October 21, 2010, 1, 4.

77 Testimony of Richard Stewart, New York University School of Law, Hearing before the National Commission, September 28, 2010.

78 33 U.S.C. § 1319(c)(1).

79 33 U.S.C. § 1319(c)(2).

80 26 U.S.C. § 9509.

81 Ray Mabus, America’s Gulf Coast: A Long Term Recovery Plan after the Deepwater Horizon Oil Spill.

82 Exxon Valdez Oil Spill Trustee Council, Science Panel, http://www.evostc.state.ak.us/people/sp.cfm. 

83 Joe Hunt, Mission Without a Map: The Politics and Policies of Restoration Following the Exxon Valdez Oil Spill: 1989-

2002, Exxon Valdez Oil Spill Trustee Council (Anchorage, 2009): 156-157.

84 See, e.g., Testimony of Stanley Senner, Director of Conservation Science, Ocean Conservancy, Hearing before the 

National Commission, September 28, 2010.

85 President Barack Obama, “Remarks by the President to the Nation on the BP Oil Spill” (June 15, 2010), http://www.

whitehouse.gov/the-press-office/remarks-president-nation-bp-oil-spill.

86 Press Release, Office of the Governor, Gov. Jindal Announces “Agenda For Revitalizing Coastal Louisiana,” July 15, 2010, http://wwwprd.doa.louisiana.gov/LaNews/PublicPages/Dsp_PressRelease_Display.

cfm?PressReleaseID=2550&Rec_ID=1.

87 NOAA, Damage Assessment, Remediation, and Restoration Program: Glossary, http://www.darrp.noaa.gov/glossary/index.htm. 

88 Testimony of Stanley Senner.

Chapter Eight

1 Magne Ognedal, “Thirty years since Kielland – why are major accidents still happening?” (speech, Petroleum Safety 

Authority of Norway, August 27, 2010) 3, http://www.ptil.no/major-accidents/safety-lunch-at-ons-risk-of-amajor-accident-is-always-present-article7202-144.html.

2 BP, Sustainability Review (2009), 20–21. http://www.bp.com/assets/bp_internet/globalbp/STAGING/global_assets/

e_s_assets/e_s_assets_2009/downloads_pdfs/bp_sustainability_review_2009.pdf.

3 Health and Safety Executive, Major Incident Investigation Report, BP Grangemouth Scotland (29th May – 10th June 

2000) (August 18, 2003), 7, http://www.hse.gov.uk/comah/bpgrange/images/bprgrangemouth.pdf.

4 Ibid.

5 Ibid.

6 Health and Safety Executive, BP Grangemouth Executive Summary—Findings and Recommendations, http://www.

hse.gov.uk/comah/bpgrange/execsumm/findings.htm.

7 Andrew B. Wilson, “BP’s Disaster: No Surprise to Folks in the Know,” CBS, June 22, 2010, http://www.cbsnews.com/

stories/2010/06/22/opinion/main6605248.shtml. 8 Jan Erik Vinnem, Offshore Risk Assessment: Principles, Modelling and Applications of QRA Studies, Second Edition 

(London: Springer Studies in Reliability Engineering, 2007), 91, 100, 102.
Endnotes 347 347

9 Andrew B. Wilson, “BP’s Disaster: No Surprise to Folks in the Know,” CBS, June 22, 2010, http://www.cbsnews.com/

stories/2010/06/22/opinion/main6605248.shtml.

10 Oberon Houston, email message to Commission staff. 

11 The Report of the BP US Refineries Independent Safety Review Panel, (January 2007). 

12 U.S. Chemical Safety and Hazard Investigation Board, Investigation Report: Refinery Explosion and Fire (March 

2007),145, http://www.csb.gov/assets/document/CSBFinalReportBP.pdf. 

13 Testimony of Carolyn W. Merritt, Chairman and Chief Executive Officer, U.S. Chemical Safety Board, before the U.S. 

Senate Committee on Environment and Public Works, Subcommittee on Transportation Safety, Infrastructure Security, and Water Quality, July 10, 2007.

14 Ibid.

15 U.S. Chemical Safety and Hazard Investigation Board, Investigation Report: Refinery Explosion and Fire, 19-20.

16 Ibid.

17 Ibid.

18 The Report of the BP US Refineries Independent Safety Review Panel. 

19 Ibid.

20 Ibid., 224.

21 Ibid., 165 

22 “BP’s Alaskan Oil Spill Triggers Lawsuit,” 815 TCE: The Chemical Engineer (May 2009): 9.

23 Ibid.

24 Ibid.

25 “BP Faces Lawsuits for 2006 Spills,” 32 Oil Spill Intelligence Report, no. 17 (April 16, 2009); “BP Settles with Royalty 

Trust,” 32 Oil Spill Intelligence Report, no. 22 (May 21, 2009). 

26 The Report of the BP US Refineries Independent Safety Review Panel, 1. 

27 Ibid., XVII.

28 L. Duane Wilson, Independent Expert Third Annual Report, 2001 covering January-December 2009 (March 2010): 4.

29 Ibid., 25–26.

30 Elmer Danenberger, interview with Commission staff, December 9, 2010. 

31 BP, Deepwater Horizon Accident Investigation Report (September 8, 2010).

32 “BP Report Attacked,” New Scientist, 2 October, 2010, 4.

33 Richard Sears, e-mail message to Commission staff, November 23, 2010.

34 Consulting Services Lloyd’s Register EMEA Aberdeen Energy, North American Division Summary Report (March 

2010). 

35 Ibid., App. C, 6. 

36 Ibid., App. C, 8, 11. 

37 Ibid., 10-11. 

38 Ibid., 29. 

39 Halliburton, History of Halliburton, http://www.halliburton.com/AboutUs/default.aspx?navid=970&pageid=2312.

40 Ibid.

41 Russell Gold and Ben Casselman, “Drilling Process Attracts Scrutiny in Rig Explosion,” Wall Street Journal, April 30, 

2010.

42 Montara Commission of Inquiry, Report of the Montara Commission of Inquiry, (June 17, 2010), http://www.ret.

gov.au/Department/Documents/MIR/Montara-Report.pdf.

43 Ibid., 63.

44 Ibid.

45 Commission staff created this map and associated table using loss of well control data available on BOEMRE’s Incident Statistics and Summary webpage. Although efforts were made to accurately capture and illustrate every loss of 

well control from 1996-2009 in the U.S. Gulf of Mexico, the data presented does not purport to be comprehensive, 

but instead illustrative of the fact that losses of well control, blowouts, potential catastrophes, and near misses are 

more frequent than commonly reported and publicized. 46 Commission staff analysis of International Regulators Forum International Association of Drilling Contractors and 

International Association of Oil and Gas Producers data. See http://www.irfoffshoresafety.com/country/performance/, http://www.iadc.org/asp.htm, and http://www.ogp.org.uk/index.asp?main=publications/main.asp.
348 National Commission on the BP Deepwater Horizon OIl Spill and Offshore Drilling

47 Testimony of Eric Milito, Upstream Director, American Petroleum Institute, “The Deepwater Horizon Incident: Are 

The Minerals Management Service Regulations Doing The Job?” Hearing Before the Subcommittee on Energy and 

Mineral Resources of the House Committee on Natural Resources, 111th Congress (2010) (“Since 1924, API has 

developed industry standards and practices that promote reliability and safety through the use of proven engineering 

practices. . . . API standards are developed through a collaborative effort among industry experts, technical experts 

from government, and other interested stakeholders. The industry has helped create more than 500 standards, including some 240 exploration and production standards that address offshore operations.”)

48 American Petroleum Institute, API 2010 Publics Programs and Services Catalog (March 2010), http://www.api.org/

Standards/upload/2010_Catalog_web.pdf. 

49 American Petroleum Institute, “Certifications recognized around the world,” Training and Certifications Program 

brochure (August 9, 2009), http://www.api.org/certifications/upload/ENGLISH_SUMMARY_BROCH.pdf.

50 Testimony of Eric Milito (“Seventy-eight of these standards are referenced in Minerals Management Service regulations.”). For MMS rulemakings that incorporate industry standards into regulations over time, see Oil and Gas 

and Sulphur Operations in the Outer Continental Shelf, 61 Fed. Reg. 60,019 (November 26, 1996); Oil and Gas 

and Sulphur Operations in the Outer Continental Shelf—Pipelines and Pipeline Rights-of-Way, 72 Fed. Reg. 56,442 

(October 3, 2007); Press Release, Minerals Management Service, Minerals Management Service to Adopt the Latest 

Edition of Industry Standard on Fixed Offshore Production Platforms, April 21, 2003, http://www.boemre.gov/ooc/

press/2003/press4-21.htm.

51 Letter from Allen Verret, Offshore Operators Committee, and Tim Sampson, American Petroleum Institute, to the U.S. 

Minerals Management Service (September 15, 2009), http://www.scribd.com/doc/30588089/Joint-API-OOC-Letterto-MMS; American Petroleum Institute and Offshore Operators Committee, “Safety and Environmental Management 

Systems for Outer Continental Shelf Oil and Gas Operations,” Public Comment (September 15, 2009), http://www.

boemre.gov/federalregister/PublicComments/AD15SafetyEnvMgmtSysforOCSOilGasOperations/OOCAPICommentLetter9-15-09.pdf; American Petroleum Institute, “Postlease Operations Safety,” Public Comment (July 1, 1998), 

http://www.boemre.gov/federalregister/PublicComments/Sub_A_Comments/prorule.pdf, http://www.boemre.gov/

federalregister/PublicComments/Sub_A_Comments/subacomm.pdf.

52 Commission staff held several meetings during August and September 2010 with representatives of major oil and gas 

companies during which the role of API in standard setting processing, including the impact of API’s broader advocacy role on those standards, was discussed.

53 T.A.F. Powell, “US Voluntary SEMP Initiative: Holy Grail or Poisoned Chalice?” (Offshore Technology Conference [OTC] 

Paper 8111, May 1996).

54 Letter from Allen Verret, Offshore Operators Committee, and Tim Sampson, American Petroleum Institute, to the U.S. 

Minerals Management Service (September 15, 2009), http://www.scribd.com/doc/30588089/Joint-API-OOC-Letterto-MMS; Offshore Operators Committee and American Petroleum Institute, “Oil, Gas, and Sulphur Operations in the 

Outer Continental Shelf (OCS)—Safety and Environmental Management Systems,” Public Comment (May 22, 2006).

55 T.A.F. Powell, “US Voluntary SEMP Initiative: Holy Grail or Poisoned Chalice?”

56 Oil and Gas and Sulphur Operations in the Outer Continental Shelf—Safety and Environmental Management Systems, 75 Fed. Reg. 199 (October 15, 2010). 

57 T.A.F. Powell, “US Voluntary SEMP Initiative: Holy Grail or Poisoned Chalice?”

58 Elmer Danenberger, interview with Commission staff, December 9, 2010.

59 Testimony of Tad W. Patzek, “Beneath the Surface of the BP Spill: What’s Happening Now, What’s Needed Next,” 

Briefing Before the Subcommitee on Energy and Environment of the House Committee on Energy and Commerce, 

111th Congess (2010): 4. 

60 Ibid.

61 Ibid.

62 Testimony of James Ellis, Institute of Nuclear Power Operations, Hearing before the National Commission, August 

25, 2010.

63 Federal Aviation Administration, “Mission,” http://www.faa.gov/about/mission/.

64 Federal Aviation Administration, “Delegation and Designee Background,” http://www.faa.gov/about/history/deldes_background/.

65 Federal Aviation Administration, “Designees and Delegations: Designated Engineering Representative (DER),” http://

www.faa.gov/other_visit/aviation_industry/designees_delegations/designee_types/der/; Nancy Leveson (MIT), interview with Commission staff, October 13, 2010.

66 Federal Aviation Administration, “Delegation and Designee Background,” http://www.faa.gov/about/history/deldes_background/.

67 Leveson, interview.

68 Ibid. 69 Nancy Leveson, Safeware: System Safety and Computers 556 (Boston: Addison-Wesley, 1995).

70 Ibid.
Endnotes 349 349

71 Nancy Leveson, Engineering A Safer World: Systems Thinking Applied To Safety 376-77 (Cambridge, MA: MIT Press, 

forthcoming in 2011), http://sunnyday.mit.edu/safer-world.

72 Ibid., 375.

73 Ibid., 376. 

74 Ibid., 376, 378.

75 Ibid., 375–6.

76 Ibid., 375–6.

77 Ibid., 378.

78 Ibid., 378.

79 Ibid., 379.

80 Ibid., 380–1.

81 Ibid., 380.

82 Ibid., 380. 

83 Ibid., 380.

84 Ibid., 381–2.

85 Ibid., 385.

86 Ibid., 385–6.

87 Ibid., 388.

88 Alaska Oil Spill Commission, Spill: The Wreck of the Exxon Valdez (Final Report) (February 1990), 1.

89 Samuel K. Skinner and William K. Reilly, The Exxon Valdez Oil Spill: A Report to the President (May 1989), 1.

90 Ibid., 27–8.

91 National Transportation Safety Board, Safety Recommendation (September 18, 1990), http://www.ntsb.gov/recs/

letters/1990/M90_26_31A.pdf.

92 Exxon Valdez Oil Spill Trustee Council, “Settlement,” http://www.evostc.state.ak.us/facts/settlement.cfm; Exxon 

Valdez Oil Spill Trustee Council, “Questions and Answers,” http://www.evostc.state.ak.us/facts/qanda.cfm.

93 Exxon Mobil, 2009 Corporate Citizenship Report, 15.

94 Testimony of Rex Tillerson, CEO of Exxon Mobil, Hearing before the National Commission, November 9, 2010.

95 Ibid.

96 Ibid.

97 Exxon Mobil, 2009 Corporate Citizenship Report, 14.

98 Ibid.,13, 19. 

99 “Shell ‘Ignored Accident Warning,’” BBC online, June 14, 2006, http://news.bbc.co.uk/2/hi/5077886.stm; Terry 

Macalister, “Shell Accused Over Oil Rig Safety,” The Guardian, June 23, 2006.

100 “Shell ‘Ignored Accident Warning.’” 

101 Shell, Sustainability Report 2009, 16–17, http://sustainabilityreport.shell.com/2009/servicepages/downloads/files/

all_shell_sr09.pdf.

102 Testimony of Marvin Odum, Shell, Hearing before the National Commission, November 9, 2010.

103 Ibid.

104 Ibid.

105 Ibid.

106 Ibid.

107 Responsible Care, Who We Are, http://www.responsiblecare.org/page.asp?p=6406.

108 Ibid. 

109 Jody Freeman, “Private Parties, Public Functions and the New Administrative Law” in Recrafting the Rule of Law: 

The Limits of Legal Order, ed. David Dyzenhaus (Toronto: Hart Publishing, 1999), 21.

110 Ibid., 33. 

111 Press Release, Securities and Exchange Commission, Chairman Cox Announces End of Consolidated Supervised Entities Program, September 26, 2008; Stephen Labaton, “Agency’s ’04 Rule Let Banks Pile Up New Debt,” New York 

Times, October 3, 2008.
350 National Commission on the BP Deepwater Horizon OIl Spill and Offshore Drilling

112 Press Release, Securities and Exchange Commission, Chairman Cox Announces End of Consolidated Supervised Entities Program.

113 Edward J. Balleisen and Marc Eisner, “The Promise and Pitfalls of Co-Regulation: How Governments Can Draw on 

Private Governance for Public Purpose,” in New Perspectives on Regulation, ed. David Moss and John Cisternino, 

(Cambridge, UK: Cambridge University Press, 2009), 31.

114 Ibid., 130.

115 Ibid.

116 Ibid.

117 Testimony of Marvin Fertel, President and CEO of Nuclear Energy Institute, “Three Mile Island—Looking Back on 

Thirty Years of Lessons Learned,” Before the Subcommittee on Clean Air and Nuclear Safety, 111th Congress (2009). 

118 Testimony of James Ellis, Institute of Nuclear Power Operations, Hearing before the National Commission, August 

25, 2010.

119 John G. Kemeny, Report of The President’s Commission on the Accident at Three Mile Island: The Need for Change: 

The Legacy of TMI (1979), 68. The full subsection of the recommendation reads, “The industry should establish a 

program that specifies appropriate safety standards including those for management, quality assurance, and operating procedures and practices, and that conducts independent evaluations. The recently created Institute of Nuclear 

Power Operations, or some similar organization, may be an appropriate vehicle for establishing and implementing 

this program.” 

120 Institute of Nuclear Power Operations, “About Us,” http://www.inpo.info/AboutUs.htm. 

121 Joseph V. Rees, Hostages of Each Other: The Transformation of Nuclear Safety Since Three Mile Island (Chicago: 

University of Chicago Press, 1996), 50–51. 

122 Lee Gard, interview with Commission staff, November 8, 2010. 

123 Rees, Hostages of Each Other: The Transformation of Nuclear Safety Since Three Mile Island, 57–58.

124 Rees, Hostages of Each Other: The Transformation of Nuclear Safety Since Three Mile Island, 143.

125 Lee Gard, interview.

126 Ibid.

127 Ibid.

128 Ibid.

129 Ibid.

130 Ibid.

131 Lee Gard, e-mail message to Commission Staff, December 6, 2010. 

132 Lee Gard, interview.

133 Testimony of A. C. Tollison Jr., Executive Vice President, Institute of Nuclear Power Operations, “National Energy 

Policy: Nuclear Energy,” Before the Subcommittee on Energy and Air Quality, 107th Congress (2001).

134 Ibid.

135 Rees, Hostages of Each Other: The Transformation of Nuclear Safety Since Three Mile Island, 76. 

136 Alice Camp, “Nuclear: In Pursuit of a Renaissance,” EPRI Journal (Summer 2007): 20. 

137 Rees, Hostages of Each Other: The Transformation of Nuclear Safety Since Three Mile Island, 81.

138 Ibid., 53.

139 Ibid., 53

140 Ibid., 53–54.

141 Lee Gard, e-mail message to Commission Staff, December 1, 2010.

142 Rees, Hostages of Each Other: The Transformation of Nuclear Safety Since Three Mile Island, 104.

143 Lee Gard, interview. 

144 Michael Golay (MIT), interview with Commission Staff, October 27, 2010. 

145 Lee Gard, e-mail message to Commission Staff, December 1, 2010. 

146 Michael Rencheck (AREVA Inc.), interview with Commission staff, November 1, 2010. 

147 Rees, Hostages of Each Other: The Transformation of Nuclear Safety Since Three Mile Island, 104.

148 Michael Golay, interview.

149 33 U.S.C. § 2210. 
Endnotes 351 35

150 Lee Gard, e-mail message to Commission Staff, December 1, 2010. 

151 Lee Gard, e-mail message to Commission Staff, November 15, 2010.

152 Lee Gard, e-mail message to Commission Staff, December 13, 2010. 

153 “Oil Industry Needs Self-Regulation, Says Alternate Energy Holdings Inc. CEO,” Forbes Magazine, August 26, 2010. 

154 Lee Gard, interview.

155 Rees, Hostages of Each Other: The Transformation of Nuclear Safety Since Three Mile Island, 57.

156 Lee Gard, interview.

157 Ibid.

158 Rees, Hostages of Each Other: The Transformation of Nuclear Safety Since Three Mile Island, 96–97.

159 Ibid., 116.

160 Ibid., 111–117.

161 Testimony of James Ellis, Institute of Nuclear Power Operations, Hearing before the National Commission, August 

25, 2010; Institute of Nuclear Power Operations, 2009 Annual Report; Institute of Nuclear Power Operations, 1994 

Annual Report. 

162 Testimony of James Ellis, Institute of Nuclear Power Operations, Hearing before the National Commission, August 

25, 2010.

163 Institute of Nuclear Power Operations, Performance Objectives and Criteria (May 2005); Institute of Nuclear Power 

Operations, Principles for Nuclear Safety Culture (November 2004). 

164 Rees, Hostages of Each Other: The Transformation of Nuclear Safety Since Three Mile Island, 44.

165 Ibid., 64.

166 U.S. Department of the Interior, Outer Continental Shelf Safety Oversight Board, Report to the Secretary of the 

Interior (September 1, 2010), 11–13.

167 Ibid., 13–14.

168 10 C.F.R. Parts 1–171.

169 Testimony of Rex Tillerson, Exxon Mobil, Hearing before the National Commission, November 9, 2010.

170 Ibid.

171 Testimony of Michael Bromwich, Director, Bureau of Ocean Energy Management, Regulation and Enforcement, 

Department of the Interior, Hearing before the National Commission, November 9, 2010, 228. 

172 Oil and Gas and Sulphur Operations in the Outer Continental Shelf – Safety and Environmental Management Systems, 75 Fed. Reg. 199 (October 15, 2010).

173 National Commission Staff, “Response/Clean-Up Technology Research & Development and the Deepwater Horizon 

Oil Spill,” (staff working paper, 2010) 

174 Angel Gonzalez, “Oil Firms Plan Rapid-Response Force,” Wall Street Journal, July 22, 2010; Daniel Squire, e-mail 

message to Commission staff, December 1, 2010. 

175 Marine Well Containment Company, “Industry Initiatives to Ensure Safe, Protective Drilling Practices in the Deepwater Gulf of Mexico: The Marine Well Containment System” (presentation, Washington, D.C., September 2010). 

176 Marine Well Containment Company, “About Us,” http://www.marinewellcontainment.com/index.php. 

177 Helix Energy Solutions Group, “Spill Containment: Fast Response to GOM Subsea Oil Spills” (unpublished document 

provided to Commission staff by Helix Energy Solutions Group). 

178 Independent Deepwater Exploration Coalition, meeting with Commission staff, November, 29, 2010. 

179 “Moody’s Offshore drilling insurance rates to jump,” BusinessWeek, June 4, 2010. 

180 Julia Kollewe, “Oil Industry Set for Surge in Insurance Premiums after Deepwater Disaster,” The Guardian, September 20, 2010, http://www.guardian.co.uk/business/2010/sep/20/deepwater-oil-rigs-insurance-costs.

181 Aspen Re interview with Commission staff, October 19, 2010; Testimony of Dr. Robert Hartwig, President and 

Economist, Insurance Information Institute, “Liability and Financial Responsibility for Oil Spills under the Oil Pollution Act of 1990 and Related Statutes,” Hearing Before the House Committee on Transportation and Infrastructure, 

111th Congress (2010). 

182 33 U.S.C. § 2702. 

183 Ibid.

184 33 U.S.C. § 2704. 185 33 U.S.C. § 2704; 33 U.S.C § 1321 (Clean Water Act civil and criminal penalties); Jonathan Ramseur, Oil Spills in 

U.S. Coastal Waters: Background, Governance, and Issues for Congress (Congressional Research Service, updated 

September 2, 2008), 26 (“A 2003 study identified 16 states that impose unlimited liability for oil spills.”).
352 National Commission on the BP Deepwater Horizon OIl Spill and Offshore Drilling

186 CLEAR Act, H.R. 3534, 111th Cong. § 702 (2010) (as passed by House); S. 3663, 111th Cong. §102 (2010)(“Reid 

Clean Energy bill”); RESPOND Act, S. 3763, 111th Cong. § 6 (2010)(“Landrieu bill”); Big Oil Bailout Prevention Act, 

H.R. 5214, 111th Cong. § 2 (2010).

187 Testimony of Charles Anderson, SKULD North America, “Liability and Financial Responsibility for Oil Spills under 

the Oil Pollution Act of 1990 and Related Statutes,” Hearing Before the House Committee on Transportation and 

Infrastructure, 111th Congress (2010), 9.

188 Graeme Wearden, “BP oil spill costs to hit $40bn,” The Guardian, November 2, 2010 ($39.9 billion estimated costs); 

33 U.S.C. §2716 (maximum required financial responsibility for offshore facilities is $150 million). 

189 Rawle King, Deepwater Horizon Oil Spill Disaster: Risk, Recovery, and Insurance Implications (Congressional Research Service, July 12, 2010), 16–18. 

190 Press Release, Munich Re, Munich Re Develops New Insurance Solution for Oil Catastrophes, September 12, 2010, 

http://www.munichre.com/en/media_relations/press_releases/2010/2010_09_12_press_release.aspx; Munich Re 

executives, telephone interview with Commission staff, September 17, 2010.

191 RESPOND Act, S. 3763, 111th Cong. § 7 (2010).

192 Graeme Wearden, “BP oil spill costs to hit $40bn,” The Guardian, November 2, 2010.

Chapter Nine

1 Exec. Order No. 13543, 75 Fed. Reg. 29,397 (May 21, 2010).

2 See 43 U.S.C. § 1337(b)(6) (“An oil and gas lease issued pursuant to this section shall . . . contain such rental and 

other provisions as the Secretary may prescribe at the time of offering the area for lease.”).

3 These terms are taken directly from the Council on Environmental Quality (CEQ) NEPA implementing regulations. 40 

C.F.R. § 1508.28. 

4 40 C.F.R. §1508.4.

5 A “Development Operations Coordination Document” in the Gulf of Mexico is functionally the same as a 

“Development and Production Plan” in other LES regions.

6 Press Release, Department of the Interior, Categorical Exclusions for Gulf Offshore Activity to be Limited While Interior 

Reviews NEPA Process and Develops Revised Policy, August 16, 2010,

7 Minerals Management Service, MMS 2007-018 Gulf of Mexico OSC Oil and Gas Lease Sales: 2007-2010 Final 

Environmental Impact Statement (April 2007), Volume I, 2-3 to 2-5. 

8 Minerals Management Service, MMS 2007-026 Chukchi Sea Planning Area Oil and Gas Lease Sale 193 and Seismic 

Surveying Activities in the Chukchi Sea Final Environmental Impact Statement (May 2007), Volume I, 1. 

9 Department of Interior, Department Manual Part 516: National Environmental Policy Act of 1969 (September 2009), 

3.4. 

10 Government Accountability Office, GAO-10-276 Offshore Oil and Gas Development: Additional Guidance Would Help 

Strengthen the Minerals Management Service’s Assessment of Environmental Impacts in the North Aleutian Basin

(March 2010), 21. 

11 Council on Environmental Quality, Final Recommendations of the Interagency Ocean Policy Task Force (July 19, 

2010), 41. 

12 43 U.S.C. § 1346. 

13 Commission staff analysis of MMS yearly budget request and enactments, by nominal and real (2005) dollars. Bureau of Ocean Energy Management, Office of Administration and Budget: Budget Division, http://www.boemre.gov/

adm/budget.html; Herbert Kaufman and Cheryl Anderson, Department of the Interior, OCS Environmental Studies 

Contract Projects—Fiscals Years 1973 through 1983 (DOI Minerals Management Service Branch of Environmental 

Studies, December 1983), II-8. 

14 33 U.S.C. § 1321(j)(5)(D)(i); 40 C.F.R. § 300.211. 

15 30 C.F.R. § 254.2(a). 

16 30 C.F.R. § 254.126

17 40 C.F.R. § 300.322

18 23 U.S.C. § 125.

19 Pub. L. No. 107-171, § 2701,116 Stat. 134, 278-279 (2002). 20 Department of the Interior, National Notice to Lessees and Operators of Federal Oil and Gas Leases, Outer Continental 

Shelf No. 2010-N10 (November 8, 2010), http://www.gomr.boemre.gov/homepg/regulate/regs/ntls/2010NTLs/10-

n10.pdf. 
Endnotes 353 353

21 30 C.F.R. §§ 250.410-418. 

22 30 C.F.R. § 250.418(j).

23 Transcript, Deepwater Blowout Containment Conference (September 22, 2010), http://www.doi.gov/news/video/

Deepwater-Blowout-Containment-Conference.cfm.

24 Doug Suttles, interview with Commission staff, October 13, 2010. 

25 Response workers generally must be trained pursuant to the Hazardous Waste Operations and Emergency Response (“HAZWOPER”) regulation administered by the Occupational Safety and Health Administration. 29 C.F.R. § 

1910.120. This regulation requires specific training and medical surveillance and monitoring for workers dealing 

with hazardous materials. While this regulation presumably applied to formal response contractors after the Deepwater Horizon spill, it was not applied consistently to citizen responders who also require its protections.

26 Public information should further be provided in languages and formats that are understandable to individuals with 

limited English proficiency and individuals with disabilities. ESF #8—Public Health and Medical Services Annex at 7. 

27 Indeed, the Public Health and Medical Services Annex provides for long-term monitoring of potentially exposed 

individuals, requiring the Department of Health and Human Services to “assist[] State, tribal, and local officials in 

establishing a registry of potentially exposed individuals . . . and conducting long-term monitoring of this population 

for potential long-term health effects.” ESF #8 – Public Health and Medical Services Annex at 9-10; Rebecca Bratspies, 

et al., From Ship to Shore: Reforming the National Contingency Plan to Improve Protections for Oil Spill Cleanup 

Workers (Center for Progressive Reform, September 2010).

28 Whether or not respirators should be required for cleanup workers emerged as a major controversy in the response.

29 Ray Mabus, America’s Gulf Coast: A Long Term Recovery Plan after the Deepwater Horizon Oil Spill (September 

2010); Exec. Order No. 13554, 75 Fed. Reg. 62313–62317 (October 8, 2010). 

30 Federal liability for damages is not the only potential liability that could result from an offshore drilling incident. 

Under the Oil Pollution Act, drillers are strictly liable for removal costs. Companies can also be subject to federal civil 

and criminal penalties as well as unlimited liability for damages under some state laws. These liabilities presumably 

drive business to internalize risk and mitigate safety, though not as fully as they might if damages liability were not 

capped.

31 Gulf Coast Claims Facility, Frequently Asked Questions, http://www.restorethegulf.gov/sites/default/files/imported_

pdfs/library/assets/gccf-faqs.pdf. 

32 Gulf Coast Claims Facility, Frequently Asked Questions, http://www.gulfcoastclaimsfacility.com/faq#Q9. Government claims for loss of revenue are being handled by BP: http://www.bp.com/governmentclaims. A $60 million BP 

fund is in place for real estate claims across the five Gulf states and is being administered by National Catastrophe 

Adjusters, a claims adjustment firm: www.gulfreclaims.com; Kathy Jumper, “Realtors Tap National Catastrophe 

Adjusters To Administer Oil Spill Claims,” Press-Register, August 24, 2010, http://blog.al.com/live/2010/08/realtors_oil_claims.html. BP has set aside $100 million for rig workers who experience hardship due to the moratorium, 

to be administered by the Gulf Coast Restoration and Protection Foundation: http://www.gcrpf.org/. Claims for 

repairs or damage to vessels involved in the Vessel of Opportunity program are being handled by BP. 

33 Letter from Thomas J. Perrelli, Associate Attorney General, Department of Justice, to Kenneth Feinberg, September 17, 

2010.

34 “Leader on BP Claims Blames Fraud for Slow Payouts”, Associated Press, October 5, 2010. 

35 Press Release, Gulf Coast Claims Facility, Feinberg Announces Faster and More Generous Payments from GCCF, 

September 25, 2010, http://www.gulfcoastclaimsfacility.com/press6.php; Press Release, Gulf Coast Claims Facility, 

Feinberg Announces Clarification Regarding Geographic Proximity, October 4, 2010, http://www.gulfcoastclaimsfacility.com/press7.php; Editorial, “Are Victims of the Gulf Oil Spill Getting What They Deserve?,” Washington Post, 

November 25, 2010, http://www.gulfcoastclaimsfacility.com/pressA.php; Siobhan Hughes and Ryan December, 

“Feinberg Softens His Stance on Claims From Spill,” Wall Street Journal, November 26, 2010.

36 Gulf Coast Claims Facility, GCCF Program Statistics—Overall Summary, Gulf Coast Claims Facility, December 11, 

2010, http://www.gulfcoastclaimsfacility.com/GCCF_Overall_Status_Report.pdf. 

37 Minerals Management Service, Budget Justifications and Performance Information Fiscal Year 2011.

38 43 U.S.C. § 1337(b)(6).

Chapter Ten

1 Energy Information Administration, Annual Energy Review 2009 (August 19, 2010), Table 5.2, 131, http://www.eia.

doe.gov/emeu/aer/pdf/pages/sec5_7.pdf. 

2 Energy Information Administration, Annual Energy Outlook 2010 (April, 2010), 75, http://www.eia.doe.gov/oiaf/

aeo/pdf/0383(2010).pdf. 

3 Technically recoverable reserves, however, are very different from proven reserves, because the former unlike the latter 

includes reserves that may well be as a practical manner be too expensive to recover.

4 Energy Information Administration, Annual Energy Review 2008 (June 26, 2009), Table 4.1, 99, http://www.eia.
354 National Commission on the BP Deepwater Horizon OIl Spill and Offshore Drilling

gov/FTPROOT/multifuel/038408.pdf. 

5 National Academy of Sciences, Advancing the Science of Climate Change (Washington, D.C.: The National Academies 

Press, 2010). 

6 Energy Information Administration, Annual Energy Review 2009 (August 19, 2010), Figure 2.0, 37, http://www.eia.

gov/emeu/aer/pdf/pages/sec2.pdf. (Most of the remaining transportation fuels came from ethanol and natural gas.)

7 National Academy of Sciences, America’s Energy Future: Technology and Transformation (Washington, D.C.: The 

National Academies Press, 2010), xi. 

8 Energy Information Administration, Annual Energy Review 2009, Tables 4.2, 5.1, 101, 129 (calculated from tables) 

http://www.eia.doe.gov/aer/pdf/aer.pdf. 

9 Ibid., Table 11.5, 315. 

10Ibid., Tables 11.4, 11.10, 313, 325 (calculated based on tables). “Proved reserves” represent only a small part of can be 

ultimately recovered and are estimated by different standards around the world. 

11 Ibid., Table 5.17, 167, http://www.eia.gov/emeu/aer/pdf/pages/sec5_43.pdf. 

12 Ibid., Table 3.5, 77. http://www.eia.gov/emeu/aer/pdf/pages/sec3_11.pdf 

13 Stephen Brown and Hillard Huntington, “Estimating U.S. Oil Security Premiums: EMF OP 68,” September 2009. 

14 Census Bureau, “Trade in Goods (Imports, Exports and Trade Balance) with China 1985-2010,” http://www.census.

gov/foreign-trade/balance/c5700.html#2010. 

15 Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards, 75 Fed. 

Reg. 25,324 (May 7, 2010). The joint rulemaking in 2010 by the Department of Transportation and EPA establishing light duty vehicle greenhouse gas emission standards and corporate average fuel economy standards promises to 

significantly increase fuel efficiency and reduce greenhouse gas emissions. 

16 Jay Hakes, A Declaration of Energy Independence: How Freedom from Foreign Oil Can Improve National Security, 

Our Economy, and the Environment (Hoboken, New Jersey: John Wiley & Sons, 1978), 68-70, 87-88; Energy 

Information Administration, Annual Energy Review 2009 (August 19, 2010), Figure 5.1, 129, http://www.eia.gov/

emeu/aer/pdf/pages/sec5_5.pdf. 

17 National Research Council, America’s Energy Future: Technology and Transformation (Washington D.C.: National 

Academies Press, 2009); National Research Council, Limiting the Magnitude of Future Climate Change (Washington 

D.C.: National Academies Press, 2010).

18 President’s Council of Advisors on Science and Technology, Report to the President on Accelerating the Pace of Change 

in Energy Technologies through an Integrated Federal Energy Policy (Washington D.C.: Executive Office of the President, 2010).

19 ”Shares,” Gazprom, http://www.gazprom.com/investors/stock/. 

 20 “The Other Way Out,” Economist, November 19, 2010; Energy Information Administration, “Country Analysis 

Briefs: Mexico,” June 2010. 

21 There are also massive natural gas resources in and off Alaska, but until a pipeline is built to the lower 48 states, the 

gas cannot be brought to market and used.

22 Department of the Interior, “Estimated Undiscovered, Economically Recoverable Resources,” http://www.doi.gov/

whatwedo/energy/ocs/upload/UERR-map-2012-2017-80-NoYear-Note.pdf.

23 Bureau of Ocean Energy Management, “Lease Sales,” December 2, 2010, http://alaska.boemre.gov/lease/hlease/

LeasingTables/lease_sales.pdf; Minerals Management Service, “Summary of Company Bids,” February 7, 2008, 

http://alaska.boemre.gov/cproject/Chukchi193/193Saleday/Sale%20193%20Sum%20of%20Co%20Bids%20by%20

Co%20Code.pdf. 

24 Energy Information Administration, Annual Energy Review 2009, Table 5.2, 131. 

25 Energy Information Administration, Annual Energy Outlook 2011, Table A14. 

26 Unpublished information provided to the Commission by the Energy Information Administration. 

27 Northern Economics, Economic Analysis of Future Offshore Oil and Gas Development: Beaufort Sea, Chukchi Sea, 

North Aleutian Basin (March 2009), ES-7, 9. 

28 Audobon Alaska, “Chukchi Sea,” http://ak.audubon.org/issues-action/chukchi-sea. 

29 Press Release, Department of the Interior, U.S. Fish and Wildlife Service Announces Final Designation of Polar Bear 

Critical Habitat, November 24, 2010. 

30 Lori Quakenbush, “Bowhead Whale,” Alaska Department of Fish & Game, September 22, 2010. 

31 Ibid. 

32 Ronald O’Rourke, Changes in the Arctic: Background and Issues for Congress (Congressional Research Service, October 15, 2010), 31 (“On June 25, 2010, the Coast Guard announced that Polar Sea had suffered an unexpected engine 

casualty and consequently will likely be unavailable for operation until at least January 2011.”). 

33 The Arctic Council is a multinational and intergovernmental group. Members include the governments of Canada, 
Endnotes 355 355

Denmark (including the Faroe Islands and Greenland), Finland, Iceland, Norway, the Russian Federation, Sweden, and 

the United States of America. The Permanent Participants of the Arctic Council are: Aleut International Association 

(AIA), Arctic Athabaskan Council (AAC), Gwich’in Council International (GCI), Inuit Circumpolar Council (ICC), Russian Association of Indigenous Peoples of the North (RAIPON), and the Saami Council.
356 Appendix A

Appendix A

Commission Members

SENATOR BOB GRAHAM, Co-Chair, is the former two-term 

governor of Florida and served for 18 years in the United States 

Senate. After retiring from public life in January 2005, Senator 

Graham served for a year as a senior fellow at the Harvard 

Kennedy School of Government. There he commenced writing 

America, the Owner’s Manual, published in 2009 as a guide to 

participatory citizenship. From May 2008 to February 2010, 

he served as chairman of the Commission on the Prevention of 

Weapons of Mass Destruction Proliferation and Terrorism, and 

currently serves as a member of the Financial Crisis Inquiry 

Commission and the CIA’s Executive Advisory Board.

WILLIAM K. REILLY, Co-Chair, is a founding partner of Aqua 

International Partners, LP, a private equity fund dedicated 

to investing in companies engaged in water and renewable 

energy, and a senior advisor to TPG Capital, LP, an international 

investment partnership. He co-chaired the National Commission 

on Energy Policy. Mr. Reilly served as Administrator of the U.S. 

Environmental Protection Agency (1989-1993) and president of 

World Wildlife Fund (1985-1989). He also served as the head of 

the U.S. delegation to the United Nations Earth Summit at Rio in 

1992.

FRANCES G. BEINECKE, Member, is the President of the Natural 

Resources Defense Council (NRDC), a non-profit corporation that 

works to advance environmental policy in the United States and 

across the world. In addition, Ms. Beinecke currently serves on the 

Board of the World Resources Institute and the steering committees 

of the U.S. Climate Action Partnership. She is a member of the 

Aspen Institute’s Commission on Arctic Climate Change, and on 

the advisory boards of the Yale School of Management and the 

Yale School of Forestry and Environmental Science.

Mandel Ngan/AFP/Getty Images
Appendix A 357 357

DONALD F. BOESCH, Member, is President of the University of 

Maryland Center for Environmental Science, where he is also a 

Professor of Marine Science and Vice Chancellor for Environmental 

Sustainability for the University System of Maryland. He is a 

biological oceanographer who has conducted research on coastal 

ecosystems along the Atlantic Coast, the Gulf of Mexico, Australia 

and the East China Sea. A native of Louisiana, he has assessed 

the long-term environmental effects of offshore oil and gas 

development and multiple environmental problems of the Gulf 

Coast.

TERRY D. GARCIA, Member, is currently Executive Vice President 

for Mission Programs for the National Geographic Society, 

responsible for the Society’s core programs that manage more 

than 400 scientific field research, conservation and exploration 

projects annually. From 1994 to 1996, he was General Counsel at 

NOAA and led the implementation of the Exxon Valdez Oil Spill 

Restoration Plan for Prince William Sound and the Gulf of Alaska. 

From 1997 to 1999, he was Assistant Secretary of Commerce for 

Oceans and Atmosphere and Deputy Administrator of NOAA. 

CHERRY A. MURRAY, Member, is Dean of the Harvard School of 

Engineering and Applied Sciences and John A. and Elizabeth S. 

Armstrong Professor of Engineering and Applied Sciences. She 

is currently the Past President of the American Physical Society. 

She was formerly Senior Vice President of Physical Science 

& Wireless Research at Bell Labs and past Principal Associate 

Director for Science & Technology at Lawrence Livermore National 

Laboratory. A member of the National Academy of Engineering 

and the National Academy of Sciences, she has served on more 

than 80 national and international scientific advisory committees, 

governing boards, and National Research Council panels, including 

chairing the Council’s Division of Engineering and Physical Science.

FRAN ULMER, Member, is Chancellor of the University of Alaska 

Anchorage, Alaska’s largest public university. Ms. Ulmer has 

served as Mayor of Juneau and Lieutenant Governor of Alaska. 

As a state legislator, she served on the Special Committee on the 

Exxon Valdez Oil Spill Claims Settlement. She has been a member 

of the North Pacific Anadromous Fish Commission, the Alaska 

Coastal Policy Council, the Alaska Nature Conservancy, the 

National Parks Conservation Association, the Aspen Institute’s 

Commission on Arctic Climate Change, among many others.
358 Appendix B

Appendix B

List of Acronyms

API American Petroleum Institute

BOEMRE Bureau of Ocean Energy Management, Regulation and Enforcement

CWA Clean Water Act

DOI Department of the Interior

EA Environmental Assessment

EIS Environmental Impact Statement

FDA Food and Drug Administration

HPSA Health Professional Shortage Area

IADC International Association of Drilling Contractors

INPO Institute of Nuclear Power Operations

MMS Minerals Management Service

NASA National Aeronautics and Space Administration

NEPA National Environmental Policy Act

NOAA National Oceanic and Atmospheric Administration

NRC Nuclear Regulatory Commission

NRDA Natural Resource Damage Assessment

OPA Oil Pollution Act of 1990

OPEC Organization of Petroleum Exporting Countries

OCS Outer Continental Shelf

OCSLA Outer Continental Shelf Lands Act

SEMP Safety and Environmental Management Program

SEMS Safety and Environmental Management Systems
Appendix C 359 359

Appendix C

Executive Order-- National Commission on the BP 

Deepwater Horizon Oil Spill and Offshore Drilling

By the authority vested in me as President by the Constitution and the laws of the United 

States of America, it is hereby ordered as follows:

Section 1. Establishment. There is established the National Commission on the BP 

Deepwater Horizon Oil Spill and Offshore Drilling (the “Commission”).

Sec. 2. Membership. (a) The Commission shall be composed of not more than 7 members 

who shall be appointed by the President. The members shall be drawn from among 

distinguished individuals, and may include those with experience in or representing the 

scientific, engineering, and environmental communities, the oil and gas industry, or any 

other area determined by the President to be of value to the Commission in carrying out its 

duties.

(b) The President shall designate from among the Commission members two members to 

serve as Co Chairs.

Sec. 3. Mission. The Commission shall:

(a) examine the relevant facts and circumstances concerning the root causes of the 

Deepwater Horizon oil disaster;

(b) develop options for guarding against, and mitigating the impact of, oil spills associated 

with offshore drilling, taking into consideration the environmental, public health, and 

economic effects of such options, including options involving:

(1) improvements to Federal laws, regulations, and industry practices applicable to 

offshore drilling that would ensure effective oversight, monitoring, and response 

capabilities; protect public health and safety, occupational health and safety, and 

the environment and natural resources; and address affected communities; and

(2) organizational or other reforms of Federal agencies or processes necessary to ensure 

such improvements are implemented and maintained.

(c) submit a final public report to the President with its findings and options for 

consideration within 6 months of the date of the Commission’s first meeting.

Sec. 4. Administration. (a) The Commission shall hold public hearings and shall 

request information including relevant documents from Federal, State, and local officials, 

nongovernmental organizations, private entities, scientific institutions, industry and 
360 Appendix C

workforce representatives, communities, and others affected by the Deepwater Horizon oil 

disaster, as necessary to carry out its mission.

(b) The heads of executive departments and agencies, to the extent permitted by law 

and consistent with their ongoing activities in response to the oil spill, shall provide 

the Commission such information and cooperation as it may require for purposes of 

carrying out its mission.

(c) In carrying out its mission, the Commission shall be informed by, and shall strive to 

avoid duplicating, the analyses and investigations undertaken by other governmental, 

nongovernmental, and independent entities.

(d) The Commission shall ensure that it does not interfere with or disrupt any ongoing 

or anticipated civil or criminal investigation or law enforcement activities or any 

effort to recover response costs or damages arising out of the Deepwater Horizon 

explosion, fire, and oil spill. The Commission shall consult with the Department of 

Justice concerning the Commission’s activities to avoid any risk of such interference or 

disruption.

(e) The Commission shall have a staff, headed by an Executive Director.

(f) The Commission shall terminate 60 days after submitting its final report.

Sec. 5. General Provisions. (a) To the extent permitted by law, and subject to the 

availability of appropriations, the Secretary of Energy shall provide the Commission with 

such administrative services, funds, facilities, staff, and other support services as may be 

necessary to carry out its mission.

(b) Insofar as the Federal Advisory Committee Act, as amended (5 U.S.C. App.) (the “Act”), 

may apply to the Commission, any functions of the President under that Act, except 

for those in section 6 of the Act, shall be performed by the Secretary of Energy in 

accordance with guidelines issued by the Administrator of General Services.

(c) Members of the Commission shall serve without any additional compensation for their 

work on the Commission, but shall be allowed travel expenses, including per diem in 

lieu of subsistence, to the extent permitted by law for persons serving intermittently in 

the Government service (5 U.S.C. 5701-5707).

(d) Nothing in this order shall be construed to impair or otherwise affect:

(1) authority granted by law to a department, agency, or the head thereof; or

(2) functions of the Director of the Office of Management and Budget relating to 

budgetary, administrative, or legislative proposals.
Appendix C 361 36

(e) This order is not intended to, and does not, create any right or benefit, substantive 

or procedural, enforceable at law or in equity by any party against the United States, its 

departments, agencies, or entities, its officers, employees, or agents, or any other person.

 BARACK OBAMA

THE WHITE HOUSE,

 May 21, 2010.
362 Appendix D

Appendix D

Commission Staff and Consultants

Richard Lazarus, Executive Director

Tracy Terry, Deputy Director

Fred Bartlit, Chief Counsel Jay Hakes, Director of Policy & Research 

Priya Aiyar

Deputy Chief Counsel

Felicia Barnes

Analyst

Adam Benthem

Analyst 

Gordon Binder 

Senior Policy Advisor

Paul Bledsoe

Senior Policy Advisor

Jed J. Borghei

Counsel

C. Hobson Bryan

Analyst

Edwin H. Clark, II

Director of Operations

Kate Clark

Senior Analyst

Dave Cohen

Press Secretary

Cindy Drucker

Director of Public Engagement

Katherine Duncan

Analyst 

J. Jackson Eaton

Counsel

Michelle Farmer

Executive Legal Assistant

Sean Grimsley

Deputy Chief Counsel

David Greenberg

Senior Policy Advisor 

Brent Harris

Counsel

Lisa K. Hemmer

Senior Legal Advisor

Joe Hernandez

Analyst 

Joel Hewett

Analyst 

Christiana James

Staff Assistant 

Jill Jonnes

Senior Researcher

Nancy Kete

Senior Analyst 

Caitlin Klevorick 

Policy Advisor 

Emily Lindow

Senior Analyst 

Claire Luby

Assistant to the Executive Director

Bethany Mabee

Communications Coordinator

Scott McKee

Analyst

Claudia A. McMurray

Senior Counsel for Congressional and 

State Relations
Appendix D 363 363

Louise Milkman

Chief of Staff to the Executive 

Director

Jon Monger

Counsel

Shirley Neff

Senior Analyst

Pete Nelson

Director of Communications

Elena Nikolova

Analyst 

Jessica O’Neill

Counsel

Paul Ortiz

Senior Legal Advisor 

Tony Padilla

Analyst 

Tyler Priest

Senior Analyst 

Sarah Randle

Analyst 

Irwin Redlener

Senior Public Health Advisor

John S. Rosenberg

Chief Editor

Eric Roston

Senior Analyst

Sara Rubin

Analyst

Sambhav N. Sankar

Deputy Chief Counsel

Nicole A. Sarrine

Staff Assistant 

Richard Sears

Senior Science & Engineering Advisor

Steven Siger

Counsel

Robert Spies

Senior Environmental Science Advisor

Danielle Stewart

Staff Assistant 

Marika Tatsutani

Editor

Johnny Tenorio

Information Technology Officer

Saritha Komatireddy Tice

Counsel

Lloyd Timberlake

Senior Researcher

Clara Vondrich

Counsel

Jason Weil

Analyst 

David Weiss

Counsel

Stephen M. Willie

Administrative Officer

Andrea J. Yank

Assistant to Co-Chair William K. 

Reilly 
364 Appendix D

Senior Consultants 

The Commission would like to thank the following individuals for their contributions to 

the Commission’s work.

Albert Bolea, University of Alaska, University of Houston

Darryl A. Bourgoyne, Louisiana State University

Robert L. Booth, National Geographic 

Margaret Caldwell, Stanford University

Elmer Peter Danenberger III, Independent Consultant

Joann Donnellan, JD MEDIA, LLC

Daniel A. Farber, University of California, Berkley 

Jody Freeman, Harvard Law School 

Jed Horne, Freelance Writer

Mary E. Laur, University of Chicago Press

Nancy G. Leveson, MIT

Igor Linkov, US Army Engineer Research and Development Center

Stephen K. Lewis, Seldovia Marine Services 

Thomas W. Merrill, Columbia Law School 

Ishan Nath, Stanford University 

J.B. Ruhl, Florida State University College of Law 

John Rogers Smith, Louisiana State University 

Estes C. Thomas, Bayou Petrophysics

Mayank Tyagi, Louisiana State University

Organizational Consultants

The Commission would like to thank the following organizations as well as individuals for 

their contributions to the Commission’s work.

Bipartisan Policy Center: Jason Grumet, Nate Gorence, Lourdes Long, David Rosner

Booz Allen Hamilton: Ken Saenz, Walton Smith, Nader Kalifa Betsy Christie, 

Randolph Sta. Ana, Bob Murray, Dana Ayers, John Papa, Tom Davis, Elizabeth Chervenak, 

Andrew Gumbiner, Tom Matta, Carrie Bittman, Bob Blaylock, Barbara McKinnon,

Roxanne Bromiley, Gary Leatherman, Daniel Gregoire, Ted Perez, Linna Manomaitis, 

Marianne Martin, Kersley Joseph, James Lee, Christina Ashcraft, Joshua Guenther

Merdian Institute: John Ehrmann, Laura Cantral, Shawn Walker

Nicholas Institute for Environmental Policy Solutions, Duke University: 

Larry Crowder, Daniel Dunn, Clare Fieseler, Morgan Gopnik, Catherine Latanich, Mike 

Orbach, Tim Profetta, Linwood Pendleton, Steve Roady, Mary Turnipseed, Cindy van Dover

Resources for the Future: Bob Anderson, Sarah Campbell, Mark A. Cohen, Roger 

M. Cooke, Art Fraas, Todd Gerarden, Madeline Gottlieb, Carolyn Kousky, Alan Krupnick, 

Joshua Linn, Molly Macauley, Richard Morgenstern, Lucija Muehlenbachs, Tim Murphy, 

Ian Parry, Nathan Richardson, Heather L. Ross, Lynn Scarlett, Adam Stern

TrialGraphix: Megan O’Leary, William Lane, Devin Price
Appendix E 365 365

Appendix E

List of Commission Meetings

1st Meeting: New Orleans, LA

July 12-13, 2010: Gulf Region Perspectives

2nd Meeting: Washington, DC

August 25, 2010: Regulatory Oversight of Offshore Drilling

3rd Meeting: Washington, DC

September 27-28, 2010: Response & Restoration

4th Meeting: Washington, DC

October 13, 2010: Commission Deliberations 

5th Meeting: Washington, DC

November 8-9, 2010: Causes of Macondo Well Blowout & Drilling Safety

6th Meeting: Washington, DC

December 2-3, 2010: Commission Deliberations 
366 Appendix F

Appendix F

List of Staff Working Papers

Over the past several months, Commission staff prepared a number of working papers 

for use by Commission members to inform their work and deliberations. Listed below are 

all of the staff working papers completed as of the date of this report. The Staff Working 

Papers can be found at www.oilspillcommission.gov. 

A Brief History of Offshore Drilling (No. 1)

Decision-Making Within the Unified Command (No. 2)

The Amount and Fate of the Oil (No. 3)

The Use of Surface and Subsea Dispersants During the BP Deepwater Horizon Oil Spill 

(No. 4)

The Challenges of Oil Spill Response in the Arctic (No. 5)

Stopping the Spill: The Five- Month Effort to Kill the Macondo Well (No. 6)

Response/Clean-Up Technology Research & Development and the BP Deepwater Horizon Oil 

Spill (No. 7)

The Story of the Louisiana Berms Project (No. 8)

Industry’s Role in Supporting Health, Safety, and Environmental Standards: Options and 

Models for the Offshore Oil and Gas Sector (No. 9)

Liability and Compensation Requirements under the Oil Pollution Act (No. 10)

Scientific Research to Support Oil and Gas Decision Making: Evolution of the Department 

of the Interior’s Environmental Studies Program (No. 11)

The National Environmental Policy Act and Outer Continental Shelf Oil and Gas Activities 

(No. 12)

Offshore Drilling in the Arctic: Background and Issues for the Future Consideration of Oil 

and Gas Activities (No. 13)

Unlawful Discharges of Oil: Legal Authorities for Civil and Criminal Enforcement and 

Damage Recovery (No. 14)
Appendix F 367 367

Long-Term Regional Restoration in the Gulf: Funding Sources and Governance Structures 

(No. 15)

Rebuilding an Appetite for Gulf Seafood after Deepwater Horizon (No. 16)

Natural Resource Damage Assessment: Evolution, Current Practice, and Preliminary 

Findings Related to the Deepwater Horizon Oil Spill (No. 17)

Continuous Improvement Is Essential: Leveraging Global Data and Consistent Standards 

for Safe Offshore Operations (No. 18)

A Competent and Nimble Regulator: A New Approach to Risk Assessment and 

Management (No. 19)

Demonstrating a Comprehensive, Rigorous Management Approach for Deepwater Drilling 

(No. 20)

Federal Environmental Review of Oil and Gas Activities in the Gulf of Mexico: 

Environmental Consultations, Permits, and Authorizations (No. 21)
368 National Commission on the BP Deepwater Horizon OIl Spill and Offshore Drilling

INDEX

Page numbers in italics refer to figures and illustrations.

accidents, offshore drilling. See safety, offshore drilling

active pit system, definition of, 109

Adair, Red, 167

Administration for Children and Families, 193

Administrative Procedure Act, 152

Agenda for Revitalizing Coastal Louisiana, 212

Alabama, effects of Macondo oil spill on, 131, 138, 140, 150, 153, 155, 172, 176–77, 185, 188, 278-79

Alaska, oil and gas industry in: Exxon Valdez spill, 36, 70, 130n, 132–33, 144, 189, 194, 211–12, 231-32; future of, 

294, 299, 301–5; history of, 2, 31, 35–36, 40, 45, 46, 52, 63, 67, 78, 220, 301; recommendations for reforms in, 

252, 253, 254, 261, 263n, 265 

Alaska Natives, 194, 303

Alexander Kjelland (rig), 68–69

Allen, Thad, 136–39, 137, 147, 151, 156–57, 161, 164–67, 169

Alonso, Dan, 142

Amerada Hess Corporation, 227

American Chemistry Council, 233

American Exploration Company, 226

American Petroleum Institute (API), 30, 71, 225, 228-29, 241-42

Amoco, 32, 40, 43, 43, 45, 221, 226-27. See also BP

Anadarko Petroleum, 2, 43, 48, 51, 90, 94, 227

Anderson, Jason, 5–6, 7–8, 17, 107, 109, 112–14

Andrus, Cecil, 62–63

annular preventers, for Macondo well, 93, 107, 108, 114, 274, 275

Apache Corporation, 227

Arco, 43, 45, 70

Arctic, oil and gas industry in, 35–36, 44, 250, 252, 253, 254, 262, 263n, 265, 294, 301–5. See also Alaska, oil and gas 

industry in

Arctic Council, 304

Arctic Offshore Oil and Gas Operation Guidelines, 304

Area Committees, 265-66, 268

Area Contingency Plans, 265–66, 268, 271

Argo, 227

Army Corps of Engineers, U.S., 154, 156-57, 169, 204, 206–08

Asian immigrant populations, in Gulf of Mexico region, 179, 192, 193

Atchafalaya River, 199, 204

Atlantic Richfield. See Arco

Atlantis site, 46–50

ATP Oil & Gas Corporation, 227

Audrey, Hurricane (1957), 25

Audubon Society, 141

Auger site, 23, 36, 38-40, 39, 42

Australia, offshore oil and gas industry in, 44, 224

Baker, James III, 221-22

Baker Hughes, 38, 44

Bankston (supply vessel), 8, 9, 12, 13, 14, 16–19, 130

barrier islands, along Gulf of Mexico coast, 154, 193–94, 199, 203, 206–07

beaches, effects of Macondo oil spill on, 155, 175–77, 185–91

Berger, Jonah, 188

berms, use of after Macondo oil spill, 151–57, 169; recommendations for reforms affecting, 265, 271

Bertone, Steve, 5, 9–11, 13–17

Betsy, Hurricane (1965), 27

Bhopal (India), chemical leak in, 231-34

BHP Billiton, 46, 51, 226-27

Bik, Holly, 177

birds, in Gulf of Mexico region, 141, 142, 143, 175–77, 181, 183

Birnbaum, Elizabeth, 151

Blanchard, Dean, 171

blowout preventer (BOP), 92; attempts to seal at Macondo well, 131–32, 137–38, 146, 149–50, 159–67, 159n, 253n, 

273; and causes of Macondo well blowout, 115, 120, 121–22; engineering challenges of, 28, 49, 52; on Macondo 

well, 7, 13, 14, 19, 92–93, 103, 114–15, 121–22; recommendations for reforms affecting, 274-75; safety regulations 

for, 73–74, 152

Blue Water 1 (drilling barge), 23, 25

Boeing, 230

Bonnie, Tropical Storm (2010), 154
Index 369 369

boom, use of after Macondo oil spill, 132, 140–41, 151–54, 153, 170, 177, 179

BP: and causes of Macondo well blowout, 90, 115–27, 125, 221; compensation of victims of Macondo well blowout and 

oil spill, 179, 185–86, 189, 193, 278, 283, 284, 287; containment initiatives after Macondo well blowout and oil spill, 

241–43; corporate revenue of, 2, 284; and drilling of Macondo well, 2–4, 42, 82–85, 89–90, 92–115, 132, 273, 274; 

engineering innovations of, 31–32; expenditures on Macondo well blowout and oil spill response, 135n, 179, 184–85, 

188, 189, 194, 238, 244, 278, 283, 284, 287; history of drilling in Gulf of Mexico, 23, 36–37, 40–41, 43, 45–53; 

lawsuits against after Macondo well blowout and oil spill, 279; response to Macondo well blowout and oil spill, 

16–17, 130–70, 174, 184–85, 188, 189, 194, 272, 274; risk-management processes of, 216–21; and safety issues, 2, 

6, 216–21, 224–25, 295

BP Deepwater Horizon Oil Budget: What Happened to the Oil?, 167–69, 167n, 168n

Brazil, offshore oil and gas industry in, 44

Breaux, John, 207

Breaux Act (1990). See Coastal Wetlands, Planning, Protection and Restoration Act (1990).

Brice-O’Hara, Sally, 136

Bromwich, Michael, 241

Brown, Douglas, 4, 9

Brown, Michael, 137

Brown, Stephen, 297

Brown & Root, 21, 24, 32

Browne, John, 45, 47

Browner, Carol, 161, 165, 167–68, 167n

Bullwinkle site, 33, 34, 36–38, 40

Bureau of Indian Affairs, 63

Bureau of Land Management, 26, 63, 76–77

Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE), 55, 131n, 241, 255, 255n, 257, 261, 

266, 273, 290

Burkeen, Dale, 17

burning of surface oil, after Macondo oil spill, 143, 159, 168–69, 168n, 168

Bush, George H. W., 24, 67

Bush, George W., 52, 137

California, oil and gas industry in, 20, 23, 26, 28–29, 29, 31, 56, 58, 63, 67, 135, 181, 297, 301

Callon Petroleum Operating Company, 227

Camardelle, David, 151

Cameron International Corporation, 131

Camille, Hurricane (1969), 27

Campbell, Pat, 167

Canada, offshore oil and gas industry in, 69, 302

capping stack, 162–67

Carden, Stan, 11, 13, 15, 16

Carla, Hurricane (1961), 27

Carter, Jimmy, 59–63

casing, offshore well, 91, 95; and attempts to seal Macondo well after blowout, 158, 162; in Macondo well, 4, 92–99, 

102–6, 113, 115; safety regulations for, 30, 43, 152

cement evaluation tools, definitions of, 102

cementing, in offshore wells, 91, 99; and attempts to seal Macondo well after blowout, 132, 167, 169; and causes of 

Macondo well blowout, 115–18, 125; in Macondo well, 1, 3–4, 7, 94, 96, 98–103; safety regulations for, 152, 228

Centers for Disease Control and Prevention, 141

centralizers, offshore well, 96; in Macondo well, 96–97, 116, 118, 123; safety regulations for, 77

C. F. Bean, 157

CGG Veritas, 44

Chaisson, Nathaniel, 102

chemical industry, safety issues in, 233

Chemical Safety Board, 219, 221-22

Chet Morrison Contractors, 44

Chevron: containment initiatives after Macondo well blowout and oil spill, 243-45; history of drilling in Gulf of Mexico, 

21, 24, 29, 32, 42, 43, 46, 47, 50, 51, 84n; oil-spill response plans of, 133; and safety issues, 226-27

Chu, Steven, 138, 148–50, 148, 161–65, 253n

civil aviation, safety issues in, 229

Clark, Donald, 17, 109

Clean Gulf Associates, 30

Clean Water Act, 80, 84, 200, 211, 245, 265, 280

climate change, 295, 298, 300, 305

Coalition to Restore Coastal Louisiana, 207

coastal and marine spatial planning, 201, 262–63, 281–82

Coastal Impact Assistance Program, 208

Coastal Studies Institute (Louisiana State University), 206

Coastal Wetlands, Planning, Protection and Restoration Act (1990), 207

Coast Guard, U.S.: recommendations for reforms in, 251, 256, 257, 266–74, 276; and regulation of offshore drilling, 

62, 68n, 75–76, 301, 304; response to Macondo well blowout and oil spill, 17–19, 129–61, 163, 170

Coast Guard-Bureau of Ocean Energy Management, Regulation, and Enforcement Deepwater Horizon Joint Investigation 

Team, 130n
370 National Commission on the BP Deepwater Horizon OIl Spill and Offshore Drilling

Coast 2050, 207

Cocales, Brett, 97, 116

cofferdam (containment dome), use of after Macondo oil spill, 145–46, 159

Cognac site, 23, 31–32

Commerce, Department of, 255

Commission on Fiscal Accountability of the Nation’s Energy Resources (1981–82), 63–64

Commission on Ocean Policy, U.S. (2004), 281

Concept Safety Evaluation program (Norway), 71

Congress, role of in regulation of oil and gas industry: history of, 56, 58–60, 62–63, 65–67, 70, 76, 79–82, 85, 269, 

298, 301; overlapping committees, 288–89; recommendations for reforms in, 249–91, 299, 304, 306

ConocoPhillips, 31, 34, 40, 42–43, 68–69, 84n, 133, 244-45

Constitution, and environmental protection, 57, 67

contracting, in offshore oil and gas industry: history of, 24, 37–38, 40, 43–44, 74; and liability issues, 245-46; 

recommendations for reforms in, 251–54; and safety issues, 221–22

Cook, Kevin, 157, 166

Cooper, Anderson, 139, 150, 157, 187

Cooper, George, 149

corals, in Gulf of Mexico, 174–75, 182, 183

Corexit (dispersant), 144

Costner, Kevin, 142

Council on Environmental Quality, 210, 260–62

Cox, Christopher, 234

crabs, in Gulf of Mexico, 175, 177–78, 186–87

Creole site, 21–22, 23

Crist, Charlie, 150, 151

Crone, Timothy, 167n

Cuba, offshore oil and gas industry in, 254, 300

Curtis, Stephen, 8, 17, 109, 113–14

Danciger Oil & Refining Co., 2

dead zone. See hypoxia

DeepStar consortium, 38

deepwater drilling: changing definitions of, 25–27, 31, 41–43, 41, 46, 52–53; engineering challenges of, 2, 24, 26–28, 

31–34, 35, 36–38, 46, 52–53, 90–92, 94; future of, 293–306; history of, 21–53, 49; moratorium on after Macondo 

well blowout and oil spill, 151–52, 185; recommendations for reforms in, 249–91, 299–300; safety issues with, 

35–36, 72–76, 216–45; size of reservoirs, 31–33, 36–45, 46–48, 51, 91; spill containment options for, 135–36, 145-

46, 149

Deepwater Horizon (rig), 1; blowout events of April 20, 8–19, 18, 88, 102–15; causes of blowout, 90, 115–27, 125; 

crew of, 1–6, 191, 198, 223; and drilling of Macondo well, 2–4, 53, 92–115; history of, 1–3, 23, 44, 51, 53; oil spill, 

127, 129–70; safety issues on, 6, 223; sinking of, 55, 130–32. See also Macondo well

Deepwater Horizon MC252 Gulf Incident Oil Budget, 167–69, 168n

Deepwater Royalty Relief Act, 23, 42, 76

Defense, Department of, 183, 208, 255. See also Army Corps of Engineers, U.S.

Dekle, Scott, 187

Deltares, 154

Dennis, Hurricane (2005), 48, 50

Denny, Patricia, 189

Department of Defense Appropriation Act of 2006, 208

departments, U.S. See specific departments under the first key term in their names (e.g., Interior, Department of the)

Designated Engineering Representatives, 230, 234

Devon Energy, 47, 227

Diamond Offshore, 43

Dickey, Bob, 187

Discoverer Enterprise, 46, 49, 145, 159, 159

Discoverer Seven Seas, 33, 37

dispersants, use of: after Macondo oil spill, 133, 143–45, 147, 160–61, 169–70, 168, 174-76, 180, 181–82, 187; 

recommendations for reforms affecting, 265, 269, 270–71, 278

diverter system, definition of, 114

Dodd, Mark, 176

dolphins. See marine mammals

Dominion Exploration & Production, 225

Drake, Edwin, 296

Dresser Industries, 44

drilling terminology, definitions of, 91

drill pipe, 74, 91; in Macondo well, 4, 5, 6–7, 92–93, 104-08, 110-14, 111, 113, 120–21

Duplessis, Bonnie, 209

Duplessis, Clarence R., 209
Index 371 37

East Cameron Partners, 227

economy, effects of Macondo oil spill on, 173–74, 179, 185-91, 200; compensatory damages related to, 174, 179, 

185–86, 189, 193, 278, 283, 284, 287; fishing and seafood industry, 139–41, 163, 170, 171, 179, 185–88, 188, 

193–94, 197, 209; health problems of local population, 191–95; local businesses, 155, 163; oil and gas industry, 

151–52, 185–86, 197; ports of, 186, 197; recommendations for reforms related to, 275–82; tourism, 155, 177, 

185–86, 188–91, 197

Effective Daily Recovery Capacity regulations, 270

Eisenhower, Dwight, 58

El Paso E&P Company, 227

emergency disconnect system, and Macondo well blowout, 13–15, 114–15

Endangered Species Act, 80, 84, 181

Energy, Department of, 59; recommendations for reforms in, 253, 253n, 264, 267, 270, 272; response to Macondo well 

blowout and oil spill, 148–50

Energy Information Administration, 302

Energy Partners, Ltd., 227

energy policy: future of, 294–306; goal of energy independence, 56, 59–60, 294

Energy Resource Technology, 227

engineering: contracting for, 24, 44; for deepwater drilling, 2, 31–32, 35, 36–38, 53, 90–92, 94; of Mississippi River, 

177, 194, 197, 204, 206, 210; recommendations for reforms in, 243, 269–70, 272–75; and response to Macondo well 

blowout and oil spill, 135–37, 143–50, 154, 156-62, 164-70

Eni US Operating Co., 227

environment, effects of Macondo oil spill on, 172-73, 173–95, 175, 176, 196-97, 202; deepwater oil plumes, 175, 

181–82; marine ecosystems, 174–82; Natural Resource Damage Assessment, 182–85, 276; recommendations for 

reforms related to, 275–82; waste from response effort, 170; wildlife health, 139–43, 153–54, 174–82

Environmental Defense Fund, 187

Environmental Protection Agency (EPA), 235; recommendations for reforms in, 257, 262, 266, 267–72, 274, 278, 282; 

and regulation of offshore drilling, 68n, 219, 255; response to Macondo well blowout and oil spill, 133, 143–45, 160, 

167n, 170, 187

environmental protection movement, 29–30, 33, 56, 58–60, 63, 79–85, 197–213

Environmental Studies Program (Department of the Interior), 59, 259, 263

equivalent circulating density (ECD), definition of, 94

erosion, in Gulf of Mexico region, 197–213, 205

Eureka (drillship), 27

explosions, history of in oil and gas industry, 8–19, 29–30, 69, 102–15, 217–20, 216, 220

ExxonMobil: containment initiatives after Macondo well blowout and oil spill, 240, 243-45; history of drilling in 

Gulf of Mexico, 25, 36, 40, 42, 42n, 45, 46, 84n; oil-spill response plans of, 133; Operations Integrity Management 

System (OIMS), 231-32; role in response to Macondo well blowout and oil spill, 164

Exxon Valdez (vessel), oil spill from, 36, 70, 130n, 132–33, 144, 189, 194, 211–12, 230, 232, 270, 277n, 280, 288

Exxon Valdez Oil Spill Trustee Council, 280

Exxon Valdez Trustee Council Science Panel, 211

Ezell, Randy, 5–8, 11, 15–16, 18, 112, 114

Fairways Offshore Exploration, Inc., 227

Farm Security and Rural Investment Act (2002), 270

Federal Aviation Administration (FAA), 230, 253n

Federal Communications Commission (FCC), 257, 290

Federal On-Scene Coordinator, 130–31, 134–36, 135n, 138, 142–44, 150, 153, 160–62, 170, 270, 276

Feinberg, Kenneth, 189, 194, 287

Fina Oil & Chemical Company, 45

fish, in Gulf of Mexico, 139–40, 174–75, 178–81, 185–88, 193–94

Fish and Wildlife Service, U.S., 58, 206, 262, 303

fishing and seafood industry, 30; effects of Macondo oil spill on, 139–43, 163, 171, 179, 183, 185–88, 188, 193–94, 

197, 209, 278–79; overfishing by, 199, 201

Fitzgerald, Timothy, 187

Flex Trend site, 31–32

Fleytas, Andrea, 7, 10, 15, 16

float valves, in Macondo well, 98, 102, 116–19

Flood Control Act (1928), 204

Florida, 208; effects of Macondo oil spill on, 131, 138, 140, 150, 153, 174, 177, 188–89, 191, 278; offshore oil and gas 

industry in, 67, 67n, 254, 297

Florida Department of Environmental Protection, 153

Florida Restaurant and Lodging Association, 191

flow-rate estimates, Macondo oil spill, 132, 133, 146–47, 149–50, 158, 166, 167, 167n, 274

Flow Rate Technical Group, 147, 167n

Food and Drug Administration (FDA), 170, 187

food safety, concerns about after Macondo oil spill, 170, 185–88, 278–79

Forcenergy, 227

Ford, Gerald, 63

Forest Oil Corporation, 227

Formal Safety Assessment program (United Kingdom), 71

Forties Alpha platform (BP), 219
372 National Commission on the BP Deepwater Horizon OIl Spill and Offshore Drilling

fracture pressure, definition of, 90

Frank’s Casing Crew and Rental Tools, 44

Freeport McMoRan, 227

Gagliano, Jesse, 96–97, 101, 102

García Márquez, Gabriel, 53

Garwin, Richard, 149, 165

Gauthe, Sharon, 192

Gazprom (company), 300

Geological Survey, U.S., 25–26, 28–30, 63–65, 79; recommendations for reforms in, 253, 263, 264, 270, 272, 274; 

response to Macondo well blowout and oil spill, 147, 161, 166, 168n

geology, subsurface, 52–53; Lower Miocene deposits, 47; Lower Tertiary (Paleogene) deposits, 23, 47, 51, 52; at 

Macondo site, 2, 3, 89; Middle Miocene deposits, 3; role of salt in, 22, 24, 32–33, 39, 41-43, 45, 49, 52; technology 

for surveying, 27, 32–34, 37–38; Upper Jurassic deposits, 39

Geophysical Services Inc. (GSI), 37

Gervasio, Antonio, 12

Glasscock Drilling Company, 25

Global Industries, 44

Global Marine, 36, 44

GlobalSantaFe, 2

Glomar Challenger (drillship), 27

Gonzalez, Elian, 136

Gordon, Wayne, 163

GovernanceMetrics International, 231, 232n

government, role of in oil and gas industry. See regulation of oil and gas industry, federal and specific departments and 

agencies by name

Government Accountability Office, 261

Grangemouth Complex (BP), 218–19

Greater New Orleans, 191

Great Flood of 1927, 197, 204

Great Lakes, 263

Green Canyon, oil and gas drilling in, 40, 46–48 

Greenland, offshore oil and gas industry in, 302

Guide, John, 4, 96, 97, 98, 99, 102, 116

Gulf Coast Claims Facility, 185–86, 189, 193, 283, 287

Gulf Coast Ecosystem Restoration Council, recommendation for, 280–81

Gulf Coast Ecosystem Restoration Science and Technology Program, recommendation for, 281

Gulf Coast Ecosystem Restoration Task Force, 210, 279

Gulf Island Fabricators, 44

Gulf of Mexico: economic impact of Macondo oil spill on, 139–43, 173–95; environmental impact of Macondo oil spill 

on, 139–43, 173–95; environmental recovery and restoration of, 197–213; future of, 293–306; history of drilling in, 

2, 21–53; recommendations for reforms affecting, 249–91; regulation of drilling in, 55–57, 62, 65–67, 71, 72–76, 

80–85

Gulf of Mexico Alliance, 185

Gulf of Mexico Energy Security Act (2006), 208, 210

Gulf of Mexico Integrated Ocean Observing System, 282

Guns of Navarone, The, 162

Gustav, Hurricane (2008), 197–98, 203

Hafle, Mark, 2, 97

Haire, Chris, 109

Hall-Houston Oil Company, 226

Halliburton Company, 38, 44, 74; and causes of Macondo well blowout, 90, 115–18, 123-25, 125, 223; and cementing 

of Macondo well, 1, 2–4, 90, 94–103; and safety issues, 222-24, 295

Hanzalik, James, 130

Harrell, Jimmy, 4–5, 11, 13, 17, 92, 107

Hay, Mark, 19

Hayward, Tony, 135, 144, 150, 157, 159

health, effects of Macondo oil spill on human, 141, 144, 170, 174, 185–88, 190, 192, 191–95, 277–78

Health and Human Services, Department of, 141

Hecht, Michael, 191

Heerema Marine Contractors, 44

Helis Oil & Gas Corporation, 227

Helix Energy Solutions Group, 244-45

Herbst, Lars, 135, 157

Hess Corporation, 51

Hickel, Walter, 29

Hilda, Hurricane (1964), 27

Hitec system, 110, 110n, 112

Holloway, Caleb, 113
Index 373 373

Holstein site, 46–49

Homeland Security, Department of, 62, 131, 255. See also Coast Guard, U.S.

Hormuz, Straits of, 296

Houston, Oberon, 219

Houston Exploration Company, 226-27

Hsieh, Paul, 166

Humble Oil, 24, 27

Hunt Oil Company, 227

Hunter, Tom, 148, 149, 161–62, 165

Huntington, Hillard, 297

hurricanes. See specific hurricanes by name (e.g., Katrina, Hurricane)

hypoxia, in Gulf of Mexico, 198–200

Hyundai Heavy Industries, 44

Ida, Hurricane (2009), 2, 92

Ike, Hurricane (2008), 198, 296

Incident Command Posts, 130–31. See also Unified Command

Inglis, Andy, 146

injuries, offshore drilling. See safety, offshore drilling

Institute of Nuclear Power Operations (INPO), 234–42, 239n, 240n

Interagency Alternative Technology Assessment Program, 142

Interagency Ocean Policy Task Force, 262, 281

Interior, Department of the, 54; changes in after Macondo well blowout, 250; and environmental recovery and 

restoration of Gulf of Mexico, 181-83; history of regulation by, 29, 33, 55–85, 228-29, 239-240; recommendations 

for reforms in, 249–91, 299, 304; response to Macondo well blowout and oil spill, 55, 78n, 131, 131n, 143, 145, 

152, 181, 183. See also Minerals Management Service (MMS) and other specific agencies by name

International Association of Drilling Contractors (IADC), 72

International Organization for Standardization (ISO), 252, 304

International Regulators’ Forum, 252, 254

Iran: oil and gas industry in, 36, 45, 296; Revolution of 1979, 31, 63

Iraq, oil and gas industry in, 296

Ivan, Hurricane (2004), 50

Ixtoc oil spill, 225, 244

Jackson, Lisa, 145, 160–61, 167n

Jack 2 site, 23, 47

Jindal, Bobby, 138–39, 150–51, 151, 153, 154, 156–57, 169, 212

Johnfroe, Donald Jr., 192

Joint Oceanographic Institutions for Deep Earth Sampling project, 27

Jones, Gordon, 17

Jones Act, 142–43

J. Ray McDermott, 24, 31-32, 44

junk shot, 148–49

Justice, Department of, 30, 287

Kaluza, Robert, 3, 6, 14, 98, 105, 107, 124

Kash, Don, 64–65

Katrina, Hurricane (2005), 50, 136–37, 145, 163, 191–93, 195, 198, 203, 206, 208–9, 212, 296

Keith, Joseph, 109, 112

Kelley, Merrick, 120

Kemp, Roy Wyatt, 17, 112

Keplinger, Yancy, 7, 11, 15, 16

Kermac 16 site, 23, 24

Kerr-McGee Oil Industries, 22, 24, 48, 227

kick detection, in Macondo well, 91, 109–14, 120-21

Kleppinger, Karl Dale, Jr., 17

Kuchta, Curt, 4–5, 7-8, 13, 14–17

Kuwait, oil fires in during first Gulf War, 149

Lambert, Lee, 107

Landrieu, Mary, 150, 152, 204

Landrieu, Mitch, 150, 151

Landry, Alwin J., 12, 14
374 National Commission on the BP Deepwater Horizon OIl Spill and Offshore Drilling

Landry, Mary, 130-31, 133-34, 134, 143

Lawrence Berkeley National Laboratory, 148

Leasing and Environmental Science Office, recommendation for, 258–59, 261, 262, 264

leasing of offshore drilling sites, federal, 61; and environmental considerations, 29, 59–63, 79–82; history of, 24, 26, 

31, 33, 52-52, 58–63; recommendations for reforms in, 249–91; royalties from, 56, 58, 63–67, 64, 76–78, 295

Lee, Alvin, 156

Leno, Jay, 149

levees, on Mississippi River, 197, 204, 206, 208, 210

Lili, Hurricane (2002), 50

Lindsay, Sheryl, 155

LLOG Exploration Offshore, Inc., 227

lockdown sleeve, on Macondo well, 104, 120, 123, 127

Louisiana: effects of Macondo oil spill on, 138–40, 150–54, 156-57, 161, 163, 171, 174–81, 187–88, 191–95, 271, 276, 

278; environmental recovery and restoration of, 197–213; oil and gas industry in, 21–53, 58, 60, 78, 292, 292-93, 

297

Louisiana Act 6 (1989), 207

Louisiana Coastal Area Comprehensive Coastwide Ecosystem Restoration report, 207

Louisiana Coastal Area Ecosystem Restoration Program, 207

Louisiana Coastal Protection and Restoration Authority, 208

Louisiana Coastal Protection and Restoration Fund, 208

Louisiana Department of Health and Hospitals, 140

Louisiana Department of Wildlife and Fisheries, 140

Louisiana-Mississippi Gulf Coast Ecosystem Restoration Working Group, 210

Louisiana National Guard, 133

Louisiana Office of Coastal Protection and Restoration, 154

Louisiana State University Charity Hospital, 195

Lubchenco, Jane, 167n, 168–69

Lutz, Peter, 133

Lyder, Jane, 181

Lynch, Richard, 146, 160

Mabus, Ray, 210, 211, 279–80

MacDonald, Ian, 186, 187

Macondo well: attempts to seal after blowout, 131–32, 137–38, 149–50, 159n, 162, 164-67; blowout events of April 

20, 8–19, 88, 102–15; causes of blowout, 89, 115–27, 125; drilling of, 2–4, 23, 53, 89–115, 93; geology of site, 3, 

89; naming of, 53 oil spill from, 127, 129–70; Oil Spill Response Plan for, 84, 133; permit process for, 77, 82–84, 104, 

108, 127, 132; relief wells, 132, 135, 157, 158, 166–67, 169

Mad Dog site, 46–49

Magnuson-Stevens Fishery Conservation and Management Act, 80, 81, 83–84

mangroves, effects of Macondo oil spill on, 175, 177, 186

Mansfield, Brent, 10–11, 17

Manti Operating Company, 227

Manuel, Blair, 17

Marathon Oil Corporation, 51

Marianas (rig), 2, 92–93

Marine Board (National Research Council), 70–71

marine ecosystems, effects of Macondo oil spill on, 174-78, 180-182

Marine Mammal Commission, 181

Marine Mammal Protection Act, 80

marine mammals: in Arctic oil regions, 303; in Gulf of Mexico, 174–75, 178, 180, 181, 183

Marine Protected Areas, 282

Mariner Energy, 51, 227

Marine Spill Response Corporation, 132–33, 243

Marine Well Containment Company (MWCC), 243-45

marshes: effects of Macondo oil spill on, 139, 143, 154, 174-75, 177, 181, 186, 202; and environmental recovery and 

restoration of Gulf of Mexico, 202, 205–8

Mars site, 36–37, 40, 45, 50

Martinez, Dennis, 17

Massachusetts, coastal and marine spatial planning in, 201

Matrix Oil & Gas, 227

Matterhorn (rig), 19

Max Chouest (vessel), 19

McKay, Douglas, 58

McNutt, Marcia, 147–49, 161, 165, 274

Meche, Gregory, 12, 112

media coverage of Macondo well blowout and oil spill: effects of on food safety concerns and tourism, 187–88; initial, 

129–30; of response to oil spill, 139, 141, 142–43, 142n, 149, 150, 167–68

Meinhart, Paul, 15

Melancon, Charlie, 150

Merritt, Carolyn W., 219

Meshkati, Najmedin, 223
Index 375 375

Mexico, oil and gas industry in, 21, 254, 300

microbes. See oil-degrading microbes

Minerals Management Service (MMS), 54, 73, 75; and causes of Macondo well blowout, 126–27; corruption and 

mismanagement in, 77–79, 250, 251, 254–55; creation and early history of, 23, 33, 36, 38–39, 42, 56, 63–69; 

environmental protection role of, 55–57, 79–85, 206, 254–55; permit process for Macondo well, 82–85, 126–27, 

273; permitting role of, 55–57, 254–55; reorganization of after Macondo well blowout, 55, 131n, 255; response to 

Macondo well blowout and oil spill, 19, 131, 131n, 133, 135–36, 145, 149–50, 152, 157, 161; revenue collection role 

of, 55–57, 63–67, 64, 76–78, 254–55; and safety issues, 67–76, 75. See also Bureau of Ocean Energy Management, 

Regulation, and Enforcement (BOEMRE)

Mississippi, 208: effects of Macondo oil spill on, 131, 138, 140, 170, 177, 187, 191, 193

Mississippi Canyon, oil and gas drilling in, 2, 3, 31, 42, 46, 47-48, 53, 89

Mississippi Canyon Block 252, 2, 53, 89, 92

Mississippi River: agricultural pollution in, 198–200; effects of Macondo oil spill on, 177, 178; environmental recovery 

and restoration of, 197–213; geology of, 22, 27, 202, 204; in history of oil and gas industry, 22, 24, 27, 31, 37, 50; 

re-engineering of, 194, 197, 204, 206, 210

Mississippi River and Tributaries Project, 204

Mississippi River Gulf of Mexico Watershed Nutrient Task Force, 200

Mississippi River Gulf Outlet, 206

M-I SWACO, 3, 98, 106

MMS. See Minerals Management Service (MMS)

mobile drilling, history of, 24–26, 44

Mobil Oil. See ExxonMobil

MOEX, 2, 90, 94

Montara (platform), 224

Monterey Bay Marine Sanctuary, 67

moratoriums, offshore drilling, 36, 52, 58, 67; in response to Macondo well blowout and oil spill, 151–52, 185, 247

Morel, Brian, 2, 3, 4, 96, 97, 98, 102, 104, 116, 123

Mr. Charlie (drilling barge), 23, 24

Mr. Gus (drilling barge), 25

mud, use of in offshore wells, 91, 105, 106; and causes of Macondo well blowout, 115, 120–24, 125; in Macondo well, 

7, 8, 92–94, 96, 98–99, 103-07, 109-14; in top kill and static kill efforts at Macondo well, 149–50, 158, 166–67

mudflats, effects of Macondo oil spill on, 175, 177

Munich Re, 246

Murphy Exploration & Production Company, 227

Murray, Chad, 11, 13, 15, 16

Na Kika project, 46, 48

Nalco, 144

Napolitano, Janet, 131, 136

National Academy of Engineering, 223, 253

National Academy of Sciences, 264, 296, 303

National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling, 151, 192, 225, 249–50, 291, 295, 

305–6

National Contingency Plan, 130-32, 134-36, 138-39, 141, 144, 265-69, 271-72, 274, 277–78, 304

National Domestic Violence Hotline, 193

National Energy Act (1978), 59

National Environmental Policy Act (NEPA) (1970), 29, 56, 59, 60, 62, 80–82; and Macondo well blowout, 81n, 82–84, 

83n; recommendations for reforms in, 258–62, 265, 267, 289

National Incident Commander, 136–37, 141, 143, 156, 267, 268, 270

National Marine Fisheries Service, 140, 141

National Marine Sanctuaries, 80, 81, 282

National Ocean Council, 201, 276, 281–82

National Oceanic and Atmospheric Administration (NOAA); and environmental recovery and restoration of Gulf of 

Mexico, 201, 212; recommendations for reforms in, 253, 256, 257, 262–68, 270-71, 274, 282; and regulation of 

offshore drilling, 68n, 81, 84, 84n; response to Macondo well blowout and oil spill, 131, 133, 140–41, 143, 145, 153, 

157, 168–70, 178, 181, 183, 187, 189

National Oceanographic Partnership Program, 264

National Research Council, 298

National Response Framework, 278

National Response Team, 131, 141, 268, 269, 272, 274

National Science Foundation, 28, 184, 276

National Wildlife Federation, 141

Natural Resource Damage Assessment, 182–85, 186, 264, 276–77, 276n

Natural Resources Revenue, Office of (ONRR), recommendation for, 256-60

Naval Petroleum Reserve, 58, 296

Navy, U.S., 22–24, 58, 228–30, 234

negative-pressure tests, 105; and causes of Macondo well blowout, 118, 119, 121, 123–24, 125, 126; on Macondo well, 

4-7, 104-09, 112; safety regulations for, 228

Neptune site, 23, 43

Newfield Exploration Company, 51, 226

Nguyen, Ve Van, 179
376 National Commission on the BP Deepwater Horizon OIl Spill and Offshore Drilling

Nigeria, oil and gas industry in, 36, 45

Nixon, Richard M., 29, 31, 59, 63, 135

NOAA. See National Oceanic and Atmospheric Administration (NOAA)

NOAA Catch Share policy (2010), 201

Norcen Explorer, 226

North Sea, oil and gas industry in, 23, 31, 34, 38, 45, 68–69, 71–72, 124, 218, 225, 252

Norway, offshore oil and gas industry in, 68–69, 71, 201, 218, 302

Nuclear Electric Insurance Limited (NEIL), 237

nuclear power, safety issues in, 229-31, 235-41

Nuclear Regulatory Commission (NRC), 235-37, 239, 253n, 258

Nungesser, Billy, 150–51, 151, 154, 156–57

Obama, Barack: address on Macondo well blowout and oil spill, 173, 212; commissioning of studies after Macondo well 

blowout and oil spill, 249, 279-80, 291; creation of BP escrow fund, 185; environmental policies of, 201, 210, 212, 

262–63, 281; plan to expand offshore leasing, 53, 84n, 301; response to Macondo well blowout and oil spill, 131, 

136, 148, 150–51, 151, 156, 162, 191

O’Bryan, Patrick, 5-8, 14, 105

Occidental Petroleum, 69, 219

Occupational Health and Safety Administration (OSHA), 68n, 141, 144, 234

occupational safety, definition of, 218

Oceaneering, 3, 38

Ocean Endeavor (rig), 19

Ocean Energy, 226

Ocean Energy Safety Institute, 272

Ocean Foundation, 181

Ocean Ranger (rig), 69

OCS Group, 3

Odum, Marvin, 233

Office of Management and Budget (OMB), 72, 210, 251

Office of Natural Resources Revenue, 55

offshore drilling. See deepwater drilling; oil and gas industry, offshore; and specific aspects of the offshore oil and gas 

industry by name

Offshore Drilling and Exploration Company, 24

Offshore Operators Committee, 28, 30, 72

Offshore Safety and Anti-Pollution Equipment Committee, 30

Offshore Safety Authority, recommendation for, 256, 257–58, 289–90

Offshore Technology Conference, 30, 52

Ognedal, Magne, 69, 218

oil and gas industry, offshore: corporate safety culture of, 215–47; future of, 293–306; history of, 21, 21–53, 55–85; 

recommendations for reforms in, 215–16, 239–45, 249–91, 293, 306; regulatory history of, 55–85; and supply and 

demand for oil in U.S. history, 22, 25, 31–33, 34, 46, 52, 63, 293–306. See also specific companies and aspects of the 

industry by name

Oil Budget report, 167–69, 168n

oil-degrading microbes, 174

Oil Pollution Act (1990), 70, 80, 83–84, 130n, 132, 182–85, 191, 212, 232, 245; recommendations for reforms in, 

268–70, 276, 279, 283, 286–87

Oil Spill Liability Trust Fund, 134, 135n, 141, 211, 283–87, 304

Oil Spill Response Plans, 83–84

oil spills: history of, 2, 23, 28–29, 29, 31, 36, 53, 56, 58–59, 63, 71, 130n, 132–33, 135, 144, 174, 181, 189, 194, 

211–12, 216–20, 223–25, 230–31, 232, 241, 243, 270, 277n, 280, 288; after Macondo well blowout, 127, 129–70, 

198

One Hundred Years of Solitude (García Márquez), 53

OPEC oil embargo (1973), 31, 56, 296

Orca Energy (Dunhill), 227

Oregon, offshore oil and gas industry in, 26, 67, 297

Oryx Energy, 43, 226

Outer Continental Shelf Lands Act and Amendments (1953/1978), 23, 30, 57–64, 79, 80, 84, 254–56, 262–64

Outer Continental Shelf Safety Oversight Board, 78–79, 78n, 82

Overton, Keith, 191

oysters, in Gulf of Mexico, 140, 163, 176, 178–79, 186–87

Paradis, Joseph, 130

Parish Presidents (Louisiana), 139–40, 154

Patzek, Tad, 229

Pemex, 254, 300

Pennsylvania, oil and gas industry in, 296

Pennzoil, 32

Perdido site, 51
Index 377 377

Perry, Harriet, 178

Petrobras, 44, 51, 226

Petroleum Geo-Services, 44

Philadelphia Electric, 238

Phillips Petroleum Company. See ConocoPhillips

Pillow, Travis, 187

pipelines, oil and gas, 25, 30, 35, 49, 296, 302

Pipeline Safety Act, 256

Piper Alpha (platform), 23, 69–70, 217, 227

Placid Oil, 34

platforms, offshore oil and gas, 22, 24–25, 28, 30, 34–35, 35, 39, 41–42

Pleasant, Christopher, 6, 13, 19, 114–15

Pompano (U.S. Coast Guard cutter), 17, 130

pore pressure, definition of, 90

positive-pressure tests, on Macondo well, 4, 104, 105

President’s Council of Advisors in Science and Technology, 298

President’s Council on Environmental Quality, 81n, 83, 84n

Price-Anderson Act, 237

Primary Care Access Stabilization Grants, 195

process safety, definition of, 218

Project Independence, 31

Project Mohole, 26

Prudhoe Bay pipeline (BP), 2, 222

Pure Oil, 21

Q4000 (vessel), 159–60, 159

R&B Falcon, 44

Ragen, Tim, 181

Rainey, Dave, 45

Ramblin’ Wreck (boat), 10, 17

rams, in offshore well blowout preventer, 52, 74: and causes of Macondo well blowout, 122; in drilling of Macondo 

well, 92–93, 114; and oil spill after Macondo well blowout, 131, 137–38, 149, 275

Randolph, Charlotte, 150

Rapid Response Research (RAPID) Program, 184

Reagan, Ronald, 63, 66

Regional Citizens’ Advisory Councils, 268–69

Regional Contingency Plans, 265

Regional Response Teams, 143, 145, 265, 268, 271

regulation of oil and gas industry, federal: and causes of Macondo well blowout, 126–27; changes in after Macondo 

well blowout and oil spill, 55, 72, 152, 211–12, 228, 255; compared to other nations, 69–72; compared to other risky 

industries, 229–41; conflicting priorities in, 28, 55–60, 65, 68–76, 80–82, 200–201, 228–29, 254–55; congressional 

role in, 56, 58–60, 62–63, 65–68, 71, 72, 76, 79–82, 85, 269, 298, 299, 301, 304, 306; Constitutional authority for, 

57, 67; definition of lands under federal control, 58, 239; failure to respond to changes in industry, 72–74, 228, 239; 

history of, 29, 55–85; and industry self-policing, 234-35, 237–42; liability issues, 243–46; recommendations for 

reforms in, 215–16, 239–45, 249–91, 293, 299, 306. See also specific regulatory agencies by name

relief wells, at Macondo site, 132, 135, 158, 159, 166–67, 169

remotely operated vehicles (ROV), 38; in drilling of Macondo well, 3, 93; in response to Macondo well blowout, 19, 

131–32, 146, 164

renewable energy sources, 256–59, 264, 294–95

Repsol (company), 300

Resource and Conservation Recovery Act, 106–7

response to Macondo well blowout and oil spill, 129–70; attempts to seal blowout preventer, 131–32, 137–38, 146, 

149–50, 159–67, 159n; boom and berms, 151–57, 169–70; capping stack, 162–67; cofferdam (containment dome), 

145–46, 150, 159; compensation of victims, 179, 185–86, 189, 194, 278, 283, 284, 287; confusion of authority 

in, 130, 135–36, 138–39, 149, 151, 160–61 dispersant use, 133, 143–45, 147, 160–61, 169–70, 174, 180, 181–82, 

187; firefighting, 130–31, 130n; flow-rate estimates, 132, 133, 146–47, 149–50, 158, 166, 167, 167n, 274; local 

population and, 139–43, 152–55, 170; moratorium on offshore deepwater drilling, 151–52, 185; nuclear option, 146; 

oil removal efforts, 132–33, 140–45, 151–57, 168–69; plumes controversy, 181–82; recommendations for reforms 

related to, 249–91; relief wells, 132, 135, 157, 158, 166–67, 169; search and rescue efforts, 12–19, 129–32; top kill 

and junk shot, 148–50, 158–59, 161–62, 166. See also specific companies, government agencies, and individuals by 

name

Responsible Care initiative (American Chemistry Council), 233

Revette, Dewey, 5, 17, 107–9, 112–13

Rhode Island, coastal and marine spatial planning in, 201

Rickover, Hyman, 230

Riley, Bob, 150, 153

riser, offshore well: engineering challenges of, 37, 49, 51; and Macondo well, 7, 14, 18, 103–11, 103n, 114, 115, 120, 

121, 124; and oil spill at Macondo well, 132–33, 132, 145-47, 159, 159n, 164
378 National Commission on the BP Deepwater Horizon OIl Spill and Offshore Drilling

Riser Insertion Tube Tool, 146

risk management, offshore oil and gas industry, 217-47, 251–54. See also safety, offshore drilling

Rita, Hurricane (2005), 50, 136–37, 145, 197–98, 208, 212, 296

Robichaux, Brenda Dardar, 193, 203

Rooster Petroleum, 227

Roshto, Shane, 17, 112

Royal Dutch Shell. See Shell Oil

rupture disks, in Macondo well, 158–59, 162, 274

Russia, offshore oil and gas industry in, 302

safety, offshore drilling: accident and injury rates, 3, 27-28, 30, 55, 69, 217-28, 226, 228, 232, 251, 254; changes in 

regulation of after Macondo well blowout and oil spill, 55, 72, 227, 243; compared to other risky industries, 229-42; 

conflict with revenue generation, 56, 254–55; corporate culture and, 215–47; with deepwater drilling, 35–36, 90–91; 

in hurricanes, 22, 25, 27, 50–51; inspections for, 68–76, 75, 78–79; insurance for, 245-46; recommendations for 

reforms in, 215–17, 239–45, 249–91, 293–95; regulation of, 28–30, 56, 68–76. See also explosions; oil spills

Safety and Environmental Enforcement, Bureau of, 55

Safety and Environmental Management Program (SEMP), 71–72, 242

Safety and Environmental Management System (SEMS), 228, 251, 253, 257

safety case approach, 68–69, 227, 252, 252n, 258

safety culture, definition of, 218

Salazar, Ken, 55, 78, 78n, 131–32, 131n, 136, 147–48, 148, 151–52, 161, 165, 255, 260, 301

salt, role of in offshore oil and gas reservoirs, 22, 24, 32–33, 39, 41–43, 45, 49, 52

Salvin, Bill, 147

Sandell, Micah, 9, 12

Sandia National Laboratories, 149

Santa Barbara Channel, oil spill in (1969), 23, 26, 28–29, 29, 31, 56, 58–59, 63, 135, 181

Saucier, Mike, 135

Saudi Arabia, oil and gas industry in, 21

Schlumberger, 3–4, 38, 44, 103, 118, 129

Scire, Grace, 192

Sears, Richard, 223

Securities and Exchange Commission (SEC), 234

Sedco-Forex, 44

September 11, 2001, terrorist attacks of, 75, 136

September 11th Victim Compensation Fund, 185, 287

Sepulvado, Ronald, 3

Shaw Group, 157

Shell America (vessel), 33

Shell Oil, 301–2; containment initiatives after Macondo well blowout and oil spill, 243-45; history of drilling in Gulf of 

Mexico, 21, 23, 24, 25–26, 30–30, 31–34, 36–41, 45, 48, 51, 84n; oil-spill response plans of, 133; role in response to 

Macondo well blowout and oil spill, 164; and safety issues, 226, 231-33

Shivers, Bradley, 10

shoe track, in Macondo well, 97–98, 97, 102, 120, 121

shrimp, in Gulf of Mexico, 140, 144, 175, 179, 186–87

Sierra Club, 65

Sims, David, 4–8, 14, 17, 19, 97

Skidmore, Ross, 4

skimming, use of after Macondo oil spill, 129, 132, 140, 143, 154, 161, 167n, 168, 169

Slocum, Alexander, 149

Smit Salvage Americas, 130

Sole, Mike, 153

Sonat Offshore Drilling, 33, 37

spacer, in Macondo well, 7, 7n, 106–9, 106, 111–12, 119, 121

Sperry Sun, 109–11, 110n, 112, 121

Spill of National Significance designation, 136–37, 155, 267–68, 278–79, 283, 287

Sport Fish Restoration and Boating Trust Fund, 207

Stafford Act (1988), 138, 268–69

Standard Oil of California, 21

Standard Oil of New Jersey, 24

Stanislaus, Mathy, 161

State On-Scene Coordinators, 138

static kill, 166–68

Statoil, 44, 47, 51

Stone Energy Corporation, 227

Strategic Petroleum Reserve, 296–97

Strickland, Tom, 136

Submerged Lands Act (1953), 23, 58

SUBSAFE system, 230-31, 234

Substance Abuse and Mental Health Administration, 194

Sunseri, Al, 163

Sunseri, Blake, 163

Sunseri, Sal, 163
Index 379 379

Superior Energy Services, 167

Superior Oil, 21

Suttles, Doug, 133, 134, 145, 146, 159, 164

Tabler, Vincent, 102

Taffaro, Craig, 140

Tana Oil and Gas Corporation, 226

Taylor, Sharon, 142

Technip, 44

temporary abandonment procedures, 4n, 77, 103; at Macondo well, 4, 6, 103–6, 109, 119–20, 123, 126–27

Tenneco, 32

Texaco, 21, 27, 38

Texas: effects of Macondo oil spill on, 177; oil and gas industry in, 2, 21–53, 58, 217–20, 297

Texas City refinery (BP), 2, 218–22

Thierens, Harry, 138

3-D seismic imaging, for offshore drilling, 27, 33, 37–38, 42–45

Three Mile Island meltdown (1979), 229, 235, 239, 240n

Thunder Horse site, 23, 46-47, 49

Tiber site, 51

Tillerson, Rex, 232, 240

Tolstoy, Maya, 167n

Tooms, Paul, 150, 161

top kill, 148–50, 158–59, 161–62, 166

Total (oil company), 43, 44, 52

tourism, effects of Macondo oil spill on, 155, 185–86, 188–91, 197

Trahan, Buddy, 5, 7, 11, 13, 17

Trans-Alaska Pipeline, 35, 302

Transocean, 44, 74; and causes of Macondo well blowout, 90, 115–27, 124, 223; and drilling of Macondo well, 2–4, 90, 

92–115 response to Macondo well blowout and oil spill, 130–31, 137–38; and safety issues, 223-23, 295

Transportation, Department of, 68n, 255

tribal communities, in Gulf of Mexico region, 193–94

Tri-Union Development Corporation, 227

Truman, Harry, 58, 296, 298

Trustees for Natural Resources, 277, 282

tuna, in Gulf of Mexico, 83n, 175, 178, 180

Turner, Eugene, 177

turtles, in Gulf of Mexico, 175, 180–81, 180, 183, 184

Ultra-Deepwater and Unconventional Natural Gas and Other Petroleum Resources Program, 253

Unified Area Command, 131, 135, 139, 161, 181

Unified Command, 131–33, 135, 138–41, 143–46, 149, 154

Union of Concerned Scientists, 239n

Union Oil Company, 28, 32, 58, 227

Union Pacific Resources Company, 227

United Houma Nation, 193–94, 203

United Kingdom, offshore oil and gas industry in, 69–72, 218-19, 228-29

United Kingdom Health and Safety Executive, 218-19

U.S. departments and services. See specific departments and services under the first key term in their names (e.g., Coast 

Guard, U.S.; Interior, Department of the)

USS Thresher (submarine), 229, 230, 231

Utilities Solid Wastes Activities Group, 235

Valdez, oil spill from See Exxon Valdez (vessel), oil spill from 

Van Oord, 154

Vastar Resources, 226

Vessels of Opportunity program, 129, 140–41, 170, 287

Vidrine, Don, 6, 8, 13, 107–8, 112

Virginia, offshore oil and gas industry in, 301

Vitter, David, 150, 156

W & T Offshore, 227

Walter Oil & Gas Corporation, 227
380 National Commission on the BP Deepwater Horizon OIl Spill and Offshore Drilling

Walz, Gregory, 97

Washington, offshore oil and gas industry in, 26, 67, 297

Water Resources Development Act (2007), 207

Watson, James, 160, 162

Watt, James, 56, 63–67, 66, 76

Weatherford International, 96, 98

Weise, Adam, 17, 112

Well Integrity Team, 162, 164

Wereley, Steve, 147

West Africa, offshore oil and gas industry in, 44

Western-Geco, 44

wetlands, in Gulf of Mexico region, 173, 175, 194, 197-208, 210-13

whales. See marine mammals

Wheeler, Wyman, 5–6, 11, 15–16, 107

wildlife, in Gulf of Mexico. See specific types of wildlife by name

Wild Well Control, 167

Williams, Mike, 9, 10, 15–16

Winslow, Daun, 5, 6, 7, 12–14, 17, 19

Woods Hole Oceanographic Institution, 146–47, 147n

workforce, offshore oil and gas industry: effects of Macondo oil spill on, 152, 185; logistical challenges of, 3, 22, 34; 

and safety issues, 3, 6, 28, 30, 69, 152, 215-29, 232-34, 239-42, 251; whistleblowers in, 254

Worley Parsons, 44

wrack zone, 177

Young, David, 16, 112–13

Zane Barnes (vessel), 36

Zapata Offshore Company, 24

Zukunft, Paul, 161, 170
Index 381 38
ISBN: 978-0-16-087371-3

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