Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 1 of 150
IN THE UNITED STATES DISTRICT COURT
FOR THE SOUTHERN DISTRICT OF TEXAS
HOUSTON DIVISION
In Re: BP P.L.C., SECURITIES ) Case No.: 10-md-2185 LITIGATION ) ) ) HON. KEITH P. ELLISON
CONSOLIDATED CLASS ACTION COMPLAINT FOR
FOR VIOLATIONS OF FEDERAL SECURITIES LAWS
(SUBCLASS)
JURY TRIAL DEMANDED Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 2 of 150
TABLE OF CONTENTS
Page
I. INTRODUCTION 2
II. THE PARTIES. 7
A. PLAINTIFFS 7
B. DEFENDANTS 9
1. CORPORATE DEFENDANT. 9
2. INDIVIDUAL DEFENDANTS. 9
C. UNNAMED PARTICIPANTS. 13
III. JURISDICTION AND VENUE 14
A. JURISDICTION AND VENUE. 14
B. CAUSE AND EFFECT IN THE UNITED STATES . 15
IV. SUBCLASS ACTION ALLEGATIONS 16
V. FACTUAL ALLEGATIONS 18
A. BP’S RAPID GROWTH: ACQUISITIONS AND DEEP SEA EXPLORATION
OF THE GULF OF MEXICO 18
1. THE CHALLENGES OF DEEPWATER OIL DRILLING IN THE GULF
OF MEXICO 20
2. STATUTES AND REGULATIONS RELEVANT TO OFFSHORE
DRILLING. 21
3. THE PROCESS OF FINDING AND DRILLING A DEEPWATER
OFFSHORE WELL. 23
a. Searching for and Finding a Reservoir of Oil and Gas. 23
b. Drilling A Well. 25
i Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 3 of 150
c. Preparing for Oil Extraction. 27
d. Temporary Abandonment. 31
B. BP’S CORPORATE STRATEGY OF DRACONIAN COST-CUTTING . 33
C. BP’S HISTORY OF SAFETY LAPSES 34
1. 2003: FORTIES ALPHA. 34
2. 2005: TEXAS CITY DISASTER 35
a. Background of the Texas City Disaster 35
b. US Chemical Safety and Hazard Investigation Board Report 37
c. BP Issues Incident Investigation Report. 39
d. Costs and Consequences to BP of the Texas City Disaster 40
3. 2005: THUNDER HORSE. 40
4. 2006: PRUDHOE BAY, ALASKA. 41
a. Employees’ Complaints of Cost Cutting At the Expense
of Safety. 42
b. BP Pleads Guilty . 46
D. REGULATORY REPORTS FORCE BP TO ADDRESS, AT LEAST
PUBLICLY, SAFETY LAPSES 47
1. BAKER REPORT 47
2. U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD
FINAL REPORT 54
E. BP RESPONDS TO ENVIRONMENTAL DISASTERS BY PROMISING
CHANGE. 55
F. BP MISLEADS INVESTORS REGARDING THE SAFETY OF ITS GULF
OPERATIONS. 57
ii Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 4 of 150
1. BP ATLANTIS: DEFENDANTS CONCEAL REPEATED WARNINGS
ASSOCIATED WITH THEIR GULF OF MEXICO OPERATIONS.... 58
2. ADDITIONAL INCIDENTS PROVIDED RED FLAG WARNINGS OF IDENTICAL RISKS TO THOSE OF THE DEEPWATER
HORIZON 64
3. BP’S LEASE, DESIGN AND DRILLING OF THE MACONDO
WELL. 65
a. The Macondo Site. 65
b. The Macondo Well Design. 67
c. Drilling the Macondo Well. 68
d. Departures from Normal Procedures in Drilling the Macondo
Well 70
1. Long String Casing Versus a Liner 70
2. A Lack of Centralizers. 72
3. Cement Fill and Cement Testing 75
4. Testing Leading Up To Temporary Abandonment. 80
5. Temporary Abandonment Procedures 83
6. Failure to Detect the Kick. 86
7. Failure of the Blowout Preventer. 87
4. DEEPWATER HORIZON EXPLOSION 89
G. INTERNAL DOCUMENTS AND TESTIMONY CONFIRM BP CONCEALED
COST-CUTTING RISKING LIVES AND THE ENVIRONMENT. 91
1. DEEPWATER HORIZON’S TATTERED SAFETY AND
MAINTENANCE RECORD. 96
iii Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 5 of 150
2. PRESIDENTIAL COMMISSION FINDS BP LACKED SUFFICIENT
SAFETY PROCESSES AND IMPROPERLY ELEVATED PROFITS
OVER SAFETY. 98
3. GOVERNMENTAL TESTIMONY CONFIRMS BP’S CONCEALED
CORPORATE ETHOS OF PROFITS OVER SAFETY. 101
4. THE NATIONAL ACADEMY OF ENGINEERING NATIONAL
RESEARCH COUNCIL AND DEEPWATER HORIZON STUDY
GROUP CONFIRM THAT BP RECKLESSLY ELEVATED PROFITS
OVER SAFETY. 105
5. INDUSTRY PEERS CONFIRM THAT BP’S SAFETY AND RISK
MANAGEMENT PROCESSES WERE BELOW INDUSTRY
STANDARDS 106
H. ADDITIONAL EVIDENCE OF BP’S CONCEALED GULF OPERATIONAL
PROBLEMS 107
1. BP CONCEALED THAT SAFETY PROCESSES HAD YET TO BE
IMPLEMENTED IN THE GULF OF MEXICO. 107
2. EXPERTS AND CONFIDENTIAL WITNESSES CONFIRM THAT,
CONTRARY TO ITS REPRESENTATIONS, BP FAILED TO IMPLEMENT SAFETY OPERATIONS IN THE GULF OF
MEXICO 111
VI. MISREPRESENTATIONS AND OMISSIONS DURING
THE SUBCLASS PERIOD . 113
A. 2008 FORM 20-F ANNUAL REPORT. 113
B. MARCH 10, 2009 INITIAL EXPLORATION PLAN. 119
C. MARCH 25 2009 HOWARD WEIL ENERGY CONFERENCE. 121
D. NOVEMBER 19, 2009: STATEMENTS TO THE SENATE ENERGY AND
NATURAL RESOURCES COMMITTEE 122
E. 2009 ANNUAL REVIEW . 127
1. SVANBERG STATEMENTS. 127
iv Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 6 of 150
2. HAYWARD STATEMENTS 127
3. INGLIS STATEMENTS 129
4. COMPANY STATEMENTS. 130
F. MARCH 2, 2010 STRATEGY PRESENTATION 131
G. 2009 FORM 20-F ANNUAL REPORT . 136
H. MARCH 22, 2010 HOWARD WEIL CONFERENCE. 141
I. CODE OF CONDUCT. 143
J. 2009 SUSTAINABILITY REVIEW 144
K. 2009 SUSTAINABILITY REPORT 148
VII. LOSS CAUSATION. 153
VIII. SCIENTER ALLEGATIONS . 155
A. BASED ON THEIR CORPORATE ROLE AND MEMBERSHIP TO KEY
BOARD COMMITTEES, INDIVIDUAL DEFENDANTS HAD KNOWLEDGE
OF BP’S CONCEALED GULF OF MEXICO SAFETY PROBLEMS 157
1. SAFETY, ETHICS, AND ENVIRONMENT ASSURANCE
COMMITTEE . 157
2. GROUP OPERATIONS RISK COMMITTEE 158
3. BP’S INTERNAL REPORTING STRUCTURES MANDATED THAT
GULF SAFETY PROBLEMS REACHED THE EXECUTIVE AND
BOARD LEVEL. 159
B. DEFENDANTS KNOWINGLY OR RECKLESSLY DISREGARDED FACTS
THAT BELIED THEIR STATEMENTS CONCERNING THE SAFETY OF
THEIR GULF OPERATIONS. 161
C. CONFIDENTIAL WITNESSES AND GOVERNMENTAL INVESTIGATIONS
PROVIDE AN ADDITIONAL INFERENCE OF SCIENTER. 167
IX. PRESUMPTION OF RELIANCE 167
X. INAPPLICABILITY OF THE STATUTORY SAFE HARBOR 168
v Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 7 of 150
XI. CLAIMS FOR RELIEF. 169
COUNT I. VIOLATION OF SECTION 10(b) OF THE EXCHANGE ACT
AND RULE 10b-5 PROMULGATED THEREUNDER. 169
COUNT II.
VIOLATION OF SECTION 20(a) OF THE EXCHANGE ACT
(Against the Individual Defendants). 172
XII. PRAYER FOR RELIEF 174
XIII. JURY TRIAL DEMAND . 175
vi Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 8 of 150
Plaintiffs Robert H. Ludlow, Peter D, Lichtman, Leslie J. Nakagiri, and Paul Huyck
individually and as the Court-appointed Lead Plaintiffs on behalf of the Subclass described
below (“Plaintiffs”) bring this action for damages against Defendants BP, plc and BP America,
Inc. (collectively referred to as “BP”), as well as Defendants Anthony Hayward, Andy Inglis,
Carl-Henric Svanberg, H. Lamar McKay, William Castell, Paul Anderson, Antony Burgmans,
Cynthia Carroll, and Erroll B. Davis, Jr. (collectively referred to as the “Individual Defendants”)
for violation of the United States federal securities laws. Plaintiffs allege the following based
upon the investigation of Plaintiffs and their counsel, which included, among other things:
• interviews of confidential witnesses, including senior officials within risk management operations in the Gulf;
• interviews of former BP employees and consultants;
• interviews of industry experts on risk management practices;
• investigation reports by the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling (“Presidential Commission”);
• investigation reports by the National Academy of Engineering (“NAE”) and the National Research Council (“NRC”);
• investigation reports by the U.S. Chemical Safety and Hazard Investigation Board;
• investigation reports by the Deepwater Horizon Study Group;
• testimony and documents produced to the U.S. House of Representatives
Subcommittee on Oversight and Investigations, the Committee on Energy and Commerce, the U.S. Coast Guard and the Mineral Management Service;
• testimony and documents produced in In Re Oil Spill by the Oil Rig “Deepwater
Horizon” in the Gulf of Mexico, on April 20, 2010 , MDL No. 2179 (E.D. La.);
• public statements and filings with the U.S. Securities and Exchange Commission (“SEC”) by officers and representatives of BP; and
• reports, press releases and media reports.
1 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 9 of 150
I.
INTRODUCTION
“ Our commitment to safe, reliable and responsible operations starts with the group
chief executive Tony Hayward and his leadership team : a commitment that filters
down through the organization and is regularly communicated to all staff.”
2009 BP Sustainability Report, April 15, 2010 (five days before the Deepwater Horizon
explosion)
“There is a complete contradiction between BP's words and deeds . You were brought
in to make safety the top priority of BP, but under your leadership, BP has taken the
most extreme risks. BP cut corner after corner to save a million dollars here, a few
hours or days there, and now the whole gulf coast is paying the price .”
Chairman, U.S. House of Representatives Subcommittee on Oversight and Investigations, Committee on Energy and Commerce, June 15, 2010.
1. This is an action on behalf of a proposed Subclass of investors who purchased
securities in BP, plc (“BP”), including American Depository Receipts (“ADRs”), between
March 4, 2009 and April 20, 2010 (the “Subclass Period”), and who suffered losses following
the catastrophic explosion to BP’s oil drilling rig in the Gulf of Mexico. As described herein, BP
and its most senior executives repeatedly represented – both in SEC filings, public statements,
and documents filed with government regulators – that it was committed to safe operations in
the Gulf of Mexico, and had implemented internal risk management practices to reduce the
Company’s exposure. These representations were untrue, and the catastrophic consequences are
now manifest in the sullied waters and beaches of the Gulf, the decimated businesses operated by
Gulf residents, and the massive losses suffered by BP investors.
2. Deepwater oil drilling is dangerous, technologically complex and expensive.
Human errors are unavoidable. As such, oil companies like BP must insure that appropriate
safety processes are in place to account for human fallibility. Without appropriate safety
2 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 10 of 150
processes to check and balance independent decisions, such as a failure to verify cement
composition or the selection of a particular casing, such companies are highly exposed since
drilling accidents can have devastating consequences – both on the environment and the
Company’s operations and financial condition.
3. Accordingly, BP’s safety and risk management practices were highly material to
its investors, particularly during the Subclass Period, which followed a series of high profile BP
accidents, including the Texas oil refinery explosion in Texas City in 2005, and the Prudhoe Bay
Oil Spill in 2006. Following the Texas City refinery disaster, former U.S. Secretary of State
James A. Baker, III chaired a panel that found “systemic” failures in BP’s safety procedures:
“from the top of the company, starting with the Board and going down . . . BP has not provided
effective process safety leadership and has not adequately established process safety as a core
value.”
4. In 2007, following these incidents, BP reorganized its leadership structure and
represented that the Company was now focused “like a laser on safe and reliable operations,”
particularly in the Gulf. BP touted to investors that it had successfully implemented top quality
safety mechanisms to prevent catastrophic accidents going forward, and actively monitored and
managed operational risk in order to reduce exposure.
5. BP also publicly published certain internal policies relating to its safety measures
and risk management. For example, BP’s Code of Conduct, which was made available
publically on its website, contained a section entitled, “Health, safety, security and the
environment,” stating:
3 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 11 of 150
At BP our aspirations are - no accidents, no harm to people and no
damage to the environment.
We are committed to the protection of the natural environment, to the safety of the
communities in which we operate, and to the health, safety and security of our people.
Everyone who works for BP, everywhere, has a responsibility for getting HSSE right.
6. Similarly, in its 2009 Annual Report on Form 20-F, which was issued on March
5, 2010, a month prior to the Deepwater Horizon disaster, BP stated that:
“Safety, people and performance are BP’s top priorities. We constantly seek to
improve our safety performance through the procedures, processes and training
programmes that we implement in pursuit of our goal of ‘no accidents, no harm to people and no damage to the environment.’”
7. Unfortunately, while BP touted its ability to safely explore the deepwaters of the
Gulf of Mexico, and reassured the public that its robust risk management practices protected the
Company in the event of any accident, BP’s officers and directors were aware of serious and
systemic safety issues in the Company’s Gulf operations. As described herein, and supported by
testimony of BP employees in In Re Oil Spill by the Oil Rig “Deepwater Horizon” in the Gulf of
Mexico, on April 20, 2010 , MDL No. 2179 (E.D. La.) and confidential witness interviews, BP’s
Gulf drilling operations – which BP officers and directors were routinely kept informed of
through the Company’s mandatory internal reporting mechanisms – represented a powder keg
ready to blow.
8. Specifically, at the same time BP was reassuring the market, senior executives
were told of widespread safety problems in its Gulf operations. E-mails, audits, and other
documents presented to BP senior management discussed serious problems at the Deepwater
Horizon and its sister oil rig, the Atlantis. BP managers on the Deepwater Horizon itself were
issuing orders to move faster at the expense of safety. The Deepwater Horizon explosion was not
4 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 12 of 150
the result of unforeseeable forces, but rather the predictable outcome of BP’s intentional decision
to disregard repeated warnings.
9. Put simply, the story spun by BP to outside investors was far different from the
reality of its internal operations. By touting the growth potential of its Gulf of Mexico
operations, beginning in March of 2009, and highlighting the safety of the operations, BP
convinced investors, including Plaintiffs, that BP would be able to generate tremendous growth
with minimal risk. However, BP was misleading the investing public.
10. On May 21, 2010, President Obama established the National Commission on the
BP Horizon Oil Spill and Offshore Drilling (“Presidential Commission” or “Commission”). The
purpose of the Commission was, in part, to examine relevant facts and circumstances concerning
the root causes of the Deepwater Horizon explosion. The Commission held meetings from July
through December of 2010, taking statements, reports and presentations from numerous
individuals and experts. On January 11, 2011 the Commission released its Final Report to the
President, entitled Deepwater: The Gulf Oil Disaster and the Future of Offshore Drilling 1 (hereinafter referred to as “Pres. Comm. Report”) . The Commission found that BP repeatedly
placed profits over safety and lacked any process by which safety decision making could be performed on BP’s offshore rigs.
11. Similarly, the National Academy of Engineering and National Research Council
(“NAE”) concluded that BP “lack[ed] . . . a suitable approach for anticipating and managing the
inherent risks, uncertainties and dangers associated with deepwater drilling operations” and
“fail[ed] to learn from previous near misses.” The truth was that BP was cutting corners and
1 http://www.oilspillcommission.gov.
5 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 13 of 150
reducing its spending on safety measures in an effort to maximize profits in the Gulf of Mexico.
Indeed, it was not until April 20, 2010, after the explosion, that material information began to emerge about BP’s safety measures.
12. The April 20, 2010 disaster was a predictable outcome, at least within BP’s
offices. For years, BP had been engaged in systematic and draconian cost-cutting maneuvers in
order to improve profits. In making those cuts, BP sacrificed safety, choosing to cut corners
instead of ensuring that its oil exploration and production business did not cause injury or harm
to their own employees, the public, and the fragile Gulf Coast environment. There is no dispute
that appropriate safety processes present at BP’s peers could have prevented the blowout on the
Deepwater Horizon.
13. BP hid the fact that its safety procedures were deficient, both overall and specific
to operations in the Gulf of Mexico. For example, BP’s Gulf leases had been the sites of spills
and accidents during the year before the disaster on April 20, 2010. BP did not disclose any of
these facts and indeed, concealed them from the investing public. Plaintiffs believe that
additional information about BP’s safety protocols, both in general and relating specifically to its
Gulf operations were concealed and not disclosed to the public.
14. Following the explosion, BP’s securities plummeted in value. The losses are
directly related to the materialization of the risks created by BP’s misleading statements and
assurances about its core operations. The impact of these assurances on BP’s security prices is
readily reflected by the market’s reaction following the explosion, when the truth became known.
15. For example, as the following chart demonstrates, BP’s ADR share price grew
steadily after the March 4, 2009 Annual Report was issued by BP, touting the growth potential of
oil operations in the Gulf of Mexico and BP’s supposed “top priority” of safety to protect the
6 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 14 of 150
company’s exposure to risk. By April 20, 2010, the day of the Deepwater Horizon explosion,
BP’s ADR shares closed at $59.49 a share. However, immediately following the April 20
explosion, and continuing during the weeks of subsequent corrective disclosures, BP’s market
capitalization collapsed as its shares plummeted.
II.
THE PARTIES
A. PLAINTIFFS
16. Plaintiff Robert H. Ludlow, Jr. is a citizen of California. Ludlow purchased BP
ADRs on January 4, 2010 in reliance on BP’s statements and would not have purchased these
ADRs had he known BP’s actual safety and risk management practices. Ludlow and other
Subclass members similarly situated have been damaged as a result of Defendants’ securities fraud.
7 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 15 of 150
17. Plaintiff Peter D. Lichtman is a citizen of California. Lichtman purchased BP
ADRs on July 1, 2009, July 20, 2009, October 1, 2009, December 29, 2009, and January 19,
2010 in reliance on BP’s statements and would not have purchased these ADRs had he known
BP’s actual safety and risk management practices. Lichtman and other Subclass members similarly situated have been damaged as a result of Defendants’ securities fraud.
18. Plaintiff Leslie J. Nakagiri is a citizen of California. Nakagiri purchased BP
ADRs on April 12, 2010 in reliance on BP’s statements and would not have purchased these
ADRs had he known BP’s actual safety and risk management practices. Nakagiri and other
Subclass members similarly situated have been damaged as a result of Defendants’ securities fraud.
19. Plaintiff Paul Huyck is a citizen of California. Huyck purchased BP ADRs on
April 7, 2010 in reliance on BP’s statements and would not have purchased these ADRs had he
known BP’s actual safety and risk management practices. Huyck and other Subclass members similarly situated have been damaged as a result of Defendants’ securities fraud.
20. Plaintiffs and other Subclass members purchased BP securities in the open
market, unaware that Defendants’ statements and omissions regarding BP’s safety records were
false and/or misleading and were causing BP’s stock price to be artificially inflated. Plaintiffs
and the Subclass relied upon Defendants’ statements and omissions in BP’s public reports, press
releases, and SEC filings when they purchased BP securities and were thus injured by the
Defendants’ actions. Plaintiffs and the Subclass further relied on the integrity of the market for
BP securities and the fact that BP securities were fairly priced. As a result, Plaintiffs and each
Subclass member have been injured.
8 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 16 of 150
B. DEFENDANTS
1. CORPORATE DEFENDANTS
21. Defendant BP, plc (“BP”) is a public limited company formed under the laws of
the United Kingdom with its principal place of business in the United Kingdom. During the
Subclass Period, BP had a little under 19 billion shares outstanding. BP securities trade in an
efficient market.
22. Defendant BP America, Inc. (“BP America”) is a Delaware corporation with its
principal place of business in Warrenville, Illinois. BP America is a subsidiary of BP, plc and
conducts substantial business in the State of Texas, including leasing and operating the
Deepwater Horizon.
23. There is a unity of interest and ownership between BP and BP America such that
the acts of the one are for the benefit and can be imputed as the acts of the other. Hereinafter,
BP, plc and BP America, Inc. are jointly referred to as “BP.”
2. INDIVIDUAL DEFENDANTS
24. Defendant Anthony B. Hayward (“Hayward”) was the Chief Executive Officer
and a member of the Board of Directors during the Subclass Period. Before becoming Chief
Executive Officer in 2007, Hayward, who joined BP in 1982, served as the Chief Executive
Officer of Exploration and Production from 2002 to 2007 and as an Executive Director since
2003. Hayward served on the Group Operations Risk Committee (“GORC”) and was the
executive liaison to the Safety Ethics & Environment Assurance Committee, (“SEEAC”), which
is responsible for ensuring that BP’s safety protocols are implemented and followed. GORC was
expressly charged with reviewing and analyzing safety incidents in BP’s operations and reporting
to SEEAC.
9 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 17 of 150
25. Hayward received a salary, performance bonus, and other benefits in the amounts
of $4,000,000 in 2008 and $5,100,000 in 2009. Hayward also received a severance package of
approximately $20,000,000 when he was removed from the role of CEO. Hayward is a citizen of
the United Kingdom. By virtue of his position, operational and management control, and
systematic involvement in the fraudulent scheme, he had the power to influence and control, and
did influence and control, directly and indirectly, the decision-making and actions of BP,
including the content and dissemination of the various statements which Plaintiffs contend are
misleading.
26. Defendant Andy G. Inglis (“Inglis”) was an Executive Director and the Chief
Executive of Exploration and Production (“E&P”) during the Subclass Period. Inglis worked for
BP in various capacities since 1980 and served as an Executive Director and E&P Chief from
2007 through July 2010. As chief executive of BP E&P, Inglis attended meetings of the BP
Board’s Safety, Ethics and Environment Assurance Committee to report on topics specific to the
BP exploration and production. During the relevant time period, Inglis also served as a GORC
member. By virtue of his position, operational and management control, and systematic
involvement in the fraudulent scheme, he had the power to influence and control, and did
influence and control, directly and indirectly, the decision-making and actions of BP, including
the content and dissemination of the various statements which Plaintiffs contend are misleading.
27. Inglis received compensation in the amount of $3,300,000 in 2008 and $3,500,000
in 2009. Inglis is a British national with extensive contacts with the U.S. over the past decade,
including his work as the Chief Executive of BP Exploration and Production from 2007 until
October 31, 2010 and, before then, his oversight of BP’s operations in the Gulf of Mexico.
10 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 18 of 150
28. Defendant Carl-Henric Svanberg (“Svanberg”) is the Chairman of the Board of
Directors. He was appointed a Non-Executive Director of BP in September 2009 and became
Chairman in January 2010. Svanberg also heads the Chairman’s Committee and is a member of
BP’s Nomination Committee. Svanberg is a citizen of Sweden and travels to and from the United
States. By virtue of his position and operational and management control of the committee and
systematic involvement in the fraudulent scheme, he had the power to influence and control, and
did influence and control, directly and indirectly, the decision-making and actions of BP,
including the content and dissemination of the various statements which Plaintiffs contend are
misleading.
29. Defendant H. Lamar McKay (“McKay”) is Chairman and President of BP
America, Inc. In 1980, McKay started with Amoco, which was acquired by BP in 1998,
occupying a variety of positions until being appointed to his current roles in 2009. McKay is a
citizen of Texas. By virtue of his position, operational and management control, and systematic
involvement in the fraudulent scheme, he had the power to influence and control, and did
influence and control, directly and indirectly, the decision-making and actions of BP, including
the content and dissemination of the various statements which Plaintiffs contend are misleading.
30. Defendant William Castell (“Castell”) is the chairman of BP’s Safety, Ethics and
Environment Assurance Committee. Castell joined BP’s Board of Directors in 2006. By virtue
of his position and operational and management control of the committee and systematic
involvement in the fraudulent scheme, he had the power to influence and control, and did
influence and control, directly and indirectly, the decision-making and actions of BP, including
the content and dissemination of the various statements which Plaintiffs contend are misleading.
11 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 19 of 150
31. Defendant Paul Anderson (“Anderson”) is a member of BP’s Safety, Ethics and
Environment Assurance Committee. Anderson joined BP’s Board of Directors on February 1,
2010. By virtue of his position and operational and management control of the committee and
systematic involvement in the fraudulent scheme, he had the power to influence and control, and
did influence and control, directly and indirectly, the decision-making and actions of BP,
including the content and dissemination of the various statements which Plaintiffs contend are
misleading.
32. Defendant Antony Burgmans (“Burgmans”) is a member of BP’s Safety, Ethics
and Environment Assurance Committee. Burgmans joined BP’s Board of Directors in 2004. By
virtue of his position and operational and management control of the committee and systematic
involvement in the fraudulent scheme, he had the power to influence and control, and did
influence and control, directly and indirectly, the decision-making and actions of BP, including
the content and dissemination of the various statements which Plaintiffs contend are misleading.
33. Defendant Cynthia Carroll (“Caroll”) is a member of BP’s Safety, Ethics and
Environment Assurance Committee. Carroll joined BP’s Board of Directors in 2007. By virtue
of her position and operational and management control of the committee and systematic
involvement in the fraudulent scheme, she had the power to influence and control, and did
influence and control, directly and indirectly, the decision-making and actions of BP, including
the content and dissemination of the various statements which Plaintiffs contend are misleading.
34. Defendant Erroll B. Davis, Jr. (“Davis”) was a member of BP’s Safety, Ethics
and Environment Assurance Committee and Audit Committees until stepping down from the
Board on April 15, 2010. Davis joined BP’s Board of Directors in 1998. By virtue of his
position and operational and management control of the committee and systematic involvement
12 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 20 of 150
in the fraudulent scheme, he had the power to influence and control, and did influence and
control, directly and indirectly, the decision-making and actions of BP, including the content and
dissemination of the various statements which Plaintiffs contend are misleading.
35. The individuals identified above are hereinafter collectively referred to as the
“Individual Defendants.” Because of their positions with BP, these Individual Defendants
possessed the power and authority to control the contents of BP’s reports to the SEC, press
releases and presentations to securities analysts, money and portfolio managers, i.e. the market.
Each defendant was provided with copies of BP’s reports, presentations and press releases
alleged herein to be misleading prior to, or shortly after, their issuance and had the ability and
opportunity to prevent their issuance or cause them to be corrected. Because of their positions
and access to material non-public information available to them, each of these defendants knew
that the adverse facts specified herein had not been disclosed to, and were being concealed from
the public, and that the positive representations which were being made were then materially
false and misleading.
C. UNNAMED PARTICIPANTS
36. Numerous individuals and entities participated actively during the course of and in
furtherance of the scheme described herein. The individuals and entities acted in concert by joint
ventures and by acting as agents for principals, in order to advance the objectives of the scheme
to benefit Defendants and themselves to the detriment of Plaintiffs and the Subclass.
13 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 21 of 150
III.
JURISDICTION AND VENUE
A. JURISDICTION AND VENUE
37. Plaintiffs assert claims under Section 10(b) and 20(a) of the Exchange Act, (15
U.S.C. §§ 78(j)(b) and 78(t)(a)), and Rule 10b-5 promulgated thereunder. The Court has
jurisdiction over the subject matter of this action pursuant to Section 27 of the Exchange Act (15
U.S.C. §78aa) and 28 U.S.C. § 1331.
38. Venue of this action in this Court is proper pursuant to Section 27 of the
Exchange Act, 15 U.S.C. § 78aa and 28 U.S.C. § 1391(b) because the Defendants resided,
transacted business, were found, or had agents in this District. Venue is also proper in this
District because the Judicial Panel on Multidistrict Litigation ordered this action centralized in
this District.
39. Defendants, directly and/or indirectly, used the means and instrumentalities of
interstate commerce, the United States mails, and the facilities or the national securities markets
in connection with the acts, conduct, and other wrongs complained of herein.
40. Each Defendant has sufficient minimum contacts within Texas to make the
exercise of jurisdiction over each Defendant by the federal courts in Texas consistent with
traditional notions of fair play and substantial justice. Each Corporate Defendant transacts
business, has an agent, and/or is found within the State of Texas and the unlawful conduct
alleged in this complaint was carried out and had effects in the State of Texas. Each Individual
Defendant made statements which were directed at the United States, including Texas, were
control persons who approved the filing and/or dissemination of forms required by the Securities
& Exchange Commission, and/or performed other acts which were directed towards the United
14 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 22 of 150
States, including Texas, and which they knew would have a cause and effect on the price of BP securities.
B. CAUSE AND EFFECT IN THE UNITED STATES
41. BP has extensive United States and Texas operations, many of BP’s shareholders
are in the United States, and the site of the wrongdoing occurred in substantial part in this
District.
42. As BP’s former CEO, Hayward, told the Houston Forum on November 8, 2007:
“America – and Americans – [are] the greatest single part of BP.”
43. BP’s relationship to the United States is highlighted by the following:
• 39 percent of BP’s worldwide shareholders reside in the United States.
• BP has approximately 34,000 employees in the United States, one third of
its total worldwide employees and more than in any other country.
• BP produces more crude oil in the United States than in any other country.
• BP produces more natural gas in the United States than in any other
country.
• BP’s capital expenditures in the United States are larger than in any other
country, and BP has more operating capital employed in the United States
than in any other country.
• 45% of BP’s proved oil reserves are in the United States.
• BP is the second largest gasoline retailer in the United States.
• BP’s single largest division – BP America – is incorporated in Delaware
and has its headquarters in Houston.
15
Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 23 of 150
• BP’s operations in Texas and the Gulf of Mexico are the most significant
part of BP’s operations in the world.
IV.
SUBCLASS ACTION ALLEGATIONS
44. This action is brought by Plaintiffs, individually, and on behalf of a Subclass of all
others similarly situated, for the allegedly wrongful acts of the Defendants. Plaintiffs bring this
action pursuant to Federal Rule of Civil Procedure 23. The Subclass is defined as followed:
All persons and entities who, during the Subclass Period from March 4, 2009
(the date of BP’s 2008 Annual Form 20-F) through April 20, 2010, purchased shares in BP securities, including American Depository Receipts (“ADR”).
Excluded from the Subclass are Defendants herein, members of their
immediate families and their legal representatives, parents, affiliates, heirs,
successors or assigns and any other person who engaged in the improper
conduct described herein (the “Excluded Persons”).
45. Plaintiffs seek to recover damages for themselves and the Subclass under the
federal securities laws.
46. Numerosity of the Subclass – Federal Rule of Civil Procedure 23(a)(1). The
Subclass is so numerous that joinder of all members is impracticable. BP is a publically traded
security with a little under 19 billion outstanding shares. Nearly half of the shareholders of BP
are American citizens. While the exact number of Subclass members is unknown at this time,
Plaintiffs are informed and believe that the number is in the hundreds of thousands, at a
minimum.
47. Existence and Predominance of Common Questions of Law and Fact –
Federal Rule of Civil Procedure 23(a)(2) and 23(b)(3). Common questions of law and fact exist
16 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 24 of 150
as to all Subclass members and predominate over questions affecting only individual Subclass
members. These common questions include:
(a) Whether Defendants’ acts alleged herein violated federal securities laws; and
(b) Whether Plaintiffs and members of the Subclass were damaged, and the
appropriate measure of damages.
48. Typicality – Federal Rule of Civil Procedure 23(a)(3). Plaintiffs’ claims are
typical of the claims of other members of the Subclass in that Plaintiffs and other Subclass
members were all injured as a result of the misconduct of the Defendants. Plaintiffs are
members of the Subclass they seek to represent and have suffered harm due to the misleading and
fraudulent statements and omissions of material facts by Defendants.
49. Adequacy of Representation – Federal Rule of Civil Procedure 23(a)(4) and
23(g)(l). Plaintiffs will fairly and adequately represent the interests of the Subclass; their
interests are coincident with, and not antagonistic to those of the Subclass they seek to represent.
Plaintiffs are represented by experienced and able attorneys, who intend to prosecute this action
vigorously for the benefit of Plaintiffs and all Subclass members. Plaintiffs and their counsel
will fairly and adequately protect the interests of the Subclass members.
50. Proper Maintenance of Subclass – Federal Rule of Civil Procedure 23(b)(2)
and (c). Defendants have acted or refused to act, with respect to some or all issues presented in
this Complaint, on grounds generally applicable to the Subclass, thereby making it appropriate to provide relief with respect to the Subclass as a whole.
51. Superiority – Federal Rule of Civil Procedure 23(b)(3) and (c). An action on
behalf of a Subclass is the best available method for the efficient adjudication of this litigation
because individual litigation of Subclass members’ claims would be impracticable and unduly
17 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 25 of 150
burdensome to the courts, and have the potential to result in inconsistent or contradictory
judgments. There are no unusual difficulties likely to be encountered in the management of this
litigation as a class action. A class action presents fewer management problems and provides the
benefits of single adjudication, economies of scale and comprehensive supervision by a single
court.
V.
FACTUAL ALLEGATIONS
A. BP’S RAPID GROWTH: ACQUISITIONS AND DEEP SEA EXPLORATION OF
THE GULF OF MEXICO
52. BP was founded as the Anglo Persian Oil Company in 1909 and is now one of the
world’s largest oil and gas companies. BP engages in every area of the oil and gas industry,
including exploration and production, refining and distribution. During fiscal year 2009, BP’s
business generated $246 billion in revenues and over $16 billion in profit. BP is now the single
largest producer of oil and gas in the United States.
53. BP’s emergence as a global power arose under the tenure of former CEO, Lord
John Browne. In 1989, Browne, who was then head of BP exploration and development,
assigned ten geologists, including Defendant Hayward, to develop a new strategy to find oil.
Deepwater wells in the Gulf of Mexico, while technologically complex and geologically
demanding, were particularly promising to BP. 2
2 Peter Elkind and David Whitford, BP: An Accident Waiting to Happen (Fortune,
January 24, 2011).
18 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 26 of 150
54. This new focus was particularly attractive, according to Browne, since the “costs 3 would be lower per barrel for big fields.”
55. The inaccessibility and technological difficulty of the “new exploration” plan
required substantial capital commitment. Drilling a deepwater well can cost as much as $200
million.4 Accordingly, BP needed access to greater capital.
56. In 1998, BP entered into a $110 billion “merger of equals” with Amoco, and the
combined company purchased the Atlantic Richfield Company (“Arco”) to become the third
largest oil company in the world. Amoco was targeted, in part, because of its sizeable Gulf of 5 Mexico assets.
57. After the ARCO merger was announced, Browne stated, “We’ll be the largest 6 producer of oil in the non-OPEC world.” This was not just bluster as BP’s corporate value
quadrupled in value as BP became a huge global competitor almost overnight.
58. Following the mergers, BP embarked on an aggressive campaign of exploring,
developing and increasing (through the acquisition of regional leases) its Gulf assets.
59. Exploration and production involves the use of heavy industrial equipment to drill
and access oil in deep water. Deepwater drilling is not only expensive but, as described in
3 John Browne, Beyond Business, An Inspirational Memoir From a Visionary Leader
(The Orion Publishing Group, Ltd., 2010), Pg. 60.
4 Russell Gold, BP’s Big Oil Find Cements Gulf’s Revival , (Wall Street Journal, Sept. 3,
2009).
5 Aug. 11, 1998 BP Press Release available at
http://www.bp.com/genericarticle.do?categoryId=2012968&contentId=2006699
6 Abrahm Lustgarten, Furious Growth and Cost Cuts Led to BP Accidents Past and
Present (ProPublica Oct. 26, 2010).
19 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 27 of 150
greater detail below, the technological risks of drilling thousands of feet below sea level are
enormous.
1. THE CHALLENGES OF DEEPWATER OIL DRILLING IN THE GULF
OF MEXICO
60. New technologies have allowed offshore drilling to probe deeper and deeper into
the Earth’s crust to tap previously unreachable natural resources. However, creating and
maintaining those deeper wells also comes with unprecedented levels of risks. As near-shore
reserves depleted and exploration technology improved, drilling moved farther offshore, into
deeper waters and deeper into the sand and rock below those waters. The conditions in which
this drilling happens are extreme and the challenges are formidable. '
61. Drilling a deepwater well involves stringing equipment and steel from a floating
oil rig through water, sand and rock at variant pressures and temperatures and terminating at
depths of up to 20,000 feet below the seabed.
62. In creating an oil well, a drilling rig uses a drill string and bit that create a hole
approximately 36 inches (or three feet) in diameter. This whole narrows as it becomes deeper,
and the well is encased initially in steel and eventually in cement. The types of dangers that can
arise from drilling a well are numerous including, but certainly not limited to, puncturing a high
pressure pocket of gas or liquid, maneuvering pieces of steel that weigh more than one ton, and
starting oil fires, which are nearly impossible to control or put out.
63. The risks inherent in drilling any oil well increase greatly when the top and
bottom of the well are drilled further and further below surface of the water. The absence of
' John McQuaid, The Gulf of Mexico Oil Spill: An Accident Waiting to Happen , (Yale Environment 360, May 10, 2010).
20 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 28 of 150
adequate safety procedures have led to blowouts which predictably kill and injure workers,
damage equipment, and spill oil and gas into the environment. These risks have been well
known for decades, harkening back to a drilling disaster off the Santa Barbara, California Coast
in 1969, which dumped more than three million gallons of oil into the water and led to a 8 moratorium on offshore drilling in the United States.
2. STATUTES AND REGULATIONS RELEVANT TO OFFSHORE
DRILLING
64. Because of the dangers inherent in offshore drilling, the oil industry is subject to
expansive regulations regarding the safety of offshore drilling operations.
65. The Outer Continental Shelf Lands Act (“OCSLA”), enacted in 1953, provides the
foundation for federal regulation of offshore oil and gas development. OCSLA authorizes the
Department of Interior (“DOI”) to lease defined offshore areas for development and to formulate
regulations pertaining to offshore drilling and drilling safety as necessary.
66. From its inception, and at all relevant time periods, the Secretary of the Interior, 9 through the former Minerals Management Service [“MMS”], was the federal agency primarily
responsible for leasing, safety, environmental compliance, and royalty collections 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 workovers (major well
8 Jesus Sanchez, The oil spill that triggered the debate over offshore drilling, (L.A.
Times, June 18, 2008).
9 Recently renamed the Bureau of Ocean Energy, Management, Regulation and
Enforcement.
21 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 29 of 150
maintenance), production safety systems, platforms and structures, pipelines, well production,
and well-control and production safety training.
67. 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 inspection of 10 the operations to prevent blowouts, fires, spills, and other major accidents.”
68. 30 C.F.R. § 250 et seq. governs drilling operations on the Outer Continental Shelf
(“OCS”) which includes BP’s Gulf of Mexico operations. Subpart B of 30 C.F.R. § 250.202
provides that a company must submit an Exploration Plan (“EP”), a Development and Production
Plan (“DPP”), and a Development Operations Coordination Document (“DOCD”) before any
drilling activities may be conducted on the offshore lease. Additionally, submitted plans “must
demonstrate that you have planned and are prepared to conduct the proposed activities in a
manner that . . . [i]s safe.” Even after MMS approval of the EP, the oil company must still secure
approval of its application for its permit to drill and approval of production safety systems. 30
C.F.R. §§ 250.281, 250.410 and 250.800.
69. 30 C.F.R. § 250.300 requires “(a) [d]uring the exploration, development,
production ... the lessee shall take measures to prevent unauthorized discharge of pollutants into
the offshore waters. The lessee shall not create conditions that will impose unreasonable risk to
public health, life, property, aquatic life, wildlife, recreation, navigation, commercial fishing, or
other uses of the ocean.”
10 Pres. Comm. Report, Pg. 68.
22 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 30 of 150
70. Importantly, to protect health, safety, property, and the environment : (1) all
operations must be performed in a safe and workmanlike manner; (2) all equipment and work
areas must be maintained in a safe condition; (3) any hazardous oil or gas accumulations or other
health, safety or fire hazard must be immediately controlled, removed, or otherwise corrected;
and (4) best available and safest technology (BAST) must be used whenever practical on all
exploration, development and production operations. 30 C.F.R. § 250.107.
3. THE PROCESS OF FINDING AND DRILLING A DEEPWATER
OFFSHORE WELL
a. Searching for and Finding a Reservoir of Oil and Gas
71. Once a piece of land is leased, an offshore drilling rig must be set up in order to
locate what is known as a “trap” below the seabed. A trap is a reservoir of porous rock which is
filled with oil and/or gas. Oil forms deep beneath the Earth’s surface when organic materials
deposited in ancient sediments slowly transform due to the intense heat and pressure. These materials, known as “hydrocarbons,” are lighter than the rock and other fluids around them.
Therefore, they move upward toward the surface. When a layer (or many layers) or an
impermeable substance (such as sheets of rock or sediment) blocks the path of the hydrocarbons,
they collect in porous rock layers beneath that impermeable layer. The business of drilling for oil
consists of finding and tapping these areas. These areas are also referred to as the “Pay Sands,” or “Pay Zone.”
72. Locating potential traps requires the use of seismic surveying and advanced
technology. For example, BP believed and expected based on seismic surveys of the region that
the Pay Sands nearly 20,000 feet below sea level at the Macondo well would be large and very
23 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 31 of 150
profitable. However, it is difficult to know for certain whether a trap is accessible and possesses
useful and extractable oil and gas until an exploratory well is drilled.
73. The offshore drilling rig can be anchored in place in either of two ways. First, a
rig can be anchored with enormous mooring chains. Alternatively, a rig can be free floating and
dynamically positioned through satellite GPS technology and powerful thrusters to ensure that it
stays above the location of the well. These are known as dynamically positioned Mobile
Offshore Drilling Units, or “MODUs.” BP used two different drilling rigs at the Macondo well,
the Marianas, an anchored rig, and the Deepwater Horizon, a MODU. The first rig to drill at the
well was the Marianas, which was damaged during Hurricane Ida in November of 2009. 11 12 In
January of 2010, the Deepwater Horizon arrived and continued the work done by the Marianas.
74. Because Macondo was the first well in the plot of land, BP knew relatively little
about the geology. However, based on available data there was an indication that a large oil and
gas reservoir would warrant installing production equipment at the well. Thus, while the original
purpose of the well was exploratory, BP intended to extract the oil and gas approximately 20,000
feet below sea level and nearly 15,000 feet below the sea bed.
75. The well was designed as an “infrastructure-led development, meaning that the
exploration well was designed so that it could later be completed to be a production well” if a
sufficient reservoir was found. 13
11 The Marianas drilled for 34 days to a depth of just over 9,000 feet. It moved off-site
when Hurricane Ida was arriving, but was still damaged in the storm and subsequently replaced by the Deepwater Horizon.
12 Pres. Comm. Report, Pg. 92.
13 September 8, 2010 BP Deepwater Horizon Accident Investigation Report, Pg.16.
24 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 32 of 150
b. Drilling A Well
76. Once a location has been selected, the process for drilling a deepwater offshore
well begins. For wells such as Macondo, this is a multi-step, lengthy and complex process.
Most of the time, the workers and engineers on the rig cannot see what the drill bit is
encountering and rely solely on tangential measurements and information during the drilling
process.
77. Additionally, it is a process with virtually no margin for error. The well begins at
a diameter of approximately thirty-six inches. The deeper the well is drilled, the narrower the
hole becomes. Guiding the drill through rock and sand, more than one mile below where the
engineer sits, inside a hole less than three feet wide means that the smallest error can send the
drill askew and into unseen or potential pockets of gas or liquid.
78. Further, it is a multi-step process involving numerous people, materials and
stages. It involves drilling, multiple layers of gradually narrower steal casing, stabilizers, cement,
valves and safety mechanisms, all of which must be placed with exacting specificity under
conditions of extreme temperature and pressure far outside the perceptions of the people in
charge of guiding the drill and making decisions which can have catastrophic consequences.
79. These general risks are amplified when the geology of the area is relatively
unknown. Drillers use fluids (generally synthetic muds) in order to balance the pressure inside
the well with the pressure in the surrounding rocks. Drillers force fluids down the wellbore
following the drill. The mud cools and lubricates the drill and controls the pressure inside the
well. The weight of the column of mud exerts pressure which counterbalances the pressure in the
hydrocarbon formation.
25 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 33 of 150
80. This pressure must be balanced in two ways – “Pore Pressure” and “Fracture
Gradient.” Pore Pressure is the pressure exerted by fluids in the pore space of rock. If this
pressure is not balanced by the drilling fluids, hydrocarbons flow up into the well bore and can
cause unprotected sections of the well to collapse. This is known as a “kick.” A large “kick,” 14 allowing hydrocarbons to flow up the well in an uncontrolled manner, is called a “blowout.”
81. Fracture Pressure is the pressure at which the rock formations are no longer strong
enough to withstand the pressure of the drilling fluids. If the pressure exerted by the fluids is too
high, it will cause the surrounding formations to fracture. This causes the fluids to flow out of
the wellbore and into the rock formation instead of circulating back to the surface. This is known
as a “lost return” or “lost circulation” event. 15
82. The principal challenge in deepwater drilling is to drill a path to the Pay Zone in a
manner which simultaneously controls the enormous pressures inside the well and on the
geologic formation where the reservoir is found. Balancing the Pore Pressure while avoiding
fracturing the surrounding rock is a delicate, sensitive and highly technical task which requires
specialized equipment and the interpretation of data from environments which are extremely
difficult to operate in.
83. As the well gets deeper, drillers use “casing strings” to stabilize the wellbore.
These are a series of steel tubes which are installed to line the well as the drilling progresses.
They are installed so that the first string is the widest - approximately thirty-six inches, which
matches the original diameter of the well. However, as the well gets deeper, the strings are
14 Pres. Comm. Report, Pg. 90.
15 Id.
26 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 34 of 150
inserted through the existing hole, meaning that each string is slightly smaller than the previous
one. At the bottom of the well, the hole is significantly narrower, allowing for less and less
margin of error the deeper the well goes. These strings protect the well from hydrocarbons
leaking into the wellbore and causing a kick or a blowout, as well as protecting the rock
formations outside the well from the pressure the drilling mud exerts against them from inside
the well. 16
84. Once the casing strings are in place and the well is drilled into the Pay Zone,
engineers begin running tests to determine whether the reservoir is viable. In order to be viable,
the reservoir must be of sufficient size and pressure to make it economically worthwhile to install
the “production casing” used to recover oil and gas from the well.
c. Preparing for Oil Extraction
85. There are multiple types of casings which can be cemented into place. The
original option at Macondo was to use a “long string” casing. This casing creates a continuous
wall of steel from the wellhead on the sea floor to the Pay Zone at the bottom of the well.
However, lost circulation events, the extremely fragile nature of Pay Zones, and the narrow range
of pressure which could create the appropriate balance inside and outside the well, often make
use of a long string impossible.
86. In such a case, the alternative is to use a “liner.” This is a much shorter casing
which is hung lower in the well and anchored to the next higher string. A liner is more complex,
and can be more leak-prone over the life of a well, but can be significantly easier to cement into
place. The installation of a casing (either a long string or a liner) requires crews to lower a tool
16 Pres. Comm. Report, Pg. 92.
27 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 35 of 150
from the rig floor all the way to the bottom of the well (in the case of Macondo, more than
18,000 feet down) and to assemble the casing section by section.
87. Prior to the installation of the casing, drillers install “centralizers” which are
critical components to ensuring a good cement job. The centralizer serves to stabilize the casing
in the center of the wellbore. The centralizers come in multiple forms - “subs” and “slip-ons.”
“Sub” centralizers screw securely into place between sections of casing. “Slip-on” centralizers
slide onto the exterior of a piece of casing and are usually secured by “stop collars” on either
side. The collars are either welded directly to the centralizers or supplied as separate pieces. If
the slip-on centralizers are supplied as separate pieces, there is a risk that they can slide out of
position or catch on other equipment as the casing is lowered.
88. After the centralizers are ready, the casing is lowered into place. This is done by
attaching a “shoe track” to the leading end of the casing. This begins with a bullet-shaped piece
of metal with three holes designed to help guide the casing down the hole. It is followed by a 17 length of narrow steel casing and then a “float collar.” The float collar is simply two valves
held up by a short tube through which the drilling liquid and mud in the well can flow. As the
casing string is lowered downward, the mud passes through the holes in the “shoe” and then 18 through the auto-fill tube which props open the “float collar.” This allows the mud in the well
to flow up the casing string as it is put into place.
89. Once the well is drilled and the production casing is in place, specialized blends
of cement are sent down the inside of the casing string. At the bottom of the string, the cement
17 September 8, 2010 BP Deepwater Horizon Accident Investigation Report, Pg. 69.
18 Id.
28 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 36 of 150
“turns the corner” and then moves up the “annular space” between the casing and the sides of the
open hole. If the casing is not directly in the center of the wellbore, the cement does not flow
evenly back up all sides of the casing. Because the cement pushes the drilling mud out of the
well (and eventually out of the wellbore) if the casing is not centered in the wellbore, the cement
will flow up the path of least resistance and can leave mud and debris which can severely
compromise a primary cement job and create paths and gaps which hydrocarbons can flow
upward.
90. The cement that is used in a cement job is a highly specialized “slurry.” The
slurry must be tested before it is used, and because the pressure and temperature at the bottom of
a well significantly alters the strength and curing rate of a slurry, this testing is generally done as
close to the start of a pumping job to ensure that the cement will behave as needed and expected
while at the bottom of the well.
91. The process involves sending cement down the well, followed by drilling mud and
then, determining when that cement has “turned the corner.” However, “even following best
practices, a cement crew can never be certain how a cement job at the bottom of the well is 19 proceeding as it is pumped.” Accordingly, crews must rely on other information like pressure
and volume readings. The crew knows how much cement and mud went down the well, and how
much pressure is exerted by the pumps to push that cement and mud, and uses that information to
determine whether the amount of mud being displaced is equal to the amount of mud and cement
sent down the well. Additionally, cement teams look for pressure spikes which confirm that
“wiper plus” have landed at the bottom of the well as expected and also look for a steady increase
19 Pres. Comm. Report, Pg. 99.
29 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 37 of 150
in pressure which demonstrates that the cement has turned the corner and is now being pushed up
the annular areas against gravity.
92. While these indicators suggest that a job has gone as planned, they “say little
specific about the location and quality of the cement at the bottom of the well.” Therefore, after 20 cementing, crews engage in pressure testing and “cement evaluation logging.”
93. Once the cement is cured (or set) it bonds to the rock formation and to the casing.
In theory, this seals off the annular space and isolates the Pay Zone from the annular space
around the casing and from the inside of the casing itself. This is known as the “primary” cement
job.
94. After the cement job is completed, the rig crew performs tests to determine if it
was successful. Once the pumps are turned off, the crews attempt to determine if the float valves
are closed and holding. The crew opens a valve at the end of the cementing unit and measures
how much fluid flows out of the well. There is an expectation that some will, but if the amount
is greater than the predicted amount it indicates that the cement is migrating back up the casing.
In addition to this measurement, the crews use cement evaluation tools to test the integrity of the
cement in the annular space around the casing. These tools primarily use acoustic signals.
However, the tools have important limits. They cannot evaluate the cement inside the “shoe” or
in the space below the flow valves, and are significantly more accurate when the cement is given
adequate time to cure.
20 Pres. Comm. Report, Pg. 99.
30 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 38 of 150
d. Temporary Abandonment
95. Once the cement job is completed and tested, the final stage in preparing to
extract oil is called, “Temporary Abandonment.” This process is not always necessary, but when
a drilling rig the size (and cost) of the Deepwater Horizon is used, the oil company will bring in a
smaller rig to install collection and production equipment and to extract the oil from the well. In
order to make way for a new rig, the existing one must remove the “riser” and “blowout
preventer” (“BOP”) from the well head. The riser is the piping that connects the drilling rig at
the surface with the BOP.
96. The BOP is a crucial last line of defense for a drilling vessel and its workers if all
other attempts to balance well pressure and counter an influx fail, and the well begins to flow out
of control. The BOP functions as a safety mechanism designed to prevent the types of
explosions and disasters which occurred at the Macondo well. Each drilling rig has its own BOP.
97. The BOP is a stack of valves that, once in place, everything needed in the well
passes through. The BOP on the Deepwater Horizon was a four-hundred ton device that was
latched onto the wellhead on the sea floor. The BOP had several features which are designed to
seal the well. The top two were large rubber donuts called “annular preventers.” They encircle
the casing inside the BOP. When squeezed shut they seal off the space around the piping. The
BOP also had five sets of metal rams, including a “blind shear ram” which was designed to cut
through the drill pipe inside the BOP to seal off the well in case of an emergency. It was
designed so that it could be activated manually on the rig, through a remote operated vehicle or
through an automated “deadman system.” In addition to the “blind shear ram” there was also a
“casing shear ram” designed to cut through the casing, and three sets of pipe rams in place to
close off the space around the drill pipe.
31 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 39 of 150
98. Once the BOP is properly positioned and secured over the pilot hole, the drilling
apparatus and additional casing sections are lowered down through the BOP into the well, while a pipe called a “marine riser” connects the wellhead to the drilling vessel at the surface.
99. In the process of “temporary abandonment,” crews secure the well so that it can be
safely abandoned before removing the riser and BOP. There are four prominent features of
temporary abandonment. First, crews install a cement plug at the top of the casing. This is
designed to act as a backup for the cement at the bottom of the well. Second, the location of the
cement plug is placed at the “mud line.” At the Macondo well, this was planned to be placed
3,300 feet below the seabed, which was deeper than regulations allowed and deeper than usual. 21
Third, the crew determines the presence of seawater in the well below the sea floor. Crews
replace some of the mud in the wellbore above the cement plug with seawater, which is
significantly lighter and therefore alters the pressure pushing down on the mud and cement in the
casing leading down to the Pay Zone. Finally, the crews may install a “lockdown sleeve.” This
is a device that goes over the top of the well on the sea floor and is designed to keep the casing
from floating up out of the well.
100. In addition to these processes, crews also perform “positive pressure” and
“negative pressure” tests. The positive test assesses the integrity of the production casing. The
negative test assess the integrity of the well and bottom cement job to ensure that outside fluids
(hydrocarbons) are not leaking into the well.
21 Pres Comm Report, Pg. 103.
32 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 40 of 150
101. If the tests are completed and the cement plug and lockdown sleeve are put in
place, the rig can then move away from the well and leave it secured for the production rig to
begin extraction of oil.
B. BP’S CORPORATE STRATEGY OF DRACONIAN COST-CUTTING
102. In 1995, upon his promotion to CEO, Lord John Browne immediately instituted a
company-wide cost-cutting strategy, reducing budgets by 25% and cutting 6,000 jobs. “Safety
and maintenance expenditures were a significant portion of the cuts.” 22
103. BP’s cost-cutting would continue throughout Browne’s tenure as CEO. For
example, in 2004, Texas City refinery manager, Don Parus, was told to reduce the plant’s annual
operational budget of $300 million by $48 million. During this time, Texas City was BP’s most profitable refinery, generating $900 million in annual earnings. 23
104. BP’s cost cutting was implemented, among other ways, through “incentive” and
“bonus” programs for lower-level workers which had the guaranteed effect of cutting corners on
safety in order to get the job done more quickly. Rig workers were given bonuses if their
projects were completed at or before a targeted number of days. BP would also use this
information for employee performance evaluations, grading employees every year based on how
much money they saved the Company. 24
22 U.S. Chemical Safety and Hazard Investigation Board, Investigation Report Refinery
Explosion and Fire (15 killed, 180 injured) (“CSB”), at Pg. 159 (March 2007).
23 B.P. U.S. Refineries Independent Safety Review Panel Report (“Baker Report”)
(January 2007 ), at Pg. 83.
24 BP put profits over safety: An Editorial, (New Orleans Times-Picayune, Oct. 10,
2010).
33 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 41 of 150
C. BP’S HISTORY OF SAFETY LAPSES
105. Prior to 2007, BP experienced a number of catastrophic incidents. The
Company’s lengthy record of safety and environmental violations are attached as Exh. A . Four incidents are detailed below.
1. 2003: FORTIES ALPHA
106. On November 27, 2003, a gas line ruptured on BP’s Forties Alpha oil platform off
of the coast of Scotland. The gas line rupture was found to have been caused by corrosion. BP
admitted breaching U.K. health and safety regulations and was fined £200,000.
107. Oberon Houston was BP’s second in command on the Forties Alpha at the time of
the gas line rupture. Houston attributed the incident to BP’s strategy of promoting financial
performance over operational performance :
A continual focus on costs and an undoubted commercial savvy was not
complimented with similar expertise, or enthusiasm, for the nuts and bolts of the
job. Management listened intently to the views of market analysts, who knew
little about the technical detail of the oil business, but instead were driven by
quarterly results; encouraging and cheering on management’s relentless drive to
reduce costs . This resulted in a chronic short term view at the very top of the
company, obsession with performance metrics became the business for
management, not the informed outcome.
Engineers were regularly teased for wanting to “gold-plate everything”, or
reminded that “we are not building a Rolls Royce here”. It felt that senior
management in BP commonly thought we were more concerned about the
elegance of a solution rather than the costs involved, and therefore we were not
really trusted. These concerns were voiced at all levels, but found little understanding or sympathy. 25
25 Oberon Houston: Beyond Petroleum – Events in the Gulf of Mexico affect us all, available at http://conservativehome.blogs.corn/platform/2010/06/oberon-houston.html#more, last visited February 8, 2011.
34 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 42 of 150
2. 2005: TEXAS CITY DISASTER
a. Background of the Texas City Disaster
108. On March 23, 2005, at 1:20 pm, the BP Texas City refinery suffered one of the
worst industrial disasters in recent US history. The explosions and fires killed 15 people and
injured another 180 and resulted in financial losses exceeding $1.5 billion. The blast occurred
during the startup of an isomerization unit (ISOM) when a raffinate splitter tower was overfilled;
pressure relief devices opened, resulting in a geyser like flammable liquid from a blowdown
stack that was not equipped with a flare. The release of the flammables caused an explosion and
fire. A shelter-in-place order was issued that required 43,000 people to remain indoors and
houses were damaged from as far as three-quarters of a mile from the refinery. The BP Texas
City facility is the third-largest refinery in the United States.
109. The ISOM startup procedure required that the level control valve on the splitter
tower be used to send the liquid from the tower to the storage. Findings show that this valve was
closed by an operator and the tower was filled for over three hours without any liquid being
removed. This led to flooding of the tower and high pressure which in turn activated relief
valves that discharged flammable liquid to the blowdown system. Some of the underlying
factors involved in overfilling the tower included:
• The tower level indicator showed that the tower level was declining when in fact
it was overfilling. The redundant high level alarm did not activate, and the tower was not equipped with any other type of safety device.
• The control board display did not provide adequate information on the imbalance
of flows in and out of the tower to alert the operators to the high levels of danger.
• A lack of supervision during the startup, and especially hazardous period, was an
omission contrary to BP’s safety guidelines. An extra board operator was not
assigned to assist, despite a staffing assessment that recommended an additional
board operator for all the ISOM startups.
35 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 43 of 150
• Supervisors and operators poorly communicated the critical information regarding the startup during the shift turnover.
• ISOM operators likely were fatigued from working 12-hour shifts for 29 or more consecutive days.
• The operator training program was inadequate. The central training department
staff had been reduced from 28 to 8, and simulators were unavailable for operators
to practice handling abnormal situations, including infrequent and high hazard operations such as startups and unit upsets.
• There were outdated and ineffective procedures that did not address the recurring
operational problems during the startup which led operators to believe that
procedures could be altered or did not have to be followed during the startup
process.
110. The process unit was also started despite the previously reported malfunctions of
the tower level indicator, level sight glass, and a pressure control valve. The findings also found
that the size of the blowdown drum was insufficient to contain the liquid sent to it by the pressure
relief valves. The blowdown drum overfilled and the stack vented flammable liquid to the
atmosphere, which then fell to the ground and formed a cloud that ignited. BP did not replace
the blowdown drums and atmospheric stacks even though a series of incidents warned that the equipment was unsafe.
111. In 1992, OSHA cited a similar blowdown drum and stack as being unsafe, but the
citation was withdrawn as part of a settlement agreement and therefore the drum was not
connected to a flare as was recommended. BP had safety standards requiring that blowdown
stacks be replaced with equipment, such as a flare, when major modifications were made. In
1997, a major modification replaced the ISOM blowdown drum and stack with similar
equipment, but BP still did not connect it to a flare. In 2002, BP engineers proposed connecting
the ISOM blowdown system to a flare, but they ended up going with a less expensive option to save money.
36 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 44 of 150
112. The occupied trailers were sited too close to a process unit handling highly
hazardous materials. All the fatalities occurred in or around the trailers and in the years prior to
the incident, eight serious releases of flammable material from the ISOM blowdown stack had
occurred, and most of the ISOM startups experienced high liquid levels in the splitter tower. BP did not investigate these events.
113. This disaster, while tragic, was predictable. In the fall of 2004, the Texas City
refinery plant manager, Don Parus, gave a presentation to BP’s worldwide refining and
marketing chief, John Manzoni, entitled “Texas City is not a Safe Place to Work.” The
PowerPoint slides discussed circumstances surrounding two deaths at the Texas City refinery that year, and warned that “WE STILL HAVE MUCH TO DO!”26
b. US Chemical Safety and Hazard Investigation Board Report
114. After the Texas City refinery disaster, the US Chemical Safety and Hazard
Investigation Board (“Safety Board”) investigated BP’s safety performance at Texas City and also the role played by BP senior management.
115. According to the Safety Board’s final report, the Texas City disaster was caused
by organizational and safety deficiencies at all levels of BP. Warning signs of a possible
disaster were present for several years, but company officials did not intervene to prevent the
disaster. The extent of the serious safety deficiencies were further revealed when the refinery
experienced two additional serious incidents just a few months after the March 2005 disaster. In
one, a pipe failure caused approximately $30 million in damage and in the other, there was
26 Daniel Schorn, The Explosion At Texas City (CBS News, October 29, 2006).
37 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 45 of 150
approximately $2 million in property loss. In each of the incidents, community shelter-in-place orders were issued.
116. The Safety Board’s report states:
Simply targeting the mistakes of BP’s operators and supervisors misses the
underlying and significant cultural, human factors, and organizational causes
of that disaster that have a greater preventative impact. One underlying cause was that BP used inadequate methods to measure safety conditions at Texas City.
For instance, a very low personal injury rate at Texas City gave BP a misleading
indicator of process safety performance. In addition, while most attention was
focused on the injury rate, the overall safety culture and process safety
management (PSM) 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 risk of a catastrophic event .”
117. Some of the key organizational findings from the Safety Board’s final report
found :
• cost-cutting, failure to invest and production pressures from BP Group
executive managers impaired the process safety performance at Texas City.27
• The Texas City refinery had a “check the box” mentality meaning the
personnel would complete paperwork and check off on the safety policy
and procedural requirements without even actually doing the checks and meeting the requirements.
• BP Texas City lacked a reporting and learning culture. The personnel
were not encouraged to report safety problems and some even feared
retaliation for doing so. Therefore, the lessons that could have been
learned from the incidents were never learned because the incidents were never acted upon. This would be a recurring theme for BP.
• BP’s safety campaigns, goals, and rewards that were more focused on
improving personal safety metrics and worker behaviors rather than on
process safety and management safety systems. Even though Texas City
was compliant with many safety policies and procedures, the managers did
not lead by example regarding safety. There were numerous surveys,
27 CSB Report, Pg. 25.
38 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 46 of 150
studies, and audits that identified deep-seated safety problems at Texas
City, but the response of the BP managers at all the levels was usually “too little, too late.”
c. BP Issues Incident Investigation Report
118. On December 9, 2005, BP issued its final incident investigation
report on the Texas City disaster. The investigation found that “[a] number of interviewees
noted that safety did not seem to be a priority, particularly as compared to cost
management” and that “ [p]rocess safety, operations performance and systematic risk 28 reduction priorities had not been set and consistently reinforced by management.” In that
report, BP claimed to improve safety not only at that refinery but throughout all of its operations.
119. Ross Pillari, president of BP Products North America, Inc. stated that “[t]he report
clearly describes the underlying causes and management system failures which contributed to the
worst tragedy in BP’s recent history. We accept the findings, and we are working to make Texas
City a complex that attains the highest levels of safety, reliability and environmental performance.”29
120. A BP press release issued after the Texas City accident stated, “BP has accepted
responsibility for the explosion and fire that occurred at its Texas City refinery on March 23,
2005. BP is deeply sorry for what occurred and for the suffering caused by its mistakes. BP is
working to improve plant integrity, safety culture and process safety management at all BP-
operated facilities in order to prevent incidents like this in the future .”
28 John Mogford, Fatal Accident Investigation Report (December 9, 2005), at Pg. 165.
29 Dec. 9, 2005 BP Press Release, BP Issues Final Report on Fatal Explosion, Announces $1 billion Investment at Texas City .
39 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 47 of 150
d. Costs and Consequences to BP of the Texas City Disaster
121. As a result of the Texas City disaster, BP pleaded guilty to federal felony charges
and was fined more than $50 million by the U.S. Environmental Protection Agency. BP officers
signed a settlement with federal safety inspectors vowing to institute improvements, but in 2009
the federal Occupational Safety and Health Administration (“OSHA”) assessed an $87 million
fine – the largest in its history – to BP for failing to correct the safety violations at the Texas City
plant. OSHA also declared that BP had a “ serious systematic safety problem .”
122. OSHA enforcement at the BP refinery was also examined. After the explosion,
OSHA uncovered 301 “egregious willful” violations for which BP paid a $21 million fine, the
largest ever issued by OSHA.
123. A 2006 shareholder derivative lawsuit in the aftermath of the Texas City refinery
explosion resulted in a settlement in which BP agreed to incorporate changes to improve its
safety record.
3. 2005: THUNDER HORSE
124. BP invested $5 billion in Thunder Horse, a huge drilling platform in Gulf of
Mexico. Thunder Horse, at full capacity, could pump 250,000 barrels of oil per day, doubling
BP’s total oil output in the Gulf.
125. In July 2005, Thunder Horse was evacuated due to the approach of Hurricane
Dennis. After the hurricane had passed, the platform was listing badly.
126. The cause of the list was six inches of pipe that had been improperly installed and
allowed water to flow freely between tanks that kept the rig level. Additionally, one way valves
40 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 48 of 150
that were supposed to keep water out had been installed backwards and were forced open when
the rig began to tip over. 30
127. BP soon discovered that the pipes connecting to the rig were cracked because of
welding mistakes. If the well had been active at the time of the accident, the damaged pipes
could have caused a major oil spill. As a senior engineering consultant on the Thunder Horse
project, later explained: “You would have lost a lot of oil a mile down before you would have
even known. It could have been a helluva spill – much like the Deepwater Horizon.” 31
4. 2006: PRUDHOE BAY, ALASKA
128. On March 2, 2006, BP discovered an oil spill at its pipeline in Western Prudhoe
Bay, Alaska. 267,000 gallons of oil had spilled over 1.9 acres, making it one of the largest oil
spills ever in Alaska. The cause of the leak was a corroded pipeline that was the result of grossly
neglected maintenance. BP was later forced to admit that it had implemented various
cost-cutting measures that had reduced monitoring of the pipeline for corrosion. As
Robert Malone, CEO of BP America, admitted to a congressional committee, there “was a
concerted effort to manage the costs [at the Alaska fields] in response to the continuing
decline in production at Prudhoe Bay.” 32
129. Inspectors found that the steel pipe – the inside of which hadn’t been inspected in
years – had been corroded to dangerously thin levels along nearly 12 miles of pipeline. BP had
30 Sarah Lyall et al., In BP’s Record, a History of Boldness and Costly Blunders (N.Y.
Times July 12, 2010).
31 Id.
32 Andrew Buncombe, BP’s Oil Spill in Alaska Blamed on Cost-Cutting (The
Independent, May 17, 2007).
41 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 49 of 150
been warned to check the pipeline in 2002, but did not do so. BP was fined $20 million in
criminal penalties after prosecutors charged it with neglecting corroded pipelines.
a. Employees’ Complaints of Cost Cutting At the Expense of Safety
130. In 2001, as part of a probation with the EPA to avoid having its Alaska division
debarred, BP agreed to reorganize its environmental management, establish protections for
employees who spoke out about safety issues, and reform its approach to risk and regulatory
compliance.
131. While BP pledged to improve its conduct and reform its safety and maintenance
programs, BP employees had raised concerns about management’s concerted commitment to
safety and maintenance programs.
132. In October 2001, a BP Operations Review Team issued a report finding that
“certain critical safety systems are in need of urgent maintenance or significant upgrades” and
that “workers are not convinced that management is adequately addressing their operational 33 integrity concerns.” The Report also found that “[m]any employees believe that budgets have
been cut too deeply and that [Greater Prudhoe Bay] management’s top priority is controlling
costs in order to achieve short-term budget targets and not safety, regulatory compliance or
delivering long-term operational integrity. 34
133. As was confirmed in this Operational Integrity report, BP had neglected key
equipment needed for emergency shutdown, including safety shutoff valves and gas and fire
33 BP Operational Review Team, Review of Operational Integrity Concerns at Greater
Prudhoe Bay (Oct. 2001), at Pg. 5.
34 Id. at Pg. 13.
42 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 50 of 150
detectors similar to those that could have helped prevent the fire and explosion on the
Deepwater Horizon rig in the Gulf.
134. The panel identified systemic problems in maintenance and inspection programs –
the operations that keep the drilling in Prudhoe Bay running safely – and warned BP that it faced
a “fundamental culture of mistrust” by its workers, in part because senior management lacked a
structure of accountability.
135. The Report, in relevant parts, found
There is a disconnect between GPB (Great Prudhoe Bay) management's stated commitment to safety and the perception of that commitment .
Correcting these underlying causes is essential ... for ensuring long term
operational efficiency and mechanical integrity. Without a concerted effort to address these basic issues, any other action will provide only temporary relief. 35
136. The Report found maintenance backlogs to be “unacceptable,” concluding that
BP tried to sustain profits even though production was declining. BP also neglected to clean and
check pressure valves, emergency shutoff valves, automatic emergency shutdown mechanisms
and gas and fire safety detection devices essential to preventing a major explosion. It warned
management of the need to update those systems, which “ have a potential immediate safety impact or that pose an environmental threat .”36
137. The Report also warned that emergency shutdown systems would need to be
operated manually, that there may not be enough staff to do so, and said that even if closed, the
isolation valves were known to leak.
35 Review of Operational Integrity Concerns at Greater Prudhoe Bay, Pg. 19 (October,
2001).
36 Id. at Pg. 7.
43 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 51 of 150
138. The Report found that workers did not have adequate access to “as built”
drawings of equipment and the progressing work. “As-built” drawings allow engineers and first
responders to quickly understand the details of the equipment and the ongoing construction, and
therefore to adequately respond. However, as is clear, from the Kenneth Abbott’s whistle blower
complaint, discussed infra, this was a recurring problem at BP.
139. “As-built” drawings are essential safety components. They prove that a piece of
equipment, e.g. a shutoff valve, was built the way it was supposed to be. Those drawings are
thus the final checks to make the equipment operates properly. They also serve as instruction
manuals for emergencies. If there is a fire or blowout, operators can use the drawings to find a
kill lever that can shut an engine down.
140. BP retained the law firm Vinson & Elkins to investigate complaints made by its
Prudhoe Bay employees. The firm’s study confirmed that pipeline corrosion endangered
operations but also found that BP allowed “pencil whipping,” or the falsification of inspection
data and an intense “pressure on contractor management to hit performance metrics (e.g. fewer
OSHA recordables) creates an environment where fear of retaliation and intimidation did occur.”
The report quoted an employee who said BP workers felt pressure to skip key diagnostics,
including pressure testing, cleaning of pipelines and checking for corrosion, in order to cut
costs.37
141. According to a safety complaint filed by a BP employee, BP Management, in an
effort to cut costs, failed to “to rebuild the pulling equipment as often . . . and possibly not
37 Abrahm Lustgarten & Ryan Knutson, Years of Internal BP Probes Warned That
Neglect Could Lead to Accidents (ProPublica June 7, 2010).
44 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 52 of 150
pressure test the equipment . . . [t]his obviously would increase the potential for equipment 38 failure resulting in equipment damage, environmental spills and injury to workers.”
142. In August 2006, just five months after the spill at Prudhoe Bay, Stuart Sneed, a
pipeline safety technician for a BP contractor, discovered a crack in the steel skin of an oil transit
line. Nearby, contractors were grinding down metal welds, sending a fan of sparks shooting
across the work site. Sneed feared the sparks could ignite stray gases, or the work could make
the crack worse, so he ordered the contractors to stop working.
143. According to Sneed: “Any inspector knows a crack in a service pipe is to be
considered dangerous and treated with serious attention. . . . The crack could have created a
hellacious leaker with people grinding on it.” Sneed was scolded by his supervisor for stopping
the contractors from working, singled out by his supervisor and harassed and two weeks after the
incident was terminated.
144. During the investigation into Sneed’s termination, investigators determined that
“many of the people interviewed indicated that they felt pressured for production ahead of
safety and quality.” Contractors received a 25% bonus tied to BP’s production numbers. This
led to fewer delays which in turn led to more oil being pumped which in turn led to more cash
flow to companies executing the work under BP supervision. Sneed said of BP’s corporate
policies and public statements, “ They say it’s your duty to come forward . . . but then when
you do come forward, they screw you. They’ll destroy your life . . . No one up there is
38 Id.
45 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 53 of 150
going to say anything if there is something they see is unsafe. They are not going to say a
word.”39
b. BP Pleads Guilty
145. On October 25, 2007, a BP subsidiary pled guilty to a criminal violation of the
Clean Water Act and U.S. District Court Judge Ralph Beistline sentenced BP to three years
probation. Judge Breistline stated at that time that oil spills were a “serious crime” that could
have been prevented if BP had spent more time and funds investing in pipeline upgrades and a
“little less emphasis on profit.” A Congressional committee later determined that BP had
ignored opportunities to prevent the spill and that “draconian” cost-saving measures had
led to shortcuts in its operations .
146. According to Jeanne Pascal, a former EPA attorney, who investigated BP for
twelve years, “They are a recurring environmental criminal and they do not follow U.S. health
safety and environmental policy . . . At what point are we going to say we are not going to do
business with you any more, bye? None of the other supermajors have an environmental
criminal record like they do.”
147. The architect of the BP Alaska environmental disaster and retaliatory atmosphere,
Doug Suttles, eventually was promoted at BP America, and put in charge of the Gulf of Mexico
offshore operations.
39 Abrahm Lustgarten & Ryan Knutson, Years of Internal BP Probes Warned That
Neglect Could Lead to Accidents (ProPublica June 7, 2010).
46 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 54 of 150
D. REGULATORY REPORTS FORCE BP TO ADDRESS, AT LEAST PUBLICLY,
SAFETY LAPSES
1. BAKER REPORT
148. After the Texas City refinery incident, BP followed the recommendation of the
U.S. Chemical Safety and Hazard Investigation Board and formed the BP US Refinery
Independent Safety Review Panel to conduct a thorough review of the company’s corporate
safety culture, safety management systems, and corporate safety oversight. The Panel included
such luminaries as James A. Baker, III, former U.S. Secretary of State and former Senator
Thomas Slade Gorton III (R-Washington).
149. In January 2007, the Panel issued a report, commonly referred to as the “Baker
Report,” which stated that “BP’s Group requirements are intended to ensure a consistent Group-
wide effort to achieve BP’s stated commitment toward ‘no accidents, no harm to people, and no
damage to the environment.’”
150. The Baker Report set forth the standards and guidelines that BP publically
claimed to be followed in a section entitled, “BP Group-Level Standards, Practices, and
Expectations for Process Safety.” This section goes on to state:
BP CODE OF CONDUCT
The Code of Conduct provides a starting point for the conduct expected of BP
employees.” All employees must follow the Code of Conduct, and supervisors
must also promote, monitor, and enforce compliance with it. The Code of
Conduct contains a two-page section addressing the health-and safety-related
conduct of all BP employees and anyone else working at BP facilities. It
provides that “[n]o activity is so important that it cannot be done safely” and
emphasizes that “[s]imply obeying safety rules is not enough. BP’s
commitment to safety means each of us needs to be alert to safety risks as we go
about our jobs. The Code of Conduct does not make reference to specific BP
standards, practices, or expectations; instead, it contains a list of basic rules that
all employees must follow. These basic rules induce practices that might be
47 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 55 of 150
described as axiomatic, such as “stop any work that becomes unsafe” and “make
sure you know what to do if an emergency occurs at your place of work.”
GETTING HSE RIGHT
Getting HSE right (gHSEr) describes the BP HSE Management System
Framework and represents how BP intends to meet its HSE performance
commitment. It sets forth the Group’s expectations for the health, safety, and
environmental practices of its business units. These HSE expectations
“encompass the complete spectrum of health, safety, and environmental risk
management including personal security, technical/operational integrity of
facilities and equipment, and product stewardship. gHSEr represents “the
boundaries within which all SP managers must operate” and is mandatory for
every business unit.
According to BP, an HSE management system containing the gHSEr elements
should ensure continuous improvement of the business unit’s HSE practices
through a”Plan-Perform-Measure-and-Improve cycle.” Each business unit is then
responsible for designing an HSE management system that meets all of the
relevant BP Group-wide expectations set out in gHSEr:
BP’s HSE expectations are presented in gHSEr’s 13 Elements of Accountability,
which provide expectations in the following areas:
• Leadership and accountability . Managers must develop,
document, and implement HSE management systems in
accordance with HSE expectations.
• Risk assessment and management. Managers must assess,
document, and reference risks in their decisions.
• People, training, and behaviors. HSE responsibilities should be
assigned by managers to individuals, and managers must document
those responsibilities and create performance targets.
• Working with contractors and others. Contractors must be
supervised, and this includes reviewing their HSE policies,
• Facilities design and construction. There must be documentation
of project management systems and formal approval for design,
procurement, and construction standards. Also, pre-start-up
reviews must be carried out for all new or modified equipment.
48 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 56 of 150
• Operations and maintenance. Post-start-up reviews must be
completed and procedures must be developed and followed for
equipment operations, maintenance, and retirement.
• Management of change. Changes must be formally assessed and
approved, and they must nat exceed their original scope or
duration.
• Information and documentation. Information must be made
available but also secure.
• Customers and products. BP must maintain information about
product hazards and adverse product effects and have a recall
system in place.
• Community and stakeholder awareness. BP must communicate
HSE information to the community.
• Crisis and emergency management. Plans must be developed,
continuously updated, and tested through drills.
• Incident analysis and prevention. All incidents must be fully
reported, investigated, and findings must be shared as appropriate.
BP should have teams with some members from outside the
business unit for major incidents.
• Assessment, assurance, and Improvement. HSE target, and
audit programs to track progress towards them must be established.
In addition to these elements of accountability, gHSEr contains key HSE
processes that BP business units should employ as part of their HSE management
systems. The HSSE processes listed in gHSEr are directed toward delivering
HSSE assurance, behaviors, HSSE risk management, crisis and emergency
management, major incident and high potential incident reporting, incident
investigation guidelines, HSSE performance targets, HSSE reporting
requirements, joint ventures and other operational experiences, HSSE reporting
definitions, and health management.
gHSEr contains an expectation that BP business units conduct gHSEr
self-assessments annually and sponsor external gHSEr audits at least once every
three years. The Panel has reviewed a number of reports describing recent gHSEr
self-assessments and audits of individual U.S. refineries. The Panel has also
reviewed reports that BP’s Internal.
49 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 57 of 150
BP GOLDEN RULES
The Golden Rules are intended to provide easy-to-remember, basic guidance to
the BP workforce in eight areas: (l) permit to work, (2) ground disturbance, (3)
working at heights, (4) driving safety, (5) energy isolation, (6) confined space
entry, (7) lifting operations, and (8) management of change. Several of the
Golden Rules, including permit to work and management of change, are relevant
to the management of process safely.
In addition to the Golden Rules, BP expects that the following basic principles
will be incorporated into each rule:
“[W]ork will not be conducted without a pre-job risk assessment and a safety
discussion . . . [A]ll persons will be trained and competent in the work they
conduct. [P]ersonal protection equipment will be worn . . . [E]mergency response
plans . . . will be in place before the commencement of work .... [And] everyone
has an obligation to stop work that is unsafe.”
The Golden Rules do not provide specific procedures aimed at refining operations
or any other individual BP operation. Standards and policies addressing specific
aspects of BP operations are contained in, among other sources, Group standards
and engineering technical practices, which are discussed below. Because they
apply broadly to the daily activities of BP’s workforce, the Golden Rules
frequently overlap with more specific sources of authority such as Group
standards or engineering technical practices. The Golden Rules are relatively
simple, and they do not appear to conflict with more specific authorities. BP’s
control of Work Group standard, which touches on many of the same work
practices contained in the Golden Rules, states that guidelines in the control of
work standard should be used in conjunction with the Golden Rules.
BP GROUP STANDARDS
BP has issued a limited number of Group standards to address certain risks
relating to all of BP’s business segments, such as Refining and Marketing. Group
standards establish expectations and processes for reducing the risk of failure to
deliver Board goals or the risk of noncompliance with the Code of Conduct in the
areas that are subject to Group standards. As of December 1, 2006, BP had issued
Group standards related to safety in the areas of driving safety, control of work,
and integrity management. In addition, a draft Group marine operations standard
is currently under review. Three of BP’s Group standards have direct bearing on
process safety practices in refining, the 2001 process safety/integrity management
standard: the new 2006 integrity management standard which replaces the process
safety/integrity management standard; and the control of work standard.
50 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 58 of 150
BP process safety/integrity management standard
In May 2001, BP issued a process safety/integrity management (PS/IM) standard
directed toward process safety/integrity management at BP facilities. Intended to
support the delivery of the HSE expectations in gHSEr, BP promulgated this
standard partly in response to three major process incidents that occurred at the
BP Grangemouth Petrochemical Complex in Scotland during May through June
2000.
The PS/IM standard sought to “help prevent the occurrence of, or minimize the
consequences of, catastrophic releases of hazardous materials and to assure
facilities are designed, constructed, operated[,] and maintained in a safe fashion
using appropriate codes and standards.” It established requirements in the
following areas related to process safety and integrity management, hazard
evaluation, management of change, mechanical integrity, protective systems,
competent personnel, incident investigation, emergency response, and
performance management and assurance, BP viewed the eight requirements
comprising the PS/IM standard as having their basis in the gHSEr expectations, and applicable gHSEr expectations were linked to each of the eight requirements.
A key aspect of the PS/IM standard is the requirement that “[a]ll facilities must
systematically identify hazards within its boundary arising from normal and
abnormal operations and shall eliminate/ control/mitigate the hazards such that
residual risks are as low as is reasonably practicable. The new integrity
management standard, described below, has superseded the PS/IM standard.
BP integrity management standard
BP designed the integrity management standard to ensure that equipment used in
BP operations is fit for service, thereby avoiding loss of containment incidents. In
promulgating this standard, BP observed that it was derived from, and intended to
improve upon, the 2001 PS/IM standard. The integrity management standard
defines a formal approach to management integrity at BP operations during all
phases of equipment life, from design and construction, through operation and
maintenance, to decommissioning. BP’s U.S. refineries have begun to implement
the integrity management standard, with full implementation required by
December 31, 2008. BP has recently developed an audit protocol for assessing
compliance with the integrity management standard.
The integrity management standard has ten elements: (1) accountabilities, (2)
competence, (3) hazard evaluation and risk management, (4) facilities and process
integrity, (5) protective systems, (6) practices and procedures, (7) management of
change. (8) emergency response, (9) incident investigation and learning, and (10)
performance management and learning. According to BP, the integrity
management standard has incorporated all elements of the superseded PS/IM
standard. However, the Panel notes that the integrity management standard’s
51 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 59 of 150
hazard evaluation and risk management element does not contain the PS/IM
standard’s requirement that identified risks be mitigated “as low as reasonably
practicable.” Instead, the new integrity management standard contains a more
general requirement that BP operations “identify and mitigate” integrity
management hazards and risks, including development of a hazard and risk
register for each BP operation with links to the measures, systems, processes, and
procedures in place to manage or mitigate the risks.
The integrity management standard requires all BP operations to conduct an
assessment for quantifying and ranking major accident risks. This major accident
risk methodology is described in BP Group Engineering Technical Practice GP
48-50, Guidance on Practice for Major Accident Risk Process, discussed below,
To ensure that the assessments are done consistently from one refinery to the next,
BP’s Head of Major Hazards and Fire established dedicated teams to conduct
major accident risk assessments of BP refineries. In addition to major accident
risk assessments, the integrity management standard also requires each site to
develop formal procedures for identifying and managing integrity management
hazards associated with both normal and abnormal operations.
BP control of work standard
BP issued the control of work standard to ensure a “formal approach to managing work risk for BP employees and for BP companies and their contractors.
Although the BP Golden Rules existed prior to the control of work standard and
provided some basic guidance relating to control of work, BP concluded that the
standard was necessary based upon its review of fatal accidents to the BP
workforce from 2000 to 2004. From this review, BP discovered that job factors
related to control of work were frequently identified during its incident root cause
analyses.
BP intends for the control of work standard to provide a means for safely
controlling construction, maintenance, demolition, remediation, operating
tasks, and similar work activities. Among other things, the control of work
standard requires a written policy for describing the control of work process,
defined account abilities for all identified roles within the control of work policy
and associated procedures, and training for persons involved in the control of
work process. The standard also prohibits tasks unless they are assessed for
risk. Additionally, it imposes a permit requirement for work involving confined
space entry, work on energy systems, ground disturbance, hot work, or other
hazardous activities. Control of work policy and associated procedures must also
make clear to everyone that they have the obligation and authority to stop unsafe
work. Refineries must implement the standard by the end of 2009.
52 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 60 of 150
BP refining subsequently published minimum expectations for control of work to
implement the control of work standard. This publication contains
element-by-element direction, specific to BP refining operations, to ensure that
BP refineries comply with the requirements contained in each element of the
standard.
151. In sum, the Baker Report warned of a systemic breakdown in BP’s process
management, noting that “information available to the Panel appears to indicate a more systemic breakdown occurring at multiple levels and in different line and functional positions.” 40
152. After the Baker Report was released, Browne stated: “We will use this report to
enhance and continue the substantial effort already underway to improve safety culture and
process safety management at our facilities . . . I intend to ensure BP becomes an industry
leader in process safety management and performance. ”41
153. At a BP news conference following the presentation of the Baker Report,
Browne said:
If I had to say one thing which I hope you will all hear today it is this, BP gets it, and I get it too.
This happened on my watch and, as Chief Executive, I have a responsibility to
learn from what has occurred. I recognise the need for improvement and that my
successor, Tony Hayward, and I need to take a lead in putting that right by championing process safety as a foundation of BP’s operations .42
40 Baker Report, Pg. 228.
41 Jan. 16, 2007 BP Press Release, BP will Implement Recommendations of Independent
Safety Review Panel.
42
http://www.bp.com/liveassets/bp_internet/globalbp/globalbp_uk_english/SP/STAGING/1
ocal assets/assets/pdfs/Baker_panel transcriMpdf
53 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 61 of 150
2. U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD
FINAL REPORT
154. In March 2007, the Safety Board issued its final report on the Texas City
explosion.
155. The Safety Board concluded that BP at its highest levels failed to insure that it
could safely operate its refinery. The “BP Group Board did not provide effective oversight of
BP’s safety culture and major accident prevention programs” and the BP Group . . . did not
effectively evaluate the safety implications of major organizational, personnel and policy
changes.”43
156. Moreover, the Safety Board determined that BP’s senior officers, in mandating
budget cuts to safety programs with knowledge of the perilous safety conditions at Texas City,
left “the Texas City refinery vulnerable to catastrophe.” 44
157. Specifically the Board found:
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.
Decisions to cut budgets were made at the highest levels of the BP Group
despite serious safety deficiencies at Texas City. BP executives directed Texas
City to cut capital expenditures in the 2005 budget by an additional 25 percent
despite three major accidents and fatalities at the refinery in 2004.
158. The Safety Board concluded that budgets cuts and a lack senior officer and
director concern for process safety negatively impacted BP’s safety processes:
43 CSB Report, at 179, 210.
44 Id. at Pg. 20.
54 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 62 of 150
Cost-cutting, failure to invest and production pressures from BP Group executive managers impaired process safety performance at Texas City. 45
BP Group executive management became aware of serious process safety
problems at the Texas City refinery starting in 2002 and through 2004 when three major incidents occurred. 46
BP Group Board did not provide effective oversight of the company’s safety
culture and major accident prevention programs. 47
159. The Safety Board noted that BP’s safety process problems were not confined to
the Texas City refinery. In 2004, “BP’s “GHSER [Getting Health, Safety and the Environment
Right] audits for 2003 . . . found a number of serious safety deficiencies common throughout the corporation.”48
E. BP RESPONDS TO ENVIRONMENTAL DISASTERS BY PROMISING
CHANGE
160. In 2007, after the continuous stream of disasters and the publication of the Baker
Report and the final Safety Board Report, BP aggressively sought to change its public image.
Recognizing BP’s poor safety history, CEO Anthony Hayward took over the company in 2007
and launched a campaign to convince the market that the company had changed its ways and was
conducting its operations in a safe and reliable manner. This response was also critical to BP’s
ability to maintain its share value, given its tarnished reputation from the string of environmental
disasters.
45 Id. at Pg. 25.
46 Id. at Pg. 143.
47 Id. at Pg. 295.
48 Id. at Pg. 166.
55 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 63 of 150
161. After taking over as CEO, Hayward represented that his first priority was
“focusing like a laser on safe and reliable operations .” In an interview before his
announcement as CEO, he described how the death of a worker who was on an operation he was
leading in Venezuela shaped his opinion. Defendant Hayward stated that, “I went to the funeral to pay my respects. At the end of the service his mother came upon and beat me on the chest.
‘Why did you let it happen?’ she asked. It changed the way I think about safety. Leaders must make the safety of all who work them their top priority .”
162. Hayward took office amid three criminal investigations and publicly sought to
implement a five-year plan to improve safety across the company.
163. While BP began to tout new areas of oil exploration and production, such as the
deepwater Gulf of Mexico and BP’s unique ability to extract and produce that oil in an
environmentally friendly and safe manner that posed little risk to the company and its
shareholders, Hayward was concerned that “ delays to new production in the Gulf of Mexico” were causing BP’s profits to dip. 49
164. Concealed from Plaintiffs, was Hayward’s and BP’s uninterrupted focus on cost-
cutting and refusal to correct the safety process issues that were roiling the Company. As is now
clear, despite its history of catastrophes and close calls, BP is unable or unwilling to learn from
its many mistakes or to give up its thirst for profits above all else. The company’s dismal safety
record and disregard for prudent risk management are the results of a corporate safety culture that
49 Terry Macalister, Hayward Outlines restructuring to BP staff (The Guardian, October
11, 2007).
56 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 64 of 150
has been repeatedly called into question by government regulators. BP has consistently chosen profits over safety and often at the expense of human lives, the environment, and shareholders.
165. Hayward and the individual defendants had ample motivation to ignore process
safety. According to BP’s year end 2009 20-F, under the executive compensation policies
adopted by the Board, 70% of Hayward’s performance bonus in 2009 would be based on the
achievement of financial metrics, and only 15% on safety (and not process safety ). As a
result, while BP would publicly represent the safety of its Gulf Operations, its CEO had no
incentive to implement true safety mechanisms.
F. BP MISLEADS INVESTORS REGARDING THE SAFETY OF ITS GULF
OPERATIONS
166. In its 2009 Annual Form 20-F, filed on March 5, 2010, BP stated in a section
entitled “Safety” that “ Good progress is being made on underpinning improved safety
performance in 2009. Throughout the year, we continued to focus on training and
enhancing procedures across the organization ” and touted the “continued success of our
Gulf of Mexico deepwater operations. ”
167. While focusing on marketing itself as being able to achieve substantial revenue
growth from new oil exploration in the Gulf of Mexico, BP misled investors that it was
conducting such operations in a safe manner. For example, BP was quietly cutting thousands of
jobs in an effort to save billions. In 2009, Defendants cut operational costs by 15% stretching
BP’s ability to operate in the Gulf in a non-dangerous manner.
168. In December 2008, an internal BP strategy document warned Defendants that BP
still did not adequately plan for serious safety risks for its operations in the Gulf. The
document warned that senior management’s failure to address this shortcoming could result in
57 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 65 of 150
“multiple injuries/fatalities,” “major environmental damage,” “catastrophic loss of the facility,” 50 and “damage to corporate reputation.” Instead of confronting its inadequate safety processes,
BP represented the exact opposite. In its 2009 20-F, while addressing its oil exploration and
production operations, including highlighting its deepwater Gulf of Mexico operations, BP stated
that, “In Exploration and Production, safety, both personal and process, remains our highest
priority .”
1. BP ATLANTIS: DEFENDANTS CONCEAL REPEATED WARNINGS
ASSOCIATED WITH THEIR GULF OF MEXICO OPERATIONS
169. In mid-2008, safety issues regarding BP’s Gulf operations were raised within BP.
BP’s Deepwater Atlantis facility had a piece of tubing rupture which caused a 193 barrel oil
spill.51 The tubing was connected to a pump that had failed after BP managers had delayed
maintenance on it. An internal report later found that maintenance was postponed because of a
“tight cost budget. ”52
170. Internal BP documents, concealed from the investing public, revealed that BP
investigators found “the deferred repair was a ‘critical factor’ in the incident, but ‘leadership did
not clearly question’ the safety impact of the delay. The budget for Atlantis – one of BP’s most
50 Peter Elkind, et al., BP: “An Accident Waiting to Happen,” (Fortune, January 24,
2011).
51 Guy Chazan, et al., “As CEO Hayward Remade BP, Safety, Cost Drives Clashed ,”
(Wall Street Journal, June 29, 2010).
52 “BP Oil Spill: The Rise and Fall of Tony Hayward ,” Telegraph., July 27, 2010.
58 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 66 of 150
sophisticated facilities – was ‘underestimated,’ resulting in ‘conflicting directions/demands.’ As
investigators were questioning Atlantis’ lean operation, top executives were praising it. 53
171. According a June 29, 2010, Wall Street Journal’s investigation: “ In an internal
communication in early 2009, Neil Shaw, then-head of BP's Gulf of Mexico unit, lauded
Atlantis' operating efficiency , saying it was ‘4% better than plan’ in its first year of production.
It was part of a success story that Mr. Shaw said had enabled BP to become the No. 1 oil producer in the Gulf.”54
172. In this same time period, Kenneth Abbott, a thirty year oil and gas veteran, was
hired as the “project controls lead” for the Atlantis. Abbott supervised six persons charged with
internal auditing of Atlantis’ engineering documents, including “as-built” drawings. Abbott soon became aware that BP did not have a large number of “as-built” drawings.
173. This was well-known to the management of Atlantis. Abbott’s predecessor, Barry
Duff told Abbott and confirmed via email that the “as-built” drawings were not yet ready to be
delivered to the crews that operated the Atlantis.
The current procedures are out of date . . . The risk in turning over drawings that are not complete are:
1) The Operator will assume the drawings are accurate and up to date. This could
lead to catastrophic Operator errors due to their assuming the drawing is
correct. Turning over incomplete drawings to the Operator for their use is a
fundamental violation of basic Document Control, the IM Standard and Process Safety Regulations,
2) Having the project document control person turnover drawings that are not
complete, places the onus on her that they are the most current version. Currently
53 Guy Chazan, et al., “As CEO Hayward Remade BP, Safety, Cost Drives Clashed ,”
(Wall Street Journal, June 29, 2010).
54 Id.
59 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 67 of 150
there are hundreds if not thousands of Subsea documents that have never been
finalized, yet the facilities have been turned over. In some cases, Tinikka does not
have all the versions. Turning over the version she has, runs the risk of the wrong version being used.
The point here is that even if we condoned handing over documents that were not
approved/handed over, we run the risk of not handing over the most current version, (the one theoretically closest to being the most accurate).
174. While at BP Atlantis, Abbott and his team developed a database detailing the
completion status, or latest approval status. As depicted below, the majority of the documents and drawings had never received any engineering approval at any phase of the development.
175. Out of over 7,000 drawings and documents, almost 90% of the necessary
engineering inspections on Atlantis. While BP’s failure to document these engineering
inspections enabled BP to speed Atlantis into production and save two million dollars, according
to Abbott, without properly maintained “as built” engineering documents, persons operating the
Atlantis “are flying blind, and have no way to assure the safety of offshore drilling
operations.”
176. “As-built” documents are standards for the industry. Machinery is designed,
approved for manufacturing, checked to insure the machinery was built properly, and then finally
approved. Without them, it would be the equivalent of constructing a house without having an architect or engineer sign off on the blueprint. 55
177. Nonetheless, BP had obtained authorization to proceed and extract oil and gas by
falsely certifying to the government that it had the required as-built documents on hand. As a
55 House Subcommittee on Energy and Commerce, Transcribed Interview of Kenneth W.
Abbott, at Pg. 70 (June 17, 2010).
60 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 68 of 150
result, BP extracted an estimated $5 billion while failing to create, maintain, or submit critical
engineering, operations, and safety documents. 56
178. According to Abbott, “There seemed to be a big emphasis to push the contractors
to get things done and that was always at the forefront of the operation,” Abbott said “I felt
there had to be balance. You had to have safety because peoples’ life depended on it. My 57 management didn't see it that way .”
179. While BP states that Abbott’s contract was terminated because of a force
reduction, Abbott has stated that he was terminated for his continued insistence that BP develop
or obtain “as-built” engineering documents to insure the safety of BP’s offshore drilling
operations. Two weeks after his termination, BP put out an advertisement for his replacement.
180. MMS regulations as well as BP internal procedures require that the engineering
documents, which Abbott clamored for and was denied, be approved by BP engineers
specializing in the design of offshore structures. According to BP records, the design was not
approved by BP engineers. The Subsea portion of Atlantis was constructed in Drill Centers.
Each one collected the product from several wells and passed it to the surface facility. When
Abbott worked for Atlantis, Drill Center-1 was in production and Drill Center-3 was under
construction. It was brought to Abbott’s attention that his team did not have “approved for
construction” documents for Drill Center-3. In his statement to the House Subcommittee on
Energy and Mineral Resources on June 17, 2010, Abbott said that “we did not have ‘approved
for construction’ documents for DC-3. In my experience, entering into construction without
56 Id. at Pg. 2.
57 Abrahm Lustgarten & Ryan Knutson, Years of Internal BP Probes Warned That
Neglect Could Lead to Accidents (ProPublica June 7, 2010).
61 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 69 of 150
‘approved for construction’ documents can be a major problem. I immediately attempted to
obtain approved for construction documents, but was never able to obtain them.”
181. According to Abbott, the above identified items were critical to the safe and
proper functioning of a drilling system handling oil and gas flows thousands of feet beneath the
surface of the sea under extreme pressures and temperatures. “While design documentation
shortcuts are unacceptable for any engineering project, the accuracy and detail of Atlantis subsea
engineering and design is especially vital to safe operations and protection of the environment.
Yet, BP management has rejected requests by its own employees to remedy the unsafe situation 58 because of the estimated . . . cost[s].”
182. Abbott’s assertions regarding BP’s failure to complete essential engineering
documents were confirmed by BP’s Ombudsman and an independent firm hired by BP in 2009.
BP violated its own policies by not having completed engineering documents on board the
Atlantis when it began operating in 2007. 59
183. Some of the same problems Abbott raised were determined to be causal factors of
the Deepwater Horizon blowout: (1) blowout preventers did not close – on Atlantis, safety
shutdown system logic has not been engineer-approved; this could cause failure of shutdown
systems; (2) rig crew did not understand makeup of blowout preventers – this would be due to
failure to have up to date as-built documents; same problem as Atlantis; (3) a mechanic
apparently did not have access to manual shutdown procedures for diesel engines – again, failure
to have proper documentation; and (4) there was apparently no gas sniffer and automatic
58 Exh. E to the June 17, 2010 Statement of Kenneth W. Abbott before the United States
House of Representatives Subcommittee on Energy and Mineral Resources.
59 May 15, 2010 Associated Press.
62 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 70 of 150
shutdown for the diesel engines – failure to have safety equipment which should have been present happens when proper engineering procedures are not followed. 60
184. Abbott’s complaints were not the first time the company had been warned about
not maintaining as-built drawings. According to BP’s internal 2001 operational integrity
report, as-built documentation was not maintained at the company’s Prudhoe Bay
operations either.
185. Abbott later testified to Congress in 2010:
“From my experience working in the industry for over 30 years, I have never seen
these kinds of problems with other companies. Of course, everyone and every
company will make mistakes occasionally. I have never seen another company
with the kind of widespread disregard for proper engineering and safety
procedures that I saw at BP and that we hear from the news reports about BP
Horizon, or BP Texas City, or the BP’s Alaska pipeline spills. BP’s own
investigation of itself, by former Secretary of State James Baker, reported
that BP has a culture which simply does not follow safety regulations. From 61 what I saw, that culture has not changed. ”
186. Internal BP documents corroborate Abbott’s opinion of the BP culture. In an
internal report obtained by the Wall Street Journal, after the 2008 incident on the Atlantis
platform, BP on notice of its lax safety oversight and tight budgets in the Gulf of Mexico,
concluded “A key question to ask, especially with apparently minor and disconnected defects, is
‘What’s the worst thing that could happen ?’”
60 June 17, 2010 Statement of Kenneth W. Abbott before the House Subcommittee on
Energy and Mineral Resources.
61 June 17, 2010 Statement of Kenneth W. Abbott before the House Subcommittee on
Energy and Mineral Resources.
63 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 71 of 150
2. ADDITIONAL INCIDENTS PROVIDED RED FLAG WARNINGS OF
IDENTICAL RISKS TO THOSE OF THE DEEPWATER HORIZON
187. Additional incidents, concealed to the marketplace, provided additional notice of problems to come on the Deepwater Horizon.
188. An MMS study noted that blowouts during cementing work were continuing with
alarming regularity, particularly in the Gulf of Mexico. Cementing was a factor in 18 of 39 well
blowouts in the Gulf of Mexico between 1992 and 2006.
189. Halliburton, BP’s Deepwater Horizon joint venturer, was responsible for
cementing a well off the coast of Australia that blew in August 2009, leaking oil for ten weeks
before it was plugged. An MMS official has testified that a poor cement job likely caused the
blowout.
190. Moreover, a blowout preventer manufactured by Cameron was the subject of a
dispute between BP and Transocean (the builder and owner of the oil rig) in June 2000.
Cameron also made the blowout preventer that failed on the Deepwater Horizon. In the 2000
incident, BP issued a notice of default to Transocean concerning the functioning of one of
Transocean’s oil rigs, in which the blowout preventer was the subject of concern. Nevertheless,
BP used a Cameron-built blowout preventer on the Deepwater Horizon. Defendant Hayward
acknowledged the existence of this dispute in public comments on May 4, 2010. 62
191. In addition, BP was aware of an August 2009 blowout in the Timor Sea off the
coast of Australia, which was found to have been caused by careless cementing work. During
62 Stephen Power et al., Investigators Focus on Failed Device, (Wall Street Journal, May
6, 2010).
64 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 72 of 150
that incident, which bears a strong resemblance to the Deepwater Horizon disaster, oil leaked
from the site for ten weeks, spreading damage over 200 miles from the well site.
3. BP’S LEASE, DESIGN AND DRILLING OF THE MACONDO WELL
a. The Macondo Site
192. The first step in any offshore drilling process is the selection of a site to drill. In
this instance, BP paid more than $34 million to lease “Mississippi Canyon Block 252,” a nine
square mile plot of land in the Gulf of Mexico. On March 10, 2009, BP filed an Initial
Exploration Plan for Mississippi Canyon 252. The document was dated as being received by the
MMS on February 23, 2009.
193. The well itself is located approximately 48 miles from the nearest shoreline;
approximately 114 miles from the shipping supply point of Port Fourchon, Louisiana; and 154
miles from the Houma, Louisiana helicopter base. The Macondo well was BP’s first well in
Mississippi Canyon Block 252. The water in the area where the Macondo well was drilled is
approximately 5,360 feet deep.
194. The Macondo site in the Northern Gulf of Mexico is notorious for high temperatures, high pressure, highly gaseous hydrocarbon reservoirs and brittle rock formations.
It is a very difficult area to extract hydrocarbons.
195. BP knew or should have known this – the MMS letter approving BP’s Macondo
exploration plan, dated April 6, 2009, and sent from Michael Tolbert to Ms. Scherie Douglas of
BP, stated in part: “Exercise caution while drilling due to indications of shallow gas and possible
water flow.”
196. Based on seismic and other information, BP believed that there was a significant reservoir of hydrocarbons in the porous sands between 18,000 and 21,000 feet below sea level.
65 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 73 of 150
The sea floor is just over 5,000 feet below sea level. The first thousand feet below the sea floor,
the “Pleistocene Layer” consist largely of shale. Between 6,000 and 8,000 feet below sea level,
the “Pliocene Layer” is a mixture of shale and sandstone. The “Late Miocene Layer” exists from
approximately 8,000 feet to 14,500 feet below sea level and is also a mixture of layers of
sandstone and shale.
197. Below that is the “Miocene” layer, which runs from about 14,500 feet to 20,000
feet below sea level. BP expected this layer to contain a porous layer of sand and rock which
was the objective of the well. The porous layer was expected to be about 18,500 feet below sea
level.
198. Before BP could begin operations at the Macondo site, federal regulations
required BP to submit its EP demonstrating that it had planned and prepared to conduct its
proposed activities in a manner that was safe, conformed to applicable regulations and sound
66 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 74 of 150
conservation practices, and would not cause undue or serious harm or damage to human or
marine health, or the coastal environment. 30 C.F.R. §§ 250.201, 250.202.
199. At the Macondo site, the drilling operations would occur at depths in excess of
18,000 feet. BP knew that the threat of blowouts increases as drilling depths increase, especially
in an area with such troublesome geology as the Northern Gulf of Mexico.
200. After its EP was approved, BP sought a permit from the MMS authorizing it to
drill up to a total depth of 19,650 feet at the Macondo site. Notably, after the explosion and spill,
a BP crewman admitted that this depth had been misrepresented to MMS, and that BP had in
fact been drilling in excess of 22,000 feet, in violation of its permit .
b. The Macondo Well Design
201. The well was designed to be drilled down to 20,200 feet below sea level. The
design was created by engineering teams which estimated the pore pressures and strengths of the
geologic formations and used those estimates as a basis for drilling the well. The original plan
consisted of eight casing strings, starting with a thirty-six inch hole and narrowing down to the
production casing designed to be nine and seven-eighths of an inch wide. In part because of the
uncertainty inherent in the drilling process and in part because the geology of the area where the
Macondo well was drilled, there were multiple departures from the well design when the drilling
was actually underway.
202. The well called for narrowing casings on a gradual scale: a twenty-eight inch
casing to be installed at 6,275 feet; a twenty-two inch casing to be installed at 8,000 feet; a
sixteen inch casing to be installed at 12,500 feet; a thirteen and five-eighths inch liner to be
installed at 15,300 feet; a contingency liner below that; and eventually the production casing of
nine and seven-eighths inches at 19,650 feet.
67 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 75 of 150
c. Drilling the Macondo Well
203. Drilling operations began on October 6, 2009 with the Marianas. After it
evacuated on November 8, 2009 due to Hurricane Ida, it was replaced on January 31, 2010 by the
Deepwater Horizon, which resumed drilling on February 6, 2010. The pore pressures and 63 fracture gradients experienced in drilling the well were different than the design basis. There
was no way to know of these differences until the drilling actually penetrated the rock layers and the pore pressure and fracture gradient were analyzed.
204. The reality under the ocean floor was different than expected and resulted in an additional layer of casing being installed and in the depth of the changes in casing being lessened.
This resulted in a production casing being installed at an actual depth of 18,304 feet which was
only seven inches wide.
205. The first problem encountered in drilling the well occurred at approximately
12,350 feet. At that depth, there were indications of increasing pore pressure which resulted in a
lost circulation zone. This meant that the pressure the drilling fluids exerted on the surrounding
rock was too great and the mud began leaking into the rock formations. This was remedied with
the use of “Lost Circulation Materials.” These materials are sometimes known as a “pill” which
is sent down the well in order to plug leaks which are occurring into the surrounding rock.
206. After circulation was restored, there were problems re-reaching the depth of
12,350 feet. Therefore, the sixteen inch casing was installed nearly 1,000 feet earlier than
63 As noted in BP’s Deepwater Horizon Accident Investigation Report (Pg. 17), this was common for exploratory wells in the Gulf of Mexico. This highlights the inherent difficulty and risk connected with deepwater drilling in the Gulf.
68 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 76 of 150
planned. After the sixteen inch section was drilled and cemented, drilling of the next layer of
casing began which resulted in another “well control event.”
207. On March 8, 2010, BP experienced serious problems with the well, including a
hydrocarbon influx into the well and loss of well control. The hydrocarbons leaking into the well
went unnoticed for about 33 minutes, allowing 40 barrels of hydrocarbons to flow into the well
before it was shut in to restore well control. The formation damage from the March 8, 2010,
incident was so severe that a length of drilling pipe became stuck in the open hole of the well
bore, and BP was forced to abandon the lower part of the well bore, plug it with cement, and
begin drilling anew in a different direction, setting well progress back several days and costing
$25 million.
208. Pursuant to their Drilling Contract, BP was paying Transocean approximately
$500,000 per day to lease the Deepwater Horizon, not including contractors’ fees. BP had
planned for the drilling work at Macondo to take 51 days, at a cost of approximately
$96,000,000. Therefore, the lowest part of the wellbore was abandoned.
209. Subsequent drilling bypassed the abandoned wellbore, and revised plans now
called for the seven inch production string to be used due to the high formation pressure
encountered at these depths. The drilling continued with a new contingency liner until April 4,
2010 when another lost circulation event occurred at 18,260 feet. Lost circulation “pills” were
again pumped into the well, and the mud weight was reduced from 14.3 pounds per gallon
(“ppg”) to 14.17 ppg. At this point, there was almost no margin for error because the difference
in the pore pressure and the fracture gradient was almost nonexistent – the pressure had to be
maintained at 14.0 ppg to balance the pressure exerted by the hydrocarbons in order to attempt to
prevent a kick or blowout.
69 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 77 of 150
210. The reduction in pressure solved the circulation problems and full circulation was
regained on April 7, 2010. Two days later, the well was drilled to a final depth of 18,360 feet.
At this point, the BP engineers calculated that drilling any deeper would increase the pressure
beyond the fracture gradient because the additional weight of the mud, even at the lowest
pressure possible. Therefore, they concluded that the well could not be drilled any deeper
without either fracturing the rock or having hydrocarbons begin to seep up the wellbore. The
final stopping point was nearly 2,000 feet shallower than the original designs.
211. Once the final depth was reached, the crews spent five days “logging” the well in
order to evaluate the Pay Zone. After the reservoir was determined to be both large enough and
at acceptable pressure levels, the crews conducted tests to check the stability of the well. One of
these tests was a “bottoms up” test, which involves circulating mud from the bottom of the well
back up to the top by pushing new mud into the well. This is done to ensure that there is no gas
trapped inside the mud.
d. Departures from Normal Procedures in Drilling the Macondo Well
212. Because drilling oil wells, in general and drilling deepwater wells, specifically is
inherently risky and unpredictable, there are always surprises that require changing plans and
diverting from normal drilling techniques. However, the series of decisions were made during
the drilling of the Macondo well which were the product of a corporate culture within BP to save
money and time, which resulted in increasing the already significant risks associated with
deepwater drilling.
1. Long String Casing Versus a Liner
213. In order to strengthen the well design and provide multiple barriers against
blowouts, drilling companies often use a redundant casing design called a “liner/tieback,” which
70 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 78 of 150
provides four barriers against blowouts, while the “long string” casing design chosen by BP only
provided two: the cement sealing off the hydrocarbons in the reservoirs from entering the well
and, more than 18,000 feet above that, the seal assembly at the top of the well.
214. The long string casing design was especially inappropriate for a difficult and
kick-prone well like Macondo. BP had originally planned to use the safer liner/tieback design,
but rewrote the drilling plan just weeks before the disaster – against the advice of its contractors
and its own employees – because the project was behind schedule and over budget. Internal BP
emails from late March 2010 acknowledged the risks of the long string design but chose it as the
primary option because it “saves a lot of time . . . at least 3 days,” “saves a good deal of
time/money,” and is the “[b]est economic case.” 64
215. For two days on April 14 and 15, 2010, engineers from Halliburton and BP used
computer modeling to attempt to determine the outcome of the cementing process. Early results
suggested that there was not a reliable way to cement a long string production casing. The
cementing experts recommended a shift to a Liner, but that recommendation was resisted by BP.
216. BP could have drilled the hole with a “liner” which would have reduced the
blowout risk, but this was rejected because it would cost up to $10 million more .
217. Although the liner/tieback design is more expensive and takes more time to
install, it provides four barriers against hydrocarbons leaking into the well and causing blowouts:
(1) the cement at the bottom of the well; (2) the hanger that attaches the liner pipe to the existing
64 Email from Brian Morel, BP Drilling Engineer, to Allison Crane, Materials
Management Coordinator, March 25, 2010; Email from Brian Morel, BP Drilling Engineer, to
Sarah Dobbs, Completion Engineer, March 30, 2010.
71 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 79 of 150
casing in the well; (3) the cement that secures the tieback pipe on top of the liner; and (4) the seal 65 assembly at the wellhead.
218. BP was aware that the long string design was the riskier option. A BP “Forward
Plan Review” recommended against the long string option because of the risks: “Long string of
casing was the primary option” but a “Liner/Tieback . . . is now the recommended option.”
219. The BP Forward Plan Review identified several arguments against using the long
string casing design, including the high risk of a failed cement job, the inability to comply with
MMS regulations, and the need to verify the cement job with a cement bond log test and most
likely perform remedial cement job(s). The Review also noted a number of advantages to using
the liner/tieback design, including the liner hanger acting as an additional barrier against influxes,
a higher chance for a successful cement job on the first try, and the flexibility to postpone a
remedial cement job, if it was found that one was required.
2. A Lack of Centralizers
220. While the crew was lowering the casing, they began installing centralizers in order
to ensure that the casing would remain centered in the wellbore when the cementing process
began. The original designs had called for sixteen or more centralizers to be placed along the
long string. On April 1, 2010, BP learned that their supplier of centralizer subs had only six
centralizer subs available. At this point, BP was faced with a choice – wait for their supplier to
order and receive more centralizer subs or use slip-on centralizers to make up the difference.
221. Centralizers ensure that the casing pipe is centered in the well bore; if the pipe is
not centered, the cement placed around it often fails to create a secure seal against the
65 House Subcommittee on Energy and Commerce, Letter to Tony Hayward, at Pg. 4
(June 14, 2010).
72 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 80 of 150
highly-pressurized hydrocarbons surrounding the well. The cement around the casing is intended
to seal the space (the “annulus”) between the rock walls of the drilled out well bore hole and the
casing that runs through the well bore. If the casing is not centered within the wellbore, the pipe
can lay near or against the sides of the bore hole, creating too narrow of a space for the cement to
set properly and leaving “channels” of empty space or weak areas in the cement. Those channels
and imperfections can allow hydrocarbons to escape out of the formations and into the well,
causing a kick or a blowout.
222. Based on modeling done on proprietary software called OptiCem, which
calculates the likely outcome of cementing jobs based on a number of variables, including the
number of centralizers, the Macondo production casing needed more than six centralizers in
order to avoid “channeling.” Channeling occurs when the annular areas outside the production
casing are unequal, causing the cement to flow more quickly up one side and slowly, or not at all,
up the other portions which allows for gas flow in the annular areas.
223. The BP engineers were told of the need for more centralizers on April 15, 2010.
BP’s team obtained permission from senior manager David Sims to order sixteen additional slip-
on centralizers, which was the most BP could transport on a single helicopter, meaning they
could remain on schedule. The OptiCem simulations with twenty-one centralizers in place
showed that the channeling and gas flow would be less severe.
224. An email from shore-based BP Operations Vice President Brett Cocales to
rig-based BP drilling engineer Brian Morel acknowledged the importance of centralizers, noting
that “[e]ven if the hole is perfectly straight, a straight piece of pipe even in tension will not seek
the perfect center of the hole unless it has something to centralize it.”
73 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 81 of 150
225. In an effort to minimize delay, BP workers and their supervisors decided to save
ten hours by only installing six centralizers instead of the recommended twenty-one and did not
adequately ensure the cement could contain the pressure of the well. As the Commission notes:
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.
Halliburton happened to find out that BP had run only six centralizers when one
of its cement engineers overheard a discussion on the rig.
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. To this day, BP witnesses
provide conflicting accounts as to what type of centralizers were actually sent to
the rig.
226. Even more egregious was BP’s decision not to conduct cement log evaluations
after the cementing was completed. BP concluded that the cementing was a success based solely
on the indication that there were no lost returns. In an effort to control costs, BP opted to send expert consultants home instead of allowing them to conduct their tests .
227. When the BP team leader learned of the decision to add more centralizers, he
challenged it. He was concerned that adding on forty-five additional pieces of equipment would take at least ten additional hours. The additional hours meant additional expenditures.
Ultimately, the team leader prevailed and BP installed only six centralizers on the production casing.
74 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 82 of 150
228. Upon learning of BP’s decision, Halliburton engineer Jesse Gagliano sought to
determine if six centralizers would be enough to prevent channeling that gaseous hydrocarbons
could seep through. Halliburton’s analysis concluded that 21 centralizers was the recommended
number to ensure a secure cement job; using ten would result in a “moderate” gas flow problem
and using only six would result in a “severe” gas flow problem. As stated previously, BP
employee, Brett Cocales, responded: “who cares, it’s done, end of story, will probably be
fine.”
3. Cement Fill and Cement Testing
229. During the lead up to the cement fill, BP’s first concern was in avoiding another
“lost returns” event. 66 This concern led them to place a number of significant constraints on the
cementing design submitted to them by Halliburton. First, BP limited the circulation of drilling
mud through the wellbore prior to cementing. Usually (and optimally), the mud in the wellbore
is circulated in “bottoms up” – bringing the mud originally at the bottom all the way to the top of
the rig. This both reduces the likelihood of channeling and allows technicians to examine the
mud from the bottom for hydrocarbon content prior to cementing the well. Therefore, BP
circulated approximately only 350 barrels of mud prior to cementing. To do a full “bottoms up”
circulation would have required 2,760.
66 A lost returns event occurs when the pressure being exerted inside the well exceeds the fracture gradient (the pressure the rock being drilled into can withstand without fracturing). Basically, this means the drilling mud is too heavy and causes the surrounding rock to crack.
Then, the mud, instead of reaching the bottom of the well and returning up the side (the
"annulus"), seeps out into the rock formation.
75 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 83 of 150
230. A “bottoms up” circulation cleans the well bore and prepares the annular space for
cementing by completely circulating the drilling fluids from the bottom of the well all the way to
the surface. A bottoms up circulation also ensures the removal of well cuttings and other debris
from the bottom of the well, preventing contamination of the cement, permits a controlled release
of gas pockets that may have entered the mud during the drilling process, and allows workers on
the drilling vessel to test the mud for influxes of gas. Given that gaseous hydrocarbons leaking
into the well was what ultimately caused the blowout, a bottoms up circulation could have
revealed the severity of the situation at Macondo before it was too late.
231. The American Petroleum Institute (“API”) guidelines recommend a full bottoms
up circulation between installing the casing and beginning a cementing job. According to his
sworn testimony before the House Subcommittee, Halliburton technical advisor Jesse Gagliano
told BP that Halliburton’s “recommendation and best practice was to at least circulate one 67 bottoms up on the well before doing a cement job.” Even BP’s own April 15, 2010 operations
plan for the Deepwater Horizon called for a full “bottoms up” procedure to “circulate at least one
(1) casing and drill pipe capacity, if hole conditions allow.”
232. But a full bottoms up circulation would have taken up to 12 hours on the
deep Macondo well, so against the recommendations of the API and Halliburton, and
against industry standards and its own operations plan, BP chose to save time and money
at the expense of safety.
233. Second, BP decided to pump cement down the well at a rate of four barrels or less
per minute. This is a relatively low rate of speed in the cementing process. Higher flow rates
67 House Subcommittee on Energy and Commerce, Transcribed Interview of Jessie Marc
Gagliano, at Pg. 57 (June 11, 2010).
76 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 84 of 150
increase the efficiency and effectiveness with which the cement replaces the mud in the annular
space. This decision was also made in order to reduce the risk of a lost returns event.
234. Third, BP limited the total volume of the cement which was pumped down the
well. Standard industry practice is to use more cement due to the inherently uncertain nature of
the cementing process. It also reduces risks which arise due to errors in placement. However,
more cement meant more pressure on the rock formation in the Pay Zone. Therefore, BP
determined that to exert as little pressure as possible, the annular cement column was only to
extend 500 feet above the hydrocarbon zone. While BP determined that this fulfilled federal
regulations (requiring 500 feet above the hydrocarbon zone), it did not satisfy BP’s own
internal guidelines . Those guidelines called for annular cement columns to extend 1,000 feet
above the hydrocarbon zone. BP planned to have Halliburton pump just 60 barrels of cement
down the well, an amount its own engineers recognized provided little margin for error .
235. Finally, BP chose to use “nitrogen foam cement.” This type of cement is leavened with bubbles of nitrogen gas, which are injected into the slurry just before it goes down the well.
The purpose of this decision, again was to lower the pressure exerted on the rock formation in
the Pay Zone by reducing the weight of the cement by more than ten percent.
236. While Halliburton worked with BP to design the cement plan, these compromises
were made at BP’s insistence. Importantly, the President’s Commission noted that while
“Halliburton is an industry leader in foam cementing,” BP has “little experience with foam 68 technology for cementing production casing in the Gulf of Mexico.”
68 Pres. Comm. Report, Pg. 100.
77 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 85 of 150
237. Also noteworthy were the failures to properly test the slurry and failures of
communication between BP and Halliburton about the test results. The first round of testing on the slurry occurred in February, just after the Deepwater Horizon began working on the well.
The “pilot tests” on the cement blend were sent to BP in early March and showed that the slurry
design was unstable. There is no indication that BP ever reviewed the tests, ever sought to alter
the slurry or questioned Halliburton about the cement design.
238. Internal documents show a second test was conducted in February which failed
even more severely than the original. Finally, a test was conducted by Halliburton starting on
April 18, 2010 at around 2:00 a.m. This test generally takes forty-eight hours to complete, but
the cement job was completed prior to the time when forty-eight hours would have elapsed. The
desire to act quickly and complete the drilling at the Macondo well took precedence over the
importance of gathering information about the stability and adequacy of the cement used in the
well. The final test results were reported to BP six days after the blowout occurred.
239. The final phase of cementing the well involves evaluating the cement job once the
crew believes it has been completed. As noted above, because of the inherent difficulty and
uncertainty of the process, there is virtually no way to determine the success of a cement job
while it is ongoing. Thus, it is vital to test and evaluate the well after the cement has had a
chance to cure. This is generally done both through a check to determine whether the valves are
closed and holding and through acoustics testing to analyze whether the cement has filled in and
attached to the walls of the casing and the rock layers at the edge of the well. 69
69 Just like a bell which is muffled sounds different than a free swinging one, the acoustics of a well which is fully cemented sound significantly different than a well prior to the cementing and one in which the cementing leaves gaps which hydrocarbons or other gases can enter and rise up the wellbore.
78 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 86 of 150
240. Once the pumpers were finished with the primary cement job, BP opened a valve
to check to determine if the float valves were closed and holding. BP expected about five barrels
of flow back. They experienced about five and a half barrels of flow back, which then reduced to
a “finger tip trickle.” This extra half barrel was decided to be within the acceptable margin for
error. The flow reduced to a “pencil stream,” stopped, started and then stopped altogether. On
the basis of this observation, BP determined that the float valves were closed.
241. Normally, the next step would involve a team of technicians from an outside
company to perform “a suite of cement evaluation tests on the primary cement job, including 70 cement bond logs.” These technicians had been on standby on the rig, waiting for the
completion of the primary cement job for at least one day. BP decided that the testing was
unnecessary, called the job a “success” based on the lack of lost returns and the flow-back
analysis and sent the testing team home. This decision was based on an internal “decision-tree”
which had been prepared by BP before the testing began. The primary criteria on that tree was
whether there had been losses while cementing the long string production casing. BP then began
to prepare for temporary abandonment.
242. Even more egregious was BP’s decision not to conduct cement log evaluations
after the cementing was completed. BP concluded that the cementing was a success based solely 71 on the indication that there were no lost returns. In an effort to control costs, BP opted to send expert consultants home instead of allowing them to conduct their tests .
70 Pres Comm. Report, Pg. 102.
71 Importantly, even this may have been an errant conclusion. As noted above, there was more displacement by a half barrel than was expected, but it was concluded on the spot that this was acceptable and within the margin of error.
79 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 87 of 150
243. BP’s own internal report on the explosion indicates that the evaluation logs should
have been conducted. These logs could have helped to confirm numerous factors which were
otherwise unknowable, including the location of the cement, whether channeling had occurred,
whether the cement had been contaminated, and whether the cement had remained stable.
244. According to testimony before the House Subcommittee on Energy and
Commerce, by avoiding the bond log, BP saved $128,000 and less than 12 hours of work .
4. Testing Leading Up To Temporary Abandonment
245. There were two important tests to be performed during the temporary
abandonment process – the positive pressure test and the negative pressure test. The positive test
evaluates the ability of the casing in the well to hold in pressure. Federal regulations require this
test to be performed prior to abandonment. The crew performed this test by closing the well
below the BOP and pumping in fluids to generate pressure and then checking to see if the well
would hold. BP performed two positive pressure tests, one at 250 psi for five minutes and one at
2,500 psi for thirty minutes. Both tests were successful – there were no leaks through which
fluid was passing from inside the well to the outside.
246. The negative pressure test is designed to check both the integrity of the casing
(like the positive test) and the integrity of the cement job at the bottom of the well. This was the
only test designed to check the bottom hole cement job at the Macondo well. The negative
pressure test is performed by removing pressure from inside the well to see if fluids
(hydrocarbons from the Pay Zone) leak into the well through the bottom hole cement job. This is
done by removing the fluids and the riser, which eliminates the “overbalancing” pressure. This
simulates the absence of pressure which occurs during temporary abandonment. It is a three step
process involving simulating the hydrostatic pressure exerted by the column of fluids on the
80 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 88 of 150
bottom of the well, bleeding any pent up pressure from the well making the pressure inside the
casing zero psi, and finally watching to see if anything flows into the well and determine whether
pressure builds back up inside the well. If there is no fluid or pressure entering the well, the
negative pressure test is considered successful.
247. To conduct the negative pressure test, BP needed to lower the pressure bottom of
the well by approximately 2,350 psi. The result would be that the pressure pushing up on the
bottom of the well from the Pay Zone would exceed the pressure pushing down on the bottom
from the column of fluid in the well. This creates an “unbalanced” state. In preparing for the
test, BP used a “spacer,” a liquid mixture which separates the heavy drilling fluids from the much
lighter seawater.
248. Instead of using a normal spacer, BP used leftover unused lost circulation
materials or pills in order to avoid having to dispose of them onshore as hazardous waste. These
materials had never previously been used by anyone on the rig or by BP as a spacer and had
not been tested for the purpose that BP was employing it for.
249. The crew then began to reduce the pressure in the drill pipe in an attempt to bleed
it down to zero. This requires closing off the “annular preventer” inside the BOP to isolate the
well from the downward pressure exerted by the mud and spacer in the riser. However, they
could not get it below 266 psi and as soon as the pipe was closed, the pressure jumped up to
1,262 psi.
250. The crew noticed that the fluid level inside the riser was dropping, indicating that
the annular preventer was not sealed. Once it was closed more tightly the leak stopped and the
pressure was reduced inside the well to zero psi. However, after the drill pipe was again closed
the pressure built back up to at least 773 psi. A third attempt again managed to reduce the
81 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 89 of 150
pressure to zero psi, but when the pipe was sealed the pressure built back up to approximately
1,400 psi.
251. At this point, there had been three failed negative pressure tests at Macondo.
However, BP concocted an explanation for the pressure build ups which would allow them to
consider the tests successful. According to BP, the pressure buildup was the result of a “bladder
effect.” This is caused by the heavy mud in the riser exerting pressure on the annular preventer 72 which in turn transmits pressure to the drill pipe.
252. In order to attempt to confirm this theory, and because BP had specified in its 73 application that it would do so, BP performed a negative pressure test on the “kill line.” The
crew bled the pressure in the kill line to zero and sealed it. It held for thirty minutes. In theory,
the pressure in the kill line and the drill pipe during an negative pressure test (and during
subsequent abandonment) would be identical because both flow paths went to the same place.
However, during this test on the kill line, the pressure on the drill pipe remained at 1,400 psi
throughout.
253. While the “bladder effect” was proposed as an explanation for this, based on the
1,400 psi reading on the drill pipe “ could only have been caused by a leak into the well. ”74
Despite this, the BP team concluded that the second test had confirmed the well’s integrity and
declared the negative pressure tests a success. This was a key error and a mistaken conclusion. 75
72 Pres. Comm. Report, Pg. 108.
73 The “kill line” is one of three pipes which are three inches in diameter from the rig to
the BOP to allow the crew to circulate fluids into and out of the well at the sea floor.
74 Pres Comm. Report, Pg. 108-109.
75 Pres Comm. Report, Pg. 109.
82 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 90 of 150
254. In May 2010, BP admitted that these pressure test results were clear warning signs
of a “very large abnormality” in the well. 76
255. In their November 16, 2010, interim report, the NAE panel wrote that “it is clear
that pressure buildup or flow out of a well is an irrefutable sign that the cement did not establish
a flow barrier” against the entry of hydrocarbons into the well. At Macondo, there was both
pressure buildup to 1400 psi and unexpected flow out of the well during the negative pressure
tests.
256. Despite the pressure test “red flags,” BP moved forward with the temporary
abandonment process, which resulted in an unnoticed kick, a blowout and eventually the
explosion that sank the Deepwater Horizon resulted in the death of eleven crew members and the
subsequent oil spill in the Gulf of Mexico.
5. Temporary Abandonment Procedures At The Macondo Well
257. BP’s procedures leading up to temporary abandonment involved three important
decisions.
258. First, BP concluded that it would set the cement plug on the top of the production
casing nearly 3,300 feet below the sea floor. This was done in order to in order to allow BP to
hang 3,000 feet of drill pipe from the top of the well in order to create enough pressure to set the 77 lockdown sleeve. There was no reason other than the desire to generate force by hanging drill
76 House Subcommittee on Energy and Commerce Memorandum, Key Questions Arising from Inquiry in the Deepwater Horizon Gulf of Mexico (May 25, 2010); Stephen Power, BP
Cites Crucial Mistake, (Wall Street Journal, May 25, 2010).
77 The Lockdown Sleeve goes over the top of the well and is one of the final safety
mechanisms involved in temporary abandonment. BP chose to set the lockdown sleeve last in
the temporary abandonment sequence. They never reached this step. Setting the sleeve required
100,000 pounds of force, most of which BP intended to generate by hanging the drill pipe from
83 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 91 of 150
pipe that BP identified as the purpose of setting the cement plug so far below the sea floor.
Additionally, BP could have achieved this goal by using heavier drill pipe and setting the cement
plug 1,300 feet below the sea floor.
259. Second, BP decided to displace the 3,300 feet of mud above where the cement
plug would be set with sea water. This greatly reduced the amount of pressure above the well
because the water was significantly lighter than the mud. This was done because it is simpler to
set plugs in sea water and can avoid mud contamination. However, BP has acknowledged that a
cement plug can be set in mud, and there is no evidence that BP or any other operator had ever
set a cement plug so deep in sea water.
260. Third, BP decided to begin displacement of the mud from the riser before the
cement plug (or some other barrier) had been set in the production casing. This meant that
during the displacement of the riser, while the BOP was open and before the cement plug was set
at the top of the production casing, the only barrier between the Pay Zone and the rig was the
primary cement job at the bottom of the well.
261. Each of the temporary abandonment decisions made by BP substantially increased
the risks in an already unnecessarily risky situation. The Presidential Commission concluded that
it was neither necessary nor advisable for BP to replace 3,300 feet of mud with sea water. This
increased the stress on the cement job at the bottom of the well. There were numerous options
involving the use of non-cement plugs, setting the cement plug in mud and setting the cement
plug in water closer to the sea floor which would have exerted less stress on the cement job at the
bottom of the well. There is no evidence that any of these options were even considered .
the bottom.
84 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 92 of 150
262. Further, it was not necessary to set the cement plug so far below the sea floor.
Additionally, the BP employee in charge of lockdown sleeves in the Gulf of Mexico had
recommended using heavier more costly piping and placing the plug only 1,300 feet below the
sea floor. This would have greatly increased the margin of safety for the well.
263. The decision by BP to displace the mud from the riser before setting another
barrier dramatically increased the risk of a blowout. According to a 60 Minutes report, based on
interviews with a survivor of the Deepwater Horizon and the government’s expert tasked with
investigating the Deepwater Horizon disaster, BP issued orders that greatly heightened the risk of
a disaster. These orders were issued by senior BP managers. BP knew that it was operating in a
dangerous formation in which extra safety precautions were required, not less. Immediately
before the disaster, BP ordered that the drillers begin extracting the mud from the well before all
of the concrete plugs were put into place. This would speed up the process but meant that
pressure in the well would be highly unstable. According to engineering expert Robert Bea, if
the mud had been left in place, the Deepwater Horizon accident would likely not have occurred.
264. Nevertheless, with a broken blowout preventer, BP ordered a dangerous
procedure to be performed that jeopardized the workers on the Deepwater Horizon, the public
and the environment. This directive was given by BP in order to save money. The results were
catastrophic.
265. Finally, and most troubling, the decision to displace the riser prior to setting other
barriers, including the cement plug, meant that only the primary cement job was between the Pay
Zone and the rig. The result of this decision was that the only well safety guarantees were based
on a faulty negative pressure test and well monitoring during displacement. As discussed, the
85 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 93 of 150
pressure test failed and the human monitoring failed to detect the kick and subsequent blowout
until it was too late.
266. These decisions reflect both a lack of attention to safety measures and a total lack
of systematic procedures and protocols to govern how those decisions are made. There is no
evidence that BP considered alternatives, weighed safety concerns, evaluated risks or sought to
come up with an abandonment plan to which would have avoided or reduced the likelihood of a
blowout.
6. Failure to Detect the Kick
267. Once BP had determined the well was secure and could move forward with
temporary abandonment, they began displacing mud and spacer from the riser. Perhaps the most
important task at this point was to monitor the well, through a slew of technical and video
apparatus, for any unplanned influxes of gas, fluid or other anomalies which would provide an
indication of a “kick.”
268. Early detection of kicks is vital as once indications of gaseous hydrocarbons rising
up the wellbore become apparent, action must be taken quickly and decisively to avoid or limit
the impact of the kick. As the hydrocarbons rise, they expand with ever increasing speed – a
barrel of gas at the Macondo well could expand over a hundred times as it traveled the one mile
between the wellhead and the rig.
269. Crews monitor flow rates, and real time data measuring the volume of mud in the 78 “active pits.” Crews additionally perform visual checks through a number of cameras to
78 The Active Pit System is a series of mud pits (twenty in the case of the Deepwater
Horizon) where fluids can be stored. It is a subset of pits that the driller selects for monitoring purposes.
86 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 94 of 150
determine whether fluids are flowing out of the well. Finally, the crews monitor drill pipe
pressure as a tangential measure indications of kicks. Unexplained changes in drill pipe pressure
are red flags that may indicate a kick and need to be investigated when they occur.
270. Just after 8:00 p.m. the crew began displacing the riser. For an hour, things were
uneventful. However, drill-pipe pressure began increasing just after 9:00 p.m. in an unexpected
and unexplained way. One possible explanation was the beginning of a kick due to hydrocarbons
flowing into the well. This pressure change was not noticed or investigated. At 9:30 p.m. there
was an unexpected pressure difference between the drill pipe and the kill line. In response to this
mounting pressure the crew took action to reduce it and equalize the pressures. However,
nobody performed a visual flow check or shut down the well.
271. Ten minutes later, mud began spewing onto the rig floor. This was the first time
that the crew realized a massive kick had occurred. Action was taken to attempt to reduce the
impact of the kick but the gas was already above the BOP, expanding rapidly as it shot up the
riser. This made an explosion all but inevitable.
272. The Presidential Commission offered three possible explanations for why the
crew did not activate the BOP in time. First, that they did not recognize the severity of the
situation, which seems unlikely given the amount of mud spewing onto the rig; second, that there
simply was not time to act given that the explosion occurred just six minutes after mud emerged
on the rig floor; or third, and most significantly, “the crew had not been trained adequately
how to respond to such an emergency situation .”
7. Failure of the Blowout Preventer
273. The BOP has a series of arms and valves which are designed to seal a well in the
event of an emergency. After the tardy detection of the kick, the BOP was the last resort in
87 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 95 of 150
preventing or lessening the power, force and ultimately the duration of the explosion and
disaster. The crews activated two systems on the BOP just after mud began spewing on the rig
deck. The flow rates coming up the well at this point were likely too high for either of these
systems to seal the well and reduce the likelihood or impact of explosion. Earlier kick detection
could have helped to increase the odds of successfully shutting down the well.
274. After the first explosion, the crew attempted to engage the Emergency Disconnect
System (“EDS”) to sever the drill pipe, seal the well and disconnect the rig. None of this was
successful. This could have been because the initial explosion damaged the BOP preventing the
EDS system from operating properly. Even after this failure, the “deadman” system on the BOP
should have activated. However, there was no power from the rig to the BOP and the last back
up system failed. The Presidential Commission determined that this may have been due to poor
maintenance. Post-incident testing revealed that the “pods” which control the system had very
low battery charges and defective valves. If those problems existed prior to the blowout they
would have prevented the system from working. According to engineering expert Robert Bea,
the malfunctioning of a control pod is like “losing one of your legs.”
275. Importantly, the BOP on the Deepwater Horizon had been significantly modified
by BP. The system was purchased by Transocean in 2001. Subsequently, BP approved
modifications to the BOP despite being warned that it would reduce the safety and effectiveness
of the BOP. In 2004, Transocean sent a letter to BP about those modifications. BP signed and
acknowledged receipt of that letter at the time. The letter indicates that BP acknowledges that
88 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 96 of 150
the conversions it asked for will reduce the built-in redundancy of the BOP and potentially
increase the risk profile. 79
276. Once the BOP failed, there was no way to stop the fire, explosions or leak which
was shooting gas up the well “like a freight train.”
4. DEEPWATER HORIZON EXPLOSION
277. As detailed above, the blowout was the result of several individual missteps and
oversights. When the Deepwater Horizon rig arrived at the Macondo field, the drilling of the
Macondo well already was facing delays and cost overruns after a previous rig, the Marianas, was damaged by a hurricane in the previous fall.
278. Every dollar counted to BP and the Horizon was drilling as fast as it could. Mike
Williams (the rig’s chief electronic technician) explained on CBS’s 60 Minutes that he was
ordered by a BP manager to “bump it up; and what he was talking about there is he’s bumping up
the rate of penetration – how fast the drill bit is going down.” According to Williams, the efforts
to drill too fast caused the base of the well to split open causing a two week delay and costing BP
millions of dollars. Williams stated in response to whether the delay caused added pressure, 80 “There’s always pressure, but yes, the pressure was increased.”
279. By April 20, 2010, the Macondo project was $55 million over budget, leading to 81 tremendous corporate top-down pressure to finish the job and minimize the cost overruns.
79 Role of BP in Deepwater Horizon Explosion and Oil Spill, hearing before the
Subcommittee on Oversight and Investigations, 6/17/10, pages 206-207.
80 Sally Granastein, et al., Blowout: The Deepwater Horizon Disaster, 60 Minutes, New
York: CBS Productions.
81 Joe Carroll, BP Well Was 61% Over Budget Before Drilling-Rig Blast (Bloomberg,
October 6, 2010).
89 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 97 of 150
280. The immediate cause of the explosion was the failure to contain hydrocarbon
pressures inside the well. There were three primary ways to contain those pressures: the cement
at the bottom of the well, the mud in the well and in the riser, and the BOP. However, failures to
appreciate risks and compromises in the process of finalizing the well and preparing for
temporary abandonment greatly reduced the ability of each of those potential barriers. By
steadily depriving the rig crew of safeguards (and the failures in implementing what safeguards
remained), the blowout became an inevitability that turned out to be uncontrollable.
281. In combination, the Presidential Commission concluded, there is “nothing to
suggest that BP’s engineering team conducted a formal, disciplined analysis of the combined 82 impact of these risk factors on the prospects of a successful cement job.”
282. BP’s culture of profits over safety and the pressure to get the Macondo drilling
project done caused workers on the Horizon to make a number of decisions that increased the
risk of an accident. As detailed below, to avoid additional delays and cost overruns, BP workers
at the Horizon did not test the well for a build-up of pressure before starting the process of
capping it with cement.
283. Finally, it is also apparent that there were very few, if any, individual crew
members who were in a position to understand or know of the multitude of risk factors which led
up to the explosion. BP’s failure to coordinate and communicate among different persons and
groups who were performing different, yet related tasks, contributed to risk of disaster.
284. Because there was little coordination, there was little reason for any one person to
suspect that the smaller individual causes would eventually result in an epic disaster. While no
82 Pres Comm Report, Pg. 118.
90 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 98 of 150
singular decision, whether it be the failure to evaluate cement composition or the failed negative
pressure test, or the decision to use a long string rather than a liner alone caused the well blow
out, none of the decisions were consistent with good safety process.
285. According to a confidential expert witnesses on oil rig operational safety and a
former consultant to the BP Board of Directors, (“CW1"), there was a company failure to
implement an appropriate Operations Management Safety protocol which would have ensured
that the individual decision makers at the rig level understood how cost-savings and corner-
cutting could effect the process safety of the Horizon.
286. BP’s failure to plan for a major accident was confirmed by Tony Hayward: “What
is undoubtedly true is that we did not have the tools you would want in your tool kit,” and it was
“an entirely fair criticism” to say the company had not been fully prepared for a deep-water oil
leak.83
G. INTERNAL DOCUMENTS AND TESTIMONY CONFIRM BP CONCEALED
COST-CUTTING RISKING LIVES AND THE ENVIRONMENT
287. Prior to the Deepwater Horizon explosion, internal BP emails revealed mounting
safety worries and managers obsessed with hitting their performance targets, which determined
their bonuses as well as the top down mandate to continually cut costs.
288. According to a June 29, 2010 Wall Street Journal investigation, under Neil Shaw,
the former head of the Gulf of Mexico Operations, bonuses for top managers and low level
workers alike. The engineer said even small costs, like food at lunch meetings got targeted. 84
83 Ed Crooks, BP 'not prepared' for deep-water spill (Financial Times, June 2, 2010).
84 Guy Chazan, et al., “As CEO Hayward Remade BP, Safety, Cost Drives Clashed ,”
(Wall Street Journal, June 29, 2010).
91 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 99 of 150
289. In May 2008, Shaw communicated to his Gulf of Mexico staff that efficiency was
improving in the drilling and completing of wells. According to the Wall Street Journal, Shaw
cited that the number of days it took to drill 10,000 feet was 6% below plan. Idle time had fallen
to 24% of total rig days, from 34% in 2007. In May 2009, he said in another memo that BP’s
output in the Gulf had reached a record 500,000 barrels a day, a year ahead of schedule.
290. According to an internal presentation on Gulf drilling performance dated
April 13, 2010, a week before the Deepwater Horizon explosion, BP’s estimate for 2010 capital
spending on wells in the Gulf fell by $221 million to $2.03 billion. 85
291. However, at the same time capital spending decreased and drilling completion
increased, so did safety incidents. For example, according to August 2009 safety steering
committee minutes, the “Total Recordable Incident Rate,” which normally measured incidents
for every 200,000 man-hours worked was higher than it should be. The rate was 0.97 for the
Gulf drilling unit, over the target of 0.62.
292. In a March 2010 strategy update for investors, BP publicly stated it sought to cut
$500 million from its drilling operations by improving efficiency. Contemporaneously, internal
BP emails from late March 2010 depicted drilling techniques in the Gulf selected because they
would “save[] a lot of time . . . at least 3 days,” “saves a good deal of time/money,” and is the 86 “[b]est economic case.”
85 Id.
86 Email from Brian Morel, BP Drilling Engineer, to Allison Crane, Materials
Management Coordinator, March 25, 2010; Email from Brian Morel, BP Drilling Engineer, to
Sarah Dobbs, Completion Engineer, March 30, 2010.
92 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 100 of 150
293. While BP was representing to investors that it could safely chop hundreds of
millions of dollars from its drilling operations, emails just weeks before the Deepwater Horizon
blowout demonstrated the problems BP employees were facing at the Macondo well which was
identified as a “crazy,” and “nightmare” well.
294. At the time of the blowout, drilling at Macondo was already months behind
schedule, costing BP over $1 million per day in vessel lease and contractor fees and putting them
increasingly over budget. The Deepwater Horizon was tens of millions of dollars over budget.
This excess cost put the Macondo project in conflict with BP’s mandate for 7% reductions in 87 costs for all of its drilling operations in the Gulf of Mexico. In spite of the difficulties and
dangers of drilling in the Gulf and related to Macondo specifically, BP made multiple decisions
about the drilling plan for economic reasons, even though those decisions increased the risk of
the catastrophic failure of the “nightmare” well, and were contrary to representations made to the
investing public.
295. After investigating the disaster, Prof. Robert Bea, an oil industry expert leading
the Deepwater Horizon Study Group, wrote: “Pressures to complete the well as soon as possible
and minimize costs as much as possible are evident in the cascade of decisions and choices that
led to the blowout.”
296. According to BP’s own internal reporting, decisions on the Macondo “appear to
have been made by the BP Macondo team in ad hoc fashion without any formal risk analysis or
internal expert review . . . This appears to have been a key casual factor to the blowout.”
87 Transcript of Testimony before the Joint United States Coast Guard/Bureau of Ocean
Energy Management Investigation, Pg. 58 (December 8, 2010).
93 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 101 of 150
297. Just days before the Macondo well blast, the onshore BP plc manager in charge of
the drilling rig warned his supervisor that last-minute procedural changes were creating “chaos”
on the rig. Alexander John Guide , who directed the Deepwater Horizon’s operations from BP’s
Houston offices, wrote in an email, “The operation is not going to succeed if we continue in this
manner.” Guide’s supervisor, David Sims, responded to Guide by telling him to tell the rig
workers “to hang in there.” Sims signed off the email by saying he was attending dance practice and promised to call the next day.
298. In a follow-up email, Guide wrote, “I totally concur, I told them all we will work 88 through it together. I want to do better.” Three days later the Deepwater Horizon exploded.
299. Fred Bartlit, the general counsel for the Presidential Commission, said Guide’s
email “further confirms the commission’s finding that BP poorly managed last-minute design and procedural changes at Macondo.”
300. Contrary to its public statements, this chaos was caused by BP’s failure to have a
system(s) place that would insure the gulf drilling could be done in a safe environment. For
example, on April 17, Guide sent an email to Sims complaining that “there has been so many last
minute changes to the operation” and that the rig’s on-board managers had “finally come to their
wits end.” Sims replied to Guide saying the team working on the well should stay positive “until this well is over.”
301. Additionally, BP: (1) consciously elected not to install an acoustically activated
remote-control shut-off valve, costing only $500,000, to the well and (2) chose not to install a
deep-water valve that would have been placed about 200 feet under the sea floor. BP ignored
88 Ben Casselman, et al., Shifting Procedures Upset BP’s Rig Team (Wall Street Journal,
Jan. 29, 2011).
94 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 102 of 150
these precautions despite being well aware of the increased risk of a failure of the primary
blowout safety mechanism, the blowout preventer, from deep-sea operators. 89
302. Moreover, BP should have known the importance of a fully functioning blowout
preventer. According to a 2004 study by federal regulators showed that blowout preventers may
not function in deepwater drilling environments because of the increased force needed to pinch
and cut the stronger pipes necessary to drill at such great depths. Additionally, over ten years
ago, the MMS sent out an industry-wide safety alert ordering companies drilling in deep water in
the outer continental shelf to have effective backup systems. The March 2000 notice stated: “The
MMS considers a backup [blowout preventer] actuation system to be an essential component of a
deepwater drilling system, and therefore expects OCS operators to have reliable back-up systems
for actuating the [blowout preventer].”
303. MMS, however, left it up to the individual companies to decide what kind of
backup system to use. BP chose the cheapest method, electing not have a backup system for
activating the blowout preventer on the Deepwater Horizon.
304. While, BP publicly represented it had implemented systematic changes to its
safety processes, those representations do not comport with the actions taken on the Deepwater
Horizon which demonstrate a company that when faced with the choice of a cheaper and quicker
or safer, chose the cheaper and quicker every time.
305. For example, according to the NAE and Presidential Commission, gas and fire
detection sensors and the shutoff systems were not operating in the engine room of the
89 Russell Gold, et al., Leaking Oil Well Lacked Safeguard Device (Wall Street Journal,
April 28, 2010).
95 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 103 of 150
Deepwater Horizon. According to BP’s own internal reporting, these same important pieces of
safety equipment were lacking at BP facilities as far back as 2001.
306. BP repeatedly ignored warnings from their own employees and contractors on the
Deepwater Horizon, all in order to reduce costs and save time on the behind-schedule and
over-budget Macondo well. Testimony of employees and documents referenced above highlight
the time pressure BP was putting on workers as it rushed them to finish quickly so the well could
be sealed and BP could begin extracting oil and move the Horizon to the next Gulf of Mexico
lease.
307. This emphasis on speed and cost savings over safety led to actions that were
contrary to BP’s public representations of safety as BP’s No. 1 priority during the Subclass
period but is consistent with BP’s 2009 spending 0.0033 percent of its revenues on research and
development regarding safer offshore drilling technologies.
1. DEEPWATER HORIZON’S TATTERED SAFETY AND MAINTENANCE
RECORD
308. The Deepwater Horizon was leased to BP for drilling exploratory wells at the
Macondo prospect site, pursuant to the December 9, 1998, Drilling Contract between Transocean
and BP.90
309. Prior to the Spill, BP was on notice that Transocean’s safety performance during
offshore drilling operations was deficient. Transocean CEO Steven L. Newman admitted prior to
90 The parties to the 1998 Drilling Contract, Vastar Resources, Inc. and R&B Falcon
Drilling Co., are now BP and Transocean entities, respectively. The Deepwater Horizon,
formerly known as RBS-8D, was in the process of being built for R&B Falcon Corp. between
1998 and 2001, during which time Transocean purchased R&B Falcon Corp. Upon completion,
the Deepwater Horizon was delivered to Transocean. BP America is a successor-in-interest to
Vastar Resources, Inc. Amendments to the Drilling Contract were subsequently signed by
representatives of Transocean and BP.
96 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 104 of 150
91 the Spill that “we have to improve our safety performance.” Just a month before the Spill, in
response to “a series of serious accidents and near-hits within the global organization,”
Transocean commissioned a broad review of the safety culture of its North American operations,
including the Deepwater Horizon.
310. In September 2009, a BP audit team concluded an audit of Deepwater Horizon and found excessive overdue maintenance, totaling 390 separate jobs and 3,545 man hours.
Many were deemed high priority. Thirty-one jobs included findings that were related to well
control system maintenance, six related to BOP maintenance, and additional problems were
noted related to the electronic alarm systems, ballast systems used to stabilize the vessel in the
water, and other significant deficiencies that could “lead to loss of life, serious injury or 92 environmental damage as a result of inadequate use and/or failure of equipment.” All findings
were outstanding as of December 2009. This audit was or should have been known to
Defendants but was concealed from Plaintiffs.
311. The audit also expressed concern for the safety culture on the rig: “An annual
health and safety plan was not in place although a number of safety goals were listed, but they were not commonly known and not widely communicated.” 93
91 Clifford Krauss and Tom Zeller Jr., A Behind-The-Scenes Firm in the Spotlight , (NY
Times, Mary 24, 2010).
92 CBS News: Report: Oil Rig Co. Had Issues at 3 More Wells, (Aug. 5, 2010).
93 Danny Fortson, BP’s Deepwater Horizon had history of shortcomings , (The
Australian, Aug. 9, 2010).
97 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 105 of 150
312. In a glaring example of BP’s reckless disregard for safety, BP’s regional mitigation plan was cut and pasted from a mitigation plan developed for drilling in Alaska, and
listed a long-deceased expert as the person to be contacted in the event of an emergency.
2. PRESIDENTIAL COMMISSION FINDS BP LACKED SUFFICIENT
SAFETY PROCESSES AND IMPROPERLY ELEVATED PROFITS OVER
SAFETY
313. A key finding of the Commission was that BP repeatedly placed profits over
safety, implementing procedures that greatly increased risk, primarily in order to avoid the expense of delay. 94
314. In relevant part:
Decisionmaking processes at Macondo did not adequately ensure that personnel fully considered risks created by time– and money– saving decisions .
There is nothing inherently wrong with choosing a less-costly or
less-time-consuming alternative—as long as it proves 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 [] decisions in Figure 4.10 appear to have been subject to
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.
94 Pres. Comm. Report, Pg. 125, Figure 4.10: Examples of Decisions That Increased Risk at Macondo While Potentially Saving Time.
98 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 106 of 150
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 cost savings.
* * *
Of course, some decisions will have shorter timelines than others, and a
full-blown peer reviewed 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.
99 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 107 of 150
315. While BP claimed in its public filings and public statements that it had sufficient
safety processes and systems the Presidential Commission, after six months of analysis
concluded that BP lacked sufficient safety processes and systems and repeatedly placed profits over safety.
316. The Commission further determined that the Macondo well explosion was fundamentally based on a failure of management and safety process.
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 peer review process and changes to well
design are subsequently subject to a management of change (MOC) process,
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 fashion
without any formal risk analysis or internal expert review. 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.
100 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 108 of 150
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. It does not appear that the changes to the temporary
abandonment procedures went through any sort of formal review at all.
317. In sum, BP had no competent system or policy in place that would assist
employees at the rig level with decision making in emergency situations. There was no effective risk management. There was no emphasis on safety processes.
3. GOVERNMENTAL TESTIMONY CONFIRMS BP’S CONCEALED
CORPORATE ETHOS OF PROFITS OVER SAFETY
318. The House of Representatives Subcommittee on Oversight and Investigations,
Committee on Energy and Commerce investigated the causes of the Deepwater Horizon disaster.
The subcommittee reviewed tens of thousand of internal BP documents, conducted
numerous interviews and received tens of hours of briefings by corporate, governmental, and academic experts .
319. After this investigation, Chairman Waxman stated “[t]hey [internal BP
documents] appear to show that BP repeatedly took shortcuts that endangered lives and increased
the risks of a catastrophic blowout.”
When you became CEO of BP, you promised to focus “like a laser on safe and
reliable operations.” We wanted to know what you had done to keep this promise,
so we asked what emails you had received, what documents you had reviewed
about the Deepwater Horizon rig or the Macondo well before the blowout.
Deepwater drilling is inherently dangerous. As the entire country now knows, an uncontrolled blowout can kill rig workers and cause an environmental disaster.
We wanted to know whether you were briefed about the risks and were monitoring
the safety of the drilling operation.
We could find no evidence that you paid any attention to the tremendous risks
BP was taking. We have reviewed 30,000 pages of documents from BP,
including your emails. There is not a single email or document that shows you
paid even the slightest attention to the dangers at this well.
101 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 109 of 150
You are the CEO, so we considered the possibility that you may have delegated the
oversight responsibility to someone else. We reviewed the emails and briefing
documents received by Andy Inglis, the chief executive for exploration and
production, and Doug Suttles, the chief operating officer for exploration and
production and the person now leading BP's response to the spill.
According to BP, these are the senior officials who were responsible for the
Macondo well. But they, too, were apparently oblivious to what was
happening. We can find no evidence that either of them received any emails or
briefings about the Deepwater Horizon rig or drilling activities at the well.
BP's corporate complacency is astonishing . * * *
The drilling engineer for the rig called Macondo a “nightmare well.” Other BP
employees predicted that the cement job would fail. Halliburton warned of a
“SEVERE gas flow problem.” These warnings fell on deaf ears .
BP’s corporate attitude may be best summed up in an email from its operations
drilling engineer who oversaw BP's team of drilling engineers. After learning of
the risks and BP's decision to ignore them, he wrote, quote, “Who cares, it’s done,
end of story, will probably be fine,” end quote.
There is a complete contradiction between BP's words and deeds . You were
brought in to make safety the top priority of BP, but under your leadership, BP has
taken the most extreme risks. BP cut corner after corner to save a million
dollars here, a few hours or days there, and now the whole gulf coast is paying
the price.
320. Chairman Stupak, in an attempt to piece together what went wrong with BP’s
exploration of the Macondo well offered the following statement: “I am concerned that the
corporate culture , from BP CEO Tony Hayward down to Chairman and President of BP
America Lamar McKay, and Chief Operating Officer Doug Suttles and possibly down to the 95 leadership on exploration rigs reflects a willingness to cut costs and take greater risks.”
321. Congressperson Shakowsky: “As the ongoing investigation by this committee has
already discovered, BP executives created an atmosphere where safety concerns were ignored
95 House Subcommittee on Energy and Commerce, Rep. Bart Stupak Opening Statement
(June 17, 2010).
102 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 110 of 150
in order to ensure that the company's already staggering profits this year, approximately $93
million a day in the first quarter, continued unabated. This appalling disregard for the Gulf Coast
and its inhabitants is without question one of the most shameful acts by a corporation in American
history.96
322. Congressman Welch: “And the question I think many of us have is
whether a CEO who has presided over a company that has incurred $370 million in criminal fines;
whose company, according to independent assessors, has one of the worst records in the world for
safety and consistently puts money ahead of safety; whose peers, including Mr. Tillerson from
Exxon Mobil, who testified from where you are 2 days ago they never – Exxon never would
have drilled a well the way it did at BP Deepwater Horizon ; and who, as CEO, has presided
over the destruction of nearly $100 billion in shareholder value and the suspension of an annual
$10 billion dividend; does that leader continue to enjoy and have a valid claim on the trust and
confidence of his employees, his shareholders, the public regulators and, most importantly, the
families and small businesses of the Gulf Coast, or is it time, frankly, for that CEO to consider to 97 submit his resignation”
323. Congressman Sullivan: I would say that this problem is with your organization
and your safety and the culture of your company’s safety culture , and not a culture of our
domestic oil and gas producers. As we can see, they haven't had the kind of problems you have
had with cutting corners on safety . They have a lot of redundancies, contingency plans. I
96 House Subcommittee on Energy and Commerce, The Role of BP in the Deepwater
Horizon Explosion and Oil Spill, at Pg. 39 (June 17, 2010).
97 Id. at 52-53.
103 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 111 of 150
venture to say that this may not have happened if one of these other companies was operating that rig.98
324. The following exchange between Congressman Sutton and Hayward is telling as to
the Congressional findings regarding BP’s public representations of commitment to safety and its concealed efforts to cut costs at the expense of safety.
Congressman Sutton: You talked about the importance of safety and the
environment, but you presided over a corporate culture where safety and
risks and risks to the environment were ignored in order to save a few days
and a few dollars in drilling costs . If you are the leader of the company, don't
you have to take responsibility?
Mr. Hayward: I am absolutely responsible for the safety and reliable
operations in BP. That is what I have said all along.
325. Congressman Stupak:
“Time after time, BP had warning signs that this was, as one employee put it, a ‘nightmare well.’” BP made choices that set safety aside in exchange for cost-
cutting and time-saving decisions .
For example: BP disregarded questionable results from pressure tests after
cementing in the well.
BP selected the riskier of two options for their well design. They could have hung
a liner from the lower end of the casing already in the well and install a tieback on
the top of the liner, which would have provided additional barriers to the release of
hydrocarbons. Instead, they lowered a full string of new casing, which took less
time and cost less but did not provide the same protection against escaping
hydrocarbons.
BP was warned by their cement contractor Halliburton that the well could have a
“SEVERE gas flow problem” if BP lowered the final string of casing with only six
centralizers instead of the 21 Halliburton recommended. BP rejected Halliburton’s
advice to use additional centralizers. In an email on April 16th, a BP official
involved in the decision explained, and I quote, "It will take 10 hours to install
them. I do not like this," end of quote. BP chose not to fully circulate the mud in
98 Id. at 89.
104 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 112 of 150
the well from the bottom to the top, which was an industry-recommended best
practice that would have allowed them to test for gas in the mud.
BP chose not to use a casing hanger lockdown sleeve, which would have provided
extra protection against a blowout from below.
326. Internal BP documents produced to Congress confirmed that BP put
costs ahead of safety. “ Because we have also talked about some documents that the
committee has unearthed, and document after document that indicated that BP officials in
charge of the Deepwater Horizon were focused on saving time and money – for example, the
document that says that the well design was chosen because it would save $7 million to $10
million” according to Congressman Sutton. 99
4. THE NATIONAL ACADEMY OF ENGINEERING NATIONAL
RESEARCH COUNCIL AND DEEPWATER HORIZON STUDY GROUP
CONFIRM THAT BP RECKLESSLY ELEVATED PROFITS OVER
SAFETY
327. The National Academy of Engineering and National Research Council’s (“NAE”)
November 16, 2010 Interim Report to the Department of Interior echoes the safety lapses of BP’s past and confirms the findings of BP’s recklessness.
328. The Report stated in relevant part that “numerous decisions to proceed toward
abandonment despite indications of hazard, such as the results of repeated negative-pressure tests,
suggest an insufficient consideration of risk and a lack of operating discipline .”100
329. Moreover, the panel determined that BP suffered a lack of “management
discipline” and problems with “delegation of decision making” on board the Deepwater
99 Role of BP in Deepwater Horizon Explosion and Oil Spill, hearing before the Subcommittee on Oversight and Investigations, 6/17/10, Pg.150.
100 NAE Interim Report at 3.
105 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 113 of 150
Horizon. Workers aboard the drilling vessel were often unsure about who was actually in charge, 101 and there was a “lack of on board expertise and of clearly defined responsibilities.”
330. The Deepwater Horizon Study Group 102 found that BP’s Macondo team’s actions
reflected “gross imbalances between production and protection incentives” and manifested in
“actions reflective of complacency, excessive risk-taking, and a loss of situational awareness.”
331. The sole consistent theme through all of BP’s disasters is the corporate cultural
contribution of profit over safety and decisions made with indifference to the foreseeably tragic
results to human lives, the environment, and its shareholders.
5. INDUSTRY PEERS CONFIRM THAT BP’S SAFETY AND RISK
MANAGEMENT PROCESSES WERE BELOW INDUSTRY STANDARDS
332. In testimony before Congress, executives of four major oil companies testified that
BP’s operations were deficient and below industry standards. As Exxon Mobil Chairman, Rex
Tillerson, succinctly put, “We would not have drilled the well the way they did.”
333. Similarly, Anadarko’s chief executive, Jim Hackett, stated “The mounting
evidence clearly demonstrates that this tragedy was preventable and the direct result of BP’s
reckless decisions and actions.” Hacket added that he was “shocked” to find that BP “operated
101 Id. at 14.
102 The Deepwater Horizon Study Group was formed by members of the U.C. Berkeley
Center for Catastrophic Risk Management in May 2010 in response to the explosion and fire at the Deepwater Horizon well on April 20, 2010. The group is comprised of more than sixty faculty members from the University of California and other institutions, accident investigators, petroleum engineers, social scientists, environmental advocates, and directors of research centers. At the request of the House of Representatives Subcommittee on Oversight and
Investigations, Committee on Energy the Group has provided findings and conclusion regarding the causes and consequences of the Deepwater Horizon disaster.
106 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 114 of 150
unsafely and failed to monitor and react to several critical warning signs during the drilling of the
Macondo well.”
H. ADDITIONAL EVIDENCE OF BP’S CONCEALED GULF OPERATIONAL PROBLEMS
1. BP CONCEALED THAT SAFETY PROCESSES HAD YET TO BE
IMPLEMENTED IN THE GULF OF MEXICO
334. BP began implementing an Operational Management System (“OMS”) to address
process safety in its Gulf Operations in 2008. Contrary to its representations to the investing
public, by 2009 and 2010, the program was still in its infancy stages and yet to be fully
implemented in the Gulf. According to Confidential Witness 2 (“CW2"), a former BP senior
manager and an expert in the offshore oil and gas drilling and completions, BP’s OMS lagged far behind its peers (e.g. Chevron and Exxon) in 2009.
335. In the fourth quarter of 2009 and in January 2010, BP, as part of a global cost-
cutting restructuring, reorganized the drilling operations unit for the Gulf of Mexico. According
to CW2, the global reorganization was attributable to decisions made by Defendant Inglis and BP
America Chief Operating Officer Doug Suttles. A consequence of the restructuring was the
termination or forced transfer for those chiefly responsible for BP’s Gulf Operations, including but not limited to safety processes and the implementation of BP’s OMS in the Gulf of Mexico.
As a consequence, BP’s safety processes in 2010 were not as BP represented them to be. Further
as described below, the individuals brought in to both implement BP’s OMS and manage BP’s
Gulf Operations lacked the knowledge, experience and expertise of those they were replacing.
107 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 115 of 150
108 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 116 of 150
336. According to CW2, this restructuring was implemented despite concerns raised by
CW2 and other senior BP employees in the Gulf regarding BP’s ability to conduct its operations
safely in the Gulf, including but not limited to the implementation of BP’s OMS. These issues
were addressed to Barbara Yilmaz who had direct reporting responsibilities to BP’s Board of
Directors.
337. Ian Little was the Gulf of Mexico wells manager for BP. Little was replaced by
David Sims who, according to CW2, lacked Little’s knowledge and expertise. Despite this, Sims
was required to make decisions regarding not only management of the well, but manage the
response to the Horizon’s explosion.
338. Prior to becoming Vice President of Drilling and Completions, London in
December 2009, Harry Thierens served from 2006-2009 as the well director for the Gulf of
Mexico. He managed the engineering and operations group in the Gulf of Mexico. Thierens was
replaced by David Rich, who according to CW2 lacked the expertise of Thierens.
339. When the Horizon disaster occurred, Thierens was called back to deal with the
fallout. Thierens testified in Houston before a federal panel and said that the plumbing on the
blowout preventer was connected improperly. He said that the plumbing line that was supposed
to be connected to one of the rams meant to cut off a runaway well was actually connected to a
test ram that would be of no use in containing the well. Thierens’ log showed his bewilderment
that the blowout preventer had been modified and noted that he had immediately met with
Transocean engineer William Stringfellow, Jr. and others working to choke the well: “When I
learned this news I lost all faith in this BOP stack plumbing. Billy Stringfellow, clearly emotional
109 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 117 of 150
103 told me ‘this stack is plumbed wrong’,” Thierens wrote. The plumbing issue affected efforts to
jump-start the preventer using underwater robots but not the initial effort to trigger the preventer
from the burning rig. When Thierens was asked about the chain of command on the rig, he said
he didn’t know. 104 How could he, he was replaced the previous December.
340. Kevin Lacy was the vice president of Drilling and Completions for BP until
December 15, 2009 when he was terminated. Lacy, who worked in exploration and production
for thirty years, was replaced by Patrick O’Bryan.
341. According to CW1 and CW2, O’Bryan lacked Lacy’s experience and expertise.
According to CW2, by 2009 and 2010, BP had still not implemented a robust operations
management system to insure offshore processes could be managed effectively for both
exploration and risk. Given the difficulties of Gulf exploration this invited disaster.
342. Four days before the explosion, BP had ordered its veteran well site leader back to
Louisiana for routine training and replaced him with Robert Kaluza. When U.S. Coast Guard
Capt. Hung Nguyen question the Transocean Rig Manager Paul Johnson who the head of BP’s
chain of command was on the Horizon, Johnson could not readily identify the person and stated
“We didn’t know who this gentleman was . . . I asked who was Mr. Kaluza. Where did he come
from? I asked about his deep-water experience during ... a critical phase of the well.” BP
officials assured Johnson that Kaluza was “an accomplished well site leader.” 105
103 David S. Hilzenrath, BP executive says blowout preventer was not connected properly, (Washington Post, Aug. 25, 2010).
104 Transcript of Testimony before the Joint United States Coast Guard/Bureau of Ocean
Energy Management Investigation, pages 77-78, 82, 106-107 (Aug. 25, 2010).
105 Transcript of Testimony before the Joint United States Coast Guard/Bureau of Ocean
Energy Management Investigation, Pgs. 258-259 (Aug. 23, 2010).
110 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 118 of 150
343. A BP audit report of the Horizon found: (1) Not all relevant personnel on the rig
were knowledgeable about drilling and well operation practices; (2) A review showed significant
overdue maintenance jobs that required more than 3,545 man hours; (3) No single person on
board the rig could account for which alarms had been disabled and for what reason; and (4) A
warning on under-staffing was issued, saying that any further reduction of experienced personnel
may be “detrimental to the performance of the rig.” 106
2. EXPERTS AND CONFIDENTIAL WITNESSES CONFIRM THAT,
CONTRARY TO ITS REPRESENTATIONS, BP FAILED TO
IMPLEMENT SAFETY OPERATIONS IN THE GULF OF MEXICO
344. According to CW2 and CW3, both experts in oil company operations safety and
former consultants to BP’s Board of Directors, by no later than 2005, BP had recommended and
approved “Best Practices” for its operations. Contrary to its public statements during the Subclass
Period, BP failed to implement them. According to CW3, while BP distributed this roadmap to
some downstream operations, it contemporaneously slashed their budgets by 25% and provided
no resources by which to implement the safety processes. Further, according to CW3, BP’s
Upstream businesses (e.g. offshore exploration) never received any information related to any
suggested cures for BP’s endemic safety process and risk management problems.
345. According to CW3, BP failed to implement best practices, such as hiring personnel
experienced in safety and risk management, implementing operational safety policies with budgetary support and not cost cutting on safety issues.
346. Indeed, it was only last month that BP’s current CEO, Bob Dudley, finally
created a global safety division to deal with BP’s systemic safety and risk management
106 Rong-Gong Lin II, Chaos described as BP hearings resume, (LA Times, Aug. 24,
2010).
111 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 119 of 150
problems. This division was suggested to BP’s Board of Directors, including by confidential
witnesses, as early as 2001 and by governmental prosecutors through and including the present.
347. According to one reporter, there was division between the London and United
States operations regarding BP’s failure to comply with public assurances concerning its safety
and risk management practices. While the U.S. leaders wanted to put more emphasis on safety,
their counterparts in London discounted the recommendation because it was coming from
Americans. Accordingly, even if BP had aspirations of fixing its internal culture as it related to
safety and processes the statements that “Hayward and other executives were making about
improving safety weren’t being fully implemented.” 107
348. While BP insisted it had learned from its mistakes, that safety was a priority and
that managers were rewarded for safe operations as well as performance, Harry Thierens, BP’s
vice president for drilling and completions, in his testimony before Congress, could not recall
what BP had done to improve safety after the Texas City explosion. 108
349. It is apparent that even if Hayward did stress BP’s commitment to safety – given
the three criminal investigations, the Baker Report and the final U.S. Chemical Safety Board
Report how could he not – BP’s actual philosophy during the Subclass Period was actually to
continue the same plans that existed under John Browne. BP pushed for the most lucrative oil
deposits in the Gulf, but intentionally cut costs and failed to implement safety processes to
account for the engineering challenges BP encountered.
107 Loren C. Steffy, Drowning in Oil: BP & the Reckless Pursuit of Profit (McGraw-Hill
2010), Pg. 152.
108 Transcript of Testimony before the Joint United States Coast Guard/Bureau of Ocean Energy Management Investigation, Pg. 65 (Aug. 25, 2010)..
112 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 120 of 150
350. Under Hayward’s stewardship, BP slashed $4 billion in expenses in 2009 and spent
0.0033 percent of BP revenues on research and development regarding safer offshore drilling
technologies.
351. Despite Hayward’s vows to make safety a priority, BP’s management structure
“was still convoluted, accountability was hard to find . . . and cost cutting and financial performance continued to overshadow operations.” 109
VI.
MISREPRESENTATIONS AND OMISSIONS DURING
THE SUBCLASS PERIOD
352. Beginning on March 4, 2009, BP began to highlight the safety and success of its
operations in the Gulf of Mexico, touting the fact that it was one of the largest deepwater
operators in the world. At the same time, BP failed to disclose that it had not implemented safety
measures for its Gulf of Mexico operations, disregarded warnings about its operations, and lacked
robust risk management processes that left the Company dangerously exposed.
A. 2008 FORM 20-F ANNUAL REPORT
353. On March 4, 2009, BP filed with the SEC its 2008 Form 20-F which included the
following representations on safety and risk management:
Safety
This section reviews BP’s safety performance in 2008.
There were five workforce fatalities in 2008, compared with seven in 2007. One
resulted from fatal injuries sustained during operations at our Texas City refinery;
one was the result of a fall from height at the Tangguh operations in Indonesia; one
109 Loren C. Steffy, Drowning in Oil: BP & the Reckless Pursuit of Profit (McGraw-Hill
2010), Pg. 160.
113 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 121 of 150
fatality was on a land farm near Texas City, and two were driving fatalities
incidents in Mozambique and South Africa. We deeply regret this loss of life. By
learning from these incidents and implementing appropriate improvement actions,
we continue to seek to secure the safety of all members of our workforce. Our
workforce reported recordable injury frequency, which measures the number of
injuries per 200,000 hours worked, was 0.43 in 2008. This was a good
improvement on the rate of 0.48 recorded in both 2007 and 2006.
Throughout 2008, senior leadership across the group continued to hold safety
as their highest priority. Site visits, in which safety was a focus, were undertaken
by the group chief executive (GCE) and members of the executive team to
reinforce the importance of their commitment to safe and reliable operations.
Management systems
We continue to implement our new operating management system (OMS), a
framework for operations across BP that is integral to improving safety and
operating performance in every site.
When fully implemented, OMS will be the single framework within which we will
operate, consolidating BP’s requirements relating to process safety, environmental
performance, legal compliance in operations, and personal, marine and driving
safety. It embraces recommendations made by the BP US Refineries Independent
Safety Review Panel (the panel), which reported in January 2007 on safety
management at our US refineries and our safety management culture.
The OMS establishes a set of requirements, and provides sites with a systematic
way to improve operating performance on a continuous basis. BP businesses
implementing OMS must work to integrate group requirements within their local
system to meet legal obligations, address local stakeholder needs, reduce risk and
improve efficiency and reliability. A number of mandatory operating and
engineering technical requirements have been defined within the OMS, to address
process safety and related risks.
All operated businesses plan to transition to OMS by the end of 2010. Eight sites
completed the transition to OMS in 2008; two petrochemicals plants, Cooper River
and Decatur, two refineries, Lingen and Gelsenkirchen and four Exploration and
Production sites, North America Gas, the Gulf of Mexico, Colombia and the
Endicott field in Alaska. Implementation is continuing across the group and a
number of other sites, including all refineries not already operating the OMS, are
expected to complete the transition in 2009.
For the sites already involved, implementing OMS has involved detailed planning,
including gap assessments supported by external facilitators. A core aspect of
OMS implementation is that each site produces its own ‘local OMS’, which takes
114 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 122 of 150
account of relevant risks at the site and details the site’s approach to managing
those risks. As part of its transition to OMS, a site issues its local OMS handbook,
and this summarizes its approach to risk management. Each site also develops a
plan to close gaps that is reviewed annually. The transition to OMS, at local and
group level, has been handled in a formal and systematic way, to ensure the change
is managed safely and comprehensively. Experience so far has supported our
expectation that having one integrated and coherent system brings benefits of
simplification and clarity, and that the process of change is supporting our renewed
commitment to safe operations.
We are on track to meet our target of implementing OMS across the group by the
end of 2010.
Capability development
In addition to ongoing training programmes we are undertaking a group wide
programme to enhance the capability of our staff from front line to executive level
to deliver operational excellence.
Almost 1,000, around a third, of our front-line supervisors have started the
Operating Essentials programme, which includes training on leadership, process
safety, operating culture, practices and coaching and effective performance
conversations.
More than 190, around half, of our operations leaders started the Operations
Academy programme in 2008. The academy, which has been established in
partnership with the Massachusetts Institute of Technology (MIT), provides
participants with a total of six weeks of operations training, concentrating on the
management of change and continuous improvement.
The Executive Operations programme, which seeks to increase insight into
manufacturing and operation activities among senior business leaders, has built on
its successful launch with the first group, which included the group chief executive
and his executive team. By the end of 2008, 99 executives had attended the
three-day programme.
In addition, new cadres of projects and engineering staff have progressed through
the Project and Engineering Academy at MIT and 13 process safety courses have
been delivered for project and project engineering managers at the Project
Management College. We have continued to develop training on hazard evaluation
and risk assessment techniques for all engineers, operators and HSSE
professionals.
115 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 123 of 150
Process safety management
We remain fully committed to becoming a recognized industry leader in
process safety management and are working to achieve this. We have taken a
range of steps, including acting on the recommendations from both the panel and
those within the first annual report of the independent expert.
Our actions can be summarized in three principal areas:
• We have made progress in reducing process safety risk at our US
refineries. For example, we have completed and learned from safety and
operations audits, relocated workers to lower-risk accommodation and
implemented fatigue reduction programmes.
• Executive management has taken a range of actions to demonstrate their
leadership and commitment to safety. The group chief executive has
consistently emphasized that safety, people, and performance are our top
priority, a belief made clear in his 2007 announcement of a forward agenda
for simplification and cultural change in BP. Safety performance has
been scrutinized by the Group Operations Risk Committee (the
GORC), chaired by the group chief executive and tasked with assuring
the group chief executive that group operational risks are identified
and managed appropriately. We continued to build our team of safety
and operations auditors. A team of 45 auditors is now in place, with 36
audits completed in 2008.
• Many of the process-safety related improvements recommended by the
panel are being implemented across the group through the OMS. The
group essentials within the OMS (which cover diverse aspects of operating
activity including legal compliance, process and environmental safety and
basic operating practices) in some cases go beyond the panel’s process
safety recommendations, a point noted by the independent expert in his first
report.
In addition to action in these areas, we have continued to participate in
industry-wide forums on process safety and have made efforts to share our learning
with other organizations.
The independent expert has been tasked with reporting to the board on BP’s
progress in implementing the panel’s recommendations. We welcome the
independent expert’s view expressed in his first report (May 2008) that BP appears
to be making substantial progress in changing culture and addressing needed
process safety improvements’. However, we also acknowledge his observation
that ‘a significant amount of work remains to be done on the process safety
journey’ and that ‘successful completion of the task will require the continued
116 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 124 of 150
support and involvement of the board, executive management, and refinery
leadership along with a sustained effort over an extended period of time’. The
independent expert’s second report is expected in the first half of 2009.
Operational integrity
We continue to implement the six-point plan launched in 2006 to address
immediate priorities for improving process safety and minimizing risk at our
operations worldwide.
We have met our commitment to remove occupied portable buildings (OPBs) from
high-risk zones within onshore process plant areas and to remove all blow-down
stacks in heavier-than-air, light hydrocarbon service. All major sites and our fuels
value chains have completed major accident risk assessments, which identify major
accident risks and develop mitigation plans to manage and respond to them.
We continue to implement the Control of Work and Integrity Management
standards. We have made progress in ensuring our operations meet the
requirements of a group framework designed to ensure we stay in compliance with
legal requirements on health and safety. We are continuing to take steps to close
out past audit actions. Leadership competency assessments, which involve
assessment of the experience of BP management teams responsible for major
production sites or manufacturing plant, have been completed in Exploration and
Production and in all major Refining and Marketing manufacturing sites.
Implementation of these actions is expected to be largely complete by the end of
2009, with some aspects of implementation being incorporated into the transition
to the OMS, expected to be completed by the end of 2010. The GORC regularly
monitors progress against the plan.
We monitor and report separately on major incidents such as those covering fatal
accidents, significant property damage or significant environmental impact. We
also track and analyze ‘high potential’ incidents – those that could have resulted in
a major incident. All major incidents and many high-potential incidents are
discussed by the GORC and we continue to seek to learn as much as possible from
each incident.
A total of 21 major incidents were reported in 2008. Two of the major incidents
were related to hurricanes and eight were related to driving incidents.
There were 335 oil spills of one barrel or more in 2008, similar to 2007
performance of 340 oil spills. The volume of oil spilled in 2008 was
approximately 3.5 million litres, an increase of 2.5 million litres, compared with
2007. This was largely the result of two incidents, one at Texas City and one at the
117 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 125 of 150
Whiting refinery, which accounted for two-thirds of the total reported volume of
oil spilled, the great majority of which remained contained and the oil recovered.
Performance indicators
We have well-developed systems, processes and metrics for reporting personal
safety and environmental metrics that support internal performance management as
well as public reporting.
We introduced several new metrics in 2008 that aim to enhance our monitoring of
process safety performance within BP’s operating entities. These include, for
example, a process safety incident index, as recommended by the panel, which uses
weighted severity scores to record and assess process safety events, and a measure
to record any loss of hydrocarbon from primary containment.
Our indicators include industry-aligned ‘lagging’ process safety metrics that
register events that have already occurred, and ‘leading’ indicators that focus on
the strength of our controls to prevent undesired events in future. A suite of
indicators is regularly reported to the GORC within the quarterly ‘HSE and
Operations Integrity Report’ and several new metrics have also been piloted. To
further enhance the management of health risks across the group, we began the
systematic reporting of recordable illness rates within the HSE and Operations
Integrity Report. We continue to work with industry bodies such as the Centre for
Chemical Process Safety and the American Petroleum Institute on the development
of process safety metrics, definitions and guidance.
Continuing to focus on health
In addition to our efforts to improve process safety performance, we strive to
protect the personal health and safety of our workforce, recognizing that healthy
performance is delivered through healthy people, healthy processes and healthy
plant.
In the course of 2008, we defined health ‘group essentials’, which specify
requirements designed to prevent harm to the health of employees, contractors,
visitors and local communities. These were incorporated within the OMS
framework. Our health strategy and plan was also refreshed in 2008. Priorities
include reducing significant occupational exposure and infectious disease risks,
maintaining robust regulatory compliance in product health and safety and
addressing the issue of fatigue management raised by the panel by providing
training and awareness-raising.
354. The above referenced statements were materially false and misleading when made
because Defendants failed to disclose or indicate the following: (1) BP had inadequate safety
118 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 126 of 150
procedures in place for its Gulf operations; (2) BP conducted its operations in the Gulf without
any legitimate oil spill response plan; (3) BP understated the risks of its Gulf operations while
overstating its ability to extract oil from the Gulf; and (4) BP lacked adequate internal safety and
risk management controls.
B. MARCH 10, 2009 INITIAL EXPLORATION PLAN
355. On March 10, 2009, BP filed an Initial Exploration Plan for Mississippi Canyon
252. The document was dated as being received by the MMS on February 23, 2009. Attached as
Exhibit B is a true and correct copy of the Initial Exploration Plan (“EP”), which details the
safety mechanisms that BP said it intended to implement.
356. This document was false and misleading as it failed to appropriately and accurately
detail the true risks and dangers of this operation and failed to disclose the fact that BP had
disregarded known risks relating to the operation of the Deepwater Horizon. In the
Environmental Impact Analysis section of the EP, BP repeatedly and falsely asserted that it was
“unlikely that an accidental surface or subsurface oil spill would occur from the proposed
activities.” BP falsely estimated a worst-case discharge scenario of 162,000 gallons of oil per day,
an amount it falsely assured the MMS that it was prepared to respond to. BP also claimed the
well’s distance from the nearest shoreline would preclude any significant adverse impacts from a
spill.
357. Additionally, before BP could begin operations at the Macondo site, federal
regulations required BP to submit its EP demonstrating that it had planned and prepared to
conduct its proposed activities in a manner that was safe, conformed to applicable regulations and
sound conservation practices, and would not cause undue or serious harm or damage to human or
119 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 127 of 150
marine health, or the coastal environment. 30 C.F.R. §§ 250.201, 250.202. BP did not have such
a plan or a means of conducting their proposed activities.
358. Further, federal regulations required that the EP be accompanied by “oil and
hazardous substance spills information” and “environmental impact analysis information.” 30
C.F.R. §§ 250.212, 250.219, 250.227.
359. Among the information required to accompany the EP was a “blowout scenario,” described as follows:
A scenario for the potential blowout of the proposed well in your EP that you
expect will have the highest volume of liquid hydrocarbons. Include the estimated
flow rate, total volume, and maximum duration of the potential blowout. Also,
discuss the potential for the well to bridge over, the likelihood for surface
intervention to stop the blowout, the availability of a rig to drill a relief well, and
rig package constraints. Estimate the time it would take to drill a relief well. 30
C.F.R. § 250.213(g).
360. The oil and hazardous spills information accompanying the EP was also required to
include an oil spill response plan providing the calculated volume of BP’s worst-case discharge
scenario (See 30 C.F.R. § 254.26(a)), and a comparison of the appropriate worst-case discharge
scenario in [its] approved regional [Oil Spill Response Plan] with the worst-case discharge
scenario that could result from [its] proposed exploration activities; and a description of the
worst-case discharge scenario that could result from [its] proposed exploration activities ( See 30
C.F.R. §§ 254.26(b), (c), (d), and (e)); 30 C.F.R. § 250.219.
361. Federal regulations required BP to conduct all of its lease and unit activities
according to its approved EP, or suffer civil penalties or the forfeiture or cancellation of its lease.
30 C.F.R. § 250.280.
362. Concealed to the investing public was BP’s failure to have sufficient internal safety
and risk management processes to satisfy the above referenced regulated. In fact, BP Chief
120 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 128 of 150
Operating Officer Doug Suttles acknowledged on May 10, 2010, that BP did not actually have a
response plan with “proven equipment and technology ” in place that could contain the
Deepwater Horizon Spill. Later, Defendant Hayward admitted that “ BP’s contingency plans were inadequate,” and that the company had been “making it up day to day .”
363. On May 12, 2010, Defendant McKay admitted in testimony to the House
Subcommittee on Oversight and Investigations, Committee on Energy and Commerce, that BP did
not have the capability and technology to respond to the Deepwater Horizon oil spill:
Mr. McKay: We are using the best technology at scale. This is the largest effort
that has ever been put together. So we believe we are using the best technology and
if we have any other ideas.
Mrs. Capps: But you never had any until it happened.
Mr. McKay: Well, we have been drilling with the Coast Guard for years.
Mrs. Capps: Did you develop technologies for dealing with this?
Mr. McKay: Not individual technologies for this, no.
Mrs. Capps: I rest my case.
364. Suttles’ acknowledgment, Hayward’s admission, and McKay’s testimony are further evidence of the falsity of BP’s EP plan.
C. MARCH 25 2009 HOWARD WEIL ENERGY CONFERENCE
365. On March 25, 2009 Defendant McKay spoke at the Howard Weil Energy
Conference. His remarks included the following:
“There’s no better example of what technology can do than the deep waters of the
Gulf of Mexico.”
“By the way, let me add that managing costs down does not mean BP will be
skimping when it comes to ensuring our operations remain safe, reliable and
compliant in the years ahead.”
121 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 129 of 150
“Safety will continue to have first call on the company resources .”
366. These statements were false and misleading because Defendant McKay, in his
position as the CEO of BP America, knew about serious safety problems throughout BP’s Gulf of
Mexico operations. At the time that statement was made, there were systemic safety problems at
BP that were known to Defendant McKay and directives had been issued by senior BP managers
to put profit before safety.
367. Further, these statements were false and misleading because (1) BP did skimp on
operational safety and (2) safety not only was not the first call of the company’s resources, but
was recklessly underfunded.
D. NOVEMBER 19, 2009: STATEMENTS TO THE SENATE ENERGY AND
NATURAL RESOURCES COMMITTEE
368. On November 19, 2009, David Rainey, Vice President for Gulf of Mexico
Exploration for BP America, Inc. (a subsidiary of BP, plc) testified in front of and submitted
written statements to the United States Senate and Energy and Natural Resources Committee.
While Rainey acknowledged the general risks of drilling for oil in the Gulf of Mexico, he omitted
the fact that BP had not implemented adequate safety provisions, and therefore was highly
exposed to operational risks in the Gulf of Mexico.
369. Rainey’s written statements before the United States Senate Energy and Natural
Resources Committee included the following assertions:
BP’s Energy Portfolio
BP is not only the largest oil and gas producer in the United States, but also the
largest investor in energy of all sorts. In the last five years, we have invested
approximately $35 billion in the US to ensure Americans have the energy and fuels they need to live their lives. These include:
122 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 130 of 150
Oil and natural gas: Offshore and onshore, from the Alaskan North Slope to the
deep waters of the US Gulf of Mexico, we are a leader in providing America’s
traditional energy needs.
370. In discussing safety specifically, Rainey stated:
While our intent is to prevent all accidental discharges, we conduct regular
emergency drills with local, state, and federal agencies. All of our production
facilities have contingency plans that identify the procedures, response equipment, and key personnel needed for responding to incidents.
371. Rainey’s statement further provided specific information regarding the
complexities of oil operations in the Gulf of Mexico, but failed to include material facts relating
to BP’s inadequate safety protocols:
US Deepwater Gulf of Mexico
Industry began to explore in the US Gulf of Mexico during the early 1930's. The
first discovery out of site of land was made by Kerr McGee in 1947. The MMS
classifies water depths greater than 1,000 feet as deepwater, and depths beyond
5,000 feet as ultra-deepwater. The first deepwater exploration well was drilled in
1975. The first ultra-deepwater exploration well was drilled in 1987. So, while it
took more than 40 years for industry to develop the technology to move from the
shoreline to 1,000 feet water depth, it took just 12 years to move from 1,000 feet to 5,000 feet. Wells in water depths up to 10,000 feet are now routine.
In the US Gulf of Mexico, shallow salt canopies underlie about 65 percent of the
seabed in the deepwater areas. These salt canopies make seismic imaging of the subsurface very challenging. . .
Early exploration in the US Deepwater Gulf of Mexico was focused on the 35
percent of the area which has no salt canopy. Without the salt, conventional
seismic imaging worked and fields were discovered as the advances in drilling
technology enabled industry to move rapidly into the deepwater. Much of the success in this period was enabled by widely-spaced two dimensional seismic data.
The technology challenge was about developing the systems to safely produce the
oil and gas in these water depths. Our colleagues in Shell were at the forefront of this phase of Gulf of Mexico development.
By the mid-1990's, the large fields had been found in the areas of the deepwater
free of shallow salt canopies. This led industry to turn its attention to the challenge
of exploring below the salt. To do this, we matured a technology known as seismic
depth imaging. This technology combines geological modeling and computer
123 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 131 of 150
algorithms to restore the seismic wave paths to their correct positions-allowing the image to emerge.
By the late 1990's, depth imaging allowed the industry to begin to explore beneath
the salt. These early forays were restricted to areas where the top and base of the
salt were geometrically simple and the imaging problem was, from where we stand
today, relatively easy to solve. BP’s Mad Dog, Atlantis, and Thunder Horse
discoveries were delivered on the back of this technology in 1998 and 1999. Since
then, we have continued to refine the technology and have been able to announce a
steady stream of discoveries – most recently Kaskida in 2006, Isabela in 2007,
Kodiak and Freedom in 2008, and this year Mad Dog South and Tiber.
In 2003, BP began to address the problem of how we would explore under more
complex salt geometries. We predicted that continuing incremental improvements
to what was then considered conventional; depth imaging methods would soon
reach a point of diminishing returns. So we set out to create a step change by
developing a completely new seismic imaging technology.
Conventional depth imaging is a data processing technology which involves some
of the most sophisticated computer algorithms ever created. These algorithms
require powerful super-computers to run them. However, the underlying data were
acquired using a technology which had not changed significantly for 25 years. The
data were acquired using a single seismic vessel towing both the seismic source
and the receivers. Effectively, therefore, the data were acquired in two dimensions,
but at sufficiently close spacing to allow processing in three dimensions.
BP’s Wide Azimuth Towed Streamer (WATS) and Ocean Bottom Node
technologies involve truly three-dimensional seismic acquisition. They were
conceptualized, modeled, and piloted at scale in the US Deepwater Gulf of
Mexico. The WATS pilot was on our Mad Dog Field, and the Nodes pilot was on
Atlantis. At Mad Dog, the WATS data have contributed significantly to our ability
to continue to develop the field. The successful Mad Dog South appraisal well
which we announced in July of this year was enabled by these data. At Atlantis,
development of the North Flank of the field has been enabled through the
application of nodes technology and production has begun.
We have worked hard to drive our WATS technology into the market, and to refine
it to make it cost effective in the exploration arena. Today, much of the US
Deepwater Gulf of Mexico is covered by what we call XWATS - for Exploration
WATS - seismic surveys. The data from these surveys will allow us to continue to
move forward the limits of where we explore. As a result, we will be more
efficient, drill fewer wells, and have less impact on the environment as we become
better at predicting the presence of oil and gas in the subsurface.
124 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 132 of 150
I have mentioned above how drilling technology advanced to allow us to drill in
deep and ultra-deep waters. As discoveries were made, production technology
followed. A variety of production systems have been developed to account for the different metocean, seabed, and reservoir conditions.
BP has been at the forefront of this recent phase of deepwater development.
Today, we operate eight major producing facilities in the US Deepwater Gulf of
Mexico. They range from the Pompano fixed platform, installed in 1994 in 1,300
feet of water, to the Atlantis semi-submersible platform, which started production in 2007 and sits in 7,100 feet of water. In between lie:
• The Marlin tension leg platform in 3,234 feet of water;
• The Holstein, Mad Dog, and Horn Mountain spar facilities in 4,344, 4500 and 5,422 feet of water, respectively; and
• The Thunder Horse and Nakika semi-submersible platforms in 6,050 feet and 6,340 feet of water, respectively;
Today Atlantis is the world’s deepest oil production facility, an honor previously held by both Horn Mountain and Nakika, when they began production.
In addition to enabling the industry to move into ever deeper waters, the drilling envelope has been extended by advances in directional and extended reach drilling.
The Nakika development is an example of where these technologies have been
combined with subsea production technology to bring six otherwise uneconomic
discoveries to production. These independent, medium-sized fields are tied back to
the centrally-located semi-submersible production host facility. Distance from the
central host varies from five to 26 miles. By combining directional and extended
reach drilling with subsea production systems, the environmental footprint has
been reduced by requiring only one surface facility, where previously six would
have been needed.
This month marks the tenth anniversary of our Marlin oil and gas hub. As the
Marlin Field has declined, a series of satellite fields have been tied back using
subsea production technology. In total, five satellite fields have been tied back,
with distance from the host ranging from two miles to 18 miles. This year, the
Dorado and King South satellite fields have been brought on line. These tiebacks
have returned the facility to a second peak of production – a very rare occurrence in
our industry. Again, the combination of directional and extended reach drilling
and subsea production technology has enabled multiple fields to be developed from
a single host platform. The environmental footprint has been reduced and the
useful life of the facility has been extended.
125 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 133 of 150
In addition to directional and extended reach drilling, today’s drilling technology
allows us to drill to total depths which were unimaginable just 15 years ago. In the
mid-1990's, drilling was restricted to roughly 20,000 feet total depth. Today we
routinely drill to 30,000 feet and below. This means that we encounter ever greater
temperatures and pressures. Our Thunder Horse development currently defines the limits for what we call high-pressure/ high-temperature production technology.
That said, we are already moving beyond these limits. Our Kaskida discovery,
with reservoir depths ranging from 30,000 feet to 32,500 feet, has reservoir
pressures above 20,000 pounds per square inch. We are currently designing the systems which will be required to bring Kaskida to production.
Finally, we have recently announced our Tiber discovery – which was at the time
of rig release the deepest well in the history of the oil and gas industry at 35,055
feet. Tiber is an exciting discovery, and we are working hard to understand the
technologies which will be required to bring it to production.
Offshore Technologies Enabling Environmental Stewardship
Three key technologies which enable the safe and reliable production of offshore
oil and gas resources:
• Seismic imaging;
• Offshore drilling; and
• Offshore production systems.
Seismic imaging allows us to predict the presence of hydrocarbon reservoirs below
the sea bed. Drilling allows us to test for the presence of hydrocarbons in the
reservoirs. When hydrocarbons are present, the well bore connects the reservoir to
the surface, where production systems enable us to produce the hydrocarbons, and
deliver them safely to the refinery.
372. These representations were false and misleading. While explaining the successes
and profit potential of BP’s Gulf of Mexico Operations, Rainey omitted to disclose to investors
the risks and dangers of these operations. Most importantly, Rainey omitted the fact that BP had
failed to implement safety and risk management protocols, including those recommended to
senior management, and were dangerously exposed due to its drilling operations in the Gulf.
126 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 134 of 150
E. 2009 ANNUAL REVIEW
373. On February 26, 2010, BP issued its 2009 Annual Review.
1. SVANBERG STATEMENTS
374. The Annual Review included a letter from Chairman of the Board Carl-Henric
Svanberg, stating: “Risk remains a key issue for every business, but at BP it is fundamental to
what we do. We operate at the frontiers of the energy industry, in an environment where attitude
to risk is key. The countries we work in, the technical and physical challenges we take on and the
investments we make – these all demand a sharp focus on how we manage risk. We must never
shrink from taking on difficult challenges, but the board will strive to set expectations of how risk
is managed and remain vigilant on oversight .”
375. These statements were not true. The reality was that BP was trying to manage risk
in the least costly way possible, and intentionally chose not to implement safety and risk
management protocols, including those recommended to senior management, which left the
Company dangerously exposed due to its drilling operations in the Gulf. If BP had truly been
willing to put safety first, it would have complied with safety standards and reduced safety risks
necessary to prevent a disaster like the Deepwater Horizon incident.
2. HAYWARD STATEMENTS
376. Defendant Hayward wrote, “Despite these difficult conditions, a revitalized BP
kept up its momentum and delivered strong operating and financial results while continuing to
focus on safe and reliable operations . Replacement cost profit for the year was $14 billion, with
a return on average capital employed of 11%.” Defendant Hayward went on to say, “2009 was an
outstanding year. Reported production grew by 4% and unit production costs were down by 12%.
We are now the largest producer in deepwater fields globally. In the Gulf of Mexico, we ramped
127 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 135 of 150
up production at Thunder Horse to more than 300,000 barrels of oil equivalent per day.
Production started from Atlantis Phase 2, Dorado and King South. And in September we
announced the Tiber discovery, the deepest oil and gas discovery well ever drilled. These
successes make us the largest producer and leading resource holder in the deepwater Gulf of
Mexico .”
377. Defendant Hayward acknowledged that BP was operating on the frontiers of the
energy industry, but then reassured investors that risks were being handled appropriately, “BP has
always operated at the frontiers of the energy industry and our core strengths are more relevant
and valuable than ever. BP’s experience, skills, capability, technology and access to markets
enable resource holders to maximize returns over the long term. We continue to show our ability
to take on and manage risk, doing the difficult things that others either can’t do or choose not
to do. This is why we are able to form such strong relationships with governments and national
oil companies and why we continue to have a critical role to play in supplying the world with its
future energy needs.”
378. Defendant Hayward answered questions in the “Group chief executive’s review,”
which was disseminated to BP shareholders. When asked about the priorities he had set for BP,
Defendant Hayward responded “[o]ur priorities have remained absolutely consistent - safety,
people and performance . . . Achieving safe, reliable and compliant operations is our number
one priority and the foundation stone for good business. ”
379. These statements were false and misleading. While touting the strength of BP’s
Gulf of Mexico Operations, Hayward omitted the fact that BP’s safety protocols were woefully
inadequate and that BP had failed to implement safety and risk management protocols, including
128 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 136 of 150
those recommended to senior management, which left the Company dangerously exposed due to
its drilling operations in the Gulf.
3. INGLIS STATEMENTS
380. Defendant Inglis, BP’s Chief Executive of Exploration and Production reiterated
BP’s claim that safety was BP’s primary focus:
Safety, both personal and process, remains our highest priority. 2009 brought
further improvement in personal safety with the segment’s reported recordable injury frequency improving from 0.43 in 2008 to 0.39 in 2009.
We also achieved improvements in the number of process safety-related incidents and a significant reduction in the number of spills.
During the year we continued our migration to the BP operating management
system (OMS), which provides an increased focus on process safety and
continuous improvement. By the end of 2009, 87% of our operating sites had
transitioned to OMS.
381. Defendant Inglis went on to reaffirm BP’s purported “Deepwater Expertise” stating
that, “BP is the leading operator in the deepwater Gulf of Mexico. We are the biggest producer,
the leading resource holder and have the largest exploration acreage position. Thunder Horse is
now the largest single producing field in the Gulf of Mexico. Fully operational and performing
beyond expectations, it has enabled us to grow our Gulf of Mexico production from 240,000
barrels of oil equivalent per day in 2007 to more than 400,000 barrels of oil equivalent per day in
2009.”
382. Defendant Inglis’ statements were misleading. Based on his position as Chief
Executive of E&P, Inglis knew about serious safety problems throughout BP’s Gulf of Mexico
operations and that BP was woefully ill prepared to safely drill in the deepwaters of the Gulf of
Mexico. Further, BP had failed to implement safety and risk management protocols, including
129 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 137 of 150
those recommended to senior management, and was dangerously exposed due to its drilling
operations in the Gulf.
4. COMPANY STATEMENTS
383. In a section entitled “Sustaining momentum and growth,” BP acknowledged that
its safety protocols are material to investors by including a separate section on safety entitled
“Safety, reliability, compliance and continuous improvement.” That section states:
Safe, reliable and compliant operations remain the group’s first priority. A key
enabler for this is the BP operating management system (OMS), which provides a
common framework for all BP operations, designed to achieve consistency and
continuous improvement in safety and efficiency. Alongside mandatory practices
to address particular risks, OMS enables each site to focus on the most
important risks in its own operations and sets out procedures on how to
manage them in accordance with the group-wide framework.
384. This statement was false and misleading because BP had failed to implement its
OMS system in the Gulf operations in a sufficient manner. Moreover, according to CW2, BP’s
safety operations for its Gulf of Mexico offshore drilling operations lagged far behind BP’s competitors.
385. In the 2009 Annual Review, BP boasted that, due to its proactive safety measures,
it was reducing oil spills:
130 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 138 of 150
386. Collectively, all these representations were false and misleading. BP was wholly
unprepared to manage risk, inadequately prepared to safely exploit the Gulf of Mexico resources
and lacked adequate internal and safety controls particularly with respect to its deepwater Gulf of
Mexico operations critical to BP’s financial results. As a result of the foregoing, the Company’s
financial statements were false and misleading. As is now clear, the truth was that safety was not
BP’s first priority. Rather, BP’s failure to implement and enforce appropriate safety measures
made a costly and deadly incident like the Deepwater Horizon a virtual inevitability.
F. MARCH 2, 2010 STRATEGY PRESENTATION
387. On March 2, 2010, BP created and published a Powerpoint presentation in London,
which highlighted its deepwater operations, especially in the Gulf of Mexico.
131 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 139 of 150
388. BP’s presentation also highlighted the Gulf of Mexico as the site of a majority of
its “final investment decisions” for 2010 and 2011. These sites would be crucial for BP’s
continued economic growth.
132 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 140 of 150
389. In the following additional slide, BP acknowledges that the largest area of growth
for BP from 2010-2015 is the Gulf of Mexico. In fact, the majority of new projects for BP during
the 2010-2015 time period were to be in the Gulf of Mexico.
390. BP’s presentation also highlighted its safety record. BP’s first point is that
“Safe and reliable operations remains #1"
133 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 141 of 150
134 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 142 of 150
391. The presentation was false and misleading. While it is true that the Gulf of Mexico
was an important economic driver for BP, it is not true that BP was focused on safety. Instead, a
cascade of failures by BP made an incident like the Deepwater Horizon disaster virtually
inevitable. No lessons were learned from the past and no new commitment was made to safety,
and as confirmed by confidential witnesses, safety protocols that were promised were either
never implemented or enforced after 2009. Additionally, as detailed above and in the Abbott
whistleblower action BP concealed the fact that BP’s engineers predicted a catastrophic disaster of
this nature.
392. In February 2010, two months before the Deepwater Horizon disaster, 19 members
of Congress called on the agency that oversees offshore oil drilling to investigate Abbott’s
whistle-blower’s complaints about the Atlantis and BP’s commitment to safety in the Gulf.
Neither BP’s own independent investigation nor BP’s Ombudsman’s conclusions that BP’s lack
of completed engineering documents was violating its own policies as well as federal law were
disclosed to shareholders and was not revealed until after the Deepwater Horizon disaster.
393. In January 2010, Karen Westall, an attorney for BP, wrote a letter to Congress
saying the company is compliant with all federal requirements and the Atlantis has been operating
so safely that it received an MMS award. This statement was false and misleading. University of
California, Berkeley engineering professor Robert Bea describes running an oil rig with flawed
and missing documentation is like cooking a dinner without a complete recipe. According to
Prof. Bea, “This is symptomatic of a sick system. This kind of sloppiness is what leads to
disasters.”
135 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 143 of 150
G. 2009 FORM 20-F ANNUAL REPORT
394. On March 5, 2010, BP issued its 2009 Form 20-F Annual Report. BP stated, in
relevant part:
The priorities that drove our success in 2009 – safety, people and performance
– remain the foundation of our agenda as we build on our momentum and work to further enhance our competitive position.
* * *
Good progress has been made on underpinning improved safety performance in
2009. Throughout the year, we continued to focus on training and enhancing
procedures across the organization. Significantly, 2009 was an important year in
the development of OMS. By the end of 2009, around 80% of our operating sites
were using the system, including all our operated refineries and petrochemical plants.
* * *
In Exploration and Production, safety, both personal and process, remains our highest priority.
* * *
Our priorities remain the same safety, people and performance , focusing on the
delivery of safe, reliable and efficient operations. In 2010, we aim to use the
momentum generated in 2009 to continue to improve operational, cost and capital
efficiency, while ensuring we maintain our priorities of safe, reliable and
efficient operations. ”
395. These representations were false and misleading. Defendants failed to disclose, according to a confidential former BP senior employee with Gulf of Mexico responsibilities ,
BP’s Gulf Operations had only begun to implement OMS in a pilot stage and lagged far behind its
Big Oil peers. Moreover, BP had terminated and/or restructured the Gulf Operations team who
was charged with implementing the OMS. As a result, BP’s representations concerning the
adequacy of its commitment to safety and the implementation thereof, at least as it related to the
Gulf of Mexico, were false and misleading.
136 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 144 of 150
396. In discussing the Gulf of Mexico, BP specifically stated: “BP applies high
resolution seismic data for the identification of reservoir extent and fluid contacts only where
there is an overwhelming track record of success in its local application. In certain deepwater
fields, such as fields in the Gulf of Mexico, BP has booked proved reserves before production
flow tests are conducted, in part because of the significant safety, cost and environmental
implications of conducting these tests.”
397. BP’s operations in the United States take place in three major areas: the deepwater
Gulf of Mexico, the lower 48 states and Alaska. BP acknowledges the deepwater Gulf of Mexico
is easily its largest area of growth in the United States. The report specifically stated:
Deepwater Gulf of Mexico
Deepwater Gulf of Mexico is our largest area of growth in the US. In addition, we
are the largest producer and acreage holder in the region.
Significant events were:
• In May 2009, BP announced it had begun production from the Dorado (BP
75% and operator) and King South (BP 100%) projects. Both projects are
subsea tiebacks to the existing BP Marlin Tension Leg Platform (TLP)
infrastructure. Dorado comprises three new subsea wells located about two
miles from the Marlin TLP. King South comprises a single subsea well
located 18 miles from the Marlin TLP. Both projects leverage existing
subsea and topsides infrastructure and the latest subsea and drilling
technology to enable the efficient development of the fields. Dorado
utilizes dual completion technology enabling production from five Miocene zones and King South is produced through the existing King subsea pump.
• In June 2009, the Atlantis Phase 2 (BP 56%) project achieved first oil ahead of schedule, signaling the official start-up.
• In July 2009, BP announced the drilling of a successful appraisal well in a
previously untested southern segment of the Mad Dog field (BP 60.5% and
operator). The 826-5 well is located in the Green Canyon block 826,
approximately 100 miles south of Grand Isle, Louisiana, in about 5,100 feet
137 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 145 of 150
of water. The results from this well continue the successful phased development of the Mad Dog field and build upon the success from 2008.
• In September 2009, BP announced the Tiber discovery in the deepwater
Gulf of Mexico (BP 62% and operator). The discovery well, located in
Keathley Canyon block 102, approximately 250 miles south-east of
Houston, is in 4,132 feet of water. It was drilled to a total depth of
approximately 35,055 feet making it the deepest oil and gas discovery well ever drilled. The well found oil in multiple Lower Tertiary reservoirs.
Appraisal will be required to determine the size and commerciality of the discovery.
398. Again, these representations were false and misleading. While touting the Gulf of
Mexico as one of the critical areas of growth, BP omitted the fact that its operations in the Gulf of
Mexico were unsafe. The truth, as revealed by the cascade of systematic failures that resulted in
the Deepwater Horizon disaster, shows that the above-mentioned statements were not true. BP
did not have in place a mechanism for conducting operations in a safe and reliable manner, which
made an incident of this nature virtually inevitable. These facts were not disclosed.
399. BP’s 2009 Form 20-F also included the following representations:
Safety
Safety, people and performance are BP’s top priorities. We constantly seek to
improve our safety performance through the procedures, processes and training
programmes that we implement in pursuit of our goal of ‘no accidents, no harm to
people and no damage to the environment.’
In 2009, a third-party-operated helicopter carrying contractors from BP’s Miller
platform crashed in the North Sea resulting in the tragic loss of 16 lives. In
addition, BP sustained two fatalities within our own operations, one, when a rig
worker was lost overboard during drilling operations in Azerbaijan and a second,
in a crush injury on a well pad in Alaska.
We deeply regret the loss of these lives.
138 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 146 of 150
Safety and operational performance
In 2009, BP’s safety record continued to improve, as indicated by measures of
personal safety including reported recordable injury frequency (RIF) and days away
from work case frequency (DAFWC).
Our overall RIF of 0.34 was significantly lower than the rate of 0.43 in 2008 and
0.48 in 2007. Our DAFWCF was 0.069, an improvement on the level of 0.080 in
2008.
In 2009, eight work-related major incidents were reported, compared with 21 in
2008. Major incidents include incidents resulting in fatalities, significant property
damage or significant environmental impacts. All fatalities and other major
incidents and many that have the potential to become major incidents, are
discussed by the group operations risk committee (GORC), chaired by the group
chief executive. Our mandatory internal requirement to undertake incident
investigations seeks to ensure that we learn as much as possible from each incident
and take action to prevent re-occurrence.
There were 234 oil spills of one barrel or more reported in 2009, a significant
reduction on the 335 spills that occurred in 2008. The reported volume of oil
spilled in 2009 was approximately 1,191 million litres, a reduction of 65%
compared with 2008.
This performance follows several years of intense focus on training and procedures
across BP. BP’s operating management system (OMS), which provides a single
operating framework for all BP operations, is a key part of continuing to drive a
rigorous approach to safe operations. 2009 marked an important year in the
continuing implementation of OMS.
Safe, reliable and responsible operations
Having been introduced at eight operating sites in 2008, implementation of the
OMS gathered pace in 2009. The system was up and running at 70 operations
across the business by the end of the year, including all our operated refineries and
petrochemicals plants. This represents around 80% of the operations for which
OMS implementation is planned, with the remainder scheduled to be live by the
end of 2010.
Taking a systematic approach is integral to improving safety and operating
performance in every BP site. Our OMS covers all areas from process safety, to
personal health, to environmental performance. By applying consistent principles
and processes across the BP group’s operations, the system provides for an
integrated and consistent way of working. These principles and processes are
139 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 147 of 150
designed to simplify the organization, improve productivity, enable consistent
execution and focus BP on performance.
Capability development
Having built a safety and operations learning framework to enhance the capability
of our staff to deliver safe, reliable, responsible and efficient operations, we
defined target populations for these programmes more accurately in 2009.
More than 2,700 front-line operational leaders across our global operations have
started one or more of the modules within the Operating Essentials programme
which seeks to embed the BP way of operating as defined by OMS. Our
Operations Academy (OA), a partnership with the Massachusetts Institute of
Technology (MIT), is also now well established. Seven cadres of senior operations
staff have already attended this academy and three of these have graduated: all are applying their learning and having a deep influence in the operations community.
We also have an Executive Operations Programme which has continued to support
the executive team and senior business leaders in the development of their unique
operations capability requirements.
Process safety management
We continued to implement the 2007 recommendations made by the BP US
Refineries Independent Safety Review Panel (Panel), which following the incident
at Texas City in 2005, reviewed process safety management at our US refineries
and our safety management culture.
In accordance with those recommendations, we appointed an Independent Expert
for a five-year term to monitor their implementation. We again co-operated closely
with the Independent Expert in 2009, providing him access to our sites, personnel
and documentation and routinely supplying him with progress reports. In the
Independent Expert’s second annual report, published in 2009, he acknowledged
BP’s sustained focus on its safety and operations agenda and the priority given by executive management and the board to safe, reliable and responsible operations.
The report identified areas for continued focus and highlighted the progress made
in several areas, including the development of capability programmes, OMS
implementation, safety and operations auditing, and the improvement of metrics to
monitor process safety performance. During the course of 2009, we also provided
regular progress updates to the Safety, Ethics and Environment Assurance
Committee of the board.
See Legal proceedings on pages 95-96 in respect of ongoing Texas City refinery
matters.
140 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 148 of 150
By the end of 2009 our safety and operations audit team had audited a total of 94
BP businesses, including all major operating sites, within a three-year period. The
audits, which in 2009 included pilot audits for analysis against the requirements of
the OMS, have provided a rigorous process for assessing our businesses against
BP’s relevant standards and requirements.
We also participated in industry-wide forums on process safety. We chaired the
API/ANSI multi-stakeholder group developing a standard for public reporting of
leading and lagging process safety indicators. Through this and other bodies, we
shared our learning with other organizations within and outside the oil and gas
industry.
‘Six-point plan’
Our efforts on process safety included taking action to close out our six-point plan for
process safety, which was launched in 2006 to address immediate priorities for improving
process safety and minimizing risk at our operations worldwide. We have either
completed the required actions or integrated the few continuing requirements within the
OMS, for tracking to completion. We established a clear approach for future monitoring
of these within the internal HSE & Operations Integrity Report. This report, which is the
key source of management information relating to safety and operations in BP, is prepared
quarterly for the GORC.
400. These statements were false and misleading or omitted material facts necessary to
make other statements not misleading. While highlighting the rewards of its Gulf of Mexico
operations, BP actively hid the risks and dangers, the failure to implement appropriate safety
measures, and its abdication of appropriate risk management.
H. MARCH 22, 2010 HOWARD WEIL CONFERENCE
401. On March 22, 2010, less than a month before the Deepwater disaster,
Defendant Inglis spoke at the Howard Weil Conference in New Orleans. His prepared remarks
include the following:
We are currently planning to make final investment decisions for 24 new major
projects in the next two years. Each project has been high-graded though our
project selection and progression process. They are concentrated in the Gulf of
Mexico, the North Sea, Azerbaijan and Angola – high margin production areas that improve the portfolio and enable profitable growth.
141 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 149 of 150
Safety and operational integrity underpins everything we do , and we are now
in the final phase of rolling out our operating management system that provides
a single, consistent framework for our operations, covering all areas from personal
and process safety to environmental performance. And I am pleased to say that in
2009 we saw continuing improvement in all aspects.
402. While it was true that BP was concentrating in particular areas, including the Gulf
of Mexico, as described above, according to a former BP senior employee with Gulf Operations
responsibilities, it was not true that BP was in the final stages of rolling out their operations
management system, at least with respect to the Gulf of Mexico, nor was it true that safety
underpinned everything BP did. In fact, in the Gulf of Mexico, BP had only begun to implement
its OMS in a pilot stage when it terminated and/or displaced the key employees responsible for its
implementation. As such, the statements above were false and misleading or omitted material
facts necessary to make other statements not misleading.
403. While touting the huge growth potential of the Gulf of Mexico, Defendant
Hayward, on behalf of BP, concealed the fact that there were rampant safety problems in the Gulf
of Mexico, which were known to BP. BP’s representation that it could deliver huge profits in a
safe and reliable manner, while concealing known dangers in that area, was intended to and did
induce investors such as the Plaintiffs to invest in BP securities.
404. Moreover, approximately four to five weeks prior to the Deepwater Horizon
incident, chunks of the annular on the blowout preventer had broken off and floated to the surface.
BP also knew in the weeks and months prior to the incident that the battery on the blowout
preventer was weak and one of the control pods on the blowout preventer was broken. According
to engineering expert Robert Bea, a malfunctioning control pod is “like losing one of your legs.”
142 Case 4:10-md-02185 Document 112 Filed in TXSD on 02/11/11 Page 150 of 150
405. Therefore, BP’s knowledge of these facts rendered its statements false and
misleading.
I. CODE OF CONDUCT
406. BP published in its public filings its “Code of Conduct.” BP’s Code of Conduct
states, in pertinent part:
BP is committed to providing all BP employees – and those of other companies
working on our premises – with a safe and secure work environment where no one
is subject to unnecessary risk.
We recognize that safe operations depend not only on technically sound plant and
equipment, but also on competent people and an active HSSE culture. No activity
is so important that it cannot be done safely.
Simply obeying safety rules is not enough. BP’s commitment to safety means each
of us needs to be alert to safety risks as we go about our jobs. Basic rules you must follow.
Always
• Comply with the requirements of the HSSE management system at
your work location – including the use of relevant standards, instructions and processes – and with the golden rules of safety.
• Stop any work that becomes unsafe.
• Only undertake work for which you are trained, competent,
medically fit and sufficiently rested and alert to carry out.
• Make sure you know what to do if an emergency occurs at your place of work.
• Help ensure that those who work with you – employees, contractors
and other third parties – act consistently with BP’s HSSE commitments.
• Promptly report to local BP management any accident, injury,
illness, unsafe or unhealthy condition, incident, spill or release of
material to the environment, so that steps can be taken to correct,
143 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 1 of 96
prevent or control those conditions immediately. Never assume that someone else will report a risk or concern.
• Seek advice and help if: – You are ever unclear about your HSSE
obligations. – You have a concern about a potential or actual breach of HSSE law or a BP HSSE requirement.
Never
• Undertake work when your performance is impaired by alcohol or other drugs, legal or illegal, prescribed or otherwise.
• Possess, use or transfer illegal drugs or other substances on company premises.
• Use threats, intimidation or other violence at work, or bring
weapons – including those carried for sporting purposes – onto
company premises
Wherever we operate, we will strive to minimize any damage to the environment
arising from our activities.
407. The statements referenced above were false and misleading because among other
reasons, (1) BP was unprepared for a catastrophic disaster in the Gulf; (2) BP lacked sufficient
internal controls and risk management to insure environmental stewardship; and (3) its drilling processes were done safely to avoid environmental disasters.
J. 2009 SUSTAINABILITY REVIEW
408. On April 15, 2010, BP issued its online 2009 Sustainability Review. BP stated, in
relevant part:
• Our Values
BP is progressive, responsible, innovative and performance driven.
• Responsible
We are committed to the safety and development of our people and the
communities and societies in which we operate. We aim for no accidents, no harm
to people and no damage to the environment.
144 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 2 of 96
• Performance Driven
We deliver on our promises through continuous improvement and safe, reliable
operations.
These values guide us in the conduct of our business. In all our business we expect
our people to meet high ethical standards and to act in accordance with our code of
conduct.
• Group Chief Executive's Review
Question: What progress has BP made on safety during 2009?
Answer : Safety is fundamental to our success as a company and 2009 was
important because of the progress we made in implementing our operating
management system (OMS). The OMS contains rigorous and tested processes
for reducing risks and driving continuous improvement. I see it as the foundation
for a safe, responsible and high-performing BP. Having been initially introduced
at eight sites in 2008, the OMS rollout extended to 70 sites by the end of 2009,
including all our operated refineries and petrochemicals plants. This means
implementation is 80% complete. I’m proud that our injury rates have come down around 75% in the past decade.
• How We Operate
Risk Management
Group risks – the significant risks that could affect the achievement of our
objectives – have responses designed to deal with them in the most appropriate
way. These include our operating management system for delivery of safe,
responsible and reliable operating activity, and group standards, which set out
processes for other major areas such as investment decisions or fraud and misconduct reporting.
The group chief executive’s (GCE) senior team – known as the executive team – is
supported by sub-committees to be responsible for and monitor specific group
risks. These include the group operations risk committee, the group financial risk
committee and the group people committee. The GCE also conducts regular
performance reviews with the business segments and key functions to monitor
performance and the management of risk and to intervene if necessary.
145 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 3 of 96
People Management
People management is based on performance objectives through which individuals
are accountable for delivering specific elements of the group plan within agreed boundaries.
Clear lines of communication exist for the provision of relevant information to
help ensure all people are clear on what is expected of them and are up to do their
job. Employees can raise concerns with line managers, human resources, legal or compliance teams or through OpenTalk, and independent confidential helpline.
• Diverse and affordable energy
Working at the fronteirs
BP works at the geographical and technological frontiers of the energy industry. We have
decades of experience of using cutting-edge skills and technology to undertake complex
oil and gas projects in many of the world’s most technically challenging and hostile
environments, such as the Arctic and ultra deepwater. Recent innovations include new
technologies to increase recovery from mature oil fields and advanced seismic techniques
that create highly detailed images of reservoir formations miles below the surface. One of
our recent finds, the Tiber field in the Gulf of Mexico , was made by drilling a well 31,000
feet into the earth in water 4,000 feet deep.
Deepwater exploration
BP has substantial deepwater assets around the world, including the Gulf of Mexico ,
Angola and Brazil (pending closure).
• Safe And Responsible Energy
Safety, People and Performance
Safety, people and performance are BP's top priorities.
Our commitment to safe and reliable operations starts with the group chief
executive and leadership: a commitment that filters down through the organization and is regularly communicated to all staff.
All fatalities, other major incidents and many that had the potential to become
major incidents are discussed by the group operations risk committee, chaired by
the group chief executive. We undertake incident investigations with the aim of learning as much as possible and taking action to prevent recurrence.
146 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 4 of 96
We constantly seek to improve our personal, process and transportation safety
performance through the use of established processes, ongoing capability development and knowledge sharing with other organizations.
Personal Safety and Health
Creating a safe and healthy working environment is essential for our success.
• Operating Skills and Knowledge
Our safety and operations learning framework enhances the capability of our staff at all levels to deliver safe, reliable, responsible and efficient operations.
Our Operations Academy helps senior operations leaders learn to manage
operations in a way that eliminates defects and drives continuous improvement, not
only taking actions themselves, but empowering front-line employees to be agents
of change. Executive Operations sessions support the executive team and senior business leaders in the development of operations capability specific to their role.
“I am extremely proud of BP's 2009 safety performance – it reflects a sustained effort across all our operations over many years.” – Tony Hayward
• Managing Our Impact
We aim to minimize our environmental impact by taking a systematic and
disciplined approach to operations, using sophisticated risk assessment techniques that directly inform our business plans.
• Our People
People are fundamental to our progress in BP. Our performance and our safety
record depend on our employees' skill and commitment. We therefore organize,
manage and reward employees in ways designed to achieve the best possible performance, today and for the long term.
• Compliance and Ethics
BP’s reputation, and therefore its future, depends on every BP employee,
everywhere, every day, taking personal responsibility for ethical and compliant
business conduct. It is a fundamental BP commitment to comply with all
applicable legal requirements and adhere to high ethical standards.
409. The above referenced statements were materially false and misleading when made
because Defendants failed to disclose the following facts of which they were aware or were
147 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 5 of 96
reckless in not being aware of: (1) BP had failed to implement adequate safety procedures; (2) BP
conducted its operations in the Gulf without any legitimate oil spill response plan; (3) BP
understated its exposure from drilling operations in the Gulf; (4) BP lacked adequate internal and
safety controls; (5) BP’s Gulf Operations had failed to implement BP’s OMS in any robust
manner and the individuals responsible for its implementation had been terminated or moved
outside of Gulf Operations; and (6) BP’s highest officers had knowledge that its Gulf Operations
had caused oil spills in 2008 and two of its rigs (the Deepwater Horizon and the Atlantis) had
reported operational safety problems, which would have been reported to GORC and, as such, put
Defendants on notice of the inadequacy of their safety processes in the Gulf of Mexico.
K. 2009 SUSTAINABILITY REPORT
410. On April 15, 2010, BP issued its 2009 Sustainability Report. BP stated, in relevant
part:
• A Systematic Approach
BP constantly seeks to improve its safety performance through the
procedures, processes and training programmes that we implement in pursuit
of our goal of no accidents, no harm to people and no damage to the
environment.
Our commitment to safe, reliable and responsible operations starts with the group
chief executive Tony Hayward and his leadership team: a commitment that filters down through the organization and is regularly communicated to all staff.
Safety performance is a regular focus of the group chief executive's formal
communications such as BP's quarterly results and in less formal communications
such as his regular townhalls with BP staff. BP’s leadership has continued to
reinforce the importance of safety when undertaking regular site visits to BP facilities around the world and from all parts of the business.
“I am extremely proud of BP's 2009 safety performance – it reflects a sustained effort across all our operations over many years.” – Tony Hayward
148 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 6 of 96
Promoting Safe Operations
We are carrying forward our efforts on process safety, which is an integral part of
our operating management system (OMS) and ingrained within our capability
programmes. As participants in a second round of operations leadership sessions at
MIT this year, the group chief executive and his executive team were instrumental
in establishing the concept of continuous improvement to help drive systematic
safety and reliability in our operations. Continuous improvement is a means of
empowering our operations managers and supervisors, who are closest to our
operational problems, to develop the necessary solutions.
Taking Our Safety Pulse
We believe our focus on changing BP's safety culture over the last few years is
yielding results . To measure how effectively we have embedded our safety
message in the organization, we assess employee views on various dimensions of
safety within the ‘Pulse plus” survey.
Responses suggest continued progress in integrating safety into our business, with
98% of those surveyed saying they know how to do their job safely. Positive
responses have also been received to questions regarding confidence in line
management making safety a priority (82% compared with 80% in 2008), being
open to suggestions for improving safety performance (87%, from 81% in 2008) and being receptive to honest information about safety (98% versus 97% in 2008).
In a new question on whether employees have seen evidence that BP is making
progress in improving the safety and reliability of its operations, 76% gave a
positive response.
• Striving for Safe Operations
BP continues to implement its operating management system (OMS), a cornerstone
of achieving safe, reliable and responsible operations at every BP operation.
Taking a systematic approach is integral to improving safety and operating
performance in BP operated sites. Our operating management system covers all
areas from process safety, to personal health, to environmental performance.
A Unifying Way of Operating
We have successfully introduced OMS at every refinery worldwide in advance of
the internal expectations. Hugh Parsons, Vice President with responsibility for
management processes in refining states that "the OMS framework has given us a
common path, applicable across different sites and assets worldwide. It has
provided a unifying way of operating. This is true not only for refining but across
149 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 7 of 96
the whole of BP, where we have a much clearer definition of what ‘good
operations' looks and feels like, regardless of the business context."
• Safety Performance
BP has well-developed systems, processes and metrics for reporting safety
performance in support of internal performance management and to enable
learning and public reporting .
Our Approach to Safety Reporting
Reported health and safety data is collected for all operations where BP has health
and safety management control. Data is not externally reported from units where
BP does not have operational control, such as part-owned entities and joint
ventures operated by others, including TNK-BP. If an incident occurs, it is
recorded locally by employees, contractors and management using our internal web-based data management system .
All fatalities, other major incidents and many that had the potential to
become major incidents are discussed by the group operations risk committee ,
chaired by the group chief executive . We undertake incident investigations with
the aim of learning as much as possible and taking action to prevent recurrence.
Detailed data is collected on all work-related incidents resulting in fatalities
involving employees, contractors or third parties. Incidents which cause injury or
illness to members of the workforce (employees and contractors) are recorded and
their severity categorized using definitions and guidance provided by the US
Occupational Health and Safety Administration (OSHA).
• Safety and Operations Audits
BP's safety and operations audits assess compliance with standards and the
effectiveness of operational risk management.
The audits provide a rigorous check on safety and operations programmes.
We categorize audit findings against pre-defined criteria agreed between the audit
team and the audited entity's leadership and, for identified issues, set remedial
corrective actions, including completion due dates. For the audit report findings,
the group audit team tracks actions, verifying that they have been completed and
using subject matter experts where necessary. Progress is reported quarterly, at
which time issues, such as overdue action closures, are highlighted to executive
management in the executive-level group operations risk committee. To date,
more than 10,000 actions have been generated, of which more than 70% have been verified as closed.
150 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 8 of 96
We’ve developed the audit process and protocols to enable auditing against the
requirements in our operating management system (OMS). We’ve also developed
and delivered a training programme to prepare auditors for auditing against OMS
and its associated practices and are completing the modification of all relevant information management systems.
Our safety and operations audit team, which is independent from the businesses
they review, has, as planned, identified key sites and audited their performance. In
the three-year period to the end of 2009, the team completed a full cycle of audits,
covering 94 BP operations. This work, which in 2009 included pilot audits for
analysis against the requirements of the OMS, has provided a rigorous process for
assessing our businesses against BP's relevant standards and requirements.
• Process Safety
BP is fully committed to becoming a recognized industry leader in process
safety management and continues to work to achieve this.
Process safety involves applying good design principles, engineering and operating
and maintenance practices to manage our operations safely.
Process Safety Reporting
To track our progress in process safety management, we measure lagging
indicators which record events that have already occurred, such as oil spills, and
leading indicators that focus on the strength of our controls to prevent undesired
incidents, such as inspections and tests of safety-critical equipment .
• Oil Spills
BP recognizes the risk posed to the environment from spills and takes a range
of measures to prevent any loss of hydrocarbons .
Our approach
Our strategy to address spills has three components:
Prevention: we seek to assure the integrity of vessels and pipelines used to
transport oil and other hydrocarbons.
Preparation: we seek to ensure an infrastructure is in place to deal effectively
with spills and their impacts. Our operating facilities have the capacity and
resources to respond to spill incidents and we participate in industry and
151 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 9 of 96
international forums to coordinate contingency planning and emergency
response.
Performance: we record incidents, learn lessons and aim to reduce the number of
losses from primary containment.
Incidents are recorded locally by our staff and contractors using our web-
based incident tracking system. BP’s executive management is notified
quarterly about numbers and volumes of spills and spills of more than 100
barrels.
411. The above referenced statements were materially false and misleading when made
because Defendants failed to disclose the following facts of which they were aware or were
reckless in not being aware of: (1) BP had failed to implement adequate safety procedures; (2) BP
conducted its operations in the Gulf without any legitimate oil spill response plan; (3) BP
understated its exposure from drilling operations in the Gulf; (4) BP lacked adequate internal and
safety controls; (5) BP’s Gulf Operations had failed to implement BP’s OMS in any robust
manner and the individuals responsible for its implementation had been terminated or moved
outside of Gulf Operations; and (6) BP’s highest officers had knowledge that its Gulf Operations
had caused oil spills in 2008 and two of its rigs (the Deepwater Horizon and the Atlantis) had
reported operational safety problems, which would have been reported to GORC and, as such, put
Defendants on notice of the inadequacy of their safety processes in the Gulf of Mexico.
412. Moreover, Defendant Hayward chaired GORC and Defendant Inglis was a
member. As detailed above, the BP Gulf Rig Atlantis caused an oil spill in 2008 and raised
concerns of safety critical equipment on the Atlantis that according to BP’s statements would have
been received and reviewed by Hayward and Inglis. Additionally, as detailed above safety critical
equipment on the Horizon was tested and inspected prior to the spill and the results of these tests
and inspections according to BP’s own statements, would have been communicated to GORC.
152 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 10 of 96
413. Despite having knowledge of safety process problems in the Gulf of Mexico,
including knowledge of oil spills, safety-critical equipment failures on two Gulf Rigs, and safety
process concerns in the Gulf during the Subclass Period, BP issued false and misleading
statements related to the safety process strength of BP’s Gulf Operations. Defendants, including
but not limited to Hayward and Inglis, had knowledge of BP’s Gulf of Mexico safety and
operational problems, yet touted the huge growth potential of the Gulf of Mexico, concealing the
massive safety problems that existed in the Gulf of Mexico, which were known to BP.
VII.
LOSS CAUSATION
414. During the Subclass Period, as detailed herein, the Defendants engaged in a
scheme to deceive the market and in a course of conduct that artificially inflated the value of BP
securities, including ADRs, and operated as a fraud or deceit on members of the Subclass by
misrepresenting the Company’s risk management and safety processes.
415. As a result of the Individual Defendants’ fraudulent conduct as alleged herein, the price of BP securities, including ADRs, was artificially inflated throughout the Subclass Period.
When Lead Plaintiffs and other members of the Subclass purchased their securities, the true value
of such securities was substantially lower than the prices actually paid. When the truth about BP’s
safety operations and risk management was revealed to the market, the price of BP securities
declined in response, as the artificial inflation caused by BP’s material omissions and false and
misleading statements were removed from the price of BP’s securities, thereby causing substantial
damage to Plaintiffs and other members of the Subclass.
153 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 11 of 96
416. Defendants’ false and misleading statements set forth above were widely
disseminated to the securities markets, investment analysts, and to the investing public. Those
statements caused and maintained the artificial inflation of the price of BP’s securities, which
consequently traded at prices in excess of their true value. As a result of the Deepwater Horizon
spill, which revealed the truth about BP’s disregard of risk management and safety practices, BP’s
shares have lost a substantial percentage of their value. For example, on April 20, 2010, the price
of one BP ADR was approximately $59. Within a week, the share had dropped to approximately
$50. The price continued to plunge in response to the further materialization of the true state of
Defendants’ Gulf of Mexico safety operations and risk management.
154 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 12 of 96
417. It was entirely foreseeable that concealing the true state of BP’s safety and risk management procedures in the Gulf of Mexico would artificially inflate the price of BP securities.
It was similarly foreseeable that the ultimate revelation of the true condition of BP’s safety and
risk management procedures operation in the Gulf of Mexico would cause the price of BP securities to drop significantly as the inflation caused by their misstatements was corrected.
Accordingly, the conduct of the Defendants, as alleged herein, proximately caused foreseeable
damages to Plaintiffs and members of the Subclass.
418. Plaintiffs purchased their shares of BP in reliance on BP’s statements that they had
implemented appropriate risk management and safety mechanisms to reduce the risk that
catastrophic and expensive disasters such as the Deepwater Horizon would occur, and if they did
occur, that BP’s exposure would be reduced because of such measures. It is now apparent,
however, that such mechanisms were not implemented. Therefore, Defendants’ wrongful conduct directly and proximately caused the economic loss suffered by Plaintiffs.
419. As explained herein, these false statements directly or proximately caused, or
were a substantial contributing cause of, the damages and economic loss suffered by Lead
Plaintiffs and other members of the Subclass, and maintained the artificial inflation in the prices
of BP securities throughout the Subclass Period and until the truth was revealed to the market.
VIII.
SCIENTER ALLEGATIONS
420. Appropriate safety and risk management procedures are at the core of BP’s drilling
operations, particularly in the Gulf. Accordingly, the implementation of appropriate safety and
risk management processes was a matter driven from the top of the organization. BP’s CEO and
155 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 13 of 96
Board of Directors were involved in both the day-to-day and strategic decisions relating to BP’s
procedures and protocols. Nevertheless, as detailed herein, Defendants took affirmative steps
which inhibited the ability of BP to implement appropriate safety processes, including but not
limited to, mandating budget cuts at the expense of safety processes, disregarding warnings from
BP employees and risk managers, and terminating or removing key Gulf Operators charged with
implementing safety processes in the Gulf.
421. Moreover, BP’s corporate structure mandated that BP’s officers and directors were
on notice of and has access to all material facts relating to the safety processes of BP’s Gulf
operations. Accordingly, Defendants knew or recklessly disregarded facts concerning the
inadequate safety and risk management practices in BP’s Gulf operations. For example, BP’s
senior management openly boasted of their personal commitment to such practices, and executive
officer and Board oversight of safety processes were described as a fundamental part of BP’s
corporate restructuring, particularly after Hayward became CEO and BP implemented the Baker
Report’s guidance on executive and Board oversight of corporate safety processes.
422. However, Defendants knowingly or recklessly disregarded these facts concerning
the safety of their Gulf of Mexico drilling operations. Additionally, confidential witnesses and
other investigations provide facts, described above, which further contribute to a strong inference
of scienter.
156 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 14 of 96
A. BASED ON THEIR CORPORATE ROLE AND MEMBERSHIP TO KEY BOARD
COMMITTEES, INDIVIDUAL DEFENDANTS HAD KNOWLEDGE OF BP’S
CONCEALED GULF OF MEXICO SAFETY PROBLEMS
1. SAFETY, ETHICS, AND ENVIRONMENT ASSURANCE COMMITTEE
423. BP’s Board has five committees, including an Audit Committee, Remuneration
Committee, Chairman’s Committee, Nomination Committee, and a Safety, Ethics, and
Environment Assurance Committee (“SEEAC”) committee. SEEAC was formerly known as the
Ethics and Environment Assurance Committee, but in 2005, following the Texas City disaster,
added “Safety” as a focus. As stated above, Defendant Castell is the current Committee chairman.
424. SEEAC is composed of independent non-executive directors and is charged with the oversight of health, safety, and environmental (HSE) matters.
425. According to BP’s Board Governance principles, SEEAC is charged with:
• Monitoring and obtaining assurance that the Group Chief Executive’s (“GCE’s”)
internal control system for operations is designed and implemented effectively in
support of his observance of the relevant Executive Limitations;
• Monitoring and obtaining assurance that the management or mitigation of
significant BP risks of a non-financial nature is appropriately addressed by the
GCE;
• Receiving and reviewing regular reports from the GCE or his delegate, the Group
Internal Auditor and the Group Compliance and Ethics Officer regarding the
GCE’s adherence to the relevant Executive Limitations and his management in
responding to risk;
157 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 15 of 96
• Reviewing material to be placed before shareholders which addresses
environmental, safety and ethical performance and make recommendations to the
Board about their adoption and publication;
• Reviewing reports on the Group’s compliance with its Code of Conduct and on the
employee concerns programme (OpenTalk) as it relates to non-financial issues; and
• Recommending to the Board any changes or further delineation of the Executive
Limitations in relation to non-financial matters
426. Defendants Castell, Anderson, Burgmans, Carroll and Davis are all directors of BP
and members of BP’s Safety, Ethics and Environment Assurance Committee. These directors are
responsible for making both day-to-day and strategic decisions regarding safety for BP and for
monitoring that those safety mechanisms were implemented . As a result, these Defendants had
knowledge of and access to, or recklessly disregarded, BP’s safety problems in the Gulf of
Mexico, which were concealed from Plaintiffs.
2. GROUP OPERATIONS RISK COMMITTEE
427. In 2007, BP created a GORC, which consisted of BP executives. During the
Subclass Period, GORC was chaired by BP’s then-CEO and Board member Hayward. Defendant
Inglis was also a GORC member. GORC was expressly charged with reviewing and analyzing
safety incidents in BP’s operations and regularly reporting SEEAC. GORC was charged with
providing process safety oversight by conducting regular reviews of incidents , detailed
examinations of safety-related activities , and identifying areas for additional focus .
428. GORC consisted of BP executives and was at all relevant times chaired by BP’s
then-CEO and Board member Hayward, and it included Defendant Inglis. GORC was expressly
158 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 16 of 96
charged with analyzing safety incidents in BP’s operations. According to BP, GORC would have
regularly been provided analyses and data, including compliance violations, fines and penalties,
and government reportable incidents. Thus, members of GORC had access to facts concerning the true nature of the safety and risk of BP’s Gulf of Mexico operations.
429. The flow chart below (from BP’s 2009 Annual Report) shows how all the pieces fit
together to support BP’s goal of “no accidents, no harm to people, and no damage to the
environment.”
3. BP’S INTERNAL REPORTING STRUCTURES MANDATED THAT GULF
SAFETY PROBLEMS REACHED THE EXECUTIVE AND BOARD
LEVEL
430. According to BP’s 2009 Form 20-F Annual Report, BP’s safety and operations
agenda was given the highest priority by executive management and the Board to ensure the
Company operated safely, reliably and responsibly. BP purportedly implemented, among other
159 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 17 of 96
means of reporting, safety and operations auditing and metrics to monitor process safety
performance and regular progress updates to SEEAC . BP further claimed that it possessed
well-developed systems, processes and metrics for reporting safety performance in support of
internal performance management and to enable learning and public reporting.
431. Additionally, all fatalities, other major incidents and incidents that had the
potential to become major incidents were discussed by the GORC, chaired by the GCE for the
purpose of undertaking incident investigations with the aim of learning as much as possible and
taking action to prevent recurrence.
432. Further, health and safety data was collected and should an incident occur, it would
be recorded locally by employees, contractors and management using our internal web-based
data management system. Any reported incidents, including the problems on the Gulf Rigs
Atlantis and Deepwater Horizon, would have been reviewed or recklessly disregarded by GORC
and communicated to SEEAC. As such all Defendants would have access to, and knowingly or
recklessly disregarded, information related to the endemic safety problems BP faced in the Gulf of
Mexico during the Subclass Period.
433. According to BP’s 2009 Sustainability Report, to track its progress in process
safety management, it recorded events such as oil spills (those in excess of 100 barrels, e.g
Atlantis). Also leading indicators that focused on the strength of BP’s controls to prevent
undesired incidents, such as inspections and tests of safety-critical equipment , would have been
measured and elevated to executive management through BP’s web-based incident tracking
system. As such, BP’s executive management knowingly or recklessly disregarded the Gulf of
Mexico safety incidents that were occurring during the Subclass Period. Deposition testimony of
160 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 18 of 96
a senior BP safety employee, whose name and exact title are withheld pursuant to the
confidentiality agreements entered in both this action and MDL 2179, testified that an internal database was utilized and was accessible for all recorded safety incidents.
434. As confirmed by a BP safety analyst in deposition testimony from the MDL 2179,
high potential incidents like those described above, including incidents during the Subclass
Period, would have been reviewed at the Board level. The deponent’s name and exact title are
withheld from this Complaint due to Confidentiality Agreements in both this action and the MDL
2179 action. This witness confirmed that he had prepared reports regarding safety incidents that were delivered to the Board or to a Board representative.
435. Additionally, according to a senior member of the BP internal audit team, whose
name and exact title are withheld pursuant to the confidentiality agreements entered in both this
action and MDL 2179, the Gulf of Mexico Operations were audited by a safety and operational
risk audit team, which would have reported to the BP, plc audit committee of which Defendant
Davis, Jr. was a member. The audit committee in turn had reporting responsibilities to the full
Board. Given the myriad safety and operational risk complaints on both the Atlantis and
Deepwater Horizon, including but not limited to the complaints raised by Ken Abbott set forth
above, the true state of the operational safety and risk of the Gulf of Mexico Operations was known or recklessly disregarded by Defendants.
B. DEFENDANTS KNOWINGLY OR RECKLESSLY DISREGARDED FACTS
THAT BELIED THEIR STATEMENTS CONCERNING THE SAFETY OF THEIR
GULF OPERATIONS
436. During the Subclass Period, Defendants had both the motive and opportunity to
commit fraud. For example, under the executive compensation policies adopted by the Board,
161 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 19 of 96
70% of Defendant Hayward’s performance bonus in 2009 would be based on the achievement of
financial metrics and no bonus based process safety.
437. They also had actual knowledge of the misleading nature of the statements they
made or acted in reckless disregard of the true information known to them at the time. In so
doing, Defendants participated in a scheme to defraud and committed acts, practices and
participated in a course of business conduct that operated as a fraud or deceit on purchasers of BP
securities (as set forth herein) during the Subclass Period.
438. At the time of making (and/or adopting) the above referenced misrepresentations
and omissions regarding BP’s internal safety operations, Defendants were aware of facts and
knowingly or recklessly disregarded facts that belied these statements and the omission of which
facts made those statements misleading. In addition to the facts set forth above which show the
falsity of Defendants’ statements (and thus also show scienter in making those statements), the
facts below support a strong inference of scienter.
439. As Defendants had knowledge that the Gulf of Mexico was a key driver for BP and
the documents (many of which were signed or attested to by top officers and directors), testimony,
and confidential statements cited above show, BP had publically stated that new exploration in the
Gulf of Mexico was critical to BP’s growth and success and that it could achieve those results in a
safe manner.
440. However, Defendants also knew that BP had systemic problems relating to its
safety and risk management practices in the Gulf. Evidence of this knowledge is shown as
follows:
• Internal communications by project managers to senior staff in BP that, in the Gulf
of Mexico, project managers and engineers were submitting out-dated information
162 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 20 of 96
that violated BP’s Code of Conduct and created a serious risk of a catastrophic
disaster. This includes the April 15, 2008 Duff e-mail.
• An internal BP presentation in May 2009 citing a shortage of experienced offshore
workers and stating that more training was required to “maintain safe, reliable and efficient operations.”
• In the months leading up the Deepwater Horizon, BP not only knew about
problems on the oil rig, it was BP senior managers who gave direct orders that put
profit and speed before safety. Those orders are one of the principal causes of the
Deepwater Horizon disaster. These facts were concealed and not disclosed to BP
shareholders.
• Defendants Hayward’s and Inglis’ involvement in GORC meant that the Gulf Rig
Atlantis problems were communicated to them. Additionally, as detailed above,
safety critical equipment on the Deepwater Horizon was tested and inspected prior
to the spill, and the results of these tests and inspections, according to BP’s own statements, would have been communicated to GORC.
• GORC members, including Defendants Hayward and Inglis would have received
safety process information via the internal web-based data management system and
as such would have or should have had knowledge regarding the Gulf problems,
including but not limited to the Atlantis and Deepwater Horizon rigs detailed
above.
• BP’s Ombudsman and an independent firm hired by BP 2009 confirmed that BP
failed to complete essential engineering documents and was thereby violating its
own policies on the Gulf Rig Atlantis.
• BP terminated or displaced the highest ranking employees responsible for Gulf of
Mexico Operations in the fourth quarter of 2009 and first quarter of 2010, for among other reasons, concerns these individuals raised related to process safety.
• A December 2008 internal BP strategy document BP strategy document warned
Defendants that BP still did not adequately plan for serious safety risks for its
operations in the Gulf. The document warned that senior management’s failure
to address this shortcoming could result in “multiple injuries/fatalities,” “major
environmental damage,” “catastrophic loss of the facility,” and “damage to corporate reputation.”
• Delayed maintenance on the Deepwater Horizon sister rig because of a tight cost budget which led to a minor oil spill in the Gulf.
163 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 21 of 96
• Some of the same equipment BP had been found to have negligently allowed to
deteriorate at Prudhoe Bay for emergency shutdown, including safety shutoff
valves and gas and fire detectors were found to be lacking and could have helped
prevent the fire and explosion on the Deepwater Horizon.
• BP could have drilled the hole with a “liner” which would have reduced the
blowout risk, but this was rejected because it was slower and up to $10 million
more expensive.
• An internal BP document (Forward Plan Review) recommending against the long
string option because of the risks: “Long string of casing was the primary option” but a “Liner/Tieback . . . is now the recommended option.”
• Advance testing by engineers from Halliburton and BP determining the
unreliability of cementing with a long string production casing. The cementing
experts recommended a shift to a Liner, but that recommendation was resisted by BP.
• Internal BP emails from late March 2010 acknowledged the risks of the Long String design but chose it as the primary option because it “saves a lot of time . . .
at least 3 days,” “saves a good deal of time/money,” and is the “[b]est economic
case.”
• BP’s Senior Management’s selection of six centralizers versus the original
designed 21 to save 10 hours. Six centralizers were selected despite advance
testing by Halliburton which concluded that 21 centralizers was the recommended
number to ensure a secure cement job; using 10 would result in a “moderate” gas flow problem and using only six would result in a “severe” gas flow problem.
• Advance knowledge of three failed negative pressure tests at Macondo and BP’s
admission that these pressure test results were clear warning signs of a “very large
abnormality” in the well.
• BP’s knowledge that the manufacturer of Deepwater Horizon’s blowout
preventer’s had a history of blowout preventer failures. Nevertheless, BP used that manufacturer’s blowout preventer on the Deepwater Horizon.
• Previous disputes with the manufacturer of the blowout preventer that failed on the
Deepwater Horizon concerning blowout preventers.
• A 2004 study by federal regulators showed that blowout preventers may not
function in deepwater drilling environments because of increased force. BP knew
that better blowout preventers were needed for the Deepwater Horizon but
consciously chose not to install them.
164 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 22 of 96
• An MMS study noted that blowouts during cementing work were continuing with
alarming regularity, particularly in the Gulf of Mexico. Cementing was a factor in
18 of 39 well blowouts in the Gulf of Mexico between 1992 and 2006.
• Halliburton, BP’s Deepwater Horizon joint venturer, was responsible for
cementing a well off the coast of Australia that blew in August 2009, leaking oil
for ten weeks before it was plugged. An MMS official has testified that a poor
cement job likely caused the blowout.
• April 6, 2009, letter from MMS to BP indicating risks of drilling at the Macondo
well.
• BP drilling at a depth in excess of the MMS permitted depth despite knowledge the
threat of blowouts increases as drilling depths increase, especially in an area with
such troublesome geology as the Northern Gulf of Mexico and advance warnings
of the same by the MMS.
• BP’s determination, against API guidance and Halliburton recommendation not to
do a “bottoms up circulation” to save time and money.
• Failure to pay for a $128,000 bond long.
• BP’s mandate for 7% reductions in costs for all of its drilling operations in the Gulf
of Mexico.
• Under Hayward’s stewardship, BP slashed $4 billion in expenses in2009 and spent
0.0033 percent of BP revenues on research and development regarding safer
offshore drilling technologies.
• An internal BP audit confirmed safety process problems and outstanding safety
items on the Deepwater Horizon but instead of improving safety on the oil rig,
made efforts to further cut costs.
• A September 2009 BP audit team finding that the Deepwater Horizon suffered from excessive overdue maintenance totaling 390 jobs and 3,545 man hours.
Thirty-one of which included findings that were related to well control system
maintenance, and six related to BOP maintenance. All findings were outstanding
as of December 2009.
• Executive compensation policies where 70% of performance bonuses are based on
the achievement of financial metrics, and only 15% on safety (and not process safety).
165 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 23 of 96
• Congressional testimony by executives of four major oil companies testified that
they did not agree with BP’s methods of operations. “We would not have drilled the well the way they did” stated Exxon Mobil Chairman Rex Tillerson.
• Anadarko’s chief executive, Jim Hackett, stated “The mounting evidence clearly
demonstrates that this tragedy was preventable and the direct result of BP’s
reckless decisions and actions.” Hacket added that he was “shocked” to find that
BP “operated unsafely and failed to monitor and react to several critical warning
signs during the drilling of the Macondo well.
• Congressional testimony by Harry Thierens, BP’s vice president for drilling and
completions, wherein he stated he could not recall what BP had done to improve
safety after the Texas City explosion.
• BP Chief Operating Officer Doug Suttles’s admission that BP did not actually have
a response plan with “proven equipment and technology” in place that could
contain the Deepwater Horizon Spill.
• Defendant Hayward’s admission that “BP’s contingency plans were inadequate,” and that the company had been “making it up day to day.”
• Defendant McKay’s testimonial admission to the House Subcommittee on
Oversight and Investigations, Committee on Energy and Commerce, that BP did
not have the capability and technology to respond to the Deepwater Horizon oil
spill.
• Congressional findings that BP senior officials who were responsible for the
Macondo well were oblivious to the problems at the Macondo well.
• Findings of the NAE that BP “lack[ed] . . . a suitable approach for anticipating and
managing the inherent risks, uncertainties and dangers associated with deepwater
drilling operations” and “fail[ed] to learn from previous near misses.”
441. As a result of their positions with BP, Defendants either knew or were reckless in
failing to know each of the above facts.
166 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 24 of 96
C. CONFIDENTIAL WITNESSES AND GOVERNMENTAL INVESTIGATIONS
PROVIDE AN ADDITIONAL INFERENCE OF SCIENTER
442. As set forth above, confidential witnesses have confirmed that BP’s senior
management knew of systemic safety process problems prior to the Deepwater Horizon. These
witnesses confirm that safety process problems and solutions were submitted to BP’s Board of
Directors and were not implemented at its offshore operations. Moreover, CW2 confirms that
BP’s restructuring threatened the operational safety of BP’s Gulf of Mexico operations and that
this concern was known or should have been known by among other, Defendant Inglis.
443. In addition, lawsuits and/or investigations are now proceeding by the Department
of Justice and States’ Attorney Generals against BP and Defendants, which are further evidence of
scienter.
IX.
PRESUMPTION OF RELIANCE
444. Plaintiffs, representing the Subclass, relied on BP’s statements and would not have
purchased BP securities had they known of BP’s actual safety and risk management practices.
Plaintiffs are also entitled to a presumption of reliance under Affiliated Ute Citizens of Utah v.
United States, 406 U.S. 128 (1972), because the claims asserted herein are predicated in
part upon material omissions of fact that Defendants had a duty to disclose.
445. Additionally, Plaintiffs are entitled to a presumption of reliance on Defendants’
material misrepresentations and omissions pursuant to the fraud-on-the-market doctrine because,
at all relevant times, the market for BP securities, including ADRs, was open, efficient and well
developed. For example, with respect to BP ADRs:
167 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 25 of 96
• BP ADRs met the requirements for listing, and were listed and actively traded, on
the NYSE, a highly efficient market.
• As a regulated issuer of securities in the United States, BP filed Annual Reports on
Form 20-F with the SEC. These reports were publicly available and could be and
were reviewed by the investing public.
• BP ADRs were followed by securities analysts employed by major brokerage firms
who wrote reports which were distributed to the sales force and certain customers
of their respective brokerage firms. Each of these reports were publicly available
and entered into the public marketplace.
• BP regularly issued press releases that were carried by national newswires. Each
of these releases was publicly available and entered the public marketplace.
446. As a result, the market for BP securities promptly digested current information
with respect to BP from all publicly-available sources and reflected such information in BP’s
stock price. The price of BP securities moved in direct response to information regarding the
company that was put out in the public marketplace. For example, the share price of BP ADRs
dropped significantly after the explosion on the Deepwater Horizon and the resulting discovery of
BP’s safety and risk management practices. Under these circumstances, all purchasers of BP
securities during the Subclass Period, including Plaintiffs, relied on the market price of BP
securities and suffered similar injury through their purchase of such securities at artificially
inflated prices and a presumption of reliance applies.
X.
INAPPLICABILITY OF THE STATUTORY SAFE HARBOR
447. The statutory safe harbor provided for forward-looking statements under certain circumstances does not apply to any of the allegedly false statements pleaded in this complaint.
The statements alleged to be false and misleading concerned statements of existing or historical
fact or conditions. Additionally, to the extent that any of the statements alleged to be false and
168 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 26 of 96
misleading may be deemed to be forward looking statements, the Defendants are nevertheless
liable for those statements because they were not identified as forward looking statements or, even
if so identified, the statements were material. They were not accompanied by meaningful
cautionary statements identifying important factors that could cause actual results to differ
materially from those in the purportedly forward-looking statements. Additionally, at the time
each of those statements was made, the Defendants had actual knowledge that the particular
forward-looking statement was false or the forward looking statement was authorized and/or
approved by an officer or director of BP who knew that the statement was false when made. In
addition, to the extent that any of the statements set forth above were accurate when made, they
became inaccurate or misleading because of subsequent events, and the Defendants failed to
update those statements that later became inaccurate and/or did not disclose information that
undermined the validity of those statements.
XI.
CLAIMS FOR RELIEF
COUNT I.
VIOLATION OF SECTION 10(b) OF THE EXCHANGE ACT
AND RULE 10b-5 PROMULGATED THEREUNDER
(Against the BP Defendants McKay, Hayward, Svanberg and Inglis)
448. Plaintiffs hereby incorporate by reference all of the allegations set forth above as
though fully set forth hereafter.
449. During the Subclass Period, each of the Defendants carried out a plan, scheme and
course of conduct which was intended to and, throughout the Subclass Period, did deceive the
investing public, including Plaintiffs and other Subclass members, as alleged herein and caused
169 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 27 of 96
Plaintiffs and other members of the Subclass to purchase BP securities at distorted prices that they
would not have paid had they known of the improper conduct alleged herein. In furtherance of
this improper scheme, plan and course of conduct, Defendants, and each of them, took the actions
set forth herein.
450. Defendants: (i) employed devices, schemes, and artifices to defraud; (ii) made
untrue statements of material fact and/or omitted to state material facts necessary to make the
statements not misleading; and (iii) engaged in acts, practices, and a course of business which
operated as a fraud and deceit upon the purchasers of BP securities, including Plaintiffs and other
members of the Subclass, by making false and misleading statements and omitting material facts
regarding BP’s risk management and safety practices generally and specifically as to the Gulf of
Mexico. This was done in an effort to artificially inflate BP’s securities’ value in violation of
Section 10(b) of the Exchange Act and Rule 10b-5. All Defendants are sued as primary
participants in the wrongful and illegal conduct and scheme charged herein. These false
statements and omissions are set forth above.
451. Defendants, individually and in concert, directly and indirectly, by the use, means
or instrumentalities of interstate commerce and/or of the mails, engaged and participated in a
continuous course of conduct to make affirmative misrepresentations and conceal adverse
material information about BP’s safety record and earnings, as specified herein.
452. Defendants employed devices, schemes and artifices to defraud and a course of
conduct and scheme as alleged herein to improperly manipulate and profit and thereby engaged in
transactions, practices and a course of business which operated as a fraud and deceit upon
Plaintiffs and members of the Subclass.
170 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 28 of 96
453. As set forth above, Defendants had actual knowledge of the misrepresentations and
omissions of material facts set forth herein, or acted with reckless disregard for the truth in that
they failed to ascertain and to disclose such facts, even though such facts were available to them.
Defendants’ material misrepresentations and/or omissions were done knowingly or recklessly and
for the purpose and effect of inflating the market price of BP securities, including ADRs.
454. As a result of the dissemination of the materially false and misleading information
and failure to disclose material facts, as set forth above, the market prices of BP securities were
distorted during the Subclass Period such that they did not reflect the true financial health and risk
management and safety practices of BP as alleged herein. In ignorance of these facts, the market
prices of the shares were distorted, and relying directly or indirectly on the false and misleading
statements made by the Defendants, or upon the integrity of the market in which the securities
trade, and/or on the absence of material adverse information that was known to or recklessly
disregarded by Defendants but not disclosed in public statements by Defendants during the
Subclass Period, Plaintiffs and the other members of the Subclass acquired the shares or interests
in BP during the Subclass Period at distorted prices and were damaged thereby when the value of
their shares fell after the truth became known, representing the causal connection between
Defendants’ fraud and Plaintiffs’ damages.
455. At the time of said misrepresentations and omissions, Plaintiffs and other members
of the Subclass were ignorant of their falsity, and believed them to be true. Had Plaintiffs and
other members of the Subclass and the marketplace known of the truth concerning BP’s
operations, which were not disclosed by Defendants, Plaintiffs and other members of the Subclass
would not have purchased or otherwise acquired their shares or, if they had acquired such shares
171 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 29 of 96
or other interests during the Subclass Period, they would not have done so at the distorted prices
which they paid.
456. By virtue of the foregoing, Defendants violated Section 10(b) of the Exchange Act,
and Rule 10b-5 promulgated thereunder.
COUNT II.
VIOLATION OF SECTION 20(a) OF THE EXCHANGE ACT
(Against the Individual Defendants )
457. Plaintiffs hereby incorporate by reference all of the allegations set forth above as
though fully set forth hereafter.
458. It is appropriate to treat the Individual Defendants and BP as a group for pleading
purposes and to presume that the materially false, misleading, and incomplete information
conveyed in the BP public filings, press releases and other publications are the collective actions
of the Individual Defendants and BP.
459. The Individual Defendants acted as controlling persons of BP within the meaning
of Section 20(a) of the Exchange Act for the reasons alleged herein. By virtue of their operational
and management control of BP’s respective businesses and systematic involvement in the
fraudulent scheme alleged herein, the Individual Defendants named herein each had the power to
influence and control and did influence and control, directly or indirectly, the decision-making
and actions of BP, including the content and dissemination of the various statements which
Plaintiffs contend are false and misleading. Each of the Individual Defendants named herein had
the ability to prevent the issuance of the statements alleged to be false and misleading or cause
such statements to be corrected.
172 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 30 of 96
460. Each of the Individual Defendants named herein had direct and supervisory
involvement in the operations of BP and, therefore, did have the power to control or influence the
implementation of BP’s risk management and safety procedures for its oil exploration and
production operations, including those that relate to the Deepwater Horizon disaster that give rise
to the securities violations as alleged herein, and exercised the same.
461. Each of the Individual Defendants named herein, by virtue of their high-level
positions and participation in and/or awareness of BP’s operations, had the power to influence and
control and did influence and control, directly or indirectly, the decision-making of BP, including
the content and dissemination of the various statements that Plaintiffs contend are false and
misleading. The Individual Defendants were provided with or had unlimited access to copies of
BP’s reports, press releases, public filings and other statements alleged by Plaintiffs to be
misleading prior to and/or shortly after these statements were issued and had the ability to prevent
the issuance of the statements or cause the statements to be corrected. BP controlled the
Individual Defendants and all of its employees.
462. As set forth above, Defendants BP, McKay, Hayward, Svanberg and Inglis
violated Section 10(b) and Rule 10b-5 by their acts and omissions as alleged in this Complaint.
By virtue of their positions as controlling persons, each of the Individual Defendants is liable
pursuant to Section 20(a) of the Exchange Act. As a direct and proximate result of Defendants’
wrongful conduct, Plaintiffs and other members of the Subclass suffered damages in connection
with their purchases of BP securities during the Subclass Period at inflated prices and the losses
suffered when the value of their shares fell after the truth became known, representing the causal
connection between Defendants’ fraud and the damages suffered by Plaintiffs and the Subclass.
173 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 31 of 96
XII.
PRAYER FOR RELIEF
WHEREFORE, Plaintiffs, on behalf of themselves and the Subclass, pray for judgment as
follows:
1. Declaring this action to be a proper action pursuant to Rule 23 of the Federal Rules
of Civil Procedure on behalf of the Subclass defined herein;
2. Awarding Plaintiffs and all members of the Subclass damages against the
Defendants, jointly and severally, in an amount to be proven at trial;
3. Awarding Plaintiffs and members of the Subclass pre-judgment interest, as well as
reasonable attorneys’ fees and other costs;
4. Awarding such other relief as this Court may deem just and proper.
/ / /
/ / /
/ / /
174 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 32 of 96
XIII.
JURY TRIAL DEMAND
Plaintiffs, pursuant to Federal Rule of Civil Procedure 38, demand a trial by jury of all
issues which are subject to adjudication by a trier of fact.
Dated: February 11, 2011
By s/ Joseph W. Cotchett By s/ Richard W. Mithoff
COTCHETT, PITRE & McCARTHY MITHOFF LAW FIRM
Joseph W. Cotchett Richard W. Mithoff
Mark C. Molumphy Texas Bar Number: 14228500
Jordanna G. Thigpen William J. Stradley
Imtiaz A. Siddiqui Texas Bar Number: 19353000
Matthew K. Edling One Allen Center
840 Malcolm Road 500 Dallas Street
Burlingame, CA 94010 Houston, TX 77002
Telephone: (650) 697-6000 Telephone: 713-654-1122
Fax: (650) 697-0577 Fax: 713-739-8085
Co-Lead Counsel for Lead Plaintiffs and the Attorney-In-Charge and Co-Lead Counsel
Proposed Subclass for Lead Plaintiffs and the Proposed Subclass
175 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 33 of 96
EXHIBIT A Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 34 of 96
HISTORY OF SAFETY LAPSES
February 1985 : BP pays £15,000 for safety violations after a gas blowout in the 1 North Sea.
March 1989 : Exxon Valdez spill. BP was responsible for containing the
spill but they did not have adequate/proper equipment and was unable to respond. Exxon took over the clean-up operations.
Browne was head of BP E&P at the time and later became BP’s CEO.2
March 1998 : BP fined £750,000 after the Grangemouth Explosions that
killed three workers. Reports of a chemical leak were ignored 3 while a BP employee maintained it was safe to continue work.
October 1990 : BP fined $2.3 Million for dumping pollutants from its 4 Pennsylvania refinery into the Delaware River for 6 years.
July 1991 : BP fined $135,000 for violations that lead to a Washington
state refinery exploding and killing 1 worker and injuring 6 others.5
April 1994 : BP Chemicals fined £200,000 for a fire that started at the
1 The Guardian (London). “BP Fined 15,000 pounds on safety charge after North Sea
fire.” February 6, 1985.
2 CBS News. “BP Played Central Role in Exxon Valdez Disaster Two Decades after
Alaska Spill, Observers Find Eerie Similarities in Oil Company's Slow Containment Response.” May 25, 2010.
3 The Herald (Glasgow). “BP is fined pounds 750,000 after fatal blast at refinery.” March
22, 1988.
4 Associated Press. "BP Oil assessed $2.3 million fine for polluting river. (Delaware
River)." The Oil Daily. Energy Intelligence Group. October 24, 1990.
5 Lange, Larry. “Refiner cited for violations in fatal blast; British Petroleum fined record
$135,000 for safety 'shortcuts.'” Seattle Post-Intelligencer. July 16, 1991.
1 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 35 of 96
Grangemouth plant. One worker was killed in the fire and 3 were seriously burned. 6
March 1999 : BP paid $1.75 Million to the EPA for illegally discharging
pollutants into the air and not alerting emergency response 7 authorities of their actions at an Ohio refinery.
May 1999 : BP Exploration fined £20,000 for violating health and safety
regulations that lead to an explosion on a North Sea gas 8 platform.
February 2000 : BP Exploration pays $22 Million in fines and civil penalties for
dumping hazardous materials at a North Slope oil field and 9 failing to notify authorities.
April 2000 : BP Amoco paid $32 Million to settle claims that BP underpaid royalties on oil leases on Federal and Indian land. 10
June 2000 : BP fined $1.43 Million when a steam line ruptured at
Grangemouth and threatened local residents. Three days later
Grangemouth had a flammable gas leak that led to a 9 ton 11 vapor explosion.
BP fined £15,000 for dumping pollutants into the River Tweed with home heating oil, and spent another £200,000 for clean-
6 The Herald (Glasgow). “BP Chemicals fined £200,000 over death fire.” April 22, 1994.
7 US Environmental Protection Agency press release. “BP Oil must monitor flaring of
gases at Toledo refinery.” March 15, 1999.
8 The Herald (Glasgow). “Maximum fine for oil firm over gas explosion.” May 11, 1999.
9 Speiss, Ben. “BP settles for $15.5 million; company also faces probation in dumping of toxic waste.” Anchorage Daily News. February 2, 2000.
10 Sniffen, Michael J. “BP Amoco to Resolve Royalties Case.” Associated Press. April
11, 2000.
11 “Grangemouth incidents scar BP.” The Oil Daily. January 23, 2002.
2 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 36 of 96
up.12
January 2001 : Eight refineries at BP Amoco violated the Clean Air Act which
resulted in BP Amoco paying $600 million to resolve and
another $10 million in civil penalties. 13
March 2001 : Three workers killed during explosions at BP Amoco Polymers 14 Plant, located in Augusta, Georgia.
September 2001 : BP fined $141,000 by OSHA that related to the explosion and
fire at a North Carolina facility. Three employees were killed during this accident.
October 2001 : BP fined £200,000 for exposing their platform workers to gas leaks for 4 years on an Amoco gas platform. 15
December 2001 : BP fined £60,000 when a gas station in Luton, England leaked
40,000 liters of gas. 16
July 2002 : BP settled a suit for $46 million that alleged its Arco
Subsidiary failed to improve leaking underground fuel storage 17 tanks at 59 gas stations for over 10 years.
2003 - 2004 : BP paid $303.5 million in fines, penalties and restitution to
settle charges against them that they manipulated the propane
12 The Scotsman. “BP fined 15,000 pounds over river pollution.” June 14, 2000.
13 US Environmental Protection Agency press release. “EPA finalizes agreement with petroleum refinery.” January 19, 2001.
14 Edwards, Johnny. “Three die in fatal explosion at Augusta, Ga. BP Amoco Polymers
Plant.” Augusta Chronicle. March 14, 2001.
15 The Scotsman. “BP fined more than GBP 200,000.” October 13, 2001.
16 “One fuel spill BP need worry about no longer.” Luton Today. May 14, 2010.
17 Carrell, Severin. “BP pays $46m settlement after breaching US anti-pollution laws.”
The Independent. July 7, 2002.
3 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 37 of 96
market, drove up prices for consumers while generating a $20 million profit. 18
July 2004 : BP fined £25,000 for leaking 6.5 tonnes of diesel fuel into the
North Sea while its supply ship was trying to refuel a drilling platform. 19
November 2004 : BP fined £200,000 for a gas leak from its Forties Alpha North
Sea platform in 2002. 20
March 2005 : An explosion and fire at BP’s Texas City Refinery killed 15
workers and injured over 170 people. 21 Monitoring alarm
systems failed to alert the plant that highly combustible
chemicals and vapors were overfilling the unit which caused
the explosion.22 This accident was the worst industrial accident 23 in the U.S. in the past 15 years. The Chemical Safety Board
said that BP’s lack of safety procedures and safety culture
attributed to this major accident. 24 Investigators also
determined that budget cuts within BP and production
18 U.S. Commodity Futures Trading Commission. Press Release. “U.S. Commodity
Futures Trading Commission Charges BP Products of North America, Inc. with Cornering the
Propane Market and Manipulating the Price of Propane.” June 28, 2006; BP Statement on
Settlements. “BP America Announces Resolution of Texas City, Alaska, Propane Trading Law
Enforcement Investigations.” October 25, 2007.
19 Innes, John. “Diesel spill in sea costs BP £25,000.” Scotsman. December 6, 2005.
20 Barry, Maggie. “Gas Leak: BP Fined.” Daily Mirror. November 17, 2004.
21 U.S. Occupational Health and Safety Administration. Press Release. “OSHA Fines BP
$2.4 Million for Safety and Health Violations.” April 25, 2006.
22 Porretto, John and Dan Caterinicchia. “Probe of BP plant blast cites oversight.”
Associated Press.
23 Porretto, John and Dan Caterinicchia. “Probe of BP plant blast cites oversight.”
Associated Press. Olsen, Lise. “BP refinery deaths top industry in U.S.” Houston Chronicle.
May 16, 2005.
24 “Poor BP safety standards at root of refinery blast.” Birmingham (UK) Post. March 20,
2007.
4 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 38 of 96
pressures on managers affected process safeties. As a result,
BP was fined $50 million for violating the Risk Management
Plan regulations under the Clean Air Act. In addition, BP paid
$21 million to OSHA for workplace safety violations and another $1.5 billion in damages and repairs.
July 2005 : Hurricane Dennis damaged and destabilized the Thunder Horse
Deep Sea Platform in the Gulf of Mexico. 25 BP found a ballast
piping was installed incorrectly which caused the Platform to 26 dip into the Gulf. BP also found additional problems in 2006
with their subsea equipment and compressions systems. 27
August 2005 : BP’s Board commissioned the Baker Panel after the CSB
warned that BP had serious safety management lapses. CSB
urged the BP Board to look into their safety oversight, safe
management of refineries, and their corporate safety culture.
March 2006 : BP’s Prudhoe Bay facility leaked 267,000 gallons of crude oil,
from a corroded pipeline, into Alaska’s North Slope, which was deemed “the largest spill of crude on the North Slope.” 28
Similarly in August 2006, BP had to shut down Prudhoe Bay
due to a second corroded pipeline which caused another small 29 leak. BP admitted that they disregarded the necessary steps
and actions to avoid the spill and eventually paid $20 million in
fines and restitution. 30 BP also paid $1.7 million in fines to
25 Andrew, Kelly. “Delays at Thunder Horse add to BP’s woes.” The Oil Daily.
September 19, 2006.
26 Greising, David. “Troubles run deep on Gulf oil platform.” Chicago Tribune. May 28,
2007.
27 “New Thunder Horse Woes.” International Petroleum Finance. June 1, 2006.
28 “Alaska hit by ‘massive’ oil spill.” BBC. March 11, 2006.
29 BP. Press Release. “BP to shutdown Prudhoe Bay Oil Field.” August 7, 2006.
30 BP Statement on Settlements. “BP America Announces Resolution of Texas City,
Alaska, Propane Trading Law Enforcement Investigations.” October 25, 2007.
5 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 39 of 96
Alaska for oil spill containment violations in 2009. 31 As of
2010, U.S. authorities are still trying to collect millions of
dollars from BP for water and air pollution violations and
neglecting their promised deadlines to prevent future spills. 32
April 2006 : BP fined $2.4 million for workplace safety violations at its
Ohio refinery. These violations were similar to those that
contributed to the Texas City disaster. 33
August 2006 : A pipeline technician, Stuart Sneed, working on the Prudhoe
Bay, found a crack in a transit line pipeline and issued orders
for all nearby welders to stop working, for fear of igniting a
fire. BP retaliated and fired Sneed two weeks later. Arbitrators
were brought in to investigation and confirmed Sneed’s story.
September 2006 : BP fined $900,000 by the EPA for discharging volatile organic
compounds from its gas stations. 34
September 2006 : Report commissioned from the Vinson & Elkins law firm
found that BP’s environment was not conducive for employees 35 to report problems to upper management. For example, a BP
worker filed a complaint that the corrosion inspection staff was
31 Alaska Department of Law and Alaska Department of Environmental Conservation.
Press Release. “State Reaches Settlement with BP Exploration (Alaska) Inc.” September 22,
2009.
32 Loy, Wesley. “Federal regulators, BP work on settlement for ’06 spills.” Anchorage
Daily News. May 23, 2010.
33 U.S. Occupational Health and Safety Administration. Press Release. “OSHA Fines BP
$2.4 Million for Safety and Health Violations.” April 25, 2006.
34 US Environmental Protection Agency. “BP, Shell Pay $1.5 Million in Penalties for
Auto Gas Violations Threatening Public Health.” October 5, 2006.
35 Davidson, Paul. “Congressmen slam BP executives at Alaskan oil leak hearing.” USA
Today. September 7, 2006.
6 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 40 of 96
cut by 25% and he was threatened with firing. 36
December 2006 : Supply boat hits the North Sea platform’s support legs and was
evacuated. Structural integrity of platform may have been compromised.37
January 2007 : Baker Report was issued and the panel found that BP had not
provided effective process safety leadership and had not
established process safety as a core value across BP’s refineries.
March 2007 : CSB issued their final report regarding the investigation into
the Texas City disaster. The report stated that the BP, “Board
of Directors did not provide effective oversight of BP’s safety
culture and major accident prevention programs.”
Booze Allen reported that BP’s strategy of focusing on
financial performance over operational safety created a culture
where all projects and activities must fit into a budget, whether
it was safe or not.
June 2007 : BP fined $869,000 by state of Michigan for ignoring and
failing to clean up leaking gas station tanks even though BP was aware of these leaking tanks for years. 38
July 2007 : BP settled with California utilities and paid $18 million for
overcharging customers for electricity during California’s energy crisis in 2000 and 2001. 39
36 Mauer, Richard. “BP was warned of intimidation.” Anchorage Daily News. October 3,
2007.
37 “Alert on oil platform after collision.” (Aberdeen) Press and Journal. December 14,
2006.
38 Lam, Tina. “BP is fined for leaking underground tanks.” Detroit Free Press. June 2,
2007.
39 “U.S. FERC approves $18 mln BP-California settlement.” Reuters. July 6, 2007.
7 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 41 of 96
August 2007 : BP settled a class action lawsuit that alleged BP underpaid
landowners for the right to drill oil on their land for $35 million.40
October 2007 : BP pleads guilty and agreed to pay a $20 million fine related
with the Alaska oil spills. BP also had to pay a $12 million
criminal fine and serve 3 years of probation.
BP also announced 2 plea agreements and a deferred
prosecution agreement with U.S. DOJ related to the Texas City disaster.
May 2008 : The Deepwater Horizon rig flooded with sea water due to removed piping and caused $1 million in damages.
Investigators concluded that the piping was removed without
permit or authority from management.
June 2008 : Atlantis rig spilled 193 barrels of oil into the Gulf of Mexico
due to a ruptured steel tubing. Investigators concluded that BP managers postponed repairs due to cost savings and budget. 41
August 2008 : The Deepwater Horizon lost power for two minutes and almost
drifted into the sea.
Ken Abbott, BP’s production manager, e-mailed colleagues and
warned that hundreds of documents of “as built” documents for
the Atlantis rig were never finalized. He warned that having the wrong documents could lead to catastrophic failures.
Abbott was terminated after his concerns were raised.
September 2008 : An eight-inch high pressure gas line in Alaska separated.
There were no injuries but investigators found that the incident
40 Laura Dichter et. al v. BP America Production Company. Case No.
D-0101-CV-200001620, State of New Mexico, First Judicial District. Notice of Settlement.
August 15, 2007.
41 Guy Chazan, Benoit Faucon, and Ben Casselman. “AS CEO Hayward Remade BP,
Safety, Cost Drives Clashed.” Wall Street Journal. June 29, 2010.
8 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 42 of 96
could have been potentially catastrophic. According to
Alaska’s Petroleum Systems Integrity Office, the separation
resulted from “procedures that either were not in place or had
not been fully implemented at BP in their management
system.”
BP evacuated 212 workers from rig when a blowout caused the
Azeri-Chirag-Guneshli field to be shut down for weeks. BP
concluded that the blowout was caused by a faulty cement job.
February 2009 : BP fined $180 million by the EPA for violating the Clean Air Act in connection with the Texas City disaster. 42
March 2009 : U.S. Federal Court in Houston approved BP’s guilty plea and
$50 million criminal fine for a criminal workplace safety
charge in connection with the Texas City Refinery disaster. BP
America Chairman and President, Bob Malone, admitted that
had BP’s safety and risk management were more disciplined
and comprehensive, the Texas City disaster could have been
avoided altogether. 43
January 2010 : U.S. House of Representatives members Bart Stupak and Henry
Waxman wrote to BP’s president of Alaskan operations, and
warned that the Company’s efforts to cut costs could imperil
safety at BP facilities: “Committee staff have received reports
that proposed budget cuts by BP may threaten the company’s
ability to maintain safe operations.” Attached to the
Congressmen’s letter was a request for documents. The letter
and the document requests were discussed with the Board.
U.K. Health and Safety inspectors visited the Magnus rig off
the coast of Scotland and found that confusion existed about
42 US Environmental Protection Agency. “BP Products to pay nearly $180 million to
settle Clean Air violations at Texas City Refinery.” February 19, 2009.
43 BP America, Inc Press Release. “BP America announces resolution of Texas City,
Alaska, propane trading, law enforcement investigations.” October 25, 2007; British Petroleum.
U.S. Securities and Exchange Commission filing 20-F, 2009.
9 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 43 of 96
who would order a well shut-off in event of a blowout. 44
EPA attorneys sent an email to BP General Counsel, Jack
Lynch, stating that: “[i]t appears that BP, regardless of its code
of conduct and statements to the government, will do whatever
is necessary to cover up the improper actions of its senior
managers. This promotes intimidation, retaliation, blackballing
and unethical behavior in the management ranks, and a culture
of fear and lack of ethics in the employee ranks. Nothing has
been done in TWO YEARS. This is a current graphic example of why EPA does not trust BP.” 45
April 2010 : Deepwater Horizon disaster.
44 Tom Bergin & Daniel Fineren, BP North Sea rig lacked procedures on blow-outs
(Reuters Sep. 15, 2010).
45 Abrahm Lustgarten, Furious growth, cost cuts led to BP accidents past and present
(ProPublica, October 26, 2010).
10 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 44 of 96
EXHIBIT B Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 45 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 46 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 47 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 48 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 49 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 50 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 51 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 52 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 53 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 54 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 55 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 56 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 57 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 58 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 59 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 60 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 61 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 62 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 63 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 64 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 65 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 66 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 67 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 68 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 69 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 70 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 71 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 72 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 73 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 74 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 75 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 76 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 77 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 78 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 79 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 80 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 81 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 82 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 83 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 84 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 85 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 86 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 87 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 88 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 89 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 90 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 91 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 92 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 93 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 94 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 95 of 96 Case 4:10-md-02185 Document 112-1 Filed in TXSD on 02/11/11 Page 96 of 96