corpus/source-0035.txt

U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD 
INVESTIGATION REPORT 
VOLUME 4 
REPORT NO. 2010-10-I-OS 
 
4/17/2016 
 DRILLING RIG EXPLOSION AND FIRE AT THE 
MACONDO WELL 
(11 Fatalities, 17 Injured, and Serious Environmental Damage) 
 
 DEEPWATER HORIZON RIG 
MISSISSIPPI CANYON 252, GULF OF MEXICO 
KEY ISSUES: 
 
 
 
 
 
 
 
 APRIL 20, 2010 
• 
US OFFSHORE SAFETY REGULATION DURING AND AFTER MACONDO 
• 
ATTRIBUTES OF AN EFFECTIVE REGULATOR AND REGULATORY SYSTEM 
 
 

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Contents 
ACRONYMS AND ABBREVIATIONS ..................................................................................................... 7 
REGULATORY OVERSIGHT OF U.S. OFFSHORE OIL AND GAS OPERATIONS: A CALL FOR 
MORE ROBUST AND PROACTIVE REQUIREMENTS ....................................................................... 10 
VOLUME 4 – INTRODUCTION .............................................................................................................. 11 
1.1 
Approach to Analysis ..................................................................................................................... 12 
1.2 
Attributes of an Effective Regulatory Model ................................................................................. 13 
2.0 
REVIEWING INTERNATIONAL REGULATORY MODELS .................................................. 18 
2.1 
History of Safety and Environmental Management Systems Offshore in the US ......................... 18 
2.1.1 
The Outdated API Offshore Safety Management System Approach................................ 20 
2.2 
Purpose of the Regulations and Role of the Regulator .................................................................. 22 
2.3 
An Alternative Regulatory Model: The Safety Case ..................................................................... 23 
2.4 
Managing Major Accident Hazards in the US ............................................................................... 26 
3.0 
INADEQUATE POST-MACONDO SAFETY MANAGEMENT REGULATIONS .................. 28 
3.1 
SEMS: No Goal-Setting Risk-Reduction Standard ....................................................................... 29 
3.1.1 
The Use of Standards and Guidance in ALARP-based Regulatory Regimes ................... 33 
3.1.2 
Insufficient US Alternative Legal Mechanisms to Drive Continual Safety Improvements
 
35 
3.1.3 
Ineffective Regulatory “Workarounds” ............................................................................ 37 
3.1.4 
Recent BSEE-proposed Regulatory ALARP-type Language ........................................... 38 
3.2 
SEMS Activity-Based Requirements: A Compliance-Based Mentality ........................................ 39 
3.3 
Safety Responsibility Offshore ...................................................................................................... 43 
3.3.1 
Offshore Regulatory Ambiguity and Industry/Stakeholder Response .............................. 45 
3.3.1.1 
Post-Macondo BSEE Efforts to Hold Contractors Responsible for Safety ... 48 
3.3.1.2 
Stakeholders Attempt to Fill Responsibility Gap with Voluntary Guidance 50 
3.3.2 
Other Regimes’ Focus on Safety Responsibilities of Operator/Lessee and Drilling 
Contractor 51 
3.3.3 
Conclusion ........................................................................................................................ 54 
3.4 
Insufficient SEMS Worker Participation Provisions ..................................................................... 54 
3.4.1 
Post-Macondo/SEMS Worker Participation Provisions ................................................... 56 
3.4.2 
Insufficient and Limited SEMS Worker Participation Provisions .................................... 57 
3.4.3 
No SEMS Provisions for Worker-Elected Safety Representatives ................................... 59 

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3.4.4 
No SEMS Requirement for Contractor Participation ....................................................... 62 
3.4.5 
SEMS Stop-Work Authority Impact on Worker Liability ................................................ 63 
3.4.6 
Inadequate SEMS Requirements to Protect Workers from Retaliation ............................ 64 
3.4.7 
No SWA Worker-Requested Regulatory Provision in Regulation ................................... 67 
3.4.8 
No SEMS Safety Committees or Tripartite Safety Forums Provision .............................. 68 
3.4.9 
Conclusion ........................................................................................................................ 70 
4.0 
US OFFSHORE REGULATOR CHALLENGE IN EFFECTIVE OVERSIGHT ........................ 71 
4.1 
No Required Review of Major Accident Hazard Documentation Before Hazardous Work Begins
 
72 
4.2 
Regulatory Safety Oversight Audits and Initiatives ...................................................................... 77 
4.2.1 
Challenges of Relying on Third-Party Audits in the GoM ............................................... 79 
4.3 
Regulatory Use of Safety Performance Indicator Data .................................................................. 80 
4.3.1 
Roadblocks to Regulatory Improvements in Data Collection and Analysis ..................... 81 
4.3.2 
Inadequate Use of Safety Performance Indicators ............................................................ 85 
4.4 
Transparency of Offshore Safety ................................................................................................... 89 
4.4.1 
Regulatory Approaches to Transparency .......................................................................... 90 
5.0 
INSUFFICIENT AND INADEQUATE STAFF FOR APPROPRIATE OVERSIGHT ............... 95 
5.1 
Models for Building a Competent Regulator ................................................................................. 95 
5.1.1 
UK Offshore Safety Directive Regulator .......................................................................... 95 
5.1.2 
US Government Incentives to Build Competent Staff ...................................................... 97 
5.2 
Disproportionate Regulator Resources for Gulf of Mexico Offshore Activity .............................. 98 
5.3 
The Deficit in Regulator Technical Competency and Credibility ............................................... 101 
5.4 
Post-Macondo Efforts to Improve Competency .......................................................................... 102 
5.5 
Insufficient Regulatory Funding Mechanism for Securing Staff ................................................. 103 
5.5.1 
Ineffectual Funding Appropriations for Offshore Activity ............................................. 104 
5.5.2 
Industry Funding of International Offshore Regulators .................................................. 107 
5.6 
The Importance of an Independent Regulator .............................................................................. 109 
5.6.1 
The Minerals Management: The Safety Versus Revenue Conflict ................................. 109 
5.6.2 
BSEE Organizational Structure ...................................................................................... 111 
5.6.3 
Critical BSEE Drilling Permit Concerns ........................................................................ 114 
5.6.4 
Historical Recognition for Separating Safety Oversight from Resource Development .. 115 
5.6.4.1 
Creation of the Mine Safety and Health Administration ............................. 115 

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5.6.4.2 
Creation of the Nuclear Regulatory Commission ....................................... 115 
5.6.4.3 
Creation of the UK HSE Offshore Division ................................................ 116 
6.0 
CONCLUSION ............................................................................................................................ 117 
7.0 
RECOMMENDATIONS ............................................................................................................. 118 
APPENDIX A: INTERNATIONAL OFFSHORE INCIDENTS AND THE US RESPONSE ................ 122 
Alexander Kielland and Regulatory Change in Norway ........................................................................... 122 
Ocean Ranger and Regulatory Change in Canada .................................................................................... 123 
Piper Alpha and Regulatory Change in the United Kingdom ................................................................... 124 
Montara and Regulatory Change in Australia ........................................................................................... 125 
History of Regulatory Change in the US .................................................................................................. 126 
 
 
 

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Figures and Tables 
 
Figures 
Figure 3-1. Transocean’s Well Delivery Process as defined by Transocean corporate polices. ................. 44 
Figure 4-1. Department of Interior organization chart: at the time of the April 20, 2010, Macondo incident 
and currently. .................................................................................................................................... 113 
 
Tables 
Table 3-1. Current and BSEE proposed language for § 250.107, What must I do to protect health, safety, 
property, and the environment? .......................................................................................................... 39 
Table 4-1. Abridged list of reportable incidents to BSEE from § 250.188. ................................................ 82 
 
 
 
 
 
 

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Acronyms and Abbreviations 
AB 
 
Accreditation Body 
ACOP 
Approved Code of Practice 
AEC 
 
Atomic Energy Commission 
ALARA 
As Low As Reasonably Achievable 
ALARP 
As Low As Reasonably Practicable 
ANSI 
American National Standards Institute 
AOC 
 
Acknowledgement of Compliance 
API 
 
American Petroleum Institute 
ASME 
American Society of Mechanical Engineers 
ASP 
 
Audit Service Provider 
ASTM 
American Society for Testing and Materials 
BAST 
Best Available and Safest Technology 
BOEM 
Bureau of Ocean Energy Management 
BOEMRE 
Bureau of Ocean Energy Management, Regulation, and Enforcement 
BOP 
 
Blowout Preventer 
BSEE 
Bureau of Safety and Environmental Enforcement 
CCPS 
Center for Chemical Process Safety 
C.F.R. 
Code of Federal Regulations 
COMAH 
Control of Major Accident Hazards 
COS 
 
Center for Offshore Safety 
CSB 
 
U.S. Chemical Safety Board 
CUPA 
Certified Unified Program Agency 
DAFW 
Days Away From Work 
DNFSB 
Defense Nuclear Facilities Safety Board 
DNV 
 
Det Norske Veritas 
DOI 
 
Department of Interior 
DWH 
Deepwater Horizon 
EPA 
 
Environmental Protection Agency 
EPP 
 
Employee Participation Plan 

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FRC 
 
Financial Reporting Council 
GAO 
 
US Government Accountability Office 
GASCET 
Guidance for the Topic Assessment of Major Accident Hazard Aspects of Safety Cases 
GoM 
 
Gulf of Mexico 
HSE 
 
Health Safety Executive (of the United Kingdom) 
IADC 
International Association of Drilling Contractors 
INC 
 
Incident of Noncompliance 
INPO 
Institute of Nuclear Power Operations 
IPD 
 
Interim Policy Document 
IRF 
 
International Regulators’ Forum 
ITL 
 
Information to Lessee 
JSA 
 
Job Safety Analysis 
LCM 
 
Loss Circulation Material 
LTI 
 
Lost Time Incident 
MBI 
 
Marine Board of Investigation 
MDL 
Multi-District Litigation 
MESA 
Mining Enforcement and Safety Administration 
MMS 
Minerals Management Service 
MOA 
Memorandum of Agreements 
MOC 
Management of Change 
MODU 
Mobile Offshore Drilling Unit 
MSHA 
Mine Safety and Health Authority 
NAE 
 
National Academy of Engineering 
NOPSA 
National Offshore Petroleum Safety Authority; formally NOPSEMA (of Australia) 
NOPSEMA 
National Offshore Petroleum Safety and Environmental Management Authority 
NRC 
 
Nuclear Regulatory Commission 
NTL 
 
Notice to Lessee 
OCS 
 
Outer Continental Shelf 
OCSLA 
Outer Continental Shelf Lands Act 
OECD 
Organization for Economic Co-operation and Development 
OESAC 
Ocean Energy Safety Advisory Committee 

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OIAC 
Offshore Industry Advisory Committee 
OIM 
 
Offshore Installation Manager 
ONRR 
Office of Natural Resources Revenue 
OOC 
 
Offshore Operators Committee 
OSDR 
Offshore Safety Directive Regulator 
OSHA 
Occupational Safety and Health Administration 
OTC 
 
Offshore Technology Conference 
PHMSA 
Pipeline and Hazardous Materials Safety Administration 
PINC 
Potential Incident of Noncompliance 
PSA 
 
Petroleum Safety Authority 
PSM 
 
Process Safety Management 
RIF 
 
Recordable Injury Frequency 
ROP 
 
Reactor Oversight Process 
SEC 
 
Securities and Exchange Commission 
SEMP 
Safety and Environmental Management Program 
SEMS 
Safety and Environmental Management System 
SHE 
 
Safety, Health and Environment 
SMS 
 
Safety Management System 
SOP 
 
Standard Operating Procedure 
SWA 
Stop Work Authority 
TRB 
 
Transportation Research Board 
TPSR 
Total Potential Severity Rate 
TRIR 
Total Recordable Injury Rate 
UK 
 
United Kingdom 
US 
 
United States 
USCG 
United States Coast Guard 
UWA 
Ultimate Work Authority 
WCS 
 
Well Construction Standards 
WEST 
Workforce Engagement Support Team 
WOMP 
Well Operations Management Plan 
 

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Volume 4 
Regulatory Oversight of U.S. 
Offshore Oil and Gas Operations: A 
Call for More Robust and Proactive 
Requirements 
 
 
 
 
 
 

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Volume 4 – Introduction 
In the aftermath of the Macondo incident, the US offshore safety regulations for drilling and completions 
activities on the outer continental shelf have been reviewed, debated, and revised.1 Amid several 
reorganizational efforts, the Department of Interior established the Bureau of Safety and Environmental 
Enforcement (BSEE) in October 2011 to oversee safety of the US offshore oil and gas operations.2 
BSEE’s immediate predecessor, the Bureau of Ocean Energy Management, Regulation & Enforcement, 
(BOEMRE),3 promulgated the Safety and Environmental Management Systems (SEMS) rule in October 
2010,4 requiring the previously voluntary practices in the American Petroleum Institute's (API) 
Recommended Practice 75 (API 75).5 After BSEE’s creation, the agency amended SEMS in 2013 to 
further its initiative for performance-based6 regulations to “reduce the occurrence of accidents, injuries, 
and spills during oil and gas activities on the Outer Continental Shelf (OCS).”7 In April 2015, BSEE 
proposed well control regulations that it identified as the “most substantial rulemakings in the history” of 
offshore safety in the United States.8 Most recently, on December 7, 2015, BSEE announced the launch 
of a pilot Risk-Based Inspection Program to complement its existing inspections and audits with the goal 
of more efficiently and effectively managing the limited inspection and auditing resources of the agency.9 
In support of these endeavors, BSEE has made efforts over the last five years to educate its staff and 
 
1 See Appendix A for a history of offshore US oil and gas safety regulation. Including pre-Macondo events. 
2 http://www.bsee.gov/About-BSEE/BSEE-History/index/ (accessed January 19, 2016). 
3 BOEMRE replaced the Minerals Management Service (MMS) shortly following the Macondo incident in 2010. 
4 Oil and Gas and Sulphur Operations in the Outer Continental Shelf, 75 Fed. Reg. 63609 (Final Rule, October 15, 
2010) (to be codified at 30 C.F.R. Part 250). 
5 API Recommended Practice 75, 3rd ed., Recommended Practice for Development of a Safety and Environmental 
Management Program for Offshore Operations and Facilities, May 2004 (Reaffirmed May 2008). 
6 The US Nuclear regulatory commission defines performance-based regulation as “a regulatory approach that 
focuses on desired, measurable outcomes, rather than prescriptive processes, techniques, or procedures. 
Performance-based regulation leads to defined results without specific direction regarding how those results are to 
be obtained;” http://www.nrc.gov/reading-rm/basic-ref/glossary/performance-based-regulation.html (accessed 
January 19, 2016). 
7 Oil and Gas and Sulphur Operations in the Outer Continental Shelf—Revisions to Safety and Environmental 
Management Systems, 78 Fed. Reg. 20423 (Final Rule, April 5, 2013) (to be codified at 30 C.F.R. Part 250); 
While the original SEMS rule became effective on November 15, 2010, this subsequent enhancement effective June 
4, 2013 is referred to as SEMS II. SEMS II incorporated additional safety requirements that addressed stop work 
authority, ultimate work authority, employee participation plans, guidelines for reporting unsafe work conditions, 
job safety analyses, and independence of accredited audit service providers. Unless otherwise stated, when the 
CSB refers to SEMS, it is addressing both the original SEMS rule and the subsequent SEMS II revisions; see also, 
BSEE. Safety and Environmental Management Systems (SEMS) Fact Sheet; http://www.bsee.gov/BSEE-
Newsroom/BSEE-Fact-Sheet/SEMS-II-Fact-Sheet/ (accessed March 21, 2016). 
8 Oil and Gas and Sulphur Operations in the Outer Continental Shelf—Blowout Preventer Systems and 
Well Control, 80 Fed. Reg. 21504 (Proposed Rule, April 17, 2015) (to be codified at 30 C.F.R. Part 250). 
9 Bureau of Safety and Environmental Enforcement to Launch Pilot Risk-Based Inspection Program for Offshore 
Facilities. December 7, 2015. http://www.bsee.gov/BSEE-Newsroom/Press-Releases/2015/Bureau-of-Safety-and-
Environmental-Enforcement-to-Launch-Pilot-Risk-Based-Inspection-Program-for-Offshore-Facilities / (accessed 
December 21, 2015). 

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engage in dialogue with industry, regulatory bodies, and safety experts worldwide to improve its function 
as the regulator of offshore safety. 
While the acknowledging these positive efforts, the CSB concludes that the SEMS regulations do not 
provide BSEE with an adequate framework for major accident prevention, and an improved approach is 
needed to reduce the risk of another Macondo-like event. SEMS does not utilize goal-setting, meaning the 
reduction of risks to a goal such as “as low as reasonably practicable” (ALARP). In addition, 
notwithstanding the implementation of SEMS, BSEE audit findings suggest that a culture of minimal 
regulatory compliance continues to exist in the Gulf of Mexico and risk reduction continues to prove 
elusive.10 Ultimately, the offshore regulatory changes made thus far do not sufficiently place the onus on 
industry to reduce risk or empower the regulator to ensure proactive and effective industry management 
and control of major hazards. 
1.1 
Approach to Analysis 
The CSB’s preventive mission as a federal agency is to reduce chemical hazards as broadly as possible 
(e.g., through recommendations that will effect national preventive changes). The CSB, therefore, focuses 
its recommendation efforts on changing national legislation, regulation, voluntary consensus standards, 
and industry recommended practices. As a result of an investigation or study, the CSB may issue 
“proposed rules or orders” to regulators such as the EPA Administrator and the Secretary of Labor “to 
prevent or minimize the consequences of any release of substances that may cause death, injury or other 
serious adverse effects on human health or substantial property damage as the result of an accidental 
release.”11 The CSB’s investigative analytical approach, therefore, must look beyond technical and 
management system causes. 
The CSB approach to regulatory analysis and recommendations starts with an examination of key 
investigative findings and an analysis of whether the applicable regulatory and enforcement regime 
manifests weaknesses or gaps that were causally related to the incident. The CSB formulates 
recommendations that, if effectively implemented, work to prevent or reduce the similar incidents or 
hazards to as great an extent as possible. For example, key findings in Volumes 3 and 4 of the Macondo 
Report show that the US offshore regulator lacks effective use of key process safety indicators and 
guidance addressing corporate boards of directors and human factors focused on major accident 
prevention. The CSB report analysis shows that addressing these significant gaps could help reduce the 
risk of similar incidents. 
 
10 See Section 4.2 and Bureau of Safety and Environmental Enforcement. BSEE Priorities Regarding SEMS, 
Offshore Technology Conference, Houston, TX, 2015; 
http://www.bsee.gov/uploadedFiles/BSEE/BSEE_Newsroom/Speeches/2015/OTC%202015%20Mtg%20SEMS%
20Presentation.pdf (accessed December 19, 2015). 
11 42 USC sec. 7412(r)(6)(c)(ii). 

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1.2 
Attributes of an Effective Regulatory Model 
Various international models for offshore safety regulation can be used to compare and contrast what the 
US regulator has adopted since Macondo. No one approach is an undisputed panacea for all accidents, 
partly because prevention requires active and sustained participation in risk reduction from industry, the 
workforce, and the regulator. Ultimate responsibility for preventing incidents and protecting workers and 
the public always remains with the employers and parties who create or control major accident risk. Yet 
regulatory systems have an important role to play in establishing sufficient requirements, guidance, and 
Throughout Volume 4, the CSB refers to “the regulator” or “offshore regulations” to indicate either 
MMS or BSEE and their respective safety regulations for drilling and completions activities on the 
outer continental shelf. As indicated in the figure below, MMS evolved into BSEE after the Macondo 
incident occurred. In reality, several regulatory bodies oversee the offshore oil and gas industry, 
including the US Coast Guard (USCG), the Bureau of Ocean Energy Management (BOEM), and the 
Environmental Protection Agency (EPA), but the CSB generally limits its discussion to MMS and 
BSEE due to its specific authority over the safe conduct of offshore drilling and completion 
operations. 

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oversight to establish a floor of practice that if covered employers implement effectively works to reduce 
major incidents. 
As part of the agency’s investigative approach, the CSB frequently compares international regulatory 
regimes from what existed at the worksite under investigation to examine the strengths and weaknesses of 
different models and methodologies. 12 It would be incorrect, however, to assume that an effective model 
found in some other international jurisdiction could necessarily be imported to the US with no allowance 
for important variances that may exist among cultures, existing legal and regulatory structures, political 
systems, as well as numerous and varied industry stakeholder interests and levels of involvement. To that 
end, the CSB reviews international regulatory models to identify various attributes that could strengthen 
the current US offshore regulatory environment. This helps clarify key attributes that could provide more 
effective safety regulation for addressing identified gaps and weaknesses. Recent CSB reports used this 
approach, such as those analyzing the 2010 Tesoro Anacortes and 2012 Chevron Richmond refinery 
incidents, and have identified attributes from other regulatory regimes to address causal regulatory gaps 
related to the incidents. 13 Those attributes related to the Macondo incident causal factors include: 
 
Continual Risk Reduction to Levels As Low As Reasonably Practicable (ALARP) 
The intention of a goal-based, risk-reduction regulatory framework is to eliminate or sufficiently 
minimize the risks in an operation. Although risk can never be completely eliminated, any such 
framework must continually strive toward this goal. With major accident hazards, the key question 
becomes: Is there anything more that can be done to reduce the risk? ALARP is a standard familiar to 
industry in other global offshore regimes, and even in other high-hazard industries in the US. In such 
regimes, the government sets the goal, and the duty holder demonstrates how it will meet that goal 
through submitted documentation. The regulator then holds the duty holder accountable to execute that 
 
12 In the investigation of a 1999 fire that killed four workers at the Tosco Avon refinery in Martinez, California, the 
CSB report identified features and attributes from the UK HSE’s regulatory guidance related to safe piping and 
equipment opening in process plants that supported the analysis and recommendations in the report. See USCSB, 
2001, Refinery Fire Incident, Martinez, CA, February 23, 1999, Report No. 99-014-I-CA, Section 3, pp 31-44, 
March 2001, http://www.csb.gov/assets/1/19/Tosco_Final_Report.pdf (accessed March 25, 2016). 
In the 2002 CSB Hazard Investigation Report, Improving Reactive Hazard Management, the CSB concluded that the 
UK HSE and European Union utilize a comprehensive “all hazards” approach to reactive hazard management 
with regulatory requirements based upon a facilities’ written analysis of specific hazards and needed controls 
rather than limited to an approach that only reviews listed chemicals based upon their inherent instability. Those 
regulatory attributes buttressed CSB’s recommendations that called upon EPA and OSHA to base reactive hazard 
coverage upon classifications beyond a list that would include combinations of chemicals and process specific 
conditions. See USCSB, 2002, Improving Reactive Hazard Management, Section 8.1.3, pp 83-84, October 2002, 
http://www.csb.gov/file.aspx?DocumentId=355 (accessed March 25, 2016). 
13 USCSB, 2013. Regulatory Report: Chevron Richmond Refinery Pipe Rupture and Fire, Richmond, CA, August 6, 
2012, Report No. 2012-03-I-CA, April 2013, 
http://www.csb.gov/assets/1/19/Chevron_Regulatory_Report_11102014_FINAL_-_post.pdf (accessed January 
25, 2016). 
USCSB, 2014. Catashtrophic Rupture of Heat Exchanger, Anacortes, WA, April 2, 2010, Report No. 2010-08-I-
WA, May 2014, http://www.csb.gov/assets/1/7/Tesoro_Anacortes_2014-May-01.pdf (accessed October 7, 2015). 

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plan. The regulator will work with duty holders to obtain the necessary improvement if their work raises 
significant safety concerns at any point in the lifecycle of the hazardous operation. 
The post-Macondo US offshore regulatory framework still does not provide goal-setting, risk-reduction 
requirements for oil and gas operations in the same manner as ALARP, though that may change, in part, 
if the well control rule BSEE recently proposed is adopted.14 
 
Regulator Adaptability 
The regulator has the tools to encourage industry to adopt new technologies and safer practices without 
additional rule-making. Such improvements may result from learnings from major accidents that occur 
within jurisdictional waters or internationally. The regulator must be capable of assessing the duty 
holders’ chosen methods to assure that they remain adequate in terms of good practice and achieve a 
satisfactory level of safe operation. 
 
Safety Responsibility is Maintained by those that Control or Create the Risk 
Liability, and thus responsibility, for safety resides with the companies (“duty holders”) that have the 
most direct control over the design, management, and execution of hazardous activities being undertaken. 
For example, an operator is responsible for the safe design of a well, while the drilling contractor supplies 
most of the workforce and infrastructure, resulting in control over the primary drilling operations and well 
response actions. 
 
Active Worker Participation 
Past CSB investigations have consistently identified the important role workers and their representatives 
play in major accident prevention. A fundamental element in effective safety management for major 
accident prevention is active and meaningful participation from the regulator, industry, and labor. Each of 
these entities provides unique and essential insights, so denying their effective participation removes 
critical voices in health and safety matters. Recognizing this operating principle, the United Kingdom 
(UK) and Norway established tripartite systems of industry, the regulator, and the workforce to deal with 
safety and health issues. Yet, the US offshore framework does not endow the workforce with a legally 
empowered voice on matters concerning safety. Similarly, US offshore regulations do not support a more 
traditional tripartite arrangement like those in other high-hazard industrial settings, domestically and 
internationally, where the regulator, industry, and workforce all play important roles. 
 
Required Written Safety Documentation by Duty Holders 
Duty holders submit or make available to the regulator documentation that analyzes all major hazards; the 
risks associated with those hazards; and the technical, operational, and organizational controls to reduce 
those risks to ALARP or a similar goal. Also included is a description of the safety management systems 
 
14 Oil and Gas and Sulphur Operations in the Outer Continental Shelf—Blowout Preventer Systems and 
Well Control, 80 Fed. Reg. 21504 (Proposed Rule, April 17, 2015) (to be codified at 30 C.F.R. Part 250). 

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to continually monitor and respond to health and safety hazards. These documents become the basis for 
regulator audits to confirm that duty holders are following their own stated practices. 
 
Regulatory Assessment and Verification 
Regulators have a number of proactive tools at their disposal to evaluate and monitor safety performance. 
These include preventive assessments to verify that a company’s technical and safety management 
practices are aligned with their written safety documentation, controlling regulations, industry standards, 
and good practice guidance before hazardous work begins, as well as audits and inspections to review the 
on-going effectiveness of a company throughout the lifecycle of the hazardous operation. 
 
Regulator uses Process Safety Indicators that Drive Performance 
The aim of collecting and using safety performance indicators is to publicly identify safety trends and to 
establish initiatives for industry to meet higher performance levels. An effective safety indicators program 
allows for regulatory focus on key indicators, target-setting to drive industry improvements, and issue-
specific regulatory program initiatives. 
 
Regulator Transparency 
Through real-time publication of appropriate indicators, inspection results, and safety documentation, a 
regulator prompts companies to reduce risk. These safeguards illuminate for all stakeholders the 
companies that are experiencing superior safety results because of improved technologies or enhanced 
operational methodologies, and they can help companies with weaker safety performance to improve. 
Such transparency can also spur workforce and public pressure on companies to improve safety, 
protecting the lives of workers and the offshore environment. 
 
Independent, Qualified, and Adequately Funded Regulator 
An independent, technically qualified, and adequately resourced regulator is necessary to ensure that 
regulatory oversight does not devolve into an exercise in compliance-checking and paperwork. The 
regulator must be able to vigorously question and dialogue with industry regarding the offshore hazards, 
barriers, and safety management systems industry members have established to manage those hazards. 
 
This final volume builds on Volume 3 analysis to support the conclusion that the offshore safety 
management regulations, specifically the SEMS Rule, do not adequately employ rigorous approaches to 
process safety management and major accident prevention. Despite the restructuring of the US offshore 
regulatory system and new safety management regulations for drilling and completion operations, critical 
gaps remain. Current safety management regulations fail to establish goal-oriented risk reduction 
measures for preventing major incidents; do not adequately support a tripartite system of industry, 
workforce, and regulator collaborating to improve safety; do not feature adequate proactive audits and 
inspections by the regulator; and do not sufficiently use leading and lagging safety performance indicators 
to avoid major accidents and influence ongoing safety improvements. The regulatory attributes identified 

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in this final volume of the CSB’s Macondo investigation series highlight the important roles of the 
regulator, industry, and workforce in a goal-setting, risk-reduction regime. 
 
 

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2.0 Reviewing International Regulatory Models 
Volumes 2 and 3 of the CSB’s Macondo Investigation Report demonstrate that the incident would have 
been less likely to occur if BP and Transocean had implemented modern process safety good practices 
applicable to offshore (e.g., those concerning safety critical barrier identification and management, human 
factors, safety performance indicators of barrier health and safety system reliability, ALARP, and 
corporate governance of major accident hazards). While Transocean and BP had adopted some of these 
process safety concepts into their corporate policies, they did not apply them at Macondo. This disregard 
of their stated commitments reveals a culture of minimal compliance with regulations and demonstrates 
the need for regulatory action to prevent such an approach. 
Before Macondo, offshore US regulations did not address safety management systems and risk 
management, relying instead on voluntary participation by operators to adopt safety and environmental 
management programs. Since Macondo, BSEE has promulgated SEMS, which incorporates by reference 
API’s Recommend Practice for Development of a Safety and Environmental Management Program for 
Offshore Operations and Facilities. Process safety management good practice has advanced considerably 
since API 75 was first published, but those advances are not reflected in the recommended practice, and 
consequently not in SEMS. 
After reviewing the regulatory history of safety management systems offshore in the US, this chapter 
introduces a regulatory model referred to as the “safety case regime,” which has been widely 
recommended post-Macondo in numerous investigation reports. Volume 4 examines the safety case 
models used in the UK and Australia as well as the regulatory model adopted in Norway to review how 
the attributes identified in Section 0 might be implemented in the US to address regulatory gaps and 
weakness highlighted by the Macondo incident. 
2.1 
History of Safety and Environmental Management Systems 
Offshore in the US 
In 1991, the then-US offshore regulator, MMS, proposed a regulatory model for offshore safety 
management, the Safety and Environmental Management Program (SEMP). 15 SEMP was to address key 
points such as written management policies, procedures, training, accident prevention and investigation, 
and corrective action plans. Some industry commenters requested that MMS wait until the voluntary API 
75 standard was published before making a decision, while some recommended MMS simply set safety 
goals for the industry rather than promulgating regulations.16 Ultimately, MMS did not promulgate SEMP 
regulations, but after helping to develop API 75, MMS requested that offshore operators17 voluntarily 
adopt the principles contained in it once published.18 
 
15 Oil and Gas and Sulphur Operations in the Outer Continental Shelf, 56 Fed. Reg. 30400 (Notice, July 2, 1991). 
 
16 Oil and Gas and Sulphur Operations in the Outer Continental Shelf, 59 Fed. Reg. 29277 (Notice, June 30, 1994). 
17 ‘Operators’ as referenced in US offshore regulations refer explicitly to the leaseholders of the well; this term does 
not include drilling contractors or other well service providers. 
18 Oil and Gas and Sulphur Operations in the Outer Continental Shelf, 59 Fed. Reg. 29277 (Notice, June 30, 1994). 

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API 75 recommended that OCS operators have a safety and environmental management program for their 
operations that included elements such as: 19 
• 
safety and environmental information; 
• 
hazards analysis; 
• 
management of change; 
• 
safe work practices 
• 
training; 
• 
assurance of quality and mechanical integrity of critical equipment; 
• 
and audit of safety and environmental management program elements. 
Rather than ensuring continual safety improvement and evaluation of the effectiveness of safeguards 
through more rigorous requirements (e.g., using language such as “shall”), the standard relied upon 
permissive language such as “should” and “recommends.” For example, API 75 only permissively stated 
that owners and operators “should,” rather than “shall,” require that program elements be documented and 
reviewed to assure they continued to be suitable, adequate, and effective.20 
On June 30, 1994, MMS published a notice in the Federal Register stating that it would closely monitor 
the voluntary adoption of API 75 by OCS operators for two years.21 In another notice published in the 
Federal Register on July 18, 1996, MMS stated that it collaborated with API to conduct an annual series 
of surveys to gauge how well OCS operators were implementing SEMP through API 75.22 The MMS 
stated that surveys conducted in January 1995 and January 1996 showed OCS operators “well on their 
way to implementing SEMP plans,” and if progress similar to this were maintained, the MMS expected 
that many of these companies’ SEMP plans would be “fully implemented in the field within the next 1-2 
years.”23 As MMS continued to collect information, it deferred deciding for a mandatory or voluntary 
adoption of the SEMP by OCS lessees. 
Throughout the 1990s and 2000s then, MMS monitored the voluntary adoption of SEMP, but it was not 
until 2006 that MMS again addressed making SEMP, and potentially elements addressed by API 75, a 
regulatory requirement.24 At that time, MMS published a study of 310 incident that resulted in 13 
fatalities and 97 injuries.25 MMS’s analysis indicated that the contributing causes to the majority of these 
incidents were associated with four SEMP elements: hazards analysis, management of change, 
mechanical integrity, and operating procedures. MMS observed, “requiring operators to implement 
 
19 API Recommended Practice, 75, 3rd ed., Recommended Practice for Development of a Safety and Environmental 
Management Program for Offshore Operations and Facilities, May 2004 (Reaffirmed May 2008). 
20 Ibid., p 2. 
21 Oil and Gas and Sulphur Operations in the Outer Continental Shelf, 59 Fed. Reg. 29277 (Notice, June 30, 1994). 
22 Safety and Environmental Management Program (SEMP) on the Outer Continental Shelf (OCS), 61 Fed. Reg. 
37493 (Notice, July 18, 1996). 
23 Ibid. 
24 Oil and Gas and Sulphur in the Outer Continental Shelf (OCS)—Safety and Environmental Management Systems, 
71 Fed. Reg. 29278 (Advanced Notice of Proposed Rulemaking, May 22, 2006). 
25 Ibid. 

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these critical elements of an integrated safety management system could address MMS’s concerns 
with performance and ultimately improve safety and environmental compliance on the OCS.”26 
This proposal was not without strong opposition. The Offshore Operators Committee (OOC),27 a large 
industry group comprising major oil company representatives of which BP is a member, conducted a 
workshop in September 2009.28 The OOC resisted making SEMP a required regulation. Instead, OOC 
compared MMS’s proposal to adopt API 75 as regulation to the potential damage from a hurricane: “Both 
are disruptive to operations and are costly to recover from!”29 OOC also asserted that MMS failed to 
understand that the existing voluntary programs for safety and environmental protections were effective, 
that the industry’s safety record continued to improve without the need for prescriptive regulation. OOC 
asserted that the “recordkeeping” envisioned in SEMP/SEMS did nothing to keep people safe, thereby 
making the implementation of SEMS unnecessary.30 OOC concluded that offshore safety could be most 
improved through the continued use of voluntary safety programs that allowed the “various operators the 
opportunity to style their programs to fit their corporate culture and operations” and the need to “modify 
worker behavior.”31 Ultimately, it was only after the consequences of Macondo were fully realized did 
safety and environmental management systems become a regulatory requirement. 
2.1.1 
The Outdated API Offshore Safety Management System Approach 
API 75 was, in part, based upon API 750, “Management of Process Hazards,” whose safety focus is for 
the “prevention of catastrophic releases of toxic and explosive material.” API 75, though, lacks the 
explicit purpose of preventing major hazard accidents and instead encompasses offshore safety and 
environmental protection in general.32 As generally discussed in Volume 2, the low probability of major 
accidents can lead to low perception of risk. As a result, offshore drillers may not assess major accident 
scenarios and identify controls to prevent or mitigate them.33 Both BP and Transocean illustrated this 
lapse at Macondo. For example, BP’s risk matrix for Macondo did not consider potential blowouts, but 
 
26 Ibid. 
27 According to the Offshore Operators Committee Mission Statement, available on its website: “The Offshore 
Operators Committee (OOC) is a non-profit organization comprised of any person, firm or corporation owning 
offshore leases and any person, firm or corporation engaged in offshore activity as a drilling contractor, service 
company, supplier or other capacity that desires to participate in the work of OOC or the Offshore Operators 
Committee…The Committee's activities are focused on providing its member operators with information and 
technical support that will assist them in conducting their offshore activities in a manner that will promote sound 
safety and environmental operational practice.” See “About the OOC” at http://www.offshoreoperators.com 
(Accessed March, 26, 2016). 
28 OOC. Offshore Operators Committee SEMS Feedback, September 2, 2009; 
http://big.assets.huffingtonpost.com/MMS-2008-OMM-0003-0030.3.pdf (accessed March 26, 2016). 
29 Verret, A. MMS Expectations, Offshore Operators Committee SEMS Feedback, September 2, 2009; 
http://big.assets.huffingtonpost.com/MMS-2008-OMM-0003-0030.3.pdf (accessed March 26, 2016). 
30 Parker, W. Closing Statement, Offshore Operators Committee SEMS Feedback, September 2, 2009; 
http://big.assets.huffingtonpost.com/MMS-2008-OMM-0003-0030.3.pdf (accessed March 26, 2016). 
31 Parker, W. Closing Statement, Offshore Operators Committee SEMS Feedback, September 2, 2009; 
http://big.assets.huffingtonpost.com/MMS-2008-OMM-0003-0030.3.pdf (accessed March 26, 2016). 
32 API Recommended Practice, 750, 1st ed., Management of Process Hazards, January 1990. 
33 Volume 2, Section 4.1. 

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rather other more probable well control issues such as a stuck pipe or lost circulation.34 In the case of 
Transocean, safety critical procedures identified and addressed personal safety hazards or relatively minor 
spills rather than potential loss of well control events.35 
API 75 states that operators should develop SEMP documentation addressing 11 management program 
elements such as hazard analysis, management of change, incident investigation, and audits.36 While the 
11 elements are important safety management systems, they fall short of the more rigorous approach 
taken by the Center for Chemical Process Safety (CCPS), which details additional elements that include 
process safety culture, management review and continual improvement, workforce involvement, and 
measurement and metrics.37 These key topics and others are either missing or not effectively addressed in 
API 75. Moreover, language of the SEMP/SEMS guidelines weakens their impact. API 75 does not 
recommend a specific safety goal such as preventing accidents or controlling hazards, nor does it 
reference a risk goal such as ALARP. 
The provisions listed in API 75 for each management program element are typically activity-based,38 
meaning that the mere completion of an activity does not necessarily focus on the effectiveness of 
accident prevention measures, or necessarily result in actual risk reduction. For example, the hazard 
analysis element in API 75 states the purpose of the analysis is “to identify, evaluate, and where 
unacceptable, reduce the likelihood and/or minimize the consequences of uncontrolled releases and other 
safety or environmental incidents.”39 Without a risk-reduction requirement such as ALARP, this 
formulation leaves what is “unacceptable” entirely to the discretion of owners/operators, rendering the 
regulator powerless to proactively question or intervene, even if the owners/operators’ efforts seem 
minimal or insufficient. 
Both API RP 750 and API 75 were first issued early in the development of process safety principles. API 
750 is no longer published, and although API 75 was reaffirmed in 2008 and 2013, has not been updated 
since 2004. Neither reflects current process safety principles described throughout Volume 3, yet API 75 
is a cornerstone of offshore US safety regulations requiring operators to “develop, implement, and 
maintain a safety and environmental management system (SEMS) program [that addresses] elements 
described in American Petroleum Institute’s Recommended Practice for Development of a Safety and 
Environmental Management Program for Offshore Operations and Facilities.” 40 
 
34 Volume 3, Section 4.4.2. 
35 Volume 3, Sections 1.8.2 - 1.8.4. 
36 API Recommended Practice, 75, 3rd ed., Recommended Practice for Development of a Safety and Environmental 
Management Program for Offshore Operations and Facilities, May 2004 (Reaffirmed May 2008). 
37 Center For Chemical Process Safety. Guidelines for Risk Based Process Safety; John Wiley & Sons: Hoboken, 
NJ, 2007. 
38 The CSB coined the term “activity-based” in its Chevron regulatory report; USCSB, 2013. Regulatory Report: 
Chevron Richmond Refinery Pipe Rupture and Fire, Richmond, CA, August 6, 2012, p 9, Report No. 2012-03-I-
CA, April 2013, http://www.csb.gov/assets/1/19/Chevron_Regulatory_Report_11102014_FINAL_-_post.pdf 
(accessed January 25, 2016). 
39 API Recommended Practice, 75, 3rd (2004, reaffirmed 2008) ed., Recommended Practice for Development of a 
Safety and Environmental Management Program for Offshore Operations and Facilities, p 7. 
40 30 C.F.R. § 250.1900 (2016). 

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2.2 
Purpose of the Regulations and Role of the Regulator 
Offshore safety regulators exist, in part, to hold industry accountable for health, safety, and environmental 
protection standards in their offshore operations, and to address other issues not necessarily related to 
safety, such as licensing, revenue collection, and environmental protection and stewardship. Due to the 
dangers posed by high-hazard offshore oil and gas operations, the US government has an interest in 
establishing minimum safety standards and outside verification mechanisms to oversee that industry 
follows those standards to benefit of workers and the environment. The catastrophic potential for injuries, 
deaths, or damage that could result without an effective regulator cannot in good conscience be tolerated, 
and companies may not always choose to operate with appropriate protections unless the government 
requires it. At a minimum, offshore regulations explain to industry and the public the boundaries and 
expectations for those protections. These offshore resources are to some extent considered held in public 
trust, so another of the regulator’s key tasks relates to effective stewardship of the deepwater assets 
themselves. Moreover, the regulator must act on environmental protection issues, driven by the growing 
need to safeguard the natural environment and the interest of all stakeholders as it grants operators and 
drillers a public license to extract offshore resources safely for the benefit of the corporation and the 
overall US economy. 
Regulators can conduct oversight responsibilities through varied mechanisms, both proactively and 
reactively, to influence industry safety improvements. Regulators can challenge safety claims that 
industry makes and assure their implementation of safety management systems in general through 
inspections, audits, and incident investigation. Some regulatory attributes inherently provide a regulator 
with more tools or position the regulator to provide more effective—and even more proactive—oversight 
in high-hazard industries like offshore drilling. 41 
 
 
 
41 See Section 0 for a summary of these regulatory attributes, though they will be discussed more in depth 
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2.3 
An Alternative Regulatory Model: The Safety Case 
Following the Macondo blowout, numerous widely circulated official investigative reports recommended 
broad improvements to the US offshore regulatory regime. Many specifically promoted adopting a 
fundamentally different regulatory model for deepwater drilling in the outer continental shelf region of 
the US, the “safety case.” They included: 
• 
The National Commission on the BP Deepwater Horizon Oil Spill (National Commission) which 
stated, “The Department of the Interior should develop a proactive, risk-based performance 
approach specific to individual facilities, operations and environments, similar to the ‘safety case’ 
approach in the North Sea. … Require operators to develop a comprehensive ‘safety case’ as part 
of their exploration and production plans—initially for ultra-deepwater (more than 5,000 feet) 
areas, areas with complex geology, and any other frontier or high-risk areas—such as the 
Arctic.”42 
• 
The National Academy of Engineering (NAE), along with the National Research Council (NRC), 
examined the probable causes of the Macondo explosion, fire, and oil spill, recommending that 
the US “fully implement a hybrid regulatory system that incorporates a limited number of 
prescriptive elements into a proactive, goal oriented risk management system for health, safety, 
and the environment.” 43 
• 
Det Norske Veritas (DNV), one of the leading classification and certification bodies operating 
worldwide, asserted, “The current safety regime for the US Gulf of Mexico is largely a 
prescriptive regulation with no requirement for safety cases to be performed.… an offshore safety 
regime based on a performance-based regulation requiring safety cases including risk assessments 
supplemented by required or recommended specific prescriptive regulation for selected areas is 
the most effective regime model.”44 
• 
The Department of Interior recommended several improvements concerning its offshore safety 
regime, including specific reference to the safety case model: “The Department Will Adopt 
Safety Case45 Requirements for Floating Drilling Operations on the OCS … based on IADC 
[International Association of Drilling Contractors] Health, Safety and Environmental Case 
Guidelines for Mobile Offshore Drilling Units (2009).”46 The DOI further recommended: 
 
42 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling. Deepwater: The Gulf Oil 
Disaster and the Future of Offshore Drilling - Report to the President; Janurary, 2011; pp 252-253. 
43 National Academy of Engineering and National Research Council. Macondo Well Deepwater Horizon Blowout: 
Lessons for Improving Offshore Drilling Safety; December 14, 2011; p 90. 
44 Pitblado, R.; Bjerager, P.; Andreassen, E. An Effective US Offshore Safety Regime; Det Norske Veritas: 22 2010, 
July; p 3. http://www.dnvusa.com/Binaries/1008-001%20Offshore%20Update_Key%20aspects_tcm153-
430982.pdf (accessed March 16, 20106). 
45 DOI defines the safety case as follows: “A safety case is a comprehensive and structured set of safety 
documentation to ensure the safety of a specific vessel or equipment. This documentation is essentially a body of 
evidence that provides a basis for determining whether a system is adequately safe for a given application in a 
given environment;” Department of Interior. Increased Safety Measures for Energy Development on the Outer 
Continental Shelf; May 27, 2010; p 27. 
46 Department of Interior. Increased Safety Measures for Energy Development on the Outer Continental Shelf; May 
27, 2010; p 27. 

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“Finalize a rule that would require operators [on the OCS] to develop a robust safety and 
environmental management system for offshore drilling operations,” which DOI described as “a 
comprehensive, systems-based approach to safety and environmental management that 
incorporates best practices from around the globe.”47 
• 
The United States Coast Guard (USCG) recommended that it “work with BOEMRE to evaluate 
the benefits of shifting to a “Safety Case” approach similar to that used in the North Sea, a 
method in which there is a more holistic approach to safety.48 
These recommendations reflect a logical progression of a regulatory approach seen throughout the history 
of offshore oil and gas regulation. It makes sense for society to protect its interests through appropriate 
regulation if an industry, such as offshore oil and gas exploration and production is capable of 
endangering the lives or safety of workers or creating significant health and safety or environmental risk 
to its citizens. Such a regulatory regime could be: (1) a state-run, nationalized industry centrally 
controlled by the government; (2) a prescriptive licensing and approval regime with audits and 
inspections and penalties for failure to comply with regulations; or (3) a safety case type of regime where 
the company proposes to conduct its activities and then explains its major accident hazards assessment 
and control plan to the regulator, typically (but not always) for acceptance before commencing drilling 
exploration or production operations. 
Some prescriptive regulation is typically present in a safety case regime, such as technical requirements 
for equipment, but overall, the safety case approach refers to a goal-setting, risk-reduction approach 
intended to drive the risk of a major accident event to as low as reasonably practicable. Upon drilling a 
new well, this begins in the project development stage, when the leaseholder has a duty to demonstrate to 
the regulator that the risks of its design are ALARP, and how it will reassess any significant changes to 
maintain risk levels. The well design inherently defines what operational risks drilling contractors will 
manage and how they will implement, monitor, and maintain effective barriers (also referred to as 
controls) for each of those risks. Ultimately, the drilling contractor submits for the offshore regulator’s 
acceptance its “case” concerning the controls it has implemented to maintain operational safety. 
A key advantage of this type of a goal-setting regulatory approach, in contrast to a regulatory scheme 
based on compliance with prescriptive requirements, is the freedom or flexibility it provides companies to 
control risks, and to be able to rely on good practice using their own preferred methods to achieve safe 
operation. This flexibility is particularly necessary for both the regulator and the company in situations 
affecting unique scenarios on the cutting edge of technology where good engineering practice continues 
to develop, such as Arctic operations. In fact, as explained by offshore expert Peter Wilkinson, “[o]ne of 
the main benefits [of the safety case model] is not the finished product, but the actual process of preparing 
 
47 Ibid., pp 27- 28. 
48 As offshore safety regulators in the US, BOEMRE and USCG formed a Joint Investigation Team to investigate 
the Deepwater Horizon disaster. BOEMRE and the USCG published separate reports addressing their respective 
areas of safety responsibility; USCG, Report of the Investigation into the Circumstances Surrounding the 
Explosion, Fire, Sinking and Loss of Eleven Crew Members Aboard the Mobile Offshore Drilling Unit Deepwater 
Horizon in the Gulf of Mexico, April 20-22, 2010, Volume 1, MISLE Activity Number 3721503; p 127. 
http://www.uscg.mil/hq/cg5/cg545/dw/exhib/DWH%20ROI%20-%20USCG%20-%20April%2022,%202011.pdf 
(Accessed March 26, 2016). 

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the safety case and having to identify hazards and review the installation design, construction and 
operation.”49 
A regulatory model like the safety case regime, however, demands that the regulator play a fundamental 
role in ensuring that industry continually strives to reduce risks to ALARP. This means the regulator is 
instrumental in using a variety of means to ensure good practices exist across the sector. Put simply, the 
regulator sets the goals (e.g., drive the risk as low as reasonably practicable), reviews a company’s 
proposed written case for safety in terms of its operations and management of hazards, and then ensures 
that a company performs as promised in meeting stated goals. If the regulator has concerns about a 
company’s safety case or operational performance, then it has the resources and other tools to understand 
the company’s position through direct engagement. The regulator can then can either accept the 
company’s case, or alternatively initiate efforts to obtain necessary improvement. According to 
Wilkinson, the safety case regime even helps make regulators more effective. He noted: “safety cases 
make it possible for the regulator’s interventions to be more effective because the safety case should 
identify the critical safety issues and the regulator’s interventions can concentrate on these.”50 These 
interventions reach far beyond complying with items on a checklist or maintaining completed 
documentation about required tasks that the operators and drillers performed.51 So a duty holder’s 
systematic analysis of major hazards documenting the risks, control measures and safety management 
systems meant to ensure their effectiveness is a necessary improvement in the US offshore environment. 
This would be the case whether the BSEE adopts an entire safety case system or imports to the US 
attributes from safety case regimes to fill regulatory gaps. 
The safety case model is not a form of self-regulation. The regulator’s acceptance of a safety case does 
not constitute approval, in the traditional sense, that somehow the burden of maintaining safe operations 
shifts from the regulated to the regulator. Instead, acceptance is more akin to a comprehensive review of 
the operator’s or driller’s submitted safety case by the regulator. The regulator’s acceptance of the safety 
case implies that the submitter’s proposed documentation satisfactorily proposes good practice relating to 
identified hazards. Thereafter, the burden of operating safely continues to remain on the parties 
undertaking the risk, and the regulator will hold those parties to the submitted standards in the written 
cases for safety. 
The regulator in a goal-setting, risk reduction regime must cultivate a sophisticated and nuanced 
approach, remaining nimble and playing different roles in different circumstances. The regulator’s role 
ranges from one of challenging industry to establish sound safety strategies, and enforcing the 
prescriptive aspects of the existing system—as well as each duty holder’s written case for safety—to 
partnering with operators and guiding industry toward continual improvements in offshore drilling 
safety.52 This volume explains why the regulator must be independent and have adequate resources, 
 
49 Shaw, S. What’s the Case for a US Version of the Safety Case?; April 2, 2014; http://www.erm.com/en/news-
events/platform/whats-the-case-for-a-us-version-of-the-safety-case/ (accessed March 26, 2016). 
50 Ibid. 
51 Ibid. 
52 Wilkinson, P. Creating a New Offshore Petroleum Safety Regulator, Presentation to IADC, Australian Petroleum 
Production & Exploration Association Conference, March 25, 2003; p 5 
http://www.nopsema.gov.au/assets/document/IADC-Annual-General-Meeting.pdf (accessed March 26, 2016). 

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including necessary funding and a strong workforce with sufficient technical expertise, interpersonal 
skills, credibility, and authority to work alongside industry for continual improvement.53 
While safety case type approaches were practiced by the UK and Australia before Macondo, 
recommendations for a safety case regime in response to the Macondo blowout also occurred 
internationally.54 On September 23, 2013, based on its own independent studies, the European 
Commission implemented Safety of Offshore Oil and Gas Operations Directive that was “broadly based” 
on the preexisting UK offshore safety regime and related requirements, including preparation of a written 
case for safety.55 This direct response to Macondo was in recognition of the more than 1,000 oil and gas 
production facilities offshore in the oceans surrounding EU member countries. 
2.4 
Managing Major Accident Hazards in the US 
The CSB concludes that while adopting the SEMS regulation was an improvement for offshore US 
regulations, it remains inadequate for major accident prevention in offshore drilling, and BSEE is not 
fully empowered to accomplish its mission as the offshore regulator. 
To illustrate by analogy, the current SEMS model in many ways parallels the Occupational Safety and 
Health Administration (OSHA) onshore Process Safety Management (PSM) regulation for fixed 
industrial facilities, which the CSB has studied extensively in its 17-year operating history.56 The CSB 
has found that the onshore PSM approach used to regulate petroleum refineries in the US relies on a 
regulatory framework that duty holders can satisfy by “checking the box” when completing a variety of 
required safety-related activities, such as a process hazard analysis or management of change. Yet 
compliance with those requirements can still fail to improve safety. The activity may not adequately 
identify major hazards or control major accident events, in part, because the regulatory requirement lacks 
targeted risk-reduction, goal-setting requirements, and accommodations for a proactive regulator to 
engage with the facility. As such, the PSM approach has devolved into an activity-based, reactive 
regulatory climate. Activity-based approaches run contrary to longstanding onshore process safety good 
practice that advocates for the ultimate goal of continual risk reduction. In 1992, CCPS emphasized “after 
identifying hazards and analyzing effects of those hazards, a management system should be in place to 
assure that all practical steps have been taken to reduce the risks.”57 
Despite the improvements to the US offshore regulatory scheme, as with onshore, there is no risk-
reduction goal of ALARP or equivalent. In addition, the current US offshore regulatory framework 
emphasizes the regulator’s role to a reactive one rather than encourage meaningful proactive engagement 
 
53 Ibid., p 3. 
54 Norway has a regulatory model that reflects many of the attributes in Section 0, but distinct differences exist 
between its regulatory model and that in the UK and Australia. Some of those differences are described 
throughout this volume. 
55 http://www.hse.gov.uk/offshore/directive.htm (accessed January 26, 2016). 
56 For example, the CSB investigated major industrial accidents such as the 2005 BP Texas City explosion and fire, 
which resulted in 15 fatalities and 180 injuries; the 2010 heat exchanger catastrophic rupture at Tesoro Anacortes 
Refinery, which led to seven fatalities, and the Chevron Richmond Refinery pipe rupture and fire, which caused 
worker injuries and over 15,000 local residents to seek medical attention. See, www.csb.gov. 
57 CCPS. Plant Guidelines for Technical Management of Chemical Process Safety; American Institute of Chemical 
Engineers: New York, NY, 1992; p 67. 

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among the regulator, industry, and workforce. The outcome, therefore, may be similar to the PSM 
approach in which offshore operators may comply with SEMS requirements and communicate this 
compliance to the regulator, but they are not adequately or effectively identifying and controlling hazards 
or implementing good practice. 
 

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3.0 Inadequate Post-Macondo Safety Management 
Regulations 
The offshore oil and gas industry is subject to legal requirements from a variety of regulators, including 
the US Environmental Protection Agency (EPA),58 Bureau of Ocean Energy Management (BOEM),59 US 
Coast Guard (USCG), and BSEE. Specific to safety, the Outer Continental Shelf Lands Act (OCSLA) 60 
gives broad authority to the USCG and BSEE to regulate activities that affect the safety of life and 
property on facilities and vessels operating on the Outer Continental Shelf. The USCG and BSEE have 
signed Memoranda of Agreements (MOAs) to assign responsibilities between the two agencies for 
inspecting and overseeing systems and sub-systems on Mobile Offshore Drilling Units (MODUs)61 and 
other fixed OCS facilities.62 For example, on MODUs like the Deepwater Horizon, BSEE has lead 
regulatory oversight on systems related to drilling and completion activities, and the USCG has lead 
oversight of fire suppression systems. While the CSB acknowledges the dual regulatory role in 
maintaining safety on the OCS, the analysis contained in this report focuses on BSEE’s regulatory 
responsibility because many of the systems for which the USCG has lead oversight (e.g., station keeping, 
fire protection, emergency evacuation plans, etc.) were not causal to the initial well release and explosion 
which were the focus of the CSB’s investigation. 
This chapter demonstrates that despite changes post-Macondo, US offshore safety regulations still do not 
provide an adequate safety management framework for major accident prevention. Without a continual 
risk-reduction goal like ALARP, the SEMS regulations are not as agile in driving ongoing industry 
improvement, especially because the US regulatory regime lacks mechanisms for rapidly adapting to 
 
58 For example, 40 C.F.R. Part 122. See also Memorandum of Understanding Between the Environmental Protection 
Agency and the Department of the Interior Concerning the Coordination of SPDES Permit Issuance with the 
Outer Continental Shelf Oil and Gas Lease Program. 
http://www.bsee.gov/uploadedFiles/BSEE/Newsroom/Publications_Library/001_1984-MOU.pdf (accessed 
Feburary 26, 2016). 
59 “BOEM promotes energy independence, environmental protection and economic development through 
responsible, science-based management of offshore conventional and renewable energy and marine mineral 
resources,” http://www.boem.gov/About-BOEM/ (accessed Feburary 26, 2016). 
60 43 U.S.C. § 1331 et seq. 
61 As defined by 46 U.S.C. § 2101 15(a), a MODU is “a vessel capable of engaging in drilling operations for the 
exploration or exploitation of subsea resources.” 
62 USCG and BSEE. Subject: Mobile Offshore Drilling Units (MODUs). Memorandum of Agreement between the 
Bureau of Safety and Environmental Enforcement - U.S. Department of the Interior and the U.S. Coast Guard - 
U.S. Department of Homeland Security; BSEE/USCG MOA: OCS008; June, 4 2013; 
http://www.bsee.gov/uploadedFiles/BSEE/Newsroom/Publications_Library/MOA_OCS-
08_MODUs_signed_06.04.2013.pdf (accessed Feburary 26, 2016); 
USCG and BSEE. Subject: Fixed Outer Continental Shelf (OCS) Facilities. Memorandum of Agreement between 
the Bureau of Safety and Environmental Enforcement - U.S. Department of the Interior and the U.S. Coast Guard 
- U.S. Department of Homeland Security; BSEE/USCG MOA: OCS008; September, 19, 2014; 
http://www.bsee.gov/uploadedFiles/BSEE/International_and_Interagency_Collaboration/Interagency/Agreements
/MOA-2014-USCG-Fixed%20OCS%20Facilities.pdf (accessed Feburary 26, 2016); 

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ongoing advances in technology and safety practices.63 This shortcoming results in weak, performance-
based requirements that lead to the activity-based approach in which both industry and regulator can 
become preoccupied with the completion and documentation of activities without necessarily 
demonstrating that the implemented safety management activities can effectively control hazards and 
minimize risks. Moreover, SEMS regulations apply explicitly to the operator, whose SEMs program is 
intended to manage all the activities of third-party contractors. Finally, BSEE’s safety management 
regulations do not adequately provide for worker participation throughout the lifecycle of hazardous 
operations. 
To that end, companies’ current SEMS plans may therefore not be adequate for major accident prevention 
because SEMS regulations: 
• 
lack a risk-reduction methodology to drive continual improvement (e.g., ALARP); 
• 
fail to facilitate the regulator’s ability to require companies to make safety changes based on 
lessons learned from major incidents and newly identified hazards; 
• 
lack a requirement for documented demonstration that the safety management system elements as 
implemented will reduce risk to the targeted level; 
• 
favor of activity-based requirements; 
• 
fail to focus specifically on process safety for major accident prevention, instead seeking to 
address health and safety matters as a general proposition; 
• 
lack sufficient focus on human factors/safety critical task analysis requirements for each element; 
• 
misapply legal responsibility for safety solely to operators even though contractors also create or 
control risk; 
• 
lack clarity on the major accident safety responsibilities of key parties, such as operators and 
drilling contractors, for safety critical tasks; and 
• 
do not adequately address the important role of workers and their representatives in safety 
management. 
This chapter describes approaches taken by other international regimes that offer alternative means to 
ensure that those who control risk are responsible for managing it. 
3.1 
SEMS: No Goal-Setting Risk-Reduction Standard 
A performance-based regulatory approach with a goal of reducing risk to ALARP increases both the 
industry’s and regulator’s flexibility. For industry, performance regulations provide freedom to conduct 
its work as it determines best as long as it can demonstrate the chosen methods will work consistently 
with good practice. Good practice, however, is not a static concept; in fact, it will evolve with time.64 In 
some cases, standards for what is ALARP for a particular activity do not exist, so they will need to be 
developed to adequately control risks. As new technology is developed or costs of previously developed 
technologies decrease, the standard for “reasonably practicable” will change. Consequently, an ALARP 
approach provides the regulator with the flexibility to make ALARP judgements, keep what constitutes 
 
63 See Section 3.1.1. 
64 UK HSE. Principles and Guidelines to assist HSE in its judgements that duty-holders have reduced risk as low as 
reasonably practicable, http://www.hse.gov.uk/risk/theory/alarp1.htm (accessed March 1, 2016). 

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good practice under review, and influence the industry to adopt new practices. To that end, a credible, 
well-resourced regulator would have a full range of tools needed to advise and, if necessary, to challenge 
a company’s assertion that its risk-reduction practices satisfy ALARP. 
Pertinent to ALARP, the Baker Panel65 notes in its 2007 report (“the Baker Report”) on BP and its 
process safety performance following the 2005 BP Texas City disaster that an effective process safety 
management system builds on an “improvement cycle” that “should include, in practice, continual 
reduction of process risk and improvements in safety performance according to some measurable 
criteria.”66 
The Baker Panel defined “continuous improvement” as 
• 
improving controls for process hazards, including process safety knowledge and competence of 
workers; 
• 
improving process safety leadership of supervisors; 
• 
improving process engineering to identify and design to remove or mitigate the effects of process 
hazards; 
• 
extending legal compliance to reducing risks through best practices; 
• 
extending mere compliance with internal standards to learning from operating experiences, 
incident and near-miss investigations, hazard studies, audits, and other assessments to improve 
those internal standards; and 
• 
identifying and implementing not only those external standards that must be observed, but also 
those that represent best practices that can lead to process safety excellence.67 
While offshore SEMS regulations require companies to identify hazards and manage safety,68 they do so 
without a goal either the industry or regulator can work toward, such as maintaining good practice as an 
ALARP approach would. Therefore, the US still lacks a goal-setting risk-reduction standard in its 
offshore regulatory scheme to encourage continual improvement and adaptability. 
Volume 3 of this report describes ALARP as the level at which further risk reduction, through 
incremental sacrifice (in terms of cost, time, effort, or other expenditure of resources) becomes grossly 
disproportionate to the incremental risk reduction achieved.69 In practice, prescriptive legislation is easier 
to comply with and for regulators to enforce compliance (e.g., by inspecting or auditing by checking 
boxes concerning requirements contained on a list), whereas goal-setting legislation is a more challenging 
regime to operate.70 But, the goal-based ALARP requirements demand more effort by the company to 
 
65 In the aftermath of the BP Texas City Incident, BP followed the recommendation of the CSB and formed an 
independent panel known as the Baker Panel to conduct a thorough review of the company’s corporate safety 
culture, safety management systems, and corporate safety oversight at its US refineries. For a copy of their 
findings and recommendations, see http://www.csb.gov/assets/1/19/Baker_panel_report1.pdf (accessed January 
25, 2016). 
66 Ibid., p 166. 
67 Ibid. 
68 30 C.F.R. § 250.1900. 
69 Volume 3, Section 4.1. 
70 The BSEE SEMS section Chief spoke on this issue. “We need to emphasize that compliance requires operators to 
demonstrate that they are implementing SEMS as a performance-based standard and not just checking off items 
on a list;” OTC: BSEE reports 100% SEMS compliance after first cycle. Oil & Gas Journal; Slocum, M., Ed., 

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ensure risks are reduced to targeted levels, and they empower the regulator to drive further improvements 
over time. 
The UK, Norwegian, and Australian offshore regulators have all adopted ALARP-type goals. The UK’s 
Health and Safety Executive (HSE) has produced much guidance concerning ALARP. The agency’s 
guidance on ALARP for onshore facilities explains that to achieve the goal of ALARP, the risk reduction 
measures to prevent major accidents should at least be “relevant good practice.”71 The duty holder must 
demonstrate that the good practice is relevant and up to date, and must review risks and risk reduction 
measures as circumstances, technology, knowledge, and information evolve.72 When assessing whether 
risks are reduced to ALARP, companies in the UK weigh the risk “against the measures necessary to 
eliminate the risk. The greater the risk … the less will be the weight to be given to the factor of cost.”73 
In Norway, the Petroleum Safety Authority (PSA) regulates offshore safety74 and ensures that companies 
adapt to safety and technological advances through its performance-based approach to regulatory 
oversight.75 While Norwegian regulations do not specifically reference ALARP, they do require 
companies to choose the technical, operational, and organizational solutions that offer the best results, 
provided the costs are not significantly disproportionate to the risk reduction achieved.76 For instance, the 
regulations call on “the operator and others participating in the activities” to address the goal of 
operational safety through any effective method, as opposed to requiring specific actions.77 This approach 
ensures that duty holders are primarily responsible for determining the best methods to mitigate the risks 
they create, which in turn helps the regulator ensure that safety practices keep pace with advances in 
industry. 
The Australian National Offshore Petroleum Safety and Environmental Management Authority 
(NOPSEMA) requires companies to reduce risks to the health and safety of people onboard offshore 
facilities to a level as low as reasonably practicable.78 NOPSEMA explains that to do this, the company 
 
May 7, 2015, http://www.ogj.com/articles/2015/05/otc-bsee-reports-100-sems-compliance-after-first-cycle.html 
(accessed March 26, 2016). 
71 UK HSE. Guidance on ALARP Decisions in COMAH. 
http://www.hse.gov.uk/foi/internalops/hid_circs/permissioning/spc_perm_37/ (accessed January 5, 2016). 
72 Ibid. 
73UK HSE. Principles and guidelines to assist HSE in its judgements that duty-holders have reduced risk as low as 
reasonably practicable. http://www.hse.gov.uk/risk/theory/alarp1.htm#P4_129 (accessed January 5, 2016). 
74 See http://www.psa.no/about-us/category877.html (accessed March 26, 2016). 
75 See Petroleum Safety Authority Norway, Regulations Relating to Health, Safety and the Environment in the 
Petroleum Activities and at Certain Onshore Facilities (The Framework Regulations) (2013), 
http://www.ptil.no/framework-hse/category403.html (accessed March 26, 2016). 
76 Regulations Relating to Health, Safety and the Environment in the Petroleum Activities and at Certain Onshore 
Facilities (The Framework Regulations), Section 11 Risk Reduction Principles, http://www.ptil.no/framework-
hse/category403.html#_Toc282603288 (accessed March 26, 2016). 
77 Regulations Relating to Health, Safety and the Environment in the Petroleum Activities and at Certain Onshore 
Facilities (The Framework Regulations), Section 7 Responsibilities pursuant to these regulation, 
http://www.ptil.no/framework-hse/category403.html#_Toc282603288 (accessed March 26, 2016). 
78 NOPSEMA. ALARP Guidance Note; N-04300-GN0166, Rev 6; June, 2015; 
http://www.nopsema.gov.au/assets/Guidance-notes/N-04300-GN0166-ALARP.pdf (accessed March 26, 2016). 

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“has to show, through reasoned and supported arguments, that there are no other practical measures that 
could reasonably be taken to reduce risks further.”79 
In the US offshore, the OCSLA states that it “shall be the duty of any holder of a lease or permit under 
this subsection to (1) maintain all places of employment within the lease area or within the area covered 
by such permit in compliance with occupational safety and health standards and, in addition, free from 
recognized hazards to employees of the lease holder or permit holder or of any contractor or subcontractor 
operating within such lease area.”80 Although it can be argued that this duty supports implementing a 
goal-setting regulatory requirement like ALARP, BSEE has yet to explicitly adopt such a requirement 
within its regulatory scheme or the SEMS rule. This may change with the proposal of new well control 
regulations described in Section 3.1.4. 
The SEMS rule states that operators “through your management, are responsible for the development, 
support, continued improvement, and overall success of your SEMS program.”81 At specified intervals 
and at least annually, US operators are required to review their SEMS programs to determine if the 
program “continues to be suitable, adequate and effective (by addressing the possible need for changes to 
policy, objectives, and other elements of the program in light of program audit results, changing 
circumstances and the commitment to continual improvement) and document the observations, 
conclusions and recommendations of that review.”82 But without a benchmark such as ALARP in place 
establishing goals for risk reduction, this can become a documentation exercise that does not actually 
result in the reduction of risk. 
Performance-based regulatory regimes already exist in the US. The US Nuclear Regulatory Commission 
(NRC) was an early adopter of the performance-based approach to regulation. The NRC defines 
performance-based regulation as “approach that focuses on desired, measurable outcomes, rather than 
prescriptive processes, techniques, or procedures” but does not specify precisely how to achieve the 
results.83 According to the Commission, performance-based regulations permit licensees to “have 
flexibility to determine how to meet the established performance criteria in ways that encourage and 
reward improved outcomes.”84 Under this approach, a regulator focuses on whether the goal of as low as 
reasonably achievable, or ALARA (see callout box), has been achieved in “processes, procedures, and 
judgments” related to both design and operational risk85 For design risk, quantitative judgements are more 
likely, but when operational risk is addressed, qualitative factors become more important. “What is 
essential, for ALARA practiced at any level, is that the choices be fully documented, together with the 
criteria which have [been relied on to make] those choices. When the criteria are qualitative, it is more 
 
79 Ibid. 
80 43 U.S.C. § 1348 (b). 
81 30 C.F.R. § 250.1909. 
82 30 C.F.R. § 250.1909 (d). 
83 US Nuclear Regulatory Commission. Performance-based regulation, http://www.nrc.gov/reading-rm/basic-
ref/glossary/performance-based-regulation.html (accessed January 19, 2016). 
84 US Nuclear Regulatory Commission. Background and Staff Guidance on Performance-Based Regulation, 
http://www.nrc.gov/about-nrc/regulatory/risk-informed/concept/performance.html (accessed January 19, 2016). 
85 Fassò, A.; Rokni, S. Operational Radiation Protection in High Engery Physics Accelerators. Implemenation of 
ALARA in Design and Operations of Accelerators; SLAC-PUB-13800; SLAC National Accelerator Laboratory: 
May, 2009; p 7. http://www.slac.stanford.edu/cgi-wrap/getdoc/slac-pub-13800.pdf (accessed March 26, 2016). 

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likely that subjective judgments play a large role, but those judgements must be equally recorded [as they 
are for quantitative judgements].” 86 
 
 
3.1.1 
The Use of Standards and Guidance in ALARP-based Regulatory 
Regimes 
For the most part, the goal-setting regulations in the UK, Norway, and Australia do not use prescriptive 
requirements to follow either national or international or industry standards. Where prescription is used, it 
is in connection with, for example, the areas to be covered in hazard analysis documentation or the 
frequency of examination and testing of lifting equipment.87 Both the UK HSE and Norway PSA publish 
regulatory topic guidance to advise duty holders on how to achieve compliance with their respective 
regulations. For example, the UK has an Approved Code of Practice (ACOP) for preventing fire, 
explosion, and emergency response on offshore installations.88 It is not mandatory to follow the guidance 
in an ACOP, but HSE has indicated “if you do follow the guidance you will normally be doing enough to 
 
86 Ibid., pp 6-7. 
87 Whewell, I. Former Director, UK HSE Offshore Division, Personal communication, July 6, 2011. 
88 UK HSE. Prevention of fire and explosion, and emergency response on offfshore installations; L65; HSE: 2012; 
http://www.hse.gov.uk/pUbns/priced/l65.pdf (accessed March 2, 2016). 
In the US, the nuclear industry provides a model of continual risk reduction. Similar 
to ALARP, the target is “as low as reasonably achievable” (ALARA). The Nuclear 
Regulatory Commission’s Reactor Oversight Process (ROP), its primary 
performance-based regulation, is the means by which it achieves its mission of public 
health and safety in commercial nuclear power plant operations.a The ROP uses 
seven “cornerstones,” such as mitigating systems and barrier integrity, to monitor 
three performance areas (reactor safety, radiation safety, and security safeguards).b 
Licensee performance data, inspection plans, quarterly assessments, and assessment 
and inspection responses are tied to each performance area and several cross-cutting 
objectives, such as worker involvement and human performance.c Licensees may 
choose their own methods to meet overarching performance goals, which are guided 
by their duty to reduce risks to ALARA.d The Commission has stated that this 
flexibility is one of the main reasons its regulatory philosophy encourages continual 
improvement.e 
a US Nuclear Regulatory Commission. Reactor Oversoght Process (ROP), 
http://www.nrc.gov/NRR/OVERSIGHT/ASSESS/ (accessed March 26, 2016). 
b US Nuclear Regulatory Commission. Reactor Oversight Process; December, 2006; p 2. 
http://pbadupws.nrc.gov/docs/ML0708/ML070890365.pdf (accessed March 26, 2016). 
c Ibid., p 3. 
d US Nuclear Regulatory Commission.. Guidance for Performance - Based Regulation; NUREG/BR-
0303; December, 2002; p 1. http://www.nrc.gov/reading-rm/doc-
collections/nuregs/brochures/br0303/br0303.pdf (accessed March 26, 2016). 
e US Nuclear Regulatory Commission. Background and Staff Guidance on Performance-Based 
Regulation, http://www.nrc.gov/about-nrc/regulatory/risk-informed/concept/performance.html 
(accessed January 19, 2016). 

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comply with the law.”89 A duty holder can also comply with the law if it demonstrates that alternative 
measures are likely to be just as effective as those specified in the ACOP. ACOPs tend not to refer to 
specific technical standards, but describe the way of achieving a specific outcome. ACOPs are being used 
less as they can have the effect of discouraging technical progress and innovation. 
HSE also publishes guidance with every set of regulations it produces, giving the duty holder advice on 
interpreting the legislation and information on how to achieve compliance.90 Following this guidance is 
not mandatory, but like ACOPs, in most cases an inspector will accept that if the duty holder follows the 
guidance, it complies with the requirement. 
Guidance published HSE’s Energy Division comes in a variety of forms:91 leaflets, books on its 
webpages, advisory notices,92 and research reports. While the latter is not strictly guidance, research 
reports represent available knowledge on hazards and risks, and duty holders would be expected to take 
into account the latest research in forming their hazard and risk control strategies. Although HSE does not 
publish lists of approved technical and other standards, some are referenced in the guidance HSE 
publishes. The best example is in Guidance for the Topic Assessment of Major Accident Hazard Aspects 
of Safety Cases (GASCET).93 Ultimately, while industry good practices can form the basis for hazard 
assessments, the duty holder is required to effectively identify and control risks as lessons are learned, 
technology improves, and information is shared.94 The key question for assessing major hazard risk is 
whether anything more can be done to reduce risk.95 While technical guidance like GASCET helps relate 
assessors’ technical judgements to good practice, it does not cover all major accident event hazards poised 
offshore. For instance, GASCET identifies basic well design and equipment hazards,96 but it does not 
identify guidance and standards for the assessment of well conditions and operational activities, such as 
those occurring at Macondo at the time of the blowout. In effect, assessors and industry will rely on the 
general ALARP guidance previously described to assess the adequacy of organizational and operational 
barriers identified in Volumes 2 and 3. 
Norway’s offshore regulator publishes guidelines on how to achieve the requirements in its provisions.97 
When using a recommended standard in a regulatory guideline, the “party can normally assume that the 
 
89 UK HSE. Legal status of HSE guidance and ACOPs, http://www.hse.gov.uk/legislation/legal-status.htm (accessed 
March 3, 2016). 
90 Whewell, I. Former Director, UK HSE Offshore Division, Personal communication, July 6, 2011. 
91 UK HSE. Guidance, http://www.hse.gov.uk/guidance/index.htm (accessed March 2, 2016). 
92 UK HSE. Safety alerts and notices, http://www.hse.gov.uk/offshore/notices/sn_index.htm (accessed March 2, 
2016). 
93 UK HSE. GASCET (Guidance for the topic assessment of the major accident hazard aspects of safety cases), 
http://webcommunities.hse.gov.uk/connect.ti/gascet/view?objectId=62036 (accessed March 2, 2016). 
94 Ibid. 
95 UK HSE. Guidance on Risk Assessment for Offshore Installations; Offshore Information Sheet No. 3/2006; 
http://www.hse.gov.uk/offshore/sheet32006.pdf (accessed March 2, 2016). 
96 The main hazard sources identified in GASCET are intermediate formations, reservoir-introduced fluids, 
explosive, radioactive sources, pressure vessels, and dropped objects. 
97 PSA. Guidelines Reguarding the Framework Regulations, http://www.psa.no/framework/category408.html 
(accessed March 2, 2016). 

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regulatory requirements have been met.”98 If a party wants to adopt an approach not specified in the 
guideline standards, the party must document how the same level of health, safety and environmental 
protection is achieved.99 The regulatory guidelines are mostly technical in nature,100 but parties must 
demonstrate “strategies and principles that form the basis for design, use and maintenance of barriers, so 
that the barriers' function is safeguarded throughout the offshore or onshore facility's life” for operational 
and organizational barriers not addressed in the guideline standards.101 
In Australia, NOPSEMA does not endorse any ACOPs or standards.102 NOPSEMA has clarified its stance 
on good practice, “the term ‘good practice’ in NOPSEMA guidance documentation therefore is taken to 
refer to any well-defined and established standard or codes of practice adopted by an 
industrial/occupational sector, including ‘learnings’ from incidents that may yet to be incorporated into 
standards. Good practice generally represents a preferred approach; however, it is not the only approach 
that may be taken. While good practice informs, it neither constrains, nor substitutes for, the need for 
professional judgement.”103 
3.1.2 
Insufficient US Alternative Legal Mechanisms to Drive Continual Safety 
Improvements 
The OCSLA calls upon the Secretary of the Interior to promulgate safety regulations that include “the use 
of the best available and safest technologies which the Secretary [of the Interior] determines to be 
economically feasible, wherever failure of equipment would have a significant effect on safety, health, or 
the environment.”104 But these requirements do not apply if the Secretary of the Interior determines that 
the safety improvements do not justify the costs of implementing the technology.105 
A BSEE regulation calls for using the “best available and safest technology (BAST) whenever practical 
on all exploration, development, and production operations” 106 … “in general, we consider your 
compliance with BSEE regulations to be the use of BAST.”107 Limiting BAST to compliance with BSEE 
 
98 Regulations Relating to Health, Safety and the Environment in the Petroleum Activities and at Certain Onshore 
Facilities (The Framework Regulations), Section 24 Use of recognized standards, http://www.psa.no/framework-
hse/category403.html#_Toc357595254 (accessed March 26, 2016). 
99 Ibid. 
100 For a summary, see OGP. Regulators' use of standards; Report No. 426; OGP Standards Committee: March, 
2010; p 33 and Annex F1. 
101 Regulations Relating to Management and the Duty to Provide Information in the Petroleum Activities and at 
Certain Onshore Facilities (The Management Regulations), Section 5, Barriers, 
http://www.psa.no/management/category401.html#_Toc377975494 (accessed March 26, 2016). 
102 NOPSEMA. Guidance Note: ALARP; N-04300-GN0166, Revision 6; June, 2015; p 6. 
http://www.nopsema.gov.au/assets/Guidance-notes/N-04300-GN0166-ALARP.pdf (accessed March 2, 2016). 
103 Ibid 
104 43 U.S.C. § 1347 (b). 
105 43 U.S.C. § 1347(b). The Supreme Court explained that this provision of the OCSLA is one in which Congress 
has imposed two independent requirements: that an administrative action be “feasible” and that it is justified by a 
balancing of costs and benefits. Indus. Union Dep’t., AFL-CIO v. Am. Petroleum Inst., 448 U.S. 607, 709 n. 27 
(1980). 
106 30 C.F.R. § 250.107(c). 
107 30 C.F.R. § 250.107(d). 

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regulations, however, undermines the potential impact of requiring the use of the best available and safest 
technology not required in the BSEE regulatory scheme. 
The BSEE Director may require additional measures to ensure using BAST to avoid equipment failure 
that would have a significant effect on safety, health, or the environment, so long as it is “economically 
feasible” and “the benefits outweigh the costs.”108 Nevertheless, the cost-benefit analysis needed to meet 
this requirement results in a high burden of proof on the regulator to require operators to do something not 
specifically stated in the regulations. It differs from the continual improvement mechanism of the North 
Sea and Australian regimes, which require companies to monitor new developments and continually drive 
risks to ALARP.109 
30 C.F.R. § 250.198 is an example of a BSEE regulation that incorporates certain standards by reference, 
yet it is also an example of not being easily adaptable. The effect of incorporation by reference is that the 
incorporated documents are treated as if they were published in the Federal Register as part of the 
underlying regulation.110 The incorporated material, like any other properly issued regulation, has the 
force and effect of law.111 Some of the documents incorporated into that regulation include ANSI/ASME 
Codes, API Recommended Practices, ASTM Standards, American Welding Society Codes, and American 
Gas Association Reports. The regulation states that the documents incorporated in the rule are limited to 
the edition cited, but that BSEE will publish any changes to such documents in the Federal Register 
before amending the rule. Yet the regulation also states that BSEE may change the version of a document 
referenced in this rule without an opportunity for public comment if the agency determines the revisions 
would result in safety improvements or represent new industry standard technology and they do not 
impose undue costs on the affected parties.112 The aim of this rule, to be able to adapt BSEE requirements 
to changing practices and technology without having to go through the rulemaking process, could 
therefore be subverted if a party challenges BSEE’s finding that revisions do not impose “undue costs.” 
This situation leaves updating the regulation to the more traditional process, which is time-consuming, 
burdensome, and often difficult, even where the regulated matters are far less complex. 
Finally, BSEE regulations have a provision for alternative procedures or equipment, but the requirements 
to receive approval are vague in comparison to the guidelines international regulatory regimes have 
provided their own assessors.113 Currently, to receive approval, “you must either submit information or 
give an oral presentation to the appropriate Regional Supervisor. Your presentation must describe the site-
 
108 30 C.F.R. § 250.107(d). 
109 Reducing to ALARP does not assure the best risk controls available are reasonably practicable. According to the 
UK HSE, “it is only if the cost of implementing these new methods of control is not grossly disproportionate to 
the reduction in risk they achieve that their implementation is reasonably practicable. For that reason, we accept 
that it may not be reasonably practicable to upgrade an older plant and equipment to modern standards. However, 
there may still be other required measures to reduce the risk ALARP: for example, partial upgrades or alternative 
measures;” UK HSE, Some fallacies about ALARP, http://www.hse.gov.uk/risk/theory/alarpglance.htm (accessed 
March 26, 2016). 
110 Update of Revised and Reaffirmed Documents Incorporated by Reference, 75 Fed. Reg. 22219 (Final Rule, April 
28, 2010). 
111 30 C.F.R. § 250.198(a)(3); Update of Revised and Reaffirmed Documents Incorporated by Reference, 75 Fed. 
Reg. 22219 (Final Rule, April 28, 2010). 
112 30 C.F.R. §§ 250.198(a)(2)(i)-(ii). 
113 30 C.F.R. 250.141 

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specific application(s), performance characteristics, and safety features of the proposed procedure or 
equipment.”114 As HSE has indicated, among other benefits, guidelines provide “transparency to the 
assessment decisions and criteria” and “a basis for consistency in the assessment process and its 
outcomes.”115 BSEE does not yet provide such guidance to its intended audience. 
3.1.3 
Ineffective Regulatory “Workarounds” 
Since US offshore regulations do not have an effective continual safety improvement requirement, 
rulemaking is required to change any part of an existing regulation that may become outdated or 
irrelevant after new safety information emerges. Since the rulemaking process is onerous, BSEE 
sometimes communicates safety messages to offshore lessees through Notices to Lessees (NTLs),116 
Information to Lessees (ITLs),117 and Safety Alerts.118 NTLs are “formal documents that provide 
clarification, description, or interpretation of a regulation or OCS standard; provide guidelines on the 
implementation of a special lease stipulation or regional requirement; provide a better understanding of 
the scope and meaning of a regulation by explaining BSEE interpretation of a requirement; or transmit 
administrative information”.119 ITLs are “formal documents that provide additional information and 
clarification, or interpretation of a regulation, OCS standard, or regional requirement, or provide a better 
understanding of the scope and meaning of a regulation by explaining BSEE interpretation of a 
requirement”.120 Safety Alerts are used to inform industry of the circumstances surrounding an incident or 
a near-miss and to provide “recommendations that should help prevent the recurrence of such an incident 
on the OCS.”121 
These documents may be helpful in providing guidance for regulatory compliance, but the NTLs, ITLs, 
and Safety Alerts themselves cannot expand upon what BSEE regulations require, and BSEE has no 
ability to force operators or contractors to comply with the guidance in these documents. For instance, in 
2000, MMS issued a Safety Alert urging offshore lease holders to install a backup mechanism for 
activating subsea blowout preventers.122 In the Safety Alert, MMS stressed that a secondary activation 
system was an “essential component” of any rig’s emergency response system. Although having a backup 
 
114 30 C.F.R. 250.141(c) 
115 UK HSE. GASCET (Guidance for the topic assessment of the major accident hazard aspects of safety cases), 
http://webcommunities.hse.gov.uk/connect.ti/gascet/view?objectId=62036 (accessed March 2, 2016). 
116 BSEE. Notices to Lessees and Operators, http://www.bsee.gov/Regulations-and-Guidance/Notices-to-Lessees-
and-Operators/ (accessed March 2, 2016). 
117 BSEE. Information to Lessees and Operators, http://www.bsee.gov/Regulations-and-Guidance/Information-to-
Lessees-and-Operators/ (accessed March 2, 2016). 
118 BSEE. Current Safety Alerts, http://www.bsee.gov/Regulations-and-Guidance/Safety-Alerts/Safety-Alerts/ 
(accessed March 2, 2016). 
119 BSEE. Notices, Letters, and Information to Lessees and Operators (NTL)s, http://www.bsee.gov/Regulations-
and-Guidance/Notices-to-Lessees/index/ (accessed March 2, 2016). 
120 Ibid. 
121 BSEE. Current Safety Alerts, http://www.bsee.gov/Regulations-and-Guidance/Safety-Alerts/Safety-Alerts/ 
(accessed March 2, 2016). 
122 BSEE. MMS Safety Alert: Accidental Disconnect of Marine Drilling Risers; Safety Alert No. 186; March 2, 
2000; http://www.bsee.gov/uploadedFiles/BSEE/Regulations/Safety_Alerts/Safety%20Alert%20No%20186.pdf 
accessed March 26, 2016). 

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activation system for BOPs should have been a best safety practice, BSEE’s use of the Safety Alert could 
not require operators to install such backup systems because it was not contained in a regulation. Thus, 
Safety Alerts and Notices can provide useful guidance on a short-term basis, but because they are not 
incorporated into regulation, they cannot require timely adaptation of best safety practices. 
3.1.4 
Recent BSEE-proposed Regulatory ALARP-type Language 
In April 2015, BSEE proposed new regulations that it described as “most substantial rulemakings in the 
history” of offshore safety in the United States.123 As part of these regulations, BSEE introduced ALARP-
type language to “reduce risks to the lowest level practicable” that if adopted, could empower BSEE with 
a more proactive regulatory authority. Table 3-1 lists some of the current language in § 250.107 and 
BSEE’s proposed changes. 
BSEE explained the proposed regulations were intended to consolidate equipment and operational 
requirements with a focus on blowout preventer equipment, well design, well control, casing, 
cementing, real-time well monitoring, and subsea containment. Just has described in Section 3.1.1, 
few standards exist for assessing well conditions and operational activities that form the basis of 
organizational and operational barriers intended to prevent a major accident. So, while BSEE and industry 
may be able to rely on good practice to guide the judgment on technical barriers, demonstrating that 
organizational and operation barriers reduce risks to the lowest level practicable will be a continual 
improvement process based on company’s SEMS program. 
As Volume 3 documents, neither BP nor Transocean effectively implemented their numerous 
programs to manage safety at Macondo. Furthermore, their indicators tended to be lagging instead of 
leading; thus, they did not sufficiently monitor the real-time health and effectiveness of the physical 
barriers and safety management systems to prevent a major accident. Therefore, a provision to 
“reduce risks to the lowest level practicable” will empower BSEE to challenge the efforts and claims 
that risks are being managed by companies’ and require that more be done if necessary. 
 
 
 
123 Oil and Gas and Sulphur Operations in the Outer Continental Shelf—Blowout Preventer Systems and 
Well Control, 80 Fed. Reg. 21504 (Proposed Rule, April 17, 2015) (to be codified at 30 C.F.R. Part 250). 

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Table 3-1. Current and BSEE proposed language for § 250.107, What must I do to protect health, safety, property, 
and the environment? 
Current 
Proposed 
 (a) You must protect health, 
safety, property, and the 
environment by: 
 (1) Performing all operations in a 
safe and workmanlike manner; and 
 (2) Maintaining all equipment 
and work areas in a safe condition. 
Paragraph (a) of this section would be revised to include a 
general performance-based requirement that operators 
utilize recognized engineering practices that reduce risks 
to the lowest level practicable during activities covered by 
the regulations and conduct all activities pursuant to the 
applicable lease, plan, or permit terms or conditions of 
approval. Recognized engineering practices may be drawn 
from established codes, industry standards, published peer-
reviewed technical reports or industry recommended 
practices, and similar documents applicable to 
engineering, design, fabrication, installation, operation, 
inspection, repair, and maintenance activities. This risk 
reduction objective is used in other regulatory programs 
and is consistent with BSEE’s goal of taking a more risk-
based approach in its regulations. This risk reduction 
principle has also been included in a recently published 
industry document (API Bulletin 97) which addresses 
drilling, completion, and workover activities. 
Does not currently exist. 
Proposed paragraph (e) would be added to clarify BSEE's 
authority to issue orders when necessary to protect health, 
safety, property, or the environment. The first sentence 
authorizes BSEE to issue orders to ensure compliance with 
the regulations. The second sentence clarifies that BSEE 
may order that operations of a component or facility be 
shut-in because of a threat of serious, irreparable, or 
immediate harm to health, safety, property, or the 
environment posed by those operations or because the 
operations violate law, including a regulation, order, or 
provision of a lease, plan, or permit. 
 
 
3.2 
SEMS Activity-Based Requirements: A Compliance-Based 
Mentality 
Although intended to deliver features of a performance-based regime, the SEMS rule does not drive 
improved safety performance as do the NRC or other international offshore regimes. SEMS requires 

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operators to develop and implement a safety and environmental management system that incorporates 
several safety elements typically found in SMS models, including hazard analysis, management of 
change, operating procedures, and incident investigations. It directs operators to address all required 
elements and “maintain a safety and environmental management system.”124 But the SEMS rule does not 
contain a risk-reduction goal or target that would provide the regulator with the tools to drive continual 
risk-reduction at offshore facilities. It does not function like a strong performance-based regulation 
because completing these actions does not necessarily result in a reduction of risk. Directives such as 
“maintain,”125 “comply,”126 and “manage”127 do not suggest what must be achieved with safety elements. 
In contrast, a goal-setting, risk-reduction, performance-based regulation would include a target (ALARP) 
and would specify what should be accomplished in order to meet the requirements of existing good 
practice. 
Nor does SEMS require the operators to document recognized methodologies, rationales, and conclusions 
to claim that safeguards to control hazards will be effective. Rather, SEMS requires that facilities 
“manage” identified hazards,128 with no further requirement regarding how far the operator must go to 
control those hazards. This is, in fact, weaker language than OSHA’s PSM regulation, which specifically 
requires that hazards be controlled.129 Terms such as “manage hazards” and “resolve recommendations” 
are activity-based, as they do not include a performance-based requirement to control hazards or prevent 
major accidents.130 In fact, this formulation allows for managing hazards and resolving recommendations 
without determining that action be taken. Therefore, companies may conduct a weak or inadequate hazard 
analysis and not identify or manage the appropriate safety critical tasks and equipment—yet still comply 
with the regulation.131 
Volume 2 highlights that while the SEMS regulations Rule promotes safety and environmental protection, 
it lack requirements for companies to explicitly address potential major accident events.132 By identifying 
potential MAEs, companies can draw clear linkages between barriers created by safety critical tasks and 
equipment and the major accident hazards they are designed to prevent or mitigate.133 As part of the 
process to reduce MAE risk to ALARP, companies could explicitly demonstrate the adequacy of the 
barriers and the distribution of the types of controls implemented (e.g., engineering, procedural, or 
administrative), among other factors.134 
 
124 30 C.F.R. § 250.1900. 
125 Ibid. 
126 30 C.F.R. § 250.1901. 
127 Ibid. 
128 30 C.F.R. § 250.1911(a). 
129 29 C.F.R. § 1910.119(e)(1). 
130 The CSB Macondo Investigation Report Volume 2, Section 6.1.1 details this point. 
131 Volume 2 of this report concludes the SEMS regulations are insufficient in guaranteeing safety performance 
improvements throughout the SCE lifecycle. 
132 Volume 2, Section 4.1. 
133 Volume 2, Section 4.2.3. 
134 Volume 2, Section 4.2.3. 

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BSEE incident investigation regulations are another example of activity-based requirements. Under 
SEMS requirements, operators must “establish” investigation procedures to “identify” contributing 
factors (human or otherwise) and “recommend” changes as a result of findings.135 Companies must also 
“establish” corrective action plans based on the findings for investigations. BP actually met these 
requirements when it investigated the March 8, 2010 kick at Macondo, exemplifying the weakness of the 
current regulatory language.136 During BP’s investigation, Transocean identified the need to improve 
hazard recognition among the crew,137 but neither BP nor Transocean examined Transocean’s safety 
management systems meant to prevent a lack of hazard awareness. So while a human factor was 
“identified” as causal to the incident—delayed crew well kick response—only technical recommendations 
resulted from the investigation rather than effectively addressing the identified need to improve kick 
response—a causal factor in the Macondo incident. Ultimately, SEMS language requires an activity of 
conducting an investigation, but not implementing effective recommendations to reduce risk to a targeted 
level. Therefore, companies can still be in compliance with regulations without actually reducing risk 
when investigating incidents and resolving recommendations. 
Critics have voiced their concern over the lack of robust performance-based, risk-reduction requirements 
in SEMS. The safety management subcommittee of BSEE’s own advisory group, the Ocean Energy 
Safety Advisory Committee (OESAC), stated that the SEMS regulation, although well-intended, is 
essentially a prescriptive rule “promotes the idea that operators only have to meet the minimal 
requirements in order to comply with the regulations.”138 Similarly, the International Association of 
Drilling Contractors (IADC) called the SEMS rules “overly prescriptive” in its comments to BSEE.139 
IADC urged BSEE to “consider a wholesale re-write of 30 C.F.R. Subpart S to make it more goal-setting 
and less prescriptive.”140 Without sufficient goal-setting, risk-reduction features, a regime risks losing 
focus on risk reduction because companies are doing only the activities the rule requires—which may not 
be the safest practicable action. 
IADC’s position should carry some weight in this debate. The IADC HSE Case Guidelines have been 
required for use in 10 countries and are recognized as best practice in 10 additional countries, some of 
which had regulations pending to require adoption or use of the Guidelines, suggesting more jurisdictions 
are moving toward ALARP-type risk-reduction approaches.141 
 
135 30 C.F.R. § 250.1919. 
136 Volume 3, Section 2.4. 
137 Ibid. and Email from Macondo Rig Manager, Transocean, to Wells Team Leader, BP, Subject: Hazard 
Recognition, 18 March, 2010, BP-HZN-2179MDL00289217, 
http://www.mdl2179trialdocs.com/releases/release201305171200030/TREX-000684.pdf (accessed October 7, 
2015). 
138 OESAC. Safety Management System Enchancement Reccomendation; SMS SC – Vector #2 Recommendation; 
April 10, 2012; p 4. 
139 IADC. Re: Revisions to Safety and Environmental Management Systems (SEMS); Docket ID BOEM; November 
11, 2011; pp 4-5. http://www.bsee.gov/uploadedFiles/IADC%2011-11-2011.pdf (accessed March 26, 2016). 
140 Ibid. 
141 Countries having required use of the guidelines by force of regulation include Australia, Cuba, Denmark, Faeroe 
Islands, Germany, Ireland, the Netherlands, New Zealand, Norway, and the United Kingdom, while Angola, 
Canada, Brazil, India, Malaysia, Oman, Qatar, Senegal, South Africa, and Trinidad & Tobago have recognized the 

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Australia provides another example of a regulation requiring a performance-based hazards analysis, in 
contrast to BSEE’s hazards analysis requirement in the SEMS rule. In Australia, safety case assessments 
must provide a “well-considered, detailed description of a suitable and sufficient formal safety 
assessment.”142 In that analysis, the duty holder must evidence an understanding of “the factors that 
influence risk and the controls that are critical to controlling risk, the magnitude and severity of 
consequences arising from major accident events for the range of possible outcomes, and the likelihood of 
potential major accident events.”143 These requirements are more nuanced, but similar in spirit, to the US 
SEMS requirement to “identify, evaluate, and manage the hazards involved in the operation,”144 to 
“control technology applicable to the operation,145 and to “evaluate possible safety and health effects on 
employees and potential impacts to the human and marine environments, which may result if the control 
technology fails.”146 
In contrast, the Australian regime also requires hazard analyses to clarify linkages between hazards, 
control measures, and the potential major accident events.147 This is how Australian duty holders show 
that their chosen control measures will manage the risks to ALARP. Australia requires a prioritized list of 
actions in the hazard analysis to reduce risks to ALARP.148 Because the SEMS rule is not accompanied 
by an ongoing duty to reduce risks to ALARP (or another appropriate goal-based target), the hazards 
analyses could be outdated (i.e., the controls could be ineffective or may not reduce risks to a practicable 
level) but still comply with the rule, which must be updated “when an internal audit is conducted to 
ensure that it is consistent with your facility’s current operations.”149 
In Australia and the UK, the hazard analysis is a key component of a safety case document, which the 
regulator must accept before obtaining a license to operate. In these regimes, the regulator proactively 
reviews the operator’s identified hazards and risk-reduction strategies to ensure that risks are reduced to 
the required standard. The regulator may require the installation of a missing control or barrier if it would 
further reduce risks to ALARP. Moreover, during the UK safety case acceptance process, the regulator 
often questions the hazard and risk analyses, and if necessary, updates or changes them if discovered to be 
insufficient, thus creating robust industry/regulator interaction before hazardous activities begin.150 
 
guidelines as best practice. Recent regulatory changes may have affected the status afforded the Guidelines by 
these countries. See http://www.iadc.org/iadc-hse-case-guidelines/ (accessed March 26, 2016). 
142 NOPSEMA. Guidance Note: Hazard Identification; N- 04300-GN0107, Rev. 5; December, 2012; p 7. 
http://www.nopsema.gov.au/assets/Guidance-notes/N-04300-GN0107-Hazard-Identification.pdf (accessed March 
26, 2016). 
143 Ibid. 
144 30 C.F.R. § 250.1911(a). 
145 30 C.F.R. § 250.1911(a)(1)(iii). 
146 30 C.F.R. § 250.1911(a)(1)(iv). 
147 NOPSEMA. Guidance Note: Hazard Identification; N- 04300-GN0107, Rev. 5; December, 2012; p 7. 
http://www.nopsema.gov.au/assets/Guidance-notes/N-04300-GN0107-Hazard-Identification.pdf (accessed March 
26, 2016). 
148 Ibid. 
149 30 C.F.R. § 250.1911(a). 
150 Discussed in more detail in Section 4.1.2. 

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3.3 
Safety Responsibility Offshore 
Volume 3 introduced two categories of well risk: design and operational.151 The operator’s well design 
and drilling program are the basis for the drilling and well control operations undertaken by a drilling 
contractor and other well services providers. The well design is the first opportunity to assess hazards and 
ensure risks are reduced to ALARP. Once the well design has been determined, the operator then holds 
the primary responsibility to plan the work and apply the ALARP principle in selecting the contractor and 
rig. The well operator should review hazards throughout the lifecycle of the well, from initial spudding to 
final abandonment, and assess any significant changes to ensure well design risks remain ALARP. While 
the well operator controls design risk, the drilling contractor has the most direct control over the 
management of day-to-day operations, and a primary responsibility for the overall safety of the drilling 
installation and the personnel onboard.152 The combination of facility and wellsite specific conditions 
could increase the risk or complexity of various drilling operations. Therefore, an integral second 
opportunity arises to assess hazards and ensure operational, organizational, and technical control 
measures are sufficient to reduce risks to ALARP, namely a review of the hazards in the facility’s 
activities, equipment, personnel, and drilling and well control operations provides. 
By illustration, Figure 3-1 depicts Transocean’s corporate well delivery process, beginning with the 
development of a Well Construction Plan in conjunction with the operator (referred to as the “Customer” 
in Figure 3-1) that was considered a key component of the development, communication, and execution 
of a well plan. The process depicted in Figure 3-1 is a joint endeavor, and as such, the control of major 
accident risk requires the operator and the drilling contractor to play a role in managing risk. Central to 
this effort are the safety management systems the parties use to plan, conduct, and monitor well design 
and operational risk. While these safety management systems will overlap in some cases, they will each 
have their own focus and attributes. 
 
151 Volume 3, Section 1.8.1. 
152 As stated in Transocean’s Well Control Handbook, “The OIM is responsible for overall safety of the Installation 
and all personnel onboard,” Internal Company Document, Transocean. Well Control Handbook, Issue HQS-OPS-
HB-01, Revision 00, July 22, 2011, Well Planning Considerations, Exhibit 5781, 
http://www.mdl2179trialdocs.com/releases/release201302281700004/Braniff_Barry-Depo_Bundle.zip (accessed 
October 7, 2015). 

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Figure 3-1. Transocean’s Well Delivery Process as defined by Transocean corporate polices.153 
Despite this, SEMS applies explicitly to the operator, and drilling contractors are not required to develop 
and implement a SEMS program.154 Instead, an operator’s SEMS program is intended to manage all the 
activities on an offshore facility, including those of the operator and any third-party contractors. The Rule 
states that operators have sole responsibility for creating and managing their SEMS program, even though 
contractors “may adopt appropriate sections of the operator’s SEMS program.”155 This exclusion goes 
against a basic tenet of managing safety within high-hazard operations: those that create or have the 
 
153 Volume 3 provides evidence to indicate that Transocean did not follow its own internal well delivery process. 
This figure was taken from a document not publicly available (Field Operations Policies & Procedures Manual), 
but a similar figure and supporting text can be found in Transocean’s Performance and Operations Policies and 
Procedures Manual which is publically available: Performance and Operations Policies and Procedures Manual-
Level L1A, Issue #1, Revision # 00, April 19, 2010, Section 2 (Planning and Reporting), Subsection 1 (Well 
Construction Planning), TRN-MDL-00607022. 
http://www.mdl2179trialdocs.com/releases/release201302281700004/Rose_Adrian-Depo_Bundle.zip Exhibit 
1474 (accessed January 28, 2015). 
 Internal Company Document, Transocean. Field Operations Policies & Procedures Manual, Issue 01, Revision 
00, HQS-POP-PP-01, August 8, 2009, Performance Management: Rig and Well Operation Management, TRN-
CSB-0002274-TRN-CSB-00023200. 
154 As stated by BSEE, “[BSEE] does not regulate contractors; we regulate operators;” Oil and Gas and Sulphur 
Operations in the Outer Continental Shelf, 75 Fed. Reg. 63609 (Final Rule, October 15, 2010) (to be codified at 
30 C.F.R. Part 250). 
155 The rule exempts contractors from primary responsibility for compliance by stating that operators must document 
contractor selection criteria, obtain and evaluate information about the contractor’s safety and environmental 
performance, and ensure that contractors have their own written safe work practices. 30 C.F.R. § 250.1914. 

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greatest control of the risks associated with a particular activity are responsible for managing them.156 
Members of BSEE’s own advisory committee, the Ocean Energy Safety Advisory Committee, pointed 
out the dangers of this gap in contractor coverage in the SEMS Rule, which the committee described as 
“very confusing.”157 In fact, the committee recommended in April 2012 that BSEE address the 
jurisdiction the SEMS Rule covers158 as well as the responsible party.159 
Section 3.3.1 of this chapter describes the difficulties BSEE has had in holding contractors responsible for 
safety. Section 3.3.2 describes international regulatory obligations placed on both operators and drilling 
contractors to conduct a risk assessment of all major hazards, define the systems and barriers to control 
those hazards, and demonstrate their effectiveness throughout the drilling process. 
3.3.1 
Offshore Regulatory Ambiguity and Industry/Stakeholder Response 
BP and Transocean had corporate polices for risk management that reflected their roles in the Macondo 
project, but neither company ensured the policy implementation, which could have minimized the gap 
between Transocean’s work-as-done by BP and work-as-imagined.160 Instead, a lack of clarity regarding 
hazard identification and risk management roles and responsibilities resulted in significant safety gaps, 
leaving the companies vulnerable to a major accident. Clarifying these roles and responsibilities is 
important because contractors compose an estimated 80% of offshore workers performing drilling and 
well completion activities.161 In the case of Macondo, only 8162 of the 126 individuals on the rig at the 
time of the blowout were BP employees, while 79 were Transocean employees, 25 were other third-party 
 
156 UK HSE. Planning to do business in the UK offshore oil and gas industry; October, 2011; p 2. 
http://www.hse.gov.uk/offshore/guidance/entrants.pdf (accessed March 26, 2016); NOPSEMA, What is a safety 
case, http://www.nopsema.gov.au/safety/safety-case/what-is-a-safety-case/ (accessed March 26, 2016). 
157 “As currently written the SEMS regulations state that only Operators are responsible for developing and 
implementing a SEMS program. In fact the preamble for the SEMS regulations specifically states, “This final rule 
does not require that a contractor have a SEMS program;” OESAC. Safety Management System Enchancement 
Reccomendation; SMS SC – Vector #2 Recommendation; April 10, 2012; p 3. 
158 The Committee explained that the term “system,” when used in conjunction with the term “safety management 
system,” typically represents a complete structure such as vessel or a fixed facility, and therefore encompasses all 
operations, processes, activities and systems that make up each structure. The BSEE SEMS regulations do not 
follow this logic because they apply only to operators and cover only operations and activities that fall under 
BSEE jurisdiction. 
159 OESAC. Safety Management System Enchancement Reccomendation; SMS SC – Vector #2 Recommendation; 
April 10, 2012; p 13. 
160 Volume 3, Section 1.8 illustrates the gap between Transocean’s work-as-imagined and work-as-done at 
Macondo. 
161 MMS made this observation in 2003, and then it was reiterated after Macondo by the National Commission on 
the BP Deepwater Horizon Oil Sill and Offshore Drilling: Oil and Gas and Sulphur Operations in the Outer 
Continental Shelf—Incident Reporting Rule, 68 Fed. Reg. 40585 (Proposed Rule, July 8, 2003) and National 
Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling, A Competent and Nimble Regulator: 
A New Approach to Risk Assessment and Management, Staff Working Paper No. 21, p 7. 
162 Two of the individuals from BP were not part of the crew, but visiting management (the Vice President of 
Drilling & Completion and the Drilling & Completions Operations Manager.) 

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well providers, and 14 were caterers.163 Despite the high reliance on contractors, a historical examination 
of MMS citations and regulatory action leading up to the Macondo blowout reveals that the regulator did 
not hold all employers accountable to this responsibility.164 The data show that MMS chose to limit 
responsibility for safety (and other potential liability) to the operator/lessee. 
In the aftermath of Macondo, BSEE issued Incidents of Noncompliance (INCs) to two contractors, 
Transocean (drilling contractor) and Halliburton (provider of cementing services), for violations of 
regulations leading to the Macondo incident.165 This was the first time in the history of the agency or its 
predecessors that such action was taken against the drilling contractor and another well service provider. 
The INCs issued to Transocean were resolved in a 2013 consent decree, in which BSEE agreed not to 
pursue enforcement if Transocean paid $400 million in fines and met certain health and safety 
conditions.166 This consent decree does not affect BSEE’s overall ability to issue INCs because it did not 
address their validity vis-à-vis Transocean. Halliburton appealed its INCs, and the Interior Board of Land 
Appeals will consider that appeal after the District Court litigation (MDL) has concluded.167 
Although BSEE started citing contractors under 30 C.F.R. § 250.107(a) pursuant to the agency’s authority 
under the OCSLA, ambiguity still exists in US legislation and regulations regarding contractor 
accountability for safety. In a congressional hearing about the release of the Joint Investigation Team final 
report in October 2011, former Director Bromwich cited 43 U.S.C. §1350(b), as the provision in the 
Outer Continental Shelf Lands Act (OCSLA) that supports expanding BSEE enforcement oversight of 
contractors. OCSLA § 24(b), codified at 43 U.S.C. §1350(b), states: 
[e]xcept as provided in paragraph (2), if any person fails to comply with any provision of this 
subsection, or any terms of a lease, license, or permit issues pursuant to this subsection, or any 
regulation or order issued under this subsection after notice of such failure and expiration of any 
reasonable period allowed for corrective action, such person shall be liable for a civil penalty of 
not more than $20,000 for each day of the continuance of such failure. 
 
163 Internal Company Document, Transocean. Personnel On-Board as of 20 Apr 2010 17:09:15, April 20, 2010, 
TRN-MDL-00030435, http://www.mdl2179trialdocs.com/releases/release201303071500008/TREX-00687.pdf 
(accessed March 26, 2016). 
164 For an example, BSEE Civil Penalties and Appeals, available at http://www.bsee.gov/Inspection-and-
Enforcement/Civil-Penalties-and-Appeals/Civil-Penalties-and-Appeals/ (accessed March 26, 2016). 
165 BSEE. BSEE Issues Violations Following Investigation Into Deepwater Horizon: Notices Sent to BP, 
Transocean, and Halliburton. October 12, 2011, http://www.bsee.gov/BSEE-Newsroom/Press-
Releases/2011/BSEE-Issues-Violations-Following-Investigation-Into-Deepwater-Horizon/ (accessed March 26, 
2016). 
166 Partial Consent Decree Between the Plaintiff United States of America and Defendants Triton Asset Leasing 
GMBH, Transocean Holdings LLC, Transocean Offshore Deepwater Drilling Inc., and Transocean Deepwater 
Inc., Doc. 8608, case 2:10-md-02179 (E.D. La.) (Feb. 19, 2013). 
167 “In January 2012, the IBLA, in response to our and the BSEE's joint request, suspended the appeal and ordered 
us and the BSEE to file notice within 15 days after the conclusion of the MDL and, within 60 days after the MDL 
court issues a final decision, to file a proposal for further action in the appeal. The BSEE has announced that the 
INCs will be reviewed for possible imposition of civil penalties once the appeal has ended.” Halliburton Form 10-
K, report to the Securities and Exchange Commission for Fiscal Year 2012 (p 18), 
http://www.sec.gov/Archives/edgar/data/45012/000004501213000086/hal-
12312012x10k.htm#sBEA207F94C6DF488FB8EE5FD8404B586 (accessed January 26, 2016). 

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Presumably, BSEE can regulate contractors because they are encompassed within the broad definition of 
“person” in the aforementioned provision.168 Additionally, in 43 U.S.C. § 1334(a), the introductory 
section covering “Administration of Leasing” on the Outer Continental Shelf,169 explains the subject and 
scope of regulations that the Secretary of the Interior can promulgate for OCS activities. The scope of this 
clause is broad:170 
the Secretary shall administer the provisions of this subsection relating to the leasing of the outer 
Continental Shelf, and shall prescribe such rules and regulations as may be necessary to carry out 
such provisions. The Secretary may at any time prescribe and amend such rules and regulations as 
he determines to be necessary and proper in order to provide for the prevention of waste and 
conservation of the natural resources of the Outer Continental Shelf . . . such rules and regulations 
shall, as of their effective date, apply to all operations conducted under a lease issued or 
maintained under the provisions of this subsection.171 
Immediately, the drilling industry and its stakeholders publicly opposed BSEE’s position and the issuance 
of INCs to Transocean and Halliburton, claiming the Bureau had “no express statutory authority to extend 
its jurisdiction”172 to contractors and “there are no definitions of exactly who is covered, nor are there 
standards for performance.”173 Even some members of Congress are not persuaded by BSEE’s asserted 
authority to hold contractors liable. In the Committee Report for the Department of Interior, Environment 
and Related Agencies Appropriations Bill for Fiscal Year 2013, congressional appropriators noted: 
The Committee continues to be concerned with the Bureau’s stated intentions for the expansion 
of regulatory authority over nonlease holders under the Outer Continental Shelf Lands Act 
(OCSLA). The authority and need for this action has not been explained or justified to the 
Committee, nor how this diversion of limited resources would impact the Bureau’s current 
mission and objectives identified in the fiscal year 2013 budget request. … the Committee directs 
 
168 In the statute, “person” means, in addition to a natural person, “an association, a State, a political subdivision of a 
State, or a private, public, or municipal corporation.” 43 U.S.C. § 1331(d). In the accompanying regulations, 
“person” is similarly defined to include “a natural person, an association (including partnerships, joint ventures, 
and trusts), a State, a political subdivision of a State, or a private, public, or municipal corporation.” 30 C.F.R. § 
250.105. The Part 250 regulations define the word “you” as “a lessee, the owner or holder of operating rights, a 
designated operator or agent of the lessee(s), a pipeline right-of-way holder, or a State lessee granted a right-of-
use and easement.” 30 C.F.R. § 250.105 (emphasis added). A plain language reading of the statute and these 
defining regulations could support BSEE’s position that a contractor, as an agent of the lessee, may be legally 
responsible for compliance. 
169 In an Interim Policy Document issued on August 15, 2012, BSEE cites this section of the OCSLA to support its 
regulatory jurisdiction over all entities that perform activities under OCSLA leasing provisions; BSEE. Issuance 
of an Incident of Non Compliance (INC) to Contractors; IPD No. 12-07; August 15, 2012; 
http://www.bsee.gov/uploadedFiles/Issuance%20of%20an%20Incident%20of%20Non%20Compliance%20to%20
Contractors.pdf (accessed March 26, 2016). 
170 A look at the legislative history for this section of the Act reaffirms its breadth. Congress contemplated that oil 
companies would be the primary actors in OCS leasing and related activities and did not differentiate among 
leaseholders, operators, or contractors. H. CONF. REP. 95-1474 at 1679 (1978). 
171 43 U.S.C. § 1334(a). 
172 http://www.perkinscoie.com/bsee-asserts-jurisdiction-over-offshore-oil-and-gas-service-companies-12-08-2011/ 
(accessed August 28, 2012). 
173 http://rigzone.com/news/article.asp?a_id=116394 (accessed August 28, 2012). 

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that no funds be expended for other purposes until the agency has fully explained its authority, 
intentions, and objectives to the Committee and the public.174 
Furthermore, regulations in Title 30 Part 250, which include safety requirements, define the Secretary’s 
authority to regulate oil, gas, and sulphur exploration, development, and production operations on the 
Outer Continental Shelf under the OCSLA.175 The definitions section states that when the word “you” is 
used in the Part 250 regulations, it “means a lessee, the owner or holder of operating rights, a designated 
operator or agent of the lessee(s), a pipeline right-of-way holder, or a State lessee granted a right-of-use 
and easement.”176 Still, other regulations confuse the definition. For instance, one regulation ensures that 
only co-lessees are jointly and severally liable for regulatory compliance, but then adds in a subsequent 
part that the “person” actually performing the activity to which the lessee requirement applies is also 
jointly and severally responsible for complying with the regulation.177 
3.3.1.1 
Post-Macondo BSEE Efforts to Hold Contractors Responsible for Safety 
BSEE’s decision to issue the INCs to Transocean and Halliburton post-Macondo reflected “the severity of 
the incident, the findings of the joint investigation, as well as Secretary Ken Salazar’s and Director 
Bromwich’s commitment to holding all parties accountable.”178 In his keynote address to the IADC 
annual conference in November 2011, former BSEE Director Bromwich reaffirmed the departure from 
the agency’s previous practice of issuing INCs only to operators. Bromwich noted that law did not require 
the MMS historical practice of limiting its citations to operators. He explained, “the fact that we had 
unilaterally decided to grant immunity to all non-operators was a misguided act of administrative grace 
rather than a result dictated by law or good policy. The fact that we had followed a bad practice was not a 
sufficient reason to continue it.”179 
 
174 Comittee on Appropriations. Department of the Interior, Environment, and Related Agencies Appropriation Bill, 
2013; Report No. 112-586; July 10, 2012; https://www.gpo.gov/fdsys/pkg/CRPT-112hrpt589/html/CRPT-
112hrpt589.htm (accessed March 26, 2016). 
175 30 C.F.R. § 250.101. 
176 30 C.F.R. § 250.105. 
177 “When you are not the sole lessee, you and your co-lessee(s) are jointly and severally responsible for fulfilling 
your obligations . . . unless otherwise provided in these regulations.” 30 C.F.R. § 250.146(a). “Whenever the 
regulations in 30 C.F.R. parts 250 through 282 and 30 C.F.R. parts 550 through 582 require the lessee to meet a 
requirement or perform an action, the lessee, operator (if one has been designated), and the person actually 
performing the activity to which the requirement applies are jointly and severally responsible for complying with 
the regulation.” 30 C.F.R. § 250.146(c). 
178 BSEE. BSEE Issues Violations Following Investigation Into Deepwater Horizon: Notices Sent to BP, 
Transocean, and Halliburton. October 12, 2011, http://www.bsee.gov/BSEE-Newsroom/Press-
Releases/2011/BSEE-Issues-Violations-Following-Investigation-Into-Deepwater-Horizon/ (accessed March 26, 
2016). 
179 BSEE. BSEE Director Delivers Keynote Address at International Association of Drilling Contractors 
Conference, November 11, 2011, http://www.bsee.gov/BSEE-Newsroom/Press-Releases/2011/BSEE-Director-
Delivers-Keynote-Address-at-International-Association-of-Drilling-Contractors-Conference/ (accessed March 26, 
2016). 

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On August 15, 2012, BSEE issued Interim Policy Document No. 12-07, entitled Issuance of an Incident 
of Non Compliance (INC) to Contractors,180 which states that BSEE will issue enforcement actions 
against contractors who, after considering four factors,181 it determines to have engaged in “egregious” 
conduct.182 The document also notes that issuing INCs to contractors does not relieve lessees from 
liability, and in fact, INCs that are issued to contractors will also be issued to the lessee or operator.183 
Since the Macondo incident and the issuance of Interim Policy Document No. 12-07, BSEE has continued 
to issue INCs to non-operators. BSEE investigated a November 16, 2012, incident at a platform in the 
Gulf of Mexico operated by Black Elk Energy Offshore Operations.184 An explosion and fire on Black 
Elk’s platform killed three workers and caused several other serious injuries during welding operations.185 
This was the second incident investigation for which BSEE issued INCs to contractors for failure to 
perform safe operations.186 
On March 5, 2013, BSEE issued a single INC to Island Operating, a contractor working with Apache 
Corporation to work on an unmanned Apache platform. The INC, issued pursuant to 30 C.F.R. § 
250.107(a) for failure to perform all operations on the Platform in a safe and workmanlike manner, 
followed an incident at the platform where two Island Operating employees improperly transferred 
chemicals into a chemical tank, causing a fire and damage to the platform.187 Island Operating appealed, 
challenging BSEE’s jurisdiction. In a recent decision that will likely have far-reaching impact on offshore 
contractors, the Department of Interior Board of Land Appeals upheld BSEE’s issuance of the INC 
 
180 BSEE. Issuance of an Incident of Non Compliance (INC) to Contractors; IPD No. 12-07; August 15, 2012; 
http://www.bsee.gov/uploadedFiles/Issuance%20of%20an%20Incident%20of%20Non%20Compliance%20to%20
Contractors.pdf (accessed March 26, 2016). 
181 The four factors are: 1) the type of violation; 2) the harm resulting from the violation; 3) foreseeability of harm; 
and 4) the extent of the contractor’s involvement in the violation(s). Ibid at pp 1 and 2. 
182 Ibid., p 2. 
183 Ibid. 
184 BSEE. Investigation of November 16, 2012, Explosion, Fire and Fatalities at West Delta Block 32 Platform E; 
BSEE Panel Report 2013-002; November 4, 2013; Gulf of Mexico Region, New Orleans Distric Lease No. OCS 
00367; 
http://www.bsee.gov/uploadedFiles/BSEE/Enforcement/Accidents_and_Incidents/Panel_Investigation_Reports/Fi
nal%20BSEE%20Black%20Elk%20report.pdf (accessed March 26, 2016). 
185 Ibid. p 1. 
186 A total of 41 INCs were issued to Black Elk Energy Offshore Operations, Wood Group Production Service 
Network, Grand Isle Shipyard and Compass Engineering Consultants. See BSEE’s Notifications of Incidents(s) of 
Noncompliance at, 
http://www.bsee.gov/uploadedFiles/BSEE/Enforcement/Enforcement_Programs/Compass%20INC's%20Signed%
2011-13-13.pdf; 
http://www.bsee.gov/uploadedFiles/BSEE/Enforcement/Enforcement_Programs/GIS%20INC's%20Signed%2011
-13-13.pdf; and 
http://www.bsee.gov/uploadedFiles/BSEE/Enforcement/Enforcement_Programs/Wood%20Group%20INC's%20S
igned%2011-13-13.pdf (accessed March 26, 2016). 
187 See BSEE’s Notification of Incident(s) of Noncompliance at 
http://www.bsee.gov/uploadedFiles/BSEE/Enforcement/Enforcement_Programs/Island%20INC.pdf (accessed 
December 22, 2015). 

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despite the fact that Apache Corporation was the lessee.188 The Board noted that the Secretary is 
authorized under the Outer Continental Shelf Land Act (OCSLA) to prescribe regulations “necessary” to 
ensure that “operations” on the OCS are “conducted in a safe manner … sufficient to prevent or minimize 
… [any] occurrences which may cause damage to the environment or to property, or endanger life or 
health.”189 The Board held that BSEE has general authority under OCSLA to issue a regulatory violation 
or civil penalty to “any person” who has violated the statute or related regulations.190 The Board also 
relied on 30 C.F.R. § 250.146(c), which provides that “[w]henever the regulations in 30 C.F.R. [P]art 250 
… require the lessee to meet a requirement or perform an action, the lessee, operator[,] … and the person 
actually performing the activity to which the requirement applies are jointly and severally responsible for 
complying with the regulation.”191 Island Operating then had 90 days from the date of the opinion to file 
an action with the federal district court seeking judicial review of the opinion.192 
BSEE has cited additional contractors under 30 C.F.R. § 250.107(a) as well: On March 9, 2013, BSEE 
issued one INC to Alliance Oilfield for allegedly failing to enact proper fall protection safeguards and 
creating hazardous conditions following a fatality in April 2011. On March 5, 2013, BSEE issued one 
INC to Nabors Offshore Corporation for failing to determine whether an electricity source was on or off, 
resulting in a serious injury. Finally, on March 5, 2013, BSEE issued four INCs to Ensco Drilling, 
including three related to drilling operations, for an inadvertent disconnect of the blowout preventer, 
failure to properly lock out/tag out, and failure to prevent a discharge into the Gulf of Mexico. This 
pattern suggests that BSEE believes it has the authority to issue INCs to contractors and will continue to 
use INCs as an enforcement strategy for both operators and contractors as long as the agency has 
authority to do so. 
The drilling industry disputes BSEE’s position that contractors are as accountable as operators. For 
example, the IADC opposed BSEE’s use of a policy document to announce contractor liability, 
proclaiming that “BSEE’s guidance is inconsistent with the industry model and creates a whole new area 
of ambiguity.”193 
3.3.1.2 
Stakeholders Attempt to Fill Responsibility Gap with Voluntary Guidance 
Despite industry pushback to BSEE oversight of contractors, the American Petroleum Institute attempted 
to fill safety management gaps with API Bulletin 97, Well Construction Interface Document Guidelines. 
API Bulletin 97 is voluntary industry guidance intended to help operators align their SEMS program with 
drilling contractors’ safe work practices.194 It envisions operators and drilling contractors creating 
bridging documents that delineate the operator’s and contractor’s responsibilities during well construction 
 
188 Island Operating Co., Inc., IBLA 2013-137 (September 25, 2015). 
https://www.oha.doi.gov/IBLA/Ibladecisions/186IBLA/186IBLA199%20.pdf (accessed December 22, 2015). 
189 186 IBLA 207. Citing U.S.C. §§ 1332 and 1348(a) (2012). 
190 Ibid. 
191 186 IBLA 213. 
192 The standard of review under the Administrative Procedures Act allows for reversal of the Board’s decision only 
if it is found to be “arbitrary, capricious, an abuse of discretion…[or] in excess of statutory jurisdiction [or] 
authority….” 5 U.S.C. § 706(2). 
193 IADC. IADC criticizes BSEE policy for citing drilling contractors. August 17, 2012, 
http://www.iadc.org/news/iadc-criticizes-bsee-policy-for-citing-drilling-contractors/ (accessed March 26, 2016). 
194 API Bulletin 97, 1st ed., Well Construction Interface Document Guidelines, November 2013. 

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activities in light of the API RP-75/SEMS rule.195 If followed, this bulletin could help operators and 
contractors better follow the spirit of the SEMS rule; however, it is still voluntary guidance that cannot 
impose any legal requirement. Furthermore, because the regulator was not involved in its development 
and will not review the bridging documents or assess their use, there is no reliable way to know how 
Bulletin 97 is being adopted or how many companies are actually using it. Finally, it does not solve the 
primary issue—that the owner of the offshore installation and (typically) the employer of a workforce 
majority can strongly influence how the major accident risks are controlled, but the regulator does not 
hold them directly accountable to demonstrate that those risks are effectively managed. 
3.3.2 
Other Regimes’ Focus on Safety Responsibilities of Operator/Lessee 
and Drilling Contractor 
Outside the US, the UK and Australia avoid the ambiguity of responsibility through statutory directives 
over an offshore duty holder (or controller of risk). Norway takes a different approach by acknowledging 
different parties can bear either individual responsibility or co-responsibility, but makes it is the 
operator’s responsibility to ensure regulations are being adhered to by everyone on an offshore 
installation. 
While placing safety and environmental duties on all entities that create or contribute to the control of the 
risks for a particular activity, 196 UK regulations place primary compliance responsibility on the duty 
holder. On production installations, this is the “operator,” which may be either the entity appointed by the 
lessee to manage the installation functions, or the lessee itself. On non-production installations such as 
MODUs like the Deepwater Horizon, the duty holder is the rig “owner, which is the entity that controls 
the operation of that installation”197 In either case, the duty holder is “in overall control of the installation 
and must co-ordinate the health and safety activities of all the companies and personnel present.”198 
The responsibilities of the principal duty holder go beyond the basic requirement to develop and 
implement a basic safety and environmental management program. They must also:199 
• 
Submit safety case documentation to the regulator that demonstrates how the major hazards will 
be controlled and mitigated and risks are reduced to as low as reasonably practicable; 
 
195 Ibid., p 1. 
196 “The ultimate purpose of the enforcing authorities, [including the Offshore Division], is to ensure that duty 
holders manage and control risks effectively, thus preventing harm.” This enforcement method is based in part on 
proportionality, or relating enforcement action to the risks. “Those whom the law protects and those on whom it 
places duties (duty holders) expect that action taken by enforcing authorities to achieve compliance or bring duty 
holders to account for non-compliance should be proportionate to any risks to health and safety, or to the 
seriousness of any breach, which includes any actual or potential harm arising from a breach of the law.” UK 
HSE Enforcement Policy Statement, Pub. No. 41 (revised December 2009), 
http://www.hse.gov.uk/pubns/hse41.pdf (accessed March 26, 2016). 
197 Offshore Installations (Safety Case) Regulations 2005; Offshore Installations (Offshore Safety Directive)(Safety 
Case etc.), 2015, Interpretation, Regulation 2(1) “duty holder.” 
http://www.legislation.gov.uk/uksi/2015/398/regulation/2/made (accessed March 26, 2016). 
198 UK HSE. A guide to the Offshore Installations (Safety Case) Regulations 2005, 3rd ed.; SCR 2005; 2006; 
http://www.hse.gov.uk/pubns/books/l30.htm (accessed March 26, 2016). 
199 Adapted from Offshore Safety Case Regulations: Duty Holder Relationships, presented to CSB by Ian Whewell, 
retired head of UK HSE OSD; July 2011. 

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• 
Submit appropriate revisions to the safety case documentation when the stipulated hazards 
management plan changes; 
• 
Review the safety case documentation for accuracy and completeness every 5 years; 
• 
Conform to the contents of the safety case documentation; 
• 
Comply with the auditing requirements meant to verify conformance. 
Thus, if the Macondo well were drilled in the North Sea, Transocean, as drilling contractor and owner of 
the rig, would be the designated duty holder, with primary legal responsibilities to ensure all operations 
on the rig were executed safely and that it conformed to all safety management practices and aspects of 
risk control as described within its safety case document.200 
To be clear, in the UK arrangement, the leaseholder is not exempt from safety responsibility. BP, as the 
operator, would have primary responsibility to plan and design the well safely to ensure that “the well is 
so designed and constructed, and is maintained in such repair and condition, that (a) so far as reasonably 
practicable, there can be no unplanned escape of fluids from the well; and (b) risks to the health and 
safety of persons from it or anything in it, or in strata to which it is connected, are as low as reasonably 
practicable.”201 The leaseholder is legally required to communicate and cooperate fully with the rig owner 
to ensure safe execution of those plans,202 and the leaseholder would be held liable for any of its actions 
found to be contributory to an incident. These shared legal requirements ensure that key participants are 
fully aware that they may be held liable in the event of an incident and that they cannot rely on legal 
responsibility falling on another party. As such, both the operator and owner have specific and explicit 
risk-reduction responsibilities, which are auditable by the regulator, to ensure that they safely conduct 
drilling and completion operations. 
In Australia, NOPSEMA asserts the principle that “those who create the risk must manage it” and states 
that this is the “operator’s job” because the operator of the facility “has the greatest in-depth knowledge 
of their installation.”203 NOPSEMA defines the operator as a person nominated by a facility owner or 
titleholder who has or will have the day-to-day management and control of the facility (or proposed 
facility) and the operations at that facility.204 For a drilling and completion operation like Macondo, this 
would be the facility/installation owner, similar to the UK. The applicable offshore regulations stipulate 
that the operator with direct control of the facility identify the hazards and risks, describe how it controls 
those risks, and explain its safety management system to apply the controls effectively and 
 
200 UK HSE. A guide to the Offshore Installations (Safety Case) Regulations 2005, 3rd ed.; SCR 2005; 2006; p 5, 
http://www.hse.gov.uk/pubns/books/l30.htm (accessed March 26, 2016). 
201 Offshore Installations (Offshore Safety Directive)(Safety Case etc.), 2015, Establishment of well examination 
scheme, Regulation 11, http://www.legislation.gov.uk/uksi/2015/398/regulation/11/made (accessed March 26, 
2016). 
202 Oil & Gas UK. Well Integrity Guidelines, Issue 1; July, 2012; Section 2. 
203 NOPSEMA, What is a safety case, http://www.nopsema.gov.au/safety/safety-case/what-is-a-safety-case/ 
(accessed March 26, 2016). 
204 Offshore Petroleum and Greenhouse Gas Storage (Safety) Regulations 2009, Select Legislative Instrument No. 
382, 2009 as amended, Chapter 2.3, https://www.legislation.gov.au/Details/F2013C00945 (accessed March 26, 
2016). 

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consistently.205 The titleholder (or leaseholder) also has specific safety responsibilities for the well. It 
must prepare a Well Operations Management Plan (WOMP) identifying all risks that can cause a loss of 
well integrity to adequately assess the control measures and performance standards.206 Guidance provided 
by the regulator on the WOMP states, “The description and explanation should summarize the well 
management system goals, the well lifecycle integrity philosophy and process and provide a detailed risk 
assessment showing how these risks are reduced to as low as reasonably practicable. The content and 
level of detail must be sufficient for NOPSEMA to assess the well management system to be applied by 
the titleholder.”207 
Norwegian regulations state, “in reducing the risk, the responsible party shall choose the technical, 
operational or organisational solutions that, according to an individual and overall evaluation of the 
potential harm and present and future use, offer the best results, provided the costs are not significantly 
disproportionate to the risk reduction achieved.”208 They require the responsible party to “establish, 
follow up and further develop a management system designed to ensure compliance with requirements in 
the health, safety and environment legislation.”209 
Norwegian PSA regulations use the neutral phrases “responsible party” or “obligated party” to encompass 
the leaseholder, drilling contractor, and any other third-party contractors.210 PSA guidance explains the 
use of a neutral term because several parties can be responsible for compliance at the same time, and an 
individual’s responsibility will be limited to those tasks where the individual has control and instruction 
authority. The operator, however, has the duty to ensure that anyone working for it complies with the 
health, safety environmental regulations.211 Therefore, if Macondo had happened in Norwegian waters, 
Transocean would have had to establish a safety management system and technical, organizational, and 
operational barriers for its activities at the well, but BP would have been ultimately held responsible for 
any failures to do so. 
 
205 NOPSEMA, What is a safety case, http://www.nopsema.gov.au/safety/safety-case/what-is-a-safety-case/ 
(accessed March 26, 2016). 
206 NOPSEMA. Guidance Note: Well operations management plan content and level of detail; N-04600-GN1602, 
Rev. 0; December, 2015; http://www.nopsema.gov.au/assets/Guidance-notes/GN1602-Well-operations-
management-plan-content-and-level-of-detail-Rev-0-December-2015.pdf (accessed March 26, 2016). 
207 Ibid., p 8. 
208 Petroleum Safety Authority Norway, Regulations Relating to Health, Safety and the Environment in the 
Petroleum Activities and at Certain Onshore Facilities (The Framework Regulations) (2013), Section 11, Risk 
reduction principles, http://www.psa.no/framework-hse/category403.html#_Toc357595238 (accessed March 26, 
2016). 
209 Ibid., Section 17, Duty to establish, follow up and further develop a management system, 
http://www.psa.no/framework-hse/category403.html#_Toc357595245 (accessed March 26, 2016). 
210 Petroleum Safety Authority Norway, Guidelines Regarding the Framework Regulations, Re Section 7, 
Responsibilities pursuant to these regulations, http://www.ptil.no/framework-hse/category408.html#p7 (accessed 
March 26, 2016). 
211 Petroleum Safety Authority Norway, Regulations Relating to Health, Safety and the Environment in the 
Petroleum Activities and at Certain Onshore Facilities (The Framework Regulations) (2013), Section 7, 
Responsibilities pursuant to these regulations, http://www.psa.no/framework-
hse/category403.html#_Toc357595233 (accessed March 26, 2016). 

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In these other regimes, the regulator would also have the authority to proactively assess the drilling 
contractor’s performance, such as Transocean’s management of hazards throughout the applicable phases 
of the lifecycle where it is recognized as the primary duty holder. For example, when the UK HSE 
became concerned about human and organizational factors aboard Transocean facilities, the regulator 
decided to audit five Transocean rigs in the North Sea to determine the extent of the problems.212 
Operators in this regulatory environment come to understand that safety is more than a checklist of 
completed required documents and tasks—that they must obey the rules and bear the burden of operating 
safely, acting “with confidence, knowing that they have a robust safety culture which can stand up to 
scrutiny, both externally and internally.”213 
3.3.3 
Conclusion 
Work conducted by contractors offshore directly impacts the risk of offshore operations. Sometimes 
personal safety risk is affected, but other times it plays a role in process safety risk that could increase the 
probability of multiple fatalities and large scale environmental damage, both consequences of the 
Macondo blowout. Risk management approaches for the latter are different from those intended to 
mitigate personal safety.214 Just as the CSB argues that industry should approach personal and process 
safety differently, the CSB also sees value in the regulator having different approaches. To that end, the 
CSB sees the greatest potential to improve major accident prevention in US waters by explicitly focusing 
on the design and operation risks governed by the leaseholder/operators and drilling contractors for 
reasons. Ultimately, while this section describes the different approaches of several international regimes, 
the US needs to develop a more effective system for the oversight of key contractors’ work such as the 
drilling contractor during offshore operations who create or control major accident risk. 
3.4 
Insufficient SEMS Worker Participation Provisions 
Workers participate in virtually every safety activity, whether onshore or offshore.215 At a minimum, 
management should encourage workers to participate in the following activities: 
• 
Collaborating in hazard and management of change (MOC) reviews and job safety analyses; 
• 
Investigating incidents and near-misses; 
• 
Serving on health and safety committees; 
• 
Conducting health and safety inspection/audits; 
• 
Defining safe operating procedures and work practices for a task or job; 
 
212 Specialist Inspection Report, Transocean Offshore (North Sea) Ltd., by Martin Anderson, Specialist Inspector 
(Human and Organizational Factors), Offshore Division (inspections conducted over four months from July to 
October 2008). 
213 Shaw, S. What’s the Case for a US Version of the Safety Case?; April 2, 2014; http://www.erm.com/en/news-
events/platform/whats-the-case-for-a-us-version-of-the-safety-case/ (accessed March 26, 2016). 
214 See Volume 3, Section 3.1 
215 Center For Chemical Process Safety. Guidelines for Risk Based Process Safety; John Wiley & Sons: Hoboken, 
NJ, 2007; p 125. 

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• 
Reporting unsafe conditions, tools, equipment, and practices to management; and 
• 
Providing safety feedback through defined mechanisms to other workers.216 
Actively engaging the workforce, employees, and contracted personnel ensures all those involved with 
the hazardous work are participating in efforts to identify and manage safety risks. Enhanced workforce 
participation helps to create a strong safety culture and can lead to a safer workplace. The experience of 
companies in implementing enhanced efforts to engage and empower the workforce shows that efforts to 
increase workforce involvement greatly outweighs the costs of such programs.217 
Inadequate worker involvement in policies, programs, and regulations limits a drilling crew’s ability to 
help manage the hazards for major accident prevention. BP and Transocean used limited means to 
encourage and empower workers to be involved in managing major hazards. Efforts to include them in 
safety management primarily resided in company safety observation programs focused on occupational 
health and safety. As Volume 3 discussed in depth, occupational safety measures do not improve the 
process safety status of the organization. The CSB identified in previous investigation reports that 
effective process safety management and major accident prevention cannot be achieved without involving 
workers and their representatives. In its Chevron Regulatory Report, the CSB noted that the CCPS lists 
workforce involvement as one of 20 essential management components necessary to reduce process 
safety risks and prevent chemical accidents:218 
…workers are potentially the most knowledgeable people with respect to 
the day-to-day details of operating the process and maintaining the 
equipment and facilities and may be the sole source for some types of 
knowledge gained through their unique experiences. Workforce 
involvement provides management a mechanism for tapping into this 
valuable expertise.219 
Worker participation in the offshore oil and gas industry is of critical importance. Workers aboard a rig 
can contribute keen insights into the daily workings of an operation that upper management might miss. 
As such, workers should be engaged in a wide range of safety management activities, including project 
planning, risk analysis, and incident investigations, and thus can play an integral role in preventing 
accidents. As Volumes 2 and 3 demonstrate, decisions that people on a rig make can impact the potential 
for a well kick, or strengthen or weaken a barrier. For example, “any problems that did occur during the 
TA [temporary abandonment] plan would be dealt with by employing the knowledge, experience and 
skills of the drilling team”220 Therefore, if workers are not effectively engaged in the management of 
major hazards in these ways, a duty holder bypasses a key layer of insight and enhanced protection. 
Inclusion of workers also contributes significantly to creation of a positive safety culture, while omitting 
 
216 American National Standards Institute/American Industrial Hygiene Association (ANSI/AIHA) Z10-2012, 
Occupational Health and Safety Managment Systems, 2012, p 34. 
217 Eves, D.; Gummer, J. Questioning Performance: Essential Guide to Health, Safety and the Environment ; IOSH 
Services Ltd: Wigston, United Kingdom, 2011, p 91. 
218 Center For Chemical Process Safety. Guidelines for Risk Based Process Safety; John Wiley & Sons: Hoboken, 
NJ, 2007; p liv. 
219 Ibid., p 124. 
220 Volume 3, Section 1.8.2. 

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workers minimizes their contribution and weakens safety culture onboard a rig. A strong safety culture 
empowers individual workers and encourages them to be fully focused on safe working conditions. Thus, 
workforce engagement is vital to major accident prevention, and should be encouraged. 
 
At the time of the Macondo incident, there were no effective US offshore regulations that provided for 
worker participation in the management of process safety. While BSEE asserts that post-Macondo worker 
participation provisions within SEMS221 provide “several key ways for personnel to help ensure safe 
performance of oil and gas activities on the OCS,”222 these regulations could be substantially improved to 
enhance worker engagement in offshore safety management and major accident prevention efforts. 
Comparisons of the SEMS worker participation regulations with those of international offshore regimes 
and other high-hazard industries in the US illustrate opportunities for further improvement. 
3.4.1 
Post-Macondo/SEMS Worker Participation Provisions 
In April 2013, several provisions were added to the SEMS regulations for worker participation,223 but 
regulations do not guarantee that workers are effectively participating in managing offshore process 
safety. Effective worker participation requires active engaging workers in the designing, implementing, 
and improving an operation’s safety management systems.224 BSEE intends to meet this goal with the 
SEMS provisions: 
1. Operators must have an Employee Participation Plan (EPP) for their employees. Under the rule, 
operators must consult with employees regarding the SEMS. Furthermore, operators must create a 
“written plan of action” showing how “appropriate employees” will contribute to the 
“development and implementation” of an operator’s SEMS. Employees are also required to have 
access to any part of the SEMS that relates to their duties.225 
2. Operators must include Stop-Work Authority (SWA) procedures in their SEMS program. Such 
procedures would authorize and require all employees and other personnel who witness an 
activity presenting an imminent risk or danger to the health or safety of an individual, the public, 
 
221 30 C.F.R.250.1930-1932. 
222 Final Rule, Oil and Gas and Sulphur Operations in the Outer Continental Shelf—Revisions to Safety and 
Environmental Management Systems, 78 Fed. Reg. 20,423 (Apr. 5, 2013). 
223 Ibid. 
224 Center For Chemical Process Safety. Guidelines for Risk Based Process Safety; John Wiley & Sons: Hoboken, 
NJ, 2007; p 124. 
225 30 C.F.R. § 250.1932. 
The purpose of employee participation is to utilize the employees' collective 
knowledge and experience to ensure that matters are sufficiently explored before 
decisions are made that concern health, safety, and the environment, and to provide 
the employees with the opportunity to exert influence on their own work situation. 
 — Norwegian PSA Framework Legislation, Section 13, Facilitating Employee Participation, 
http://www.ptil.no/framework/category408.html#p13. 

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or to the environment to stop the work creating the risk or danger. “Imminent risk or danger is 
defined as any condition, activity, or practice in the workplace that could reasonably be expected 
to cause: 
• 
Death or serious physical harm; or 
• 
Significant environmental harm ….”226 
3. Operators must define a process to designate an individual with Ultimate Work Authority (UWA) 
on each facility for operational and safety decision-making. After a Stop Work is initiated, work 
can resume upon determination by the UWA “that the imminent risk or danger …. no longer 
exists.”227 
4. Operators must provide all personnel with a system for reporting unsafe work conditions.228 
These provisions are a marked improvement over the offshore safety regulations that existed at the time 
of the Macondo incident; however, the provisions are not adequate to ensure the workforce is engaged in 
creating and implementing a company’s SEMS program. 
3.4.2 
Insufficient and Limited SEMS Worker Participation Provisions 
In promulgating the Employee Participation Plans, BSEE sought to encourage an “environment that 
promotes participation by employees and management in order to eliminate or mitigate hazards on the 
OCS.”229 BSEE held that the rule would require “an operator who performs regulated activities on the 
OCS … to consult with its employees [workers] regarding the development, implementation, and 
modification of its SEMS program.”230 “Consult,” however, is a vague term that does not ensure workers 
have a voice in process safety management matters. Consultation can be a one-way process, with 
operators simply telling their workers how the hazards will be managed without consideration of worker 
viewpoints or concerns. The purpose is to engage and empower the workforce throughout the entire 
SEMS lifecycle (development, implementation, and modification), incorporating the workforce’s views, 
accepting those that are valid, and explaining why they are rejected when appropriate. But the SEMS 
regulations do not provide a framework for how that should occur. Furthermore, management selects the 
workers it deems “appropriate” and defines their level of involvement231 in a way that makes the most 
sense for each company or operation, but the possibility exists for continued worker exclusion. 
SEMS provisions that require worker participation are limited in scope. Additionally, other SEMS 
provisions that discuss aspects of worker involvement fail to require the level of active engagement that 
 
226 30 C.F.R. § 250.1930. 
227 Ibid. The person with the ultimate work authority would be the person on the fixed, floating facilities or MODU 
with the final responsibility for making decisions. The operator’s SEMS program must identify all persons that 
could have UWA, and the operator must designate those persons as such. 
228 30 C.F.R. § 250.1933. Furthermore, on August 28, 2013 BSEE reports it has launched a confidential near-miss 
reporting system with the Department of Transportation and Statistics. The system will “provide important trend 
analysis and statistical data to BSEE.” See BTS and BSEE to Develop Confidential Near-Miss Reporting System, 
http://www.rita.dot.gov/bts/bts_bsee (accessed March 26, 2016). 
229 Final Rule, Oil and Gas and Sulphur Operations in the Outer Continental Shelf—Revisions to Safety and 
Environmental Management Systems, 78 Fed. Reg. 20,423 (Apr. 5, 2013). 
230 Ibid. 
231 30 C.F.R. § 250.1932(b). 

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would help to drive safety improvement. For instance, the SEMS Job Safety Analysis (JSA) provision 
requires “the immediate supervisor of the crew performing the job onsite [to] conduct the JSA, sign the 
JSA, and ensure that all personnel participating in the job understand and sign the JSA.”232 Essentially, 
the supervisor must inform workers of risks associated with their respective jobs and have them sign off 
on the analysis, but the workers need not be involved in identifying, assessing, or mitigating such risks. 
By contrast, other offshore regimes provide specific requirements for including the workforce in safety 
management activities through worker-elected safety representatives.233 Moreover, the SEMS Rule states, 
“Your SEMS program must establish and implement a training program so that all personnel are trained 
in accordance with their duties and responsibilities to work safely and are aware of potential 
environmental impacts.”234 Thus, incorporating process safety concepts and effective practice should be 
part of the required training provided to the workers or their representatives. 
The only other mechanism in SEMS directly addressing worker involvement besides EPP are the Stop-
Work Authority (SWA) provisions;235 however, SWA provisions are a weak substitute for worker 
involvement in major accident prevention offshore. A regulatory SWA provision will not be successful if 
the workforce is not aware of the specific safety risks of the work. For example, on the Deepwater 
Horizon, the majority of the frontline workers reported that they were “comfortable with identifying and 
understanding the hazards they were exposed to,”236 but supervisors and rig leadership had concerns with 
hazard awareness amongst the crew. They noted that the crew did not always identify major hazards and 
appropriate controls in their THINK237 plans.238 As one person stated, “they don’t know what they don’t 
know.” The stop-work programs of BP and Transocean allowed for any employee to call for a stop work 
to intervene in hazardous operating conditions, but without clear understanding of the risks, the workforce 
is hindered from effectively identifying situations when major hazard risk barriers have been 
compromised and, thus, will be less likely to initiate a stop work. 
 
232 30 C.F.R. § 250.1911(b)(2). 
233 See CSB Chevron Regulatory Report Section 4.4 for a detailed discussion of Active Workforce Participation in 
other jurisdictions; USCSB, 2013. Regulatory Report: Chevron Richmond Refinery Pipe Rupture and Fire, 
Richmond, CA, August 6, 2012, Report No. 2012-03-I-CA, April 2013, 
http://www.csb.gov/assets/1/19/Chevron_Regulatory_Report_11102014_FINAL_-_post.pdf (accessed January 
25, 2016). 
234 30 C.F.R. § 250.1915 
235 30 C.F.R. §§ 250.1930, 250.1931. 
236 Internal Company Document, Transocean. Safety Management and Safety Culture/Climate: North America 
Division Summary Report, July 2, 2010, TRN-HCEC-00090521, see Exhibit 0929 
http://www.mdl2179trialdocs.com/releases/release201304041200022/Bertone_Stephen-Depo_Bundle.zip 
(accessed October 7, 2015). 
237 THINK is a planning and risk management tool that begins with task development and the identification of 
associated task hazards. After hazards are identified, the THINK process requires management to communicate 
hazards to people and to put in place controls to mitigate them. The complexity of a task determines the depth of 
assessment and formality of the THINK plan; See Volume 3, Section 1.8.3 for more detail. 
238 Internal Company Document, Transocean. Safety Management and Safety Culture/Climate: North America 
Division Summary Report, July 2, 2010, TRN-HCEC-00090521, see Exhibit 0929 
http://www.mdl2179trialdocs.com/releases/release201304041200022/Bertone_Stephen-Depo_Bundle.zip 
(accessed October 7, 2015). 

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3.4.3 
No SEMS Provisions for Worker-Elected Safety Representatives 
Safety representatives are spokespeople elected by the workforce onboard offshore drilling or production 
vehicles or other facilities to advocate for workers on “both day-to-day and strategic health and safety 
issues.”239 Exact rules for using safety representative vary among jurisdictions. The UK initiated safety 
representatives post-Piper Alpha, resulting in stronger workforce commitment to implement safety 
management programs. Now frontline personnel encourage employees to share valuable input in 
identifying and controlling hazards.240 
In many international regimes, the safety representative requirement is considered crucial to effectively 
implement worker participation measures.241 The regulator-mandated safety representative motivates 
companies to include workers in safety management activities and promotes an essential dialogue among 
labor, the regulator, and the operator.242 The explicit nature of the UK, Norwegian, and Australian 
regulations pertaining to worker-elected safety representatives demonstrate the recognized integral role 
workers play in robust safety management. Such regulation fosters an environment where workers can 
participate with industry and the regulator in managing safety. In addition, empowering workers to elect 
safety representatives through regulation is an important step in overcoming fears of management 
retaliation for reporting concerns.243 
UK regulations grant worker safety representatives a variety of defined functions and powers, including: 
• 
Investigating potential hazards and examining the causes of accidents; 
• 
Investigating workforce complaints relating to health and safety; 
• 
Inspecting installation equipment; 
• 
Reporting findings from investigations to installation managers; 
• 
Reporting unsafe activities to the regulator when, for instance, the installation management does 
not take immediate remedial actions after safety representatives bring the circumstances to their 
attention; 
• 
Participating as a member of the installation’s safety committee; and 
 
239 UK HSE. A guide to the Offshore Installations (Safety Representatives and Safety Committees) Regulations 
1989; 2012; http://www.hse.gov.uk/pubns/priced/l110.pdf. (accessed March 26, 2016). 
240 Ibid., p 4. 
241 See The Offshore Installations (Safety Representatives and Safety Committees) Regulations 1989, 1989 No. 971, 
18 Sept. 1989; Regulations Relating to Health, Safety and the Environment in the Petroleum Activities and at 
Certain Onshore Facilities (The Framework Regulations); Offshore Petroleum and Greenhouse Gas Storage Act 
2006, Volume 3, Schedule 3, Part 3, 
http://www.comlaw.gov.au/Details/C2013C00071/Html/Volume_3#_Toc347403628; Working Environment Act, 
December 14, 2012; available at: http://www.arbeidstilsynet.no/binfil/download2.php?tid=92156; 
http://www.ptil.no/framework-hse/category403.html#_Toc357595234 (accessed March 26, 2016). 
242 UK HSE. A guide to the Offshore Installations (Safety Representatives and Safety Committees) Regulations 
1989; 2012; p 7. http://www.hse.gov.uk/pubns/priced/l110.pdf. (accessed March 26, 2016). 
243 Efforts to enhance worker participation should not conflict with provisions established under the National Labor 
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• 
Consulting in the development of a safety case document.244 
Worker-elected safety representatives formally accomplish the worker participation in safety 
management.245 The UK captures the requirement that all workers participate in all phases of operation 
through the definition of the word “workforce” which “includes every person who is for the time being 
working on or from an offshore installation.”246 Worker-elected safety representatives in the UK are also 
permitted by regulation to participate in a wide range of safety matters aboard an offshore installation, 
ranging from investigations of accidents to general matters affecting the occupational health and safety of 
members of the workforce, and all without the loss of pay.247 
Norway provides workers with an opportunity to follow up on safety matters.248 For example, the 
working environment committee, which represents workers, “shall participate in planning safety and 
environmental work and shall follow up developments closely in [relation to] the safety, health and 
welfare of the employees [workers].”249 This helps workers to know that management takes their 
concerns seriously. Similarly, Norway provides workers with the opportunity to participate in safety 
matters throughout the lifecycle of the operation.250 Workers in Norway elect safety representatives called 
“safety delegates” to “see that work is carried out in such a manner that the safety, health and welfare of 
the employees [workers] are taken care of.”251 Through their elected representatives, workers are involved 
early in the safety management process.252 Relevant regulations provide that worker participation “shall 
be ensured in all various phases of the [petroleum] activities,” including the “establishment, follow-up 
 
244 The Offshore Installations (Safety Representatives and Safety Committees) Regulations 1989, 
http://www.legislation.gov.uk/uksi/1989/971/contents/made (accessed March 26, 2016). 
245 UK HSE. A guide to the Offshore Installations (Safety Representatives and Safety Committees) Regulations 
1989; 2012; http://www.hse.gov.uk/pubns/priced/l110.pdf. (accessed March 26, 2016). 
246 The Offshore Installations (Safety Representative and Safety Committees) Regulations 1989, Interpretation, 
SI971 (1989), (emphasis added), available at: http://www.legislation.gov.uk/uksi/1989/971/regulation/2/made 
(accessed March 26, 2016). 
247 UK HSE. Safety representatives and safety committees on offshore installations: A brief guide for the workforce, 
INDG199(rev1), 1999, http://www.hse.gov.uk/pubns/indg119.htm (accessed April 12, 2016). 
248 Petroleum Safety Authority Norway, Regulations Relating to Health, Safety and the Environment in the 
Petroleum Activities and at Certain Onshore Facilities (The Framework Regulations) (2013), Section 17, Duty to 
establish, follow up and further develop a management system, and Section 13, Facilitating employee 
participation, http://www.psa.no/framework-hse/category403.html (accessed March 26, 2016). 
249 Working Environment Act, December 14, 2012; Section 7-2, 
http://www.arbeidstilsynet.no/binfil/download2.php?tid=92156 (accessed March 26, 2016). 
250 Petroleum Safety Authority Norway, Regulations Relating to Health, Safety and the Environment in the 
Petroleum Activities and at Certain Onshore Facilities (The Framework Regulations) (2013), Section 13, 
Facilitating employee participation, http://www.ptil.no/framework-hse/category403.html#_Toc357595240 
(accessed March 26, 2016). 
251 Ognedal, M. PSA, Workforce Contribution, June 11, 2011; 
http://www.hse.gov.uk/aboutus/meetings/iacs/oiac/wig/110609/psa.pdf, Slides 6-7. PSA. Guidelines Regarding 
the Framework Regulations, Re Section 13, Facilitating employee participation, 
http://www.ptil.no/framework/category408.html#_Toc407544828 (accessed March 26, 2016). 
252 Petroleum Safety Authority Norway, Regulations Relating to Health, Safety and the Environment in the 
Petroleum Activities and at Certain Onshore Facilities (The Framework Regulations) (2013), Section 13, 
Facilitating employee participation, http://www.ptil.no/framework-hse/category403.html#_Toc357595240 
(accessed March 26, 2016). 

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and further development of management systems.”253 Norway believes “the employees’ experience and 
active participation is a significant precondition for a sound management system.”254 The Norwegian 
safety delegates also have duties and protections similar to those established in the UK.255 PSA believes 
that this mandate provides workers with the opportunity to actually participate in and influence safety in 
day-to-day operations.256 
 
Australia’s NOPSEMA requires that health and safety representatives be members of the workforce, 
which includes employees and contractors.257 The representative is also selected by the workforce. By 
objective, this regulation intends to “ensure that expert advice is available on occupational health and 
 
253 Ibid. 
254 PSA. Guidelines Regarding the Framework Regulations, Re Section 17, Duty to establish, follow up and further 
develop a management system http://www.ptil.no/framework/category408.html#_Toc407544828 (accessed March 
26, 2016). 
255 PSA. Guidelines Regarding the Framework Regulations, Section 13, Facilitating employee participation, 
http://www.ptil.no/framework/category408.html#_Toc407544828; Working Environment Act, December 14, 
2012; Chapter 6, http://www.arbeidstilsynet.no/binfil/download2.php?tid=92156 (accessed March 26, 2016). 
256 Guidelines Regarding the Framework Regulations, Re Section 13, Facilitating employee participation, 
http://www.ptil.no/framework/category408.html#_Toc407544828 (accessed March 26, 2016). 
257 Offshore Petroleum and Greenhouse Gas Storage Act 2006, Volume 3, Schedule 3, Part 3, and Volume 3, 
Schedule 3, Part 1.3 “member of the workforce,” 
http://www.comlaw.gov.au/Details/C2013C00071/Html/Volume_3#_Toc347403628 (accessed March 26, 2016). 
Worker Participation in Mine Safety Regulation 
In the US, the Mine Safety and Health Act of 1977 provides for two or more miners to 
designate a representative to advocate for their rights.a While the representative may 
be an employee, he or she does not necessarily have to be.b The miners’ 
representative can request inspections,c participate in Mine Safety and Health 
Administration (MSHA) inspections,d and learn of and participate in enforcement 
proceedings.e Congress provided miners with worker participation rights because it 
believed the miners’ knowledge of the operation could provide the MSHA with critical 
safety information.f 
 a A Guide to Miners’ Rights and Responsibilities: Under the Federal Mine Safety and Health Act of 
1977; pp 11-15. 
 http://arlweb.msha.gov/s&hinfo/minersrights/minersrights.pdf (accessed March 26, 2016); 30 C.F.R 
40.1. 
 b Ibid., pp 10-11. 
 c Federal Mine Safety and Health Act of 1977 § 103(g). 
 d Federal Mine Safety and Health Act of 1977 § 103(f). 
 e Federal Mine Safety and Health Act of 1977 § 107(b). 
 f A Guide to Miners’ Rights and Responsibilities: Under the Federal Mine Safety and Health Act of 
1977; p 10. 
 http://arlweb.msha.gov/s&hinfo/minersrights/minersrights.pdf (accessed March 26, 2016). 

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safety matters.”258 Such representation encourages a “consultative relationship between all relevant 
persons concerning the health, safety and welfare of members of the workforce at those facilities.”259 
3.4.4 
No SEMS Requirement for Contractor Participation 
SEMS does not directly apply to contractors. The EPP in SEMS, which requires the operator to “consult 
with its employees regarding the development, implementation, and modification of its SEMS 
program,”260 does not encompass contractor employees, including the drilling contractor and other well 
service providers.261 Yet, most crew members aboard these offshore facilities are contracted.262 On the 
Deepwater Horizon, 118 of the 126 crew members were contractors,263 including most of the individuals 
involved in the well operations activities leading up to the incident. Further, contractors performed 54% 
of BP’s 373 million total work hours in 2013.264 
Many production facilities also have high numbers of contractors conducting hazardous operations. In the 
November 16, 2012, multi-fatality hot work incident on a Black Elk Energy production platform, all 24 
crew members present were employed by one of three contractor companies. A number of safety 
management system failures were identified as causal, including poor hot work procedures, inadequate 
assessment of the hazards, insufficient supervision, and lack of monitoring for flammable gas.265 No 
Black Elk employees were working aboard the production platform at the time of the incident, and as a 
result, the contracting companies did not have to have a SEMS program, nor did the workers have a 
regulatory right to have an EPP and participate in the SEMS development process. Thus, no one aboard 
the Black Elk facility had a regulatory right to be involved in the safety management aspects of their 
work. 
 
258 Offshore Petroleum and Greenhouse Gas Storage Act 2006, Volume 3, Schedule 3, Part 1.1, 
http://www.comlaw.gov.au/Details/C2013C00071/Html/Volume_3#_Toc347403590 (accessed March 26, 2016). 
259 Offshore Petroleum and Greenhouse Gas Storage Act 2006, Volume 3, Schedule 3, Part 1.1, 
http://www.comlaw.gov.au/Details/C2013C00071/Html/Volume_3#_Toc347403590 (accessed March 26, 2016). 
260 30 C.F.R. § 250.1932; Oil and Gas and Sulphur Operations in the Outer Continental Shelf—Revisions to Safety 
and Environmental Management Systems, 78 Fed. Reg. 20423 (Final Rule, April 5, 2013). 
261 Ibid. 
262 MMS made this observation in 2003, and then it was reiterated after Macondo by the National Commission on 
the BP Deepwater Horizon Oil Sill and Offshore Drilling: Oil and Gas and Sulphur Operations in the Outer 
Continental Shelf—Incident Reporting Rule, 68 Fed. Reg. 40585 (Proposed Rule, July 8, 2003) and National 
Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling, A Competent and Nimble Regulator: 
A New Approach to Risk Assessment and Management, Staff Working Paper No. 21, p 7. 
263 Internal Company Document, Transocean. Personnel On-Board as of 20 Apr 2010 17:09:15, April 20, 2010, 
TRN-MDL-00030435, http://www.mdl2179trialdocs.com/releases/release201303071500008/TREX-00687.pdf 
(accessed March 26, 2016). 
264 BP. Sustainability Review 2013; Working with our contractors, suppliers and partners; p 27, 
http://www.bp.com/content/dam/bp/pdf/sustainability/group-reports/BP_Sustainability_Review_2013.pdf 
(accessed March 26, 2016). 
265 BSEE. Investigation of November 16, 2012, Explosion, Fire and Fatalities at West Delta Block 32 Platform E; 
BSEE Panel Report 2013-002; November 4, 2013; Gulf of Mexico Region, New Orleans Distric Lease No. OCS 
00367; 
http://www.bsee.gov/uploadedFiles/BSEE/Enforcement/Accidents_and_Incidents/Panel_Investigation_Reports/Fi
nal%20BSEE%20Black%20Elk%20report.pdf (accessed March 26, 2016). 

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The failure of the SEMS rule to include contract workers who comprise the majority of the frontline 
workforce presents significant risks for offshore oil and gas operations. The UK, Norway, and Australia 
offshore regulations grant participation rights to both employed and contracted labor. In the UK, the 
Offshore Installations (Safety Representatives and Safety Committees) Regulations 1989 stipulate that 
“every person who is for the time being working on or from an offshore installation under a contract of 
service or a contract for services”266 has the authority to nominate and elect safety representatives “to 
ensure that the whole workforce is formally involved in promoting health and safety.”267 
Similarly, Norwegian regulation provides that all workers elect a safety delegate, requiring each 
“individual employer” who carries out “simultaneous activities at the same workplace,” meaning all 
employees, including contractors, to comply with this mandate.268 In fact, PSA requires that the employer 
coordinate its selection of a safety delegate with a contractor’s selection,269 with the total number of 
representatives dependent on the operation size and the working conditions.270 
Australia’s NOPSEMA also requires that health and safety representatives be members of the workforce, 
including employees and contractors, and be selected by the workforce.271 Such representation encourages 
a “consultative relationship between all relevant persons concerning the health, safety and welfare of 
members of the workforce at those facilities”272 in order to “ensure that expert advice is available on 
occupational health and safety matters.”273 
3.4.5 
SEMS Stop-Work Authority Impact on Worker Liability 
The SEMS SWA provision does not sufficiently prohibit reprisal for stopping dangerous activities. It 
grants “all personnel the responsibility and authority, without fear of reprisal, to stop work or decline to 
perform an assigned task when an imminent risk or danger exists.”274 Since the SWA provision obligates 
workers to report unsafe operations, workers could be blamed for failing to stop the work if an incident 
occurs. 
 
266 UK HSE. A guide to the Offshore Installations (Safety Representatives and Safety Committees) Regulations 
1989; 2012; p 2. http://www.hse.gov.uk/pubns/priced/l110.pdf. (accessed March 26, 2016). 
267 Ibid., p 7. 
268 Petroleum Safety Authority Norway, Regulations Relating to Health, Safety and the Environment in the 
Petroleum Activities and at Certain Onshore Facilities (The Framework Regulations) (2013), Section 8, 
Employer's duties toward employees other than its own, http://www.ptil.no/framework-
hse/category403.html#_Toc357595234 (accessed March 26, 2016). 
269 Ibid; Working Environment Act, December 14, 2012; Section 2-2, 
http://www.arbeidstilsynet.no/binfil/download2.php?tid=92156 (accessed March 26, 2016). 
270 Ibid; Working Environment Act, December 14, 2012; Section 6-1, 
http://www.arbeidstilsynet.no/binfil/download2.php?tid=92156 (accessed March 26, 2016). 
271 Offshore Petroleum and Greenhouse Gas Storage Act 2006, Volume 3, Schedule 3, Part 3, and Volume 3, 
Schedule 3, Part 1.3 “member of the workforce,” 
http://www.comlaw.gov.au/Details/C2013C00071/Html/Volume_3#_Toc347403628 (accessed March 26, 2016). 
272 Offshore Petroleum and Greenhouse Gas Storage Act 2006, Volume 3, Schedule 3, Part 1.1, 
http://www.comlaw.gov.au/Details/C2013C00071/Html/Volume_3#_Toc347403590 (accessed March 26, 2016). 
273 Ibid. 
274 30 C.F.R. § 250.1930. 

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Placing “the responsibility and authority” to halt dangerous activities on workers can create a culture of 
assigning blame to workers. The provision discusses that workers should not fear reprisal for initiating an 
SWA; however, the regulation does not speak to the protections granted to those who arguably failed to 
initiate an SWA when circumstances might have seemed to require it. If workers do not have a sufficient 
awareness of the hazards of an activity, they may be blamed or criticized after an incident for failing to 
initiate a stop work. Essentially, a worker is confronted with the dilemma of choosing between facing 
criticism (or worse) for stopping work or being blamed for failure to act. 
The concept of imminent risk should not be a sole determinant for stop-work authority. Control of major 
hazards depends on defense-in-depth, or reliance on multiple barriers to prevent imminent danger because 
of barrier redundancy. Yet loss of a critical barrier should warrant a stop-work order even if risk is not 
imminent. 
A poorly designed or supported SWA program may encourage workers to try to ignore certain activities 
in the hopes of avoiding fault in a potential stop-work situation – the antithesis of an engaged workforce. 
Thus, involving workers in these situations can have the unintended effect of reducing safety reporting, 
increasing defensive posturing by workers, and minimizing the benefits of a reporting system.275 
In contrast, both the UK and Norway remove from the workforce any duty to stop work.276 UK Safety 
Representative regulations state that “no function conferred on a [either the safety representative or the 
safety committee] by this regulation shall be construed as imposing a duty on [them].”277 Legislation in 
Norway provides the safety representative with the opportunity to stop work, but the “representative is not 
liable for any loss suffered by the undertaking as a result of work being halted.”278 In both instances, 
removing potential sources of blame on the worker for stopping work is crucial to improving offshore 
safety. 
3.4.6 
Inadequate SEMS Requirements to Protect Workers from Retaliation 
The SWA provision in SEMS is designed for use when work stoppage is most challenging. When the 
work is being performed, time and economic pressures are likely high, and the crew well understands the 
consequences of stopping work.279 The CSB Tosco Avon Refinery investigation uncovered workers who 
stated they felt pressure to avoid using stop work because of economic implications and production 
pressures.280 As such, they were greatly concerned about retaliation for initiating a stop work. Similarly, 
 
275 Dekker, S. Just Culture: Balancing Safety and Accountability; Ashgate Publishing Company: Hampshire, 
England, 2007; pp 20-27. 
276 Working Environment Act, December 14, 2012; Section 6-3, 
http://www.arbeidstilsynet.no/binfil/download2.php?tid=92156; The Offshore Installations (Safety 
Representatives and Safety Committees) Regulations 1989, No. 16 
http://www.legislation.gov.uk/uksi/1989/971/contents/made (accessed March 26, 2016). 
277 The Offshore Installations (Safety Representatives and Safety Committees) Regulations 1989, No. 16 
http://www.legislation.gov.uk/uksi/1989/971/contents/made (accessed March 26, 2016). 
278 Working Environment Act, December 14, 2012; Section 6-3, 
http://www.arbeidstilsynet.no/binfil/download2.php?tid=92156 (accessed March 26, 2016). 
279 USCSB, 2001, Refinery Fire Incident, Martinez, CA, February 23, 1999, Report No. 99-014-I-CA, March 2001, 
http://www.csb.gov/assets/1/19/Tosco_Final_Report.pdf (accessed March 25, 2016). 
280 Ibid. 

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in the GoM, the fear of retaliation for stopping work is described in BSEE’s investigation of the 2012 
Black Elk production platform explosion, where BSEE noted that contractors did not initiate a stop work 
because they feared losing their jobs for doing so.281 
In many instances, simply requiring that companies have a stop-work program does not guarantee the 
workforce will actually use it. The workers must believe that using SWA will not result in disciplinary 
action. Indeed, the SEMS SWA provision creates the type of stop work programs already implemented by 
BP and Transocean at the time of the blowout, found to be lacking adequate worker protections. 282 
SEMS also requires that operators establish a program for reporting unsafe working conditions that 
protect “a person’s identity to the extent authorized by law.”283 Initially, BSEE reported that it was 
developing a confidential near-miss reporting system with the Bureau of Transportation and Statistics.”284 
This program has now been implemented.285 According to the BSEE website, the program is both 
voluntary and anonymous.286 At this time, the toll-free hotline line is operational but the BSEE website 
has not yet been modified to accept online reporting.287 However, there are insufficient provisions within 
SEMS to protect workers from retaliatory action. 
 A bill that originated in 2010 in the House Committee on Education and the Workforce stated there was 
that no federal law that protects oil and gas workers if they are retaliated against after they blow the 
whistle on workplace health and safety violations on the Outer Continental Shelf.288 The bill eventually 
 
281 BSEE. Investigation of November 16, 2012, Explosion, Fire and Fatalities at West Delta Block 32 Platform E; 
BSEE Panel Report 2013-002; November 4, 2013; Gulf of Mexico Region, New Orleans Distric Lease No. OCS 
00367; pp 3-4. 
http://www.bsee.gov/uploadedFiles/BSEE/Enforcement/Accidents_and_Incidents/Panel_Investigation_Reports/Fi
nal%20BSEE%20Black%20Elk%20report.pdf (accessed March 26, 2016). 
282 Bureau of Ocean Energy Management, Regulation, and Enforcement. Report Regarding the Causes of the April 
20, 2010, Macondo Well Blowout; 2011; pp 189-190; OCEANA statement to BSEE, RE: Revisions to Safety and 
Environmental Management Systems (SEMS), 1010-AD73, November 14, 2011; p 3. 
http://www.bsee.gov/uploadedFiles/Oceana%2011-9-11.pdf (accessed March 26, 2016). 
283 30 C.F.R. § 250.1933; 30 C.F.R. § 250.193. 
284 Notice of Voluntary Confidential NearMiss Reporting System Public Workshop, 79 Fed. Reg. 17563; See also 
BTS and BSEE to Develop Confidential Near-Miss Reporting System, http://www.rita.dot.gov/bts/bts_bsee 
(accessed March 26, 2016). 
285 This program was implemented on May 5, 2015 in SafeOCS. See Section 4.3.2. 
286 “SafeOCS is a voluntary and completely confidential system, in which the Bureau of Transportation Statistics 
(BTS) will collect and analyze near-miss reports submitted by individual OCS workers, companies, and others. 
The aggregated data will be shared with the general public through the BTS website, and used to identify safety 
trends and increase understanding of offshore risk;” http://www.bsee.gov/BSEE-Newsroom/Press-
Releases/2015/BSEE-Director-Brian-Salerno-Announces-Key-Efforts-to-Reduce-Risk-Offshore/ (accessed March 
26, 2016). 
287 The CSB has not identified an anonymous online reporting tool on the BSEE website. The Bureau of 
Transportation Statistics does have a functioning SafeOCS near-miss reporting system link which can be found 
here: https://near-miss.bts.gov/#contactUs (accessed March 31, 2016). 
288 111 H.R. 5851. Offshore Oil and Gas Worker Whistleblower Protection Act of 2010. 
https://www.congress.gov/bill/111th-congress/house-bill/5851 (accessed January 7, 2016). The House also 
brought forward subsequent versions of this bill in 2011, and then again in 2015. See 112 H.R. 503, Offshore Oil 
and Gas Worker Whistleblower Protection Act of 2011; 114 H.R. 2824, Offshore Oil and Gas Worker 
Whistleblower Protection Act of 2015. 

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expired due to inaction during a previous Congress. Nevertheless, such legislation highlighted the 
regulatory gap in whistleblower protection that the SEMS program has not addressed. 
BSEE itself, in its Safety Culture Policy Statement of May 9, 2013, identified an “Environment for 
Raising Concerns” as one of nine characteristics of a robust safety culture and that this meant that “A 
work environment is maintained where personnel feel free to raise safety and environmental concerns 
without fear of retaliation, intimidation, harassment, or discrimination.”289 
Some existing statutes have jurisdictional language that may apply offshore and the possibility exists that 
offshore workers may have some, albeit limited, measure of whistleblower protection. OSHA currently 
oversees enforcement of many different whistleblower protection laws arising in areas such as 
occupational, environmental, nuclear, transportation, consumer, and other categories.290 Some of the most 
potentially applicable statutes that might help protect offshore workers tend towards environmental 
protection, are the Clean Air Act,291 the Comprehensive Environmental Response, Compensation and 
Liability Act,292 and the Federal Water Pollution Control Act (the Clean Water Act).293 
In the UK, the workforce brings forward its safety concerns to its designated safety representatives who 
present these matters to the installation manager.294 In effect, the workforce has a protective mechanism 
from retaliation. Norway and Australia take similar approaches.295 
The Mining Safety and Health Administration, or MSHA, also provides protections for workers voicing 
safety concerns with mining operations. Neither a miner nor a miner’s representative can be discharged or 
retaliated against for filing a complaint concerning safety related matters. Moreover, a miner or a miner’s 
representative can seek legal relief if they believe they have been the subject of dismissal or harassment 
for filing such complaint.296 
Effectively managed reporting programs provide the regulator a view of issues that may not otherwise be 
detected through inspections. To manage a reporting program effectively, the operator must remove 
 
289 BSEE, Safety Culture Policy, http://www.bsee.gov/Safety/Safety-Culture-Policy/ (accessed October 7, 2015). 
290 US Department of Labor. The Whistleblower Protection Programs, 
http://www.whistleblowers.gov/wb_filing_time_limits.html (accessed March 31, 2016). 
291 42 U.S.C. § 7422. 
292 42 U.S.C. § 9610. 
293 33 U.S.C. § 1367. 
294 Malloy, J. Former Director, Regional Organizer, RMT Union Offshore Energy Branch, Personal communication, 
October 3, 2013; UK HSE. Safety representatives and safety committees on offshore installations: A brief guide 
for the workforce, INDG199(rev1), 1999, http://www.hse.gov.uk/pubns/indg119.htm.; The Offshore Installations 
(Safety Representatives and Safety Committees) Regulations 1989, 
http://www.legislation.gov.uk/uksi/1989/971/contents/made (accessed March 26, 2016). 
295 Working Environment Act, December 14, 2012; Section 6-2, 
http://www.arbeidstilsynet.no/binfil/download2.php?tid=92156.; Offshore Petroleum and Greenhouse Gas 
Storage Act 2006, Volume 3, Schedule 3, Part 3, Subdivision B, 
http://www.comlaw.gov.au/Details/C2013C00071/Html/Volume_3#_Toc347403653. 
296 30 U.S.C. § 815(c). 

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penalties for reporting safety issues.297 As long as SEMS and other potential sources of federal oversight 
fail to provide protection for whistleblowers or workers seeking to stop work in the offshore environment, 
offshore process safety suffers. 
3.4.7 
No SWA Worker-Requested Regulatory Provision in Regulation 
The SEMS regulations do not contain a provision allowing the workforce to seek intervention by the 
regulator should they feel that management is not responding adequately to their call for a stop work. 
Rather, SEMS states, “Work may be resumed when the individual on the facility with Ultimate Work 
Authority (UWA) determines that the imminent risk or danger does not exist or no longer exists.”298 But 
management designates the individual with the UWA.299 This creates the potential for resolving when to 
resume operations without adequate or impartial review. Workers may reasonably believe that operations 
still pose a significant risk if restarted. Therefore, SEMS should provide for regulatory intervention 
whenever management and workers disagree on whether work can be safely resumed. 
UK law provides that if two or more safety representatives believe an “imminent risk” exists in any 
activity, they must inform the installation manager.300 The installation manager then must inform an HSE 
inspector of the issue through a report as soon as is reasonably practicable.301 The HSE may issue an 
enforcement notice either to prohibit the activity until matters have been corrected or to require some 
longer-term improvements, or in the worst case, to prosecute the responsible party.302 The decision on 
when work can begin again is left to the regulator and is specified in the prohibition notice.303 
In Norway, the safety representatives have the right to halt dangerous work. The danger must be 
immediate and cannot be averted by other means. If the safety representative determines these conditions 
to be the case, work may be halted until the labor inspection authority decides whether work may 
continue.304 
 
297 Committee on Education and the Workforce. H.R. 503: Offshore Oil and Gas Worker Whistleblower Protection 
Act, http://democrats.edworkforce.house.gov/bill/hr-503-offshore-oil-and-gas-worker-whistleblower-protection-
act (accessed March 26, 2016). 
298 30 C.F.R. § 250.1930(c). 
299 30 C.F.R. § 250.1931(a). 
300 The Offshore Installations (Safety Representatives and Safety Committees) Regulations 1989, 
http://www.legislation.gov.uk/uksi/1989/971/contents/made (accessed March 26, 2016). 
301 UK HSE, Safety Representatives and Safety Committees on Offshore Installations, 
http://www.hse.gov.uk/pubns/indg119.pdf (accessed March 26, 2016). 
302 UK HSE, HSE Public Register of Enforcement Notices, http://www.hse.gov.uk/notices/ (accessed March 26, 
2016). 
303 Joomla!. UK Health and Safety Legal System: Appendix A – UK Health and Safety Legal System, Prohibition 
Notice, 
http://www.simplesensiblesafety.co.uk/index.php?option=com_content&view=article&id=22&catid=1&Itemid=8
2 (accessed March 26, 2016). 
304 Working Environment Act, December 14, 2012; Section 6-3, 
http://www.arbeidstilsynet.no/binfil/download2.php?tid=92156 (accessed March 26, 2016). 

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Australia requires safety representatives to report an imminent danger to the supervisor or, if no 
supervisors can be located, to stop work.305 If supervisors can be located, then the supervisor is required 
to take actions that he or she believes will remove the danger. If the safety representatives believe 
imminent danger still exists, they may make a request to NOPSEMA to conduct an inspection of the 
activity. This option also exists for the supervisors if they disagree with the safety representatives. Only 
after the NOPSEMA inspection determines that the activity is safe can work resume.306 
The SEMS failure to require regulatory intervention in a stop-work dispute between the workforce and 
management increases potential safety risk. Lack of regulatory participation in a stop-work situation can 
result in management’s always making the ultimate decision. Management may order work to resume 
after a stop work before eliminating or sufficiently mitigating the hazard in the interest of averting costs, 
lost time, and other economic impacts caused by the stop work. Management may decide even with 
limited understanding of the risks due to distance from the worksite or unfamiliarity with the work, the 
requirements of its special tasks, or other unique circumstances. Regulatory intervention of the type 
discussed in the UK, Norway, and Australia thus provide an avenue for improving the SEMS regulation. 
The reality is, however, that the formality of involving the regulator in a stop work situation is only a 
backstop. Sound safety culture, with informed safety representatives and enhanced protection for workers 
who exercise stop work authority should resolve worker concerns about safety without frequent need for 
regulator involvement. Nevertheless, the right to involve the regulator is always available in those 
jurisdictions, and it remains a powerful driver to resolve issues. The US should emulate this important 
protection. 
3.4.8 
No SEMS Safety Committees or Tripartite Safety Forums Provision 
A fundamental element in effective safety management for major accident prevention is active and equal 
participation from the regulator, industry, and labor. Each stakeholder provides unique and essential 
insights; removing the participation of any of them can result in losing a critical voice in safety 
management. While the regulator and industry management typically have the means to ensure that their 
voices are heard—they have the enforcement power on one hand and ownership or managerial authority 
on the other—the workers often lack similar means. Labor participation is vital as it gives workers the 
opportunity to provide management and the regulator with invaluable insights, and in many instances the 
workers are the only source of this information.307 In other offshore regimes, workers are guaranteed 
rights to form safety committees, made up of both management and workforce members, to encourage 
dialogue on safety issues or concerns at each offshore facility. In contrast, SEMS lacks requirements for 
workforce-management safety committees that would promote dialogue on safety concerns between both 
entities. 
The UK requires each offshore installation with more than one safety representative to establish a safety 
committee comprised of the installation manager, another person appointed by the installation manager, 
 
305 Offshore Petroleum and Greenhouse Gas Storage Act 2006, Volume 3, Schedule 3, Part 3, Division 5, 44, 
http://www.comlaw.gov.au/Details/C2013C00071/Html/Volume_3#_Toc347403653. 
306 Ibid., Division 5, 44 & 45. 
307 Center For Chemical Process Safety. Guidelines for Risk Based Process Safety; John Wiley & Sons: Hoboken, 
NJ, 2007; p 124. 

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and all of the safety representatives.308 Through the committee, management and the workforce discuss 
health and safety matters with the goal of developing mutual cooperation and ensuring the safety of the 
workforce.309 
In addition to these safety committees, many regimes have developed larger forums where regulator, 
industry, and workforce all have equal opportunities to directly interact and discuss safety matters. The 
regulator often hosts and supports these forums. Yet no such regulator-supported forum has been 
developed for US offshore worker representatives can openly discuss safety issues with industry 
management and the regulator. 
The UK has a tripartite forum which is enabled through Step Change in Safety,310 an organization 
established in 1997 when industry decided to require significant improvements in health and safety, and 
when collaboration among the parties became a priority.311 Through the years, Step Change influenced 
greater cooperation among labor, industry, and the regulator.312 The organization is led by a team of 
senior managers from industry, trade unions, trade associations, and the regulator. The workforce is 
specifically engaged through networks, including elected safety representatives, safety professionals, and 
site leaders. Regular meetings are held throughout the year to share safety information and to discuss 
safety issues. Through this framework, issues such as competence, leadership, workforce engagement, 
continual improvement, asset integrity, and communication are addressed to improve health and safety 
offshore.313 Step Change supports a number of steering groups, including the Workforce Engagement 
Support Team (WEST), which aims to maximize the value of both safety representatives and workforce 
engagement survey tools that strengthen workers’ role in safety management.314 The UK HSE also chairs 
a more formal, higher level tripartite body, the Offshore Industry Advisory Committee (OIAC), which 
brings employer and worker representatives together with the regulator in another important forum to 
discuss offshore health and safety matters.315 
Similarly, Norway’s regulator established a number of tripartite bodies. A working environment 
committee is involved in planning safety issues such as construction work, work processes, and 
 
308 The Offshore Installations (Safety Representatives and Safety Committees) Regulations 1989, 
http://www.legislation.gov.uk/uksi/1989/971/contents/made (accessed March 26, 2016). 
309 UK HSE. A guide to the Offshore Installations (Safety Representatives and Safety Committees) Regulations 
1989; 2012; p 2. http://www.hse.gov.uk/pubns/priced/l110.pdf. (accessed March 26, 2016); note, in the United 
States, safety committees are required by some state laws and often, in unionized workplaces, through the 
collective bargaining process. 
310 http://www.stepchangeinsafety.net/; UK HSE. Offshore Oil & Gas Sector Strategy, 
http://www.hse.gov.uk/offshore/priorities.htm (accessed March 26, 2016). 
311 Step Change in Safety, Strategic Plan 2010-2015: Making the UK the safest place to work in the worldwide oil 
and gas industry, 2010. 
312 Ibid. 
313 Ibid. 
314 Step Change in Safety, Workforce Engagement, https://www.stepchangeinsafety.net/about-step-change-
safety/steering-groups/workforce-engagement (accessed March 26, 2016). 
315 UK HSE, Offshore Industry Advisory Committee (OIAC), http://www.hse.gov.uk/aboutus/meetings/iacs/oiac/ 
(accessed March 26, 2016). 

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preventive safety measures. The committee receives paid time off to attend training sessions.316 A 
Regulatory Forum and the Safety Forum317 also facilitates discussion of safety issues such as trends in 
risk management, practical implementation of regulatory requirements, and safety standards for use 
offshore.318 PSA asserts that these forums are beneficial venues to raise awareness of safety issues and 
discuss potential solutions, especially for industry members who are less sophisticated.319 
Australia’s NOPSEMA uses its Offshore Petroleum Safety Tripartite Forum to actively engage all the 
stakeholders involved in the offshore petroleum industry.320 NOPSEMA maintains that such engagement 
will improve safety by promoting “information sharing, learning and innovation across the offshore 
petroleum industry.”321 
The US lacks similar initiatives to encourage participation among the regulator, industry, and labor. This 
remains a missed opportunity. 
3.4.9 
Conclusion 
The importance of worker participation in safety management cannot be overstated. Existing US offshore 
safety regulations addressing workforce participation are improved since Macondo; however, the 
regulations still suffer from significant gaps. The regulations fail to engage all members of the workforce; 
lack workforce-elected safety representatives and safety committees; rely heavily on SWA which is a 
weak form of worker involvement if not properly implemented or supported; and create potential 
opportunities for blaming the workforce without recourse to regulator intervention. These gaps diminish 
safety by discouraging workforce participation in managing offshore safety. The regulator should take 
additional steps to improve these regulatory provisions, provide for protection against retaliation for 
workforce participation in safety management activities, as well as play a lead role in establishing a 
tripartite forum to aid workers in having a larger voice in process safety management and major accident 
prevention. 
 
 
 
 
316 Working Environment Act, December 14, 2012; Section 7, 
http://www.arbeidstilsynet.no/binfil/download2.php?tid=92156 (accessed March 26, 2016). 
317 Hauge , H., Okstad , E., Tinmannsvik , R., Lootz, E., Ovesen , M., Carlsen, I., Risk of Major Accidents: Causal 
Factors and Improvement Measures Related to Well Control in the Petroleum Industry, SPE Americas E&P 
Health, Safety, Security and Environmental Conference, Galveston, TX, March 18-20, 20132; SPE-163775-MS: 
318 Ibid.; PSA, Regulatory Forum, 2014, http://www.ptil.no/regulations/regulatory-forum-article9524-216.html# 
(accessed March 26, 2016). 
319 Sophistication refers to industry members who do not have the breadth and depth of offshore business experience 
as some of the oil majors, who have well-developed operational programs from decades of experience; CSB 
Norway trip notes, April 26 – May 1, 2012. 
320 NOPSEMA. Offshore Petroleum Safety Tripartite Forum, http://www.nopsema.gov.au/safety/offshore-
petroleum-safety-tripartite-forum/. 
321 Offshore Petroleum Safety Tripartite Forum, Terms of Reference, Feb. 26, 2013, 
http://www.nopsema.gov.au/assets/document/Terms-of-Reference-Offshore-Petroleum-Safety-Tripartite-Forum-
Rev-0-Feb-2013.pdf. 

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4.0 US Offshore Regulator Challenge in Effective Oversight 
BSEE’s goal of a SEMS program is “to promote safety and environmental protection.”322 To accomplish 
that goal, operators must “ensure [their] SEMS program identifies, addresses, and manages safety, 
environmental hazards …”323 This language is weaker than the corporate policies BP and Transocean had 
at the time of Macondo to prevent incidents that harmed people and the environment and to apply 
ALARP principles in their operations.324 Furthermore, BP and Transocean already had mandated internal 
safety management systems that would have satisfied post-Macondo SEMS requirements, including 
hazard analysis, management of change, operating procedures, and incident investigation.325 The analysis 
presented in Volume 3 demonstrates that BP and Transocean’s failures to effectively implement these 
systems were causal factors in the blowout. Thus, merely having a documented safety management 
program that complies with SEMS regulations is not sufficient. A fundamental question arises: Have 
enough changes occurred in the US to make safety management programs, like those which BP and 
Transocean already had in place, effective? This chapter answers the question by describing the value of 
major hazard documentation that identifies the major hazards and the barriers intended to prevent or 
mitigate them, as well as the influential role of the regulator in proactive review and verification of that 
documentation. The chapter also describes potential opportunities for BSEE to drive further industry 
safety improvements through the use of effective process safety indicators and transparency. 
 
 
 
322 30 C.F.R. § 250.1901. 
323 Ibid. 
324 BP’s OMS Exploration and Production Drilling and Well Operations Practice (DWOP) states, “all risks shall be 
managed to a level which is as low as reasonably practical” or ALARP, Internal Company Document, BP. GP 10-
00 Drilling and Well Operations Practice, Issue 1, October 2008, "This document contains the practices that have 
been agreed by BP management as current and relevant for drilling and well operations.", p A-8, BP-HZN-
BLY00034518, http://www.mdl2179trialdocs.com/releases/release201304110900026/TREX-06121.pdf (accessed 
May 26, 2015). Transocean policies requires employees to manage risks to ALARP, which Transocean defines as 
“… requiring personnel to consider the various additional risk reduction measures (additional controls) and 
determine if the effort and cost of those measures justify the additional amount of risk reduction obtained” 
Internal Company Document, Transocean. Health and Safety Policies and Procedures Manual, Issue 03, Revision 
07, HQS-HSE-PP-01, December 15, 2009, Section 4 (Safety Policies, Procedures and Documentation), p BP-
HZN-2179MDL00132218, see Exhibit 4942, BP-HZN-2179MDL00132055, 
http://www.mdl2179trialdocs.com/releases/release201302281700004/Farr_Daniel-Depo_Bundle.zip (accessed 
October 7, 2015). 
Internal Company Document, BP. The BP Operating Management System Framework, Part 1, An Overview of 
OMS, Issue 2, November 3, 2008, p 24, BP-HZN-2179MDL0033320, see Exhibit 2352 
http://www.mdl2179trialdocs.com/releases/release201302281700004/Lynch_Richard-Depo_Bundle.zip 
(accessed October 7, 2015). 
Internal Company Document, Transocean. Health and Safety Policies and Procedures Manual, Issue 03, Revision 
07, HQS-HSE-PP-01, December 15, 2009, General, BP-HZN-2179MDL00132067, see Exhibit 4942 
http://www.mdl2179trialdocs.com/releases/release201302281700004/Farr_Daniel-Depo_Bundle.zip (accessed 
October 7, 2015). 
325 30 C.F.R. § 250.1902 and Volume 3. 

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In 2015 BSEE laid out two strategic goals:326 
• 
Regulate, enforce, and respond to OCS development using the full range of authorities, policies, 
and tools to compel safety, emergency preparedness and environmental responsibility and 
appropriate development and conservation of the offshore oil and natural gas resources. 
• 
Build and sustain the organizational, technical, and intellectual capacity within and across 
BSEE’s key functions – capacity that keeps pace with OCS industry technological 
improvements, innovates in regulation and enforcement, and reduces risk through systemic 
assessment and regulatory and enforcement actions.” 
Yet despite these aims and the post-Macondo regulatory changes, BSEE still struggles with several 
limitations and untapped opportunities to more effectively regulate the offshore oil and gas industry: 
• 
Limited proactive oversight mechanisms to drive industry to improve safety systems as evidenced 
by these shortfalls: 
o BSEE does not require documentation demonstrating control of major hazards before 
commencing the hazardous offshore operations; 
o Lack of sufficient direct involvement in SEMS audits, and the accompanying dialogue 
with the company that occurs as part of the auditing process, which minimizes BSEE’s 
influence; 
• 
Inadequate collection and use of safety performance indicator data to identify and analyze 
developing safety issues before they turn into more severe problems; 
o BSEE has not initiated industrywide or companywide audits to proactively assess safety 
trends; 
• 
Historically inadequate levels of transparency in disseminating industry safety information and in 
the performance of oversight activities. 
 
This chapter explores proactive mechanisms BSEE can use to counter this issues and more effectively 
oversee industry’s efforts to manage major accident risk, while driving further safety improvements and 
promoting trust among members of industry, workforce, and the public. 
4.1 
No Required Review of Major Accident Hazard Documentation 
Before Hazardous Work Begins 
Oil and gas companies operating in the US OCS are not required to provide major hazard documentation 
that: (1) identifies all major accident hazards, (2) implements the necessary barriers and controls to reduce 
risk to ALARP, and (3) describes an effective and operational safety management program to ensure that 
those barriers and controls will remain reliable and available as needed. 327 While point 3 could 
 
326 The US Department of the Interior. Budget Justifications and Performance Information Fiscal Year 2015: 
Bureau of Safety and Environmental Enforcement; 
http://www.bsee.gov/uploadedFiles/BSEE/About_BSEE/Budget/BSEE%20FY%202015%20Final%20Greenbook
%20File.pdf (accessed March 25, 2015). 
327 See Chapter 4, Volume 2. 

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potentially be addressed by a SEMS program, points 1 and 2 go beyond current SEMS requirements.328 
BSEE could review major hazard documentation, and if necessary, challenge a company’s assertions 
before and/or during hazardous activities. Furthermore, the assertions in major hazard documentation 
could become the foundation for BSEE to conduct more effective preventative audits and inspections and 
have meaningful dialogue with the duty holder about its specific risk management policies and 
practices.329 
As described in Chapters 2.0 and 3.0, the development of a written case for safety is critical to the UK 
and Australian offshore regulatory regimes, and a similar “internal control” plan requirement exists for 
companies operating in Norwegian waters.330 Originally only UK and Australian offshore regulators had 
to accept331 a facility’s written case for safety before it could commence operation, and as of June 28, 
2013 that requirement now applies to all European Union members, 332 including over 1,000 facilities in 
the North Sea, Mediterranean Sea, and Black Sea with offshore drilling and production activities.333 The 
regulator’s acceptance of a written case for safety in any jurisdiction (called a Major Hazard Report under 
the EU directive) still does not license the facility or installation as “fit,” nor does it shift the duty of risk 
control and reduction away from the facility owner or operator and onto the regulator. Rather, the duty of 
major accident prevention and risk-reduction to ALARP remains with the duty holder throughout the life 
of the facility. In fact, even in adopting the new directive, the EU noted that offshore safety remains 
primarily the obligation of the offshore operators and the individual countries in which they operate.334 
Following the regulator’s acceptance of the safety case document, the duty holder must ensure that the 
installation is operated in accordance with the safety management system and other risk-reduction 
provisions described in the safety case. 
The term “safety case” came about because in such a regime, the duty holder is expected to make a 
written case for safety to the regulator.335 In their documentation, duty holders must explain the processes 
 
328 As described in Section 6.1.1 of Volume 2, the hazard analysis requirement in SEMS (30 C.F.R. 250.1911) is not 
focused on targeted risk reduction of major accident events and the barriers intended to prevent or mitigate them. 
329 Section 4.2 for further discussion. 
330 See, Hopkins, A. Explaining the Safety Case; Working Paper 87; National Research Centre for OHS Regulation, 
Australian National University: April, 2012. 
331 This concept is discussed in the CSB’s report on the Chevron Richmond Refinery. “Acceptance requires 
satisfaction with the duty holder’s approach to identifying and meeting health and safety needs … HSE ‘accepts’ 
the validity of the described approach as being capable, if implemented as described, of achieving the necessary 
degree of risk control, but HSE does not confirm the outcomes of that approach.” Therefore, “HSE will accept a 
safety case or a revision … when duty holders demonstrate and describe specified matters to HSE’s satisfaction. 
Acceptance will be based on HSE’s judgment that the arrangements and measures described in the safety case 
taken as a whole are likely to achieve compliance if implemented as described. To give acceptance HSE does not 
need to be satisfied that compliance will be achieved….” UK HSE. A guide to the Offshore Installations (Safety 
Case) Regulations 2005, 3rd ed.; SCR 2005; 2006; p 6, http://www.hse.gov.uk/pubns/books/l30.htm (accessed 
March 26, 2016). 
332 Http://ec.europa.eu/energy/en/topics/oil-gas-and-coal/offshore-oil-and-gas-safety. 
333 Safety of Offshore Oil and Gas Operations Directive, http://eur-lex.europa.eu/legal-
content/EN/ALL/?uri=CELEX:32013L0030. 
 334 European Commission, Offshore oil and gas safety, Http://ec.europa.eu/energy/en/topics/oil-gas-and-
coal/offshore-oil-and-gas-safety (accessed January 26, 2016). 
335 Ibid., p 4. 

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they used to identify hazards and assess risks336 and their rationale for choosing a particular method of 
controlling them.337 The regulator reviews the case and accepts or rejects the document, which is a 
prerequisite to obtain a license to drill.338 Once a rig has an accepted safety case, it can operate anywhere 
in that jurisdiction without resubmitting the case, assuming it addressed the full range of hazard options. 
This presentation and acceptance feature of the Australian and UK safety case process forms the basis of 
the legal agreement between the company and the regulator. 
According to UK HSE guidance on the offshore Safety Case Regulations, safety case reports are 
“intended to be living documents, kept up to date and revised as necessary during the operational life of 
the installation.”339 Similarly, Australian regulators explain that if carried out properly, the process of 
developing the safety case will “improve safety of offshore activities by ensuring a systematic review of 
the hazards, their associated risks and the control measures that are applied at the facility to either 
eliminate the hazards or otherwise reduce the risks. Progress, in terms of risk-reduction, is achieved by 
applying the process both during initial development of the safety case and subsequently in the course of 
continual improvement.”340 
 
 
 
336 Ibid., p 5. 
337 Ibid., p 5. 
338 Whewell, I. Former Director, UK HSE Offshore Division, Personal communication, July 6, 2011. 
339 UK HSE. A guide to the Offshore Installations (Safety Case) Regulations 2005, 3rd ed.; SCR 2005; 2006; p 7. 
http://www.hse.gov.uk/pubns/books/l30.htm (accessed March 26, 2016). 
340 NOPSEMA. ALARP Guidance Note; N-04300-GN0166, Rev 6; June, 2015; p 18. 
http://www.nopsema.gov.au/assets/Guidance-notes/N-04300-GN0166-ALARP.pdf (accessed March 26, 2016). 
EU-wide safety standards 
Under the Safety of Offshore Oil and Gas Operations Directive, the EU put in place a 
set of rules to help prevent accidents, as well as to respond promptly and efficiently 
should one occur before exploration or production begins. For their offshore 
installation, companies must prepare a Major Hazard Report, containing a risk 
assessment and an emergency response plan. They must keep resources at hand to put 
them into operation when necessary when granting licenses. EU countries must 
ensure that companies are well financed and have the necessary technical expertise 
and solutions critical for the safety of operators' installations. These must be 
independently verified by the regulator before the installation commences operation. 
National authorities must verify safety provisions, environmental protection 
measures, and the emergency preparedness of rigs and platforms. If companies do not 
respect the minimum standards, EU countries can impose sanctions, including halting 
production. Information on how companies and EU countries keep installations safe 
must be made available for citizens. Companies will be fully liable for environmental 
damages caused to protected marine species and natural habitats. For damage to 
marine habitats, the geographical zone will cover all EU marine waters including 
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Internationally, both the UK HSE and NOPSEMA require acceptance of an operator’s safety case before 
beginning activities.341 This framework requires operators to demonstrate that all risks were reduced to 
ALARP.342 Nevertheless, the safety case is “accepted” and not “approved,” as the safety of the facility is 
not guaranteed by the regulator, nor does it mean the operation as a whole is fit.343 Acceptance of the 
safety case indicates that the facility’s approach is valid in terms of good practice; however, confirmation 
of compliance is based on post-acceptance programs, such as inspections and audits.344 The requirement 
that the regulator accept an operator’s safety case before beginning activities is beneficial because it 
allows for meaningful dialogue to begin at the early stages of development.345 
In Norway, the PSA does not formally review and “accept” the management system documentation 
before permitting companies to drill, but it does require that management system documentation be 
prepared and be made available for the regulator’s review at any time, such as during a facility audit. PSA 
then routinely reviews the documentation and discusses its contents with the operator to assess how the 
operator’s SMS is working.346 PSA does not require the facility to submit its safety management system 
for acceptance, and asserts that the benefits of this approach are: (1) it does not create the impression that 
the duty of ensuring safety has shifted to the regulator and (2) regulatory resources can focus on industry 
activities instead of the paperwork review.347 
In the UK, Australia, and Norway, duty for assuring risks are reduced to ALARP remains with the entity 
responsible for creating or controlling the risk. The regulator checks that an operation is effectively 
reducing risk to ALARP through audits and inspections that verify the duty holder’s adherence to its own 
 
341 See The Offshore Installations (Safety Case) Regulations 2005, No. 3117, Regulation 7 & 8, 
http://www.legislation.gov.uk/uksi/2005/3117/contents/made (accessed March 26, 20160; Offshore Petroleum and 
Greenhouse Gas Storage (Safety) Regulations 2009, Division 2- Submission and acceptance of safety cases, 
https://www.legislation.gov.au/Details/F2013C00945 (accessed March 26, 2016). 
342 UK HSE. A guide to the Offshore Installations (Safety Case) Regulations 2005, 3rd ed.; SCR 2005; 2006; 
Demonstration of ‘as low as reasonably practicalbe, p 13. http://www.hse.gov.uk/pubns/books/l30.htm (accessed 
March 26, 2016); Offshore Petroleum and Greenhouse Gas Storage (Safety) Regulations 2009, 1.4 Objects, 
https://www.legislation.gov.au/Details/F2013C00945 (accessed March 26, 2016). 
343 Pitblado, R.; Bjerager, P.; Andreassen, E. An Effective US Offshore Safety Regime; Det Norske Veritas: 22 2010, 
July; p 3. http://www.dnvusa.com/Binaries/1008-001%20Offshore%20Update_Key%20aspects_tcm153-
430982.pdf (accessed March 16, 20106); Powell, T. US Voluntary Semp Initiative: Holy Grail or Poisoned 
Chalice?, Offshore Technology Conference, Housont, TX, May 8-9, 1996; OTC 8111. 
344 CSB Public Hearing: Regulatory Approaches to Offshore Oil and Gas Safety, Washington, DC, December 15, 
2010; see, for example, pp 32-35. 
http://www.csb.gov/assets/1/19/Transcript_of_Public_Meeting_12_15_2010.pdf (accessed March 7, 2015). 
345 Ibid. 
346 Transportation Research Board of the National Academies. Evaluating the Effectiveness of Offshore Safety and 
Environmental Management Systems; Transportation Research Board Special Report 309; National Academy of 
Sciences: Washington, DC, 2012; pp 62-63. http://onlinepubs.trb.org/onlinepubs/sr/SR309.pdf (accessed March 
31, 2016). 
347 Center for Stratetic & International Studies. The International Regulatory Structures for Offshore Exploration; 
November 8, 2010; p 2. http://csis.org/files/attachments/101108_Summary_International%20Practices.pdf 
(accessed March 26, 2016). 

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safety assertions.348 The true strength of the regimes lie then in the regulators’ abilities to test the validity 
of duty holder claims.349 
Without such a review of the documentation detailing the planned risk reduction measures, a scenario 
could arise in which the operator assembles and executes a deficient safety management system and 
BSEE misses an opportunity to identify safety gaps. The permit-to-operate process that currently exists in 
the US OCS provides opportunities to evaluate aspects of a facility’s management systems before certain 
design and operational phases of the well site. None, however, sufficiently address process safety 
concerns. For instance, in bidding on an OCS lease, BOEM can disqualify a potential lessee for various 
reasons, including unresolved or multiple incidents of noncompliance, civil penalties, or failure to adhere 
to lease obligations.350 While civil penalties may touch upon aspects of process safety, disqualification 
largely depends on administrative or occupational safety matters. 
Once a lease has been obtained, an operator must obtain approval from BSEE to drill by submitting 
information such as design criteria for the proposed well, drilling plans, and diverter and BOP system 
descriptions.351 The information required by BSEE is a prescriptive-based series of technical 
specifications that does not contain a comprehensive list of best technical practices nor a comprehensive 
barrier-risk analysis that addresses both design and operational site specific risks.352 Further, there is no 
performance based requirement to ensure the design risks of the well are and will remain reduced to a 
level such as ALARP throughout the lifecycle of the well. 
For the US to effectively implement a more robust regulatory regime for its offshore oil and gas 
operations, BSEE must play a proactive role in risk-reduction. In the CSB’s view, this includes not only 
active review and response to third-party audit results, but independent BSEE audits and initiatives on 
identified safety issues or at-risk facilities/companies, and the authority and to accept, reject, or require 
 
348 CSB Public Hearing: Regulatory Approaces to Offshore Oil and Gas Safety, Washington, DC, December 15, 
2010; see, for example, p 95. http://www.csb.gov/assets/1/19/Transcript_of_Public_Meeting_12_15_2010.pdf 
(accessed March 7, 2015). UK HSE. A guide to the Offshore Installations (Safety Case) Regulations 2005, 3rd 
ed.; SCR 2005; 2006; Demonstration of ‘as low as reasonably practicalbe, p 6. 
http://www.hse.gov.uk/pubns/books/l30.htm (accessed March 26, 2016). 
349 “The fact is that the safety case is simply a series of ‘claims’ as to how an installation is being safely operated. 
The real strength in the regime is testing the validity of those claims through strategic intervention by competent 
regulators,” Whewell, I. Former Director, UK HSE Offshore Division, Personal communication, August 23, 2013. 
350 30 C.F.R. § 556.35; & 30 C.F.R. § 550.136; see also BSEE. Regional Leasing, http://www.boem.gov/Oil-and-
Gas-Energy-Program/Leasing/Regional-Leasing/Index.aspx (accessed March 26, 2016). 
351 §250.410; §250.400 indicates that those subject to Subpart D—Oil and Gas Drilling Operations under which the 
permitting requirements are described include lessees, operating rights owners, operators, and their contractors 
and subcontractors. 
352 For example, the regulations for cementing require that the operator provide “A written description of how you 
evaluated the best practices included in API Standard 65—Part 2, Isolating Potential Flow Zones During Well 
Construction, Second Edition...Your written description must identify the mechanical barriers and cementing 
practices you will use for each casing string (reference API Standard 65—Part 2, Sections 4 and 5).” Sections 4 
and 5 in API Standard 65 state, “This section [4] is not exhaustive, nor does it provide the reader with a 
comprehensive set of detailed recommendations for well construction. The intent is to highlight the salient aspects 
that should be considered and summarize the interrelationship between drilling operations and cementing success. 
All topics discussed are covered in detail in various API, ISO, and other industry publications. […] This 
[technical references] list is not all-inclusive. Other technical references are available in industry literature.” 

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modifications to a company’s major hazard risk management approach before or throughout the entirety 
of the offshore operation. 
4.2 
Regulatory Safety Oversight Audits and Initiatives 
After BSEE’s first audit of the SEMS program in 2013, it noted there was a significant variation in SEMS 
programs amongst operators.353 As might be expected, for companies like BP and Transocean, BSEE 
observed that complying with the SEMS regulations entailed mapping their corporate policies to the 
SEMS elements listed in 30 C.F.R. 250 Subpart S.354 BSEE noted that for other organizations, the SEMS 
rule “triggered a first effort to develop and implement a formal SEMS,” and that for many organizations 
the focus was on compliance rather than “developing a tool to manage their respective operating health, 
safety, and environmental (HSE) risks.”355 
In a 2012 interview, former BSEE Director James Watson contended that BSEE did not “review and 
approve the safety and environmental management system programs and that’s by design.”356 BSEE did 
not want to create a system in which industry relied on the government to management it.357 ‘Reviewing’ 
a company’s SEMS program and major hazard documentation, however, is an opportunity for the 
regulator to challenge 1) if hazards and risks have been assessed and 2) if controls and proposed safety 
management systems meant to ensure their effectiveness have been established. In this framework, 
“approving’ a SEMS program or major hazard documentation can simply be acknowledgement by the 
regulator that all the elements it has deemed necessary to manage safety have been addressed. The 
effectiveness of a SEMS program though can only be assessed or audited after being tested under the 
demands of actual operations. 
In 2012, BSEE (then BOEMRE) engaged the Transportation Research Board (TRB) to provide guidance 
on how to evaluate the effectiveness of the SEMS regulations. TRB observed:358 
• 
If BSEE’s goal is, as it should be, to encourage a culture of safety so that individuals know the 
safety aspects of their actions and are motivated to think about safety, then the agency will need 
to evolve an evaluation system for Safety and Environmental Management Systems (SEMS) that 
emphasizes the evaluation of attitudes and actions rather than documentation and paperwork. 
 
 
353 BSEE. SEMS Program Summary—First Audit Cycle (2011-2013); July 23, 2014, 
http://www.bsee.gov/uploadedFiles/BSEE/Regulations_and_Guidance/Safety_and_Environmental_Management_
Systems_-_SEMS/SEMS%20Program%20Summary%208132014.pdf (accessed March 29, 2016). 
354 Ibid. 
355 Ibid. 
356 Dlouhy, J. Offshore enforcement chief outlines approach to safety. Fuel Fix from the Houston Chronicle, 
December 18, 2012, http://fuelfix.com/blog/2012/12/18/offshore-enforcement-chief-outlines-approach-to-safety/ 
(accessed March 26, 2016). 
357 Ibid. 
358 Transportation Research Board of the National Academies. Evlauating the Effectiveness of Offshore Safety and 
Environmental Managment Systems; Transportation Research Board Special Report 309; National Academy of 
Sciences: Washington, DC, 2012; pp 31 and 91. http://onlinepubs.trb.org/onlinepubs/sr/SR309.pdf (accessed 
March 31, 2016). 

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• 
BSEE can encourage or hurt the development of a culture of safety by the way it measures and 
enforces SEMS. Forcing an operation to satisfy checklists that require specific forms of 
documentation and penalizing those operations that do not is likely to encourage a culture of 
compliance and discourage the development of a culture of safety. 
BSEE’s findings two years later in 2014 on the SEMS programs validated TRB’s observations. BSEE 
noted that audit questions “were focused on assessing compliance rather than focusing on successfully 
reducing or managing risk” and that some reports were submitted “as nothing more than a completed 
checklist with little incorporated information or analysis.” BSEE stated that compliance checklists “limit 
[its] ability to assess degrees of implementation or effectiveness [of SEMS programs].” TRB reviewed 
existing approaches for assessing safety management systems and BSEE’s potential role in the process. 
TRB’s report summarizes several auditor characteristics it observed in US and international regulatory 
agencies from a variety of industries (not all inclusive):359 
• 
Specialized training for auditors to ensure a working knowledge of SMS elements, worker duties, 
and the industry 
• 
A variety of tools for auditors to assess the implementation of SMSs including observing 
operations, verifying procedures, seeking evidence of corrective actions, and in the case of 
offshore, speaking to workers and managers, both at the offshore facilities and shore-based 
offices. 
• 
Scheduled audits, in response to an incident or risk-based. 
• 
Regulatory tools to stop work if companies cannot demonstrate adequate risk management of 
operations. 
Specific to Norway, TRB noted that PSA replaced the term “inspection” with “supervision,” and 
“approvals” with “consents.” PSA believes that the terminology change was significant because it helped 
move audits beyond monitoring exercises and created a climate “in which PSA worked with the industry 
to improve safety instead of acting in the role of a compliance inspector and guarantor of the acceptability 
of company.”360 This sentiment was paralleled both in the US and the UK. In 1990, a Marine Board 
charged with exploring alternative inspection measures for the OCS told MMS that regulatory presence 
on offshore installations conveys a sense of oversight and provides impetus for safety improvement by 
marginal and inexperienced operators. 361 In the UK, following the 2005 Buncefield incident,362 the HSE 
onshore regulator began emphasizing regulatory inspections and audits to ensure companies implement 
safety management systems to reduce risks to ALARP, as described in their safety case reports. 
 
359 Ibid., Chapter 4. 
360 Ibid., pp 60-61. 
361 Committee on Alternatives of Inspection of Outer Continenetal Shelf Operations, Marine Board, Commission on 
Engineering and Technical Systems National Reserach Council. Alternatives for Inspecting Outer Continental 
Shelf Operations [Online]; National Academy Press: Washington, 1990; p 81, 
http://www.nap.edu/download.php?record_id=1517 (accessed March 26, 2016). 
362 On December 11, 2005, a number of explosions occurred at Buncefield Oil Storage Depot in Hemel Hempstead, 
Hertfordshire, England, following the overfilling of a gasoline tank. There were no fatalities, 43 people were 
injured, and nearby commercial and residential property totaled $1.5 billion; Buncefield Major Incident 
Investigation Board. The Buncefield Incident, 11 December 2005; Volume 1; UK HSE: 2008; 
http://www.hse.gov.uk/comah/buncefield/miib-final-volume1.pdf (accessed March 26, 2016). 

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According to HSE, roughly 70 percent of an HSE onshore inspector’s time is now spent inspecting.363 In 
conversations with CSB investigators, HSE management and inspectors emphasized the importance of 
inspections and the “creative tension” created during dialogue between the inspector and the duty 
holder.364 
4.2.1 
Challenges of Relying on Third-Party Audits in the GoM 
Third-party SEMS program audits are required by BSEE, 365 after which BSEE receives an audit report 
that then becomes its main source of information on the effectiveness of a SEMS program.366 Third-party 
audit service providers (ASP) can play an important role in achieving safety, but solely relying on them 
creates a gap between BSEE and the companies it regulates. For instance, BSEE does not accredit the 
ASPs itself, instead relying on BSEE-approved Accreditation Bodies (AB).367 Currently, the only AB 
BSEE has approved is the Center for Offshore Safety (COS), an industry sponsored organization.368 
Therefore if BSEE does not independently determine the quality and effectiveness of the third-party 
audits, the process could potentially devolve into ineffective industry self-regulation. 
As part of the auditing process, the ASP must provide BSEE with an Audit Plan 30 days prior to 
conducting the audit, whereby BSEE reserves the right to modify the list of facilities identified for 
audit.369 The auditor must provide BSEE a report of the audit findings and conclusions, including 
identified deficiencies, within 30 days of completion, and the company audited must provide a plan for 
addressing the deficiencies, the corrective actions that will be taken, and the person responsible for 
each.370 BSEE has the legal authority to verify that the corrective actions have been taken.371 
Yet, this approach has limitations and raises conflict-of-interest concerns. If BSEE does not conduct any 
of its own SEMS audits, it risks losing opportunities to: directly interact with the companies it regulates, 
gain familiarity with those offshore facilities and well operations/technologies/equipment, and dialogue 
directly with the workforce. These lost opportunities inhibit the development of that “creative tension” 
between the regulator and those regulated. Additionally, the manner in which third parties conduct BSEE 
audits is potentially problematic for several reasons: 
 
363 Learned during CSB staff visit to the UK in March 2014. 
364 The UK HSE uses third-party audits to augment its own work, not supplant it. See Chapter 5.5, Volume 2. 
365 30 C.F.R. § 250.1920(a) (2016). Prior to April 2013, BSEE also permitted “designated and qualified” personnel 
to complete the audits; 30 C.F.R. § 250.1920(a) (2012). With the introduction of SEMS II, BSEE removed this 
definition. Oil and Gas and Sulphur Operations in the Outer Continental Shelf—Revisions to Safety and 
Environmental Management Systems, 78 Fed. Reg. 20423 (Final Rule, April 5, 2013) (to be codified at 30 C.F.R. 
Part 250). 
366 BSEE communication to the CSB in 2016. 
367 30 C.F.R. § 250.1921 and 1922. 
368 BSEE can recognize other accreditation bodies, but currently has only named COS an AB; BSEE. Information to 
Lessees (ITL) and Operators of Federal Oil and Gas Leases on the Outer Continental Shelf (OCS); June 18, 
2015; http://www.bsee.gov/uploadedFiles/Information%20To%20Lessees-%20Accreditation%20Body.pdf 
(accessed March 26, 2016). 
369 30 C.F.R. § 250.1920(b)(4) 
370 30 C.F.R. § 250.1920(c) and (d) 
371 30 C.F.R. § 250.1920(e) 

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• 
No law requires third-party auditors to behave independently and consistently, especially without 
regulator review of, and routine calibration with, all accredited auditors. 
• 
SEMS does not require BSEE to send staff to attend audits, even though it does; thus, if these 
audit practices do not evolve, BSEE’s own staff will not develop its own expertise. 
• 
Problems with consistency are surfacing among accredited service providers. At a June 2015 
Ocean Energy Safety Institute forum a presenter from DNV GL, an ASP, indicated inconsistent 
practices existed amongst ASPs.372 For instance, DNV GL will not conduct an audit of a non-
operating asset, but it has been informed that other ASPs are.373 
On December 7, 2015, BSEE announced the launch of a pilot Risk-Based Inspection Program.374 Industry 
data and BSEE reportable incident data indicates that four out of five incidents occur at just 20% of 
offshore facilities.375 Consequently, BSEE wanted to efficiently and effectively manage the limited 
inspection and auditing resources of the agency by focusing on facilities that present a higher safety 
risk.376 Such a program may prove to bridge the gap created by solely relying on third party audits, but as 
the pilot program is in its infancy, no conclusions concerning its effectiveness can be made at this time. 
Furthermore, lack of an accident does not guarantee no accidents in the future. Thus, BSEE must examine 
and follow-up on third-party audit results to proactively identify emerging safety issues at specific 
facilities/companies as well as industry-wide trends. 
4.3 
Regulatory Use of Safety Performance Indicator Data 
One essential mechanism by which a regulator can check the pulse of industry and target major accident 
event risk is through comprehensive review of safety performance indicators. As the CSB learned in its 
July 2012 public hearing on Safety Performance Indicators377 and then emphasized in its Chevron Interim 
and Regulatory Reports,378 leading process safety indicators help drive continual safety improvements in 
 
372 Ilango, C. Where has SEMS Been, an Auditors Perspective, Taking SEMS to the Next Level Ensuring 
Continuous Improvement of Safety and Environmental Management Systems, Houston, TX, July 2015, 2015; 
http://oesi.tamu.edu/events/forum/ (accessed March 16, 2016). 
373 DNV also noted that initially, audit consistency was poor. While COS criteria has better defined audit 
expectations, new issues are emerging, for example “the minimum duration of audits allowing for wide variability 
in the depth of the audits – compliance vs. system audit;” Ibid. 
374 Bureau of Safety and Environmental Enforcement to Launch Pilot Risk-Based Inspection Program for Offshore 
Facilities. December 7, 2015. http://www.bsee.gov/BSEE-Newsroom/Press-Releases/2015/Bureau-of-Safety-and-
Environmental-Enforcement-to-Launch-Pilot-Risk-Based-Inspection-Program-for-Offshore-Facilities/ (accessed 
December 21, 2015). 
375 BSEE. BSEE Blog: Risk-Based Inspection Pilot Program: What’s in your facility?, 
http://www.bsee.gov/safety/bsee-blog/ (accessed March 16, 2016). 
376 Ibid. 
377 Described more fully in Section 3.4.1 of Volume 3; CSB Public Hearing: Safety Performance Indicators, 
Houston, TX, July 23-24, 2012; http://www.csb.gov/events/csb-public-hearing-safety-performance-indicators/ 
(accessed October 7, 2015). This information, including the agenda, the verbatim transcript of the proceedings, 
working papers submitted, slide presentations, and other materials from the proceedings, is available as part of the 
CSB’s record pertaining to the Macondo investigation. 
378 USCSB, 2012 and 2014. Regulatory and Intermim Reports: Chevron Richmond Refinery Pipe Rupture and Fire, 
Richmond, CA, August 6, 2012, Report No. 2012-03-I-CA, 
http://www.csb.gov/assets/1/19/Chevron_Regulatory_Report_11102014_FINAL_-_post.pdf and 

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preventing major accidents, as long as regulators effectively use these indicators to focus inspections, 
audits, and investigations, and to share lessons learned throughout industry. Similarly, industry must 
simultaneously focus attention on indicators. Yet the indicators and other data BSEE collects do not 
adequately focus on process safety matters, especially relating to leading indicators. As such, BSEE’s 
efforts are still insufficient in guiding industry concerning safety trends and deficiencies. 
In contrast with the company-specific indicators tracked by individual companies, regulators can track 
more broad-based indicators, which they can then use to: 
• 
Diagnose systemic problems in the safety management systems across industry; 
• 
Develop and maintain industry benchmarks; 
• 
Assess the effectiveness of their own regulations and policies to prevent major accidents; 
• 
Measure the regulator’s own performance with respect to core duties such as audits, inspection 
activities, and related regulatory initiatives; and 
• 
Analyze macro trends to focus on big-picture issues and initiatives to improve industry safety 
performance. 
4.3.1 
Roadblocks to Regulatory Improvements in Data Collection and 
Analysis 
Following the Piper Alpha incident in the UK in 1988, the US regulator received technical advice for 
improvement to its regulatory standards and practices. For example, a National Research Council 
Committee recommended that “MMS improve its collection, analysis, and use of safety-related data 
regarding offshore operations,” since “improvements in safety performance derive in large part from past 
lessons.”379 The Committee explained: 
The committee recommends that MMS place its primary emphasis on detection of potential 
accident-producing situations—particularly those involving human factors, operational 
procedures, and modifications of equipment and facilities—rather than scattered instances of non-
compliance with hardware specifications. … An important step is to extend the definition of a 
“mishap” to include near misses, i.e., drilling or production disruptions, and events that prompt 
the operator or an MMS inspector to shut down operations and require investigation of these less 
serious occurrences as well as events (accidents). 380 
Thirteen years after the Committee’s study, in 2003, MMS proposed federal rulemaking to enhance 
reporting regulations.381 At the time, MMS only required death or serious injury, fires, explosions, and 
blowouts be reported orally,382 but the rule proposed expanding requirements to include written reports of 
 
http://www.csb.gov/assets/1/19/Chevron_Interim_Report_Final_2013-04-17.pdf, April 2013 and October 2015 
(accessed October 7, 2015). 
379 Committee on Alternatives of Inspection of Outer Continenetal Shelf Operations, Marine Board, Commission on 
Engineering and technical Systms National Reserach Council. Alternatives for Inspecting Outer Continental Shelf 
Operations [Online]; National Academy Press: Washington, 1990; p 31, 
http://www.nap.edu/download.php?record_id=1517 (accessed March 26, 2016). 
380 Ibid., p 831. 
381 Oil and Gas and Sulphur Operations in the Outer Continental Shelf—Incident Reporting Rule, 68 Fed. Reg. 
40585 (Proposed Rule, July 8, 2003). 
382 30 C.F.R. § 250.191 (2003) 

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the incidents listed in Table 4-1. MMS’s intent was to capture those “near misses” that did not result in 
the accidents already being reported by industry. In proposing the rule, MMS noted that results from the 
voluntary SEMP program indicated there could be a marked increase in the number of incidents 
reported.383 Tracking this data, MMS hoped to develop regulatory initiatives, conduct risk-based 
inspections, and work with industry to develop new standards, among other approaches, to address safety 
issues on the OCS. Additionally, MMS requested industry comments on whether it should collect the total 
number of hours worked by employees and the kind of information it should collect about contractors.384 
Without such data, MMS observed it could not normalize raw injury data and calculate injury rates or 
account for injury and illness cases that involved contractors, which MMS indicated made up 80% of the 
offshore workforce.385 
Table 4-1. Abridged list of reportable incidents to BSEE from § 250.188. 
1. All fatalities. 
2. All injuries that require the evacuation of the injured person(s) from the facility to shore or to 
another offshore facility. 
3. All losses of well control. 
4. All fires and explosions. 
5. All reportable releases of hydrogen sulfide (H2S) gas. 
6. All collisions that result in property or equipment damage greater than $25,000. 
7. All incidents involving structural damage to an OCS facility. 
8. All incidents involving crane or personnel/material handling operations. 
9. All incidents that damage or disable safety systems or equipment (including firefighting 
systems). 
10. Any injuries that result in one or more days away from work or one or more days on restricted 
work or job transfer; 
11. All gas releases that initiate equipment or process shutdown; 
12. All incidents that require operations personnel on the facility to muster for evacuation for 
reasons not related to weather or drills; 
13. All other incidents, not listed in paragraph (a) of this section, resulting in property or 
equipment damage greater than $25,000. 
 
 
383 MMS reported “injuries that required evacuation from the facility, and injuries that resulted in days away from 
work, restricted work, or job transfer) could require up to 291 additional injury reports.” Incidents due to 
hydrogen sulfide and gas releases, collisions, damage, and cranes could result in an increase of 60 incidents 
reported per year; Oil and Gas and Sulphur Operations in the Outer Continental Shelf—Incident Reporting Rule, 
68 Fed. Reg. 40585 (Proposed Rule, July 8, 2003). 
384 Oil and Gas and Sulphur Operations in the Outer Continental Shelf—Incident Reporting Rule, 68 Fed. Reg. 
40585 (Proposed Rule, July 8, 2003). 
385 Ibid. 

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Numerous objections to the proposed rule were raised by industry groups, including the Offshore 
Operator’s Committee (OOC) 386 the IADC, and the National Ocean Industries Association. 387 They 
objected because the proposed rule was overly prescriptive and burdensome and too complex.388 One 
example the OOC gave was the proposed requirement to report “any unintentional release of gas at an 
OCS facility that could, without corrective action, raise hydrocarbon or other gas concentrations to the 
lower flammable (explosive) limit.”389 OOC explained that it would be difficult to determine when an 
unintentional release could have raised gas concentrations to explosive limits. OOC noted that gas 
detectors in some areas could result in system shut-ins, but reporting such incidents would be burdensome 
to MMS and the industry and “serve no purpose in improving safety on platforms.” MMS disagreed: 
platforms have numerous sources of ignition, and there are many small fires reported on these 
facilities. Small fires have the potential to become major incidents that could cause serious 
injuries or deaths. By collecting the information on gas releases that result in equipment or 
process shut-in, we can track the trends, and possibly decrease the number of gas releases.390 
With gas releases, MMS began to address the National Research Council’s recommendation to extend the 
definition of “mishap” to include near-misses, but the CSB notes that due to the qualifiers on the 
definition of a gas release,391 the data has limitations as to its usefulness. A review of previous years’ data 
demonstrates that most of the companies operating in the OSC will likely not experience a qualifying gas 
release in a given year. In fact, there were never more than 17 gas releases that met the reporting criteria 
per year during any of the last six years. If BSEE had previously mandated that operators were to report 
all hydrocarbon releases, they would have reported more incidents, which could assist the regulator in at 
least three different functions: 
• 
To alert the regulator about incidents or near-miss events that could warrant an immediate 
regulator response such as an urgent offshore visit to investigate; 
• 
To help the regulator gather industrywide data at a macro scale for assessing overall industry 
performance and trends, and to help direct the regulator’s priorities; and 
• 
To benchmark and compare individual operators and companies. 
At its most basic level, such data could alert the regulator to potentially dangerous trends that require 
initiating regulatory action or other industry improvements. This oversight role accords with the same 
industry methodology accepted and currently in use by other offshore regimes. 
 
386 The Offshore Operator’s Committee’s comments to the proposed regulation were particularly strong citing 
“serious flaws” in “several areas” of the proposed regulation. Offshore Operator’s Committee, letter referencing 
RIN 1010-AC57; NPRM Incident Reporting FR 68-40585, November 24, 2003, p 2. 
387 According to the group’s website, “The National Ocean Industries Association (NOIA), founded in 1972 with 33 
members, represents all facets of the domestic offshore energy and related industries. Today, over 300 member 
companies are dedicated to the safe development of offshore energy for the continued growth and security of the 
United States.” http://www.noia.org/about/ (accessed March 26, 2016). 
388 Oil and Gas and Sulphur Operations in the Outer Continental Shelf—Incident Reporting Requirements, 71 Fed. 
Reg. 19640 (Final Rule, April 17, 2006). 
389 Ibid. 
390 Ibid. 
391 A ‘gas release’ must result in either equipment or process shutdown; 30 C.F.R § 250.188(b)(2). 

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BSEE could also track other types of near misses. An examination of loss of well control events 
illustrates this point. The 2006 reporting rule essentially defined loss of well control as the point when 
formation (or other fluids) leaves the well.392 Analysis of the data collected from MMS’s incident 
reporting rules since 2006 reveals that reported loss of well control events are infrequent. In fact they 
amounted to no more than eight events per year in the Gulf of Mexico over the last several years. 393 This 
is not a surprise as MMS predicted “a very minor increase in the number of loss of well control incidents 
(blowouts) reported due to this rule.”394 
A loss of well control is different from a well kick, which is the unintended flow of formation fluids into 
the wellbore. While not all well kicks evolve into serious events, Macondo demonstrates that unmanaged 
ones can lead to dangerous ‘gas-in-riser’ events and blowouts.395 Therefore, variables related to kicks can 
produce trends to evaluate industry performance and create strategies to promote safety on the OCS. 
Ultimately, while the US offshore regulator recorded fewer than eight loss of well control events since 
2006, internal Transocean kick data demonstrates that from 2006 to 2009 Transocean observed an 
increase in kicks in North America from 7 to 19, 396 and this is only from a single driller. By focusing on 
the more severe, but less frequent, loss of well control events, the utility of the metric is limited and does 
not lend itself to trending. Researchers funded by BSEE recently proposed key performance indicators 
related to kicks that “require special consideration and consistent tracking.” 397 These include kick 
response time, kick volume, and the frequency of kicks during various drilling activities. In fact, the 
suggested key performance indicators echo kick indicators suggested by Transocean itself.398 
MMS adopted the final reporting rule in 2006,399 and required incident data (Table 4-1) for both operators 
and contractors.400 The 2006 rule did not ultimately require that the total number of employee hours 
 
392 The rule defined loss of well control as an (i) Uncontrolled flow of formation or other fluids. The flow may be to 
an exposed formation (an underground blowout) or at the surface (a surface blowout); (ii) Flow through a diverter; 
or (iii) Uncontrolled flow resulting from a failure of surface equipment or procedures; Oil and Gas and Sulphur 
Operations in the Outer Continental Shelf—Incident Reporting Requirements, 71 Fed. Reg. 19640 (Final Rule, 
April 17, 2006). 
393 BSEE, OCS Incidents/Spills by Category: 1996-2007, http://www.bsee.gov/Inspection-and-
Enforcement/Accidents-and-Incidents/Spills-Archive-less-than/ and OCS Incidents/Spills by Category: CY 2008 - 
2015 ytd, http://www.bsee.gov/Inspection-and-Enforcement/Accidents-and-Incidents/Listing-and-Status-of-
Accident-Investigations/ (accessed March 26, 2016). 
394 Oil and Gas and Sulphur Operations in the Outer Continental Shelf—Incident Reporting Requirements, 71 Fed. 
Reg. 19640 (Final Rule, April 17, 2006). 
395 See Volume 3, Section 1.3. 
396 Volume 3, Section 3.5.1.1.; Internal Company Document, Transocean. Well Control Events & Statistics 2005 to 
2009, TRN-INV-00760094, http://www.mdl2179trialdocs.com/releases/release201303211200016/TREX-
05649.pdf (accessed June 24, 2015). 
397 Fraser, D.; Lindley, R.; Moore, D.; Staak, V. Early Kick Detection Methods and Technologies, SPE Annual 
Technical Conference and Exhibition, Amsterdam, The Netherlands, October 27-29, 2014; SPE-170756-MS. 
398 See Volume 3, Section 3.5.1.1. 
399 Oil and Gas and Sulphur Operations in the Outer Continental Shelf—Incident Reporting Requirements, 71 Fed. 
Reg. 19640 (Final Rule, April 17, 2006). 
400 30 C.F.R. § 250.189-190 (2016). 

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worked to be reported, despite MMS’s initial indication that it would like them.401 This did not change 
until 2011 when BSEE made a voluntary MMS Form-131 mandatory (renamed “BSEE-0131”402).403 This 
form collects personal safety statistics and infrequent lagging metrics listed in, such as recordable illness 
injuries, Days Away, Restrictions and Transfers (DART), injury/illness rate, notices of EPA 
noncompliance, and the total number of oil spills suffered over a specified period of time in a 
standardized written format not previously required.404 The report format and reportable incidents mirrors 
that found in Appendix E of API 75. BSEE-0131 remains substantively similar to its predecessor. 
At best, the regulator and the company reporting the information can use data from BSEE-0131 and Table 
4-1 only to react to the circumstances giving rise to the incidents reported after the fact. It is good that a 
regulator would be responsive to data of any type, including personal safety matters and lagging 
indicators, but BSEE cannot effectively use the data on this form to shape audits or inspections because of 
its inherent limitations. It also is less useful in identifying precursor events that present warning signs, 
which could allow for the company’s immediate responsive action, or even the regulator’s own urgent 
attention. The result of this narrow data-gathering process is a small data set that does not lend itself to 
trending or other potentially helpful analysis because only serious incidents are reported. 
BSEE continues to miss a critical opportunity to use performance safety indicators more proactively 
because it collects mostly infrequent lagging indicator data and does not use the data to inform its own 
performance in terms of special areas of focus, audit and inspection activities, and other targeted 
activities. 
4.3.2 
Inadequate Use of Safety Performance Indicators 
One essential mechanism by which a regulator can check the pulse of industry and target major accident 
event risk is through comprehensive review of safety performance indicators. Neither MMS before 
Macondo, nor BSEE currently, had (has) direct indicator data that provides information on the 
effectiveness of the barriers and safety management systems meant to keep offshore operations safe (e.g., 
maintenance issues, audit results, failures of equipment during routine testing).405 These are the Tier 3 and 
Tier 4 indicators described in Volume 3.406 Instead, the original desire of MSS to use indicator data to 
influence safety strategies on the OCS remain limited by the type of data collected. 
 
401 Oil and Gas and Sulphur Operations in the Outer Continental Shelf—Incident Reporting Rule, 68 Fed. Reg. 
40585 (Proposed Rule, July 8, 2003). 
402 BSEE. BSEE-0131, Performance Measures Data; 
http://www.bsee.gov/uploadedFiles/BSEE/About_BSEE/Doing_Business_with_BSEE/OCS_Forms_New/Form%
200131%20for%20exp%202018.pdf (accessed March 29, 2016). 
403 Reorganization of Title 30: Bureaus of Safety and Environmental Encorcement and Ocean Energy Management, 
76 Fed. Reg. 64432 (Final Rule, October 18, 2011). 
404 See BSEE Form 131, http://www.bsee.gov/About-BSEE/Procurement-Business-Opportunities/BSEE-OCS-
Operation-Forms/BSEE-OCS-Operation-Forms.aspx (accessed January 21, 2016). 
405 See Volume 3, Chapter 3, particularly Sections 3.4.1-3.4.2. 
406 Section 3.4.2, as defined by API 754, Tier 3 indicators include challenges to a safety systems, which results when 
exceeding defined process limits and a safety system is initiated to bring the system back to an accepted safe state 
(e.g., the activation of a shutdown system or a pressure relief device); Tier 4 indicators include performance of 

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As the CSB has emphasized,407 leading process safety indicators help drive continual safety 
improvements in the area of major accident prevention, as long as regulators effectively utilize these 
indicators to focus inspections, audits, and investigations, and to share lessons learned throughout 
industry. 
 
 
To date, BSEE does not have SEMS performance indicators, though it has reported sponsoring efforts to 
quantify such indicators.408 As such, BSEE’s efforts are insufficient in guiding industry with respect to 
safety trends and deficiencies. In the meantime, indirect, lagging measures of a SEMS program could be 
gleaned from the reporting of the incidents listed in Table 4-1; presumably, an effective SEMS program 
would reduce the occurrence of fatalities, injuries, loss of well control, etc. On May 5, 2015, BSEE 
 
barriers and management system components, such as management of change (MOC) compliance, inspections, or 
timely training schedules. 
407 Volume 3, Chapter 3. 
CSB Public Hearing: Safety Performance Indicators, Houston, TX, July 23-24, 2012; 
http://www.csb.gov/events/csb-public-hearing-safety-performance-indicators/ (accessed October 7, 2015). 
(including the agenda, the verbatim transcript of the proceedings, working papers submitted, and PowerPoint 
presentations and other materials from the proceedings are all available and included as part of the CSB’s record 
pertaining to the Macondo investigation).; 
407 USCSB, 2012 and 2014. Regulatory and Intermim Reports: Chevron Richmond Refinery Pipe Rupture and Fire, 
Richmond, CA, August 6, 2012, Report No. 2012-03-I-CA, 
http://www.csb.gov/assets/1/19/Chevron_Regulatory_Report_11102014_FINAL_-_post.pdf and 
http://www.csb.gov/assets/1/19/Chevron_Interim_Report_Final_2013-04-17.pdf, April 2013 and October 2015 
(accessed October 7, 2015). 
408 For example, there is an April 2016 SPE/BSEE Summit: Assessing the Processes, Tools, and Value of Sharing & 
Learning from Offshore E&P Safety Related Data, http://www.spe.org/events/smsr/2016/ (accesses April 1, 
2015). 
Global Indicator Data Sharing 
The International Regulators’ Forum (IRF) on Global Offshore Safety Performance 
Measurement Project was created to establish a framework based on a common set of 
indicators definitions and criteria. The IRF annually complies indicators, such as 
numbers of fatalities and injuries, losses of well control, mass hydrocarbon releases, 
collisions, and fires, for each IRF member country and makes them publicly available 
on the IRF website.† The focus is on higher consequence lagging and personal safety 
data, and the IRF is still working on reporting consistency among members. But, as 
this global sharing network continues to improve, it should allow for even greater 
improved opportunities to uncover emerging safety risks. 
 † IRF, IRF Performance Measurement Project, 
http://www.irfoffshoresafety.com/country/performance/scope.aspx 
 (accessed December 21, 2015). 

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announced its intention to initiate a new program called SafeOCS.409 In addition to providing a voluntary 
and anonymous reporting channel for offshore workers, BSEE designed this program as a way to collect 
leading and lagging safety indicator data that could made publicly available and inform prevention and 
mitigation efforts.410 Although a positive step, BSEE currently has limited SafeOCS reports.411 Several 
companies have verbally indicated they will participate in the near future,412 but BSEE will need more 
time to determine the success of the voluntary program. Anonymous reporting and key performance 
indicators though are two different systems, and while they complement one another, they do not replace 
one another. 
BSEE publishes incident statistics and summaries of the data received on incidents listed in Table 4-1 on 
its website,413 and could use this data to drive industry initiatives as observed in other oil-producing 
jurisdictions around the world. In the UK, the offshore regulator HSE uses focused Key Programme 
Initiatives (Key Programmes or KPs), which are multi-year efforts to collect data and assess trends to 
drive improvement in offshore areas of significant concern, such as hydrocarbon releases, deck and 
drilling operations, asset integrity, and aging facilities.414 The Key Programmes are not limited to data 
collection and trend assessments, but are detailed and coordinated programs covering other regulatory 
activities including inspecting sites, raising awareness, and facilitating the development of standards, all 
requiring some level of data gathering activity. 
HSE launched these Key Programmes to formulate and share good practices with industry.415 During the 
first Key Programme (KP1), between 2000 and 2004, among other notable regulatory activities, the 
regulator worked with industry and unions to collect relevant data to reduce reportable hydrocarbon 
releases by 50 percent in four years. For KP1, gas releases were categorized as minor, significant, or 
major using release size, rate, and duration criteria developed with industry.416 While the number of major 
releases was reduced by 33%, the regulator noted a 50% increase in the number or reported minor 
releases.417 This was attributed to an increased awareness of the need to report minor releases, and 
demonstrates that regulator participation can lead to more robust data collection. 
 
409 BSEE. BSEE Director Brian Salerno Announces Key Efforts to Reduce Risk Offshore, 
http://www.bsee.gov/BSEE-Newsroom/Press-Releases/2015/BSEE-Director-Brian-Salerno-Announces-Key-
Efforts-to-Reduce-Risk-Offshore/ (accessed March 26, 2016). 
410 BSEE, 2014 Annual Report; p 9, 
http://www.bsee.gov/uploadedFiles/BSEE/BSEE_Newsroom/Publications_Library/Annual_Report/BSEE%20201
4%20Annual%20Report.pdf (accessed December 21, 2015). 
411 BSEE communication to the CSB. 
412 Ibid. 
413 BSEE. Incident Statistics and Summaries, http://www.bsee.gov/Inspection-and-Enforcement/Accidents-and-
Incidents/Other-Incidents/ (accessed March 29, 2016). 
414 UK HSE, Key Programme final reports, http://www.hse.gov.uk/offshore/programmereports.htm (accessed March 
26, 2016). 
415 UK HSE. OSD hydrocarbon release reduction campaign, Report on the hydrocarbon release incident 
investigation project -1/4/2000 to 31/3/2001; 2001; p 1. 
http://www.hse.gov.uk/research/otopdf/2001/oto01055.pdf (accessed March 26, 2016). 
416 Ibid., p 2. 
417 Ibid., p iii. 

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In 2010, the UK HSE initiated KP4 to address the issue of aging equipment offshore and the operation of 
installations beyond their design life.418 That same year, the HSE published Managing Aging Plant: A 
Summary Guide,419 to aid industry in preventing major accidents. The report provides an overview of 
plant and equipment failure due to age related mechanisms, their management, and suggested leading and 
lagging indicators to monitor them. It also presents analysis on how aging plant equipment may be a 
factor in loss of containment incidents. According to Jake Malloy, Regional Organizer of the National 
Union of Rail, Maritime and Transport Workers Union (UK), “it is our firm belief that the most 
influential and effective schemes using indicators to measure improvements and major accident 
prevention are those initiatives generated by our regulator, the Health and Safety Executive.”420 
The Norwegian offshore regulator, PSA, runs a multi-year program to track indicators data. The program, 
Trends in Risk Level in the Petroleum Activity (RNNP), focuses on identifying trends in leading and 
lagging indicators such as near-miss incidents, barrier performance, chemical exposure, well control 
incidents, and maintenance management.421 PSA chose these indicators for its trends program because it 
noticed industry was relying on indicators such as lost-time incidents, which alone are unable to present a 
full picture of safety.422 PSA states, “RNNP has become an important management tool for all 
participants in the petroleum sector. Its findings are valuable for our planning of supervision activities and 
development of the regulations.”423 Furthermore, PSA indicates, “with solid facts on the table, employers 
and unions can drop time consuming discussions [on whether the industry is “safe”] and concentrate 
instead on achieving improvement.”424 
If BSEE were to take the lead in establishing a robust system of safety performance indicators that 
includes information on barriers and safety management systems and use that information to target audits, 
inspections, enhanced rule-making, and other regulatory activity aimed at major offshore accident 
prevention, the risk of incidents like Macondo can be reduced. Ultimately, six years after the catastrophe, 
regulatory requirements are still needed for developing and implementing safety performance indicators 
to prevent major accidents. 
 
 
418 UK HSE. Key Programme 4 (KP4): Ageing and life extension, http://www.hse.gov.uk/offshore/ageing/kp4-
report.pdf (accessed December 8, 2014). 
419 UK HSE. Managing Ageing Plant, A Summary Guide, http://www.hse.gov.uk/research/rrpdf/rr823-summary-
guide.pdf (accessed November, 1, 2013). 
420 CSB Public Hearing: Safety Performance Indicators, Houston, TX, July 23-24, 2012; testimony of Jake Malloy, 
Safety Performance Indicators—The Workforce Perspective, p 139, 
http://www.csb.gov/assets/1/19/CSB_20Public_20Hearing.pdf (accessed October 7, 2015). 
421 Numerous reports available, PSA. Trends in risk level, http://www.psa.no/risk-level/category876.html (accessed 
March 26, 2016). 
422 PSA. Summary Report 2012—Norwegian Continental Shelf, Trends in Risk Level in the Petroleum Activity, p 1, 
http://www.ptil.no/getfile.php/PDF/RNNP_2012/Trends%20in%20risk%20level_2012.pdf (accessed March 26, 
2016). 
423 PSA, Trends in risk level in the petroleum activity (RNNP), http://www.psa.no/about-rnnp/category911.html 
(accessed March 26, 2016). 
424 See video at http://www.psa.no/about-rnnp/category911.html (accessed March 26, 2016). 

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4.4 Transparency of Offshore Safety 
Public disclosure of offshore safety information encourages accountability, risk-reduction, effective 
enforcement, and sharing of lessons learned. Public disclosure of this type of information could also 
promote trust among workers, operators, and the regulator, and even help to provide a mechanism for 
members of the public to satisfy themselves about the safety of offshore operations and the adequacy of 
regulatory action. Historically, the US offshore safety regulator did not promote safety improvements 
through transparency.425 That may now be starting to change, however, as BSEE initiated an annual 
report, which is publicly available and published on the agency’s website. The report contains industry 
safety performance indicator data, acknowledges operational and organizational BSEE deficiencies, and 
provides strategic goals and objectives for the agency. The report notes that BSEE is working to create a 
Data Stewardship team, with the primary responsibility of improving the overall quality, management, 
and use of offshore data.426 In addition, BSEE issues safety alerts and publishes them on its website to 
help share lessons learned from investigations of incidents.427 BSEE also makes available on its website a 
listing of “Incident Statistics and Summaries” which includes data covering a variety of topics back to 
2008, with additional incident archive data back to 1996. 428 BSEE notes in its 2014 annual report that 
lessons learned from investigations in the Pacific Region triggered two safety alerts in 2014.429 Currently, 
 
425 Steffy, L. Dearth of data leaves Gulf safety record in the dark. Fuel Fix from the Houston Chronicle, December 
7, 2012, http://fuelfix.com/blog/2012/12/07/steffy-dearth-of-data-leaves-gulf-safety-record-in-the-dark/ (accessed 
March 26, 2016). 
426 BSEE. 2014 Annual Report. May 5, 2015; p 12. 
http://www.bsee.gov/uploadedFiles/BSEE/BSEE_Newsroom/Publications_Library/Annual_Report/BSEE%20201
4%20Annual%20Report.pdf (accessed December 21, 2015). 
427 BSEE. Current Safety Alerts, http://www.bsee.gov/Regulations-and-Guidance/Safety-Alerts/Safety-Alerts/ 
(accessed March 26, 2016). 
428 BSEE. Incident Statistics and Summaries, http://www.bsee.gov/Inspection-and-Enforcement/Accidents-and-
Incidents/Listing-and-Status-of-Accident-Investigations/ (accessed March 26, 2016). 
429 BSEE. 2014 Annual Report. May 5, 2015; p 17. 
http://www.bsee.gov/uploadedFiles/BSEE/BSEE_Newsroom/Publications_Library/Annual_Report/BSEE%20201
4%20Annual%20Report.pdf (accessed December 21, 2015). 
Safety performance indicators (SPIs) should be used as an aid to communication. 
They are not the entire message. . . . All stakeholders need to remember SPIs do not 
measure the level of safety. SPIs indicate how the measures to achieve safe operation 
are performing. SPIs offer a chance to improve transparency and communication 
between operators and inspectors. It is up to senior management to decide whether 
they wish to implement these tools. Government policy makers need to realize the 
potential and provide suitable training and resources to allow inspectors to be 
competent partners in the use of SPIs and thus enable the necessary dialogue to take 
place. † 
 † Jennings, K.; Hailwood, M. OECD Guidance on Safety Performance Indicators - An International 
Approach to Assessing the Success of Industry, Public Authorities and Communities in Managing Major 
Accident Hazards; IChem E Loss Prevention Bulletin 2010, 212, p 10. 

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operators and drilling contractors are not required to provide public access to safety-related 
documentation or statistics. Some enforcement data and statistics on lagging indicators are available 
publicly,430 but insufficient dialogue about these issues remains among industry, the regulator, and the 
public. 
4.4.1 
Regulatory Approaches to Transparency 
Transparency can be achieved through publishing enforcement actions, safety case documentation, and 
annual reports of safety statistics. In Norway, the PSA disseminates offshore process safety data through 
its website, forums, and archives.431 The PSA website provides statistics, an annual Risk Assessment 
Report, and information on recent major accidents in Norwegian waters.432 PSA also uses numerous 
indicators to uncover trends and determine the overall process safety health offshore, which are published 
in an annual Risk Assessment Report. The agency then bases it priorities for the year on PSA data 
analysis and establishes forums in which it participates with industry and workers to engage in open 
discussion on how to improve safety.433 The PSA asserts this approach is necessary to reduce risks.434 
Although the UK does not make public an operator’s safety case documentation,435 it does publish 
guidance for compliance with ALARP, enforcement decision processes for the safety case, and 
aggregation of process safety indicators.436 The Seveso III Directive, enacted in UK law in June 2015 
through Control of Major Accident Hazards (COMAH) regulations, requires active public disclosure of 
major accident risks at any operation.437 The UK HSE provides public access to its enforcement decisions 
regarding safety case violations.438 The UK HSE also publishes its safety case assessment process online 
 
430 30 C.F.R. § 250.1929; and BSEE. Incidents of Noncompliance, http://www.bsee.gov/Inspection-and-
Enforcement/Enforcement-Programs/Incidents-of-Non-Compliance/. 
431 PSA. Transparency: Open and honest, http://www.ptil.no/news/transparency-open-and-honest-article7627-
878.html (accessed March 26, 2016); CSB Public Hearing: Regulatory Approaces to Offshore Oil and Gas Safety, 
Washington, DC, December 15, 2010; see, for example, pp 70-71. 
http://www.csb.gov/assets/1/19/Transcript_of_Public_Meeting_12_15_2010.pdf (accessed March 7, 2015). 
432 See PSA. Safety Stats and signals, http://www.ptil.no/?lang=en_US; Report following the audit of Exxon 
Mobil’s use of quantitative risk analyses, http://www.ptil.no/news/report-following-the-audit-of-exxon-mobil-s-
use-of-quantitative-risk-analyses-article6019-878.html; and Notification of orders to BP after investigation of 
Valhall PC fire, http://www.ptil.no/risk-management/notification-of-orders-to-bp-after-investigation-of-valhall-
pcp-fire-article8233-1029.html; and Risk Level, http://www.ptil.no/rnnp/category876.html (accessed March 7, 
2015).. 
433 CSB Public Hearing: Regulatory Approaces to Offshore Oil and Gas Safety, Washington, DC, December 15, 
2010; see, for example, pp 70-71. 
http://www.csb.gov/assets/1/19/Transcript_of_Public_Meeting_12_15_2010.pdf (accessed March 7, 2015). 
434 PSA. Transparency: Open and honest, http://www.ptil.no/news/transparency-open-and-honest-article7627-
878.html (accessed March 26, 2016); 
435 The CSB Investigations staff learned in its March 2014 trip to the UK that before 9/11, the UK HSE made safety 
case report summary documents publicly available; however, for security reasons, the UK ceased to make these 
documents available under a Secretary of State order. 
436 Learned during CSB staff visit to the UK in March 2014. 
437 UK HSE, Public Information, http://www.hse.gov.uk/seveso/public.htm (accessed March 26, 2016). 
438 UK HSE, HSE Public Register of Enforcement Notices, http://www.hse.gov.uk/notices/ (accessed March 26, 
2016). 

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along with annual offshore safety statistics, safety alerts, and reports of key intervention programmes.439 
According to Ian Travers, the UK HSE Head of Chemical Industries Strategy Unit, Hazardous 
Installations Directorate, transparency revolutionized the offshore industry. For example, Travers 
explained that although UK HSE operates a hotline for confidential whistle-blowing, it is “rarely used” 
and tends to be used only in situations where companies operating offshore lack a good safety culture, 
which Travers attributed to an atmosphere of “transparency” in the North Sea.440 Travers also explained 
that the role of the regulator in terms of its relationship with industry, along with the unique place 
indicators play in that relationship: 
The essential role of the regulator for major hazards is to provide public assurance that those 
whose activities give rise to risks to people and the environment are adequately controlling those 
risks. Industry in turn should ensure that there is transparency and openness in how well those 
risks are being controlled. KPIs are an essential ingredient in that dialogue between the regulator 
and the regulated in, for example, setting and agreeing on programmes for operators’ major 
hazard improvement and the regulator’s intervention strategies and plans.441 
Travers’s testimony was corroborated by Bob Lauder, former Health and Safety Policy Manager of Oil & 
Gas UK, the industry trade association that serves as “the voice of the offshore industry” in the North Sea. 
Lauder testified this openness did not always exist: 
There was significant reluctance on the part of lots of companies … in the UK to go as public as 
we’ve now gone with our statistics. … So, what we do now is … we get this information directly 
back from the Health and Safety Executive from their managed database. And, on a quarterly 
basis, we put it on our website so it’s publicly available. … And, on a quarterly basis, we—I 
hate to use the phraseology, but it has been called naming and shaming …. You can see that we 
named the duty-holder, we named the installation, and then we give some indication of the 
nature and scale of the release. So, that's out there. It’s [visible to] anybody who wants to see it. 
A point I might want to make here is you’ll see some very familiar names on there. … So, I 
think that really was a big deal for us to [become] as transparent as we now are with that and it 
didn’t happen overnight and it didn't happen without some resistance.442 
Mr. Lauder left unstated, however, that industry players in the UK are now working in a more mature 
regulatory environment that values disclosure of this type of safety information. Rather than viewing it as 
harmful to their respective competitive positions or to their standing within the industry, the operators 
came together through their trade association and formalized an arrangement to provide for openness 
about hydrocarbon releases. This intentional strategy is an important source of potential learning for the 
 
439 UK HSE, Key Programme final reports, http://www.hse.gov.uk/offshore/programmereports.htm (accessed March 
26, 2016); 
440 CSB Public Hearing: Safety Performance Indicators, Houston, TX, July 23-24, 2012; testimony of Ian Travers, 
Overview of Leading Indicator and Usage, p 157, http://www.csb.gov/assets/1/19/CSB_20Public_20Hearing.pdf 
(accessed October 7, 2015). 
441 CSB Public Hearing: Safety Performance Indicators, Houston, TX, July 23-24, 2012; written testimony of Ian 
Travers, The Implementation of Effective Key Performance Indicators for Major Hazard Enterprises, p 3, 
http://www.csb.gov/UserFiles/file/Travers%20%28HSE%29%20-%20Testimony%20-%20printed.pdf (accessed 
October 7, 2015). 
442 CSB Public Hearing: Safety Performance Indicators, Houston, TX, July 23-24, 2012; testimony of Bob Lauder, 
Major Hazard (Asset Integrity) Key Performance Indicators in Use in the UK Offshore Oil and Gas Industry, pp 
175-176, http://www.csb.gov/assets/1/19/CSB_20Public_20Hearing.pdf (accessed October 7, 2015). 

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entire industry, and it can actually help to promote public and political trust and confidence in offshore 
operators. 
In his testimony to the CSB at the agency’s performance safety indicators event on July 24, 2012, Jake 
Malloy, Regional Organizer of the National Union of Rail, Maritime and Transport Workers Union (UK), 
further corroborated the transparency of the UK’s offshore regulator, explaining the benefits of open, 
public and transparent safety information that he has observed over the course of his career in the UK 
offshore industry since the HSE initiated “Key Programmes.” Malloy explained that Key Programme 1 
(KP1), “Reducing Hydrocarbon Releases,” was accompanied by publicly available results and other 
information relative to actions by North Sea operators and the regulator. Malloy noted that “since KP1 
was launched the industry has been pro-active in setting its own targets for leak reduction.” In addition, 
industry publishes details of the leaks, including volumes, locations, and operators as part of their own 
initiative to reduce leaks still further through sharing and learnings.”443 Malloy attributed this improved 
performance to the general availability of the information explaining, “KP1 was launched publicly, 
meaning workers and moreover the press had the ability to report and monitor performance. In short, it is 
transparent and subject to public and governmental scrutiny.”444 
Some of Australia’s safety regulators provide the public with summaries of safety case documentation 
produced by the duty holders.445 NOPSEMA, Australia’s federal safety regulator, offers public access to a 
host of safety-related information, including monthly newsletters containing data on inspections and 
incidents, aggregated safety statistics, drilling guidance, and brochures on process safety.446 For instance, 
NOPSEMA publishes guidance on elements of a safety case report, including hazard identification with 
assistance on selecting a hazard identification technique.447 
The Nuclear Regulatory Commission provides a positive example of using transparency to drive safety 
improvement. Testifying before the CSB, John Lubinski, Director of the Division of Inspection and 
Regional Support, Office of Nuclear Reactor Regulation, explained: 
Yes, we believe [public reporting] does [influence safety] as far as impacting the performance. 
Under the old system … [w]hen we had findings or we had people that were outside of a key 
performance indicator, we could take enforcement action issuing citations, issuing monetary civil 
 
443 CSB Public Hearing: Safety Performance Indicators, Houston, TX, July 23-24, 2012; testimony of Jake Malloy, 
Safety Performance Indicators, The Workforce Perspective; 2012; 
http://www.csb.gov/UserFiles/file/Molloy%20%28RMT%29%20Testimony.pdf (accessed March 26, 2016). 
444 Ibid. 
445 See WorkSafe Victoria, Guidance Note: Overview of the Safety Case regime for a Major Hazard Facility; p 14. 
“The local community must be provided with certain information, including a summary of the Safety Case,” 
http://www.worksafe.vic.gov.au/__data/assets/pdf_file/0015/12381/50712_WS_3_Safety_Case_OV_5HR.pdf, 
(accessed March 26, 2016). Examples Safety Case Summaries can be found at: 
http://www.exxonmobil.com/Australia-English/PA/Files/publication_safetycase_altonaref.pdf; and 
http://www.exxonmobil.com/Australia-English/PA/Files/publication_Longford_Safety_Case_2013.pdf (accessed 
March 26, 2016). 
446 IRF. Member Country Profile—Australia, http://www.irfoffshoresafety.com/country/Australia.aspx (accessed 
March 26, 2016). 
447 NOPSEMA. Guidance Note: Hazard Identification; N- 04300-GN0107, Rev. 5; December, 2012; 
http://www.nopsema.gov.au/assets/Guidance-notes/N-04300-GN0107-Hazard-Identification.pdf (accessed March 
26, 2016). 

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penalties. What we found is this is actually a more risk informed and also a benefit from the 
standpoint of moving forward to increasing performance. Number one is it focuses the licensee's 
effort and the NRC inspection efforts in the correct area. But, number two is because all of the 
information is made public, not just when a bad event occurs at a plant, all the information. It 
requires all the licensees to look at it and say “how are we being publicized on the NRC 
website?” The performance indicators are not a report card; however, they are information. And 
we think that information being available, not only does it have the licensees more accountable 
for safety but it also has us as the regulator more accountable. When the public is looking at this 
website and saying how can you have a plant that has white performance indicators, yellow 
findings and you're still letting them operate, what is your technical basis for doing that? So it 
holds us accountable in being able to describe what the safety performance is of that plant. So, 
that's where we see the benefits to making all this information available to the public. The final 
[reason] is just the fact that from our standpoint we believe in open and transparent regulation and 
we want the people in the community to understand what the hazards are associated with the plant 
and what the safety implications are of any activities that are occurring. 448 
In addition to boosting public goodwill for a high-hazard industry, transparency provides a tangible safety 
benefit: deterrence. Public scrutiny can be a significant deterrent against bad practices in offshore 
operations through publications, discussions, and political pressure.449 The Environmental Protection 
Agency (EPA) enforces anti-pollution laws and makes them public. Former EPA Administrator William 
Reilly recently noted, “I see no reason not to publicize these violations,” Reilly explained during his 
investigation of the Macondo incident for a Presidential Commission.450 
Further elaborating on the desirability of publicly available safety information, Lois Epstein, Engineer 
and Arctic Program Director for The Wilderness Society, explained, “the public interest community 
strongly supports making operator-specific data publicly available with shielding of company names kept 
to a minimum and only with a very strong justification. Sunshine451 improves the quality and increases 
the learning opportunities associated with accident prevention data. Potential litigation should not be a 
reason to withhold data, as litigation will occur regardless.”452 
Complete transparency is not necessary. For instance, the UK does not require that an operation’s safety 
case be made publicly available.453 In contrast, certain states and territories of Australia make safety case 
 
448 CSB Public Hearing: Safety Performance Indicators, Houston, TX, July 23-24, 2012; testimony of John W. 
Lubinski, Questions & Answers by CSB Board, Staff and Public, p 94, 
http://www.csb.gov/assets/1/19/CSB_20Public_20Hearing.pdf (accessed October 7, 2015). 
449 CSB Public Hearing: Safety Performance Indicators, Houston, TX, July 23-24, 2012; testimony of Jake Malloy, 
Safety Performance Indicators, The Workforce Perspective, pp 139-40, 
http://www.csb.gov/assets/1/19/CSB_20Public_20Hearing.pdf (accessed October 7, 2015). 
450 Dlouhy, J. After spill, offshore enforcement remains murky. Fuel Fix from the Houston Chronicle, December 12, 
2012, http://fuelfix.com/blog/2012/12/12/after-spill-offshore-enforcement-remains-murky / (accessed March 26, 
2016). 
451 “Sunshine” refers to openness or transparency in matters of public importance, relating back to a famous quote 
from former US Supreme Court Justice Brandeis. "Publicity is justly commended as a remedy for social and 
industrial diseases. Sunlight is said to be the best of disinfectants; electric light the most efficient policeman." 
452 CSB Public Hearing: Safety Performance Indicators, Houston, TX, July 23-24, 2012; testimony of Lois N. 
Epstein, Safety Performance Indicators, p 152, http://www.csb.gov/assets/1/19/CSB_20Public_20Hearing.pdf 
(accessed October 7, 2015). 
453 CSB UK trip notes, March 6 & 7, 2014. 

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summaries publicly available. There are also limits on disclosing some information due to commercial 
sensitivity (e.g., trade secrets, confidential business information) that provides a competitive advantage in 
a challenging sector of the economy, as well as physical security issues, among other concerns. 
Companies must strike a balance between disclosing all relevant information and protecting information 
not appropriate for disclosure. Yet global experience suggests that an effective offshore regulatory regime 
will seek opportunities to use transparency to drive continual safety improvements. 
 
 

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5.0 Insufficient and Inadequate Staff for Appropriate 
Oversight 
BSEE’s ability to regulate safety is contingent upon adequate numbers of staff with multifaceted 
competencies in not only technical disciplines, but human and organizational factors, communication and 
interpersonal skills such as negotiation, persuasion and advocacy, and process safety, among others. 
These skill sets provide inspectors with the tools to conduct effective preventive audits and inspections, 
and to regularly engage with duty holders. To date, the staffing changes in BSEE have not fully met these 
requirements. Congress has not appropriated sufficient funding on an ongoing and consistent basis for 
BSEE to meet such staffing needs, and along with these constraints, continuing conflicts between political 
and legislative priorities are structural impediments to BSEE’s ability to fulfill its difficult mission. The 
Department of Interior has confronted this issue recently, noting that continuing resolutions and a 
sequester of 5 percent in fiscal years 2013 and 2014 significantly impacted the Department’s agencies, 
requiring a hiring freeze and reducing funding for staffing and oil and gas activities.454 
To ensure that companies are managing major hazard risks and employing the best available standards 
and technology effectively, the regulator must hire and retain knowledgeable and skilled staff who can 
critically assess company safety practices. The CSB discusses in the Chevron Regulatory Report the 
importance of having a well-funded, technically competent regulator that has the ability to conduct 
proactive, preventive inspections. To operate a robust performance-based regulatory regime in which the 
regulator directly oversees and evaluates total safety performance of the industry, BSEE’s enhanced 
recruiting, hiring, and retention efforts must continue and must include senior specialists with experience 
in areas such as petroleum engineering, process safety, human factors, and organizational performance. 
5.1 
Models for Building a Competent Regulator 
The UK and other US safety regulators, particularly in the nuclear sector, use effective methods for 
recruiting, training, and retaining highly proficient staff that could help inform BSEE efforts. 
5.1.1 
 UK Offshore Safety Directive Regulator 
The UK Offshore Safety Directive Regulator (OSDR) is part of the UK Health and Safety Executive 
(HSE). It provides detailed guidance for companies, inspectors, and the public on how the regulator 
assesses companies’ plans to reduce major accident hazards.455 It published pamphlets and handbooks, 
geared toward duty holders, on offshore topics ranging from corrosion to human factors to process 
integrity. The “Assessment Principles for Offshore Safety Cases” is an agreed framework for inspector 
conduct during the offshore assessment process.456 Those principles emerge from the definitive, 300+ 
 
454 US Covernment Accountability Office. Report to Congressional Requesters. Oil and Gas: Interior Has Begun to 
Address Hiring and Retention Challenges but Needs to Do More; US Government Accountability Office: January, 
2014; p 77; http://www.gao.gov/assets/670/661025.pdf (accessed March 26, 2016). 
455 UK HSE, Guidance, http://www.hse.gov.uk/offshore/safetycases.htm (accessed March 26, 2016). 
456 UK HSE. Assessment Principles for Offshore Safety Cases (APOSC); March, 2006; 
http://www.hse.gov.uk/offshore/aposc190306.pdf (accessed March 26, 2016). 

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page inspector’s manual, Guidance for the Topic Assessment of the Major Accident Hazard Aspects of 
Safety Cases (GASCET).457 
The OSDR can hire competent personnel to develop guidance and perform safety case reviews because it 
is authorized to pay offshore staff higher specialist salaries. Offshore assessor work involves time away 
from family in uncomfortable conditions. To incentivize it, most mid-level OSDR technical staff were 
paid between £67,213 and £77,499 in 2012, the equivalent of $109,241 to $125,959.458 Specialist staff in 
Aberdeen receive a location enhancement on top of these “standard” pay scales that enables HSE to 
recruit to that location and compete with the oil industry. The enhancement is currently £10,000 
(approximately $15,600). These salaries are significantly higher than their onshore inspector counterparts, 
whose mid-level salaries ranged from £37,303 to £46,937 in 2012, the equivalent of $60,628 to $76,286. 
Former UK Offshore regulatory staff reported that the OSDR looks for new recruits with good 
communication skills in addition to relevant education, licensure, and experience because their job 
requires getting companies to aspire to make safety improvements that the companies may not want to 
do.459 Once on board, new recruits directly from industry undertake a rigorous regulator training program 
during their first two years, including significant on-the-job training.460 They are required to take a series 
of courses and related assessments, and they may be fired if they do not pass the assessments.461 At the 
same time, new inspectors receive training by working alongside more experienced inspectors on safety 
case procedures, technical assessment procedures (such as electrical and mechanical safety), audit and 
regulatory intervention activities.462 For inspectors who have a primary interface role with offshore 
companies, OSDR aims to rotate them to different companies every two to three years to avoid the 
inspectors becoming too comfortable with their surroundings.463 One message that UK offshore industry 
and regulatory staff repeated to CSB investigators is that the industry believes having proficient 
regulatory staff adds significant value to their business.464 Professional proficiency, as well as technical 
and risk management acumen, allow regulatory staff the wherewithal to pushback against industry claims, 
should that be necessary.465 This competence is also essential for companies’ confidence in the accuracy 
of the regulatory staff’s advice, inspections, and citations. 
 
457 HSE. (http://webcommunities.hse.gov.uk/connect.ti/gascet/view?objectId=62036 (accessed March 2, 2016). 
458 In contrast, BSEE pays mid-level petroleum engineers somewhere between $62,000 and $84,000 per year. 
https://www.usajobs.gov/GetJob/ViewDetails/341573400 (accessed March 26, 2016). 
459 Whewell, I. Former Director, UK HSE Offshore Division, and Wilkinson, P. principal “architect” for the 
development of Australia’s National Offshore Petroleum Safety Authority, (NOPSA), Personal communication, 
July 11, 2011. 
460 Ibid. 
461 Ibid. 
462 Ibid. 
463 Ibid. 
464 Ibid. 
465 Wilkinson, P. Australia Department of Industry, Tourism and Resources, Presentation to the National Research 
Centre for Occupational Health and Safety; May 15, 2002. 

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5.1.2 
US Government Incentives to Build Competent Staff 
The federal government has used extensive resources to retain the best available talent to focus on health 
and safety oversight of US commercial and defense nuclear facilities.466 Many nonsupervisory technical 
staff at the US Nuclear Regulatory Commission (NRC)467 and the Defense Nuclear Facilities Safety 
Board (DNFSB) are paid at the top of the General Schedule.468 Virtually all technical staff at the DNFSB 
hold technical master’s degrees, and approximately 25 percent hold doctorates.469 
The US government has a unique category of non-executive positions, Scientific or Professional,470 which 
involve high-level research and development in the physical, biological, medical, or engineering sciences, 
or a closely related field.471 These positions are classified above the highest general schedule pay level. 
These special salary authorizations contribute to the ability of technical agencies to compete with private 
industry in recruiting and retaining highly proficient staff. 
The NRC’s extensive training programs also help attract and retain competent technical staff. For new 
inspection staff, the NRC requires a series of courses, assessments, and simulations, all of which take 
approximately two years to complete.472 Inspectors must have a bachelor’s degree in engineering or a 
degree in a relevant scientific field and Professional Engineer certification.473 The agency operates a 
technical training center in Chattanooga, Tennessee, with various control room simulators that mirror 
licensees’ facilities. NRC staff are expected to understand how this equipment operates so that they can 
conduct audits and investigations.474 Before they are deemed qualified to inspect, inspector candidates 
must be recommended by the NRC inspector qualification board and certified by the regional 
administrator or division director.475 
 
466 FY 2013 Budget Request to the Congress; Defense Nuclear Factilities Safety Board: 2012; pp 1-3; 
http://www.dnfsb.gov/sites/default/files/About/Budget%20Requests/2013/FY%202013_CONG%20BUDGET_FI
NAL.PDF (accessed March 26, 2016). 
467 Presentation by NRC Executive Director Bill Borchardt to CSB, January 2011. 
468 $123,758 to $155,500 per year in 2012 in Washington, DC.; OPM. Pay & Leave, Salaries & Wages, 
https://www.opm.gov/oca/12tables/html/dcb.asp (accessed March 26, 2016). 
469 FY 2013 Budget Request to the Congress; Defense Nuclear Factilities Safety Board: 2012; p 7; 
http://www.dnfsb.gov/sites/default/files/About/Budget%20Requests/2013/FY%202013_CONG%20BUDGET_FI
NAL.PDF (accessed March 26, 2016). 
470 See, e.g., 5 C.F.R. § 319.103. This category covers non-executive positions classified above the GS-15 level. See 
https://www.opm.gov/policy-data-oversight/senior-executive-service/scientific-senior-level-positions/ (accessed 
January 7, 2016). 
471 OPM. Senior Executive Service, http://www.opm.gov/ses/recruitment/stpositions.asp (accessed March 26, 2016). 
472 NRC. NRC Inspection Manual, Qualification Program for Operating Reactor Programs (Ch. 1245); 2011; p 4; 
http://pbadupws.nrc.gov/docs/ML1110/ML11105A153.pdf (accessed March 26, 2016). 
473 NRC Reactor Inspector Job Posting No. R-I/DRS-2013-0001. 
474 See, e.g., IAEA. NS Tutorial, http://www.iaea.org/ns/tutorials/regcontrol/regbody/reg2124.htm (accessed March 
26, 2016). 
475 NRC. NRC Inspection Manual, Qualification Program for Operating Reactor Programs (Ch. 1245); 2011; ; 
http://pbadupws.nrc.gov/docs/ML1110/ML11105A153.pdf (accessed March 26, 2016). 

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5.2 
Disproportionate Regulator Resources for Gulf of Mexico 
Offshore Activity 
Historically, the number of MMS employees working on permitting, permit modifications, and 
inspections did not increase proportionally to the increase in production—in fact, those staff numbers 
decreased by 36 percent between 1983 and 2010.476 Meanwhile, MMS found that OCS leasing 
experienced a 200 percent increase, and oil production increased by 185 percent between 1982 and 
2007.477 In addition, an internal MMS report issued a few months after the Macondo incident put it more 
bluntly: the Gulf of Mexico district offices did not have enough engineers to conduct permit reviews, and 
they had only about 55 inspectors for 3,000 facilities.478 
Following these reports and associated recommendations to increase hiring,479 BSEE stated that it 
intended to triple the number of inspectors in the Gulf of Mexico,480 but hiring efforts initially focused on 
recent graduates, who lacked relevant professional experience. Former-Director [of BOEMRE] Bromwich 
began the hiring effort by visiting several universities with petroleum engineering departments to entice 
new graduates to work for the offshore regulator.481 The agency also sought recently retired petroleum 
engineers to work temporarily until permanent hires could join, but several potential applicants lost 
interest when they saw that the starting salaries were significantly lower than what industry offered for 
similar work.482 In March 2012, former BSEE Director Watson stated to Congress that the agency 
increased inspector hiring by 50 percent since April 2010, but engineers hiring had only increased by ten 
percent.483 Watson later explained that BSEE intended to hire another 200 people to conduct permit and 
spill response plan reviews, inspect offshore facilities, and ensure environmental compliance.484 He added 
 
476 Lewis, W.; Kendall, M.; Suh, R. U.S. Department of the Interior Outer Continental Shelf Safety Oversight Board 
Report to the Secretary of the Interior Ken Salazar ; US Department of the Interior: September 1, 2010; p 6 and 
13; http://www.noia.org/wp-content/uploads/2015/12/DOI-OCS-Safety-Oversight-Board-Report.pdf (accessed 
March 26, 2016). 
477 Ibid., p 13. 
478 The report highlighted a 71% increase in permit modification applications in the New Orleans District in 2009; 
Ibid., p 6. 
479 See, e.g., National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling. Deepwater: The 
Gulf Oil Disaster and the Future of Offshore Drilling - Report to the President; Janurary, 2011; p 256, 
Recommendation A5. 
480 Budget Justifications and Performance Information Fiscal Year 2013; US Department of the Interior: 2012; p 30; 
http://www.bsee.gov/About-BSEE/Budget/FY2013BudgetJustification/ (accessed March 26, 2016). 
481 Snow, N. BOEMRE seeks recently retired petroleum engineers, Bromwich says. Oil & Gas Journal, April 22, 
2011, http://www.ogj.com/articles/2011/04/boemre-seeks-recently.html (accessed March 26, 2016). 
482 Ibid. 
483 Watson, J. Statement of James Watson, Director Bureau of Safety and Environmental Enforcement United States 
Department of the Interior Committee on Appropriations Subcommittee on Interior, Environment and Related 
Agencies House of Representatives; March 7, 2012; 
http://www.bsee.gov/uploadedFiles/BSEE/Newsroom/Congressional_Testimony/Congressional%20Testimony%2
020120307.pdf (accessed March 26, 2013). 
484 Dittrick, P. OTC: BSEE director calls for industry to promote safety culture. Oil & Gas Journal, May 1, 2012, 
http://www.ogj.com/articles/2012/05/otc-bsee-director-calls-for-industry-to-promote-safety-culture.html 
(accessed March 26, 2016). 

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there was “still a considerable amount of positions yet to be filled, including additional inspectors, 
engineers, regulatory specialists, environmental specialists, and other critical disciplines.”485 
BSEE stated in its 2014 annual report that the Bureau hired 88 personnel in 2014, a net gain of 9 full-
time-equivalent employees, and 56 of the 88 newly hired personnel were from critical scientific, 
inspection, and engineering fields. 486 BSEE noted in the report that it will maintain its long-term focus on 
growing its workforce by attracting the top talent available to fill the agency’s ranks.487 In April 2015, 
BSEE reported that the number of inspectors in the Gulf of Mexico OCS region increased from 55 in 
April 2010 to 92 (as of April 20, 2015).488 Additionally, the number of engineers in the BSEE workforce 
increased from 106 in October 2011 to 129 in April 2015.489 Despite the challenges, BSEE made 
progress. 
In 2015, BSEE received authorization to offer new recruits a salary incentive of 25% above base pay.490 
The purpose of this authorization was to help BSEE better compete with the private sector, which is not 
bound by the federal government’s salary and retention rules;491 however, the authorization brought entry-
level starting salaries up to only approximately $40,000, nowhere near equivalent to private industry 
offerings for equivalent jobs, which average $80,849.492 Also, this authorization focused exclusively on 
geophysicists, geologists and petroleum engineering positions, but did not incentivize hiring specialists 
with other critical professional backgrounds such as environmental science, human factors, psychology, 
toxicology, or other complementary engineering disciplines relevant to offshore exploration, drilling and 
production. More remains to be done to help BSEE attract and retain the staff needed to execute its 
important mission. 
 
485 Watson, J. Statement of James Watson, Director Bureau of Safety and Environmental Enforcement United States 
Department of the Interior Committee on Appropriations Subcommittee on Interior, Environment and Related 
Agencies House of Representatives; March 7, 2012; 
http://www.bsee.gov/uploadedFiles/BSEE/Newsroom/Congressional_Testimony/Congressional%20Testimony%2
020120307.pdf (accessed March 26, 2013). 
486 BSEE. 2014 Annual Report. May 5, 2015; p 13. 
http://www.bsee.gov/uploadedFiles/BSEE/BSEE_Newsroom/Publications_Library/Annual_Report/BSEE%20201
4%20Annual%20Report.pdf (accessed December 21, 2015). 
487 Ibid., p 3. 
488 BSEE and BOEM. Reforms since the Deepwater Horizon Tragedy; 
http://www.eenews.net/assets/2015/04/16/document_gw_03.pdf (accessed March 26, 2016). 
489 Ibid. 
490 BSEE. Understanding the Special Salary Rate for Certain Geologist, Geophysicist, and Petroleum Engineer 
Positions in the BSEE and BOEM Gulf of Mexico Region; p 1. 
http://www.boem.gov/uploadedFiles/BOEM/About_BOEM/Jobs/FAQs_BOEM-PayTables.pdf (accessed 
December 21, 2015). 
491 BSEE. Director’s Corner, August 27, 2014, http://www.bsee.gov/safety/directorscorner/ (accessed March 26, 
2015). 
492 BSEE starting salaries for entry level petroleum engineers range from $35,657.00 to $56,859.00. See BSEE 
position announcement for Petroleum Engineer, GS-0881-05/07, 
https://www.usajobs.gov/GetJob/ViewDetails/331348800. Meanwhile, the median salary for a highly recruited 
petroleum engineer in the private sector is $127,970, with average starting salaries around $80,000. See, e.g., 
http://www.reuters.com/article/2012/01/18/us-energy-jobs-idUSTRE80H1GQ20120118; 
http://www.forbes.com/pictures/efkk45eghj/1-petroleum-engineering/ (accessed March 26, 2015). 

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Unfortunately, a 2014 report published by the US Government Accountability Office (GAO) found that 
the actual pay increase provided to support BSEE’s hiring initiative was lower than the 25 percent target 
envisioned because the increase did not include locality pay.493 The report also found that US Department 
of Interior oil and gas departments, such as BSEE and BOEM, continue to struggle hiring and retaining 
 
493 US Covernment Accountability Office. Report to Congressional Requesters. Oil and Gas: Interior Has Begun to 
Address Hiring and Retention Challenges but Needs to Do More; US Government Accountability Office: January, 
2014; pp 22-23; http://www.gao.gov/assets/670/661025.pdf (accessed March 26, 2016). 
The BSEE salary incentive allows for only 25% more than a new hire’s base pay, not 
above the locality pay. Locality pay is a supplemental pay amount added to account 
for regional differences in cost of living, among other factors.a The specific duty 
locations that can offer this special pay rate in the Gulf of Mexico Region are 
Jefferson, Lafayette, Lake Charles, and Houma, Louisiana.b Although the Lake 
Jackson, Texas, District Office is part of the Gulf of Mexico Region, its basic pay plus 
locality pay is higher than the 25 percent allotted by Congress, so employees of that 
office cannot receive this supplemental pay.c 
For instance, a new graduate hired for a petroleum engineer position at general 
schedule Grade 7, step 5 in Jefferson County, Louisiana would receive a base salary 
of $38,511 per year in 2012.d Even without the special authority, he or she would 
automatically receive the locality pay increase for that area, which means the salary 
would actually be $43,964 per year.e BSEE’s incentive authority would permit an 
increase of up to 25 percent of base salary, or $9,628, for a total salary of $48,138 
per year. If the engineer were hired for the Lake Jackson, Texas, District Office, he or 
she would not get the bonus pay, because the locality-adjusted salary of $49,568 per 
yearf is already more than the 25 percent bonus. In effect, this special pay authority is 
able to bring only the other Gulf of Mexico district office salaries for geophysicists, 
geologists, and petroleum engineers closer to their peers’ salaries in Lake Jackson. 
 a OPM. Pay & Leave, Salaries & Wages, http://www.opm.gov/oca/payrates/LPA.asp (accessed March 
 26, 2015). 
 b BSEE. Understanding the Special Salary Rate for Certain Geologist, Geophysicist, and Petroleum 
 Engineer Positions in the BSEE and BOEM Gulf of Mexico Region; p 1. 
 http://www.boem.gov/uploadedFiles/BOEM/About_BOEM/Jobs/FAQs_BOEM-PayTables.pdf 
 (accessed December 21, 2015). 
 c Ibid. 
 d For an example, see BSEE position announcement for Petroleum Engineer, GS-0881-05/07, 
 https://www.usajobs.gov/GetJob/ViewDetails/331348800 http://www.opm.gov/oca/payrates/LPA.asp; 
 OPM. Pay & Leave, Salaries & Wages, http://www.opm.gov/oca/payrates/LPA.asp (accessed March 
 26, 2015). 
 e OPM. Pay & Leave, Salaries & Wages, http://www.opm.gov/oca/payrates/LPA.asp (accessed March 
 26, 2015). 
 f Ibid. 

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key oil and gas oversight positions, including inspectors and petroleum engineers.494 The report attributes 
this difficulty to competitive oil and gas industry salaries and signing bonuses for new hires,495 although 
low oil and natural gas prices in recent quarters started to impact this dynamic. The report also stated that 
these challenges have resulted in less time available for oil and gas oversight activities, including 
inspections. Surveys conducted by GAO showed that the number and thoroughness of inspections were 
“somewhat or greatly reduced because of … vacancies.”496 To compound the problem, the report noted 
that a “high proportion of staff in key oil and gas positions … will be eligible to retire within a few 
years.”497 GAO analysis found that roughly 35 percent of BSEE’s petroleum engineers would be eligible 
to retire by 2017 compared with a government-side average of 27.5 percent for all federal employees 
during the same period.498 
BSEE staff has to cover three geographical regions (Alaska, GoM, and the Pacific), and the GoM alone 
has 2,481 active platforms, with 329 new wells drilled during 2014, and 133 designated operators.499 
Thus, total staffing resources leveraged against the current GoM assets and accompanying drilling and 
production activity, supports the agency’s human capital aspirations “to meet the consistent challenge of 
recruiting and retaining top talent.”500 With its efforts in place, BSEE may be able to take advantage of 
macroeconomic conditions and the current low prices of oil and natural gas which are driving down GoM 
activity and job cuts in the industry.501 It is only a matter of time, however, before the trend reverses, 
therefore BSEE needs to remain ready for these cycles. 
5.3 
The Deficit in Regulator Technical Competency and Credibility 
Earlier reports on the Macondo incident, such as the Presidential Oil Spill Commission Report502 and 
MMS’s own report,503 explained MMS permit reviewers and inspectors historically lack technical 
competency, noting that it struggled to retain competent staff. In the version of the proposed SEMS rule 
 
494 Ibid., p 14. 
495 Ibid., p 19. 
496 Ibid., pp 31-32. 
497 Ibid. p 17. 
498 Ibid., p 17 
499 BSEE. 2014 Annual Report. May 5, 2015; p 8. 
http://www.bsee.gov/uploadedFiles/BSEE/BSEE_Newsroom/Publications_Library/Annual_Report/BSEE%20201
4%20Annual%20Report.pdf (accessed December 21, 2015). 
500 Ibid., p 13. 
501 As of April 1, 2016, the total number of active rigs in the US dropped by 545; Baker Hughes. Rig Count 
Overview & Summary Count, http://phx.corporate-ir.net/phoenix.zhtml?c=79687&p=irol-rigcountsoverview; and 
Reed, S. Stung by Low Oil Prices, BP Will Cut 4,000 Jobs. January 12, 2016, 
http://www.nytimes.com/2016/01/13/business/energy-environment/bp-jobs-oil-prices.html (accessed March 26, 
2016). 
502 See e.g., National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling. Deepwater: The 
Gulf Oil Disaster and the Future of Offshore Drilling - Report to the President; Janurary, 2011; p 74. 
503 Lewis, W.; Kendall, M.; Suh, R. U.S. Department of the Interior Outer Continental Shelf Safety Oversight Board 
Report to the Secretary of the Interior Ken Salazar ; US Department of the Interior: September 1, 2010; pp 13-16; 
http://www.noia.org/wp-content/uploads/2015/12/DOI-OCS-Safety-Oversight-Board-Report.pdf (accessed March 
26, 2016). 

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issued the year before the Macondo incident, MMS noted that most comments received in response to the 
2006 advanced notice of proposed rulemaking expressed that API RP 75 provided excellent guidance, but 
that MMS should not approve SEMS plans, “rather, a third party should determine or certify whether a 
SEMS plan is viable, because MMS may not have the resources and expertise to approve a minimum of 
one plan for each OCS operator.”504 MMS’s inadequate budget and conflicting missions resulted in 
serious management deficiencies and a pervasive culture of deference to the offshore industry for 
guidance on reviews and inspections at the time of the Macondo incident.505 
5.4 
Post-Macondo Efforts to Improve Competency 
BSEE has been working to correct many of the deficiencies in MMS’s recruitment and training programs 
for offshore inspectors and investigators. In March 2010, it issued an internal handbook to improve the 
conduct of internal investigations, but it did not significantly change the basic protocol or management 
responsibilities outlined in an earlier manual.506 More importantly, it did not provide special procedures 
for conducting catastrophic or serious accident investigations, nor did it contain a protocol for evidence 
gathering.507 
To improve training at the agency, BSEE opened its virtual National Offshore Training Center in 2011.508 
According to BSEE, agency staff logged more than 10,000 hours of technical and safety training in FY 
2012,509 and 38 staff attended a two-week boot camp in petroleum geology, drilling engineering, 
production engineering and permitting, with lectures by college professors complemented by hands-on 
exposure to equipment in August 2012.510 Additionally, BSEE Director Salerno recently stated that the 
National Offshore Training Program grew in FY 2014, offering 79 technical courses, an increase of 29 
courses over FY 2013.511 The BSEE 2014 Annual Report noted the agency remains committed to 
employee development and that in calendar year 2014, BSEE offered 105 training courses with 145 
 
504 Safety and Environmental Management Systems for Outer Continental Shelf Oil and Gas Operations, 74 Fed. 
Reg. 28639 (Proposed, June 17, 2009). 
505 Forty-two percent of inspectors interviewed for the Safety Oversight Board’s Report to Secretary Salazar stated 
that “headquarters management does not provide sufficient direction and support;” Lewis, W.; Kendall, M.; Suh, 
R. U.S. Department of the Interior Outer Continental Shelf Safety Oversight Board Report to the Secretary of the 
Interior Ken Salazar ; US Department of the Interior: September 1, 2010; p 15; http://www.noia.org/wp-
content/uploads/2015/12/DOI-OCS-Safety-Oversight-Board-Report.pdf (accessed March 26, 2016). 
506 Ibid., p 22. 
507 Ibid., p 22. 
508 BSEE. BSEE Director Delivers Remarks at the International Regulators Forum 2011 Global Offshore Safety 
Summit Conference. October 4, 2011, http://www.bsee.gov/BSEE-Newsroom/Press-Releases/2011/BSEE-
Director-Delivers-Remarks-at-the-International-Regulators-Forum-2011-Global-Offshore-Safety-Summit-
Conference/ (accessed March 26, 2016). 
509 Dlouhy, J. Tougher offshore scrutiny? Not yet. Fuel Fix from the Houston Chronicle, December 13, 2012, 
http://fuelfix.com/blog/2012/12/13/tougher-offshore-scrutiny-not-yet/ (accessed March 26, 2016). 
510 Ibid. 
511 BSEE. The National Offshore Training Program Shows Continued Growth in 2014: Remains a Priority for 
BSEE Moving Forward. October 28, 2014, http://www.bsee.gov/BSEE-Newsroom/BSEE-News-Briefs/2014/The-
National-Offshore-Training-Program-Shows-Continued-Growth-in-2014/ (accessed December 9, 2014). 

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engineers attending an average of three classes each, and 124 inspectors attending an average of 
approximately four classes each, for a total of 24,486 training hours conducted.512 
Additional insights into BSEE’s intentions to equip its staff with needed skills appear in the 2014 US 
Department of the Interior Office of Inspector General (IG) Report on Offshore Oil and Gas 
Permitting.513 According to the report, BSEE issued an internal policy document in spring 2013, Training 
Requirements for Engineers, which requires all engineers to complete at least 32 hours of approved 
technical training annually and newly hired engineers with fewer than 3 years of oil and gas engineering 
experience to complete BSEE’s engineering boot camp or a similar program.514 The report found that 
BSEE did not “effectively or efficiently” implement that policy, and “did not ensure that all employees 
were aware of the new requirement.”515 As a result, the IG recommended that BSEE “document that all 
permitting employees are aware of IPD [Interim Policy Document] requirements; and monitor and track 
all training to ensure that training requirements, including training hours, are met and that all training is 
recorded.”516 BSEE stated in its response that in April 2014, it finalized a mandatory online training 
awareness module, that by August 29, 2014, “more than 94 percent of BSEE engineers had completed 
their fiscal year 2014 training requirements … [and that] by January 1, 2015, BSEE will ensure that all 
technical courses offered in FY15 will have the training hours listed on the engineer’s transcript, as well 
as the class completion certificate.”517 
In addition to needing technical competency, inspectors must have excellent communication, advocacy, 
and negotiation skills. Hiring and developing regulatory personnel with a full range of skill sets is 
essential to help build a knowledgeable, credible regulator who can recognize deficiencies and engage 
with operators to develop appropriate risk-reduction strategies and persuade them to make changes when 
necessary.518 
5.5 
Insufficient Regulatory Funding Mechanism for Securing Staff 
At the time of the Macondo incident, the US offshore safety regulator did not have sufficient, sustainable 
funding to manage major accident prevention activities. To drive continual improvement in the offshore 
industry and hire and retain sufficient competent staff, the offshore regulator needs adequate and 
sustainable funding. Insufficient funding is often cited as the main reason that MMS was unable to hire 
 
512 BSEE. 2014 Annual Report. May 5, 2015; p 13. 
http://www.bsee.gov/uploadedFiles/BSEE/BSEE_Newsroom/Publications_Library/Annual_Report/BSEE%20201
4%20Annual%20Report.pdf (accessed December 21, 2015). 
513 IG. Offshore Oil and Gas Permitting US Department of the Interior; Report No. CR-EV-BSEE-0006-2013; 
September, 2014; https://www.doioig.gov/sites/doioig.gov/files/CR-EV-BSEE-0006-2013Public.pdf (accessed 
March 26, 2016). 
514 Ibid., p 12. 
515 Ibid., p 1. 
516 Ibid., p 13. 
517 Ibid., p 18. 
518 Wilkinson, P. Creating a New Offshore Petroleum Safety Regulator, Presentation to IADC, Australian Petroleum 
Production & Exploration Association Conference, March 25, 2003; p 6 
http://www.nopsema.gov.au/assets/document/IADC-Annual-General-Meeting.pdf (accessed March 26, 2016). 

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and retain sufficient staff or to adequately oversee deepwater drilling.519 Beginning in 2011, BSEE 
received a sizeable budget increase; however, this funding is by congressional appropriations that may 
(and likely will) vary from year to year. Other offshore regimes ensure the regulator is funded at variable 
but appropriate levels through an industry self-funding or “cost recovery” mechanism. As offshore 
activities increase or decrease, so too does the regulator funding to ensure adequate resources for 
regulatory oversight. 
5.5.1 
Ineffectual Funding Appropriations for Offshore Activity 
As offshore drilling activities increase and expand into deeper and riskier waters, the need for a stronger, 
more effective offshore regulator becomes greater.520 Adequate and sustainable funding is a necessary 
attribute of a competent regulator.521 One way to ensure consistent funding in the appropriation process is 
to provide agencies with an independent funding mechanism.522 An independent funding mechanism 
based on the number and type of active offshore sites renders a straightforward means of ensuring 
sufficient funding. When offshore operations decline, the overall level of risk that the industry assumes 
declines, and so too would the funding. 
As a component of the Department of the Interior, MMS was, and BSEE is, appropriated funding by 
Congress through the General Fund.523 Each year, the agency sends a budget justification and request to 
its appropriators in Congress, whose jurisdiction extends to the rest of the Department of the Interior, the 
Environmental Protection Agency, and several smaller independent agencies.524 The appropriators then 
determine the size of each agency’s annual budget. In March 2012, former BSEE Director Watson 
attributed recent regulatory action and increased hiring of inspectors partly to the budget increase that 
Congress provided.525 By spring 2012, however, Interior officials expressed concern to the Government 
Accountability Office that current and future budgetary constraints may prevent BSEE from fully 
implementing reforms as planned, and that this would handicap BSEE’s ability to manage oil and gas 
 
519 MMS’s inability to keep up with technological advances was made more problematic because its level of funding 
and technical staffing remained static or decreased as industry’s offshore drilling activity increased; National 
Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling. Deepwater: The Gulf Oil Disaster and 
the Future of Offshore Drilling - Report to the President; Janurary, 2011; p 72. 
520 “Interior’s capacity to identify and evaluate risk remains limited, raising questions about the effectiveness with 
which it allocates its oversight resources;” US Government Accountability Office. Oil and Gas Management: 
Interior’s Reorganization Complete, but Challenges Remain in Implementing New Requirements; GAO-12-423; 
July 30, 2012; p 106. http://www.gao.gov/assets/600/593110.pdf (accessed March 26, 2016). 
521 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling, A Competent and Nimble 
Regulator: A New Approach to Risk Assessment and Management, Staff Working Paper No. 21. 
522 Barkow, R. Insulating agencies: avoiding capture through institutional design, Texas Law Review, 89, 2010, p 15, 
44. 146-47. http://papers.ssrn.com/sol3/papers.cfm?abstract_id=1717037. 
523 The General Fund is the US Treasury account that appropriates funds to most federal agencies. 
524 US House of Representative Committee on Appropriations. Interior Subcommittee Jurisdiction, 
http://appropriations.house.gov/about/jurisdiction/interiorenvironment.htm (accessed March 26, 2016). 
525 Watson, J. Statement of James Watson, Director Bureau of Safety and Environmental Enforcement United States 
Department of the Interior Committee on Appropriations Subcommittee on Interior, Environment and Related 
Agencies House of Representatives; March 7, 2012; 
http://www.bsee.gov/uploadedFiles/BSEE/Newsroom/Congressional_Testimony/Congressional%20Testimony%2
020120307.pdf (accessed March 26, 2013). 

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activities in the Gulf of Mexico.526 BSEE officials from the Gulf of Mexico regional office said that they 
could not reliably anticipate budget increases for new hiring and helicopter operating costs.527 This budget 
uncertainty, the officials explained, hindered BSEE’s ability to review permits and conduct inspections.528 
The fiscal year 2012 appropriations bill, passed in March 2012, included a line item for inspection fees of 
$62 million,529 which BSEE officials agreed would cover most of the resources needed to increase 
BSEE’s inspection and permitting capacity for that year.530 In a given year, fees for inspections and 
additional offsetting collections can comprise a portion of BSEE’s operating costs, and they are 
subtracted from the appropriated budget.531 Despite the increase for fiscal year 2012, BSEE officials 
expressed concern that public and congressional attention to oversight of offshore oil and gas drilling may 
diminish over time and that future appropriations may decrease, which would endanger their ability to 
provide effective safety oversight offshore.532 Despite these concerns, BSEE total appropriations have not 
drastically changed since 2012. BSEE total appropriations were $182.4 million in FY 2012,533 $200.8 
million in FY 2013,534 $202.6 million in FY 2014,535 and $204.6 million in FY 2015.536 
The Mine Safety and Health Administration (MSHA) provides a particularly compelling example of how 
appropriations funding can decrease over time. MSHA was formed in 1977, following a slew of mining 
 
526 US Government Accountability Office. Oil and Gas Management: Interior’s Reorganization Complete, but 
Challenges Remain in Implementing New Requirements; GAO-12-423; July 30, 2012; p 101. 
http://www.gao.gov/assets/600/593110.pdf (accessed March 26, 2016). 
527 Ibid., p 101. 
528 Ibid., p 101. 
529 For FY 2015, the BSEE budget requested $204.6 million, which includes $50.4 million from offsetting rental 
collections, $8.2 million from cost recovery fees, and $65.0 million inspection fees; The US Department of the 
Interior. Budget Justifications and Performance Information Fiscal Year 2015: Bureau of Safety and 
Environmental Enforcement; 
http://www.bsee.gov/uploadedFiles/BSEE/About_BSEE/Budget/BSEE%20FY%202015%20Final%20Greenbook
%20File.pdf (accessed March 25, 2015). 
530 US Government Accountability Office. Oil and Gas Management: Interior’s Reorganization Complete, but 
Challenges Remain in Implementing New Requirements; GAO-12-423; July 30, 2012; p 101. 
http://www.gao.gov/assets/600/593110.pdf (accessed March 26, 2016). 
531 For example, in FY2013, BSEE anticipated receiving half of its appropriation from fees and offsetting 
collections. The portion has varied significantly, but it has typically been 25% or less of the total appropriation; 
Budget Justifications and Performance Information Fiscal Year 2013; US Department of the Interior: 2012; p 6, 
Table 1; http://www.bsee.gov/About-BSEE/Budget/FY2013BudgetJustification/ (accessed March 26, 2016). 
532 US Government Accountability Office. Oil and Gas Management: Interior’s Reorganization Complete, but 
Challenges Remain in Implementing New Requirements; GAO-12-423; July 30, 2012; p 101. 
http://www.gao.gov/assets/600/593110.pdf (accessed March 26, 2016). 
533 Budget Justifications and Performance Information Fiscal Year 2013; US Department of the Interior: 2012; p 3; 
http://www.bsee.gov/About-BSEE/Budget/FY2013BudgetJustification/ (accessed March 26, 2016). 
534 Budget Justifications and Performance Information Fiscal Year 2014; US Department of the Interior: 2013; p 3; 
http://www.doi.gov/budget/appropriations/2014/upload/FY2014_BSEE_Greenbook.pdf (accessed March 26, 
2016). 
535 Budget Justifications and Performance Information Fiscal Year 2016; US Department of the Interior: 2015; p 3; 
http://www.doi.gov/budget/appropriations/2016/upload/FY2016_BSEE_Greenbook.pdf (accessed March 26, 
2016). 
536 Ibid., p 3. 

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disasters when Congress and the public realized that the predecessor agency, the Mining Enforcement and 
Safety Administration, had prioritized revenue generation over safety.537 Congress recognized that the 
increased enforcement, legal, and administrative responsibilities for MSHA would require additional 
funds for hiring and support services. Yet it did not create a special mechanism to ensure increased 
funding was available year after year. Instead, Congress expected that MSHA’s funds “can be provided 
through the normal appropriation process as necessary.”538 So in 1979, the year it became a fully 
operational agency, MSHA’s budget peaked at an inflation-adjusted $355 million. By 2007, despite some 
increases in spending, the budget dropped 15 percent.539 The President recommended to Congress that 
MSHA receive a budget of $395 million in 2016.540 The MSHA experience is a powerful reminder that 
the source of an agency’s funding is critical to achieving its mission. 
If it is to avoid repeating MSHA’s good intentions and budget woes, a renewable, sustainable funding 
structure is the best way to ensure that BSEE will have adequate funding to regulate environmental and 
safety activity on the OCS in future years. One argument against an industry-funded regulator is that it 
can become “captured” by the industry that funds it. 541 Conversely, interest groups can exert pressure on 
Congress to control an agency’s activities through its budget, which is just another type of agency 
capture. 542 Yet other federal safety regulators transitioned to industry-funded appropriations precisely to 
avoid the inadequacies and lack of a consistent budget. The Nuclear Regulatory Commission (NRC) was 
reorganized in response to the Three Mile Island incident in 1979. As part of the regulatory overhaul in 
the 1980s and 1990s, the NRC transitioned to a fee-for-service model of regulating. Now, Congress sets 
the agency’s budget, but the NRC is required by law to recover at least 90% of its funding through 
licensing and inspection fees.543 For instance, each year the agency determines and publishes fee amounts 
for new reactor license applications ($17,800), amendments to licenses ($9,600), and inspections ($273 
 
537 Senate Report 95-181 at 3405 (95th Congress), May 16, 1977 
http://arlweb.msha.gov/SOLICITOR/COALACT/leghist2.htm (accessed March 26, 2016). 
538 Ibid. 
539 OMB Watch. Coal Mine Safety Shortchanged by Years of Budget Cuts; OMB Watch: Washington, D.C., 2008; 
http://miningquiz.com/pdf/NEC/US_Coal_Mine_Safety_Shortchanged_by_Years_of_Budget_Cuts.pdf (accessed 
March 26, 2016); meanwhile, mining production had increased significantly since the 1970s. In 1973, the U.S. 
Department of Energy, Energy Information Administration reported 591 million short tons of coal produced in the 
U.S. By 2007, production increased to 1.147 billion short tons; The American Resource, Trends in U.S. Coal 
Mining 1923-2001, http://www.nma.org/pdf/c_trends_mining.pdf. (accessed March 26, 2016). 
540 US Department of Labor. Budget request for FY 2016 outlines priorities for future, 
http://www.msha.gov/fromthedesk/2015/0203.asp (accessed March 26, 2016). 
541 Rachel E. Barkow, Insulating Agencies: Avoiding Capture Through Institutional Design, 89 TEX. L. REV. 15, 42 
n. 146-47 (2010); see also Steven A. Ramirez, Depoliticizing Financial Regulation, 41 WM. & MARY L. REV. 503, 
517 (2000) (noting with surprise that most proposals for offshore regulatory reform have not focused on agency 
financing). 
542 Capture of a federal agency can be defined as strong responsiveness to the desires of the industry or groups being 
regulated. See Rachel E. Barkow, Insulating Agencies: Avoiding Capture Through Institutional Design, 89 TEX. 
L. REV. 15, p 21 (2010); Roger G. Noll, REFORMING REGULATION 99-100 (1971). This document explains that 
capture happens most often when an agency assigns undue weight to the interests of the regulated industries as 
opposed to public interests. 
543 Section 6101 “NRC User Fees and Annual Charges,” Omnibus Budget Reconciliation Act, Pub. L. 103-66. 107 
Stat. 312 (Aug. 10, 1993). 

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per hour).544 This funding mechanism ensures that the agency’s budget adequately covers the regulatory 
activities it performs, but no more. It also simplifies the agency’s budget planning. Because fees directly 
correspond to the actions the NRC performs, the agency does not worry about potential budget shortfalls 
from year to year. BSEE could use this same approach to fund additional hires. Offshore revenue from 
existing drilling and production activities could cover necessary inspection staff. Salaries could then be 
calculated at a rate comparable to a private third-party auditor in the GoM, making the structure more cost 
effective. 
The Pipeline and Hazardous Materials Safety Administration (PHMSA) within the Department of 
Transportation provides another example of an industry-supported federal safety regulator. PHMSA is 
authorized to assess and collect pipeline user fees to fund its pipeline safety activities.545 The pipeline 
safety statute that authorized PHMSA recognized a need for consistent funding for the pipeline 
regulator’s safety oversight. It reflected Congress’s intention that the total costs of administering certain 
federal pipeline safety programs be recovered through charges to the industry.546 PHMSA assesses 
operators of interstate and intrastate natural gas and hazardous liquid transmission pipelines so that the 
operators each pay a share of the total federal pipeline safety program costs in proportion to the number of 
miles of pipeline they have in service at the end of a calendar year.547 
At least one county safety regulator is industry funded. In Contra Costa County, California, the California 
Accidental Release Prevention Program (CalARP) works to prevent catastrophic accidental releases of 
highly toxic or flammable chemicals through its Risk Management Program.548 CalARP engineers review 
industry risk-management program plans, conduct regular audits of sites, and follow up with action items 
to verify compliance.549 The county uses a Certified Unified Program Agency (CUPA) single-fee system, 
which assesses fees to users of all CUPA programs, including CalARP.550 Under this system, a single 
invoice is issued annually to each of the regulated business sites for review and audit services that 
CalARP performs. The collected fees cover salaries and benefits, services and supplies, and overhead 
costs of the CUPA programs.551 
5.5.2 
Industry Funding of International Offshore Regulators 
In contrast to the US offshore regulator’s hybrid fee and congressional appropriation scheme, the North 
Sea and Australian offshore regimes use a cost-recovery model. Since 1999, the UK offshore regulator 
 
544 10 C.F.R. § 170.21. 
545 49 U.S.C. § 60301. 
546 Skinner v. Mid-America Pipeline Co., 490 U.S. 212 (1989). 
547 The 2010 fee assessed on liquid pipelines was offset by $18.8 million, roughly half of the total program allocated, 
from the Oil Spill Liability Trust Fund. Letter from Cynthia Quarterman, Administrator, Pipeline and Hazardous 
Materials Safety Administration, to Senator Daniel K. Inouye, Chairman, Committee on Appropriations (April 5, 
2010). 
548 Contra Costa Health Services, California Accidental Release Prevention (CalARP) Program, 
http://cchealth.org/groups/hazmat/california_accidental_release_prevention.php (accessed March 26, 2016). 
549 Ibid. 
550 http://cchealth.org/groups/hazmat/pdf/cupa/fee-exhibits.pdf. 
551 Contra Costa Health Hazardous Materials. List of Exhibits: To Staff Report on the Determination and 
Apportionment of CUPA Fees; http://cchealth.org/hazmat/pdf/cupa/fee-exhibits.pdf (accessed March 26, 2016). 

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aimed to recover its costs entirely through fees or “charges” to duty holders.552 The UK government 
wanted to ensure appropriate funding for the offshore safety and health program, so it decided the 
industry benefiting from the regulator’s services should support that program. It instituted a per-hour cost 
recovery rate for offshore regulatory activities, such as safety case document review and inspections.553 
Not long after the fee schedule was established, an independent consulting firm authored a report for UK 
HSE examining the potential effects on UK HSE charging industry in this manner. Relying on extensive 
interviews with duty holders, unions, UK HSE staff, document review, and statistical analysis,554 the 
report explained that the majority of the industry respondents interviewed indicated their relationship with 
the regulator had not been “negatively affected”, and they observed no change in regulatory performance 
or in efficiency on the part of the regulator.555 
Although there were some faults in the program in terms of implementation, including some negative 
feedback concerning administrative issues (primarily proper invoicing and difficulties for duty holders 
with anticipated budgeting based on anticipated inspector activity at particular locations),556 cost did not 
turn out to be an issue. Only half of the companies surveyed claimed to have incurred additional costs 
after the UK transitioned to this system, most of which were less than £3,000 (approximately $4,516).557 
The single most important focus in terms of statistical analysis covered by the report was to determine if 
any change in outcomes on health and safety resulted across the population of duty holders.558 The study 
concluded that it was impossible to prove statistically whether the new system affected health and safety 
issues due to the low probability of events, resulting in a relative paucity of data from which to try to 
draw such conclusions.559 The study documented, however, a significant statistical increase in 
documented activity across all regulatory areas by inspectors, including increased issuance of 
improvement notices, prohibition notices, enforcement notices, and prosecutions.560 The total number of 
safety cases presented, and accepted, also increased significantly from 1996-2001, but the percentage of 
safety cases accepted remained relatively constant.561 
 
552 Offshore Oil and Gas in the UK—An Independent Review of the Regulatory Regime; 
https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/48252/3875-offshore-oil-gas-uk-
ind-rev.pdf (accessed March 26, 2016). “The Panel comprised three independent appointees, including myself, 
all with an element of experience and knowledge relevant to the industry, alongside a senior representative of 
each of the three national regulatory bodies with responsibilities for the offshore oil & gas sector, namely: the 
Department of Energy and Climate Change (DECC), the Health and Safety Executive (HSE) and the Maritime 
and Coastguard Agency (MCA);” Ibid., p 1. 
553 Since April 2016, the charge is £266 per inspector hour. http://www.hse.gov.uk/charging/offshore/chgoffsh.htm 
for information on the UK HSE’s charging process (accessed March 26, 2016). 
554 Ibid., § 1.2. 
555 Ibid., e.g., §§ 1.6-1.7, 1.10, 1.16-1.17. 
556 Ibid., § 1.12. 
557 Ibid., § 1.2. 
558 Ibid., § 3.2. 
559 Ibid., § 4.1. 
560 Ibid., § 4.1-4.4. 
561 Ibid., § 4.5-4.6. 

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Australia’s offshore safety regulator, NOPSEMA, is also industry-funded, but in a slightly different way 
than the UK OSDR.562 Much like the UK, NOPSEMA collects funds through safety case levies on the 
offshore industry, which it determines by individual activity levels.563 Rather than hourly rates, levies 
paid by the duty holders are flat fees based on the facility in use.564 This arrangement ensures that each 
operator is well aware of the cost it will incur for regulatory services. Also, the regulator is aware of its 
budget for the year, and it does not cause industry any misgivings over the need for additional inspections 
or audits. In addition, this funding scheme helps regulatory staff build healthy and appropriate 
relationships with industry. 
While BSEE’s most recent budget suggests that it is well-funded, an industry funding mechanism 
guarantees that future funding is always commensurate with industry activity offshore, regardless of 
cyclical movements of oil and gas prices, which can impact the industry, along with changing political 
will in terms of the desirability of an enhanced regulatory presence versus production pressures during 
times of peak energy demand. 
5.6 
The Importance of an Independent Regulator 
To ensure that safety is a priority offshore, the regulator must maintain its independence from the 
economic aspects of offshore drilling activities. Independence is an essential feature of an effective safety 
regulator for major hazard facilities because offshore leasing and revenue generation goals are often in 
conflict with safety and environmental protection. In mining and nuclear safety, Congress recognized that 
an independent safety regulator requires full isolation of the safety mission from the government agency 
tasked with production and revenue management. A regulator must be regarded as independent from 
stakeholder community it regulates while still maintaining appropriate levels of engagement. UK HSE 
communications with the CSB corroborate this, noting that even the perception of a conflict of interest 
with industry in the UK would undermine that regulator’s effectiveness. 
BSEE has taken steps to establish and maintain independence, but evidence suggests it has yet to achieve 
full independence, and the appearance of a conflict of interest may remain. Reorganization of offshore 
safety regulator in the Department of Interior fails to reflect the lessons from previous congressional 
safety reforms and the experiences of other international offshore regulatory regimes. 
5.6.1 
The Minerals Management: The Safety Versus Revenue Conflict 
The Minerals Management Service (MMS) regulated offshore safety from 1982 until its reorganization 
following Macondo in 2010. Through the Secretary of the Interior, MMS used the Outer Continental 
 
562 Australian Petroleum (Submerged Lands) Act Section 138 specifies industry payment of fees to the regulator. 
563 NOPSEMA, Cost Recovery and Levies, http://www.nopsema.gov.au/about/cost-recovery-and-levies/ (accessed 
March 26, 2016). 
564 NOPSEMA. Guideline: Safety Case Levies; December 19, 2013; 
http://www.nopsema.gov.au/assets/Guidelines/N-11000-GL0238-Safety-Case-Levies.pdf (accessed March 26, 
2016); Ibid. 

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Shelf Lands Act to promulgate regulations outlining leasing, revenue collection, environmental 
compliance, and safety requirements for activities on the outer continental shelf (OCS).565 
MMS was created in 1982, during a period of rising inflation and market uncertainty about oil prices.566 
Then-Secretary of the Interior James Watt, expressing concern about offshore revenue, attempted to 
expand offshore federal leasing to promote drilling and oil production. Soon after, an administration blue 
ribbon commission issued a report that exposed ineffective revenue management for energy production 
on federal lands, describing it as “a failure for more than 20 years.”567 
To expand leasing and revenue-promotion goals, Secretary Watt used his discretion under the Outer 
Continental Shelf Lands Act to transition the authority for revenue collection from the Bureau of Land 
Management and for regulatory oversight of offshore activity from the US Geological Survey. These 
functions, previously separated, were now vested in one agency, the new Minerals Management 
Service.568 This created an inherent conflict of interest within one agency because through the fall of 
2010, the MMS would oversee both regulatory and revenue functions for offshore drilling operations on 
the OCS. In many ways, Secretary Watt’s actions were reinforcing the purpose of the Outer Continental 
Shelf Lands Act of “expeditious and orderly development [of OCS resources], subject to environmental 
safeguards, in a manner which is consistent with the maintenance of competition and other national 
needs.”569 Nevertheless, the inherent conflict remained, with the desire for enhanced revenue generation 
potentially pitted against the drive for offshore safety. 
One of Watt’s first actions were to streamline the OCS leasing process and to encourage drilling with an 
ambitious five-year leasing plan for up to five billion acres of the US Outer Continental Shelf.570 Though 
it succeeded in invigorating lease sales, the 1982-1987 five-year plan was dampened by a longstanding 
congressional leasing moratorium,571 which was followed by a series of executive offshore leasing 
moratoria, the first issued by President George H. W. Bush in 1990.572 The western Gulf of Mexico, 
 
565 See 30 C.F.R. Part. 250. 
566 Bernanke, B.; Gertler, M.; Watson, M.; Sims, F.; Friedman, B. Systematic Monetary Policy and the Effects of Oil 
Price Shocks; Brookings Papers on Economic Activity 1997 (1), 1997, pp 91-157; see also International Monetary 
Fund. Global Economy Learns to Absorb Oil Price Hikes, 
http://www.imf.org/external/pubs/ft/survey/so/2012/num052512a.htm (accessed March 26, 2016); Ibid. 
567 Commission on Fiscal Accountability of the Nation's Energy Resources. Fiscal Accountability of the Nation's 
Energy Resources; January, 1982; http://www.onrr.gov/laws_R_D/FRNotices/PDFDocs/linowesrpt1-5.pdf 
(accessed March 26, 2016). 
568 Secretarial Order No. 3071 (Jan. 19, 1982). 
569 43 U.S.C. § 1332(3). 
570 Department of the Interior Notice, Tentative Proposed Final 5-Year OCS Oil and Gas Leasing Program, 47 Fed. 
Reg. 11980 (March 19, 1982). 
571 Over Secretary Watt’s objections, Congress reined in his proposal to offer almost all of the US coastline for 
offshore oil and gas development by 1987. The 1984 Interior appropriations bill banned drilling along most of 
California and Cape Cod. See e.g., Russakoff, D. Watt's Adversaries Would Almost Hate To See Him Resign. The 
Washington Post, October 7, 1983, https://www.washingtonpost.com/archive/politics/1983/10/07/watts-
adversaries-would-almost-hate-to-see-him-resign/f324ed56-31d7-4b59-ae52-2b756cf53e91/ ; and Vann, A. 
Offshore Oil and Gas Development: Legal Framework; RL33404 2-3; Congressional Research Service: 2011. 
572 President George Bush: Statement on Outer Continental Shelf Oil and Gas Development; June 26, 1990; 
http://www.presidency.ucsb.edu/ws/?pid=18638 (accessed March 26, 2016). 

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however, was not part of the leasing and drilling moratoria, and the lease sales and resulting revenue 
became the second largest revenue source for the federal treasury.573 An assessment of the scope of MMS 
activities from that time through the date of the Macondo incident shows the agency’s emphasis on 
maximizing revenue generation as compared to safety and environmental regulation.574 
5.6.2 
BSEE Organizational Structure 
Changes in the Department of the Interior post-Macondo are in line with the September 2010 US 
Department of Interior Outer Continental Shelf Safety Oversight Board’s Report to Secretary of the 
Interior Ken Salazar, which recommends “In future institutional structures implemented through the 
ongoing BOEMRE reorganization, separate the management of environmental functions from the leasing 
and development to ensure that environmental concerns are given appropriate weight and 
consideration.”575 They are also consistent with the Presidential Commission’s recommendation to create 
“an independent agency within the Department of the Interior with enforcement authority to oversee all 
aspects of offshore drilling safety.”576 The recommendation did not resolve the inherent problems with the 
Secretary of Interior’s continued responsibility for simultaneous missions that often conflict. The 
Department of the Interior retains offshore production and revenue collection authority. 
The various bureaus and services composing the Interior Department are not independent agencies; each 
is one part of a strict, hierarchical structure with the Secretary at the top of the pyramid.577 These line 
bureaus operate only on delegated authority because the statutes they implement do not even mention the 
bureau. Instead, final powers of decision remain with the Secretary of the Interior.578 The following 
organizational charts for the Department of the Interior illustrate the similarities between MMS and 
BSEE’s positions within the Department. Both agencies report to the Assistant Secretary for Land and 
Minerals Management, who reports to the Deputy Secretary of the Interior, who reports to the Secretary. 
The Director of BSEE is three levels of authority below the Secretary of the Interior, as was the MMS 
Director. The agency branch responsible for safety follows the same hierarchical structure as before the 
Macondo blowout. 
 
573 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling. Deepwater: The Gulf Oil 
Disaster and the Future of Offshore Drilling - Report to the President; Janurary, 2011; p 63. 
574 House Committee on Energy and Commerce, JIT hearing, July 20, 2010, statement of Rep. Sutton, 
http://www.gpo.gov/fdsys/pkg/CHRG-111hhrg77922/html/CHRG-111hhrg77922.htm. 
575 Lewis, W.; Kendall, M.; Suh, R. U.S. Department of the Interior Outer Continental Shelf Safety Oversight Board 
Report to the Secretary of the Interior Ken Salazar ; US Department of the Interior: September 1, 2010; p 33; 
http://www.noia.org/wp-content/uploads/2015/12/DOI-OCS-Safety-Oversight-Board-Report.pdf (accessed March 
26, 2016). 
576 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling. Deepwater: The Gulf Oil 
Disaster and the Future of Offshore Drilling - Report to the President; Janurary, 2011; p 26, Recommendation 
A4. 
577 George Cameron Coggins and Doris K. Nagel, Nothing Beside Remains: The Legal Legacy of James G. Watt’s 
Tenure as Secretary of the Interior on Federal Land Law and Policy, 17 B.C. ENVTL. AFF. L. REV. 473, 482 
(1990). 
578 Ibid. 

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Other agencies with competing missions exist in the federal government.579 The federal administrative 
agencies and bureaus that manage public lands, like the former MMS, the Bureau of Land Management, 
and the US Forest Service, probably have the most diverse and sweeping range of goals, including 
production, environmental protection, public use, and worker and public safety, all of which are difficult 
to address equally.580 Each of these agencies has either admitted to or been accused of emphasizing one or 
more of their missions, typically the economic or production-related ones, over others such as safety.581 
There are signs that BSEE may continue to emphasize the economic or production-related aspects of 
DOI’s mission, particularly for permitting offshore operations. 
 
579 In addition to the Department of the Interior, they include the Federal Bureau of Investigation, the US Forest 
Service, and the Department of Homeland Security, among others. See, e.g., Eric Biber, Too Many Things To Do: 
How to Deal With the Dysfunctions of Multiple-Goal Agencies, 33 HARV. ENVT’L. L. REV. 1 (2009). 
580 For an example, see Eric Biber, Too Many Things to Do: How to Deal With the Dysfunctions of Multiple-Goal 
Agencies, 33 HARV. ENVT’L. L. REV. 1, 2 (2009). 
581 Ibid. 

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Figure 4-1. Department of Interior organization chart: at the time of the April 20, 2010, Macondo incident and 
currently. 

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5.6.3 
Critical BSEE Drilling Permit Concerns 
Post-Macondo, there has been a resurgence of pressure for BSEE to approve drilling permits. In more 
than one committee hearing that purported to explore other topics, the focus of questioning shifted to 
Gulf-area congressional representatives’ concerns about oil production and the pace of drilling permit 
review. In an October 2011 House Natural Resources committee hearing about the results of the Joint 
Investigation Team,582 committee members chided then-Director Bromwich for not focusing enough on 
speeding up drilling permit reviews and production.583 A few months later, after testimony before the 
House and Senate appropriations subcommittees in 2012, members repeatedly questioned former Director 
Watson about BSEE’s slow pace of drilling permit approvals.584 In episodes reminiscent of early MMS 
OCS subcommittee discussions, congressional representatives expressed concern about a decrease in 
drilling permits and about rigs “leaving our shores and going to Brazil” because the country needs to “get 
[offshore] production going up and prices at the pump going down.”585 Less than two years following the 
incident, congressional attention to safety reform was nearly eclipsed by a seeming preoccupation with 
the potential effects of a drilling moratorium that had been in place while the Macondo well was still 
leaking oil into the Gulf. Thus, the inherent conflict between production and safety remains on the 
shoulders of the DOI Assistant Secretary, Deputy Secretary, and Secretary, all whom also face economic 
development and production pressures. By remaining under the DOI umbrella, the offshore safety 
regulator is not truly independent from these pressures, potentially compromising major accident 
prevention initiatives. 
 
582 As offshore safety regulators in the US, BOEMRE and USCG formed a Joint Investigation Team to investigate 
the Deepwater Horizon disaster. BOEMRE and the USCG published separate reports addressing their respective 
areas of safety responsibility; USCG, Report of the Investigation into the Circumstances Surrounding the 
Explosion, Fire, Sinking and Loss of Eleven Crew Members Aboard the Mobile Offshore Drilling Unit Deepwater 
Horizon in the Gulf of Mexico, April 20-22, 2010, Volume 1, MISLE Activity Number 3721503; p 127. 
http://www.uscg.mil/hq/cg5/cg545/dw/exhib/DWH%20ROI%20-%20USCG%20-%20April%2022,%202011.pdf 
(Accessed March 26, 2016). 
583 Full Committee Oversight Hearing on the BOEMRE/U.S. Coast Guard Joint Investigation Team Report, U.S. 
House of Representatives Committee on Natural Resources, October 13, 2011, see e.g., p 3 
https://www.gpo.gov/fdsys/pkg/CHRG-112hhrg70720/pdf/CHRG-112hhrg70720.pdf (accessed March 26, 2016). 
584 House Natural Resources Subcommittee on Energy and Mineral Resources Hearing on President Obama’s Fiscal 
2013 Budget Proposal for the Bureau of Ocean Energy Management and Bureau of Safety and Environmental 
Enforcement, March 8, 2012 http://naturalresources.house.gov/calendar/eventsingle.aspx?EventID=282268 and 
Senate Appropriations Subcommittee on Interior, Environment and Related Agencies Hearing on the Proposed 
2013 Appropriations for the Interior Department’s Onshore and Offshore Energy Development Programs, March 
14, 2012 
http://www.appropriations.senate.gov/imo/media/doc/hearings/03_14_12%20Interior%20&%20Environment%20
On&Off%20Shore%20energy%20GPO%20Record.pdf (accessed March 26, 2016). 
585 House Natural Resources Subcommittee on Energy and Mineral Resources Hearing on President Obama’s Fiscal 
2013 Budget Proposal for the Bureau of Ocean Energy Management and Bureau of Safety and Environmental 
Enforcement, March 8, 2012 http://naturalresources.house.gov/calendar/eventsingle.aspx?EventID=282268 
(accessed March 26, 2016). 

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5.6.4 
Historical Recognition for Separating Safety Oversight from Resource 
Development 
Congress can rely on several precedents for separating safety and environmental oversight from a 
predecessor agency to an independent regulator. Some of the most analogous situations that resulted in 
legislative actions to separate safety oversight were prompted by a catastrophic incident much like 
Macondo. As it has done with mining and nuclear safety, Congress would need to take action to move 
offshore safety regulation into an independent agency separate from the Department of Interior. 
5.6.4.1 
Creation of the Mine Safety and Health Administration 
The current Mine Safety and Health Administration (MSHA) was once the Mining Enforcement and 
Safety Administration (MESA), a subcomponent of the Department of the Interior. After a string of 
serious mining disasters in the 1970s (including Sunshine Silver, Buffalo Creek, Blacksville, and Scotia), 
Congress reviewed MESA’s enforcement record, finding the fatality and injury numbers unacceptably 
high.586 Congress determined that a conflict existed between MESA, which was responsible for enforcing 
and administering the mine safety and health laws, and the Department of Interior, which “pursued the 
goal of maximizing production.”587 Congress reasoned that separating the mine safety and health 
regulator from revenue-related activities would solve the problem of conflicting missions.588 MSHA was 
moved to the Department of Labor because its primary mission is to keep workers safe.589 Congress 
enacted the Federal Mine Safety and Health Amendments Act of 1977 to formalize MSHA’s authority.590 
5.6.4.2 
Creation of the Nuclear Regulatory Commission 
Just as the reorganization of MESA was prompted by a catastrophic accident, nuclear safety regulatory 
structures were reformed again after the Three Mile Island nuclear incident in 1979. The original Atomic 
Energy Commission (AEC) had three conflicting goals: managing the atomic weapons program, 
promoting the peaceful use of atomic power, and protecting public health and safety.591 The AEC came 
under attack for its focus on developing nuclear technology and a cozy relationship with industry. Critics 
complained that it was “like letting the fox guard the henhouse.”592 In response, Congress split the AEC, 
assigning safety regulation to the new Nuclear Regulatory Commission (NRC) and placing the 
development and research in what is now the Department of Energy.593 But the NRC’s Reorganization 
 
586 Senate Report 95-181 at 3405 (95th Congress), May 16, 1977 
http://arlweb.msha.gov/SOLICITOR/COALACT/leghist2.htm (accessed March 26, 2016). 
587 Ibid. 
588 Ibid. 
589 Ibid. 
590 Ibid. 
591 Mazuzan, G.; Walker, S. Controlling the Atom: The Beginnings of Nuclear Regulation, 1946-1962, 1st ed.; 
University of California Press: 1984. 
592 Ibid. 
593 Energy Reorganization Act of 1974, Pub. L. No. 93-438, 88 Stat. 1233; see also Alice L. Buck, U.S. Dep’t of 
Energy, A History of the Atomic Energy Commission 8 (1983) (describing history of conflict); see also Eric 
Biber, Too Many Things To Do: How to Deal With the Dysfunctions of Multiple-Goal Agencies, 33 HARV. 
ENV’TL. L. REV. 1, 33 (2009). 

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Plan No. 1 of 1980, a major overhaul of the agency, was the direct result of Three Mile Island accident. 
The 1980 plan established a program to integrate NRC findings about licensee performance into a public 
report, expanded performance-oriented and safety-oriented inspections and risk assessment, and 
strengthened and reorganized a separate, independent NRC enforcement office.594 
5.6.4.3 
Creation of the UK HSE Offshore Division 
In the UK, the offshore regulator was initially organized within the Department of Energy—Petroleum 
Engineering Division. This division held responsibility for developing and enforcing health and safety 
regulations in addition to licensing and resource development.595 Although the conflict between these 
missions was apparent before then, a 1972 inquiry identified fundamental flaws in this arrangement.596 In 
1988, the Piper Alpha disaster confirmed that a complete reorganization of offshore safety regulation was 
necessary.597 
A major recommendation of the Lord Cullen report was to transfer the responsibility for offshore safety 
regulation from the Department of Energy to the UK’s HSE. In response, the UK HSE Offshore Division 
was created in 1991, with sole responsibility for offshore safety oversight.598 This separation of 
responsibility for regulating offshore safety from licensing and revenue collection continued in the UK 
ever since, despite various subsequent organizational changes. Following the recent implementation of the 
EU Offshore Safety Directive by the UK, the offshore regulator is now the Offshore Safety Directive 
Regulator (OSDR). In the US, a similar structure without inherent conflicts would strengthen BSEE in its 
regulatory function. 
 
 
 
594 See, e.g., NRC. Backgrounder on the Three Mile Island Accident, http://www.nrc.gov/reading-rm/doc-
collections/fact-sheets/3mile-isle.html#impact; Nuclear Regulatory Legislation: 113th Congress; 2nd Session 
(Volume 1, Number 11), http://www.nrc.gov/reading-rm/doc-collections/nuregs/staff/sr0980/v1/sr0980v1.pdf, 
(accessed March 26, 2016). 
595 T. Hunter and J. Paterson, Offshore Petroleum Facility Integrity in Australia and the United Kingdom: A 
Comparative Study of Two Countries Utilising the Safety Case Regime, Oil, Gas & Energy Law Intelligence 
(October 2011), p 7. 
596 Ibid. 
597 Ibid. 
598 UK HSE, Who we are, http://www.hse.gov.uk/offshore/who.htm (accessed March 26, 2016). 

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6.0 Conclusion 
This final volume on the Macondo blowout focuses on several key attributes of more robust process 
safety management regulatory regimes that the CSB believes would enhance existing US offshore 
regulations. Many of the attributes of an effective goal-setting, risk-reduction regime focused on major 
accident prevention were not present pre-Macondo, and recent changes to the US offshore regulator’s 
organization and regulations, particularly the establishment of SEMS, do not go far enough to ensure 
effective industry management and control of major hazards or prevent possible future Macondo-type 
incidents. Specifically, the US offshore regulatory regime does not adequately put the onus on industry to 
minimize risk and empower the regulator proactively to ensure effective industry management and 
control of major hazards. 
The CSB finds that more robust US and international regimes focus on major accident prevention and 
continual improvement and they identify gaps and weaknesses that were causal to the Macondo incident. 
When taken together: 
• 
Foster continual improvement by requiring companies to reduce their risks through goal-setting 
risk reduction techniques such as ALARP; 
• 
Cultivate more adaptability; 
• 
Clarify safety responsibility to focus accountability on key parties such as leaseholder/operator 
and drilling contractor that create or control major accident risks; 
• 
Create opportunities for active workforce participation; 
• 
Require written safety documentation by duty holders; 
• 
Require proactive regulatory assessment and verification; 
• 
Establish and use helpful process safety indicators to drive performance; 
• 
Employ appropriately trained and experienced regulatory staff; and 
• 
Feature a transparent, independent, and well-resourced regulator. 
Collectively, these attributes provide the foundation for a more robust goal-setting risk-reduction 
regulatory model for US offshore drilling and production operations. Based upon its analysis of other 
high-hazard industries that use similar performance-based regulations, as well as other offshore regimes, 
the CSB concludes that augmenting the current US offshore regulatory model will better ensure major 
accident risk reduction. 

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7.0 Recommendations 
The CSB issues four recommendations to the US Department of Interior for additional improvements in 
offshore safety. 
 
CSB2010-10-I-OS-R11 
Recommends Revision to the Offshore Safety Regulations to Establish a 
Regulatory Framework with a Specific Goal Of Preventing Major 
Accidents Based on the Attributes Described in CSB Macondo 
Investigation Report Volume 4. 
United States Department of Interior 
Revise and augment the offshore safety regulations, including the SEMS Rule (C.F.R. 250 subpart S), and 
issue guidance as it relates to those revisions/augmentations, to: 
a. Establish clear and consistent safety and environmental management responsibilities to prevent 
major accidents for the companies having primary control over the hazardous activities being 
undertaken (e.g., the owner/drilling contractor for a non-production installation and the 
leaseholder/operator for the production installation); 
b. Require all responsible parties as defined in R11(a) to develop documentation for each hazardous 
operation/facility it maintains primary control over, where the documentation demonstrates the 
party’s systematic analysis that risks posed by all identifiable major accident hazards are reduced 
to As Low As Reasonably Practicable (ALARP) or similar risk-reduction target. The 
documentation shall include: 
1. Identification of major hazards and the barriers and safety management systems controls 
(including augmented SEMS elements) that will be used to reduce risk to ALARP or 
similar risk reduction target; 
2. Use of the hierarchy of controls to the greatest extent feasible in establishing safety 
barriers and controls; 
3. Identification of safety critical elements and tasks to establish and maintain safety 
barriers and controls, in fulfillment of R1 (See Volume 2); 
4. Demonstrate use of established qualitative, quantitative and semi-quantitative methods in 
determining (1) the barriers and safety management systems necessary to achieve 
ALARP risk reduction levels and (2) the performance requirements of those barriers and 
controls (e.g., reliability, functionality, and availability) to ensure their effectiveness; 
5. Identification of all US and international standards that have been applied, or will be 
applied, in relation to the facility, hazardous operation, or equipment used on/in 
connection with the operation for which required documentation is submitted. Should the 
responsible party wish to use standards other than well-recognized US or international 
consensus safety standards developed by a representative committee of diverse 
stakeholders, a detailed technical justification that those standards achieve risk-reduction 
to ALARP must accompany submitted documentation. The regulator may challenge or 
reject the technical justification. Remove from the US offshore safety regulatory scheme 

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the provisions that allow companies to substitute requirements to use the best available 
and safest technology with a showing of compliance with BSEE regulations. 
c. Require responsible parties as defined by R11(a) to fully implement all aspects of the 
documentation stipulated in R11(b) and establish a documented process to verify that all methods 
to manage, reduce, and control those hazards are effectively maintained throughout the lifecycle 
of the operation/facility. 
 
 
CSB2010-10-I-OS-R12 
Recommends Strengthening Preventative Oversight by the Offshore 
Safety Regulator 
United States Department of Interior 
Augment the capabilities and functioning of BSEE to incorporate the following proactive oversight 
mechanisms: 
a. Review of the documentation required to be submitted under CSB 2010-I-OS-R11(b) by 
technically qualified regulatory personnel who have the capability and authority to require 
modifications and improvements to the major hazards report as necessary, either before an 
acceptance process and commencement of the major hazards operation(s) or during periodic 
proactive review by the regulator; 
b. Establish a program for preventive, comprehensive inspections and audits with technically 
qualified staff as described in R13(a) to ensure that the responsible party as defined in R11(a) can 
demonstrate the risk reduction commitments stipulated in its major hazards report. 
 
 
CSB2010-10-I-OS-R13 
Recommends Continued Efforts to Develop a Sufficiently Resourced, 
Technically Qualified, and Diverse Staff 
United States Department of Interior 
Further enhance the qualifications, professional competency, and diversity of BSEE staff to implement 
major accident prevention programs by: 
a. Continuing efforts to enhance recruiting and retention of sufficient staff with a diversity of 
expertise, professional backgrounds and skill sets, such that BSEE has staff competencies in a 
variety of safety-critical and technical areas, including petroleum, chemical, and mechanical 
engineering; human and organizational factors; well design and control; and process safety, as 
well as those with industry experience to perform an even more expanded mission as envisioned 
in this report; 
b. Retaining the services of a human resources consulting firm to complement BSEE’s efforts to 
date on human capital management and workforce planning issues, in light of documented 
difficulties in recruiting and retaining necessary staff, including the development of a plan with 
respect to large numbers of retirements facing the agency in the coming decade, as well as a 
compensation analysis (and a plan for subsequent periodic market analyses and benchmarking) to 
ensure BSEE remains competitive with other employers in the offshore industry. Augment the 
agency’s compensation system as necessary to enable BSEE to attract and retain the level of 
staffing needed to perform BSEE’s mission. 

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c. Continuing to assess, expand, and improve ongoing BSEE training programs for new hires to 
provide all employees with robust skill sets, including appropriate technical training as well as 
interpersonal skills such as communications, negotiation and advocacy. 
 
If funding, legislative authority, or other approvals are required to implement the recommended 
regulatory provisions in Recommendation R11 – R13, the Secretary of the Interior shall seek such 
authority from Congress or expedited hiring authority from the Office of Personnel Management. 
 
CSB2010-10-I-OS-R14 
Recommends Improving the Regulatory Reporting Program to Drive 
Continual Safety Improvement of Industry 
United States Department of Interior 
Expand the offshore safety regulatory program that collects, tracks, and analyzes safety performance 
indicators from industry to further influence industry efforts in reducing major accident risks to ALARP. 
At a minimum, this program shall: 
a. Require the reporting of safety indicator data by all responsible parties, as defined in R11(a); 
b. Emphasize the greater preventive value of using leading indicators to actively monitor the health 
and performance of major accident safety barriers and the management systems meant to ensure 
their effectiveness, and work with industry to develop leading indicators that are measurable, 
actionable, normalized across industry, and that occur with sufficient frequency to allow for 
meaningful trending and analysis at the facility and corporate levels; 
c. Augment current reporting requirements to include leading safety performance indicators; 
d. Use the safety performance indicator data to: 
1. identify industrywide, companywide, and facility-specific safety trends and deficiencies; 
2. set annual process safety goals or targets for the industry, company and/or facility, as 
appropriate, based upon those identified safety trends and deficiencies; 
3. issue, at a minimum, annual reports that publicly communicate those trends, deficiencies, 
targets, and goals; and 
4. determine future appropriate allocations of BSEE resources and the prioritization of 
BSEE inspections; 
e. Include use of significant lagging indicators data (including those already mandated by 30 C.F.R. 
250.188(a) and (b), such as major events like explosions, fires, gas releases, fatalities, INCs) as 
qualification criteria in the lease-approval and permit-to-drill decision-making processes by the 
regulator. 
 
CSB2010-10-I-OS-R15 
Recommends Strengthening Regulatory Requirements for Worker 
Engagement in the Management of Safety 
United States Department of Interior 
Issue participation regulations and training requirements for workers and their representatives that include 
the following: 
a. Worker-elected safety representatives and safety committees for each staffed offshore facility 
chosen under procedures overseen by the regulator; these safety representatives will have the 

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authority to interact with employers (such as operators and drillers) and regulators on issues of 
worker health and safety risks and the development and implementation of the major hazard 
report documentation; 
b. The elected worker representative has the right to issue an enforceable stop-work order if an 
operation or task is perceived as unsafe; all efforts should be made to resolve the issue at the 
workplace level, but if the issue remains unresolved, BSEE shall establish mechanisms such that 
the worker representative has the right and ability to seek regulator intervention to resolve the 
issue, and the regulator must respond in a timely fashion; 
c. The regulator will host an annual tripartite forum for workforce representatives, industry 
management, and the regulator to promote opportunities for interaction by all three entities on 
safety matters and to advance initiatives for major accident prevention. 
d. Protections for workers participating in safety activities with a specific and effective process that 
workers can use to seek redress from retaliatory action with the goal to provide a workplace free 
from fear that encourages discussion and resolution of safety issues and concerns. Protected 
activities include, but are not limited to reporting unsafe working conditions, near misses, and 
situations where stop work authority is used. 
 
CSB2010-10-I-OS-R16 
Recommends Incorporating API 75 by Reference upon Revision in 
Response to CSB Recommendation R11 
United States Department of Interior 
Incorporate by reference into the offshore safety regulations the revised version of Recommended 
Practice 75, Development of a Safety and Environmental Management Program for Offshore Operations 
and Facilities, 3rd Ed., May 2004 (reaffirmed May 2008) upon the inclusion of the CSB 
recommendations in R11 by API. 
 
 

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Appendix A: International Offshore Incidents and the US 
Response 
Alexander Kielland and Regulatory Change in Norway 
On March 27, 1980, the Alexander L. Kielland installation capsized in the North Sea, killing 123 of the 
212 people on board.599 The incident had a dramatic impact on the offshore industry and the Norwegian 
regulator, which was called the Norwegian Petroleum Directorate.600 The day after the incident, a 
Commission was appointed to determine the causes of the accident and recommend actions to prevent 
similar incidents.601 The Commission’s final report identified weaknesses in Norwegian inspection 
routines, safety training, and technical expertise in rescue equipment.602 It also recommended centralizing 
regulatory authority and finalizing the Petroleum Activities Act, which licensed internal controls for 
offshore operations and implemented risk-analysis requirements.603 
By the mid- to late-1980s, dramatic changes took place for the regulator and the overall management of 
major accident risk. New regulations and requirements were established for companies operating offshore 
to develop and implement internal control plans for safety management, which required regulatory 
approval.604 The aim of these regulatory changes was to shift from adherence to prescriptive requirements 
to a more comprehensive understanding of risk.605 In addition to centralizing regulatory authority, new 
concepts were introduced, including a “compliance responsibility” whereby companies were required to 
verify acceptable risk management.606 
The Norwegian government began to consider its role as supervisor instead of inspector of the offshore 
industry.607 The regulator began interacting with industry professional associations and studies, adding to 
 
599 Norwegian Public Reports, Presented to Ministry of Justice and Police (March 1981), NOU 1981: 11 “The 
Alexander L. Kielland accident” p 9. 
600 Melberg , E. Determined to learn from history. August 13, 2010, http://www.npd.no/en/publications/norwegian-
continental-shelf/no1-2010/determined-to-learn-from-history/ (accessed 31 2013, October). 
601 Norwegian Public Reports, Presented to Ministry of Justice and Police (March 1981), NOU 1981: 11 “The 
Alexander L. Kielland accident” pp 1-2. 
602 PSA. From prescription to performance in petroleum supervision. March 12, 2010, 
http://www.ptil.no/news/from-prescription-to-performance-in-petroleum-supervision-article6696-878.html 
(accessed October 31, 2013). 
603 Ibid. 
604 Committee on Alternatives of Inspection of Outer Continenetal Shelf Operations, Marine Board, Commission on 
Engineering and technical Systms National Reserach Council. Alternatives for Inspecting Outer Continental Shelf 
Operations [Online]; National Academy Press: Washington, 1990; p 111, 
http://www.nap.edu/download.php?record_id=1517 (accessed March 26, 2016). 
605 Melberg , E. Determined to learn from history. August 13, 2010, http://www.npd.no/en/publications/norwegian-
continental-shelf/no1-2010/determined-to-learn-from-history/ (accessed 31 2013, October). 
606 PSA. From prescription to performance in petroleum supervision. March 12, 2010, 
http://www.ptil.no/news/from-prescription-to-performance-in-petroleum-supervision-article6696-878.html 
(accessed October 31, 2013). 
607 Ibid. 

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its audit, verification, investigation and consideration responsibilities.608 Additionally, it began issuing 
“consents” to operate in lieu of “approvals.”609 These shifts helped the Norwegian offshore regulator 
transform from a compliance-based regime that shifted some of the responsibility for safety from the 
regulator into a goal-based regime that allowed industry to determine how best to meet those goals.610 
Ocean Ranger and Regulatory Change in Canada 
The Ocean Ranger drilling rig capsized off the Canadian coastal region of Newfoundland during a severe 
storm with hurricane-force winds, ending 84 lives.611 A Royal Commission on the Ocean Ranger Marine 
Disaster formed to investigate the incident found the prescriptive offshore regulatory regime overly 
complex and inadequately enforced. Recommendations from the Commission’s resulting two reports 
involved consolidation of regulatory powers under a single body.612 At the time of the incident, the 
Canada Oil and Gas Lands Administration, Newfoundland Labrador Petroleum Directorate, and the US 
Coast Guard all held some regulatory authority over the Ocean Ranger’s drilling operation.613 In 1985, the 
Canada-Newfoundland Offshore Petroleum Board was formed to centralize regulatory authority.614 As 
offshore development continued to grow into more complex and challenging geographical locations, the 
offshore safety regulators for Canada’s eastern provinces, the Nova Scotia and Newfoundland Labrador 
Offshore Petroleum Boards, worked with the Norwegians to implement changes they considered 
necessary to safely develop their resources.615 They have replaced many of their prescriptive offshore 
regulations for goal-based rules, moving much of their prescription to guidance documents. The boards 
recognized that this fundamental change allowed for the regulator not only to keep step with industry 
advances, but also to demand continual safety improvement from industry without rule-making.616 
 
608 Ibid. 
609 Ibid. 
610 Melberg , E. Determined to learn from history. August 13, 2010, http://www.npd.no/en/publications/norwegian-
continental-shelf/no1-2010/determined-to-learn-from-history/ (accessed 31 2013, October). 
611 Higgins, J. Response to the Ocean Ranger Disaster. Newfoundland and Labrador Heritage, 2012, 
http://www.heritage.nf.ca/articles/politics/ocean-ranger-disaster-response.php (accessed December 17, 2014). 
612 Ibid. This regulatory body is now known as the Canada-Newfoundland and Labrador Offshore Petroleum Board. 
There is also a Canada-Nova Scotia Offshore Petroleum Board which regulates offshore oil and gas industry 
safety for the Nova Scotia and frontier lands and a National Energy Board, which regulates offshore areas not 
otherwise covered by provincial or federal management systems. http://www.neb-one.gc.ca/clf-
nsi/rthnb/whwrndrgvrnnc/nbfctsht-eng.html (accessed January 26, 2016). 
613 The Ocean Ranger was owned by Ocean Drilling and Exploration Company, an American corporation that had 
been contracted by Mobil Oil to drill; Higgins, J. Response to the Ocean Ranger Disaster. Newfoundland and 
Labrador Heritage, 2012, http://www.heritage.nf.ca/articles/politics/ocean-ranger-disaster-response.php (accessed 
December 17, 2014). 
614 Ibid. 
615 Trip notes from CSB meeting with the Canada Newfoundland and Labrador Offshore Petroleum Board 
(CNLOOPB), St. John’s, Newfoundland, Canada (March 7, 2011). 
616 Ibid. 

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Piper Alpha and Regulatory Change in the United Kingdom 
On July 6, 1988, an explosion occurred aboard the Piper Alpha oil production platform 120 miles off the 
coast of Scotland in the North Sea.617 A series of explosions and fire killed 167 workers and almost 
completely destroyed the platform. This accident is the deadliest in the history of the offshore 
operations.618 Multiple systemic, organizational, and regulatory deficiencies caused the incident.619 
The UK government conducted an inquiry that called into question the adequacy of the detailed 
prescriptive regulatory regime that existed at the time of the incident.620 Lord Cullen, the judge leading 
the inquiry, listed 106 recommendations to revamp offshore safety regulation in the UK, which included a 
recommendation for the responsible party providing a written case for safety identifying the hazards and 
demonstrating the adequacy of the safety management systems in place to control for each hazard at every 
offshore site.621 
The intent of the safety case was to shift the responsibility for identifying and mitigating hazards and risks 
from the regulator to the duty holder.622,623 Lord Cullen reasoned that “a regulator cannot be expected to 
assume direct responsibility for the on-going management of safety. … this is and remains in the hands of 
the operator.”624 The UK government accepted all of the 106 recommendations,625 ushering in new goal-
setting regulations to replace the existing prescriptive ones.626 The Offshore Installations (Safety Case) 
Regulations came into force in 1992. By November 1993, a safety case for every installation had been 
submitted to the HSE, and by November 1995, all had had their safety case accepted by the HSE. 
 
617 Department of Energy. The Public Inquiry into the Piper Alpha Disaster; Presented to Parliament by the 
Secretary of State for Energy by Command of her Majesty. November, 1990. 
618 John M.T. Balmer, The BP Deepwater Debacle and Corporate Brand Exuberance, 18 J. Brand Mgmt. 97, 100 
(2010). 
619 Department of Energy. The Public Inquiry into the Piper Alpha Disaster; Presented to Parliament by the 
Secretary of State for Energy by Command of her Majesty. November, 1990; pp 121-22.; John Paterson, The 
Significance of Regulatory Orientation in Occupational Health and Safety Offshore, 38 B.C. Envtl. Aff. L. Rev. 
369 (2011), http://lawdigitalcommons.bc.edu/ealr/vol38/iss2/8 (accessed March 26, 2016). 
620 T. Hunter; J. Paterson; "Offshore Petroleum Facility Integrity in Australia and the United Kingdom: A 
Comparative Study of Two Countries Utilising the Safety Case Regime" OGEL 6 (2011); p 9. 
621 Ibid. 
622 Duty holders are considered to be “those who create and/or have the greatest control of the risks associated with a 
particular activity. Those who create the risks at the workplace are responsible for controlling them.” HSE. 
Planning to do business in the UK offshore oil and gas industry? What you should know about health and safety; 
October 2011; p 2. These entities may include operators, contractors, and subcontractors. 
http://www.hse.gov.uk/offshore/guidance/entrants.pdf (accessed June 5, 2013). 
623 T. Hunter; J. Paterson; "Offshore Petroleum Facility Integrity in Australia and the United Kingdom: A 
Comparative Study of Two Countries Utilising the Safety Case Regime" OGEL 6 (2011); p 9-10. 
624 Ibid. 
625 180 Parl. Deb., H.C. (6th ser.) (1990) 329-45; John Paterson, The Significance of Regulatory Orientation in 
Occupational Health and Safety Offshore, 38 B.C. Envtl. Aff. L. Rev. 369 (2011), 
http://lawdigitalcommons.bc.edu/ealr/vol38/iss2/8 (accessed March 26, 2016). 
626 John Paterson, The Significance of Regulatory Orientation in Occupational Health and Safety Offshore, 38 B.C. 
Envtl. Aff. L. Rev. 369 (2011), http://lawdigitalcommons.bc.edu/ealr/vol38/iss2/8 (accessed March 26, 2016). 

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The Safety Case Regulations require the duty holder of every installation operating in UK waters to 
submit a safety case to HSE for acceptance. The safety case must fully explain the duty holder’s plans for 
managing health and safety and controlling major accident hazards on the installation.627 It must 
demonstrate that the company has established safety management systems, identified risks and reduced 
them to as low as reasonably practicable, introduced management controls, provided a temporary safe 
refuge on the installation, and provided for safe evacuation and rescue.628 Duty holders are required to 
revise and update their safety cases as needed throughout the life cycle of their installation. 
Outside the UK, other regulators also heeded the Cullen Report recommendations. A few months after the 
incident, Australia formed the Consultative Committee on Safety in the Offshore Petroleum Industry to 
advise the Minister for Resources on safety issues related to Australia.629 The Committee recommended 
that the key outcomes of the UK Piper Alpha inquiry be implemented in Australia, and regulatory reform 
ensued that made the safety case a requirement for offshore.630 The UK Safety Case Regulations were 
revised in 2005 to improve their effectiveness and reduce the burden of three yearly resubmissions. 
Montara and Regulatory Change in Australia 
On August 21, 2009, approximately six months prior to the Macondo incident, the Montara Wellhead 
Platform suffered a blowout in the Timor Sea off the coast of Australia.631 The Montara rig caught fire 
and a well leaked tens of thousands of barrels of oil over two-and-a-half months before it was shut 
down.632 Although it was similar to the Macondo event in many ways, including well capping and 
misunderstandings about cement,633 this blowout did not result in any fatalities. At the time of the 
Montara incident, Australia was already using a goal-setting regulation that required operating companies 
to set their own standards based on the hazards and risks posed by their activities, and then follow through 
on their commitment.634 The duty holder on the Montara platform failed to comply with its own well 
construction standards (WCS) in numerous ways, including (1) failure to test the cemented casing shoe 
and subsequent reliance on this untested barrier, (2) reliance on pressure containing corrosion caps 
(PCCCs) as a well barrier when these are not approved in the WCS, (3) failure to install sufficient barriers 
to meet the requirements for long-term suspension of the well, and (4) failure to monitor completion fluid 
 
627 Oil & Gas UK. Piper Alpha Lessons Learnt; 2008; p 5. http://oilandgasuk.co.uk/wp-
content/uploads/2015/05/HS048.pdf (accessed 26 2016, March). 
628 Ibid. 
629 Patrick Brazil and Peter Wilkinson, The Establishment of a National Offshore Petroleum Safety Authority (2005) 
24 Australian Resources and Energy Law Journal 87, pp 88-89. 
630 T. Hunter; J. Paterson; "Offshore Petroleum Facility Integrity in Australia and the United Kingdom: A 
Comparative Study of Two Countries Utilising the Safety Case Regime" OGEL 6 (2011); pp 15-16. 
631 Montara Commission of Inquiry. Report of the Montara Commission of Inquiry; Commonwealth of Australia 
2010: June, 2010; http://www.iadc.org/wp-content/uploads/2016/02/201011-Montara-Report.pdf (accessed March 
26, 2016). 
632 Ibid., p 38. 
633 Hayes, J. Operator competence and capacity – Lessons from the Montara blowout; Safety Science 2012, 50, pp 
563-574. 
634 Ibid. 

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parameters to ensure overbalance and subsequent reliance on this unmonitored barrier during temporary 
suspension.635 
As a result of the accident, the Australian government organized an inquiry to identify the likely causes of 
the release, including regulatory failures.636 The Australian government report confirmed that the blowout 
was immediately caused by the failure of the primary well control barrier—the cement casing shoe.637 In 
addition, the report also criticized the operator’s reliance on improper secondary well control barriers, 
inadequate well management plans, improper pressure testing, and inexperienced personnel.638 The 
Montara blowout was the worst of its kind in Australia’s offshore industry history.639 The inquiry helped 
the Australian government realize that the provincial regulation of offshore safety was inadequate for 
preventing major accident. In other words, no problem was uncovered concerning the quality of the well-
integrity regulations, but a failure of the provincial regulator (the Northern Territory) to adequately 
enforce the existing regulations, primarily based on the authority being too trusting of industry. It has 
since implemented changes to bring offshore operations under the purview of NOPSEMA, a national 
agency with the necessary resources to enforce existing regulations more effectively. 
History of Regulatory Change in the US 
The lessons learned from major industrial accidents helped shape the major hazard regulatory regimes 
around the world, both on and offshore. In most cases, post-accident regulatory changes involved 
replacing compliance-based regulations with performance-based, goal-setting risk-reduction models that 
support adaptability and continued risk-reduction to as low as reasonably practicable (ALARP) or some 
roughly equivalent standard, while providing the regulator with the needed resources and tools to drive 
continual improvement among major hazard facilities. 
For example, the international offshore energy industry experienced several catastrophic accidents in the 
1980s, including the Alexander Kielland in Norway in 1980, the Ocean Ranger in Canada in 1982 and 
Piper Alpha in the UK in 1988. These accidents prompted significant shifts in the offshore regulatory 
structures of Norway, Canada, the UK, and Australia from prescriptive compliance-based regulation to 
performance-based goal-setting models. The CSB’s Chevron Regulatory Report also provides a helpful 
discussion of the accidents that spurred global development of the safety case regulatory regime for 
onshore and offshore major hazards.640 
 
635 Ibid. 
636 Peter Wilkinson presentation on Montara to CSB, July 2011 (slide 14). 
637 Montara Commission of Inquiry. Report of the Montara Commission of Inquiry; Commonwealth of Australia 
2010: June, 2010; p 7. http://www.iadc.org/wp-content/uploads/2016/02/201011-Montara-Report.pdf (accessed 
March 26, 2016). 
638 Ibid., pp 7-11. 
639 Ibid., p 5. 
640 USCSB, 2013. Regulatory Report: Chevron Richmond Refinery Pipe Rupture and Fire, Richmond, CA, August 6, 
2012, Report No. 2012-03-I-CA, April 2013, 
http://www.csb.gov/assets/1/19/Chevron_Regulatory_Report_11102014_FINAL_-_post.pdf (accessed January 
25, 2016). See Chapter 3 for a helpful discussion of the accidents that spurred global development of the safety 
case regulatory regime for onshore and offshore major hazards. 

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At the time of the Alexander Keilland accident in 1980, the US GoM OCS region still consisted of 
shallow-water (defined here as less than 1,000 feet) exploration, drilling, and production operations, 
though some offshore drilling operations reached depths of approximately 1,500 feet in the California 
OCS as early as 1975, which were considered “deepwater” drilling operations at the time.641 The GoM 
also enjoys more hospitable weather, as well as calmer seas, minus the occasional hurricane, and warmer 
temperatures than the North Sea. Thus, it is perhaps not surprising that lessons learned overseas in foreign 
offshore oil-producing jurisdictions did not result in full-scale changes to the US offshore regulatory 
regime, especially with an accident such as the Alexander Keilland which was not a drilling platform or 
vessel but an accommodations vessel. Drilling and production regulations in the US thus remained 
prescriptive and focused heavily on equipment rather than on hazard assessments and safety management 
systems. 
Yet a decade later, regulatory changes did not keep pace with changes in the field, as the US GoM OCS 
industry began exploring deeper waters, encountering ever more complex subsea geology and higher 
pressures during more dangerous drilling operations.642 Approximately one year after the Piper Alpha 
incident, when the US experienced its own major offshore event—a 1989 explosion at the ARCO 
platform in the Gulf of Mexico resulting in 7 fatalities643—MMS commissioned a task force to review its 
regulatory program. It also requested that the Marine Board of the National Research Council recommend 
improvements in MMS’s operational safety and environmental protection inspection practices.644 
The National Research Council Marine Board, referencing Piper Alpha, recommended adopting a more 
systems-based risk analysis focused on human factors, operational procedures, and modifications of 
equipment and facilities rather than adding equipment-specific prescriptive regulations.645 The Marine 
Board report identified that MMS’s prescriptive approach to regulating offshore operations actually 
forced industry into a compliance mentality that did not promote effective risk identification or 
comprehensive accident mitigation.646 The Board highlighted its long-held belief that the offshore 
regulatory regime should itself evolve by exploring different inspection, enforcement, and compliance 
 
641 National Commission on the BP Deepwater Horizon Oil Spill. A Brief History of Offshore Oil Drilling; Staff 
Working Paper No. 1; August, 2010; 
http://cybercemetery.unt.edu/archive/oilspill/20121211011815/http:/www.oilspillcommission.gov/sites/default/fil
es/documents/A%20Brief%20History%20of%20Offshore%20Drilling%20Working%20Paper%208%2023%2010
.pdf (accessed March 26, 2016). 
642 Hopkins, A. Disastrous Decisions; CCH Australia: Australia, 2012; p 138. 
643 E.P. Danenberger et al., Investigation of March 19, 1989 Fire, South Pass Block 60 Platform B, Lease OCS-G 
1608, OCS Report MMS 90-0016 (New Orleans: U.S. Dept of the Interior, MMS, April 1990), p 15, as cited in 
National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling. Deep Water: The Gulf Oil 
Disaster and the Future of Offshore Drilling; 2011; p 70. It is important to note that the ARCO incident involved 
shallow-water drilling at approximately 200 feet below sea level. See http://incidentnews.noaa.gov/incident/6687 
(accessed March 26, 2016). 
644 Committee on Alternatives of Inspection of Outer Continenetal Shelf Operations, Marine Board, Commission on 
Engineering and technical Systms National Reserach Council. Alternatives for Inspecting Outer Continental Shelf 
Operations [Online]; National Academy Press: Washington, 1990; p v, 
http://www.nap.edu/download.php?record_id=1517 (accessed March 26, 2016). 
645 Ibid., p 83. 
646 Ibid. 

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approaches.647 For example, the Board found that MMS’s program at the time “incorporates no 
mechanism or analytical basis for systematically upgrading safety requirements for OCS operations.”648 
Specifically, the Board found that MMS failed to: 
• 
analyze data to identify safety trends; 
• 
collect data consistently across operators and facilities that would permit such analyses; 
• 
document operator safety histories; or 
• 
cross-reference PINCs (potential incidents of non-compliance) and incidents of noncompliance 
(INCs) to events (accidents).649 
The Board recommended that MMS enhance its collection and analysis of safety-related data to “permit 
systematic targeting of spot inspections, and … to support a variety of continuing safety analysis to be 
used to improve safety and environmental protection on the OCS.”650 The Board noted these activities 
were “essential to an ongoing ‘risk assessment and management’ program.”651 It recommended that MMS 
emphasize “detection of potential accident-producing situations—particularly those involving human 
factors, operational procedures and modifications of equipment and facilities—rather than scattered 
instances of non-compliance and hardware specifications.”652MMS was not slow to act on the Board’s 
recommendations, perhaps because, along with the US Coast Guard, it was preoccupied with the effects 
of the Exxon Valdez oil spill, in March 1989.653 
Two years later, in 1991, MMS introduced a regulatory model for offshore safety management, the Safety 
and Environmental Management Program (SEMP).654 Industry pushback led to SEMP stagnating and it 
became a voluntary program whereby MMS asked offshore operators655 to adopt active safety and 
environmental management approaches in their operations.656 
Before the Macondo incident, MMS maintained an insular view of learning from international accidents. 
In particular, eight months prior to the Macondo incident, MMS largely disregarded the causes of a 
blowout in Australian waters from the Montara Wellhead Platform.657 Especially concerning about this 
 
647 Ibid., p v. 
648 Ibid., p 81. 
649 Ibid., p 81. 
650 Ibid., p 75. 
651 Ibid., p 75. 
652 Ibid, p 83. 
653 On March 24, 1989, the tanker Exxon Valdez grounded on Bligh Reef in Alaska's Prince William Sound, 
rupturing spilling nearly 11 million gallons of Prudhoe Bay crude oil into the Sound. Before the 2010 Deepwater 
Horizon oil spill, it was the largest single oil spill in US coastal waters. 
654 Oil and Gas and Sulphur Operations in the Outer Continental Shelf, 56 Fed. Reg. 30400 (Notice, July 2, 1991). 
655 “Operators” as referenced in US offshore regulations refer explicitly to the leaseholders of the well; this term 
does not include drilling contractors or other well service providers. 
656 Oil and Gas and Sulphur in the Outer Continental Shelf (OCS)—Safety and Environmental Management 
Systems, 71 Fed. Reg. 29278 (Advanced Notice of Proposed Rulemaking, May 22, 2006). 
657 U.S. Chemical Safety and Hazard Investigation Board interview of former MMS Director, April 5, 2011; 
Montara Commission of Inquiry. Report of the Montara Commission of Inquiry; Commonwealth of Australia 
2010: June, 2010; p 7. http://www.iadc.org/wp-content/uploads/2016/02/201011-Montara-Report.pdf (accessed 
March 26, 2016). 

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situation were the similarities between that incident and Macondo,658 and despite differences in the 
regulatory framework between the two countries, and some differences in the operations, sufficient 
similarities between Montara and Macondo blowouts made Montara a missed learning opportunity for 
MMS. For example, the failure of the cement to seal in the well, improper pressure testing, and reliance 
on limited and compromised (or missing) barriers all presented MMS with opportunities to study a major 
offshore accident. This could have aided MMS in identifying potential deficiencies in the US regulatory 
system, or in sharing some lessons learned with industry to enhance major accident prevention in US 
waters. 
MMS might have learned lessons from Montara if it had mechanisms for assessing major incidents and 
implementing needed changes from the lessons learned. But MMS lacked those mechanisms. Despite the 
enormous concern in Australia about the Montara incident, the Director of MMS at the time said, “what 
had happened in Australia was not going to happen here.”659 She also reported the US had little to learn 
 
658 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling. Deep Water: The Gulf Oil 
Disaster and the Future of Offshore Drilling; 2011; p 125 and 327. 
659 U.S. Chemical Safety and Hazard Investigation Board interview of former MMS director, April 5, 2011. 
Offshore Operators Historically Opposed SEMP Due to Its Prescriptive Nature 
Industry opposition to SEMP’s incorporation as regulation, as documented in public 
comment (excerpted below) submitted during consideration of the issue, revealed 
industry’s concerns about the limiting and compliance-based nature of a prescriptive 
regime. These concerns could be ameliorated by supplementing the existing 
regulatory structure with the attributes identified in this volume... 
“As MMS has noted, most industrial accidents and spill result from human error or 
organizational errors, not device or equipment failures and we agree. So, the question 
is, How do we overcome human error? It is difficult for us to see how a mandatory, 
highly prescriptive program proposed in the rulemaking will overcome human error.” 
— Offshore Operators Committee, OOC/API Comments on Proposed Subpart S-
SEMS, RIN 1010-AD 15; FR Vol. 74, No. 115, (June 17, 2009). 
“While BP is supportive of companies having a system in place to reduce injuries, 
risks, accidents and spills, we are not supportive of the extensive, prescriptive 
regulations proposed in this rule.” — BP Americaa 
“The proposed rule takes the approach of incorporating API RP 75 into the 
regulation and then rewords the requirements. Complicating these proven processes 
with additional prescriptive requirements may be detrimental to the overall 
implementation and will take away from the key elements of an integrity management 
system.” — Exxon Mobilb 
 
 a Comment on Proposed Rule (74 Fed. Reg. 1010-AD15), from Richard Morrison, BP, to MMS, 
(September 19, 2009). 
 b Comment on Proposed Rule (74 Fed. Reg. 1010-AD15) from Jonathan Armstrong, Exxon, to MMS 
(September 14, 2009). 

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from the event because Australia’s offshore regulatory standards were not as strong as those in the US.660 
The CSB observed that such statements from MMS offshore regulatory personnel made during interviews 
reflected an agency that was not attuned to learning best-practice lessons from other jurisdictions and 
lacked a broader continual learning philosophy aimed at major accident prevention and continued 
improvement. Rather, at the time of the Montara incident, MMS appeared to focus more on issues such as 
offshore production and oil and gas royalty revenue collection than on major accident prevention.661 Thus, 
notwithstanding Montara, it took the Macondo disaster to spur increased dialogue regarding safety 
management offshore in the US. 
History demonstrates that the broad lessons of Macondo were not new. While other regimes made drastic 
changes to their regulatory frameworks after major offshore accidents, it was not until the US had an 
accident in its own waters that change was spurred. In a break from the past, and in an effort to prevent 
similar incidents, the US offshore regulatory regime reorganized and introduced new safety regulations 
beginning in 2010 in the aftermath of Macondo. 
Two months after the Macondo incident, MMS was renamed the Bureau of Ocean Energy Management, 
Regulation and Enforcement (BOEMRE). On October 1, 2010, the revenue collection arm of the former 
MMS moved to its own office, the Office of Natural Resources Revenue.662 In October 2011, then-
Department of Interior Secretary Salazar created the Bureau of Ocean Energy Management (BOEM) and 
BSEE from the former BOEMRE.663 BOEM, with leasing responsibilities, and BSEE, with environmental 
and safety responsibilities,664 both report to the same Assistant Secretary for Land and Minerals 
Management, and the heads of these two bureaus still report to Secretary of the Interior.665 According to 
communications from former Secretary Salazar and the Department of the Interior, however, this 
restructuring had been intended to eliminate conflicts associated with the differing missions of promoting 
resource development, enforcing safety regulations, and maximizing revenue from offshore oil and gas 
development.666 
The reorganization was in line with the Presidential Oil Spill Commission’s recommendation to create 
“an independent agency within the Department of the Interior with enforcement authority to oversee all 
aspects of offshore drilling safety.”667 The Presidential Commission’s recommendation did not resolve the 
 
660 Ibid. 
661 U.S. Chemical Safety and Hazard Investigation Board interview of former MMS director, April 5, 2011. Issues 
included (1) an offshore renewable energy program, (2) five-year plans for offshore oil and gas production under 
the OCSLA, (3) environmental sensitivity analysis for the current five-year plan, and (4) ongoing issues about oil 
and gas royalty revenue collection. 
662 Fact Sheet, BSEE and BOEM Separation: An Independent Safety, Enforcement and Oversight Mission (January 
19, 2011). http://www.bsee.gov/uploadedFiles/BOEMRE%20Reorganization%20Fact%20Sheet(1).pdf (accessed 
March 26, 2016). 
663 Ibid. 
664 The US Coast Guard shares responsibility with BSEE for regulating safety and the environment offshore. 
665 Secretarial Order No. 3299 (May 19, 2010). 
666 BSEE. The Reorganization of the Former MMS. http://www.bsee.gov/About-BSEE/BSEE-
History/Reorganization/Reorganization/ (accessed March 26, 2016). 
667 National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling. Deep Water: The Gulf Oil 
Disaster and the Future of Offshore Drilling; 2011; Recommendation A4; p 256. Both the US Coast Guard 
(regulates safety of navigation and environmental protection on OCS units and vessels) and BSEE have shared 

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inherent problems associated with the Secretary of Interior’s continued responsibility for missions that 
often conflict with one another. The Department of the Interior retains offshore production and revenue 
collection authority. In addition, the various bureaus and services that compose the Interior Department 
are not independent agencies; each is part of a strict, hierarchical structure with the Secretary at the top of 
the pyramid.668 These line bureaus also operate only on delegated authority because the statutes they 
implement do not even mention the bureaus.669 Instead, final decision authority remains with the 
Secretary.670 
Once BSEE was created, the agency made an effort to increase its staffing and hire additional inspectors. 
According to former BSEE Director James Watson, between April 2010 and March 2012, BSEE 
increased its number of inspectors by 50 percent and its number of engineers by nearly 10 percent.671 In 
conjunction with changes to the regulatory body, new safety regulations were also established. The Safety 
and Environmental Management Systems (SEMS) rule is the new regulation through which BSEE 
oversees oil and gas offshore safety. Its stated purpose is to ensure safe operations on the OCS. In 
promulgating this regulation, BSEE stated that “requiring operators to implement SEMS will reduce the 
risk and number of accidents, injuries, and spills during OCS activities.”672 The final rule, issued in 
October 2010, incorporated by reference and made mandatory API RP 75(3rd edition). As a result, SEMS 
established requirements pertaining to 13 specific safety management elements, including hazard 
analysis, management of change, operating procedures, and training, among others.673 Any permissive 
language found in API RP 75 was also amended in the final version of the rule and made mandatory. 
 
responsibilities for safety regulation on the OCS. The two entities have a Memorandum of Agreement to establish 
a process for the identifying offshore safety and environmental management requirements within the jurisdiction 
of both agencies and to spur joint development of policies and guidance. See 
http://www.bsee.gov/uploadedFiles/BSEE/Newsroom/Publications_Library/BSEE-
USCG%20MOA_FINAL%20SIGNED%2004-30-13.pdf (accessed January 6, 2016). 
668 George Cameron Coggins and Doris K. Nagel, Nothing Beside Remains: The Legal Legacy of James G. Watt’s 
Tenure as Secretary of the Interior on Federal Land Law and Policy, 17 B.C. ENV’TL. AFF. L. REV. 473, 482 
(1990). 
669 Since the Secretary of the Interior created each bureau without presidential or congressional direction, the 
bureaus are operating through authority delegated to the Secretary, not to the head of the bureaus. Thus, the 
bureaus are purely creations of the Secretary of the Interior. 
670 George Cameron Coggins and Doris K. Nagel, Nothing Beside Remains: The Legal Legacy of James G. Watt’s 
Tenure as Secretary of the Interior on Federal Land Law and Policy, 17 B.C. ENV’TL. AFF. L. REV. 473, 482 
(1990). 
671 Watson, J. Statement of James Watson, Director Bureau of Safety and Environmental Enforcement United States 
Department of the Interior Committee on Appropriations Subcommittee on Interior, Environment and Related 
Agencies House of Representatives; March 7, 2012; 
http://www.bsee.gov/uploadedFiles/BSEE/Newsroom/Congressional_Testimony/Congressional%20Testimony%2
020120307.pdf (accessed March 26, 2013). Director Watson noted that there was still a considerable number of 
positions to be filled, including additional inspectors, engineers, regulatory specialists, and other disciplines. 
672 Oil and Gas and Sulphur Operations in the Outer Continental Shelf, 75 Fed. Reg. 63609 (Final Rule, October 15, 
2010) (to be codified at 30 C.F.R. Part 250). 
673 30 C.F.R. § 250, Subpart S (2011). 

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In April 2013, BSEE published additional safety provisions as amendments to SEMS. Informally called 
“SEMS II,”674 it provided additional requirements for stop-work authority and ultimate work authority, 
employee participation in developing and implementing SEMS programs, reporting unsafe working 
conditions, conducting independent third-party audits of operators’ SEMS programs, and performing job 
safety analyses (JSAs) for activities identified in an operator’s SEMS program. 
 
674 Oil and Gas and Sulphur Operations in the Outer Continental Shelf—Revisions to Safety and Environmental 
Management Systems, 78 Fed. Reg. 20423 (Final Rule, April 5, 2013) (to be codified at 30 C.F.R. Part 250). 

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By the 
 
U.S. Chemical Safety and Hazard Investigation Board 
 
 
 
Vanessa A. Sutherland 
 
 
Chairperson 
 
Manuel Ehrlich 
 
 
Member 
 
 
 
Rick Engler 
 
 
Member 
 
 
 
Kristen Kulinowski 
 
 
Member 
 
 
 
 
 
Date of Board Approval: April 17, 2016