Changing Direction: How Regulatory Agencies Have Responded to the Deepwater Horizon Oil Spill (Part I of II)
The Deepwater Horizon oil spill, also referred to as the BP oil spill, occurred on April 20, 2010 and is considered the largest marine oil spill in the history of the petroleum industry.  The enormous spill put the Gulf of Mexico’s ecosystem in crisis, releasing an estimated 4.9 million barrels of oil into the Gulf of Mexico, causing a decline in seafood catches, as well as deformities and lesions found in fish. The National Commission on the BP Oil Spill (the Oil Spill Commission) investigated the spill and condemned BP and its partners for a series of cost-cutting decisions and inadequate safety systems, highlighting that the spill resulted from “systemic” root causes and would happen again if significant reform in both industry practices and government policies did not occur.  The Commission further criticized the oil and gas industry’s widespread reliance on categorical exclusions from National Environmental Policy Act (NEPA) requirements as well as the lack of coordination and leadership by federal agencies during the response. Further, the Commission declared spill response capabilities had not improved since the Exxon Valdez spill in 1989. Most alarming, the Commission stated BP and its collaborators on the doomed well lacked a system to ensure their actions were safe.
The Commission’s report made it clear that the BP oil explosion was a disaster waiting to happen: Inadequate agency regulations combined with a lack of concern for proper safety created the ultimate ticking time bomb. Yet as the oil spill’s four-year anniversary approaches, questions remain as to what has been done to make sure another major disaster does not happen. Have drastic steps been taken to change the safety culture of offshore drilling, or has it been a return to the old status quo? Investment analysts report that 45 to 50 deep water drilling rigs could be operating in the Gulf of Mexico in 2014, a nearly 50 percent increase over the number of rigs drilling at the time of the BP-Deepwater Horizon disaster. Since the BP explosion, the U.S. government has made an effort to better regulate the offshore drilling industry. Yet this effort could be characterized as trivial at best, as there has not been a single new piece of offshore safety or environmental liability legislation passed by the U.S. government since the BP explosion.This paper will describe what steps have been taken by federal agencies to make offshore drilling safer and identify what more can be done to ensure another major disaster like the BP explosion does not occur. The following topics are discussed in the paper:
- An overview of the government safety regulations for offshore drilling before the BP oil disaster.
- A review of the federal government’s response to the BP oil disaster. Specifically, the creation of new agencies such as the Bureau of Ocean, Energy, Management, Regulation, and Enforcement (BOEMRE), Bureau of Ocean Energy Management (BOEM), and Bureau of Safety and Environmental Enforcement (BSEE), as well as each agencies respective powers and roles.
- A compare and contrast of what other national governments and foreign government agencies have done in regards to offshore drilling regulations.
- An analysis of what the major oil companies are doing on their own within the industry to make offshore drilling safer. How effective can self-regulation be?
- A proposal of ideal government regulations and agency review that would promote proper safety practice in offshore drilling.
II. Government Regulations Before the BP Oil Disaster
Before the Deepwater Horizon Oil Spill, the government agency tasked with regulating offshore oil exploration and drilling was the Minerals Management System, or MMS. The MMS was a bureau within the U.S. Department of the Interior (DOI). Charged with regulating an extremely sophisticated industry—an industry possessing some of the most complex technology available in the energy field—MMS never possessed the proper budget necessary to regulate effectively. While Outer Continental Shelf (OCS) leasing increased by 200 percent between 1982 and 2007, during that time period MMS staffing resources decreased by 36 percent. Such budget restraints clearly diminished the agency’s capacity to properly regulate the growing offshore oil and gas industry. For example, MMS employed around 60 inspectors to cover nearly 4,000 offshore facilities in the Gulf of Mexico. MMS inspections were infrequent, rarely unannounced, and often consisted almost entirely of verifying paperwork.
Lenient penalty statutes were another flaw in MMS’s failed regulation of the offshore drilling industry. The Outer Continental Shelf Lands Act was the main legislation used by MMS to regulate offshore drilling. OCSLA was enacted to promote and provide a framework for exploitation of the federal oil and gas resources on the OCS. OCSLA’s biggest flaw of was its penalty provisions, which were extremely weak and highly unlikely to deter risky conduct within a multi-billion dollar industry. Federal records show that despite chronic safety problems within the industry, MMS imposed paltry fines that often took years to collect.In the overwhelming majority of cases where workers were actually killed, there was no record of fines being paid by the workers’ employers to MMS. When fines did occur, the maximum penalty was only $25,000. In a 20-year period, MMS only fined the oil drilling industry $21 million dollars for hundreds of serious safety violations. That is roughly $1 million dollars in fines per year for an industry that made $800 billion in profits during that timeframe.
MMS’s insufficient fines highlight the biggest flaw in its regulation of the offshore drilling industry. Its budget may have been inadequate and its mandate out of date, but MMS’s biggest problem was agency capture. In 2008, MMS was caught in a scandal in which the Department of Interior’s inspector general found that regulators had “inappropriate relationships with industry that could compromise their objectivity.” Those inappropriate relationships allegedly included sharing alcohol at industry functions, using drugs, and sexual relationships between regulators and industry professionals.  The inspector general also characterized MMS as dependent on industry’s greater expertise with the technology of deepwater and ultra-deepwater drilling, and thus reliant on industry’s judgment of appropriate safeguards to incorporate in regulations. Essentially, the oil industry’s deep pockets gave it strong leverage over MMS decisions.
The three primary problems regarding MMS’s regulation of the offshore drilling industry—inadequate funding, inadequate penalties for serious violations, and agency capture—must be addressed if state and federal governments are to properly regulate the offshore drilling industry.
III. The U.S. Government’s Response to BP Oil Disaster
In response to the BP oil explosion, the federal government split MMS into three separate divisions: the Office of Natural Resources Revenues (ONRR) to manage revenues from all offshore and onshore mineral leases; the Bureau of Ocean Energy Management (BOEM) to manage offshore leasing and environmental assessments; and the Bureau of Safety and Environmental Enforcement (BSEE) to oversee offshore safety and environmental protection. The new tripartite structure did not fully meet the Oil Spill Commission’s recommendation of establishing an independent safety agency; however, it did provide a clearer division of responsibilities than did the previous structure by outlining exactly what is each agency’s respective role. Several months after the Deepwater Horizon spill, the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE), a successor to BOEM and BSEE, promulgated a rule requiring offshore drilling companies to implement Safety and Environmental Management Systems (SEMS) for oil and gas and sulfur operations on the Outer Continental Shelf. The rule was finalized on October 15, 2010, and incorporated by referencing the existing industry-developed voluntary management system known as API RP 75.
The Notice of Proposed Rulemaking (NPR) from BOEMRE proposed modeling the new SEMS after API RP 75, focusing on hazards analysis, management of change, operating procedures, and mechanical integrity. The final rule requires the operator (a lessee, owner or holder of operating rights, or the designated operator) to integrate a comprehensive SEMS program into the management of their OCS operations, providing for the prevention of waste and conservation of natural resources of the OCS. The rule aims to hold the operator accountable for the overall safety of the offshore facility, including ensuring all contractors and subcontractors have safety policies and procedures in place to support the operator’s SEMS program.
By making the previously voluntary SEMS mandatory, the Department of the Interior placed new requirements on industry’s shoulders. It is now the responsibility of management to ensure that SEMS is fully implemented as an integral part of operations. Operators must conduct a hazard analysis using a systematic approach to identify all potential safety and environmental risks and ensure that control measures capable of reducing the risks to an “acceptable” level are in place. The SEMS plan must include detailed provisions for management of change, standard operating procedures, and safe work practices. Companies have a duty to select contractors who have safe work practices and must ensure that all contractors are aware of the detailed operational procedures. Companies must provide ongoing safety training for staff. There must be procedures in place to ensure mechanical integrity of all equipment through testing and inspection. Companies must conduct a pre-startup review, essentially a checklist before new operations start or new equipment is used, ensuring that all factors such as emergency procedures and staff training are in place. 
The final four elements of the SEMS plan cover emergency response, accident investigation, audits, and recordkeeping. Companies must now develop full emergency response and control plans. They must ensure that incident investigations are conducted and recorded so as to capture learning about the causes of the incident to prevent future occurrences. Companies’ SEMS must be audited at least every three years by either an independent third party or qualified and designated employees, with an initial audit conducted two years after implementation. The company must notify BSEE at least 30 days prior to the audit so that BSEE may observe or participate if it wishes.
BSEE also has authority to conduct its own evaluations of a company’s SEMS or to require additional audits. If it finds shortcomings in the SEMS, BSEE may issue Incidents of Noncompliance, seek civil penalties, and/or disqualify the company from serving as an OCS operator. All SEMS documents must be kept for at least six years and made available to BSEE on request. In addition, companies must submit annual safety and environmental data to DOI, including details of injury and illness rates for employees and contractors, the number of EPA National Pollutant Discharge Elimination System (NPDES) noncompliances, and the number of spills over 42 gallons.
Among the most significant proposed amendments to SEMS are requirements that audits only be conducted by independent third parties, companies must show how employees are involved in the development of their SEMS, and employees will have the right to report violations to BSEE or request inspections without corporate retribution. The requirement for regular audits is important, but in order to be successful these audits must be conducted by independent auditors. Under the existing SEMS rule, employees as well as third parties may conduct audits. This is a weakness as these employees may be seen as acting on behalf of their respective employer. EMS should be revised to demand independent verification of compliance. BSEE’s proposal to limit the audit function to third parties should be adopted into the finale rule.
Independent verification of compliance is crucial because the evidence suggests management systems alone are unlikely to change practices or attitudes. There is a risk that SEMS will be a compartmentalized, paper process that companies do not consider or integrate in their daily operations. In order for the SEMS to be successful, they must carry a punishment for noncompliance. Unfortunately, BSEE has not made clear which outcomes it will assess as part of the SEMS audits and how it will go beyond merely checking that the SEMS paperwork is in place. Paperwork, without a genuine safety culture, will not reduce accidents or protect workers or the environment. Evidence indicates that API RP 75 was not widely followed by offshore companies when it was voluntary, thus, now that DOI is making the SEMS mandatory, they must provide strong incentives to follow the now mandatory requirements.
The new, mandatory SEMS are a step in the right direction; however, there are amendments and clarifications the DOI must make to help the SEMS achieve its goal of providing proper safety practices in the offshore drilling industry. BSEE’s new SEMS rules should (1) define the term “independent auditor” in the rule, (2) require the auditors be accredited, (3) require that senior corporate officers certify their companies’ SEMS programs subject to civil and criminal penalties, (4) establish clearer procedures for BSEE inspections, (5) define the term “effective” in the criteria for evaluating SEMS, (6) promote workforce involvement in implementation of and compliance with SEMS, (7) prohibit companies from penalizing workers who report non-compliance and/or (8) halt an operation in order to protect safety or the environment, and (9) require that companies identify plans for continual improvement of safety and environmental operations even when in compliance with applicable requirements.
On top of the new SEMS program, BOEMRE instituted many new permit requirements through formal notice-and-comment-rulemaking as well as less formal Notice to Lessees. Many of these new requirements appeared in the new “Drilling Safety Rule,” a largely prescriptive regulation that imposed tighter controls over the drilling process, such as requiring two independent barriers to flow paths and new BOP inspection and testing requirements and ROV capabilities. Operators are now required to obtain certification by a professional engineer of their drilling, casing, and cementing program to assure well integrity. Independent third-party certification was required to show that the blind shear rams in the BOP were capable of cutting any drill pipe in the hole.Another Notice to Lessees, NTL-5, required the Chief Executive Officer of every operating company certify on a one-time basis that his or her company was knowledgeable about and was in compliance with all existing offshore operating regulations and specifically listed four specific items requiring company review, including all well control equipment being used (especially BOPs and ROVs) and assurance that all personnel involved in well operations were properly trained and capable of performing their jobs under both normal and emergency conditions.
IV. Offshore Drilling Regulation in the United Kingdom and Brazil
The United Kingdom’s Safety Case is one of the models highlighted by the Oil Spill Commission as an example of a comprehensive risk-based approach to safety regulation. The Safety Case requires companies to identify all possible risks of the operation they plan to undertake and explain how these will be eliminated or reduced to an acceptable level. The Safety Case requires companies to demonstrate, to themselves first and to regulators second, that their operations will be safe. The regulations specify the acceptable level of risk but do not contain any prescriptive requirement except the use of good practice, which is required as a minimum. “Good practice” refers to standards which are developed by industry and recognized by the Health and Safety Executive (HSE), a quasi-autonomous non-departmental public body. Oversight of offshore safety sits with a specialized offshore division of HSE.A company’s Safety Case must be accepted by HSE before drilling operations can commence. Acceptance of the Safety Case does not mean HSE guarantees the safety of the rig. The duty to ensure safety remains with the operating company at all times. The Safety Case must be reviewed and resubmitted every five years, although it must be kept up to date at all times with the company making revisions in between the formal resubmissions in the event of any operational changes.
Safety Cases are prepared by either independent consultants or company employees in accordance with an elaborate set of guidelines mandating that each document address in detail such disparate topics as: (1) procedures for controlling risks, (2) the selection and training of key personnel, (3) installation of preventive technologies such as emergency cut-off equipment, (4) procedures to control higher-risk events such as change of shifts, design, or production goals, (5) the operating firm’s control over the activities of subcontractors, and (6) how the entire crew of a given facility should respond in an emergency.
The Safety Case regime contains at least three enforcement mechanisms. First, there are traditional inspections conducted by HSE, which is well-resourced agency. Second, independent third-party audits are required for “safety-critical elements” of the specified plant. Industry publishes detailed guidance on such audits. Third, workforce representatives are directly elected in secret ballots by workers and have the authority, inter alia, to inspect rigs, investigate complaints, report risks to HSE and represent the workforce in dealings with HSE. An independent review of the Safety Case regime, commissioned by the British government after Deepwater Horizon, found that the combination of these three elements was one of the strengths of the Safety Case.
The Safety Case appears to have helped create a systematic approach to risk assessment within the industry and may have sparked technological improvements. Some evaluations find that it encourages industry to innovate and spread best practices. The Safety Case emphasizes the benefits of formalized workforce involvement and, in particular, the authority delegated to the safety representative, in improving a company’s safety culture. Workforce safety representatives must be provided with training paid for by the company and be consulted on various matters including preparation of the Safety Case and the design of workforce safety information and training. Companies must give safety representatives paid leave to carry out their functions and provide them the facilities and information they require.  However, the review noted that the effectiveness of the representatives was dependent on companies providing sufficiently detailed training to provide the representatives with a high level of knowledge of operational hazards and risk management practices. 
While the Safety Case is not a perfect regulatory program, it is a highly successful one. The Safety Case improved offshore drilling safety by requiring operators to thoroughly analyze and understand specific risks before commencing operations. It uses independent third-party audits of critical equipment and processes, conducting a large number of inspections by a well-trained and well-resourced government agency, where inspections are paid for by industry. The Safety Case has a strong and formalized role for workforce involvement including appointment of Workforce Safety Representatives who themselves have powers of inspection, providing effective data collection and reporting, and combining a cooperative approach with the threat of criminal sanctions. These regulatory practices, especially the independent third-party audits, industry-paid inspections, and criminal sanctions for noncompliance, should be practiced by federal agencies in the United States to ensure proper safety practices.
The Safety Case squarely places the duty on the operator to assure safety. The regulator merely “accepts” rather than “approves” the safety case submitted to it, and the operator’s duty is to continuously assess risks as condition change and adapt operations to new conditions. As the President of U.S. operator Apache Corporation put it:
“There’s no excuse for you if things go wrong because you are the one who wrote the plan. It’s harder on the well operator, it requires you to write the rules and figure out the chance of this happening or that. It makes you plan very well, makes you look at every aspect of what could potentially happen out there.”
The Apache President went on to say the industry needed a change regarding risk assessment and safety problems, and in his opinion the Safety Case program had a better chance of protecting the environment and people’s lives.
Unfortunately, the weaknesses of the government agencies tasked with regulating offshore drilling likely prevents the U.S. from adopting a system similar to the United Kingdom’s Safety Case. Resource restraints currently plague BOEMRE. At the moment it has approximately 55 to 60 inspectors to cover 3,500 offshore facilities. Thus, wholesale adoption of the Safety Case regime will prove an expensive and negative distraction to American efforts to strengthen regulation offshore. Another feature of the Safety Cases that would prove difficult to implement in the U.S. is confidentiality. No one except the consultants, top level management, the assigned agency official, and a worker representative is allowed to see the finished documents in its entirety. This level of secrecy is the exact opposite of what U.S. offshore regulation needs. In order for American agencies to properly regulate and enforce restrictions on the oil and gas industry, there must be complete transparency throughout the industry on all infractions that occur.
Another issue preventing a program like the Safety Case from being implemented is the conflicting values in law between the U.S. and the U.K.. While the fundamental principles of British and American worker protection laws are superficially similar (agencies are instructed to balance anticipated risks against the costs of reducing them), these mandates have produced a pervasive reliance on quantitative risk assessment in both countries. Yet when implemented in the context of offshore regulation, these surface similarities diverge in two key respects. Procedurally, the British are willing to delegate to industry the role of performing quantitative risk assessments on individual facilities, while American regulators generally conduct their own analyses and apply them in the context of industry-wide rulemaking.Substantively, the British are willing to tolerate a risk standard of “as low as reasonably practicable.” This standard is interpreted as one in 1,000 deaths and a value of $1,000,000 per life as the minimum levels of risk to be tolerated. This standard is significantly less protective than what American regulators, instructed by court decisions, are allowed to accept.
Instead of setting a numerical metric as a risk standard similar to the United Kingdom, U.S. regulatory agencies rely on verbal formulations that are vague and leave industry personnel clueless as to what is a risk and what is an acceptable level of protection. For example, the leading judicial interpretation of the level of protections required by the OSH ACT is the Benzene decision set forth in AFL-CIO v. American Petroleum Institute. The Benzene decision refused to establish a bright-line rule for “significant risk” and the court did not believe risk levels needed to be measured by numeric formulations. Rather, the AFL-CIO court held that to prevent a significant risk, an agency should adopt rules that are “reasonably necessary or appropriate” using the “best available evidence” to answer that “to the extent feasible” that “no employee will suffer material impairment of health of functional capacity.” Such vague terminology may be helpful for agencies, which prefer broad discretion in carrying out their duties, but for industry leaders, it can be difficult to ascertain which practices are safe and which risk violating laws and regulations when there is no formula to follow. Without such clear, measurable standards established for operators to follow, the U.S. will never be able to establish a sufficient agency such as the U.K’s safety case.
Brazil is another foreign market whose offshore drilling regulations should be closely monitored. Brazil has only recently opened up its oil industry to private and foreign investment, as it had a legal monopoly on its oil industry until 1997. However, one former National Petroleum Agency (ANP) employer labeled Brazil’s new oil policy as “nationalist and populist.” Brazil’s stance on foreign drilling was exemplified by its reaction to a small leak off the coast of Rio de Janeiro caused by a sudden rise in pressure. The Brazilian Institute of the Environment (IBAMA) fined Chevron $28 million for the 3,000 barrel leak, as well as a further $10 million for poor contingency planning. ANP, Brazil’s industry regulator, closed one of Chevron’s oilfield wells and suspended the firm’s drilling rights. The Rio de Janeiro state government is suing for $150 million; federal prosecutors are demanding $20 billion in punitive damages while also seeking an injunction to halt all further operations in Brazil by Chevron; and federal police want to bring criminal charges against the company.
Brazil’s harsh penalties on Chevron may come across as strict regulations in the post-Horizon world, but one former ANP director claims the Chevron spill shows just how unqualified IBAMA and ANP are in overseeing safety and accident prevention in the offshore drilling industry. While IBAMA and ANP set steep requirements for foreign companies to drill in Brazilian waters and hand out harsh penalties for companies responsible for a spill, IBAMA and ANP do not take the necessary proactive measures to help ensure a spill does not occur. IBAMA is in charge of awarding licenses to potential operators as a condition prior to activities using natural resources. Petroleum operators require three licenses: Previous License, which is mandatory for the activities of drilling and production tests; Installation License, which is mandatory for the development activities for the new fields and for the installation of new equipment for fields that are already in production; and Operation License, which is mandatory for seismic production activities. An environmental study is required for seismic operations.While such licensing requirements are a positive measure in ensuring proper drilling practices are being conducted, IBAMA appears to ease up on its regulations once the licenses are handed out.
One of ANP’s positive practices is the requirement that oil companies wishing to drill off the Brazilian coast must participate in a public bidding process established under the Petroleum Law. Submitted bids must provide the following: (a) description of the blocks being offered and estimated period for exploration to be fulfilled by the interested companies and the conditions for qualification of these companies; (b) the requirements to be fulfilled by the interested companies and the conditions for qualification of these companies, as well as (c) the minimum government and land owner responsibilities. The bids must survive multiple bidding rounds, and companies that successfully win drilling bids are then likely to be subjected to unitization. If unitization is necessary for a particular field, the concessionaries will first seek to reach a mutual agreement and present a unitization plan to the ANP for approval. The process of unitization can be quite difficult and contentious. Whereas members of a consortium bidding for oil and gas properties have had the opportunity to establish their internal rights and governance pursuant to the terms of a joint operating agreement or joint bidding agreement when evaluating whether to proceed with a particular investment, parties subject to a unitization plan typically have no choice.
As demonstrated by the Chevron example, Brazil’s main focus in regulating the offshore drilling industry is holding foreign operators fully responsible for any environmental harm they may cause. In wake of the BP oil spill, Brazil’s environmental agency and navy drafted a national contingency plan for responding to offshore oil spills to complement a federal law enacted in 2000 that made operators on Brazil’s offshore platforms responsible for spill prevention and clean-up.
Preferred Citation: Stuart Theriot, Changing Direction: How Regulatory Agencies Have Responded to the Deepwater Horizon Oil Spill, LSU J. Energy L. & Res. Currents (November 19, 2014), http://sites.law.lsu.edu/jelrblog/?p=506.
 Campbell Robertson & Clifford Krauss, Gulf Spill is the Largest of its kind, Scientists Say, N.Y. Times.Aug. 2, 2010, at http://www.nytimes.com/2010/08/03/us/03spill.html?_r=0
 Deep Water: The Gulf Oil Disaster and the Future of Offshore Drilling, National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling, Report to the President 127, 167, 174-83 (2011) [hereinafter Nat’l Comm’n Report]; Brain Skoloff & June Wardell, BP Oil Spill Cost Hits $40 Billion, Company Returns to Profit, Huffington Post Green (Nov. 2, 2010, 8:57 AM) http://www.huffingtonpost.com/2010/11/02/bp-oil-spill-costs-hit-40_n_777521.html.
 Doug Hastings et al., Recommendations for Improved Oversight of Offshore Drilling Based on a Review of 40 Regulatory Regimes, Emmett Environmental Law & Policy Clinic, Harvard Law School: Environmental Law Program (June 25, 2012) http://blogs.law.harvard.edu/environmentallawprogram/files/2013/10/Offshore-Drilling-White-Paper-FINAL_revised-10-2-13.pdf.
 Nat’l Comm’n Report, supra note 3, at vii, 56, 62, 67-68, 132-39.
 Jacqueline L. Weaver, Offshore Safety in the Wake of the Macondo Disaster: Business as Usual or Sea Change?, 36 Hous. J. of Int’l L. 147, 148(2014).
 Id. at 152
 Alyson C. Flournoy, Three Meta-Lessons Government and Industry Should Learn From the BP Deepwater Horizon Disaster And Why They Will Not, 38 B.C. Envtl. Aff. L. Rev. 281, 296 (2011).
 Oil and Gas Management: Key Element to Consider for Providing Assurance of Effective Independent Oversight: Hearing on The Deepwater Horizon Incident: Are the Minerals Management Service Regulation Doing the Job? Before the Subcomm. on Energy and Mineral Resources, 111th Cong. 3 (2010) (statement of Frank Rusco, Director, U.S. Govt’t Accountability Office).
 Mark Clayton, BP Oil Spill: MMS shortcomings include ‘dearth of regulations. The Christian Science Monitor (June 17, 2010), http://www.csmonitor.com/USA/Politics/2010/0617/BP-oil-spill-MMS-shortcomings-include-dearth-of-regulations.
 Flournoy supra note 8, at297.
 Flournoy, supra note 8, at 296.
 Pierre Thomas, Offshore Drilling: Years of Lax Oversight, Small Fines for Serious Violations, ABC News, Jun. 24, 2010, http://abcnews.go.com/WN/oil-spill-mms-offshore-drilling-regulation-small-fines/story?id=11003043.
 Juliet Eilperin, “Birnbaum ‘took fall’ after MMS played catch-up after lapses in ethics, oversight.” http://www.washingtonpost.com/wp-dyn/content/article/2010/05/28/AR2010052804855.html?sid=ST2010052805077,
 Flournoy, supra note 8, at, 297.
 Weaver, at 154
 Hastings et al., supra note 4, at 12.
 Oil and Gas and Sulphur Operations in the Outer Continental Shelf—Safety and Environmental Management Systems, 75 Fed. Reg. 63,610 (Oct. 15, 2010); 30 C.F.R. 250.
 30 C.F.R. § 250.1909-10 (2010).
 30 C.F.R. § 250.1911-17 (2013).
 30 C.F.R. § 250.1924-28 (2013).
 30 C.F.R. § 250.1918 (2014).
 30 C.F.R. § 250.1919 (2014).
 30 C.F.R. § 250.1918-20 (2013).
 Hastings et al., supra note 4, at 32.
 Oil and Gas and Sulphur Operations in the Outer Continental Shelf—Revisions to Safety and Environmental Management Systems, 76 Fed. Reg. 56,683 (Sep 14, 2011) (to be codified at 30 C.F.R. pt. 250).
 Andrew Hartsig, “Shortcomings and Solutions: Reforming the Outer Continental Shelf Oil and Gas Framework in the Wake of the Deepwater Horizon Disaster”, 16 Ocean & Coastal L.J. 269, 306 (2011).
 Neil Cunningham, Integrating Management Systems and Occupational Health and Safety Regulations, 26 J. Law & Soc. 192, 196-200 (1999).
 See Safety and Environmental Management Systems for Outer Continental Shelf Oil and Gas Operations, 74 Fed. Reg. 28,639 (June 17, 2009) (to be codified at 30 C.F.R. pt. 250).
 Weaver, supra note 6, at 175.
 Id. at
 Id. at
 See generally Principles and Guidelines to Assist HSE in its Judgments that Duty-Holders Have Reduced Risk as Low as Reasonably Practicable, Health and Safety Executive (Dec. 13, 2001), http://www.hse.gov.uk/risk/theory/alarp1.htm ; Assessment Principles for Offshore Safety Cases, Health and Safety Executive (March 2006) http://www.hse.gov.uk/offshore/aposc190306.pdf (for offshore Safety Cases specifically).
 Assessing Compliance with the Law in Individual Cases and the Use of Good Practice, Health and Safety Executive (June 17, 2003) http://www.hse.gov.uk/risk/theory/alarp2.htm.
 Non-departmental public bodies (NPDB) differ from executive agencies as they are not created to carry out ministerial orders or policy, instead they are more or less self-determining and enjoy greater independence. NDPBs are established under statute and are accountable to Parliament rather than to Her Majesty’s Government.
 A Guide To The Offshore Installations (Safety Case) Regulations 2005 page 10: Guidance on Regulations; www.hse.gov.uk/pubns/priced/130.pdf
 Id at 29.
 Flournoy, supra note 8, at 296.
 Geoffrey Maitland et al., Offshore Oil and Gas in the UK: An Independent Review of the Regulatory Regime 3, 85-86 (2011) available at https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/48252/3875-offshore-oil-gas-uk-ind-rev.pdf.
 Vectra Group Limited, Literature Review on the Perceived Benefits and Disadvantages of UK Safety Case Regimes 19-21 (Aug. 2003) http://www.hse.gov.uk/research/misc/sc402083.pdf (commissioned by HSE)(covering all industries-not just offshore-subject to Safety Cases and using a small number of interviews to obtain industry views on the regimes).
 A Guide to the Offshore Installations Safety Representatives and Safety Committees Health and Safety Executive (2012) http://www.hse.gov.uk/pubns/priced/I110.pdf at 17
 Maitland at 69-72.
 Weaver, supra note 6, at 193.
 Flournoy, supra note 8, at 281-303, 296.
 Indus. Union Dep’t., AFL-CIO v. American Petroleum Inst., 448 U.S. 607, 621 (1980).
 Flournoy, supra note 8, at 281-303, 295.
 Indus. Union Dep’t., 448 U.S. at .642
 Id. at 612.
 Continue reading for a more detailed discussion on clear and measurable goals.
 Oil, Water and Trouble; Chevron and Brazil’s Oil Industry, The Economist, Dec. 2011, at 23.
 Marilda Rosado de Sa Ribero, The New Oil and Gas Industry in Brazil: An Overview of the Main Legal Aspects, 36 Tex. Int’l L. J. 141, 157 (2001).
 Lei No. 9.478 de 6 de Agosto de 1997, Diário Oficial da União [D.O.U.] de 07.08.1997, arts 23, 36 (Braz.).
 Steven P. Qtillar et al, Recent Developments in Brazil’s Oil & Gas Industry: Brazil Appears to be Stemming the Tide of Resource Nationalism, 30 Hous. J. Int’l L. 2, (2008).
 Unitization provides for the exploration and development of an entire geologic structure or area by a single operator so that drilling and production may proceed in the most efficient and economic manner.
 Qtillar, supra note 66, at 263.
 Gary D. Libecap & James L. Smith, The Economic Evolution of Petroleum Property Rights in the United States, 31 J. Legal Stud. 589, 606 (2002).
 Micheal Kepp, Brazil Perfecting Oil Spill Contingency Plans in Wake of BP Accident in Gulf of Mexico, Daily Rep. for Executives, June 21, 2010, at A12.