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Home My WebLink AboutBinders 27, 28, 30, 32-3427. University of California, Berkeley — National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling — November 2010 28. Approval Requirements for Subsea Blowout Preventer (BOP) or Surface BOP 30. UK House of Commons, Energy and Climate Change Committee, UK Deepwater Drilling — Implications of the Gulf of Mexico Oil Spill, web published 01/06/2011 32. Noetic Solutions Review of PTTEP Australia's Response to the Montara Blowout — November 2010 33. Statement by the Minister for Resources and Energy — February 2011 34. Department of Resources, Energy and Tourism Deed of Agreement — February 2011 • UNIVERSITY OF CALIFORNIA, BERKELEY _ Py`tY• F�� C BERKELEY • DAVIS • IRVINE • LOS ANGELES • MERCFD • RI\'l?RSIDI. • S:\\ DIEGO • SAN HR kNCIS(A) p{�;w� o� SANTA BARBARA • SANTA CRUZ w of s� .� lase• Center for Catastrophic Risk Management Department of Civil and Environmental Engineerir 212 McLaughlin Hall Berkeley, California 94720-1710 Tel: (510) 642-0960 ce. berkeley. edu November 24, 2010 Robert Professor Robert Bea, Ph.D., P.E. Deepwater Horizon Study Group Tel: (510) 643-8678 Fax: (510) 643-8919 bea@ce.berkeley.edu ccrm. berkeley. edu National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling 1 Thomas Circle, N.W. Washington, D.C. 20005 Dear Commissioners: The Deepwater Horizon Study Group submits these comments on the Commission's preliminary technical and managerial conclusions presented on November 8 and 9, 2010. In light of these conclusions and our analyses related to the Deepwater Horizon explosion and fire during the past seven months, we provide specific recommendations to help ensure that future offshore drilling in "new frontier" areas will operate within acceptable levels of risks. • The Deepwater Horizon Study Group, formed in May 2010, is organized under the auspices of the Center for Catastrophic Risk Management at the University of California, Berkeley. It is comprised of more than 60 experienced professionals, experts, and scholars in the fields of offshore drilling and operations, geology, accident investigations, organizational management, governmental regulatory affairs, system safety and reliability, risk assessment and management, marine ecology, environmental science, and law. As noted in the attached comments, the Study Group concurs with the correctness of the Commission's technical findings related to the now path, cement failures to isolate the hydrocarbons, inappropriate reliance on inadequate negative pressure tests, and the additional risk created by BP's temporary abandonment procedures. We agree with the Commission that any technical conclusions related to the role of the blowout preventer should await further forensic testing of the equipment. The Study Group does not conclude those who worked on the Deepwater Horizon Macondo well project made conscious `well informed' decisions to trade safety for money. Analysis of the available evidence indicates that when given the opportunity to save time and money — and make money — tradeoffs were made for the certain thing — production — because there were perceived to be no downsides associated with the uncertain thing — failure caused by the lack of sufficient protection. Thus, as a result of a cascade of deeply flawed failure and signal analysis, decision -making, communication, and organizational - managerial processes, safety was compromised to the point that the blowout occurred with catastrophic effects. The oil and gas industry is embarking on an important "next generation" series of exploration and production operations in the ultra -deep waters of the Gulf of Mexico, the remote waters of • the Arctic, and other new frontier areas. Oil and gas development will continue to pose risks, with concurrent likelihoods and consequences of catastrophic failures, that are several orders of magnitude greater than previously confronted by regulators, the industry, and society. The CCRM Deepwater Horizon Study Group 1 November 24, 2010 • special conditions for minimizing the likelihood of the worst -case scenario and for minimizing its impacts if it does occur. 3. Worker Safety and Health - Priority should be given to resolving current uncertainties regarding regulatory and inspection roles of BOEMRE and the U.S. Coast Guard for worker safety and health and to enacting a process safety management rule with provisions for change management, as similar to OSHA's process safety management rule for onshore oil and gas operations. In assuming responsibilities for worker safety and health, BOEMRE should enact workplace safety and health regulations that are integrated with and reinforce its accident prevention requirements, and not assume that accident prevention requirements alone provide sufficient protection for worker safety. 4. Stop Work Authority - BOEMRE should require by rule that a worker safety representative be appointed at each installation to participate in operational decisions and be empowered to suspend operations when the representative believes in good faith that continuation of operations would imminently endanger worker safety. These are key features of proven value in the Norwegian regulatory approach to offshore safety. 5. Safety and Environmental Management System (SEMS) - BOEMRE's new SEMS rule marks the first time that a federal agency will directly regulate the structure and core functions of the safety management system of an offshore operator. The SEMS rule mandates operator fulfillment of eleven broadly stated safety management functions, as well as compliance with other self -auditing, documentation, and reporting requirements. The rule also explicitly requires operators to implement and to comply with standards and practices • developed by the American Petroleum Institute (API) and other standard -setting organizations or risk regulatory enforcement action for noncompliance. This new approach raises several issues that need to be addressed by BOEMRE: a) Given that each company's fulfillment of the functional, performance -based requirements will be based, in part, on consideration of the special features of its operation, and thus differ in several respects from what other companies do for compliance, BOEMRE needs to ensure that each company's compliance with SEMS affords equivalent protection for workers and the environment. b) The current checklist approach to inspection, whereby relatively inexperienced inspectors police companies for potential incidents of noncompliance with prescriptive technical standards and rules, is inadequate for evaluating compliance with the broadly -stated functional requirements of the SEMS rule. Therefore, BOEMRE needs to ensure that inspections pursuant to the SEMS rule are conducted by highly qualified personnel capable of fully evaluating companies' efforts to meet the performance -based functional requirements and capable of offering regulatory guidance, as necessary. c) BOEMRE also must ensure that the safety standards and recommended practices relied upon by companies for compliance with the SEMS rule, such as those defined by the American Petroleum Institute (API) and other standard -setting organizations, are qualitatively sufficient in terms of the technical state of the art and are not compromised by the economic interests and lobbying activities of the membership of these standard - setting organizations. Because the procedures used by such organizations for developing standards and recommended practices are not transparent, nor do the procedures generally • permit access by non -industry stakeholders, BOEMRE should also conduct transparent "regulatory forums" in which existing and proposed standards and best practices related to the SEMS rule are discussed with participation by non -industry stakeholders. CCRM Deepwater Horizon Study Group 3 November 24, 2010 • Deepwater Horizon Study Group Members Thomas Azwell, Doctoral Student, Anthony Hare, Psy.D., Executive Researcher, Department of Director, Center for Catastrophic Risk Environmental Science, Policy, and Management, University of California Management, University of California, Berkeley. Berkeley. Samantha Joye, Ph.D., Professor, Michael Baram, LL.B., Professor Department of Marine Sciences, Emeritus, Boston University Law University of Georgia School, Boston, Massachusetts. Jahon Khorsandi, M.S.E., Graduate Robert G. Bea, Ph.D., P.E., Professor, Student Researcher, Center for Department of Civil and Environmental Catastrophic Risk Management, Engineering, University of California, University of California, Berkeley. Berkeley. Kennith Kotow, P.E., Senior Associate, Michael J. Blum, Ph.D., Arnold Early Successful Energy Practices Career Professor in Earth and Ecological International, San Antonio, Texas. Science, Department of Ecology and Evolutionary Biology, Tulane Trevor A. Kletz, D.Sc., Visiting University, New Orleans, Louisiana. (Adjunct) Professor, University of Loughborough, United Kingdom. K. Florian Buchler, LL.M., Attorney at Law (Germany), Tulane University, Sindhu Kubendran, B.S., Research Buehler & Co., New Orleans, Louisiana. Associate, University of California, Berkeley. W. E. Carnes, M.A., B.S., Practitioner Associate, Center for Catastrophic Risk Kevin Lacy, B.S., Petroleum Management, Haas School of Business, Engineering, M.B.A., Senior Vice University of California, Berkeley. President, Global Drilling and Completions, Talisman Energy, Calgary Paul Donley, Corporate Trainer, Alberta, Canada. Programer, Web Developer, Relevant Training, Melbourne, VIC Australia Artin Laleian, Student, Research Associate, University of California, Yngvar Duesund, Special Advisor to Berkeley the Center for Information Technology Research in the Interest of Society, The Gary Marsh, B.S.M.E., Retired, Shell Banatao Institute—CITRIS, University Drilling Engineering Advisor, Houston, of California, Berkeley. Texas. William E. Gale Jr., Ph.D., P.E., CSP, Wayne Needoba, B.S., P.E., Consultant CFEI, CFII, Forensic Engineering on Drilling, Project Coordination, Consultant, President, William E. Gale, Learning, Competence Assessment, Jr., Inc.; Principal, Bundy, Gale & Labrador Holdings WA, Perth, Western Shields LLC, Novato, California. Australia; Managing Director, LIS Thailand Co., Chiang Mai, Thailand. Ove T. Gudmestad, Ph.D., Professor, of Science and Technology, is University of Stavanger, Stavanger, University Norway. CCRM Deepwater Horizon Study Group 5 November 24, 2010 • APPENDIX A Deepwater Horizon Study Group Center for Catastrophic Risk Management at the University of California, Berkeley Commentary on National Commission Investigators' Preliminary Technical & Managerial Conclusions of November 8 and 9, 2010 TECHNICAL CONCLUSIONS Conclusion: Flow path was exclusively through shoe track and up through casing. Comment: This mode of failure was one of the two primary modes of failure analyzed by the DHSG.' The evidence available at this time indicates the flow path through the bottom casing assembly and cement is the most plausible mode of failure that led to the blowout. The physical evidence of the recovered casing head seal assembly, the failed negative pressure test, and the post -hoc analysis of the cement slurry test data conducted by Chevron support this as the most likely flow path scenario. Alternatively, if the flow path did not develop through the shoe track and up thorough the casing, it could have developed up the outside of the long -string production casing (channeling through fractures in the failed cement), flowing up the annulus and to the production casing hangar at the seafloor. Expanding hydrocarbons could have found their • way into the riser through the unsecured casing hangar at the seafloor due to pressures in the annulus; however, the absence of external erosion and damage on the outside of the casing hanger seal assembly and its orifices does not support this alternative hypothesis. Another low probability leak path into the production casing bore could have been a breach developed in one of the slim -line production casing connections. A vulnerability was created by not cleaning, inspecting, and then protecting metal -to -metal seals in the casing connections when they were deployed. Conclusion: Cement (potentially contaminated or displaced by other materials) in shoe track and in some portion of annular space failed to isolate hydrocarbons. Comment: The available evidence indicates the "experimental" nitrogen foamed cement, the pre- and post- cementing processes (e.g. partial bottoms up circulation, positive pressure testing before cement cure), the hardware used near and at the bottom of the long -string production casing (e.g. minimum centralizers, float collar and shoe, the characteristics of the well at the bottom (e.g. clearance between production casing and weak formation, clearance between the bottom reamer and the bottom of the well — the "rat hole"), and the reservoir characteristics (high pressures, high temperatures, gaseous hydrocarbons, relatively weak formation) all contributed to failure of the cement near and at the bottom of the Macondo well.2 ' G.L. Marsh, "Analysis of MC 252#1 Well Blowout, DHSG Working Paper. 2 G.L. Marsh, "Cementing 7" x 9-7/8" Production Casing at MC 252#1 Well, DHSG Working Paper. CCRM Deepwater Horizon Study Group 1 November 24, 2010 • `latent defects' so they can be remediated before they are activated to help cause failures.6 Conclusion: Negative pressure test(s) repeatedly showed that primary cement job had not isolated hydrocarbons. Despite these results, BP and Transocean treated negative pressure tests as a complete success. Comment: This experience provides a classic example of tests and the analyses of those tests developing `false positives.' The combination of the signals or data provided by the test and the analyses of those tests falsely indicates there is no significant likelihood of failure in the well structure. This type of `system' failure involves a combination of factors emanating from the operating teams, their organizations, the hardware (e.g. instrumentation, data displays, communications), procedures (formal, informal), environments (external, internal, social), and interfaces among the foregoing.' The information exists, but is not properly accessed and evaluated, or if it is properly accessed, it is not properly understood (unknown knowable). There are a wide variety of reasons for such `cognitive' (thinking, sensemaking) malfunctions. One of the most important is `conformational bias' — what we see and think is what we expect to see and want to think (wishful thinking). It is debatable whether the cement job ever had a chance to achieve isolation given the large pressure reversal from the top stray zones to the bottom — what is not debatable is understanding the risk of actually executing a successful cement job — and planning remedial measures accordingly. 0 Conclusion: BP's temporary abandonment procedures introduced additional risk Comment: The revised temporary abandonment procedure was proposed to the MMS on April 14, 2010 and approved by the MMS on the same day. Additional changes were made, all of which added to the risks associated with the temporary abandonment procedure. The available evidence and testimony indicates the temporary abandonment procedure had several parts that were of major concern to the Transocean drill crew and Offshore Installation Manager. The revised temporary abandonment procedure was introduced in the final days of completing the drilling of the Macondo well. The temporary abandonment procedure involved major changes from completing the well as an exploratory well to completing it as a production well as the Commission investigators clearly documented in their Master Presentation. Such modifications were made to expedite `early production' from the prolific hydrocarbon formations that had been discovered at this location. The temporary abandonment procedure was designed to make the completion activities more efficient (save time and money) by `early' displacement and offloading of the drilling mud and running of an all -in -one tapered casing string extending from the bottom ' R.G. Bea, "Risk Assessment and Management: Challenges of the Macondo Well Disaster," Y. Duesund and O.T. Gudmestad, "Deepwater Well Design, Competency — Management of Risks," D.M. Pritchard and K. J. Kotow, 'The New Domain in Deepwater Drilling: Applied Engineering and Organizational Impacts on Uncertainties and Risk," D.M. Pritchard and K. Lacy, "Deepwater Well Complexity — The New Domain," J.E. Skogdalen, I.B. Utne, J.E. Vinnem, • "Looking Back and Forward: Could Safety Indicators Have Given Early Warnings About the Deepwater Horizon Accident?," D.M. Pritchard, 'Targeting Problematic Deepwater Drilling Operations," DHSG Working Papers, 2010. ' R. G. Bea, "Risk Assessment and Management: Challenges of the Macondo Well Disaster," "Managing Rapidly Developing Crises — Real -Time Prevention of Failures," DHSG Working Papers, 2010. CCRM Deepwater Horizon Study Group 3 November 24, 2010 • alarms that had been installed on the Deepwater Horizon to provide data on important parts of the operations were not `coordinated,' `displayed,' or in some cases, such as the general alarm and a critical flow sensor for the final part of the displacement, bypassed. Direct and unambiguous information on volume of fluids going into and out of the well was not readily available. With multiple distractions and ambiguous data difficult to analyze, the crew was not able to detect, analyze, and effectively react to the developing blowout. Analyses of past accidents repeatedly have shown the `perils of parallel processing' at critical times and places in operations. The simultaneous oil and gas production operations and critical maintenance operations prior to the failure of the Occidental Petroleum Piper Alpha platform in the North Sea, and the simultaneous operations carried out onboard the bridge of the Exxon Valdez tanker as it was departing outside the approved shipping lane in Prince William Sound are prime examples of the perils of parallel processing. While each of these simultaneous operations can be `safe', it is their unexpected and unmanaged interactions and distractions at critical times and places that can provide the impetus for catastrophic failures. Conclusion: Nevertheless, kick indications were clear enough that, if observed and recognized, these warnings would have allowed the rig crew to have responded earlier. Comment: In hindsight, it is evident that the well was in the process of `kicking' for almost an hour before it actually blew out. Yet, no one on the rig noticed the evolution until sea water was blown to the top of the drilling derrick, followed quickly by a stream and shower of oil drilling mud, followed by gas and oil that spread across the decks of the • Deepwater Horizon. Early detection of the symptoms of a potential crisis situation is critical so that more time is available to analyze and understand those symptoms, analyze alternatives for corrective action, and then implement the alternative or alternatives that can rescue the system. The available evidence indicates that those on the Deepwater Horizon that night were confident that the well was secure and that all was going just fine. They would be wrapping up this "well from hell" in a few hours, moving the rig to a new location, and going home for a much deserved break. The evidence indicates that vigilance and preparations to handle crisis had turned to complacency in the haste to wrap up the Macondo well and move on to another offshore project. Conclusion: Once the rig crew recognized the influx, there were several options that might have prevented or delayed the explosion and/or shut in the well. Comment: As acknowledged by the Commission investigators, once portions of the rapidly expanding gas and hydrocarbons were in the riser, it was too late to prevent the gas and hydrocarbons from reaching the drill deck. When the gas and hydrocarbons reached the drill deck, immediate activation of the emergency shut down systems for ventilation and diversion of the gas and hydrocarbons directly overboard could possibly have prevented the explosions and fires. Unfortunately, the emergency shut down on ventilation systems apparently had been put on `inhibit mode' requiring human activation that came too late. Because the large hydrocarbon influx was not detected in earlier stages, the closing of the annular BOP may have been "too little and too late". • The decision was made on the drill floor (perhaps days or weeks before) to divert the well flow to the "poor -boy" mud gas separator that could not handle the flow pressures and CCRM Deepwater Horizon Study Group 5 November 24, 2010 Conclusion: No evidence at this time to suggest that there was a conscious decision to sacrifice safety concerns to save money. Comment: Analysis of the available evidence indicates that when given the opportunity to save time and money — and make money — tradeoffs were made for the certain thing — production — because there were perceived to be no downsides associated with the uncertain thing — failure caused by the lack of sufficient protection. Thus, as a result of a cascade of deeply flawed failure and signal analysis, decision -making, communication, and organizational - managerial processes, safety was compromised to the point that the blowout occurred with catastrophic effects. Time and cost pressures are an inherent part of this type of operation. Operations of this type cost $1 to $1.25 million per day — nearly $1,000 per minute. Income from the operations also provides important pressures. A well like Macondo can produce 50,000 barrels of oil per day — or more. This production has a total value (upstream and downstream) that approaches $10 millions per day or about $7,000 per minute. The DHSG does not conclude those who worked on the Deepwater Horizon Macondo well project made conscious `well informed' decisions to trade safety for money. The DHSG analyses of the available evidence indicates they were trading something that was in their estimation unlikely for something that was sure. They were trading sure savings in time and money — and perhaps quicker returns on investments - for the very unlikely possibility of a blowout and its unimagined severe consequences. The risks were • erroneously judged to be insignificant. Thus, erroneous tradeoffs between risks (safety) and costs were developed. The available evidence indicates this crew, the onshore support staffs, and the regulatory agency staffs had never experienced a major accident such as unfolded on the Deepwater Horizon. This failure was beyond their experience — a "failure of imagination. " The Macondo well permitting documentation clearly shows that both BP and the MMS believed the likelihood of a catastrophic blowout were not significant. Blowout prevention plans were not required (waived). Procedures, processes, and equipment for containment and cleanup of the `worst case' blowout were deemed to be readily available and would prevent significant negative environmental impacts. There was significant experience to bolster this over confidence in success. This very complex system (managers, men, and machines) had just completed a world record setting operation to the west of the Macondo well — the Tiber well. The Tiber well was drilled to 35,000 feet below the drill deck in more than 4,000 feet of water. The Tiber well led to discovery of more than 3 billion barrels of hydrocarbon reserves. This system had completed 7 years without a reportable - recordable lost time accident. This system was confident in its abilities to cope with the challenges posed by the Macondo well — whose risks were judged to be `insignificant.' Available evidence and testimony indicates there were multiple (10 or more) major decisions and subsequent actions that developed in the days before the blowout that in • hindsight (hindsight does not equal foresight) led to the blowout. There were conscious deliberations about each of the primary decisions and action sequences — on the rig and `on the beach' (the office staffs). The well permitting documentation contains many CCRM Deepwater Horizon Study Group 7 November 24, 2010 . in place and were being used. Protective barriers were in place and were incorrectly thought to be sufficient and functional. The failures that developed before, during, and after the Macondo well project clearly show these risk assessment and management processes — barriers - were deeply deficient and pervasively flawed. Important things that were supposed to have been done correctly were either not done or were not done correctly. When the system was `tested' before, during, and after the blowout, it performed miserably. As described by Exxon -Mobil CEO Rex Tillerson in response to questions before the National Commission, an organization's safety culture takes time (several decades) to develop and has to be grown from within — you can't buy it or import it — it has to be nurtured from within the organization. Exxon -Mobil has been at it now for more than twenty years, after learning the hard way and paying for its complacency and risk management failures that led to the Valdez spill. Since that time, Exxon -Mobil has turned the corner and introduced many positive innovations to improve safety culture, such as their Operations Integrity Management System (DIMS), introduced in 1992 as an integral part of their overall safety management system. In contrast, at the time of the Macondo blowout, BP's corporate culture remained one that was embedded in risk -taking and cost-cutting — it was like that in 2005 (Texas City), in 2006 (Alaska North Slope Spill), and in 2010 ("The Spill").8 Perhaps there is no clear- cut "evidence" that someone in BP or in the other organizations in the Macondo well project made a conscious decision to put costs before safety; nevertheless, that misses the point. It is the underlying "unconscious mind" that governs the actions of an • organization and its personnel. Cultural influences that permeate an organization and an industry and manifest in actions that can either promote and nurture a high reliability organization with high reliability systems, or actions reflective of complacency, excessive risk -taking, and a loss of situational awareness. MANAGERIAL CONCLUSIONS Conclusion: Individuals should be trained to repeatedlti, question data, raise concerns, and double-check assumptions. Comment: Significant resources have been devoted to learning about training people to perform complex operations. One of the key insights developed from this work is effective training requires effective selection of personnel who will perform specific types of operations. The selection process is intended to identify individuals who have the talents and abilities required to work with a particular system — the Right Stuff.' Training can then be used to help amplify the required talents and abilities to develop the needed capabilities and competencies. Training needs to address normal, abnormal, and unbelievable situations and developments. Excellent guidelines that address the challenges associated with selection and training of personnel to operate critical systems have been developed for high reliability systems such as commercial nuclear power generation and commercial aviation. ' W.E. Gale, Jr., "Perspectives on Changing Safety Culture and Managing Risk," R.G. Bea, "Understanding the • Macondo Well Failures," K. Roberts, "After the Dust Settles," E. Roe and P. Schulman, "A High Reliability Management Perspective on the Deepwater Horizon Spill, Including Research Implications," DHSG Working Papers, 2010. 9 R. G. Bea, "Managing Rapidly Developing Crises — Real -Time Prevention of Failures," DHSG Working Paper, 2010. CCRM Deepwater Horizon Study Group 9 November 24, 2010 • Conclusion: Greater attention should be paid to the magnitude of consequences of all anomalies, even seemingly minor anomalies. Comment: Attention is a vital and perishable human resource. Choosing what to pay attention to and what not to pay attention to during the performance of complex tasks requires the skills of discrimination. This is particularly difficult when the signals associated with anomalies are weak in a `strong noise environment.' Slowly evolving developments leading to crises frequently are difficult to detect because signals of evolving degradations are drowned out by the noise of normal daily operations. We loose our ability to expect the unexpected frequently losing situational awareness. Values, beliefs, and feelings trump knowledge, logic and good sense and we fail to take appropriate action. Slowly developing crises, if properly detected and evaluated, provide time to develop optimized solutions, experimentation, and correction. Rapidly evolving developments leading to crises frequently are difficult to manage because of surprise factors — they destroy beliefs - and time pressures that can lead to cognitive lock -up — tunnel vision. In such crises, the challenge is to survive — quickly find and implement a solution that works. The problems associated with correct diagnosis of clues also pose major challenges in managing crises — correctly connecting the `dots' (clues) that tell us what causes or problems are causing escalation of the crisis. Flawed mental models (wrong, incomplete), • defensive behavior (actions to avoid embarrassment, injury and loss), muddled goals (contradictory), uncertainties, repair service behavior (treating symptoms not causes) and denying unwelcome realities lead to failure to properly connect the dots. Conclusion: Individual risk factors cannot be considered in isolation but as an overall matr& Personnel can not ignore anomalies after believing they have addressed them. Comment: The available evidence does indicate that risk assessments associated with completion and temporary abandonment of the Macondo well were made separately — there was no `risk memory.' This type of challenge is one of the key reasons for requirements of disciplined formal Management of Change procedures and processes, Safety Cases, and Process Safety analyses. While each step in a proposed process can be judged to be `safe', due to the uncertainties associated with the conditions and analyses, the accumulation of risk in the process can prove to be fatal. The need for continuous vigilance during performance of critical processes is an important part of risk assessment and management (RAM) and Management of Change (MOC) processes to maintain the reliability of complex systems operating in hazardous environments. Interactive RAM processes performed during the time activities are performed take many forms — such as Quality Assurance and Control, Management of Change, and Management of Crises. Early detection of anomalies that can be indicative of failure and risk escalation can provide more time for analyses of the anomalies, mobilization of resources, and implementation of strategies to return a system to a reliable state. Similarly, after the system has been returned to a reliable state, the process • of `observe, orient, decide, act' (OODA)9 must be continued to confirm that a reliable state has been achieved and is being maintained. The Macondo well pre -failure CCRM Deepwater Horizon Study Group 11 November 24, 2010 • feedback on the health of both their system and their people.' 1 And they practice timely, effective, thorough, and honest communications that effectively bind the individuals, teams, and organization together. The best organizations prepare by creating systems and people robust enough to tolerate damage and defects and resilient enough to bounce back from trauma. Such systems embody four important elements: 1) appropriate configurations - they put the right stuff in the right places at the right times, 2) excess capacity - they can carry excessive demands when one or more elements become overloaded, 3) ductility - they stretch and deform with out breaking or loosing capacity; and 4) appropriate association - they morph to fit the situation, turning independent or high associative when required. Effective crisis management systems focuses on providing people and system supports that promote protection (safety) and reliability. People support is focused on selecting, training, organizing, leading, and managing the right stuff - assuring that the right stuff is in the right amounts and places at the right times and ways. System support is focused on providing serviceable, safe, compatible and durable assemblies of hardware and humanware that are robust, resilient, and sustainable. Strategies that reduce the likelihoods of malfunctions, increase their detection and remediation, and reduce the effects of malfunctions are employed in a continuous process to improve protection and reliability — and maintain productivity. Selection and training of people to enhance their abilities to successfully address rapidly developing crises is of critical importance. Training consists of much more than • developing procedure manuals and guidelines. Prototype hardware and computer simulators that can approximate realistic crisis conditions can provide important skill building experiences. Realistic drills can also provide valuable learning experiences. Much can be learned from communities that must be constantly prepared to deal with rapidly developing crises such as emergency medicine, military operations, fire fighting, commercial nuclear power generation, and commercial aviation. Communities that succeed in crisis management practice and drill to become near perfect.9 That starts with communication — effective, timely, understandable — with encouragement of feedback. Crisis managers must learn to clearly explain not just goals, but why they do things so people can work independently and creatively and still move in the right direction. Team members learn to subordinate their personal prominence to achieving successful management of crises. They work within a fluid organization where leadership develops and migrates so the team can do things otherwise beyond their reach. Through experiences and practice, development and maintenance of trust is critical. • " E. Roe and P. Schulman, "A High Reliability Management Perspective on the Deepwater Horizon Spill, Including Research Implications," "O.T. Gudmestad and M. Tiffany, "Issue Management - Treatment of Bad News", DHSG Working Papers, 2010. CCRM Deepwater Horizon Study Group 13 November 24, 2010 Page 1 of 1 Offshore Close BOEMRE issues guidance regarding permit standards Offshore staff WASHINGTON, D.C. — The US federal Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE) has released additional information about how to comply with the recently issued rules and previous guidance. •The new publication addresses the Drilling Safety Rule (or Interim Final Rule), NTL-6 (including Worst Case Discharge calculations), and NTL-10, as well as further information on BOEMRE's inspections of BOP testing, Oil Spill Response Plans (OSRP), and the manner in which environmental assessments will be conducted for deepwater drilling plans. • The actual publication is online at http://www.boemre. ovg /oog/press/2010/pressl2l3.htm. "As we continue to strengthen oversight and safety and environmental protections, we must ensure that the oil and gas industry has clear direction on what is expected," said BOEMRE Director Michael R. Bromwich. "Following discussions with members of the oil and gas industry, it is clear that this information will assist in their implementation of the stronger safety and environmental standards we have put in place. We remain committed to working with industry to provide additional guidance on these and other issues." 12/14/2010 To access this Article, go to: http://www.offshore-mag.com/offshore/en-us/index/article-tools-template.articles.offshore.di•ilti ng- completion.us-gulf-of-mexico.2010.12.boemre-issues_gui dance..html http://www.offshore-mag.com/index/article-tools-template/ printArticle/articles/offshore/... 12/14/2010 BOEMRE Press Release Page 1 of 1 • FOR RELEASE: December 13, 2010 BOEMRE Issues Guidance for Deepwater Drillers to Comply with Strengthened Safety and Environmental Standards Information Provides Clear Path Forward for Safe Resumption of Deepwater Drilling Operations WASHINGTON — The Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) today issued additional guidance regarding the steps required of operators to resume deepwater activity. This information contains no new or additional regulatory requirements, but instead provides additional information to assist the oil and gas industry in their efforts to comply with recently -issued rules and prior guidance. "As we continue to strengthen oversight and safety and environmental protections, we must ensure that the oil and gas industry has clear direction on what is expected," said BOEMRE Director Michael R. Bromwich. "Following discussions with members of the oil and gas industry, it is clear that this information will assist in their implementation of the stronger safety and environmental standards we have put in place. We remain committed to working with industry to provide additional guidance on these and other issues." Since Interior Secretary Ken Salazar lifted the deepwater drilling moratorium on October 12, 2010, BOEMRE has met with multiple oil and gas operators and industry representatives to help clarify and provide additional guidance about new regulations, Notices to Lessees (NTL), and how the agency will apply National Environmental Protection Act (NEPA) requirements with respect to deepwater drilling operations. Today's guidance presents a clear path to move forward with the resumption of work in deepwater. • The issues addressed in the information document include compliance issues relating to: the Drilling Safety Rule (or Interim Final Rule), NTL-6 (including Worst Case Discharge calculations), and NTL-10, as well as further information on BOEMRE's inspections of BOP testing, Oil Spill Response Plans (OSRP), and the manner in which environmental assessments will be conducted for deepwater drilling plans. • The information document is available here Contact: BOEMRE Public Affairs DOI_GOV USA.GOV Accessibility Disclaimers FOIA Inspector _General Privacy PAY_GOV Last Updated: 1211312010 12:06 PM Central Time htti)://www.boemre.f4ov/ooe/press/2010/-Pressl2l3.htm 12/14/2010 • Approval Requirements for Activities That Involve the Use of a Subsea Blowout Preventer (BOP) or a Surface BOP On a Floating Facility Purpose The purpose of this document is to (a) summarize and clarify certain information relating to the regulations and guidance previously issued by the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE), and (b) describe certain procedures being applied by BOEMRE's Gulf of Mexico OCS Region (GOMR), as they apply to previously -approved, pending, and newly -submitted Exploration Plans (EPs) and Development Operations Coordination Documents (DOCDs), Permits to Drill (APDs, RPDs, ASTs, RSTs, ABPs, RBPs, APMs, RPMs), and Regional Oil Spill Response Plans (OSRPs) regarding oil and gas activities in the Gulf of Mexico. This document is intended to provide helpful information regarding the applicable requirements and procedures to obtain approval to conduct activities that propose using a drilling rig equipped with a subsea blowout preventer (BOP) system, a floating drilling rig equipped with a surface BOP system, or a drilling rig on a floating platform. The information contained in this document does not constitute new or additional regulatory requirements. Rather, this document is intended to provide lessees, operators and other relevant parties with information and clarity about the application and implementation of BOEMRE's existing regulations and guidance. • Background Effective June 18, 2010, BOEMRE issued Notice to Lessees and Operators (NTL) No. 2010- N06, Information Requirements for Exploration Plans, Development and Production Plans, and Development Operations Coordination Documents on the OCS. The purpose of this NTL was to rescind the limitations set forth in NTL No. 2008-G04 regarding a blowout scenario and worst case discharge (WCD) scenario, and to provide national guidance to lessees and operators regarding the content of the information BOEMRE requires in blowout scenario and worst case discharge scenario descriptions. On August 16, 2010, the Director of BOEMRE instructed the agency not to routinely use categorical exclusions with respect to National Environmental Policy Act (NEPA) reviews for EPs and DOCDs that propose to conduct an activity that requires approval of an APD and involves the use of a subsea BOP or a surface BOP on a floating facility. In light of this policy, BOEMRE describes in Appendix A of this document the information operators would need to supply to allow BOEMRE to prepare appropriate environmental assessments (EAs) for EPs and DOCDs for proposed operations that fall within these categories. On October, 14, 2010, BOEMRE issued an interim final rule entitled "Increased Safety Measures for Energy Development on the Outer Continental Shelf' (75 FR 63346) (the Safety Interim Final Rule). The Safety Interim Final Rule implements certain safety measures recommended in the Department of the Interior's May 27, 2010, offshore energy safety report to the President. • This rule amends drilling regulations related to well control, including regulations governing: subsea and surface BOP's, well casing and cementing, secondary intervention, unplanned • BOEMRE's methodology for verifying operators' WCD calculations employs reservoir simulation and nodal analysis techniques routinely used in industry. BOEMRE does not require that operators use any prescribed methodology or software to calculate WCD. For example, operators have submitted and presented information on methodology and data used to calculate WCDs using various methodologies and software packages (including Merlin, Eclipse, WEB, Perform, Prosper, and Avalon), any of which is acceptable if done properly. 2. Regarding Well Permits: To increase the safety of activities that require approval of an APD/RPD, an AST/RST, an ABP/RBP, or an APM/RPM operators must comply with the Safety Interim Final Rule. See Appendix B, Requirements under the Interim Final Rule. Operators must also provide the information set forth under NTL No. 2010-N 10, Statement of Compliance with Applicable Regulations and Evaluation of Information Demonstrating Adequate Spill Response and Well Containment Resources, effective November 8, 2010. If an operator's original APD, ABP, or AST has demonstrated that it has access to and can deploy containment resources that would be adequate to properly respond to a blowout or other loss of well control, then an RPD/RST/RBP for the same operation need not readdress the NTL No. 2010-N10 informational requirements, unless any of the elements of the operator's available • containment resources has changed. See Appendix C, Requirements under NTL No. 2010-N10. 3. Regarding OSRPs: In accordance with 30 CFR 254.30 (e), BOEMRE's Regional Supervisor may require an operator to revise its OSRP if significant deficiencies in the OSRP are indicated by (1) periodic reviews of OSRO capabilities, (2) information obtained during drills or actual spill responses, or (3) other relevant information obtained by the Regional Supervisor, including, for example, changes in an operator's WCD calculation scenario as reflected in an operator's EP or DOCD submission. In the event that the BOEMRE Regional Supervisor requires an operator to revise its OSRP, the operator may continue to operate for up to two years while BOEMRE reviews the revised OSRP if the operator complies with 30 CFR 254.2(b), which requires that the operator certify that it has the capability to respond, to the maximum extent practicable, to a worst case discharge or substantial threat of such a discharge. This certification must establish that the operator has ensured by contract, or by other means approved by the Regional Supervisor, the availability of private personnel and equipment necessary to respond to the discharge. Confirmation from the organization(s) providing the personnel and equipment must accompany the certification. During BOEMRE's review of revised OSRPs, BOEMRE will evaluate all available equipment, technologies, and practices addressing intervention and recovery, including, but not limited to, • cap and collect, cap and contain, mechanical recovery, burning, dispersants (including subsea), and surveillance (including surveillance and operations at night, if equipment is available, e.g. X- • o. Night operations p. In -situ burn q. Spotter aircraft r. Responder communications equipment compatibility s. Area Contingency Plan consistency Retarding BOP tests Operators are expected to notify BOEMRE at least 72 hours prior to all BOP stump tests and initial BOP tests on the seafloor to facilitate having a BOEMRE representative present to witness at least one of these tests. If BOEMRE receives appropriate notice and is unable to, or elects not to, witness at least one of the tests due to factors beyond the operator's control (including, for example, weather conditions and transportation availability), the operator may proceed with the test. However, in cases in which BOEMRE does not witness a BOP stump test or initial seafloor test, the operator must provide the results of the test (in either electronic or paper format) to BOEMRE within 72 hours of the test. Contact If you have any questions regarding the information requirements for EP's and DOCD's, contact Michael Tolbert of the BOEMRE GOMR Plans Section by telephone at (504) 736-2867 or by email at michael.tolbert(d$oemre.gov. • If you have any questions regarding the requirements for well permits, contact Jane Powers of the BOEMRE GOMR Office of Field Operations by telephone at (504) 736-2558 or by email at jane.powersAboem re.gov If you have any questions regarding the requirements of NTL No. 2010-N 10, contact Bryan Domangue of the BOEMRE GOMR Office of Field Operations by telephone at (985) 853-5885 or by email at brvan.domangue@boemre.gov If you have any questions regarding the requirements for Regional and subregional OSRPs, contact Nick Wetzel of the BOEMRE GOMR Office of Field Operations by telephone at (504) 736-2419 or by email at nick.wetzelAboemre.gov If you have any questions regarding BOP tests, contact Michael Saucier of the BOEMRE GOMR Office of Field Operations by telephone at (504) 736-2503 or by email at michael. saucier(aboemre.gov. 0 2. General Information (30 CFR 250.213 and 250.243) is (a) Drilling fluids. (1) Using the format below, provide information on the types (including chemical constituents) and amounts of the drilling fluids you plan to use to drill your proposed wells. Figures in the model tables below are included for illustrative purposes only. Type of Drilling Fluid Estimated Volume of Drilling Fluid to be Used per Well Water -based (seawater, freshwater, barite) 35,000 bbls Oil -based (diesel, mineral oil) 500 bbls Synthetic -based (internal olefin, ester) 120,000 bbls (2) For each oil -based drilling fluid you list in the table above, (i) Use the format below to describe its major components: Amount to be Reference Product Name Used Number Bentonite 100 50-lb bags CAS # 1302-78-9 PureDrill IA-35 500 bbls CAS # 178603- 63-9 (ii) Provide a Material Safety Data Sheet (MSDS), MSDS No., or Internet address for the MSDS (or equivalent information) for each product. (b) Oils characteristics. For DOCDs only, use the format below to provide the chemical and physical characteristics of the oils (see definition under 30 CFR 254.6) that will be produced, handled, transported, or stored at the facilities you will use to conduct your proposed development and production activities. Characteristic Analytical Methodologies Should Be Consistent With: (1) Gravity (API) ASTM D4052 (2) Flash Point (-C) ASTM D93/IP 34 (3) Pour Point (^C) ASTM D97 (4) Viscosity (Centipoise at 25 ^C) ASTM D445 (5) Wax Content (wt %) Precipitate with 2-butanon/dichloromethane (1 to 1 volume) at -10 -C (6) Asphaltene Content (wt %) IP-Method 143/84 (7) Resin Content (wt %) Jokuty et al. (1996) (8) Boiling point distribution including, for each fraction, the percent volume or weight and the boiling point range in degrees C ASTM D2892 (TBP distillation), or ASTM D2887/5307 (9) Sulphur (wt %) ASTM D4294 Note: For the distillation information in item no. 8 above, the BOEMRE GOMR may accept the following information in lieu 6 • (c) Modeling report. If you model the trajectory or fate of discharges of the projected solid or liquid wastes generated by your proposed activities, provide two copies of the modeling report or the modeling results, or a reference to such report or results if it has already been submitted to the Regional Supervisor. Include the oceanographic data you used in the modeling in the report. If you plan to model, consult with the Regional Supervisor for further guidance on preparing the modeling report. Provide this report only when you propose activities for which the U.S. Environmental Protection Agency requires an individual NPDES permit. 4. Oil Spills Information (30 CFR 250.219 and 250.250) (a) Oil spill response discussion. Discuss your response to an oil spill resulting from the activities proposed in your EP or DOCD. Include all the information described in 30 CFR 254.26(b), (c), (d), and (e) that is applicable. As the source of the spill, use whichever of the following gives the greater volume of oil: (i) The blow-out scenario you describe in the information you submit to comply with NTL No. 2010-N06; or (ii) The volume of the largest oil/fuel storage tank on the drilling rig or facility. (b) Modeling report. If you model a potential oil or hazardous substance spill, provide two copies of the modeling, or a reference to such a report if it has already been provided to the • Regional Supervisor. Include the oceanographic data used in the modeling in the report. If you plan to model, contact the Regional Supervisor for guidance on preparing the report. 5. Support Vessels and Aircraft Information (30 CFR 250.224 and 250.257) (a) Diesel oil supply vessels. Using the format below, provide additional information on the vessels you will use to supply diesel oil. Make sure you include any vessels that will transfer diesel oil you will use for purposes other than fuel (e.g., base for corrosion control fluids). If the specific fuel supply vessel has not yet been determined, use the maximum size, fuel capacity, and trip frequency for the type of vessel you will use. Size of Fuel Capacity of Fuel Frequency of Fuel Route Fuel Supply Supply Vessel Supply Vessel Transfers Vessel Will Take 180 feet 1,500 bbls Weekly From the shorebase in Fourchon, LA, to XYZ Field, then to WC Block 134. (b) Solid and liquid wastes transportation. If you plan to transport any of your solid and liquid wastes from the site of your proposed activities to other offshore structures or to temporary or permanent onshore facilities for storage or disposal, use the format below to provide the following information: Type of Waste Total Amount Name/Location Rate Transport • Approx. Composition I I I I Method 11 • Appendix B Requirements under the Safety Interim Final Rule The requirements under this interim final rule are hereby clarified as follows: A. Changes to API RP language (submitted under Subpart A) 1. Documents incorporated by reference located at 30 CFR 250.198(a)(3), are clarified as follows: a. With respect to any incorporated document, the term "should", is to be interpreted as meaning "must" for purposes of these regulations. If this interpretation creates any contradictions or eliminates options available for addressing particular situations encountered by an operator, then an operator is to include, as part of its permit application, a discussion of the options that the operator considered and an explanation regarding the alternative chosen by the operator. Departures from the alternatives provided under the Safety Interim Final Rule will be evaluated on a case by case basis and granted where the situation warrants. B. Applications for Permit to Drill (submitted under Subpart D) 1. Casing and Cementing Requirements located at 30 CFR 250.420(a)(6), are clarified as • follows: a. The registered professional engineer (PE) must certify that during the drilling/construction of the wellbore there will be two barriers in each annulus (for example, primary cement job and seal assembly) and that, upon running and cementing the final production casing/liner, there will be two barriers in the center of the wellbore (for example, dual mechanical floats). This certification may apply to a completion permit if you are running the production casing under the completion APM. b. The PE may not certify work that was previously performed. The PE must only certify the work to be performed under the permit submitted. c. When using less cement than approved in the original APD, an RPD will be required to include PE certification for the new cement volumes. d. If an increase in cement volume is needed because an additional hydrocarbon zone is identified, then an RPD will be required to include PE certification for the new cement volumes. e. As with other requests, requests for permit revisions outside normal business hours will require PE certification prior to approval. An email stating that the PE has certified the revisions will suffice, but the stamped revisions should be submitted within 72 hours of the e-mail to the appropriate District Office. f. The barriers must be tested or in the case where a barrier cannot be tested there must be a methodology in place to verify the placement of the barrier (operational parameters or direct measurement methods that will indicate successful placement or successful installation.) • 2. Casing and Cementing Requirements located at 30 CFR 250.415(f), are clarified as follows: U 6. BOP Inspection Requirements located at 30 CFR 250.451(i) is clarified as follows: a. If pipe is sheared, either in a well control event or accidentally, you must retrieve, physically inspect, and conduct a full pressure test of the BOP stack. C. Applications for Permit to Modify (submitted under Subparts E and F) 1. Well Completions, Re -completions and Workover Requirements located at 30 CFR 250.500 thru 30 CFR 250.618 are clarified as follows: a. PE certification is not required when changing zones, plugging back for immediate sidetrack, or recompletions. PE certification is only needed for drilling, TA and PA permits. 2. BOP Maintenance and Inspection Requirements located at 30 CFR 250.516(g) and 30 CFR 250.617(1) are interpreted as follows: 13 a. API RP 53, Section 17.10 states "After each well, the well control equipment should be cleaned, visually inspected, preventative maintenance performed, and pressure tested before installation on the next well." The pressure test may be performed after • nippling up on the well for a surface stack. 1). Applications for Permit to Modify (submitted under Subpart Q) 1. Permanently Plugging Wells Requirements located at 30 CFR 250.1712(g), are clarified as follows: a. For wells being permanently abandoned (PA) and the wellhead removed, the PE needs to certify that there are two independent barriers in the center wellbore and the annuli are isolated per the regulations at 30 CFR 250.1715. However, if the wellhead is being left in place for the PA, the PE must certify two independent barriers in both the center wellbore and the annuli. b. The PE may not certify work that was previously performed, the PE must only certify the work to be performed under the permit submitted. c. PE certification is not required for an APM to conduct work that would convert a temporarily abandoned (TA) well to a PA well by cutting and pulling casings only (assuming that there are no additional plugs being set and there are no cementing operations taking place.) d. As with other requests, requests for permit revisions outside normal business hours will require PE certification prior to approval. An email stating that the PE has certified the revisions will suffice, but the stamped revisions should be submitted within 72 hours of the e-mail to the appropriate District Office. e. The barriers must be tested or in the case where a barrier cannot be tested, there must • be a methodology in place to verify the placement of the barrier (operational parameters or direct measurement methods that will indicate successful placement or successful installation.) • • • 15 6 Are fluid densities sufficient to maintain well control without inducing lost circulation? Yes/No CRITICAL WELL DESIGN PARAMETERS 7 NVill you use a cementing simulation model in the design of this well'.' l'e. No 7a If yes, how is the output of this simulation model used in your decision -making process? Describe below 7b If no, include discussion of why a model is not being used. Describe below 7c Either way, include the number and placement of centralizers being used. Describe below 8 Will you ensure the planned top of cement will be 500 feet above the shallowest potential flow zone? Yes/No 9 Have you confirmed that the hole diameter is sufficient to provide adequate centralization? Yes/No 10 If there are any isolated annuli, how have you mitigated thermal casing pressure build-up? NA or Describe below 11 Will you ensure the well will be stable (no volume gain or losses, drilling fluid density equal in vs. out) before commencing cementing operations? Yes/No 12 List all annular mechanical barriers in your design. Describe below 13 Has the rathole length been minimized or filled with drilling fluid with a density greater than the cement density? Yes/No 14a If you have any liner top packers exposed to the production or intermediate annulus, what is the rating for differential pressure across thispacker? NA or Describe below 14b If you have any liner top packers exposed to the production or intermediate annulus, have you confirmed that your negative test will not exceed this rating? Yes/No/NA 15 1 What type of casing hanger lock -down mechanisms will be used? Describe beloA 16 For all intermediate and production casing hangers set in subsea, HP wellhead housing, will you immediately set/energize the lock -down ILng prior to performing any negative test? Yes/No 17 For all production casing hangers set in subsea, HP wellhead housing, will you set/energize the lock -down sleeve immediately after running the casing and prior to performing any negative test? Yes/No 18 Will you have 2 mechanical barriers in addition to cement in your final casing string (or liner if it is your final string)? Yes/No 19 Do you plan to nipple down BOP in accordance with the WOC requirements in 30 CFR 250.422 and API RP 65 Part 2 First Edition? Yes/No 20 Do you plan on running a cement bond log on the production and intermediate casing/liner prior to conducting the negative test on that string? Yes/No Are contingency lans in place for the following: 21 Lost circulation? Yes/No 22 Unplanned shut -down? Yes/No 23 Unplanned rate change? Yes/No 24 Float equipment does not hold differentialpressures? Yes/No 25 Surface Equipment issues? Yes/No 26 1 Will you monitor the annulus during cementing and WOC time? Yes/No 27 If using foam cement, is a risk assessment being conducted and incorporated into cementing Ian? Yes/No 28 If using foam cement, will the foamer, stabilizer, and nitrogen injection be controlled by an automated process system? Yes/No CRITICAL MUD REMOVAL PARAMETERS 28 Have you tested your drilling fluid and cementing fluid programs for compatibility to reduce possible contamination? Yes/No 29 Have you considered actual well conditions when determining appropriate cement volumes? Yes/No 30 Has the spacer been modeled or designed to achieve the best possible mud removal? Yes/No CRITICAL CEMENT SLURRY PARAMETERS 31 Have all appropriate cement slurry parameters been considered to ensure the highest probability of isolating all potential flow zones? Yes/No 32 Do you plan on circulating bottom up prior to the start of the cementjob'? Yes/No If any question is answered "No," additional explanation will be needed as to why that 17 • Appendix C Requirements under NTL No. 2010-N 10 A. In order to ensure that an operator can safely conduct activities that require approval of an APD/RPD, an AST/RST, or an ABP/RBP, and involve the use of a subsea BOP system, a floating drilling rig equipped with a surface BOP system, or a drilling rig on a floating platform, the operator must provide a statement of compliance in accordance with NTL No. 2010-N 10. This statement of compliance must be provided with each APD/RPD, AST/RST, or ABP/RBP in the categories described above and must be signed by the company's authorized official that is on file with BOEMRE. B. For activities that require approval of an APD/RPD, an AST/RST, or an ABP/RBP and involve the use of a subsea BOP system, a floating drilling rig equipped with a surface BOP system, or a drilling rig on a floating platform, BOEMRE will evaluate whether an operator has submitted adequate information demonstrating that it has access to and can deploy surface and subsea containment resources that would be adequate to promptly respond to a blowout or other loss of well control. An operator may satisfy these informational requirements by, for example, submitting a Containment Plan as part of its regional or subregional OSRP. This Containment Plan should demonstrate that the operator has access to and can deploy containment resources • that would be adequate to properly respond to a blowout or other loss of well control. In evaluating the sufficiency of subsea containment information submitted by an operator, BOEMRE will consider an analysis of the Mudline Shut -In Pressure (MLSIP) for the proposed operation. This analysis will consist of an evaluation of the well design to determine MLSIP (that is, the pressure that the system at the mudline would have to contain.) BOEMRE will evaluate whether the operator has demonstrated the ability to shut in the well with a capping stack with full displacement of the mud while maintaining wellbore integrity (including, e.g., casing, shoe, and open hole) under MLSIP. In cases in which an operator proposes a capping stack as the primary containment option, BOEMRE will evaluate whether the well design is sufficient to allow shut-in without broach to the sea floor. If full containment is necessary, BOEMRE will evaluate the process flow for the entire containment system, including source to storage of captured oil. BOEMRE also will evaluate factors such as debris removal from the site of a blowout, if required. This analysis will not be performed with respect to proposed operations under APM's or RPM's. GUIDELINES FOR THE DEVELOPMENT OF CONTAINMENT PLANS Make the following assumptions: 1. An uncontrolled Blowout/Explosion/Fire scenario that requires evacuation of the rig/facility. • 2. Full displacement of drilling fluid • House of Commons Energy and Climate Change Committee UK Deepwater Drilling —Implications of the Gulf of Mexico Oil Spill • Second Report of Session 2010-11 Volume I Volume l: Report, together with formal minutes, oral and written evidence Additional written evidence is contained in Volume ll, available on the Committee website at www.parliament.uk/ecc Ordered by the House of Commons to be printed 14 December 2010 is HC 450-1 Published on 6 January 2011 by authority of the House of Commons London: The Stationery Office Limited f 22.00 • The Energy and Climate Change Committee The Energy and Climate Change Committee is appointed by the House of Commons to examine the expenditure, administration, and policy of the Department of Energy and Climate Change and associated public bodies. Current membership Mr Tim Yeo MP (Conservative, South Suffolk) (Chair) Dan Byles MP (Conservative, North Warwickshire) Barry Gardiner MP (Labour, Brent North) Ian Lavery MP (Labour, Wansbeck) Dr Phillip Lee MP (Conservative, Bracknell) Albert Owen MP (Labour, Ynys Mon) Christopher Pincher MP (Conservative, Tamworth) John Robertson MP (Labour, Glasgow North West) Laura Sandys MP (Conservative, South Thanet) Sir Robert Smith MP (Liberal Democrat West Aberdeenshire and Kincardine) Dr Alan Whitehead MP (Labour, Southampton Test) The following members were also members of the committee during the parliament: Gemma Doyle MP (LabourlCo-operative, West Dunbartonshire) Tom Greatrex MP (Labour, Rutherglen and Hamilton West) • Powers The committee is one of the departmental select committees, the powers of which are set out in House of Commons Standing Orders, principally in SO No 152. These are available on the Internet via www.parliament.uk. Publication The Reports and evidence of the Committee are published by The Stationery Office by Order of the House. All publications of the Committee (including press notices) are on the internet at www.parliament.uk/parliament.uk/ecc. A list of Reports of the Committee in the present Parliament is at the back of this volume. The Report of the Committee, the formal minutes relating to that report, oral evidence taken and some or all written evidence are available in a printed volume. Additional written evidence may be published on the internet only. Committee staff The current staff of the Committee are Nerys Welfoot (Clerk), Richard Benwell (Second Clerk), Dr Michael H. O'Brien (Committee Specialist), Jenny Bird (Committee Specialist), Francene Graham (Senior Committee Assistant), Jonathan Olivier Wright (Committee Assistant), Emily Harrisson (Committee Support Assistant), Estelita Manalo (Office Support Assistant), and Nick Davies (Media Officer). Contacts All correspondence should be addressed to the Clerk of the Energy and Climate isChange Committee, House of Commons, 7 Millbank, London SW1P 3JA. The telephone number for general enquiries is 020 7219 2569; the Committee's email address is ecc@parliament.uk F Contents Report Page Summary 3 1 Introduction 5 2 Challenges of Deepwater Drilling 6 UK Deepwater Drilling Activity 7 Operations on the UK Continental Shelf 7 3 Offshore Regulation 9 UK Offshore Regulatory Regime 9 US and UK Offshore Regulations 10 Environmental Regulation and Inspection 11 Emergency Response 12 Changes since Macondo 12 Authority to Stop Operations Offshore 13 Catastrophic Failure of the BOP 14 The Importance of Simple Checks 17 • Independence of ICPs 17 Protection of Whistle -blowers 19 Contractor Oversight 20 Operating in Different Regulatory Regimes 20 Licensing 21 Controversy over the Bly Report 22 4 Liability and Compensation 24 Cost of the Deepwater Horizon Incident 24 Offshore Pollution Liability Association 24 Insurance 27 5 UK Oil Spill Response 28 Oil Pollution Emergency Plans 28 Dealing with an Oil Spill in the UK 29 The Role of SOSREP 30 UK Spill Statistics 30 Methods of Dealing with Spills 31 Use of Sub -sea Dispersant 31 Capping and Containment Systems 32 The West of Shetland Environment 33 6 EU Regulatory Role 35 • Environmental Legislation European Commission Calls for a Moratorium 35 36 • C�j • 2 7 Impacts of a Moratorium Impact of the US Moratorium Evidence on a UK Moratorium 8 Conclusions and Recommendations Annex 1—Chronology of the Deepwater Horizon Incident The Macondo Well in the Gulf of Mexico The Deepwater Horizon Drilling Rig Factors Identified as Contributing to the Incident Casing Cement Negative Pressure Test BP's Attempts to Kill the Macondo Well BP's Gulf of Mexico Clean-up Operations Environmental Impacts in the Gulf of Mexico Formal Minutes Witnesses List of printed written evidence List of additional written evidence List of unprinted evidence List of Reports from the Committee during the current Parliament 38 38 38 41 45 45 45 47 47 48 49 49 50 51 52 53 54 54 54 55 • • • Summary On 20 April 2010, a blowout of BP's Macondo well in the Gulf of Mexico led to the deaths of 11 workers on Transocean's Deepwater Horizon drilling rig, and the release of an estimated 4.9 million barrels of oil. The wellhead was located in a depth of water over 1,500m. In the aftermath of this incident the United States observed a moratorium on deepwater drilling until 12 October 2010. Despite calls for a moratorium from the European Commission, the UK Government has decided that the UK regulatory regime is "fit for purpose". Even so, in the Annual Energy Statement to Parliament on 27 July 2010 the Secretary of State, Rt Hon Chris Huhne MP, announced that the UK would, "undertake a full review of the oil and gas environmental regulatory regime" following the outcome of investigations into the causes of the Gulf of Mexico incident. We believe that the UK has high regulatory standards —as exemplified by the Safety Case Regime that was set up in response to the 1988 Piper Alpha tragedy —and the flexible, goal - setting approach adopted by the Health and Safety Executive's Offshore Safety Division is superior to the regulatory regime under which the Deepwater Horizon incident occurred. However, we welcome the Government's review. As demonstrated by BP's response to the blowout in the Gulf of Mexico, the offshore oil and gas industry was clearly not prepared for a sub -sea blowout of a well. The industry felt that it had mitigated away the risks associated with high -impact, low -probability events and so did not need to plan for them — it needs to revisit scenarios that it thought were too unlikely to occur. The Government needs to ensure that offshore oil and gas exploration companies have considered such outcomes as part of the process by which they obtain a licence to drill. The blowout in the Gulf of Mexico could have been prevented if the last -line of defence — the blind shear ram on the blowout preventer, located at the well head on the ocean floor — had activated and crushed the drill pipe. Given the importance of this equipment, and the evident dangers of relying on a single device, we urge the HSE to consider prescribing shear rams. The blind shear ram on the Macondo Well appears to have failed in part due to the absence of simple checks —such as whether the batteries had sufficient charge. The UK's offshore inspection regime should never allow such simple, potential failures to go unchecked. BP's internal investigation into the incident in the Gulf of Mexico —the "Bly Report" — contains controversial conclusions surrounding the design of the well. We recommend the Government consider the Bly Report's conclusions in parallel with the observations of other companies involved, and alongside recommendations of US agencies. We believe that should an oil spill resulting from drilling activities occur in the UK, there needs to be absolute clarity as to the identity of the responsible party, and liability legislation needs to ensure that those affected are compensated as soon as possible. Given the high costs of the Gulf of Mexico incident, we believe that the Offshore Pollution Liability Association (OPOL) limit of $250 million is insufficient. We are also concerned that the voluntary requirement of OPOL membership —despite it being a pre -requisite of the licensing process —weakens any legal control over it, allowing polluters to claim that 4 any damages to biodiversity and ecosystems are "indirect", and therefore do not qualify for compensation. Oil spill response procedures in the UK are robust, rightly focussing on prevention, followed by containment and then clean-up. While we welcome the development of devices to respond to a deepwater blowout in the UK, we urge the Government to recognise that oil spill response equipment is not a substitute for a fully functioning blowout preventer. Furthermore, we are concerned about the ability of oil spill response equipment to function in the challenging environment found in the seas West of Shetland. Given the evidence available to us, we conclude that there should not be a moratorium on deepwater drilling in the UK Continental Shelf. Such a moratorium would increase the UK's reliance on imports of oil and gas, potentially decreasing our security of supply. We conclude that any calls for increased oversight of the UK offshore industry by the European Commission should be rejected in favour of multilateral approaches to regulation and oil spill response amongst those countries with a coastline that could be affected by an oil spill. r 1 U 0 • 1 Introduction 1. On 20 April 2010 an explosion on the Deepwater Horizon drilling rig —operated by Transocean in the Gulf of Mexico, under contract to BP —led to the deaths of 11 workers and an oil leak at an unprecedented depth. The full extent of the environmental impact and the effect on communities is not yet known. In light of the incident, the Department of Energy and Climate Change (DECC) conducted a review of the existing safety and environmental regulatory regimes in the UK and found them to be "fit for purpose". However, it announced that annual inspections of drilling rigs were to double and insurance requirements were to be reviewed. The US suspended all deepwater drilling in the aftermath of the incident, and the European Commissioner for Energy, Gunther Oettinger, urged EU national governments to ban any new deepwater drilling temporarily. The UK did not impose any such ban. In the light of these events, we decided to examine the safety and environmental regulations of oil and gas operations on the UK Continental Shelf (UKCS)—especially in the deepwater to be found in the region West of Shetland — and the potential positive and negative impacts of a moratorium on deepwater drilling. 2. We announced our inquiry on 20 July 2010 and sought evidence on: the implications of the Gulf of Mexico oil spill for deepwater drilling in the UK; • the extent to which the existing UK safety and environmental regulatory regime is fit for purpose; the hazards and risks of drilling in the deeper waters West of Shetland; the necessity of deepwater oil and gas production during the UK's transition to a low -carbon economy; and • the extent to which deepwater oil and gas resources will contribute to the UK's security of supply. We are very grateful to all those who have assisted us during the inquiry. 3. We believe that the offshore industry needs to revisit scenarios that they previously thought were too extreme and unlikely to occur. As demonstrated by BP's response in the Gulf of Mexico, the industry was not prepared for a sub -sea blowout. They incorrectly believed that they had mitigated away the risks associated with high -consequence, low - probability events, and failed to plan for them. We conclude that BP appears to have cut corners during its operations to make the Macondo well ready for production. We are concerned that the poor decisions made in the run up to the blowout —that led to loss of 11 lives and 4.9 million barrels of oil being released into the Gulf of Mexico —could have been driven by commercial pressures. At Annex 1, we describe the chronology that we believe led to the Deepwater Horizon incident. In this report we now go on to examine the implications of the incident for offshore oil and gas exploration in the UK. • r� u 2 Challenges of Deepwater Drillin 4. Deepwater drilling depths are sometimes defined as greater than around 400m, while water depths of greater than 1500m are defined as "ultra-deepwater". Mr Malcolm Webb, Chief Executive of the industry association Oil and Gas UK, told us: I don't think there is an agreed industry definition of what constitutes deepwater [... ] When we started in the North Sea over 40 years ago, depths of 100 or 200 feet [30- 60m] would have been regarded as deepwater, and as our abilities and technologies have moved forward so the definition of what is "deep" has moved with it.' 5. Compared to conventional offshore drilling methods, deepwater presents unique technical challenges related to greater water depths, higher pressures, manipulating the extra long riser pipe connecting the wellhead to the rig (over 1,500m in the case of the Deepwater Horizon), extreme temperature gradients and added costs. We found it interesting to note Mr Webb's observation that the intervention in the well at the seafloor switches from divers to Remotely Operated Vehicles (ROVs) at "about 500 feet [150m]",2 as this seems to be an obvious threshold for deepwater operations. 6. The pressure in the well is controlled by ensuring that the pressure of the drilling fluid (known as mud) in the well bore —known as the bottomhole pressure —is sufficient to isoppose the pressure from the oil, gas and water in the reservoir (known as the formation pressure or the pore pressure). This prevents fluids from the reservoir entering the well. Dr Tony Hayward, BP's former Group Chief Executive, informed us "the pressure on the drill pipe and the volume of [drilling] mud [... ] are the two most important parameters that are monitored and measured on a continuous basis".' If the formation pressure is greater than the bottomhole pressure oil and gas would enter the wellbore, and would lead to a blowout if uncontrolled. The drilling fluid engineer monitors the formation pressure and increases the density of drilling mud to balance the pressure and keep the well bore stable. These active pressure control systems are the first line of defence against losing control of the well. 7. Mr Webb told us: "deep water brings some particular risks with it".4 Deepwater is characterised by young rock formations that differ from shallow -water or onshore exploration. This is exemplified by the narrow gap between the pressure of the oil and gas in the reservoir and the typically small changes in pressure required to fracture the rock around it (known as a low fracture gradient, this is typically low under deepwater). Small increases in formation pressure can therefore cause rock fractures to occur, destabilising the borehole and potentially leading to an influx of gas and oil (known as a kick) which if uncontrolled could lead to a blowout. This inclination for fractures to occur is caused by an increased weight pressing down on the oil and gas bearing rock formation (known as overburden). This can necessitate using lighter drilling fluid, which could potentially make • Qa zQ12 3 Q 116 (Hayward) 4 Q 3 it more difficult to control the well, and a lighter cement mixture (used when fixing the pipe casing into the borehole), potentially making the well more vulnerable to the formation of channels around the casing up which gas could flow. 8. Deepwater environments also present the combination of low temperatures, high seabed pressures, gas and water that cause "gas hydrates" to form. Gas hydrates are cages of frozen water molecules with gas trapped inside and have a tendency to bond with metal, resulting in blockages (as occurred during BP's "top hat" operation to kill the Macondo well). 9. Even though the incident in the Gulf of Mexico took place in deepwater, Mr Webb told us: "The depth of water is not the critical element here".' Mr Roland Festor, Managing Director of Total Exploration and Production UK, argued that: "Macondo has fundamentally nothing to do with deepwater".6 This is because, once the blowout had occurred —while the depth of the water made the response to the incident more difficult — it was the fact that it was a high-pressure, high -temperature (HPHT) well that made it more challenging to control. UK Deepwater Drilling Activity 10. The majority of wells drilled on the UK Continental Shelf (UKCS) are in water -depths of less than 100m, but oil and gas exploration companies have increasingly been drilling in deeper waters as reserves in more accessible areas run dry. Mr Webb told us: "the deepest • well so far drilled in the UK Continental Shelf was at 6,000 feet [over 1,800m] of water".' According to DECC statistics on existing production installations in the West of Shetland (WoS) Basin, BP has a platform on the Clair field, and two processing ships in the Foinhaven and Schiehallion Fields. The Clair began production in 2005, and has a water - depth of around 140m. The Foinhaven has a water depth of between 400-600m and the Schiehallion 350-450m. We heard from Paul King, Managing Director of Transocean's North Sea Division, that: "The Paul B Lloyd [a Transocean rig] is working for BP west of Shetlands at the moment in up to 3,000 feet [over 900m] of water".8 The Tormore and Laggan fields are being explored by Total and lie in 630m of water.' Total is also searching 1,600m underwater in the Tobermory field, north of the Clair field. Chevron is exploring the Rosebank-Lochnagar fields in 1,115m of water.10 In comparison, the Deepwater Horizon was drilling in ultra-deepwater at a depth of 1,544m. Operations on the UK Continental Shelf 11. The Macondo Well in the Gulf of Mexico was being drilled into a high-pressure, high - temperature (HPHT) "over -pressurised" oil and gas reservoir. Over -pressurised wells are hazardous as the fluid in the reservoir can escape rapidly. Total pointed out that while they have operational experience of such fields in the Central North Sea, the geological SQ1 6 Q 239 •7 QS BQ69 e Ev 77 0 Chevron Business Portfolio, www.chevron.com/countries/unitedkingdom/businessportfolio 8 conditions encountered WoS are very different and "no significant overpressure" has been encountered in that area to date. 11 Dr Hayward told us: "there is nowhere where we are drilling in deepwater [in the UKCS] and the reservoirs have high pressures and temperatures".12 12. DECC figures estimate that the deepwater oil and gas resource (which includes estimates for future discoveries) of the West of Shetland and the less well explored West of Scotland account for 15-17.5% of UK total resources. However, the resource estimates for the West of Scotland (located north of the Outer Hebrides) area are highly uncertain." 13. As part of Total's development of the Laggan-Tormore area (600m in depth) in the WoS, a new gas pipeline system is being built that will connect these discoveries to the UK mainland. The new system has been "oversized" with the expectation that further exploration and development in the coming decades (including prospects that in isolation could not justify the cost of this infrastructure) will take advantage of the excess capacity. This development has started with the construction of a new gas plant in Sullom Voe, the Shetland Island's oil and gas terminal. Total hope that discoveries such as Tobermory, located eight blocks north of the Clair field and in 1,600m of water, will create opportunities for new fields and infrastructure that "would further protect the UK's security of supply".19 14. DONG Energy is one of the largest acreage holders in the WoS region and a partner in • Total's recently sanctioned Laggan-Tormore gas development. DONG Energy is not currently drilling as operator in UK territorial waters, but drilled the WoS Glenlivet gas field in 2009 and has interests in a further six discoveries." 15.On 1 October 2010 the Government gave the go-ahead for the first deepwater drilling off Britain since the Gulf of Mexico incident. This consent was given to Chevron to drill in the Lagavulin Prospect located in the West of Shetland area at a depth of just over 1,500m (comparable to the Macondo Well). Chevron and its partners plan to drill an exploration well in the prospect with an expected duration of six months. In accordance with UK regulation, an Environmental Statement for the well has been in the public domain since March 2010.16 Chevron has drilled 18 deepwater wells in the WoS since 1987 without serious incident, and is also exploring the Rosebank-Lochnagar fields in 1,115m of water.17 11 Ev 77 11 Q 114 13 Ev 596 • 4 Ev 77 15 Ev 632 6 Ev 591 17 Ev 591 • 3 Offshore Regulation 16. In the Annual Energy Statement to Parliament on 27 July 2010, Rt Hon Chris Huhne MP, DECC's Secretary of State, announced that the UK would, "undertake a full review of the oil and gas environmental regulatory regime" following the outcome of investigations into the causes of the Gulf of Mexico incident.]$ This was a re -announcement of plans released originally on 8 June 2010, by which date a review by DECC officials had already found the UK's existing regulatory regime "fit for purpose".19 Mr Webb, of the industry - body Oil and Gas UK, told us: "possible [regulatory] enhancements are relatively marginal in nature",20 and "[UK regulations mitigate] strongly against the likelihood of anything like Macondo ever happening here".21 UK Offshore Regulatory Regime 17. Charles Hendry MP, Minister of State for DECC, told us: "the regime we have in place in the North Sea is one of the most robust in the world".22 The offshore safety regime was revised following the Cullen Inquiry into the 1988 Piper Alpha disaster, leading to a tripartite arrangement for offshore regulation. Mr King, Managing Director of Transocean's North Sea Division, told us: "If I look at the conditions I worked under offshore in 1975 and compare that to the way we operate today [since the Cullen Inquiry], • there is no comparison whatsoever".23 Total's Mr Festor added: "I came back [after] 30 years [... ] and I discovered that here in the UKCS—before Piper Alpha and after Piper Alpha —it's another world".24 18. Mr Webb told us: "[The Cullen Report into Piper Alpha] called for the revision of responsibilities between the licensing regulation and safety regulation, and it was from that that the whole concept of the safety case came and the whole concept of independent verification and inspection"." The Health and Safety Executive (HSE), an executive non - departmental public body of the Department for Work and Pensions, has responsibility for assessing and regulating the integrity and safety of offshore installations in the UK. DECC's Energy Development Unit ,is responsible for licensing and regulating UK oil and gas activities, including environmental regulation, and the approval of Oil Pollution Emergency Plans (OPEPs).26 The Maritime and Coastguard Agency (MCA), an executive agency of the Department for Transport, is responsible for deploying counter pollution measures during an oil spill. The US Minerals Management Service (MMS) that oversaw both regulation and licensing of offshore drilling during the Deepwater Horizon incident to HC Deb, 27 July 2010, col 867 19 "UK increases North Sea rig inspections", DECC Press Release, 8 June 2010 20 Q 1 21Q1 22Q271 • 23Q36 2" Q 234 (Festor) 2s Q 85 11 Ev 596 • 10 has since been split into separate agencies, reflecting the changes that took place in the UK after the Piper Alpha incident.27 19. The HSE requires that all operations have detailed safety cases on potential dangers, their consequences, and the methods of controlling any risks. The overall responsibility for safety on an installation falls to the Safety Case Duty Holder who appoints an Offshore Installations Manager (OIM) to discharge this responsibility. In the case of mobile drilling rigs, the duty holder is the drilling contractor (for example, Transocean in the Deepwater Horizon incident). Mr Walker, Head of the HSE's Offshore Safety Division, told us: "Before an operator brings a drilling rig into the UK or operates a fixed platform, they have to prepare a safety case for the Health and Safety Executive to approve"." 20. The Operator, or Licence Holder (for example, BP in the Deepwater Horizon incident), is subject to separate and additional verification requirements under the Design and Construction Regulations in the form of well examinations carried out by an independent and competent person (ICP). All parties involved have legal duties to cooperate with both the OIM and the well Operator when the well is under construction. The Safety Case Duty Holder and the well Operator must demonstrate how their safety management systems will operate together, who has primacy in an emergency, and who has overall responsibility. 21. The UK's goal -setting safety regulations allow a flexible approach in the choice of technology and systems to meet safety standards. Oil and Gas UK, the industry association, • described the goal -setting regime to us: The UK's goal -setting safety regime requires a systematic approach to the identification of hazards and through the application of quality engineered solutions and systems ensures that risks are reduced to as low as reasonably practicable (ALARP).29 This is in contrast to the prescriptive regulatory regime that the Deepwater Horizon operated under in the United States.30 A prescriptive regime has specific obligations on the types of equipment required and the degree to which a risk has to be mitigated. 22. In the light of recent drilling activity in the waters around the Falkland Islands, we asked witnesses from OSPRAG and Oil and Gas UK whether the UK regulatory regime applied to drilling in that area. There was a lack of clarity over responsibility for drilling and oil response in the Falkland Islands. We recommend that the Government clarify what regulatory regimes apply to drilling and oil spill response in the Falkland Islands and who is responsible for enforcing them. US and UK Offshore Regulations 23. The industry association Oil and Gas UK pointed out the different basin characteristics between the Gulf of Mexico and the UK Continental Shelf, and the way in which the UK ""Salazar Divides MMSs Three Conflicting Missions", US Department of the Interior press release, 19 May 2010 • 26 Q 189 29 Ev 63 M • 11 regulatory safety case regime is more advanced than in the US. They also highlighted the following differences in regulation between the US and the UK: in the UK the safety and licensing aspects are handled by two separate regulatory bodies, the HSE and DECC respectively —by contrast, until the Deepwater Horizon incident, both safety and licensing fell under the remit of the US Minerals Management Service, MMS; • design of all UKCS wells requires clearance by an independent competent person (ICP) who is contracted and paid for by the oil and gas exploration company; and • the safety case —required for all UK installations and introduced following the recommendations of the Cullen Report into the 1998 Piper Alpha disaster. 24. DECC gave evidence that since drilling began on the UKCS in 1964, over 10,000 wells have been drilled, and "although there have been a small number of incidents [... ] there has not been an oil blow-out [as opposed to a gas -blowout] or any significant spillage of oil directly resulting from drilling operations".31 25. Mr Steve Walker, Head of HSE's Offshore Safety Division (OSD), told us: "we have a more sophisticated inspection regime [compared to the US] because we have a performance -based legislation [... ] we have a different safety culture compared to the safety culture that applied in the Gulf of Mexico".32 • Environmental Regulation and Inspection 26. DECC's Energy Development Unit is responsible for licensing and regulating UK oil and gas activities, developing the environmental regulatory framework for the UK Continental Shelf (UKCS), and for administering and ensuring compliance with that regime in relation to offshore oil and gas exploration and production and decommissioning, including the approval of facility -specific Oil Pollution Emergency Plans (OPEPs). The Minister told us: "[DECC inspectors] are looking at the environmental implications [... ] during the drilling process [whereas] The HSE are responsible for every aspect of safety on those operations for the whole of their lifetime"." 27. Among the interim steps taken in the UK since the Deepwater Horizon incident, DECC doubled the number of annual environmental inspections to drilling rigs, and recruited three additional inspectors. This brought the total number of inspectors to ten (including one senior inspector). Given DECC's less extensive areas of responsibility compared to the HSE, it and its predecessor Departments have all operated with fewer inspectors than the HSE—the HSE Offshore Division has 114.5 specialist inspectors, while DECC has ten environmental inspectors.34 DECC inspectors visit offshore installations and onshore offices to inspect records and management systems, as well as interviewing people and observing site conditions, standards and practices. DECC told us that the increased 31 Ev 596 33 Q 189 33 n 287 34 Ev 596 • 12 number of inspectors will allow "DECC to double the number of environmental inspections carried out on mobile drilling rigs in the UKCS from an average of eight to at least sixteen on annual basis with immediate effect"." The Minister referred to the movement of inspectors between the public and private sectors.36 This may make it difficult for DECC to recruit and maintain high -quality inspectors in the future. 28. DECC's Offshore Inspectorate describe their environmental inspection strategy as "risk based".37 Of the rigs currently undertaking drilling activities (approximately 24 according to DECC), about 20% are on gas reservoirs, which DECC say "inherently pose less of a potential risk to the environment compared with those working on oil reservoirs".38 Taking this into account, along with the location of the rig and the nature of the well, DECC targets inspections on rigs undertaking drilling activity on specific oil reservoirs. 29. We heard from oil and gas industry representatives that they were not aware of anyone on their boards who had a background in environmental consultancy.39 Given the potential environmental impacts —and the large associated costs —that we have seen in the Gulf of Mexico as a result of an offshore incident, we are surprised that companies have not seen fit to include such expertise on their boards. 30. Oil company boards lack members with environmental experience. The industry should take steps to remedy this and the Government should encourage them to do so. Emergency Response 31. Oil Pollution Emergency Plans (OPEPs) set out the arrangements for responding to oil spill incidents that have the potential to cause marine pollution. They aim to prevent such pollution and reduce or minimise its effects should it occur. OPEPs are risk assessments that are relevant to a specific field or installation. The plans focus on the worst -case scenario; following the Gulf of Mexico incident, UK operators are now required to carry out additional modelling for deepwater drilling installations, including an extended assessment of oil spill beaching predictions. The plans are also reviewed by Maritime Coastguard Agency and relevant consultees, such as the Marine Management Organisation (or relevant devolved authority), the Joint Nature Conservation Committee and the relevant inshore statutory body. Changes since Macondo 32. We asked witnesses how they had changed their methods of operation in UK deepwaters since the incident in the Gulf of Mexico. Mr Cohagan of Chevron told us: "I don't believe that we have fundamentally changed in any way [since the Deepwater Horizon incident]".40 This was owing to the strong regulatory regime that was a legacy of 3s Ev 596 36 Q 288 • 37 Ev 596 38 Ev 596 39 Qq 247-249 40 Q 229 • 13 the Cullen Inquiry into the Piper Alpha incident. With regard to making any regulatory changes in response to the Deepwater Horizon tragedy Mr Webb was wary of "making global and universal changes that may not be appropriate from situation to situation [... ] the kernel of what we have in the safety case regime, is, on a case -by -case basis, the expertise within the industry [... ] the independent verifier, and then [... ] the regulator"" 33. There is a sense that the industry seems to be responding to disasters after they have happened rather than anticipating and planning for high -consequence, low probability events. Dr Hayward agreed that "there is no doubt that the inability of BP and the industry to intervene because it wasn't properly prepared was unacceptable".42 He went on to observe that "the occurrence of black swans [high -impact, low -probability events] seems to be more often than not these days".41 Mr McAllister admitted that "as an industry, if we can do something better, it is to make sure that we do not take maybe such an introverted view of our operations" 44 34. We conclude that the UK has high offshore regulatory standards, as exemplified by the Safety Case Regime that was set up in response to the Piper Alpha tragedy in 1998. The UK regulatory framework is based on flexible, goal -setting principles that are superior to those under which the Deepwater Horizon operated. 35. Nevertheless, despite the high regulatory standards in the UK we are concerned that the offshore oil and gas industry is responding to disasters, rather than anticipating • worst -case scenarios and planning for high -consequence, low -probability events. Authority to Stop Operations Offshore 36. We were told from both the regulator and industry that there were people on offshore installations who —at all times —have the authority to close off the well.41 Mr Walker told us: "there will be a bridging document between the rig owner's systems and the well operator's systems to make sure that issues such as who has the final say [... ] [are] well and truly agreed before you start the operation".46 The HSE told us that there will always be one person who is ultimately responsible for safety on the rig, and that is the Offshore Installations Manager (OIM), who is usually the drilling contractor. 37. There are enormous financial costs of halting or delaying drilling operations, even for short periods. In the case of the Deepwater Horizon, BP aimed for the drilling of the Macondo well to take 51 days, at an estimated cost of $96 million. It was expected that the drilling platform would be leaving as early as 8 March 2010, but the Macondo well took longer to complete than anticipated. By 20 April —the day of the blowout that killed 11 workers —the rig was 43 days late, which would have cost an extra $21 million in lease fees 41 Q 52 (Webb) 42 Q 158 43 Q 127 �Q 8% 45 Qq 242, 286 41 Q 200 (Walker) • 14 alone." There is a risk that those responsible for taking decisions to halt operations could feel commercial pressure not to do so if at all possible. 38. It is imperative that there is someone offshore who has the authority to bring a halt to drilling operations at any time, without recourse to onshore management. We urge the Government to seek assurances from industry that the prime duty of the people with whom this responsibility rests is the safety of personnel and the protection of the environment. Catastrophic Failure of the BOP 39. The last line of defence against a blowout of the Macondo well was a device called the "blind shear ram", part of the blowout prevent (BOP) stack located on top of the wellhead, over a mile below the surface on the ocean floor. If the upward pressure from the oil and gas in the reservoir overcame the downward pressure of the heavy drilling fluid — and all other recourses to control the well failed — the blind shear ram's two blades, or "pinchers" as they are sometimes referred to, were supposed to slice through the drill pipe and seal the well. The importance of the BOP was highlighted by Dr Hayward who told us "If it [the BOP] had functioned as designed, there would not have been the [Deepwater Horizon] accident"41 40. The blind shear ram is described as the "ultimate fail-safe device". The Deepwater • Horizon had a single blind shear ram located inside the 15.5m tall BOP stack at the wellhead on the seafloor. An April 2000 report Risk Assessment of the Deepwater Horizon BOP Control System carried out by EQE International for Cameron Controls Corporation (the manufacturer of the BOP for Transocean, owner of the rig) concluded that: The major contributor to the failure likelihood associated with the BOP control system results from the selected stack configuration. With only one shear ram capable of sealing the well in, it is extremely difficult to remove all the single failure points from the control system. The final shuttle valve, which supplies the hydraulics to the blind shear ram, represents such a single point failure [... ] and accounts for 56% of the failure likelihood of the system to perform an EDS (Emergency Disconnect Sequence)." 41. A further concern is that with a single blind shear ram, there is a risk it could close on one of the extremely strong joints that connect the sections of drilling pipe, and be unable to collapse it. Such a risk is mitigated by the use of two blind shear rams. Deepwater Horizon's single blind shear ram malfunctioned and never fully closed. 42. Despite the fact that the BOP on the Deepwater Horizon had only a single blind shear ram, Dr Hayward told us that: "The blowout preventer that you are referring to was fully compliant with the [US] regulatory regime and it should have functioned".50 Mr Bernard 61 Fleet Status Report, Transocean, 13 April 2010, www.deepwater.com 4e Q 181 49 Risk Assessment of the Deepwater Horizon Blowout Preventer (BOP) Control System, EQE Holdings, April 2000, http://documents.nyti mes.com/documents-on-the-oil-spill#document/p2 50Q91 • 15 Looney of BP North Sea told us: "We operate at the moment two mobile drilling units in the North Sea. They have one blind shear ram".51 However, Mr Looney went on to explain that as a result of the Macondo incident they were now bringing an independent third party on to each rig to ensure that the BOP had not been compromised and was operating as it was designed to." 43. In the UK, the BOP has to be tested every 14 days.53 As to whether a drilling rig in the UK could operate with the same BOP setup as the Deepwater Horizon, Mr Walker, head of the HSE Offshore Safety Division, told us "we would have asked the well operator [... ] `why have you chosen that design? Why have you chosen, say, only one [blind shear] ram or two rams' [... ] we would then assess their answers"." 44. Mr Cohagan, Managing Director of Chevron UK, told us that adding an extra blind shear ram to existing BOPs would be a difficult job, as they can be up to three storeys tall and extremely heavy." Mr Cheshire added "if it's not the appropriate piece of equipment for the specific well [... ] you are taking more [health and safety] risks with individuals handling these at the surface"." 45. Given that the failure of the single blind -shear ram to fire on the Deepwater Horizon's blowout preventer seems to have been one of the main causes of the blowout of the Macondo well, we recommend that the Health and Safety Executive specifically examine the case for prescribing that blowout preventers on the UK Continental Shelf are equipped with two blind shear rams. 46. At an advanced stage in the inquiry it came to our attention that an incident had occurred on a Transocean platform on 23 December 2009. The Sedco 711 platform was being operated for Shell in the North Sea Bardolino Field. According to Tom Fielden of the BBC: [... ] key indicators that something was going badly wrong were either misinterpreted or discounted [... ] A major spill was averted only when the BOP, or blowout preventer, was activated capping -off the well on the sea floors? 47. Once this incident was brought to the public attention, Shell issued a statement on the incident that had been updated from 18 August 2010. Shell said, "the well was successfully closed using the BOP [... ] Three barrels of oil -based drilling mud were released into the sea, no people were injured and there was no loss of asset integrity".58 Shell pointed out that the well involved "differs from the Gulf of Mexico in that it is not in deepwater and it is not a high pressure well".59 In evidence originally submitted to us by Transocean, the only 51Q155 53 Q 156 53 Qq 44, 258 54 Q 1 g0 55 Q 258 [Cohagan] se Q 258 [Cheshire] 51 BBC News Blog, Tom Fielden, 7 December 2010, www.bbc.co.uk/blogs se Response Statement on Bardolino "Kick", Shell, 18 August 2010—updated 7 December 2010 ss Response Statement on Bardolino "Kick", Shell, 18 August 2010—updated 7 December 2010 • 16 reference to the Sedco platform was that it was now operating West of Ireland rather than on the UKCS.60 48. We asked Transocean and the HSE to provide further information on the nature of the incident that took place on 23 December 2009. Transocean noted that the Sedco 711 incident was a "matter of public record" and that they had "reported the incident to the HSE [... ] on 24 December".61 Regarding reports that there was "not enough heavy mud available to pump back down into the well" to control it,62 Transocean explained that: The mud displaced from the hole after the blowout preventer was closed was contaminated with hydrocarbons [oil and gas] and not suitable to pump back in the hole. As a result, good mud needed to be brought back onboard from a supply vessel.61 49. However, given that there will always be a risk that drilling mud could become contaminated with hydrocarbons during a loss -of -well -control event, it is not clear why Transocean did not have sufficient ingredients for kill -weight mud on the platform. According to the oilfield services provider Schlumberger: "Kill -weight mud, when needed, must be available quickly to avoid loss of control of the well or a blowout".64 We see this as yet another example of the offshore industry not planning for high -impact, low probability events. The HSE told us: • There is no specific prescriptive requirement to have mud of the required density that could kill the well onboard a drilling installation at all times [... ] It is therefore good industry practice to have sufficient weighting agents onboard the installation that can raise the mud's density to kill the well if required.61 50. However, the HSE stated that the "performance of the crew prior to the incident was not satisfactory" and "problems caused by not having sufficient mud at the correct mud weight available should have been foreseeable, planned for and dealt with better by the offshore and onshore management".66 In light of the Sedco 711 event Shell and Transocean implemented "corrective actions" that the HSE told us "addressed the shortcomings that led to this incident" 67 51. The UK's goal -setting safety regulations allow a flexible approach in the choice of technology and systems to meet safety standards. However, evidence to us from the Institute of Mechanical Engineers told us: "the safety regimes have focused heavily on mitigating and managing consequences rather than fundamental integrity assurances in equipment and systems",6a a call that was echoed by the Marine Conservation Society for so Ev 59 61 Ev 133 62 BBC News Blog, Tom Fielden, 7 December 2010, www.bbc.co.uk/blogs 63 Ev 133 64 "Kill -weight fluid", Oil Field Glossary, Schlumberger, www.glossary.oilfield.slb.com is66 6s Ev 635 Ev 635 67 Ev 635 6e Ev wl • 17 the HSE to provide "more guidance and possibly regulation with regard to the best available technology".69 Mr Walker of the HSE argued: "performance -setting legislation [...] [is] more challenging for the industry [than prescriptive regulation]".71 52. While the flexibility of the UK safety regulation regime appears to have worked well, we recommend that for fail-safe devices such as the blowout preventer the Government should adopt minimum, prescriptive safety standards or demonstrate that these would not be a cost-effective, last -resort against disasters. The Importance of Simple Checks 53. An examination of the two control pods on Deepwater Horizon's BOP following the accident revealed that there was a fault in a critical valve in one of the control pods, and that the other control pod had insufficient charge on its batteries; these faults probably existed at the time of the incident." At least one operational control pod was required to operate the Automatic Mode Function (AMF) which would have closed the BOP. The AMF function should have happened automatically, without intervention, when the electric cables and hydraulic line were damaged during the explosion on the rig. The AMF is a critical backup system, also known as the "deadman". 54. We are concerned that such simple failures were not spotted during inspection. Dr Hayward told us: "we have implemented across our global drilling operation a programme • to ensure that the equipment will do what it is designed to do [... ] the second thing we have done [... ] is significantly enhance the testing protocols of blowout preventers, including ensuring that the backup systems work and are tested in the course of drilling a well".72 Although the new regime is welcomed, this is another example of the industry responding to a disaster rather than anticipating a potential problem. 55. We believe that the Government must ensure that the UK offshore inspection regime could not allow simple failures —such as a battery with insufficient charge —to go unchecked. Independence of ICPs 56. Unlike the US regulations under which the Deepwater Horizon operated, design of all wells on the UK Continental Shelf (UKCS) requires clearance by an independent competent person (ICP). UK companies are also required by law to ensure that their well is managed in such a way that there can be no unplanned escape of oil or gas (or any other well fluids) and that risks to people and the environment are as low as reasonably practicable. This requirement is set out in the Offshore Installations and Wells (Design and Construction, etc) Regulations 1996 (DCR), covering all stages of a well's life including 69 Q 70 19292 71 Deepwater Horizon —Accident Investigation Report, BP, 8 September 2010, www.bp.com 72 Q 107 • 18 design modification, commission, construction (drilling), operation, maintenance, suspension of activities and abandonment.73 The DCR regulations require that: • the conditions below ground are properly assessed beforehand; • the materials used for all parts of a well are suitable for the task; • the well control equipment is installed to protect against blowouts; and • the well is operated by appropriately qualified people. 57. A key component of the regulations is the requirement for a formal well examination scheme and the appointment of an independent well examiner who must verify the design, construction and maintenance of a well. An operator must have arrangements in place for a well examination scheme by such an ICP before starting on a new well design. The ICP monitors all stages of the well's life from planning through to execution and operation. It is also the ICP's role to examine how the operator controls the pressure in the well, and to ensure that the pressure containment equipment that forms part of the well is suitable for this purpose. 58. A well's ICP is normally employed by a separate specialist company, and must be sufficiently knowledgeable and separate from the immediate line management of the well operations. These details must be available for inspection by HSE. Well designs are usually peer -reviewed by in-house and external bodies at each stage. Chevron state that their well design process is now subject to an additional peer review by "experienced drilling staff from our Gulf of Mexico Deep Water business unit".74 The final well design is presented to and examined by the independent Well Examiner and the HSE. 59. Mr McAllister of OSPRAG told us: "the independent company [...] is populated by seasoned drilling professionals, who've got no commercial interest in the well".75 He added: "they [...] may have worked in oil companies in their past".76 Mr Toole of DECC told us that if his organisation felt the degree of independence between the ICP and the operator was insufficient they would do something about it.77 Even so, Ms Susie Wilks, Biodiversity Lawyer for ClientEarth argued that "the legal requirement[s] for independence are not tough enough"." 60. Whilst there is a risk of conflicts of interests affecting the judgement of independent competent persons who assess the design of wells we have had no evidence of such conflicts presented to us. "Offshore Installations and Wells (Design and Construction, etc) Regulations 1996 (sl 1996/913) 74 Ev 591 7Q 76 30 Q 30 77 0276 71 Q 211 (WiIks) • 19 Protection of Whistle -blowers 61. Due to the enormous commercial pressures to keep a drilling rig operating, we are concerned that employees who try to draw attention to safety problems may be —or feel — intimidated by their managers. Dr Jonathan Wills, Independent Councillor for Lerwick South and freelance environmental consultant told us that "whistle -blowers are not able to call a halt to things and the managers are obviously trying to make money for the company [... ] They're not there to protect the environment".79 However, Mr Webb of Oil and Gas UK tried to assure us that the offshore workforce are "free and able to intervene on issues of safety, and without fear of retribution"." This assurance was repeated to us by other members of the industry.81 62. However, the HSE Offshore Division's Specialist Inspection Report for 2009 indicated that Transocean rig staff were subject to "bullying, aggression, harassment, humiliation and intimidation" from offshore management.12 When we asked Paul King —Managing Director of Transocean's North Sea Division —about these claims, he told us: [... ] the report needs to be viewed in its entirety [... ] We have several alternative ways for people to get [... ] [safety concerns to us including] via an ombudsman line, which is manned by a third -party company. Anybody who has anything that they are concerned about can, in complete confidence, talk to someone and report it, and move on from there.83 63. Mr Cohagan of Chevron UK described to us a "stop work authority card" that are handed out offshore.84 These cards have Mr Cohagan's signature on, and he told us: "it says `Not only do you have the duty but you have the responsibility, if you see anything wrong, to stop the work."' When we raised concerns with the Minister about intimidation of whistle -blowers, he told us: "The crime is not reporting [health and safety concerns]".85 64. We asked the oil and gas industry about a policy known as "not required back". This was the process by which an Offshore Installations Manager (OIM) could have contractor personnel permanently removed from a rig. Oil and Gas UK, the industry -body, highlighted concerns in trade unions and the industry that the "lack of a clear and transparent process could potentially prevent individuals from raising safety concerns".86 Oil and Gas UK worked with trade unions to introduce new guidelines to ensure that "where removal [of personnel from a rig] is deemed an appropriate course of action [... ] this is done in a fair and transparent way"." Mr Looney, of BP North Sea, told us: "We are fully compliant with the [not required back] agreement that Oil and Gas UK as a trade 79Q210 80 Q 41 (Webb) 81 Qq 34, 41, 124, 234. ez HSE Offshore Division Human and Organisational Factors Team, Specialist Inspection Report—Transocean Offshore (North Sea) Ltd, (from inspections undertaken in 2009) 83 Q 34 en Q 234 85 Q 316 (Hendry) 86 "New Oil & gas UK Guidelines Lift Shadow of NRB", 25 February 2009, Oil and Gas UK Press Release 87 "New Oil & gas UK Guidelines Lift Shadow of NRB", 25 February 2009, Oil and Gas UK Press Release • 20 association has with the unions and the workforce and we have no issues with that policy".88 65. At an advanced stage in the inquiry we received evidence from the National Union of Rail, Maritime and Transport Workers (RMT) regarding the need for offshore safety representatives to have greater powers. The RMT told us that they "want to see more specialised training become a statutory entitlement [... ] Safety Reps should have the statutory power to insist on more training".R9 The RMT are of the opinion that the existing "five-day basic safety rep course" is insufficient, and the following specialised training should become a regulatory requirement: • principles of Risk Assessment; • root Cause Analysis—accident/incident investigation; • major hazard awareness; • development of safety auditing/inspection skills; and • communication skills —presentation, negotiation, interpersonal, and meeting organisation. 66. We find some conflict in the reports from the HSE about bullying and harassment on rigs and the assurances of the industry that sincere whistleblowers will be heard and protected. We recommend that the Government should discuss with the industry and unions what further steps are needed to prevent safety representatives from being or feeling intimidated into not reporting a hazard, potential or otherwise. Contractor Oversight 67. BP's Bly Report emphasises that the failures that led to the Deepwater Horizon incident involved a number of companies as well as themselves. Dr Hayward told us: "in our report we talk about [the need for] `significantly greater oversight [of principal contractors]"'." Dr Hayward went on to tell us that they had identified "a lack of rigour and quality of oversight" of contractors as one of the factors leading to the incident.91 68. It is important and necessary that the offshore safety culture is cascaded throughout the supply chain, from existing contractors at all levels, through to new -entrants on to the UK Continental Shelf. Operating in Different Regulatory Regimes 69. The oil and gas industry operates under many different regulatory regimes around the world. BP North Sea's Mr Looney told us "We apply the same standards [worldwide]. They 88 Q 132 69 Ev 634 90 Q 112 91Q121 • 21 are clearly influenced by variations in regulatory regime". Dr Hayward added that: "this does not imply a difference in the level of standard but there are different requirements".92 70. To demonstrate operating at the same standard, but under different regulatory requirements, Mr Festor of Total described to us the assumptions that were made when designing the well -casing under different regulatory regimes.93 These assumptions define the load that will be applied on the casings. In the US, the sealed well is assumed to be half full of liquid, and half full of gas. In the UK it is assumed to be full of gas. The UK assumption is more conservative, leading to the casing being able to withstand a greater load, as under the US assumption the liquid offsets a greater proportion of the upward pressure from the oil and gas in the reservoir. 71. We received evidence from the industry, regulators and other stakeholders, that the UK offshore regime changed dramatically for the better after the Cullen Inquiry into the 1988 Piper Alpha tragedy. A comparable change in regulatory regime is expected in the US as a result of the incident in the Gulf of Mexico. Already in the US, the responsibilities for licensing, safety and promotion of the oil and gas industry have split into three separate agencies.94 Under the regime that the Deepwater Horizon operated in the Gulf of Mexico, these issues were all the responsibility of the US Minerals Management Service (MMS). In the UK, promotion of the oil and gas industry —namely, identification of investment opportunities and liaising with new entrants —remains within DECC (under the Energy Development Unit) along with licensing. Platform, the social and ecological justice • campaigners, argued that "close links between the [... ] industry and the government [... ] undermine public confidence in the ability to regulate and legislate effectively".95 The Minister told us: "It's the industry's own job to promote itself"' and that if "[other countries] decide to go beyond [...J [the level of UK regulation] we would need to [...] respond to that".97 72. There is both risk and the advantage of competition where global oil and gas companies operate to different standards when working in different regulatory regimes. We recommend that the Government monitor any changes in the US regulatory regime to see if —in the light of the response to the Deepwater Horizon incident —the US establishes a new gold -standard of regulation, as the UK and Norway did after the Piper Alpha tragedy. We would urge the Government to work with regulators in other offshore oil and gas provinces to ensure that the highest standards of safety can be achieved globally through an exchange of best practice lessons. Licensing 73. Before a drilling programme is approved, the HSE needs to be satisfied that well design and construction are satisfactory and DECC needs to be satisfied that emergency plans for 9' Q 102 99 Q 262 (Festor) 94 "Salazar Divides MMSs Three Conflicting Missions", US Department of the Interior press release, 19 May 2010 99 Ev 598 96 Q 300 97 Q 322 • 22 all wells represent best practice. We were told that, "for deepwater drilling, operators are being required to demonstrate that the factors identified in the BP report have been satisfactorily addressed".98 On 27 October 2010 it was announced by DECC that 144 licences to extract oil and gas from UK waters were offered in the 26" licensing round.99 Controversy over the Bly Report 74. In a press release on 8 June 2010, the Secretary of State said that the Deepwater Horizon incident gave the Government, "pause for thought [... ] given the beginning of exploration in the deeper waters West of Shetland".10' DECC claims that the process of approving new licences for deepwater wells "now includes rigorous testing against the findings of BP's report into the causes of the Deepwater Horizon accident".101 But we note that BP's internal investigation —the Bly Report —into the Gulf of Mexico incident implied that, while BP was partially responsible for the disaster on Transocean's Deepwater Horizon drilling rig, decisions made by "multiple companies and work teams" contributed to the incident.102 Dr Hayward said, "to put it simply, there was a bad cement job [... ] based on the report, it would appear unlikely that the well design contributed to the incident":103 a claim he reiterated when giving evidence to us.114 If the Macondo Well design were found to be seriously flawed, BP would be liable for an additional fine of $15 billion under the US Clean Water Act.'os 75. Transocean, who owned the Deepwater Horizon and operated it on behalf of BP, • claimed that BP's well design was "fatally flawed", while BP's cement contractor Halliburton said that it found a number of omissions and inaccuracies in the Bly Report and, "contractors do not specify well design [... ] that responsibility lies with the well owner".10' British Gas (BG Group) told us that in their view "it appears that the Macondo blowout was significantly attributable to a flawed well design".117 76. It is argued that the Bly Report does not represent a "root -cause analysis" into the Macondo incident."' Its author, BP's Head of Safety and Operations, told us that "We were trying to understand what were the chain of events that happened and what the immediate causes were so that we could get some insights as quickly as possible".109 Mr Cohagan se Ev 596 99 "Blocks away —excellent results for latest offshore oil and gas licensing round", DECC Press Release, 27 October 2010 loo "UK increases North Sea rig inspections", DECC Press Release, 8 June 2010 101 Ev 596 102 Deepwater Horizon Accident Investigation Report BP, 8 September 2010, www.bp.com 103 BP Releases Report on Causes of Gulf of Mexico Tragedy, BP Press Notice, 8 September 2010, www.bp.com 104 Q 160 cos BBC News Blog, Robert Peston, 8 September 2010, www.bbc.co.uk/blogs ,oe "BP Oil Disaster Report Paves Way for Bitter Legal Battle", The Telegraph, 9 September 2010 107 Ev 592 roe Root -cause analysis (RCA) is a process of determining the root cause of a problem with the aim preventing a reoccurrence of the problem. 109 Q 119 • 23 argued that "If you really want to do a root cause analysis, it is a very time-consuming process".1' 77. We asked the Minister on the influence of the Bly Report on the safety regime in the UK. He told us that they had taken account of the recommendations in the Bly report, 11' but it was "not the building block of [licence granting]" 112 and DECC were "now waiting for the further US investigations to decide whether there are any recommendations [... ] we should take into account".1' We were assured when the Minister told us: "if there is further evidence that comes through that requires any greater tightening of those [licensing conditions] then we will take account of that"."' 78. The Bly Report—BP's internal investigation into the Deepwater Horizon incident — does not contain a root -cause analysis of the events that led to the blowout of the Macondo well, the loss of 11 men on the Deepwater Horizon, and the release of 4.9 million barrels of oil into the Gulf of Mexico. We urge the Government not to rely extensively on the Bly Report, given the controversy surrounding the responsibility for the incident and the design of the Macondo well, but rather to consider its conclusions in parallel with the observations of other companies involved with the incident, and with the recommendations of US agencies investigating the incident. 79. We believe that the environmental impacts of a sub -sea well blowout need to be understood and taken into account when a drilling licence is issued in the UK. We urge the Government to ensure that the licensing regime takes full account of high consequence, low probability events. 80. We observed throughout the inquiry that the offshore oil and gas industry believed they had mitigated away the risks associated with high -consequence, low probability events. The Minister told us: "as part of changes that we've made, [operators] have to look at worst case scenarios".1' 81. We recommend that as part of the drilling -licence process, the Government require companies to consider their responses to high -consequences, low -probability events — such as a blowout. The Government should not automatically accept claims that companies have mitigated away the risk of such worst -case scenarios. We urge the Government to introduce this requirement as drilling ventures into increasingly extreme environments. "0 Q 241 Q 250 "2 Q 305 "=Q69 269 Q 297 (Hendry) 115 Q 286 (Hendry) • 24 4 Liability and Compensation 82. The liability and compensation provisions in the UK could be inadequate given the high costs of dealing with the blowout of the Macondo well. Oil and Gas UK told us that companies operating in the UK "bear the full responsibility in the case of environmental or other material damage resulting from accidents or critical situations".1' The Minister told us: "The liability is quite clearly with the operator"."' In contrast, Ms Wilks, a biodiversity lawyer with ClientEarth, argued that there was an absence "of any [... ] clear, consistent and reliable regulatory framework for determining liability and compensation arrangements in the case of a spill".1' Ms Wilks explained to us that existing EU directives on environmental liability would likely `be of limited application in the case of a big spill in European waters".11' Cost of the Deepwater Horizon Incident 83. On 3 May 2010 President Obama announced that it was his Administration's view that BP was responsible for the oil spill, and that BP would be paying for the costs of the clean- up operation. By 7 June the estimated clean-up costs (including the cost of the spill response, containment, relief well drilling, grants to the US gulf states, claims paid, and federal costs) was $1.25 billion. On 16 June BP's Dr Hayward attended a high-level meeting with President Obama at which BP announced it would suspend shareholder dividends until at least the end of the year and set aside $20 billion (£12.5 billion) for an escrow fund to cover compensation claims stemming from the disaster.121 84. BP agreed to set aside $5 billion a year for four years, and decided to try and sell $10 billion worth of its assets to fund this. Some analysts suggested BP should sell its North Sea assets, as although it is a mature province, BP's North Sea portfolio still holds an estimated 3 billion barrels of oil. It emerged on 3 August that BP faced an additional penalty of $15 billion under the US Clean Water Act if the company was found liable for gross negligence.121 On 9 August 2010 BP announced that the oil spill had cost the group $6.1 billion, including $319 million paid out in compensation, and deposited the first $3 billion into the escrow compensation fund. By early September the cost of the incident had risen to $8 billion and $399 million had been paid out in compensation.122 Offshore Pollution Liability Association 85. In the UK DECC will not issue a licence for exploration unless the operator is a member of the Offshore Pollution Liability Association Ltd (OPOL). The use of this fund 16 Ev 63 117 Q 274 18 Q 215 is Q 215 1z0 An escrow fund is money held by a third -party. 121 BBC News Blog — Robert Peston, 8 September 2010, www.bbc.co.uk/blogs 122 "BP Says Cost of Spill Has Hit $8 Billion", The Wall Street Journal, 4 September 2010 • 25 represents a back up to a company's own insurance provision should it be insufficient to deal with compensation claims arising from offshore pollution incidents from exploration and production facilities. Since OPOL came into effect in 1975 its limits of liability have been increased, and they now stand at $250 million (£158 million) per incident. The annual aggregate is the predetermined amount to which an insurer will cover the insured each year, regardless of the number of claims submitted or defence costs associated with these claims. Mr McAllister of OSPRAG told us: If the third party liability under the OPOL [Offshore Pollution Liability Association Ltd] scheme for some reason does not materialise, and somebody defaults on that payment, the entire industry has a collective responsibility to meet those payments.12' 86. However, Ms Wilks of ClientEarth argued that "the limit of that [voluntary OPOL scheme] is $250 million and it's not enough [... ] voluntary means that it has no legal footing. There is no legal control over it".124 Ms Wilks went on to explain to us: [...]the OPOL scheme covers direct pollution damage [... ] it is debatable whether some of the widespread ecological effects that you can see and that [... ] [Dr Jonathan Wills] has talked about would qualify as direct damage according to the oil company that is going to be paying for it. So we need to have that system on a legal footing.125 87, The Minister explained that membership of the OPOL scheme was voluntary, but it . was simultaneously a pre -requisite for obtaining a licence from DECC.126 The Minister also told us that the limit of the OPOL scheme sounded small in comparison to the sums of money discussed in relation to the Deepwater Horizon incident because "economic activity in the north of Scotland compared to the [... ] Gulf of Mexico [... ] have resulted in a greater need there [the Gulf] for greater cover".127 KIMO UK (the Local Authorities International Environmental Organisation) told us: "the current compensation regime [... ] would leave oil spill responders out of pocket and the costs would ultimately rest with the taxpayer". 88. In July 2010 the US House of Representatives retroactively removed the liability limitation regime for vessel owners (including offshore oil and gas operations) for all claims arising on or after the date of the Macondo Well blowout, with similar legislation pending before the Senate.121 Transocean (the owner of the Deepwater Horizon) called for the UK Government "not [to] take action that could raise insurance requirements to unsustainable levels" as a number of companies, particularly small ones, would be unable to pay the increased insurance rates.121 On 13 October 2010 the European Commission announced new measures under which member states issuing drilling licences would have 123 Q 61 124 Q 217 125 Q 217 1:5 Q 273 is 21 Q 272 121 Securing Protections for the Injured from Limitations on Liability Act, US House of Representatives (H.R. 5503) 121 Ev 59 • 26 to ensure oil companies had the financial means available to pay for environmental damages.13' These proposals are at an early stage of development. 89. Dr Wills, Independent Councillor for Lerwick South and freelance environmental consultant, told us: "Compensation for victims of oil tanker spills is typically slow, grudging and inadequate [... I many Amoco Cadiz and Exxon Valdez claimants had died before the final payouts were made, 18 and 21 years respectively after the events".13' In March 1978 the Amoco Cadiz oil tanker split into three off the coast of Brittany, resulting in the largest ever oil spill to that date (1.6 million barrels).132 The Exxon Valdez struck a reef off the coast of Alaska in March 1989, spilling almost 285,000 barrels of oil —the remoteness of the area made it difficult to mitigate the impact of the spill on the surrounding environment.13 In January 1993 the Braer oil tanker ran aground 10 miles off the coast of Shetland, spilling almost 630,000 barrels of light crude oil.13' Dr Wills told us: A spill such as the Braer can mean bills far beyond the means of a small coastal local authority. In the end central government has to pay up if, as in the case of the Braer, the shipowners and their insurers contrive to escape full liability. So all spills cost the taxpayer.135 90. Given the high costs of the incident in the Gulf of Mexico, we believe that the OPOL (Offshore Pollution Liability Association) limit of $250 million is insufficient. We are concerned that the OPOL provisions only cover direct damage and also that the precise definition of "direct damage" is unclear. While membership of OPOL remains voluntary —despite it being a pre -requisite for a licence —its voluntary nature weakens its legality and the control and deployment of its funds. We believe this lack of legal control will allow polluters to claim that damages to biodiversity and ecosystems are indirect, and therefore do not qualify for compensation. 91. We conclude there needs to be clarity on the identity and hierarchy of liable parties to ensure that the Government, and hence the taxpayer, do not have to pay for the consequences of offshore incidents. We conclude that any lack of clarity on liability will inhibit the payment of compensation to those affected by an offshore incident. We recommend that it should be a requirement of the licensing process that the licensee prove their ability to pay for the consequences of any incident that could occur. We recognise that these measures could add to the cost of investing in new UK oil and gas production and urge the Treasury to reflect this when considering incentives to such investments. Speech by Commissioner Oettinger, 13 October 2010, http://europa.eu/rapid Ev 593 12 "Amoco Cadiz —the largest ever oil spill", June 2007, www.oilspillresponse.com "Exxon Valdez —the most expensive oil spill in history", March 2008, www.oilspillresponse.com Scottish Executive Fisheries Research Service, Ten Years on - MV Braer Oil Spill, 2003 15 Ev 593 • • n Insurance 92. Dr Wills told us: "the insurance industry could massively increase offshore standards tomorrow".136 We see the need for many large oil companies to self -insure as being indicative of the industry undertaking very large risks. Dr Hayward told us: "the reason that BP moved to self -insure [... ] was that we found the insurance market was not deep enough to provide us cover against some of the risks that we would want to insure"Y' In contrast, the Minister told us: "For smaller companies involved [... ] [in the UKCS] they would need to look more to the market in order to get their [insurance] cover"."' 93. We recommend that the Government consider whether compulsory third -party insurance should become a necessary requirement for small exploration and production companies. 136 Q 221 137 Q 162 138 Q 324 • 28 5 UK Oil Spill Response Oil Pollution Emergency Plans 94. UK offshore operators are required to have Oil Pollution Emergency Plans (OPEPs), the details of which have to be approved by DECC as required by the Offshore Installations (Emergency Pollution Control) Regulations 2002,1sv and the Merchant Shipping (Oil Pollution and Preparedness, response Co-operation Convention) Regulations 1998.14' The plans are reviewed by DECC, the Maritime and Coastguard Agency (MCA) and relevant environmental consultees, such as the Marine Management Organisation (or relevant devolved authority), the Joint Nature Conservation Committee (JNCC) and the relevant inshore statutory nature conservation body (for example, Natural England). 95. OPEPs set out the arrangements for responding to oil spill incidents that have the potential to cause marine pollution. They aim to prevent such pollution and reduce or minimise its effects should it occur. OPEPs are risk assessments that are relevant to a specific field or installation. The plans focus on the worst -case scenario; following the Gulf of Mexico incident, operators are now required to carry out additional modelling for deepwater drilling installations, including an extended assessment of oil spill beaching predictions. • 96. OPEPs use computer models to determine the likely movement of any spilled oil and the environmental sensitivities of the location. Predicting the wind direction and sea - current patterns are critical to the accuracy of such models and the subsequent response. For instance, in the West of Shetland, prevailing westerly winds would generally direct an oil spill towards the Shetland shoreline, so in the case of an oil slick the response would move immediately to coastal protection. It is acknowledged by DECC that the computer model used industry -wide (OSIS) has limitations with regard to predicting long term spill and deepwater effects.141 The Oil Spill Response and Advisory Group (OSPRAG) are undertaking a review of this model.14' 97. Depending on the nature of the spill, the response can range from monitoring slick behaviour, through to the use of chemical dispersants along with physical containment (the use of booms and skimmers) and recovery of the oil. To ensure the OPEP is, and remains, fit -for -purpose operators are obliged to hold a personnel and equipment exercise every five years with the MCA. Under the International Convention on Oil Pollution Preparedness, Response and Co-operation Convention 1990, adopted by the UK in 1994, all operators must test their OPEP offshore with every shift at least once a year.141 "'The Offshore Installations (Emergency Pollution Control) Regulations 2002 (51 2002/1861) 160 The Merchant Shipping (Oil Pollution Preparedness, Response and Co-operation Convention) Regulations 1998 (SI 1998/1056) Ev 596 42 Ev 596 43 Ev 596 • 29 Dealing with an Oil Spill in the UK 98. The MCA maintain stockpiles of counter pollution equipment at various sites throughout the UK, with oil spotting and dispersant spraying aircraft located in Inverness and Coventry. If this equipment is required, control of the incident will pass to the MCA and the Secretary of States' Representative for Maritime Salvage and Intervention, SOSREP, who represents DECC in relation to offshore installations, and the Department for Transport in relation to shipping. Oil spill response is divided into three categories depending on the amount of oil spilled: Tier 1-100 tonnes or 740 barrels —a small sized spill that will employ local resources; Tier 2-500 tonnes or 3,700 barrels —a medium spill requiring regional assistance; and • Tier 3-10,000 tonnes or 74,000 barrels —activates the National Contingency Plan.144 99. For comparison, it is estimated that approximately 4.9 million barrels of oil leaked into the Gulf of Mexico. The National Contingency Plan (NCP) is one of the measures the UK has taken to meet its obligations under the United Nationals Convention on the Law of the Sea (UNCLOS), setting out the circumstances in which the MCA's national assets are • deployed. The NCP supports and underpins an operator's required Oil Pollution Emergency Plan (OPEP), the details of which have to be approved by DECC. These include installation -specific risk assessments that model the likely path of an oil spill and environmental sensitivities. The date for testing OPEPs, NCPs and the powers of SOSREP has been brought forward from 2013 to spring 201 L15 100. While we acknowledge that oil spill response plans often share procedures for dealing with oil spills, this should not lead to complacency or a copy -and -paste culture in Oil Pollution Emergency Plans (OPEPs). Mr McAllister told us: "First of all, prevention; secondly, early containment and capping [... ] thirdly, what happens to the oil when it is released from the well [... I you would not expect the oil spill response plan to vary dramatically from one company to another".16 Mr Naylor of the MCA explained that 11certain elements of a plan [... I will be applicable for many types of field and for many types of activity'."' However, Mr Naylor assured us that the MCA has changed the OPEP requirements in light of the events in the Gulf of Mexico. 18 101. We acknowledge that oil spill response plans often share procedures for dealing with oil spills. There is some concern that in the past this may have led to a culture of copying -and -pasting rather than the production of site -specific plans which recognise the drilling environment and the risk of high -consequence, low -probability events. We 1°" Ev 67 145 Q 302 is146 Q 48 167 Q 193 148 Q 199 • 30 recommend the Government re-examine oil spill response plans to ensure that this is not the case. The Role of SOSREP 102. The role of the Secretary of States' Representative for Maritime Salvage and Intervention (SOSREP) was created in 1999 as part of the Government's response to Lord Donaldson of Lymington's review of the grounding of the Sea Empress oil tanker at the entrance to Milford Haven in 1996, which spilt around 70,000 tonnes of oil (over 500,000 barrels). SOSREP represents the Secretary of State for the Department of Energy and Climate Change in relation to offshore installations, and the Secretary of State for the Department for Transport in relation to ships and tankers. SOSREP is empowered to make crucial decisions, often under time pressure, without recourse to a higher authority, where such decisions are in the "overriding UK public interest".141 Lord Donaldson's Review had concluded that the involvement of Ministers in operational decisions was not a practical option. Mr Hugh Shaw, the current SOSREP, told us: "the bias for my role is certainly towards the shipping [... I the triggers for bringing myself in on the oil and gas side was probably [... ] less than 5% of actual incidents"."0 103. Legislation requires that every five years each operator must conduct an exercise to test a facility's Oil Pollution Emergency Plan (OPEP) with the involvement of SOSREP. The Maritime and Coastguard Agency (MCA) maintain stockpiles of counter pollution equipment at various sites throughout the UK, and have remote sensing and dispersant spraying aircraft located in Inverness and Coventry. If this equipment is required, control of the incident will pass to the MCA and SOSREP. SOSREP automatically becomes involved in any incident where there is a significant threat of significant pollution, known as the "trigger point" for intervention. The key responsibilities of SOSREP include: acting at the earliest point during a shipping or offshore incident to assess the risk to safety, to prompt the end of any such incident and to ensure that increasing risk is evaluated and appropriate measures taken to prevent or respond to escalation; monitoring all response measures to significant incidents involving shipping and the offshore industry; if necessary, exercising ultimate control by implementing the powers of intervention, acting in the overriding interests of the UK and its environment; and reviewing all activities after significant incidents and exercises. "I UK Spill Statistics 104. In August 2010 the HSE published its annual offshore statistics for 2009-10. These included the number of major and significant hydrocarbon releases, regarded as potential precursors to a major incident but not necessarily an actual oil spill to the sea.112 The number of hydrocarbon (oil and gas) releases each year has followed a falling trend from 2001-02 through to 2008-09, but increased in 2009-10.153 The HSE has recently increased 14I Ev 596 • so Q 301 151 "SOSREP Role and Responsibilities", Maritime and Coastguard Agency, www.mcga.gov.uk 53 HSE, "Offshore industry warned over 'not good enough' safety statistics", HSE Press Release, 24 August 2010 113 Ev 631 • 31 the level of its offshore investigations of all major and significant hydrocarbon releases to ensure that operators identify and address the causes of the increase. The data show that there was a significant increase in the total number of major and significant hydrocarbon releases (85) in 2009-10 compared to the previous year's total of 61. This compares to an annual average of 73 over the previous five years. From 2008-09 to 2009-10 the number of minor releases rose slightly from 96 to 100.Overall, the total number of releases rose by 26 in 2009-10."' 105. These HSE Statistics on hydrocarbon releases do not identify the incidents that led to a loss of liquid hydrocarbon to the sea (an oil spill), as the HSE spill severity classification focuses on safety implications to workers rather than environmental impacts. This data is instead required by DECC, who reported that during 2009 they were notified of 56 crude oil spills resulting in 6 tonnes of oil released into the sea, which was a significant reduction on the previous year when 83 crude oil spills led to 20 tonnes of oil released.15' DECC's Energy Development Director, Mr Campbell told us: "HSE look at hydrocarbon releases on the platform [...] [whereas] we're in small numbers here in terms of actual spills to the water". 116 Methods of Dealing with Spills Use of Sub -sea Dispersant • 106. One of the methods BP used to deal with the oil escaping from the Macondo Well was the use of chemical dispersants at the well head. Chemical dispersant had only previously been used on the surface. Dr Wills told us that "the use of dispersants on the surface is largely cosmetic"15' and Dr Hayward explained that "the volume of dispersant [used sub- sea] you had to apply was much smaller than you needed to apply at the surface to achieve the same effect,"' [... I [and the sub -sea use of] the dispersant was approved by the US Environmental Protection Agency [EPA]".15' We are concerned that the decision to use sub -sea dispersants was made after the event; the use of sub -sea dispersants was not a part of BP's oil spill response plan for the Deepwater Horizon. There was no scientific basis for the efficacy of dispersants used underwater, and we are therefore concerned about the potential unknown environmental impacts of sub -sea dispersants used in the Gulf of Mexico should they be employed in UK waters. 107. The use of sub -sea dispersants may have unknown effects. Mr Naylor of the MCA told us that he was "not sure that the technology [sub -sea use of dispersants] is sufficiently well developed to say that it is a response that could be used at the moment".16' Mr Cohagan of Chevron UK explained that "if we thought sub -sea dispersant would be $4 Ev 631 ss Ev 596 156 Q 295 • 1Q 201 Ise58 Q 170 159 Q 171 160 Q 195 r �J 32 something that would be a positive attribute to help disperse it [the oil spill], we would bring that forward".161 Mr Campbell, Energy Development Director at DECC, confirmed that "we would use [sub -sea] dispersants if the overall outcome was better than the oil alone".16' However, Mr Campbell also noted that any sub -sea use of dispersants would require a permit from DECC.161 108. We recommend that the Government draw up clear guidelines on the sub -sea use of dispersants in tackling oil spills, based on the best available evidence of both their effectiveness and their environmental impact. We also recommend the Government monitor the effects of sub -sea dispersants in the Gulf of Mexico to inform these guidelines. Capping and Containment Systems 109. BP eventually developed containment systems to deal with the oil leaking from the blownout Macondo well, and a capping system to seal it off finally. Mr McAllister of OSPRAG told us: "a lot of the costs for BP were because it took time to design these [oil containment devices]11.169 Dr Hayward told us that BP was shipping two of these containment devices to the UK, to be based at the Oil Spill Response Centre in Southampton.16' The Minister told us that in addition: "We've got a Chevron facility that will be a capping device".166 • 110. We welcome the new capping and containment systems, but believe that they are not a substitute for fully functioning blowout preventers. We also observe that the absence of such equipment in the first instance is another example of the oil and gas industry's inability to prepare for high -consequence, low probability events. Dr Wills told us: "there isn't any cure. The only option in town is prevention".167 He went on to explain to us: We can see where the oil is going. We still can't do anything about it [... ] there is no way you could contain or clean up a significant amount of oil and I don't think the Committee should be under any illusion about this.161 111. We recognise that the UK's oil spill response system is robust and rightly focuses on prevention, followed by containment and then clean-up. We welcome the development of new capping and containment systems capable of dealing with a sub- sea blowout. However, we feel that the absence of these devices before the Macondo incident is indicative of the industry's and the regulator's flawed approach to high - consequence, low -probability events. Prevention is better than cure, and we 161 Q 245 162 Q 291 (Campbell) ,ba Q 291 (Campbell) 6"Q64 16s Q 123 166 Q 286 (Hendry) 167 Q 201 the Q 213 (Wills) • 33 recommend once again the Government recognise that in its regulatory regime these systems are not a substitute for fully functioning blowout preventers. The West of Shetland Environment 112. The physical characteristics of the deeper waters to the West of Shetland (WoS) are significantly different from those encountered in the Gulf of Mexico, and the wells are more remote from the coast (the Macondo was 50 miles from Louisiana, whereas BP's Schiehallion Field is 110 miles from Shetland). Comparing the Gulf of Mexico and the West of Shetland, Mr McAllister told us that they were "very, very different marine environment in terms of the waves, in terms of natural dispersal of the oil".16' Dr Wills identified the overriding problem as "[...I the weather. It's appalling [... I if something goes wrong, it's going to be more difficult to fix".1' However, Mr Naylor of the MCA explained that the weather itself would act to break up and eventually disperse any spilt oil."' 113. The Shetland region has major currents, meaning a spill would not be as contained as in the Gulf of Mexico. While hurricanes are common in the Gulf of Mexico, the WoS sea is consistently rougher throughout the year, which has implications for oil recovery. These factors would make physical containment of a spill difficult, although the Braer tanker oil spill in 1993 (which spilt 85,000 tonnes of light crude oil) showed that prolonged storms can be effective at naturally dispersing some types of oil spill."' From 1 January 1999 to 11 August 2010, there were no crude oil drilling operation spills in water depths of over • 300m.13 114. It is estimated that during the Gulf of Mexico incident 3% of the oil released was recovered by skimming and 5% by burning. Booms which direct oil to a recovery resource such as a skimmer would find it difficult to contain a spill in the rough seas WoS, where it would also be difficult to burn the oil.14 The surface temperature WoS is lower than in the Gulf of Mexico; meaning natural evaporation (which accounted for the fate of 25% of the oil released from BP's Macondo Well) is far slower. Around 8% of the oil released from the Macondo well was dissipated using chemicals dispersants released at the well head on the ocean floor. 115. BP began drilling relief wells on 2 May-12 days after the blowout of the Macondo Well —which intersected the well on 16 September, pumping in cement and finally killing the well two days later. The British Rig Owners Association believe that there is a limited supply of rigs in the WoS that could drill relief wells if this were to prove necessary as a long term solution to killing a well. Moving available rigs into remote areas during the bad weather often experienced WoS would be logistically challenging.1' 169050 170 Q 207 71 Q 211 (Naylor) • 7' Ev 59 173 Ev 596 74 Ev 596 75 Ev 594 • • 34 116. The Joint Nature Conservation Committee (a statutory government adviser) noted that the two producing fields WoS—BP's Foinhaven and Schiehallion—have heavy oils that will "rapidly form stable emulsions on the water surface [... ] [increasing] the hazard relative to light oil fields in the North sea".16 The Shetland Islands Council, in partnership with industry, has drawn up a pollution contingency plan. However, it only extends a short way out to sea and focuses on tankers in the Sullom Voe Port, and with potential spills from the terminals there. Dr Wills, an independent councillor for Lerwick South, told us: "I haven't seen any containment, dispersal or clean-up system that works in the open Atlantic".17 117. There are serious doubts about the ability of oil spill response equipment to function in the harsh environment of the open Atlantic in the West of Shetland. We recommend that the Government ensures that any capping, containment and clean-up systems are designed to take full account of the harsh and challenging environment West of Shetland. 171 Ev M 177 Q 176 • 35 6 EU Regulatory Role Environmental Legislation 118. The EU legislation on oil rigs currently includes rules on environmental assessment and safety. The Environmental Liability Directive (ELD) aims to prevent oil pollution incidents associated with oil rigs and respond to the consequences. However, at the EU level, there are no harmonised rules on major accidents and emergency planning in relation to oil rigs, and there are no instruments setting up funds or other rules regarding financial guarantees. Furthermore, the scope of the ELD with respect to biodiversity damage caused by oil spills is limited to certain protected habitats. ClientEarth, an organisation of activist environmental lawyers, describes the ELD in its current state as: [... ] a general system of environmental liability in the EU but it is badly under - equipped to respond to the kind of damage which could result from an offshore pollution incident [... ] the gap should be filled by a framework employing a broad definition of environmental damage, and capable of imposing strict liability on all potentially responsible parties."$ 119. The House of Commons Environment, Food and Rural Affairs Committee, in its report on the implementation of the Environmental Liability Directive, noted that: Certain types of environmental damage are excluded from the scope of the Directive. These include damage arising from diffuse pollution which cannot be attributed to one or more specific operators, and damage falling within the scope of international Conventions relating to oil pollution [... ] where those Conventions are in force in the Member State where the damage occurs. The Directive also provides for `defences' against liability such that operators would not bear the cost of remediation in certain circumstances, such as where a third party was responsible, or where environmental damage occurred despite the operator complying with the conditions of a permit.19 120. Ms Wilks, of ClientEarth, explained that the ELD is "supposed to provide [... ] some kind of ecologically sound compensation [... ] not just a monetary payment".18' KIMO UK (the Local Authorities International Environmental Organisation) told us "that the polluter [... ] [should] pay for any pollution from oil rigs and the associated clean up operations".'" 121. ClientEarth argues that "a comprehensive new regulatory package is now needed that not only amends existing EU legislation [... ] [but] also introduces legislation to fill the dangerous voids in the current regime".18' It argues that these "dangerous voids" could be filled by extending existing legislation frameworks to include "operational drilling projects, 18 Ev 595 111 Environment, Food and Rural Affairs Committee, Sixth Report of Session 2006-07, Implementation of the Environmental Liability Directive, HC 694, para 9 10 ea Q 220 81 Ev 590 fez Ev 595 0 36 exploratory drilling, and the period after wells have been decommissioned".1R3 ClientEarth also calls for a new EU level agency to coordinate functions in connection with major accident prevention, emergency response plans, inspections and exchange of best practice, with the European Maritime Safety Agency as a candidate for this role. 122. We conclude that —as it stands —the EU Environmental Liability Directive is unlikely to bring to account those responsible for environmental damage caused by an offshore incident such as happened in the Gulf of Mexico. We recommend that the Government works with the EU to ensure a new directive is drawn up that follows the polluter -pays principle and unambiguously identifies who is responsible for the remediation of any environmental damage. European Commission Calls for a Moratorium 123. In his statement on 7 July 2010 calling for an EU moratorium on deepwater drilling, European Commissioner Oettinger also called for European oversight of regulators, suggesting he would "not hesitate to propose a European framework for `controlling the controllers' if need be".184 DECC acknowledged Commissioner Oettinger's call for a moratorium on deepwater drilling, as well as his calls for a broader review of EU regulation of such activities. DECC and the HSE wrote that they, "will be a key contributor to Commission workshops to discuss these issues", including a review of how to improve the • capacity for cooperation in terms of response and clean up, and considerations of the need to strengthen regional and international standards.l"S However, Lord Marland, the Parliamentary Under -Secretary of State for DECC, responded to the question of a European moratorium from Lord Stoddart of Swindon by saying: We are not aware of any current provision within EU law which would enable any EU body to require a moratorium, or on deep water drilling [... ] But HMG remain of the firm view that these are matters which are properly left to individual member states.l ss 124. Oil and Gas UK dispute the necessity of EU oversight, citing a lack of EU competence in offshore exploration and production, and also highlight the risk that moving to a set of EU standards could lead to the lowering of UK national standards.I" Mr Webb told us that while there "is clearly scope to extend [... ] [oil spill regulations at the EU level] to drilling",188 he was still concerned that with increased EU oversight "we might see a dumbing down as opposed to a raising up of standards"."' The Minister told us that "we want to encourage others to come up to [... ] [our] level rather than see any watering down,"190 and went on to tell us that he regarded the UK safety regulations as the best in e9 Ev 595 Speech by Commissioner Oettinger, 7 July 2010, http://europa.eu/rapid ss Ev 596 ,es HL Deb, 20 July 2010, col 1262 187 Ev 63 ee Q 23 189 Q 26 190 Q 323 • 0 37 the world.191 He did not want their effectiveness to be unnecessarily diluted by the unnecessary involvement of EU Member States who did not possess a coastline. 1 I 125. ClientEarth argued for an EU level agency that could undertake functions in connection with: major accident prevention polices; safety reports; emergency response plans; inspection; and information exchange.19' They believed that: The European Maritime Safety Agency [EMSA] is a clear candidate for this role, and its capacity should be extended, with appropriate resources, to cover offshore installations in addition to its current tasks in relation to shipping.1 ' 126. EMSA's main objective as it currently stands is to provide assistance to the European Commission and Member States in the "proper development and implementation of EU legislation on maritime safety, pollution by ships and security on board ships".195 127. We utterly reject calls for increased regulatory oversight from the European Commission. We recommend that EU countries without a North Sea coastline should not be involved with discussions on regulation of the offshore industry on the UK Continental Shelf. 191 Q 326 327 193 Ev 595 94 Ev 595 195 EMSA, www.emsa.europa.eu • 38 7 Impacts of a Moratorium Impact of the US Moratorium 128. The US observed a moratorium on any deepwater drilling from the time of the Deepwater Horizon incident in. April until 12 October 2010. There were 33 deepwater drilling platforms in the Gulf of Mexico on which work halted as result. As a consequence, on 8 July 2010, the Texas based deepwater drilling contractor Diamond Offshore announced that its Ocean Endeavour drilling platforms —capable of operating in over 2,400m of water —would be leaving the Gulf of Mexico and immediately moving to Egyptian waters. The Ocean Endeavour had been leased to Devon Energy Corporation, and had been drilling in the same region of the Gulf of Mexico as the Deepwater Horizon. On 11 July 2010 Diamond announced that it would be moving a second platform out of the Gulf of Mexico to waters off the Republic of Congo. Mr Cohagan of Chevron UK told us: "We have to pay for the drill ships whether they are working or not [...] If we can't drill here it will be necessary for us to find some place [else] in the world".116 129. Devon tried to cite the deepwater drilling ban to get out of its contracts to lease the Diamond platform, but Diamond still took $31 million in early termination fees. Murphy Oil Corp and Cobalt Energy Inc also sought to annul contracts with Diamond because of the moratorium, but Diamond rejected their force majeure claims. Force majeure is a common clause in contracts that essentially frees both parties from liability or obligation when an extraordinary event or circumstance beyond the control of the parties occurs. Anadarko, which owned a 25% interest in the Macondo well, notified four out of its three drilling contractors in the Gulf of Mexico of its intent to use force majeure to break their contracts, although Noble (which owns one of the rigs) disputed that the moratorium constituted an event that would free both parties from their contract. Evidence on a UK Moratorium 130. ClientEarth, Platform, Greenpeace, the Marine Conservation Society and Caroline Lucas MP gave evidence to us calling explicitly for a moratorium on new deepwater drilling in the UKCS.197 ClientEarth argued that a moratorium was necessary until "a comprehensive new regulatory package [comes into force that] introduces new legislation to fill the dangerous voids in the current regime".19' Transocean, Chevron, DECC, DONG and British Gas (BG Group) argued that a ban would be unwarranted.19I Chevron UK told us that a "moratorium on deep water drilling would have unnecessary and lasting negative impact on the UK's ability to maximise the value of a vital national resource".200 DONG Energy said that a moratorium on deepwater drilling would "prevent the discovery and 16 Q 264 (Cohagan) 9J Ev 595, Ev 598, Ev 599, Ev 630, Ev 633 18 Ev 595 Ev 59, Ev 591, Ev 596, Ev 631, Ev 592 zoo Ev 591 • 39 extraction of new sources of gas supply [... ] required to mitigate the decline in supply from other areas of the UK [Continental Shelf]11.201 131. At a September 2010 meeting of the Oslo and Paris Conventions for the protection of the marine environment of the North-East Atlantic (OSPAR) in Norway, a proposal for a moratorium on deepwater drilling was withdrawn due to strong opposition during a meeting of ministers, including from the UK.202 The EU Commission's calls for a moratorium on deepwater drilling were eventually voted down by the European Parliament.113 132. Production of oil and gas from the North Sea is in decline. The average size of discoveries on the UK Continental Shelf in the last 10 years is only around 20 million barrels of oil equivalent and many of them are gas discoveries. Despite this, the decline of UK gas production has been much quicker than that of oil production.204 Dr Hayward believed that "there is no doubt that deepwater will provide an important part of [future oil and gas production] 11.205 133. At the London Oil & Money Conference on 12 October 2010, the executive director of the International Energy Agency (IEA), Nobuo Tanaka, said that half of the world's oil supplies could come from offshore production by 2015, up from approximately a third today.206 A 2009 study from the Society of Petroleum Engineers quantified the deepwater oil and gas resources world wide as 11.9 billion tonnes of oil equivalent, or almost 88 billion barrels.207 Of this deepwater resource 15% was in Europe, and of that 25% was 101 located in the UK: 450 million toe (over 3.3 billion barrels), comprised of 237 million tonnes of oil (1.75 billion barrels), and 213 million tonnes of gas.211 134. Global production of oil in 2009 was 3.8 billion tonnes (28 billion barrels), while proven reserves stood at 181.7 billion tonnes (1.34 trillion barrels). UK consumption in 2009 was 74.4 million tonnes (almost 550 million barrels). In terms of global demand the UK deepwater resource is small, amounting to just over three years of domestic oil consumption. However, the Economics and Social Research Council point out that under IEA and EU rules, the UK is committed to sharing available oil with partners in the event of a major disruption, so West of Shetland (WoS) oil should be seen as a contribution to collective security as it cannot be reserved for the UK.20S DECC figures estimate that the 3- 3.5 billion barrels of deepwater oil and gas resource (including both WoS and the less well explored West of Scotland) account for 15-17.5% of UK total resources. However, they note that this resource estimate includes 1 billion barrels of highly uncertain resource from the West of Scotland area. 209 Mr Cheshire of DONG Energy told us that a moratorium on 2p1 Ev 632 202 "The deepwater moratorium issue", International Association of Oil and Gas Producers —Highlights, October 2010 201 "The deepwater moratorium issue", International Association of Oil and Gas Producers —Highlights, October 2010 I" Ev 77 205 Q 176 Zoe "Half the world's oil production could come from offshore production by 2015", Reuters, 12 October 2010 201 Ev w6 211 Ev w6 211 Ev 596 • 40 new deepwater drilling in the UK would lead to, "a very significant delay on the ability to deliver projects".21' 135. The main prospective oil and gas producing areas in deepwater within the UK Continental Shelf (UKCS) are considered to be in areas West of Shetland (WoS). The area West of Scotland (north of the Outer Hebrides) may also contain substantial oil and gas resources, but is yet to be fully explored. Mr Webb of Oil and Gas UK told us: [... ] industry is going to have to invest something like £60 billion over the next 10 years or so [... ] if we want to keep rigs drilling here in the UKCS then what is needed most of all is the right investment climate for that to happen.2 ' 136. The West of Shetland area is estimated to hold around 20% of the UK's remaining oil and gas reserves, 3.5-4.5 billion barrels of oil equivalent. This includes about 1 billion boe of gas, representing around 17% of the remaining UK gas reserves, the majority of which lies in deepwater. The remaining WoS oil potential, 3 billion barrels, is split approximately 50:50 between deep and shallow water.212 Dr Wills told us that: "Jobs and contracts in the terminals are worth £50 million to £60 million a year to a local community of 22,000 people".213 137. Production from the three fields West of Shetland (BP's Foinhaven-400-600m, Schiehallion-350-450m and Clair-140m) represents about 9% of total oil production from the UKCS (114,000 barrels per day). Total's £2.5 billion investment to develop the Laggan-Tormore fields will result in the production of 30 billion cubic metres of gas —the largest gas field development in over ten years. The infrastructure put in place to develop Laggan-Tormore will secure the installation of the first major gas pipeline from the area to the British mainland, opening up the basin for further developments. Chevron is exploring the Rosebank-Lochnagar fields in 1,115m of water.211 138. We conclude that a moratorium on offshore drilling in the UK Continental Shelf would cause drilling rigs and expertise to migrate to other parts of the globe. A moratorium on deepwater drilling would decrease the UK's security of supply and increase the UK's reliance upon imports of oil and gas. A moratorium could also harm the economies of communities in Scotland who rely upon the UK offshore oil and gas industry as well as the wider British economy to which the industry makes a major contribution. There is insufficient evidence of danger to support such a moratorium. We conclude that there should not be a moratorium on deepwater drilling in the UK Continental Shelf. 211 Q 264 (Cheshire) • 2'1Qg15and 81 "2 Ev 596 213 Q 222 214 Ev 63 • 41 8 Conclusions and Recommendations 1. In the light of recent drilling activity in the waters around the Falkland Islands, we asked witnesses from OSPRAG and Oil and Gas UK whether the UK regulatory regime applied to drilling in that area. There was a lack of clarity over responsibility for drilling and oil response in the Falkland Islands. We recommend that the Government clarify what regulatory regimes apply to drilling and oil spill response in the Falkland Islands and who is responsible for enforcing them. (Paragraph 22) 2. Oil company boards lack members with environmental experience. The industry should take steps to remedy this and the Government should encourage them to do so. (Paragraph 30) 3. We conclude that the UK has high offshore regulatory standards, as exemplified by the Safety Case Regime that was set up in response to the Piper Alpha tragedy in 1998. The UK regulatory framework is based on flexible, goal -setting principles that are superior to those under which the Deepwater Horizon operated. (Paragraph 34) 4. Nevertheless, despite the high regulatory standards in the UK we are concerned that the offshore oil and gas industry is responding to disasters, rather than anticipating worst -case scenarios and planning for high -consequence, low -probability events. (Paragraph 35) 5. It is imperative that there is someone offshore who has the authority to bring a halt to drilling operations at any time, without recourse to onshore management. We urge the Government to seek assurances from industry that the prime duty of the people with whom this responsibility rests is the safety of personnel and the protection of the environment. (Paragraph 38) 6. Given that the failure of the single blind -shear ram to fire on the Deepwater Horizon's blowout preventer seems to have been one of the main causes of the blowout of the Macondo well, we recommend that the Health and Safety Executive specifically examine the case for prescribing that blowout preventers on the UK Continental Shelf are equipped with two blind shear rams. (Paragraph 45) 7. While the flexibility of the UK safety regulation regime appears to have worked well, we recommend that for fail-safe devices such as the blowout preventer the Government should adopt minimum, prescriptive safety standards or demonstrate that these would not be a cost-effective, last -resort against disasters. (Paragraph 52) 8. We believe that the Government must ensure that the UK offshore inspection regime could not allow simple failures —such as a battery with insufficient charge —to go unchecked. (Paragraph 55) 9. Whilst there is a risk of conflicts of interests affecting the judgement of independent competent persons who assess the design of wells we have had no evidence of such • conflicts presented to us. (Paragraph 60) 0 42 10. We find some conflict in the reports from the HSE about bullying and harassment on rigs and the assurances of the industry that sincere whistleblowers will be heard and protected. We recommend that the Government should discuss with the industry and unions what further steps are needed to prevent safety representatives from being or feeling intimidated into not reporting a hazard, potential or otherwise. (Paragraph 66) 11. It is important and necessary that the offshore safety culture is cascaded throughout the supply chain, from existing contractors at all levels, through to new -entrants on to the UK Continental Shelf. (Paragraph 68) 12. There is both risk and the advantage of competition where global oil and gas companies operate to different standards when working in different regulatory regimes. We recommend that the Government monitor any changes in the US regulatory regime to see if —in the light of the response to the Deepwater Horizon incident —the US establishes a new gold -standard of regulation, as the UK and Norway did after the Piper Alpha tragedy. We would urge the Government to work with regulators in other offshore oil and gas provinces to ensure that the highest standards of safety can be achieved globally through an exchange of best practice lessons. (Paragraph 72) 13. The Bly Report—BP's internal investigation into the Deepwater Horizon incident — does not contain a root -cause analysis of the events that led to the blowout of the Macondo well, the loss of 11 men on the Deepwater Horizon, and the release of 4.9 million barrels of oil into the Gulf of Mexico. We urge the Government not to rely extensively on the Bly Report, given the controversy surrounding the responsibility for the incident and the design of the Macondo well, but rather to consider its conclusions in parallel with the observations of other companies involved with the incident, and with the recommendations of US agencies investigating the incident. (Paragraph 78) 14. We believe that the environmental impacts of a sub -sea well blowout need to be understood and taken into account when a drilling licence is issued in the UK. We urge the Government to ensure that the licensing regime takes full account of high consequence, low probability events. (Paragraph 79) 15. We recommend that as part of the drilling -licence process, the Government require companies to consider their responses to high -consequences, low -probability events —such as a blowout. The Government should not automatically accept claims that companies have mitigated away the risk of such worst -case scenarios. We urge the Government to introduce this requirement as drilling ventures into increasingly extreme environments. (Paragraph 81) 16. Given the high costs of the incident in the Gulf of Mexico, we believe that the OPOL (Offshore Pollution Liability Association) limit of $250 million is insufficient. We are concerned that the OPOL provisions only cover direct damage and also that the precise definition of "direct damage" is unclear. While membership of OPOL remains voluntary —despite it being a pre -requisite for a licence —its voluntary nature weakens its legality and the control and deployment of its funds. We believe 43 this lack of legal control will allow polluters to claim that damages to biodiversity and ecosystems are indirect, and therefore do not qualify for compensation. (Paragraph 90) 17. We conclude there needs to be clarity on the identity and hierarchy of liable parties to ensure that the Government, and hence the taxpayer, do not have to pay for the consequences of offshore incidents. We conclude that any lack of clarity on liability will inhibit the payment of compensation to those affected by an offshore incident. We recommend that it should be a requirement of the licensing process that the licensee prove their ability to pay for the consequences of any incident that could occur. We recognise that these measures could add to the cost of investing in new UK oil and gas production and urge the Treasury to reflect this when considering incentives to such investments. (Paragraph 91) 18. We recommend that the Government consider whether compulsory third -party insurance should become a necessary requirement for small exploration and production companies. (Paragraph 93) 19. We acknowledge that oil spill response plans often share procedures for dealing with oil spills. There is some concern that in the past this may have led to a culture of copying -and -pasting rather than the production of site -specific plans which recognise the drilling environment and the risk of high -consequence, low -probability events. We recommend the Government re-examine oil spill response plans to ensure that this is not the case. (Paragraph 101) 20. We recommend that the Government draw up clear guidelines on the sub -sea use of dispersants in tackling oil spills, based on the best available evidence of both their effectiveness and their environmental impact. We also recommend the Government monitor the effects of sub -sea dispersants in the Gulf of Mexico to inform these guidelines. (Paragraph 108) 21. We recognise that the UK's oil spill response system is robust and rightly focuses on prevention, followed by containment and then clean-up. We welcome the development of new capping and containment systems capable of dealing with a sub -sea blowout. However, we feel that the absence of these devices before the Macondo incident is indicative of the industry's and the regulator's flawed approach to high -consequence, low -probability events. Prevention is better than cure, and we recommend once again the Government recognise that in its regulatory regime these systems are not a substitute for fully functioning blowout preventers. (Paragraph 111) 22. There are serious doubts about the ability of oil spill response equipment to function in the harsh environment of the open Atlantic in the West of Shetland. We recommend that the Government ensures that any capping, containment and clean- up systems are designed to take full account of the harsh and challenging environment West of Shetland. (Paragraph 117) . 23. We conclude that —as it stands —the EU Environmental Liability Directive is unlikely to bring to account those responsible for environmental damage caused by an offshore incident such as happened in the Gulf of Mexico. We recommend that 44 • the Government works with the EU to ensure a new directive is drawn up that follows the polluter -pays principle and unambiguously identifies who is responsible for the remediation of any environmental damage. (Paragraph 122) 24. We utterly reject calls for increased regulatory oversight from the European Commission. We recommend that EU countries without a North Sea coastline should not be involved with discussions on regulation of the offshore industry on the UK Continental Shelf. (Paragraph 127) 25. We conclude that a moratorium on offshore drilling in the UK Continental Shelf would cause drilling rigs and expertise to migrate to other parts of the globe. A moratorium on deepwater drilling would decrease the UK's security of supply and increase the UK's reliance upon imports of oil and gas. A moratorium could also harm the economies of communities in Scotland who rely upon the UK offshore oil and gas industry as well as the wider British economy to which the industry makes a major contribution. There is insufficient evidence of danger to support such a moratorium. We conclude that there should not be a moratorium on deepwater drilling in the UK Continental Shelf. (Paragraph 138) 0 0 • 45 Annex 1-Chronology of the Deepwater Horizon Incident The Macondo Well in the Gulf of Mexico BP started drilling the Macondo well on 7 October 2009, using the Transocean owned Marianas platform. Hurricane Ida damaged this platform on 9 November 2009, and so BP and Transocean (who operated the platform under contract to BP) replaced the Marianas with the Deepwater Horizon, which began drilling on 6 February 2010. Transocean charged BP approximately $500,000 per day to lease the rig, plus contractor fees.211 BP aimed for the drilling to take 51 days, with an estimated cost of $96 million. It was expected that the Deepwater Horizon would be leaving as early as 8 March 2010, but the Macondo well took longer to complete than anticipated. By 20 April —the day of the blowout that killed 11 workers and injured 17—the rig was 43 days late, which would have cost an extra $21million in lease fees alone. BP owns a 65% interest in the Macondo well. The US -based company Anadarko Petroleum owns a 25% share, and the Japanese company Mitsui owns 10%. The Deepwater Horizon drilling platform (an exploration rig, not a production rig) was owned by Transocean, who also operated it for BP. The objective of the drilling operation was to • "successfully evaluate any commercial hydrocarbon [oil and gas] [... ] discovered".216 The oil and gas reservoir was located at over 5,596m below the seabed, with the wellhead at a water depth of over 1,500m. The Macondo project yielded one of the largest finds in the Gulf of Mexico, but the crew repeatedly struggled to maintain control of the well against powerful "kicks" of surging oil and gas. In evidence published by the US House of Representatives Energy and Commerce Committee, BP staff described Macondo as "a nightmare well that has everyone all over the place", just six days before the Deepwater Horizon platform exploded.217 The Deepwater Horizon Drilling Rig The Deepwater Horizon was a semi -submersible, mobile offshore drilling rig built for Transocean by Hyundai (South Korea) in 2001. It flew a Marshallese Islands' flag of convenience. "Semi -submersible" rigs are kept afloat and upright by watertight pontoons located below the surface and beneath the waves, and are usually used in water depths greater than 200m where floating fixed structures are not practical. The Deepwater Horizon was dynamically positioned, which meant —rather than using chains or wire to anchor it in place during drilling operations —that its position was computer controlled using underwater thrusters. 75 F/eet Status Report, Transocean, 13 April 2010, www.deepwater.com "6 BP Macondo Prospect Well Information, September 2009, http://energycommerce.house.gov 21 BP Email, 14 April 2010, http://energycommerce.house.gov • 46 The drilling rig was capable of operating in harsh environments and water depths of nearly 2,500m (upgradeable to over 3,000m). While drilling the Macondo well it was operating in just over 1,500m of water. In 2009, before work began on the Macondo well, Transocean crews working with BP discovered oil in the giant Tiber field in the Gulf of Mexico. At a total depth of approximately 10,685m (in an ocean depth of 1,259m) it was the deepest oil well in the world. The Deepwater Horizon rig was due for a series of extensive maintenance checks late in 2010, with records indicating it was last checked thoroughly in 2005. Documents from Transocean's maintenance department indicated various asset deficiencies including "intermittent alarms [on the control panel] on unrelated functions when opening [a valve on the blowout preventer]", and "low pressure readings" in the hydraulic system.211 Blowout prevention devices are designed to handle a range of well control problems, and often come fitted with several different types of rams, giving engineers flexibility in their response. The blind shear ram is described as the ultimate fail-safe device, crushing and sealing the well pipe as a measure of last resort. The Deepwater Horizon had a single blind shear ram located inside the 15.5m tall blowout preventer stack at the wellhead on the seafloor. With a single blind shear ram, there is a risk that it could close on one of the extremely strong joints that connect the sections of drilling pipe, and be unable to collapse it. Such a risk is minimised by the use of two blind shear rams. • Transocean hired West Engineering to carry out a physical assessment of Deepwater Horizon's well control system, but they were unable to access the blowout preventer (BOP) as it was on the seafloor. This meant they were unable to verify whether the blind shear ram on Deepwater Horizon's BOP could shear through drill pipe and seal off the well while in deepwater. A 2009 industry study entitled Pull Your BOP Stack - Or Not? calculated the price of stopping operations to pull up a blowout preventer for repairs at $700 per minute.219 BP's internal investigation of the Gulf of Mexico oil spill culminated in the Deepwater Horizon Accident Investigation Report (the Bly Report), published 8 September 2010. The full details are not yet known, but it appears that gas and oil rushed up to the wellhead on the sea floor, and the blowout preventer (BOP) device was unable to contain the pressure. According to Dr Tony Hayward, Group Chief Executive of BP: "[the Deepwater Horizon incident] arose from an interlinked series of mechanical failures, human judgments, engineering design, operational implementation and team interfaces".221 18 Deepwater Horizon Rig Assessment, http://documents.nytimes.com/documents-on-the-oil-spill?ref=us#document/pl9 "'Jeff Sattler (West Engineering Services), "Pull Your BOP Stack — Or Not? A systematic method to making this multi- million dollar decision", SPE/IADC Drilling Conference and Exhibition - Amsterdam, 17-19 March 2009 211 Q 89 (Hayward) • 47 Factors Identified as Contributing to the Incident Casing Deepwater wells are drilled in sections. The basic process involves drilling through rock, installing and cementing casing into place —casing lines the well —to secure the wellbore (well hole), and then drilling deeper and repeating this process. One day before the blowout —while preparing the well for future production at a later date —BP decided to install a single long -string casing from the top of the well to the bottom, rather than multiple individual casings with a seal (known as a "liner" with a "tieback"). Mr Richard Cohagan, Managing Director of the oil and gas exploration company Chevron UK, told us: "BP was designing the well so that they could use it as a production well and that's one reason that they had a long string in the well [... ] We tend to have larger [... ] and multiple physical barriers"."' Mr Cohagan went on to argue that: "BP was trying to design the right well for their conditions"?" Multiple individual casings would have provided more barriers to the flow of gas up the well in the event of a blowout, but would have taken longer to install and been more expensive. A BP -plan review in mid -April recommended against the single casing as it would make the seal at the wellhead the "only barrier" in the event of a failure."' Dr Hayward told us: "The decision to run the long -string was actually based on long-term integrity [... ] a liner with a tieback [... ] is subject, over time, to degradation and can leak"."' • When the final string of this single casing was installed, one key challenge was making sure the casing ran down the centre of the well bore. If this is not done properly, it becomes difficult to displace drilling fluid from the narrow open space around the casing, which in turn will lead to an inability to cement the casing in place properly. In such an instance, it is possible that channels will form in the cement that allow gas to flow up the open space around the casing. Centralisers are attachments that go around the casing to centre it in the borehole. Halliburton, the cementers, recommended using 21 centralisers on this final string of casing, but BP decided to use six. The Bly Report makes the case in Key Finding 2 that this decision is unlikely to have contributed to the incident. BP aimed for the drilling of the Macondo well to take 51 days, at an estimated cost of $96 million. It was expected that the Deepwater Horizon would be leaving as early as 8 March 2010, but the Macondo well took longer to complete than anticipated. By 20 April —the day of the blowout that killed 11 workers —the rig was 43 days late, which would have cost an extra $21 million in lease fees alone.225 221 Q 251 222 Q 252 223Letter to Tony Hayward, US House of Representatives, 14 June 2010 http://energycommerce.house.gov 224 Q 98 121 Fleet Status Report, Transocean, 13 April 2010, www.deepwater.com • 48 Cement Despite Halliburton's and BP's own predictions of a gas flow problem caused by an incomplete cement job, BP decided not to run a 9-12 hour procedure known as a "cement bond log" to assess the integrity of the cement seal, dismissing the Schlumberger contractors who had been hired to undertake the test.226 This acoustic test would have determined whether the cement had bonded to the casing and surrounding formations. If a channel that allows gas to flow up is found, the casing can be perforated and additional cement injected into the annular space to repair the cement job. Key Finding 1 of the Bly report discusses BP's belief that the cement mix designed by Halliburton was unfit for purpose. We were told by Dr Hayward: "we know the cement was not good because we had influx into the well".227 Dr Hayward added: "I think we need to be cautious until we can complete [... ] [an] analysis [of the cement] to understand why the cement failed".228 As Halliburton refused to provide samples for testing, the BP investigators had an independent laboratory analyse the design of the cement slurry.229 BP noted that there was a high percentage of nitrogen found in the cement ingredients, making it difficult for the cement to form a stable "foam slurry" 231 The cement used was injected with nitrogen to make it into a lighter "foam".231 This is done in order to avoid damaging the rock formation of the reservoir, which would make it more difficult to produce oil at a later date. BP says that when the independent laboratory tried to produce a representative cement sample —based on the slurry design —they could not demonstrate cement stability. • Therefore, BP concluded that the foam slurry likely experienced "nitrogen breakout" resulting in channels forming that would have allowed oil and gas to flow through it.232 While drilling into high-pressure, high -temperature fields like the Macondo, the well is usually filled with heavy drilling fluid (known as "mud") while drilling to compensate for the upwards pressure of the oil and gas in the reservoir. It is recommended that this drilling mud is fully circulated from the top to the bottom before commencing the cementing process. This allows the mud to be conditioned —by removing any pockets of gas and other debris safely —so that the cement is not contaminated. BP decided against the full 12-hour procedure and only partially circulated the mud.233 The choice to use a single string of casing meant the Macondo well had just two barriers to gas flow up the annular space around the final string of casing: the cement at the bottom of the well and the seal at the wellhead on the sea floor. Insufficient centralisers also meant that there was a severe risk that the cement job would fail, and the lack of a cement bond log meant that BP were unable to check this. Finally, BP did not deploy the casing ue Letter to Tony Hayward, US House of Representatives Energy and Commerce Committee,14 June 2010 227 Q 108 228 Q 109 "I Deepwater Horizon Accident Investigation Report BP, 8 September 2010, www.bp.com 230 Deepwater Horizon —Accident Investigation Report BP, 8 September 2010, www.bp.com 211 Deepwater Horizon —Accident Investigation Report BP, 8 September 2010, www.bp.com 232 Deepwater Horizon —Accident Investigation Report BP, 8 September 2010, www.bp.com zaa Letter to Tony Hayward, US House of Representatives Energy and Commerce Committee,14 June 2010 • 49 "lockdown sleeve" that would have prevented the seal from being blown out from below."' Even when cemented in the wellhead, under certain pressure conditions the casing can become buoyant and rise up, creating an opportunity for oil and gas to break through the wellhead seal and enter the riser to the surface. The lockdown sleeve prevents this. Negative Pressure Test One of the Bly Report's key findings was that readings taken during the "negative pressure test" to determine well integrity indicated that there was a flow of oil and gas from the reservoir into the well even though the "Transocean rig crew and BP well site leaders" thought the test was a success and well integrity had been established.23' Dr Hayward told us: "we know that with the benefit of hindsight that the negative test was erroneously interpreted ".236 This test simulates the temporary abandonment of the well after drilling and prior to production, when a proportion of the well is displaced to sea water. BP's Group Head of Safety and Operations, Mr Bly, added: "There are records of the information that would have been available, so we know that [information on the drill pipe pressure increasing, when it should have been decreasing] was there. We can't explain why they didn't see it".237 This series of decisions may have been driven by expense and time, as by 20 April —the day of the blowout —the rig was 43 days late, and would have cost BP at least an extra £21 million in lease fees alone. However, each decision and failure increased the risk of a • blowout. Exemplifying the industry's inability to take account of high -consequence, low probability events, Dr Hayward told us: "we weren't prepared"."' Mr Cohagan, of Chevron UK, told us: "Deepwater Horizon gave us a new perspective on how bad things could be"."' We are concerned that the offshore oil and gas industry has failed to prepare for what they had previously classified as worst -case scenarios. BP's Attempts to Kill the Macondo Well On 22 April, two days after the blowout and subsequent explosion that killed 11 workers, the Deepwater Horizon drilling rig sank This bent the 1,500m "riser" pipe connecting the rig to the wellhead on the sea floor. Submersible robots discovered two leaks close to the seabed. Over the next few days, BP attempted to activate the single blind shear ram in the blowout preventer (BOP), a device located at the wellhead on the sea floor. The blind shear ram would have severed and sealed the pipe, but attempts to activate it failed. On 2 May, BP began drilling relief wells, intending to intersect the existing well in order to send down heavy drilling mud and cement to stop the leak By 7 May BP had constructed a 234 Letter to Tony Hayward, US House of Representatives Energy and Commerce Committee,14 June 2010 235 Deepwater Horizon —Accident Investigation Report BP, 8 September 2010, www.bp.com 236 Q 23] Q 117 238 Q 186 239 Q 236 • 50 12m tall containment dome, known as "top hat". They attempted to lower the dome on to one of the largest leaks from the bent pipe, but it became clogged with an icy mix of gas and water (called gas hydrates). After several unsuccessful attempts, BP inserted a mile -long tube into one of the leaks on the broken riser pipe on 16 May, and succeeded in siphoning off some of the oil to a ship on the surface, collecting an estimated 22,000 barrels a day, over nine days. This siphon was cut off on 26 May as BP attempted its "top kill' and "junk shot" operations. "Top kill" attempted to overcome the pressure of the rising oil by pumping drilling mud into the top of the well, while "junk shot" attempted to clog up the BOP by injecting objects such as golf balls. These attempts failed. On 31 May BP cut the damaged pipe away from the BOP and lowered a dome —connected to the surface by a new riser —on to the blowout preventer. Methanol and warm seawater pumped down the riser prevented the formation of icy gas crystals, and oil and gas were funnelled to a ship on the surface. An additional siphon supplemented the system on 16 June, pumping more oil to surface vessels. By mid -July BP had four vessels on site to collect and process retrieved oil and gas, collecting 62,000 barrels per day. On 10 July, BP removed this cap and replaced it with a new device, containing many of the same features as a BOP. The hydraulic rams on the new cap were closed on 14 July, and pressure sensors indicated that oil was not leaking from elsewhere on the seafloor. BP began its "static kill' operation to plug the well on 4 August 2010. Drilling mud pumped from the surface forced the oil back down the well, and cement was then sent in • through the top of the well to seal it off. The final "bottom kill" procedure —where cement was pumped through relief wells into the Macondo—took place successfully on 18 September. BP's Gulf of Mexico Clean-up Operations A team of experts assembled by the US National Incident Command (NIC) announced on 2 August that an estimated total of 4.9 million barrels of oil had been released from the Macondo well. The National Oceanic and Atmospheric Administration (NOAA) then determined what had happened to the oil. It is estimated that burning (5%), skimming (3%) and direct recovery from the well (17%) removed a quarter of the oil released. Another quarter naturally evaporated or dissolved, and just under a quarter was naturally (16%) or chemically (8%) dispersed. Dissolution is the process by which the oil dissolves into the water, whereas dispersion is the process by which larger volumes are broken down into smaller droplets. Residual oil made up just over a quarter of the oil spilt. Residual oil is a combination of categories all of which are difficult to measure or estimate, and includes oil: that is on or just below the surface as "light sheen" and "tar balls"; has been washed ashore or collected from the shore; or is buried in sand and sediments. It is thought that dispersed and residual oil will be naturally degraded. Response efforts addressed 33% of the oil spilled. Dispersants are chemicals that can be used to break up and speed the natural degradation of oil on the surface. It is argued that they are less harmful than oil and biodegrade more quickly than untreated oil. In the Deepwater Horizon spill the dispersants were used underwater to prevent more oil from reaching the vulnerable marshes, wetlands and coastlines of the US Gulf states. BP was pre -authorised to use approved dispersants, according to the US Environmental Protection Agency, on spills no closer than three miles 51 from the shore, but was required to get daily permission from the U.S. Coast Guard during the clean-up operations for this incident. Dispersants are usually used on the surface, but BP injected them into the oil as it flowed from the well. BP began by using the dispersant Corexit 9527a, and then switched to Corexit 9500. Both of these products were removed from the UK Marine Management Organisation's approved list in 1998, as they proved too toxic in instances where they might end up on rocky shorelines (although existing stocks could be used)."' Booms are temporary floating barriers used to contain oil by concentrating it into thicker surface layers. Exclusion booming is used to keep oil away from sensitive areas, while diversion booming is used to direct the flow of oil elsewhere. Containment booms are deployed in a "u" or "v" shape to direct the flow of oil to a recovery resource, such as a skimmer. "Skimmer" is a common name for any device (usually attached to a ship) used to remove oil (or an oil/water mixture) from the surface without using chemicals. In -situ burning is a method of burning freshly -spilled oil while it is floating on the water. Environmental Impacts in the Gulf of Mexico The Macondo well is estimated to have leaked 4.9 million barrels of oil, making it the largest marine spill in US history. The full extent of the impact on the environment is not yet known. As of 16 August 2010, more than 7,000 birds, sea turtles and dolphins have been found dead or debilitated in the Gulf of Mexico since the oil spill began.241 While a • majority of the dead were not visibly oiled, scientists have yet to determine why they died. However, it has been confirmed that more animals are dying than during the same time in previous years. Not all injuries or deaths were necessarily caused by the oil spill, and some of those found dead may have been oiled after death. The higher than expected numbers of animals found dead may have been an artefact of the increased monitoring of the area. More than twice the number of stranded sea turtles have been found than normal at this time of year.242 Of the nearly 500 found visibly -oiled, the majority were found alive. Of the nearly 600 found not -visibly -oiled, the majority were found dead. Some suspect that shrimp fishermen may be causing the increased deaths by not using devices that prevent turtles trapped in nets from drowning (whilst the federal agencies are distracted). More than 50% of one batch of turtle corpses analysed showed evidence of drowning.241 Of the more than 2,300 birds (mostly pelicans) found not -visibly -oiled, all were dead, compared to about half of the 3,800 found visibly-oiled.244 When ingested or inhaled, oil can cause brain lesions, pneumonia, kidney damage, stress and death. There have also been reports of dolphins acting as if they were drunk, and it is suspected that disorientation caused by oil exposure is making them more susceptible to boat strikes. '40 "Oil spill treatment products approved for use in the United Kingdom", UK MMO, 8 October 2010 "The Oil Spill's Effects on Wildlife",16 August 2010, www.nytimes.com 343 "The Oil Spill's Effects on Wildlife",16 August 2010, www.nytimes.com 143 "The Oil Spill's Effects on Wildlife",16 August 2010, www.nytimes.com 244 "The Oil Spill's Effects on Wildlife",16 August 2010, www.nytimes.com 52 Formal Minutes Tuesday 14 December 2010 Members present: Mr Tim Yeo, in the Chair Dan Byles John Robertson Barry Gardiner Laura Sandys Ian Lavery Sir Robert Smith Dr Phillip Lee Dr Alan Whitehead Christopher Pincher The following declarations of interest relating to the inquiry were made: 7 September 2010,15 September, 26 October, 2 November and 14 December 2010 Sir Robert Smith declared the following interests: Shareholder Shell Transport and Trading; vice -chair of the all -party group on the offshore oil and gas industry; and attendance at the First International Offshore Oil and Gas Conference: The Future of Offshore Exploration and Development after Macondo in New Orleans 8-9th December. Travel accommodation and hospitality were provided by the organisers the Institute for Energy Law of the Centre for American and International Law, Plano, Texas. • 15 September 2010 Gemma Doyle declared the following interest: a family member was employed by BP. Draft Report (UK Deepwater Drilling —Implications of the Gulf of Mexico Oil Spill), proposed by the Chair, brought up and read. Ordered, That the draft Report be read a second time, paragraph by paragraph. Paragraphs 1 to 138 read and agreed to. Annex and Summary agreed to. Resolved, That the Report be the Second Report of the Committee to the House. Ordered, That the Chair make the Report to the House. Ordered, That embargoed copies of the Report be made available, in accordance with the provisions of Standing Order No. 134. Written evidence was ordered to be reported to the House for printing with the Report (in addition to that ordered to be reported for publishing on 7 September, 15 September, 12 October and 19 October. Written evidence was ordered to be reported to the House for placing in the Library and Parliamentary Archives. 0 [Adjourned till Wednesday 15 December at 3.00 pm • • 0 Witnesses Tuesday 7 September 2010 53 Page Mr Paul King, Managing Director North Sea Division, Transocean, Mr Malcolm Webb, Chief Executive, Oil & Gas UK, and Mr Mark McAllister, Chair, Oil Spill Prevention, Response and Advisory Group (OSPRAG). Ev 1 Wednesday 15 September 2010 Dr Tony Hayward, Group Chief Executive, BP, Plc, Mr Bernard Looney, Managing Director, BP North Sea, and Mr Mark Bly, Group Head of Safety and Operations, BP, Plc. Ev 14 Tuesday 26 October 2010 Mr Steve Walker, Head of Health and Safety Executive's Offshore Division, Mr Philip Naylor, Director Maritime Services, Maritime and Coastguard Agency, Dr Jonathan Wills, Independent Councillor for Lerwick South — Shetland Islands —and freelance environmental consultant, and Ms Susie Wilks, Biodiversity Lawyer, ClientEarth. Ev 29 Mr Roland Festor, Managing Director, Total E&P UK Ltd, Mr Richard Cohagan, Managing Director, Chevron UK Ltd and Mr Brent Cheshire, Managing Director, DONG Exploration and Production UK Ltd Ev 38 Tuesday 2 November 2010 Mr Charles Hendry MP, Minister of State, Department of Energy and Climate Change, Mr Simon Toole, Oil and Gas Director, Department of Energy and Climate Change, Mr Jim Campbell, Energy Development Director, Department of Energy and Climate Change, and Mr Hugh Shaw, Secretary of States' Representative for Maritime Salvage, Department of Energy and Climate Change and Department for Transport Ev 47 • 54 List of printed written evidence 1 Transocean Drilling UK Ev 59 2 Oil and Gas UK Ev 63 3 UK Oil Spill Prevention and Response Advisory Group Ev 67 4 BP Ev 74 5 Total E&P UK Ltd Ev 77 6 Chevron North Sea Limited Ev 81 7 Dr Jonathan Wills Ev 85 8 ClientEarth Ev 93 9 Department of Energy and Climate Change, Health and Safety Executive, and Maritime Coastguard Agency Ev 109 10 DONG Energy Ev 130 11 Transocean Drilling UK supplementary evidence Ev 133 12 Health and Safety Executive supplementary evidence Ev 135 List of additional written evidence • (published in Volume II on the Committee's website www.parliament.uk/ecc) 1 Institution of Mechanical Engineers Ev w1 2 Joint Nature Conservation Committee Ev w4 3 Research Councils UK Ev w6 4 KIMO UK Ev w12 5 BG Group plc Ev w12 6 British Rig Owners' Association Ev w14 7 Chamber of Shipping Ev w18 8 Platform Ev w19 9 Greenpeace Ev w26 10 Marine Conservation Society Ev w31 11 National Audit Office Ev w34 12 Caroline Lucas MP Ev w40 13 RMT Ev w41 List of unprinted evidence The following written evidence has been reported to the House, but to save printing costs has not been printed and copies have been placed in the House of Commons Library, where they may be inspected by Members. Other copies are in the Parliamentary Archives (www.parliament.uk/archives), and are available to the public for inspection. Requests for inspection should be addressed to The Parliamentary Archives, Houses of Parliament, London SW1A OPW (tel. 020 7219 3074; email arch ives@parliament.uQ. Opening hours are from 9.30 am to 5.00 pm on Mondays to Fridays. UKD 7 Plexus Holdings 55 • List of Reports from the Committee during the current Parliament Session 2010-11 First report Emissions Performance Standards HC 523 First Special Report Low carbon technologies in a green economy: HC 455 Government Response to the Committee's Fourth Report of Session 2009-10 Second Special Report Fuel Poverty: Government Response to the HC 541 Committee's Fifth Report of Session 2009-10 Third Special Report The future of Britain's electricity networks: HC 629 Government Response to the Committee's Second Report of Session 2009-10 • C7 • Energy and Climate Change Committee: Evidence Ev 1 Oral evidence Taken before the Energy and Climate Change Committee on Tuesday 7 September 2010 Members present: Mr Tim Yeo (Chair) Dan Byles Christopher Pincher Gemma Doyle Laura Sandys Tom Greatrex Sir Robert Smith Dr Philip Lee Dr Alan Whitehead Albert Owen Examination of Witnesses Witnesses: Paul King, Managing Director North Sea Division, Transocean, Malcolm Webb, Chief Executive, Oil & Gas UK, and Mark McAllister, Chair, Oil Spill Prevention, Response and Advisory Group (OSPRAG). Ql Chair: Good morning and welcome to this first public evidence session that this Committee has held during this Parliament. So we are very pleased to see you and we have chosen to address what we believe is a very topical issue. Can I say right at the outset that our concerns are as indicated in the terms of reference for the inquiry? They extend to safety, including of course particularly the safety of people and also to the environment, and the consequences of deepwater drilling for the environment. I believe you would like to make a short opening statement. Malcolm Webb: If that's possible, Mr Chairman, I would, and I think Mr King would as well. Chair: The benefit of it will vary inversely with its length. Malcolm Webb: Thank you. I take that on board. I will be brief. The Macondo well incident was a dreadful event and first and foremost we think of the 1 I men who lost their lives, and the others who were injured, some of them seriously, as a result of that catastrophic incident. That blowout and the sustained flow of oil which resulted from it was truly shocking and rightly caused the offshore and the gas industry and its regulators around the world to reflect upon the implications of this incident for their own operations. The UK was no exception and, without prompting, the industry, together with its regulators and trade unions, quickly came together to take stock of our position and without seeking to pre-empt or prejudge the lessons to be learned from Macondo set about a thorough review of our practices and procedures, and looking to see what enhancements could be made. One result of this review is that we continue to have faith in our regulatory systems and industry practices and, surprisingly, we believe we have found opportunities for improvement and are moving to implement these. However, these possible enhancements are relatively marginal in nature and do not cause us to lose faith in the strength and integrity of the regime we work in, in all parts of the United Kingdom Continental Shelf (UKCS). Much has been made of the fact that the Macondo well was drilled in deep water and indeed some Governments have imposed moratoriums on drilling in deeper waters. The UK Government have so far, and in our view quite rightly, resisted the notion of a drilling moratorium. Furthermore, most of these calls for drilling moratoriums tend to focus on deeper water areas. In truth, there is no reason for this concentration on deeper water save that this recent and awful Macondo incident just happened to occur in deeper waters. The depth of water is not the critical element here. Rather, what is critical are the practices and procedures employed to drill the well and to regulate those who are doing that drilling. In that regard policy and practice in the UK are substantially different to those employed in the US Gulf of Mexico and there is, in our opinion, no cause for public concern that the industry standards and regulatory practices and procedures employed in the UK are not fully fit for purpose. They are and they militate strongly against the likelihood of anything like Macondo ever happening here. Q2 Chair: Right. Does anyone else want to say anything at the start? Paul King: Yes, Mr Chairman, if it's all right. Thank you for inviting me here today to represent Transocean and to assist the Committee in understanding the readiness of the UKCS to handle any situations that occur that are similar to the Macondo incident that happened in the Gulf of Mexico. My name is Paul King. I am the Managing Director for Transocean Drilling UK and I have been working for that company for 35 years. I started out in the North Sea as a rig electronic technician and am currently today responsible for the day-to-day business of Transocean in the North Sea. Now, we at Transocean continue to feel deeply the loss of the I industry colleagues who lost their lives in Macondo, nine of whom were part of the Transocean family, and I personally knew one of those who lost his life there having worked with him in the Gulf of Mexico many years ago. I would just like to point out at this time that Transocean continues to look for the answers, along with the rest of the industry, and we fully support Oil & Gas UK and the OSPRAG committees in getting to the bottom of the issues that we are • • Ev 2 Energy and Climate Change Committee: Evidence 7 September 2010 Paul King, Malcolm Webb and Mark McAllister facing today and in ensuring that the UKCS is safe to Malcolm Webb: I do not think it has called a continue drilling. moratorium on drilling, Sir. I think what it has done is that it has suspended the granting of new licences Q3 Chair: Right. Thank you very much. Just picking up something that was said just now, you said the depth is not critical but it is the case, is it not, that if you are drilling in very deep waters then it is more difficult and the hazards are greater? I appreciate it depends on the procedures but the problems are more challenging the deeper you are. Malcolm Webb: You are right, Mr Chairman. Water is a. hazard that you have to plan for and deep water brings some particular risks with it. Q4 Chair: There is a definition in America of "deepwater" and what they call "ultra-deepwater". Does that definition apply in the UK as well? Malcolm Webb: No, I do not think it does, really. I don't think there is an agreed industry definition of what constitutes deepwater; indeed, I think it is something of a moving feast. When we started in the North Sea over 40 years ago, depths of 100 or 200 feet would have been regarded as deepwater, and as our abilities and technologies have moved forward so the definition of what is "deep" has moved with it. Q5 Chair: As a matter of practice have we been drilling in UK waters at anything like the depths that this was taking place in the Gulf? Malcolm Webb: Yes, Sir, we have in water depths. I think the deepest well so far drilled in the UK Continental Shelf was at 6,000 feet of water, and that was drilled some years ago. Q6 Chair: Right, and are there current plans to go on drilling at comparable depths to the Deepwater Horizon? Malcolm Webb: I am not aware of all companies' plans but I think we can anticipate that wells will be drilled at that depth in the UK Continental Shelf, yes. Chair: Okay. Q7 Albert Owen: Just to get my head around this, are we talking about actual exploration or are we talking about drilling that has been capped and left for a while and then you return to it? Have those sorts of exploratory drilling been done in the past and you return into it to get the oil out? Malcolm Webb: You can cap wells and go back into them at a later time; that is called suspending the wells. That does happen. And the thing— Q8 Albert Owen: And has that happened in the UK around the Celtic Sea and in the North Sea? Malcolm Webb: It can happen. There are suspended wells around the United Kingdom Continental Shelf, yes, but I think in the Macondo incident it was not a question of a re-entry into a suspended well; it was the drilling of an exploration well. in northern deeper areas but that does not mean that it has stopped deepwater drilling. Q10 Dr Lee: Well, it implies that it is awaiting developments and finding out what happened in the Gulf of Mexico. My understanding is that they are predominantly gas fields in Norway, yes? If that is the case, why would it suspend issuing licences more than, say, the UK where we are talking about oil? Why do you think it has made that decision? Malcolm Webb: I don't know. I am afraid you would have to ask them. My view would be that there is no case, given the strength of the regulatory regime that we have in here and the fact that we know the risks that are involved in the drilling of these wells and have engineering practices that can deal with them, that we should impose any blanket moratorium on the drilling of wells in the UK Continental Shelf. Q11 Dr Lee: Do they have, like, different procedures about assessment of oil spill plans? Malcolm Webb: I do not believe so. I am afraid I am not an expert on the Norwegian regime but I think it has a number of elements that are similar to our regime, to be distinguished from, for example, the more prescriptive American regime. Dr Lee: Okay. Q12 Sir Robert Smith: I should declare my interest to the Committee as a shareholder in Shell and also as a vice -chair of the all -party group on the offshore oil and gas industry. First of all in terms of depth, at what depth does the intervention in the well at the seafloor switch from divers to ROVs? Malcolm Webb: Well, others might be able to comment but I believe that is round about 500 feet, something like that. Q13 Sir Robert Smith: Because that seems to be more of a transition, in a way, in terms of operating differently, than the American definition. Malcolm Webb: It brings in the need for a whole new range of technologies and approaches; that is true, yes. Q14 Sir Robert Smith: You have already touched on the fact that you don't think that there should be a moratorium. Can you understand how, to the layman, it seems that when a disaster happens, you stop, obviously, and then wait for the lessons? Malcolm Webb: Yes, I can, but just because an event has happened in another part of the world doesn't mean to say that in a regime such as ours, because that has happened, we should automatically stop doing what we are doing, I believe, in an entirely safe and proper way. • Q15 Sir Robert Smith: Yes, we will be touching Q9 Dr Lee: You mentioned other countries that felt more on how the regime works here in the UK in the need to issue moratoriums on deepwater drilling. more detail with other questions. Obviously, having a Norway is one of them. constituency in the North East of Scotland, I am very Malcolm Webb: I don't think so, Sir. aware of the jobs and the revenue and the impact of Dr Lee: It has suspended until 2011. the industry, but I just wondered what would be the • • • Energy and Climate Change Committee: Evidence Ev 3 7 September 2010 Paul King, Malcolm Webb and Mark McAllister consequences on that side for the community in terms of investment in the industry and continuing production? Malcolm Webb: I think it would send a very negative message. I think it could be quite serious. There is a need for substantial continued investment in UK offshore areas. If we are to achieve what we need to achieve to allow this country to keep a measure of energy security, my industry is going to have to invest something like £60 billion over the next 10 years or so. Those investment sums will be prejudiced if people see that the UK regime is a stop/go, switch on/ switch off type of regime, particularly if there is no good reason for that switching off and on. Sir Robert Smith: Thanks. Q16 Albert Owen: You mentioned that depth wasn't an issue but regulation was. Do you think it is time — the EU is calling for it —that we regulate the regulators, that we do have a level playing field across the world? Malcolm Webb: I find that a very strange concept — that we should put over the level of our very expert professional regulators that we have here, who have hard-won experience from the North Sea, what I would have thought was bound to be a relatively less expert EU umbrella. I have heard it said from the EU that we need to control the controllers. Frankly, I think I am at a loss to understand what added value there would be with a European level of regulation. Q17 Albert Owen: But what I find difficult is that we are talking about here an accident that occurred predominantly in the Gulf of Mexico. Experienced companies are drilling there. We are not talking about a new country developing this now. We have got Norway wanting a moratorium, and again it is an experienced country. So why does Britain feel it has to be out of sync or worried about increased regulations? Malcolm Webb: I am sorry, you may say I am picking on this, but I still do not believe that Norway has called for a moratorium. Albert Owen: No, I am asking a question. Malcolm Webb: I think it has put a limitation, it has slowed down the granting of new licences but I do not think it has imposed a moratorium. Q18 Albert Owen: I understand the technical difference but it has done it for a reason, hasn't it? You know, it is a first-rate country when it comes to oil production. Malcolm Webb: Yes. Well, you would have to ask the Norwegian authorities why they have decided to limit their licences. I am not aware of it. Q19 Albert Owen: It is our near neighbour. I am finding this difficult to understand. It is our near neighbour and we work in co-operation with it in the North Sea, I assume? Malcolm Webb: Yes, we do. Q20 Albert Owen: And it's taken this radical step to limit licences. Malcolm Webb: I am not sure how radical the step is, Sir, and, I repeat, I do not believe it has imposed a moratorium. I come back to the point that I do not think there is a case for a moratorium to be imposed in this country bearing in mind the regulatory regime and the industry practices that we adopt here, and there are critically important differences, I believe, between the US system of administration, for example, and the UK administration. Q21 Albert Owen: Okay, but talking about Europe, and that was the premise of my question, surely we can contribute to the European level of regulation. You know, the expertise that you talk about —over 40 years of proven experience —could actually enhance the European level. Malcolm Webb: Well, to be quite frank, the last thing I would wish to see is any diminution in the resources available to the regulators here to support a pan- European initiative. I would rather they were kept here in the UK, continuing to do the excellent job they do here in the UK. Q22 Albert Owen: Well, I am not suggesting that they go overseas. What I am suggesting is that they share their expertise. Malcolm Webb: They could do. Q23 Albert Owen: Okay. With regards to the oil spill regulations at a European level, that is mostly for shipping and tankers. Do you think there is a scope to extend this to drilling? Malcolm Webb: There is clearly the scope to extend it to drilling. I think it does not extend that far at the moment, but as far as the industry is concerned that would not be an issue of primary concern for us because as an industry we take the greatest steps to ensure that if there is any spill of oil from any of our operations the industry deals with that —deals with the clean-up, and deals with the compensation for that — and the industry has an excellent track record on that, and has furthermore set up bodies to support it in that on a mutual co-operative basis here in the UK. So, it is an interesting question but in some ways somewhat academic as to the way that the industry does approach those issues here in the UK. Q24 Albert Owen: I did not mean to be too academic. I meant, you know, to try and direct the answer. What concerns me is that if there is a spillage —we have seen spillages in the past —it does affect innocent countries that, you know, are not involved in the actual drilling. Malcolm Webb: Yes. Albert Owen: I am talking about Europe now. If there is something on this scale that does happen in Europe, it's not going to stop at international boundaries. Malcolm Webb: No. Albert Owen: So, that is why I am asking whether the present regulation shouldn't go beyond shipping, which is a moving object, to deal specifically now with the experience in the Gulf of Mexico —to deal with drilling and exploration. Malcolm Webb: I think that is something that could be looked at but I think the other point you make is a very important point too. It is important that the nations in Europe, and particularly those around the 0 • Ev 4 Energy and Climate Change Committee: Evidence 7 September 2010 Paul King, Malcolm Webb and Mark McAllister North Sea, collaborate and co-operate together, and again there is a good track record and good history on that in the UK. Q25 Albert Owen: I think you are moving towards what I asked in the first place, and perhaps there is a move towards that. Do you feel that the environmental liability directive would hold operators liable for the damage they do in terms of biodiversity? Malcolm Webb: I am not sure, actually. I am not sure that I am expert on that. I think our view is that it probably —it does not at the moment, no. Q26 Laura Sandys: This just really follows on from my colleague's questions about this international regulation. I mean, it is an international business. We are seeing now that rigs are being moved from the Gulf of Mexico to the Congo, to Egypt. When you start to look at some sort of international framework, would that not then offer in many ways a much stronger level playing field across the world and ensure that there is some consistency? I mean, in the documents that we have there is a very clear message from you that the regulatory structure in the UK is excellent; it affects all aspects of safety. Would we not see that as a benchmark to raise everyone else's up to that level, rather than you saying in many ways that by us spreading our expertise we are going to diminish our capability? I just see that it is a global business, and that there are global standards on environmental protection, and I wonder whether we should use ourselves as a stronger model for that international framework. Malcolm Webb: I would hope that other people can look at our model and learn from it, and improve their practices and procedures in line with what we are doing here in the UK, and if we can play a part in that we would be very pleased to do so. I would still be slightly concerned, on a precipitative move to the creation of some pan-European regulatory authority, that we might see a dumbing down as opposed to a raising up of standards. Q27 Dan Byles: I am particularly interested in the difference between the regulatory system in the UK and in the US. Now, you have described the UK regulation as being less prescriptive. My understanding is, in effect, companies are required to be safe and are then inspected rather than told specifically what to do. Can I ask how much variation that leads to? Do individual companies, individual wells, tend to operate on a case by case basis when it comes to specifically what equipment is installed? I am thinking now of BOPS, blind shear rams, this sort of thing. Malcolm Webb: The answer is yes, it is relatively case -specific, and that is one of the billion factors behind it, really, so you will have different requirements for different types of operation depending on the type of operation. That does not mean to say, however, that we have got lax standards. It means, actually, the safety case regime in the UK — introduced after, of course, a seminal Cullen report — is a goal -setting regime. It requires the operators or the duty holders to make sure that they have reduced the risks of their operations as low as is reasonably practicable (ALARP). That is the obligation upon them and they have to take all necessary steps to do that and import all appropriate techniques, and it is a very dynamic system, therefore, as well. Q28 Dan Byles: Doesn't that make it harder for the actual regulators then to come in, if there is not effectively a single standard in operation —if a well operated by one company might have significantly different equipment to a well operated by another? I mean, I think there is going to be a lot of focus on things like the numbers of blind shear rams that should be in place. Malcolm Webb: Yes. Q29 Dan Byles: My understanding is that in the US for some time there has been a suggestion there should be a minimum of two, but in the case of Deepwater Horizon there was only one. That is a very prescriptive issue, but it seems that in our system it is going to be much harder for the regulators to decide what is the minimum gold standard if we have a lot of variety on different wellheads. Mark McAllister. Sorry, but if I may interrupt, I think another key element in this process is the use of independent verification of well design. It is very important, because when we talk about a goal -setting self-regulating system, it can sound terribly lax, except when you think about it, what is happening is an operator is being asked to consider all the risks, to demonstrate that they have thought about all the risks in a mature and sensible way, and have mitigated against them. So their design, their management system, and all of their practices then go to an independent company to be verified. Now, that is populated by seasoned drilling professionals, who've got no commercial interest in the well itself but are looking at that from a perspective of what is the water depth, what is the reservoir depth, whether it is gas or oil, and what is the pressure and temperature which it is producing. They can make a very, very informed, experienced decision on whether that is a good way of mitigating risk, and then the application goes to the regulator. So, the regulator has got that independent assessment. Q30 Dan Byles: Interestingly, you have touched on what my next question was going to be about: the independent and competent persons. I am very curious to know who these independent competent persons are. Are they other people from the industry, people from other companies? Mark McAllister: They are people in independent consultancies. So they are industry professionals who may have worked in oil companies in their past. They probably have; they probably trained in oil companies. They generally tend to be more experienced professionals. Dan Byles: So they are from the industry? Mark McAllister. They are from the industry. Dan Byles: So the independent competent persons assessing parts of industry come from other parts of the same industry, in effect? • Energy and Climate Change Committee: Evidence Ev 5 7 September 2010 Paul King, Malcolm Webb and Mark McAllister Mark McAllister. Well, yes, except of course that they are not working for the oil companies. They are working for independent consultants whose reputation and whose name is their only currency. Q31 Laura Sandys: Are they chosen by them? Mark McAllister. Sorry? Laura Sandys: To add to that, are those consultancies chosen by the oil companies —that is, is it a client relationship? Mark McAllister. Yes, it is. Laura Sandys: Right. Q32 Tom Greatrex: Mr. Webb, earlier on you described the UK regulations as fit for purpose, and 1 think you said the regulators do an excellent job. Does that mean your view is that the Deepwater Horizon would have been allowed to operate, if those regulations were in place? Malcolm Webb: As we don't know what happened yet, and we do not fully see the picture there, I think it is impossible to answer that question, Sir, but do I believe that we operate in the UK under a superior regulatory regime to that which is applying in the US? Yes, I do. We have a regime where safety is divided from economic regulations, which is not the case in the US. We have the whole safety case regime, which obliges the operator and the owners of the vessels to make sure that they are operating to a standard which reduces the risk of the operation as low as reasonably practicable, and we do have independent verification of well design. We also have independent verification of safety critical equipment; and on top of that we have the 115 expert inspectors within the highly professional Health and Safety Executive, which also, after all of those other checks have gone through, reviews all well proposals. So, I believe we have got a very, very good system. It came out, of course, of a dreadful occurrence here. This came out of the Piper Alpha tragedy, when the seminal Cullen inquiry and the inquiry report that came from that established this system, and I believe it has served us exceptionally well over the last 20 years. Q33 Tom Greatrex: So the work of the Health and Safety Executive, when it is doing its inspections, and the conclusions it comes to in its reports is something the industry takes seriously? Malcolm Webb: Absolutely. We work very closely with the Health and Safety Executive. I am delighted to say the Health and Safety Executive readily agreed to join us in the OSPRAG work, along with the Department of Energy and Climate Change and the Marine Coastguard Agency. We work with them as well in the Step Change in Safety initiative, which you may be aware of, along with the trade unions as well. Q34 Tom Greatrex: Perhaps then I could ask Mr King if he could give his reaction to the bits from the health and safety report on, I believe, one of your operations in the North Sea that say that there was evidence of bullying, harassment, and intimidation of health and safety representatives. Have you got any views on that point? Paul King: Yes, I have. I think the report needs to be viewed in its entirety. There were some comments — anecdotal observations —made from discussions with our personnel offshore that there were some isolated cases of intimidation or bullying, which was news to the management in town. We are a company that cares deeply about the way our people work offshore, that they work safely, and about the importance of providing an incident -free environment for them to work in. We have several alternative ways for people to get this message to us in shore -based management and to corporate executives via an ombudsman line, which is manned by a third -party company. Anybody who has anything that they are concerned about can, in complete confidence, talk to someone and report it, and move on from there. Q35 Tom Greatrex: Sorry, that sounds all very good theoretically but it seems to jar with what the Health and Safety Executive found. Are you telling me that there is not bullying and intimidation happening, and if there is bullying and intimidation happening of Health and Safety reps what are you doing about it? Paul King: Well, you know, I firmly believe that our company works safely and that these are isolated cases. I would not let my son work for this company if I did not believe it was a company that cared for its people. As a result of receiving the report from the HSE and discussing it with it, we put this out to our personnel offshore throughout our division, and allowed them to review it. We then brought 500 of about 1,200 personnel into town to discuss directly with us the issues that were raised, and we could not at that stage confirm that there was any indication of, you know, widespread intimidation or bullying. We focus on the issues of fair play and make sure that our people can work in an environment that allows them to work safely. The feedback from our people during those meetings was very positive. We reiterated quite clearly that it is unacceptable for Transocean to condone any sort of intimidation, bullying, or whatever issues that would affect the way that they work. We continue to ensure this is unacceptable with Transocean and we continue to enforce that. Q36 Tom Greatrex: Can I ask you, then, is it fair, this view that I have heard from a number of different people who work offshore, which is that the drillers are the part of the industry that takes health and safety less seriously? Part of that is linked, or seems to be linked, to the sense that you still operate NRB despite the agreement that has been in place. Paul King. I actually find it quite offensive that people think that we take rules for granted. We seriously care about the way our business is run. We are a professional industry. We have learned from lessons in the past. I can see through the 35 years that I have worked in the industry the radical changes that have been made. If I look at the conditions I worked under offshore in 1975 and compare that to the way we operate today, there is no comparison whatsoever. Q37 Tom Greatrex: Do you operate NRB? Perhaps you could explain for the Committee now. • Is • Ev 6 Energy and Climate Change Committee: Evidence 7 September 2010 Paul King, Malcolm Webb and Mark McAllister Paul King: "Not required back"? No, we do not. If we have a problem with anybody on our rigs who is not performing from a safety perspective or a competency perspective, we would talk with them offshore before they leave the rig to advise them what our thoughts are about their work and, if it is the case that we find their work unacceptable, why they will not be coming back to the rig. Tom Greatrex: So why do you think it is, then, that the trade unions involved have said — Chair: Can someone turn that mobile phone off or leave the room, whoever it is? Q38 Tom Greatrex: Sorry, could you perhaps comment on why it is that the trade unions that are involved have said that they are not prepared to renegotiate the NRB because it is not being, as they say, observed by all parts of the industry and particularly drillers? Is that something that you are aware of? Paul King: No, it is not something that they have talked directly to me about. Malcolm Webb: Can I respond, if I might? I am slightly taken aback by that comment. Oil and Gas UK has a guideline related to NRB which was agreed with the trade unions and all members of the industry. We undertook a review of that guideline. It was launched just over a year ago. We undertook an independent review of that. We found that there were certain improvements that could be made to the regime, particularly around some of the education and spreading the message around the industry, but also for providing within the contracts —the relevant work contracts —that the NRB guideline should be adhered to. That was readily agreed by the industry and agreed by the unions, and in agreement with the unions we are in the process of re -launching that guideline at the moment. So I don't think actually at the moment we have a disconnect with the trade unions on that point, Sir. Q39 Sir Robert Smith: When you say "the industry", does that include the drilling contractors? Malcolm Webb: It does, Sir. Q40 Sir Robert Smith: Mr King, the report that we have seen parts of in the press was not actually published by the HSE, but are you able to give us a copy of it so that we can see it? Paul King: Yes, we certainly can. We have no problem with giving a copy of that to the Committee. Q41 Sir Robert Smith: Thank you. That will be helpful. Just reinforcing, the bit that does cause concern, though, is that if, when the HSE turns up, it sees a sizeable number of people saying they feel there is a culture of bullying, it is a worrying phenomenon. Surely the most crucial thing for safety is that, no matter where you work in the organisation, you have to have the confidence and the courage to know that if you see something unsafe you can stop it or make sure it does not escalate. Quite often it won't be a senior person that is seeing the thing that is going wrong and someone in a more junior role has to have that confidence. Paul King: I think the issue of time out for safety, which is, you know, an industry standard that has been developed in the UKCS, is something that we fully support. When you get the entire HSE report, you will see the positive aspects of the report and the negative aspects of the report, the negative being that there were some instances —and I wouldn't say we are talking about a large amount of instances —of bullying; I believe you will find that they are isolated cases. But on the positive side the HSE recognises that Transocean fully supports time out for safety. We continue to train our people and ensure that they have no issues if they want to stop the job. I think a lot of people look at time out for safety thinking that we are going to shut the rig down every time someone calls a time out, but more often than not it is part of the way we work offshore. When guys come on their shift, they are advised on what operation is going on on the rig, the weather conditions, the environment, and what is liable to happen over the next 12 hours. They then go off with their individual supervisors to discuss the next 12 hours' work that they have. It is important, and each of our supervisors reiterates this at the start of the tariff, that if there is anything that they do not understand then they call a time out for safety. This is really so that they understand fully the job that they are doing. Similarly, if a new person comes to join the team they will take a time out so that he is brought fully up to speed on what is going on. So, I think when you have read the HSE report you will see that, yes, we do provide and are driven towards providing a safe working environment for our people. Malcolm Webb: There is indeed another report that we might draw to your attention. You may recall the HSE undertook a major programme, KP3, a while ago looking at asset integrity. In the context of that report, it undertook an independent survey of the work force. There was very good participation. I think they had about 5,000 respondents on this, looking particularly at the issue of work force engagement and ability to intervene on a safety matter. The results are quite startling. They show the industry in an exceptionally good light, in my view, with very, very high assurance amongst the work force that they are free and able to intervene on issues of safety, and without fear of retribution. I will be very happy to let you see a copy of that report too, if you would like it. Q42 Chair: There are a lot of pressures, though, aren't there? I mean, there is another report which I understand estimated the cost of stopping operations to put up a blowout preventer, or make repairs, at $700 a minute, so it is not just the bullying that might deter someone. The financial incentives to cut corners are huge, aren't they? Malcolm Webb: Well, as are the costs of getting it wrong. Mark McAllister: I think the other way of looking at that statistic is actually the cost of poor planning and poor well design is great, and good well design and good planning go with good safety. So, you know, in such a capital -intensive business, actually getting it right from the design phase is fundamental. • Energy and Climate Change Committee: Evidence Ev 7 7 September 2010 Paul King, Malcolm Webb and Mark McAllister Q43 Chair: Well, I am sure that is an approach which can well be adopted by senior executives sitting in their office, but when you are out on a well and you have got to make a minute -to -minute decision, the financial pressures not to stop are nevertheless very considerable, aren't they? Mark McAllister. That is why another important part of the regulatory regime that Mr Webb has referred to on several occasions is the management system —a transparent and clear chain of command —both for the operating company and for the rig contractor, and the interface between those, so that individuals are not put under pressure actually to make million -dollar decisions without a clear opportunity to reach up the chain and get endorsement for that. Chair: Christopher, you have been trying to come in for a while. Q44 Christopher Pincher: We have already asked my question, but just in relation to this point, we are talking about making sure that safety is crucial. How often do you think it is right that the BOPt should be brought back from the seafloor for testing and checking? Paul King. The BOP is generally tested on the seabed during an operation. It has to be tested every 14 days. Then it is fully function -tested, and fully pressure - tested. There are some times when the operations will be in such a condition that an exemption is requested. The risk will be assessed on the rig; it will then be passed on to the support team in town to analyse, and there will be discussion with the client. We will then make a decision on whether an exemption will be allowed for a certain amount of days until we are in a position where we can test the BOP, or whether we will stop at that time to test the BOP stack. But the BOP stack —blowout preventer stack —is actually one of the pieces of equipment that is tested more thoroughly than any other piece of equipment that we have in our industry. Q45 Laura Sandys: Just going back to what Mr McAllister was talking about in the sense of pre- planning and looking at drill design and the overall well design, many scientists would say that actually we know less about the bottom of the sea than we do about the moon and the knowledge and understanding of the environment in which you are operating is not as well understood as many other environments. When you look at OSPRAG's remit and also its membership, there seem to be no scientists involved. Obviously there are industry scientists, but I refer to independent oceanographers, marine engineers who are independent of the oil and gas sector, and a true sort of desire to look into the future. You say that you need to plan from the future. I see this group as being, first of all, a little bit more of an analysis of a disaster of the past, which is important to learn from, but this is an opportunity for you actually to gather information for the future too, and actually to use more independent assessment and also input. It just seems like a quite closed sort of intimate shop. Mark McAllister. Okay, let me try and answer that by, first of all, talking a little bit about the membership I Note from the witness: `Blow Out Preventer' of OSPRAG and also its workflow and the different things we are looking at so you can get an understanding of how we are trying to attack these issues. OSPRAG is, I think, quite typical of the way the industry in the North Sea works. We did the same when there was the helicopter tragedy last year. It is not just the oil companies and the contractors, but DECC, the HSE, the Secretary of State's representative, the Maritime and Coastguard Agency, and the trade unions all involved together, so it is very much a communal activity to make sure that we have the processes and the readiness for this. Now, if you look at that chain of activity, the first thing is to reduce as low as we possibly can the chances of an event like this happening in the North Sea, and actually the expertise for that does lie within the oil industry. Your 7,000 wells drilled in the North Sea have been drilled by people in the oil industry. The experience of dealing with different pressure regimes, different geological formations, and different water depths, lies almost entirely within the oil industry, so actually, on the primary, important task of making sure it does not happen, we do have the expertise within the industry to attack it. The second element, then, is, if such an event were to happen, how can we ensure that it is dealt with as quickly as possible with the least oil spill possible? Actually, that has been one of the key elements of the OSPRAG work so far, and once again, largely the expertise does lie within the industry, although we are looking outside, and a lot of it, you know, draws on very much the experience of Macondo and some of the solutions that BP has come up with to make sure those solutions are already manufactured and readily available to the North Sea. Now, the third element —and I think this is where your point about external help is most pertinent —is containing the oil during the period that you are trying to actually cap the well, and how we deal with modelling of oil spills, environmental impact, et cetera, and that is where we are reaching out beyond the industry. The model is sitting in completely different organisations not part of our organisation. Those have the most up-to-date and pertinent models of, you know, the movement of oil in the sea, for instance. Q46 Laura Sandys: In the wider sense, do you feel that you are putting enough investment into understanding the environment in which you are working, because it is a very complex and very lightly understood environment? Maybe from an oil and gas perspective you have quite a lot of experience, but it is still an environment that is not known and not understood in quite the same way as other environments. Mark McAllister. In what context? When you just used the word "environment" in that context, what are you talking about? If you are talking about the drilling of wells, the environmental uncertainties are around the key things that could cause the well not to perform or to blow out and that is around geological horizons, it is around pressure, whether it is oil or gas, and this expertise is almost exclusively within the oil industry. If you are talking about dealing with a spill and • C Ev 8 Energy and Climate Change Committee: Evidence 7 September 2010 Paul King, Malcolm Webb and Mark McAllister getting it contained, once again the expertise sits within the oil industry. If you are then talking about, as I say, the impact of this oil spreading in the sea, then of course we are looking as widely as we can to get help to make sure that we are modelling that correctly so our resources are correct —are adequate. Malcolm Webb: We are not working alone on that. You have organisations such as the Maritime and Coastguard Agency and the like who are also very much focused on that and bringing their own scientific expertise to bear. Mark McAllister. Yes. Q47 Dr Lee: Does OSPRAG ever plan to review oil spill response plans that have been submitted before the Gulf of Mexico incident? Mark McAllister. Sorry, just restate the question. Dr Lee: Well, the oil spill review plans that have been submitted as part of an application for the last period, are you seeking or looking to review them, the ones that have been submitted prior to the Gulf of Mexico? I say that, but I looked at the oil spill response plan for the Gulf of Mexico and-1 don't know —it is a weighty tome so I can't say I have read it. I have reviewed it and there is sort of evidence of a bit of a cut -and -paste job about it and I just wonder whether OSPRAG might want to review plans that have been submitted to date. Mark McAllister. Yes. Absolutely, as part of— Q48 Dr Lee: I mean specifically. I will give you one example. There is a map in it and it has an icon for a walrus. I mean, you don't get walruses in the Gulf of Mexico. Mark McAllister. We have seen these stories in the press, and I understand what you are saying. Actually, that is one of the things about the whole OSPRAG constituency because the constituency is the oil industry —both producers and contractors —the regulator, the trade unions, and the coastguard agency. So actually all of us are looking and saying, "Well, what are the constituent parts of an oil spill response plan?" First of all, prevention; secondly, early containment and capping —what has been learned from Macondo—and, thirdly, what happens to the oil when it is released from a well. Now, this has been done together, so, you know, if there was something as farcical as a walrus, we are together in the same room. The entire industry, including the regulator, is looking at, "Have we got the provisions? Have we got the right plans?" You would not expect the oil spill response plan to vary dramatically from one company to another, because we are drawing on communal resources to a large degree. Q49 Dr Lee: Yes, the size of it has certainly differed. I have seen some at 60 pages and this one is almost 600. In terms of spill volumes, you make a prediction, as I understand it —a credible spill volume chart. Clearly, they underestimated how long it was going to take to cap that well. Are we happy with the sort of projections for a spill in West Shetland, for example? Particularly in view of the fact the sea conditions would be much different. Mark McAllister. Much different; I agree with you entirely. That is why, with a risk of repeating myself, I go to this chain: first, it is prevention; secondly, it is actually not saying, "Did we get the spill length wrong?" but "What have we learned in Macondo to make the spill length as short as possible, and what resources do we need to be able to cap any well?" So one of the elements of one of the groups in OSPRAG is to look at the BOPs at work in the North Sea and look at the variety of different connections one would have into them to make sure that we can design equipment that is available to the industry that can be collocated with any of these blowout preventers on top of the wells. So that is a key element. It is not a question of having underestimated. Let's take that underestimation and say, "Okay, how do we make sure that if such an event occurred we can deal with it as quickly as possible?" Q50 Dr Lee: Just one final question. In the Gulf of Mexico, as I understand it, BP was under licence. BP was spraying dispersant at source, which had never been done before. In terms of permission for that, the Americans take responsibility, I guess, for allowing that to happen. The point is that we do not actually know what the environmental impact of doing that is. It could be, for instance, that oil is sitting 250 metres under the sea, couldn't it, as we speak? So in view of that, do you think that sort of subsurface dispersant would be used if it happened in West Shetland and, going back to what you were saying earlier about the impact upon neighbouring countries, would we have to tell the Danish with regards to the Faroe islands or that sort of thing? Mark McAllister: There are no plans at the moment to use dispersants at source within what we are looking at. However, the key thing here, going back to your earlier question about expertise, is this is the area where expertise is most needed because we have a very, very different marine environment in terms of the waves, in terms of natural dispersal of the oil. So, that is a key element of the OSPRAG work —making sure that our modelling of the oil spills, and our understanding of the use of dispersants, is as well informed as possible, and that is probably the longest wavelength piece of work that we will do within this whole process. Q51 Dan Byles: Thank you. Leaving aside whether the regulatory system itself would require changing, do you think that the industry and regulators, as a result of what has happened in the Gulf of Mexico, should now reconsider some of your assumptions on what might be the minimum acceptable safety standards of equipment at the bottom? I make no apology for coming back to BOP stacks and blind shear rams because it seems to me that it was a catastrophic equipment failure in this area that was not anticipated that led to the problems in the Gulf. You have already stated that we do not have minimum required standards laid down by regulation for two blind shear rams, for example, looked at on a case - by -case basis. Do you now think it is necessary to go back and re -look at wellheads that we believed were safe in the light of what has happened and say, "Well, 11 • • Energy and Climate Change Committee: Evidence Ev 9 7 September 2010 Paul King, Malcolm Webb and Mark McAllister actually, maybe we are at risk in some of these areas of a similar catastrophic equipment failure"? Mark McAllister: Certainly, what we have done as part of the OSPRAG work, and Mr Webb has described the regime, is to make sure that actually that regime is working and, working with the entire drilling management community of all the operators in Aberdeen, to actually interrogate —to ask, "How is this working for you and can we share best practice?" It is obviously something you will see in our evidence throughout. Sharing best practice is a key element in the industry. Q52 Dan Byles: But I am suggesting that what was previously considered best practice might be reconsidered in the light of this. Mark McAllister. Yes, might be reconsidered, I agree with you, and that will be part of the work —looking at what is best practice and whether there need be any changes. I think where we are wary is making global and universal changes that may not be appropriate from situation to situation. I have seen it in the oil industry in the past and I am sure it happens in other industries when regulators react to one event by imposing some new standard which is thought to improve the situation, and actually that becomes a key contributing factor to the next incident that happens. Without being too sentimental and just from a personal nature, my brother was one of the 96 who died at Hillsborough, which was a very, very different situation but a key contributing factor were the fences that were put up to keep the fans in, which was thought to make the place safer and actually made it less safe. We have seen the same thing in the oil industry. So, yes, we need to use everything that comes out of Macondo to examine safety of equipment, our processes, and our planning, but the kernel of what we have in the safety case regime is, on a case -by -case basis, the expertise within the industry, the expertise within the independent verifier, and then the expertise within the regulator, making sure that we are looking intelligently at every situation. Malcolm Webb: If I could add to that, I think that is absolutely right. That is the brilliance of the safety case regime here. In response to your question, "Will these issues be looked at?", yes, you can be assured they will be looked at because of the goal -setting nature of that, the players involved and what they have to do, and it is very dynamic. This is an industry that does not have to wait for a regulation or the government to legislate on something for it to move forward. It will move forward under the ALARP principle as and when it is needed to do so, or is appropriate to do so, so it will happen. Q53 Chair: Would it be fair to sum up your views about the issue of changes to the regulatory environment as, "No. 1: European Commission, get lost," and "No. 2: no change required in the UK"? Malcolm Webb: That is a very blunt way of putting it, if I might say so. Chair: Well, it is my distillation of what you have said in the last 45 minutes. Malcolm Webb: I think it is difficult to see that the European Commission can add much to the regulatory regime here in the United Kingdom. We do believe that the basic structure here is a very, very strong structure, is serving the country well, and should continue. I might add as well, I do think it is vital for this regime to work that it also has appropriate expertise within the regulators, and that they have the resources to do their jobs, and I do hope that the cuts we hear being talked about around Government don't in any way impair the regulators' ability to regulate properly. We need strong regulators as a part of this process. That is very important to us. Q54 Chair: And that is what is emerging from the OSPRAG review at the moment, is it, as well, that sort of general conclusion? Mark McAllister. It is not as coarsely put as that; we are talking about a basic framework that is mature, that is intelligent, that stands us in good stead, that needs to be stress -tested occasionally and that we have made sure is actually working in practice the way it is meant to. Q55 Gemma Doyle: Can I ask a bit more about the industry's response in the event of a deepwater blowout? How would the response work? How would it operate, and is that being re-examined at the moment in light of what has happened? Do you envisage that there will be changes to emergency plans? Mark McAllister. I am sure there will be changes and we are examining it. Once again, without sounding like a broken record, our first priority is around planning to minimise these things happening. The second thing is, again, early containment. These wonderful bits of kit that BP invented —this type of approach is to make sure that if something did happen, we can have that available very, very quickly. That is a major element of our work flow in OSPRAG, so that is the key thing. Then the third thing is, as you say, the response. At the moment the response through the use of booms and of dispersants is through a communal approach through offshore OSRL, and we are looking at their equipment, and whether it is sufficient for the cases that we are designing for. Q56 Gemma Doyle: Would the response be significantly different from what we have seen in the Gulf of Mexico because of the differences with the North Sea? Mark McAllister. Now, you see, when we talk about the Gulf of Mexico of course we are talking about one element of the Gulf of Mexico, which is the ultra - deep water. Of course, in the North Sea we have got everything, from 100-feet water depth gas wells in the southern gas basin through 300 feet, including high pressure, high temperature condensate wells, 500 feet and traditional black oil fields in the North Sea, and then the deeper waters west of Shetland. So part of the OSPRAG remit is actually to make sure that we are looking for the appropriate response for each of these situations. Malcolm Webb: I do think one other slight difference would be the ability of the Government to intervene • L_J Ev 10 Energy and Climate Change Committee: Evidence 7 September 2010 Paul King, Malcolm Webb and Mark McAllister as well. If you look at the powers of SOSREP, they have extensive powers to act offshore in any instance such as that, and act very swiftly as well if it is a Tier 3 incident. Q57 Christopher Pincher: At the risk of getting my question slightly out of kilter, you have said the North Sea is different from the Gulf of Mexico and that there is a huge variety of sorts of drilling going on. I wonder if you could give us some more detail about the specific challenges of drilling in deep water in the North Sea. For example, you said earlier, Mr Webb, that below a certain depth you cannot use divers; you need to use ROVs to, for example, seal a leak. Now, in the Gulf of Mexico I think the ROV failed to fire the blind shear ram. You also talk about different rock formations, and the rock formations in deep water in the North Sea can be more immature, so the rocks can fracture more easily, so you need to put less pressure down to hold the fluids down. So, if the wells are that much less controllable and more able to fracture, what are the risks that you see drilling, and why don't you think that a more determined regulatory framework around deepwater drilling is appropriate? Mark McAllister. Let's start with the rocks. Immature, lower pressure, more friable rocks are possible in all different parts of the North Sea. So the central North Sea, for instance, almost has a number of different industries within it. We have the giant Forties Field which is up in the Paleocene, which is generally much softer rocks, and different types of oil. We have got quite high pressure also in the central North Sea. This is not in deep water at all, so those hazards— Q58 Christopher Pincher: But it will be easier to cap those, surely, than deeper water formation? Mark McAllister: Not necessarily, because obviously the ability to cap it is about, first of all, is how much pressure and how much fluid is coming out of the well. Actually, even if it were possible to use divers to cap the well, because of the water depth it is unlikely that we would want to use divers, in order not to risk their lives. So, it is actually likely that even in shallow water depths we would want to use ROVs in a situation such as this. So, as we said at the beginning, we do not see the deep water necessarily being a major element in this whole process. The real major elements are: what happens below the seabed; what is the pressure regime; what is the geological formation; and what depth we are drilling to. You know, some of these wells in the Gulf of Mexico are drilled to 25,000 feet below the seabed. That is 5 miles. That is like drilling to the top of Mount Everest from the base, so it is a long, long way. The traditional well in the North Sea is more like 10,000 feet. It is a much shallower well; so you are in a very different regime below the seabed. So we generally don't see the deep water being a major contributory factor to this. Malcolm Webb: I come back to the point as well, again not wishing to sound like another chipped record here, that the safety case regime is a very purposeful, dynamic and demanding regime for this industry to work in. So the idea that it is not demanding enough and it is not rigorous enough for deepwater areas I cannot accept. I think it is; it is already. We have got it. Q59 Christopher Pincher: But don't you accept, as Dan has said, that, for example, having two blind shear rams in place reduces the risk considerably of a flow which you cannot stop? Malcolm Webb: You have to examine each case on the particularities of the case in point, and in some cases that might be true and in others it would be a futile exercise. Q60 Laura Sandys: I always think that the insurance sector is quite an interesting barometer of risk and assessment of risk. Would the industry be able to give us an outline of what has changed, in terms of insurance policy costs before the Gulf of Mexico and now? Obviously it will be looking at not just the operational risk —I think there is obviously the operational risk —but also the environmental risk, and it must have also done quite a lot of rigorous assessments of what the industry is capable of doing, how it can recover a situation, and over what period of time. Malcolm Webb: Speaking personally, I can't. I do not have that information. My organisation has not looked into it, but we could look into it if you would like and come back to you on it. Q61 Laura Sandys: Is the insurance sector part of your group? Mark McAllister. It is in the sense that there is a collective approach to liabilities through OPOL so every person who drills a well in the North Sea has to demonstrate certain ability to deal with a situation such as this. OPOL is the group, is the body, through which that is regulated. So OPOL actually looks at the insurance that any company has in place to make sure it is adequate, not just in terms of value but in terms of, you know, the small print and the way that works. If the third party liability under the OPOL scheme for some reason does not materialise, and somebody defaults on that payment, the entire industry has a collective responsibility to meet those payments. Q62 Laura Sandys: Do you expect premiums to increase significantly as a result of the Gulf of Mexico? Malcolm Webb: I am really not expert enough to comment on that. I would have thought there could be some increase but whether it is considerable or not, I do not know, and it is outside my area of expertise, I am afraid. We could get back to you on that point, if you like, but we would have to take advice. It is not within our area, if you like. Q63 Dr Lee: Along the same issue, in the Gulf of Mexico, the liability was $75 million US. Was that all right? It probably ran out after about two weeks? I am just looking at the figures you have got. You are suggesting you are going up to $250 million; when do you see that being the case, or is that going to be retrospective? Is it going to cover West Shetland? Malcolm Webb: Yes, it is. • is Energy and Climate Change Committee: Evidence Ev 11 7 September 2010 Paul King, Malcolm Webb and Mark McAllister Mark McAllister. Yes, every well drilled from now on. Q64 Dr Lee: And I think that we are talking over $1 billion dollars already at BP. The reality is if it was not so big an organisation, it would have gone bust. Mark McAllister: Yes, and that is why again, you know, the chain is the design and the regulation around the drilling of the wells to limit the possibility of this happening. The second priority is the early containment. You know, a lot of the costs for BP were because it took time to design these. We can look at what it learned. Some of the things we are looking at, as I have said before, are finding and designing a piece of equipment that is able to go on any of the BOPS that are already in the North Sea, so that we can contain this in days and actually keep it within that limit. Q65 Dr Lee: Yes, it is somewhat surprising to me that you did not actually have contingencies in place that you knew worked prior to this. You know, what you are saying is, "Thank God we've had a spill in the Gulf of Mexico because now we know how to deal with it." If I adopted that approach in medicine, I would end up in court. So it surprises me that you — not you personally —drilled at that sort of depth and you did not actually know how to plug a hole if it did occur, and that makes me sort of wonder. I have been shown this grid —a high consequence probability grid —and it looks as if this sort of low probability, high consequence event is not really allowed for in the plans that I have seen. Do you think we need something more specific, for instance, for something as unlikely as we have seen in the Gulf of Mexico? Do you think we need something more specific —a plan for that type of incident? Mark McAllister: That is certainly a major element of the OSPRAG work —first of all, planning for an incident such as that, but also actually ensuring that an incident such as that does not happen. You know, we can talk about the industry in general's readiness for incidents such as this before Macondo. It is what it is, but actually as an industry, you know, we are working flat out with the regulator, with the coastguard agency, and with everybody else, to make sure that we learn every lesson. Q66 Dr Lee: But you would agree, though, that it is somewhat surprising to a layman that you have instituted as an industry drilling at such a depth without actually knowing how you would deal with it if there was a hole there? Malcolm Webb: I don't think that is quite true. Dr Lee: You know, they were sort of shoving old tyres down there and there was a sense it was almost like, "Oh God, what can we do next?" That is the impression the layman had, anyway. Albert Owen: Absolutely. Malcolm Webb: And I can quite appreciate that, but what I would say is that the industry was not wholly unprepared, and in the final analysis, of course, we know what to do with a blown well in order to kill it. You drill a relief well and you kill the well, and it is well known how we deal with that. I think what we can also say is that the technology is available to cap flowing wells as well. What I think maybe we saw in Macondo was a lack of preparedness in the industry to bring those solutions quickly into place. The solutions are there but they weren't brought quickly into place, and I think one of the works that OSPRAG is looking at —and OSPRAG is not alone in this; the industry around the world is looking at this as well — is how can we increase our industry preparedness to do that, as Mark said, within a matter of days. That is what we have got to do and it can be done. It is entirely achievable. This is not new engineering. It is not new science that is needed there. It is actually some good planning and procedures. Q67 Chair: Were Transocean actually operating the rig in Deepwater Horizon? Paul King. We were the drilling contractor; yes, we were. Q68 Chair: How many rigs have you got on the UK Continental Shelf? Paul King. We have 16 currently operating. Q69 Chair: At what sort of depths, drilling in deep water? Paul King. The Paul B Lloyd is working for BP west of Shetlands at the moment in up to 3,000 feet of water. Q70 Chair: One of the concerns I do not think we have mentioned so far is the sometimes possible difficulties of communication amongst people who are working on the rig. You have got a lot of different nationalities represented there and there may be linguistic problems in communicating. Is that an issue that you have thought about? Paul King. In the UK it is not as big an issue, or is not an issue that has raised concerns, compared to operations in South America, where the ex pat supervision does not necessarily speak Portuguese, but up here the primary requirement is that everybody speaks English and they can read English, and it is a predominantly UK workforce. Q71 Chair: And in the case of the Deepwater Horizon were there several different languages? Paul King. No, they were all Americans. In the Gulf of Mexico it is a requirement that they be Americans. Q72 Chair: Did the Deepwater Horizon rig have the same blowout preventer all the time? Paul King. As far as I am aware that is the case but I am not an expert on the Deepwater Horizon operation, since it operated in the Gulf of Mexico for its entire life. I have not actually operated the rig. Chair: No; sure. Okay. Q73 Albert Owen: What Mr Webb said there in response to Philip Lee I think was very interesting in the sense that he said there is no new science here. I know we have seen stories about tyres, but it is basically using mud and sand to cap this well. You know, Mr King, you do not really have to be an expert to think that that would be at hand very quickly if • E is Ev 12 Energy and Climate Change Committee: Evidence 7 September 2010 Paul King, Malcolm Webb and Mark McAllister there was a blowout of this nature. I think the difficulty the public are finding here is that if it is not new technology, are we ready for it? The simple process of getting natural elements like sand and mud close by, so that this would not happen again —is that in place close to your rigs in the North Sea? Paul King: From the standpoint of being able to drill a relief well? Or — Albert Owen: To prevent a blowout from happening. Paul King. You are obviously ensuring that you don't get into an uncontrolled well condition, and I think the intent and the requirement on board is that you have what we term "kill mud" on board and available to you. Q74 Albert Owen: What, sorry? Paul King. Kill mud. It is to kill the well, for example if you get a gas influx, an influx into the well, so that is a requirement operationally that the operator maintains throughout. Q75 Albert Owen: Sure, but what I don't understand is that was the early talk. When this happened first there was talk about doing this —putting sand, putting mud in —and all of a sudden a period of time elapsed and then they came back to that theory and resolved it. Mark McAllister. That biggest issue is engaging with the metalwork that is on the seabed. That is the biggest challenge that they had and I am sure you will be talking to BP about this in a couple of weeks' time. So plentiful supplies of the weighted mud and other materials to kill a well is part of what is on the rig all the time, and that is readily available to reinforce that. The issue is, having lost control of this well, how do you re-engage with it? That is why once again one of the key workflows of OSPRAG is, "Can we design a simple piece of equipment that is available to the entire industry and can, very, very quickly, engage with every conceivable configuration on the seabed that we can think of?" Q76 Christopher Pincher: Just following up on that, you talked about using best technology. As I understand it, you have hydraulic mechanisms to fire blind shear rams but they are slower than electronic mechanisms. So isn't it a simple thing to do to switch over to electronic mechanisms to fire your rams more quickly, if you need to? Paul King. There are operating standards that require these rams or operations sub -sea to be closed within a certain timeframe. In the shallow waters the hydraulically operated functions meet that requirement, and as you get into the deeper waters — obviously the time it takes a hydraulic signal to go down 12,000 feet, 5,000 or 6,000 feet, is a lot longer —it delays the initiation of the function. Therefore, the electronic multiplex, as we call it, systems are there so that when the button is pushed on the surface, less than two tenths of a second later the actual function is operating. Q77 Christopher Pincher: And they are available in all the deepwater wells off the UK? Paul King. Well, the multiplex systems are available actually for some of our shallow water operations as well. They were the pre -requirement for deepwater wells many years ago. They are used throughout our industry now. Q78 Chair: Rigs are leaving the Gulf of Mexico because of the US moratorium, is that right? So if we had a moratorium here, presumably the same thing would happen here as well. People would start looking for work elsewhere. Malcolm Webb: It must be a risk. Q79 Chair: But if we don't have a moratorium here and the Americans extended theirs, the opposite might apply. We might have more rigs operating here. Paul King: There is a barrier to entry to the UKCS inasmuch as that a safety case will have to be generated. It is a very thorough process that rigs have to go through to be able to operate on the UKCS. Q80 Chair: How long does it take? Paul King. A minimum of three to six months. Q81 Sir Robert Smith: Isn't it slightly the reality that whether rigs are used in the North Sea or not depends on the investment climate? Obviously, I suppose if there is a surplus of rigs, the price might drop, but the price took a long time to drop when the demand dropped the last time. And also isn't the sort of history in the North Sea that because of its maturity, as rigs leave, they just tend not to come back? Malcolm Webb: There has been a tendency for that, but I think you are quite right in your basic assumption that if we want to keep rigs drilling here in the UKCS then what is needed most of all is the right investment climate for that to happen. Q82 Dr Lee: Just a quick question. Does OSPRAG cover the Falklands? Mark McAllister: Not at the moment, no. Q83 Dr Lee: But is it under the same regulatory regime as UK Continental Shelf —the Falkland Islands? Malcolm Webb: No. Mark McAllister. No. Q84 Dr Lee: It is not. I just wondered in terms of access to facilities, if you have a big spill, the Argentinians are not going to be terribly helpful in this, not necessarily. Malcolm Webb: You caught me unawares with that. I am not — Dr Lee: I just read an article about the Falkland Islands and presumably it is UK territory. Malcolm Webb: I am afraid I parochially concern myself with the UK and not with the Falkland Islands. I don't know if it is a different regime and I am not quite sure what it is. Dr Lee: Fine. Q85 Sir Robert Smith: I remember Piper Alpha; I remember hearing it on the news while I was in my flat in Aberdeen and then hearing the helicopters going out all night. Is it worth maybe highlighting a bit more for the Committee what Lord Cullen did in • • Energy and Climate Change Committee: Evidence Ev 13 7 September 2010 Paul King, Malcolm Webb and Mark McAllister response to Piper Alpha and how that changed the culture so dramatically? Malcolm Webb: Well, it is thanks to him that we have this regime. That was where we saw the recommendations that came out of Cullen which called for the revision of responsibilities between the licensing regulation and safety regulation, and it was from that that the whole concept of the safety case came and the whole concept of independent verification and inspection as well. So it was a seminal moment and I think it has given the UK 20 years of safe operation. It was a tremendous step forward and I might say in those 20 years there has been nothing; there have been no blowouts in the UK. I know that is not a guarantee, looking back to that, but we have not had a blowout. We have not had any really uncontrolled escape of hydrocarbons in the North Sea. Yes, there are spills that have occurred through that period. I don't think in any one year the aggregate of spills of oil from the whole of our installations operating in the North Sea has reached three figures in tonnes. This is a very good record, I think, and, furthermore, I think what Cullen also did was spawn this new approach to safety and you see it exemplified in things such as Step Change in Safety where the industry is coming together and openly sharing difficult information about things that have gone wrong and sharing that within our industry and with the regulators too, as well. All of this is designed to inform the whole principle of ALARP; that is what the whole industry is determined to move forward to, and its regulators as well. So, yes, Piper Alpha was a deeply shocking event for the industry but the good that came out of it was the Cullen report and where it led us to after that. Q86 Chair: From what you said, that Cullen report clearly shaped the regulatory environment that has existed here for the last 20 years. Did it have any influence on regulators in other parts of the world? Malcolm Webb: I am not aware so. This may be an uninformed comment, but if one looks to the Gulf of Mexico and the US, it would seem that it had little impact there because not many of the Cullen recommendations seem to have been taken up in the United States of America. Q87 Chair: Do you find that surprising, given this is an international industry? In fact Piper Alpha was operated by an American company, was it not? Malcolm Webb: It was. It was Occidental. I go back to the point that was made before: I think, as an industry, if we can do something better, it is to make sure that we do not take maybe such an introverted view of our operations. We probably could do more to share information and expertise across international boundaries, and I think again, coming out of this, there are signs that that is happening too. In the United States there was a joint industry task group that was formed, I think somewhat similar to OSPRAG, to look at issues, but on top of that the Oil and Gas Producers, the international operation, has set up a Global Industry Response Group which is looking to make sure that it understands again the lessons from Macondo and that those are shared on a pan -industry basis around the globe. So the guys at OGP, I think, are looking to make just that sort of difference as well. Q88 Sir Robert Smith: Does OPITO, the oil and gas academy, try and promote standards? Malcolm Webb: Yes, OPITO, which is our oil and gas academy in the UK here, has been very instrumental in taking the safety culture from the UK and exporting it around the world, as well as some of our best safety practices, especially around the issue of emergency response and emergency evacuation. The OPITO BOSIET, or basic offshore safety induction training, and HUET, or helicopter evacuation training —which, by the way, anybody going offshore in the UK must have been trained in, along with further minimum industry training standards which we have just agreed through Step Change —are standards that are being exported and taken up readily around the globe and they are being exported by OPITO, which is doing very good work in an international arena too. Chair: Right. Has any colleague got any further points they wanted to raise? Okay. Well, thank you very much for your time this morning. It has been a very interesting and sometimes illuminating session, I think, for us. So we are grateful to you for coming in and I hope we shall produce a report sometime by the end of next month. Malcolm Webb: Thank you very much indeed. Paul King: Thank you. Mark McAllister. Thank you. 0 Ev 14 Energy and Climate Change Committee: Evidence Wednesday 15 September 2010 Members present: Mr Tim Yeo (Chair) Dan Byles Christopher Pincher Gemma Doyle Laura Sandys Tom Greatrex Sir Robert Smith Dr Philip Lee Dr Alan Whitehead Albert Owen Examination of Witnesses Witnesses: Dr Tony Hayward, Group Chief Executive, BP, Plc, Mr Bernard Looney, Managing Director, BP North Sea, and Mr Mark Bly, Group Head of Safety and Operations, BP, Plc. Q89 Chair: Good afternoon, and thank you for coming. Welcome to this session of the Energy and Climate Change Committee. As you know, this Committee's interest in this inquiry is particularly about the adequacy of the safety and environment regime in the UK and particularly as that relates to deepwater drilling in UK waters, for example, west of Shetland. We are also considering the contribution that deepwater oil and gas resources may make to meeting Britain's energy security needs and, indeed, also the extent to which we need to drill in deep water, given the hoped for transition to a low -carbon economy over the next couple of decades. But we have a particular interest naturally in BP because of the Deepwater Horizon disaster. We would like to try and understand better what lessons can be learned from what went wrong there and what changes in practice, procedures, training, possibly even in the regulatory regime here, may be needed in the light of that experience. That is particularly why we would like to talk to you this afternoon. But I think, Dr Hayward, you would like to make a short opening statement? Tony Hayward. Yes, if I can, Mr Chairman. Mr Chairman, ladies and gentlemen, good afternoon. Thank you for the opportunity to make this short statement to the Committee before answering the questions. There is much still to learn about the Deepwater Horizon accident and many investigations are ongoing. Throughout this crisis BP has received strong support from the UK Government, for which we are very grateful. We will answer all the questions we can, recognising that there are limitations to what we can say because of the large number of legal proceedings that are underway. To help provide the fullest answers possible, I have brought along Mark Bly, who led our internal investigation into the accident, and Bernard Looney, who is in charge of BP's operations in the North Sea. Let me begin by saying how much everyone at BP has been devastated by this terrible accident which so tragically cost the lives of 11 people and injured many others. I deeply regret what happened and its effects on the families of those involved as well as its impact on the communities and environment of the Gulf Coast. From the very beginning BP accepted that as the operator of the lease we were a responsible party and had the obligation to stop the spill, clean up the damage and compensate affected parties. I committed from the beginning that we would do the right thing and we would stay the course, and that has not changed. We also believed it right to make public all that we have learnt from this tragedy by sharing our internal investigation report and lessons we have learnt from spill response. I hope those reports can assist the industry as a whole, to improve both its safety and its ability to respond. The results of our investigation demonstrate that this was a very complex accident. It arose from an interlinked series of mechanical failures, human judgments, engineering design, operational implementation and team interfaces. No single factor caused the accident and multiple parties including BP, Halliburton and Transocean were involved. The report makes 26 specific recommendations. BP has accepted the recommendations. We've begun a programme to implement them across our worldwide drilling operations. I believe a good number of the recommendations are relevant to the oil industry more generally and would expect some of them to be widely adopted. It has been easy for some parties to suggest that this is a problem with BP. I emphatically do not believe that that is the case. The need to further mitigate risks associated with offshore drilling is an industry issue and one that I believe we all need to address. It is also tempting to call for universal drilling bans. I do not think that is wise, given the world's demand for oil and gas. It's worth recalling that prior to this accident the industry had drilled for more than 20 years in deep water without a major accident. Instead we should take a calm and rational approach to this, learning from what has happened and ensuring that the lessons are fully implemented across the world. In the offshore UK there are four strategic actions the Committee could consider: confirm that what we have is working as intended; build on lessons leamt from the Gulf of Mexico, ensuring they are applied across the industry; enhance testing protocols on blowout preventers including the backup systems; and enhance relief well planning. Ladies and gentlemen, thank you for the opportunity for those few words. We would now be very happy to take your questions. 0 • Energy and Climate Change Committee: Evidence Ev 15 15 September 2010 Dr Tony Hayward, Mr Bernard Looney and Mr Mark Bly Q90 Chair: When you were appointed chief executive three years ago you were quoted as saying you were going to focus, I think the term was, "laser -like" on safety. On your watch as chief executive in those three years we've had now perhaps the biggest ever oil spill in US waters —II deaths on Deepwater Horizon —and this morning's Financial Times says last year four out of five of your North Sea installations failed to comply with emergency regulation on oil spills, that the offshore inspection records seen by the Financial Times said that you've not complied with rules on regular training for offshore operators on how to respond to an incident. That's a failing which may be very relevant to what happened on Deepwater Horizon. It also says in the Financial Times that inspectors from the Department of Energy and Climate Change said you had failed to conduct oil spill exercises adequately. Given those circumstances, why should this Committee conclude that BP is a responsible company to operate deepwater wells in UK waters? Tony Hayward. Can I address that question in two parts, Mr Chairman? First, in terms of what we've done over the last three and a half years, we have made safe, reliable operations the No. 1 priority at BP. It is the priority of everyone at BP. But of course it's about much more than rhetoric. It's about what you do underneath the banner of safe and reliable operations. Safety is about three things. It's about plant, people and process. Over the last three years we have invested more than $14 billion into the integrity of our operating plant globally. Over that same period of time we have established a safety and operations integrity group. We have recruited broadly from outside of the industry —from the nuclear industry, from the petrochemicals industry. We have recruited thousands of engineers into our operations and we have established new processes across the company, including a new operating management system designed to ensure that everywhere our operations are safe. And it is undeniably the fact that because of all of that this particular incident is so devastating to me personally, because we have made an enormous amount of progress in that three-year period. If I can take now the question of the North Sea, we take all safety issues very seriously. I do not believe that the issues that were reported this morning point to any fundamental weakness in our North Sea operations. We have a very strong track record in the North Sea. It is better than the industry average. We have seen major improvements in the course of the last two years. BP's spills, which are a good indicator of safety performance in terms of integrity of plant, have fallen by 20% over the last two years and we now lead the industry in terms of that particular metric in the North Sea. I will ask Mr Looney to comment on the North Sea, if that would be helpful, but I do think there was some commentary this afternoon from DECC which said that nothing that they identified compromised the overall integrity of the installation or its pollution response provision, and they use the letters as evidence of a robust environmental regulatory system in action. Bernard Looney. As Tony said, we take any observations like this from the regulators very, very seriously, obviously. We view it as an opportunity to improve our business. Specifically in these two areas that you mentioned, the first being training, it is true that there were a handful of people, less than 10, who had not undergone mostly refresher training, which is a one to two-hour computer -based training exercise. It was an administrative error. Clearly, today, all of our people are compliant with that training requirement and beyond that we have taken action to make sure that that administrative error doesn't recur. So that's the first thing. The second point you raised was in the matter of drills or how we practise for spill response. We had been carrying out and continue to carry out exercises as to how we would respond if there were a spill or an incident in the North Sea. I think it is fair to say that there was some confusion within industry as to what was exactly required within the drills. I think it is reasonable to say that that confusion was recognised by the regulator, and in August of this year the regulator issued clarification guidance on what exactly should be carried out when those exercises are undertaken. Clearly today we are in full compliance with what is required of us under the law. Q91 Chair: In the efforts you've been making on safety in the last three years, was your decision to have only one blind shear ram on the Deepwater Horizon, despite reports for the US Minerals Management Service suggesting that rigs needed two some years earlier, taken to save money by reducing the time it took to conduct well tests and therefore allow longer periods for drilling? Tony Hayward. We have found no evidence in our assessment and investigation of this accident to suggest that cost was any part of how this occurred. The blowout preventer that you are referring to was fully compliant with the regulatory regime and it should have functioned. Clearly the fact that it didn't function is something that the industry needs to understand and ensure that the right actions are taken to ensure that equipment operates as it is designed to. There was nothing wrong with the design basis of the blowout preventer or the use to which it was being put. The fact is that it failed to operate as it was designed to. Q92 Chair: The question was, was the decision to have only one taken to save money by BP? Tony Hayward. There was no decision of that sort taken to save money. Q93 Chair: Just six days before the explosion why did your staff describe the Macondo well as, I quote, "a nightmare well that has everyone all over the place"? Tony Hayward. There is no doubt that there had been some not unusual drilling challenges in drilling the Macondo well. They had had to deal with a gas influx at a higher elevation. I think the description is unfortunate, made by one of our young drilling engineers, but certainly the well had been • E 0 Ev 16 Energy and Climate Change Committee: Evidence 15 September 2010 Dr Tony Hayward, Mr Bernard Looney and Mr Mark Bly challenging —not unusually so in the context of the Gulf of Mexico. Q94 Chair: You mean the Gulf of Mexico is full of "nightmare wells"? Tony Hayward. The Gulf of Mexico is a more challenging drilling environment than many other parts of the world. Q95 Chair: Is it more challenging than the west of Shetlands? Tony Hayward. Undoubtedly so. Q96 Sir Robert Smith: I just wanted to follow up on the working of the blowout preventer in terms of performing to standard because my understanding is that it should fail-safe, yet one of the batteries was flat and that didn't seem to fail in a safe mode. It just meant that the thing wouldn't operate. Is that a misunderstanding? Tony Hayward. Well, there are three modes for operation of the blowout preventer. The first is when the rig is connected to the blowout preventer operated from the surface. If the rig becomes disconnected from the blowout preventer, then the so-called "deadman" function should activate the blowout preventer which requires the control panels on the blowout preventer to activate the blowout preventer. The third mechanism of activating the blowout preventer is through, effectively, in essence, manual intervention —the intervention of the ROV on the blowout preventer itself. In the case of this accident all three mechanisms failed. Q97 Dan Byles: I would just like to explore a little bit more the concerns some people have that perhaps some operational decisions might have been influenced by financial considerations. On the day of the blowout the well was 43 days late and somewhere in the region of £21 million beyond budget, and there do seem to be a series of decisions. Tim's alluded to the single blind shear ram which was contrary to recommendations by the US Minerals Management Service. I understand that only six centralisers were used rather than the recommended 21 that Halliburton had recommended. There was the decision to install a single long -string casing rather than multiple individual casings, contrary to your own internal plan review in April and the decision not to run a cement bond log. Now, obviously these are all individual operational decisions. But when you start to look at them together, it gives the impression that perhaps corners were being cut. I would like your thoughts on that. Tony Hayward. Yes. If I can, without going too technical, I'd like to address each one of those issues in turn because I think it is important that we understand what did and did not cause this accident. Q98 Dan Byles: Well, to a certain extent it doesn't really matter if any of those caused the accident. It's more about the principle that in each of these cases there is a recommended approach and the approach taken by BP appears to fall short of the recommended approach. Tony Hayward. Let's just take those one at a time, if we can. So, in the matter of the long -string, running a long -string had nothing to do with this accident. The flow was up the production casing; it was not round the side. So the long -string was not a cause of the accident. The decision to run the long -string was actually based on long-term integrity. If you use a liner with a tieback, where the tieback connects to the rest of the casing is subject, over time, to degradation and can leak, and we have lots of examples of exactly that occurring in the Gulf of Mexico. So the practice of the majority of the industry today is to run long -strings to avoid the possibility of degradation between the tieback and the rest of the casing. That is why the decision to run the long -string was taken. The decision not to run a cement bond log was because they believed that they had demonstrated the cement job had been effective. So the procedure in drilling a well is: run the casing, pump the cement, conduct a positive test. Will flow go into the formation? Then conduct a negative test. Will flow come out of the formation? Now, we know with the benefit of hindsight that the negative test was erroneously interpreted, but they believed that it was good and therefore they had a good cement job and there was no need to run a cement bond log. A cement bond log is used to determine where you have a cement problem rather than whether or not a cement job is good, because it can't determine pinprick holes in the cement. So what would typically happen is that, if they had identified correctly that the negative pressure test was wrong and we didn't have a seal, it's very likely that they would have then run the cement bond log to try and determine where additional cement needed to be placed. Q99 Dan Byles: So if your quality control systems — the test —erroneously suggested that they were okay but actually the problem was with the cement, could that problem currently exist on any of your other wells without you being aware of it? Tony Hayward. Well, we clearly have taken a lot of action, as I suspect others in the industry have, to clarify and provide much greater rigour around the assessment of a negative pressure test. At BP we've been very prescriptive about what does and does not constitute a negative pressure test, and we have elevated the authority to say that it is acceptable off the rig to the shore in the event that there is any ambiguity. Q100 Dan Byles: I shall ask one more focal question, if I may. Do you apply the same safety standards to all of your operations worldwide or do you apply the minimum required by the local regulatory regime? Tony Hayward. We apply the same standards. They are clearly influenced by variations in regulatory regime. Q101 Dan Byles: So you would say the standards applied in your current operations in the UK are to the same standard as the standards you were applying in this incident in the Gulf of Mexico? E • Energy and Climate Change Committee: Evidence Ev 17 15 September 2010 Dr Tony Hayward, Mr Bernard Looney and Mr Mark Bly Tony Hayward: The standards in the UK are very strongly influenced by the safety regulations that exist in the UK, which at some point we may wish to discuss. So the standards in the UK are very much driven by the safety regulations here, which, as you probably appreciate, are very different from those in the US. Q102 Dan Byles: So would you say therefore that you are operating lower standards in the US than you do in the UK because the local regulatory regime allowed it? Tony Hayward: I don't think they are lower standards. I think we have the same standards, but there are differences in the regulatory regime, which does not imply a difference in the level of standard but there are different requirements. Q103 Albert Owen: You have given very detailed technical answers and I understand why. But in your opening remarks you talked about one of the faults being human judgment. We had before us last week the managing director from Transocean, Paul King, who said there was a chain of command within his part of the company and he couldn't comment because the Bly Report hadn't come out then with the details, but he said there was a time-out. When in any doubt, there's a time-out period. Are you suggesting that there were calls for time-out that had been neglected, when you get a young driller saying it's a nightmare scenario there? I mean, you say he's a young driller, but he's trained. He's aware of the dangers there. Are we led to believe that when a time-out is called it happens on each and every occasion even when you're late, even when those pressures are on, and has the report identified anything different? Tony Hayward: Categorically the answer to that is yes. When anyone at any level in a drilling operation on a drilling facility calls a time-out, time-out occurs. There is absolutely no evidence from our investigation that anyone at any moment in time called a time-out. In the matter of the negative pressure test, which is one of eight critical factors, the BP well site leader required it to be taken again and it was taken again. The conclusion of the team on the rig was that they had a good test and could therefore proceed. Q104 Albert Owen: Sure, but I don't understand — when there's been talk about a battery being flat, surely that would have been tested and somebody would have said, "Time-out. We can't go any further"? Tony Hayward: Well, of course the battery that was flat was in the blowout preventer at 5,000 feet down on the seabed. Q105 Albert Owen: So there's no way of testing it? Tony Hayward. Well, the last time it would have been tested was prior to being put on the seabed. Now, what we haven't determined is exactly what was tested at the time that the blowout preventer was last put on the seabed. Q106 Albert Owen: But you will be having a fuller inquiry into that? Tony Hayward: Absolutely. Q107 Chair: So there could be flat batteries all over the place? Albert Owen: That's the worry. Tony Hayward. So what we have done —and I am sure everyone in the industry has done the same —as soon as these things came to light, not waiting for the report but as soon as they came to light, is we have implemented across our global drilling operation a programme to ensure that the equipment will do what it is designed to do. In a number of cases that has required us to halt drilling in the middle of a well and bring the blowout preventer to the surface. We have done that a couple of times in the North Sea because we weren't certain. We subsequently confirmed that they were perfectly okay and we continued. So the first thing we've done is confirm absolutely that everything that we have operational today is working as it was designed to. The second thing we have done, which I believe is something the industry will also do, is significantly enhance the testing protocols of blowout preventers, including ensuring that the backup systems work and are tested in the course of drilling the well. Previous to this they were only tested at the end of each well. We've actually introduced the additional safeguard of ensuring that the backup systems are tested on a regular basis through the course of drilling the well. Q108 Christopher Pincher: I'd like to come back to the cement item that Dan Byles raised. Halliburton provides your cement slurry. Halliburton are quoted as saying that they are confident the work was completed on the well meeting BP's specifications, whereas you, I think, have said that it was a bad cement job, though BP, and presumably anybody else in your position, are responsible for signing off on that cement. So I wonder what you are doing new or differently to ensure that what you do sign off on from other providers you are happy with. Tony Hayward: Well, the first thing I would say is, of course, we know the cement was not good because we had influx into the well. So there is no doubt that this was not a good cement job. Exactly why it wasn't is not clear today. We have not been able to complete the investigation in that area because we haven't had access to samples of the cement. What we have done is as recommended. Q109 Christopher Pincher: But you've simulated that, haven't you? Tony Hayward: We have simulated it, but we haven't actually got a sample. So I think we need to be cautious until we can complete that analysis to understand why the cement failed. Notwithstanding that, what we've done is to require that all cement contractors have third -party verification of their standards and procedures, the cement formulas — everything around the cement. Q110 Christopher Pincher: Is this a new requirement or a requirement you already have? Tony Hayward: It's an enhancement to our previous procedures. • • • Ev 18 Energy and Climate Change Committee: Evidence 15 September 2010 Dr Tony Hayward, Mr Bernard Looney and Mr Mark Bly Q111 Christopher Pincher: So who are the third parties that you're going to employ that can verify that the mixture is correct? Tony Hayward. They are cement engineers, in essence. Q112 Sir Robert Smith: I should remind the Committee and the witnesses of my entry in the Register of Members' Interests as a shareholder in Shell and as vice -chair of the all -party group on the offshore oil and gas industry. I just wanted to follow up on your lessons learnt and the recommendations. There's quite a lot about how you need to beef up or change the conditions you apply to those providing services to you —to those who contract to you. I just wondered about that in terms of how the industry has evolved because a lot of things that used to be inhouse for big major oil companies are now provided outside, and as the industry evolves there are a lot of smaller operators buying a lot more services from integrated providers. Are there bigger lessons the industry needs to learn about how to cascade the same safety culture throughout the contracting supply chain? Tony Hayward. I think it would be surprising, given the nature and gravity of this accident, if many in the industry did not look afresh at the relationships between themselves and their principal contractors. I know BP will. I think it's too early to conclude exactly what the changes will be. In our report we talk about "significantly greater oversight". It is possible it may go beyond that. It's possible that some of the things may come back into BP, but I think we need to be quite thoughtful about doing that. The reason the industry evolved in the way it did —and drilling goes back probably 25 to 30 years —is the idea of creating deep skills and competency in a narrow space. We need to be certain that if we bring things back in we've actually legitimately reduced the risk. So I think the industry will look very hard at the nature of relationships between operators and contractors in a number of dimensions in the light of this tragedy and it will be for participants to determine. All I can tell you is that it's something that BP will be doing. Q113 Laura Sandys: Just to follow on in some ways from what we have already been discussing, having read the summary and some of the substance of the Bly Report, I was interested in the fact that it was obviously looking very much at the technical side. But a lot of the issues surrounding health and safety and also engineering solutions are really management — and possibly risk assessment —issues. There was very little reference to anything to do with, as Robert said, the management of contractors, common standards and how you manage risk assessment. From your report that you then submitted to this Committee, you are saying that you are now looking at the North Sea in particular with subsea blowout preventers. But are you doing more than that? Are you looking at those management structures? Are you looking at your risk assessment in relation to all your international deepsea drilling activities, because it just struck me that, yes, fine, you can always look at the technology and you can always look at the engineering, but ultimately it's people, companies and, ultimately, shareholders who end up being responsible? Tony Hayward: I think, in defence of Mark, the investigation was asked to understand what happened and to make recommendations relevant to the immediate course. What BP is clearly looking at is as you have suggested. I think the issue is the management of low -probability, high -impact risk. This risk was identified at the very top of the BP group risk register. It was identified as a principal risk in the exploration and production business. It was the principal risk in the Gulf of Mexico business and yet it still crystallised. So we clearly have to ask ourselves what more can be done in the general question of the management of very low -probability, high -impact risk. We have to keep reminding ourselves that the industry had drilled for 20 years in deepwater without a blowout, and we believe that we mitigated the risk through all of the actions that we'd taken and we clearly hadn't. Q114 Laura Sandys: Then if we can move the risk assessment to the North Sea, what is your prime risk issue when you are looking at your operations in the North Sea? Tony Haywadrd. Can I just make a couple of comments on the North Sea generically? Bernard can clearly go into detail. I do think that it's important that, whilst all of the lessons learnt need to be applied to the North Sea, we do recognise that there are some quite important differences. The first one is that there is nowhere where we are drilling in deepwater and the reservoirs have high pressures and high temperatures. So the high-pressure, high -temperature area of the North Sea occurs in shallow water. It's in the central North Sea offshore from Aberdeen. In the deepwaters of the west of Shetlands there is no high pressure and high temperature, which means it's a very different thing; it's a very different engineering challenge. I think the second thing is the strength of the regulatory regime here. The North Sea had its own disaster with Piper Alpha 20 years ago and as a consequence of that the safety and regulatory regime was fundamentally changed. The Cullen Report, I believe, has provided the foundation for an extraordinarily good safety performance over the last 20 years. I think those are two quite important differences. Q115 Laura Sandys: But what is your priority in the North Sea when it comes to risk? Bernard Looney. The priority in the North Sea is very, very clear. It is the No. 1 thing. If you come into our office you will see it on the walls and screens; you will talk to people; you will hear them talk about it. The No. 1 priority is and has been, certainly in my tenure, the reduction of hydrocarbon releases. The reason for that being the No. 1 priority —not just in risk or in safety or in business; it is the priority in the business —is, as we have seen in the Gulf of Mexico, that the consequences of it going wrong are significant. For that reason we have focused very, very heavily on that priority in the last several years. The first thing is actually to declare that it is the most important thing. We have done a lot of work on • is is Energy and Climate Change Committee: Evidence Ev 19 15 September 2010 Dr Tony Hayward, Mr Bernard Looney and Mr Mark Bly education in this space in helping our workforce. There's a facility in the UK which actually helps people see what happens physically in an explosion at Speedam and it helps people actually understand the strength of what can happen. So we've had people, safety reps, go to that. We've invested in maintenance and inspection in our facilities to improve the integrity of our facilities and I am pleased to say that, while we must never stop in this space, we have made improvement. We've made significant improvement in the last two years and that track record continues this year. So the priority in our business is very clearly, No.l, the reduction of hydrocarbon releases. It is the thing that I frankly worry about first in the morning and last in the evening because it is the thing that when it goes wrong people can lose their lives and that's why we, and 1, focus so much on it. Q116 Gemma Doyle: The report seems to state that the drill pipe pressure was increasing when it should have been decreasing for round about 50 minutes but no action was taken. Can you say how often those readings should have been observed and what should have happened in that situation? Tony Hayward: Well, let me start, but I'm going to ask Mark to add something. The primary measurement in a drilling operation is two things: it's the pressure on the drill pipe and the volume of mud. Those are the two most important parameters that are monitored and measured on a continuous basis. Is the volume of mud increasing or decreasing? If it's increasing it tells you something is flowing into the well, and if it's decreasing it tells you the mud is flowing into the formation. And, similarly with pressure, if it's going up then there's something happening deep in the well. They are monitored on a continuous basis on a display in the driller's control unit. Mark Bly. Just to add, in addition to that there is another surge provided on the drilling rig which is called the mud lying service. This service also monitors those parameters to provide a redundant set of eyes on the data. So it was indeed an important finding in the investigation that the influx into this well occurred over several tens of minutes leading up to the explosion and it's just counter to what you expect to see. The fundamental practice in the industry is early detection and early action and for some reason that wasn't accomplished here. Q117 Gemma Doyle: So do you have concerns that the equipment wasn't functioning correctly? Mark Bly: What the report really has been able to do is identify that the signs were not caught —that some of the equipment was available to the driller. We can't say that it all was at all times, but we know that some of it was because we captured that with real-time data. There are records of the information that would have been available, so we know that that was there. We can't explain why they didn't see it. Q118 Christopher Pincher: Can I ask then, given that the data was available but no action was taken for, as you describe it, tens of minutes —I think it was up to 40 minutes —do you have concerns about the training of your resources if they didn't potentially spot what was going on, and what you are doing to rectify that as a possibility? Mark Bly: The recommendations that we've made are to consider enhanced training. There is industry standard training, and for all of the people that were close to this we confirmed that they were up to date and they had all the appropriate training. The recommendation that we've made to the company is that we should consider superseding that and going further with training competency. Then the other thing we've recommended, and this is almost something that you could take for granted because it's such a common practice in the industry, is we've said, "Let's go back and absolutely define what are our minimum requirements for well monitoring, equipment, equipment redundancy, etc." So while we couldn't get right to the bottom of it, we've sort of stepped back and made a recommendation to go and just seek to make it more robust anyway. Gemma Doyle: Sorry, I should mention that I have a family member who works for BP, although not in this part of your business. So I need to declare that. Q119 Dr Lee: You've already mentioned that Mr Bly was told to deal with immediate findings in the immediate period after the accident took place. Looking at your report, Mr Bly, there doesn't appear to be a root cause analysis. I can't see any evidence of that and I wonder why that was the case. Mark Bly: As Tony said, our objective was to understand, as quickly as we could, the sequence of events, remembering that at the time it was a horrific incident to look at. We were trying to understand what were the chain of events that happened and what were the immediate causes so that we could get to some insights as quickly as possible. That's what we've done. I think it's a good contribution to developing understanding and it's the case that there may be more to do —maybe make it commonplace. Q120 Dr Lee: Okay, but on the basis of that, though, does BP as a whole have any sort of indicative feelings that there is one thread of causality through all of this or is it a series of threads? Mark Bly: I think it's important to consider all of the eight things we've identified and recognise that any one of those, had the barrier remained in place, could have prevented or significantly reduced the impact of the incident. So there is a way to think about each of those and how would you strengthen them. The recommendations that we've made are targeted at exactly that —at thinking through what steps would you take. They range from consideration of engineering design, through consideration of improved standards of practices and proceduralisation of the things, to consideration, in cases where we are buying in or acquiring services from contractors, of how we up our game in ensuring that we get absolute quality there. So those are the broad themes that we went after in the recommendations. Q121 Dr Lee: I guess what I am trying to get at is that Dr Hayward inherited a pretty tough situation with regards to the safety record. When you were r1 is Ev 20 Energy and Climate Change Committee: Evidence 15 September 2010 Dr Tony Hayward, Mr Bernard Looney and Mr Mark Bly appointed you mentioned that straightaway, and we have seen it on the front page of the FT today. Do you think you are still dealing with that legacy of a lax safety culture that the Baker Report of the Texas City Refinery explosion indicated? Do you think that what we are seeing here is that you are still working through that and, dare I say it, is there some sort of institutional issue here? It's interesting to know what you think. Tony Hayward: I think it's very dangerous to join up dots that it may not be appropriate to join up. I don't think we've got any evidence here of the sort of issues that we were confronted with at Texas City. What we do have, and I think it is very clear, is a lack of rigour and the quality of oversight of a contractor. Now, the contractors we are using here are of world class, world standard, and you may not expect that they would need that quality of oversight. But it is clearly something that was found wanting, it's something that the report makes strong recommendations around and it's something that we've already taken action on. Clearly, we wait for the report to be published to begin taking action around the extent of the oversight that we apply in our drilling operations, be it in the cementing area or in the overall drilling area, and 1 think that is a legitimate concern. But I don't believe that that ties back to the issues that we had at Texas City. Q122 Dr Lee: But you do intend to do a root cause analysis at some point in a later report? Is that planned? Mark Bly: This report satisfied our terms of reference that we were asked to do. I have given it, provided it to the company and it will be thought about. Q123 Dr Lee: Bringing it closer to home, in view of what happened in Macondo, were detailed plans in place to handle a failure at a subsea wellhead here prior to the incident in the Gulf of Mexico? Tony Hayward: I think it is evident, and we have certainly acknowledged it, that the industry was not prepared to deal with a subsea blowout in 5,000 feet of water. The reason we were not prepared is that we believed we had effectively mitigated that risk such that it was not going to occur. Now, that probably was not the right conclusion on the part of the industry, with the benefit of hindsight. So over the course of the last four or five months we have built an enormous amount of capability, as you have seen in the Gulf of Mexico, to be able to intervene in the subsea environment through the creation of a whole series of essentially capping mechanisms that would allow you to cut away any debris, put a cap on a blowing out well and contain it. What we are doing for the North Sea is that we are, as we speak, shipping two of those capping structures across to the UK to be based in Southampton at the Oil Spill Response Centre as the beginning of creating the capability to be able to intervene if such a situation did occur. Now, that doesn't mean to say there is no lack of focus on mitigating that risk and ensuring it doesn't occur, but I think, as our industry colleagues described to you last week, the industry in the UK is moving forward to create capability to deal with a subsea blowout. The first step of that is, as I have said, to bring two of the multipurpose capping pieces of equipment to the UK to be based in Southampton with the Oil Spill Response Centre. Q124 Dr Lee: I have one final question with regards to the sort of day-to-day management of a functioning rig. I am a practising medical doctor, so I speak from a position that, in my profession, whistle -blowing is difficult. It's got a track record in the NHS where there is no particular system in place. So it's something which we are having to address as a profession. It strikes me that most people, if not all people, on the rigs are under contract. It may be directly or indirectly to BP or whichever company it is. Do you think that that is a problem in terms of reporting concerns? There are people who understand that we need to be drilling because of the need for oil etc., but do you think that perhaps for the sake of the industry's reputation there is some sense in having an independent person on the rig who says, "Look, I'm not happy about this"? At the moment potentially there is a conflict of interest —people are under pressure; there are contracts, money etc. Tony Hayward: I think there are lots of things that could be done, but I do want to stress again that we found no evidence of anyone being under any pressure to do something they didn't want to do. Perhaps more importantly, the offshore installation manager of the Deepwater Horizon testified under oath at the Marine Board. He is the ultimate authority on the rig. He said that at no time had he felt he was under any pressure to reduce costs or to go quickly. If he had been, he would have told whoever was trying to do it to please desist because as far as he was concerned he was the accountable person and he made certain that those pressures did not apply on his facility. So I think, whilst it's tempting to believe that this was causal somehow in this accident, there is no evidence for that whatsoever. Q125 Dr Lee: I am not suggesting that it is. I am just suggesting that maybe in terms of management of reputation of the industry and individual companies it might be something worth considering. Bernard Looney: If I could add just a comment on that, just to help you understand what is in place in the UK today in the North Sea. There are two things, both of which are legislative requirements. The first is the requirement to have a group of people offshore known as safety representatives who are volunteers. It is a legislative requirement. Their job is as much independence as anything else. In fact when I go offshore to a facility, as I do often, I meet with them independent of the management of the facility to understand if they have issues with the management of the facility —if they have issues that they want to bring to my attention. That exists today. The other thing that you'll see when you travel to an offshore installation is that people are encouraged, and there are posters around the place, to have direct access to a hotline in the Health and Safety Executive should they wish to raise concerns, and people do use that facility. So they are the things that are in place today. I am not saying it doesn't need to be enhanced further, • • Energy and Climate Change Committee: Evidence Ev 21 15 September 2010 Dr Tony Hayward, Mr Bernard Looney and Mr Mark Bly but I just wanted to make sure that you understood what was in place in the North Sea today. Maybe it's something we need to do more of, but that is in place today. Q126 Laura Sandys: It worried me a little bit what you said, Dr Hayward, that you had already assessed that there could not be any deepwater hydrocarbon spillage, i.e. you didn't have a response mechanism or a recovery mechanism in place. What I am concerned about, and I have seen it in operations in the caucuses to do with pipelines etc, is where there is a presumption there isn't a risk because in some ways we haven't had a disaster in relation to that risk. I think it's very, very important that we learn the lessons from Mexico, but that these aren't the only lessons that one learns. It's important that you start opening up a lot more on potential risk and that you revisit some of the risks that you have now declared are totally safe because not only are we talking about a changing globe, but you are operating in different areas. So I would very much urge the industry to look again and not to dismiss something because it's never happened or we believe that we have the technical capacity. These disasters, in my view, could start to increase around the world and not decrease due to all sorts of seismic issues. Tony Hayward: I agree with you completely. I'm sorry if you interpreted what I said to mean that. Q127 Laura Sandys: No, but in the past one has said either, "We have a technical solution for this so therefore it's no longer a problem", or "It hasn't happened, so therefore it's not a problem." Tony Hayward. Like I say, I completely agree with you and I think the occurrence of black swans seems to be more often than not these days. So I think, you know, certainly at BP —I can only talk for BP of course —we are looking very carefully across our company at the low -probability, high -impact risks that we believe we've effectively mitigated to understand not just the extent of the mitigation but what is the quality of the contingency plan should the risk crystallise and you have to deal with it. Laura Sandys: And that would be particularly interesting, obviously, in relation to the North Sea and any other future projects you have. Q128 Sir Robert Smith: The capping technology was an impressive emergency response and a major subsea engineering feat. But is it the right lesson? Would the lesson be not to have blowout preventers that really do mitigate the risk and really do operate as a fail-safe so that you don't have to have the capping technology? Tony Hayward. Of course it's far better to mitigate than to have to deal with it should it arise. That is of course the right approach. You have seen in our report and you've heard what I've said about the actions we've taken on blowout preventers as they exist today. I would expect that further changes will be made to blowout preventers as the industry moves forward to further insure against any failing. Q129 Chair: Just on the blowout preventer, at page 48 of the report you identified three options as to why the blowout preventer didn't shut the well. The third one, I think, suggests that the bottomhole assembly was parched at the same place as the blowout preventer and that's why it didn't operate. Is that likely? Tony Hayward. Let me ask Mr Bly to comment on that. Mark Bly: Yes. This was one explanation for one of the reasons that the blind shears didn't work. What this stems back to, we know, or we strongly believe, is that during the ROV intervention activity they did take an action that managed to close the shear rams, but it did not stop the flow from the well. At the time the report was written, and still today, we could not determine the specific reason for that failure mechanism, and so these three were identified as the most likely possibilities. This is one that we may learn more about, though, as the equipment is taken out and forensically de -constructed. This is one part that there may be more information on. Q130 Tom Greatrex: I apologise to Dr Hayward and the Committee for my late arrival. I just wanted to go back to the point you were making about people feeling under pressure. In the context of the North Sea, are you confident that health and safety reps and other people aren't experiencing that pressure when they are working for you either directly or as contractors? Tony Hayward. I don't believe we have any evidence of it at all, but let me ask Bernard to comment. Bernard Looney. I think people are clear in our priorities in the North Sea. I have spoken about what the priority in our business is. I have seen no evidence of that in my time in the role. It's important, obviously, first that people feel that they can stop a job if pressure happening and, secondly, that they do not feel under any pressure that they can't say something to somebody. As I say, when I go offshore, I test, and the way 1 test it is that I talk, independent of the management of that facility, to the people who are volunteering their time to be safety representatives. I sit down with them and these are exactly the questions that I ask them because that is at the root of a good safety culture, or the absence of it is, as you suggest, at the root of a not -so -good safety culture. I haven't seen any evidence of that and if I did I would take action because it's unacceptable. Q131 Tom Greatrex: I suspect that I am sure, even when you are talking to people independently, they would probably have an idea of who you are and maybe perhaps their responses may be slightly different on other occasions. Going back to this point about the safety reps and the consistency —because I read, as other Committee members have read, various bits and I accept there are parts of reports from the HSE and other bodies that get amplified in the media —how do you ensure or how can you ensure that there is consistency of that approach across the whole of the company and for your contractors as well, and that that safety regime is at the heart of everything? • • • Ev 22 Energy and Climate Change Committee: Evidence 15 September 2010 Dr Tony Hayward, Mr Bernard Looney and Mr Mark Bly Tony Hayward. Well, I think the first thing is ensuring that the management walk the talk. As we discussed earlier, that is not only saying it but doing it, and that's about investing in safety. So safety has the first call on every dollar that BP invests. Before we invest in anything else, we invest in safety. It's about making certain that we have the right people with the right skills and capabilities, and then, as Bernard says, it is about creating the right environment so that people feel they can speak up and raise their hand if there is something that they are not happy about with respect to safety. We were discussing before you joined us that over the last four years we have implemented across BP a common operating management system which is designed to ensure that all of our operations are conducted to the same high standard and there is the same look and feel to the safety of those operations everywhere in the world. Q132 Tom Greatrex: Can I just ask finally, because others wish to get in, do you operate NRB on your rigs and your installations in the North Sea —"not required back"? Bernard Looney. Not required back. We are fully compliant with the agreement that Oil and Gas UK as a trade association has with the unions and the workforce and we have no issues with that policy. We fully support it and it's wholly in place in our operations today. Q133 Dan Byles: You referred to the fact that you have moved these two structures to the UK, which now gives, presumably, an ad hoc capability effectively to respond should there be an incident in UK waters. How long do you think it would be before we could have confidence that the industry in the UK has a routine robust procedure and plan in place to deal promptly with a blowout in deep water in the UK? Tony Hayward. The plan is to build that capability over the next six months initially and then to continue to review what might be appropriate over a longer time period. Q134 Chair: Just coming above ground for a bit and moving away from the technical stuff, looking back over the last five months, are there any aspects of the public relations handling that you regret? Tony Hayward. I think there are probably many things that I would do differently if I had the opportunity to do them again, but I think it's also important that we all understand that, given the scale of this tragedy and the enormity of the disaster, the emotion and anger in the United States was very high, and quite understandably so. Therefore it made the whole public relations area extraordinarily difficult. Q135 Chair: Do you consider you were fairly treated by the authorities in the United States? Tony Hayward. As I said, I think there was an enormous amount of emotion and anger and it was very understandable. Q136 Chair: That answer suggests you think you were not fairly treated. Tony Hayward. It was a terrible tragedy that was causing immense stress and distress to many thousands of people. Q137 Chair: So the reaction from the Administration was proportionate to the incident? Tony Hayward. I think the reaction was entirely understandable and I would also like to be very clear that BP had an extraordinarily constructive relationship with the Government of the United States across many different branches of government and mounted in co-operation and co-ordination with the US Government the largest spill response ever seen by probably two orders of magnitude. Others in history will be able to determine how effective that was, but it was undoubtedly the largest response of its kind ever seen and that required tremendously close co-operation between ourselves and the various arms of the US Government. Q138 Chair: Roughly how many countries round the world does BP operate in? Tony Hayward. In our exploration and production business, around 30. Q139 Chair: In any of those countries apart from the United States, has the Government attempted to intervene with your dividend policy? Tony Hayward. I think it's important to be clear that the United States Government didn't interfere with our dividend policy. Our decision to suspend the dividend was a decision taken by the board of BP at a time at the height of the crisis when our financial liabilities were very, very unclear and extreme financial prudence was warranted to preserve long-term shareholder value. It was a very painful decision for all of those who were involved in taking it. It clearly created an enormous amount of pain short term for our shareholders and pensionees, but it was taken by the board of BP in the interests of preserving the financial strength of BP and the long-term interests of the shareholder. Q140 Chair: And the board of BP was not influenced in any way by the comments of the President or the Congress? Tony Hayward. It was nothing to do with what the Congress said. It was all to do with looking at the liabilities that we could see coming towards us and ensuring that the company's balance sheet remained strong and robust and we were able to deal with everything that we could see coming. Q141 Chair: Would you say in the light of that experience that there is now a degree of political risk attached to operating in the United States? Tony Hayward. I think there is political risk attached to operating in most jurisdictions of one sort or another. Q142 Chair: But many people would say that — I don't know —Nigeria or somewhere might be riskier than the US. Tony Hayward. I think that is probably a fair assessment. • 0 • Energy and Climate Change Committee: Evidence Ev 23 15 September 2010 Dr Tony Hayward, Mr Bernard Looney and Mr Mark Bly Q143 Chair: Even now? Tony Hayward: Even now. Q144 Albert Owen: Just on this point, in response to the Chair, you were careful in your response about how you've been treated by the press. Do you think you have been treated by the British press fairly? I will put it to you that only last week, when the Bly Report was produced, most of the headlines were saying that BP was abdicating its responsibility and blaming everybody else but BP. How do you respond to that? Tony Hayward. I think the Bly Report stands on its face. It's a very factual, thorough and rigorous report. I believe it will provide the foundation for many of the subsequent inquiries, and it is what it is. Q145 Albert Owen: But how do you respond to the headlines? Tony Hayward. I think they are not of consequence in the matter of the report. The report stands as it is written. Q146 Albert Owen: So you take overall responsibility —BP takes overall responsibility —for what happened in the Gulf of Mexico? Tony Hayward: I think we've been very clear. We were a responsible party. We had an obligation to stop the spill, which we succeeded in doing. We had an obligation to clean up the oil, which we have to a large extent done. We had an obligation to remediate any environmental damage, which we will do. We had an obligation to compensate those who have been affected. But the report was not designed to apportion blame. The report was designed to identify what exactly happened, allow us to learn from it and ensure that those learnings could be rapidly applied across the rest of BP's drilling operations and, I would assert, many other drilling operations around the world. Q147 Albert Owen: Yes, but I have a final point and I will put it to you again. From that final response I think you're saying that you were unfairly treated by the press and the way it handled it. But can you not understand the anger in the United States, which you referred to? You have drilling operations here. The British public is aghast to see what's happened out there and the fear. So do you not say that the press was fair in its response? Tony Hayward. I really think it's not a case of fair or unfair. It's just a case of it was what it was. Q148 Dr Whitehead: Could I take you on to UK deepwater drilling activity? I ought, for the record, to state that a family member of mine is in receipt of a BP pension. Chair: With not much dividend. Dr Whitehead: Well, the pension is protected, I think. When we are talking about deepwater drilling, the popular supposition in the UK is that we are not really talking about deepwater to the same extent as we are talking about in the Gulf of Mexico. But you have experience of reasonably deepwater drilling in the west of Shetland, in the Foinaven, Clair and Schiehallion fields. What experiences have you already learnt from both exploring and drilling in those fields? Tony Hayward. Well, I think the first thing to observe is that those fields were found in the late '90s. In fact they were found in the early '90s and developed in the late '90s. So we've been active in the west of Shetlands for 20 years with a very good safety track record, with no incidents or major accidents. Whilst the water is deeper than the rest of the North Sea, the reservoir pressures and temperatures are relatively low. So we don't have the juxtaposition of high pressure and high temperature and deep water that we were dealing with in the Macondo incident, and I think our business has been well conducted over a 20-year period there. Q149 Dr Whitehead: Forgive me, since I'm not a scientist in that sense, but you mentioned that the pressures and the temperatures are relatively low. That, presumably, is from experience of what you have found and developed so far. Is that something you will extrapolate across all fields for the west of Shetland or is it something that is an unknown? Tony Hayward. I think, undoubtedly, what you don't know, you don't know. So we can extrapolate within a reasonable area of the areas where we drilled. As the industry moves to ever deeper waters, there is the possibility that higher pressures and higher temperatures may be encountered. It's a possibility. It's not necessarily what you would predict from the geology, but it's a possibility. Q150 Dr Whitehead: So you are intending, 1 believe, to begin deepwater drilling in the North Uist Prospect later this year. Are you proceeding with that? Tony Hayward. I think our North Uist Prospect will not be drilled until probably 2011. Q151 Dr Whitehead: But you will be proceeding? Tony Hayward. Well, we haven't made a decision on that yet. Q152 Dr Whitehead: And do you have any evidence prospectively as to the circumstances that you might find there? Tony Hayward: Well, the water is deeper. Q153 Dr Whitehead: It is 1,300 metres. Tony Hayward. I will have to defer to Mr Looney on the projections of pressure and temperature. Bernard Looney. The projections on pressure in that well are similar to the predictions that we would have for pressure in the environment in that water depth, west of Shetland, and they are about half the pressure that we experienced in a well like Macondo in the deepwater Gulf of Mexico. Q154 Dr Whitehead: But the depth is roughly equivalent? Bernard Looney. The depth is very similar, but the pressure is roughly half from what we expect in that well. So, as Tony said, we don't have that combination west of Shetland. The geology is different and we don't have that combination of water depth and pressure that we experience in the Gulf of Mexico. 0 Ev 24 Energy and Climate Change Committee: Evidence 15 September 2010 Dr Tony Hayward, Mr Bernard Looney and Mr Mark Bly Q155 Dr Whitehead: Of your existing wells, and indeed on your planning for the North Uist Prospect well, what would be the status of the blowout preventers on those wells? Do you employ one shear cutter or two shear cutters? What is your normal process? Bernard Looney: We operate at the moment two mobile drilling units in the North Sea. They have one blind shear ram. What we do prior to taking on any new rig is that we go through a very comprehensive audit system where we establish the condition of the rig, the track record of the rig and the competence of the people. As Tony, alluded to, we will obviously be looking very closely, as we do in our existing operations today, where we bring in a third -party company who looks at that blowout preventer and will confirm that it works as it is intended to work. Chair: That is the Division bell. We will suspend the Committee for 10 minutes, and I just inform my colleagues that, as soon as we have a quorum, we will resume. (Short Adjournment) Chair: My apologies for the interruption, but we are quorate, so we will resume now and colleagues will join us. Q156 Dr Whitehead: I think before we were rudely interrupted I was in the process of asking you about the plans for exploration and drilling in the North Uist Prospect, what your plans for shear cutters and blowout preventers were in that instance and what you have in place in existing deepwater fields. Bernard Looney. As Tony says, we have a prospect in the deeper waters west of Shetland. We are not drilling that prospect this year. We will likely drill it next year. The types of rigs that can operate in that water depth tend to be dynamically positioned, they tend to be the newer rigs and they tend to have more than one blind shear ram. They tend sometimes to have two. But, as yet, we do not have a rig identified that we will use at this time. That is something that we will undertake over the coming weeks and months. In the rest of our operations throughout the North Sea we have standard equipment that is used throughout the industry. I think Tony alluded to what we now do consequent on the accident in terms of how we look at blowout preventers because I think the report says that, if the blowout preventer had operated as it was designed to, as it was intended to, the consequences could have been very different, and that's why we've taken the steps to give us an additional level of assurance to what we had in place where we bring in a third party. We have done it once for our existing fleet, to say that the existing BOPS operate as intended, and that they will operate as they are designed, and, importantly, going forward, every time a BOP is retrieved, every time maintenance is carried out on that BOP or any modifications are carried out or whatever, we will ensure that there is a third party independent company on that rig at that time who will witness that work and will verify that in no way has the operability of the blowout preventer been compromised through that work or through that maintenance. I think that is a very important thing that we are doing and will do. As Tony said, the second thing which we are doing which we believe is important is this aspect of physically testing the secondary systems. So one of the things you do in the event of an incident like this is you have a remotely operated vehicle that comes and physically connects itself to the ram to operate it. We will actually simulate that, and we do that today, on surface, with the same type of pump, the same type of pressure, to confirm that if that secondary system is needed, it will operate as we require it to. They are some of the things that Tony alluded to in his opening remarks —things that I think aren't just applicable to BP but may have more impact right across the industry. Q157 Dr Whitehead: Would you say at least one of the lessons, it would be fair to say, that might arise from the Gulf of Mexico would be to have more than one blind shear ram? Bernard Looney: It may. It's interesting. What we have to do, I think, and Mark's report makes it clear it is the area where there are some unknowns remaining, because the blowout preventer has just been recovered to surface. But, as I think was mentioned earlier, what is important is that we take action in the near term to ensure that the systems work as intended, because if they do they will operate and do what we expect them to do. Then, as Tony said, longer term there is no doubt, I think, that the industry will look further at the design of the BOP itself and what can be done to it to further enhance its reliability and its redundancy. Chair: Now that everyone is back, I will just clarify that we will run through until about 5.10. We've been given a little extra time to make up for that loss. I am grateful to our witnesses for that purpose. Q158 Albert Owen: You have dealt with some of the issues that I wanted to ask about such as the killing of the well and the lessons that you've learnt from it. But can you not understand, for Jay people watching this, the sheer timescale involved? In April we have the blowout; then for a long period of time until September it isn't capped. Surely, in a multi -billion dollar industry like this, that has high -risk operations around the world, for the lay person it seems extreme that nothing temporary was done immediately to sort of temporarily to do this. It was spilling out. I know there was early action that was done that capped it for a short while. But do you not understand the frustration and anger, not just of the American Senators and Congressmen but of the people who care about the environment, that this is allowed to happen? You are now proud of the fact that the capping could be done relatively easily. But surely there should have been some foresight that an accident would happen at this depth. Again, two-thirds of the whole spillage has gone, disappeared, dispersed. The lessons to be learned you've talked about, but I find the whole thing outrageous, to be honest with you. How would you comment? Tony Hayward. I understand why people feel the way they do, and there is no doubt that the inability of BP and the industry to intervene because it wasn't properly prepared was unacceptable. There is no doubt about that. What we did at the time that it • • Energy and Climate Change Committee: Evidence Ev 25 15 September 2010 Dr Tony Hayward, Mr Bernard Looney and Mr Mark Bly occurred was to create a multi -pronged strategy which was around partial containment, complete containment, relief wells, and we pursued those in parallel from the very beginning, and implemented each option as we crystallised the engineering around it and the ability to intervene. The truth is that it took longer than any of us wanted it to and that was undoubtedly a consequence, that the industry was not prepared, because it believed it had mitigated the risk and did not believe that this risk was going to crystallise. That clearly was a very bad assumption, as it turned out. Q159 Albert Owen: There wasn't any new science involved here in doing it, though, was there? It was just about putting mud down, basically. Again, the lay person would think that you would have this thing certainly within the region —if not on every rig but within the region. We are talking about an experienced area where you've got experienced companies. Tony Hayward: There was no new science. There was a lot of new engineering, because engineering of this sort in 5,000 feet of water has never been done before. It had never been done before. In doing it, we created an enormous amount of lessons for the industry, which means that if it ever is required again —none of us ever want it to be required again —the industry's ability to intervene would be far quicker and far more effective than it was in this first instance. I don't want to defend the industry because I don't think when something like this happens it is defensible. The complacency came from the fact that we had been doing these operations for 20 years and drilled more than 5,000 wells all over the world and had had a very strong track record of no accidents. That was, in hindsight, wrong. Q160 Albert Owen: You say you don't want to defend the industry, but the other major companies at the time immediately afterwards certainly put a lot of blame on BP and said it wouldn't have happened to them. How do you respond to that? Tony Hayward: I think it's perhaps an understandable response given what was going on in the United States. I think the investigation makes it pretty clear that this was not an issue of the well design. It was a whole series of failures that came together to create the accident. Q161 Laura Sandys: When it comes to BP and the way it structures its financing, you self -insure, don't you? Tony Hayward: We do. Q162 Laura Sandys: Picking up from Tim's point about your shareholders, in some ways they became the insurance. They became the names at the end of the day to plug your potential deficit or your potential liability. Do you think that we should be embarking on very large engineering issues without having third party insurance in the sense as a barometer of risk and as the ability to assess where issues and risk lie? Tony Hayward: Well, the reason that BP moved to self -insure, which occurred about 20 years ago, was that we found the insurance market was not deep enough to provide us cover against some of the risks that we would want to insure. Where it was, the premiums far outweighed —we looked at a 15-year period of premiums paid versus claims made, and the premiums we were paying, because of the nature of the risks that companies like BP undertake, were such that the premiums were far greater than any claim we'd ever made. So I think there were two drivers. Q163 Laura Sandys: But that insurance issue is a measure of risk. So if the premiums are very expensive, that is a barometer of the risks that you are taking, isn't it? Tony Hayward: That's of course true. It is one measure of risk. There are many other measures of risk and it is also a measure of the depth of the insurance market. Q164 Sir Robert Smith: Obviously, there is a dreadful human tragedy, with the loss of life and a devastating environmental incident as well, but also, as has been touched on, it is a great financial incident for those who depend on BP for their investments. But also those who work in BP now have the uncertainty of where BP is going. From a local angle, what are the implications for investment in the North Sea and BP's operations in the North Sea of having to meet this new liability? Tony Hayward: There are no implications for our investment in the North Sea. We have a very significant investment programme into the North Sea —I think £12 billion over the course of the next five years —and that is not in any way impacted by our need to restore the financial strength of BP. Q165 Chair: Did it surprise you at all that only two weeks after the explosion the President announced that the Administration took the view that BP was responsible for this? Tony Hayward: Under the Oil Pollution Act in the United States, as the operator and leaseholder, BP is a responsible party. So it did not surprise us. It is very clear under US legislation that that was the case. Q166 Chair: Even though your Bly Report says that the responsibility is shared with at least two other companies? Tony Hayward: Well, we, as the operator and the leaseholder, have the responsibility to deal with the incident, cap the well, clean up the oil, and remediate the environment. Q167 Chair: But you went on to say that BP would be paying for the costs. Tony Hayward: As I have said, under the legislation it's very clear. Q168 Chair: You didn't regard that comment as pre- empting due process in any way? Tony Hayward. I didn't regard it as pre-empting due process. I think there is lots of legal process still to come which will determine exactly where the costs ultimately fall. But in the first instance it's very clear under US legislation that it was BP's responsibility to • • Ev 26 Energy and Climate Change Committee: Evidence 15 September 2010 Dr Tony Hayward, Mr Bernard Looney and Mr Mark Bly respond to this and we responded in, I believe, the most fulsome way we could have done. Q169 Chair: Can you remember if the British Prime Minister said two weeks after Piper Alpha who would be paying for that? Tony Hayward. I'm afraid I wasn't in the country at the time. I was working in China for BP when Piper Alpha occurred. Q170 Dr Lee: Can I move on to the use of dispersant during the spill response. Can I first just quote from a BP document released June 19—the "Dispersant Background and Frequently Asked Questions" document: "Our initial tests show that when we apply dispersants underwater at the well site, we can use much smaller amounts of dispersant than we would need at the surface, and achieve the similar results. They also show we can show dispersants underwater in good or bad weather, day or night, when other methods of containment can't be used." I emphasise: "That kind of information might be helpful to other companies in the future." Would you agree that that statement has got a rather glib quality to it? Tony Hayward. Well — Dr Lee: I say that because it just appears to suggest that the Gulf of Mexico is now being treated as a vast laboratory experiment on the environmental impact of a deepsea oil spill. Tony Hayward: Clearly this is about how you interpret that statement. That was not what was intended. There are some important facts which are facts. What we found through the application of dispersants in the subsea environment was that the volume of dispersant you had to apply was much smaller than you needed to apply at the surface to achieve the same effect. The reason for that was that the oil and dispersant were travelling through a mile of water and mixing very effectively as they went through that water, something rather like a washing machine. No one knows today the environmental impact of this. There is lots of speculation, but we have a very substantial science programme in place measuring the water column and the marine fauna and flora in an enormous amount of detail to determine what, if any, environmental impact there has been from the application of dispersants. I think it's fair to say that time and science will determine precisely what, if any, environmental impact there has been. Q171 Dr Lee: Your Oil Spill Response Plan contains a section discussing the permission process for the use of dispersant. Dispersants are specifically designed to work at the interface of air and water and I can't see any reference to it being used at depth in your plan. What was the process whereby you made the decision and you got permission to use the dispersant in that way when, as you have just declared, you had no idea what the environmental impact would be? Ecotoxicology studies were not done, but if you are spraying it at that sort of level, that sort of pressure, you can get a substance formed and you don't know whether that's going to float to the top, float to the middle or stay at the bottom. There are a lot of unknowns here. I am pleased to hear that there is a science operation in play, but where are you going to start looking? It's impossible to predict where this substance is. How are you going to deal with that unknown as to where to look? Tony Hayward. I think it's very important to recognise that the dispersant was approved by the US Environmental Protection Agency. Every application of it, be it on the surface or in the subsea, was approved by the EPA. Q172 Dr Lee: But on what basis, because we haven't done it before? If I inject a drug into a patient I need to have some evidence that I know what it's going to do. Looking at it from a layman's view —I am no expert —you are essentially saying, "We're going to try this but we don't actually know what's going to happen and we don't know what the long-term consequences are" which has issues for BP and other companies with regards to liabilities. I am just wondering how the US authorities made that judgment. Tony Hayward: I think it was a belief that it was going to be more effective applied at depth. It was a theory. It turned out that, indeed, that was true: that the volume of dispersant applied to create the same effect of physical dispersion was significantly less when applied at the source than applied on the surface. Q173 Dr Lee: Presumably you couldn't have created those circumstances in the laboratory. So I guess that was just a bit of a punt. Was it a scientific punt? Tony Hayward: It was a scientific theory which was applied and proven to be accurate actually. Q174 Dr Lee: All right. Do you have any sense of what the medium/longer term environmental consequences are going to be? I bring that over to the UK continental shelf. It's a totally different environment, but presumably if the same thing happened you would attempt the same thing. In view of the fact that somebody has come up with the science about what it might do at source, do we have any sense as to what it might — Tony Hayward. I don't want to project or predict the outcome of the science programme. The only thing I can tell you is about the data that has been collected so far. So on the data that has been collected so far, there is no evidence of dispersants or oil entering the food chain. There has been a very extensive programme of sampling of marine fauna and flora and there has been no evidence of it entering the food chain. There has been no evidence since 20 July of any oil or any dispersants being retained in the water column. There was for a period during the spill, but since 20 July all of the sampling that has been taken across the water column at various depths has not identified any residual oil or dispersants in the water column. Q175 Dr Lee: I have one final question. In view of all this, and it does strike me as an ongoing experiment here, as someone who wants a vibrant successful British oil industry —I declare that —it • • • Energy and Climate Change Committee: Evidence Ev 27 15 September 2010 Dr Tony Hayward, Mr Bernard Looney and Mr Mark Bly surprises me that there's no environmental representative from BP here today. Am I to be concerned by that? Tony Hayward. I don't think so. I think we have a fairly significant environmental capability that, frankly, will be enhanced as a consequence of this, because there are lots of lessons here. There are lessons in this accident across many dimensions. One of them is the area that you are referring to —the application of dispersant, its effectiveness in mitigating an oil spill and its impact on the environment. A lot of good science will come out of it. I believe strongly that we should allow time and science to determine exactly what the consequences are. All I can say is, to date, what I have described to you. Q176 Chair: Do you think it is inevitable there's going to be much more deepwater drilling now? Tony Hayward. Today the world produces and consumes about 85 million barrels a day. If you look forward over the next two decades, that number is going to rise to somewhere between 90 and 100 million barrels a day, which doesn't sound like a big increment but of course there is significant natural decline. So if you go out 20 years, the world is required to fill 50 million barrels a day of daily production over the next 20 years and there is no doubt that deepwater will provide an important part of that. Today, global deepwater is 5 million barrels a day and it is projected to rise to 10 million barrels a day by 2020. So 10% of global supply and demand is satisfied by deepwater oil production. I think if you look at the UK there is perhaps a more interesting and pertinent point. The UK imports close to 30% of its domestic gas from Norway, and 65% of that gas is produced in deep water. So in the UK today we are dependent. Somewhere between 17 and 20% of our domestic gas supplies are from the deep waters of Norway. So I believe that the deepwater provinces of the world will be a very important source of oil and gas supply as the world makes a transition to a more diversified energy mix. But it's a transition that will take, as I think we all appreciate, several decades. Q177 Chair: How does the energy return on investment for deepwater oil compare with other resources? Tony Hayward. It depends very much on the fiscal regime that is prevalent in the basin where you are exploring, and, frankly, it's driven more by the fiscal regime than it is by the water depths. Q178 Chair: But I was referring really to the energy consumed in recovering the oil. Tony Hayward. The energy consumed in recovering the oil is not materially greater than that consumed in onshore fields, particularly mature oilfields onshore where you have to put a lot more energy in to get the incremental barrel out, whereas in the deep water we are typically producing fresh new fields where there is a lot of energy in the reservoir. Q179 Chair: Is it the case that under your leadership BP has cut its investment in low -carbon technologies? Tony Hayward. That's not actually the case. We've increased our investment in low -carbon technology, but we've focused it. So we've focused it into four areas. We've focused it into wind, into solar, into biofuels and carbon capture and sequestration. We've been investing in excess of $1 billion a year for each of the last three years, significantly more than anyone else in the industry and significantly more than we were four years ago. Q180 Chair: And is that increase likely to continue? Is it going to be sustained? Tony Hayward. Of course that's not for me to say now, Chairman, but I believe it's very likely that the investment in alternative energy will continue to expand. It's something that BP believes in, but we also believe that it needs to be commercial. Q181 Sir Robert Smith: I know we have laboured this point. To the layman the idea that if you had a double shear ram, especially if it was more than a joint width apart so that whatever was holding up the one we've mentioned, prompts the question, how easy is it to adapt these blowout preventers to have a different configuration of bands if that does look like being the right thing? Tony Hayward. I think it's fair to say that adaptation is not terribly easy. It would require fairly significant re -engineering of the entire blowout preventer. I do think it's important to keep coming back to this. If it had functioned as designed, there would not have been the accident. Q182 Tom Greatrex: If I may turn very briefly to the regulatory regime, I wonder, given your recent experience and your previous experience, do you think it is safer to operate in a regime where the offshore licensing that was with DECC, and the safety regulation that's with HSE, is a better and a safer way to operate than having it under one agency, like the MMS or an equivalent? Tony Hayward. I think saying one is better than the other is probably not appropriate. They are clearly different. I think the separation of duties between safety oversight and licence granting has clearly been very beneficial in the UK and it is of course something that the United States has now decided to do. It is one of the early changes that was made to the MMS following this accident. Q183 Tom Greatrex: You have decided to do it because it's safer or because that helps give out added confidence? Tony Hayward. I think it allows much clearer separation of duty and much greater ability to focus on one specific area. Q184 Albert Owen: Just going back to the environmental impact and your response to Dr Lee, which I found astonishing really, you say we've got to wait and learn from this. We've got experience with spillages around the world, of tankers in particular, and I know the scale is completely different. We are talking here about some 5 million barrels. But surely we can take something from the previous data. And is • is Ev 28 Energy and Climate Change Committee: Evidence 15 September 2010 Dr Tony Hayward, Mr Bernard Looney and Mr Mark Bly it linked to the fact that there is a moratorium in the United States now for deep drilling? The Norwegians haven't issued any new licences. Do you think that they will need to assess the environmental impact in case of a blowout before new licences? Shouldn't the industry now be saying, "We've got these safety mechanisms in place to limit that environmental impact?" I am just astonished that the industry —and I presume you are speaking on behalf of the industry and not just BP there —will learn lessons from this when surely we should have learnt lessons from tanker spillages and the environmental impact that they've had. Tony Hayward. Of course we have. I wasn't implying that lessons hadn't been learnt. But this was the first spill in 5,000 feet of water. It's the first time we'd had to deal with it. Q185 Albert Owen: But you know it's going to have a devastating impact on the environment. Tony Hayward. I would prefer to let time and science determine exactly that. It just isn't clear today. I don't want to make a projection as to what the environmental impact will be. Q186 Albert Owen: Well, there are dead animals, dead birds and various things as a consequence of this, and the coastline has been impacted. The worry is — and, like Dr Lee, I want to support the British Oil Industry —there are fears of this environmental impact on our coastline. Tony Hayward. I think I was trying to say that the first thing is to take the lessons learnt to ensure that this risk is mitigated so that it can't recur. Those are the actions that we've talked about around blowout preventers, drilling operations, safety. The second thing is to put in place the ability to respond far more effectively than BP was able to in the Gulf of Mexico because, as you quite rightly observed, we weren't prepared. I think with those two things you can have confidence that, in the event that something like this did happen, the environmental impact would be significantly mitigated. Q187 Chair: Is there anything else you and your colleagues would like to tell us before we close the session? Tony Hayward. I think the only thing I would like to say is that I would like to thank the Committee for the discussion this afternoon. I would like to thank, again, the Government for their support throughout this crisis and to say that BP remains very committed to oil and gas exploration, development and production in the North Sea, and we intend to make absolutely certain that all of the lessons that we've learnt from the Gulf of Mexico in all of the dimensions that we've discussed today are fully applied to everything that we do in the UK. Chair: Thank you very much for your time. We will be producing our Report reasonably quickly and no doubt much of what you have told us will be incorporated in one form or another. 0 • is Energy and Climate Change Committee: Evidence Ev 29 Tuesday 26 October 2010 Members present: Mr Tim Yeo (Chair) Dan Byles Christopher Pincher Gemma Doyle Laura Sandys Dr Phillip Lee Sir Robert Smith Albert Owen Dr Alan Whitehead Examination of Witnesses Witnesses: Mr Steve Walker, Head of Health and Safety Executive's Offshore Division, Mr Philip Naylor, Director Maritime Services, Maritime and Coastguard Agency, Dr Jonathan Wills, Independent Councillor for Lerwick South —Shetland Islands —and freelance environmental consultant, and Ms Susie Wilks, ClientEarth, Biodiversity Lawyer, gave evidence. Q188 Chair: Good morning and welcome. Thank you for coming to the Committee. We have about an hour to range through a number of issues with you. I appreciate that some of you come from slightly different standpoints on this subject, but don't feel obliged —each of you —to answer every single question, unless you want to say something different from what other people have said. Can I ask you to introduce yourselves? This is the first time we have seen you in this Parliament. So perhaps we could start with you, Mr Walker? Mr Walker. Yes, I'm Steve Walker. I'm the Head of the Offshore Division of Health and Safety Executive. Mr Naylor. I am Philip Naylor. I'm the Director of Maritime Services for the Maritime and Coastguard Agency. Dr hills: I'm Jonathan Wills. I'm a wildlife tourism operator, a recovering journalist and also a local councillor; although 1 attend today in a private capacity and not on behalf of my council. Chair: Did you say you are "a recovering journalist"? Dr Wills: I spent 20 years covering the oil industry. Ms Wilks: I'm Susie Wilks and I'm an environmental lawyer from a non-profit law firm, ClientEarth. Q189 Chair: Would you like to start, perhaps, by saying how the Health and Safety Executive's responsibility for offshore installations compares to the regime in the United States? Mr Walker. Yes. It's different and we have additional and different layers of regulation. In the UK we have a safety case regime whereby, before an operator brings a drilling rig into the UK or operates a fixed platform, they have to prepare a safety case for the Health and Safety Executive to approve. I can go into that in more detail if you want me to. The US doesn't have that. In addition, 21 days before you drill a well, you have to send a fair amount of technical detail about how that well is going to be drilled, designed and so on, to the Health and Safety Executive. So that gives us an opportunity to assess that well design, have discussions with the company and take action if we need to. The US doesn't have that. We also have a system of independent verification, which is enshrined in law, both for the well design and also for the safety -critical elements offshore, such as the BOP, and that would involve independent verification by people like Lloyds and DNV. The US doesn't have that. We also have, I think, a different way in which the regulator operates. I'd like to think we have a more sophisticated inspection regime because we have a performance -based legislation. Therefore, rather than just a checklist approach of inspection, it is a more sophisticated inspection. And, lastly, in the UK I'd like to think that we have a different safety culture compared to the safety culture that applies in the Gulf of Mexico —a lot more employee involvement and a healthier safety culture. I can expand on that if you want me to. Q190 Chair: Would the Deepwater Horizon, for example, have been allowed to operate in the UK in deep water, say with a single blind shear ram on the blowout preventer? Mr Walker. The way in which that would have been done in the UK, we would have seen that particular operation; we would have seen the design, which would have come in 21 days before that well was drilled. After discussions with my technical staff, we would have accepted that BOP because its design was to the relevant standards and we would have asked the well operator exactly, "Right, why have you chosen that design? Why have you chosen, say, only one ram or two rams", etcetera. We would then assess their answers and decide whether we needed to take any action. Q191 Sir Robert Smith: Two things: earlier you mentioned the different safety culture and that does seem to be, anecdotally, what a lot of people say, as neighbours and friends in the north east of Scotland. But I just wondered how we maintain that safety culture within the North Sea as we fragment the ownership, going from larger companies that can maybe permeate that culture to new entrants. How are the new entrants inducted into the North Sea culture? Mr Walker: I think that is a challenge, as the industry changes from the major companies to the smaller companies. Within the UK we do have organisations such as Step Change, which is the industry's safety focus, of which all operators who belong to Oil & Gas UK are members —and the trade unions and the regulators. So that provides a very good learning and networking environment and it does drive forward 0 • Ev 30 Energy and Climate Change Committee: Evidence 26 October 2010 Mr Steve Walker, Mr Philip Naylor, Dr Jonathan Wills and Ms Susie Wilks safety on the UKCS. Part of that working is the workforce engagement, workforce involvement work. So that is one way in which new entrants will be inducted into the safety culture. You also need to remember that, quite often, it's the same people just turning around into different sort of organisations. It's very rare for there to be a completely new company to come into the UKCS. There are also the legislative requirements that we have in the UK. We have legal requirements for there to be safety representatives on every offshore installation, and safety committees. So, whether you are a new entrant or an established company, you still have to have that and my staff go out and make sure that those arrangements are working. Q192 Chair: Is there a case for HSE to be more prescriptive about what technology is being used? Mr Walker. There is always this argument about prescription against the performance setting. Our line is very much that we see performance -setting legislation as in fact much more challenging for the industry, much more able to keep up with developments and provide, in the end, a safer environment for those working offshore. I think I'm quite pleased that, in the global discussions, other countries seem to have accepted that the approach that we and the Norwegians take on performance -based legislation has been taken up by people like the Australians, the Canadians, and so on. And that seems to be the approach that the Americans are now taking, post Deepwater Horizon. Chair: Phillip? Q193 Dr Lee: Good morning. A few questions on the spill response. When we had BP here, I asked them about their oil spill response plan for the Macondo well, because I had had access to it. My impression of that document was that it maybe was cut and pasted, and I've since been made aware of plans for ongoing exploration in other parts of the world that have similar schoolboy errors —for example, references to animals that don't exist in the region in which the well is being drilled. It is a broad question: are we happy that the oil spill response plans that have been put in on the UK continental shelf stack up? Mr Naylor. Yes, good morning. I accept the point that you make in relation to cutting and pasting a plan; certain elements of a plan, it is true, will be applicable for many types of field and for many types of activity. One of the reasons for that is that the underlying principles of dealing with a spill are going to be the same, regardless of where the activity takes place. There will be some differences reflected in the plan that, by and large, go to the heart of the way the plan will model the behaviour of the spill following its occurrence. The reference you make to Antarctic animals or Arctic animals being present in the Caribbean, I think is well known. I'm not sure that goes to the heart of dealing with a spill. Dr Lee: I'm not so sure it was well known before I said it. Mr Naylor. Sorry. Okay. I was aware of it, probably because I am in the business. But, as I say, from the point of view of providing a practical plan to deal with and to respond to a spill, the underlying principles are similar, regardless of where the spill occurs. Q194 Dr Lee: My concern, though, it gives the impression of a bit of a slap —"Oh the environment thing. We'll deal with it". It didn't give the impression that it was being taken seriously. That is my point. Mr Naylor: Yes. I wouldn't want to comment on that, other than perhaps to say that another way of looking at that approach might be to say that they're drawing on some tried and tested approaches to dealing with the issue, rather than trying to come at everything from first principles and make more mistakes along the way. Q195 Dr Lee: Okay. Staying within the realm of the plan, 1 also asked BP about their use of dispersant at 5,500 metres subsea. Would you say "Yes" if BP asked for that in Shetland? Mr Naylor. The use of dispersants in the subsea mode is something that emerged from the response to the Macondo spill. I'm not sure that the technology is sufficiently well developed to say that that is a response that could be used at the moment. Q196 Dr Lee: So tomorrow, if you got the call, would you say "Yes"? Mr Naylor: I think we would need to have some evidence that it was an efficacious way of dealing with the spill. Q197 Dr Lee: So you are saying that you would say no; because there isn't any evidence, is there? Mr Naylor. We haven't seen any evidence, one way or the other. What we have seen coming out of the response to Macondo are some views that say the use of dispersants was developed and it seems to have an effect. Q198 Dr Lee: Yes, but over what time scale? I mean the whole problem with dispersants is that they disperse oil to various areas of the Gulf. We don't know where. We don't know how it is going to come out in the system. We could be talking decades before we start seeing plankton that are slightly affected, and then if those plankton are consumed by fish and we eat the fish —I mean the potential liability here is great. What I want is a straight answer that you use an evidence base before you say yes to using a technology like that. Mr Naylor. I can assure you of that. Q199 Dr Lee: All right. I recently had the pleasure of going to Oslo for a trip and I asked at the Petroleum Ministry about the Norwegian approach to licensing for deep sea drilling. It is not that there is a moratorium in place, but the Minister said, "Before we give any new licensing to deep water we will need more knowledge". What knowledge do you think the Minister was referring to? Mr Naylor. I'm not sure what knowledge he was referring to. Dr Lee: Any ideas what he might be referring to, because we haven't suspended anything, have we, and • • is Energy and Climate Change Committee: Evidence Ev 31 26 October 2010 Mr Steve Walker, Mr Philip Naylor, Dr Jonathan Wills and Ms Susie Wilks we have not suggested that we're going to suspend anything? Mr Naylor. As far as I'm aware, we have treated the licensing that is in hand on its merits. We've certainly changed the information that we need to see in the operator's OPEP to respond to some of the experiences that came out of the Gulf of Mexico, particularly in relation to the operator's demonstration of the worst case scenario from their well. I'm not aware of anything that would act as a reason why we would say no. Q200 Dr Lee: One more question. It has been suggested to me that there may be a managerial problem on wells on a rig, and that everybody on the rig is under contract to the company that is drilling, which creates a culture and an atmosphere whereby, if you're the Emperor's clothes man and you say, "There's a problem here", that could affect your employment in the wider industry. When I suggested that there may be a managerial issue to Dr Hayward there was a pretty negative response. But rumours are flying around that there wasn't anybody on the well in Macondo to make the decision to switch it off. Now, are we happy with the regulation in that area? For instance, I go back to Norway. There is a union member on each rig, and they are not viewed as a whistle -blower. They are viewed as helping if they raise any safety concerns. I'm not suggesting it needs to be a union man, it could be any nominated person, but I am not aware that it is the same on our side. Are you happy about that set-up? Are we happy that there is somebody on each rig who can make that call? Mr Naylor: Can I answer that question from the point of view of the MCA's interest in oil spill response? I wonder if you might want to direct the question about the underlying safety culture to Mr Walker. The first answer, in relation to the decision -maker on the rig, is that, from the point of view of the MCA and our responsibility for managing the response to pollution, for us it is very clear —and is an aspect that is captured in our national contingency plan —that there is an offshore installation manager on a rig. From our point of view, that individual is the decision -maker. But I wonder if you might like to direct the remainder of the question to Mr Walker? Dr Lee: Yes. Mr Walker. When you have a drilling rig, there are usually two main organisations on board: there will be the actual owner of the rig —in the case of Macondo, that was Transocean—and you'll also have the well operator —in the case of Macondo, that was BR Certainly, in the UK, the owner of the actual rig has the control and the responsibility for the safety of the people on board. So, as Philip said, the OIM—the offshore installations manager —has the final say. There is a need for both parties to co-ordinate their activities because they have different, but separate, responsibilities. The way in which we do that in the UK is that there will be a bridging document between the rig owner's systems and the well operator's systems to make sure that issues such as who has the final say —who can press the BOP buttons, and so on —is well and truly agreed before you start the operation. So you have a very clearly laid down procedure for that. On top of that —you mentioned the trade unions in Norway —in the UK we have a system of safety representatives on every rig or platform and so on. They don't have to be trade union representatives, as such, but they are representatives and they are voted on by the work force. And that's part of the increased safety culture that we have in the UK, because people like that can act as formal whistle -blowers. They have the strength of the legislation behind them and also are accepted by the oil companies. So there are two areas —the clarity of responsibilities via the bridging document and the empowerment of employees by their safety representatives to take action. Q201 Chair: Dr Wills, do you have a point on that? Dr Wills: Thank you, yes. I think if you asked the Offshore Industry Liaison Committee, which is now part of the RMT union, they would give you a rather different answer about safety reps. The split of responsibilities here and in the States was mentioned earlier. After the Cullen Report into Piper Alpha, we hived off health and safety regulation to a separate organisation. In the States, regulation remained in the same organisation —the Minerals Management Service, I believe it's called —as the licensing authority and the organisation responsible for promoting the industry, which is part of what the Department of Energy does, and it has to be done. We still have the promotion of the industry and its licensing in the same Department. I think the Americans are catching up on the way you have to split off health and safety, but we may have some lessons to learn because they now have those three separate boxes. There is pre -approval, as I understand it, for the use of dispersants on the surface. The evidence I've seen from studying Exxon Valdez, the Bragr in Shetland, the Amoco Cadiz and the Erika and various other spills is that the use of dispersants on the surface is largely cosmetic. As Dr Lee said, we don't know yet what the effect is if you use dispersants below the surface. They are likely to spread the oil more widely through the water column. They are likely to be ingested by various plankton and, in some instances, we know the by-products from them ingesting the oil can be more toxic than the oil itself. Basically, nature cleans up and the only question is how long it takes and how bad the effects are. I haven't seen any containment, dispersal or clean-up equipment that works in the open Atlantic. It didn't even in work in flat calm in the Gulf of Mexico. I haven't seen an oil spill where more than 20% is recovered; and, of that 20%, most of it is probably water because you recover an emulsion. The old statement is that prevention is better than cure. It's a truism, obviously, but there isn't any cure. The only option in town is prevention, which is why what the gentleman on my right is saying is so important. We have to make sure this doesn't happen. I do not have the technical ability to argue with him, but I do know that around the Shetland Islands and west of the Shetland Islands are some of the most fragile and bio-diverse marine ecosystems in the • • Ev 32 Energy and Climate Change Committee: Evidence 26 October 2010 Mr Steve Walker, Mr Philip Naylor, Dr Jonathan Wills and Ms Susie Wilks world, some of the most productive marine ecosystems in the world, and we damage them at our peril. The oxygen we're breathing in this air partly comes from the plankton in the ocean. Q202 Laura Sandys: I was very interested when we had the session with Dr Hayward. He said that BP had decided that there was no risk from deepwater drilling in the Gulf of Mexico, and they would focus on other risks. When you're looking into the future, what risks that you might have put aside are you bringing back to the table? This issue that the industry itself has decided that certain aspects, certain operations, do not come with risk is quite a concern from my perspective. Also, when you talk about prevention rather than cure, we need to pre-empt some of the issues and work collectively with your bodies, but also internationally, to ensure that we are predicting and that we do have actions in place. Mr Walker: I must admit, that statement from Tony Hayward I don't recognise in the UK because the whole legislation and the whole safety ethos is that companies need to look at the major hazard risks that could occur during a particular operation. And that's the whole range, not cutting anything out. Then they have to convince us, as the regulator, that they have planned and have the facilities and the capability for dealing with those risks. Companies have to do that even before they start their operation and then part of the role of my staff is to go out and make sure that their promised procedures and processes are there and working. So I don't see that we have ignored a particular area in the UK. Certainly, drilling is a high -hazard operation. You are drilling into a pressurised reservoir and there are precautions that must be taken. As the development matures, as you put your production platform in, as your production platform ages, you have different risks. If you're talking about an old production platform 30 years on, it's not the drilling problem there; it's the ageing, it's the corrosion, it's the obsolescence of the machinery. So from cradle to grave, there are significant risks in the offshore industry that the industry must address. So I don't see that there are bits where they're saying, "Oh, we're not going to bother about that". Q203 Laura Sandys: It is just that they'd done the risk assessment and decided there was no risk. I also am concerned about what the industry is taking away from this particular disaster, which is that we always plan our risk assessments on the last disaster. There might be other issues that we need to address and I was just interested in how you look at the wide breadth of risk assessments and whether we're not just, in many ways, responding first of all to the Piper Alpha issue, which determined a lot of our regulation. We're now going to look at the Gulf of Mexico. That will determine our responses. Do you think we need a total overhaul that in some ways looks at a wider group of risks? Mr Walker. I think it's right that we do look at some of the root causations. If we get too tied up with a particular incident, then we'll prevent that incident but there will be other ones. I think, to give you an example, we did a big programme of work called KP3 between 2004 and 2007 that looked holistically at how the offshore industry was managing its assets —in other words, how it was keeping the oil and the gas in the pipework—and that was a three-year programme, 100 inspections and a report afterwards. It did raise some fundamental issues —general issues about leadership, managing of assets and information. I think it's by tackling those over -arching areas that the industry can improve and we can ensure that the industry improves. It was interesting; we did a follow-up from KP3. We did a review and we did find that, although it's not completely hunky-dory offshore, there had been a significant improvement by the industry. And we're keeping on hammering those same areas of safety leadership, of competence and so on, and the industry have picked that up and made that one of their flagship improvement areas. Q204 Sir Robert Smith: I had better remind the Committee of my entry in the Register of Members' Interests as a shareholder in Shell. But on KP3, because the industry was looking at driving down the safety statistics, was it not in a sense much easier to look at management, slips, trips and falls and the things that could be measured? Had the industry lost sight at that time —it maybe has that sight back —of the fact that if you don't keep the structural integrity then you could end up with much larger incidents, albeit less frequent? Mr Walker. Yes, that's correct. It's very easy just to look at the slips, trips and falls and what I call the occupational safety incidents, which happen relatively frequently. To manage a major hazard activity —these major hazards very rarely happen, but when they do happen they have very big consequences —you need to be looking at the underlying precursors and the hints that all may not be quite well. Therefore it does require a different way of managing, a different way of leading and looking at different metrics in order to see, "Are we doing all right? Do we have all our barriers in place?" That was something that came out of KP3. We felt the industry was too focused on occupational safety and it needed to change to look at process safety and the major hazards. When we did the KP3 review, we felt that there had been a significant redirection of the industry, looking at the major hazard potential of the offshore industry. Q205 Albert Owen: Mr Walker, you said the regulations were different in the UK to the US. Is there anything unique about the operations off the west coast of Shetland? Are there any unique issues there that need addressing? Mr Walker: From a drilling safety perspective, the geology will change, and it can change very, very quickly. So West of Shetland covers a large area but I don't think there are any particular challenges in West of Shetland deep water that you won't have in deep water in Norway, Brazil or the States. As I say, the geology is slightly different over here than perhaps in the Gulf of Mexico, but the geology can change and you can drill some relatively easy deep -water wells in the West of Shetland and you can have some more • • Energy and Climate Change Committee: Evidence Ev 33 26 October 2010 Mr Steve Walker, Mr Philip Naylor, Dr Jonathan Wills and Ms Susie Wilks challenging wells. But, once again, it depends on where you're drilling. So I don't think there's anything fundamentally different West of Shetland. Deep -water drilling does have its challenges, but there's nothing that brings West of Shetland out as a red-light area. Q206 Albert Owen: What about the biodiversity that Dr Wills mentioned and the environment? Mr Walker. That's something for the Department of Energy. Q207 Albert Owen: I'm not just asking you, Pm asking everybody. Would others like to respond to the question about the uniqueness of West of Shetland? Dr Wills: I think it's right that technically, on the drilling side, there probably isn't anything special. Although the wells out there are generally lower pressure and in rather shallower water, they are still a major technical challenge. The overriding problem out there is the weather. It's appalling. Take what Total said in their recent environmental statement. We rely on the oil industry for many of the details we have of the meteorological regime and the biodiversity. The industry has done some great research out there and it's very useful to us. Total said "the area of the Atlantic Ocean to the West of Shetland on the edge of the Continental Shelf is characterised by extreme environmental conditions such as strong winds, huge waves, very low temperatures and significant water depth". That simply means that if something goes wrong, it's going to be more difficult to fix it. It has just become slightly more difficult because the MCA has decided to withdraw the emergency towing vessel, emergency tug, which is designed to cope with drifting tankers. In fact, it's extremely useful out there because it's equipped with spraying equipment and it is also a fire -fighting tug. It has just been withdrawn as an economy measure, which sends — Chair: Maybe the Navy will think it's not an economy measure after what happened last week. Dr fills: It sends us the wrong message, I'm afraid. Q208 Albert Owen: But isn't what you're saying there about the weather —the fact that there is terrible weather to deal with, and that they disconnect from the wells —that they are testing their equipment more than they did in the Gulf of Mexico? So isn't there a plus side to that? Dr Wills. One would hope so. When something does go wrong and it's a north -wester, we have less than two days before the oil is ashore in a pristine kelp forest; which is where the fish breed and live until they're big enough to be caught by the fishing industry. Q209 Albert Owen: There's a lot of experience in the North Sea. Can we learn a lot from what's happened in the North Sea and how different it is in the West of Shetland? I hear what you say about the depth and the pressure, and that has to be dealt with technically, but my concern is the environmental damage that you talked about, possibly the biodiversity that you talked about. What lessons have been learned from the North Sea that can be learnt in the West of Shetland? I go back to the point about the weather and the need to decouple and to test the equipment more because what I found outrageous in the responses that we had is that nobody had tested batteries, for instance. You know, this is very basic to me; that in a multi -billion pound industry there was no operator looking after the levels of batteries. Are these issues being looked at? There was no preparedness in the Gulf of Mexico. Are we prepared today? Dr Wills. The battery problem was one of the reasons there was Esso Bernicia spill in 1978—new year 1979. Q210 Albert Owen: So this is recurring? Dr fulls. It's an old problem. It's a simple problem. The technical problems that cause disasters tend to be quite simple. As I think Dr Lee said, it's very often a management problem —people are not following their own safety procedures, the whistle -blowers are not able to call a halt to things and the managers are obviously trying to make money for the company. That's what they're there for. They're not there to protect the environment. They're there to make money and good luck to them. It's our job to protect the environment and make sure they do what their own procedures say they should do and what our law says they should do. Because it's not their oil, it's our oil. That's why they have to apply for licences. Q211 Albert Owen: Mr Naylor or Ms Wilks, would you like to say whether anything is unique about the West of Shetland? Ms Wilks: From a legal point of view, there's nothing particularly unique about it. That area comes within the same safety case regulatory system as any other area. I think, having listened to what the rest of the panel have said, I understand the benefits of having a goal -setting regulatory regime and I don't think that fundamentally there's any problem with that. But it just is a way of regulating that relies really strongly on having a strong regulator with efficiency and capacity and robustness and proper independence. One of my key concerns about the regulation, even on paper at the moment, is some of the independence requirements. So, for example, in the system of verification of well design by independent and competent persons, the legal requirements for independence are not tough enough. I understand that the system operates as a client relationship essentially between the oil companies and the consultants who carry out these verification systems. I would prefer to see that brought on to a much more independent level and administered independently with an extra level of oversight from an EU independent authority as well. While the UK may be doing a lot more than other jurisdictions, we need to think of this as a European Union -wide issue and we need to be sharing some of the best practice that we developed after Piper Alpha and so on. They're drilling off the Netherlands and Denmark as well as off the UK Continental Shelf, and this is a trans -boundary issue. Mr Naylor: In terms of uniqueness, it's true that the weather in that part of the Atlantic can be atrocious but the oil industry is quite well accomplished at • �J Ev 34 Energy and Climate Change Committee: Evidence 26 October 2010 Mr Steve Walker, Mr Philip Naylor, Dr Jonathan Wills and Ms Susie Wilks exploring for oil in very hostile conditions, whether in the North Sea or other parts of the globe. If, heaven forbid, there was a spill —I sincerely hope there never will be —the weather would act as a force to assist with the breakup and eventual dispersal of the oil. So in some ways the atrocious weather conditions can assist. I think the point about the depth of the well is obviously that, as was shown with Macondo, it takes much longer to resolve the problem if you're in deeper water, purely because of issues of accessibility, distance and so on. But I'm not, by any means, an expert on the oil exploration industry. Picking up on the point that Susie mentioned in relation to trans -European co-operation, I think it's worth bearing in mind that that the model of oil spill response that the MCA has developed, as described in our national contingency plan, does have the ability to, and in fact would, involve other member states within Europe under what we call the Bonn agreement. That is an agreement among all European member states that border the North Sea to work together, to lend assistance and to really make best endeavours to assist other European member states when they have a problem. Similarly, in relation to Norway, we have an agreement called the Norbrit Agreement, which in many ways is a mirror of the UK's national contingency plan and establishes a very clear boundary and clear communication and command and control arrangements for a spill in UK waters that might affect Norway or vice versa. So, to that extent I think it's probably fair to say that we've got quite a good model of co-operation within Europe and indeed with Norway. Q212 Sir Robert Smith: Just on the EU role, there is a lesson from the fishing industry. The model that Mr Naylor outlined is a better model than maybe the EU-wide model because Czechoslovakia, Poland and Austria don't necessarily have much interest in what's happening in the North Sea whereas those countries that live and breathe and work around the North Sea do. So what we're trying to achieve in the fishing industry is regional management again, which may be one we should stick to for this. Mr Naylor: I suppose I use the term "EU" loosely. More correct would probably be to say those members of the EU with whom we have a common interest within the area where we operate, rather than the EU per se. Q213 Dr Whitehead: Mr Naylor, you mentioned the possibility, heaven forbid, of a blowout. The Shetland region has not just rougher weather throughout the year but very strong currents —unlike in the Gulf of Mexico. How would those particular circumstances affect oil spill response plans? Mr Naylor. Well, they go to the very heart of the principles that would underlie a response to an oil spill because the first thing that we would look to do is model the expected dispersion of oil as it came to the surface. That obviously needs to take account of aspects such as wind and weather but also aspects such as drift. That would then be verified in the early stages of responding to the spill by mobilising equipment towards the scene of the problem by surveillance. We have a surveillance aircraft that is on short readiness to fly out. It is fitted with a number of sensors including sea -surface radar which can paint a very clear picture of what's on the surface of the sea, coupled with satellite imagery, particularly the satellite imagery that emerges from what's called the clean sea net. The modelling that we would do, coupled with our observation of what was happening in reality, would then give us a very clear steer about what was happening to this oil as it came to the surface, where it was likely to go and hence what our response strategy needed to be. Dr hills: We have much better surveillance capacity than we used to have. We can see where the oil is going. We still can't do anything about it. The coastline of the Shetland Islands, if you go to every bay and around every little island, is 1,600 miles. It varies from salt marsh to some of the highest cliffs in the United Kingdom. Much of it is, to all intents and purposes, inaccessible to spraying equipment. There is no way you could contain or clean up a significant amount of oil and I don't think the Committee should be under any illusion about this. We do have plans, very detailed plans. There are some for inshore and for sheltered harbours like Sullom Voe, which have worked very well. But none of the kit would work in the open Atlantic. Q214 Dr Whitehead: But in the case of Macondo, the eventual solution took three and a half months and involved a relief well being drilled. Arguably, the effort to clean up the oil prior to drilling the relief well, putting the cement in and capping the well were pretty ineffective, but clearly the relief well was effective. So if a relief well were required to be drilled, are there sufficient rigs in the area and would the same sort of circumstances apply to the drilling of a relief well —which after all I think started only a fortnight after the blowout in the Gulf of Mexico —or would there be particular difficulties with that? Dr hills: I imagine there would, as there were in northern Australia in a recent, very well publicised spill, or there would be in a blowout that went on for a long time. We haven't had a prolonged blowout in the North Sea since Ekofisk and that was only seven days until it was stopped. Q215 Gemma Doyle: Taking the issue of environmental legislation at an EU level, do you think there are problems with the current legislation and, if so, what changes would you like to see? Ms Wilks. Can I just respond to that and also respond to Robert's point about the dangers of EU intervention? Obviously, we wouldn't want to see something like the disaster of the common fisheries policy coming out of a call for extra EU action. Nobody wants to see the EU coming in with some kind of lowest common denominator or a one -size - fits -all policy. However, there is capacity within DG Energy and DG Environment to assist with a forum for best practice sharing and looking at whether some kind of minimum technical standards or procedural standards are necessary; capacity for assisting with inspections, and capacity for working on research and development outcomes and training of rig personnel • Energy and Climate Change Committee: Evidence Ev 35 26 October 2010 Mr Steve Walker, Mr Philip Naylor, Dr Jonathan Wills and Ms Susie Wilks or national inspectors. Given the rapidly changing technologies and the new environments that we're going into, and what we were saying before about the need to predict some of the dangers rather than just respond to things that have already happened, we need to use all of that capacity and take advantage of it. We could go in there and share best practice and take what assistance we can because, while our system might be better than many, it's still not perfect and there's still room for improvement. Your question was about what I would like to see in terms of different legislation or amendments to current legislation. My main concern is with the liability system and the absence of any regulatory framework or any clear, consistent and reliable regulatory framework for determining liability and compensation arrangements in the case of a spill. So we have the European environmental liability directive, but it is likely to be of limited application in the case of a big spill in European waters and, as a matter of UK law, there's nothing to fill that gap. So I'd like to see something done about liability. Q216 Gemma Doyle: Do the rest of the panel agree with that? Dr Wills. Yes, I couldn't disagree with that. There is a good precedent. The European Marine Safety Agency now based in Lisbon is trying to do much the same for tanker traffic and for shipping standards in general Mr Naylor: I think, from the point of view of the Maritime and Coastguard Agency, I can probably do no more than to remind members of the organisation's mission which simply is, "Safer Lives, Safer Ships and Cleaner Seas". That's why we exist. So we would endorse anything that has the effect of helping to keep the seas cleaner. Q217 Dan Byles: I'm interested in touching further on the liability regime. One of the things that raised a lot of eyebrows about the Gulf of Mexico spill was the sheer cost involved once an incident has happened. I think it is probably fair to say that a smaller company than BP with less deep pockets would not have been able to cope with that on their own. Do you think that the entire international liability regime, as it is stands, is fit for purpose for this sort of incident? Ms Wlks. No, is the short answer. No, it's not; it's far from being fit for purpose. While the US has not been so strong on prevention, a lot tougher on liability, which probably comes as no surprise. There's no equivalent to that in the EU or in the UK specifically. There are international conventions dealing with oil pollution liability and compensation for tanker traffic, but no equivalent for offshore installations. The problem with the environmental liability directive, without going into too much detail, is that it only responds to very particular kinds of environmental damage --so the most relevant to this scenario is probably biodiversityspecies and habitats —and it responds only to specifically legally protected habitats and species, and then only if the damage is significant enough, which is quite a high threshold of adversity. So the chances of it providing a complete regime are pretty slim. There is, of course, the OPOL Voluntary Industry Scheme but the limit of that is $250 million and it's not enough, in my view, given what we now know about how much Macondo has cost. Also it's a voluntary scheme and at the moment all the drillers on the UK Continental Shelf are a member of it, but they don't have to be. Also the fact that it is voluntary means that it has no legal footing. There is no legal control over it. So basically the company that has caused the damage and should be paying the claim is also deciding on the value of the claim and deciding whether the kind of damage that has been caused falls for coverage under the rules of this particular scheme. So the OPOL scheme covers direct pollution damage. There's a whole set of legal principles about what constitutes direct versus indirect damage and it is debatable whether some of the widespread ecological effects that you can see and that Jonathan has talked about would qualify as direct damage according to the oil company that is going to be paying for it. So we need to have that system on a legal footing. Q218 Dan Byles: For my own information and for the rest of the panel —I genuinely don't know this — the independent competent persons, do they have any liability? If they investigate and sign off a well and there is a subsequent incident, is there any liability that comes back to them? Ms Wdks: That's an interesting question. I think you would probably have to show some sort of negligence, just as a matter of regular tort law. If they had been negligent and the oil company had relied on what they said and there was, therefore, a loss — Dan Byles: But there is no direct clear liability link? Ms Wlks: There is no strict liability mechanism, no. Dr Wills: On that point, Det Norske Veritas—the Norwegian ship inspection company which also inspects platforms —signed off the motor tanker Braer in January 1993 and said she was okay to go to sea, despite the fact that her main steam pipe had just been repaired without being physically inspected by an inspector. DNV suffered no loss and there was no liability. The government picked up most of the tab. I'd like to refer to the point raised by Susie and one of the Members just now about the extraordinary costs of oil spills. Shetland Islands Council, which I have the honour to be a member of, operates the Sullom Voe Oil and Gas Terminal'. It's the largest export terminal in Europe and our Head of Ports and Harbours just yesterday produced some rather interesting figures in connection with the loss of the emergency towing vessel. This shows that in the Fair Isle Sea area the cost to the UK economy —not to Shetlands economy —per tonne of crude oil spilled is something like £1,600. So you could basically multiply any numbers by 1,600. It is a very interesting paper, far too detailed to go into here. But if you are interested, sir, I could leave it with the Committee Clerk. You might wish to consider it. Chair: Thank you. Note from the witness: "The council only runs the port. The terminal is operated by BP on behalf of a consortium of many oil and gas companies." is 11 Ev 36 Energy and Climate Change Committee: Evidence 26 October 2010 Mr Steve Walker, Mr Philip Naylor, Dr Jonathan Wills and Ms Susie Wilks Q219 Laura Sandys: Just picking up from Dan's points and your inputs on this, one of the things that really concerns me is the issue of how we get compensation through the system. If you look at BP's response, in many ways their immediate response was much more to do with their reputation with the US and ensuring that the US Government were looking at them in a little bit more of a benign way than previously. If they hadn't had those interests in the US, the matter would have ended up in court between all the different parties. Now we are getting these very, very large investments, multiple partners, all looking to blame each other through the courts. How can we structure a process where compensation would be not necessarily immediate but speedy; where people would not have to spend five, 10 or 15 years in the courts before, let's say, communities got their compensation? How do we structure something like that to bring security to the communities that might be impacted? Ms Wilks. The US system has its problems, as I understand. I don't know if you've come across the Environmental Liability Superfund. It is a system of comprehensive and strict liability, by which I mean liability regardless of fault, where you identify any "potentially responsible party" —that is how they phrase it. So the issue of the contractual arrangements between the driller and the rig contractor, for example, is irrelevant to getting the compensation paid to the people who have been damaged. So it is a joint and several system; any potentially responsible party can wind up liable for the entire loss and then it is for the companies to wrangle it out between them. So that is a possibility; that is one example. I would suggest that a liability regime like that would and should have a pretty strong preventive effect as well in terms of risk management. Q220 Christopher Pincher: On that same point, in the UK, unlike the United States, you cannot claim any money for environmental damage. After the Exxon Valdez, some communities received compensation which they then used, for example, to purchase areas of pristine forest to prevent it being clear-cut and this was seen as an environmental compensation. That isn't possible in this country because you can kill as many gannets as you like; they're not worth anything. Ms Wdks: Yes, so the environmental liability directive is supposed to provide for remedial measures, not for property damage, but for environmental damage. If you destroy X number of sea birds, you have to provide some kind of ecologically sound compensation for that, not just a monetary payment. Q221 Christopher Pincher: Thanks, Chair. My question is directed specifically at Dr Wills, as you are on site, as it were. I suppose there is a tension, hopefully a creative one, on Shetland between a hugely enriching business on your doorstep and one that poses very significant environmental risks and you have alluded to some of them very eloquently. I wonder if you can tell us what the perception is of the oil and gas industry among the islanders? Dr Wills: Well, it got off to a bad start. In 1978 the 12th tanker spilt 1,100 tonnes of fuel oil, which killed more birds than the 85,000 tonnes from the Braer. It was a different kind of oil. Then the industry realised that it had a PR problem and a big one and, in good faith, it came to the council and the MCA and other bodies concerned and said, "How can we improve this?" As a result, we received a tanker traffic control system, which at that time was the best in the world. The entire process is based on stopping things happening —you can clean up in a harbour, but you can't clean up outside a harbour —and we have been very impressed with the industry, and particularly with BR Companies can do it if they want to and if they have to. We regard BP on Shetland Islands Council —and 1 am sure I do here speak for most councillors —as a partner and an honest partner who will do things that we require them to do for the health of the environment. We've seen in Shetland BP —as belatedly in Alaska — has realised that looking after the environment is very good business for them and the public relations costs of spills, in the days of electronic media, are quite catastrophic. They are much more serious than they were in 1978 because not many people heard about our oil spill then. That was in the days when only the industry had fax machines. By 1993, when we had the Braer, everybody had a mobile phone and a few people had email. But nowadays the damage from that kind of PR disaster goes around the world in seconds and we have found that BP and its partners at the Sullom Voe Oil Terminal are capable and willing to have a successful and clean offshore oil and gas industry. Now, this refers to pipelines and to tankers. We haven't had any pipeline problems and we've had very few tanker problems. The big tanker problem we did have was a tanker that wasn't subject to the rules of our oil terminal. The rules in Sullom Voe are good international standards but they are enforced by clauses in commercial contracts. So when you have a tanker and you go to pick up a cargo of oil at Sullom Voe, you have to agree in writing that you will observe all these extra standards and this is enforced by the industry's own commercial clauses in their own commercial contracts. When you bring the insurance industry into it, of course, that's where you have real clout. The insurance industry could massively increase offshore standards tomorrow. Q222 Christopher Pincher: Can you quantify the benefits to the Shetland Islands of the industry? How many people are employed, directly or indirectly, by it? Dr Wills: Jobs and contracts in the terminals are worth £50 million to £60 million a year to a local community of 22,000 people. We have trust funds which have been built up by a very tiny levy on the price of each barrel of oil passing through —a very tiny levy, a fraction of half a per cent. —and I think we have £175 million' in a charitable trust that is for the use of inhabitants for charitable purposes. There is also a reserve fund that the council operates from Z Note from witness: "The total was £178 million on 22 October 2010" • • 0 Energy and Climate Change Committee: Evidence Ev 37 26 October 2010 Mr Steve Walker, Mr Philip Naylor, Dr Jonathan Wills and Ms Susie Wilks being the port operator. Again, it is a small proportion of the total. I think we have currently £80 million' in the reserve fund. These are small sums to the oil industry, but they are big sums to a small community and they have been earned over the past 34 years because the industry recognised very early on that to be a real partner, not just a paper partner, it had to take the concerns of the local fishing industry and the local wildlife tourism industry into account. The one thing you may not know is that oil spills kill a lot of sheep because sheep in coastal areas eat seaweed and if it gets oiled and they eat it you have to destroy them, usually. There are all sorts of things you don't think about when an oil spill happens and I've seen enough of them; so I don't want to see anymore. Q223 Dr Whitehead: The question I want to ask this morning is a question on the West of Shetland's environment and ecology and also the environment of the islands themselves and this is a particular question, perhaps, to Dr Wills. Do you think overall the knowledge that we have of how the systems, particularly on the West of Shetland seabed, work and the particular nature of the continental shelf marine environment in that part of the world means that we have to do a lot more work on understanding that before one might seriously go into deep sea drilling in the way that has been described? Dr Wills: We are just starting to find out what is going on down there. It is very new science. When I was born, I will not say when, we didn't know anything. We didn't even know there was a mid -Atlantic ridge. Now we know a lot more about the topography of the seabed; we know a lot more about -the ecology. We've discovered there are corals down there —corals that don't need light and don't co -exist with a plant. So there are large deposits of coral down there. We're learning all the time. Thanks to the oil industry's own researches, we've leamt a lot, but you're undoubtedly right that there's a great deal more that we have to learn. As long as the industry operates safely, that ecology will not be damaged. The question is whether the commercial pressures on the people working out there are so great that they won't or can't follow their own procedures? That is my worry. Q224 Dr Whitehead: Are there, in your view —and indeed in any of the panel's view —particular circumstances of the ecology and the environment West of Shetland that might cause one to say that, over and above what we know about best endeavours in safety procedures, other issues need to be taken into account that are specific to the West of Shetland further precautions need to be thought about? Dr Wd1s: Of course. The Precautionary Principle suggests we should "gang warily" as they say in Scotland and the industry themselves have told us, Note from witness: "The total was £90.3 million on 22 October 2010" from their scientists' research, that where normally you expect the variety and the numbers of animals to decline as you go into deeper water, West of Shetland they do not. They get richer and we're still exploring that. So I'm not technically competent to say whether there should be a moratorium on deep-sea drilling. You will be, by the time you have heard your evidence, but I would err on the side of caution. Ms Mks: Briefly, again on the liability question, I just want to add that, the current liability regime that we have just discussed relies on protected habitats and protected species. Marine areas currently lag way behind terrestrial areas in terms of designation of protected sites and we're discovering new marine species so they can't all be on the protected species list yet. So, the precautionary principle becomes particularly important against that background. Q225 Sir Robert Smith: Isn't it important to remember, though, that we are not just starting drilling West of Shetland. We have been drilling West of Shetland for some time, and we are producing West of Shetland? Dr Wills. That's true, but we are only just beginning to understand the ecology of the seabed down there and what goes on underneath the seabed. We have a very limited understanding of what goes on in the plankton and deep water plankton —the zooplankton. Q226 Chair: Just to conclude; Mr Naylor, is it your view that the oil spill response in the UK is more focused on tanker spills than well blowouts? Mr Naylor. That is not my view. My view is that the plans we have, which have been developed over so many years now, based on our experience of dealing with spills, originated back, I suppose, in the days of the Torrey Canyon. It is true to say that many of the spills that we have had to deal with have been as a result of transportation -related spills, whether from tankers or of fuel from ships. But, nevertheless, as I mentioned before, the principles of dealing with an oil spill pay little regard to the origin of the oil. The principles of dealing with it are the same and so, to that extent, I would say that the plan is not shipcentric. It is unfortunately the case that we have to deal with many more incidents of oil from ships than we do oil from the offshore industry. The record of the offshore industry, in terms of calling on us to manage any consequences from its activities, is much better. Dr Wills: That may or may not be true, but how do we know if there has been a spill offshore? Mr Naylor. It's self -inspection and self -reporting. Dr Wills: I don't know if there's a spill going on offshore today and I wouldn't know unless the spiller told me. Chair: Well, it depends how big it is. Mr Wills. Yes, there are lots of small ones every day; I know that —a few gallons here and there. Chair: Okay. Well, thank you all very much for coming in. • • s Ev 38 Energy and Climate Change Committee: Evidence 26 October 2010 Mr Roland Fester, Mr Richard Cohagan and Mr Brent Cheshire Examination of Witnesses Witnesses: Mr Roland Festor, Managing Director, Total E&P UK Ltd, Mr Richard Cohagan, Managing Director, Chevron UK Ltd and Mr Brent Cheshire, Managing Director, DONG Exploration and Production UK Ltd, gave evidence. Chair: Good morning and welcome. Would you like to just introduce yourselves briefly, please? Mr Festor: Good morning. I'm Roland Festor, the Managing Director of Total. Macondo happened six months ago, but it's never too late to express some sympathy with all the people who had problems because of it. 1 would just like to start by saying that we will be totally open and ready to help you as much as we can in what you are trying to do. Total has now been working in the UK for more than 40 years. We are one of the big operators here in this country, producing between 10% and 20% of the production in this country. We are mainly gas producers, and I think we have always professionally done our job in this country. Of course, we have to recognise that Macondo happened and we have done all we could to understand what happened, why it happened and we have tried to take all required actions to benefit from the lessons learned. This is what we have tried to do in the past month and we are continuing to improve our operation. Mr Cohagan: I'm Rick Cohagan with Chevron. I'm pleased to be here today. I think, as most of you know we're currently drilling an exploration well in deep water West of Shetland. It's 160 miles north of Shetland. The well was spudded about four weeks ago and we have gone through a very enhanced level of scrutiny by the regulators. You might be interested to know that we are making good progress on the well. In fact, we're running riser and the BOP as we speak. I also want to let you know that there is quite a bit of technical information that may come out today. If there is some follow-up that we need to do with some of our technical experts to answer more detailed questions we're happy to do that. Mr Cheshire: My name is Brent Cheshire. I'm the UK Country Chairman for DONG Energy in the UK and Managing Director of their exploration and production operations in the UK. Q227 Chair: Would you like to tell us what challenges there are in drilling in the West of Shetland? Mr Festor: Drilling similar exploration wells West of Shetland, we have discovered some gas reservoirs during many years, not big enough to make a project out of them. We have then worked in the frame of a taskforce under the leadership of DECC by grouping all the operators working West of Shetland to try to work out something that could create the conditions to make the project economical both for the companies and for the country. During that process, we made a discovery called Tormore. Laggan plus Tormore was judged big enough under the frame of the conditions prevailing here in this country to make a project. In March 2010, we got field development approval from DECC and we have decided to develop the first gas production development West of Shetland, which you all know. It is called Laggan-Tormore and is in 600 metres of water. We have now signed most of the contracts and not later than tomorrow we are going to sign the contract for a gas plant to be built on the Shetland area onshore. In the meantime, we continue to undertake exploration. Normally, if everything works well, we hope to start producing gas West of Shetland in 2014. Q228 Chair: Mr Cohagan, I was really trying to tease out what kind of difficulties might be encountered. Mr Cohagan: There are quite a number of difficulties, most of it around metocean and weather conditions. There's no question also that West of Shetland is still a relatively unexplored area. There are areas where we have found production and we're currently producing, but there are still large areas where we still have not explored yet. That's one of the things we're doing now with the well we're drilling north of the Shetlands. We do experience weather and bad ocean conditions that make it difficult to get people and supplies out there. Normally, we do get enough break in the weather to do that, but we have to take that into consideration. Also, when we're drilling, we will get conditions in the oceans, heaves and waves, where we will have to shut down drilling because of the operation we're doing at the time. In fact, on the well we're drilling right now, in the last two weeks we've been down for about eight days just waiting on weather. But that's something we expect and take into account and we continue to tell our people who are working offshore on these wells, "If you have any doub, shut it down and make sure it's safe, because we want to make sure that we drill this well right". Q229 Chair: Have you changed'in any way since the Deepwater Horizon incident? Mr Cohagan: I don't believe that we have fundamentally changed in any way. We have gone back and looked at the design of our well and tested it against the information that came out from the Bly Report, the report that BP did, and the Salazar recommendations that came out. We also went back and looked at our well design, the procedures and the processes against those recommendations. We wanted to make sure that everything we were doing was correct. There were a few things that we strengthened, just to make sure everything was in place that we needed. But we have found, overall, that most of the design and the processes we use are very robust and they fit very well with the recommendations that have been coming out of the Gulf of Mexico. Q230 Chair: How did the worst case scenario in the environmental statement you submitted in March compare with what happened in Macondo? Mr Cohagan: We did go back and we looked at the worst oil spill condition we might have. When we • Energy and Climate Change Committee: Evidence Ev 39 26 October 2010 Mr Roland fester, Mr Richard Cohagan and Mr Brent Cheshire went in and we looked at the pour pressures, the pressures down -hole in the well, and we looked at what seismic has shown us might be the producing interval, we calculated what the largest spill rate could be. We came up with a very large spill rate in that condition of about 77,000 barrels a day, which is more than Macondo. We've looked at that to test it and say, "What would we do in those cases?" We tested our spill response plans against that. Again, the one thing I'll point out is that, although that is a worst case, this is an exploration well. So there's a one in 10 chance of it being a success, which means nine out of 10 times it won't be a success. In those times that it is a success, it probably will be smaller than what we have modelled as a worst case, but we do try to look at that to make sure we know what we're getting into. Q231 Laura Sandys: I just wondered whether you felt that the $250,000 limit for the Offshore Pollution Liability Association programme is going to be adequate when you talk about the spillage that you could predict might happen in West of Shetland? Mr Cohagan: Obviously, as a very large company, we're going to stand behind whatever happens out there. The $250 million OPOL limit per incident is kind of what the industry has said; that's what we will make sure is that we have as a stopgap. But I think Chevron, like most large companies, understands that if we have a large spill we're going to need to stand behind that. As a large company, we have a global corporate insurance package which covers all of the various issues we might get into around liability. Like most companies, we benchmark that against others. We also look at what self-insurance limits we need to have. Because we are a large company, those are fairly high but we do feel like we have the necessary insurance, the necessary backing, should anything happen. Q232 Laura Sandys: Just to clarify, you self -insure or you are insured by third parties? Mr Cohagan: It's a package and there are some parts of it that have self-insurance elements and there are parts of it that have third party. Q233 Laura Sandys: One of the concerns that we discussed with our last panel members is the fact that if you have multiple operators, you would spend more time, in many ways, creating litigation issues between each other than coming to a settlement with the community or the United Kingdom; depending on who should be the beneficiary. Mr Cohagan: I think, similar to what you saw in Macondo, you get to a point where what you have to do is take care of your responsibilities, first and foremost, and then try to sort out the various impacts of that between the partners. But we also know, as an industry —and I think that's one reason we're spending so much time as an industry, whether it's through OSPRAG, whether it's through OGP or whether it's the work going on in the US —that the actions of one of us and any problems that one of us might have reflects on all of us. Therefore, we all have to do the right thing and make sure that we're putting the right processes and procedures in place so we don't have these spills in the first place. We're spending a lot of time trying to get it right. Q234 Sir Robert Smith: One of the earlier witnesses talked about how, when you're managing systems offshore, the profit motive is driving the manager. But, in a sense, isn't the consequence of a safety failure even more expensive than ignoring the safety risk? Mr Cohagan: Absolutely, and that's one thing that we spend a lot of time on —not only with our own people but with the contractors who work for us. We talk to them all the time about stopping work if they see anything that might be an indication that there's something wrong. I've brought a card that I'll be happy to leave. This is our stop work authority card. When we go out to talk to our crews offshore, when we have turnarounds where we shut down work on our platforms to talk, I go to those meetings where we bring all the contractors in to talk about the work. We hand these cards out —it's got my name, my signature here —it says, "Not only do you have the duty but you have responsibility, if you see anything going wrong, to stop the work." I tell the folks, "If anyone gives you any problems, you call me because this is what I want you to do and this is why we're giving it to you". You are absolutely right, if we have any issue offshore and we have a problem, the impact of that is normally far worse than any kind of lost productivity from slowing down a little bit. Mr Festor. I would like to comment a little bit on what Rick said. When I was a young engineer, my first job was working in the North Sea 30 years ago. I never heard my boss talking one day about safety. It was not a concern. I came back 30 years after and I discovered that here in the UKCS—before Piper Alpha and after Piper Alpha —it's another world. And also in the meantime I have been working on all the continents in several subsidiaries of Total. I've never seen one place where the safety is of priority as it is here. In all that we do with the work force, in the communication with the work force, in our procedures I can guarantee you that safety here is concern number one. Mr Walker from HSE was here before. He is not always making our life easy, but he is my big support because I am the Managing Director of Total here in the North Sea and, okay, when they come and they inspect and tell us, "You should do this, this, this and this", for me as Managing Director it's a major help. Q235 Dr Whitehead: All operators are required to have an OPEP—oil pollution emergency plan. What changes have you made in your OPEPs since the Deepwater incident and its gravity became apparent? Mr Cohagan: With our OPEP, as I mentioned earlier, we went back and we first looked do we have the right size spill model, because we saw from Macondo what could happen in a large spill. We then went back and said what are the resources that we have to call upon. I think, based on what we saw in the Gulf of Mexico, we saw that there were cases where sometimes OPEPs or different plans that were being used in response to spills weren't as strong as they needed to be. We tried to make them strong, but we found some gaps after Macondo and we said, "We'd better make sure we r� C Ev 40 Energy and Climate Change Committee: Evidence 26 October 2010 Mr Roland Fester, Mr Richard Cohagan and Mr Brent Cheshire have the necessary facts and figures and that we have thoroughly looked at it", and that's what we've done with the OPEP. We've gone back and we've looked at it in terms of those situations that we've seen in the US, as well as our own situation here, and we've tried to make sure that they were modelled correctly and that we had the right information in them and that we could use them in the case of the response to take care of any size spill that we might have. Q236 Dr Whitehead: Is it fair to say, however, that the fact that you have revisited OPEPs and had a look at worst -case scenarios indicates that the industry as a whole had not placed those worst -case scenarios into its OPEPs before Deepwater Horizon? Why do you think that was? Mr Cohagan: I think Deepwater Horizon gave us a new perspective on how bad things could be. I think any time you have an incident, whether it's something like the Deepwater Horizon —Roland referred earlier to Piper Alpha —you get a new perspective and you think, "How bad could some of these things be if we actually had them?" I think that always causes us to think about it and adjust our thinking and that's what we need to be doing. We need to take all these leamings and make sure we get them implemented into the things we're doing. It's not unlike what's going on with OSPRAG right now or some of the work that OGP is doing. As we're getting information in, whether it's the Bly Report or any other reports that will be coming to us in the near future from the Gulf of Mexico, we're going to take that information and we're going to say, "What do we need to modify or change? What can we learn from this and how do we implement it?" So I think it is back to the situation we have with the regulatory regime in the UK. It is goal -setting; it is non -prescriptive, which means we have to continually demonstrate that we're doing everything we can to keep our risk as low as reasonably practical and make sure we're working that new information and any new best practices and leamings that we get into our plans. Q237 Dr Whitehead: Has part of that learning process been looking at the question of the power and availability of remote operating vehicles? One of the issues in Macondo was that those vehicles were either not available and, when they were, they didn't appear to sufficiently powered for the tasks that faced them. Is that an issue West of Shetland or is it something that you think is already well covered? Mr Cohagan: I can tell you from the work that we've done on the well that we're currently drilling, we've taken all the lessons from Macondo and we've looked at what we need to do to modify it. When we were getting ready to run our BOP yesterday, we had the ROV operators as well as the BOP manufacturer, Cameron, on site talking about if there is a problem what do we need to do with the ROVs to make sure they can access the BOP subsea if there was an issue like they had at Macondo. So we feel like we've tested everything. We've looked at everything on the ROV as well as the other equipment to ensure that we won't see those kind of issues. Q238 Dr Whitehead: Mr Cohagan, you've given, I think, an impression that, as it were, all bases are covered. That might be a description of what you have said this morning. Is that the view of everybody on the panel? Mr Cheshire: I think from our point of view you produce an OPEP when you're operating a well or about to drill a well. At the moment, we're not operating a well, so that is not something that we're working on at the moment. But through the OSPRAG analysis that's been done on this, that will be accommodated when we do drill our next well. Also we're revisiting the last operated well that we drilled, Glenlivet, last year. We will take that information and rerun our OPEP in the light of that and see what we could have done differently, what will be done differently next time. So we're fully aware of that. In terms of all bases being covered, I agree with the other comment that was made earlier about the risks of not doing that being so high that we are, as an industry, checking things through extremely thoroughly, more vigorously than ever. Every eventuality —can we imagine what that might be? Possibly not, but we're modelling every scenario and we, as a partner of both Chevron and Total, are also, with extreme rigour now watching what they're doing to make sure that our interests are covered as well and we've been very satisfied to date. Q239 Sir Robert Smith: If you're drilling a gas well, what kind of pollution concerns would you have compared with drilling a mixed well or an oil well? Mr Festor. Laggan-Tormore is going to be gas production. So the problem of having a blowout is not very much different than what you have when you drill an oil well. But in case you have one, the treatment is completely different because you would not have a spill of the type you had on Macondo. You would have gas bubbling through the seawater and you would have, of course, what we do not like: greenhouse gas emissions. But the problem of treating a spill would not exist because these kinds of wells are producing very little liquid, very light liquids, which would evaporate very quickly in the conditions of West of Shetland. So for Laggan-Tormore, it's not so much a concern. The concern would be: how can we close the well. To come back to the fundamentals, Macondo has fundamentally nothing to do with Deepwater. The real problem is a problem of well control, so somewhere the operator has lost the control of the well. This can happen on an onshore well. On any well you drill, if you are not careful, this can happen. The best we can do is prevention. And prevention is the capability to be sure you have barriers avoiding what happened in Macondo. You come back to the fundamentals of drilling. You have two barriers, one is mud and one is the BOP, and I think the big lesson for all of us is to come back to fundamentals: make sure at any moment we have the two barriers; make sure we have the competent people understanding what is happening with your well; make sure your BOP is working. It's something we all know in our industry but, okay, we have been reminded how important it is to permanently have two barriers working. If one is not working you are in a • E Energy and Climate Change Committee: Evidence Ev 41 26 October 2010 Mr Roland Fester, Mr Richard Cohagan and Mr Brent Cheshire downgraded situation and you have to find a second barrier. Whatever the type of wells, for me these are the fundamentals and we are completely mobilised — and I am sure my colleagues are also —in our procedures, in our operation. Everywhere we have a well, we have those two barriers. Q240 Dr Lee: Moving on to the prevention is better than cure line, Mr Cohagan, you mentioned the Bly report. Were you surprised that a proper root cause analysis was omitted from that report? Mr Cohagan: I think the Bly report is the first report that we're going to be seeing. There's going to be a number of other reports that are going to be coming out from the incident in the Gulf of Mexico. I think that the Bly report has given us some information that we didn't have before that we can now take and look at and say, "Do we have all the proper actions that we can learn from that report, implemented into the wells and the way we do things?" I think you will eventually get to the point where you will see more information around what happened, different perspectives. You may eventually get a root cause analysis type of report coming out. Q241 Dr Lee: Do you think it's already taking place? Mr Cohagan: I'm sorry? Dr Lee: Do you think they've already done it, just not published it? Mr Cohagan: 1 haven't heard specifically that it will be done. I know that was a question that was asked of BP and I think that they were trying to get information out on this and sometimes the root cause analysis can take quite a bit of time to make sure you get to the bottom line. If you really want to do a thorough root cause analysis, it is a very time-consuming process. Q242 Dr Lee: It has been suggested to me that there was an absence of anybody on the well who had the responsibility to switch it off. With regards to your own, does that person exist on every well 24 hours a day, 365 days of the year? Mr Cohagan: When we drill a well, we — Dr Lee: You have your card. What I mean is, is there somebody who can say, "Right, we're stopping now"? Is there someone present on the spot in West of Shetland now who has the authority to switch it off? Mr Cohagan: We have people on the well at all times that have that ability. We have our drill site manager and the ones that we have drilling on our well right now have over 25 years' experience. They know that their fundamental job/duty is to monitor that well and, if anything looks like it could go wrong, to shut it down. So we do have that on all the wells that we drill. Q243 Dr Lee: Moving on to the response plans, it is well known and I've asked many questions about it. I've had access to the one at Macondo. May I ask a question about how you go about getting a response plan? Is this a third party company? Is this a company that Chevron or Total or BP pays somebody to provide them with a plan? Is that what happens or is it in- house? Mr Cohagan: I guess I would say it's a mutual working that goes on. We do have people from the outside that help us. We also have our own internal people that are involved with it. So we work it both ways. Q244 Dr Lee: So in terms of liability, if there are errors in those plans that then contribute towards a poor response, shall we say; where does the liability rest? Mr Cohagan: We feel that the responsibility rests with us. Q245 Dr Lee: Specifically with regards to dispersant usage, infamously being used subsea in Macondo without any apparent evidence for its efficacy — certainly not in the public domain —would you countenance doing the same thing yourself if you had a spill? Mr Cohagan: I think if we had a severe spill that was of the magnitude that the Macondo spill was, we would bring to bear everything we could and, if we thought subsea dispersant would be something that would be a positive attribute to help disperse it, we would bring that forward. I will say though —and it has probably already been pointed out —in West of Shetland, with the wave and the wind action, there is a much more physical break-up of any oil spill that would occur, relative to a place like the Gulf of Mexico. That would have a positive effect. You have the negative effect of colder water but the positive of more aggressive wave action. Q246 Dr Lee: Have you had discussions with relevant authorities here that that would be your intention? Have you said that to the agencies we've just spoken to? Mr Cohagan: 1 think that in our oil spill emergency plan, we've identified that as a possibility. I don't think we have actually said that's what we would do. I think we would be looking at it on a case -by -case basis. I will say that with the work being done by OSPRAG with looking at a capping stack if there's a problem, the work that BP has done in bringing over two containment caps in case there's a problem, there will be the ability to apply dispersant down -hole if that is something that people decide is the right response to it. Q247 Dr Lee: Just one final question on a broader issue. Is there anybody on the boards of Chevron and Total who have an environmental consultancy background? Mr Festor: In Shetland, we are drilling gas wells fundamentally. So we have not had so much concern in respect of the consequences of big oil spills because, with what we have to manage today, as I said before, we would not be in the situation where we could have to face this kind of spill. Q248 Dr Lee: So that's a "no", yes? Mr Festor. Sony? Dr Lee: That's a "no", is it? • • Ev 42 Energy and Climate Change Committee: Evidence 26 October 2010 Mr Roland Fester, Mr Richard Cohagan and Mr Brent Cheshire Mr Cohagan: I will say, from the Chevron side that I'm not aware of anyone on the board but I'd have to check that. Q249 Dr Lee: Because it's interesting that we have Chevron, Total, BP —most of the oil industry, the big ones —and not one board member has an environmental consultancy background. I just wonder whether, in view of the facts —you have made reference to the huge costs of a spill —that might be something that the oil industry reflects upon. Mr Festor. I think from the OSPRAG process, the industry has really mobilised all together to implement solutions in case something happened. As Rick said, we have been working a lot on the capping system. We are also working a lot on the response in case there is a spill. Clearly, we have to recognise we were not as ready as maybe we should have been for all these kinds of questions. But I must say —and this is really something I discovered in this country —the industry has strongly mobilised, very quickly, less than a few weeks after Macondo happened. We were all together —all the operators, the coastguards, the OSV teams, the Department of Energy and Climate Change —and we have worked out a work programme. We are working on it. Of course, we are not able to give answers a few weeks or even a few months after, but what I can guarantee is that we do all we can to get the adequate knowledge to minimise consequences in case something like this happens. Again, for me, as I said before, prevention is the attitude No. I we have to demonstrate. Q250 Christopher Pincher: I think you've all mentioned the Bly report and that you've read it carefully. The Bly report says that the responsibility for the disaster lies with multiple companies and work teams and indeed, when Mr Hayward came before this Committee I think last month, he said, "I think the investigation makes it pretty clear that this was not an issue of well design; it was a whole series of failures that came together". I think Transocean would take a somewhat contra view and probably Halliburton as well. I wonder, given that there seems to be some disagreement about the conclusions of the Bly report, do you think it is appropriate that the Department for Energy and Climate Change uses that report as a basis for assessing new licences, particularly licences for deepwater drilling West of Shetland? Mr Cohagan: I think the Department of Energy and Climate Change should use all reports that come out and look at the information contained in all of it because I think there's always information from those reports that can be helpful. We have taken the Bly report and we've looked at each of the recommendations and we've compared that to what we're doing on the well that we're currently drilling — in fact, I brought a copy of that report, if the Committee would like to have it; we can leave it —and how it addresses it. I think we all have read through it. We probably all have opinions on whether everything in the report really gets to the root cause of the accident but I think we're going to continue to need to look at other reports that come out. Building on what Roland said, I will say that we are also of the opinion that if you have the right processes, the right procedures and the right well design and you do those things, you should never get to the point where you're having an issue with a spill. I think that's something that has been reinforced with the work that we've done in comparing what the recommendations were in the Bly report with what we're doing on the well that we're currently drilling. Q251 Christopher Pincher: What is your analysis of the Bly report? Do you think that the design of the well played a part in the blowout at Macondo? Mr Cohagan: 1 will say this. BP was designing the well so that they could use it as a producing well and that's one reason that they had a long string in the well. Most exploration wells that we drill —in fact all the recent exploration wells that I'm familiar with — we drill them as wells that will not be used. We will drill them, get the information and then plug them. Because of that, we use a different design in these wells. We tend to use more liners where we have larger physical barriers and multiple physical barriers from the producing formation to the surface. The design that BP had has been used successfully in a lot of wells worldwide. So I'm not saying that the design was at fault. All I'm saying is that the way we design wells, it is different. They used nitrified cement on it. We would not use that when we get into wells of this depth because of fear that the nitrogen might break out and you wouldn't have a good cement job. I think this is part of the technical issues around it that— Q252 Christopher Pincher: Can I ask why there are technical differences between what you would do and what BP does? Surely there must be one view based upon geological formations, depth of well, that should be followed rather than different companies taking their own view of what's appropriate. Mr Cohagan: I think what all companies do when they get ready to drill a well, they look at the conditions that they're drilling in, they look at what do they have —as far as whether it's water depth or the geologic formation —and, depending on what the conditions dictate, they try to design the right well for their conditions. In the case here, I think BP was trying to design the right well for their conditions. It's back when we look at it, we've said our design would be different. Q253 Albert Owen: Can I push you on that? What Dr Hayward said to this Committee was that there was a whole series of failures that came together and what was alarming —and I paraphrase —is that the industry wasn't prepared for this at that time. Mr Festor, you said basically, it's all down to how we prepare for it and then you go on to contradict yourself and say, "But we learn from disasters." Is this a disaster then or is it prevention? I'm a little confused. With regards to the Gulf of Mexico, you're saying Chevron would have done things differently. Isn't the flip side to that BP did it wrong? , Mr Cohagan: Let me say we've seen one report that has come out from BP; the Bly report, and we've looked at that and we've tried to analyse that and • • is Energy and Climate Change Committee: Evidence Ev 43 26 October 2010 Mr Roland Fester, Mr Richard Cohagan and Mr Brent Cheshire we've tried to look at how we're drilling our well versus that report. There are going to be other reports that will be coming out that will have other information, so it's very difficult right now to guess at all the things that might be surrounding the reasons for the accident. Q254 Albert Owen: I understand the sensitivity of different reports but my understanding isorrect me if I'm wrong —that your company and other companies, when they went in front of the American Senate and Congress, basically said it wouldn't happen to them. That was what we took from that. Therefore, did the industry have serious faults that are now being rectified when it comes to deep drilling? Mr Cohagan: I believe what our company said is we would have designed the well differently and, with the design that we have for our well, we don't think we would have seen the problems that Macondo saw. Mr Festor: I can just confirm what Rick said. The Macondo well, if it has to go through the technical references of Total, the design would have been different. It's a high-pressure well. We would have drilled top of the reservoir, set the casing and then set the liner for the reservoir. Secondly, we would not have used the type of cement BP has used, which was quite a very big surprise for us when we saw the type of cement used. I do not know what the organisation of BP is but cement has always been a top technical, important point in our organisation. In Aberdeen, I have three cement engineers and I have one cement specialist on each of our platforms. I do not know if that is the case of BP, but it has been quite a surprise for us that they used this kind of nitrogen form cement in front of a high pressure reservoir. The next point is that we would never have considered that the cement in the shoe trap of a well is a barrier. So there are several points that we do not know why but that should not have been in the design if we had had to design this well with our organisation. Now, I have worked with BP several times in my life. It is a reasonable and good company but, okay, this happened. Why, I do not know, and we are also waiting. We saw the Bly report. We would like to see the Transocean report and we would like to see the Halliburton report before having a final comment on why Macondo happened. Q255 Chair: Do you have a comment, Mr Cheshire? Mr Cheshire. We don't operate outside of Europe, so familiarity with the Gulf of Mexico is not something, from a company point of view, that we have. In terms of our procedures and design, given where we operate, that would not be the way that we would design a well. But that's driven largely by the geological conditions and the subsurface pressures and temperatures that we encounter particularly in the West of Shetland. What I would also say —and I think it's very important —is that when we design a well, we also have the independent well examiner; we have our own procedures; we have an independent peer review within our own company of specialist drilling engineers to check our design by the people who've done it; we have the independent well examiner and then we have the HSE. I'm confident that that well design would not have got through that procedure in the UK system. Q256 Albert Owen: One final point, if I may, Chair. Do you think the whole licence regime will now change as a consequence of what happened in the Gulf of Mexico? Mr Cohagan: The licence regime here or in the Gulf of Mexico? Albert Owen: Both. Will we learn from that and will it change there and will we learn from it here? Mr Cohagan: Based on what I'm hearing, it sounds like there is a high probability that the regime is changing in the US and will continue to change as they try to learn from this and implement. I think the fact that the UK regulatory and licensing system is being referenced over there to a great degree is, "Here is where you have had success of not having issues", and I think they are looking at that to say, "How much do we want to follow along with what places like the UK and Europe are doing?" As far as here is concerned, I think —again, it has been alluded to earlier —that the regulatory agencies here are always looking to what they can learn from it and if they think they need to modify and change, I think they will. Having said that, it is a very robust regime here that has worked extremely well and I think most of what we are seeing is other people trying to copy what is going on here. So I think if there are changes, I hope everyone will be able to have that discussion and make sure the changes are for the benefit of the industry and the public to make sure that we do the right thing there. Q257 Albert Owen: Do you agree, Mr Festor? Mr Festor: I fully agree with what Rick said. The approach we have in this country, which is a risk - based approach, requires us to concentrate on what we do. So if we are doing something, we have to demonstrate that what is being done brings the risk to a minimum, so you concentrate on what you do. When you have a regulation —very prescriptive, telling you that you have to do this —you have a tendency just to do this, but you are not completely sure that it is the best for the problem that you have. This is the big difference here between what I have seen anywhere else. Again what I said at the beginning, HSE is not making our life easy every day but they are of great help and each time they go offshore they bring confidence to me as managing director. Q258 Sir Robert Smith: Can I just ask on the well design —it has come up before in other evidence sessions, I mean obviously you should have batteries that work in a blowout preventer and you should test your blowout preventer—would there have been any benefit in having a second set of line shear rams or is that something that you ever do in your designs? Mr Festor: What you need is to have shear rams which shear and which work. If you have one or two what you need is to be sure that you have a system that works, and here in the UK it is mandatory to test your BOP every two weeks. So we test the BOP every two weeks. Function: does it open -close, open -close and then under pressure. So we put pressure from the • • • Ev 44 Energy and Climate Change Committee: Evidence 26 October 2010 Mr Roland fester, Mr Richard Cohagan and Mr Brent Cheshire kill line and we check all our rams every two weeks. Of course we do not shear every two weeks because this is just almost noticeable, but we check if the BOP we use is able to shear before we use it. So there are two ways to do that. You have document certifications giving you the guarantee that the BOP is able to shear or, if not —it is one of the lessons learned for us from Macondo—before we start drilling we will shear. Mr Cohagan: We also are looking at this whole issue around the BOP and redundancy, through not only OSPRAG but also OGP and the work they're doing as well as what's going on in the States. I think the thing that we are going to have to look at when we start asking those questions —the BOPS are very large pieces of iron. Some of the BOPS that we are using offshore are three storeys in height. So adding an additional line shear is not something that you do quickly. You have to look at it and make sure you understand' exactly what it would be doing. The BOPS that were used at Macondo, as well as the ones that are used here, they've served the industry well for thousands and thousands of wells. We have successfully drilled them with the BOPS, but that's not to say we can't learn and we can't also improve on it and I think that's something that's going to be looked at. We just need to do it in a way that takes into account the risk and whether there is anything that you're doing that might hurt you if you add redundancy to it. Mr Cheshire: I think that's our analysis as well. Realistically, you have to plan for the wells on a well - by -well basis what is the most appropriate risk. As Rick has just said, if you make something ever bigger it imposes extra loads on the subsurface when you're putting the casing in, when you're actually running these things. These huge pieces of equipment have to be handled on the rigs and so on. So it is possible, if it's not the appropriate piece of equipment for the specific well and it's just an extra comfort level in fact, that you are taking more risks with individuals handling these at the surface and the HSE impact of that. So it is something that needs to be thought through very carefully and, as an industry, this is exactly what we're looking at, at the moment. Q259 Sir Robert Smith: But testing and making sure it actually works is the fairly obvious thing that goes on here that should be going on. Mr Cheshire: Yes. Mr Cohagan: And we do. We spend quite a bit of time trying to do exactly that. We were bringing the Stena Carron, the drill ship that's currently drilling our exploration well —it had drilled here in West of Shetland for three wells. We then sent it to Canada to drill two wells. When it was coming back, the BOP was tested before we ran it. We pressure tested it again. We're function testing every seven days on this well and we're pressure testing every 14 to 21 days trying to make sure. Then, in addition, we've gone back to the BOP manufacturer and we've done bench tests to make sure that it can shear when it's required to. But you're right, all those things have to be checked and checked thoroughly because they are complicated pieces of equipment. Q260 Dan Byles: I'm fascinated by this discussion about the difference in well design and I'm particularly interested to know how the local regulatory regime impacts on well design. We're familiar with the differences between the UK regulatory regime and the US regulatory regime. Mr Cheshire, I'm very interested in your suggestion that the Macondo well design would not have passed UK muster. I'm curious to know whether the rest of the panel agree with that analysis. Do you think that the Macondo well design would have been approved here in the UK under our regulatory regime? Mr Cohagan: Again, I don't know if I know enough about all the details. I've seen the one report, the Bly report, so it's a little bit difficult for me to respond. Probably some of our technical experts would be in a better place to respond to that. I will say that with the technical reviews that go on, not only similar to probably Total and DONG, Chevron also has a complex well group in Houston that does nothing but look at these wells that are very complicated to say, "Is the design the correct design for the area?" Q261 Dan Byles: I am particularly interested in the impact of the local regulatory regime on the well design, because we seem to be coming up with a picture here of different companies having a different approach to well design, but only Mr Cheshire has mentioned the impact of the regulatory regime on that well design. Mr Cheshire: Just to clarify what I actually said was that, given the geological conditions that we have and the areas that we work in, this sort of well design would not be appropriate for what has been done in the West of Shetland. But I think and what I understand from the Bly report is that there were changes to the programme and so on that would have been addressed by the well examiner and things may have been done in a slightly different way. So, as I understand it, our process —the different levels of control before you can change things or make changes to design —that is something that our system would address. Q262 Dan Byles: We have had more than one witness tell us it probably couldn't have happened here, that our regulatory regime is different. People have suggested it is better. I am just really curious about this, because most of your companies operate all around the world and I am very curious to know just how much well design varies from regulatory regime to regulatory regime; not necessarily as a result of the geographical differences but as a result of what you are and are not allowed to do. Would you say that you apply higher standards in countries where the regulatory regime demands it than you do in countries where it doesn't, for example? Mr Festor: Thanks to the help of my drilling manager sitting behind me, he is just giving me the answer to it. The standards of designing a well are much tighter here in the UK than in the US. One very fundamental difference is that when you design the casing programme of a well in the UK, you have to assume that the well is closed at the top and is full of gas, which means that the pressure that is just below the • • Energy and Climate Change Committee: Evidence Ev 45 26 October 2010 Mr Roland Fester, Mr Richard Cohagan and Mr Brent Cheshire well head is much higher than what is used in the US where you consider that half of the well is full of liquid and that the remainder is full of gas. So it is a little bit technical but when you have a column of gas the remaining pressure at the top is much higher than when it is liquid, because the weight of liquid is compensating. So in the case of the UK, it is a well full of gas which is taken in consideration to define the load that is applied on the casings. So it is a part answer to what you are asking. The standards are much more difficult here in the UK than in the US. Mr Cohagan: May I just add that Chevron, as a company, does not have a different standard depending on where we're operating? Now, there are regulatory requirements that sometimes necessitate doing things different but what we do when we look at a well, whether we drill it here or whether we drill it anywhere else in the world, we apply the same standards to that well to make sure it is drilled properly. Mr Festor. Which is also the case for Total, used worldwide. Mr Cheshire. And indeed DONG Energy. We have a standard well design which is driven from our experts in Copenhagen and that approach is taken throughout so we have one standard across all our operations. First and foremost, our well design has to pass our own internal examination and peer review process and every well we design as a project, that has five clear stages where we have independent examiners from our own company who come in and check that design and make sure it meets those standards that have been set across the company. Q263 Albert Owen: You have touched on most of the questions that I wanted to ask, but I will just ask a general question. We hear that Norway has suspended licences. What would the implication and the impact be on the UK if there was a ban, a moratorium, on licences? Mr Cheshire: Can I answer that first of all? I have spoken to my Norwegian colleagues and Norway is one of the main areas that we operate. In fact, there was no moratorium. What was stated by the Norwegian energy minister was that when he came to announce the licensing round, he wanted to fully understand the implications from the Deepwater Horizon incident, but that round was announced almost exactly on time as it would have been without that, and also the drilling has continued. I believe there are a number of wells that are going on at the moment that are being drilled. Q264 Albert Owen: Are there any new ones that have been given a licence at this moment in time? Mr Cheshire: The licensing process is ongoing at the moment. So, as we do, there is a routine time when they will be issued and that is the process that is continuing. That process has not been stopped. From DONG Energy's point of view, I think we focus entirely on the West of Shetland in the UK. If there was a moratorium, what we have seen and I think my colleagues have mentioned it, is that there is only a limited amount of equipment available that is of sufficient quality and standards to operate in this area. In addition, we try and operate at the best time of the year. When we don't and it is in the winter, things take a lot longer. What we would see is there would be a very significant delay on the ability to deliver projects —that has a very significant financial impact —and also on the ability to get the information. The knock -on effect would be quite dramatic and I think, from our point of view, it would certainly make some of the projects that we were looking at look a lot less attractive than if we lost one or two years because of that ability to have the equipment available and to be able to drill in the right weather window. Mr Cohagan: The same answer for us. I think that, when you look at the remaining resource in the UK, there are still 20 billion barrels possibly to find. A large part of that will be West of Shetland and if you did get to the point where you said there was going to be a moratorium for a period of time, I think that would have very much of an effect on the industry. When we are drilling the well that we are currently drilling, we have to contract for drill ships years in advance. We have to pay for the drill ships whether they are working or not. We have to find places for them to work. If we can't drill here it would be necessary for us to find some place in the world where they could be used. Mr Festor. Economic problems, of course, but we have to be coherent and say that safety comes before economics. But for me where it would really be counterproductive is the risk of losing the competent people because what we need is competent people and here in the UK we have very good people. But if we stopped drilling, there are plenty of places in the world where they would be welcome and if they went, to bring them back would be a very big challenge. I think it would be really very counterproductive if there was a moratorium on drilling. Honestly, I do not understand the moratorium on licences, because, okay, you don't give new licences but you continue drilling on existing licences. I do not really understand it. For me, the important thing is to keep the know-how in the country —the people who know the North Sea, who know how our operation is being run —and make sure that they do not go for somewhere else. Q265 Dan Byles: It is interesting you touching on that. Would you say that there would be an impact on UK's energy security? You referred to 20 billion more barrels potentially out there to be found. If we were to say that UK deepwater oil and gas drilling is too difficult, too dangerous or too expensive and we are not sure we want to be doing it, what sort of impact do you think that would have on energy security for the UK? Is that the sort of thing that you, as commercial companies, look at or is that the politicians' problem? Mr Cheshire. I think, if I can answer that, from a DONG Energy point of view, we are in the full energy chain. We're a power generator, power from coal and from gas. We're also the world's largest offshore wind farm installer and operator, so we've got a lot of experience about the energy balance. What I would say is our analysis, on a European basis, leads us to • ,7 Ev 46 Energy and Climate Change Committee: Evidence 26 October 2010 Mr Roland Fester, Mr Richard Cohagan and Mr Brent Cheshire believe —and this is why we are focused on gas in the West of Shetland —that that gas from the West of Shetland is incredibly important, and not only for the UK's energy security. Our major shareholder is the Danish Government. The Danish Government's view is that energy security is extremely important as well and that indigenous -sourced gas is an extremely important part of that, not least because the more windmills you build, the more gas fired power stations we need to cope with the intermittency of supply. When the wind doesn't blow, we need to be able to generate the electricity from flexible, modern, relatively green power stations —much greener than coal-fired power stations —which means new gas -fired power plants. So our own company point of view is that it is very important to have that indigenous supply to be able to literally support the move towards the green energy from wind power. Q266 Dan Byles: Obviously you are commercial companies and you don't necessarily have to worry about UK energy security. Is it a consideration that your board will ever look at, the energy security of the countries you operate in? Mr Cohagan: We look at it all the time and we like to have a balance. If you get to the point where some areas of the world are closed off it makes it more difficult to achieve that balance. So it is extremely important to us and that's one reason we have such a large operation, not only in the UK but also in Europe, and we have a lot of people working on trying to increase the supply here in the UK for that very reason. Q267 Dan Byles: Do you think there is an opportunity cost of chasing ever -deeper oil and gas when perhaps that money could have been used to invest in research in alternative energy sources? Mr Cohagan: I think there is a place for both. I can speak for Chevron. We're looking over the next three years in investing $2.3 billion in renewables and energy efficiency. So for us it's not either/or, it's that we have got to have both. It's important. Even for the foreseeable future, oil and gas are going to continue to be an important part of the energy mix, even as more and more renewables come on. I think it's something where you have to have all sources of the energy in order to get us to where we need to be to supply the world with energy. Mr Festor. We are totally in line with what my colleague from Chevron said. But you must have realised that I am French and, being French, we look at the UK and we are very jealous of the fossil oil and gas you have in your country. When you look as an engineer at numbers: yes, we need oil, gas and renewables. We need, very strongly, oil, gas and renewables. In your country, if you look at the numbers, we have already produced 40 billion equivalent barrels of oil and gas and we see remaining potential —numbers can change a lot if you are pessimistic or optimistic, but there remains 20, 25 maybe 30. So it is a huge asset you have in this country, a fantastic asset, and I think we cannot avoid continuing exploring in this country and we at Total think it is an interesting country to work. There is a strong supply chain, there is a strong and competent workforce. And so that is the reason we are here and we have never invested as much as these days in this country. Chair: We do not often hear such praise from a Frenchman, and we are very grateful to you, Mr Festor. I think we are running out of time now. Thank you very much. It has been a very helpful session from our point of view and I am very grateful to all three of you. If we have any further points obviously we will come back to you as well. • is Energy and Climate Change Committee: Evidence Ev 47 Tuesday 2 November 2010 Members present: Mr Tim Yeo (Chair) Dan Byles Laura Sandys Dr Phillip Lee Sir Robert Smith Christopher Pincher Dr Alan Whitehead Examination of Witnesses Witnesses: Mr Charles Hendry, Minister of State, Department of Energy and Climate Change, Mr Simon Toole, Oil and Gas Director, Department of Energy and Climate Change, Mr Jim Campbell, Energy Development Director, Department of Energy and Climate Change, and Mr Hugh Shaw, Secretary of States' Representative for Maritime Salvage, Department of Energy and Climate Change and Department for Transport, gave evidence. Q268 Chair: Good morning, Minister. Welcome to the Committee. Would you like to introduce your officials, please? Mr Hendry. Good morning, Chairman. Thank you very much indeed. I'm joined by Jim Campbell, who is the Director of the Energy Development Unit, by Simon Toole, who is the Director of the Oil and Gas Licensing Exploration and Development Section of the EDU, the Energy Development Unit, and by Hugh Shaw, who is the SOSREE Q269 Chair: Thank you. The Secretary of State announced in the Annual Energy Statement that the UK would undertake a full review of the oil and gas environmental regulatory regime following the outcome of investigations into the causes of the Gulf of Mexico incident. Would you like to tell us how you're getting on with that? Mr Hendry: Well, what we initially did was to do an interim assessment and to establish that we should have a larger number of inspectors and more inspections. We've therefore increased by half the number of inspectors and doubled the number of inspections, particularly focusing on the drilling operations. We have looked at the evidence in the BP internal report and have largely concluded that the measures that they have identified are things we're already doing, but we're now waiting for the further US investigations to decide whether there are any recommendations that come out of that that we should take into account. So, the full scale of the report will be done, we would expect, in the early part of next year when we have the American evidence. Q270 Chair: Right. When is the American evidence going to be published, do you know? Mr Hendry. We're hoping the presidential report should be out in the very early part of 2011. Q271 Chair: Right. So, how long after that will you want before you conclude what you're doing? Mr Hendry. We will deal with it very urgently because I think once we have the full analysis of what they believe happened in the United States people will want to know extremely quickly what steps we would plan to take here. As we've said before, we do believe the regime we have in place in the North Sea is one of the most robust in the world, and we think that we've looked carefully at that again since the Gulf of Mexico incident. So I think we would expect to be in a position to respond very quickly to the final reports in the States. Q272 Chair: You said that our regulatory regime is fit for purpose. Do you believe that extends to the liability regime? Mr Hendry. Yes, I do. I think if you look at the liability regime here, we have almost a unique relationship in the world. The liabilities regime means that by being involved in OPOL people have a guaranteed cover of up to $250 million. That was $120 million and has been increased to $250 million. If companies fall short in terms of their own cover, then others in the industry will step forward to make sure that that cover is in place. And I think we've also looked very carefully at the nature of the situation here. There are new containment facilities that would be available, which we believe in the event of a catastrophic incident would enable that to be capped or contained more quickly. We believe the location of where these facilities are and the distance they are from shore allows the time to be put in place to stop the oil reaching shore. 1n addition to that, we look at the economic activity in the north of Scotland compared to the very high levels of fishing, of the tourism industry, right along the whole of the Gulf of Mexico, which have resulted in a greater need there for greater cover. Q273 Chair: Just on OPOL, is membership voluntary or is it a requirement now of a licence? Mr Hendry: It is voluntary but in order to satisfy us that people have the cover, they can only have that by being members of OPOL. Q274 Chair: Right. That's the kind of voluntary approach I can understand. When the oil spill regulations were amended by a statutory instrument, do you think they identified clearly who the liable party would be? Mr Hendry: I think what we tried to do was provide greater clarity and 1 think what we recognised through that SI was that there was a potential loophole and we have moved to address that. The liability is quite clearly with the operator. The whole way in which • • Ev 48 Energy and Climate Change Committee. Evidence 2 November 2010 Mr Charles Hendry, Mr Simon Toole, Mr Jim Campbell and Mr Hugh Shaw the liability is established is that the operator has full liability for what goes on in their operations. Chair: Laura? Q275 Laura Sandys: I'm just interested in the well design approval process, not being an engineer but having been involved in the engineering sector in a distant way. Twenty-one days from somebody submitting a well design to you and them then being able to actually exercise and use that well design, does that seem like an adequate period, particularly when we might be working in areas that are less common and particularly when we're working at such deepwater depth? Mr Hendry: I'll ask Jim and Simon to come in, but normally what we see is an incremental change rather than a fundamentally different design that comes through. Therefore, we're not looking at something that is absolutely new, which needs to be assessed, and therefore most of the work of assessing a design has already been done historically. The sort of work that is being done and the areas that people are looking to explore and develop, then again that tends to be incremental, so that we are seeing around the world a significant amount of deep sea drilling: 14,000 wells have been drilled in deep sea water around the world and so there is significant experience in dealing with this. But let me ask Jim and Simon to comment further. Mr Toole: It's the HSE that do the well assessment and the 21 days is just a period where people have to give that much notice. I think if the HSE found they had any difficulty with the well design or if the independent assessor had any difficulty with the well design, then the period would extend until such time it was resolved. So I think that is just a sort of administrative time step. It doesn't mean that everything has to be completed within that period. Q276 Laura Sandys: In addition to that, there is also the issue of the independent assessor who is employed to look at well design and to support in many ways the company. They're both employed by the company although they're independent, but also I suppose their business is based on good relationships with the oil and gas business. Do we feel that that distance is distant enough; do we feel that that independence is institutionalised enough, or is the relationship a little bit too intimate and close? Mr Toole: Well, these are arrangements put in place by the HSE, not by DECC, so I can't really respond for them. Laura Sandys: But as the regulatory authority? Mr Toole: I can only imagine that if the HSE felt that there was too close a relationship they would do something about it. Q277 Laura Sandys: But as the regulatory authority, do you feel that that is a distant enough relationship to ensure that the assessor is truly independent and can assess risk or highlight issues of concern? Mr Campbell: Yes. I think if you look at HSE's track record here and you look at what happens in terms of an independent assessor's report, you'd feel quite comfortable with the fact that there's quite a bit of challenge in that process. I think the independent assessor is only as good as they are independent in this process, and if HSE felt they weren't doing that job they certainly wouldn't be using them. So, I think we are very comfortable with that kind of approach and, indeed, it's one the Americans seem to be heading towards in terms of their revision of their system. So, I think we can be quite confident It has worked very well over recent years. There's been 10,000 wells drilled in UKCS and fortunately we haven't had the kind of incident they had in the Gulf of Mexico. Laura Sandys: Thank you. Mr Hendry: I think one of the major lessons that we have seen from the United States' experience is that the robustness of our regime significantly depends on the separation of powers and that the health and safety is not done by the licensor. So, as a result of that, there is no commercial conflict but, more importantly, the HSE can bring together experience it has in other sectors. So, it is not purely looking at the oil and gas; it's looking at nuclear plant and a whole range of other areas. If it identifies risks and new ways of handling risk that it can adapt to other areas, it can bring that experience to bear elsewhere. I think that's one of the reasons why the Americans are now actively looking at the separation of powers that we have here. Chair: Dan? Q278 Dan Byles: Thank you, Chairman. I'm interested in the tax relief available under the field allowance. It could be said that the UK is incentivising the drilling of wells that are potentially more difficult to control than the Macondo through our tax regime. I'm interested in your thoughts on that. Mr Hendry: We believe it's absolutely in Britain's interests to get the best resource that we can out of the UKCS. We know that for the foreseeable future we're going to be using oil and gas and we're either going to be using our own oil or gas or we're going to be importing it. Therefore, it's in the national interest to develop those facilities as best that we can. Looking at how one stimulates that, we're looking at companies that generally have an opportunity to go anywhere they want in the world, and the UK regime has to be sufficiently attractive in order to bring them here. The tax regime is not a tax break; it is simply reducing the level of tax payable. So they're not getting a tax giveaway; they are actually just paying slightly less in tax than they would otherwise be paying. We think that's important to stimulate the investment in the sector. As I say, the nature of the fields here is that they're quite often more marginal; they're more difficult to work in in terms of the extent to which they've already been exploited; and, therefore, trying to attract that investment has to have the right tax signals. While it's a matter for the Treasury primarily, we broadly believe that we've got the balance right. Q279 Dan Byles: Why is it that the temperature and pressure threshold for that allowance was reduced this year? Mr Campbell: Sorry, I didn't catch that. • .7 Energy and Climate Change Committee: Evidence Ev 49 2 November 2010 Mr Charles Hendry, Mr Simon Toole, Mr Jim Campbell and Mr Hugh Shaw Dan Byles: The temperature and pressure thresholds were reduced for that allowance this year. I was wondering why that was. Mr Campbell: In terms of it's simply to make them applicable to a bigger catchment of fields. Q280 Dan Byles: So you're simply tweaking them in order to try and bring more of the available fields in the North Sea into this allowance? Mr Campbell: Yes, to exploit them. Dan Byles: And how would this — Mr Campbell. Sorry, do you want to — Mr Toole. I think the intention behind the measure is to make fields that are more costly and more difficult to develop —whether it's small fields, whether it's HPHT fields, whether it's heavy oil fields —ensure that when they're economic to develop they become commercial to develop. Therefore, we need to make sure that the catchment of fields are those that in some way the tax is holding back from development. So we don't tweak it to include as many fields as we can; we look with the Treasury —and indeed it's the Treasury that does it —at the economics of fields, we look at their commerciality, and where those two come out of balance we look at the tax system to see if it's the tax system that is causing that. Q281 Dan Byles: Is there a danger that on the one hand we're trying to incentivise low carbon technologies and then, on the other hand, because perhaps the market is getting out of kilter and suddenly more investment resources are going to low carbon, you start to incentivise oil and gas to redress the balance, and that it is a juggling act? Mr Hendry: It is a juggling act, you're absolutely right, but I think what we're looking at here is a real desire to decarbonise our society but recognising that that can only go at a certain pace. The nuclear power plants that we would hope to see built will only, for the first few years, be replacing old nuclear plants, they won't be adding to capacity. The huge rollout of renewables will be towards the end of this decade and beyond that before they can really fulfil their potential. The development of carbon capture and storage is very much in its infancy. So, in all of the terms of the options then we still see a very strong continuing role for oil and gas for some years to come. Now, we want to decarbonise that. We'll be looking at whether it's appropriate to apply CCS to gas, as we were discussing in our previous evidence session. But in the meantime we recognise that the world will significantly rely on hydrocarbons and, therefore, if we have a huge resource we should be looking to see how best we can develop that. So, we don't see a conflict between those two but we do understand that overall over time we must be decarbonising. Q282 Dan Byles: Wouldn't a better approach be to reduce the level of incentives on low carbon rather than increase the incentives for oil and gas? Mr Hendry. I think what we're trying to do is separately we need to get people to invest in the UKCS. If they're going to do that they've got to find it as a regime that is attractive to them. Sir Ian Wood, who heads up one of the major support industries in Aberdeen, said that the difference between continuing on existing policies, where he reckons there is perhaps 11 billion barrels that are retrievable, or if we had policies in place to maximise returns would be 24 billion barrels. Well, that 13 billion barrels at current prices is a trillion pounds worth of income for the United Kingdom. So this is a huge contributor to our national wealth and, as I say, the choice is do we wish to import this or do we wish to develop our own resources. We think it's absolutely in our national interest, given the safety regime that we have in place, to continue to develop that. Chair: Robert? Q283 Sir Robert Smith: I must declare my interest on the Register of Members' Interests as a shareholder in Shell. Isn't it, rather than anything, the important point that the oil and gas industry is not competing with the UK renewables, it's competing with the world oil and gas industry and, therefore, the price of oil won't be changed whether we produce much in the North Sea or not, but the jobs that come from it and the tax revenues that come from it will be lost to this country if it's imported rather than produced locally? Mr Hendry: I wish I'd put it quite so eloquently. Q284 Sir Robert Smith: I was just also remembering, wasn't the reason that the original incentive for high pressure high temperature was actually only going to likely incentivise one well in the whole of the North Sea? Mr Toole: There were representations made by industry that the original definition did not properly reflect or did not properly target those fields that had this disconnect between commerciality and economic liability, and there was a change made as you have suggested. Q285 Sir Robert Smith: Just one last thing, just to make sure it's understood: I think the Minister made the point that it's not that we're taking a great incentive compared with the rest of industry; they still pay a higher corporation tax even after the incentive. The incentive is only against some of the earlier costs until the allowance is used up and then they go and pay the supplemental corporation tax as well. Mr Hendry. That's right. They typically pay 50% to 70% tax rate on the resources that they recover. So, it's a high level of tax that is already payable. Chair: Christopher? Q286 Christopher Pincher: Thanks, Chair. Can I just step back briefly to the regulatory regime and the relative relationship between the drilling contractor and the licence holder, the operator? This description I think comes from the HSE but it says, "The safety case duty holder and the well operator must demonstrate how their safety management systems will operate together, who has primacy in an emergency and who has overall responsibility." I just wonder why that might differ from case to case. Why is it not the drilling contractor who has primary responsibility in an emergency or the operator? Mr Hendry. I think it depends to some extent on the nature of the emergency. We do have an escalation • �J • Ev 50 Energy and Climate Change Committee: Evidence 2 November 2010 Mr Charles Hendry, Mr Simon Toole, Mr Jim Campbell and Mr Hugh Shaw process that is in hand, and it might be worth bringing in SOSREP at a point to talk about his role in this respect as well. In terms of how an escalation takes place, that first of all it's noted to —well, I have it down here, sorry. The Coastguard Marine Rescue Co-ordination Centre is alerted to any spill. If it's greater than one tonne then it is alerted to the counter pollution and salvage officer and to DECC and then SOSREP is involved in setting up an offshore control unit. Then there are other elements that come into play according to if it's coming towards the coast as well. In terms of the safety mechanisms involved, then the person in charge of the rig is in charge of safety mechanisms and operational aspects. And also, before anybody can start operating they have to satisfy us that they have an environmental management system in place and it has to be there before they start operations, and in doing that we have to have third party audit of that process. We have to be absolutely satisfied that that is appropriate. They also now, as part of changes that we've made, have to look at worst case scenarios and so to have satisfied us that in the event of something going catastrophically wrong they have appropriate measures in place for handling that. Simon? Mr Toole. Can I just say that there is always one person who is responsible ultimately for safety on the rig: the OIM, the duty holder. That is usually the drilling contractor. Clearly, where you have a situation where a well has been designed by the operator and there are changes to the well design, then it is for the operator to take those through the safety process. But that's at a different level than if there is something happening on the rig that is giving the OIM cause for concern. It is his responsibility to make sure his rig is safe and under that situation he is paramount. Chair: Phillip? Q287 Dr Lee: Thank you, Chairman. Moving on to environmental regulation inspection and potential environmental impact of an oil spill specifically in West Shetland, firstly, with regards to environmental inspectors you have 10 overseeing 289 oil and gas installations on UKCS. How do you justify such a small number in relation to, say, the HSE numbers? Mr Hendry: They're doing fundamentally different roles. Ours are looking at the environmental implications and the time when that is at greatest risk is during the drilling process. The HSE are responsible for every aspect of safety on those operations for the whole of their lifetime. So, even in terms of the kitchen and the accommodation facilities and aspects like that, HSE has a role in all of those. So they have a much more substantial role compared to the very narrow role that our own inspectors have. If you look in terms of the number of wells that are being drilled at any particular one time, in a typical year we might see 24 being drilled from mobile platforms. Of those, a quarter, perhaps, are gas and of the remaining three quarters only a minority would be deep sea. So, we are going to focus attention on the deep sea drilling to make sure that there is annual inspections of those, that all of the deep sea ones have been inspected this year since the Gulf of Mexico. So we believe that in terms of the very narrow focus of the environmental work that comes under my Department we have in place an inspection regime that covers it, but the HSE responsibilities are very much wider. Q288 Dr Lee: How does DECC ensure that you have competent environmental inspectors? Presumably anybody half decent is employed by the operator, not the regulator. Mr Hendry: I think for many people they see this as a very important part of their career development. What we're looking for is somebody with an appropriate degree and five years' experience in the industry. So we have got people who have very strong practical experience of working in the industry, because it is both involving paper assessment work and then a visual inspection. So, the skills that they need to bring to that are very specialist indeed. I think absolutely many people see this as an important part of their career development. They may not necessarily believe they're going to spend the rest of their lives doing it, but it makes them better in terms of returning to the industry in due course if they've actually spent a— Q289 Dr Lee: Are there figures on retention? Do people stay for two years and then get snapped up by the operators? Mr Campbell. Well, can I say one thing? First of all, we have a very competent bunch of inspectors in Aberdeen who are all the way decent and I'm very proud of them, actually. Yes, we do occasionally get some people leaving; indeed, I think the last one left to join HSE. So we do get a bit of interchange there. We haven't had a huge turnover of staff over the last 10 years. We have employed, as you're aware, an extra additional three inspectors at the present time, so we'll have 10 altogether, taking the chief inspector into account. The other thing I should add that is of interest is that you shouldn't just see it as inspectors alone because we have over 50 people in Aberdeen that are all involved in environmental regulation in one way or another, through environmental permits, through analysis of the documents and so on. So it's slightly distorting just to see it in terms of numbers of inspectors. We do have quite a number of people looking at the environmental issues out of Aberdeen. If indeed we need some more, I'm sure we wouldn't hesitate to employ more inspectors if indeed the amount of activity and the types of activity would justify that as being the case. Q290 Dr Lee: All right. Just moving on to the oil pollution emergency plans, can I draw your attention to paragraph 72 on page 16 of your memorandum, "The plans are reviewed by DECO, MCA and relevant environmental consultees, such as the Marine Management Organisation or relevant Devolved Authority" and so on. Are we happy about how good the plans are? I draw your attention to the Macondo oil spill response plan, which I've trawled through. It's a weighty document; it's big. There are some errors in it. There is an air of cut and paste about it. Are we happy with the quality of the plans that have been submitted to us? • of Energy and Climate Change Committee: Evidence Ev 51 2 November 2010 Mr Charles Hendry, Mr Simon Toole, Mr Jim Campbell and Mr Hugh Shaw Mr Hendry: What we have required, as I was saying just now as well, was that they must now look at worst case scenarios, and historically they haven't been required to do that. We think that does make them more robust. So, in the event that there was a very large leak, how would that be managed over a period and what would the response be? We're also making that retrospective, so it's not just for new applications, this is for historic ones as well and for existing operations. I think that has, therefore, broadened the nature of this. I do come back to the fact that we do believe that we have one of the most robust regimes in the world, probably with the Norwegians. It has meant that over 40-plus years of North Sea operations we haven't had a serious drilling incident which has resulted in a large oil spill. We take nothing for granted; we're not complacent about it, but we do believe we have a very robust mechanism in place that allows the development of this sector but does it in a way that does the most to reassure the public about safety and environmental protection. Q291 Dr Lee: Just one final question: paragraph 74, "Pollution incident assessment and dispersant and aerial surveillance requirements. OPEPs focus on the worst case scenario." The Macondo oil spill response plan made no mention of the use of dispersant sub- sea, none at all. Last week, the managing director of Chevron strongly indicated that if there was a spill in West Shetland they would use sub -sea dispersant. Have any conversations taken place between DECC and Chevron? On what basis has a decision been made, if one has been made? What's the evidence? Is it in the public domain? Mr Hendry. Before issuing the licence to Chevron they had to satisfy us on a whole range of fronts, which we then went back to them in the light of the Gulf of Mexico and the BP report and asked for further answers to a range of additional questions. So, all of that will be in the public domain. But in terns of the specific question, Simon, on dispersants, or Jim? Mr Campbell. What we would do in conjunction with MCA, who are actually responsible for the oil spill clean-up and so on, is we would look at the individual case and determine what would be the best response in that circumstance. I would be able to say there is no initial view that we would use sub -sea dispersants at all and it would be through some kind of permitting process that we would allow that to happen if it was thought to be the case that that was actually beneficial. So what we would look at is what's the oil like, where is it, what are the weather conditions and so on, in conjunction with MCA, and we would use dispersants if the overall outcome was better than the oil alone. A judgement is made as to whether that's the best thing to do. Q292 Dr Lee: Yes. My point is how do you make a judgement when it has never been done before and we don't know where that oil is now in the Gulf of Mexico? BP turn up saying, "We've got hundreds of scientists doing this." I'd like to know where they're looking. You've got this huge water column. It could be dispersed everywhere. I'm hearing reports from friends that dolphins and whales are swimming off Barbados for the first time in history. I'm just wondering, it's an anecdotal report but how does one make a judgement when one hasn't — Mr Campbell. Well, I think it's accepted that it's very much at the leading edge, if you like, of how you would use dispersant. We certainly wouldn't be going there as an initial look. It's not something that we, as a permitting body along with MCA, would be using as a chosen method to do that. The MCA, along with ourselves, would be in a position to make the decisions about how a clean-up would actually be handled. Chair: Robert? Q293 Sir Robert Smith: I just wondered two things. How goal -setting is the approach to environmental pollution? Is it a similar regime as to the HSE one? Mr Campbell. It's a bit different. You appreciate HSE have the safety case where they're looking at a very clear outcome focus, where you've got a very clear outcome the well should be safe in terms of how it's used. In terms of environmental, the outcome we hope is never going to happen. They're not going to spill oil —it's not going to happen —so it's much more preventative, if you like, than the HSE approach. I think that's by its nature how it has to be because what we're trying to do is stop this ever happening in the first place in terms of the procedures, the bridging documents, the co-ordination mechanisms and so on and so forth. So we're in a different place. It's not really applicable to use the same kind of philosophical approach, I don't think. Q294 Sir Robert Smith: What have the inspectors found over the years? Have they found anything frightening or have they basically got there and found that things are looking pretty good? Mr Campbell. I'm slightly unsure how to answer that. We've had two prosecutions over the last seven or eight years, and I would think that probably a prosecution amounts to something that is quite concerning for us. But two prosecutions over the number of inspections we'll have conducted during that time I would suggest to you is not evidence of a system that is in disrepair or where something causes us a huge amount of worry over the overall process. We pick up small things from time to time and, indeed, if they were major things we would either prosecute or we would put in place prohibition notices and stop people operating immediately, and we don't do that terribly often. Usually what we do is we write people a letter around the things that we have found and then we check that they've addressed them, following that up. So that's the kind of place we're at in terms of environmental regulation. If you look at the number of oil spills over the last several years, then the number of oil spills are going down and the actual quantities have gone down year on year. So, we're an environment where historically we're an improving situation and I would have to say one where we feel quite comfortable in terms of the regulatory oversight. Chair: Laura? • • • Ev 52 Energy and Climate Change Committee: Evidence 2 November 2010 Mr Charles Hendry, Mr Simon Toole, Mr Jim Campbell and Mr Hugh Shaw Q295 Laura Sandys: Just following on from that, in your report you say there has been an increase, about a 20% increase, in hydrocarbon releases last year as opposed to years before. The issue there is what are you learning from that and what are you ensuring that HSE and also any remedial environmental impacts — what assessment are you doing of that increase and why is it happening? Mr Campbell. Well, we should avoid confusion here. I was talking about oil. Laura Sandys: Spills, yes. Mr Campbell. HSE look at hydrocarbon releases on the platform. If I can just say, regarding spills —and I'll come on to your question specifically just in a second —in 2009 there were 56 spills and six tonnes of oil altogether; in 2008, 83 spills and 20 tonnes. So you can see we're in small numbers here in terms of actual spills to the water. You're talking about HSE's hydrocarbon releases and that can be small releases of gas or whatever. It doesn't involve oil in the water. It's quite a different kind of release. Now, HSE generally take the line —and I'm not speaking for them —that that is indicative of the overall, if you like, philosophy on a platform or the overall philosophy within the basin in terms of releases, but they themselves would say that this past year has been slightly out of trend. If you look at the trending over several years then it has been going down and down and down, and this is a bit of a blip. I'm sure they themselves would say you shouldn't look at just one year. It's a very unfortunate instance and it's something that I know they're going to be looking at quite carefully but I don't think you would say from that one yearly figure that there's something here is worrying in terms of the overall approach. Q296 Laura Sandys: But the point is are you and HSE learning something from this increase and is there any trend? One of the things that was a bit concerning when we were talking to BP was they said that, first of all, the well design and the operations in the Gulf of Mexico, they believed they didn't need to look at it as a potential risk because what they decided was, "We've done this thousands of times before; there is no risk." The problem is that where we think we've got either the engineering safe, we've got the HSE inspection appropriately organised, and then suddenly within that framework we've not looked at that risk and suddenly there is some major incident. It's about revisiting some of these risks that we've actually put aside and said, "They're no longer risks." That is my concern overall throughout the whole regulatory and HSE aspects. Mr Hendry. I think there are two aspects here, one of which is what are we doing to prevent accidents happening. I think that the steps that we have taken we believe does address that. So, increasing the number of inspections, focusing on the drilling operations we believe does address that issue. The second issue is what happens if there is an accident. And what has happened since the Gulf of Mexico, we now have two containment facilities that are based in the United Kingdom in Southampton. We've got a Chevron facility that will be a capping device. So containment would reduce the flow but not completely stop it; a capping one would actually stop it completely. The Chevron facility, which is being developed for their Lagavulin development, will be a capping facility and OSPRAG is developing our own UK capping facility. So we've made very, very significant progress since Gulf of Mexico in ensuring that should an accident happen it can be contained and capped much more quickly. Chair: Christopher? Q297 Christopher Pincher: Following on from Laura's point, my question is around licensing. Back in July the Secretary of State said that in issuing deepwater licences close regard will be paid to the Bly Report. Now, the Bly Report is somewhat controversial insofar as BP and Tony Hayward have said that well design played no part in the Macondo disaster. Transocean take a somewhat different view. They say that well design was fatally flawed. We had Total and Chevron representatives in front of us last week and they made it clear that they would have designed the well differently in deep water. So, how is it possible, if this report is so flawed, that we are taking account of it in issuing licences? Mr Hendry: What we've always made clear is we would take account of all the reports. So, the first one to come out was the BP, the Bly Report, the intemal report. Then we had the presidential commission and we also had the marine board's report. There may be lessons from all of those that we can learn. In terms of the licensing that we have allowed since the Gulf of Mexico incident, it is our view that this is an important national resource, we should be continuing to develop it, and therefore the issuing of licences is something that we can do and we can do that safely. We're satisfied that the measures we have in place respond adequately to the information that we have, and we have obviously said that if there is further evidence that comes through that requires any greater tightening of those then we will take account of that and respond very quickly. Simon, you were going to make a point. Mr Toole: Can I just add that there is a lot of evidence in the public domain through the hearings and, as the Minister said, through the Salazar Report, which was the earliest one, and BP's own report. We are closely monitoring all the evidence that comes out and the picture that is emerging is there are a group of things that could have caused that problem. There is some debate about which actually caused the problem, but I think it is fairly clear what the entire group of things that could have caused the problem are and we are paying close attention to all of those in approving wells and in looking at our licensing. Q298 Christopher Pincher: And there are things such as there was one blind shear ram; there might have been more; there was no relief well. Are those the sort of things that — Mr Toole. Yes, and down to the fact whether or not the battery was charged up in the BOP. Up to the other end of it is how the drilling contractor relates to the cementing contractor who relates to the operator. There is this big picture of what could have contributed to the accident, and I think we are keeping • • • Energy and Climate Change Committee: Evidence Ev 53 2 November 2010 Mr Charles Hendry, Mr Simon Toole, Mr Jim Campbell and Mr Hugh Shaw pretty much on top of all of those features. I don't think there's a huge amount of dispute about what could have caused the accident. What is going on at the moment is a process of finding out what actually caused the accident, but we are aware of that entire class of things that could have caused the accident. Q299 Christopher Pincher: So are you considering additional precautionary measures to be put into place for deepwater wells, such as having additional blind shear rams or having a relief well drilled? Mr Hendry: We're not considering them at this stage. In response to the information that we have, we believe that we have a robust system in place and if there is new evidence that comes forward that requires us to reconsider the approach that we take here or to have additional inspectors, of course we will do that. Q300 Christopher Pincher: One last question, then. The same Department is responsible for licensing operators and also promoting the industry. Do you think it's possible in the thoughts that you have about how you can improve safety and regulation that the licensing might be split off from the promotion of the industry? Mr Hendry: I think that essentially our job is more to do with licensing than promoting the industry. It's the industry's own job to promote itself. But we do believe that within DECC we have the greatest body of expertise anywhere in government in terms of understanding the issues facing this industry and having that reporting into the Secretary of State responsible for those issues I think is the right way forward. The critical difference has been the separation of licensing from health and safety and I think that has been an integral part of the British system since Piper Alpha. It's one of the reasons why I think we have such a robust system in place in the United Kingdom and I think one of the reasons why we understand the Americans are looking at a similar separation as well. Chair: Robert? Q301 Sir Robert Smith: I suppose you always remember from the Gulf of Mexico incident the first thing that happened was the loss of life and the safety failure before the environmental impact. If you can have a safe operation it shouldn't really be impacting on the environment. Can I just tum to the role of SOSREP and maybe you could explain for us your roles and power? Mr Shaw: Good morning. The SOSREP post was introduced in 1999 and it was government's response to Lord Donaldson's investigation into the Sea Empress incident. It was felt at that time there should be a clearer management or emergency management structure in place for the UK for dealing with shipping incidents, which it addressed at that time. A SOSREP was appointed to act on behalf of the Secretary of State for Transport at that time, and in 2002 we saw that being extended into DTI, as they were then. Basically, as the SOSREP, I represent both Secretaries of State. If we're talking offshore today, I'm representing the Secretary of State for Energy and Climate Change. I'm triggered into an incident once it has occurred and that would normally be triggered by one of the DECC environmental inspectors. So I'm triggered in at the onset of the incident. My role is to monitor on behalf of the UK Government. My intervention powers, which come with the job, are triggered automatically as soon as I receive the first call. So there are no delays from that point of view. And, really, the powers give me the ability to monitor what the operator is doing by means of responding to the accident and I have the powers there to intervene. In extremis, the powers would go as far as allowing me to take overall control of the incident. Basically, the remit is to either minimise, if there has already been a loss to the environment, to try and prevent further loss on that side and stem the flow of any oil on that side where we're looking at significant pollution. Q302 Sir Robert Smith: But your involvement is after the fact. Do you have any roles in preventing the incidents before they happen? Mr Shaw: My role on the prevention side is working closely with all the operators within the UK Continental Shelf. We have a stringent exercise regime we have with operators. We have a national exercise that in the past we've been carrying out on a five yearly basis. We've now brought that forward to a three-year basis. The last exercise was in 2008 and we're intending holding the next national offshore exercise in May next year. In addition to the national exercises, we have more local exercises with each of the operators. Going back to the introduction of the Offshore Installations Regulations in 2002, at that time DTI put forward a requirement that each operator would have to carry out an exercise, at least one exercise, with the SOSREP at least every five years. So, we've been working through that process. Probably that works out on average about 15 exercises with myself a year and that has taken us a long way since the process started back in 2002. It gives us the ability to look at the level of preparedness of the operator, to recommend any changes on their side, and it has also helped us from the regulatory side. It has made our operation a lot slicker over the years in dealing with an incident. If I have an incident, I set up what we call an operations control unit and, again, as part of the exercising regime we also bring other participants into that group. So I have representatives from the Maritime and Coastguard Agency, representatives from the Environment Group. We have a liaison officer from there, so it also gives them the ability to enhance their skills and to get their staff through a training regime looking at a wide variety of scenarios. One thing I would just like to add, I think the question was covered earlier on about trends and that. We introduced the SOSREP system to the oil and gas side in 2002 and that gave the SOSREP the ability, if we had an incident, to set up an OCU on that side. Since that time there has only been a need to set up one OCU and that was actually in relation to a capsized anchor handler out West of Shetland but not for the sort of incident we're dealing with. I can give you a comparison. With the shipping side, probably on average we're probably looking at three to four • • • Ev 54 Energy and Climate Change Committee: Evidence 2 November 2010 Mr Charles Hendry, Mr Simon Toole, Mr Jim Campbell and Mr Hugh Shaw equivalent salvs each year since we introduced the system in 1999. So the bias for my role is certainly towards the shipping, and I think the figures for last year for the triggers for bringing myself in on the oil and gas side was probably just on or just less than 5% of the actual incidents I have to deal with. Q303 Sir Robert Smith: On the practice runs, though, have you got a feel of whether the UK is capable of responding to a blowout in a deepwater well? Mr Shaw. Yes. We're looking at the worst case scenario that has now come from the Gulf of Mexico. I don't think it has changed what we already had in place. I think we run a very tight centre. If we are unfortunate enough to have an exercise of any magnitude then the operator has to present its plans or its recovery plans back to myself and the team. The final decision rests with myself whether we think it is appropriate, whether more needs to be done on that side, and again I can use the intervention powers if I think they need to either take other action or they need to bring more resources in or they need to bring resources quicker to the scene if I don't feel that's happening soon enough. So I don't think the powers on my side could be any more wide-ranging than were already given to the SOSREP back in 2002 for the oil and gas. In fact, I think it is the envy of many countries around the world that the UK, back in 1999, put this system in place and I think all credit to the late Lord Donaldson to put a system in back then and it has still to this day held up to the test of time. Q304 Sir Robert Smith: One of the other things that came out of the incident was the emergency towing vessels. Does their withdrawal alter how you would be able to respond to an incident? Mr Shaw. No. I think from the emergency towing vessel it would simply have been another vessel that may have been available or not to come in and possibly help, but not with respect to looking at oil response. It was one of the secondary duties for the emergency towing vessels in the past, but we've never built it into any of the oil spill plans because there was never likely to be a guarantee of one of the ETVs being available. So it would have been an additional facility that may have been of some use but it certainly would not have any impact if we had an incident similar to the Gulf of Mexico. Chair: Phillip? Q305 Dr Lee: Can we just pop back to the offshore licensing and specifically the use of the Bly Report as a basis for assessing new well licences? The Bly Report doesn't include a proper root cause analysis. Are we happy to use it as a basis for making the assessments that you're doing for new well licences as a consequence? Mr Hendry: It has not been the basis. We have based the licensing granting based on the evidence that we have used over a significant period of time in response to the very detailed responses that the company has to provide to the department. We said we will take account of the Bly Report but that was not the building block of it. We've got a whole wide range of other issues that are absolutely instrumental to doing it. As I say, we believe that this has reinforced our view that we have a fit for purpose regime that is among the toughest in the world and should be the type of licensing and safety regime that others should be aspiring to. Q306 Dr Lee: I've been told it's impossible that BP haven't done one and they just haven't published it. In view of that, are BP applying for new well licences at the moment? Mr Hendry: BP have been issued with new licences under our licensing round last week. Q307 Dr Lee: So, it just begs the question should we perhaps say, "Publish the information you've got before you get a new well licence."? What I'm trying to get at is you're in a position of being able to try to extract information that might lead to a safer, in terms of environmental terms, regime in West of Shetland because you can force BP's hand by saying, "Well, before you get a licence let's see the info, please." Mr Hendry. Well, there's a separation, and granting the licence, which is what we did last week, is one stage in that process. They then have to come to us with a plan for how they're actually going to manage the drilling operation. That is an extremely extensive programme. It involves an enormous amount of us asking them questions, and if we're not satisfied on any of those areas we can withhold the permission to take that forward. So, that is just one stage of the process. But we're not looking at a particular set of issues for BP. Everybody has to meet the same standards for any development anywhere in the UKCS. Q308 Dr Lee: The other thing with regards to the licensing, each oil company that has come here, the boards of the companies have no environmentally trained individuals on their boards: Chevron, Total, BP. Do you think DECC might have a role in saying, "Look, guys, it's about time you at least appeared to take this seriously by having somebody on the boards of your companies that actually have the environment at the top of their list of priorities," and that you might use your licensing regime to try and influence that change? Mr Hendry. I don't think it needs to be a prescriptive approach. Sir Robert was saying earlier in terms of that it started off as a health and safety issue rather than environmental issue, and some of the most senior people in any of these companies are the people in charge of health and safety issues. They would report in directly to the chief executive and, therefore, in terms of the person who is most accountable and can most drive through relevant decisions then there is no separation of powers between them. They report directly into them. Now, I think it's for each company to decide whether they want that person to be board level or somebody who doesn't have the other board responsibilities and purely focuses on that but is accountable to the chief executive and the board. I think what every company in this sector is doing since Gulf of Mexico is reviewing their procedures to make sure that they are fit for purpose. • is Energy and Climate Change Committee: Evidence Ev 55 2 November 2010 Mr Charles Hendry, Mr Simon Toole, Mr Jim Campbell and Mr Hugh Shaw Q309 Dr Lee: Finally, on a typical rig everybody on the rig is employed by the operator; am I right? Mr Hendry: No, nothing like that. Q310 Dr Lee: No? Who isn't? Mr Hendry: It would probably be a small minority who actually are employed directly by the operator, but everybody on that rig is accountable, responsible and managed by the installation manager. But you'd have— Q311 Dr Lee: Are they all under contract ultimately to the — Mr Hendry: You'd have many contractors. On a typical rig you would have perhaps 200 people working on it. Some of those would be employed by the operator but many others would be a drilling contractor or a contractor — Q312 Dr Lee: Yes, paid for by the operator? Mr Hendry: Yes. Q313 Dr Lee: So, ultimately, the person at the top of the tree is BP, Chevron, Total, is my point. Is there anybody on there who is totally and utterly independent of the oil company? Mr Toole: Everybody on a drilling rig is paid for by the licensees, the operator, but under HSE law there is someone on there who has ultimate and sole responsibility for the safety and— Q314 Dr Lee: Who is paid for by the operator? Mr Toole: Well, yes, he'll be part of the rig— Q315 Dr Lee: I'm being pedantic because in Macondo that was the case and the rumour is that there wasn't somebody on there with the authority to switch it off. Mr Toole: But that was a different system. I wouldn't like to comment on how it was. Over here there is one man sitting on the rig who has ultimate responsibility to overrule any other person, whether it be operator or not. Q316 Dr Lee: Yes, but there is a culture potentially on a well. It's like the National Health Service —and I'm a doctor —that if there's one employer being a whistleblower is difficult; the anaesthetist in the Bristol case is now working in Australia, for example. In this sort of scenario —I know that there has been a controversy in recent months in Norway with Statoil—are we confident that there is a culture, a system whereby if somebody has a concern about a well operation that we have a system in place that they will feel confident to be able to say something without fear of never being employed in the industry again in the future? Mr Hendry: Before I last went offshore and watching the safety video that was produced by Apache, the global chairman or chief executive of Apache was saying, "If you have any concerns about anything on this rig, I don't just want you to say that there's a problem; it is your duty; it's your responsibility to say it. The crime is not reporting it rather than reporting it." That is, I think, an attitude that runs across the industry now, a real determination that health and safety comes first, their global reputation depends on how they handle these issues, and a real desire that everybody working on that installation is part of that process. I've never been involved in any other sector where safety is the absolute overriding priority in the same way as I've seen it offshore. I think that the steps that they have taken, which I think were present here already in the UKCS but certainly have been extended since Gulf of Mexico, makes it absolutely clear that anybody who sees anything that is not working as it should has a duty to report it. Mr Campbell. Can I just add I'm sure HSE must have said that they believe the culture is very different here from the culture in the States. We have safety reps; we have worker engagement all the time, and they certainly see it as quite a different environment from the environment elsewhere. People are involved. Q317 Chair: Can we move on to security of supply issues? Given that there are sharing arrangements under the IEA and the EU rules in the event of an emergency, any oil that we do discover at depth, say, West of Shetland, it will enhance collective security; it doesn't enhance Britain's security of supply? Mr Hendry: It depends to some extent who the operator is going to be, but I think that our view is exactly the point that Sir Robert was making earlier that either this is going to have to be imported from elsewhere around the world into the United Kingdom or we develop our own facilities. We think it's in our national interest to do that. Nevertheless, we are net importers of oil and gas and that is a trend that we expect to continue. Q318 Chair: But just to clarify the point, it clearly seems desirable if we've got oil in our waters that we should find it and exploit that, but in the event of an emergency we would still be required to share this resource with our partners? Mr Hendry: Under EU rules there are sharing rules, yes. Q319 Chair: Do you think that it's the aim to encourage and to incentivise drilling at greater depth? Is the Treasury here looking to a new source of revenue from corporation tax rather than anything else? Mr Hendry: I think we have a collective national interest in making this happen and that the Treasury has its interest in seeing this happen too. About 20% of our remaining oil and gas reserves are West of Shetland, so it's a very significant part of the resource that we have available to us. Based on the fact this is import substitution, it has an important role to play and also, in terms of revenue, it will generate for the Treasury, they too have an interest in this. Q320 Chair: The decline of gas production, of course, has been quite sharp, much sharper than oil. Does that mean we're going to be relying very heavily on LNG imports in the future? Mr Hendry: I think we'll be more heavily dependent on imports. That's absolutely clear. Some of that may be LNG; some of it is also pipeline infrastructure. The • • • Ev 56 Energy and Climate Change Committee: Evidence 2 November 2010 Mr Charles Hendry, Mr Simon Toole, Mr Jim Campbell and Mr Hugh Shaw development of the Langaled pipeline opened probably about three years ago. It has been a very significant contributor to that additional pipeline infrastructure. It has been looked at both with Scandinavia and mainland Europe, so we see this as being an important part of the mix. We are looking at measures to enhance the security further because I think if we are becoming increasingly dependent on it then greater storage has an important role to play in that. I was pleased last week to issue a licence to the Deborah facility, which would, if developed, by 2015 double our gas storage capability. Chair: Robert? Q321 Sir Robert Smith: Isn't one of the other advantages of incentivising domestic production the extra bonus we've now got from what has grown up in the North Sea, which is the expertise that is now exported and the skills that are used around the world from the north-east of Scotland and the rest of the UK from what we've learnt in the North Sea? By continuing to keep a home base going, we maximise the location here while increasing the potential to earn more from our exports. Mr Hendry: We undoubtedly have one of the world's leading energy sectors in Aberdeen. An enormous proportion of the global contracts for deep sea work, for remote work under water, are coming back to companies based in the Aberdeen area, north-east of Scotland. This is a huge national resource and having a domestic market as well for them to be working in is a key part of keeping them there. Chair: Laura? Q322 Laura Sandys: I'm interested in you've said to us at previous sessions that we're looking at £200 billion investment in the whole overall energy investment over the next 20 to 30 years. As we're in a global market, what is going to happen when the US enforce, as one expects, in some ways some very radical regulatory changes? Possibly very similar to the UK in our response to Piper Alpha is that they will become in some ways the gold standard for regulation and environmental certainly assessments of liabilities. Are we going to then move to meet that gold standard or are we still going to stay in our existing regulatory framework and not learn lessons or take remedial action that the US will probably no doubt adopt? Mr Hendry: We will learn from any evidence anywhere in the world. We don't believe that you actually maintain your standards by just saying, "Look, that's what we've got and we're keeping it come what may". This is a constantly evolving process and if there are new things that can be learned, we will certainly do that. So, we believe that it's to Britain's great advantage that actually we do have the toughest regime, with the Norwegians. We think that if countries elsewhere decide to come up towards that level that is desirable globally. If they decide to go beyond that level then we would need to see what we need to do to respond to that. But at the moment I think we are in a position where others are looking to catch up with our gold standard rather than setting a higher gold standard. Q323 Laura Sandys: Also the European Commission have issued some very clear statements about the liability and the ability of companies to meet their environmental liabilities over a period after a disaster. Today or yesterday BP announced good profits but also, due to the liabilities that they have in the Gulf of Mexico, they're having to sell a whole series of assets. Are we absolutely sure that we have done enough financial assessment of each company that they will be able to meet those particular liabilities and do you welcome the European Commission's announcement? Mr Hendry. On OPOL, I think that does put in place the regime that we think is appropriate because each company is required to have its own cover. In the event that that company was to fail, then the others would collectively take up that liability. So we believe that does give us, uniquely in the world, an extremely high standard of protection. In terms of the role of the EU within this, we believe that these are matters that are retained, that individual nation states are best setting their own levels, because by doing that we have been able to set these at an extremely high level. The concern that we would have about global setting of standards is that that could easily lead towards being the lowest common denominator rather than being moved upwards towards the highest level of environmental and safety protection. I think as we believe that ours is a very robust and secure mechanism then we want to encourage others to come up to that level rather than see any watering down. There is certainly a role that the EU can play in helping people understand the technologies and the approaches that are being used, but we would be very reluctant to lose control of being able to set our own standards at the level that we think are appropriate. Q324 Laura Sandys: Are you comfortable with the idea that oil and gas companies self -insure? Do you feel that that's an effective enough cushion from our perspective if there was a major environmental disaster? Mr Hendry: It depends on the size of the company. Clearly, a company like BP has shown that through self-insurance it has been able to cover the degree of the liabilities. For smaller companies involved, and particularly those that are looking at the UKCS, then they would need to look more to the market in order to get their cover. But at the same time we believe that the cost of catastrophic disaster would be more constrained here than it has been in the Gulf of Mexico. That is because now there is the capping availability and the containment availability, which is much greater than it was at the time of Gulf of Mexico, and in terns of the loss of livelihoods on the Gulf of Mexico, where many more livelihoods were affected by that than would be the case here. So, in terms of the cover, we believe the $250 million limit on that is sufficient, but that is within recognition that there is an unlimited liability for compensation and for liabilities. So the $250 million is simply a threshold, and bear in mind that most companies would then have additional insurance cover on top, which would add many tens of millions on top of that as well. • • • Energy and Climate Change Committee: Evidence Ev 57 2 November 2010 Mr Charles Hendry, Mr Simon Toole, Mr Jim Campbell and Mr Hugh Shaw Q325 Chair: When the commissioner suggested there should be a moratorium on deepwater drilling, the British Government said, "Get lost." Mr Hendry: Well, we'd never say that, but we did explain that this is a retained area. We explained the fact that this is a matter that nation states should be absolutely driving forward in that respect. We looked at the regime and in discussions that I have had with Commissioner Oettinger he recognises that the Norwegians and the British have, as I say, some of the most robust safety regimes anywhere in the world and we are the level to which others should be aspiring to move to. So, we do believe that the case for a moratorium was never established. We believe that it is legitimate to go on developing a resource of national importance and to do it in a way that is subject to the highest safety and environmental standards. So I think what we had done was to, as we discussed earlier, look at whether additional steps were necessary, and we identified some that we thought were appropriate, but within that framework it was permissible to go on permitting deep sea drilling to take place. Q326 Chair: Well, I'm sure that was a very charming and diplomatic way of saying, "Get lost." Is it the case that what we fear in Britain is if the EU starts poking its nose into all this standards will go down rather than up? Mr Hendry. That I think is always a risk with international standard setting, that when countries are themselves responsible for their own protection then they will drive standards higher than perhaps if it's being driven to a lowest common denominator level. So, I think our concern in this area is when you do have what you regard to be among the best in the world you don't want that to be undermined by any international co-ordination. You want others to be working towards that same level. Chair: Robert? Q327 Sir Robert Smith: Isn't it also the lesson from the Common Fisheries Policy that if you have the North Sea managed by a union that has a lot of countries that have no interest in the North Sea there are trade-offs in the way that is managed? Obviously, it makes sense for those that share the North Sea to share best practice and to inform each other of incidents and so on, but to have the bureaucracy of an overarching management by an organisation that isn't directly interested — Mr Hendry. We do work very closely with other countries that have a shared interest in the North Sea so that we are looking and so that I would imagine that the OSPRAG solution of a containment facility or a capping facility is something that would be shared with other countries if the need was there. I think you're absolutely right that we should be looking at how those countries that have a direct collective interest in this can move jointly, but involving countries that perhaps don't have any shoreline, for example, in setting those standards is something that could become more bureaucratic than helpful. Q328 Chair: Across the world, countries whose GDP increases tend also to increase their oil consumption. Do you think that's a sustainable trend? Mr Hendry: Ultimately not. We do know that there will be a peak oil point at some point. I suspect we won't know until well after it has happened when it was, but nevertheless we know for certain that there will be a point when the global oil availability will be in decline. I think that the International Energy Agency and Dr Tanaka has done some very useful work in this respect of saying the challenge for us is to get the consumption of oil, the demand, to start coming down before the peak and then the consumer gains the benefit. If the peak in demand is after peak production then for ever the oil companies would have the benefit. So, I think that is why we are leading, and I think many other countries are obviously working in the same respect, to try and take us towards a decarbonised society. Q329 Chair: Do you think we're moving fast enough in that direction? Mr Hendry. No, I don't. I think there's much more that we can be doing and I think we are now putting that in place. So, the £1 billion that was committed in the spending review to taking forward carbon capture and storage is part of that process. The nearly £1 billion renewable heat incentive to deal with the huge consumption of gas and oil in our homes and encourage people to look at renewable heat, the £1 billion committed to the Green Investment Bank to support investment in low carbon technologies, all of those I think are things that will contribute towards this process. So, I think historically we haven't been but I think we are now addressing those issues. Q330 Chair: The CCS is primarily going to be used for coal and to some extent for gas. We don't use much oil to generate electricity in this country. Oil is absolutely critical for transport fuels, though. Are we doing enough to wean off our dependence on oil for transport? Mr Hendry. I think it's a gradual process and so I think again it's an area where we can do and will do more. The move towards electric vehicles is something that to some extent is constrained by base load capacity. If the country switched overnight to electric vehicles, it wouldn't have the base load for being able to charge that network and operate it. So there is a natural speed at which this can happen but I don't think we're working at the limits of what that process can deliver. In terms of transportation, we're also looking clearly at things like the high-speed rail link as a Government as a way of trying to eliminate the need for so many domestic flights. 1 think that is an important part of that process as well. Q331 Chair: Do you think that encouraging or at least certainly allowing drilling in more and more extreme and deepwater conditions is compatible with the efforts we're making to try and increase our proportion of energy from renewable sources? Mr Hendry. I think it absolutely is. I think on the one side we want to move towards that decarbonised society but we know it's going to take time to get • • • Ev 58 Energy and Climate Change Committee: Evidence 2 November 2010 Mr Charles Hendry, Mr Simon Toole, Mr Jim Campbell and Mr Hugh Shaw there. So, realistically, picking up Sir Robert's point earlier, we will either meet that with domestic supply or we'll meet it with imported oil and gas. So, given that 17% of our remaining oil and gas reserves are in the deeper waters West of Shetland, that is an entirely proper area for us to be issuing licences. It is an important part of our national resource and we are keen to see that developed. Chair: Phillip? Q332 Dr Lee: In terms of the sourcing of where our oil and gas comes from, on a recent trip to Norway, I was told that the Russians flare more gas per year than Norway produces. Can we buy our gas from Norway and not from Russia as a consequence? By definition, we are reducing our carbon impact release as a country, aren't we? Mr Hendry. We do buy from Norway, and Qatar, being the primary suppliers. We get perhaps 1% or 2% of our gas from Russia. Q333 Dr Lee: In the future, it's more likely that that's going to go up from Russia, and if Iran comes on stream their infrastructure is similarly pretty antiquated. I just wonder whether we're going to end up endeavouring to have lots of wind farms but actually importing oil and gas from countries that are pumping CO2 into the environment. Mr Hendry: After you raised this at the last evidence session that I appeared at, I asked some questions in the Department on whether we can do work through OPEC on this, but, in fact, what I've established is that there is an international organisation there to try and reduce the role of flaring. Britain is playing a very active role in that work. The Russians are very actively looking to work with us to have help in reducing that. Very often it arises not because of the gas that they can't be bothered to bring it to market, but it's being produced as a by-product to the development of oil and, therefore, the infrastructure isn't in place in those locations to deal with it. But there is international co-ordination, which Britain is playing a very active role in, to try and reduce flaring globally, in Russia and elsewhere. Q334 Dr Lee: I guess my point is we will spend a lot of money on CCS; we've committed £1 billion. The danger is that we will get to a point where our oil and gas is produced as efficiently as possible. The Norwegians have. But there's absolutely no financial —because the price of gas and price of oil is set internationally. I am wondering whether on the international stage there is an argument for saying gas from Russia is more expensive than gas from Norway; it is costing more because in the longer term we've got climate change costs to deal with. Mr Hendry. The problem in many countries is knowing the exact source of where the gas has come from. There will be some fields in Russia and elsewhere in the world that are absolutely capturing the gas and avoiding flaring, but to impose some sort of levy on them equally, simply because it goes into a pipeline and one doesn't know where it has come from, it's quite difficult to see how one could implement that. So I think that's why we believe it's right to put the focus of effort on reducing flaring. I've seen a figure also that Russia flares more gas than it exports in gas to Germany, so this is a huge potential market for Russia and they are actively looking for international partners. British companies are playing a key role in trying to help them reduce that flaring. Q335 Chair: There is a report in the Financial Times today suggesting that investors in offshore wind may now be deterred by the risk that if an oil company wishes to start looking for oil in an area where they have a wind farm they may not be compensated. Mr Hendry: I think this started from a story in the weekend press that Oil & Gas UK were looking at taking legal action over their concerns in this area. They have issued a press statement categorically saying that they are not looking at taking legal action, that they're looking at working in partnership. We absolutely believe that partnership is the best way forward. We think that there is scope there for oil and gas to be developed. We also believe there is scope for a major rollout in development of offshore wind. What we would look for in these areas is to make sure that the oil companies are also looking at the interests of the offshore wind companies. I chair the Offshore Wind Developers Forum. We've had a very valuable meeting this week. There's a lot of interest in developing this in the United Kingdom and this issue was not raised at all. Q336 Sir Robert Smith: We've touched on all the incentives for production. Have you got any assessment or concerns about the current projections for production from the North Sea, whether we're further down the slope than we expected to be at this stage? Mr Hendry: I think that the response to the last two licensing rounds has been extremely encouraging. These have been two of the largest rounds we've had. The expressions of interest this year was the highest it has been for, I think, about 30 years. So we are seeing a very significant amount of interest of companies coming in, although what is very clearly changing is that these tend to be medium -size companies, which are still huge internationally but compared to the international oil giants they're the medium -size companies. I think that reflects the nature of the resources that are there. Quite often we've got people coming into largely depleted fields but who reckon they can get another 10 or 20 years of life out of that through their drilling technologies and the approaches that they will bring to it. We've got a number of new entrants; I think five new entrants have come through in the licensing round issued last week. So we've got a lot of new players who are coming in to this market on a continuing basis. So I think the level of interest that is there in the UKCS is extremely positive. Chair: Do any colleagues have any further points? Minister, thank you very much indeed, and to your officials as well. It has been a very helpful session from our point of view. Energy and Climate Change Committee: Evidence Ev 59 Written evidence Memorandum submitted by Transocean Drilling U.K. Limited 1. EXECUTIVE SUMMARY The Select Committee on Energy and Climate Change (Committee) has requested that Transocean Drilling U.K. Limited (this entity and the Transocean group of companies being referred to as "Transocean") offer comments regarding the recovery of oil and natural gas from the United Kingdom Continental Shelf (UKCS), particularly in the wake of the incident involving the Macondo well on 20 April 2010 in the US Gulf of Mexico (GOM). Transocean's comments regarding the events of 20 April are circumscribed by both pending and expected investigations and litigation arising from those events. However, Transocean is grateful for the opportunity to provide evidence to the Committee and offer its perspective as a major contractor involved in exploration and production operations on the UKCS and the US Outer Continental Shelf (OCS). This evidence briefly outlines Transocean's and its predecessor companies' long involvement in UK offshore operations, as well as comparing UK and US GOM regulatory and operational conditions. It also describes a number of US responses to the Macondo well incident. Finally, in response to the Committee's inquiry, Transocean respectfully submits its view that the offshore safety and environmental regulations regarding oil and natural gas production are "fit for purpose" and offers a number of recommendations for the Committee to take under advisement as this Inquiry continues. 2. BACKGROUND AND EXPERIENCE OF WITNESS Paul King is the Managing Director for Transocean's North Sea Division, based in Aberdeen. This position requires the day to day management and direction of Transocean's UK operations. Mr. King's current position is the latest in a career with Transocean and predecessor companies stretching back some 35 years. After serving five years in offshore positions, Mr. King completed a further six years onshore, each in the discipline of electronics engineer. This was followed by a series of management positions, with increasing responsibility, over the next 24 years culminating in his current position. In these management positions, Mr. King spent significant time overseeing Transocean's operations in the UK (eight years), the US GOM (10 years) and Brazil (seven years), and served as Vice President of Operations in Houston, Texas for two years. 3. TRANSOCEAN's DEEPWATER ACTIVITIES IN UK 3.1 Role of Transocean in the UK's Qjfshore lndustry Globally, the Transocean group of companies employs approximately 18,000 people in more than 30 countries. Operations in the UK represent a key part of Transocean's global business strategy and the company's roots in the UK stretch back some 40 years. Currently more than 400 employees at Transocean are based in the company's UK offices in Aberdeen, approximately 1,200 employees work on the UKCS, and more than 3000 UK nationals are members of Transocean's global workforce. Transocean currently has a fleet of 17 rigs in its UK business, 10 of which are operating currently on the UKCS.' Transocean is a member of a number of technical associations active in the UK offshore oil and gas industry, including Oil and Gas UK, Oil Spill Prevention and Response Advisory Group (OSPRAG), UK Step Change in Safety, the International Association of Drilling Contractors (IADC), and the British Rig Owners Association. Transocean has played a critical role in the development of the UK's offshore oil and gas exploration industry for decades. Most notably, the Transocean Explorer was the world's first offshore drilling installation to gain acceptance by the UK Health and Safety Executive (HSE) for its Safety Case. Transocean was also the first drilling contractor to establish a fleet -wide ISO 140011 approved environmental management system (EMS) in the UK. This UK approval was the template for the EMS currently in use across the company. Similarly, Transocean's management system approved under ISO 9001 was the first in the drilling industry and remains in place for all UK operations.3 3.2 Transocean—BP Relationship in the UK Transocean and BP have a longstanding and strong working relationship, particularly on the UKCS. BP is the designated Operator of one of Transocean's offshore rigs currently located on the UKCS, the Paul B Loyd Jr. The Loyd has worked under contract to BP continuously since 1994, the vast majority of its drilling undertaken west of Shetland. ' The Sedco 711 rig is excluded from the operating rig count as it is operating West of Ireland, not on the UKCS. 2 Further information on these environmental standards is available at http://www.iso.org/iso/iso_catalogue/management_standards/iso_9000_iso_14000/iso_14000_essentials.htm. 3 Additional information on these management standards is available at http://www.iso.org/iso/iso_catalogue/management_standards/iso_9000_iso_14000/iso_9000_essentials.htm. Ev 60 Energy and Climate Change Committee: Evidence • Transocean and BP also have worked together on environmental awareness projects, most notably the SERPENT Project (www.serpentproject.com). SERPENT was the first program of its kind to marry the scientific and offshore industry communities with the express purpose of studying the ecosystem of the west of Shetland area. This program allows scientists to use Transocean's rigs in the west of Shetland area as bases of operations for the study of marine wildlife through the use of remote operated vehicles (ROVs). The program remains active to this day.4 4. THE MACONDO WELL INCIDENT 4.1 Brief Description of Macondo Well Incident Between late January and 20 April 2010, the Transocean mobile offshore drilling unit ("MODU") Deepwater Horizon conducted drilling operations at the Macondo well in the US GOM for the operator, BR On the evening of 20 April 2010, a well control event occurred at the Macondo well which led to an explosion and fire aboard the Deepwater Horizon. Tragically, the incident led to the death of 11 crew members, including nine Transocean employees. The loss of these colleagues has been painfully felt across Transocean, and underlines the necessity of our commitment to the safety of all our employees. At this time, the causes of the well control event and resulting sinking of the MODU remain under investigation and thus Transocean believes it is premature to speculate as to the cause or causes of this tragic event. Transocean has and will continue to fully assist all appropriate authorities in their investigations of the incident. As the investigations are ongoing and Transocean is involved in pending litigation regarding issues surrounding these events the company cannot comment further on those matters. 4.2 US Responses to the Incident Following the 20 April incident, numerous US federal and state agencies began to conduct response and recovery efforts at the direction of BP, the majority leaseholder and operator of the Macondo well. On 26 April, US Secretary of the Interior Ken Salazar directed that the US Minerals Management Service (MMS) conduct physical inspections of all deepwater drilling rigs within two weeks.` Since then, various agencies within the federal government also offered a number of policy responses. 4.2.1 Moratorium on Deepwater Drilling On 28 May 2010, the US Department of the Interior (DOI) issued an order suspending all new drilling operations in offshore waters deeper than 500 feet.' This significant policy shift required that offshore oil and natural gas lessees "cease drilling all new deepwater wells" and notified affected parties that MMS would not consider new drilling permits for covered activities for six months.? Following a US federal court decision striking down the initial drilling moratorium, the DOI initiated a second moratorium on deepwater drilling. This order suspends drilling operations for wells that use "subsea blowout preventers (BOPS) or surface BOPS on a floating facility."8 Partly in response to significant opposition to the moratorium due to the expected negative economic impact on the Gulf coast region, some Obama Administration officials have suggested that this moratorium may not remain in place until its 30 November 2010 expiration date.9 4.2.2 BOP Act The Committee on Energy and Commerce for the US House of Representatives unanimously passed the Blowout Prevention Act in late July.10 This legislation seeks to mandate well design and safety procedures in detail. The offshore oil and gas industry expressed significant concern over this legislation as several components of it could negatively impact the safe and reliable operation of well control equipment. As the full House sought to consolidate several pieces of spill -related legislation, some provisions of the Act were included in the consolidated bill that was passed on 30 July, including corporate certifications regarding proper functioning of all well control equipment. Similar legislation is pending before the US Senate. 4 Photos and videos created through the SERPENT Project are available at http://www.deepwater.com/fw/main/SERPENT- Project-340.1itm1. 5 For a complete outline of initial federal efforts to respond to the Macondo well incident, please see http://www.whitehouse.gov/blog/2010/05/05/ongoing-administration-wide-response-deepwater-bp-oil-spill. 6 Minerals Management Service Notice to Lessees No. 2010-N04. 7 Id. R See Department of Interior, Decision Memorandum Regarding the Suspension of Certain Offshore Permitting and Drilling Activities on the Outer Continental Shelf (July 12, 2010), available at http://www.doi.gov/deepwaterhorizon/ loadercfm?csModule = security/getfile&PagelD = 38390. 9 "White House May End Ban on Deepwater Drilling Early," The Washington Post, 3 August 2010. 10 H.R. 5626, at http://frwebgate.access.gpo.gov/cgi-bin/getdoc.cgi?dbname= Ill_cong_bills&docid=f:h5626ih.txt.pdf • Energy and Climate Change Committee: Evidence Ev 61 4.2.3 Repeal of the Vessel Owner Liability Limitation Regime Finally, the US House of Representatives also has acted to radically shift the financial structure of the entire maritime industry, including offshore oil and gas operations, under US civil liability law. Civil liability for vessel owners for death or injuries on the high seas has been in place for more than 150 years and is fundamental within the US maritime insurance industry. In fact, US law is based on historical UK maritime liability regimes. In July, the US House of Representatives retroactively removed the liability limitation regime for vessel owners for all claims arising on or after 20 April 2010." This action reverses decades of American jurisprudence on this issue. Without this limitation in place, the US would stand as the only major seafaring nation without a vessel owner limitation of liability regime. Similar legislation is pending before the US Senate. 5. COMPARING US GOM AND UK NORTH SEA OPERATIONS 5.1 General In the US GOM, a majority of Transocean's operations utilise dynamic positioning vessels in water depths up to 12,000 feet. There are fewer moored, semi -submersible rigs as compared to the UKCS and Transocean has no jack -up rigs in the US GOM. On the UKCS, Transocean's operations generally are conducted in shallower waters. Generally, UKCS drilling operations are not conducted beyond a depth of 3,000 feet. When drilling at depths of up to 2,500-3,000 feet, there are few differences in operations. Beyond approximately 3,000 feet water depths major consideration must be given to changes to well control systems and other operating issues. The UKCS is a harsher environment than the Gulf, particularly the northern North Sea and west of Shetland margins. Differences in conditions include lower water temperature, higher annual wave height and wind speed averages that create a dissimilar operating arena both technically and environmentally. Finally, operations on the UKCS occur a greater distance from shorelines than drilling in the US GOM. In some cases, drilling operations occur 150 miles offshore, and therefore the drilling operations have a reduced impact on coastal communities. 5.2 Regulatory The health and safety aspects of offshore drilling are considered one of the most highly controlled and regulated sectors of the UK offshore industry. After the 1988 Piper Alpha incident, the UK Government introduced the Safety Case regime. The Safety Case Regulations (SCR) with the supporting regulations (DCR, Prevention of Fire and Explosion and Emergency Response Regulations (PFEER) and Management and Administration Regulations (MAR)), provide a robust goal setting regime that requires all duty holders to consider the Major Accident Hazards that could occur on their installations and demonstrate how they can effectively prevent and mitigate against them. This goal setting regime ensures that constant improvements can be made in light of new technology or processes to improve safety and operations. The Safety Case is a living document that continues to evolve over the years as new information is available or elements of the rig operations change. The Safety Case is submitted by the "duty holder" to the Health and Safety Executive (HSE) who monitor regulatory compliance. In the case of MODUs, the duty holder is the drilling contractor. The Operator, as the Licence Holder, is subject to separate and additional verification requirements under the DCR in the form of well examinations, which are carried out by a suitably independent and competent person. The Operator is responsible for ensuring that all aspects of well design and well control (up to and including the BOP and well control equipment) are suitable and this is verified through the well examination scheme. The development of a well examination scheme is a continuing process and subject to ongoing monitoring and review by the Operator. The BOP and well control equipment are also included within the equipment maintained and operated by the duty holder for the MODU and are covered by the Written Scheme of Verification for safety -critical equipment under the SCR. Regulation of the BOP exists under both the US and UK regimes although, as mentioned, there is the additional cross-check in the UK under the Safety Case regime by the Operator via the independent well examination scheme. The Safety Cases produced for Transocean MODUs and the Written Schemes of Verification prepared for safety -critical equipment under the SCR complement Transocean's maintenance procedures and together provide the necessary focus and understanding with regard to equipment criticality when planning and implementing drilling operations. In addition to the health and safety legislation, there are specific environmental response requirements from DECC that provide a legislative framework under which cross industry response to major environmental incidents can be assured through the implementation of the SOSREP's powers. H.R. 5503, available at http://frwebgate.access.gpo.gov/cgi-bin/getdoc.cgPdbname = I I 1 _cong_bills&docid = f:h5503eh.txt.pdf Ev 62 Energy and Climate Change Committee: Evidence Finally, Transocean notes the important division of responsibility in the UK over the offshore oil and gas industry, with DECC having responsibility for licencing and environmental issues and HSE having authority over health and safety, including asset integrity, well integrity and systems and processes. In contrast, in the United States it was only in response to the 20 April incident and concerns over close relationships between the regulator and the regulated that a similar division of authorities is being established. 6. RECOMMENDATIONS Recognising the role of the Committee, Transocean offers the following brief recommendations as the Inquiry into deepwater drilling regulations continues. 6.1 The Government Should Allow the Investigations of the Macondo Well Incident to Conclude Before Acting There are several US federal investigations ongoing into the Deepwater Horizon incident, including a national commission created by President Obama and a formal hearing being conducted jointly by the Coast Guard and the BOEM. The US Congress has reacted to the tragic events at the Macondo well before all the facts are known and without thorough contemplation of the ramifications of changes to the offshore regime. Transocean respectfully requests the UK Government refrain from acting preemptively and await the findings of investigating authorities so any recommendations are considered, on point and proportionate. 6.2 The Government Should Not Impose a Moratorium on Deepwater Drilling on the UKCS, Particularly West of Shetland Operations in deep water on the UKCS west of Shetland have continued for 30 years with 400 wells being drilled without serious incident. As discussed above, Transocean employs state of the art safety and environmental protection technology aboard all its rigs operating around the world, including west of Shetland, and, at all times, does its utmost to comply, and where appropriate exceed, all UK regulations regarding offshore drilling operations. Regulations developed by the UK government in the wake of the Piper Alpha incident are thorough, appropriate and fit for purpose. Transocean welcomes the revised inspection schedule required by DECO but feels at this point no further • regulatory action is necessary. The industry is continuously reviewing standards to ensure all operations and practices are as rigorous as possible to promote safe and secure drilling on the UKCS. To that end, OSPRAG, created by Oil and Gas UK with participation of the HSE, is working to "provide a focal point for the sector's review of the industry's practices in the UK, in advance of the conclusion of investigations into the Gulf of Mexico incident." A moratorium on deepwater drilling in the UK would not result in safer offshore UKCS oil and gas operations, and ultimately would have negative consequences for the economy directly impacting tens of thousands of jobs. Arguably the risks of drilling in deep water are no greater than drilling anywhere in terms of the controls, vigilance and expertise required. Recovering from a serious loss of control or spill in deep water does have a greater degree of difficulty. In short, the prevention measures are the same irrespective of water depth. 6.3 The Government Should Not Create a De Facto Moratorium Actions taken by the Government which create an uncertain business climate for offshore exploration and production would impose a de facto moratorium severely limiting resource recovery from the UKCS. Transocean briefly outlines actions that, if taken by the Government, would dramatically limit oil and gas recovery from the UKCS. 6.3.1 The Government Should Not Take Action That Could Raise Insurance Requirements to Unsustainable Levels Were the UK Government to take any action that could raise insurance rates for offshore industry participants, the number of companies, particularly smaller independent oil companies, able to maintain their insurance could be significantly diminished. In turn, many of these smaller companies would be compelled to dramatically curtail or suspend altogether their operations on the UKCS. Losing these smaller companies, many of which are key components of the offshore industry, would cost well -paying jobs for the UK economy, particularly in the Aberdeen area. 6.3.2 The Government Should Continue to Permit International Flagging of Vessels On 30 July 2010, the US House of Representatives passed legislation imposing a requirement that all offshore drilling vessels operating on the OCS must be flagged in the US. If enacted into law, this requirement would cause significant disruption to operations on the OCS, weaken US energy security, and represent a shift in the global maritime industry. Importantly, a switch to local flagging would not create increased safety requirements or lead to a safer industry. Vessels are frequently flagged in a select few countries for purposes of logistical convenience, not for financial gain or reduced regulatory obligations. There is no material difference in safety or Energy and Climate Change Committee: Evidence Ev 63 • environmental protection between vessels flagged in these countries' ports and vessels flagged in the UK. Vessels flagged under these registries must undergo rigorous inspections before and during their operations within UK waters as required by HSE and MCA under the Written Scheme of Verification. Transocean's MODUs are inspected by Class Societies, including ABS or DNV, and the Class Society requirements would be the same irrespective of Flag State. Transocean respectfully recommends that international flagging for offshore drilling units and support vessels continue to be permitted. 7. CONCLUSION The tragic events surrounding the Macondo well incident of 20 April 2010 provide a sobering reminder of the difficult challenges in recovering natural resources in offshore areas. However, the safety record of the offshore industry in the UK over the 20 years since the Piper Alpha disaster demonstrates that with proper safety precautions and adequate training, drilling operations can be completed successfully and in a safe and environmentally responsible manner. Transocean appreciates the opportunity to offer this written evidence to the Committee and stands ready to assist the Committee as this Inquiry continues. September 2010 Memorandum submitted by Oil and Gas UK 1. EXECUTIVE SUMMARY 1.1 The UK regulatory regime is robust and fit for purpose. The offshore oil and gas industry in the UK is controlled by comprehensive, rigorous environmental and safety regulation, enforced by competent regulators. 1.2 The UK safety regime is fundamentally different to that in the USA with a clear separation in • regulatory function between licensing (Department of Energy and Climate Change) and safety (Health & Safety Executive). A goal setting rather than prescriptive philosophy is delivered through the safety case to ensure that major accident risks are evaluated and controlled. The safety case regime obliges the UK industry to review its existing arrangements in the light of new information, eg the Macondo incident. 1.3 Further restrictions on drilling in the UK would be unwarranted and, in holding back development in offshore areas, would be deeply damaging to the national economy, hitting investment, jobs, security of primary energy supply and Treasury revenues. 1.4 We believe the risks involved in drilling on the UK Continental Shelf (including deeper water) are well understood; there are effective multiple barriers in place; a high degree of workforce engagement; and a strong safety culture. 1.5 However, the UK offshore oil and gas industry is not complacent. It is working with its regulators and the trade unions through the newly formed Oil Spill Prevention and Response Advisory Group (OSPRAG) to review current practices and procedures. It is also liaising with industry bodies worldwide and will implement relevant lessons learned from the Macondo incident. 1.6 The UK will be dependent on oil and gas as its main source of primary energy for decades to come. Any loss of indigenous UK production would result in more imports from potentially less stringently controlled producing regions of the world. 1.7 Additional EU level regulation would add no additional value and has the potential to complicate and confuse. 2. OIL & GAS UK Oil & Gas UK is the leading representative body for the UK offshore oil and gas industry. It has over 100 members comprising the major multi -national oil and gas companies, smaller specialist producers and explorers as well as large contractors and SME suppliers active across the UKCS. 3. KEY FACTS ABOUT THE UK OIL AND GAS INDUSTRY In 2009, this industry: 3.1 satisfied some two thirds of UK primary energy requirements; 3.2 was the largest investor and the largest contributor to the UK national gross value added (GVA) among the industrial sectors of the economy (total expenditure was £12.3 billion); 3.3 supported almost half a million high value, highly skilled jobs across the UK; 3.4 contributed around 20% of the UK's corporation tax bill (£6.3 billion in tax revenues rising to an estimated £9.4 billion in 2010-11); Ev 64 Energy and Climate Change Committee: Evidence 3.5 boasted a world leading supply chain, which not only services the UKCS but also exports oilfield goods and services across the world worth £5 billion per annum; 3.6 generated further revenues from the supply chain through corporation and payroll taxes (an estimated £5-6 billion in 2009). Please refer to Annex 1 (Oil & Gas UK 2010 Economic Report) for additional facts and figures. EVIDENCE ADDRESSING QUESTIONS POSED 4. To what extent would deepwater oil and gas resources contribute to the UK's security of supply? There is no agreed definition of deepwater in the UKCS or worldwide. As technology has evolved over time, it has allowed the industry to exploit resources in ever deeper waters with confidence that the risks remain effectively managed. 4.1 The UK's indigenous oil and gas resource, located essentially offshore, has a crucial role to play in helping to secure the UK's future energy. Oil and gas will continue to dominate UK energy supply for many decades to come. Hydrocarbons currently provide 75% of the country's primary energy. Even upon full achievement of Government targets for renewable energy (renewable sources to provide 15% of primary energy in 2020), 70% of our primary energy in 2020 will still need to be found from oil and gas. Furthermore, with oil dominating transport needs and gas for heating, demand will only decline slowly through to 2050. 4.2 The UK's estimated remaining hydrocarbon resource is up to 24 billion barrels of oil and gas, 10 billion barrels of which are yet to be discovered. Provided investment can be held at £5-6 billion per annum, the decline in UK production could be slowed to a gradual 5% per annum. This means that the UK could still be producing oil and gas in sufficient volumes in 2020 to satisfy half of the UK's oil and gas demand. 4.3 DECC data show that circa 2.8 billion barrels of oil equivalent (boe) of the UK's currently discovered oil and gas reserves lie in deeper waters. It is estimated that around 3.3 billion boe of the UK's yet -to -be - found oil and gas resources will be discovered in these waters. 4.4 The UK industry already safely produces substantial quantities of oil from these deeper waters and in 2014, it will start producing gas in significant quantities for the first time, demonstrating the potential of • the west of Shetland basin: (a) Production from the three existing oil fields west of Shetland (Foinaven, Schiehallion and Clair) is currently around 114,000 bpd (barrels per day), representing about 9% of total oil production from the UKCS. (b) The £2.5 billion investment to develop the Laggan-Tormore fields will result in the production of some 30 bcm (billion cubic metres) of gas, plus some oil, from the largest gas field to be developed in over 10 years. (c) Furthermore, the infrastructure put in place to develop Laggan-Tormore will secure the installation of the first major gas pipeline from the area to the British mainland, opening up opportunity for further gas and joint gas and oil development in the basin. This new pipeline will be built to deliver far greater volumes of gas than that needed for Laggan-Tormore, providing sufficient capacity to satisfy up to 8% of UK gas demand. 4.5 Oil & Gas UK estimates that over the next five years, production from new and incremental projects west of Shetland could amount to approximately 314 million boe; a moratorium on deepwater drilling in the UK would, at best, delay these projects and possibly put a freeze on them altogether. It would also stifle exploration, which would have a knock -on effect for future production. 5. Is deep water oil and gas production necessary during the UK's transition to a low carbon economy? 5.1 All resources, not just those in deeper water oil and gas production, will be essential for UK security of energy supply during the transition to a low carbon economy as this transition will not happen quickly, nor will it be absolute. We see oil and particularly gas as a key part of any low carbon economy. See section 4. 5.2 Harnessing the oil and gas potential of the deeper waters west of Shetland will bring other long-term economic and social benefits: (a) Without strong indigenous oil and gas production, any transition will be more costly and therefore possibly slower as the UK will have to pay for a much greater proportion of its oil and gas in imports to meet its energy requirements, with consequential serious impacts on the nation's balance of trade. (b) Currently there are almost 20 companies with interests in the west of Shetland basin and 50licences. • Oil & Gas UK has identified future projects on nine existing or new fields in the area awaiting the green light for development. These interests represent considerable economic potential for the UK. (c) The substantial investment required for further exploration and development in the deeper waters west of Shetland will provide highly skilled, well -paid employment in the UK oil and gas industry supply chain. It will also create an engine for the development of new exportable and transferrable C7 Energy and Climate Change Committee: Evidence Ev 65 technologies. The further opening up of the North East Atlantic will therefore allow the industry to continue helping the country to strengthen its manufacturing and skills base whose output can be exported and transferred to the benefit of the nation. (d) Future oil and gas production will earn the UK Exchequer valuable revenues, and generate taxes from companies in the busy and successful supply chain, helping to strengthen the country's finances. 6. What are the hazards and risks of drilling west of Shetland? 6.1 The UK's goal setting safety regime requires a systematic approach to the identification of hazards and through the application of quality engineered solutions and systems ensures that risks are reduced to as low as reasonably practicable (ALARP). The approach taken west of Shetland is no different, albeit some of the hazards may differ. 6.2 What is considered to be deep water has changed over time. The North Sea, for example, with a water depth range of approximately 100-700 ft, was considered to be deep water 30-40 years ago. Depths west of Shetland vary from approximately 500 ft to 6,000 ft plus. 6.3 Since the start of UKCS operations in the 1960s, almost 11,000 wells in total have been drilled, of which around 400 have been west of Shetland. Of all the wells drilled, 330 were in more than 1,000ft of water; 284 of these located west of Shetland. The deepest well was in just over 6,000ft of water, drilled near Rockall in 2001. 6.4 The particular challenges of deepwater drilling west of Shetland relate primarily to the area's physical environment and remoteness. The area encounters long Atlantic swells and heavy seas. Currents are complex and fast; depending upon the location, they can vary in direction and speed at different water depths. The weather, especially during winter months, can be severe and lead to the temporary suspension of operations. 6.5 The above factors make open water operations west of Shetland complex, necessitating the design and deployment of sophisticated, specialist equipment. • 6.6 Other factors which must be considered include well depth and the geology of the rock formation, but these are not unique to the west of Shetland. 6.7 The following section (section 7) describes the safety and environmental regime for the UK offshore oil and gas industry, including the process of well design, examination and independent verification by a competent person. This section summarises how the risks associated with drilling are managed. The same procedures apply to the west of Shetland as to any other region of the UKCS: (a) Well design: under the Offshore Installations and Wells (Design and Construction) Regulations 1996, all UK well operators must ensure that a well is so designed, modified, commissioned, constructed, equipped, operated, maintained, suspended and abandoned that: — So far as is reasonably practicable there can be no unplanned escape of fluids from the well; and 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. (b) Selection of drilling rig: the selection of the right drilling rig is essential. Dynamically positioned (DP) rigs are typically used in water depths greater than 1,000ft and use sophisticated sensors, together with their own thrusters and propellers, to maintain position and heading. Water depth and deepwater currents have impacts on all aspects of riser operations (risers provide the linkage between the top of the wellbore and the rig). These must be carefully planned for and managed, particularly in the event of a disconnect. (c) Primary well control: the first line of defence is provided by managing the drilling fluids (known as "muds") injected into the borehole to maintain sufficient downward pressure in the well. Robust planning, design and execution of the well are essential, and contingencies must be in place to contain pressure in the well in the event of the riser being disconnected. (d) Secondary well control: during drilling operations an influx of hydrocarbons into the well bore can happen. Primary well control is re-established by operating the blowout preventer (BOP), which is a large, mechanical device designed to monitor, control and, ultimately, seal off the wellhead to bring the well under control and prevent a blowout. As BOPs are safety -critical, the UK regulations require that they are regularly inspected, tested, maintained and independently verified as fit - for -purpose. . (e) Tertiary well control: In the unlikely event that secondary controls fail, the industry's primary means of tertiary response is the drilling of a relief well to intersect the damaged well in order to kill it, and to respond to the environmental and economic impacts of an oil spill through surface clean-up operations. Additional enhanced tertiary controls such as those seen deployed on the Macondo well, are being considered through OSPRAG's technical review group. • Ev 66 Energy and Climate Change Committee: Evidence 7. To what extent is the existing UK safety and environmental regulatory regimefit for purpose? The UK regulatory regime is robust and fit for purpose. The offshore oil and gas industry in the UK is controlled by comprehensive, rigorous environmental and safety regulation, enforced by competent regulators. 7.1 Safety 7.1.1 Following the Cullen Inquiry into the Piper Alpha disaster in 1988, the offshore safety regime was revised through a consultative process involving expert representatives from the industry and workforce. The outcome included a separation of regulation of operations and safety (now resting with DECC and HSE respectively) and a suite of offshore -specific regulations addressing: (a) Prevention of fire and explosion; (b) Securing effective emergency response arrangements; (c) The integrity of offshore installations and wells; (d) The requirement for independent competent checks that safety -critical systems are and remain fit - for -purpose; (e) Workforce involvement (through safety representatives); and (f) A requirement for a safety case for all offshore installations (including mobile drilling rigs). 7.1.2 The regulatory framework sets objectives to be achieved (goals) without prescribing how to comply. This is fundamentally different from the US regime and means that the precautions to be taken must show that the risks are as low as reasonably practicable (ALARP). In addition, as new information or safety - enhancing technology becomes available, the industry is obliged under the safety case regime to review its existing arrangements so that risks remain ALARR 7.1.3 Compliance with the law is based on conformity with recognised good industry practice, including: (a) HSE approved codes and guidance; • (b) UK and international standards; and (c) Guidance agreed by relevant trade bodies. 7.1.4 An HSE accepted safety case is required for all installations before operating (including drilling) on the UKCS. For the safety case to be accepted, it needs to demonstrate that the company management system is adequate to ensure legal compliance; that there are arrangements in place for auditing the safety management system; that there has been a detailed and systematic approach to the identification of all hazards with the potential to cause a major accident, and that all the major accident risks have been evaluated and measures taken to control those risks to as low as reasonably practicable. A blow out is a recognised major accident hazard. 7.1.5 Specific safeguards for wells: (a) Well notification system—HSE must be advised at least 21 days in advance of drilling/well intervention activities. HSE wells specialists can review the well design and execution plan, and require amendments if necessary; (b) The requirement for the well design and construction to be examined by an independent and competent person (eg experienced drilling engineer); (c) Verification by an independent competent person (eg Lloyds or DNV) of the initial suitability and continuing good repair and condition of safety -critical equipment involved in drilling (eg BOP); (d) Weekly drilling reports sent by operators to HSE, enabling HSE wells specialists to identify and respond to changing risks; (e) Requirements that workers involved in well operations are suitably informed, instructed, trained and supervised; and (f) HSE inspectors test the veracity of the information received through their prioritised inspection and intervention programmes. 7.1.6 The UK industry has an established safety culture and demonstrates a mature and responsible approach to safety issues. There is a strong track record of collaboration with regulators, the trade unions and the workforce to share lessons learned and improve practice, as exemplified by the creation of Step Change in Safety in 1997, the Helicopter Task Group, the response to the HSE's KP3 and KP4 reports and • OSPRAG, in response to the Macondo incident in the Gulf of Mexico. 7.1.7 Since the creation of Step Change, there has been a marked improvement in the offshore oil and gas industry's overall health and safety performance. The industry has today one of the lowest non -fatal injury rates in the UK and is safer than agriculture, construction, manufacturing and even the wholesale/retail and public administration sectors. • Energy and Climate Change Committee: Evidence Ev 67 7.2 Environment 7.2.1 The UK offshore industry is subject to stringent international, EU and UK environmental controls, which lay down the requirements for consents, permits and environmental reporting (as well as the limits for discharges and emissions), inspection, investigation and enforcement. Central to this is the requirement for all operators to have an independently verified Environmental Management System in place, which ensures that appropriate control measures are applied. 7.2.2 The regulations require every offshore operation, including exploration drilling to have an approved Oil Pollution Emergency Plan (OPEP), approved by DECC in consultation with specialist advisers. These are tailored to location and the environmental and socio-economic sensitivities within a potential impact area; updated as required; and exercised periodically. Specific spill response is provided by specialist contractors from common resources, supported by additional local resources where required. Response personnel are appropriately trained through accredited courses. 7.2.3 The industry in the UK has the services of Oil Spill Response (OSR) available to it. This was established as an industry cooperative in 1985 to provide a dedicated and shared oil spill response capability for UKCS offshore operations. 7.2.4 Companies in the UK are responsible for environmental or other damage if their installations fail. There is no legislative cap on a company's responsibility for clean-up and compensation. However, in the event of a default on payments, under a mutual agreement established in 1975, administered by another industry cooperative, Offshore Pollution Liability Association Ltd (OPOL), the rest of the industry will step in to pay third -party costs up to a limit of $250 million. 8. What are the implications of the Gulf of Mexico oil spill for deepwater drilling in the UK? 8.1 While investigations into the Macondo incident continue, it is too early to draw final conclusions into its causes. However this has not stopped the industry from taking action. 8.2 The Gulf of Mexico incident obliges the industry to reconsider the worse case scenarios and demonstrate to the satisfaction of all its stakeholders that it is competent to drill all targeted reservoirs on the UKCS and has the capacity to respond effectively to a loss of well control and to any resultant oil spill. 8.3 The formation of OSPRAG in part responds to that requirement. It is currently engaged in assessing the UK's strengths and reviewing possible enhancement, including how additional well capping and control techniques might be developed and related oil spill response mechanisms extended. 8.4 This work is going ahead in advance of the publication of the investigations into the Macondo incident but will, nevertheless, be ultimately informed by these findings. It is therefore important that OSPRAG be given space to deliver and its recommendations not be pre-empted. 8.5 It is our belief that to impose a moratorium on deepwater drilling or additional regulatory burden on the UKCS would be unwarranted and unjustifiable. The risks involved in drilling in the UKCS (including in deep water areas) are well understood, there are effective multiple barriers in place, a strong workforce engagement and safety culture, together with a robust regulatory regime, which is enforced by competent regulators. 8.6 Furthermore, an additional layer of regulation at EU level would add no additional value to the existing robust process in the UK, other than more bureaucracy and the potential to complicate and confuse. September 2010 Memorandum submitted by the UK Oil Spill Prevention and Response Advisory Group (OSPRAG) 1. INTRODUCTION: OSPRAG 1.1 The Oil Spill Prevention and Response Advisory Group (OSPRAG) has been convened as a proactive initiative to review oil spill prevention and response arrangements in the UK and ensure they continue to be fit for purpose and enhanced where appropriate. OSPRAG comprises senior representatives from relevant UK regulators, the trade unions, the directorate and individual members of Oil & Gas UK, - including oil companies and drilling contractors, and seeks to identify and address cross industry issues arising from the Gulf of Mexico incident in the UK continental shelf (UKCS). 1.2 OSPRAG has also established active liaison with European, American and international regulatory, technical and industry bodies and acts as a communications focal point for sharing information across the UK offshore oil and gas industry. • Ev 68 Energy and Climate Change Committee: Evidence 2. EXECUTIVE SUMMARY 2.1 The oil and gas industry has a long history of safe drilling operations in the UK with 11,000 wells drilled in total over the last 40 years (Source: DEAL). 2.2 The oil and gas industry on the UKCS is controlled by a rigorous environmental and safety regulatory regime, the latter being built upon the recommendations of the Cullen Inquiry into the Piper Alpha incident in 1988. 2.3 The UK safety regime is fundamentally different to that in the USA with a clear separation in regulatory function between licensing (Department of Energy and Climate Change) and safety (Health & Safety Executive). A goal setting rather than prescriptive philosophy is delivered through the safety case to ensure that major accident risks are evaluated and controlled. Furthermore, the safety case regime obliges the UK industry to review its existing arrangements in the light of new information (eg the Macondo incident). 2.4 The offshore oil spill strategy is intended to provide an effective response in the seas of the UKCS, utilising the energetic nature of the UK marine environment together with the application of chemicals to enhance this natural dispersion, when necessary. 2.5 The Gulf of Mexico incident obliges the industry to reconsider the worst case scenarios and demonstrate to the satisfaction of all its stakeholders that it is competent to drill all targeted reservoirs on the UKCS and has the capacity to respond effectively to a loss of well control and to any resultant oil spill. OSPRAG aims to fulfil this requirement. 2.6 It should be noted that whilst the primary responsibility for oil spill response rests with the licensed operator, the Maritime and Coastguard Agency (MCA), through the Merchant Shipping Act (Section 293), has powers to assume control of "at sea" counter pollution operations. The Offshore Installations (Emergency Pollution Control) Regulations 2002 give the Secretary of State for Energy and Climate Change the power to intervene in an incident involving an offshore installation where there is, or there may be, a risk of significant pollution. These provisions are reflected in the National Contingency Plan (NCP). MCA is taking an active role in OSPRAG to ensure that any recommendations made are consistent with the NCP. 2.7 Work within OSPRAG is proceeding in advance of the publication of the investigation into the Gulf • of Mexico incident but will ultimately be informed by the findings. It is important that OSPRAG be given the space to deliver and its recommendations not be pre-empted. 2.8 The remit of OSPRAG is to review and make recommendations to support the provision of adequate response mechanisms for the UKCS. However, it should be recognised that some elements of the response could be developed as a result of work undertaken by other international bodies and groups with whom OSPRAG is in contact (see Section 3.6.4 below). 3. OSPRAG—IN DETAIL 3.1 As the scale and potential ramifications of the Gulf of Mexico incident became clear, Oil & Gas UK initiated the establishment of OSPRAG, with the inaugural meeting held on 2 June. 3.2 Building on a successful collaborative model previously used by the UK industry to establish Step Change in Safety and the Helicopter Task Group, the OSPRAG membership consists of senior representatives from organisations with a legitimate interest in the objectives of the group. 3.3 The membership currently consists of Mark McAllister, Fairfield Energy Limited (Chair); Department of Energy and Climate Change (DECC); Health & Safety Executive (HSE); the Secretary of State's Representative for Maritime Salvage and Intervention (SOSREP); Maritime and Coastguard Agency (MCA); Unite; RMT; KCA Deutag Drilling Limited; Transocean Drilling UK Ltd; International Association of Drilling Contractors (IADC); Oil Spill Response (OSR); BG Group plc; BP Plc; Chevron Upstream Europe; CNR International (UK) Limited; ConocoPhillips (UK) Limited; ExxonMobil International Ltd; and Total E&P UK Limited. A representative of the EU Energy Commission also attends as an observer, while a similar invitation has been extended to the Norwegian Ministry of Petroleum and Energy. The Oil & Gas UK Chief Executive and Policy Directors provide support to the group. 3.4 The agreed remit of OSPRAG is to: — Review UKCS regulation and arrangements for pollution prevention and response; — Assess the adequacy of financial provisions for UKCS response; and — Monitor and review information from the Deep Water Horizon incident and facilitate implementation of pertinent recommendations. is3.5 OSPRAG meets every four weeks to oversee and steer the work of four review groups established to undertake the reviews and assessments, as well as act upon any recommendations which may arise either from the Gulf of Mexico investigations or the work of the review groups. 3.6 The four review groups meet frequently to identify short and long term recommendations to be implemented on a cross -industry basis. These are: Energy and Climate Change Committee: Evidence Ev 69 • 3.6.1 Technical —reviewing relevant aspects of well design, examination and control in the context of preventing loss of control. Representation is from DECC, HSE, Oil & Gas UK, offshore operators, drilling contractors and offshore unions. Sub groups are assessing: — Well capping and containment; — Well examination, verification and primary well control; — BOP inventory & recommendations for improvements; — Competency, behaviours and human factors; and — Flowing well status. The Technical Review Group is preparing a report with final recommendations and a forward plan for implementation for OSPRAG approval. This will include the proposals regarding capping and containment options being developed by Wood Group Kenny and is due at the beginning of October. 3.6.2 Oil Spill and Emergency Response —reviewing spill response capability and industry co-ordination with National Contingency Plan. Representation is from DECC, MCA, Oil & Gas UK, offshore operators, drilling contractors, oil spill response specialists and environmental agencies. Sub groups have been established to undertake the work necessary to ensure that: — Oil spill models are fit for purpose for all release scenarios; — Data for offshore and onshore sensitivities are up to date and fit for purpose; — Data resources are common and readily accessible for use in contingency planning and during a response; — Response resources are sufficient, maintained and deliverable; — Oil Pollution Emergency Plans are fit for purpose for all operations; and • — A comprehensive response exercise is held during 2011. 3.6.3 Indemnity and Insurance —reviewing liability, indemnity and insurance provisions that would be invoked in the event of a spill. Representation from DECC, MCA, Oil & Gas UK, OPOL and offshore operators. The group is assessing: — Financial and administrative arrangements currently in place in the UK; — Future requirements; and — Adequacy of the OPOL financial responsibility levels. A recommendation by OSPRAG to raise the level of the limit for third party costs from $120 million per incident to $250 million has been approved by OPOL. This figure will be reviewed in the light of the outcome of spill scenarios currently being modelled. See Section 4.5.3 for further information about OPOL. 3.6.4 European Issues —acts as an information sharing and communications focal point, to ensure other relevant bodies are well informed of the work of OSPRAG, and vice versa. Representation is provided from HSE, Oil & Gas UK, international oil and gas trade associations, national regulators and trade associations from other European oil and gas provinces. The group has the role of ensuring that: — The work of OSPRAG is coordinated with activities taking place elsewhere in the world; and — Links with other European National Oil Industry Associations (NOIAs) as well as OGP (International Association of Oil & Gas Producers) through the Global Industry Response Group, IPIECA (the global oil and gas association for environmental and social issues) and the API (American Petroleum Institute) are established and maintained. 3.7 As a direct result of the effective regulatory regime there has been a marked improvement in the offshore oil and gas industry's overall safety and environmental performance over the past twenty years. Oil spills that do occur are small and do not have a significant environmental impact. For example, in 2008, from a total production of approximately 66,212,848 tonnes of oil, 36 tonnes were spilled (Source: DECC). 3.8 However, we must always ensure we put the safety of our employees first and minimise any adverse environmental impacts of the industry's operations, so in light of the recent Gulf of Mexico incident, it is only right that the UK offshore sector take a fresh look at its practices in the UK for oil spill prevention and response. The review being conducted under OSPRAG will be comprehensive and will help ensure that the arrangements in the UK continue to be fit for purpose. • Ev 70 Energy and Climate Change Committee: Evidence 4. What are the implications of the Gulf of Mexico oil spill for deepwater drilling in the UK? 4.1 The robust regulatory regime in the UK and the resultant industry performance indicate that risks continue to be effectively managed. 4.2 However, the scale of the Gulf of Mexico incident changed perceptions of risk which has resulted in greater scrutiny of company internal procedures and of how the UK regulatory regime is enforced (eg DECC has doubled the number of environmental inspections offshore). 4.3 The Macondo incident has obliged the UK oil and gas industry to review comprehensively the adequacy of its prevention (primary and secondary well control) and response arrangements, from well design through to oil spill cleanup, so that they remain fit for purpose and operations to maximise recovery of hydrocarbons from the UKCS can be safely pursued with minimum adverse environmental impacts. 4.4 OSPRAG was established as a cross -industry initiative to deliver this assessment, while absorbing and applying relevant lessons learned from incidents elsewhere in the world. 4.5 OSPRAG's initial focus is on: 4.5.1 The Technical Review Group's work on primary and secondary well control including competency/behaviours and human factors, well examination, verification and blow out preventers. This work concludes that there is a high degree of confidence in the UK regulatory regime and that it drives the right safety and environmental behaviours. Recommendations are being developed to ensure the capture and transfer of best practice in these areas. 4.5.2 The potential design and delivery of a capping and containment capability for the UKCS. The Technical Review Group will make recommendations on this by the end of September for approval in early October. 4.5.3 The ability of an operator to pay third party response costs and compensation to those affected by an oil spill. Companies in the UK are responsible for environmental or other damage if their installations fail. There is no legislative cap on a company's responsibility for clean-up and compensation. However, if there is a default on payments, under a mutual agreement established in 1975, administered by OPOL (Offshore Pollution Liability Association Ltd), the rest of the • industry will step in to pay third -party costs up to a pre -determined limit. The OPOL Board agreed mid -August to increase this limit to $250 million, which is sufficient to cover the third party costs of an oil spill in previously modelled spill scenarios. All operators on the UKCS are members of OPOL. OSPRAG's Indemnity and Insurance Review Group is continuing work on two fronts. Currently under OPOL all operations are seen to pose a similar risk but clearly the financial risk of oil spill from a southern sector gas well is different to that from a northern sector oil well. The review group will make recommendations on any further changes once the implications have been properly assessed. 4.5.4 The ability of the UK to respond to a sustained oil release. The UK oil spill strategy is based on a tiered response: — Tier 1: A small operational spill (< 100 tonnes) employing local resources during any clean up, provided by the operator; — Tier 2: A medium sized spill (— 500 tonnes) requiring regional assistance and resources, provided by a service company; and — Tier 3: A large spill (> 10,000 tonnes), requiring national assistance and resources. The National Contingency Plan will be activated in this case. The industry sponsored provider of the Tier 3 response, Oil Spill Response, is based in Southampton and can call on resources from other oil producing regions to supplement UK equipment stockpiles. This resource can be supplemented by nationally held equipment under the control of the MCA. An inventory of all oil spill response equipment held in the UK by government agencies and industry is being prepared, against which an assessment of adequacy can be made. In addition, a comprehensive oil spill exercise, led by MCA, is being planned for mid 2011 to test the response provisions. 5. To what extent are UK safety and environmental regulatory regimes fit for purpose? 5.1 Safety 5.1.1 OSPRAG believes that the UK regulatory safety regime is robust and fit -for -purpose. The regime • was built upon the recommendations of the Cullen Inquiry into the Piper Alpha incident in 1988 and as a result is fundamentally different to that in the USA. 5.1.2 Firstly there is a clear separation in regulatory function between licensing (DECC) and safety (HSE), which allows the economic goal of maximising recovery of hydrocarbons to remain distinct from the enforcement of safe operations. Energy and Climate Change Committee: Evidence Ev 71 • 5.1.3 Second, a goal setting rather than prescriptive philosophy (as seen in the USA) is dclivered through the safety case to ensure that major accident risks are evaluated and controlled and that precautions taken are tailored to the actual risks. This also allows new technology which enhances safety to be introduced as it becomes available without having to change the law. 5.1.4 The safety case, accepted by the HSE, is required for all installations before operating (including drilling) on the UKCS. For the safety case to be accepted, it needs to demonstrate that the company management system is adequate to ensure legal compliance; that there are arrangements in place for auditing the safety management system; that there has been a detailed and systematic approach to the identification of all hazards with the potential to cause a major accident, and that all the major accident risks have been evaluated and measures taken to control those risks to as low as reasonably practicable. Furthermore, as new information or safety enhancing technology becomes available, the UK industry is obliged under the safety case regime to review existing arrangements so that risks remain as low as reasonably practicable. 5.1.5 Specific safeguards for wells: Well notification system —in which the HSE is advised at least 21 days in advance of drilling or well intervention activities. This allows HSE specialist wells inspectors to review the well design and execution plan, and require amendments if necessary; The requirement for the design and construction of a well to be examined by an independent and competent person (an experienced drilling engineer, for example); Verification by an independent competent person (Lloyds or DNV, for example) of the initial suitability and continuing good repair and condition of safety -critical equipment involved in drilling (blow-out preventers, for example); — Weekly drilling reports sent by operators to HSE, enabling HSE wells specialists to identify and respond to changing risks; — Requirements that workers involved in well operations are suitably informed, instructed, trained and supervised; and . — Specialist inspectors from HSE's Offshore Division test the veracity of the information received through their prioritised inspection and intervention programmes. 5.2 Environment 5.2.1 The UK offshore industry is subject to stringent international, EU and UK environmental controls, which lay down the requirements for consents, permits and environmental reporting (as well as the limits for discharges and emissions), inspection, investigation and enforcement. Central to this is the requirement for all operators to have an independently verified Environmental Management System in place, which ensures that appropriate control measures are applied. 5.2.2 The regulations require every offshore operation, including exploration drilling to have an Oil Pollution Emergency Plan (OPEP), approved by DECC in consultation with specialist advisers. These are: tailored to location and the environmental and socioeconomic sensitivities within a potential impact area; updated, as required; and exercised periodically. Specific spill response is provided by specialist contractors from common resources, supported by additional local resources where required. Response personnel are appropriately trained through accredited courses. 5.2.3 These operations are subject to inspection by DECO, which recently announced increased resourcing for this area. 6. What are the hazards and risks of deepivater drilling west of Shetland? 6.1 In large part, the hazards of drilling west of Shetland are no different from elsewhere. Differences when compared to the North Sea are primarily related to the challenges of the area's physical environment, which is characterised by heavy seas, fast and complex currents, severe weather, particularly in winter, and deeper waters than are typically encountered elsewhere on the UKCS. 6.2 The risks associated with these hazards are however well understood and, with over 40 years of experience in UK offshore operations, are well managed under a fit -for -purpose regulatory regime and an effective safety culture with multiple barriers in place. 6.3 In total, more than 400 wells have been safely drilled west of Shetland over the last 30 years, while the Foinaven and Schiehallion fields have been successfully producing for over ten years and Clair for five • years, without any significant oil spill incident (Source: DEAL). 6.4 The industry has a good safety and environmental record on its drilling operations in the region, reinforcing the view that the processes, procedures and control practices employed in the UK for deep water drilling and production are safe and fit -for -purpose. September 2010 Ev 72 Energy and Climate Change Committee: Evidence 0 Annex OSPRAG PARTICIPANTS The group is chaired by Mark McAllister, chief executive of Fairfield Energy Limited. The following also participate in OSPRAG. INDUSTRY — Drilling contractors. — Oil and gas operators. — International Association of Drilling Contractors (IADC). — Oil & Gas UK. — Oil Spill Response (OSR). REGULATORS — Department for Energy and Climate Change (DECC). — Health and Safety Executive (HSE). — Maritime and Coastguard Agency (MCA). — Secretary of State's Representative for Maritime Salvage and Intervention (SOSREP). TRADE UNIONS — RMT. — Unite. In the course of the group's work, it liaises with and consults other relevant bodies, some of which are listed below. — American Petroleum Institute (API) through the Gulf of Mexico Joint Industry Task Force. • — International Association of Oil and Gas Producers (OGP) through the Global Industry Response Group. — IPIECA (the global oil and gas association for environmental and social issues). — European national trade associations: OLF (Norway); Nogepa (the Netherlands), WEG (Germany); IOOA (Ireland); the Danish Operators. OSPRAG REVIEw GROUP PARTICIPANTS OSPRAG's work is carried out through four review groups. Representatives from the following organisations participate in the review groups. TECHNICAL REVIEW GROUP — Talisman Energy (UK) Limited. — Oil & Gas UK. — Senergy Oil & Gas Limited. — HSE. — RMT. — Unite the Union. — BP. — OED Norway. — Total E&P UK Limited. — KCA Deutag Drilling Limited. — Transocean Drilling UK Limited. — DECC. — Apache North Sea limited. • — ConocoPhillips (U.K.) Limited. INDEMNITIES AND INSURANCE REVIEW GROUP — Oil & Gas UK. — Enquest. • Energy and Climate Change Committee: Evidence Ev 73 — BP plc. — Shell U.K. Limited. — MCA. — DECC. — BG Group plc. — Reed Smith. — OPOL Ltd. — Endeavour Energy UK Limited. OIL SPILL RESPONSE REVIEW GROUP — Petrofac Training. — Morlich Services. — Transocean Drilling UK Limited. — Energy Environment. — Hess Limited. — DECC. — Oil Spill Response. — Fisheries Research Services (FRS) Marine Laboratory. — Oil & Gas UK. — JNCC. — Briggs Environmental. — Maersk Oil UK Limited. • — BP Plc. — MCA. — Shell U.K. Limited. — Talisman Energy (UK) Limited. — Premier Oil plc. — Dong (UK) Ltd. — CNR International (U.K.) Limited. — Nexen Petroleum (U.K.). — Total E&P UK Limited. — ExxonMobil International Ltd. — Marine Management. — Kingston Ambrose Ltd. — Chevron Upstream Europe. — Scottish Coastal Forum. — ConocoPhillips (U.K.) Limited. — Marathon Oil U.K. Limited. EU ISSUES REVIEW GROUP — Apache North Sea limited. — Nexen Petroleum (U.K.). — IADC. — OLF. — Oil & Gas UK. — ConocoPhillips (U.K.) Limited. — WEG. — NOGEPA. — BG Group plc. — DECC. Ev 74 Energy and Climate Change Committee: Evidence • — MCA. — HSE. — Petro -Canada UK Limited. — Tullow Oil UK Limited. — ITF. Hess Limited. — Perenco (UK) Limited. — Chevron Upstream Europe. — IPIECA. — Norwegian Petroleum Directorate. — Maersk Oil UK Limited. — GDF SUEZ E&P UK Ltd. — Marathon Oil U.K. Limited. Memorandum submitted by BP SUMMARY — BP is determined to share the lessons of the Deepwater Horizon accident widely. The incident is still under investigation by numerous entities, including a non -privileged investigation by BP. BP will provide the Committee with a copy of that investigation report when it is published (para. 3). — The accident took place on 20 April 2010. No oil leakage has been detected into the Gulf of Mexico since 15 July. No volumes of oily liquid have been recovered since 21 July and the last controlled • burn operation occurred on 20 July (para. 9). — BP has made extensive reviews of its drilling operations in light of the accident in the Gulf of Mexico (para. 15). — There are opportunities for the industry to be better prepared than at present for a subsea disaster (paras. 18-19). — The UK experience of a goal -setting approach to regulation allows for a process of continuous improvement, based on a growing body of information and knowledge (para. 23). — Any moratorium on deepwater drilling in the UKCS would have implications for both UK Security of Supply and the long term future of the industry in the UK, and would not necessarily reduce the risk of accidents if based exclusively on water depth (para. 27). — Lessons will be learnt from the tragic accident in order to minimise the risk of a similar occurrence. BP, along with the rest of the industry, is determined to continue to carry out its essential public service in as safe and in as responsible a way as possible (para. 28). INTRODUCTION 1. The sinking of the Transocean drilling rig Deepwater Horizon in the Gulf of Mexico, following an explosion on 20 April, is one of the most tragic events in the history of the oil industry. First and foremost, it resulted in the death of eleven people employed on the rig. The accident has also had major implications for the environment in the Gulf of Mexico, for the prosperity and living standards of Gulf Coast residents, and for the companies directly concerned as well as of the oil industry as a whole. 2. In the wake of this accident, it is essential that the lessons are learnt and that measures are implemented to minimise the chances of such an accident happening again (although the risk of accidents can never be eliminated entirely). 3. BP is determined to share the lessons from the accident widely. However, there is still much that is unknown, and numerous entities continue to investigate the incident, including a BP investigation team, independent of management, that is preparing a non -privileged report of the incident. BP will provide the Committee with a copy of that report when it is published. 4. In addition to BP's own internal, non -privileged investigation, various committees in both houses of • the United States Congress and agencies and commissions of the U.S. Executive Branch are also investigating the accident. 5. Both the Oil Spill Prevention and Response Advisory Group (OSPRAG) and Oil and Gas UK are submitting written evidence to this Inquiry. BP works closely with both bodies and will seek to avoid duplication in this submission. • Energy and Climate Change Committee: Evidence Ev 75 THE GULF OF MEXICO OIL SPILL 6. The original accident was described thus by Transocean on 21 April 2010: "Transocean Ltd. (NYSE: RIG) (SIX: RIGN) today reported a fire onboard its semisubmersible drilling rig Deepwater Horizon... The rig was located approximately 41 miles offshore Louisiana on Mississippi Canyon block 252." BP is the operator of the licence on which Transocean's rig, the Deepwater Horizon, was drilling an exploration well. The rig was evacuated on the night of 20 April, and on 22 April, BP issued the following statement: BP today activated an extensive oil spill response in the US Gulf of Mexico following the fire and subsequent sinking of the Transocean Deepwater Horizon drilling rig 130 miles south-east of New Orleans. BP is assisting Transocean in an assessment of the well and subsea blow out preventer with remotely operated vehicles. BP has also initiated a plan for the drilling of a relief well, if required. A nearby drilling rig will be used to drill the well. The rig is available to begin activity immediately. 7. On 24 April, search and rescue operations for missing personnel ended, and BP issued the following statement: BP today offered its deepest sympathy and condolences to the families, friends and colleagues of those who have been lost following the fire on the Deepwater Horizon oil rig in the Gulf of Mexico this week. Group Chief Executive Tony Hayward said: "We owe a lot to everyone who works on offshore facilities around the world and no words can express the sorrow and pain when such a tragic incident happens." • "On behalf of all of us at BP, my deepest sympathies go out to the families and friends who have suffered such a terrible loss. Our thoughts also go out to their colleagues, especially those who are recovering from their injuries," he said. He added: "BP will be working closely with Transocean and the authorities to find out exactly what happened so lessons can be learnt to prevent something like this from happening anywhere again." 8. From 24 April, huge effort has been given to addressing as far as possible the human aspects of the tragedy, to stopping the leak, and to minimising its environmental consequences. This effort has involved capping the well in unprecedented circumstances, including the deployment of resources, technology and skills on a scale never witnessed before. 9. In early June, a customized containment cap was fitted to the well from which oil was piped to the Discoverer Enterprise. A second containment system was installed in mid -June, and by early July these two systems were collecting or flaring around 25,000 barrels of oil equivalent a day. On 12 July, a new sealing cap was installed, and, on 15 July, a well integrity test began in which the cap's three ram capping stack was closed, effectively shutting in the well and all sub -sea containment systems. No oil leakage has been detected into the Gulf of Mexico since 15 July. Moreover, no volumes of oily liquid have been recovered since 21 July and the last controlled burn operation occurred on 20 July. Subsequently, BP commenced a "static kill" of the well, and, on 5 August, completed cementing operations associated with that procedure. Monitoring of the well has confirmed that the static kill procedure was effective. Since then, work has continued on a relief well which will intercept the Macondo well annulus and result in the permanent sealing of the well. THE IMPLICATIONS OF THE GULF OF MEXICO OIL SPILL FOR DEEPWATER DRILLING IN THE UK 10. Clearly, lessons learnt from the Gulf of Mexico accident must be reviewed in the context of the United Kingdom Continental Shelf (UKCS). The oil and gas industry is global, and many of the challenges faced, and technologies used, are the same everywhere. But there are also some distinct differences. For example, there are no deepwater HPHT wells in the North Sea thereby obviating certain challenges that exist when drilling deepwater wells with high pressures (> 10,000psi). [Reservoirs of greater than 10,000 psi and 150 deg C are typically classified as High Pressure and High Temperature (HP/HT). The North Sea HP/HT fields are generally located in the Central North Sea at water depths of 100-150 metres]. 11. The prime difference between the two areas is the water depth in which drilling and development activity take place. Gulf of Mexico water depths range from very shallow (swamp barges) to over 3,000 metres, with a number of developments in excess of 1,500 metres. In contrast, North Sea developments take place in depths ranging from shallow (tens of metres in Southern North Sea) to depths of 500 metres (WoS). Exploration drilling also occurs in the Atlantic Margin WoS and the Norwegian Sea where water depths greater than 1000 metres can be found. • Ev 76 Energy and Climate Change Committee: Evidence 12. Water depths bear on the types of drilling rigs used. Because of its deeper waters, the Gulf of Mexico often has more than twenty dynamically positioned (DP) drilling rigs in operation (in contrast to the UKCS, where two is the current maximum). Typically in the North Sea, anchored rigs are used but are limited to depths up to 600 metres. In addition, for water depths over 150 metres, Remotely Operated Vehicles (ROVs) are used to interface with subsea equipment on the ocean floor. 13. In terms of weather, the North Sea is generally exposed to more severe seas and stronger winds than the average conditions experienced in the Gulf of Mexico. However, the Gulf of Mexico experiences extreme weather, including hurricanes, which require procedures that are unnecessary for the UKCS. The Gulf of Mexico also experiences strong sub -sea currents in the deepwater, known as Loop Currents, which affect both the positioning of DP rigs and the design and fatigue strength of the risers. 14. Efforts in the UKCS are at present concentrated upon prevention and damage limitation should a blowout occur. OSPRAG will no doubt cover in detail the action that has already been taken in respect of capability and equipment reviews; the development of a generic subsea containment system; and the reforms that may be necessary to the insurance and liability regime. 15. BP has made extensive reviews of its drilling operations in light of the accident in the Gulf of Mexico. A specific focus has been on blowout preventers (BOPS). All subsea BOP stacks in use in BP operations have been evaluated to confirm that they operate as designed and have not received modifications that might compromise their operation. In the UKCS, this has included physical recovery and inspection of two BOPS. 16. 'Turning specifically to WoS, the majority of the risks encountered are similar to those encountered in other UKCS offshore areas, while others —such as HP/HT wells —are not encountered at all. WoS, however, weather conditions are more severe and water depths are generally greater. 17. There are various factors which determine the overall risk of drilling —water depth is one of these. However, the serious attention paid to risk needs to be the same in any water depth and, as argued below (para. 27), the specific circumstances of any well are paramount. It is a legal requirement to identify hazards, assess risk, and to mitigate risks through using procedures, equipment or engineering to a level "As Low As Reasonably Practical' (ALARP). • 18. The longer -term implications of the Gulf accident will only become apparent when the causes of the accident are better understood. For example, the physical recovery of the damaged BOP will be an important piece of evidence in understanding the accident. Regardless, there are opportunities for the industry to be better prepared than at present for a subsea disaster. Improvements in this area will likely involve developing a similar capability for dealing with large undersea spills as already exists for surface spills, and important work in this area has already begun. 19. Other important lessons include: — The need to share information across the industry on its capacity to respond to an undersea accident; — Application, where appropriate, of consistent policies and equipment standards; and — The need for active cross -industry engagement with government and regulators in many areas, including with respect to operational capability and competence and financial capacity. THE UK SAFETY AND ENVIRONMENTAL REGULATORY REGIME 20. In the UKCS there are two main regulators: the Health and Safety Executive (HSE), which regulates offshore safety; and the Department of Energy and Climate Change (DECC), which regulates the offshore environment for oil and gas activity. 21. In the UK, the design, construction and maintenance of a well must be independently verified, and it is the Well Examiner's role to examine all stages of a well's planning, execution and operation throughout its life cycle. 22. In addition, the HSE Safety Case Regulations (SCR) and related regulations require the identification and assessment of the major accident hazards associated with an installation and require measures to mitigate those hazards and to ensure the rescue of personnel. Under the SCR, UK companies must manage wells to avoid unplanned escapes of oil or any other well fluids. It is an important principle that the risks of escape of hydrocarbons and of personal injury must be demonstrably as low as reasonably practical. 23. In essence, the UK regime involves goal -setting based on an analysis of major hazards and risk assessment, with the emphasis on prevention of accidents. By contrast, the US regime identifies precisely what an operator is expected to do. Operators in the UKCS are required to demonstrate the identification and assessment of major accident hazards; they must also provide assurance that necessary measures have been taken to minimise these risks and to give precedence to the safety of personnel. This allows for a process of continuous improvement, based on a growing body of information and knowledge. This "goal -setting" approach was largely developed in response to the Piper Alpha disaster in the UKCS in 1988. • Energy and Climate Change Committee: Evidence Ev 77 THE NEED FOR DEEPWATER DRILLING 24. Global definitions of "Deepwater" differ, but at depths of over 600m Dynamically Positioned Rigs are likely to be needed which carry a different risk profile. Depths greater than 5,000ft/1500m are classified as ultra -deep water. WoS drilling occurs across a range of water depths from 150m (BP's Clair field), through 400-500m (BP's Schiehallion and Foinaven fields) to exploratory drilling at over 1,000-1,500m. The Deepwater Horizon incident occurred at a water depth of 5,000ft/1,500m. 25. The accident in the Gulf of Mexico has raised questions over whether the world's need for new energy resources justifies the risks of deepwater drilling. In this respect, it is instructive to look at the history of offshore oil production over the past decade, as illustrated by the following chart (source PIRA). World offshore production in 1990 at 17 million barrels per day (mbd) represented some 25% of total global production and took place almost exclusively in shallow water. Today, with some 30% of total global production accounted for by offshore activity (27 million barrels per day), deepwater production (> 1,000 feet) is much more significant and contributes some 7% of the total. By 2020, this is expected to increase to over 9%. To forego oil produced from deepwater would have global strategic significance for energy supply. 26. The same can be said for the UK specifically, where reserves of oil and gas amount to some 24 billion barrels, but where some 25% of the UK's currently discovered oil and gas reserves lies in the deeper waters to WoS. This same area also has the greatest exploration potential, and very little of the UK's deeper water potential has so far been discovered or licensed. Delay in realising this potential would have implications for the security of UK oil and gas supplies. 27. While a moratorium could threaten security of supply and the long term future of the UK industry, it does not follow that it would necessarily reduce the risk of accidents. The special characteristics of deepwater drilling depend heavily on the specific circumstances of each offshore well. Thus the risk of a hydrocarbon release, and the appropriate risk mitigation measures which accompany it, are not exclusively related to water depth. In simple terms, a shallow water well near to shore may carry as much risk as a deep water operation if it is not designed and operated to appropriate standards. Given these considerations, a blanket moratorium, based (for example) on water depth, cannot be relied on to exclude those operations of greatest • risk; this type of risk reduction can only be achieved through comprehensive risk assessment and design of mitigation measures on a case -by -case basis. CONCLUSIONS 28. Deepwater drilling is increasingly satisfying a growing proportion of global energy demand. The UKCS is no exception. The future potential of the North Sea to provide consumers with the energy they need and want is dependent to an important extent on current and future operations West of Shetlands. It is impossible to eliminate risk from any aspect of North Sea operations, whether in shallow or deep water. But the lessons to be learnt from the tragic accident in the Gulf of Mexico will enable the industry to reduce greatly these risks, and to help prevent a similar occurrence happening elsewhere. In the UKCS, as outlined above, steps are already being taken with precisely this objective. There can never be grounds for complacency, and there is always room for improvement. But BP, along with the rest of the industry, is determined to continue to carry out its essential public service in as safe and in as responsible a way as possible. September 2010 Memorandum submitted by TOTAL E&P UK LIMITED EXECUTIVE SUMMARY Major incidents offshore are, thankfully, rare. However, they are a stark reminder to the industry that a combination of poor planning, decisions or competences can combine with disastrous results. Following the Macondo blow-out in the Gulf of Mexico, TOTAL E&P UK, like many others, has looked closely at its own procedures, both within the company and in collaboration with regional and national regulatory authorities. Audits of safety, environmental and operating processes, competences and regulatory requirements have been carried out. There is no doubt that the whole industry has been severely challenged by the Macondo incident. TOTAL E&P UK's corporate technical and management procedures and the UKCS regulatory regime are robust for both exploration and production operations, across all water depths of the UKCS. Around the world drilling is now carried out in water depths of up to 3,000 metres whilst, in the UKCS, water depths do not come close to these levels. In addition, it should be noted that water depth was not the determining factor in the causes of the Macondo incident and that water depth is not considered the most significant element in designing and drilling a subsea well. Ev 78 Energy and Climate Change Committee: Evidence • TOTAL E&P UK COMPANY PROFILE. TOTAL E&P UK is one of the largest operators on the UK Continental Shelf in terms of production and reserves, with daily operated production in the region of 270,000 barrels of oil equivalent per day. Some 70% of this production is gas. TOTAL E&P UK owns and operates the Alwyn North, Dunbar, Ellon, Grant, Nuggets, Forvie, Jura and Otter fields in the Northern North Sea. Along with its partners, it also owns and operates the Elgin, Franklin, West Franklin and Glenelg Fields in the Central Graben Area of the Central North Sea. In March 2010, TOTAL E&P UK received final sanction to develop its Laggan and Tormore gas fields in the region West of the Shetlands (WoS), in which the company has an 80% interest (DONG Energy has 201/6). Developing those fields and the associated infrastructure will open up the whole of the WoS region and unlock the UK's gas reserves currently stranded there. The development of the fields has started with the construction of a new gas plant in Sullom Voe on the Shetland Island, with offshore drilling of the gas wells being planned for mid 2012 in a water depth of 630 metres. Onshore, TOTAL E&P UK also operates the St Fergus Gas Terminal on the northeast coast of Scotland, which receives and processes up to 20% of the UK's natural gas requirements from over 20 fields in the UK and Norway. In 2014 the gas production coming from WoS will also be processed in the St Fergus terminal. EVIDENCE ADDRESSING THE FIVE QUESTIONS POSED Ql What are the implications of the Gulf of Mexico oil spill for deep water drilling in the UK? 1.1 A major offshore incident in the oil and gas industry, whilst rare, is a reminder of the inherent risks and the need to be totally rigorous in identifying potential dangers and taking appropriate steps to eliminate or minimise risks to staff and the environment. Twenty years ago exploration drilling in up to 300m water depth was considered to be deep water. Global experience acquired during those intervening years, plus very significant advances in technology, now enable drilling to take place in 3,000m of water whilst, in the UK, wells have been drilled in water depths up to 1,800m. For this reason, drilling rigs are designed and constructed specifically for the local environment, with the appropriate technology and safety equipment to suit these conditions (eg water depth, meteorological and oceanographic conditions), in which they are • expected to operate. The industry, however, which has operated successfully for so many years in the UK, is now challenged by the magnitude of the Macondo incident. Although UK operators have built up a unique range of experience by working in difficult conditions around the UKCS, the implications of the Macondo incident are numerous. 1.2 For an operator like Total what are the implications? First, we immediately asked ourselves the question, "Could this happen to us`'" The answer to that is that the risk is very low but it is not impossible. Despite our confidence we have therefore taken immediate action to ensure this risk remains As Low As Reasonably Practicable ("ALARP") across our operations worldwide and particularly in the UK. To this extent we have launched several actions covering procedures, competence and emergency response: (a) Immediate actions taken internally by Total We immediately launched an audit on current drilling operations with most emphasis on: — The design and architecture of the wells —this is key; — The BOP equipment, its configuration, maintenance and function tests; — Well control training and exercises; — Review of the functioning of our organization; and — Approval of, and thereafter adherence to, the drilling programme. (b) Longer term actions In parallel, but with a deadline before the end of 2010, various internal work groups have been set up in Total's headquarters with focus on the following subjects: — Re-evaluation of our drilling procedures, of BOP equipment and training of personnel; — Study and design of capture/containment techniques in subsea wells; is— Re-evaluation of safety barriers in place on our deepwater production installations; and — Re -analysis of the methods and techniques of anti -pollution treatment and control. All this work will take into account the lessons from the Macondo incident, its causes and also the measures taken by BP to make good the damage. Energy and Climate Change Committee: Evidence Ev 79 • (c) Follow up and active participation in industry activities In addition, TOTAL is actively participating in industry -wide work on the same subjects within the framework of national and international associations (OSPRAG, OGP, IPIECA, API) as well as with the regulatory authorities of Norway and the Netherlands. In particular, it should be mentioned that TOTAL E&P UK is directly involved with our drilling experts in the technical work groups of OSPRAG, which includes UK regulators, and OGP in Europe. It should be noted that the implications of the Macondo incident are not limited to deep water activities. All subsea operations require to be reviewed, both in light of the information becoming available from the Gulf of Mexico and from all the investigations being carried out in the industry. Regarding TOTAL, our procedures are based on worldwide experience, are under permanent review and are adjusted or modified as necessary in light of new experiences and technologies. The TOTAL organisation is relatively centralised; this not only encourages the growth and sharing of knowledge but also a control of its global activities to ensure that worldwide experience is incorporated in all operational areas. 1.3 An important implication of the incident is the necessity to reassess the competence of staff and contractors and especially those holding key positions on drilling rigs. All TOTAL's operational staff benefit from extensive training, certified by independent organisations, including regular assessments on the subject of well control. The performance of our subcontractors, the principal drilling contractor and associated service companies, are the subject of formal reviews. In addition to comprehensive training programmes already in place, we are now in the process of reinforcing our Competence Assessment Management System for specific roles. Before commitment, any drilling rig is fully inspected and the main components, including safety equipment, are tested. We ensure that staff and contractors are fully aware of the importance of the strict rules and procedures and that the supervisory staff and managers implement these strict processes. 1.4 Emergency response plans are an essential element of every drilling or production programme. These are subject to the same rigorous and detailed in-house analysis, as well design and construction, and are fully exposed to regulatory inspection. The Gulf of Mexico incident is a stark reminder of the need to keep these plans updated as circumstances change, and keep staff fully aware and prepared. In all cases a blow-out contingency plan is developed and plans for emergency relief wells are defined before drilling commences. • However, improvements must be made regarding well -capping methodology and equipment availability. Within OSPRAG, with Oil Spill Response Ltd and the Maritime & Coastguard Agency, we are reassessing how the existing responses to pollution can be improved but it must be recognised this is a difficult problem in the environmental conditions of the North Sea. However, Environmental Statements remain vital to demonstrate all risks are assessed and control plans are in place. In the UK these are placed before the regulators and the public for scrutiny. 1.5 The points raised in the answers above frequently refer to staff competence and awareness. This cannot be over -emphasised since no amount of excellent procedures and processes, top -rated equipment and safety systems, environmental analysis and controls can be sufficient if they are not correctly implemented. In TOTAL E&P UK any initiative targeting cost -savings by shortcutting procedures is prohibited. This is clearly the policy of most operators. In TOTAL, senior management regularly visit all operational sites and offshore facilities to remind staff and contractors of our policy and that their "going home safe and well" at the end of a tour of duty is paramount. Individual responsibility must be a habit and remains critical to the ultimate success of any activity. Q2 To what extent is the existing UK safety and environmental regulatory regime fit for purpose? 2.1 The UK regulatory regime takes a risk -based approach and is considered fully fit for purpose. It requires that, prior to any activity, all elements of the work are reviewed and every possible risk evaluated for potential impact with a full programme of risk avoidance or reduction put in place. The UK regulatory regime is one of the, if not the most, robust and rigorous regimes in the world with a very positive dialogue and level of challenge from the regulators and other organisations, which adds considerably to the final operational programme placed before the regulator for approval. 2.2 UK regulators have the benefit of experience from every operator in the UKCS and so have a broad range of knowledge to draw upon when assessing both Operational Plans, Safety Cases and Environmental Statements. In addition to this robust process, TOTAL is part of one of the largest, integrated oil and gas companies in the world with significant experience of High Pressure High Temperature and Deepwater Drilling Operations. Our own corporate review procedures, before any application is made to the UK regulator, require that the full technical work programme is thoroughly vetted and passes the strict level of review, based on our global experience and procedures. 2.3 As already pointed out to Lord Marland as part of TOTAL E&P UK's response to the question of red tape in DECC regulation, one concern is the significant pressure on a small number of highly professional DECC staff. Already we have seen slow responses on items of high importance and any reduction in the existing staff or loss of expertise would, we believe, result in inefficient operations and potential for error. We strongly support the DECO units regulating oil and gas activities and would be very concerned if there were any degradation in numbers or experience. C Ev 80 Energy and Climate Change Committee: Evidence Q3 What are the hazards and risks of deepvater drilling to the West of'Shetland? 3.1 The West of Shetland area is not considered to be an especially deepwater area by global oil and gas operational standards. Around 300 exploration and appraisal wells have already been drilled in the area with no major problems. Hazards especially associated with West of Shetland drilling relate primarily to meteorological and oceanographic conditions. Wind, waves and currents are more severe and often less predictable than encountered during normal Gulf of Mexico activity and require a range of operational decisions to be made regarding the drilling unit contracted. If operations were to continue all year a Harsh Environment Unit might be needed. This would include the option of both moored and dynamic positioning systems. Due to significant water currents at different depths, more care must be taken with riser design, wellhead fatigue analysis and general load distribution. These and many other aspects are major considerations in selecting a suitable rig to operate WoS and are often more demanding criteria than applied to normal UKCS activities. However, all of these elements form part of the strict in-house planning process which takes place prior to putting a programme to the regulator. The number of wells drilled clearly demonstrates that the industry does have the skills and technology required to operate safely WoS. 3.2 The Macondo well was being drilled into an overpressured reservoir in the Gulf of Mexico. In some parts of the world, TOTAL conducts such High Pressure High Temperature (HPHT) operations in relatively deep water. In the UK, TOTAL E&P UK has extensive and successful HPHT operational experience from the Elgin/Franklin and associated fields in the Central North Sea, with wells drilled on dedicated fixed platforms. However, the geological conditions WoS are very different and no significant overpressure has been encountered by TOTAL E&P UK to date in this part of the UKCS. 3.4 Some of the technical differences noted between TOTAL E&P UK's WoS operations and that of BP in the Gulf of Mexico include the following: (1) Tormore and Laggan have hydrostatic pressure; (2) We use conventional cement slurries; (3) We centralise our casings properly; (4) We perform cement bond logs; (5) The wellhead system incorporates locking mechanisms as standard; (6) A detailed well control audit is performed; (7) The secondary Blow -Out Preventer shut-off mechanism is routinely tested; and (8) We do not use auto -fill float equipment. 3.5 BP has already developed several oil fields in the WoS region, including Foinaven and Schiehalion with floating units and more recently the Clair Field in shallower waters with a fixed platform. TOTAL E&P UK is in the process of developing the Laggan and Tormore fields. These fields, located in 630m water depth are gas fields and the drilling of 7 gas wells is planned to be carried out from mid 2012. Laggan and Tormore are very conventional gas reservoirs with no particular technical difficulty anticipated. Q4 Is deepwater oil and gas production necessary during the UK's transition to a low carbon economy? 4.1 DECC figures show that 70% of primary energy supply in 2020 will come from oil and gas. 4.2 TOTAL E&P UK have production profiles for existing fields and current developments to at least 2030 on the UKCS. With additional exploration, particularly WoS where new pipeline infrastructure offers a new incentive to exploration drilling, this date could be pushed further out. 4.3 Maximising recovery from the UKCS reduces our dependence on imports, which DECC's own publications confirm will be scarcer but in demand beyond 2050 and consequently more expensive. The UK cannot afford to waste a valuable resource that can mitigate against delays in development of alternative energy strategies. It can be assumed, from recent experience, that imports of hydrocarbons will be both expensive and at the mercy of overseas suppliers. Political and economic pressures on import prices are unpredictable but can be avoided for as long as possible by maximising indigenous hydrocarbon supplies, much of which will come from the as yet undeveloped WoS area. 4.4 While oil is primarily for transport, chemicals and special products, gas plays and will continue to play a vital role in electricity and heat production for decades. TOTAL E&P UK is already working to develop gas fields that will produce approximately I trillion cubic feet of gas, and has a range of additional exploration and appraisal plans for further work over the next few years. The WoS area is crucial to maintain gas supplies to the UK. 4.5 Maximising UKCS production through the WoS exploration and developments also provides a major investment opportunity for UK businesses, will maintain large numbers of jobs with highly exportable skills, significant revenues for the Treasury and ensures security of supply for the country. Energy and Climate Change Committee: Evidence Ev 81 • Q5 To what extent would deepwater oil and gas resources contribute to the UK's security of supply? 5.1 Production from the North Sea is in decline. Significant discoveries will no doubt still be found but these will be very much smaller than the billion -barrel fields of the 1970s. The average size of UKCS discoveries in the last 10 years is only around 20 million barrels of oil equivalent and many of them are gas discoveries. Despite this, the decline of the UK gas production has been much quicker than the oil production, and the UK "has moved from being a country self-sufficient in gas to one increasingly dependent on supplies from elsewhere in the world" (cf Jonathan Roger, Centrica—Profile; Press & Journal). It should be remembered that the UK is the biggest gas consumer in Europe. As a result, imports have reached more than 50% of the country's needs, gas being imported through pipelines from Europe or as liquefied natural gas by tankers from the Middle East or elsewhere. The same scenario will soon happen for oil. It is therefore now a vital political decision to let dependency from foreign imports increase, or maximize domestic production to reinforce security of supply. In that respect it is relevant to remind that "the past winter was the harshest for more than 30 years and gas demand reached record highs" creating a situation of shortfalls. 5.2 The Southern, Central and Northern North Sea areas make a vital contribution to the UK's hydrocarbon production. All these areas are in water depths of less than 200m. Although water depths are greater WoS, this is a very large area and with developing technologies and rising product prices combining to encourage drilling, more discoveries have been made and prospects identified. As part of the current development of the Laggan-Tormore area by TOTAL E&P UK, a new gas pipeline system is being built that will connect these WoS discoveries to the UK mainland. This new system has been oversized in the expectation that further exploration and development will look to use the pipeline for decades to come, including accumulations that in themselves could never justify the cost of this new -build infrastructure. 5.3 Discoveries such as Tobermory, to the north of Laggan-Tormore, hold the hope of further gas field developments and new infrastructure, which could again open up new areas for TOTAL E&P UK and third parties, which would further protect the UK's security of supply. 5.4 Although there are various ranges published, DECC estimates there could be as much as 36 billion barrels of oil equivalent still recoverable from the UKCS, compared with about 40 billion barrels oil equivalent already produced. This estimate reflects the possibilities in new areas and new technologies. Seventeen percent (17%) of the proven and probable reserves are estimated to lie to the West of Shetland but, as shown above, the availability of new gas -gathering pipelines is anticipated to offer a significant incentive to further exploration and the discovery of new reserves in the coming years, which are not included in proven and probable reserve estimates. September 2010 Memorandum submitted by Chevron North Sea Limited What are the ha=ards and risks of deepwater drilling to the West of Shetland? 1. OVERVIEW The following submission is offered to the House of Commons Select Committee on Energy and Climate Change as written evidence to the Inquiry on UK Deepwater Drilling, implications of the Gulf of Mexico oil spill, with particular reference to the question, what are the hazards and risks of deepwater drilling to the West of Shetland? The submission will provide general background on Chevron Corporation, our systems and processes for achieving Operational Excellence and our response to the Gulf of Mexico accident. It will also provide information on Chevron Upstream Europe's exploration activities with particular focus on the West of Shetland and on the issues associated with drilling in deep water in this environment and why we believe that we can continue to carry out our exploration and appraisal activities there safely and without environmental harm. 2. EXECUTIVE SUMMARY —KEY MESSAGES — The Gulf of Mexico accident was tragic and we, along with the rest of industry, are committed to making sure an event like this never happens again. — We recognize and accept that we have an obligation to the UK public to ensure that vital energy resources are produced safely, reliably and without environmental harm. — We believe that the Deepwater Horizon accident represented a dramatic departure from the industry norm in deep water drilling. — Responsible drilling is an essential element of oil and gas exploration, appraisal and development and a moratorium on deep water drilling would have an unnecessary and lasting negative impact on the UK's ability to maximise the value of a vital national resource and on its economic contribution through inward investment, employment, exports and technology development. • Ev 82 Energy and Climate Change Committee: Evidence — Chevron's drilling policies and procedures are rigorous and our record is strong. We have successfully drilled 375 deep water wells globally since 1987 (including 75 in the Gulf of Mexico and 18 in the UK, West of Shetland) without a single serious well control event. — Chevron's commitment to safety and environmental protection is fundamental to the way we conduct our business worldwide —it is not just a priority, it is a value that never changes. — Chevron's Operational Excellence Management System governs how we systematically manage safety, health, environmental stewardship, reliability and efficiency across our daily operations around the world through stringent processes and procedures for risk management, emergency preparedness and compliance assurance. — We have confidence that our operations are safe and we can drill deep water wells in UK waters safely and without environmental harm, based on our global standards, our strong safety culture and performance, and our experience of working within the UK's robust regulatory environment. — Exploration drilling presents different challenges in different conditions —this is why Chevron has processes designed to analyse, quantify and mitigate risk, and why the risk -based, case by case approach taken by the regulators is effective. — Deep water exploration carries issues of not just water depth, but water temperature and met -ocean conditions which have an impact on supporting marine operations and rig selection. Chevron's exploration and drilling processes are designed to ensure that these issues are understood and properly managed. Chevron provides its own, in-house well control training to ensure that everyone within our operations is proven competent against the same high standards. Our philosophy is that well control is at the very heart of well design. 3. CHEVRON Chevron Corporation and its subsidiaries make up one of the world's largest integrated energy companies, conducting business worldwide and engaged in every aspect of the oil and gas industry, as well as chemicals manufacturing and sales, geothermal energy and power generation and investment in renewables and advanced technologies. Chevron is one of the leading leaseholders in the Gulf of Mexico, with mature deep water producing assets, new developments, projects progressing through development phases and new discoveries. Following the Macondo accident, Chevron played a leading role in the response, deploying technical experts to assist with containment efforts, and helped lead the Joint Industry Task Force, which made recommendations to raise industry drilling standards to an even higher level, many of which were already in use by Chevron. Chevron Upstream Europe is one of ten international Strategic Business Units and is headquartered in Aberdeen. It has exploration and production interests in the UK, Norway, Netherlands, Denmark, Greenland and Poland. In the UK, our upstream operating company is Chevron North Sea Limited. Chevron has been active in the UK upstream industry for over 40 years and has made very substantial investments in the UK since then. We have a strong portfolio West of Shetland, with interests in over 50 blocks, including the Rosebank discovery which is currently under appraisal. We are optimistic that this region can offer significant new opportunities for the industry and for the UK in terms of economic benefits and security of supply and can be explored and developed safely. We are currently planning a three well exploration drilling campaign in the region which we hope to commence this September and which will last approximately a year. This will be carried out with the Stena Carron, a dynamically -positioned, state of the art drillship commissioned in 2008 and specially designed for harsh environments and water depths up to 10,000 feet. It safely and successfully drilled four wells in water depths of over 3,400 feet West of Shetland between November 2008 and October 2009 and has just successfully drilled a Chevron well in the Orphan Basin, offshore Canada in a water depth over 8,500 feet. 4. OPERATIONAL EXCELLENCE Chevron's commitment to safety is fundamental to the way we conduct our business worldwide —it is not just a priority, it is a value that never changes. We believe that our framework of safeguards is robust; it is focused on prevention and has helped us build our excellent record of safe operations but we realise that we must continually work to ensure that our processes and safeguards are fully utilized, updated and improved in the light of lessons learned, new challenges and new technologies. Chevron's Operational Excellence Management System governs how we systematically manage safety, health, environmental stewardship, reliability and efficiency across our daily operations around the world. • This means we have strict processes and procedures for risk management, management of change, emergency preparedness and compliance assurance and internal audit processes that ensure that we are meeting our own high standards. Central to Chevron's Operational Excellence Management System are our Tenets of Operation and Stop Work Authority. Any employee or contractor involved in our operations has not only the right but the obligation to call a halt to work if he/she believes that there is risk to safety or the environment. There are Energy and Climate Change Committee: Evidence Ev 83 many instances of our people being recognized by the company for exercising that authority. Our Tenets of Operation are the heart of a code of conduct used as a tool to guide daily decisions. They are based on two key principles —"Do it safely or not at all" and "There is always time to do it right" and are used throughout Chevron as the foundation for our operational excellence culture. Chevron is drilling in deep water basins all over the world and has successfully drilled 375 deep water wells globally since 1987 (including 75 in the Gulf of Mexico and 18 in the UK, West of Shetland) without a single serious well control event. We carried out internal reviews across our global operations of our drilling processes and well control contingency plans immediately after the Deepwater Horizon tragedy and this confirmed our confidence that our policies and procedures are rigorous and our control practices for deepwater wells are safe and environmentally sound. This included our UKCS drilling processes and procedures and though we have added some strengthening to these around training, verification and emergency response, we are confident that these are robust. Nonetheless, we operate in the belief that we can always learn and improve. There is a strong culture of industry co-operation in the UK, as well as continuing open dialogue with our regulators and we are confident that relevant lessons from the Gulf of Mexico will be applied. 5. THE REGULATORY FRAMEWORK We are intensely focused on continuously assessing and mitigating risk to avoid accidents. In the UK, we operate within a framework of close and robust regulation by knowledgeable and independent technical experts, creating safety standards which are considered the highest in the world. In addition, the safety and environmental regulatory regime that was created following Lord Cullen's enquiry into the Piper Alpha tragedy is a goal -setting, non -prescriptive one, which places the responsibility for safe and environmentally sound operations squarely with the duty holder, where the operational knowledge and expertise lies, with the regulators having the powers to ensure that operators comply fully with regulations and the standards set by the operators themselves. This approach has been highly successful over the past 20 years. 6. WELL PLANNING AND OPERATIONS Chevron's drilling policies and procedures are rigorous. We require continuous training and the is certifications necessary for qualified drilling personnel. Certification covers procedures to manage unusual circumstances and the means to verify that contractors involved in drilling wells possess the skills necessary to execute well control. Chevron provides its own, in-house well control training to ensure that everyone within our operations is proven competent against the same high standards. Our philosophy is that well control is at the very heart of well design. In the early stages of developing a well plan, Chevron's Exploration Review Team peer reviews each of our prospects to determine its size, geologic risk and overall drill -ability. From this data, we define our well objectives using our Value Based Well Objectives process, followed by a systematic assessment of all risks and appropriate mitigations using a Risk and Uncertainty Management Standard process. Together, these lead us to define the appropriate objectives for a given well. In addition to the external regulatory environment, Chevron's well planning worldwide is governed by our Operational Excellence Well Design and Construction Process which mandates a range of procedures and standards to identify, mitigate and manage risk; to ensure that well design and construction are fully compliant with legislation, the planning process is rigorous and operations are carried out safely and with care for the environment. These processes require input from internal and external stakeholders, including our service partners and drilling contractors, to ensure alignment amongst all parties. In addition, Chevron operates a Well Examination Scheme and a verification scheme, under which well designs are independently examined and verified by a qualified Well Examiner, who also independently monitors the actual construction of wells, and any necessary modifications, through a robust Management of Change process for modifications or deviations from design and the identification of any associated risk. During the planning phase of all our wells, we hold internal peer assists. This is a formal approach to review well design and execution of drilling, completion and abandonment carried out by subsurface, drilling and completion professionals not associated with the project to ensure objective review. Other operational preparations include management -led Incident Free Operations workshops attended by key onshore and offshore Chevron staff, service partners and the drilling contractor to ensure alignment of all parties around Chevron's core values of safety and environmental stewardship and setting out clear expectations around incident free operations, stakeholder engagement, communications and continuous improvement. It also ensures familiarisation with our Key Principles, our Tenets of Operation and Stop Work Authority. Similarly, all parties involved in drilling operations participate in a Drill the Well on Paper exercise which examines the plans and procedures in place, identifies and addresses possible gaps and, crucially, ensures that potential risks and uncertainties in each hole section have been properly addressed and that mitigation and contingency plans are robust. Ev 84 Energy and Climate Change Committee: Evidence • These examples are only part of an extensive suite of measures designed to ensure that all parties involved in drilling planning and operations are fully aligned; that there are clearly defined roles and responsibilities; that risks are identified and appropriate control or mitigation plans are in place; that people are trained and competent, and that Chevron's core values of safety and environmental protection and expectations around Incident Free Operations are understood and embraced. i. DRILLING IN DEEP WATER Exploration drilling presents different challenges in different circumstances and it is vital that the risks are analysed, quantified, fully understood and mitigated. Chevron's exploration and drilling processes are designed to ensure that the risks associated with deep water drilling are properly managed. Deep water exploration carries issues of not just water depth, but water temperature and met -ocean conditions which have an impact on supporting marine operations and rig selection. The hazards of deepwater drilling West of Shetland relate primarily to the area's severe physical environment and remoteness. The area encounters long Atlantic swells and heavy seas. Currents are complex and fast; depending upon the location, they can vary in direction and speed at different water depths. The weather, especially during winter months, can be severe and lead to the temporary suspension of operations. There is a risk that methane hydrates (molecules of natural gas trapped in "cages" of ice) might form during certain operations, which could block pipe -work and processing equipment, possibly creating a hazardous condition, requiring careful planning and contingencies to be put in place, including the injection of inhibitors to prevent or slow the rate of hydrate formation. Primary well control is at the heart of well design and has the single aim of ensuring that hydrocarbons are prevented from entering the well in an uncontrolled manner during drilling, completion or abandonment. Robust planning, design and execution of the well are essential for maintaining primary well control and secondary well contingencies must be in place to contain pressure in the well in the event of an influx of hydrocarbons into the wellbore. The gases and fluids in a hydrocarbon reservoir can be under considerable pressure and have potential to be released into the wellbore if precautions are not taken. In all drilling operations a drilling fluid (known as mud) is pumped into the wellbore to maintain downward pressure in the well to counterbalance the upward pressure from the reservoir and to prevent "kicks" (unexpected influx of reservoir fluids). Well pressure is constantly monitored and the drilling fluids' properties adjusted to maintain stable pressure in the borehole. Should a kick occur, the driller will operate secondary well control equipment in the form of the blow out preventer (BOP). Chevron's policy is that the driller will immediately close the BOP whenever a positive indication of a kick is noted, without reference to higher authority. The BOP is an arrangement of special valves designed to monitor, control and, ultimately, seal off the well to bring a kick under control and prevent it from developing into a blowout. The BOP utilises a system of rams (opposing pistons which move horizontally across the top of the well) and annular preventers to close off the well and prevent reservoir fluids from escaping. A number of different types of BOPS can be used together in a configuration known as a BOP stack —thus providing multiple, redundant barriers. The specification for the BOP stack is part of the well design and reflects the expected reservoir pressure and fluid type. Operating the BOP is part of the normal procedure for bringing the well back under control in the event that a kick has occurred. Water depth (distance between the BOP and drilling rig) influences the selection of BOP control options which can be electrical or hydraulic signals, or a mixture of the two. Acoustic or ROV-deployed activation can also be used for emergency purposes. All BOPs have a fail-safe mechanism to close the well if control and power are severed. BOPS are classed as safety -critical equipment and UK regulations require that they are regularly inspected, tested, maintained and independently verified as fit -for -purpose. The selection of the right drilling rig is essential. Chevron has contracted the Stena Carron, a state of the art drillship specifically designed for year round drilling in harsh met -ocean conditions at water depths up to 10,000 feet. It is a dynamically positioned (DP) vessel that uses sophisticated systems to maintain position and heading without the use of anchors. This offers significant advantages over anchored rigs in terms of efficiency, greater ability to sustain safe operations in bad weather and in reducing risks associated with anchor handling in deep water. The Carron's blowout preventer system has seven elements —two annular preventers and five rams —that can secure the well depending on the nature of the situation. If a situation should arise that requires the vessel to move off location, this can be done quickly and safely by activating the Emergency Disconnect System. Two of the rams are shear rams capable of shearing the tubulars used during the drilling operation. In the event of a sustained blowout the primary response is to drill a relief well to intersect the blowout wellbore and to pump in mud to kill it. This is still an option but the Gulf of Mexico incident has highlighted 40 the potential for alternative capping and containment options which are currently under review by the OSPRAG Technical Review Group. Chevron has experts participating in this UK industry effort and is also one of the four companies who have committed to design, build and deploy a new containment system for the Gulf of Mexico. We have also taken steps to have a tertiary well capping mechanism available for our 2010-11 West of Shetland campaign. Energy and Climate Change Committee: Evidence Ev 85 8. ENVIRONMENTAL PROTECTION In addition and complementary to the regulatory requirements for environmental impact assessment and the production of comprehensive environmental statements and oil pollution emergency plans, Chevron has developed a number of processes within its Operational Excellence Management System for environmental stewardship, which requires that all health, safety and environmental risks are identified and assessed. These include our Environmental, Health and Social Impact Assessment process (ESHIA) which is applicable to all seismic, exploration and major capital project activities. 9. LAGAVULIN The Lagavulin prospect lies some 160 miles North of Shetland in a water depth of just over 5,000 feet. Chevron and its co -venturers plan to drill an exploration well in the prospect, with an expected start date in September and up to six months' duration. An Environmental Statement for the well was prepared in accordance with UK regulation and has been in the public domain since March 2010. Chevron is employing numerous procedures, practices and control measures to minimise the risk of major spill incidents during drilling operations, viz: — Rig selection —the well will be drilled with the Stena Carron (see description in section 7, above); — Well design —this has been subject to all the processes described above, including a second peer review by experienced drilling staff from our Gulf of Mexico Deep Water business unit, and has also been independently reviewed by the Well Examiner and an expert member of the Gulf of Mexico deep water team, and a review by the UK HSE-OSD wells team; — Blowout preventer operation assurance —the Stena Carron's BOP stack and associated well control equipment are all rated to 15,000 psi working pressure, against a maximum anticipated wellhead pressure of +/-9,650psi; inspection and verification of the BOP equipment will be carried out before it is run on the well and in addition to the regular testing regime, the back-up ROV-deployed control systems will also be tested; — Competence and awareness assurance of supervisory drilling personnel —the senior Drill Site Managers assigned to the well have been with the Carron since it came to Chevron and all have over 20 years' experience, including deep water operations; all will be certified in accordance with is Chevron's well control policy and will carry out drills with the Stena crew according to our well control policy to ensure competency; additionally, a member of the Chevron Global Well Control team will provide additional deep water control training to the rig crews and support the DSMs with competency assurance; — Drilling mud —water based mud will be utilized throughout the drilling operation; this has advantages for early kick detection and also offers environmental benefits; the mud will also contain chemical inhibitors to protect against the formation of hydrates; and — Audit/inspection—Chevron will undertake an internal safety and environmental audit of the Stena Carron prior to it drilling the potential reservoir sections at Lagavulin. Septemher 2010 Memorandum submitted by Dr Jonathan Wills "The area of Atlantic Ocean to the West of Shetland on the edge of the continental shelf, is characterised by extreme environmental conditions such as strong winds, huge waves, very low temperatures and significant water depths. " This quotation is from Total Exploration and Production UK,12 describing their new Laggan-Tormore gas project, lying 125km west of Shetland," in 600 metres of water. These are the harshest conditions in UK waters. So why go there? Total's public documents explain: — West of Shetland has the potential to produce 2.5 billion barrels of oil equivalent; — The area holds around 17% of the UK's remaining oil and gas reserves; — They contain more than 1 trillion cubic feet of gas, plus some condensates —equating to about 230 million barrels of oil equivalent; and — Peak production rates are expected to be about 500 million standard cubic feet per day. 12 See Total's "Project Overview" at: http://www.laggan-tormore.com/project.cfm and also their "West of Shetland Environmental Statement" at http://www.laggan-tormore.com/pdfiWest_of Shetland_Environmental_Statement.pdf 13 For an introduction to the Shetland Islands, see: http://visit.shetland.org/about-shetland Ev 86 Energy and Climate Change Committee: Evidence • Even though the development costs of the first group of wells are in the order of £2.5 billion, it is still worthwhile extracting gas out there. It's going to happen, along with further development of other gas and oil deposits and fields not yet discovered. The question is whether the regulators have the power, the determination, the staff and the money to ensure that it is done without unacceptable environmental damage. Let me first declare a direct and pecuniary interest in this subject: I make part of my living at Noss National Nature Reserve,14 showing tourists the amazingly rich and varied marine wildlife of the Shetland Islands.15 And I lost a lot of business the one and only time we had a big oil spill, in 1993. So I have more enthusiasm than most for keeping the sea clean, even though I work on a boat that burns 21 tonnes of diesel a year (that's about 10 litres per passenger). I also have grandchildren in London and Prague and am thus a disgracefully frequent flyer. So while I may sometimes have been seen as a critic of the industry, I'm also a very good customer. And I think that gives me the right to say what I think the oil and gas corporations ought to be doing better. I've watched BP at close and critical quarters in Shetland since the mid- 1970s, in my former careers as a journalist and environmental consultant and, more recently, as a councillor. I don't subscribe to the view that the initials BP stand for Bad People. Most of the BP officials I've met were honestly trying to do a good job. Not all succeeded, of course, but I should also declare that I believe BP's environmental performance in Shetland over the past 31 years has been mostly first class. They got off to a bad start when the 12th tanker16 to call at the Sullom Voe oil terminal, in December 1978, collided with a jetty and spilled 1,142 tonnes of fuel oil. The accident wasn't BP's fault but the failure to contain and clean up the spill certainly was. They learned their lesson and in April 1979, in co-operation with Shetland Islands Council, BP instituted a pioneering tanker safety scheme and one of the best pollution prevention and response regimes in the world. It went far beyond normal best practice and was enforced by the clauses in commercial contracts for the uplift of oil cargoes. This mechanism to ensure compliance was very effective but, alas, has not been widely copied in other oil provinces around the world. Given BP's record in Shetland I was rather surprised, in 1989, to find the company up to its neck in the Exxon Valdez disaster, where a BP -dominated firm, Alyeska Pipeline Service Company, in association with the US Coast Guard and the Alaska Department of Environmental Conservation, repeated all the spill prevention and response mistakes BP had made in Sullom Voe a decade before. The learning curve clearly had some big steps on it. I wrote this up in newspaper articles and a book. BP Alaska were not best pleased with me. They were still upset when, in 1999, I wrote a paper reviewing the impressive improvements that BP and its Alaskan partners had belatedly introduced after Exxon Valdez, and pointed out one or two things they appeared to have missed. They prevailed on my client, a citizens' advisory group established in Alaska by President George Bush (The First), not to publish my paper.17 I would be happy to provide the committee with a copy if it is of interest. Each oil or gas disaster brings demands for new laws and better working practices. Often the disaster could have been avoided if people had just complied with existing laws and best practice. In Shetland I have seen with my own eyes that it is possible to have a profitable oil and gas industry without causing widespread environmental pollution, ecological catastrophe, social disruption and the impoverishment of the majority. I admit this is a fairly uncommon situation, taking the world as whole, but I insist that it is possible. So I remain an optimist, the latest Gulf of Mexico blow-out notwithstanding. We're asked: "Could it happen here?" The answer seems to be "Yes". But we really don't know how likely a seabed blow-out is in the West Shetland oil and gas fields. The Macondo experience is telling us that there may be serious and hitherto unsuspected problems with blow-out preventers (BOPs). The record in the shallower waters of the North Sea over the past 40 years should be encouraging —there has been only one very prolonged, serious blow-out that I can recall (Ekofisk), although there have been some close calls. The Piper Alpha disaster caused terrible loss of life but the pollution was neither extensive nor prolonged. A question the technical experts surely must now answer is this: are the blow-out preventers properly designed for the much higher pressures of deep water drilling? And does the industry have credible contingency plans to deal promptly and effectively with deep sea blow -outs? In the relatively shallow North Sea it is usually possible to send down saturation divers to tackle problems. In the very deep waters west of Shetland it is not. As in the Gulf of Mexico, any response to a seabed blow-out would depend to a large extent on remotely -operated vehicles (ROVs). These submarines are ingenious machines and can do a great deal but, as we have seen with the Macondo well, they are slow and cumbersome. Contingency plans ought to reflect this. 14 See: http://www.nnr-scotland.org.uk/reserve.asp?NNRId=3 15 See: http://www.seabirds-and-seals.com 16 The Exxon -owned tanker Esso Bernicia. For an account of this incident and the parallels with the Exxon Valdez clean-up, see Wills, J, 1991. A Place in the Sun —Shetland and Oil. Mainstream, Edinburgh. 17 Wills, J, 2001. Partners or Regulators? Prince William Sound/Sullom Voe Comparisons, 1989-99. Prince William Sound Regional Citizens' Advisory Council, Contract Report No. 400.00.1, Valdez, Alaska. Energy and Climate Change Committee: Evidence Ev 87 If a damaged wellhead has to be sealed off permanently, the only way to do it is to drill a relief well. As we saw in the Gulf of Mexico (and north of Australia not long ago), this can take months. The technology is impressive but progress is necessarily slow. Because it takes so long, should relief wells be drilled alongside every group of new wells? And what would this cost? Of course, seabed blow -outs are relatively rare. Most spills come from exploration rigs, production platforms and floating production, storage and offloading vessels (FPSOs) at the surface. Most leaks are small and many are chronic. They have been a daily occurrence in the North Sea for almost four decades, although performance has improved with the progressive implementation of the OSPAR18 accords by member states. In the early 1970s we were very worried about the potential for massive pollution from submarine pipelines but, as far as I am aware, there have been no large, prolonged leaks from the thousands of miles of seabed pipeline laid since the 1970s. In fact, submarine pipelines in the North Sea appear to have a much better safety record than pipelines on land. We mainly learn about leaks of oil and gas from the polluters. This self -reporting is a problem because under the present enforcement regime there is no such thing as a surprise inspection to check on compliance. Ronald Reagan's principle of "Trust but Verify" is not applied offshore. It ought to be. It might have helped at Macondo. Another concern is the use of FPSOs in the "Atlantic Frontier" oilfields west of Shetland for the past dozen years. There have been several incidents, including a ship collision, and this system of oil production in deep water appears to be inherently more accident-prone than fixed or tethered platforms with subsea wellheads connected to pipelines. Should it be allowed to continue? Numerous official reports19 on accidents and incidents in the offshore oil and gas induStry20 suggest that the biggest danger to safe operations is in fact routine interference in the work of expert drillers and other technical staff, often by shore -based managers chasing financial targets, resulting in repeated failures to follow industry best practice. This seems to have been the case, yet again, with the Macondo disaster in the Gulf of Mexico. Some managers fail to ensure compliance with safety regulations; others turn a blind eye to corner cutting; and some even order operations staff to ignore the rules in order to get the job done on time and under budget. This seems to be what was happening on Transocean's Deepwater Horizon rig. Perhaps someone in government should have noticed. If they did, nothing was done in time. 0 Other questions that can be answered by witnesses more qualified than I am include: — Are the pollution prevention plans for West Shetland adequate? In partnership with the oil and gas industry, Shetland Islands Council has drawn up a pollution contingency plan,21 although it is not obliged to do so by law. However, it only extends a short way out to sea and deals mainly with tanker traffic in the port of Sullom Voe and with potential spills from the onshore oil and gas terminal there. — Are the government and industry response plans adequate for dealing with a deep -water spill? — Do we have an adequate compensation regime in the event of a spill from a wellhead, pipeline, production platform or drilling rig? The recent report by Client Earth22 would suggest not. What I can try to tell the committee, from my personal experience and knowledge, is: — How the Gulf of Mexico and West Shetland offshore environments differ. — Where seabed and surface spills are likely to end up. — What's at risk in those stormy waters off the west coast of Shetland. — Why this area is so exceptionally rich biologically. — Why conventional oil spill response techniques are unlikely to be effective west of Shetland. — And, last but not least, what the economic effects of a major, prolonged spill might be. How do the Gulf of Mexico and West Shetland offshore environments differ? Much of the Gulf of Mexico is far deeper than the area beyond the edge of the continental shelf west of Shetland. Around our islands the seabed is less than 200 metres deep, gently shelving down to a depth of about 500 metres. It doesn't reach 1,000 metres until midway between Shetland and Faeroe, part of the area currently being developed for oil and gas extraction. 18 The Oslo -Paris Convention to protect the environment of the North-east Atlantic, the North Sea and the Baltic. See: http://www.ospar.org/ 19 See, for example, the Cullen Report into the Piper Alpha disaster, at: http://hansard.millbanksystems.com/commons/1991/ mar/07/piper-alpha-sullen-report-I 20 See also the records kept by the Offshore Industry Liaison Committee (OILQ, now the offshore workers' branch of the RMT trade union http://www.oilc.org/oilcorg/ 21 See the recently updated version at: http://www.shetland.gov.uk/ports/Contingencypians/marinepollution.asp 22 See: Luk, S & Wilks, S, September 2010. Legislative Briefing: International and EU regulation of oil rigs and other offshore activities. Analysis and proposals for reform. Client Earth, 274 Richmond Road, London E8 3QW. http://www.clientea rth. org/reports/legisla tive-briefing-internationa I-and-eu-regulation-of-offshore-drilling.pdf Ev 88 Energy and Climate Change Committee: Evidence • Whereas the Gulf of Mexico is a basin, in which the main currents rotate in what oceanographers call a "gyre", the West Shetland sea area has more complicated currents, due to a broad, undulating ridge between Shetland and the Faeroe Islands. Here the relatively warm surface currents mostly run from south-west to north-east all year round, while the cold, dense, saltier water of the bottom currents spills over the Faeroe - Shetland ridge from north to south. However, there are significant variations and near the edge of the shelf the current may flow in the same direction on the seabed as on the surface. Total's researchers23 describe these currents as "complex" with "various strong non -tidal currents interacting with relatively weak tidal flow". At the surface, wind and waves certainly dominate the water movement: "On the surface, the deep water over the West of Shetland continental slope is exposed to a large fetch and strong winds, particularly from the west and southwest. These conditions generate an extreme wave regime in the area which is more severe than that experienced in the northern North Sea. The area is also affected by long periods of ocean swells generated from Atlantic storms." Where are seabed and surface spills likely to end up? The bathymetry of the Gulf of Mexico basin and the prevailing winds mean that most oil spills will stay in the Gulf of Mexico. Things are rather different in the North-east Atlantic, where the remains of any spill are likely to end up in the Arctic Ocean. We now have a good idea of the probable track of oil spills at the surface west of Shetland. The research24 done for the Foinaven and Schiehallion oilfields in the 1990s, together with more recent work in connection with the environmental assessment for Total's new gas fields, confirms that surface currents and wind will tend to take surface slicks in a generally north-easterly direction, parallel to the edge of the shelf, past the coast of Shetland and out into the Norwegian sea. This prediction is based on the prevailing south-westerly winds but strong winds may blow from any quarter at different times of year. The Meteorological Office wind rose data25 make this very clear. A strong and sustained north-westerly wind, very common at some seasons, would blow any oil slick ashore on the west coast of Shetland within two or three days. The track of a seabed spill from a wellhead or pipeline, on the other hand, is harder to predict. The cold, bottom current flowing to the south and south-west is not uniform and it is difficult to calculate its effect on a wellhead spill, although Total have tried.26 However, being warmer than the surrounding water, any is leaking oil or condensate would tend to rise towards the surface, where the current would certainly carry it in a predominantly north-easterly direction. But, once on the surface, it would be subject to the dominant influence of the wind. Further research may be needed if we are to model accurately the probable tracks of seabed spills in this area. We also have no clear idea of what proportion of a seabed spill would reach the surface in these cold, northerly seas. But it is interesting to note that seabed water temperatures in the Gulf of Mexico are surprisingly similar to the cold depths west of Shetland,27 although surface temperatures are, of course, much higher all year round. What we can be sure of (although Total say it is "unlikely" as far as the condensates from their gas fields are concerned)2s is that at least part of any large and prolonged spillage, whether it occurred on the seabed or at the surface, would be very likely to hit the shoreline somewhere in the 100 miles between Fair Isle at the southern end of Shetland and Muckle Flugga at the northern. Any beachcomber knows that. What's at risk on the Hest coast of 'the Shetland Islands? When oil spills come ashore they generate words and pictures as the media reports the latest wildlife disaster to the world. The media coverage of the Braer oilspill, which took place in midwinter when most of the seabird population was well away from Shetland, gives some idea of the publicity firestorm that could result from a midsummer spill in idyllic islands made justly famous by Simon King's wildlife TV shows. And the Braer was before the internet, Facebook and Twitter. Shetland's high media profile, as one of the best places in Europe to watch seabirds and marine mammals at close range, guarantees that any spill, let alone a blow-out, will make global front pages for many days, and for legitimate reasons. The public naturally becomes enraged when confronted with footage of thousands of oiled and dying seabirds on a beach. It is harder to feel sympathy for microscopic plankton and ugly anglerfish. Oil dispersed under the surface, particularly when it is 70 miles from shore, is unseen by reporters and camera crews but may have even more serious effects on marine ecology than a high profile coastal spillage. 23 See: "West of Shetland Environmental Statement", Section 6, at http://www.laggan-tormore.com/pdf/West of Shetland_Environmental—Statement.pdf • 24 See: Bett, B J & Masson, D G, 2000. Main discoveries of the AFEN research project. Section 6.1. http://www.noc.soton.ac.uk/ obe/PROJECTS/DEEPSEAS/pdf files/AFEN6l.pdf 25 See wind rose on foot of web page at: http://www.metoffice.gov.uk/climate/uk/ns/print.htmi 26 http://www.laggan-tormore.com/pdf/West_of Shetland—Environmental_Statement.pdf 27 The two regions even share similar cold -water corals of the Lophelia family. 28 See pp.193-196 of the Laggan-Tormore Environmental Statement at: http://www.laggan-tormore.com/pdf/West_of Shetland —Environmental Statement.pdf • is Energy and Climate Change Committee: Evidence Ev 89 Even in summer, the open Atlantic west of Shetland is, more often than not, a grey, cold, stormy place. From the deck of a ship it can look deserted, apart from scattered flocks of seabirds. Most people find it hard to imagine its cold depths as anything other than cold, deep and empty. In fact this ocean and its seabed are teeming with life -forms —equipped to thrive where we cannot survive. To quote the Atlantic Frontier Environmental Network (AFEN): "Contrary to general expectations, the abundance of animal life in the deep waters of both the Rockall Trough and Faeroe -Shetland Channel is not markedly lower than that encountered in shallower waters. In the Rockall Trough and the waters to the north of'Shetland, animal abundance appears to increase with depth."29 Over 2,000 different species of animals were recorded during seabed surveys in 1996 and 1998. Total's Environmental scientists30 have found the same: "In general, deep sea habitats demonstrate a decrease in biomass and abundance with increasing water depth but the West of Shetland area, because of its dynamic currents, temperatures and contours and trenches31 on the seabed, does not follow this trend..." Various species of sea urchin are the most common seabed animals here, along with burrowing worms, polychaete worms, shrimps, hermit crabs, sponges, sea anemones and colonial, encrusting animals such as bryozoan crinoids ("sea fans") and cold -water corals. The Atlantic margin west of Shetland is an important nursery and feeding ground for many commercial fish species, including haddock, monkfish, whiting, cod, saithe, ling, herring and mackerel. Valuable shellfish landed from this area are brown crabs, scallops, squid and prawns. The most abundant seabirds here are the northern fulmar, the black -legged kittiwake and the gannet. Common guillemots, arctic terns, puffins and storm petrels are seasonal visitors, on passage to and from their breeding colonies ashore in Shetland. In observations over the past 20 years, 16 species of whale and dolphin have been sighted in the West Shetland oil and gas fields. The edge of the continental shelf has been described as "a whale motorway". Why is this area so biologically rich? The best summary of Shetland's ecological significance that I have seen is in J. Laughton Johnston's book, A Shetland Naturalist (Poyser, 1999): "Shetland is a spectacular group of islands with a varied geology, a wonderful landscape and a special flora and fauna ... ... Shetland remains one of Britain's national treasures." The most outstanding features include the following: — The inshore waters around Shetland are still pristine, and certainly the cleanest in the North Sea (although marine litter is a significant problem). — The unusual "jigsaw" shape of the islands packs a profusion of coastal and marine life into the 1600-mile-long coastline of a land area of just 567 square miles. There is about 20 times as much coastline per square mile of land in Shetland as in Sussex or Norfolk. — The variety of inshore habitats over short distances is remarkable —from seabed over 120m deep to cliffs over 200m high; from tidal lagoons and sandy beaches to caves and kelp forest; from oxygen - depleted waters at the head of Sullom We to the turbulent, oxygen -rich waters of Bluemull Sound. It is doubtful if such a wide variety of coastal geomorphology could be found in an area of similar size anywhere in Britain. — Unlike much of Scotland, Shetland has a "drowned" coastline, due to a rise in relative sea level of some 120 metres since the end of the last glaciation. This has provided material for the outstanding diversity of sand and shingle bars, spits and "tombolos" (causeways), not found in such numbers anywhere else in the UK. All of these features are highly vulnerable to oil pollution. The submarine topography is extraordinarily varied over short distances, creating rich habitats for inshore sea life, particularly in the kelp forest, which may have an area of over 200 square miles (no-one has yet charted it accurately). — The continental shelf around the islands is one of the richest and most productive seas in the world. As a plankton producer it ranks with the Grand Banks of Newfoundland, Russia's Sea of Okhotsk and the Gulf of Alaska. Like the deeper waters west of the shelf edge, it is far more "biodiverse" than a casual observer might suppose. One reason for this is the extreme turbulence of our coastal waters, due to the mingling of Atlantic, Arctic and North Sea currents, the churning effect of tide races in the narrow sounds between the islands, and the upwelling of bottom water as tides and currents run over the drowned cliffs and ridges extending offshore from many headlands. Some of these submarine obstructions rise 30-40m from the seabed. In addition, Shetland experiences an average of about 100 days a year when the wind is Force Seven (near -gale) or higher. 29 Bett, B I & Masson, D G, 2000, op. cit. 30 http://www.laggan-tormore.com/pdf/West_of_Shetland_Environmentall_Statement.pdf i1 These trenches —and there are hundreds of them —are plough marks made by icebergs that grounded thousands of years ago when the sea level was much lower. • Ev 90 Energy and Climate Change Committee: Evidence The turbulence caused by all these factors traps large amounts of nutrients (mainly from rotted seaweed and dead plankton) in sunlit water less than 30 metres deep (the "photic zone"). Underwater visibility in Shetland is therefore surprisingly poor between March and September, due to the plant plankton "blooms" fed by the profusion of nutrients. This phytoplanktonic "fog" is in turn eaten by swarms of animal plankton. This zooplanktonic "snow", including the larvae of all our commercial finfish and shellfish, is food for fish, basking sharks and baleen whales. These blooms and swarms of plankton extend out to and beyond the continental shelf margin, well into the area currently being explored and exploited for oil and gas. Research32 into the effects of oil spills on plankton suggests very serious and long-lasting damage can occur —even if we don't spread the pollution throughout the water column by spraying dispersant on surface slicks or injecting it into plumes of oil leaking from a seabed wellhead. The plankton may be out of sight and, for most people, out of mind, but it is the basis of the coastal ecosystem. The plant plankton also produces a significant proportion of the oxygen we breathe. Without it the oxygen level in the atmosphere would drop below the 21 % level at which we have evolved. This surface layer indeed gave rise to the first plants and still contains most of the world's flora, by mass. It is extraordinarily thin and fragile, rarely more than 30 metres deep. In comparison with the diameter of the Earth, the phytoplankton layer is thousands of times thinner than the skin of a bubble. The precautionary principle strongly suggests that we should make all possible efforts to avoid damaging or disrupting it. At the top of the plankton -based food chain, Shetland's seabird breeding colonies33 are of international significance and among the largest in the North Atlantic. The Hermaness National Nature Reserve,34 for example, lies directly downwind and downstream of the Foinaven and Schiehallion FPSOs that have been producing oil since 1998. The island of Foula35 is another ornithological jewel, lying in the track of spills from the West Shetland fields when the wind is between west and north-west. A single spill during the breeding season could cause severe and widespread damage, all along the west coast of Shetland, to populations of gannets, fulmars, puffins, guillemots, black guillemots, razorbills, kittiwakes, arctic and common terns, great and arctic skuas, shags, cormorants, eiders, red -breasted merganser and red -throated divers. • A prolonged spillage from a blow-out, lasting weeks or months, could easily develop into a major ecological catastrophe. Even in winter, there are large populations of vulnerable seabirds inshore around the islands —including rare winter visitors such as great northern divers, slavonian grebes and long-tailed duck.3s Shetland is a vital staging post for migratory birds and has a world-famous ornithological observatory on Fair Isle. Shore birds and wintering wildfowl are particularly vulnerable to coastal oil pollution. Our populations of grey and common seals and otters are nationally important. Shetland has the highest density of otters in the UK. Grey seals have been recorded as far as 70 miles out in the Atlantic. The coastline is also of special botanical interest, with some surviving rarities such as oyster plant, surprisingly lush cliff meadows and very interesting plant communities now developing on more than 60 small holms where sheep are no longer grazed. Geologically, Shetland is more varied than almost any area of similar size in Europe. The islands have recently gained Unesco Geopark37 status because of this. The rock exposures along the shoreline range from basalt cliffs and ancient oceanic crust through almost every major rock type to Devonian fossil beds and desert sandstones. Classic sites include major structural features such as the northern extension of the Great Glen Fault and glacial overflow channels. Shetland's long ridges of hills and voes (sea lochs) are a textbook example of "Appalachian" landforms, related directly to the underlying geology. Coastal geological exposures of international scientific significance are all critically exposed to oil pollution. As the most northerly stretch of coast in Britain, Shetland is literally a place on the edge. The shoreline lies in the frontier zone between temperate and sub -arctic marine ecosystems. For some northern species it is the southern limit of their range, and vice versa. It is an ideal place to monitor and measure the ecological consequences of climate change, which is likely to have extreme effects in Shetland, particularly with the expected further rise in sea level. 32 See: Patin, SA, 1999. Environmental Impact of the Offshore Oil & Gas Industry. EcoMonitor Publishing, East Northport, New York. ISBN 0-9671836-0-X. http://www.offshore-environment.com/synopsis.html and Wills, J. W. G. 2000. Muddied Waters A Survey of Offshore Oi bfield Drilling Wastes and Disposal Techniques to Reduce the Ecological Impact of Sea Dumping. http:// citeseerx.ist.psu.edu/viewdoc/summary?doi=10.1.1.133.3403 3; See: Gage, J D, 2000. Deep-sea benthic community and environmental impact assessment at the Atlantic Frontier. http://www.sciencedirect.com/science'I_ob=ArticleURL&_udi=B6VBJ-435KF21-B&_user=I0& coverDate=05%2F31 %2F2001& rdoc=l&_fmt=high&_orig=search&_origin=search&_sort=d&_docanchor=&view=c& searchStrld=14 58538542& rerunOrigin=google& acct=C00005022I&-version=l&_urlVersion=0& userid=l0&md5=945df722b3310 62481287b273f6dt97c&searchtype = a 34 http://www.nnr-scotland.org.uk/reserve.asp?NNRId=1 35 www.foulaheritage.org.uk/Bird%20Sudies'/2OBibliography.htm i6 SOTEAG = Shetland Oil Terminal Environmental Advisory Group. See the annual reports of SOTEAG's monitoring programme, 1978-2000. 37 http://www.geoparkshetland.org.uk/ Energy and Climate Change Committee: Evidence Ev 91 • Shetland's environment is exceptionally well documented, with a larger literature about it in the natural sciences than for any similar -sized area in Scotland. A bibliography, which I compiled in 2003 for Shetland College and UHI, ran to 63 pages and over 1,000 books and papers. It was by no means exhaustive. There is a vast amount of "baseline" information about Shetland's coastline, due in part to the work of the Shetland Oil Terminal Environmental Advisory Group3S (SOTEAG) which for over 30 years has carried out regular biological sampling and monitoring under the auspices of Aberdeen University, to accumulate some of the longest -running, most detailed and methodologically consistent data sets of their kind in the world. Scottish Natural Heritage also has a long -running programme of wildlife and habitat monitoring, while the North Atlantic Fisheries College marine centre39 in Scalloway, Shetland, has recently completed a major piece of baseline research for the Shetland Marine Spatial Plan 40 This is part of the Scottish Sustainable Marine Environment Initiative (SSMEI) and one of the first —and certainly the most detailed — such projects in Britain. The Marine Atlas in the plan is a remarkably valuable data set, compiled in collaboration between scientists, fishermen and other marine industries, including tourism operators. So we know what we have at present and we would be able to say with some accuracy what we had lost if a major spill occurred, whether or not it beached. Unfortunately, there is no known way of compensating for such a loss. Will conventional oilspill response techniques work west of Shetland? The simple answer is "No". The reason is the weather. The Macondo slicks have shown us, yet again, that even in calm weather in the Gulf of Mexico the best containment booms, skimmers and other oil recovery techniques are unlikely to recover more than 20% of a spill, and mach of that will in fact be a water/oil emulsion. This has been detailed in the US Government and Congressional inquiries into the disaster. Few floating booms can hold oil in waves of more than one metre. Such small waves are almost never found in the West Shetland oil and gas fields. So most oil spilled will not be contained. Nor will it be recovered, as there is currently no open ocean skimmer capable of recovering more than insignificant token amounts, and then only during rare weather windows. Even if it were recovered, how could it be transferred to tankers and barges in the open ocean? Natural evaporation is far slower in the cold water of the North-east Atlantic than in the Gulf of Mexico and may be largely discounted, at least insofar as a spill reaching the coast in a few days is concerned. Burning oil at sea is possible in the Gulf of Mexico but impracticable in the rough, cold seas of the North- east Atlantic. So we can forget that also. The only practical way to deal with an offshore seabed spill is by injecting dispersants into the plume of oil at the wellhead or pipeline leak, and to spray the surface slicks as they appear. However, the risk of causing serious ecological damage to the plankton may outweigh the largely cosmetic benefits of dispersing a slick. It looks good on television but it's fairly ineffective and that's about all you can say for spraying dispersants.41 That leaves Nature to clean up. And sometimes she can. Although Gulf of Mexico/Caribbean hurricanes have long since blown themselves out by the time they have crossed the Atlantic, the remains of these storms do reach Shetland, where hurricane force winds of Force 12 are sometimes recorded several times a year. The Braer oil spill in January 199342 showed that prolonged, violent storms can be more effective than human efforts at cleaning up (or, at least, dispersing) some types of oil spill. This may also prove to be the case in the Gulf of Mexico during the 2010 hurricane season. Violent storms can disperse some oil but for best effect their energy needs to be concentrated by topography, as happened when a sustained (and rather unusual) Force 11 storm dispersed most of the Braer's 85,000 tonnes of oil by churning it up with the sea in two sandy bays less than 15 metres deep. This natural mechanism for dispersing spills is likely to be less effective in the open ocean. In summary, only a very small fraction of any open Atlantic spill west of Shetland is ever likely to be recovered or dispersed by human agency. Various snake oil salesmen and perpetual motion machine inventors will try to convince us otherwise but there is, in fact, almost nothing useful we can do once it happens. That is the awful truth and we would do better to face it and concentrate on preventing spills rather than entertain technological fantasies about mega -skimmers funded by celebrities and slurping up thousands of tonnes of oil. In your dreams... ;s http://www.soteag.org.uk/?/home 39 http://www.nafc.ac.uk/Home.aspx 40 The plan is available online at http://www.nafc.ac.uk/WebData/Files/Part°/2OOne%2OPolicy%2OFramework.pdf with the marine atlas section at http://www.nafe.ac.uk/WebData/Files/Part%2OTwo°/2OMarine%2OAtias.pdf 41 There has been an interesting debate about this in the US press. For example, see: http://green.blogs.nytimes.com/2010/06/ 02/more-dispersant-asking-hard-questions/and http://www. huffingtonpost.com/2010/05/ 13/wheres-the-oil-your-gover_n_575647.html 42 For a non -technical description of this incident see Warner, K and Wills, J W G, 2003. Innocent Passage —the Wreck of the Tanker Braer. Mainstream, Edinburgh. The scientific work is summarised in Kingston, P et al, 1994. Recovery of the Marine Environment following the Braer spill, Shetland. Ecological Steering Group on the Oil Spill in Shetland (ESGOSS), available online at: http://www.iosc.org/papers/01800.pdf Ev 92 Energy and Climate Change Committee: Evidence • What are the likely economic effects of a major, prolonged spill Shetland's fisheries (including salmon and mussel farms) were worth £225 million in 2006, in the most recent detailed economic study. The figure is now probably about £250 million. This is about four times the annual value of the Sullom Voe oil and gas terminal to the local economy. We know from experience in Cornwall (Torrey Canyon), Brittany (Amoco Cadiz), Alaska (Exxon Valdez) and Shetland (Esso Bernicia and Braer), that oil spills, particularly large ones, usually have some or all of the following consequences: — closure of fishing grounds; — massive destruction of farmed fish and shellfish; — loss of markets in the short and longer term; — loss of product reputation built up over many decades; — bankruptcies among boat owners, fish farm companies, processing factories, sales agents and local suppliers; — widespread unemployment among boat crews, fish farm workers, factory hands and employees of local suppliers; and — and that's before we consider the mental and physical illness caused to local people and cleanup workers.°' In addition, any spill gives an area massive bad publicity, which persists long after the oil has ceased to be visible. This depresses markets for all local products and particularly for tourism, which is likely to be severely affected for a full year after the spill and may take many years to recover. Tourism is a growing industry in Shetland, currently worth about £18 million. Its growth is mainly spurred by wildlife tourism, helped by some carefully targeted and highly effective publicity organised by the new Promote Shetland" marketing organisation. On top of these losses to private businesses and individuals, a spill inevitably creates costs for local authorities and voluntary organisations who try to respond, often when they have no statutory duty to do so. A spill such as the Braer can mean bills far beyond the means of a small coastal local authority. In the is end central government has to pay up if, as in the case of the Braer, the shipowners and their insurers contrive to escape full liability.45 So all spills cost the taxpayer. Compensation for victims of oil tanker spills is typically, slow, grudging and inadequate. But at least some of those who suffered financially from the Amoco Cadiz, Exxon Valdez and Braer spills eventually got something.46 And the spills I have mentioned are all "single -point" incidents where all the oil was in the water within a few days of the grounding. An uncontrolled leak from a seabed blow-out in the open Atlantic west of Shetland —pumping thousands of tonnes of oil a day into the ocean over many weeks —could devastate the Shetland economy, cripple the finances of the local authority and have long-lasting and far- reaching financial effects that are, literally, incalculable. With a spill from an offshore installation, it appears that there is little or no compensation available from the polluters or their insurers and the whole cost could well fall on the public. This surely amounts to the nationalisation of risk and the privatisation of profit, a phenomenon with which we are all wearily familiar in this country. The Gulf of Mexico spill appears partly to have been the result of lax enforcement and excessive familiarity (not to say conviviality) between the regulators and the regulated but in one respect at least the USA is ahead of us: in American courts it is possible to win exemplary damages (if the Supreme Court doesn't intervene) and also to sue for damage to environmental assets like birds, whales, seals and even plankton. It is a sad irony that in Shetland, where we have far better baseline information about our world - class environmental treasures than almost anywhere else in the world, the gannets, fish and plankton are not worth a penny in the eyes of the law. So I'm glad Parliament is looking into these problems and I hope you will propose some practical solutions soon. A good place to start would be Europe -wide laws on adequate compensation for spills from rigs, platforms and production ships. A firm but fair enforcement regime would be useful. A law to allow pollution victims to sue for environmental damage would help. And we should not forget the extraordinary power the insurance industry can wield, if it chooses, to require and enforce compliance with the highest standards of design, operation and maintenance. 43 See two books by Dr Riki Ott, an Alaskan marine toxicologist who studied the health effects of the Exxon Valdez spill: Ott, R, 2005. Sound Truth & Corporate Myth$. Lorenzo Press—http://www.chelseagreen.com/bookstore/item/ sound truth_and_corporate_myth/and Ott, R, 2008. Not one Drop. Chelsea Green—http://books.google.co.uk/ books?id = b-TWppwB_RwC&printsec = frontcover&dq = Riki + Ott&source = bl&ots = gMEPLzgHc5&sig = GV74 x2D 0628ijPXe1Za40ZdMk&h1= en&ei = p5COT0_RHNS7jAfc6,tWgBg&sa = X&oi = book_result&ct = result&resnum =16 &ved = OCFAQ6AEwDw#v = onepage&q&f = false 44 See: http://www.shetland.org/ 45 See: Wills, J W G, 2001. What Really Happened on the Braer. Shetland Post, Lerwick. 46 Although many Amoco Cadiz and Exxon Valdez claimants had died before the final payouts were made, 18 and 21 years respectively after the events. • Energy and Climate Change Committee: Evidence Ev 93 We are going to need quite a lot of oil and gas for at least a century, by the look of things, so the sooner we minimise its adverse effects on the marine life that sustains us all, the better. Thank you for the invitation to take part in your inquiry. It is much appreciated. September 2010 Memorandum submitted by ClientEarth INTERNATIONAL AND EU REGULATION OF OIL RIGS AND OTHER OFFSHORE ACTIVITIES ANALYSIS AND PROPOSALS FOR REFORM INTRODUCTION The regulation of offshore installations, including oil rigs, is seriously lacking at EU level and internationally. In the wake of the Deepwater Horizon disaster, and criticism of regulatory failings in the US, attention in the EU has focussed in on the question of whether a similar catastrophe could take place in European waters, and how its consequences might be dealt with. This question will only become more forceful as the drive for "energy security" pushes exploration efforts further into environmentally hazardous and sensitive territory. ClientEarth has looked closely at the state of regulation in Europe and the following paper examines where the main failures lie, and suggests what action is needed by way of legal reform to guard as closely as possible against another devastating offshore incident. Many EU laws controlling the operation of other dangerous activities, such as chemicals facilities, mining and transportation of oil by sea expressly exclude coverage of offshore drilling. Some (though not all) of the international conventions related to oil pollution also apply to oil rig pollution, but even then their implementation is not always reliable, enforcement mechanisms may be weak, and different rules exist for different regions. Many important aspects of oil rig regulation, or of deep sea exploration more generally, M are not covered by international conventions at all. For example, there are no international rules on liability and financial security in relation to these types of activities (as those which exist are limited to very restricted circumstances when oil pollution arises from ships or tankers). Earlier this year, in the aftermath of Deepwater Horizon, ClientEarth produced a legal background paper analysing the main rules governing the operation of offshore oil rigs in the EU, pointing out the significant weaknesses and gaps. Since then, momentum has grown in the EU and amongst certain Member States for a comprehensive regulatory reform. Energy Commissioner Oettinger gave his support to an EU wide moratorium on deepwater drilling on 14 July 2010, announcing at the same time that the Commission would be conducting an analysis of the situation during the summer, with a view to putting its proposals before the European Parliament and Council of Ministers in September. ClientEarth fully supports Commissioner Oettinger's call for an immediate moratorium until the causes of the Deepwater Horizon accident can be established and the regulatory regime internationally and in the EU strengthened as much as possible so as to avoid a repeat of that catastrophe. Since the publication of our original report, we have conducted further work on some of the legal issues raised by offshore drilling, whether for oil, gas or other mineral extraction, or other seabed projects such as carbon capture and storage. The following updated paper incorporates the previous analysis, plus additional material. We have organised the analysis into a number of thematic areas covering the different aspects of the regulatory landscape, examining what regulation already exists and what more is needed under each heading: 1. Rights to drill in territorial waters. 2. Pollution prevention —safety standards and inspections. 3. Emergency planning and accident response. 4. Research, monitoring and information sharing. 5. Impact and environmental assessments. • 6. Liability, compensation and financial security. 7. Company transparency. The various legal instruments reviewed each deal with one or more of these areas in combination, so there is some overlap in the discussion between the above headings. • Ev 94 Energy and Climate Change Committee: Evidence SUMMARY OF KEY POINTS A comprehensive new regulatory package is now needed that not only amends existing EU legislation where this is appropriate, but also introduces legislation to fill dangerous voids in the current regime. This new framework needs to extend to operational drilling projects, exploratory drilling, and the period after wells have been decommissioned. The opportunity should not be missed to ensure that all sea-bed drilling is carried out in a safe and properly managed fashion —be it drilling for oil, other minerals, or carbon capture and storage projects. ClientEarth's key recommendations for measures to be adopted in the new framework are summarised as follows. l . The EU Hydrocarbons Directive should require that licences for offshore hydrocarbon exploration and exploitation may only be issued where appropriate environmental protections (and financial guarantees) are in place. 2. A package of measures equivalent to the Seveso II, Erika and Third Maritime Safety packages is required for offshore installations. This new legislation should require: — Major accident prevention policies; — Safety reports covering specified information; — Emergency response plans at operator and Member State level; — Systematic inspection of installations according to designated criteria; and — Information exchange between Member States and with the Commission. 3. An EU level agency should exist to undertake functions in connection with these measures, to provide support to Member State authorities and to the Commission in ensuring full implementation and enforcement. The European Maritime Safety Agency is a clear candidate for • this role, and its capacity should be extended, with appropriate resources, to cover offshore installations in addition to its current tasks in relation to shipping. 4. The current review of the Environmental Impact Assessment Directive should result in amendments improving the application of impact assessments to offshore projects. These amendments should ensure EIAs are mandatory for the full range of seabed exploitation projects (in exploratory, operational, and decommissioned phases), improve the quality of EIAs, introduce specific guidelines for the content and evaluation of EIAs in the offshore drilling industry, impose special requirements for EIAs for hyper -hazardous activities, and improve the implementation of rules on transboundary EIAs. 5. A new liability regime is essential, tailored to the particular risks presented by offshore activities including oil rigs, carbon capture and storage projects, and all other seabed development. The Environmental Liability Directive in its current state represents a general system of environmental liability in the EU but is badly under -equipped to respond to the kind of damage which could result from an offshore pollution incident. The gap should be filled by a framework employing a broad definition of environmental damage, and capable of imposing strict liability on all potentially responsible parties. 6. The definition of environmental damage in the new liability regime should be comprehensive enough to cover damage to the global climate —a clear risk where seabed drilling and hydrocarbon pollution incidents are concerned. 7. A mandatory collective compensation scheme or other system of financial security is required as a key element of the liability regime. 8. The Marine Strategy Framework Directive should be amended so that its ambit extends to activities on the continental shelves which could affect marine waters in the exclusive economic zones, and so that consequences from marine accidents involving offshore installations cannot be used by EU Member States as a justification for failure to meet the 2020 target of good environmental status in marine waters. 9. Rules on company transparency need to be much more rigorous, with clear requirements regarding the nature and extent of environmental disclosures which companies are required to make. Current • activity on this issue within the European Commission must be prioritised. 10. A resolution should be passed at the September OSPAR ministerial meeting to extend the OSPAR Convention to cover emergency response measures, liability and financial guarantees. Implementation of the OSPAR and Barcelona Conventions must be improved, including via action by the EU institutions, as these conventions represent binding EU law. • Energy and Climate Change Committee: Evidence Ev 95 DISCUSSION OF INTERNATIONAL AND EU REGULATORY FRAMEWORK 1. Rights to drill in territorial waters: The UN Convention on the Law grthe Sea and the EU Hydrocarbons Directive Basic rights and obligations governing oil rigs are set out in the UN Convention on the Law of the Sea 1982 (UNCLOS), which gives coastal states the exclusive right to authorise and regulate drilling and oil exploration in their exclusive economic zones and on the continental shelf (Articles 56, 60 and 81). In respect of "the Area", ie the seabed, ocean floor and subsoil beyond the limits of national jurisdiction, natural resources are the common heritage of mankind and no State or person may claim sovereignty over them (Articles 136 and 137 of UNCLOS). In the EU, the key legislation is the Hydrocarbons Directive (Directive 94/22/EC). This specifically acknowledges the sovereignty of Member States over the hydrocarbon resources on their territories, ie that Member States retain the right to determine the areas within their territories to be made available for exploration and production of hydrocarbons (see Article 2(1)). The primary aim of the Hydrocarbons Directive is to impose rules ensuring non-discrimination in the allocation by Member States of prospecting licences, encouraging competition, and safeguarding the internal market. It is also intended to improve security of energy supply. Member States are permitted, under Article 6(2), to impose conditions and requirements on hydrocarbon exploration/production activities which they have authorised, including for reasons of environmental protection, the protection of biological resources, or the safety of installations and of workers. While this Directive therefore maintains the option for Member States to impose safety and environmental conditions on the operation of oil rigs (whether offshore or onshore) it imposes no incentive or obligation to do so. As noted, Member States have retained sovereignty over their hydrocarbon resources and how to exploit them. This is enshrined in the Treaty (Article 194 TFEU). However, the Treaties also enshrine the principle of ensuring a high level of protection and improvement of the quality of the environment. According to the principle of subsidiarity, EU legislation in areas of shared competence (which include environment, energy and public health, Article 4(2) TFEU) is justified (and required) if the relevant objectives cannot be sufficiently achieved by the Member States acting alone or at regional level, and are better achieved at Union • level by reason of their scale and effects (Article 5(3) TEU). Avoiding and dealing with an offshore oil spill is a prime example of such an action. The Treaty even envisages that measures may be taken in the area of the environment, by special legislative procedure, which may significantly affect a Member State's choice between different energy sources and the structure of its energy supply (Article 192(2)(c) TFEU). Member States' right to determine the conditions for exploiting their energy resources as stated in Article 194 TFEU is without prejudice to Article 192(2)(c). The Hydrocarbons Directive should be amended to the effect that Member States must impose adequate environmental conditions, or at least that Member State licensing authorities must be satisfied that the operator has taken appropriate measures in this regard, including through having in place emergency plans, and adequate financing to cover potential liabilities. If, as ClientEarth recommends, a comprehensive legislative package is introduced containing detailed specifications for oil rig safety standards, accident prevention measures, emergency planning, liability and compensation mechanisms, this should be cross referenced in the Hydrocarbons Directive so that Member States may not issue licences unless the competent authorities are satisfied that the measures contained in that instrument are/will be complied with. 2. Safety standards and inspections pollution prevention obligations There are various international conventions and EU laws which contain obligations to take steps to prevent pollution and manage the risk of accidents concerning oil rigs or other activities in the marine environment. The UN Convention on the Law of the Sea 1982 This contains environmental protection obligations regarding the marine environment (see Part XII, Article 192), including in relation to pollution from "installations and devices used in exploration or exploitation of the natural resources of the seabed and subsoil" and "other installations ... operating in the marine environment" (see Articles 194 and 208). There is an obligation to take pollution prevention measures in respect of activities in the Area, with particular attention to be paid to activities such as drilling, and the operation of offshore installations (Article 145). • UNCLOS therefore imposes international law duties on its parties to prevent pollution, including from oil platforms. It is binding international law, but relies on national and regional rules and cooperation to be put in place to achieve its goals. As a legal instrument in itself, it contains little in the way of sanctions against any country which fails to fulfil the duties it sets out. Therefore, it is necessary to examine EU and other regional rules (and national laws) intended to give effect to the aims of UNCLOS, to determine the status of the UNCLOS provisions targeted at preventing oil rig accidents. • Ev 96 Energy and Climate Change Committee: Evidence The OSPAR Convention A crucial international convention from a European point of view is the OSPAR Convention 1992. This applies in the North East Atlantic and obliges its Contracting Parties to "take all possible steps" to prevent and eliminate marine pollution and to "take necessary measures" to protect the maritime area against adverse effects caused by human activities, in order to safeguard human health and conserve marine ecosystems. The OSPAR Convention has 16 Contracting Parties including Iceland, Norway, Portugal and Spain, as well as the EU. It is implemented in the EU in the form of Decision 98/249/EC, but as the EU is a Party to the Convention, it forms an integral part of EU law in any event and is thus binding on all EU Member States (in relation to their activities in the North East Atlantic) and not just those which have individually signed it (see Article 216(2) TFEU). Pollution from offshore sources is specifically dealt with by the OSPAR Convention in Article 5 and Annex III (though it should be noted that "offshore sources" is defined by reference to hydrocarbon related activities only, not other seabed drilling such as carbon capture and storage or other mineral mining). Annex III contains the detail of the obligations. Article 3 of Annex III prohibits the dumping of waste from offshore installations, Article 4 requires the strict regulation by national authorities of the offshore use of substances "which may affect the maritime area", and Article 9 requires Contracting Parties to issue instructions regarding the inspection of installations and reporting of incidents. The conditions under which oil rigs themselves can be decommissioned and abandoned by the operators is addressed, and dumping without permission is prohibited. Article 7 of Annex III imposes an obligation on the Contracting Parties to: "take appropriate measures, both individually and within the relevant international organisations, to prevent and eliminate pollution resulting from the abandonment of offshore installations in the maritime area caused by accidents. In the absence of relevant guidance from such international organisations, the measures taken by individual Contracting Parties should be based on Guidelines as the Commission may adopt." (Emphasis added). The OSPAR Commission's Offshore Oil and Gas work stream has developed a number of further detailed • Recommendations for this sector, tackling topics such as the disposal of disused offshore installations, the disposal of materials resulting from offshore hydrocarbon exploration, environmental management systems in the offshore industry, and screening of chemicals proposed for use offshore. The OSPAR Convention expressly applies the precautionary and polluter pays principles and the use of best available techniques and best environmental practice (Article 2(2), Annex I, Article 2(1)). Similarly to Article 193 of the Treaty on the Functioning of the European Union, the OSPAR Convention allows Contracting Parties to take more stringent measures in relation to pollution prevention and elimination, or with respect to the protection of the maritime area against the adverse effects of human activities (Article 2(5)). The OSPAR Offshore Oil and Gas Industry Strategy from 2003 applies all of these principles, as well as the principle of sustainable development and an integrated ecosystem approach. It aims to develop programmes and measures to reduce marine pollution from the oil and gas industry, and to: "promote the development and implementation by the offshore industry of environmental management mechanisms, including elements for auditing and reporting, which are designed to achieve both continuous improvement in environmental performance and the environmental goals" and `promote the joint development oj'environmental best practice guidelines for offshore activities for the purpose of giving effect to the principle of sustainable development." The OSPAR Convention does not contain any provision for certain other important areas including emergency response planning, nor does it set down any rules in relation to clean-up and liability once an accident has occurred (see below). While it is binding law, and contains strong objectives, OSPAR relies on national governments and the EU institutions to put into effect its key requirements. The extent to which this is done in practice can be variable. As an international convention OSPAR lacks enforcement mechanisms generally. However, as binding EU law its provisions are directly applicable in all Member States and can and should be enforced by the EU institutions 47 In addition, every OSPAR measure (such as Recommendations of the OSPAR Commission on all OSPAR's major work streams, including Offshore Oil and Gas) has an implementation reporting and assessment procedure. This should assist the OSPAR Commission and working groups in identifying where measures are still lacking, and more action by Contracting Parties is needed. The 20 to 24 September 2010 will see a key meeting of the parties to the OSPAR Convention in Bergen, Norway, where Ministers from the Contracting Parties will discuss topics including a status report on the • health of the North East Atlantic environment, and actions for improving the protection of marine biodiversity such as the creation of protected areas. The status report will cover an examination of the impacts of activities in the region including offshore drilling. The Belgian Presidency of the EU has pushed 47 See, for example, case 104/81 Hauptzollami Mains v Kaupferberg, explaining the duty of EU institutions, as well as Member States, to ensure compliance with the obligations arising from international agreements. Energy and Climate Change Committee: Evidence Ev 97 • for deep sea drilling to be highlighted in the ministerial declaration that will follow the September meeting. It remains to be seen whether this will gain the backing of other OSPAR parties. New provisions on offshore installations and activities adopted under the auspices of OSPAR would bind the EU plus Iceland and Norway, so could be of great benefit. The Barcelona Convention The 1976 Convention for the protection of the Mediterranean Sea Against Pollution (the Barcelona Convention) (as amended) mirrors several of the provisions of the OSPAR Convention but applies instead to the Mediterranean Sea area. The Barcelona Convention, like the OSPAR Convention, applies the precautionary and polluter pays principles (Article 4(3)), and requires the use of best available techniques and best environmental practices (Article 4(4)). One of the types of pollution specifically addressed in the Barcelona Convention is pollution resulting from exploration and exploitation of the continental shelf and the seabed and its subsoil. Article 7 requires parties to the Convention to "take all appropriate measures to prevent, abate, combat and to the fullest possible extent eliminate pollution of the Mediterranean Sea Area resulting from exploration and exploitation of the continental shelf and the seabed and its subsoil." The Barcelona Convention has a number of protocols which contain detailed measures for protecting the Mediterranean from specific types of pollution. The Hazardous Wastes Protocol covers "waste oils/water, hydrocarbons/water mixtures" and emulsions within the definition of hazardous waste in addition to "mineral oils unfit for their originally intended use", and requires parties to "take all appropriate measures to reduce to a minimum, and where possible eliminate, the generation of hazardous wastes" (Article 5(2)). A protocol setting out provisions for protecting the Mediterranean from pollution resulting from exploration and exploitation of the continental shelf and the seabed and subsoil was drawn up in 1994 but has not entered into force as it still needs to be ratified by one further party. The only EU Member State to have ratified this Protocol is Cyprus, and the EU has as yet neither signed nor ratified it. • The EU is a party to the Barcelona Convention (along with 21 countries which border the Mediterranean Sea). This means the Barcelona Convention is a binding part of EU law (see again Article 216(2) TFEU), though the various Member State parties differ in their levels of activity in response to it. Although the Hazardous Wastes Protocol is in force, it has not been ratified by the EU. Among the EU Member States therefore, only Malta is bound by this Protocol as the only Member State to have ratified it individually. Some strong objectives on pollution prevention and safety standards exist at international level. In particular, Annex III of the OSPAR Convention requires Contracting Parties to take appropriate measures to prevent pollution from oil rigs. These requirements are binding requirements of EU law and must be implemented. However, the Convention lacks enforcement mechanisms, and more EU enforcement action is needed. The September OSPAR conference should resolve to build on the Convention in the wake of the Deepwater Horizon disaster. It should review current implementation practices and put pressure on any Parties not fulfilling any of their existing obligations to do so. Similarly, the Barcelona Convention requires Contracting Parties to minimise pollution resulting from seabed exploration and exploitation, and to cooperate in dealing with any pollution incidents in the Mediterranean Sea. These are binding provisions of EU law, but again there may be issues over full implementation. Although detailed Protocols regulating seabed activities and hazardous wastes have been drawn up they have not been ratified by the EU and are not binding on all EU Member States. In addition, the international conventions which currently exist are limited in their territorial extent. Stronger and more consistent regulation is therefore needed. The Marine Strategy Framework Directive The Marine Strategy Framework Directive (MSFD) (Directive 2008/56/EC) is worth noting in this section for its provisions dealing with environmental protection requirements in marine waters, for example by setting the requirement for Member States to achieve "good environmental status" in their marine waters by 2020. • The MSFD is intended to pursue good environmental status in EU marine waters including by phasing out pollution so that it presents no significant impacts on or risks to marine biodiversity and ecosystems. It incorporates a number of steps towards achieving good environmental status (assessed according to prescribed criteria), by 2020. There are certain grounds on which Member States can ask to be exempted from this deadline. Ev 98 Energy and Climate Change Committee: Evidence • One major weakness of MSFD is that there is no compliance mechanism. Member States cannot be challenged for a failure to achieve good environmental status by 2020. In addition the MSFD only applies within exclusive economic zones and does not extend onto the continental shelf. Any drilling outside the relevant exclusive economic zone could not be regulated by a programme of measures under the MSFD as it currently stands. Article 13 of the MSFD should be amended to state that the programmes of measures adopted under the MSFD should include measures applying to all sea-bed activities licensed by the Member States that take place on the continental shelf, outside their marine waters, and which could affect the environmental status of the marine waters within the exclusive economic zone. It should not be acceptable under the MSFD for an oil or other deep sea/seabed related accident to be accepted as a derogation from the obligation to achieve good environmental status. 3. EMERGENCY PLANNING AND ACCIDENT RESPONSE (i) The International Convention on Oil Pollution Preparedness, Response and Cooperation 1990, the Barcelona Convention and other international conventions Under international law, the key convention dealing with this area of regulation is the International Convention on Oil Pollution Preparedness, Response and Cooperation 1990, (the OPRC Convention). This agreement seeks to introduce measures to prepare for and respond to oil pollution incidents, including from oil rigs, by requiring coordinated and approved oil pollution emergency plans (to be prepared by the operator), as well as national contingency plans (to be prepared by government authorities), and by introducing reporting and information sharing and international cooperation requirements in relation to spills. The EU is not a signatory to this Convention, but the majority of its Member States are. Compliance with the Convention is mainly through regional seas agreements, such as the Helsinki Convention, the Barcelona Convention and the Bonn and Lisbon Agreements. However, there is great disparity between EU Member States (and regions) in the level of activity and effectiveness of the relevant regional seas conventions and • the implementation of the OPRC Convention. In addition, the OPRC Convention is concerned only with accident planning and response —it does not extend to issues of liability and compensation. The Barcelona Convention also has a specific protocol on this issue. The Prevention and Emergency Protocol sets out how parties to the Convention should respond in the event of a pollution incident including an oil spill from either a ship or an offshore installation, and it stipulates which state party should be responsible for bearing the costs associated with cleaning up pollution incidents within their jurisdiction (Article 13(2)) as It also requires parties to the Convention to ensure that operators of offshore installations in their jurisdiction have contingency plans for combating any pollution incidents (Article 11(5)). The EU is one of only seven Convention Parties to have ratified the Prevention and Emergency Protocol. This means that although only three Member States have ratified the Protocol individually, it is nonetheless a binding part of EU law and all EU Member States must implement its provisions when operating in the Mediterranean Sea area. Note: The International Convention Relating to Intervention on the High Seas in Cases of Oil Pollution Casualties 1969 also gives coastal states the right to take necessary measures on the high seas to prevent, mitigate or eliminate danger to its coastline or related interest from oil pollution or threat of oil pollution. There are also a number of other international conventions connected to safety, training etc. (For example, The Convention on Safety of Life at Sea 1974, the COLREG Convention 1972 on preventing collisions at sea and the STCW Convention 1978 on standards of training, certification etc). However, these conventions are not of such direct relevance in relation to the matter at the heart of this paper, incidents involving offshore installations. The OPRC Convention imposes emergency planning rules on operators of oil rigs, but it is not general EU law and its implementation is disparate. It does not cover other deep sea/seabed activities not connected to oil pollution. OSPAR does not provide for emergency planning processes or for clean up responsibilities and the allocation of liability. Neither does it provide for insurance or financial guarantees in relation to accidents. The Barcelona Convention contains emergency planning requirements, but is limited in its coverage to the Mediterranean. • To ensure that accident response plans are comprehensive across the EU—crucial given the transboundary nature of offshore pollution —improved implementation/compliance and EU wide requirements are needed. 48 Note this does not extend to a comprehensive system for assigning ultimate liability for pollution damage and/or a compensation system —discussed further below. • Energy and Climate Change Committee: Evidence Ev 99 (ii) EU safety, emergency planning and accident response: the Seveso II Directive, the Erika packages and EMSA As a consequence of the Piper Alpha disaster in 1988, there are now a number of EU Directives that aim to protect workers on oil rigs and that consequently impose safety procedures and safety measures in relation to oil rigs (see for example Directive 89/391/EC and Directive 92/91/EC). However, they prescribe only very basic safety measures, and do not provide for environmental protection standards. Seveso II The Seveso II Directive (Directive 96/82/EC on the control of major -accident hazards involving dangerous substances) imposes rules requiring operators of facilities handling dangerous substances to put in place major accident prevention policies, management systems and procedures. It includes notification and information requirements and rules on safety reports, emergency plans and even land -use planning with respect to the location of facilities handling dangerous substances (Articles 6-14). These measures are all aimed at safeguarding a high level of protection for "man and the environment" (see Article 7). However, the Seveso 11 Directive specifically does not apply to off -shore exploration or exploitation of minerals, including hydrocarbons (see Article 4(f)). It is therefore of no application at all in the context of oil rigs. Similarly, the Mining Waste Directive (Directive 2006/21/EC), which also contains provision for major accident planning (see Article 6) does not apply to oil rigs. Seveso II contains a number of crucial elements which should clearly apply to off -shore installations including oil rigs just as they are applied to other installations handling high risk substances. The recitals to Seveso II list several important features concerning the context of the legislation, which apply with equal force in the context of offshore oil drilling: for example, reference to the transboundary nature of accident impacts, the potential role of management failures in causing catastrophes, the need to harmonise inspection standards, and to give the public access to safety records. The extension of the Seveso II Directive to cover oil rig regulation in addition is an option worthy of consideration. However, it should be noted that simply removing the exclusion in Article 4(f) would not provide a complete solution to the oil rig problem. Seveso II is a Directive designed to deal with a particular type of situation, ie scenarios where dangerous substances are present in significant quantities over specified • thresholds. This may not always be the case for off -shore drilling (consider exploratory drilling or decommissioned rigs for example), and while Seveso 11's coverage extends to the anticipated presence of dangerous substances, is needlessly ambiguous. Seveso II deals with major accidents, while in contrast, a comprehensive system of regulation for oil platforms should also aim to address issues such as the incipient oil well leakage which occurs during "normal" operation and the possibility of leaks after rigs have been decommissioned. It applies to "establishments under the control of the operator" —which again, in the context of a platform drilling beneath the seabed, is not an appropriate wording. It covers land use planning but not the parallel of taking into account accident risks during oil field licensing processes. In summary, to use Seveso II as a vehicle for regulation of oil rigs (and other deep sea/seabed activities) would require a major overhaul of the Directive, and it may be more appropriate to deal with offshore drilling via separate legislation covering, in parallel, the features of the Seveso II Directive. On top of these Seveso II equivalents, other elements are necessary to the regulation of oil rigs, which Seveso II does not deal with, for example the allocation of liability for accidents and compensation mechanisms. These are discussed in the following sections. Finally, on the question of health and safety regulation, it should be noted that question marks currently exist over the capacity of Member State inspection authorities to ensure that even the basic worker' protection standards contained in current EU legislation are properly adhered to. For example, in the UK, the Health and Safety Executive (tasked with oil rig inspection duties) is under resourced in terms of a sufficient number of properly qualified personnel to carry out this function. It therefore relies to a significant extent on the industry to "self -regulate", providing information on risk management procedures and accident records, which the HSE itself may not have the capacity to verify independently. The possibility of augmenting Member States' inspection capacities via an EU level agency with responsibility for oil rig safety is returned to below. The Erika packages (I and II) and the Third Maritime Safety Package After the Prestige and Erika tanker oil spills off the French and Spanish coasts, the EU passed a number of measures aimed at preventing future accidents of this nature, including (but not limited to): — Measures linked to port state control (Directive 95/21/EC and Directive 2009/16/EC), ship inspections, safety standards and flag state requirements (Directive 94/57/EC, 2001/105/EC, • Directive 2009/21/EC, Regulation 391/09/EC and Directive 2009/15/EC), ship generated waste (Directive 2002/59) and on banning single -hull oil tankers (Regulation 417/2002/EC). — Measures to increase transparency in relation to the availability of information on ship safety, EU vessel traffic monitoring and information systems (Directive 2002/59/EC), and an EU maritime safety structure (Regulation 2099/02/EC). • Ev 100 Energy and Climate Change Committee: Evidence — Rules on traffic monitoring, accident investigation, and liability of carriers of passengers by sea in the event of an accident (Regulation 392/09/EC). — Mandatory requirements for ship -owners to insure against damage to third parties caused by their ships where such damage is not covered by the LLMC Convention (but not the oil pollution conventions mentioned above) (Directive 2009/20/EC). The measures introduced in the Erika packages and the Third Maritime Safety Package are aimed at oil pollution from ships. They do not address potential oil rig accidents or indeed other forms of deep sea/seabed activities. A key issue for consideration in this context is the role of the European Maritime Safety Agency (EMSA) (established —again in response to Erika —by Regulation 1406/2002/EC, and carrying out a number of key functions in respect of the implementation and enforcement of the measures described above). At the moment, EMSA's mandate specifically refers to ships, and it does not play any role either in relation to the inspection of oil rigs or other, non -shipping related offshore activities, or in relation to any oil pollution preparedness measures specifically aimed at offshore installations. It should be considered whether EMSA's role can, and should be extended in this direction. EMSA currently has various responsibilities and areas of experience which might place it well to take on a similar role in relation to oil rigs/other offshore installations. For instance: — Inspection tasks—EMSA has responsibilities for ensuring that EU legislation concerning ship safety and port control is properly implemented by the Member State authorities responsible for upholding it within their jurisdictions. For this purpose EMSA may undertake visits to Member State authorities. Its role may be seen as "controlling the controllers". — EMSA provides training for seafarers on safety issues, and also provides training for Member State inspectors. — EMSA provides support to Member States in investigating serious "maritime accidents". It also maintains a database on accidents, with the aim of making it easier to identify trends and manage risks. — EMSA has access to qualified engineers and a fleet of vessels for the purpose of assisting with clean • up of spills from oil tankers, and a satellite system ("CleanSeaNet") capable of detecting and tracking spills regardless of their source. Part of EMSA's pollution incident response function is to facilitate cooperation between Member States. — EMSA performs research and maintains databases of information on safety and technical issues, disseminating information on best practice. EMSA has the experience and technical capabilities to respond to oil spills whatever the source, and indeed has provided assistance in the case of Deepwater Horizon. All of these tasks could be extended into the realm of oil rigs and regulation of other deep sea/seabed activities, and potentially be of enormous assistance to Member State authorities. Consideration should also be given to whether EMSA could, with appropriate funding, go even further and take on a fully independent role eg in respect of the investigation of accidents or the inspection of installations. EMSA's future mandate is currently under review in any event, plus in addition the Commission is working on a feasibility study regarding a European Coastguard service. The potential role of either or both in relation to oil rigs should be a feature of this work. Extra funding will be needed. In EU law, more rigorous and detailed safety policies and management systems are required for oil rigs, as is a harmonised system of inspections. This could potentially be achieved by extending the provisions of the Seveso II Directive to oil rigs, which it currently excludes, but would be better be done by introducing a separate package of legislation covering the same elements as Seveso II to fill the current regulatory gap, including in particular requirements for: — operators of offshore installations to have a major accident prevention policy, — operators to produce safety reports covering specified information, — operators and Member State authorities to draw up emergency plans, review, revise and update these,49 — systematic inspection of installations by Member State authorities according to designated criteria (which should be specific to offshore installations), and production of reports on these inspections, and — information provision and exchange between the Commission and Member States. • Measures passed as a response to the Erika and Prestige disasters do not consider potential accidents caused by oil rigs. Off -shore installations need to be controlled and regulated in a similar way to ships. 49 Note this is a requirement of the international OPRC Convention, but as discussed below, implementation of this is patchy in Europe and an EU law requirement would be beneficial in ensuring all Member States' procedures were in line. • Energy and Climate Change Committee: Evidence Ev 101 EMSA's role should be extended to cover offshore installations including oil rigs. It should have enhanced and independent powers of inspection and enforcement. With appropriate resources, EMSA would be well placed to play a central role in any package of accident response measures. 4. RESEARCH, MONITORING AND INFORMATION EXCHANGE (i) International law: UNCLOS, OSPAR and Barcelona UNCLOS imposes on its Contracting Parties duties of monitoring and international cooperation (Article 197ff). The OSPAR Commission monitors the development of North Sea offshore oil and gas installations and maintains an inventory of details such as location, size, type and operational phase. The OSPAR Convention requires its Contracting Parties to provide various items of information to the OSPAR Commission, which collates this and publishes it on an annual basis. This includes information on emissions and discharges from offshore installations, including substances used in drilling operations, and accidental spills. OSPAR's work also extends to projects reviewing the impacts of carbon capture and storage operations. As noted above OSPAR countries are obliged in addition to report on the implementation and effectiveness of Recommendations of the OSPAR Commission. The OSPAR Convention also contains a general obligation on its Parties to cooperate in regular monitoring and assessment of the marine environment. Quality Status Reports are produced on a 10 to 20 year time frame. This assessment and reporting includes the effects of human activities in the North Sea, including the impacts of the offshore oil and gas industry. The Barcelona Convention likewise contains commitments on monitoring pollution in the Mediterranean area, and on sharing scientific and technical knowledge (see Articles 10 and 11). In Europe, the most systematic collection and dissemination of data relating to safety and environmental impacts of offshore installations is carried out under the OSPAR Convention. This is valuable, but only has relevance to the North East Atlantic region. Similarly, research and monitoring of pollution including from offshore sources is carried out under the auspices of the • Barcelona Convention, but only in respect of the Mediterranean. There is a need for a Europe -wide co-ordination of these activities, building on the work that is already on -going, ensuring consistent standards and sharing results, expertise and best practice across the regions (to include the North East Atlantic, Mediterranean plus the Baltic and Black Sea). (ii) EU measures: the Seveso II Directive, Erika packages and EMSA The EU measures described in the previous section, ie the Seveso II Directive and the Erika/Prestige and Third Maritime Safety packages touch on research, monitoring and information exchange in relation to the sectors which they cover. For example, Seveso Il requires that prescribed information about safety at the installations it regulates is compiled, reviewed every three years, proactively disseminated to the public and exchanged with other Member States. After major accidents, Seveso II requires operators and Member State authorities to collect specified information so that a full analysis can be performed of the "technical, managerial and organisational" aspects of the incident and recommendations made. Article 19 of Seveso 1I states as follows: "Member States and the Commission shall exchange information on the experience acquired with regard to the prevention of major accidents and the limitation of their consequences. This information shall concern, in particular, the functioning q/'the measures provided for in this Directive." As noted above, EMSA is tasked with maintaining a maritime accident database collating information on the causes and consequences of shipping related accidents. It is developing systems for harmonising the approaches taken by different Member States to investigating maritime accidents and dealing with data on shipping safety standards. One of EMSA's key roles is organising workshops, training sessions and expert discussions to facilitate the exchange of information between Member States, and the European Commission. The second "Erika Package" of EU legislation put in place monitoring systems to track and report on ships carrying hazardous goods. None of these monitoring and information systems apply to offshore installations or accidents involving oil rigs or other types of deep sea/seabed activities, and there is no equivalent centralised EU system. Within the EU, there are several systems in place for carrying out research, monitoring activity and sharing information in the realm of shipping, and EMSA plays a central role, but no equivalent exists for offshore installations. An equivalent framework is needed. Once again, EMSA's remit should be extended so it can carry out similar functions in relation to oil rigs and other forms of deep sea/seabed activities. This role could include liaising with the OSPAR and Barcelona Convention bodies to leverage the research and information sharing experiences already developed in the regions with which they deal. • Ev 102 Energy and Climate Change Committee: Evidence IMPACT AND ENVIRONMENTAL ASSESSMENTS (i) International law: UNCLOS, the Espoo Convention 2001 and the Kiev Protocol 2003 UNCLOS imposes on its Contracting Parties duties of monitoring and environmental assessment (Articles 204 and 205). The Espoo Convention (Convention on Environmental Impact Assessment in a Transboundary Context 2001) requires its Parties to "take all appropriate and effective measures to prevent, reduce and control significant adverse transboundary environmental impact from proposed activities" (Article 2(1)). The Convention requires that transboundary environmental impact assessments are carried out where significant adverse impacts are likely to result from a proposed activity, and the responsibility falls on the "Party of Origin", ie the party in whose jurisdiction the activity in question is going to take place. Appendix I of the Espoo Convention lists offshore hydrocarbon production as an activity with potential to cause significant adverse impacts, but not other possible deepsea/seabed activities, for example in relation to carbon capture and storage (see below). An oil spill from an offshore rig affecting more than one country would constitute a "transboundary impact' with a significant "impact' on the environment (including the marine environment). Importantly, the environmental and human health impacts which Parties to the Espoo Convention are required to prevent by taking relevant measures, are defined very broadly, and are not restricted to specific elements of the environment (as is the case, for example, with the EU Environmental Liability Directive, as explained further below). However, countries vary in their interpretation of whether adverse impacts are "likely". Guidance produced by UNECE on the Convention recommends that assessments are performed for projects whenever there is even a low likelihood of significant transboundary impacts,50 but this is not a requirement of the Convention itself. The Kiev Protocol on Strategic Environmental Assessment 2003 is intended to support the Espoo Convention by ensuring that individual Parties integrate environmental assessment into their more general plans and programmes at an early stage, thereby helping to lay the groundwork for sustainable development. The Kiev Protocol entered into force in June 2010. The EU is a signatory to both the Espoo Convention and the Kiev Protocol, which makes them integral • parts of EU law and immediately binding on EU Member States (see above). The EU rules on EIAs and SEAS (described in the next section) do incorporate transboundary requirements, but there are question marks over how well transboundary EIAs are operating in practice. In addition to improving procedures under the EU Directives, guidance at EU level on when a project may be expected to have transboundary effects would be useful. The application of the Espoo Convention and the effectiveness of transboundary environmental impact assessments within the EU appears to vary considerably and could be improved by EU wide guidance on when transboundary consultations should be carried out. It should be the case that transboundary EIAs are mandatory for offshore drilling, given the strong potential for a spill in the marine environment to have effects on more than one Member State. It may be necessary to amend EU legislation in these areas to ensure that international rules on transboundary assessments are properly incorporated. (ii) EU Environmental Assessment Rules Oil rigs are subject to requirements under various EU rules on environmental assessments, such as: — The Environmental Impact Assessment (EIA) Directive (Directive 85/337/EC as amended by Directive 97/11/EC): commercial petroleum extraction projects of more than 500 tonnes of oil a day are subject to mandatory environmental impact assessment (as they are Annex 1 projects); — The SEA Directive (Directive 2001/42/EC) under Article 3(2)(a); and — Appropriate assessments under Article 6(3) of the Habitats Directive (Directive 92/43/EEC), which applies to any plan or project that may have significant effects on sites protected under that Directive. The EIA Directive is currently under review and a number of issues arise in relation to its application to offshore installations which should be built in to this process with a view to making necessary improvements. Some of the issues arising in the context of the EIA review include: — Ensuring that exploratory drilling for oil or for any other resources or any other reasons is covered by the requirement for an EIA in every case. Currently an EIA is required under Annex I of the Directive for "Extraction of petroleum and natural gas for commercial purposes where the amount M extracted exceeds 500 tonnes per day...". It is conceivable that this could result in no mandatory EIA requirement for exploratory drilling projects, drilling for research purposes or other sea bed drilling activities not related to hydrocarbon extraction, which may not actually result in an oil rig producing more than 500 tonnes per day but may nevertheless pose serious environmental risks. 50 http://www.unece.orglenv/documents/2006/eia/ece.mp.eia.8.pdf Energy and Climate Change Committee: Evidence Ev 103 • — The quality of EIAs in some cases is a serious issue. There is currently no system for ensuring that those responsible for carrying out impact assessments perform this work to an appropriate standard, using reliable information and analyses; such as a system for accreditation of consultants, or for independent review. The Commission's current review of the EIA Directive already highlights the potential use of guidelines on specific issues to be taken into account in preparing EIAs for particular sectors. — Current experience as detailed in the Commission's EIA review shows that transboundary EIAs are hampered by practical issues including differing standards, guidelines, timetables and language difficulties cross -border. The definition of environmental impacts for the purposes of the EIA Directive is broad. However, climate impacts may not be considered, and there may be a need to refer expressly to these (liability for climate damage is discussed in more detail in the next section of this paper). In the case of exploratory drilling for sea-bed oil, it may be the case that the risks of a particular project do not fully emerge, or change in nature, as the drilling progresses. There should be a requirement that any material change to the information in an EIA which comes to light after a project has been consented be notified to the competent authorities. In the EU, specific rules exist in relation to environmental impact and strategic environmental assessments. In relation to oil rigs, the implementation of the EIA, SEA and Habitats Directives (as well as the Espoo Convention) needs to be monitored to ensure assessments are properly carried out and all provisions relating to environmental impact assessments are being applied consistently throughout the EU. The current review of the EIA and any potential recast should address the following points: — All sea-bed drilling and deepwater activities should require environmental impact assessment. The EIA Directive should be amended so that any sea bed drilling, or at least any sea bed drilling beyond a certain depth, is included in Annex I. This would enable coverage of carbon capture and storage activities, as well as any exploratory drilling which could otherwise be in • danger of falling through the gaps. — EIAs must be carried out to a satisfactory quality level. Key suggestions for improving quality include —accreditation of consultants, independence requirements for consultants, independent external review of EIAs, and guidelines on specific issues aimed at both the author of the EIA (ie what information should be covered) and the decision makers (how to weigh and assess the information). — The suggestion that sector specific guidelines are employed should definitely be built into the updated EIA Directive in respect of offshore installations. The guidelines should ensure that all of the potential consequences of an accident involving deep sea/seabed activities or installations, including oil rigs, are fully covered and assessed as accurately as possible, building on scientific/technical knowledge gained from previous accidents including Deepwater Horizon. A centralised database on oil rig and other relevant accidents (maintained by EMSA for example) would be of assistance to this end. All impacts and potential impacts need to be properly explored, including accident impacts, leaks following decommissioning or blocking of a drilling site, and oil leaks during "normal" operation. — New requirements should be made for EIAs for "hyper -hazardous" activities (such as deep water drilling) coupled with a prohibition on Member States' authorities granting development consent where the EIA reveals that risks cannot effectively be mitigated, or where technology to perform the activity safely does not exist. — The EIA Directive's procedures for transboundary impact assessments need to be improved, with procedural requirements properly harmonised. — EIAs should be required to take into account climate damage caused by oil rigs either during the course of normal operation or in the case of an accident resulting in large discharges of greenhouse gasses. 6. LIABILITY, COMPENSATION AND FINANCIAL SECURITY (i) International conventions on maritime liability and compensation for oil pollution With the exception of the OSPAR and Barcelona Conventions, which state the "polluter pays principle" is but do not go on to provide details as to how this should operate in practice, the "polluter pays" principle is not expressly applied in international law, and in particular no liability or compensation frameworks exist under international law with respect to the consequences of an accident involving pollution from an offshore installation. Commitments in the Barcelona Convention (Article 12) to develop detailed provisions for determining liability and compensation have not yet been adopted. • Ev 104 Energy and Climate Change Committee: Evidence International conventions dealing with liability in relation to oil pollution (and for that matter, other forms of pollution) arising from shipping, or with the limitation of liability for maritime claims, do not apply to pollution arising as a result of accidents on oil rigs or other offshore installations. They are restricted in their application to pollution incidents caused by ships. Therefore, none of the following conventions would apply to an oil rig accident: — The Convention on Limitation of Liability for Maritime Claims (LLMC) 1976. — The International Convention on Civil Liability for Oil Pollution Damage (CLC) 1992. — The International Convention on the Establishment of an International Fund for Compensation for Oil Pollution Damage (the Fund Convention) 1992. — The International Convention on Civil Liability for Bunker Oil Pollution Damage (the Bunkers Convention) 2001. — The International Convention on Liability and Compensation for Damage in Connection with the Carriage of Hazardous and Noxious Substances by Sea (the HNS Convention) 1996. The above instruments set out various systems for assigning liability for the consequences of spills to ship owners and operators, liability limits, funds to which ship operators contribute and which provide readily accessible compensation up to maximum limits, and mandatory insurance requirements. (ii) Compensation and financial security in the EU Plans to introduce a number of collective compensation schemes, or a fund providing a financial guarantee for civil liability, and to establish a wider principle of liability on the part of carriers and cargo owners were introduced under the Erika and Third Maritime Safety packages but never realised. The proposal included an EU level fund to top up the maximum compensation levels available under the various international conventions (described above) in the case of an oil spill from a tanker. Provisions for financial guarantees have been incorporated to a limited extent into the Mining Waste Directive but only in relation to the period after the mine closes (eg after decommissioning) and for land rehabilitation (in Article 14). However, in any case, neither the Mining Waste Directive nor the liability and insurance rules of the Erika and Third Maritime Safety packages extend to operators of offshore installations. • The Environmental Liability Directive (discussed in detail below) does not contain provisions for guarantees of financial security, or (as a general liability framework) collective compensation mechanisms for particular sectors. As matters stand therefore, nothing exists under EU law in terms of a compensation fund, automatic liability or mandatory insurance or other financial security requirements for oil rig/offshore installation operators. As seen in the previous section, there is no framework under international law either which would cover this gap. As such, it is essential that consideration be given to a new EU mechanism requiring either contribution to a collective compensation scheme, and/or other types of financial security, including insurance, to provide for the costs of remedying environmental damage. Precedents such as the IOPC Funds for ship based oil pollution, and the EU rules on ship pollution liability are available. Other sectors, such as waste, have related requirements —for example the Landfill Directive (Directive 1999/31/EC) provides that Member State authorities may not issue landfill permits unless satisfied that adequate provision has been made by way of financial security to cover operations including after -care of a landfill site. Voluntary industry schemes already exist —four of the major oil companies have instigated a scheme of their own following the Deepwater Horizon disaster, to deal with accident response. OPOL, involving operators on the UK continental shelf, is an industry funded arrangement guaranteeing compensation up to a certain level, including in the event that the operator responsible cannot pay. However, arrangements need to be mandatory and contributions must be calculated to cover the realistic costs. Clearly, detailed consideration will need to be given to what the appropriate contributions and compensation limits need to be, in view of the maximum costs of the Deepwater Horizon clean up and in consultation with industry, regulators, and observers. International conventions on liability and compensation for oil and other pollution only apply to ships, not to oil rigs or other offshore activities. Therefore they will not provide any funds or compensation in relation to an oil spill caused by an oil rig or any other environmental damage caused by any deep sea/seabed activities. Given the potentially enormous quantities of oil which could be released by an oil rig accident, for example, as compared to a tanker accident, the absence of an equivalent framework for compensation and liability covering oil rigs (and increasingly also other types of deep sea/seabed activities) is a gross imbalance. • No system exists at EU level to fill this gap. The Environmental Liability Directive (see below), contains no requirements relating to compulsory financial security or insurance requirements for operators undertaking Annex III dangerous activities. Neither does any other EU law. This is a crucial feature of any comprehensive liability regime, as without guarantees that funds will be available in the event they are needed, liability will be a pyrrhic victory. • • Energy and Climate Change Committee: Evidence Ev 105 Drawing from the international conventions listed above, and considering what is necessary in the context of offshore drilling, the following elements should be covered in a liability and funding framework: — An agreed system assigning liability in the event of a pollution incident involving an offshore installation to the party or parties responsible. This should entail all potentially responsible parties on a joint and several basis. Liability should be strict (see also comments in the following section). — A fund, to which compulsory payments must be made as a condition of being granted operating licences for offshore activities. This fund would guarantee resources for clean-up operations and compensation payments for personal injury, property and other environmental damage (broadly defined), up to set limits. Research is needed on the basis of the costs of previous spills in order to decide what the appropriate payments and limits should be, and there should be widespread public consultation on that issue. — In the event that the party responsible for the pollution is unable to pay, for example in case of insolvency, the fund should be available to meet costs. — Financial security conditions should extend to the period after a well is decommissioned, for example by requiring bonds or funds regarding potential future liabilities. — Consideration should also be given to whether insurance is an appropriate vehicle for financial security. — The system should apply to any entity which wanted to undertake offshore drilling or any other type of offshore activity in the deep sea/seabed for any purpose including oil, gas, other deep sea minerals, CCS and including exploratory drilling. — The Hydrocarbons Directive should be amended so the Member States may not issue licenses for off -shore drilling unless the operator can demonstrate it has emergency funds and/or insurance for environmental damage in place up to a sufficient minimum level. (iii) Liability in the EU: The Environmental Liability Directive The key piece of liability legislation relevant at EU level is the Environmental Liability Directive. As seen above, at international level, virtually no framework exists for regulating liability with respect to oil rigs or other deep sea/seabed activities. Likewise, no formal compensation structure exists at either EU or international level as far as such activities are concerned, though there is precedent in the form of oil tanker regulation, and voluntary industry agreements. The Environmental Liability Directive (ELD—Directive 2004/35/EC) establishes rules that implement the polluter pays principle by making "operators" carrying out certain "dangerous" activities (see below) automatically, and regardless of fault, responsible for preventing and remedying significant damage to water (defined by reference to the Water Framework Directive (Directive 2000/60/EC)), soil (if there is a risk to human health) and biodiversity (certain habitats and species protected under the Habitats Directive (Directive 92/43/EC)). It also imposes fault -based liability in relation biodiversity damage only (as just defined) as regards all "occupational activities" (not just certain "dangerous" ones). The ELD applies in Member States' exclusive economic zones. Crucially however, the ELD does not cover any category of marine water damage. Out of the damage categories covered by the ELD, only biodiversity damage could be a relevant consideration in relation to an oil rig accident, and only where the incident caused serious damage to a protected species or habitat. To trigger liability under the ELD, such damage would need to have a significant adverse effect on species or habitats protected under the Wild Birds Directive (Directive 2009/ 147/EC), or Habitats Directive (Directive 92/43/EC), as regards their reaching or maintaining favourable conservation status (see Article 2(1)(a) of the ELD). Annex III of the ELD lists a number of activities which are perceived as dangerous (and regulated as such under EU law), or which involve dangerous substances. Thus, it includes the management of extractive waste pursuant to the Mining Waste Directive, but also the: "7. (mJanufacture, use, storage, processing, filling, release into the environment and onsite transport of: (a) Dangerous substances as defined in Article 2(2) of Council Directive 67/548/EEC... Annex I of Directive 1272/2008/EC, replacing the Annex I of the abovementioned Directive 67/548/EEC, lists the substances referred to in Article 2(2) of Directive 67/548/EEC (which still applies today). Hydrocarbons and crude oil are included. Under the same Directive 1272/2008/EC, the definition of Is "manufacture" includes the "production or extraction of substances in the natural state" (Article 2(14)). The drilling and extraction of crude oil is therefore covered by Annex III of the ELD, and any damage caused by such activity which caused significant adverse effects to any such sites or species protected under EU law would trigger strict liability on the part of the operator under the ELD. • Ev 106 Energy and Climate Change Committee: Evidence In cases where liability is established under the ELD, the rules require that the damage must be reinstated and/or complementary and compensatory remedial measures might also be required (see Article 6 and Annex II of the ELD). Both the operator and the competent authority are under a duty to take action, with costs incurred by a competent authority being recoverable from the operator (see Articles 5, 6, 7 and 11 ELD). There are also requirements relating to the prevention of damage where there is an imminent threat of it occurring (Article 5). However, major problems exist with the application of the ELD generally and some of these problems are particularly pertinent in respect of oil rig accidents (or accidents relating to other deep sea/seabed activities). Firstly, the ELD covers only specific types of environmental damage, and not damage to biodiversity, water or soil in general. Namely, as already explained, it relates only to areas of environmental protection in relation to which the EU has made specific rules (eg water status and protected species and habitats). However, other types of environmental damage including damage to habitats, species and ecosystem services outside of the framework of special EU protection would not be covered by the ELD. This stands in stark contrast to other, generally applicable directives, such as the EIA and SEA Directives and, importantly, the Mining Waste Directive, which apply much more broadly to risks to "the environment' in general (see for example Article 4(1) of the Mining Waste Directive). Oil pollution from an oil rig accident could have widespread environmental effects which would not be captured by the ELD as it currently stands. Against this background it should be noted that the EU Natura 2000 network of protected sites under Directives 79/409/EEC and Directive 92/43/EEC has not yet been fully designated in the marine zone, which has knock -on effects for the coverage provided by the ELD. Secondly, the damage thresholds that trigger liability under the ELD are set at a very high level, which is incredibly difficult to establish (the ELD has been in force since 2007 and has been applied very infrequently). On the other hand, the Mining Waste Directive (which has aims very closely connected to those of the ELD and is listed in Annex III of the ELD—see further below), sets a much lower damage threshold in its general requirements: danger to human health, harm to the environment, in particular risks to water, air, soil, and fauna and flora (Article 4). Thirdly, as already explained, the ELD introduces two different liability regimes (Article 3(1)). In relation to activities listed in Annex III of the Directive, it imposes strict liability. In relation to other "occupational • activities" (essentially, all other commercial or business activities), liability for biodiversity damage is fault based, and there is no liability at all in relation to water and soil damage. It is questionable whether the Annex III definition is robust enough to capture exploratory drilling activities, and other types of sea-bed drilling not entailing the extraction of hydrocarbons, plus activities in connection with sealing and decommissioning a drilling site once its use was at an end. If the ELD were extended to apply to marine water damage, then it would be important that strict liability rules extended to this category of damage for all occupational activities, not just Annex III activities. It should also be noted that the ELD does not apply to environmental damage arising from incidents in relation to which certain international oil (and other) pollution liability conventions (listed in the above section on compensation funds and financial security) are triggered. However, these conventions are restricted in their application to oil (and other) pollution from ship sources, not from oil rigs. The Environmental Liability Directive applies to oil pollution caused by oil rig accidents in very limited circumstances, namely where significant damage is caused to biodiversity with protected status under EU law. As the extraction of crude oil falls within the list of dangerous activities in Annex III of the ELD, strict liability (ie liability regardless of fault such as negligence) would attach to the operator of the oil rig in these circumstances. However, this is the extent of the ability of the ELD to respond to environmental damage caused by an oil rig accident. Environmental damage as a general concept is not covered. Damage to marine waters per se, independent of any particular biodiversity damage, is not covered, unlike inland water damage. Damage to the global climate is highly unlikely to be captured. In effect, damage categories under the ELD are extremely narrow, and damage thresholds are extremely high. The ELD is scheduled to be reviewed in 2013-14 (see Article 18), and its current weaknesses should be remedied at this opportunity. With adequate amendments, the ELD could provide an effective solution to regulating liability for oil rig pollution and other deep sea/seabed incidents. However, if this cannot be achieved, it is essential that separate legislation is passed in parallel to the ELD to address these types of activities specifically. Liability regimes specific to particular activities are necessary where the risk profile of those activities demands it, as in the case of seabed drilling. The following points should be addressed in such legislation (as well as being considered more broadly in the wider ELD review): — Damage thresholds need to be materially lower than those in the current ELD. The ELD, and any specific oil -related (or deep sea/seabed activity related) liability legislation, should contain wide-ranging definitions of "environmental damage" as do the EIA and Mining Waste Directives. The definition should be broad enough to include damage to the global climate. E Energy and Climate Change Committee: Evidence Ev 107 There must be strict liability coverage for all seabed activities, including phases of a project before the "production or extraction of substances" has actually commenced. There must be coverage for activities in relation to sealing and decommissioning of a site as well as its operation. As concerns the ELD, Annex III should be extended to cover all of the potentially environmentally damaging activities listed in the annexes to the EIA and SEA Directives. — Liability for offshore pollution must be capable of attaching to all potentially responsible parties on a joint and several basis (not only to the owner or "operator" of the oil rig or other installation). Any one potentially responsible party must be capable of being found liable for the maximum costs of clean-up and compensation. The designation of liability as between joint venture partners, subcontractors, and so on, should be allocated by those parties between themselves without prejudice to the position of clean up operations and victims of environmental damage. The 30 year temporal limitation under the ELD needs to be reviewed, and such a limit is certainly inappropriate in the context of specific regulation addressing liability in the case of offshore drilling. Capped wells may leak decades after they go out of use. At the moment there is no system assigning liability for oil spilt from a decommissioned well which has been abandoned by its original operator. The regulation of sea-bed drilling should reflect the regime for (for instance) waste as set out in the Landfill Directive, where the responsibilities of the site operator during an after -care period are acknowledged. Operators should remain liable for drilling sites after closure. — Mandatory financial security provisions are required to complement the liability regime —see the previous section. (iv) Liability for climate damage In addition to the problems described above for dealing effectively with liability in general, no mechanism currently exists, either at EU level or internationally, for dealing with liability for the damage to the global climate which could result from a marine disaster. In addition to oil spill fires, including controlled burns issuch as those deployed in response to the Deepwater Horizon incident, such damage could result from methane or other greenhouse gas emissions released by sea bed drilling. Climate damage constitutes a special kind of damage, which, because it may not necessarily result in local damage to habitats or humans, or protected species, runs a very high risk of falling through the cracks of liability regimes such as the Environmental Liability Directive. As well as their physical consequences, large releases of climate forcing emissions pose an additional problem in that they risk pushing legally binding carbon budgets and emissions trajectories out of line. A method therefore needs to be found for accounting for such accidental releases in frameworks such as the EU Emissions Trading Scheme. The issue of liability for climate damage has arisen in the context of carbon capture and storage (CCS), and legislation regulating this sector does at least acknowledge and attempt to deal with the issue. Where leakage occurs from CCS sites, there will be (1) strict liability under the ELD where local damage also results, (2) financial liability, to buy carbon credits under the EU ETS to cover the amount of the leak, and (3) liability in tort where there is property or health damage to a third party. There are serious failings with this approach. Firstly, as we have seen, the scope of the ELD is very limited and it is easy to envisage a situation where a climate damaging release of gasses would have no immediate effect on an EU protected site or species, so that the ELD would not apply. Secondly, a requirement to buy carbon credits is not a penalty in itself. It simply limits liability for climate damage to the current carbon price. In addition, the quantity of gasses released may be impossible to quantify, and the solution is limited to carbon dioxide, ignoring other climate forcing emissions such as sea-bed methane. Finally, tort liability would only arise where the leaked gasses caused personal injury, damage to private property or economic loss, so again, does not respond to the full range of environmental damage. The EU liability regime needs to be capable of capturing significant damage to the global climate, whether this results from CCS activities or any other marine activities including offshore oil drilling. As already discussed in the context of the ELD, definitions of "damage" in the environmental liability regime should be as comprehensive as possible, but in any event should cover damage to the global climate. A liability system designed specifically to address offshore/ seabed activities should encompass legal obligations to take corrective measures where accidental releases of greenhouse gasses occur. Corrective measures may often involve domestic offsets. A mechanism also needs to be found to incorporate estimations of these significant additional emissions into greenhouse gas reporting frameworks and account for them in carbon budgeting. • The Directive on geological storage of carbon dioxide (Directive 2009/31/EC) was an example of a missed opportunity to install a fit for purpose liability regime able to cope with the risks represented by a particular sector, with the result that CCS activities will currently proceed under a limited liability framework. The picture for CCS could be remedied by a new regime covering oil rigs, but extending to all seabed drilling projects in addition. • Ev 108 Energy and Climate Change Committee: Evidence 7. COMPANY TRANSPARENCY Company transparency is a vital aspect of ensuring that individual companies properly manage the environmental risks associated with their activities. The Deepwater Horizon disaster and related market losses have demonstrated the potential vulnerability of investments in companies operating in sectors with high environmental risks, where companies have not taken sufficient precautions to guard against such risks. International framework Currently, there is no system of environmental reporting requirements within international accounting frameworks, such as the International Financial Reporting Standards. Many companies produce corporate social and environmental responsibility reports, but frequently on a voluntary basis (depending on national requirements) and these vary widely in terms of their coverage and quality because no global standard exists. The Global Reporting Initiative (GRI), an organisation established in alliance with the United Nations Environment Programme and consisting of a network of businesses and NGOs, has developed a set of Sustainability Reporting Guidelines to promote a standardised approach to reporting of (amongst other issues) companies' environmental performance. A Sector Supplement to the Guidelines is being developed for the oil and gas industry which will cover, amongst other items, reporting of emergency preparedness and response measures taken by oil and gas companies. However, the GRI Guidelines are currently subscribed to on a voluntary basis only. The GRI has recently collaborated with the Prince's Accounting for Sustainability Project to set up an International Integrated Reporting Committee (IIRC) to develop a globally accepted framework for sustainability accounting. Importantly the IIRC will include input from standard setting bodies such as the International Accounting Standards Board. While such international accounting standards are not mandatory as such, compliance with them is generally required for the signing -off by auditors of the accounts of public companies, so that incorporation into these standards of suitably rigorous environmental reporting requirements could have significant effects. • EU requirements EU law contains some basic requirements for reporting by companies on environmental issues. The main piece of legislation on this topic is the Accounts Modernisation Directive (Directive 2003/51/EC). This amended the Fourth Council Directive on the annual accounts of certain types of companies (Directive 78/ 660/EEC) to include the following provision: "To the extent necessary for an understanding of the company's development, performance or position, the analysis [to be included in the annual report] shall include both financial and, where appropriate, non -financial key performance indicators relevant to the particular business, including information relating to environmental and employee matters;" Commission Recommendation 2001/453/EC (on the recognition, measurement and disclosure of environmental issues in the annual reports of companies) led up to the adoption of the Accounts Modernisation Directive and contained detailed discussion of what the Commission considered to be appropriate for company disclosure in relation to environmental issues. The Recommendation set out guidelines for how environmental liabilities and environmental expenditure should be recognised and measured in company reporting and on the sort of environmental disclosures companies should make, for example information on energy performance energy, materials and water use, emissions and waste disposal. However, the Recommendation has no legal force. The Commission has in recent months undertaken a series of workshops and discussions with stakeholders on the subject of improving company reporting of environmental issues. No legislative proposal has yet emerged from this process. Various international accounting standards have been adopted as EU law (see Regulation 1606/2002 and Commission Regulation 1126/2008), so that companies traded on regulated markets within any of the Member States must prepare their annual accounts and reports in accordance with them. Incorporation of environmental reporting requirements into such international standards, via the work of the IIRC for example, could lead to such measures being adopted as EU law and becoming legally binding in EU Member States. • Enhanced mandatory disclosure on environmental issues and corporate governance is essential to ensure improvements in environmental practices. Voluntary environmental reporting standards exist internationally, but there is currently no framework with legally binding effect. Systematic environmental reporting requirements should be built into international accounting standards, and these should be incorporated into EU law. Energy and Climate Change Committee: Evidence Ev 109 • The current EU rules on environmental disclosure are not sufficiently stringent. The Commission should bring forward, as a priority, its initiative to enhance company environmental, social and governance disclosure, and a rigorous, mandatory and enforced framework for disclosure on these matters. September 2010 Memorandum submitted by the Department of Energy and Climate Change, Health & Safety Executive, and Maritime and Coastguard Agency INTRODUCTION 1. This Memorandum first sets out some general information relevant to the Committee's inquiry, including regulatory responsibilities within Government, and then responds to the specific questions posed by the Committee in their call for evidence. There are also some supporting documents attached including, at Annex A, responses to a number of additional questions suggested by the National Audit Office. 2. UK oil and gas production continues to form a vital component within the UK's energy needs (supplying over 60% of primary domestic energy demand in 2009). It contributes significantly to our economy. The upstream sector attracts around £12 billion annual expenditure by industry and provides around £10 billion annually to the Treasury in taxation. The industry supports around 350,000 UK jobs directly and indirectly (plus another 100,000 involved in exporting goods/services). 3. From both an economic and security of supply perspective, as we make the transition to a low carbon economy, it is vital that the Government and industry work to maximise economic recovery of the UK's indigenous hydrocarbon resources as part of our energy security policy. Production is declining but this is still a major UK resource and, although some 40 billion barrels of oil equivalent (boe) have been produced so far, there are perhaps 20 billion boe, maybe more, left to produce. It is a key Government objective to encourage industry to continue to invest in exploration, development and production so that we can fully realise this potential. However it is absolutely essential that, at the same time, such activities are carried out • safely, high standards of management are maintained, and environmental impacts are minimised. 4. Our regulatory regime is already among the most robust in the world and the industry's track record in the North Sea is strong. But we must learn everything we can from the Macondo well. Over the last four months we have been looking very closely at all the information that has come out of the Gulf of Mexico incident including the recent BP investigation report, and determining how this relates to our own regime and will continue doing so until the formal US investigations are completed in 2011. 5. During the period from 1964-2009, over 10,000 wells have been completed on the UK Continental Shelf (UKCS). Although there have been a small number of incidents involving shallow gas events,51 or blow -outs, during the course of these drilling operations, there has not been an oil blow-out or any significant spillage of oil directly resulting from drilling operations. 6. There are two incidents that are exceptions to that strong track record. First the Ocean Odyssey incident which took place on the UKCS in 1988 which involved a blow-out during exploration drilling. However this differed significantly from the recent US blow-out in that the Ocean Odyssey rig was drilling a high pressure well on a gas condensate field. The incident also pre -dated the restructuring of the UK offshore safety regime following Piper Alpha. 7. The Piper Alpha tragedy which also took place in 1988 has been the most serious incident on the UKCS. This was a gas explosion caused by leaking pipe -work that was under maintenance, and exacerbated because there were inadequate emergency shutdown facilities available to cut off production from other fields. At the time both safety and operational issues were dealt with by the then Department of Energy. After the incident, although Lord Cullen concluded that there had not been a conflict of interests within the Department, it was decided that the responsibility for these should be split to implement new arrangements with a clear separation of duties between those responsible for licensing operations and those regulating safety matters. DEPARTMENTAL RESPONSIBILITIES 8. Following Piper Alpha new tripartite arrangements for offshore regulation were implemented. 9. Under these it is the responsibility of the Health & Safety Executive (HSE), an executive non departmental public body of the Department for Work and Pensions, to assess and regulate the integrity • and safety of offshore installations in the UK via the Health and Safety at Work Etc Act 1974 and the offshore specific suite of regulations. 51 A Shallow gas event occurs where hydrocarbon gas close to the sea bed is encountered during drilling operations and, as it cannot be contained using standard well control practices, it is allowed to deplete. Eleven of these type of events have occurred in the UKCS since 1987. • Ev 110 Energy and Climate Change Committee: Evidence 10. The Department of Energy and Climate Change's (DECC) Energy Development Unit is responsible for licensing and regulating UK oil and gas activities, developing the environmental regulatory framework for the UKCS, and for administering and ensuring compliance with that regime in relation to offshore oil and gas exploration and production and decommissioning, including the approval of Oil Pollution Emergency Plans (OPEPs). 11. The Maritime and Coastguard Agency (MCA), an Executive Agency of the Department for Transport is responsible, if required, for deploying any counter pollution measures to minimise a pollution incident. 12. In order to provide a coherent picture to the Committee this Memorandum is being submitted jointly by all three organisations. 13. A chart is also attached at Annex B which shows the relationship between these three key regulatory bodies and the allocation of roles, which ensure that all aspects of the industry's activities are regulated holistically and in a seamless fashion. OFFSHORE DRILLING —MEANING OF "DEEP WATER" 14. The Committee's questions are largely focused on activities in deep water and it is probably helpful to explain how this has been interpreted in this evidence. There is no standard or uniform definition of "deep water" in the industry or in use among regulators but, for the purposes of this Memorandum, DECC, HSE and MCA are using the term "deep water" as referring to activities taking place in water depths of more than 300 metres. This accords with the commonly used concept of "deep water drilling" as that which requires the use of floating rigs, rather than fixed production platforms or jack -up rigs. 15. There are very few fixed platforms operating around the world at a depth of 300 metres, and current technology would almost always dictate that a floating drilling facility is required for drilling activity at this depth and deeper. The US Administration uses a similar concept to identify "deep water drilling"; but it should be noted that water depths have not been stipulated specifically in recent measures put forward by the US Department of the Interior. A map showing the water depths in the Northern North Sea and areas to the North and West of Scotland is attached at Annex C to this Memorandum. • DEEP WATER DRILLING IN THE UK 16. Clearly the Deepwater Horizon incident in the US has served to focus great attention on how drilling operations are regulated and controlled. Given the move into deeper waters West of Shetland, there is every reason to increase our regulatory vigilance. Notwithstanding the strengths of the existing UK regime, the agencies are keen to secure full learning from all new and emerging information, and to ensure that the system is in every respect as good as it can be. 17. Interim steps are already being implemented including: action to double the number of annual environmental inspections by DECC to drilling rigs including the appointment of three additional inspectors, bringing the total number of environmental inspectors to 10 (nine inspectors and one senior inspector); — the launch of a new joint industry and Government group called the Oil Spill Prevention and Response Advisory Group—(OSPRAG),—to review the UK's ability to prevent and respond to oil spills; — the award, by OSPRAG, of a contract to Wood Group Kenny for the design of new oil spill mitigation technology for the UKCS; — agreement by the industry to increase by more than double oil spill liability insurance for the settlement of claims, from US$120 to US$250 million; — a study, set up by OSPRAG, in the light of the Gulf of Mexico incident, to look at estimates of the cost of oil spill clean up in the UK area; and — bringing forward the planned testing of the National Contingency Plan, and its interaction with other major incident plans, including oil pollution emergency plans submitted by operators of offshore installations, with a major oil pollution exercise involving the offshore industry in 2011. 18. The consenting of all wells is on a case by case basis taking full account of new and emerging information. And for deepwater wells, this now includes rigorous testing against the findings of BP's report into the causes of the Deepwater Horizon accident. The companies will have to demonstrate effective • coordination between companies involved in the well, and between the companies and relevant Government agencies. The testing of the effectiveness of these arrangements will be a condition of future permissions. The Government is working closely with other Government and international bodies to secure that all lessons from the Macondo accident are learned. This may result in additional cooperation across borders and, where appropriate, companies will need to demonstrate that they have given full effect to these arrangements and that they have been tested. Energy and Climate Change Committee: Evidence Ev 111 • 19. The Government plans to review our new and existing procedures as soon as the detailed results of the formal investigations into the Deepwater Horizon incident in the Gulf of Mexico are available. We expect this to build on the work already begun by OSPRAG. INTERNATIONAL DIMENSION 20. As part of our response to these events HSE and DECC are also in contact with our counterpart offshore regulators in the United States, the Bureau of Ocean Energy Management, Regulation and Enforcement (previously the Minerals Management Service), as well as engaging in high level contacts with BP in the UK. This will ensure that we can identify at the earliest opportunity any lessons from Deepwater Horizon that might be relevant and applied to UK offshore activities. 21. At the European level HSE and DECO have been actively involved. Although nation states have primacy in these issues, Mr Oettinger, the European Union Energy Commissioner, has taken a particular interest in this matter and has called for a review of the broader EU regulation of such activities. Mr Oettinger has also called for a moratorium on deep sea drilling; a review of how to improve the capacity for co-operation in terms of response and clean up; and consideration of the need to strengthen regional and international standards. Through HSE and DECC, the UK will be a key contributor to Commission workshops to discuss these issues. 22. As has been described above the UK already has a robust regulatory regime, the but we are seeking to learn as much as possible from the Macondo accident, and steps have nevertheless already been taken to increase our regulatory vigilance. All drilling programmes are considered on a case by case basis, taking account of the latest available information. HSE needs to be satisfied that well design and construction are satisfactory and DECC needs to be satisfied that emergency plans for all wells represent best practice. For deep water drilling, operators are being required to demonstrate that the factors identified in the BP report have been satisfactorily addressed; and that there is effective coordination between all the companies involved, and between companies and relevant Government agencies. This may delay or halt the commencement of some wells but we do not consider that such an approach will result in a de facto moratorium. In this light, the UK Government does not see a case for any ban or moratorium on deep water drilling. • 23. Following a meeting between UK and Norwegian Energy Ministers in August, a joint statement was issued which included a commitment by the UK and Norway to exchange information and confer on the investigations into the Gulf of Mexico oil spill and the appropriate regulatory and industry responses to the accident. 24. At a broader international level, through the G20, the Russian Government have initiated a review of best practice for deepwater drilling as part of a global marine environment initiative. The terms of reference and activities to deliver on this initiative are under discussion. The aim is an intermediate report mid -October 2010 and for the work to be concluded for the Seoul G20 Summit in November 2011. 25. The position of the three agencies with regard to these initiatives is that we need to be closely involved in shaping and contributing to them to ensure that lessons are learned and best practice is shared. However, we also need to ensure that any proposals for change: — are based on robust evidence; — are proportionate and risk assessment based; — avoid disruption to existing mature regulatory regimes (such as the UK's) that have proven to be effective over time; and — do not lead to any reduction in national safety requirements by setting lower international standards. RESPONSES TO THE COMMITTEE'S QUESTIONS What are the implications of the Gulf of Mexico oil spill for deep water drilling in the UK? 26. The majority of UK gas fields are located in water depths of less than 50 metres, whilst oil fields are mainly located in water depths between 50 and 250 metres. However, to the West of Shetland, there are a number of fields and undeveloped discoveries in water depths of between 300 and 1,600 metres, and proposals to drill in water depths greater than 1,600 metres. 27. The UKCS to the West of Scotland, which may be the subject of oil and gas exploration in the future, includes areas where the water depth is in excess of 3,000 metres. • 28. Overall deepwater oil and gas resource potential (including both West of Shetland and the less well understood West of Scotland) is estimated to be around 3 to 3.5 billion barrels of oil equivalent (some 15-17.5% of UK total resources) of which about a third is gas and two thirds oil. Earlier this year DECC gave the go-ahead to Total's Laggan/Tormore gas development, which lies in 600 metres of water, and which is set to open up West of Shetland for wider development with a new gas pipeline to mainland Scotland via the Shetland Islands. • Ev 112 Energy and Climate Change Committee: Evidence 29. The southern part of the North Sea is a gas province and so if there were a blow out it would not result in significant oil spillage. Some other areas of the North Sea contain oil reservoirs which have insufficient pressure to support a blow out similar in nature to the Deepwater Horizon spill. In these reservoirs oil has to be pro -actively pumped for it to be produced. However, there remain other oil reservoirs, including some in the deeper waters to the West of Shetland, where the pressure and hydrocarbons are such that, were the safety measures in place to fail, a blowout incident could occur. Although the possibility of blowouts occurring are not confined to deep water, water depth clearly can increase the technical challenge of drilling a well and can make any mitigation measures required more difficult to implement. (See also Annex D for more detail of operational factors relevant to deep water operations.) 30. In advance of the conclusion of the formal investigations into the Gulf of Mexico incident, Oil & Gas UK (the offshore industry's main representative body) has established the Oil Spill Prevention and Response Advisory Group (OSPRAG) to review the industry's practices in the UK. The Group is formed of senior representatives from all sides of the industry, the relevant regulatory authorities—DECC, HSE and MCA — and trade unions. 31. OSPRAG has established four specialist review groups whose remit is to focus on: — Technical issues including first response for protection of personnel, the well examination process and an inventory of blowout preventers and remotely operated vehicles currently employed in the UKCS; — Oil spill response capability and remediation including national emergency response measures: — Indemnity and insurance requirements; and — European Issues (Pan -North Sea regulations/response mechanisms). 32. On 5 August 2010, OSPRAG announced that it had awarded the contract for engineering services to assess subsea capping and containment options for the UK continental shelf to Wood Group Kenny. Wood Group Kenny will work closely with the OSPRAG Technical Review Group and recommendations will be presented in September 2010. These recommendations will allow OSPRAG to make an informed decision • about the potential contingency options for subsea capping and containment that should be put in place in the UK. 33. Clearly improvements in the stand-by capability to cap and capture leaking oil would allow us to engage much more rapidly in a mitigation exercise should an incident involving leaking oil occur on the UKCS in the future. 34. The strength of the UK regulatory regime is reflected in the fact that the initial report from the US Department of the Interior has already indicated that elements of our own approach will help inform the changes to be implemented in the US system —for example: case -by -case safety case appraisal, independent verification of the design of wells, and the separation of the safety function from licensing within Government. 35. Although the UK regulations on the design and construction of wells are goal setting in approach, they do require a full assessment of subsurface conditions before drilling. This is to identify potential hazards and require that the well is designed, constructed, maintained and operated such that, so far as is reasonably practicable, there can be no unplanned escape of fluids from the well. In addition the UK will not consent to the drilling of wells unless we are satisfied that the emergency plans represent best practice. 36. The Macondo incident has shown that co-ordination between all the companies involved, and between companies and relevant Government agencies, is an essential part of safe operation. For deepwater wells the case by case assessment of wells will now include the requirement for companies to demonstrate rigorously the effective coordination between all the companies involved, and between companies and relevant Government agencies. Companies seeking to drill in deep waters will need to provide evidence that such co-ordination arrangements are in place and tested. 37. The regime developed since Piper Alpha ensure that the roles and responsibilities of all parties, including rig owners, well operators, sub -contractors and regulators, are clear and well understood. The overall responsibility for safety on an offshore installation falls to the Safety Case Duty Holder who appoints an Offshore Installation Manager (OIM) and the ability to discharge this responsibility must be demonstrated through the Safety Case. All parties involved in offshore operations including, for example, the cementing contractors have legal duties to co-operate with both the operator of the installation (the Safety Case Duty holder, OIM) and the Well Operator when the well is being constructed. The Safety Case Duty holder and the Well Operator must demonstrate that their safety management systems will operate is effectively in combination, who has primacy in emergencies, and who has overall responsibility for decision - making. A recognised way of achieving this is through a formal bridging document. Safety Case holders and Well Operators must be able to demonstrate appropriate crew training, and the crews' understanding of the decision -making procedures for events that may occur during the well construction. The regime is regulated by HSE who can take formal enforcement action where duty holders' performance falls short of that expected and poses serious risks. Energy and Climate Change Committee: Evidence Ev 113 38. In addition, the industry through its OSPRAG workgroup is reviewing the training of crews on this critical area and the crucial relationship between OIM, Well Operator and key contractors to be able to demonstrate that no opportunity to improve the safety of operations is missed. 39. Once the results of the formal investigations into the incident in the Gulf of Mexico are known we will ensure that all the lessons to be learnt are incorporated into our procedures and that the UK continues to appropriately regulate its offshore oil and gas industry in order to maintain the highest possible standards. To what extent is the existing safety and environmental regulatory regime fit for purpose? 40. As detailed above, it cannot be guaranteed that a blow-out incident could not happen on the UKCS, but we strongly believe the safety and environment regulatory regime is fit for purpose. There is a comprehensive regulatory regime in place, administered by the HSE and DECC, which covers all aspects associated with the proactive management of this type of risk. Details are given below along with action that has been taken thus far following the Gulf of Mexico incident to provide further reassurance that the regime remains robust, and to improve it where possible. HEALTH AND SAFETY REGULATION 41. HSE is responsible for regulating the risks to health and safety arising from work in the offshore industry on the UKCS. The UK has one of the best health and safety records in the world, based on the simple, enduring principle that those who create the risk are best placed to manage it. HSE has nearly 40 years' experience as an independent regulator of a wide range of industrial hazards. In practice, HSE has a system where the regulator, duty holders, worker representatives and other stakeholders work together, utilising the best available evidence, to produce proportionate regulation, standards and guidance aimed at protecting the health and safety of workers and the public. This is backed up by a regime of inspections, assessments, investigations and, where necessary, enforcement. 42. The UK has a comprehensive offshore regulatory framework in place to prevent or mitigate the health and safety risks associated with drilling for oil and gas offshore. The main regulations include: — The Offshore Installations (Safety Case) Regulations 2005 (SCR) —which require operators or owners of an offshore installation to prepare a safety case providing evidence that all major • accident risks have been evaluated and measures taken to control risks. This must be submitted to HSE for acceptance before a rig drills in UK waters; — The Offshore Installations and Pipeline Works (Management and Administration) Regulations 1995 (MAR) —which set out requirements for the safe management of offshore installations; — The Offshore Installations (Prevention of Fire and Explosion, and Emergency Response) Regulations 1995 (PFEER)—which provide for the protection of people from fire and explosion, and for securing an effective emergency response; — The Offshore Installations and Wells (Design and Construction, etc) Regulations 1996 (DCR)— which set out the requirements for the integrity of installations and the safety of offshore and onshore wells; and — Offshore Installations (Safety Representatives and Safety Committees) Regulations 1989—which place duties on offshore installation managers, owners and operators to establish arrangements for consultation with workers. These regulations apply to the workforce on the installation regardless of their employer's identity. 43. The UK offshore regulatory framework, developed after the Piper Alpha disaster in 1988, implements the relevant European Directive 92/91/EEC on the minimum requirements for improving the safety and health of workers in the mineral -extracting industries through drilling. The UK regulations also contain a range of additional safeguards to mitigate the health and safety risks associated with offshore drilling. These measures also reduce the risk of an oil pollution incident occurring: — DCR requires a full assessment of subsurface conditions before drilling to identify potential hazards. DCR also requires that the well is designed, constructed, maintained and operated such that, so far as is reasonably practicable, there can be no unplanned escape of fluids from the well; There is a statutory requirement for wells to be notified to HSE at least 21 days prior to drilling or well intervention operations taking place, which allows specialist wells inspectors to review well design and procedures and require improvements if necessary; — A second check is required of the design and construction of the well by a competent person, independent of the operator, to ensure that it is fit for purpose; — An independent competent person (such as Lloyds Register) must verify the suitability and state of • good repair of safety critical equipment such as blowout preventers (BOPs) on mobile drilling rigs; — Regulations require that everyone involved in well operations has received suitable information, instruction, training and supervision; — Weekly summaries of operations are required to be submitted by well operators to HSE Wells Inspectors; and 9 Ev 114 Energy and Climate Change Committee: Evidence — HSE Wells Inspectors assess and inspect well control and well integrity arrangements and other HSE offshore specialists assess and inspect other aspects of drilling rig operations and integrity. 44. To apply the UK's legislation and monitor safety within the offshore oil and gas industry, HSE's Offshore Division has 114.5 specialist inspectors (figures as at 1 April 2010) who provide expertise in the following disciplines: regulatory inspection; well engineering; occupational health; process safety; fire and explosion; marine and structural; evacuation and escape; mechanical; electrical; and diving. Overall, this equates to 105.5 inspector years when factors such as part time working are taken into account. 45. A further measure worth noting is the level of Hydrocarbon Releases (HCRs) on the UKCS. This is a key indicator of how well the offshore industry is managing its major accident potential. The UK offshore oil and gas industry has shown considerable improvements in recent years in relation to HCRs. There has been a steady decrease from 2001-02 to 2009-10. However, HSE has just reported a rise in HCRs last year. There were 61 HCRs in 2008-09—the lowest since HSE began regulating the industry —with a provisional total of 85 being reported for 2009-10. These figures show that there is no room for complacency. As a result of this, HSE has increased the level of its offshore investigation of all major and significant HCRs to ensure that root causes are identified and rectified by duty holders. HSE will continue to monitor the industry's HCRs performance closely and will take action against operators where required improvements are not delivered and/or poor practice is evident. 46. In summary, the Government believes the UK has a rigorous offshore oil and gas safety regime, with significant differences in the type and style of the legislative requirements and the regulatory/enforcement approach compared with the USA. The UK offshore oil and gas industry also has a somewhat different safety culture than that in the Gulf of Mexico. Here, there is greater workforce engagement in safety issues, which is supported by regulatory requirements. Whilst it is impossible to say that such a blowout as occurred with the Deepwater Horizon could never happen in UK waters, our additional and different layers of regulatory protection provides a reduced probability that it would. DECC—ENVIRONMENTAL REGULATION 47. A comprehensive framework of environmental protection measures has been developed to minimise the impact of oil and gas activities. This is embodied in the relevant legislation, consistent with and in large • part derived from the legislation framework of the European Community (EC). In addition, the UK is a signatory to the Oslo and Paris Convention for the Protection of the Marine Environment of the North East Atlantic (the OSPAR Convention). To date, the UK has implemented and applied all of the OSPAR decisions and recommendations. 48. This robust offshore environmental protection regime covers oil and gas development throughout its life cycle, from the initial licence application to the final decommissioning of facilities. All activities that could potentially impact on the environment are subject to rigorous assessment, and significant activities are controlled through the issue of permits, consents or authorisations. There is also an inspection and enforcement regime in place to confirm compliance with the conditions included in the environmental approvals. 49. The robust regime is reflected by the industry's performance, and the UK has a good environmental record with no significant impact on the marine environment resulting from offshore oil and gas activity. 50. The regime includes: The Environmental Assessment of Plans and Programmes Regulations 2004—require a Strategic Environmental Assessment to be carried out before oil and gas licensing is undertaken. The SEA is subject to public consultation and evaluates both the individual and cumulative impacts of offshore oil and gas activity at a strategic level. The Offshore Petroleum Production and Pipelines (Assessment of Environmental Effects) Regulations 1999—require the operator to undertake an environmental assessment for a wide range of projects. The Offshore Petroleum Activities (Conservation of Habitats) Regulations 2001—require an Appropriate Assessment for all projects or activities that could affect the integrity of a protected habitat or species. The Offshore Chemicals Regulations 2002 (as amended) --control the use and discharge of all operational chemicals and implement OSPAR Decision 2000/2 on a harmonised mandatory control system for the use and reduction of the discharge of offshore chemical. The Offshore Petroleum Activities (Oil Pollution, Prevention and Control) Regulations 2005— control all deliberate oil discharges. Major discharges are waste streams contaminated with reservoir hydrocarbons eg produced water. The Offshore Combustion Installations (Prevention and Control of Pollution) Regulations 2001 (as amended) —control the quantities of noxious pollutants emitted from combustion equipment on qualifying installations, and implement the Integrated Pollution Prevention and Control Directive for offshore oil and gas installations. The regulations ensure that Best Available Techniques are employed to reduce emissions. • Energy and Climate Change Committee: Evidence Ev 115 The Greenhouse Gas Emissions Trading Scheme Regulations 2005 (as amended) —authorise the emission of greenhouse gases (currently only CO2) and implement the EU Emissions Trading Scheme. The Offshore Installations (Emergency Pollution Control) Regulations 2002—ensure that operators have appropriate measures in place to prevent oil spills and to ensure that if they occur they are handled effectively and provide for the role of the Secretary of State's Representative for Maritime Salvage and Intervention. The Merchant Shipping (Oil Pollution Preparedness, Response and Co-operation Convention) Regulations 1998—require operators to prepare and submit an Oil Pollution Emergency Plan, covering all activities where there is a risk of hydrocarbon spill and detailing the action to be taken should a spill occur. Offshore Environmental Inspections 51. As detailed above, most oil and gas activities are controlled by the issue of activity specific permits, consents or authorisations containing legally binding terms and conditions. DECC actively ensures that industry is complying with the conditions included in environmental approvals by reviewing permit compliance returns and undertaking a series of prioritised environmental inspections using a risk based approach. 52. DECC inspectors visit offshore installations and onshore offices to: — inspect records and management systems; — interview people; and — observe site conditions, standards and practices. 53. This allows for a comprehensive assessment of environmental legislative requirements, restrictions or prohibitions imposed upon operators and best practice as regards pollution prevention and incident response measures. Where applicable enforcement action is taken in accordance with the DECC Enforcement Policy52 to ensure that those who have duties under the law take preventative or remedial measures to prevent pollution; put in place measures to achieve compliance; and are held to account when failures to comply occur. 54. During 2008 and 2009, the Inspectorate undertook 76 and 65 offshore trips respectively, covering both inspection and investigation activities. To July 2010, 39 offshore visits have been undertaken (comprising of 23 fixed installation inspections, four fixed installation investigations and 12 drilling rig inspections). 55. In addition to regulatory inspections carried out by DECC, operators carry out their own internal audits and reporting as part of their Environmental Management System (EMS) requirements. DECC requires all operators of installations to have an independently verified EMS which satisfies the requirements of OSPAR Recommendation 2003/5 that recognises the requirements of international standards. 56. All of the 81 licensed operators on the UKCS have an independently verified EMS. An EMS is designed to achieve the prevention and elimination of pollution from offshore sources and to deliver and manage compliance with environmental laws and regulations on an ongoing basis. As part of the DECC EMS requirements operators must also produce an annual public statement providing an overview of their offshore operations and environmental performance. The public statements are available via the DECC website (www.og.decc.gov.uk). 57. Following an initial review of DECC procedures in the light of the Deepwater Horizon incident, it was concluded that with exploration and appraisal moving to ever deeper waters, including those West of Shetland, it would be prudent to reinforce the level of assurance available that the regulatory processes are being adhered to by increasing the number of inspections to drilling rigs operating in this area including undertaking joint environmental & safety inspections with HSE where appropriate. 58. DECC's regulatory process encompasses the general oversight of offshore activity through permitting and consenting which is undertaken prior to the activity being agreed. DECC's Offshore Environment and Decommissioning Unit has three senior environmental managers and six environmental managers, who are responsible for the environmental assessment of offshore oil and gas activities, and for the administration of environmental legislation. The Environmental Management Team coordinates the review of applications or submissions required under various legislation, for example environmental statements, applications for chemical permits and applications to undertake seismic surveys. Most of these activities are controlled by the issue of activity specific permits, consents or authorisations. 59. Given DECC's less extensive areas of responsibility compared to HSE, it and its predecessor Departments have always operated with many fewer inspectors than HSE. However, to further ensure • industry compliance, three additional offshore environmental inspectors are being recruited alongside the existing team of six, bringing the total number of inspectors to ten (one senior environmental inspector and 52 DECC's enforcement policy, which is publicly available, sets out the general principles that inspectors shall follow to ensure that any enforcement action taken is proportional, consistent, transparent and targeted. https://www.og.decc.gov.uk/ environmenUEIE_Policy.pdf Ev 116 Energy and Climate Change Committee: Evidence • nine environmental inspectors). This will increase supervision of drilling contractors by allowing DECC to double the number of environmental inspections carried out on mobile drilling rigs in the UKCS from an average of eight to at least sixteen on an annual basis with immediate effect. 60. Offshore drilling activity varies throughout the year but currently there are approximately 24 mobile drilling operations ongoing in the UKCS. DECC's Offshore Inspectorate use a risk based strategy to implement their offshore environmental inspection regime. Of those rigs undertaking drilling activity in the UKCS at present, approximately 20% are working on gas reservoirs, which inherently pose less of a potential risk to the environment compared with those working on oil reservoirs. The locality of any rig and the nature of the well also contributes to the risk assessment process. On this basis the Department targets inspections on those rigs that are undertaking exploration, appraisal and development drilling of specific oil reservoirs. Reporting of Oil and Chemical Spills 61. Under the Regulations DECC requires that all oil and chemical spills, irrespective of volume, be reported to the Offshore Inspectorate within six hours of such an accident occurring, or within one hour if the release is over one tonne. DECC's Inspectorate maintain a 24/7 incident response on call service to receive calls regarding pollution incidents and incidents which may affect security of supply. If a pollution incident occurs the Inspector communicates with the operator to ensure that contingency arrangements are implemented in accordance with the operators approved OPEP (see paragraph 71). In doing so, the Inspector would also liaise with the MCA on matters associated with pollution response and act as assistant to the SOSREP (see paragraph 76), who would monitor the operators actions to ensure adequate measures were taken to prevent pollution. This allows the most effective incident response and environmental strategy to be developed and adopted according to the circumstances of the incident. 62. In accordance with DECC's investigation policy, incidents are investigated by Inspectors from the Department's Offshore Inspectorate, and the relevant enforcement action pursued. Methods of enforcement include letters, enforcement notices, prohibition notices, revocation of a permit and prosecution. The first four methods are non -punitive in nature and are focussed on bringing the permit holder or licensed operator into compliance. 63. Incidents that could be of relevance to other operators on the UKCS, because of common working . practice or because of the nature of the event, are circulated as an Environmental Alert on the DECC website, which can be accessed by all operators (who are notified of new alerts by e-mail), drilling contractors or other third party companies. 64. In addition to the HSE Hydrocarbon Release reporting (see para 45), DECC, as the offshore environmental regulator, also requires operators to submit details of oil spills to sea, regardless of quantity. During 2009 DECC were notified of 56 crude oil spills which resulted in approx six tonnes of crude oil being released to sea which, by comparison to the previous years' results, where 83 crude oil spills were notified resulting in approx 20 tonnes of oil being released to sea, shows that spill numbers and quantity have gone down. Against this background the industry's general performance has improved but there is always more that can be done and DECC will continue to regulate the environmental aspects of the offshore oil and gas activity as rigorously as possible. National Contingency Plan 65. As a party to the United Nations Convention on the Law of the Sea, the United Kingdom has an obligation to protect and preserve the marine environment. The National Contingency Plan for Marine Pollution from Shipping and Offshore Installations(NCP) is one of the measures the UK has taken to meet this obligation and the Department of Transport's Maritime Coastguard Agency (MCA) is the custodian of the Plan. 66. The NCP's purpose is to ensure there is a timely and measured response to an oil pollution incident. The plan sets out the circumstances in which the MCA deploys the UK national assets in response to a marine pollution incident to protect the overriding public interest and how these resources are managed. The plan deals with a variety of issues, including: — establishing the level of response; — setting up the national response units; and — at sea response and shoreline/onshore responses. 67. The NCP supports and underpins an operator's individual Oil Pollution Emergency Plan —see below. 68. To test the effectiveness of the NCP, and its interaction with other major incident plans, including OPEPs submitted by operators of offshore installations, a major oil pollution exercise involving a shipping casualty is held annually and an offshore installation exercise is held every five years. 69. The last such exercise involving the offshore industry was Exercise Unicorn, held on 10 June 2008, involving BP as the operator. The exercise was designed to test all the facets of incident response, such as key roles being identified and understood, utilising a challenging scenario which incorporated a number of foreseeable risks, all of which had the potential to occur on and/or around an offshore oil and gas production facility. The exercise's main objectives were to: Energy and Climate Change Committee: Evidence Ev 117 • — Test the NCP for marine pollution as it effects offshore installations; — Test the effectiveness of the operator's OPEPs; — Ensure an integrated approach is achieved between BERR (now DECC), MCA and other stakeholders; and — Test the powers of intervention of the SOSREP—see below. 70. Whilst the next date for a national exercise involving an offshore asset was not due until 2013, this has been brought forward to Spring 2011 and exercise planning has just commenced, through the auspices of OSPRAG which provides a focal point for the oil & gas sector's review of the industry's practices in the UK, in advance of the conclusion of investigations into the Gulf of Mexico incident. 71. The NCP has consistently been shown to be effective when it has been invoked in response to incidents in the last ten years. Where there are lessons to be learned from such incidents, they are incorporated in the NCP when it is periodically reviewed and refreshed. A review of the NCP has just started and this will take account of any lessons learned from the Gulf of Mexico incident. Part of this review will include consideration of the frequency of offshore installation oil pollution exercises, with initial views being that such exercises should be held every three years in future. Oil Pollution Emergency Plans (OPEP) 72. Under the requirements of the Merchant Shipping (Oil Pollution Preparedness, Response and Co- operation Conventions) Regulations 1998, all operators of an offshore installation or oil handling facility must have an Oil Pollution Emergency Plan in place. The plans are reviewed by DECC, MCA and relevant environmental consultees, such as the Marine Management Organisation or relevant Devolved Authority, the Joint Nature Conservation Committee and the relevant inshore statutory nature conservation body, eg Natural England, before approval by DECC. 73. OPEPs set out the arrangements for responding to incidents with the potential to cause marine pollution by oil, with a view to preventing such pollution or reducing or minimising its effect. The plan is • relevant and particular to a specific field or installation and covers activity such as drilling rigs carrying out exploration, appraisal and development drilling, production installations, pipelines, subsea tiebacks and new installations that are on site but not yet producing. 74. The OPEP covers a variety of topics for both onshore and offshore personnel, including; pollution incident scenario and hazard identification, pollution incident assessment and dispersant and aerial surveillance requirements. OPEPs focus on the worst -case scenario. Following the Gulf of Mexico incident, operators are now required to carry out additional modelling for deep water drilling operations, which includes an extended time frame for oil spill beaching predictions. The OSIS model that is used industry wide has limitations with regard to predicting long term spill and deep water predictions. The OSPRAG Oil Spill and Emergency Response Group is undertaking a review of the model and comparing oil spill scenarios with OSCAR, a model which appears better suited to deep sea oil releases. 75. To ensure the OPEP is, and remains, fit for purpose operators are expected to exercise personnel and equipment through different scenarios at different frequencies, as follows: — In addition to the NCP exercise (see above), operators are obliged to hold an exercise with the SOSREP every five years and during the last cycle of such SOSREP exercises, the OPEPs of 22 operators were tested. The latest cycle of SOSREP exercises is presently being undertaken and to date 13 have been held since 2008. — Under the International Convention on Oil Pollution Preparedness, Response and Co-operation Convention 1990, adopted by the UK in 1994, there is a requirement for all operators of offshore installations, drilling rigs and offshore loading terminals to have in place an oil spill response system that will include an element of pre -positioned response equipment, training and regular exercise, appropriate to the perceived risk. This includes: 1. testing their OPEP offshore with every shift at least once per year; 2. deployment of dispersant spraying equipment offshore at least once per month; 3. deployment of oil recovery equipment offshore at least once per year; 4. testing their onshore emergency response centre and associated procedures at least once per year; and 5. testing the industry deployment of oil spill response equipment at least every five years —the industry deployment of equipment will be included in the NCP exercise being planned for 2011. Secretary of State's Representative for Maritime Salvage and Intervention (SOSREP) • Ev 118 Energy and Climate Change Committee: Evidence 76. The Offshore Installations (Emergency Pollution Control) Regulations 2002 give the Secretary of State for Energy and Climate Change the powers to intervene in an incident involving an offshore installation where there is, or there may be a risk of significant pollution. The UK created the role of the Secretary of State's Representative for Maritime Salvage and Intervention (SOSREP) in 1999, following a recommendation contained in Lord Donaldson's Review of Salvage and Intervention and their Command and Control.53 The SOSREP acts as the single representative on behalf of the Secretaries of State for the Department for Transport (in relation to ships) and for the Department of Energy and Climate Change (in relation to offshore installations). Once oil, from a ship or an offshore oil & gas installation, enters the water the MCA lead any Government response to clean-up the spill. 77. The SOSREP will monitor the operator's response to a pollution incident and if he deems necessary, has the powers to give directions and to take such other actions as may be required to prevent or minimise pollution or the threat of pollution. The SOSREP is empowered to make crucial and often time -critical decisions, without delay and without recourse to higher authority, where such decisions are in the overriding UK public interest. 78. Operators must have facilities and personnel available to work alongside their existing Emergency Response Centre to accommodate the SOSREP and his associated team in the Operations Control Unit, which may be set up as a result of a pollution incident. It is also a requirement of the legislation that every five years each operator must conduct an exercise to test the OPEP and the involvement of the SOSREP. The Offshore Pollution Liability Association Limited (OPOL) 79. To search for and extract petroleum requires a licence issued by DECC under the Petroleum Act 1998. Licensees are, among other things, required to comply with instructions from DECC to ensure sufficient funds are available to discharge any liability for damage attributable to any oil pollution incident. 80. The licence sets no limit to the licensee's liabilities and the licensee must demonstrate at the time of the licence application that they have sufficient funds or indemnity provisions to meet expected commitments, liabilities and obligations. 81. All offshore operators currently active in exploration and production on the UKCS are also party to • a voluntary compensation agreement known as the Offshore Pollution Liability Association Ltd (OPOL), which came into being on 1 May 1975. 82. The agreement provides for each operator to provide an orderly means for compensating and reimbursing any person who sustains pollution damage and any public authority which incurs costs for taking remedial measures (clean-up) as the result of a discharge of oil from any offshore installation. As part of the process, OPOL requires every operator to provide satisfactory evidence of its ability to meet any liability under the Agreement. OPOL provides for the mutual agreement from all of its members for the settlement of claims up to US$ 250 million per incident, in the event of a default by an operator. This liability is based on worst case scenario planning. 83. As part of its work following the Deepwater Horizon incident OSPRAG has set up an Indemnity and Insurance Review Group (IIRG) to review the provisions of OPOL and the financial and cross -indemnity arrangements behind the current mutual co-operative industry mechanism (Offshore Cooperative Emergency Services). DECC has already requested that OPOL immediately revisit the modelling to review the worst case scenarios. This is being taken forward by IIRG which has commissioned modelling of alternative spill scenarios with the aim of providing a more comprehensive picture of potential oil spill costs so that discussions about the future OPOL level are better informed. It is expected that this modelling will be concluded in September 2010. The industry has already agreed to increase the limit for the settlement of claims from US$120 to US$250 million. Aerial and Satellite Surveillance 84. Following the Torrey Canyon incident, the Bonn Agreement was signed by Belgium, Denmark, France, Germany, Ireland, Netherlands, Norway, Sweden and the UK in 1969. This was updated in 1983 with the inclusion of the European Community. In 1987 the agreement was extended to cover co operation in surveillance. The Bonn Agreement facilitates co operation and mutual support between the contracting parties in responding to large scale maritime pollution incidents by ensuring a common approach. 85. The Bonn Agreement includes procedures on mutual aerial surveillance, both aircraft and satellite, and highlights the deterrent aspect of known surveillance operations in preventing deliberate illegal discharges. To meet the UK's Bonn obligations DECC undertakes aerial surveillance flights, through a service level agreement with MCA, to monitor offshore oil and gas installation activity and identify any potential release of oil. The flights identify the extent and volume of any such spill and play a key role in directing appropriate resources to the incident. Through the MCA, the aerial surveillance contract also provides for resources to be deployed to counteract the effects of such a spill through the application of dispersants. 53 Lord Donaldson's Review of Salvage and Intervention and their Command and Control, published February 1999 ISBN 0 10 141932 5 • Energy and Climate Change Committee: Evidence Ev 119 86. In addition, DECC has access to the satellite surveillance, provided through the European Maritime Safety Agency (EMSA). The Cleanseanet service allows for marine oil spill detection and surveillance in European waters, including certain footprints over the UKCS. DECO uses this tool to identify discharges to the marine environment, including cases where the release may not have yet been identified by the operator. The satellite surveillance facility can be used in tandem with aerial surveillance, where pre -planned flights follow the path of the satellite pass. 87. In summary, whilst the continued development of the UKCS offshore oil and gas sector is considered to be crucial to the security of the UK's energy supply, the Government is committed to ensuring that the impact of oil and gas activity on the environment continues to be minimised. Legislation adopted over the last fifteen years has resulted in the development of a comprehensive, robust and effective environmental regime, which is consistently applied, understood by industry and fully satisfies the UK's international obligations. What are the hazards and risks of deepwater drilling to the West of Shetland? 88. Drilling for petroleum is an intrinsically hazardous activity. It involves breaking the integrity of an underground reservoir of highly flammable gases and liquids. The most immediate risk is therefore of fire and explosion with a consequential loss of heavier hydrocarbons contained in the reservoir leading to environmental pollution. 89. Most wells drilled in the UK's waters present a hazard of a blowout but there are degrees of technical difficulty with not all wells being equally hazardous or having the same risk of failing. The majority of wells are at the low difficulty end of the spectrum. Deepwater wells tend to be at the higher end of the spectrum. The factors that affect the risk profile include: — the nature of the rock strata; — the pressure and type of fluid expected to be encountered (eg how much gas or oil there is); — the depth of the well beneath the seabed; and • — the depth of water in which the well is being drilled. 90. Many of these factors tend to extend over wide areas and so inevitably are better understood the more wells have been drilled in an area. For example, a condition that is exceptional in an early well can be routine in later exploration in the same area. However, even in mature exploration areas, errors or unexpected conditions can occur. For this reason, it is essential that procedures are in place for the well to be designed to contain the flow and that the drilling crew are trained to know how to avoid errors and respond to abnormal events. 91. Potentially challenging wells are already drilled in many parts of the UKCS. For example, wells drilled deep into the formations of the Central North Sea often encounter abnormally high pressures and require great care. To assist in this process the UK industry has developed detailed guidance on planning and drilling high pressure wells, with even more stringent safety requirements than for more routine wells. 92. The frequency of "kicks"54 (an early warning that there has been an unexpected flow into the well and that action must be taken) varies widely between geographical areas, with kicks more common, although generally low risk, in the Southern North Sea, which has been explored since the 1960s. In 2009 there were 18 kicks in the UKCS. 93. Although offshore drilling operations in UK waters all carry a risk of a blowout, these risks are heightened in deepwater. This is because there is a chance of the marine pipeline, or riser, between the drilling rig and the seabed failing or disconnecting allowing drilling fluid to leak out and lighter seawater to seep in. This will cause the well to flow. In consequence of this added hazard, operators need a high level of confidence in the operability of blowout preventers. 94. To date there has been limited exploration West of Shetland, and hence the pressures and the geological hazards are less well known —it is the UK's frontier exploration area. However, from experience to date, and in contrast to the Gulf of Mexico, the geology in the UK's deepwater offshore blocks West of Shetland appears relatively benign. Since 2006, nine deep water wells have been drilled in the area with only one kick reported (a minor brine flow that did not pose a threat either to safety or the environment). 95. Other operational factors have the potential to make deepwater drilling hazardous. These relate to • the high pressures encountered when drilling a well to such depths, the problems associated with stopping a flowing well and other well control risks (see background at Annex D). 54 For the most part, kicks involve geological conditions (eg dolomite rafts which float in salt and compartmentalized reservoirs) that are difficult to detect before the well is drilled. Kicks are more common in the Southern North Sea and, generally, these are low risk as they involve brine and not hydrocarbon. • Ev 120 Energy and Climate Change Committee: Evidence Is deepwater oil and gas production necessary during the UK's transition to a low carbon economy? To what extent would deepwater oil and gas resources contribute to the UK's security of supply? 96. Taking both of these questions together, the Government believes that UK deep water oil and gas production is necessary during the UK's transition to a low carbon economy, and that recovery of indigenous resources contributes to the UK's security of supply. The following text details the expected contribution of oil and gas to the UK energy mix and by extension security of supply. 97. The table below shows that on central projections (consistent with DECC's Updated Energy and Emissions Projections published in June 2010 at http://www.decc.govuk/en/content/cros/statistics/ projections/projections.aspx) oil and gas are each expected to continue to provide a third or more of total UK primary energy demand until at least 2025. Together, they are expected to continue to provide approaching three quarters of total UK energy demand. The UK is no longer self-sufficient in oil or gas but indigenous production of both is expected to be a major contributor to meeting domestic demand in the years ahead. On the basis of DECC's UK oil and gas production projections published in September 2010 (at https://www.og.decc.gov.uk/information/bb_updates/chapters/Section4_l7.htm), UK oil and gas production are each expected to provide half of UK demand in 2020 and well over a third in 2025. SHARES OF TOTAL UK PRIMARY ENERGY DEMAND 2010 2015 2020 2025 Oil 36% 37% 37% 38% Gas 38% 35% 33% 36% Oil & Gas 74% 72% 71% 74% UK Oil Production 29% 23% 18% 14% UK Gas Production (Gross) 25% 21% 17% 13% UK Oil & Gas Production 54% 44% 35% 27% UK PRODUCTION AS PROPORTION OF UK DEMAND • 2010 2015 2020 2025 Oil 800/0 62% 49% 37% Gas 66% 60% 50% 36% Oil & Gas 73% 61% 50% 36% 98. The contribution of deepwater oil and gas, whether from the UK or elsewhere, has not been projected separately. But deepwater reserves have the potential to provide a significant share of UK production and (thus) to meet a sizeable share of UK energy demand in the years ahead. 99. As noted above it is vital for UK security of supply and the economy that the Government and industry work to ensure economic recovery of indigenous hydrocarbon reserves. Oil and gas are still a major UK resource and, although some 40 billion barrels of oil equivalent (boe) have been produced so far, there are perhaps 20 billion boe, maybe more, left to produce. 100. Currently, the main prospective oil and gas producing areas in deep water within the UKCS are considered to be in areas West of Shetland. The area West of Scotland may contain substantial hydrocarbon resources but owing to the lack of geological knowledge and distance to existing infrastructure, only very small areas have been explored and therefore much less is actually known about the potential oil and gas resources. The water depths map attached at Annex C also shows an approximate dividing line between the areas considered to be West of Scotland and West of Shetland. 101. Based on current analysis the area to the West of Shetland is estimated to hold a potential 3.5 to 4.5 billion boe, which is around 20% of the UK's remaining oil and gas reserves. This includes about 1 billion boe of gas, (which represents around 17% of remaining UK gas reserves), the majority of which lies in deep water. The remaining West of Shetland oil potential (some three billion barrels) is split approximately 50:50 in deep vs shallow water. The area West of Scotland may contain perhaps 1 billion boe, almost all of which is likely to be in deep water, although, as noted above, current resource estimates for this area are highly uncertain. 102. Overall the deepwater oil and gas resource potential (including both West of Shetland and the less • well understood West of Scotland) is estimated therefore to be around 3 to 3.5 billion boe (some 15-17.5% of UK total resources) of which about a third is gas and two thirds oil. But it should be noted that this estimate includes 1 billion boe of highly uncertain resource from the West of Scotland area. The pie chart below shows the make up of UKCS reserves and elements attributable to west of Shetland and West of Scotland. Energy and Climate Change Committee: Evidence Ev 121 • (Overall UKCS Resource circa 20 billion boe) Deep water O&G resource estimate 3-3.5 billion boe* (15 - 17.5% of overall UK) O Rest of UK Oil and Gas West of Shetland & Scotland Deep water gas 0 West of Shetland & Scotland Deep water oil 0 West of Shetland & Scotland Shallow water oil West of Shetland & Scotland Shallow water gas 'These volumes include highly speculative West of scotland resource volumes of 1 billion be 103. It can be seen that deepwater areas make a significant contribution to the future UK energy mix. Earlier this year DECC gave the go-ahead to Total's Laggan/Tormore gas development, which lies in 600 metres of water, and which is set to open up West of Shetland for wider oil and gas development with a new gas pipeline to mainland Scotland via the Shetland Islands. First gas is scheduled for 2014. SUMMARY AND WAY AHEAD 104. As indicated in the evidence above, Government considers that the UK regulatory regime is robust but nobody in our regulatory process can afford to be complacent. Faced with the events we saw unfold in the Gulf of Mexico we must continue to do everything we can to minimise the risks so this will never happen in the UK. We have therefore instigated or contributed to a wide range of initiatives addressing all aspects of drilling operations. 105. At the domestic regulatory level HSE, DECC and MCA have undertaken rapid reviews of regulatory regimes to ensure that they are fit for purpose. 106. At the international level, the UK is a key contributor to European Commission led efforts to review the suitability of European legislation and to share best practice approaches, and will do the same with respect to G20 initiatives. The UK is also working with Norway, with both countries committed to exchanging information between them and conferring on the investigations into the Gulf of Mexico oil spill and the appropriate regulatory and industry responses to the accident. 107. At the technical and operational level, the joint industry, trades union and regulator forum, OSPRAG, is making good progress in developing new designs for well capping and containment technology as well as looking more broadly at first response and longer term remediation capability and well control and well examination guidelines. The outcomes of this OSPRAG work will be a key influence on future regulatory and response work. 108. At the operational level: HSE, DECC and MCA remain in close contact with BP and the US Authorities to ensure that we get the earliest feedback on Deepwater Horizon causation that we can then act upon; DECC's environmental inspection capacity for mobile drilling has been increased, and where appropriate and where offshore facilities allow, DECC environmental and HSE safety inspections will be made at the same time; and — proposals for drilling in deepwater West of Shetland are being thoroughly scrutinised, including rigorous testing against the findings of BP's report into the causes of the Deepwater Horizon accident. The companies will have to provide evidence that effective arrangements are in place and tested, to secure full cooperation between all companies involved and between the companies and relevant agencies, and that these arrangements effectively provide for international cooperation where relevant. 109. With these workstreams in progress, once the causes of the Deepwater Horizon incident are known, • DECC, HSE and MCA will take stock of the totality of legislative and technical barriers to similar incidents happening on the UKCS. In doing so, to ensure that an independent perspective is brought to bear on the work, we intend to involve external experts who will have relevant background knowledge of offshore oil and gas activities and/or regulatory processes but who currently sit outside of government or industry. September 2010 Ev 122 Energy and Climate Change Committee: Evidence • Annex A ENERGY & CLIMATE CHANGE SELECT COMMITTEE—DEEPWATER DRILLING INQUIRY: ADDITIONAL INFORMATION REQUESTED BY THE NATIONAL AUDIT OFFICE (NAO) INTRODUCTION • Since 2000, there have been 3,002 wells drilled on the UK Continental Shelf. Of these, 145 have been drilled in depths of 300 metres or more. 87 of these were development wells on the Foinaven, Schiehallion and Loyal fields. The remainder were exploration or appraisal wells West of Shetland or West of Scotland. RESPONSES TO NAO QUESTIONS 1. Oil spills (barrels/tonnes) resulting from UK deepwater drilling operations in each year during the last 10 years? In the period from 1 January 1999 to 11 August 2010, there were no crude oil drilling operation spills in water depths of over 300m. 2. Number of reported incidents involving deepwater drilling operations by type in each year during the last 10 years? Information on well control incidents reported to HSE for wells drilled at water depths of over 300m (-1,000ft) is shown in the following table. Years with no incidents are not shown. TYPE YEAR NUMBER Investigated Minor kick 1998-99 1 0 Minor kick 1999-2000 2 2 Minor kick 2001-02 1 1 Minor kick 2002-03 3 2 Minor kick 2004-05 1 0 Minor kick 2005-06 1 0 Minor kick 2007-08 2 0 Minor kick 2009-10 2 0 Totals 13 5 A minor kick is a small influx into the well (less than 20 barrels) which was detected in a timely manner, controlled and removed without further influx or release of hydrocarbons. There have been no incidents reported to DECC involving deepwater drilling operations during the period from 1 January 1999 to 11 August 2010. 3. Total oil production (barrels) from deepwater drilling during last 10 years (compared to total North Sea production)? Over the calendar years 2000 to 2009, total UKCS oil production was 6,896 million barrels, of which 552 million barrels (ie 81/o) came from deep water (viz Foinaven, Schiehallion and Loyal fields). 4. Number of deepwater drilling incidents investigated; number ofprosecutions; number and value ofpenalties (£s) in each year during the last 10 years? There have been no deep water drilling incidents which required investigation by DECC in the last 10 years. For investigation of safety incidents see Table in Q2 above. All of the incidents reported to HSE were minor kicks and there were no related prosecutions. A minor kick is not in itself a safety failure as the safety barriers operated effectively to control influx to the well. 5. Minimum, maximum and average length of time taken to investigate incidents/close cases? The average length of time taken to investigate the well kick incidents was 29 days within a range from five to 53 days. Energy and Climate Change Committee: Evidence Ev 123 • 6. Number of incidents (and level of severity) by Company? WELLS DRILLED IN WATER DEPTH OF OVER 300M (— 1,OOOFT). 1998-2010 Severity of Company Wells Number of Investigated incident drilled incidents Minor BP 81 5 3 Minor Chevron (Including Texaco) 10 2 0 Minor ExxonMobil (as Mobil) 4 3 2 Minor Hess 4 3 0 Seven other companies drilled a total of seventeen other wells in the same period 7. Planned and actual spending on inspectionlenforcement relating to deepwater drilling operations in 2009-10, and budget for inspectionlenforcement in 2010-11 ? DECC has no set budget for environmental inspection & enforcement activity related to mobile drilling units as all spend is recoverable through fees paid by the offshore oil & gas operators. Actual spend on environmental inspection & enforcement activity related to mobile offshore drilling rigs in 2009-10 was approximately £190,800. This covers staff, accommodation, allowances & equipment costs. In 2010-11 again there will be no set budget as actual spend will be recovered via fees. However, it is estimated that actual spend for environmental inspection & enforcement activity related to mobile offshore drilling rigs will increase to approximately £424,131 taking into account increased numbers of inspectors and inspections. These figures do not include the environmental managers (see question 8 below) nor the administrative support given to both the Inspectorate and the Management Team. The overall budget for all environmental regulatory activities for 2009-10 is £5.1 million. HSE has no separate budget for activities related to deepwater drilling operations and the level of regulatory activity is dependent on the operations which are planned or carried out by offshore operators. HSE's planned and actual spends for all offshore inspection and enforcement (including assessment and • investigation) is summarised below: Year Plan Actual 2009-10 £ 13,757,229 £ 12,742,428 2010—I 1 £ 13,704,371 — Note: The enforcement of offshore safety law takes place under a cost recoverable permissioning regime. The above figures relate to the planned and actual cost recoverable activity and are calculated under a Memorandum Trading Account. 8. Number of staff trained in the inspection of deepwater drilling operations, and number of unfilled vacancies? Within DECC there are six environmental inspectors and one senior environmental inspector, all of whom have been trained to carry out environmental inspections on all North Sea Installations/mobile drilling rigs, including those carrying out deep water drilling operations. Following the Gulf of Mexico incident, it was decided that an additional three inspectors should be recruited to allow us to increase the number of inspections being carried out both generally and more specifically in relation to deep water drilling. The recruitment process is well progressed with interviews being held during w/c 16 August. Following completion of this process and given the likely conditions of the applicants' current employment, we would anticipate the additional staff being in place by mid -October. In addition to the Offshore Inspectorate, DECO also employs three senior environmental managers and six environmental managers, who are responsible for the environmental assessment of offshore oil and gas activities and for the administration of environmental legislation. The Environmental Management Team coordinates the review of applications or submissions required under various legislation, for example environmental statements, applications for chemical permits and applications to undertake seismic surveys (all of which may be required in relation to drilling operations). Most of these activities are controlled by the issue of activity specific permits, consents or authorisations. There is one vacancy in this team for which we are currently recruiting. • The Health and Safety Executive has 114.5 specialist inspectors involved in the regulation of health and safety of the UK's offshore oil and gas industry (figures as at 1 April 2010). This equates to 105.5 inspector years when factors such as part time working are taken into account. Specialist inspectors are employed in safety critical areas such as Well Engineering, Process Safety, Fire and Explosion, Marine & Structural, Evacuation and Escape, Mechanical, Electrical and Diving. Ev 124 Energy and Climate Change Committee: Evidence • There are 10 Well Engineering inspectors who deal specifically with well control and drilling operations. Deepwater drilling is not a separate specialism within well engineering; rather the potential difficulties increase progressively with the water depth and other factors such as exposure to weather. The more experienced inspectors deal with the more complex drilling notifications. Across all offshore disciplines there are 18 vacancies; there is one vacancy within Well Engineering. 9. Number of inspections of deepwater drilling operations planned and number completed in 2009-10; and number planned. for 2010-11 ? Offshore drilling activity will vary throughout the year, but currently there are approximately 24 mobile drilling operations ongoing in the UKCS. DECC's offshore environmental inspectorate use a risk based strategy to implement their offshore inspection regime. Of those rigs undertaking drilling activity in the UKCS at present, approximately 25% are working on gas reservoirs, which inherently pose less of a potential risk to the environment compared with those working on oil reservoirs. The locality of any rig also contributes to the risk assessment process. As such the Department is focused on those rigs that are undertaking exploration, appraisal and development drilling of oil reservoirs. The Department's Offshore Inspectorate undertake a series of prioritised environmental inspections to fixed installations and drilling rigs using a risk based approach. The inspections ensure that permit holders/ operators have been, or are complying with the requirements, restrictions or prohibitions imposed upon them by the relevant statutory provisions. In 2009, DECC carried out 12 drilling rig inspections of which one was in deep water. There is currently 1 deep water inspection planned for 2010-11. The average number of drilling rig inspections by DECC in past years has been eight and at least 16 are intended during 2010. Although DECC will be focusing particularly on those drilling in deep water, this is dependent on activity actually taking place at these water depths. 2009-10 OFFSHORE DEEP WATER (+300M WATER DEPTH) DRILLING ACTIVITY INSPECTIONS BY HSE: • All offshore specialist Inspections involving inspections wells inspectors Leiv Eiriksson 1 1 Paul B Lloyd Jr 1 0 Stena Carron 2 1 The inspection of well operations is not solely performed offshore but is also conducted onshore by inspection of Well Notifications. In 2009-10 HSE received some 500 offshore well operation notifications which included 20 in deep water; 275 offshore designs were inspected of which 29 were in deep water. (Some of these 29 were significant changes to design not recorded as separate notifications. Deep water West of Shetland is largely an exploration area involving a higher level of design review than mature areas.) 2010-11—To date no drilling activity in deep water. A well notification has been received for deepwater drilling activity (Chevron Stena Carron). HSE plans to undertake an inspection of the drilling operation this year if the well goes ahead. A safety case currently being assessed for the Seadrill West Phoenix which is capable of operating in deep water. One inspection of West Phoenix has already taken place this year with a further two pending. 10. A copy of DECC's recently completed review of the safety and environmental regulatory regimes? In light of the Gulf of Mexico incident, and on the basis of the limited information currently available, Senior Management conducted a rapid review of the implications for DECC's offshore regulatory regime. It was considered that in the past, drilling activity has mainly been conducted in water depths of less than 300m. The review looked at potential future levels of activity and the resources available to ensure compliance with regulations. In addition, existing regulations and controls and in particular those related to oil spills and contingency plans were reviewed. This concluded that with exploration and appraisal moving to ever deeper waters and to the particularly environmentally sensitive area to the West of Shetland it would be prudent to reinforce the level of assurance available that the regulatory processes are being adhered to. So, although the current regime was considered to be fit for purpose, it was determined that DECC should further strengthen this regime. As a result, three additional environmental inspectors are to be recruited and more environmental inspections carried out. Regulation will only work if it is applied fully • by those regulated and we are determined to ensure that this is the case by carrying out increased checks on compliance. The review activity did not result in a written report. A further much more comprehensive review of the UK regime will be undertaken as soon as the detailed analysis of the factors which caused the Gulf incident has taken place. This will look at the how the root causes of the Gulf incident can be protected against and determine what more, if anything, needs to be done to reinforce further our regulatory approach. Energy and Climate Change Committee: Evidence Ev 125 11. Of the North Sea platforms in operation, how many are exploration rigs and how many are production platforms, and how many are operating in deepwater (or plan to be)? There are 289 oil and gas installations on the UKCS (270 platforms and 19 Floating Production Systems), of which two are located in deep water (the Foinaven and Schiehallion-Loyal FPSOs) (see https://www.og.decc.gov.uk/information/bb_updates/appendices/Appendixl3.xls ) There are no approved Field Development Plans in place for new deep water installations. However there is a Floating Production System being planned for Chevron's Rosebank project. Also for the Schiehallion field, the operator is planning to build and install a replacement FPSO. Total are developing the Laggan and Tormore gas fields in — 600 in water depth West of Shetland using subsea technology . This does not require a production platform, but drilling using mobile drilling rig is expected to start in 2012 to allow first production in 2014. BP are planning to replace the Schiehallion FPSO with a new, larger, vessel in 2014. Chevron are considering options for a floating production system on Rosebank, but no decision has yet been made on whether or not to proceed to development. Development options for three other deep water discoveries are being studied, but no decision has yet been made on whether or not to proceed or what development scheme might be adopted. SUPPLEMENTARY QUESTIONS A: An up to date stakeholder map of who does what in respect of the regulatory framework over environmental, health and safety framework (including whether MMO taken over the role of MCA for pollution from shipping and offshore installations) A stakeholder map attached is attached at Annex B. The Maritime and Coastguard Agency remains responsible for pollution from shipping and offshore installations. The Marine Management Organisation does not have a role to play in this area. B: The date of the latest DECO review on oil pollution emergency plans, and the results of this review? • Under The International Convention on Oil Pollution Preparedness, Response and Co-operation 1990 (OPRC Convention) and The Merchant Shipping (Oil Pollution Preparedness, Response and Co-operation Convention) Regulations 1998 (OPRC), all operators of an offshore installation or oil handling facility must, to satisfy the requirements of the OPRC regulations, have in place an approved oil pollution emergency plan (OPEP). The Department of Energy and Climate Change is the competent authority for the approval of such plans and as such has also issued Guidance Notes to Operators of UK Offshore Oil and Gas Installations (including pipelines) https://www.og.decc.gov.uk/environment/msr]998.htm to assist operators in their preparation and submission. This Guidance Note was re -issued on 3 April 2009 after a comprehensive review of the structure and format of content, including a suggested layout of the plan. The consultation process involved all DECC stakeholders, such as the Maritime and Coastguard Agency (MCA), Joint Nature Conservation Committee (JNCC), Oil and Gas UK and oil and gas operators. The information provided in the Guidance Note allows an operator to prepare and submit a more focussed response document that sets out the arrangements for responding to incidents which cause or have the potential to cause marine pollution by oil, with a view to preventing such pollution or reducing or minimising its effect. The plan is relevant and particular to a specific field or installation and covers activity such as drilling rigs carrying out exploration, appraisal, development and production operations, production installations, pipelines, subsea tiebacks, new installations that are on site but not yet producing. All OPEPs must be resubmitted for approval every five years and operators must submit the plans at least two months prior to the end of this period to ensure an approved OPEP remains in place. The plan covers a variety of topics for both onshore and offshore personnel, including: 1. Pollution incident scenario and hazard identification; 2. Pollution incident assessment; 3. Dispersant and aerial surveillance requirements. In this regard, there are minimum dispersant and aerial surveillance response requirements that must be met and must be detailed within the plan. The operator must specify within the plan their capability to provide such surveillance or dispersant arrangements. In addition, should a plan identify an activity taking place in any block wholly or partly within 25 miles of the coastline, additional measures must be considered, including: — Presence at all times of a vessel with the capability to provide dispersant spraying within a shorter period (30 minutes of notification), • — Sufficient dispersant stock to deal with a pollution incident of 25 tonnes and if required have the capability of recovering oil likely to be lost under a Tier 1 scenario, and — Submission of a Shoreline Strategy Plan. The potential for shore line contamination must be assessed and determined by the operator and must be submitted with the OPER The Shoreline Protection Plan must contain certain information, such as: Ev 126 Energy and Climate Change Committee: Evidence 0 — Procedures for the shoreline protection, response initiation, implementation and closeout; — Arrangements with local authorities and other integrated emergency management responders for the methods to be deployed to respond and recover any oil that reaches the coastline. In this regard, local authorities and other responders will ensure the plan co- ordinates with local arrangements developed as part of the NCP and/or those through the Civil Contingencies Act 2004 ( Resilience groups); — Details of environmental sensitivities likely to be affected; and — Estimated resource mobilisation and deployment times. 4 Response strategy and implementation. Included within this remit are the tier levels of response, namely: — Tier 1 is the lowest level of response and requires resources to be available on the offshore installation —dispersants may or may not be used; — Tier 2 is for larger pollution incidents where the local resource may be insufficient. In these cases, and as detailed with the plan, the operator would call upon the resources of a third party contractor to provide assistance —again this capability must be able to be mobilised within a minimum period of time; and — Tier 3 is where national resources are required and the NCP implemented. MCA dispersant stocks are located at various locations around the UK, including Inverness, Shetland, Northern Ireland, Southampton and Coventry, whilst Shoreline and Offshore Response Equipment are currently held at Bristol, Barnsley and Dundee. Under the OPRC Regulations, personnel with a responsibility for oil pollution incident response must be competent, both in oil pollution incident response and in the use of their OPEP. Again, DECC has produced Oil Response Training Guidance which must be followed by industry as a minimum standard. https:// www.og.decc.gov.uk/environment/msrl 998. htm To ensure the OPEP is, and remains fit for purpose, operators are expected to exercise personnel and equipment through different scenarios at different frequencies. For example, as a minimum, the offshore • OPEP must be exercised by every shift offshore at least once per year and the offshore deployment of Tier 1 dispersant spraying equipment must take place at least once per year. Finally, The Offshore Installations (Emergency Pollution Control) Regulations 2002 (EPC) give the Secretary of State for Energy and Climate Change the powers to intervene in an incident involving an offshore installation where there is, or there may be a risk of significant pollution. The Secretary of State's Representative (SOSREP) acts as the single representative on behalf of the Secretary of State. https:// www.og.decc.gov.uk/environment/msri 998.htm The SOSREP will monitor the operator's response to a pollution incident and if he deems necessary, has the powers to give directions and to take such other actions as may be necessary to prevent or minimise pollution or the threat of pollution. Operators must have facilities and personnel available to work alongside their existing Emergency Response Centre to accommodate the SOSREP and his associated team in the Operations Control Unit (OCU), which may be set up as a result of a pollution incident. Within their respective OPEPs, operators must: include arrangements to reflect the potential involvement of the SOSREP and his team; demonstrate where the OCU fits into the company's emergency response management structure; and — identify those personnel who may be deployed to the OCU as part of the SOSREP's team. It is a requirement of the legislation that every five years each operator must conduct an exercise to test the OPEP and the involvement of the SOSREP. C: Confirmation of whether the regulatory regime been subject to best practice review by the Better Regulation Task Force or Risk & Regulation Advisory Council and the results of that review if one has been completed The DECC oil & gas regulatory regime has not be subject to either a best practice review by the Better Regulation Task Force or Risk & Regulation Advisory Council. However, Action 9 of DECC's Annual Energy Statement makes a commitment to "undertake a full review of the oil & gas environmental regime following the outcome of investigation into the causes of the GoM incident. " This review of the UK regime will be undertaken as soon as the detailed analysis of the factors • which caused the Gulf incident has taken place. This will look at the how the root causes of the Gulf incident can be protected against and determine what more, if anything, needs to be done to reinforce further the UK's regulatory approach. The Better Regulation Task Force undertook an enforcement review which included health and safety in its scope in 1999. This was a general study and did not specifically consider the offshore regulatory regime. • is • LICENUIG ENVIRONMENTAL TECHNICAL, FINANCIAL ASSESSMENT OF PROPOSED & ENVIRONMENTAL LICENCE BLOCKS COMPETENCE DECC(OED) DECC(LED/OED) PETROLEUM EU SEA DIRECTIVE EU EIA DIRECTIVE ACT 1998 EU HABITATS DIRECTIVE EU BIRDS DIRECTIVE Activity Regulatory Oversight Counter Pollution Activities Consultees & Stakeholders EXPLORATION PRODUCTION DECOMMISSIONING WELL DESIGN LICENCE ENVIRONMENTAL ENVIRONMENTAL FIELD DEVELOPMENT SAFETY CASE APPROVAL OF WELLINTEGRITY OBLIGATIONS REGS/PERMITS & REGS/PERMITS & PLANS&INFRASTRUCTURE DECOMMISSIONING DRILLING & SAFETY CASE COMPLIANCE e.g. COMPLIANCE e.g. PROJECTS / OPEPS & OPEPS OPEPS SAFETYCASE HSE(OD) DECC(LED) DECC(OED) DECC(OED) DECC(LED) HSE(OD) DECO (ODD) HSE (OD) COUNTER POLLUTION ACTIVITIES —OPERATORS, MCA, SOSREP DECC— NATIONAL CONTINGENCY PLAN MCA AND OIL SPILL RESPONSE LTD - PROVIDES AERIAL SURVEILLANCE & DISPERSANT SPRAYING CAPABILITY ALONG WITH EQUIPMENT THAT CAN BE USED FOR MECHANICAL RECOVERY & CONTAINMENT OF OIL TO OFFSHORE OPERATORS SCR PETROLEUM EU EIA DIRECTIVE EU EIA DIRECTIVE PETROLEUM ACT LP PETROLEUM ACT 1998 MAR ACT 1998 EU HABITATS DIRECTIVE EU HABITATS DIRECTIVE 1998 SCR PFEER EU BIRDS DIRECTIVE EU BIRDS DIRECTIVE MAR DCR CPA 1949 CPA 1949 PFEER SRSCR OCR OCR DCR OPPC OPPC SRSCR FEPA EU ETS OPRC PPC EPC FEPA OPRC EPC m O to N 7 tl n_ 3 d CD n s N 7 to O 3 3 m N m Q m 7 n m N V • 0 Ev 128 Energy and Climate Change Committee: Evidence Annex B UK OFFSHORE OIL & GAS REGULATORY LANDSCAPE —KEY CCW Countryside Council for Wales CEFAS Centre for Environment, Fisheries & Aquaculture Science CPA 1949 Coast Protection Act 1949 DCR Offshore Installations & Wells (Design & Construction, etc.) Regulations 1996 DECC LED Department Energy & Climate Change —Licensing Exploration & Development DECC OED Department Energy & Climate Change —Offshore Environment & Decommissioning DEFRA Department for Environment, Food & Rural Affairs EA Environment Agency EHS Environment & Heritage Service EPC The Offshore Installations (Emergency Pollution Control) Regulations 2002 EU EIA Directive Environmental Impact Assessment Directive EU ETS The Greenhouse Gas Emissions Trading Scheme Regulations 2005 EU SEA Directive Strategic Environmental Assessment Directive FEPA Food & Environment Protection Act 1985 HSE OD Health & Safety Executive Offshore Division JNCC Joint Nature Conservation Committee MAR Offshore Installations & Pipeline Works (Management & Administration) Regulations 1995 MCA Maritime & Coastguard Agency MMO Marine Management Organisation MOD Ministry of Defence MS Marine Scotland NE Natural England NFFO National Federation of Fishermen's Organisations NIA Northern Ireland Assembly NLB Northern Lighthouse Board OCR Offshore Chemicals Regulations 2002 OPEPS Oil Pollution Emergency Plans OPPC Offshore Petroleum Activities (Oil Pollution Prevention & Control) Regulations 2005 OPRC The Merchant Shipping (Oil Pollution Preparedness, Response Co-operation Convention) regulations 1998 PFEER Offshore Installations (Prevention of Fire & Explosion, & Emergency Response) Regulations 1995 PPC Offshore Combustion Installations (Prevention & Control of Pollution) (Amendment) Regulations 2007 SCR Offshore Installations (Safety Case) Regulations 2005 SEPA Scottish Environment Protection Agency SFF Scottish Fishermen's Federation SG Scottish Government SNH Scottish Natural Heritage SOSREP Secretary of States Representative SRSCR Offshore Installations (Safety Representatives & Safety Committees) Regulations 1989 TH Trinity House UKHO United Kingdom Hydrographic Office WAG Welsh Assembly Government • • • WATER DEPTHS & EXPLORATION ACTIVITY WEST OF SHETLAND & WEST OF SCOTLAND • Exploration and Appraisal Wells to date r Oil & Gas fields (in production or under development) August2010 Faroe Islands oV ..1 1 1 1 1 1 1 1 1 1 1 1 1 1 T OF COTLA� D 1 1 1500•m . • • • �1 r s • s 010 p O (n 1 a It •; • (� etland Islands A 1 "WEST OF Y• , � SHE1 to f 1Q/ i 0° Orkney Islands O i o ' O0 It o � PD/MAPS/GENERAL/ST BATHY 040810 veld A4 w • Ev 130 Energy and Climate Change Committee: Evidence Annex D BACKGROUND NOTE OPERATIONAL FACTORS WHICH COMPLICATE DEEP WATER DRILLING OPERATIONS Wells are controlled and prevented from flowing by a column of high density drilling fluid, commonly referred to as "mud." The level of risk at any given well location is determined by the particular way in which rocks have been laid down over time. However there are a number of operational factors for deepwater drilling operations that result in the wells being more difficult to control. As a rule of thumb the reservoir pressure is determined by the depth below the sea surface, while rock strength increases only with depth below seabed. As result, for a given depth below seabed deepwater wells are more highly pressured than wells in shallower water, while rock strength is unaffected by water depth. Factors which affect well control in deep water wells include: — Higher pressures encountered when drilling a well. There is no information about the pressure regime in the Gulf of Mexico well, but assuming a normal pressure gradient, the reservoir pressure would be in the order of 8,000 psi compared to 6,000 psi for a well in shallow water in otherwise similar circumstances. — Lower tolerance to kicks. As deep water wells tend to be more highly pressured they require a higher density of drilling fluid to control the reservoir. However, the rock strength may be insufficient to withstand the higher density of the fluid, fracturing the rock, allowing the drilling fluid to leak away and allowing the reservoir to flow. This is countered by lining the well with steel casing and has to be done more often than in wells in shallower water. — Temperature variations between cold sea and hot rock below the seabed can alter the density of the drilling mud. In deep water drilling, this complicates the ability to control the density of the drilling fluid, keeping it sufficient to stop the well from flowing but not too high to fracture the rock. — Less responsive pressure control arrangements. With the long distance between rig and seabed changes in pressure in the well take longer to detect, and longer to respond to action taken at • surface to control them. — Disconnection or failure of the marine riser. The marine riser is the large diameter pipe connecting the well at seabed to the rig at surface during drilling operations. The riser will contain high density drilling fluid, but before it is disconnected the drilling fluid ("mud") will need to be replaced by seawater. In deep water the combination of seawater in the riser and drilling fluid below the seabed will be insufficient to prevent the reservoir from flowing, so for planned disconnection the density of drilling fluid below seabed is increased to compensate. For an unplanned disconnection or failure of the riser, the well must be shut in at the seabed by closing the blowout preventers at the seabed. Memorandum submitted by DONG Energy EXECUTIVE SUMMARY — The Macondo blowout in the Gulf of Mexico was a tragic accident which has challenged the whole oil and gas industry to carry out a thorough and detailed audit and revalidation of its safety, environmental and operating processes across all of its exploration and production (E&P) activities; — In the immediate wake of the Macondo incident DONG Energy established an internal "Deepwater Horizon Learning Task Force". This was designed to ensure that all information and data emanating from the various technical groups and industry initiatives established to investigate the incident could be comprehensively gathered, distributed and incorporated throughout the organisation's procedures; — DONG Energy has stringently re -appraised the existing regulatory regime against our internal processes and concluded that the goal -setting framework in the UK is robust and fit for purpose for operations in all water depths; — In light of this, we do not believe that there is a requirement for a moratorium on drilling in the West of Shetlands; — The industry response to the Macondo incident through OSPRAG will allow the industry to apply • the lessons learned from the disaster; and — A moratorium would prevent the discovery and extraction of the new sources of gas supply from the West of Shetland which are required to mitigate the decline in supply from other areas of the UKCS. This continued supply is imperative as the drive for renewable electricity will demand new, low -carbon, flexible gas fired power plants to compensate for the intermittency of wind generation. Energy and Climate Change Committee: Evidence Ev 131 1. DONG Energy Company Profile 1.1 DONG Energy is a leading energy company operating in Northern Europe and headquartered in Denmark. It has a strong presence across the energy value chains. These include Exploration and Production, Generation (thermal and renewable), Energy Markets and Sales and Distribution. DONG Energy does not however supply energy to retail customers in the UK. 1.2 By 2020, DONG Energy aims to have reduced its CO2 emissions per kWh of generation by 50%, and by 85% by 2040. In order to achieve these targets, growth has been focussed on the two main areas of Renewable Power Generation and natural gas. The United Kingdom has a major part to play in both areas. Exploration and Production (E&P) 1.3 DONG Energy is one of the largest acreage holders in the West of Shetland Region and a partner in the recently sanctioned Laggan-Tormore gas development. The company's first operated well in the UK (the Glenlivet gas discovery) was drilled in the West of Shetland in 2009. It has interests in a further six discoveries. DONG Energy is not currently drilling as operator in UK territorial waters. Aside from the UK, DONG Energy is the operator of nine licences in Denmark, six in Norway, including the Barents Sea and one in Greenland. Renewable Power Generation 1.4 DONG Energy is one of the most active offshore wind operators and investors in the United Kingdom. The company currently operates three offshore wind farms (Gunfleet Sands, Barrow & Burbo Bank). It has a stake in a further two sites currently under development (London Array and Walney). DONG Energy is the major shareholder in London Array. It also possesses a strong pipeline of potential future renewable projects. Thermal Generation 1.5 In thermal generation, DONG Power UK is close to completing a new CCGT gas fired power station • of 824MW output at Severn in South Wales. 2. What are the implications of the Gulf of Mexico oil spill for deepwater drilling in the UK? 2.1 DONG Energy believes that careful planning, competence of personnel, integrity management of equipment and risk management of operations are imperative prerequisites of safe conduct and acceptable results. Whilst the physical conditions of deepwater drilling do change the requirements for planning and equipment, the principles for operations, risk management and risk reduction remain the same. The application of the lessons learned from the Macondo incident should not therefore be limited to deepwater operations, regardless of definition. 2.2 The principle implication of the Macondo incident is a renewed need for the oil and gas industry to actively demonstrate that it has taken account of worst case scenarios in its planning. It must be able to demonstrate to the satisfaction of all interested stakeholders that it is competent to drill safely in all targeted reservoirs on the UKCS and that it has the capacity to respond promptly and effectively to a loss of well control and to any resultant oil spill —however unlikely that occurrence might be. 2.3 It is important to consider what defines deepwater drilling and, more significantly, what impact water depth had on the operations and incidents leading up to the Deepwater Horizon blow-out. Depth was but one factor of many. Whilst drilling does take place at significant water depths in the West of Shetland Region, other factors are notably different to those at Macondo. Temperature and pressure, for example, are substantially lower in the WoS. Judgement of risk on water depth alone is too crude a measure. 2.4 There is no standard or uniformly adopted definition of deepwater operations. However, for the purposes of progressing the investigations into deepwater drilling in the UKCS, DECC, HSE and MCA use the term "deepwater" to indicate drilling operations in water depths of more than 300 metres. When the UK offshore oil and gas business was in its early development phase in the early/mid 1970s, water depths of 200 metres were considered "deep". Over the last three decades, the global offshore drilling industry has developed technology and experience that has enabled drilling operations to take place in water depths as high as 3,000 metres. Advances in offshore technology mean that the number of regions of the world in which exploration is possible will continue to grow in the years ahead. 2.5 There are fundamental challenges and risks to any form of drilling. Some of these are specific to the conditions and environment of a certain area, but others are common to all. Maintaining and ensuring well iscontrol, both primary and secondary, is of overriding importance in all drilling operations anywhere, whether onshore or offshore, in shallow or deep water. DONG Energy conducts its operations in accordance with management systems based on regulatory requirements, international standards and norms, industry best practice and more than 30 years of operational experience. We believe that the probability of major accidents is dictated by a variety of factors including company policy, equipment, procedures and personnel —not on the specific location alone. Our operations are constantly evaluated against risk to ensure Ev 132 Energy and Climate Change Committee: Evidence • that risk is reduced as low as reasonably practicable (ALARP). We look for continuous improvement in our planning and operations and require absolute compliance with our internal company standards wherever we operate. DONG Energy's response to the Macondo incident 2.6 In the immediate wake of the Macondo incident DONG Energy established an internal "Deepwater Horizon Learning Task Force". This was designed to ensure that all information and data emanating from the various technical groups and industry initiatives established to investigate the incident could be comprehensively gathered and distributed throughout the organisation. Furthermore, it has ensured that DONG Energy is aware of all industry programmes and is well-equipped to contribute its expertise as appropriate. 2.7 DONG Energy in the UK has played a full and active role in the work of the OSPRAG Technical Review Group sub -teams to ensure effective cross -industry learning and the dissemination of best practice. 3. To what extent is the existing UK safety and environmental regulatory reginie fit for purpose? Regulatory Regime 3.1 In contrast to the US and other parts of Europe where regulation lays down precisely what an operator is expected to do, the UK HSE regulatory environment is based on a goal -setting, non -prescriptive regime. This approach was developed following Lord Cullen's inquiry into the Piper Alpha tragedy of 1988. Under the current process, operators on the UKCS are required to show that they have taken appropriate steps to identify and assess the consequences of major accident hazards and to demonstrate to the regulator that necessary measures have been taken to reduce these risks as far as reasonably practicable. The regime is also designed to give precedence to the safety of personnel and places an emphasis on the prevention of accidents. This approach has been seen to be effective and successful over the past 20 years. DONG Energy subscribes to the widely -held view that the UK regulatory regime is regarded as one of the most thorough and robust in the world. • Offshore Installations and Wells (Design and Construction, etc) Regulations 1996 (DCR) 3.2 A key component of DCR is the requirement for a formal well examination scheme and the appointment of a Well Examiner. The regulation requires that the design, construction and maintenance of a well must be independently verified and defines the Well Examiner's role in examining all stages of a well's planning, execution and operation throughout its life cycle. DONG Energy places a high importance on well design, planning and construction. All DONG Energy well designs are planned from the conceptual stage of a Basis of Design (BOD) and evolve through the sequential cycle of a well planning process. DONG Energy has five clear stages of well planning, from the initial Business Planning and Feasibility Study stages, through to the final Execution phase synonymous with the drilling of the well. Prior to progressing through each stage, the well design is peer reviewed by both in-house and external bodies. This includes assessment by the UK Well Examination scheme, which reviews and assesses well design. Ultimately, the final well design is presented to and examined by the independent Well Examiner and Health and Safety Executive (HSE), prior to final sign off and acceptance of the well plan. DONG Energy considers these requirements to represent a robust and practical method of managing and controlling well design to ensure the safe drilling and completion of wells on the UKCS. Environmental Management 3.3 The management of environmental matters on the UKCS is subject to strict UK, EU and International environmental legislation. This legislation is broad and far reaching and defines requirements for consents, permits and environmental reporting. Limits for discharges and emissions are also included, as are arrangements for oil spill planning and response. These matters are under the control of DECC which is also responsible for inspection, investigation and enforcement. In line with OSPAR requirements, DONG Energy operates under an ISO 14001 certified Environmental Management System. The ISO 14001:2004 certification provides independent verification that DONG Energy conducts its activities in an environmentally responsible manner and is compliant with UK law and relevant oil industry standards. The award of the ISO certificate confirms that the company has identified and assessed the environmental impacts and risks of its operations and has a reliable system in place to manage these issues. • UK Regulatory Bodies 3.4 DONG Energy recognises and acknowledges the wide-ranging skills, knowledge and experience of both HSE and DECO. Both organisations possess the ability to access a wide range of knowledge and experience which adds exceptional value when assessing the management of safety and environmental risk offshore. Energy and Climate Change Committee: Evidence Ev 133 • 4. What are the hazards and risks of deepwater drilling to the West of Shetland? 4.1 The West of Shetland area is not considered to be an especially deepwater area by global industry standards. The most significant hazards with West of Shetland operations are its remoteness and the meteorological and oceanographic conditions encountered in the region particularly during winter months. Wind, waves and currents are more severe and often less predictable than in other areas of the UKCS. DONG Energy is extremely confident that the risks associated with these hazards are well understood and well managed under a fit -for -purpose regulatory regime and an effective safety culture with multiple barriers in place. DONG Energy keeps these systems under regular review, most recently in light of the Macondo incident. 4.2 Water -depth and deepwater currents impact on all aspects of drilling operations. These must be carefully planned for and managed, particularly in the event of severe weather conditions which require the rig to disconnect from the well until those conditions subside. Due to significant water currents at different depths, more care must be taken with riser design, well -head fatigue analysis and general load distribution. These and many other aspects are major considerations in selecting a suitable rig to operate West of Shetland and are often more demanding criteria than applied to normal UKCS activities. The selection of the right drilling rig is essential. Dynamically positioned rigs and drillships are typically used in water depths greater than 300 metres and use sophisticated sensors, together with their own thrusters and propellers, to maintain position and heading. 4.3 DONG Energy is active in several areas in the West of Shetland. During 2009, the company (as operator) successfully drilled an exploration well on the Glenlivet field in UKCS Block 214/30a with no incident or accident. This well is classed as a discovery and it is intended that this field should be developed further. Whilst the Glenlivet field is a normally pressured gas reservoir, DONG Energy will ensure that any and all lessons learned from the Macondo incident will be implemented in internal processes both for operated and non -operated activities. 4.4 In total, more than 400 wells have been safely drilled West of Shetland over the last 30 years. The Foinaven and Schiehallion fields have been successfully producing oil for over ten years and Clair for five years without any significant oil spill incident. The number of wells drilled clearly demonstrates that the industry does have the skills and technology required to operate safely in the West of Shetland area. • 4.5 The UK's goal setting safety regime requires a systematic approach to the identification of hazards and ensures that risks are reduced as low as reasonably practicable through the application of quality engineered solutions and systems. The approach taken West of Shetland is no different. 5. Is deepwater oil and gas production necessary during the UK's transition to a low carbon economy? 5.1 DONG Energy believes that the production of gas is critical for the transition to a lower carbon future. The West of Shetland area is currently believed to hold some 17-20% of the UK's remaining hydrocarbon reserves. As such, it is essential for the maintenance of a secure source of supply for the UK, particularly in terms of gas. 6. To what extent would deepwater oil and gas resources contribute to the UK's security of'supply? 6.1 DONG Energy believes that there is significant remaining gas prospectivity in the West of Shetland outside of the Laggan-Tormore area which could strongly reinforce the UK's gas security in the future. This will require further exploration activity and the installation of further pipelines and infrastructure. It should be noted that the time to drill, appraise and develop fields in the West of Shetlands is very lengthy and therefore it is imperative to maintain ongoing activity to guarantee this future security. October 2010 Supplementary memorandum submitted by Transocean I write in response to the letter I received from the Energy and Climate Change Committee on 7 December 2010 regarding a well control incident on the Shell UK -operated Sedco 711 drilling rig in the North Sea Bardolino Field on 23 December 2009. Transocean Drilling U.K. Limited. (Transocean) appreciates the opportunity to clarify several misstatements and inaccuracies reported in the Today Programme and other media outlets. As a threshold matter, Transocean notes that the 23 December 2009 incident on the Sedco 711 is a matter of public record, having been reported in several media outlets, including the New York Times and the European edition of the Wall Street Journal in August 2010, prior to the Committee's first inquiry on 7 September 2010. • First, Transocean stresses that the safety programme onboard the rig functioned as designed, allowing one of the annulars on the blowout preventer to be closed and seal off the well, pursuant to the Transocean and Shell well control procedures for a "hard close in". Transocean took all appropriate actions to address the matter in the days and weeks following the incident. There were no casualties, no asset integrity loss, and a minimal amount of product —approximately three barrels of oil -based mud and the equivalent 0.9 tonnes of oil —lost to sea. Ev 134 Energy and Climate Change Committee: Evidence Second, as required by the Health and Safety Executive (HSE) Regulation, the Operator, Shell UK, reported the incident to the HSE in an OIR9B filing on 24 December 2009, which under the Regulation must be submitted within ten days of the incident. This notice provided the agency with an explanation of what transpired on 23 December, and the agency had a full understanding of the incident. The HSE sent Shell UK Ltd a letter on 24 February 2010 acknowledging the incident and notifying Shell that "any release of hydrocarbons from a well could lead to enforcement action under the Regulation". The Department of Energy and Climate Change (DECC) was advised of the event by Transocean in a PON1 filing. As explained to the HSE in the OIR9B filing, the series of events that took place were as follows: The incident took place on 23 December 2009 at 17:15 onboard the Sedco 711 semi -submersible drilling rig during the upper completion clean up phase of the well. The lower completion had been installed and the isolation packer and formation isolation valve (FIV) were pressure tested. The FIV was then successfully inflow tested with a column of base oil confirming the integrity of the mechanical barrier to the reservoir. After the successful completion of the test, the clean up of the well to seawater began in preparation for final displacement to base oil. During the clean up and displacement, mud returns were routed to the reserve pits. As a result, volumes could not be monitored on the active pit system and thus, actual displacement could not be measured. There were indications of an increase in flow out in the rate of mud returns to the pit room during displacement, but this was expected due to the increased pump rate. After approximately ten minutes at a higher pump rate, the rate was reduced to allow the pit room to resolve the increasing flow issues. At this point the well began to flow, unloading mud onto the drill floor. The shaker alarms were triggered indicating an increase in gas levels. As soon as the mud was observed, the pumps were switched off and the blowout preventer was successfully activated with the lower annular. With the well shut in, the drill pipe was spaced out and the middle pipe rams of the blowout preventer were closed, securing the well. • The general alarm was sounded by the control room. Emergency Response Procedures were initiated pursuant to the Operations Management Plan. The Emergency Response Team (ERT) provided a briefing informing that there were no casualties; full muster of 95 persons on board was achieved at 17:36. The ERT coordinator was contacted and continuously kept informed of the situation. The HSE was satisfied with the investigation led by Shell and the actions from the investigation report for Shell, Transocean and Schlumberger, and thus did not require a specific change in procedures as a result of the Sedco 711 incident on December 23. However, Transocean issued two operations advisories in response to the incident. A Well Operations Group Advisory, dated 5 April 2010 and issued to all Transocean installations, confirmed that the Well Control Handbook would be modified to clarify the requirements for monitoring and maintaining at least two barriers when displacing to an underbalanced fluid during completion operations. The second advisory was issued to the entire Transocean North Sea fleet and recommended specific follow-up actions related to well control preparedness during a completion phase, awareness of well control indicators, and adequate well programs. With regard to the "insufficient mud" referenced in the Today Programme, there was minimal reserve mud onboard the Sedco 711 as the mud in the hole was "kill mud weight" for pressures known in the well. The mud displaced from the hole after the blowout preventer was closed was contaminated with hydrocarbons and not suitable to pump back in the hole. As a result, good mud needed to be brought back onboard from a supply vessel. Finally, although the Bardolino well control incident and the Macondo blowout in the Gulf of Mexico appear to share certain elements in common —both involved an underbalanced column of drilling fluids in the well, for example —we believe that the two events, based on our current understanding of the events surrounding the 20 April Macondo incident, are distinct examples from which the industry as a whole can learn. While the Macondo blowout remains under investigation by Transocean and multiple U.S. governmental bodies, we know that the cementing of the final casing string and the use of an unusual spacer during negative pressure testing have been identified as potential contributing factors to the 20 April incident. By contrast, neither • cement nor spacer material were identified by Shell or Transocean as underlying causes of the Bardolino incident. In addition, Bardolino involved the drilling of a deviated hole, rather than a vertical hole as with Macondo; Bardolino was drilled in the North Sea, not the U.S. Gulf of Mexico, which are starkly different drilling environments; and each incident involved a different operator. Transocean is not aware of any other incidents on its rigs in the North Sea in the last five years that are of a similar profile to the 23 December 2009 Bardolino incident. Energy and Climate Change Committee: Evidence Ev 135 Transocean continues to operate its rigs on the UK Continental Shelf with the highest degree of safety and diligence. It is committed to ensuring a safe and reliable work place for its employees and stands willing to assist the Committee in its ongoing inquiry. December 2010 Supplementary memorandum submitted by the Health and Safety Executive WELL CONTROL INCIDENT TRANSOCEAN SEDCO 711 WELL 22/13A-8 (BARDOLINO) Shell has informed us that HSE was informed of the spill from the Sedco 711 platform and carried out its own investigation of the series of events that led up to the spill. How serious was the incident? HSE answer: Shell viewed this incident as high potential. If the blowout preventer (BOP) had not shut the well in there was the possibility for a blowout to occur with the resulting potential for escalation of the incident. However, this can be said for any "kick" (which is an early warning that there has been an unexpected flow into the well and that action must be taken) that are not detected and shut in promptly. In this instance, the BOP did work effectively as planned and provided the barrier to shut the well in, stop it flowing and allow it to be brought back under control. Did HSE require any changes to procedures as a result of its investigations? HSE answer: As a result of the HSE investigation, and in accordance with our Enforcement Management Model (which is a framework which helps inspectors make enforcement decisions), a letter was sent to Shell regarding their general well integrity responsibilities under Regulation 13 Offshore Installations and Wells (Design and Construction, etc) Regulations 1996. HSE assessed the corrective actions implemented by Shell and Transocean and considered they addressed the shortcomings that led to this incident and have addressed the • well control issues that occur when displacing drilling mud out of the well. How satisfactory was the response by the crew to the incident? HSE answer: The crew's response to the incident in terms of bringing the flow in the well under control (a "well kill") was ultimately satisfactory. However the performance of the crew prior to the incident was not satisfactory, as they did not detect that the well was flowing sooner. The crew's risk awareness and risk perception was blinkered by a previous positive test of the operation of the Formation Isolation Valve and they did not fully take into account that such a tested barrier can subsequently fail. The crew should have also stopped the displacement of the drilling mud from the well sooner to evaluate what was happening in the well. The crews well control preparedness was not as their procedures called for as certain information was not immediately available for use, and they had not had a well control drill for 10 days. These issues were subsequently addressed in the Shell/Transocean corrective actions. Did the HSE consider whether the incident was appropriately dealt with by the offshore management as events developed.? HSE answer: The comments above also apply to the offshore management. Additionally the problems caused by not having sufficient mud at the correct mud weight available should have been foreseeable, planned for and dealt with better by the offshore and onshore management. The changes that then took place to instigate an alternative method of "well kill" were initially insufficiently formalised. However, after further deliberation, the well kill was stopped and reconsidered by onshore and offshore staff under a formal and comprehensive management of change process, and the revised method successfully circulated mud in the well under controlled conditions. Are such offshore drilling platforms required to have mud of a sufficient density ready to kill the well? What was the HSE's reaction to finding that the Sedco did not? • HSE answer: There is no specific prescriptive requirement to have mud of the required density that could kill the well onboard a drilling installation at all times —there are fluid storage limitations on some installations. It is therefore good industry practice to have sufficient weighting agent onboard the installation that can raise the mud's density to kill the well if required (if excessive well bore pressure is experienced while preparing the kill weight mud it can be managed in a controlled fashion). Ev 136 Energy and Climate Change Committee: Evidence • In this incident, because the well had been successfully inflow tested Shell considered that they could offload the mud from the rig. HSE considers this could have been managed better by the offshore management team, and ensured that this was fed into the incident lessons learnt. • How may of the 56 oil spills in 2009 were as a result if incidents which could have led to blowouts if evasive action had not been taken? HSE answer: None of the 56 crude oil spills reported to DECC in 2009 were related to drilling incidents which could have led to a blowout. The incident on 23 December did not give rise to a spill of any crude oil to sea. The fluid released to sea during the incident was a drilling mud that is classified as a chemical under the provisions of DECC's Offshore Chemicals Regulations 2002. As such, the fluid release was reported to DECC as a chemical release. The loss of the drilling mud did not result in any adverse effect on the environment. December 2010 ISBN 978-0-215-55579-3 V ?EFC PVFC/16-33-6 Printed in the United Kingdom by The Stationery Office Limited 1/2011 006268 19585 IN -CONFIDENCE • • REVIEW OF PTTEP AUSTRALASIA'S RESPONSE TO THE MONTARA BLOWOUT For the Department of Energy, Resources, and Tourism Noetic Solutions Pty Limited ABN 87 098 132 024 November 2010 Ouaiily ISO 9001 f sa GLOBAL IN -CONFIDENCE Distribution This document was prepared for the sole use of the Department of Energy, Resources and Tourism (DRET). Distribution of this report is at the discretion of DRET. Authors Principal Mr Peter Murphy Primary Author Governance Review: Mr Damien Victorsen Technical Review: Mr Peter Wilkinson Contributors Ms Lex Drennan, Mr Barry Adams Mr Barry Adams Revision Log 26 November 2010 Draft Report presented to DRET executive. The Draft Report is for comment. 7 December 2010 DRET provides the Draft Report to PTTEP AA for comment prior to finalisation. 4 January 2011 Final Report provided to DRET. Noetic Solutions Pty Limited ABN: 87 098 132 027 PO Box 3569 Manuka ACT 2603 Australia Phone +61 2 6232 6508 Fax +61 2 6232 6515 Web www.noeticgroup.com a • • WWW.NOETICGROUP.COM IN -CONFIDENCE • CONTENTS EXECUTIVESUMMARY............................................................................................................................. IV 1 INTRODUCTION.................................................................................................................................1 1.1 Background 1 1.2 Aim of this Report 2 1.3 Review Scope 2 2 METHODOLOGY................................................................................................................................4 2.1 Stage 1: Start Up and Scoping 4 2.2 Stage 2: Review of Documentation 4 2.3 Stage 3: Direct Engagement 4 2.3.1 Engagement with personnel 4 2.3.2 Review of documentation 4 2.4 Stage 4: Analysis 5 2.5 Stage 5: Finalisation and Presentation of Report 5 3 TECHNICAL REVIEW........................................................................................................................6 3.1 Overview of Findings 6 3.2 Detailed Findings 6 3.2.1 The original Montara Action Plan 7 3.2.2 Amended Montara Action Plan (Revision 12) 8 3.2.3 Amended Montara Action Plans 9 3.2.4 Additional Documents supplied by PTTEP AA 10 . 4 GOVERNANCE REVIEW.................................................................................................................14 4.1 Definition of Governance 14 4.2 Montara Commission of Inquiry Summary of findings regarding PTTEP AA 15 4.3 Findings 16 4.3.1 Assessment of Montara Action Plan 16 4.3.2 Governance Structures and Processes, and Relationships 18 4.3.3 Internal Environment 27 4.3.4 Implementing sustainable change 29 4.3.5 PTTEP AA's Future Plans 31 4.4 Analysis of Findings 33 5 LESSONS FOR INDUSTRY.............................................................................................................34 5.1 MAE education for leaders and managers 35 5.2 Performance monitoring and auditing 35 5.3 Providing incident information quickly 36 5.4 Increase the reporting of high potential or significant incidents 36 5.5 Review the training available for personnel making judgments on the safety of well operations 36 5.6 Mergers and Acquisitions 36 5.6.1 Due Diligence 36 5.6.2 Integration of Acquisitions 37 5.7 Integration of Health Safety and Environment 38 5.8 Governance and Oversight 38 5.8.1 Advisory Boards 38 6 CONCLUSION..................................................................................................................................39 • ANNEX A: LIST OF ACRONYMS AND ABBREVIATIONS:::::::::::::::::::::::::::::::::::::.............................40 ANNEX B: INTERVIEWED PERSONNEL .......................... 41 ANNEX C: DOCUMENTS REVIEWED..................................................................................................42 WWW.NOETICGROUP.COM IN -CONFIDENCE ANNEX D: CORPORATE PLANNING FRAMEWORK.........................................................................47 ANNEXE: PERSONNEL PARTICIPATING IN MONTARA ACT/ON PLANSTEERING COMMITTEE • MEETINGS...........................................................................................................................48 ENCLOSURE 1: TERMS OF REFERENCE - TECHNICAL REVIEW...................................................49 ENCLOSURE 2: TERMS OF REFERENCE - GOVERNANCE REVIEW..............................................51 ENCLOSURE 3: INITIAL REPORT AND KEY ISSUES SUMMARY.....................................................53 ENCLOSURE 4: AMENDED MONTARA ACTION PLAN (DRAFT B - 2 NOVEMBER 2010)..............61 ENCLOSURE 5: MONTARA ACTION PLAN (LIST OF ACTIONS) REV 14, 29/10/201).....................68 r �J • WWW.NOETICGROUP.COM IN -CONFIDENCE • EXECUTIVE SUMMARY In August 2009 the Blowout' at the Montara wellhead platform (WHP) became Australia's third largest oil spill. At the time of the Blowout, the Thailand -based PTT Exploration and Production Company Limited (PTTEP)'s Australian subsidiary, PTTEP Australasia Ashmore -Cartier Pty Ltd (PTTEP AA) was the licence holder for the Montara oil field. PTTEP had recently acquired Coogee Resources Limited (CRL) to establish this Australian subsidiary. Following receipt of a report from the Montara Commission of Inquiry (MCI), the Minister for Resources and Energy, (the Minister) directed the Department of Resources, Energy and Tourism (DRET) to commission an independent review of the Montara Action Plan, which PTTEP AA had provided to the Minister in response to the MCI draft Report. DRET contracted Noetic Solutions Pty Limited (Noetic) to undertake a review of PTTEP AA's governance arrangements (the Governance Review) and a review of PTTEP AA's Montara Action Plan (the Technical Review). The intent of the reviews was to provide the Australian Government with sufficient assurance that the Montara Action Plan will address the lessons from the MCI and that PTTEP AA's identified operational measures meet industry good practice requirements. This Report details the outcomes of the independent reviews. It provides background to the Montara Blowout and the MCI, and the methodology used to undertake the reviews. It provides the findings from Noetic's engagement with PTTEP AA, their response to interim findings and Noetic's analysis. Finally, Noetic identifies a number of options and recommendations for DRET to consider. In conducting the reviews, Noetic examined key documentation including the MCI Report, transcripts from the MCI's hearings and PTTEP AA's Montara Action Plan. Noetic also engaged directly with personnel from both PTTEP AA and its parent company PTTEP. This Report contains a number of findings about PTTEP AA's initial Montara Action Plan (4 June 2010) and PTTEP AA's governance framework. Noetic found that in the Montara Action Plan (4 June 2010), PTTEP AA had identified the actions necessary to address the technical issues that caused the Montara Blowout. However, in its original Action Plan, PTTEP AA had not identified the actions needed to address the systemic organisational and governance issues that provided the environment for the Montara Blowout to occur. The shortfalls in PTTEP AA's Action Plan were raised with the company during the course of the review. PTTEP AA was subsequently able to identify a number of initiatives either underway or planned, which address the Action Plan's shortfalls and some of the company's systemic or organisational issues. PTTEP AA has since developed a more comprehensive Montara Action Plan. This demonstrates PTTEP AA's willingness to engage and a genuine desire to build confidence in its ability to meet industry good practice requirements. The willingness to engage and the initiatives now included in PTTEP AA's updated Montara Action Plan provide some confidence that PTTEP AA is taking, and will continue to take, the steps necessary to improve its operations and governance to ensure it operates safely in the future. PTTEP's intent that improvements in PTTEP AA will also provide a new benchmark for standard practice across PTTEP is also encouraging. However, at this (early) stage of PTTEP AA's change process, Noetic has only been able to examine the company's intent and comprehensiveness of its plans for change. To this end, Noetic is satisfied that PTTEP AA has a plan that • effectively responds to the issues raised in the MCI and importantly the plan sets the company on the path to ' An uncontrolled loss of hydrocarbons in the form of oil or gas. WWW.NOETICGROUP.COM Iv IN -CONFIDENCE achieving industry standards for both good oilfield practice and good governance. However, the success of PTTEP AA's program for change will depend entirely on the quality of execution" • Until its change initiatives are completed and fully implemented, questions remain as to whether PTTEP AA's actions will be effective in meeting industry standards for good governance and good oilfield practice. The most important governance activity is the clarification of the governance arrangements between PTTEP and its subsidiary PTTEP AA (and related Australian entities2). This action is central to the effective long-term governance of PTTEP AA and its safe operation. Therefore, if the Australian Government decides to allow PTTEP AA to continue to operate, ongoing oversight is recommended to ensure that PTTEP AA successfully implements its planned change initiatives and addresses its shortcomings effectively. This follow up, if conducted over a period of 18 months, should provide sufficient assurance to the Australian Government that PTTEP AA has taken all reasonable steps to meet good industry practice requirements. In this report, Noetic has also identified lessons, which the Australian petroleum exploration and production industry should consider. Those lessons address issues such as enhancing the effective execution of mergers and acquisitions; and safety benefits arising from strong corporate governance. • • z Noetic was informed by PTTEP that all actions identified would be applied to all Australian entities. WWW.NOETICGROUP.COM V IN -CONFIDENCE • 1 INTRODUCTION 1.1 Background On 21 August 2009 there was a release of oil and gas (a Blowout) from the Montara Wellhead Platform (WHP), located off the north-west coast of Australia. The Blowout became Australia's third largest oil spill in history after the Kirki oil tanker and Pricess Anne Marie oil tanker 3. At the time of the Blowout, the Thailand -based PTT Exploration and Production Company Limited (PTTEP)'s Australian subsidiary, PTTEP Australasia Ashmore -Cartier Pty Ltd (PTTEP AA) was the licence holder for the Montara oil field. PTTEP had recently acquired Coogee Resources Limited (CRL) to establish this Australian subsidiary. Following the Blowout at Montara, the Australian Government established the Montara Commission of Inquiry (MCI)4. The MCI invited submissions, held public hearings and released parts of its draft report for comment. The Government received the Final MCI Report on 18 June 20105 and released the Final Report and its draft response to the public on 24 November 20106. On 4 June 2010, Mr Anon Sirisaengtaksin, President and Chief Executive Officer of PTTEP, wrote to the Minister for Resources and Energy, the Hon Martin Ferguson AM MP (the Minister), outlining PTTEP and PTTEP AA's response to the Montara Blowout, the draft MCI Report and plans to address the issues discussed in the MCI's public hearings. Mr Sirisaengtaksin's letter included the Montara Action Plan, and outlined how PTTEP AA proposed to transform their offshore petroleum operations and management to bring PTTEP AA in line with industry practice and government requirements. Following the receipt of this letter, the Minister announced he had directed the Department of Resources, Energy and Tourism (DRET) to commission an independent review of PTTEP AA's Montara Action Plan 7. The independent review was to inform the Minister on how the Montara Action Plan and PTTEP AA measures up to industry standards. DRET commissioned two reviews to satisfy the Minister's requirements. The intent of both independent reviews was to determine if the Australian Government could be assured that PTTEP AA is addressing the lessons from the MCI and will implement operational measures and governance arrangements that meet good practice within the petroleum exploration and production industry. The first review was to focus on the technical adequacy of PTTEP AA's Montara Action Plan (the Technical Review). The second review focused on the adequacy of PTTEP AA's governance arrangements (the Governance Review). The terms of reference (issued by DRET) for the Technical Review are provided at Enclosure 1. The terms of reference (issued by DRET) for the Governance Review are provided at Enclosure 2. DRET contracted Noetic Solutions Pty Limited (Noetic) to undertake both independent reviews simultaneously. 3 Commonwealth of Australia, 2010. Report of the Montara Commission of Inquiry. Borthwick, D. AO PSM. 4 Hon Martin Ferguson, AM MP. 5 November 2009. Media Release: Minister Announces Details of Montara Commission of Inquiry. s Hon Martin Ferguson, AM MP. 18 June 2010. Media Release: Montara Commission of Inquiry Report Received. e Hon Martin Ferguson, AM MP. 24 November 2010. Media Release: Final Report of the Montara Commission of Inquiry Released. Hon Martin Ferguson, AM MP. 11 August 2010. Address to the APPEA Oil and Gas Safety Conference. WWW.NOETICGROUP.COM PAGE 9 OF 73 IN -CONFIDENCE 1.2 Aim of this Report 0 This Report describes the outcomes of both the Technical Review and the Governance Review. In meeting this aim, the Report documents the: + background on the circumstances leading to the independent reviews; + scope of the independent reviews, including what is in scope and what is out of scope; + methodology applied to undertaking the independent reviews, including the evaluation methodology, the documentation reviewed and the personnel interviewed; + findings from the independent reviews; + options available for addressing those findings; + recommended actions for both PTTEP AA and the Australian Government in response to the independent reviews; and + lessons for the petroleum exploration and production industry. 1.3 Review Scope In combination, the scope of both independent reviews included: + a review of the technical adequacy of PTTEP AA's Montara Action Plan (4 June 2010) including: • review of the adequacy of the Montara Action Plan (4 June 2010) to address the issues identified by the MCI; • review the relationship between the contents of the Montara Action Plan (4 June 2010) and industry best practices; • identify gaps between the MCI's Report and the Montara Action Plan (4 June 2010); identify ways in which the Australian Government can ensure the Montara Action Plan (4 June 2010) is implemented, and; • recommend any broader actions that will support growth and training in the offshore petroleum industry; + review of PTTEP AA's governance arrangements including: • corporate structure and organisational chains of authority; • operations policies and management processes; • procedures (including for implementing change and continuous improvement); and • systems and processes for implementation of review activities; + a review of PTTEP AA's Montara Action Plan (4 June 2010), including: • implementation of the Montara Action Plan, • operating standards, • training methods, • policy framework, • governance framework, and • documents describing individual roles and responsibilities of key PTTEP AA personnel and managers; + review of written evidence of governance arrangements including strategic, policy and procedure documents; + direct engagement (via face to face interview) with PTTEP and PTTEP AA's personnel; and + liaison between the Technical Review and the Governance Review. a See the note in the Initial Report and Summary of Key Findings regarding 'best practice', provided at Enclosure 3. WWW.NOETICGROUP.COM PAGE 2 OF 73 IN -CONFIDENCE The scope of both independent reviews excluded: + consideration of issues with legal implications associated with the Montara incident and the outcomes of the Governance Review; + a review of the Commonwealth, State or Territory regulatory environments (including marine safety, offshore petroleum safety, environmental protection, etc); + a review of PTTEP activities outside of Australia, except where they had direct relevance to the governance of PTTEP AA; and + development of implementation plans for the recommendations or options provided by this Governance Review. WWW.NOETICGROUP.COM PAGE 3 OF 73 IN -CONFIDENCE 2 METHODOLOGY 0 Noetic applied a project management methodology to undertake the independent reviews. This provided for the phases of both the Governance Review and the Technical review to be undertaken both simultaneously, so that they would inform each other. The phases of the independent reviews are illustrated below in Figure 1. Each of the project phases is also outlined in the sections below. Figure 1. Illustration of the phases of the independent reviews. Stage 4 Stage 9- Stage 2: Stage 3: Analysis & Stag* $' Start-up8 Reviewof Direct Development Finetisation& Close 3cupiny Documenlstion Engagement ofiOptions� Presentafion of Report Report 2.1 Stage 1: Start Up and Scoping The independent reviews commenced with a meeting involving DRET's project team (including Project Sponsor and Project Manager) and Noetic's Review Team (Mr Peter Murphy, Mr Damien Victorsen, Ms Lex Drennan and Mr Peter Wilkinson). During the meeting, the project's scope, key roles and responsibilities, assumptions, risks deliverables and timelines were confirmed. Noetic also sought to identify and source relevant documentation for subsequent review and the full range of stakeholders and personnel for direct engagement. 2.2 Stage 2: Review of Documentation Noetic identified a number of preliminary documents for review prior to our direct engagement with PTTEP AA, those documents included: + Report on MCI, + transcripts of hearings held for the MCI, and + PTTEP AA's letter to DRET of 4 June 2010 and the attached Montara Action Plan. 2.3 Stage 3: Direct Engagement 2.3.1 Engagement with personnel Noetic engaged directly with PTTEP AA and PTTEP personnel and relevant contractors through semi -structured face to face interviews in two sessions. The first engagement session occurred between 27 and 30 September 2010 and the second engagement session occurred on 29 October 2010. The personnel engaged through both sessions are listed at Annex B. 2.3.2 Review of documentation During and following this engagement, Noetic sought to identify further documentation that would provide evidence of PTTEP AA's governance arrangements and operations. A full list of documents reviewed is at Annex C. • WWW.NOETICGROUP.COM PAGE 4 OF 73 IN -CONFIDENCE • • 2.4 Stage 4: Analysis This Report contains the outcomes of the analysis of findings and development of options following the review of documentation and engagement with PTTEP AA. As part of its first session of direct engagement with PTTEP AA, Noetic identified a number of headline findings. Summaries of these headline findings were provided verbally to PTTEP AA throughout the engagement process and are reflected in section 4.3. Following initial engagement with PTTEP AA on 27 to 30 September 2010, Noetic re-engaged with PTTEP AA in Perth on 29 October 2010 providing them with an opportunity to respond to the headline findings. Their response has been incorporated into the findings of this Report. Finally, section 5 identifies lessons for the Australian petroleum exploration and production from PTTEP AA's experience of the Montara Blowout and the findings of this Report. 2.5 Stage 5: Finalisation and Presentation of Report Noetic presented the draft Report to the DRET Executive on 26 November 2010. As part of the finalisation process DRET will provide PTTEP and PTTEP AA the draft Report for comment. WWW,NOETICGROUP.COM PAGE 5 OF 73 IN -CONFIDENCE 3 TECHNICAL REVIEW 3.1 Overview of Findings Noetic found PTTEP and PTTEP AA personnel to be cooperative, open and receptive to Noetic's enquiries, and accepting of the gaps identified. Noetic's impression was that PTTEP AA engaged suitably experienced personnel, both employees and contractors. We were informed that the PTTEP AA Safety, Security, Health and Environment (SSHE) team was to be further strengthened. PTTEP AA pointed out that their Montara Action Plan (4 June 2010) was produced in response to what they believed were the important issues likely to be raised in the Final MCI Report. These tended to be the more immediate causes of the Montara Blowout. Whilst the MCI Report, (in the context of this Technical Review) does refer to cultural or organisational failings on the part of PTTEP AA, these are not explicitly defined in safety management terms in the MCI Report itself. The original Montara Action Plan (4 June 2010) did not target a number of the organisational improvements needed. However, the revised Montara Action Plan (29 October 2010) does. Some of these organisational issues would probably have been addressed as a result of the planned integration of PTTEP AA into PTTEP. In particular, the planned SSHE integration plan was halted (now restarted) as a result of the pressures resulting from managing the Montara Blowout and subsequent MCI activities. PTTEP and PTTEP AA have in place (or plan to put in place) systems and processes, which represent good practice if effectively implemented, and which will make them comparable with other companies operating internationally in the upstream oil and gas industry. It will take a number of years to fully implement all the actions and receive the full benefits of the planned changes. However, it should be noted that as relatively few of the items in the Montara Action Plan, Revision 14 (29 October 2010) had been completed9, this Report is based principally on what we have been told PTTEP and PTTEP AA intended to do. This Report makes a number of recommendations on how DRET can monitor the implementation the Montara Action Plan(s) as it evolves and on the lessons for the industry resulting from this incident. 3.2 Detailed Findings This section of the Report presents the detailed findings on the gaps in the Montara Action Plan (4 June 2010) (first reported in Noetic's Initial Report and Key Issues Summary — see Enclosure 3); the response to these gaps by PTTEP and PTTEP AA (cross-referenced to the Montara Action Plan, 4 June 2010); and our analysis of the various documents supplied by PTTEP and PTTEP AA, including: 1. the original Montara Action Plan (4 June 2010); 2. amended Montara Action Plan, Revision 12 (30 September 2010); 3. amended Montara Action Plan, Revision 14 (29 October 2010); and 4. additional documents supplied by PTTEP AA. C] 'At 29 October 2010 eight of a total of 35 actions were complete, 20 were in progress, seven were to be done and 10 were behind target. Source: Montara Action Plan, Rev 14. WWW.NOETICGROUP.COM PAGE G OF 73 IN -CONFIDENCE 3.2.1 The original Montara Action Plan The original Montara Action Plan (4 June 2010) refers to the document submitted to DRET as an attachment to PTTEP AA's letter of 4 June 2010. This is the Action Plan we characterised in our initial review as 'necessary and important, but insufficient'. The Montara Action Plan (4 June 2010) identified a wide range of important improvements to PTTEP AA's standards, documents, competence arrangements and associated matters. Some organisational actions were also identified such as 'Demobilise... contracted drilling personnel...' (Item 7.1) and a review of the PTTEP AA organisation (Item 7.2). Noetic identified seven areas that were not clearly addressed in the Montara Action Plan (4 June 2010), which from our reading of the MCI Report and the evidence are important in preventing major incidents such as blowouts. They are all topics commonly regarded as good practice in safety management terms. The key deficiencies in the original Montara Action Plan (4 June 2010) were: 1. Leadership behaviours (in relation to the most senior PTTEP AA personnel) were not mentioned. 2. No changes to company policies and objectives were discussed, nor was there any mention of the development of suitable lagging and leading measures or key performance indicators (KPIs) to help PTTEP AA monitor progress with the improvements outlined in the Montara Action Plan(s). 3. The actions directed at improving the competency arrangements did not explicitly mention the training of • personnel (from the most senior to those on the front line) in major accident event (MAE) causation and the techniques of preventing MAEs above and not just risk assessment. 4. There was no mention of how the workforce would be actively involved in helping to shape and implement the planned changes. • 5. Whilst the Montara Action Plan (4 June 2010) referred to changes to the contracts entered into with third parties (Items 3.1 and 3.2), there was no discussion of the wider issue of improving communications within PTTEP AA and between PTTEP AA and contractors. The proposed methods to achieve effective teamwork between the various companies were also not examined. 6. It was unclear what performance monitoring arrangements would be put in place. In addition, the distinction between 'performance monitoring' (as carried out by line personnel such as managers and supervisors) and 'auditing' (as carried out by people with some independence of the organisation) was not discussed. Related to the concept of performance monitoring, the Montara Action Plan (4 June 2010) did not outline any proposed plans to carry out safety climate reviews or cultural surveys to monitor the implementation of the changes being contemplated. 7. The MCI Report found that communications with regulatory organisations were not always complete or accurate. There was no mention in the Montara Action Plan (4 June 2010) of how this would be addressed. The original Montara Action Plan (4 June 2010) was the subject of an Initial Report and Key Issues Summary (provided at Enclosure 3). Further details of these key issues and the approach to identifying them are in Appendix 1 and 2. WWW.NOETICGROUP.COM PAGE 7 OF 73 IN -CONFIDENCE 3.2.2 Amended Montara Action Plan (Revision 12) The amended Montara Action Plan (Montara Action Plan, Revision 12 was provided to Noetic during its first visit to Perth on the 28-30 September. The key difference from the original Montara Action Plan (4 June 2010) was that it had been updated in relation to progress against the identified actions. The original plan contained 35 actions. In addition, a further 75 actions were listed in Appendix 1 to this version under the heading of the 'AA Drilling Management System'. These additional 75 actions were identified as a result of a report PTTEP AA commissioned from the AGR Group, an international upstream company with subsea expertise ('AGR Report — Montara Well Incident, Report on Actions to Prevent Reoccurrence, Rev 1, 16/2/10). During Noetic's visit to Perth on 28-30 September, PTTEP AA provided the following information in relation to version 12 of the Montara Action Plan: Table 1. Status of Actions in Rev 12 of the Montara Action Plan 35 8 20 (10 behind target) 7 The original Montara Action Plan (4 June 2010) was prepared in response to the immediate technical issues identified during the MCI hearings and in draft MCI Report chapters provided to PTTEP AA. The original Montara Action Plan • was also a consolidation of pre-existing actions including those that arose from the PTTEP Internal Investigation Report and other internal reviews. The amended Montara Action Plan, Revision 12 was also prepared on this basis before the publication of the MCI Report and before Noetic had the opportunity to present our view of its deficiencies, (see Noetic's Initial Report and Key Issues Summary at Enclosure 3). Consequently, it was not surprising that this version of the Montara Action Plan did not address the broader organisational issues. However, during the discussion we became aware of a number of actions underway within the company, which did address some of these organisational issues, but had not been recorded in the Montara Action Plan. Because of this, it was difficult to determine if in aggregate the various actions satisfied the findings from the MCI, the underlying organisational issues and reasonable expectations of good practice. As a result of this, and in the light of the deficiencies Noetic identified during the initial desktop review, Noetic provided the following advice to PTTEP AA, both in Perth during the initial visit 28-30 September and again separately to Mr Andrew Jacob in Canberra on 30 October 2010: + review and update the Montara Action Plan, Revision 12 in the light of the seven safety management deficiencies identified in Noetic's Initial Report; + identify in the Montara Action Plan(s) those items which must be completed before drilling is started on Montara, in other words the 'critical actions'; and + prepare a document (or documents) in narrative form to explain the purpose and scope of the Montara Action Plan(s) and the governance arrangements for its implementation and how they fitted into the broader strategy for PTTEP AA in Australia. 0 Additional advice was given in relation to the Governance Review at Chapter 4 of this Report. WWW.NOETICGROUP.COM PAGE 8 OF 73 IN -CONFIDENCE Noetic's advice was accepted by PTTEP AA and our commentary on their response appears in the following sections . of our Report: + Amended Montara Action Plan (Revision 14); and + Additional Documents supplied by PTTEP AA. • 0 3.2.3 Amended Montara Action Plans During Noetic's second visit to PTTEP AA in Perth on 28 October, an amended version of the Montara Action Plan, (Revision 14) was tabled and provided to Noetic. This version included new action items to address the safety management deficiencies identified in Noetic's Initial Report and classifies (and marks in red) those action items, which they deem critical to complete prior to drilling on Montara. In addition, documents were tabled that place the Montara Action Plan in the broader organisational context — see Section 3.2.4.1 below. Following Noetic's visit on 28 October, Noetic was made aware of a further revised version of the Montara Action Plan (Rev 15, 2 November 2010) and during the Review process was provided with an opportunity to cite it. Noetic was not provided with a copy of the Montara Action Plan, Rev 15 (2 November 2010) at the time this report was written and therefore has not been able to fully consider it in the course of this Review. However, Noetic understands relatively minor changes were made between Revision 14 and Revision 15. Table 2 below provides a comparison of the changes, between Revision 12 and 14 of the Montara Action Plans. Table 2. A comparison of Montara Action Plan Rev 12 and Rev 14 (+ 20 new actions without an entry in the status column) In summary, the Montara Action Plan, Rev 14 (29 October 2010) retains all the original items and has an additional 20 items. These additional items largely appear to address the seven 'key issues' identified in our Initial Report and Summary of Key Issues (at Enclosure 3). The table below provides cross references between the Montara Action Plan (Revision 14) and the seven safety management issues described in the Initial Report. WWW.NOETICGROUP.COM PAGE 9 OF 73 IN -CONFIDENCE Table 3. The seven safety management issues identified in the 'Initial Report' cross-referenced with Montara Action Plan (Rev 14). 1. Leadership Behaviours Action 36 Corporate Lessons learned — item 1 'Demonstrate Top Management SSHE leadership and commitment'. 2. Policies and Objectives and No one Montara Action Plan This comment was made based on Lagging/leading KPIs Reference but see Action 49 reviewing the original Montara Action and the integration of PTTEP Plan (4 June 2010). Following AA into the PTTEP SSHE discussions, it is now apparent that Management System numerous Policies etc are being implemented in PTTEP AA (e.g. the SSHE Management Standard Revision 1 dated October 2008, which at section 6.1 refers to the need for assets to develop appropriate lead and lag KPIs). 3. MAE Causation Actions 52 and 53. 'Critical Actions' (Critical Actions are those identified as necessary to complete prior to starting drilling at Montara) 01 4. Workforce Involvement Action 48 5. Communications Action 57 A'Critical Action' 6. Performance Monitoring. Actions 42 and 43 Safety Climate or Culture Action 50 7. Communications with Regulators Action 15 and 54 This was described as an intent to engage with regulators 'over and above what was required by legislation'. (Andy Jacob 28 October 2010). Action 15 was in the original Action Plan. 3.2.4 Additional Documents supplied by PTTEP AA Noetic was provided with a wide range of documents by PTTEP (listed in Annex C). Noetic focussed its attention on the most important and relevant of these, including: + documents that sought to explain the purpose and scope of the Montara Action Plan and the governance arrangements for its implementation and how they fitted into the broader strategy for PTTEP AA in Australia; + documents that described the PTTEP SSHE system; and + Well Engineering Standards (D41-502433-FACCOM). 0 WWW,NOETICGROUP.COM PAGE 10 OF 73 IN -CONFIDENCE 3.2.4.1 DOCUMENTS WHICH EXPLAIN THE PURPOSE, SCOPE AND CONTEXT OF THE MONTARA ACTION PLAN During Noetic's visit in September to Perth, we noted that the Montara Action Plan lacked a narrative to explain where the work listed in the Plan 'sat' in relation to the broader organisational goals of PTTEP and PTTEP AA. During our visit to Perth on 28 October, we were provided with some additional documentation: + PTTEP AA Australia Strategy and Execution Plan, Draft A, dated 28 October 2010; and + PTTEP Montara Action Plan, Draft A dated 5 October 2010 ('Narrative document'). These documents are discussed in more detail in Chapter 4 of this Report (Governance Review). However, they are relevant to the Technical Review because taken together they articulate a link between the corporate (PTTEP) mission to the PTTEP AA strategy and the Montara Action Plan(s). The PTTEP AA Australia Strategy and Execution Plan describes the PTTEP mission as being to: '...reliably and safely deliver competitively priced oil and gas with responsibility to society and the environment, adhering to good corporate governance and financial discipline'. The Montara Action Plan narrative document amongst other things describes how the Montara Action Plan implementation will be overseen by the Montara Action Plan Steering Committee (MAPSC). The MAPSC membership includes the Bangkok -based Dr Somporn, Executive Vice President, International Assets Group as Chair as well as an advisor to the Chief Executive Officer of PTTEP. Annex E provides a full list of MAPSC members. The Montara Action Plan narrative document also lists the critical actions (in the Montara Action Plan, Rev 14) that must be completed prior to drilling at Montara. Noetic concludes from this document that the Montara Action Plan is being overseen by an appropriately senior level of management within PTTEP. 3.2.4.2 DOCUMENTS WHICH DESCRIBE THE SSHE SYSTEM The SSHE Management System is relevant because PTTEP are expecting that many of the improvements required in PTTEP AA will be addressed through the implementation of the PTTEP Corporate SSHE Management System by the Australian subsidiary. (See Montara Action Plan, Rev 14 action item 49). Noetic's approach to the SSHE Management System was to review the overall 'architecture' of the system and compare it with what is regarded as international good practice and then to sample a number of the important elements including: + SSHE Management System (Revision 1 October 2008); + Performance Management Standard (SSHE MS.S.12); + Asset Integrity Management Standard (SSHE MS.S.08, Revision 0, issued April 2009); and + Asset Routine Reporting (SSHE, MS.P.12-01, Revision 0, issued May 2009). SSHE Management System (Revision 1 October 2008) Noetic's review of the SSHE system shows that this is 'built' on well-known management principles including the International Association of Oil and Gas Producers (OGP) Guideline for the Application of Health, Safety and Environmental Management Systems (Report No 6, 36/210). Noetic concludes that the overall 'architecture' of the system is appropriate. WWW.NOETICGROUP.COM PAGE OF 73 IN -CONFIDENCE In addition, the SSHE Management System document makes clear the distinction between line management 'monitoring' and independent 'auditing'. As we commented in Noetic's Initial Report and Key Issues Summary (at Enclosure 3), this is not a semantic distinction. The MCI Report repeatedly finds non -compliances with PTTEP AA processes and procedures and that managers did not know of these non -compliances, which suggested weaknesses in the monitoring procedures within PTTEP AA. Performance Management (SSHE MS.S.12 Performance Management Standard). In Noetic's Initial Report and Key Issues Summary to RET, we stated: `It is not clear what performance monitoring arrangements are to be put in place. In addition it is not clear that the important difference between performance monitoring' activities as carried out by line personnel such as managers and supervisors compared with auditing by people with some independence of the organisation is recognised'. PTTEP AA's Performance Management Standard articulates the basic principles and practices of monitoring in general terms and refers to identifying '...procedures and practices... that are most critical to risk[s] control ... [and the need to] ... set priorities for and limit the scope of SSHE performance monitoring and measurement to focus on manageable number of indicators'. This is appropriate. However, the Asset Integrity Management Standard SSHE MS.S.08, in a section on 'Monitoring' refers to 'Audits/Management Review' as a type of 'Monitoring'. This suggests a lack of clarity around these concepts. When Noetic raised this issue in a meeting with PTTEP in late September 2010, they acknowledged this ambiguity and the importance of distinguishing 'monitoring' from 'audit'. Montara Action Plan, Revision 14 explicitly addressed this issue. In addition, the 'new' action items 42 and 43 (added after Noetic's meetings with PTTEP AA), are classified as 'critical actions'. Furthermore, in discussions with Andrew Jacob and David John, they acknowledged the value and importance of giving proper emphasis to line management monitoring. Asset Integrity (SSHE, MS.P.12-01, Revision 0, issued Date May 2009). PTTEP's Asset Integrity Standard, in common with the other PTTEP corporate level documents, is a high level document intended to be implemented by PTTEP AA's local management. Asset integrity, as the document explains on page 1 is, '...very much concerned with the identification, elimination or risk control of major accidents'. This document refers to major accidents as MAEs. In other words, asset integrity is specifically aimed at preventing incidents such as the Montara Blowout. It is a positive that PTTEP recognise the importance of asset integrity. A more detailed reading of the document suggests that the high level goals of an asset integrity program are appropriately described and the scope of the Asset Integrity Standard is described as applying '...over the whole lifecycle of all PTTEP facilities...in Thailand or internationally..' (page 1). We presume this cover drilling activities. This supposition was supported by the list of 'Critical Elements', which were identified in Appendix 1 to the Montara Action Plan(s) and includes blowout preventers (BOPs), well pressure control equipment and derricks and sub -structures. However, other aspects of the document give the feel that the Standard is more orientated to the lifecycle of production facilities as opposed to drilling. For example 'drilling' does not appear as a stage in an assets lifecycle in Appendix 2. Equally, Table 1 'Six Phases of the AIM Lifecycle (page 15) does not refer to drilling. As a result, Noetic concluded that it is not clear that this Standard applies to drilling activities. Mr Andrew Jacob in our meeting on 13 October 2010 in Canberra concurred with this conclusion. When this was raised with the Montara Action Plan coordinator (Mr David John), he said (in an email dated 13 October), that: is WWW.NOETICGROUP.COM PAGE 12 OF 73 IN -CONFIDENCE • 'There is no overall Al [Asset Integrity] system [in PTTEP AA] but some relevant documents exist — corrosion management standard and a risk based maintenance management'. It's one of the issues we would have raised in the BKK — AA SSHE MS Integration work that was interrupted by the blowout. We'll restart that in the near future'. Asset Routine Reporting Noetic commented to Mr David John that PTTEP's Asset Integrity Standard did not adequately define what was required to be reported. He responded that this was because it was (as previously mentioned) a high level document for implementation by local management. However, there is apparently no Asset Integrity Procedure equivalent to PTTEP's Asset Routine Reporting Procedure. The Asset Routine Reporting Procedure specifies in considerable detail what is to be reported and at what intervals. By contrast, PTTEP's Asset Integrity Standard only requires KPIs to be established at an asset level and reported on monthly. This is only a 'recommendation' in the Standard. This means that traditional personal safety related data is closely specified but reporting on major accident safety appears not to be so closely specified. If data on asset integrity is not clearly specified and reported, it is difficult to see how effective governance can be established over this important element of the SSHE. David John agreed that the Asset Integrity Standard needs improving and needs a supporting detailed procedure. 3.2.4.3 WELL ENGINEERING STANDARDS (D41-502433-FACCOM) This document was provided to Noetic during our visit to Perth on 28 October 2010. It is a draft document and is not formally endorsed. Although it is a draft, it was reviewed because it is a significant document in relation to the immediate causes of the Montara blowout as it sets out a proposed company policy on well barriers. The document sets out the intended policy in Section 5.3.2.1: All planned well operations will normally be executed under the protection of two independent barriers.... Should one barrier be lost then the focus of operations will divert to regaining the two -barrier status...'. It would appear that this is an appropriate standard, which should address the MCI recommendations on a minimum of two barriers. It should also be noted that at the time of our visit just two of the five critical actions identified in the Montara Action Plan, Rev 14 (29 October 2010) related to the Drilling Management System had been complete. WWW.NOETICGROUP.COM PAGE 13 OF 73 IN -CONFIDENCE 4 GOVERNANCE REVIEW 4.1 Definition of Governance For the purposes of the Governance Review, it was important to identify what 'governance' means and how'good' governance practices is identified. Noetic's approach (based on our experience and extensive research) is outlined below and is applied through this report. Governance The term 'governance' can take on a variety of meanings depending on the context in which it is applied. For the purposes of this Governance Review, Noetic examined the rules, relationships, systems and processes that determine how decisions are made and acted upon. Governance also incorporates the systems and processes an organisation uses to ensure that actions are in accordance with decisions and that decisions are in accordance with agreed rules. In this sense, governance is how an organisation maintains control over its decisions and actions. Good Governance Principles Whether an organisation's governance is 'good' can be determined by examining whether the governance arrangements reflect a set of 'effective governance principles that can be broadly categorised as follows: + Predictability. This is the degree of certainty that a process (such as a decision making process) will achieve an expected outcome. Predictability is increased by clearly defined rules and consistent application of rules or a process. If applied, this principle also achieves well defined rights and duties of staff, as well as mechanisms for enforcing rules and settling disputes. + Transparency. This element addresses the level of availability of information to stakeholders that may clarity of rules, decisions and outcomes. Transparent processes and decisions are ones that can be cross-examined by an outsider or auditor. Transparency also implies the lines of accountability and responsibilities are observable. + Accountability. This principle refers to the degree with which those with authority for decision -making are answerable to stakeholders or those from whom they derive their authority. This requires criteria by which to gauge performance of managers and oversight mechanisms to determine if expectations are being met. + Participation. This encompasses the ability of stakeholders and staff to influence activities10. Participation can occur via engagement with stakeholders and staff that may be able to influence the decision making processes, the decisions or the execution of actions. Each of these principles underpin the structure and function of all governance activities within an organisation. Good Governance Practices With the above principles of good governance in mind, an organisation will exhibit a number of good governance practices. These practices will be evident in the behaviour of personnel, the structure and functions of systems and the culture of a workforce. Some practices of good governance can include: + foundations for management and oversight are solid; + governance structures and bodies add value and are accountable to stakeholders; " Shailer, G. 2004. 'An Introduction to Corporate Governance in Australia'. Perason Education Australia, Canberra, ACT. WWW.NOETICGROUP.COM PAGE 14 OF 73 IN -CONFIDENCE • C7 + decisions are made in accordance with established processes, ethically and responsibly; to+ the decision making process is understood and can be interrogated; + integrity in financial reporting is safeguarded; + disclosure of information is timely and balanced; + shareholders' rights are respected and their views are heard; + risks are recognised and managed appropriately; + remuneration is provided fairly and responsibly; + resources are assigned according to priority; + documentation clearly records the governance arrangements, decision making process and outcomes, lines of accountability, responsibilities and timelines; and + the organisation's mission, vision, goals and strategies are clearly articulated, understood within the organisation, and influence everything the organisation does. 4.2 Montara Commission of Inquiry Summary of findings regarding PTTEP AA The MCI Report is 391 pages in length, containing 100 findings and 105 recommendations across six areas of focus. The MCI Report is heavily focussed on technical matters and only one sub -chapter" within the MCI Report deals with matters directly relevant to PTTEP AA's governance. This sub -section contains only two findings (finding 46 and 47) that are directly relevant to PTTEP AA's governance. These two findings are noted in Table 3. Table 3. Findings from the MCI Report that directly relate to PTTEP AA's governance. 46 PTTEP AA's internal governance structures post -acquisition were somewhat deficient: first, there was less committee oversight of important decisions, which is likely to have reduced the level of quality assurance; secondly, there was an attenuation in the lines of accountability when decision -making was located offshore in Bangkok. 47 Had more rigorous internal governance structures been in place it is possible that risks associate with the operations at Montara may have been identified and addressed. The MCI Report also contains a number of other findings that are relevant to PTTEP AA's governance, and they provide an indication of the adequacy of PTTEP AA's governance arrangements. One example is finding number 45, which points to deficiencies in PTTEP AA's competency management systems. This finding is indicative of broader failures in PTTEP AA's ability to identify and manage systemic issues. There are a range of others that reflect on management oversight, processes and procedures. "'Shortfalls in governance structures within PTTEP AA' (p.145) WWW.NOETICGROUP.COM PAGE 15 OF 73 IN -CONFIDENCE 4.3 Findings 0 This section presents an overall assessment, which discusses the sufficiency of PTTEP AA's Montara Action Plan (4 June 2010) and PTTEP AA's ability to articulate plans to address the systemic issues identified in the MIC Report. The remainder of this section discusses our findings within four themes, which are: + Governance Structures and Process, + Internal Processes, + Implementation of Change, and + Plans for the future. Some of the findings discussed in this section also relate to technical issues. These technical issues are discussed in this section as far as they relate to PTTEP AA's governance. Detailed discussion on the technical issues is in Chapter 3 of this Report. 4.3.1 Assessment of Montara Action Plan Noetic examined whether PTTEP AA's Montara Action Plan (4 June 2010) was adequate to address the findings contained in the MCI Report or whether it demonstrated PTTEP AA is or was demonstrating good governance practices. Our findings are presented in this sub -section. 4.3.1.1 ADEQUACY An organisation that has fully embraced and embedded the principles of good governance has established transparent auditing, monitoring and reporting systems that allow it to identify and recognise the systemic issues that led to a major incident (such as a Blowout). Such an organisation would also establish fully transparent lines of accountability that assign responsible personnel to appropriate actions. PTTEP AA's Montara Action Plan (4 June 2010) did not sufficiently demonstrate the company had fully embraced and embedded the principles of good governance in this way. The Montara Action Plan (4 June 2010) did not sufficiently address the full range of issues that are necessary to provide a high level of assurance that PTTEP AA is practicing good governance. Through its initial engagement with PTTEP AA Noetic was advised that the Montara Action Plan (4 June 2010) was never intended to address these systemic issues. It was during this process that PTTEP AA recognised that the Montara Action Plan also needed to address the systemic and organisational issues that contributed to the Montara Blowout. Building from this engagement PTTEP AA amended the original Montara Action Plan (4 June 2010) and produced an over -arching document that provides a strategic and historical context in relation to the actions following the Montara Blowout (the Montara Action Plan 'narrative document', Draft B, 2 November 2010) (refer Enclosure 412). This document included, as an attachment the Montara Action Plan, Rev 14 (29 October 2010), — provided at Enclosure 5. The Montara Action Plan, Rev 14 (29 October 2010) contains a comprehensive list of actions that, if implemented effectively, should address many of technical and organisational issues identified in the MCI Report. The amendments made by PTTEP AA to the Montara Action Plan provide a greater level of assurance that the company is making good progress and seeking to both meet and set good practice standards for the industry. �7j 12 The 'narrative document' Montara Action Plan, Draft B (2 November 2010) was provided to Noetic by PTTEP AA via email following our visit to Perth on 29 October 2010. WWW.NOETICGROUP.COM PAGE 16 OF 73 IN -CONFIDENCE • Chapter 3 of this Report explains in detail our finding that the Montara Action Plan (4 June 2010) contained the actions necessary to address the 'base' technical issues that lead directly to the Montara Blowout. Chapter 3 explains how the Montara Action Plan (4 June 2010) addressed issues such as well barrier integrity and drilling management identified in the MCI Report. However, the Montara Action Plan (4 June 2010) was insufficient in that it did not contain all the actions necessary to address the broader systemic and governance related issues that led to the Montara Blowout. In essence, it contained a series of technical point solutions. Systemic issues include organisational communication problems that meant technical issues were not recorded or reported. The scope of PTTEP AA's Montara Action Plan improved significantly during the course of the Governance Review. It now covers technical, governance and systemic/organisational issues and, if implemented effectively, should ensure PTTEP AA has addresses the findings and recommendations of the MCI. 4.3.1.2 SYSTEMIC MATTERS PTTEP AA's original Montara Action Plan (4 June 2010) was prepared for the purpose of addressing the technical failings identified by the Commission of Inquiry relating to the cause of the blow-out and in particular the drilling component. The Action Plan as such did not contain initiatives that would fully address the systemic and organisation - wide issues, However, PTTEP AA personnel were able to identify a number of initiatives, which were intended to address these issues to Noetic. Noetic also identified a number of initiatives underway or planned, which would address some of PTTEP AA's systemic issues. These initiatives can be divided into the three categories — Montara response initiatives, PTTEP —CRL integration initiatives, and PTTEP AA change initiatives. The majority of systemic/organisational issues within PTTEP AA were intended to be addressed in the PTTEP — CRL Implementation Plan13. Many of the initiatives in this plan were suspended following the Montara Blowout due to resources being dedicated to responding to the Montara Blowout and the MCI. However, work on the PTTEP — CRL Implementation Plan has resumed, as evidenced by the update Action Plan. Although plans to address some systemic issues identified by PTTEP AA personnel, PTTEP AA had not identified the relevance of these plans in respect of the MCI findings prior to engaging with Noetic. During Noetic's second round of engagement with PTTEP AA, there was clear evidence that PTTEP AA had recognised the importance of addressing systemic and governance issues. This was evident in the PTTEP Montara Action Plan (Draft A, dated 5 October 2010), which included the Montara Action Plan, Rev 14 (dated 29 October 2010). The PTTEP Montara Action Plan (Draft A, dated 5 October 2010) articulated the historical and strategic context for the list of actions contained within the Montara Action Plan, Rev 14 (dated 29 October 2010), which also includes most of the actions necessary to address systemic issues within PTTEP AA. t3 McKinsey & Co. for PTTEP, 2008. PTTEP — CRL Integration Plan. WWW.NOETICGROUP.COM PAGE 17 OF 73 IN -CONFIDENCE The progress PTTEP AA had made between the two rounds of engagement with Noetic demonstrates PTTEP AA's recognition, and articulation, of the need to address effectively the systemic and governance issues. PTTEP AA Montara Action Plan, Rev 14 (dated 29 October 2010) outlines actions that, through effective implementation will address systemic issues identified. 4.3.2 Governance Structures and Processes, and Relationships This sub -section discusses Noetic's findings that relate to PTTEP AA's governance structures and processes. It also addresses the adequacy of performance monitoring, leadership behaviours, and PTTEP AA's relationships with government. 4.3.2.1 PTTEP AA'S STRATEGIC PLANNING A mature corporate planning framework demonstrates explicit links between the strategic, operational and tactical levels of planning in an organisation. Mature corporate planning is essential for good governance as it reflects transparency and accountability; it also advances predictability and participation of the workforce in certain areas within an organisation (in particular, safety and health). A detailed description of the elements of an effective corporate planning framework is provided at Annex D. The maturity of an organisation's corporate planning framework has direct relevance to the effectiveness of its governance as it provides the mechanism by, which an organisation's mission, vision, goals and strategies are articulated and shared throughout the organisation. An illustration of this framework is provided below in Figure 2. A pyramid diagram is used to illustrate that the bottom level (sub -tasks) contains many specific items, whereas the top level contains only one very broad statement. Links is between each level should be explicitly described in planning and policy documentation. Explicit descriptions of the linkages provide clarity and context to personnel at all levels an organisation (executives, managers, employees and contractors) as well as external observers. • WWW.NOETICGROUP.COM PAGE 18 OF 73 IN -CONFIDENCE • �J During Noetic's initial round of engagement with PTTEP AA, gaps were identified within PTTEP AA's corporate planning framework that was consistent with the integration of CRL, into PTTEP not fully completed. Figure 2. Summary illustration of the corporate planning framework. -- •A ua;trntyn ,Y axd ";..I; nc F • M>r :M[M+aY xr r4rciv r M d.ar t ma ra: ai for ;N orPanl•�;im's r.luarca�. [!IC 6vwfrn Ou[ [N N�jtifarinn rrno;ac •� t!w• pwwit/ ai.Nwr.nn lu.,v up ivisxr. itir I.rlS a c�J...i •adw+..n1•. r/ vh+l rn nrC.nw.d�m wAi . m. In a,{w..r. M _ 11vn n. v�ZiOn ird rGH.{ANr at Ir�M1Unrt Goals •A Ww __n"A; Ix rrara..abw. •Lk-",br rawrrr orw'vtw to aUpM A:ef�Nnr.;w ew+: Strategies •►ra.6 r.par atlond rha nryia .r. N: a caMrnyrn ana Mr they wCC cm;tr ,u tv an vr.annaavn ; m to vn and nar'an. • q 11 a uhYA.Nt n to rnUrY Mt �ratr[r and W&a It, Initiatives/Fro rams .4, 'W.jvj rh. IV_0W rer FR 14 VIVA, in141itrMor irc>lranu V; r ,V,VIA. •kiwnrnwan �iw G.�n.l.,r[�/,.n row�.r..�r i.i V.an,! Tasks • u.�.ath,ouxwrn M;rtd�ra•ax ar rove trsm Sub -tasks •&Vk down J. dWd trL;,Mo n[Y1 164 WA, � • Typryh undrr[aasn a an ind�.iO�ai. Table 4 below provides an analysis of PTTEP AA's observed corporate planning activities against the framework depicted above. WWW.NOETICGROUP.COM IN -CONFIDENCE PAGE 19 OF 73 Table 4. Analysis of PTTEP AA's corporate planning framework. Strategic Vision + Defined for PTTEP and was published only on the PTTEP website. + A vision unique to PTTEP AA was not clearly identified. + A vision for PTTEP AA (potentially explaining how it contributes to PTTEP's vision) was yet to be identified. Mission + Defined for PTTEP and was published only on the PTTEP website. + A mission unique to PTTEP AA was yet to be identified. + A mission for PTTEP AA (potentially explaining how it contributes to PTTEP's mission) was yet to be identified. Values + Defined for PTTEP and was published only on the PTTEP website. + A statement that PTTEP AA adopts PTTEP's values or describing values unique to PTTEP AA was yet to be clearly identified. Objectives + Objectives/goals to achieve growth in Australia were identified in the PTTEP AA or Goals '5 Year Growth Plan'. However, the link between the objective/goal of growth in Australia and PTTEP's vision, mission and values was not explicit. + There was no description of how PTTEP's vision, mission or values will be implemented in PTTEP AA. + Health, safety and environment (HSE)-related objectives/goals were yet to be identified. Operational Strategies + Strategies and their links to objectives/ goals were not explicit or not identified. + No single source of guidance or summary of all initiatives underway at the tactical level could be identified. + Reporting lines and oversight bodies were not clearly documented for programs of work. Tactical Initiatives + Initiatives were evident in PTTEP AA's Montara Action Plan (4 June 2010) but there or was no clear articulation of how they relate to the corporate vision, mission, values or programs objectives/goals. of work + Other initiatives (such as the Integration Program) were identified but documentation examined did not clearly identify explicit links between those initiatives and the operational or strategic level. + While initiatives were suitably assigned to responsible personnel with due dates, critical dependencies were not clearly identified. Individual + Of the individual tasks identified in the documentation provided, tasks were suitably tasks assigned to individuals and due dates were applied. However, critical dependencies were not clearly identified. + There was no clear linkage between tasks and the relevant strategy or objective/ goal. r, is WWW.NOETICGROUP.COM PAGE 20 OF 73 IN -CONFIDENCE Sub -tasks + Of the individual sub -tasks identified in the documentation provided, tasks were suitably assigned to individuals and due dates were applied. However, critical dependencies were not clearly identified. + There was no apparent clear linkage between sub -tasks and the relevant strategy or objective/ goal. This analysis highlights that the linkages between each level of planning and implementation in PTTEP AA were lacking. This can result in: + executives and managers not understanding the full range of activities underway or planned; + implementation teams and individual employees not fully understanding the rationale for their work activities; + health and safety not being seen as valued by owners and management; + initiatives or programs of work occurring that do not contribute to the overall vision, mission and values of an organisation (i.e. unfocussed or unnecessary effort); + outside observers or stakeholders not understanding why certain activities are being planned or undertaken; + initiatives or programs of work that are in conflict with each other; and + failure to identify the appropriate strategies and initiatives/ programs of work necessary to achieve the whole of the overall vision, mission and/or all objectives/goals. During initial engagement with PTTEP AA, some of these issues were observed. For example, PTTEP's mission, as documented on its website14, stated that the company aimed to meet its responsibilities to society and the • environment. This implied the company's intentions to operate safely and therefore the need for its Security, Safety, Health and Environment (SSHE)-related strategies. However, the PTTEP Outlook and Strategic Plan for 2010-2014 did not contain adequate mention of SSHE issues. All other documentation initially provided by PTTEP AA, including the PTTEP AA 2010 and 5-year Work Plan also did not contain explicit SSHE strategies to explain the links between PTTEP's mission and the implementation of PTTEP AA's SSHE policies and procedures. This indicates that there may be a lack of awareness of SSHE issues at the operational level (refer Figure 2) of the organisation. Such a lack of awareness may have acted to limit the ability of PTTEP AA to effectively align and manage the range of SSHE activities with other operational aspects of the business. • Following its engagement with Noetic, PTTEP AA has more clearly articulated its intention to establish 'a robust framework to manage for results through clear strategy, defined paths, operations excellence and clear accountability and measures'. PTTEP AA through the Australian Strategy and Execution Plan has identified that its vision, mission and business objectives need to be linked explicitly to its systems, organisation, process and behaviour. The document also aims to provide a single integrated view of key initiatives and their linkages. The development of this document represents an enhancement in PTTEP AA's corporate planning framework. However, Noetic did express concern that SSHE-specific goals and strategies should be better identified in this document. PTTEP AA acknowledged this gap and satisfactorily addressed this matter in the following iteration of the Australian Strategy and Execution Plan. " About PTTEP(httn://www.otteo.com/en/aboutPttei)VisionAndMission.asox) last accessed 13 October 2010. WWW.NOETICGROUP.COM PAGE 21 OF 73 IN -CONFIDENCE The Australian Strategy and Execution Plan satisfactorily addresses the concerns identified in relation to PTTEP AA's corporate planning framework and its linkage with PTTEP more generally. 4.3.2.2 PTTEP AA'S CORPORATE GOVERNANCE STRUCTURES As part of the Review, Noetic focussed on two essential elements of governance structures that were identified by the MCI Report. These include corporate governance structures (in general) and health and safety governance structures. For an organisation to demonstrate that it is practicing good governance and able to operate safely, it must have in place appropriate and effective corporate and safety governance structures. This includes clarity of responsibility, that effective oversight is exercised from the Board through to the most junior manager, defined reporting processes and systems, and a feedback mechanism to ensure that all of this works as intended. Corporate Governance Prior to PTTEP acquiring CRL, corporate oversight structures were in place (such as the CRL Board's Risk Committee) 15. These structures dissolved when PTTEP AA was established and corporate oversight responsibilities were transferred to existing PTTEP committees (such as the PTTEP Board's Audit Committee and the Risk Management Committee's). The PTTEP HQ — PTTEP AA Working Relations document set out the relationship between PTTEP and PTTEP AA. This document did not provide clarity of responsibilities, there was no direct oversight of PTTEP AA's operations (including safety) and the guiding principle was one of autonomy. Since the Montara Blowout, PTTEP has recognised that its decision to allow PTTEP AA to operate with a high degree of autonomy was a flawed approach and has taken a more active role in PTTEP AA's governance. This is evident in increased oversight from PTTEP's Executive Vice President of International Assets Division (Mr Somporn Vongvuthipornchai) and increased reporting expectations. PTTEP's efforts to amend its approach to the governance of PTTEP AA are also evident in its amendments of the draft PTTEP HQ — PTTEP AA Working Relations document, which seek to increase corporate oversight of PTTEP AA. However, the amendments do not outline a set of governance arrangements that would conform to good practice nor is the document endorsed by the CEO of either the PTTEP AA or PTTEP or being acted upon by PTTEP AA personnel. While these preliminary steps taken to improve PTTEP AA's governance are commendable, PTTEP AA acknowledged that the PTTEP HQ — PTTEP AA Working Relations document should be finalised and endorsed as a priority to allow the governance relationships between PTTEP and PTTEP AA to be formalised. PTTEP AA subsequently advised that the governance arrangements between PTTEP AA and PTTEP would be finalised and in place by January 2011. In establishing its governance arrangements, Noetic suggested that PTTEP AA consider establishing a Safety, Health and Environment Advisory Board. While having no direct governance role it would support both PTTEP and PTTEP AA's formal framework by providing outside advice on matters of interest. The establishment of such an Advisory Board will support PTTEP AA's commitment to implementing and conforming to leading governance and technical practice. PTTEP established a structure to oversight of the implementation of the Action Plan, the Montara Action Plan Steering Committee (MAPSC). The primary role of the MAPSC is to oversee and coordinate actions arising from the Montara Blowout. The MAPSC has appropriate representation from both PTTEP and PTTEP AA senior personnel, and processes to support its role. Notably in reviewing the Official Minutes, Noetic found that the MAPSC has discussed and managed broader issues relating to PTTEP AA's corporate functions and operations, a clear indication of PTTEP's 41 'S This report makes no comment on the effectiveness of these structures apart from that they were in place and conformed to appropriate governance models. 16 As identified in PTTEP Organisation Structure (1 April 2010) available from http://www.pttei).com/en/aboutPttep Overview 2.aspx WWW.NOETICGROUP.COM PAGE 22 OF 73 IN -CONFIDENCE commitment to actively monitoring the activities of PTTEP AA and is an important component of establishing comprehensive and enduring governance arrangements. PTTEP AA has identified a clear strategy for establishing more robust and company appropriate governance arrangements (and accompanying documentation) by January 2011 Health and Safety Governance Robust HSE structures are a key element of an effective safety management system. Effective HSE structures allow for HSE issues to be escalated from site -specific SSHE committees to PTTEP's corporate level SSHE Committee and for the relevant Board committee to oversight this operation. This will ensure that senior managers are provided with the information they need to decide whether to intervene on site based issues, or support and assign resources to address company -wide SSHE issues. The governance arrangements should ensure the communication paths between SSHE committees are open and effective. This will include ensuring feedback is provided on the progress of actions required to address issues. The SSHE committee structure should allow site -specific SSHE committees to focus on workplace hazards and the control measures used to reduce risks. It should also allow corporate level SSHE committees to focus more on the highest risks across the business or business unit and the effectiveness of the processes put in place to reduce the likelihood of a major accident event (MAE). PTTEP AA did not have the appropriate SSHE governance structures in place at the time of the Montara Blowout. It did have site -based SSHE committees, which discussed SSHE issues at an operational level', with the information isdiscussed in these committees being communicated back to Perth head office via line management. However, there was no Perth -based SSHE coordination committee to ensure there was direct reporting of PTTEP AA -wide SSHE issues to PTTEP's Bangkok -based corporate SSHE Committee. This was not consistent with good HSE governance arrangements, with high-level risks across the Australian arm of the business not being fully identified and/or managed as effectively as they should have been. . Since the Montara Blowout, PTTEP AA has established a Perth -based SSHE18 Committee to ensure SSHE issues are communicated from sites to PTTEP AA and then to the PTTEP SSHE Committee in Bangkok19. This is an important initial step that will allow PTTEP AA to conform to good SSHE governance arrangements. PTTEP AA recognises that sustained effort is required to ensure the PTTEP AA SSHE Committee remains active, meaningful and relevant. Planned actions and efforts already undertaken to improve SSHE governance arrangements within PTTEP AA are consistent with industry practice. PTTEP AA recognises that sustained effort in implementation is required to ensure the PTTEP AA SSHE Committee remains active, meaningful and relevant. "Minutes of Monthly SSHE Review Meeting (1 April to 26 July 2010). No records prior to 1 April 2010 were provided. e PTTEP AA SSHE Committee Charter 9 Montara Action Plan, Rev 14 (29 October 2010). PTTEP AA SSHE Committee Charter (October 2010). WWW.NOETICGROUP.COM PAGE 23 OF 73 IN -CONFIDENCE 4.3.2.3 LAGGING AND LEADING INDICATORS Effective practice within the industry is for companies to have a balanced portfolio of leading and lagging performance indicators rather than rely purely on the traditional lagging indicators (such as lost time injuries or first aid cases). A wide variety of leading indicators are utilised in the oil and gas, and mining industries in order to gain greater insight into the performance of company systems and their implementation. Such indicators include: + hazards reported, + performance against HSE plans, + high potential incident frequency, + safety perception surveys, + incident actions closed out within time, and + management safety visit effectiveness. PTTEP's SSHE Plan Management Standard identifies example key performance indicators (KPIs) and annual targets for the corporate SSHE Plan including lagging and leading measures. A sample of example KPIs provided are summarised below in Table 5. Table 5. Sample of example KPIs provided in PTTEP's SSHE Plan Management Standard. Lost time injury frequency Revision of SSHE management standard Total Recordable incident rate SSHE Plan standard Restricted work day case Revisions of SSHE training and competence • Medical treatment case Revision of loss prevention and risk management standard Hydrocarbon releases/ spill Revision of asset integrity management Flare/ emissions Revision of performance management and behavioural based safety standards and revision of incident management standard Fire Revision of audit and review standard Major production loss or property Closeout of corrective actions from audits, reviews and inspections and damage incident investigations High potential incidents Management visits (qualify of visits) Vehicle/ transport incidents Revision of guidelines for minimum SSHE management standard for international assets. The list above and the full list of example KPIs provide in the SSHE Plan Management Standard represent an appropriate and comprehensive list of both leading and lagging indicators. Noetic was advised that PTTEP AA was in the process of contracting expert advisors to undertake a Management System Development and Implementation project, which was intended to develop and deliver Management System and Communication including 'design of management team score cards and performance monitoring mechanism"20. This project also sought to: 0 20 Email from David John received 2 November 2010, subject: 'RE: project addressing lead/lag indicators'. WWW.NOETICGROUP.COM PAGE 24 OF 73 IN -CONFIDENCE + define KPIs at the management level and address all relevant risks and performance metrics, and + align KPIs with roles, accountabilities and job descriptions. The Management System Development and Implementation project was not yet finalised in scope and confirmed. The effective implementation of the Management System Development and Implementation project will likely ensure that the SSHE Plan Management Standard is fully incorporated within PTTEP AA. The Management System Development and Implementation project should ensure that the adequate implementation of the intent of the SSHE Plan Management Standard within PTTEP AA, with PTTEP AA establishing and implementing appropriate leading and lagging performance indicators. 4.3.2.4 PERFORMANCE MONITORING Auditing and performance monitoring are key activities within an organisation by ensuring that responsible personnel are accountable for their decisions and actions. If administered effectively, auditing and performance monitoring provide a level of assurance that decisions are in accordance with guidance and priorities, and that decisions are and have been acted upon appropriately. Effective performance monitoring and auditing is essential to good governance. For the purposes of this report, 'performance monitoring' refers to the regular activities (both formal and informal) undertaken by managers to determine if process, people and technology are behaving or functioning as expected. It is an ongoing activity that should be conducted on a regular basis by managers at all levels of an organisation. Performance monitoring checks that'what should be happening, is happening' in accordance with documented policies and procedures. Executives should be involved in performance monitoring to ensure that critical activities are conducted thoroughly and that all relevant information is captured. Auditing is a discrete activity of evaluation that may occur at set points — it is a separate activity to performance monitoring (although the two are often as confused as the same thing). Audits should occur with a degree of independence, ideally conducted by someone outside the direct operating line. Auditing is retrospective, more passive and is useful for learning lessons from past events. Audits check 'what should have happened, did happen' in accordance with documented policies and procedures. In the case of PTTEP AA, Noetic identified a number of'audit' type activities, which were designed to evaluate the past performance of the organisation and identify lessons to learn. Examples from the Montara Action Plan (4 June 2010) included an 'independent review of the Well Construction Management Framework (WCMF) and Well Control Standard (WCS)'21 and 'Develop and conduct plan of corporate technical and SSHE Management system audits, 22. Another example included the Montara Audit Program23, which identifies the need for a Drilling Start-up Audit and a drilling and SSHE Compliance Audit. PTTEP's Performance Management Standard24 provided the corporate policy describing how performance monitoring should be directed and implemented across PTTEP's assets (including PTTEP AA). It provided guidance on leadership, pro -active monitoring (to prevent incidents) and reactive monitoring (which occurs following incidents). However, the standard was focussed heavily on the collection and documentation of monitoring of data. It provided relatively less emphasis on the need for face to face 'active monitoring' to ensure both personal safety and process . 21 Montara Action Plan, Rev 12 Draft, 21/9/2010, item 2.1. 22 Montara Action Plan, Rev 12 Draft, 21/9/2010, item 8.2. 21 Montara Audit Program, Rev 1 9/9/2010. 24 PTTEP, 2009. Safety, Security, Health and Environment (SSHE) Performance Management Standard (SHEE MS. S.12). WWW.NOETICGROUP.COM PAGE 25 OF 73 IN -CONFIDENCE safety. PTTEP's Behavior -Based Safety (BBS) Standard25 indicated the need for face to face 'active monitoring' via an observation and feedback process. However, the BBS Standard makes no mention of how senior executives will be involved in actively monitoring. Despite these three standards providing guidance to auditing, monitoring and behaviour based safety; there was inadequate mention in the documentation of the need for both senior and middle levels of management to be actively engaged in active monitoring at an operational level. This represented a gap in PTTEP AA's implementation of a culture of transparency and openness in respect to monitoring of its safety processes, including process safety and asset integrity. PTTEP AA has recognised these shortfalls and has identified actions within its Montara Action Plan, Rev 14 (29 October 2010) as part of the Supplementary Actions. Relevant actions identified include defining auditing and monitoring philosophy, and establishing PTTEP AA -wide audit plans and monitoring programs. These are important improvements to PTTEP AA's original Montara Action Plan (4 June 2010) and, through effective implementation, should address issues surrounding auditing and performance monitoring within the company. PTTEP AA should consider incorporating additional actions in relation to ensure that senior executives within PTTEP and PTTEP AA clearly understand the distinction between auditing and performance monitoring. The actions identified in the Montara Action Plan, Rev 14 (29 October 2010), Supplementary Actions in relation to integrating within the organisation an audit and monitoring philosophy and the establishment of effective audit plans and monitoring programs, reflect good practice governance arrangements. 4.3.2.5 LEADERSHIP BEHAVIOURS • Appropriate and visible leadership behaviours reflect that an organisation has embraced transparency and participation as principles of its governance. In these organisations, leaders are seen to both demonstrate and actively promulgate behaviours that achieve the organisation's vision, missions, objectives and strategies. The MCI report identified that there was an absence of '...robust supervision and compliance monitoring within PTTEP AA'. This lack of active monitoring by management is evident in both the transcripts of the MCI and the MCI Report. PTTEP AA's original Montara Action Plan (4 June 2010) did not contain any actions that directly sought to address leadership behaviours within the company. However, PTTEP AA is undertaking development of its competency assurance framework for drilling and engineering businesses. This project is being undertaken by expert advisors and covers the following areas: + development of a competency management system (CMS) design summary; + capability planning; + evaluation of competency management system; + development of tools and competency action planning; and + evaluation of recruitment. This project may also address some of the issues associated with the competency of PTTEP AA's senior managers by identifying appropriate competencies and competency standards. However, the project may not fully address all aspects of leadership behaviour that support good governance. There is also no stated intention for the project to lead • " PTTEP, 2009. Safety, Security, Health and Environment (SHEE) Behavior -Based Safety (SSHE MS. S.13). Revision 0. WWW.NOETICGROUP.COM PAGE 26 OF 73 IN -CONFIDENCE to substantial strengthening of PTTEP AA's leadership to ensure they promulgate and promote the appropriate management, operational and safety behaviours. WhilePTTEP AA's CMS project has the potential to improve the behaviour and strength of PTTEP AA's leadership, the success of the project in achieving this objective can only be determined by review of its implementation. Effective promulgation and promotion of the appropriate management, operational and safety behaviours throughout PTTEP AA will be a key factor in the success of the CMS project. 4.3.2.6 MANAGEMENT OF RELATIONSHIPS WITH GOVERNMENT ORGANISATIONS The health of an organisation's relationships with external bodies is reflective of how effectively the organisation has embraced transparency into its ethos. Transparency is evident in a willingness to engage and provide the appropriate information in a timely manner to those who request it. This is especially true for a regulated organisation's relationship with its government regulators. Inadequacies in PTTEP AA's relationship with government organisations were noted in the MCI Report. If these relationships are inadequate, it could impact on the ability of PTTEP AA to understand and comply with all relevant legislation and regulations or achieve practical solutions that satisfy the regulators should issues arise. However, during engagement with Noetic, PTTEP AA personnel did not appear to be aware of the MCI's concerns about their relationships with government bodies. PTTEP AA also provided anecdotal evidence they had positive experiences and formed good relationships when engaging with both state and federal government agencies. Noetic's experience with PTTEP AA personnel was also positive, which supports their claims. • However, Noetic's engagement was limited to PTTEP AA's personnel based in Perth and did not include field -based operational personnel who were engaged with government representatives during the MCI. These operational personnel had been demobilised following the MCI and were unavailable to Noetic. There was also no evidence presented that would allow Noetic to determine if PTTEP AA's operational personnel shared the same receptive and cooperative working ethic with Perth -based management. Similarly, there was no evidence of any effort by PTTEP AA to ensure effective working relationships with government at the operational level. This leaves open the possibility that relationships between the operational level of PTTEP AA and government organisations may be lacking. However, it must be recognised that effective relationships can only be built by active engagement from both parties. Therefore, both PTTEP AA and its regulators must engage actively to address any relationship issues. • Noetic advised PTTEP AA that it should act to address the possibility by ensuring appropriate strategies are identified and initiatives are in place to ensure they engage actively with its regulators. PTTEP AA has responded by identifying the need to 'engage with regulators above the legal requirement' in its amended Montara Action Plan, Rev 14 (29 October 2010)26. This initiative should ensure good working relationships between PTTEP and its regulators. PTTEP AA's response to improving relationships with government regulators is appropriate. 4.3.3 Internal Environment This sub -section of this Report deals with aspects internal to PTTEP AA and how they reflect the company's ability to apply the principles of good governance. Specifically, this sub -section examines whether PTTEP AA's governance " Item 54 of the Montara Action Plan, Rev 14 (29 October 2010). WWW,NOETICGROUP.COM PAGE 27 OF 73 IN -CONFIDENCE practices have resulted in adequate workforce participation, whether PTTEP AA has taken adequate steps to monitor its workforce culture, and whether internal communications will be effective. 4.3.3.1 WORKFORCE PARTICIPATION Participation is a key principle of good governance that, if embedded effectively in an organisation, will ensure that all parts of an organisation are actively pursuing the organisations vision, mission, goals and strategies. Effective participation is essential to ensure management decisions are implemented effectively and is a hallmark of good industry practice in all resource industries. This is especially true for the implementation of health and safety policies and procedures, where management and the workforce hold joint responsibilities for ensuring the health and safety of a workplace. Active workforce participation in change processes, as well as active monitoring regimes, is a key feature advocated in safety and risk -related literature27 and is an important part of the Safety Case regime. Effective workforce participation will be especially crucial for PTTEP AA during its planned rapid expansion leading up to the re -commencement of drilling operations in April 201128. PTTEP AA will need to ensure its workforce is actively engaged in implementing its ambitious plans for growth as well as implementing its quality and safety control procedures. Despite the importance of workforce participation to the success of the change planned for PTTEP AA, Noetic notes that the strategies identified by PTTEP AA that aim to target effective workforce participation could be further enhanced. Noetic advised PTTEP AA of this, and highlighted that improved workforce participation as a corporate strategy would ensure a smoother change management transition in procedures and plans being followed and implemented. The strategies identified by PTTEP AA that aim to target effective workforce participation could be enhanced further. • 4.3.3.2 SAFETY CLIMATE AND CULTURE In addition to ensuring effective participation among its workforce, an organisation must ensure transparency by effectively monitoring the culture and climate of its workforce and workplace. It is especially important for an organisation to monitor its safety culture to determine if its workforce is actively engaged in safety practices. Safety climate and culture are characteristics of an organisation that can affect its ability to achieve its safety standards29. They can provide indicators of workforce attitudes and potentially the inter- and intra-team communications issues mentioned in the next section. PTTEP had recognised the value of actively monitoring its safety climate and culture via surveys in its Behavior -Based Safety Standard30 where had identified the need for 'periodic SHEE climate/ culture surveys'. However, the Montara Action Plan (4 June) did not identify the need for a safety climate or culture survey in response to the MCI. This may have occurred because the application of the Behavior -Based Safety Standard to PTTEP AA had been slowed or suspended, along with other integration initiatives, while PTTEP AA responded to the Montara Blowout and the MCI. Since then, PTTEP AA has recognised the specific need for a safety climate survey (item 50) in the Montare Action Plan, Rev 14 (2 November 2010). 2' See 'Safety, Culture and Risk: The organizational causes of disasters' by Andrew Hopkins. 28 As indicated in discussion, presentations provided by PTTEP AA personnel and the 'PTTEP AA 2010 and 5-Year Work Plan'. 2' Hopkins, A, 2005. Safety Culture and Risk: The Organisational Causes of Disasters. p.3 30 PTTEP, 2009. Safety, Security, Health and Environment (SHEE) Behaviour -Based Safety (SSHE MS. S.13). Revision 0. WWW.NOETICGROUP.COM PAGE 28 OF 73 IN -CONFIDENCE The actions identified in the Montara Action Plan, Supplementary Actions, Rev 14, 29 October 2010, identify the need for SSHE improvements including the need to undertake a Safety Climate Survey (item 50). This provides evidence that the Behaviour -Based Safety Standard is being applied across PTTEP AA as part of the CRL - PTTEP integration program. 4.3.3.3 INTER AND INTRA-TEAM COMMUNICATION Effective communications within an organisation demonstrate that it has embraced and embedded both transparency and participation as principles of good governance in an organisation. Effective communications lead to the flow of essential information to and from individuals and within and between work teams. It also reflects an organisation's commitment to reducing information 'silos' and protective behaviours that hinder the achievement of common goals. The MCI Report identifies problems caused by poor communications between teams and individuals as a key factor that led to technical issues not being reported both on -rig and on -shore. One PTTEP AA staff member, who indicated PTTEP AA had inherited an 'aggressive' culture from CRL, validated the MCI Report's findings. His testimony was that this 'aggressive' culture had discouraged individuals from questioning decision making and reporting potential problems. This had resulted in a culture where communication within and between teams was hindered. Despite this admission from its personnel, the original Montara Action Plan (4 June 2010) did not identify initiatives specifically aimed at addressing this cultural issue. In recognition of this gap, PTTEP AA has identified 'communication and teamwork' as a key element that will need to be considered by the MAPSC in determining whether PTTEP AA should re -commence its drilling program in April • 2011. PTTEP AA also identified the need to conduct a review of 'communications processes' in its Montara Action Plan, Rev 14 (29 November 2010) (item 36). These initiatives, should allow PTTEP AA to improve communications within and between teams within the company. The actions identified in the Montara Action Plan, Supplementary Actions, Rev 14, 29 October 2010, through effective implementation, should improve communications within and between teams within the company. 4.3.4 Implementing sustainable change This sub -section of this Report deals with PTTEP AA's ability to implement long term, sustainable change across the organisation. In this sub -section, we examine whether PTTEP AA has develop the appropriate guidance for change, whether the lines of reporting for change are clear, and whether coordination of change is adequate and comprehensively managed. 4.3.4.1 A SINGLE SOURCE OF GUIDANCE FOR CHANGE A key aspect of good governance is the existence of clearly identified, integrated and authoritative guidance from an organisation's executive decision makers. This guidance may include a strategic statement, policy documents or plans that guide both actions and subordinate deliberations. During Noetic's first engagement, PTTEP AA provided a number of documents that described all the change initiatives underway. These documents identified a number of change initiatives that were either planned or underway within one of the following three categories: + Montara response initiatives: initiatives planned or underway in response to the Montara Blowout (as documented in the Montara Action Plan (4 June 2010). WWW.NOETICGROUP.COM PAGE 29 OF 73 IN -CONFIDENCE + PTTEP — CRL Integration initiatives: actions planned or underway under the auspice of the PTTEP — CRL Integration program (as documented in the PTTEP — CRL Integration Plan and other documents). + PTTEP AA change initiatives: actions planned or underway under the direction of PTTEP AA (such as the development of the Competency Management System). With the exception of the Montara response initiatives, a number of documents were provided within each category. This meant there was no single document that collated all the initiatives planned or underway. PTTEP AA recognised that the absence of such a consolidated change planning or management document was not good practice. Noetic provided PTTEP AA with an illustration of the concept of how the various initiative and plans underway in PTTEP and PTTEP AA could be brought together into a consolidated change management plan (CCMP) (refer Figure 3) Figure 3. Conceptual illustration of the elements of a consolidated change management plan. • Based on its discussions with Noetic, PTTEP AA strengthened its Australia Strategy and Execution Plan, which drew links between each level of planning and activity within the company. The Australia Strategy and Execution Plan identifies the vision, mission and headline goals and strategies for the company. This provides confidence that PTTEP AA will continue to enhance its ability to integrate its activities. The Australia Strategy and Execution Plan provides confidence that PTTEP AA will continue to enhance its ability to integrate its activities. • WWW.NOETICGROUP.COM PAGE 30 OF 73 IN -CONFIDENCE 4.3.4.2 CHANGE MANAGEMENT • Comprehensive and effectively coordinated management of change is observed in organisations that have good governance processes in place. This is because necessary parts of the organisation are involved in planning and implementation, roles are clearly defined and all aspects of change are identified. Importantly the vision, strategies and required actions for change are typically articulated in an overarching document. PTTEP AA had indicated it was undertaking a substantial program of change and growth. These plans for growth are explored in the next section but can be summarised as substantial. This growth will occur at a time when the company is undertaking a significant integration program as well as directing resources to recover from the Montara Blowout, and respond to the outcomes of the MCI. Given the scale and complexity of the exploration and production growth plans, combined with the organisational change occurring in PTTEP AA, it will be important for the company to develop and implement a comprehensive change management plan. PTTEP AA's change management plan should examine all elements of the organisation that will require change, including its people, processes and technology. Such a plan should be strongly overseen by individuals or governance bodies with real powers to make decisions and real accountabilities to stakeholders. PTTEP AA was aware that without a comprehensive change plan, identifying all the change initiatives underway or planned, it would make it difficult for both PTTEP and PTTEP AA's management to gain and maintain a full appreciation of the effort and resources required to achieve the company's ambitions. In addressing change management, PTTEP AA developed the Montara Action Plan, Draft 8 (2 November 2010), which provides the context for the full suite of change initiatives underway across PTTEP AA, while the attached Montara Action Plan, Rev 14 (29 October 2010) provides a comprehensive list of change actions. These documents, when combined with the Australia isStrategy and Execution Plan, adequately identify the full spectrum of changes required to personnel, systems and technology. They contain information relevant to all parts of PTTEP AA's business. The Montara Action Plan, Draft 8 (2 November 2010); the Montara Action Plan, Rev 14 (29 October 2010) combined with the Australia Strategy and Execution Plan are comprehensive and adequately identify the full spectrum of changes required and contain information that is relevant to all parts of PTTEP AA's business. 4.3.6 PTTEP AA's Future Plans This final sub -section of Noetic's findings relates specifically to PTTEP AA's plans for growth over the next 5 years. This section discusses the implications for these growth plans on PTTEP AA's ability to operate safety in Australia. 4.3.5.1 PTTEP AA'S GROWTH PLANS An organisation that demonstrates good governance has the structures and processes in place that ensure management fully understands the scope and scale of future plans under consideration. This will mean that growth plans should consider implications for the organisation's people, systems/ business processes and technology/ hardware. PTTEP AA has a significant growth program in Australia over the next five years that includes: + finalisation of the re -commissioning of Montara oil field operations; + enhancement and modernisation of current permits; + safely and economically decommissioning of Challis and Jabiru oil fields; • + enhance PTTEP AA's ability to explore, develop and sanction projects; and + aligning Australia's growth strategy to ensure it is better able to achieve PTTEP's 2020 production targets. WWW.NOETICGROUP.COM PAGE 31 OF 73 IN -CONFIDENCE The 'PTTEP AA 2010 and 5-year Work Plan'31 provides substantial detail on how these production and commercial targets will be reached. Additional documentation details drilling schedules, (hydrocarbon) resource strategies and risk assessments. PTTEP AA's growth plans within Australia represent additional challenges that are generated by the need to incorporate large numbers of personnel into a changing organisation. These challenges, while potentially posing a risk to PTTEP AA's ability to meet its five-year work plan can be managed through comprehensive and mature governance arrangements. PTTEP AA has demonstrated it is committed to long-term operation within Australia. The growth plans that PTTEP AA has identified for the next five years can be successfully realised through the successful implementation of the Montara Action Plan, Rev 14 (29 October 2010) and the Australia Strategy and Execution Plan Action Plan and other integration plans that have been noted in this report. • "Memorandum #154527 from PTTEP AA CEO on 9 September 2010. WWW.NOETICGROUP.COM PAGE 32 OF 73 IN -CONFIDENCE • 4.4 Analysis of Findings The Governance Review has found that PTTEP AA has identified the point solutions necessary to address the technical issues that led to the Montara Blowout. These point solutions, which address problems with well barrier integrity and drilling management systems, are identified in PTTEP AA's Montara Action Plan (4 June 2010). The Montara Action Plan (4 June 2010) also identified point solutions that address problems in PTTEP AA's contracts and document management, industry liaison, organisation and personnel, training and competence and environmental management standards and corporate oversight/ lessons learned. However, these point solutions did not identify how they contributed to PTTEP AA's broader vision, mission, objectives and strategies. The Montara Action Plan (4 June 2010) did not recognise the importance of ensuring the governance relationship between PTTEP and PTTEP AA was explicitly clear. During its engagement with Noetic, PTTEP AA was able to identify a series of change initiatives that will address some of the organisational issues highlighted in the MCI Report. These initiatives were described in the PTTEP — CRL Integration Plan, and in other improvement plans underway within PTTEP AA. However, the linkage between these change initiatives and how they contributed to PTTEP AA's overall vision was unclear. In addition there was no single document that had been prepared that linked together all of these change initiatives (including the initiatives within the Montara Action Plan (4 June 2010)). Subsequent to its formal engagement with Noetic, and PTTEP AA has developed plans to address these deficiencies. In this regard, Noetic can advise that PTTEP AA has amended its Montara Action Plan and recognised the importance and priority in clarifying its corporate governance and planning frameworks. PTTEP AA has also consolidated its plans • into a single change management document, which tie together all change initiatives, and their strategic context. These changes provide Noetic with confidence that PTTEP AA has a comprehensive plan to achieve a governance framework consistent with good industry practice. However, plans are only valuable if implemented successfully. All of PTTEP AA's planned improvements will take time to implement. The quality of the implementation will determine the effectiveness of the measures. Consequently, Noetic believes that there remains a need for the Australian Government to monitor implementation of these improvements before it can be fully assured that PTTEP AA will operate safely and responsibility in the future. WWW.NOETICGROUP.COM PAGE 33 OF 73 IN -CONFIDENCE 5 LESSONS FOR INDUSTRY In addition to the specific findings and recommendations made regarding PTTEP AA, Noetic has identified a series of lessons arising from the Montara incident that potentially have relevance to the oil and gas industry. The lessons address themes within the acquisition and integration of production assets; and governance and oversight. The literature on MAEs suggests that although each MAE is different in relation to the detail of their causation, they exhibit similar characteristics. Dr Tony Barrell, formerly Chief Executive Officer of the UK Health and Safety Executive's Offshore Safety Division, who led the development of the regulatory response to the 1988 Piper Alpha disaster, has observed: '...there is an awful sameness about these incidents... they are nearly always characterised by lack of forethought and lack of analysis and nearly always the problem comes down to poor management, it is not just due to one particular person not following a procedure or doing something wrong..,.32 Noetic believes that the Montara incident shares underlying (and organisational) causes similar to other MAEs. Consequently, we believe that there are few, if any, completely new lessons except perhaps at the detailed level. Given the large number of detailed findings and recommendations in the MCI Report, we have consciously chosen to 0 focus on a smaller number of high level points (or '...overarching actions and activities..'.). We also recognise that the recommendations from the various official inquiries underway in the United States of America into the Macondo Blowout in the Gulf of Mexico will most likely have an important influence on offshore petroleum safety globally and not • just Australia. We believe there are seven main recommendations that arise from this review's findings and conclusions: + Ensure MAE education is available for leaders and managers in the offshore petroleum industry (including MAE prevention and management techniques). + Provide guidance to leaders and managers on effective 'performance monitoring' versus auditing strategies and techniques. + Provide incident information quickly to the industry and its workforce as soon as is practicable after an incident has occurred on what has happened. + Increase the reporting and communication of high potential or significant incidents and near misses so that the lessons learnt can be applied by others before major incidents occur. + Review the training courses available for personnel making judgments on the safety of well operations to ascertain whether they provide sufficient theoretical and practical knowledge to ensure safe operations. + Ensure mergers and acquisitions are undertaken thoroughly with adequate due diligence processes and integration of acquisitions. + Ensure the integration health, safety and environment into corporate -level planning. . 32 'Spiral to Disaster'. BBC Television. WWW.NOETICGROUP.COM PAGE 34 OF 73 IN -CONFIDENCE + Improving governance and oversight in the industry by highlighting the benefits of advisory boards. These recommendations will now be expanded upon in order. 5.1 MAE education for leaders and managers The offshore oil and gas industry has made impressive improvements in 'personal' safety. However, the techniques for managing 'personal' safety, such as behavioural safety techniques and the typical metrics used, such as lagging measures of injury rates, are not relevant to MAEs. These two distinct types of 'safety' require preventive strategies with differing emphases. MAE prevention requires an explicit focus on the management systems, leadership behaviours and culture of the organisation. This is because prevention depends on much more than the acts or omission of one person and requires significant managerial and leadership attention to focus on MAE prevention. It also presupposes that the senior leaders of the organisation are familiar with the distinction between personal safety and major accident events and the techniques for the prevention of MAEs. DRET should work with industry and the Australian Petroleum Production and Exploration Association (APPEA) to develop programs to ensure greater understanding of MAE include causes, prevention and management. • 5.2 Performance monitoring and auditing This Report identified that there was an apparent lack of understanding between active performance monitoring and auditing within PTTEP AA. This lack of clarity in the organisation's policies may stem from a lack of understanding among senior executive personnel. In Noetic's experience the term 'audit' is often used to mean 'monitoring,' in the petroleum exploration and production industry. This is an inaccurate use of the term in the context of health, safety and environment management systems. Auditing is generally defined as a checking process by people who are (to a greater or lesser extent) independent of the facility, location or process being checked. 'Monitoring' or 'Performance Monitoring' is the process of line personnel routinely checking that their subordinates are effectively implementing the specified policies, procedures and risk controls. This is not an academic distinction. If this lack of clarity is common within the petroleum exploration and production industry, it may be leading to an inadequate emphasis on active (and therefore effective) performance monitoring. The widespread understanding of the importance of active monitoring at all levels of an organisation would appear to be critical to minimising the likelihood of MAE. 'Monitoring' or 'Performance monitoring' is a feature of all credible management systems not just in connection with health, safety and environment management systems and is a feature of the safety management models set out in the IADC HSE Guidelines, the Chevron Operational Excellence Management System, and by regulators. It is therefore recommended that DRET work with industry and APPEA to ensure that the strategies and techniques of performance . monitoring are well understood. WWW.NOETICGROUP.COM PAGE 35 OF 73 IN -CONFIDENCE DRET should work with APPEA and other industry bodies to ensure senior executives in the industry clearly understand the distinction between auditing and performance monitoring. 5.3 Providing incident information quickly Until the release of the MCI Report on 24 November 2010, there was no authoritative source of information on the Montara Blowout for almost 12 months (apart from the transcripts of evidence). This period seems too long to allow for the industry promptly identify lessons and develop a response. While legal liability may be cited by regulators and companies as a reason for not publishing material earlier, efforts need to be made to ensure information is made available in a more timely manner. DRET should work with the industry to identify mechanism to publish factual reports as soon as possible after an incident to assist others engaged in similar activities or using similar equipment to avoid an incident. 5.4 Increase the reporting of high potential or significant incidents There is a need to ensure that significant incidents related to MAEs, such as the failure of critical controls or barriers, are reported and shared with others. There is anecdotal evidence to suggest that there is only patchy reporting of high potential incidents, and that this may be linked to legal liability concerns. • DRET should work with industry and APPEA to develop mechanisms to share information on high potential incidents. 5.5 Review the training available for personnel making judgments on the safety of well operations Many personnel working in drilling 'come up through the ranks'. There are advantages in this but this practical experience needs to be supplemented by training typically in 'well control'. Given the MCI Report and the evidence given at the MCI, the adequacy of the existing training should be reviewed and modified as required. DRET work with industry and APPEA to enhance the training available to personnel involved in well operations. 5.6 Mergers and Acquisitions 5.6.1 Due Diligence PTTEP AA identified that it had undertaken a due diligence investigation of CRL prior to acquisition. However, • interviews with key personnel and transcripts from the MCI indicate that the implementation of SSHE arrangements on the Montara WHP were not adequate when the Blowout occurred. It would appear that PTTEP was unaware of the WWW.NOETICGROUP.COM PAGE 36 OF 73 IN -CONFIDENCE relatively poor state of SSHE on the Montara WHIR when it was acquired. This raises important questions regarding • the comprehensiveness of PTTEP's due diligence process, in particular the need to include SSHE as part of this process. There are valuable lessons that industry can draw from PTTEP's experience in acquiring CRL to ensure similar issues are not encountered in the future by others in the industry. The due diligence process undertaken by companies should include all elements of the target's HSE including HSE policies and procedures, HSE performance, safety culture and related issues. Due diligence of HSE -type policies and procedures should consider, at a minimum, the completeness and efficacy of safety practices at an operational level. Acquiring companies might consider independent verification that operational risks have been adequately identified, and that controls are being effectively implemented, maintained and monitored. Any issues highlighted in the company being acquired should be given suitable weight in decision making alongside financial considerations. DRET should consider working with the Australian Petroleum Production and Exploration Association (APPEA) to promote and educate industry on matters relating to good practice in undertaking due diligence around safety, health and environment. 5.6.2 Integration of Acquisitions • PTTEP AA provided a summary of its PTTEP — CRL Implementation Plan, which highlighted the following focus areas: + strategy: integrate Australia into PTTEP country strategies; + deal closing: ensure on-time/early closure; • + human resources: screen core people and retain pivotal positions; + project management: ensure Montara project delivery; + finance and accounting: monitor and approve key financial decisions; and + communication: shape all key stakeholders views toward collaboration.ss, In establishing the integration team charters, PTTEP set the objective to 'ensure nothing is forgotten'. However, it is apparent from the summary of focus areas described above, that specific consideration was not given to HSE as part of the PTTEP — CRL Implementation Plan. In the discontinuous management environment that can follow a merger or acquisition, there is an increased risk of safety incidents and major accident events occurring due to uncertainty of management and reporting requirements. Particularly where pre-existing management arrangements are being replaced or integrated, there is increased chance of incidents or major accidents occurring during the transition phase. The integration of HSE arrangements should be explicitly planned for as part of the take-over/ merger process. An integration/change management plan should be developed that deals with both the structural and human elements of systems integration, ensuring that the emphasis on safety, active monitoring and good governance is not obscured during the transition phase. " PTTEP — CRL Implementation Plan WWW.NOETICGROUP.COM PAGE 37 OF 73 IN -CONFIDENCE DRET should consider working with APPEA to promote and educate industry on matters relating to good practice in dealing with asset integration to ensure asset integrity following acquisition. 5.7 Integration of Health Safety and Environment This Report and the MCI Report highlights a number of inadequacies within PTTEP AA that indicate SSHE-related concerns were not adequately considered in everyday operations and management considerations. It is likely this occurred because SSHE-related issues were not integrated into the corporate planning and strategies. This omission in corporate level strategic planning may also occur in other small- to mid -tier companies in the industry. DRET could work with APPEA to determine if HSE issues are adequately integrated into corporate -level strategic planning in other small- to mid -tier companies. If the problem is common, DRET and APPEA could identify initiatives to ensure small- to mid -tier companies are considering HSE issues at all levels of their organisations. DRET should work with APPEA to improve the ability of mid to small tier companies to incorporate HSE issues into corporate planning frameworks. 5.8 Governance and Oversight 5.8.1 Advisory Boards i This Report highlights that PTTEP did not understand fully the culture within CRL when it was acquired. It also highlights that PTTEP did not establish sufficient governance arrangements to ensure PTTEP AA was operating in accordance with good oil field practice in Australia. These two failures may be, in part, a result of PTTEP's inadequate appreciation of the operating environment within Australia. This situation may not be unique to PTTEP and could have applied to any other international petroleum exploration and production company looking to establish a presence in Australia. In these situations, it is important for foreign -owned or multi -national companies to ensure they understand the local regulatory environment, labour market, community and workplace culture and other local factors that may influence local operation. This `local knowledge' could be acquired by the multi -national by establishing an advisory board. The advisory board would provide both the parent company and local senior management with opportunity to seek external advice on safety related issues that take into account local conditions. DRET should work with APPEA to provide advice to industry on the use of advisory boards to enhance safety, health and environmental outcomes. • WWW.NOETICGROUP.COM PAGE 38 OF 73 IN -CONFIDENCE • 6 CONCLUSION The conduct of the Technical Review and the Governance Review, involved an extensive review of documentation provided by PTTEP AA, including its Montara Action Plan. The reviews also included engagement with both PTTEP and PTTEP AA personnel in Perth. Throughout the review process, PTTEP AA demonstrated a willingness to engage in a positive manner with Noetic. PTTEP AA's initial Montara Action Plan (4 June 2010) was necessary in that it addressed the majority of technical issues identified through the MCI. However, the initial Montara Action Plan (4 June 2010) was insufficient as it did not address many of the systemic and governance issues that led to the Montara Blowout. Subsequent versions of the Montara Action Plan contained the initiatives required to address technical, systemic and governance issues that arose from the Montara Blowout and MCI. The revised Montara Action Plan now articulates a comprehensive change management program that will assist PTTEP AA to meet industry good practice. Crucially, PTTEP AA has also recognised the need to address the lack of clarity in the governance arrangements between PTTEP and PTTEP AA. PTTEP AA's CEO has assured Noetic these governance issues will be resolved as a matter of priority. At this (early) stage of PTTEP AA's change process, Noetic has only been able to examine the company's intent and the comprehensiveness of its plans for change. To this end, Noetic is satisfied that PTTEP AA has a plan that effectively responds to the issues raised in the MCI and importantly the plan sets the company on the path to achieving industry standards for both good oilfield practice and good governance. However, the success of • PTTEP AA's program for change will depend entirely on the quality of execution. • PTTEP AA's plans for change are extensive. The benefits of the changes will require up to 18 months to be realised. PTTEP AA has clearly identified its commitment and capacity to implementing its change program. However, to ensure the effective implementation of the Montara Action Plan, the Australian Government should instigate a monitoring program. Noetic understands that the MCI Report recommends the Minister undertake a review of PTTEP AA's licence to operate under the Offshore Petroleum and Greenhouse Gas Storage (OPGGS) Act 2006. Noetic notes that the scope of the independent review does not include commenting on this recommendation. However, we understand that this is one avenue that the Minister is able to use in order to seek assurance on the quality of the implementation of the Montara Action Plan by PTTEP AA. Noetic also notes that the Minister has the option to monitor directly PTTEP AA's implementation of the Montara Action Plan, through the appropriate regulators, directly by DRET through a regime of follow-up reviews, or through a combination of both. WWW.NOETICGROUP.COM PAGE 39 OF 73 IN -CONFIDENCE - - A—nvm nr I I nnn fnrm KIM— AM Member of the Order of Australia APPEA Australian Petroleum Production and Exploration Association BOP blowout preventers CEO Chief Executive Officer Commonwealth Commonwealth of Australia Used interchangeably with Australian Government in this Report CMS Competency management system CRL Coogee Resources Limited Acquired by PTTEP in February 2009. DRET Department of Resources, Australian Government Department Energy and Tourism HSE health, safety and environment Referred to as SSHE in PTTEP JV Joint venture KPI(s) Key performance indicator(s) MAE Major accident event MAPSC Montara Action Plan Steering Committee MCI Montara Commission of Inquiry Established by the Australian Government pursuant to the Royal Commission Act 1902. MP Member of Parliament Noetic Noetic Solutions Pty Limited Minister, the Minister for Resources and Minister of the Commonwealth of Australia Energy NOPSA National Offshore Petroleum Australian Government agency Safety Authority PTT PTT Public Company Limited Formerly known as the Petroleum Authority of Thailand. PTTEP PTT Exploration and Production Majority owned by PTT. Company Limited PTTEP AA PTTEP Australasia A subsidiary of PTTEP. Also referred to as PTTEP Australasian Asset or PTTEP Australasia. Incorporates PTTEP Australia Pty Ltd, PTTEP Australia Offshore Pty Ltd, PTTEP Australia Perth Pty Ltd, PTTEP Australia Timor Sea Pty Ltd, PTTEP Australasia (Ashmore Cartier) Pty Ltd, PTTEP Australia Browse Basin Pty Ltd, PTTEP Australasia Pty Ltd, PTTEP Australasia (Petroleum) Pty Ltd, and PTTEP Australasia (Operations) Pty Ltd. SSHE security, safety, health and Equivalent to HSE environment WHP wellhead platform • WWW.NOETICGROUP.COM PAGE 40 OF 73 IN -CONFIDENCE MEEF"..'.91 Dncifinn TiMn rinn�hmnn* !^, r� r� U Dr Chalermkiat Tongtaow Chief Executive Officer PTTEP Australasia Mr David John SSHE Advisor Safety, Security, Health Environment Department PTTEP Mr Andy Jacob Chief Operations Officer PTTEP Australasia Mr Pasook Eagark Drilling and Well Service Manager PTTEP Australasia Mr Dan Dunne SSHE Manager PTTEP Australasia Sorasan Milindasuta Business Services Manager PTTEP Australasia WWW.NOETICGROUP.COM PAGE 41 OF 73 IN -CONFIDENCE ANNEX C: DOCUMENTS REVIEWED 2003 Principles of Conduct 2005 Integrity Management: Learning From Past Major Industrial Incidents. Booklet fourteen. 2005 Safety, Culture and Risk 2006 Developing process safety indicators 2007 Corporate Governance Principles and Recommendations with 2010 Amendments 2007 Operational Excellence 2007 The Report of the PM US Refineries Independent Safety Review Panel 2008 2009 2009 25 Mar 2003 Jan 2006 Oct 2006 Oct 2008 Dec 2008 Dec 2008 Dec 2008 Mar 2009 Australian Petroleum Production and Exploration Association BP CCH Australia Limited Health and Safety Executive (UK) ASX Corporate Governance Council Chevron Corporation Independent Safety Review Panel Code of Environmental Practice Australian Petroleum Production and Exploration Association Health, Safety and Environmental Case Guidelines for International Association of Drilling Mobile Offshore Drilling Units Contractors Managing the Risks of Organizational Accidents Creating a New Offshore Petroleum Safety Regulator Australian Government Department of Industry, Tourism and Resources McKinsey Coogee Integration Plan V5 Jan 06 McKinsey Montara Development: Schedule of Quality, Validation Coogee Resources and Equipment Critically Requirements Safety Security Health and Environment Management PTTEP System Asset integrity - the key to managing major risks International Association of Oil and Gas SSHE MS.S.01 Plan Management Standard SSHE MS.S.06 Document Management Standard SSHE MS.S.11 Security Management Standard Producers PTTEP PTTEP AA PTTEP • • WWW.NOETICGROUP.COM PAGE 42 OF 73 IN -CONFIDENCE (continued) • Apr 2009 SSHE MS.S.08 Asset Integrity Management Standard PTTEP Jun 2009 SSHE MS.S.09 Management of Change Standard PTTEP Jun 2009 SSHE MS.S.15 Audit and Review Standard PTTEP Jul 2009 SSHE MS.S.02 Training & Competence Standard PTTEP Jul 2009 SSHE MS.S.07 Risk Management Standard PTTEP Jul 2009 SSHE MS.S.12 Performance Management Standard PTTEP Aug 2009 SSHE MS.S.04 Regulatory Compliance Standard PTTEP Oct 2009 SSHE MS.S.14 Incident Management Standard PTTEP Nov 2009 SSHE MS.S.10 Emergency and Crisis Management Standard PTTEP 9 Nov 2009 Initiatives Charter - PTTEP AA 1 Integration - 9 Nov 09 PTTEP AA Dec 2009 SSHE MS.S.13 Behaviour -Based Safety PTTEP Jan 2010 Production Operations Monthly HSE Report PTTEP 15 Jan 2010 PTTEP Organisation Structure PTTEP AA 15 Jan 2010 PTTEP Organisation Structure PTTEP . Feb 2010 Production Operations Monthly SHE Report PTTEP Feb 2010 SSHE MS.S.03 Contractor Management Standard PTTEP Feb 2010 SSHE MS.S.05 Communication Standard PTTEP • WWW.NOETICGROUP.COM IN -CONFIDENCE PAGE 43 OF 73 (continued) 0 16 Feb 2010 Montara HI ST1 Well Release Incident - Report on PTTEP AA action to prevent re -occurrence Mar 2010 Production Operations Monthly SHE Report PTTEP Apr 2010 Delegation of Authority PTTEP AA 1 Apr 2010 Minutes of Meeting: Monthly SSHE Review Meeting 21 Apr 2010 Minutes of Meeting: Monthly SSHE Review Meeting PTTEP May 2010 Production Operations Monthly SHE Report PTTEP 1 Jun 2010 Minutes of Meeting: Monthly SSHE Review Meeting PTTEP 4 Jun 2010 Letter to Ho Minister Ferguson PTT Exploration and Production Public Company Limited 4 Jun 2010 Letter to Minister Ferguson PTTEP 10 Jun 2010 Montara Action Plan Steering Committee (charter) PTTEP 17 Jun 2010 Report of the Montara Commission of Inquiry Commonwealth of Australia 14 Jul 2010 Montara Well H1 ST1 Incident, 21 August 2009 PTTEP 16 Jul 2010 Job Competency Profile (JCP): Well Engineering PTTEP • 23 Jul 2010 Job Competency Profile (JCP): Drilling PTTEP 23 Jul 2010 Technical Career Ladder - Drilling - Competency PTTEP Criteria 26 Jul 2010 Minutes of Meeting: Monthly SSHE Review Meeting PTTEP AA Aug 2010 New Venture Process PTTEP i WWW.NOETICGROUP.COM PAGE 44 OF 73 IN -CONFIDENCE (continued) • Aug 2010 New Venture Process PTTEP Aug 2010 PTTEP AA Integration - August 2010 Report PTTEP AA 4-Aug 2010 Drilling Interfaces Meeting PTTEP AA Sep 2010 Australia Assets Division Org Chart PTTEP AA Sep 2010 Drilling Department Org Chart PTTEP AA Sep 2010 International Assets Group Org Chart PTTEP AA 4 Sep 2010 Parliament Steering Committee visit PTTEP 9 Sep 2010 Montara Audit Program PTTEP AA 9 Sep 2010 PTTEP AA 20101 and 5-year Work Plan PTTEP AA 14 Sep 2010 PTTEP AA Drilling & Well Engineering Competency PTTEP AA Assurance 21 Sep 2010 PTTEP Corporate Lessons Learned from Montara and PTTEP AA Macondo 23 Sep 2010 Montara vs Macondo Comparison PTTEP AA 27 Sep 2010 PTTEP AA Drilling & Well Engineering Competency PTTEP Assurance: Weekly Meeting #2 - Project Team 28 Sep 2010 PTTEP AA Drilling & Well Services Organisation PTTEP 5 Oct 2010 PTTEP Montara Action Plan (Draft A) PTTEP AA • WWW.NOETICGROUP.COM IN -CONFIDENCE PAGE 45 OF 73 (continued) • 25 Oct 2010 Management Standard (VA) PTTEP 28 Oct 2010 Montara Action Plan, Rev 14 (Action list) PTTEP 28 Oct 2010 PTTEP AA Australia Strategy and Execution Plan (Draft A) PTTEP 29 Oct 2010 Montara Action Plan Timeline, Rev 3 PTTEP Oct 1998 SSHE MS Management System Rev 1 PTTEP 28 Sep 2010 PTTEP AA Drilling & Well Services Organisation PTTEP (undated) About PTTEP (Corporate Value) PTTEP (undated) About PTTEP (Vision and Mission) PTTEP (undated) PTTEP AA 2011 Drilling Campaign Drilling Integrated PTTEP Project Planning & Execution (PREP Rev 6) (undated) PTTEP HQ — PTTEP AA Working Relations PTTEP (undated) Well Engineering Standards (D41-502433-FACCOM) PTTEP 2010 PTTEP AA is building its Governance System and is PTTEP aligning with the Corporate Committees. 15 to 30 Mar 2010 Evidence Montara Commission of Inquiry 31 Marto 16 Apr 2010 Evidence Montara Commission of Inquiry 9 Apr 2010 Evidence given PTT Mar — Aug 2009 PTTEP — CRL SSHE MS Integration PTTEP • WWW.NOETICGROUP.COM PAGE 46 OF 73 IN -CONFIDENCE ANNEX D: CORPORATE PLANNING FRAMEWORK The corporate planning framework described below is based on Noetic's expertise and experience in assisting a number or public sector and private sector organisations. It is based on our practical experience to develop of planning and implementation at the strategic, operational and tactical levels. The strategic level includes: + Vision. This is a statement of end state an organisation wishes to achieve. The vision is typically aspirational and sits at the top of the planning framework. The vision may contain a time -specific end date. + Mission. This is a statement of the reason for the organisation's existence. A mission is ongoing for the duration that the organisation chooses. + Values. These describe the principles of operation that are important to the organisation. They provide guidance as to how an organisation will seek to achieve its vision and carry out its mission. Values should drive decisions at all levels and are ideally reflected in the behaviour of employees at all levels of the organisation. Values are not limited by time. + Objectives or Goals. These are high-level statements of what an organisation will aim to achieve in order to attain its vision and complete its mission. Objectives and goals can be specific to one part of an organisation or can apply across the whole organisation. Achievement of objectives or goals must be measurable either subjectively or objectively. Goals may be both finite and non-finite, meaning they can have an end date or be ongoing. The operational level includes: + Strategies. They describe how the organisation is to achieve its objectives or goals. They emphasise the core themes that initiatives or programs of work are grouped under or contribute to. Strategies provide an explanation of why initiatives are being undertaken and how they will contribute to an organisation's mission and vision. Strategies will ideally reflect the values of an organisation. Strategies are not finite and may be applied on an on- going basis. The tactical level includes: + Initiatives or programs of work. These must be undertaken and completed in order to realise the strategy and achieve the objective or goal. They implement the strategy and are typically assigned to individual managers who will be responsible for ensuring the initiatives or programs are completed. Initiatives are usually finite, with a specific end date. + Individual tasks. These are activity items that form part of an initiative or program of work. They are usually undertaken by individuals or small teams, depending on their complexity. Individual tasks may include development of tools, production documents, maintenance activities or monitoring activities and all activities needed to implement strategies. Individual tasks are finite with an end date. + Sub -tasks. These break -down individual tasks into even smaller tasks. They are typically undertaken by an individual who forms part of a team. There may be several levels of sub -tasks underneath sub -tasks. Sub tasks are finite with an end date. WWW.NOETICGROUP.COM PAGE 47 OF 73 IN -CONFIDENCE ANNEX E: PERSONNEL PARTICIPATING IN MONTARA ACT/ON PLAN STEERING COMMITTEE MEETINGS Table 6. Montara Action Plan Steering Committee MemberS34 Dr Somporn Vongvuthipornchai (Chair) Executive Vice President, International Assets Group Bangkok Mr Somchai Manopinives Senior Vice President, Operations Support Division Bangkok Mr Jirapong Dharaphop Vice President, Safety, Security, Health and Environment Bangkok Department Mr Christopher Pungya Kalnin Advisor to Chief Executive Officer's Bangkok Mr David John SSHE Advisor Bangkok Implementation Manager and Committee Secretary Dr Chalermkiat Tongtaow Chief Executive Officer, PTTEP AA Perth Andy Jacob Chief Operation Officer, PTTEP AA Perth Table 7. Other Montara Action Plan Steering Committee participantS35 Mr Pramote Phloi-montri Acting EOP Bangkok Jose Martins Chief Finance Officer Perth Mr Vanruedee International Assets Group Bangkok Mr Janpen International Assets Group Bangkok Mr Preecha International Assets Group Bangkok • 34 As noted in Memorandum from PTTEP CEO dated 10 June 2010. "As noted from Minutes from MAPSC from 10 June to 14 September 2010. WWW.NOETICGROUP.COM PAGE 48 OF 73 IN -CONFIDENCE • ENCLOSURE 1: TERMS OF REFERENCE —TECHNICAL REVIEW • 1 Statement of Requirements 1.1 The Department's Requirements 1.1.1 Scope for Consultancy: Review of PTTEP Australasia Action Plan36 The Commonwealth Minister for Resources and Energy, the Hon Martin Ferguson AM MP, has tasked the Department of Resources, Energy and Tourism (Department) with commissioning an independent review of the PTTEP Australasia (PTTEP AA) Action Plan. The Action Plan was developed by PTTEP AA, with the assistance of its parent company PTTEP, prior to the finalisation of the Report of the Montara Commission of Inquiry. The Montara Commission of Inquiry was commissioned by the Minister in November 2009 immediately after the uncontrolled release of hydrocarbons from PTTEP AA's Montara Wellhead Platform in the Timor Sea. The Action Plan details how PTTEP proposes to substantially transform their offshore petroleum operations and management to bring PTTEP AA in line with industry best practice requirements and fully leverage the resources, experience and capabilities of PTTEP to meet industry compliance standards. The intent of the independent review is to provide the Australian Government with sufficient assurance that the Action Plan will address the learnings from the Montara Commission of Inquiry and that PTTEP AA's identified operational measures meet industry best practice requirements. The review of the Action Plan will be principally undertaken by an independent petroleum industry expert, with a supporting audit of the governance structures of PTTEP AA to be performed by an accredited auditor. Legal support will be provided both in terms of general oversight of the review process and to ensure that all legal issues are considered, with supporting legal advice as appropriate, in the course of the industry expert's review. 1.1.2 Purpose of consultancy: industry expert To undertake a technical review of the PTTEP AA Action Plan in support of the Australian Government's objective of facilitating the development of the 'best and safest offshore petroleum industry in the world'. The review will: (i) consider if the Action Plan adequately addresses the issues identified by the Montara Commission of Inquiry, and if not, gaps are to be identified with recommended options to address them as appropriate; (ii) consider if the measures to be implemented in regards to PTTEP AA's operations and management processes and procedures reflect industry best practice, and if not, those actions are to be identified, with recommended options as appropriate; 38 The'Action Plan' referred to in this Terms of Reference is the Montara Action Plan referred to in the body of the Report to which this document is annexed. WWW.NOETICGROUP.COM PAGE 49 OF 73 IN -CONFIDENCE (iii) consider PTTEP AA's progress against, and timeliness for, implementation of the Action Plan; and (iv) suggest possible conditions and/or mechanisms that the Australian Government may place on PTTEP AA to assure it that the Action Plan is being implemented and that PTTEP AA operations reflect industry best practice. This will require specific analysis of the well management systems and processes put in place by PTTEP AA at the Montara Wellhead Platform (and elsewhere) to determine whether these systems and processes are in accordance with industry best practice and compliance monitoring standards. The successful supplier will have detailed practical knowledge of petroleum industry procedures and processes in respect of offshore petroleum well operations and management, with a sound knowledge of industry best practice and accepted regulatory standards for offshore petroleum operations. Detailed technical knowledge of well drilling techniques is not a specific requirement of the consultancy. 1.1.3 Required Outcomes In light of the criteria outlined above at (i) to (iv), the industry expert will be required to provide a report to the Department which addresses the following outcomes: 1. Investigate the actions and activities contained in the PTTEP AA Action Plan with a view of ascertaining: a. whether these actions and activities are adequate to address the issues identified by the Montara Commission of Inquiry and the Report of the Montara Commission of Inquiry; and b. whether these actions and activities represent industry best practice. This will require an analysis of PTTEP AA's actions against the Action Plan and consideration of PTTEP AA's existing operating standards, technical practice procedures and protocols, training methods, policy framework and governance framework. The industry expert will also consider the methods identified by PTTEP AA to ensure continuous improvement in these areas. 2. Recommend overarching actions and activities, arising from their understanding of the issues/ learnings/ process and procedures of industry identified by the Montara Commission of Inquiry in relation to industry best practice that may be leveraged to support growth and training in the broader offshore petroleum industry. • • WWW.NOETICGROUP.COM PAGE SO OF 73 IN -CONFIDENCE • ENCLOSURE 2: TERMS OF REFERENCE — GOVERNANCE REVIEW 1 Statement of Requirements 1.1 The Department's Requirements 1.1.1 Scope for Consultancy: Review of PTTEP Australasia Action Plan37 The Commonwealth Minister for Resources and Energy, the Hon Martin Ferguson AM MP, has tasked the Department of Resources, Energy and Tourism (Department) with commissioning an independent review of the PTTEP Australasia (PTTEP AA) Action Plan. The Action Plan was developed by PTTEP AA, with the assistance of its parent company PTTEP, prior to the finalisation of the Report of the Montara Commission of Inquiry. The Montara Commission of Inquiry was commissioned by the Minister in November 2009 immediately after the uncontrolled release of hydrocarbons from PTTEP AA's Montara Wellhead Platform in the Timor Sea. The Action Plan details how PTTEP proposes to substantially transform their offshore petroleum operations and management to bring PTTEP AA in line with industry best practice requirements and fully leverage the resources, experience and capabilities of PTTEP to meet industry compliance standards. The intent of the independent review is to provide the Australian Government with sufficient assurance that the Action Plan will address the learnings from the Montara Commission of Inquiry and that PTTEP AA's identified governance structure meets industry best practice requirements. The review of the Action Plan will be principally undertaken by an independent petroleum industry expert, with support from an auditor. The auditor will focus specifically on the governance structure of PTTEP AA. The industry expert and auditor will work cooperatively in undertaking the review. Legal support will be provided both in terms of general oversight of the review process and to ensure that all legal issues are considered, with supporting legal advice as appropriate, in the course of the review. 1.1.2 Purpose of consultancy: auditor To undertake an audit of the PTTEP Action Plan and PTTEP AA governance structure to ensure their appropriateness and adequacy for addressing systemically the findings of the Montara Commission of Inquiry. The review of the Action Plan will: (i) consider if the Action Plan adequately addresses the issues identified by the Montara Commission of Inquiry, and if not, gaps are to be identified with recommended options to address them as appropriate; 37 The 'Action Plan' referred to in this Terms of Reference is the Montara Action Plan referred to in the body of the Report to which this document is annexed. WWW.NOETICGROUP.COM PAGE 51 OF 73 IN -CONFIDENCE (ii) consider if the measures to be implemented in regards to PTTEP AA's operations and management processes and procedures reflect industry best practice, and if not, those actions are to be identified, with • recommended options as appropriate; (iii) consider PTTEP AA's progress against, and timeliness for, implementation of the Action Plan; and (iv) suggest possible conditions and/or mechanisms that the Australian Government may place on PTTEP AA to assure it that the Action Plan is being implemented and that PTTEP AA operations reflect industry best practice. 1.1.3 Required Outcomes In light of the criteria outlined above at (i) to (iv), the auditor will be required to: 1. Undertake an audit of PTTEP AA's governance structure, operating policy and review procedures, including procedures to implement change and continuous improvement, with a view of ascertaining whether they are appropriate and adequate to address the issues identified through the Montara Commission of Inquiry and the Report of the Montara Commission of Inquiry. 2. Undertake an audit of PTTEP AA's systems and processes for the implementation of review activities under the PTTEP Action Plan. This will require an analysis of PTTEP AA's actions against the Action Plan and consideration of PTTEP AA's existing operating standards, training methods, policy framework and governance framework. The auditor will also consider the methods identified by PTTEP AA to ensure continuous improvement in these areas. • WWW.NOETICGROUP.COM PAGE SZ OF 73 IN -CONFIDENCE • ENCLOSURE 3: INITIAL REPORT AND KEY ISSUES SUMMARY Summary PTTEP AA's Montara Action Plan outlines how the company planned to address the expected findings of the MCI. A review of the Montara Action Plan identified that the majority of the actions it contained were concerned with improving future drilling operations by improving the PTTEP AA Drilling Management System. These improvements are necessary and important, but in our view, insufficiently address the root causes of the Montara Blowout. Our reasoning for this is that while significant improvements to drilling practices are required, significant improvements are also required at the organisational level. This is because the drilling activities take place within an organisational context, which the MCI Report found to be unsatisfactory. While PTTEP AA's Montara Action Plan identified some organisational improvements, they received less detail and prominence than well management issues. Additionally, some improvements, which we believe are needed appear to be absent. As we have set out below, from our reading of the MIC Report, the Montara Blowout is a classic 'organisational incident' and actions to prevent a recurrence need to be explicitly targeted at this the organisational level as well as the detailed drilling practices. Further discussion on the nature of organisational accidents, the key issues and the approach we have taken to identifying them, is in the following sections. • Difficulties with Assessing the Action Plan As we have mentioned above, the Montara Action Plan contained little we could authoritatively judge in a desk top review without access to supporting documents and the personnel responsible for developing and implementing the planned actions. For example the nature of the '...strengthened ...drilling organization,' referred to in PTTEP AA's letter of 4 June 2010 was not described in the Montara Action Plan nor was the 'enhanced reporting and review management process' (see page 2 PTTEP AA's letter of 4 June 2010). By contrast, there were 74 actions identified in Appendix 1 of the Montara Action Plan in relation to improving the PTTEP AA Drilling Management System. Background to our Approach to Identifying Key Issues Accidents in the oil and gas industry can be looked at in two different ways, personal safety and major accident events. Firstly, 'personal safety' refers to incidents which typically involve one person of which most are slips and trips, minor machinery incidents, falling off a ladder and so on. They are typically measured using lagging indicators such as loss time incident rates (LTIFR) or a similar measure. Secondly, major accident events (MAEs), such as the Montara Blowout, refer to those low probability but high consequence events which although very rare can have disastrous consequences in terms of loss of life, environmental, asset and hence value destruction. Traditional safety measures such as LTIFR are irrelevant as a measure of these sorts of low probability but high consequence events. These two 'types' of safety require different approaches. Personal Safety and Major Accident Events — Different Approaches MAEs in the oil and gas industry are often associated with a loss of containment of hazardous substances, such as toxic or flammable materials from the well or process plant, which can result in serious fires and explosions. In the WWW.NOETICGROUP.COM PAGE 53 OF 73 IN -CONFIDENCE petrochemical industries they are also referred to as 'process safety' events. Examples of these types of major accident events are the Piper Alpha fire and explosion in the North Sea, the BP Texas City explosion in the US, and • the Esso Longford Gas plant explosion. The Montara Blowout was an MAE. Our experience, as well as the literature on MAEs, strongly suggests there is no correlation between a good personal safety performance (as measured by loss time injury rates or similar measures) and the risk of MAEs. Companies with excellent personal safety records have suffered disastrous MAEs. Conversely, companies with poor personal safety records may also have a poor process safety performance. These two distinct types of 'safety' require preventive strategies with differing emphases. In particular, to prevent MAEs, an explicit focus on the management systems, leadership behaviours and culture of the organisation is required. This is because prevention depends on much more than the acts or omissions of one person and requires significant managerial and leadership attention to focus on MAE prevention. It also presupposes that the senior leaders of the organisation are familiar with the distinction between personal safety and major accident events and the techniques for the prevention of MAEs. Issues Identified by the Montara Commission of Inquiry The MCI comments that there were 'many deficiencies in [PTTEP AA's] practices and corporate culture,' (section 7.75), and these shortcomings were described in the Executive Summary of the MIC Report as 'widespread and systemic'. Based on our experience of reviewing MAEs in both the offshore oil and gas industry and other so called 'major hazard' sectors, this is not unusual. MAEs are usually multi -causal, with the immediate or 'proximate' causes representing the final risk control that failed amongst other more systematic organisational failures. Generally, some risk controls have deteriorated or failed gradually over time. In addition, in the offshore oil and gas . industry there is an inevitable barrier to communications due to the onshore/ offshore divide. Often this divide is compounded by the multi -national nature of an industry. In this situation it is common for the organisational level risk - controls (or barriers to incidents) to be managed remotely from the scene of the operational activity by senior managers onshore (or who are frequently in another country). High quality communications are essential to overcome this issue. Inadequate communications or management of competency issues are examples of the 'organisational causes' of incidents. In summary, in addition to the immediate or proximate technical causes of MAEs, there are usually a variety of management system, leadership and cultural shortcomings. These shortcomings provide the environment in which the immediate or proximate causes exist. It is our analysis that these shortcomings are the ultimate case in the Montara Blow out. Therefore the organisational causes of MAEs must be addressed by PTTEP AA if MAEs are to be prevented in the future. Identifying key issues Noetic has approached the identification of the 'key issues' by reviewing the MCI Report and MCI evidence and by grouping the findings into themes. The themes were constructed by identifying findings with common underlying contributory causes (e.g. 'insufficient competence' or 'inadequate communications'). For example Finding 9 is concerned with the testing of the cemented shoe and the failure to follow the Well Construction Standard (WCS). At the time of the incident, PTTEP AA onshore management were not aware of the failure to follow WCS. Finding 16 relates to the failure to install a pressure corrosion control cap (PCCC). Again PTTEP AA onshore managers were not aware of the failure to install the PCCC. These two examples strongly suggest there was insufficient oversight (or . 'performance monitoring') by managers at the time of the Blowout. WWW.NOETICGROUP.COM PAGE 54 OF 73 IN -CONFIDENCE • Comparison with an HSE Management System In addition to using our own expertise in oil and gas health and safety environment (HSE) issues, Noetic has also examined the MCI Report from the perspective of the International Association of Drilling Contractors (IADC) HSE Case Guidelines, a highly regarded HSE system. This approach will assist us to examine where the emphasis was placed in the Montara Action Plan compared with a widely accepted model of a safety management system to help identify apparent gaps. According to the 3.2 version of the IADC HSE Case Guidelines, a management system can be defined as a structured set of elements (independent principles and processes) intended to ensure the operations of an organisation are directed, planned, conducted and controlled in such a way as to provide assurance that the objectives of the organisation are met. Many detailed and important activities in the Montara Action Plan need to take place within an organisational environment, which is as well equipped as possible to ensure that the actions are discharged effectively and reliably. Current good practice would expect this environment to include an HSE management system, which includes all the essential elements of a recognised HSE management system. IADC Guidance on HSE Cases We have used the IADC HSE Case Version 3.2 Management System Elements as the basis of our comparison. However, it should be noted that all management systems share these elements, albeit described in slightly different terms. Table 8 below compares the United Kingdom health and safety regulator's guidance on safety management systems with the IADC guidance and Chevron's Operational Excellence Management System, (GEMS). Although the terminology is slightly different in each case, the fundamental principles are the same. Additionally these approaches are aligned with the relevant standards used internationally for occupational health and safety management systems. Table 8. Comparison of IADC, Chevron and UK HSE Safety Management System Elements + Policies and Objectives + Organisation, Responsibilities and Resources + Standards and Procedures + Performance Monitoring + Management Review and Improvement IADC HSE Case Guidelines Part 2.0.1 + Purpose, Scope and Objectives + + Procedures + + Resources, Roles and + Responsibilities + + Measurement and Verification + + Continual Improvement + Chevron Operational Excellence Management System (GEMS) 2007 Policy Organising Planning and Implementing Measuring Performance Audit Review HS(G)65 Successful Health and Safety Management, HSE Books, UK. Note on `Best Practice'. The concept of 'best practice' is not defined nor universally accepted. The concept of 'best practice' implies that . there is one 'best' way to do something. In the risk management world the focus tends to be more on the outcome — are the risks reduced to a level 'as low as is reasonable practicable'. This is an important concept in risk management in relation to the Australian petroleum regulatory regime. The risk management concept implies that WWW.NOETICGROUP.COM PAGE SS OF 73 IN -CONFIDENCE there are a variety of acceptable ways in which the risks can be made acceptable. Therefore, there is no one 'best practice'. For this reason Noetic has chosen to use the term 'good practice'. 0 Key Issues Following the Technical Review, Noetic believes the key issues with the Montara Action Plan relate to how adequately it addresses organisational causes of the Montara Blowout. The PTTEP AA has identified a wide range of important improvements to its standards, documents, competency arrangements, etc that are listed in the Montara Action Plan. Some organisational actions are also identified such as Demobilise ... contracted drilling personnel..'. (Item 7.1) and a review of the PTTEP AA organisation, (Item 7.2). However, other important organisational issues were either not mentioned or their intent or impact was not clear. Noetic could not be certain that PTTEP AA intended to address the organisational causes of the Blowout on the basis of a desk top examination of the Montara Action Plan. To provide assurance to the Australian Government that it is addressing the lessons from the MCI and meeting industry standards for good practice, PTTEP AA needed to address the seven key issues outlined below. + Leadership behaviours (in relation to the most senior PTTEP AA personnel) are not mentioned. + No changes to company policies and objectives are referred to in the Action Plan nor is there any mention of the development of suitable lagging and leading measures (or KPIs) to help PTTEP AA monitor progress with the improvements outlined in the Action Plan. + The actions directed at improving the competency arrangements do not explicitly mention the need to train personnel (from the most senior to those on the front line) in MAE causation and the techniques of preventing MAEs above and not just risk assessment. + There is no mention of how the workforce will be actively involved in participating in helping to shape and implement the changes which are planned. + While the Montara Action Plan refers to changes to the contracts entered into with third parties (Items 3.1 and 3.2), there is no mention on the wider issue of improving communications within PTTEP AA and between PTTEP AA and contractors. Related to this point is the absence of any mention of how effective teamwork between the various companies will be achieved. + It is not clear what performance monitoring arrangements are to be put in place. In addition it is not clear that the important difference between 'performance monitoring' as carried out by line personnel such as managers and supervisors compared with auditing by people with some independence of the organisation is recognised. Related to the concept of performance monitoring, there is no mention of PTTEP AA planning to carry out any safety climate or culture survey to help monitor the implementation of the changes currently contemplated. + Communications with regulatory organisations were not always complete or accurate. There is no mention in the Montara Action Plan as to how this will be addressed. Noetic believes that unless they are in place (or are perhaps being addressed outside of the Montara Action Plan) there is less chance that the important improvements currently listed in the Montara Action Plan will be implemented effectively and reliably 'in the field'. Further commentary on the seven issues mentioned above is provided in the • following sections to follow. WWW.NOETICGROUP.COM PAGE 66 OF 73 IN -CONFIDENCE • 6.1.1 Leadership Behaviours The behaviour of senior leaders is recognised as one of the most important determinants of an organisation's performance. This is sometimes defined as senior management's visible and active participation in HSE initiatives to ensure HSE is embedded in a company's culture. It is difficult to understand how the systemic failures described in the MCI Report could have occurred if the safety leadership was effective. Consequently, it is unlikely that some improvements cannot be identified and included in the Montara Action Plan. 6.1.2 Company Policies and Objectives There were no references to any changes in PTTEP AA's policies and objectives in the Montara Action Plan. One example relates to the significant changes made to the Drilling Department where contract staff either have been or are being replaced by staff personnel. It was not clear from the Montara Action Plan whether this was one off short- term change or if it was a change of practice and policy in PTTEP AA. Good practice would expect PTTEP A to codify an organisation -wide change in a policy document concerning organisational staffing for safety critical roles. The Montara Action Plan does not mention any revised HSE management objectives and HSE programmes, nor does it identify plans to show how HSE objectives are to be achieved. Given the number and significance of the adverse MCI findings we would have expected that a key PTTEP AA objective would be to review and change its key HSE policy objectives. However, such reviews were not reviewed in the Montara Action Plan. Nor was there any mention in the Montara Action Plan of the need for the development of suitable lagging and leading measures (or KPIs) to help PTTEP AA monitor progress with the improvements. 6.1.3 Competency in MAE causation and the techniques of preventing MAEs. Competency issues form a major feature of the MCI Report and 'competence' falls into the management system element of 'organisation, responsibilities and resources' in the IADC framework. Examples of the competency issues raised in the MCI Report include Finding 7 (risk assessment), Finding 26 (use of PCCCs), Findings 32-34 (well operations), Finding 44 (cementing) and Finding 45 (PTTEP AA did not have effective systems to acquire and maintain appropriate level of expertise). These issues were addressed in the Montara Action Plan. However, good practice in preventing MAEs includes the provision of training in: + the theoretical concepts of MAE causation; + the techniques used for identifying and assessing critical controls; + the classification into both preventive controls and mitigating controls; + the documentation and recording of these controls in ways in which all members of the workforce can see how their contribution contributes to effective risk management, e.g. by the use of 'fault and event trees' or 'bow -tie' diagrams; and + the techniques of performance monitoring of the critical controls (This last point is discussed further in key issue number 6 below). These elements were not explicitly mentioned in the Montara Action Plan. WWW.NOETICGROUP.COM PAGE 57 OF 73 IN -CONFIDENCE 6.1.4 Workforce Involvement There was no mention in the Montara Action Plan of how the workforce would be actively involved in participating in shaping and implementing the changes aimed at improving HSE in PTTEP AA. Active participation is widely regarded as a prerequisite for effective management of HSE and is considered good practice. Good practice also includes the provision of a 'stop work authority', enhancement of reporting arrangements of unsafe acts/ conditions and the introduction of a 'no blame' or 'just' culture. The Montara Action Plan did not explicitly include actions that would introduce these elements of workforce participation. 6.1.4.1 STOP WORK AUTHORITY A feature of many HSE management systems is the empowerment of the workforce to decide for themselves to stop work if they believe an activity is unsafe. To make this work effectively managers must ensure that supervisors understand that this is legitimate and actively supported by more senior managers. Good practice in this area is for supervisors and/or managers (once a member of the workforce has initiated the stop work process) to demonstrate that it is safe to work in circumstances in which a member of the workforce believe it is unsafe, rather than the individual demonstrate it was unsafe. 6.1.4.2 INTRODUCTION OF THE 'JUST CULTURE' CONCEPT To support this good practice of a stop work authority for all personnel, the concept of a 'just culture' needs to be embedded in an organisation. 'Just culture' draws on the discipline of human factors to understand the causes of human error. Even the perception of a blame culture can inadvertently drive the reporting of incidents or near misses, which are valuable learning opportunities 'underground'. Hence a 'just culture' is important so that it is recognised that not all human errors are equally culpable. It allows organisations to focus on understanding what happened and why rather than apportioning blame. 6.1.4.3 IMPROVING REPORTING OF INCIDENTS AND NEAR MISSES To complement a stop work authority and introduction of a 'just culture', specific action is also appropriate to encourage the reporting of unsafe conditions, incidents and near misses. It was not clear how far the Montara Action Plan would improve the safety observation program. 6.1.5 Communications and Teamwork with Contractors While the Montara Action Plan refers to changes to the contracts entered into with third parties (3.1 and 3.2) there was no mention on the wider issue of improving communications within PTTEP AA and between PTTEP AA and contractors. There was also an absence of information on how effective teamwork between the various companies could be achieved. It is important to ensure that the goals and objectives of all parties in a drilling campaign are aligned so far as possible, if good HSE outcomes are to be delivered. This is because whoever has the contractual responsibility, effective teamwork on the part of all participants is still essential. This is true onshore and offshore. However, it is particularly important where company representatives, the drilling rig offshore installation manager and third party contractors such as cementing contractors are working together on a drilling rig. It is difficult to see how effective team working can be delivered solely by contractual means. 6.1.6 Performance Monitoring There are a number of MCI findings that relate to failures in oversight. Some examples include a failure to detect that the WCS was not followed (Finding 9); the failure to detect the absence of the 133/8 PCCC (Finding 16); monitoring of the casing fluid (Finding 35); and the absence of internal systems to achieve a high level of quality assurance with • respect to well control operations - through internal audits (Finding 42). WWW.NOETIGGROUP.COM PAGE SH OF 73 IN -CONFIDENCE 6.1.6.1 PERFORMANCE MONITORING DEFINED Performance monitoring is a crucial element in an effective management system. Effective performance monitoring detects variances from standards and controls and allows corrective action to be taken. It is akin to the thermostat on an air conditioning unit. It detects if the desired temperature is being achieved and enables corrective action to increase or decrease the temperature. Effective performance monitoring systems are implemented by line management and require engagement from senior personnel in their design and implementation including taking part themselves in these activities. These are not just frontline supervisory activities and middle and senior managers need to be involved too. These activities also play an important part in effective governance arrangements. However, there was no mention of changing or improving performance monitoring processes in the Montara Action Plan. 6.1.6.2 PERFORMANCE MONITORING VS AUDIT It is possible the MCI Report (and PTTEP AA) used the term 'audit' to mean '[performance monitoring' in Finding 42. This is a common but inaccurate use of the term in the context of HSE management systems. Auditing is generally defined as a checking process by people who are (to a greater or lesser extent) independent of area or process being checked. 'Performance monitoring' is the process of line personnel routinely checking that their subordinates are effectively implementing the specified policies, procedures and risk controls. This is not an academic distinction. A failure to distinguish between the two concepts can lead to gaps in organisational performance. Performance monitoring is a feature of all credible management systems not just in connection with health, safety and environment management systems and is a feature of the models set out in Table 1 of the IADC HSE Guidelines and the Chevron Operational Excellence Management System. Failure to distinguish clearly between these two different concepts cannot be regarded as good practice and will need to be followed up during the dialogue with . PTTEP AA personnel. 6.1.6.3 SAFETY 'CLIMATE' OR 'CULTURE' SURVEY Given the changes in personnel, documents and systems and hence working practices, senior management will need to have as clear a picture as possible as to the views and attitudes of the workforce to these changes. To assist in obtaining this picture many companies use proprietary safety climate or culture surveys which seek to elicit anonymous feedback. 6.1.7 Regulatory Relationships The MCI Report finds several examples of inadequate communications with regulators, particularly the Northern Territory Department of Resources (NOT DoR) and the National Offshore Petroleum Safety Authority (NOPSA). There was no mention of improving communications with regulators in the Montara Action Plan apart from lobbying in relation to a more collaborative approach during an emergency, nor is there mention of developing PTTEP AA's knowledge of the role of the regulators and what would constitute professional behaviour in relation to its dealings with them. 6.2 Conclusion From Noetic's initial review of the Montara Action Plan provided with the letter from PTTEP AA of 4 June 2010, we conclude that there are very many good and important actions underway or planned within PTTEP AA. The largest single set of actions is aimed at addressing the undoubted weaknesses in the Drilling Management System. However, based on the limited evidence contained in the Montara Action Plan and letter of 4 June, (and without any dialogue with PTTEP AA), there appears to be insufficient focus on the organisational failures which arose during the drilling of the Montara wells. However, we emphasise that this is only a very preliminary observation based on limited WWW.NOETICGROUP.COM PAGE 59 OF 73 IN -CONFIDENCE evidence. This will need to be examined in much more detail in the dialogue with PTTEP AA personnel scheduled for week commencing 27 September. . • 0 WWW.NOETICGROUP.COM PAGE GO OF 73 IN -CONFIDENCE • LJ ENCLOSURE 4: AMENDED MONTARA ACTION PLAN (DRAFT B - 2 NOVEMBER 2010). PTTEP MONTARA ACTION PLAN WWW.NOETICGROUP.COM PAGE 61 OF 73 IN -CONFIDENCE Document Number: D John, Draft B 2/11/10 Final draft for review CSH Draft A 5/10/10 First draft for review. D John, Dr Chalermkiat, Dr Somporn, CSH PTTEP AA CEO INA Revision Date Reason for Issue Author Checked By Approved By CONTENTS 1. DISTRIBUTION LIST 3 2. INTRODUCTION 3 3. PURP OSE 3 4. MONTARA ACTION PLAN 3 • 4.1 General 3 4.2 Responsibilities and Accountabilities 4 4.3 Management of Change 4 4.4 Post Action Plan 4 Is 5. MONTARA ACTION PLAN IMPLEMENTATION 5 5.1 Steering Committee Objectives 5 5.2 Steering Committee Members 5 5.3 Steering Committee Meetings 5 5.4 Implementation Manager 5 5.5 Montara Response, Perth 5 5.6 Request For Services 6 6. KEY MILESTONE 6 7. RELATION WITH OTHER INITIATIVES 6 0 WWW.NOETICGROUP.COM PAGE 62 OF 73 IN -CONFIDENCE 0 1. DISTRIB UTION LIST PTTEP Bangkok PTTEP AA Khun Somchai, INA Dr Chalermkiat, CEO Khun Somchai, EOP Andy Jacob, COO Khun Jirapong, CSH Dan Dunne, SSHE Manager Chris Kalnin, Advisor to CEO Khun Pasook, Well Const. Manager Khun Vanruedee, INA Khun Sakchai, CFO Khun Chayong, EDL Ian Paton, Exploration Manager Khun Pramote, EWE Greg Youd, Production Manager Khun Alongkorn, HRD Khun Sanga, HRD David John, CSH 2. INTRODUCTION On 21" August 2009 a blowout occurred on the H1 ST1 well at the Montara wellhead platform in the Timor Sea, offshore north west Australia. The Montara Field is operated by PTTEP Australasia (PTTEP AA), a subsidiary of PTT Exploration and Production PCL (PTTEP). • 69 people were evacuated safely from the jack -up drilling rig West Atlas. A relief well had to be drilled to control the blowout. A first well kill attempt on 1st November 2009 was unsuccessful and ignition of hydrocarbons occurred. The fire burned until 3rd November 2009 when a second well kill attempt was successful. The West Atlas was a total constructive write-off. The wellhead platform topsides were damaged. During the period that the blowout occurred a likely 400 barrels per day on light oil were released to the sea. Environmental impacts appear to have been limited by oil evaporation, natural degradation, dispersant spraying and skimming. PTTEP and PTTEP AA recognize that the consequences could have been worse, particularly potential loss of human life. Lessons must be learned and actions taken to prevent recurrence. 3. PURP OSE The purpose of this document is to provide a narrative to the actions that have been identified to prevent recurrence of such a major accident event (MAE) and describe how those actions are managed. Some of the Actions identified will be implemented in the PTTEP company for the first time. In this respect PTTEP AA is acting as a sounding board for future reverse implementation of these actions into the PTTEP corporate function (and other subsidiaries). WWW.NOETICGROUP.COM PAGE 63 OF 73 IN -CONFIDENCE 4. MONTAR A ACTION PLAN 4.1 General • A Montara Action Plan has been developed that lists the actions identified to prevent incident recurrence. The sources of actions in the Plan are: • PTTEP Internal Investigation Report, subject to legal professional privilege. • Borthwick Commission of Inquiry Transcripts. At the time of writing the Commission Report has been submitted to, but not published by the Minister of Energy. • Third party sources e.g. recommendations from AGR (a drilling management consultancy). • Observations from Noetic, contracted by the Department of Resources, Energy and Tourism to review progress and suitability of the Action Plan. The Action Plan is a live document and will be amended as required e.g. when the Borthwick Commission of Inquiry Report is published. The current revision of the Action Plan can be requested from David John, davido(Wotteo.com Actions are a combination of 'point actions' intended to prevent recurrence of a specific event (blowout) and systemic actions which have a broader scope and can be applied to other MAE's. Note that actions also cover Corporate Lessons Learned. 4.2 Responsibilities and Accountabilities • Responsibilities (doing the work) and accountabilities (ensures work is done) are shown in the Action Plan. One of the actions of the Responsible parties is to identify those that need to be Consulted or Informed. In general line management are assigned as Responsible with the next level of Management as Accountable. 4.3 Management of Change Actions that may require Management of Change to be applied are identified in the Action Plan. Reference SSHE Standard Management of Change. 4.4 Post Action Plan The Action Plan has a discrete lifetime. It is required that actions and behaviours be embedded in PTTEP and PTTEP AA organizations and processes to ensure continuity of response. 5. MONTARA ACTION PLAN IMPLEMENTATION A Steering Committee was originally established to oversee implementation of the Montara Action Plan. Ref memo PTTEP/2000/M.139/2010. 0 WWW.NOETICGROUP.COM PAGE 64 OF 73 IN -CONFIDENCE • 5.1 Steering Committee Objectives The objectives of the Steering Committee are to: • Provide senior management oversight of the Action Plan. • Agree the Action Plan and any amendments to it. • Monitor progress with closing out actions. • Ensure and confirm that recommendations in the Action Plan are completed in agreed timescales and at the required level of rigor. • Monitoring overall work plans to ensure capability exists to execute work safely. • Ensure that resources (financial, personnel etc) are available to achieve the above. • Provide advice about strategic issues regarding Action Plan implementation. • Ensure coordination of efforts between different departments in Perth and Bangkok. • Be made aware of potential impediments to completing actions and proposing solutions. • Review and agree (or not) proposals from PTTEP AA Line Management to progress with key activities e.g. recommencing drilling. • Approve information to be sent externally, in particular to Authorities / Government. • Oversight and coordination of other initiatives (see section 7). 5.2 Steering Committee Members Members of the Steering Committee are: • Dr Somporn, EVP International Assets Group, Bangkok, (Chairman). • Khun Somchai, SVP Operations Support Division, Bangkok. • Chris Kalnin, Advisor to the CEO, Bangkok. • Khun Jirapong, VP SSHE, Bangkok. • Dr Chalermkiat, CEO PTTEP AA, Perth. • Andy Jacob, COO, PTTEP AA, Perth. • David John, SSHE Advisor, Bangkok (Implementation Manager + Committee Secretary). • Other members may be co-opted as required. is 5.3 Steering Meetings The Committee will meet regularly by video conference between Perth — Bangkok. The Committee Secretary will arrange meetings, prepare draft meeting minutes for review and issue final minutes. WWW.NOETICGROUP.COM PAGE 65 OF 73 IN -CONFIDENCE 5.4 Implementation Manager • A full time Montara Action Plan Implementation Manager has been appointed (David John, CSH, based in Bangkok). Key functions are: • Reports to EVP International Assets. • Develop and update the Montara Action Plan. • Animate process to ensure assigned personnel are aware of responsibilities under the Plan and they follow actions up in a timely and rigorous manner. • Identify with assigned persons how to make action permanent and sustainable. • Identify with those responsible any actions under the Action Plan that require Management of Change review such as risk assessments. Arrange / facilitate these as required. • Regularly report Action Plan progress and status to the Steering Committee, including highlighting any areas of concern. • Prepare reports for external review if required. 5.5 Montara Response, Perth PTTEP AA COO has been temporarily assigned to follow-up the issues below relating to Montara: (Ref memos 154331_1 and 154335_1) • Investigations • Environmental Monitoring Plans • Montara Action Plan • Claims • Insurance • Media • Government Relations 5.6 Request For Services RFS INA004/2010 has been raised for use by involved Departments — CSH, EDL, EWE, HRS etc. 6. KEY MILESTONE The key milestone is the decision to recommence the Montara drilling campaign. There are a number of actions that are required to be completed before drilling can start. In particular these are: • Adequate drilling organization defined based on work plan and personnel recruited. • Competency Assessments and training of PTTEP AA drilling personnel. • An approved PTTEP AA Drilling Management System has been issued (including Bangkok — Perth drilling interfaces). • Drilling contractors and sub -contractors fully engaged. • Pre -Drilling Audit completed and actions closed out. • Major Accident Event prevention program in place. is • WWW.NOETICGROUP.COM PAGE 66 OF 73 IN -CONFIDENCE In order to ensure an appropriate level of decision making the following will present the case for • recommencing drilling to the Montara Steering Committee for final sanction: • U PTTEP AA Drilling Manager for drilling -related issues (Drilling Management System, Recruitment, Training and Competency, Drilling MAE's, Drilling Contractor Communication and Teamwork) Implementation Manager for all other issues. This presentation to be made approximately 1 month before expected commencement of drilling activities. 7. RELATIONSHIP WITH OTHER INITIATIVES There are currently 3 major initiatives in PTTEP AA: • Montara Action Plan (to which this document refers) • Growth Strategy and Enablers. • 2011 Work Plan including Integration Plan. Links between them are given in the overarching PTTEP AA Australia Strategy and Execution Plan to which further reference should be made. WWW.NOETICGROUP.COM PAGE 67 OF 73 IN -CONFIDENCE ENCLOSURE 5: MONTARA ACTION PLAN (LIST OF ACTIONS) REV 14, 29/10/201) Main Plan # Action Description Responsible Accountable Review By Original Current MoC Status Comment Target Target Assessment Clarify Well Barrier Integrity 1 Review and confirm status of existing AA Drilling, AA COO BKK 30/6/10 Complete Safety Case risk Program finalised and regulatory approvals See Montara Well Verification Report, Rev 2, well barriers AGR Drilling assessment obtained. Completed 27/7/10. 13/8/10. 2 Prepare well barrier integrity test AA Drilling, AA COO BKK 30/6/10 Complete Safety Case risk Program prepared and reviewed by EDL. procedures / plan. AGR Drilling assessment Completed. 3 Prepare contingency plans should AA Drilling, AA COO BKK 30/6/10 Complete Safety Case risk Program prepared and reviewed by EDL. integrity tests prove inconclusive or AGR Drilling assessment Completed. negative. 4 Execute well barrier integrity tests AA Drilling AA COO BKK 30/6/10 Complete Safety Case risk Completed 26/7/10. offshore. Drilling assessment oversight 5 Carry out any remedial work required as AA Drilling AA COO BKK 30/6/10 Complete Safety Case risk Works carried out as part of 1.4 above. per contingency plan Drilling assessment Completed. oversight AA Drilling Management System (see Appendix 1 Complete an independent review of the AGR AA COO AA Drilling, 30/6/10 Complete Part of review is Complete. List of actions developed. See AGR Report - Montara Well Incident, Report WCMF and WCS BKK to ensure no risks Appendix 1 on separate spreadsheet. on Actions to Prevent Reoccurrence, Rev 1, Drilling increased / 16/2/10. See 75 actions in AGR PTTEP introduced. WCMS Update Tracker file. Draft DMS documents AGR AA COO 30/6/10 Complete No Completed 30/6/10 Compare DMS with PTTEP Corporate BKK Drilling AA COO 31/7/10 30/9110 No Drilling Management System project with References: PTTEP Drilling Management requirements and Good Oilfield Practice. Expert Advisors. System, PTTEP-DMS-001 Rev C. Well Operations Manual, PTTEP-WOM-002 Rev C Develop stand alone Well Operations AA Drilling AA COO As As No To be done. Clarify with regulator preferred format Management Plans. required required Develop PTTEP AA specific Blowout AA Drilling AA COO AA Drilling, 1/4/11 114/11 No To be done. Ensure in line with EDL BCP being prepared Contingency Plan BKK by Boots + Coots. Drilling Contracts / Document Amendment 11 Insert a requirement in Contracts that any AA Drilling AA COO 1/4/11 1/4/11 No To be done Next drilling campaign planned for April 2011. reports Contractor prepares on work done must be sent to PTTEP AA Drilling on / offshore. 12 Review contracts to make sure there is a AA Drilling, AA COO 1/4/11 1/4/11 No To be done Next drilling campaign planned for April 2011. requirement for third party personnel to Legal complete training as per their Training Matrices which should be similar to PTTEP AA Operating Discipline standards. 13 Update PTTEP AA investigation AA HSE AA COO 3016/10 3019/10 No Drafted. To be reviewed by new Well Reference: Corporate SSHE Standard protocols to require PTTEP Corporate or Construction Manager before issue. Incident Management independent expert to investigate any well control incidents. 14 Ensure that realities of drilling activities AA Drilling, AA COO 1/3/11 1/3/11 No To be done. As part of hazards identification Ensure personnel familiar with MAE barriers are accounted for in Major Accident AA HSE studies for Safety Case submission. e.g. bow ties. Event identification and QRA in Safety Cases. Industry Liaison 15 Lobby industry to approach NOPSA to AA CEO + AA COO 31/12/10 31/12/11 No APPEA Drilling & Completions steering Ongoing. develop a policy which requires COO committee established. Emergency collaborative engagement and Response and Oil Spill Sub Committees consultation during an emergency. established. 16 Participate in industry response BKK Drilling, AA COO 31/12/10 31/12/10 No PTTEP AA personnel participating in APPEA Should also refer to need to improve Well W W V.NOETICGROUP.COM PAGE 68 OF 73 IN -CONFIDENCE 0 0 0 • • • (particularly lessons learned from AGR initiatives. PTTEP BKK personnel will Control Certification training courses. Montara / Macondo). Take account of participate in OGP Oil Industry Response leamings in drilling, emergency Group. response, spill response. Organisation and Personnel 17 Demobilise, or temporarily assign for AA COO AA COO 30/6/10 Complete No Completed 30/6/10 knowledge continuity, contracted Drilling personnel from Perth office. 18 Undertake a review of AA drilling AA Drilling AA COO EDL, COO 31/9/10 Complete No Discussed and agreed. Complete. organisation, taking in to account 2010 work plans. 19 Develop a Recruitment Tool AA Drilling, AA COO EDL, COO 31/10/10 31/10/10 No 2/11/10. Work done by Expert Advisors AA COO (Competency Management System Phase 1). Complete. Recruit AA Drilling personnel. AA Drilling AA COO 31/12/10 31/12/10 No In progress 21 Review complete organisation of PTTEP AA CEO, AA INA HOP 1/5/11 1/5111 No Link to Operating Model and Growth Operating Model meeting 7/10/10. AA. Make recommendations and COO Enablers work. implement changes required including personnel. Training and Competence 22 Review technical and SSHE competency HRS, CSH, AA COO 1/4/11 1/4/11 No Ongoing. Will use BKK JC Profiles for Drilling References: Corporate SSHE Standard matrices for drilling personnel (and BKK Drilling, and Well Engineering as a basis. Expert Training and Competence; Corporate extend to other disciplines later). PTTEP AA Advisor assistance from 13/9/10 - Competency Management System. benchmarking; review JCP's for Australian work; aide to recruitment. Undertake competency assessments, PTTEP AA AA COO 1/4/11 1/4/11 No See above. Any Gaps identified to be input to 7.4. involving relevant disciplines from PTTEP Line HQ. Management 24 Review and improve technical and SSHE HRS, CSH, AA COO 1/4/11 1/4/11 No In progress. BKK matrices passed to AA for training matrices for Drilling and other BKK Drilling, review. personnel (operations, SSHE, PTTEP AA Construction etc 25 Identify and provide training courses HRS, CSH, AA COO 1/4/11 1/4/11 No To be done. The 2 1/2 day Safety Induction developed for required. BKK Drilling, Montara Project can be used as a basis for PTTEP AA training Drilling personnel, with some adjustments. 26 Engage with training providers to AA COO AA COO 31/12/10 31/12/10 No To be done. Will be part of APPEA process see 5.1 broaden well control course scope. Environmental 27 Revise Oil Spill Contingency Plan AA HSE AA COO 31/8/10 3019/10 No Incorporate leamings from Inquiry, discuss Review of emergency / crisis response in with AMSA PTTEP AA 22-23/7/10 will identify issues. Input from Dr Wardrop received. Internal workshop 9th August 28 Assess Oil Spill Equipment / Chemical AA HSE AA COO 31/8/10 30/9/10 No AMOSC Will be part of APPEA process see 5.1 availability 29 Develop sampling packs at operational AA HSE AA COO 31/8/10 30I9/10 No In progress. locations 30 Identify training gaps re Oil Spill AA HSE AA COO 31/8/10 30I9/10 No In progress. Contingency Plan 31 Review existing base line data available AA HSE AA COO 31/8/10 30/9/10 No In progress. for locations associated with our operations 32 Develop list of possible studies required AA HSE AA COO 31/8/10 3019110 No To allow for case by case selection of studies Maybe part of APPEA process see 5.1 post spill, suitable providers Corporate Oversight I Lessons Learned 33 Ensure appropriate level of Corporate EDL, AA AA COO 31/10/11 Complete No Drilling relations Perth - BKK discussed oversight of PTTEP AA Drilling activities. Drilling 4/8110 and agreed. Complete. 34 Ensure appropriate level of Corporate AA CEO INA 31/5/11 31/5/11 No Growth Enablers Workshop 7/10/10. SSHE oversight of PTTEP AA activities MS Integration already started. generally. Develop and conduct plan of Corporate CSH INA 1/4/11 1 1/4/11 1 No I Audits plannedpre-drilling and during drilling. Reference: Corporate SSHE Standard Audit VWM.NOETICGROUP.COM PAGE 69 OF 73 IN -CONFIDENCE technical and SSHE Management I Top Management Visit planned during and Review; Operations and Project Technical system audits. drilling. To be executed. Review documents. 36 Develop and implement lessons learned CSH, EDL, CEO 31/12/10 31/12/10 Review Corporate Lessons Learned file drafted and from Montara at Corporate level. INA under discussion with relevant departments. Implementation 37 Establish a senior management INA + AA CEO 30/6/10 Complete No Committee established. Regular meetings committee to oversee implementation of CEO taking place. this plan. Members from PTTEP AA and PTTEP HQ. 38 Appoint an Implementation Manager to IN + AA CEO 30/6/10 Complete No Done 2815/10. DJ appointed. ensure this plan is followed -up in agreed CEO timeframes and actions are sustainable. Shaded (;ell = Action GIosed. Critical, before drilling start u Number of Actions 38 Completed 12 In progress 18 To be done 7 Supplementary Plan 8 behind target # Action Description Responsible Accountable Review By Original Target Current Target MOC Assessment Status Comment Leadership + Commitment 39 Establish PTTEP AA Corporate SSHE committee AA SSHE AA CEO 31/12/10 31/12/10 No Charter drafted. 40 Regular SSHE information sharing meeting AA SSHE AA CEO 31/12/10 31/12/10 No 41 Define and implement SSHE Leadership Program AA SSHE AA CEO CSH 1/4/11 1/4/11 No APPEA Stand Up For Safety; UK HSE Leadership for Major Hazard Industries Audit + Monitoring Define audit and monitoring philosophy AA SSHE AA COO 31/12/10 31/12/10 No Establish audit plan and monitoring program. AA SSHE AA COO 114/11 1/4/11 No Annual audit plan exists; monitoring to be developed. Drilling first. Governance 44 Review role of PTTEP AA Board of Directors Board Chairman CEO 31/12/10 31/12/10 No In progress. Advisory Board recommended. Action from Growth Enablers Workshop 7/10/10. New Chairman announced. 45 Review SSHE organisation in PTTEP AA (report to CEO AA SSHE, AA CEO AA COO CSH 31/12/10 31/12/10 No In progress 46 Develop overarching plan covering PTTEP AA initiatives CK, DK INA Steering Ctte 31/10/10 31/10/10 No Drafted. 47 Develop Montara Action Plan narrative. DJ Steering Cttee Steering Ctte 31/10/10 31/10/10 No Drafted. SSHE Improvements 48 Ensure workforce involvement in DMS development, Safety Cases etc AA Drilling, AA SSHE AA COO 1/4/11 1/4/11 No 49 Re -start BKK - Perth SSHE MS integration DJ, DID CSH, AA COO CSH 31/12/11 31/12/11 No 50 Undertake Safety Climate Survey AA SSHE AA COO CSH 31/12/11 31/12/11 No 51 Extend BBS training to PTTEP AA CSH/O COO 31/12/11 31/12/11 No Major Accident Event Prevention Implement MAE's prevention program for drilling. AA Drilling, AA SSHE AA COO CSH/I 1/4/11 1/4/11 No Discussions with RPS and Expert Advisors. Identify MAE's, identify barriers; assign TA's; develop monitoring program; ensure senior mana ement'line of sight' 53 Implement MAE prevention program for other disciplines AA SSHE + others AA COO CSH/I 31/12/11 31/12/11 No Identify MAE's; identify barriers; assign TA's; develop monitoring program; ensure senior mana ement'line of sight' Engage Regulators 54 Engage Regulators regularly, above legal I AA COO AA CEO 1/4/11 114/11 1 No V MN.NOETICGROUP.COM PAGE 70 OF 73 IN -CONFIDENCE 0 0 0 • I reauirements Competence 55 Extend Competency Assessments to AA COO AA CEO 31/12/11 31/12/11 No CMS Phase 2 by Expert Advisors. See item 22 in Main Plan. other disciplines, including Management Multiple Drilling Operations Confirm adequate management and AA Drilling AA COO 31/12/10 31/12/10 No supervisory levels for 2011 drilling program Hold teambuilding sessions for drilling AA Drilling, AA COO 1/4/11 1/4/11 No department, contractors and sub- AA SSHE contractors 58 Extend scope of Drilling Peer Reviews HOP HRS 31/12/10 31/12/10 No Will be extended to other areas via PREP Action from Growth Enablers Workshop process. Drilling Peer Review held in BKK 5- 7110/10. 6/10/10 _ Critical, before drilling start Appendix 1 A Action Status Further Action Comment Activity Task 1 Review Well Construction Standards and development drilling programs to assess Done Follow up actions Done by AGR. List of 75 actions (this list). 0 ortunities for technical improvement. identified. "' a 2 Refer to need for peer reviews of final well design. Before drilling 4.1.2 3 3 Refer to Drill the Well on Paper session to be held to inform service providers. Before drilling 4.1.2 6 4 Align PTTEP AA drilling documents with PTTEP Corporate Drilling Management System Before drilling EDL review n/a 5 Additional information on well barrier policy and implementation when MODU is not in place. Before drilling TS, 5, Barrier Drilling Supervisors to review JSA's and be aware of content. During drilling Use 2 112 day SSHE Induction for Montara Project. 4.1.4 3 Ensure Rig Contractor applies and monitors JSA performance. During drilling 4.1.4 2 8 Undertake compliance PTTEP AA HSE and technical integrity reviews (by PTTEP Corporate), During drilling 4.1.2 3 9 Include authorities, responsibilities and accountabilities for each drilling ob. Before drilling 10 Include current logistics and materials management processes. Before drilling Review if attendance of third party contractors at HAZIDS is compulsory. Before drilling Amend PTTEP Safety Critical Service provider contracts (Rig, Boats, Helicopters, Testing) 12 Ensure Safety Case submission standards do not drop. Before drilling Ensure that PTTEP AA continue to involve themselves with the Rig Contractors SCR preparation process. Should reserve the make changes in the event that sub -standard work is proposed by the drilling contractor. Perhaps a suggestion to APPEA / NOPSA would be development of 'Best Practice' guidelines for all who submit these documents to follow. These may be floating around already however I have never seen them. Review rig operators SMS to ensure effective JSA is in place + covers 3rd party work on rig. Before drilling 4.1.4 2 14 Require that daily work instructions issued by Driller are Signed Off by Senior Toolpusher or During drilling Use 2 1/2 day SSHE Induction for Montara Project. 4.1.4 3 OIM. 15 Drilling Supervisors sign off any Operational Management of Change requests. During drilling Use 2 1/2 day SSHE Induction for Montara Project. 4.1.4 3 16 Daily conference call is held attended by core operations team on rig, in Darwin and Perth. During drilling Use 2 1/2 day SSHE Induction for Montara Project. 4.1.4 4 17 Third party audit is undertaken of safety critical components of Well Construction management During drilling S stem such as Management of Change. n/a 18 Implementation of MODU facility Safety Case revision requirements interfaces with PTTEP AA Before drilling Drilling Pro ram and WOMP 19 Periodic audits held of Rig Contractors JHA process. During drilling WCMS Changes made, pending PTTEP acceptance To be included in the DSDG submitted for review & acceptance - 4.1.4 3 9.7 & 14.9.3 covers 20 Documenting of reasons for selecting Drilling Supervisors and benchmark skills against Before drilling Include in Process/Framework as an action for the Well responsibilities and ensure further reference for each person employed is sourced. Construction Manager. 21 Include Frontline Safety Leadership for training for Drilling Supervisors. Before drilling Use 2 1/2 day SSHE Induction for Montara Project. 22 Ensure Materials and Logistics Supervisors have been trained and understand work processes. Before drilling 23 Induct Drilling Supervisors into WCMS before operations start. Before drilling Use 2 1/2 day SSHE Induction for Montara Project. 4.1.4 1 2 VWVW.NOETICGROUP.COM PAGE 71 OF 73 IN -CONFIDENCE I= Handover notes to be sent to Drilling Superintendent as well as oncoming Drilling Supervisor During drilling I the night before shift changeover. 1 hour long call to take place day before change over and 4.1.4 3 short face-to-face meeting on rig. 25 Ensure Rig Contractors have effective tracking system for Safety Observation Programs. During drilling DSDG submitted for review & acceptance - 10.3 covers 26 Drilling Supervisors to be trained in PTTEP AA HSE, hazard identification, well control. Before drilling DSDG submitted for review & acceptance - 19.3, 9.4 & 9.5 covers 27 As part of Management of Change process ensure each hazard is identified and Drilling During drilling Superintendent and Offshore each have opportunity to sign off on final risk assessment and 4 1 8 mitigations, and that this is checked during audits. Reference: Corporate SSHE Standard Management of Change. 28 Ensure ongoing risk management is done and this is audited. During drilling 4.1.7 2 29 Review drilling training matrix to cover third party and rig equipment. Review and update Before drilling DSDG submitted for review & acceptance - 10.4, &14.8 covers annuall . Reference: Corporate SSHE Standard Training and Competence. 30 Develop more detailed training matrix that identifies courses or experience requirements to Before drilling each well of well construction personnel. 31 Develop minimum training matrices for major contractors eg Rig Operators, Cementers. Before drilling 32 Develop an Operating Discipline Standard for supervisors. Before drilling 33 Set clear expectations regarding importance + effectiveness of supervision / oversight at rig Before drilling DSDG submitted for review & acceptance - propose that section 10 site. covers 34 Ensure manufacturer's instructions are received and available on site. During drilling DSDG submitted for review & acceptance - propose that section 10 covers 35 As built diagrams containing serial numbers of all components are provided on job completion. During drilling DSDG submitted for review & acceptance - propose that section 10 covers 36 Review communications processes and suggest improvements. Before drilling DSDG submitted for review & acceptance - propose that section 15.10 covers 37 Ensure Drilling Superintendent and Drilling Engineer cross check that the work being reported During drilling Use 2 1/2 day SSHE Induction for Montara Project. as having been done in the DDR and [ADC is what is said was done and any changes are DroDerly assessed by Management of Change process. 38 Include hold points in Drilling Program where work must cease until it has been signed off by During drilling DSDG submitted for review & acceptance-15.8.2 covers the Drilling Su t and ON that it has been completed. 39 Regular technical drilling audits occur during drilling campaign. During drilling DSDG submitted for review & acceptance - 10.8 covers / WCMS q 1.2 5 Changes made 40 Competency Matrix is developed for Drilling Manager, Drilling Superintendent, Drilling Engineer Before drilling and Drilling Supervisors. Reference: Corporate Competency Management System (HRS), Co rate SSHE Standard Training and Competence. 41 Persons employed for above roles are engaged in accordance with Competency Matrix. Before drilling 42 Infield verification of competency prior to undertaking role unsupervised the first time. This may During drilling be waived if person has worked for PTTEP AA before and Drilling Manager and COO agree. PTTEP Corporate to assist with performing competency assessment 43 Requirement to comply with Drilling Program is included in Drilling Supervisors Job Description. Before drilling DSDG submitted for review & acceptance -10.8 covers / WCMS Changes 44 Need to comply with JSA and MoC is included at inductions and on Drilling Supervisors course. Before drilling DSDG submitted for review & acceptance - 9.5 covers 4.1.4 4 45 Audit program to include checks that JSA and MoC procedures are being complied with. During drilling DSDG submitted for review & acceptance - 15.9.3 covers / WCMS Changes Include in JSA training examples of what constitutes safe work, Good Oilfield Practice. Before drilling Use 2 1/2 day SSHE Induction for Mortara Project. 47 Audits to be conducted for JSA's for all critical tasks and SimO s. During drilling DSDG submitted for review & acceptance - 10.6 covers 48 A materials list for all significant well control steps is available. During drilling 49 Production logistics system will apply to drilling. During drilling 4.1.5 3/4 50 Requirement for 2 proven well barriers to be included. During drilling 51 Review updated WCMS documents by third party or PTTEP Corporate. Before drilling TS, 5. Barrier 52 Schedule periodic project management audits. N/A This action applied when Drilling reported to Projects. 53 PTTEP Corporate to review roles, responsibilities and accountabilities for PTTEP AA CEO, Before drilling Project Team relevance now that Drilling is no longer in Projects ? HSE Drilling Team and Project Team. Update Job Descriptions based on above review. Before drilling J Any change in well control barriers is fully risk assessed and is submitted with MoC documents During drilling Use 2 1/2 day SSHE Induction for Montara Project. to the Re ulator with the application to change approval. Hold pre -spud meetingfor each swingshift to explain well design + reasonin Before /during 4.1.8 1/2/3 VWIAN.NOETICGROUP.COM PAGE 72 OF 73 IN -CONFIDENCE 0 0 0 0 0 0 I I drfllina Develop Drilling Program based on manufacturer's instructions for installation of any parts such that detailed use is described and there is no need to refer to manufacturers instructions later. Before drilling 4.1.4 1 Clearly identify requirements with respect to cementing well and if appropriate for the design and use of lead / tail cement. Before drilling Drilling to undertake handovers using Operations methodology. During drilling Use 2 1/2 day SSHE Induction for Montara Project. Documented records are kept of teleconferences between onshore / offshore. During drilling Use 2 1/2 day SSHE Induction for Montara Project. Barrier certifications are provided to Drilling Superintendent and Drilling Engineer for review. During drilling DSDG submitted for review & acceptance - 10.9 covers / WCMS Changes 4.1.4 4 Day to Day Instructions to Drillers are copied to the Drilling Supt, Drilling Manager + Drilling Eng. During drilling DSDG submitted for review & acceptance - 15.1 covers / WCMS Changes 4.1.4 6 Detailed minutes of any hazid are kept. Before / during drilling DSDG submitted for review & acceptance - 10.3 covers / WCMS Changes 4.1.4 3 All staff technical drilling personnel are required to undertake 20 hours of continuing professional development per year. Before / during drilling 4.1.7 1 /2/3 Contractors required to ensure management personnel have undergone a program similar to PTTEP and are required to work to work to PTTEP discipline operating standard. Before drilling Document the need for a repeat pressure test if the plugs do not bump or de -bump. During drilling Address a failure of floats during the course of cementing. During drilling Identify the relevance of other documents to well control e.g. contractors operations manual. Before drilling Include in template Drilling Programme / AGR / included in 1.3.1. Cementing Operations Guidelines created and submitted for review Drilling and suspension of wells at a platform prior to topsides installation. During drilling Well control during batched tieback of casing strings on different wells. During drilling TS, 5, Barrier Develop WOMP's so that they are stand alone documents and there is no need to refer to any other document when reading it and that they include manufacturer's instructions Before drilling I TS. 5, Barrier Review formatting of documents associated with the Management System Before drilling 4.1.2 E Develop a new desk guide for Drilling Supervisors. Before drilling Develop Cementing Manual covering cementing process, what can go wrong + what to do. Before drilling Include reference to investigating emergency resources (rigs etc) in the region prior to starting drilling Before drilling W''JS Training + Competence Audit Comms / Supervision Drilling Documents WAW.NOETICGROUP.COM PAGE 73 OF 73 IN -CONFIDENCE CJ Statement by the Minister for Resources and Energy, the Hon Martin Ferguson AM, MP The Report of the Independent Review of the PTTEP Australasia (Ashmore -Cartier) Pty Ltd Montara Action Plan 0 4 February 2011 Introduction 1. In November 2010, I addressed the Parliament regarding the Report of the Montara Commission of Inquiry. The Report concluded that PTTEP Australasia (Ashmore -Cartier) Pty Ltd did not observe sensible oil field practices at the Montara oil field and that the 'widespread and systemic' shortcomings in PTTEP Australasia's procedures were a direct cause of the loss of well control which commenced on 21 August 2009. • 2. The Report also found that well control practices approved by the • regulator would have been sufficient to prevent the loss of well control, however PTTEP Australasia did not adhere to these practices or its own well construction standards. 3. During the course of the Commission, PTTEP Australasia's parent company PTTEP developed the Montara Action Plan (the Action Plan), which detailed the changes that had to occur if PTTEP Australasia's operations were to meet industry best practice standards and how those changes could be achieved. Importantly, the Commissioner of the Montara Inquiry, Mr David Borthwick, commented favourably on this Action Plan. 4. Commissioner Borthwick recommended that I undertake a review • of PTTEP Australasia's licence to operate at the Montara oil field. The Commissioner further recommended that, as the mechanism for instigating this review, I issue a `show cause' notice to PTTEP Australasia, pursuant to the cancellation of titles sections of the Offshore Petroleum and Greenhouse Gas Storage Act 2006. 5. I accepted the Commissioner's recommendation to review PTTEP Australasia's licence to operate. 6. However, I also determined that a review of PTTEP Australasia's licence to operate which was restricted to its operations at the Montara field would be insufficient in light of the company's other operations in Australia. • FA • 7. I directed my Department to instigate an independent review of the Montara Action Plan — a review that would provide me with advice on whether the Action Plan, when implemented, would ensure that the operations and procedures of PTTEP Australasia (a term which hereafter includes subsidiaries and associated entities with Australian operations) meet industry best practice standards. 8. I noted that the outcome of this process would be a central part of my consideration as to whether to issue a `show cause' notice which might lead to the cancellation of all of PTTEP Australasia's petroleum titles. 9. I also committed to making the Independent Review Report and is my response to it public within seven days of receiving advice from my Department. Independent Review Report: "Review ofPTTEP Australasia's Response to the Montara Blowout " 1 O.Today, I am pleased to deliver on that commitment and present to the Parliament the Report of the Independent Review of the PTTEP Australasia Montara Action Plan. 11.The Independent Review, undertaken by industry experts, examined both technical and governance issues. It examined key documentation and engaged directly with personnel from both PTTEP Australasia and its parent company, PTTEP. • 12.The Independent Review concludes that the Montara Action Plan • effectively responds to the issues identified by the Montara Commission of Inquiry and sets PTTEP Australasia on the path to achieving industry best practice standards for both good oil field practice and good governance. 13.I can inform the Parliament that PTTEP has already initiated substantial changes to the leadership roles and structures at PTTEP Australasia. PTTEP has advised that further changes will be implemented and formally announced during the first quarter of 2011. 14.However, the Independent Review also makes clear that the success of PTTEP Australasia's program for change will depend • entirely on the quality of the execution of the Action Plan and recommends an 18 month monitoring program to ensure the Action Plan is properly implemented. 15.Based on the Independent Review's findings and the recommendation of my Department, I have decided not to issue a `show cause' notice to PTTEP Australasia at this time. 16.This decision is conditional on PTTEP and PTTEP Australasia entering into a binding Deed of Agreement with the Australian Government in which it is agreed that the Montara Action Plan will be implemented in full in respect of all of PTTEP Australasia's operations, and that this implementation will be subject to an 18 month monitoring program undertaken by independent experts • appointed by my Department. 4 • 17.However, should the Montara Action Plan not be fully completed and properly implemented, or should any other concerns arise that warrant it, I am able to issue a `show cause' notice to PTTEP Australasia at any time. 18.PTTEP will also be subject to an additional set of conditions on the renewal or future granting of offshore petroleum title applications in Australia. These conditions will ensure that good oil field and governance practices are applied by the company across its Australian operations. 19.The Independent Review Report also makes several recommendations for the offshore petroleum industry to consider. • My Department is now working with the National Offshore Petroleum Safety Authority (NOPSA) and industry through the Australian Petroleum Production and Exploration Association (APPEA) to progress these recommendations. 20. Shutting down Australia's offshore petroleum industry is not an option. It is an industry too important to our economy given our dependence on oil, and our ever worsening trade deficit in this commodity. 21. But it is an industry that must operate safely, an industry that must continuously improve and strengthen its systems and processes to mitigate to the greatest extent possible the inherent risks in its operations. • W 22. We are learning the lessons from past incidents both here and 0 overseas to put in place a world -class regulatory regime and to make sure the companies operating off our shores comply with that regime to the letter. 23.This is what the Government is doing in implementing the recommendations of the Montara Report, assessing the findings of the US National Commission into Deepwater Horizon and establishing a single national offshore petroleum regulator. 24.Collectively, Government, industry, operators and regulators must embrace a culture of the highest safety standards and good oil field practice, with oversight through effective corporate governance arrangements. 0 25.This is what PTTEP Australasia is doing and we will make sure they continue to do it. 26.Industry understands that in order to maintain its social licence to operate it must put the safety of workers and the environment first as part of the responsible development of our natural resources, and that this is something Government will hold them to. 27.I commend the "Review of PTTEP Australasia's Response to the Montara Blowout" to the Senate. 1] P� Department of Resources, Energy and Tourism Deed of Agreement Commonwealth of Australia, as represented by the Department of Resources, Energy and Tourism (Commonwealth) AND PTT Exploration and Production Public Company Limited (PTTEP) on behalf of its Australian subsidiaries: PTTEP Australia Pty Ltd (ABN 87 127 997 684) PTTEP Australia Offshore Pty Ltd (ABN 96 127 997 719) PTTEP Australia Perth Pty Ltd (ABN 74 134 686 525) PTTEP Australia Timor Sea Pty Ltd (ABN 70 064 126 138) PTTEP Australasia (Ashmore Cartier) Pty Ltd (ABN 27 004 210 164) PTTEP Australia Browse Basin Pty Ltd (ABN 78 134 686 543) PTTEP Australasia Pty Ltd (ABN 12 115 470 552) PTTEP Australasia (Petroleum) Pty Ltd (ABN 95 088 553 075) PTTEP Australasia (Operations) Pty Ltd (ABN 72 009 785 326) • Details Date 22nd February 2011 day month year Parties Name The Commonwealth of Australia as represented by the Department of Resources, Energy and Tourism ABN 46 252 861 927 Short form name Commonwealth Address details Tania Constable, Head of Division, Resources GPO Box 1564 Canberra ACT 2601 Level 51 Allara Street Canberra City ACT 2610 Name PTT Exploration and Production Public Company Limited • ABN n/a Short form name PTTEP Address details David John, Security, Safety, Health & Environment Adviser PTT Exploration and Production Public Company Limited Energy Complex Building A 6th Floor & l9th - 36th Floor 555/1 Vibhavadi Rangsit Road Chatuchak, Chatuchak Bangkok 10900 Thailand Background A In August 2009, there was a blowout at the Montara wellhead platform in the Timor Sea, off the northern coast of Western Australia. B At the time of the blowout, PTTEP's Australian subsidiary, PTTEP Australasia (Ashmore Cartier) Ply Ltd (PTTEP AA) was the licence holder for the Montara oil field. C Following receipt of a report from the Montara Commission of Inquiry, PTTEP AA submitted the Montara Action Plan to the Minister for Resources and Energy (the Minister), which outlines a strategy for PTTEP AA to achieve industry standards for both good oilfield practice and good governance. D The Commonwealth contracted Noetic Solutions Ply Limited (Noetic) to conduct an independent review of the Montara Action Plan. Based on recommendations provided by page 2 • Noetic, PTTEP AA has since developed a more comprehensive Montara Action Plan that has been endorsed by Noetic. By entering into this Deed, PTTEP has, on behalf of its Australian subsidiaries, agreed to implement the Montara Action Plan and to comply with a monitoring program that will be undertaken by the Commonwealth. This Deed cannot fetter the Minister's discretion under the Act. 0 page 3 • reed terms 1. Defined terms and interpretation 1.1 In this Deed, unless the contrary intention appears: (a) Act means the Offshore Petroleum and Greenhouse Gas Storage Act 2006, including any regulations or instruments made under the Act; (b) Action Plan means revision 16 of the PTTEP AA Montara Action Plan or any subsequent revision as agreed to by the Commonwealth in accordance with clause 2.2. Revision 16 of the Montara Action Plan is at Attachment A of this Deed; (c) Additional Actions means additional actions to be conducted by PTTEP that were identified by the independent review by Noetic Solutions Pty Ltd of the Montara Action Plan, as outlined in Attachment B; (d) Commonwealth means the Commonwealth of Australia, as represented by the Department of Resources, Energy and Tourism; (e) Deed means this deed of agreement, including any attachments, annexures or schedules; (f) Licence includes a petroleum exploration permit, petroleum retention lease and petroleum production licence or other licence granted pursuant to the Act. (g) Minister means the Commonwealth Minister for Resources and Energy; • (h) Monitoring Program means the monitoring program at Attachment C to this Deed; (i) PTTEP means PTT Exploration and Production Public Company Limited and its Australian subsidiaries (an outline of the corporate group is contained in Attachment D); and (j) PTTEP AA means PTTEP Australasia (Ashmore Cartier) Ply Ltd. 2. Action Plan and Additional Actions 2.1 PTTEP must, to the Commonwealth's satisfaction, implement and ensure that PTTEP AA, and all Australian subsidiaries of PTTEP, implement across the entire PTTEP corporate group (excluding subsidiaries of PTTEP doing business outside Australia): (a) the Action Plan, in accordance with Attachment A to this Deed; and (b) the Additional Actions in accordance with the Attachment B to this Deed, or where the Action Plan has been superseded or the Additional Actions are incorporated in a revised Action Plan, the revised Action Plan. page 4 is u 2.2 Any revision to the Action Plan which involves the amendment of action items or removal of action items requires the written approval of the Commonwealth. The Commonwealth may, in its absolute discretion, approve or not approve any such revision. 3. Monitoring Activities 3.1 The Monitoring Program will commence on the date of commencement of this Deed. 3.2 PTTEP and all of PTTEP's subsidiaries, to the extent that they are holders of a Licence under the Act, must, to the Commonwealth's satisfaction provide full cooperation with monitoring activities conducted by the Commonwealth, or a delegate of the Commonwealth, in accordance with the Monitoring Program, including any investigations conducted by, or on behalf of, the Commonwealth relating to the compliance with this Deed by PTTEP. 3.3 PTTEP acknowledges that the Commonwealth may take steps incidental to the monitoring powers in the Act, which may include powers to: (a) enter and search facilities, premises or vessels; (b) inspect and make copies of documents; (c) take measurements and conduct tests; (d) take photographs, make video recordings, and make sketches; (e) inspect the seabed and subsoil in the vicinity of a facility; (f) operate and secure electronic equipment to access data; (g) copy and take data; and • (h) take equipment, disks, tapes or devices. 4. Reports 4.1 PTTEP must, in accordance with the Monitoring Program: (a) provide written monthly reports to the Commonwealth; and (b) undertake quarterly face to face briefings with the Commonwealth. 4.2 PTTEP must, upon request, provide ad hoc reports to the Commonwealth in relation to the implementation of the Action Plan in accordance with the Commonwealth's requirements. 5. Term of Deed 5.1 This Deed will commence on 22ntl February 2011 and will end on 21" October 2012 unless terminated earlier in accordance with clause 14. 6. Deed to be made public 6.1 PTTEP agrees that the Commonwealth may, in its sole discretion, make this Deed publicly available at any time. 7. Publicity 7.1 PTTEP must not make any public announcements in connection with this Deed without the Commonwealth's approval, except to the extent required by law or the rules of the Stock Exchange of Thailand, in which case PTTEP must provide prior written notice to the Commonwealth and to the extent that it is possible to do so, take into account any comments 0 page 5 0 provided by the Commonwealth before making a public announcement to the Stock Exchange of Thailand. This clause does not extend to public announcements about the attachments of this Deed. 8. Assignment and Novation 8.1 A party may not assign or novate its rights and obligations under this Deed. 9. Variation 9.1 No Deed or understanding varying or extending this Deed is legally binding upon either party unless the Deed or understanding is in writing and signed by both parties. 10. Waiver 10.1 Waiver of any provision of, or right under, this Deed: (a) must be in writing signed by the party entitled to the benefit of that provision or right; and (b) is effective only to the extent set out in any written waiver. 11. Minister's discretion is not fettered 11.1 For the avoidance of doubt, compliance with this Deed does not limit the Minister's discretion under section 275 of the Act or under any other section of the Act. 12. Indemnity • 12.1 PTTEP will at all times indemnify, hold harmless and defend the Commonwealth, its officers and employees from and against any loss or liability, including: (a) loss of, or damage to, property of the Commonwealth; (b) claims by any person in respect of personal injury or death; (c) claims by any person in respect of loss of, or damage to, any property; and (d) costs and expenses including the costs of defending or settling any claim referred to in this clause 12, arising out of or as a consequence of any breach of this Deed by PTTEP, but only to the extent to which PTTEP or its personnel or subcontractor are liable in negligence in respect of any such loss, damage, costs or expenses. page 6 0 • 12.2 PTTEP's liability to indemnify those indemnified will be reduced proportionally to the extent that any negligent act or omission of those indemnified contributed to the loss, damage, costs or expenses. 13. Dispute Resolution 13.1 In the event that a dispute arises under this Deed, each party must, in the first instance, use its reasonable efforts to resolve the dispute by direct negotiation before commencing any court proceedings or other dispute resolution proceedings. Negotiations should be conducted by the Secretary of the Department of Resources, Energy and Tourism and the Chief Executive Officer of PTTEP, or where agreed to by the parties, their nominees. 14. Termination 14.1 Without limiting any other rights or remedies the Commonwealth may have against PTTEP, the Commonwealth may, at any time, by notice, terminate this Deed. 14.2 Without limiting the generality of clause 14.1 of this Deed, the Commonwealth may exercise its right to terminate this Deed if: (a) PTTEP breaches any provision of this Deed; or (b) the Commonwealth Is satisfied that any statement made by PTTEP in connection with the Action Plan, Additional Actions, Monitoring Plan or this Deed is materially incorrect, materially incomplete, false or misleading in any way. 15. Governing law and jurisdiction • 15.1 This Deed is governed by the law of the Australian Capital Territory and each party irrevocably submits to the non-exclusive jurisdiction of the courts of the Australian Capital Territory. 0 page 7 Signing page EXECUTED as a deed. Signed for and on behalf of the Commonwealth of Australia as represented by the Department of Resources, Energy and Tourism by its duly organised delegate: Signature of delegate DREW CLARKE Name of delegate (print) SECRETARY OF THE DEPARTMENT OF RESOURCES, ENERGY AND TOURISM Position of delegate (print) MARL IN htRGUSUN Name of witness (print) MINISTER FOR RESOURCES AND ENERGY Position of witness (print) • • page 8 9 0 • Executed by PTT Exploration and Production Public Company Limited by its authorised representatives, on behalf of its subsidiaries: PTTEP Australia Pty Ltd (ABN 87 127 997 684) PTTEP Australia Offshore Pty Ltd (ABN 96 127 997 719) PTTEP Australia Perth Pty Ltd (ABN 74 134 686 525) PTTEP Australia Timor Sea Pty Ltd (ABN 70 064 126 138) PTTEP Australasia (Ashmore Cartier) Pty Ltd (ABN 27 004 210 164) PTTEP Australia Browse Basin Pty Ltd (ABN 78134 686 543) PTTEP Australasia Pty Ltd (ABN 12115 470 552) PTTEP Australasia (Petroleum) Pty Ltd (ABN 95 088 553 075) PTTEP Australasia (Operations) Pty Ltd (ABN 72 009 786 326) Signat re of Ex ti a Vice President International Assets of PTT Exploration and Production Public Company Limited SOMPORN VONGVUTHIPORNCHAI Name of Executive Vice President International Assets of PTT Exploration and Production Public Company Limited (print) �� ffll� Signature of President and Chief Executive Officer of PTT Exploration and Production Public Company Limited ANON SIWSAENGTAKS1N Name of President and Chief Executive Officer of PTT Exploration and Production Public Company Limited (print) page 9 • • • A PTTEP AA Montara Action Plan ATTACHMENT A PTTEPAA Montara.4ction Plan (Rev 16) (2 Decen:her 2010) Provided to the Department post completion of the Report of the Independent Review of the PTTEPAuvtralavia Montara Action Plan undertaken by Noetic Solutions Pty Ltd. lrl'n�M Clarify Well Barrier Integrity 1 Review and confirm status of existing AA Drilling, AA COO BKK 30/6/10 Complete Safety Case risk Program finalised and regulatory approvals well barriers AGR Drilling assessment 1 obtained. Completed 27/7/10, 2 Prepare well barrier integrity test AA Drilling, AA COO BKK 30!6110 Complete Safety Case risk Program prepared and reviewed by EDL. procedures / plan. AGR Drilling assessment Completed. This campaign was safely and successfully carried out offshore ending on 26/7110. The 3 Prepare contingency plans should AA Drilling, 'AA COO BKK 3016110 Complete Safety Case risk Program prepared and reviewed by EDL. integrity tests prove inconclusive or AGR Drilling assessment Completed. status of all wells was determined. Pressure negative. was detected below the PCCC on 4 out of 5 wells. Contingency caps were fitted to these. 4 Execute well barrier integrity tests AA Drilling AA COO BKK 30,16110 Complete I Safety Case risk Completed 26/7110. offshore. I Drilling assessment See Montara Well Verification Report. 3.6.10 oversight t 5 Carry out any remedial work required as AA Drilling AA COO BKK 3016110 Complete. Safety Case risk Works carried out as part of 1.4 above. per contingency plan Drilling assessment j Completed. oversight AA Drilling Management System (see Appendix 1) Complete an independent review of the AGR AA COO AA Drilling, 30!6110 Complete Part of review is Completed by AGR. See report Montara H1 WCMF and WCS BKK to ensure no risks ST1 Well Release Incident- Report on Drilling increased ! actions to prevent recurrence, rev 1, 16010. introduced. This contained 75 recommendations that became Appendix 1 of the Montara Action - - Plan. -1 Draft DMS documents AGR AA COO 3016110 Complete No Documents were initially drafted by AGR. Following review by EDL and SBC it was decided that further amendments were required to produce the following documents: Drilling Management System, Well Delivery Process, Well Design Guideline, Well Control Manual, Driling Operations Manual. This work is by SBC as part of the Drilling Management System, project. 23/11/10 - all drafts issued for review. Compare OMS with PTTEP Corporate BKK Drilling AA COO 3117/10 Complete No Completed 12/11/10 in Phase I DMS by References: PTTEP Drilling Management requirements and Good Oilfield Practice. _ SBC. System, PTTEP-DMS-001 Rev C. Well Operations Manual, PTTEP-WOM-002 Rev C Develop stand alone Well Operations AA Drilling AA COO As As No Part of DMS deliverables by SBC. Ongoing. Clarify with regulator preferred format Management Plans. required required Develop PTTEP AA speck Blowout AA Drilling AA COO AA Drilling, 1/4111 114/11 No Partly in DMS deliverables by SBC. Ensure in line with EDL BCP being prepared Contingency Plan BKK by Boots + Coots. Drilling Hold teambuilding sessions for drilling AA Drilling AA COO 1/4/11 1/4/11 No Partly covered in DMS by SBC. Drill the Well department, contractors and sub- on Paper session with rig crews + 3rd party contractors contractors. 12 Insert requirement in Contracts that AA Drilling AA COO 1/4/11 1/4111 No Documented in DOM as one of the key Next drilling campaign planned for April 2011. Contractor reports on work done must be responsibilities of Drilling Supervisor and sent to PTTEP AA Drilling on / offshore. Superintendent. 13 Review contracts to make sure there is a AA Drilling, AA COO 1/4111 114111 No Drilling Management System Phase 1 and 2 Next drilling campaign planned for April 2D11. requirement for 3rd party personnel to Legal with Schlumberger Business Consulting. complete training as per their Training Also Vendor Management under Matrices which should be similar to Management System by SBC.Section 8.7 of PTTEP AA CMS and DMS. Drilling Contract. SSHE Improvements' 14 Establish PTTEP AA Corporate SSHE AA SSHE AA CEO 31/12/10 31/12/10 No 5111/10 Charter drafted. committee 15 Regular SSHE information sharing AA SSHE AA CEO 31/12110 31/12110 No To be done. note combined with relevant SSHE elements Identified in the Supplementary Plan supporting REV 14 of the Montara Action Plan • • • 16 aI-A meeting 16 Define and implement SSHE Leadership AA SSHE AA CEO CSH 1/4111 114111 No Led by AA with SBC building training into APPEA Stand Up For Safety; UK HSE Program management interfaces. SBC MS ProjecL Leadership for Major Hazard Industries Define audit and monitoring philosophy AA SSHE AA COO 31/12/10 31/12/10 No MS deliverable by SBC. SBC MS project has 3 main elements: a) business maps and operating model, b) leading indicators, c) employee satisfaction + SSHE surveys. See SBC proposal. Establish audit plan and monitoring AA SSHE AA COO 114/11 1/4/11 No MS deliverable by SBC. Annual audit plan exists; monitoring to be program. developed. Drilling first 19 Ensure workforce involvement in DMS AA Drilling AA COO 114/11 11011 No To be done. development, Safety Cases etc 20 Re -start BKK - Perth SSHE MS AA SSHE CSH, AA CSH 31/7/11 31/7/11 No Project Plan issued 2/12/10. DD + DJ met integration COO 1/12/10 to discuss. 21 Undertake Safety Climate Survey AA SSHE AA COO CSH 31/12/11 31/12/11 No Part of DMS deliverables by SBC. Survey drafted. Start on 3112/10. - 22 Extend BBS training to PTTEP AA CSH/O COO 31/12/11 31/12/11 No Base on existing BBS course by CSH/O. 23 Update AA investigation protocols to AA HSE AA COO 3016110 Complete No Done, confirmed by DD 1/12110. require PTTEP Corporate or independent expert to investigate any well control incidents.. Implement MAE's prevention program for AA Drilling AA COO CSH/I 1/4111 114/11 No Link in with 3rd party MAE program Identify MAE's; identify barriers; assign TA's; dolling. findings/KPI's to establish Line of Sight with develop monitoring program; ensure senior SSHE. PA, DO and DJ discussed 29/11/10. management "line of sight" 25 Implement MAE prevention program for AA SSHE + AA COO CSHA 31/12/11 31/12/11 No Link in with 3rd party MAE program Identify MAE's: identify barriers; assign TA's; other disciplines others findings/KPI's to establish Line of Sight with develop monitoring program; ensure senior SSHE. SBC MS project. management "line of sight" 26 Ensure that realities of drilling activities AA Drilling, AA COO 1/3111 1/3/11 No To be done. As part of hazards identification Ensure personnel familiar with MAE barriers are accounted for in Major Accident AA HSE studies for Safety Case submission. e.g. bow ties. Event identification and ORA in Safety Cases. Regulatory /Industry Liaison 3S 27 Lobby industry to approach NOPSA to AA CEO + AA COO 31/12/10 31/12/11 No APPEA Drilling & Completions steering Ongoing. develop a policy which requires COO committee established. Emergency collaborative engagement + consultation Response and Oil Sol Sub Committees during emergency, established. 28 Participate in industry response BKK Drilling, AA COO 31/12/10 31/12/11 No PTTEP AA personnel participating in APPEA Should also refer to need to improve Well (particularly lessons learned from AGR initiatives. PTTEP BKK personnel will Control Certification training courses. Montara / Macondo). Take account of participate in OGP Oil Industry Response learnings in drilling, emergency Group. response, spill response. 29 Engage Regulators regularly, above legal AA COO AA CEO 114111 1/4/11 No In progress. Meet WA and NT re WOMP's requirements. w/o 6/12/10. 30 Engage with training providers to AA COO AA COO 31112/10 31/12/10 No To be done. Will be part of APPEA process see 5.1 broaden well control course scope. Organisation and Personnel 31 Demobilise, or temporarily assign for AA COO AA COO 3016/10 Complete No Completed 30/6H0: Last contractor knowledge continuity, contracted Dulling demobilised personnel from Perth office. 32 Undertake a review of AA drilling AA Drilling AA COO EDL, COO 31/9/10 Complete No Typical organisations in other operators organisation, taking in to account 2011 reviewed. Discussed and agreed. 2 work plans. Managers under Well Construction Manager. Complete. 33 Develop a Recruitment Tool AA Drilling, i AA COO EDL, COO 31/10/10 Complete No 2/11/10. Work done by SBC (Competency AA COO I Management System Phase 1). Complete. Recruit AA Drilling personnel. AA Drilling AA COO 31/12/10 31/12/10 No 2010 recruitment completed. More in 2011. Confine adequate management and AA Drilling AA COO 31/12/10 Complete No Typical organisations in other operators supervisory levels for 2011 drilling reviewed. Discussed and agreed. 2 program Managers under Well Construction Manager. Complete 1112/10. 36 Review complete organisation of PTTEP AA CEO, AA INA HOP 115/11 1/5/11 No High level organisation review and Operating Model meeting 7110/10. AA. Make recommendations and COO recommendations in MS deliverables by implement changes required including SBC. personnel. 37 Review SSHE organisation in PTTEP AA AA SSHE, AA COO CSH 31/12/10 31/12/10 No In progress. See CSH memo Note: recruitment of SSHE Drilling Advisor in (report to CEO) AA CEO PTTEP130/M231/2010. progress. Start expected Jan 2011. • • • V� Training and Competence 38 Review technical and SSHE competency HRS. CSH, AA COO 114111 1/4/11 No Part of CMS deliverables by SBC. Self References: Corporate SSHE Standard matrices for drilling personnel. BKK Drilling, assessments started end Nov 20% SSHE Training and Competence; Corporate PTTEP AA Drilling JCP in development. AA Competency Competency Management System. Coordinator appointed. 39 Extend review of technical and SSHE HRS, CSH, AA COO 1/11111 31/12/11 No To be done. competency matrices for relevant PTTEP AA disciplines and management. Undertake competency assessments, PTTEP AA AA COO 1/4111 1/4/11 No Part of CMS deliverables by SBC in TCL Any Gaps identified to be input to 7A, with relevant disciplines from PTTEP HQ. Line implementation. Self assessments started Management end Nov 2010. 41 Review and improve technical and SSHE HRS, CSH, AA COO 114/11 1/4/11 No Part of CMS deliverables by SBC, training matrices for Drilling. BKK Drilling, development module. PTTEP AA 42 Review and improve technical and SSHE HRS, CSH, AA COO 1/11/11 31/12/11 No To be done. training matrices for other disciplines PTTEP AA 43 identify and provide training courses HRS. CSH, AA COO 114/11 114111 No To be done. The 2 1/2 day Safety Induction developed for required. BKK Drilling, Montana Project can be used for training PTTEP AA Drilling personnel, with some adjustments. i Environmental 44 Revise Oil Spill Contingency Plan AA SSHE AA COO 31/8/10 31/12/10 No Incorporate leamings from Inquiry, discuss Review of emergencycrisis response in with AMSA PTTEP AA 22-2317/10 will identify issues. Input from Dr Wardrop received. Internal workshop 9th August 45 Assess Oil Spill Equipment / Chemical AA SSHE AA COO 31/8110 31/12/10 No With AMOSC and APPEA, Drilling support Will be part of APPEA process see 5.1 availability package being developed - booms. absorbent booms, dispersant PPE. 46 Develop sampling packs at operational AA SSHE AA COO 3118110 31/12/10 No In progress. locations 1 training gaps re Oil Spill AASSHE AA COO 3118/10 31/12/10 No In progress. Oil Spill Plan to be finalised first. Contingency Plan F4947Identify Review existing base line data available AASSHE AA COO 31/8/10 31/12110 No In progress, for locations associated with our operations Develop fist of possible studies required AA SSHE AA COO 31/8110 Complete No Complete 1/12110. List developed post- Would need Government approval restudy post spill, suitable providers ' Montara will be used for future reference. scope in the event of a spill in any case. Work by APPEA ongoing re Browse Basin initiative. Governance / Oversight! Lessons Learned 50 Ensure appropriate level of Corporate EDL, AA AA COO 31110/11 Complete No Drilling relations Perth - BKK discussed To be cross refernced in DMS documents. oversight of PTTEP AA Drilling activities. Drilling 4/8/10 and agreed. Complete. 51 Review role of PTTEP AA Board of Board CEO 31/12/10 31/12/10 No In progress. Advisory Board recommended. Action from Growth Enablers Workshop Directors Chairman 7110110. New Chairman announced. 52 Develop overarching plan covering CK, DK INA Steering 31/10/10 31/10/10 No Strategy and Execution Plan drafted. Link to PTTEP AA initiatives Ctte SBC DMS workstream. 53 Develop Montara Action Plan narrative. DJ Steering Steering 31/10/10 Complete No Complete. Issued 1112/10. Cttee cde 54 Ensure appropriate level of Corporate AA CEO INA 3115/11 3115/11 No Growth Enablers Workshop 7/10110. SSHE oversight of PTTEP AA activities. MS Integration already started. Drafted generally by defining governance Working Relations document can be used as relationship between Perth - Bangkok. a reference. Part of SBC MS project, Develop and conduct plan of Corporate CSH INA 114111 114111 No Audits planned pre -drilling and during drilling. Reference' Corporate SSHE Standard Audit technical and SSHE MS audits. Top Management Visit planned during and Review, Operations and Project Technical drilling. To be executed. Need to plan further Review documents. SSHE MS, CMS, DMS and MS audits in Annual Plans. 56 Develop and implement lessons learned CSH, EDL, CEO 31/12/10 31/12/11 Review Corporate Lessons Learned file drafted and from Montara at Corporate level. INA under discussion with relevant departments. 57 Extend scope of Dulling Peer Reviews HOP HRS 31/12/10 Complete No Has been extended via PREP process Action from Growth Enablers Workshop (Project Risk Management, PREP-GM-07). ; 7110/10. Drilling Peer Review held in BKK 5- 6/10/10. PREP Phase 3A Peer Review and 0 0 0 Implementation 58 Establish a senior management INA + AA CEO committee to oversee implementation of CEO this plan. Members from PTTEP AA and PTTEP HO. 59 Appoint an Implementation Manager to INA + AA CEO ensure this plan is followed -up in agreed CEO I timeframes and actions are sustainable. Shaded Cell = Action Closed. Critical, before drilling start up Change Number of Actions 59 0 Completed 19 I + 4 In progress 33 .4 To be done I 7 Behind Target 0 7 30/6/10 1 Complete I No 30/6/10 1 Complete I No 1 completed. 6 revised target date Hazed, Bangkok, 22-25/11/10. Committee established. Regular meetings Scope of Committee was increased 17/11/10 taking place. I to cover Strategy and Execution Plan work. Done 28/5/10. DJ appointed. PTPFP AA .tiWonrara Acion Plan (Rev 16) (2 December 2010) —Appendix 1 Action ' # Revise drilling documents: Content, �---.Status Action Comment � Comment - Activity Task Further FA formatting and alignment with Corporate DMS 1 Review Well Construction Standards and Done f Follow up Done byAGR. List cf 75 actions (this � DMS - development drilling programs to assess actions list) n/a opportunities for technical improvement, identified 4 Align PTTEP AA drilling documents with PTTEP Before EDL review n!a DMS Corporate Drilling Management System drilling 72 Review formatting of documents associated with the I Before 4 1,2 £ I ")MG Management System j drdling 51 Review updated WCti1S documents by third party or ; Before TS, 5, DMS,IDP3 PTTEP Corporate, drdlina Barrier 5o Requirement for 2 proven well barriers to be WES 5.3 During WE included. drilling 5 Additional information on well barrier policy and WES 5.3 Before TS, 5, WES RUIN" implementation when MODU is not in place. drilling Barrier s, 56 Clearly identify requirements with respect to WES 10.4 Before WES cementing well and if appropriate for the design and drilling use of lead / tail cement. 74 Develop Cementing Manual covering cementing WES 10.5 Before WESIDOM process, what can go wrong +what to do. drillino fi 66 Document the need for a repeat pressure test if the Why? Suggest During WESIDOM Does not make sense: Casing cement plugs do not bump or de -bump. we drop drillino should always be pressure tested regardless of plug bump or de -bump - suggest we drop 67 Address a failure of floats during the course of WES 10-5 During WESMOM .� cementing. drilling 69 Drilling and suspension of wells at a platform prior to WES 5." During WESlDOM topsides installation. drilling C7 55 Any change in well control barriers is fully risk assessed and is submitted with MoC documents to the Regulator with the application to change approval. 71 Develop WOMP's so that they are stand alone documents and there is no need to refer to any other document when reading it and that they include manufacturer's instructions 57 1 Develop Drilling Program based on manufacturer's instructions for installation of any parts such that detailed use is described and there is no need to refer to manufacturers instructions later, ='2 Refer to need for peer reviews of final well design. Refer to Drill the Well on Paper session to be held to inform service providers. 52 j Schedule periodic project management audits Before drilling i Defc re l drilling drilling NIA DP3 �- 4.14. 1 - 4.1.2 3 - - DP3 4.tz 6 i This action applied v:hen Drilling reported to Projects, 34 • Ensure manufacturer's nstNCJons are received and During DSDG sub°nitted for review & available on site. drilling acceptance- propose that section 10 covers 35 As built diagrams containing serial numbers of all During DSDG submitted for review & components are provided on job completion. drilling acceptance - propose that section 10 covers 32 Develop an Operating Discipline Standard for Before supervisors. drilling 73 Develop a new desk guide for Drilling Supervisors. Before drilling 14 Require that daily work instructions issued by Driller During Use 2 112 day SSHE Induction for are Signed Off by Senior Toolpusher or OIM. drilling Montara Project. 15 Drilling Supervisors sign off any Operational During Use 2 112 day SSHE Induction for Management of Change requests. drilling Montara Project. 16 Daily conference Call is held attended by core During Use 2 1/2 day SSHE Induction for operations team on rig, in Darwin and Perth. drilling Montara Project. DOM DOM DOM 4.1.4 3 DOM 4.1.4 3 DOM 4.1.4 4 24 Handover notes to be sent to Dolling Superintendent During as well as oncoming Drilling Supervisor the night drilling before shift changeover. 1 hour long call to take 4.1.4 3 place day before change over and short face-to-face meeting on rig. 37 Ensure Drilling Superintendent and Drilling Engineer During Use 2 1/2 day SSHE Induction for cross check that the work being reported as having drilling Mortara Project. been done in the DDR and IADC is what is said was done and any changes are properly assessed by Management of Change process. t 38 Include hold points in Drilling Program where work During DSDG submitted for review & must cease until it has been signed off by the Drilling drilling acceptance - t 5.8.2 covers Supt and ON that it has been completed. 62 Day to Day Instructions to Drillers are copied to the During DSDG submitted for review & Drilling Supt, Drilling Manager + Drilling Eng. drilling acceptance - 15.1 covers / WCMS 4.1.4 6 Changes 56 Hold pre -spud meeting for each swing shift to explain Before / well design + reasoning. during 41.8 1/2/3 drilling 59 Drilling to undertake handovers using Operations During Use 2 1/2 day SSHE Induction for methodology. drilling Mortara Project. 6D Documented records are kept of teleconferences During Use 2 1/2 day SSHE Induction for between onshore / offshore. drilling Montara Project. 6 Drilling Supervisors to review JSA's and be aware of During Use 2 1/2 day SSHE Induction for 4.1.4 3 content. drilling Mortara Project. 33 Set clear expectations regarding importance + Before DSDG submitted for review & effectiveness of supervision / oversight at rig site. drilling acceptance - propose that section 10 covers 75 Include reference to investigating emergency Before resources (rigs etc) in the region prior to starting drilling drilling 61 Barrier certifications are provided to Drilling During DSDG submitted for review & Superintendent and Drilling Engineer for review. drilling acceptance - 10.9 covers / WCMS 4.1.4 4 I Changes 48 A materials list for all significant well control steps is During available, drilling I { DOM DOM DOM DOM DOM DOM DOM DOM DOM DOM DOM/WCM • i 68 Identify the relevance of other documents to well crontroi e.g. contractors operations manual. 7r ( Well control during batched tieback of casing strings on different wells. BRevise training & development requirement for drilling staff 26 �tacd$sdett t1uo XIfiorlVOt�'��C } 1 z1 [,1. 1i)c i ili 0—aderiftf ca .0 C Ircevlse joo requirement ana star selection criteria for drilling positions (including contractors) iBefore i Include in template Drilling Programme ; 77' �.WCtf drilling AGn i 'included in 1.3.1. Cernenting 7 I Ope eations Guicei;nes created and ! - sUbrnrt,,d for r ,now During rS 5. WCM d il6ng I, - Barrier IMInclude authorities, responsibilities and Before accountabilities for each drilling job. drilling Documenting of reasons for selecting Drilling Before p Supervisors and benchmark skills against drilling responsibilities and ensure further reference for each Include in Process/Framework as an action for the Well Construction Manager. CMS Phase I - JDs/JRs CMS Phase I- Recruitirg Training + Competence° AZO udit r . Drildng.Uocumen "fi r �J • ATTACHMENT B Additional Actions from Independent Review by Noetic Detail �, Action - Timeframe Action Officers Implementation of the Montara Action Plan: Additional actions Monturu Action Regularly review and update as necessary Ongoing PTTEP Plan Implementation Manager Provide an update of Montara Action Plan Ongoing PTTEP AA CEO Steering Committee activities PTTEP —CRL Regularly review and update as necessary Ongoing PTTEP AA CEO Integration Plan PTTEP HQ — PTTEP Amend the Working Relations document to As PTTEP AA CEO AA Working include an outline of governance milestone Relations arrangements that conform to good practice is met document Finalise Working Relations document and As PTTEP AA CEO seek endorsement by PTTEP CEO and PTTEP milestone AA CEO is met Take steps to ensure the Working Relations As PTTEP AA CEO document is acted upon by PTTEP AA milestone personnel is met PTTEPAA Regularly review and update as necessary Ongoing PTTEP AA CEO Australia Strategy and Execution Plan SSHE Provide an update of Perth -based SSHE Ongoing PTTEP AA CEO Improvements Committee activities Update the Asset Integrity Standard as it As PTTEP AA CEO applies to drilling activities and Asset Routine milestone Reporting) is met Update the PTTEP Outlook and Strategic Plan As PTTEP AA CEO for 2010-2014 to adequately address SSHE milestone issues is met Update the PTTEP AA 2010 and 5-year Work As PTTEP AA CEO Plan to adequately address SSHE issues and milestone demonstrate awareness of SSHE issues at the is met operational level Progress the PTTEP AA Management System As PTTEP AA CEO Development and Implementation project to milestone ensure that the PTTEP SSHE Plan is met Management Standard is fully incorporated within PTTEP AA Ensure that appropriate leading and lagging As PTTEP AA CEO performance measures are established and milestone implemented within PTTEP AA is met Update the PTTEP SSHE Performance As PTTEP AA CEO Management Standard and the PTTEP SSHE milestone Behaviour -Based Safety Standard to involve is met senior executives in auditing and performance monitoring Provide an update on the PTTEP AA Ongoing PTTEP AA CEO Competency Management System project to demonstrate effective promulgation and promotion of appropriate management, operational and safety behaviours throughout PTTEP AA Communication Take action to ensure a consistent public End PTTEP AA CEO and reporting message as means of providing confidence to February the public that the issues highlighted as a 2011 result of the incident and subsequent Inquiry are being addressed in an appropriate manner Ensure adequate reporting of operations Ongoing PTTEP AA CEO announcements and company issues • • • ATTACHMENT C Monitoring Program and Reporting Requirements 1. In light of the findings of the Report of the Montara Commission of Inquiry and the outcomes of the independent review of the Montara Action Plan, the Australian Government is undertaking a monitoring program of PTTEP Australasia (Ashmore Cartier) Pty Ltd's (PTTEP AA) petroleum activities and operations. 2. The monitoring program is based around the key activities identified by PTTEP AA in the Montara Action Plan and additional actions identified by the independent review of the Montara Action Plan. 2.1 Information provided in accordance with the monitoring program shall be submitted and/or presented to the Minister for Resources and Energy or his Delegate. 2.2 It is anticipated that the monitoring program will be for a period of 18 months, however this period may be amended at the discretion of the Minister for Resources and Energy or his Delegate. 2.3 The Minister for Resources and Energy or his Delegate may, at their discretion, seek independent expert verification or advice in relation to information submitted in accordance with the monitoring program, with conditions of confidentiality and privacy being applied. 2.4 In addition to the expert verification and/or advice outlined in paragraph 2.3, PTTEP AA is to fully cooperate with an independent review of the actions taken pursuant to the monitoring program, which will be commissioned by the Minister for Resources and Energy or his Delegate at six -monthly intervals. 2.5 PTTEP AA will cover all internal costs associated with meeting the reporting requirements of • the monitoring program. 3. Within eight (8) weeks of the commencement of the monitoring program, PTTEP AA is to provide a detailed outline of the corporate governance framework as it applies to all PTTEP subsidiaries and operations in Australia. It is understood that this framework may be subject to review and revision and that the Minister for Resources and Energy or his Delegate be notified of any such revision as soon as practicable. • 3.1 The outline is to specify the officer or employee accountable for PTTEP and all its subsidiaries and operations in Australia and the scope of the officer's responsibilities. 3.2 The outline is to specify the chain of command and reporting framework in place for PTTEP and all its subsidiaries. 4. PTTEP AA is to provide written monthly reports to the Minister for Resources and Energy or his Delegate on the status of the actions and milestones outlined in this document and the Montara Action Plan, and any supplementary plans, appendices and related change initiatives or programs, in a format agreed with the Minister for Resources and Energy or his Delegate. 5. PTTEP AA is to undertake quarterly face-to-face briefings with the Minister for Resources and Energy or his Delegate on the status of the actions and milestones outlined in this document and the Montara Action Plan, and any supplementary plans, appendices and related change initiatives or programs. 6. In addition to the actions and milestones outlined in the Montara Action Plan, and any supplementary plans, appendices and related change initiatives or programs, PTTEP AA is to implement the additional actions identified by the independent review of the Montara Action Plan (refer Attachment B of the Deed of Agreement). Updates on the progress of the actions are to be provided in accordance with paragraphs 4 and 5. page t • • • PTTEP Australia PIL ABNIACN: 87 127997684 Location: Western Australia Level 1 152 Colin Street West Perth PTTEP Australia Offshore PIL ABNIACN: 96 127997719 Main business location: WA 6005 Permit % Held B ACIP 36 x 20 h °;AAt�,I0�391„ �Pa!iL--' raIGrea 'I;'Marpt: WA-P4 30 PTT Exploration & Production Public Co Ltd CEO: Sidsaengtaksin, Mr Anon Location: Thailand PTTEP Office Building, 55511 Vibhavadi Rangsit Road Chatuchak, Bangkok 10900 Thailand PTTEP Australia Perth PIL ABN/ACN: 74 134686525 Location: Western Australia Level 1 162 Cohn Street West Perth PTTEP Australia Browse Basin P/L ABNIACN: 78 134686543 Registered since 18 December 2008 Main business location'. WA 6005 PTTEP Australasia P/L ABN/CAN: 12 115470552 Main business location: WA 6005 February 2009: PTTEP acquired Coogee Resources Ltd which was renamed PTTEP Australasia Ltd PTTEP Australasia (Petroleum) P/L ABNIACN: 95 088553075 Main business location: WA 6005 September 2003: Formerly Newfield Int.(Aust.) PIL, the company was acquired by Coogee Resources PTTEP Australasia (Operations) P/L ABNIACN: 72 009785326 Main business location: WA 6005 February 2009: Cmgee Res (Ops) PIL was renamed PTTEP Australasia (Operations) PIL PTTEP Australasia (Ashmore Cartier) P/L ABNIACN: 27 004210164 Main business location: WA 6005 February 2009. Changed name from Coogee Resources (Ashmore Cartier) P/L PTTEP Australia Timor Sea P/L ABN/ACN: 70 D64126138 Main business location: WA 6000 October 2009: OMV Timor Sea P/L renamed PTTEP Australia Timor Sea PIL. ATTACHMENT D Permit %L Held By ACIP 17 50 PTTEP Australia Timor Sea PIL AC/P 24 60 PTTEP Australia Timor Sea PIL ACIP 4 50 PTTEP Australia Timor Sea PIL AC/RL 4 50 PTTEP Australia Timor Sea PIL ACIRL 4 T 100 PTTEP Australia Timor Sea P!L AC/RL 5 so PTTEP Australia Timor Sea P/L ACIRL 5 T 50 PTTEP Australia Timor Sea P/L ACIRL 6 50 PTTEP Australia Timor Sea PIL AC/RL 6 A 50 PTTEP Australia Timor Sea PIL Permit % Held B AC/L 1 89.68 PTTEP Australasia lAshmore Cartier PIL ACIL 2 89.68 PTTEP Australasia Ashmore Cartier P/L AC/L 3 89.68 PTTEP Australasia Ashmore Cartier P/L `AC/L 7' -100 PTTEP Australasia Ashmore Cartier P/L AC/L 8 100 PTTEP Australasia Ashmore Cartier P/L ACIP 32 35 PTTEP Australasia Ashmore Cartier PIL ACIP 33 100 PTTEP Australasia Ashmore Cartier P/L AC/P 34 100 PTTEP Australasia Ashmore Cartier PIL ACIP 40 100 PTTEP Australasia Ashmore Cartier PIL ACIRL 7 80 PTTEP Australasia Ashmore Cartier PIL WA-378-P 20 e=: 'r WobtlsMle [? ltd=xw+ WA.996-P 20 WAJ97-P 20-� R VUtlodlFfd6,FrletytUY! ,,