Achieving American energy dominance has moved one step closer with the approval of Arctic exploration operations on the Outer Continental Shelf for the first time in more than two years. The Bureau of Safety and Environmental Enforcement approved an Application for Permit to Drill. Eni U.S. Operating Co. Inc. submitted the application in August. Drilling the exploratory well from a man-made artificial island in the Beaufort Sea is expected to start as early as this December.
“Responsible resource development in the Arctic is a critical component to achieving American energy dominance,” said BSEE Director Scott Angelle. “BSEE is committed to working with our Alaskan Native and Industry partners by taking a thoughtful and balanced approach to oil and gas exploration, development and production in the Arctic"
Eni’s exploratory drilling will take place on Spy Island, a man-made artificial island approximately three miles offshore of Oliktok Point. Photo credit: BSEE
The Bureau’s approval allows Eni to move forward with new exploration in federal waters, but only after a thorough review by BSEE Alaska Region personnel to ensure the request met appropriate technical adequacy, safety and environmental sustainability standards.
“BSEE Alaska Region staff conducted a thorough and complete review of Eni’s well design, testing procedures and safety protocol,” said Mark Fesmire, BSEE Alaska Region director. “Exploration must be conducted safely, and responsibly in relation to the Arctic environment and we will continue to engage Eni as they move forward with drilling its exploratory well.”
According to Eni, new exploratory well operations will add an additional 100-110 jobs during the drilling of the well, and any potential plan of development is dependent on the results of Eni’s proposed exploration wells. At a minimum, new development could lead to the creation of 100-150 jobs in the region and new production of 20,000 barrels of oil per day.
Eni’s exploratory drilling will take place on Spy Island, a man-made artificial island approximately three miles offshore of Oliktok Point, in State of Alaska waters. Both the island and Oliktok point are already home to Eni production facilities comprising 18 producing wells, 13 injector wells and one disposal well. Eni is now proposing to use extended-reach drilling techniques to drill into federal submerged lands.
The extended reach drilling will target a formation in the newly formed Harrison Bay Block 6423 unit, a 13-lease unit on the OCS that BSEE approved in December 2016. Eni will explore the Harrison Bay Block 6423 Unit in partnership with Shell and plans to drill two explorations wells plus two potential sidetracks over the next two years.
Prior to the start of drilling operations, BSEE Alaska Region engineers and inspectors will conduct required pre-drill inspections at the Spy Island location. As part of the inspections, BSEE engineers and inspectors witness equipment tests, and verify that all operations are being conducted in accordance with approved plans and permits.
"I am always mindful of the need to protect the environment and our subsistence way of life and I appreciate BSEE and the Department of Interior's commitment to responsible development," said North Slope Borough Mayor and whaling captain, Harry K. Brower Jr. "The Borough and the majority of our residents have long supported the careful and responsible development of oil and gas resources within our region that protects the balance between economic development and our subsistence way of life."
BSEE Alaska Region personnel, in coordination with State of Alaska, currently oversee oil production at Northstar Island in the Beaufort Sea, producing approximately 10,000 barrels of oil per day. A second project in the Beaufort Sea, known as Liberty, is currently open to public comment with the Bureau of Ocean and Energy Management. If permitted, Liberty would be the first completely federal OCS production facility in the Alaska Region.
Image credit: Statoil
Statoil has submitted the PDO (plan for development and operation) for the Johan Castberg project on behalf of the partnership with Eni and Petoro. Several major contracts will also be awarded to Norwegian industry.
“This is a great day! We have finally succeeded in realizing the Johan Castberg development. The project is central part of the further development of the northern regions, and will create substantial value and spinoffs for Norway for 30 years,” says Margareth Øvrum, Statoil’s executive vice president for Technology, Projects and Drilling.
Capital expenditures for Johan Castberg are estimated at some NOK 49 billion. Recoverable resources are estimated at 450 – 650 million barrels of oil equivalent. This makes the Johan Castberg project the biggest offshore oil and gas development to be given the go-ahead in 2017. First oil is scheduled for 2022.
“Johan Castberg has brought challenges. The project was not commercially viable due to high capital expenditures of more than NOK 100 billion and a break-even oil price of more than USD 80 per barrel. We have been working hard together with our suppliers and partners, changing the concept and finding new solutions in order to realize the development. Today we are delivering a solid PDO for a field with halved capital expenditures and which will be profitable at oil prices of less than USD 35 per barrel,” Øvrum says.
“Johan Castberg will be the sixth project to come on stream in Northern Norway. The field will be a backbone of the further development of the oil and gas industry in the North. Infrastructure will also be built in a new area on the Norwegian continental shelf. We know from experience that this will create new development opportunities,” says Arne Sigve Nylund, Statoil’s executive vice president for Development and Production Norway.
The Johan Castberg field will have a supply and helicopter base in Hammerfest and an operations organization in Harstad. The costs of operating the field are estimated at some NOK 1.15 billion per year. This will represent about 1700 man-years nationwide, some 500 of which will be located in Northern Norway. This includes both direct and indirect effects.
“Johan Castberg will be producing for more than 30 years, and the greatest spinoffs will be generated in the long production phase. Castberg will create considerable activities for Norwegian supply companies and generate ripple effects in Northern Norway,” Nylund says.
Parallel with the submission of the PDO Statoil is signing a contract both for the Johan Castberg subsea system, and engineering and procurement management, both with Aker Solutions AS. The contracts have a total value about NOK 4 billion.
Johan Castberg is a big subsea development, and this contract includes 30 wells, 10 subsea templates and two satellite structures.
“We are pleased to see that Norwegian suppliers again demonstrate their competitiveness and will play a key role in the development of Johan Castberg. The jobs generated nationwide during the development are estimated at almost 47 000 man-years,” Øvrum says.
Statoil, on behalf of the partners in the Snorre license, is also signing a letter of intent (LoI) with FMC Kongsberg Subsea AS for the subsea system for Snorre Expansion Project (SEP). The LoI is worth slightly less than NOK 2 billion and includes 6 subsea templates and subsea production equipment for a total of 24 wells.
The press is invited to Melkøya in Hammerfest at 12.15. Torger Rød, SVP, project management control, and Siri Espedal Kindem, SVP Operations North, will then hand over the Johan Castberg PDO to Minister of Petroleum and Energy, Terje Søviknes.
The press is also invited to the contract signing at 13.00 at Aker Fornebuporten. Executive vice president Margareth Øvrum will participate from Statoil together with Luis Araujo in Aker Solutions AS. All contracts are subject to government approval of the PDO. The Johan Castberg partnership consists of Statoil (operator 50%), Eni (30%) and Petoro (20%).
The field development concept includes a production vessel and extensive subsea development with a total of 30 wells, 10 subsea templates and two satellite structures. This is the biggest subsea field under development in the world today.
The Johan Castberg development costs are estimated at around NOK 49 billion. The jobs generated nationwide during the development are estimated at slightly less than 47,000 man-years, some 1800 of which will be located in Northern Norway.
The Johan Castberg project will account for a substantial part of the investment level on the NCS in 2018-2022.
Together with other operators of oil discoveries in the Barents Sea Statoil is investigating the possibility of finding a profitable oil terminal solution at Veidnes.
Rutter Inc. has announced the delivery of their sigma S6 Oil Spill Detection to a port in Saudi Arabia. Rutter’s system will be fully integrated by the port’s Vessel Traffic Service (VTS) provider to add environmental protection capabilities to their traffic management system. Rutter’s technology is currently being integrated into the system, with full deployment in 2018.
“This order represents a forward-thinking mentality towards the detection and clean-up of oil spills,” said Fraser Edison, President and CEO of Rutter. “Integrating our systems into existing port monitoring systems ensure minimization of the impact of spills on the environment in heavily trafficked areas at a low cost point.”
This delivery is another step forward for Rutter in the Middle East following a recent delivery of three oil spill detection systems to vessels destined for Saudi Arabia.
Damen Shipyards Group has delivered its first vessels to Marine Core & Charter LLC (MC2), a marine services company supporting the offshore energy sector in the Arabian Gulf. This is the first transaction between the two organisations and Damen is delighted to be setting out on what it hopes will be a productive and long-lasting relationship with MC2.
The transaction is also a milestone as it represents the first deliveries of the Fast Crew Supplier (FCS) 4008 class, Damen’s latest addition to its FCS range. The first of the two FCS 4008 vessels was delivered in late September, just two months after the initial contract signing.
The second FCS 4008, named AMIA was officially handed over at a ceremony held at the Emirates Palace Marina in Abu Dhabi on the 23rd of November. The 9-year old son of the CEO held a fantastic speech, followed by his grandmother who cut the ribbon.
Like her sister ship AMPI, the AMIA is also fitted with seating for 90 personnel, has a top speed of 25 knots and a range of 1200 nautical miles. This gives her the ability to reach even the furthest offshore installations. 140 square meters of cargo deck aft enable her to carry containers and a wide range of other equipment. Damen’s famous ‘axe bow’ design delivers excellent seakeeping in a wide range of weather conditions, ensuring that personnel arrive at their destinations ready for work.
The 40-meter FCS 4008 was introduced recently to fill the gap between the 53-meter FCS 5009 and the 33-meter FCS 3307. The FCS 4008 is essentially a scaled-down version of the FCS 5009 and is fully capable of taking on the same, wide variety of roles. As well as personnel transfers, it can be fitted out for fire-fighting, oil recovery, safety stand-by, towing and security duties; on a smaller scale, but also at a lower cost. As with all Damen designs, the FCS range is subject to continuous updates based on customer requests and feedback, and so the AMPI and AMIA represent the very latest in FCS design and optimisation.
The CEO of Marine Core & Charter L.L.C, Mr. Adib Abdel Massih, commented, “The delivery by Damen of the second FCS 4008 brings our total fleet up to 20 vessels. With the addition of these two boats, we have achieved the growth we had planned for this year, both in terms of the number of vessels and the expansion of our operations. We chose Damen in part due to their extensive experience in the crew boat market, the local support in the UAE and also because of their build for stock policy. Their ability to deliver vessels very rapidly when a company like ourselves wins new business was a deciding factor.”
Mr. Massih also commended the design of the FCS 4008, in particular its unique ability to deliver personnel quickly and comfortably in the adverse weather that can occur in the Gulf. AMPI has started operations on a contract with a duration of up to three years. AMIA is expected to operate from Abu Dhabi.
MC2’s core activities are chartering, ship management, towage and transportation, and offshore services. It operates a diverse fleet of vessels ranging from jack-up rigs and accommodation barges to tugs and Multi Cats. This latest acquisition is part of its strategy to build on its focus on chartering and increase its role in marine contracting using its own fleet.
ExxonMobil announces that its wholly owned affiliate, ExxonMobil Exploration and Production Mauritania Deepwater Ltd., has signed production sharing contracts with the government of Mauritania for three deepwater offshore blocks.
“These blocks further enhance ExxonMobil’s leading global deepwater acreage position,” said Steve Greenlee, president of ExxonMobil Exploration Company. “We thank the government of Mauritania for the opportunity to evaluate the potential of this acreage using our expertise and advanced technology.”
Blocks C22, C17 and C14 are located an average of 124 miles, or 200 kilometers, offshore Mauritania. Together they measure nearly 8.4 million acres in water depths ranging from 3,300 feet to 11,500 feet, or 1,000 meters to more than 3,500 meters.
Following government approval of the contracts, ExxonMobil will begin exploration activities, including acquisition of seismic data and analysis.
ExxonMobil will carry out the work program as operator with 90 percent interest. Societe Mauritanienne des Hydrocarbures et de Patrimoine Minier holds a 10 percent interest.
The Icemann gangway system has reached a milestone of 10,000 transfers since its arrival in Eastern Russia in August to transfer personnel working on offshore platforms under the Sakhalin-2 project. Developed by Ampelmann, the global leader in offshore access solutions, it is currently the only gangway system of its kind able to operate in remote and extreme cold climate.
The Icemann will brave extreme icing, vibrations and vessel motions in Sakhalin, while maintaining a safe, efficient and reliable means of transfer for the workforce. (Photo credit: Ampelmann)
The N-type gangway, nicknamed ‘Icemann’ has been installed on the Stepan Makarov, a new ice-class platform standby vessel built for the Sakhalin-2 project under a 20-year charter between Sakhalin Energy and vessel operator, Sovcomflot. It is the first standby vessel in the world to use such a gangway for operations in severe ice states and temperatures.
“The Icemann was born in response to a growing demand for safe and effective transfer equipment in frontier regions,” said Arnoud van Leer, senior motion control engineer with Ampelmann. “It is purpose-built to service remote and extreme cold climate oil and gas operations in areas such as non-Arctic Russia, Norway and Canada, as well as regions of the Caspian Sea. We worked closely with Sakhalin Energy over a period of two years to tailor the system to the unique requirements of the project.”
Built in The Netherlands, it is designed to safely and efficiently transfer crew in extreme ice states and temperatures as low as -28 oC (-18 oF). The fully enclosed and insulated system is operational in sea states up to 3.5 metres (m) significant wave height and comprises active motion compensation. The transfer deck can accommodate up to 20 people and can rotate 360 degrees to ensure flexibility in platform landing locations and directions. It has a maximum gangway length of 32m, a telescopic scope of 11m and a footprint of 11x11m.
“Given the remoteness of the work, it was crucial to ensure that any maintenance required to the gangway system was minimized and this was reflected in the design. Various extreme weather technologies were employed in the design of the Icemann, making it the most high performance gangway system that has ever been built from an operations and conditions point of view.”
Before leaving Ampelmann’s manufacturing facility in Delft, The Netherlands, the Icemann was successfully tested offshore in the North Sea. The system successfully compensated its first waves while company operators evaluated the performance of the system. Following completion of the trials, the Stepan Makarov arrived in Rotterdam for the system mobilization, which was completed in a matter of days.
In addition, Sakhalin Energy will charter a standard, non-winterized version of the motion compensated gangway for five years, to be installed on a second ice breaking support vessel, the Fedor Ushakov, and to support the personnel transfer requirements during the summer period.
Airborne Support Inc. (ASI) and Fototerra Aerial Survey LLC (Fototerra) announces a joint venture to provide integrated airborne oil spill response services in the Gulf of Mexico for the responder's community and the oil and gas operators. The joint venture will capitalize on the strong reputation Airborne Support Inc. has developed as a leader for aerial dispersant application in the Americas and on Fototerra's strength in aerial remote sensing with unique technologies for oil spill detection and analysis.
"This agreement represents each organization's strong commitment to provide customers with a single source for the best in oil spill response," commented Brad Barker, ASI President and CEO. "This joint venture expands the ASI offering into a total service solution. When unique remote sensing capabilities are combined with the ASI reputation and credibility for excellence in dispersant application, you have a situation that can't be matched in aerial services for oil spill response." The services for the joint venture will include aerial remote sensing, aerial dispersant application supported by remote sensing information, and GIS services. The joint venture will sell its services through Airborne Support Inc. and it will be focused initially in the Gulf of Mexico.
"Intelligence on the scene is essential during an oil spill response," commented Guilherme Pinho, Fototerra President and CEO. "It allows the responders to understand the environment, to decide the best strategies and tactics and to control the outcomes. This systems approach offers a single source from the early detection to the application of mitigation measures. Seamless integration of all elements means maximum customer value and assures our customers a reliable service and the highest level of expectation."
Statoil will in 2018 establish a new onshore integrated operations center (IOC) that will help increase safety, add value and reduce emissions from their installations on the Norwegian continental shelf (NCS).
An integrated operations center (IOC) is an important step in Statoil’s digital roadmap, and will enable increased production efficiency and production potential on the NCS. In a 10-year perspective, our ambition is that the increase in production from our operated fields could lead to a total annual value creation of around NOK 10 billion before tax.
“The establishment of the center contributes strongly to our ambition of being a global digital leader. It will enable us to optimize production and better predict support needs, ensuring optimally efficient and safe operations from our operated fields. The center will be essential to progressing the good improvement work on the NCS, and capturing additional value for Statoil, our partners and society,” says Statoil’s chief executive officer, Eldar Sætre.
“The center may also improve sharing of knowledge in our organization and further improve our collaboration with our suppliers and partners,” says Sætre.
The location of the new center will be decided next year. It will integrate Statoil’s existing production support centers and condition monitoring centers, which are located in various parts of Norway.
“The IOC establishment will build on existing condition monitoring and specialist centers. The integrated operations center will take a more proactive approach by gathering inter-disciplinary resources that may utilize extended data integration, visualization, analysis and new technology, supporting our installations on the NCS to an even greater extent than now,” says Kjetil Hove, Statoil’s senior vice president for operations technology on the NCS.
The IOC is also intended to make data available in a more user-friendly format, providing the operations organization offshore with a better decision-making basis and support.
“When the center is established next year the Åsgard field in the Norwegian Sea and Grane and Gina Krog in the North Sea will be the first fields getting support from the center. New fields and installations will gradually be integrated, allowing time for learning and adjustment to new work processes,” says Hove.
The IOC will help ensure that production on the fields is optimally efficient at all times, solving bottle necks through condition monitoring. This will be achieved by means of specialist support within production optimization and preventive maintenance from inter-disciplinary teams, e.g. within production technology, processing, mechanical and electrical engineering.
“We are now developing tools that will stream data live from the sensors offshore. The tools will help conduct detailed analyses of the production and the performance of equipment on the installations. One important goal for the center is to identify and prevent operational disruptions,” says Hove.
The center will initially be set up to support Statoil installations on the NCS, but may in the future also be relevant to onshore plants and the company’s international offshore operations. The IOC is based on experience from the US and our multi-field operations and production support centers in Norway.
An integrated operations centers will be operational in Austin in December this year. This center will interact with the field-based centers in Bakken and Eagle Ford.
Innovative cable sealing solutions designed by Roxtec have been used in the construction of Dana Petroleum’s new Western Isles floating, production, storage and offloading (FPSO) vessel, which started production in the UK North Sea last month.
Dana Petroleum’s new Western Isles floating, production, storage and offloading (FPSO). Photo credit: Dana Petroleum
Roxtec UK managing director Clive Sharp said enclosure seals are being used aboard the platform to allow cables to pass between separate areas, while protecting people and equipment.
Roxtec UK Managing Director Clive Sharp.
The firm’s cable sealing systems can also be found in the vessel's hull area, living quarters and within power utility modules. Bulkhead seals and deck seals are being used topside to allow cables to pass between the FPSO's sections safely and securely. “Roxtec seals are protecting life and assets against a huge range of potential dangers, including fire, jet-fire, gas pressure, water, explosions and electromagnetic interference,” he said. “As well as offering a comprehensive protection package, they also allow businesses to save time, space and weight. Due to the simplicity of our flexible transit systems, businesses are able to cut down time spent on design and engineering.”
He added that due to Roxtec's global reach, the company was able to provide assistance in the UK during the project's design phase, as well as in China while the FPSO vessel was under construction. Further support was made available in the UK when the platform entered its hook-up and commissioning stage following its arrival off the coast of Britain in the summer.
"Roxtec's multi-cable and pipe transits are ideal for the type of environment found onboard the FPSO platform," said Mr. Sharp. "Our ES solutions form a barrier against electromagnetic interference to ensure electromagnetic compatibility at all times, while our Ex solutions, which are ATEX certified and comply with the latest European standards, are used on cables going in and out of hazardous areas due to the risk of an explosion occurring. These challenging environments are where our sealing systems really thrive, offering customers a simple, safe and effective solution."
Trelleborg’s offshore operation is committed to continuing its work in Mexico to help educate and develop specifications aimed at improving fire safety solutions used in harsh offshore environments. To this end, Hans Leo Hals, Managing Director for Trelleborg’s offshore operation based in Norway, met with leading oil and gas representatives in Mexico over a number of months to support in improving the safety of Mexico’s offshore assets in the Gulf of Mexico.
Hans Leo, states: “In offshore environments, fire safety is of the utmost importance, as the occurrence of fire on any structure can endanger onboard personnel and cause extensive damage to assets. In its third year, Trelleborg’s safety education initiative for the Gulf of Mexico focuses on helping develop specifications aimed at improving fire safety solutions used in harsh offshore environments.
“By specifying effective and reliable passive fire protection systems for offshore oil and gas platforms, Mexico can increase the safety of personnel and offshore assets, while at the same time reducing risks, event escalation and production downtime. We believe that ensuring safety onboard any production facility is absolutely vital to reducing the risk of fire hazards and is a key priority for the region.”
Trelleborg has completed its first two projects in Mexico focused on improving safety for offshore assets in the Gulf of Mexico. The first project was for the manufacture and installation of 530 meters of Elastopipe™ for the Nohoch A-01 platform and the second for the manufacture and installation of Elastopipe™ on the Abkatun Alpha compression platform. Both projects were completed on time, within budget and without any safety incidents.
Hans Leo, continues: “By installing Elastopipe™ on these platforms, we were able to create peace of mind for onboard personal with the added bonus of protecting platform assets. Our Pemex NRF 127 approved Elastopipe™ is designed to meet the developing safety needs and requirements of Mexico’s oil and gas industry.”
Elastopipe™ is a corrosion-free, explosion, impact and jet fire resistant flexible piping system. Its typical applications are deluge and sprinkler systems, utility and drain water systems, nitrogen distribution systems and chemicals and hydrocarbon transportation. The system is lightweight, durable and offers a 30-year minimum maintenance life, while its corrosion-free performance means system-testing frequency can be reduced to statutory requirements.
Passive Fire Protection, specifically Trelleborg’s FireStop™ material, can be used for different topside applications to ensure safety comes first. FireStop™ is non-corroding and can withstand jet fires with a heat flux of 390kW/m2, temperatures above +2552 °F / +1400 °C and flame speeds that exceed the speed of sound. This makes it an ideal material choice for reducing fire hazard risks in demanding environments both onshore and offshore.
Safety on offshore oil and gas installations is of paramount importance, and the need to have effective and reliable passive fire protection solutions has never been greater to ensure onboard safety. Trelleborg’s offshore operation is committed to supplying high performance, robust and dependable solutions that significantly improve onboard safety to protect personnel, equipment, critical components and structures in demanding environments.
Global Marine Group (“GMG”), a market leader in offshore engineering services to the telecommunications, renewables and oil & gas industries, announces that it has completed its previously announced acquisition of Fugro N.V.’s (“Fugro”) (AMS:FUR) trenching and cable lay services business.
The Fugro acquisition significantly enhances GMG’s portfolio of service offerings to the market, with a comprehensive range of integrated services that enable GMG to complete additional packages of work in direct response to market demands. The transaction also provides GMG with highly capable, proven assets, including 23 employees located in Aberdeen, that have a successful track record of delivering complex subsea engineering projects to offshore customers globally. For example, the M/V Symphony, a multi-purpose vessel built in 2011 with an extensive 1,400m2 deck space, has recently joined GMG’s cable installation and maintenance fleet. In addition, GMG has added two powerful Q1400 trenchers and two work class remotely operated vehicles to its offering. As part of this transaction, Fugro will become the preferred provider of marine site characterisation and asset integrity services to GMG.
“We believe this acquisition has two key benefits, meeting the needs of our customers, while at the same time strengthening GMG’s market position in offshore power,” said Ian Douglas, Chief Executive Officer of GMG. “I’m delighted to welcome on board such a well-respected group of people led by Mike Daniel, and I look forward to seeing the contribution they will make to the Global Marine Group over the coming months.”
Mike Daniel, manager of the trenching and cable lay services business, added, “We have an excellent track record in the offshore renewables and oil & gas sectors. As a team, we have been involved in the installation of more than 470 power cables, recently completing the installation of 122 cables at the Rampion Offshore Wind Farm. We have also successfully completed the trenching of the export cable and inter array cables on the world’s first floating wind farm, Hywind Scotland, off the coast of Aberdeenshire, demonstrating our innovative industry leading approach. Moving forward, we will continue to support existing and new customers alike, utilising our skill set to support the wider business goals of Global Marine Group.”
MacGregor, part of Cargotec, has won new davit orders from Spanish shipyard Astilleros Zamakona. They are destined for a service operation vessel (SOV) owned by the Danish company Esvagt AS. The contract includes an order for one of MacGregor's largest davit systems, specially-designed to ensure safe transfers in rough weather. Equipment deliveries are scheduled for November 2018 and the order was booked in Cargotec's fourth quarter 2017 order intake.
"We are glad to continue our cooperation with Zamakona and Esvagt with the delivery of these advanced davit systems to a growing and interested market," says Høye G. Høyesen, Vice President, Advanced Offshore Solutions, MacGregor. "Esvagt already knows and trusts our davits, operating a large number in its fleet, so this order speaks volumes for their performance and reliability."
The vessel will feature one of MacGregor's largest davits, a 15-tonne lifting capacity MacGregor HMD G150 system designed for daughter craft, and a smaller six-tonne capacity HMD A60-type davit, designed for man-overboard/rescue and workboats. The davits will transfer technicians, tools and spares as part of their offshore wind farm duties.
The HMD G150 davit includes a high-speed constant-tensioning winch system, shock-absorbing system, anti-pendulum system and an automatic parking cradle for daughter craft. The anti-pendulum system, together with an adjustable painter-line boom and a guiding system, ensures the safe launch-and-recovery of daughter craft in rough weather conditions.
The A60 davit also includes a high-speed constant-tensioning winch system, shock-absorbing system, guiding system and an automatic parking cradle. Additionally, both davits will meet the shipowner's high standards for noise and vibration limits.
"The contract highlights our long and successful reputation for delivering advanced launch-and-recovery systems and our ability to offer equipment that is ideally suited to meet the needs of operators serving the offshore wind energy market," says Bjørnar Bakke, Sales Manager, MacGregor. "Our G150 davit is specially-designed for the safe handling of daughter craft transferring turbine technicians.
"MacGregor davits have a well-proven design, offering great performance and trusted reliability," he adds. "We have delivered over a thousand davit systems and have seen significant orders for them in 2017. This is mainly because of our strong reputation, but also because we are able to adapt our products, proven in mature markets such as the offshore oil and gas industry, to meet the needs of new ones such as the renewable energy sector."
Subsea services group Acteon is announcing that it has enhanced its moorings capabilities by completing the purchase of the Viking Seatech Group.
The announcement follows regulatory approval for Acteon to acquire Viking Seatech while selling Mirage Machines to Actuant, a US corporation.
Paul Alcock, executive vice president at Acteon, said: “The addition of Viking Seatech to Acteon allows us to further respond to the needs of our clients working in the area of dynamic and critical infrastructure, offering an end-to-end service in the regions where they are operating, delivering consistent, efficient, safe and reliable services and reducing the need for multiple points of contact.”
Viking Seatech’s services will compliment those of InterMoor, the global leader in mooring services and specialist in foundation solutions and offshore installations, whilst extending Acteon’s global reach for clients and adding capabilities in rental and engineering, as well as chain inspection and survey in Australia.
Mark Jones, global CEO of InterMoor, added: “The synergies between Viking Seatech and InterMoor, in terms of our complimentary assets and aligned values, mean we can enhance our offering to clients with locations in key hubs around the world, combining global strength with local expertise.”
Acteon Field Life Service (FLS) offers a “joined-up” approach to the capex and opex challenges presently being experienced by the oil and gas industry.
Global subsea equipment specialists, Ashtead Technology, has strengthened its leadership team with the appointment of Steven Thrasher as regional vice president for the Americas.
Bringing almost 20 years’ experience in the subsea industry, Thrasher, who will be based in Houston, Texas, will head up Ashtead’s US operation as it gears up for further growth in the Gulf of Mexico (GoM) and neighboring markets.
Prior to joining Ashtead, Thrasher held a number of senior and technical positions at FTO Services, C-Innovation and Schilling Robotics.
He began his career in the oil and gas industry in 1998, when he joined Sonsub as a ROV technician where he eventually advanced to ROV Superintendent, delivering the mobilization and commissioning of several high-profile projects.
Thrasher has established a successful track record with key oil and gas operators and brings extensive experience of developing sales within the GoM marketplace as well as internationally.
At the same time, Chris Echols will take on a newly created role of vice president of sales for the Americas. Chris, who has over 20 years’ experience with Ashtead will focus on delivering growth in existing and new markets across the region.
Allan Pirie, chief executive of Ashtead said: “Over the past 18 months we have focused on maintaining a strong service offering that is fit for the challenges of the market, improving the execution of projects, driving greater efficiency and lowering operating costs where possible.
“Our focus now turns to growth and execution of our business development strategy. Steven’s appointment and Chris’ new role strengthens our ability to offer great service, develop a solutions-based capability and identify opportunities to grow with both existing and new customers.
“Current market conditions create challenges and opportunities, and having the right organization in place is key. I am confident these two appointments will allow Ashtead to be successful in the GoM market in the long term.”
Global Supply/Demand Balance Continues to be Supportive
Clear sailing for the booming global economy. The resulting strong oil demand growth together with OPEC cuts have accelerated rebalancing, virtually eliminating the global surplus. OPEC continues to overestimate the global surplus, ensuring the cuts will stay longer than required. In PIRA’s view, the market’s focus on duration of cuts is misplaced; the OPEC cuts are perpetual. Non-OPEC cuts, which have been minimal, will fade in 2H 2018. The vulnerability for crude prices in 2018 comes during the weak seasonal first half when stock builds undermine backwardation causing some financial length to exit oil markets. Strong demand for refined products is outstripping refinery capacity growth, increasing utilization rates in swing refineries and raising refinery margins. U.S. crude exports will trend higher and inland U.S. differentials will firm as Cushing draws crude stocks. Middle East tensions are rising and supply vulnerability is ever-present.
Any Way You Slice It, It Is Difficult to Locate Trouble Spots in the Global Economy
Growth in world trade rose at its fastest pace since 2011 during the third quarter. Based on leading indicators, trade will continue to expand at a solid pace. Recent global industrial production has similarly been strong. Labor markets are tightening in the U.S., Europe and Japan, but core inflation figures have not been accelerating. India’s growth slowed in the first half of 2017 after disruptions from major policy changes. But key data pointed to a rebound during the third quarter. A historical relationship between world GDP and a number of economies having difficulties suggests faster global economic growth in 2018.
Propane Stock Draws Muted by Increases in Propane Production and Imports
Propane exports topped 1.1 million b/d for the week ending November 24, but the effect on stock draws was muted by increases in propane production and propane imports. Propane production increased 50,000 b/d to a record high 1.92 million b/d, and propane imports from Canada jumped 85,000 b/d to 231,000 b/d. The net impact on inventories was a moderate draw of 560,000 barrels. Propane prices fell 1.25% last week settling at 98.875 cents/gal. However, propane price strength has closed the Asian arbitrage window, and shipment cancellations are reportedly on the rise in early December. Increasing NGL production is having a bearish impact on ethane prices as steam cracker demand remains relatively stable at present levels until the next wave of steam crackers come online next year. There are no scheduled Gulf Coast steam cracker turnarounds this winter. Declines in ethane prices last week supported ethane steam cracker margins, which increased 1.7% to 22.1 cents/lb ethylene production. Ethylene and propylene prices fell last week as producers are clearing year-end inventories, which led to a decline in all other steam cracker feedstock margins.
U.S. Ethanol Manufacturing Margins were Stable in November
RIN values declined. Ethanol output increased in the South-Central region of Brazil in the first half of November. European ethanol prices were lower. U.S. biodiesel prices rose.
Dryness in Argentina has the soybean market’s full attention entering the first full week of December after forecasters had started to warn that a relatively dry month was a possibility for growing regions as the calendar turned to the final month of the year late last week. For a market that’s starving for any sort of input, and probably won’t get any non-weather data until the January WASDE, a dry weekend to go with a forecasted dry week was enough to gap higher by a few cents on Sunday night and push prompt bean futures to their highest level since the end of July.
U.S. Gas Weekly Report
The long holiday weekend helped Henry Hub fall below $3/MMBtu for the first time since November 6. The national benchmark has averaged $2.93/MMBtu over the past seven days, down 9 cents/MMBtu (3%). The December 2017 future contract whipsawed through the last week of trading, reaching as low as $2.81/MMBtu on November 24 before settling at $3.07/MMBtu on its last day of trading on November 28 —its last day of trading. In spite of surging production, expectations of cool weather for the first half of December sparked the rebound. U.S. weather forecasts remain in flux, favoring relatively warm conditions then cold and then back to warm. Today, the nearby NYMEX is again rallying following yesterday’s sharp selloff, suggesting yet another shift in demand expectations.
Walking a Tightrope, Little Slack Without Mild Temps
Winter-like weather arrived early in November after a significantly warmer than normal October, and December is beginning with frigid temperatures that are raising German demand by 15%. While this additional demand will likely lead to some price appreciation, there will be limited ability to balance gas through the power market as inefficient coal power is cheaper than efficient gas power. Additionally, LNG re-export activity is worrying a market that already feels tight after TTF spot has increased upwards of 42% from summer lows, however, export activity YTD has been relatively muted historically speaking. Despite this, the coming months show significant re-export risks, as global spreads have widened – meaning upward European price pressure.
Germany Tightens, French Restarts Loom
In France, all 12 reactors under review this year for the Le Creusot Forge irregularities have been cleared, but only six have officially restarted, after lengthy delays (14 days). While output in November set a new historical minimum, we assume that the December output will be 49.8 GW (only 0.5 GW above year ago levels), with January assumed to average 54.7 GW, up 0.7 GW Y/Y. In other words, we see upsides for French prices, as we still have output 1 to 2 GW below the 5-year average. In Germany, scarcity prices are increasingly emerging – even at relatively higher temperatures and/or wind output levels. While there is still no agreement in sight to form a government, the hypothesis of additional lignite closures is now shaping up, either to allow Germany to move closer to the carbon targets or as a result of tougher emission standards mandated under the updated LCP BREF. In a scenario where 3 GW of additional lignite units are retired on top of the climate reserve, German 2020 prices should be up by €1.1/MWh, but that impact increases to €1.9/MWh, when 5 GW of lignite unit retirements are assumed. The introduction of a minimum carbon price – or equivalent increases in the EUA prices, assuming the current reform of the EU ETS tightens the market successfully – could potentially have a larger impact.
Downstream Markets will Remain Strong
The Brent price outlook remains bullish in December but is more vulnerable in 1H18 as stocks draw in December but build in 1H18. Nevertheless, the available commercial inventory excess net of working stocks has essentially been eliminated in the OECD. WTI’s discount to Brent will narrow as Cushing drains in 1Q18. U.S. crude exports are expected to trend higher with USG pricing remaining in export parity.
Refinery margins will stay strong as strong demand growth for refined products, limited growth in available refinery capacity outside China, and poor refinery operations in Latin America will require high utilization rates in Europe even in some less economic capacity to balance Atlantic Basin product markets. This will support margin strength through 2018.
SP15 Rockets Higher as Gas Curtailments Loom
With gas market tightness boosting late November SoCal Citygate spot gas prices above $5/MMBtu despite mild weather, December gas prices soared to $6 amid talk of curtailments, driving local power markets higher. We have increased SoCal citygate gas basis forecasts for December and January to $1.50/MMBtu and $1.10/MMBtu, respectively, equivalent to $4.70 and $4.50, so there is clearly upside risk from these levels. Higher gas prices will lead to downward pressure on implied heat rates, particularly in January as transmission availability from the Southwest improves. November SP15 implied heat rates averaged in the low 9,000s and we expect December to be in the high 8,000s before a sharp drop in January (~8,000). That would result in December on-peak just under $50 compared with market forwards about $10 higher. Other Western markets are in line with previous forecasts, but downside risk is growing as runoff projections are beginning to climb. This may be countered in the near term by colder than normal weather in the Northwest.
Coal Prices Range Bound…For Now
International thermal coal prices faded over the first three weeks of the month, only to regain most of the ground lost in the final week of November. The market was clearly uneasy with the pace of pricing declines at the start of the peak demand season. Short-term prices retain upside risks due to seasonal demand issues as well as potential supply disruptions from intensifying la Niña conditions. However, 2018 prices will face heavy bearish pressures from weaker coal demand in China, and more intense competition with LNG on the global stage.
MA Announces Exempt Loads for RPS
Exempt loads play a large role in determining the Solar Carve-Out compliance obligations for the MA Renewables Portfolio Standard. MA DOER has updated prior exempt loads projections and for the first time has provided loads served by contracts before the SREC II May 8, 2016 cut-off date. PIRA’s updated RPS demand estimates show lower SREC I obligations in 2017 vs. 2016, with SREC II much higher. 2018 will see significantly higher solar requirements. The Clean Energy Standard, finalized in August 2017, effectively raises the Class I RPS obligation beginning 2018.
Product Tanker Rates Stronger as U.S. Refiners Restore Full Operations
VLCC and Suezmax markets weakened in November and will likely head lower in December as excess supply and OPEC cuts weigh on tanker markets. But product tanker rates recovered as U.S. refinery runs and product exports ramped higher over final months of year following completion of October maintenance and recovery from residual effects of Hurricane Harvey.
Financial Stresses Move to a New Low
The S&P 500 extended its gains above the 2,600 level and tested 2,650, for the first time, setting more records along the way. Volatility (VIX), however, increased significantly, though oil volatility (OVX) was lower. Other credit metrics, such as high yield debt (HYG), and emerging market debt (EMB), weakened. Commodities were modestly lower, but industrial metals and precious metals lost notable ground. The dollar was modestly higher. The St. Louis financial stress indicator moved sharply lower to a new cyclical low.
U.S. Stock Draws Resume
Overall commercial stocks fell 7.6 million barrels this past week as imports declined and demand increased, widening the year on year stock deficit by 8 million barrels to 89 million barrels, or 6.6%. Both gasoline and distillate showed substantial inventory builds because of weak seasonal demand and high run rates (+720 MB/D Y/Y). Crude stocks drew 3.4 million barrels last week with Cushing crude drawing 2.9 million barrels, the largest weekly draw this year reflecting the Keystone outage. With the Keystone outage largely continuing for next week’s EIA report, Cushing draws 2.8 million barrels of crude while the overall crude stock decline is forecast to be 6.4 million barrels because of higher runs and a sharp reduction in SPR barrels, now that the latest sale is virtually complete. Gasoline and distillate show another large inventory build next week while a rebound in jet demand pulls its stock lower.
Stocks are up 3.6 Million Barrels from this time Last Year
U.S. ethanol production fell to 1,066 MB/D last week, dropping 8 MB/D from the record high 1,074 MB/D set during the preceding week. Despite the decline, output during the holiday-shortened week was still the second highest on record. Total inventories built by 147 thousand barrels to a 19-week high 22.0 million barrels. Stocks are up 3.6 million barrels from this time last year, with Midwest stocks 1.8 million barrels higher. Ethanol-blended gasoline production decreased by 34 MB/D to 9,077 MB/D.
Short-Term Forecast Shows Next Major Supply Push Extended to 2019
PIRA has extended the short-term supply/demand forecast through December 2019. The short-term JKM, NBP, and HH forecasts have also been extended. While we see the market loosening up considerably in 2Q’18, the next major slug of incremental supply is likely to be extended out to 2019. This assumes a much slower ramp-up of the Australian Wheatstone, Ichthys, and Prelude projects over 2018 and an extended ramp-up to full capacity in the US of Cove Point over 2018.
Ukrainian Industrial Gas Prices on the Rise
On December 1, 2017 Naftogaz Ukrainy increased the price of gas sold to industrial consumers on a prepayment basis by 2.4% compared to November. According to the company, this price is relevant for consumers buying gas on a prepayment basis in the amount of more than 50,000 cubic meters per month if there are no debts to the company – this price also applies to 100% subsidiaries of Naftogaz. For other buyers the price, which already was higher, increased by 2.3%.
ISONE 2021/2022 Capacity Auction: S&D Bearish for Price
Our expectation of a $3.60-$4.20/kW-month clearing price in the upcoming Forward Capacity Auction (FCA 12) for the 2021-22 capacity commitment period (CCP) is below the FCA 11 clear of $5.29/kW-month due to looser supply and demand factors. Weaker peak demand expectations have lowered the demand curve and installed capacity requirement (ICR). The linear part of the demand curve also moved further to the left due to a lower adjustment related to the transition to the Marginal Reliability Impact (MRI) curve. Supply also looks higher with more existing Demand Response (DR) resources and state policies favoring clean generation additions.
Japan Still Higher Runs, but Rising Prices Might be Hurting Demand Performance
The key takeaways are that runs continue to rise, and while kero demand has kicked up, other demands look lackluster. On the week, crude imports eased back and crude stocks drew 3.43 MMBbls, while finished product stocks drew slightly due to a good draws in gasoline and kerosene. The market remains largely balanced, for now, but demand performance needs to step up so to absorb higher runs. Implied refining margins eased slightly, but remain decent. Retail prices continue to rise and that “push through” again accelerated last week, with the indicative marketing margin taking another jump higher.
Global Equities Set More Records
Global equity markets set more records this week, with the S&P 500 trying to test the 2,650 level for the first time, and gaining about 1.6%. The strongest domestic sectorial performers were banking (+5.9%), retail (+4.8%), and housing (+3.3%). Energy also outperformed, higher by 2.7%. Internationally, most of the tracking indices lost ground, with the weakest being China, emerging Asia, and emerging markets, all lower 4-5%.
EPA Sets Final Mandates for Biofuels for 2018 and Biomass-based Diesel for 2019
The requirements and standards are similar to what was proposed in July, but the requirements for advanced biofuel was much lower than what was originally specified in RFS2
U.S. September 2017 DOE Monthly Revisions: Demand and Stocks
EIA just released their monthly September 2017 (PSM) U.S. oil supply/demand data. September 2017 demand came in at 19.581 MMB/D, which is 284 MB/D higher than PIRA had assumed, but 635 MB/D lower than the weeklies had indicated. Total product demand “growth” slowed further and became somewhat more negative at -176 MB/D or -0.9% versus year-ago. However, Gulf Coast hurricanes were a headwind and hampered performance, particularly impacting petrochemicals, where NGL demand was down -3.4%. Key transportation fuel drivers such as the American Trucking Association’s “for-hire” truck tonnage index continues to post accelerating growth into October, with gains vs. year-ago reaching 7.3%, while the Federal Highway Administration’s vehicle miles travelled growth pattern has slowed since May and stood at only 0.3% vs. year-ago in September. End-September total commercial stocks stood at 1,304.7 MMBbls, which were 12.6 MMBbls higher than PIRA had assumed. Compared to the preliminary weeklies, total commercial stocks were revised higher by 10.5 MMBbls, with crude raised 4.5 MMBbls and product raised 6.1 MMBbls. Compared to September 2016 PSA data, total commercial stocks are now lower than year-ago by -51.4 MMBbls vs. -63.9 MMBbls at end-August. While the end-Sept crude deficit narrowed vs. Aug, the product deficit grew.
World Biofuel Output to Reach 3.4 MMB/D by 2030
Ethanol production to grow at a 2.8% CAGR. Bio-mass based diesel is projected to make up 3.5% of the world diesel supply by 2030.
November Weather: U.S. and Japan Cold, Europe Warm
November weather for the three major OECD markets turned out to be 10% colder than the 10-year normal and the resulting oil-heat demand effects were 191 MB/D above normal. On a 30-year normal basis, the markets were 1% colder.
Saudi Arabia: Big Gain in Latest FX Reserve Data Could Be Misleading
Saudi Arabia just reported its latest foreign exchange reserve holdings for end-October, which showed a huge month-on-month uptick of $8.1 billion. This was the best month-on-month gain since October 2013. The three month average draw rates slowed to only $0.4 billion, the best since October ‘14. The sudden improvement, however, probably reflected a booking of proceeds from the $12.5 billion bond sale that occurred in late September.
Texas Leads September Production Growth
U.S. crude and condensate actuals for September 2017 came in at 9,510 MB/D, indicating growth of 300 MB/D month-on-month and 950 MB/D year-on-year. Texas growth leads the production surge, with the U.S. reaching volumes not reported since March 2015. PIRA’s Reference Case outlook forecasts U.S. crude and condensate production growing 360 MB/D in 2017 and 730 MB/D in 2018.
The information above is part of PIRA Energy Group's weekly Energy Market Recap - which alerts readers to PIRA’s current analysis of energy markets around the world as well as the key economic and political factors driving those markets. To read PIRA’s Market Recap first, subscribe to PIRA Perspectives here.
Exxon Mobil Corporation (NYSE:XOM) announces that the Hebron project started production safely and ahead of schedule. At its peak, the project will produce up to 150,000 barrels of oil per day.
Discovered in 1980, the Hebron field is estimated to contain more than 700 million barrels of recoverable resources. The Hebron platform consists of a stand-alone gravity-based structure, which supports an integrated topsides deck that includes living quarters and drilling and production facilities. The platform has storage capacity of 1.2 million barrels of oil.
The completed Hebron Oil Platform, before it was towed out to the edge of the Grand Banks off Newfoundland Canada. Photo credit: Wikipedia
The platform is located about 200 miles (350 kilometers) offshore Newfoundland and Labrador in water depths of about 300 feet (92 meters).
“The successful startup of the Hebron project demonstrates ExxonMobil’s disciplined project management expertise and highlights its ability to execute large-scale energy developments safely and responsibly in challenging operating conditions,” said Liam Mallon, president of ExxonMobil Development Company. “We thank the project’s co-venturers for their expertise and support, as well as the employees and contractors who supported construction of the facility, its tow out to the field and drilling of the initial wells.”
During its eight-year engineering, construction and startup phase, the Hebron project contracted hundreds of vendors throughout the province of Newfoundland and Labrador and created about 7,500 jobs during the peak of the construction phase. The project achieved more than 40 million hours without a lost-time injury during construction. “The local and international contractors played a critical role in helping to complete the Hebron project ahead of schedule,” Mallon said. “By leveraging their expertise, we were able to bring this world-class platform online safely and successfully.”
Hebron is operated by ExxonMobil affiliate, ExxonMobil Canada Properties, which holds 35.5 percent equity in the project. Chevron Canada Limited holds 29.6 percent interest, Suncor Energy Inc. holds 21 percent, Statoil Canada Ltd. has 9 percent and Nalcor Energy-Oil and Gas Inc. has 4.9 percent.
Statoil and Total have agreed on a transaction whereby Statoil will acquire Total’s equity stakes in the Martin Linge field (51%) and the Garantiana discovery (40%) on the Norwegian continental shelf (NCS). Statoil will take over both operatorships and pay Total a consideration of USD 1.45 billion.
Martin Linge is an oil and gas field under development west of the Oseberg field in the North Sea. Image credit: Statoil
When in operation, Martin Linge will be a modern production facility with low production cost and low carbon footprint. As a result of the transaction, Statoil will also receive remaining tax balances with a nominal post-tax value of more than USD 1 billion.
“This transaction adds competitive growth assets to our portfolio on the Norwegian continental shelf. The Martin Linge project features innovative solutions to enhance safety, capture value and reduce emissions, in line with our strategy. By leveraging Statoil’s operational experience and existing contracts, we can realize additional opportunities and synergies from these assets,” says Arne Sigve Nylund, Statoil’s executive vice president for Development & Production Norway.
Martin Linge is an oil and gas field under development west of the Oseberg field in the North Sea, with estimated recoverable resources in excess of 300 million barrels oil equivalent. The expected production lifetime extends into the 2030s.
Martin Linge is being developed with a manned wellhead platform. The jacket substructure is already installed on location in the North Sea, while the topside is being completed at the Samsung yard in South-Korea and will be transported to Norway early 2018. The project has experienced schedule delays and cost increases due to delayed topside engineering, construction and currency impact. A tragic accident at the yard in May 2017 also had consequences for the progress of the project. The current operator expects start of production in the first half of 2019. Recoverable resources have increased since the initial Plan for Development and Operation due to additional resources discovered.
Operations will be controlled remotely from an onshore digital operations center, enabling reduced operational expenditures. Electrification is made possible through a 160 km cable from shore, the longest AC power link in the world. This will reduce CO2 emissions by 200,000 tonnes per year. Following completion of the transaction, Statoil will increase from 19% to a 70% interest in the field.
Garantiana is an oil discovery north of the Visund field in the North Sea with a recoverable resource potential between 50 to 70 million barrels oil equivalent. Development concepts are currently being evaluated. Following completion of the transaction Statoil will have a 40% interest in the discovery.
Statoil will take over relevant employees from Total in accordance with the applicable legislation including required information and consultation process.
The transaction is subject to certain conditions, including government approval.
The agreed purchase price is based on an effective date of 1 January 2017. At completion of the transaction in 2018, the amount payable will be subject to adjustment. Statoil will take over as operator upon closing of the transaction in 2018.
Total announces first oil from the Libra mega-field, located in ultra-deep waters 180 kilometers offshore Rio de Janeiro, in the pre-salt Santos Basin in Brazil. The floating production, storage and offloading (FPSO) unit Pioneiro de Libra has a capacity of 50,000 barrels of oil. This start-up of the early production system will generate revenue while also enabling technical data to be collected to optimize the subsequent development phases.
The FPSO which will be used in Libra Extended Well Test was converted in Singapore and arrived in Brazil last May. Photo credit: Total
“Total is pleased that production has begun on the giant Libra field, which is a multi-billion barrel resource,” said Arnaud Breuillac, President, Exploration & Production at Total. “Libra is a major asset in Total’s portfolio and fits into our strategy of investing in highly competitive projects with low break-even points. The start-up is a major step in the development of this field, and Total is bringing its deep offshore expertise to the project.”
Beyond this early production phase, the Libra development will further continue with the next investment decision for the Libra 1 FPSO with a capacity of 150,000 barrels per day. In the years ahead, other production units of similar capacity will be invested in so that the field can be developed to its full potential.
The Libra field is operated by Petrobras (40%) as part of the international consortium whose other partners are Total (20%), Shell (20%), CNOOC (10%) and CNPC (10%).
Total in Brazil
Total has been present in Brazil for over 40 years, has more than 2,800 employees there and operates through five affiliates in the exploration and production, gas, lubricants, chemicals and renewable energies (solar and biomass) segments.
Total Exploration & Production’s portfolio of assets currently includes 15 exploration blocks, located in the Barreirinhas, Ceará, Espirito Santo, Foz do Amazonas and Pelotas basins.
In February 2017, Total and Petrobras signed agreements covering a number of upstream and downstream assets in Brazil, cementing the Strategic Alliance announced in December 2016. Under that deal, Total will hold a 22.5% stake in the Iara concession area in Block BM-S-11 and a 35% stake in and operatorship of Block BM-S-9 in the Lapa field concession, which came on stream in December 2016. Additionally, technical cooperation between the two companies will be strengthened, particularly through joint appraisal of the exploration potential in promising areas in Brazil and through the development of new technologies, particularly in the deep offshore. The transaction is subject to approvals by the relevant regulatory entities.
Talos Energy LLC ("Talos") and Stone Energy Corporation (NYSE: SGY; "Stone") have announced that their Boards of Directors have unanimously approved the combination of Talos and Stone in an all-stock transaction that will create a premier offshore-focused exploration and production company. The company will be named Talos Energy, Inc. and is expected to trade on the New York Stock Exchange ("NYSE") under the new ticker symbol "TALO."
Highlights of the combined company will include:
- Pro forma estimated 2017 average daily production of approximately 47 thousand barrels of oil equivalent (Mboe/d);
- Pro forma proved reserves of 136 million barrels of oil equivalent (MMboe) as of June 30, 2017 based on SEC pricing, which are 69% oil and 74% located in the Deepwater Gulf of Mexico;
- Two recent discoveries, Tornado II and Rampart, provide near-term opportunities for growth;
- Long-term growth profile, underscored by the historic, world-class Zama oil discovery in the shallow waters of Mexico; and
- Strong pro forma balance sheet and credit profile, highlighted by low leverage and ample liquidity.
Under the terms of the transaction, each outstanding share of Stone common stock will be exchanged for one share of Talos Energy, Inc. common stock and the current Talos stakeholders will be issued an aggregate of approximately 34.2 million common shares. At closing, Talos stakeholders will own 63% of the combined company, with Stone shareholders owning the remaining 37%. Based on Stone's stock price of $35.49 on November 20, 2017 and the terms of the proposed transaction, Talos Energy, Inc. will have an initial equity market capitalization of approximately $1.9 billion and an enterprise value of approximately $2.5 billion.
"This combination represents an important step in our goal of becoming the premier offshore exploration and production ("E&P") company. We will have two core areas in the Deepwater U.S. Gulf of Mexico Deepwater and the outstanding new Zama discovery located in the shallow waters of offshore Mexico," stated Timothy S. Duncan, Talos's Chief Executive Officer. "The combined talent, technical resources and balance sheet of the resulting company will allow us to accelerate development of our own robust project inventory while also giving us the horsepower to pursue compelling transactional and exploration opportunities. We fully expect to achieve material operating synergies and maximize capital efficiency going forward. This transaction is a tremendous opportunity for both Talos and Stone as we create a Gulf of Mexico frontrunner."
Neal P. Goldman, Stone's Chairman, stated, "This transaction represents the successful culmination of Stone's previously announced strategic review process and is a compelling opportunity for our shareholders to benefit from the significant upside and synergies of the combined company. Talos Energy, Inc. will have substantial scale, important asset diversification and a talented management team, along with the strong financial position to continue to grow value for our combined shareholder base. I am very proud of Stone's success in growing shareholder value since its financial restructuring in February 2017 and I am confident Tim will lead the combined company to even greater success."
James M. Trimble, Stone's Interim Chief Executive Officer and President, stated, "I want to thank our employees for their focus and dedication in positioning Stone for this important transaction. The team's management of Stone's assets and business in a safe and environmentally responsible manner will continue our success for the combined shareholder base. The combined company will be strategically positioned to drive meaningful production growth through complementary acreage positions. We look forward to this partnership with Tim and the Talos team."
Combination Benefits and Pro Forma Position
The combination will create a leading offshore independent E&P company and a leader in the Gulf of Mexico with a large, high quality asset base and leading cost profile. The combined company will have estimated 2017 average daily production of approximately 47 Mboe and proved reserves of 136 MMboe as of June 30, 2017 based on SEC prices.
The combined company will also benefit from a deep inventory of identified exploration and development prospects and a significant acreage footprint in the Gulf of Mexico, including over 1.2 million combined gross acres, of which approximately 160,000 acres is offshore Mexico. The Zama oil discovery, operated by Talos, was the first private sector offshore exploration well in the history of Mexico and was previously disclosed as having between 1.4 billion and 2.0 billion gross barrels of original oil in place. Additionally, the combined company expects to achieve up to $25 million in annual pre-tax synergies from supply chain management and other operational efficiencies by year end 2018.
The new company will have increased financial flexibility, in part through its expected new $1 billion credit facility with an expected $600 million in initial borrowing capacity, and no material long term note maturities until 2022. Upon closing, the combined company's pro forma unrestricted cash, undrawn credit facility and ability to access public capital markets will provide flexibility to pursue additional attractive growth opportunities. The combined company is expected to have a pro forma net debt-to-2017E EBITDA ratio of 1.4x and approximately $325 million to $375 million in liquidity at closing. Talos Energy, Inc. will be well-positioned as the counterparty of choice for drilling and consolidation opportunities in the Deepwater Gulf of Mexico.