MOSCOW, July 31, 2014 – Honeywell (NYSE: HON) Process Solutions today announced it will upgrade process control and alarm management systems at the Molikpaq platform on the Sakhalin shelf, Russia, to improve safety, reliability and operational efficiency.
The Molikpaq platform, owned by Sakhalin Energy Investment Co. Ltd., celebrated its 15-year anniversary in September 2013. The platform produces 48,000 barrels of crude oil per day.
“Offshore production is associated with a number of risks to workers, the environment and efficient processes, and demands systems that meet the highest reliability, safety and durability standards,” said Frank Whitsura, vice president, Honeywell Process Solutions. “Our innovative solutions are designed to meet the requirements needed to operate in harsh environmental conditions and help our partners to improve their operational and cost efficiencies.”
The Molikpaq platform was installed northeast of Sakhalin, 16 kilometers offshore, at a depth of 30 meters. In the winter, the temperature, including the wind chill, can be as cold as 70 degrees below zero Fahrenheit.
To modernize the process control system and improve safety at the facility, Honeywell will implement the latest version of its Experion® Process Knowledge System (PKS), which will be extended by the new C300 controller including Foundation Fieldbus license. By enabling unified access to process control, production management and asset management, the distributed control system will help to improve efficiency and profitability, reduce total cost of ownership while helping the facility achieve optimum production of oil.
In addition, Honeywell will install its DynAMo™ Alarm Suite, which leverages more than 20 years of alarm management experience in the process industries, and can help users reduce overall alarm count by as much as 80 percent, identify maintenance issues, and increase visibility of critical alarms that require urgent attention.
Honeywell Process Solutions (www.honeywellprocess.com) is a pioneer in automation control, instrumentation and services for the oil and gas; refining; pulp and paper; industrial power generation; chemicals and petrochemicals; biofuels; life sciences; and metals, minerals and mining industries. Process Solutions is part of Honeywell’s Performance Materials and Technologies strategic business group, which also includes UOP, a leading international supplier and licensor of process technology, catalysts, adsorbents, equipment, and consulting services to the petroleum refining, petrochemical, and gas processing industries.
Honeywell (www.honeywell.com) is a Fortune 100 diversified technology and manufacturing leader, serving customers worldwide with aerospace products and services; control technologies for buildings, homes and industry; turbochargers; and performance materials. Based in Morris Township, N.J., Honeywell’s shares are traded on the New York, London, and Chicago Stock Exchanges. For more news and information on Honeywell, please visit www.honeywellnow.com.
Having evaluated the different options for Maersk Drilling, A.P. Moller – Maersk has concluded that listing Maersk Drilling as a standalone company presents the most optimal and long-term prospects for its shareholders, offering them the possibility to participate in the value creation opportunity of a globally leading pure play offshore drilling company with long-term development prospects.
The process has been initiated to ensure that Maersk Drilling is operationally and organisationally ready for a listing in 2019. As part of the preparation, debt financing of USD 1.5bn from a consortium of international banks has been secured for Maersk Drilling to ensure a strong capital structure after a listing. Further details for a listing will be announced at a later stage.
Separation of the oil & oil related businesses
The decision on the future of Maersk Drilling marks a milestone in the business transformation of A.P. Moller – Maersk towards becoming an integrated transport & logistics company as announced on 22 September 2016.
The target was set to find new viable solutions for the oil and oil related businesses within 24 months. During the past two years solutions for Maersk Oil and Maersk Tankers have been found and today the plan to list Maersk Drilling is announced.
For Maersk Supply Service, the pursuit of a solution will continue. However due to challenging markets, the timing for defining a solution is difficult to predict.
Chairman of the A.P. Moller – Maersk Board of Directors, Jim Hageman Snabe says:
“The Maersk Drilling team has done a remarkable job operating the business at a time of high uncertainty and is well positioned to become a successful company on Nasdaq Copenhagen. The announcement of the intention to list Maersk Drilling completes the decision process on the structural solutions for the major oil and oil related businesses. Yet another important step in delivering on the strategy.”
Capital structure and proceeds from the oil & oil related businesses
A.P. Moller – Maersk remains committed to maintaining its investment grade rating which is demonstrated by increased capital discipline over the last two years combined with maintaining a high financial flexibility.
Net cash proceeds to A.P. Moller-Maersk from separation of Maersk Oil, Maersk Tankers and now expected Maersk Drilling is around USD 5bn. Maersk Drilling’s separate financing is expected to release cash proceeds of around USD 1.2bn to A.P. Moller – Maersk.
In addition, A.P. Moller-Maersk sold Total S.A. shares for an aggregated amount of around USD 1.2bn during July 2018. This represents the increase in value since signing of the sale of Maersk Oil in August 2017. A.P. Moller – Maersk retains 78.3 million shares in Total S.A. with a current aggregated value of around USD 5bn.
Subject to maintaining investment grade rating it is now expected that:
Maersk Drilling will be demerged via a listing in 2019 with distribution of Maersk Drilling shares to A.P. Moller – Maersk’s shareholders
Following the demerger of Maersk Drilling a material part of the remaining Total S.A. shares will be distributed to A.P. Moller – Maersk’s shareholders in cash dividends, share buy-backs or as a distribution of the Total S.A shares directly
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Growing, digitizing and integrating across transport and logistics
The overall transport and logistics business has grown significantly over the last two years – both organically and inorganically through the acquisition of Hamburg Süd. A turnover close to USD 40bn is expected for 2018, equaling an increase of almost 50 percent since 2016. The non-Ocean business is as planned growing organically at a higher pace than the Ocean business.
Synergies are being realised as expected and the business is on track to deliver around USD 1bn by end 2019 from integration of Hamburg Süd and increased collaboration across the transport and logistics business.
“With the decision made on Maersk Drilling, A.P. Moller – Maersk can stay focused on transitioning into an integrated transport and logistics company and developing solutions to meet our customers end-to-end supply chain management needs. New value adding services as well as customer experience are improving continuously based on digital solutions. We will continue to grow revenue with a specific focus on non-Ocean revenue and at the same time improve our current unsatisfactory level of profitability,” says CEO of A.P. Moller – Maersk, Søren Skou.
Chairman of the A.P. Moller – Maersk Board of Directors, Jim Hageman Snabe continues:
“The Board initiated the fundamental business transformation of A.P. Moller – Maersk almost two years ago. This is a massive undertaking touching all parts of our company globally and I would like to thank the management for progressing on many strategic efforts in parallel.”
ABOUT
A.P. Moller – Maersk is an integrated container logistics company working to connect and simplify its customers’ supply chains. As the global leader in shipping services, the company operates in 130 countries and employs roughly 76,000 people.
With simple end-to-end offering of products and digital services, seamless customer engagement and a superior end-to-end delivery network, Maersk enables its customers to trade and grow by transporting goods anywhere – all over the world.
Air BP today announced its agreement to purchase the aviation fuel business, Statoil Fuel & Retail Aviation AS (SFR Aviation), from Canadian company Alimentation Couche-Tard Inc. The deal will add around 73 new airports in the Nordic countries and Northern Europe to Air BP’s 600-strong global fuels network. The deal, which is subject to regulatory approvals, is expected to close by the end of 2014. On completion around 59 SFR Aviation employees, currently based in Norway, Sweden and Denmark are expected to join Air BP.
David Gilmour, chief executive of Air BP, said: “Bringing SFR Aviation’s business into our own strengthens our position in Scandinavia which is an attractive region for the aviation industry, especially in the general aviation market. This deal will grow BP’s airport coverage, as well as introduce us to new customers, and give us access to SFR Aviation’s quality infrastructure and operations. It complements our existing presence in the region and will allow us to expand where we see long term prospects.”
The acquisition gives Air BP presence in new locations, particularly in Norway, and a strong position in the general aviation customer segment.
“As a competitive, leading supplier in the region we’ll be offering our new commercial airline, general aviation and military customers Air BP’s full range of services including security of supply, product quality assurance, our technical services offer, and 24/7 customer support,” said Gilmour.
The acquisition brings Air BP a network of quality locations, high operating standards, new supply and sales agreements including some military contracts, a fleet of refuelling vehicles, and storage and distribution infrastructure.
SFR is selling its aviation fuel business, comprising supply at 79 airports across Norway, Sweden, Denmark, Faroe Islands, Greenland, Finland, Netherlands and Germany, plus interests at 3 airports in the UK & Belgium
Air BP, the aviation division of BP, is one of the world’s largest suppliers of aviation fuel products and services with over 1,100 employees. It currently supplies over seven and a half billion (US) gallons of jet kerosene and aviation gasoline to its customers across the globe each year.
Through its direct operations, Air BP fuels more than 6,400 flights every day – that’s one every 15 seconds. The company operates at more than 600 locations in over 45 countries serving customers including the private pilot, military aircraft, business and private aircraft owners, commercial airlines in addition to international airports and airfield operators.
General Aviation is the civil aviation industry other than commercial airlines – business jets, emergency services, flying schools, offshore industry helicopters, small airfields, private pilots, etc. It is a fast growing sector in all regions of the world.
NEW YORK & SÃO PAULO- Alcoa (NYSE: AA) today announced it will curtail 147,000 metric tons of smelting capacity at its São Luís (Alumar) and Poços de Caldas smelters in Brazil due to challenging global market conditions in primary aluminum and increased costs that have made the smelters uncompetitive. The curtailments are expected to be complete by the end of May 2014.
In 2013, the Company curtailed 34,000 metric tons at Poços and 97,000 metric tons at São Luís. The new curtailments will include the remaining 62,000 metric tons of capacity from the Poços smelter, resulting in a full curtailment of its three potlines. Another 85,000 metric tons will be curtailed at São Luís.
“Across the globe, we are taking measures to curtail high-cost smelting capacity that is not competitive and reshape our cost profile,” said Bob Wilt, President of Alcoa Global Primary Products. “These are difficult but necessary actions in support of Alcoa’s strategy to lower the cost base of our upstream businesses.”
As a result of the smelter curtailment, the Poços refinery will also reduce production accordingly. The mine, aluminum powder plant and casthouse at Poços will continue normal operations, as will the refinery at São Luís. Other Alcoa operations in Brazil are not affected.
“We know how deeply this decision affects our employees, our contractors and our communities,” said Aquilino Paolucci, President of Alcoa Latin America and the Caribbean. “While our teams have worked incredibly hard to make these facilities more competitive, we must take steps regarding our primary metal production in Brazil given the market conditions we are facing. We appreciate the support of governments at all levels, and will actively work in partnership with our employees, unions, and community stakeholders to manage through this transition and minimize the impact.”
In May 2013, Alcoa placed 460,000 metric tons of smelting capacity under review. Once all announced curtailments and closures are complete, Alcoa will have approximately 800,000 metric tons, or 21 percent, of smelting capacity offline.
Total restructuring-related charges associated with the Brazil curtailments in the first quarter are expected to be between $40 million and $50 million after-tax, or $0.04 to $0.05 per share, of which approximately 30 percent would be non-cash.
Alcoa’s review of its primary metals operations is consistent with the Company’s goal of lowering its position on the world aluminum production cost curve to the 38th percentile and the alumina cost curve to the 21st percentile, by 2016.
About Alcoa in Brazil
Alcoa operates in Brazil throughout the aluminum production chain, from bauxite mining to the production of transformed and value-add products. Alcoa has 5,700 employees and six production units and offices in the states of Maranhão, Minas Gerais, Pará, Pernambuco, Santa Catarina, São Paulo and Federal District. Alcoa owns 100% of the Poços smelter, and the São Luís smelter is owned 60% by Alcoa Alumínio and 40% by BHP Billiton. The Company also has shareholdings in Mineração Rio do Norte (MRN) and in four hydroelectric power plants: Machadinho, Barra Grande, Serra do Facão and Estreito. In 2013 it was considered the most sustainable company in its industry and in the category of Relationship with Suppliers of the Guia EXAME de Sustentabilidade [EXAME Magazine’s Sustainability Guide]. In the same year, it was recognized for the twelfth time as one of the Best Companies to Work and for the second consecutive year the Best Company for Women to Work in Brazil, by the Great Place to Work Institute.
About Alcoa
A global leader in lightweight metals engineering and manufacturing, Alcoa innovates multi-material solutions that advance our world. Our technologies enhance transportation, from automotive and commercial transport to air and space travel, and improve industrial and consumer electronics products. We enable smart buildings, sustainable food and beverage packaging, high-performance defense vehicles across air, land and sea, deeper oil and gas drilling and more efficient power generation. We pioneered the aluminum industry over 125 years ago, and today, our 60,000 people in 30 countries deliver value-add products made of titanium, nickel and aluminum, and produce best-in-class bauxite, alumina and primary aluminum products. For more information, visit www.alcoa.com,
This news is courtesy of www.alcoa.com
ROSSLYN, VA., A new study released today confirms the growing importance of the domestic aluminum industry to the U.S. economy. Research conducted by economic research firm John Dunham & Associates found that the U.S. aluminum industry directly employs more than 155,000 workers and generates $65 billion in economic output in all 50 states and the District of Columbia.
According to the study, for each aluminum industry job an additional 3.3 jobs are created elsewhere in the economy for a total of 672,000 jobs. When supplier and induced impacts are taken into account, the industry has an economic footprint of more than $152 billion – nearly 1% of Gross Domestic Product.
Other key findings from the report include:
Workers directly employed by U.S. aluminum industry earned more than $12 billion in wages and benefits in 2013.
Indirect employment by the industry creates another $29 billion in wages and benefits.
When all employment supported by the industry is taken into account, these jobs generate nearly $16 billion in federal, state and local taxes.
These workers earn average compensation of more than $60,000, far exceeding the national average of $43,000.
“As an integral part of the U.S. manufacturing base and overall economy, the aluminum industry supports hundreds of thousands of high quality manufacturing jobs in communities of all sizes,” said Layle “Kip” Smith, President and CEO of Noranda and Chairman of the Aluminum Association. “Aluminum is a vital material for the modern era and a bellwether for domestic manufacturing.”
The Aluminum Association last released an economic impact study based on 2009 data that reported 106,000 jobs directly supported by the aluminum industry. The new study uses an improved methodology in order to more fully capture the industry’s footprint. The new methodology is based on company specific microdata rather than aggregate data from the Bureau of the Census. Microdata captures the actual physical locations of all the firms in the different facets of the industry, whereas Census Data only captures the broad-based employment numbers, generally only from the largest firms. The new results show significant job growth in a number of key areas:
4X increase in secondary smelting and alloying jobs (4,500 vs. 16,800)
73% increase in sheet, plate, foil and extruded products jobs (32,500 vs. 56,200)
23% increase in foundries jobs (29,600 vs. 36,400 jobs)
“It’s encouraging to see that, as an industry, we’re growing,” said Heidi Brock, President of the Aluminum Association. “As the country recovers from the recession, we’re seeing demand for our product bouncing back – up 30 percent since 2009. Lightweight, durable and highly recyclable, aluminum is a metal uniquely suited to the 21st century.”
The study was completed by economic research firm John Dunham & Associates and is based on data provided by Dun & Bradstreet, Inc., the federal government and the Aluminum Association. The analysis uses the Minnesota IMPLAN Model to quantify the economic impact of the aluminum industry on the overall U.S. economy.
For the purposes of the report, the aluminum industry is defined to include alumina refining; primary aluminum processing; secondary aluminum smelting and alloying; manufacturing of aluminum sheet, plate, foil, extrusions, forgings, coatings, and powder; aluminum foundries; metals service centers, and wholesalers. The study measures the number of jobs in this industry, the wages paid to employees, total economic output, and federal and state business taxes generated.
Courtesy of The Aluminium Association
Today, the White House and the Department of Energy are hosting a Capstone Methane Stakeholder Roundtable. In addition, DOE is announcing a series of actions, partnerships, and stakeholder commitments to help modernize the nation’s natural gas transmission and distribution systems and reduce methane emissions.
The Capstone event is the culmination of four previous in-depth Roundtables at which leaders from industry, environmental organizations, state regulators, consumer groups, academia, and manufacturing and labor unions were asked to provide Administration and other representatives with their individual perspectives on opportunities to modernize natural gas infrastructure and reduce mid- and downstream methane emissions.
The fundamental lesson learned from the Roundtables: there is broad stakeholder support for taking action that reduces methane emissions from natural gas transmissions and distribution systems. The drivers for these actions, however, vary by the groups represented at the Roundtables and include: the potential for increasing jobs associated with transmission and distribution system maintenance and equipment upgrades; opportunities for enhancing cost recovery for infrastructure investments and expanding markets; concerns about providing reliable and affordable utility service; the commitment to improving safety; and addressing near term opportunities to address climate change. Roundtable participants identified a range of opportunities across these many fronts.
The path forward emerging from the Methane Roundtables — a key deliverable in the Climate Action Plan Strategy to Reduce Methane Emissions — also addresses several key Administration goals, including:
Enhancing job creation, affordable energy, infrastructure modernization, and the role of natural gas in a clean energy economy;
Reducing methane emissions from natural gas systems; and
Producing the first-ever Quadrennial Energy Review, focusing on America’s energy infrastructure.
Representatives from all of the participating sectors are coming together today to discuss lessons learned and actions that will be taken to modernize natural gas transmission and distribution infrastructure. It is not intended to be an end point for action, rather an inflection point for a range of actions to follow. DOE’s initiative — Investing in Gas T&D Infrastructure: Improving Safety, the Economy, the Environment, and Creating Jobs — incorporates many of the lessons learned from the Roundtables and, together with stakeholder commitments, establishes a path forward to address these critical issues.
INITIATIVE TO MODERNIZE NATURAL GAS TRANSMISSION AND DISTRIBUTION INFRASTRUCTURE
The Department of Energy is announcing several new initiatives and enhancing existing programs to modernize infrastructure and reduce methane emissions through common-sense standards, smart investments, and innovative research to advance the state of the art in natural gas system performance. These initiatives include:
Efficiency Standards for Natural Gas Compressors. Today, DOE will take the first step toward establishing energy efficiency standards for new natural gas compressor units by issuing a Request for Information. Gas compressor units are estimated to consume over 7 percent of natural gas end use in this country, and improved efficiency will provide meaningful energy savings and reductions in greenhouse gas emissions.
Incentives for Modernization of Natural Gas Transmission System Infrastructure. Following discussions with Chairwoman Cheryl LaFleur, the Secretary of Energy is recommending that the Federal Energy Regulatory Commission to explore efforts to provide greater certainty for cost recovery for new investment in modernization of natural gas transmission infrastructure, as part of FERC’s work to ensure just and reasonable natural gas pipeline transportation rates. These efforts may include additional consideration of a simplified cost recovery mechanism for gas transmission companies who replace old and inefficient compressors and leak-prone pipes and perform other infrastructure improvements and upgrades to enhance the safe and reliable operation of the pipeline.
Advanced Natural Gas System Manufacturing R&D Initiative. DOE is launching a collaborative effort with industry with the goal of establishing an Advanced Natural Gas System Manufacturing R&D initiative. The initiative will evaluate and scope high-impact manufacturing research and development to improve natural gas system efficiency and reduce leaks. This will include a formal Request for Information, public workshops, and technical analysis and will leverage technology development areas already in progress through the Administration’s Advanced Manufacturing Partnership (AMP 2.0), including Advanced Sensors, Control, and Platforms for Manufacturing; Advanced Materials Manufacturing; and Advanced Reciprocating Engine Systems.
Pipeline Efficiency Research, Development and Demonstration Program. DOE is proposing to establish a new “First Things First” natural gas infrastructure technology program, focusing on RDD&D to enhance pipeline and distribution system operational efficiency and reduce methane emissions. The goal of the program is to drive research and technology development to improve identification of methane leaks, for example, by developing smart sensor technologies that collect and communicate data on a variety of operational parameters such as operating pressure and flow rates.
Providing Loan Guarantees for New Reduction Technologies: Advanced Fossil Energy Projects that Reduce Methane Emissions. DOE will conduct outreach to industries in the advanced fossil sector and other stakeholders to increase awareness of the $8 billion solicitation that DOE issued in December 2013 to provide loan guarantees to spur commercialization of innovative technologies that reduce methane emissions from gas transmission and distribution systems. This includes, but is not limited to, projects involving new wellhead drilling technology, flare reduction, methane capture and collection, or reducing methane leakage from pipelines and distribution networks.
Investing in Technologies for Leak Detection and Measurement. DOE’s efforts will build on the methane sensing initiative underway at ARPA-E, which on April 29, 2014, released a funding opportunity announcement for up to $30 million for the Methane Observation Networks with Innovative Technology to Obtain Reductions (MONITOR) program. This program seeks to fund disruptive technologies for low-cost, highly sensitive systems for the detection and measurement of methane associated with the production and transportation of oil and natural gas.
Quadrennial Energy Review. DOE will continue to conduct analysis and engage with stakeholders and the public through meetings for the Quadrennial Energy Review (QER). Two recent QER meetings in Pittsburgh and Denver focused in part on natural gas transmission and distribution systems and the need for modernization. These meetings are engaging stakeholders and the public in the development of the first installment of the QER, which focuses specifically on energy transmission, storage, and distribution infrastructure. This QER will include analysis to estimate the job creation from manufacturing, installing and maintaining equipment associated with reducing natural gas system leakage through a specific set of best practices.
PARTNERSHIPS & ENHANCED COORDINATION
Building on suggestions from Roundtable participants to enhance coordination within the Administration and with stakeholders, DOE is announcing the following new partnerships and collaborative efforts:
State Leadership for Efficient Natural Gas Distribution. DOE will join with the National Association of Regulatory Utility Commissioners (NARUC) in a technical partnership to enable investments in infrastructure modernization and repairs to natural gas distribution networks. The role for DOE will be to provide grant funding and technical assistance to help inform decision-making by state utility commissioners. Through research and technical workshops, NARUC and DOE will also work with other federal agencies to convene decision makers, including the Pipeline and Hazardous Materials Safety Administration (PHMSA), to help establish leak measurement protocols and to identify new technologies and cost-effective practices for enhancing pipeline safety, efficiency and deliverability.
Sharing Solutions on Methane Measurement and Reduction
Establishing a Clearinghouse. In close consultation with stakeholders and other federal agencies, DOE will develop a public clearinghouse to share information on successful strategies for measuring and reducing methane emissions, such as information on methane measurement studies, technology R&D, job creation, policies, and incentives, among other quantifiable co-benefits or drivers of infrastructure development. The first steps will be to consult with individual roundtable participants and potential clearinghouse partners, conduct broader outreach, survey existing resources and identify gaps, and identify potential partners.
Convening Workshops. DOE will also host workshops on technical solutions, financial models and other best practices to stimulate public discussion and inform company investments and policy actions. This will include measurement technologies and their various applications, strengths and limitations as well as policy options that can drive the adoption of improved sensing technologies into the marketplace.
Follow-on Coordination and Collaboration. The Methane Capstone is an inflection point in our efforts to work with other agencies and stakeholders.
Intra-DOE collaboration. Several different DOE program offices are actively involved with implementing various aspects of the Administration’s Strategy to Cut Methane Emissions. DOE has initiated an internal methane working group to help coordinate these activities within DOE and to continue engagement with external stakeholders, and to ensure that technology and policy development activities are shared with other agencies.
Interagency collaboration. The White House is working with DOE, DOT (PHMSA), EPA, DOI and other agencies under the umbrella of the Quadrennial Energy Review and the Interagency Methane Strategy to share the lessons learned from the roundtables, collaborate on the range of new activities under this natural gas infrastructure initiative, and make it easier for stakeholders to engage on these issues.
Stakeholder collaboration. As discussed at the Roundtables, DOE will continue to work with stakeholders on these initiatives to modernize the nation’s natural gas transmission and distribution systems and reduce methane emissions.
COMMITMENTS FROM ROUNDTABLE PARTICIPANTS
SAVE ENERGY, STOP LEAKS, START WORK
Capstone participants have demonstrated leadership on methane leakage reductions and are making specific commitments going forward. For example:
A group of five unions, the United Association of Plumbers and Pipefitters, the International Brotherhood of Electrical Workers, the Utility Workers Union of America, the Laborers International Union of North America, and the United Steelworkers, are announcing an expansion of apprenticeship and training programs to meet the need for skilled construction and utility workers to meet the growing demand for employees to replace and repair existing distribution pipeline systems.
The Interstate Natural Gas Association of America’s membership has greatly reduced leaks over the last 30 years, as part of various safety improvements; they pledge to reduce methane releases even further by focusing on major leaks around key equipment, and developing guidelines for directed inspection and maintenance at those facilities.
Through initiatives outlined in the American Gas Association document “The LDC Story: A Focus on Safety Also Benefits the Environment,” the natural gas utility industry will continue its concerted effort to upgrade and modernize our nation’s pipeline network to enhance safety, which has also contributed significantly to a declining trend in emissions from the natural gas system while balancing costs with an eye towards providing clean natural gas to customers at affordable prices.
National Grid is investing more than $1 billion in its natural gas infrastructure this year and $6 billion over the next five years, to both grow the distribution network to meet customer demands and reduce methane emissions through main pipeline replacement and technology deployment. National Grid is committed to working with the Administration, federal and state regulators, other energy companies, local communities, and other stakeholders, to bring the nation’s energy network into the 21st century.
PSE&G recently reached a settlement on its Energy Strong proposal with the New Jersey Board of Public Utilities BPU that will allow them to proactively protect, strengthen, and modernize a portion of the gas systems against severe weather conditions. The result will be an increase in resiliency, safety, and a continuation of declining emissions reductions.
PG&E, the second largest gas utility in the country, is taking actions today that enhance safety, create jobs and protect the environment by deploying advanced leak detection technologies to efficiently find and fix leaks, accelerating pipe replacement and eliminating cast iron, improving the way employees do their work, and partnering with key stakeholders to more accurately measure and account for methane associated with the operation of the natural gas delivery system.
NW Natural is committed to completing its pipeline modernization program, with removal of cast iron pipes completed in 2000 and the last of their bare steel pipe scheduled for replacement in 2015. The company is also assessing new methods to further tighten the system through modifications of equipment and use of advanced emission reduction techniques during pipeline maintenance.
The National Association of Regulatory Utility Commissioners will join DOE in a technical partnership.
The BlueGreen Alliance (BGA), a national partnership of labor unions and environmental organizations, will launch a national public education campaign supporting accelerated repair and replacement of America’s natural gas distribution pipelines later this year. The BlueGreen Alliance recently published its report, Interconnected: The Economic and Climate Change Benefits of Accelerating Repair and Replacement of America’s Natural Gas Distribution Pipelines, that shows the U.S. can grow or sustain over 300,000 jobs by tripling the current rate of repair and replacement of pipes in the distribution system.
Environmental Defense Fund is collaborating with groups of industry, academics, and other experts, to conduct foundational science to improve understanding of the scale and sources of methane emissions across the natural gas supply chain, as well as conducting independent economic research to demonstrate where the most cost-effective reduction opportunities exist.
Participants in the Downstream Initiative (Consolidated Edison Company of New York, Inc., National Grid, Pacific Gas & Electric, Public Service Electric & Gas, and Xcel Energy) are committed to working with the Administration, federal and state regulators, and stakeholders to address technical, regulatory, and workforce challenges to modernize infrastructure and achieve additional methane emissions reductions from the distribution segment. While natural gas utility companies have made progress over the years reducing methane emissions, they are committed to taking a leadership role and doing more to modernize infrastructure going forward to realize the safety, economic, environmental, and health benefits that natural gas provides their customers.
Southwestern Energy Company believes that opportunities exist to cost-effectively reduce methane emissions from the natural gas sector, and is taking steps to pursue these opportunities through measurement R&D; implementing new technologies and practices to reduce methane emissions, including a company-wide leak detection and repair program; and collaborating with other companies across the natural gas supply chain to identify cost-effective solutions for reducing methane emissions and enhancing the energy delivery efficiency of the natural gas supply chain.
Peoples Gas is committed to reducing methane emissions through an accelerated investment in its natural gas distribution system in Chicago. More than 1,000 highly skilled workers across multiple trades are replacing the infrastructure to reduce methane emissions by 192,000 metric tons of carbon dioxide equivalent (CO2e), comparable to taking 38,000 cars off the road.
Shell’s CEO Ben van Beurden today updates on 2014 performance and his priorities for the company, in presentations to financial markets.
Van Beurden commented: “Shell has delivered where it counts in 2014. We are stepping up our drive for stronger capital efficiency, whilst being careful not to over-react to the recent fall in oil prices.
Successful delivery of 2014 programme. Improved financial and operating performance including $25 billion free cash flow: strengthening of the balance sheet; $15 billion of dividends and share buybacks; reduction of capital investment; early completion of $15 billion divestment target; and implementation of tighter performance management.
2015 to see continuation of 2014 drive to balance growth and returns. New restructuring programmes in world-wide resources plays and upstream engines, leveraging oil price downturn to capture multi-billion supply chain cost opportunities world-wide, and plans to reduce Shell’s operating costs in 2015.
Organic capital investment in 2015 is expected to be lower than 2014 levels, and we have curtailed over $15 billion of potential spending over the next three years. Shell has options to further reduce spending, but we are not over-reacting to current low oil prices and keeping our best opportunities on the table.
Shell’s strategy is founded on disciplined capital investment, integrated operations, technological expertise and large scale. This is underpinned by an unrelenting focus on safety. Investment in long term opportunities is balanced with short term delivery.
Van Beurden continued: “We set out an agenda in 2014 to balance growth and returns in Shell, and our results in 2014 show that this strategy is impactful where it matters: at the bottom line. By successfully delivering against our three key priorities of better financial performance, enhanced capital efficiency and continued strong project delivery, we are improving Shell’s competitive position in the oil & gas industry.”
Delivery in 2014 included:
Improved earnings and returns, including $25 billion of free cash flow, underpinning $15 billion of dividends and share buybacks.
Tighter performance management and accountability implemented across the company, including increased shareholding requirements for senior management to further align interests with shareholders.
Restructuring programmes and cost reduction in North America resources plays, where major portfolio changes are now complete; and in Oil Products, where substantial progress has been made and new cost programmes were launched at the end of 2014.
Increased asset sales – some $15 billion in 2014, completed before markets weakened across the end of the year, and reduced capital spending, as we make decisions on portfolio to improve Shell’s capital efficiency.
Successful delivery of new projects including deep water, and successful integration of the LNG portfolio purchased from Repsol, which delivered over $1 billion to CFFO in 2014.
A firm uptick in the 2014 exploration performance, with 10 material discoveries in frontier and heartland basins, and a further 41 near-field discoveries.
Van Beurden continued: “Our strategy is delivering, but we’re not complacent. Weaker oil prices underline that there’s a lot more to do. The three themes of financial performance, capital efficiency and project delivery will remain as Shell’s priorities in 2015.”
In 2015, these priorities will include a focus on the following:
Financial performance
This will include a continued drive to improve performance in Oil Products and North America resources plays, and new restructuring programmes in Upstream engines and International resources plays.
Cost competitiveness is integral to our tighter performance management drive. Our established programmes and new initiatives are expected to move operating costs down in 2015.
Capital efficiency
Given Shell’s rich portfolio funnel and today’s lower oil prices, investment levels are under severe pressure in the near term. Today’s lower prices are creating opportunities to reduce our own costs and to take costs out of the supply chain, where there is multi-billion dollar savings potential for Shell.
In addition, the company is deferring spending in many areas, without compromising on HSSE, exiting selective growth positions, and driving costs down in the supply chain. This should result in reduction of potential capital investment for 2015-17 of over $15 billion.
2015 organic capital investment is expected to be lower than 2014 levels. Shell is considering further reductions to capital spending should the evolving market outlook warrant that step, but is aiming to retain growth potential for the medium term.
Project delivery
2015 should see further ramp-up from the new fields brought on line in 2014. The company continues to invest in a competitive suite of new oil & gas fields and LNG, with the next wave of significant start-ups in the 2016-18 timeframe.
Van Beurden continued: “The agenda we set out in early 2014 to balance growth and returns has positioned us well for the current oil market downturn. However, lower oil prices and the impact of our 2014 divestments will likely reduce this year’s cash flow.”
Shell announced dividends of $12 billion in 2014 and repurchased $3.3 billion of shares. We slowed our buyback program at the end of 2014 to conserve cash, and near-term oil prices will dictate the buyback pace.
Van Beurden concluded: “We are taking a prudent approach here and we must be careful not to over-react to the recent fall in oil prices. Shell is taking structured decisions to balance growth and returns.”
BHP Billiton notes the range of media reports and public commentary on the composition of the tailings released from the Samarco Fundão dam, in Minas Gerais, Brazil, on 5 November 2015.
The tailings that entered the Rio Doce were comprised of clay and silt material from the washing and processing of earth containing iron ore, which is naturally abundant in the region. Based on available data, the tailings are chemically stable. They will not change chemical composition in water and will behave in the environment like normal soils in the catchment.
The National Water Agency (ANA) and Brazilian Geological Service (CPRM) are continuing to collect, analyse and report water and sediment samples in the Rio Doce.
Results from these samples on 14 November 2015 indicate “that concentrations of metals obtained at these sites do not significantly differ from the results produced by CPRM in 2010”. The results, published on 20 November, can be found online.
In addition, Samarco has issued a statement today indicating that further tests carried out by SGS GEOSOL Laboratórios after the incident confirm the waste from the Fundão dam is not hazardous to human health.
Samarco statements can be found at www.samarco.com and in other online channels.
– Group production increased by 9% during the December 2014 half year with records achieved for eight operations and five commodities. Production guidance remains unchanged and we are on track to deliver Group production growth of 16% over the two years to the end of the 2015 financial year.
– Metallurgical coal production increased by 21% to 26 Mt in the December 2014 half year as Queensland Coal and Illawarra Coal both achieved record half year volumes.
– Western Australia Iron Ore production increased by 15% to a record of 124 Mt (100% basis) in the December 2014 half year as the ramp-up of Jimblebar continued and we improved the availability, utilisation and rate of our integrated supply chain.
– Petroleum production increased by 9% to a record 131 MMboe in the December 2014 half year supported by a 71% increase in Onshore US liquids volumes to 24.4 MMboe.
– Copper production(1) decreased by 2% to 813 kt as strong underlying operating performance across the business was offset by lower grades at Antamina.
– Record manganese ore and alumina production was underpinned by strong performances at both Hotazel and the Alumar refinery.
BHP Billiton Chief Executive Officer, Andrew Mackenzie, said: “Our operational performance over the last six months has been strong. We are reducing costs and improving both operating and capital productivity across the Group faster than originally planned. These improvements will help mitigate some of the impact of lower commodity prices and we remain alert to opportunities to further increase free cash flow.
“In Petroleum, we have moved quickly in response to lower prices and will reduce the number of rigs we operate in our Onshore US business by approximately 40 per cent by the end of this financial year. The revised drilling program will benefit from significant improvements in drilling and completions efficiency. Our ongoing shale investment program will remain focused on our liquids-rich Black Hawk acreage. However, we will keep this activity under review and make further changes if we believe deferring development will create more value than near-term production.
“We continue to believe that our planned demerger will help support further improvements in operating performance in both the core BHP Billiton and South32 assets. Within BHP Billiton, it would allow us to identify and deploy best practice across our assets more quickly and simplify our organisation to reduce overheads. We are making good progress towards securing the approvals we require to put the proposal to a shareholder vote in May and remain on track to complete the process before the end of the financial year.”
Major development projects
The Escondida Oxide Leach Area Project was successfully completed during the December 2014 quarter and the BMA Hay Point Stage Three Expansion project loaded first coal on 12 January 2015, both on revised schedule and budget. The Escondida Oxide Leach Area Project will not be reported in future Operational Reviews. At the end of the December 2014 half year, BHP Billiton had seven major projects under development with a combined budget of US$13.5 billion.
Corporate update
On 8 December 2014, BHP Billiton announced that the new company it intends to create through its proposed demerger will be called South32. A final Board decision on the proposed demerger will be made once all necessary third party approvals are secured on satisfactory terms. On this basis, BHP Billiton expects to release all shareholder documentation with full details of the proposed demerger in mid-March 2015, with a shareholder vote taking place in early May 2015. The demerger remains on track to be completed in the first half of the 2015 calendar year.
BHP Billiton expects Underlying attributable profit in the December 2014 half year to include impairment charges in the range of approximately US$200 million to US$250 million recognised as a result of the divestment of conventional petroleum assets in North Louisiana and unconventional gas assets in the Pecos field in the Permian.
The Minerals Resource Rent Tax (MRRT) in Australia has been repealed and was applicable until 30 September 2014. As a result, the MRRT deferred tax asset carried by the Group was derecognised and an income tax charge of US$809 million will be reported as an exceptional item in the December 2014 half year. The Group’s adjusted effective tax rate(4) is expected to remain in the range of 30 per cent to 34 per cent in the December 2014 half year.
On 12 November 2014, BHP Billiton announced that the review of its Nickel West business was complete and the preferred option, the sale of the business, was not achieved on an acceptable basis. As a result of operational decisions made subsequent to the conclusion of this process, an impairment charge in the range of US$200 million to US$350 million (after tax expense) will be recognised as an exceptional item in the December 2014 half year. At this time, Nickel West remains in the BHP Billiton portfolio and the Company continues to operate the business to maximise production, reduce operating costs and increase free cash flow. This guidance will be updated should material information or events arise as the Company finalises its financial statements.
Marketing update
The average realised prices achieved for our major commodities are summarized in the table below. Iron ore shipments, on average, were linked to the index price for the month of shipment, with price differentials reflecting product quality. The majority of metallurgical coal and energy coal exports were linked to the index price for the month of shipment or sold on the spot market, with price differentials reflecting product quality.
At 31 December 2014, the Group had 322 kt of outstanding copper sales that were revalued at a weighted average price of US$2.87 per pound. The final price of these sales will be determined over the remainder of the 2015 financial year. In addition, 350 kt of copper sales from the 2014 financial year were subject to a finalization adjustment in the current period. The provisional pricing and finalization adjustments will decrease earnings before interest and tax by US$210 million in the December 2014 half year (December 2013 half year: US$196 million increase).
Total petroleum production – Total petroleum production increased by nine per cent in the December 2014 half year to a record 131.0 MMboe. Guidance for the 2015 financial year remains unchanged at 255 MMboe. Crude oil, condensate and natural gas liquids – Crude oil, condensate and natural gas liquids production increased by 24 per cent in the December 2014 half year to 62.1 MMboe.
Onshore US liquids volumes rose by 71 per cent in the December 2014 half year to a record 24.4 MMboe. This strong performance was underpinned by continued momentum in the Black Hawk and Permian where liquids production increased by 81 per cent and 107 per cent, respectively.
In our Conventional business, liquids production at Pyrenees and Atlantis increased by 34 per cent and 12 per cent, respectively, supported by strong uptime performance and the completion of new production wells in the second half of the 2014 financial year.
Natural gas – Natural gas production declined by two per cent in the December 2014 half year to 413 bcf. Strong uptime performance at North West Shelf and Macedon partially offset lower seasonal demand at Bass Strait and the divestment of Liverpool Bay which was completed in the 2014 financial year.
Onshore US development activity
Onshore US drilling and development expenditure totalled US$1.9 billion in the December 2014 half year. In response to weaker prices, the Company will reduce its operated rig count from 26 at period end to 16 by the end of the 2015 financial year. An update to the drilling and development expenditure budget for the 2015 financial year will be provided with the release of our interim results in February 2015.
The majority of the revised drilling program will be focused on our liquids-rich Black Hawk acreage with activity in the Permian and Hawkville limited to the retention of core acreage. The Company’s dry gas development program will be reduced to one operated rig in the Haynesville, with a focus on continued drilling and completions optimisation ahead of full field development.
The reduction in drilling activity will not impact 2015 financial year production guidance and we remain confident
that shale liquids volumes will rise by approximately 50 per cent in the period.
Petroleum exploration expenditure for the December 2014 half year was US$268 million, of which US$244 million was expensed. Total petroleum exploration expenditure for the 2015 financial year is now forecast to be US$600 million, a 20 per cent reduction from prior guidance. The program will remain focused on the Gulf of Mexico, Western Australia and Trinidad and Tobago.
The seismic acquisition program in Trinidad and Tobago was successfully completed for the seven deep water blocks accessed between 2012 and 2014. The acquisition for the two blocks awarded in the 2014 deep water bid round is progressing on schedule.
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After a comprehensive review and consideration of comments received from the public, stakeholders, and Federal and state partner agencies and tribes, the Bureau of Ocean Energy Management (BOEM) today conditionally approved Shell Gulf of Mexico, Inc.’s revised multi-year Exploration Plan (EP) for the Chukchi Sea.
Among the conditions of approval is the requirement that Shell obtain all necessary permits from other state and federal agencies, including permits to drill from the Bureau of Safety and Environmental Enforcement (BSEE) and appropriate authorizations under the Marine Mammal Protection Act. Another condition of approval prevents Shell from commencing drilling operations until all Biological Opinions under the Endangered Species Act have been issued and requires all operations under the plan comply with the terms and conditions included in those Biological Opinions.
“We have taken a thoughtful approach to carefully considering potential exploration in the Chukchi Sea, recognizing the significant environmental, social and ecological resources in the region and establishing high standards for the protection of this critical ecosystem, our Arctic communities, and the subsistence needs and cultural traditions of Alaska Natives,” said BOEM Director Abigail Ross Hopper. “As we move forward, any offshore exploratory activities will continue to be subject to rigorous safety standards.”
The EP describes all exploration activities planned by the operator, including the timing of these activities, information concerning drilling vessels, the location of each planned well, and actions to be taken to meet important safety and environmental standards and to protect workers, resources, wildlife and access to subsistence use areas. In accordance with the National Environmental Policy Act, the review of the EP included the preparation of an Environmental Assessment and a subsequent Finding of No Significant Impact.
“The review of this Exploration Plan was a team effort,” said James Kendall, BOEM Alaska Regional Director. “We’d like to thank the experts in our cooperating agencies, the tribal government representatives who took time out from their busy schedules to do government-to-government consultations and of course the many members of the public and stakeholder organizations who provided us with valuable comments during the review process.”
Shell’s revised EP proposes the drilling of up to six wells within the Burger Prospect, located in approximately 140 feet of water about 70 miles northwest of the village of Wainwright. Shell will conduct its operations using the drillship M/V Noble Discoverer and the semi-submersible drilling unit Transocean Polar Pioneer, with each vessel providing relief-well capability for the other. The two drilling units and their supporting vessels will depart the Chukchi Sea at the conclusion of each exploration drilling season.
The Department of the Interior is currently undertaking an ambitious reform agenda to strengthen, update and modernize Outer Continental Shelf (OCS) energy regulations. In April the Department announced proposed regulations to better protect human lives and the environment from oil spills. The proposed measures include more stringent design requirements and operational procedures for critical well control equipment used in OCS oil and gas operations.
The proposed well control rule, which is open for public comment, addresses the range of systems and equipment related to well control operations. The measures are designed to improve equipment reliability, building upon enhanced industry standards for blowout preventers and blowout prevention technologies. The rule also includes reforms in well design, well control, casing, cementing, real-time well monitoring and subsea containment.
Additionally, the Department released proposed Arctic standards in February that will ensure that exploration of the Alaska OCS is subject to strong standards specifically tailored to the region’s challenging and unforgiving conditions. The proposed rule, which is open to public comment until May 27, 2015, includes many required measures that have been adopted previously as conditions on Shell’s Arctic operations and which BOEM also adopted in its approval of this revised EP. Those standards build upon existing Arctic-specific standards as well as experience with previous operations offshore Alaska.
A copy of BOEM’s conditional approval letter, the approved EP, the Environmental Assessment and the Finding of No Significant Impact are available at: www.boem.gov/shell-chukchi/
The Bureau of Ocean Energy Management (BOEM) promotes energy independence, environmental protection and economic development through responsible, science-based management of offshore conventional and renewable energy resources.
BP and Woolworths Group (Woolworths) today announced that they have agreed to enter a strategic partnership that will include BP acquiring, rebranding and operating Woolworths’ existing 527 fuel and convenience sites across Australia, as well as an additional 16 sites currently under construction, for a total consideration of US$1.3 billion.
The partnership is an exciting prospect for Australian customers with BP and Woolworths set to deliver a fuel and convenience store and loyalty offer unlike any other in Australia. Key features of the offer are:
Reinventing convenience with a truly differentiated offer, to be branded Metro at BP, that includes a strong seasonal selection of high quality, ready-to-eat and take home fresh food products.
It is proposed that BP will become a cornerstone partner in Woolworths’ Everyday Rewards loyalty program, inviting customers to earn rewards points on both fuel and in-store purchases at any BP site in Australia.
For the first time, Woolworths’ Everyday Rewards cardholders would also be able to redeem points at the register as discounts on purchases at BP.
BP will maintain the Woolworths’ 4 cent per litre redemption offer in the 527 fuel and convenience sites acquired from Woolworths, and will expand this offer to additional BP sites, giving customers even more reasons to enjoy BP’s quality fuels.
Tufan Erginbilgic, Chief Executive, BP Downstream, commented, “The development of high-quality, differentiated fuel and convenience offers is a key part of BP’s strategy – allowing us to grow our marketing business in important global markets.
“We are excited to be establishing this strategic partnership with Woolworths, one of Australia’s largest supermarket retailers. Globally we have developed a winning retail formula where we partner with strong local brands, like Marks & Spencer in the UK, to provide our customers with a convenience retail offer that meets the needs of their busy lifestyles. The combination of all aspects of this strategic partnership is expected to create significant value for BP.”
Initially, BP and Woolworths will launch a Metro at BP pilot program across 16 BP fuel and convenience sites, allowing both companies to test the offer and generate customer feedback. A second phase will see a further expansion of the Metro at BP format across more than 200 sites.
Andy Holmes, President BP Australia, added, “Over the past three years BP has significantly invested in its fuel and convenience sites across Australia. The opportunity to grow our retail business and work alongside Woolworths, with their strength in grocery and food innovation, will further enhance our customers’ fuel and convenience retail experience.
“We enjoy strong, successful commercial partnerships with our many dealers, distributors and suppliers and we look forward to sharing the benefits this transaction brings to us all.
“While Woolworths fuel business has solid foundations, the future combination of BP’s international experience and expertise in fuel and convenience offers with Woolworths high quality food products and loyalty program means that BP expects to realise significant improvements in value.”
The acquisition of Woolworths’ fuel and convenience sites will add to BP’s existing network of 350 company-owned retail sites across Australia. BP also supplies fuel and branding to a further 1,000 sites owned by independent business partners.
Brad Banducci, Woolworths Group Chief Executive Officer, said, “For Woolworths customers our Strategic Partnership with BP will enable them to enjoy our leading Woolworths Reward program at BP fuel sites and ensure they continue to benefit from the 4cpl fuel discount. Longer term, it will also provide them with a compelling, new “food-on-the go” offering through the roll-out of the “Metro at BP” concept.”
The transaction, which is subject to approval from the Australian Competition and Consumer Commission (ACCC) and the Foreign Investment Review Board (FIRB), is expected to complete over the next 12 months.
BP in Australia
There are currently 1,400 BP branded fuel and convenience retail sites across Australia, of which 350 are company-owned. The rest are branded BP but owned by independent business partners.
BP is one of the largest suppliers of fuel to Australia’s industrial and commercial sectors.
BP is one of Australia’s most significant investors, most visibly through our terminals, retail fuel sites and refinery, as founding participants in the North West Shelf and Browse joint ventures and operator of exploration permits in the Carnarvon Basin. We continue to invest in local economies, growing jobs and building infrastructure in metropolitan and regional Australia.
BP is engaged in the exploration and production of oil, natural gas and liquefied natural gas and the refining and marketing of petroleum and lubricant products.
For more information about BP in Australia please visit www.bp.com.au
Woolworths in Australia
Founded in 1924, Woolworths Group is Australia’s largest retailer with more than 3,500 stores across Australia and New Zealand that span food, drinks, petrol, general merchandise and hotels.
Woolworths Group manages some of Australia’s most recognised and trusted brands – including Woolworths, Countdown, Dan Murphy’s, BWS and BIG W – and endeavours to create a world class experience for customers across all of its stores and platforms.
In FY’16, Woolworths Group generated more than $58 billion in revenue.
The Woolworths Group is a proud, home-grown Australian business, an employer of more than 205,000 people, and a committed business partner of many thousands of local farmers, producers and manufacturers.
HOUSTON – BP today announced an oil discovery at the Guadalupe prospect in the deepwater U.S. Gulf of Mexico.
The discovery well, on Keathley Canyon Block 10, was drilled by operator Chevron on behalf of the Guadalupe co-owners. The well encountered significant oil pay in Paleogene age Wilcox Sands.
Located approximately 180 miles off the Louisiana coast in 3,992 feet of water, the well was drilled to a total depth of 30,173 feet. More tests are being conducted on the well and additional appraisal activity will be needed to determine the extent of the resource.
The Guadalupe co-owners are: BP Exploration & Production Inc, with a 42.5 percent working interest; Chevron U.S.A. Inc. (operator), 42.5 percent; and Venari Resources LLC, 15 percent.
BP has previously made three discoveries in the emerging Paleogene trend in the deepwater U.S. Gulf of Mexico: Gila in 2013, Tiber in 2009 and Kaskida in 2006.
“BP is pleased to be a part of another discovery in the Paleogene trend, an area of increasing importance to the future of the Gulf of Mexico and to America’s energy security,” said Richard Morrison, regional president of BP’s Gulf of Mexico business. “This again highlights BP’s strength in exploration and our commitment to the deepwater U.S. Gulf of Mexico where we are the leading energy investor and leaseholder, and a top oil and natural gas producer.”
BP is a leading producer in the deepwater Gulf and has been the largest investor in the region over the last ten years. BP is also the leading leaseholder in the deepwater U.S. Gulf of Mexico. BP directly employs more than 2,300 people in its Gulf of Mexico business and supports tens of thousands of additional jobs in the region.
About BP:
Over the past five years, BP has invested nearly $50 billion in the U.S. – more than any other energy company. BP is a leading producer of oil and gas and provides enough energy annually to light the entire country for a year. Employing approximately 20,000 people in all 50 states, BP supports more than 260,000 jobs total through all of its business activities. For more information, go to www.bp.com/us.
WASHINGTON – BP’s business activities in the US helped generate close to $143 billion in economic impact in 2013 and currently support nearly 220,000 American jobs, according to the company’s US Economic Impact Report 2014.
Released today, BP’s new report provides a detailed, state-by-state look at the breadth and impact of the company’s activities in America. Since 2009, BP has invested nearly $50 billion, making it America’s largest energy investor. In 2013 alone, BP spent $22 billion with vendors across the country on products and services, ranging from offshore drilling rigs to gasoline-producing equipment for its refineries.
“No energy company has invested more in the US over the past five years than BP,” said John Mingé, BP America chairman and president. “Our investments not only provide the energy to power the nation, but they also support hundreds of thousands of jobs that fuel the economy.”
BP’s business investments in the US include oil and natural gas exploration and production, fuel and chemical refining, lubricants, shipping, trading, renewable energy production and cutting-edge technology research and development. The US also is home to a number of operations that serve BP’s global businesses, such as the Center for High-Performance Computing in Houston, which houses the world’s largest supercomputer for commercial research.
BP produces more than 628,000 barrels of oil equivalent a day – enough to light nearly the entire country. The company’s three northern-tier refineries in Indiana, Ohio, and Washington are together capable of processing more than 742,000 barrels of oil per day. Also, BP’s chemical and lubricant facilities supply materials necessary for modern life, including greases and engine oils marketed under the Castrol brand and chemicals used in fabrics and packaging.
In addition to physical assets and energy production, the US is home to nearly 40 percent of BP’s publicly traded shares and more BP employees than any other nation. The US also is a center for BP research and recruitment. The company will spend $60 million this year on academic research, educational initiatives, and recruitment activities at more than 50 US universities.
At the corporate level, BP contributes more than $30 million a year to charitable and nonprofit organizations such as United Way of America and the National Multiple Sclerosis Society. This includes contributions through BP’s unique Fabric of America program in which BP employees may annually designate $300 of corporate funds to a nonprofit organization of their choice within the United States. Since the fund’s 2007 inception, BP has given more than $26 million on behalf of our employees, helping to support roughly 19,000 organizations in all 50 states.
The investments and spending detailed in the report do not include costs associated with cleanup and restoration activities in the Gulf of Mexico, or claims payments related to the Deepwater Horizon accident.
To view or download BP’s full US Economic Impact Report 2014, please visit: www.bp.com/EIR.
BP in the US – By the Numbers:
Employees: More than 18,000 employees
Total Jobs Supported: Nearly 220,000 jobs
Employee Payroll and Benefits: $5 billion, including pensions and other post-employment costs
National Economic Impact Nearly: $143 billion in 2013
BP U.S. Investment since 2009: Nearly $50 billion – the most of any energy company
Money Spent with Vendors: More than $22 billion in 2013
Community Investment: $30 million in corporate contributions annually
About BP in the US:
Over the past five years, BP has invested nearly $50 billion in the US – more than any other energy company. BP is a leading producer of oil and gas and provides enough energy annually to light nearly the entire country for a year. Employing more than 18,000 people in all 50 states, BP supports around 200,000 additional jobs through all of its business activities. For more information, go to www.bp.com/EIR.
BP presents to investors its strategy and plans to the end of the decade and beyond for its Upstream oil and gas business.
The presentation, led by BP’s Upstream chief executive Lamar McKay, provides an in-depth and detailed account of how BP is managing its Upstream business and its distinctive strategy for the long term. The presentation also reviews the macro-environment and the context of recent developments in oil prices.
McKay and senior members of his upstream management team will share further insights into the depth and quality of the Group’s resource base and investment portfolio, which underpin BP’s long-term value proposition through the changes in the price environment.
“Although the current environment is challenging, BP is well-positioned to respond and manage our Upstream business for the long term,” said Lamar McKay. “We expect to see growth from our conventional and deepwater assets and an increasing contribution from gas. And we also have a quality pipeline of opportunities that we believe are capable of extending underlying growth well beyond 2020. Our focus throughout will remain firmly on safe operations, execution efficiency and greater plant reliability.”
BP also said today that, as part of its wider ongoing Group-wide programme to simplify across its Upstream and Downstream activities and corporate functions, it expects to incur non-operating restructuring charges of circa $1 billion in total over the next five quarters, including the current quarter. Details of these charges and further guidance on the programme are expected to be given with each quarter’s results.
Group Chief Executive Bob Dudley said: “We have already been working very hard over these past 18 months or so to right-size our organisation as a result of completing more than $43 billion of divestments. We are clearly a more focused business now and, without diverting our attention from safety and reliability, our goal is to make BP even stronger and more competitive.
“The simplification work we have already done is serving us well as we face the tougher external environment. We continue to seek opportunities to eliminate duplication and stop unnecessary activity that is not fully aligned with the group’s strategy.”
As an integrated group, not all BP’s businesses are equally exposed to the oil price. About one third of its Upstream projects around the world are operated under production sharing contracts and it is also investing in high quality gas projects which are typically less sensitive to oil price movements. Importantly, while BP approves projects at $80 a barrel, it also already tests each at $60 a barrel to understand the resilience of the portfolio at a range of prices. It will also continue to consider lower price sets as appropriate.
BP also has a strong balance sheet, with historically low gearing of 15% at the end of the third quarter of 2014, which provides time and flexibility to adjust to changes in the environment.
Across the Group, BP has said it will be looking to pare or re-phase capital expenditure without compromising safety or future growth. In October, BP told investors this could result in reductions of $1 billion to $2 billion in capital expenditure across the Group in 2015 against guidance of $24 billion to $26 billion laid out in March. This will be reviewed further as part of the 2015 plan, recognising the current outlook for oil prices.
When oil prices fall, there is typically deflation in the industry as a whole. Together with its already greater focus on streamlining activity, this would be expected to further help BP align its cost base with its smaller footprint and reduced activity levels.
The Upstream team will today detail the business’s track record of delivery as part of the Group’s 10-point plan. Amongst the milestones, over the last three years, the Upstream has improved safety and reliability of operations; doubled exploration drilling activity; and rebuilt Gulf of Mexico production. It has also increased the rate of reinvestment; made $32 billion of divestments in the Upstream business alone; and, by year end, also expects to have delivered 15 new upstream projects with average operating cash margins double 2011 average.
Between now and 2020, the Upstream team’s focus will be on delivery, through safe and reliable operations, strong execution in the existing base business, and the start-up of a suite of new projects which are expected to be capable of adding over 900,000 barrels of oil equivalent a day of net incremental production to BP’s portfolio by 2020. BP will also be progressing opportunities expected to continue to drive underlying growth into the next decade as it builds out its well-established conventional and deepwater oil positions and a distinctive and material portfolio of gas options.
The BP Statistical Review of World Energy 2014 – launched today at the World Petroleum Congress meeting in Moscow – reveals how the world of energy echoed broader global themes in 2013. Emerging differences in global economic performance, geopolitical uncertainty and ongoing debates about the proper roles of government and markets are all reflected in its data.
Global energy demand accelerated in 2013 but, reflecting the weakness of the global economy, growth of 2.3% remained slightly below the historical average. Within this global picture, however, shifts in energy consumption mirrored those in the world’s economic patterns.
Energy consumption in the emerging economies grew below their long-term average rate, rising by 3.1%, driven by slower growth in China. However, consumption in the mature economies of the OECD grew by a higher-than-average rate of 1.2% – entirely as a result of strong growth in the US. As a result the gap between growth in the OECD and non-OECD narrowed to levels not seen since 2000.
Nonetheless, the emerging economies continue to dominate the growth in global energy demand, accounting for 80% of growth last year and nearly 100% of growth over the past decade.
The Review – the publication’s 63rd annual edition – also illustrates how geopolitical events in a number of countries continued to impact oil production in 2013, with Libya suffering the largest single decline in the face of renewed civil unrest. Those disruptions, however, were offset by a big increase in oil production in the US – driven by the massive investment in production from shale and other ‘tight’ formations. As a net result, average oil prices remained unusually stable – albeit at levels exceeding $100 per barrel for a third consecutive year.
Speaking at today’s launch in Moscow, BP Group Chief Executive Bob Dudley said: “The Review again demonstrates the strength of the flexible global energy system in adapting to a changing world. The major disruptions to production seen throughout 2013 were balanced by continued rises in production elsewhere. This underlines the importance of continuing to secure these new supplies through continued access to new resources, policies to encourage markets and investment, and the application of new technologies worldwide.”
The developments also highlighted the critical importance of both policy and market forces in delivering new supplies. As BP Chief Economist Christof Rühl also noted, “The huge investments seen in the US have been encouraged and enabled by a favourable policy regime. And this has resulted in the US delivering the world’s largest increase in oil production last year. Indeed, the US increase in 2013 – up by 1.1 million barrels a day – was one of the biggest annual oil production increases the world has ever seen.”
Elsewhere, the impact of policy on energy was also seen in continued robust growth in renewable energy – albeit from a low base. Renewables now account for more than 5% of global power output and, including biofuels, for nearly 3% of primary energy consumption. However, the challenge of sustaining expensive subsidy regimes has become visible where penetration rates are highest, namely in the below-average growth of Europe’s leading renewable producers, who are grappling with weak economic growth and strained budgets.
Review highlights – energy developments
Global primary energy consumption increased by 2.3% in 2013, growing faster than in 2012 (+1.8%) but below the 10-year average of 2.5%.
All fuels except oil, nuclear power and renewables in power generation grew at below-average rates. Growth was below average for all regions except North America.
Oil remains the world’s leading fuel, with 32.9% of global energy consumption, but it lost market share for the 14th consecutive year and its current market share is once again the lowest in our data set, going back to 1965.
Emerging economies accounted for 80% of the global increase in energy consumption – even though growth in these countries was a below average 3.1%. OECD consumption rose by an above-average 1.2%.
Robust US growth (+2.9%) accounted for all of the net increase in the OECD and consumption in the EU and Japan fell by 0.3% and 0.6%, respectively.
Oil
Dated Brent averaged $108.66 per barrel in 2013, a decline of $3.01 per barrel from the 2012 level.
Global oil consumption grew by 1.4 million barrels per day (b/d), or 1.4% – just above the historical average.
Countries outside the OECD now account for the majority (51%) of global oil consumption and they once again accounted for all of the net growth in global consumption. OECD consumption declined by 0.4%, the seventh decrease in the past eight years.
The US (+400,000 b/d) recorded the largest increment to global oil consumption in 2013, outpacing Chinese growth (+390,000 b/d) for the first time since 1999.
Global oil production did not keep pace with the growth in global consumption, rising by just 560,000 b/d or 0.6%. The US (+1.1 million b/d) recorded the largest growth in the world and the largest annual increment in the country’s history for a second consecutive year.
The US accounted for nearly all (96%) of the non-OPEC output increase of 1.2 million b/d (the strongest since 2002) to reach a record 50 million b/d.
Global refinery crude runs increased by a below-average 390,000 b/d or 0.5%. Non-OECD countries accounted for all of the net increase, rising by 730,000 b/d.
OECD refinery throughputs declined by 340,000 b/d, the seventh decline in the past nine years despite an increase of 320,000 b/d in US refinery runs, as the US continued to ramp up net product exports.
Global oil trade in 2013 grew by 2.1% or 1.2 million b/d – among importers, growth in Europe and emerging economies more than offset declines in the US and Japan.
Global proved reserves of oil increased to 1687.9 billion barrels at the end of 2013, sufficient to meet 53.3 years of global production.
Natural gas
World natural gas consumption grew by 1.4%, below the historical average of 2.6%. As with primary energy, consumption growth was above average in the OECD countries (+1.8%) and below average outside the OECD (+1.1%).
Growth was below average in every region except North America. China (+10.8%) and the US (+2.4%) recorded the largest growth increments in the world, together accounting for 81% of global growth.
India (-12.2%) recorded the largest volumetric decline in the world, while EU gas consumption fell to the lowest level since 1999.
Globally, natural gas accounted for 23.7% of primary energy consumption.
Global natural gas production grew by 1.1%, which was well below the 10-year average of 2.6%.
Growth was below average in all regions except Europe and Eurasia. The US (+1.3%) remained the world’s leading producer, but both Russia (+2.4%) and China (+9.5%) recorded larger growth increments in 2013.
Global natural gas trade grew by 1.8% in 2013, well below the historical average of 5.2%. Pipeline shipments grew by 2.3%.
LNG’s share of global gas trade declined slightly to 31.4% – and international natural gas trade accounted for 30.9% of global consumption.
Global proved reserves of natural gas increased to 185.7 trillion cubic meters (tcm), sufficient to meet 54.8 years of global production.
Other fuels
Coal consumption grew by 3% in 2013, well below the 10-year average of 3.9% but it is still the fastest-growing fossil fuel.
Coal’s share of global primary energy consumption reached 30.1%, the highest since 1970. Consumption outside the OECD rose by a below-average 3.7%, but still accounted for 89% of global growth.
Global nuclear output grew by 0.9%, the first increase since 2010. Nuclear output accounted for 4.4% of global energy consumption, the smallest share since 1984.
Global hydroelectric output grew by a below average 2.9%, and accounted for 6.7% of global energy consumption.
Renewable energy sources – in power generation as well as transport – continued to increase in 2013, reaching a record 2.7% of global energy consumption, up from 0.8% a decade ago.
Globally, wind energy (+20.7%) once again accounted for more than half of renewable power generation growth and solar power generation grew even more rapidly (+33%), but from a smaller base.
Global biofuels production grew by a below-average 6.1% (80,000 b/doe), driven by increases in the two largest producers: Brazil and the US.
This is courtesy of www.bp.com
The project will feature the construction of a normally unmanned platform together with corresponding subsea infrastructure, a first for BP Trinidad and Tobago. Fabrication is proposed to begin in 4th quarter, 2014.
The Juniper facility will take gas from the Corallita and Lantana fields located 50 miles off the south east coast of Trinidad in water-depth of approximately 360 feet. The development will include five subsea wells and will have a production capacity of approximately 590 million standard cubic feet a day (mmscfd). Gas from Juniper will flow to the Mahogany B hub via a new ten kilometer flowline.
Juniper will become bpTT’s 14th offshore production facility. Drilling is due to commence in 2015 and first gas from the facility is expected in 2017.
BPTT Regional President Norman Christie said: “Juniper demonstrates bpTT’s commitment to Trinidad and Tobago over the long-term. This development is an important part of the future for bpTT because it will assist the company in meeting its natural gas commitments to the market. It is also an important step change for bpTT as it introduces subsea infrastructure to continue the development of its resources in the Columbus Basin.”
BPTT operates in 904,000 acres off Trinidad’s east coast. BPTT has 13 offshore platforms and two onshore processing facilities.
The Juniper project has been undertaking Front End Engineering and Design (FEED) activities since 2012.
www.bp.com
BP announced today that it is now operating the world’s first robotic coreflooding system. The Core Flood Robot is the most recent addition to BP’s programme of enhanced oil recovery (EOR) research facilities.
Coreflooding is one of the most important techniques used to identify and evaluate EOR technologies. It measures the effectiveness of water or gas injected into an oil-bearing rock sample to displace oil. This can be used to assess the potential for water flooding in an oil field.
“The EOR technologies being developed by BP are vitally important to help increase global oil supplies,” said Ahmed Hashmi, BP’s head of upstream technology. “We believe this step-change in our core-flooding capability will hugely improve the speed and efficiency with which we can deploy new technologies to recover more oil from reservoirs.”
BP has had a large-scale in-house coreflooding laboratory in the UK for many years, where reservoir samples can be tested at high pressure and temperature ‘reservoir conditions,’ and different reservoir types can be evaluated. The new robotic coreflood system operates for 24 hours a day, seven days a week.
The complete automation and work-flow optimisation in the new Core Flood Robot enables hundreds of coreflood tests to be performed each year, rather than dozens as in the past, and greatly enhances BP’s ability to evaluate a continuous stream of new EOR technologies. This should reduce the time spent developing new technologies by at least 50 per cent.
The Core Flood Robot is operated by the same team that developed LoSal® EOR, BP’s breakthrough reduced salinity waterflooding technology. More than 45 coreflood tests were performed in validating the LoSal EOR effect, before field trials in Alaska. BP and its partners are now deploying the technology at scale on the Clair Ridge project in the North Sea. BP was awarded the 2014 Offshore Technology Conference Distinguished Achievement Award for the Clair Ridge LoSal EOR project, recognising the company’s specialist EOR technologies.
BHP Billiton is meeting the challenges of the global iron ore market through a focus on productivity and a “relentless pursuit of the basics” in its Western Australia Iron Ore (WAIO) operations.
In a key note address at this year’s Global Iron Ore and Steel Forecast Conference, Asset President WAIO, Edgar Basto, spoke to the global market dynamics affecting one of Australia’s most important exports.
“Following a decade of strong growth driven by fixed assets investments, the Chinese economy is transitioning to a more consumer and services based model, with future growth likely to be inherently less steel intensive,” he said.
“The Chinese Government’s steel industry restructure plans will take time to implement but it’s important to note a reduction in excess capacity will mean improved sustainability of the industry and our customers are likely to benefit from any consolidation.”
Mr Basto reiterated that the mining industry would need to continue to meet the challenges of a lower price environment through productivity.
“Our structured approach to safely increasing the availability, utilisation and rate of our existing infrastructure will support continued productivity improvements at WAIO,” he said.
“We continue to increase our productivity in Port and Rail as we approach our targeted run rate of approximately 270 million tonnes per annum.
“This has been achieved through a range of measures such as the optimisation of our pit-to-port scheduling strategy and alignment of maintenance shutdowns across our mines, port and track.”
Mr Basto said BHP Billiton’s new Operating Model would also support safe delivery of further productivity gains from WAIO’s Tier 1 asset base in the Pilbara.
“Our productivity drive has supported an EBITDA margin of over 50 per cent at WAIO despite the iron ore price halving since 2012,” he said.
“Through the new Operating Model we will deliver faster replication of leading practices and improved technologies across all of BHP Billiton’s global operations as well as a major reduction in the costs of our functions.”
Mr Basto reinforced the Company’s commitment to Western Australia and its local communities.
“WAIO remains a strong supporter of the communities in which we operate, having committed A$300 million over the past five years to health, education and Indigenous development programs and community infrastructure.
“We are proud of the contribution we have made, and continue to make in WA. Despite the challenging market conditions faced by the industry, BHP Billiton is unwavering in its commitment to the State and our local communities.”
TREVOSE, PA. —Federated Co-Operatives Limited’s Co-op Refinery Complex in Regina, Saskatchewan, was named Industrial Water Project of the Year at the annual Global Water Awards. The award recognizes the project, commissioned in 2016, that represents the most impressive technical or environmental achievement in the field of industrial water.
Using GE Water & Process Technologies’ advanced water recycling equipment, the Co-op Refinery Complex became the first refinery in North America to treat 100 percent of its wastewater on-site and then recycle the treated effluent for steam production. Steam is used for heating, hydrogen production, to power equipment and for cooling towers.
“We are honored that our Co-op Refinery Complex was named Industrial Water Project of the Year. Water is a precious resource and our wastewater improvement project allows us to be efficient and sustainable by recovering every drop of water—2 million gallons of wastewater daily. With GE’s technology, we now recycle all of our wastewater in a socially responsible and environmentally sound way to conserve water for Regina and the entire province of Saskatchewan,” said Gil Le Dressay, vice president, refinery operations, Federated Co-Operatives Limited.
Heiner Markhoff, president and CEO of GE Water & Process Technologies, accepted the award last week in Madrid during Global Water Intelligence’s Global Water Summit 2017.
“We are very proud that this project, which uses our advanced wastewater treatment technologies, has won this prestigious award,” said Markhoff. “Federated Co-Operatives Limited’s outstanding commitment to environmental sustainability should be an enduring example for the entire oil refining industry.”
Several years ago, the refinery expanded its operations to produce 30,000 more barrels of oil per day (BPD) taking it from 100,000 BPD to a 130,000-BPD facility, which increased its water usage. The refinery’s current water source is a blend of well water and city water, and restrictions on water use mandated that the Co-op Refinery Complex find a new source of water. Water & Process Technologies offered a solution combining ZeeWeed* membrane bioreactor technology and a high-efficiency reverse osmosis system to recycle and reuse 2 million gallons of wastewater a day. In addition to the water reuse solution, Water & Process Technologies provides the refinery with wastewater specialty chemicals and monitoring solutions to provide system optimization.
With a fully operational wastewater improvement project, the Co-op Refinery Complex’s reliance on raw water from the city of Regina aquifer will decrease by the equivalent of 3,100 households in Regina on an annual basis. By recycling 100 percent of its wastewater on-site, the Co-op Refinery Complex significantly decreases volatile organic compound emissions from its wastewater ponds and reduces the associated nuisance odors.
Established in 2006 by Global Water Intelligence magazine, the awards recognize the most important achievements in the international water industry within several categories and reward those initiatives in the water, wastewater and desalination sectors that are moving the industry forward through improved operating performance, innovative technology adoption and sustainable financial models.
About Water & Process Technologies
with operations in 130 countries and employing over 7,500 people worldwide, GE’s Water & Process Technologies applies its innovations, expertise and global capabilities to solve customers’ toughest water and process challenges. It offers a comprehensive set of chemical and equipment solutions, as well as predictive analytics, to enhance water, wastewater and process productivity. Water & Process Technologies strives to enable customers to meet increasing demands for clean water, overcome scarcity challenges, strengthen environmental stewardship and comply with regulatory requirements.
About GE
GE (NYSE: GE) is the world’s Digital Industrial Company, transforming industry with software-defined machines and solutions that are connected, responsive and predictive. GE is organized around a global exchange of knowledge, the “GE Store,” through which each business shares and accesses the same technology, markets, structure and intellect. Each invention further fuels innovation and application across our industrial sectors. With people, services, technology and scale, GE delivers better outcomes for customers by speaking the language of industry. www.ge.com
The Canpotex Board of Directors has approved a new methodology for determining the amount of increased productive capacity resulting from such completed major mine expansions as its producers may independently decide to undertake. The aggregate productive capacities of Canpotex producers are used in determining their respective export sales entitlements through Canpotex.
Until now, Canpotex producers have had to demonstrate increases in productive capacity of existing mines from completed major mine expansions through an independently audited sustained production run of 90 operating days, scheduled at the producer’s discretion. The new methodology will instead rely on an independent engineering firm and approved protocols to calculate productive capacity.
Audit protocols employed by the independent engineer will consider historical data and designed increases tested against a set of detailed parameters. Both conventional and solution mine audit protocols will also include a short 10- to 14-day production run scheduled at the producer’s discretion to validate audit results.
Although the new audit procedures are intended to replace the need for a more sustained production run to determine increased productive capacity resulting from a completed major mine expansion, a Canpotex producer which is dissatisfied with the engineering audit results will still be able to thereafter elect to revert to the audited 90-day run procedure and have those operating results used to calculate the increased productive capacity of its mine resulting from the major mine expansion. The new procedures also will not apply to such major mine expansions that have previously completed a 90-day production run to demonstrate the mine’s increased productive capacity, or which may be in the process of conducting a 90-day production run.
Canpotex, with its head office in Saskatoon, is Canada’s largest mineral exporter. With its extensive supply chain network and global reach, Canpotex markets Canadian potash to approximately 40 countries around the world.
Wellington, New Zealand, – Chevron New Zealand Exploration Ltd., a Chevron Corporation subsidiary, today announced it has been granted exploration rights to three blocks located offshore New Zealand, in a frontier basin with water depths ranging from 2,600 feet (800 m) to 9,800 feet (3,000 m).
“This award adds to Chevron’s range of potential long-term options in the Asia-Pacific region,” said Melody Meyer, president of Chevron Asia Pacific Exploration and Production Company. “Chevron’s approach to this project will be guided by our commitment to maintain the highest environmental and safety standards.”
The three petroleum exploration permits – 57083, 57085 and 57087 – in the offshore Pegasus and East Coast basins, cover more than 6.26 million acres (25,300 sq. km), and are located southeast of North Island. Chevron New Zealand Exploration Ltd. will be the operator of the blocks with a 50 percent working interest. Statoil will hold the remaining 50 percent interest.
Chevron has operated in the downstream sector of New Zealand for more than 90 years, and plans to continue to build on these relationships with communities and government.
Chevron is one of the world’s leading integrated energy companies, with subsidiaries that conduct business worldwide. The company is involved in virtually every facet of the energy industry. Chevron explores for, produces and transports crude oil and natural gas; refines, markets and distributes transportation fuels and lubricants; manufactures and sells petrochemical products; generates power and produces geothermal energy; provides energy efficiency solutions; and develops the energy resources of the future, including biofuels. Chevron is based in San Ramon, California. More information about Chevron is available at www.chevron.com.
NEW YORK, N.Y., – Chevron Corporation (NYSE: CVX) hosted its annual security analyst meeting in New York where executives reiterated priorities, expressed confidence in the company’s near term outlook and emphasized an advantaged position when markets rebound.
“We’re completing major projects that have been under construction for several years. This enables us to grow production and reduce spending at the same time, which should improve our net cash flow significantly,” said John Watson, Chevron’s chairman and chief executive officer. Watson reiterated the importance of dividend growth and maintaining a strong balance sheet in the company’s financial priorities, noting the company’s record of 28 consecutive years of dividend increases, and plans to limit debt increases beyond 2016.
“Industry conditions are tough right now, with low oil and natural gas prices. We believe markets will improve, and we’ll be well positioned when they do,” Watson continued. “We have an excellent upstream and downstream portfolio, and we are driving operating and administrative efficiencies across the company.”
Jay Johnson, executive vice president, upstream, highlighted key plans. “We’re focused on safe, reliable operations and effective project start-ups and ramp-ups. At Gorgon, we’re producing LNG and the first cargo is expected to ship next week. With an advantaged position in the Permian and a deep portfolio of operating assets, we’re transitioning our spending to more short-cycle, higher-return activity that utilizes existing infrastructure. We have a portfolio of assets that should allow production growth through the end of the decade, even at moderate prices.”
SAN RAMON, Calif., – Chevron Corporation (NYSE: CVX) today announced its Australian subsidiaries have signed a binding Sales and Purchase Agreement (SPA) with SK LNG Trading Pte Ltd (SK). Under the SPA, SK LNG Trading, which is part of a leading industrial conglomerate in South Korea, will receive 4.15 million tons of LNG over a five-year period starting in 2017.
During the time of this agreement, over 75 percent of Chevron’s equity LNG from Gorgon will be committed to customers in Asia.
“This agreement is an important step in the commercialization of Chevron’s significant natural gas holdings in Australia,” said Pierre Breber, president, Chevron Gas and Midstream. “As Chevron continues to grow into one of the world’s largest LNG suppliers, this SPA represents further progress and diversification of our sales portfolio.”
“We are pleased with the opportunity to supply LNG to SK and look forward to building lasting relationships with our customers in the region as the Gorgon and Wheatstone projects move into operations,” said Roy Krzywosinski, managing director, Chevron Australia. “SK joins our existing strong LNG customer base and demonstrates the Chevron-led Gorgon and Wheatstone projects are well-placed to meet the growing demand for natural gas in the Asia-Pacific region.”
The Chevron-operated Gorgon Project is a joint venture of the Australian subsidiaries of Chevron (47.3 percent), ExxonMobil (25 percent), Shell (25 percent), Osaka Gas (1.25 percent), Tokyo Gas (1 percent) and Chubu Electric Power (0.417 percent).
The Gorgon Project combines the development of the Gorgon Field and the nearby Jansz-Io Field. Facilities being built on Barrow Island include a liquefied natural gas (LNG) facility with three processing units capable of producing 15.6 million metric tons of LNG per year, a carbon dioxide injection project and a domestic gas plant.
Chevron is also developing the Wheatstone Project as an LNG and domestic gas operation near Onslow, in the Pilbara region of Western Australia. The project’s initial capacity is expected to be 8.9 million metric tons per year of LNG. The project also includes a domestic gas plant.
Chevron is one of the world’s leading integrated energy companies, with subsidiaries that conduct business worldwide. The company is involved in virtually every facet of the energy industry. Chevron explores for, produces and transports crude oil and natural gas; refines, markets and distributes transportation fuels and lubricants; manufactures and sells petrochemical products; generates power and produces geothermal energy; and develops the energy resources of the future, including biofuels. Chevron is based in San Ramon, Calif. More information about Chevron is available at www.chevron.com.
SAN RAMON, Calif., December 2, 2014 – Chevron Corporation (NYSE: CVX) announced that crude oil and natural gas production has begun at the Jack/St. Malo project in the Lower Tertiary trend, deepwater U.S. Gulf of Mexico. Jack/St. Malo is a key part of Chevron’s strong queue of upstream projects and was delivered on time and on budget.
The Jack and St. Malo fields are among the largest in the Gulf of Mexico. They were discovered in 2004 and 2003, respectively, and production from the first development stage is expected to ramp up over the next several years to a total daily rate of 94,000 barrels of crude oil and 21 million cubic feet of natural gas. With a planned production life of more than 30 years, current technologies are anticipated to recover in excess of 500 million oil-equivalent barrels. Successive development phases, which could employ enhanced recovery technologies, may enable substantially increased recovery at the fields.
“The Jack/St. Malo project delivers valuable new production and supports our plan to reach 3.1 million barrels per day by 2017,” said George Kirkland, vice chairman and executive vice president, Upstream, Chevron Corporation.
“This milestone demonstrates Chevron’s capital stewardship and technology capabilities, featuring a number of advances in technology that simply didn’t exist when the fields were discovered,” added Jay Johnson, senior vice president, Upstream, Chevron Corporation. “These learnings can now be transferred to other deepwater projects in our portfolio.”
The Jack and St. Malo fields are located within 25 miles (40 km) of each other in approximately 7,000 feet (2,100 m) of water in the Walker Ridge area, approximately 280 miles (450 km) south of New Orleans, Louisiana. The fields were co-developed with subsea completions flowing back to a single host, semi-submersible floating production unit located between the fields. The facility is the largest of its kind in the Gulf of Mexico and has a production capacity of 170,000 barrels of oil and 42 million cubic feet of natural gas per day, with the potential for future expansion.
“Jack/St. Malo is the result of the collaboration of hundreds of suppliers and contractors and many thousands of people across nine countries over a ten-year period,” said Jeff Shellebarger, president, Chevron North America Exploration and Production Company. “This project highlights our long-term commitment to the U.S. Gulf of Mexico, where Chevron is among the top leaseholders. Moreover, we expect Jack/St. Malo will continue to deliver sustained economic and community benefits, including job creation, along the Gulf Coast.”
Crude oil from the facility will be transported approximately 140 miles to the Green Canyon 19 Platform via the Jack/St. Malo Oil Export Pipeline, and then onto refineries along the Gulf Coast. The pipeline is the first large-diameter, ultra-deepwater pipeline in the Walker Ridge area of the Lower Tertiary trend. The combination of extreme water depths, large diameter, high-pressure design, and pipeline structures have set new milestones for the Gulf of Mexico.
The project, which was sanctioned in 2010, has delivered new technology applications, including the industry’s largest seafloor boosting system and Chevron’s first application of deepwater ocean bottom node seismic technology in the Gulf of Mexico, providing images of subsurface layers nearly 30,000 feet below the ocean floor.
Chevron, through its subsidiary, Chevron U.S.A. Inc., has a working interest of 50 percent in the Jack field, with co-owners Statoil (25%) and Maersk Oil (25%). Chevron, through its subsidiaries, Chevron U.S.A. Inc. and Union Oil Company of California, also holds a 51 percent working interest in the St. Malo field, with co-owners Petrobras (25%), Statoil (21.5%), ExxonMobil (1.25%) and Eni (1.25%); and a 40.6 percent ownership interest in the host facility, with co-owners Statoil (27.9%), Petrobras (15%), Maersk Oil (5%), ExxonMobil (10.75%) and Eni (0.75%).
Chevron is one of the world’s leading integrated energy companies, with subsidiaries that conduct business worldwide. The company is involved in virtually every facet of the energy industry. Chevron explores for, produces and transports crude oil and natural gas; refines, markets and distributes transportation fuels and lubricants; manufactures and sells petrochemical products; generates power and produces geothermal energy; provides energy efficiency solutions; and develops the energy resources of the future, including biofuels. Chevron is based in San Ramon, Calif. More information about Chevron is available at www.chevron.com.
SAN RAMON, Calif., – Chevron Corporation (NYSE: CVX) today announced that its indirect, wholly-owned subsidiary, Chevron Canada Limited, has reached agreement to sell a 30 percent interest in its Duvernay shale play to Kuwait Foreign Petroleum Exploration Company’s wholly-owned subsidiary, KUFPEC Canada Inc., for $1.5 billion. The total purchase price includes cash paid at closing as well as a carry of a portion of Chevron Canada’s share of the joint venture’s future capital costs. The Duvernay is located in west-central Alberta, and is believed to be among the most promising shale opportunities in North America.
The agreement creates a partnership for appraisal and development of liquids-rich shale resources in approximately 330,000 net acres in the Kaybob area of the Duvernay.
Kaybob area of the Duvernay playChevron Canada has drilled 16 wells since beginning its exploration program, with initial well production rates of up to 7.5 million cubic feet of natural gas and 1,300 barrels of condensate per day.
“This sale demonstrates our focus on strategically managing our portfolio to maximize the value of our global upstream businesses and is consistent with our partnership strategy,” said Jay Johnson, senior vice president, Upstream, Chevron Corporation. “The transaction provides us an expanded relationship with a valued partner. It also recognizes the outstanding asset base we have assembled.”
Following the closing of the transaction, Chevron Canada will hold a 70 percent interest in the joint venture Duvernay acreage and will remain the operator. The transaction is expected to close in November 2014.
“We remain encouraged by the early results of our exploration program and view the Kaybob Duvernay as an exciting growth opportunity for the company,” said Jeff Shellebarger, president of Chevron North America Exploration and Production Company.
Chevron Canada has drilled 16 wells since beginning its exploration program, with initial well production rates of up to 7.5 million cubic feet of natural gas and 1,300 barrels of condensate per day. A pad drilling program recently commenced which is intended to further evaluate and optimize reservoir performance as well as reduce execution costs and cycle time.
Chevron is one of the world’s leading integrated energy companies, with subsidiaries that conduct business worldwide. The company is involved in virtually every facet of the energy industry. Chevron explores for, produces and transports crude oil and natural gas; refines, markets and distributes transportation fuels and lubricants; manufactures and sells petrochemical products; generates power and produces geothermal energy; and develops the energy resources of the future, including biofuels. Chevron is based in San Ramon, Calif. More information about Chevron is available at www.chevron.com.
SAN RAMON, Calif.– Chevron Corporation’s (NYSE: CVX) wholly owned subsidiary Chevron Global Energy Inc. today announced that it has entered into an underwriting agreement for the sale of its 50 percent shareholding in Caltex Australia Limited (CAL).
It is expected that these shares will be sold to a broad range of Australian and global equity market institutional investors.
“This transaction reflects Chevron’s commitment to regularly review our portfolio and generate cash to support our long-term priorities. It is aligned with our previously announced asset sales commitment,” said Michael Wirth, executive vice president, Downstream and Chemicals. “We appreciate the strong performance of Caltex Australia over the many years we’ve been a shareholder, and look forward to a mutually beneficial supply and brand relationship for many years to come.”
Mark Nelson, president, International Products, Downstream and Chemicals, Chevron, said: “Asia-Pacific is a core strategic focus for Chevron’s Downstream business and we remain focused on ensuring our operations, portfolio and investments are well-positioned to meet the region’s growing demand for energy.”
Today’s announcement does not alter Chevron’s focus on moving the Gorgon and Wheatstone liquefied natural gas (LNG) projects towards start-up. Chevron is one of Australia’s largest foreign investors and is the largest holder of natural gas resources in the country.
Caltex is a prominent brand in the Australian petroleum market. The current trademark licensing agreement between Chevron and CAL will remain in effect following the transaction. Chevron will continue to ensure a reliable, high-quality supply of product is available to CAL to supply to its retail and reseller franchise network. Chevron is also committed to seeking long-term relationship opportunities with CAL.
Chevron is one of the world’s leading integrated energy companies, with subsidiaries that conduct business worldwide. The company’s success is driven by the ingenuity and commitment of its employees and their application of the most innovative technologies in the world. Chevron is involved in virtually every facet of the energy industry. The company explores for, produces and transports crude oil and natural gas; refines, markets and distributes transportation fuels and other energy products; manufactures and sells petrochemical products; generates power and produces geothermal energy; provides energy efficiency solutions; and develops the energy resources of the future, including biofuels. Chevron is based in San Ramon, Calif. More information about Chevron is available at www.chevron.com
SAN RAMON, Calif., – Chevron Corporation (NYSE: CVX) announced today that the Hess Corporation-operated Tubular Bells deepwater project, located in the U.S. Gulf of Mexico, has started crude oil and natural gas production. The field is located 135 miles (217 km) southeast of New Orleans, in approximately 4,300 feet (1,310 m) of water in the Mississippi Canyon area. The discovery well was drilled in 2003, and project construction began in October 2011.
Tubular Bells is expected to deliver total production of approximately 50,000 barrels of oil- equivalent per day producing from three wells.
“The deepwater Gulf of Mexico plays a significant part in our earnings and production growth. Achieving first oil at Tubular Bells is an important step towards Chevron achieving its production goal of 3.1 million barrels per day by 2017”, said George Kirkland, vice chairman and executive vice president, Upstream, Chevron Corporation.
“Tubular Bells and the Chevron-operated Jack/St. Malo project further strengthens Chevron’s deepwater portfolio,” said Jay Johnson, senior vice president, Upstream, Chevron Corporation. Jack/St. Malo, a large lower Tertiary development, is scheduled to be brought online later this year.
“This project’s success is the result of our strong business relationship with Hess, reinforcing our commitment to achieve results with excellence, and enabling new opportunities in this strategic area,” said Jeff Shellebarger, president, Chevron North America Exploration and Production Company.
The Tubular Bells production facility is producing from the Miocene trend, where, for many years, Chevron subsidiaries have had multiple producing assets and a leading leaseholder position.The floating production facility is a classic spar hull with traditional three-level topsides. The field has an estimated production life of 25 years.
Chevron subsidiary Chevron U.S.A. Inc. has a 42.86 percent working interest in the Tubular Bells development and Hess is the operator with a 57.14 percent working interest in the field.
Chevron is one of the world’s leading integrated energy companies, with subsidiaries that conduct business worldwide. The company is involved in virtually every facet of the energy industry. Chevron explores for, produces and transports crude oil and natural gas; refines, markets and distributes transportation fuels and lubricants; manufactures and sells petrochemical products; generates power and produces geothermal energy; and develops the energy resources of the future, including biofuels. Chevron is based in San Ramon, Calif. More information about Chevron is available at www.chevron.com.
SAN RAMON, Calif., – Chevron Corporation (NYSE: CVX) today announced that its subsidiary, Chevron Global Energy Inc., has sold its 25 percent non-operated interest in a producing oil concession in southern Chad and the related export pipeline interests to the Republic of Chad for approximately $1.3 billion. The sale closed June 13.
“This sale demonstrates our focus on strategically managing our portfolio to maximize the value of our global upstream businesses,” said George Kirkland, vice chairman of Chevron Corporation.
“These assets have played a significant role for Chevron in Africa for the past 14 years,” said Ali Moshiri, president of Chevron Africa and Latin America Exploration and Production Company. “They have been a profitable part of our portfolio for many years. The combination of current market conditions and the size of the assets relative to our portfolio make this an ideal time for a divestiture.”
The transaction includes the sale of the Chevron subsidiary’s interests in seven fields in Chad’s Doba Basin, which in 2013 had an average net daily crude oil production of about 18,000 barrels. The sale also includes the Chevron subsidiary’s approximate 21 percent non-operated interest in a pipeline system that transports crude oil to the coast of Cameroon as well as associated marine facilities.
Chevron is one of the world’s leading integrated energy companies, with subsidiaries that conduct business worldwide. The company’s success is driven by the ingenuity and commitment of its employees and their application of the most innovative technologies in the world. Chevron is involved in virtually every facet of the energy industry. The company explores for, produces and transports crude oil and natural gas; refines, markets and distributes transportation fuels and other energy products; manufactures and sells petrochemical products; generates power and produces geothermal energy; provides energy efficiency solutions; and develops the energy resources of the future, including biofuels. Chevron is based in San Ramon, Calif. More information about Chevron is available at www.chevron.com.
SAN RAMON, Calif. Chevron Corporation (NYSE: CVX) today provided an overview of the company’s work to respond to the COVID-19 pandemic at its 2020 annual meeting of stockholders. This year’s meeting was virtual in place of an in-person event due to safety concerns related to the pandemic.
“Our thoughts are with those affected by COVID-19 and the healthcare workers on the front lines battling to contain the outbreak,” said Michael Wirth, Chevron’s chairman and CEO.
The energy industry’s continued operations are necessary to ensure the security, safety, and health of all communities and critical to efforts to respond to the pandemic. The company’s biggest challenges are to ensure safe access to its facilities and continuity of operations. Chevron is successfully running essential facilities at operational levels necessary to meet current demand. The company is taking strong precautionary measures to reduce the risk of exposure, including screening workers and visitors at these locations.
“We activated our pandemic response plan in January, and have continued to adapt as events have unfolded,” Wirth said. “I am proud of our workers who show up every day to keep energy flowing into the economy.”
Commodity prices have fallen significantly due to the destruction of demand resulting from the COVID-19 pandemic and the over-supply of crude oil. The company expects its financial results will be depressed as long as current market conditions persist.
“Chevron is responding to these unprecedented challenges by making changes to what we can control,” Wirth said. “It’s always good to hear from our stockholders. We hope the meeting today left them with a deeper understanding of how we’ve advanced the business over the past year and our plans for the year ahead.”
The preliminary results from the meeting can be accessed via chevron.com here. Final voting results will be posted in the same location after they have been reported on a Form 8-K, which will be filed with the U.S. Securities and Exchange Commission. Specific information about the proposals before Chevron stockholders this year may be found in the “Investors” section of the company’s website under “Stockholder Services – Annual Meeting Materials.”
Chevron Corporation is one of the world’s leading integrated energy companies. Through its subsidiaries that conduct business worldwide, the company is involved in virtually every facet of the energy industry. Chevron explores for, produces and transports crude oil and natural gas; refines, markets and distributes transportation fuels and lubricants; manufactures and sells petrochemicals and additives; generates power; and develops and deploys technologies that enhance business value in every aspect of the company’s operations. Chevron is based in San Ramon, Calif. More information about Chevron is available at www.chevron.com.
SAN RAMON, Calif., – Chevron Corporation (NYSE: CVX) announced today that its U.K. subsidiary, Chevron North Sea Limited, has reached a final investment decision and received approval from the U.K. government to proceed with the development of the Alder Field in the Central North Sea. The project has a planned design capacity of 110 million cubic feet of natural gas and 14,000 barrels of condensate per day. First production is expected in 2016.
“The Alder Field development is an important milestone in support of our strategic plan to profitably grow production and is among our solid queue of major capital projects that will deliver value to shareholders,” said Chevron vice chairman George Kirkland.
“The Alder project builds on Chevron’s already well-established presence in the U.K. energy development sector,” said Todd Levy, president of Chevron Europe, Eurasia and Middle East Exploration and Production. “For more than 50 years Chevron has been active in the U.K.’s oil and gas industry, and we will continue to play a role in developing the region’s natural resources.”
Discovered in 1975, development has recently been enabled by innovative technologies to manage the high-pressure high-temperature gas condensate field located in Block 15/29a, in a water depth of 492 feet (150 meters) approximately 100 miles (160 kilometers) from the Scottish coastline and 37 miles (60 kilometers) from the U.K./Norway median line.
The field will be developed via a single subsea well tied back to the existing Britannia Platform, a distance of 17 miles (28 kilometers).
Chevron North Sea Limited operates the project and has a 73.684 percent interest, with co-venturer ConocoPhillips (U.K.) Limited (26.316 percent).
This Press Release is courtesy of www.chevron.com
SAN RAMON, Calif. and DEERFIELD, Ill., – Chevron U.S.A. Inc., a subsidiary of Chevron Corporation (NYSE: CVX), and Caterpillar Inc. (NYSE: CAT) today announced a collaboration agreement to develop hydrogen demonstration projects in transportation and stationary power applications, including prime power.
The goal of the collaboration is to confirm the feasibility and performance of hydrogen for use as a commercially viable alternative to traditional fuels for line-haul rail and marine vessels. The collaboration also seeks to demonstrate hydrogen’s use in prime power. Linked to the collaboration, and facilitated by Progress Rail, a Caterpillar company, the parties also agreed to demonstrate a hydrogen-fueled locomotive and associated hydrogen-fueling infrastructure. Work on the rail demonstration will begin immediately at various locations across the United States.
“Through Chevron New Energies, Chevron is pursuing opportunities to create demand for hydrogen – and the technologies needed for its use – for the heavy-duty transportation and industrial sectors, in which carbon emissions are harder to abate,” said Jeff Gustavson, president of Chevron New Energies. “Our collaboration with Caterpillar is another important step toward advancing a commercially viable hydrogen economy.”
“As we work to provide customers with the capability to use their desired fuel type in their operations, collaborating with Chevron is a great opportunity to demonstrate the viability of hydrogen as a fuel source,” said Joe Creed, Caterpillar group president of Energy & Transportation. “This agreement supports our commitment to investing in new products, technologies and services to help our customers achieve their climate-related objectives as they build a better, more sustainable world.”
About Chevron
Chevron is one of the world’s leading integrated energy companies. We believe affordable, reliable and ever-cleaner energy is essential to achieving a more prosperous and sustainable world. Chevron produces crude oil and natural gas; manufactures transportation fuels, lubricants, petrochemicals and additives; and develops technologies that enhance our business and the industry. To advance a lower-carbon future, we are focused on cost efficiently lowering our carbon intensity, increasing renewables and offsets in support of our business, and investing in low-carbon technologies that enable commercial solutions. More information about Chevron is available at www.chevron.com.
About Caterpillar
With 2020 sales and revenues of $41.7 billion, Caterpillar Inc. is the world’s leading manufacturer of construction and mining equipment, diesel and natural gas engines, industrial gas turbines, and diesel-electric locomotives. Since 1925, we’ve been driving sustainable progress and helping customers build a better world through innovative products and services. Throughout the product life cycle, we offer services built on cutting-edge technology and decades of product expertise. These products and services, backed by our global dealer network, provide exceptional value to help our customers succeed. We do business on every continent, principally operating through three primary segments – Construction Industries, Resource Industries, and Energy & Transportation – and providing financing and related services through our Financial Products segment. Visit us at caterpillar.com or join the conversation on our social media channels at caterpillar.com/social-media.
HOUSTON, Texas, – Chevron Energy Technology Company and GE Oil & Gas announced today the creation of the Chevron GE Technology Alliance, which will develop and commercialize valuable technologies to solve critical needs for the oil and gas industry.
The Alliance builds upon a current collaboration on flow analysis technology for oil and gas wells. It will leverage research and development from GE’s newest Global Research Center, the first dedicated to oil and gas technology.
“GE brings its leading manufacturing capabilities, worldwide marketing, distribution, and extensive R&D capabilities not only for oil and gas, but also other business sectors to this alliance,” said Paul Siegele, president of Chevron Energy Technology Company and chief technology officer. “Together, we hope to bring impactful new technologies to the industry.”
“Chevron’s deep understanding of the oil and gas industry, combined with GE’s long tradition of technology development and close collaboration with strategic partners, will uniquely position this new alliance to address the industry’s technology needs,” said Lorenzo Simonelli, president and CEO, GE Oil & Gas. “The solutions developed by this alliance will take on even more industry significance given Chevron’s proven leadership in being first to field-test and deploy new technology breakthroughs.”
This partnership builds upon an ongoing collaboration between Chevron and GE developing the GE Safire™ flow meter, now being tested and deployed on Chevron land-based well production lines in the western United States. In addition to the flow metering collaboration, which is being conducted with the Measurement & Control business within GE Oil & Gas, the Alliance is also managing a coatings project and will be taking on additional high-value projects in the near future.
The Alliance provides a mechanism for commercializing early stage technologies from Chevron, GE or other technology partnerships. For example, GE flow meter products will be developed incorporating the Swept Frequency Acoustic Interferometry metering technology incubated in an alliance between Chevron and Los Alamos National Laboratory.
“Los Alamos develops unique technologies and these can have powerful applications for U.S. industry,” said Duncan McBranch, chief technology officer for Los Alamos National Laboratory. “Strategic partnerships with industry allow us to accelerate breakthrough innovation in these areas. As the alliance demonstrates, national laboratories can serve an important role in connecting different industry partners to strengthen the U.S. innovation landscape.”
Chevron is one of the world’s leading integrated energy companies, with subsidiaries that conduct business worldwide. The company’s success is driven by the ingenuity and commitment of its employees and their application of the most innovative technologies in the world. Chevron is involved in virtually every facet of the energy industry. The company explores for, produces and transports crude oil and natural gas; refines, markets and distributes transportation fuels and other energy products; manufactures and sells petrochemical products; generates power and produces geothermal energy; provides energy efficiency solutions; and develops the energy resources of the future, including biofuels. Chevron is based in San Ramon, Calif.
This Press Release is courtesy of www.chevron.com
SAN RAMON, Calif., April 10, 2014 – Chevron Corporation (NYSE: CVX) today confirmed that subsidiaries of the company have signed agreements with the Argentine oil company YPF S.A. to continue development of shale oil and gas resources from the Vaca Muerta formation located in the Neuquén province in Argentina.
“This is a significant step in our subsidiaries’ joint efforts with YPF to develop one of the most exciting shale plays in the world today,” said George Kirkland, vice chairman of Chevron Corporation. “Vaca Muerta could become an important contributor to Chevron’s long term production growth.”
The agreements build off the progress made with the drilling program begun in 2013 and call for continued investment toward large-scale drilling and production in the 96,000-acre (388-sq. km) Loma Campana concession. The agreements also call for exploration of shale oil and gas resources in the 49,400-acre (200-sq. km) Narambuena area located about 70 miles (100 kilometers) north of Loma Campana in the Chihuido de la Sierra Negra concession, one of the main producing areas in the Neuquén Basin of west-central Argentina.
“YPF is a reliable partner and operator that is advancing the project in the right direction,” said Ali Moshiri, president of Chevron Africa and Latin America Exploration and Production Company. “We are pleased with the progress achieved so far and look forward to continuing to provide our technical expertise and investment to help Argentina achieve its goal of energy self-sufficiency.”
Chevron is one of the world’s leading integrated energy companies, with subsidiaries that conduct business worldwide. The company’s success is driven by the ingenuity and commitment of its employees and their application of the most innovative technologies in the world. Chevron is involved in virtually every facet of the energy industry. The company explores for, produces and transports crude oil and natural gas; refines, markets and distributes transportation fuels and other energy products; manufactures and sells petrochemical products; generates power and produces geothermal energy; provides energy efficiency solutions; and develops the energy resources of the future, including biofuels. Chevron is based in San Ramon, Calif. More information about Chevron is available at www.chevron.com.
Nexen Energy ULC announces organizational changes in response to industry downturn
Calgary, Alberta (March 17, 2015) – Nexen Energy ULC (Nexen), a wholly-owned subsidiary of CNOOC Limited, has announced organizational changes that will reduce its North American workforce by approximately 340 employees. Nexen UK has also initiated a consultation process to adjust its staffing levels by approximately 60 employees.
“In response to the recent industry downturn that has affected all companies in the energy sector, a decision was made to conduct a thorough review of our organization to ensure our long-term viability and sustainability,” said Fang Zhi, Chief Executive Officer of Nexen. “While regrettable, these organizational changes are necessary to align the company with our reduced capital spending program. We take these decisions seriously, and all impacted employees have been treated fairly and with respect.”
“Nexen has enhanced its performance over the past two years. We have already demonstrated our ability to continuously improve as evidenced by our best-ever health, safety and environmental performance in 2014, our Oil Sands production rising by 40% since 2012 and our ability to bring on Golden Eagle, a major North Sea development, on-stream ahead of schedule and under budget.
“Our long-term perspective continues to be fundamental to how we make decisions for our organization. As one of the world’s largest oil and gas producers, CNOOC Limited is focused on driving long-term stability for the company. CNOOC Limited’s rationale for acquiring Nexen remains the same – it was not made with a short-term view, but rather to acquire, and responsibly develop long-term, quality resources.”
Nexen remains committed to the health and safety of its employees, contractors, the environment and the communities where it operates. The company is fully compliant with all of its Investment Canada undertakings.
Alpha Natural Resources, Inc. (Alpha), one of the nation’s largest coal companies, Alpha Appalachian Holdings (formerly Massey Energy), and 66 subsidiaries have agreed to spend an estimated $200 million to install and operate wastewater treatment systems and to implement comprehensive, system-wide upgrades to reduce discharges of pollution from coal mines in Kentucky, Pennsylvania, Tennessee, Virginia and West Virginia, the Department of Justice and the U.S. Environmental Protection Agency (EPA) announced today. Overall, the settlement covers approximately 79 active mines and 25 processing plants in these five states.
EPA estimates that the upgrades and advanced treatment required by the settlement will reduce discharges of total dissolved solids by over 36 million pounds each year, and will cut metals and other pollutants by approximately nine million pounds per year. The companies will also pay a civil penalty of $27.5 million for thousands of permit violations, which is the largest penalty in history under Section 402 of the Clean Water Act (CWA).
“The unprecedented size of the civil penalty in this settlement sends a strong deterrent message to others in this industry that such egregious violations of the nation’s Clean Water Act will not be tolerated,” said Robert G. Dreher, Acting Assistant Attorney General for the Justice Department’s Environment and Natural Resources Division. “Today’s agreement is good news for communities across Appalachia, who have too often been vulnerable to polluters who disregard the law. It holds Alpha accountable and will bring increased compliance and transparency among Alpha and its many subsidiaries.”
“This settlement is the result of state and federal agencies working together to protect local communities from pollution by enforcing the law,” said Cynthia Giles, Assistant Administrator of EPA’s Office of Enforcement and Compliance Assurance. “By requiring reforms and a robust compliance program, we are helping to ensure coal mining in Appalachia follows environmental laws that protect public health.”
In addition to paying the penalty, the companies must build and operate treatment systems to eliminate violations of selenium and salinity limits, and also implement comprehensive, system-wide improvements to ensure future compliance with the CWA. These improvements, which apply to all of Alpha’s operations in Appalachia, include developing and implementing an environmental management system and periodic internal and third-party environmental compliance audits.
The companies must also maintain a database to track violations and compliance efforts at each outfall, significantly improve the timeliness of responding to violations, and consult with third party experts to solve problem discharges. In the event of future violations, the companies will be required to pay stipulated penalties, which may be increased and, in some cases, doubled for continuing violations.
The government complaint alleged that, between 2006 and 2013, Alpha and its subsidiaries routinely violated limits in 336 of its state-issued CWA permits, resulting in the discharge of excess amounts of pollutants into hundreds of rivers and streams in Kentucky, Pennsylvania, Tennessee, Virginia, and West Virginia. The violations also included discharge of pollutants without a permit.
In total, EPA documented at least 6,289 violations of permit limits for pollutants that include iron, pH, total suspended solids, aluminum, manganese, selenium, and salinity. These violations occurred at 794 different discharge points, or outfalls. Monitoring records also showed that multiple pollutants were discharged in amounts of more than twice the permitted limit on many occasions. Most violations stemmed from the company’s failure to properly operate existing treatment systems; install adequate treatment systems; and implement appropriate water handling and management plans.
Today’s settlement also resolves violations of a prior 2008 settlement with Massey Energy, and applies to the facilities and sites formerly owned by the company. Under the 2008 settlement, Massey paid a $20 million penalty to the federal government for similar CWA violations, in addition to over a million dollars in stipulated penalties over the course of the next two years. Alpha purchased Massey in June 2011 and, since taking over the company, has been working cooperatively with the government in developing the terms of today’s settlement.
CWA permits allow for the discharge of certain pollutants in limited amounts to rivers, streams, and other water bodies. Permit holders are required to monitor discharges regularly and report results to the respective state agencies.
Alpha, headquartered in Bristol, Va., is one of the largest coal companies in the nation. Alpha operates more than 79 active coal mines and 25 coal preparation plants located throughout Kentucky, Pennsylvania, Tennessee, Virginia, West Virginia, and Wyoming. The Wyoming operations are not included in today’s settlement.
The States of West Virginia, Pennsylvania, and Kentucky are co-plaintiffs in today’s settlement. The U.S. will receive half of the civil penalty and the other half will be divided between the co-plaintiffs based on the number of violations in each state, as follows: West Virginia ($8,937,500), Pennsylvania ($4,125,000), and Kentucky ($687,500).
The consent decree, lodged in the U.S. District Court for the Southern District of West Virginia, is subject to a 30-day public comment period and approval by the federal court.
This Press Release is courtesy of www.justice.gov
Underscoring President Obama’s Climate Action Plan to cut harmful emissions and double energy efficiency, the Energy Department is taking action to develop the next generation of combined heat and power (CHP) technology and help local communities and businesses make cost-effective investments that save money and energy. As part of this effort, the Department launched today seven new regional Combined Heat and Power Technical Assistance Partnerships across the country to help strengthen U.S. manufacturing competitiveness, lower energy consumption and reduce harmful emissions.
Last year, President Obama established a new national goal of 40 gigawatts of new CHP capacity by 2020 – a 50 percent increase from today. Meeting this goal would help American manufacturers and companies save as much as $100 billion in energy costs over the next decade and reduce emissions equivalent to taking 25 million cars off the road. View an Energy Department infographic on how CHP technology works and its environmental and economic benefits.
Launching Seven New CHP Technical Assistance Partnerships
Since 2003, the Energy Department has supported a set of regional centers to help organizations understand how CHP can improve their bottom lines and lower energy bills.
Today, the Department is launching seven regional CHP Technical Assistance Partnerships – the next generation of these centers – to help further grow America’s CHP market for commercial, institutional and industrial businesses, state agencies, utilities and trade associations. Located in California, Colorado, Illinois, New York, North Carolina, Pennsylvania and Washington state, these organizations will offer best practices for CHP project financing, management and state policies, market analysis tools and resources, and technical site evaluations.
Find more information on how the CHP Technical Assistance Partnerships are helping U.S. businesses and communities get the information they need to make smart, cost-effective investment decisions.
Strengthening Infrastructure Reliability and Resilience
Combined heat and power technologies can also help make our nation’s infrastructure smarter, stronger and better equipped to maintain power against increasingly severe weather events. During and after Hurricane Sandy, CHP helped hospitals, fire stations and multifamily housing in New York and New Jersey continue their operations when the electric grid went down.
The Energy Department, the Department of Housing and Urban Development and the Environmental Protection Agency recently issued a guide to help state and local officials determine if CHP is a good option for Sandy rebuilding efforts. The guide includes practical information on financial, site and technical decision-making as well as how to operate and maintain these systems.
The Energy Department is also helping critical facilities across the country invest in CHP – providing affordable, reliable power and heat and ensuring that life-saving operations keep running. For example, in 2010, Thermal Energy Corporation installed a new high-efficiency 48 megawatt CHP system to power and heat the University of Texas MD Anderson Cancer Center, Texas Children’s Hospital and 16 other institutions at the Texas Medical Center. The Energy Department invested about $10 million in this project, matched by $62 million in private funding. Last year, the Midwest Clean Energy Application Center helped Gundersen Health system complete installation of a CHP system at its medical campus in Onalaska, Wisconsin – completely offsetting its electricity and steam needs and saving about $100,000 each year.
Developing Innovation CHP Technologies
In addition to technical assistance efforts, the Energy Department is supporting research, development and demonstration projects to help grow the CHP market, including finding CHP solutions that fit small- and medium-sized facilities and accelerating new product commercialization.
Industries with high and continuous demand for both electrical and thermal energy – such as food processing, paper manufacturing and metals production – are well suited for CHP installations but often face market and technical barriers to deployment. With that in mind, the Department is supporting demonstration projects to test how these systems impact plants’ operations and energy use and help identify financing and maintenance best practices. For instance, the Department partnered with Frito-Lay to install and test a CHP system at its Killingly, Conn.-based food processing facility. In addition to providing reliable, efficient power, the gas-fired system reuses excess heat to warm Frito-Lay’s chip fryer oil – cutting costs and reduce harmful air pollution.
The Department is also supporting new CHP technologies that are cleaner, more efficient and can use a variety of fuel sources. The Gas Technology Institute is developing a new CHP burner technology that cuts greenhouse gas emissions while improving overall system efficiency. Capstone Turbine Corporation is designing a combined 65 kilowatt CHP system and biomass gasifier that can use stalks, grass and other material to generate gas and power a turbine. Capstone is also developing a 370 kilowatt CHP system that can save about 44 percent more energy over a traditional system while reducing carbon dioxide emissions by 60 percent and nitrogen oxide emissions by 95 percent.
Courtesy Department of Energy
SAN RAMON, Calif., – Chevron Corporation (NYSE: CVX) subsidiary Chevron U.S.A. Inc. announced that it has begun commercial production of premium base oils from a newly constructed manufacturing facility at the company’s Pascagoula refinery.
Base oils produced at Pascagoula will add to capacity from the company’s refinery in Richmond, California and a joint venture facility in Yeosu, Korea, approximately doubling Chevron’s production capacity and positioning it to be the world’s largest producer of premium base oil.
“Lubricants are a high growth business supporting economic development worldwide,” said Mike Wirth, executive vice president, Chevron Downstream & Chemicals. “The addition of the Pascagoula plant to Chevron’s base oil network enhances Chevron’s reputation as a reliable and flexible base oil supplier globally.”
Base oils from the new facility will supply customers in the U.S. East, Europe and Latin America, with Richmond continuing to supply the U.S. West, and both Richmond and Yeosu supplying Asia.
The facility is designed to manufacture 25,000 barrels per day of premium base oil, helping countries around the world meet increasingly strict regulatory requirements and higher performance standards for lubricants. Premium base oil is the main ingredient in the production of top-tier motor oils that help improve fuel economy, lower tail-pipe emissions and extend the time between oil changes. Base oils are used to make lubricants and greases for machinery and equipment in the commercial and industrial sectors.
The base oil facility uses Chevron’s proprietary ISODEWAXING® technology invented in 1993. The technology results in higher yields and enables a broader range of crude oil to be used in the manufacturing process. Over half of the world’s premium base oil is manufactured with this technology through licensing agreements with Chevron.
Chevron Corporation is one of the world’s leading integrated energy companies, with subsidiaries that conduct business worldwide. The company’s success is driven by the ingenuity and commitment of its employees and their application of the most innovative technologies in the world. Chevron is involved in virtually every facet of the energy industry. The company explores for, produces and transports crude oil and natural gas; refines, markets and distributes transportation fuels and other energy products; manufactures and sells petrochemical products; generates power and produces geothermal energy; provides energy efficiency solutions; and develops the energy resources of the future, including biofuels. Chevron is based in San Ramon, Calif. More information about Chevron is available at www.chevron.com.
The Department has been considering the proposed acquisition by LetterOne of twelve producing North Sea oil and gas fields currently owned by RWE Dea. The Secretary of State for the Department of Energy and Climate Change Ed Davey is responsible for ensuring the continued and safe production of the UK’s petroleum resources. In the discharge of these regulatory responsibilities, the Secretary of State has raised concerns with the respective companies about the effect that possible future sanctions imposed on LetterOne may have on the continued operation of these twelve fields and the serious health and safety and environmental risks that may result.
The companies have made a proposal designed to alleviate those concerns. After careful consideration the Secretary of State has decided that the proposal does not adequately and surely alleviate those concerns and has notified the companies involved that if the proposed acquisition were to proceed in its current form, he would be minded to require the companies to arrange for a further sale to a suitable third party.
HOUSTON, — Diamond Offshore Drilling, Inc. (NYSE:DO) and GE Oil & Gas (NYSE:GE) today announced the offshore drilling industry’s first-of-its-kind contractual service agreement (CSA) that transfers full accountability for BOP performance to GE Oil & Gas. In this Pressure Control by the Hour™ model, Diamond Offshore will compensate GE Oil & Gas only when the BOP is available. This 10-year collaborative arrangement for GE’s engageDrilling™ Services showcases a new way of thinking to drive continuous improvement in deepwater drilling.
The arrangement will include GE purchasing the BOP systems aboard Diamond Offshore’s four drillships, currently located in the U.S. Gulf of Mexico, for a total of $210 million.
“Subsea equipment repair and maintenance is the single largest cause of nonproductive time across our industry, resulting in great expense to both drillers and operators,” said Marc Edwards, President and CEO of Diamond Offshore. “In today’s market, we have to make the economics of offshore drilling more competitive for our clients. The purpose of our new Pressure Control by the Hour service model is to incentivize all parties to prioritize equipment reliability and availability for the ultimate benefit of our customers.”
“To deliver a solution that improves drilling efficiency now and in the future, collaboration is essential,” said Lorenzo Simonelli, President and CEO, GE Oil & Gas. “We are changing the game by building the new blowout preventer service model for the industry. With improved control, maintenance and servicing of our equipment, we are putting skin in the game and guaranteeing performance.”
The GE Oil & Gas engageDrilling™ Services offering enhances BOP system availability by transferring the maintenance and service of pressure control equipment to GE Oil & Gas. This includes on-rig GE Oil & Gas personnel, management of parts, overhaul and repair, continuous certification, data monitoring, and management of change. This new arrangement is a performance-based alliance that leverages the scale of GE data, predictive analytics, insights and continuous certification, positioning GE as a long-term commercial, operational and technical partner.
Under the new service model, Diamond Offshore will begin capturing data through GE’s monitoring and analytics solutions. Over time, this will enable condition-based monitoring and maintenance, which will drive proactive decision-making and planning to address the requirements of industry standards for drilling systems. By transferring the maintenance and service of well control equipment to GE Oil & Gas, Diamond Offshore is simplifying operations and optimizing between well maintenance to reduce the frequency and duration of downtime.
“This is a key part of GE’s business strategy to collaborate with drilling contractors and operators to push the boundaries of our industry,” said Simonelli. “Our new CSA model addresses the current needs of drilling companies, and establishes the roadmap for smart, predictive, condition-based services and maintenance in our digital-industrial future.”
“We look forward to partnering with GE Oil & Gas to lead the way forward in our industry,” said Edwards. “By combining Diamond Offshore’s operational excellence with the guaranteed performance of GE’s BOPs, we are increasing our competitiveness in the market.”
Riyadh, Saudi Arabia : The Saudi Arabian Mining Company (Ma’aden) and GE today signed a strategic Memorandum of Understanding to explore opportunities to deploy GE’s industry leading digital solutions across Ma’aden’s diverse mining operations, including sites focused on gold, copper, aluminum, and phosphate. GE will provide Ma’aden with digital transformation advisory and applications, as well as leadership and training opportunities for Ma’aden’s employees across the Kingdom.
To maintain its world leading competitive position across a number of commodities, Ma’aden is pursuing a number of partnerships in order to capture the opportunities found in digitization and innovation, and will invest in the application of pioneering technologies in its operations in the Kingdom in order to remain ahead of the competition and reinforce the company as a global mining leader. GE’s digital mining solutions will look at specific areas within Ma’aden including solutions that make adaptations for improving ore grades; reduce fuel and energy costs and usage; improve equipment reliability and availability; reduce maintenance costs; and increase productivity and efficiency across operations.
Darren Davis, Ma’aden Acting President & CEO, said of the partnership, “The Kingdom of Saudi Arabia has high aspirations for the deployment of new technology and the digitization of industrial landscape in the country. Ma’aden is committed to championing the responsible development of the mining sector as a major pillar of the Saudi economy and digitalization, as part of the fourth industrial revolution, will be key to ensuring we achieve our goal of becoming a ‘sustainable mining champion’. This initiative will unlock the next wave of significant value creation and increase our competitiveness and sustainability. Our partnership with GE is an important step and we look forward to working together to develop and utilize new digital solutions for our industry.”
Bill Ruh, President & CEO, GE Digital continued, saying, “We are partnering with organizations across heavy industries around the world to bring digital solutions to their operations. The scale and impact of organizations such as Ma’aden is enormous, and we know that the optimization and increases in efficiency will have a major impact on the company and the country. By working together to develop solutions that are tailored for the sector and environment in which they will operate, we can ensure truly positive outcomes.”
BHP Billiton today released its Climate Change Portfolio Analysis report which explains how it could continue to create shareholder value in a carbon constrained world.
Chief Commercial Officer Dean Dalla Valle said the Company had published details of its scenario analysis as part of its ongoing program of engagement with investors.
“With the release of this document, we are providing more information than ever before about how we are responding to climate change and how climate risk might affect the portfolio. The opportunities and risks associated with climate change will not be spread evenly between businesses or sectors. More disclosure will allow investors, policy makers and regulators to make more informed decisions. By sharing our analysis of BHP Billiton’s portfolio in a 2°C world, we believe investors will be able to decide how well BHP Billiton is equipped to manage climate risk.”
Helen Wildsmith, Stewardship Director – Climate Change, at charity specialist CCLA, said: “As long-term investors the ‘Aiming for A’ coalition supports diversified miners, oil and gas majors, and electrical utilities as they face the challenge of demonstrating their strategic resilience through the low carbon transition. Today we applaud BHP Billiton for proactively improving their disclosure. In co-ordination with the global Carbon Asset Risk investor initiative, representing over US$3.5 trillion of collective assets, we will be proposing further shareholder resolutions at some of the largest companies in these sectors in 2016 to promote similar stress testing.
“Like BHP Billiton, the ‘Aiming for A’ coalition believes key stakeholders need to work together through periods of systemic change. We encourage BHP Billiton to play an active role in building a cross-sectoral coalition of the willing to accelerate CCS and other low emissions technologies becoming commercially viable at scale.”
“BHP Billiton has shown real leadership by publishing its climate change portfolio analysis ahead of COP21 in Paris. This provides an excellent starting point for more detailed dialogue with investors on portfolio stress testing and future cap-ex decisions in a carbon efficient manner.” said Stephanie Maier, Head of Responsible Investment Strategy & Research at Aviva Investors, and Chair of the Institutional Investors Group on Climate Change’s member-led corporate engagement group.
BHP Billiton’s portfolio in a 2°C world
Speaking in London, Mr Dalla Valle said: “The world faces two critical challenges. As the global population steadily grows, the continued development of emerging economies depends on access to affordable energy and resources. At the same time, responding to climate change requires the global average temperature increase to remain below 2°C relative to pre-industrial levels.
“Achieving these goals would entail substantial changes to the global economy. Companies in all sectors will have new market opportunities, face new competitors and all will need to find new ways of working. In a well-managed transition, the most efficient producers in growth markets will do best.
“In our scenario analysis we consider a range of potential pathways and outcomes. This provides deeper, more valuable insights into the potential impacts on our portfolio and improves our ability to respond and adapt our portfolio where we see key signposts and triggers.
“In a 2°C scenario, we expect the demand for most of BHP Billiton’s products will continue to rise in absolute terms. As the energy mix changes, copper, gas and uranium could see stronger demand than otherwise would have been the case. Measures to reduce emissions in steel manufacturing could also increase prices for the Company’s higher-quality iron ore.
“Together these factors would help offset weaker demand, lower prices or higher costs in other areas of our portfolio such as energy coal. Group margins would remain strong, reflecting BHP Billiton’s focus on low cost production. The average rate of return on investment in our growth projects would fall slightly but remain at approximately 20 per cent. The Company could create value by bringing on production into growing markets.
“This helps ensure the value of BHP Billiton’s portfolio would remain robust if emissions decline to levels consistent with a 2°C world after 2030, as well as in a stress test that models the implications of more rapid change. In both cases, Group EBITDA would continue to grow over the next fifteen years and BHP Billiton’s commodity diversification, competitive production, high quality resource base, and the rapid payback periods of growth projects minimise the risk of stranded assets.”
BHP Billiton has also joined a growing number of leading businesses in disclosing the Company’s assumptions on global carbon price ranges which it applies to its investments and portfolio evaluation to inform decision making.
Our action on climate change
Mr Dalla Valle described how BHP Billiton is supporting the move to limit global temperature increases to 2°C.
“We are investing in the development of low-emissions technologies and supporting market mechanisms that provide financial incentives for emissions reductions and sustainable development.”
“We believe that a range of measures are needed to address climate change. First and foremost we are reducing our own emissions and improving our energy efficiency, with a target of keeping greenhouse gas emissions below our 2006 baseline.
“We also seek to enhance the global response to climate change by actively engaging with governments to provide our perspective while recognising that each government will formulate its own policy to reduce emissions in line with its own circumstances and the need for meaningful action.
Mr Dalla Valle concluded: “As climate change continues to evolve, so too will our approach and we will continue to engage with our investors and other stakeholders to keep improving our disclosure.
About ‘Aiming for A’ in the UK: ‘Aiming for A’ was launched by CCLA in 2012. The Church Investor Group members currently involved are: the three Church of England National Investing Bodies (the Church Commissioners, the Church of England Pensions Board and the CBF Church of England Funds) and the Central Finance Board of the Methodist Church. The other five partners in this £230bn UK initiative are the Local Authority Pension Fund Forum, Rathbone Greenbank Investments, Sarasin & Partners, Hermes Investment Management, and the Pensions Trust. The last three joined the initiative after supporting the ‘Aiming for A’ BP and Shell strategic resilience resolutions, which achieved >98% of the vote at the companies’ AGMs earlier this year. The ‘A’ within ‘Aiming for A’ refers to the best A-E CDP performance band. Within the scoring methodology considerable weight is given to operational emissions management, alongside the strategic and governance issues covered in the ‘Aiming for A’ 2015 shareholder resolutions.
CALGARY, Alberta and HOUSTON, Texas – September 6, 2016 – Enbridge Inc. (TSX, NYSE:ENB) (Enbridge) and Spectra Energy Corp (NYSE:SE) (Spectra Energy) today announced that they have entered into a definitive merger agreement under which Enbridge and Spectra Energy will combine in a stock-for-stock merger transaction (the “Transaction”), which values Spectra Energy common stock at approximately C$37 billion (US$28 billion), based on the closing price of Enbridge’s common shares on September 2, 2016. The combination will create the largest energy infrastructure company in North America and one of the largest globally based on a pro-forma enterprise value of approximately C$165 billion (US$127 billion). The Transaction was unanimously approved by the Boards of Directors of both companies and is expected to close in the first quarter of 2017, subject to shareholder and certain regulatory approvals, and other customary conditions.
Under the terms of the Transaction, Spectra Energy shareholders will receive 0.984 shares of the combined company for each share of Spectra Energy common stock they own. The consideration to be received by Spectra Energy shareholders is valued at US$40.33 per Spectra Energy share, based on the closing price of Enbridge common shares on September 2, 2016, representing an approximate 11.5 percent premium to the closing price of Spectra Energy common stock on September 2, 2016. Upon completion of the Transaction, Enbridge shareholders are expected to own approximately 57 percent of the combined company and Spectra Energy shareholders are expected to own approximately 43 percent. The combined company will be called Enbridge Inc.
This combination brings together two highly complementary platforms to create North America’s largest energy infrastructure company and meaningfully enhances customer optionality. With an asset base that includes a diverse set of best-in-class assets comprised of crude oil, liquids and natural gas pipelines, terminal and midstream operations, a regulated utility portfolio and renewable power generation, the combined company will be positioned to provide integrated services and first and last mile connectivity to key supply basins and demand markets. On a combined basis for the 12 months ended June 30, 2016, the company would have generated combined revenues in excess of C$40 billion (US$31 billion) and combined Earnings before Interest and Taxes (EBIT) of C$5.8 billion (US$4.4 billion), and will have the scale, balance sheet strength, financial flexibility and free cash flow to comfortably fund future growth.
“Over the last two years, we’ve been focused on identifying opportunities that would extend and diversify our asset base and sources of growth beyond 2019,” said Al Monaco, President and Chief Executive Officer, Enbridge Inc. “We are accomplishing that goal by combining with the premier natural gas infrastructure company to create a true North American and global energy infrastructure leader. This Transaction is transformational for both companies and results in unmatched scale, diversity and financial flexibility with multiple platforms for organic growth.”
Greg Ebel, President and Chief Executive Officer of Spectra Energy, who will become chairman of Enbridge following the closing of the Transaction, said, “The combination of Enbridge and Spectra Energy creates what we believe will be the best, most diversified energy infrastructure company in North America, if not the world. This is an incredible opportunity for both companies and we at Spectra Energy could not be more excited about what it means going forward. Together, the merged company will have what we believe is the finest platform for serving customers in every region of North America and providing investors with the opportunity for superior shareholder returns.”
Mr. Monaco added, “Bringing Enbridge and Spectra Energy together makes strong strategic and financial sense, and the all-stock nature of the Transaction provides shareholders of both companies with the opportunity to participate in the significant upside potential of the combined company. With combined secured projects in execution of C$26 billion (US$20 billion) and another C$48 billion (US$37 billion) of projects under development, the Transaction allows us to extend our anticipated 10-12 percent annual dividend growth through 2024. We believe our combination of best-in-class assets, superior growth and strong commercial underpinning of our business will be unrivaled in our sector. Importantly, we will preserve and enhance our shareholder value proposition, which centers on delivering consistent growth with a low-risk business model.
“This is also a combination of two companies, management and staff that have a shared vision and talented teams that are dedicated to serving customers and providing the energy that people want and need, safely and reliably every day. We look forward to welcoming Spectra Energy employees to Enbridge as we move forward as one company. In building on our existing strengths by joining with Spectra Energy, Enbridge will be very well positioned for future growth and continued value creation.”
Mr. Ebel added, “The strength of the combined company will support a large capital program to fund the continued development of Spectra Energy’s existing, preeminent project inventory in addition to allowing the combined company to compete for and win the most attractive new growth projects – all while maintaining expected strong dividend growth with exceptional coverage. The transaction premium recognizes the strength of Spectra Energy’s world-class natural gas pipeline system and significant expansion program, while providing shareholders the opportunity to participate in the unparalleled value creation potential of the combined company. While our assets are largely complementary, our values are shared, and together we will create a best-in-class company for shareholders, employees, customers, and communities alike.”
Compelling Value Proposition
Six leading strategic growth platforms: The combined company brings together many of the highest quality energy infrastructure assets in North America: liquids and gas pipelines; US and Canadian midstream businesses; a top tier regulated utility portfolio; and a growing renewable power generation business. A map of the assets of the combined entity is available at www.enbridge.com and www.spectraenergy.com.
Secure, low-risk commercial structure with stable long-term cash flow visibility: 96 percent of pro-forma free cash flow is underpinned by long-term commercial agreements (cost-of-service, take-or-pay, of fixed fee); 93 percent of customers are strong, investment grade or equivalent counterparties; less than 5 percent of combined pro-forma cash flow will have direct exposure to commodity price risk.
Largest and most secure program of diversified organic growth projects in the industry: Together, Enbridge and Spectra Energy bring C$26 billion (US$20 billion) in secured capital and a C$48 billion (US$37 billion) inventory of probability weighted projects in development.
Strong balance sheet, growing cash flow and access to capital markets to fund large capital program: The combination is expected to result in sufficient internally generated cash flow to fund growth and improve balance sheet strength. Enbridge will have multiple, cost-effective funding sources and be even more competitive in capturing opportunities.
Attractive dividend yield with visible organic dividend growth: The combined company’s C$74 billion (US$57 billion) organic growth platform is expected to support a highly visible dividend growth rate of 10-12 percent through 2024, including an anticipated aggregate increase of 15 percent in 2017 post closing, while maintaining a conservative payout of 50-60 percent of available cash flow from operations (ACFFO). This provides an industry leading total return driven by a strong, low-risk dividend yield.
Achievable cost synergies: The combination is expected to achieve annual run-rate synergies of C$540 million (US$415 million), the majority of which should be achieved in the latter part of 2018. In addition, approximately C$260 million (US$200 million) of tax savings can be achieved through utilization of tax losses commencing in 2019.
Complementary businesses, shared culture and values support smooth integration: Enbridge and Spectra Energy have similar business and operational models, talented teams, common cultures and values, including shared commitment to safety, stewardship of the environment, meaningful stakeholder engagement and investing in communities.
Leadership, Governance and Structure
Upon closing of the Transaction, Al Monaco will continue to serve as President and Chief Executive Officer of the combined company. Greg Ebel will serve as non-executive Chairman of Enbridge’s Board of Directors.
Enbridge’s Board of Directors is expected to have a total of 13 directors consisting of 8 members designated by Enbridge, including Mr. Monaco, and 5 members designated by Spectra Energy, including Mr. Ebel.
The senior management team of the combined entity will be communicated in due course. On closing, the following appointments will take effect:
Guy Jarvis, President, Liquids Pipelines & Major Projects
Bill Yardley, President, Gas Transmission & Midstream
John Whelen, Executive Vice President & Chief Financial Officer
The headquarters of the combined company will be in Calgary, Alberta. Houston, Texas will be the combined company’s gas pipelines business unit center; Edmonton, Alberta will remain the business unit center for liquids pipelines, with gas distribution continuing to be based in Ontario.
Enbridge and Spectra Energy will immediately establish an integration planning team composed of leaders from both management teams to prepare for and oversee the effective and timely integration of the businesses. The approach to integration planning will be collaborative, drawing on strong participation from both companies, and ensuring continuity for customers and other stakeholders.
On closing the Enbridge common shares to be issued in connection with the Transaction will be listed on the TSX and NYSE. Spectra Energy common stock will be delisted from the NYSE.
Financial Considerations
Enbridge expects the Transaction to be neutral to its 12 percent to 14 percent secured ACFFO per share CAGR guidance through the 2014-2019 time period, and strongly additive to its growth beyond that timeframe. Enbridge is committed to maintaining the financial strength of the combined company. The funding program is designed to ensure strengthening of the balance sheet with the objective of maintaining strong investment grade credit ratings. Enbridge expects it will divest of approximately $2 billion of non-core assets over the next 12 months to provide additional financial flexibility.
At closing, Enbridge Energy Partners, LP and Spectra Energy Partners, LP are expected to continue to be publicly traded partnerships headquartered in Houston, Texas. Enbridge Income Fund Holdings will remain a publicly traded corporation headquartered in Calgary, Alberta.
Timing and Approvals
The Transaction is expected to close in the first quarter of 2017 subject to the receipt of both companies’ shareholder approvals, along with certain regulatory and government approvals, including compliance with the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and approval under Canada Competition Act, and the satisfaction of other customary closing conditions.
Analysts, members of the media and other interested parties can access the call toll-free at 1-866-610-1072 or within and outside North America at 1-973-935-2840 using the access code of 77468882. The call will be audio webcast live here (http://event.on24.com/r.htm?e=1261390&s=1&k=27BFA58D1E6D82F42F35E52AF74D0395). A webcast replay and podcast will be available approximately two hours after the conclusion of the event and a transcript will be posted to the website within 24 hours. The replay will be available at toll-free 1-800-585-8367 or within and outside North America at 1-404-537-3406 (access code 77468882) for seven days after the call.
ABOUT ENBRIDGE INC.
Enbridge Inc., a Canadian company, exists to fuel people’s quality of life, and has done so for more than 65 years. A North American leader in delivering energy, Enbridge has been ranked on the Global 100 Most Sustainable Corporations index for the past seven years. Enbridge operates the world’s longest crude oil and liquids transportation system across Canada and the U.S., and has a significant and growing involvement in natural gas gathering, transmission and midstream business, as well as an increasing involvement in power transmission. Enbridge owns and operates Canada’s largest natural gas distribution company, serving residential, commercial, and industrial customers in Ontario, Quebec, New Brunswick and New York State. Enbridge has interests in nearly 2,000 megawatts of net renewable and alternative generating capacity, and continues to expand into wind, solar and geothermal power. Enbridge employs nearly 11,000 people, primarily in Canada and the U.S., and is ranked as one of Canada’s Top Employers for 2016.
Enbridge’s common shares trade on the Toronto and New York stock exchanges under the symbol ENB. For more information, visit www.enbridge.com.
ABOUT SPECTRA ENERGY CORP
Spectra Energy Corp (NYSE: SE), a FORTUNE 500 company, is one of North America’s leading pipeline and midstream companies. Based in Houston, Texas, the company’s operations in the United States and Canada include approximately 21,000 miles of natural gas and crude oil pipelines; approximately 300 billion cubic feet of natural gas storage; 4.8 million barrels of crude oil storage; as well as natural gas gathering, processing, and local distribution operations. Spectra Energy is the general partner of Spectra Energy Partners (NYSE: SEP), one of the largest pipeline master limited partnerships in the United States and owner of the natural gas and crude oil assets in Spectra Energy’s U.S. portfolio. Spectra Energy also has a 50 percent ownership in DCP Midstream, the largest producer of natural gas liquids and the largest natural gas processor in the United States. Spectra Energy has served North American customers and communities for more than a century. For more information, visit www.spectraenergy.com.
Energy is used to heat and to cool buildings and homes, transport goods, and power the economy. But with ageing infrastructure, poorly integrated markets, and uncoordinated policies, our consumers, households and businesses do not benefit from increased choice or from lower energy prices. It is time to complete the single energy market in Europe. Delivering on this top priority set out in President Juncker's political guidelines, today the European Commission sets out its strategy to achieve a resilient Energy Union with a forward-looking climate change policy.
The Energy Union means in particular:
Solidarity clause: reducing the dependence on single suppliers and fully relying on their neighbours, especially when confronted with energy supply disruptions. With more transparency when EU countries make deals to buy energy or gas from countries outside the EU;
Energy flows, as if it were a Fifth freedom: that of free flow of energy across borders - strictly enforcing the current rules in areas such as energy unbundling and the independence of regulators – taking legal action if needed. Redesigning the electricity market, to be more interconnected, more renewable, and more responsive. Seriously overhauling state interventions in the internal market, and phasing out environmentally harmful subsidies.
Energy efficiency first: fundamentally rethinking energy efficiency and treating it as an energy source in its own right so that it can compete on equal terms with generation capacity;
Transition to a low-carbon society that is built to last: ensuring that locally produced energy – including from renewables – can be absorbed easily and efficiently into the grid; promoting EU technological leadership, through developing the next generation of renewables technology and becoming a leader in electromobility, while European companies expand exports and compete globally.
In an Energy Union, citizens are at the core. The prices they pay should be affordable and competitive. Energy should be secure and sustainable, with more competition and choice for every consumer.
These and other commitments sit alongside an action plan to meet these ambitious goals in our energy and climate policy.
Jean-Claude Juncker, Commission President, said "For too long, energy has been exempt from the fundamental freedoms of our Union. Current events show the stakes – as many Europeans fear they may not have the energy needed to heat their homes. This is about Europe acting together, for the long term. I want the energy that underpins our economy to be resilient, reliable, secure and growingly renewable and sustainable."
Maroš Šefčovič, the Vice-President responsible for the Energy Union said: "Today, we launch the most ambitious European energy project since the Coal and Steel Community. A project that will integrate our 28 European energy markets into one Energy Union, make Europe less energy dependent and give the predictability that investors so badly need to create jobs and growth. Today, we set in motion a fundamental transition towards a low-carbon and climate-friendly economy, towards an Energy Union that puts citizens first, by offering them more affordable, secure, and sustainable energy. Together with all other Commissioners who have worked closely on the project team, and with the support of the entire Commission, I am determined to now turn this Energy Union into reality."
Miguel Arias Cañete, Commissioner for Climate Action and Energy said: "Let's get down to work. Today we have set the course for a connected, integrated and secure energy market in Europe. Now, let's make it happen. Our path to real energy security and climate protection begins here at home. That's why I will focus on building our common energy market, saving more energy, expanding renewables, and diversifying our energy supply. After decades of delay, we will not miss another opportunity to build an energy union. The Juncker Commission gets the big things right."
Key figures
The EU is the largest energy importer in the world, importing 53% of its energy, at an annual cost of around €400 billion.
12 EU Member States[1] do not meet the EU's minimum interconnection target – that at least 10% of installed electricity production capacity be able to "cross borders". The EU has listed 137 electricity projects, including 35 on electricity interconnection: between them, these projects could bring that figure from 12 down to 2 Member States.
An appropriately interconnected European energy grid could save consumers up to €40 billion a year.
6 EU Member States[2] are dependent on one single external supplier for all their gas imports.
75% of our housing stock is energy inefficient; 94% percent of transport relies on oil products, of which 90% is imported.
Over €1 trillion needs to be invested into the EU energy sector by 2020 alone.
Wholesale electricity prices in Europe are 30% higher, and wholesale gas prices over 100% higher, than in the US.
European renewable energy businesses have a combined annual turnover of €129 billion, employing over a million people. The challenge is to retain Europe's leading role in global investment in renewable energy.
EU greenhouse gas emissions fell 18% in the period 1990-2011.
By 2030, the EU aims to cut greenhouse gas emissions by at least 40%, boost renewable energy by at least 27%, and improve energy efficiency by at least 27%.
What has been adopted today
A Framework Strategy for a Resilient Energy Union with a Forward-Looking Climate Change Policy. This sets out, in five interrelated policy dimensions, the goals of an energy union – and the detailed steps the Juncker Commission will take to achieve it, including new legislation to redesign and overhaul the electricity market, ensuring more transparency in gas contracts, substantially developing regional cooperation as an important step towards an integrated market, with a stronger regulated framework, new legislation to ensure the supply for electricity and gas, increased EU funding for energy efficiency or a new renewables energy package, focusing European R&I energy strategy, reporting annually on the 'State of the Energy Union', just to name a few.
An Interconnection Communication, setting out the measures needed to achieve the target of 10% electricity interconnection by 2020, which is the minimum necessary for the electricity to flow and be traded between Member States. It shows which Member States currently meet the target - and which projects are necessary to close the gap by 2020.
A Communication setting out a vision for a global climate agreement in Paris in December. The vision is for a transparent, dynamic and legally binding global agreement with fair and ambitious commitments from all parties. The Communication also translates the decisions taken at the European Summit in October 2014 into the EU's proposed emissions reduction target (the so-called Intended Nationally Determined Contribution, or INDC) for the new agreement.
Eni has made a world class supergiant gas discovery at its Zohr Prospect, in the deep waters of Egypt. The discovery could hold a potential of 30 trillion cubic feet of lean gas in place covering an area of about 100 square kilometres. Zohr is the largest gas discovery ever made in Egypt and in the Mediterranean Sea. Eni will immediately appraise the field with the aim of accelerating a fast track development of the discovery that will utilise at best the existing offshore and onshore infrastructures. Eni’s CEO, Claudio Descalzi, has recently travelled to Cairo to update Egypt’s President, Abdel Fattah Al-Sisi, on this important success, and discuss this discovery with the Prime Minister, Ibrahim Mahlab, and the Minister of Petroleum and Mineral Resources, Sherif Ismail.
The discovery, after its full development, will be able to ensure satisfying Egypt’s natural gas demand for decades
According to the well and geophysical data available, the field could hold a potential of 30 trillion cubic feet of lean gas in place, therefore representing one of the world’s largest natural-gas finds, located in a permit where Eni holds a 100% of the Contractor’s working interest
Eni’s CEO, Claudio Descalzi, has recently travelled to Cairo to discuss the new exploration success with the Egyptian institutional leaders
San Donato Milanese (Milan), 30 August 2015 – Eni has made a world class supergiant gas discovery at its Zohr Prospect, in the deep waters of Egypt. The discovery well Zohr 1X NFW is located in the economic waters of Egypt’s Offshore Mediterranean, in 4,757 feet of water depth (1,450 metres), in theShorouk Block, signed in January 2014 with the Egyptian Ministry of Petroleum and the Egyptian Natural Gas Holding Company (EGAS) following a competitive international Bid Round.
According to the well and seismic information available, the discovery could hold a potential of 30 trillion cubic feet of lean gas in place (5.5 billion barrels of oil equivalent in place) coveringan area of about 100 square kilometres. Zohr is the largest gas discovery ever made in Egypt and in the Mediterranean Sea and could become one of the world’s largest natural-gas finds. This exploration success will give a major contribution in satisfying Egypt’s natural gas demand for decades.
Eni will immediately appraise the field with the aim of accelerating a fast track development of the discovery that will utilise at best the existing offshore and onshore infrastructures.
Zohr 1X NFW was drilled to a total depth of approximately 13,553 feet (4,131 metres) and hit 2,067 feet (630 metres) of hydrocarbon column in a carbonate sequence of Miocene age with excellent reservoir characteristics (400 metresplus of net pay). Zohr’s structure has also a deeper Cretaceous upside that will be targeted in the future with adedicated well.
Eni’s CEO, Claudio Descalzi, has recently travelled to Cairo to update Egypt’s President, Abdel Fattah Al-Sisi, on this important success, and discuss this discovery with the Prime Minister, Ibrahim Mahlab, and the Minister of Petroleum and Mineral Resources, Sherif Ismail.
“It’s a very important day for Eni and its people. This outstanding result confirms our expertise and our technological innovation capacity with immediate operational application, and above all shows the strength of the cooperation spirit amongst all the company’s units which are at the foundation of our great successes. Our exploration strategy allows us to persist in the mature areas of countries which we have known for decades and has proved to be winning, reconfirming that Egypt has still great potential. This historic discovery will be able to transform the energy scenario of Egypt in which we have been welcomed for over 60 years. The exploration activities are central to our growth strategy: in the last 7 years we have discovered 10 billion barrels of resources and 300 million in the first half of the year, confirming Eni’s leading position in the industry. This exploration success acquires an even greater value as it was made in Egypt which is strategic for Eni, and where important synergies with the existing infrastructures can be exploited allowing us a fast production startup‘, Claudio Descalzi commented.
Eni, through its subsidiary IEOC Production B.V., holds a 100% of the Contractor’s working interest in the Shorouk Block and is the operator of the concession. Eni has been present in Egypt since 1954 through its subsidiary IEOC, a company which has always been a frontrunner in exploring and exploiting gas resources in Egypt since the discovery of the Abu Maadi Field in 1967.
By adopting new exploration concepts, leading edge technologies and operational approaches, through AGIBA and Petrobel, operating companies participated by IEOC and EGPC, Eni has successfully managed to double production of oil from the Western Desert and the GOS Abu Rudeis Concessions in the last three years as well as to revamp production from the Abu Maadi plays in the Nile Delta area following the recently announced Nidoco NW 2 discovery (Nooros prospect) currently already in production.
Eni is the main hydrocarbon producer in Egypt, with a daily equity production of 200,000 barrels of oil equivalent.
HOUSTON–Nov. 21, 2017– Enterprise Products Partners L.P. (NYSE:EPD) was among the most honored companies as recognized by Institutional Investor magazine’s 2018 All-America Executive Team rankings, and was one of only five companies that swept their respective sectors. The results of this year’s survey reflect the opinions of more than 4,000 buy-side and sell-side analysts at over 1,200 firms, marking the second year in a row that Enterprise has earned a sweep.
In the Natural Gas Pipeline and Master Limited Partnership sector, Enterprise was the top-ranked Investor Relations Company by both the sell-side and buy-side analyst communities. Individual honors went to A.J. “Jim” Teague, chief executive officer of Enterprise’s general partner, who was selected top-ranked CEO overall and in the sector by both the buy-side and sell-side firms; Bryan F. Bulawa, senior vice president and chief financial officer of Enterprise’s general partner, was voted the top-ranked CFO overall and in the sector by both the buy-side and sell-side firms; and John R. “Randy” Burkhalter, vice president, Investor Relations of Enterprise’s general partner, was voted the top-ranked Investor Relations Professional overall by both the buy-side and sell-side firms. In addition, Enterprise was recognized for hosting the Best Analyst Day event.
“These individual honors reflect the dedication and hard work of our more than 7,000 employees at Enterprise,” said Randa Duncan Williams, chairman of the board of Enterprise’s general partner. “In this challenging environment, we continue to demonstrate our commitment to taking the steps necessary to build value for our investors, and we sincerely appreciate the financial community’s recognition of our efforts.”
The 2018 Executive All-America Team will be published in the January 2018 issue of Institutional Investor and also on their website at www.institutionalinvestor.com. In determining the results of the annual All-America Executive Team, buy-side analysts, portfolio managers and sell-side analysts at securities firms and financial firms across the country were asked to name the best CEOs, CFOs, IR professionals and companies with the best investor relations programs in their sector. All votes were weighted by place and aggregated to produce distinct rankings for each category.
Enterprise Products Partners L.P. is one of the largest publicly traded partnerships and a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, refined products and petrochemicals. Our services include: natural gas gathering, treating, processing, transportation and storage; NGL transportation, fractionation, storage and import and export terminals; crude oil gathering, transportation, storage and terminals; petrochemical and refined products transportation, storage and terminals; and a marine transportation business that operates primarily on the United States inland and Intracoastal Waterway systems. The partnership’s assets include approximately 50,000 miles of pipelines; 260 million barrels of storage capacity for NGLs, crude oil, refined products and petrochemicals; and 14 billion cubic feet of natural gas storage capacity.
IRVING, Texas–Exxon Mobil Corporation (NYSE:XOM) said today it added 2.7 billion oil-equivalent barrels of proved oil and gas reserves in 2017, replacing 183 percent of production. ExxonMobil’s proved reserves totaled 21.2 billion oil-equivalent barrels at year-end 2017. Liquids represented 57 percent of the reserves, up from 53 percent in 2016. ExxonMobil’s reserves life at current production rates is 14 years.
“Our exploration success and strategic acquisitions made during a period of low commodity prices are adding high-quality resources that are among the lowest cost of supply in the industry,” said Darren W. Woods, chairman and chief executive officer. “ExxonMobil’s portfolio of development opportunities positions us to grow shareholder value as we bring on new supplies of oil and natural gas to meet growing demand.”
During 2017, proved additions at Upper Zakum in Abu Dhabi totaled more than 800 million barrels of crude oil. Additions from liquids-rich unconventional plays in the United States, mainly in the Permian Basin, totaled approximately 800 million oil-equivalent barrels. Additions in the Permian are supported by ExxonMobil’s growth plan and increased drilling activity, expected to increase daily production to more than 600,000 oil-equivalent barrels by 2025.
Other significant new proved reserve additions were made in Guyana, where the company funded the first phase of development last year, and in Mozambique, associated with the project funding of the Coral FLNG project in the gas-rich deepwater Area 4.
Offshore Guyana, ExxonMobil has discovered recoverable resources, including current proved reserves and additional resources, estimated to be 3.2 billion gross oil-equivalent barrels prior to the 2018 Ranger discovery. Production from Liza Phase 1 is expected to begin by 2020, less than five years after discovery. In Mozambique, ExxonMobil acquired a 25 percent indirect interest in Area 4, which contains an estimated 85 trillion gross cubic feet of natural gas in-place.
Reserves additions reflect new developments as well as revisions and extensions of existing fields resulting from drilling, studies and analysis of reservoir performance.
Consistent with SEC requirements, ExxonMobil reports reserves based on the average of the applicable market price prevailing on the first day of each calendar month during the year. As a result of higher prices in 2017 relative to 2016, about 900 million oil-equivalent barrels in North America qualified as proved reserves under SEC guidelines due primarily to the extension of the projected economic end-of-field-life.
The annual reporting of proved reserves is the product of the corporation’s long-standing, rigorous process that ensures consistency and management accountability in all reserves bookings.
Resource Base
ExxonMobil added 9.8 billion oil-equivalent barrels to its resource base in 2017 through by-the-bit exploration discoveries and strategic acquisitions. This was the largest addition to the resource base since the acquisition of XTO Energy in 2010. The resource base includes proved reserves, plus other discovered resources that are expected to be ultimately recovered.
Through its acquisition of various entities from the Bass family of Fort Worth, Texas in 2017, ExxonMobil added significant resource in the Permian Basin, with upside potential in multiple additional prospective horizons. The company continues to maximize capital efficiency in its tight oil developments by taking advantage of contiguous acreage to drill long laterals with optimized completion designs.
Key resource additions were also made in deepwater Brazil pre-salt with the acquisition of interest in the two billion gross oil-equivalent-barrel Carcara field, onshore Papua New Guinea with the acquisition of InterOil Corporation, and Mozambique with the purchase of an interest in Area 4.
Three new discoveries offshore Guyana in 2017 also contributed to the by-the-bit resource additions. Additional exploration drilling in Guyana is planned in 2018 on the 11.5 million gross acres currently held offshore.
ExxonMobil’s resource base totaled approximately 97 billion oil-equivalent barrels at year-end 2017, taking into account field revisions, production and asset sales.
About ExxonMobil
ExxonMobil, the largest publicly traded international energy company, uses technology and innovation to help meet the world’s growing energy needs. ExxonMobil holds an industry-leading inventory of resources, is one of the largest refiners and marketers of petroleum products, and its chemical company is one of the largest in the world. For more information, visit www.exxonmobil.com or follow us on Twitter www.twitter.com/exxonmobil.
IRVING, Texas – ExxonMobil and Scepter, Inc. have agreed to work together to deploy advanced satellite technology and proprietary data processing platforms to detect methane emissions at a global scale. The agreement has the potential to redefine methane detection and mitigation efforts and could contribute to broader satellite-based emission reduction efforts across a dozen industries, including energy, agriculture, manufacturing and transportation.
ExxonMobil and Scepter, Inc. to deploy satellite technology for real-time methane emissions detection
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Real-time methane emissions monitoring at global scale
Technology consolidates data from multiple detection sources
Multi-sector initiative spans 12 industries
“This collaboration will enable multiple industries to identify the sources of methane emissions around the world in real-time, so that leak repairs or mitigation solutions can be deployed rapidly,” said Bart Cahir, senior vice president of unconventional at ExxonMobil. “This is another example of how ExxonMobil is investing in technology with leading innovators to align with the Global Methane Pledge to reduce methane emissions by 30% by 2030, compared to 2020 levels.”
In the first phase of the project, the companies will design and optimize the plan for satellite placement and coverage, initially focused on capturing methane emissions data from ExxonMobil operations in the Permian Basin. Scepter will deploy satellites in 2023 and increase coverage to more than 24 satellites over three years, forming a large constellation network capable of monitoring operations around the world.
Scepter’s satellite detection technology has shown the ability to accurately collect data on methane, while also identifying sources of carbon dioxide, nitrogen oxides, sulfur oxides, and other greenhouse gases.
ExxonMobil and Scepter are also pioneering a proprietary data fusion system that reconciles information collected from multiple detection methods, including ground-based, stationary and mobile monitoring devices. By consolidating the data, scientists could unlock valuable insights and opportunities to further quantify and validate programs that reduce methane emissions.
“We’re excited to work with ExxonMobil to develop a system that goes beyond methane detection. Our data fusion platform will be central to a broader capability to detect, quantify, abate and certify,” said Philip Father, chief executive officer of Scepter. “This approach is rooted in our mission of providing comprehensive observations on a real-time basis and global scale, therefore meeting various environmental, social and governance reporting needs.”
When combined with ExxonMobil’s data from ground-based sensors and aerial surveys using advanced analytics, Scepter’s data platform allows the company to further establish information regarding its methane emissions performance on an unprecedented scale and quickly identify high-emitting sources. The data processing platform will enable the expansion of third-party certification and supplement methane emissions-reductions efforts.
ExxonMobil supports the development of satellite surveillance and is conducting field trials of emerging technologies. The company is also taking part in an industry study with the Collaboratory to Advance Methane Science to expand ongoing initiatives to identify smarter and faster ways to detect and mitigate emissions using satellites.
The company recently announced plans to achieve net zero greenhouse gas emissions from its operated assets in the U.S. Permian Basin by 2030. These efforts include several key focus areas including continued investments in methane monitoring and detection technologies and eliminating routine flaring in the company’s Permian Basin operations by year-end 2022, in support of the World Bank’s Zero Routine Flaring initiative.
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About ExxonMobil
ExxonMobil, one of the largest publicly traded international energy companies, uses technology and innovation to help meet the world’s growing energy needs. ExxonMobil holds an industry-leading inventory of resources, is one of the largest refiners and marketers of petroleum products, and its chemical company is one of the largest in the world. To learn more, visit exxonmobil.com and the Energy Factor.
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About Scepter, Inc.
Scepter has developed, and internationally patented, a ground-breaking approach to monitoring the atmosphere in real-time using an array of terrestrial, airborne and Low Earth Orbit satellite-based sensors to provide actionable information for businesses, consumers, governments and NGOs. These capabilities are not only critical for solving the global pollution and climate change crises, but also provide the platform for an emerging multibillion-dollar commercial atmospheric monitoring industry to meet environmental ESG reporting needs. To learn more, visit ScepterAir.com.
HOUSTON- -ExxonMobil Upstream Research Company has awarded Delta Screens & Filtration LLC a limited international license to ExxonMobil’s Alternate Path technology patent portfolio for gravel packing cased and openhole completion wells.
Alternate Path is a patented technology developed by ExxonMobil to improve the reliability of wells completed in sand-prone reservoirs. The technology provides alternate flow paths called shunt tubes in the downhole tool used for packing gravel in the producing sections of a well. The shunt tubes enable the Alternate Path packing operation to continue when sand prematurely blocks the well annulus, which would stop a conventional packing operation. The shunt tubes divert the gravel slurry around sand blockages and through distributed portholes to fill voids in the annulus until a complete pack is in place.
“Alternate Path technology is one of several sand control completion technologies developed by ExxonMobil to improve reliability of sand-prone production wells,” said Sara N. Ortwein, president of ExxonMobil Upstream Research Company. “When the geology and the economics of a development call for openhole completions, Alternate Path technology is the technique preferred by ExxonMobil.”
The Alternate Path license allows Delta Screens to produce and deploy Alternate Path technology for ExxonMobil affiliates around the world and for ventures in which ExxonMobil participates.
“Alternate Path technology gives us a more reliable way to gravel pack wells where we need sand control,” said Delta Screens President, Richard Grifno. “Alternate Path is field proven and we’re very pleased to be approved as a licensee for ExxonMobil.”
About ExxonMobil Upstream Research Company
ExxonMobil Upstream Research Company is the Upstream research affiliate of Exxon Mobil Corporation (NYSE:XOM), a leading global oil, natural gas, and petrochemicals company with operations in nearly 200 countries and territories worldwide. ExxonMobil Upstream Research Company is charged with developing an industry-leading array of proprietary technologies that support the Corporation’s continued leadership position in exploration, development, production and gas commercialization.
About Delta Screen & Filtration LLC
Headquartered in Houston, Texas, Delta Screen & Filtration, LLC (dba Delta Screens) is a world-leading manufacturer of sand control screens for oil and gas production. Delta Screens offers a comprehensive selection of custom and standardized screens to reliably address virtually any sand control challenge.
HOUSTON–(BUSINESS WIRE)–ExxonMobil Upstream Research Company has awarded the first commercial license for its innovative InteliRed™ remote gas detection system to co-developer Providence Photonics, LLC.
The InteliRed system is designed to improve process safety and environmental performance at oil refineries, chemical plants, liquefied natural gas (LNG) facilities and other gas processing facilities. This new, state-of-the-art system employs a specially developed computer algorithm to autonomously analyze infrared camera images to detect escaping hydrocarbon gases. The InteliRed system provides an early warning alert of hydrocarbon leaks with minimal false alarms.
Providence Photonics, LLC is an affiliate of Providence Engineering headquartered in Baton Rouge, La. ExxonMobil and Providence scientists co-developed the InteliRed system over a four-year period culminating in field tests of the system that began last year at an LNG liquefaction plant in Qatar.
“The InteliRed system is the latest example of ExxonMobil’s continuous focus on process safety and environmental protection,” said Sara N. Ortwein, president of ExxonMobil Upstream Research Company. “Our collaboration with the imaging experts at Providence Photonics has resulted in a remote gas detection system that is very accurate and, with its robust design, is capable of operating in the harsh environments of many different oil and gas processing facilities around the world.”
“This system automatically and relentlessly scans for hydrocarbon gas leaks from process equipment and notifies operators to take action before the leak can become a hazard,” said Yousheng Zeng, Providence managing partner. “Our global license from ExxonMobil enables Providence to bring this unique process safety technology to our customers around the world.”
This Press Release is courtesy of www.exxonmobil.com
DOHA, Qatar -ExxonMobil Research Qatar (EMRQ) today announced that ExxonMobil has awarded a global commercial license for Immersive 3D Operator Training Simulator technology to co-developer EON Reality Inc.
The innovative technology incorporates ultra-realistic, multi-angle immersive virtual reality for training process operators and engineers in oil and gas production, processing and transportation facilities. The technology enables effective training to take place in a safe and controlled environment.
The new technology also supports the development of simulators that combine dynamic process training and fully functional 3D models. These complex models include interactive 3D objects such as rotating valves, push-buttons and active gauges; natural gestures and voice commands; and enhanced 4D sensory conditions including tactile feedback, odors, vibration and wind simulation.
The dynamic process simulator uses actual plant operating conditions to create realistic training scenarios for critical procedure execution, upset condition training, and emergency response training. Scenarios also can be created for workforce development, competency assurance, project commissioning support, new hire orientation, and more efficient turnaround/shutdown planning.
A full-scale simulator of an actual gas processing facility in Qatar has been operational since 2013, providing realistic training on more than 300 interactive control devices in six gas processing units.
“The Immersive 3D Operator Training Simulator provides a realistic 3D virtual environment that is a very close replica of an operating plant,” said Sara Ortwein, president of ExxonMobil Upstream Research Company. “These simulators are highly effective in training workers on how to prevent incidents, while teaching them to respond quickly and appropriately should any occur. This technology, developed in cooperation with EON Reality, is another example of how ExxonMobil continues to support research and safety, health and environmental protection across its global operations.”
“The Immersive 3D Operator Training Simulator will change how operators and plant crews train on existing facilities and even before a facility is operational,” said Mats W. Johansson, CEO of EON Reality. “Working with ExxonMobil, we have created an immersive training tool to ensure that entire plant operation teams have practiced actual procedures together on a virtual facsimile of their plant. This truly is a flight simulator for plant operations.”
The Immersive 3D Operator Training Simulator technology is the latest demonstration of how scientists and researchers at EMRQ are committed to helping Qatar and other global ExxonMobil partners supply the world with much needed energy, while improving environmental and operational performance of production facilities.
EMRQ opened its facility at Qatar Science & Technology Park in 2009 to conduct research in areas of common interest to the State of Qatar and ExxonMobil. Scientists and researchers at EMRQ continue to advance projects in the areas of environmental management, water reuse, LNG safety and coastal geology.
About ExxonMobil Research Qatar
ExxonMobil established ExxonMobil Research Qatar (EMRQ) as an anchor tenant at Qatar Science & Technology Park (QSTP) in Education City, Qatar. ExxonMobil Qatar Inc. is a subsidiary of Exxon Mobil Corporation and is the interface point within Qatar for all ExxonMobil affiliated activities. To learn more, visit exxonmobil.com.qa or www.إكسون-موبيل-قطر.com.
About ExxonMobil
ExxonMobil, the largest publicly traded international oil and gas company, uses technology and innovation to help meet the world’s growing energy needs. ExxonMobil holds an industry-leading inventory of resources, is the largest refiner and marketer of petroleum products, and its chemical company is one of the largest in the world. The term “ExxonMobil” is used for convenience and may include Exxon Mobil Corporation (NYSE:XOM) or any affiliates it directly or indirectly stewards.
About EON Reality
EON Reality, Inc. is the world leader in Virtual Reality based knowledge transfer for industry, education, and edutainment. EON Reality provides state-of-the-art 3D display technology for immersive and stereoscopic viewing, from portable tablet PCs and glass free stereo display systems to curved-screen and immersive rooms consisting of multi-channel projection walls. The technology foundation for developing interactive digital content includes importing the most common 3D animation formats into EON’s authoring software and creating modules and applications that can be viewed on various display systems. EON’s technology solutions enable all organizations to more effectively visually communicate, collaborate and accelerate knowledge transfer. For further information, visit www.eonreality.com.
IRVING, Texas–ExxonMobil said today that it has begun drilling the Haimara-1 exploration well offshore Guyana, the first of two planned wells in January. The Stena Carron drillship is drilling the well, which is located 19 miles (31 kilometers) east of the Pluma-1 discovery in the southeast Stabroek Block.
The Noble Tom Madden drillship is expected to drill the second well, Tilapia-1, about three miles (five kilometers) west of the Longtail-1 discovery. The Tilapia-1 well is located in the growing Turbot area.
“We continue to prioritize high-potential prospects in close proximity to previous discoveries in order to establish opportunities for material and efficient development,” said Steve Greenlee, president of ExxonMobil Exploration Company. “Like the Liza and Payara areas, the Turbot area is on its way to offering significant development options that will maximize value for Guyana and our partners.”
ExxonMobil is progressing the Liza Phase 1 development, which has moved into its peak execution phase ahead of expected startup in early 2020. Drilling of development wells in the Liza field is continuing using the Noble Bob Douglas drillship, subsea equipment is being prepared for installation, and the topside facilities modules are being installed on the Liza Destiny floating, production, storage and offloading (FPSO) vessel in Singapore.
Preparations are underway for the commencement of pipe-laying activities in the Liza field in the spring. The Liza Destiny FPSO is expected to sail from Singapore to arrive offshore Guyana in the third quarter of 2019.
The potential exists for at least five FPSOs on the Stabroek Block producing more than 750,000 barrels of oil per day by 2025. Liza Phase 2 is expected to start up by mid-2022. Pending government and regulatory approvals, project sanction is expected first quarter 2019 and will use a second FPSO designed to produce up to 220,000 barrels per day. Sanctioning of a third development, Payara, is also expected in 2019 with start up as early as 2023.
ExxonMobil also plans to deploy a seismic vessel operated by Petroleum Geo-Services (PGS) to the Turbot area to acquire 4-D seismic data similar to a 4-D campaign conducted in the Liza area in 2017. A second PGS vessel has been released after seismic acquisition activities were suspended on Dec. 22 when vessels were approached by the Venezuelan navy in the northwest portion of the Stabroek Block.
Drilling and development operations offshore Guyana are unaffected by the incident, which occurred more than 110 kilometers from the Ranger discovery, the closest of 10 discoveries made by ExxonMobil in the southeast section of the Stabroek Block.
ExxonMobil operates the Stabroek Block offshore Guyana under license from the government of Guyana. The acquisition of seismic data was being conducted under license from the government of Guyana in the country’s exclusive economic zone. ExxonMobil is evaluating next steps for the seismic program.
Throughout its activities, ExxonMobil continues to emphasize and promote direct benefit to local business. More than 50 percent of the Guyana affiliate’s employees, contractors and subcontractors are Guyanese, a number that will continue to grow as operations progress. ExxonMobil, its partners and its contractors spent about US$65 million with more than 300 local suppliers during the first three quarters of 2018. The Centre for Local Business Development, established by ExxonMobil in 2017 to promote the establishment and growth of small- and medium-sized local businesses, continues to enable access to training and capacity-building. More than 1300 local businesses have registered with the centre.
ExxonMobil affiliate Esso Exploration and Production Guyana Limited is operator and holds 45 percent interest in the Stabroek Block. Hess Guyana Exploration Ltd. holds 30 percent interest and CNOOC Nexen Petroleum Guyana Limited holds 25 percent interest.
About ExxonMobil
ExxonMobil, the largest publicly traded international energy company, uses technology and innovation to help meet the world’s growing energy needs. ExxonMobil holds an industry-leading inventory of resources, is one of the largest refiners and marketers of petroleum products, and its chemical company is one of the largest in the world. For more information, visit www.exxonmobil.com or follow us on Twitter www.twitter.com/exxonmobil.
HOUSTON –ExxonMobil Chemical Company announced today that it has started construction of a multi-billion dollar ethane cracker at its Baytown, Texas, complex and associated premium product facilities in nearby Mont Belvieu. This project, and major investments ExxonMobil has made to develop oil and natural gas resources in the United States, including the merger with XTO Energy, demonstrates the company’s continuing commitment to American economic growth and job creation.
The steam cracker will have a capacity of up to 1.5 million tons per year and provide ethylene feedstock for downstream chemical processing, including processing at two new 650,000 tons per year high performance polyethylene lines at the company’s Mont Belvieu plastics plant.
“The project is made possible in large part by abundant, affordable supplies of U.S. natural gas for energy and chemical feedstock,” said Steve Pryor, president of ExxonMobil Chemical Company. The chemical industry and other industrial sectors account for nearly 30 percent of U.S. natural gas demand. “Shale development has provided U.S. chemical producers a double benefit as an energy source and as a key raw material to make plastics and other essential products, creating jobs and economic activity across the value chain.”
The project will employ about 10,000 construction workers, create 4,000 related jobs in nearby Houston communities and add 350 permanent positions at the Baytown complex. It is expected to increase regional economic activity by roughly $870 million per year and generate more than $90 million per year in additional tax revenues for local communities.
Contracts have been awarded for construction, which will begin immediately. Contracts have been awarded to Linde Engineering North America, Inc. and Bechtel Oil, Gas, and Chemicals, Inc. to build olefins recovery units at the ExxonMobil Baytown Olefins Plant. Mitsui Engineering & Shipbuilding Co, Ltd. and Huertey Petrochem S.A. will construct the new olefins furnaces. At the Mont Belvieu Plastics Plant, Mitsubishi Heavy Industries will construct two 650,000 tons-per-year high-performance polyethylene lines. Jacobs Engineering, Ltd. will oversee enabling works and interconnections at both locations. Dashiell Corporation and Wood Group Mustang will provide specialty contracting services.
The expansion, coupled with ExxonMobil’s global sales and technology support network, enables ExxonMobil Chemical to economically supply a rapidly growing demand for high-value polyethylene products. These premium products deliver sustainability benefits such as lighter packaging weight, lower energy consumption, and reduced emissions. ExxonMobil Chemical estimates exports could increase significantly as a result of the expansion. Production of these high-quality petrochemical products used in a wide range of consumer and industrial applications is expected to start in 2017.
“This expansion will provide many great opportunities for workers with technical skills who are interested in energy and chemical manufacturing. These are high-paying jobs that lead to fulfilling and rewarding careers in an industry that’s vital to the American economy,” Pryor said. The average annual wage in the Texas chemical industry is about $100,000.
To support the project’s need for skilled workers, ExxonMobil has committed $1 million to the Community College Petrochemical Initiative, a training program offered by nine Houston-area community colleges to provide technical skills to high school graduates, returning military veterans and others. The program has earned state and federal recognition for recruiting and training instrument technicians, welders, pipefitters and other skilled employees for the chemical industry. This program will involve 50,000 students and educators over the next five years.
For more information about the project or to learn more about a career in the industry, visit www.HoustonNaturalGas.com or www.gulfcoastcc.org. Prospective students may apply online or enroll at the campus of their choice for classroom instruction, dual-credit courses, internships, certificate programs and two-year degrees.
About ExxonMobil
ExxonMobil, the largest publicly traded international oil and gas company, uses technology and innovation to help meet the world’s growing energy needs. ExxonMobil holds an industry-leading inventory of resources, is the largest refiner and marketer of petroleum products, and its chemical company is one of the largest in the world. Follow ExxonMobil on Twitter at www.twitter.com/exxonmobil.
– See more at: http://news.exxonmobil.com/press-release/exxonmobil-chemical-company-begins-multi-billion-dollar-expansion-project-baytown-texa#sthash.rieBBGt6.dpuf
IRVING, Texas –ExxonMobil today released a report that outlines for shareholders how the company assesses and manages risks associated with developing unconventional resources, including through hydraulic fracturing.
“Hydraulic fracturing has been responsibly and safely used by the oil and gas industry for more than 60 years, but the process isn’t without risks,” said Jeffrey Woodbury, vice president of Investor Relations. “This report to shareholders details how ExxonMobil uses sound risk management processes and engages with stakeholders to ensure safe and environmentally responsible operations.”
Unconventional natural gas and oil development in the United States has resulted in widespread benefits, including significant job creation, reduced carbon dioxide emissions, lower energy costs, new sources of government revenue and improved energy security. The report highlights numerous studies that support these trends.
The report presents information on how the application of sound risk management practices that protect human health and the environment can be deployed to continue supporting the significant benefits of resource development.
Release of the report is part of an ongoing dialogue between ExxonMobil and its shareholders about important matters. The report to shareholders is available at www.exxonmobil.com/hfreport. Additional information about unconventional resources development and hydraulic fracturing can be found in ExxonMobil’s Outlook for Energy and Corporate Citizenship Report on ExxonMobil’s website www.exxonmobil.com.
Cautionary Statement: Statements of future events or conditions discussed in The Outlook or this release are forward-looking statements. Actual future conditions (including economic conditions, energy demand, international trade flows, energy supply sources, impacts of new technology, and efficiency gains) could differ materially due to changes in law or government regulation and other political events; changes in technology; the development of new supply sources; demographic changes; and other factors discussed in The Outlook and under the heading “Factors Affecting Future Results” on the Investors page of our website at www.exxonmobil.com. See also Item 1A of ExxonMobil’s latest Form 10-K.
About ExxonMobil
ExxonMobil, the largest publicly traded international oil and gas company, uses technology and innovation to help meet the world’s growing energy needs. ExxonMobil holds an industry-leading inventory of resources, is the largest refiner and marketer of petroleum products, and its chemical company is one of the largest in the world. Follow ExxonMobil on Twitter at www.twitter.com/exxonmobil.
IRVING, Texas — ExxonMobil is looking to significantly reduce spending as a result of market conditions caused by the COVID-19 pandemic and commodity price decreases, the company said today.
ExxonMobil evaluating significant near-term capital and operating expense reductions
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“Based on this unprecedented environment, we are evaluating all appropriate steps to significantly reduce capital and operating expenses in the near term,” said Darren Woods, chairman and chief executive officer of Exxon Mobil Corporation. “We will outline plans when they are finalized.”
Woods said that ExxonMobil has faced numerous market downturns throughout its long history and has experience operating in a sustained low-price environment. “We remain focused on being a safe, low-cost operator and creating long-term value for shareholders,” said Woods.
The company is closely monitoring the COVID-19 pandemic and has adjusted work arrangements to ensure a healthy work environment and support communities where we operate.
Woods stressed the company will maintain its ongoing commitment to safety and environmental performance.
“We are confident that we will manage through these challenging times by taking deliberate action to keep our people safe, our environment protected and our company strong,” said Woods.
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About ExxonMobil
ExxonMobil, one of the largest publicly traded international energy companies, uses technology and innovation to help meet the world’s growing energy needs. ExxonMobil holds an industry-leading inventory of resources, is one of the largest refiners and marketers of petroleum products, and its chemical company is one of the largest in the world. To learn more, visit exxonmobil.com and the Energy Factor.
Follow us on Twitter and LinkedIn.
IRVING, Texas & GEORGETOWN, Guyana–ExxonMobil Foundation said today that it will contribute US$10 million to a new collaboration with Conservation International and the University of Guyana to train Guyanese for sustainable job opportunities and to expand community-supported conservation.
The investment is also intended to support Guyana’s Green State Development Plan, the country’s 15-year development plan that aims, among other things, to diversify Guyana’s economy and balance economic growth with the sustainable management and conservation of the country’s ecosystems. The ExxonMobil Foundation will provide the investment over five years.
Initial grant money will fund a feasibility study driven by Conservation International, through its affiliate, Conservation International Guyana, to further define the details of the program. Once defined, Conservation International Guyana and the University of Guyana will deliver the education, training, research and retention programs that will help ensure that economic growth reinforces Guyana’s environmental development goals.
The investment is also intended to expand conservation areas in the Rupununi Wetlands, aid mangrove restoration and management and support improvements to community-based fishing on Guyana’s coast, a sector the government of Guyana has identified as critically important to the wellbeing of the Guyanese people, and support the work of the University of Guyana’s Greening Research and Innovation Centres.
“This partnership will support the highest conservation priorities for the country as well as education and training for sustainable employment,” said Kevin Murphy, president of the ExxonMobil Foundation. “It reinforces the government’s objectives as outlined in its Green State Development Strategy and demonstrates the value we place on our long-term relationship with the citizens of Guyana.”
“Guyana stands at a critical crossroads in its development,” said Jennifer Morris, president of Conservation International. “By investing in both people and nature, this partnership will play an important part in helping Guyana execute its vision for a green future.”
“A central feature of Guyana’s development plans is its Green State Development Strategy which envisions a commitment to a green economy, sustainable development and protection of its forests and fresh water resources aligned with the UN’s 2030 Sustainable Development Goals,” said Professor Nigel E. Harris, chairman of the University of Guyana Council. “Funding support for a collaborative effort between Guyana’s leading university, Conservation International and ExxonMobil Foundation promises a critical opportunity to build relevant teaching, research and outreach capacity at our university that is necessary to underpin Guyana’s 2030 Vision for an inclusive, green and prosperous state.”
At this stage, Conservation International anticipates that training will be focused on environmental innovation and sustainability, and on entrepreneurship in nature-based sectors. Conservation International will tap its partnerships with key international universities such as Arizona State University in the United States to help develop the programs.
Conservation International is the grantee and the University of Guyana a key beneficiary. Conservation International, with over 20 years’ experience in Guyana, will take the lead in managing project objectives and implementation, including success measures as well as financial and reporting requirements of this multi-year partnership. Conservation International has been working in Guyana with over 50 communities to protect nearly 3 million acres of indigenous lands while also improving livelihoods.
ExxonMobil is placing an emphasis on supporting local priorities, including business and employment opportunities as well as broader community programs in Guyana. The company has spent about US$39 million with local suppliers in Guyana through 2017 and first quarter 2018. Approximately 68 percent of ExxonMobil’s current in-country employees are Guyanese.
About the ExxonMobil Foundation
The ExxonMobil Foundation is the primary philanthropic arm of Exxon Mobil Corporation (NYSE:XOM) in the United States. The foundation and the corporation engage in a range of philanthropic activities that advance education, with a focus on math and science in the United States, promote women as catalysts for economic development and combat malaria. In 2017, the ExxonMobil Foundation, together with Exxon Mobil Corporation, its divisions and affiliates along with employees and retirees, provided $204 million in contributions worldwide.
About ExxonMobil
ExxonMobil, the largest publicly traded international energy company, uses technology and innovation to help meet the world’s growing energy needs. ExxonMobil is a global leader in LNG project execution and holds an industry-leading inventory of resources, is one of the largest refiners and marketers of petroleum products, and its chemical company is one of the largest in the world. For more information, visit www.exxonmobil.com or follow us on Twitter www.twitter.com/exxonmobil. Esso Exploration and Production Guyana Limited is the affiliate in Guyana.
About Conservation International
Conservation International uses science, policy and partnerships to protect the nature that people rely on for food, fresh water and livelihoods. Founded in 1987, Conservation International works in more than 30 countries on six continents to ensure a healthy, prosperous planet that supports us all. Learn more about Conservation International, the groundbreaking “Nature Is Speaking” campaign and its series of virtual reality projects: “My Africa”, “Under the Canopy” and “ Valen’s Reef ”. Follow Conservation International’s work on our Human Nature blog, Facebook, Twitter, Instagram and YouTube.
About University of Guyana
The University of Guyana (UG) was established by act of parliament in 1963. It is the country’s leading tertiary institution and Guyana’s only national university. With a current enrollment of some 8,000 students, UG has graduated more than 40,000 students who have gone on to successful careers locally, regionally and internationally. Over 65 percent of its graduates are absorbed in the local workforce. The university is also a major contributor to the national economy and to business and industry. UG expanded in 2000 with the addition of the Tain Campus. It now offers more than 90 undergraduate and post-graduate programs including engineering, environmental studies, forestry, urban planning and management, tourism studies, education, creative arts, economics, law, medicine, optometry and nursing. Several online programs are available and UG also offers extra-mural classes at four locations across Guyana through its Institute of Distance and Continuing Education. UG also offers the opportunity for student engagement in debating, sports, and cultural, religious and professional activities. Visit www.uog.edu.gy.
RVING, Texas–Darren W. Woods, chairman and chief executive officer of Exxon Mobil Corporation (NYSE:XOM), today presented a $50,000 gift to Promise House to assist in its mission of providing critical services to homeless children and teens in Dallas, Texas.
Established in 1984, Promise House combats youth homelessness with unique programs that address the needs of homeless, runaway and at-risk youth. The organization provides residential services, including emergency shelter and long-term housing to youth in need. Promise House programs develop critical life skills, personal responsibility and financial independence, as well as offer a broad continuum of health, education and counseling services.
Through its community outreach initiatives, Promise House partners with physical and mental health care providers, state and local agencies and schools to offer a range of services to non-residential clients in crisis. Support includes food kits, community counseling, parent education classes and case management.
“More than 1,200 Dallas-area youth do not have a bed to sleep in each night,” Woods said. “Promise House helps the most vulnerable people in our community and guides them toward a brighter, more promising future. We are proud to support them with this year’s gift.”
“For years, ExxonMobil has been a dedicated partner in our mission to end youth homelessness in North Texas,” said Dr. Ashley Lind, chief executive officer of Promise House. “This gift will help us provide hot meals, safe shelter, counseling, education services and much more to our city’s most vulnerable young people. ExxonMobil’s support will be critical as we expand to meet the needs of a growing number of homeless children and teens in our community.”
Created by ExxonMobil in 2006, the annual holiday gift supports a North Texas nonprofit in continuing their important work. Recent grant recipients include The Gatehouse, Jonathan’s Place, ACH Child and Family Services, Grapevine Relief and Community Exchange and Interfaith Housing Coalition.
About ExxonMobil
ExxonMobil, the largest publicly traded international energy company, uses technology and innovation to help meet the world’s growing energy needs. ExxonMobil engages in a range of philanthropic activities that advance education, with a focus on math and science in the United States, promote women as catalysts for economic development, and combat malaria. In 2016, together with its employees and retirees, ExxonMobil, its divisions and affiliates, and the ExxonMobil Foundation provided $242 million in contributions worldwide. Additional information on ExxonMobil’s community partnerships and contribution programs is available at www.exxonmobil.com/community.
About Promise House
Promise House is leading the charge to end youth homelessness in North Texas. Our free programs include lifesaving emergency shelter, transitional housing, pregnant and parenting teen support, counseling, education and outreach services. Since 1984, Promise House has had an open door – 24 hours a day, 365 days a year – to children, teens and families in crisis, serving approximately 1,700 youth and families annually. By improving each client’s chances for long-term stability, Promise House works to prevent chronic homelessness in North Texas.
IRVING, Texas-Exxon Mobil Corporation (NYSE:XOM) today announced enhancements to its U.S. oil and natural gas portfolio managed by subsidiary, XTO Energy Inc., through separate agreements in the Permian Basin in Texas and Utica shale in Ohio.
“These transactions underscore our commitment to developing high-margin liquids growth in areas such as the Permian, while also efficiently funding development of our extensive domestic natural gas resource in emerging plays such as the Utica,” said Randy Cleveland, president of XTO Energy Inc.
Through an agreement with Endeavor Energy Resources, L.P., XTO will fund development to gain substantial operating equity in approximately 34,000 gross acres in the prolific liquids-rich Wolfcamp formation in Midland and Upton counties. Endeavor will continue to operate shallow production while XTO will drill and operate horizontal wells in the deeper intervals.
The agreement increases XTO’s holdings in the Permian Basin to just over 1.5 million net acres, enhancing the company’s significant presence in one of the major U.S. growth areas for onshore oil production.
“The Wolfcamp shale is a vast, tight oil resource with tremendous potential,” said Cleveland. “The presence of multiple, stacked pay zones creates the potential for capital-efficient horizontal development, and the proximity to XTO’s ongoing Wolfcamp operations will offer operating cost efficiencies.”
In a separate transaction involving its holdings in the Utica shale, XTO signed an agreement with American Energy – Utica, LLC (AEU) following a competitive bid process. The agreement will enable AEU to earn approximately 30,000 net acres of XTO’s Ohio leasehold in Harrison, Jefferson and Belmont counties. XTO will continue to operate in a core area of approximately 55,000 net acres, optimizing development by using proceeds from the transaction to fund 100 percent of near-term development costs.
“We just initiated development in the Utica and are encouraged by results from our initial well that is producing at a peak 30-day rate of about 15 million cubic feet of dry gas per day,” Cleveland said. “The agreement funds near-term development of a substantial operating position in this emerging play.”
XTO grew its production in the Appalachia region by almost 30 percent in 2013, and maintains a strong presence with about 645,000 acres in the Marcellus and Utica shale plays.
XTO manages a portfolio that has tripled in size since 2009 when the merger with ExxonMobil was announced.
This Press Release is courtesy of www.exxonmobil.com
IRVING, Texas – ExxonMobil said today that it has made a final investment decision on a multi-billion dollar expansion of its integrated manufacturing complex in Singapore to convert fuel oil and other bottom-of-the-barrel crude products into higher-value lube base stocks and distillates.
The expansion project uses proprietary technologies to increase yields of higher-value products
Integrated downstream and chemical investment enhances site competitiveness
Construction to begin in second half of 2019, startup anticipated in 2023
The expansion project is part of the company’s plan to further enhance the competitiveness of the Singapore facility, which includes the world’s only steam cracker capable of cracking crude oil. The project, which leverages proprietary technologies, integration and scale, will significantly increase site downstream and chemical earnings potential. Engineering, procurement and construction activities have begun, and startup is anticipated in 2023.
“The demand for high-quality fuels and lubricants will increase as the global economy expands,” said Bryan Milton, president of ExxonMobil Fuels & Lubricants Company. “By using a combination of proprietary catalyst and process technologies, we will increase the site’s competitiveness and help meet growing demand for high-performance lubricants and cleaner fuels.”
The investment will add 20,000 barrels per day of ExxonMobil Group II base stocks capacity, which includes EHCTM 50 and EHCTM 120 grades, in addition to a new high-viscosity Group II base stock to meet increasing demand in the Asia-Pacific region.
“The project also applies new chemicals technologies and leverages integration across the crude cracker and refining complex to further enhance the competitiveness of crude cracking,” said Karen McKee, president of ExxonMobil Chemical Company.
The expansion will add the capacity to increase production of cleaner fuels with lower-sulfur content by 48,000 barrels per day, including high-quality ExxonMobil Marine fuels to enable customers to meet the International Maritime Organization’s 0.50 percent sulfur requirement.
The project represents the latest and most significant in a series of recent ExxonMobil investments in base stock production. Recent ExxonMobil EHCTM Group II base stock investments include a 2015 expansion in Singapore and the startup of a world-scale, enhanced hydrocracker unit in Rotterdam in 2018.
Exxon Mobil Corporation
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Engineering, procurement and construction contracts have been awarded to Técnicas Reunidas for the new process units, and Wood Group for interconnecting pipelines and supporting infrastructure facilities. As part of the project, ExxonMobil is working on a long-term commercial agreement with Linde to upgrade residue from the site to hydrogen and synthesis gas.
About ExxonMobil
ExxonMobil, the largest publicly traded international oil and gas company, uses technology and innovation to help meet the world’s growing energy needs. ExxonMobil holds an industry-leading inventory of resources, is one of the largest refiners and marketers of petroleum products, and its chemical company is one of the largest in the world. For more information, visit www.exxonmobil.com or follow us on Twitter www.twitter.com/exxonmobil.
IRVING, Texas–Exxon Mobil Corporation (NYSE:XOM) said today it has made a final investment decision to proceed with the first phase of development for the Liza field, one of the largest oil discoveries of the past decade, located offshore Guyana.
The company also announced positive results from the Liza-4 well, which encountered more than 197 feet (60 meters) of high-quality, oil-bearing sandstone reservoirs, which will underpin a potential Liza Phase 2 development. Gross recoverable resources for the Stabroek block are now estimated at 2 billion to 2.5 billion oil-equivalent barrels, which includes Liza and other successful exploration wells on Liza Deep, Payara and Snoek.
The Liza Phase 1 development includes a subsea production system and a floating production, storage and offloading (FPSO) vessel designed to produce up to 120,000 barrels of oil per day. Production is expected to begin by 2020, less than five years after discovery of the field. Phase 1 is expected to cost just over $4.4 billion, which includes a lease capitalization cost of approximately $1.2 billion for the FPSO facility, and will develop approximately 450 million barrels of oil.
“We’re excited about the tremendous potential of the Liza field and accelerating first production through a phased development in this lower cost environment,” said Liam Mallon, president, ExxonMobil Development Company. “We will work closely with the government, our co-venturers and the Guyanese people in developing this world-class resource that will have long-term and meaningful benefits for the country and its citizens.”
The Liza Phase 1 development can provide significant benefits to Guyana, including jobs during installation and operations, workforce training, local supplier development and government revenues to fund infrastructure, social programs and services.
The development received regulatory approval from the government of Guyana.
The Liza field is approximately 190 kilometers offshore in water depths of 1,500 to 1,900 meters. Four drill centers are envisioned with a total of 17 wells, including eight production wells, six water injection wells and three gas injection wells.
The Liza field is part of the Stabroek Block, which measures 6.6 million acres, or 26,800 square kilometers. Esso Exploration and Production Guyana Limited is operator and holds a 45 percent interest in the block.
Hess Guyana Exploration Ltd. holds a 30 percent interest and CNOOC Nexen Petroleum Guyana Limited holds 25 percent.
Esso Exploration and Production Guyana Limited is continuing exploration activities and operates three blocks offshore Guyana – Stabroek, Canje and Kaieteur. Drilling of the Payara-2 well on the Stabroek block is expected to commence in late June and will also test a deeper prospect underlying the Payara oil discovery.
CAUTIONARY NOTE:
Statements that reference future events or conditions in this press release are forward-looking statements. Actual future results, including project plans, costs, and schedules, production rates, and resource recoveries may differ significantly from the forecasts, depending on changes in oil or gas prices and other market or economic factors that affect the petroleum industry; the outcome of development programs; reservoir performance; unexpected technical difficulties or other technical or operating factors; the actions of governmental authorities or regulatory agencies; and other factors listed under the heading “Factors Affecting Future Results” on the Investor page at the ExxonMobil website at www.exxonmobil.com and in Item 1A of ExxonMobil’s most recent Form 10-K. References to barrels of oil and other quantities of oil or gas in this release include volumes that are not yet classified as proved reserves under SEC definitions, but that we believe will ultimately be produced.
About ExxonMobil
ExxonMobil, the largest publicly traded international oil and gas company, uses technology and innovation to help meet the world’s growing energy needs. ExxonMobil holds an industry-leading inventory of resources, is the largest refiner and marketer of petroleum products, and its chemical company is one of the largest in the world. Follow ExxonMobil on Twitter at www.twitter.com/exxonmobil.
IRVING, Texas – ExxonMobil said today it has reconfigured manufacturing operations in Louisiana to produce medical-grade hand sanitizer for donation to COVID-19 response efforts in Louisiana, New Jersey, New Mexico, New York, Pennsylvania and Texas.
ExxonMobil modifies facilities to produce medical-grade sanitizer for COVID-19 response
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Product to be donated to health care providers and first responders across the United States
Equipment modified to enable Baton Rouge area facilities to produce, blend, package and distribute sanitizer
Targeting production of 160,000 gallons of sanitizer, enough for nearly 5 million bottles
Initial production of 160,000 gallons of medical grade sanitizer – enough to fill nearly 5 million 4-ounce bottles – is being distributed to medical providers and first responders. Additional donation locations are planned.
“The ingenuity and dedication of our employees to develop a consumer-ready product in record time demonstrates ExxonMobil’s commitment to help those in need during the global pandemic,” said Darren Woods, chairman and chief executive officer of Exxon Mobil Corporation. “We’re focused on keeping our people and communities safe while supporting frontline responders and meeting customer needs.”
ExxonMobil has increased monthly production of isopropyl alcohol — a key ingredient in sanitizer – by about 3,000 tonnes at its chemical manufacturing facility in Baton Rouge, Louisiana. To produce, package and distribute hand sanitizer, the company purchased additional ingredients and modified equipment in Baton Rouge and at a lubricants plant in nearby Port Allen, Louisiana.
“To stand up an entirely new process and supply chain in a matter of weeks, while maintaining ExxonMobil’s high standards for safety and quality and in compliance with FDA requirements is truly remarkable,” said Karen McKee, president of ExxonMobil Chemical Company.
Earlier this month, ExxonMobil announced the increased production of isopropyl alcohol, which is enough to enable monthly production of up to 50 million 4-ounce bottles of sanitizer. The company also increased its capability to manufacture specialized polypropylene, used in medical masks and gowns, by about 1,000 tonnes per month, which is enough to enable production of up to 200 million medical masks or 20 million gowns.
ExxonMobil is also participating in a technology collaboration with the Global Center for Medical Innovation to rapidly redesign and manufacture reusable personal protection equipment, such as medical face shields and masks.
About ExxonMobil
ExxonMobil, one of the largest publicly traded international energy companies, uses technology and innovation to help meet the world’s growing energy needs. ExxonMobil holds an industry-leading inventory of resources, is one of the largest refiners and marketers of petroleum products, and its chemical company is one of the largest in the world. To learn more, visit exxonmobil.com and the Energy Factor.
IRVING, Texas–ExxonMobil has been named 2017 Explorer of the Year by the World Oil and Gas Council in recognition of excellence and innovation in the global energy industry.
“This award is recognition of ExxonMobil’s successful efforts to strengthen our portfolio by accessing and discovering the highest quality resources,” said Steve Greenlee, president of ExxonMobil Exploration Company. “This recognition would not be possible without the dedication of our employees and their daily commitment to safety and operational excellence at every stage of exploration.”
During the year, ExxonMobil announced a number of discoveries, acquisitions and other activities in various countries, including Brazil, Cyprus, Equatorial Guinea, Guyana, Mauritania, Papua New Guinea and Suriname.
Significant exploration activity took place offshore Guyana, where ExxonMobil announced four discoveries in 2017 at Payara, Liza Deep, Snoek, and Turbot. These four discoveries added to the earlier Liza discovery, made in 2015.
Mike Cousins, executive vice president of ExxonMobil Exploration Company, accepted the award on behalf of ExxonMobil at an award dinner in London in December. He was accompanied by a number of company representatives, including Kerry Moreland, Guyana Basin exploration manager.
“Guyana has become an exciting exploration area where we have consistently demonstrated our technical ability in deepwater exploration and operations,” said Moreland. “We are planning for continued success with our drilling program in 2018.”
Since receipt of the award in December 2017, ExxonMobil has announced a sixth discovery offshore Guyana at the Ranger-1 exploration well.
Other notable ExxonMobil exploration highlights throughout the year include:
Brazil
In September and October, the company added 14 blocks comprising more than 1.25 million net acres offshore Brazil through bid rounds and farm-in agreements, bringing its total acreage in the country to more than 1.4 million net acres. These included an agreement to purchase half of Statoil’s interest in an offshore block containing the Carcara field, estimated to contain a recoverable resource of two billion barrels of oil.
In December, ExxonMobil signed a memorandum of understanding with Petrobras to jointly identify and evaluate potential business opportunities.
Cyprus
In April, the company signed an exploration and production sharing contract for offshore Block 10.
Equatorial Guinea
In June, ExxonMobil signed a production sharing contract with the government of Equatorial Guinea for deepwater block EG-11.
Malaysia
In November, ExxonMobil signed production sharing contracts for acreage offshore Sabah, Malaysia.
Mauritania
In December, ExxonMobil signed production sharing contracts for three offshore blocks: C22, C17 and C14.
Papua New Guinea
In June, ExxonMobil announced positive production well tests results from the Muruk-1 sidetrack 3 well. ExxonMobil also drilled the P’nyang South-2 well, which successfully confirmed an extension to the earlier P’nyang discovery.
Across Papua New Guinea, ExxonMobil acquired an additional 5.7 million net acres of prospective acreage, onshore and offshore.
Suriname
In July, ExxonMobil signed a production sharing contract for Block 59 offshore Suriname in the Guyana-Suriname Basin.
United States – Gulf of Mexico
In March and August, ExxonMobil was awarded 25 blocks in the U.S. Gulf of Mexico lease sales.
About ExxonMobil
ExxonMobil, the largest publicly traded international energy company, uses technology and innovation to help meet the world’s growing energy needs. ExxonMobil holds an industry-leading inventory of resources, is one of the largest refiners and marketers of petroleum products, and its chemical company is one of the largest in the world. For more information, visit www.exxonmobil.com or follow us on Twitter www.twitter.com/exxonmobil.
IRVING, Texas–Exxon Mobil Corporation (NYSE:XOM) today announced the CLOV project in Angola started up on schedule and is expected to reach daily production capacity of 160,000 barrels in the coming months.
CLOV is the fourth major development hub of Total-operated Block 17, after Girassol, Dalia and Pazflor. An ExxonMobil affiliate has a 20 percent working interest in CLOV, which will produce oil from the four fields of Cravo, Lirio, Orquidea and Violeta at water depths ranging from 3,600 feet to 4,593 feet.
“Block 17, along with Esso Angola-operated Block 15, in which the company has a 40 percent working interest, are the most productive blocks in Angola,” said Neil Duffin, president of ExxonMobil Development Company.
CLOV, located 87 miles offshore Luanda, includes 34 wells and eight manifolds connected by 112 miles of subsea pipelines to a floating production storage and offloading vessel and crude oil offloading terminal.
The 1,000-foot-long, 197-foot-wide vessel can store up to 1.8 million barrels of oil. Natural gas produced at CLOV will be exported through a subsea pipeline to an Angola liquefied natural gas plant in Soyo.
CLOV produces two types of oil from the Miocene and Oligocene geological horizons. Miocene oil is more viscous than Oligocene oil and required a subsea multiphase pump system for transportation to boost co-mingled fluid and enhance oil recovery.
The project was completed with more than 10 million hours performed by a local workforce to complete fabrication and assembly of the storage and offloading vessel in Angola. The water treatment module, a critical component of the vessel, was built and installed in Angola, a first for the country. The project also provided training programs for local personnel and played a part in enhancing the country’s socio-economic development.
“CLOV is another indication of ExxonMobil’s commitment to Angola, where we have been involved for about 20 years,” Duffin said. “ExxonMobil continues to evaluate additional development opportunities in the country.”
Sonangol is the concessionaire for Block 17. Total has 40 percent interest, Statoil has 23.33 percent, and BP has 16.67 percent.
ExxonMobil affiliates’ Angola interests also include 15 percent of the Kaombo project, located in southeast area of Block 32, which launched development of six fields in April. Production in Block 15 from Kizomba Satellite Phase 1 started in 2012 and Phase 2 project development is underway with production startup targeted for 2015.
– See more at: http://news.exxonmobil.com/press-release/exxonmobil-oil-production-increase-time-startup-clov-project#sthash.0UuebHZy.dpuf
NEW YORK — ExxonMobil today outlined an aggressive growth strategy to more than double earnings and cash flow from operations by 2025 at today’s oil prices.
“We’ve got the best portfolio of high-quality, high-return investment opportunities that we’ve seen in two decades,” Darren W. Woods, chairman and chief executive officer, said at the company’s annual meeting of investment analysts at the New York Stock Exchange.
“Our plan takes full advantage of the company’s unique strengths and financial capabilities, using innovation, technology and integration to drive long-term shareholder value and industry-leading returns.”
Growth plans include steps to increase earnings by more than 100 percent – to $31 billion by 2025 at 2017 prices – from last year’s adjusted profit of $15 billion, which excluded the impact of U.S. tax reform and impairments.
Woods said this plan projects double-digit rates of return in all three segments of ExxonMobil’s business – upstream, downstream and chemical – which are all three world-class businesses in their own right.
In the upstream, the company expects to significantly increase earnings through a number of growth initiatives involving low-cost-of-supply investments in U.S. tight oil, deepwater and liquefied natural gas (LNG). Growth coming online from new and existing projects is expected to increase production from 4 million oil-equivalent barrels per day to about 5 million.
The company plans to increase tight-oil production five-fold from the U.S. Permian Basin and start up 25 projects worldwide. Those startups will add volumes of more than 1 million oil-equivalent barrels per day. In LNG, the company expects to bring on new production to meet a projected increase in global demand.
Upstream growth will benefit from ExxonMobil’s industry-leading exploration success and strategic acquisitions. In 2017 alone, the company added 10 billion oil-equivalent barrels to its resource base in locations including the Permian, Guyana, Mozambique, Papua New Guinea and Brazil.
Key drivers of growth are in Guyana, where exploration success has added 3.2 billion gross oil equivalent barrels of recoverable resource and plans are in place for development and further exploration, and in the Permian, where the company has increased the size of its resource to 9.5 billion oil-equivalent barrels from less than 3 billion in the past year.
Through its acquisition of several Bass entities in 2017, ExxonMobil added an estimated resource of 5.4 billion oil-equivalent barrels in the Permian. The original resource estimate of 3.4 billion barrels at the time of the purchase was increased through technical evaluation and successful delineation in the Delaware Basin, reducing the acquisition cost to just above $1 per oil-equivalent barrel.
The contiguous stacked pays from the New Mexico acquisition are now estimated to provide more than 4,800 drilling locations with an average lateral length of more than 12,000 feet, enabling capital-efficient execution of Permian volumes growth and the potential to further increase future volumes.
“We are in a solid position to maximize the value of the increased Permian production as it moves from the well head to our Gulf Coast refining and chemical operations, where we are focusing on manufacturing higher-demand, higher-value products,” Woods said.
ExxonMobil’s downstream business is projected to double earnings by 2025 by upgrading its product slate through strategic investments at refineries in Baytown and Beaumont in Texas and Baton Rouge, Louisiana, Rotterdam, Antwerp, Singapore, and Fawley in the U.K.
These projects are expected to result in double-digit returns by enabling increased production of higher-value products, such as ultra-low sulfur diesel, chemicals feedstocks and basestocks for lubricants. As a result of these improvements, the company’s 2025 downstream margins are projected to increase by 20 percent.
Expansion is supported by projected demand growth in emerging markets, and includes entries into new markets such as Mexico and Indonesia. It is supported by integration with chemical manufacturing and upstream production.
In its chemical business, ExxonMobil expects to grow manufacturing capacity in North America and Asia Pacific by about 40 percent. That growth will be achieved in part by adding 13 new facilities, including two world-class steam crackers in the United States. These investments would enable the company to meet increasing demand in Asia and other growing markets.
“We are uniquely positioned to take advantage of the global demand growth for higher-value products in the downstream and chemical,” Woods said. “Our combined strengths in innovative technology, resource and market access, marketing product leadership and integration improve profitability and create significant shareholder value.”
Woods said the company’s overall growth strategy is designed with a key goal in mind – fully leveraging our competitive advantages to grow shareholder value across all three of our world-class businesses. Through higher returns from increased investments, the company has the potential to increase its return on capital employed to about 15 percent by 2025.
“Our existing business and plans for growth are robust to a wide range of price environments, allowing us to maintain a growing dividend and a strong balance sheet while returning excess cash to our shareholders,” said Woods.
About ExxonMobil
ExxonMobil, the largest publicly traded international oil and gas company, uses technology and innovation to help meet the world’s growing energy needs. ExxonMobil holds an industry-leading inventory of resources, is one of the largest refiners and marketers of petroleum products and its chemical company is one of the largest in the world. For more information, visit www.exxonmobil.com or follow us on Twitter www.twitter.com/exxonmobil.
IRVING, Texas — Exxon Mobil Corporation has received notice of an unsolicited mini-tender offer by Ponos Industries LLC to purchase up to 1 million shares of ExxonMobil common stock, which represents approximately 0.024 percent of the shares outstanding as of the April 27, 2020 offer date.
ExxonMobil recommends shareholders reject below-market mini-tender offer by Ponos Industries LLC
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Ponos’ offer price of $48 per share is conditioned on the closing price per share exceeding $48 per share on the last day before the offer expires. This means that the offer will only be accepted if the offer is below market value.
ExxonMobil recommends that stockholders do not tender their shares in response to Ponos’ offer because the offer is at a price below a conditional market price for ExxonMobil’s shares and subject to numerous conditions. ExxonMobil is not affiliated or associated in any way with Ponos, its mini-tender offer or the offer documentation.
Ponos has made many similar mini-tender offers for shares of other companies. Mini-tender offers seek to acquire less than 5 percent of a company’s shares outstanding, thereby avoiding many disclosure and procedural requirements of the U.S. Securities and Exchange Commission (SEC) that apply to offers for more than 5 percent of a company’s shares outstanding. As a result, mini-tender offers do not provide investors with the same level of protections as provided by larger tender offers under U.S. securities laws.
The SEC has cautioned investors that some bidders making mini-tender offers at below-market prices are “hoping that they will catch investors off guard if the investors do not compare the offer price to the current market price.” More on the SEC’s guidance to investors on mini-tender offers is available at www.sec.gov/reportspubs/investor-publications/investorpubsminitendhtm.html.
ExxonMobil urges investors to obtain current market quotations for their shares, to consult with their broker or financial advisor and to exercise caution with respect to Ponos’ offer. ExxonMobil recommends that shareholders who have not responded to Ponos’ offer take no action. Shareholders who have already tendered their shares may withdraw them at any time prior to the expiration of the offer, in accordance with Ponos’ offering documents. The offer is currently scheduled to expire at 1 p.m. EST on Friday, Nov. 27, 2020. Ponos may extend the offering period at its discretion.
ExxonMobil encourages brokers and dealers, as well as other market participants, to review the SEC’s letter regarding broker-dealer mini-tender offer dissemination and disclosure at www.sec.gov/divisions/marketreg/minitenders/sia072401.htm.
ExxonMobil requests that a copy of this news release be included with all distributions of materials relating to Ponos’ mini-tender offer related to ExxonMobil shares of common stock.
About ExxonMobil
ExxonMobil, one of the largest publicly traded international energy companies, uses technology and innovation to help meet the world’s growing energy needs. ExxonMobil holds an industry-leading inventory of resources, is one of the largest refiners and marketers of petroleum products, and its chemical company is one of the largest in the world. To learn more, visit exxonmobil.com and the Energy Factor.
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The new, five-year agreement builds on ExxonMobil’s participation in Princeton’s E-filliates Partnership, which began in 2015. E-filliates is a corporate membership program administered by the Andlinger Center and aims to help accelerate research, development and deployment of energy and environmental technologies through academia and industry partnerships.
“We collaborate with leading universities and institutions around the world to find meaningful and scalable solutions to develop lower-emission technologies” said Vijay Swarup, vice president of research and development for ExxonMobil Research and Engineering Company. “Our work with Princeton University’s Andlinger Center builds on decades-long interactions with the university, supporting the essential research in science, engineering and humanities needed to address national and global issues.”
“Working with companies is a critical piece of translating fundamental knowledge and discoveries into real-world impact. We challenge ExxonMobil scientists to explore the fundamental scientific questions that underpin technology development in new ways, and they challenge our scientists to think about the practical considerations of scaling technologies,” said Yueh-Lin (Lynn) Loo, Andlinger Center director and the Theodora D. ’74 and William H. Walton ’78 Professor in Engineering. “It’s a win-win and ultimately helps us carry out a core tenet of our mission, which is to reduce emissions globally while improving access to energy around the world.”
ExxonMobil is the world-leader in carbon capture, sequestering more carbon in the last 20 years than any other company. Princeton University is advancing this technology with new research to better understand how stored CO2 flows within rocks and interacts with minerals, improving the understanding of underground storage capacity. Future CO2 storage projects can be more optimally planned and operated to achieve net emissions reductions.
Princeton University scientists are also working with ExxonMobil on the development of carbonate fuel cells. This is in addition to the company’s ongoing collaboration with FuelCell Energy to enhance technology for capturing CO2 from industrial facilities and electric power generation.
Over the past five years, through the company’s participation in E-ffiliates, ExxonMobil scientists have collaborated with Princeton faculty and researchers to support early-stage research projects that are focused on identifying lower-emission technologies that can accelerate the energy transition. Results have been published in peer-reviewed journals including Nature Geoscience, Science, Applied Energy, Journal of the American Chemical Society, and Energy and Environmental Science.
Princeton University researchers also are working to better understand the barriers, technology needs and opportunities of the global energy transition. This research is taking a comprehensive look at potential pathways to achieve net-zero emissions in the United States by 2050, and the investments in technology, infrastructure, and skill development to achieve that goal. The fundamental approach and modeling tools developed in this pilot study will be available for global use. The effort is co-led by the Andlinger Center, along with other campus partners, and funded in part by ExxonMobil and other partners.
Princeton’s Andlinger Center for Energy and the Environment is one of five university energy centers ExxonMobil has partnered with to undertake fundamental research to provide low-carbon energy solutions while meeting global energy demand.
Since 2000, ExxonMobil has invested approximately $10 billion in projects to research, develop and deploy lower-emission energy solutions. The company also continues to expand collaborative efforts with more than 80 universities, five energy centers and multiple private sector partners around the world to explore next-generation energy technologies.
About ExxonMobil
ExxonMobil, one of the largest publicly traded international energy companies, uses technology and innovation to help meet the world’s growing energy needs. ExxonMobil holds an industry-leading inventory of resources, is one of the largest refiners and marketers of petroleum products, and its chemical company is one of the largest in the world. To learn more, visit exxonmobil.com and the Energy Factor.
Follow us on Twitter and LinkedIn.
About Princeton University’s Andlinger Center for Energy and the Environment
The mission of the Andlinger Center for Energy and the Environment is to develop solutions to ensure our energy and environmental future. To this end, the center supports a vibrant and expanding program of research, teaching, and stakeholder collaboration in the areas of sustainable energy technology, energy transitions, and environmental sensing and remediation. A chief goal of the center is to translate fundamental knowledge into practical solutions. Since it began operations in 2010, the center has grown rapidly, launching unique educational programs, and catalyzing high-risk/high-payoff research with industry partners. Housed in Princeton University’s School of Engineering and Applied Science, the Andlinger Center actively convenes companies, government, peer institutions, and non-profit organizations to foster collaborative initiatives that help to overcome shared challenges to develop and deploy more sustainable systems. You can follow the work of the center on its website, Twitter account, and Facebook page.
Cautionary Statement: Statements of future events or conditions in this release are forward-looking statements. Actual future results, including project plans and timing and the impact and results of new technologies, including efficiency gains and emission reductions, could vary depending on the outcome of further research and testing; the development and competitiveness of alternative technologies; the ability to scale pilot projects on a cost-effective basis; political and regulatory developments; and other factors discussed in this release and under the heading “Factors Affecting Future Results” on the Investors page of ExxonMobil’s website at exxonmobil.com.
IRVING, Texas–ExxonMobil said today that production of liquefied natural gas (LNG) has safely resumed at the PNG LNG project in Papua New Guinea following a temporary shutdown of operations after a severe earthquake occurred in the region on Feb. 26. LNG exports are expected to resume soon.
One train is currently operating at the LNG plant near Port Moresby. The plant’s second train is expected to restart as production is increased over time.
During the period that production was shut-in, ExxonMobil was able to complete unrelated maintenance scheduled for later in the year to allow for more efficient operations in the months ahead.
“Resuming LNG production ahead of our projected eight-week timeframe is a significant achievement for ExxonMobil, our joint-venture partners and our customers,” said Neil W. Duffin, president of ExxonMobil Production Company. “We will continue to support those communities impacted by the earthquake as we work toward fully restoring our operations. We hope our contributions and assistance will provide comfort to those in need.”
ExxonMobil is supporting multiple local and international relief agencies involved in the humanitarian response to the earthquake.
In addition to the company’s previously announced $1 million contribution for humanitarian relief, ExxonMobil crews have donated and delivered more than 37 tons of food, 14 tons of drinking water, 600 tarpaulins used as emergency shelters, 1,000 solar lights for households, 20 larger solar lighting units for institutions, as well as other essential supplies including water purification tablets, cooking aids and hygiene kits.
The company is also assisting with the restoration of health care facilities and community food gardens, and is providing resources to help the government address the significant task of restoring roads in the Highlands region.
“While a lot of work remains to be done, we are confident that with the support of all our partners and stakeholders, we can help our friends and neighbors recover from this tragic natural disaster,” said Andrew Barry, managing director of ExxonMobil PNG.
About ExxonMobil in Papua New Guinea
ExxonMobil has had a presence in Papua New Guinea since the 1920s and currently has a workforce of 2,600 in the country, 80 percent of whom are Papua New Guineans. The company operates the PNG LNG project, an integrated development that includes natural gas production and processing facilities, onshore and offshore pipelines, and liquefaction facilities. Production and processing facilities are located in the Southern Highlands, Hela, Western, Gulf and Central provinces of Papua New Guinea. The company also has interests in oil production and fuels marketing.
About ExxonMobil
ExxonMobil, the largest publicly traded international oil and gas company, uses technology and innovation to help meet the world’s growing energy needs. ExxonMobil holds an industry-leading inventory of resources, is one of the largest refiners and marketers of petroleum products, and its chemical company is one of the largest in the world. For more information, visit www.exxonmobil.com or follow us on Twitter at www.twitter.com/exxonmobil.
IRVING, Texas–Exxon Mobil Corporation (NYSE:XOM) today said it shipped the first cargo of liquefied natural gas (LNG) from the $19 billion PNG LNG project ahead of schedule.
PNG LNG, operated by ExxonMobil affiliate ExxonMobil PNG Limited, is expected to produce more than 9 trillion cubic feet of gas over its estimated 30 years of operations. The first cargo is bound for LNG customer Tokyo Electric Power Co. Inc. (TEPCO) in Japan.
Production from the first train started in April and production from the second train has also started as additional wells came online.
“The PNG LNG project exemplifies ExxonMobil’s leadership in project execution, advanced technologies and marketing capabilities,” said Neil W. Duffin, president of ExxonMobil Development Company. “Our demonstrated expertise will enable us to progress other LNG opportunities in our portfolio, including expansion opportunities in Papua New Guinea and to meet growing global demand. Disciplined project execution has enabled us to supply Asia’s increasing energy needs and will benefit the people of Papua New Guinea for decades.”
Construction of PNG LNG began in 2010, and took more than 190 million work hours to complete. At its peak, the project employed more than 21,000 people.
Flooding, minimal pre-existing infrastructure and extremely steep slopes were among obstacles that were overcome in constructing the project. Pipe had to be airlifted in some areas because the soil could not support heavy machinery and lack of infrastructure required construction of supplemental roads, communication lines and a new airfield.
“This project has brought significant economic benefits to our country that will last for generations to come,” said Papua New Guinea Prime Minister, Hon. Peter O’Neill.
“Not only will the people of Papua New Guinea now benefit, their children and grandchildren will continue to enjoy the benefits and positive effects from this valuable resource development for many years to come,” O’Neill said.
The PNG LNG project is an integrated development that includes gas production and processing facilities in the Southern Highlands, Hela, Western, Gulf and Central provinces of Papua New Guinea. Approximately 435 miles of pipeline connect the facilities, which include a gas conditioning plant and liquefaction and storage facilities with capacity of 6.9 million tonnes of LNG per year.
The four major customers for the project’s output are China Petroleum and Chemical Corp. (Sinopec), Tokyo Electric Power Co. Inc. (TEPCO), Osaka Gas Co. Ltd., and CPC Corp. Taiwan.
In addition to ExxonMobil PNG Limited, co-venturers are Oil Search Limited, National Petroleum Company of PNG, Santos Ltd., JX Nippon Oil & Gas Exploration Corp., Mineral Resources Development Company (representing landowners) and Petromin PNG Holdings Limited.
ExxonMobil continues to assess and advance new expansion and development opportunities in Papua New Guinea.
About ExxonMobil
ExxonMobil, the largest publicly traded international oil and gas company, uses technology and innovation to help meet the world’s growing energy needs. ExxonMobil holds an industry-leading inventory of resources, is the largest refiner and marketer of petroleum products, and its chemical company is one of the largest in the world. For more information, visit www.exxonmobil.com or follow us on Twitter www.twitter.com/exxonmobil.
– See more at: http://news.exxonmobil.com/press-release/exxonmobil-ships-first-cargo-png-lng-project#sthash.N4ZE1cmZ.dpuf
IRVING, Texas–Exxon Mobil Corporation (NYSE:XOM) announced 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 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.
About ExxonMobil
ExxonMobil, the largest publicly traded international energy company, uses technology and innovation to help meet the world’s growing energy needs. ExxonMobil holds an industry-leading inventory of resources, is one of the largest refiners and marketers of petroleum products and its chemical company is one of the largest in the world. For more information, visit www.exxonmobil.com or follow us on Twitter www.twitter.com/exxonmobil.
HOUSTON–ExxonMobil said today that operations have commenced at its new 1.5 million ton-per-year ethane cracker at the company’s integrated Baytown chemical and refining complex.
The new cracker, part of ExxonMobil’s Growing the Gulf initiative, will provide ethylene feedstock to new performance polyethylene lines at the company’s Mont Belvieu plastics plant, which began production in the fall of 2017. The Mont Belvieu plant is one of the largest polyethylene plants in the world, with manufacturing capacity of about 1.3 million tons per year.
“Our new ethane cracker will help us meet the growing global demand for high performance plastic products that deliver key sustainability benefits such as lighter packaging weight, lower energy consumption and reduced emissions, further enhancing our competitiveness worldwide,” said John Verity, president of ExxonMobil Chemical Company. “The abundance of domestically produced oil and natural gas has reduced energy costs and created new sources of feedstock for U.S. Gulf refining and chemical manufacturing while creating jobs and expanding economic activity in the area.”
Together, the Baytown ethane cracker and Mont Belvieu plant represent ExxonMobil’s largest chemical investment in the U.S. to date. Operations associated with the Baytown and Mont Belvieu projects are expected to increase regional economic activity by roughly $870 million per year and generate more than $90 million per year in local tax revenues. The two projects have created more than 10,000 construction jobs, 4,000 jobs in nearby communities and 350 permanent positions.
ExxonMobil is strategically investing in new refining and chemical-manufacturing projects in the U.S. Gulf Coast region to expand its manufacturing and export capacity. The company’s more than $20 billion Growing the Gulf expansion program consists of major chemical, refining, lubricant and liquefied natural gas projects at proposed new and existing facilities along the Texas and Louisiana coasts. Investments began in 2013 and are expected to continue through at least 2022.
With the increase in chemical manufacturing and the industry’s need for more skilled workers, ExxonMobil has contributed more than $2 million over the last five years to the Community College Petrochemical Initiative, a training program offered by nine Houston-area community colleges to provide technical skills to high school graduates, returning military veterans and others.
About ExxonMobil
ExxonMobil, the largest publicly traded international oil and gas company, uses technology and innovation to help meet the world’s growing energy needs. ExxonMobil holds an industry-leading inventory of resources, is one of the largest refiners and marketers of petroleum products, and its chemical company is one of the largest in the world. For more information, visit www.exxonmobil.com or follow us on Twitter at www.twitter.com/exxonmobil.
TORRANCE, Calif.- ExxonMobil has reached an agreement with PBF Energy, Inc. for the sale and purchase of its refinery in Torrance, California, a lubricants distribution center at Vernon, products terminals at Vernon and Atwood, and associated California pipelines and other logistics assets, including facilities at the Southwest terminal.
“The sale results from a strategic assessment of the site and how it fits with our refining portfolio,” said Jerry Wascom, president of ExxonMobil Refining & Supply Company.
“ExxonMobil regularly adjusts its portfolio through investment, restructuring or divestment consistent with overall global and regional business strategies. We remain committed to a large, global refining portfolio as part of our integrated business strategy. We will continue to make significant investments across the globe to strengthen our facilities which are often advantaged by scale and integration with chemicals and lubricant manufacturing.”
Approximately 700 employees and 700 contractors work at the refinery and associated facilities. Employees are expected to be offered positions with PBF and existing third-party supply agreements, obligations, terms and conditions remain unchanged.
Subject to repairs to the refinery’s electrostatic precipitator and regulatory approval, change-in-control is anticipated to take place by mid-2016.
ExxonMobil is retaining a presence in California through ongoing production of oil and natural gas and sales of fuels and lubricant products. Exxon- and Mobil-branded retail sites in the state are unaffected by the agreement.
PBF recently contracted to purchase the Chalmette refinery in Louisiana through a separate, independent bidding process, in which ExxonMobil holds 50 percent interest.
Cautionary Note: Statements of future events or conditions in this release are forward-looking statements. Actual future results, including future business plans and closing of the sale and purchase agreement, may differ depending on political and regulatory events, including granting of regulatory approvals for closing of the agreement; satisfaction of other conditions specified in the agreement; the outcome of commercial negotiations; and other factors discussed under the heading “Factors Affecting Future Results” on the Investors page of our website at exxonmobil.com and in Item 1A of ExxonMobil’s most recent Annual Report on Form 10-K.
About ExxonMobil
ExxonMobil, the largest publicly traded international oil and gas company, uses technology and innovation to help meet the world’s growing energy needs. ExxonMobil holds an industry-leading inventory of resources and is one of the world’s largest integrated refiners, marketers of petroleum products and chemical manufacturers. For more information, visit www.exxonmobil.com or follow us on Twitter www.twitter.com/exxonmobil.
IRVING, Texas – ExxonMobil has increased its estimated recoverable resource base in Guyana to more than 8 billion oil-equivalent barrels and made a further oil discovery northeast of the producing Liza field at the Uaru exploration well, the 16th discovery on the Stabroek Block.
ExxonMobil ups Guyana recoverable resources to more than 8 billion oil-equivalent barrels, makes discovery at Uaru
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Stabroek Block recoverable resources increased by 2 billion oil-equivalent barrels
Uaru well is 16th discovery, will be incremental to the new resource estimate
Fifth drillship expected in 2020
The new recoverable resource estimate includes 15 discoveries offshore Guyana through year-end 2019. The Uaru discovery is the first of 2020 and will be added to the resource estimate at a later date.
“With recent high-quality finds at Tripletail and Mako contributing to our recoverable resources, our investments will continue to provide benefits for the people of Guyana,” said Mike Cousins, senior vice president of exploration and new ventures at ExxonMobil. “The Uaru discovery is another positive step as we begin a new decade with the Co-operative Republic of Guyana and our co-venturers.”
Uaru encountered approximately 94 feet (29 meters) of high-quality oil-bearing sandstone reservoir. The well, drilled in 6,342 feet (1,933 meters) of water, is located approximately 10 miles (16 kilometers) northeast of the Liza field, which began producing oil in December 2019.
Production from the Liza Phase 1 development is currently ramping up and will produce up to 120,000 barrels of oil per day in the coming months, utilizing the Liza Destiny floating production storage and offloading vessel (FPSO).
The Liza Unity FPSO, which will be employed for the second phase of Liza development and will have a production capacity of 220,000 barrels of oil per day, is under construction and expected to start production by mid-2022.
Pending government approvals and project sanctioning of a third development, production from the Payara field north of the Liza discoveries could start as early as 2023, reaching an estimated 220,000 barrels of oil per day.
Four drillships in Guyana continue to explore and appraise new resources as well as develop the resources within approved projects. A fifth drillship is expected to be deployed later this year.
The Stabroek Block is 6.6 million acres (26,800 square kilometers). ExxonMobil affiliate Esso Exploration and Production Guyana Limited is operator and holds 45 percent interest in the Stabroek Block. Hess Guyana Exploration Limited, holds 30 percent interest and CNOOC Petroleum Guyana Limited, a wholly-owned subsidiary of CNOOC Limited, holds 25 percent interest.
About ExxonMobil
ExxonMobil, the largest publicly traded international energy company, uses technology and innovation to help meet the world’s growing energy needs. ExxonMobil is a global leader in LNG project execution and holds an industry-leading inventory of resources, is one of the largest refiners and marketers of petroleum products, and its chemical company is one of the largest in the world. For more information, visit www.exxonmobil.com or follow us on Twitter at www.twitter.com/exxonmobil.
IRVING, Texas–ExxonMobil has increased its holdings in Brazil’s pre-salt basins after it won the Titã exploration block with co-venturer Qatar Petroleum during Brazil’s 5th pre-salt bid round.
The block awarded added more than 71,500 net acres to the ExxonMobil portfolio, expanding the company’s total position in the country to approximately 2.3 million net acres.
“With the acquisition of this block, we continue to increase our holdings in Brazil’s pre-salt basins, which are high-quality opportunities that enhance ExxonMobil’s global portfolio,” said Steve Greenlee, president of ExxonMobil Exploration Company. “These resources will benefit from ExxonMobil’s considerable capabilities, which we will employ as we explore and develop them with our co-venturers and the government.”
Equity interest in the block will be 64 percent for ExxonMobil and 36 percent for Qatar Petroleum. ExxonMobil will be the operator.
Through the remainder of 2018 and into 2019, ExxonMobil will continue to obtain 3-D seismic coverage, as well as continue to progress work on regulatory requirements for exploration drilling by 2020. Development work is also ongoing in the Equinor-operated Carcara field, which contains an estimated recoverable resource of more than 2 billion barrels of high-quality oil.
ExxonMobil subsidiary ExxonMobil Exploração Brasil Ltda. has interests in a total of 26 blocks offshore Brazil and is operator of 66 percent of its net acreage. The company has had business activities in Brazil for more than 100 years and has about 1,300 employees in the country across its upstream, chemical and business service center operations.
About ExxonMobil
ExxonMobil, the largest publicly traded international oil and gas company, uses technology and innovation to help meet the world’s growing energy needs. ExxonMobil holds an industry-leading inventory of resources, is the largest refiner and marketer of petroleum products, and its chemical company is one of the largest in the world. For more information, visit www.exxonmobil.com or follow us on Twitter www.twitter.com/exxonmobil.
IRVING, Texas–ExxonMobil has increased its holdings in Brazil’s pre-salt basins after winning eight additional exploration blocks during Brazil’s 15th bid round. The blocks awarded add about 640,000 net acres to the ExxonMobil portfolio. Six of the eight newly awarded blocks will be operated by ExxonMobil.
The additional blocks expand the company’s total position in the country to more than two million net acres, making it one of the largest acreage holders among international companies in Brazil.
“These recent bid round results add highly prospective acreage to ExxonMobil’s deepwater portfolio that we will explore and develop with our partners,” said Steve Greenlee, president of ExxonMobil Exploration Company. “This acreage in Brazil’s pre-salt play will provide excellent opportunities to deploy our deepwater expertise. We will continue working with the government to develop these world-class resources for the benefit of Brazilians for many years to come.”
ExxonMobil and its partners jointly won a total of eight blocks, which include:
Two blocks in the Santos area which ExxonMobil will operate with partner Qatar Petroleum.
Four blocks in the Campos area: ExxonMobil will operate two blocks with partners Petrobras and Qatar Petroleum; Petrobras will operate two blocks with partners ExxonMobil and Statoil.
Two blocks in the Sergipe-Alagoas area which ExxonMobil will operate with partners Queiroz Galvão Exploração e Produção (QGEP) and Murphy Oil Corporation, and which will enhance the value of adjacent blocks already held.
ExxonMobil plans to obtain 3-D seismic coverage in 2018 on more than 4,000 square kilometers, including all of the ExxonMobil-operated exploration blocks announced in 2017, subject to permitting approvals.
The company now has interests in 24 blocks offshore Brazil. ExxonMobil has worked in Brazil for more than 100 years.
About ExxonMobil
ExxonMobil, the largest publicly traded international oil and gas company, uses technology and innovation to help meet the world’s growing energy needs. ExxonMobil holds an industry-leading inventory of resources, is one of the largest refiners and marketers of petroleum products, and its chemical company is one of the largest in the world. For more information, visit www.exxonmobil.com or follow us on Twitter at www.twitter.com/exxonmobil.
HOUSTON –ExxonMobil today signed a memorandum of understanding with the Korea Institute of Energy Technology Evaluation and Planning and the Korea Gas Corporation (KOGAS) to hold discussions concerning natural gas technologies and new energy technologies.
The agreement will focus on the natural gas value chain, including cryogenic materials, hydrogen production and fuel cell utilization, energy efficiency technologies and technologies associated with robotics and automation.
The multi-year agreement was signed in the presence of Youngsam Kim, director general of investment policy at the Korea Ministry of Trade and Industry; Sara Ortwein, president of ExxonMobil Upstream Research Company; Richard Guerrant, vice president of ExxonMobil Gas and Power Marketing Company; and Graham Dodds, president of ExxonMobil in Korea.
Rob Franklin, president of ExxonMobil Gas and Power Marketing, said ExxonMobil is a world leader in LNG across the entire value chain.
“This memorandum of understanding establishes a framework that allows for information exchange on liquefied natural gas technology, research and development projects and best practices,” said Franklin. “It will enable professional exchanges that will help expand our joint capabilities.”
Sara Ortwein, president of ExxonMobil Upstream Research Company, said the technology development is vital to providing energy to help meet the world’s energy needs.
“Strong partnerships are key to developing and delivering integrated technology solutions,” Ortwein said. “We look forward to working with the Korea Institute of Energy Technology Evaluation and Planning and the Korea Gas Corporation to advance new research and development opportunities and energy technologies.”
Graham Dodds, president of ExxonMobil in Korea, noted that ExxonMobil has had a presence in Korea for more than 40 years, and through its ventures supplies about 30 percent of LNG demand, manufactures and markets Mobil-branded lubricants and markets ExxonMobil chemical products in the country.
“This agreement strengthens the links between ExxonMobil and Korea,” said Dodds.
About ExxonMobil
ExxonMobil, the largest publicly traded international oil and gas company, uses technology and innovation to help meet the world’s growing energy needs. ExxonMobil holds an industry-leading inventory of resources and is one of the world’s largest integrated refiners, marketers of petroleum products and chemical manufacturers. For more information, visit www.exxonmobil.com or follow us on Twitter www.twitter.com/exxonmobil.
IRVING, Texas–Global energy demand will increase 25 percent between 2014 and 2040, driven by population growth and economic expansion, ExxonMobil said today in the 2016 edition of The Outlook for Energy. At the same time, energy efficiency gains and increased use of renewable energy sources and lower carbon fuels, such as natural gas, are expected to help reduce by half the carbon intensity of the global economy.
During the period, the world’s population will increase by about 2 billion people and emerging economies will continue to expand significantly. Most growth in energy demand will occur in developing nations that are not part of the Organization for Economic Co-operation and Development (OECD). Per capita income in those countries is likely to increase by 135 percent.
Natural gas is expected to meet about 40 percent of the growth in global energy needs and demand for the fuel will increase by 50 percent. Nuclear and renewable energy sources – including bio-energy, hydro, geothermal, wind, and solar – are also likely to account for nearly 40 percent of the growth in global energy demand by 2040. By then, they are expected to make up nearly 25 percent of supplies of which nuclear alone represents about one third.
“ExxonMobil’s analysis and those of independent agencies confirms our long-standing view that all viable energy sources will be needed to meet increasing demand,” said Rex W. Tillerson, chairman and chief executive officer of Exxon Mobil Corporation. “The Outlook for Energy is a useful resource to help understand future energy supply and demand, which can aid decisions by individuals, businesses and governments that together will affect the future of energy.”
The outlook projects that global energy-related carbon dioxide emissions will peak around 2030 and then start to decline. Emissions in OECD nations are projected to fall by about 20 percent from 2014 to 2040.
The Outlook for Energy is ExxonMobil’s long-range forecast developed by its economists, engineers and scientists through data-driven analysis. It examines energy supply and demand trends for approximately 100 countries, 15 demand sectors and 20 different energy types.
“Our forecast is used as a foundation for the company’s business strategies and to help guide multi-billion dollar investment decisions,” said William Colton, vice president of ExxonMobil Corporate Strategic Planning, which develops The Outlook for Energy. “For many years the outlook has taken into account policies established to reduce energy-related carbon dioxide emissions. The climate accord reached at the recent COP 21 conference in Paris set many new goals, and while many related policies are still emerging, the outlook continues to anticipate that such policies will increase the cost of carbon dioxide emissions over time.”
Key findings of the report include:
In 2040, oil and natural gas are expected to make up nearly 60 percent of global supplies, while nuclear and renewables will be approaching 25 percent. Oil will provide one third of the world’s energy in 2040, remaining the No. 1 source of fuel, and natural gas will move into second place.
North America, which for decades had been an oil importer, is on pace to become a net exporter around 2020.
India will surpass China as the world’s most populous nation, with 1.6 billion people. The two countries are expected to account for almost half of the growth in global energy demand.
Global demand for electricity is expected to increase by 65 percent, and 85 percent of the increase is in non-OECD nations.
The share of the world’s electricity generated by coal is expected to fall to about 30 percent in 2040 from approximately 40 percent in 2014.
Global energy demand from transportation is projected to rise by about 30 percent, and practically all the growth will be in non-OECD countries.
Sales of new hybrids are expected to jump from about 2 percent of new-car sales in 2014 to more than 40 percent by 2040, when one in four cars in the world will be a hybrid. Average fuel economy will rise from 25 to about 45 miles per gallon.
Already the world’s largest oil-importing region, Asia Pacific’s net imports are projected to rise by more than 50 percent by 2040 as domestic production remains steady and demand increases.
For more information about The Outlook for Energy, visit www.exxonmobil.com/energyoutlook.
Cautionary Statement: Statements in The Outlook for Energy and this release relating to future events or conditions are forward-looking statements. Actual future global or local conditions (including economic conditions and growth, population growth, energy demand growth and mix, energy supply sources, efficiency gains, the impact of technology, and carbon emissions) could differ materially due to changes in supply and demand and market conditions affecting oil, gas, and other energy prices; changes in law or government regulation and other political events; changes in technology; the occurrence and duration of economic recessions; the actions of competitors; the development of new supply sources; demographic changes; and changes in other assumptions or factors discussed in The Outlook for Energy and under the heading “Factors Affecting Future Results” on the Investors page of our website at www.exxonmobil.com. See also Item 1A of ExxonMobil’s latest Form 10-K.
About ExxonMobil
ExxonMobil, the largest publicly traded international oil and gas company, uses technology and innovation to help meet the world’s growing energy needs. ExxonMobil holds an industry leading inventory of resources, is the largest refiner and marketer of petroleum products, and its chemical company is one of the largest in the world. Follow ExxonMobil on Twitter at www.twitter.com/exxonmobil.
BOSTON & HOUSTON – October 31 – GE (NYSE: GE) and Baker Hughes (NYSE: BHI) today announced that the companies have entered into an agreement to combine GE’s oil and gas business (“GE Oil & Gas”) and Baker Hughes to create a world-leading oilfield technology provider with a unique mix of service and equipment capabilities. The “New” Baker Hughes will be a leading equipment, technology and services provider in the oil and gas industry with $32 billion of combined revenue1 and operations in more than 120 countries. By drawing from GE technology expertise and Baker Hughes capabilities in oilfield services, the new company will provide best-in-class physical and digital technology solutions for customer productivity.
Under the terms of the agreement, which has been unanimously approved by the boards of directors of both companies, at the closing of the transaction Baker Hughes shareholders will receive a special one-time cash dividend of $17.50 per share and 37.5% of the new company. GE will own 62.5% of the company. The transaction is expected to close in mid 2017.
“This transaction creates an industry leader, one that is ideally positioned to grow in any market. Oil & gas customers demand more productive solutions. This can only be achieved through technical innovation and service execution, the hallmarks of GE and Baker Hughes,” said Jeff Immelt, Chairman and Chief Executive Officer of GE. “As we built the GE Oil & Gas business, I have always been impressed by the respect our customers have for Baker Hughes. GE Oil & Gas is a key GE business, one that fully leverages the GE Store. As we go forward, this transaction accelerates our capability to extend the digital framework to the oil and gas industry. An oilfield service platform is essential to deliver digitally enabled offerings to our customers. We expect Predix to become an industry standard and synonymous with improved customer outcomes. GE investors will benefit through ownership of a stronger business with substantial synergies and an improved competitive position. The transaction is expected to add approximately $.04 to GE EPS in 2018, $.08 by 2020.”
Martin Craighead, Chairman and Chief Executive Officer at Baker Hughes said, “This compelling combination brings together best-in-class oilfield equipment manufacturing and services, and digital technology offerings for the benefit of all customers and stakeholders. The combination of our complementary assets will create a platform capable of seamless integration while we enhance our ability to deliver optimized and integrated solutions and increase touch points with our customers. In addition, Baker Hughes shareholders will receive a special one-time cash dividend of $17.50 per share and benefit from the upside of a stronger, larger business. With employees of Baker Hughes and GE Oil & Gas coming together, the new company will be an industry leader, well-positioned to compete in the oil and gas industry while pushing the boundaries of innovation for our customers.”
Lorenzo Simonelli, who is currently president and CEO of GE Oil & Gas said, “This transformative transaction will create a powerful force in the oil and gas market as we continue to drive long-term value for our customers and shareholders. This transaction is also exciting for employees of both companies. GE Oil & Gas and Baker Hughes are an exceptional cultural fit, sharing a commitment to exceeding customer expectations. Both companies’ employees will benefit significantly from being part of a larger, stronger company that is positioned for long-term growth. We look forward to combining the digital solutions and technology from the GE Store with the domain expertise of Baker Hughes and its culture of innovation in the oilfield services sector.”
Compelling Strategic and Financial Benefits of the Transaction
Complementary assets and integrated offerings will provide differentiated services for combined company’s customers. The company will combine the digital solutions, manufacturing expertise and technology from the GE Store and the outstanding track record of success Baker Hughes has in the oilfield services sector. With combined revenue of over $32 billion1 the product portfolio of GE Oil & Gas and Baker Hughes in drilling, completions, production and midstream / downstream equipment and services will create the second largest player in the oilfield equipment and services industry. Customers should expect sustainable innovation and integration that will deliver valuable outcomes. As one company, we will have operations in more than 120 countries. Both companies have invested even in the downturn and have strong, complementary competitive scope across the industry. From GE’s fullstream oil and gas manufacturing and technology solutions spanning across subsea & drilling, rotating equipment, imaging and sensing to the Baker Hughes portfolio in Drilling & Evaluation and Completion & Production, the combined company will be moving beyond oilfield services and into oil and gas productivity solutions.
The combination produces substantial synergies through combined efficiency and growth. The companies expect to generate total runrate synergies of $1.6 billion by 2020, which has a net present value of $14 billion. While this is primarily driven by cost out, we believe that the new company is positioned for growth as the industry rebounds.
Combination positioned to create value for Baker Hughes shareholders. The diversified portfolio can deliver through the oil and gas cycle. There is a large pool of synergies that will improve operating margins and drive organic growth. The “New” Baker Hughes has a strong balance sheet.
Combination positioned to create value for GE shareholders. The transaction is expected to be accretive to GE’s earnings per share by $.04 by 2018 and $.08 by 2020. This is another step in creating the premium digital industrial company.
The “New” Baker Hughes is expected to be the partner and employer of choice for the industry. Combination is an exceptional cultural fit. Both companies’ employees will benefit significantly from being part of a larger, more diversified company.
1 Based on 2015 combined revenue
Financial Structure
The transaction will be executed using a partnership structure, pursuant to which GE Oil & Gas and Baker Hughes will each contribute their operating assets to a newly formed partnership. GE will have a 62.5% interest in this partnership and existing Baker Hughes shareholders will have a 37.5% interest through a newly NYSE listed corporation. Baker Hughes shareholders will also receive a special one-time cash dividend of $17.50 per share at closing. The $7.4 billion contributed by GE to the new partnership will be used to fund the cash dividend to existing Baker Hughes shareholders.
Headquarters, Management and Board of Directors
The “New” Baker Hughes will have dual headquarters in Houston, Texas and London, UK.
Jeff Immelt, Chairman and CEO of GE will serve as Chairman of the Board of Directors and Lorenzo Simonelli, president and CEO of GE Oil & Gas will serve as President and Chief Executive Officer. Martin Craighead, Baker Hughes Chairman and CEO, will serve as Vice Chairman of the Board. The remainder of the executive leadership team will be a combination of existing leaders from both GE and Baker Hughes.
Upon closing, the “New” Baker Hughes board will consist of nine directors: five of whom, including Chairman Jeff Immelt will be appointed by GE and four, including Vice Chairman Martin Craighead will be appointed by Baker Hughes.
About GE
GE (NYSE:GE) is the world’s Digital Industrial Company, transforming industry with software-defined machines and solutions that are connected, responsive and predictive. GE is organized around a global exchange of knowledge, the “GE Store,” through which each business shares and accesses the same technology, markets, structure and intellect. Each invention further fuels innovation and application across our industrial sectors. With people, services, technology and scale, GE delivers better outcomes for customers by speaking the language of industry. www.ge.com
About GE Oil & Gas
GE Oil & Gas is inventing the next industrial era in the oil and gas sector. In our labs and factories, and in the field, we constantly push the boundaries of technology to solve today’s toughest operational & commercial challenges. We have the skills, knowledge and technical expertise to bring together the physical and digital worlds to fuel the future. Follow GE Oil & Gas on Twitter @GE_OilandGas or visit us at www.geoilandgas.com
About Baker Hughes
Baker Hughes is a leading supplier of oilfield services, products, technology and systems to the worldwide oil and natural gas industry. The Company’s 34,000 employees today work in more than 80 countries helping customers find, evaluate, drill, produce, transport and process hydrocarbon resources. For more information about Baker Hughes, visit: www.bakerhughes.com
New Delhi, Contributing to India’s exploration and production (E&P) activities in the oil and gas sector, GE (NYSE: GE) has signed an exclusive Memorandum of Understanding (MoU) with L&T Hydrocarbon Engineering Limited, a wholly-owned subsidiary of Larsen & Toubro (L&T). Together, the firms will partner in the manufacture of subsea manifolds destined for future deep water projects in the Krishna-Godavari basin on the east coast of India.
The partnership brings together the manufacturing and technological excellence of two leading companies in the oil and gas space, and also marks India’s entrance into local subsea equipment manufacturing.
Spread over an area of 600,000 sq.m. and with an annual capacity of 50,000 MT, L&T’s modular fabrication facility in Tamil Nadu was chosen as the production site after a rigorous qualification process. The plant is equipped with advanced welding and fabrication capabilities along with a 150m jetty, making it an ideal location to manufacture advanced hardware for the seabed. Utilizing a modular approach, GE’s subsea manifolds will provide long-term reliability, safety and quality, while addressing the complexities of the subsea environment.
Ashish Bhandari, CEO, GE Oil & Gas, South Asia said, “GE continues to grow its widespread manufacturing footprint in India and this latest collaboration will continue our contributions towards Make in India. Our strategic partnership with L&T has opened new avenues for us to manufacture highly advanced equipment to serve the needs of India’s oil and gas sector as well as the broader, global industry.”
Commenting on the development, Subramanian Sarma, CEO and MD, L&T Hydrocarbon Engineering, said: “Associating with GE will help L&T to broaden its offering in the deep water space and provide a compelling value proposition to our customers. Projects of such strategic importance and magnitude bring huge responsibility and we are poised to make significant contributions to India’s growth curve going ahead.”
In addition to this MoU, L&T Infotech has also joined the GE Digital Alliance Program, with the organizations collaborating to develop innovative digital industrial solutions powered by GE’s Predix operating system for the Industrial Internet. They will work together to leverage analytics and real-time insights to enhance competitiveness and transform the way companies manage their assets and workforce.
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About GE
GE (NYSE: GE) is the world’s Digital Industrial Company, transforming industry with software-defined machines and solutions that are connected, responsive and predictive. GE is organized around a global exchange of knowledge, the “GE Store,” through which each business shares and accesses the same technology, markets, structure and intellect. Each invention further fuels innovation and application across our industrial sectors. With people, services, technology and scale, GE delivers better outcomes for customers by speaking the language of industry. www.ge.com
About GE Oil & Gas:
GE Oil & Gas works on the things that matter in the oil and gas industry. In collaboration with our customers, we push the boundaries of technology to bring energy to the world. From extraction to transportation to end use, we address today’s toughest challenges in order to fuel the future. www.geoilandgas.com. Follow GE Oil & Gas on Twitter @GE_OilandGas
About L&T
L&T is an Indian multinational engaged in technology, engineering, construction, manufacturing and financial services with over USD 16 billion in revenue. It operates in over 30 countries worldwide. A strong, customer–focused approach and the constant quest for top-class quality have enabled L&T to attain and sustain leadership in its major lines of business for over seven decades.
About L&T Hydrocarbon Engineering
L&T Hydrocarbon Engineering, a wholly-owned subsidiary of L&T, serves the O&G sector around the world. Organized under Offshore, Onshore, Construction Services, Modular Fabrication and Engineering Services verticals, the company delivers ‘design to build’ engineering and construction solutions across the hydrocarbon spectrum.
BOSTON – GE (NYSE: GE) announced today the completion of the previously announced combination of GE’s oil and gas business with Baker Hughes. Baker Hughes, a GE company (NYSE:BHGE) is the first and only company to bring together industry-leading equipment, services and digital solutions across the entire spectrum of oil and gas development.
BHGE provides differentiated services for customers by combining digital solutions and technology from the GE Store with the domain expertise of Baker Hughes and its culture of innovation in the oilfield services sector. No other company brings together capabilities across the full value chain of oil and gas activities—from upstream to midstream to downstream. This fullstream portfolio positions BHGE to create new sources of value, improving productivity and project economics through integrated equipment and service offerings.
Jeff Immelt, Chairman and CEO of GE and Chairman of BHGE, said, “BHGE is an industry leader positioned to deliver in any economic environment and assist our customers in driving productivity. This deal capitalizes on the current cycle in oil and gas while also strengthening our position for the market recovery. I am extremely proud of the GE and Baker Hughes teams for completing the combination in just eight months, which is a testament to the team’s unwavering focus and dedication since the announcement last October. As we go forward, the new fullstream offering accelerates our ability to extend a digital framework to customers while delivering world-class technical innovation and service execution. We look forward to continuing a seamless integration for our customers.”
Under the terms of the transaction agreement, which was previously announced on October 31, 2016, the transaction resulted in a partnership structure, pursuant to which Baker Hughes was converted to a partnership and GE contributed its Oil & Gas business into that partnership. GE has a 62.5% interest in this partnership and legacy Baker Hughes shareholders have a 37.5% interest through their ownership of BHGE. Former Baker Hughes shareholders, whose shares converted into shares of Class A common stock of BHGE in the transaction, are also entitled to receive a special one-time cash dividend of $17.50 per share (to be paid on July 6, 2017). $7.4 billion was contributed by GE to the new partnership, which will be used to fund the cash dividend to legacy Baker Hughes shareholders.
Baker Hughes, a GE company is dual headquartered in Houston, Texas and London, UK.
Click here to view a snapshot of the company.
Stock Exchange Trading
Class A common stock of Baker Hughes, a GE company will begin trading on the New York Stock Exchange (NYSE) under the symbol BHGE on the opening of the NYSE on July 5, 2017. In connection with the completion of the transaction, the shares of common stock of Baker Hughes Incorporated (NYSE: BHI) will continue to trade on the NYSE until the close of the NYSE today, July 3, 2017, at which point BHI will be delisted from the NYSE.
About GE
GE is the world’s Digital Industrial Company, transforming industry with software-defined machines and solutions that are connected, responsive and predictive. GE is organized around a global exchange of knowledge, the “GE Store,” through which each business shares and accesses the same technology, markets, structure and intellect. Each invention further fuels innovation and application across our industrial sectors. With people, services, technology and scale, GE delivers better outcomes for customers by speaking the language of industry. www.ge.com
TREVOSE, PA. –GE (NYSE: GE) today announced two new products to help refineries process incompatible crude oil blends. Unlike many traditional asphaltene dispersants, GE’s new EmBreak* 2167 and EmBreak 2168 crude stabilizers are ashless and do not contain any metals that could contribute to catalyst contamination or equipment fouling.
These new oil-based crude stabilizers are a part of GE’s patent-pending technology that can be used specifically in refinery desalters and other oil and water separation equipment. They are part of GE’s family of EmBreak emulsion breakers, which offer a full suite of products that span the entire range of crudes, delivering superior desalter performance and potentially reducing total costs of operation.
Traditional asphaltene dispersants can contain metals, such as phosphorous or calcium, which can act as a catalyst to foul downstream equipment. Fouling is the accumulation of unwanted material on solid surfaces that impedes the function of the equipment. GE’s new EmBreak 2167 and 2168 crude stabilizers are ashless, do not contain metals and outperform existing phosphorus and calcium-based compounds tested by GE. Being ashless and metal free is a benefit to downstream units and prevents fouling and poisoning.
“Being able to process discounted crude oils depends on the other crudes that they are blended with, and that is where EmBreak 2167 and 2168 come into the picture. GE developed a testing methodology to predict crude oil incompatibility and created innovative chemical crude stabilizer solutions to help successfully process these incompatible crude oils,” said Buzz Barlow, global general manager, hydrocarbon process—water and process technologies for GE Power & Water.
GE’s new crude stabilizers help refineries more effectively anticipate and respond to processing issues associated with opportunity crudes and their incompatibility. Incompatible crudes blends may precipitate asphaltenes or other heavy molecular weight aliphatics resulting in uncontrolled emulsions, which can cause poor effluent brine quality as well as deteriorating salt and solids removal efficiency. Some of the processing issues and risks associated with opportunity crudes include:
Poor salt removal efficiency—higher corrosion of asset risk.
Poor effluent brine quality—regulation risk as well as higher reprocessing costs to separate oil, water and solids.
Poor solids removal efficiency—higher fouling risk and potential erosion of downstream equipment.
GE’s new Embreak 2167 and 2168 coupled with GE’s innovative testing capability can help refineries more effectively anticipate and respond to processing issues associated with opportunity crudes.
*Trademark of the General Electric Company; may be registered in one or more countries.
About GE
GE (NYSE: GE) works on things that matter. The best people and the best technologies taking on the toughest challenges. Finding solutions in energy, health and home, transportation and finance. Building, powering, moving and curing the world. Not just imagining. Doing. GE works. For more information, visit the company’s website at www.ge.com.
About GE Power & Water
GE Power & Water provides customers with a broad array of power generation, energy delivery and water process technologies to solve their challenges locally. Power & Water works in all areas of the energy industry including renewable resources such as wind and solar; biogas and alternative fuels; and coal, oil, natural gas and nuclear energy. The business also develops advanced technologies to help solve the world’s most complex challenges related to water availability and quality. Power & Water’s six business units include Distributed Power, Nuclear Energy, Power Generation Products, Power Generation Services, Renewable Energy and Water & Process Technologies. Headquartered in Schenectady, N.Y., Power & Water is GE’s largest industrial business.
HOUSTON — With unconventional oil and gas operators seeking more flexible production equipment that can handle fluctuating conditions, GE Oil & Gas (NYSE: GE) today announced the global introduction of its next-generation Vector PlusTM variable speed drive (VSD) surface control system for electric submersible pumps (ESPs). ESPs are a widely used form of artificial lift that utilize centrifugal force to pump hydrocarbons to the surface, enabling high flow and enhanced production.
ESPs and other artificial lift pumping applications are used in 94 percent of the roughly 1 million oil-producing wells around the world, helping lift hydrocarbons to the surface in reservoirs with low pressure and improving the efficiency of naturally flowing wells.
ESPs are widely used to aid production in with high-volume wells and operate, on average, 6,000 feet below the surface. GE provides two ways to control the ESP motor from the surface—by using either a switchboard or a VSD system such as the company’s new Vector Plus VSD and its predecessor, the Vector VIITM VSD. While switchboards allow the operator to turn the motor on and off, GE’s new Vector Plus VSD allows the operator to gradually increase ESP motor speed and remotely adjust ESP speed from the surface with greater ease of use and improved intelligent control capabilities.
GE’s Vector Plus VSD is compatible with other GE artificial lift products, such as Zenith Downhole Sensors and Field VantageTM Solution, and incorporates other existing control technologies, enabling GE to offer customers a cost-effective, integrated solution.
“The introduction of the Vector Plus VSD illustrates GE’s commitment to continually push the envelope to improve on our existing, proven artificial lift technologies while also developing new innovations that will help our customers meet their challenging production requirements in the field,” said Jerome Luciat-Labry, president of GE’s Well Performance Services business.
“The Vector Plus VSD enhances the operator’s ability to more effectively control an ESP system, which is directly tied to increased system production and improved run-life,” said Richard Torbenson, product line manager—drives, for GE Oil & Gas. “Our Vector Plus solution and other ESP technologies provide operators with critical real-time equipment performance data, helping operators to make better production decisions.”
Other key customer benefits of the Vector Plus VSD include:
It can be used with ESP applications ranging from 100 to 1,000 horsepower.
It is designed to work on all worldwide power systems rated 380-480 volts in both 50 and 60 Hz markets.
It has an outdoor NEMA 4 rating, meaning that the enclosure is completely sealed against the outdoor environment, to prevent the entrance of dust, dirt and moisture.
Significant growth in the global unconventional oil and gas space is a major energy trend driving GE Oil & Gas’ innovations in artificial lift technologies, with the goal of offering operators the right type of solution to address the unique technical and environmental challenges of unconventional wells. Unconventionals production, driven by shale exploration and production, is expected to increase globally by 50 percent by 2018 alone.
GE made its first significant entry into the artificial lift segment with its 2011 acquisition of the Well Support Division of John Wood Group PLC., a major ESP manufacturer. GE’s subsequent 2013 acquisition of Lufkin Industries’ beam pumps, progressing cavity pumps (PCPs), gas lift, plunger lift, hydraulic lift, reciprocating pumps and automation solutions allows the company to offer a complete portfolio of artificial lift technologies, depending on a well operator’s needs. In 2014, GE Oil & Gas consolidated all of its artificial lift offerings in the new Well Performance Services business.
As a result, GE is now among the world’s leading artificial lift solutions providers, offering a comprehensive range of pumping solutions to the worldwide oil production. GE is developing technologies today to address tomorrow’s energy challenges.
About GE
GE (NYSE: GE) works on things that matter. The best people and the best technologies taking on the toughest challenges. Finding solutions in energy, health and home, transportation and finance. Building, powering, moving and curing the world. Not just imagining. Doing. GE works. For more information, visit the company’s website at www.ge.com.
About GE Oil & Gas
GE Oil & Gas works on the things that matter in the oil and gas industry. In collaboration with our customers, we push the boundaries of technology to bring energy to the world. From extraction to transportation to end use, we address today’s toughest challenges in order to fuel the future. Follow GE Oil & Gas on Twitter @GE_OilandGas.
ABERDEEN, UK— Energy services company, GE Oil & Gas (NYSE: GE), today announces the launch of its GirlsGetSET initiative in the North East of Scotland. A five-year programme, it has been designed to raise awareness amongst female pupils of the wide range of opportunities available through pursuing a career in the fields of science, engineering and technology (SET).
With women making up just 6 per cent of the engineering workforce in the UK[1] and only 5.3 per cent of females involved in SET-related roles[2], the initiative—the brainchild of engineering graduates from GE’s Aviation business—seeks to contribute to closing the gender gap between pupils choosing SET subjects at secondary school.
Kimberley Kirkham, the initiative’s co-founder, introduced the programme to GE Oil & Gas’ Subsea Systems business when she joined its global operations team in Aberdeen. She said: “My dad is a structural engineer and was pretty instrumental in encouraging my interest in the field. He spent some time as a university lecturer when I was younger and used to bring cool experiments home for my brother and I to play with. I never realised there was an engineering stereotype until I went to university and was the only girl in a class of about 60.
“Until I started at GE, I didn’t have any strong female role models. I think that’s important, especially for young girls who haven’t yet made any assumptions about who engineers are and what they do. If we can make it accessible and they can see someone who’s done it before, then that helps them to identify the career possibilities and understand how to get there. Engineering is a great outlet for creativity and innovation and I want to help more female pupils to understand and appreciate that.
“I’m really excited that, through GE Oil & Gas, we’ve been able to bring this fantastic opportunity to the North East of Scotland, a key region for driving continued growth across the worldwide energy sector. Some of the pupils involved will almost certainly become the future of our industry and it’s important that we invest in them now.”
GE invited 120 girls (aged 11-15) and teaching staff from Bridge of Don Academy, St Machar Academy and Montrose Academy to the launch event at its subsea headquarters in Aberdeen, where the day started with an official welcome address from VIP guest and GE Oil & Gas’ chief technology officer, Eric Gebhardt. He was joined by Subsea Systems’ quality leader, Ron Ritter and chief information officer, Angelica Tritzo.
Pupils kick-started the day by taking part in a series of fun workshops designed to simulate some of the challenges faced by those working in the oil and gas industry. This was followed by a networking event, in which they met GE employees to find out more about the variety of different roles available in energy sector, before ending the day with a prize-giving ceremony.
Now ‘live’, GirlsGetSET is an ongoing programme in which the girls will be mentored for the duration of their academic careers, before leaving for work, apprenticeships, college or university. Across the next five years, they will be given the opportunity to take part in a variety of fun and increasingly challenging activities, from day-long events and mini teamwork-based projects, to a year-long engineering project. Complementing this, they will have the chance to visit universities, take part in careers’ evenings, and join a personal branding workshop hosted by GE, designed to equip them with the soft skills required to kick-start their chosen careers.
Sharon Findlay, Global HR Leader at GE Oil & Gas Subsea Systems, said: “It is not news to us that a growing economy and the heightened demand for energy worldwide is increasing the need for more engineers. It’s something we continue to work on tirelessly, with various initiatives designed to tackle the issue. Partnerships between the energy sector and education are key to this, with GirlsGetSET demonstrating the concerted efforts being made by our organisation to boost the numbers of young people entering the industry at a time when talent is one of the biggest constraints.”
About GE
GE (NYSE: GE) works on things that matter. The best people and the best technologies taking on the toughest challenges. Finding solutions in energy, health and home, transportation and finance. Building, powering, moving and curing the world. Not just imagining. Doing. GE works. For more information, visit the company’s website at www.ge.com.
About GE Oil & Gas
GE Oil & Gas works on the things that matter in the oil and gas industry. In collaboration with our customers, we push the boundaries of technology to bring energy to the world. From extraction to transportation to end use, we address today’s toughest challenges in order to fuel the future.
FLORENCE, ITALY – GE Oil & Gas (NYSE: GE) has signed a Memorandum of Understanding (MoU) with the Kuwait Oil Company (KOC), a subsidiary of Kuwait Petroleum Company (KPC), to collaborate in the state of Kuwait in research and development (R&D), develop cost-effective solutions for the oil and gas sector and provide specialized training programs for engineers to strengthen Kuwaiti skilled talent.
The signing ceremony took place on the eve of the opening of the 16th GE Oil & Gas Annual Meeting in Florence. Rafael Santana, President & CEO, Turbomachinery Solutions signed the MoU on behalf of GE Oil & Gas and Hashem Hashem, CEO of KOC signed on behalf of KOC. Jeff Immelt, Chairman & CEO of GE and Lorenzo Simonelli, President & CEO of GE Oil & Gas were also present together with Mr Nizar Al-Adsani, CEO of Kuwait Petroleum Corporation.
“This agreement underlines our commitment to working in true partnership to promote the development of local human capital including technical skills of young engineers,” said Mr. Santana. Rami Qasem, president & CEO, GE Oil & Gas Middle East, North Africa & Turkey remarked “as a long-term partner of KOC, it is fantastic to be able to grow our relationship by sharing our knowledge base and advancing training initiatives in Kuwait.”
Hashem Hashem of KOC said: “As we go forward, realizing success will hinge on collaborating with local and international institutions. For this, KOC approached GE Oil & Gas to achieve a collaborative partnership that comes in-line with Kuwait International Petroleum Research Center’s (KIPRC) collaboration strategy and can be used to promote cooperation in areas that address our collective challenges and to support the acceleration of the learning curve in KOC in accordance with R&D/TM Roadmap. The parties, KOC and GE Oil & Gas, shall together promote cooperation in R&D and technology innovations, education and training and the development of KOC employees.”
GE Oil & Gas offers an extensive portfolio of highly reliable machinery and equipment to all segments of the oil and gas industry. With a global installed base of more than 20,000 units from production through transportation and processing into finished products, GE Oil & Gas is one of the industry’s major suppliers of turbomachinery, compressors, pumps, static equipment and metering systems.
GE Oil & Gas has a strong industry footprint across the Middle East region, and partners with leading oil and gas companies, petrochemical industries and power and water industry stakeholders. GE’s advanced technologies enable our customers to enhance the efficiency, reliability and productivity of their operations.
Join the conversation at our GE Hewar blog: http://middleeast.geblogs.com/
About KPC and KOC
From a position of strength, KPC launched an ambitious 2030 growth plan across the hydrocarbon value chain. Given the complexity of the challenges and in order to achieve this plan, KPC and its subsidiaries embarked on establishing KIPRCKOC R&D Group has been tasked to incubate KIPRC on KPC’s behalf and drive implementation of K- Company R&D Programs. The center envisions to being a preeminent applied R&D and Technology Management Centre that contributes to maximizing the value of Kuwait’s hydrocarbon resources in an effective and sustainable manner. To deliver on this vision, the center will provide customer-centric, collaborative, and cutting edge R&D and technology solutions through in-house capabilities and global partnerships. To date, KIPRC has enjoyed a number of key achievements. These include:
Developed an in-depth understanding of the technical challenges faced by the oil and gas sector in Kuwait and putting forward a 5-year R&D and technology roadmap
Developed an R&D Collaboration Strategy
Shaped the concept design of the architectural landscape that will host the R&D and technology activities.
Designed the operating model and identifying manpower requirements to deliver on our mandate.
About GE
GE (NYSE: GE) works on things that matter. The best people and the best technologies taking on the toughest challenges. Finding solutions in energy, health and home, transportation and finance. Building, powering, moving and curing the world. Not just imagining. Doing. GE works. www.ge.com.
About GE Oil & Gas
GE Oil & Gas works on the things that matter in the oil and gas industry. In collaboration with our customers, we push the boundaries of technology to bring energy to the world. From extraction to transportation to end use, we address today’s toughest challenges in order to fuel the future. Follow GE Oil & Gas on Twitter @GE_OilandGas
FLORENCE, Italy, — General Electric (NYSE: GE) reaffirmed its commitment to the company’s growth plans in Russia by announcing a $1 billion sourcing program and signing a series of agreements with its Russian strategic partners at the 17th GE Oil & Gas Annual Meeting in Florence. The new initiatives are aimed at accelerating GE’s localization of advanced technology solutions across the oil & gas, power, and transportation industries, as well as driving demand for local suppliers.
GE announced it will work with Russian businesses to develop up to $1 billion in sourcing opportunities by 2020 to better meet its global manufacturing needs by capitalizing on the increased competitiveness of Russian fabrication, forging, and casting. The company is currently working on several key infrastructure projects with Russian producers that meet GE quality and safety standards.
Jeff Immelt, GE Chairman and CEO, said: “We continue to see long-term development opportunities in Russia, including in sourcing from Russian manufacturers for our global businesses. Today, we are also pleased to be strengthening our partnerships with Rosneft and Transmashholding. This is a great example of GE working with leading Russian companies to tackle some of the region’s most technically intensive projects.”
Expanding the scope of their 2013 strategic partnership, GE and Rosneft, Russia’s largest oil company, announced a long-term cooperation program to jointly develop local expertise and advanced solutions, including in marine propulsion and oilfield equipment manufacturing.
In marine:
GE and Rosneft will proceed with preparations for joint work at an industrial shipbuilding cluster in Vladivostok. The cluster is planned to locally produce electrical equipment and steerable pod thrusters based on GE technology – as well as service marine diesel engines produced by a GE‑Transmashholding joint venture – for Rosneft’s fleet and other Russian civil vessels.
At the meeting in Florence, GE, Rosneft, and Transmashholding signed a Letter of Intent providing for the local production of GE V250 marine diesel engines by the GE-Transmashholding JV in Penza, Russia. The delivery of the first units to Rosneft is expected in early 2018.
In oil & gas:
GE and Rosneft will further explore development plans for a facility in Murmansk, Russia to locally assemble GE oil & gas equipment to support Rosneft’s production activities.
The companies will continue joint work on artificial lift technology, with deliveries of GE electric submersible pumps (ESPs) already underway to Rosneft and its subsidiaries for testing and evaluation.
Advancing their collaboration on small-scale LNG technologies, GE and Rosneft’s subsidiary Itera will move forward with development plans for the first small-scale LNG plant in Russia.
The companies will cooperate on a pilot project to leverage GE digital technologies for remote monitoring and control to further optimize operations at Rosneft’s largest refinery, located in Ryazan, Russia.
GE and Rosneft will also evaluate the potential of stationary distributed power solutions based on diesel engines locally produced by GE and Transmashholding in Penza.
Commenting on the program signing, Igor Sechin, Rosneft Management Board Chairman, said: “The implementation of the program signed today with one of the global technology leaders, signifies that our partnership is entering a new stage – industrial cooperation – which will enable us to meet the buoyant demand being formed by the Russian fuel and energy sector with the potential to jointly enter global markets.”
Also in Florence, GE and Transmashholding (TMH), Russia’s leading rail equipment producer, signed a strategic business plan providing for the launch of a 50-50 joint venture, pending final regulatory approvals, to localize manufacturing of advanced GEVO diesel engines at a new facility in Penza, Russia. The project is aimed at addressing the locomotive needs of Russian Railways, as well as providing engine solutions for marine vessels and distributed power applications.
The companies plan to invest over $70 million in the plant and related equipment, training, and technology. The GEVO engines to be produced at the new facility will incorporate advanced GE technologies to lower life-cycle operating costs, while increasing efficiency, reliability, ease of maintenance, and time between overhauls. The agreement envisages initial production of up to 250 engines per year in the 2,900–4,700 kW class, with the potential to expand the venture’s production capacity and product portfolio according to future market demand. The companies also agreed that a priority goal for the joint venture will be identifying export opportunities for its products.
Andrey Bokarev, Transmashholding President, said: “Transmashholding has high expectations for the future of this joint project with GE to develop and produce state-of-the-art diesel engines. It will significantly expand our expertise and the range of products we offer to the market. In combination with our existing solutions, we will be able to offer engines to our customers that precisely meet their needs. It’s particularly noteworthy that the new venture will produce engines not only for the Russian market, but also for export.”
GE’s new agreements with its strategic partners in Russia accelerate the company’s commitment to invest $1 billion in the Russian oil & gas, power, and transportation industries by 2020.
Ron Pollett, President & CEO, GE Russia/CIS, said: “Russia has been an important and strategic market for us for nearly 100 years. Together with Rosneft and Transmashholding, we are moving forward on key projects to support the development of Russian infrastructure and manufacturing capabilities. By strengthening our mutually beneficial strategic partnerships and growing our local supply chains, GE is reaffirming its long-term commitment to the Russian market.”
Today’s announcement is an example of the GE Store at work — connecting knowledge and innovations across industries to drive customer outcomes, move technology forward, and power economic growth.
HOUSTON— At next week’s 2015 Offshore Technology Conference, GE (NYSE: GE) will demonstrate how it optimizes its cross-industry portfolio to provide game-changing value for the offshore oil and gas industry.
“The key to maximizing value in this price-challenged environment lies in providing cutting-edge solutions quickly, and delivering cost savings and operational efficiency for our customers’ existing and future operations,” said Lorenzo Simonelli, President & CEO of GE Oil & Gas. “It is clear that the industry has a great opportunity to enter a new era in the way it works. Taking the best technology, integrating systems through predictive software, and supporting assets through industry-leading thinking and on-the-ground-support must be viewed as one comprehensive strategy to stay competitive in the offshore market.”
GE is answering the offshore industry’s toughest challenges by providing its customers a one-stop shop to access industry-leading technical knowledge. This “GE Store” draws on innovation, global technologies and expertise from across the company in order to locate and accelerate development of advanced cross-industry technologies, tools and ideas. When offshore customers do business with GE, they are tapping into the full breadth of technological expertise, experience and thinking from over 50,000 experts across the whole company. Because of this, GE can bring innovative solutions, built on proven technologies, to the market to deliver for its customers faster and more efficiently.
“Our newly created GE Marine vertical allows us to combine the commercial and technical expertise across multiple GE businesses into one global infrastructure close to where our customers operate,” Mark Begor, President & CEO of GE Energy Management added. “We are excited about the opportunity to provide improved operating performance to our customers in the offshore industry by leveraging the GE store and its ability to tap the best brainpower and technology from across GE. The GE store enables us to provide innovative solutions from our Power Conversion business that power, propel and position critical marine applications.”
Given the cost constraints the industry is facing, operators are looking to get more from their assets. Capital expenditure in the sector is expected to reduce by $30bn this year alone (1). However, the challenges remain the same, with operators focusing on reducing downtime and increasing productivity.
GE is committed to supporting its customers in responding to these requirements during this CAPEX constrained era. Many of the products developed in the GE store do just this. At OTC, GE will showcase and provide technological deep dives into the following solutions and new partnerships to demonstrate the significant value GE can deliver to the offshore industry:
• SeaStream™ Insight: At the forefront of GE’s Industrial Internet, SeaStream™ Insight is the latest innovation in offshore remote monitoring and asset support. Offering customers total visualization, service and management of their monitored assets and operations, it addresses the key challenges of the offshore industry, helping to maximize customer revenue, productivity and efficiency through analytics based operations.
• InspectionWorks Connect: GE Measurement & Control will offer live demonstrations of InspectionWorks Connect, a remote collaboration software platform for asset reliability inspections. InspectionWorks Connect allows nondestructive testing inspectors to access live video and data in real time, which can shorten the duration of large, complex inspection jobs like maintenance turnarounds and equipment commissioning.
• Diesel Engine Innovation: GE’s family of medium-speed marine diesel engines includes 12- and 16-cylinder V250 models and 6- and 8-cylinder L250 models that range from 1.3 MW to 4.7 MW. GE offers an innovative non-Selective Catalytic Reduction (SCR) technology for its L250 and V250 series diesel engines that requires no urea-based after-treatment. Eight years in the making, this technology reduces key emissions by more than 70% and enables in-engine compliance with EPA Tier 4 and IMO Tier III emissions standards.
• HPRC (High Pressure Ratio Compression): Technology based on an innovative architecture that combines unshrouded and shrouded impellers on a single high-speed shaft to achieve pressure ratios and efficiency levels higher than other available technologies. As result of the increased head per stage, HPRC units have a shorter bearing span that reduces the number of casings required. Applications that would typically require multiple compressor bodies will only need one with HPRC. Individual HPRC units are already smaller and lighter than traditional compressors, and the elimination of units per train is another giant improvement in overall plant footprint, reliability, availability and weight.
• GE’s Water & Process Technologies offers broad solutions for upstream chemicals, sulfate removal and enhanced oil recovery including pretreatment filters, NF membranes, upstream chemicals, remote monitoring & diagnostics, pre-engineered solutions, and more.
For show interviews, video and live updates, visit the landing page at www.geoilandgas.com/otc. You may also visit GE’s booth for a technology tour at # 3163.
About GE
GE (NYSE: GE) works on things that matter. The best people and the best technologies taking on the toughest challenges. Finding solutions in energy, health and home, transportation and finance. Building, powering, moving and curing the world. Not just imagining. Doing. GE works. For more information, visit the company’s website at www.ge.com.
About GE Oil & Gas
GE Oil & Gas is inventing the next industrial era in the oil and gas sector. In our labs and factories, and in the field, we constantly push the boundaries of technology to solve today’s toughest operational & commercial challenges. We have the skills, knowledge and technical expertise to bring together the physical and digital worlds to fuel the future.
Follow GE Oil & Gas on Twitter @GE_OilandGas.
About GE Energy Management
Energy Management is GE’s electrification business. We make energy safer and more useful through our ability to transmit, distribute and convert electricity. We integrate leading products and technology to solve customer problems. Energy Management’s electrical solutions allow utilities and energy-intensive industries such as oil & gas, marine, data centers, metals and mining to efficiently manage electricity from the point of generation to the point of consumption.
About GE Power and Water
GE Power & Water provides customers with a broad array of power generation, energy delivery and water process technologies to solve their challenges locally. Power & Water works in all areas of the energy industry including renewable resources such as wind and solar; biogas and alternative fuels; and coal, oil, natural gas and nuclear energy. The business also develops advanced technologies to help solve the world’s most complex challenges related to water availability and quality. Power & Water’s six business units include Distributed Power, Nuclear Energy, Power Generation Products, Power Generation Services, Renewable Energy and Water & Process Technologies. Headquartered in Schenectady, N.Y., Power & Water is GE’s largest industrial business.
Glencore is announcing today a 500,000 tonne reduction of contained zinc metal mine production across its operations in Australia, South America & Kazakhstan. The main reason for the reduction is to preserve the value of Glencore’s reserves in the ground at a time of low zinc and lead prices, which do not correctly value the scarce nature of our resources.
These changes, which represent around one-third of Glencore’s annual zinc production, will reduce fourth quarter 2015 mine production by approximately 100,000 tonnes of contained zinc metal.
Glencore’s operations at Lady Loretta in Australia and Iscaycruz in Peru will be suspended and operations at George Fisher and McArthur River in Australia and various mine operations in Kazakhstan will reduce production levels.
Glencore remains positive about the medium and long term outlook for zinc, lead and silver prices. This decision will ensure that our zinc operations are sustainable well into the future, providing jobs in the communities where we operate and returns to shareholders.
These changes, although temporary, will unfortunately affect employees at our operations. This decision has not been taken lightly. In the coming days we will engage with all employees and put in place support services to assist people who may be affected as a result of these changes.
Glencore is one of the world’s largest global diversified natural resource companies and a major producer and marketer of more than 90 commodities. The Group’s operations comprise of over 150 mining and metallurgical sites, oil production assets and agricultural facilities.
With a strong footprint in both established and emerging regions for natural resources, Glencore’s industrial and marketing activities are supported by a global network of more than 90 offices located in over 50 countries.
Glencore’s customers are industrial consumers, such as those in the automotive, steel, power generation, oil and food processing. We also provide financing, logistics and other services to producers and consumers of commodities. Glencore’s companies employ around 181,000 people, including contractors.
Glencore is proud to be a member of the Voluntary Principles on Security and Human Rights and the International Council on Mining and Metals. We are an active participant in the Extractive Industries Transparency Initiative.
10 July 2015 – Global oil demand growth is forecast to slow to 1.2 million barrels per day (mb/d) in 2016, from an average 1.4 mb/d this year, the IEA Oil Market Report for July informed subscribers, though strong consumption is expected in non-OECD Asia.
World oil demand growth appears to have peaked in the first quarter at 1.8 mb/d and will continue to ease throughout the rest of 2015 and into 2016 as temporary support fades.
Global oil supply surged by 550 000 barrels per day (550 kb/d) in June, on higher output from both OPEC and non-OPEC producers. At 96.6 mb/d, world oil production was an impressive 3.1 mb/d higher than a year earlier, with OPEC crude and natural gas liquids accounting for 60% of the gain. Non-OPEC supply growth is expected to grind to a halt in 2016, as lower oil prices and spending cuts take a toll.
OPEC crude supply rose by 340 kb/d in June to 31.7 mb/d, a three- year high, led by record high output from Iraq, Saudi Arabia and the United Arab Emirates. OPEC output stood 1.5 mb/d above the previous year. The “call on OPEC crude and stock change” for 2016 is forecast to rise by 1 mb/d, to 30.3 mb/d.
OECD industry inventories hit a record 2 876 mb in May, up by a steep 38 mb. Product holdings led the build-up and by end-month covered 30.7 days of forward demand. Global supply and demand balances suggest that the rate of global stock increases quickened rapidly to an astonishing 3.3 mb/d during the second quarter.
Robust margins spurred stronger-than-expected OECD refinery runs, lifting second-quarter global throughput estimates to 78.7 mb/d. Global refinery throughputs are forecast to increase by a further 0.7 mb/d in the third quarter, with annual gains shifting to the non-OECD. New capacity start-ups in 2015 and 2016 will put margins under pressure.
The July OMR also features a focus on the demand implications of the Greek debt crisis as well as analysis of OPEC capacity, Petrobras and refinery capacity additions.
ROTTERDAM: GoodFuels Marine, the world’s first supplier of sustainable low carbon marine fuels, in conjunction with bulker and tanker owner and operator NORDEN A/S, has successfully completed trials of the world’s first zero emission, ‘drop in’ Heavy Fuel Oil (HFO)-equivalent marine biofuel – almost entirely reducing all carbon and sulphur emissions.
The culmination of three years extensive research and development with partners including Royal Dutch Boskalis and technology group Wärtsilä, GoodFuels’ Bio-Fuel Oil (BFO) delivers near-zero carbon and Sulphur Oxide (SOx) emissions without any requirement for engine modifications. The trials – which saw hundreds of tonnes of ‘drop in’ BFO taken onboard in the Amsterdam-Rotterdam-Antwerp region – were conducted on the 37,000 deadweight tonne (dwt) Handysize product tanker vessel NORD HIGHLANDER as she ran in typical commercial operation in the North and Baltic Seas.
The successful operation effectively means that there is the capability to future-proof fuel requirements for shipowners and operators who are seeking an alternative to both distillates and Ultra Low Sulphur Fuel Oil (ULSFO) in order to comply with 2020 0.5% sulphur cap requirements, as well as impending International Maritime Organisation (IMO) Greenhouse Gas (GHG) reduction requirements. These requirements include an objective to reduce average carbon intensity from shipping – the amount of carbon emitted for each unit of transport – by at least 40% by 2030, and 70% by 2050.
Dirk Kronemeijer, CEO, GoodFuels Marine, commented:
“We want to greatly thank NORDEN A/S for being a pioneer and for joining us as we take this crucial step towards developing a carbon-busting solution that is scalable, truly sustainable, technically compliant and – crucially – affordable. In our journey so far we have focused on realising the widescale use of bio-marine gas oil (MGO) equivalent biofuel, but for over three years we have been working day and night to develop our BFO solution.
“The importance of its arrival in the market is further underlined by the dual prospect of impending lower sulphur and carbon legislation. Bringing this to market now offers shipping a near-zero carbon and SOx alternative to HFO, and VLSFO – 0.5% blended fossil fuel – both of which will be prevalent in the market post-2020. From this point onwards we want to scale supply as fast as we can in order to actively contribute to the world’s 1.5 degree challenge.”
Jan Rindbo, CEO, NORDEN, added:
“NORDEN is proud to be at the forefront of testing and introducing CO2 neutral fuel that truly makes an impact on the highly important agenda of reducing the carbon footprint of shipping.”
“NORDEN has come a long way in increasing fuel efficiency and has reduced CO2 emissions per tonne cargo transported on owned tanker vessels by 25% between 2007 to 2017. With the newly introduced IMO targets on CO2 reductions, however, it is evident that increased fuel efficiency alone is not enough. We need alternative solutions and with this test, NORDEN has shown a viable method towards reaching these targets.
“Now that we have proven CO2 neutral transport as a viable alternative, I am convinced many carbon-conscious customers will demand this type of transport within a foreseeable future.”
NORDEN A/S and GoodFuels Marine will continue working with each other to gain more experience and scale usage of the fuel as an alternative to HFO, ensuring the realisation of the opportunity to offer commercially attractive carbon-neutral transport to meet customers’ demands.
To support this aim, in 2016 GoodFuels founded The GoodShipping Program to further engage cargo owners in the challenge of combatting shipping’s carbon emissions. In September 2018 the Program announced that five shippers had completely offset the carbon emissions of their cargo by refuelling a vessel with marine biofuels.
About GoodFuels Marine
GoodFuels Marine is a Netherland’s based global pioneer in sustainable marine fuels. The company has created a one-stop shop for marine industry customers integrating the entire supply chain for sustainable marine biofuels. From feedstock to tank, GoodFuels Marine’s proposition covers elements of sourcing feedstock and ensuring its 100% sustainability, the production and refining, the global distribution, quality assurance and marketing programs with ports, governments and end clients. GoodFuels Marine has its operations RSB certified.
GoodFuels Marine is part of the GoodNRG Group, which is active under various labels and companies in sales, marketing, trading, R&D and production of truly sustainable fuels for the transport segments for which biofuels is one of the best or only viable long-term alternative. GoodFuels has a partnership with Varo Energy on the distribution and development of speciality blending solutions for Low Carbon Marine fuels for the ARA region. Learn more about GoodFuels at goodfuels.com
About NORDEN A/S
Founded in 1871 Dampskibsselskabet NORDEN A/S is an independent shipping company incorporated in Denmark and listed on Nasdaq Copenhagen. NORDEN operates a mix of owned and chartered tonnage. In dry cargo, NORDEN is active in a number of vessel types and one of the world’s largest operators of Supramax and Panamax vessels. In tankers, NORDEN is active in the Handysize and MR product tanker vessel types operated through the 50% owned Norient Product Pool.
HOUSTON- Halliburton Company (NYSE: HAL) and Baker Hughes Incorporated (NYSE: BHI) today announced that the companies will market for sale additional businesses in connection with Halliburton’s pending acquisition of Baker Hughes. Pursuant to the Merger Agreement, and in order to permit completion of Halliburton’s acquisition of Baker Hughes, the following additional businesses are intended to be divested: Halliburton’s expandable liner hangers business, which is part of the company’s Completion & Production Division; Baker Hughes’ core completions business, which includes: packers, flow control tools, subsurface safety systems, intelligent well systems, permanent monitoring, sand control tools and sand control screens; the Baker Hughes sand control business in the Gulf of Mexico, including two pressure pumping vessels; and Baker Hughes’ offshore cementing businesses in Australia, Brazil, the Gulf of Mexico, Norway, and the United Kingdom.
The divestitures process for the previously announced divestitures of Halliburton’s Fixed Cutter and Roller Cone Drill Bits, Directional Drilling and Logging-While-Drilling (LWD)/Measurement-While-Drilling (MWD) businesses is continuing, and Halliburton is pleased that last Friday it received proposals from multiple interested parties for each business.
The combined 2013 revenue associated with all of the businesses intended to be divested was approximately $5.2 billion. The sale of these businesses will be subject to the negotiation of acceptable terms and conditions for the divestitures, the approval of the divesting company’s Board of Directors, and final approval of the Baker Hughes acquisition by competition enforcement authorities. Halliburton anticipates that the companies will complete the sales of these businesses in the same timeframe as, and the closing of the divestitures would be conditioned on, the closing of the pending Baker Hughes acquisition.
There is no agreement to date with any competition enforcement authority as to the adequacy of the proposed divestitures. The companies will continue to work constructively with all competition enforcement authorities that have expressed an interest in the proposed transaction. The pending acquisition has received unconditional regulatory clearances in Canada, Kazakhstan, South Africa, and Turkey.
Halliburton and Baker Hughes have also amended their timing agreement with the Antitrust Division of the U.S. Department of Justice (DOJ) to extend the earliest closing date by three weeks, to the later of Dec. 15, 2015 (from the current date of Nov. 25, 2015) or 30 days following the date on which both companies have certified final, substantial compliance with the DOJ second request. Timing agreements are often entered into in connection with large, complex transactions, and provide the DOJ additional time to review responses to its second requests. In light of the timing agreement, Halliburton and Baker Hughes have agreed to extend the time period for closing of the acquisition pursuant to the Merger Agreement to no later than Dec. 16, 2015. The Merger Agreement also provides that the closing can be extended into 2016, if necessary.
About Halliburton
Founded in 1919, Halliburton is one of the world’s largest providers of products and services to the energy industry. With more than 70,000 employees, representing 140 nationalities in over 80 countries, the company serves the upstream oil and gas industry throughout the lifecycle of the reservoir – from locating hydrocarbons and managing geological data, to drilling and formation evaluation, well construction and completion, and optimizing production through the life of the field. Visit the company’s website at www.halliburton.com. Connect with Halliburton on Facebook, Twitter, LinkedIn, Oilpro and YouTube.
About Baker Hughes
Baker Hughes is a leading supplier of oilfield services, products, technology and systems to the worldwide oil and natural gas industry. The company’s 49,000 employees today work in more than 80 countries helping customers find, evaluate, drill, produce, transport and process hydrocarbon resources. For more information on Baker Hughes, visit: www.bakerhughes.com.
HOUSTON – Halliburton Company (NYSE: HAL) and Baker Hughes Incorporated (NYSE: BHI) today announced that the companies will market for sale additional businesses in connection with Halliburton’s pending acquisition of Baker Hughes. Pursuant to the Merger Agreement, and in order to permit completion of Halliburton’s acquisition of Baker Hughes, the following additional businesses are intended to be divested: Halliburton’s expandable liner hangers business, which is part of the company’s Completion & Production Division; Baker Hughes’ core completions business, which includes: packers, flow control tools, subsurface safety systems, intelligent well systems, permanent monitoring, sand control tools and sand control screens; the Baker Hughes sand control business in the Gulf of Mexico, including two pressure pumping vessels; and Baker Hughes’ offshore cementing businesses in Australia, Brazil, the Gulf of Mexico, Norway, and the United Kingdom.
The divestitures process for the previously announced divestitures of Halliburton’s Fixed Cutter and Roller Cone Drill Bits, Directional Drilling and Logging-While-Drilling (LWD)/Measurement-While-Drilling (MWD) businesses is continuing, and Halliburton is pleased that last Friday it received proposals from multiple interested parties for each business.
The combined 2013 revenue associated with all of the businesses intended to be divested was approximately $5.2 billion. The sale of these businesses will be subject to the negotiation of acceptable terms and conditions for the divestitures, the approval of the divesting company’s Board of Directors, and final approval of the Baker Hughes acquisition by competition enforcement authorities. Halliburton anticipates that the companies will complete the sales of these businesses in the same timeframe as, and the closing of the divestitures would be conditioned on, the closing of the pending Baker Hughes acquisition.
There is no agreement to date with any competition enforcement authority as to the adequacy of the proposed divestitures. The companies will continue to work constructively with all competition enforcement authorities that have expressed an interest in the proposed transaction. The pending acquisition has received unconditional regulatory clearances in Canada, Kazakhstan, South Africa, and Turkey.
Halliburton and Baker Hughes have also amended their timing agreement with the Antitrust Division of the U.S. Department of Justice (DOJ) to extend the earliest closing date by three weeks, to the later of Dec. 15, 2015 (from the current date of Nov. 25, 2015) or 30 days following the date on which both companies have certified final, substantial compliance with the DOJ second request. Timing agreements are often entered into in connection with large, complex transactions, and provide the DOJ additional time to review responses to its second requests. In light of the timing agreement, Halliburton and Baker Hughes have agreed to extend the time period for closing of the acquisition pursuant to the Merger Agreement to no later than Dec. 16, 2015. The Merger Agreement also provides that the closing can be extended into 2016, if necessary.
About Halliburton
Founded in 1919, Halliburton is one of the world’s largest providers of products and services to the energy industry. With more than 70,000 employees, representing 140 nationalities in over 80 countries, the company serves the upstream oil and gas industry throughout the lifecycle of the reservoir – from locating hydrocarbons and managing geological data, to drilling and formation evaluation, well construction and completion, and optimizing production through the life of the field. Visit the company’s website at www.halliburton.com. Connect with Halliburton on Facebook, Twitter, LinkedIn, Oilpro, and YouTube.
About Baker Hughes
Baker Hughes is a leading supplier of oilfield services, products, technology and systems to the worldwide oil and natural gas industry. The company’s 49,000 employees today work in more than 80 countries helping customers find, evaluate, drill, produce, transport and process hydrocarbon resources. For more information on Baker Hughes, visit: http://www.bakerhughes.com/.
HOUSTON – Halliburton Company (NYSE: HAL) today announced its Board of Directors has appointed Executive Vice President and Chief Financial Officer Mark McCollum to the new role of Executive Vice President and Chief Integration Officer. In this capacity, he will serve as head of the Joint Integration Team that Halliburton and Baker Hughes Incorporated (NYSE: BHI) are assembling in connection with Halliburton’s pending acquisition of Baker Hughes. Mr. McCollum will continue reporting to Dave Lesar, Chairman and Chief Executive Officer of Halliburton, and will remain a member of the company’s Executive Committee.
Christian Garcia, Senior Vice President and Chief Accounting Officer, will become Senior Vice President of Finance and assume Mr. McCollum’s CFO responsibilities on an interim basis. It is anticipated that Mr. McCollum will resume his CFO duties at the conclusion of the two companies’ integration. Mr. Garcia will report to Mr. Lesar and will join Halliburton’s Executive Committee. Charlie Geer, currently Vice President of Finance, will become Vice President and Corporate Controller and will take over Mr. Garcia’s accounting responsibilities on an interim basis as well. He will continue reporting to Mr. Garcia. The new roles are effective January 1, 2015.
Belgacem Chariag, President of Global Products and Services for Baker Hughes, will serve as lead for Baker Hughes on the Joint Integration Team.
“Establishing a unified integration team under the direction of Mark and Belgacem is an important first step in bringing together the talent and expertise of both companies to make a stronger combined company,” said Mr. Lesar. “We are committed to putting together a detailed and thoughtful integration plan to make the post-closing transition as seamless, efficient and productive as possible.”
On Nov. 17, Halliburton and Baker Hughes jointly announced a definitive agreement under which Halliburton will, subject to the conditions set forth in the agreement, acquire Baker Hughes in a stock and cash transaction.
About Halliburton
Founded in 1919, Halliburton is one of the world’s largest providers of products and services to the energy industry. With more than 80,000 employees, representing 140 nationalities in over 80 countries, the company serves the upstream oil and gas industry throughout the lifecycle of the reservoir – from locating hydrocarbons and managing geological data, to drilling and formation evaluation, well construction and completion, and optimizing production through the life of the field. Visit the company’s website at www.halliburton.com. Connect with Halliburton on Facebook, Twitter, LinkedIn, Oilpro, and YouTube.
HOUSTON – Halliburton (NYSE: HAL) today announced it has provided wireline services technology for two deepwater exploratory wells in Angola’s demanding pre-salt environment for Cobalt International Energy, Inc. (NYSE:CIE).
The wireline technology enhances the understanding of the rock and fluid properties of the formation and enables the company to make informed decisions and minimize drill-stem test risks.
Combined with the standard suite of petrophysical tools, Halliburton employed its RDT™ reservoir description tool to collect reservoir formation pressure and samples over the course of three to four days. The tool collected reservoir formation pressure gradients, mini-drill stem test with straddle packers and fluid samples in a single run, saving time by working longer than conventional tools in this hostile environment.
In addition, Halliburton’s new HRSCT-B™ hostile rotary sidewall coring tool was deployed on both rigs, taking samples at three times the volume of conventional core samples and allowing for more meaningful lab results given that the larger samples offer a better representation of the formation. This technology produces samples that are 1.5-inches in diameter and 2.4-inches in length, while eliminating the microfractures typical in percussion cores and reducing the potential for uncertainties. Rated to withstand temperatures up to 400 degrees Fahrenheit, the tool saved considerable time over coring operations performed by previous service providers in some of the most challenging formations on earth.
“Halliburton’s latest portfolio of technologies designed specifically for the challenging and often hostile environment of deepwater exploration performed exceptionally well and delivered key data for the analysis of these wells,” said Brady Murphy, senior vice president of Halliburton’s Business Development and Marketing. “We are proud to be a part of this exciting and new play in the pre-salt of Angola and with such an innovative operator as Cobalt.”
James Painter, Cobalt’s executive vice president, Execution and Appraisal, stated, “Utilizing technology that provides representative and meaningful information in the pre-salt environment enables Cobalt to assess risk, mitigate hazards and make safe and timely decisions.”
Along with the other tools, Halliburton used its new Integrated Computational Element (ICE CoreSM) optical fluid analyzer technology to obtain a better understanding of the reservoir fluid composition. Using ICE Core tool technology, the company was able to identify which fluid components were present in a sample.
This Press Release is courtesy of www.halliburton.com
HOUSTON – Halliburton (NYSE: HAL) announces the signing ofa partnership agreement with Gubkin Russian State University of Oil and Gas for
the development of unconventional resources in Russia, including the Bazhenovshale. A signing ceremony took place on January 30 at the university.
As part of the agreement, Halliburton will provide senior technical and management staff to serve on Gubkin’s Industry Advisory Boards, as well as provide the foundation material for Gubkin’s unconventional curriculum that will become the basis for student and industry training. In addition, Halliburton will work with Gubkin to explore basic applied research opportunities in conventional and unconventional resource development, provide assistance with student projects, and pursue R&D opportunities with Russian industry partners.
According to Brady Murphy, Halliburton’s Senior Vice President of Business Development, “Halliburton is positioned to provide the most recent ideas in unconventional development as well as state-of-the-art research and development solutions for the Bazhenov in Russia.” Speaking at the signing ceremony, university Rector Viktor Martynov noted that “by collaborating with Halliburton, Gubkin will be able to offer students and industry personnel real world experience in unconventional resource development.”
According to published reports Russia may hold as many as 680 trillion cubic meters of unconventional resources, which include gas from shale, sandstones and coal beds. Konstantin Schilin, Halliburton’s Vice President for Russia, noted that Halliburton, as well as local companies, will require new graduates with the requisite knowledge and training to tackle the challenges of the Bazhenov and other unconventional resources.
Professor Mikhail Silin, university Vice Rector in charge of innovation activity and commercialization of new developments, noted that “by partnering with Halliburton, Gubkin is now in a position to create a collaborative framework to strengthen our educational curriculum and learning environment and to prepare students to contribute more to their employers upon graduation.”
This news is courtesy of www.halliburton.com
NAPLES, Fla., — Hertz Equipment Rental Corporation (hertzequip.com), a wholly owned subsidiary of The Hertz Corporation (NYSE:HTZ), has expanded its Denver, Colorado operations with the launch of a new satellite facility in Cheyenne, Wyoming’s capital. The Cheyenne location serves the southern Wyoming and northern Colorado oil plays and also operates onsite at a key services partner location.
“We are continuing to make strategic investments in the oil and gas exploration and production sector, one of our strongest industrial business segments,” said Lois Boyd, President, Hertz Equipment Rental Corporation. “As part of this focus, we are very excited to extend our Denver-based equipment rental operations with our new Cheyenne, Wyoming speciality location to support oil plays in the surrounding area. As always, our mission is to help our customers control costs, expand their revenues, take comprehensive safety measures and maintain compliance.”
Hertz Equipment Rental brings over 30 years of experience with oil field clientele, with equipment and services specially designed for upstream and midstream operations. The company serves many oil and gas plays in North America, including the Bakken, Barnett, Eagle-Ford, Haynesville, Marcellus, Permian Basin, and Utica. Hertz Equipment Rental works closely with both operating and production companies as well as the drilling contractors working within those environments.
The Hertz Equipment Cheyenne facility provides a wide range of industrial fleet for rent or sale. The equipment includes aerial lifts, earth moving, forklifts, heaters, hoses, light plants, portable power and power distribution products, speciality pumps and compressors, and other oil field specific fleet. The company can also set up on-site operations around the clock with full time staff where needed in order to minimize downtime and maximize production.
Hertz equipment is purchased from the industry’s leading manufacturers and is available for daily, weekly, monthly and long-term rentals. There are also rent-to-own and rental purchase option plans available for the new and used equipment for sale.
Hertz Equipment Rental employs highly trained, experienced staff fully dedicated to providing customers a premier rental experience. Specialist personnel can engineer a complete application study to deliver the best solution to generate the highest level of success for customers.
The company also offers its clients safe operation equipment training to assist in the safety education of employees. These courses can be tailored to each company’s individual safety needs.
The Cheyenne facility is located at 715 E 15th St, Cheyenne, WY 82001. Its hours of operation are 7:00am – 5:00pm Monday – Friday. Staff can be reached via telephone number 307 635 9051.
About Hertz Equipment Rental Corporation
Hertz Equipment Rental Corporation (www.hertzequip.com) – a wholly owned subsidiary of The Hertz Corporation since 1965 – operates one of the world’s largest equipment rental businesses, offering a diverse line of equipment and tools for rent and sale. Products include aerial manlifts, air compressors and tools, earthmoving equipment and power generators, forklifts and material handling equipment, pumps, and trucks and trailers. Hertz Equipment also offers programs and equipment through its customer programs for Aerial, Energy, Entertainment, Government, HERC360 Fleet Management, Industrial Plants, National Accounts and Safety. With approximately 360 locations in the United States, Canada, China, France, Spain and Saudi Arabia as well as through international licensees, Hertz Equipment Rental offers daily, weekly, monthly and long-term rentals, tools and supplies, as well as new and used equipment for sale.
About The Hertz Corporation
Hertz operates its car rental business through the Hertz, Dollar, Thrifty and Firefly brands from approximately 10,400 corporate, licensee and franchisee locations in North America, Europe, Latin America, Asia, Australia, Africa, the Middle East and New Zealand. Hertz is the largest worldwide airport general use car rental brand, operating from approximately 8,800 corporate and licensee locations in approximately 150 countries. Hertz is the number one airport car rental brand in the U.S. and at 111 major airports in Europe. Dollar and Thrifty have approximately 1,580 corporate and franchisee locations in approximately 80 countries. Hertz is an inaugural member of Travel + Leisure’s World’s Best Awards Hall of Fame and was recently named, for the thirteenth time, by the magazine’s readers as the Best Car Rental Agency. Hertz was also voted the Best Overall Car Rental Company in Zagat’s 2013/14 U.S. Car Rental Survey, earning top honors in 10 additional categories, and the Company swept the global awards for Best Rewards Program and Best Overall Benefits from FlyerTalk.com. Product and service initiatives such as Hertz Gold Plus Rewards, NeverLost®, and unique cars and SUVs offered through the Company’s Adrenaline, Prestige and Green Traveler Collections, also set Hertz apart from the competition. Additionally, Hertz owns the vehicle leasing and fleet management leader Donlen Corporation and operates the Hertz 24/7 hourly car rental business. Hertz also operates one of the world’s largest equipment rental businesses, Hertz Equipment Rental Corporation, through approximately 350 branches in the United States, Canada, China, France, Spain and Saudi Arabia, as well as through its international licensees.
This news is courtesy of www.hertz.com
NEW YORK– Hess Corporation (NYSE:HES) announced today its intention to pursue the formation and initial public offering of a master limited partnership (MLP). Hess remains focused on value creation and the pursuit of its previously announced intention to monetize its midstream assets in the Bakken oil shale play in North Dakota. Hess intends to use the MLP as the primary midstream vehicle to support its Bakken production growth, and expects initially to contribute interests in the following midstream assets to the MLP:
Hess’s natural gas processing plant located in Tioga, North Dakota, where a large-scale expansion, refurbishment and optimization program was recently completed;
Hess’s rail loading terminal in Tioga, North Dakota, along with the associated rail cars;
Hess’s crude oil truck and pipeline terminal located in Tioga, North Dakota; and
Hess’s propane storage cavern and related rail and truck loading and storage terminal located in Mentor, Minnesota.
Hess will own the general partner of the MLP, all of its incentive distribution rights, and a majority of its limited partner interests following completion of the initial public offering.
Hess expects the MLP to file a registration statement with the Securities and Exchange Commission in the fourth quarter of 2014 and, subject to market conditions, expects to make an initial public offering of common units representing limited partner interests in the MLP in the first quarter of 2015.
This news release shall not constitute an offer to sell or the solicitation of an offer to buy securities. Any offers or solicitations of offers to buy or any sales of securities will be made in accordance with the registration requirements of the Securities Act of 1933, as amended (Securities Act). This announcement is being issued in accordance with Rule 135 under the Securities Act.
Hess Corporation is a leading global independent energy company engaged in the exploration and production of crude oil and natural gas. More information on Hess Corporation is available at http://www.hess.com.
ABU DHABI, United Arab Emirates, Nov. 15, 2021 — Today at ADIPEC, IBM (NYSE: IBM) and Amazon Web Services, Inc. (AWS), an Amazon.com, Inc. company (NASDAQ: AMZN) announced the two companies will combine the benefits of IBM Open Data for Industries for IBM Cloud Pak for Data and the AWS Cloud to serve energy customers. This comprehensive solution is built on Red Hat OpenShift and will run on the AWS Cloud, simplifying the ability for customers to run workloads in the AWS cloud and on-premises. The two companies also intend to collaborate on further co-development of future functionality to provide greater flexibility and choice on where to run OSDU applications.
As an IBM and Reuters whitepaper, sponsored by IBM, found, the energy industry is facing pressure to reduce greenhouse gases as demand for affordable energy continues to rise. Energy companies need solutions that help drive efficiencies to free up capital, time and resources to invest in discovering new, more sustainable energy sources for the future. Data and digital technologies can help to navigate this transition, yet an IBM survey found that less than half of oil and gas executive respondents are using data to drive that innovation. This is in part because most of the digitization efforts have been in proprietary closed systems, hindering the potential to combine and maximize the value of data.
The collaboration between IBM and AWS aims to accelerate reduction of data barriers in the industry. IBM Open Data for Industries is an open-source solution using the OSDU data foundation for the oil, gas and energy industry. IBM Open Data for Industries is fully integrated with IBM Cloud Pak for Data for easy data management, and built on Red Hat OpenShift, the industry’s leading Kubernetes platform and open architecture, designed so that companies can run and operate applications universally. With this collaboration, customers will gain the flexibility to run OSDU Data Platform applications in the AWS cloud or on-premises while addressing data residency requirements. Combined with the expansive cloud infrastructure of AWS cloud services, this data platform can help energy companies reduce the cost, time and resources needed to leverage the data to derive insight, streamlining operations and transition to sustainable energy generation.
“Much of the data needed to solve the complex energy challenges, such as superior subsurface decisions, already exists, yet is untapped. This is because one of the greatest values of that data is derived when it can be effectively combined, but usually this data is locked by data residency requirements, legacy applications or proprietary data formats,” said Bill Vass, vice president, engineering, AWS. “By collaborating with IBM and leveraging Red Hat OpenShift, we will be able to offer customers a global, seamless offering with the flexibility to run on virtually any IT infrastructure and drive longer-term digital innovation.”
The OSDU Forum is a cross-industry collaboration that provides a vendor-neutral framework for companies to develop data platforms against common energy industry standards. By working together, IBM and AWS will accelerate the value of this platform for global customers. The goal is that this combined effort will help serve the needs of energy companies today with flexibility to adapt to change amid energy transition.
“Data is a critical asset to help fuel energy transition, yet too often energy companies must choose between running applications on-premises or in the cloud, and often each deployment uses a proprietary data format,” said Manish Chawla, global managing director, energy, resources and manufacturing, IBM. “This means that rather than using all of that collective data to gather insights, augment operations and inform innovation, some of it was going unused. Our collaboration with Amazon Web Services is addressing the need to make it easier for energy customers to access their data and provides the industry with a flexible solution to meet the challenges of today, as well as more easily adapt as the industry evolves.”
This collaboration underscores the value of IBM and Red Hat to provide flexibility and unlock greater business value for operational data across industries.
Those attending the ADIPEC Exhibition and Conference are encouraged to attend a joint, fireside session hosted at the AWS booth, Abu Dhabi Convention Centre, Hall 13, AWS booth #13360, on Monday, Nov. 15th 12:30pm – 1:00pm GMT +4. AWS and IBM will further discuss this collaboration and meeting the challenges of the industry.
About IBM
IBM combines technology with industry expertise to help Oil & Gas clients digitally reinvent their businesses for resilience and sustainability. Pioneering advances in materials science from IBM Research accelerate energy transition. Data science and AI take the guesswork out of exploration. Predictive asset management raises production throughput. Supply chain insights and blockchain build trust and transparency across the downstream ecosystem. Customer experience experts reshape consumer connections at the gas pump or electric charge station. Through these solutions IBM helps Oil & Gas clients emerge smarter. For further information visit: https://www.ibm.com/industries/oil-gas
Red Hat, the Red Hat logo and OpenShift are trademarks or registered trademarks of Red Hat, Inc. or its subsidiaries in the U.S. and other countries.
IBM’s statements regarding its plans, directions, and intent are subject to change or withdrawal without notice at IBM’s sole discretion. Information regarding potential future products is intended to outline our general product direction and it should not be relied on in making a purchasing decision. The information mentioned regarding potential future products is not a commitment, promise, or legal obligation to deliver any material, code or functionality. Information about potential future products may not be incorporated into any contract. The development, release, and timing of any future features or functionality described for our products remains at our sole discretion.
Contact: Allison Bishop, allison.bishop@ibm.com
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INEOS today announced that it has agreed to acquire a strong portfolio of natural gas assets in the North Sea from a UK subsidiary of DEA Deutsche Erdoel AG, which is part of the LetterOne Group.
INEOS Upstream will acquire gas fields, including the Breagh and Clipper South fields in the Southern North Sea which are well positioned close to INEOS’ sites in the North East and Scotland. The annual production from these fields account for 8% of the UK’s annual gas production, enough gas to warm 1 in 10 British homes.
INEOS is a new entrant to the North Sea. However, the company has extensive experience in operating chemical plants of similar complexity to these offshore platforms.
As one of the world’s largest operators of chemical plants and a huge consumer of hydrocarbons these assets should make a significant contribution to INEOS’s European energy and feedstock strategy.
The company operates Scotland’s largest manufacturing complex at Grangemouth which is the only refining / petrochemicals complex directly attached to the North Sea.
INEOS has recently announced its intention to be the leading UK player in onshore gas development and, as part of the company’s growing interest in energy production, is now evaluating additional opportunities in the offshore area.
As part of the company’s ongoing business planning, it has set up INEOS Upstream, a new oil and gas subsidiary of INEOS AG and is working with a number of top class North Sea oil and gas professionals. Their first task has been to conduct a strategic review of the potential opportunities in the North Sea to see whether these are suitable to play a part in the development of the INEOS Upstream business.
Rob Nevin, Chairman INEOS Upstream, says, “INEOS and its JV partners are huge consumers of natural gas, ethane, propane and condensates. North Sea oil and gas can make a significant contribution to providing these feedstocks as well as servicing our energy needs.”
INEOS also owns a number of Shale gas licences in England and Scotland and is investing a further $1 billion in an ambitious project to bring US Shale gas to the UK and to Norway.
Jim Ratcliffe, INEOS chairman adds, “The acquisition of these North Sea gas fields is a great entry point for the INEOS Upstream business. They are high quality, low risk assets and they come with a highly experienced management team. Whilst no decisions have yet been made, we will continue to evaluate other opportunities in the North Sea”.
The twelfth meeting of the energy dialogue between the European Union (EU) and the Organization of the Petroleum Exporting Countries (OPEC) took place in Vienna, Austria.
The EU delegation was headed by Miguel Arias Cañete, Commissioner for Climate Action & Energy at the European Commission. The OPEC delegation was led by Abdalla Salem El-Badri, Acting Secretary General of OPEC.
Both parties emphasised that the Energy Dialogue has come a long way since its establishment in 2005 and is more important than ever in the current context of energy markets. Supported by various roundtables, workshops and studies, the Energy Dialogue has resulted in productive joint activities on a wide range of oil and energy related issues and has brought significant benefits to both sides.
The parties noted that since the last Energy Dialogue meeting in June 2014, there has been a growing challenge in energy markets, particularly for oil. Oil prices have fallen by more than 70%, many investments have been deferred or cancelled, manpower has been laid off, and the market has been searching for a supply-demand balance.
Looking ahead, both the EU and OPEC noted with concern that the current price environment has considerably reduced investments. Such a massive fall in investment could in time lead to a supply shortfall and the risk of a sharp oil price rebound, as has been witnessed in the past.
Although producers and consumers might have different views on what is an adequate oil price level, there was broad agreement that excessive oil price volatility and/or sharp price rises would be harmful for the economies of both the producing and consuming countries. An affordable and stable oil price, alongside a balanced and stable market, is a prerequisite for economic growth for both producers and consumers.
Both the EU and OPEC recognised that through the Energy Dialogue and through initiatives in other global fora and organisations, cooperation should be enhanced, as should understanding of the behaviour of energy and oil markets, something which is important to helping achieve future oil market stability.
The adoption in December 2015 of the ‘Paris Agreement’ to combat climate change was welcomed by both sides.
OPEC presented an assessment of short-term oil market prospects. It emphasised that lower crude oil prices mainly reflect the ongoing excess crude oil supply over global demand. The positive impacts of low oil prices on oil demand in major growth regions remain intact in both the OECD and non-OECD regions. Expected oil demand growth in 2016 is in line with the average seen over the last three years. On the supply side, lower oil prices have reversed the strong growth trend in non-OPEC supply into an expected contraction in 2016. It was noted however, that over the previous three years, non-OPEC supply has increased significantly while on average there was no growth in OPEC crude supply.
OPEC also provided an overview of the long-term oil market outlook. It highlighted that energy demand will increase by almost 50% in the period up to 2040, with oil remaining the fuel with the largest share over the next 20 years. Oil demand reaches almost 110 mb/d by 2040, with developing countries accounting for most of the growth. On the supply side, total non-OPEC supply is expected to increase in the next decade, but declines towards the end of the projection period. OPEC crude supply is anticipated to increase steadily which underscores once again the need for future investments in the industry. However, it was stressed that the Outlook is clouded with uncertainties stemming, in particular, from economic growth and non-OPEC supply prospects.
The EU side presented the latest developments in EU energy policies, focusing on the Communication on the State of the Energy Union of November 2015 and the ‘Security of Supply Package’ adopted by the Commission on 16 February 2016. The package includes initiatives to foster the EU energy security, notably two proposals for the revision of the Regulation on Security of Gas Supply and for a revision of the Decision on Intergovernmental Agreements as well as strategies for LNG & gas storage and for heating & cooling.
The main energy policy initiatives foreseen for 2016 were also presented. Emphasis was given to a package, to be adopted later this year, which will propose initiatives in the energy efficiency sector. Energy efficiency will be a key tool to achieve EU’s decarbonisation objectives and for a more sustainable use of energy. The EU expressed its willingness and availability to share its experience in the area of energy efficiency with the OPEC partners in the framework of the current energy dialogue or in other fora.
The EU side also presented the economic developments and outlook in the EU and in the euro area based on the latest European economic forecasts issued on 4 February 2016. The European economy has now entered its fourth year of recovery and growth is expected to continue increasing at a moderate pace, driven mainly by rising consumption.
The ongoing and future activities of the Energy Dialogue were also discussed. These included a report on a roundtable that discussed the outcomes of a joint study on the ‘Petrochemical Outlook: Challenges and Opportunities’. There was an update on a joint study being undertaken on the prospects for non-crude liquids.
All participants expressed satisfaction with the outcome of the meeting, which was seen as a further important step in the EU-OPEC Energy Dialogue. Both parties expressed their strong commitment to that process, and agreed that the next EU-OPEC Energy Dialogue meeting would take place in the first half of 2017.
MEXICO CITY & NEW YORK– KKR, a leading global investment firm, today announced a new joint venture with Monterra Energy (“Monterra”) to pursue investments in the midstream energy sector in Mexico. Under the agreement, KKR is making an equity commitment to Monterra for the development of new projects and acquisition of midstream assets and businesses. Financial terms and details of the partnership were not disclosed.
Monterra was founded in 2014 by Arturo Vivar and Michael A. Williams to pursue select investment opportunities in the midstream sector in Mexico. With offices in Houston, Texas and Mexico City, Monterra has a proven management team and highly experienced, local advisory board members with success across North and South America in the areas of upstream, midstream and oilfield services.
“Monterra is excited to partner with KKR,” said Arturo Vivar, CEO of Monterra. “Together with KKR and its investment expertise, Monterra will provide a differentiated set of capabilities that can be applied to the development and operation of strategic midstream projects and assets in Mexico.”
Tudor, Pickering, Holt and Co. estimates that Mexico should attract approximately $50 billion and $13 billion in capital expenditures spending for pipeline infrastructure and power generation, respectively, over the next five years.
Monterra intends to own, develop, build and operate midstream infrastructure in Mexico through both new (greenfield) and existing (brownfield) projects and assets. Primary areas of focus include terminaling and storage infrastructure for refined products, crude oil and natural gas liquids (NGLs) as well as pipeline and rail logistics assets to transport and handle refined products, crude oil and NGLs. Other areas of interest may include natural gas transportation and storage and power generation.
Commenting on the partnership, Marc Lipschultz, Global Head of KKR’s Energy and Infrastructure business, said: “This partnership is about backing a strong team with decades of experience in the energy sector and in Latin America to deliver superior solutions to Mexico’s growing energy sector. We look forward to working with the Monterra team.”
Jorge Fergie, KKR’s Head of Brazil and Latin America, added: “We are very optimistic when it comes to the macroeconomic landscape in Mexico, and we continue to believe the country has significant opportunities – in energy and beyond – for long term investment.”
KKR has a depth of experience investing in energy and in businesses that operate in Mexico. KKR’s contributions to the joint venture will be funded primarily from KKR’s North America XI Fund. KKR’s Global Energy & Infrastructure business invests across the entire energy supply chain and the firm manages approximately $10 billion in energy and infrastructure related assets. The Firm also has a global private equity portfolio that includes multiple companies that together employ over 10,000 employees in Mexico, including Aceco TI, Capsugel, First Data, Laureate Education, Lake Region Medical, Nielsen, and PRA Health Sciences.
About KKR
KKR is a leading global investment firm that manages investments across multiple asset classes including private equity, energy, infrastructure, real estate, credit and hedge funds. KKR aims to generate attractive investment returns by following a patient and disciplined investment approach, employing world‐class people, and driving growth and value creation at the asset level. KKR invests its own capital alongside its partners’ capital and brings opportunities to others through its capital markets business. References to KKR’s investments may include the activities of its sponsored funds. For additional information about KKR & Co. L.P. (NYSE:KKR), please visit KKR’s website at www.kkr.com.
The development of the largest new field discovered in the UK North Sea for a decade* has been approved by the UK Oil & Gas Authority. The Maersk Oil operated high pressure, high temperature (HPHT) Culzean field in the UK Central North Sea is expected to produce enough gas to meet 5% of total UK demand at peak production in 2020/21. Culzean is also the largest gas field sanctioned since East Brae in 1990*.
Discovered in 2008 by Maersk Oil and its co-venturers, the gas condensate field has resources estimated at 250-300 million barrels of oil equivalent. Production is expected to start in 2019 and continue for at least 13 years, with plateau production of 60,000-90,000 barrels of oil equivalent per day.
Maersk Oil and its co-venturers, JX Nippon and BP (Britoil) are investing around £3bn (USD 4.5 bn) in the development, with more than 50% committed to investments in the UK. Over the projected life of the field, it’s anticipated that £2.1bn (USD 3.3 bn) in operating expenditure will be spent in the UK domestic market. The Culzean field aligns with the UK’s commitment to increased gas-fired electricity generation and is expected to support an estimated 6,000 UK jobs and create more than 400 direct jobs.
The Culzean development has benefited from the HPHT Cluster Area Allowance introduced by the UK Government as part of the 2015 Budget. The allowance supports the development of high pressure, high temperature projects – which typically have considerably higher capital costs – and encourages exploration and appraisal activity in the surrounding area or ‘cluster’.
Welcoming today’s announcement, Jakob Thomasen, CEO of Maersk Oil said, “Culzean is an important development for the UK and also for Maersk Oil and our co-venturers. We are pleased the field will support UK economic growth as well as extend understanding of HPHT development. Culzean is the latest in a series of large investments by Maersk Oil in the North Sea where we are active in Denmark, Norway and the UK – reflecting our commitment to the future of the North Sea region.”
The Chancellor of the Exchequer, Rt Hon George Osborne MP said, “Today’s announcement sends a clear signal that the North Sea is open for business. Already the UK’s oil and gas industry supports hundreds of thousands of jobs across the country and this £3 billion investment comes on the back of massive government support for the sector. “Despite challenging times, this government has backed the oil and gas industry at every turn, introducing a vital package of support to help it to protect and create jobs.
Andy Samuel, Chief Executive of the Oil & Gas Authority said, ”Maersk Oil and partners’ £3 billion investment to develop the Culzean discovery is excellent news for the UK during a period when the decline in global oil prices has created difficult operating conditions for this critical sector of our economy. The Oil & Gas Authority has worked closely with Maersk Oil and HM Treasury on the development plans for the Culzean field, which will support many new contracts in the oil and gas supply chain across the UK.”
STAVANGER, NORWAY –When iconic innovator and GE founder, Thomas Edison, said “I find out what the world needs. Then I go ahead and try to invent it,” little did he realize that, many decades later, the business would continue to heed this philosophy.
Today, GE Oil & Gas’ (NYSE: GE) engineers and technologists remain firmly in agreement that, through technology, expertise, innovation and working closely with their customers, they can develop solutions to meet the ever more challenging operational environments that are characteristic of today’s exploration and production (E&P) activity.
This was the overarching message at the launch of GE’s Deepwater Vertical Xmas Tree (DVXT), unveiled today at the company’s new, interactive Technology Solutions Center in Stavanger, in conjunction with the Offshore Northern Seas (ONS) 2014 conference and exhibition.
The latest addition to GE Oil & Gas’ comprehensive range of subsea products is rated for depths of up to 3,000m and expands the company’s portfolio of pre-engineered, pre-qualified modular systems, designed to enable products to be brought to market faster.
“There is a rising sense in the oil and gas industry that many of the challenges faced today can be addressed by leveraging standardized products and solutions in order to simplify processes and reduce lead times,” said Chris Phebus, Engineering Executive for Subsea Systems at GE Oil & Gas. “By offering our DVXT as a standard product, we can not only improve cycle times, but also ensure the highest levels of quality, safety and reliability for our products.”
Deployed with the company’s next-generation remote electronics canister—the SemStar5-R—the DVXT incorporates the latest in communication technology and is designed with the objectives of higher subsea reliability, extended service life and improved environmental monitoring. Already a market leader with communications out to 220km, at depths of up to 3,000m, the ModPod subsea control module is designed to complement the DVXT’s modular layout and enables an even more flexible communications network—a key ingredient for future field expansion and enhanced access to remote wells.
Mike Wenham, Subsea Trees Senior Application Engineer, GE Oil & Gas, said: “Just a few decades ago, the idea of producing oil at depths of more than just a few hundred feet would have been unthinkable. Now, the ocean’s depths are the key to meeting the rising global demand for energy in this age of complex fuel. As an industry, we need to make sure we stay focused on both the future and the now, working to address the challenges of deepwater development.
“The launch of our new DVXT is a great example of this, providing customers with a leading-edge production system that enhances our subsea trees portfolio to meet current and future needs, and enabling us to offer the industry a tree to meet any of its challenges, regardless of depth.”
GE Oil & Gas is exhibiting in Hall D, Booth #454 during ONS2014. For more information about the company’s new Technology Solutions Center, opened by GE Oil & Gas President and CEO, Lorenzo Simonelli, on August 25, use the GE Newsroom.
About GE
GE (NYSE: GE) works on things that matter. The best people and the best technologies taking on the toughest challenges. Finding solutions in energy, health and home, transportation and finance. Building, powering, moving and curing the world. Not just imagining. Doing. GE works. For more information, visit the company’s website at www.ge.com.
About GE Oil & Gas
GE Oil & Gas works on the things that matter in the oil and gas industry. In collaboration with our customers, we push the boundaries of technology to bring energy to the world. From extraction to transportation to end use, we address today’s toughest challenges in order to fuel the future. Follow GE Oil & Gas on Twitter @GE_OilandGas.
