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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.

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.

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.

The Conference reviewed the oil market outlook, as presented by the Secretary General, in particular supply/demand projections for the first, second, third and fourth quarters of 2015, with emphasis on the first half of the year. The Conference also considered forecasts for the world economic outlook and noted that the global economic recovery was continuing, albeit very slowly and unevenly spread, with growth forecast at 3.2% for 2014 and 3.6% for 2015.

The Conference also noted, importantly, that, although world oil demand is forecast to increase during the year 2015, this will, yet again, be offset by the projected increase of 1.36 mb/d in non-OPEC supply. The increase in oil and product stock levels in OECD countries, where days of forward cover are comfortably above the five-year average, coupled with the on-going rise in non-OECD inventories, are indications of an extremely well-supplied market.

Recording its concern over the rapid decline in oil prices in recent months, the Conference concurred that stable oil prices – at a level which did not affect global economic growth but which, at the same time, allowed producers to receive a decent income and to invest to meet future demand – were vital for world economic wellbeing. Accordingly, in the interest of restoring market equilibrium, the Conference decided to maintain the production level of 30.0 mb/d, as was agreed in December 2011. As always, in taking this decision, Member Countries confirmed their readiness to respond to developments which could have an adverse impact on the maintenance of an orderly and balanced oil market.

Agreeing on the need to be vigilant given the uncertainties and risks associated with future developments in the world economy, the Conference directed the Secretariat to continue its close monitoring of developments in supply and demand, as well as non-fundamental factors such as speculative activity, keeping Member Countries fully briefed on developments.

The Conference appointed Dr. Bernard Mommer, Venezuelan Governor for OPEC, as Chairman of the Board of Governors for the year 2015, and Mr. Ahmed Messili, Algerian Governor for OPEC, as Alternate Chairman for the same period, with effect from 1st January 2015.

The Conference decided to extend the tenure of HE Abdalla S. El-Badri as Secretary General for a further period of six months, until 31st December 2015.

The Conference approved the Budget of the Organization for the year 2015.

The Conference resolved that its next Ordinary Meeting will convene in Vienna, Austria, on Friday, 5th June 2015, immediately after the OPEC International Seminar on “Petroleum: An Engine for Development” which will take place at the Vienna Hofburg Palace on 3rd and 4th June 2015.

LAGOS, NIGERIA— —After nearly four years of planning and investing more than $4.5 million in facilities, recruitment and training, GE Oil & Gas (NYSE: GE) has added the capability to fabricate subsea wellheads in Nigeria for its oil and gas customers. The announcement was made in Lagos by Uzo Nwagwu, chief operating officer for GE Oil & Gas in Nigeria.

This is a major milestone for GE Oil & Gas in the company’s efforts to substantially increase the local capabilities of its operations in Nigeria through ambitious technology programs and workforce development. With this achievement, GE’s customers operating in Nigeria no longer need to import these fabricated wellheads, thereby reducing costs and improving delivery time.

The new wellhead production capabilities at GE’s existing Onne facility in River State align with the Nigerian federal government’s local content law and desire for increased manufacturing capacity, skill acquisition and technology transfer. However, for GE, this milestone represents significantly more than complying with local content laws.

“GE Oil & Gas has a vision to ‘Fuel the Future’ by delivering cost-effective customer solutions on time wherever they are needed across the globe,” said GE’s Uzo Nwagwu. “By investing now in the development of our people and facilities, we are able to localize subsea wellhead assembly and partner with local suppliers to create a more sustainable business for Nigeria.”

Nwagwu referred to the establishment of the subsea wellhead fabrication capabilities in Onne as “a true win-win proposition for the indigenous industry and the Nigerian content agenda.”

GE’s Onne facility in River State has been operating since 2002. This purpose-built facility is the first and only portside facility of its caliber in Nigeria and employs more than 200 people. It has an exceptional safety record and is a cornerstone in GE’s commitment to the country’s oil and gas industry. With continually expanding capabilities, the site provides complete assembly, testing and life cycle service for subsea tree systems, subsea control modules, specialty connectors and pipe. It also includes a dedicated on-site training center and offers broad business development opportunities for local suppliers.

GE spends $11 million annually to service facilities in Onne and Port Harcourt and is investing $250 million in manufacturing and assembly facilities in Calabar, Cross River State by 2018. This $250 million investment is expected to create 2,300 jobs in the local economy. An additional $750 million will be allocated to sourcing local supplies and employee training in the surrounding communities as well as expanding GE’s service facility in Onne.

GE has been operating in Nigeria for more than 40 years, with businesses spanning a number of key sectors including aviation, power generation, oil and gas, healthcare and transportation. In the past three years, there has been a renewed focus on the country with an eye on new service facilities and employment of more local talent to expand the company’s capabilities. GE’s portfolio of technology solutions is well aligned with Nigeria’s infrastructure needs and is contributing to economic development and improved quality of life in the region.

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.

The global energy system is in danger of falling short of the hopes and expectations placed upon it. Turmoil in parts of the Middle East – which remains the only large source of low-cost oil – has rarely been greater since the oil shocks in the 1970s. Conflict between Russia and Ukraine has reignited concerns about gas security. Nuclear power, which for some countries plays a strategic role in energy security (and which is examined in depth in this edition of the World Energy Outlook [WEO-2014]), faces an uncertain future. Electricity remains inaccessible to many people, including two out of every three people in sub-Saharan Africa (the regional focus in WEO-2014). The point of departure for the climate negotiations, due to reach a climax in 2015, is not encouraging: a continued rise in global greenhouse-gas emissions and stifling air pollution in many of the world’s fast-growing cities.

Advances in technology and efficiency give some reasons for optimism, but sustained political efforts will be essential to change energy trends for the better. Signs of stress would be much more serious, were it not for improvements in efficiency and continuous efforts to innovate and reduce the cost of emerging energy technologies, such as solar photovoltaics (PV). But global energy trends are not easily changed and worries over the security and sustainability of energy supply will not resolve themselves. Actions from well-informed policy-makers, industry and other stakeholders are needed. WEO-2014, with projections and analysis extended to 2040 for the first time, provides insights that can help
to ensure that the energy system is changed by design, rather than just by events.

Energy: the answer to – and the cause of – some urgent problems
Global energy demand is set to grow by 37% by 2040 in our central scenario, but the development path for a growing world population and economy is less energy-intensive than it used to be. In our central scenario, growth in global demand slows markedly, from above 2% per year over the last two decades to 1% per year after 2025; this is a result both of price and policy effects, and a structural shift in the global economy towards services and lighter industrial sectors. The global distribution of energy demand changes more dramatically, with energy use essentially flat in much of Europe, Japan, Korea and North America, and rising consumption concentrated in the rest of Asia (60% of the global
total), Africa, the Middle East and Latin America. A landmark is reached in the early 2030s, when China becomes the largest oil-consuming country, crossing paths with the United States, where oil use falls back to levels not seen for decades. But, by this time, it is India,
Southeast Asia, the Middle East and sub-Saharan Africa that take over as the engines of global energy demand growth.

By 2040, the world’s energy supply mix divides into four almost-equal parts: oil, gas, coal and low-carbon sources. Resources are not a constraint over this period, but each of these four pillars faces a distinct set of challenges. Policy choices and market developments that
bring the share of fossil fuels in primary energy demand down to just under three-quarters in 2040 are not enough to stem the rise in energy-related carbon dioxide (CO2) emissions, which grow by one-fifth. This puts the world on a path consistent with a long-term global average temperature increase of 3.6 °C. The Intergovernmental Panel on Climate Change estimates that in order to limit this temperature increase to 2 °C – the internationally agreed goal to avert the most severe and widespread implications of climate change – the world cannot emit more than around 1 000 gigatonnes of CO2 from 2014 onwards. This entire budget will be used up by 2040 in our central scenario. Since emissions are not going to drop suddenly to zero once this point is reached, it is clear that the 2 °C objective requires urgent action to steer the energy system on to a safer path. This will be the focus of a WEO Special Report, to be released in mid-2015 in advance of the critical UN climate talks in Paris.

Energy security concerns on the rise
The short-term picture of a well-supplied oil market should not disguise the challenges that lie ahead as reliance grows on a relatively small number of producers. Regional oil demand trends are quite distinct: for each barrel of oil no longer used in OECD countries, two barrels more are used in the non-OECD. Increased oil use for transport and petrochemicals drives demand higher, from 90 million barrels per day (mb/d) in 2013 to 104 mb/d in 2040, although high prices and new policy measures gradually constrain the pace of overall consumption growth, bringing it towards a plateau. Investment of some $900 billion per year in upstream oil and gas development is needed by the 2030s to meet projected demand, but there are many uncertainties over whether this investment will be forthcoming in time – especially once United States tight oil output levels off in the early 2020s and its total production eventually starts to fall back. The complexity and capital-intensity of developing Brazilian deepwater fields, the difficulty of replicating the US tight oil experience at scale outside North America, unresolved questions over the outlook for growth in Canadian oil sands output, the sanctions that restrict Russian access to technologies and capital markets and – above all – the political and security challenges in Iraq could all contribute to a shortfall in investment below the levels required. The situation
in the Middle East is a major concern given steadily increasing reliance on this region for oil production growth, especially for Asian countries that are set to import two out of every three barrels of crude traded internationally by 2040.

Demand for natural gas grows by more than half, the fastest rate among the fossil fuels, and increasingly flexible global trade in liquefied natural gas (LNG) offers some protection against the risk of supply disruptions. The main regions that push global gas demand higher are China and the Middle East, but gas also becomes the leading fuel in the OECD energy mix by around 2030, helped by new regulations in the United States limiting power sector emissions. In contrast to oil, gas production increases almost everywhere (Europe is the main exception) and unconventional gas accounts for almost 60% of global supply growth. The key uncertainty – outside North America – is whether gas can be made
available at prices that are attractive to consumers while still offering incentives for the necessary large capital-intensive investments in gas supply; this is an issue of domestic regulation in many of the emerging non-OECD markets, notably in India and across the Middle East, as well as a concern in international trade. Import needs are set to rise across much of Asia as well as in Europe, but concerns about the security of future gas supply are allayed in part by a growing cast of international gas suppliers, a near-tripling of global liquefaction sites and a rising share of LNG that can be re-directed in response to the short-term needs of increasingly interconnected regional markets.
While coal is abundant and its supply secure, its future use is constrained by measures to tackle pollution and reduce CO2 emissions. Global coal demand grows by 15% to 2040, but almost two-thirds of the increase occurs over the next ten years. Chinese coal demand plateaus at just over 50% of global consumption, before falling back after 2030. Demand declines in the OECD, including the United States, where coal use for electricity generation plunges by more than one-third. India overtakes the United States as the world’s second-biggest coal consumer before 2020, and soon after surpasses China as the largest importer. Current low coal prices have put pressure on producers worldwide to cut costs, but the shedding of high-cost capacity and demand growth are expected to support an increase in price sufficient to attract new investment. China, India, Indonesia and Australia alone account for over 70% of global coal output by 2040, underscoring Asia’s importance in coal markets. Adoption of high-efficiency coal-fired generation technologies, and of carbon capture and storage in the longer term, can be a prudent strategy to ensure a smooth transition to a low carbon power system, while reducing the risk that capacity is idled before recovering its investment costs.

Prices and policies have to be right to get more efficiency into the mix
Energy efficiency is a critical tool to relieve pressure on energy supply and it can also mitigate in part the competitive impacts of price disparities between regions. A renewed policy focus on efficiency is taking hold in many countries and the transport sector is in the front line. With more than three-quarters of global car sales now subject to efficiency standards, oil transport demand is expected to rise by only one-quarter despite the number of cars and trucks on the world’s roads more than doubling by 2040. New efficiency efforts have the effect of suppressing total oil demand growth by an estimated 23 mb/d in 2040 – more than current oil production of Saudi Arabia and Russia combined – and measures mainly in power generation and industry hold the growth in gas demand back by 940 billion cubic metres, more than current gas output in
North America. Aside from reducing energy-import bills and environmental impacts, efficiency measures can also help in part to address the concern, felt in some import-dependent regions, that relatively high prices for natural gas and electricity put their energy-intensive industries at a competitive disadvantage. But regional energy price disparities are set to persist and North America, in particular, remains a relatively low-cost region through to 2040: the average amount spent on a unit of energy in the United States is expected even to fall below that of China in the 2020s.

Fossil-fuel subsidies totalled $550 billion in 2013 – more than four-times those to renewable energy – and are holding back investment in efficiency and renewables. In the Middle East, nearly 2 mb/d of crude oil and oil products are used to generate electricity when, in the absence of subsidies, the main renewable energy technologies would be competitive with oil-fired power plants. In Saudi Arabia, the additional upfront cost of a car twice as fuel-efficient as the current average would, at present, take about 16 years to recover through lower spending on fuel: this payback period would shrink to 3 years if gasoline were not subsidised. Reforming energy subsidies is not easy and there is no
single formula for success. However, as our case studies of Egypt, Indonesia and Nigeria show, clarity over the objectives and timetable for reform, careful assessment of the effects and how they can (if necessary) be mitigated, and thorough consultation and good communication at all stages of the process are essential.

Power sector is leading the transformation of global energy
Electricity is the fastest-growing final form of energy, yet the power sector contributes more than any other to the reduction in the share of fossil fuels in the global energy mix. In total, some 7 200 gigawatts (GW) of capacity needs to be built to keep pace with increasing electricity demand while also replacing existing power plants due to retire by 2040 (around 40% of the current fleet). The strong growth of renewables in many countries raises their share in global power generation to one-third by 2040. Adequate price signals will be needed to ensure timely investments in the new thermal generation capacity, which is necessary, alongside investment in renewables, to maintain the reliability of electricity supply. This will require reforms to market design or electricity pricing in some cases. The shift towards more capital-intensive technologies and high fossil fuel prices lead to increasing average electricity supply costs and end-user prices in most countries in the
world. However, end-use efficiency gains help reduce the proportion of household income spent on electricity.

Renewable energy technologies, a critical element of the low-carbon pillar of global energy supply, are rapidly gaining ground, helped by global subsidies amounting to $120 billion in 2013. With rapid cost reductions and continued support, renewables account for almost half of the increase in total electricity generation to 2040, while use of biofuels more than triples to 4.6 mb/d and the use of renewables for heat more than doubles. The share of renewables in power generation increases most in OECD countries, reaching 37%, and their growth is equivalent to the entire net increase in OECD electricity supply. However, generation from renewables grows more than twice as much in non-OECD countries, led by
China, India, Latin America and Africa. Globally, wind power accounts for the largest share of growth in renewables-based generation (34%), followed by hydropower (30%) and solar technologies (18%). As the share of wind and solar PV in the world’s power mix quadruples,
their integration both from a technical and market perspective becomes more challenging, with wind reaching 20% of total electricity generation in the European Union and solar PV accounting for 37% of summer peak demand in Japan.

A complex set of elements in decision-making on nuclear power
Policies concerning nuclear power will remain an essential feature of national energy strategies, even in countries which are committed to phasing out the technology and that must provide for alternatives. Global nuclear power capacity increases by almost 60% in our central scenario, from 392 GW in 2013 to over 620 GW in 2040. However, its share of global electricity generation, which peaked almost two decades ago, rises by just one percentage point to 12%. This pattern of growth reflects the challenges facing all types of new thermal generation capacity in competitive power markets and the specific suite of other economic, technical and political challenges that nuclear power has to
overcome. Growth is concentrated in markets where electricity is supplied at regulated prices, utilities have state backing or governments act to facilitate private investment.

Of the growth in nuclear generation to 2040, China accounts for 45% while India, Korea and Russia collectively make up a further 30%. Generation increases by 16% in the United States, rebounds in Japan (although not to the levels prior to the accident at Fukushima Daiichi) and falls by 10% in the European Union. Despite the challenges it currently faces, nuclear power has specific characteristics that
underpin the commitment of some countries to maintain it as a future option. Nuclear plants can contribute to the reliability of the power system where they increase the diversity of power generation technologies in the system. For countries that import energy, it can reduce their dependence on foreign supplies and limit their exposure to fuel price movements in international markets. In a Low Nuclear Case – in which global capacity drops by 7% compared with today – indicators of energy security tend to deteriorate in countries that utilise nuclear power. For example, the share of energy demand met from domestic sources is reduced in Japan (by 13 percentage points), Korea (by six) and the European Union (by four) relative to our central scenario.

Nuclear power is one of the few options available at scale to reduce carbon-dioxide emissions while providing or displacing other forms of baseload generation. It has avoided the release of an estimated 56 gigatonnes of CO2 since 1971, or almost two years of total global emissions at current rates. Annual emissions avoided in 2040 due to nuclear power (as a share of projected emissions at that time) reach almost 50% in Korea, 12% in Japan, 10% in the United States, 9% in the European Union and 8% in China. The average cost of avoiding emissions through new nuclear capacity depends on the mix and the costs of the fuels it displaces, and therefore ranges from very low levels to over $80/tonne.

Almost 200 reactors (of the 434 operational at the end of 2013) are retired in the period to 2040, with the vast majority in Europe, the United States, Russia and Japan; the challenge to replace the shortfall in generation is especially acute in Europe. Utilities need
to start planning either to develop alternative capacity or to continue operating existing plants years in advance of nuclear plants reaching the end of their current licence periods. To facilitate this process, governments need to provide clarity on their approach to licence
extensions and details of the regulatory steps involved well ahead of possible plant closures. We estimate the cost of decommissioning nuclear plants that are retired in the period to 2040 at more than $100 billion. Considerable uncertainties remain about these costs,
reflecting the relatively limited experience to date in dismantling and decontaminating reactors and restoring sites for other uses. Regulators and utilities need to continue to ensure adequate funds are set aside to cover these future expenses.

Public concerns about nuclear power must be heard and addressed. Recent experience has shown how public views on nuclear power can quickly shift and play a determining role in its future in some markets. Safety is the dominant concern, particularly in relation to operating reactors, managing radioactive waste and preventing the proliferation of nuclear weapons. Confidence in the competence and independence of regulatory oversight is essential, especially as nuclear power spreads: in our central scenario, the number of economies operating reactors rises from 31 to 36 as newcomers outnumber those that phase out nuclear power. The cumulative total of spent nuclear fuel doubles to more than 700 thousand tonnes over the projection period, but, to date, no country has opened a permanent disposal facility to isolate the most long-lived and highly radioactive waste produced by commercial reactors. All countries that have ever produced radioactive waste should have an obligation to develop a solution for permanent disposal.

Power to shape the future in sub-Saharan Africa
Those who have no access to modern energy suffer from the most extreme form of energy insecurity. An estimated 620 million people in sub-Saharan Africa do not have access to electricity, and for those that do have it, supply is often insufficient, unreliable and among the most costly in the world. Around 730 million people in the region rely on solid biomass for cooking, which – when used indoors with inefficient cookstoves – causes air pollution that results in nearly 600 000 premature deaths in Africa each year. Sub-Saharan Africa accounts for 13% of the global population, but only 4% of global energy demand (more than half of which is solid biomass). The region is rich in energy resources, but they are
largely undeveloped. Almost 30% of global oil and gas discoveries made over the last five years were in the region, and it is also endowed with huge renewable energy resources, especially solar and hydro, as well as wind and geothermal.

The sub-Saharan energy system is set to expand rapidly but, even so, many of the existing energy challenges will be only partly overcome. By 2040, the region’s economy quadruples in size, the population nearly doubles and energy demand grows by around 80%. Power generation capacity quadruples and almost half of the growth in generation comes from renewables, which also increasingly provide the source of power for mini- and off-grid systems in rural areas. Overall, nearly one billion people gain access to electricity, but more than half a billion still remain without it in 2040. Output from Nigeria, Angola and a host of smaller producers means that sub-Saharan Africa remains an important centre of global oil supply – although an increasing share of output is consumed within the region. The region emerges also as an important player in gas, as development of the major east coast discoveries off Mozambique and Tanzania accompanies increased production in Nigeria and elsewhere.

Sub-Saharan Africa’s energy sector can do more to support inclusive growth. In an “African Century Case”, three actions in the energy sector – if accompanied by more general governance reforms – boost the sub-Saharan economy by a further 30% in 2040, delivering an extra decade’s worth of growth in per-capita incomes:
 An upgraded power sector: additional investment that reduces power outages by half and achieves universal electricity access in urban areas.
 Deeper regional co-operation: expanding markets and unlocking a greater share of the continent’s hydropower potential.
 Better management of energy resources and revenues: more efficiency and transparency in financing essential improvements to Africa’s infrastructure.
A modern and integrated energy system allows for more efficient use of resources and brings energy to a greater share of the poorest parts of sub-Saharan Africa. Concerted action to improve the functioning of the energy sector is essential if the 21st is to become an African century.

This report is courtesy of www.iea.org

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.

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.

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.

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.

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.

Royal Dutch Shell plc (“Shell”) announces today two separate transactions whereby the company will exit its Pinedale and Haynesville onshore gas assets in exchange for approximately $2.1 billion of cash, plus additional acreage in the Marcellus and Utica Shale areas in Pennsylvania.
In one agreement with Ultra Petroleum, Shell will acquire 155,000 net acres in the Marcellus and Utica Shale areas in Pennsylvania and receive a cash payment of $0.925 billion from Ultra in exchange for 100 percent of Shell’s Pinedale asset in Wyoming, including associated gathering and processing contracts, subject to closing.

In a separate agreement with Vine Oil & Gas LP and its partner Blackstone, Shell has agreed to sell 100 percent of its Haynesville asset in Louisiana, including associated field facilities and infrastructure for $1.2 billion in cash, subject to closing.

“We continue to restructure and focus our North America shale oil and gas portfolio to deliver the most value in the longer term. With this announcement we are adding highly attractive exploration acreage, where we have impressive well results in the Utica, and divesting our more mature, Pinedale and Haynesville dry gas positions,” said Marvin Odum, Shell’s Upstream Americas Director.

The Shell net production from Pinedale in the second quarter 2014 was 190 million standard cubic feet per day (mmscf/d) of dry gas (32 thousand barrels of oil equivalent per day (kboe/d)). During the first half of 2014, Ultra’s net production from the assets Shell is acquiring in Pennsylvania averaged 109 mmscf/d (19 kboe/d).

“We first entered the Pinedale Anticline in 2001, and I am proud of our operational excellence, community engagement, and leadership in responsible energy development over that time,” said Odum.

Shell’s Pinedale asset (which includes 19,000 net acres of leasehold interest, 1,108 gross wells and associated facilities, and an average of 0.7 percent overriding royalty interest in 11,500 acres) will be exchanged for cash and Ultra’s 100 percent interest in the Marshlands area (63,000 net acres) as well as its entire interest (92,000 net acres) in the Tioga Area of Mutual Interest (AMI), an unincorporated joint venture with Shell. After completion of this transaction, Shell will have a 100 percent interest in the Tioga AMI. The agreement is effective 1 April 2014, and is expected to close this year.

Shell’s Haynesville asset includes 107,000 net acres in in north Louisiana. The transaction includes 418 producing wells, 193 of them operated by Shell. As of 1 July 2014, the gross production from the Haynesville asset was approximately 700 mmscf/d of dry gas, with Shell’s net working interest share at approximately 250 mmscf/d (43 kboe/d). The agreement is effective 1 July 2014, and is expected to close in the fourth quarter of this year.

“We very much appreciate the support we have had in north Louisiana, and we will continue to operate in the state, as we have for decades, through our downstream, retail, midstream, and New Orleans-based deep-water operations,” said Odum.

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

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.

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.

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.

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.

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.

Shell today announces its third major discovery in the Norphlet play in the deep waters of the Gulf of Mexico with the successful Rydberg exploration well. After more than 10 years of exploration activities in the Eastern Gulf of Mexico, Shell continues to lead industry in exploring this Jurassic play.
“The Rydberg discovery builds upon our leadership position in the Eastern Gulf of Mexico and its proximity to our other discoveries in the area make Rydberg particularly exciting.” said Marvin Odum, Shell Upstream Americas Director. “These successes represent the emergence of another hub for Shell’s deep-water activities that should generate shareholder value.”

The Rydberg well is located 75 miles (120 kilometres) offshore in the Mississippi Canyon Block 525 in 7,479 feet (2,280 metres) of water. It was drilled to a total depth of 26,371 feet (8,038 metres) and encountered more than 400 feet (122 metres) of net oil pay.

Shell is completing the full evaluation of the well results but expects the resource base to be approximately 100 million barrels of oil equivalent. Together with the Appomattox and Vicksburg discoveries, this brings the total potential Norphlet discoveries to over 700 million barrels of oil equivalent.

This is the first discovery for the partnership of Shell (operator, interest 57.2%), Ecopetrol America Inc. (28.5%) and Nexen (14.3%), a wholly-owned affiliate of CNOOC Limited. The discovery is within 10 miles (16 kilometres) of the planned Appomattox development and the 2013 Vicksburg discovery (Shell, operator, 75% and Nexen, 25%).

Shell and Nexen are following up the Rydberg discovery with an exploratory well at Gettysburg, located in Desoto Canyon Block 398 which is also within 10 miles (16 kilometres) of the planned Appomattox Development.

The Jurassic-period Norphlet play is a geological formation that extends from onshore to the deep waters of the Eastern Gulf of Mexico.
Appomattox (Shell, operator, 80% and Nexen, 20%) is currently in the define phase of development and is moving forward with engineering design for the floating production system, subsea infrastructure and wells.
The drillship Noble Globetrotter I drilled the Rydberg well and is currently repositioning to drill the Gettysburg exploratory well.
The Gulf of Mexico is a major production area in the USA, accounting for almost 50% of Shell’s oil and gas production in the country and almost 180 thousand boe per day in 2013.

This is courtesy of www.shell.com

HOUSTON, – Phillips 66 (NYSE: PSX), an energy manufacturing and logistics company, has agreed to purchase a 7.1 million-barrel storage capacity terminal located near Beaumont, Texas. The Beaumont Terminal will be the largest terminal in the Phillips 66 portfolio.

“This acquisition supports our midstream growth strategy,” said Tim Taylor, president, Phillips 66. “Given our expectations for increasing volumes of North American crude oil movements into the Gulf Coast region and growth in refined product exports, the Beaumont Terminal is well positioned to serve this growing market while providing significant expansion potential.”

The Beaumont Terminal is strategically located on the U.S. Gulf Coast. It provides deep-water access and multiple interconnections with major crude oil and refined product pipelines serving 3.6 million barrels per day of refining capacity. The terminal also has:

4.7 million barrels of crude oil storage capacity and 2.4 million barrels of refined product storage capacity;
Two marine docks capable of handling Aframax tankers and one barge dock; and
Rail and truck loading and unloading facilities.
The Beaumont Terminal is currently owned by UNOCAL, a member of the Chevron Group. The transaction is expected to close in the third quarter of 2014 following the receipt of regulatory approvals. Terms are not being disclosed.

About Phillips 66
Built on more than 130 years of experience, Phillips 66 is a growing energy manufacturing and logistics company with high-performing Midstream, Chemicals, Refining, and Marketing and Specialties businesses. This integrated portfolio enables Phillips 66 to capture opportunities in a changing energy landscape. Headquartered in Houston, the company has 13,500 employees who are committed to operating excellence and safety. Phillips 66 had $51 billion of assets as of March 31, 2014. For more information, visit www.phillips66.com or follow us on Twitter @Phillips66Co.