Specialist well abandonment company said it won an intervention work contract for TAQA Bratani Limited, a unit of Abu Dhabi National Energy Company (TAQA).
Well-Safe Solutions signed its first contract after launching in July this year.
The specialist well abandonment company secured a three-year framework agreement with TAQA Bratani Limited for the provision of intervention management services for all their North Sea assets, the company said in a statement.
Under this call-off arrangement, Well-Safe said it will provide people and engineering services to support TAQA with well plug and abandonment (P&A) planning.
This announcement follows several high profile appointments at Well-Safe, which now employs 25 people, in its newly refurbished headquarters at the prestigious Hill of Rubislaw in Aberdeen.
Phil Milton, chief executive officer of Well-Safe, said “Winning our first piece of work, less than four months after start-up, is a major milestone for Well-Safe. It underlines the unrivalled well plug and abandonment expertise we have already amassed in such a short space of time.
“Working collaboratively with TAQA’s in-house team, we will undertake well P&A planning that identifies the safest, most-effective and efficient solutions.
“Our goal is to build long-term relationships, based on trust between our employees, clients and the industry, and we look forward to working in true partnership with TAQA to support them in making informed decisions on P&A activity and then implementing them effectively.”
Aiming to become a major “Tier 1” well abandonment service company, Well-Safe Solutions will provide a fully integrated package using its own bespoke marine and land-based assets to help oil and gas operators meet the challenges of safe and cost-efficient decommissioning of wells.
Global oil and gas leaders shared their views at the Abu Dhabi International Petroleum Exhibition and Conference (ADIPEC) on the changes the industry is going through towards building models for success after recent years of reduced capital expenditure.
At the Global Business Leaders panel on the first day of ADIPEC Musabbeh Al Kaabi, CEO of Petroleum and Petrochemicals, Mubadala Investment Company, (formed by merging Mubadala Development Co and International Petroleum Investment Co.) said it’s merger was a success which resulted in building a fully integrated portfolio. “We’re a multi-cultural company and our main objective is creating value. With the current state of the industry, it is very important to have a resilient portfolio. The integrated business is more resilient - we have the right scale and we are ready for any oil price going forward,” he added.
In petrochemicals specifically, Al Kaabi said Mubadala has created scale is one of the largest producer of polyolefin. The scale and technology has put us in a very strong position globally. Because of the attractiveness of the shale gas revolution, it is creating the right environment for petchems to grow in that industry.”
Dr Rainer Seele, CEO of OMV said businesses will need integrated cooperation for the future. “We’ve seen stable business models of integrated companies.”
Vagit Alekperov, President, Member of the Board of Directors, Chairman of the Management Committee at Lukoil said the company has been focusing on improving efficiency at its oldest oilfields and now it has improved production and efficiency, while increasing its reserves. “The government of Russia shared its risks with us and gave us the opportunity to expand,” he said. “We are confident about our future and in being a reliable partner in major projects in Mexico, Iran and Iraq.”
José Anaya, CEO of PEMEX said it is adjusting to a new energy industry in Mexico which has seen privatisation of oil and gas projects.
“For many decades, only Pemex was allowed to have gasoline stations around the country. Now, it is a huge change for people when they see other brands. Pemex is adjusting with bringing knowledge, sharing investments. It is open and ready for this change,” he said.
Alexander Medvedev, deputy chairman of the management committee at Gazprom said: We have a record 190 billion cubic meters of gas production this year and we’re sure no one else can compete with us because of effective production and delivery.
We are confident our gas was, is and will remain competitive in Europe. But we are looking at China. For pipeline LNG, we’re sure will be reaching everywhere LNG will be needed.”
Some of the energy industry’s biggest players have given ADIPEC delegates an insight into how their companies have weathered the oil price downturn – and lessons learned.
It came during a Global Business Leaders panel centred on the theme: driving growth – pioneering strategies and breaking boundaries for global success.
The bosses of BP, Total and Petronas also reflected on possible future energy mixes, the surprise rise of shale and how technology may shape future strategy.
Bob Dudley, Group Chief Executive of BP, said: “We now have to be mindful of how we grow because we have to tackle carbon emissions at the same time as meeting the world’s growing energy needs.
“We need to find a way to do both things and they’re not mutually exclusive. We want to be realistic about how our world has changed and needs to change.
“The new reality of abundant new energies is really out there; it’s going to mean some downward pressure on prices…so we need transformation.”
Dudley continued: “I’m going to use the word stepchange. The first is simplicity in what we do; second is technology, so vitally important; the third efficiency. That’s what we have to do in the broad scale all around to have strategies for a successful new world. It’s a bit simplistic, but each one of those things is very important.
“None of us can do everything we need to do. We need to collaborate as partners. Companies that don’t respond quickly…”
Total Chairman and CEO Patrick Pouyanne outlined lessons learned in the last three years.
“We need to be able to combine a strong discipline on one side and still an ambition to grow, because we need to think long term; we need to answer to the demand of energy for the world.
“This is where we have to adapt fundamentally. Disciplines mean to have a permanent eye on what is the break even of our portfolio of assets, because we don’t control the price of oil; we just rediscovered that.
“We came back to basics – we have to be excellent at what we control.”
Pouyanne said he and Dudley were lucky to head large companies, better suited to weather the price storm.
“We have some deep roots that whatever the weather is around us we can rely on,” said the Total chief.
“External circumstances forced us to adapt, but I don’t think you change your culture. One of the values we have is pioneering spirit.”
Dudley added: “Companies, all of us, have slightly different cultures. There’s a great business phrase that’s probably 20 years old that culture trumps strategy every time. You can have a great strategy, but if you don’t have a culture to execute it it’s going to be difficult.”
French oil giant Total has signed an agreement with Engie to acquire its portfolio of upstream liquefied natural gas (LNG) assets for $1.49 billion to become the second largest global LNG player
This portfolio includes participating interests in liquefaction plants, notably the interest in the Cameron LNG project in the US, long term LNG sales and purchase agreements, an LNG tanker fleet as well as access to regasification capacities in Europe.
Additional payments of up to $550 million could be payable by Total in case of an improvement in the oil markets in the coming years.
“The acquisition of Engie’s upstream LNG business enables Total to accelerate the implementation of its strategy to integrate along the full gas value chain, in an LNG market growing strongly at 5 per cent to 6 per cent per year. The combination of these two complementary portfolios will allow the Group to manage an overall volume of around 40 million tonnes of LNG per year by 2020, making Total the second largest global player among the majors with a worldwide market share of 10 per cent”, commented Patrick Pouyanné, chairman & chief Executive Officer of Total.
With the equity stake in the Cameron LNG project, Total will also become an integrated player in the US LNG market, where the Group is already a gas producer”
The deal is expected to close by mid 2018.
Following the transaction, Total will take over the teams in charge of the LNG activities at Engie, which represents around 180 employees. In addition Total and Engie agreed to cooperate to promote the use of biogas and renewable hydrogen, with Engie becoming Total's priority supplier in this field.
London-listed Victoria Oil & Gas has hit more than 84 metres of net gas sands after the latest drilling programme in Cameroon.
Preliminary results from the drilling programme from well La-108 indicate that 84.5m net gas sands have been encountered in the Logbaba Formation, exceeding pre-drill expectations with significantly more net sands than La-107, which encountered 58m of net pay and subsequently flow tested at 54 mmscf/d maximum flowrate through a 70/64ths inch choke.
Ahmet Dik, CEO, said: “La-108 has now successfully reached target depth, which is an excellent result for the company with over 84.5m of net gas sands encountered. This net pay exceeds those of the successful La-107 well, brought into production during September. La-107 has already delivered us a significant increase in available gas supply and we look forward to releasing flow test results from La-108 by the end of November. Our objective is to build scale from our gas production, to be in a position to deliver gas to high usage customers. We estimate that there is demand for over 150 mmscf/d of gas in the Douala Basin and GDC is presently the sole provider to the region.”
The production test through the Logbaba production facility is expected to commence during November. This will mark the end of drilling operations for the two well Logbaba drilling campaign that started in November 2016.
Driven by expansion in developing countries, global energy demand is set to increase by 35 per cent by 2040, with investments keeping pace, OPEC said in its new World Oil Outlook 2040.
Primary energy demand is forecast to grow by 96 million barrels of oil equivalent per day (boepd) between 2015 and 2040, up from 276 million to 372 million. This is a growth of 35 per cent compared to the 2015 base year, with an average annual growth rate of 1.2 per cent during the forecast period, the report said.
This growth will be unequally distributed among major regions, OPEC said, with developing countries anticipated to grow at 1.9 per cent per year during the 2015-2040 forecast period, while OECD countries will grow at just 0.1 per cent, and Eurasia will grow at 0.9 per cent. Factors such as population growth, urbanisation rate and expansion in economic activity are expected to play the largest role in growth disparity. India and China are among the largest contributors to future energy demand, the report said.
OPEC expects its energy supply to grow slightly by 2040.
“In terms of crude, it is estimated that OPEC will need to supply an additional 7.7 million bpd in the period 2020-2040,” OPEC Secretary General Mohammad Barkindo said in the report.
“For all OPEC liquids, the figure is 10.5 million bpd. Moreover, the share of OPEC crude in global oil supply is expected to increase from 34 per cent in 2016 to 37 per cent in 2040,” he added.
This is on back of medium-term growth of liquids supply from non-OPEC but a deceleration from 2022 onwards and a decline after 2027 to 60.4 million bpd by 2040, Barkindo said.
Within the energy mix, natural gas will become the largest contributor to future energy demand at a global scale. Its demand will increase by almost 34 million boepd, reaching a level of 93 million boepd by 2040. Its share in the global energy mix is expected to increase by a significant 3.6 percentage points.
Meanwhile, long-term oil demand is expected to increase by 15.8 million bpd, rising from 95.4 million bpd in 2016 to 111.1 million bpd in 2040.
However, average growth is forecast to slow around 300,000 bpd between 2035 and 2040 on the back of anticipated efficiency improvements, a further tightening of energy policies, as well as decelerating GDP and population growth.
Demand in the OECD region is anticipated to show a significant decline of 8.9 million bpd over the forecast period.
A structural shift of economies towards a more service-oriented structure means oil will be facing strong competition from other energy sources.
Light products are expected to satisfy more than half of the long-term oil demand growth, while demand for gasoil/diesel has been revised downward, the report said.
Light products (ethane/liquefied petroleum gas (LPG), naphtha and gasoline) are expected to satisfy more than 50 per cent of global demand growth in the period to 2040; 8.5 million bpd out of a total demand growth of 15.8 million bpd. Demand for middle distillates is anticipated to increase by 6.8 million bpd during the forecast period, while that for heavy products increases only marginally by 0.5 million bpd.
Meanwhile, jet or kerosene is the fastest growing fuel in the outlook and diesel or gasoil remains the most important product category.
AG&P (Atlantic, Gulf and Pacific Company), the Philippines-based company, has signed an exclusivity with Karaikal Port Pvt. (KPPL), to develop an LNG import terminal at the Port, including LNG sourcing and supply.
The Karaikal Port is a deep-water facility located on the east coast of India. As part of the Port’s expansion it has allocated an area within its existing breakwater to develop an LNG terminal to serve power, industrial and other customers in the region.
AG&P has signed an exclusive deal with PPN Power to supply LNG.
“Karaikal Port is a center of trading for Southeast India and is crucial to the region’s GDP. With the addition of AG&P’s LNG import terminal, Karaikal Port will continue to be an engine of growth for the region’s future. Offering an all-weather operation with a breakwater ensuring 99 per cent availability, night navigation, limited dredging requirements, proximity to GAIL’s existing Cauvery Basin gas pipeline network and 24/7 access to port services, we are immensely proud of the Port’s facilities that attracted AG&P to this prime site,” said GRK Reddy, chairman and Promoter director of KPPL.
The development of AG&P’s LNG import terminal at Karaikal Port shall complement Indian Oil’s under construction LNG terminal at Ennore 300 kilometers to the north and will provide wider gas accessibility to Puducherry and Tamil Nadu.
GRK Reddy added: "“AG&P’s coming Karaikal LNG terminal is a landmark development that will accelerate industrialisation, create jobs, trigger overall economic and social development and lead to much needed cleaner air. It will improve the quality of life for millions of Indians."
“AG&P’s innovative approach will establish Karaikal as a major gateway for distributing LNG, CNG and gas quickly and efficiently to customers throughout the region. Leveraging its standardized designs and modular approach to building terminals developed in AG&P’s Houston, Texas Engineering Center, AG&P not only eliminates expensive, bespoke engineering costs, but significantly reduces construction time. This means the terminal will be up and running by mid-2019,” Karthik Sathyamoorthy, president, LNG Marketing, AG&P.
OMV has announced that with its partners they have begun gas production at the Sofiya gas field in the Mehar block in Pakistan.
The Sofiya D&P lease within the Mehar block is operated by OMV Maurice Energy Limited.
OMV and its joint venture partners Ocean Pakistan, Government Holdings Private Limited and Zaver Petroleum Corporation successfully put the Sofiya-2 well in production on October 27, 2017.
The Sofiya-2 well now adds 15 million standard cubic feet of gas per day and 1,400 barrels of condensate per day to the production of the field.
Hydrocarbons from the Sofiya-2 well were discovered in August, 2013 and development activities began in early 2017 after a development and production lease was granted.
Development activities began in early 2017 after a development and production lease was granted.
TechnipFMC has been awarded a subsea contract by Murphy Sabah Oil in offshore Sabah, Malaysia.
The subsea contract is for the Phase 1A Block H Gas Development Project. The project is located in offshore Sabah, Malaysia at a water depth of approximately 1,300 meters.
This contract covers the Engineering, Procurement, Construction, Installation and Commissioning (EPCIC) of the umbilicals, risers and flowlines as well as the transportation and installation of subsea hardware and controls.
Hallvard Hasselknippe, president Subsea Projects at TechnipFMC, commented: “We are proud to have been awarded this contract from Murphy Sabah Oil which demonstrates the strength of our solutions and deepwater capabilities in Malaysia.”
ENGIE has renewed the regasification and storage services contract with Chinese energy group CNOOC for the winter season. This will be provided by the FSRU GDF SUEZ Cape Ann in the port of Tianjin.
The FSRU arrived in Tianjin fully loaded with LNG and started operations at the end of October. The vessel will remain in the Chinese port until Spring 2018.
Cape Ann has previously provided similar services to CNOOC, from November 2013 to January 2017, as a contribution to both LNG and natural gas supply needs.
In addition to the usual FSRU activities, Cape Ann will also transfer LNG into smaller on-shore tanks which are used by CNOOC for LNG trucking activity.
Philip Olivier, head of ENGIE Global LNG, commented: “We are especially pleased to continue this relationship with CNOOC, a long standing partner of ENGIE in the field of LNG. This new contract illustrates ENGIE’s fast track capabilities to provide safe, reliable and flexible LNG importing solutions to meet the needs of our customers.”
ENGIE said that in China it aims to become a benchmark player in China’s energy transition, developing decarbonated, decentralised and digitalised solutions.
CB&I has been awarded a contract by a subsidiary of Lukoil for the detailed engineering, procurement and supply of process equipment, including two proprietary coking heaters for the Deep Conversion Complex in Kstovo City, central Russia.
The units will use Chevron Lummus Global's (CLG) delayed coking technology for the processing of 2,100 KTA of refinery residues.
In addition to the engineering, procurement and supply contract, CB&I is continuing to work closely with LUKOIL to assess a broader range of solutions for the project.
"CB&I is pleased to be providing a wide range of services to Lukoil for their project. CLG was previously awarded the coking technology license, and this award demonstrates the value CB&I can bring through an array of technology and engineering solutions to the Russian region," said Duncan Wigney, CB&I's Executive Vice President of Engineering & Construction.
UK's Ineos Shale has acquired interests in five English onshore shale licenses from France's Total.
The firm has bought Total’s entire 40 per cent stake in the license PEDL 139 and 140 in North Nottinghamshire, as well as a 30 per cent interest in PEDL 273 and 305 in Yorkshire, and a 30 per cent stake in PEDL 316 in Lincolnshire. Total has also transferred to INEOS its option to farm-in to PEDL 209.
The deal's value wasn’t disclosed.
Ron Coyle, CEO at INEOS Shale, said: “Our acquisition of these assets represents an important development for INEOS Shale and demonstrates our ongoing commitment to this important industry. Shale gas represents an exciting opportunity for the UK, and has the real potential to bring much needed jobs and investment to local communities.”
All the licences in which INEOS acquired interest are operated by British onshore explorer IGas.
Echo Energy has acquired a 50 per cent stake in four licences within the prolific Santa Cruz province in Argentina.
The four licences (Fracción C, Fracción D, Laguna de los Capones and Tapi) cover 11,153 square kilometres in Santa Cruz province.
In a statement, Echo says that the licences deliver a production base (11.4mln cubic feet per day gross) hosted in the Fracción C & D licences, where production growth potential (up to 80mln cubic feet per day).
Drilling expected in first quarter of 2018
“This transaction is a transformational acquisition in the region and will form the backbone of our gas business, blending exploration, appraisal and production. Echo is now positioned as a leading regional gas explorer with a unique platform for growth and a staged work programme,” said Fiona MacAulay, Echo chief executive.
Echo added that the Tapi Aike licence offers access to a ‘multi TCF’ opportunity, whereas Fracción C and Fracción D are said to have ‘transformational’ exploration and appraisal potential.
McDermott International has been awarded a contract from India's Reliance Industries for the KG-D6 subsea field development in the Krishna Godavari Basin, located off the east coast of India.
Reliance is developing deepwater gas and oil fields in the KG-D6 block. The north-western boundary of the block is about 24 to 37 miles (40-60 km) southeast of Kakinada in water depth of between 400 meters and 2,300 meters.
McDermott will provide engineering, procurement, installation and pre-commissioning of subsea flowlines, vent lines, and a pipeline-end manifold for connection with six subsea wells in the R-cluster field at a water depth of up to 2,100 meters.
“We look forward to working with Reliance on this important and challenging project and building on our recent experience and expertise in deepwater projects across the region,” said Hugh Cuthbertson, McDermott’s vice president for Asia.
In addition to the R-Cluster of six subsea wells, the option for five to seven more subsea wells can be exercised by the client for an optional S-cluster package.
The contract is set for completion by the second quarter of 2020 for the base scope, and the first quarter of 2021 for the optional scope.
Australia's Oil Search has agreed to buy three oil blocks in the Alaska North Slope for US$400 million from privately-owned companies Armstrong Energy and GMT Exploration.
The deal gives Oil Search stakes of 25.5 per cent in the Pikka Unit and 37.5 per cent in the Horseshoe Block in the Alaska North Slope, with the option of doubling its stake for an additional $450 million, the company said in a statement.
The deal will give Oil Search a roughly 26 per cent holding in the Nanushuk play, co-owned by Spain’s Repsol, which is one of the largest conventional oil fields discovered in the U.S. in more than 30 years. The Nanushuk field, which is located adjacent to several giant producing oil fields, was discovered in 2013.
The company said it has plans to fund the deal from its cash reserves.
The Australian firm, which mainly operates in Papua New Guinea is looking to diversify its asset base.
Oil Search managing director, Peter Botten Said: "The Nanushuk field in the Alaska North Slope is a giant oil discovery and has been acquired at an attractive point in the commodity cycle, at a very competitive price."
Oil Search said it was in the process of creating a separate U.S.based entity with U.S. oilfield services giant Halliburton Co and Armstrong Energy to operate the Alaskan assets, which the company will run from mid-2018 onwards.
Botten added: "Our joint venture partners in these assets comprise Repsol, with whom we have a strong working relationship in PNG, and Armstrong, which has a proven 15 year track record of finding major oil accumulations in Alaska. As highlighted, Oil Search will assume the operator role in June 2018."
Shell said it has completed the sale of a package of UK North Sea assets to Chrysaor for a total of up to $3.8 billion as part of its $30 billion divestment plan.
This includes an initial consideration of $3.0 billion and a payment of up to $600 million between 2018 and 2021 subject to commodity price, with potential further payments of up to $180 million for future discoveries, Shell said in a statement.
The package of assets consists of Shell’s interests in Buzzard, Beryl, Bressay, Elgin-Franklin, J-Area, the Greater Armada cluster, Everest, Lomond and Erskine, plus a 10 per cent stake in Schiehallion. Shell retains a significant, more focused and strengthened presence in the UK North Sea, to which it remains committed, it said.
This sale was announced on 31 January 2017 and has an effective date of 1 July 2016. Completion follows receipt of all necessary regulatory and partner approvals. Shell said 253 of its staff transferred to Chrysaor upon completion of the transaction.
In Q4 2017, Shell will record an accounting gain on sale of $1.0 billion against the values of both the Shell and former BG assets included in the package.
Shell said the completion of this deal shows the clear momentum behind its $30 billion divestment programme and is in line with Shell’s drive to simplify the upstream portfolio and re-shape the company into a world class investment.
Shell’s stake in the assets sold was as follows: Buzzard (21.7), Beryl (39.4), Bressay (18.4), Elgin-Franklin (14.1), J-Area (30.5), the Greater Armada cluster excluding Gaulpe (76.4), Everest (100 per cent), Lomond (100), Erskine (32.0) and Schiehallion (10.0). Chrysaor has assumed operatorship of Armada, Everest and Lomond. Shell retains a 44.9 stake in Schiehallion.
Fugro has renewed a contract for integrated survey work offshore India for the country’s multinational oil and gas company ONGC.
The scope of the work includes bathymetric surveys, seabed mapping, shallow seismic profiling and well head investigation.
The three-year deal is worth US$7.7 million. It is the third consecutive time that Fugro has been awarded the contract for engineering surveys in field developments off both western and eastern shores of India.
“It is very satisfying to win this contract for a third consecutive time. We have been supporting these field developments offshore India with our marine site characterisation services for more than two decades,” commented Mike Dravitzki, Fugro’s regional Director.
Fugro has used its survey vessel, Fugro Mapper, from September 2017 to perform surveys in water depths ranging from 10 metres to 100 metres
British oil giant BP has seen profits jumped in the third quarter of 2017 thanks to a jump in production and strong downstream earnings.
BP’s Q3 profits more than doubled in the period. Its pre-tax profits for the period totalled $2.95billion, up from $1.33billion a year ago.
The rise in profits was driven by higher production for the quarter which hit 2,462mboe/d, 16.3 per cent higher than the third quarter of 2016. This rise is due to the ramp-up of major projects with three major upstream major projects beginning production in Q3.
Bob Dudley, Group chief executive commented: "We are steadily building a track record of delivering on our plans and growing across our businesses. This quarter, three new Upstream projects and the highest Downstream earnings in five years, underpinned by reliable operations and disciplined spending, have generated healthy earnings and cash flow. There is still room for further improvement and we will keep striving to increase sustainable free cash flow and distributions to shareholders."
SOCO International has signed a new Production Sharing Agreement (PSC) for Blocks 125 and 126 offshore central Vietnam with PetroVietnam and SOVICO Holdings.
Blocks 125 & 126 are located in deep water in the Phu Khanh Basin, offshore central Vietnam, to the north of the Cuu Long Basin.
SOCO was awarded a 70 per cent operating interest in the two blocks.
SOCO’s president and chief executive, Ed Story said: “SOCO began its serious evaluation of the exploration potential of Blocks 125 & 126 in the Phu Khanh Basin in 2010, following an interest that preceded that time by many years. We are delighted that our tenacity has successfully delivered two new blocks; along with partnership with one of Vietnam’s preeminent conglomerates, SOVICO Holdings.”
In a statement SOCO said that the interpretation of the existing data indicates there is good potential for source, expulsion and migration of oil with numerous reservoir and seal intervals likely.
A Memorandum of Understanding was signed by the partners in 2015 and the final PSC was approved by the Vietnamese Government and Prime Minister in August 2017.
SOCO has been present in Vietnam for almost two decades and has invested over $1 billion into its oil and gas projects located offshore southern Vietnam.
World gas reserves rose by 0.9 per cent in 2016, driven by the United States, Nigeria and Iraq, Eni said on Monday.
During last year, world gas production increased by 0.7 per cent, driven mainly by new Australian LNG plants, according to Eni’s second edition of its report titled World Oil and Gas Review.
United States, the world’s largest producer of natural gas, saw its reserves grow after a decrease in 2015, while production slightly declined by 3.2 per cent after 10 years of growth driven by the shale gas boom, the report said.
Meanwhile, Russia remains the top holder of gas reserves with a 25 per cent. Among the top ten, six are OPEC countries with 32 per cent of the world’s total gas reserves.
In Europe, Norway’s production was almost flat after a strong jump in 2015, whilst output continued to decline in the European Union, down 3 per cent.
In Russia, the world’s second gas producer, output resumed growth after the decline registered last year.
Eni said world gas demand recorded robust growth in 2016, up 2 per cent, thanks to a strong recovery in Europe, up 5.4 per cent, mainly due to the power sector and weather conditions, and in the Asia-Pacific region, up 5.1 per cent, led by strong demand in China, which grew by 8.6 per cent. Gas demand also rose substantially in India and South Korea; UK, Germany, Italy, and France reported the highest increases in Europe, the report said.
Meanwhile, in wind and solar, which are key elements in the energy transition towards a low carbon future, installed capacity accounted for almost 40 per cent of total installed renewable power capacity, Eni said.
China leads the market for solar and wind with an installed capacity of 226 GW or 30 per cent of the world total, the report said.
In 2016, solar photovoltaic capacity additions grew by 50 per cent compared to 2015, reaching a record 71 GW driven by declining cost of technology. Wind capacity increased by 51 GW, but additions fell by 21 per cent compared to 2015. Total new installations were concentrated in China (44 per cent). North America (+21 GW), thanks to new photovoltaic installations, slightly overtook Europe (+19 GW), where wind led the growth.
In 2015, wind represented 3.5 per cent of power generation, solar energy 1 per cent. The contribution of modern renewables to power generation remains lower than their contribution to capacity due to current low average capacity factors (below 25 per cent for wind and 15 per cent for solar).