New base energy news issue 928 dated 20 september 2016

Copyright © 2015 NewBase www.hawkenergy.net Edited by Khaled Al Awadi – Energy Consultant All rights reserved. No part of this publication may be reproduced, redistributed,

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NewBase Energy News 20 September 2016 - Issue No. 928 Edited & Produced by: Khaled Al Awadi

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UAE:lowet bids ever submitted for Abu Dhabi’s 350MW solar plant in Sweihan at 2.3 cent/kwh.. The National - LeAnne Graves

Abu Dhabi could expand its Sweihan solar project to well over 1 gigawatts after record low bids were submitted on Monday.

Abu Dhabi Water and Electricity Authority’s procurement arm received six bids for the upcoming 350 megawatt solar photovoltaic (PV) plant in Sweihan, with the lowest bid at 2.42 US cents per kilowatt-hour (kWh) coming from an Asian consortium. A local firm bid second-lowest at 2.53 US cents per kWh.

While the local figure is 16 per cent lower than the record lows reached in Chile last month, a whole new offer was put on the table from the Asian consortium. The consortium submitted an offer to expand the plant to 1,170MW at an offer of 2.30 cents, according to sources who did not want to be named.

However, it is important to note that these submissions do not mean that the project has been awarded, as authorities will now evaluate the proposals to ensure thoroughness and economic viability.

The UAE’s solar sector has been playing out on an international arena for a couple of years after Saudi Arabia’s Acwa Power, partnered with TSK of Spain, came to the forefront and delivered a




winning bid of 5.84 cents for a 200MW phase of the Mohammed bin Rashid Al Maktoum Solar Park in Dubai.

At the time this was a huge leap from what was considered normal at about 8 to 9 cents. It seems as though that price is long gone, because in June there were new lows in Dubai at 2.99 cents for 800MW. It was widely expected that Abu Dhabi would beat that rate, which resulted in many com-panies pulling out.

In the beginning, 90 companies expressed an interest, with that number dwindling to only 34 becoming pre-qualified. Big names such as Italy’s Enel, TSK and Acwa, and Abdul Latif Jameel all pulled out over the summer, leaving a competition among seven. In the latest move the French firm Engie called it quits.

While some are concerned that these rates will place a squeeze on the industry, Acwa believes that there is still room for further drops. "We haven’t reached the bottom yet, but we’re close," said Paddy Padmanathan, the chief executive of Acwa.

He said that there will not be drastic drops all at once, but a gradual slide in the future. "Clearly the market is still able to innovate, and given that the interest rate environment is remaining static I’m delighted to see this new normal," he said.

Mr Padmanathan said that the main focus now will need to be on a balance of systems, which should highlight construction and efficiency gains in methodology. However, he did warn of future liquidity concerns for the market.

Frank Wouters, the former director of Masdar Clean Energy, also agreed that the cheap financing was temporary.

"On the one hand I think the low cost of capital plays an important role and that will not remain so low forever, but on the other hand we’re still learning how to further reduce the cost of solar cells and other components as well as operation and maintenance cost," he said. "So there’s no reason why the cost of solar will ever increase again."




UAE:Technip to be lead contractor for Dubai Enoc in Jebel Ali refinery expansion … The national - Anthony McAuley

Emirates National Oil Company (Enoc) said French engineering firm Technip will be the lead contractor for its US$1 billion expansion project at its Jebel Ali oil refinery. The development is a key part of the UAE’s downstream strategy to be self-sufficient in domestic fuels, as well as expanding the slate of products on offer for export.

"Meeting the growing energy demand tops the government’s agenda," said Enoc’s vice chairman, Saeed Mohammed Al Tayer. "This ambitious expansion project is one of the key building blocks in the energy infrastructure sector to meet future demands."

The main element of the three-part package, which is to grow the refinery’s capacity by 50 per cent, is a new condensate processing train, raising daily crude oil processing capacity to 210,000 barrels per day, from a current 140,000 bpd.

Other new units include a liquefied petroleum gas/naphtha hydrotreater, an isomerisation unit, a kerosene hydrotreater and a diesel hydrotreater will help to produce petrol, jet fuel and diesel to meet domestic demand and fuel emissions standards for markets that include Europe.

Technip Italy, a unit of the company based in Rome, will be the engineering, procurement and construction contractor handling all aspects of the design and construction of the main processing unit.

Enoc is still evaluating bids for the other two elements of the project, which will include building storage tanks and a 31,000 square feet warehouse. The project bidding phase has dragged on as prices have fallen amid industry deflation that has accompanied a worldwide oil and oil products glut.

Refinery capacity has been expanding in the region to meet rapidly growing fuel demand, which in the UAE has been rising at a rate of about 9 per cent a year. Last year, the Ruwais refinery in Abu Dhabi’s Western Region brought onstream units to double capacity to 900,000 bpd.

The Jebel Ali plant was originally commissioned in 1999 – with Technip also the main contractor – and capacity was last increased in 2010, when an $850 million investment lifted capacity to 120,000 bpd from 70,000 bpd.

Enoc said last month it was also expanding its petrol stations both in the UAE and Saudi Arabia, partly to meet the Dubai 2021 development goals and expected growth from Expo 2020.

Enoc plans 54 new retail outlets over the next four years and is refurbishing its existing 112 outlets. The company also won a bid to build 27 service stations on link roads between the major cities in Saudi Arabia.




Oman: Tethys Increases Oil Production in Oman by Andreas Exarheas|Rigzone

Swedish energy company Tethys Oil AB announced Monday that its share of production, before government take, from Blocks 3 and 4 onshore the Sultanate of Oman increased to 387,174 barrels of oil, or 12,489 barrels of oil per day, in August. Tethys’ share of production from the blocks amounted to 368,628 barrels in July, which corresponds to 11,891 bopd.

The Oman-focused oil producer recorded an output of 1.096 million barrels during the second quarter of 2016, which was similar to the company’s production of 1.101 million barrels of oil during 1Q, and marks a slight increase from Tethys’ output rate of 997,904 during the fourth quarter of last year. The company’s full year production in 2015 was 3.539 million barrels of oil. FirstEnergy Capital revealed that market reaction to Tethys’ latest news was neutral but maintained the company’s ‘outperform’ recommendation. “This is in line with expectations, however production is trending-up with 11,600 barrels per day in June and 11,900 bpd in July,” said FirstEnergy in a brief research note to Rigzone. Tethys is one of the largest onshore oil concession holders in the Sultanate of Oman with a current net production of around 12,000 barrels of oil per day, according to Tethys’ website. The company also has exploration and production assets onshore Lithuania and France. Earlier this month, Tethys appointed Jesper Alm as its new chief financial officer, following the decision of Morgan Sadarangani to step down. Tethys also appointed Fredrik Robelius as its new chief technical officer. Sadarangani will step down as CFO Nov. 30 and will remain available to the company until March 1, 2017. Robelius has been with the company since 2011, first as senior petroleum engineer and currently as technical manager, and he will assume his new role as CTO with immediate effect. “I am happy to welcome Jesper and Fredrik to their new roles in the company. I look forward to continue our cooperation for Tethys Oils’ future success,” said Magnus Nordin, managing director of Tethys Oil, in a company statement.




Qatar:Investment ramp up, Barzan output to lift Qatar real GDP growth to 3.8% in 2017: QNB .. Gulf times

The ramp up in investment spending and initial gas production from the Barzan gas project will accelerate Qatar’s real GDP growth to 3.8% in 2017 and 4.1% in 2018 from 3.2% this year, QNB has said in its ‘Qatar Economic Insight’.

The report by QNB Economics examines recent developments and the outlook for the Qatari economy as it continues its strong growth based on non-hydrocarbon investment spending.

According to QNB, Qatar’s economy has weathered low oil prices due to strong macroeconomic fundamentals including a low fiscal breakeven price, the accumulation of significant savings from the past and low levels of public debt.

Oil prices are expected to recover over the medium term; averaging $44.7 for barrel in 2016, before rising gradually to $55 in 2017 and $57.9 in 2018 as declining US oil production and steady demand growth are expected to reduce excess supply, the QNB report said.

Lower hydrocarbon revenue and continued capital spending by the government are expected to result in modest deficits in 2016 and 2017, but the rebound in oil prices should gradually bring the government back to near balance by 2018.

Revenue is expected to decline in 2016 due to the weakness in oil prices and slower non-hydrocarbon growth, but should pick up over the medium-term due to the introduction of a 5% value-added tax in 2018.

The government is expected to continue its investment spending programme while rationalising current spending, leading to a modest decline in expenditure as share of GDP from 2016 to 2018.

The current account surplus is expected to fall to 4.1% of GDP in 2016 before rising to 6.6% in 2017 and 6% in 2018 mirroring the projected movement in oil prices, given that hydrocarbons account for more than two-thirds of Qatari exports.

Qatar’s international reserves are expected to be maintained at just below $40bn, or around seven months of prospective import cover, QNB said. Inflation is expected to rise to 3.2% in 2016 and 3.4% in each of 2017 and 2018 in line with the pick-up in global inflation.

International inflation is expected to rise on stronger food and oil prices while population growth should support domestic inflation, QNB said.




Tunisia: Eni successfully restarts exploration activities Source: Eni

Eni has successfully resumed exploration activities onshore Tunisia in the Sahara desert, approx. 700 kms south of Tunis. Eni has just completed operations on the discovery well Laarich East-1, located in the MLD (Makhrouga-Laarich-Debbech) licence, where Eni owns a 50% stake and the Tunisian state company ETAP the remaining 50%.

L aarich East-1, which is 5 kms away from the oil treatment center in the concession, has reached the final depth of 4,111 meters discovering hydrocarbons in sandstone layers of Silurian and Ordovician age. Production tests revealed a delivery capacity of approx. 2,000 barrels of oil per day, confirming the upside potential of the concession identified through the recent three-dimensional geophysical survey carried out on the permit.

The Laarich East-1 well, whose drilling started in June, has already been connected to production. In the meantime, exploration activities in Tunisia are continuing with the drilling of additional prospects, which have been already identified on 3D Seismic.

The drilling of Laarich East-1 is part of Eni’s near field strategy, adopted to cope with the low oil price environment, and consisting in conducting exploration activities in the proximity of existing infrastructures with available spare capacity. In case of a

discovery, this strategy allows for the optimization of development costs and competitive time to market for production start-up.

Eni operates in Tunisia in exploration and production activities since the early 60s, when the giant oil field El Borma, which is still operating today, was discovered. Eni's equity production in the country is currently 11 thousand barrels of oil equivalent per day.




Norway: Statfjord field passes historic 5 billion barrels Source: Statoil

On Monday 19 September minister of petroleum and energy Tord Lien together with Statoil, Centrica and ExxonMobil celebrated the 5 billion barrels of oil equivalent delivered by Statfjord since first oil in 1979.

Photo below: Arne Sigve Nylund (left), Statoil’s executive vice president for Development and Production Norway with Minister of petroleum and energy Tord Lien.

Statfjord field passes historic 5 billion barrels

The minister got the honour of filling the barrel, which was decorated in golden colour for the occasion.

'The spin-offs created by Statfjord can hardly be exaggerated. Generating more than NOK 1500 billion in revenues and 200 000 direct and indirect man-years since the 1970s the field has been of great importance to the Norwegian society,' says Arne Sigve Nylund, Statoil’s executive vice president for Development and Production Norway. He took part in the celebration on Statfjord A.

After Statfjord has been on stream for more than a generation Statoil and its partners still have a horizon until 2025 for the field. Originally the partnership hoped to recover 40 percent of the oil at Statfjord. The result so far is record-high 67 percent.

The additional resources recovered beyond what was initially believed to be possible equal the lower production estimate for Johan Sverdrup.




On this is a historic day we take a retrospective view. This, however, is also a story about the future, describing how knowledge, skills and experience acquired through many years across the oil industry are harnessed to create ever more values and new activity. Statfjord was supposed to be shut down more than ten years ago.

Instead technology development, smart solutions and clever decisions have extended the productive life and increased the level of activity. This is characteristic of Norwegian oil history and something we will build on in Statfjord’s next chapter and on the NCS for many decades to come,' Nylund says.

Increased production for the fourth consecutive year Thanks to active subsurface work, efficient drilling and well operations, and well operated installations Statfjord this year successfully

increases production for the fourth consecutive year. 451 wells have been drilled on the field, and more than 40 years after the field was discovered new profitable wells are still being drilled.

Safe and efficient operations are essential to optimal resource recovery. At Statfjord the drilling costs have been reduced by 50%. Overall more than one million metres have been drilled at Statfjord, roughly corresponding to a round trip from Oslo to Stavanger.

Both oil and gas

Statfjord is still producing oil. However, the most important decision after the turn of the millennium was made in 2005. Through the Statfjord Late Life project the field was converted from an oil field to a gas field by reducing the reservoir pressure. A bold decision by the partnership, and a successful implementation with important contribution from the suppliers.

NOK 23 billion was invested, and production was maintained during the conversion process. The work included the drilling of 70 new wells and extensive modifications to the platforms.

The high recovery factor is largely thanks to the Statfjord Late Life project, lifting the horizon towards 2025. This means that the old oil giant Statfjord will still be producing when a new giant by the name of Johan Sverdrup has started its 50-year production.

Statfjord field partners: Statoil (44.34 % - operator), ExxonMobil Exploration and Production Norway (21.37 %), Centrica Resources (Norge) (19.76 %) and Centrica Resources (14.53 %).




The United States is both a major importer and exporter of motor gasoline…eia

The United States simultaneously imports and exports gasoline because of regional differences in gasoline supply and demand balances. The two regions with the largest supply and demand imbalances are the East Coast, which imported 581,000 barrels per day (b/d) of gasoline in 2015, and the Gulf Coast, which exported 551,000 b/d of gasoline in 2015.

Regional supply and demand balances in these two regions are described in detail in EIA's recent PADD 1 and PADD 3 Transportation Fuels Markets report. East Coast (defined as Petroleum Administration for Defense District, or PADD, 1) refining capacity is below consumption, and to meet demand gasoline must be shipped in from other parts of the United States and from international sources. Refining capacity in the Gulf Coast (PADD 3), conversely, exceeds demand, allowing the region to send gasoline elsewhere in the United States and to export internationally.

Patterns of international trade in gasoline in all U.S. regions are also affected by transportation constraints and shipping regulations. Pipelines between the Gulf Coast and East Coast already operate at or near full capacity, while maritime regulations can add significantly to the cost of marine movements between U.S. ports.

The East Coast had the highest gasoline consumption in the country at 3.2 million b/d in 2015. However, refinery production in the region was only 550,000 b/d in 2015. To meet demand, the East Coast receives gasoline via pipeline and marine shipment from Gulf Coast refineries.

Approximately 1.9 million b/d of gasoline, or 60% of East Coast gasoline demand, came from the Gulf Coast in 2015. The East Coast also imports gasoline from other countries, predominantly from Western Europe and Canada. Imports into the East Coast accounted for 87% of total U.S. gasoline imports in 2015.




Source: U.S. Energy Information Administration, Petroleum Supply Monthly

Unlike refinery capacity on the East Coast, capacity in the Gulf Coast exceeds demand. In 2015 Gulf Coast refinery gasoline production was approximately 4 million b/d, while demand was approximately 1.5 million b/d. The Gulf Coast sends its surplus gasoline to other regions in the United States and to foreign markets.

The Gulf Coast exported more than 89% of total U.S. gasoline exports in 2015. The primary destinations for Gulf Coast exports were to other countries in North America and Central and South America accounting for 51% and 35% of total U.S. gasoline exports, respectively.

Refineries on the U.S. Gulf Coast have increasingly exported gasoline to Central and South America in recent years, but they face increased competition as new and upgraded refineries in that region come online and likely decrease the need for imports.




NewBase 20 September 2016 Khaled Al Awadi

NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE

Oil prices fall on speculation a global glut will be sustained amid rising supply from Nigeria to the U.S. .. Reuters + NewBase

Oil prices fell on Tuesday after Venezuela said that global crude supplies needed to fall by 10 percent in order to bring production down to consumption levels, confirming analyst views that markets remain heavily oversupplied.

Global oil supply of 94 million barrels per day needs to fall by about a tenth if it is to match consumption, Venezuela's Oil Minister Eulogio Del Pino said on Monday.

International benchmark Brent crude oil futures were trading at $45.80 per barrel at 0048 GMT, down 15 cents from their last close. U.S. West Texas Intermediate (WTI) crude futures were down 25 cents at $43.05 a barrel.

"Global production is at 94 million barrels per day, of which we need to go down 9 million barrels per day to sustain the level of consumption," Del Pino said in an interview with state oil company PDVSA's internal TV station. Del Pino is also president of PDVSA.

The statements came the same day as credit ratings agency Standard & Poor's said that a proposed bond swap by PDVSA was a "distressed exchange" that would be "tantamount to default" if completed, a blow to the cash-strapped firm's effort to seek a financial lifeline.

Nigerian Output Brent for November settlement fell 14 cents, or 0.3 percent, to $45.81 on the London-based ICE Futures Europe exchange. Prices advanced 18 cents to $45.95 a barrel on Monday. The global benchmark traded at a $2.17 premium to WTI for November delivery.

Oil price special

coverage




Nigerian production should reach 1.8 million barrels a day next month and 2 million by December, when most export terminals resume operations, Kachikwu said Monday at a government economic management team meeting with private investors in Abuja. The nation’s output fell in May to the lowest in 27 years after increasing attacks by militants on oil infrastructure and was at 1.44 million barrels a day in August, according to data compiled by Bloomberg.

MEI: Oil Market Rebalance Will Take Another 6 Months by Rigzone Staff

Data and analytics specialist McKinsey Energy Insights (MEI) has forecasted that it will take more than six months for the oil markets to fully rebalance. In its latest research, MEI suggests that the pace and timing of an oil price recovery depends on four key drivers in the short-term; GDP growth, decline in producing fields, slowdown in US light tight oil (LTO) production and OPEC Gulf state behaviour - in particular, the actions of Iran and Saudi Arabia. MEI, which modeled four possible future scenarios comprising fast recovery, slow recovery, under-investment and supply abundance, found the latest trends point towards a slow market recovery scenario. In this case, the market will take another six months for oversupply to disappear and another 6-12 months to burn excess inventories, according to the analytics company. In the long-term, continuous cost compression efforts could reduce average marginal costs to $65-75 per barrel, driven by deep-water and LTO plays, says MEI. “The market is recovering but this may be slower than previously expected. We expect demand growth to decelerate as a result of slowing economic development and structural shifts in the transport sector,” said James Eddy, head of MEI.




“On the supply side, in addition to OPEC Gulf crude production, we see unconventionals and offshore resources playing an important role in replacing the 34 million barrels per day decline in conventional basins through 2030,” he added. The research also notes that there is a key short-term risk that OPEC Gulf members have the capacity to add more than 3-4 million barrels per day incremental production by 2019. This could potentially stifle oil prices further into 2018-19.

NewBase Special Coverage

News Agencies News Release 04 September 2016

Mothballing the World's Fanciest Oil Rigs Is a Massive Gamble Bloomberg - David Wethe

In a far corner of the Caribbean Sea, one of those idyllic spots touched most days by little more than a fisherman chasing blue marlin, billions of dollars worth of the world’s finest oil equipment bobs quietly in the water.

They are high-tech, deepwater drillships -- big, hulking things with giant rigs that tower high above the deck. They’re packed tight in a cluster, nine of them in all. The engines are off. The 20-ton anchors are down. The crews are gone. For months now, they’ve been parked here, 12 miles off the coast of Trinidad & Tobago, waiting for the global oil market to recover.

The ships are owned by a company called Transocean Ltd., the biggest offshore-rig operator in the world. And while the decision to idle a chunk of its fleet would seem logical enough given the collapse in oil drilling activity, Transocean is in truth taking an enormous, and unprecedented, risk. No one, it turns out, had ever shut off these ships before. In the two decades since the newest models hit the market, there never had really been a need to. And no one can tell you, with any certainty or precision, what will happen when they flip the switch back on.

It’s a gamble that Transocean, and a couple smaller rig operators, felt compelled to take after having shelled out millions of dollars to keep the motors running on ships not in use. That technique is called warm-stacking. Parked in a safe harbor and manned by a skeleton crew, it typically costs about $40,000 a day. Cold-stacking -- when the engines are cut -- costs as little as $15,000 a day. Huge savings, yes, but the angst runs high.

“These drillships were not designed to sit idle,” said Willard Duffey Jr., an electrician who spent two decades with Transocean. The Deepwater Pathfinder, a ship he had served on for four years, was among the first to be parked off the Trinidad coast. The ship made the voyage there from the Gulf of Mexico about a year ago. Duffey was one of the last men aboard before the engines were turned off. He fretted constantly -- “did I do everything I could?” -- as he flew back home to Ore City, Texas. “To get the Pathfinder back up would be very difficult to guess actually,” he said.

Once famously labeled the “new Ferraris” of the oil world, these are no ordinary ships. Carrying a price tag of about $500 million a piece, they are loaded bow to stern with sophisticated, and very heavy, gadgetry.




Below the water line sit a half-dozen Rolls-Royce thrusters, coordinated by satellite to push against each other and keep the rig hovering on top of wells lying as much as two miles underwater. Up on deck, there’s a robot that can be launched to work a screwdriver or a wrench under water pressures on the seabed that no human could survive.

And the 220-foot tall, dual-activity oil-drilling derrick is capable of simultaneously lifting and lowering gear down to the seafloor, including a diamond-studded drill bit, a five-story-tall blowout preventer and a heavy-drill pipe. The derrick can handle as much as 5 million pounds of gear -- equal to the weight of some 20 adult blue whales -- going up and down at one time.

All of these fancy elements, though, are what make turning the ships back on so daunting. Chip Keener, whose rig-storage consulting firm advises Transocean, compares it to what would happen if you left a high-tech new car parked in the garage for months. The battery would be dead, sure, but then there’d also be a slew of pre-sets to reprogram. On a drillship, there are thousands and thousands of pre-sets. And unlike your car, those on a ship are essential to its proper functioning. “It’s a big deal,” says Keener.

For now, cold-stacking has been a huge success for Transocean, a long-time Texas powerhouse that’s based today in Switzerland. (It owned the offshore rig that BP Plc was operating in the 2010 Gulf of Mexico disaster.) The company reported a profit of $77 million in the second quarter, surprising investors who had been bracing for a loss. Its stock price jumped 8.5 percent in minutes the next morning in New York.

"I don’t think a simple congrats on this quarter’s cost beat is really sufficient," one stunned analyst, Scott Gruber at Citigroup, told Transocean executives on a conference call. “A big kudos to all of you.”

Still, there are any number of deepwater rig operators unwilling to turn the engines off: Noble Corp., Rowan Cos. and Pacific Drilling, to name a few. They’re paying anywhere from $30,000 to $50,000 a day to store their out-of-work ships. Chris Beckett, the CEO of Pacific Drilling, said the unknowns of cold-stacking are just too great and the cost to keep the ships running too manageable -- about $10 million a year -- to turn them off. He likes the peace of mind that comes with this approach. “We don’t worry about how you start them again,” Beckett said in an interview in the company’s Houston headquarters.




The cold-stack versus warm-stack dilemma doesn’t figure to go away anytime soon.

Nearly half of the world’s available floating rigs are out of work today, and most observers expect that number will climb further. Not only are the drillship operators’ customers -- the likes of ConocoPhillips and Total SA -- slashing spending in high-cost offshore areas and canceling work contracts early, but new rigs that were ordered in recent years keep rolling out of shipyards. Bloomberg Intelligence estimates as much as $56 billion worth of offshore rigs, capable of drilling in everything from shallow water to oceans more than two miles deep, are still under construction.

It’s a far different mood than a couple years ago, when crude was hovering around $100 a barrel and just about every single deepwater rig on the planet was in use. Transocean’s Pathfinder was in many ways the symbol of those go-go days. In mid-2014, just as oil prices were peaking, Eni SpA agreed to pay Transocean $681,000 a day to lease the ship. It was one of the richest drilling contracts ever, an amount that’s about triple the rate a deal signed today would fetch. By the end of that year, with oil in freefall, Enicanceled the contract four months before it was due to expire.

Things are quiet on the Pathfinder these days. The water is calm off Trinidad, one of the top global destinations for drillship storage. A handful of seamen recruited locally make the rounds, in part to ward off criminal elements. They’re joined every once in a while by Transocean mechanics sent in to monitor the ships. The company’s chief operating officer, John Stobart, recently dropped in to check them out himself. CEO Jeremy Thigpen said Stobart came away encouraged.

"He was really impressed with the preservation of all the critical components," Thigpen said at an energy conference in New York this month. "His belief is, ‘Listen, we’re going to be able to reactivate these rigs in a timely and low cost manner.’"

Stobart’s going to have to wait for his chance. Oil, after having briefly rebounded above $50 in June, is slumping again. And Transocean seems prepared to be in Trinidad for a while. According to island officials, the contract that the company’s negotiating to lease out seabed space could extend through October of 2020.




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Khaled Malallah Al Awadi, Energy Consultant MS & BS Mechanical Engineering (HON), USA Emarat member since 1990

ASME member since 1995 Hawk Energy member 2010

Mobile: +97150-4822502 [email protected] [email protected]

Khaled Al Awadi is a UAE National with a total of 26 years of experience in the Oil & Gas sector. Currently working as Technical Affairs Specialist for Emirates General Petroleum Corp. “Emarat“ with external voluntary Energy consultation for the GCC area via Hawk Energy Service as a UAE operations base , Most of the experience were spent as the Gas Operations Manager in Emarat , responsible for Emarat Gas Pipeline Network Facility & gas compressor stations . Through the years, he has developed great

experiences in the designing & constructing of gas pipelines, gas metering & regulating stations and in the engineering of supply routes. Many years were spent drafting, & compiling gas transportation, operation & maintenance agreements along with many MOUs for the local authorities. He has become a reference for many of the Oil & Gas Conferences held in the UAE and Energy program broadcasted internationally, via GCC leading satellite Channels. NewBase : For discussion or further details on the news above you may contact us on +971504822502 , Dubai , UAE

NewBase 20 September 2016 K. Al Awadi




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New base energy news issue 928 dated 20 september 2016