New base 585 special 20 April 2015

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,

or otherwise copied without the written permission of the authors. This includes internal distribution. All reasonable endeavours have been used to ensure the accuracy of the information contained in this

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NewBase 20 April 2015 - Issue No. 586 Khaled Al Awadi

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

UAE Diversification efforts likely to offset oil price impact By Sarah Diaa Staff Reporter , Gulf News 2015. All rights reserved.

The impact of falling oil prices on job creation in Abu Dhabi is likely to be offset by a boost in efforts for economic diversification, according to the latest report by Cluttons, a real estate consultancy firm.

Other cities in the UAE such as Dubai and Sharjah have already seen a curb in rental growth recently, with demand stabilising.

“With oil prices fluctuating around the $50 (Dh184) per barrel mark, we are likely to see this start to impact the rate of job creation in the oil and gas sector as the year progresses and hydrocarbon-linked firms begin reassessing their growth plans,” said Steve Morgan, chief executive officer of Cluttons Middle East.

In the office market, demand remained lopsided and centred on prime stock, which is still short in supply. Demand, however, is stable, leading to upward pressure on Grade A rents across the city, according to Cluttons’ Spring 2015 Abu Dhabi Property Market Outlook report. Grade A office space

Currently, the performance of the office market is very much dependent on demand from oil firms, however.




“The evolution of oil prices over the course of the year will very much dictate how the office market fares not just in Abu Dhabi, but across most Opec [Organisation of Petroleum Exporting Countries] member states,” Morgan added.

Average asking rates for Grade A office space in the capital remained stable at Dh1,850 per square metre in the first quarter of 2015, though landmarks like the World Trade Centre and Nation Towers each saw office prices at Dh2,000 per square metre.

Prices at Etihad Towers were even higher, at Dh2,250 per square metre, registering an 18 per cent increase in rents during the fourth quarter of 2014. Demand is also expected to be strong for the upcoming opening of the Abu Dhabi Global Market Square on Al Maryah Island.

Mathew Green, head of research at CBRE, a commercial real estate adviser, said that the increased supply of office space together with weaker demand will lead to a deflation of rental rates especially among secondary locations.

“Abu Dhabi’s office sector is driven primarily by the government and oil and gas, so I think we have to assume that overall demand levels are pretty weak this year. You may start to see some longer time periods for deals to be completed … generally, it’s probably going to be a relatively weak picture for the office market this year, but that will depend on how long the slump will continue,” he told Gulf News.

He expected the residential market to be relatively strong and stable, though.

Residential Market

In 2014, rents across Abu Dhabi’s main freehold market continued to grow strongly, with Saadiyat Island registering the best performance. Three-bedroom apartments on the island saw a surge of just over 22 per cent in Q4 2014 alone, the report said.

Overall, apartments on Saadiyat saw an 11.2 per cent increase in rents in 2014, with the ongoing delivery of units driving up demand, which is expected to see another boost as the Louvre and Guggenheim museums are completed.




Saudi’s SABIC Signs Deal To Use U.S. Shale Gas At British Plant Reuters + NewBase

Saudi Basic Industries Corp has signed a deal to use shale gas from the United States at its Teesside petrochemical plant in Britain, acting chief executive Yousef Abdullah al-Benyan told Reuters on Sunday.

“In fact we did sign the contract – we have not yet agreed with the supplier to publicly announce it, but we did firm up a contract for gas supply,” Benyan said, declining to name the supplier.

He said the timing and other details of the project, which he described as the first use of shale gas exported from the U.S. Gulf in Britain, should be available by next quarter. “It is going to meet our full demand for the next ten years and is renewable beyond ten years,” Benyan said.

SABIC has previously said scarce gas supplies at home have forced it to look at investment opportunies abroad. Last year, the company said it planned to upgrade its Teesside cracker to capitalise on shale gas opportunities in the United States.

Benyan also said on Sunday that SABIC was still considering a proposal to build a plant able to turn crude oil directly into chemicals, without first having to refine the oil. The proposal was originally announced by oil minister Ali al-Naimi early last year.

Asked if talks had been held with companies to develop the project, Benyan said that ideally SABIC would like to do the project by itself, and that any partner would need to make an important contribution and help to spread risks.




Kuwait finds four new oilfields with huge volumes Reuters + NewBase

Kuwait, which plans to boost oil output capacity by a third by 2020, has discovered four new oilfields in the north and west of the country, a top oil official was quoted as saying by state news agency KUNA on Sunday. Hashem Hashem, the chief executive of state-run Kuwait Oil Co (KOC), did not give production rates of the new oilfields, but said exploration activities have moved ahead despite oil prices dropping nearly 50 per cent since last June.

"The (new) fields will be developed and production will start briefly," he said, adding that the new discoveries had been announced after two years of exploration activities had proved positive. Two reservoirs for unconventional oil in the north of the country were also discovered, Hashem said. The grades found in the fields were both light and heavy oil, with preliminary results showing "huge commercial volumes", KUNA quoted Hashem as saying. Kuwait plans to boost its oil and gas drilling rigs by 50 per cent by early 2016 as it seeks to boost crude and gas production despite low oil prices, Hashem said in February. Most of Kuwait's production is from Burgan, the world's second largest, which is in the southeast of the country. Kuwait's current output potential is around 3 million barrels per day (bpd), but the country wants to lift this to 4 million bpd by 2020. The Gulf Arab country expects a big boost from its northern fields, planning later this year to invite international oil firms to bid for technical service agreements in the area.




History of failure over gas policy in the Mediterranean Gulf News ( Rubin Mills ) + NewBase

As the Argentinian writer Jorge Luis Borges said of the Falklands War, it was “two bald men fighting over a comb”. In the quest for East Mediterranean gas, there are four bald men, but even finding the comb is proving to be a problem.

The search for gas in the deep waters of the East Mediterranean was highlighted by large discoveries by the United States’s Noble Energy off Israel: Tamar in 2009 and Leviathan in 2010. Egypt had already been exploring in its sector for a decade, with considerable success. Cyprus also enjoyed success with its first well when Noble found the Aphrodite field in late 2011. And, to great fanfare, Lebanon launched its offshore licensing round on April 30, 2013.

For three energy-short countries, the discovery of offshore gas and, it was hoped, oil, offered energy security and relief from crushing bills. Debt-ridden Lebanon and Cyprus hoped to find a way out of their fiscal morass.

But there followed a remarkable story of ineptitude, indecision, illogicality and impatience. Governments and the public alike were keen to kill and devour the golden goose before it had even laid an egg.

In Lebanon, expectations soared to particular heights, with then energy minister Gibran Bassil announcing in 2013 that reserves could be 95.9 trillion cubic feet of gas, without a single well drilled or even a block licensed. But the required legislation to permit the bid round is still held up in cabinet, with new minister Arthur Nazarian saying: “Frankly, I don’t have a clue when these decrees will be passed.”




Cyprus hoped gas would solve its financial problems. But appraisal downgraded the size of Aphrodite, ENI has drilled two dry wells and does not plan to try again before its licence expires in February 2016 and, according to the Middle East Economic Survey, Total looks likely to withdraw without drilling at all.

Israel has made the most progress, with Tamar gas now supplying half of its electricity, but its policy has also been the most bewildering and contradictory. To meet populist demands, it raised taxes on gas producers, and set quotas limiting exports, even though its domestic market cannot handle all of the gas found. This deterred Woodside, an Australian company expert in liquefied natural gas (LNG), from buying into Leviathan.

The resulting delays have put agreements to supply Jordan and Egypt in doubt. The regulatory authority then went back on earlier undertakings which required the Noble consortium to sell some small fields that were of no real consequence, and declared it a monopoly – even though its main customer in Israel, the electricity company, is also a monopoly.

Egypt, the first of the quartet to become a significant gas producer, was already short of gas by 2011, as artificially low prices stimulated demand while making offshore fields uneconomic. Perhaps surprisingly, its recent performance has been the most improved, with the long-delayed agreement for BP to develop the large North Alexandria field. But it needs Cypriot or Israeli gas to keep its LNG plants operating.

In retrospect, expectations in all countries were excessive. The fields discovered so far, though large and regionally important, are not global giants, and contain only limited amounts of valuable liquid hydrocarbons, unlike for instance Qatar’s North Field. They are in deep water, and a

pipeline from Aphrodite to Cyprus would have to cross a 2,500-metre trench.

Most of all, the fields’ potential is limited by geography, markets and politics. The unresolved Cyprus dispute blocks off export routes to or via Turkey, and no viable LNG concept has yet been put forward, while prices have fallen sharply.

Good policy could still have overcome these disadvantages, and brought the benefits of

gas and its revenues to the people of the East Mediterranean. But politicians and administrators in all four countries seem to prefer fighting over imaginary combs.

Written by: Robin Mills is Head of Consulting at Manaar Energy,




EU dreams of Iranian gas to break dependence on Moscow AFP + NewBase

The European Union (EU) is hoping future gas imports from Iran can break its dependence on Russia as prospects grow for a nuclear deal that would include lifting sanctions on Tehran.

The EU is betting on so-called Southern Corridor pipelines to supply gas to southern Europe via Turkey from fields in Azerbaijan and nearby countries, including Iran. “It’s one of our priorities,” EU commissioner for Climate Action and Energy Miguel Arias Canete said on Wednesday in the Latvian capital Riga when referring to the gas route.

Due to be operational in 2019, the project is expected in an initial stage to deliver 10 billion cubic metres of gas per year to Bulgaria and Greece. “That will not be enough,” conceded a source in the European Commission, the executive of the 28-nation EU.

But with Iranian gas flowing after an eventual lifting of the sanctions, “capacity could be increased to 40 billion cubic metres of gas per year and that would be substantial,” a European official said on Friday on condition of anonymity.

Europe is desperately seeking to diversify its energy suppliers and supply routes as the Ukraine crisis strains ties with Russia to breaking point. The 28-nation bloc depended on imports for more than half its needs at a cost of some €400 billion (Dh1.5 trillion) in 2014.

Russia alone supplies about a third of its requirements — it bought 125 billion cubic metres from Russia’s state gas operator Gazprom, with half that amount going through pipelines that cross Ukraine, which provides the country with a major source of revenue.




But transit through Ukraine has become increasingly unpredictable because of the endless financial disputes between Gazprom and Naftogaz, the Ukrainian operator. The war pitting Kiev government troops against pro-Moscow rebels in eastern Ukraine has only increased tensions.

Gazprom chief Alexei Miller is threatening to put an end to the supply of gas through Ukraine in 2019. He had bet on the South Stream pipeline, which would have skirted Ukraine to supply gas to Bulgaria under the Black Sea, but Russian President Vladimir Putin scrapped the plan in December as relations with Brussels nosedived.

He then launched what is known as Turkish Stream, a pipeline to replace South Stream with capacity of 63 billion cubic metres — the same volume as transits Ukraine. The Europeans will have to assume the costs to connect with Turkey and lay the infrastructure needed to deliver purchases from this country.

The Russian side is convinced that the Southern Corridor will never be viable for lack of gas, while the EU believes that Turkish Stream will never materialise.

Construction began last month of the section of the pipeline that will deliver gas from Azerbaijan to Turkey, but plans for the pipeline that will take it through Greece and Albania into Italy are further behind with the first pipes to be laid only next year.

Greece has expressed interest in the Turkish project but “nothing has been signed yet, no contract has been concluded,” a spokesman for the European Commission said. The investment needed will be “considerable,” a European official added.

Experts said Iranian and European gas interests converge if Iran seals a deal in June with the US and five other powers to curb its nuclear programme in return for a lifting of years of sanctions, but expressed guarded optimism.

“Actually the Iranians are desperate for investment. They are desperate for hard currency. They are desperate to modernise the infrastructure,” Judy Dempsey, a Berlin-based analyst for the Carnegie Europe think tank, said.

“And the Europeans are desperately eager to go into Iran to get a share of the pie,” she said. “It’s definitely an alternative, but the Europeans need to be very careful not to put all their eggs in the Iranian basket,” Dempsey added.

Daniel Gros, director of the Brussels-based Centre for European Police Studies, said, “it will take a long time before Iran becomes a ‘solid’ alternative to Gazprom”, if and when sanctions are lifted.

It will take time to build new pipelines and other infrastructure for Iranian gas, while, through its existing pipelines, “Russia will remain the cheapest supplier for the EU for some time to come,” he said.

NewBase views & comments , said the S.E “ EU will have to stay dreaming on this issue “




Statoil committed to end routine flaring by 2030 Statoil + NewBase

Statoil and several other oil companies and nations joined together Friday to commit, for the first time, to end the practice of routine gas flaring at oil production sites by 2030.

CEO Eldar Sætre represented Statoil at the signing at the World Bank in Washington together with Norwegian foreign minister Børge Brende. 'Meeting the target of zero routine flaring by 2030 is a highly important contribution our industry can make towards mitigating climate change,' Sætre said in his speech in Washington on Friday.

'In our operations in Norway we do not carry out any routine flaring. This leading performance was made possible by a

government determined to avoid waste and maximise value from its natural resources,' Sætre continued.

In 1971 Norway banned routine flaring. Coupled with a price on carbon equivalent of USD 65/ton CO2 today, these measures provided the necessary incentives for both the government and the industry to invest in production and export of gas.

But globally every year, around 140 billion cubic metres of associated natural gas is wastefully burned or 'flared' at thousands of oil fields. This results in more than 300 million tons of CO2 being emitted to the atmosphere - equivalent to emissions from approx. 77 million cars.

Together with Statoil and Norway, eight other oil companies and eight other countries have endorsed the initiative recognising

that routine gas flaring is unsustainable from a resource management and environmental perspective. They have all agreed to cooperate to eliminate ongoing routine flaring as soon as possible and no later than 2030.




Russia: $27bn Yamal LNG project work in full gear Reuters + NewBase

Natural gas reservoirs under construction at the port of Sabetta in the Kara Sea shore line on the Yamal Peninsula in the Arctic circle, some 2,500km northeast of Moscow. Sabetta, Russia: Spread across the frozen whiteness of the Russian Arctic, the ambitious $27bn Yamal gas mega project aims to defy both the extreme temperatures and the Ukraine crisis impacting its funding.

Some 2,500km northeast of Moscow, the Yamal site — a joint venture by Russia’s Novatek, France’s Total and China’s CNPC — is eventually meant be one of the world’s biggest liquefied natural gas (LNG) projects and ship deliveries to both Asia and Europe. But not long ago the area drew only a handful of geologists and explorers whose neighbours in the virgin territory were polar bears and foxes. “There was nothing. Just tundra,” said Dmitry Fonin, a veteran of industrial projects in the Russian north who is at the helm of construction of Yamal LNG. Over two years later development is in full gear and around 9,000 workers are toiling away in often fiercely inhospitable conditions to launch the massive facility by 2017 that aims to produce some 16.5 million tonnes of LNG per year. “It’s rather warm now, -10 degrees,” Ruslan Mikhailov, who captains an icebreaker tasked with keeping the waters around the port navigable, told journalists during a recent press trip. “The average here in the winter is -30 and it goes as low as -56.” Plans for the Yamal LNG project date back about 10 years, long before Russia’s current standoff with the West over Ukraine and punishing sanctions imposed by the United States and European Union after Moscow’s annexation of Crimea. Russia hopes the location of the plant will allow it to diversify energy exports and ship both to European markets and Asia, via the northern route, the shortest passage between European Russia and the Pacific Ocean though navigation there remains highly seasonal. Fears have swirled over the future of the vast project, however, as international ties nosedived

To be launched by 2017

to produce 16.5 MTY of

LNG




over the Ukraine crisis and the West slapped tough sanctions on Russia that led to some major energy ventures involving Western and Russian firms being shelved. Although the vast project was not directly targeted by the sanctions — and Total and CNPC still remain onboard with 20 percent each — the economic tit-for-tat has hit the venture in other ways. In mid-July Novatek was put on the blacklist by the US Treasury, and even though the joint venture is not directly under sanctions, the punitive measures from the West are closing off huge swaths of potential cash. The project still needs $18bn of investment and the funding issue has been exacerbated by the current reduced price of oil that has cut down industry revenues. Gas prices are often linked to crude oil prices. “(If) we would not have this question of sanctions, the financing would have been done already, let’s be clear,” Total CEO Patrick Pouyanne said said during a recent visit to the site, adding thought that he hoped it would arrive “in a matter of weeks.” “Because of the sanctions we cannot use dollars, we use financing through Chinese banks, European banks and other Asian banks,” said Pouyanne. Beyond the facility itself, subcontractors and suppliers suffer sanctions too, said Novatek chief Leonid Mikhelson. “There are technical difficulties with the money, though they can be overcome,” he said.

Russia has granted long-term loans worth 150bn rubles ($2.7bn), half of which has already been provided. An employee of a European company present at the facility confirmed potential investors are hesitant: “Banks take time to make sure they don’t violate sanctions, and they wonder whether the sanctions will be tightened further. It creates stress.” Despite the current hitches the energy

bosses remained upbeat on the project and insist that it will be seen through to completion. “We can supply the European market and the Asian market,” Pouyanne said, describing it the venture as a “launchpad for growth” in Russia. Total’s commitment to Russia was spearheaded by Pouyanne’s predecessor Christophe de Margerie, who died last October when his plane collided with a snowplough in a Moscow airport. And all sides insist the viability of the project is in no doubt once it gets going. “We have contracts for almost 100 percent of the gas,” Novatek chief Leonid Mikhelson said recently. “Of course large volumes will go to the Asia-Pacific region.” For Russia, analysts say projects like Yamal are vital, as Moscow needs to start tapping new fields beyond its current maturing sites. So keeping the project on track is a must whatever the obstacles may be in the near future. “LNG projects are likely to face significant delays, due to high costs, geopolitics and financial sanctions,” analysts with energy association Cedigaz said in a recent note. “But (they) could eventually develop on a significant scale in the next decade.”




US: New maps highlight geologic characteristics of tight oil, shale plays Source: U.S. Energy Information Administration,

EIA is currently in the process of updating maps of major tight oil and shale gas plays, including the Eagle Ford andMarcellus plays, which will help to better characterize the geology of key areas of production in the United States. EIA's most recent maps focus on shale and tight oil plays, and characterize plays based on geologic characteristics, including rock type and age. Understanding geologic history and processes helps exploration and production companies reduce the risk of drilling dry, nonproducing wells and better understand hydrocarbon resource potentials.

Production of crude oil and natural gas occurs in two classes of rock: source rocks and reservoir rocks. Source rocks are sedimentary rocks in which hydrocarbons (organic chemical compounds of hydrogen and carbon) form. Reservoir rocks are both porous, meaning that there are open spaces, or voids, within the rock, and permeable, meaning fluids are able to flow within them. After

forming in the source rock, hydrocarbons, which can vary from simple structures, like methane (a constituent of natural gas), to very complex structures, like bitumen (contained in tar sands), can migrate to the reservoir rock.

Historically, nearly all hydrocarbons produced domestically were withdrawn from carbonate and sandstone reservoirs. However, over the past decade, production from shale and other tight rock formations, spurred by advances in exploration and production technology, has grown dramatically.

Geologic formations that contain oil and gas include clastic or detrital rocks (formed from pieces of pre-existing rocks or minerals), chemical rocks (formed by chemical precipitation of minerals), and organic rocks (formed by biological debris from shells, plant material, and skeletons). The three most common sedimentary rock types encountered in oil and gas fields are shales, sandstones, and carbonates.

Classifying these rock types primarily depends on characteristics such as grain size and composition, porosity (pore space within and between grains), and cement (a chemically formed material that holds the grains together), each of which can influence oil and gas production.




Shale is formed by the accumulation of very small sediments deposited in deep water, at the bottoms of rivers, lakes, and oceans. Shales are the most abundant clastic sedimentary rock, and because of their potential for a high organic content, shales are considered to be the primary source rocks for hydrocarbons.

Sandstone is created by larger sediment, deposited in deserts, river channels, deltas, and shallow sea environments. These rocks tend to be more porous than shales, and consequently make excellent reservoir rocks. Sandstone is the second most abundant clastic sedimentary rock and is the most commonly encountered reservoir rock in hydrocarbon production.

Carbonate is created by the accumulation of shells and skeletal remains of water-dwelling organisms in marine environments. The third most abundant sedimentary rock, carbonate (e.g., limestone) rocks are also very good reservoirs and are commonly encountered during hydrocarbon production.

Geologic age is an important determinant of hydrocarbon potential, beyond the characteristics of source and reservoir rocks. Identifying fossils, other chemical markers, and correlating rocks across different formations allows earth scientists to determine the age of the rock and to understand the processes that influenced the sediments and organic material over time.

While many rocks of different ages produce oil and natural gas, domestic areas of prolific production include formations from several different geologic periods: the Devonian (416 to 359 million years ago (mya), the Carboniferous (359 to 299 mya), the Permian (299 to 251 mya), and the Cretaceous (145 to 65 mya). During these periods, organic-rich materials accumulated and, over time, heat and pressure chemically altered originally organic chemicals into natural gas and oil.




Oil Price Drop Special Coverage

WTI today oil prices




Saudi February oil exports drop Bloomberg + NewBase

Saudi Arabia’s crude exports dropped from an 11-month high in February when the world’s biggest shipper cut pricing to boost demand and defend its market share.

Exports fell to 7.35 million barrels a day from 7.47 million in January, the highest since February 2014, according to figures published Sunday on the website of the Joint Organisations Data Initiative. Shipments were down from 7.76 million barrels a day in February last year.

Saudi Arabia, the world’s largest crude exporter, announced price cuts in February for oil sales to Asia to the lowest in at least 14 years in a sign that it was continuing to fight for market share. Oil Minister Ali Al Nuaimi said in March global demand for oil was improving gradually.

“Keeping the market share is very important and it seems that the Saudis don’t want to see their crude exports fall below the 7.4 million barrels mark,” said Essam Al Marzouq, a Kuwait-based oil analyst. “The Saudi exports data of the first two months of 2015 suggests that they needed to give more discounts to stimulate demand for their crude.”

Saudi Arabia, which led the Organisation of Petroleum Exporting Countries (Opec) last year in refusing to cut output, produced 10.3 million barrels a day last month and will keep pumping for now at around 10 million, Al Nuaimi said this month.

Crude shipments in the first two months of 2015 averaged 7.4 million barrels a day, up from 7.1 million barrels a day in the last two months of 2014 and lower than the 7.63 million barrels a day average in the first two months of 2014, JODI data show.

Burning of crude, a sign of how much oil is available domestically to generate power, rose to 315,000 barrels a day in February from 276,000 barrels a day in January, while domestic refineries processed 2.08 million barrels a day compared with 2.1 million barrels a day in January, according to JODI data.




Prospect of Iran nuclear deal is already weighing on oil prices Reuters + NewBase

Lifting sanctions on Iran's oil industry could significantly change the outlook for oil supply and prices, the head of the U.S. Energy Information Administration told U.S. legislators.

"If and when sanctions are lifted, EIA's baseline forecast for world crude oil prices in 2016 could be reduced $5-$15 per barrel," Adam Sieminski said to the Senate's Committee on Energy and Natural Resources on Thursday.

The prospect of between 500,000 and 1 million barrels per day (bpd) of additional Iranian crude

becoming available in 2016 or 2017, perhaps with even more by the end of the decade, is one of

the biggest influences on the medium-term outlook.

While the price of short-dated futures contracts for Brent delivered in 2015 and early 2016 are now slightly higher than they were at the end of 2014, after a strong rally in recent weeks, prices for deliveries from June 2016 onwards have actually fallen.

Stronger nearby prices reflect the downturn in U.S. drilling and expectations that it will cut U.S. oil

production in the coming months. But the drop in forward prices most likely reflects the impact of

additional Iranian oil reaching international markets.

The entire Brent forward curve has pivoted, and the pivot point is the second quarter of 2016, which coincides with when most analysts think a nuclear framework could result in extra export volumes ().

Nuclear negotiators have until the end of June 2015 to hammer out the details of a "joint comprehensive plan of action". Most observers think it will take a further six to 18 months to secure U.S. congressional approval, complete preliminary work by Iran and obtain a UN Security Council resolution.




Assuming it takes 12 months for all the necessary preparatory work to be done, extra Iranian crude would start hitting the international market from around June 2016, plus or minus a few months.

Lower Brent futures prices for the second half of 2016 and 2017 could be the impact of extra oil, discounted for the probability of a deal happening and sanctions being lifted. Other factors are also having an impact on longer-dated prices, including the "fracklog" of drilled but uncompleted wells and the prospect that drilling will accelerate again. But the extent and timing of higher Iranian exports is now one of the central drivers of prices in 2016 and 2017.




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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 25 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 09 April 2015 K. Al Awadi







Economy & Finance

New base 585 special 20 April 2015