New base 1013 special 23 march 2017 energy news

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 23 March 2017 - Issue No. 1013 Senior Editor Eng. Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
EDF partners with Masdar for third phase of Mohammed bin
Rashid Al Maktoum solar park in Dubai
The national LeAnne Graves
French utility EDF has entered the Middle East solar market by partnering with Abu Dhabi’s
Masdar for the third phase of Dubai’s US$14 billion Mohammed bin Rashid Al Maktoum solar park
in Dubai.
EDF, through its EDF Energies Nouvelles unit, will help to develop the 800-megawatt solar
photovoltaic (PV) project, taking over the stake from Saudi Arabian company Abdul Latif Jameel’s
FRV.
The deal signals a stronger alliance between the two companies for upcoming projects in the
Middle East as EDF places a greater focus on the region’s renewable energy sector.
"The Middle East is a strategic area for EDF which has strong ambitions for renewable energies,"
said Antoine Cahuzac, chief executive of EDF Energies Nouvelles. "This 800MW solar project
realised alongside Masdar, a key player in renewables, seals a major long-term partnership."

The award of the project for the plant, to be constructed in three stages over the next three years,
in June to Masdar and then partner FRV was at a world record- breaking price for electricity
produced from solar of 2.99 US cents per kilowatt hour. Construction has already begun on the
first tranche totalling 200MW.
Mohamed Al Ramahi, Masdar’s chief executive, said that EDF’s international experience would
help the consortium bring to fruition what will be the "largest solar power plant in the world on
completion".
The new partnership will be jointly developed by Masdar and EDF, contributing equal amount of
financing with France’s Natixis acting as the lead bank.
EDF is the largest renewable energy power producer in Europe, with 1,200MW of wind and solar
capacity commissioned and another 1,800MW of renewable energy projects currently under
construction, according to its year-end earnings.
It is not the first time that Masdar and EDF have tied up for projects, as the two partnered on Abu
Dhabi’s 350MW Sweihan solar PV plant, losing by a narrow margin to Asian consortium, Japan’s
Marubeni and Jinko Solar of China.
EDF also bid for the third phase of the Dubai solar park with Qatari partner Nebras at a 33 per
cent higher price than the winning Masdar bid with original partner, FRV. Yet solar prices have
dropped since the summer making the winning Masdar bid more attractive, according to Jean-
Bernard Levy, chairman and chief executive of EDF.
"We have trust to achieve the kind of return we expect based on improved pricing. As time has
elapsed, we’ve seen the benefit in the drop of solar prices," he said.
While FRV is no longer on board with the Dubai project, the Saudi company wants to expand to
other countries including the United States and India.
"Now that the contract has been awarded and the implementation phase has commenced, we feel
that the time is right to concentrate our resources on projects where we have a key delivery role or
a major stake," an FRV spokesman told The National.
The Mohammed bin Rashid Al
Maktoum solar park project, with
planned capacity of 5,000MW by 2030,
highlights the increased international
importance of the UAE’s renewable
energy market.
"The solar park has attracted the interest
of global business and energy
companies, which reflects the trust and
interest from international investors in
large projects adopted by the Dubai government," said Saeed Al Tayer, managing director and
chief executive of the Dubai Electricity and Water Authority.
Mr Al Tayer added that the framework for the power sector encourages more foreign investment
that will help the emirate to reach its target of 25 per cent of Dubai’s total power output from clean
energy sources by 2030.
The 200MW second phase of the Mohammed bin Rashid Al Maktoum solar park began producing
electricity on Monday with enough capacity to power 50,000 homes in Dubai.

Oman: Duqm Special Economic Zone contract awards top RO 705m
Oman Observer
The Special Economic Zone Authority at Duqm (SEZAD) has awarded contracts totalling RO 705
million to date — a figure that is set to soar on the back of a plethora of new infrastructure and
utility contracts due to be tendered out over the coming 12-plus months.
According to a senior official of SEZAD, construction contracts accounted for a hefty RO 625
million of the total, while consultancy firms netted in excess of RO 30 million in contracts. Projects
awarded last month alone totalled around 49 million in value, underscoring the pace at which the
Sultanate’s most ambitious SEZ enterprise is being developed, said Eng Hussain al Zadjali, Head
of Building Projects at SEZAD.
Speaking to journalists during a media tour of the sprawling zone on Oman’s Al Wusta coast, Al
Zadjaii listed a number of prestigious contracts that are currently under tender and due for award.
They include contracts for a service corridor to the $6 billion Duqm Refinery, expansion of the
water distribution network, construction of new roads and bridges, establishment of drainage
systems at Duqm Port, and various consultancy services for various initiatives.
Several major developments are also ongoing at a cost of several hundreds of millions of dollars,
he said. Notable are contracts for the construction of the Jurf and Saay channels designed to
secure the SEZ against potential flooding.
The partnership of Serka Taaghhut and Ajab is executing this package of infrastructure works.
Separately, Premier International Projects is undertaking the construction of flood protection dams

upstream of these channels, aimed at staving off destructive flood events in the future. Both
contracts are due for completion in the second half of 2019.
Just south of the SEZ, Galfar Engineering & Contracting is constructing the nation’s largest fishery
harbour, which will anchor an Industrial Fisheries Hub planned as part of the SEZ. The contract,
comprising marine infrastructure and road networks linking the facility to the SEZ, is due for
completion in Q2 2019.
At the Port of Duqm, the joint venture of Serka Taaghhut and MSF is implementing the IP2
package of works, which includes the construction of roads, terminal infrastructure and buildings
at the Commercial Quay and Operational Zone areas of the port. This key contract is targeted for
delivery by around mid-2019.
Also at the port, the Netherlands-based Royal Boskalis Westminster is undertaking the dredging
and the marine infrastructure of Phase 1 of the Bulk Liquid Berth which will handle ships loading
and unloading liquid cargoes linked to, among others, the Duqm Refinery and future
petrochemicals scheme.
Further, local contractor Modern Delta International is undertaking the design and construction of
access facilities to the site of a proposed automobile assembly plant jointly promoted by Karwa
Motors of Qatar and Oman Investment Fund (OIF).
As for the Duqm Airport Passenger Terminal, currently under construction along with cargo
terminal and Air Traffic Control tower, the target is to bring the completion facility into operation
during the first half of 2018, Al Zadjali added.

Libya's Oil Production Rebounds Back to Level Before Clashes
Reuters
Libya's oil production has reached 700,000 barrels per day (bpd), the National Oil Corporation
(NOC) said on Wednesday, recovering from a drop earlier this month caused by fighting at two
key oil ports.
"We are working very hard to reach 800,000 barrels by the end of April 2017, and, God willing, we
will reach 1.1 million barrels next August," NOC Chairman Mustafa Sanalla was quoted as saying
in a statement.
The NOC said in a separate statement it hoped to produce 55,000 bpd in the coming weeks from
the Abu Attifel and Rimal fields, which are currently closed for maintenance.
The fields are operated by Mellitah Oil and Gas, a joint venture between the NOC and Italy's ENI.
The NOC said Mellitah is currently producing 41,000 bpd from onshore and offshore fields, as well
as 43,000 bpd of condensate.
Libya's output fell to around 600,000 bpd after eastern security forces lost control on March 3 of
the major oil terminals of Es Sider and Ras Lanuf, before regaining them 11 days later. Sanalla
has said he expects to regain control over operations at the ports, despite some officials in
eastern Libya appearing to cast doubt over continuing cooperation with the NOC in Tripoli.
Workers at the ports have been gradually returning to their posts, and a tanker is expected to load
of crude at Es Sider on Saturday or Sunday, according to shipping sources. The NOC said on
Monday that some gains could come from the southwestern Sharara field, where it hopes to boost
production by 70,000 bpd, from 221,000 bpd currently.
Libya's output remains well below the 1.6 million bpd the North African country had been pumping
before a 2011 uprising.
Libya along with Nigeria is exempt from recent production cuts agreed by the Organization of the
Petroleum Exporting Countries (Opec).

LNG demand in the Middle East is expected to grow, S&P
Global Platts says
Gulf News + NewBase
Liquefied natural gas (LNG) demand in the Middle East is expected to continue to grow over the next
two years, before stabilising above 40 billion cubic metres (29.2 million metric tonnes) per year,
according to forecasts from S&P Global Platts.
In 2014, the region which also includes Pakistan imported 5.9 bcm (4.3 million metric tonnes) of LNG
or just under 2 per cent of the global total LNG imports.
By the end of 2016, the figure has gone up to 28.6 bcm (20.9 million metric tonnes) or 7.9 per cent of
the global total.
“Over the past three years, LNG imports into the region have grown by more than 380 per cent at a
time when deliveries to traditional demand centers have been relatively stagnant or in decline. The
demand will continue in the coming years,” S&P Global Platts said in a special report on LNG demand
in the Middle East that was shared with the media at a press conference in Abu Dhabi on Tuesday.
According to the report, Egypt is expected to remain the largest importer of LNG in the region over the
next two years, after which domestic gas supplies from Zohr and other smaller gasfields are set to
displace much of the demand for LNG.
Imports into the UAE are also expected to continue to increase with the delivery of the country’s
second Floating Storage and Regasification Unit (FSRU) to Abu Dhabi in 2016 and a third import
terminal set to be installed in the emirate of Sharjah in mid-2018.
The UAE mainly imports gas to generate electricity from Qatar through the Dolphin energy pipeline.
Dolphin Energy was established by Abu Dhabi government in 1999 and has been implementing
Dolphin gas project since 2007.

Apart from importing gas, the UAE is also focusing developing its own gasfields with the
commissioning of Al Hosn sour gas project in 2015 with a production capacity of one billion cubic feet
per day.
The report also said that Bahrain will be the next Middle Eastern country to enter the LNG market with
a planned 8.2 bcm per year capacity FSRU to come online in July 2018. Kuwait is also expected to
complete an onshore regasification terminal by 2020.
“LNG industry is going through something it never been through before which is 50 per cent increase
in global LNG supply growth in the space of just five years from 2015 to 2020,” said Marc Howson,
senior managing editor at S&P Global Platts.
He said new LNG supply hitting the market in the next few years specially the arrival of the US Gulf
coast LNG exports which is ramping up to 70 million tonnes by 2020 will be something of a game
changer.
The Middle East, traditionally associated with large scale LNG exports, has become one of the fastest
growing demand centers for commodity, he added.

Oman BP’s gas project to deliver 1.5 BCFD of natural gas
Times of Oman
British Petroleum said that its newly extended area within block 61, Ghazeer field, is projected to
deliver 0.5 billion cubic feet of natural gas per day by 2020.
With Khazzan due to deliver a billion cubic feet a day by the end of 2017, the two fields will
together eventually increase Oman’s natural gas supply by around 40 per cent, according to a
company release. This will provide solid foundations for Oman to diversify its industrial base.
Field and well development plans are already underway at Ghazeer and the first development well
has been drilled. Around 3.5 trillion cubic feet of accessible gas are estimated to exist at Ghazeer
and 125 wells will be drilled over the project lifetime to access it.
The amendment to the Oman Block 61 exploration and production sharing agreement (EPSA)
announced in 2016 was ratified, with the issue of a Royal Decreeon March 19, 2017by His
Majesty Sultan Qaboos bin Said.
The amended agreement extends the licence area of the block and enables further development
of the gas reserves in the area. Block 61 is located around 350kilometers south west of Muscat,
with the southern part of it known as the Khazzan field. The newly extended area, which adjoins
Khazzan to the southwest, will henceforth be known as ‘Ghazeer.’ It adds approximately 1,000
square kilometers to the block, bringing the total Block 61 size to 3,950 square kilometers.
“The issuing of the Royal Decree is a momentous occasion for BP Oman as we continue the
development of Block 61 with our partner, OOCEP. We are on track to deliver Khazzan First Gas
later this year and, in parallel to that, we will be driving ahead the field development of Ghazeer.
Our knowledge and experience from the Khazzaan Field will help develop the Ghazeer fieldwith
thegreatest efficiency,” said Eng. Yousuf Al Ojaili, president of BP Oman.
As the largest investor among the integrated oil companies in the Middle East and North Africa,
BP brings a wealth of technical expertise in advanced seismic, hydraulic fracturing and horizontal

well design. This deep technical knowledgeis key to unlocking the vast reserves of tight gas which
are contained in the deep, dense and extremely hard rock strata at Khazzan and Ghazeer.
BP is the operator of block 61 and holds a 60 per cent interest. The Oman Oil Company for
Exploration &Production holds a 40 per cent interest.
With its national oil company partners, BP is currently helping to develop over 5.5 million barrels
per day of oil and gas production throughout the Middle East.
• Block 61 contains significant volumes of unconventional gas, distributed across several reservoirs. Owing to
the tight nature of the rocks in the Khazzan reservoirs, the wells need to be hydraulically stimulated to flow
gas at target rates.
• BP signed an agreement with the Government of Oman in January 2007 for the appraisal and development of
Block 61. BP carried out one of its largest-ever onshore seismic surveys covering the 2,700km2 Block 61 area
and began appraisal well drilling activities in 2008.
• In March 2011 BP Oman achieved a milestone with the first gas delivery to the government from its extended
well test project in Block 61. This successful pilot project helped to demonstrate the potential of a much larger
scale development.
• Phase 1 is on track to deliver first gas by end 2017 producing 1 bcf/d through development of seven trillion
cubic feet of recoverable gas resources. By end of 3Q2016, 37 development wells had been drilled and
completed. Its two-train Central Processing Facility is more than 80% complete and around 11,000 people are
currently working in the field. The estimated cost for developing Phase 1 and the Phase 2 extension is around
$16 billion.
• BP is preparing for the full field development of Khazzan on a number of fronts, most recently with the launch
of its multi-year technicians’ development programme for Omani nationals that will qualify over 80 technicians
to support the long term operations of the Khazzan project. BP is also investing in Omani capability
development for graduates and mid-career staff. Over 65% of BP’s staff in Oman are Omani nationals.

Norway sees decrease in February oil production
Source: NPD
The Norwegian Petroleum Directorate reports that preliminary production figures for February
2017 show an average daily production of 2,010,000 barrels of oil, NGL and condensate, which is
a decrease of 25,000 barrels per day (approx. 1 percent) compared to January. Total gas sales
were 10.2 billion Sm3 (GSm3), which is a decrease of 1.3 GSM3 from the previous month.
Average daily liquids production in February was: 1,620,000 barrels of oil, 360,000 barrels of NGL
and 30,000 barrels of condensate. The oil production is about 0.4 percent below the oil production
in February last year and is about 0.8 percent above the NPD’s prognosis for February 2017. The
oil production is about 0.5 percent above the prognosis so far this year.

The total petroleum production for the first two months in 2017 is about 41.0 million Sm3 oil
equivalents (MSm3 o.e.), broken down as follows: about 15.5 MSm3 o.e. of oil, about 3.8 MSm3
o.e. of NGL and condensate and about 21.7 MSm3 o.e. of gas for sale. The total volume is 0.3
MSm3 o.e. lower than in 2016.
Final production figures from January 2017 show an average daily production of about 1.623
million barrels of oil, 0.413 million barrels of NGL and condensate and a total of 11.5 billion Sm3
saleable gas production.

U.S. biomass-based diesel imports increase 65%, set new record
in 2016.. Source: U.S. Energy Information Administration, Petroleum Supply Monthly
U.S. imports of biomass-based diesel, which include biodiesel and renewable diesel, increased by
65% in 2016 to reach a record level of 916 million gallons. Increasing Renewable Fuel Standard
(RFS) targets and the recently expired biodiesel blender’s tax credit were strong drivers of
biomass-based diesel demand in 2016, incentivizing increased levels of imports of both biodiesel
and renewable diesel. The biodiesel blender’s tax credit has expired several times in the past,
most recently expiring at the end of 2014, only to be retroactively reinstated.
Biodiesel and renewable diesel are valuable because they qualify for the two major renewable fuel
programs in the United States: the nationwide RFS and California’s Low Carbon Fuel Standard
(LCFS). Biomass-based diesel fuels have additional advantages over other renewable fuels such
as fuel ethanol because of their relatively high energy content and low carbon intensity, which
allow them to qualify for higher credit values in both renewable fuel programs.
Both biodiesel and renewable diesel fuels are produced from refining vegetable oils or animal fats.
Biodiesel is blended with petroleum diesel up to 5% or 20% by volume (referred to as B5 and B20,
respectively). Renewable diesel is a drop-in fuel—meaning that it meets specifications for use in
existing infrastructure and diesel engines—and is not subject to any blending limitations.
U.S. imports of biodiesel, which totaled 353 million gallons in 2015, nearly doubled in 2016 to
reach a record-high 693 million gallons. More than half of U.S. imports of biodiesel originated from
Argentina (64%), with much of the rest coming from Indonesia (15%) and Canada (14%).

Roughly half (53%) of biodiesel imports arrived along the Atlantic Coast because of the favorable
economics of importing seaborne cargoes to that region relative to the movement of domestically
produced product by rail from the Midwest. On a monthly basis, biodiesel imports exceeded 100
million gallons for the first time in December 2016. The five largest volumes for monthly biodiesel
imports occurred during the second half of 2016, ahead of the expiration of the $1/gallon biodiesel
blender’s tax credit.
Imports of renewable diesel increased 9% from 2015 levels to reach 223 million gallons in 2016.
Similar to 2015, Singapore was the only source of imported renewable diesel, which was primarily
destined for the West Coast, most likely for compliance with California's LCFS program. Given the
way lifecycle greenhouse gas emissions are calculated for compliance in California’s LFCS,
renewable diesel is one of the most valuable renewable fuels for generating LCFS credits, which
has encouraged its import into the region in recent years.
EIA’s most recent Short-Term Energy Outlook projects biomass-based diesel imports to remain
largely flat in 2017 because of the expiration of the blender’s tax credit, before increasing in 2018
as a result of increasing RFS targets. Net imports of biomass-based diesel (imports minus
exports) are expected to remain largely unchanged at roughly 800 million gallons in 2017,
accounting for approximately one-third of total U.S. biomass-based diesel consumption in 2007,
before increasing to around 900 million gallons in 2018.
EIA used the 2017 RFS targets in the final rule in developing the U.S. biofuels forecast through
2017 for the latest Short-Term Energy Outlook (STEO). EIA expects that the rule will have the
greatest impact on biomass-based diesel consumption, which is forecast to continue its recent
growth into 2017, while ethanol consumption remains largely unchanged.
Biomass-based diesel generates Renewable Identification Number (RIN) credits, which are used
by refiners and importers of gasoline and diesel to meet the RFS targets for use of biomass-based
diesel, advanced biofuels, and total renewable fuel. Biomass-based diesel RINs, also known as
D4 RINs, are more valuable than D6 RINs for grain-based ethanol given their flexibility in meeting
multiple RFS targets.

NewBase 23 March 2017 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil bounces off November lows, but bloated US stockpiles pressure market
Reuters + NewBase
Oil prices on Thursday recovered from losses chalked up the session before, but the market
remains under pressure as bloated U.S. crude inventories and rising output dampen OPEC-led
efforts to curb global production.
Prices for front-month Brent crude futures, the international benchmark for oil, were at $50.95 per
barrel at 0033 GMT, up 31 cents from their last close. That came after Brent briefly dipped below
$50 a barrel the previous session for the first time since November.
In the United States, West Texas Intermediate (WTI) crude futures were up 33 cents at $48.38 a
barrel, after testing support at $47 a barrel overnight.
Despite the bounce on Thursday, traders said that prices remained under pressure, largely due to
a bloated U.S. market and doubts that an effort led by the Organization of the Petroleum Exporting
Countries (OPEC) to cut output were having the desired effect of reining in a global fuel supply
overhang.
Greg McKenna, chief market strategist at futures brokerage AxiTrader, said OPEC was
"underwriting the investment plans and returns of their competition in U.S. shale oil".
McKenna said there was a risk of oil prices dropping further due to U.S. output and a lack of
compliance by some producers who said they would cut production.
The Energy Information Administration (EIA) said U.S. inventories climbed almost 5 million barrels
to a record 533.1 million last week, far outpacing forecasts of a 2.8 million-barrel build.
The high inventories come as U.S. oil production has risen over 8 percent since mid-2016 to more
than 9.13 million barrels per day (bpd) to levels comparable in late 2014, when the oil market
slump started.
Oil price special
coverage

NewBase Special Coverage
News Agencies News Release 23 March 2017
Big Oil companies Replaces Rigs With Wind Turbines
by Jess Shankleman
Big oil is starting to challenge the biggest utilities in the race to erect wind turbines at
sea.
Royal Dutch Shell Plc, Statoil ASA and Eni SpA are moving into multi-billion-dollar
offshore wind farms in the North Sea and beyond. They’re starting to score victories
against leading power suppliers including Dong Energy A/S and Vattenfall AB in
competitive auctions for power purchase contracts, which have developed a specialty
in anchoring massive turbines on the seabed.
The oil companies have many reasons to move into the industry. They’ve spent
decades building oil projects offshore, and that business is winding down in some
areas where older fields have drained. Returns from wind farms are predictable and
underpinned by government-regulated electricity prices. And fossil fuel executives want
to get a piece of the clean-energy business as forecasts emerge that renewables will
eat into their market.
“It is certainly an area of interest for us because there are obvious synergies with the
traditional oil and gas business,” said Luca Cosentino, the vice president of energy

solution at the Italian oil producer Eni, which is working with General Electric Co. on
renewables. “As the oil and gas industry we know, we cannot get stuck where we are
and wait for someone else to take this leap.”
Even as oil production declined in the North Sea over the last 15 years, economic
activity has been buoyed by offshore windmills. The notorious winds that menaced
generations of roughnecks working on oil platforms have become a boon for a new era
of workers asked to install and maintain turbines anchored deep into the seabed. About
$99 billion will be invested in North Sea wind projects from 2000 to 2017, according to
Bloomberg New Energy Finance. A decade ago, the industry had projects only a
fraction of that size.
While crude still supplies almost a third of the world’s energy, oil executives are starting
to adjust to demands for cleaner fuels. Even so, emerging fossil-fuel alternatives
including wind and solar power are starting to limit growth in oil demand.
Those technologies and electric cars may displace as much as 13 million barrels of oil
a day from global demand by 2040, more than is currently being produced by Saudi
Arabia, according to Bloomberg New Energy Finance.
Shell’s Interest
Shell, whose CEO Ben van Beurden has said oil demand may peak in the second half of
the next decade, has set up a business unit to identify the clean technologies where it
could be most profitable, according to Sinead Lynch, the company’s chair for U.K.
businesses. Wind farms are especially interesting to Shell because they can power
electrolysis reactions that make hydrogen, which the company says may be a major fuel
for cars in the coming decades.
It’s exploring new opportunities across Europe in offshore wind after winning contracts
from the Dutch government to build the Borssele III and IV wind farms in December.
Shell’s bid marked the second cheapest cost for the technology worldwide, according
to Lynch, who said the oil major’s big advantage in renewables may be its expertise in
marketing.
“It’s also about marketing energy,” Lynch said. “Once you produce your wind, you need
to market the power and we have a phenomenally strong marketing and trading
business.”
Statoil’s Costs
Oil majors are also changing the offshore wind industry by driving down costs, Statoil
Senior Vice President Stephen Bull wrote in an email.
The Norwegian oil major’s Dudgeon wind farm off England’s east coast will be 40
percent cheaper than a neighboring plant built six years ago, Bull said. It’s also
creating floating offshore wind foundations that eliminate the costly step of anchoring
windmill masts into the seabed. In addition to the U.K., the company is developing
projects in Germany and Norway and won a December auction to build an offshore wind
farm in New York.

Cost cuts for offshore wind are helping the technology start to compete with traditional
forms of energy, especially nuclear, according to Bloomberg New Energy Finance.
Current projects entering operation are delivering power at about half the price of farms
finished in 2012 thanks to larger turbines and more competition. Costs could fall
another 26 percent by 2035, according to the London-based researcher.
The entry of oil majors into renewables is part of “a longer term trend,” according to
Nick Gardiner, head of offshore wind at U.K. Green Investment Bank, who notes that
companies with the scale of Shell and Eni have the clout to finance projects more
cheaply than many of their competitors.
“I don’t think they are doing this just for investor-relation purposes,” said Gunnar
Groebler, head of wind at Sweden’s Vattenfall AB, one of the top five offshore wind
developers who welcomed the added competition. “Given that these projects are
billion-euro investments, I just assume that they will have done their assessments very
thoroughly.”

NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
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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
khdmohd@hawkenergy.net
khdmohd@hotmail.com
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 March 2017 K. Al Awadi

New base 1013 special 23 march 2017 energy news

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