New base energy news issue 888 dated 19 july 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,
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
publication. However, no warranty is given to the accuracy of its content. Page 1
NewBase Energy News 19 July 2016 - Issue No. 888 Edited & Produced by: Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
UAE: Dubai DEWA to explore feasibility of geothermal energy
for water desalination
The National - LeAnne Graves + NewBase
Having taken the lead on developing solar power, Dubai is on the hunt for other renewable
sources of energy it can make use of, such as the seas of the Gulf of Oman and the steam from
the earth.
Dubai Electricity and Water Authority (Dewa) is requesting proposals for an early-stage feasibility
study on producing electricity from geothermal energy and its use in desalination – removing salt
from water to make it potable.
The other area of focus for the study will be to, for the first time in the country, gauge the potential
for tidal, wave and ocean currents as a source for power generation.
Dubai’s Clean Energy Strategy includes the aim to generate 75 per cent of its electricity from
clean energy sources by 2050.
Geothermal energy from beneath the Earth’s surface, the heat that creates hot springs, needs to
be at temperatures of more than 200°C to be a prime candidate for power generation. The UAE’s
temperatures are much lower than this, making geothermal more suitable for applications such as
desalination rather than power generation, according to experts.
Steve Griffiths, the vice president for research at Abu Dhabi’s Masdar Institute, which has been
studying the potential for geothermal in the UAE, said that using this kind of energy for
desalination was the most viable option, as the GCC’s geothermal resources were only suitable
for low-temperature applications, averaging about 100°C.

“It could be viable – the details will need to be worked out, but if there’s a tender for geothermal-
based desalination, it’s not insane," Mr Griffiths said, adding that the attractiveness resulted from
the UAE’s efforts to “decouple power and water systems".
“So it could be running as a
stand-alone water desalination
application, which could be
cost-competitive with [other
conventional approaches] such
as reverse osmosis," he said.
The hydrocarbon-rich UAE
does have the advantage that
geothermal energy can be
found with the same drilling
techniques that are used to
explore for oil and gas.
However, when it comes to
ocean power, Mr Griffiths said
that to date he had not seen
anyone propose using the sea
as a way to generate electricity
at any level of scale. “Based
on the known information on
renewable energy resources in the GCC, you probably wouldn’t bank on this approach for any
significant amounts of electricity," he said.
According to the European Commission, it is estimated that 0.1 per cent of the energy in ocean
waves could be capable of supplying the entire world’s energy needs five times over.
But the fact is the technology just is not there yet. Using the sea to generate electricity has been
deployed in only a handful of countries including France – and to date, nothing has been proven
commercially viable.
Power generated from the ocean only totals about 500 megawatts globally, whereas solar
photovoltaic applications totalling more than 64,000MW are expected to be added this year alone,
according to market analysis by GTM Research.
In any case, interested consultancies will have a chance to explore the options, with proposals to
be submitted to Dewa by the end of the month.

UAE: Dubai Municipality gives go-ahead for implementation of
Dh30b smart, sustainable satellite city. Gulf News + NewBase
Dubai Municipality has given the go-ahead for the implementation of the Desert Rose City, a
smart and sustainable satellite city project that was announced in 2014.
Hussain Nasser Lootah, director-general of Dubai Municipality, on Monday said in a press release
that the project has been given the green signal in line with the vision of His Highness Shaikh
Mohammad Bin Rashid Al Maktoum, Vice-President and Prime Minister of the UAE and Ruler of
Dubai.
He also announced the
formation of a committee
headed by Abdullah Raffia,
assistant director-general for
Engineering and Planning
Sector, to supervise the
studies, designs and the
construction of the satellite
city and follow up its
implementation at all levels.
Consisting of building clusters
in the shape of a desert
flower, the Dh30 billion
mixed-used development will
come up on an area of 14,000
hectares on the Dubai-Al Ain
Road.
Once complete, it is expected to accommodate 160,000 residents who will work and live in the city
that will be surrounded by a green belt.
There will be 20,000 plots for building luxury homes for Emiratis and 10,000 affordable housing
units for expatriates. The city will rely on its own resources to provide means of transport and
communications, energy consumption and recycled water. It will have resources to provide more
than 40,000 cubic meters of potable water.
Dawood Al Hajeri, director of the Planning Department, said the Desert Rose City will be a
sustainable city that produces 200 megawatts of electricity using solar panels on the rooftops of
homes and other buildings.
The project will be implemented progressively, complying with the emirate’s green building code,
and will have eco-friendly solutions like green roofs to mitigate temperatures and purify the air
from pollutants.
Al Hajeri said that the importance of the green building project lies in reducing carbon emissions
and improving the internal environment and air quality, thereby improving the health of the
community. The city will also have sustainable transport solutions that will further reduce the
carbon emission.
The first phase of the project is expected to be complete before Dubai hosts the World Expo 2020.

Oman’s IPP Manah power plant to transfer to govt in 2020
Oman Observer - Conrad Prabhu
The Manah power plant – Oman’s first Independent Power Project (IPP) which also blazed a new
trail in privately procured power generation capacity in the Middle East when it launched two
decades ago — transfers to government ownership in 2020.
The transfer, which will mark the end of the 20-year Power Purchase Agreement (PPA)
underpinning the procurement of the project, is billed as a significant milestone in the ongoing
evolution of the process of
liberalisation and privatisation
underway in Oman’s power and
water industry.
Located in Dakhiliyah
Governorate, the 264 megawatt
(MW) capacity gas-fired facility
was the first privately developed
and owned power plant when it
was brought into operation in
stages starting in 1996.
The project provided a useful
template for the procurement of
new privately developed and
financed power and water
schemes that underscore the
success of the Omani government’s pioneering efforts to unbundle, restructure and privatise this
critical sector. “(Manah IPP’s) Power Purchase Agreement (PPA) expires in December 2020, at
which time ownership of the plant transfers to the Government,” said the Oman Power and Water
Procurement Company (OPWP), which is the sole off-taker of output from Manah, as indeed other
power plants in operation across the Sultanate.
“OPWP is considering several options for the continued operation of the plant, including a
competitive tender for sale of the asset, backed by a multi-year PPA with OPWP,” the state-owned
utility — a wholly owned subsidiary of Nama Group — added in its newly released 7-Year Outlook Statement.
Significantly, Manah IPP is the first privately developed power plant that is scheduled to fall out
contract. Next in line to fall out of contract are the Al Kamil and Barka 1 power plants, which are
currently in the process of negotiations for contract extensions to the year 2021.
The latter schemes will also be eligible to bid in a revamped competitive process for new Power /
Water Purchase Agreements due to be rolled out by OPWP in 2022.The revamped competitive
process, currently under development by OPWP, envisages a new methodology for the
procurement of new electricity generation capacity. “It will allow existing generators, those
approaching contract expiration, to compete for new long-term contracts.
The first capacity procurement to use this new methodology is expected to be for contract terms
beginning in 2022,” according to the utility. Manah IPP, owned by United Power Company SAOG
(UPC), transfers to the government on December 31, 2020.

Morocco: Sound Energy provides update on Tendrara well,
Source: Sound Energ
Following the recent share price increase, Sound Energy, the European / Mediterranean focused
upstream gas company, has updated the market on continued positive developments at the
Company's Tendrara licence, onshore Morocco.
The Company continues with rigless operations and, having now secured contact with a
significant portion of the net pay, is pleased to announce that it has already achieved a very
significant gas flow rate which is in the process of stabilising during the clean up process.
The rate is already highly commercial and well above initial expectations. The Company will now
finalise the rigless operations and make further announcements, as anticipated, within approx. two
weeks time.

Pakistan: PPL gas discovery at Hadi X-1A, Gambat South Bloc
Source: PPL
Pakistan Petroleum Ltd (PPL), the operator of Gambat South Block with 65 percent working
interest (WI) along with its joint venture partners, Government Holdings Private Limited and Asia
Resources Oil Limited with 25 percent and 10 percent WI, respectively has announced a gas
discovery at its exploration well Hadi X-1A located in District Sanghar, Sindh.
Hadi X-1A was spud on February 5, 2016 and reached the final depth of 4,020 meters on April 19,
2016. Based on wireline logs interpretation, potential hydrocarbon bearing zones were identified in
Sembar Formation.
During initial testing in Sembar Formation immeasurable amount of gas flowed at the surface for
three days and reservoir appeared to be tight.
To further evaluate tight gas potential Frac job was conducted after which flow rates improved
significantly. The well flowed at 0.85 MMscfd gas at 32/64 inches choke size, thus confirming the
presence of natural gas at Hadi X-1A.
Post Frac results suggest that it is a tight gas discovery. However, further evaluation is required to
determine the size and commerciality of the discovery, based on post well studies and its
integration with geological, geophysical and engineering data collected during drilling and testing
of the well.

UK: EnQuest to farm out interest in Kraken field development to Delek
Source: EnQuest / energy-pedia
EnQuest announced Monday that it is holding discussions with Delek Group for the sale by
EnQuest to one of Delek’s subsidiaries of an interest in the Kraken development. EnQuest
confirms that EnQuest and Delek have signed a non-binding memorandum of understanding and
are working towards executing binding transaction documents. Delek is today releasing
information concerning this negotiation as part of its disclosure obligations with regard to a
separate transaction.
The key terms of the proposal are currently as follows:
• EnQuest to farm out to Delek a 20% working interest in Kraken.
• Delek would bear its share in the project capex from January 1, 2016.
• At completion, Delek will advance USD20 million to the Seller for a period of up to 5 years at an
annual interest of 3% which shall be returned to Delek in the event that its costs are not covered by
revenues within 5 years from the completion date.
• The parties are discussing mechanisms for additional contingent consideration, to be set out in
binding transaction documents.
• The parties may, prior to completion, by agreement and subject to requisite third party consents
(including that of EnQuest’s lenders), convert the transaction such that Delek may acquire a
subsidiary of EnQuest which holds a 20% working interest in Kraken.
There is no guarantee that a final agreement will be reached. EnQuest announced previously that
in addition to its ongoing cost reduction initiatives, it was also pursuing a range of further
opportunities for debt reduction, including potential asset sales and farm outs. The transaction is
subject to EnQuest’s lending banks’ consent. EnQuest continues to closely monitor and manage
its funding and liquidity position in light of the current market environment and is engaging as
appropriate with its credit facility providers (including banks and bondholders) in this regard.
Note that if Delek and EnQuest agree and sign binding transaction documents, completion of the
transaction would be subject to the normal third party consents. EnQuest will provide further
details in the event either of transaction documents being signed or of it becoming apparent that a
binding agreement cannot be reached.
Kraken field
According to information on the EnQuest web site - Kraken is a large heavy oil accumulation,
located in UKCS Block 9/2b, in the East Shetland
basin. It is one of the largest current development
projects in the UK North Sea and has an anticipated
production life of up to 25 years, with first oil is
targeted in 2017. The field will be produced via
the Armada Kraken FPSO. Current Kraken partners
are: EnQuest 70.5%,Cairn Energy 29.5%. Earlier this
year EnQuest increased its stake in Kraken to
70.5% with the acquisition, for nominal consideration,
of an additional 10.5% share from First Oil, thereby
increasing EnQuest’s net 2P reserves by 13 MMboe.

U.S. shale output drop seen for tenth straight month in August
Reuters + NewBase
U.S. shale oil production is expected to fall some 99,000 barrels per day in August, according to a
U.S. government forecast released on Monday that highlighted the hit to the industry from weak
global crude prices.
Total output is expected to fall to 4.55 million bpd, according to the U.S. Energy Information
Administration's (EIA) drilling productivity report. U.S. shale companies have scaled back
production since the price of U.S. crude slipped from above $100 a barrel in 2014. It traded at
about $45 on Monday.
Bakken production from North Dakota is expected to fall 32,000 bpd, the third monthly decline,
while production from the Eagle Ford formation in Texas is expected to drop 48,000 bpd, the
smallest monthly decline since March.
Production from the Permian Basin in West Texas is expected to fall 6,000 bpd, according to the
data, the smallest monthly decline since April.
New well oil output per rig is forecast to rise by 17 bpd to 858 bpd for the Bakken, up by 12 bpd to
515 bpd in the Permian and up by 24 bpd to 1,076 bpd in the Eagle Ford, data showed.
Total natural gas production, meanwhile, is forecast to decline for a sixth consecutive month in
August to 45.7 billion cubic feet per day (bcfd), the lowest level since July 2015, the EIA said.
That would be down a little over 0.4 bcfd from July, making it the smallest monthly decline in three
months, it noted.
The biggest regional decline was expected to be in Eagle Ford, down 0.2 bcfd from July to 5.8
bcfd in August, the lowest level of output in the basin since February 2014, the EIA said.

August output in the Marcellus formation, the biggest U.S. shale gas field, was expected to ease
by less than 0.1 bcfd from July to 18.0 bcfd. That would be the sixth monthly decline in a row,
falling to the lowest level since December.
In the Marcellus formation, located in Pennsylvania and West Virginia, initial production during the
first full month for a new well was expected to edge up to a record high 11.3 million cubic feet per
day in August. That compares with 9.5 mmcfd in August 2015.
If correct, that would be the 16th straight monthly increase in initial production for a new well in the
Marcellus. That growth rate, however, was on track to decline for a sixth consecutive month in
August.

U.S. oil companies closer to balancing capital investment with
operating cash flow ..Source: U.S. Energy Information Administration, based on Evaluate Energy
Although the crude oil price decline since 2014 has led to significant reductions in operating cash
flow for U.S. oil companies, their immediate financial situations are improving. As oil companies'
spending falls and crude oil prices increase, the need for oil companies to find external sources of
funding may decline, which could reduce financial strain in the coming quarters.
First-quarter 2016 financial results from U.S. onshore producers reveal an improving balance
between capital expenditure and operating cash flow. Although operating cash flow was the
lowest in any quarter in the past five years, larger reductions to capital expenditure brought these
companies closest to self-finance (when capital investment can be paid for entirely from operating
cash flow).
With crude oil prices such as the global benchmark Brent price averaging over $45 per barrel in
the second quarter—a 34% increase from first-quarter 2016—cash flow may improve and help
offset declining revenue from lower production.
The difference between operating cash flow and capital expenditure—known as free cash flow or
the financing gap—represents whether a company can pay for its investment through its after-tax
profits. Over the past five years, companies substantially increased investment spending to raise
production.
In 2012 and early 2013, operating cash flow was about half of capital expenditure, making
external finance necessary to pay for investment in production growth.
Sources of cash that do not come from operating activities typically come from:
• Selling property, equipment, other business segments, or other assets
• Issuing shares of stock
• Taking on debt, such as through borrowing from a bank or selling a bond

Operating cash flow has declined over the past year, but it nonetheless has covered an increasing
share of capital expenditure as companies are reducing their investment budgets more quickly.
Smaller investment budgets are lowering the amount of cash U.S. onshore oil producers need to
raise through outside sources.
Capital expenditure decreases, however, may lead to further declines in production for U.S. oil
producers. First-quarter 2016 was the first year-over-year decline in crude oil and other liquids
production for these companies in the past five years, driven by declines from existing fields and a
lack of new well drilling. Falling production would likely reduce revenue and cash flow absent an
increase in crude oil prices.
The companies included in this analysis are 39 public U.S. crude oil producers operating only
onshore fields. Their collective production averaged 2.1 million barrels per day, or approximately
30% of U.S. Lower 48 production in first-quarter 2016. These companies will release second-
quarter 2016 results in mid-August.

NewBase 19 July 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 oversupply concerns despite output cuts
Reuters + NewBase
Oil prices eased on Tuesday as concerns over a crude and refined fuel glut outweighed an
expected cut in U.S. shale production and a probable further draw in U.S. crude inventories.
Crude prices fell more than 1 percent in the previous session after worries about potential supply
disruptions stemming from an attempted coup in Turkey proved unfounded.
"Prices are a bit softer in the Asian trading period - traders and investors are torn which way prices
are going to break. It's a knife edge between optimism and pessimism," said Ben Le Brun, market
analyst at Sydney's Options Express.
The market is waiting for U.S. crude stocks data on Tuesday and Wednesday to help give
direction to prices, he said. Brent crude slipped 13 cents to $46.83 a barrel as of 0349 GMT after
finishing the previous session down 65 cents, or 1.4 percent.
U.S. crude, known as West Texas Intermediate (WTI), fell 14 cents to $45.10 a barrel after settling
71 cents, or about 1.6 percent, lower in the previous session.
Fuel inventories in the United States, Europe and Asia are brimming despite this being the peak
summer driving season, leading traders to store diesel on tankers at sea amid wilting demand
growth. With landed oil product storage nearly full as well, there is little support for any sustained
recovery in crude prices even as output tapers.
U.S. shale oil production is expected to fall in August for a tenth straight month, by 99,000 barrels
per day to 4.55 million bpd, according to a U.S. drilling productivity report on Monday.
Oil price special
coverage

Further weighing on supply, U.S. commercial crude oil inventories likely fell by 2.2 million barrels
last week, a Reuters poll of analysts showed on Monday.
That would be the ninth consecutive week stocks have fallen.
The poll was taken ahead of weekly oil stocks reports due on Tuesday from the American
Petroleum Institute (API) and on Wednesday from the U.S. Department of Energy's Energy
Information Administration (EIA).
Giving some support to prices, China's crude oil imports - which slowed partly due to seasonal
refinery maintenance in May and June - could rebound in the second half of the year as refineries
there further diversify sources of supply, shipbroker Banchero Costa (Bancosta) said in a report
on Tuesday.
China's crude imports grew 14.2 percent over January-June, with most of the gains coming from
huge increases in supply from Russia, Oman, Iraq and Brazil, said Ralph Leszczynski, head of
research at Bancosta.

Dark cloud of offshore fuel storage rising over oil price
Reuters - RON BOUSSO AND LIBBY GEORGE
This has not been the summer many oil traders had expected after last year's bumper profits.
Banking on more of the same, the world's refineries have churned out more diesel, gasoline and
jet fuel than eager drivers and holiday makers have been able to consume even over the summer
travel season.
Fuel inventories in the United States, Europe and Asia are brimming despite the height of peak
summer driving. European traders are now moving to store diesel on tankers at sea as on shore
storage tests its limits yet again.
At least one vessel, the 90,000 ton STI Grace has dropped anchor off the chic holiday town of
Southwold on England's east coast in what traders said was floating storage. The vessel was
chartered by Glencore. The Baar, Switzerland-based commodities trader did not immediately reply
to a request for comment.
Several other trading houses including Vitol, CCI Rolympus and Hartree have enquired about
floating storage in recent days, according to ship brokers.
The resurgence of floating storage, full tanks on land and the wilting demand growth underscore
the difficulty crude oil will face to find any sustained price recovery in the near term, even as crude
production itself tapers off.
"Global oil stocks refuse to come lower," said Tamas Varga, analyst with PVM Oil Associates.
Some market analysts had focused on drops in U.S. crude inventories, and expected declines in
oil production there, as a sign that the market had begun rebalancing, he said. "It is the product
stocks that should prevent any (crude oil) price recovery."
DOG DAYS COME EARLY
Benchmark diesel futures are trading in a contango until November 2017. This structure, when
prices in the future are above those a seller could get now, makes storing profitable. But with land
storage nearly full, a deep prompt contango of over $7 a ton and low freight rates, storing diesel
on tankers is profitable in some cases, according to traders and shipping brokers.
Gasoline traders are also locking in expected profits for next year, and in a rare move are stashing
summer-grade gasoline in tanks until next year.
U.S. gasoline futures, an indicator of the state of the global market, are in a sustained contango
for the first July in eight years, Varga said, highlighting the excess of product available now at
exactly at the time of year when it is usually in the highest demand.
It is a remarkable development, due in part to a stock build that has squashed profit margins for
refineries that have over the past two years of low oil prices benefited from a sharp rise in global
oil demand. But over production coupled with slower-than-expected demand growth are now
taking their toll.
Many refineries shifted their production yield in recent weeks from gasoline to distillates, such as
diesel and jet fuel, but only a sustained reduction of refining rates will likely change the picture,
said Robert Campbell, head of oil products markets at consultancy Energy Aspects.
"If not, a massive inventory hangover will bedevil the market for months to come," Campbell said.

NewBase Special Coverage
News Agencies News Release 19 July 2016
Exxon & Total ,fighting over the rights to build a $32 billion
LNG project. .. David Fickling in Sydney at dfickling@bloomberg.net
Who'd have thought that with a global gas glut forecast till the end of the decade, two of Big Oil's
largest beasts would be fighting over the rights to build a $32 billion LNG project.
That's what's happening in Papua New Guinea, where Exxon Mobil has trumped Total and Oil
Search's $2.2 billion, $40.25-a-share takeover offer for explorer InterOil with a $45-a-share
proposal.
Note: Japan contract import price reflects only spot prices so will tend to be more volatile than
Bloomberg Intelligence's average import price figure, which includes long-term contract prices.
Spot prices for LNG imports to Japan, the biggest importer, were running at $4.10 per million
British thermal units in May. Bloomberg Intelligence's average import price estimate is probably a
better measure of what gas producers can hope to earn but isn't much better, at $6.61/mmbtu in
April. Papua LNG, the giant export project on which InterOil's value depends, needs $6.96/mmbtu
just to break even.
Why get into a fight over a project that's set to lose money at current prices?
One reason is cost. Predicting long-term commodity prices is like trying to do the weather forecast
for a date five years in the future, so for the most part, resource companies barely try. Instead,

they attempt to benchmark themselves against competitors and ensure their production costs are
the lowest, on the basis that the cheapest producer will always be the last to fall during a market
slump and the best placed to profit when things rebound.
Papua New Guinea's gasfields are among the least costly in Asia Pacific. PNG LNG, an Exxon
Mobil-operated project that started production in 2014, breaks even at around $8.29/mmbtu,
according to Wood Mackenzie estimates. That leaves it in the cheapest half of LNG projects in the
region, according to an Oil Search presentation in May -- but InterOil's Papua LNG project is much
more frugal, close to the lowest quartile in Oil Search's ranking:
Those prices still look tough when you consider the current LNG market, but Exxon Mobil has
another advantage.
Papua New Guinea's gas is located in the country's highlands, a somewhat isolated area all but
unknown to the outside world until the 1960s. Getting it to consumers in Asia requires hundreds of
kilometers of pipelines crossing the rainforest and seafloor, plus LNG liquefaction plants and ship
terminals close to the capital Port Moresby.
PNG LNG's facilities, which cost $19 billion to build, are already up and running. If gas markets
remain in the doldrums, the best hope of cutting costs for both projects will be a deal to share
some of those facilities -- and that's going to be a lot easier if PNG LNG's operator Exxon Mobil
has a stake in Papua LNG as well.
The volume-weighted average price of Oil Search's shares has
been A$6.74 since its offer was announced May 20, according to
Bloomberg-compiled data. That's equivalent to about $5.11 at
current exchange rates. A 10 percent premium to Exxon's $45-a-
share offer would require $49.50-a-share, which would suggest
an exchange ratio of 9.7

Note: For "Papua LNG, Total wins" and "Papua LNG, Exxon wins", equity-share figures are based
on assumption of a 22.9% share for the PNG government, landowners and other stakeholders
once the project is in operation. This share is excluded from the "Papua LNG" share estimate
because the stakeholders haven't yet backed in their equity share. "Papua LNG, Exxon wins"
chart based on assumption that Exxon acquires InterOil's stake.
It's hard to see Total and Oil Search straining too hard to block Exxon Mobil. Total's net debt-to-
equity ratio would already be at slightly elevated levels of 31 percent if it puts up the $1.2 billion it's
promised in order to fund its side of the InterOil deal. Oil Search, for its part, had proposed to offer
8.05 shares for each InterOil one, a ratio that likely would have to rise above 9.5 if it wanted to
knock out Exxon Mobil's proposal.
Should the Texans win this battle, Total will still be the biggest shareholder in Papua LNG. Oil
Search will maintain its shareholding as well, even if it misses out on the extra equity and debt
cancellation it could have won under Total's offer. Bringing Exxon Mobil on board will also mean
that Papua LNG's $16 billion capital cost will be spread more widely, and hopefully reduced if
some of those facilities can be shared.
Total and Oil Search have three days to put in a counter-bid. They have most to gain from
standing pat.
C R E

NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
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For additional free subscription emails please contact Hawk Energy
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 19 July 2016 K. Al Awadi

New base energy news issue 888 dated 19 july 2016

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New base energy news issue 888 dated 19 july 2016