KA-CARE nuclear city $100B top GCC project

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 09 September 2015 - Issue No. 683 Senior Editor Eng. Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
King Abdullah City for Atomic and Renewable Energy (K.A.CARE) ‘most
expensive’ project in GCC at $100 billion
Saudi Gazette + NewBase
Megaprojects worth hundreds of billions of dollars are creating enormous opportunities for
contractors, sub-contractors, suppliers, and manufacturers in the Middle East.
This is one of the suggestions of a new report published by Ventures Onsite, which details the
top 30 projects set for construction in the region over the next two decades. The report entitled
“GCC Major Building Projects” also revealed that a third of these major developments have still
not appointed a main contractor.
“Most projects without contractors are scheduled to start either at the end of the year or the start
of next year. So the nature of construction means they are likely to be close to making a decision,”
said Andy White, Vice President of dmg events and The Big 5 2015.
“Two of the projects in Oman will not begin until 2017, but the demand being generated for
building materials and equipment from other projects means the next few months represent an
ideal window of opportunity for contractors, suppliers, and manufacturers to secure contracts and
source products,” he added.
Mohammed Bin Rashid City, a 10-year multibillion dollar project in Dubai, is one of the most
expensive projects under construction in the report. The mixed-use project is set to become home

to Mall of the World, the world’s largest retail destination, and a family leisure entertainment
complex that is being built in partnership with Universal Studios. If all goes to plan it will also host
the biggest swimming pool in the world, at 40 acres.
However, with a projected cost of over $100 billion, the most expensive project in the report is the
King Abdullah City for Atomic and Renewable Energy (K.A.CARE) in Saudi Arabia. This state-of-
the-art sustainable city forms an important part of a region-wide focus on green construction and
sustainability and comes with ambitious plans to install 7GW of nuclear power and 41 GW of solar
capacity by 2040.
It is also expected to develop 20 gigwatts worth of geothermal and wind power, and has
established plans to construct 16 nuclear power plants with 17 gigawatts of capacity over the next
20 years, according to the World Nuclear Association, a trade group.
Construction of the city is scheduled to start early next year once a main contractor has been
appointed, the report said.
Meanwhile, the complexity and size of construction projects in the Middle East suggest
contractors may need to adapt their business models as the market shifts aggressively towards
government-sponsored infrastructure projects.
“The GCC has established a reputation for creating some of the most iconic skylines in the world.
The projects of the future are likely to be equally impressive, but a change is taking place in the
region and the next wave of construction will be infrastructure. This process has already begun
and promises to transform the region,” he said.
White said the fact the region’s top megaprojects are scheduled for completion between 2016
and the mid-2030’s reflects a long-term perspective towards the built environment that is being
guided by governments’ desire to improve quality of life in the region .

Oman’s flagship Orpic’s privatisation plan on track
Oman Observer - Conrad Prabhu
Plans for the privatisation of the wholly-government owned refining flagship Oman Oil Refineries
and Petroleum Industries Company Limited (Orpic) are on track, although a timeframe for the
landmark move has not yet been decided, according to a top official of the company.
Musab al Mahrouqi (pictured), Chief Executive Officer, said the proposed
disinvestment plan — via an Initial Public Offering on the Muscat Securities
Market — underscores Orpic’s strategic importance as sole provider of the
nation’s requirement of refined fuels, and an emerging petrochemicals giant as
well.
“There have been a couple of announcements by senior government officials that
Orpic is on track to be privatised. We are very excited about this opportunity. We see this as a
motivational element for the organisation, as well as the parent group (Oman Oil Company) in
general and we are already working to maximise the available capabilities within the company,” Al
Mahrouqi said during a media briefing following a tour of Orpic’s sprawling refinery complex at
Sohar Industrial Port.
Orpic, he said, was currently focused on strengthening its commercial appeal, as well as
strengthening ties with its stakeholders. “The relationships we have with the various stakeholders,
including the government, are being strengthened further in light of the prospect of an IPO. We
use this (prospect) all the time in our discussions and stress the need to build a strong commercial
company that’s able to attract local and international investors at that point of time.”
Orpic, which currently owns and operates the nation’s two refineries at Mina al Fahal and Sohar
as well as the aromatics and polypropylene plants integrated with the Sohar facility, is investing an
estimated $7 billion in a trio of projects that will elevate the company into one of Oman’s most
valuable and strategically important undertakings.
Orpic’s flagship Sohar Refinery is currently subject of a major expansion and modernisation at a
cost of around $2.6 billion. Dubbed the Sohar Refinery Improvement Project (SRIP), the upgrade
will enhance the refining capacity of the plant by around 70 per cent as well as increase the
production of gasoline, diesel, propylene, naphtha and bitumen. Next year, Orpic plans to kick off
construction work on a major petrochemicals project alongside its Sohar complex. The Liwa
Plastic venture (LPIC) is an estimated $.4.2 billion project that will double Orpic’s profitability.

India Gas Business: No Significant E&P Investment Expected in
Indian Gas Sector in Near Future
Crisil Research India
The Indian natural gas sector is not expected to see any significant increase in E&P investment in
the near future despite revised price mechanisms due to low gas price and lack of clarity on
“premium” for deep water and high pressure high temperature fields, according to Crisil Research,
India’s leading independent research house.
Low gas price and no clarity on “premium” will limit E&P investments, particularly in deep water
fields, said Rahul Prithiani, Director, Industry & Customised Research, Crisil Research during
the 5th Annual Conference on LNG Business in India: Amid Low Oil Prices held on 26-27 August
in New Delhi.
The procedure for determining the “premium” has yet to be notified by the government and
premium pricing is not applicable for discoveries made till October 2014.
However, despite expectation of lack of investment, Prithiani said production is set to rise with
development of existing discoveries, particularly by Indian state owned energy companies.
Domestic natural gas output is expected to rise from 92 mmscmd in 2014-15 (Apr-Mar) to 138
mmscmd in 2019-20. ONGC’s production will rise from 60 mmscmd in 2014-15 to 80 mmscmd in
2019-20.
ONGC’s Daman project (with peak output expectation of 8.5 mmscmd) and KG basin block
(approx. 22 mmscmd) are expected to drive production growth. Field Development Program
(FDP) for KG D6 satellite fields (10 mmscmd) and D-34 (15 mmscmd) have been approved with
investment of $3.8 billion but, Prithiani said, ongoing litigation and low domestic gas prices pose
potential downside risk to production.
The global LNG industry has seen some radical changes in the recent months. This sharp
decline in oil prices is attributed to a systemic demand-supply disequilibrium in the global
market. This has been characterized by a period of market tightness driven by Asian
demand & constrained supply growth; continuously expanding new supply sources &
addition of new LNG importing countries; greater application of new technologies in LNG
production & expansion in the end use of LNG mainly in the transport sector. Where
would India find its LNG business amid falling crude oil prices? Will there be new contract
terms introduced in the existing contracts? How would India benefit from the decreasing
energy prices and what are the challenges ahead ?

Output from unconventional sources like coal bed methane (CBM) is expected to be limited by
regulatory and land acquisition hurdles, he said.
Indian gas prices to remain muted for most of this decade
With Indian domestic prices now considerably linked to global benchmarks, depressed
international crude oil and gas prices are likely to keep local gas price muted.
“There is going to be a sustained period of depressed gas prices,” Prithiani said, adding that low
global gas prices are set to bring down domestic gas price to about $4/mmBtu by 2016-17 from
current $4.8/mmBtu. However, partial rebound in crude oil price over the longer term will lend
support to domestic gas price. From low of $4/mmBtu in 2016-17 price is forecast to rise to $4.5-
$5/mmBtu by 2019-20.
Indian gas market which till last October was completely regulated by the government has
gradually moved towards a market based one. Till October 2014, multiple gas pricing regimes
existed in India namely APM from nominated fields set by government, broadly on cost-plus basis
($4.2 per mmbtu), non-APM from nominated fields fixed by government ($4.2 – 5.25 per mmbtu),
pre-NELP which was contractually determined and based on alternate fuel prices ($3.5 – 5.73 per
mmbtu) and NELP which was formula based and needed to be approved by the government ($4.2
per mmbtu).
In October 2014, a “New Domestic Natural gas Pricing Guidelines” was notified linking domestic
gas price to global gas trading hubs: Henry Hub (US), Alberta (Canada), National Balancing Point
(Europe) and Russian domestic gas price. Fields where gas price is contractually determined,
such as the Pre-NELP fields (Panna-Mukta-Tapti) were exempt.
According to Prithiani LNG price ((Delivered Ex-Ship, India), both contracted and spot, are likely to
decline during the next few years. From $13.7/mmBtu in 2014-15 contracted LNG price is
expected to decline to $12.5-$13/mmBtu in 2015-16. In comparison spot LNG price is forecast to
see a significant slide from $11.3/mmBtu in 2014-15 to $7.5-$8/mmBtu in 2015-16.
This 60 percent premium over spot price will impact offtake of contracted LNG, Prithiani stated,
adding enforceability of “take-or-pay” will remain a key risk for marketers like GAIL.

Falling prices, higher output to boost consumption
Aided by falling price amid higher production, Indian gas consumption is set to grow to 204
mmscmd in 2019-20 from 140 mmscmd in 2014-15, an annual growth of almost 8 percent.
Fuel cost pass-through,
new urea investment
policy is likely to boost
gas demand from
fertilisers sector.
Demand from power
sector will see a leg up
due to rising supply and
subsidy for LNG based
power. Demand is
forecast to rise from 25
mmscmd in 2014-15 to
36 mmscmd in 2015-16
(when subsidies start
kicking in) to 61 mmscmd in 2019-20.
Assured domestic gas supply for compressed natural gas (CNG) and domestic piped natural gas
(PNG) will also aid demand growth, Prithiani said.
However, steep fall in price of alternate fuel will limit demand from industrial segments.
“Price of gas will be uncompetitive vis-à-vis coal and that will pose a challenge,” he said.

Indonesia: OPEC says Indonesia to reactive its group
Reuters
Indonesia is reactivating its membership of the Organization of the Petroleum Exporting Countries
in December, OPEC said on Tuesday, which would add almost 3 percent to the group's oil output
already close to a record high.
The southeast Asian country would be
the fourth-smallest producer in the
Organization of the Petroleum Exporting
Countries ahead of Libya, Ecuador and
Qatar, and bring the number of
participants to 13 countries.
Indonesia was the only Asian OPEC
member for nearly 50 years before
leaving the group at the start of 2009 as
oil prices hit a record high, and rising
domestic demand and falling production
turned it into a net oil importer.
In a statement, OPEC said Indonesia's request to reactivate its full membership was circulated to
OPEC members and following their feedback, OPEC's next meeting on Dec. 4 will include the
formalities of reactivating its membership.
Oil amp; opportunity Todd Colvin, SVP Global Institutional Sales, Ambrosino Brothers, and Pavel
Molchanov, Raymond James energy analyst, discuss the day market activity and whether the
market has begun to calm down?
"Indonesia has contributed much to OPEC's history," the statement from the group's Vienna
headquarters said. "We welcome its return to the Organization." Indonesia's Energy Minister,
who OPEC said will be invited to December's meeting, told Reuters earlier on Tuesday the
country would return as a full member.
The development is no great surprise as in OPEC terms Indonesia never really left. OPEC termed
its departure a "suspension." Ecuador, which rejoined in 2007, set a precedent for a return from
suspension. OPEC sources made clear the door was always open.
Indonesia's status as a net importer had raised the question of whether it would return as a full
member given that OPEC's Statute says any country with a "substantial net export of crude
petroleum" may become a full member.
OPEC pumps more than a third of the world's oil and is engaged in a defense of market share,
having dropped its long-standing policy of cutting output to support prices in November 2014.
The addition of Indonesia's output will boost OPEC's production by about 2.6 percent based on
July output figures towards 33 million barrels per day (bpd) - far in excess of OPEC's 30 million
bpd official target.
OPEC output has not been above 32 million bpd since 2008, before Indonesia's exit. Indonesia
produced 840,000 bpd in July, according to the International Energy Agency, and OPEC pumped
31.88 million bpd in July according to a Reuters survey - the highest monthly rate on record from
the current 12 members.

UK oil and gas output to rise for first time in 15 years
Source: Reuters + NewBase
British oil and gas production is set to rise for the first time in 15 years this year as investment in
more efficient technology pays off, the industry's association said on Wednesday.
Britain's oil and gas output has more than halved in the past 10 years due to easy-to-reach
resources running low and a lack of investments in new areas. This trend will likely reverse this
year when production is expected to rise 3-4 percent, the first increase since Britain's oil and gas
output peaked in 2000, lobby group Oil & Gas UK said.
'Despite a very difficult
business climate we are
beginning to turn a corner,'
Mike Tholen, economics
director for Oil & Gas UK, told
Reuters at the launch of the
association's yearly economic
report. 'We are turning a corner
in terms of the massive spend
on North Sea fields pulling
production up with it and on top
of that we're now begininig to
get to terms with the cost base
to find ways to make
businesses cope in a much
weaker environment.'
Preliminary government data showed oil and gas output over the first six months of this year rose
3 percent compared with 2014. The increase comes after years of investments in new
technologies that have meant new fields are run more efficiently.
However, the recent slump in oil prices has tightened oil companies' purse strings and Oil & Gas
UK expects capital expenditure to fall to 10-11 billion pounds ($16.91 billion)this year, down from
14.7 billion pounds last year.
Low oil prices in combination with high operating costs in the North Sea have caused many
operators to question the economic viability of continuing to run some of their oldest fields.
Maersk Oil said last month it would file for early decommissioning permission for its Janice field
in the North Sea.
'Inevitably there will be some more fields decommissioned as a result of low prices,' Tholen said.
'It's a significant concern but it's not the edge of the cliff.'
Bringing down operating costs in the North Sea is a key priority for operators and the British
government which hopes a rebound in production will also increase tax revenue. Since the start of
oil production in the 1970s, the industry has paid over 330 billion pounds in taxes to the British
government.
Oil & Gas UK expects operating costs to fall by more than 2 billion pounds, or 22 percent, by the
end of 2016 as companies work more efficiently.

NewBase 09 September - 2015 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil markets rise, remain weak as oversupply keeps biting
Reuters + NewBase
Crude oil prices rose today 09/09/2015, Wednesday as Asian stock markets caught a tailwind
from a strong performance in the United States and Europe, although fuel markets remained
generally dogged by oversupply.
Asian shares gained after upbeat German economic data powered rising U.S. and European
markets, and traders said the more upbeat sentiment in Asia had flowed through to oil markets.
The Brent global crude benchmark was trading at $49.75 per barrel at 0313 GMT, 23 cents up
from its last settlement after jumping 4 percent in the previous session. U.S. West Texas
Intermediate crude gained 19 cents to $46.13 a barrel after falling in the previous session.
In Japan, weekly crude and refined products statistics showed stable utilization rates and stock
levels.
Despite Wednesday's gains, concerns remained that high global production was being met with a
growing slowdown in demand, especially in the United States where the end of the summer
driving season means slowing consumption.
Oil price special
coverage

Oil prices have fallen almost 60 percent since June 2014 on a global supply glut, with prices
seesawing in recent weeks as concerns about a slowing Chinese economy caused turmoil in
global stock markets, while production remained near record highs.
"Commodity price volatility remains high with markets trying to establish a new base against the
headwind of weaker seasonal demand," ANZ bank said.
On the supply side, recent speculation that some producers were willing to cooperate in cutting
output in support of prices was dealt a blow this week by Russia and Mexico, who both said they
would not cut.
The Organization of the Petroleum Exporting Countries (OPEC) is producing close to record
volumes to squeeze out competition, especially from U.S. shale producers, which have so far
weathered the price plunges to keep pumping oil.
In oil politics, OPEC said that Indonesia was reactivating its membership of the oil exporter club
despite being a net crude importer.
If completed, the move would add almost 3 percent to OPEC's oil output, which is already close to
a record high.
Indonesia would be the fourth-smallest OPEC producer ahead of Libya, Ecuador and Qatar, and
bring the number of participants to 13 countries.
Indonesia was the only Asian OPEC member for nearly 50 years before leaving the group at the
start of 2009 as oil prices hit a record high, and rising domestic demand and falling production
turned it into a net oil importer.

Can Middle East oil pricing be fixed after China
breaks it?: Russell
Reuters - Clyde Russell
Nobody is happy with the current state of oil markets in Asia, apart maybe from some Chinese,
but they probably shouldn't be that pleased either. The reasons are multi-faceted but at the heart
is the breakdown and dislocation of the oil pricing mechanism for the bulk of Middle East crude
that is shipped to Asian refiners.
The current system has worked well for years, but the rise of China to becoming the world's
biggest crude buyer has also led to the increasing influence of the trading arms of its giant state-
controlled oil companies PetroChina and Sinopec .
PetroChina's trading arm Chinaoil and Sinopec's Unipec have in the past year established a
position of dominance in the daily price assessment for benchmark Dubai crude, used by Middle
East producers such as Saudi Arabia, Iran and Iraq to price their crude cargoes to Asia.
Aggressive trading by the two, heavy buying by Chinaoil and selling by Unipec, has made Middle
East crudes more expensive relative to oil from the Atlantic basin, such as crudes from Angola,
Nigeria and Latin American producers such as Brazil.
As a result, life has become more difficult for everybody from producers to traders to refiners
outside of China. For top exporter Saudi Arabia, the shifting dynamic has made it difficult for
them to keep their official selling price at a level that ensures they can maintain market share.
For traders such as Glencore , Trafigura, Mercuria and others they are no longer market makers
and are being forced to accept prices that squeeze their margins, and they are finding it harder to
source physical cargoes.

Refiners outside of China are being forced to pay more than they think they should for Middle East
grades supplied under term contracts, reducing profitability and the stability of pricing that they
desire.
Middle East producers, such as Saudi Arabia, Iraq, Iran and Kuwait set their official prices with
reference to the Dubai benchmark provided by pricing agency Platts. Platts in turn discovers the
price through a daily trading window whereby market players can buy or sell cargoes of approved
grades, currently Oman, Dubai and Upper Zakum.
This has worked satisfactorily in the past, as there was sufficient quantities of physical oil to meet
the demands of buyers during the Platts Dubai Market on Close ( MoC ) process.
THE CHINESE DOMINATE
But Chinaoil has roiled the market by bidding heavily, up to the point where there are now
concerns that the MoC will run out of available cargoes. In August, Chinaoil snapped up a record
number of cargoes with Unipec the main seller.
There are a whole host of theories as to why the two firms are bidding against each other, as it
would appear to benefit Chinaoil at the expense of other Chinese players.
Even then there is considerable doubt as to whether Chinaoil can make enough profit on paper
trades to offset losses on the physical market caused by bidding the Dubai price higher relative to
other benchmarks. What is certain is that even if Chinaoil can show a profit, the rising Dubai price
is costing China as a whole millions of dollars every month.
But in some ways it doesn't matter what the motivations of the Chinese traders are, only what the
impact is and what other market players can do about it if they feel the current system is no longer
working. The problem with the current process is that there is about 1.2 million barrels per day
(bpd) of freely tradable Oman, Dubai and Upper Zakum available.
Platts is mulling adding in more grades such as Abu Dhabi's Murban and Qatar's Al-Shaheen, but
this would most likely boost the available amount of crude for the MoC process by about one-third,
to somewhere close to 2 million bpd.
Given that Sinopec and PetroChina combined can process about 8 million bpd, it's unlikely that
adding grades will be enough.
"If you give an elephant 50 cookies and it isn't satisfied, will giving it 70 cookies make a difference"
was how one market participant put it this week during the oil industry's annual gathering in
Singapore.
PROBLEMS LIKELY TO PERSIST
So what can be done to fix this
The Chinese are working on creating a futures contract through the Shanghai International Energy
Exchange that will be yuan-denominated and deliverable in Shanghai and storages in northeast
China.
The contract may be launched in October, but it's still far from certain that it will gain widespread
acceptance rapidly.

Some market participants are worried about taking delivery in China, given the limited number of
potential buyers for crude cargoes, while others said the currency risk of being traded in yuan may
be an issue.
Another potential fix is for producing countries such as Saudi Arabia to dump the Platts
assessment and switch to using the Dubai Mercantile Exchange's (DME) Oman contract , which
allows for delivery and reduces counterparty risk. This is the most logical short-term solution as
Chinaoil and Unipec would find it much harder to dominate a regulated market like the DME in the
way they have taken over the MoC .
Other solutions include developing a new Middle East benchmark based on a crude stream such
as Iraq's Basra Light and Basra Heavy, but this would take time to gain acceptance and isn't likely
even in the medium term.
The reality is that even though the Middle East crude pricing system appears dysfunctional
currently, there is no easy fix and market participants are likely to have to adapt their strategies to
deal with the current situation.

NewBase Special Coverage
News Agencies News Release 09 Sep. 2015
Regulatory worries, oil prices take shine off Shell-BG deal
Reuters + NewBase
A look at valuations illustrates how regulatory concerns and stubbornly low energy prices have
stoked investor anxiety over Royal Dutch Shell’s planned takeover of British rival BG Group.
Hailed as an audacious and industry-changing merger when it was unveiled in April, the headline
value of the deal has slipped from £47bn ($72bn) to around £38bn because of the lower price of
Shell shares, which closely track oil prices.
Concerns that the Australian and Chinese regulators could set high hurdles and, more broadly,
that the persistently low oil prices could yet lead Shell to rethink the deal are dampening
sentiment. That has left BG shares trading at a discount to the Shell cash and share offer.
The wider malaise infecting the global equity market in recent weeks has also contributed to
heightened caution among investors. That gap between the price of BG shares and the Shell
cash and shares offer has widened over the past two weeks to an average of 16% from around
12% following the announcement of the deal on April 8, showing that sense of investor unease.
“The spread widening is driven by the risk-off environment and unwinding (of positions),” said
Lionel Melka, chief investment officer at Paris-based asset management company Bernheim,
Dreyfus & Co.

More tangibly, the Australian Competition and Consumer Commission said last week it needed
more time to review the takeover. It postponed a decision until September 17 as it weighs
whether the merger could impact Australian gas prices and hinder competition, particularly in
Queensland where both companies are developing large projects.
“In our view, the key risk is the Australian approval,” added Melka.
Investors were reminded of the risks associated with mega mergers in July after reports that US
antitrust enforcers voiced concerns that oilfield services provider Halliburton Co’s $35bn
acquisition of smaller rival Baker Hughes may lead to higher prices and less innovation.
However, the Shell-BG merger has received key approvals from US, Brazilian and European
regulators but still requires the green light from two Australian bodies as well as China. The deal
was seen as a bold bet by Shell on the oil price recovering to $80-$90 per barrel within three
years, but it currently remains under $50.
Despite the jitters, analysts still expect the deal to go through in its original form. They largely
agree with Shell chief executive Ben van Beurden’s assertion that the merger would make Shell “a
simpler and more profitable company, making Shell more resilient in a world where oil prices could
remain low for some time.”
BG is seen as much more vulnerable to a prolonged downturn since most of its projects break
even at price much higher than those for Shell. Shell’s low gearing allows it to finance the
acquisition while maintaining dividends while BG’s increased production will boost cash flow, UBS
analysts said in a note.
The industrial logic of the deal is still compelling for many investors. “Concerns about the deal not
going through due to low oil prices aren’t, in our view, justified... Overall we find the risk-reward
currently pretty attractive,” said Melka, who has invested in BG shares.
BG’s rapid oil and gas output growth in the coming years is set to make the combined entity the
top producer among international oil companies, leapfrogging Exxon Mobil at around 4mn barrels
of oil equivalent per day by 2020, according to analysts at US investment bank Simmons and
Company.
The acquisition will make the combined entity the world’s top liquified natural gas (LNG) producer
and the largest investor in Brazil’s deepwater oil production. A Shell spokesman declined to
comment, stressing that the deal was on course for completion in early 2016. Any delays to the
deal could result in BG shareholders missing out on one or possibly two Shell dividend payouts,
That would account for up to 3.8% of the spread between the two shares, according to Anish
Kapadia, Managing Director, International Upstream Research at US investment bank Tudor,
Pickering Holt and Co.
The gap between the offer valuation and BG share price would appear to offer pickings for
arbitrage deals — the buying and selling of related assets to profit from price differentials.
However, the sheer scale of the deal militates against this — buying 1% of BG shares requires
more than £300mn.
“The deal is so big that there are not enough arbitragers that can keep the spread in a tight
ranges,” said Niels Lammerts van Bueren, senior portfolio manager at Amsterdam-based
arbitrage fund TRZ Funds. “I don’t think anyone wants to go into the arbitrage too big so the
spread could widen further,” he added.

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MS & BS Mechanical Engineering (HON), USA
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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 September 2015 K. Al Awadi

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KA-CARE nuclear city $100B top GCC project

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KA-CARE nuclear city $100B top GCC project