New base energy news issue 892 dated 25 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,
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NewBase Energy News 25 July 2016 - Issue No. 892 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: Enec and Khnp sign agreement for nuclear plant operations
Gulf News + Agencies
The Emirates Nuclear Energy Corporation (Enec) and Korea Hydro and Nuclear Power (Khnp)
have signed an Operating Support Services Agreement for the Barakah nuclear power plant, a
statement by Enec said.
ENEC and KHNP Sign Operating Support Services Agreement for the Barakah Nuclear Power Plant
The Emirates Nuclear Energy Corporation (ENEC) and Korea Hydro & Nuclear Power (KHNP)
have signed an Operating Support Services Agreement (OSSA) at a ceremony held at ENEC’s
headquarters in Abu Dhabi in the presence of senior management representatives from both
companies. Under the agreement, KHNP will dispatch experienced and qualified nuclear plant
personnel to the Barakah Nuclear Power Plant (BNPP), including main control room operators and
local operators, to support ENEC’s operating subsidiary, Nawah Energy Company (Nawah).
At the ceremony, H.E. Mohamed Al Hammadi, Chief Executive Officer of ENEC, and Mr Seok
Cho, CEO of KHNP, confirmed the joint commitment of both companies to the safe operations of
the four APR-1400 nuclear units under construction at Barakah, in the Western Region of Abu
Dhabi.
he contract was signed in Abu Dhabi by KHNP CEO Cho Seok and Enec CEO Mohamed Al Hammadi

As part of the scope of the OSSA to contribute to safe operations and maintenance of the nuclear
energy plants, an estimated 400 KHNP experts will support operations at the Barakah site every
year until 2030.
As per regulations of the Federal Authority for Nuclear Regulation (FANR), KHNP experts will be
required to pass regulatory exams to be licensed to operate and manage APR-1400 technology in
the UAE.
Mohamed Al Hammadi, ENEC CEO, said, “ENEC continues to progress construction to the
highest international standards of safety, quality and excellence. The OSSA provides the
framework for KHNP to share its knowledge that it has accumulated throughout its 40 years of
experience in operating 25 nuclear power plants in South Korea, with ENEC.”
“We are entering a crucial phase in the development of the Barakah plant and we are looking
forward to working with the experts from KHNP to ensure the operational readiness of the
Barakah plant,” continued Mr. Al Hammadi.
“Over the next decade and beyond, the agreement will continue to build on and enhance the
existing long-term nuclear energy partnership between the UAE and South Korea,” added Al
Hammadi.
The construction of the Barakah NPP commenced in 2012, and is scheduled for completion in
2020. With four reactors online, the facility will deliver up to a quarter of the UAE’s electricity
needs and save up to 12 million tons in carbon emissions every year.
The project at Barakah is progressing steadily. Overall, construction of Units 1 to 4 is now more
than 66 percent complete. All four units will deliver safe, clean, reliable and efficient nuclear
energy to the UAE grid, pending regulatory reviews and licensing.

Oman:Musandam’s first gas-fired power plant to launch in Feb
Oman Observer - Conrad Prabhu
Gas-based power generation will soon become a reality in Musandam Governorate when the first
Independent Power Project (IPP) in the Sultanate’s strategically important enclave in the north —
which overlooks the Strait of Hormuz — comes into operation next February.
Musandam Power Company (MPC), a
joint venture of the wholly government
owned investment entity Oman Oil
Company and LG International Corp of
South Korea, is currently developing the
120-megawatt (MW) capacity plant at
Tibat. When brought online in February
2017, the new IPP will supplement
diesel-based generation output operated
by the Rural Areas Electricity Company
(RAECO), a subsidiary of the Nama
Group tasked with providing electricity
and potable water coverage in areas
falling outside the nation’s grid-
connected zones.
According to Oman Power and Water
Procurement Company (OPWP), the sector’s sole procurer of new electricity generation and water
desalination capacity, the new Musandam IPP will meet projected electricity demand growth in the
governorate at least through 2022.
RAECO currently owns and operates a string of diesel-based power stations offering a combined
installed capacity of around 91 MW in the governorate. The largest of these plants — a 57 MW
capacity diesel powered station — currently supplies Khasab town.
Importantly, the IPP is under construction not far from a new oil and gas processing plant at Tibat,
owned and operated by Oman Oil Company Exploration & Production LLC (OOCEP), a subsidiary
of Oman Oil Company.
The Musandam Gas Plant, as it is known, processes production fluids from the nearby offshore
Bukha A and West Bukha fields and has a processing capacity of up to 20,000 barrels of crude,
45 million cubic feet of gas and 75 tonnes of LPG per day. Part of the natural gas output will be
used to power the new IPP.
With its anticipated launch early next year, the new Musandam power project will add to the governorate’s
growing civil infrastructure designed to leverage, among other features, its geo-strategic location and
untapped commercial and tourist appeal. With economic ties with Iran across the Hormuz Strait set to
burgeon, coupled with strong prospects for tourism investment, Oman is moving to develop the
governorate’s infrastructure to help capitalize on these opportunities.
Khasab, an emerging hotspot for cruise tourism, dhow trips, dolphin watching and adventure tourism, is
proposed to be developed into a full-fledged destination. Omran has been tasked with developing Khasab
Port into a mixed use waterfront based tourism attraction. Furthermore, to help meet Khasab’s growing
potable water needs, OPWP is preparing to launch the tendering process for the procurement of the
governorate’s first Independent Water Project (IWP). Khasab IWP, with a capacity of 16,000 cubic metres
per day (3 million imperial gallons per day MIGD), is targeted for launch in Q4 2019. “The procurement
process is expected to begin in 2016, pending final site approvals,” OPWP said.

Libya oil exports threatened as NOC warns against port deal
Reuters + NewBase
Libya's hopes to boost crude exports have been dealt a blow after the head of the National Oil
Corporation (NOC) objected to a deal between the government and local guards to reopen key
ports.
In a letter seen by Reuters to U.N. Libya envoy Martin Kobler and a number of oil and diplomatic
officials, NOC chairman Mustafa Sanalla said it was a mistake to reward Ibrahim Jathran, head of
the Petroleum Facilities Guard (PFG), for a blockade of the oil ports of Ras Lanuf, Es Sider and
Zueitina.
The PFG confirmed on Friday that it would implement an agreement with Libya's U.N.-backed
Government of National Accord (GNA) to reopen the ports within days, following a visit by Kobler
to meet Jathran in Ras Lanuf.
The terms for ending the
blockade have not been
made public, but an initial
payment for salaries for
Jathran's men has been
agreed, sources familiar
with the matter say.
In the letter, Sanalla said
the deal included payments
that would encourage other
groups to disrupt oil
operations in the hopes of a
similar payout.
"It sets a terrible precedent
and will encourage
anybody who can muster a
militia to shut down a
pipeline, an oilfield, or a
port, to see what they can
extort," the letter said.
Sanalla said the NOC
would not lift force majeure
at export terminals if a payout went through due to the risk that the corporation would face
liabilities. Should any court cases arise internationally for losses stemming from the blockade, "we,
as NOC, are determined not to be attached to these lawsuits", the letter said.
The NOC also threatened to withdraw its recognition of the GNA's leadership, or Presidential
Council.
Ali al-Hassi, a PFG spokesman, would not confirm whether any money had been received, but
said the guards' salaries should be paid now that the force was fulfilling its promise to open the
ports.
OPEC member Libya has been in turmoil for years, with rival governments and complex alliances
of armed groups vying for power and a share of the country's significant oil wealth.

Armed factions, labour disputes and security threats have helped slash oil output to less than a
quarter of the 1.6 million barrels per day (bpd) seen before the 2011 uprising against Muammar
Gaddafi.
The blockade by Jathran alone has cost Libya some $100 billion in lost export revenue, according
to the letter.
Sanalla's letter said that due to attacks from Islamic State militants and other damage, exports
from the ports would struggle to surpass 100,000 bpd in the near term, a fraction of their designed
capacity.
He added that NOC's largest subsidiary, Agoco, would be able to increase production by that
amount if it received its operational budget from the government. "To pay Jathran instead of
Agoco makes no sense, politically, economically or legally," Sanalla said.
Asked about the terms of any deal with the PFG, Ahmed Maiteeg, a member of the GNA's
Presidential Council, said only that he hoped the ports would open soon so Libya could earn badly
needed foreign currency.
The country faces a financial crunch because of the collapse in its oil revenues. "We heard many
times from the PFG that they will open the oil ports," he told reporters in Tripoli. "Hopefully this
time it will happen."
Jathran led blockades of the ports starting in 2013 saying he was trying to prevent corruption in oil
sales, though others have disputed his motives. The PFG has since helped push Islamic State
fighters back along the coast to Sirte, where they are surrounded by GNA-aligned forces.
Kobler's visit to Jathran focussed on continuing security cooperation with the GNA, diplomatic
sources said.

US:Refiners in US, stuck with lots of gasoline, switch to winter brew
Reuters + NewBase
Winter has come early for US refiners and blenders. In a summer of discontent with high
inventories and an unseasonably weak demand, some refiners have started blending winter grade
gasoline earlier than usual to sell later in the year, two trading sources told Reuters last week.
The switchover from summer blends, which are more environmentally friendly and costlier to
produce, usually happens in August for sale starting on September 15, the date allowed under US
government regulations. Winter blends are more likely to evaporate in the summer heat and
cause smog.
“Why produce more summer grade right now when you can produce something at a cheaper cost
and then be prepared to bring that into your supply chain right when the government specifications
allow,” said Eric Rosenfeldt, refined products trader at PAPCO.
But mixing more winter gasoline now threatens to worsen the glut later, a risk willingly taken by an
industry left with few other choices.
Big imports and a massive overhang in gasoline inventories have turned the market on its head
and pushed gasoline stockpiles to the highest levels for this time of the year in a quarter of a
century, even as demand from US motorists during the busy summer is near a record.
Independent US refiners are expected to post another quarter of weak earnings en route to
possibly the worst year since the shale boom began in 2011.
Summer grade gasoline is harder to produce than winter grade, which is why pump prices tend to
rise with the heat.
In the winter, when evaporation is less of a concern, gasoline is made with a higher Reid Vapor
Pressure (RVP), a common measure of the volatility of gasoline. This year, looking to cut costs,
refiners and blenders are making an early move to mix cheap butane — a cheaper blending

component than most other ingredients — to convert the summer barrels into winter barrels,
according to the trading sources.
Some see the shift as a sign of a tougher road ahead. “They made summer grade in winter
because winter was crap. Now they will make winter in summer because summer is crap,” said
one US East Coast trader.
Decisions by refiners to ramp up 2015 production cost them in the first quarter of 2016, as profits
were hit by an overhang of inventory. Part of the reason for the shift to winter grade is the anomaly
in the structure of the market, traders said.
Historically, gasoline prices weaken as autumn begins in September and refiners start to switch to
winter grade gasoline. But this time, the drop in forward prices is not expected to be as
pronounced as in the past six years.
Futures for delivery in September traded at a premium of just 7 cents to those for delivery in
October. That is well below the 20-cent gap at this time last year.
This, along with the overhang in summer-grade gasoline inventory, has motivated refiners to shift
to winter gasoline before August, betting that gasoline in storage would satisfy demand for the rest
of the summer.
US gasoline futures, which typically soar in July and August, have crashed about 17% from the
2016 high touched in May. With US gasoline stocks last week at 241mn barrels, 10% more than a
year ago and well above the five-year average, more run cuts are likely.
“Simply trimming the amount of crude a refinery processes does very little to reduce gasoline
supply,” Energy Aspects said in a note on Thursday.

U.K. onshore Wind Farm subsidies Ban May Cost Scotland $B3.9
Bloomberg - Jessica Shankleman Jess_Shankleman
The U.K. should review its decision to ban onshore wind subsidies, a move that could cost
Scotland as much as 3 billion pounds ($3.9 billion) and torpedo its clean energy targets,
lawmakers said.
The Scottish government’s views weren’t considered when former Prime Minister David
Cameron’s Conservative government said it wou ld end new subsidies for the technology,
according to a report issued Monday by the House of Commons Scottish Affairs Committee.
Scotland currently hosts about 60 percent of the U.K.’s onshore wind capacity.
Onshore wind is the U.K.’s cheapest way to produce low-carbon electricity, according to
Bloomberg New Energy Finance. Scotland’s fast wind speeds and long coastlines have helped
build up an industry that supports about 21,000 jobs and more than 1 billion pounds ($1.3 billion)
of annual investment, according to Scottish Renewables trade group.
“This is an important sector of Scotland’s economy, and also makes a vital contribution to meeting
our commitments to tackle climate change,” Committee chairman Pete Wishart said in a
statement. “The sector’s future success relies on a supportive policy framework.”
‘Bruising Impact’
The U.K. government should improve consultations with Scotland over future changes to renewable energy
support, according to the committee. Scotland wants to generate 100 percent of its energy from
renewables by 2020 -- a goal that probably will be missed without future support to wind energy, according
to the report.
“We have urged the government to clarify the future support which will be available to the renewable
sector, and set out how they will work with the Scottish government to develop a clear, long-term plan that
will allow renewable energy to remain a central part of the energy mix,” Wishart said.
The U.K.’s Department for Business, Energy and Industrial Strategy didn’t immediately respond to a
request for comment.
“The committee has highlighted the very real and bruising impacts of the sudden cuts and changes made
to renewable energy policy in the last year,” said Jenny Hogan, director of policy at Scottish Renewables,
in an e-mailed statement.

NewBase 25 July 2016 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Crude stays near 2-month low on oil glut worries
Reuters + NewBase
Crude prices inched down on Monday in Asia, staying not far from two-month lows hit in the
previous session, amid worries over a global oil glut. A strong dollar and the fourth weekly rise in
the U.S. oil rig count have helped relieve pressure on crude futures.
London Brent crude for September delivery was down 4 cents at $45.65 a barrel by 2243 GMT on
Sunday, after settling down 51 cents on Friday. The benchmark contract on Friday hit $45.17, the
lowest since May 11.
NYMEX crude for September delivery was down 5 cents at $44.14 a barrel, after closing down 56
cents on Friday. Libya's hopes to boost crude exports have been dealt a blow after the head of
the National Oil Corporation (NOC) objected to a deal between the government and local guards
to reopen key ports.
In a summer of discontent with high inventories and an unseasonably weak demand, some U.S.
refiners have started blending winter-grade gasoline earlier than usual to sell later in the year, two
trading sources told Reuters last week.
The world's biggest economies will work to support global
growth and better share the benefits of trade, policymakers
said on Sunday after a meeting dominated by the impact of
Britain's exit from Europe and fears of rising protectionism.
Money managers cut their net long U.S. crude futures and
options positions to a four-month low in the week to July 19,
the U.S. Commodity Futures Trading Commission said on Friday.
Oil price special
coverage

Rig Gains Add to Glut Concerns, as Oil Trades Near Two-Month Low as
Oil traded near the lowest close in more than two months as U.S. producers increased drilling for
a fourth week, raising speculation a global glut will persist.
Futures were little changed in New York after slipping 3.8 percent last week. Rigs targeting oil in
the U.S. rose by 14 to 371 for the longest run of gains since August, Baker Hughes Inc. said
Friday. Money managers added the most bets in a year on falling West Texas Intermediate
prices during the week ended July 19, according to Commodity Futures Trading Commission data.
Crude has fluctuated between about $43 and $52 a barrel since early June after almost doubling
from a 12-year low in February amid supply disruptions as speculation gains the worst of
the market rout is over. Commodities have also been affected by a stronger U.S. currency,
which typically reduces the appeal of dollar-denominated raw materials to investors.
“The general tone for the market at the moment is soft to sideways,” Ric Spooner, a chief analyst
at CMC Markets in Sydney, said by phone. “It’s being weighed down by U.S. dollar strength
against a background of relatively high inventories and the fact the rig count has begun to creep
up.”
WTI for September delivery was at $44.13 a barrel on the New York Mercantile Exchange, down 6
cents, at 11:44 a.m. Hong Kong time. The contract lost 1.3 percent to $44.19 on Friday, the lowest
close since May 9. Total volume traded was about 24 percent below the 100-day average.
Rig Count
Brent for September settlement was 4 cents lower at $45.65 a barrel on the London-based ICE
Futures Europe exchange. The contract dropped 51 cents to $45.69 on Friday, capping a 4
percent decline for the week. The global benchmark crude traded at a premium of $1.50 to WTI.

Drillers added the most rigs last week since December, according to Baker Hughes. Machines
have been put back to work seven of the past eight weeks. U.S. crude production has halted its
slide, increasing for a second week through July 15, according to data from the Energy
Information Administration.
Photographer: Andrew Burton/Getty Images

Oil Bulls Headed Over Demand Cliff as B
Bloomberg - Mark Shenk ShenkMark
Beware, oil bulls: Just as U.S. oil production sinks low enough to drain supplies, demand is about
to fall off a cliff.
American gasoline consumption typically ebbs in August and September as vacationers return
home, and refiners use that dip to shut for seasonal maintenance. Over the past five years,
refiners’ thirst for oil has dropped an average of 1.2 million barrels a day from July to October.
"People are looking ahead to the fall and are worried," said Michael Lynch, president of Strategic
Energy & Economic Research in Winchester, Massachusetts."There’s more and more talk of
prices going south of $40 and as a result people are going short."
Money managers added the most bets in a year on falling West Texas Intermediate crude prices
during the week ended July 19, according to Commodity Futures Trading Commission data. That
pulled their net-long position to the lowest since March. WTI dropped 4.6 percent to $44.65 a
barrel in the report week and traded at $44.14 at 11:53 a.m. Singapore time on Monday.
Ample Stockpiles
With weekly Energy Information Administration data showing U.S. gasoline stockpiles at the
highest seasonal level since at least 1990, refiners may shut sooner and for longer ahead of the
Labor Day holiday in early September, the end of the driving season.
"With gasoline supplies the highest since April, refiners may pull some projects forward," said Tim
Evans, an energy analyst at Citi Futures Perspective in New York. "This will take more support
away the market and add to the broader problem of excess supply."
Hedge funds’ net-long position in WTI fell by 23,665 futures and options combined to 156,804,
CFTC data showed. Shorts surged 24 percent, while longs, or bets on rising prices, increased 1.4
percent.

In other markets, net-bullish bets on Nymex gasoline dropped 18 percent to 1,020 contracts, the
lowest since November. Gasoline futures fell 3.8 percent. Net-long wagers on U.S. ultra low sulfur
diesel decreased 19 percent to 16,640 contracts. Futures slipped 5.4 percent.
"If we’ve gone through the bulk of the summer driving season and haven’t done much damage to
gasoline supply, refiners are going to react," said Michael D. Cohen, an analyst at Barclays Plc in
New York. "It will be hard to find investors that are willing to go long."
OPEC Production
The Organization of Petroleum Exporting Countries boosted production 0.7 percent to 32.9 million
barrels a day in June, according to Bloomberg estimates. Russian outputwill climb by 590,000
barrels a day over the next three years to exceed the former Soviet record, Goldman Sachs Group
Inc. said last week.
Even as U.S. crude stockpiles have dropped nine straight weeks amid supply disruptions in
Canada and Nigeria, the longest streak in EIA data going back to 1982, the seeds of higher future
output are being sown. Drillers targeting crude in the U.S. added 41 rigs over the past four weeks,
Baker Hughes Inc. data show.
"What’s striking about the nine-week streak is it’s consistency, not it’s overall size," Evans said.
"Back in May when the disruptions in Canada and Nigeria were at their peak, there were
estimates that inventories would drop an additional 10 to 20 million barrels on top of the normal
seasonal drop. Stockpiles are actually down a little less than is normal."

NewBase Special Coverage
News Agencies News Release 25 July 2016
Making Fracking Great Again
Liam Denning in San Francisco at ldenning1@bloomberg.net
Two giants of the oilfield services industry, Halliburton and Schlumberger, reported second-
quarter results this week and gave their assessment of where the oil and gas industry stands.
Unlike what you might have heard last night from Cleveland, these two actually see light at the
end of the tunnel.
Halliburton was boldest, declaring that its E&P clients had stopped focusing on "survival" in favor
of "growth." Schlumberger was a little less forthright. Even so, on Friday morning's call, CEO Paal
Kibsgaard agreed drilling activity in North America had bottomed out.
What comes next, though, is a curious mix of arm-wrestling and hand-holding that will decide
where oil prices go over the next couple of years.
In different words, both companies said the same thing: The collapse in drilling has stopped, but
now we need to get paid.
The Big Squeeze
Ebitda margins have collapsed as the oil-price crash has taken hold
Halliburton tied its message together with a nice sound bite: "900 is the new 2,000" -- referring to
the number of rigs it would take to absorb all the pumping capacity ("horsepower" in industry

parlance) available for fracking in the U.S. In other words, a lot of machinery has been left to rust
or been cannibalized for parts as E&P companies have retrenched during the downturn, even as
the intensity of ongoing drilling has ratcheted up. The implication is that, with the rig count
currently around the 450 mark, it won't take long to exhaust fracking capacity -- and pricing will
have to recover to encourage more of it onto the market.
Schlumberger's Kibsgaard, meanwhile, summed it up this way:
What has taken place over the past 21 months is instead a redistribution of the profit and cash
flow shortfall from previously sitting mostly with the oil producers to now representing an
unsustainable burden for the supplier industry even after a massive reduction of costs and
capacity.
Besides the impact of this on margins -- note the ugly chart above -- you can see what Kibsgaard
means when you look at what's happened to Schlumberger's receivables compared to revenue:
Waiting For That Pay
Receivables as a proportion of revenue at Schlumberger has jumped in recent quarters
The upshot of all this is two-fold.
First, it suggests strongly that U.S. shale cannot fulfill the role of swing producer in the global oil
market, as some have hoped. When two of the largest service contractors are saying they will
need a big share of the rewards from any increase in oil prices, that leaves less extra cash flow for
E&P companies to plow back into the ground.
In other words, E&P companies' cost per barrel will have to rise, meaning oil prices will have to
reflect that to encourage more drilling. You can see here that, over the long run, oil prices and
industry costs are best buds:

Following The Money
U.S. E&P cost inflation mirrors movements in the oil price
However, this doesn't mean shale can't act at all to cap oil-price rallies. The resources are still
there -- as a recent report from Rystad Energy served to underline -- they just require the proper
application of people, machinery and capital to exploit them.
The swing factor is time: How long to re-recruit laid off workers, build new horsepower, and raise
more funds? Halliburton and Schlumberger suggest this isn't a matter of mere months, and they
are likely right.
But even if it takes two years to stabilize and turn around U.S. oil production -- as estimated in a
recent report by Evercore ISI's James West -- that would still be a big change from the much
longer cycles that prevailed before this downturn. Expectations of the size and duration of future
oil rallies will have to adjust accordingly.
The other implication is that the business of fracking has to change fundamentally. Schlumberger
on Friday pointed out that, even with a recovery in oil prices, the E&P industry has to find a way to
reduce its cash burn. Looking at a sample of 87 U.S. E&P companies screened on the Bloomberg
terminal, you have to agree Schlumberger is onto something:
The Burning Issue
The E&P business was burning cash even before the collapse in oil prices in late 2014
E&P companies, too profligate when oil was at $100, cannot prosper over the long term by simply

passing losses up the supply chain. As the 30,000-odd job losses at Halliburton and
Schlumberger in just the first half of 2016 warn, E&P firms risk not having a supply chain to use.
The services firms are, of course, talking their own book when they say E&P companies need to
work more closely with them to ensure that cost savings coming out of this downturn are structural
rather than just cyclical. But they are also right, which bodes well for their shares, as they are
providing resources that are scarcer today than a year or two ago.
And despite the fact that E&P firms will have to share some of the spoils of higher oil prices as
they appear, they can also take heart from this. The fact is, operators have already shown they
can wring higher productivity from shale -- certainly far more easily than the majors have with
their mega-projects. Looking ahead, once the arm-wrestling is over, a bit of hand-holding between
E&P companies and their contractors should reap some sustainable gains in the form of lower
costs.

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 25 July 2016 K. Al Awadi

New base energy news issue 892 dated 25 july 2016

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New base energy news issue 892 dated 25 july 2016