New base 582 special 14 april 2015

Copyright © 2015 NewBase www.hawkenergy.net Edited by Khaled Al Awadi – Energy Consultant All rights reserved. No part of this publication may be reproduced, redistributed,
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NewBase 14 April 2015 - Issue No. 582 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
Total Pulls Out Of Oman Offshore Exploration Block 41
Reuters + NewBase
French oil and gas giant Total has pulled out of a deepwater block41 in offshore Oman after
failing to make commercially attractive
discoveries, a senior Omani official told
reporters on Monday. Nasser Al Aufi,
undersecretary at the Ministry of Oil and Gas,
did not provide details regarding Total’s
decision.
The company signed an exploration and
production-sharing agreement in December
2013 for Block 41, which lies off the Omani
coast northwest of Muscat and covers almost
24,000 square kilometres of seabed with depths of up to 3,000 metres.
Aufi also said that last year Hungarian oil group MOL had pulled out from Block 34, and
Norwegian oil firm DNO from Block 31.

Oman’s PDO Says To Increase Oil Output 5% In Four Years
Reuters + NewBase
Petroleum Development Oman (PDO), the country’s top oil and gas producer, aims to lift
crude output by about five per cent over the next four years, managing director Raoul
Restucci said on Monday.
“We aspire to reach 600,000 barrels per day by 2019,” he told reporters at an annual briefing
on Oman’s energy industry, adding the company would then maintain that production level for
10 years.
PDO’s planned average output for this year is 570,000 bpd, although it exceeded that amount
in the first two months of the year, Restucci said in March. He said on Monday that PDO
planned to invest over $40 billion in its projects by 2019, but did not specify where the
company would obtain the money.
PDO is owned 60 per cent by Oman’s government, 34 per cent by Royal Dutch Shell, four per
cent by Total and two per cent by Portugal’s Partex, according to its website. Salim Nasser al-
Aufi, undersecretary at the Ministry of Oil and Gas, told the same briefing that government
spending on Oman’s oil sector totalled $8.7 billion last year while spending on natural gas
production was $2.8 billion.
Oman lacks the ample oil and financial
reserves of its wealthy Gulf neighbours
and its state budget has been hit hard
by the decline of oil prices. But it is
spending heavily to upgrade its energy
industry infrastructure and boost
production. Oman hopes to increase its
total crude oil output by five per cent to
one million bpd this year, Aufi said last
month.
Issam al-Zadjali, chief executive of
state-owned energy investment firm
Oman Oil Co (OOC), said on Monday
that OOC would refocus more of its investments inside the country. Sixty-five percent of the
company’s current investments are local; its investments in Europe are doing well but not
those in India and China, Zadjali added.
OOC and its partners had invested a total of OMR9.4 billion ($24.4 billion) in companies
within Oman as of 2013, according to its latest annual report. State-owned Oman Oil
Refineries and Petroleum Industries Co (ORPIC) suffered a loss of $4 million last year,
instead of the $725 million profit for which it was aiming, Chief Executive Musab al-Mahrouqi
told the briefing.
Changes in the market environment as oil prices plunged cost the company $571 million,
while technical problems at ORPIC’s Sohar refinery cut operations at its main refining unit by
76 per cent, costing a further $111 million.

Oman produces 943,000 bpd in 2014
Oman produced 943,000 barrels a day of oil and condensate combined in 2014, just
missing its target of 950,000 barrels a day, Oman’s Undersecretary of Oil and Gas said in
Muscat on Monday.
“Because of some problems we faced in the year, because of the condensate, we haven’t been
able to produce all the amounts we expected,” Undersecretary Salim Nasser Said Al Aufi told
reporters at the ministry’s annual media briefing.
Al Aufi did not state what the problems were.
The 943,000 barrels a day produced last year is in line with Oman’s annual production target of
around 950,000 barrels a day since 2007 when the country produced 710,000 barrels a day. Al
Aufi said Oman will continue to target 950,000 barrels a day but expects production to reach
980,000 barrels a day in 2015.
Oman is the largest Middle Eastern oil producer that is not a member of the Organisation of
Petroleum Exporting Countries (Opec), whose members pump a third of the world’s oil, according
to the US Energy Information Administration.
Oman added around 393 million barrels of oil to its general reserve in 2014, compared to 517
million barrels a year earlier, lifting oil reserves to 5.306 billion barrels as of December 31, 2014,
Al Aufi said.
Oman invested $11.5 billion (Dh42.2 billion) into its oil and gas sector in 2014, a year when crude
prices collapsed. Brent crude, the international marker for crude oil, fell from a June 2014 high of
around $115 to $45 in January 2015. On Monday, Brent was trading at $58.96 a barrel, up 1.88
per cent at 2pm local time.
The majority of oil and gas investments were in the oil sector, accounting for $8.7 billion spent
while $2.8 billion was invested into the gas sector. The majority of expenditures were for new
projects, Al Aufi said, while 30 to 35 per cent of investment was to maintain existing operations.

Saudi Arabi: Lukoil likely to pull out of Saudi
Reuters + NeBase
Lukoil will likely pull out from Saudi Arabia where the economics of its search for gas have been
crushed by the collapse of the oil price, three industry sources said. Lukoil is Russia's largest
private oil company. The Russian energy industry's ventures abroad often parallel Kremlin foreign
policy, which has turned cooler towards Saudi Arabia.
Some in Moscow blame Riyadh for allowing the oil price drop, which has hobbled Russia's
economy, by not cutting output. Lukoil was the last company left active in the consortia of
international oil firms Saudi Arabia invited in 2003-2004, part of a high profile drive to find gas in
its southeast Empty Quarter, the Rub al Khali.
It has a majority stake in Luksar - a joint venture with state oil company Saudi Aramco - which was
set to drill deep for the unconventional gas, called tight gas, this year after more than a decade-
long hunt for conventional deposits that has proved futile.
Luksar was winding down, an industry source said. "By June, six or seven people will be there, so
this is not a company anymore," the source said. "There are so many economic issues, it is
uneconomic, with the low oil prices, the deep targets, it is expensive."
A Lukoil source said the exit was likely.
"There is no chance to get a reasonable price for gas from the Saudi government now when oil is
so cheap," he said. Saudi Aramco has said it plans to cut costs and renegotiate contracts as a
result of the lower oil prices. The slump in oil prices since June is testing the ability of listed oil
companies to support cash flows and has sparked a rush to cut costs across the sector.
None of the other companies, with the exception of Royal Dutch Shell, have said publicly they
have pulled out from the Empty Quarter. But China's Sinopec, Italy's Eni and Spain's Repsol have
Deep exploration drilling on
Tukhman structure, Contract area
Block A in the Kingdom of Saudi
Arabia

all abandoned the search because of the relatively high cost and low returns of developing gas in
Saudi Arabia, where sales prices are fixed at a fraction of probable production costs.
"It wasn't a good prospect to begin with, the economic outlook has changed globally, it was always
a high risk development," said Sadad al-Husseini, a former senior executive of Saudi Aramco and
now an energy consultant.
A third industry source said Lukoil was evaluating its options in Saudi Arabia and that there was
no final definitive decision taken. Talks with Saudi officials were still ongoing but the company was
"close to taking a decision... if there is no movement on improving the economics of the project."
Saudi Aramco declined to comment.
Saudi Arabia wants natural gas to help it cover subsidised domestic power demand so it can save
its oil for more lucrative exports. Lukoil had decided to carry out trial work costing around $300
million in the Empty Quarter involving drilling one vertical and two horizontal wells which will take
about two years, chief executive officer Vagit Alekperov said in a Lukoil publication on January 31.
Alekperov said he was assured the gas price could be flexible for an individual project so its
economics are attractive for the investor. Lukoil, Russia's second-largest oil producer said in
March its net income fell by 39 percent last year to $4.75 billion, missing analysts expectations,
due to weaker oil prices and non-cash impairment losses.
Block A – Saudi Arabia – Luk Oil
In March 2004, LUKOIL Overseas joined the Block A exploration and development project. The
term of the contract is 40 years. A joint venture was created to execute the project, LUKOIL Saudi
Arabia Energy Ltd (LUKSAR), where LUKOIL Overseas owns 80% and 20% is owned by state oil
company Saudi Aramco. LUKSAR
opened an office in Al Khobar
(Eastern Province) in summer
2004.
Block A covers 29,900 square kilometers and is located in the Rub Al Khali desert in the southern
part of Saudi Arabia near Al Ghawar, the world’s largest oil field.
Exploration activities led to the discovery of a formation in the central part in the Tukhman
structure containing 85 million tons of oil equivalent, as well as the Mushaib gas condensate
formation containing 150 million tons of oil equivalent. A total of 9 exploration wells were drilled in
the block during the exploration period. With the discovered fields entering the appraisal stage,
90% of the Block A territory was returned to the state fund. The total area to be appraised in the
Tukhman and Mushaib fields is currently 2,900 square kilometers.
The appraisal plan until mid-2016 includes 3D seismic covering an area of 1,700 square
kilometers and drilling sidetracks from existing prospect wells. To date, an appraisal well has been
drilled in the Tukhman field, and a research project is ongoing to study the best tight gas
production techniques for the Mushaib field. Sidetracks from two existing prospect wells are
planned in 2015 to update reserves and test production flow rates for the field.

Downstream focus may help GCC refineries’ capacity rise
to 7.4mn bpd by 2022: S&P
Gulf Times + NewBase
The total capacity of GCC refineries may reach approximately 7.4mn barrels per day (bpd) by
2022 as Gulf producers reorient their focus on downstream projects in view of a decline in oil and
gas prices, a new report has shown.
The dip in oil and gas prices has encouraged Gulf producers to reorient their focus on
downstream projects, rather than curb spending altogether, said Standard & Poors in a report.
Gulf States are expanding their refineries to develop a downstream industry and export more
value-added products, diversify away from oil and gas income, and meet rising domestic needs for
fuel, it said.
Currently, Gulf refineries’ total capacity stands at 4.3mn bpd, S&P said, quoting consultants Frost
& Sullivan. S&P thinks that in certain jurisdictions the oil price decline could lead to an increased
focus on renewables and other means of securing energy supplies that are less dependent on the
cyclicality and volatility of oil prices.
An example would be the fiscal pressures Gulf sovereigns are facing as a result of recent
commodity price declines, and the consequent potential for energy subsidy reform that could pave
the way for more renewable projects in Gulf Cooperation Council (GCC) markets.
Historically, S&P said, power plants using subsidised fossil fuels have had an economic
advantage over renewable projects, typically wind or solar. However, lower government revenues
stemming from cheaper oil and natural gas have prompted some administrations to rethink their
energy subsidies. Oman, Qatar, and Bahrain have all raised the price of gas supplied to
downstream industries.
And any change in energy subsidies to the power sector that paved the way for more cost-

reflective tariffs will, in its view, improve the regulatory environment for renewable power projects
in the region.
“Despite the pressure of low oil prices, many governments have a commitment to use project
finance as an effective tool to meet essential infrastructure needs, both within and outside of the
oil and gas industry. They take the long term view and have not allowed the recent price drop to
influence capital spending.
“Saudi Arabia, Kuwait, and the UAE have all announced limited changes to their capital budgeting
plans for 2015-2016, despite low oil prices.” The commodity price dip has also encouraged Gulf
producers to explore shale opportunities. Speaking at an investment conference in Riyadh in
January 2015, Khalid A al-Falih, chief executive officer of Aramco, said publicly for the first time
that the company had already earmarked $3bn for shale gas exploration.
Historically, investment in shale projects has required high oil prices because of the significant
development costs associated with the exploratory phase, S&P pointed out. However, countries
which built up fiscal reserves when oil prices were high, like Saudi Arabia, have a compelling
reason for a presence in the shale sector, especially given recent technological advances in
extracting oil and gas from shale.
Market estimates put Saudi Arabian shale gas reserves at about 600tn cubic feet, and according
to S&P, Saudi Aramco was in talks to secure 40 extra rigs to cover shale gas operations,indicating
that it expected “large-scale production over the medium term.”
Because of lower prices, however, some Middle Eastern and African countries have revised the
subsidies they bring to certain projects. This, in turn, has elevated the importance of cost-reflective
tariff arrangements and market-based pricing.
“We think this will pave the way for more private-sector participation in some emerging markets in
the utilities sector, particularly by way of participation through PPPs in competing generation
plants.”

Indonesia: Pertamina, Kalla Group Agree to Build 4 Mtpa LNG Receiving Terminal
State owned energy firm Pertamina and Bumi Sarana Migas have agreed to build Indonesia’s
second land based LNG receiving terminal, news agency Reuters reported Monday. Bumi Sarana
Migas, a part of Kalla Group, and Pertamina have inked initial agreement to develop the 4 million-
tonne-per-year (MTPA) project.
Construction of the Bojonegara receiving terminal in Banten, Java should be complete by 2019,
Pertamina CEO Dwi Soetjipto said in a statement without giving details about when work would
commence, Reuters reported.
"Infrastructure is the main requirement in utilizing gas fuel, because once infrastructure is installed
demand will be created," Soetjipto said, noting that a power plant was expected to be built
afterward using gas from the terminal to feed into the western Java grid.
According to Reuters, the two firms have already completed pre-feasibility studies for the project,
with Pertamina expected to utilise 100 percent of the regasification facility for 20 years.

Shell Eyeing Onshore Gas Projects in Nigeria
The Guardian Nigeria + NewBase
Shell has started the process of reviewing some large gas projects onshore Nigeria,
according to The Guardian Nigeria newspaper.
This move is aimed at increasing company’s contribution to the nation’s LNG output, said Vice
President, Nigeria and Gabon, Shell Upstream International, Markus Droll adding that negotiations
have started with Nigerian National Petroleum Corporation (NNPC) and the Nigerian Liquefied
Natural Gas (NLNG).
“Onshore, we are reviewing a number of large gas projects. If funding solutions are agreed upon,
and when completed, these projects are expected to keep NLNG supplied with gas and to
contribute to Nigeria maintaining its strategic position in the global LNG market,” Droll said in a
paper titled ‘The Journey Towards Transformation’, The Guardian Nigeria reported.
He also stated that the company is committed to making the Assa North/Ohaji South project a
reality. “This would be one of the largest domestic gas projects in Nigeria,” Droll said.

Senegal:FAR provides evaluation plan for Cairn-operated
Source: FAR
Following the successful drilling campaign offshore Senegal in 2014, FAR Ltdand its joint
venture partnersConocoPhillips, Cairn Energy and Petrosen (the Government of Senegal) are
planning a first phase work program to evaluate the SNE-1 and FAN-1 discoveries. The work
program includes two
wells to appraise the
SNE-1 discovery and one
exploration well likely to
assess a 'shelf' prospect.
The program will also
include further evaluation
of the FAN-1 discovery
and a new 3D seismic
survey over a part of the
Contract area including a
portion of the Sangomar
and Rufisque blocks. An
evaluation work program
will be submitted to the
Government of Senegal
in May 2015.
The SNE-1 and FAN-1
wells (shown in Figure 1)
were the first exploration
wells to be drilled in the
deep water offshore
Senegal and were the
first to be drilled offshore
Senegal for 26 years. As
a result, these two wells
were highly significant
not only because they
discovered oil but
because they have
provided key data to
update pre-drill geological models and have given FAR strong encouragement that further
exploration drilling could result in more discoveries. To this end, and since the Notice of
Discoveries was submitted to the Government in November 2014, the joint venture has
progressed detailed analysis of SNE-1 and FAN-1 well data, extensive geological studies and
modern 3D seismic reprocessing. FAR has re-assessed its portfolio of exploration leads and
prospects based on the current data and these are included in this report.
Based on the size of the SNE-1 oil accumulation (gross, best estimate contingent resource 330
mmbbls*), excellent reservoir properties, known oil and gas column height and confidence in the
mapping of the structure on 3D seismic data, SNE is the more attractive discovery for early
evaluation and will be the initial focus of the joint venture’s evaluation work program. Cairn, the
Operator, anticipates that two appraisal wells will be drilled and the reservoir will be flow tested

and cored in the first phase evaluation program. The objective of appraisal drilling is to confirm
the reserves and productivity required for a commercial development (reference Cairn
Preliminary Results Announcement to the London Stock Exchange, 10 March 2015). The
minimum economic field size for a standalone development is estimated by Cairn, the Operator,
to be approx. 200 million barrels (reference Cairn Preliminary Results Announcement to the
London Stock Exchange, 10 March 2015).
Exploration wells are expected to focus initially on shelf prospects. Such prospects have the
potential to contribute to building a larger resource base for an initial development project. The
Operator estimates the minimum economic volume for a tie back development to be approx. 75
million barrels within a 25 km radius (reference Cairn Preliminary Results Announcement to the
London Stock Exchange, 10 March 2015).
The development concept outlined by Operator for a SNE field development consists of a
standalone Floating Production Storage and Offloading (FPSO) facility hub with potential to
integrate nearby discoveries as shown in Figure 2. Gas re-injection and/or water flood is also
contemplated (reference Cairn Preliminary Results Announcement to the London Stock
Exchange, 10 March 2015).
FAR has reworked the mapping of the prospects and leads on the shelf following the FAN-1 and
SNE-1 discoveries. The additional prospects mapped by FAR are shown in Table 1. Following
the discovery of oil in the SNE-1 well FAR assesses the probability of success of encountering
hydrocarbons for the shelf prospects to range from 33% to 52%.
Cairn, the Operator, continues work on finding an appropriate rig for the evaluation program. As
stated at a recent RBC Investor Lunch Series in London, the Operator said that with falling deep
water rig rates and the experience gained drilling offshore Senegal in 2014, they believe wells
could be drilled offshore Senegal at US$30-40 million per well (taking 30-40 days per well).
Based on this information, FAR estimates that the firm drilling program will cost approx. US$150
million with FAR’s share being approx. US$25 million (approx. AUD$33 million).

Statoil hits gas in Roald Rygg prospect (Norway)
Source: Statoil
Operator Statoil has together with PL602 partners made a gas discovery in the Roald Rygg
prospect in the Norwegian Sea. This is the second discovery made by Statoil in the Aasta
Hansteen area spring 2015.
The drilling of the Roald Rygg well 6706/12-3started on March 22, 2015 with a Transocean
Spitsbergen drilling rig.“Statoil has completed a targeted two well exploration programme around
Aasta Hansteen which aimed to
test additional potential in the
area and make the Aasta
Hansteen project more robust.
“Both wells, Snefrid Nord and
Roald Rygg, have resulted in
interesting discoveries, which
will now be further evaluated for
future tie-in to the Aasta
Hansteen
infrastructure,” says Irene
Rummelhoff, senior vice
president exploration Norway in
Statoil.
According to Statoil, the well
6706/12-3, drilled by the
Transocean Spitsbergen rig in
the Roald Rygg prospect,
proved a 38-metre gas column
in the Nise Formation with very
good reservoir quality. Statoil
estimates the volumes in Roald
Rygg to be in the range of 12-
44 million barrels of
recoverable oil equivalent (o.e.)
Roald Rygg is located less than 7 kilometres west of the Snefrid Nord discovery. The estimated
total volumes in the two discoveries correspond to about 25% of the Aasta Hansteen recoverable
volumes.
According to the company, Aasta Hansteen will be the largest SPAR platform in the world and is
the biggest ongoing field development project in the Norwegian Sea. It is one of the main projects
in Statoil’s portfolio. The plan for development and operations (PDO) was approved by the
Norwegian Ministry of Petroleum and Energy in 2013. Production start-up is expected in 2017.
Exploration well 6706/12-3 is situated in PL602 in the Norwegian Sea. Earlier this year, Statoil
increased its equity share in PL602 through transactions with Rocksource ASA and Atlantic
Petroleum Norge AS.
Subject to government approval, the PL602 partnership will consist of Statoil Petroleum AS
(operator, 42.5%), Petoro AS (20%), Centrica Resources (Norge) AS(20%), Wintershall Norge AS
(10%) and Atlantic Petroleum Norge AS (7.5%).

Oil Price Drop Special Coverage
Oil prices rallies over US shale production dip with small gains
News Agencies + NewBase
Crude prices rose today , Tuesday 14th
April 2015 after the US Energy Information Administration
said it expected US shale oil output to record its first monthly decline in over four years. Front-
month Brent crude futures were trading up 34 cents a $58.27 a barrel by 0106 GMT, while US
crude had risen 31 cents to $52.22.
The EIA expects US shale production to fall by 45,000 barrels to 4.98 million barrels per day in
May from April.
That would underscore how record crude output from the US shale boom may be backtracking
after global markets saw prices effectively slashed by 60 per cent since June on oversupply and
lacklustre demand.
While political instability in the Middle East also helped push prices higher, analysts said that high
global production and stocks were capping gains. "Geopolitical risk in oil markets remains
elevated. From a fundamental perspective however, supply from the Middle East is expected to
remain high, with Saudi Arabia and Iraqi production on the rise," JP Morgan said in a note.
"Our base case is for crude stocks to decline through 2015, as US production is expected to turn
lower in 2Q2015. If production, however, remains unchanged through the remainder of 2015, US
crude stocks will likely increase to above 540 million barrels during the fall refinery maintenance
period," it said.

US inventories in the week to April 3 surged nearly 11 million barrels to a fresh record high of
482.4 million, the US Department of Energy said. Meanwhile in Saudi Arabia, Oil Minister Ali Al-
Naimi announced output hit a record 10.3 million barrels a day in March.
The global oil market lost about 60 percent of its value to about $40 per barrel between June and
late January, owing largely to an oversupply in world markets and the OPEC’s refusal to cut
production.
The drop in big oil companies’ profits in the past eight months isn’t just a function of lower crude
prices - it also reflects strategic choices. A Reuters examination of corporate filings by some of the
biggest players in the industry, including BP, Shell and France’s Total, shows the sensitivity of
these companies’ earnings to changes in oil prices has risen in recent years.
This means that for every dollar the oil price drops, their profits sink more than they might have
done five years ago. Choices made by several oil majors that built more exposure to prices into
their portfolio, mainly through the kinds of contracts they opted to sign, was aimed at enjoying
prices that were historically high.
Japan’s nuclear industry pledges to refire reactors
Oman Observer + AFP
Japan’s pro-nuclear lobby pledged on Monday that 2015 would be the year reactors are restarted,
despite public wariness that has lingered since the Fukushima disaster. Industry officials and
supporters said the country desperately needs atomic power to play its part in cutting greenhouse
gas emissions and to ensure a stable electricity supply.
“This year marks the exit from zero nuclear power,” Takashi Imai, Chairman of the Japan Atomic

Industrial Forum, told an audience of around 900 people, including industry officials and global
policymakers.
“It is self-evident that nuclear power plants that have passed safety tests should be restarted as
soon as possible,” he said, citing the need for a stable power supply. Japan’s atomic watchdog
last year gave the green light to restarts for four reactors — a move welcomed by pro-nuclear
Prime Minister Shinzo Abe.
The push from the nuclear industry comes as the public remains deeply concerned about safety,
more than four years after a tsunami sparked meltdowns at Fukushima, spreading radiation over a
large area and forcing tens of thousands of people from their homes.
It also comes as Japan prepares to decide its new energy policy — how much electricity will come
from renewables, nuclear and fossil fuels — and readies to make a new international pledge on
cutting greenhouse gas emissions before a global summit on climate change this year. Yukiya
Amano, Director General of the International Atomic Energy Agency (IAEA), said the atom could
not be forsaken.
“Despite the Fukushima Dai-ichi accident, nuclear power has continued to play an important part
in the global energy mix,” he said. “Nuclear power can make countries more competitive by
delivering the steady supply of base-load electricity which is needed to power the modern
economy. It also helps to reduce emissions of greenhouse gas,” Amano said. — AFP

NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
Your partner in Energy Services
NewBase energy news is produced daily (Sunday to Thursday) and
sponsored by Hawk Energy Service – Dubai, UAE.
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 09 April 2015 K. Al Awadi

New base 582 special 14 april 2015

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