New base 812 special 21 march 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 21 March 2016 - Issue No. 812 Edited & Produced by: Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
Iraq exports first natural gas shipment in its history
AP + Gulf News + NewBase
Iraq on Sunday exported the first shipment of natural gas in its history, a key development for the
Organisation of the Petroleum Exporting Countries (Opec) member struggling to feed a cash-
strapped economy.
The move revives a long-sought ambition by Iraq to be a gas exporter, thanks to a joint venture
with Anglo-Dutch Royal Dutch Shell PLC and Japan’s Mitsubishi Corp.
Iraq first planned to begin exporting gas in the late 1970s, but that timeline was delayed by the
Iraq-Iran war when Iraqi export ports were bombed.
A Panama-flagged gas carrier sailed on Sunday afternoon from Iraq’s southern port of Umm Qasr
on the Arabian Gulf with a cargo of about 10,000 standard cubic feet of gas in the form of
condensates, Oil Ministry spokesman Assem Jihad said.
Jihad wouldn’t reveal how much the cargo was worth or the buyer, but he added that the next
cargo will be shipped by the end of this month.
In November 2011, Iraq signed a $17 billion (Dh62 billion) deal to form a joint venture to gather,
process and market gas from three oilfields in the oil-rich province of Basra. The fields are the

17.8 billion-barrel Rumaila, the 4.1 billion barrel Zubair field, and the 8.6 billion barrel West Qurna
Stage 1.
In the 25-year joint venture, called the Basrah Gas Company, Iraq holds a 51 per cent stake and
Royal Dutch Shell has 44 per cent, with the remaining 5 per cent for Mitsubishi.
According the International Energy Agency, Iraq has estimated natural gas reserves of 112 trillion
cubic meters, making it the 11th largest in the world. The inauguration of Iraq’s gas industry is
meant to boost the coffers of a government badly in need of cash .
Iraq holds the world’s fourth-largest oil reserves, some 143.1 billion barrels, and oil revenues
make up nearly 95 per cent of its budget.
Like other oil-reliant countries, Iraq’s economy has been severely hit by plummeting oil prices
since 2014, plunging the nation into an acute financial crisis despite record crude oil export levels.
The crisis has forced Prime Minister Haidar Al Abadi’s government to introduce austerity
measures by eliminating government posts, merging some ministries, halting spending on
construction projects and imposing new taxes to pay for civil servants and fund the military.
According to Oil Ministry figures, Iraq exported an average of 3.225 million barrels a day in
February 2016, far below levels planned for this year’s budget.
Last month exports grossed about $2.2 billion, based on an average price of about $23 per barrel.
Iraq’s 2016 budget is based on an expected price of $45 per barrel with a daily export capacity of
3.6 million. As a result, the nearly 106 trillion Iraqi dinar (about $89.7 billion, Dh351 billion) budget
has a deficit of over 24 trillion dinars (about $20.5 billion). Officials plan to cover the shortfall with
loans from local and international lenders.

UAE: Adnoc, OMV and Occidental to explore offshore Abu Dhabi
oil and gas fields.. The National - Anthony McAuley
The Vienna-based oil company that is 25 per cent owned by the Abu Dhabi energy investment
vehicle Ipic said it had arranged a four-year seismic, drilling and engineering work programme to
explore and appraise oil and gasfields in the North-West Offshore Abu Dhabi area that includes
the Ghasha and Hail blocks.
The company said it had won the contract from Abu Dhabi National Oil Company (Adnoc) to work
in conjunction with Occidental Petroleum, which this time last year was awarded an evaluation
contract for the same areas.
Adnoc said at the time that it and Occidental would spend up to US$500 million to run 3D seismic
surveys, drilling appraisal wells and engineering studies by 2017 to evaluate the area’s
prospects.There was no mention by any of the parties last year or in yesterday’s statement about
how expenditure would be split, but Saoud Mubarak Al Mehairbi, Adnoc’s exploration manager,

had said: “Oxy will provide manpower support in form of ‘secondees’ … and will organise a
number of training courses to provide human resources development opportunities."
Similarly, OMV’s statement yesterday said: “OMV and Occidental will also contribute with
seconded personnel and technical expertise for the evaluation activities." OMV’s chief executive,
Rainer Seele, said: “This cooperation will further strengthen our already excellent partnership with
Adnoc," which includes the appraisal of the sour gas Shuwaihat field.
The exploration and production side of the industry has been severely hit by the oil price crash in
the past 18 months, but the OMV spokesman Robert Lechner said the Abu Dhabi opportunity was
too good to pass up. “Even in a low oil price environment it makes sense for OMV to further
develop assets in strategically important regions such as the UAE," he said.
Occidental’s $10 billion Al Hosn sour gas project produced its first gas last year, and its outgoing
chief, Stephen Chazen, estimated last year that its share of the project would generate between
$7.5bn and $12bn in cash over its 25-year life.
Nevertheless, he has consistently said the company would be open to selling some or all of its
stake, and the company has long-standing plans to reduce exposure to the Middle East in
general. OMV has struggled with stagnant production and only recently stabilised its earnings.
Previous geological evaluations have associated the Hair Dalmah and Ghasha structures with
natural gas rather than oil prospectively.

Oman: BP kicks off appraisal of Amin reservoir in Block 61
Oman Observer - Conrad Prabhu
BP Oman has commenced appraisal work targeting the Amin reservoir in the northern area of its
Block 61 licence in central Oman, a move that together with its Khazzan tight gas development
(Phase 1) and Block Extension, could see the energy major producing volumes equating to
around half of the Sultanate’s current combined gas output by 2020.
According to BP Country Manager Yousuf al Ojaili
(pictured), appraisal work on the Amin reservoir began
around two weeks ago as part of efforts to test the
performance of the reservoir, as well as appraise volumes
and gas quality.
At the same time, a developmental plan is under
formulation covering the Block Extension in the south and
west of the concession, a Heads of Agreement (HoA) for
which was inked recently with the Omani government, he
said.
Speaking at the annual media briefing hosted by the Ministry of Oil & Gas, Al Ojaili said the two
initiatives along with the ongoing Phase 1 Khazzan development could see BP Oman — a
partnership of BP (60 per cent) and Oman Oil E&P (40 per cent) — producing around 1.5 billion
cubic feet (bcf) of gas per day by the year 2020.
“Khazzan, as we all know, is the single largest project currently under execution in the Sultanate,
targeting very tight natural gas reservoirs with condensate. Phase 1 is targeted to add around 30
per cent to domestic gas production.
If we combine the Block
Extension phase, this
contribution goes up to 40
per cent, and we succeed
in the Northern Area
appraisal, then we will be
delivering gas equivalent to
more than 50 per cent of
current domestic
production,” he stated.
Overall project completion
has crossed the 65 per cent
mark, with around 31 wells
drilled so far, the Country
Manager said. The well count is projected to rise to 50 wells when Phase 1 commissioning
commences next year, he stated.
Construction work on a giant complex of facilities at Khazzan has reached the 60-65-per cent
mark, said Al Ojaili, with an army of around 11,000 workers focused on delivering a Central
Processing Facility with two gas processing trains and condensate processing facilities, along with
an expansive gas gathering system, power generation system, water treatment plant and road
network, among other components.

UAE: Dewa power stations switching lighting to LED to save
The National - LeAnne Graves
The switch to energy saving lighting by Dewa at two power stations in Dubai has cut power
consumption by nearly 75 per cent.
Etihad Esco, the agency responsible for implementing energy efficiency programmes in Dubai,
replaced 8,500 lighting fixtures with high efficiency LED lights in Dubai Electricity and Water
Authority’s Jebel Ali and Al Awir plants.
The project has resulted in annual savings of Dh6.6 million based on commercial electricity rates
in the emirate, a statement said.
“This pioneering project in Dubai demonstrates the viability and efficiency of the LED technology
in achieving energy savings while ensuring better light quality," said Stephane le Gentil, chief
executive of Etihad Esco.
The company said that Dewa’s investment of Dh21m would be paid back through savings in less
than three-and-a-half years. Mr le Gentil added that the biggest impact would be the large
reduction in energy consumption while reducing the maintenance budget for lighting to zero.
Olav Scholte, senior marketing manager at Philips Lighting, said at a conference in Dubai last
week that there would be a 70 per cent increase in lighting points globally by 2050 as a result of
population growth and increasing
urbanisation.
Lighting accounted for 19 per cent of
the world’s total electricity
consumption, but in the Middle East
region, that figure is slightly higher at
22 per cent, according to Alfonso
D’Andretta, Philips Lighting head of
systems centre in Dubai.
“Importance of energy efficient LED
lighting solutions is getting more
crucial every day for a more sustainable standard of living," he said.
ETIHAD ESCO AND DEWA SIGN TOGETHER AED 37 MILLION ENERGY SAVINGS PERFORMANCE CONTRACTS
14 January, 2015, Dubai, United Arab Emirates: Guaranteed energy savings of 31% to be generated in
DEWA-owned buildings and 68% in guaranteed energy savings in lighting upgrades

Indonesia's Expects Reduced LNG exports in Coming Years
Indonesia’s Badak LNG expects continuous decline in output for next few years due to insufficient
supply from depleting gas fields, Jakarta Post reported Friday. Badak LNG is one of country’s
biggest LNG plants. Output is expected to be 152 LNG cargoes this year, down from 182 cargoes
last year.
“This is because of a predicted decline in output from Mahakam block, which will be quite
significant. We will see additional input from Bangka field, but [not by much],” company’s president
director Salis Aprilian was quoted by the newspaper as saying.
The plant currently operates four trains, out of total eight. Plan is to shut down another plant by the
middle of this year, Jakarta Post added. Unless production from Mahakam is increased or at least
maintained, Badak will need to shut down another train in the near future. It is likely to operate
with only two LNG trains by 2019.

Kenya and Uganda presidents to meet oil companies over crude pipeline
Source: Reuters
Kenya and Uganda's presidents and oil company executives will meet on Monday to hold further
discussions on a route for a pipeline to transport the two countries' oil, the Kenyan president's
spokesman said on Sunday. Resolving the pipeline route is crucial to helping oil companies
involved in Uganda and Kenya to make final investment decisions on developing oil fields.
'President Uhuru Kenyatta will host
Ugandan President Yoweri Museveni
tomorrow ... They will discuss the
construction of the Uganda-Kenya oil
pipeline, a key plank of the Northern
Corridor Infrastructure Projects,'
Manoah Esipisu said in a statement.
Last week, Tanzania's presidency
said that Total, which has a stake in
Uganda's crude oil discoveries, had
set aside $4 billion to build a pipeline
from Ugandan fields to the Tanzanian
coast and that Tanzania wants the
three-year construction schedule
shortened. The comments raised the
stakes in a competition to secure the
pipeline with Kenya, which wants
Ugandan oil to be exported across its
territory and wants the pipeline to link
up with Kenyan oil fields.
'Kenya favours the northern route
through Lokichar, because as part of
the Lamu Port, South Sudan,
Ethiopia Transport (LAPSSET)
project, it would transform
infrastructure and the way of life of
the people in the towns and counties across its path,' Esipisu said. He added that officials
from Tullow Oil, Total and China's CNOOC had been invited to the meeting.
Total has previously raised security concerns about the Kenyan route. Sections of the Kenyan
pipeline could run near Somalia, from where militants have launched attacks on Kenya. But
industry officials have also said that connecting Kenyan fields, which have estimated total
recoverable reserves of 600 million barrels, with those in Uganda would make the pipeline
project cheaper because costs would be shared.
Both Kenya and Uganda, which the government says has a total 6 billion barrels of crude, have
yet to begin commercial production.
Tullow Oil and partner Africa Oil first struck oil in Lokichar in northwest Kenya in 2012. Africa
Oil and Tullow were 50-50 partners in Blocks 10 BB and 13T, where the discoveries were made.
Africa Oil has since sold a 25 percent stake in those blocks to A.P. Moller-Maersk.

India's thirst for gasoline helps spur global oil demand - John Kemp
REUTERS - BY JOHN KEMP
India's gasoline consumption is surging and has become one of the fastest-growing components
of global oil demand.
With other parts of the global economy struggling, continued growth in gasoline consumption in
India, together with the United States and China, has become one of the most important indicators
for global oil prices.
Saudi Arabia and other members of the Organization of the Petroleum Exporting Countries are
relying on India's continued consumption growth to help absorb excess crude supply and
rebalance the oil market in 2016/17.
India's drivers used 500,000 barrels per day of motor spirit in the 12 months ending in February
2016, according to the Petroleum Planning and Analysis Cell of the Ministry of Petroleum.
Gasoline consumption rose by more than 60,000 bpd in 2015 compared with an increase of
240,000 bpd in the (much larger) U.S. market.
Gasoline still accounts for a relatively small share, about 12 percent, of refined petroleum products
consumed in India. The corresponding figure for the United States is 47 percent.
But gasoline consumption has been growing much faster than petroleum demand as a whole as
the country becomes more affluent and the expanding urban middle class become car owners.

Gasoline consumption has grown at a compound annual rate of 11 percent over the last five years
compared with 5 percent for other products . Gasoline consumption growth surged to around 14
percent over the last year compared with 9 percent for other products.
Gasoline consumption has doubled since the start of 2009 and quadrupled since 1999, according
to India's Central Statistics Office. India's growing number of drivers provided the third-largest
increase in gasoline consumption anywhere in the world last year after the United States and
China.
The Ministry of Petroleum predicts gasoline consumption will increase further to almost 800,000
bpd by 2021/2022 . Since actual consumption is already running ahead of the five-year plan the
eventual outturn could be higher.
Sales of passenger cars and utility vehicles are expected to grow by as much as 12 percent in
2016/17 up from 6 percent in 2015/16, which translates to around 230,000 new vehicles hitting the
roads every month.
The government plans to spend around $14 billion in the next fiscal year upgrading the country's
road network ("India in the driver's seat as fuel demand roars at fastest rate ever", Reuters, March 17).
Consumption of other fuels and lubricants is also growing, although not as fast as the super-
charged gasoline market. India's total petroleum consumption has increased by around 340,000
bpd over the last year, with gasoline accounting for more than 18 percent of the increase.
India's fuel markets have become one of the most important sources of global oil demand growth
.India accounted for more than one barrel in every six of extra oil demand reported in 2015,
according to estimates prepared by the International Energy Agency.
Total consumption of petroleum products has doubled from 2 million bpd in 1998/99 to almost 4
million bpd in 2015/16. India's oil ministry predicts consumption will hit 5.4 million bpd by 2021/22.

NewBase 21 March 2016 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Crude oil falls for 2nd day as U.S. oil rig count rises
Reuters + NewBase
Crude oil slid for a second session on Monday, falling further from last week's 2016 highs on
concerns over a supply glut after the U.S rig count rose for the first time since December.
U.S. energy firms last week added one oil rig after 12 weeks of cuts, according to data by industry
firm Baker Hughes. The addition, coming after oil rigs had fallen by two-thirds over the past year
to 2009 lows, showed the fall in crude drilling stabilising after a 50 percent price rally since
February.
U.S. crude fell 40 cents, or 1.0 percent, to $39.04 a barrel by 0001 GMT. The market on Friday
climbed to $41.20 a barrel, its highest since early December, before losing ground to settle down
nearly 2 percent at $39.44.
Over the past two months, prices have rallied after the Organization of the Petroleum Exporting
Countries (OPEC) floated the idea of a production freeze at January's levels. Brent crude's front-
month contract was down 12 cents at $41.08. It hit a high of $42.54 a barrel in the last session.
"The rebound in crude oil prices in the last month appears to have stabilized the number of rigs at
work in the U.S. shale sector," ANZ said in a note to clients. "After falling for six consecutive
months, Baker Hughes data showed U.S. oil rig counts increased by one to 387."
Global oversupply in oil had knocked crude prices down from mid-2014 highs above $100 a barrel
to 12-year lows earlier this year, taking Brent to around $27 and U.S. crude to about $26.
The combination of declining oil output, smaller crude stockpile builds and surging gasoline
consumption in the United States also helped the recovery, although some analysts said the rally
had been overdone.
Oil price special
coverage

Why the Global Oil Glut Might Not Fill Swimming Pools After All
Bloomberg - Grant Smith
One of the warning lights that there’s too much oil around is no longer flashing, adding to signs
that global crude markets are finally on the mend.
Just a month ago, oil traders were weighing up whether to park unwanted crude aboard tankers
while BP Plc Chief Executive Officer Bob Dudley joked that swimming pools might be needed to
hold the excess. Yet instead of offering bumper profits, as in previous market gluts, stockpiling
barrels on ships would result in a financial loss, just as it has done for the past six months, in a
sign the current surplus may not be as big as feared.
Declining U.S. oil production coupled with disruptions in OPEC members Iraq and Nigeria have
helped revive crude to $40 a barrel, leading the International Energy Agency to conclude that the
worst of the rout is over. Contrary to expectations that tankers would be needed, onshore storage
hasn’t been exhausted, according to Torbjoern Kjus, an analyst at DNA ASA in Oslo.
“There’s less going into floating storage rather than more in the past few months,” Kjus said.
“Fundamentals are gradually improving. The worst of the price rout was just sentiment.”
A crude trader would lose about $7.6 million if they wanted to park 2 million barrels at sea for six
months, more than double the loss they would have swallowed in February, according to data
compiled by Bloomberg from E.A. Gibson Shipbrokers Ltd. and oil futures exchanges.
The losses from storage partly reflect that hiring a tanker has become more expensive amid
robust demand for crude. Day rates on the industry’s benchmark route -- to Japan from Saudi
Arabia -- advanced to $66,641, according to data from the Baltic Exchange in London. That’s
about 30 percent more than a month earlier. In dollars-per-barrel terms, the cost of using the ships
to store for six months advanced to $6.80 from $6.16 over the month, E.A. Gibson estimates.

Yet the economics also give an insight into the oil market itself. Storing crude at sea becomes
profitable when the spread between the current price and longer-term ones, known as contango,
is wide enough to cover the cost of hiring a tanker.
The gap between first and seven-month futures narrowed to $2.30 a barrel on Friday, the lowest
level since July, down from $5.07 a barrel on Jan. 29. It’s simply “nowhere near” enough to cover
the cost, Ted Petrone, vice chairman of tanker operator Navios Maritime Holdings Inc. said on
March 3.
It’s a distinct shift from the market conditions prevalent a month ago, when Chris Bake, a senior
executive at Vitol Group, said that with primary storage sites “pretty much full,” it was “probably a
good time to be a vessel owner.”
The biggest change between now and a month ago is oil supply that’s been unexpectedly curbed.
One pipeline linking the the northern part of Iraq to the Mediterranean Sea halted in mid-February,
while another from Nigeria was hit by sabotage. U.S. oil production is threatening to drop below 9
million barrels a day for the first time since November 2014.
From those three locations alone, combined output was restricted by about 1 million barrels a day
compared with a month earlier, according to data compiled by Bloomberg. That’s about half the
global surplus. Since then, flow from Iraq’s
Trading houses including Vitol, Koch Supply & Trading LP and Glencore Plc, plus the in-house
trading arms of BP and Royal Dutch Shell Plc, collectively made billions of dollars from 2008 to
2009 stockpiling crude at sea. At the peak of the floating storage spree, sheltered anchorages in
the North Sea, the Persian Gulf, the Singapore Strait and off South Africa each hosted dozens of
supertankers.
The receding risk that storage tanks will overflow encouraged Goldman Sachs Group Inc. in its
view that the worst for oil prices is over. “Your probability of having a containment issue, of
blowing out storage, is starting to decline,” Jeff Currie, New York-based head of commodities
research at Goldman Sachs Group Inc. said in a Bloomberg Television interview.

NewBase Special Coverage
News Agencies News Release 21 March 2016
Billions $ Loss for Generators as a Million U.S. Roofs Get Solar
Bloomberg - Jonathan Crawford
Rooftop solar is casting a $2 billion shadow over power generators across the eastern U.S.
With more than a million U.S. houses set to have solar panels by the end of next month, grid
managers serving the eastern U.S. plan to cut the amount of electricity they buy from conventional
plants by about 1,400 megawatts, starting in 2019, according to industry consultant ICF
International Inc. That’s enough juice to power about 780,000 households.
The result could be as much as $2 billion in lost revenue for generators that are already reeling
from lower demand, tight environmental regulation and depressed prices. Power producers
including NRG Energy Inc. warn that the growing reliance on solar may curtail investment in
conventional power plants, threatening the reliability of the U.S. electricity system. That’s already
happened in Germany, they say, citing plans by EON SE and RWE AG to scrap existing or
planned plants.
The decision “creates a risk you are going to repeat in the United States what’s happening in
Germany,” said George Katsigiannakis, a principal at Fairfax, Virginia-based ICF, in a telephone

interview. “The result of that is going to be that generating resources, reliable generating
resources, don’t make their money and they retire.”
Under "Energiewende," a German transition plan designed to lessen fossil fuel use, about 30
percent of the country’s power is now generated by renewables, sending power prices to their
lowest levels in more than a decade. That spurred EON’s Uniper unit to seek closure of two gas-
fired units in Bavaria, and Essen-based RWE to scrap plans to start up its coal-fired Westfalen-D
plant, valued at 1 billion euro ($1.1 billion).
While EON didn’t respond to a phone call and e-mail seeking comment, an RWE spokeswoman
said “nearly all of our stations are in the red” as a result of low prices.
“The considerable drop in wholesale electricity prices and the difficult political environment are
weighing on us,” Vera Buecker said in an e-mailed response to questions. “Many power plants are
hardly being used and cannot cover their costs.”
In the U.S., power availability is sold at auctions held by the operators of regional power grids
such as PJM Interconnection LLC, which serves more than 61 million customers ranging from
Washington to Chicago, and ISO New England Inc., which manages a six-state system with 7.1
million customers. The grids estimate their power needs to meet peak demand, then gather supply
commitments from generators who bid to sell their power.
This year, for the first time, PJM and New England have included solar growth in their estimates
for 2019, spurring a national debate on how the nation’s electrical system will be financed and
managed moving forward.

Falling Revenue
The new grid estimates come as generators have been battling a toxic combination of low prices
and increasingly stringent environmental rules. Wholesale power prices are largely determined by
the cost of natural gas, now trading at a 17-year low. The newly approved federal rules, estimated
to cost the industry $9.6 billion per year, now mandate the use of expensive "scrubbers" to curb
emissions.
Last year, revenue from electricity sales in the U.S. fell 1.3 percent to $388.1 billion, and the
industry retired almost 18,000 megawatts of generation, according to the Energy Information
Administration. A decision by the grids to factor in power from rooftop solar arrays in the future
would be "a double punch on the conventional power plants," Katsigiannakis said.
Abe Silverman, the assistant general counsel at NRG Energy, says the grids are trading reliability
for low costs by including weather-sensitive resources such as wind and solar.
If the grids are allowed “to suppress prices below economically sustainable levels, the region will
experience premature resource retirement and the inability to attract new" power plants, Silverman
said in an e-mailed response to questions.
Loss Breakdown
The $2 billion in losses identified by ICF International breaks down three ways for 2019.
Generators stand to lose as much as $716 million in New England’s auction, where demand for
conventionally-generated power has been cut by 390 megawatts, according to ICF. It’s a figure
that takes into account both the amount of new solar expected to be in use by 2019, and
estimates for the power lost when the sun isn’t shining. At the PJM auction, the loss is about $754
million, and in New York it’s about $523 million.
"It’s certainly possible to see rooftop solar growing to a level where it becomes a serious issue for
regulated utilities and merchant generators," said Swami Venkataraman, vice president and senior
credit officer for infrastructure finance at Moody’s Investors Service Inc. "It compounds all the
other issues if solar is also going to cause demand to go down."
To be sure, there is another side to the issue. Rooftop solar has been a bonus for consumers.
Last year, the average solar panel system generated enough electricity to meet the needs of 80
percent of the average household’s electricity, according to the Solar Energy Industries
Association. At the same time, utilities in about 30 states pay for the exports at the full retail price
of electricity, aiding their rapid deployment.
The practice, known as net metering, is being fought by power providers, who say customers
should pay more for the costs of maintaining the overall electrical system.
“This is only going to get more sizable in the future, because this is real capacity,” said Sanem
Sergici, a Cambridge, Massachusetts-based analyst at the Brattle Group Inc., in a telephone
interview. “The bottom line is that most of the grid operators are now really relying on these
distributed energy resources as long-term reliable resources.”
Spot wholesale power for PJM’s benchmark West hub fell $5.11, or 18 percent, to average $23.53
a megawatt-hour during the hour ended at 1 p.m. local time Wednesday from the same time a day
earlier, grid data compiled by Bloomberg showed.

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 21 March 2016 K. Al Awadi

New base 812 special 21 march 2016

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