Siemens to Build Major Gas Plant in Northern UAE

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NewBase 11 April 2016 - Issue No. 827 Edited & Produced by: Khaled Al Awadi
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UAE: Siemens to build gas power plant in Northern Emirates
The National - LeAnne Graves
Siemens will develop a major gas-fired power plant in the Northern Emirates to help the area meet
its growing power needs.
The German company signed a memorandum of understanding with the Federal Electricity and
Water Authority (Fewa) for the construction of a 2.2 gigawatt plant in the Northern Emirates to
“enhance the electricity infrastructure in the area", said Siemens. No other details were provided.
Dietmar Siersdorfer,
the chief executive
of Siemens Middle
East and UAE,
said that this deal
fell in line with the
company’s
strategy to play an
even greater role
in the country’s
power sector.
Siemens technology
accounts for about
40 per cent of
electricity generated
in the UAE. This
includes the
Dh1.47 billion
expansion at the
Jebel Ali M-Station
agreed last year.
While Siemens did not release specifics, the company is pushing its H-class gas turbines, which it
claims has the highest efficiency rates on the market, standing at 61 per cent.
Using less fuel means more for exporting, which is a plus in the low oil price environment. And all
of this would help the Northern Emirates as it struggles with insufficient power generation.
Fewa is trying to ramp up construction of additional capacity as well as draw power from the larger
emirates through the Emirates National Grid.
Last month, Fewa inaugurated the Dh33.9 million Al Hamra substation in Umm Al Quwain,
reducing loads on the old power station. Fewa’s external director of shared services, Adnan
Naseeb, said that there would be future expansion plans for Al Hamra.
Um Al Quowain

Saudi Aramco, Sabic said to study plan for joint oil refinery
Gulf Times + Bloomberg
Saudi Arabian Oil Co and Saudi Basic Industries Corp are studying a plan to build a joint refinery
that would produce chemical products directly from crude oil, according to two people with
knowledge of the talks.
The world’s largest crude exporter known as Saudi Aramco and Sabic, the second biggest
petrochemical maker in the world, are planning to build the refinery in Yanbu on the Red Sea
coast of Saudi Arabia, said the people, who asked not to be identified because the talks are
confidential.
Saudi Aramco declined to comment while Sabic didn’t respond to a request for comment.
“This move is long overdue given that both companies are operating and competing in the same
markets,” said Mohamed Ramady, a London-based energy analyst, said by phone. “Sabic and
Aramco cooperation will ensure that both companies will avoid duplication of projects in this period
of Saudi economic rationalization and cost effectiveness.”
In a recent interview with Bloomberg in Riyadh, Saudi Deputy Crown Prince Mohammed bin
Salman said a conflict between Aramco and Sabic had been resolved in the past few months.
Both independent companies will have a majority ownership by Saudi Arabia’s sovereign wealth
fund, the Public Investment Fund, the prince said.
“Having Aramco and Sabic working together is needed since both companies will report to the
Public Investment Fund and this eventually will create more natural synergies between them,”
John Sfakianakis, the director of economic research at Gulf Research Center in Riyadh, said by
phone.
Saudi Aramco and Sabic had been working separately on projects to produce chemicals straight
from crude oil without the need to have separate refineries, the people said. Aramco has delayed
plans to build an oil refinery with a petrochemical complex in Yanbu with a planned capacity of
400,000 bpd as it awaits progress on studies for the joint refinery with Sabic, they said.
Aramco’s chief executive officer, Amin Nasser, confirmed at a conference in Al-Ahsa, Saudi
Arabia, on March 30 that the company is testing the new technology to produce chemicals from
crude oil. Saudi Oil Minister Ali al-Naimi had announced in 2013 that the ministry was working with
Sabic for the construction of an oil-to-chemical refinery in Yanbu.
The Saudi government is pushing the two state-controlled companies to collaborate on the Yanbu
refinery project and to undertake more joint projects, said the two people with knowledge of the
talks.

Thailand: Mubadala to Drill Sri Trang-1 Well Offshore Block G1/48
by Tap Oil Ltd.|Press Release|
Tap Oil Limited, an Australian oil and gas exploration and production company, provided Monday
the following Funding and Exploration drilling update.
Funding Update
As announced March 31, Tap has now executed an Amended Facility Agreement with BNP
Paribas and Siam Commercial Bank (BNP Facility).
The current outstanding balance of the BNP Facility is $25 million. At current oil prices (Brent
forward as at April 7), Tap expects the outstanding balance of the BNP Facility at Dec. 31, ember
to be $9 million and the cash position to be approximately $7 million.
As part of the above amended facility agreement, the Company:
has hedged approximately 700,000 barrels of forecast Manora production from April 2016 to
February 2017 at an average swap price of $42.15/bbl, representing approximately 47.5 percent
of forecast volumes over the 11 month period; and
is in the process of raising a minimum of $5 million in additional capital through a pro rata
renounceable rights issue of fully paid ordinary shares in the Company for up to $5.8 million (AUD
7.75 million) (before costs).
The closing date for acceptance and payment for the rights is 5pm (AEST) Wednesday April 13.
Sri Trang-1 Exploration Well
The Tap Board has approved Tap’s participation in the Sri Trang-1 exploration well in the
Reservation Area of the G1/48 Concession in the Northern Gulf of Thailand.
The Sri Trang-1
exploration well is
located in the
Reservation Area of the
G1/48 Concession
approximately 11 miles
(18 kilometers) north
northeast of the Manora
oil development.
Mubadala Petroleum,
Operator of the G1/48
Reservation Area
concession, has
advised that the
Atwood Orca (400' ILC)
is currently expected to
commence drilling Sri
Trang-1 in mid May.
The well objective is to
evaluate the primary

Middle Miocene lacustrine sands target with secondary targets of Late Miocene fluvial sands. The
Middle Miocene lacustrine sands target is the main reservoir level at the Manora Oil Field. A valid
test of the primary objective Middle Miocene sands is essential as it will validate the hydrocarbon
prospectivity of the Northern Kra basin and de-risk dependent prospects immediately to the West
of Sri Trang-1.
The well is being drilled in shallow water and will be drilled to approximately 8,497 feet (2,590
meters) measured depth (8,153 feet or 2,485 meters true vertical depth). The well is expected to
take 10 days on a trouble free dry hole basis.
The outcome of the well will determine any likely development scenario, including a scenario
where a production platform is tied back to the Manora Production facility.
The drilling cost of the Sri Trang-1 well will be offset against the G1/48 Reservation Area fee ($3.8
million) paid to the Department of Mineral Fuels (DMF) by the Joint Venture of the Reservation
Area in the G1/48 concession. Providing the well comes in on budget, Tap will not be required to
contribute any further cash for the well. Tap’s share of the expected well cost is $1.02 million.

US: Waste-to-energy electricity generation concentrated in
Florida and Northeast
U.S. EIA, Monthly Electric Generator Report
At the end of 2015, the United States had 71 waste-to-energy (WTE) plants that generated
electricity in 20 U.S. states, with a total generating capacity of 2.3 gigawatts. Florida contains
more than one-fifth of the nation's WTE electricity generation capacity, and in 2015, Florida's Palm
Beach Renewable Energy Facility Number 2 became the first new WTE plant to come online
since 1995 and the largest single WTE electricity generator in the United States.
WTE plants account for a relatively small
portion of the total U.S. electric capacity
and generation, providing about 0.4% of
total U.S. electricity generation in
2015. WTE power plants convert the
combustible content of municipal solid
waste (MSW) to energy.
MSW contains biomass (or biogenic)
materials like paper, cardboard, food
waste, grass clippings, leaves, wood,
and leather products, as well as
nonbiogenic materials such as plastics,
metals, and petroleum-based synthetic
materials. The biogenic component of
MSW makes up about 59% of the total
tonnage, but because of a lower heat
content (i.e., less energy value), it

accounts for about half of the total net electricity generation.
In 2015, Florida and four states in the Northeast accounted for 61% of the total WTE power plant
capacity in the United States, and they produced 64% of total U.S. WTE electricity generation.
WTE plants are primarily intended as a MSW management option, with electricity generation a
secondary benefit. Burning MSW reduces the volume of waste by about 87%. The remainder is
ash from air pollutant emissions control systems, ash from the combusted material, and
noncombustible materials.
About 90% of WTE electricity generation capacity was added between 1980 and 1995, when
landfilling MSW was relatively expensive. In the early 1990s, as the mercury and dioxin emissions
implications associated with combusting MSW began to be recognized, most existing facilities had
to install air pollution control systems or be shut down, and the construction of new MSW-fired
electric generation capacity came to a halt.
Although Florida's Palm Beach facility is the first new WTE plant to come online since 1995, some
WTE generation capacity has been added to existing WTE plants since then.
Based on the most recent estimates from the U.S. Environmental Protection Agency, the United
States produced about 254 million tons of MSW in 2013. EIA estimates that WTE plants burned
about 29 million tons of MSW in 2015, of which 26 million tons were used to generate electricity.
The remaining tonnage of MSW was either recycled, composted, or disposed in a landfill.

NewBase 11 April 2016 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Crude oil futures rise as US drilling falls to 2009 lows
Reuters + BewBase
Oil futures on Monday extended sharp rises from the end of last week following a decline in U.S.
inventories and drilling, while outages and hopes that exporters could freeze output boosted
international prices.
U.S. West Texas Intermediate (WTI) crude futures were trading at $40.17 per barrel at 0002 GMT,
up 45 cents or 1.1 percent from their last close. International Brent crude futures were up 35
cents or 0.8 percent at $42.29 a barrel.
U.S. energy firms cut oil rigs for a third week in a row to the lowest level since November 2009, oil
services company Baker Hughes said Friday, as energy firms keep slashing spending despite
crude futures prices jumping roughly 50 percent since hitting a near 13-year low in February.
Drillers cut 8 oil rigs in the week to April 8, bringing the total rig count down to 354, Baker Hughes
said in its closely followed report. U.S. prices had previously been supported by a drop in U.S.
crude stocks, albeit from all-time highs.
Brent was lifted by production outages in the North Sea and West Africa, as well as by hopes that
a meeting of exporters planned for April 17 would result lead to an agreement to rein in ballooning
overpoduction that sees at least 1 million barrels per day pumped in excess of demand.
With both benchmarks back above $40 per barrel, analysts said that more investors could be
attracted if prices now breached highs reached in March, when Brent rose above $42.50 and WTI
rose to $41.90 per barrel. "Crude oil prices are back to or near the March high and a significant
resistance point. If oil prices can break above this level, investor sentiment towards commodities
should receive a further boost," ANZ bank said on Monday.
Oil price special
coverage

LNG Backers Face Comatose Market as Oil Shows Signs of Life
Bloomberg - Dan Murtaugh danmurtaugh
As oil markets look for the green shoots of a price recovery, LNG participants are hunkering down
for a long winter.
The most influential executives, investors and traders in the liquefied natural gas market will
gather in Perth, Australia, this week for the industry’s biggest conference. While Brent oil has
surged about 50 percent since hitting a 12-year low in January amid the worst energy crash in a
generation, LNG continues its downward slide.
For crude, two years of spending cuts have throttled output and begun to ease an unprecedented
period of oversupply. In the LNG markets, where projects cost billions of dollars and take years to
build, a backlog of developments sanctioned when prices were higher are bringing supply online
faster than demand can soak it up.
“It looks like we’re entering the down cycle for LNG rather than coming out the other side,” Jeff
Brown, president of consulting firm FGE, said by phone from Singapore. “For the spot market in
the next several years, it looks like there’s going to be a lot of LNG out there chasing buyers.”
Oil and LNG prices have historically been linked because traditional long-term contracts priced the
gas in relation to crude. That correlation held through 2014 and 2015, as prices for both fuels
tanked amid a global glut.
Opposite Directions
The two are now heading in opposite directions. Spot LNG in Singapore slipped to $4.029 per
million British thermal units the week of April 4, the lowest since Singapore Exchange Ltd. began
assessing it in September 2014 and extending its decline into a fifth month. Brent, meanwhile,
recovered from its early-year crash to post its best first quarter in four years. The global oil

benchmark rose as much as 1.2 percent on Monday to $42.45 a barrel, up about 13 percent since
the beginning of the year.
Oil production comes from a mixture of short-, medium- and long-term drilling projects, while LNG
output only comes from years-long efforts to build liquefaction plants and export terminals, said
Trevor Sikorski, an analyst with Energy Aspects Ltd. in London. In the U.S., where shale suppliers
can go to production from drilling within months, producers have cut about 600,000 barrels a day
of output since a June peak.
“In oil, the big thing is the loss of production, as drilling activity around the world has dropped off
and that’s balancing the market,” Sikorski said. “LNG is going to continue to throw gas at the world
as major projects come on stream and need to recover their big costs. It’s a perfect storm of stuff
to keep the spot market low.”
Liquefaction Action
LNG export complexes cool the fuel to minus 256 degrees Fahrenheit (minus 160 Celsius) to
shrink its volume so it can be shipped aboard ocean-going tankers. As U.S. and Australian
companies boost output an international gas market is emerging akin to the long-established one
for the more readily transportable crude oil.
About 42 million tons a year of liquefaction capacity is expected to come online this year, boosting
global supplies by 14 percent, according to the International Group of Liquefied Natural Gas
Importers. The majority of the new capacity will be in Australia, where Chevron Corp. recently
shipped the first cargo from its $54 billion Gorgon project.

The new supply was drawn by expectations of rampant demand growth in Asia that failed to
materialize. South Korea and Japan, the world’s two largest consumers, each reduced LNG
shipments by about 4 million tons in 2015 because of slow economic growth, mild weather and
increased use of alternative fuels, according to the importers group.
Market Deficit
The oversupply may only last a few years as low prices force the cancellation of some projects,
setting the market up for a potential shortage the next decade. Woodside Petroleum Ltd. and
partners including Royal Dutch Shell Plc and BP Plc last month scrapped plans to develop the $40
billion Browse venture in Australia citing an “extremely challenging” market.
There may be a deficit of 75 million metric tons of LNG per year by 2025, which would require
$250 billion in investment through 2020, Sanford C. Bernstein & Co. estimated in November.
However, the market is well-supplied to 2018 and possibly to the end of the decade, it said.
“This imminent supply surge has been well known for some time, and developers built in
anticipation of high Asian demand,” said James Taverner, a Tokyo-based energy analyst for IHS
Inc. “Demand fundamentals have turned bearish and the LNG market faces oversupply for at least
the next few years.”

NewBase Special Coverage
News Agencies News Release 11 April 2016
Shell under pressure to reduce spending
REUTERS - RON BOUSSO
Royal Dutch Shell is under pressure from shareholders to cut annual spending below $30 billion
after buying BG Group to ensure it can maintain its dividend given the slow oil price recovery.
Shell and other large oil companies slashed budgets, scrapped huge projects and cut tens of
thousands of jobs last year in the face of a slump in oil prices from a June 2014 peak of nearly
$116 a barrel to below $40.
Shell reduced spending by $8.4 billion to $28.9 billion last year and for the first time in more than
three decades global capital spending in the oil and gas industry, known as capex, is set to fall for
a second year in a row.
After the completion of the $50 billion BG acquisition, the Anglo-Dutch company set 2016
spending for the combined group at $33 billion and Chief Executive Officer Ben van Beurden said
in February it had "options on the table to further reduce our spending should conditions warrant
that step".
At $33 billion, Shell's capex is the highest among its rivals, exceeding that of U.S. giant Exxon
Mobil by about $10 billion. After increasing its debt to nearly 25 percent of its market capitalization
after the BG acquisition, investors and analysts say Shell must tighten its belt further.
"Shell needs to cut capex to give the market confidence that the dividend can be sustained, and
grown in future," said Charles Whall, portfolio manager at Investec Asset Management, which
owns Shell shares.

Whall expects Shell's 2016 capex to be cut below $30 billion, and to trend lower.
Steady dividend payouts have been the main attraction for investors in large oil companies over
the years and some have tapped the debt market to maintain payouts in the face of last year's oil
price rout.
Shell, for example, has not cut its dividend since the Second World War and has vowed to keep it
unchanged following the BG deal.
NEW ASSETS
Ben Ritchie, senior investment manager at Aberdeen Asset Management, which is a top 10
investor in Shell, said while the company was expected to do more to reduce costs, it should not
endanger growth.
"We wouldn't be surprised to see capex guidance lowered again. However, we want the company
to continue to focus on driving long-term growth," Ritchie said.
"Simply cancelling or deferring economically viable projects to hit a lower capex number doesn't
make sense, especially when the company's balance sheet remains reasonably robust," he said.

Following the BG acquisition, Shell's production and cash flow is set to grow rapidly thanks to new
assets in Brazil's offshore deepwater oil fields and Australian gas, and hence its need to invest in
new projects is lower, according to analysts at Bernstein, who rate the company's shares as
"outperform".
"Shell has yet to give investors enough comfort that all the numbers stack up in 2016 if oil prices
don't move up from current levels," Bernstein said, anticipating that Shell will revise its 2016 capex
to $28 billion at its June 7 investor day.
Spending cuts could include a $1 billion reduction in exploration, about $2 billion from cost savings
and some $1.8 billion from project delays or cancellations, they said.
Shell has "the capacity to reduce capex significantly, and should have had sufficient time by June
to review the portfolio following the BG acquisition," Investec's Whall said. According to a top 20
investor in Shell who declined to be identified, Shell should aim to reduce spending to $25 billion
by 2017: "Anything above $28-$30 billion in 2016 would be a disappointment."
Shell's shares have traded at a discount to most rivals over the past year though 25 out of 32
analysts have "buy" or "strong buy" recommendations for Shell, according to Reuters data.
Shell's 12-month forward share price-to-earnings ratio is below 20 compared with an average of
about 27 for its peers, which indicates investors are anticipating higher growth from rivals,
according to Reuters data. Signaling further capex and costs reductions would boost investor
confidence in the stock, according to Whall.
"If Shell can deliver clear, decisive capex guidance and instil confidence in the dividend
sustainability, there is considerable performance potential given its valuation discount," he said.
"Ben van Beurden can pull this together."

Oil market seen better off gauging US supplies despite freeze talks
Oil investors looking for signs of a sustained price recovery would do well to assess US supplies
rather than the banter between major producers on freezing output, according to Saxo Bank.
While Opec members and producers outside the group are set to meet in Qatar this month to
discuss a deal, just a cap on output would have limited impact on prices because several
participants are already pumping near record amounts of crude, Ole Hansen, the bank’s head of
commodity strategy, said in an interview last Thursday.
The rebalancing of the oil market amid a glut triggered by the US shale boom hinges more on
American drilling activity, he said. Oil has rallied since mid-February amid speculation that nations
including Saudi Arabia, the biggest member of the Organization of Petroleum Exporting Countries,
and Russia will agree to freeze output and shrink the glut that sent Brent crude to a 12-year low in
January. For all the comments from various producers during “a cat and mouse game” in the lead
up to the gathering in Doha on April 17, there’s been no definitive action on curbing supplies,
according to Saxo.

“The market can be fooled, and we have been fooled,” Hansen said. “We have seen almost a 50%
recovery in oil prices since the first signs of verbal intervention emerged back in January. So a lot
has been achieved already without doing anything, so I think at this stage they will be very happy
if they can just keep the market in the belief that action can be taken if necessary.”
While global producers are “buying time” and waiting for the focus to shift from the oversupply to
rising demand, US producers will “absolutely” be the ones driving the potential rebalancing of the
oil market, according to Hansen.
“No doubt, because they have the ability to react much quicker to price changes,” he said,
referring to US producers. He warned that a price surge to $55 to $60 a barrel may prompt drillers
to pump more. Others including Goldman Sachs Group Inc, UBS Group AG and IHS Energy have
also said a recovery in crude may sputter once prices go high enough to keep US oil flowing.
After surging to 9.6mn bpd last year, the highest level in more than three decades, daily US
production has dropped to about 9mn as of early April. Meanwhile, the number of rigs drilling for
oil in the US has dropped to the lowest level since 2009.
Still, the market may reach equilibrium in 2017, according to Hansen. The International Energy
Agency has warned that investment cuts taking place now because of the energy downturn
increase the possibility of oil-security surprises in the “not-too-distant” future.
Oil prices had slid to $27.10 on January 20, the lowest level since November 2003.
With major producers already producing near record volumes, the impact of an agreement to keep
output at January levels will be limited, said Hansen. Iraq has the potential to continue to increase
supplies, even though the country still needs investments to boost output, while Russia is seen
nearing peak production, he said.
Iran plans to boost crude output to 4mn bpd, the highest level since 2008, before it will consider
joining other suppliers in seeking ways to rebalance the global oil market, Oil Minister Bijan
Namdar Zanganeh said, according to a report from the Iranian Students News Agency on March
14.
Saudi Arabia has said it will only freeze output if it’s joined by other suppliers including Iran, while
Kuwait has signalled a deal doesn’t hinge on the Gulf state.
“For every month they manage to keep us satisfied, that something will happen, then we move
closer to the time where the market will take over and start to look at the potential risk of where
supplies are going to come from,” Hansen said.

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Khaled Malallah Al Awadi,
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MS & BS Mechanical Engineering (HON), USA
Emarat member since 1990
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Mobile: +97150-4822502
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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 11 April 2016 K. Al Awadi

Siemens to Build Major Gas Plant in Northern UAE

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