New base 733 special 22 november 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 22 November 2015 - Issue No. 733 Senior Editor Eng. Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
Masdar research boils up hot idea for water desalination
The National
Amid the UAE’s celebration of Innovation Week, which kicks off Sunday, students at the Masdar
Institute are working on projects to support the development of the Emirates, including drinking
water made from geothermal energy.
However, using this resource as a
desalination method, or removing
salt from water to make it potable,
is under-explored. Savvina
Loutatidou, 26, from Greece is
trying to change that. “Solar
desalination will be implemented
in the UAE, but I … thought it
would be interesting to know
about other [methods],” said the
researchr and PhD candidate at
the Masdar Institute.
The consumption of desalinated
water in Abu Dhabi has nearly
doubled over the past decade to
1.126 billion cubic metres from
667 million cubic metres, according to Statistics Centre Abu Dhabi. Yet the price associated with
desalination is often high because it is an energy intensive project.
And the geothermal resources present in the UAE is of the low temperature kind – up to 150°C
compared with up to 300°C for high “enthalpy”, or temperature, resources – which means it would
not be viable for power generation but more suited for direct applications such as cooling and
desalination.
However, geothermal in the UAE is not yet proven to be cost competitive for desalination even
though there are potentially huge fuel savings compared with conventional methods. “If we can
get the cost down enough to compete with other sources, then maybe it could be possible,” said
Ms Loutatidou.
So far, her research has shown that in the UAE geothermal desalination with low-level
temperatures will cost approximately US$2.50 per cubic metre.
Ms Loutatidou is hoping that with more research and development costs can fall. Currently the
price for thermal desalination can run from $0.67 to nearly $1.50, according to Saudi Arabia’s King
Abdulaziz City for Science and Technology. “It may not be applicable in the UAE now, but maybe
in the future,” said Ms Loutatidou. “I think innovation is … about identifying needs for now and for
the future.”

Iran Is Seeking to Increase Output Within OPEC’s Existing Ceiling
Bloomberg - Anthony Dipaola
OPEC should make room for increased Iranian crude production within its ceiling of 30 million
barrels a day, the nation’s oil minister said, adding the group will probably leave that limit
unchanged when it meets next month.
Iran has asked OPEC to accommodate its return to previous production levels when international
sanctions are lifted, Bijan Namdar Zanganeh told reporters in Tehran. Iran plans to add 1 million
barrels a day within five to six months of the curbs being removed and that increase should be
within OPEC’s production ceiling, Amir Hossein Zamaninia, deputy minister for commerce &
international affairs, said in Tehran on Saturday.
Brent crude tumbled more than 60 percent since the middle of last year as OPEC followed Saudi
Arabia’s strategy of defending its share of the global market against competitors such as U.S.
shale producers. The Organization of Petroleum Exporting Countries, which accounts for about 40
percent of global supply, has been pumping above its target level for 17 months. It is scheduled to
meet on Dec. 4 to discuss the ceiling.
Managed Return
“I don’t expect to receive any new agreement” at the OPEC meeting, Zanganeh said. “OPEC is
producing more than its approved ceiling and I asked them to reduce production and to respect
the ceiling, but it doesn’t mean we won’t produce more because it is our right to return to the
market.”
Iran was OPEC’s second-largest producer before sanctions over its nuclear program were
tightened in 2012. The nation, which reached an agreement with world powers in July over the
trade restrictions, is currently the group’s fifth-largest supplier, pumping 2.7 million barrels a day
last month, according to data compiled by Bloomberg.
“I sent a letter to OPEC to consider our return to the market and to manage it,” Zanganeh said.
“We don’t need to receive any permission from any organization for our return to the previous
level of production. It is a sovereign right.”
Market Balance
Most OPEC members see $70 a barrel as a fair price for oil, Zanganeh said. Brent crude last
traded at that level in December, days after OPEC gathered in Vienna and opted to resist calls
from members including Venezuela to cut output. Brent settled near $45 a barrel in London on
Nov. 20.
Venezuela President Nicolas Maduro is scheduled to meet Russian President Vladimir Putin in
Tehran on Nov. 23 to work together on oil prices, he said on state television last week. Russia,
which isn’t a member of OPEC, is facing competition in Europe after Saudi Arabia reduced pricing
for buyers in northwest Europe and started selling in established Russian markets such as
Poland.
Russia was lobbied last year by Venezuela as it sought to coordinate action with non-OPEC
producers to halt the collapse in oil prices. Global supply and demand is best balanced by the
market, Russian Energy Minister Alexander Novak said Saturday in Tehran. Any discounts on
Russian crude are a matter for the oil companies and not the Energy Ministry, Novak said.

Netherlands: Parkmead announces first gas production from the
Diever West gas field Source: Parkmead
Parkmead, the UK and Netherlands focused independent oil and gas group, has announced that
first commercial gas production has been achieved at the Diever West gas field in the
Netherlands. The field was discovered in September 2014 and, under a fast-track and low-cost
development programme, has been tied into existing production facilities through a new
dedicated pipeline with gas extraction
via the Garijp treatment system.
Parkmead has worked closely with its
joint-venture partners on the fast-track
development of the Diever West field,
and the partnership has successfully
brought the field onstream within just 14
months of discovery. This is an
outstanding achievement.
Diever West is located onshore on the
western edge of the Lower Saxony
Basin, approx. 10km to the east of the
producing Weststellingwerf,
Noordwolde, Vinkega and Nijensleek
fields, on the Drenthe IIIb Production
licence, which also contains
Parkmead's producing Geesbrug gas
field. The Diever-2 well was drilled in
September 2014 on behalf of the co-
venturers by operator Vermilion Energy,
and gas was discovered in a good
quality Rotliegendes age sandstone
reservoir. A 157 foot gas column was
encountered, with both net pay and
porosity values exceeding pre-drill
expectations. The well was flow tested after the successful discovery and recorded an excellent
flow rate of 29 million cubic feet per day (approx. 5,000 barrels of oil equivalent per day).
The Lower Permian Rotliegend sandstone in this area contains three productive formations, and
Diever-2 confirmed the presence of all three reservoir sections. The Slochteren Sandstone
formation in the vicinity possesses excellent reservoir properties, typically exhibiting a net-to -
gross ratio in excess of 90% and porosities of approx. 20%.
Parkmead's gas assets in the Netherlands continue to provide a robust revenue stream and
important net cash flows to the Company. A number of enhanced production opportunities are
available across Parkmead's existing Netherlands portfolio, which the Company intends to
capitalise on, with the aim of significantly increasing its net gas production.
These include a new low-cost infill well at Geesbrug and a further exploration target at De
Mussels. The new production from Diever West and the additional Geesbrug well are forecast to
more than treble Parkmead's net gas production in the Netherlands. This will serve as a natural
hedge against low and volatile oil prices.

Myanmar: BG Group and Woodside to start exploration offshore
Source: Myanmar Times
BG Group and Australia’s Woodside Energy will start offshore exploration next week according
to a notice in state media.
BG Group will undertake 3D seismic surveys in Blocks A-4 and AD-2 in the Rakhine basin off
the western coast of Myanmar, starting from November 23. The company will conduct seismic
campaigns using a Ramform Sovereign ship until the end of April 2016, according to the
statement.
Woodside Energy also will carry out 3D seismic surveys with a Ramform Titan vessel in deep
water Block AD-5 and shallow water A-7, also in the Rakhine offshore basin. The company will
begin exploration on November 20 until mid-April 2016.
'The four blocks cover a total area of nearly 30,000 sq kms, which is why the seismic surveys will
take around six months,' said an official from Myanma Oil and Gas Enterprise (MOGE). In
2013, the two international oil companies were awarded the right to exploration and production
activities in two shallow water and two deepwater blocks in Rakhine basin.
MOGE, BG and Woodside signed a production-sharing contract in March 2015, when the two
companies committed to invest more than US$1 billion across the four blocks over a six-to- eight-
year exploration period, according to MOGE.

NewBase 22 November - 2015 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Weakening crude spreads put more strain on U.S. oil's $40 support
Reuters +Newbase
A surprisingly abrupt breakdown in U.S. crude oil spreads this week has strengthened some
traders' conviction of a decisive move below $40 a barrel, extending the early winter price slump.
As traders rushed to dump expiring December West Texas Intermediate (WTI) futures on Friday,
rather than take delivery in Cushing, Oklahoma, where storage space is dwindling, the spread
versus the second month widened to as much as $2.90 a barrel, the most since 2011.
The second-third month spread has tumbled more than 30 cents to -$1.35 a barrel, its lowest
since April.
"The contango will probably provide the fuel for us to get well and below $40," said John McLane,
chief investment officer at Mobius Asset Management in Scottsdale, Arizona. He has sold short
prompt WTI prices while buying longer-dated oil.
"The way these spreads are acting is giving you every indication that lower prices are yet to
come," McLane said. "Just three to four months ago, we were looking at a difference of 30 to 40
cents on nearby WTI spreads."
The cheapening of the spot oil contract versus forward, a market structure known as contango,
comes as U.S. crude stocks resume rising toward record highs, with demand tempered by
unusually mild winter weather.
U.S. stocks rose for an eighth week last week to more than 487 million barrels, near April's record
highs. In Cushing, where the WTI contract is delivered, inventories rose by 2.14 million barrels in
the week to Tuesday, according to energy monitoring service Genscape. [EIA/S]
Traders believe that widening crude
spreads will accelerate WTI's descent to
below the $37.75 low set on Aug 27,
putting it on track to a new bottom since
2009. WTI's December futures hit a
$38.99 low on Friday before expiring as
the spot-month.
Spot WTI will have an opportunity to trade
above $40 again on Monday as the
January contract, which settled on Friday
at nearly $42, becomes its front-month. "The question is how long the support will hold as there's
going to be a new battle to get below $40 after this," said Tariq Zahir, who trades mostly in crude
spreads at Tyche Capital Advisors at Syosset, New York.
John Kilduff, partner at New York energy new hedge fund Again Capital, concurred. "The cash
market for oil is so weak it looks inevitable that the contango will widen."
Oil price special
coverage

Russia playing down threat of low-priced Saudi oil to Europe
Bloomberg
Russian officials said Saudi Arabia won’t be able to maintain the discounted crude prices offered
to refiners in Eastern Europe as the nation toned down its criticism of oil shipments from the
biggest Opec producer.
Saudi Arabia has priced its oil at a six-year low for Europe after starting to ship crude to traditional
Russian markets such as Poland.
The discounted crude “is a temporary situation and it won’t work for a long period,” Nikolay
Tokarev, chief executive officer of Russia’s state-run oil pipeline operator, Transneft, said in an
interview on Friday.
Oil executives in Russia, which ships almost 70% of its crude to Europe, last month criticised
Saudi Arabia’s strategy even before it dropped its December price for the northwest of the
continent to lowest since February 2009. Still, while the Russian central bank warned last week

that increased competition from the Middle East may create economic risks, Energy Minister
Alexander Novak was more sanguine on Friday.
“If more or less one oil cargo is added or drops off, there’s no need to turn it into a sensation,”
Novak told reporters in Moscow.
Russia is increasing crude exports to the European Union, including through Transneft’s Druzhba
pipeline that feeds Eastern Europe, Germany and the Baltic states, Tokarev said. Eastern
European refineries, mainly designed with Soviet technology, would need investment to process
Saudi crude, he said.
“There is no reason, from an economic point of view, to change technology for the benefit of some
sort of political ambition,” Tokarev said.
Saudi crude is heavier and more sour than the Russian Urals oil traditionally processed in Eastern
Europe, said Michael Nayebi-Oskoui, senior energy analyst for Middle East and South Asia at
Texas-based Stratfor.
The discounts being offered by the Saudis aren’t big enough to offset the extra costs of a large-
scale and long-term switch from Russian crude, he said.
“It does not mean that the regional refineries cannot use Saudi volumes,” Nayebi-Oskoui said.
“They’ll just be less profitable and over time require longer periods of maintenance.”

NewBase Special Coverage
News Agencies News Release 22 Nov. 2015
Africa boom fades as $50 crude shuts door on high-cost deals
Bloomberg
The banner was “On the brink of a boom,” on Pricewaterhouse Coopers’ review of Africa’s oil
industry 16 months ago. Now, oil below $50 has made more than two out of three investment
projects on the continent non-viable.
“Capital markets are effectively closed to the oil and gas industry” in Africa, Tony Hayward, former
head of BP and now chairman of Genel Energy, said at a conference in Cape Town last month. “A
decade of exploration, with billions of dollars invested and only limited commercial success.”
When six of the 10 biggest
global oil discoveries in 2013
were made in Africa, it
underlined the potential of
the energy riches that had
lured companies from Royal
Dutch Shell to Exxon Mobil
Corp. Governments have
been slow to react as the
slump in crude makes the
royalties charged from Libya
to Angola look punitive.
African production, already
19% below its 2008 peak of
10.2mn bpd, is set to drop for
a third year.
While final investment
decisions have been made
on less than 10% of the 48bn
barrels of oil equivalent
discovered in the past
decade, governments
haven’t adapted to the new
environment, Martin Kelly,
director for sub-Saharan
Africa research at
consultancy Wood Mackenzie, said in an interview at the Africa Oil Week conference. That means
some nations including Nigeria, the continent’s biggest producer, are proposing increasing
royalties at a moment the industry can least bear it.
“There is a raft of changes working their way through various parliaments around Africa at the
moment and they’ve been primarily based on prices that were $100,” Kelly said. “The world has
changed since then.”

African governments’ profit share from deepwater oil projects off the continent ranges from 91.1%
in Libya to about 60.7% in Gambia, according to data from Wood Mackenzie. That’s higher than
elsewhere in the world, with the continent’s average onshore take of 66.1% being 8.5 percentage
points above the global one, the consultants said.
Persuading governments to cut their share of the spoils won’t be easy with the end of the oil boom
destabilising economies as revenue slumps and currencies tank. Nigeria, Africa’s biggest
producer, has imposed foreign-exchange restrictions to stabilise the naira, while second-ranked
Angola has been forced to devalue its currency twice since June and slashed its budget by a
quarter.
Nigeria has proposed increasing the government’s share of profits and plans to review offshore
contracts signed with oil companies two decades ago. The last draft of a proposed petroleum law,
stalled in parliament for the past seven years, seeks to raise offshore taxes to 73% and those for
onshore to 87% from 50% and 83% respectively.
Exploration drilling in Nigeria is close to the lowest in more than a decade because of shelved
investment plans, according to the Petroleum Ministry.
With oil below $50 a barrel, only a third of $270bn of potential investment projects in Africa make
economic sense, according to Obo Idornigie, principal analyst at Wood Mackenzie.
Tullow Oil, responsible for some of the biggest discoveries on the continent, is concentrating on
safer projects in Ghana and Kenya after cutting jobs and trimming its annual exploration budget to
about $200mn from $1bn.
“We need a higher oil price” to meet future production requirements, Tullow chief executive officer
Aidan Heavey said in an interview, adding that companies need to react quickly to the current
environment. “Do it quick, do whatever needs to be done and maximise the value of the core
assets that you have.”
Kenya is among the African nations that tried to respond after the slide in crude prompted
companies to start withdrawing drilling rigs.
“The government has to look for ways of bailing them out,” said Hudson Andambi, senior
petroleum geologist at Kenya’s Ministry of Energy. “Some have been given extensions just as an
incentive to make them stay.”

There are exceptions to the continent’s woes, including the Rovuma basin, where Mozambique
last month awarded exploration licences to applicants including Exxon and partner, Rosneft, said
Chris Bredenhann, a partner at PwC in Cape Town. The programmes proposed in Rovuma for the
next four years may see investment of $700mn, the nation’s exploration regulator said.
That optimism must be balanced against the need for further clarity on how a framework
Mozambican law passed last year will be implemented, Bredenhann said. The absence of
legislative and regulatory certainty has also halted investment of as much as $5bn by explorers
including Shell in South Africa.
With PwC’s 2015 review of Africa’s oil industry showing that many oil explorers assumed prices
higher than $80 per barrel when modelling projects, additional risks are weighing on investment.
“Even without the oil price collapse, it was time for the industry and governments to take stock,”
Genel’s Hayward said. “I’m afraid the next six to 12 months will be very challenging to many
industry participants and survival will become the name of the game.”

The use of competing solar technologies hinges on economics
The national - LeAnne Graves
There’s no denying the trend that is solar power. It seems as though it’s everywhere and the UAE
wants to lead the way in the region. But the bottom line is, and will always be, money.
Many studies show consumers across the globe saying how they care about the environment. But
when it comes to being greener – the price tag is what truly wins support, even with so-called eco-
friendly products.
US-based Retailmenot.com conducted a survey that showed three in five people would buy green
items only if the costs were the same or less than non-eco-friendly products. It also found that 81
per cent of consumers surveyed thought greener means more expensive.
The same is true for the power sector, with many believing that cleaner, greener models will drive
up bills. If electricity from solar costs more to produce than traditional sources such as natural
gas, utilities and consumers alike will be less inclined to support clean energy.
So it was significant that when Dubai unveiled the winning bid for the 200-megawatt second phase
of the Mohammed bin Rashid Al Maktoum solar photovoltaic (PV) park at the same rates as
natural gas, the utility and country showed that solar energy was on a financial par with
conventional sources.
The consortium won the contract at 5.84 US cents per kilowatt hour. It was the cheapest rate in
the solar industry and has been undercut only recently in the US. So now that the UAE has proven
that PV can present a major economical solution to power generation, the country is looking to
expand another type of solar technology.
Concentrated solar power (CSP) offers something that PV doesn’t: energy storage. This means
that electricity generated can be fed into the grid even when the sun isn’t shining. This is leverage
that PV doesn’t have because any electricity generated in a PV system must be immediately put
into the grid or else the power is lost. However, this also means that CSP typically runs at twice
the price of PV.
Gus Schellekens, a partner at the clean energy division of the consultancy EY, said that even
when discussing which technology would be better suited, the question of cost always arises.
“Even when I’ve received request for proposals, there’s always a one-line [input] and the
consultants will recommend the most cost-effective technology,” he said.
And although Dewa may be studying new CSP techniques, the utility seems to agree that PV
currently outranks CSP. Looking back at the solar park that garnered so much attention, it was
originally planned to have a mixture of solar applications spanning from PV to CSP.
The tender was open to the best technology, and PV came out of the gates and finished the race
first. So much so that Dewa doubled down and made the entire park PV. “That’s a sign of where
the smart money is – they see it as economically and technically impactful on their grid,” said
Matthew Merfert, a technical director at First Solar.
Mr Schellekens noted that CSP is still in its early days. “Whether it gets support from big
investment will depend on the awareness and comfort investors have with the technology,” he
said.

The UAE has another problem that drives up costs. CSP technology has many moving parts,
unlike its competitor. With that comes the job of cleaning – a task that requires water, which isn’t
readily available in desert areas.
The technology also needs direct sunlight to have maximum effect. However, the UAE has not
only a significant amount of dust in the air, but also humidity that results in hazy conditions.
On top of this, building a 100-megawatt CSP plant takes about two to three years, as opposed to
PV’s build time of less than a year.
Mr Schellekens, a self-proclaimed “big CSP fan”, believes the industry went wrong about seven
years ago. “They didn’t do enough to reduce their costs to remain competitive and viable in the
competing market,” he said. “It’s a great technology, but the costs remain stubbornly high and in a
cost-conscious world you’re not going to win.”
Hadi Tahboub, a vice president of the Middle East Solar Industry Association, described how CSP
is finding industrial applications in Oman, where it is used in enhanced oil recovery. “But the UAE
isn’t looking into that at this stage and the economics of scale of implementing PV-based projects
is going to far outweigh CSP,” he said.
But the question remains: how much are you willing to pay?
“The big break for CSP will come either when governments and utilities realise that they have a
need for storage,” said Mr Schellekens. “Or costs come down substantially and it gets to grid
parity.”

NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
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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 K. Al Awadi

New base 733 special 22 november 2015

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