New base energy news october 29 2018 no-1210 by khaled al awadi

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NewBase Energy News 29 October 2018 - Issue No. 1210 Senior Editor Eng. Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
UAE to develop world’s first largest hybrid landfill gas-solar
agro power plant .. By Staff Writer, The Saudi Gazette
The UAE will soon see the development of the world’s first and largest Integrated Hybrid Landfill
Gas-Solar-Agro project in Ras Al Khaimah, it was announced last Oct. 25 by Engineer Ahmed
Mohammed Ahmed Al Hammadi, Director General of the Public Works and Services
Department, Government of Ras Al Khaimah at the Renewable Energy Conference, part of Wetex
2018.
This is the world’s first integrated hybrid landfill gas (LFG)-solar project that will also include an agro-
product development component to make it a completely green and sustainable industry – in line
with the UAE Government’s vision to promote green and sustainable economy. With an investment
outlay of $100 million (AED367 million), the project will generate up to 16 megawatt (MW) power to
be supplied to the customers in Ras Al Khaimah.
An agreement to this effect was signed between Public Works and Services Department and Utico,
for developing and operating a 16 MW LFG-Solar project. The project is in line with the new UAE
energy strategy that aims to increase the contribution of clean energy in the total energy mix to 50
percent, thus saving Dh700 billion by 2050.
The agreement was signed by Engineer Ahmed Mohammed Ahmed Al Hammadi, Director General
of Public Works and Services Department, Government of Ras Al Khaimah and Richard Menezes,
Vice-Chairman and Managing Director of Utico, in the presence of Ms Sonira Nasser, Director of
Ras Al Khaimah Waste Management Authority (RAKWMA).
Al Hammadi said this project is in line with the directives of the UAE government, as well as RAK
Ruler’ directives to provide the best services to citizens and residents, as well as ensure sustainable
development.
UAE Energy Plan for 2050 is targeting an energy mix that combines renewable, nuclear and clean
energy sources to meet the UAE’s economic requirements and environmental goals. The UAE aims
to invest Dh600 billion by 2050 to meet the growing energy demand and ensure sustainable growth
of the country’s economy.
Sonia Nasser said the project was envisioned over a few years and this signing ceremony is the
outcome of a long drawn tendering and selection process. She said that the agency is dedicated to
providing the best services to all in RAK and leading the way for sustainable development.
Utico, a private sector utility supplier which is also a developer plant supplier for water desalination
equipment as well as EPC contractor and operator for water and power facilities, will develop the
project and operate the project.
Power offtake will be utilized by Utico’s transmission and distribution arm.

“The benefits of this project will be passed onto consumers and will be in line with the program to
assist investment and investors in the UAE,” Richard Menezes, Vice-Chairman and Managing
Director of Utico, said,
“Electricity produced will be used to power the desalination plant making it the world’s least carbon
footprint desalination plant as well as its benefits will be passed onto our residential consumers as
per part of our SolarFree program at lower than the current peak consumer rates.”
Utico is the largest private full services utility in the UAE and has invested over $540 million (AED2
billion in the UAE with over $600 million (AED2.2 billion) projects under construction and
development.
Utico is the first GCC company to be awarded Desalination Company of the year Award as well as
the first in the MENA region to be certified ISO50001 for energy management. It recently received
investment from PIF, PPA, Government of Bahrain, Brunei and Islamic Development Bank through
fully-owned Asma Capital as part of the US$147 million deal.
The Gulf countries are expected to invest $252 billion over the next five years on projects for setting
up new power production plants, distribution systems, and supply grids. GCC represents 47 percent
or 148 GW of the current MENA power-generating capacity, according to reports by Ventures
Onsite, a UAE-based project tracker.
The region would require $85 billion for the addition of 69GW of generating capacity and another
$52 billion for transmission and distribution over the next five years. The GCC power capacity needs
to expand at an average annual pace of 8 percent between 2016 and 2020.

Nigeria Heads to Sea in Search of Safer Future for Oil Producers
Bloomberg - Elisha Bala-Gbogbo
By early next year, the largest offshore production vessel ever delivered to Nigeria will start pumping
crude from a deposit deep beneath the seabed, boosting the West African country’s oil output by
about 10 percent. The project, viewed as the most ambitious in Nigeria’s history, could help to push
production to a record by 2022.
The project will help to boost the share of the nation’s production from offshore fields, part of
a strategic shift that began at the start of the decade when companies including Chevron Corp.
and Royal Dutch Shell Plc started looking at higher-cost offshore fields to minimize risks from
sabotage, kidnapping and crude theft. Two-thirds of the nation’s production will stem from deep-
water deposits by 2022, up from half today, according to Nigeria’s state oil company.
“Deep-water drilling will replace onshore as the bulk of Nigeria’s oil production and revenue,” said
Cheta Nwanze, head of research at Lagos-based risk advisory SBM Intelligence. “The fiscal terms
are much better than onshore as of today and this implies that, in addition to less concern about
security, international producers get a bigger share of the pie.”
The asset that’s due to start later this year is Egina, Total SA’s $4 billion floating production, storage
and offloading vessel. At 330 meters (1,080 feet) long, it’s the largest FPSO ever built by the French
major and it will operate further offshore and in deeper waters than anyone else has tried so far in
Nigeria -- a sign of growing confidence in the technology required to operate such assets. Egina is
the first offshore field to start production in Nigeria since Exxon Mobil Corp.’s Usan in 2012.
With no big developments lined up on land, the share of output stemming from offshore is only going
to rise -- but it will take time. After Egina, the projects at the most advanced stage are Shell’s $10
billion expansion of its Bonga field and Eni’s Zabazaba-Etan project, which are still years away
from production. Formal decisions on investment are still pending in both cases and neither
company responded to emails seeking an update.

Nigeria is currently pumping just over 2 million barrels of oil a day and it plans to roughly double
that by 2020, a target that could prove difficult to achieve given delays that often occur in
developments. Ecobank Energy Research expects the nation’s total output to rise to a record by
2022.
Less Risky
International oil companies “absolutely love Nigeria’s deep water and they will be delighted to develop it,”
Gail Anderson, research director at Wood Mackenzie, said by phone from Edinburgh. “You’re somewhat
removed from all of the risks of being in the onshore.”
Nigeria’s success in boosting offshore developments will, however, also depend on its efforts to make the
regulatory and legislative backdrop more certain for investors.
Over the past 15 years, since around the time that Egina was discovered, a raft of other fields has been
added to Nigeria’s potential project lineup. They include the Bosi field, as well as the massive billion-
barrel Owowo field, both discovered by Exxon, but still awaiting development. Chevron is working on
Nsiko, part of a block that’s over 2,400 meters deep, much deeper than Bonga.
Nigeria’s Oil Minister Emmanuel Kachikwu has been looking at how much the nation earns from offshore
developments for years as the government seeks funds to modernize its infrastructure. Nigeria has also
started expanding contracts on field development to include other investments, such as a refinery that’s to
be built as part of Eni’s Zabazaba-Etan project.
Good Value
The nation is looking for the “best value for the country,” Kachikwu saidon Oct. 15, adding it plans to hold
talks with majors on reviewing offshore contract terms. That’s in addition to four other planned pieces of
legislation, replacing more than a dozen existing regulations on the industry and how it is funded. With
general elections scheduled for February, the legislative overhaul may not happen immediately. “The long
term growth of deep-water fields depends on the terms that are contained in the petroleum fiscal bill still in
the National Assembly,” said Nwanze. “If the terms are right, deep-water will thrive.”

Oman Gas to add 600km of new pipeline capacity
Oman Observer – P. Prabhu Conrad Prabhu
Oman Gas Company (OGC) — the energy infrastructure vertical of the restructured Oman Oil Company
(OOC) — is ramping up its gas and liquids transportation capacity through investments in new pipelines
serving industrial and petrochemical hubs in Suhar and Duqm.
The wholly government-owned company is also making the transition from a national
gas network operator to an independent, integrated energy transportation and
distribution services provider envisioned on the lines of the globally reputed Enbridge
of the United States or Engie of France, a top official said.
Sultan Hamad al Burtmani (pictured),
Acting Executive Managing Director of OGC,
told The Oil & Gas Year (TOGY), a well-
known oil and energy business intelligence
journal, that the company was in the process
of a consolidation exercise which will
culminate in a major rebranding in the coming
years. “We want to consolidate the whole gas
network under one dedicated technical
system operator, or TSO,” The Oil & Gas
Year quoted Sultan al Burtmani as saying.
“This entity will operate the whole gas
network and integrate it with the processing
facilities in the long term. One of our key aims
is to ensure that the infrastructure is ready,
not only to maintain a reliable and
uninterrupted supply of natural gas to
consumers, but at the same time to maximise
the value generation from this resource,” he
further noted.
In conjunction with this transformation,
OGC is poised to see its pipeline network
— the centrepiece of the nation’s gas grid
— grow by around 25 per cent. “In the
coming years, we will see another 500-600
kilometres of pipelines added to OGC’s
national gas transmission network, mainly
catering to the new industrial hub in Duqm,
as well as to meeting demand growth in the
Suhar area. This represents significant
growth and will take the total length of our
gas network to well over 3,000 kilometres,”
the Acting Executive Managing Director
said.
In the north, OGC is constructing a 36-inch
pipeline running around 250 km from Fahud
to Suhar, where new industrial and manufacturing investments in Sohar Port and Freezone, as well
as Sohar Industrial Estate, are driving up energy demand. The pipeline is being built along a
separate line carrying Natural Gas Liquids (NGLs) from Fahud to the ethylene cracker facility of

Orpic’s multi-billion dollar Liwa Plastics project. In the southeast, OGC is overseeing the
construction of a new pipeline from Saih Nihayda in central Oman to Duqm, where a mammoth
Special Economic Zone (SEZ) is under development. The roughly 350 km, 36-inch pipeline will
serve as an energy lifeline to investors in Duqm.
Under the restructured Oman Oil Group, OGC serves as the platform for the entire midstream
segment of Oman Oil Company’s business portfolio. The platform hosts the gas pillar
(encompassing the gas infrastructure including the pipelines, processing facilities such as:-
 The Salalah LPG extraction and future natural gas liquids [NGL] facilities)
 the Oil Infrastructure pillar, under which comes Oman Oil’s investment in the Oil tanking
Terminal in Sohar Port,
 The new Liquid Terminal under construction at Duqm Port, and
 The Crude Oil Park at Ras Markaz;
 The Power Infrastructure Pillar, which includes the Musandam Power Project,
 The upcoming Duqm power project to be implemented in Duqm SEZ by its subsidiary
Marafiq, and future renewable energy projects.
The consolidation of these different pillars under OGC is currently ongoing, said the Acting
Executive Managing Director. “We have already finalised the financing, consolidations and
integrations.
Especially because we are legally transferring the assets from Oman Oil Company to Oman Gas
Company, we are restructuring the whole capital structure related to the holding, and we will be
rebranding OGC in line with Oman Oil Company within the next few years. The reorganisation
review is happening this year. We will require another year to integrate all of this under one name.
Globally, you see similar models, such as Enbridge in Canada or Engie in France.”

Europe’s LNG imports have increased lately, but remain below 2011 peak
U.S. EIA, International Group of LNG Importers (GIIGNL) Annual Reports, 2005–2018
Imports of liquefied natural gas (LNG) to the 28 countries that make up the European Union (EU-
28) averaged 5.1 billion cubic feet per day (Bcf/d) in 2017, increasing for the third consecutive year
but remaining below their 2011 peak. In 2017, imports of LNG into EU-28 accounted for 13% of the
global total.
LNG import capacity in EU-28 currently stands at 20 Bcf/d, or almost one-fifth of the global total, but
utilization of EU-28 LNG import facilities has declined from about 50% in 2010 to between 20% and
25% in recent years as expansions in regasification capacity far exceeded demand for LNG imports.
Currently, 13 of the EU-28 member countries import LNG. In 2017, LNG accounted for 11% of EU-
28’s overall natural gas supply. Domestic natural gas production in EU-28, two-thirds of which is in
the United Kingdom and the Netherlands, has steadily declined in recent years and in 2017
accounted for 25% of EU-28 natural gas supply.
European natural gas production is expected to continue to decline because of an aging, mostly
depleted resource base. In addition, the Netherlands’ largest natural gas field, Groningen, has been
subject to increasingly strict production reduction measures.
Imports of natural gas by pipeline, in particular from Russia and Norway, have increased. In 2017,
natural gas imports from Russia provided 35% of the total EU-28 supply and Norway provided 24%.
In the first six months of 2018, pipeline imports from Russia continued to increase, averaging a
record 17.1 Bcf/d, 8% higher than in the same period last year, based on data from S&P Global
Platts.

EU-28 LNG imports have largely followed trends in regional natural gas consumption. From 2011
through 2014, relatively high natural gas prices led to less consumption of natural gas for electric
power generation in several EU-28 countries, especially the United Kingdom and Spain. More
recently, the use of natural gas in power generation increased in the EU-28. In 2017, several factors
such as low hydroelectric output in Spain, Italy, and Portugal as well as unplanned nuclear plant
shutdowns in France led to greater natural gas consumption and higher LNG imports.
Going forward, LNG imports in Europe will have to compete on a cost basis with existing and new
pipeline supplies of natural gas, particularly from Russia. A new undersea pipeline from Russia to
Germany—Nord Stream 2, with a capacity of 5.3 Bcf/d—has secured permits needed for
construction in Russia, Germany, Finland, and Sweden. Construction of the Russian portion of the
pipeline has started, but developers have not been able to obtain permits in Poland and Denmark
and have been considering alternative routes. This pipeline's expected in-service date is the end of 2019.

NewBase 29 October 2018 - 2018 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil falls as investors wary of trade slowdown Oil markets
Reuters + NewBase
Oil prices dipped on Monday amid cautious sentiment as a plunge in financial markets last week
and dollar strength early this week underscored concerns that growth may be slowing, especially in
Asia's emerging economies.
Front-month Brent crude oil futures were trading down 39 cents, or 0.5 percent, at $77.23 a barrel
at 0616 GMT.
U.S. West Texas Intermediate (WTI) crude futures were at $67.31 a barrel, down 28 cents, or 0.4
percent, from their last settlement.
Investors remained wary after hefty losses last week, while a stronger dollar on safe-haven buying
puts pressure on the purchasing power of emerging markets.
Oil price special
coverage

"Cooling economic conditions and symptoms of softer international trade have exacerbated bearish
conditions as (the) growth outlook dims," said Benjamin Lu of brokerage Phillip Futures in
Singapore.
Singapore-based ship tanker brokerage Eastport said stock prices were falling amid policy
uncertainty, rising interest rates and disappointing earnings from some companies. Financial
market turmoil may "weigh on investment and consumer spending, reducing trade flows and
ultimately hitting demand," it said.
Hedge funds slashed their bullish wagers on U.S. crude in the latest week to the lowest level in
more than a year, the U.S. Commodity Futures Trading Commission said on Friday. The speculator
group cut its combined futures and options position in New York and London by 42,644 contracts
to 216,733 in the week to Oct. 23, the lowest level since September 2017.
There were also signs of a slowdown in global trade, with rates for dry-bulk and container ships -
which carry most raw materials and manufactured goods - coming under pressure.
On the supply side, however, oil markets remain tense ahead of looming U.S. sanctions against
Iran's crude exports, which are set to start next week and are expected to tighten supply, especially
to Asia which takes most of Iran's shipments.
The tight market in Asia is visible in the low amount of unsold crude oil stored on tankers on waters
around Singapore and southern Malaysia, the region's main oil trading and storage hub. Just four
stationary supertankers are currently filled with crude oil, according to Refinitiv Eikon ship tracking
data.
That's down from around 15 a year ago, and from 40 in mid-2016 during the peak of the supply glut.
In North America, however, there is no oil shortage as U.S. crude oil production has increased by
almost a third since mid-2016 to around 11 million barrels per day.
Production is set to rise further. U.S. drillers added two oil rigs in the week to Oct. 26, bringing the
total count to 875, the highest level since March 2015, Baker Hughes energy services firm said on
Friday.
More than half of all U.S. oil rigs are in the Permian basin in West Texas and eastern New Mexico,
the country's biggest shale oil formation.

Iran sanctions adds uncertainty to crude oil and gasoline price forecasts
Source: U.S. Energy Information Administration, Short-Term Energy Outlook, October 2018
EIA’s October 2018 Short-Term Energy Outlook (STEO) forecasts Brent crude oil spot prices, which
averaged $79 per barrel (b) in September, to average $81/b in the fourth quarter of 2018, before
falling to an average of $75/b in 2019.
However, the effects of the U.S. withdrawal from the Joint Comprehensive Plan of Action (JCPOA),
the re-imposition of sanctions on Iran, and the potential response from members of the Organization
of the Petroleum Exporting Countries (OPEC) and other countries pose significant uncertainty to
the forecast.
EIA forecasts Brent crude oil prices to average $81/b in the fourth quarter of 2018, reflecting the
recent upward price movement and the possibility that crude oil prices could remain elevated while
market participants assess the effects of the sanctions.
EIA forecasts West Texas Intermediate (WTI) prices to increase at a slightly slower rate, leading to
a widening of the Brent-WTI spread to $9/b in October. EIA forecasts the spread to narrow to $4/b
by December 2019.
The May 2018 announcement that the United States would withdraw from the JCPOA and reinstate
sanctions against Iran included two wind-down periods, the second of which will end November 4
and includes a number of measures that target Iran’s energy sector.
The October STEO assumes that the effects of sanctions will increase during the first few months
of full implementation and that Iran's average crude oil production (excluding condensate) in 2019
will fall by approximately 1.0 million barrels per day (b/d) from Iran’s April 2018 production level of
3.8 million b/d. This decline is similar to the drop in Iran's crude oil production that occurred when
sanctions on Iran’s Central Bank were imposed in 2012.

EIA also assumes that Iran's condensate production will fall as a result of the new sanctions. Crude
oil and condensate exports are a significant source of revenue for Iran, with net oil export revenues
estimated at $55 billion in 2017. The exact effect of the sanctions will depend on the total volume of
crude oil and condensate that comes off the market and the response from OPEC members and
other countries.
EIA forecasts that OPEC spare production capacity will average 1.6 million b/d in 2018 and will fall
to 1.3 million b/d in 2019, down from 2.1 million b/d in 2017 and lower than the 10-year (2008–2017)
average of 2.3 million b/d. This decline creates a market with relatively low spare capacity at the
same time Iran and Venezuela are forecast to experience production declines.
The total volumes of crude oil and condensate coming off the market will become more apparent in
the months following the full implementation of sanctions in November. However, the response of
other producers to compensate for lost supplies from Iran is also uncertain. Significant differences
between any potential production response and the actual volumes taken off the market would likely
result in increased price volatility.
The higher crude oil prices at the end of 2018 and in 2019 will likely support increased global crude
oil production. EIA forecasts U.S. crude oil production to increase by 1.0 million b/d in 2019. EIA
forecasts total global liquid fuels inventories to decrease by 200,000 b/d in 2018, followed by an
increase of 280,000 b/d in 2019.

NewBase Special Coverage
News Agencies News Release 29 October 2018 -2018
Most utility-scale fixed-tilt solar photovoltaic systems are tilted
20 degrees-30 degrees
Source: U.S. EIA, Annual Electric Generator Report
Nearly 40%, or 10.4 gigawatts (GW), of utility-scale solar photovoltaic (PV) systems operating in the
United States at the end of 2017 were fixed-tilt PV systems rather than tracking systems. Of the
utility-scale fixed-tilt solar PV systems, 76% of the capacity was installed at a fixed angle between
20 degrees and 30 degrees from the horizon.
The amount of electricity generated by a fixed-tilt solar PV system depends on the orientation of the
PV panels relative to the sun. The panels of a solar PV system collect solar radiation more efficiently
when the sun's rays are perpendicular to the panel.
Fixed-tilt PV systems use two separate angles that determine their orientation relative to the sun:
the azimuth and the tilt.
 The azimuth specifies the compass direction that a tilted panel is facing: north, south, east,
or west. Most panels in the Northern Hemisphere are south-facing.
 The tilt is the angle from the horizontal ground. A tilt of zero degrees means that the panel is
lying flat on the ground, while a tilt of 90 degrees means that the panel is perpendicular to
the ground, like on the side of a building.

Source: U.S. Energy Information Administration
Latitude is often the primary factor that determines the tilt of the panels because tilting the panel
toward the south at an angle equal to its latitude will maximize the panel’s annual exposure to direct
sunlight. In the United States, systems installed at lower latitudes (further south) typically have
shallower PV tilts, while systems installed at higher latitudes (further north) typically have steeper
tilts.

U.S. utility-scale fixed-tilt PV systems are located at latitudes between 20 degrees (Hawaii) and 50
degrees north, in states such as Oregon and Minnesota. Panels are often installed at a shallower
tilt than would be indicated by latitude because of other factors such as height limitations, shading
concerns, and system layouts.
Systems with tilt angles less than the latitude angle of the plant’s location are expected to have
enhanced output during spring and summer months when the mid-day sun is higher in the sky, at
the expense of reduced output during fall and winter.
In recent years, solar power plants have increasingly been installed with tracking systems instead
of fixed-tilt systems. Tracking systems either rotate on a single axis (typically east to west) or on a
dual axis. Although tracking systems are more expensive than fixed-tilt systems, revenue from the
additional electricity generated by following the path of the sun across the sky often exceeds the
increased cost. Because the tracking mechanism is designed to track east to west, many existing
single-axis tracking systems have a tilt of zero degrees.

NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
The Editor :”Khaled Al Awadi” Your partner in Energy Services
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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 28 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 October 2018 K. Al Awadi

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