UAE Barakah nuclear plant passes final unit test

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NewBase Energy News 21 May 2020 - Issue No. 1340 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:Barakah power plant passes major testing phase for its final unit
The National
The UAE’s Barakah nuclear power plant is a step closer to being switched on after major tests were
completed at all four of its units. The energy plant, which will power 25 per cent of the nation’s
homes and business, passed the cold hydrostatic test for its Unit 4, it was revealed on Tuesday.
Located 50km southwest of Ruwais in Al Dhafra region, the overall construction of the facility’s four
units are 94 per cent complete.
“I am proud of the continued progress being made at Barakah despite the circumstances we have
all faced in relation to Covid-19,” said Mohamed Al Hammadi, the chief executive of the Emirates
Nuclear Energy Corporation.
“The UAE leadership’s decisive and proactive response to the pandemic supported us in taking
timely, safety-led actions to protect the health and safety of our workforce and our plant.”
The cold hydrostatic test measured the reactor’s ability to maintain its internal temperature at a safe
level during operations. Components of the coolant system were tested, including the coolant
pumps, the welds and joints, as well as the high-pressure systems.
Barakah nuclear plant ‘on schedule’ as measures taken on Covid-19 outbreak, says Enec CEO
UAE becomes Arab world's first nuclear energy nation as Barakah reaches major milestone
www.linkedin.com/in/khaled-al-awadi-38b995b

The unit’s system was increased to 25 per cent above what will be the normal operating pressure.
The four units at Barakah will produce 5,600 MW of clean baseload electricity. This will help prevent
the release of 21 million tons of carbon emissions each year, the equivalent of removing 3.2 million
cars off the roads annually.
The peaceful nuclear energy programme is “on schedule” despite the Covid-19 outbreak, The
National reported on May 7. Enec is now preparing for the safe start-up of Unit 1 in the coming
months.
Throughout each stage, the ENEC has implemented a programme aimed at meeting the safety
commitments set out in international standards, making the UAE a reference point for nuclear
projects in the region. So far, the FANR has carried out more than 255 inspections to ensure that
the Barakah plant, its personnel and its processes have the highest standards of quality and nuclear
safety. These national reviews have been supported by more than 40 assessments conducted by
the International Atomic Energy Agency, the IAEA and the World Association of Nuclear Operators,
WANO.
The UAE authorities indicated in January that their first nuclear power plant would be operational
"this year", despite the fact that the first of the four reactors was to be commissioned at the end of
2017. This decision has been postponed to meet safety requirements. This plant -which has four
reactors- will be the first of its kind in the Arab world once it becomes operational.
The country considered as one of the main oil exporters in the world has made a 180-degree turn
in its energy policies with the implementation of this plant, which aims to obtain energy in a "cleaner"
way. Currently, the Emirates Nuclear Energy Corporation is completing the construction of the three
remaining units of the Barakah Nuclear Power Plant, located in the Al Dhafra region of Abu Dhabi.
Thus, construction of the four units is currently more than 93 percent complete. The four Barakah
units will generate up to 25 per cent of the UAE's electricity demand, producing 5,600 MW of clean
electricity and avoiding the release of 21 million tonnes of carbon emissions each year, equivalent
to removing 3.2 million cars from the roads annually, according to estimates by the WAM news
agency.

Oman-owned chemicals giant eyes new capacity growth in 2021
Oman Observer - Conrad Prabhu
Wholly Omani owned OQ Chemicals (formerly Oxea) – a global manufacturer of oxo intermediates
and oxo derivatives – says it plans to boost its output of carboxylic acids, which are a key ingredient
in the international animal feeds industry as well in the manufacture of synthetic lubricants.
Germany-headquartered OQ Chemicals – which is wholly owned by OQ (until recently Oman Oil
and Orpic Group) – the refining and petrochemicals powerhouse of the Sultanate – also announced
moves to ramp up its production of other key intermediate chemical products.
The announcements came as the erstwhile Oxea formally rebranded as ‘OQ Chemicals’ as part of
its integration into OQ – the Sultanate’s consolidated energy conglomerate. The integration with
OQ will open up new synergies for international clients of the newly rebranded OQ Chemicals, said
Dr Oliver Borgmeier, who oversees Downstream International Assets at Muscat-headquartered OQ.
“Long-term, our customers will benefit from synergies at OQ: We will continue to invest in innovation.
In 2021, we aim to add 30 per cent to our company’s total production capacity for carboxylic acids
with a sixth world-scale production plant. For the same year, we plan to bring on-stream additional
production capacity for TCD Alcohol that will cover the anticipated global demand for years to come,”
he added.
Oxea, which became part of OQ’s predecessor Oman Oil Company (OOC) in 2013, is a global
producer of oxo intermediates and oxo derivatives, such as alcohols, polyols, carboxylic acids,
specialty esters, and amines.
These products are used for the production of high-quality coatings, lubricants, cosmetics and
pharmaceutical products, flavours and fragrances, printing inks and plastics. OQ Chemicals, with
plants in the United States, Germany, China and the Netherlands, produces more than 70 different
types of oxo intermediates and derivatives currently totaling over 1.3 million tons per annum and
generating revenues of around about €1.2 billion annually.
Early last year, OQ Chemicals affirmed plans to bolster capacity at its five existing carboxylic acid
production units during 2020 in preparation for the goal of bringing a sixth world-scale production
plant on stream in 2021.

UAE: Lamprell awarded EPIC contract by Sharjah National Oil Corporation
Source: Lamprell
Lamprell, through its site services business, has been selected by Sharjah National Oil Corporation
(SNOC) to undertake a medium-sized* engineering, procurement, installation and commissioning
contract (EPIC) associated with the Mahani gas and condensate field in Sharjah, United Arab
Emirates.
Scheduled for completion in early 2021, Lamprell's scope of work is specific to the Mahani Extended
Well Test project and includes hook-up and installation at the well, existing systems upgrade,
associated tie-ins and a new 25 km export pipeline.
Discovery of the onshore Mahani field was announced by SNOC and its partner Eni at the end of
January 2020.
Commenting on the award, Chief Executive Christopher McDonald said:
'SNOC is an important client for us and through delivering to consistently high and competitive
standards, we are very proud of the track record we've developed with them. Mahani is a strategic
gas discovery. We are looking forward to being associated with it, delivering this project safely and
on time.'
(*Lamprell defines a medium-sized contract as between USD 6 million and USD 50 million)
Mahani

Saudi Aramco Is First to Regain Pre-Price-War Share Price
Bloomberg - Filipe Pacheco
Saudi Aramco is the first major global oil producer to see its stock recover to the level it traded at
before the price war between Russia and Saudi Arabia.
Aramco climbed 3.1% in Riyadh on Tuesday, advancing for a record sixth day alongside an
extended increase in the price of crude. The stock has gained each session since the company
announced it would retain dividend payouts, despite a drop in first-quarter profit.
Aramco’s recovery has been achieved on much smaller share volumes than its international
counterparts, with less than 2% of the Saudi company’s stock available for trading. An average of
about $35 million worth of Aramco shares changed hands each session last week, rising to $100
million on Monday. That compares with yesterday’s Exxon Mobil Corp. share turnover of $1.4
billion.
Much of Aramco’s stock sold during its initial public offering in December went to locals, who stand
to receive bonus shares if they maintain their holdings for six months. The shares are now 20%
higher than this year’s lowest close on March 16.
Shares in oil companies plummeted in March after an OPEC+ meeting ended without a deal to curb
production, an impasse that was followed by an all-out price war between Saudi Arabia and Russia.
The Covid-19 pandemic disrupted global energy demand as economies shut down, prompting a
collapse in the oil market. Crude futures have since recovered as governments started to ease
lockdown measures and after major suppliers eventually agreed to production cuts.
While Aramco stuck to its dividend plans, Royal Dutch Shell Plc slumped last month after cutting its
payout for the first time since the Second World War. Total SA offered to pay part of its final 2019
dividend in shares, rather than cash.

“While oil-output cuts across the world have helped push prices above $30 a barrel, we remain
cautious about the pace of a recovery in oil demand and compliance with the OPEC+ pact,” said
Bloomberg Intelligence analysts Salih Yilmaz and Rob Barnett. They added that price volatility may
persist, “given uncertainty over the relaxation of coronavirus pandemic lockdowns.”
A Month After Oil Plunged Into the Abyss, Prices Are Surging
Just a few weeks ago, crude oil was akin to industrial waste in some parts of the world, something
you had to pay people to take away. Now prices are surging, up about 70% in
The turnaround, which has been welcomed from Riyadh and Moscow to the White House, came
quicker than most people were expecting but wasn’t easy. Painful OPEC+ production cuts and the
world’s risky first steps out of coronavirus lockdown have lifted the market out of the abyss of
negative prices, but either of them could falter.
It was the afternoon of April 20 when panicked sellers drove the price of the U.S. crude benchmark
below zero for the first time in history. In one of the most extraordinary 20-minute spans in the
history of financial markets, West Texas Intermediate fell as low as minus $40.32 a barrel, stunning
everyone from veteran brokers to retail investors.
Two big things have changed since then.
First, the flood of unwanted crude has abated. Saudi Arabia ended its price war with Russia and
stopped flooding the market with record production. Instead, the pair led their allies in the OPEC+
alliance to make their deepest and fastest output cuts on record.
U.S. shale companies have also shut down unprofitable wells at an unprecedented rate.
As much as 17 million barrels of a day of crude will have been taken off the market by next month,
Mohammad Barkindo, secretary-general of the Organization of Petroleum Exporting Countries, At
the same time, the 30% drop in global oil consumption seen in April is abating. Green shoots of

recovery are emerging around the world as businesses reopen and drivers return to the
roads from Berlin to Beijing.
The oil glut is shrinking and the great fear that motivated the slump in U.S. prices below zero -- that
holders of expiring contracts would have nowhere to store crude when it was delivered -- appears
to have been averted.
WTI for June delivery settled at $32.50 a barrel on Tuesday, slightly higher than the price for July.
That’s a clear sign that holders of the expiring front-month contract weren’t fearful of getting stuck
with unwanted barrels.
“Concerns about the planet running out of places to store crude and product have evaporated,” said
Judith Dwarkin, chief economist at RS Energy Group. “Near-month prices in the physical market
are factoring this in as well as for the outlook ahead.”
Risky Rally
The month dubbed “Black April” by International Energy Agency Executive Director Fatih Birol is
over, but the market still faces considerable risks.
The reopening of any number of battered economies across Asia, Europe and the Americas will be
difficult, and could be set back at any moment by a second wave of Covid-19 infections.
The enthusiasm for cutting production shown by U.S. shale companies or OPEC+ could weaken.
The faltering recovery from the 1998 Asian economic crisis offers a playbook, said Greg Sharenow,
a portfolio manager focused on energy and commodities at Pacific Investment Management Co.
“You had a bunch of rallies, a bunch of sell-offs” in the 18 months after the initial oil-price slump,
Sharenow said in an interview from Newport Beach, California. There’s a strong recovery right now,
but “you have unemployment numbers around the world and you have income shocks -- those are
pretty powerful opposing forces.”
Federal Reserve Chairman Jerome Powell said this week that the U.S. economic recovery
could drag on until the end of 2021. Even that gradual timetable could be threatened if there’s a
second wave of the pandemic, he warned.
“I think it will take a long time for demand to recover fully though, probably until we have a vaccine,”
said Andurand, whose main fund is up almost 70% this year after successful bets on the direction
of prices.
Topsy Turvy
For now, there’s palpable relief that normal service has returned to the oil market. While a crude
price in the $30s is still too low to balance the budgets of most OPEC+ states, ministers from Saudi
Arabia to Russia appear satisfied with the fruits of their labor.
Even major energy importers show little desire to return to those few days when producers had to
pay consumers to take their crude.
Price wars, topsy-turvy oil benchmarks and dislocations in long-standing relationships between
markets “are things you don’t see normally and are unsustainable,” said Mukesh Kumar Surana,
chairman of India’s Hindustan Petroleum Corp.

U.S: Large battery systems are often paired with renewable
energy power plants : U.S. Energy Information Administration, Preliminary Monthly Electric Generator Inventory
Pairing renewable energy generators with energy storage, particularly batteries, is increasingly
common as the cost of energy storage continues to decrease.
The U.S. Energy Information Administration’s (EIA) latest inventory of electric generators shows
that the number of solar and wind generation sites co-located with batteries has grown from 19
paired sites in 2016 to 53 paired sites in 2019. This trend is expected to continue: according to
planned installations reported to EIA, another 56 facilities pairing renewable energy and battery
storage will come online by the end of 2023.

Combining energy storage with renewable technologies such as wind and solar provides a variety
of benefits. One of the most critical is the ability to store energy as it is generated and then
redistribute it when needed, rather than as it is produced. This ability reduces the need to curtail
renewable generation and allows the energy to be deployed during periods of high electricity
demand.
Although the most commonly reported application for batteries co-located with renewable sources
is storing excess energy, the majority of batteries serve more than one function. Frequency
regulation, which helps maintain the grid’s electric frequency on a second-to-second basis, is the
second-most common use for batteries co-located with renewables.
Batteries can also provide transmission and distribution support, helping to smooth out energy flows.
The ability to support the integration of renewables into the grid’s current infrastructure, in addition
to other ancillary services that they perform such as frequency regulation, are primary drivers in the
growth of battery-renewable pairings.
Currently, more than 90% of the total operating hybrid (renewable generator plus energy storage)
capacity in the country is located in just nine states. Texas alone has 46% of the current total. Hybrid
capacity in the United States is concentrated at a few large sites, and 10 facilities account for more
than half of total operational capacity.
Installation as part of a hybrid system is common for batteries but not for renewable generators such
as wind and solar. Although nearly 25% of total U.S. battery capacity is installed as part of a hybrid
system, only 1% of total wind capacity and 2% of total solar capacity is part of a hybrid system.
Reported data show that future projects will be much larger in scale than currently operating
projects. One anticipated projected in Nevada called Gemini Solar is expected to add more than
one gigawatt of combined renewable and storage capacity.
The U.S. Department of the Interior approved the Gemini Solar project on May 11, 2020, and the
first phase of construction is expected to begin in 2021. By the end of 2023, average renewable
capacity at proposed U.S. facilities will more than double from 34 megawatts (MW) to 75 MW, and
average battery capacity will grow from 5 MW to 36 MW.

Norway: Northern Lights submits PDO for the first CO2 storage
project on the Norwegian shelf….Source: NPD
The Northern Lights Alliance, with operator Equinor and partners Shell and Total, has submitted a
plan for an important part of the Norwegian full-scale project for transport and storage of CO2 on
the shelf.
The Ministry of Petroleum and Energy (MPE) has received the plan, while the Norwegian Petroleum
Directorate (NPD) will process the plan in accordance with the CO2 storage regulations.
Northern Lights is part of the first Norwegian full-scale project for transport and storage of CO2 -
Carbon Capture and Storage (CCS). The project includes capturing CO2 from two industrial firms
in Eastern Norway and transporting liquid CO2 to a terminal in Western Norway.
Northern Lights submits PDO for the first CO2 storage project on the Norwegian shelf
Permanent storage
CO2 will be captured from Fortum’s heat recovery plant at Klementsrud in Oslo and Norcem’s
cement factory in Breivik in the municipality of Porsgrunn, and then transported by ship to an
intermediate storage location at Kollsnes in the Øygarden municipality.
From there, the liquid CO2 will be transported in a 100-km long pipeline on the seabed and pumped
into a reservoir at a depth of around 2,700 metres in the North Sea for permanent storage. The
reservoir is in the Johansen Formation southwest of the Troll field.
The plan for the first phase is to inject 1.5 million tonnes of CO2 into the Johansen Formation.
However, the plan includes flexibility to accommodate expanding the location’s capacity, and one
important objective is to be able to offer the site as a storage location for CO2 from other European
countries.

This means a huge step forward for the Government’s ambition of cost-effective full-scale CCS. A
resolution on partial state funding of a Norwegian full-scale CCS project has the objective of
demonstrating secure storage, and contributing to reducing the costs of future projects.
Unique project
This is an important and unique project for the climate and for industrial development, both for
Norway and in an international perspective.
However, state support is a precondition for the project. In January 2019, Northern Lights was
awarded the first exploitation licence for injection and storage of CO2. The awarded area is located
near the Troll field in the North Sea.
In December of last year, drilling started on an exploration well to identify suitable reservoirs for
CO2 storage. The exploration well was terminated in February this year. “The well proved
sandstone with properties well-suited for aCO2 storage location,” says assistant director for
exploration in the NPD, Wenche Tjelta Johansen.
The reservoir is filled with water, and there has never been any oil or gas production from this part
of the formation. Many consider capture and storage of CO2 a precondition for achieving the
emission targets in the Paris Agreement, which Norway has signed.
Experience
'In Norway, we have years of experience and good expertise when it comes to safe storage of CO2
under the seabed,' says Johansen.
CO2 has been removed from the Sleipner Vest gas and injected in the Utsira Formation since 1996.
Around one million tonnes of CO2 are stored in the subsurface every year. Since 2007, around
700,000 tonnes of CO2 have also been stored each year on the Snøhvit field.
It is separated from the gas at the process plant at Melkøya before it is routed by pipeline down into
a reservoir about 140 kilometres from land. Regular surveys are performed to monitor how injected
CO2 moves within the storage location.
Dedicated storage atlas
The Norwegian Petroleum Directorate has mapped areas that are suitable for safe and secure long-
term storage, an effort that resulted in a CO2 storage atlas for the Norwegian shelf.
Estimates indicate, in theory, that the reservoir volume on the shelf is sufficient to accommodate
more than 80 billion tonnes of carbon dioxide, a volume equivalent to 1,000 years of current
Norwegian CO2 emissions.
With 43 Carbon-Capture Projects Lined Up Worldwide,
An organization with members including ExxonMobil and the governments of Australia, the United
Kingdom and the United States released a report on Tuesday arguing for the key role of carbon
capture and storage in confronting the challenge of climate change.
Members of the Global CCS Institute said 2018 could represent a turning point in the CCS industry
because of a critical mass of favorable policies and investments from global governments. The
group unveiled its 2018 Global Status of CCS report in an event held at the global climate
conference in Katowice, Poland.
Perhaps most noteworthy are the report’s contributors. Though Global CCS Institute members
include several national governments and fossil fuel companies, the report highlighted wide-

reaching contributions from experts in economics, climate change and Fatih Birol, executive director
of the International Energy Agency.
The report aims to undercut common criticisms of CCS in combating climate change — namely,
that the technology is still too expensive and not deployable at scale — by pointing out projects
planned around the world and the amount of carbon dioxide stored to date.

Carbon capture has seen the most success in the United States, where so far projects have stored
nearly 160 million metric tons of carbon dioxide. According to the report, 10 of the world’s operating
CCS facilities are located in the U.S. (one is a capture facility located in the U.S., but the carbon
dioxide is injected across the border in Canada).
The U.S. has several large-scale facilities, but only one of those projects is a large-scale CCS power
facility: Petra Nova in Texas.*
In the U.S., most captured carbon has gone to enhanced oil recovery, a process that pushes out
more oil from a producing well after the extractor has already used primary and secondary methods.
That added revenue from EOR helped Petra Nova’s economics. It’s also used at other plants like
the Great Plains Synfuels Plant in North Dakota.
Collectively, U.S. plants can capture about 25 million metric tons per year. For context, in 2017 the
U.S. power sector alone emitted 1,744 million metric tons of carbon dioxide, according to the U.S.
Energy Information Administration.
But carbon-capture advocates are very bullish, in part because of an energy tax credit, 45Q, that
the U.S. passed this year. Under the new credit, projects will get $35 per ton of carbon captured
and used for enhanced oil recovery and $50 for carbon captured and stored in geological storage.
The previous credits were $10 and $20, respectively.
While proponents of CCS technology said the new credit could make a big difference in the
deployment of more projects, a report released this year by power consulting company Wood
Mackenzie estimated that projects would need carbon prices of at least $60 to pencil out
economically.
The International Energy Agency has said an incentive of less than $40 per ton could support the
storage of 450 million metric tons of carbon dioxide per year. The organization calls CCUS (using
an acronym that includes "utilization") a “massive untapped opportunity.”

In the report released on Tuesday, the carbon-capture group said 45Q is a keystone policy for an
industry gaining momentum. But the group also pointed to the 43 large-scale CCS facilities in
operation, under construction or under development around the world.
Other countries are beginning to more earnestly invest in CCS policies, with efforts like the United
Kingdom’s CCUS Cost Challenge Task Force and a European Commission innovation fund valued
at over €9 billion (over USD $10 billion) to support renewables and CCUS energy demonstration
projects.
Pushing further carbon-capture policies forward, the group argues, is essential, because CCS is
needed to meet the goals set out in the Paris Agreement. In an October report on keeping global
temperatures below 2 degrees Celsius, the Intergovernmental Panel on Climate Change stated that
the world needs carbon capture in order to reach next-zero emissions.
But carbon capture as an industry depends on a continued reliance on fossil fuels, since carbon
dioxide is so commonly used in EOR. Though carbon-capture capacity increased between 2010
and 2019, relatively few projects use geological storage.
Only in Norway have carbon-capture projects mostly used geological storage. Australia’s Gorgon project
could help change that. When fully online, as it’s slated to be in 2019, the project will be the largest
geological storage facility in the world.

NewBase May 21-2020 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil prices climb as U.S. stock drawdown eases supply glut fears
Reuters + NewBase
Oil prices edged higher on Thursday after data showed U.S. crude inventories fell again, easing
concern about a supply glut, though lingering fears over the global economic fallout from the Covid-
19 pandemic capped gains.
Brent crude futures for July delivery were trading up 17 cents, or 0.5%, at $35.92 per barrel at 0024
GMT. U.S. West Texas Intermediate (WTI) crude futures for July were up 4 cents, or 0.1%, at
$33.53 a barrel.
U.S. crude inventories fell by 5 million barrels last week, against expectations in a Reuters poll for
a 1.2 million-barrel rise, Energy Information Administration (EIA) data showed, while stocks at the
Cushing, Oklahoma, delivery hub dropped by 5.6 million barrels.
Oil price special
coverage

“While signs that WTI storage pressures are abating is positive for prices, the latest report shows
that the fall in stocks owes more to supply factors than growing product demand,” Capital Economics
said in a note issued on Wednesday.
Prices have been boosted lately by shipping data showing the Organization of the Petroleum
Exporting Countries, Russia and other allies, a group known as OPEC+, are complying with their
pledge to cut 9.7 million barrels per day (bpd).
OPEC itself is encouraged by the rally in prices and strong adherence to output cut pledges, its
secretary general said, although sources say the group has not ruled out further steps to support
the market.
“We expect this to be the story for some time yet as OPEC+ cuts help to put a floor under prices in
the second half of this year,” Capital Economics said.
Swift OPEC+ Cuts Revive Premiums in Asia’s Physical Oil Market
Bloomberg - Sharon Cho
Swift and bold output cuts by OPEC and its allies are boosting prices of physical oil barrels in Asia
as supply tightens.
Premiums for a wide-ranging variety of crude from Russia’s ESPO, Abu Dhabi’s Upper Zakum and
Qatar’s Al-Shaheen have increased significantly in the Asian spot market since OPEC+ started
reducing output this month in-line with its pledge to cut almost 10 million barrels a day. Supplies of
more sulfurous oil from the Middle East that are favored by a majority of Asian refiners should begin
to tighten due to the production curbs.
Demand is recovering in major oil consumers China and India, led by a rebound in gasoline and
diesel consumption. Chinese refiners are seeing profits from turning crude into fuels, even as
processors across much of the region including Singapore face negative margins. In spite of that,
buyers are continuing to scramble for cargoes after Saudi Arabia, Kuwait and the U.A.E. said they
would reduce contractual supplies from June as they press ahead with planned curbs to support a
market rebalancing.

“Refiners might be panicking now in light of additional supply cuts and looking to secure cargoes,
especially as prices could start to rise,” said Michal Meidan, director of China Energy Program at
Oxford Institute for Energy Studies. “Purchases seem to be getting ahead of the demand recovery,”
potentially testing storage capacity in places like China.
In the latest trade of Russia’s ESPO crude, Surgutneftegas PJSC sold two cargoes for July loading
at a premium of $2.50-$3 a barrel to the Dubai benchmark, according to traders who asked not to
be identified. That compares with a discount of $4 or more just last month.
For Middle Eastern grades, Exxon Mobil Corp. sold Upper Zakum for July loading at a premium
of $1.30-$1.50 a barrel to the grade’s official selling price, compared with a premium of 20-30
cents last month. The discount of Qatar’s medium-sour variety Al-Shaheen also narrowed more
than 80% month-on-month for shipments that were awarded in its monthly tenders.
Cautious Outlook
Despite pockets of demand emerging, market watchers remain cautious on the outlook due to the
potential for a resurgence in coronavirus cases and the return of supplies as prices rise. Fuel
stockpiles could swell should refiners increase operating rates too quickly and run ahead of
themselves, said Meidan.
As for crude inventories, there are also ample stockpiles being housed in onshore tanks and vessels
offshore that could hit the market as the economics of storing the crude becomes less attractive.
Brent oil’s six-month contango -- a market structure where future supplies of crude are more
expensive than than prompt cargoes -- narrowed sharply to $2.76 a barrel on Monday, compared
with $11.34 in late April.
“There are still several unknowns regarding the extent to which oil demand will ultimately recover,”
said Giovanni Staunovo, commodity analyst at UBS Group AG. “While gasoline demand will rise as
people go back to work, consumption patterns will likely be different than in pre-Covid days as
society adopts a new normal at least until a vaccine is available.”

NewBase Special Coverage
The Energy world - Special 21- May-2020
Coronavirus creates repair headache for oil and gas industry
Reuters + NewBase
The coronavirus pandemic has disrupted maintenance at oil and gas projects and refineries from
Russia’s Far East to the coast of Canada, storing up problems for an industry already reeling from
slumping prices, analysts say.
Lockdowns to stop the spread of COVID-19, the flu-like infection caused by the virus, have snarled
the supply of spare parts and have prevented maintenance workers from doing their job.
Regular repairs are needed to keep wells pumping, pipelines and refineries functioning and ships
moving. Without maintenance, the risk of glitches or unplanned outages increases and delays risk
driving up the cost of work later - partly because there will be a rush to do maintenance when
lockdowns ease, and partly because plants have lost the optimal timing and weather for work during
the northern hemisphere spring.
“When the virus and the quarantine measures have been eased and it is safe to get back to work,
it doesn’t mean the same work can be done with the same intensity because the weather windows
could be missed and that can push maintenance even to the next year,” said Matthew Fitzsimmons,
Vice President of the Oilfield Service team at research firm Rystad.
In the meantime, companies which service the oil industry are being hit by the lack of work. “A lot
of service companies are not getting the revenues they had otherwise expected in 2020. That is
going to have a huge impact on the health of the service industry,” said Fitzsimmons.
A MAJOR HEADACHE
Oil and gas companies involved in exploration and production spent an average of $80 billion a year
on maintenance between 2015 and 2019, according to Rystad.
The industry typically takes advantage of periods of slow demand to do repair work but with oil
prices nearly halved since the start of the year, this is no ordinary trough. Companies, many of them
lumbered with high debts, are slashing all but the most essential work.
Some units were shut down for maintenance but the work never started according to Amanda
Fairfax, downstream oil market analyst at Genscape, a firm that monitors refineries activities with
cameras.
“They don’t want either to invest the capital expenditure into the maintenance project or they don’t
want to have as many contract workers on sites as the additional influx of workforce might
compromise people who have to remain at the refinery as essential personnel,” she said.

A large maintenance programme in Russia’s Far East Sakhalin-2 project faces delays as the firm
could not get pre-ordered pieces of machinery, two sources told Reuters.
“There was a major headache with parts manufactured in China. After the coronavirus outbreak
there, the supplier told us it couldn’t deliver our order. There are attempts to replace it, but the time
has been lost,” an industry source told Reuters.
Sakhalin Energy told Reuters that the company operates according to a long-term maintenance
plan, which is being constantly revised.
“All works will be carried out in accordance with up-to-date plans, safety instructions and quarantine
measures required by the state authorities,” the company’s representative said in an email. Its
neighbour, Sakhalin-1 project, operated by ExxonMobil (XOM.N), also said earlier this month that it
was adjusting the schedule and scope of work at the plant.
“To ensure the safety of our personnel ... we are focusing on those activities, which can be executed
safely in the current COVID-19 situation and are essential for our continued economic and
operational resilience,” ExxonMobil said.

Reuters has identified nearly a dozen companies whose maintenance and development plans have
been affected by lockdowns.
THE ITALIAN CONNECTION
The lockdown in Italy, which has suffered one of the worst virus outbreaks globally, has reverberated
across the energy sector because the country is a leading valve manufacturer.
An industry source in Milan told Reuters that until recently less than 10 percent of Italian producers
remained active, struggling to supply even strategic valves to overseas clients.
Italy eased its coronavirus lockdown early in May, giving factories the green light to restart
production lines.
One energy company in Nigeria said it was hoping to receive valves from its Italian supplier soon
as they had been first in line when the shutdown began, the source said. But others are less
optimistic.
A maintenance and development operation at an onshore field in Nigeria was delayed for months
as the local oil firm could not receive equipment on time, a company source told Reuters.

Oil companies across Nigeria have also struggled to move workers to where they are needed due
to lockdowns that vary by state, and regulations from the petroleum regulator limiting the number of
workers at any oil site is also complicating operations.
Rivers state, home to the oil hub of Port Harcourt, is under a lockdown so strict that the governor
arrested 22 oil workers who landed there, despite federal government permits allowing them to
travel.
The Rivers movement restrictions have also trapped pipes and other needed materials that are
needed at oil fields outside the state, industry sources told Reuters.
Coronavirus company impact: Royal Dutch Shell
Shell announced that it would reduce its planned capital expenditure by 24% from earlier levels of
approximately $26.5bn. The company is also planning to reduce its operating expenses by $3-$4bn
over the next 12 months compared to 2019 levels.
These measures are anticipated to enhance Shell’s free cash flow by up to $8-$9bn on a pre-tax
basis for 2020. Additionally, Shell has suspended its $25bn share buyback programme to cope with
the oil price downturn. Moreover, the company has secured a $12bn credit facility to safeguard its
dividend distribution plan.
Shell revises CapEx and OpEx to enhance free cash flow

After reducing CapEx guidance for 2020, Shell announced its exit from Lake Charles liquefied
natural gas (LNG) project in Louisiana. The company is also postponing FIDs on several upcoming
oil and gas fields. This includes the Browse project and Crux expansion project in Australia, the
Cambo deepwater oil project in the North Sea and the Bonga Southwest / Aparo in Nigeria.
The Covid-19 outbreak in the UK North Sea region has prompted Shell to postpone the construction
of the Shearwater-Fulmar gas pipeline. This development will delay the company’s objective of
increasing gas production from the Shearwater platform.
The company also decided to halt the construction at Shell Chemical’s planned Beaver County
Complex, one of the largest upcoming petrochemical projects of the company in the US, due to
Covid-19.

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
NewBase energy news is produced daily (Sunday to Thursday) and
sponsored by Hawk Energy Service – Dubai, UAE.
For additional free subscription emails please contact Hawk
Energy
Khaled Malallah Al Awadi,
Energy Consultant
MS & BS Mechanical Engineering (HON), USA
Emarat member since 1990
ASME member since 1995
Hawk Energy member 2010
www.linkedin.com/in/khaled-al-awadi-38b995b
Mobile: +971504822502
khdmohd@hawkenergy.net or 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 2020 K. Al Awadi

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