New base energy news october 15 2018 no-1206 by khaled al awadi

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NewBase Energy News 15 October 2018 - Issue No. 1206 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: Abu Dhabi Scraps Oil Refiner Cepsa's IPO
Blommberg - Macarena Munoz Montijano
Abu Dhabi shelved plans for an initial public offering of a 25 percent stake in Spanish oil refiner
Cepsa as investors balked at the valuation amid a stock market rout.
“Recent international economic developments have created uncertainty in international capital
markets,” Cepsa, which is controlled by Abu Dhabi’s state-owned Mubadala Investment Co. The
final price for the IPO was set to be decided tomorrow.
Bankers scrambled last week to save the IPO, expected to the largest by a European oil company
in more that a decade, as investors balked at Mubadala’s valuation. The sale coincided with a rout
in the global equity market, with European stocks down to the lowest since 2016 levels.
The offering would have valued Spain-based Cepsa at between 7 billion euros ($8.1 billion) and 8.1
billion euros. Mubadala’s preference was to pull the IPO rather than accept a lower valuation, people
familiar with the matter said last week.
Mubadala said it would consider reviving the IPO.
“As a long-term investor, we will consider returning to the market when we believe conditions are
favorable,” Mubadala Chief Executive Officer Musabbeh Al Kaabi said in an emailed statement.

UAE: New Adnoc sulphur pipeline to be completed in 2019
The National - Jennifer Gnana + NewBase
State-owned Abu Dhabi National Oil Company confirmed that work is on track to build a new pipeline
for transporting molten sulphur from expanding operations in its Shah sour gas fields.
Subsidiary Adnoc Sour Gas, previously known as Al Hosn Gas, said the pipeline - which will carry
the liquid sulphur for granulation at a plant located 11 kilometres away - will be completed in 2019.
Adnoc Sour Gas, which accounts for 10 per cent of gas production in the UAE, is a 60:40 venture
between Adnoc and Occidental Petroleum.
The company, which currently produces 1 billion standard cubic feet per day of gas, has been
looking to expand production at the Shah facilities as well as become one of the leading exporters
of sulphur. Adnoc is one of the world’s largest producers of sulphur due to its significant reserves of
sour gas, which after processing, yields the yellowish chemical as a byproduct.
Abu Dhabi's sulphur production currently stands at 6 million tonnes a year and its global market
share nearly doubled to 11 per cent in 2016 from 6 per cent in 2014. Sulphur carried via the new
pipeline will be transported by rail to a handling terminal at Adnoc’s downstream hub in the western
region of Ruwais.
Germany’s MMEC Mannesmann is executing the engineering, procurement, construction (EPC) as
well as commissioning of the pipeline. Adnoc estimates nearly 60 per cent of the value of the EPC
contract to be re-directed to the UAE economy under its in-country value programme.

Granulated sulphur, a key ingredient in fertiliser production, is found in Abu Dhabi sour gas fields in
the form of hydrogen sulphide, requiring refining before use. Apart from gas, the Shah gas field
produces 4,400 tonnes per day of natural gas liquids, 33,000 barrels per day of condensate as well
as 10,000 tonnes per day of pure granulated sulphur. Expansion of the field will make Adnoc one
of the world’s largest producers of sulphur.
With more unconventional gas projects targeted as part of its recently-approved Dh400 billion
spending plan, Adnoc expects the amount of sulphur available for export to increase.
The UAE has long targeted becoming the world’s biggest exporter of sulphur, a niche product for
hydrocarbon producers. In December, Adnoc signed a long-term agreement to supply sulphur to
phosphate producer OCP Morocco, the world’s largest sulphur importer.
In January, the Abu Dhabi company awarded front-end engineering and design contracts for its
offshore ultra-sour gas fields of Hail, Ghasha and Dalma as it looked to ramp-up gas production to
meet growing domestic demand.
The gasfield also produces 4,400 tonnes per day of natural gas liquids, 33,000 barrels
per day of petroleum condensates (high-quality oil produced with gas) and about 9,000
tonnes per day of pure granulated sulphur.
Adnoc plans to use the sulphur to give a boost to the existing ammonia and urea industry.
“Demand for domestic gas is rising and processing additional sour gas from new and
existing reservoirs makes sound business sense,” said Vicki Hollub, the chief executive
of Occidental.
The UAE’s gas import needs have risen by more than 20 per cent over the past six years,
to about 725 bcf annually.

There had been plans in place for further gas development, but earlier this year Royal
Dutch Shell pulled out of the $10bn project to develop the Bab ultra-sour gasfield in Abu
Dhabi’s western region, citing technical challenges and costs.
Both Shah and Bab contain a high amount of hydrogen sulphide, which is difficult and
expensive to process. Shell was 40 per cent owner and the operator of the Bab, with
Adnoc’s Gasco subsidiary owning 60 per cent.
Out of the 1 billion bcf of gas, the Bab project was forecast to produce, by 2020, 520
million bcf of network gas.
Qatar has also agreed to supply more natural gas to the UAE through the Dolphin
pipeline system, with the additional amount earmarked for Sharjah Electricity and Water
Authority and Ras Al Khaimah.
The long-term sale and purchase agreement is between Qatar Petroleum and Dolphin
Energy, a joint venture between Abu Dhabi investment company Mubadala
Development, Occidental and France’s Total. Neither has commented about the quantity
or other terms of the deal.

Oman : Orpic Logistics weighs plan for strategic fuel reserve
Oman Observer - Conrad Prabhu
Having delivered a world-class fuel distribution hub and associated pipeline system, Orpic Logistics
Company LLC — the fuel logistics arm of Oman Oil Refineries and Petroleum Industries Company
(Orpic) — is now weighing plans for the establishment of strategic fuel reserves for the nation.
The ambitious move is set to take fuel logistics to a new level in the Sultanate, effectively elevating
Oman into the ranks of nations that have in place strategic stockpiles to secure their domestic
requirements in the event of any emergencies or contingencies.
“We are continuing to explore options to increase the capacity of the Al Jifnain Terminal (the nerve
centre of the company’s fuel logistics infrastructure), especially to explore opportunities to dedicate
tankage towards strategic reserves for the country,” said Andrés Suarez (pictured), General
Manager — Orpic Logistics Company LLC.
“We are working closely with the Ministry of Oil & Gas in this regard, although right now there is
nothing tangible or concrete (to announce). The plans are there, and the discussions are ongoing.”
The comments come on the first anniversary of the commercial launch of Al Jifnain Terminal – the
centrepiece of the $336 million Muscat-Suhar Product Pipeline (MSPP) scheme, billed as one of
Orpic’s strategic growth projects.
The MSPP project comprises a network of pipelines that connect the Al Jifnain Terminal (located
just outside Muscat Governorate) with Orpic’s Mina Al Fahal refinery in Muscat. Integrated with this
network is a multi-product pipeline connecting Orpic’s Sohar Refinery with the Al Jifnain facility.
A third pipeline connects the terminal with the New Muscat International Airport, supplying jet fuel
by pipeline in place of tanker tanks. The total length of the pipeline is about 290 kilometres.
Speaking exclusively to the Observer, Suarez noted that the proposed strategic fuel reserve would
be established in a suitable location in the country. “It could be in Al Jifnain, but it could also happen
anywhere else – we are exploring different options,” he said.

Any expansion of the pipeline infrastructure beyond the current scope of the Muscat-Suhar Product
Pipeline (MSPP) system, the General Manager explained, would hinge on significant growth in fuel
demand in the Sultanate.
“It will depend on growth in consumption, especially in areas that do not have a pipeline connection.
It could be (extended) to Duqm, or could be up to Salalah, but consumption needs to grow first in
order for a viable investment to be made in pipeline capacity, since distances involved could be
around 1,000 km.”
Orpic Logistics also operates a fuel depot located within the Port of Salalah, which serves as a hub
for fuel distribution to filling stations across Dhofar Governorate. Around 15 per cent of the nation’s
fuel requirement is met via this terminal, according to the executive.
Two weeks ago, Orpic Logistics began pumping jet fuel directly from the Al Jifnain Terminal to the
new Muscat International Airport via pipeline, effectively taking all tanker truck traffic between the
terminal and the airport off the road network. Until the successful commencement of piped supplies
of jet fuel, the airport’s requirements were met by a 50 – 60 tanker trucks daily, according to the
executive.
Tanker truck movements within the capital area have also dramatically fallen in the wake of the
successful start-up of fuel distribution from Al Jifnain, said Suarez. “By shifting 70 per cent of the
demand from Mina Al Fahal to Al Jifnain, we have removed 350 – 400 trucks daily from the road
network, thereby contributing to easing traffic congestion on this stretch.
Of course, we haven’t fully eliminated all tanker trucks because filling stations in the city still need
to be served by trucks. But trucks heading to South Al Batinah and the interior parts of the country
can proceed directly from Al Jifnain, without having to traverse the heart of Muscat,” he added.
Orpic Logistics Company is a joint venture between Orpic and Spanish fuel logistics specialist
Compañía Logística de Hidrocarburos (CLH).

Mauritania/Senegal:KBR awarded FEED contract for BP’s Tortue project
Source: KBR
KBR has announced that its UK operating subsidiary has been awarded a Front End Engineering
Design (FEED) contract by BPfor Phase 1 of the Tortue field Hub/Terminal development located on
the maritime border between Senegal and Mauritania. The agreement contains a mechanism to
allow transition of the contract to an Engineering, Procurement and Construction Management
(EPCM) contract at a later date.
Under the terms of the contract, KBR will provide management of the Quarters and Utilities (QU)
including Telecoms Systems FEED and provision of supplemental services (system engineering,
interface oversight, technology planning, support and verification) of the Hub/Terminal for the Tortue
project in Senegal and Mauritania.
The FEED work is to be performed up to the end of 2018 to support the FID. Local content was
carefully considered as part of the regular contract evaluation process, and will continue to be
closely reviewed to identify potential opportunities during KBR FEED engineering work.
'We are proud to continue to be part of this significant project providing this technical assurance and
facilities integration role to BP,' said Jay Ibrahim, KBR President, Europe, Middle East and Africa
and Asia-Pacific. 'This win is indicative of KBR's strategic commitment to our partner BP, building
on concept work done by our subsidiary Granherne, and then the Pre-FEED that was executed by
KBR and now to this FEED award.'
Estimated revenue associated with this project will be booked into backlog of unfilled orders for
KBR's Hydrocarbons Services Business segment in the fourth quarter of 2018.

UK: Hydraulic fracturing start at shale gas site in Lancashire
Source: Cuadrilla
Cuadrilla has confirmed that it plans to go ahead with the start of hydraulic fracturing operations at
its Preston New Road shale gas exploration site in Lancashire.
At the High Court in London on 12 October Mr Justice Supperstone dismissed a last minute request
for an interim injunction to prevent this from happening, and also dismissed a Judicial Review case
against Lancashire County Council’s (LCC) emergency response planning and procedures for the
Preston New Road site.
Mr Justice Supperstone concluded that there was no evidence to support the contention that LCC
had breached any of the relevant duties concerning emergency planning.
Hydraulic fracturing to go ahead at shale gas exploration site in Lancashire
Francis Egan, CEO of Cuadrilla, said:
'We are delighted to be starting our hydraulic fracturing operations as planned. We are now
commencing the final operational phase to evaluate the commercial potential for a new source of
indigenous natural gas in Lancashire. If commercially recoverable this will displace costly imported
gas, with lower emissions, significant economic benefit and better security of energy supply for the
UK.'
The hydraulic fracturing process will take approx. three months to complete for both horizontal
exploration wells. Cuadrilla will then test the flow of natural gas from those two wells with initial
results expected in the New Year.

Eat Timor: Timor-Leste buys $M484 stake in Greater Sunrise fields
Pacific Beat - Stephen Dziedzic
 Timor-Leste spending $484m to buy 30 per cent stake in Greater Sunrise
 Australian officials doubt whether Timor-Leste can pull off pipeline plan
 Fledgling nation could face financial disaster if project collapses
Timor-Leste's leaders want to build a 150-kilometre pipeline, stretching all the way from the tiny
south coast hamlet of Beaço to the vast Greater Sunrise oil and gas fields of the Timor Sea. That's
not all. They see a new port and a huge LNG plant springing up in the village, processing the 5
trillion cubic feet of gas which lie under the waves.
They see a sleek new highway running along the country's south coast, linking the LNG plant to a
refinery and a sprawling airport, complete with helipads. Deal could 'unravel' borders with Indonesia
A landmark agreement over the Australian and East Timor maritime border will settle one long
dispute, but it could open another legal wrangle with Indonesia, writes Anne Barker.
And they promise this development will transform not just these towns, but Timor-Leste itself,
bringing wealth, skilled jobs and development to the fledgling nation. Analysts label this vision a
pipe-dream, and the multinational companies that hold the rights to Greater Sunrise are
unconvinced.
But Dili is pushing ahead. And this week it sent a very big signal that it remained determined,
pledging almost half a billion dollars to buy a 30 per cent share in the Greater Sunrise consortium
held by US company ConocoPhillips.

Timor-Leste's former president, Xanana Gusmao, is now set on convincing the other oil and gas
giants with a stake in Greater Sunrise that Dili's vision can work. It's a sudden and dramatic
manoeuvre. But Timor-Leste knows it has to move quickly.
Right now, almost all of its revenue comes from oil and gas fields that could run dry in less than five
years. And the sovereign wealth fund the nation has built from its natural assets will not last forever.
Experts predict it will dwindle to nothing well before 2030.
Why buy out Conoco?
If Timor-Leste wanted any chance of convincing the oil and gas giants to send LNG to Beaço, then
it needed ConocoPhillips out of the picture. Before the most recent move from Dili, exploration and
exploitation rights for Greater Sunrise were held by four energy companies — Woodside,
ConocoPhillips, Shell and Osaka Gas.
All four venture partners have been deeply sceptical about whether Timor-Leste's vision of a
flourishing domestic LNG industry is viable. But sources close to recent discussions have told the
ABC ConocoPhillips has never looked like budging.
The US energy company simply did not think the project was feasible.
PHOTO: Timor-Leste is highly dependent on its natural resources. (Supplied: Woodside Energy)
It wanted to send the gas to Australia instead, so it could maintain a reliable supply to its LNG plant
across the harbour from Darwin's CBD. And its frustrations seemed to grow when Greater Sunrise
was ensnared in a bitter diplomatic dispute.

Commercial negotiations were suspended for years while Australia and Timor-Leste wrangled over
their maritime boundary — which runs right through the gas fields. The two nations finally signed a
landmark agreement in March this year, with East Timor being granted the lion's share of royalties.
But by then, ConocoPhillips was already intent on finding new sources of gas for its Darwin plant.
It's been pushing ahead with a new plan to develop the Barossa gas fields 300km to Australia's
north.
PHOTO: Timor-Leste now owns ConocoPhillips' 30 per cent stake in the Greater Sunrise fields. (ABC: Jarrod Fankhauser/Woodside)
Meanwhile, Timor-Leste spotted an opportunity to change the fundamental dynamics of commercial
discussions. Late last week, it offered the Conoco $485 million for its stake in Greater Sunrise.
ConocoPhillips — perhaps wearying of protracted negotiations, and with no compelling reason to
stay — took the money, and got out. One of the company's vice-presidents, Kayleen Ewin, told the
ABC ConocoPhillips and Timor Leste had "different views" on Greater Sunrise, but insisted it was
an amicable parting.
"We had a full and frank exchange of views with Timor Leste. We respect the fact that their criteria
for development is different to ours," she said. "For us, we have to make sure that our investments
compete in our portfolio. So this was a way to solve the fact that we have different criteria."
If the other joint partners approve the move, Timor-Leste will get a much more powerful voice at the
table, and a substantial new stake in the venture. But it's unlikely to be the last time the Government
opens the purse strings.
Now Timor-Leste has a stake, it will probably have to funnel billions of dollars from its sovereign
wealth fund into the project in order to get it off the ground.

Timor-Leste's leaders want to boost the country's economy by building an LNG plant and refinery in Beaço. (ABC: Jarrod Fankhauser)
Dr Bec Strating from LaTrobe University said Timor's leaders had locked themselves into their
pipeline plan by presenting it as a symbol of the small nation's sovereignty.
"It really draws on nationalistic rhetoric. By describing the pipeline as a non-negotiable it really
makes it difficult for them to back away from the vision they've established," she said. "It's a
rhetorical straight-jacket."
Dili is also searching for new sources of cash, courting export credit agencies and companies in
Asia which might be willing to develop Greater Sunrise and send the gas north. But close watchers
worry its gamble will not pay off — because the project simply does not stack up.
Just a pipedream?
First, building a pipeline to Timor-Leste poses formidable challenges. It would have to cross an
ocean trench called the Timor Trough, which plunges to depths of more than three kilometres.
One expert predicts it would have to be 75 per cent thicker than the heaviest pipeline ever built
before — the Blue Stream, which runs across the Black Sea. The oil and gas companies are also
sceptical about whether Timor Leste has the capacity to develop an industry from scratch.
Earlier this year, the UN Conciliation Commission published analysis which found Timor's proposal
would only get off the ground with a government subsidy of about $7.7 billion.
That drew a furious response from Mr Gusmao, who called the assessment "shockingly
superficial" and accused Canberra of colluding with the big energy companies to send the gas to
Darwin instead of Beaço.

The future is now
The next six months will be crucial, and Australia will be watching the negotiations carefully.
Strictly speaking, the Federal Government is neutral on how the gas fields should be developed —
but officials also doubt East Timor's grand plan can become a reality. That clearly frustrates Dili,
which is using every bit of leverage it can get.
Australia and East Timor agreed on a maritime border in March, resolving years of bitter wrangling over the oil and gas riches. (AP: Seth Wenig)
Some Timor Government figures have been quoted saying if they could not convince the energy companies
to get on board, then they might turn to China to help them buy out the other partners and build the new
pipeline.
Close observers say that is probably a negotiating tactic rather than a real live option. But Australia is already
wary about China's growing influence in Pacific Island nations, and the prospect of Timor taking on a massive
soft loan from Beijing would concentrate minds in Canberra.
And there is no need to conjure nightmare scenarios — the current stalemate on Sunrise is already deeply
worrying for both countries. Timor-Leste is a poor country with a burgeoning population and few sources of
cash. It desperately needs Greater Sunrise to fill coffers that will rapidly dwindle when the current reserves
run dry. Dr Strating warned if the project collapsed, the small nation could be in dire straits.
"There doesn't seem to be any other plan for Timor Leste's future," she said. "So if the pipeline falls through,
then what else would there be to try to develop Timor Leste's economy in the long term?
"There is a great deal of risk in this strategy." If Timor does not find new sources of revenue, it could go over
a fiscal cliff within a decade. That would be a disaster for Timor-Leste. But it would be a big problem for
Australia as well.

NewBase 08 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 prices rise on Saudi tensions; demand outlook drags
Reuters+ Bloomberg + NewBase) - Crude oil futures rose on Monday as geopolitical tensions over
the disappearance of a prominent Saudi journalist stoked supply worries, though concerns over the
long-term demand outlook dragged on prices.
FILE PHOTO - A Chinese man works at a pump jack in PetroChina's Daqing oil field in China's
northeastern Heilongjiang province March 18, 2006.
Benchmark Brent crude oil jumped by $1.49 a barrel to a high of $81.92 before slipping to $80.83,
up 40 cents, by 0745 GMT. U.S. crude was last up 20 cents at $71.54.
“Growing tensions over the disappearance of journalist Jamal Khashoggi at the Saudi consulate in
Istanbul has proved supportive for oil prices,” said ING commodities strategist Warren Patterson.
Saudi Arabia has been under pressure since Khashoggi, a critic of Riyadh and a U.S. resident,
disappeared on Oct. 2 after visiting the Saudi consulate in Istanbul.
Oil price special
coverage

OPEC, Russia and other oil producers, such as U.S. shale companies, had increased production
sharply since May, the IEA said, raising world crude output by 1.4 million barrels per day (bpd). “I
just looked at the IEA numbers in detail and these are very bearish for oil prices,” said Commerzbank
commodities analyst Carsten Fritsch.
The IEA report came after the secretary general of the Organization of the Petroleum Exporting
Countries said that the group saw the oil market as well supplied and that it was wary of creating a
glut next year.
Societe Generale on Monday raised its forecast for Brent crude in the final quarter of this year to
$82 a barrel, up from a previously forecast $78, after a sharp rise in prices over the past couple of
months pushed Brent up from about $70.
The French bank wrote that there were “high levels of risk and uncertainty in the oil markets”.
Oil Prices Already Moving Toward $100
The global oil market that’s already being squeezed by U.S. sanctions on Iran is now being rattled
by the risk of potential American action against another OPEC member.
While crude prices rose almost 2 percent after Saudi Arabia pledged to retaliate and said it had an
“influential and vital role in the global economy,” it’s far from certain that it will use energy as a
weapon. The kingdom’s warning on Sunday didn’t make an explicit reference to petroleum. And
during a recent diplomatic spat with Canada, it continued to supply a refinery in the North American
country even though Riyadh severed most other economic links.
If it does resort to wielding crude as ammunition -- as it did in 1973-1974 when the kingdom led an
oil embargo during a war between Israel and a coalition of Arab states -- the move may spark far-
reaching consequences for global financial markets and economies. While U.S. crude production
rivals Saudi Arabia’s, America’s exports are much smaller. The kingdom is also a major supplier to
Gulf Coast refineries as well as top buyers in Asia.

If the Saudis retaliate using oil, it would lead to “a calamity in Asia,” said Stephen Innes, Singapore-
based head of Asia Pacific trading at Oanda Corp. “This would be so destabilizing for global markets
that it would make the current trade tensions between the U.S. and China look like a game of Axis
& Allies.”
Still, he cautioned that the countries may be exchanging idle threats and it would not be a politically
prudent move for the Saudis to escalate tensions via oil supplies because it would inflict self-
damage.
Brent crude, the benchmark for more than half the world’s oil, rose as much as 1.9 percent to $81.92
a barrel, before paring gains to trade at $81.24 by 6:58 a.m. in London. West Texas Intermediate,
the U.S. marker, jumped to $72.70 a barrel before trading at $71.90.
While the kingdom has denied any involvement in Khashoggi, U.S. administration officials are said
to increasingly regard the kingdom’s position as untenable. President Trump and his aides are said
to be more and more convinced that the Washington Post writer died after entering the Saudi
consulate in Istanbul on Oct. 2 to pick up a document for his wedding.
A range of punishments are under discussion within the U.S. administration, from downgrading
diplomatic relations or sanctioning Saudi officials to following major U.S. companies in withdrawing
officials from an investment conference in Riyadh later this month.
$100 Oil
While average Saudi oil production this year of about 10.2 million barrels a day has slightly trailed
U.S. output at 10.6 million barrels daily, the Middle East nation’s exports have averaged 7 million
barrels a day, outpacing America’s 1.8 million barrels a day of shipments. The kingdom accounted
for almost 40 percent of total Persian Gulf OPEC exports last month, data compiled by Bloomberg
show.
Global benchmark Brent crude is already over $80 a barrel as impending U.S. sanctions on Iran take
barrels out of the market, spurring economic turmoil in developing economies such as India. In
America, Trump wants to tame prices before key midterm elections in November. Some traders
have forecast prices will return to $100 a barrel soon as the Organization of Petroleum Exporting
Countries struggles to fill a supply gap.
Roger Diwan, a veteran OPEC watcher at consultant IHS Markit Ltd., said the Saudi comments
broke “an essential oil market taboo” and could be self-defeating. “Saudi Arabia threatening oil flows
at a time when the U.S. is implementing sanctions on Iran exports in coordination with Saudi Arabia
shows the tenuous position oil markets are in,” he said.
Turki Al Dakhil, who heads the Saudi state-owned Arabiya news network, wrote in an article that
U.S. sanctions against Saudi Arabia could wreak havoc on the global economy by taking oil prices
to $200 a barrel and more. Faisal bin Farhan, a senior adviser to the Saudi embassy in Washington,
said on Twitter that these comments don’t represent the Saudi leadership.
The warning came after President Donald Trump pledged “severe punishment” should Saudi Arabia
be linked to Khashoggi’s disappearance.

If Saudi Arabia does use its crude resources to hit back, it would be a break from its decades-old
policy of putting petroleum above politics. During a recent diplomatic spat with Canada, state-owned
producer Aramco continued to supply a refinery in the North American nation even though Riyadh
severed most other economic links. The kingdom had used energy as a weapon when it led an oil
embargo in 1973-1974 during a war between Israel and a coalition of Arab states.
“Issues surrounding the disappearance of Khashoggi could be one of the factors spurring the latest
rebound in oil prices,” Kim Kwangrae, a commodities analyst at Samsung Futures Inc., said by
phone. “Still, prices are likely to trade in the early $70s this week, with limited upward pressure, as
the U.S. continues to push for lower prices, while there are uncertainties about how much OPEC
and its allies can ramp up production.”
Crude has retreated more than 5 percent after reaching a four-year high earlier this month as a
darkening demand outlook, coupled with global stock market routs, spur investors to shun risk
assets including commodities. Still, traders continue to speculate whether OPEC and its partners
can offset potential supply losses from Iran as American sanctions are set to curb oil exports from
the Persian Gulf state.
READ: Russia Seen Able to Add Extra Oil as Traders Fret Spare Capacity
West Texas Intermediate for November delivery rose as much as $1.36 to $72.70 a barrel on the
New York Mercantile Exchange, and was at $71.93 at 7:30 a.m. in London. The contract slid 4
percent to $71.34 last week. Total volume traded was about 27 percent above the 100-day average.
Brent for December settlement climbed as much as $1.49, or 1.9 percent, to $81.92 a barrel on the
London-based ICE Futures Europe exchange. Prices declined 4.4 percent to $80.43 last week, the
biggest weekly drop since early April. The global benchmark crude traded at a $9.57 premium to
WTI for the same month.

NewBase Special Coverage
News Agencies News Release 08 October 2018 -2018
U.S : N. gas storage to enter winter at lowest levels since 2005Source: U.S. Energy Information Administration, Weekly Natural Gas Storage Report, Short-Term Energy Outlook
EIA forecasts that natural gas inventories will reach 3,263 billion cubic feet (Bcf) at the end of
October in its recently released October Short-Term Energy Outlook (STEO), the lowest end-of-
October level for U.S.
natural gas inventories since 2005. Lingering cold temperatures in April 2018, the coldest April in
the past 21 years, delayed the start of the natural gas storage refill season by about four weeks.
Coupled with heavy natural gas withdrawals in January 2018, the delayed start to the refill season
led to storage levels that have
remained lower than the previous
five-year minimum. However, late-
season injections during the past
four weeks have been close to their
five-year averages, with injections
averaging 81 Bcf compared with
the five-year average of 82 Bcf.

Source: U.S. Energy Information Administration, Weekly Natural Gas Storage Report, Short-Term Energy Outlook
Natural gas storage is used to balance seasonal fluctuations in production and consumption. The
greatest fluctuations in U.S. natural gas consumption are in the residential and commercial sectors,
where natural gas is used as a heating fuel. Across all sectors, U.S. consumption of natural gas
during winter months tends to be about 30% to 35% higher than in the spring and fall months, when
temperatures are relatively mild.
Natural gas is withdrawn from storage facilities throughout the United States during times of high
demand and injected into storage facilities during times of low demand. Traditionally, the injection
season lasts from the beginning of April through the end of October, though natural gas is now
regularly injected through October and into early November in the United States.

In 2018, relatively cold winter weather led to more withdrawals from storage, and inventories
transitioned from being near the previous five-year average to being lower than average. By mid-
July, inventory levels fell to lower than the previous five-year range for that time of year.
Increases in U.S. domestic production of natural gas and the buildout of infrastructure to deliver it
to consumers may have reduced the need for operators to store as much natural gas. EIA projects
that U.S. dry natural gas production will average a record 82.7 Bcf/d in 2018, an 11% increase from
2017.
With production outpacing domestic consumption, the United States has transitioned to being a net
exporter of natural gas. EIA expects U.S. gross exports of natural gas to average 10.1 Bcf/d in 2018,
a 16% increase from the previous year, with most of the growth in exports of liquefied natural gas.
EIA projects that spot natural gas prices at the Henry Hub benchmark will average $2.99/million
British thermal units (MMBtu) in 2018, virtually identical to 2017. In the STEO, annual average Henry
Hub natural gas prices are expected to increase slightly to $3.12/MMBtu in 2019.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook and CME Group
In the past, relatively low natural gas inventories have coincided with relatively high prices, but
recent changes in U.S. natural gas markets have kept prices relatively low and stable. The steady
increase in U.S. production in 2018 has suppressed natural gas futures market prices, despite
record consumption of natural gas in the electric power sector this summer and increasing U.S.
exports of liquefied natural gas.
In addition to production increases, new pipeline infrastructure in the Northeast and South
Central regions has enabled natural gas shipments directly from production centers to demand
centers, further reducing the need for maintaining high inventory levels.
The United States is typically broken out into three main regions when it comes to gas consumption
and production. These are the consuming East, the consuming West and the producing South.

Consuming East
The consuming east region, particularly the states in the northern part, heavily rely on stored gas to meet the peak demand during
the cold winter months. Due to the prevailing cold winters, large population centers and developed infrastructure, it is not surprising
that this region has the highest level of working gas storage capacity of the other regions and the largest number of storage sites,
mainly in depleted reservoirs.
In addition to underground storage, LNG is increasingly playing a crucial role in providing supplemental backup and/or peaking
supply to LDCs on a short term basis. Although the total capacity for these LNG facilities does not match those of underground
storage in scale, the short term high deliverability makes up for that.
Consuming West
The consuming west region has the smallest share of gas storage both in terms of the number of sites as well as gas
capacity/deliverability. Storage in this area is mostly used to allow domestic and Albertan gas, coming from Canada,
to flow at a rather constant rate.
Producing South
The producing south's storage facilities are linked to the market centers and play a crucial role in the efficient export,
transmission and distribution of natural gas produced to the consuming regions. These storage facilities allow the
storage of gas that is not immediately marketable to be stored for later use.
Owners and Operators of Storage Facilities
The principal owners/operators of underground storage facilities are interstate pipeline companies, intrastate pipeline companies,
local distribution companies (LDCs), and independent storage service providers. About 120 entities currently operate the nearly
400 active underground storage facilities in the Lower 48 states. If a storage facility serves interstate commerce, it is subject to the
jurisdiction of the Federal Energy Regulatory Commission (FERC); otherwise, it is state-regulated.

Owners/operators of storage facilities are not necessarily the owners of the natural gas held in
storage. In fact, most working gas held in storage facilities is held under lease with shippers, LDCs,
or end users who own the gas. The type of entity that owns/operates the facility will determine to
some extent how that facility's storage capacity is utilized.
Underground Natural Gas Storage by Region, 2000
Region
Number of
Sites
Working Gas Capacity
(Bcf)
Daily Deliverability
(MMcf)
East 280 2,045 39,643
West 37 628 9,795
South 98 1,226 28,296

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
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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 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 2018 K. Al Awadi

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