New base 02 january 2018 energy news issue 1121 by khaled al awadi-compressed

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NewBase Energy News 02 January 2018 - Issue No. 1121 Senior Editor Eng. Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
Arabian Gulf Energy Producers Issue Record Debt to Expand
Bloomberg - Mohammed Sergie
Gulf Arab energy companies issued record debt this year as producers opted to exploit lower
borrowing costs to fund expansion plans.
Oil and gas producers, pipeline operators and refiners in Kuwait, the United Arab Emirates,
Saudi Arabia, Oman, Bahrain and Qatar borrowed $28.7 billion through bonds and syndicated
loans in 2017, eclipsing the previous high set two years earlier, according to data compiled by
Bloomberg. Those companies borrowed about $71.4 billion in the past three years, more than
twice the amount in the previous period.
The annual average of the J.P. Morgan Middle East Composite Index’s debt yield, an indication of
borrowing rates in the region, declined 12 basis points to 4.58 percent in 2017, a two-year low.
Global energy demand will jump 35 percent by 2040, from 2015, OPEC estimates. Its Secretary-
General Mohammad Barkindo says oil investment is needed now to meet that growth and to make
up for declining production at older fields.
Record Debt
Gulf energy companies' borrowings surge after oil prices slumped in 2014
Source: Bloomberg
State-owned companies in the Middle East have leaned on debt since 2014 as revenue fell with
energy prices. Benchmark oil prices in the region tumbled as much as 60 percent in the period.

“I think we will see more debt-raising by state energy companies in 2018,” said Robin Mills, chief
executive officer of Dubai-based consultant Qamar Energy. Even after record borrowing, the debt
levels of Gulf energy producers lag behind that of publicly traded companies, he said.
Oil and gas producers in Saudi Arabia, Kuwait and the U.A.E. plan to spend more than $600
billion on energy projects over the next five to 10 years, officials from the countries have
announced. Global energy investment was $1.7 trillion in 2016, according to the International
Energy Agency.
Top Deals
Abu Dhabi state-run energy companies combine for almost half of Gulf borrowing in 2017
Source: Bloomberg
Abu Dhabi Crude Oil Pipeline LLC, a unit of state-run Abu Dhabi National Oil Co., raised $3 billion
in a bond offering in October to finance projects. Kuwait National Petroleum Co. borrowed $6.2
billion in May for a refinery and clean fuels projects. Saudi Arabian Oil Co. sold $3 billion in
Sharia-compliant bonds in April.
Adnoc’s fuel retailing unit took out a loan and revolving credit facility totaling $2.25 billion in
November before its initial public offering this month. Saudi Aramco, as the state energy producer
is known, has a $2 billion loan guarantee from the U.K. government in the run-up to its proposed
IPO next year, likely to be the largest in history.
Further debt may be issued next year to finance power plants in Saudi Arabia and petrochemicals
in the region, Mills said. Over the next decade, Saudi Aramco plans to invest $414 billion on oil
and gas projects and a new petrochemical complex, Nassir al-Yami, general manager for
procurement, said this month.
Adnoc plans to spend $109 billion on refineries, petrochemical plants and gas exploration in the
next five years, Abu Dhabi Crown Prince Mohamed bin Zayed Al Nahyan said in November on
Twitter.
And Kuwait Petroleum Corp. has earmarked $112 billion on oil production, refinery, petrochemical
and natural gas facilities over the next five years, the company’s managing director of planning
and finance, Wafaa Al-Zaabi, said in September 2016.

Saudi Arabia New Petrol Prices comes on effect, hikes gasoline prices
Reuters Staff
Saudi Arabia was set to raise local gasoline prices on Monday, state news agency SPA reported.
The initiative, aimed at more efficient energy use, coincides with an ambitious reform plan to boost
sources of revenue and wean the world’s top crude exporter away from oil.
It said Octane 91 will sell for 1.37 riyals a liter, up from 0.75 riyals, while Octane 95 will sell for
2.04 riyals a liter, up from 0.90 riyals. Diesel rates for trucks were left unchanged.
The kingdom will slow plans to eliminate subsidies for a wide range of energy products, according
to a new long-term fiscal plan in the 2018 state budget released last month.
King Salman formally announced on Dec. 20 that the target date for eliminating the government’s
budget deficit would be pushed back to 2023 from the original target of 2020, in order to reduce
pressure on economic growth.
The Kingdom announced its broad reform initiative in 2016, saying it aimed to “enhance the level
and quality of services” provided by government and “achieve a prosperous future and sustainable
development.”

Saudi Sabic Award India's Aarti Industries $1.6bn contract
TradeArabia News Service
Indian specialty chemicals company Aarti Industries said it has secured a Rs100 billion ($1.56
billion) contract from global chemical conglomerate Saudi Basic Industries Corporation (Sabic) for
supply of for supply of specialty chemicals intermediate to its US affiliate.
As per the deal, the Mumbai-based company will supply a high value speciality chemical
intermediate to Sabic Innovative Plastics US for 20 long years. The supplies are expected to
commence from 2020.
Aarti Industries is India’s leading producer of Benzene-based basic and intermediate chemicals
and also one of the leading suppliers of dyes, pigments, agro-chemicals, pharmaceuticals and
rubber chemicals to global manufacturers.
The company ranks globally within the Top 4 for 75 per cent of its portfolio and is ‘Partner of
Choice’ for various major global and domestic customers, said the company in a statement.
Specialty chemicals segment contributed 81 per cent, Pharmaceuticals segment contributed 14
per cent and Home & Personal Care segment contributed 5 per cent to its total FY17 consolidated
revenues.
With this deal, the Indian group is set to enter a new chemistry range, a first-of its-kind in India and
its end product is amongst the major growth initiatives for the customer, said the statement.
Aarti unveiled plans to setup a dedicated large scale manufacturing facility for production of this
speciality chemical intermediate at an investment of $35-$40 million. The upcoming facility will be
a 100 per cent export oriented unit in the Indian state of Gujarat, it added.
On the contract win, Rashesh C. Gogri, the vice-chairman and managing director, said this deal is
testament to the increasing brand equity of AIL among targeted customers.
Under the terms of the agreement, the Sabic unit will be providing $42 million as an advance to
the company in installments, which shall be adjusted against the supplies in future,. he added.-
7

Iraq's exports from southern oilfields hit record 3.535 million
bpd in December 2017 …
(Reuters) - Oil exports from Iraq’s southern Basra ports rose to a record high of 3.535 million
barrels per day (bpd) in December from 3.5 million bpd the previous month, two oil officials said
on Monday.
Southern exports are on the rise as Iraq seeks to offset the halting of shipments from its Kirkuk
oilfields in the north in mid-October after Iraqi forces took back control of fields from Kurdish
fighters.
The bulk of Iraq’s oil is exported via the southern terminals. The December figure for southern
exports beat the previous record of 3.51 million bpd set in December 2016, the last month before
an output cut agreement led by the Organization of the Petroleum Exporting Countries took effect.
Rising output from small oilfields developed by the state-run Basra Oil Company helped push up
December exports, an oil official told Reuters.
The increase last month, though, has not completely offset the halt of shipments from the
north.“Our plan is to keep boosting exports from the southern oilfields to make up for the lost
Kirkuk shipments,” said another oil official with the state-run Basra Oil Company.
Iraq is OPEC’s second-largest producer after Saudi Arabia with an output capacity of 4.8 million
bpd which Baghdad aims to increase to 5 million bpd.

Norway Faces Up to Big Oil’s Snub
Bloomberg - Mikael Holter
Norway is realizing it will have to do without the deep pockets of the biggest oil companies as it
seeks to extend an era that has made it one of the world’s richest.
The most recent blow came when only 11 companies applied for new blocks in the Arctic Barents
Sea, touted as the country’s most promising area for exploration. Chevron Corp. and
ConocoPhillips were absent after bidding the last time, while Exxon Mobil Corp. and Total
SA remained out of the race. Of the five super-majors, only Royal Dutch Shell Plc applied.
Major Indifference
Norway sees lowest interest on record for new acreage as Big Oil retreats
Source: Norwegian Petroleum Directorate
Note: Super-majors defined as Exxon Mobil, Chevron, Shell, BP and Total; available records detailing names of
applicants go back to 18th round in 2004
“It’s a warning and a cause for reflection,” said Stale Kyllingstad, chief executive officer of IKM
Gruppen AS, one of the biggest suppliers to Norway’s oil industry. “The Norwegian shelf isn’t as
popular anymore. It’s a concern.”
An historic three-year slump in the industry has seen Exxon and BP Plc relinquish their role as
field operators in western Europe’s biggest producer. The landscape is changing in the aging
North Sea basin in Norway and the U.K. as companies search for higher margins in projects such
as liquefied natural-gas or U.S. shale. Smaller, more specialized companies, some backed by
private equity, are stepping in.
The indifference to Norway’s Arctic packs a special sting. The area is thought to hold half of the
country’s undiscovered oil and gas, or almost 9 billion barrels, and success in the Barents will be

key to stopping a further decline in the country’s production in the 2020s. Financial muscle will be
needed to develop finds in a region with little infrastructure.
“The farther north you go, the bigger companies you need to sit in the front seat,” said Kyllingstad.
State-controlled Statoil ASA was operator for two thirds of the country’s production in 2016,
according to figures from the Norwegian Petroleum Directorate. It has dominated exploration for
years with Sweden’s Lundin Petroleum AB and lately Aker BP ASA, the Norwegian company that
swallowed BP’s local unit.
Statoil CEO Eldar Saetre last month told Upstream that the retreat of international companies was
“not a desirable development.”
Even the Norwegian Oil and Gas Association, a lobby group that counts the majors among its
members, has a “a certain concern.” The number of companies, and “not least a variety” of them,
are key to success, said spokesman Tommy Hansen.
In a December interview, Petroleum and Energy Minister Terje Soviknes conceded he would like
the majors to stay, but said some smaller companies could be better suited to get more value out
of old fields. He also pointed to record interest in a licensing round focused on mature areas.
Yet, with some exceptions, this acreage holds less potential for big deposits. And a closer look at
the latest awards, in January 2017, also points to Norwegian domination: Statoil and Aker BP won
more than 50 percent of the operatorships, the highest concentration since this round’s inception
in 2003, according to Bloomberg calculations.
Big Oil’s disengagement comes at a difficult time for a Norwegian industry just recovering from a
bruising downturn which saw the loss of 50,000 industry jobs.
It matches a growing distaste for the industry among Norwegians, who are increasingly debating
the moral and financial merits of oil as the world steps up the fight on climate change. A court is
expected to rule this month on an unprecedented lawsuit against the government over Arctic
licenses. The country’s $1 trillion sovereign wealth fund, built on petroleum income, has even
asked for permission to dump oil and gas stocks, sending shock waves through global markets. It
cited financial reasons.
Norway’s oil production has been halved since a 2000 peak. While natural-gas output has surged,
total production is forecast to fall again in the middle of the next decade. A flurry of investment
decisions at the end of last year hides a painful truth: after Statoil’s $6 billion Johan Castberg oil
field starts production in the Barents in 2022, the project pipeline is scant.
Projects Wanted
Maintaining Norway's oil and gas output requires continued investment and exploration

Source: Norwegian Petroleum Directorate
Successive governments have pushed for more exploration in the Barents, but companies have
yet to find the likes of multi billion-barrel giants of the North Sea.
Disappointing results in the record 2017 drilling campaign, which included the most
anticipated well offshore Norway in years, is one reason for scant interest in the licensing round,
said Neivan Boroujerdi, an analyst at Edinburgh-based consultant Wood Mackenzie Ltd.
But this year could still be a break-through for the Barents as Statoil, Lundin and Aker BP are
expected to keep up a record pace of drilling, Boroujerdi said. Lundin and OMV AG could also
take decisive steps to advance their Alta and Wisting projects, with the promise of new
infrastructure eventually triggering more interest from smaller companies that typically focus on
the mature-area rounds, he said.
"It’s not all doom and gloom,” Boroujerdi said. “I don’t think we’re going to reach a point where
Barents exploration will die completely.”

Canada is the United States’ largest partner for energy trade
Source: U.S. Energy Information Administration, based on U.S. Census Bureau
Canada is the largest energy trading partner of the United States. Based on the latest annual data
from the U.S. Census Bureau, energy accounted for about 5% of the value of all U.S. exports to
Canada and more than 19% of the value of all U.S. imports from Canada in 2016.
While the value of bilateral energy trade with Canada has varied over past decade, driven
primarily by changes in prices of oil and natural gas, the overall structure of bilateral energy trade
flows has changed relatively little, and U.S. energy imports from Canada has exceeded U.S.
energy exports to Canada by a large margin.
In 2015 and 2016, the value of U.S. energy imports from Canada and the value of U.S. energy
exports to Canada both fell, reflecting declining prices of key commodities such as crude oil,
petroleum products, and natural gas. For 2016, the value of U.S. energy imports from Canada
was $53 billion, while the value of U.S. energy exports to Canada was $14 billion.
Crude oil makes up most U.S. energy imports from Canada, averaging 3.3 million barrels per day
(b/d) in 2016. Canada is by far the largest source of U.S. crude oil imports, providing 41% of total
U.S. crude oil imports in 2016.
Sales of Canadian crude oil to the United States reached more than $83 billion in 2014. As oil
prices fell in 2015 and 2016, the value of U.S. crude oil imports from Canada fell from $47 billion
in 2015 to $36 billion in 2016, despite increasing in volume. Canada’s crude oil exports to the

United States, which are produced in Alberta and are shipped primarily to the Midwest and Gulf
Coast regions of the United States, consist mainly of heavy grades.
Until 2013, virtually all U.S. crude oil exports went to Canada. However, as the United States has
exported more crude oil to other countries, Canada has made up a smaller share of U.S. crude oil
exports.
In 2016, an average of 301,000 b/d of U.S. crude oil was exported to Canada and 219,000 b/d to
all other countries. U.S. crude oil exports to Canada are typically light, sweet grades that are
shipped to the eastern part of the country.
Bilateral petroleum products trade with Canada is relatively balanced in both volumetric and value
terms. Canada was the destination for 564,000 b/d of petroleum products in 2016, or 12% of all
petroleum products exported from the United States. These exports were valued at more than
$8.2 billion.
However, the mix of petroleum product flows between the United States and Canada varies by
product and region. For example, the United States is a net importer of gasoline from Canada,
with significant volumes flowing from refineries in Eastern Canada to serve markets in the
Northeast United States.
Conversely, very little of the petroleum products exported from the United States to Canada are
finished transportation fuels. Pentanes plus, liquefied petroleum gases, and other oils make up the
majority of U.S. product exports to Canada.
Some of these products are used as a diluent to enable pipeline movement of heavy crude oils
produced in Canada. On balance, the United States is a net exporter in its bilateral petroleum
product trade with Canada, and U.S. petroleum product exports to Canada (and other
destinations) have been gradually increasing over the past decade.

Bilateral natural gas trade between Canada and the United States is dominated by pipeline
shipments. Natural gas imports from Canada averaged 8.0 billion cubic feet per day (Bcf/d) in
2016, or 97% of all U.S. natural gas imports.
Total natural gas imports from Canada were valued at more than $5.9 billion in 2016. Most of
Canada’s natural gas exports to the United States originate in Western Canada and are shipped
to U.S. markets in the West, Midwest, and Northeast. Increases in natural gas production in the
Marcellus and Utica plays have made the United States less dependent on Western Canadian
natural gas imports in northeastern markets.
U.S. natural gas exports to Canada, which averaged 1.9 Bcf/d in 2015 and 2.1 Bcf/d in 2016,
mainly go from Michigan and New York into eastern provinces. Increases in pipeline capacity to
carry natural gas out of the Marcellus and Utica shale formations may enable increased flows of
U.S. gas into Canada over the next several years.
Source: U.S. Energy Information Administration, based on National Energy Board of Canada
Note: A small amount of electricity is traded by states outside the regions shown.
Electricity makes up a small but important share of bilateral trade. In 2015 and 2016, the value of
U.S. imports of electricity from Canada averaged $2.2 billion, down slightly from an average of
$2.4 billion from 2006 to 2014.
In 2016, the United States imported 73 million megawatthours of electricity from Canada, while
exporting 9.3 million megawatthours, based on data from Canada’s National Energy Board.
U.S. electricity trade with Canada is increasing, and although the amount of electricity imported
over the Canadian border is a small part of the overall U.S. power supply, the transmission
connections linking Canada and the United States are an important component of electricity
markets on both sides of the border, where they also support electric system reliability.

China: How China Will Shake Up the Oil Futures Market
Bloomberg - Sungwoo Park
China, the world’s biggest oil buyer, is on the verge of opening a domestic market to trade
futures contracts. It’s been planning one for years, only
to encounter delays. The Shanghai International
Energy Exchange, a unit of Shanghai Futures
Exchange, will be known by the acronym INE and will
allow Chinese buyers to lock in oil prices and pay in
local currency. Also, foreign traders will be allowed to
invest -- a first for China’s commodities markets --
because the exchange is registered in Shanghai’s free
trade zone. There are implications for the U.S. dollar’s
well-established role as the global currency of the oil
market.
1. When will trading begin?
According to the Shanghai-based news portal Jiemian, which cited an unidentified person from a
futures company, trading is expected to startJan. 18. Multiple rounds of testing have been carried
out and all listing requirements met. The State Council, China’s cabinet, was said to have given its
approval in December, one of the final regulatory hurdles. The push for oil futures gained impetus
in 2017 when China surpassed the U.S. as the world’s biggest crude importer.
Top Oil Buyer
China surpasses U.S. as world's biggest crude importer
Sources: China's General Administration of Customs, U.S. EIA

2. Why is this important for China?
Futures trading would wrest some control over pricing from the main international benchmarks,
which are based on dollars. Denominating oil contracts in yuan would promote the use of China’s
currency in global trade, one of the country’s key long-term goals. And China would benefit from
having a benchmark that reflects the grades of oil that are mostly consumed by local refineries
and differ from those underpinning Western contracts.
3. How do oil futures work?
Futures contracts fix prices today for delivery at a later date. Consumers use them to protect
against higher prices down the line; speculators use them to bet on where prices are headed. In
2017, oil futures contracts in New York and London outstripped physical trading by a factor of 23.
Crude oil is among the most actively traded commodities, with two key benchmarks: West Texas
Intermediate, or WTI, which trades on the New York Mercantile Exchange, and Brent crude, which
trades on ICE Futures Europe in London.
4. Why didn’t China begin trading futures until now?
Lower crude prices have played a part. Chinese oil futures were proposed in 2012 following
spikes above $100 a barrel, but prices in 2017 have averaged little more than $50. There’s also
concern over volatility. China introduced domestic crude futures in 1993, only to stop a year later
because of volatility. In recent years, it repeatedly delayed its new contract amid turmoil in equities
and financial markets. Such destabilizing moves have often prompted China’ government to
intervene in markets in one way or another.
5. What’s China’s track record in commodities?
Nickel was the last major commodity to be listed there in 2015; within six weeks, trading in
Shanghai surpassed benchmark futures on the London Metal Exchange, or LME. In China,
speculators play a far greater role, boosting trading volumes but making markets susceptible to
volatility. In early 2016, the then-head of the LME said it was possible some Chinese traders did
not even know what they were trading as investors piled into everything from steel reinforcement
bars to iron ore. Steep price rises relented when China intervened with tighter trading rules, higher
fees and shorter trading hours.
6. Will foreigners buy Chinese oil futures?
That remains to be seen. Overseas oil producers and traders would need to swallow not just
China’s penchant for occasional market interventions but also its capital controls. Restrictions on
moving money in and out of the country have been tightened in the past two years after a shock
devaluation of the yuan in 2015 prompted a surge in money leaving the mainland. Similar hurdles
have kept foreign investors as bit players in China’s giant stock and bond markets.
7. Could the yuan challenge the dollar’s dominance in oil?
Not any time soon, since paying for oil in dollars is an entrenched practice, according to some
analysts. Shady Shaher, head of macro strategy at Dubai-based lender Emirates NBD PJSC,
says it makes sense in the long run to look at transactions in yuan because China is a key market,
but it will take years. Bloomberg Gadfly columnist David Fickling argues that China doesn’t have
“nearly the influence in the oil market needed to carry out such a coup.” On the other hand, paying
in yuan for oil could become part of President Xi Jinping’s "One Belt, One Road" initiative to
develop ties across Eurasia, including the Middle East. Chinese participation in Saudi
Aramco’s planned initial public offeringcould help sway Saudi opinion toward accepting yuan,
which is used in only about 2 percent of global payments.

NewBase January 02 - 2018 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil rises to mid-2015 high in strongest year opening since 2014
Reuters + Bloomberg + NewBase
Oil prices had their highest January opening since 2014 on Tuesday, with Brent and WTI crude
prices rising to mid-2015 highs, supported by ongoing supply cuts led by OPEC and Russia as
well as strong demand.
U.S. West Texas Intermediate (WTI) crude futures CLc1 were at $60.64 a barrel at 0220 GMT, up
22 cents, or 0.4 percent, after hitting a June 2015 high of $60.68 earlier in the day.
Brent crude futures LCOc1 - the international benchmark for oil prices - were at $67.20 a barrel,
up 33 cents, or 0.5 percent, after hitting a May 2015 high of $67.23 a barrel earlier in the day. It
was the first time since January 2014 that both crude oil benchmarks opened the year above $60
per barrel.
“Falling inventories globally and strong economic growth offset the restart of the Forties pipeline
and the resumption of production following a pipeline outage in Libya,” said Jeffrey Halley, senior
market analyst at futures brokerage Oanda in Singapore.
Oil price special
coverage

The 450,000 barrels per day (bpd) capacity Forties pipeline system in the North Sea returned to
full operations on Dec. 30 after an unplanned shutdown.
More fundamentally, oil markets have been supported by a year of production cuts led by the
Middle East-dominated Organization of the Petroleum Exporting Countries (OPEC) and Russia.
The cuts started in January 2017 and are scheduled to cover all of 2018.
Strong demand growth, especially from China, has also been supporting crude. “Oil inventories
have been declining since March 2017 and OPEC have agreed to extend production cuts until the
end of 2018 so it is probably uncontroversial to say that the fundamental outlook for oil has
improved since the beginning of 2017,” said William O‘Loughlin, investment analyst at Australia’s
Rivkin Securities.
U.S. commercial crude oil inventories have fallen by almost 20 percent from their historic highs
last March, to 431.9 million barrels. Only rising U.S. production, which is on the verge of breaking
through 10 million bpd, is somewhat hampering the outlook into 2018.
“The higher prices are expected to stoke U.S. shale output,” O‘Loughlin said. U.S. oil production
C-OUT-T-EIA has risen by almost 16 percent since mid-2016, to 9.75 million bpd at the end of last
year. However, consultancy Rystad Energy said “U.S. crude oil production capacity has reached
10 million barrels per day.”
At end of 2017 WTI makes 12% & Brent up 17% , Annual gain
Strong China demand supports oil prices

US oil prices closed above $60 a barrel on the final trading day of the year, the first time since
mid-2015, as the commodity ended 2017 with a 12 per cent gain spurred by strong demand and
declining global inventories.
International benchmark Brent crude futures ended the year with a 17 per cent rise, supported by
ongoing supply cuts by top producers Opec and Russia as well as strong demand from China.
US West Texas Intermediate (WTI) crude futures settled at $60.42, the highest close since June
2015. Brent crude futures were last up 45 cents at $66.62 a barrel at 1932 GMT. Brent broke
through $67 this week for the first time since May 2015.
WTI prices were supported by data from the US Energy Information Administration late on
Thursday showing domestic oil production {C-OUT-T-EIA} declined last week to 9.75 million
barrels per day (bpd) from 9.79 million bpd the previous week.
The spread between the benchmarks widened throughout the year, as Brent responded to the
drawdown in supply from major world producers while US output continued to grow.
The gains indicate that the global glut that has dogged the market since 2014 is shrinking.
Earlier this year, oil prices slumped on concerns that rising crude production from Nigeria, Libya
and elsewhere would undermine output cuts led by the Organisation of the Petroleum Exporting
Countries and Russia. But prices have rallied nearly 50 per cent since the middle of the year on
robust demand and strong compliance with the production limits.
“That trend is likely to continue into 2018 and worldwide oil inventories will continue their decline,”
said Andrew Lipow, president of Lipow Oil Associates in Houston.
Lipow said he expected US crude prices to creep up to around $63 a barrel by the end of next
year, while Brent would remain around $67 a barrel as US oil exports rise to record levels.
Monthly EIA data released on Friday showed US crude production hit a 46-year high in October,
but the country’s oil exports and demand also rose.
US output is up almost 16 per cent since mid-2016. Analysts expect production to top 10 million
bpd in the next few weeks and to keep growing, limiting efforts by other producers to cap global
supplies.
“The US shale impact is now encroaching on uncharted territory,” analysts at RBC Capital
Markets wrote this month, saying it had “redrawn the global crude flow map.” WTI prices were
further boosted by an EIA report of a 4.6 million barrel weekly drop in US commercial crude
storage levels. Inventories are down by almost 20 per cent from historic highs last March, and well
below this time last year or in 2015.
Extreme cold weather across much of North America could also boost US crude prices by causing
production problems in the oilfields.
Pipeline outages
In international markets, China has issued crude oil import quotas totalling 121.32 million tonnes
for 44 companies in its first batch of allowances for 2018.
China’s imports at around 8.5 million bpd, already the world’s biggest, are expected to hit another
record in 2018 as new refining capacity is brought online and Beijing allows more independent
refiners to import crude.

Pipeline outages in Libya and the North Sea have supported oil prices, although both disruptions
are expected to be resolved by early January.
Libya is to start repairing the pipeline near the Es Sider terminal this weekend, a Libyan oil official
said, while the Forties pipeline was already pumping close to normal levels, according to trading
sources.
Oil Drillers End 2017 at a Standstill
Oil explorers are closing out a year marked for its heightened pleas of austerity from investors with
restraint.
The number of working rigs drilling for crude remained unchanged for a second straight week, at
747, according to Baker Hughes data reported Friday. The count is also unchanged from the end
of November after explorers added just as many rigs as they laid off.
Nearly half of the energy executives responding to a survey by the Federal Reserve Bank of
Dallas said they expect the rig count six months from now to be at roughly the same level. The
energy firms are expecting an average price for West Texas Intermediate, the U.S. benchmark
crude, to close out 2018 at $58.98 a barrel, slightly down from today’s level.
“Oil prices appear to be high enough to support some additional drilling in 2018, but not high
enough to significantly boost activity just yet," Michael Plante, a senior economist at the Dallas
Fed, said this week in a statement. "Almost all respondents think West Texas Intermediate crude
prices need to be more than $60 to see a substantial increase in the oil rig count.”
Oil output in the U.S. dropped last week for the first time in more than two months, falling by
35,000 barrels a day to 9.75 million, according to the U.S. Energy Information Administration.

Oil Resurrection Sets Stage for Another OPEC-Shale Clash in 2018
Oil continued its revival from the biggest crash in a generation, with prices set for a second annual
gain after a year marked by hurricanes, Middle East conflict and the tussle between OPEC and
U.S. shale.
Futures are up more than 12 percent in 2017, having entered a bull market in September. In 2018,
investors will watch whether rising prices trigger a new flood of U.S. output.
“The current highs are unsustainable in the short-to-medium term, with prices likely to head back
below $60 once we get past January, but for now the season of goodwill appears to be in full
swing,” said analysts led by Michael dei-Michei at consultants JBC Energy GmbH in Vienna.
West Texas Intermediate, the U.S. benchmark, is now trading at the highest level since mid-2015,
pushed above $60 a barrel by a severe cold snap in the northeastern U.S. that spiked demand for
heating fuel. Oil topped natural gas as the biggest source of electricity in New England on
Thursday morning, after temperatures plunged well below freezing.
U.S. output has surged overall this year, hitting a 46-year high in October when producers
pumped 9.6 million barrels a day, according to federal data. The U.S. expects production to top 10
million barrels a day in the coming year.
For now, shale drillers are showing restraint, with the number of working rigs unchanged for the
second week in a row, according to Baker Hughesdata released on Friday. The rig count, now at
747, stayed relatively stable during the last quarter, even as oil strengthened.
At the same time, speculation is rising that American drillers will put more rigs to work next year as
oil strengthens. That could undermine plans by the Organization of Petroleum Exporting Countries
and and other producers, including Russia, who have pledged to extend production curbs through
the end of 2018 to wipe out a global glut.

"With that partially offsetting production cuts by OPEC and Russia, the market will have to get
confirmation that global inventories will keep coming down," Gene McGillian, a market research
manager at Tradition Energy in Stamford, Connecticut, said by telephone. "If we don’t see that
pattern continue then, we could see a significant correction."
WTI for February delivery settled at $60.42 a barrel, up 58 cents, on the New York Mercantile
Exchange. Total volume traded was about 34 percent below the 100-day average. Front-month
prices are about 12 percent higher this year, after rising 45 percent -- the most since 2009 -- in
2016.
Brent for March settlement rose 71 cents to close at $66.87 a barrel on the London-based ICE
Futures Europe exchange. The February contract expired Thursday, after rising 28 cents to
$66.72. The benchmark for more than half the world’s oil has gained 17 percent this year, after
climbing 52 percent in 2016. It was at a premium of $6.45 to March WTI.
WTI traded at an average price of about $52 this year. U.S. crude stockpiles fell 4.6 million barrels
last week to the lowest level since October 2015, according to the Energy Information
Administration Thursday. That beat the 3.75 million average estimate in a Bloomberg survey of
analysts.
“The tug-of-war between OPEC and the U.S. will continue to pressure oil from trading above $60
a barrel in 2018,” said Kim Kwangrae, a Seoul-based commodities analyst at Samsung Futures
Inc. “Like we’ve seen this year, geopolitical risks will be the key factor going forward for oil to
breach $60.”
Another possible risk for oil prices in the new year: President Donald Trump’s trade agenda. If
Trump’s protectionist rhetoric results in real trade barriers, that could boost the value of the U.S.
dollar, which would have an inverse effect on oil price, according to Bill O’Grady, chief market
strategist at Confluence Investment Mgmt LLC.

OPEC Wins Over Hedge Funds to Make 2017 Oil's Most Bullish Year
Bloomberg - Carlos Caminada
Oil bulls are charging into the new year with unprecedented vigor, and the credit goes to OPEC.
The signs that the group is winning its tug of war with shale are compelling, and money managers
have taken note: Their combined bets on rising prices for West Texas Intermediate and Brent
crude reached record levels in December.
“At least through the first half of 2018, they’ll stay pretty bullish,” said Ashley Petersen, lead oil-
market strategist at Stratas Advisors in New York. “June will be a real turning point because that’s
when we’ll hear about unwinding the deal, and if OPEC doesn’t handle it delicately, then there will
be concern that the market will be flooded with oil again.”
The last week of the year saw futures trading above $60 a barrel in New York and $67 in London
for the first time since mid-2015, after the two most important oil benchmarks surged more than 40
percent from their doldrums in June. The rally came on the back of a well-orchestrated campaign
led by Saudi Arabia and Russia to enforce and extend supply curbs implemented by the
Organization of Petroleum Exporting Countries and other producing nations.
The effort culminated with a meeting in Vienna in November, where the group and its allies agreed
to extend the cuts through the end of next year. Meanwhile, U.S. crude stockpiles have declined
by about a fifth since peaking in March and approached the end of the year at their lowest level
since October 2015.

While the threat of too much shale production next year still looms, producers are ending the year
a lot less gung-ho than they started. Under pressure from investors to focus on profits over
growth, explorers have slowed down on drilling with the U.S. rig count stalling in December.
“The expectation is that the rebalance will continue,” Gene McGillian, a market research manager
at Tradition Energy in Stamford, Connecticut, said by telephone. “We’ve approached an area
where we really need to see a steady diet of positive information.”
The optimism wasn’t so widespread earlier this year. Concern that OPEC’s efforts weren’t enough
and would end abruptly in March 2018 led short-sellers to dominate the scene for several months,
with WTI plunging to the low-$40s in June.
"It really wasn’t until the fourth quarter that we saw a resounding faith in the recovery," Stratas
Advisors’ Petersen said.
Global events also swung the market up and down along the way, such as Hurricane Harvey,
supply disruptions in Libya and Kurdistan, a pipeline shutdown in the North Sea, and last but not
least, a brutal cold snap in the final week of the year that drove up demand for heating oil, fuel oil
and natural gas.
One of the most remarkable shifts that occurred in 2017, if a very technical one, was the change
in the futures curve -- first for Brent and more recently for WTI. Contracts for nearby delivery are
trading at a premium to longer-dated ones as demand rises and supplies tighten. This pattern,
known as backwardation, hadn’t been seen so consistently since 2014.

Hedge funds boosted their Brent net-long position -- the difference between bets on a rally and
wagers on a decline -- to an all-time high on Dec. 12 and have kept it near that level.
The net-long position on WTI increased 7.3 percent to 411,972 futures and options during the
week ended Dec. 26, according to data from the U.S. Commodity Futures Trading Commission on
Friday. That was close to a record set in February. Longs rose by 5.3 percent and shorts fell by 11
percent.
The net-short position of swap dealers, an indication of hedging, increased for the 11th straight
week to a fresh record, according to the CFTC data.
In the fuel market, money managers increase their net-long position on benchmark U.S. gasoline
by about 10 percent. Meanwhile, the net-bullish position on diesel rose by 26 percent to a record
as the cold snap boosted heating demand.

NewBase Special Coverage
News Agencies News Release January 02-2018
2017 The Year We Gained OilCoin
By Liam Denning
Andy Hall, the oil trader blessed with that nickname, caused a stir this summer by closing down
his main hedge fund after long arguing for oil prices to rally and reportedly suffering big losses.
Hall didn't declare oil was dead; indeed, he warned his withdrawal could be a contrarian signal
(which turned out to be prescient).
In his letter to investors, Hall said a combination of algorithmic trading and uncertainty about
shale-oil output had upended his approach based on fundamentals around supply and demand.
Shale was screwing up the supply model and, in the absence of such an anchor, prices swung
around on a heady mix of sentiment, positioning and momentum.
He was right about shale oil, sprung upon an unsuspecting market less than a decade ago and
defying expectations ever since. Thought just a few years ago to need oil prices north of $70 or
$80 a barrel to keep going, U.S. shale output looks like it went up by more than 500,000 barrels a
day in 2017, when West Texas Intermediate crude averaged about $51.
OPEC, which has struggled to get its arms around the competitive challenge, recently published
a big upgrade to its medium-term projections for North American tight-oil production:
Curve Ball
OPEC's view on tight-oil production from North America shifted dramatically this year
Source: OPEC
Note: Projections from OPEC's "World Oil Outlook" by year of publication.
Confusion still reigns: While OPEC projects U.S. liquids production to rise by just over a million
barrels a day in 2018, analysts at Rystad Energy think it could be 1.6 million (the International
Energy Agency and Energy Information Administration lie in between).

Shale development is faster than for conventional oil fields and more modular, with multiple small
wells rather than the big, multi-year process of, say, a deepwater field. This has made frackers
more responsive to moves in oil prices, relying on deep capital markets in North America to
finance operations and hedge future output. It's no accident that the shale boom coincided not just
with triple-digit oil prices prior to 2014's crash, but also a sustained drop in the cost of capital:
Essential Fuel
The shale boom coincided with a steady drop in financing costs for oil companies
Source: Bloomberg
The ability to tap into medium or long-term financing, as well as take advantage of occasional oil-
price rallies to hedge cash flows, has been vital to shale's resilience. Investors have effectively
provided capital with a tenor of several years to fund operations executed in a matter of months:
Mañana
More than two-thirds of E&P sector debt maturing in the next decade falls due after 2021
Source: Bloomberg
Note: Outstanding debt maturities for members of the S&P Supercomposite Oil & Gas Exploration & Production Index.

The resulting crowd of competitive North American producers is the antithesis of the controlled
market sought by OPEC and earlier would-be cartels dating back to Standard Oil. One thing
critical to loosening their hold has been the establishment of liquid futures contracts way back in
the 1980s. And that marketplace has gotten a lot bigger and more frenetic in recent years:
Pump Up The Volume
The volume of trading in Nymex crude oil futures has almost tripled since 2014, to a notional 1.3
billion barrels a day
Source: CME Group
At the same time, the trading population has changed, with many pure-play energy hedge funds
disappearing and financial or algo-driven participants entering.
An updated white paper published by the Commodity Futures Trading Commission in March
compared trading trends for products listed on the CME in two periods, November 2012 to
October 2014 and November 2014 to October 2016. Automated trading in crude oil contracts rose
from 54.3 percent to 63 percent, with all of that increase reflecting transactions that were
automated on both sides. The speed of trading also picked up (as it did across virtually all
products).
This increasing financialization of oil has reached a new level with the appearance of OilCoin,
slated to launch early in the new year. Like Bitcoin and all the other new kids on the blockchain,
OilCoin owes much to the erosion of faith in fiat currencies and institutions by 2008's financial
crisis and the subsequent years of zero rates, quantitative easing and the rest of it.

Those same policies, of course, pushed more investor dollars toward riskier stuff like high-yield
energy debt and passive oil-linked ETFs, helping to fuel the shale boom.
OilCoin's claim to fame is that, unlike other cryptocurrencies, it is backed by physical barrels of oil.
Exactly how that will work isn't clear yet, because it seems to involve a mixture of oil futures,
barrels in storage and reserves in the ground -- all of which are priced (or modeled in the case of
reserves) at sometimes radically different levels.
As a selling point, though, that physical backing could lure both the crypto-curious uncomfortable
with Bitcoin's metaphysical nature, as well as the ETF crowd.
Whether or not OilCoin becomes an actual means of exchange, it represents a further step away
from the "fundamentals" Hall prized in his letter; especially as, if OilCoin gained enough scale,
it could potentially move oil prices as money flows forced rebalancing of the coin's physical
backing.
There's even a shale-linked aspect here, too, as OilCoin's touted stability rests implicitly on an
expectation that drops and rallies in oil prices will be moderated by North American producers
adjusting output relatively quickly in response.
On the same day Hall's letter went out, Royal Dutch Shell Plc's CEO Ben Van Beurden was
creating a stir of his own by talking about "lower-forever" oil prices. Similar to Hall, Ven Beurden
wasn't saying oil prices would never rise again, just that Shell couldn't bank on that to support its
business model (the original sin of both the industry in general and OPEC).
His other implicit message, chiming with Hall's explicit one, concerned long-term oil prices and just
how difficult it is to form a view on what they are because of shale, hedging, speculative
flows, electric cars, geopolitics and all the other things that have crowded into the marketplace.
OPEC (along with some new frenemies) has spent much of 2017 trying to impose its own brand of
order on things -- albeit in a way that, by supporting prices, simultaneously undermines its long-
term control. How the organization's efforts fare from here, having already been extended far
beyond the original schedule, will be the central drama of the oil market in 2018.
This column does not necessarily reflect the opinion of Bloomberg LP and its owners.

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
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 December 2018 K. Al Awadi

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