New base energy news issue 951 dated 20 november 2016

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NewBase Energy News 20 November 2016 - Issue No. 951 Edited & Produced by: Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
Kuwait:New 120 fuel stations in Kuwait to be offered for bidders
Arabian business
Move is part of Kuwait’s vision to secure 15 percent of its energy consumption from renewable
energy . The Kuwait National Petroleum Company (KNPC) will offer 120 new fuel stations for
bidders in the next seven years, according to Mina Abdullah Refinery deputy CEO Ahmad Saleh
Al-Jemaz.
Around 19 stations have already been offered while 15 others will soon follow, Al-Jemaz told state
news agency KUNA during the launch of the smart control system for the new Riqqa filling station
operated by solar power.
Al-Jamez said the smart control
system, which was applied in
collaboration with South Korean
firms, is the first of its kind of
Kuwait.
The Kuwait Petroleum Corporation
(KPC) has reportedly set $ (KD
1.5m) for solar power projects in its
affiliated companies such as
KNPC.
The projects are part of Kuwait’s
target to secure 15 percent of its
energy consumption from renewable
energy sources by 2030.

Canada sees Malaysin Petronas taking $27bn LNG decision by April
Gulf Times
Malaysia’s Petroliam Nasional will be ready to decide whether to proceed with a proposed $27bn
liquefied natural gas plant on Canada’s Pacific Coast by April, according to Rich Coleman, British
Columbia’s minister of natural gas development.
The state-owned Malaysian energy company, which won conditional Canadian government
approval in September after more than three years of regulatory review, is in the process of
reassessing the project’s costs, including those of steel, pipes and other inputs, he said.
“They need to go out and re-price the project,” Coleman said in an interview in Vancouver. “They
hope to have that done in three to six months. Once they’ve done that, they’ll go back to the
partners and decide whether to make a final investment decision.”
Canada relies on the US to buy almost all of its energy exports, forcing it to sell at a discount to
international benchmark prices. British Columbia is positioning itself as a gateway for Asian
exports with its vast reserves and is among North America’s closest ports to the region. Petronas
is reviewing the project and working to lower capital costs, it said in an e-mailed response to
questions.
“Before the project can proceed to a positive final investment decision, we need to ensure the
project is competitive with similar projects around the world,” the Malaysian explorer said.
Petronas is the majority owner of the Pacific Northwest LNG project, which could produce as
much as 19.2mn tonnes a year of the fuel, or about 8% of last year’s global trade. Its partners are
China Petrochemical Corp, Japan Petroleum Exploration Co, Indian Oil Corp and Brunei National
Petroleum Co.
A Japex spokesman, who declined to be named citing internal policy, said there is no change to
the company’s plans regarding the Pacific Northwest LNG project. An Indian Oil spokesman was
unable to comment immediately, while a Beijing-based spokesman for Sinopec said the company
has no comment on the matter. Petroleum Brunei could not be reached for comment.

Coleman, who met with Petronas executives last month in Kuala Lumpur, said those partners
remain on board as buyers. “There was no indication that any of the partners aren’t still in,” he
said. “They have a really strong focus on getting it to be financially viable.”
The September 27 approval from Canadian Prime Minister Justin Trudeau’s government came
with about 190 conditions, including a cap on carbon-gas emissions. None of those were “overly
surprising” to Petronas or its partners and are unlikely to be a major obstacle, Coleman said.
If Petronas moves ahead with the project, it would be the first new onshore greenfield project of
that scale since December 2013, according to Wood Mackenzie.
Market forces haven’t been working in the project’s favour. Since Petronas first submitted the
project for environmental approval in 2013, spot prices for the fuel have fallen by nearly 60% as a
host of new projects have boosted supply faster than demand has grown. Global supply capacity
is expected to grow by almost half through 2020, at which point it will exceed demand by 29%,
according to Bloomberg New Energy Finance.
Those forces have stymied more than 20 export proposals in the Canadian province. Of those,
just one small one has moved ahead – a C$1.6bn ($1.2bn) project backed by Indonesian
billionaire Sukanto Tanoto’s RGE Group that will have a total capacity of about 2.1mn metric tons
per year.
Canada’s LNG developers will probably band together and merge projects – like producers in
Papua New Guinea are trying to do – to reduce costs rather than building expensive, individual
export terminals, Bob Fryklund, IHS Markit’s chief upstream strategist, said last month.
“I do think, given some of the experiences globally, that they are having some of those
conversations,” Coleman said when asked about that possibility. Merging terminals wouldn’t
trigger a new environmental assessment, he said.
With only a few, high-quality projects likely to be sanctioned amid challenging market conditions,
British Columbia’s massive resources relative to domestic demand and shorter shipping times to
Asia compared with the US Gulf Coast work in its favour, according to KPMG.
“I remain optimistic that there will be more than one LNG project that will come forward,” Coleman
said. “They’re all saying they want to get there.”

Mozambique: Eni approves investment plan for Coral South
Source: Eni
Eni's Board of Directors has authorized the investment for the first phase of the development of
the Coral discovery (Coral South project), located in the deep waters of the Rovuma Basin (Area
4), offshore Mozambique.
The project involves the construction of
6 subsea wells connected to a floating
production facility FLNG (Floating
Liquefied Natural Gas), with a
liquefaction capacity of over 3.3 million
tons of liquefied natural gas (LNG) per
year, equivalent to approx. 5 billion
cubic meters. Mozambique authorities
approved the project development plan
in February.
This project highlights Eni’s
technological leadership in the
development of deepwater gas fields
via FLNG facilities.
The Coral field, discovered in May
2012 and outlined in 2013, is entirely
located within Area 4and contains
about 450 billion cubic meters (16
TCF) of gas in place.
In October, Eni and its Area 4 partners
signed an agreement with BP for the
sale of the entire volumes of LNG
produced by the FNLG Coral South,
for a period of over twenty years. This
was the first agreement ever signed in
Mozambique for the sale of LNG
produced in the country, and was the
first significant step towards the
development of the 2400 billion cubic
meters (85 TCF) of gas discovered in
Area 4.
The approval of this investment by
Eni’s Board of Directors is another
fundamental step towards the Final
Investment Decision on the project, which will turn effective once all Area 4 partners have
approved it and the project financing, which is currently being finalized, has been underwritten.
Eni is the operator of Area 4 with a 50% indirect interest owned through Eni East Africa (EEA),
which holds a 70% stake in Area 4. The other Concessionaires are Galp Energia,
KOGAS and Empresa Nacional de Hidrocarbonetos (ENH), each owning a 10%
stake. CNPC owns a 20% indirect interest in Area 4 through Eni East Africa.

Norway:OMV, Wisting Arctic discovery exceed one B.barrels
Source: Reuters
OMV's Wisting discovery in the Barents Sea, the northernmost oil find off Norway, could contain
more than one billion barrels of oil equivalents, it said on Thursday, potentially making it the
largest find in the Norwegian Arctic so far.
If the estimates are confirmed, this would further boost the attractiveness of the remote region
which, unlike other parts of the Arctic, is ice-free. However, exploration in the Arctic has faced
strong opposition from environmental groups.
OMV and its partners continue
to explore the area and aim to
decide on whether to develop
the discovery in 2019 or 2020,
OMV's Norway chief David Latin
told an energy conference,
adding he was increasingly
confident the project was
financially viable.
The company so far estimates
recoverable resources of
between 200 million and 500
million barrels of oil equivalents,
but this is still a preliminary
number.
'We are now very, very comfortable in that range and we're moving towards the upper end. We
can now say that the in-place volumes have increased very substantially and we are now well
over a billion barrels and we haven't drilled everything yet,' Latin said.
'So it's really big and I don't see why it shouldn't be developed. If we can't develop, as an industry,
a billion-barrel field, we should just all go home and go to bed,' he added. In-place resources are
used to quantify the total oil and gas in a reservoir, but as a rule not all of the original oil in place
can be produced technically or profitably.
Located in water depths of more than 400 metres, the field would probably rely on a floating
installation for production. Output could start in 2024 or 2025, Latin said, though he declined to
provide a cost estimate.
'We've drilled five wells and we've now put the drill
bit in most of that billion barrels and there are still
some areas around in the licence that haven't
been drilled So there is upside to the billion
barrels in-place,' he said. 'And then there is a
licence next door, which we are partners in, that
hasn't been drilled yet.'
Partners in the Wisting discovery are OMV,
Norway's Statoil, Japan's Idemitsu and Norwegian
state oil firm Petoro.

US: Amount of natural gas in storage reaches new record
Source: U.S. Energy Information Administration, Weekly Natural Gas Storage Report
Working natural gas in storage reached a record high of 4,017 billion cubic feet (Bcf) as of
November 4, according to EIA’s latest Weekly Natural Gas Storage Report. Inventories have been
relatively high throughout the year, surpassing previous five-year highs in 48 of the past 52 weeks.
Declining natural gas production and strong demand from the power sector were offset by a
warmer-than-usual winter, which left natural gas inventories in April (the beginning of the 2016
injection season) above the previous five-year maximum.
The injection season for natural gas storage typically runs from April through October, although
net natural gas injections sometimes continue for several weeks during November. In fact, the
previous record for natural gas storage was set at 4,009 Bcf for the week ending November 20,
2015. This year, natural gas inventories have been relatively high in almost every natural gas
storage region in EIA’s survey.
In the past month, the Midwest and Mountain regions exceeded and remained above the previous
five-year maximum inventory levels. In the two weeks between October 21 and November 4, the
South Central region added 59 Bcf to its inventories, but it still remains slightly below its one-year
maximum of 1,352 Bcf. Additionally, the East region remains 14 Bcf below its five-year maximum
capacity of 960 Bcf. With the other regions being near or at full capacity, any injections in the
coming weeks will likely occur in the South Central and East regions.

In the Pacific region, which includes Southern California, storage levels at the end of the injection
season were below the previous five-year average for that time of year. Despite a modest net
increase in natural gas working stocks in the Pacific region, continuing storage limitations at the
Aliso Canyon storage facility resulted in a decline in normal inventory levels at the end of October.
Aliso Canyon’s 86 Bcf storage capacity accounts for about 20% of the overall storage capacity in
the Pacific region. Overall, natural gas storage in the Pacific region is about 11% lower than the
previous five-year average of 368 Bcf, and the current storage limitations mean that the region
has reached its effective storage capacity.
Source: U.S. Energy Information Administration, Weekly Natural Gas Storage Report
Note: Regional maximums based on five-year maximums reported in Weekly Natural Gas Storage Report.
Domestic dry natural gas production during the first eight months of 2016 was about 1.3 Bcf/d
lower than last year’s average of 74 Bcf/d for the same time period. Meanwhile, natural gas
consumption has remained relatively flat in 2016, with increases in natural gas demand in the
power sector offset by decreases in the residential and commercial sectors.
Based on the National Oceanic and Atmospheric Administration's (NOAA) winter forecast, EIA
expects U.S. average household natural gas consumption to increase 8% this winter, with the
largest increases in the Northeast and Midwest census regions.
Under this scenario, EIA expects inventories to end the winter at slightly below 1,900 Bcf.
However, temperatures so far this winter have consistently been at or above weekly average
normal levels, and NOAA’s latest three-month temperature outlook forecasts that December–
February temperatures will be higher than normal. In a scenario with temperatures 10% warmer
than forecast, U.S. average household natural gas consumption would be 1% lower this winter
compared to last winter, with inventories at winter’s end near 2,300 Bcf.

NewBase 20 November 2016 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil Caps Weekly Gain After OPEC Holds Informal Talks With Russia
Bloomberg - Mark Shenk
Oil caped the first weekly gain since mid-October after OPEC member Algeria said the group’s
meeting with Russia gave it confidence a deal can be reached to re-balance global markets.
Futures rose 0.6 percent in New York. Algerian Energy Minister Noureddine Boutarfa said he’s
more optimistic of clinching an agreement after discussions between the Organization of
Petroleum Exporting Countries and Russia in Doha.
Russian Energy Minister Alexander Novak said a consensus is emerging and that his country is
considering an output freeze of six months. Prices fell earlier as the dollar rallied and U.S.
explorers added the most oil rigs in 16 months.
"The expectation is that OPEC will come up with something," said Bill O’Grady, chief market
strategist at Confluence Investment Management in St. Louis, which oversees $5.6 billion. "The
talk of a cut is what’s buoyed the market the last couple of months."
Oil price special
coverage

Oil has retreated since reaching a 2016 high
last month near $52 a barrel amid skepticism
about the ability of OPEC to implement the
deal agreed on Sept. 28 in Algiers. The group
is seeking to trim output for the first time in
eight years, a plan complicated by Iran’s
commitment to boost production and Iraq’s
request for an exemption to help fund its war
with Islamic militants. Neither country sent
ministers to the Doha talks.
West Texas Intermediate for December delivery rose 27 cents to close at $45.69 a barrel on the
New York Mercantile Exchange. Prices advanced 5.3 percent this week after falling the previous
three.
Brent for January settlement increased 37 cents, or 0.8 percent, to $46.86 a barrel on the London-
based ICE Futures Europe exchange. The global benchmark crude rose 4.7 percent this week.
Brent closed at a 50-cent premium to January WTI.
Dollar Rally
The dollar is poised for its best rally in more than 15 years against the yen and global bonds were
on course for their biggest two-week loss in at least 26 years. The Bloomberg Dollar Spot Index, a
gauge of the greenback against 10 major peers, rose to the highest level since February.
"The dollar has been part of the mix since the Trump election," said Mike Wittner, head of oil-
market research at Societe Generale SA in New York. "The market is sensitive to the latest OPEC
news, but there have been no signs of a breakthrough."
Rigs targeting crude in the U.S. rose by 19 to 471 this week, the highest level since January,
Baker Hughes Inc. said on its website Friday.
While Saudi Arabian Energy Minister Khalid Al-Falih told Al Arabiya television he’s optimistic a
deal will be reached on Nov. 30, only 7 of 20 analysts surveyed by Bloomberg this week expect
OPEC to set production targets for its members needed to make an agreement work.
OPEC agreed in Algiers to reduce collective output to 32.5 million to 33 million barrels a day and
has been trying to persuade other suppliers to join the cuts, notably Russia. Trimming supply to
the lower end of that range will help speed up the recovery of the market, Al-Falih said.
Oil-market news:
Drillers burned by a two-year slump in crude prices are slowing exploration of deep-water
prospects off the coast of Africa, undermining a key driver of supply growth on the continent.
Kuwait renewed a contract to supply Egypt with crude oil for the next three years, according to a
senior Kuwaiti government official.
Nigeria reached a $5.1 billion settlement to reimburse foreign oil companies including Exxon Mobil
Corp. and Royal Dutch Shell Plc for past operating costs.
Russian billionaire Mikhail Gutseriev’s initial public offering of as much as 20 percent of Russneft
PJSC may give the oil producer a valuation as high as 176 billion rubles ($2.7 billion).

OPEC-Russia Talks on Oil Cuts Leave Key Details Unresolved
Bloomberg - Mohammed Sergie
OPEC said it made progress toward a deal to cut production by more than 1 million barrels a day
after another round of oil talks with Russia, but left crucial details including the role of Iraq and Iran
to be resolved later this month.
While ministers from Saudi Arabia and Algeria reiterated their goal of reducing the group’s
production to 32.5 million barrels a day -- the most ambitious implementation of the Sept. 28
Algiers agreement -- they offered no clear details about how to resolve Iraq and Iran’s resistance
to making cuts. Neither did they secure a pledge from Russia to do more than cap production,
which is currently at record levels.
"The goal was to prepare for Vienna,” where the Organization of Petroleum Exporting Countries
holds talks on Nov. 30, Algerian Energy Minister Noureddine Boutarfa told reporters after talks in
Doha. “We won’t turn back on the decision made in September in Algeria. All the countries, 11
present in today’s meeting, agreed to support the Algiers accord."
Members of OPEC are “all hands on deck” to reach an agreement by the group’s Nov. 30
meeting, Secretary-General Mohammed Barkindo said in an interview in Marrakech, Morocco on
Nov. 15. While Libya, Nigeria and Iran have been granted special considerations within the Algiers
deal, Saudi Arabia is insisting that other members equitably share the burden of production cuts.
Iraq, which didn’t send a minister to Doha, has sought an exemption from any supply curbs.
Proposed Cut
"The meeting in my view was very positive, very constructive,” Russian Energy Minister Alexander
Novak told reporters in Doha after talks with OPEC representatives including Saudi Minister of
Energy and Industry Khalid Al-Falih. “Our position is very consistent, we are ready to join the
OPEC deal and ready to limit our oil production at a certain level."
Russia is considering a proposal from OPEC that it should cut its production, Novak said. The
country hasn’t changed its preference for a production freeze rather than cut, the ministry’s press
service said by phone. The nation pumped 11.2 million barrels a day last month, a post-Soviet
record, according to government data.
Algeria is more confident and optimistic of getting a result on Nov. 30, said Boutarfa. A committee
was proposed to monitor special considerations within the Algiers deal for three members -- Iran,
Nigeria and Libya -- that are still restoring output from previous disruptions, he said.

Iraq Compromise
Iran has insisted it won’t accept any limits on its production until it has returned to the pre-
sanctions level of about 4 million barrels a day. In Libya and Nigeria, output is recovering after
violence and militant attacks disrupted oil infrastructure. Iraq has also sought an exemption from
joining any production cuts, arguing that its fight against Islamic State justifies special treatment.
“We discussed how to agree on all the figures and information, and God willing the decision will be
positive in the end,” Boutarfa said. “Iraq should be part of the compromise, Iraq is part of OPEC.”
Iran is considering a proposal to freeze its oil production near the 3.9 million-barrel-a-day level the
country says it pumps, rather than OPEC’s estimate of about 3.7 million, an OPEC delegate said
this week, asking not to be identified because the information is private. Iraq is mulling a cut, but
only from the Oil Ministry’s own level of about 4.8 million barrels a day, not the 4.6 million barrels a
day OPEC says it pumps, the person said.
Saudi Minister Al-Falih declined to speak to reporters in Doha Friday. In an interview with Saudi-
owned Al Arabiya television broadcast Thursday, he said he’s optimistic the Algiers accord will be
implemented and will speed up the price recovery.
US:Oil Drillers Add Most Rigs in 16 Months Amid Market Optimism
Sony Kassam
Growing confidence that crude prices will rise in coming months is sustaining the expansion of oil
drilling in the shale patch.
Rigs targeting crude rose 19 to 471 this week, the biggest increase in the last 16 months,
according to Baker Hughes Inc. data reported Friday. Shale drillers have now added 155 rigs
since an expansion started at the end of May. Natural gas rigs rose by 1 to 116, bringing the total
for oil and gas up by 20 to 588.

Crude prices hovering near $45 should keep rig gains in check, according to Bloomberg
Intelligence analysts Andrew Cosgrove and William Foiles. Oil has fallen 13 percent since peaking
near $52 last month as the Organization of Petroleum Exporting Countries works with Russia to
hammer out an agreement on production cuts.
"If oil prices can’t regain strength and push toward $50 a barrel, a more muted rig trajectory lies
ahead, with gains limited to the Permian Basin," the analysts wrote in a Nov. 14 report.
Oil rigs in the Permian Basin of West Texas saw the biggest jump this week, up 11 to total 229,
reaching levels last seen in October 2015. D-J/Niobrara in Colorado added 2 rigs to total 18. North
Dakota’s Williston Basin dropped 1 rig to end at 34.
"The Permian is the place to drill based on return on investment," James Williams, president of
WTRG Economics in London, Arkansas, said by phone. "Most parts of the Permian could
probably hold up more than other basins with prices even lower than $40."
Dakota Access
Confidence in higher oil prices and the completion of the North Dakota Access Pipeline would
push the oil rig count up in other major shale plays, such as the Bakken, Williams said. The
Obama administration this week delayed a decision on the controversial crude pipeline, even as
President-elect Donald Trump vows to speed up reviews of such projects.
"Right now the Bakken ships oil by rail. If the pipeline is finished, that’s less expensive, and the
producers would get more for their oil," he said.
Algeria said OPEC’s informal meeting with Russia in Doha this week gave renewed confidence in
a deal to curb global oil supplies. Saudi Arabia’s minister of energy and industry told Al Arabiya
television Thursday he’s optimistic of an OPEC agreement and Russia’s Energy Minister
Alexander Novak said his country is considering a six-month production freeze. OPEC will meet in
Vienna on Nov. 30 to decide on individual country production quotas.
Crude stockpiles in the U.S. rose 5.27 million barrels to 490.3 million last week, the Energy
Information Administration reported Wednesday.

NewBase Special Coverage
News Agencies News Release 20 November 2016
Glencore seeks $550 million to raise stakes in Kurdish oil game
Reuters - Dmitry Zhdannikov | LONDON
Glencore is seeking to raise $550 million from investors via a debt issue guaranteed by oil from
Iraqi Kurdistan in an attempt to secure a big slice of the high-risk - and high-reward - market in a
region at war with Islamic State.
Kurdish oil has been targeted by European traders over the past two years, during an industry
downturn, since Erbil began selling oil independently from Baghdad. It has been relatively cheap
due to the potential for supply disruptions and threats from Iraq's central government to sue
anyone touching the crude.
The government of the autonomous Kurdish region in Erbil has borrowed around $2 billion from
Glencore's rivals such as Vitol, Petraco and Trafigura to be repaid in oil. The companies have all
borrowed money from banks and lent it to Erbil at their own risk.
Glencore, whose trading division has been in the spotlight over the past two years as
mining profits have declined, was the last merchant to enter the game earlier this year by lending
$300 million to Erbil. The loan is being repaid by way of one mid-sized oil cargo a month, worth
around $25 million.
A flame rises from a chimney at Taq Taq oil field in Arbil, in Iraq's Kurdistan region,

Now the company is seeking a much bigger role in the region, but wants to split the risks by
selling debt notes to be repaid with Kurdish oil income, according to a prospectus seen by
Reuters.
Technically, the money would be raised by a special-purpose vehicle, says the document which
has been sent to a small number of investors and hedge funds who specialize in high-risk, high-
yield investments and emerging markets. The debt is nonrecourse, meaning Glencore will not be
liable should problems occur.
It says Glencore expects to enter into a new 5-year agreement with the government of Kurdistan
to buy its crude, with deliveries rising from one cargo in January, to two in February-March, four in
April and six from May onwards.
Six cargoes a month would represent a quarter of overall exports from Kurdistan and would be
worth over $1.7 billion a year at today's price of around $40 per barrel for Kurdish oil, and more
than $8 billion over the course of five years.
Glencore declined to comment. The risks of investments linked to Kurdish crude is reflected in the
high returns offered in the debt issue.
Glencore's planned five-year note would carry an interest rate of 12 percent, according to the
prospectus. That contrasts sharply with its other borrowings - it is currently buying back bonds
carrying rates of 2.5 percent to 3.125 percent.
The company is also seeking a 36-month grace period before it starts repaying the debt in
monthly installments, another reason why investors might expect a high return.
"You can argue that in a way it is not Glencore but Kurdistan who is paying that interest rate as it
is the ultimate borrower," said one industry source close to the deal.
MILITANT ATTACKS
While Glencore and rivals have loaned money to Erbil, sources have previously told Reuters, they
have never publicly acknowledged such deals for fears of confronting the Iraqi central
government, which says the Kurds have failed to respect deals to transfer agreed volumes of oil to
Baghdad.
Baghdad has softened its tone on Erbil in recent months as they wage a joint battle against
Islamic State, but Iraqi state oil firm SOMO still occasionally threatens to sue buyers and sellers of
Kurdish crude.
Kurdistan exports its oil via the Turkish Mediterranean port of Ceyhan. Flows have been running
at over 600,000 barrels per day since September after being occasionally disrupted in 2015 and at
the start of this year due to militant attacks in Turkey and Kurdistan.
Glencore says in its prospectus that, at today's oil prices, the value of oil that it will receive under
its new 5-year contract with Kurdistan will be over six times bigger than the $550 million debt
issue.
But it also warns that disruption of deliveries "may lead to deferral of monthly interest payments
and principal". It adds, however, "that historical recovery track record for Glencore of these types
of oil-backed facilities is exceptional".
Glencore has been pre-financing oil exports from difficult places for decades since it was set up by
the godfather of oil trading Marc Rich in the 1970s.

How Big Oil Loses Even Without Peak Demand
By Liam Denning
The first thing to notice is that, in contrast to recent comments from the likes of Royal Dutch Shell
Plc's CFO, these numbers don't show a peak in oil demand anytime soon.
The second thing to notice, though, is that 11 million barrels a day extra spread over 25 years
equates to average annual growth of 440,000 barrels a year. That's roughly a third of the pace
over the past 25 years, when demand increased by roughly 1.1 million barrels a day, on average,
each year.
OIL DEMAND PER DAY IN 2040
103.5 Million Barrels (Maybe)
So this wouldn't be a scenario of peak demand, just very slow-growing demand. Now match it up
with the IEA's projections for where that oil would come from. In the chart below, the various
sources that aren't controlled by OPEC are split into their major types:

Where's It All Coming From?
The IEA's oil supply projections imply that OPEC's market share will rise to 50 percent by 2040
Note: OPEC supply implied from "New Policies" projected demand and non-OPEC supply.
'Others' refers to minimal supply from coal-to-liquids and gas-to-liquids technologies. Excludes
biofuels.
Big Oil's best prospects are conventional fields outside of OPEC, which aren't subject to any
quotas (such as they are), generally enjoy better fiscal terms, and can be booked easily as
reserves. Big Oil also figures prominently in Canada's sandpit. Everything else there -- OPEC,
'Tight oil' such as shale resources, and natural gas liquids -- are generally less lucrative or not an
area where the oil majors have displayed a sustained competitive advantage. Add up projected
conventional non-OPEC and oil sands supply and it looks like this:
Shrinking Horizons
The IEA projects supply from two of Big Oil's core operations -- conventional non-OPEC fields and
oil sands -- to drop by 6.1 million barrels a day by 2040

Note: "New Policies" scenario.
Remember also that a big part of that shrinking pool of oil is in Russia, another tricky jurisdiction.
Factor it out and the pool shrinks from 25.4 million barrels a day in 2015 to 20.5 million.
The need to offset natural decline in existing oilfields means that, even under this scenario, the
majors would have opportunities to invest. But in order not to be reduced to a residual source of
supply and to promise growth to underpin dividends, they would have to cut more deals with
OPEC hosts and demonstrate that, despite the record to date, they can out-compete their
independent E&P rivals in shale. They would also have to wring as much value as they can from
natural-gas liquids -- as well as, of course, natural gas itself.
Funnily enough, Shell, run by a CEO with a long history in liquefied natural gas and
petrochemicals, is positioning itself for that world (and maybe one where oil demand peaks
sooner). Exxon Mobil Corp. also has a big downstream and chemicals business and has bet big
on U.S. shale gas and, although stymied for now, Russia. Chevron Corp., meanwhile, has
invested heavily in LNG and talks up its shale oil assets.
These are all valid responses (although gas faces risks of its own from coal and renewable
energy). The wider point is that this particular possible world looks much harsher for the majors
than the past 25 years -- even with oil demand still projected to go up.

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khdmohd@hotmail.com
Khaled Al Awadi is a UAE National with a total of 26 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 November 2016 K. Al Awadi

New base energy news issue 951 dated 20 november 2016

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New base energy news issue 951 dated 20 november 2016