New base 24 septemner 2017 energy news issue 1074 by khaled al awadi (1)

Copyright © 2015 NewBase www.hawkenergy.net Edited by Khaled Al Awadi – Energy Consultant All rights reserved. No part of this publication may be reproduced, redistributed,
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NewBase Energy News 24 September 2017 - Issue No. 1074 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 Fujairah next benchmark for refined Gulf oil Satndard, Platts
Gulf News - Andrew Staples, Chief Business Reporter
Dubai: Using Fujairah refined oil prices as a benchmark for the Gulf is likely to boost the prices
storage terminal owners can charge by 20 to 30 per cent, an industry insider estimates.
And for the past year S&P Global Platts has been collecting flat price assessments in the emirate
for diesel, jet fuel, gasoline and fuel oil. Its benchmarking service requires two years of data, said
Dave Ernsberger, global head of Energy Pricing at the commodities information provider.
The storage terminal insider, speaking at a breakout session at the Gulf Intelligence Energy
Markets Forum 2017 in Fujairah, conducted under the Chatham House Rule, which promises
speakers anonymity, said he based his estimates on prices at Singapore, compared to
From left: David Worrall, independent energy consultant; Rakesh Mehra, strategic adviser at
Gulf Petrochem; Dr Marat Terterov, principal coordinator at the Centre International Energy
Charter; Irina Heaver, partner at Fichte and Co; and Victor Gao, chairman of the China
Energy Security Institute, during a Gulf Intelligence Energy Markets Forum. Making Fujairah
a refined oil benchmark could boost prices storage terminal owners can charge by 20-30 per
cent.

”neighbouring storage facilities.There’s a natural reluctance to be the first to do anything. It’s the
hardest step to take, to be the first person to write that contract.” Dave Ernsberger, S&P Global Platts executive
Currently the Gulf’s refined products used the Singapore benchmark, with an offset to cover
shipment there, said Ernsberger, who gave Gulf News permission to attribute his comments at the
breakout session, in an interview afterwards.
But that didn’t account for the
trade the Gulf does with Africa
and other markets away from
Singapore, he said. Once the
required data was compiled in a
year’s time, a benchmark could
be established as soon as
participants agreed to make a
registered trade, Ernsberger
added. That could take some
time, as recording the data
might lead to unwanted
exposure, but once it happened
others would follow rapidly.
“There’s a natural reluctance to
be the first to do anything,” he
said. “It’s the hardest step to take, to be the first person to write that contract. That’s why we need
to show the [price] history, so there’s comfort.”
There was no reason why a Fujairah crude benchmark couldn’t be as prominent as Brent or WTI
Cushing, he said, but felt the emirate had a stronger case for a refined product benchmark — just
as important within the industry, but less likely to make headlines.
“In a year there will be enough data there to compare Fujairah prices with Singapore prices and
Rotterdam prices and make a decision as to whether they’d like to write the Fujairah price into
their short-term supply contract.”
While demand for oil storage is currently low, Fujairah is using 40-50 per cent of its capacity,
experts at the breakout session estimated — a figure higher than other nearby storage facilities,
such as Sharjah’s Al Hamriya, which it had achieved by starting to make itself more attractive to
traders.
Ernsberg said the three primary factors driving storage demand were blending and surplus
storage, both of which were affected by the economic climate, and by oil traders’ need for storage,
which was not. Demand from traders therefore acted to insulate traders from inclement economic
circumstances, he added.
“There are many more things Fujairah as an emirate, and that investor and storage providers can
do individually to support that trading environment,” he said. “It’s made great progress already —
blistering progress in just two years — but there’s still plenty of runway ahead.
“What you tend to feel as you go through these discussions is that there’s a lot of resistance to
change from folks who’ve invested in assets, in the environment, and it’s completely
understandable, resistance to change. “But the experience of almost every tank investor and
operator, almost everywhere in the world, including Fujairah, is that when you embrace disruptive
change you’re better off in the end.”

UAE: Abraaj inks deal to build wind power projects in India
Company partners with French utility ENGIE; plans projects in several key Indian states
Dubai-based Abraaj Group and ENGIE, a multinational utility company, announced on
Wednesday a partnership to build a wind platform in India. Together, Abraaj and France-based
ENGIE said they have identified a robust pipeline of wind power projects representing over 1 GW
in several key states.
A statement said the partnership will address a large and growing demand for clean energy from
the Indian Government as well as businesses in the country. The Indian renewable energy sector
continues to grow rapidly, underpinned by an increasing demand for power. Power consumption in
the country is expected to grow at 9 percent year-on-year until 2020.
The Indian government’s target of 60 GW of wind power capacity by 2022 will require a near
doubling of the current installed capacity of 32 GW over the next five years. Saad Zaman, partner
at The Abraaj Group, said: “The Indian renewables sector has seen strong growth in recent times
and we expect demand for power across the country will continue to increase.
"In line with our commitment to addressing the Sustainable Development Goals, our partnership
with ENGIE marks Abraaj’s second investment in the clean energy sector in India. "There is a real
opportunity to enhance renewable energy generation in India and we are delighted to be working
with ENGIE to deliver affordable and clean power to the country.”
Sébastien Arbola, CEO of ENGIE Middle East, South & Central Asia and Turkey, added: “Energy
demand is growing tremendously in India, and ENGIE is investing in green energy sources as part
of supporting the country with its sustainable development plans.”
In 2015, Abraaj partnered with the Aditya Birla Group to build a 1 GW scale solar energy platform
in India, and in 2017, acquired a majority stake in Jhimpir Power, a 50 MW wind power project in
the Jhimpir wind corridor in Southeast Pakistan.
The ENGIE Group is the largest independent electricity producer in the world with 112.7 GW of
installed capacity, of which 20% comes from renewables.

Kuwait GDP Seen Contracting 0.5% in 2017 After Oil Output Cut
By Bloomberg - Kyungjin Yoo
Economists now see Kuwait’s economy contracting by 0.5 percent this year after the gulf nation
reduced its crude oil production to 2.7 million barrels per day, in line with the agreed OPEC target.
Non-oil GDP will grow 3.2 percent in 2017, but growth including oil will only start to recover in
2018, according to the survey.
Key Takeaways
• The economy will contract 0.5% in 2017, expand 2.3% in 2018 and 2.9% in 2019, according to a survey conducted by Bloomberg
• Survey of 9 economists conducted from Sept. 17 to Sept. 20
• 2017 CPI forecast at +3.2% y/y versus prior survey +3.3%
• 2018 CPI forecast unchanged at +3.5% y/y versus prior survey
• See graph of GDP forecasts
Full Survey Results
2017 2018 2019
GDP YOY% -0.5% 2.3% 2.9%
Previous survey 0.7% 2.4% n/a
CPI YOY% 3.2% 3.5% 2.7%
Current Acct. % GDP 4.3% 5.5% 7.4%
Budget as a % GDP -7.3% -6.5% n/a
Previous survey -8.6% -4.2% n/a

Lebanon Passes Oil Tax Law Ahead of Energy-Rights Auction
Bloomberg
Lebanon’s parliament approved a law to tax revenue from oil operations, weeks before its first
sale of offshore energy exploration rights to interested companies like Total SA and Exxon Mobil
Corp.
Lawmakers approved the petroleum tax law in a vote on Tuesday, the state-run National News
Agency reported. Energy minister Cesar Abi Khalil called on qualified companies to take the new
tax law into consideration when bidding for the upcoming energy auction, the agency said.
The draft law called for a 20 percent income tax on petroleum operations, along with a stamp-duty
fee fixed at 5 million Lebanese pounds ($3,311), Wissam Zahabi, a member of the Lebanese
Petroleum Administration, said by phone. Authorities had extended the bidding deadline to Oct. 12
from Sept. 15 to give companies more time to understand the tax law and organize their bids,
Zahabi said earlier this month.
Lebanon is seeking to develop its energy assets after lagging behind Cyprus, Egypt and Israel in
exploring for oil and natural gas in the eastern Mediterranean. Exxon Mobil, Chevron Corp., Royal
Dutch Shell Plc and Eni SpA are among 46 companies that qualified in 2013 to bid to operate
blocks. Suncor Energy Inc., Rosneft PJSC and Qatar Petroleum are among others that qualified to
bid as non-operators, according to the energy ministry’s website.
Lebanon, which is struggling with power shortages and hosting more than a million refugees,
needs revenue to reduce its public debt. The energy auctions have been delayed due to internal
political disputes since 2013.

EU: Subsidy-Free Wind Farms Risk Ruining the Industry’s Reputation
Bloomberg - Jess Shankleman
Energy companies that stunned the world by offering to build wind farms with no subsidy may ruin
the industry’s reputation by never actually delivering on their promises.
That’s the warning of industry executives, who are cautious about the future of zero-subsidy
offshore wind farms planned in Germany this year. Developers led by Energie Baden-
Wuerttemberg AG and Dong Energy A/S are betting they can sell the electricity they produce from
the wind farms at a profit without any help from taxpayers.
“The offshore wind industry needs to be careful,” Irene Rummelhoff, executive vice president
at Statoil ASA’s New Energy Solutions unit, said at the Bloomberg New Energy Finance Summit in
London on Tuesday. “They’re taking on these options, and when you get to the delivery date, if
they’re not able to build the projects, it will ruin the reputation of the industry.”
The German government may not have been strict enough with penalties and pre-qualification
criteria in its auction to ensure developers actually deliver on their winning bids, said Thomas
Karst, senior vice president at MHI Vestas Offshore Wind AS.
“The regulatory power lies with the owners of the concessions and they may or may not get built,
so that model from the regulatory point of view doesn’t really work,” Karst said at the same
conference.
It’s not just in Germany where the costs of offshore wind power are falling. The U.K. and Netherlands have
both seen record low bids during the past year that surprised even industry insiders. Last week, developers
led by Dong won bids to develop wind farms in British waters for as little as 57.50 pounds ($77.61) a
megawatt-hour, well below the cost of the next nuclear reactors.
Winning bidders in both the Dutch and German auctions based business cases on giant wind turbines,
soaring as high as The Shard in London and generating as much as 15 megawatts of power each. Those
machines haven’t been built yet and aren’t due until the next decade.

Russia set to pipe more oil to China, stepping up race with Saudis
REUTERS/Sergei Karpukhin
Chinese oil refineries are gearing up to receive more Russian oil transported through an expanded
Siberian pipeline network from January, likely cementing Russia's position as China's largest oil
supplier in a close race with Saudi Arabia.
The planned ramp-up in pipeline supplies agreed in contracts signed in 2013 comes amid a
pledge by producers to cut output to tighten global markets and illustrates the nip-and-tuck contest
between the world's top oil exporters, Russia and Saudi Arabia, for dominance in the biggest
crude importer, China.
Russia's top oil producer Rosneft ROSN.MM said it is set to supply under government agreement
30 million tonnes of ESPO Blend crude to PetroChina 0857.HK in 2018, or 600,000 barrels per

day (bpd), an increase of 50 percent from this year, after completion of the second East Siberia
Pacific Ocean (ESPO) pipeline, which has a main spur to Chinese border town Mohe.
"Rosneft has enough resources to supply under all its existing contracts, including the planned
increase of supplies to China by 10 million tones next year," Rosneft said in a statement emailed
to Reuters on Thursday.
Top state oil firm PetroChina has designated three
refineries in northeast China as the main receivers of
Russian oil, with one of them undergoing an $880
million upgrade.
Liaoyang Petrochemical Corp, in Liaoning province,
already a regular processor of Russian oil, is
expected to double its refining capacity with the
upgrade to 400,000 bpd by the end of 2018, said two
refinery sources.
"Plants were told to be prepared for more Russian oil
next year ... Liaoyang will be the main participant as it's poorly located for seaborne shipments,"
said one of the refinery sources.
A PetroChina trading executive said seven plants in northeast China are already taking Russian
oil, but once upgrade works complete, plants in Liaoyang, Dalian and Jilin will be the main
processors. "It's about boosting efficiency by dedicating these three plants to Russian oil," said the
executive.
Rosneft's plan to proceed with the contracted supplies comes despite a pledge by producer club
the Organization of the Petroleum Exporting Countries (OPEC), of which Saudi Arabia is the de-
facto leader, and other suppliers including Russia to cut oil output by around 1.8 million bpd
between January this year and March 2018.
RACE BETWEEN RUSSIA & SAUDI
Rosneft's new flows of piped oil will come as Saudi Arabia aims to secure a stake early next year
in a Chinese refinery after years of negotiations and as Saudi Aramco IPO-ARMO.SE prepares for
its global IPO. urn:newsml:reuters.com:*:nL8N1L94F3 urn:newsml:reuters.com:*:nL4N1LV3ZS
Financed by Beijing's estimated $50 billion in loans to Moscow started last decade, Russia's
higher pipeline sales will lift its total crude sales to China to new highs after the country overtook
the Saudis for five months so far in 2017 as China's top supplier.
Chinese customs data showed Russia supplied an average of 1.18 million bpd in the first seven
months of 2017, versus Saudi Arabia's 1.05 million bpd.
Suresh Sivanandam, of consultancy Wood Mackenzie, said the fresh pipeline supplies would
offset part of China's domestic production declines from aging oilfields in its northeast, and allow
Russia to expand its market share in the world's largest oil importer at the expense of OPEC.

But Riyadh is not giving in easily, with the Saudi energy minister vowing last month to finalise a
deal with PetroChina early next year to invest in the Yunnan refinery in China's southwest that
started operations this past July. urn:newsml:reuters.com:*:nL8N1L94F3
That would help secure Aramco a share in crude supply starting in 2018 to the 260,000-bpd plant
that receives oil from a Myanmar port linked to Yunnan via a pipeline, said the PetroChina trading
executive.
"The Saudis have been promoting hard to sell more oil, by tying up supply deals with refinery
stakes," said the executive, who declined to be named as he was not authorized to speak to
media.
Saudi volumes will also receive a boost through a separate supply pact with state-run China
National Offshore Oil Corp that is starting up a new 200,000 bpd plant in south China.
Russia will secure the additional barrels for ESPO deliveries mostly by raising production at two
new East Siberian oilfields that Rosneft launched last year - Kuyumba and Messoyakha - while it
may also divert volumes from export routes to the west. urn:newsml:reuters.com:*:nR4N1F2026
Russia and China agreed on Wednesday that Rosneft will supply China National Petroleum Corp
(CNPC) CNPET.UL , parent of PetroChina, with 28.3 million tonnes of oil via the Skovorodino-
Mohe pipeline in 2018, while the remaining 1.7 million tones of ESPO Blend will be loaded via
Kozmino port.

NewBase 24 September 2017 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil rises nearly 1 percent as OPEC defers extension of output cuts
Reuters + Newbase
Oil prices ended nearly 1 percent higher on Friday, close to their highest levels in months, as
major producers meeting in Vienna said they may wait until January before deciding whether to
extend output curbs beyond the first quarter.
“I believe that January is the earliest date when we can actually, credibly speak about the state of
the market,” Russian Energy Minister Alexander Novak said after the Organization of the
Petroleum Exporting Countries and other major producers finished meeting.
Other ministers said a decision on extending cuts could be taken in November when OPEC holds
its next formal meeting. Jim Ritterbusch of Ritterbusch & Associates in Chicago said delaying a
decision allows producers “to leave some arrows in their quiver to throw something bullish at the
market at their November meeting” if necessary.
He said Brent futures got an additional boost in late trade when Nigeria’s oil minister said in
Vienna that his country, which OPEC had exempted from the output cuts, was actually pumping
less crude than its agreed cap.
Brent crude rose 43 cents, or 0.8 percent, to settle at $56.86, a penny shy of the session high
which was also the highest since March.
Oil price special
coverage

U.S. West Texas Intermediate (WTI) crude settled at $50.66 a barrel, up 11 cents or 0.2 percent,
within a few cents of its May peak.
For the week, Brent posted a gain of 2.2 percent, while WTI was up 1.5 percent.
Oil prices have gained more than 15 percent in three months, suggesting OPEC-led output cuts of
1.8 million barrels per day have reduced the global crude glut. Rising demand has also helped
balance the market.
Tony Headrick, energy market analyst at CHS Hedging LLC in Inver Grove Heights, Minnesota,
said “the market is moving toward balance.” He cited strong demand for distillates, especially
European gas oil. This, he said, “is supporting Brent and in turn is supporting U.S. products and
WTI as well.”

Rising U.S. output has somewhat offset OPEC-led production cuts. The U.S. government reported
that crude production rose to 9.51 million bpd last week, resuming output close to levels before
Hurricane Harvey hit the Gulf Coast in late August.
However, the number of U.S. oil rigs operating, an indicator of future production, fell for the third
straight week as a 14-month drilling recovery stalled as companies pared back on spending plans
when crude prices were softer.
The closely-watched Baker Hughes rig count was on track for a second month of losses in a row
and its biggest monthly decline since May 2016. Still, CHS Hedging’s Headrick said “the U.S. oil
producer has proven to be very resilient in the face of lower prices. Now that prices are higher, the
U.S. producer should continue to press production higher.”
During the session, the discount of WTI to Brent futures hit its widest since August, 2015 as U.S.
crude was pressured by hurricane damage to U.S. refineries. The spread “could stretch a bit
further” but U.S. refinery restarts and growing U.S. exports should eventually lift WTI prices and
narrow the spread, Ritterbusch said.

Oil Treads Water With OPEC's Silence on Supply-Cut Extension
Oil rose slightly after an OPEC gathering concluded with no decision on an extension or
deepening of supply cuts.
Futures toggled between small gains and losses in New York on Friday, ending the session 0.2
percent higher. As an OPEC committee meeting wrapped up, Russian Energy Minister Alexander
Novak said the cartel and allied producers can wait until at least January to consider prolonging
the output limits. Kuwait’s Oil Minister Issam Almarzooq said after the meeting that “the process is
working fine so far.”
“People feel like the market generally is rebalancing,” Michael Lynch, president of Strategic
Energy & Economic Research Inc. in Winchester, Massachusetts, said by telephone. “The news
out of OPEC is sort of bland, but these days, bland is good.”
Oil is on track for only its third monthly gain for 2017 as supply cuts by the Organization of
Petroleum Exporting Countries and partners such as Russia showed signs of whittling the
worldwide crude glut. Nigeria, which along with Libya is currently exempt from the supply-
reduction deal, reiterated that it would cap output once its production stabilizes around 1.8 million
barrels a day. The next key event will be a Nov. 30 meeting of OPEC ministers.
“It’s going to come down to the meeting,” Tariq Zahir, a New York-based commodity fund
manager at Tyche Capital Advisors LLC, said in a telephone interview. Traders will be more
interested in deeper production cuts than an extension of the existing constraints, he said.
West Texas Intermediate for November delivery rose 11 cents to settle at $50.66 a barrel on the
New York Mercantile Exchange. Total volume traded was about 40 percent below the 100-day
average. Prices posted a 1.5 percent weekly advance.

Brent for November settlement added 43 cents to end the session at $56.86 a barrel on the
London-based ICE Futures Europe exchange. The global benchmark crude traded at a premium
of $6.20 to WTI.
Brent futures for near-term delivery are trading at a marked premium to longer-term contracts, a
pattern known as backwardation that shows demand is exceeding supplies.
Oil inventories in developed economies have dropped by 170 million barrels since January and
backwardation in prices demonstrates stockpiles are shrinking and demand is rising, Kuwait’s
Almarzooq said before the meeting on Friday. There is no reason for deeper cuts, he told
reporters in Vienna. Meanwhile, OPEC’s Secretary General Mohammad Barkindo said it’s critical
for the group to maintain focus and fully implement agreed curbs.
“Overall, the market viewed the meeting as a non-event,” Phil Flynn, senior market analyst at
Price Futures Group Inc. in Chicago, said by telephone. “At the end of the day, even though they
raised hopes, there was nothing solid.”
OPEC and Russia Hold Steady on Cuts as Oil Market Improves
OPEC and Russia said they were about halfway toward clearing a global oil glut and urged fellow
producers to stay focused and finish the job, while stopping short of additional action to reassure a
jittery market.
The producers, who together pump more than half the world’s oil, have reasons to hold a steady
course. At a meeting in Vienna on Friday, ministers hailed the accelerating market recovery as
Brent crude, the international benchmark, climbed to a six-month high. Still, predictions of strong
growth in U.S. shale production next year mean there are still concerns that the scheduled expiry
of the agreement at the end of March could be premature.
“The process is working fine so far,” Kuwait’s Oil Minister Issam Almarzooq said after the
meeting. “We hope that we can consume the remaining overhang in this period“ so it’s not
possible to say whether the cuts will need to be extended until closer to expiry, he said.
Nine months into the agreement between the Organization of Petroleum Exporting Countries and
allies including Russia to cut production, there are both positive an negatives signs. Bloated
stockpiles of fuel have been “massively drained” and the group implemented more than 100
percent of its agreed cuts last month, said OPEC Secretary-General Mohammad Barkindo.
Even if that level of compliance continues, supply and demand would be finely balanced next year
and ending the accord could put the market back in surplus, data from the International Energy
Agency indicate.
Exit Strategy
Russian Energy Minister Alexander Novak acknowledged the need for flexibility, while also
making clear its commitment to the deal wasn’t open ended.
“Any agreement -- especially an agreement aimed at balancing the market, supply and demand --
has to end somewhere,” Novak said in a Bloomberg television interview after the meeting. “A
gradual, slow exit strategy” could begin between the second and fourth quarters of 2018 when
“demand can absorb additional supply,” he said.

Changing quality mix is affecting crude oil price differentials
and refining decisions U.S. Energy Information Administration, Short-Term Energy Outlook, September 2017
Growth in global liquid fuels supply since March 2017 has been driven by increases in the
production of historically higher-priced light crude oils.
This growth has more than offset recent declines in the production of medium and heavy crude
oils. As these production trends continue, price differences between certain crude oils are
narrowing, and refinery operation decisions are changing.
Two of the most important attributes when comparing the qualities of different crude oils are sulfur
content and density. EIA defines crude oil with less than 1% sulfur as sweet and crude oil with
greater than 1% sulfur as sour.
Density is measured in API gravity, an inverse of the petroleum liquid’s density relative to water.
API gravity ranges from heavy, or high, density (less than 25 degrees API) to light, or low, density
(greater than 35 degrees API).
Voluntary production cuts from some members of the Organization of the Petroleum Exporting
Countries (OPEC) since November 2016 have reduced the global supply of medium- and heavy-
quality crude oil. In addition, crude oil production outages in Canada and declines in production

from Mexico and Venezuela are further reducing the total amount of medium and heavy crude oil
available to refiners.
Source: U.S. Energy Information Administration
In contrast, global production of light crude oil has increased. Libya and Nigeria, which are not
participating in OPEC’s production cuts, have increased production of their light-sweet crude oil in
recent months. In addition, much of the increase in U.S. crude oil production has come from shale
formations in the Lower 48 states, which contain primarily light-density crude oil.

As the relative availability of light and heavy crude oils has changed, price spreads between light
and heavy crude oils have narrowed. Relatively light crude oils are typically priced higher than
heavier crude oils, because light crude oils require less refinery processing to produce high-value
products such as gasoline and diesel.
Lighter crude oils are also considered more valuable because not all refiners have the equipment
necessary to process heavier, denser crude oils.
On the U.S. Gulf Coast, the premium for Louisiana Light Sweet (LLS) crude oil over heavy Maya
crude oil from Mexico narrowed from $9 per barrel (b) in March to $5/b in August. In the Midwest,
the premium for light crude West Texas Intermediate (WTI) over heavy Western Canada Select
(WCS) also narrowed from $13/b in March to $10/b in August.
Differences in sulfur content also affect the price of crude oil and where it can be processed. Sour
crude oil requires more complex refinery processing to meet low-sulfur fuel specifications and to
avoid damage to refinery units.
Processing heavy-sour crude oil requires additional refinery units—including crackers, cokers, and
hydrotreaters—to yield light products. These additional units increase refinery complexity but also
allow the refiner more flexibility to select types of crude oils to purchase and run through their
refineries, potentially increasing profitability.
Refiners’ investment decisions often depend on the location of the refinery because of the cost of
transporting oil. Gulf Coast refineries in the United States are typically supplied with heavy
Mexican and South American crude oils. Gulf Coast refineries are more complex than East Coast
refineries, which are supplied with lighter, sweeter Atlantic Basin crude oils.
Because the price of crude oil and refinery complexity are major factors that affect profitability, a
wider price differential between heavy and medium crude oils and light crude oils benefits more
complex refineries. In 2017, the price differential between medium and heavy crude oil and light
crude oil has gotten smaller, reducing the competitive advantage of some more complex
refineries.

NewBase Special Coverage
News Agencies News Release 24 Sep. 2017
How Electric Cars Can Create the Biggest Disruption Since the iPhone
Bloomberg - Jess Shankleman
It’s been 10 years since Apple Inc. unleashed a surge of innovation that upended the mobile
phone industry. Electric cars, with a little help from ride-hailing and self-driving technology, could
be about to pull the same trick on Big Oil.
The rise of Tesla Inc. and its rivals could be turbo charged by complementary services from Uber
Technologies Inc. and Alphabet Inc.’s Waymo unit, just as the iPhone rode the app economy and
fast mobile internet to decimate mobile phone giants like Nokia Oyj.
The culmination of these technologies — autonomous electric cars available on demand — could
transform how people travel and confound predictions that battery-powered vehicles will have a
limited impact on oil demand in the coming decades.
“Electric cars on their own may not add up to much,” David Eyton, head of technology at London-
based oil giant BP Plc, said in an interview. “But when you add in car sharing, ride pooling, the
numbers can get significantly greater.”
Most forecasters see the shift away from oil in transport as an incremental process guided by slow
improvements in the cost and capacity of batteries and progressive tightening of emissions

standards. But big economic shifts are rarely that straightforward, said Tim Harford, the economist
behind a book and BBC radio series on historic innovations that disrupted the economy.
Systemic Change
“These things are a lot more complicated,” he said. Rather than electric motors gradually replacing
internal combustion engines within the existing model, there’s probably going to be “some degree
of systemic change.”
That’s what happened 10 years ago. The iPhone didn’t just offer people a new way to make
phone calls; it created an entirely new economy for multibillion-dollar companies like Angry Birds
maker Rovio Entertainment Oy or WhatsApp Inc. The fundamental nature of the mobile phone
business changed and incumbents like Nokia and BlackBerry Ltd. were replaced by Apple and
makers of Android handsets like Samsung Electronics Co. Ltd.
Today, as Elon Musk’s Tesla and established automakers like General Motors Co. are striving to
make their electric cars desirable consumer products, companies like Uber and Lyft Inc. are
turning transport into an on-demand service and Waymo is testing fully autonomous vehicles on
the streets of California and Arizona.
Combine all three, for example through an Alphabet investment in Lyft, and you have a new model
of transport as a service that would be a cheap compelling alternative to traditional car ownership,
according to RethinkX, a think tank that analyzes technology-driven disruption.
One key advantage of electric cars is the lack of mechanical complexity, which makes them more
suitable for the heavy use allowed by driverless technology, Francesco Starace, chief executive

officer of Enel SpA, Italy’s largest utility, said in an interview. “I don’t see driverless being pushed
into internal combustion engine” vehicles, he said.
After disassembling General Motors’s Chevrolet Bolt, UBS Group AG concluded it required
almost no maintenance, with the electric motor having just three moving parts compared with 133
in a four-cylinder internal combustion engine.
“Competitiveness very much depends on the utilization of the car,” Laszlo Varro, chief economist
at the International Energy Agency, said in an interview. The average Uber vehicle covers a third
more distance than the typical middle-class family car in Europe, amplifying the benefit of lower
running costs to the point that “the oil price at which it makes sense to switch to electric is $30 per
barrel lower,” he said.
Uber on Steroids
The total cost of ownership of electric and oil-fueled vehicles will reach parity in 2020 for shared-
mobility fleets, five years earlier than for individually-owned vehicles, according to Bloomberg New
Energy Finance.
Already in London, Uber plans for its UberX service to be hybrid or fully electric by the end of
2019. Its rival Lyft aims to provide at least 1 billion rides a year in autonomous electric vehicles by
2025, saying they can be used much more efficiently than gasoline-powered cars.
This combination would be “the Uber model on steroids,” Steven Martin, chief digital officer and
vice president of General Electric Co.’s Energy Connections unit, said in an interview. “Once you
have complete autonomous operation of a vehicle, then my desire to own one is going to go
down and I’ll be more willing to sign up to a subscription service.”

Autonomous Hurdles
The transition to fully autonomous fleets may not match the speed of the smartphone
revolution because of the many regulatory, legal, ethical and behavioral hurdles. Self-driving
technology should become available in the 2020s, but won’t be widely adopted until 2030, BNEF
says.
Even so, the shift to electric cars could displace about 8 million barrels a day of oil demand by
2040, more than the 7 million barrels a day Saudi Arabia exports today, the London-based
researcher says. That could have a significant impact on oil prices—a drop of 1.7 million barrels a
day in global consumption during the 2008-2009 financial crisis caused prices to slump from $146
a barrel to $36.
That doesn’t mean oil giants like BP or Exxon Mobil Corp. are heading for an inevitable Nokia-
style downfall. While transport fuels account for the majority of their sales, they also have huge
businesses turning crude into chemicals used for everything from plastics to fertilizer. They also
pump large volumes of natural gas and generate renewable energy, both of which could benefit
from increased electricity demand.
Even if electric vehicles do grow as rapidly as BNEF forecasts, the world currently consumes 95
million barrels a day and other sources of demand will keep growing, said Spencer Dale, BP’s
chief economist. The London-based energy giant expects battery-powered cars to reduce oil
demand by just 1 million barrels a day by 2035, while also acknowledging the potential for a much
larger impact if the industry has an iPhone moment.
The sheer breadth of the potential disruption makes it hard to predict what will happen. When Steve Jobs
unveiled the iPhone, few people anticipated that it meant trouble for makers of everything from cameras
to chewing gum. “The smartphone and its apps made new business models possible,” said Tony Seba, a
Stanford University economist and one of the founders of RethinkX. “The mix of sharing, electric and
driverless cars could disrupt everything from parking to insurance, oil demand and retail.”

Anadarko Gets It. Does OPEC?
By Liam Denning
Late on Wednesday, Anadarko Petroleum Corp., which closed at $44.81 a share, announced
plans to buy back up to $2.5 billion of its stock; which is interesting, because almost exactly a year
ago, it sold about $2 billion of new stock -- at $54.50 apiece.
This says a lot about Anadarko but also the whole E&P sector.
Anadarko's stock has lagged a largely beaten-down group of mini-majors this year.
The oil-price crash is partly responsible, but Anadarko inflicted one or two wounds on itself. In late
2015, it made an awkward attempt to buy rival Apache Corp. Then, a year ago, it bought $2 billion
worth of deepwater assets in the Gulf of Mexico from Freeport-McMoRan Inc., which necessitated
that sale of stock.
That deal wasn't terrible in itself. However, it reinforced a structural problem faced by Anadarko
and its mini-major peers, which are too diversified to gain the multiples awarded pure-play shale
developers, but not big or diversified enough to really count as a relative safe haven like Exxon
Mobil Corp.
A year on, Anadarko must be looking over its shoulder. Activism has started cropping up in the
sector, with EQT Corp.'s board the latest to get several not-so-friendly letters and helpful
suggestions. Meanwhile, Anadarko has also long been talked of as a potential takeover target.
And right now, it isn't just trading at a significant discount to Exxon Mobil -- the discount actually
widens with time:
Further Markdowns
Anadarko's slide leaves it looking cheap (and getting cheaper) versus Exxon Mobil, long rumored
to be a potential buyer
In an attempt to get out of the doghouse, Anadarko has sold assets and now has $6 billion in the

bank. Using a big chunk of that to buy back roughly 10 percent of its own stock, therefore, looks
like an attempt to appease a listless, but potentially restless, investor base.
This summer has been a washout for the sector. Dan Pickering, head of TPH Asset Management
in Houston, points to its "dramatic" underperformance, adding "no big long-only guys are buying;
they're selling."
The reason is that, as happens from time to time, investors are tiring of the sector's traditional
growth mantra. One of the central criticisms leveled against E&P boards by activists is that
executive compensation rewards getting bigger rather than better.
Evercore ISI analyst Doug Terreson published a detailed, and timely, report on the subject back in
May (in which, incidentally, Anadarko scored relatively poorly). Only on Wednesday, Kevin Holt,
chief investment officer for U.S. value equities at Invesco Ltd., published a report along similar
lines with the ominous title "The Math on E&P Stocks Doesn’t Add Up." Looking at the sector
returns he refers to in there, you sort of have to agree:
Drilled Down
E&P companies' focus on growth has come at the expense of generating cash flow
Note: Cash flow return on investment. "E&P sector" refers to the average CFROI for a group of 10 large U.S. E&P companies.

It is notable that, while the sector had no problem selling new equity in 2015 and 2016 to help it
keep drilling through the downturn, this has slowed markedly:
Taking Stock
After several years of big equity sales, including a blowout 2016, the E&P sector's issuance has
slowed to a trickle
Note: Data for 2017 are year-to-date, as of Sep. 20.
So while Anadarko's decision to return cash reflects its own particular challenges, it also looks like
another sign of the industry responding to a wider shift in sentiment.
Net-net, this should be positive for investors -- and for oil prices. E&P firms forced to prioritize
returns over growth should take some dollars away from marginal wells, slowing the recovery in
U.S. production.
What's ironic is that this is happening because OPEC's strategy of cutting supply to raise oil prices
has, thus far, largely failed.
Oil was trading in the mid-$40s when Anadarko sold stock last September, and the price is only a
little higher now that the company is buying it back. Flat prices have numbed investors into a mix
of capitulation and frustration.
Yet it probably wouldn't take much to change that.
OPEC and chums meet again this week in an effort to push prices higher (not least because one
big member has an upcoming IPO to pitch). Anadarko's move suggests they should cancel the
meeting if they really want to re-establish some authority. They will likely come to regret it if, for
some reason, their efforts succeed.
Note that, even as Anadarko directs cash away from drilling or acquiring assets, it still targets
growth within cash flow at $50 a barrel next year. If prices were to rise to, say, $60 or more, it is a
fair bet that much of the pressure on E&P stocks would ease up and drilling budgets would
benefit.
The nature of the shale boom, with its sharp drop in costs and relatively quick drilling schedules, is
such that, within another year, a lot might be forgiven. As Pickering says: "Investors can change
their minds faster than companies." Hardly shocking news, that, but apt nonetheless.
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
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Khaled Malallah Al Awadi,
Energy Consultant
MS & BS Mechanical Engineering (HON), USA
Emarat member since 1990
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Mobile: +97150-4822502
khdmohd@hawkenergy.net
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Khaled Al Awadi is a UAE National with a total of 25 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

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