New base 1037 special 01 june 2017 energy news ilovepdf-compressed

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 June 01 - 2017 - Issue No. 1037 Senior Editor Eng. Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
Duro Felguera to boost Jebel Ali power output
The National - LeAnne Graves
Dubai will add another 600 megawatts of power from natural gas to its Jebel Ali plant in two years, costing about
Dh800 million, The Dubai Electricity and Water Authority (Dewa) awarded a contract worth Dh798m to Duro
Felguera to help meet rising electricity demand in the emirate.
The Spanish company will install two gas turbines from Siemens for the third phase of the K-Station expansion,
which is expected to generate power to the grid by the second quarter of 2019.
"This is part of Dewa’s ongoing plan to provide a long-term, sustainable, continuous and reliable supply of
electricity and water," said Saeed Al Tayer, Dewa managing director and chief executive.
The utility added more installed capacity last year to meet demand from a 6 per cent rise in customers
compared to the previous year. Gas makes up the majority of the emirate’s power generation at 74 per cent, but
under Dubai’s clean energy strategy, gas power will decline to make up 61 per cent by 2030.
Other sources of power generation will include 25 per cent solar energy as well as a mix of clean energy to
make up 75 per cent of Dubai’s total power generation. It will be Duro Felguera’s first foray into the region.
With over 22,000MW of installed power under its belt, the Spanish company said that winning this contract
consolidated its geographical diversification strategy. Once complete, the K-Station’s total production capacity
will be 1,538MW – bringing Dewa’s total installed capacity to just under 12,000MW.

Oman:Eni’s entry bodes well for Oman’s offshore exploration ambitions
Oman Observer - Conrad Prabhu
Italian energy supermajor Eni’s maiden foray into Oman’s upstream oil and gas industry augurs well for the
Sultanate’s ambitions to unlock the promising hydrocarbon potential of its largely unexplored offshore sector,
say experts.
Rome-headquartered Eni is globally recognised as a heavyweight in the offshore exploration and production
sector with operations in dozens of countries internationally. Its well-established prowess in exploring for liquid
hydrocarbons and natural gas in shallow to semi-deep offshore basins — expertise that it has successfully
leveraged in Africa, Europe and other regions of the world — will likely be a game-changer for the Sultanate’s
efforts to harness potential resources lurking in its vast, untapped offshore space.
Block 52, awarded last week jointly to Eni and Oman Oil Company Exploration & Production (OOCEP) — a
wholly owned subsidiary of Oman Oil Company — holds particular promise. Located offshore of the Sultanate’s
southeastern and southern seaboard, the block is the largest of Oman’s oil and gas concessions covering a
massive 90,790 sq km area. It was one of four hydrocarbon blocks offered by the Ministry of Oil & Gas as part of
the 2016 Oman Licensing Bid Round.
Although there have been no discoveries made to date within this concession, gas shows were encountered in
the Lower Tertiary and Aruma sections in the Sawqarah Bay South-1, according to the Ministry. Sawqarah Bay
South-1, thus far the only well in the Block, was drilled by Petroleum Development Oman (PDO) in 1991.
Potential reservoir units within the block include: Hadhramaut Group sandstones, Aruma Group sandstones,
Natih Formation (carbonates and fractured carbonates), Shuaiba Formation (carbonates and fractured
carbonates), and Tuwaiq Mountain Formation limestones.
“The presence of potential Haima and Huqf supergroup reservoir intervals is dependent on the depth to
basement and the structural configuration of the basement. Deposits from these supergroups are not expected
on basement horst blocks. Likewise, preservation of Haima and Huqf deposits possibly only occurs in the
structurally deeper mini-basins between horst blocks,” a backgrounder on the Block explained.
The Eni-OOCEP partnership joins a limited line-up of companies that previously owned Block 52. The list
includes Sun Oil Company, Amoco, Petroleum Development Oman and more recently, Circle Oil Ltd.
Adding to the Block’s investment appeal, when it was offered as part of the 2016 Bid Round, were a number of
factors. Firstly, the area comprising the southern portion of the block was only offered recently, according to the
Ministry. Besides, the northern portion of block underwent “many shape iterations” which placed it into long-term
concession areas. Furthermore, potentially attractive deeper water areas were also only recently added to the
block’s area.

Saudi Aramco signs deal with foreign, local firms to build huge shipyard
Reuters News
Saudi Aramco said on Wednesday it had signed a joint venture agreement with three firms to build a shipyard
on the kingdom's east coast, part of the government's drive to diversify the economy beyond oil.
A shareholder agreement was signed with National Shipping Co of Saudi Arabia (Bahri), a state-controlled firm
which ships oil for Aramco, as well as London-listed Lamprell Plc , a United Arab Emirates-based engineering
firm, and South Korea's Hyundai Heavy Industries Co.
Aramco, which announced a memorandum of understanding for the project with the three partners in January
2016, gave no financial details of the venture. It has previously said the project, at Ras Al Khair, will cost over 20
billion riyals ($5.3 billion).
Major production at the yard is expected to start in 2019 with the facility reaching full capacity by 2022. It will be
able to work on four offshore rigs and over 40 vessels including three very large crude carriers annually, Aramco
said.
Pressured by low oil prices, Saudi Arabia is eager to create manufacturing jobs and produce domestically goods
and services which have traditionally been imported.
U.S. oilfield services and equipment provider McDermott International has said it will build a fabrication yard at
the Ras Al Khair complex and move some of its operations gradually from Dubai to Ras Al Khair by the mid-
2020s.

US Administration Aims to Open More Arctic Areas for Oil
Bloomberg - Jennifer A Dlouhy
U.S. Interior Secretary Ryan Zinke issued a directive aimed at spurring oil and natural gas
development in Alaska, including a move to assess just how much crude might be lurking under
the Arctic National Wildlife Refuge.
Zinke’s order, signed during a visit to Anchorage, also compels a rewrite of a 2013 plan that
limited oil and natural gas development in the National Petroleum Reserve in Alaska. The move
responds to complaints from oil companies and state officials that the Obama administration was
too restrictive, blocking drilling in promising areas while hampering their ability to build pipelines
across the 23-million-acre reserve.
"This is land that was set up with the sole intention of oil and gas production; however, years of
politics over policy put roughly half of the NPR-A off-limits," Zinke said in a statement announcing
the move. "Using this land for its original intent will create good-paying jobs and revenue."
Unlike the petroleum reserve, which was specifically designated for energy development,
Congress established the Arctic National Wildlife Refuge in 1980 to protect the 19-million-acre
territory along Alaska’s northeast frontier. But ANWR’s estimated 12 billion barrels of crude has
drawn interest from energy companies and their political allies, including Senator Lisa Murkowski,
an Alaska Republican.
President Donald Trump already has proposed raising $1.8 billion over the next decade by
opening up parts of that refuge for oil and gas development, which would require a change in the
law by Congress.
And that idea is anathema to environmentalists, who have successfully blocked ANWR drilling
plans from advancing on Capitol Hill for decades by raising concerns about threats to the polar
bears, caribou and other animals that live and travel through the territory.
The NPR-A was established roughly a century ago as a potential oil resource for the U.S. Navy.
The U.S. Geological Survey estimates the reserve contains about 895 million barrels of

economically recoverable oil. But development has been slow, in part because of logistical and
legal hurdles to launching activity even on leased acreage in the refuge.
Zinke’s order compels Interior Department officials to deliver a blueprint for reworking a plan
governing activity in the reserve that strikes an "appropriate" balance of promoting development
while protecting other resources.
Moves to relax rules governing development in the NPR-A could benefit ConocoPhillips, whose
Colville-Delta 5 field marked the reserve’s first oil production in 2015. The company added more
NPR-A acreage to its portfolio during a lease sale last December and is developing other projects
there.
‘Sensitive Area’
"We understand it’s a sensitive area up there," Zinke said during a news conference in
Anchorage, noting that native Alaskans depend on the land for their subsistence way of life.
Alaska Governor Bill Walker called the announcement the start of a "new chapter" for the state,
coming amid concerns about declining oil flows through the Trans-Alaska Pipeline System.
"The timing couldn’t be better," Walker said.
Environmental advocates
argued President Barack
Obama’s administration rightly
walled off development in 11.8
million acres of the reserve
home to caribou herds and polar
bears -- and those protections
shouldn’t be undone now.
"It’s hard to see how they could
open up more land to
development without putting at
risk some pretty sensitive
areas," said Kate Kelly, public lands director at the Center for American Progress. "Zinke might
give lip service to balance, but this announcement shows the scales are tipped pretty far in
industry’s favor."
Assessment Updates
Zinke’s directive also compels a plan for updating assessments of how much undiscovered,
technically recoverable oil and gas is located on Alaska’s North Slope, focusing closely on the
potential in NPR-A and the Arctic National Wildlife Refuge.
The Interior Department, under Obama, rejected a bid to allow seismic testing aimed at
documenting potential oil and gas resources under the Arctic refuge’s coastal plain.
But now, Zinke says he is "giving the green light" for both industry and the federal government to
look for resources in the refuge. Conservationists said Zinke’s move was unnecessary and could
jeopardize wildlife and wild places in Alaska.
Alaska is already open for drilling "with abundant leasing and opportunities for more on state and
federal lands," said Nada Culver, a senior counsel with The Wilderness Society. "We don’t need to
risk native communities and the wildlife on which they depend -- and we need to recognize that
some places are too important and fragile to risk at all."

Russia-OPEC Deal Extension Hastens Decline of Oil Heartlands
Stephen Bierman and Andrey Biryukov
Russia’s deal with OPEC has bolstered state coffers by putting a floor under crude prices, but it’s
also had one unintended consequence: depressing output in the nation’s West Siberian oil
heartlands.
With the Kremlin offering lower tax rates for new projects in the Caspian and East Siberia, Rosneft
PJSC, Lukoil PJSC and other producers have looked elsewhere for the cuts that will allow Russia
to comply with 300,000 barrels-a-day of production curbs. That means the Soviet-era fields of
West Siberia.
“West Siberian output is the first to go under knife,” said Alexander Kornilov, an oil analyst at Aton.
“These are the least profitable barrels.”
Since Russia joined forces with the Organization of Petroleum Exporting Countries, futures have
rebounded from last year’s lows and the exporters have been able to earn more while pumping
less. The nation, which relies on energy for more than 40 percent of its budget, saw revenue from
oil and natural gas taxes recover to two-year highs in February and March thanks to the pact.
While Russia was one of the earliest oil producers, with output initially centered on Baku on what
is now Azerbaijan, the industry only regained global prominence in the 1960s and 1970s with the
exploitation of reserves in the Volga-Urals region and the the discovery of some of the world’s
highest-producing fields along the Ob River in Western Siberia. Those discoveries include the
Langepas, Uray and Kogalym units whose initials gave Lukoil its name, and Rosneft’s giant 25
billion-barrel Samotlor field.

After pledging in December to reduce production by 300,000 barrels a day from a post-Soviet
record of 11.247 million in October, Russia agreed with OPEC last Thursday to extend the
landmark deal. Output in the country’s oil heartland is falling fastest, with first-quarter production at
Rosneft’s largest Yugansk unit dropping 4.2 percent from the preceding three months.
Total Russian production will remain little changed at 547 million tons this year, according to
Energy Minister Alexander Novak. The balance will come from Caspian, East and Northern
Siberian deposits, offsetting the declines in West Siberia.
Barrels with tax discounts will jump 74 percent this year to 43.1 million tons, or 866,000 barrels a
day, according to research by Bank of America Merrill Lynch analyst Karen Kostanian. That could
increase to 80.9 million tons by the end of 2020 as overall Russian output increases, he said.
While that production puts some pressure on the Kremlin’s budget, it pales beside lost revenues
of more than $10 billion should oil drop by $5 a barrel, according to Alexander Burgansky, an
analyst at Renaissance Capital.
Pricing Trade-Off
“With tax savings of up to 90 percent for new projects, the displacement of West Siberian barrels
can cost the Russian budget up to $25 a barrel, or $2.7 billion per annum,” said Burgansky. “This
seems a low price to pay for price stability.”
Russia maintains its oil-price outlook at $50 to $60 on average for this year, Novak said. Brent
crude traded at $51.17 a barrel as of 7:15 a.m. in London on Thursday.

The Russian Finance Ministry remains philosophical, seeing the shift away from West Siberia as a
natural process.
“This is standard practice when falling output at tapped fields are compensated by the
development of new fields,” Alexey Sazanov, director of tax and customs department at the
Finance Ministry said by email. “All these new fields will sooner or later become old and their tax
burden will shift to West Siberian levels.”
Higher Margins
In the meantime, Russian producers continue to shift investment to higher-margin barrels. Lukoil
is pushing ahead with investments in the Caspian, where its Filanovsky field is subject to a
combined extraction and export tax rate of 15 percent, assuming a crude price of $50. That
compares with a rate of 58.1 percent for standard Russian fields.
The government will use the beneficial environment created by the OPEC deal extension to
replenish its reserves, Finance Minister Anton Siluanov said in an email.
Over the longer term, budget revenues from oil are projected to drop 2 percent every six
years, said Former Finance Minister Alexey Kudrin, who still advises Russian President Vladimir
Putin. That would have been the case even before the deal with OPEC, which Kudrin stresses is a
short-term arrangement.
Ironically, the speed of the decline in West Siberia will be determined in part by another decades-
old oil heartland thousands of miles away -- the Permian basin in Texas, where shale producers
continue to ramp up output.
“Higher oil production elsewhere, such as the U.S., can lead to excess oil supplies and price
declines despite Russia-OPEC efforts,” said Burgansky. “In this case, the Russian budget will lose
twice.”

NewBase 01 June 2017 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil Rebounds as U.S. Industry Data Signal Stockpile Drop
Bloomberg + Reuters + NewBAse
Oil rebounded from the lowest close in more than two weeks after industry data showed U.S.
crude stockpiles extended declines, easing an inventory overhang.
Oil futures rose on Thursday from a three-week low touched the previous session, buoyed by
expectations the United States could pull out of a global climate accord and by a report that
showed U.S. crude stockpiles had fallen more than expected.
Trump said he would announce later on Thursday a decision on whether to keep the United
States in a global pact to fight climate change, as a source close to the matter said he was
preparing to pull out of the Paris agreement.
"If he actually withdraws the U.S from the climate accord, this would signal his intention to further
roll-back emission regulations that would favour the use and demand of fossil fuels, thus giving a
much needed boost to oil prices," said Jonathan Chan, investment analyst at Phillip Futures in
Singapore.
Brent crude futures for July were up 39 cents, or 0.8 percent, at $51.15 a barrel by 0552 GMT,
after trading higher earlier.
Futures advanced as much as 1.2 percent in New York after losing 3 percent the previous two
sessions. U.S. inventoriesfell by 8.67 million barrels last week, the American Petroleum Institute
was said to report. Government data Thursday is forecast to show a slide of 3 million barrels, the
eighth straight drop. Output from Libya, exempt from OPEC’s deal to reduce supply, rose to the
highest since October 2014 as production from its biggest field increased.
Oil price special
coverage

Oil slid below $50 a barrel last week after the agreement by the Organization of Petroleum
Exporting Countries and its allies to prolong supply cuts for nine months disappointed some
investors hoping for more. While U.S. stockpiles have edged lower, American production and
drilling continues to climb.
“We will continue to see crude inventories falling because of the seasonal impact and that will help
support the outlook for oil,” said Ric Spooner, an analyst at CMC Markets in Sydney. “With prices
under $50, U.S. production gains might be a bit constrained and that will help with market
balancing.”
West Texas Intermediate for July delivery advanced as much as 59 cents to $48.91 a barrel on
the New York Mercantile Exchange, and was at $48.76 at 1:09 p.m. in Hong Kong. Total volume
traded was about 3 percent below the 100-day average. The contract lost $1.34, or 2.7 percent, to
close at $48.32 on Wednesday, the lowest level since May 12. Prices fell 2.1 percent last month.
Brent for August settlement gained as much 55 cents, or 1.1 percent, to $51.31 a barrel on the
London-based ICE Futures Europe exchange. The July contract expired Wednesday after
dropping $1.53, or 3 percent, to $50.31. The global benchmark crude traded at a premium of
$2.20 to August WTI.
U.S. crude stockpiles have declined since hitting a record 535.5 million barrels at the end of
March, according to Energy Information Administration data. While inventories shrank, output has
climbed to the highest since August 2015.

Once Costly Deep-Sea Oil Turns Cheap, to OPEC's Dismay
Bloomberg - Serene Cheong ,Sharon Cho
Reports of deep-sea drilling’s demise in a world of sub-$100 oil may have been greatly
exaggerated, much to OPEC’s dismay.
Pumping crude from seabeds thousands of feet below water is turning cheaper as producers
streamline operations and prioritize drilling in core wells, according to Wood Mackenzie Ltd. That
means oil at $50 a barrel could sustain some of these projects by next year, down from an
average break-even price of about $62 in the first quarter and $75 in 2014, the energy
consultancy estimates.
The tumbling costs present another challenge for the Organization of Petroleum Exporting
Countries, which is currently curbing output to shrink a glut. In 2014, when the U.S. shale boom
sparked oil’s crash from above $100 a barrel, the group embarked on a different strategy of
pumping at will to defend market share and throttle high-cost projects. Ali Al-Naimi, the former
energy minister of OPEC member Saudi Arabia, said in February 2016 that such producers need
to either “lower costs, borrow cash or liquidate.”
“There is life in deep-water yet,” said Angus Rodger, director of upstream Asia-Pacific research at
Wood Mackenzie in Singapore. “When oil prices fell, many projects were deferred, but the ones
that were deferred first were deep-water because the overall break-evens were highest. Now in
2017, we’re seeing signs that the best ones are coming back.”
The falling costs make it more likely that investors will sanction pumping crude from such large
projects that are more complex and risky than drilling traditional fields on land. That may compete
with OPEC’s oil to meet future supply gaps that the group sees forming as demand increases and
output from existing wells naturally declines.
Saudi Arabia’s Al-Naimi left his post shortly after his speech targeting high-cost producers, and his
successor Khalid Al-Falih organized production cuts by OPEC and some other nations that are set

to run through March 2018. In a speech in Malaysia this month, Al-Falih bemoaned the lack of
investment in higher-cost projects and said he fears the lack of them could cause demand to spike
above supply in the future.
Warnings from OPEC of a looming shortage are “overstated and misleading,” Citigroup Inc. said in
a report earlier this month. The revolution in unconventional supplies like shale is “unstoppable”
unless prices fall below $40 a barrel, and deep-water output could grow by more than 1 million
barrels a day by 2022, according to the bank.
Royal Dutch Shell Plc in February sanctioned its Kaikias deep-water project in the U.S. Gulf of
Mexico, saying it would break even with prices below $40 a barrel. That followed BP Plc’s decision
in December to move forward with its Mad Dog Phase 2 project in the Gulf, with costs estimated
at $9 billion compared to $20 billion as originally planned.
Over the next three years, eight offshore projects may be approved with break-even prices below
$50, according to a Transocean Ltd. presentation at the Scotia Howard Weil Energy Conference
in New Orleans in March. Eni SpA could reach a final investment decision on a $10 billion Nigeria
deep-water project by October.
West Texas Intermediate, the U.S. marker, is trading near $50 a barrel in New York, compared
with its 2014 peak of more than $105. Brent crude, the benchmark for more than half the world’s
oil, is near $52 a barrel in London, down from more than $115 a barrel in mid-2014.
Shale Boom
As rising U.S. output and OPEC’s unbridled production exacerbated the biggest price crash in a
generation, Rodger estimates energy companies shelved projects that would have produced more
than 20 billion barrels of oil equivalent since 2014 until the start of 2016. About two-thirds of that
were deep-water, he said.
Meanwhile in America’s shale country, companies quickly reduced costs and improved
productivity, driving break-even costs in the best parts of fields from Texas to North Dakota into
the $30s. The cost reductions have helped the number of drilling rigs in the U.S. more than double
since last year.
That increased activity is causing costs to rise again, though, said Jonathan Garrett, an upstream
analyst at Wood Mackenzie. Prices for pressure-pumping equipment and sand, both of which are
necessary for the hydraulic fracturing that makes shale production possible, have increased by
more than 20 percent this year.
Renewed Momentum
While costs for shale production, known as tight oil, are edging higher now, expenses associated
with deep-water drilling is finally coming down, Rodger said. Rental rates for drilling rigs have
been cut in half since 2014, and companies are redesigning projects to be more cost efficient
instead of to maximize output.
Deep-water exploration will see “renewed momentum” over the rest of 2017 as large integrated oil
companies look to capitalize on lower service costs and strengthening fiscal positions, Fitch Group’s BMI
Research said in a May 3 note. In the U.S. Gulf of Mexico, a more cost-efficient design for deep-water
projects has reduced the break-even cost at many wells to below $40 a barrel, it said.
“The deep-water cost curve is much higher, but over time that deep-water cost curve is coming down and
over time that tight oil cost curve is going up a bit,” Wood Mackenzie’s Rodger said. “So there’s still some
clear water between the two but it’s now getting closer to each other.”

NewBase Special Coverage
News Agencies News Release 01 June 2017
This Is What the Demise of Oil Looks Like
By Jessica Shankleman and Hayley Warren
From giant companies like Exxon Mobil Corp. to OPEC members such as Saudi Arabia, oil
producers say their industry will enjoy decades of growth as they feed the energy needs of the
world’s expanding middle classes. But what if they’re wrong? There’s a host of reasons to think
they might be. Here’s what happens when you test their central assumptions.
The International Energy Agency sees oil demand rising more than 10 percent, to 103.5 million
barrels a day by 2040, while companies predict even faster growth.
Traditional Forecasters See Nothing But Growth
Global oil demand, millions of barrels per day
But forecasters don’t always anticipate seismic shifts in technology and policy that could slow
demand growth, or even eliminate it altogether in some parts of the economy. Even small changes
could add up. Advances in vehicle efficiency, a rise in electric cars, tighter emissions standards
and shifts to other fuel sources would result in oil demand much lower than the industry is banking
on.

“We cannot even begin to comprehend the transformation in the mobility arena that is coming at
us,” Jules Kortenhorst, chief executive officer of the Rocky Mountain Institute, based in Boulder,
Colorado, said in an interview. “It’s not a question if it will come, it’s only a question of what the
timing of the arrival will be.”
Technological Change
About 60 percent of oil is used in transportation, which is also where the biggest technological
changes are emerging.
All over the world, governments concerned about climate change or air pollution are pushing
tighter fuel-efficiency standards, or creating low-emission zones for cars and even ships. The
exposure of cheating on diesel-emissions test by Volkswagen AG, and similar accusations against
other automakers has added to the pressure on regulators to toughen standards.
The proliferation of big data analysis is set to dramatically curb fuel waste, according to the Rocky
Mountain Institute. Aircraft being produced today by companies like General Electric Co. can
already detect small changes in engine performance, meaning engineers can be sent out to fix
any issues and keep them operating at peak efficiency. Smarter navigation technologies allow
truck drivers to reduce the distances they travel, while improvements to aerodynamics will enable
vehicles to travel farther on less fuel.
These and many other technologies would reduce emissions, while also save money, especially in
a world where the International Energy Agency sees oil prices rising from about $50 a barrel now
to $80 at the end of the decade, and to above $100 by 2030.
All told, efficiency improvements could eliminate the need for about 11.6 million barrels a day of
supply, according to the IEA. That’s about six supertankers of oil every day. Here’s what the future
looks like with efficiency gains:
Squeezing More From Each Barrel

Probably the most noticeable shift in transport will be the electric car. This won’t just be about cars
with batteries, but part of the wider trend led by companies including Uber Technologies Inc. and
Lyft Inc. toward transportation as an on-demand service in driverless vehicles summoned from
your smartphone, according to RethinkX, a think tank based in San Fransisco.
A move away from the current norm of individual ownership of traditional petroleum-powered
vehicles toward the sharing of high-tech, possibly driverless cars would have far-reaching
economic and social consequences, particularly because they’re being pushed hardest in the
fastest-growing major economies. China’s latest auto industry plan sees all new vehicle growth
coming from electrics. India plans to sell only electric cars by the end of the next decade.
The Drive to Electric Cars
More than 20 million sales are predicted by 2030
“In a nutshell, the industry is going to evolve more in the next 10 years than in the last century,”
said Gilles Normand, head of electric vehicles for Renault SA, in an interview.
If electric cars attain a “cool factor” on a par with the iPhone, the global fleet could expand to 450
million by 2035, from about 1.2 million currently, according to BP Chief Economist Spencer Dale.
Adoption of electric vehicles on this scale could take away another 5.2 million barrels per day of oil
demand, according to the IEA.

So now the baseline looks like this:
A Very Different Outlook
Even as U.S. President Donald Trump wavers over his commitment to the 2015 Paris Accord on
climate change, envoys from Europe to China and the Middle East say the shift to a low-carbon
economy is now unstoppable.
The Future Is Clean
New clean energy investment in world’s biggest economies
Some major oil companies are reacting to this shift. Royal Dutch Shell Plc, Europe’s largest
energy company, is betting on zero-emission hydrogen cars and building liquefied natural gas
refuelling stations for trucks in the U.S. and ships in Europe.

Biofuels are also set to take share away from oil in some markets—such as airlines seeking to cut
carbon emissions, for which battery power isn’t currently suitable. The growth of bioplastics could
also eat away at demand from the petrochemicals industry, which McKinsey and Co. estimates
will drive 70 percent of growth in demand for oil through 2035.
Beverage makers like Coca-Cola already pay a few cents more for bottles made from plant-based
materials, which won’t add to the growing plastic soup in our oceans.
Widespread switching to alternatives including natural gas and biofuels could displace about 13.5
million barrels a day of oil demand by 2040, according to the IEA. That’s more than double the
gains from electric cars.
A Radically Different Future
All these things together, which is what the IEA says would be required to limit global warming to
within 2 degrees Celsius, would mean oil demand peaking around 2020 and declining by about 20
million barrels a day by 2040. That’s 36 million barrels a day lower than the average oil company
forecast for 2040—a gap larger than OPEC’s current production.
Some oil companies have acknowledged the potential for demand to peak sooner. Shell has said
oil could peak somewhere between five and 15 years, while Total thinks a surge in battery
powered vehicles will cause demand for oil to peak in the 2030s.

Dramatic Shifts
A demand shift on this scale would have dramatic consequences for oil producers, who are
among the world’s biggest companies today.
“If you take a large bite out of transportation fuels, then suddenly the economics of the whole
downstream oil and gas business look dramatically different,” said Kortenhorst.
There may be a lesson in the dismal fortunes of the U.S. coal industry. Demand for the fossil fuel
peaked there in 2007 and has gradually declined as power plants switched to natural gas. That
triggered a collapse in the value of some of the nation’s largest producers, including Peabody
Energy Corp., which is among about 50 coal companies that filed for bankruptcy in recent years.
Peabody Shares vs Coal Demand
Oil companies now tilting toward renewable energy, such as Norway’s Statoil ASA, are best
placed to survive peak demand, said Deutsche Bank AG. Exxon Mobil Corp.—due to its size and
“reluctance to change”—is the most vulnerable.
State-run giants of the type that dominate the Organization of Petroleum Exporting Countries are
even more at risk and could one day be left with billions of barrels of unwanted crude.

LNG sellers, Asian buyers spar as contract fight brews amid
supply glut … By Mark Tay | SINGAPORE
A spat brewing between Qatar, the world's No.1 producer of liquefied natural gas (LNG), and its
biggest customers in Japan underscores rising tensions between buyers and sellers of the super-
chilled fuel as a supply glut unbalances the market.
Importers of LNG having been pushing for greater benefits amid the surplus, signing new, cheaper
contracts that give them more flexible terms, while exporters try to preserve long-term supply
deals written in their favor during tighter markets.
Worried some buyers are becoming too bold in their push for an advantage, Qatar Petroleum
warned customers in Japan - by far the biggest LNG importer - not to press too hard in long-term
supply talks, because it could result in Japanese companies being squeezed out of Qatari gas
projects.
While suppliers have granted more flexible terms on some new contracts, many are worried
buyers could seek arbitration to renegotiate contracts locking them into decades-long take-or-pay
deals that don't factor in steep price falls, and which often bar importers from re-selling contracted
cargoes.
"Parties (who import LNG) have intimated their frustration with such clauses," said Nandakumar
Ponniya of law firm Baker & McKenzie.Wong & Leow, although adding that as yet there was no
surge of attempts to force contract changes through arbitration.
Arbitration is a form of legal resolution outside formal courts in which both sides of a contractual
dispute agree to be bound by the decision of a third party.
While Asia's top LNG buyers in Japan and South Korea - including JERA, a joint venture between
Tokyo Electric and Chubu Electric, and Korea Gas Corp - are not saying so publicly, several
sources familiar with the matter said there are high level internal talks over the possibility of
arbitration.

"Virtually all major Asian LNG buyers would like to seek arbitration. They just don't want to be the
first to do so, as this would likely create negative publicity," said one source who advises
companies on such cases, speaking on condition of anonymity due to the sensitivity of the matter.
"It is safe to say that arbitration is being considered by most big Asian buyers," one Japanese
utility source said. Asia takes in some 70 percent of global LNG supply. But unlike in piped natural
gas markets in North America and Europe, most of Asia's purchases are bound up in long-term
contracts, with fixed volumes, caps on price fluctuations and clauses restricting the destination to
a single port or buyer.
Should arbitration be successful, LNG buyers would likely be allowed to either re-sell excess but
contracted cargoes into the spot market, or be able to adjust supplies more flexibly, forcing
producers to sell more spot LNG.
PRECEDENT
A tide of new LNG, particularly from Australia and the United States, has pulled Asian spot prices
down more than 70 percent since 2014 to around $5.50 per million British thermal units. Like
Qatar, other LNG producers on the losing end of the price falls have warned buyers about
pursuing arbitration.
"For anybody to orchestrate an arbitration event would be so detrimental to their reputation in the
market, that it would be much more expensive to do than to just sit out the contract and sign a
better one (later)," said Maarten Wetselaar, director for gas and new energies at Royal Dutch
Shell, the world's biggest listed LNG company.
Still, there is precedent. Between 2008 and 2014, European utilities entered into dozens of
arbitration cases, most winning awards in their favor and freeing up natural gas volumes to be
bought and sold on spot trading hubs.
"It would be quite interesting to see whether and how the European script plays out in Asia," said
Sriram Chakravarthi, Singapore Academy of Law's Chief Legal Counsel. European sellers like
Norway's Statoil decided it was preferable to defend market share by offering more flexible
contracts or sell directly into the spot market.
Others, like Russia's Gazprom, were forced under arbitration to offer better terms. Now, arbitration
specialists are hoping for new business in Asia.

"We see Asian markets in a similar position as European gas markets at the beginning of the
2000s, and we believe that contractual disputes, including arbitration proceedings, will increase in
Asia," said Madjid Kubler, an arbitration expert based in Berlin, Germany.
Past European arbitration cases took place in Paris, London and Stockholm. Singapore, already
working to establish itself as Asia's trading and legal hub for the commodity sector, is lobbying
heavily to be the region's key LNG arbitration center.
"Besides being a hub for LNG ... Singapore is a regional base for many international legal firms
specializing in energy and commodities," said Lee Ark Boon, the chief executive of IE Singapore,
a government body promoting Singapore's trade.
The city-state's ambitions were boosted by commodity trader Trafigura [TRAFG.UL], which in
April launched a standard LNG master sales and purchase agreement (MSPA) that suggested
dispute resolutions be referred to and resolved by the Singapore International Arbitration Center.

NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
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 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
NewBase June 2017 K. Al Awadi

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Co-located with The Big 5 Dubai, The Big 5 Solar launches this November 26 - 29th 2017. 20% of The Big 5
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