New base 986 special 12 january 2017 energy news

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NewBase 12 January 2017 - Issue No. 986 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 Energy Plan 2050 to cut CO2 by 70% and improve
Green Energy $163 Bn .. The National
Ambitious plans to boost clean energy and slash dependence on natural gas to generate power
are at the centre of the UAE’s new energy policy for the next three decades.
The UAE Energy Plan 2050 aims to cut carbon dioxide emissions by 70 per cent, increase clean
energy use by 50 per cent and improve energy efficiency by 40 per cent by the middle of the
century, resulting in savings worth Dh700 billion.
The policy’s targets for the source of energy for local consumption by 2050 have been set at 44
per cent from renewable energy, 38 per cent from gas, 12 per cent from clean fossil and 6 per
cent from nuclear energy. At the moment, more than 90 per cent of UAE’s energy needs are met
by natural gas.
"Ensuring the sustainability of energy resources means ensuring the sustainability of the country’s
growth," said Sheikh Mohammed bin Rashid, Vice President and Ruler of Dubai, announcing the
plan on Tuesday.
"The government has made an accomplishment in drafting the first unified energy strategy for the
UAE covering production and consumption. "Those who don’t think about energy aren’t thinking
about the future."
The integration of renewable, nuclear and clean fossil energy will be funded with investment of
Dh600bn over the next 33 years, equating to an annual spend of more than Dh17bn. Sheikh
Mohammed said the first national energy strategy would ensure a balance between economic
needs and environmental targets.

He said the plan would require the participation of all institutions and bodies in the energy sector,
and all executive councils.
Despite being one of the top oil producers and exporters, the UAE is also looking to nuclear power
to meet its increasing energy demands, with its first nuclear power plant, Barakah, completed this
year.
The four-reactor plant will produce 25 per cent of the UAE’s energy needs when it is fully
operational.
Sheikh Mohammed also called for a region-wide energy policy. "Gulf countries are similar in terms
of economic structure and we hope to have a unified GCC energy strategy to ensure the
sustainable development of our peoples and the global strength of our economies."
This will be supervised by the Ministry of Energy and the Ministry of Cabinet Affairs and the
Future. Dr Thani Al Zeyoudi, Minister of Climate Change and Environment, said the policy was a
great step towards the future for which the UAE strives.
"Our reliance on sustainable energy is a guaranteed step towards a better future for us and for
future generations," he said.
Sultan Al Jaber, Minister of State and chief executive of Adnoc, the Abu Dhabi National Oil
Company, said the new policy was an important step towards energy security, which was the
backbone of all economic and development activity.
"It specifies the energy mix components and includes both clean energy and gas, which is cleaner
hydrocarbon fuel, clean coal and peaceful nuclear energy," Dr Al Jaber said. Mohammed Atif, the
Middle East and Africa regional manager for energy consultancy DNV GL, said the policy was a
significant increase on the previously announced targets.
"There were expectations within
the industry that specifically,
renewable energy targets would
increase, but it is quite
impressive to see the ambitious
approach to energy efficiency as
well," he said.
"We are aware that a number of
reforms and implementation
plans are either under way or in
early stages of execution so we
look forward to a bright future."
This is the UAE’s first nationwide
energy strategy reaching 2050,
with previous national energy targets looking to generate 30 per cent of power from clean sources
by 2030.
However, Dubai set out its own plan two years ago to have clean energy sources make up 75 per
cent of the emirate’s energy by 2050.
According to the latest figures from the International Energy Agency in 2014, half of the world’s
energy supply came from oil and gas, close to 30 per cent from coal and nuclear at 5 per cent.
Renewables – including hydropower, geothermal, solar, wind and heat – accounted for just 3.8
per cent of the total supply.

Indian Oil Corp. Refiner Hunts for Oil Assets as Demand Surges
by Debjit Chakraborty
India’s biggest fuel retailer is seeking to buy oil assets as demand surges in the world’s fastest
growing energy market.
State-run Indian Oil Corp. wants to buy assets globally to ensure a tenth of its refining capacity is
fed by crude that is either from its own oil field or from assets where it has a stake, Chairman B.
Ashok said in an interview on Monday. That goal will require the company to boost oil production
10-fold to about 210,000 barrels a day in the next eight years.
“There is a lot of potential production from our existing blocks,” Ashok said in his office in New
Delhi, referring to the blocks it holds in Africa, Latin America and the U.S. “We are also looking at
economics and seeing where the assets are available.”
Indian Oil, the nation’s biggest company by sales, and other state companies are increasing
global acquisitions to secure energy supplies and meet demand that’s expected to double by
2040. The biggest oil sector downturn in a generation opened a window for the energy hungry
Indian companies to snap up assets as oilfield operators looked to sell assets or take partners to
share expenses.
Diversifying Geographies
“This is a good time for Indian companies to buy oil assets overseas,” said Abhishek Kumar,
senior energy analyst at InterfaxEnergy’s Global Gas Analytics in London. “There could be
potential interest in the Middle East and Africa, and opportunities in Latin American nations such
as Brazil and Mexico as they seek foreign partnerships to boost output.”
China had similarly stepped up overseas oil and gas investments after the 2008 oil price crash,
snapping up assets for $108 billion in the five years to 2013, according to data compiled by
Bloomberg.

India’s oil companies spent almost $6 billion buying stakes in Russian oil fields last year. Indian
Oil is diversifying its search to other geographies and is evaluating offers from global oil
companies that are looking to sell some of their assets to generate cash, Ashok said. He did not
give details.
“There are lot of opportunities possibly on offer in Africa, Middle-East and South East Asia,” he
said. “We are looking at these and if the prices are right, we will go for it.”
The company’s shares, which have risen 55 percent in the past year, added 0.4 percent to 347.9
rupees at 10:19 a.m. in Mumbai.
Refinery Expansion
Apart from oil production, the company also plans to increase refining capacity. It is building one
of country’s biggest refinery-cum-petrochemicals complex on the western coast along with two
other state-run oil companies. It will own 50 percent in the proposed project and is keen to bring in
a foreign partner, Ashok said.
Indian Oil plans to spend about 1.8 trillion rupees ($26.2 billion) through 2022 to expand it refining
capacity to over 100 million tons and build new pipeline and distribution infrastructure. The
company currently processes 80.7 million tons of crude a year from its nine plants and two owned
by its unit Chennai Petroleum Corp.
India’s oil demand is forecast to reach 10.3 million barrels per day by 2040, according to Paris-
based International Energy Agency. The country’s 23 refineries have a total capacity of about 230
million tons a year, while total fuel demand was 196.5 million tons during 2016, according to the oil
ministry.

Russia is no longer the world's largest gas producer and isn't
happy about it. by Eric Roston
Energy politics makes strange bedfellows, none stranger than Robin Hood and Russian President
Vladimir Putin.
RT, a media organization that the U.S. intelligence community calls "the Kremlin's principal
international propaganda outlet," published an article on Jan. 2 under the unlikely headline: “Robin
Hood’s Sherwood Forest hideout under threat from frackers.”
The article, which carries no byline and cites the work of environmental activists, laments plans
of a unit of Ineos Group, a Switzerland-based chemical company, to conduct seismic testing for
natural gas near Major Oak, the millennium-old tree that served in legend as headquarters to
Robin Hood and his merry fellows. (Ineos Shale and Friends of the Earth have been involved in a
public dispute over the environmental group's depiction of fracking, with the U.K.'s Advertising
Standards Board weighing in.)
This wasn't the only foray by RT, formerly known as Russia Today, into anti-fracking coverage.
The media organization has regularly published articles and aired segments that appear to
oppose fracking, the fossil-fuel extraction technique that has made the U.S. an energy superpower
again. One "exclusive" interview about the extraction technique features the
opening question: "There are a lot of studies that say fracking is dangerous, so why do you think
some countries and companies think it’s worth the risk?"
RT's practice is so marked that U.S.
intelligence officials used it last week as an
example of how Russia promotes its national
interests abroad. The Office of the Director
of National Intelligence (ODNI) states in the
public version of its report on Russian
interference in the U.S. presidential election
(PDF):
Image of RT television reproduced in the
Director of National Intelligence report,
"Background to 'Assessing Russian
Activities and Intentions in Recent US
Elections': The Analytic Process and
Cyber Incident Attribution."
SOURCE: Office of the Director of National Intelligence
“RT runs anti-fracking programming, highlighting environmental issues and the impacts on public
health. This is likely reflective of the Russian Government's concern about the impact of fracking
and US natural gas production on the global energy market and the potential challenges to
Gazprom's profitability (5 October).”
Russia is currently the world’s second-largest natural gas producer, after the U.S., and the third-
largest producer of petroleum and other hydrocarbons, after the U.S. and Saudi Arabia, according
to U.S. Energy Information Administration data. As weird as it sounds for Russia to throw in with
American and British environmental activists, it may be a case of the-enemy-of-my-enemy-is-my-
friend, at least from the Russian perspective. Interfering with fracking-driven U.S. fossil-fuel

production—one way or another—could boost global prices of oil and natural gas, which made up
about 63 percent of Russian exports, according to this helpful visualization from MIT's
Observatory of Economic Complexity.
"This is probably the most high-profile example that points to a direct attempt by Russia to
undermine the shale revolution in the United States," said Katie Brown, a spokesperson
for Energy-in-Depth, an education and research project run by the Independent Petroleum
Association of America. The group frequently provides counterpoint to environmentalists opposed
to fracking in the U.S.
"This raises a lot of questions regarding where funding for anti-fracking foundations comes from,"
Brown added. Public charities are not required to disclose all of their funding sources.
Russian opposition to fracking abroad may be significant not because it exists—which is
widely known among analysts—but because the Office of the Director of National
Intelligence thinks it's noteworthy within the context of alleged Russian election tinkering. "It's not
exactly news," said Joe Barnes, a research fellow at Rice University's Baker Institute for Public
Policy. "It's only news at this point because it appears in the [intelligence community
assessment]."
RT wrote about the release of the U.S. intelligence report and has continued to devote attention to
it.
Russia's economy is bolted to oil and gas the way the Statue of Liberty is bolted to its pedestal.
Energy prices driven low by U.S. production have caused economic and regional political

headaches for Russia, which has seen its leadership erased or eroded in both natural gas .. and
in the production of petroleum and other liquid hydrocarbons.
The relationship between the U.S. and Russia is anything but simple. Competition for fossil-fuel
market share is made even more complicated by an array of issues the countries do or don't
cooperate on—or, in some cases, even talk about. These include the multi-nation deal on Iranian
nuclear security (to which Putin was a party), the state of NATO, to Russia's harboring of Edward
Snowden. The U.S. maintains economic sanctions on Russia that range from Cold War-era
measures that support people's freedom to emigrate to penalties imposed after Putin's incursion
into Ukraine.
How President-elect Donald Trump, with his sunnier view of Russia and Putin, will navigate this
complexity is anybody's guess. "I literally can not make a prediction," Barnes said. "Literally. Can
you? Can anyone?"

USRenewable generation capacity expected to account for most
2016 capacity additions… US EIA Electric Generators Report
Once final data are in, EIA expects 24 gigawatts (GW) of new generating capacity to be added to
the power grid during 2016. For the third consecutive year, more than half of these additions are
renewable technologies, especially wind and solar.
Of the 2016 renewable additions, nearly 60% were scheduled to come online during the fourth
quarter. Renewable capacity additions are often highest in the final months of the year, in part,
because of timing qualifications for federal, state, or local tax incentives. Estimated fourth-quarter
capacity additions for 2016 are based on planned additions reported to EIA and are subject to
change based on actual project schedules.
Monthly U.S. renewable electricity generation peaked in March as high precipitation and melting
snowpack led to a monthly peak in hydroelectric generation and strong wind resources led to a
monthly peak in wind generation.
Most renewable generation comes from the Western census division, which accounted for the
majority of the hydroelectric (63%) and solar (77%) generation in the United States in 2016. Wind
generation was more evenly spread across the country with 37% occurring in the Midwest, 35% in
the South, 24% in the West, and the remaining 4% in the Northeast.

At the end of 2015, EIA began publishing monthly estimates for distributed small-scale solar
photovoltaic (PV) (one megawatt or less) capacity and generation. As of October 2016, the United
States had a total of 12.6 GW of small-scale solar PV installed. Of this capacity, 56% was in the
residential sector, 36% in the commercial sector, and 8% in the industrial sector. Monthly
generation from small-scale solar PV peaked in July at 2.1 billion kilowatthours (kWh).
The distinction between capacity and
generation shares is important to
recognize. Because non-dispatchable
technologies such as wind and solar
facilities generate power only to the
extent those respective resources are
available, their capacity factors are
typically lower than those of other
resources.

The production tax credit (PTC) for wind and the solar investment tax credit (ITC) were extended
at the end of 2015. The tax
credits include an eventual
decline in value for both
technologies with the PTC for
wind expiring in 2020 and the
ITC for large-scale solar
declining from 30% to a
permanent 10% and expiring for
residential projects in 2022.
New York, Oregon, and
the District of
Columbia extended and
expanded their mandates for
renewable electric generation to
reach 50% of each state’s total
electricity generation by 2030,
2032, and 2040, respectively.
Hydroelectric generation increased as drought conditions that affected hydroelectric generation on
the West Coast in 2014 and 2015 diminished.

NewBase 12 January 2017 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil steady after US storage data sends mixed signals
Reuters
Oil prices were steady early on Thursday after U.S. crude and refined product stocks sent mixed
messages to the market, with ongoing uncertainty over OPEC compliance with planned output
reductions also in focus.
U.S. West Texas Intermediate (WTI) crude oil futures were trading at $52.24 a barrel at 0040
GMT, virtually unchanged from their last settlement.
Prices for Brent crude futures, the international benchmark for oil prices, were yet to trade.Traders
said that a crude oil and refined product inventory report published by the U.S. Energy Information
Administration late on Wednesday had sent mixed messages to the market.
While an unexpectedly strong rise in crude inventories by 4.1 million barrels to 483.11 million
barrels implied an ongoing supply overhang, record U.S. refinery runs of 17.1 million barrels per
day (bpd), up 418,000 bpd on the week, indicated ongoing strong demand.
"EIA data showed U.S. refineries increased the amount of crude they processed, pushing the
utilisation rate to the highest since September. This saw inventories rise ... much more than the
market expected," ANZ bank said.
Outside the United States, emerging detail of Saudi supply cuts as parts of efforts by the
Organization of the Petroleum Exporting Countries (OPEC) and other producers like Russia to
curb the global supply glut started to emerge.
Oil price special
coverage

US crude inventories rise by 4.1 million barrels, EIA says
Reuters
Oil prices rose on Wednesday, following news of Saudi supply cuts to Asia, but persistent doubt
over output reductions and signs of rising shipments from other producers kept gains in check.
Brent crude futures were up 31 cents, or 0.58 percent, at $53.95 a barrel by 10:35 a.m. ET (1535
GMT), while U.S. West Texas Intermediate (WTI) crude oil futures were up 26 cents, or 0.51
percent, at $51.08 a barrel.
U.S. gasoline prices were also up 1.7 percent at $1.573, on pace for only their second positive
day this year.
On Wednesday, the U.S. Energy Information Administration said U.S. crude inventories increased
by 4.1 million barrels from the previous week. Total motor gasoline inventories increased by 5
million barrels last week, distillate fuel inventories increased by 8.4 million barrels last week, EIA
said.
Brent has surrendered nearly 40 percent of the gains made between late November and early
January. Analysts, however, said the slide was unlikely to become more aggressive, given the
likelihood of Saudi Arabia and its Gulf neighbors at least sticking to their pledge to cut output.
"Few envision that Brent crude at sub-$50 a barrel is a viable price (in H1, or the first half of 2017)
amid OPEC production cuts tightening up the market," SEB commodities strategist Bjarne
Schieldrop said.

"If last night's low of $53.58/barrel turns out to be the low point remains to be seen. However, we
do think that buying in the territory between the current price of $53.88/b and down to $50/b is
probably as good as it gets for buyers in H1."
Saudi Arabia, the world's top oil exporter, has told some of its Asian customers that it will reduce
their crude supplies slightly in February.
OPEC's second-biggest producer Iraq plans to raise crude exports from its southern port of Basra
to an all-time high of 3.641 million bpd in February, keeping shipments high even as OPEC
production cuts take effect this month.
But there is still plenty of oil to fill the gaps left by the Organization of the Petroleum Exporting
Countries. North American drilling is on the rise, while European and Chinese traders are shipping
a record 22 million barrels of crude from the North Sea and Azerbaijan to Asia this month.
There is still doubt among many market watchers over whether the planned cuts will be enough to
rebalance a market that has been oversupplied for the past two years.
"Traders continued to fret about rising U.S. supply and compliance by OPEC to agreed-upon
production cuts," ANZ bank said.
Oil and gas companies will increase spending in 2017 and more than double new project
developments as they gain confidence that a two-year oil price slump is behind them, consultancy
Wood Mackenzie said.
The U.S. Energy Information Administration (EIA) said on Tuesday that crude production in the
United States this year would rise by 110,000 barrels per day to 9 million bpd.
On Tuesday, industry group the American Petroleum Institute (API) reported a 1.5 million-barrel
build in U.S. crude stocks in the week to Jan. 6. Analysts had expected an increase of 1.2 million
barrels.

IHS Markit: Total’s block off Cyprus to compete with Eni’s Zohr
discovery?
Driven by the success of Eni’s major Zohr field gas discovery offshore Egypt in 2015, companies
are rethinking the Eastern Mediterranean region’s gas potential, according to a new analysis from
IHS Markit, an information and analytics group.
Total’s announcement that it will drill a 2017 exploration well in its deepwater Block 11 located
offshore Cyprus indicates the growing interest in the wider region, IHS Markit said on Wednesday.
“The Zohr gas discovery in Egypt was a play opener for the region—it has caused companies to
rethink the region’s gas potential and take a closer look at the geology,” said Graham Bliss Ph.D.,
senior director of plays and basins research at IHS Markit, and lead author of a series of analyses
examining upstream energy competition in the Eastern Mediterranean.
“Zohr’s success clearly encouraged Total leadership to re-examine Block 11’s potential, since it is
contiguous with the Egyptian Shorouk Offshore Block, which is home to Eni’s Zohr Field.”
‘One of the most critical wells’ in 2017

IHS Markit believes that Total’s exploration well will be one of the most critical wells drilled globally
in 2017 for the E&P industry, especially given the slowdown in exploration drilling worldwide. The
IHS Markit analysis, Bliss said, underscores the potential impact that this well and the changing
competitive landscape could have on the future development trajectory of the hydrocarbon sector
in the Eastern Mediterranean.
Total’s Offshore Cyprus Block 11 is located to the north of Zohr’s Egyptian Shorouk Offshore
Block, which, Bliss said, is the first time in the region that a carbonate, rather than a sand,
reservoir was targeted. “The carbonate reservoir that comprises Zohr is of particularly high
quality,” Bliss said. “As such, it will likely enable development using a minimum number of wells
and, therefore, reduce costs and enhance project economics.”
The Zohr Field is one of the largest conventional gas discoveries of recent years. It has in-place
resources of 32 trillion cubic feet (TCF) of dry gas, with possible recoverable resources of about
20 TCF, according to Eni’s statements. To date, Eni has drilled five wells on the Zohr structure,
which have confirmed a large gas accumulation and the existence of a very high-quality reservoir,
IHS Markit said. The Zohr Field Phase 1 project is due to come on-stream in 2017.
“The existence of a carbonate reef play, which Zohr has proven to be, is very different from the
turbidite sand-play discoveries in the Israeli Levantine Basin and the Egyptian Nile Delta Basin,”
Bliss said.

Potential for ‘significant’ discovery in Block 11
Bliss further added: “If the Zohr carbonate play extends northward into Total’s Block 11, then the
potential for a significant discovery in Block 11 exists, resulting in profound implications for the
region. A major find would provide competition with offshore Israel gas fields to fulfill Egypt’s rising
gas demand, and within the complex jigsaw puzzle of gas supply and demand in the Eastern
Mediterranean, could even potentially lead to gas exports to Turkey.”
IHS Markit research has also
concluded that direct pipeline exports
from the Eastern Mediterranean to
Greece are potentially commercially
viable.
Competitive landscape
The competitive landscape in the
region has already begun to change in
anticipation of the potential, the IHS
Markit report said. In November
2016, BP purchased a 10 percent
equity stake in the Shorouk Offshore
Block (including Zohr) from Eni, with
the option to acquire a further 5 percent stake.
This purchase consolidated BP’s strong position along the northern margin of the Nile Delta Basin,
but by itself did little to diversify the range of players in the Nile Delta offshore where BP, Eni and
Shell dominate, according to Catherine Gifford, Africa plays and basins research lead at IHS
Markit.
“The transaction does nothing by itself to vary the number and type of companies active in the
basin,” Gifford said. “The success of this basin, and its subsequent further contribution to Egypt’s
economy, largely depends on the continuing commitment of these few companies. There is little
open acreage that could be offered in future licensing rounds, subject to acreage
relinquishments, but of course there is the potential for farm-ins.”
Gifford said that a Total discovery in Block 11 would add Total to the list of leading players in the
region. Further, in December 2016, Rosneft (in which BP holds a 19.75 percent
interest) purchased a 30 percent interest in the Shorouk Offshore Block from Eni with the option to
acquire a further 5 percent stake.
The December 2016 announcement of results from Cyprus’s Third Offshore Licensing
Round confirmed the interest of established and new companies in the Eastern Mediterranean
region’s growing gas potential. Eni extended its key role in the region with its award of Offshore
Cyprus Block 6 (northwest of Block 11) with partner Total, as well as for Offshore Cyprus Block 8
(northeast of Block 11). ExxonMobil won the bid for Offshore Cyprus Block 10 (which Total had
previously relinquished).
The ranks of larger companies in the region have now swelled to include Total, ExxonMobil and
Rosneft, in addition to the established players—Eni, Shell and BP.
While gas is the primary target for the Total Cyprus Block 11, the IHS Markit analysis said there is
some potential for a deeper, but unproven, Cretaceous target, which could have oil potential.

NewBase Special Coverage
News Agencies News Release 12 Jan. 2017
Faster e-car chargers in minutes instead of hours
Oman Observer + Reuters
in Business
Europe’s biggest carmakers are drawing on the full force of the continent’s industrial prowess to
build a network of ultra-fast charging stations as they look to stoke demand for electric cars and
break Tesla’s stranglehold on the market.
BMW, Volkswagen, Ford and Daimler plan to build about 400 next-generation charging stations in
Europe that can reload an electric car in minutes instead of hours.
The long time it takes to
charge batteries is one of
the main disadvantages of
electric cars compared to
conventional cars with
gasoline tanks that can be
filled up in seconds.
Until now, drivers of electric
cars have had to leave their
vehicles plugged in for
hours at a charging station
for a journey between cities,
making many long range
journeys impractical.
Installing new, faster
chargers would spur the
overall market, and also
help the traditional car manufacturers close the gap with Tesla, the Silicon Valley-based e-car
leader, which maintains its own network of charging stations. Tesla’s chargers are the fastest in
the industry, and are incompatible with existing electric cars made by rivals.
The carmakers are roping in experts from the European power and engineering industry, including
Germany’s Innogy, E.ON and Siemens and Portugal’s Efacec, which are all working on the
technology, people familiar with the matter said.
The new 350 kilowatt (kW) chargers would be nearly three times as powerful as Tesla’s.
“This is a structured and concerted effort across sectors to tackle the infrastructure issue in a real
way,” one of the sources said.
A spokesman for Ford, speaking on behalf of the consortium, said talks with possible partners had
started, adding he expected several energy providers to be part of the planned network, without
elaborating further.

Tesla’s tech billionaire CEO Elon Musk has hinted that the company will not be outdone, tweeting
that 350 kW chargers are a “children’s toy”. A Germany-based spokeswoman for the company
declined to comment beyond Musk’s remarks.
WHO’S AFRAID OF ELON MUSK?
European carmakers believe they are on the cusp of a surge in demand for electric vehicles.
Daimler CEO Dieter Zetsche expects electric vehicles will make up 15-25 per cent of Mercedes
sales by 2025.
But first, technicians have to solve the problem of conveniently charging them up.
Europe already has a network of nearly 72,000 public charging stations for electric cars, but most
are so slow they take hours for a meaningful charge.
The International Energy Agency says only about 5,800 European charging stations are “fast”,
which it defines as charging at a rate of 43 kW or more, the equivalent of operating 90 washing
machines simultaneously.
The fastest chargers in widespread use on the continent so far are the more than 1,800 installed
so far by Tesla. At 120 kW, they still need half an hour to give a car enough juice to drive 270 km.
As the market for electric cars grows, traditional car makers are going to find it easier to catch up
with Tesla, said Graham Evans, automotive analyst at IHS Markit.
“Tesla doesn’t really have anyone to answer to, they are independent,” he said. “(But) I think that
further out the big (automakers) are in a better position to capitalise because of their more
extensive resources.”
Installing thousands of fast chargers across the globe will require billions of dollars in investment
and offer an opportunity to manufacturers. The car consortium’s new fast chargers will cost about
200,000 euros ($210,000) each.
US market leader ChargePoint upped the ante last week by announcing stations of up to 400 kW
that will be available from July.
Navigant Research analyst Lisa Jerram said the number of players in the nascent market to build
ultra-fast charging stations makes it difficult to call out a winner yet.
“Development is under way on these chargers so there isn’t a leader at this point,” she said.
So far, makers of charging stations are focused mainly on getting exposure and market share by
installing as many as possible. But sooner or later, investors are going to want to see profits,
which means that cost will come to matter more.
That holds true even for Tesla, which is starting to adjust its business model as the industry grows
up.
Tesla cars ordered up until this week have come with free electricity from its charging stations. But
owners who order their cars after January 15 will have to pay to power them up once they reach a
limit, although the company says the price will always be cheaper than gasoline.
“Burning money as a result of the market and technology not being ready is unlikely to be
rewarded by shareholders,” said Thomas Deser, senior fund manager at Union Investment.
Trfrjm,.

Oil Discoveries Seen Recovering After Crashing to 65-Year Low
by Mikael Holter
The amount of oil discovered last year was the lowest since the 1950s as explorers slashed
spending amid the worst downturn in a generation, according to Wood Mackenzie. The good
news: It can probably only get better from here.
Oil companies found only 3.7 billion barrels of so-called conventional crude in 2016, 14 percent
less than the previous year and the lowest amount since 1952, according to updated figures from
the Edinburgh-based consultant. The results for both 2016 and 2015 are better than forecast a
few months ago, but still put discovered oil volumes at little more than a tenth of the yearly
average since 1950.
Spending on exploration has been gutted since oil prices started falling in 2014 and may drop
further this year, said Andrew Latham, Wood Mackenzie’s vice president for global exploration.
However, by making operations more efficient, focusing on easier targets and paying lower fees to
contractors oil companies are getting more for their money. Coupled with renewed industry
optimism sparked by an OPEC-led deal to curb output and boost prices, that could mean
exploration results won’t get any worse, he said.
“We’ll probably see 2016 as the turning point, the low point,” Latham said. “There will be a lag of
at least a year, but we do think that investment will start to grow again and volumes will come
back.”

Oil companies reduced spending on exploration to about $40 billion last year from $100 billion in
2014, and could invest as little as $35 billion this year, Latham predicted. Lower budgets meant
fewer wells drilled: 431 in 2016, or about a third of the activity two years earlier. This year, cost
savings mean more wells could be drilled for less money.
Explorers are now passing on the most difficult wells in very deep reservoirs or in harsh
environments such as the Arctic. They’ve also lowered the drilling duration of a typical offshore
well to 55 days from 75 days, Latham said. Among the 40 leading exploration companies Wood
Mackenzie tracks, net spending per well could fall to $40 million from $86 million in 2014, he said.
Total expenditure on exploration could rise to $40 billion to $45 billion in 2018 and further in 2019
if the oil price recovery endures, Latham said.
Even as more exploration yields additional discoveries in the years ahead, the recent dismal
results will have an effect on global oil supplies in five to 10 years, Latham said. If exploration
remained at current levels, the world could see a supply shortfall of 4.5 million barrels a day by
2035, Wood Mackenzi.
Tullow Oil issues trading statement & operational update
Source: Tullow Oil
Tullow Oil has issued a statement to summarise recent operational activities and to provide
trading guidance in respect of the financial year to 31 December 2016. This is in advance of the
Group's Full Year Results, which are scheduled for release on Wednesday 8 February 2017. The

information contained herein has not been audited and may be subject to further review and
amendment.
Commenting, Aidan Heavey, Chief Executive, said:
'2016 was another tough year for the oil & gas sector and for Tullow. However, the Company
showed exceptional resilience and strong operational performance to deliver TEN on time and on
budget; to deal with the technical issues at Jubilee; make good progress in exploration and
development in East Africa and begin the process of reducing our debt from free cash flow.
Tullow is therefore now very well placed to take advantage of the opportunities that conditions in
the sector offer. We took action early to deal with lower oil prices and we are now benefitting from
the re-set and re-structured business that we created. Our $900 million farm-down in Uganda this
week is clear evidence of the commercial attractiveness of our East African portfolio and our
ability to manage our assets according to the strategic and financial needs of the business.'
Operatioal Update
PRODUCTION
Tullow’s West Africa 2016 oil production was in line with recent guidance averaging 65,500 bopd.
This includes 4,600 bopd of production-equivalent payments received under Tullow’s Business
Interruption insurance policy for the Jubilee field. In Europe, working interest gas production
performed in line with expectations and full year net production averaged 6,200 boepd.
In 2017, West Africa working interest oil production, including production-equivalent insurance
payments, is expected to average between 78,000 and 85,000 bopd. Europe working interest gas
production is expected to average between 6,000 and 7,000 boepd.
WEST AFRICA
Ghana
Jubilee
Full year 2016 gross production from the Jubilee field averaged 73,700 bopd (net: 26,200 bopd).
Tullow has also received reimbursements for turret remediation costs and Jubilee production field
losses in 2016 of approximately $8 million (net) under the Hull and Machinery insurance policy
and approximately $72 million under Tullow’s corporate Business Interruption insurance cover
which equates to 4,600 bopd of net equivalent production.

The Jubilee turret remediation work is progressing as planned and the FPSO is expected to be
spread-moored on its current heading by the end of January 2017. This will allow the tugs
currently required to hold the vessel on a fixed heading to be removed, significantly reducing the
complexity of the current operation. The capital costs associated with this and subsequent
remediation works are expected to be covered by the Joint Venture Hull and Machinery insurance
policy.
The next phase of the project will involve modifications to the turret systems for long-term spread-
moored operations. In addition, the assessment of the optimum long-term heading continues, in
order to determine if a rotation of the FPSO is required. Detailed planning for this continues with
the JV Partners and the Ghanaian Government, with final decisions and approvals being sought in
the first half of 2017, with work expected to be carried out in the second half of 2017. It is
anticipated that a facility shutdown of up to 12 weeks may be required during 2017. However,
significant work is ongoing to look at ways to optimise and reduce any shutdown period.
Tullow expects 2017 production from the Jubilee field to average 68,500 bopd (net: 24,300 bopd),
assuming 12 weeks of shutdown associated with the next phase of remediation works. Tullow’s
corporate Business Interruption insurance cover is expected to continue to payout in respect of
lost production associated to the turret remediation works, and the equivalent average annualised
net production is around 12,000 bopd, increasing Tullow’s effective net production to around
36,300 bopd in 2017.
TEN
Following first oil from TEN in August 2016, the oil production, gas compression/injection and
water injection systems were commissioned and are now operational. In early January 2017, the
capacity of the FPSO was successfully tested at an average rate of over 80,000 bopd during a 24

hour flow test. Gross annualised working interest production in 2016 averaged 14,600 bopd (net:
6,900 bopd), in line with latest guidance.
Production testing and initial results from the 11 wells indicate reserves estimates for both
Ntomme and Enyenra to be in line with previously guided expectations. However, due to some
issues with managing pressures in the Enyenra reservoir and because no new wells can be drilled
until after the ITLOS ruling later this year, Tullow plans to manage the existing wells in a prudent
and sustainable manner. As a result, Tullow expects production from TEN to be around 50,000
bopd (net: 23,600bopd) in 2017, although work continues to consider ways to increase production
in 2017.
Gas production from the TEN fields is currently being re-injected, with gas export expected to
commence later in 2017.
Proceedings at ITLOS, with regard to the maritime border dispute between Ghana and Côte
d’Ivoire continue, with oral hearings expected 6-17 February 2017, and a final ruling anticipated in
the fourth quarter of 2017.
Non-operated Portfolio
2016 West Africa net non-operated production was in line with expectations at 27,800 bopd.
Lower oil prices have resulted in significantly lower levels of investment and 2017 net production
is expected to be around 22,000 bopd. However, flexibility remains in the portfolio, with options to
increase capital investment in 2017 and subsequent years to reduce the production decline in
these mature assets.
Full year gas production from Europe averaged 6,200 boepd in 2016, in line with expectations.
Tullow expects 2017 European gas production to
be around 6,500 boepd.
EAST AFRICA ,
Kenya
A four-well exploration and appraisal programme
commenced in mid-December in the South
Lokichar Basin with the drilling of the Erut-1 well,
located in the north of the basin, approximately
11km north of the Etom field.
The well is nearing completion, with a result
expected shortly. The rig will then move to drill
Amosing-6, a well targeting undrilled volumes,
before moving to Ngamia-10, an appraisal well to
the south of the Ngamia discovery. The planned
final well in the programme is the Etete prospect,
a structure approximately 2km south of the Etom
field. This programme could be extended by up to
four additional wells in 2017, depending upon the
assessment of the results from the initial four
wells.
Water injection trials have been successfully

completed on the Amosing discovery in the South Lokichar Basin. Data collected shows the
viability of water injection for development planning. A similar programme of water injection tests
on the Ngamia discovery are scheduled to commence later this month.
Work continues on the Early Oil Pilot Scheme, full field development planning and the export
pipeline.
Uganda
On 9 January 2017, Tullow announced that it has agreed a substantial farm-down of its assets in
Uganda to Total. Under the Sale and Purchase
Agreement, Tullow has agreed to transfer 21.57%
of its 33.33% interest in Exploration Areas 1, 1A, 2
and 3A in Uganda to Total for a total consideration
of $900 million. The farm-down leaves Tullow with
an 11.76% interest in the upstream and pipeline,
which will reduce to 10% when the Government of
Uganda formally exercises its right to back-in.
The consideration is split into $200 million in cash,
consisting of $100 million payable on completion of
the transaction, $50 million payable at FID and $50
million payable at first oil. The remaining $700
million is in deferred consideration and represents
reimbursement by Total in cash of a proportion of
Tullow’s past exploration and development costs.
The deferred consideration will fund Tullow’s share
of the development and pipeline costs as the Lake
Albert Development reaches a series of key
milestones. Completion of the transaction is subject
to government approval, after which Tullow will
cease to be an operator in Uganda.
This agreement will allow the Lake Albert
Development to move ahead and increases the
likelihood of FID around the end of 2017.
NEW VENTURES
Tullow has continued to advance its operations in South America and plans are ongoing to drill the
potential high impact Araku Prospect (Tullow: 30%), offshore Suriname, in the second half of
2017. In Guyana, planning is ongoing to acquire 3D seismic data over the offshore Kanuku and
Orinduik licences located updip of the Liza oil discovery.
The divestment of the Norway business is almost complete, with the sale of four licences to Statoil
and eight licences to Aker BP ASA completed before year end 2016. A further three sales were
executed in December 2016, which are expected to be completed in the first half of 2017.
Financial Update
Following the scheduled amortisation of RBL commitments in October 2016, the Group ended the
year with available credit under the RBL facility of $3.3 billion. At the end of 2016, Tullow had total
facility headroom and free cash of $1 billion and net debt of $4.8 billion, which includes the $300
million Convertible Bond offering in July 2016. The improvement in the year end net debt and

liquidity position versus previous forecasts is largely due to the cashflow contribution from TEN
and ongoing capex and cost management.
In 2016, Tullow expects to deliver revenue of c.$1.3 billion, gross profit of c.$0.5 billion and
operating cash flow of c.$0.7 billion. Due to the current low oil price and the impact of disposal and
farm-down transactions, a number of accounting charges are forecast to be incurred in the 2016
income statement. These charges comprise a goodwill impairment of c.$0.2 billion, a post-tax
exploration write-off of c.$0.3 billion, a post-tax impairment charge of c.$0.1 billion and an onerous
service contract charge of c.$0.1 billion.
In 2016, Tullow’s oil and gas hedge programme contributed $363 million to revenues, and as we
look ahead to 2017, the hedging position continues to provide protection of future revenues and
cashflows. The mark-to-market value at the end of December 2016 was $91 million and Tullow
will benefit in 2017 from approximately 60% of entitlement oil production hedged at an average
floor price of around $60/bbl on a pre-tax basis.
Capital expenditure will continue to be carefully controlled during 2017. The Group’s capital
expenditure associated with operating activities is expected to reduce from $0.9 billion in 2016 to
$0.5 billion in 2017.
The 2017 total comprises Ghana capex of c.$90 million, West Africa non-operated capex of c.$30
million, Kenya pre-development expenditure of c.$100 million and Exploration and Appraisal
spend limited to c.$125 million. Uganda expenditure of $125 million will be offset by the Uganda
farm-down deferred consideration.

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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 January 2017 K. Al Awadi

New base 986 special 12 january 2017 energy news

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