New base 718 special 01 november 2015

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NewBase 01 November 2015 - Issue No. 718 Edited & Produced by: Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
UAE National Committee for World Energy Council Signs Contract to
Host World Energy Congress 2019 in Abu Dhabi
(WAM) – A delegation of UAE officials, led by Dr. Matar Al Neyadi, Co-Chair of the UAE National
Committee for the World Energy Council (WEC) and Undersecretary of the UAE
Ministry of Energy, attended today the signature of the contract for Abu Dhabi to
host the 2019 World Energy Congress. The signature took place during the
World Energy Council’s 2015 Executive Assembly in Addis Ababa, Ethiopia, and
was attended by the Council’s leadership, headed by Dr. Christoph Frei,
Secretary General of the organization.
The signature ceremony was witnessed by Motuma Mekasa, Minister of Water, Irrigation &
Electricity of Ethiopia Ethiopia, as host of the Executive Assembly; as well as Ali Saad Al Omaira,
Charge d’Affaires of the UAE Embassy in Ethiopia, and the Chair of the World Energy Council,
Marie Jose Nadeau.
During the ceremony, Dr. Matar Al Neyadi highlighted the importance of hosting the World Energy
Congress for the UAE, which will become the first OPEC country to host the globally-reputed
event.
"Hosting the World Energy Congress is a key milestone for the energy sector of the UAE, as the
nation continues to emerge as a global epicenter for the future of energy," said Dr. Matar Al
Neyadi. "We understand the responsibility of hosting such a reputable event and have already
begun the initial planning with great determination. The 2019 Abu Dhabi World Energy Congress
is envisioned to become the greatest and most decisive Congress the World Energy Council has
celebrated in its 90-year history."

Dr. Christoph Frei, Secretary General of World Energy Council, also highlighted the importance of
bringing the World Energy Congress to the UAE. "We are delighted to have signed this contract
here in Addis Ababa at our Executive Assembly. The leadership shown by the UAE team will
ensure that we will be well placed to build on the success of our Istanbul Congress which will take
place in October 2016. I am sure that these two events will add significantly to the post COP21
energy agenda."
"The signature of the contract is the culmination of months of intensive collaboration between the
UAE National Committee and the World Energy Council," said Eng. Fatima Al Foora, Secretary of
the UAE National Committee and Assistant Undersecretary for Electricity of the UAE Ministry of
Energy. "We are now ready to step into a new phase of joint development with the World Energy
Council and work together to prepare for the best World Energy Congress in the history of the
organization. "
Running since 1924, the World Energy Congress is the world’s largest and most influential global
energy event covering all aspects of the energy agenda. The event takes place every three years
and is a unique platform for Ministers, CEOs and industry experts to analyze the state of global
energy affairs.
The UAE National Committee won the bid to host the 2019 World Energy Congress after a four-
month intensive campaign that sought to obtain the endorsement of the 93 member countries of
the World Energy Council. The Abu Dhabi candidacy was elected in October last year in
Cartagena de Indias, Colombia, winning over rivals Rio de Janeiro and St. Petersburg.
Abu Dhabi convinced the majority of the member countries with its unique offering of visionary
energy leadership, state-of-the-art event venues and modern infrastructure.
Preparatory works for the 2019 Abu Dhabi World Energy Congress have already begun and the
UAE National Committee for the Council is establishing the Organizing Committee to start the
procedures required to host such a reputed event. The Committee is working in close partnership
with local and federal entities to ensure the success of the event, which is scheduled to become
one of the leading events on the 2019 agenda in the UAE.

Jordan wants to retain uranium enrichment right, official says
The National + NewBase
Jordan is close to a deal to begin building the first of two Russian-design nuclear reactors, with
work expected to start in early 2017 and the reactors ready for start-up in 2024, the head of the
country’s nuclear programme said.
Jordan is part of the vanguard in the Middle East of countries with plans to add nuclear to their
energy mix to meet rapidly rising demand and to help improve their energy security and reduce
reliance on imported fossil fuels.
Russia has already claimed a significant share of the region’s nuclear business and is poised to
gain further.
Iran was the first in the region to go nuclear with its controversial Bushehr plant, which after a
saga that spanned four decades was finally commissioned as a primarily Russian-implemented
1,000-megawatt reactor in 2011.
With the largest and fastest-growing electricity demand in the region, Iran has announced
aspirations to increase its nuclear capacity 20-fold by 2020, starting with a deal for Russia to build
two more reactors at Bushehr of 1,000MW each. The cost of those plants would be about US$11
billion, Russia’s energy minister announced last week.
The UAE is the first country in the Arab world to start a nuclear building programme – and, with
Belarus, the first in the world in decades to start a nuclear programme. Turkey is expected to
Khalid Toukan, right, chairman of the Jordanian Atomic Energy Commission and Sergei Kiriyenko, of the Russian state nuclear
energy agency Rosatom, answer questions from reporters after signing a deal to build Jordan’s first nuclear power plant on
Tuesday, March 24, 2015, in Amman, Jordan. (Photo credit: AP/Sam McNeil)

begin construction of its first, Russian-designed reactor at Akkuyu next year, with a total of four
planned for that site.
Other countries in the region with nuclear plans include Egypt, which signed a memorandum of
understanding in February this year and is in final negotiations with Russia on terms to build its
first reactor, and Saudi Arabia, which plans to add up to 17 gigawatts of nuclear by 2040 and
signed a cooperation deal with Russia in June.
After a long bidding process that started in 2007, Jordan had already settled on the Russian AES
92 model for two reactors with 1,000MW capacity each, to be built at Qasr Amra, about 80
kilometres south-east of Amman, at an estimated cost of $10 billion.
Plans have now been accelerated by a year so that Jordan expects to have both 1,000MW
reactors online before the end of 2025, said Khaled Toukan, the chairman of the Jordan Atomic
Energy Commission (Jaec), after returning from recent talks in Russia.
“We are now conducting basic studies – on the cooling water, the electricity market, the grid —
and we are into the detailed side of the environmental impact study,” said Mr Toukan, who has a
nuclear engineering doctorate from the Massachusetts Institute of Technology and was a former
energy minister for Jordan.
“We are now in trilateral discussions and seeking strategic partners – technology providers as well
as finance partners,” Mr Toukan added. Contrary to some reports, Jordan has not yet reached
agreement on an ownership structure or financing.

Jaec is in talks with China National Nuclear Corporation about a potential equity stake in the Qasr
Amra development, as well as participation in the construction phase for the turbine islands and
other aspects of the plant, the company said.
Additionally, Jordan is in talks with Industrial and Commercial Bank of China about non-equity
financing. “It should be made clear that these discussions are still continuing,” said Mr Toukan.
“Operation structure is not being discussed at this point with third parties but is an option for
qualified ones.”
Jaec is also talking to potential partners elsewhere, including France and the UK – for example
with Rolls-Royce about potentially providing cooling systems for the plant.
Mr Toukan said Jaec will go on an international “roadshow” to hold further discussions with
potential partners and plans to have all of the primary deals in place “by early next year”, with
building on the first of the reactors starting at the beginning of 2017.
The addition of nuclear power is crucial for Jordan, which forecasts rapid growth in electricity
demand, from about 3,000MW this year to 8,000MW in 2030, a similar growth rate as Iran and
UAE from their much higher bases of about 70GW and 40GW, respectively.
Hitherto, it has imported almost all of its energy needs in the form of natural gas and oil.
Jordan has the advantage of being rich in uranium deposits and has a $140 million project in
place to develop a mining and milling operation at deposit sites south of the capital, which will
supply the 400 tonnes needed for the Qasr Amr reactors and rise to 1,000 tonnes thereafter with
excess supply going for export.
Jordan has also held preliminary discussions with vendors of small nuclear reactors (SMRs), an
emerging technology that Mr Toukan said may provide 400MW-500MW of additional generating
capacity.
“SMRs are surely a viable option for Jordan, once demonstrated elsewhere, as they are easier in
terms of finance and siting,” he said. “Preliminary discussions have taken place with SMR vendors
– still, the option for installing additional 1,000MW size units is not out of the question,” he adds.

Egypt: Eni starts new production from 'near field' discoveries in
the Nile Delta and Western Desert . Source: Eni
Eni has announced the success of the Nidoco North West 3 well, an appraisal of the Nidoco NW
2 Dir discovery, in the Nooros exploration prospect, located in the Abu Madi West licence in
the Nile Delta.
The field, which is estimated to contain about 15 billion standard cubic meters of gas (GSM3) in
place, plus associated condensate, was discovered on July this year and put into production after
only two months; it currently produces more than 15,000 barrels of oil equivalent per day (boepd).
The production from the new well will start-up by the end of November.
During 2015, Nooros field will produce 30,000 boepd and is expected to reach a plateau of 70,000
boepd in the first half of 2016. The gas and condensates are sent to the Abu Madi’s treatment
plant, about 25 kms from the discovery, and then routed in the Egyptian network.
Similarly to the discovery well, Nidoco NW3 was drilled from onshore to reach in deviation the
Noroos reservoir located in the offshore shallow waters. The well encountered a 65 meters thick
gas bearing sandstone layer of Messianian age with excellent petrophysical properties.

In parallel with the field development, Eni will continue its exploration activities in the license area,
where it has identified a significant additional potential which will be tested through the drilling of
other three new exploration wells.
Eni, through its subsidiary IEOC, holds a 75% stake in the Abu Madi West licence, while BP
holds a 25% stake. The operator is Petrobel, held equally by IEOC and by the state company
Egyptian General Petroleum Corporation (EGPC).
In addition to the activities in the Nile Delta, Eni reports that in October, in the Western Desert of
Egypt it has reached a new production of 73,000 barrels of oil per day, doubling in just three years
the level of production in the area.
The production increase was allowed by the production growth in the Melehia West Deep field, in
the Melehia licence, located 290 kms west of Alexandria. The new field, which contains oil and
gas in the Lower Cretaceous and Jurassic’s deep geological layers, was discovered on January
2015 and, following an appraisal campaign, it has already achieved a production level of 12,000
barrels of oil per day.
Eni expects, with the next activities of the Melehia West Deep field, to bring production over
15,000 bopd also thanks to the start-up of the first treatment plant and the gas export of Melehia’s
licence by end of November.
These new finds with immediate return of production capacity are the result of Eni’s new strategy
in the country, where the onshore have been addressed on high value activities able to grant the
rapid development of the discoveries through existing infrastructures and synergies.
Eni, through its subsidiary IEOC, holds a 100% stake of the Melehia Deep licence and a 76%
stake in the Melehia licence, together with its partner Lukoil, which holds a 24% stake. The
operator is Agiba, a joint venture between IEOC and EGPC.
Eni has been present in Egypt since 1954 where it operates through IEOC. The company is the
leading producer in the country with an equity production of around 190,000 barrels of oil
equivalent per day.

Norway: Centrica signs long-term partnership agreements for Butch
Source: Centrica
Centrica has entered into long-term partnership agreements with three suppliers. The agreements
are based on a strategic partner alliance (SPA) model covering all phases of project execution,
with duration of up to ten years. The first call-off will be for Front End Engineering and Design
(FEED) for the Butch development in the North Sea.
The SPAs have been entered into with Aibel,
Subsea 7, and DNV GL. The objective is to
establish a long-term relationship between
Centrica and the suppliers, to create value and
predictability.
'Centrica is about to embark on its first
operated field development in the North Sea,
the Butch field. We want to build expertise and
capacity over time. This is why we are entering
SPA agreements with strong suppliers, who
have extensive experience with field
developments on the Norwegian continental
shelf,' says Vice President Projects Arne Bjørlo
of Centrica.
One important goal is for this contract model to
provide Centrica’s partners with the opportunity
to continually contribute their best solutions
and project expertise through the study and
execution phases.
First challenge: Butch
Centrica and the partner oil companies in the Butch licence will invest between NOK 6 and 7
billion to develop the North Sea field. Aibel will deliver design, engineering and fabrication, Subsea
7 will provide pipelines, umbilicals and subsea service, while DNV GL will verify the work done.
'We have carried out a thorough and timely process, both to identify the various partners, and to
clarify how we will implement the SPAs – a model I think will be attractive for all parties,' says
Bjørlo.
SPA model strategy
The strategy behind the SPAs with selected suppliers is based on shared values and goals.
Centrica sees several advantages to the SPA agreements:
• Early engagement to secure optimal use of the supplier’s experience and technical
solutions
• Increased standardisation to reduce cost and project complexity
• Optimised interfaces and improved project execution
The agreements have duration of five years, with an option of an additional five years.

Tanzania: Orca Exploration announces closing of US$60 million
financing of Songo Songo development programme .
Orca Exploration has entered into a loan agreement with International Finance Corporation
(IFC), a member of the World Bank Group, for a US$60 million investment in the Company's
operating subsidiary, PanAfrican Energy Tanzania
Limited (PAET).
Proceeds of the Loan will be used to fund part of an
estimated US$120 million first phase of a Songo
Songo Main Field development programme (the
'Off-Shore Programme') currently being undertaken
using the Paragon M826 drilling rig (commenced in
September 2015). The Off-Shore Programme is
designed to (i) put safe existing suspended and
operating production wells; (ii) restore and increase
the current productive capacity of the Songo Songo
Main Field to ensure the continued delivery of
Protected and Additional gas into the existing
Songas infrastructure; and (iii) provide additional
operational redundancy and deliverability for future
additional gas sales, by way of the workover and
recompletion, abandonment or sidetrack drilling of
three existing offshore wells, and/or the drilling of
additional production gas wells at locations to be
determined in the region of the existing offshore
wells depending on the outcome of the workovers.
Since programme commencement, previously
suspended production wells SS-5 and SS-9 have
been successfully worked over and recompleted, and have been restored to full productive
capacity estimated to be approx. 35 MMscfd per well.
The Off-Shore Programme is intended to restore and expand field productive capacity from
approx. 83 million standard cubic feet per day (MMscfd) prior to the programme to approx. 190
MMscfd on completion of the programme. When completed, the field is expected to be capable of
both filling the existing Songas infrastructure to capacity of approx. 102 MMscfd, as well as
providing additional gas volumes to the newly commissioned National Natural Gas
Infrastructure Project (NNGIP) as and when contracted.
The term of the Loan is 10-years, with no repayment of principal for the first seven years, followed
by a three-year amortization period. The Loan is an unsecured subordinated obligation of PAET
and is guaranteed by Orca to a maximum of US$30 million. The guarantee may only be called
upon by IFC at maturity in 2025 and, subject to (among others) IFC approval, Orca may issue
shares in fulfillment of all or part of the guarantee obligation in 2025, subject to receipt of all
required regulatory approvals.
'The Songo Songo field is Tanzania's most important source of proven natural gas production, and is the
largest supplier of energy to the Dar es Salaam region' said Lance Crist, IFC Global Head of Natural
Resources. 'Through this investment, IFC is working to help to alleviate electricity shortages in Tanzania,
which are an impediment to the country's continued economic growth and development.'

Beyond China, other Southeast Asian countries plan for
significant hydroelectric additions. Source: U.S. EIA International Energy Statistics
China's substantial development of hydroelectric power, including the largest power plant in the
world at Three Gorges Dam, has overshadowed the relatively large hydroelectric expansion plans
of other Southeast Asia countries.
Combined, the smaller countries of Southeast Asia plan to construct 61 gigawatts (GW) of new
hydroelectric generating capacity through 2020. If all planned projects are completed, these
countries will more than double their 2012 hydroelectric capacity of 39 GW.
Many countries in Southeast Asia are planning to access the immense hydroelectric potential of
the lower Mekong River, which flows through or borders China, Myanmar, Laos, Thailand,
Cambodia, and Vietnam.
China has constructed six major dams along the upper portion of the Mekong River. Hydroelectric
power potential in the Greater Mekong Region (which includes Mekong tributaries) is estimated
between 175 GW and 250 GW. As of 2010, 71 Mekong hydroelectric dams were proposed for
completion by 2030.
Vietnam, Indonesia, Bhutan, and Laos are four of the many Southeast Asian countries with
significant planned hydroelectric additions, from projects in the Mekong region as well as projects
centered on other hydroelectric resources.
Vietnam has the most ambitious hydroelectric development plan in Southeast Asia, with plans to
develop 205 hydroelectric projects (6.2 GW) by 2017, and nearly 4 gigawatts (GW) of additional
capacity between 2017 and 2030. One of the largest projects, Trung Son, a 360-megawatt (MW)
project, is located on the Ma River in northern Vietnam, which is not a Mekong tributary.

Indonesia's goal is to develop 5.7 GW of new hydroelectric generating capacity by 2021. Included
is one of the larger hydroelectric projects outside of China, the 1,040 MW Upper Cisokan pumped
storage power facility projected to be in service by the end of 2018.
Bhutan, a relatively small, mountainous country surrounded by India and China, plans to build 10
GW of hydroelectric generating capacity. Because much of this electricity will be exported to India,
India is funding these projects. Many of Bhutan's rivers feature high vertical drops over a short
distance, ideal for hydroelectric generation. Three of these facilities with a combined 2,940 MW
capacity are currently under construction.
Laos, which currently has hydroelectric generating capacity of about 2.5 GW, plans to increase
that capacity to more than 9 GW by 2020. This increase includes 17 projects currently in the
planning stage with a combined capacity of more than 4.5 GW. One-fourth of this capacity is
attributed to the 1,285 MW Xayaburi hydroelectric power plant, the first of 11 planned
hydroelectric generating plants along the lower Mekong River. Laos, like Bhutan, expects to be a
major electricity exporter.
Despite the strong electrification potential of these projects, there are major concerns about the
environmental impacts of damming the Mekong River system and other rivers in Southeast Asia.
An independent assessment prepared for the Mekong River Commission recommended a 10-year
delay in the current hydroelectric project schedule to evaluate environmental concerns.

Indonesia infrastructure drive may turn around slowing economy: QNB
Gulf Times
Underinvestment has led to supply bottlenecks and an infrastructure gap in Indonesia, which the
country’s new government hopes to close, QNB has said in its “Indonesia Economic Insight 2015”.
The report examines the outlook for the Indonesian economy and the ongoing challenges facing
the current administration, such as capital flight and an infrastructure gap, amidst the constraining
environment of a slowing economy.
According to the report, poor infrastructure creates crippling supply bottlenecks: heavy road traffic,
congested transport networks and widespread power and water shortages. As a result, growth is
sub-par and inflation and interest rates are high. However, President Joko Widodo (Jokowi),
elected in October 2014, hopes to turn the situation around by revitalising investment in
infrastructure.
“We expect real GDP growth to slow in H2, 2015 on tighter financial conditions, as credit growth is
slowing, interbank interest rates are rising and capital outflows may continue as US monetary
policy begins to rise.
“A recovery should begin in 2016, with infrastructure investment adding to growth.”
By 2017, QNB said, the financial conditions should begin to ease as the US Federal Reserve
nears the end of its tightening cycle, adding to growth through healthier capital flows along with a
more stable Indonesian Rupiah (IDR).
In late 2015 and during 2016-17, QNB expects the current account deficit to widen as the
infrastructure investment programme gets underway, which should lead to higher imports of
capital goods. Exports are likely to be held back by restrictions on the export of certain raw
materials, which are designed to support the development of domestic manufacturing
industries,the QNB report said.
However, slightly stronger exports are expected in 2016-17 than in 2015 due to a weaker IDR,
which should boost competitiveness, as well as government policies to support manufacturing
exporters. Indonesian banking sector growth may be constrained by tight financial conditions until
2017 at the earliest. In 2016-17, deposit growth is expected to slow from high levels in line with

falling inflation and lower nominal GDP growth, according to the report. Loan growth could be
constrained in 2015-16 due to rising interest rates, depressed capital flows and higher NPLs.
From 2017, loan growth should pick up gradually as credit demand recovers (on higher economic
growth and investment) and as financial conditions ease in Indonesia, the report added.

NewBase 01 November - 2015 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil rises on U.S. rig count; market also up on week and month
Reuters + NewBase
Oil prices rose on Friday, finishing higher for the week and month as well, after another decline in
the U.S. oil rig count indicated domestic crude production could fall in coming months. Prices also
got a boost from separate data showing U.S. oil output in August fell to third lowest figure this
year.
Brent, the global benchmark for oil, settled up 76 cents, or 1.6 percent, at $49.56 a barrel. It rose 3
percent on the week and 2 percent for October. U.S. crude futures rose by 53 cents, or 1.1
percent, to $46.56, gaining 3 percent on the week and 4 percent on the month.
Oil prices had trended higher since Wednesday's 6 percent rally, sparked by a smaller-than-
anticipated build in U.S. crude and sharper-than-expected falls in gasoline and diesel stockpiles.
U.S. oil drillers removed 16 rigs in the week ended Oct. 30, bringing the total rig count down to
578, the least since June 2010, oil services company Baker Hughes Inc said in its closely followed
report.
Oil price special
coverage

The drop was a sign that low prices were continuing to keep drillers away from the well pad,
signaling lower production over the next several months. But while U.S. output is declining, global
supplies of crude and refined oil products continue to grow, testing storage capacity and
hammering oil company results.
This is prompting oil bears to argue that price rallies such as Wednesday's cannot be sustained.
"Looking at the bigger picture, there is still lots of oil in the United States," PVM Oil Associates
analyst Tamas Varga said. "We should see a softer market in the coming days."
Others are not so sure.
"Although providing fundamental rationale for a 6 percent single day advance remains
challenging, we are conceding to a significant improvement in the short term chart picture and a
need to lift pricing in order to attract fresh selling," said Jim Ritterbusch of Ritterbusch &
Associates, an oil consultancy in Chicago.
A Reuters survey was supportive to the market, showing that Saudi Arabia and Iraq pumped less
oil in October than African nations in OPEC, pushing the producer group's output down from near
record highs. Chinese government data also showed the country was doubling crude oil import
quotas for 2016.

Global LNG surplus pushing producers, importers into spot market
Reuters+ NewBase
Producers and importers of liquefied natural gas (LNG) are preparing to trade the fuel more
actively on a spot basis as a looming supply surplus threatens to overwhelm decades-old bilateral
contracts and pressure prices lower.
With the advent of 130mn tonnes of LNG capacity in Australia and North America by 2020,
producers such as Woodside Petroleum and Chevron, and traditional buyers such as Japanese
utilities, have expanded trading teams to handle excess cargo flows and navigate a more open
market.
Australia, with investments of almost $200bn in new production, is on track to overtake Qatar as
the world’s biggest LNG exporter before the end of the decade. In North America, US company
Cheniere Energy plans to export its first LNG cargo in January, and Canada is also planning to
start exports in the next few years.
“Buyers will be able to have their choice ... (of) very large supply sources that can deliver pretty
much at a moment’s notice,” Cheniere chief executive Charif Souki said this week at a conference
in Singapore.
Excess supply, along with rising demand, is key to establishing a liquid commodity market as in
tight conditions producers and consumers tend to enter long-term fixed supply agreements rather
than trade openly.

And while new demand is popping up in countries such as Jordan, Dubai, Egypt and Pakistan, it is
unlikely to be enough to offset the slower-than-expected consumption growth in China and the
falling demand in top importers Japan and South Korea.
Some major players in the industry disagree, though, on how quickly a robust spot market will
develop. Last year, less than 5% of total volumes were sold on a prompt delivery spot basis, said
Ann Collins, vice president for LNG at BG Group, at Gastech on Thursday.
“A rapid tilt towards a commoditisation of LNG seems unlikely in the near term,” she said. Still,
Ernst and Young (EY) says liquefaction capacity has more than doubled since 2000 and
exceeded demand last year.
This surplus, along with slow-growth demand, will keep prices under pressure until the end of the
decade, consultancy Wood Mackenzie said in statement this week.
Japanese power utilities – traditionally strictly buyers of LNG for gas-fired generators – are selling
to each other or reselling to emerging smaller local buyers, even as nuclear reactors restart and
the country’s overall electricity demand falls with a shrinking population.
Japan’s JERA Co, a
joint venture set up by
Tokyo Electric Power
and Chubu Electric
Power, will renew only
a minimum of the long-
term contracts that
supply 80% of its gas,
and instead meet its
needs via mid-term and
short-term contracts or
spot purchases.
Australia’s Woodside,
one of the biggest
producers of LNG, has
traditionally sold its
volumes on contracts
that last 20 years or
more, yet now says it
needs more LNG
tankers to deal with rising spot and short-term sales.
“We’re becoming more sophisticated in our marketing and trading activities,” chief executive Peter
Coleman told reporters at the industry meeting this week in Singapore.
Chevron, which up to now has also dealt mostly in long-term supply agreements, has established
an LNG trading desk in Singapore to handle output – mainly from its Australian projects – that is
not committed to buyers. Commodity trading houses are also getting ready for the increase in
supply, with Glencore planning to double its trading team as it mounts a challenge to rivals
Trafigura and Vitol to become the top merchant LNG trader.

NewBase Special Coverage
News Agencies News Release 01 Nov.. 2015
Oil majors reel under sustained oil price plunge
Syed Rashid Husain ( images by NewBase )
OIL woes are taking their toll. With prices staying at around $50, oil majors are taking hit – all
around. Unhealthy Q3 earning results and billions of dollars in asset write downs are indicative of
the state of the industry.
Saudi Arabia, the OPEC kingpin, is evaluating steps to balance budget. Riyadh is looking to raise
domestic energy prices, said Oil Minister Ali Al-Naimi last week, confirming the kingdom could cut
fuel subsidies – often blamed for waste and surging domestic fuel consumption. UAE has already
taken a step in this direction and has brought fuel prices in line with the global market prices.
The depleting oil revenues of other important producers such as Venezuela and Mexico is already
a cause of real concern to their respective governments. The issue with most remains, how to
meet the growing public expenses and aspirations.
Oil majors are no different. They are also faced with headwinds. Belt tightening is the order of the
day. Exxon Mobil Corp, the world’s largest publicly traded oil company, said on Friday its third-
quarter profit fell 47 percent.
Revenue of the Irving, Texas based company fell to $67.34 billion – from $107.49 billion a year
ago. It posted profit of $4.24 billion, or $1.01 per share, compared with $8.07 billion, or $1.89 per
share in the same quarter a year earlier. Earlier this year, Exxon had announced it would cut its
2015 capital expenditures by about $4.5 billion to $34 billion.
Chevron Corp. on Friday announced it could cut 6,000 to 7,000 jobs and pare its capital spending
by 25% next year. Profits of the company too tumbled in the third quarter. For the quarter ended
Sept. 30, Chevron reported earnings of $2.04 billion, or $1.09 a share, down from $5.6 billion, or
$2.95 a share, a year earlier. Revenue fell 37% to $34.32 billion.
The company eked out a $59 million profit in its exploration and production segment, down from
$4.65 billion a year earlier. Its US segment swung to a loss of $603 million from a profit of $929
million a year earlier.
Chevron, the second-biggest US oil company also underlined it expects capital spending of $25
billion to $28 billion in 2016, down 25% from this year’s budget. In 2017 and 2018 too, it expects
to cut spending further, to around $20 billion to $24 billion.
In the meantime, Marathon Oil Corp. became the first major shale producer to cut its quarterly
dividend, reducing it by 76 percent in an effort to prop up cash holdings. Marathon’s Dec. 10
payout to investors will drop to 5 cents a share from 21 cents, the company said.

Royal Dutch Shell PLC too is reporting a third-quarter net loss of $7.42 billion, its biggest decline
in at least 16 years, after Europe’s largest energy group abandoned projects and lowered its oil-
price expectations, resulting in one-time charges of more than $8 billion.
Its adjusted earnings came in at $1.8 billion, compared with $5.3 billion for the same quarter a
year ago, a decrease of 70 percent. The accounting included a large $8.2 billion write-off due to a
downward revision of its oil and gas price outlook and also a decision to halt projects in Alaska
and Canada. In the meantime, French oil major Total is also reporting a 23 percent drop in third-
quarter adjusted net income from the same quarter last year.
Eni SpA too has swung to a net loss in the third quarter. It is now reporting a 75 percent drop in
adjusted operating profit for the third quarter to 752 million euros, while its adjusted operating
profit for the first nine months of the year came in at 3.1 billion euros, down 67 percent compared
to same period in 2014.
The net loss in the three months to end-September was €952 million ($1.05 billion) compared with
a net profit of €1.71 billion in the same period last year. Revenue declined by almost a third to
€18.81 billion.
The gas and power division wiped out most of that profit as it reported a quarterly loss of almost
€500 million, largely due to the difference between what Eni prepaid for natural gas in past years
and the lower price during the most recent quarter.
Cost cuts and a reduction in its dividend announced in March have helped Eni weather the two-
thirds drop in the profitability of its oil and gas business so far this year, but the oil and gas unit is
no longer able to offset the struggling other businesses on its own.
In a further move to confront the new reality of depressed oil prices, Eni has also agreed to sell
12.5 percent of its troubled oil services unit Saipem to an Italian state-run investment fund. The
sale, plus Saipem’s repayment of debt, will bring Eni €5.4 billion. The proceeds of which will be
used for its exploration and production business and to shore up its balance sheet.
This is despite the fact that Eni’s success in exploration over the past year offered a bright spot in
the company’s third quarter results. Production of oil and natural gas rose 8.1% on the quarter,
slightly above analysts’ forecasts. Eni’s top recent discovery has been a massive natural gas field
off the Egyptian coast.
The British oil giant BP is in no different situation. It is slashing costs as it prepares for a long-term
low oil price environment. The company is now planning for around $60 per barrel price for Brent
crude until at least 2017.
It also plans a further $3-5 billion worth of asset sales next year. BP has also reduced its full-year
capital expenditure (capex) for the third time this year to close to $19 billion, down from previous
plans under $20 billion. This spending will fall to $17-19 billion a year through to 2017, according
to the oil major.
The oil-price rout has wiped almost $500 billion since the end of last year from the Bloomberg
World Oil & Gas Index, which tracks energy stocks globally including Shell, Exxon Mobil Corp. and
Chevron Corp. This is a starkly different – yet disturbing – energy world!

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 01 November 2015 K. Al Awadi

New base 718 special 01 november 2015

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