New base 793 special 23 february 2016

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 23 February 2016 - Issue No. 793 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:Bee’ah takes a stand on recycling at Plastivision Arabia ‘16
(WAM) -- The third edition of the Plastivision Arabia International Plastics Exhibition and
Conference gets under way from 22–25 February, at the Expo Centre Sharjah, with Bee’ah, the
Sharjah Environment Company set to take a leading role as the event’s official recycling sponsor.
Held in association with the All India Plastics Manufacturers’ Association (AIPMA), the oldest and
largest apex body in the plastics industry, Plastivision Arabia 2016 welcomes representatives and
exhibitors from across the industry’s many sub-sectors, including polymer and machine
manufacturers, processors, mould and die manufacturers, traders, exporters, consultants,
environmental institutions and many more.
As the official recycling sponsor of Plastivision 2016, Bee’ah showcases a range of its significant
eco-friendly products and services, such as its Tyre Recycling Facility (TRF) and Construction and
Demolition Waste Recycling Facility (CDW) products.
Bee’ah’s recycled products include crumb rubber used in different rubber flooring applications
such as jogging tracks, miniature golf courses as well as artificial turf infill in schools, parks and
athletic facilities.
Bee’ah also manufactures rubber tiles of different shapes and thicknesses these are widely used
as a safety flooring alternative for kids play areas, walkways, and in horse stables and exercise
areas.
Moreover, recycled products from Bee’ah’s CDW Facility are reused as aggregate for roads,
pavements, and landscaping. Plastivision 2016 is held at the Expo Centre Sharjah until the 25th of
February, from 10am–6pm daily.

Qatar to build 1,000 MW of solar power capacity
Reuters
Qatar plans to build around 1,000 megawatts of solar power generating capacity to diversify its
energy mix away from hydrocarbons, the general manager of the state utility said.
Qatar Electricity and Water Company said in late December it would hold 60 per cent of a new
solar power joint venture with Qatar Petroleum . The two shareholders will provide $500 million of
start-up capital, Fahd al-
Mohannadi told reporters on
the sidelines of QEWC's
annual shareholder meeting.
International companies will
be invited to back 40 per cent
of each project through a
competitive tender process,
Mohannadi said.
"We decided to do it based on
the fact that producing power
from solar is cheaper than buying gas from the international market," Mohannadi said. Qatar is the
world's largest exporter of liquefied natural gas.
He did not say when it would reach 1,000 MW of generating capacity. Abdulsattar al-Rasheed,
business development director at QEWC, said setting up the joint venture should be completed
around the end of this year or early in 2017.
There is little commercial generation of solar power in the Gulf, but oil-exporting countries around
the region are starting to develop it, citing environmental reasons as well as a desire to conserve
oil and gas reserves for export in the future.
Two projects in the United Arab Emirates are expected to be tendered this year which would
create 1,150 MW when fully operational. Saudi Arabia has plans for both small solar schemes and
power plants in which a solar component is combined with a fossil fuel element.
Mohannadi said solar would be a key part of Qatar's future energy mix, since both coal and wind
power had been ruled out and Qatar's land mass was too small to consider nuclear power.
DEMAND
Peak demand for both electricity and water was expected to grow at 6 to 8 per cent this year, from
last year's daily highs of around 7,000 MW and 330 million gallons of water, Mohannadi said.
However, the country has plenty of spare capacity and more coming online in the next two years,
which will take generating capacity to 11,000 MW of electricity and 400 million gallons of water by
the start of 2018.
The first phase of the Ras Abu Fontas A3 water plant expansion, built by a consortium led by
Mitsubishi Corp , is due to be completed in September and will be fully operational in January

2017 when it produces 36 million gallons daily, according to a document distributed to
shareholders.
The Umm Al Houl power plant, also built by Mitsubishi and with total production capacity of 2,520
MW of electricity and 136.5 million gallons, will come on line in phases between April 2017 and
July 2018, the document said.
Ras Abu Fontas will cost QR1.75 billion ($480.6 million) and will be funded by loans from local
banks, the document said. The cost of Umm Al Houl has already been disclosed at QR10 billion.

Qatargas, Maersk Group, Shell to Promote LNG as Marine Fuel in Middle East
Qatargas, the Maersk Group and Shell signed a Memorandum of Understanding (MoU) to explore
the development of LNG as a marine fuel in the Middle East region.
Through the joint relationship the partners plan to explore the development of new markets for
LNG to be used as propulsion fuel for merchant vessels. The memorandum envisages LNG
supplies for this initiative to be made available from Qatargas 4, a joint venture between Qatar
Petroleum and Shell Gas B.V., with Maersk Line potentially using the fuel for its merchant vessels,
Qatargas said Monday.
The MoU was signed at a
ceremony attended by
Saad Sherida Al-Kaabi,
Chairman of Qatargas
Board of Directors,
Qatargas Chief Executive
Officer, Khalid Bin Khalifa
Al-Thani, the Maersk
Group Chief Executive
Officer, Nils S. Andersen
and Shell International
Trading Middle East
Limited General Manager,
Danny Leek.
“We are very proud to
continue to pioneer new
and novel opportunities to utilize Qatar’s LNG. We are also proud to partner with industry leaders
such as Maersk and Shell to create potential new market opportunities for Qatar’s LNG and, at the
same time, provide ship operators around the globe with a cleaner fuel alternative to the heavy
fuel oils currently in use,” Saad Sherida Al-Kaabi, Chairman of Qatargas Board of Directors, said.
Nils S. Andersen, Maersk Group Chief Executive Officer said the possible use of LNG as fuel for
ships presents an opportunity to reduce both SOx emissions and in reducing the transport sectors
CO2 foot print.
Michiel Kool, Managing Director and Chairman of Qatar Shell Companies added: “LNG fuel is a
new alternative for ship and vessel operators responding to stricter emission control standards.
Shell has been a pioneer in this area with our investments in LNG for transport infrastructure in
Europe and the US, and we look forward to now deploying our expertise to create a regional hub
in the Middle East in collaboration with Qatargas, the largest LNG producer in the world and
Maersk, the world’s largest shipping container company”.

Algeria: Petroceltic commences development drilling on the Ain Tsila
Source: Petroceltic International
AIM listed Petroceltic International has announced the start of development drilling on the Ain
Tsila gas and condensate field in Algeria.
The newly built SINOPEC Rig 50117 arrived on the Isarene permit during November 2015, was
assembled successfully on site, and has now passed acceptance testing. At 18:00 on 21
February 2016 development well AT-10, the first well of the Ain Tsila development drilling
campaign, was spudded.
AT-10 is located in the north of the field approx. 3.4 km from the field discovery well AT-1, and
2.0 km from the appraisal well AT-8; each of these wells delivered gas flow rates in excess of 30
MMSCFD on test.
This vertical well is targeting the Ordovician reservoir formation to a planned total depth of
1,989m MD. AT-10 is the first of up to 24 new development wells on Ain Tsila expected to be
required to establish and maintain the currently approved annual average wet gas plateau rate of
355 MMscfpd.
In addition to the commencement of development drilling, the tender of the major field
Engineering Procurement and Construction ('EPC') contract covering main field facilities and
pipelines is progressing.
Petroceltic holds a 38.25% interest, Sonatrach a 43.375% interest, and Enel an 18.375%
interest in the Isarene PSC. Petroceltic continues to benefit from a carry of its development
costs in respect of Ain Tsila following the completion of the sale of an 18.375% interest to
Sonatrach in July 2014.
Background
Petroceltic was awarded operatorship of the Isarene PSC in April 2005 with a 75% equity interest,
this was subsequently reduced to 56.625% through the divestment of an 18.375% interest to Enel
SpA in early 2012, and reduced further to 38.25% through divestment of a further 18.375% to
Sonatrach in 2014.

After the initial Ain Tsila discovery in 2009, Petroceltic applied for a two year extension period,
from the end of the exploration period in April 2010 through to 26 April 2012, to allow time for the
appraisal of the gas accumulation. During this period, the Group drilled six appraisal wells on the
Ain Tsila structure.
Approved development plan
Following the completion of the appraisal drilling campaign and technical and economic studies, a
full field development plan was submitted to the Algerian authorities and approved in December
2012. The plan envisages the production of 2.1 Tcf of sales gas and 179 MMbbl of liquids
(comprising 69 MMbbl of condensate and 110 MMbbl of liquid petroleum gas or “LPG”) from the
field during the 30 year Production Sharing Contract (“PSC”) exploitation period. The initial plan
will result in a recovery factor of 24% of the Gas Initially in Place (‘GIIP’) in the field and the
Company anticipates that the recovery factor is likely to grow over time with additional well data
and the potential installation of additional gas processing facilities.
The field plateau production rate is forecast to be 355 MMscfpd gross wet gas and the plateau
should last for some 14 years. The development plan involves the drilling and completion of 124
vertical development wells, of which 30 (including 6 existing wells) are scheduled to be available
prior to first production. Along with basic in-field support infrastructure, the facilities will comprise a
gas processing plant with water separation, condensate and LPG recovery equipment, gas
compression, export pumps and metering facilities. The gas will be evacuated via a 95 kilometre
pipeline which will tie into the main Algerian gas transmission network near the Tin Fouye
Tabankort field. Dedicated condensate and LPG export lines will also be constructed to tie into
liquids transmission infrastructure.
The gross project cost prior to first production is expected to be in the region of $1.6 billion with
the majority of the expenditure incurred from 2016 through 2018. The capital estimate and
phasing will be confirmed in more detail after the FEED studies have been completed and EPC
contract awarded in late 2015.
Gas commercialisation
Following the execution of a legally binding Heads of Terms for the Gas Sales Agreement with
Sonatrach in 2012, the comprehensive Gas Sales Agreement detailing operation procedures and
processes required for nominations and payments was signed in September 2014 and approved
by the Algerian Energy Ministry in November 2014.

Liquids
Condensate and stabilised LPG form a significant part of the reserves and revenues from the Ain
Tsila field. Based on data from similar developments, the Company anticipates that both
condensate and LPG will be sold in the local market at a price related to Brent.
Second farm-out
A process to divest an additional 18.375% of Petroceltic’s equity in the Isarene PSC was initiated
in 2012 as part of the Company’s strategy to manage its overall financial and operational
commitment to the Ain Tsila development. In early 2013, Petroceltic agreed a farm-out proposal
from an international oil company and initialled a Sale and Purchase Agreement. However, in July
2013, Sonatrach exercised their right to pre-empt the transaction and acquire the interest on
similar terms.
The agreement to effect the transfer of the interest to Sonatrach was signed in February 2014 and
ratified by the relevant Algerian government authorities in June. The consideration included a
$20m initial cash payment, a cost carry of up to $140m and two potential further $10m payments
contingent on the achievement of certain key project milestones. Petroceltic retained a 38.25%
interest in the project through to first gas.
The farm-out has resulted in a reduction in Petroceltic’s booked proved plus probable reserves
from 300.0 MMboe to 202.7 MMboe, which has been reflected in the Company’s year end 2014
reserves
Isarene concession timeline
2005 Award of Isarene Production Sharing Contract
2006 First exploration drilling of two wells
2008 3D seismic acquisition
2009 Five wells drilled, resulting in the Ain Tsila discovery, the year’s 9th largest worldwide
2010 Two year delineation licence extension awarded
2011 Successful six well drilling campaign
2012
Farm-out of 18.375% interest to Enel
Declaration of Ain Tsila field commerciality
Development Plan and Gas Sales Heads of Terms approval
Award of 30 year exploitation licence
Booking of 304 MMboe of proved plus probable reserves
2013
Formation of joint operating organisation to develop the field
FEED tender issued to market
2014
FEED contract awarded and studies commence
Farm-out of 18.375% interest to Sonatrach
Drilling contracts tendered
2015
Mobilisation of Joint Operating Organisation to Hassi Messaoud
Rig contract awarded
Major project EPC contract to be tendered and awarded
Commencement of development drilling
2016-
2018
Project execution phase including, drilling 24 wells and constructing gas processing plant
and related infrastructure

Groupement Isarene
When the Isarene PSC was awarded in 2005, Petroceltic was qualified as an operator in Algeria.
During the initial exploration and appraisal phase of activity, almost 10,000 km of 2D and 900 sq
km of 3D seismic were shot, processed and interpreted, supporting the drilling and testing of 13
wells and the preparation of a field development plan for the Ain Tsila gas field. Enel joined
Petroceltic as an investor in the field in 2012.
Following approval of that development plan by the Algerian authorities at the end of 2012,
Sonatrach became a paying participant in the exploitation phase in respect of its 25% interest.
Upon commencement of this phase, the responsibility for the execution of petroleum operations
on the Isarene permit passed to a newly constituted Joint Operating Organisation called
‘Groupement Isarene’. This entity was set up in mid-2013 under the control of the PSC parties. It
is financed by monthly cash calls to the Isarene PSC partners and is directed by a management
council with representation of all the PSC parties.
Prior to the constitution of the Groupement Isarene, Petroceltic and Sonatrach negotiated the
organisational structure and the allocation of positions between the parties, and, through the
course of 2013, Petroceltic redeployed or recruited more than 50 experienced professionals on
behalf of itself and Enel to take up these positions, primarily in management, supervisory, finance
and technical roles. These secondees are located alongside their Sonatrach counterparts in the
Groupement offices in Hassi Messaoud (the oil and gas operating and logistical centre of Algeria).
Through 2014, the Groupement project team concentrated on the preparation of the contract
tender packages for the Ain Tsila production facilities and infrastructure FEED and development
drilling. The FEED contract was awarded to Chicago Bridge & Iron BV in the Netherlands, and the
drilling rig contract was awarded in 2015, to Sinopec International Petroleum Services
Corporation.
In 2015, the development operations will ramp up with the preparation of the tenders for the main
production facilities construction packages, the award of those construction packages, and the
commencement of drilling. In the Ain Tsila field, a forward operations base and basic infrastructure
will be constructed, allowing for the mobilisation of drilling rigs and construction crews in the
second half of 2015. This will ensure that the required number of wells are available to be hooked
up for production at first gas in Q4 2018.
In line with other operators in Algeria, the Company has prepared and issued a Development
Security Philosophy to ensure appropriate security controls for all in-country activities. The FEED
study will address a number of these critical controls – physical, procedural, organisational – and
ensure that best practice is designed and engineered into all aspects of construction and
subsequent operation of the project facilities.

Pakistan: Jura Announces gas discovery in Badin IV South
Jura + EINPresswire + NewBase
Jura Energy Corporation ("Jura") today announced a potential gas discovery at the Aminah-1
exploration well in the Badin IV South block.
Jura holds a 27.5% working interest in the Badin IV South block, which is operated by Petroleum
Exploration (Private) Limited ("PEL"). At the present time, PEL has not provided drilling depth,
testing results or other status information with regard to the drilling of Aminah-1 directly to Jura,
and Jura has not independently verified the discovery.
From time to time, Jura has been involved in various legal or administrative proceedings involving
PEL. At present, Jura and PEL are in dispute with regard to, among other things, a past cash call
for the Badin IV South block pursuant to which PEL has commenced proceedings with the
Government of Pakistan to attempt the forfeiture of Jura's working interest in the Badin IV South
block.
Jura and the other non-operated working interest holder challenged the validity of the cash call,
which was in any event paid. Jura disputes the claim by PEL that Jura is in default under the
Badin IV South joint operating agreement and that Jura's working interest in the block is validly
subject to forfeiture.
Jura will vigorously defend its interest in the Badin IV South block and further information with
regard to the potential discovery as well as the proceedings with PEL will follow in due course.

Indonesia: Oil and gas investors return 15 exploration blocks to regulator
Source: Reuters
Oil and gas investors relinquished 15 exploration blocks to the Indonesian government in 2015,
nearly double those they returned the previous year, according to the country's energy regulator,
amid low oil prices and slowing global demand growth.
Indonesia's energy sector has seen a string of production curbs and asset cuts in recent months,
with companies reeling from crude prices that have improved little since hitting a 12-year low in Jan.
Energy production is an important source of Indonesia's state revenues, and many of the big
fields that have propped up its budget in recent decades are declining, with low oil prices limiting
the prospect of increased recovery or finding new sources.
Oil and gas companies lost $820 million on exploration and other costs for the 15 blocks handed
back to the government last year, Amien Sunaryadi, chairman of the upstream oil and gas
regulator (SKKMigas), told a parliament hearing on Monday.
Companies usually hand back exploration assets when either they have made no discoveries or
the prospect of extracting reserves from them is seen as uneconomical. Under Indonesian law
companies can only begin to recover costs once oil and gas blocks start producing.
No company names were given in the presentation to parliament on Monday. The amount lost in
2015 is almost three times as much as the $283 million spent on eight blocks relinquished by
contractors in 2014, Sunaryadi said, and nearly double the $456 million spent on the five blocks
that were relinquished in 2013.
Indonesia's top crude producer, Chevron Corp, announced last month it would not extend its
contract to operate the East Kalimantan oil and gas block, after revealing plans in December to
sell its stake in the South Natuna Sea Block B.
Output from Southeast Asia's biggest crude producer has been declining steadily from just above
1.6 million barrels per day (bpd) in the mid-1990s, and could slip to 753,400 bpd this year from
779,000 bpd in 2015 if oil prices hit $20 per barrel, the regulator said earlier this month.
Oil prices jumped higher on Monday following steep losses in the previous session, supported by
a fall in the U.S. rig count, but analysts said oversupply was still capping the market.

UK Output Could Halve By 2025 If Money Dries Up
Reuters
British oil and gas production could halve by 2025 if oil companies do not spend enough to
squeeze every last drop out the North Sea, industry group Oil and Gas UK warned on Tuesday.
Oil and gas companies, including former North Sea heavyweights BP, Shell and Statoil, have
slashed their budgets by billions of dollars as they grapple with a 70 percent fall in oil prices.
Britain, one of the oldest oil and gas basins, has been hit especially hard as low revenue
prospects are coupled with some of the world's highest exploration and production costs.
New investments in the UK
Continental Shelf, Britain's offshore
oil and gas production area, are
expected to sink to less than 1 billion
pounds ($1.4 billion) this year,
compared with an annual average of
8 billion pounds over the past years.
"The outlook where we're seeing little
fresh investment coming is the scary
bit in all of it," Mike Tholen, Oil and
Gas UK's economic director and
author of its annual report, told
Reuters. "We're a very simple
industry: if you don't keep investing,
you're not likely to see a good future
in the North Sea."
The British government last year cut
oil and gas taxes to prevent
companies from leaving the North
Sea and established a dedicated oil
regulator to help them maximise
output.
Oil and Gas UK said more tax relief is needed in next month's annual budget to ensure
companies continue investing, echoing demands from the Scottish government, whose economy
is heavily oil and gas dependent.
The oil price fall has accelerated the permanent shutdown of some fields, with 21 ceasing
production in 2015, and Oil and Gas UK said as many as 80 could follow by the end of 2020.
Almost half of Britain's oil and gas fields will be loss-making this year if oil prices remain at
current levels around $30 a barrel, the lobby group said.
"Were a number of these fields to cease production, their interconnectivity would mean many
more could become sub-commercial, known as the 'domino effect'," the report said. As oil prices
are expected to remain weak, the group expects more job losses in the sector this year after a
fall of around in employment in 2015.

Chancellor urged to use budget to support ailing North Sea oil industry
Key oil industry figures have called on the chancellor to use next month’s budget to prop up the
North Sea oil industry after a collapse in investment.
The trade body Oil & Gas UK called for permanent tax breaks, warning that low Brent crude prices
were choking off the investment needed to extract the oil left under the North Sea.
It expects cash-strapped members to spend just £1bn on new projects this year, compared with
an annual average of £8bn over the past five years.
It came as the International Energy Agency warned that investment cuts worldwide meant that
when prices start to rise – as it expects in 2017 – they are likely to jump sharply.
Fatih Birol, executive director of the IEA, said: “It is easy for consumers to be lulled into
complacency by ample stocks and low prices today, but they should heed the writing on the wall:
the historic investment cuts we are seeing raise the odds of unpleasant oil-security surprises in
the not too distant future.”
The agency forecast that global oil supply would grow by 4.1m barrels a day between 2015 and
2021; in the previous six years it grew by 11m barrels a day.
Oil & Gas UK said the North Sea firms had tried ensure the industry stayed afloat by slashing
costs. It said oil explorers on the UK continental shelf cut the cost of production by 40% from an
average $29.30 a barrel in 2014 to $20.95 last year.
But the oil price has tumbled by about 70% – or more than $100 a barrel – since the summer of
2014, wiping out the effect of the cost-cutting drive.
Oil & Gas UK said that while firms could make further cuts, they would struggle to afford
investment with oil hovering at about $30 a barrel. It called for urgent changes to the taxes paid by
North Sea companies, warning of heightened fears over the long-term future of the industry.

Oil companies were handed tax relief last year when George Osborne reduced their rate to 50%,
or up to 67.5% on some fields where petroleum revenue tax also applies. But Oil & Gas UK said
the chancellor must go further or risk seeing the North Sea’s decline accelerate, adding to job
losses in the industry. “A significant, permanent reduction in those rates is now urgently needed,”
said Oil & Gas UK’s chief executive, Deirdre Michie.
The trade body pointed to the potential impact of a shrinking oil industry on the wider economy. It
said total capital expenditure fell from £14.8bn to £11.6bn last year and predicted it would drop
further, to £9bn this year.
A study by Rystad Energy found that the supply chain serving the North Sea shrank by about 25%
last year and was expected to contract further this year. The increasing difficulty of making money
in the North Sea is also speeding up decommissioning, where companies shut down oilfields that
are no longer economically viable.
This has seen reserves held by companies for future development fall from 10bn to 8.8bn barrels
of oil, compared with Oil & Gas UK’s estimate of 20bn barrels remaining overall. The trade body
believes that decommissioning will cost up to £55bn by 2050, while Revenue & Customs
estimates that the taxpayer will pick up £16bn of the bill through tax relief on decommissioning.
Oil & Gas UK warned that “the pace of decommissioning is accelerating”, indicating that the cost
of dismantling old oil platforms and cleaning up after them could rise still further.
The accelerating decline of the North Sea is forecast to punch a hole in the UK’s tax take, even as
Osborne battles to erase the deficit. The Office for Budget Responsibility predicts receipts
of £130m from the North Sea in 2015-16, compared with £11bn four years previously.

US: Pipelines, tankers, and barges convey transportation fuels
from Gulf Coast to East Coast
Source: U.S. Energy Information Administration, PADDs 1 and 3 Transportation Fuels Markets
In the United States, the East Coast and Gulf Coast are highly dependent on each other to
balance supply and consumption of transportation fuels (mainly gasoline, diesel, and jet fuel). East
Coast transportation fuels consumption is met through a number of supply sources, but none is
more important than supply from the Gulf Coast. Conversely, surplus supply in the Gulf Coast is
distributed to a number of domestic and foreign markets, but none is larger than the East Coast.
EIA has commissioned studies of transportation fuels supply, consumption, and distribution in
certain regions of the country, as defined by Petroleum Administration for Defense Districts
(PADDs). The most recent study involves the East Coast and Gulf Coast regions and nine sub-
PADD regions: four in the East Coast and five in the Gulf Coast.

Two pipelines, the Colonial Pipeline and the Plantation Pipeline, typically operate at or near full
capacity and in 2014 moved approximately 2.3 million barrels per day (b/d) of transportation fuels
from the Gulf Coast to the East Coast. The Colonial system consists of 5,500 pipeline-miles and
has connections to 29 refineries and 267 customer terminals. The Plantation system consists of
3,100 pipeline-miles and 36 pumping stations and has connections to 90 terminals at 34 delivery
locations.
An additional 0.5 million b/d of transportation fuel is shipped from the Gulf Coast to the East Coast
by coastwise-compliant tankers and barges, primarily to ports in Florida. Together, net pipeline
and waterborne shipments from the Gulf Coast to delivery points in the East Coast are equal to
58% of East Coast consumption and 37% of Gulf Coast supply.
Waterborne movements—both coastwise and internal river movements—connect supply and
consumption centers between and within the Gulf Coast and East Coast regions. The Gulf Coast
region, particularly the areas of Texas and Louisiana near the coast, is characterized by large
outbound shipments of products primarily delivered to markets in the East Coast (especially
Florida) and to export destinations, but also to coastal and riverine markets in other areas of the
Gulf Coast as well as the Midwest.
More information on East Coast and Gulf Coast transportation fuels markets is available in PADDs
1 and 3 Transportation Fuels Markets. An earlier study evaluated transportation fuel markets in
the Pacific Coast region (PADD 5).

NewBase 23 February 2016 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil dips as rising Iranian output to counter falling U.S. shale production
Reuetrs = NewBase
Oil prices dipped slightly in early trading on Tuesday after posting strong gains the previous
session on the back of an expected drop in U.S. production, but which analysts expect to be
countered by rising output from Iran.
U.S. front-month West Texas Intermediate (WTI) crude futures, were trading at $33.10 per barrel
at 0118 GMT, down 29 cents from their last settlement. International benchmark Brent was down
21 cents at $34.48 a barrel.
Tuesday's dips came after strong gains in the previous session on the back of an expected fall in
U.S. oil production this year. Production of shale oil is expected to drop by 600,000 barrels per
day (bpd) this year and a further 200,000 bpd in 2017, according to the International Energy
Agency (IEA).
"Crude supply growth from Iran will more than compensate for any decline in U.S. output," ANZ
said. The IEA said that in the longer term, U.S. production would also recover thanks to improving
cost efficiency, lifting output to a record 14.2 million bpd by 2021, compared with a peak of over
9.5 million bpd in 2015.
The expected resurgence of U.S. shale oil production will cap a recovery in the coming years in
the price of oil, which is expected to reach $80 per barrel by 2020, IEA Director Fatih Birol said at
a news conference in Houston, Texas.
Oil price special
coverage

IEA warns against complacency over ‘ample’ oil stocks
The National - LeAnne Graves + NewBase
The oil market is resembling the 1980s as the International Energy Agency (IEA) forecasts lower
investments and no short-term price recovery.
The IEA released its five-year outlook that forecasts 4.1 million barrels per day added to the global
oil supply from 2015 to 2021, which is more than a 60 per cent decrease from the previous outlook
from 2009 to 2015.
This has signaled to a fall in capital expenditures with a 17 per cent drop this year on top of last
year’s 24 per cent cut. This is the first time in three decades that the industry investments have
shrunk for two consecutive years.
“It is easy for consumers to be lulled into complacency by ample stocks and low prices today, but
they should heed the writing on the wall: the historic investment cuts we are seeing raise the odds
of unpleasant oil security surprises in the not-too-distant-future,” said Fatih Birol, the IEA’s
executive director, launching the report at IHS CeraWeek, the energy conference held annually in
Houston.
While supply may decrease as a result of declining investments, the US shale revolution is not
expected to dry up any time soon. The IEA suggests a short-term reduction, with a revival only
likely to come from greater operational efficiencies.
“But at the risk of tempting fate, we must say that today’s oil market conditions do not suggest that
prices can recover sharply in the immediate future – unless, of course, there is a major
geopolitical event,” said the IEA.
Sebastien Henin, the senior vice president of Abu Dhabi-based advisory firm The National
Investor, said the report stated the obvious. “It’s nothing new. Demand is still robust. The
oversupply is here for the entire year and the market should be balanced next year,” he said.
Global oil glut to persist, limit price rebound

The global oil glut will persist into 2017, limiting any chance of a price rebound in the short term as
the surplus takes even longer to clear than previously estimated, according to the International
Energy Agency.
While US shale oil production will retreat this year and next as the price slump hits drilling, its
subsequent recovery will ensure America remains the biggest source of new supply to 2021. The
Organization of Petroleum Exporting Countries will expand its market share slightly this decade,
with Iran, newly released from international sanctions, displacing Iraq as the organisation’s biggest
contributor to supply growth.
“Only in 2017 will we finally see oil supply and demand aligned but the enormous stocks being
accumulated will act as a dampener on the pace of recovery in oil prices,” the Paris-based adviser
to 29 countries said in its medium-term report yesterday. “It is hard to see oil prices recovering
significantly in the short term from the low levels prevailing.”
The IEA’s new outlook is the latest sign that oil forecasters are bracing for a “lower-for-longer”
price environment. The agency acknowledged that the industry’s expectations - and its own
predictions - that oil markets would recover in 2015 proved “very wide of the mark.” The report
also signals that while Opec will succeed in its policy of defending market share, the group will
have to endure an extended period of reduced revenues.
Oil futures have sunk by 42% in the past year as the global surplus was prolonged by resilient US
crude production, increased supply from key Opec members and slowing economic growth in
China.
After declining this year, supply from outside Opec will remain stable in 2017 and recover in 2018,
growing by 2mn barrels in the six years to 2021 to reach 59.7mn bpd. Prices won’t need to
rebound to $100 a barrel to finance that new output, the agency said.
While US production of shale oil, also known as light-tight oil (LTO), is projected to retreat by
600,000 bpd this year and a further 200,000 a day in 2017, it will still expand during the period as
a whole as growth resumes. Total US liquids output will increase by 1.3mn bpd by from 2015 to
2021 as drillers lower costs and improve efficiency.
“Anybody who believes that we have seen the last of rising LTO production in the US should think
again,” the IEA said.
The agency increased estimates for global oil demand each year to 2020, mostly as a result of
revisions to historical or “baseline” data. The estimate for annual growth in world fuel consumption
remains at a “very solid” average of 1.2% through to 2021, when it will reach 101.6mn barrels a
day.
As a result of the increase in demand and weaker growth in supply, Opec’s share of the total
market for crude will reach 33.8% in 2020, up from last year’s projection of 32.4%. The amount of
crude required from exporters’ group will expand to 34.8mn bpd by 2021, compared with
production of 32.1mn last year, the IEA said.
Much of the boost in Opec supply will come from existing facilities, with the organization set to add
only 800,000 bpd of new capacity in the period to 2021 as members outside the low-cost Middle
East struggle to grow. Capacity will stagnate or shrink slightly in Algeria, Angola, Ecuador,
Indonesia, Nigeria, Qatar and Venezuela.

Over the longer term, sharp cutbacks in investment leave global supplies exposed to “unpleasant
oil-security surprises in the not-too-distance future,” according to the IEA.
Spending on new output will fall by 17% in 2016 after a 24% collapse last year, mostly in the US
As a result of the cuts, the agency lowered its estimates for non-Opec supply for each year except
2016, with Russian supply set to suffer the steepest decline in the period.
“It is very tempting, but also very dangerous, to declare that we are in a new era of lower oil
prices,” the agency said. “The risk of a sharp oil price rise towards the later part of our forecast
arising from insufficient investment is as potentially destabilising as the sharp oil price fall has
proved to be.”
NewBase Special Coverage
News Agencies News Release 23 February 2016

Apart from oil, Ecuador also exports bananas, shrimp, coffee, cocoa, cut flowers and fish. The country is a haven for many exotic
animals and birds like the blue footed booby, and the orange iguana, both of which can be found in the Galapagos Islands.
Ecuador’s President is HE Economista Rafael Correa Delgado. The country joined OPEC in 1973. Nineteen years later, in 1992, it
voluntarily suspended its membership. It resumed membership of the Organization in 2007.
Did you know?
• Ecuador’s capital city Quito was declared a World Heritage Site by UNESCO in the 1970s for having the best preserved
and least altered historic centre in Latin America.
• Located in the Santa Elena Peninsula, Ancon 1 is Ecuador’s first productive oil well. It began producing oil in 1921.
Population (million inhabitants) 16.027
Land area (1,000 sq km) 284
Population density (inhabitants per sq km) 65
GDP per capita ($) 6,308
GDP at market prices (million $) 101,094
Value of exports (million $) 26,604
Value of petroleum exports (million $) 11,401
Current account balance (million $) 718
Proven crude oil reserves (million barrels) 8,273
Proven natural gas reserves (billion cu. m.) 11.00
Crude oil production (1,000 b/d) 557
Marketed production of natural gas (million cu. m.) 578
Refinery capacity (1,000 b/cd) 191
Output of refined petroleum products (1,000 b/d) 201.0
Oil demand (1,000 b/d) 281
Crude oil exports (1,000 b/d) 422
Exports of petroleum products (1,000 b/d) 8.0

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 23 February 2016 K. Al Awadi

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