New base 721 special 04 november 2015

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 04 November 2015 - Issue No. 721 Edited & Produced by: Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
MENA power contracts total $65 bn in 12 month
Oman Observer ( imgaes by NewBase)
Major power contracts worth over $65 billion were awarded throughout the MENA region between
September 2014 and September 2015, according to MENA Power 2016 — the latest market
intelligence report from MEED Insight.
More than 22 per cent of these contracts are represented by the Gulf Cooperation Council (GCC)
states. Approximately 87 per cent of the total power investments have been channelled into
generation projects and the remaining 13 per cent into transmission systems and distribution
systems.
The report estimates that installed generating capacity across the 14 countries analysed needs to
rise by 143,221MW by 2020, an increase of about 50 per cent on the current level, to meet
demand forecasts.
Author of report, Andrew Roscoe, MEED’s Power & Water Editor explained: “While several
governments have taken steps to reform subsidies in an attempt to curb consumption in the wake
of lower oil prices and rising subsidy bills, there can be no let-up in the drive to build new capacity
to cope with the additional demand and restore reserve margins to at least 15 per cent.”

Key factors driving up the demand for power include robust industrial growth, rise in population
and increase in housing and essential infrastructure investments across various sectors. In the
GCC, peak demand growth averaged 8.4 per cent in 2014, while for the entire MENA it was
slightly higher at more than 9 per cent.
Looking ahead, the largest requirement for power will be in Egypt, where an estimated 27,985MW
of new capacity is needed as a result of its fast growing population. While Saudi Arabia and
Kuwait will require additional capacity of 20,239MW and 5,758MW respectively, the actual new
build requirement will be much higher because of the need to replace or upgrade existing units on
account of age.
“With some of the region’s governments facing the prospect of doubling generation capacity by
2020, a key challenge will be securing financing to cover the significant investment required,” says
Roscoe. “Governments are increasingly looking to the private sector to share the burden of the
billions of dollars of capital investment needed.”
As discussed in the report, faced with a shortage of readily available gas supplies, governments
are turning to alternative energy to bolster capacity-building programmes.
The GCC’s first nuclear power plant is nearing completion in Abu Dhabi, with Egypt, Jordan and
Saudi Arabia also planning major nuclear power programmes. Dubai and Egypt are set to join
Morocco in adding coal-fired power plants to their generation mix, while Jordan is exploring oil
shale as an option.
A key feature of the report is the emergence of renewable energy into the region’s power sector.
“The year 2015 will be remembered as the year renewables finally made a breakthrough on a
large-scale in the MENA region,” says Roscoe.
In January 2015, Dubai propelled itself onto the global stage with the award of a contract to Saudi
Arabia’s Acwa Power to develop a 200MW project at its Mohammed bin Rashid al Maktoum Solar
Park. What makes the deal of particular significance, other than its size, is that the tariff price of
5.85$cents a kWh is the lowest ever for a large-scale photovoltaic solar project in the world. Dubai
quickly followed this up with a tender for an 800MW solar PV contract.

GCC: Oil demand rose 9% a year since 1973 across GCC
Gulf Times + NewBase
Oil demand has risen across the Gulf Cooperation Council by an average of 9% a year since
1973, growing faster than GDP (gross domestic product), on average, according to The Abdullah
Bin Hamad Al Attiyah Foundation for Energy & Sustainable Development.
The aggregate oil consumption in the six GCC States was less than 500,000 bpd in 1973 and
more than 4mn bpd in 2014.
Although power demand has been problematic in all GCC countries outside Qatar, Saudi Arabia
and Kuwait face highest pressure because of their reliance on liquid fuels – crude oil, heavy fuel
oil and diesel fuel – for most of their power generation feedstock.
Hence, while oil consumption in the remaining GCC states is weighted more heavily toward the
transport sector – where oil is considered most valuable – burning of liquid fuels for power
generation is still dominant in Saudi Arabia and Kuwait.
Saudi Arabia consumed more than a quarter of its overall production in 2013. Direct burn of crude
oil for power generation reached an average of 0.7mn bpd from 2009 to 2013 during the months
of June to September, with peak month power sector consumption rising as high as 900,000 bpd.
While Kuwait is gradually shifting toward natural gas via imported LNG (liquefied natural gas),
Saudi crude burning looks set to top 1mn bpd by 2020. Low domestic prices for crude oil –
roughly $5 a barrel in Saudi Arabia – are a major factor encouraging crude oil demand, the Al
Attiyah Foundation said in its inaugural industry report.

Intensifying domestic crude burning coupled with a 1.4mn bpd increase in crude shipments to
Aramco refineries inside and outside the kingdom signal that Saudi Arabia is moving beyond its
long-held role as the world’s market-balancing supplier of crude oil.
Recent data show slipping Saudi crude exports, alongside flat or rising production. Assuming that
Saudi crude production remains constant at around 10mn bpd, the amount of crude available for
export could fall below 5mn bpd by 2020. The GCC also holds major reserves of natural gas, but,
in contrast with oil, most production is consumed domestically. Only Qatar is a major exporter.
The UAE and Kuwait have been net gas importers since 2008. The region has no gas market
pricing mechanism, such as an index based on trade at a hub. In similar fashion to the electricity
sector, low prices (of around $1 to $2 per MMBtu) are driving demand.
But underpricing is also stifling production from known reserves – some of which are comprised of
high-cost non-associated gas – which has encouraged imports. Despite these difficulties, the US
Energy Information Administration (EIA) projects that gas consumption in the Middle East’s
generating sector will grow by nearly 150% by 2035.
In Oman, rising domestic demand and depleting conventional gas reserves have forced
reductions in LNG exports. Unconventional reserves are under development, but lifting costs are
expected to run beyond the state-fixed selling price for bulk gas.
In Saudi Arabia, a $9bn gas investment campaign aims to slow the growth of crude oil and diesel
in the power sector by substituting with gas. Saudi Aramco hopes to increase gas output by 50%
above 2011 production of 280MMcm/day, but, like Oman, most of its non-associated reserves
consist of difficult formations.

Mozambique: Sasol, Partners Awarded Two Licences
Sasol and partners were awarded two licences in Mozambique’s fifth licensing round.
Sasol (70 percent interest, operator) and ENH, Mozambique’s state oil company (30 percent
carried interest), were awarded the onshore
Area PT5-C, which is 3,012 square
kilometres, adjacent to the Pande and
Temane fields, the South African firm said
last week.
The other successful bid was for Area A5-A,
which is 5,145 square kilometres, situated in
the offshore Angoche basin. In this block, Eni
will act as operator (34% percent), with Sasol
and Statoil holding 25.5 percent each and
ENH holding a 15 percent carried stake.
“Together with our bid partners,
we welcome the opportunity to
further participate in the growth
and development of Mozambique,
the heartland of our upstream
operations. The country has been,
and continues to be, a strategic
partner for Sasol,” said David
Constable, President and Chief
Executive Officer, Sasol Limited.
The Institute of National
Petroleum of Mozambique (INP)
last Tuesday announced the
results of the fifth competitive
bidding round for Exploration and
Production Concession
Contracts.
The f ifth round commenced on
the 23rd October 2015 and
companies had nine months to
evaluate the available technical
data and formulate their
applications. The round followed
a competitive bid process that
evaluated the bids on defined
published criteria which included
Health Safety and Environmental
(HSE), financial strength,
technical competence / capability
and the economic terms offered to
the Mozambican government, INP stated.

UK: Statoil to build the world’s first floating wind farm -
Hywind Scotland. Statoil
Statoil has made the final investment decision to build the world’s first floating wind farm: The
Hywind pilot park offshore Peterhead in Aberdeenshire, Scotland.
This marks an important step forward for offshore wind technology, and potentially opens
attractive new markets for renewable energy production worldwide. The decision triggers
investments of around NOK 2 billion, realizing a 60-70 percent cost reduction per MW from the
Hywind demo project in Norway.
Statoil will install a 30 MW wind turbine farm on floating structures at Buchan Deep, 25 km
offshore Peterhead, harnessing Scottish wind resources to provide renewable energy to the
mainland. The wind farm will power around 20,000 households. Production start is expected in
late 2017.
'Statoil is proud to develop the world’s first floa ting wind farm. Our objective with the Hywind pilot
park is to demonstrate the feasibility of future commercial, utility-scale floating wind farms. This
will further increase the global market potential for offshore wind energy, contributing to realising
our ambition of profitable growth in renewable energy and other low-carbon solutions,' says Irene
Rummelhoff, Statoil’s executive vice president for New Energy Solutions.

The pilot park will cover around 4 sq kms, at a water depth of 95-120 metres. The average wind
speed in this area of the North Sea is around 10 metres per second.
Rummelhoff adds: 'We are
very pleased to develop this
project in Scotland, in a region
with a huge wind resource and
an experienced supply chain
from oil and gas. Through
industry and supportive
policies, the UK and Scotland is
taking a position at the forefront
of developing offshore wind as
a competitive new energy
source.'
Welcoming Statoil’s Hywind
development, Scotland’s
Deputy First Minister John
Swinney says: 'Hywind is a
hugely exciting project – in
terms of electricity generation
and technology innovation –
and it’s a real testament to our
energy sector expertise and
skilled workforce that Statoil
chose Scotland for the world’s
largest floating wind farm.'
'The momentum is building around the potential for floating offshore wind technology to unlock
deeper water sites. The ability to leverage existing infrastructure and supply chain capabilities
from the offshore oil and gas industry create the ideal conditions to position Scotland as a world
leader in floating wind technology,” he adds.
The British Energy and Climate Change Secretary, Amber Rudd says: 'This is fantastic news for
Scotland and the whole of the UK, demonstrating that we are open for business and that the UK’s
offshore wind industry continues to go from strength to strength.'
'This exciting project is a great example of how innovation can help to power our homes and add
to our energy mix – offering clean, secure energy to Britain’s hardworking families and
businesses,' she adds.
Statoil works with several Scottish suppliers and partners on the project. The project will provide
additional work for industry in Scotland and other countries. The onshore operation and
maintenance base will be located in Peterhead, also drawing on resources from Statoil’s existing
office in Aberdeen.
Hywind is a unique offshore wind technology developed and owned by Statoil. The concept has
been verified through six years of successful operation of a prototype installed off the island of
Karmøy in Norway. Hywind with its simplicity in design is competitive towards other floating
designs in water depths of more than 100 metres.

New Energy Solutions for the global market
In May, Statoil announced the establishment of New Energy Solutions as a separate business
area reporting to the CEO, reflecting the company’s aspirations to gradually complement its oil
and gas portfolio with profitable renewable energy and low-carbon solutions. As a starting point
Statoil’s existing offshore wind portfolio constitutes the activities in this area. Hywind Scotland is
the business area’s first new investment.
Offshore wind already has a strong foothold in Europe with 10 GW installed capacity, and a global
potential to reach more than 100 GW by 2030. With fixed turbines, offshore wind is optimal for 20-
50 metres water depth. With floating structures, further expansion will be enabled in new deep-
water areas around the world.
Key energy partner to the United Kingdom
Statoil is a key energy security partner for the UK and pursues a broad range of activities relating
to energy production and sales in Britain. Statoil is a leading supplier of natural gas to the British
market, with a market share around 20 percent. The company is also active on the UK Continental
Shelf, including the development of the Mariner oil field, operatorship for the Bressay project and
holding several exploration licences. Statoil’s Global Strategy and Business Development division
is based in London.
Statoil was the operator in the development phase for the 88 turbine Sheringham Shoal offshore
Wind Farm, 20 kilometres off the coast of Norfolk. Sheringham Shoal started producing in 2012.
The same year Statoil and Statkraft acquired the nearby Dudgeon offshore wind farm project.
Statoil is also partner in the Dogger Bank offshore wind project. In combination, Statoil’s UK
offshore wind business has the long term potential to provide competitive low carbon electricity to
around 4.5 million UK homes.
88 turbine Sheringham Shoal offshore Wind Farm

U.S. oil refiners look abroad for crude supplies as North
Dakota boom fades . REUTERS - JARRETT RENSHAW
PBF Energy Inc, one of the largest independent oil refiners in the United States, spent heavily in
recent years to build the rail terminals at its Delaware City complex that it needed to take delivery
of large loads of crude coming from North Dakota's Bakken oil fields.
But now it is considering eliminating those deliveries altogether, and replacing them with foreign
crude imports, according to two sources familiar with the situation. It has even closed its small
Oklahoma City office that was only opened in 2013 and had served as a hub for the company's
trading in North Dakota's oil, the sources said.
Gasoline-making unit at a PBF Energy Inc refinery in Delaware City, Delaware August 21, 2015.
The sudden lack of interest in Bakken crude by PBF, which is run by Thomas O'Malley, one of the
biggest names in the U.S. oil refining industry, reflects a dramatic recent change in the way East
Coast refineries are sourcing the crude that they turn into everything from gasoline to heating oil
and jet fuel.
The boom in the output of oil from North Dakota's shale has ebbed as producers have begun to
cut back in the face of the plunge in prices by nearly 60 percent since the summer of 2014.
North Dakota's Bakken production peaked at 1.153 million barrels per day in June, and had fallen
to 1.13 million barrels per day by August, according to state data.

The supply restraint has made Bakken crude relatively more expensive after transport costs than
oil shipped from Latin America, the Middle East and Africa, prompting East Coast refiners to return
to a foreign crude diet they derided as unprofitable five years ago.
Three companies that resuscitated failing oil refineries on the East Coast less than five years ago
with the promise of cheap domestic oil are now looking overseas instead, four sources familiar
with the plans told Reuters.
Together, PBF, Philadelphia Energy Solutions Inc and Delta Airline's Monroe Energy are expected
to cut their Bakken crude intake to the lowest levels since 2013, according to two oil traders who
are familiar with East Coast rail arrangements.
PES, which bought a 335,000 barrel-a-day Philadelphia refinery that was slated for closure in
2012, has slashed its Bakken deliveries to just 17 trains in November from a peak of 100 trains a
month during the summer, according to two sources familiar with the plant's operations.
The planned deliveries mark the lowest monthly volume since the company built a new rail
terminal to take advantage of the Bakken revolution. EIA data shows PES imported more than
double the amount between January and July, with cargoes from Nigeria, Chad and Azerbaijan.
LOCKED INTO PAYING
The price of Bakken hasn't fallen as much as other oil, nearly wiping out the entire $6 a barrel
discount to the U.S. benchmark that it traded at in January and sending refiners scrambling for
other sources. Meanwhile, a glut of other crudes has made importing - including transport costs of
$2 to $3 a barrel - much more attractive.
Because bringing crude by rail from North Dakota to an East Coast refinery usually costs about
$10 to $11 a barrel, without a deep discount for the oil, moving it across the country becomes
unprofitable. As a result, Bakken crude is used in the U.S. Midwest and Canada where lower
transportation costs make it a profitable option.
East Coast refineries accounted for about 10 percent of nationwide imports of crude in July,
according to the latest data from the U.S. Energy Information Administration. That is expected to
rise as the Bakken shipments fall further, analysts and traders say.
PBF had poured over $50 million into upgrading its Delaware City rail terminal and signed long-
term volume commitments to unload at least 85,000 barrels per day from trains at a fixed $2 a
barrel cost, regardless of whether it takes the oil. As a result, the company is locked into paying
$170,000 a day.
In a conference call late last week, PBF disclosed that it is only budgeting to take 25,000 barrels a
day of Bakken oil delivered by rail at its East Coast refineries in 2016.
The company's spokesman Michael Karlovich said in an email that the company was transferring
its single employee in the Oklahoma office to its headquarters in New Jersey, but declined to
provide additional detail about the company's Bakken strategy.
PBF's Delaware City refinery imported about twice as much crude in July as in January, bringing
in cargoes from Colombia and Peru, according to data from the U.S. Energy Information

Administration. The company's Paulsboro, New Jersey, refinery increased its imports by 50
percent in the same period. PES declined to comment on the shifting crude slate, while Monroe
Energy did not respond to requests for comment.
The refiners had previously found that relying on crude from the likes of Colombia, Mexico and
Saudi Arabia was unprofitable. But now it may be different provided Bakken crude remains
relatively expensive and the U.S. economy doesn't head into a downturn.
That's because the refiners are buoyed by increased U.S. fuel demand, partly because of the low
oil prices. In 2010, demand was shrinking.
Additionally, they are supported by the closure of underperforming refineries in the Atlantic Basin
during the last downturn. And then there is the current availability of deeply discounted crude oil
from overseas.
"They are looking for the lowest cost supplies," said Sandy Fielden, an analyst with RBN Energy.
"A few years ago, that was North Dakota, but not today."

NewBase 04 November - 2015 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil prices slide on profit-taking, but supply risks support
Reuters + NewBAse
Oil prices slipped in thin trading on Wednesday as investors took profits from the previous
session's rally, while potential supply disruptions in the United States, Brazil and Libya curbed
losses.
Brent futures for December delivery had fallen 4 cents to $50.50 at barrel by 0215 GMT, after
ending the last session up $1.75, or 3.6 percent. U.S. crude for December delivery dropped 2
cents to $47.88 a barrel, after closing up $1.76, or 3.8 percent. Earlier on Wednesday, it hit its
highest since Oct. 13 at $48.36.
While there were no major supply disruptions, a strike at Brazil's state-run oil producer Petroleo
Brasileiro and the closure of the Libyan oil export terminal at Zueitina provided some support to
prices, McCarthy said.
The Petrobras strike, which has slowed daily oil output by around 25 percent in the world's ninth
biggest oil producer, helped fuel the rally in prices in the previous session.
Crude stocks rose by an estimated 2.8 million barrels in the week to Oct. 30 to 479.9 million, data
from industry group the American Petroleum Institute showed on Tuesday. Official inventory data
from the U.S. Department of Energy's Energy Information Administration will be released later on
Wednesday.
Oil price special
coverage

NewBase Special Coverage
News Agencies News Release 04 Nov.. 2015
When a 127-Year-Old U.S. Industry Collapses Under China's Weight
Bloomberg - Joe Deaux
Alcoa Inc.’s latest aluminum-making cutback is signaling the end of the iconic American industry.
For 127 years, the New York-based company has been churning out the lightweight metal used in
everything from beverage cans to airplanes, once making it a symbol of U.S. industrial might.
Now, with prices languishing near six-year lows, it’s wiping out almost a third of domestic
operating capacity, Harbor Intelligence estimates. If prices don’t recover, the researcher predicts
almost all U.S. smelting plants will close by next year.
While that’s a big deal for the U.S. industry and the people it employs, it doesn’t mean much for
global supplies. Alcoa’s decision to eliminate 503,000 metric tons of smelting capacity accounts
for about 31 percent of the U.S. total for primary aluminum, but less than one percent of the global
total, according to Harbor.
For more than a decade, output has been moving to where it’s cheaper to produce: Russia, the
Middle East and China. A global glut has driven prices down by 27 percent in the past year,
rendering American operations unprofitable and accelerating the pace of the industry’s demise.
“You’ve seen a fair clip of closures in the U.S., that is just unfortunate, but a development that’s
very difficult to change,” Michael Widmer, head of metal markets research at Bank of America
Corp. in London, said in a telephone interview. “It means you’ll just have to purchase from
somewhere else.”

That’s exactly what Jay Armstrong, the president of Trialco Inc. in Chicago Heights, Illinois, is
doing. The company, which turns aluminum into finished manufactured products, now buys about
80 percent of the supplies it turns into car wheels from overseas. That’s up from 40 percent five
years ago, he said.
“It’s not the kind of business where we’re going to pay more and buy all American,” Armstrong
said in a telephone interview. “It’s too competitive a business to do that.”
Overseas Advantage
Aluminum is down 19 percent this year to $1,501 a ton on the London Metal Exchange. The metal
touched $1,460 last week, the lowest since 2009, and most American smelters can’t make money
when prices are near $1,500 or below, Austin, Texas-based Harbor estimates. Plants overseas
usually have the advantage of lower labor costs, cheaper energy expenses and weaker domestic
currencies that favor exports to the U.S.
While output has been moving abroad for some time, the game changer in the past year has been
the domination of China, where ballooning output has compounded a global surplus and driven
prices so low that Bank of America estimates more than 50 percent of producers globally lose
money. Smelters in the Asian country are still profitable, helped by higher physical premiums in
the region.
China probably will account for 55 percent of global aluminum production this year, up from 24
percent in 2005, according to Harbor research. The U.S. has gone in the opposite direction: from
2.5 million tons in 2005 to 1.6 million in 2015, it said.
Still, not all U.S. smelters will benefit from closing down. Citigroup Inc. says some domestic
operations with long-term energy contracts will have to pay regardless and are better off making
the metal than simply paying the energy bill. Some plants also have access to cheap hydro power,
said David Wilson, an analyst at Citigroup in London.

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 04 November 2015 K. Al Awadi

New base 721 special 04 november 2015

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