New base issue 1151 25 march 2018 by kaled al awadi

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,
or otherwise copied without the written permission of the authors. This includes internal distribution. All reasonable endeavours have been used to ensure the accuracy of the information contained in this
publication. However, no warranty is given to the accuracy of its content. Page 1
NewBase Energy News 25 March 2018 - Issue No. 1072 Senior Editor Eng. Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
UAE's ADNOC awards PetroChina stakes in 2 offshore concessions
Source: Reuters
PetroChina will take 10 percent stakes in two of Abu Dhabi National Oil Company’s
(ADNOC) offshore concessions under a 40-year agreement signed on Wednesday. PetroChina
paid a participation fee of 2.1 billion dirhams ($575 million) for the Umm Shaif and Nasr
concession and a fee of 2.2 billion dirhams ($600 million) for the Lower Zakum concession,
ADNOC said in a statement.
In the Umm Shaif and Nasr concession, PetroChina joins France’s TOTAL and Italy’s Eni which
were recently awarded a 20 percent and 10 percent stake respectively. In the Lower Zakum
concession, CNPC joins an Indian consortium led by ONGC Videsh, Japan’s
INPEX, TOTAL and Eni.
ADNOC retains a 60 percent majority share in both concessions.
'These agreements strengthen our growing relationship with ADNOC, and will help to meet
China’s expanding demand for energy and contribute to asset portfolio optimization and
profitability enhancement of PetroChina,' Wang Yilin, who is chairman of both PetroChina and its
parent China National Petroleum Corporation (CNPC), said in a statement.
The 40-year agreements, signed by ADNOC and CNPC, are backdated to March 9, 2018,
ADNOC said.

In February 2017, CNPC, China’s largest oil and gas producer, was awarded an 8 percent interest
in Abu Dhabi’s onshore concession, operated by ADNOC Onshore. It also has a 40 percent stake
in the Al Yasat concession with ADNOC.
'Energy cooperation is an increasingly important aspect of the UAE’s relations with China, the No.
1 oil importer globally and a major growth market for our products and petrochemicals,' ADNOC
Group Chief Executive Sultan Ahmed al Jaber said in the statement.
Chinese firms have made inroads into Abu Dhabi concessions since last year, when
PetroChina’s parent CNPC was awarded an 8 per cent stake in Abu Dhabi Onshore
as well as a 40 per cent stake in Al Yasat concession in February. A CNPC affiliate
– China National Petroleum Engineering & Construction Corporation (CPECC) -
also won in November an engineering procurement and construction contract to
expand production capacity at the onshore Bab field by 30,000 bpd from the current
420,000 bpd.

UAE Masdar celebrates 5th anniversary of Shams 1 project
Gulf news + NewBase
Shams Power Company, the developer, owner and operator of the UAE’s first large-scale solar
power project, Shams 1, is celebrating five years of uninterrupted electricity generation at the plant
this month.
Located in Al Dhafra, Abu Dhabi’s western region, the 100 megawatt-capacity (MW) Shams 1 was
the largest concentrated solar power plant in the world at the time of its inauguration in 2013 and
the first plant of its kind in the Middle East and North Africa. It also represented the world’s largest
financing transaction for a solar energy project.
Masdar, Abu Dhabi Future Energy Company, has an 80 per cent stake in Shams Power, while
Total, the world’s fourth-ranked international oil and gas company, owns 20 per cent.
Shams 1 uses 258,000 parabolic trough mirrors spread over 2.5 sq km to power an electricity
turbine with the heat of the sun.
To date, the project has achieved a net production of 972,352.33 megawatt-hours (Mwh), enough
electricity to power nearly 110,000 homes for one year while displacing more than 720,000 tonnes
of carbon dioxide. That is the equivalent of saving more than 360 million kilos of coal.
“When Shams 1 was inaugurated five years ago, it was a breakthrough for the renewable energy
sector, not only in the UAE but the Mena region as a whole,” said Yousif Al Ali, chairman of
Shams Power Company. “To complete five years of uninterrupted power generation is an
impressive achievement.”
“CSP technology is now widely accepted as a proven technology for large-scale power
generation, while Shams 1, a landmark in the Al Dhafra region, has demonstrated the economic,

technical and environmental advantages of deploying large-scale solar thermal power in the UAE,”
Al Ali said. “Such investments build knowledge, experience and skills, stimulating job growth and
activity in other areas of the economy.”
Shams 1 employs around 100 staff with UAE nationals occupying 60 per cent of management
positions. Moreover, the project has attracted contractors and service providers to the region that
are supporting the wider development of solar thermal technology. Further demonstrating the
operational efficiency of large-scale solar power, Shams 1 has also achieved 11 million man hours
without a lost-time incident (LTI) to date.
“With the support of Total and our partners, Shams 1 has played a pivotal role in the wider
development of the renewable energy sector in the UAE and the region by showing that solar
power technology is a viable, reliable and bankable alternative to fossil fuels for power
generation,” said Mohamed Jameel Al Ramahi, chief executive officer of Masdar. “Not only that, it
is has given other industry players the confidence to enter the market, applying proven renewable
energy technologies at scale.”
“Total is proud to be the partner of Masdar in the Shams 1 project and to celebrate its already five
years long success story,” said Hatem Nuseibeh, president, Total E&P UAE. “This is an important
milestone in the development of renewable energy in the UAE. As a gas and oil major, the most
proactive with regard to tomorrow’s energy, Total is committed to assisting the UAE in further
diversifying its energy mix to ensure a supply of affordable and clean energy to the region.”
The total power capacity of the renewable energy projects around the world in which Masdar is an
investor is nearly 3 gigawatts (GW). Other solar thermal power plants in Masdar’s portfolio include
Gemasolar near Seville in Spain, the world’s first utility-scale solar power plant to generate
electricity 24 hours a day by combining a central tower receiver system with molten salt storage
technology.
Also in Spain, the Valle 1 and 2 power plants use the same parabolic-trough technology as Shams
1 to meet the average power consumption needs of 80,000 homes, roughly the entire residential
community of the nearby city of Cadiz

Pearl Petroleum to increase gas output at KRG field
Arabian Business + NewBase
Pearl Petroleum, the consortium led by Crescent Petroleum and Dana Gas of the UAE, has
signed a 10-year gas sales agreement (GSA) with the Kurdistan Regional Government (KRG) to
sell the additional quantities of gas that it plans to begin producing later this year.
The increased gas production is expected to boost the much-needed local domestic electricity
generation, said a statement.
The GSA was signed on January 30
by the KRG Minister of Natural
Resources Dr Ashti Hawrami, CEO of
Crescent Petroleum Majid Jafar and
CEO of Dana Gas Dr Patrick Allman-
Ward, to enable an increase in
delivered gas production from the
Khor Mor Field by an anticipated 80
million cubic feet of sales gas per day
before the end of 2018, from the
current level of 305 million cubic feet
per day.
All contractual conditions precedent
for the agreement have since been
satisfied and consequently the project work has now commenced.
In August last year, Pearl Petroleum reached a full and final settlement with the KRG of the
arbitration between them, including receiving $1 billion in cash from the KRG for past receivables
and committing to expand their investment and operations in the region. These expansion plans
include a multi-well drilling program in both the Khor Mor & Chemchemal fields, as well as
installation of additional gas processing and liquids extraction facilities. The fields are operated
jointly by Crescent Petroleum and Dana Gas on behalf of Pearl Petroleum.
The initial phase of this expansion is through a fast-track debottlenecking project, whereby Pearl
will increase daily production of natural gas and condensates from the Khor Mor Field by around
25 per cent later this year which will deliver much needed gas to fuel additional affordable power
generation for the benefit of the local population and Iraq as a whole.
This accelerated debottlenecking project represents an important first step in the overall plan to
increase gas production by a further 125 per cent within two years after that to eventually reach
around 900 million cubic feet per day of gas production, together with associated liquids.
Total investment to date exceeds $1.3 billion with total cumulative production of over 228 million
barrels of oil equivalent (boe), which has resulted in billions of dollars of fuel cost savings and
economic benefits for the Kurdistan Region and Iraq as a whole, the statement said.
Operation full-time staff numbers are close to 500 with over 80 per cent localisation, and training
programmes to increase this figure further. In addition, Pearl has contributed to local communities
with support for local power generation, education and healthcare facilities, as well as support
programmes for internally displaced Iraqis.

Dana Gas has previously announced that the appraisal programme has to date resulted in proven
certified reserves of 15 trillion cubic feet (tcf) of gas and 310 million barrels condensate.
Dr Ashti Hawrami said: “The Kurdistan Region of Iraq holds potentially more than 200 tcf of gas
and the KRG is committed to playing a positive role in the growing gas and electricity needs of
Iraq and the region. We are pleased to see the further commitment of expansion and investment
by the companies and the anticipated growth in gas supplies will make a positive contribution to
the growing domestic needs for more electricity.”
Majid Jafar commented: “The gas sales agreement marks an important milestone in our 10th year
of continuous production, and the beginning of a new chapter of expansion in operations and
production which will see a further investment of over $600 million over the coming few years and
a more than doubling of production. The gas we have produced has led to significant fuel savings
and social and economic value for the economy, and we hope to grow this in the years to come
from the significant resources of these world class fields, for the benefit of the Kurdistan Region
and all of Iraq.”
Dr Patrick Allman-Ward added: “We and our partners in Pearl Petroleum are proud to be the
largest investors and producers in the gas sector of the Kurdistan Region. Despite all the
challenges we have maintained our production levels and operations and now with the settlement
of all past receivables last summer and continuous payments since then, we look forward to
significantly growing production to meet the growing demand for gas and electricity in the
Kurdistan Region and Iraq as a whole.”
Pearl has also implemented a corporate social responsibility program to support local
communities, including providing school supplies, drinking water treatment, generators and fuel
enabling 24-hour electricity for local villages, mobile medical units, and youth sports facilities, as
well as financial support for 1,000 orphans from the Chemchemal area in partnership with a local
charity Foundation.
These initiatives are assisting the local communities in improving their standard of living, health,
well-being, security and stability and the development of human capital, the statement said.

China gaint oil PetroChina profit almost triples to Dh13bn
Bloomberg
PetroChina Co., the country’s biggest oil and gas company, once again rewarded shareholders by
paying out its entire net income as dividends.
After a surprise payout from its half-year results in August, the Beijing-based
company said Thursday it will send investors dividends that amount to slightly more than its 22.8
billion yuan ($3.6 billion) in 2017 net income.
“Shareholders should be happy that PetroChina once again paid out all of its profit as dividend,”
said Anna Yu, a Hong Kong-based analyst at ICBC International Research Ltd. State-owned
China National Petroleum Corp. holds almost 83 percent of the company.
PetroChina Profit
Net income almost triples in 2017 on rising energy prices and cost cutting
Source: Bloomberg, company reports
PetroChina is recovering from its worst-ever performance the previous year as a rally in oil prices
bolstered its exploration and production segment. Global benchmark Brent crude averaged 21
percent higher in 2017 than a year ago as OPEC and its allies cut output. And while the state-
owned giant took a 23.9 billion yuan hit from reselling imported gas domestically below cost, those
losses are seen having peaked.
As the country’s biggest natural gas producer and importer, PetroChina is key to President Xi
Jinping’s campaign to replace coal with the cleaner-burning fuel. The nation’s gas use surged 15
percent last year, with imports satisfying around 40 percent of that demand, pushing up global
prices this winter while leaving some parts of the country short of supply.

Fueling Losses
PetroChina sells imported gas at a loss
Source: Company reports
Note: Figures represent operating losses from imports by Natural Gas & Pipeline segment
PetroChina will hand out dividends totaling 0.06074 yuan per share, including special payments.
Given that free cash flow hit a record $24 billion, the dividend payout was “uninspiring,” Aditya
Suresh, an analyst at Macquarie Capital Ltd. in Hong Kong, wrote in research note.
Profit in 2017, which almost tripled, compares with the 23.1 billion yuan median estimate in a
Bloomberg survey of 10 analysts and the company’s forecast of as much as 23.9 billion yuan in
January.
Impairments more than doubled as the company wrote down the value of petrochemical and
pipeline assets. Spending, which rose for the first time in five years, overshot its target by 13
percent. PetroChina plans to boost expenditure by about 4 percent this year.
“The conservative capital expenditure implies the free cash flow yield will remain excellent in
2018,” Morgan Stanley said in a note. In terms of dividend yield, PetroChina is less attractive than
state-owned peers China Petroleum & Chemical Corp. and Cnooc Ltd., the bank’s analysts wrote.
Shares of PetroChina fell 3.1 percent to HK$5.36 as of 9:44 a.m. in Hong Kong amid a broader
equity sell-off as trade tensions escalated between the U.S. and China. The city’s benchmark
Hang Seng Index lost 3.4 percent.
PetroChina also reported revenue rose about 25 per cent to 2.02 trillion yuan while oil and gas
output fell 0.6 per cent to 1.46 billion barrels of oil equivalent. Crude output dropped 3.7 per cent
to 887 million barrels and the company set its 2018 target at 888.2 million barrels. Natural gas
output up 4.5 per cent to 3.42 trillion cubic feet with a 2018 target at 3.54 trillion cu ft.

Iraq: Shell sells its stake in West Qurna1 oil field to Itochu Corp
Source: Shell
Shell EP Middle East Holdings has agreed to sell the entire share capital of Shell Iraq B.V (SIBV),
which holds its 19.6% stake in the West Qurna 1 oil field, for $406 million, to a subsidiary
of ITOCHU Corporation.
The purchaser will also assume debt of $144 million as part of the transaction. The sale has
received the necessary regulatory consent, is expected to complete in the next few days, and has
an effective date of 31 December 2015.

Since joining the project in 2009, Shell has enjoyed successful cooperation with its partners in the
West Qurna 1 venture, which will continue to be operated by ExxonMobil.
Shell’s Upstream Director, Andy Brown, said:
'Iraq is an important
country for the Shell
Group, and exiting West
Qurna 1 allows us to focus
our resources on other
assets in our Iraq
portfolio. We are grateful
for the support of the Iraqi
government during the
divestment process.
'Shell remains committed
to working with its partners
to redevelop Iraq’s energy
infrastructure by capturing
associated gas, through
the Basrah Gas Company
(BGC) Joint Venture, for
domestic and regional
consumption. This deal
maintains the momentum
behind Shell’s $30bn
divestment programme and
is in line with the drive to
simplify our upstream
portfolio and reshape the
company into a world class
investment.'
Shell’s other businesses in
the country will not be affected by this divestment.
Background
The divestment scope covers Shell Iraq BV, which is 100% owned by Shell EP Middle East
Holdings B.V. ('SEPMEH') and holds a 19.6% working interest in West Qurna 1 ('WQ1') Technical
Service Contract ('TSC') in Iraq. Other partners in the TSC are ExxonMobil (32.7%), PetroChina
(32.7%), Pertamina (10%) and Oil Exploration Company (5% state partner).
On completion of the sale of SIBV, Shell will have no participating interest in the TSC and will
have completely divested its interest in West Qurna 1.
On 14 September 2017, Shell Iraq Petroleum Development B.V. (SIPD) announced that the
Ministry of Oil of Iraq has endorsed its recent proposal to pursue an amicable and mutually
acceptable handover of the Shell interest in Majnoon, with timings to be agreed in due course.

U.S. Solar PV costs are declining, estimates vary across sources
https://www.eia.gov/todayinenergy/detail.php?id=35432
Costs for utility-scale solar photovoltaic (PV) systems have declined in recent years—most
sources show that system costs on a per-watt basis have fallen about 10% to 15% per year from
2010 through 2016. The level of those costs in certain years often varies across sources for
reasons largely attributable to the way these costs are estimated.
To estimate capital costs of generating technologies, analysts use one of two common methods—
total reported costs or aggregated component costs. Both approaches help explain the cost of
utility-scale solar PV systems.
Reported costs: Using actual project data provides an empirical analysis that captures a large
range of reported project costs in the market and accounts for the substantial variability in project
design, location, and timing observed in the real world. Challenges with this approach include
uncertainty about whether certain cost components are included in reported system costs, such as
interconnection costs and the treatment of financing expense. Also, the data for each year reflect
projects completed in that year, which do not necessarily reflect the costs of projects initiated in
that year.
Component costs: The component cost approach provides more detail on the impact of changes
in component-level technology and costs, which can be significant in a fast-moving market like
solar PV. Such approaches typically represent either best-in-class or common-practice project
criteria and do not necessarily capture the wide range of real-world project cost factors. Estimates
that exclude financing expenses are called overnight estimates (i.e., as if the plant could be built
instantly with no financing requirement). Component-based estimates may not reflect all potential
costs to a system, such as developer profit margins.
EIA started collecting data on total capital costs directly from project owners as a part of the Form
EIA-860 Annual Electric Generators Report in 2013. Because of respondent confidentiality, EIA
only publishes capacity-weighted average values of new projects coming online each year and
has published data for 2013, 2014, and 2015. This data series includes facilities with a nameplate

capacity of at least one megawatt of alternating current. Respondents are asked to exclude
government incentives and financing expenses from the reported costs.
The U.S. Department of Energy’s Lawrence Berkeley National Laboratory (LBNL) begins with
EIA’s capital cost dataset and gathers additional information from corporate financial reports,
Federal Energy Regulatory Commission (FERC) filings, and the U.S. Department of the
Treasury’s Section 1603 grant database. LBNL’s annual Utility-Scale Solar Report defines utility-
scale solar facilities as those with at least five megawatts or more of alternating current, which
cuts out some of the smaller plants included in EIA’s Electric Generator Report.
The U.S. Department of Energy’s National Renewable Energy Laboratory (NREL) publishes
the Solar PV System Cost Benchmark report with estimates of total system costs based on the
most up-to-date information on reported component costs and conversations with industry. These
costs do not include additional net profit components, which are common in the marketplace. Also,
NREL’s bottom-up approach models costs for a project sized at 100 megawatts of direct current,
which is large enough to have realized some economies of scale relative to smaller systems.
EIA also projects future capital costs as part of the Annual Energy Outlook (AEO). Starting costs
of solar PV come from contracted capital cost studies based on information on system design,
configuration, and construction derived from actual or planned projects, using generic
assumptions for labor and materials rates.
Although EIA does not update the capital cost study each year, in years where the report data are
not updated, EIA extrapolates cost trends observed in the literature, including the sources noted
above, and considers expected cost declines from learning-by-doing. For 2018, AEO2018 projects
installed capital costs of $1.85 per watt (AC) for fixed-tilt PV systems and $2.11 per watt (AC) for
single-axis tracking systems.

MENA: $1 trillion energy investment likely in Mena: Apicorp
NewBase + Trade Arabia
Almost $1 trillion for energy investment is likely in the Middle East and North Africa (Mena) region
over next five years, a research report said.
The annual Mena Energy Investment outlook report by Arab Petroleum Investments Corporation
(Apicorp), a multilateral development bank focused on the energy sector, forecasts that the Mena
region will see a number of critical energy projects pushed through over the next five years,
despite the uncertain geopolitical backdrop.
Around $345 billion has been committed to projects under execution while an additional $574
billion worth of development is planned, it said.
The overall economic outlook remains similar to the forecasts estimated this time last year, with
growth of around 3.2 per cent forecast for both 2018 and 2019.
Global investment in the industry is expected to pick up and parts of the Mena region are
expected to see a corresponding improvement in investment. Saudi Arabia is expected to lead the
way. The uncertainty over the possible re-imposition of sanctions on Iran means that it may
struggle to attract the foreign investment it needs to develop its industry. Iraq is also facing
challenges, despite the improving security situation.
Saudi Arabia and the UAE represent 38 per cent of planned investments, with $149 billion and
$72 billion, respectively, over the outlook period, as both countries look to boost their upstream oil
and gas sectors. For Egypt, the main focus is ramping-up of gas production and meeting rising

power demand. Planned investments in the country are $72 billion, with the power sector making
up over 50 per cent of the total.
Elsewhere planned projects in Kuwait stand at $59 billion over the same period, with over 50 per
cent in the oil sector. More specifically, the country intends to increase oil output to 4m b/d within
the next few years. Similarly, in Algeria planned projects stand at around $58bn with the Hassi
Messaoud Peripheral Field Development accounting for a significant portion of investments in
upstream oil. The country will seek to invest in upstream oil and gas to meet its target of
increasing production by 20%. However, low fiscal buffers and competing pressures on revenue
may impact Algeria’s efforts to execute its ambitious capacity expansion plans.
Other major investment in the oil and gas sector will be made in Iran, with an estimated $67bn in
planned projects in the coming period, and Iraq, at $47bn. Oil investments account for $27bn with
the ENI-led Zubair and the PetroChina-led Halfaya, two of the largest upstream development
projects in the country. However, the outlook for those countries is much less certain, with a
significantly higher degree of political risk.
There are three main challenges that could potentially hinder the growth of investment in the
region. The first is that the global investment in the oil and gas sector are closely interlinked with
oil prices, and though the situation as a whole is improving, prices are not expected to return to
the high levels seen prior to the sharp drop in 2014.
Another challenge to growth is the rising cost of capital, as some governments will find it harder to
attract foreign investment. However, supported by its high reserves, and low debt to GDP ratios,
the GCC was successful in issuing record debt of over $50bn in 2017, surpassing the previous
year’s record of $37bn. Saudi Arabia represents the bulk of this, with over $21bn of debt raised,
followed by Abu Dhabi and Kuwait with $10bn and $8bn respectively. Oman ($8bn) and Bahrain
($3bn) also tapped the international market, the report says.

Finally, the regional geopolitical environment remains fragile, and persistent conflicts in the region
are creating instability that deters investors and causes them to become cautious in investing in
the entire region.
2017 certainly saw improvements and rebalance in the region. The period of weakest economic
growth and oil prices seems to have passed, but the recovery phase will take longer and is not
without its challenges. GCC governments have announced expansionary budgets following a few
years of tightening expenditures because of lower oil revenues, and will prioritise critical
investments in their energy sectors, it says.
Commenting on the report, Dr Ahmed Ali Attiga, chief executive officer of Apicorp, said: “We
expect the Mena region to continue investing heavily as major energy-exporting countries expand
the size of their energy sector and strengthen their positions in global markets.”
“Our unique mission
as a multilateral
development bank for
the Arab world puts
us at the epicentre of
the regional energy
market, and our
reputation as a
trusted partner for
financing projects is
stronger than ever.
With our detailed
insight into the nature
and amount of
required investment in
the region, we are
well placed to support
governments and
private sector
organisations seeking
to execute landmark
energy projects.”
Mustafa Ansari, senior economist at Apicorp, added: “We see three important trends materialising
in our outlook: the first is higher allocation of capital towards the power sector, which now
accounts for the bulk of planned investments as demand for electricity continues to increase. The
second is the increase in committed investments, reflecting an improving investment climate and a
healthy transition of projects from the planning phase towards execution. And third, the private
sector has an increasing role to play in financing energy projects in the Middle-East, that will help
ease fiscal pressures on governments.”
Ghassan Al-Akwaa, energy sector specialist, added: “The emphasis on diversification has never
been more important and we are witnessing this across all sectors. Renewable energy will
continue to see its role in the power generation mix increase while governments will continue in
their efforts to integrate the supply chain and invest in new mega refining and petrochemical
projects, opening many opportunities for private investments.” –

NewBase 25 March 2018 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil rises as Saudi backs extending output cuts into 2019
Reuters + NewBase + Bloomberg
Crude prices rose on Friday, hitting their highest since late January after the Saudi energy
minister said OPEC and allied producers would need to keep coordinating supply cuts into 2019,
and as concerns grew over the future of Iranian crude exports.
Brent crude futures LCOc1 jumped $1.54, or 2.2 percent, to settle at $70.45 a barrel. For the
week, Brent was up about 6.4 percent, its strongest weekly rise since July.
U.S. West Texas Intermediate (WTI) crude futures also had their biggest weekly gain since July,
at 5.5 percent. WTI CLc1 settled at $65.88 a barrel, up $1.58, or 2.5 percent.
U.S. hedge funds and other money managers raised their bullish bets on WTI in the week to
March 20 by 34,488 contracts to 488,438, the U.S. Commodity Futures Trading Commission
(CFTC) said.
Oil price special
coverage

“There are a number of bullish things to hang the hat of the rally on this week; be it the inventory
report ... or the tariff news, or the heightened tensions between Saudi and Iran,” said Matt Smith,
director of commodity research at Clipper Data in Louisville, Kentucky.
President Donald Trump’s decision to replace national security adviser H.R. McMaster with John
Bolton, who is seen as more hawkish on Iran, also supported prices, Smith said.
Global stock markets fell as investors worried about a trade stand-off between the United States
and China. Trade jitters could also hit oil markets, but most analysts said other bullish factors
outweighed them for now.
U.S. energy companies added four oil rigs in the week to March 23 General Electric Co’s (GE.N)
Baker Hughes energy services firm reported. That brought the total number of rigs to 804, the
highest in three years.
While U.S. production keeps rising, the Organization of the Petroleum Exporting Countries
(OPEC) and allied producers have curbed output. Saudi Energy Minister Khalid al-Falih told
Reuters the curbs, instituted in January 2017, would need to continue into 2019 to reduce global
inventories.
The demand outlook also supported oil.
“We’re continuing to see signs that demand is really healthy; total U.S. demand is more than 1
million barrels a day more than it was a year ago,” said Gene McGillian, manager of market
research at Tradition Energy in Stamford, Connecticut.
“As the fundamental picture continues to tighten, that’s going to attract further length in the
market,” he said.
Morgan Stanley predicted Brent would hit $75 a barrel in the third quarter as seasonal demand
picks up. It noted the market is “only three-four weeks away from peak refinery maintenance, after
which crude and product demand should accelerate ... Global inventories are already at the
bottom end of the five-year range.”
Crude prices have been struggling to recover to their recent peaks in January as fears of a trade
war, surging U.S. shale production and a global equity rout weighed on the market. Still, last
week’s surprise draw in American crude inventory has boosted optimism the Organization of
Petroleum Exporting Countries and its allies’ production cuts are bearing fruit, helping to buoy oil
prices toward their third weekly gain.
“Trump has dismissed those that wanted to protect the Iran nuclear agreement, and has replaced
them with people who are opposed to Iran,” Takayuki Nogami, chief economist at state-backed
Japan Oil, Gas & Metals National Corp., said by phone from Tokyo. “Concern Trump will scrap the
nuclear agreement is getting bigger and bigger. This is supporting crude prices.”
West Texas Intermediate crude for May delivery rose as much as $1.12 to $65.42 a barrel on the
New York Mercantile Exchange and traded at $64.98 at 8:02 a.m. in London. Prices were 4.3
percent higher on the week, the most since January. The contract fell 87 cents to $64.30 on
Thursday. Total volume traded was about 57 percent above the 100-day average.
Brent for May settlement added 61 cents to $69.52 on the London-based ICE Futures Europe
exchange after earlier touching $70 a barrel for the first time since February on an intraday basis.
The global benchmark traded at a $4.53 premium to WTI for the same month. Futures are up 5
percent this week, the biggest weekly jump since July.

Speculation is growing that Trump’s repeated threats to withdraw from a deal curbing Iran’s
nuclear program, along with appointments of Bolton as the top national security adviser and
earlier Central Intelligence Agency Director Mike Pompeo as Secretary of State, could lead to a
harder line on the Persian Gulf state. Any resumption of unilateral U.S. sanctions against the
OPEC member could drag down oil exports from Iran by 250,000 to 500,000 barrels a day by the
end of this year, FGE said last week.
Geopolitical risks sparked by Trump follow a drop in prices Thursday after the president ordered
levies on Chinese steel and aluminum. The Asian giant announced plans to reciprocal tariffs on $3
billion of shipments from the U.S. in response. If the trade war continues, it could mute global
consumption and boost investors’ preference over havens such as gold, according to Kim
Kwangrae, a commodities analyst at Samsung Futures Inc.
“The political environment around the oil market has been becoming more tense for some time,”
said Daniel Hynes, a senior commodities strategist at Australia & New Zealand Banking Group.
“Oil was clearly caught up in the selling yesterday as a general risk off tone permeated the
markets. However, the strong fundamentals have enticed investors back into the market.”
Optimism among oil investors grew after government data earlier in the week showed a surprise
decline in American crude inventories, confounding more than 80 percent of analysts in a
Bloomberg survey who expected an increase. Stockpiles in the U.S., which is taking less OPEC-
produced oil than ever before, are below the five-year average for the first time since 2014.
U.S. drillers add oil rigs for second consecutive week
U.S. energy companies added oil rigs this week for a second week in a row, data showed on
Friday, as drillers followed through on plans to boost spending, encouraged by crude prices rising
toward their highest in nearly three years.

Drillers added four oil rigs in the week to March 23, bringing the total count to 804, the highest
since March 2015, General Electric Co’s Baker Hughes energy services firm said in its closely
followed report.
More than half the total oil rigs are in the Permian basin in west Texas and eastern New Mexico
where active units increased by seven this week to 444, the most since January 2015.
Those new rigs should help boost oil output in the Permian to a record high near 3.2 million
barrels per day in April, according to federal projections, representing about 30 percent of total
U.S. oil production.
The U.S. rig count, an early indicator of future output, is much higher than a year ago when 652
rigs were active. Energy companies have been steadily increasing spending since mid-2016 when
crude prices began recovering from a two-year crash.
U.S. crude futures traded around $65 a barrel this week, approaching the three-year high of
$66.66 hit in late January, up sharply from the $50.85 average hit in 2017 and $43.47 in 2016.
Looking ahead, futures were trading around $64 for the balance of 2018 and $59 for calendar
2019.
In anticipation of higher prices, U.S. financial services firm Cowen & Co said 58 of the roughly 65
exploration and production (E&P) companies they track have already provided guidance indicating
an 11 percent increase this year in planned capital spending.
Cowen said those E&Ps that have reported capital plans expected to spend a total of $80.5 billion
in 2018, up from an estimated $72.4 billion in 2017. Analysts at Simmons & Co, energy specialists
at U.S. investment bank Piper Jaffray, this week forecast the total oil and natural gas rig count
would average 1,015 in 2018 and 1,128 in 2019, the same as its projection last week.
So far this year, the total number of oil and natural gas rigs active in the United States has
averaged 964, up sharply from an average of 876 rigs in 2017 and 509 in 2016, and not far from
the total of 978 in 2015. Most rigs produce both oil and gas.
EIA projected this month that average annual U.S. production will rise to a record high 10.7 million
barrels per day (bpd) in 2018 and 11.3 million bpd in 2019. The current all-time peak was in 1970
at 9.6 million bpd, according to federal energy data.

NewBase Special Coverage
News Agencies News Release 25 March 2018
Statoil presents Annual and Sustainability reports for 2017
Source: Statoil
On 23 March, Statoil has presented its Annual Report and Form 20-F for the year ended 2017,
and its sustainability report.
In 2017, Statoil delivered record high equity production of
2.080 million barrels of oil equivalent per day and an
underlying production growth of more than 6%, driven by
continued strong operational performance and new fields
starting production.
This has, combined with further efficiency improvements,
contributed to USD 3.1 billion in free cash flow for the full
year and strengthened Statoil's financial position. The
reserve replacement ratio (RRR) was 150% in 2017, due to
sanctioning of new projects and positive reserve revisions
on existing fields.
'In 2017 we presented our strategy: always safe, high
value, low carbon, and we set clear ambitions for the
future. We have delivered above and beyond our ambitious
targets, and Statoil is now a stronger, more resilient and
more competitive company,' writes president and CEO of
Statoil ASA, Eldar Sætre in a letter to fellow shareholders.
'We must always be prepared for volatility in our markets. Our improvement work started when
prices were still high, and we have used the downturn to reset the company,' Sætre writes.

2017 saw increased prices and increased margins for the industry. Statoil's average realised
liquids price was USD 49.1 per barrel for the year, with oil prices increasing towards the end of the
year.
Organic capex for 2017 was USD 9.4 billion, a USD 1.6 billion reduction from the initial guiding,
achieved through continued efficiency improvements and strong project deliveries. Statoil
completed 28 exploration wells in 2017.
For the full year, the serious incident frequency came in at 0.6, a positive development from the
previous year.
'We will use this as inspiration and continue our efforts. The ‘I am safety’ initiative, launched
across the company is an important part of these efforts,' Sætre says in the letter.
Embracing the energy transition
The Annual Sustainability Report offers an overview of how Statoil follows up its ambitious
sustainability agenda and performance. Sustainability is embedded in Statoil’s strategy, and the
company is taking actions to develop the business to support the UN sustainability goals and the
Paris agreement.
In 2017, Statoil launched a new climate roadmap outlining aims to reduce the carbon intensity of
its upstream oil and gas portfolio to 8 kg CO2/boe by 2030, achieve annual CO2 emission
reductions of 3 million tonnes by 2030 and build an industrial position in profitable new energy of
up to 15-20% of capex by 2030. The company will also invest around 25% of research funds into
new energy solutions and energy efficiency by 2020.
'In Statoil we believe the winners in the energy transition will be the producers which can deliver at
low cost and with low carbon emissions. We also believe there are attractive business
opportunities in the transition to a low-carbon economy,' writes Sætre.

Statoil reduced its CO2 intensity from our production of oil and gas by 10% year-on-year, from
10kg CO2 per boe to 9kg CO2 per boe. In 2017 we achieved CO2 reductions of 356 000 tonnes.
'CO2-emissions from our oil and gas production were reduced with an additional 10% per barrel
last year. In the fall 2017 we started production from Dudgeon, and the floating windfarm Hywind.
Today, we operate three offshore wind projects in the UK, delivering competitive returns. Statoil
will continue its journey from a focused oil and gas to a broad energy company,' he continues.
The report also shows the robustness of Statoil's portfolio, illustrated by a resilience test using
different scenarios from the International Energy Agency. The changes in Statoil’s value in the
scenarios is mainly driven by different oil and gas price assumptions.
Statoil has continued to improve the value and robustness of its portfolio compared to 2016 –
reducing the breakeven oil price to USD 21 per barrel for its next generation projects.
In 2017 Statoil's total payment to governments was USD 9.6 billion. Statoil's total purchases of
goods and services was around USD 18 billion.

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

New base issue 1151 25 march 2018 by kaled al awadi

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New base issue 1151 25 march 2018 by kaled al awadi