Ne base 05 march 2018 energy news issue 1147 by khaled al awadi

Copyright © 2018 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
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NewBase Energy News 05 March 2018 - Issue No. 1147 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: Enoc awards EPC contract for jet fuel pipeline to DWC
- business@khaleejtimes.com
The construction of the pipeline is expected to be completed in 24 months
Enoc Group, through its subsidiary Horizon Terminals, awarded the engineering, procurement and
construction (EPC) contract for a 16.2-kilometre jet fuel pipeline that links its storage terminals in
Jebel Ali with Al Maktoum International Airport (DWC) in Dubai South, to Dubai-based Albanna
Engineering.
The construction of the pipeline is expected to be completed in 24 months and will be operational
in the first quarter of 2020, in time for Expo 2020 Dubai.
Upon completion, the pipeline will carry 2,000 cubic metres of jet fuel per hour to DWC, which is
billed to be the world's largest and will receive a significant share of international visitors to the
Expo.
Eventually, DWC is expected to become the world's largest airport with an annual capacity
exceeding 220 million passengers and 16 million tonnes of cargo.

Saif Humaid Al Falasi, Group CEO of Enoc, said: "The jet fuel pipeline to DWC is a strategic
infrastructure project that aligns with the growth vision of Dubai and supports the preparations for
Expo 2020 Dubai. Set in the heart of the new aviation and logistics hub, Dubai South, the airport
will serve as a global aviation centre, and we are setting the benchmark to offer jet fuel services to
a large number of international carriers using the airport.
"Awarding the construction contract is a milestone that underlines our commitment to fuel Dubai
and the nation's economic growth as it will play a vital role in meeting the growing need for
aviation fuel seamlessly."
Saeed Ahmad Mohd Saleh Albanna, chairman, Albanna Engineering, said: "We are proud to have
won this challenging contract from Enoc. This award confirms our position as a regional leader in
the pipeline construction sector in the UAE and affirms the leading role of Albanna Engineering in
the hydrocarbon sector as an EPC contractor."
Set to meet the demand for jet fuel at Dubai Airports up until 2050, the pipeline will be equipped
with state-of-the-art safety features including a leak detection system, complete automation
control and quality control, among others.
Enoc currently supplies jet fuel to Dubai International Airport through a 58-kilometre pipeline that
has a storage capacity of 141,500 cubic metres.

UAE: Dubai Dewa awards $237m SWRO desalination contract
Trade Arabia + NewBase
Dubai Electricity and Water Authority (Dewa) has awarded a contract worth Dh871 million ($237
million) to a joint venture between Acciona Agua and Belhasa Six Construct (Besix) for the
construction of a seawater reverse osmosis (SWRO)-based desalination plant at Jebel Ali.
The plant is being developed as a brownfield seawater desalination plant and associated facilities,
with the selected desalination technology being SWRO, two pass reverse osmosis (RO), including
pre-treatment facilities.
The 40-million gallons per day (mgpd) plant is expected to be commissioned by May 2020 to meet
the reserve margin criterion set for peak water demand for the year 2020 and beyond.
Saeed Mohammed Al Tayer, the managing director and chief executive of Dewa, said: "In line with
Dubai Clean Energy Strategy 2050, which aims to reduce Dubai’s carbon footprint to be the
smallest in the world by 2050, we work to increase the efficiency of the water production plants
through promoting PV panels and other solar technologies."
"To ensure this, we need to connect multi-stage flash distillation, MSF, based plants to a
centralised solar energy source such as the MBR Solar Park, so our strategy is to build production
plants based on RO, which requires 90 per cent less energy than that of MSF, making it a more
sustainable choice for water desalination," he noted.

The project is also aimed at establishing Dubai’s leading position in the region, as an example of
an effective and efficient infrastructure for electricity and water networks, to meet current and
future requirements for all aspects of development in the emirate.
"Dewa continuously works to enhance the efficiency and reliability of the water network, increase
water flow to fulfil increasing demand for water in all parts of Dubai and raise the volume of the
emirate’s water reserves and support sustainable development," he added.
Al Tayer said this project is in line with Dewa's decoupling plans for water desalination and power
production and water desalination using solar energy.
"The big projects launched by Dewa have contributed to reducing the production cost of electricity
through solar energy on a global level and we continue to decouple electricity production from
water desalination to obtain 100 percent desalinated water using a mix of clean energy and waste
heat by 2030," he noted.
Al Tayer said this will allow Dubai to exceed global targets for using clean energy to desalinate
water.
"RO will help expand our production capacity to 305 million gallons of desalinated water per day
by 2030. Eventually, reverse osmosis will produce 41 per cent compared to its current share of 5
per cent, so we will be able to produce 750 million gallons of desalinated water per day by 2030,
compared to our current capacity of 470 million gallons per day," he noted.
"Also, increasing the operational efficiency of the decoupling process will save around Dh13 billion
and reduce 43 tonnes of carbon emissions by 2030," he added.-

Libya : Total expands in Libya, buys Marathon’s Waha stake
French energy company Total substantially raised its presence in Libya with the purchase of a
16.33 per cent stake in Libya’s Waha concessions from US Marathon Oil for $450 million on
Friday.
The deal will give Total access to reserves and resources in excess of 500 million barrels of oil
equivalent (boe), with immediate production of around 50,000 boe/d (per day) and “significant
exploration potential” in concessions in the Sirte Basin, the company said in a statement.
“This acquisition is in line with Total’s strategy to reinforce its portfolio with high quality and low-
technical cost assets whilst bolstering our historic strength in the Middle East and North Africa
region,” said Total CEO Patrick Pouyanne.
Total has been in Libya for decades and holds a production share of 31,500 boe/d in 2017 from
concessions in the offshore Al Jurf field and the onshore Sharara field. It also has a share in
Mabruk field, which has been closed for several years because of poor security.
The Waha Oil Company, a subsidiary of
Libya’s state-owned National Oil Corp
(NOC), currently produces 300,000 boe/d,
which is expected to rise to 400,000 boe/d
by the end of the decade, Total said.
Other Waha stakeholders are NOC with
59.18 per cent, ConocoPhillips with 16.33
per cent and Hess with 8.16 per cent. The
oil industry in Opec member Libya has
staged a partial recovery after being hit by
blockades and armed conflict following an
uprising seven years ago.
National production dropped to lows of
about 200,000 barrels per day (bpd), before
rebounding to 1 million bpd last summer. It is still well under the 1.6 million bpd Libya was
producing before 2011, and the industry has suffered continuing stoppages including the current
closure of the southwestern El Feel field due to a protest by guards.
Waha is one of Libya’s main export grades. It is shipped from the eastern port of Es Sider, which
was blockaded by an armed faction between 2014 and 2016. Es Sider and other ports in Libya’s

Oil Crescent are now controlled by the eastern-based Libyan National Army (LNA), which allowed
the NOC to reopen them in late 2016.
Full exit
Waha’s chairman said in November that the company was aiming to increase output to 375,000
bpd by the end of 2018, but faced major funding shortfalls and challenges in maintaining damaged
infrastructure.
“Production and reserves growth is a key deal driver,” Woodmac VP for Corporate Analysis Luke
Parker said. “There’s certainly upside from where we are today ... Realising this upside would see
Total create significant value through the deal.” Marathon’s sale marks a full exit from Libya, a
move it has been considering since at least mid-2013 but has been prevented from doing so by
the NOC.
“Our relentless focus on portfolio management has driven seven country exits since 2013 and
generated proceeds of over $4 billion just in the last two years,” said Lee Tillman, Marathon
president and CEO.
In a regulatory filing in 2011, Marathon valued the Waha asset at $761 million. At the time, oil
prices were roughly double where they stand today. Brent was trading above $63 a barrel on
Friday. “They received what we consider a pretty good price for the asset given that it was
considered non-core,” said Jason Gammel, equity analyst at US investment bank Jefferies.
He said Total were “probably better able to manage the geopolitical risk of a wide-base of
operations across the Middle East.” The Marathon sale marks the second exit for a US company
from Libya in recent years.
Occidental Petroleum Corp sold a 7 per cent stake in the Nafoura oilfield to Austria’s OMV in late
2016.

Oman: Duqm petrochem hub projected at $20 billion
Oman Observer - Conrad Prabhu
Potential investments in a future downstream petrochemicals complex in Duqm integrated with a
grassroots refinery project are estimated in the order of $20 billion, according to a top official of
Oman Oil Company, the wholly government-owned investment company spearheading the
development of a world-scale petrochemicals hub in the Duqm Special Economic Zone (SEZ).
Hilal Ali al Kharusi, Executive Managing Director of Oman Oil Duqm Development Company —
one of the four verticals of the Oman Oil Group, said the ambitious scope of the proposed
petrochemicals cluster will open up immense opportunities for private sector investments in a wide
spectrum of support services in the SEZ.
Speaking at the Oman Business Forum, hosted by the Diwan of Royal Court last Wednesday, Al
Kharusi said Oman Oil Group-led investments in Duqm, commencing with the Duqm Refinery
project, will unlock business opportunities for private firms not only as investors and partners, but
also in the delivery of soft infrastructure and ancillary services.
“Along with our partner (Kuwait Petroleum International), we are starting with an investment of
around $7 billion in the Duqm Refinery project, which will grow over the next 10 years to reach
$20 billion worth of projects.
These investments will need to be serviced via the provision of various services, such as R&D,
hospitality, retail, banking, insurance, construction, transportation, health, education, you name it!
This opens up a lot of opportunities for the private sector,” the official stated.
As many as 7-8 petrochemical plants, operating
downstream of the refinery, are envisioned in the next
phase of Oman Oil Group’s plans for the development
of a major refining and petrochemicals cluster in Duqm,
according to the official. Output from these plants will
be offered to investors — local and international — as
feedstock for value-adding chemical industries, he
said.
Around 10 different types of petrochemicals and
intermediate products will be churned out by the petrochemicals cluster when it is fully operation in
the coming decade. The list includes Ethylene Glycols, High Density PE (HDPE), Oxo chemicals,
Polypropylene, Butadiene, MTBE and Aromatics.
The potential for further processing into high-value chemicals is equally promising. Oman Oil
Duqm Development Company has identified opportunities for secondary investments associated
with, among others, the production of Polymers, Plastics Processing, Plasticisers and Coatings,
Oilfield Chemicals, Paints & Adhesives, Rubbers & Elastomers, Detergent Chemicals, and
Polyesters & Nylons.

Egypt to increase gas production at Zohr to 700 mmscfd in May
Reuters + NewBase
Egypt aims to increase production at its huge Zohr offshore gas field in the Mediterranean to 700
million cubic feet per day in May from about 350 million cubic feet per day currently ،Petroleum
Minister Tarek El Molla told Reuters on Sunday.
Discovered in 2015 by Italy’s Eni ،the field contains an estimated 30 trillion cubic feet of gas. Eni
CEO Claudio Descalzi said last month that the goal was to reach 2.9 billion cubic feet per day by
mid-2019.
Noteworthy ،the petroleum minister ،Tarek El-Molla announced in January 2018 that Egypt’s
giant offshore Zohr gas field in the Mediterranean is live and set to produce an initial 350 million
cubic feet per day.
He pointed out that Egypt will achieve self-sufficiency of natural gas by the end of this year ،and
the total field production will rise by the end of 2019 to about 2.7 billion cubic feet of gas per day.
Therefore ،Zohr is likely to have a huge effect on Egypt’s energy sector.
Analytical – About:-
Discovered in 2015 by Italy’s Eni ،the field contains an estimated 30 trillion cubic feet of gas.
Egypt has been seeking to speed up production from recently discovered fields ،with an eye to
halting imports by 2019 and achieving self-sufficiency.
talian energy company Eni announced on August 30 that it had discovered a deep-water gas field
93 miles north of Egypt’s Mediterranean coast.[1] The field, named Zohr, holds an estimated 30

trillion cubic feet (cft)[2] of natural gas (NG) reserves, potentially making it the twentieth largest in
the world and the largest in the Mediterranean.
Until the Zohr discovery, Egypt had an estimated 64.8 trillion cft of natural gas reserves sitting
primarily in the Mediterranean Sea, the Nile Delta, and its western desert, making it a medium-
sized player in the natural gas market.
However, the Egyptian national oil and gas companies (EGPC and EGAS, respectively), formerly
net exporters of hydrocarbons, have recently struggled to meet the country’s internal demand,
even resorting to importing natural gas. While Eni’s new discovery is unlikely to translate into
exports for some time, it does have the potential to alleviate the gap between supply and demand.
Nonetheless, it does not do so without risks for both Eni and Egypt.
Egypt’s Energy Conundrum
Egypt’s transformation from exporter to importer was not only predictable; it was largely avoidable.
Until recently, the government’s firm ceiling price for purchasing natural gas from foreign
operators, standing at $2.65/million British thermal units (MMBtu), was well below global
standards.
With many of Egypt’s reserves being deep-water finds in the Mediterranean basin, the
government’s price ceiling made monetization commercially unviable, as steep deep-water
production costs coupled with low government purchase prices left unattractive profit margins for
foreign energy companies..
Coupling this with Egypt’s state of instability since 2011, many foreign firms viewed investment in
Egypt as a non-starter. Indeed, even though production in existing wells started to decline in 2010,
no new exploration contracts were signed between 2011 and 2013.
By 2015, production had fallen to 4.8 billion cubic feet per day (bcf/d), a contraction of 13.1
percent from 2014 and 22.3 percent since 2009.
Simultaneously, Egypt’s natural gas consumption has increased. Even though demand growth,
encouraged by low subsidized energy prices and a growing population, averaged 6 percent per
year between 2005 and 2010, supply growth helped offset any energy deficit issues—until
production started to decline.
Hence, while government repricing initiatives and subsidy reforms early on might have slowed the
growing imbalance of supply and demand, Egypt’s post-revolutionary governments did not
adequately act before gas deficits crippled Egypt’s economy. In the fiscal year 2014-2015, Egypt’s
natural gas deficit amounted to nearly 1 bcf/d, and this is expected to grow to 2.5 bcf/d by fiscal
year 2017-2018.
The growing deficit, coupled with Egypt’s dependence on natural gas for electricity generation,
not only turned net exports into net imports, but also led to power shortages across Egypt, most
notably in heavy industries such as steel and cement. Until Eni’s Zohr discovery, these
developments painted a stark picture for Egypt’s future.
Eni’s Find, Whose Fortune?
Eni’s discovery could potentially change Egypt’s energy fortunes. While Eni does plan to utilize
Egypt’s existing natural gas infrastructure to fast track production, no new gas will reach
consumers for at least three years. Moreover, Eni’s find will come at a great cost to Egypt. First,
total investment costs, which are likely to run up to $7 billion, will be borne by Eni but ultimately
paid by Egypt.

Second, production will require Eni to drill 4,300 meters at a depth of 1,450 meters below sea
level, a very expensive endeavor.
Nonetheless, if pursued correctly, the Zohr field discovery could be the best economic news
Egypt has received in years, allowing for resumed industrial growth and potential energy self-
sufficiency—that is, unless Eni intends to take its share of production elsewhere.
While the production sharing agreement (PSA) between Eni and Egypt remains private, Egypt’s
standard and past PSAs indicate how production from Zohr will likely be shared. Before Egypt
sees any gas, Eni will take up to 40 percent of the field’s output to recover its development and
exploration costs, with a yearly recovery limit of 20 percent of Eni’s total investment costs.
The remainder of the production will be split between Egypt and Eni somewhere in the range of
60-40 to 69-31 (EGAS-Eni) depending on the production volume, whereby higher levels of
production correlate to higher percentages for EGAS.
In the likely case that the field’s daily flow rises above .5 bcf/d, Eni will be entitled to 31 percent of
the field’s post-recovery production. Consequently, if Egypt looks to keep all the field’s production,
a strong possibility due to its gas deficit, it will have to pay Eni for its allotment of the post-recovery
production. Egypt’s recent purchase price revisions make this last possibility quite attractive to
Eni.
Over the last year Egyptian officials, recognizing the price ceiling’s effect on production, have
systematically renegotiated the purchase price international oil companies receive, with Eni’s price
revised in July to a range of $4-5.88 MMBtu—a much better rate than Eni could get on the
markets.
Thus, if as expected the field produces 2.5 bcf/d at an average price of $4.0/MMBtu, the field
would bring in a total profit of $3.65 billion per year. With 40 percent of total production allotted to
cost recovery and at least 31 percent of the remaining production under Eni’s ownership, the Zohr
field provides ample income for Eni to both recover its capital costs and bring in revenue—a
revenue stream that, in dollar terms, would provide Eni with around $1.13 billion per year.
Nonetheless, it is still unclear precisely how Eni’s portion will be used, with some stating that the
company will be free to utilize it as it pleases and others stipulating that it has already committed
its portion to Egypt.
This latter possibility would be likely if Eni’s PSA with EGAS follows Egypt’s standard format and
grants EGAS priority in purchasing Eni’s portion of production. In either case, if Egypt chooses to
purchase Eni’s share, Eni could potentially be compensated in either cash or gas. If Eni is paid in
cash, Egypt would owe the company up to $2.5 billion a year—$1.4 billion for recovery costs for
five years and a further $1.1 billion for Eni’s share of production. Alternatively, Egypt could agree
to pay in gas, in which case Eni would likely try to export it as LNG. Each possibility comes with its
own respective caveat.
Egypt is already a substantial debtor to a number of a foreign energy companies, including Eni,
BG, BP, and Dana Gas. While Egypt’s energy debts have steadily fallen since 2012, Egypt’s
revised natural gas purchase prices could make it harder for Egypt to service these backlogged
debts.
Consequently, Eni may prefer the safer payment schedule that LNG exports provide. Yet
unfortunately for the Italian energy giant, LNG exports may not be an option. First, under the PSA,
Egypt very likely has first dibs on Eni’s portion of the field’s gas, which it desperately needs for its
economy. Second, even though Egypt has two idle LNG plants sitting on the coast of the
Mediterranean basin with capacities of seven and five million tons per year, utilizing them to

liquefy Eni’s share of the new gas would add roughly $1/MMBtu to already steep deep-water
production costs, in turn cutting into Eni’s cash flow. This option is further clouded by the
impending glut in the market due to the new large LNG supplies from Australia, the United Sates,
and perhaps even Israel. Hence without an export option and bound by a PSA, Eni’s best, and
arguably only, option is to negotiate cash payments from Egypt.
Conclusion
Despite a potentially difficult payment schedule, Eni, which faced substantial losses in Libya and
recently had to cut its dividend payments, will find that its discovery is a boon to its company and
shareholders.
Even if Eni does not see revenue from the find for at least four years, and becomes a larger
creditor to Egypt in the process, the find will reflect well in the minds of investors and most likely
support its share price. Moreover, the new Zohr field could turn Egypt’s economic fortunes around.
While global market factors and domestic needs negate Egypt’s ability to translate the Zohr
discovery into gas export potential, it provides the necessary resources for Egypt to become once
again energy self-sufficient, in turn positively affecting Egypt’s economic climate. Egypt’s domestic
industrial base could find that it can confidently resume manufacturing capacity expansions, and
foreign investors may grow to look more favorably at industrial investment in Egypt. Indeed, the
Zohr field could translate positively for all parties involved.
Note on measurements: Most studies in the United States and the Arabian Gulf discuss natural
gas in cubic feet, while European, Asian, and Russian studies tend to use cubic meters. The
translation is 36 cft = 1 cm.
However, the price of gas worldwide is computed in $ per million of BTUs [MMBtu], since a million
BTU is quasi equivalent to 1,000 cft. Thus the industry often prefers to use cft because it allows it
to estimate quickly the cash value of production and reserves.
Another translation rule of thumb is that 10 cm per year is close to one cft per day. In the case of
Egypt a reservoir of .8 trillion cm will be equivalent to 36 billion cft, representing an overall
potential value of over $125 billion at $4/MMBtu, while a production of 2.5 billion cft/d will equal
2.5 trillion BTU, i.e., about $10 million/d.

Philippines Earmarks 2 Sites For Possible Joint Oil Exploration With China
by Reuters|Friday,
The Philippines on Friday identified two areas in South China Sea where joint exploration for oil
and gas may be undertaken with China, including one in territory that both sides have argued over
for years.
The two countries have agreed to set up a special panel to work out how they can jointly explore
in part of the hotly contested waters without having to address the issue of sovereignty, something
experts say would be extremely complex.

Philippine President Rodrigo Duterte's spokesman, Harry Roque, said the areas being considered
were sites covered by service contracts 57 and 72, which are exploration permits issued by
Manila's energy ministry.
"What I know is that there are two areas being considered for joint exploration, but both are within
the exclusive economic zone" of the Philippines, Roque told reporters. China claims almost the
entire South China Sea, believed to rich in energy reserves and marine resources. Brunei,
Malaysia, Vietnam and Taiwan also have claims.
The 880,000-hectare SC-72 at the Reed Bank, a disputed area, is where PXP Energy Corp had
been undertaking exploration to evaluate the block's gas reserves.
In 2016, the Philippines won a case at the Permanent Court of Arbitration in The Hague, which
invalidated China's claim to sovereignty over most of the South China Sea, and also made clear
the Reed Bank was inside the Philippines' Exclusive Economic Zone (EEZ). China does not
recognise the ruling.
Since Reed Bank is disputed, Roque said "there must be an agreement before the two countries
can proceed with the joint exploration".
The Philippine energy ministry suspended exploration in the Reed Bank, known locally as Recto
Bank, in late 2014 as the government pursued the arbitration case, disrupting PXP Energy's plan
to drill two wells. Chinese boats had in 2011 harassed a survey ship contracted by PXP's unit,
Forum Energy.
PXP is eager to resume exploration in the Reed Bank but said any joint venture would likely
involve a Chinese company. PXP had been talking with China National Offshore Oil Corp
(CNOOC) about Reed Bank during the administration of Duterte's predecessor, Benigno Aquino,
but the arbitration disrupted negotiations.
In September last year, the Philippines said it was pursuing a long-delayed oil and gas exploration
project with CNOOC and a Canada-listed company in the SC-57 area, which is outside disputed
waters. The area lies near the country's main oil and gas fields, including Malampaya, Nido,
Cadlao and Matinloc.
Background
U.S. Energy Information Agency The South China Sea encompasses a portion of the Pacific
Ocean stretching roughly from Singapore and the Strait of Malacca in the southwest, to the Strait
of Taiwan (between Taiwan and China) in the northeast.
The area includes more than 200 small islands, rocks, and reefs, with the majority located in the
Paracel and Spratly Island chains. Many of these islands are partially submerged islets, rocks,
and reefs unsuitable for habitation and are little more than shipping hazards, with the total land
area of the Spratly Islands encompassing less than 3 square miles.
The islands are important for strategic and political reasons, however, as claims of ownership are
used to bolster claims to the surrounding sea and its resources. The Gulf of Thailand borders the
South China Sea, and though technically not part of it, disputes surround ownership of the Gulf
and its resources as well.

NewBase March 05 - 2018 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil prices climb ahead of OPEC meeting with U.S. shale firms
Reuters + Bloomberg + NewBase
Oil prices rose on Monday ahead of a meeting between OPEC and U.S. shale firms in Houston,
raising expectations that oil producers would discuss further how to clear a global oil glut.
International benchmark Brent crude was up 19 cents, or 0.3 percent, at $64.56 a barrel by 0752
GMT.
U.S. West Texas Intermediate (WTI) crude rose 17 cents, or 0.28 percent, to $61.42 per barrel.
Oil ministers from the Organization of the Petroleum Exporting Countries (OPEC) and other global
oil players are set to gather in Houston as CERAWeek, the largest energy industry conference,
begins on Monday.
OPEC Secretary General Mohammad Barkindo and other OPEC officials are expected to hold a
dinner on Monday with U.S. shale firms on the sidelines of the conference.
Oil price special
coverage

“OPEC and Non-OPEC alliance remain at record high compliance, but with Russia continually
pressuring for an exit strategy, OPEC will look to offer an olive branch to U.S. shale,” said
Stephen Innes, head of trading for the Asia-Pacific region at futures brokerage OANDA in
Singapore.
“As such, we should interpret any positive developments from the meeting as support for
underlying oil price sentiment.” Suhail Mohamed Al Mazrouel, the United Arab Emirates oil
minister and OPEC’s current president, said on Sunday that the oil cartel has not discussed rolling
over production cuts until next year.
Rising U.S. shale oil production has been a drag on the OPEC’s commitment to erode a
prolonged global oil glut and prop up prices. U.S. crude oil production has already risen past that
of top exporter Saudi Arabia, to 10.28 million barrels per day (bpd).
Only Russia pumps slightly more, but the International Energy Agency (IEA) said last week it
expects the United States to take Russia’s seat as the world’s biggest crude oil producer by 2019,
at the latest.
The number of oil rigs drilling for new production in the United States [RIG/U] rose to 800 for the
first time since April 2015 in early March, pointing to more increases in output to come.
Speculators raised their bullish bets on U.S. crude futures and options in the week to Feb. 27 for
the second consecutive week, the U.S. Commodity Futures Trading Commission (CFTC) said on
Friday. [CFTC/]
Money managers also upped their bullish bets on Brent crude, InterContinental Exchange (ICE)
data showed.
Oil Rig Count to 800 for First Time Since 2015
U.S. oil explorers raised the rig count to 800 for the first time in almost three years amid booming
domestic and overseas demand for crude and petroleum-based fuels.
Drillers have been accelerating exploration in an almost-unbroken streak since the beginning of
November, vaulting American crude output to a record of more than 10 million barrels a day. The
unrelenting pace of expansion signals even bigger production jumps yet to come, even as
concerns about excess supplies recently weighed on oil prices.

Explorers boosted the number of rigs drilling for crude in U.S. fields by 1 this week, bringing the
total to 800, according to Baker Hughes data released on Friday. American explorers already
have put the nation on par with Saudi Arabia as a crude producer and may eclipse Russia as the
world’s largest before the year is out.
“It seems like shale producers are really getting a lot of efficiency for their capital investment and
seem to be making money at these levels” Rob Haworth, who helps oversee $151 billion in assets
at U.S. Bank Wealth Management in Seattle, said by telephone.
More than 70 percent of the rigs are concentrated in just four major shale regions, the Baker
Hughes data showed. The Permian Basin of Texas and New Mexico is by far the dominant
exploration theater with 434 rigs searching for crude.
American oil exports have doubled in the past year, providing domestic drillers with access to
markets that were mostly off-limits as recently as 2015, according to Energy Information
Administration figures. During the same 12-month period, U.S. consumption of gasoline and other
oil-derived fuels has risen almost 2 percent.
Oil Gains on Libya Field Halt as Geopolitical Risk Resurfaces
Oil climbed as geopolitical risk resurfaced, with a halt at Libya’s biggest crude field sparking
speculation that supply will tighten and help reduce a global glut.
Futures in New York rose as much as 0.8 percent after a 3.6 percent decline last week.
Production is said to have been halted at the Sharara oil field, the largest in the North African
nation, on Sunday after protests disrupted output at another of the OPEC member’s deposits last
month.
Oil has been struggling to regain the highs of January as rising U.S. output challenges efforts by
the Organization of Petroleum Exporting Countries and its allies to ease a supply glut. Surging
production from Libya has also been a thorn for the oil market, with concern that further growth

may take the country to a level that would test a pledge made to OPEC to help limit an
oversupply.
“Oil prices are responding to the tightening of supply due to the Libyan production halt,” Takayuki
Nogami, chief economist at state-backed Japan Oil, Gas & Metals National Corp., said by phone.
“Geopolitical risks in Libya were thought to have declined but that turned out to be wrong. Even if
the Sharara field starts production again, the risk of another halt remains.”
Prices Climb
West Texas Intermediate for April delivery rose as much as 50 cents to $61.75 a barrel on the
New York Mercantile Exchange and traded at $61.44 at 4:46 p.m. in Tokyo. The contract fell 3.6
percent last week, the first weekly decline in three weeks. Total volume traded was about 6
percent above the 100-day average.
Brent for May settlement added 18 cents to at $64.55 on the London-based ICE Futures Europe
Exchange. Front-month futures slipped 4.4 percent last week. The global benchmark traded at a
$3.30 premium to May WTI.
Libya has struggled to boost oil production amid the lingering effects of civil strife that erupted
earlier in the decade. Though output has risen, it remains well below the 1.8 million barrels a day
Libya pumped before the ouster and killing of former leader Muammar Qaddafi. The halt on
Sunday resulted from the closing of a pipeline from Sharara to the Zawiya refinery, according to a
person with knowledge of the matter.
While investors focus on Libya, in the U.S., oil explorers boosted the number of rigs drilling for
crude to 800 for the first time in almost three years, according to Baker Hughes data released on
Friday. Drillers have been accelerating exploration in an almost-unbroken streak since the
beginning of November, vaulting American crude output to a record of more than 10 million barrels
a day.

As CERAWeek Oil Gabfest Starts, Here's What We're Listening For
CERAWeek by IHS Markit, the largest gathering of energy executives and officials in the
Americas, begins Monday. Here’s what we’ll be listening for over the five-day period:
What’s OPEC’s next move?
Secretary General Mohammad Barkindo will dine with shale executives in Houston on Monday.
Can the two rivals make peace as the price of oil recovers?
Where will the Permian go from here?
The world’s hottest oil field is still the subject of speculation about its maximum potential. Last
year, Occidental Petroleum Corp.’s chief executive officer, Vicki Hollub, said output from the
Permian could reach 5 million barrels a day. Pioneer Natural Resources Co. Chairman Scott
Sheffield doubled that -- saying it could hit 10 million by 2027. This year, we’ll listen for any

change in tone from Occidental and Pioneer, as well as whatever Centennial Resource
Development Inc. CEO Mark Papa has to say on shale output forecasts.
Expect the unexpected!
The conference is known for big names in the industry making big pronouncements. In hindsight,
some have been prescient warnings, others have been a bit off. Here are a few of our favorites:

NewBase Special Coverage
News Agencies News Release March 05-2018
Exxon's 10-K: Russia, Reserves and a Lot of Rebuilding
Rex Tillerson's legacy means his successor has his work cut out for him.
By Liam Denning
Exxon Mobil Corp.'s annual report, released this week, reads like an epitaph
for the tenure of its last CEO, who now spends his time wrestling with a very
different kind of multinational. The bit that caught the most attention was the
disclosure that Exxon will abandon several joint ventures with Rosneft
PJSC, which have been moribund for several years anyway due to sanctions
against Russia.
This is a heavy blow. Russia represented a promised land of new mega-projects to carry the
company into the 2020s, and clinching the deal with Rosneft was to be the central part of Rex
Tillerson's legacy. On the other hand, by the time Exxon filed its 10-K this week, it merely
confirmed what everyone was assuming about Russia anyway.
But on the other, other hand, it also confirmed something else: Tillerson's successor, Darren
Woods, has his work cut.
Russia's Crimean seizure was bad luck, but the same can't be said for some of Tillerson's other
deals. The $41 billion purchase of XTO Energy Inc. in 2010 was struck just before natural gas
prices collapsed. Meanwhile, his foray into Iraq saw Exxon secure barrels in a major development,
but on terms offering razor-thin margins.
Driving all these efforts was, in part, a desire to secure reserves to replace the 4 million or so
barrels of oil equivalent Exxon pumps out every day. This instinct animates all oil and gas
producers but carries a risk of overpaying for deals or investing in sub-par projects -- as Exxon's
proved reserves disclosure in its filing illustrates.
Similar to rival Chevron Corp., Exxon announced thumping reserves replacement in 2017 after
several mediocre years. It's just that Exxon's were more mediocre:
Exxonerated?
Exxon announced good reserve replacement figures for 2017, especially when including
purchases, after several weak years
Source: Company filings
Note: Organic ratio represents production replaced by revisions, improved recovery and extensions and discoveries. Overall ratio includes
purchases and sales.

The legacy of Tillerson's deals really showed up in 2015 and 2016. About 8.4 trillion cubic feet of
U.S. natural gas proved reserves got taken out via revisions, largely because of falling prices (if
prices fall enough, some gas reserves become uneconomic to produce and, therefore, vanish
from the books). Exxon even had to take an impairment on its U.S. gas assets in 2016, an
unheard-of step for the company.
Meanwhile, reserves at the giant Kearl bitumen project in Canada, having suffered several years
of delays and contributing to a marked decline in Exxon's all-important return on capital, were
also wiped out due to price effects in 2016, leading to that year's enormously negative
replacement ratio.
Looking at the five years as a whole, Exxon's replacement ratio is dismal, due especially to the
reckoning in 2016 and the shale-gas effect:
Up In Smoke
Exxon's reserve replacement over the past five years has been very weak, especially organically
and in its natural gas business
Note: Data are for 2013-17, aggregated. Organic data reflect replacement of production via revisions,
improved recovery and extensions and discoveries. Overall figures include purchases and sales.
Higher oil and gas prices helped unwind some of that last year. Exxon re-booked more than 400
million barrels in its bitumen operations via revisions, as well as almost 700 billion cubic feet of
U.S. natural gas.
Buying reserves was just as important last year, though. Exxon has been especially active in U.S.
tight oil, where it is a relative latecomer, spending $5.6 billion on one deal alone, for the Bass
family's assets in the Permian basin.

You can see the outsize role played by acquisitions last year, looking at both Exxon's data for the
past five years and comparing 2017's additions with those of Chevron, which reported a similar all-
in replacement ratio of 166 percent last year:
The Wallet v. The Drill
Exxon's reserve replacement in 2017 owed a lot to acquisitions
Note: Organic data are additions via revisions, improved recovery and extensions and discoveries.
The Big Oil Divide
Exxon's additions to reserves in 2017 were fairly evenly split between revisions, extensions and
discoveries and acquisitions, in contrast to Chevron
Note: Data are percentage of reserves added via method. Sales excluded.
Exxon's buying spree is like a multi-billion-dollar form of retail therapy, helping it get over its earlier
missteps. The company isn't solely reliant on deals; organic reserve replacement was 127 percent last
year, and discoveries like those offshore Guyana will keep adding to the stockpile for years to come.
Yet it's clear that after being denied in Russia and suffering setbacks in Canada and shale gas, Exxon had
to open its wallet to stake out new positions in shale oil.
Exxon claims it can make shale work within its Big Oil business model. If misadventure in Russia helped
to unravel Tillerson's legacy, his successor's will depend largely on rebuilding credibility far closer to home.

NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
The Editor :”Khaled Al Awadi” Your partner in Energy Services
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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
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Mobile: +97150-4822502
khdmohd@hawkenergy.net
khdmohd@hotmail.com
Khaled Al Awadi is a UAE National with a total of 28 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 March 2018 K. Al Awadi

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