New base 10 november 2017 energy news issue 1099 by khaled 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,
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NewBase Energy News 10 November 2017 - Issue No. 1099 Senior Editor Eng. Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
Norway first off Shore platform to be remote-operated from land
Source: Statoil
On Thursday 9 November, the opening of the Valemon control room was celebrated at Sandsli in
Bergen. Valemon will be the first platform in Statoil’s portfolio to be remote-controlled from land.
'This is a vital milestone for Statoil. We have had land-based surveillance and control of offshore
operations for a long time, however, the remote control of Valemon marks one important step
forward on our digitalisation journey,' says Gunnar Nakken, head of the operations west cluster in
Statoil.
Valemon is designed and constructed for such remote control. Statoil has currently no other
platforms of this kind, but this solution will undoubtedly be considered for other small and medium-
sized platforms in the future, and remote control will be a central building block.
Proud of the new Valemon onshore control. From the left Gunnar Nakken, head of the operations
west cluster in Statoil, Norwegian minister of petroleum and energy, Terje Søviknes, head of
Kvitebjørn Valemon and Grane operations, Nina Birgitte Koch and control room operator Joakim
Tesdal. (Photos: Christian Djupvik Brandt-Hansen)
'Most of our production will still be carried out on large, manned platforms, such as Aasta
Hansteen and the Johan Sverdrup platform, but for somewhat smaller platforms and fields it will
absolutely be considered. First, we must gain experience from Valemon,' says Nakken.
'Thanks to new technology and knowledge we can utilise the advantages of our smaller,
standardised building blocks that are combined differently from field to field for optimal resource
exploitation. We want to combine the best technology, below and above water, to find optimal
solutions for every project, thereby ensuring safer operation,' says Nakken.
Onshore remote control of the Valemon platform is one example of how new ways of working and
interacting offer new possibilities and advantages.

“This demonstrates we can make the impossible possible, and we will work just as hard in the
execution phase to beat these figures,” Øvrum said during the presentation, which was broadcast
online. “We see this positive development in all types of projects globally.”
This came as the Norway-based company, which was among the first to cut back spending before
oil prices fell near the end of 2014 and deepened into an historic, transformational downturn,
reduced its capex by 43% since 2015 while it increased recoverable resources by 12%.
With oil and gas bringing in less revenue, companies worldwide were forced to change traditional
ways of doing business. Focus turned to capital discipline, bargaining with suppliers, shedding
assets, partnering with peers, halting some projects and focusing more on efficiency and
technology.
Like its peers, Statoil initiated cost-saving measures and tackled drilling efficiency, among other
areas.

Oman: Tethys Oil awarded new exploration license onshore
Source: Tethys Oil
Tethys Oil has announced that it will be awarded a new exploration license by the Ministry of Oil
and Gas of the Sultanate of Oman. Block 49 is an onshore block that covers a prospective but still
rather unexplored area in the South West of the Sultanate bordering the Kingdom of Saudi Arabia.
Tethys Oil will through its wholly owned subsidiary Tethys Oil Montasar be the operator of the
Block and hold a 100% of the license interest. The Block will be signed on 14 November 2017.
The Block 49 licence covers an
area of 15,439 sq kms. More than
11,000 kms of 2D seismic data that
has been acquired by previous
operators has been made available
to Tethys Oil. Nine wells have been
drilled within the block boundaries,
several of which are reported to
have encountered oil shows.
Among the legacy wells is the first
well ever drilled in Oman in 1955
(Dauka-1).
The exploration and production
sharing agreement (EPSA) for
Block 49 covers an initial
exploration period of three years
with an optional extension period of
another three years. In case of a
commercial oil or gas discovery, the
EPSA will be transformed in to a 15
year production license which can
be extended for another five years.
In case of a commercial discovery
Oman Government Company, has
a right to acquire up to a 30%
interest in Block 49 against
refunding of past expenditure. The
initial work commitments during the
first period include geological
studies, seismic acquisition and
processing and exploratory drilling.
'We are extremely pleased with
having been awarded Block 49 and would like to take this opportunity to express our sincere
thanks to the Government of Sultanate of Oman. Block 49 is the kind of opportunity Tethys Oil has
been pursuing for some time.
The Block covers an area with known oil shows, has a limited initial financial risk and offers
several as yet immature but potentially very prolific play concepts. After more than ten years in
Oman, Tethys Oil has built a strong technical team. As operator of the block, we are confident our
Omani experience will be well suited to make Block 49 into a success,' says Tethys Managing
Director Magnus Nordin.

Kenya: Africa Oil completes Kenya 2017 drilling campaign
Source: Africa Oil Corp
Africa Oil Corp has provided an update on its operations in Kenya. Exploration and Appraisal
(Blocks 10BB and 13T)
The 2017 exploration and appraisal drilling campaign concluded following the drilling of
the Amosing-7 appraisal well. The PR Marriott Rig-46 has been demobilized. Two discoveries
were made during the campaign.
In January 2017, the Erut-1 well resulted in a discovery, proving that oil has migrated to the
northern limit of the South Lokichar basin. The second discovery was made during May 2017,
at Emekuya-1, encountering significant oil sands, demonstrating oil charge across an extensive
part of the Greater Etom structure and further de-risking the northern area of the basin.
The Etiir-1 exploration well, which targeted a large, shallow, structural closure immediately to the
west of the Greater Etom structure, spudded in late June and was unsuccessful with no material
reservoir development or shows encountered. Although dry, drilling results will be utilized in
defining the westerly extent of the Greater Etom Structure. The Etiir-1 well has been plugged and
abandoned.
The Ekales-3 well was drilled to a total measured depth of 2,721 meters. The well targeted an
undrilled fault block adjacent to the Ekales field. While reservoir and oil shows were encountered,
and oil sampled, the well was deemed non-commercial.
Multiple appraisal wells have been drilled in the Ngamia, Amosing and Etom fieldsduring
2017: Ngamia-10 (65 meters of net oil pay), Amosing-6 (35 meters of net oil and gas
pay), Amosing 7 (25 meters of net oil and gas pay) and Etom-3 (25 meters of net oil and gas
pay)).
An extensive wireline evaluation program, including sampling has been undertaken on all
appraisal wells. The Ngamia-10, Amosing-6 and 7 and Etom-3 wells have all improved the
definition of the limits of their respective fields. However, the presence of rift edge facies has
limited their net pay. These drilling results will be incorporated into the geological models that will
be utilized for potential fields development plans.
The Auwerwer and Lokone reservoirs in the Etom-2 well were tested utilising artificial lift and
flowed at 752 bopd and 580 bopd respectively which was lower than anticipated. As a result, the

Joint Venture Partners will undertake further technical work to assess how representative the tests
may have been and identify potential options to increase flow rates from the Etom field.
Activity will now move to focus on collecting dynamic field data through extended production and
water injection testing. The Ngamia-11 appraisal well (143 meters of net oil pay) has been
completed and will be utilized in a waterflood pilot test planned for the first half of 2018.
The waterflood pilot will include the previously drilled Ngamia 3, 6 and 8 wells. This pilot is
designed to deliver a long-term assessment of the rate of enhanced oil recovery that may be
expected as a result of water injection.
The waterflood pilot follows up the successful water injection testing program which was
completed during the first half of 2017 on the Ngamia and Amosing fields. Additionally, the
partnership aims to initiate extended well testing on wells in the Amosing and Ngamia fields,
commencing in the first quarter of 2018.
Produced oil from testing will be stored and is planned to be transported as part of the Early Oil
Production Scheme (EOPS). This scheme will initially entail the evacuation of stored crude oil to
Mombasa by road, and first production from EOPS is now expected to commence in the first half
of 2018, subject to receiving the necessary consents and approvals.
Africa Oil Corp. has a 25% working interest in Blocks 10BB and 13T with Tullow Oil plc (50% and
Operator) and Maersk Olie og Gas A/S (25%) holding the remaining interests.
Field Development (Blocks 10BB and 13T)
In addition to the drilling and operational activities to support the Final Investment Decision ("FID")
for the Kenya Full Field Development, engineering studies and contracting activities are under
way in preparation for the start of the Front End Engineering Design ("FEED"), which are expected
to take place during 2018.
The Joint Venture Partners are continuing optimization of the development plans that will allow
field and pipeline infrastructure to move forward while limiting upfront capital spend.
A Joint Development Agreement (JDA), setting out a structure for the Government of Kenya and
the Kenya Joint Venture Partners to progress the development of the export pipeline, was signed
on 25 October 2017. The JDA allows important studies to commence such as FEED,
Environmental and Social Impact Assessments (ESIA), as well as studies on pipeline financing
and ownership.

Egyptian Refining Co.’s $3.7B Plant Will Start Up in September
Bloomberg -Mirette Magdy
Egyptian Refining Co.’s new $3.7 billion processing plant will begin operations in September and
save the government some $300 million a year by reducing the country’s reliance on imported
fuel, its chairman said.
Ahmed Heikal, who is also chairman of investment company Qalaa Holding, a 19 percent
shareholder in the project, said construction of the refinery will be completed in June, with
operations to begin in September. The Cairo facility will ramp up output to 98 percent of capacity
by the end of 2018.
Egypt, which currently imports much of
the refined products it needs for heating,
transportation and power generation, is
investing billions of dollars to increase
capacity and reduce its dependence on
international supply. The ERC refinery is
part of that effort, though it has
experienced repeated delays.
The most populous Arab nation has
struggled to revive its economy since the
2011 uprising that toppled former
President Hosni Mubarak scared off foreign investors and tourists. The government floated the
currency a year ago to end a crippling shortage of dollars that had made it increasingly expensive
to import basic goods such as wheat and fuel.
“This is a mega-project,” Heikal said in an interview in the capital. “It’s complex, and it takes a lot
of time.”
Public-Private Venture
The ERC plant, a public-private venture, had been scheduled to begin processing in the second
quarter of 2018, but the start date was pushed back due to construction delays, he said. Once
operational, it will reduce Egypt’s need for imported diesel by about 50 percent and for imported
gasoline by some 20 percent, Heikal said.
The new plant will satisfy about 14 percent of Egypt’s annual need for liquid oil products, with
capacity to produce as much as 4.2 million tons a year of liquid products as well as 600,000 tons a
year of sulfur and coke. It will be able to produce 2.3 million tons of diesel, 600,000 tons of jet fuel
and 522,000 tons of gasoline, in addition to butane gas and naphtha, he said.
Cairo Oil Refinery Co., Egypt’s largest processor with 20 percent of the country’s current refining
capacity, will supply ERC with fuel oil as feedstock. The new refinery will also import some of the
oil it needs, he said.
ERC will sell its products to the state’s Egyptian General Petroleum Corp. at international prices
minus 1 percent under a 25-year off-take deal, Heikal said.
Egyptian General Petroleum holds about 24 percent of ERC, with the rest owned by private
companies and international financial institutions. About $2.35 billion of the total cost is financed
by foreign loans to be repaid over a period of as many as 17 years from the project’s starting date,
he said.

Morocco: Genel Energy agrees changes of sidi Moussa licence
Source: Genel Energy
Genel Energy has come to an agreement with the Moroccan government over the nature, scope
and timing of the activity related to the remaining exploration commitment on the Sidi
Moussa offshore licensed acreage.
Under the terms of the agreement, Genel’s previous commitment to drill one well on the licence
has been replaced by an undertaking to carry out a 3D seismic campaign across the Sidi Moussa
acreage. Planning has commenced, with seismic acquisition expected to begin in 2018. The
current phase of the licence has been extended until February 2020.
The 3D seismic is expected to materially de-risk the prospectivity of the Sidi Moussa licence.
In Q4 2014 a well on the licence, SM-1, proved a working hydrocarbon system, with 26 degree
API oil recovered to surface.
Note: According to information on the Genel Energy web site, 'a farm-out process is ongoing as
part of the Company’s portfolio management activities, and Genel is in active discussions with a
number of parties' regarding the Sidi Moussa licence. Click here for Farmout Flyer.

NewBase November 10 - 2017 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil markets stable as markets tighten, but expect volatility
NewBase + Reuters + Bloomberg
Oil markets were slightly down but stable on Friday, supported by ongoing supply cuts and strong
demand which have resulted in a tightening market, although the prospect of rising U.S. output
capped prices.
Brent crude was at $63.76 per barrel at 0756 GMT, down 17 cents from its last close but within $1
of a more than two-year high of $64.65 reached earlier this week.
U.S. West Texas Intermediate (WTI) crude was at $57.07 per barrel, down 10 cents but also not
far from this week’s more than two-year peak of $57.92 a barrel.
Oil price special
coverage

SPONSORED
The high prices were a result of efforts led by the Organization of the Petroleum Exporting
Countries (OPEC) and Russia to tighten the market by withholding supplies, as well as strong
demand and rising political tensions.
“Oil prices have rallied sharply over the past week ... The latest catalyst for this move higher was
the sharp rise in geopolitical tensions last weekend, with growing confidence in an OPEC
extension and strong oil demand fueling the rally previously,” said U.S. bank Goldman Sachs.
The strong demand is visible in Southeast Asia, where the number of tankers holding oil in
storage around Singapore and Malaysia has halved since June. “Inventory changes over recent
months indicates that the supply/demand imbalance has improved,” said William O‘Loughlin,
analyst at Rivkin Securities.
But there were some words of caution. “This (oil upward) move may be short-lived ... It is possible
that shale ... production can be brought back on stream relatively quickly,” said Morgan Stanley
bank.
Goldman warned of greater price volatility ahead due to increasing tensions in the Middle East,
especially between OPEC fellows but political arch-rivals Saudi Arabia and Iran, along with
soaring U.S. oil production.
OPEC is due to discuss output policy during a meeting on Nov. 30, and it is expected it will extend
cuts beyond the current expiry date in March 2018. “Recent OPEC communication suggests that
an extension will be announced but there are no details on volumes,” Goldman said.
Oil Set for Best Weekly Run in Year
Oil is heading for a fifth weekly advance as political upheaval in the world’s biggest crude exporter
countered an expansion of U.S. output to the highest level in more than three decades.
Futures were little changed in New York, up 2.5 percent for the week. Arrests on the weekend of
senior Saudi Arabian officials in an anti-corruption probe is seen as consolidating power for Crown
Prince Mohammed bin Salman, who supports extending OPEC-led output cuts. While prices
eased during the week, record weekly U.S. oil production and a surprise increase in crude
stockpiles weren’t enough to peg back Monday’s 3.1 percent surge.

Oil is heading for the longest run of weekly gains since October 2016 as global supplies tighten
and on signs the Organization of Petroleum Exporting Countries will extend output curbs past the
end of March. OPEC this week said U.S. shale production will grow considerably faster than
expected over the next four years after cuts triggered a price recovery.
“Political stability was jolted awake this week after Saudi Arabia launched an anti-corruption
probe,” Daniel Hynes, a Sydney-based analyst at Australia & New Zealand Banking Group Ltd.,
said in a note. “While the likelihood of a disruption to supply remains low, we believe the events
raise the probability of Saudi Arabia taking a more aggressive stance on production curbs. The
risks now lie towards curbs remaining in place longer than expected.”
West Texas Intermediate for December delivery was at $57.01 a barrel on the New York
Mercantile Exchange, down 16 cents, at 7:40 a.m. in London. Total volume traded was about 48
percent below the 100-day average. Prices added 36 cents to $57.17 on Thursday.
See also: Saudi Billionaires Said to Move Funds to Escape Asset Freeze
Brent for January settlement lost 20 cents to $63.73 a barrel on the London-based ICE Futures
Europe exchange. Prices are up 2.7 percent this week, set for a fifth weekly gain. The global
benchmark crude was at a premium of $6.49 to January WTI.
Saudi Arabia said it plans to cut crude exports to all the regions it ships to next month. Shipments
will fall by 120,000 barrels a day in December from November, a spokesman for the Energy
Ministry said, without specifying what those levels would be. Bloomberg calculations from vessel-
tracking data estimated flows in October at 6.989 million a day.
WTI Oil Near $57 After Roller-Coaster Day as U.S. Output Hits Record
Oil traded near $57 a barrel after swinging wildly in the previous session as investors focused on
U.S. crude production that climbed to the highest in more than three decades.
Futures were little changed in New York. Prices on Wednesday closed 0.7 percent lower after
soaring 1.3 percent as multiple platforms suspended operations in the Gulf of Mexico. U.S. output
expanded for a third week to 9.62 million barrels a day, the highest in weekly Energy Information
Administration data going back to 1983. Crude inventories rose 2.24 million barrels last week,
compared with a 2.45-million drop forecast in a Bloomberg survey.

Oil has advanced about 20 percent since the start of September on signs the Organization of
Petroleum Exporting Countries and its allies will extend output cuts past March. An anti-
corruption probe in Saudi Arabia, the world’s top exporter, has added to price gains as arrests
were seen as consolidating power for the crown prince who has supported prolonging the
production reductions.
“Higher prices are a definite factor in bringing production back on -- this is a problem for OPEC,”
said Michael McCarthy, a chief strategist at CMC Markets in Sydney. “The first response comes
from the most agile producers, but once it looks like oil prices could be sustained at higher levels,
then even less agile producers can come back online.”
West Texas Intermediate for December delivery was at $56.84 a barrel on the New York
Mercantile Exchange, up 3 cents, at 2:27 p.m. in Hong Kong. Total volume traded was about 32
percent below the 100-day average. Prices lost 39 cents to $56.81 on Wednesday, falling for a
second session.
Brent for January settlement gained 6 cents to $63.55 a barrel on the London-based ICE Futures
Europe exchange, after falling in the past two sessions. The global benchmark crude was at a
premium of $6.48 to January WTI.
Crude stockpiles at Cushing, Oklahoma, the delivery point for WTI and the biggest U.S. oil-
storage hub, rose by 720,000 barrels to 64.6 million, the EIA said Wednesday. Gasoline supplies
fell a third week to 209.5 million barrels.
Oil markets stable, but doubts over recent bull run emerge
Oil prices held steady on Thursday after falling late in the previous session, supported by ongoing
supply cuts led by OPEC and Russia.
However, traders said a price rally that has pushed up
Brent crude by over 40 percent since July may have run
its course due to increases in U.S. supplies and some
indicators of a demand slowdown.
Brent futures were at $63.66 per barrel at 0155 GMT, up
17 cents, or 0.3 percent, from their last close, but about
$1 off the more than two-year high of $64.65 a barrel
reached earlier this week.
U.S. West Texas Intermediate (WTI) crude was at $56.92 per barrel, up 11 cents, or 0.2 percent,
but also some way off this week's more than two-year high of $57.69 a barrel. Key support was
coming from efforts led by the Organization of the Petroleum Exporting Countries (OPEC) and
Russia to withhold supplies in order to tighten the market and prop up prices.
OPEC will discuss output policy during a meeting on Nov. 30, and it is expected the group will
extend the cuts beyond the current expiry date in March 2018. "With the OPEC/non-OPEC deal
extension beyond March 2018 a certainty, prices may become stronger and temporarily reach the
$65-$70 per barrel range in 2018," said energy consultancy FGE.
Despite this, many analysts say the strong price rally of the past months has likely run its
course,at least for now. U.S. crude stockpiles rose 2.2 million barrels in the week to Nov. 3, to
457.14 million barrels, the Energy Information Administration said on Wednesday, contrary to
analysts' expectations for a decrease of 2.9 million barrels. U.S. crude production inched up
67,000 barrels per day (bpd) to 9.62 million bpd, the highest on record.

Key for the last weeks of the year is whether traders remain confident about their huge bets on
further price rises, or whether they sell out of these positions, satisfied with recent strong gains.
Asian floating oil storage declines as crude market tightens
The amount of oil stored on tankers around Singapore has dropped sharply in the last months,
the latest indication that OPEC-led supply cuts are successfully tightening crude markets even as
U.S. exports have soared.
FILE PHOTO: The Grace Star (R) oil tanker is seen being used as a floating oil storage facility off
the coast of Johor November 12, 2016. REUTERS/Henning Gloystein/File Photo
Shipping data in Thomson Reuters Eikon shows around 15 super-tankers are currently filled with
oil in waters off Singapore and western Malaysia, storing around 30 million barrels of crude. That
is half the number of ships in June and down from 40 tankers holding surplus fuel in mid-2017.
SPONSORED
The drop in floating storage around Asia’s main oil-trading hubs comes in the wake of voluntary
production cuts led by the Organization of the Petroleum Exporting Countries (OPEC) and Russia
as they look to choke off a supply overhang that has dogged markets for years.
“There are less incentives for traders to hold crude given rising crude oil prices and premiums. So
to some extent, the OPEC cuts have worked,” said Eng Hian, head of trading at Agritrade Energy
in Singapore, which trades crude and oil products. The Agritrade group of companies also has a
shipping arm that operates tankers used for storage.
Brent crude futures LCOc1 are up more than 40 percent since July to almost $64 per barrel. Also,
the Brent forward curve <0#LCO:> shows contracts for future delivery are cheaper than spot
supplies, a condition known as backwardation which makes it unattractive to store oil.
“The (backwardation) structure has flushed out oil in storage,” Eng Hian said.
The OPEC-led cuts were initially slated to last for the first half of 2017, but have since been
extended until March next year as some participants took time to comply with the curbs and as
U.S. crude imports jumped.
Tighter supplies are also evident in physical oil markets.
Saudi Arabia this month lifted the price for its light crude in Asia to the highest level since
September, 2014, just before the glut started. U.S. bank Goldman Sachs said this week that
falling inventories were also driven by strong demand for oil. “Strength in demand is an important
force in the rebalancing of the global oil market ... It has helped the decline in excess inventories,”
Goldman said in a note to clients.
Despite the tighter market, energy consultancy FGE warned this week that due to rising U.S.
shale production and a potential jump in OPEC supplies after the end of its voluntary cuts, a
supply glut could re-emerge.
“This may result in lower prices in 2019,” FGE said.
U.S. oil production climbed to a record of over 9.6 million barrels per day (bpd) this month, and
output is set to climb further. Texas issued around 1,000 oil and gas drilling permits last month, up
nearly 17 percent from the same month a year ago, according to the state’s energy regulator.

NewBase Special Coverage
News Agencies News Release November 09-2017
Total acquires Engie’s upstream LNG business and becomes the
second largest global LNG player
Source: Total
Total has signed an agreement with Engie to acquire its portfolio of upstream liquefied natural
gas (LNG) assets for an overall enterprise value of $1.49 billion. This portfolio includes
participating interests in liquefaction plants, notably the interest in the Cameron LNG project in
the US, long term LNG sales and purchase agreements, an LNG tanker fleet as well as access
to regasification capacities in Europe. Additional payments of up to $ 550 million could be
payable by Total in case of an improvement in the oil markets in the coming years.
'The acquisition of Engie’s upstream LNG business enables Total to accelerate the
implementation of its strategy to integrate along the full gas value chain, in an LNG market
growing strongly at 5% to 6% per year. The combination of these two complementary portfolios
will allow the Group to manage an overall volume of around 40 million tonnes of LNG per year by
2020, making Total the second largest global player among the majors with a worldwide market
share of 10%', commented Patrick Pouyanné, Chairman & Chief Executive Officer of Total. 'With
the equity stake in the Cameron LNG project, Total will also become an integrated player in the
US LNG market, where the Group is already a gas producer'.
The proposed transaction is subject to the applicable legally required consultation and
notification processes with employee representatives as well as approvals by the relevant
regulatory authorities and partners on certain contracts. The transaction is expected to close by
mid 2018 and will have an effective date of 1st January 2018. Following the transaction, Total
will take over the teams in charge of the LNG activities at Engie, which represents around 180
employees.
In addition, in parallel with this transaction, Total and Engie agreed to cooperate to promote the
use of biogas and renewable hydrogen, with Engie becoming Total's priority supplier in this field.
This transaction will bring to Total:
• 2.5 MTPA of liquefaction capacity to reinforce Total's existing portfolio, bringing it to
23 MTPA by 2020, with:

o 16.6% equity stake in the Cameron LNG liquefaction plant with 3 trains
currently under construction in Louisiana and the potential to expand by adding
two further trains.
o 5% equity stake in the first train of the Idku LNG project in Egypt.
• A portfolio of long-term LNG purchase and sale contracts, enabling the Group in
increase its overall portfolio to 28 MTPA by 2020, with a diversified supply from
Algeria, Nigeria, Norway, Russia, Qatar and the USA, and outlets balanced between
Europe and Asia.
• The access to regasification capacities of 14 MTPA in Europe, which, combined with
the existing 4 MTPA of Total, allows the Group to balance its consolidated purchase and
sales portfolio.
• A fleet of 10 LNG tankers which will be consolidated with the 3 LNG carriers of Total.
Overall, combining its interests in liquefaction plants and its portfolio of third party supply
contracts, the Group will manage a global volume of nearly 40 MTPA.
Chinese companies to develop LNG in Alaska
China's top state oil major Sinopec, one of the country's top banks and its sovereign wealth fund
have agreed to help develop Alaska's liquefied natural gas sector as part of President Donald
Trump's visit, the U.S. government said on Thursday.
Alaska Gasline Development, the State of Alaska, Sinopec, China Investment Corp and the Bank
of China have signed an agreement to advance LNG in Alaska, the U.S. government said in an
email.
The agreement will involve investment of up to $43 billion, create up to 12,000 U.S. jobs during
construction, reduce the trade deficit between the United States and Asia by $10 billion a year,
and give China clean energy, it said.
There were no other details. AGDC is building a gas
treatment plant, an 800-mile (1,287 km) pipeline to
south central Alaska for in-state use, and a
liquefaction plant in Nikiski to produce up to 20 million
tons of LNG per year for export.
China, the world's third-largest gas buyer, is importing
more LNG as the government tries to wean the
country off dirty coal as part of its push to clear the
skies, while the United States wants to sell more of its excess gas abroad.
Delfin signs China Gas deal, taps Chinese banks to fund 1st U.S. floating LNG plant: CEO
Delfin Midstream, developing the first floating facility to export U.S. natural gas, has sealed a
preliminary 15-year sales deal with city gas distributor China Gas Holdings, Delfin founder and
Chief Executive Officer Frederick Jones said.
Industry veteran Jones, a pioneer of spot crude oil trade in the 1970s, told Reuters in an interview
that as well as agreeing to supply 3 million tonnes a year of liquefied natural gas (LNG) from 2021,
Delfin is also tapping unnamed Chinese banks to fund its ambitious $8 billion LNG project, set to
sit 50 miles off the coast of Louisiana.

A rapidly growing spot market worldwide for LNG, allied with global oversupply of the super-chilled
fuel for at least the next few years, is transforming an energy business that traditionally counts on
20-30 year purchase agreements to bankroll projects.
“It’s a very significant challenge to secure long-term buyers given the rise of spot market and
oversupply,” said Jones. A founder-shareholder of legendary trading business Marc Rich & Co,
Jones was in Beijing as part of a trade delegation accompanying U.S. President Donald Trump on
his visit to China. [nL3N1NF121]
“We’re open to either or both types of investment...banks for debt and some strategic investors
who want LNG partially under their control,” said Jones. “We’ve seen a lot of interest from Chinese
banks to finance shipping.”
Delfin said in June it would jointly develop the Louisiana project with Golar (GLNG.O), a provider
of floating FLN technology. Jones said Delfin will borrow from Golar’s experience in tapping
Chinese banks for loans, without identifying institutions by name.
The memorandum of understanding to supply China Gas Holdings Co Ltd (0384.HK), announced
on Thursday, sees Delfin link up with one of China’s most active city gas distributors, operating
100,000 kilometers of pipelines.
Delfin also signed on Wednesday a memorandum of understanding with Chongqing Oil and Gas
Exchange to help develop a trading platform to the connect domestic Chinese market with
international markets, emulating the established benchmark Henry Hub in the states.
Chongqing, in western China next to the country’s largest natural gas province of Sichuan,
operates an extensive gas grid.
US LNG exports down on week
Sabine Pass Trains 1-4 (Image courtesy of Cheniere)
Cheniere’s Sabine Pass liquefaction terminal in Louisiana has seen fewer cargoes depart the
facility in the week ending November 8 as compared to the previous week, according to the
Energy Information Administration.
Four vessels with a combined LNG-carrying capacity of 14.4 billion cubic feet (Bcf) have departed
the plant since Wednesday last week. This compares to six vessels with a capacity of 22.4 Bcf the
week before. One vessel with a capacity of 3.8 Bcf was loading at the terminal on Wednesday.
Natural gas pipeline deliveries to Sabine Pass averaged 2.9 Bcf/d for the week ending November
8, up 0.1 Bcf from the previous week. There are currently four 0.6-Bcfd liquefaction trains
operating at Sabine Pass and a fifth is under construction and expected to enter service in mid-
2019.

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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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 27 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 November 2017 K. Al Awadi

New base 10 november 2017 energy news issue 1099 by khaled al awadi

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