New base 819 special 30 march 2016

Copyright © 2015 NewBase www.hawkenergy.net Edited by Khaled Al Awadi – Energy Consultant All rights reserved. No part of this publication may be reproduced, redistributed,
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NewBase 30 March 2016 - Issue No. 819 Edited & Produced by: Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
UAE: ADNOC 'Open' To More Partners At Onshore Oil Fields
Bloomberg - Anthony DiPaola
Abu Dhabi National Oil Co. is willing to accept additional partners at its main onshore fields, a
senior company official said, almost a year after awarding less than half the production rights it
offered for the deposits in a bidding round.
The Arabian Gulf
emirate, which holds
about 6 percent of
proven global oil
reserves, is
investing to boost
output capacity to
3.5 million barrels a
day of oil by 2017
from about 3 million
currently. Total SA
of France won a 10
percent stake in Abu
Dhabi’s onshore
joint venture, but
other former
partners in the
project including
Exxon Mobil Corp.,
BP Plc and Royal
Dutch Shell Plc either declined to bid or wouldn’t meet Adnoc’s terms.
“The door is open, if they can meet the technical and commercial requirements,” Abdul Munim Al
Kindy, Adnoc’s director of exploration and production, said Tuesday on the sidelines of an event in
Abu Dhabi. Al Kindy earlier this month left his role running the joint venture that operates the
onshore concession to take over as head of exploration at Adnoc.
Al Kindy’s appointment was one of the first major personnel changes by Sultan Al Jaber, who
became Adnoc’s new director general last month. Under Al Jaber, the company will focus on
controlling costs and boosting production of natural gas as the sheikhdom seeks more of the fuel
to run power plants and enhance recovery at oil fields, Al Kindy said.
Adnoc awarded a combined share of 18 percent of the onshore oil concession to foreign partners
last year. That leaves 22 percent of the venture to be awarded to foreign firms if Abu Dhabi
decides to maintain its 60 percent interest. Aside from Total, Adnoc’s other partners are Inpex
Corp. of Japan, with a 5 percent stake, and South Korea’s GS Energy Corp., with 3 percent.

Kuwait says it agrees with Saudi to restart Khafji oilfield
The Khafji field was shut in October 2014 for environmental reasons, having been producing
between 280,000 and 300,000 barrels per day (bpd)
Reuters + Gulf News + NewBase
Kuwait has agreed with Saudi Arabia to resume oil production at the jointly operated Khafji field,
the Opec member state’s acting oil minister said on Tuesday, weeks before oil producers are set
to agree a global output freeze.
Output at the joint Khafji
field will be small and
introduced gradually, Anas
al-Saleh told reporters in
the Kuwaiti parliament,
without giving the date of
the restart or planned
production figures.
The Khafji field was shut
in October 2014 for
environmental reasons,
having been producing
between 280,000 and
300,000 barrels per day
(bpd). It is operated by Al-
Khafji Joint Operations
Co, a joint venture
between AGOC, a
subsidiary of state oil firm
Saudi Aramco, and Kuwait
Gulf Oil Co.
Saleh said the agreement
to restart had been made
with Saudi Aramco.
“Some maintenance contracts have been amended to produce in volumes that are in line with
environmental requirements but (production) will go back to normal when all these requirements
are met,” Saleh said.
The announcement of the restart comes with oil prices about 50 per cent higher than the multi-
year lows hit in January, due to worries about an oversupply of crude. Opec and non-OPEC
producers are set to meet in April in the Qatari capital Doha to agree on freezing production at
January levels.
Wafra, another joint oilfield, has also been shut since May last year due to operating difficulties.
US oil major Chevron operates the field on behalf of the Saudi government. The impact of the
fields’ closures was more felt by Kuwait, which has less spare capacity than top Opec producer
Saudi Arabia.
Arabian Gulf

UAE: Production at Abu Dhabi’s Shah gasfield to be ramped up
Gulf News - Fareed Rahman, Senior Business Reporter
Gas production from Abu Dhabi’s Shah field is set to be increased by 50 per cent by 2021,
according to the chief executive officer of Al Hosn Gas company, which is developing the project.
“We are planning to increase production to 1.5 billion cubic feet per day within five years from the
present production capacity of one billion cubic feet per day,” Saif Ahmad Al Ghafli, chief
executive officer of Al Hosn Gas said while spea king to reporters on the sidelines of an event to
launch The Oil and Gas year report on Tuesday.
Al Hosn Gas is a joint venture between Abu Dhabi National Oil Company (Adnoc) and the US
based Occidental Petroleum. The project began operations last year and reached its full capacity
of one billion cubic feet per day in the second quarter. The main purpose of the project is to
produce usable gas from Shah’s high-sulphur field.
“We are really proud of this project. It has been done within a good time frame despite many
challenges,” Al Ghafli said. The gasfield located about 210 kilometres south-west of Abu Dhabi will
contribute significantly to the energy needs of Abu Dhabi and the UAE for over 30 years, he
added.
The UAE has been focusing on developing gas projects to meet the rising demand for electricity
generation. A gas project being developed by German company Wintershall is in progress near
Shuweihat in the western region of Abu Dhabi. Bab sour gas project faced challenges after Royal
Dutch Shell pulled out citing rising costs and technical difficulties.
According to the US based Energy Information Administration, the UAE holds the seventh-largest
proven reserves of natural gas in the world, at slightly more than 215 trillion cubic feet (Tcf) but it
has a high sulphur content that makes it highly corrosive and difficult to process. The UAE mainly
imports gas to generate electricity from Qatar through the Dolphin energy pipeline.

Oman:Tender for large-scale renewable solar power project in this year
Oman Observer
A tender for the procurement of Oman’s keenly awaited large-scale solar energy project is
expected to be floated this year, according to the head of the nation’s power sector regulatory
authority
Qais bin Saud al Zakwani, Executive President of the Authority for Electricity Regulation Oman
(AER), said the proposed venture — envisioning one or more solar-based electricity generation
plants with an aggregate capacity of up to 200 MW — will be procured as an Independent Power
Project (IPP) similar to conventional gas-based power projects.
Two locations in Dakhiliyah Governorate — Adam and Manah — have been identified as
prospective sites for the establishment of a grid-connected large-scale renewable energy scheme
based on a combination of concentrated solar power and photovoltaic technologies.
“This year, we will launch a tender for up to 200 megawatts of solar energy capacity at these
sites,” Al Zakwani said. “We hope to be using the same type of tendering mechanism for
conventional power plants to these two large-scale projects in Adam and Manah.”
To help amass “bankable data” in support of this ground-breaking renewable energy initiative,
solar radiation data is being collected from the two sites — a practice that began in 2010, he said.
Oman Power and Water Procurement Company (OPWPC), a wholly owned subsidiary of Nama
Group charged with overseeing the procurement of all new electricity generation and water
desalination capacity, is overseeing the data collection process.
According to Al Zakwani, large-scale renewable energy development in the Sultanate is expected
to make headway once the government rules on two key policy issues: One is the long-term
National Energy Strategy 2040, which will allocate a certain quota for renewable energy in the
wider energy mix; the other concerns the economic pricing of natural gas (the dominant source of
fuel in conventional power plants), which is key to assessing the economic feasibility of large-
scale renewable energy projects.

Ghana: Eni awarded new exploration licence offshore Ghana
Source: Eni
Eni has been awarded a new exploration licence, the Cape Three Points Block 4, located in the
prolific Tano basin, offshore Ghana. This acquisition will further strengthen the company’s
position in the Ghanaian offshore.
The Cape Three Points Block 4 licence was awarded, following the ratification by the Parliament
of the Republic of Ghana, to a joint venture which involves Eni Ghana (with 42.4691% stake) as
operator, Vitol Upstream Tano (with 33.9753% stake), Ghana National Petroleum
Corporation (GNPC with 10% stake),Woodfields Upstream Ghana (9.5556% stake)
and GNPC Exploration and Production Company (Explorco, 4% stake).
The new block covers an area of 1,127 sq kms in water depths ranging from 100 to 1,200 meters
and partially surrounds the OCTP block also operated by Eni. In the event of a successful
exploration outcome, the block will benefit from the OCTP project infrastructures, currently under
development.
Eni operates the OCTP project, which involves the integration and synergic development of the
various oil and gas discoveries (Sankofa Main, Sankofa East and Gye-Nyame). The project
envisages the development of subsea wells tied-back to a FPSO which will be connected to
shore via a gas transport line. The OCTP oil production start-up is expected in 2017 while the
gas production, which will supply the domestic market for power generation, is expected in 2018.
Eni has been present in Ghana since 2009 where it operates through the subsidiary Eni Ghana.
In the Country, the company has also undertaken important social programmes including the
Health Project in the Western Region for the benefit of a population of over 300,000 people.

Norway: Crude at $40 Isn't the Only Problem in its Oil Industry
Bloomberg - Mikael Holter
The collapse of crude prices isn’t the only problem facing energy companies in Norway: Explorers
in western Europe’s biggest oil-producing nation also have had their leanest drilling spell in almost
a decade.
Companies searching off Norway found less than 5 million barrels of oil and gas for every
exploration well drilled last year, the lowest ratio since 2006, according to Bloomberg calculations
based onNorwegian Petroleum Directorate data. That compares with a 27 million-barrel average
over the past 25 years.
The dismal results, due in part to the depletion of the North Sea, are bad news for a country
whose oil production has shrunk by half since 2000. The slump in prices has already dried up
income from crude extraction, which feeds the world’s biggest sovereign wealth fund and has
made Norwegians some of the richest people on the planet. In January the government made its
first withdrawal from the fund since it was set up in the 1990s as the market rout eroded growth.
The dwindling drilling success has left the country’s top explorers -- Statoil ASA and Lundin
Petroleum AB -- impatient to tap an entirely new region of the nation’s Arctic, bordering Russian
waters. Norway plans to award licenses in an area known as theBarents Sea Southeast before
summer and drilling could begin as soon as 2017.
Go North

“Those blocks are probably the best acreage being offered in Norway since the 1990s,” Lundin
Chief Executive Officer Alex Schneiter said in an interview in Oslo. “If you want to grow
significantly in resources, go north.”
With crude trading around $40 a barrel following the worst downturn in a generation, that might
seem like odd advice. Explorers including Statoil and Royal Dutch Shell Plc have fled other parts
of the Arctic such as Alaska and Greenland, where extreme conditions and environmental risks
make operations costly.
Two factors help explain why Statoil, Shell and others are salivating over new blocks in the region.
The Barents Sea, an area off Norway’s northern tip that’s the main focus of the country’s 23rd
licensing round, is less hostile than other Arctic waters thanks to the Gulf Stream, with shallower
and mostly ice-free access. And the Barents Sea Southeast, the first new acreage to be opened to
exploration in Norway since 1994, could hold “gigantic structures,” according to consultants
Rystad Energy AS.
New Province
“The 23rd round is very exciting,” said Statoil Chief Financial Officer Hans Jakob Hegge. “Access
to acreage is important to maintain stable activity” as the volumes discovered will tend to decline
in a mature area, he said.
Norway is counting on the little-explored Barents Sea to become its next big petroleum
province. So far, companies have drilled only 125 exploration wells there compared with 1,146 in
the North Sea, according to the petroleum directorate. That includes wildcat wells, which
are drilled at sites not previously explored, and appraisal wells, used to define a known reservoir.
The NPD estimates that the Barents holds almost half of the country’s undiscovered oil and gas
resources.
Eni SpA started production this month at the Barents Sea’s first oil field, Goliat. Statoil, Lundin and
OMV AG have made other discoveries that are yet to be developed. No wells have been drilled in

the Barents Sea Southeast because the area was disputed by Russia for decades until a bilateral
border agreement was reached in 2010.
The latest licensing round includes Norway’s northernmost blocks, despite protests from
environmental groups and opposition parties that they’re too close to the polar ice-cap, meaning a
spill could have disastrous consequences for an already fragile ecosystem sustaining animals
from polar bears to birds and fish.
Statoil, Shell and Lundin were among 26 companies that appliedfor licenses in December,
sending a “strong signal” of interest in the current market downturn, according to Jarand Rystad,
managing partner at Rystad Energy.
Oil companies in Norway will cut spending for a third consecutive year and drill almost half as
many exploration wells in 2016 than in 2015, the NPD forecast in January. Given the waning
activity and exploration efficiency, opening up as much acreage as possible is “the only right thing”
to do for the government, said Karl Johnny Hersvik, CEO of explorer Det Norske Oljeselskap ASA.
The biggest discovery in Norway in recent years -- the giant Johan Sverdrup field, which could
hold as many as 3 billion barrels of oil -- was made in the North Sea, not the Barents. Yet while it
showed the North Sea still has potential, even Lundin, which made the initial find in 2010, believes
future success is more likely farther north.
“It was a shock wave to the whole industry, but I would say that certainly that area is mature -- it’s
going to be less exciting than if you go north,” Lundin’s Schneiter said. In the Barents Sea, “we’re
just scratching the surface. So I think there’s the card to play -- and maybe the next Johan
Sverdrup,” he said.

U.S. production of LPG / NGL expected to increase through 2017
Source: U.S. Energy Information Administration, Short-Term Energy Outlook, March 2016
U.S. production of hydrocarbon gas liquids (HGL)—a group of products including ethane,
propane, butanes, and natural gasoline—is expected to increase from 3.86 million barrels per day
in 2015 to 4.33 million b/d in 2017, according to EIA's Short-Term Energy Outlook (STEO).
HGLs are produced at both natural gas processing plants and petroleum refineries, but natural
gas plants are expected to provide more than 95% of the forecast production growth.
Between 2008 and 2015, HGL production at natural gas processing plants (including fractionation
facilities) increased as a by-product of the growing supply of natural gas from shale gas and tight
oil formations.
Projects that increased the capacity to produce, store, transport, export, and consume HGLs
enabled the supply of HGLs to expand at a faster rate than natural gas production. STEO expects
HGL production growth to continue to outpace natural gas production growth in 2016 and 2017, as
more HGL infrastructure projects are completed.
Ethane production, which was constrained by lack of demand and low prices in recent years, is
expected to increase at a faster rate than other HGLs in 2016 and 2017, as expanded
petrochemical and export capacity provides new outlets for supply and allows more ethane to be
recovered from raw natural gas. Forecast natural gas plant ethane production increases by
300,000 b/d between 2015 and 2017, accounting for two-thirds of total HGL production growth.

The United States, which was a net importer of all HGL products in 2007, became a net exporter
of natural gasoline in 2008, of butane and propane in 2011, and of ethane in 2014. Annual
average net propane exports (gross exports minus gross imports) increased from 10,000 b/d in
2011 to an estimated 500,000 b/d in 2015, as the capacity to export liquefied petroleum gas
(LPG), including propane and butanes, increased by almost 1 million b/d.
STEO projects net propane exports to increase to 640,000 b/d in 2016 and to 740,000 b/d in 2017
as exports ramp up at two Gulf Coast terminal projects that began operating in the second half of
2015, and at another project scheduled to come online in the second half of 2016.
In March 2016, the first waterborne shipment of ethane left the United States from new ethane
export facilities at Marcus Hook, Pennsylvania. A second ethane export facility is expected to
open in the third quarter of 2016 at Morgan's Point, Texas. STEO projects net ethane exports to
increase by 80,000 b/d in 2016 and by 90,000 b/d in 2017 as exports ramp up at these terminals.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook, March 2016

NewBase 30 March 2016 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil prices rebound on less than expected build in stocks
Reuters + NEwBase
Oil futures rebounded in Asian trade on Wednesday, buoyed by a forecast for a less than
expected build in crude oil stockpiles last week. A weakening dollar also lent some support but
concern that a two-month rally was fading in an oversupplied market put a ceiling on gains.
Brent futures climbed 40 cents to $39.54 a barrel as of 0104 GMT after settling down $1.13 in the
previous session. U.S. crude rose 45 cents to $38.73 a barrel after ending the previous session
down $1.11.
Oil prices fell about 3 percent in the
previous session after Kuwait and Saudi
Arabia said they would resume production
at the jointly operated 300,000-barrel-per-
day Khafji field even as oil output is
supposed to be capped.
"There's a little bit of steadying in oil
prices in the Asian time zone. The
predominant attitude is one of wait-and-
see until the Energy Information Administration (inventory) figures come out," said Ric Spooner,
chief market analyst at Sydney's CMC Markets. The EIA is due to release official crude inventory
data later on Wednesday.
U.S. crude stocks rose last week by 2.6 million barrels to 534.4 million barrels data from industry
group, the American Petroleum Institute, showed on Tuesday. That was less than analysts'
expectations of a 3.3 million barrel build, but still a record high for a seventh straight week.
"The market is seeing how currencies go as well. It was slightly disconcerting for the market (on
Tuesday) to see oil prices falling at the same time as the dollar was falling," Spooner said. The
dollar index nudged lower on Wednesday after slipping to an eight-day low in the previous
session. A weaker dollar makes greenback-denominate d commodities cheaper for holders of
other currencies.
Rosneft, Russia's top oil producer, is set to lower oil output, Russian Natural Resources Minister
Sergei Donskoi said on Tuesday, although he gave no time frame. The plan could be lending
support to oil prices, Spooner said, although the impact would be muted because the market is
already pricing in possible output curbs.
OPEC member Iran is expected to attend an oil producers meeting in Doha on April 17 to discuss
a cap on global oil production, although it may not take part in the discussions, a source familiar
with Iranian thinking said on Tuesday.
Oil price special
coverage

NewBase Special Coverage
News Agencies News Release 30 March 2016
Gartman: Forget a freeze, this is the biggest threat to oil
CNBC - Leanne Miller | @LeanneBMiller
Oil watchers are eyeing a potential freeze by producers as the next catalyst for the commodity, but
one oil bear says crude's biggest obstacle is already here.
"I think Uber is a threat to oil for the simple reason that millennials have embraced it dramatically,"
Dennis Gartman, editor of The Gartman Letter, told CNBC's "Fast Money" traders on Monday.
"The millennials are saying 'I really don't need an automobile.'"
Since the founding of Uber in 2009, the ride-hailing company has launched in more than 400 cities
and taken passengers on more than 1 billion rides, according to the company's website.
And it's the simplicity and convenience of the service itself that Gartman said has converted many
would-be personal vehicle owners into Uber-dependent passengers. Oil has fallen more than 40
percent since Uber's inception.
This theory, he said, can be illustrated by taking a look at the history of U.S. total vehicle miles
traveled, as reported by the Federal Reserve Bank of St. Louis.
"If you take a look at the average amount of driving that has taken place in the United States, it
was a very well-defined trend line. We have broken that trend line dramatically," said Gartman.
"That whole mystique of driving an automobile is lost and it's not coming back."
For Gartman, the ride-hailing company diminishes the demand for gasoline as well as automobiles
— a bearish implication for ever-increasing oil production.
"I think on balance that is a terribly bearish circumstance," said Gartman.

The CNBC contributor stands by his theory that oil will continue to trade between $32 and $42 for
the foreseeable future. In a "Fast Money" interview last month, the so-called Commodities King
said he would not see $44 oil again in his lifetime.
"I think $42 is going to be very difficult to get through," said Gartman. "There are so many wells
that have been capped that could be brought online very quickly."

NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
Your partner in Energy Services
NewBase energy news is produced daily (Sunday to Thursday) and
sponsored by Hawk Energy Service – Dubai, UAE.
For additional free subscription emails please contact Hawk Energy
Khaled Malallah Al Awadi,
Energy Consultant
MS & BS Mechanical Engineering (HON), USA
Emarat member since 1990
ASME member since 1995
Hawk Energy member 2010
Mobile: +97150-4822502
khdmohd@hawkenergy.net
khdmohd@hotmail.com
Khaled Al Awadi is a UAE National with a total of 25 years of experience in
the Oil & Gas sector. Currently working as Technical Affairs Specialist for
Emirates General Petroleum Corp. “Emarat“ with external voluntary Energy
consultation for the GCC area via Hawk Energy Service as a UAE
operations base , Most of the experience were spent as the Gas Operations
Manager in Emarat , responsible for Emarat Gas Pipeline Network Facility &
gas compressor stations . Through the years, he has developed great
experiences in the designing & constructing of gas pipelines, gas metering &
regulating stations and in the engineering of supply routes. Many years were spent drafting, &
compiling gas transportation, operation & maintenance agreements along with many MOUs for the
local authorities. He has become a reference for many of the Oil & Gas Conferences held in the
UAE and Energy program broadcasted internationally, via GCC leading satellite Channels.
NewBase : For discussion or further details on the news above you may contact us on +971504822502 , Dubai , UAE
NewBase 30 March 2016 K. Al Awadi

New base 819 special 30 march 2016

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